BAKER HUGHES - Drilling Fluids Reference Manual

Drilling Fluids Reference Manual 

Chapter 1 – Fundamentals of Drilling Fluids 

Chapter 2 – Formation Mechanics 

Chapter 3 – Water-Base Drilling Fluids 

Chapter 4 – Contamination of Water-Base Muds 

Chapter 5 – Oil/Synthetic Drilling Fluids 

Chapter 6 – Reservoir Application Fluids 

Chapter 7 – Borehole Problems 

Chapter 8 – Corrosion 

Chapter 9 – Hydraulics 

Chapter 10 – Mechanical Solids Control 

Chapter 11 – Horizontal & Extended Reach Drilling 

Chapter 12 – Pressure Prediction and Control 

Chapter 13 – Deepwater Drilling Fluids 

Chapter 14 – Fluids Environmental Services 

Chapter 15 – Glossary of Terms

Fundamentals of Drilling Fluids 

Chapter 

One 

Fundamentals of Drilling Fluids

Chapter 1 

Table of Contents 

Fundamentals of Drilling Fluids ...............................................................................................................1-1 

Functions of Fluids................................................................................................................................1-1 

Promote Borehole Stability ...............................................................................................................1-1 

Remove Drilled Cuttings from Borehole ..........................................................................................1-2 

Cool and Lubricate Bit and Drillstring..............................................................................................1-2 

Suspend Cuttings / Weight Material When Circulation Ceases........................................................1-3 

Support Partial Weight of Drillstring or Casing................................................................................1-3 

Minimize Adverse Effects on Productive Formations ......................................................................1-3 

Transmit Hydraulic HP to Clean Bit and Bottom of Borehole .........................................................1-4 

Release Undesirable Cuttings at the Surface.....................................................................................1-4 

Ensure Maximum Information from Well ........................................................................................1-4 

Limit Corrosion of Drillstring, Casing, and Tubular Goods .............................................................1-4 

Minimize Environmental Impact ......................................................................................................1-4 

Physical and Chemical Properties of Fluids..........................................................................................1-5 

API Recommended Practices................................................................................................................1-5 

Density ..............................................................................................................................................1-5 

Rheology, Viscosity and Gel Strength Relationships .......................................................................1-5 

Newtonian and Non-Newtonian Fluids.................................................................................................1-7 

Viscosity............................................................................................................................................1-7 

Flow Regimes....................................................................................................................................1-7 

Determination of Flow Regime.......................................................................................................1-10 

Continuity of Flow ..........................................................................................................................1-11 

Mathematical Fluid Models ................................................................................................................1-11 

Newtonian Fluid Model ..................................................................................................................1-12 

Bingham Plastic Model ...................................................................................................................1-12 

Determination of PV and YP ..........................................................................................................1-14 

Power Law Model...............................................................................................................................1-16 

Determination of n and K................................................................................................................1-18 

Other Models.......................................................................................................................................1-20 

Casson .............................................................................................................................................1-20 

Robertson-Stiff................................................................................................................................1-20 

Herschel-Bulkley.............................................................................................................................1-20 

BAKER HUGHES DRILLING FLUIDS 

REVISED 2006 

REFERENCE MANUAL 

I

Table of Content 

Gel Strengths.......................................................................................................................................1-21 

Filtration..............................................................................................................................................1-22 

Testing Equipment ..........................................................................................................................1-22 

Permeability of Filter Cake.............................................................................................................1-23 

Pressure...........................................................................................................................................1-23 

Temperature ....................................................................................................................................1-23 

Viscosity .........................................................................................................................................1-24 

Time ................................................................................................................................................1-25 

Summary.........................................................................................................................................1-25 

Solids ..................................................................................................................................................1-25 

Cation Exchange Capacity (CEC)...................................................................................................1-26 

Low-Gravity Solids Analysis..........................................................................................................1-29 

Summary.............................................................................................................................................1-30 

Drilling Fluids pH and Alkalinity .......................................................................................................1-30 

Example Calculations .........................................................................................................................1-33 

Parameters.......................................................................................................................................1-33 

Exercise...........................................................................................................................................1-33 

Drill-In Fluids .....................................................................................................................................1-34 

Function ..........................................................................................................................................1-34 

Development...................................................................................................................................1-34 

Attributes.........................................................................................................................................1-34 

Screening and Selection..................................................................................................................1-34 

The Proposed Drill-In and Completion Program............................................................................1-35 

Leak-Off Control Tests ...................................................................................................................1-36 

Return Permeability Tests...............................................................................................................1-36 

Drill-In Fluid Properties......................................................................................................................1-37 

Static Filtration................................................................................................................................1-37 

Lubricity Testing.............................................................................................................................1-37 

Particle Size Distribution ................................................................................................................1-37 

Shale Inhibition (Wafer Test) .........................................................................................................1-38 

Density (API Standard Practice 13B-1, June 1990)........................................................................1-38 

Fluid Viscosity................................................................................................................................1-38 

Water, Oil and Solids......................................................................................................................1-38 

MBT (Methylene Blue Titration)....................................................................................................1-39 

Filter Cake Formation and Dispersability.......................................................................................1-39 

Reference Manual 

Baker Hughes Drilling Fluids 

ii Revised 2006


Return Permeability vs. Breakout Pressure.....................................................................................1-42 

Completion Fluids...............................................................................................................................1-44 

Definition ........................................................................................................................................1-44 

Function ..........................................................................................................................................1-44 

Attributes.........................................................................................................................................1-44 

Mechanisms for Formation Damage ...................................................................................................1-44 

Primary Factors Causing Formation Damage .................................................................................1-45 

Nomenclature ..........................................................................................................................................1-47 

References...............................................................................................................................................1-48 

List of Figures 

Figure 1-1 Deformation of a Fluid by Simple Shear ........................................................................1-6 

Figure 1-2 

Figure 1-3 

Three Dimension View of Laminar Flow in a Pipe for a Newtonian Fluid....................1-8 

Two/Three Dimensional Velocity Profile of Laminar Flow in a Pipe for a 

Newtonian Fluid..............................................................................................................1-8 

Figure 1-4 Two Dimensional Velocity Profiles of Laminar Flow for a Non-Newtonian Fluid .......1-9 

Figure 1-5 

Figure 1-6 

Two-Dimensional Velocity Profile of Turbulent Flow in a Pipe for a Newtonian 

Fluid ................................................................................................................................1-9 

Fluid Velocity is inversely Proportional to the Cross-Sectional Area of the Fluid 

Conductor......................................................................................................................1-11 

Figure 1-7 Flow Curve for a Newtonian Fluid ...............................................................................1-12 

Figure 1-8 

Flow Curve for a Bingham Plastic Fluid.......................................................................1-13 

Figure 1-9 Fann Model 35A 6 Speed V-G Meter ...........................................................................1-14 

Figure 1-10 

Figure 1-11 

Figure 1-12 

Figure 1-13 

Figure 1-14 

Flow Curve for a Power Law Fluid...............................................................................1-16 

Flow Behavior for Power Law Fluids...........................................................................1-17 

Drilling Fluid vs. Newtonian, Bingham, and Power Law Fluids..................................1-17 

Determination of n and K..............................................................................................1-18 

Gel Strength Characteristics vs. Time...........................................................................1-22 

Figure 1-15 SEM Photomicrograph X 150 – 2% PERFFLOW ® Filter Cake on AF-6 .....................1-40 

Figure 1-16 

SEM Photomicrograph 2% KCl PERFFLOW ® – Pore Bridging..................................1-40 

Figure 1-17 SEM Photomicrograph – 17 lb/gal PERFFLOW ..........................................................1-41 

Figure 1-18 

SEM Photomicrograph - Sized Salt System..................................................................1-42 

Figure 1-19 A Plot of Net Breakout Pressure vs. Return Permeability ............................................1-42 

Figure 1-20 The Effects of PERFFLOW ® on Return Permeability and Breakout Pressure .............1-43 

Figure 1-21 Effects of TBC Salt System on Return Permeability and Breakout Pressure ...............1-43 


Revised 2006 


iii


List of Tables 

Table 1-1 V-G Meter Speed and Corresponding Shear Rate ........................................................1-19 

Table 1-2 Viscosity of Water vs. Temperature .............................................................................1-24 

Table 1-3 Typical CEC Values .....................................................................................................1-28 

Table 1-4 Fluid System pH Ranges...............................................................................................1-31 

Table 1-5 Typical pH Levels of Some Common Drilling Fluid Additives...................................1-32 

Table 1-6 Fluid Parameters for Exercise Problem .......................................................................1-33 



iv Revised 2006

Fundamentals of Drilling Fluids 

Chapter 1 

A major component in drilling operation success is drilling fluid performance. The cost of searching 

for hydrocarbon reserves becomes more expensive when drilling occurs offshore, in deep water, and 

in hostile environments. These drilling environments require fluids that excel in performance. 

Measuring fluid performance requires the evaluation of all key drilling parameters and their 

associated cost. Simply stated, the effectiveness of a fluid is judged by its influence on overall well 

cost. This chapter discusses the various fundamentals of drilling fluids and their performance in 

assuring a safe and expeditious drilling operation at minimum overall cost. 

Functions of Fluids 

Promote Borehole Stability 

A fluid helps establish borehole stability by maintaining a chemical and/or mechanical balance. 

Mechanical Stability 

The hydrostatic pressure exerted by the drilling fluid is normally designed to exceed the existing 

formation pressures. The desired result is the control of formation pressures and a mechanically 

stable borehole. In many cases, these factors must also be considered: 

• Behavior of rocks under stress and their related deformation characteristics 

• Steeply dipping formations 

• High tectonic activity 

• Formations with no cohesive (lack of proper grain cementation) strength 

• High fluid velocity 

• Pipe tripping speeds and corresponding transient pressures 

• Hole angle and azimuth 

Any of these factors may contribute to borehole instability. In these situations, a protective casing 

string may be required, or hydrostatic pressure may need to be increased to values greater than the 

anticipated formation pressure. 

Chemical Stability 

Chemical interactions between the exposed formations of the borehole and the drilling fluid are a 

major factor in borehole stability. Borehole formation hydration can be the primary cause of hole 

instability, or a contributing factor. 



REVISED 2006 1-1

Hydraulics 

Aqueous drilling fluids normally use a combination of: 

• A coating mechanism (encapsulation) 

• A charge satisfaction mechanism 

• A mechanical or chemical method of preventing pore pressure transmission 

The present use of low solids/non/dispersed fluids incorporates these principles. They rely on 

polymers and soluble salts to inhibit swelling and dispersion. Commonly used polymers include: 

• Polysaccharide derivatives for filtration control 

• Partially hydrolyzed polyacrylamides for encapsulation 

• Xanthan gum for viscosity 

Isolating the fluid from the formation minimizes the potentially detrimental interaction between the 

filtrate and the formation. This is accomplished by controlling mud filtrate invasion of the formation. 

Filtrate invasion may be controlled by the type and quantity of colloidal material and by filtration 

control materials and special additives like cloud point glycols and products containing complexed 

aluminum. 

Non-aqueous drilling fluids minimize wellbore instability problems by having all-oil filtrates and by 

the osmotic pressure generated by the dissolved salt. 

Remove Drilled Cuttings from Borehole 

Drilling fluids transport cuttings from the well bore as drilling progresses. Many factors influence the 

removal of cuttings from the hole. 

The velocity at which fluid travels up the annulus is the most important hole cleaning factor. The 

annular velocity must be greater than the slip velocity of the cuttings for the cuttings to move up the 

well bore. 

The size, shape, and weight of a cutting determine the viscosity necessary to control its settling rate 

through a moving fluid. Low shear rate viscosity strongly influences the carrying capacity of the fluid 

and reflects the conditions most like those in the well bore. The drilling fluid must have sufficient 

carrying capacity to remove cuttings from the hole. 

The density of the suspending fluid has an associated buoyancy effect on the cuttings. An increase in 

density increases the capacity of the fluid to carry cuttings. 

Hole cleaning is such a complex issue that the best analysis method is to use a simulator, such as the 

one contained in ADVANTAGE ® . 

Cool and Lubricate Bit and Drillstring 

Considerable heat is generated by rotation of the bit and drillstring. The drilling fluid acts as a 

conductor to carry this heat away from the bit and to the surface. Current trends toward deeper and 

hotter holes make this a more important function. 

The drilling fluid also provides lubrication for the cutting surfaces of the bit thereby extending their 

useful life and enhancing bit performance. 

Filter cake deposited by the drilling fluid provides lubricity to the drill string, as do various specialty 

products. Oil and synthetic base fluids are lubricious by nature. 



1-2 Revised 2006


Control Subsurface Pressure 

As drilling progresses, oil, water, or gas may be encountered. Sufficient hydrostatic pressure must be 

exerted by the drilling fluid column to prevent influx of these fluids into the borehole. The amount of 

hydrostatic pressure depends on the density of the fluid and the height of the fluid column, i.e., well 

depth. Typical materials used to maintain drilling fluid density include barite (MIL-BAR ® ), hematite 

(DENSIMIX ® ), ilmenite and calcium carbonate (MIL-CARB ® ). The following formulae can be used 

to calculate the total hydrostatic pressure at any given depth or fluid density: 

Hydrostatic Pressure (psi) = 0.052 × Depth (ft) × Fluid Density (lb m / gal) 

or 

Hydrostatic Pressure (psi) = 0.00695 × Depth (ft) × Fluid Density (lb m / ft 3 ) 

or 

Hydrostatic Pressure (kg / cm 2 ) = 0.1 Depth (m) × Fluid Density (g / cm 3 ) 

While static pressures are important in controlling an influx of formation fluids, dynamic fluid 

conditions must also be considered. Circulation of the drilling fluid and movement of the drillstring 

in and out of the hole create positive and negative pressure differentials. These differentials are 

directly related to flow properties, circulation rate, and speed of drillpipe movement. These pressures 

may be calculated using the engineering software contained within ADVANTAGE. 

Suspend Cuttings / Weight Material When Circulation Ceases 

When circulation is stopped, drilling fluids must suspend the drilled cuttings and weight material. 

Several factors affect suspension ability. 

• Density of the drilling fluid 

• Viscosity of the drilling fluid 

• Gelation, or thixotropic properties of the drilling fluid 

• Size, shape and density of the cuttings and weight material 

Circulation of the suspended material continues when drilling resumes. The drilling fluid should also 

exhibit properties which promote efficient removal of solids by surface equipment. 

Support Partial Weight of Drillstring or Casing 

The buoyancy effect of drilling fluids becomes increasingly important as drilling progresses to greater 

depths. Surface rig equipment would be overtaxed if it had to support the entire weight of the drill 

string and casing in deeper holes. Since the drilling fluid will support a weight equal to the weight of 

the volume of fluid displaced, a greater buoyancy effect occurs as drilling fluid density increases. 

Minimize Adverse Effects on Productive Formations 

It is extremely important to evaluate how drilling fluids will react when potentially productive 

formations are penetrated. Whenever permeable formations are drilled, a filter cake is deposited on 

the wall of the borehole. The properties of this cake can be altered to minimize fluid invasion into 

permeable zones. Also, the chemical characteristics of the filtrate of the drilling fluid can be 

controlled to reduce formation damage. Fluid–fluid interactions can be as important as fluidformation 

interactions. In many cases, specially prepared drill-in fluids are used to drill through 

particularly sensitive horizons. 



Revised 2006 1-3

Hydraulics 

Transmit Hydraulic HP to Clean Bit and Bottom of Borehole 

Once the bit has created a drill cutting, this cutting must be removed from under the bit. If the cutting 

remains, it will be “re-drilled” into smaller particles which adversely affect penetration rate of the bit 

and fluid properties. 

The drilling fluid serves as the medium to remove these drilled cuttings. One measure of cuttings 

removal force is hydraulic horsepower available at the bit. These are the factors that affect bit 

hydraulic horsepower: 

• Fluid density 

• Fluid viscosity 

• Jet nozzle size 

• Flow rate 

Bit hydraulic horsepower can be improved by decreasing jet nozzle size or increasing the flow rate. 

The two most critical factors are flow rate and nozzle size. The total nozzle cross sectional area is a 

factor in increasing flow rate and hydraulic horsepower. 

Release Undesirable Cuttings at the Surface 

When drilled cuttings reach the surface, as many of the drilled solids as possible should be removed to 

prevent their recirculation. Mechanical equipment such as shale shakers, desanders, centrifuges, and 

desilters remove large amounts of cuttings from the drilling fluid. Flow properties of the fluid, 

however, influence the efficiency of the removal equipment. Settling pits also function well in 

removing undesirable cuttings, especially when fluid viscosity and gel strengths are low. 

Ensure Maximum Information from Well 

Obtaining maximum information on the formation being penetrated is imperative. A fluid which 

promotes cutting integrity is highly desirable for evaluation purposes. The use of electronic devices 

incorporated within the drill string has made logging and drilling simultaneous activities. 

Consequently, optimum drilling fluid properties should be maintained at all times during drilling, 

logging, and completion phases. 

Limit Corrosion of Drillstring, Casing, and Tubular Goods 

Corrosion in drilling fluids is usually the result of contamination by carbon dioxide, hydrogen sulfide, 

oxygen or, in the case of static fluids, bacterial action. Low pH, salt-contaminated, and non-dispersed 

drilling fluids are inherently more corrosive than organically treated freshwater systems. Oil or 

synthetic-based fluids are considered non-corrosive. A proper drilling fluid corrosion control program 

should minimize contamination and render the contaminating source non-corrosive. 

Minimize Environmental Impact 

Drilling creates significant volumes of used fluid, drill cuttings and associated waste. Increased 

environmental awareness has resulted in legislation that restricts the use, handling and disposal of the 

by-products generated during drilling and after the well is finished. Careful attention to the 

composition of the fluid and the handling of the residual materials reduces the potential environmental 

impact of the drilling operation. 



1-4 Revised 2006


Physical and Chemical Properties of Fluids 

The physical and chemical properties of a drilling fluid play an important role in the success of a 

drilling operation. 

The properties of drilling fluid are perhaps the only variables of the entire drilling process that can be 

altered rapidly for improved drilling efficiency. These properties usually receive the greatest 

attention. 

API Recommended Practices 

The American Petroleum Institute (API) has set forth numerous recommended practices designed to 

standardize various procedures associated with the petroleum industry. The practices are subject to 

revision from time-to-time to keep pace with current accepted technology. One such standard is API 

Bulletin RP 13B-1, “Recommended Practice Standard Procedure for Field Testing Water-Based 

Drilling Fluids”. This Bulletin described the following drilling fluid measurements as necessary to 

describe the primary characteristics of a drilling fluid: 

• Density – for the control of formation pressures 

• Viscosity and Gel Strength – measurements that relate to a mud’s flow properties 

• Filtration – a measurement of the mud’s loss of liquid phase to exposed, permeable formations 

• Sand – the concentration of sand (solid particles < 74µ) being carried in the mud 

• Methylene Blue Capacity – an indication of the amount of reactive clays present in the mud 

• pH – a measurement of the alkaline / acid relationship in the mud 

• Chemical Analysis – qualitative and quantitative measurement of the reactive chemical 

components of the mud 

Chemical properties, such as chloride content, total hardness, etc., are important. They are discussed 

in Chapter 4 of this manual, “Contamination of Water-Base Fluids”. 

Density 

The density of any fluid is directly related to the amount and average specific gravity of the solids in 

the system. The control of density is critical since the hydrostatic pressure exerted by the column of 

fluid is required to contain formation pressures and to aid in keeping the borehole open. Fluid density 

in English units is commonly expressed in lb m /gal (lb m /ft 3 in some locations) and in specific gravity or 

g/cm 3 in countries utilizing the metric system. 

The density of any fluid should be dictated by formation pressures. The density must be sufficient to 

promote wellbore stability. The pressure exerted by the fluid column should ideally be only slightly 

higher than that of the formation to insure maximum penetration rate with minimal danger from 

formation fluids entering the well bore. 

The common method for checking the density of any drilling fluid is the mud balance. The mud 

balance consists of a supporting base, a cup, a lid, and a graduated beam carrying a sliding weight. A 

knife edge on the arm rests on the supporting base. It has become common in many locations to use 

pressurized mud balances as these are considered to be more accurate. 

Rheology, Viscosity and Gel Strength Relationships 

The rheolgical properties, viscosity and gel strength of drilling fluids describe the ability of the fluid 

to transport cuttings while drilling and suspend them when circulation is interrupted. Frequently, the 



Revised 2006 1-5

Hydraulics 

term “viscosity” is confused with the term “rheology”. A more detailed analysis of the term 

“rheology” follows. 

Rheology 

Rheology is defined as physics of the flow and the deformation of matter. Rheology and the 

associated annular hydraulics (Chapter 9) relate directly to borehole stability and how effectively the 

borehole is cleaned. An understanding of rheology is essential if wellsite engineering of the drilling 

fluid is to cost effectively complement the objective of drilling the well. Rheology and hydraulics of 

drilling fluids are not exact sciences, but are based upon mathematical models that closely describe 

the rheology and hydraulics of the fluid and do not conform exactly to any of the models. 

Consequently, different methods are used to calculate rheology and hydraulic parameters. 

Fluid Deformation 

Rheology is the study of the deformation of all forms of matter. The deformation of a fluid can 

simply be described by two parallel plates separated by some distance as shown in Figure 1-1. 

Figure 1-1 

Deformation of a Fluid by Simple Shear 

Shear Stress 

An applied force (F), acting over an area (A), causes the layers to slide past one another. However, 

there is a resistance, or frictional drag, force that opposes the movement of these plates. This 

resistance or drag force is called shear stress ( τ ). In equation form, 

τ 

= 

F 

----- 

A 

with shear stress having typical units of lb f /100 ft 2 . 

Additionally, the fluid layers move past each other easier than between a pipe wall and fluid layer. 

Therefore, we can consider a very thin layer of fluid next to the pipe wall as stationary. 

Shear Rate 

The difference in the velocities between two layers of fluid divided by the distance between the two 

layers is called the shear rate ( γ ). In equation form, 

γ 

velocity difference 

= ----------------------------------------------- 

distan 

ce 

With typical units of 

or, reciprocal seconds. 

ft/sec 1 

------------ = ------ = 

ft sec 

se c 1 



1-6 Revised 2006


Newtonian and Non-Newtonian Fluids 

The relationship between shear stress ( τ ) and shear rate ( γ ) defines the flow behavior of a fluid. for 

some fluids, the relationship is linear. If the shear rate is doubled, then the shear stress will also 

double. Such fluids are called Newtonian fluids. Examples of Newtonian fluids include water, 

alcohols, and light oils. Very few drilling fluids fall into the Newtonian category. 

Fluids which have flow characteristics such that the shear stress does not increase in direct proportion 

to the shear rate are called non-Newtonian fluids. Most drilling fluids are of this type. 

Viscosity 

For a Newtonian fluid, the relationship between viscosity, shear stress and shear rate is defined as the 

viscosity ( μ ) of the fluid where, 

where, 

μ = 

τ 

- 

γ 

τ = shear stress 

μ = viscosity 

γ = shear rate. 

As previously described, the relationship between shear stress and shear rate is directly proportional 

for a Newtonian fluid. The viscosity remains constant and is the only parameter needed to 

characterize the flow properties. The metric unit typically used for viscosity is the poise, defined as 

the force in dynes per square centimeter required to produce a difference in velocity of one centimeter 

per second between two layers one centimeter apart. A centipoise is one hundredth (1/ 100 ) of a poise. 

For non-Newtonian fluids, the relationship between shear stress and shear rate is defined as the 

effective viscosity. However, the effective viscosity of a non-Newtonian fluid is not constant. For 

most drilling fluids, the effective viscosity will be relatively high at low-shear rates, and relatively low 

at high-shear rates. In other words, the effective viscosity decreases as the shear rate increases. When 

a fluid behaves in this manner, it is said to be shear thinning. Shear thinning is a very desirable 

characteristic for drilling fluids. The effective viscosity of the fluid will be relatively lower at the 

higher shear rates in areas such as the drill pipe and bit nozzles. Likewise, the effective viscosity of 

the fluid will be relatively higher at the lower shear rates in the annulus where the higher effective 

viscosity of the fluid aids in hole cleaning. 

The relationship between shear stress and shear rate for non-Newtonian fluids is developed later in the 

sub-section, Mathematical Fluid Models. 

Flow Regimes 

In 1883, Osborne Reynolds conducted experiments with various liquids flowing through glass tubes. 

He introduced a dye into the flowing stream at various points. He found that when the flow rate was 

relatively low, the dye he introduced formed a smooth, thin, straight streak down the glass. There was 

essentially no mixing of the dye and liquid. This type of flow in which all the fluid motion is in the 

direction of flow is called laminar flow. 

Reynolds also found with relatively high flow rates, no matter where he introduced the dye it rapidly 

dispersed throughout the pipe. A rapid, chaotic motion in all directions in the fluid caused the 

crosswise mixing of the dye. This type of flow is called turbulent flow. 



Revised 2006 1-7

Hydraulics 

Reynolds showed further that under some circumstances, the flow can alternate back and forth 

between being laminar and turbulent. When that happens, it is called transitional flow. 

Therefore, we can describe a fluid's flow as being either laminar, turbulent, or transitional. 

Additionally, another term has been used to describe a fluid's flow at extremely low flow rates – plug 

flow. 

The particular flow regime of a drilling fluid during drilling operations can have a dramatic effect on 

parameters such as pressure losses, hole cleaning, and hole stability. 

Plug Flow 

In plug flow, the fluid moves essentially as a single, undisturbed solid body. Movement of the fluid 

occurs due to the slippage of a very thin layer of fluid along the pipe wall or conductor surface. Plug 

flow generally occurs only at extremely low flow rates. 

Laminar Flow 

The laminar flow of a Newtonian liquid in a circular pipe is illustrated in Figure 1-2. Laminar flow of 

a Newtonian fluid can be visualized as concentric cylindrical shells which slide past one another like 

sections of a telescope. The velocity of the shell at the pipe wall is zero, and the velocity of the shell 

at the center of the pipe is the greatest. 

Figure 1-2 

Three Dimension View of Laminar Flow in a Pipe for a Newtonian Fluid 

A two-dimensional velocity profile is illustrated in Figure 1-3. The shear rate, previously defined as 

the velocity difference between two layers of fluid divided by the difference between the two layers, 

is simply the slope of a line at any point along the velocity profile. The shear rate is greatest at the 

wall and zero at the center of the pipe. Since the shear stress and shear rate for a Newtonian fluid are 

directly proportional, the shear stress is also greatest at the wall and zero at the center of the pipe. 

Figure 1-3 

Two/Three Dimensional Velocity Profile of Laminar Flow in a Pipe for a Newtonian 

Fluid 

The laminar flow of a non-Newtonian fluid is very similar to that of a Newtonian fluid with the 

exception that some portion of the cylindrical shells in the center of a pipe may not slide past one 

another. 



1-8 Revised 2006


Figure 1-4 

Two Dimensional Velocity Profiles of Laminar Flow for a Non-Newtonian Fluid 

The two dimensional velocity profile of a non-Newtonian fluid in laminar flow depends upon the 

relationship between the shear stress and shear rate. Several examples of the velocity profile are 

shown in Figure 1-4. 

Turbulent Flow 

Turbulent flow occurs when a fluid is subject to random, chaotic shearing motions that result in local 

fluctuations of velocity and direction, while maintaining a mean velocity parallel to the direction of 

flow. Only near the walls does a thin layer of orderly shear exist. Thus the velocity profile is very 

steep near the walls, but essentially flat elsewhere as shown in Figure 1-5. 

Transitional Flow 

Transitional flow occurs when the flow of a fluid is neither completely laminar nor completely 

turbulent. In other words, there is no abrupt transition from one flow regime to another. 

Figure 1-5 

Two-Dimensional Velocity Profile of Turbulent Flow in a Pipe for a Newtonian Fluid 



Revised 2006 1-9

Hydraulics 

Determination of Flow Regime 

The experiments conducted by Reynolds, besides naming the behavior of fluid flow, made the most 

celebrated application of dimensional analysis in the history of fluid mechanics by introducing the 

Reynolds Number (Re). 

Reynolds number takes into consideration the basic factors of pipe flow – pipe diameter, average fluid 

= V D ρ 

μ 

velocity, fluid density, and fluid viscosity. Reynolds number is defined as 

Re ( )( )( ) 

where, 

V = average fluid velocity 

D = pipe diameter 

ρ = fluid density 

μ= fluid viscosity 

Reynolds showed that for smooth, circular pipes, for all Newtonian fluids, and for all pipe, the 

transition from laminar to turbulent flow occurs when the Reynolds number has a value of 

approximately 2000. However, turbulent flow throughout the fluid occurs when the Reynolds number 

is more than 4000. 

Therefore, for Newtonian fluids, laminar flow is defined as a Reynolds number of 2000 or less. 

Turbulent flow is defined as a Reynolds number of 4000 or greater. Transitional flow is defined when 

the Reynolds number is between 2000 and 4000. 

As previously shown, the viscosity of non-Newtonian fluids depends upon the relationship between 

shear stress and shear rate. Likewise, the value of the Reynolds number at which the transition from 

laminar to turbulent flow occurs depends upon the shear stress/shear rate relationship. 

The relationship between shear stress and shear rate for non-Newtonian fluids is developed in the 

subsection, Mathematical Fluid Models . 



1-10 Revised 2006


Continuity of Flow 

Many hydraulic calculations in this manual require the use of the fluid velocity. It is important to 

understand the difference between flow rate and velocity. Consider the flow of a liquid through a 

pipe at a constant flow rate, as illustrated in Figure 1-6 

Figure 1-6 

Fluid Velocity is inversely Proportional to the Cross-Sectional Area of the Fluid 

Conductor 

An algebraic solution to the above diagram is described as follows: 

Q flow = V 1 A 1 = V 2 A 2 

If A 2 = ½ A 1 

V 1 (2A 2 ) = V 2 A 2 

V 1 = ½ V 2 

Because drilling fluids are very nearly incompressible, the volumetric flow rate of fluid entering the 

pipe must equal the volumetric flow rate leaving the pipe. This is the principle of continuity of flow. 

The important result of this principle is that, at a constant flow rate, the fluid velocity is inversely 

proportional to the area through which it flows. In other words, if the area decreases, the fluid 

velocity must increase for a constant flow rate. 

Mathematical Fluid Models 

A mathematical fluid model describes the flow behavior of a fluid by expressing a mathematical 

relationship between shear rate and shear stress. As described in the viscosity section, the shear 

stress/shear rate relationship is a constant for Newtonian fluids. 

For non-Newtonian fluids, however, the relationship between shear stress and shear rate is much more 

complex. A generalized relationship for all non-Newtonian fluids has not been found. Instead, 

various mathematical models have been proposed. These mathematical models do not describe the 

behavior of non-Newtonian fluids exactly, but are merely close approximations. 

Discussed below is a Newtonian Fluid Model which can be considered exact for Newtonian fluids, 

and two non-Newtonian fluid models – the Bingham Plastic Model and the Power Law Model. 

Additional models described are the Casson Model, the Robertson-Stiff Model, and the 

Herschel-Bulkley Model. 



Revised 2006 1-11

Hydraulics 

Newtonian Fluid Model 

The Newtonian Fluid Model is the basis from which other fluid models are developed. The flow 

behavior of Newtonian fluids has been discussed and it can be seen from this equation that the shear 

stress-shear rate relationship is given by: 

where, 

τ 

= 

( μ) ( γ) 


μ = viscosity 

γ = shear rate 

At a constant temperature, the shear stress and shear rate are directly proportional. The 

proportionality constant is the viscosity (μ). 

Figure 1-7 illustrates the flow curve of a Newtonian fluid. Note that the flow curve is a straight line 

which passes through the origin (0, 0) and the slope of the line is the viscosity (μ). 

Figure 1-7 

Bingham Plastic Model 

Flow Curve for a Newtonian Fluid 

In the early 1900s, E.C. Bingham first recognized that some fluids exhibited a plastic behavior, 

distinguished from Newtonian fluids, in that they require a yield stress to initiate flow. No bulk 

movement of the fluid occurs until the applied force exceeds the yield stress. The yield stress is 

commonly referred to as the Yield Point. The shear stress / shear rate relationship for the Bingham 

Plastic Model is given by: 

where, 

τ = τ o 

+ ( μ 

∞ )γ) ( 


τ o = yield point 

μ ∞ = Plastic viscosity 

γ = shear rate. 



1-12 Revised 2006


The flow curve for a Bingham Plastic fluid is illustrated in Figure 1-8. The effective viscosity, defined as 

the shear stress divided by the shear rate, varies with shear rate in the Bingham Plastic Model. The 

effective viscosity is visually represented by the slope of a line from the origin to the shear stress at some 

particular shear rate. The slopes of the dashed lines represent effective viscosity at various shear rates. 

As can be seen, the effective viscosity decreases with increased shear rate. As discussed in the Viscosity 

section, this is referred to as shear thinning. 

Figure 1-8 

Flow Curve for a Bingham Plastic Fluid 

As shear rates approach infinity, the effective viscosity reaches a limit called the Plastic Viscosity. 

The plastic viscosity of a Bingham Plastic fluid represents the lowest possible value that the effective 

viscosity can have at an infinitely high shear rate, or simply the slope of the Bingham Plastic line. 

The Bingham Plastic Model and the terms plastic viscosity (PV) and yield point (YP) are used 

extensively in the drilling fluids industry. Plastic viscosity is used as an indicator of the size, shape, 

distribution and quantity of solids, and the viscosity of the liquid phase. The yield point is a measure 

of electrical attractive forces in the drilling fluid under flowing conditions. The PV and YP are two 

parameters of a drilling fluid that many in the industry still consider to be vitally important in the 

overall drilling operation. The YP is now considered an outdated concept that has no real meaning or 

application in drilling operations. The following rheological models better describe the behavior of 

drilling fluids. This can clearly be seen when the viscometer readings are plotted on a graph and the 

resultant line is a curve and not a straight line. The Bingham model uses a straight line relationship. 



Revised 2006 1-13

Hydraulics 

Determination of PV and YP 

The commonly used V-G (viscosity-gel) meter, or direct indicator viscometer, was specifically 

designed to facilitate the use of the Bingham Plastic Model in conjunction with drilling fluids in the 

field. The instrument has a torsion spring-loaded bob which gives a dial reading proportional to 

torque and analogous to the shear stress. The speed of rotation (rpm) is analogous to the shear rate. 

When the V-G meter (with the proper rotor, bob, and spring) is used, the dial reading is determined 

as: 

where, 

θ = YP + PV⎛ 

-------- ω ⎞ 

⎝ 300 ⎠ 

θ = dial reading 

YP = yield point 

PV = plastic viscosity 

ώ = rotation speed (rpm) 

Figure 1-9 

Fann Model 35A 6 Speed V-G Meter 



1-14 Revised 2006


As defined in the Fluids Testing Procedures Manual, the determination of PV and YP are obtained 

from the dial readings at 600 rpm and 300 rpm. Substitution of the appropriate data into the equation 

shows how these terms are derived. 

θ 600 = YP + PV⎛ 

600 -------- ⎞ = YP + 2PV 

⎝300 

⎠ 

θ300 = YP + PV⎛ 

300 -------- ⎞ = YP + PV 

⎝300 

⎠ 

By subtracting θ 300 from θ 600 , we obtain, 

or, 

( θ 600 – θ 300 ) = ( YP + 2PV) – ( YP + PV) = ( YP – YP) + ( 2PV – PV ) = 0 + PV 

PV = ( θ 600 – θ 300 ) 

By re-arranging the earlier equation for θ 300 , we have, 

where, 

YP = ( θ300 – PV) 

θ 600 = 600 rpm dial reading 

θ 300 = 300 rpm dial reading 

Effective viscosity has been previously defined as the shear stress divided by the shear rate or the 

slope of the line passing through the origin to the shear stress at some particular shear rate. From the 

equations above, we see that PV can represent the effective viscosity if YP = 0, written as, 

θ600 = 0 + 2( μ∞ ) 

The effective viscosity at a shear rate of 600 rpm on the V-G meter is distinguished from the effective 

viscosity at other shear stress/shear rate data values by the term apparent viscosity. Therefore, 

apparent viscosity is defined at a 600 rpm shear rate by, 

θ 600 

μ ∞ = --------- 

2 

Although plastic viscosity (PV) and yield point (YP) are two of the most recognized properties of 

drilling fluids, these terms are simply constants in the Bingham Plastic Mathematical Model. Very 

few drilling fluids follow this model, but the empirical significance of PV and YP is firmly entrenched 

in drilling technology. In fact, drilling fluid systems such as the NEW-DRILL ® system and many 

others deviate significantly from the Bingham Plastic Model and the terms PV and YP must be 

interpreted with caution. 



Revised 2006 1-15

Hydraulics 

Power Law Model 

Most drilling fluids exhibit behavior that falls between the behaviors described by the Newtonian 

Model and the Bingham Plastic Model. This behavior is classified as pseudo plastic. The 

relationship between shear stress and shear rate for pseudo plastic fluids is defined by the power law 

mathematical model, 

where, 

τ 

= 

K( γ 

n ) 


K = consistency factor 


n = flow behavior index 

Figure 1-10 illustrates the flow curve for a pseudo plastic fluid. 

Figure 1-10 

Flow Curve for a Power Law Fluid 

The two terms, K and n, are constants in the Power Law Model. Generally, K is called the consistency 

factor and describes the thickness of the fluid and is thus somewhat analogous to effective viscosity. 

If the drilling fluid becomes more viscous, then the constant K must increase to adequately describe 

the shear stress/shear rate relationship. 

Additionally, n is called the flow behavior index and indicates the degree of non-Newtonian behavior. 

A special fluid exists when n = 1, when the Power Law Model is identical to the Newtonian Model. If 

n is greater than 1, another type of fluid exists classified as dilatant, where the effective viscosity 

increases as shear rate increases. For drilling fluids, the pseudo plastic behavior is applicable and is 

characterized when n is between zero and one. Pseudo plastic fluids exhibit shear thinning, where the 

effective viscosity decreases as the shear rate increases just like the Bingham Plastic Model. Figure 

1-11 shows the flow curves for these values of n. 



1-16 Revised 2006


Figure 1-11 

Flow Behavior for Power Law Fluids 

Similar to the Bingham Plastic Model, the Power Law Model does not describe the behavior of 

drilling fluids exactly. However, the Power Law constants n and K are used in hydraulic calculations 

(Chapter 9) that provide a reasonable degree of accuracy. 

Figure 1–12 compares the flow curve of a typical drilling fluid to the flow curves of Newtonian, 

Bingham Plastic, and Power Law Models. 

Figure 1-12 

Drilling Fluid vs. Newtonian, Bingham, and Power Law Fluids 

A typical drilling fluid exhibits a yield stress and is shear thinning. At high rates of shear, all models 

represent a typical drilling fluid reasonably well. Differences between the models are most 

pronounced at low rates of shear, typically the shear rate range most critical for hole cleaning and the 

suspension of weight material. 



Revised 2006 1-17

Hydraulics 

The Bingham Plastic Model includes a simple yield stress, but does not accurately describe the fluid 

behavior at low shear rates. The Power Law Model more accurately describes the behavior at low 

shear rates, but does not include a yield stress and therefore can give poor results at extremely low 

shear rates. A typical drilling fluid actually exhibits behavior between the Bingham Plastic Model 

and the Power Law Model. This sort of behavior approximates the Herschel Bulkley model which is 

described below. 

Determination of n and K 

The Power Law constants n and K can be determined from any two sets of shear stress-shear rate data. 

Baker Hughes Drilling Fluids has chosen to follow API Bulletin 13D in developing n and K values 

from 300 rpm and three rpm V-G meter readings (initial gel shear rate is approximately equal to three 

rpm) for the low shear rate region, and 600 rpm and 300 rpm readings for the high shear rate range. 

The low shear rate region corresponds roughly to the shear rate existing in the annulus, while the high 

shear rate region corresponds to the shear rate existing in the drill pipe. This may be written in 

logarithmic form as, 

log τ = logK + n( log γ) 

A plot of shear stress versus shear rate on log-log paper is linear for a pseudo plastic fluid. As shown 

in Figure 1–13, the slope of the curve is equal to n, and the intercept on the shear stress axis at γ = 1 is 

equal to K (since log 1 = 0). 

Log Θ 600 

Log Θ 300 

n p 

Log Θ 600 

–Log Θ 300 

LOG DIAL READING, Θ 

Log K 

Log Θ 300 

–log Θ 3 

Log Θ 3 

n a 

n 

3 rpm 

Log 511 – log 5.11 

Log Θ 300 

–n a 

log 511 

300 rpm 

Log 1022 – log 511 

600 rpm 

n p 

log 1022 

Log Θ 600 

–n p 

log 1022 

n a 

log 511 

1 

10 100 1000 

SHEAR RATE, Ў 

Figure 1-13 

Determination of n and K 



1-18 Revised 2006


Table 1-1 shows the corresponding shear rate in reciprocal seconds to the V-G meter speed in rpm, 

with standard Rotor-Bob spring combination (R 1 -B 1 ). 

Table 1-1 

V-G Meter Speed and Corresponding Shear Rate 

V-G Motor Speed 

(rpm) 

Shear Rate ( γ ) 

(Sec 1 ) 

3 5.11 

6 10.2 

100 170 

200 341 

300 511 

600 1022 

We define n a and K a as the Power Law constants for the low shear rate range and n p and K p as the 

constants for the high shear rate range. From Figure 1–13, we find the slope (n a ) of the line between 

the dial readings at 300 rpm and 3 rpm. Since the slope of a line is equal to the “rise over the run” 

then, 

( log θ 300 – logθ 3 ) 

n a = ------------------------------------------- 

log 511 – log 5.11 

θ 300 

θ 3 

n a = 0.5log--------- 

K a may be obtained from Figure 1–12 by this equation. 

logK a = ( logθ 300 – n a log511) 

K a 

θ300 

= ------------ 

511 n a 

In a like manner, n p and K p are obtained as follows: 

n p 

log θ600 – logθ300 

= ------------------------------------------ 

log 1022 – log511 

n p = 3.32 log⎛ θ600 

--------- 

⎝ ⎠ 

⎞ 

θ 300 

logK p = ( logθ 600 – n p log1022) 

K p 

θ600 

= -------------- 

1022 n p 



Revised 2006 1-19

Hydraulics 

Other Models 

Three other mathematical models have been developed which, at low shear rates, exhibit behavior 

intermediate between that of the Bingham Plastic and Power Law Models. These models are, in 

effect, hybrid models of the Bingham Plastic and Power Law Models. These are the Casson Model, 

the Robertson-Stiff Model, and the Herschel-Bulkley Model. These mathematical models are 

represented by the equations where, 

Casson 


τ o = yield stress 

μ ∞ = plastic viscosity 


K = consistency factor 

γ o = shear rate intercept 

n = flow behavior index 

τ = [ τȯ 5 + ( μ ∞ γ ) .5 ] 2 

The Casson Model is a two-parameter model that is widely used in some industries but rarely applied 

to drilling fluids. The point at which the Casson curve intercepts the shear stress axis varies with the 

ratio of the yield point to the plastic viscosity. 

Robertson-Stiff 

τ = K( γ o + γ) n 

The Robertson-Stiff Model includes the gel strength as a parameter. The model is used to a limited 

extent in the oil industry. This model is one of the two options available for hydraulics calculations in 

ADVANTAGE Engineering. 

Herschel-Bulkley 

τ = τ o + K( γ 

n ) 

The Herschel-Bulkley Model is a Power Law Model that includes a yield stress parameter. The 

Herschel-Bulkley Model gives mathematical expressions which are solvable with the use of 

computers. As a consequence the Helschel Bulkley model is more widely used than previously as it is 

seen to more accurately describe most fluids than the simpler Power Law and Bingham models. 

Therefore, it is being widely used for hydraulics calculations both by Baker Hughes Drilling Fluids 

and other companies. Difficulties are still experienced making correlations between drilling fluid 

parameters measured in the field and hydraulic calculations. 



1-20 Revised 2006


Gel Strengths 

Gel strength measurements are made with the V-G meter and describe the time-dependent flow 

behavior of a drilling fluid. Gel strength values must be recorded at 10-second (initial gel) and 10- 

minute intervals. One additional gel strength value should be recorded at 30 minutes. Gel strengths 

indicate the thixotropic properties of a drilling fluid and are the measurements of the attractive forces 

under static conditions in relationship to time. Plastic viscosity and yield point, conversely, are 

dynamic properties and should not be confused with static measurements. However, gel strengths and 

yield point are somewhat related in that gel strengths will typically decrease as the yield point 

decreases. 

Gel strengths occur in drilling fluids due to the presence of electrically charged molecules and clay 

particles which aggregate into a firm matrix when circulation is stopped. Two types of gel strength 

occur in drilling fluids, progressive and fragile. A progressive gel strength increases substantially with 

time. This type of gel strength requires increased pressure to break circulation after shutdown. A 

fragile gel strength increases only slightly with time, but may be higher initially than a progressive 

gel. The NEW-DRILL ® system is characterized by fragile gel strengths that are high initially but are 

very fragile. f gel strength measurements are taken after a 30-minute time period, the progressive or 

fragile nature of the gel strengths can be easily determined. Progressive and fragile gel strengths are 

illustrated in Figure 1–14. 

Gel strength in a drilling fluid is dependent upon chemical treatment, solids concentration, time, and 

temperature. There is no well-established means of mathematically predicting gel strengths in any 

fluid system. Generally, gel strengths will increase with time, temperature, and increase in solids. If a 

fluid system is not sufficiently treated for temperature stability, the gel strength developed after a bit 

trip becomes a major factor in the pressure required to break circulation, and in the magnitude of swab 

and surge pressures. Additionally, initial gel strength in a weighted fluid system must be sufficient to 

prevent settling of weight materials. Therefore, the drilling fluids technician must be concerned with 

having sufficient initial gel strength, yet not having excessive long-term gel strength. 

Gel strengths assume great importance with regard to suspension properties under static conditions 

and when performing swab and surge analysis. When running a drill string or casing into the hole 

it is necessary to overcome the gel strengths. Gel strengths also affect the ability of a fluid to 

release entrained gases. At times it may be necessary to break circulation at intervals while 

running into the hole rather than to initiate flow in the entire wellbore at the same time in order 

to minimize the pressure spike to initiate circulation. 



Revised 2006 1-21

Hydraulics 

Figure 1-14 

Gel Strength Characteristics vs. Time 

Filtration 

Two types of filtration are considered in this section, static and dynamic. Static filtration occurs when 

the fluid is not in motion in the hole. Dynamic filtration occurs when the drilling fluid is being 

circulated. 

Dynamic filtration differs from static filtration in that drilling fluid velocity tends to erode the wall 

cake even as it is being deposited on permeable formations. As the rate of erosion equals the rate of 

build up of the wall cake, equilibrium is established. In static filtration, the wall cake will continue to 

be deposited on the borehole. 

Testing Equipment 

The standard API low-pressure filter press consists of a cylindrical cell three inches in I.D. and five 

inches high to contain the fluid. The bottom of the cell is fitted with a sheet of Whatman No. 50 filter 

paper. Pressure is applied to the top of the cell at 100 psi. The filtrate is collected over a period of 30 

minutes and recorded in cubic centimeters (to 0.1 cubic centimeters) as the API filtrate. 

The high temperature/high pressure (HT/HP) test is run at a temperature greater than ambient and a 

differential pressure of 500 psi for 30 minutes. The filtrate volume collected is doubled to correct it to 

the filter area of the API filtration test. The permeable medium used is the same as that used for the 

low temperature test. The filter cake should also be checked for thickness and consistency after the 

filtrate loss has been tested. 

Correlation between API standard fluid loss at 100 psi and ambient temperature and hightemperature/high-pressure 

test at 500 psi and 300°F depends on several factors. Cake 

compressibility and thermal stability of additives contained in a fluid are primary factors. 

Generally speaking, a well treated lignosulfonate / lignite / bentonite system may have a ratio 

between HT/HP and standard API filtrate test in the range of 2:1 to 4:1, whereas a system 

comprised of a high concentration of drilled solids may have a ratio of 10:1 or higher. Obviously, a 



1-22 Revised 2006


drilling fluid could exhibit a low API filtrate value at 100 psi and ambient temperature and an 

extremely high filtrate (thick wall cake) on the HT/HP test. For this reason, more emphasis is placed 

on HT/HP data on deeper wells encountering high bottom hole temperatures. 

Permeability of Filter Cake 

The permeability of the filter cake is one of the most important factors in controlling filtration. The 

size, shape, and concentration of the solids which constitute the filter cake determine the permeability. 

If the filter cake is composed primarily of coarse particles, the pores will be larger, therefore, the 

filtration rate greater. For this reason, bentonite with its small irregular shaped platelets forms a cake 

of low permeability. Bentonite platelets as well as many polymers compact under pressure to lower 

permeability, hence the term, cake compressibility. 

Pressure 

If the filter cake did not compress under pressure, the fluid loss would vary with the square root of the 

pressure. This does not normally apply to drilling fluids because the porosity and permeability of the 

filter cake is usually affected by pressure. 

A useful field check for determining cake compressibility is to measure HT/HP filtrate in the normal 

manner then test again with 100 psi differential pressure. The lower the compressibility ratio, 

⎛ cc at 500 psi ⎞ 

Compressibility Ratio = 

⎜ 

⎟ 

⎝ cc at100psi 

⎠ 

the more compressible the filter cake becomes. If the compressibility ratio is 1.5 or greater, it could 

indicate that colloidal fraction is inadequate and that remedial measures are necessary. 

Temperature 

An increase in temperature will usually result in an increase in filtration rate because of adverse 

temperature effects on filtration control agents and decreased fluid phase viscosity. 

Higher temperature may also increase the solubility of contaminants and, therefore, decrease the 

effectiveness of filtrate loss control chemicals. In addition, the colloidal fraction tends to flocculate 

and increase filtration at elevated temperatures. 

Deflocculation of the colloidal fraction can contribute significantly to filtration rate. In a flocculated 

system, colloidal solids cluster or aggregate, this increases cake porosity and permeability and allows 

more fluid to pass through the filter cake. Conversely, dispersion of colloidal solids results in a more 

uniform distribution of solids in the filter cake which reduces cake permeability and lowers filtration 

rates. Deflocculants such as UNI-CAL ® are beneficial as supplementary filtration control agents, 

particularly at elevated temperatures that are encountered with depth. 



Revised 2006 1-23

Hydraulics 

The theoretical change in filtrate, due to reduction of the viscosity of the filtrate as temperature is 

increased, can be expressed by the following equation: 

where, 

f 1 = f μ 

× --------- 

μ 1 

f = filtrate at a known temperature 

f l = filtrate at an elevated temperature 

μ = viscosity of water at known temperature 

μ 1 = viscosity of water at an elevated temperature 

The change in viscosity for water at various temperatures is noted in Table 1-2. 

Table 1-2 Viscosity of Water vs. Temperature 

Temperature Viscosity of Water 

(Centipoise) 

Temperature Viscosity of Water 

(Centipoise) 

°C °F °C °F 

0 32 1.792 40 104 0.656 

10 50 1.308 60 140 0.469 

20 68 1.005 80 176 0.356 

30 86 0.801 100 212 0.284 

(Data from Rogers, W. F.; Composition and Properties of Oil Well Drilling Fluids, Third Edition) 

For example, a fluid has a known filtrate of 6.0 mL at 86°F and 100 psi. It is desired to predict the 

resultant filtrate at 140°F with pressure constant. 

f 1 

f --------- 

μ 0.801 

= × = 6.0 × ----------------- = 6.0 × 

.895 --------- = 7.8 

.469 .685 

μ1 

Temperature changes of water-base fluid in the 80° to 140°F range will result in change of filtrate of 

approximately 10% for each 17°F change. Filtrate increases as temperature increases. 

Viscosity 

The viscosity of the fluid phase of the drilling fluid, which is the same as the viscosity of the filtrate, 

has a direct influence upon the filtration rate. The viscosity of filtrate, which is directly affected by 

temperature has been previously described. As the filtrate viscosity decreases, the filtration rate and 

total volume of filtrate measured increases. 

Filtrate viscosity is also affected by water soluble materials, particularly polymers. When polymers 

are added to the mud system, the viscosity of the fluid phase as well as the whole mud is increased, 

thereby reducing the filtration rate. The equations presented above may be used to predict the effects 

of water soluble polymers on the filtration rate. One must know, or have measured, the effects of 

polymer additions on the viscosity of the filtrate in order to make such predictions. 



1-24 Revised 2006


Time 

The calculation of filtrate loss at variable time intervals relative to known filtrate loss and time 

interval can be predicted by the following equation: 

where, 

f 1 

T 1 

= f × --------- 

T 

f = known filtrate at a time interval of T 

f l = unknown filtrate at a time interval of T 1 

For example, if fluid loss is 8.0 mL in 15 minutes, the predicted fluid loss in 30 minutes would be, 

f 1 = 8 --------- 

30 

8 

5.48 

× = × --------- = 11.3 m L 

15 3.87 

or if time is doubled, filtrate theoretically would be increased by 41%. It should be noted that the 

above equation would apply only under conditions where pressure, filtrate viscosity, and cake 

permeability remained constant and no changes in chemical contents occurred due to effect of 

temperature and/or flocculation. 

Summary 

Filtration rate is often the most important property of a drilling fluid, particularly when drilling 

permeable formations where the hydrostatic pressure exceeds the formation pressure. Proper control 

of filtration can prevent or minimize wall sticking and drag, and in some areas improve borehole 

stability. Filtration control poses a question that should be answered only after a thorough study is 

made based on past experience, predicted pressure differentials, lithology, formation protection 

requirements, and overall economics. 

Solids 

Quantity, type, and size of suspended solids in a drilling fluid is of primary concern in the control of 

rheological and filtration properties. Solids in a drilling fluid are comprised of varying quantities of 

weighting materials [MIL-BAR ® , DENSIMIX ® , and/or W.O. 30 (Calcium Carbonate)], commercial 

bentonite, drilled solids (sand and shale) and, in some cases, loss of circulation additives. Material 

balance equations help differentiate high-specific gravity solids from low-specific gravity solids when 

the total solids content is obtained from the retort. These materials balance equations are presented in 

Chapter 10, Mechanical Solids Control. 

Typically, the only high-specific gravity solid in a drilling fluid is the weight material, MIL-BAR ® , 

ORIMATITA ® or DENSIMIX ®. However, low-specific gravity solids are defined as all other solids 

except weight material. Low-gravity solids are comprised primarily of MILGEL ® , drilled solids and, 

in some cases, treatment chemicals. In the analysis of low-gravity solids, it will be assumed that any 

contribution from treatment chemicals is negligible. Therefore, the analysis of low-gravity solids 

distinguishes between the quantity of commercial bentonite added to a drilling fluid and the quantity 

of drilled solids incorporated into a drilling fluid. 

ADVANTAGE performs solids analysis based on the retort and titration results. If barite is not being 

used then the default value for the weight material should be changed to the appropriate density. 



Revised 2006 1-25

Hydraulics 

Cation Exchange Capacity (CEC) 

Commercial bentonite, other clays, and many chemicals exhibit a capacity to absorb a methylene blue 

solution (C l6 H l8 N 3 SCl•3H 2 O). A standardized methylene blue solution is outlined in API Bulletin RP 

13B-1. The testing procedure is described in the Fluid Facts Engineering Handbook. If the 

absorption effects of all treatment chemicals are destroyed by oxidation with hydrogen peroxide 

according to the test procedure, then the test results give the cation exchange capacity of only the 

commercial bentonite and other clays in the drilling fluid. 

As discussed in the section, Functions of Fluids, shales contain varying types and quantities of clays 

within their structure. Some shales contain clays with characteristics very similar to that of 

commercial bentonite, while other shales have relatively inert characteristics. 

These characteristics are defined as bentonite equivalent and are directly related to their cation 

exchange capacity. The term “bentonite equivalent” does not imply that the clays are bentonite. 

Therefore, the differences in cation exchange capacities of commercial bentonite and drilled solids 

allow the use of the methylene blue test (MBT) to distinguish between them. 

The cation exchange capacity of a fluid is reported as the methylene blue capacity as follows. 

cm 

Methylene blue capacity 

3 of methylene blue 

= ------------------------------------------------------------ 

cm 3 of fluid 

The methylene blue capacity is frequently reported as pounds per barrel equivalent (referring to 

bentonite equivalent) by, 

lbs m per bbl equivalent = 5 × methylene blue capacity 

This equation is based upon commercial bentonite having a cation exchange capacity of 70 milliequivalents 

(meq) of methylene blue per 100 g of dry bentonite. This is typically a high value for 

most commercial bentonite. Depending upon the quality of the bentonite, the cation exchange 

capacity will be in the range of 50 to 65 milli-equivalents of methylene blue per 100 g of dry clay. 

Therefore, for proper analysis of commercial bentonite and drilled solids, a correction must be made 

due to this difference. We know that the cation exchange capacity of the fluid is dependent upon the 

quantity (as well as quality) of total low-specific gravity solids in the fluid. 

The following equation can be written, 

CEC fluid 

= 

ml of methylene blue solution 

--------------------------------------------------------------------------------- 

grams of LGS 

In the MBT test, we use a volume of fluid and want to determine the total quantity of low-specific 

gravity solids. 

where, 

grams of LGS 

= 

vol % LGS 

---------------------------- ( m L o f f l ui d) ( ρ 

100 

LGS ) 

% LGS = low-gravity solids, (e.g., 5.5%) 

ρLGS = density of the low-gravity solids, g/cm3 

Substituting one equation into the other, you derive, 

CEC 

( 100) ( mL of solution) 

fluid = ----------------------------------------------------------------------------- 

(% LGS) ( mL of fluid) ( ρLGS) 



1-26 Revised 2006


Then, 

= 

100 mL of methylene blue 

---------------------------------------- × ---------------------------------------------------------- 

(% LGS) ( ρ LGS ) mL of fluid 

mL of methylene blue 

lb /bbl equivalent 5 

m 

= × ----------------------------------------------------------- 

mL of fluid 

or, 

mL of methylene blue 

----------------------------------------------------------- 

mL of fluid 

lb /bbl equivalent 

m 

= -------------------------------------------------- 

5 

Again, substituting one equation into another, you derive, 

100 

lb m 

/bbl equivalent 

CEC fluid = ---------------------------------------- × -------------------------------------------------- 

(% LGS) ( ρ LGS ) 

5 

20( lb /bbl equivalent 

m ) 

= ------------------------------------------------------------- 

(% LGS) ( ρLGS) 

The density of the low-gravity solids (ρ LGS ) is typically assumed to be 2.6 g/cm 3 . However, 

measurement of the density of the drilled solids at a particular location will provide a more accurate 

value. Therefore, replacing ρ LGS with 2.6 in the equation gives, 

7.69( lb /bbl equivalent 

m ) 

CEC fl uid 

= ------------------------------------------------------------------ 

% LGS 

The following notation is common: 

where, 

CEC avg 

7.69( MBT fluid ) 

= -------------------------------------- 

% LGS 

CEC avg = cation exchange capacity correction 

MBT fluid = methylene blue capacity, lb m / bbl equivalent 

% LGS = volume % of low-gravity solids (e.g., 6.1%) 



Revised 2006 1-27

Hydraulics 

Location 

Table 1-3 

Lost Hills, CA 

Alberta, Canada 

Denver, CO 

Assumption Parish, LA 

Eugene Island Blk 19, LA 

South LA (Gumbo) 

South LA (Tuscaloosa) 

St. James Parish, LA 

South Marsh Island 

Blk 244, LA 

Ship Shoal Blk 332, LA 

Ship Shoal Blk 332, LA 

St. Landry Parish, LA 

St. Landry Parish, LA 

Vermilion Blk 190 LA 

Barzoria County, TX 

Chambers County, TX 

East TX (Midway) 

South TX (Anhuac) 

East Breaks Blk 160, TX 

East Breaks Blk 160, TX 

Centre County, PA 

Teton, WY 

Commercial Bentonite, WY 

North Sea (Gumbo) 

Typical CEC Values 

Depth of 

Sample (ft) 

-- 

6,150 

-- 

9,050 

11,000 

3,000 

19,300 

14,500 

9,800 

4,000 

11,000 

9,000 

20,000 

10,600 

-- 

-- 

7,800 

8,900 

9,300 

4,700 

-- 

-- 

-- 

-- 

5,200 

CEC (meq / 

100g) 

3 

5 

13 

22 

18 

34 

5 

22 

21 

16 

17 

18 

5 

21 

13 

25 

12 

34 

20 

22 

1 

14 

60-70 

32 



1-28 Revised 2006


Low-Gravity Solids Analysis 

As previously stated, the differences in cation exchange capacities of commercial bentonite and 

drilled solids allows the use of the methylene blue test to distinguish between them. From the earlier 

equations, we can deduce that, 

or 

where, 

Error! Objects cannot be created from editing field codes. 

Methylene BlueCapacity = 

+ 

mL of methyleneblue 

g of drilled solids 

mL of methyleneblue 

g of bentonite 

( ρ ) 

⎛ vol % drilled solids ⎞ 

( ρ ) ⎜ 

⎟ 

⎠ 

drilled solids 

ρ bent = density of bentonite, g/cm 3 

ρ drilled solids = density of drilled solids, g/cm 3 

⎝ 

100 

The following rewrites the equation in terms of cation exchange capacities, 

Methylene blue 

capacity 

bent 

vol % Bentonite 

= ( CEC bent )( ρ bent ) ⎛------------------------------------------ 

⎞ 

⎝ 100 ⎠ 

vol % drilled solids 

+ ( C EC DS )( ρ DS ) ⎛--------------------------------------------------- 

⎞ 

⎝ 100 ⎠ 

The equation can be rewritten as, 

M ethylene blue 

capacity 

vol % LGS 

= ( CEC avg )( ρ LGS ) ⎛---------------------------- 

⎞ 

⎝ 100 ⎠ 

Then, equating the two equations above, you have, 

⎛ vol % bentonite 

⎜ 

⎝ 100 

vol % LGS 

( CE C avg )ρ ( LGS ) ⎛---------------------------- 

⎞ vol % Bentonite 

= ( CEC 

⎝ 100 ⎠ bent )( ρ bent ) ⎛------------------------------------------ 

⎞ 

⎝ 100 ⎠ 

vol % drilled solids 

+ ( CEC DS )( ρ DS ) 

⎛----------------------------------------------------⎞ 

⎝ 100 ⎠ 

We have previously defined low-gravity solids as comprised of commercial bentonite and 

incorporated drilled solids, or, 

which can be written, 

% LGS = % Bentonite + % DS 

% DS = % LGS – % Bentonite 

Making further equation substitutions, you see that, 

( CEC avg )ρ ( LGS ) ⎛ % ------------------ 

LGS ⎞ % Bentonite 

= ( CEC 

⎝ 100 ⎠ bent )( ρ bent ) ⎛--------------------------------- 

⎞ 

⎝ 100 ⎠ 

⎞ 

⎟ 

⎠ 



Revised 2006 1-29

Hydraulics 

% LGS % Bentonite 

+ ( CEC DS )( ρ DS ) ⎛--------------------------------------------------------- 

– ⎞ 

⎝ 100 ⎠ 

Solving for % Bentonite gives, 

% Bentonite 

% L GS[ ( CEC avg )( ρ LGS )– 

( CEC DS )( ρ DS )] 

= ---------------------------------------------------------------------------------------------------------------------- 

( CEC bent )( ρ bent )( CEC DS )( ρ DS ) 

If we again assume that all low-gravity solids have a density of 2.6 g/cm 3 then, 

% Bentonite 

% LGS( CEC – CEC avg DS ) 

= ----------------------------------------------------------------------- 

CEC – CEC bent DS 

To convert the volume % Bentonite to pounds per barrel, 

lb /bbl Bent onite = % Bentonite 

m ( )( 9.1) 

After the volume % drilled solids is found, conversion is made to pounds per barrel, 

Summary 

lb m 

/bbl DS 

= (% DS) ( 9.1) 

The solids analysis equations in this and other chapters are based upon numerous assumptions and test 

results from a fluid check. The potential errors are obvious; however, systematic use of these 

assumptions and test results will provide information during the drilling operation in which trends 

should be analyzed rather than a single value. In some cases, wrong assumptions or poor testing can 

lead to erroneous calculated values. 

CEC values for the bentonite and drilled solids should be measured whenever possible. However, 

when measurements are not possible, assume CEC bent to be 60 milli-equivalents (meq) per 100 g. 

Table 1-3 can be used to find a typical value for CEC DS in the region. 

Drilling Fluids pH and Alkalinity 

The pH of a drilling fluid may be defined as the negative logarithm of the hydrogen ion (H + ) 

concentration. At any particular hydrogen ion (H + ) concentration, there is a corresponding hydroxyl 

ion (OH – ) concentration which will result in equilibrium. The hydrogen ion represents the acidic 

portion and the hydroxyl ion the alkaline or basic portion of the solution. Freshwater normally has an 

equal concentration of hydroxyl and hydrogen ions and a pH near 7, which indicates a neutral 

condition. Addition of a basic material such as caustic or lime would increase (OH – )concentration 

and pH, whereas an acid would increase (H + ) concentration and reduce the pH. The maximum 

concentration of hydroxyl ions would result in a pH of 14, whereas the maximum concentration of 

hydrogen ions would result in a pH of 0. 

The pH of a drilling fluid is determined either by the colorimetric method or the electrometric 

method. The colorimetric method utilizes chemically-treated pHydrion paper which is placed on the 

fluid's surface until a color change is noted. The color observed is matched with a color chart on the 

side of the dispenser. If the salt concentration is greater than 16,000 mg/l Cl¯, pH paper is not 

recommended. The electrometric procedure employs a pH meter with a glass electrode. Although 

more accurate than pHydrion paper, it is quite sensitive to shock and difficult to maintain under field 

conditions. 



1-30 Revised 2006


The pH of many water-base drilling fluid systems is maintained in the 9.5 to 10.5 range for 

the following reasons: 

• Organic dispersants and filtration control agents generally achieve maximum effectiveness in an 

alkaline environment. 

• Adverse effects of contaminating electrolytes are usually minimized at higher pH levels. 

• Corrosion rates can be reduced at higher pH levels and bacterial action on organic materials is 

retarded at elevated alkalinity levels. 

• Thermal stability of lignosulfonate systems may be improved at a pH of 10.0 or above. 

The pH ranges of some of the more common water-base fluid systems are shown in Table 1-4. 

Table 1-4 

Type System 

UNI-CAL ® , Freshwater 

UNI-CAL ® , Seawater 

UNI-CAL ® , Gypsum 

NEW-DRILL ® 

Lime-Base 

BENEX, Low-Solids 

Saturated Saltwater 

KCl Systems 

Fluid System pH Ranges 

pH Range 

9.0 - 11.5 

10.0 - 11.5 

9.0 - 10.0 

8.5 - 10.0 

11.5+ 

9.0 - 10.0 

9.5 - 11.5 

10.0 - 11.5 

Note: 

Increasing concern with corrosion control has led to higher pH values. Usually, pH values 

below 10.5 are compatible with most shales drilled, however, there are some shales which 

exhibit poor stability in the presence of excess hydroxyl ions. UNI-CAL ® systems function 

effectively over a broad pH range and have been run as low as 8.0 to 8.5 to improve shale 

stability. 

Approximate pH of some common fluid additives are listed in Table 1-5 



Revised 2006 1-31

Hydraulics 

Table 1-5 

Typical pH Levels of Some Common Drilling Fluid Additives 

Material 

PH 

CHEMTROL ® 

9.0 

LIGCO ® 

4.5 

LIGCON ® 

9.5 

NEW-DRILL ® 

8.7 

UNI-CAL ® 

4.5 

SAPP 

4.8 

Sodium Bicarbonate (NaHCO 3 ) 

8.3 

Sodium Carbonate (Na 2 CO 3 ): soda ash 

11.0 

Sodium Hydroxide (NaOH): caustic soda 

13.0 

Calcium Hydroxide (CaOH 2 ): lime 

12.0 

Calcium sulfate dihydrate (CaSO 4 H 2 O): gypsum 

6.0 

Potassium Hydroxide (KOH): caustic potash 

12.8 

MIL-BAR ® 

7.0 

MILGEL ® 8.0 

The alkalinity of a solution is related to pH since alkalinity is the measure of the quantity of an acid 

needed to reduce the pH of a filtrate to a particular value. The two common filtrate alkalinities 

utilized in fluid analysis are P f and M f . P f alkalinity is the volume of N/50 (0.02 normal solution) 

sulfuric acid required to reduce the pH of 1 cc of filtrate to 8.3. The end point is noted when the 

phenolphthalein indicator solutions changes from pink to colorless. 

M f is the quantity of N/50 sulfuric acid required to reduce the pH of 1.0 cc of filtrate to 4.3. The end 

point is obtained when a methyl orange indicator solution changes from orange to salmon pink or red. 

If the sample color is obscured with organic materials, the pH can be determined with a glass 

electrode pH meter. 

If there were no interfering ions present, the P f and M f alkalinities could be used to calculate the 

amounts of OH¯, CO = 3 , and HCO 3¯ ions present in the filtrate. However, the presence of organic acids 

or buffering ions cause the M f determination to indicate more CO = 3 and HCO 3¯ ions than actually 

present. This is the usual case in fluid filtrate, and the M f determination is only a very rough indicator 

of the CO = 3 and HCO 3¯ions present. As a general guide, M f values above 5 mL indicate that excessive 

amounts of CO = 3 and HCO 3¯ ions are probably present in the fluid. 

When excessive concentrations of CO = 3 and HCO 3¯ are suspected, another titration procedure, as 

shown in the Measurement of Carbonates (p 2-87 Water-Base Fluid Systems) in the Fluid Facts 

Engineering Handbook, can be used to determine their concentrations. 

Another alkalinity measurement (Pm) is made with the whole fluid rather than filtrate. This test (refer 

to Fluid Facts Engineering Handbook for details) is made in a manner similar to the P f test and is used 

primarily to determine concentrations of lime and cement being carried as solids in the system. 

Because it has limited solubility, considerable cement may be carried as a solid which tends to 

replenish calcium and hydroxylions as they are used up. This can be a problem when it is necessary 

to calculate the quantity of treating agent to neutralize the cement. 



1-32 Revised 2006


Example Calculations 

Parameters 

Exercise 

Table 1-6 

Fluid Parameters for Exercise Problem 

Fluid Properties 

Fluid Weight, lbm/gal 15.5 

Retort Analysis 

Solid, % 30 

Oils, % 0 

Water, % 70 

MBT, lb m / bbl equivalent 15.0 

Chlorides, ppm 21,000 

CEC bent 

CEC DS 

Measurement 

Calculation 

63 meq/100 g 

16 meq/100 g 

% LGS 5.9% 

Perform the steps and calculations to show that this is the correct value for % LGS. Find the % 

Bentonite and % DS in the fluid and the corresponding pounds per barrel of each. 

1. Make the cation exchange capacity correction. 

CEC avg 

= 

7.69( MBT fluid ) 

-------------------------------------- 

% LGS 

= 

7.69( 15.0 

------------------------- 

) 

= 19.55 meq/100 g 

5.9 

2. Find the % Bentonite. 

% LGS( CEC avg – CEC DS ) 

% Be ntonite = ------------------------------------------------------------------- 

CEC bent – CEC DS 

3. Find the pounds per barrel of Bentonite. 

= 

5.9(19.55 – 16) 

------------------------------------ = 0.45% 

63 – 16 

4. Find the % drilled solids. 

lb /bbl Bentonite = % Bentonite 

m ( )( 9.1) = ( 0.45) ( 9.1) = 4.1 lb /bbl m 

% DS = % LGS – % Bentonite = ( 5.9 – 0.45) = 5.4% 

5. Find the pounds per barrel of drilled solids. 

lb m 

/bbl DS 

= 

(% DS) ( 9.1) = ( 5.45) ( 9.1) = 49.6 lb m 

/bbl 

Notice that the quantity of Bentonite is relatively low. This is very typical of the NEW-DRILL ® 

system. 



Revised 2006 1-33

Hydraulics 

Drill-In Fluids 

Function 

A drill-in fluid must possess the desirable properties of a good drilling fluid, as discussed earlier, and 

provide the necessary attributes of a completion fluid. The primary function of a drill-in fluid is to 

develop a filter cake which effectively prevents formation damage (production impairment) and which 

is easily removed. As a standard, a drill-in fluid, like the drilling fluid itself, must provide lubricity, 

inhibition, solids suspension, and well bore stability. 

Development 

Formation protection is critical while drilling the production zone since damage to the formation can 

adversely affect the well’s production potential. This pay zone damage is minimized with the use of 

drill-in fluids - specialized fluids for “drilling in” and protecting oil/gas producing formations. 

Damage to the pay zone, including fine solids migration into the formation permeability channels, 

clay swelling within the formation pore spaces, and irreversible reactions with invading polymers, 

reduce the average permeability of the formation, resulting in lower production rates. Most formation 

damage caused by conventional drilling fluids is by fluid invasion containing barite, finely ground 

drill solids, and/or bentonite. Drill-in fluids have reduced the use of such non-acid soluble products 

across the pay zone. 

Attributes 

A non-damaging drill-in fluid should ideally possess the following characteristics: 

Easily removable filter cake 

Acid soluble bridging agents 

Bridging agents sized for flow-back through the designed completion process 

Exhibit excellent fluid loss control 

Temperature stability 

Excellent lubricity 

Provide inhibition 

The reservoir drill-in fluid is designed to protect the pay zone during well bore construction, simplify 

the clean-up process, and maximize production rates. 

Screening and Selection 

Selecting a reservoir drill-in fluid for a specific application to satisfy each of the above criteria must 

involve laboratory testing of the candidate fluids using the following screening parameters. 

Leak-off control tests 

Net breakout pressure determination 

Return permeability tests 

Fluid-fluid interactions 

Drill-in fluid properties 

Environmental considerations 



1-34 Revised 2006


Using these screening parameters will yield a designed drill-in fluid that will create a filter cake which 

will mechanically seal off all pore openings exposed to the well bore, remain intact during the 

completion phase, and be easily removed for the production (or injection) of oil and/or gas. 

The Proposed Drill-In and Completion Program 

Prior to testing and recommending a drill-in fluid, fundamental details about an operator’s reservoir 

must be known. Recording information on the items listed below will assist those involved to decide 

what application exists and which fluid should be selected for that application. 

Local Environmental Regulations 

Reservoir Characteristics 

Reservoir fluid composition (oil, gas, or formation water) 

Lithology (sandstone, limestone, etc.) 

Cementation (consolidated, unconsolidated, fractured) 

Quantity and type of clays present 

Operator Recommendation/Plan 

Slim or large hole 

Completion technique (gravel pack, non-gravel pack) 

Hole geometry (horizontal, vertical, or high-angle) 

Note: 

To learn more about the effects of a drill-in fluid on a particular type of completion, refer to 

the Baker Hughes Drilling Fluids Drill-In Fluids Manual 

As previously listed, the drill-in fluid must be subjected to the following testing to ensure adequate 

protection of a producing reservoir. 



Revised 2006 1-35

Hydraulics 

Leak-Off Control Tests 

Permeability Plugging Test Apparatus 

Spurt and cumulative leak-off into a producing reservoir is a concern because of its effect on 

permeability. Altering the chemistry and/or disturbing in-situ particles in a producing zone are the 

most common formation damage mechanisms, and must be controlled. Control of filtrate loss into a 

producing formation is an important factor to consider when designing a drill-in fluid. 

The Permeability plugging test apparatus helps determine the bridging characteristics of the drill-in 

fluid. A low initial spurt filtration and low final filtration are desirable. 

Net Breakout Pressure Determination 

Breakout Pressure 

The ability to deposit a filter cake that is easily removed when the reservoir is produced is a major 

attribute of drill-in fluids. Some drill-in fluids deposit filter cakes that are easily removed by flowing 

the well, while other deposits require remedial treatments to remove skin damage. Net breakout is the 

difference in pressure required for oil flow before fluid-off or “mud-off” (recorded while determining 

initial permeability) and the pressure required to initiate flow after fluid-off. Determining the net 

breakout pressure before and after acidizing is useful in selecting a drill-in fluid. 

A fluid that requires little or no procedural clean-up after drill-in is superior to one involving a series 

of specialized steps to remove the filter cake. 

Return Permeability Tests 

Hassler Cell Permeameter 

This test procedure determines the effect a drill-in fluid has on reservoir permeability. The return 

permeability set-up is designed to simulate flow through a core sample under downhole conditions. 

The set-up allows flow through a core (or simulated core) from two opposite directions under 

controlled temperature and pressure. 

A high-percentage return permeability indicates minimum formation damage. 

Sandpack Permeameter 

This test procedure determines the effect of a drill-in fluid on an unconsolidated sand reservoir. The 

return permeability set-up is designed to simulate flow through a core sample under down hole 

conditions. The set-up allows flow through a core (or simulated core) from two opposite directions 

under controlled temperature and pressure. A high-percentage return is desirable. 



1-36 Revised 2006


Drill-In Fluid Properties 

Static Filtration 

Test seeks to find the filtrate volume and the quality of the filtrate cake. Although evaluating filter 

cake quality is generally limited to estimating the thickness of the cake, other properties such as 

lubricity, erodibility, and texture must be considered. 

Lubricity Testing 

Lubricity testing evaluates the lubricating qualities of drilling fluids. The different test procedures 

measure the coefficient of friction characteristics of a fluid. These tests can measure the coefficient of 

friction between two metal surfaces, or between a metal surface and a piece of rock. Since drill-in 

fluids can be used to drill horizontal or highly deviated well bores, the coefficient of friction can be a 

critical issue when selecting an applicable fluid. 

Particle Size Distribution 

Effective bridging of a reservoir depends upon both the particle size distribution of materials 

comprising the drill-in fluid and the pore throat diameters of the reservoir rock. A bridging material is 

chosen by matching its size to the diameter of formation pore throats. The industry-accepted rules for 

selecting size and concentration of bridging materials are based upon work carried out by A. Abrams, 

“Mud Design to Minimize Rock Impairment Due to Particle Invasion”, SPE 5713, 1977, and include 

the following: 

The medium particle size of the bridging additive should be equal to or slightly greater than one-third 

the medium pore size of the formation. 

The concentration of the bridging solids must be at least 5% by volume of the solids in the final fluid 

mix. 

Once the mean pore diameter is known, the particle size distribution of the bridging solids must be 

measured and adjusted to meet the required specifications and included in the drill-in fluid 

formulation. 

An alternative method of determining optimal particle size distribution is to use the ideal packing 

theory. This theory determines a particle size distribution based on sealing the pore sizes over a total 

range, including pore spaces created by bridging agents. 



Revised 2006 1-37

Hydraulics 

Shale Inhibition (Wafer Test) 

The shale wafer test measures the disintegrative properties of particular shale in contact with a drilling 

fluid or liquid composition over a measured period of time. Knowledge of shale disintegration 

tendencies is important because of their effects on drilling fluid properties in actual field use. 

Incorporation of unwanted drill solids into the fluid negatively impacts the rheological properties of 

the system, reduces rates of penetration, produces poor filter cake quality, increases dilution rates and 

potential pore throat plugging that cannot be cleaned up. 

Shale disintegration, as defined in this test procedure, is measured and recorded in four ways: 

3. Weight recovery in weight percent 

4. Shale hydration in weight percent 

5. Change in shale wafer hardness 

6. Increase or decrease in shale wafer volume 

This test compares results of one fluid to another. It is one of several tests providing information on 

the interaction of a fluid in contact with a given shale. This testing is important for the design of 

reservoir drilling fluids that will ensure well bore stability and maximum fluid stability. 

Density (API Standard Practice 13B-1, June 1990) 

This test procedure determines the weight of a given volume of liquid. Fluid weight may be 

expressed as pounds per gallon (lb m /gal), pounds per cubic foot (lb m /ft 3 ), kilograms per cubic meter 

(kg/m 3 ), or specific gravity. Density is designed to meet well bore pressure requirements. 

Fluid Viscosity 

A viscometer is a mechanical device used to measure viscosity at varying shear rates. Viscosity and 

gel strength measurements relate to the flow properties of fluid. From the viscometer readings 

rheological parameters may be determined. Rheology is the study of deformation and flow of matter. 

Hole size, hole angle, and formation type determine optimal rheological properties. 

Water, Oil and Solids 

The retort instrument provides a means for separating and measuring the volumes of water, oil, and 

solids contained in a sample of fluid. In the retort, a known volume of a whole mud sample is heated 

to vaporize the liquid components which are then condensed and collected in a graduated receiver. 

Total volume of solids (suspended and dissolved) is obtained by subtracting the liquid volume from 

the total sample volume. Calculations are necessary to determine the volume of suspended solids 

since any dissolved solids will be retained in the retort. The relative volumes of low-gravity solids 

and weighting material can also be calculated. Knowledge of the solids concentration and 

composition is considered basic to viscosity and filtration control in reservoir drill-in and drilling 

fluids. 



1-38 Revised 2006


MBT (Methylene Blue Titration) 

Methylene Blue Testing provides field measurement of the reactive clay content of a drilling fluid. 

The PERFFLOW ® DIF system is formulated with no reactive clays. Minimal clay content in the 

system is desired so as not to promote any damage to the reservoir. 

PH (API 13B-1) Field measurement of drilling fluid (or filtrate) pH and adjustments to the pH are 

fundamental to drilling fluid control. Clay interactions, solubility of various components and 

contaminants, and effectiveness of additives are all dependent on pH, as are the processes that control 

acid and sulfide corrosion. 

Note: 

See Donvan, J. P. and Jones, T. A.,“Specific Selection Criteria and Testing Protocol 

Optimize Reservoir Drill-In Fluid Design”, SPE 30104, May 1995 for a more detailed 

discussion of drill-in fluid selection and testing 

Filter Cake Formation and Dispersability 

Fluid loss or leak-off is effectively controlled by bridging the pore openings with rigid or semi-rigid 

particles of sufficient size and number. However, in order to ensure that the filter cake can be 

effectively removed after placing the well in production, it must meet two important requirements: 

The fluid must possess the right particle size distribution and particle concentration to build a filter 

cake that will quickly and effectively bridge the pore openings. 

The fluid must deposit a filter cake that is highly dispersive to the produced fluid. A quick and 

effective particle bridge will limit particle invasion to maximize return permeability. In addition, a 

highly dispersive cake will be removed by the production fluids, thus requiring no acidizing or 

treatment with breakers. 

The scanning electron microscope is a very useful tool to guide the selection of the bridging materials 

since one can obtain a microscopic picture of the filter cake in place. Figure 1-15 shows a 

photomicrograph of a PERFFLOW ® filter cake on a 3-Darcy filter media. These are lateral or crosssectional 

views of the cake deposited on the filter surface. Note the clean delineation between the 

filter cake on the left and the surface of the permeable rock. Intrusion of calcium carbonate bridging 

particles has been limited to the first few micrometers of the rock surface. 



Revised 2006 1-39

Hydraulics 

Figure 1-15 

SEM Photomicrograph X 150 – 2% PERFFLOW ® Filter Cake on AF-6 

Figure 1-16 shows a photomicrograph of a cross section of a filter cake on a filter media with 24- 

Darcy permeability. In Figure 1-16 the particles have formed an internal bridge in a pore opening that 

is approximately 20 micrometers in diameter but, even in this size opening, the intrusion is only about 

50 micrometers 

Figure 1-16 

SEM Photomicrograph 2% KCl PERFFLOW ® – Pore Bridging 



1-40 Revised 2006


At differential pressures in excess of 200 psi, the calcium carbonate bridging particles can form strong 

adherence between them and be very difficult to disperse and remove from the filter surface. The 

dispensability of these particles can be greatly increased by placing a parting agent or barrier between 

them during cake formation. One of the most effective methods of accomplishing this is to coat the 

particles with certain organic water soluble polymers prior to filtration. This has been accomplished 

in the PERFFLOW ® systems as evidenced by the high return permeability results. 

Figure 1–17 shows a photomicrograph of filter cake from a 17 lb m /gal PERFFLOW fluid while that of 

a sized salt fluid is shown in Figure 1–18. Note the granular and irregular packing of the calcium 

carbonate particles in Figure 16. In contrast, note the highly oriented cubic salt crystals in Figure 

1-18. This difference in packing will result in much less surface area for particle adhesion in the 

calcium carbonate cake. This appears to be a major factor in the ease of dispersability of the 

PERFFLOW filter cake upon production as compared to the sized salt filter cake. 

Figure 1-17 

SEM Photomicrograph – 17 lb/gal PERFFLOW 



Revised 2006 1-41

Hydraulics 

Figure 1-18 

SEM Photomicrograph - Sized Salt System 

Return Permeability vs. Breakout Pressure 

The following example shows that fluids with similar leak off or fluid loss characteristics can exhibit 

extremely different return permeabilities and net breakout pressures. This example relates the 

importance of complete system analysis before utilization and possible reservoir impairment. 

Return Permeability is a measure of that permeability that can be re-established after a core has been 

damaged by the flowing of a fluid through it and then being reversed out. Net Breakout Pressure is 

the maximum pressure required to initiate flow after mudoff. Mudoff is defined as the condition 

where a mud filter cake has been deposited on the face of and a short distance into the formation. 

Figure 1-19 describes the relationship that exists between return permeability and net breakout 

pressure. Note that the lower the net breakout pressure, the higher the percent return permeability 

value. This is indicative of a minimum of formation damage having occurred from the invasion of 

mud solids. 

100 

80 

60 

40 

20 

% Return Permeability 

Specification : 

Net Breakout Pressure = < 8 psi 

Net Breakout Pressure, psi 

0 

0 10 20 30 40 50 60 70 80 90 100 

Figure 1-19 

A Plot of Net Breakout Pressure vs. Return Permeability 



1-42 Revised 2006


Figure 1-20 and Figure 1-21 compare the results of two different systems formulated with 

PERFFLOW vs. those with the TBC salt system on return permeability and net breakout pressure. 

The PERFFLOW ® DIF (drill-in fluid) system’s bridging agent design and unique polymer chemistry 

form a thin filter cake protect the pay zone from damage caused by fluid invasion. The filter cake is 

efficiently removed by low breakout pressures, leaving no residual material to inhibit the well’s 

productivity. 

Using PERFFLOW ® 

Figure 1-20 

The Effects of PERFFLOW ® on Return Permeability and Breakout Pressure 

Using the TBC Salt System 

Figure 1-21 

Effects of TBC Salt System on Return Permeability and Breakout Pressure 



Revised 2006 1-43

Hydraulics 

Completion Fluids 

Definition 

By definition, workover or completion fluids are fluids placed across the producing zones before or 

immediately after perforating, or any fluid placed across the formation during reworking, underreaming, 

drill-in, or gravel pack operations. These fluids help ensure that production is consistent 

with the expected potential of the well. 

Function 

The primary functions of completion/workover fluids are to: 

provide pressure control by preventing formation fluids from entering the borehole 

maintain borehole stability 

minimize formation damage 

control fluid loss with minimal solids invasion 

These fluids also keep the borehole “clean” of perforation debris, solids such as drill cuttings, sand, 

etc., or any other contaminants by providing a transportation medium that for circulating loose 

material to the surface. 

Attributes 

A completion/workover fluid must possess the following attributes: 

• enough density to control subsurface pressures 

• enable efficient solids removal during circulation through filtration systems 

• stable, nontoxic, low corrosivity, and bacterial growth retardant 

• non-reactive to other soluble salts, minerals, cement, etc. 

• retain desirable properties such as viscosity and other physical properties under prolonged 

exposure to high shear 

• readily degas 

Mechanisms for Formation Damage 

For a well to be profitable, the reduction of virgin permeability should be minimized. Permeability 

can be reduced by the invasion of foreign liquids and/or solids into the near well bore region. This 

hampered permeability or damaged zone is known as a skin effect. 

A critical function of completion fluids is to contain formation pressures. To accomplish this, 

hydrostatic pressure must be higher or equal to the pressure of the formation. Consequently, if the 

hydrostatic pressure is higher, the fluid would allow a certain amount of solids and liquids to be lost to 

the formation. 



1-44 Revised 2006


Primary Factors Causing Formation Damage 

Solids Invasion 

Solids can enter or penetrate the producing zone due to differential pressure placed across the interval. 

These solids can plug internal pores and flow channels, thus increasing the potential for formation 

damage. Factors which influence the migration or entrance of particles into the formation are as 

follows. 

Size and shape of particulates 

Permeability and porosity of the formation 

Differential pressure applied 

Compressibility or incompressibility of solids 

Generally, compressible solids such as polymers can be more damaging because they tend to deform 

the shape of the pore throat, thereby building an internal bridge that could eventually seal off pore 

channels connecting the pore spaces. Incompressible solids, on the other hand, become wedged, thus 

leaving some communication between the pore spaces. Also, depending on the size, quantity, and 

shape, an instantaneous bridge could occur at the pore openings, thus delivering minimal invasion of 

particulates. 

Filtrate Invasion, Hydration Inhibition, and Emulsions 

Producing zones are seldom homogeneous; therefore the detrimental effects of filtrate invasion are 

often encountered. The most frequent effect is the alteration of clays by the influx or invasion of 

freshwater. Freshwater can cause damage by the hydration and swelling of clays in the rock matrix, 

thus causing particle plugging by clay dispersion. Freshwater can cause further damage by increasing 

pore channel capillary pressure or by creating an emulsion block. 

Smectite or montmorillonite is the most important clay mineral associated with swelling. This clay is 

capable of expanding by interlayer adsorption of water and can expand as much as 10 times its normal 

occupied volume. The degree of swelling is dependent upon the type of cation present within the 

interlayer. Thus, introducing an appropriate type and quantity of cation can reduce the amount of 

swelling a particular clay undergoes. 

This reduction occurs because the positive ions have a stronger attraction or force on the negatively 

charged surfaces of the silica and alumina particles than the displaced ion. This base exchange can be 

induced by either the introduction of highly active cations, the mass action of cations, or cations with 

sufficient size to fill all available bonding sites with the structure of the clay. Thus, understanding the 

mechanisms of cation exchange is beneficial in minimizing formation damage by the hydration of 

clays within the pore throats of producing zones. 

Note: 

See Chapter 3, Water Base Fluids and Chapter 7, Borehole Problems, for a thorough 

explanation of formation clays and their associated properties. 

In addition to formation damage, freshwater invasion can cause the misinterpretation of logs, coring 

samples, and drillstem tests. 



Revised 2006 1-45

Hydraulics 

Fluid Loss 

In general, completion fluids are used to create hydrostatic pressures greater than the pore pressures of 

permeable producing zones. The completion fluid invades the permeable zone. The degree of 

invasion is dependent on the amount, size, and type of solids present in the fluid and the type of 

porosity in the permeable zone. When losses of whole fluid to the formation occur, the situation is 

referred to as lost circulation, either total, severe, partial, or seepage. These terms denote the severity 

of loss, although any loss of whole fluid or any degree of invasion of solids or liquids into producing 

zones is considered undesirable. 

Controlling fluid loss is important for preventing the impairment of production and the loss of 

expensive completion fluids during workover, drill-in, and gravel pack operations. The selection and 

use of fluid loss control media and methods should be carefully considered prior to any drilling 

operation. 



1-46 Revised 2006


Nomenclature 

A 

Area 

CEC 

Cation Exchange Capacity 

CEC bent 

CEC DS 

CEC fluid CEC avg 

D 

f 

f l 

F 

K 

K a 

K p 

lb m / bbl 

MBT m 

n 

n a 

n p 

Cation Exchange Capacity, bentonite 

Cation Exchange Capacity, drilled solids 

Bentonite correction 

Diameter 

Filtrate, known temperature 

Filtrate, elevated temperature 

Force 

Consistency factor 

Consistency factor, annular 

Consistency factor, pipe 

Pounds per barrel 

lbm / bbl equivalent of methylene blue capacity 

Flow behavior index 

Flow behavior index, annular 

Flow behavior index, pipe 

% Bentonite Volume % of bentonite 

% DS Volume % of drilled solids 

% LGS Volume % of low-specific gravity solids 

PV 

Plastic Viscosity 

Re 

Reynolds number 

T 

Time interval 

V 

Velocity 

YP 

Yield Point 

g 

Shear rate 

μ 

Viscosity 

μ a 

μ e 

μ ∞ 

μ 1 

ω 

ρ 

ρ bent 

ρ DS 

ρ LGS 

τ 

τ o 

θ 

θ 3 

θ 300 

θ 600 

Viscosity, apparent 

Viscosity, effective 

Plastic viscosity 

Viscosity, elevated temperature 

Rotation speed 

Density 

Density, bentonite 

Density, drilled solids 

Density, low-gravity solids 

Shear stress 

Yield stress 

Dial reading, viscometer 

Dial reading, 3 rpm (initial gel) 

Dial reading, 300 rpm 

Dial reading, 600 rpm 



Revised 2006 1-47

Hydraulics 

References 

1. DeNevers, N., Fluid Mechanics, Addison-Wesley Publishing Company, 

1977. 

2. Gray, G. R. and Darley, H. C. H., Composition and Properties of Oil 

Well Drilling Fluids, Gulf Publishing Company, 1979. 

3. Outmans, H. D., Mechanics of Static and Dynamic Filtration in the 

Borehole, SPE Transaction, 1963. 

4. Standard Procedure for Testing Drilling Fluids, API RP 13B-1, Second 

Edition, September 1997, American Petroleum Institute, Dallas. 

5. Theory and Application of Drilling Fluid Hydraulics, A Reference 

Manual, Exploration Logging, Inc., Sacramento, California, July 1983. 

6. Williams, M. and Cannon, G. E., Evaluation of Filtration Properties of 

Drilling Muds, API, Drilling and Production Practice, 1938. 



1-48 Revised 2006

Formation Mechanics 

Chapter 

Two 

Formation Mechanics

Chapter 2 


Formation Mechanics.............................................................................................................................2-1 

Clay and Clay Minerals .....................................................................................................................2-1 

Definitions / Terminology..............................................................................................................2-1 

Structure.........................................................................................................................................2-2 

Smectite......................................................................................................................................2-3 

Hydration Mechanics .....................................................................................................................2-4 

Other Clay Types ...........................................................................................................................2-4 

Illite............................................................................................................................................2-4 

Kaolinite.....................................................................................................................................2-5 

Chlorite ......................................................................................................................................2-5 

Attapulgite..................................................................................................................................2-6 

Mixed-Layer Clays ....................................................................................................................2-6 

Base Exchange...............................................................................................................................2-6 

States of Clays................................................................................................................................2-8 

Clay Identification .........................................................................................................................2-8 

Sandstone ...........................................................................................................................................2-9 

Composition and Characteristics ...................................................................................................2-9 

Porosity and Permeability ............................................................................................................2-10 

Compaction and Sedimentation ...................................................................................................2-10 

Carbonates........................................................................................................................................2-11 

Modern Carbonate Depositional Environments...........................................................................2-11 

Naming Carbonate Rock Types ...................................................................................................2-11 

Diagenesis of Carbonates.............................................................................................................2-12 

Lithification..............................................................................................................................2-12 

Dolomitization. ........................................................................................................................2-13 

Types of Pores in Carbonates.......................................................................................................2-13 

Permeability in Carbonates ..........................................................................................................2-13 

Reservoir Pressure ...........................................................................................................................2-14 

Formation Damage...........................................................................................................................2-14 

Permeability .................................................................................................................................2-14 

Causes and Remedies...................................................................................................................2-15 

Laboratory Studies .......................................................................................................................2-19 


Revised 2006 


i



Figure 2-1 Structure of Montmorillonite ...........................................................................................2-3 

Figure 2-2 Structure Illite/ Mica........................................................................................................2-4 

Figure 2-3 Structure of a Kaolnite Layer...........................................................................................2-5 

Figure 2-4 Structure of Chlorites.......................................................................................................2-5 

Figure 2-5 Structure of Palygorskite .................................................................................................2-6 

Figure 2-6 Cays and Clay Minerals Particle Association..................................................................2-8 

Figure 2-7 Structure of Montmorillonite Clay.................................................................................2-10 

Figure 2-8 Carbonate Rock Types...................................................................................................2-12 

Figure 2-9 SEM Photomicrograph of Venezuelan Sandstone.........................................................2-15 

Figure 2-10 Photomicrograph of Wilcox Sandstone .........................................................................2-16 

Figure 2-11 Photomicrograph of Sandstone Impregnated with Clay ................................................2-17 

Figure 2-12 Photomicrograph of Platy Kaolinite Crystals ................................................................2-18 

Figure 2-13 Schematic Diagram of a Return Permeameter...............................................................2-19 


Table 2-1 Clay and Clay Minerals Base Exchange Capacity...........................................................2-7 

Table 2-2 Order of Cation Replacibility...........................................................................................2-7 

Table 2-3 Typical Mineralogical Analysis of Norway Shale...........................................................2-9 

Table 2-4 Clastic Sedimentary Rocks ..............................................................................................2-9 



ii Revised 2006


Chapter 2 

Successful drilling requires knowledge of the formation type into which the borehole 

is drilled. The characteristics of that formation, i.e., geological composition, liquid or 

gas content, pressure, permeability, porosity, reactivity, hydration, etc. will help 

determine the type of fluid to be used in drilling and completing the wellbore. 

Clay and Clay Minerals 

The importance of clay and clay minerals in the drilling industry is evident from two viewpoints: 

• Commercially mined clays are added to drilling fluids to build viscosity, thixotropy, and to 

contribute to wall building properties. 

• Clay minerals are present in nearly all sedimentary rocks. 

• Clay reaction to the drilling process can produce major problems such as, 

• Hole enlargement 

• Sloughing 

• Hydration 

• Rheological problems. 

The magnitude of the potential problems is apparent when one realizes that more than half of 

sedimentary rocks are composed of shales, siltstones, mudstones, etc. These rock types are composed 

of more than 50% clay minerals. Even sandstones may have as much as 20% to 30% clay minerals. 

The better understanding one has of clays and clay minerals, the greater the control over problems that 

may develop in the drilling process. 

Definitions / Terminology 

Clays can be defined according to physical properties, chemical properties, size, structure, and 

reactivity in water. One definition cannot adequately describe all types of clays. A simple definition 

used by many people is that clay is a finely ground, earthy material that can be molded into shapes 

when wet. 

Geologists and mineralogists usually define clays according to the chemical and mineral content that 

make up the clay. Elements that commonly make up clays are oxygen, silicon, aluminum, calcium, 

magnesium and potassium. Non-clay minerals generally found are quartz, feldspar, pyrite, and calcite. 

Clays are also defined according to their size. The American Petroleum Institute (API) defines clays 

as being those particles that are two microns or less in size. A micron is equal to one millionth of a 

meter. In order to grasp the concept of this size, it is sometimes easier if the sizes are scaled up a 

million-fold. For example: 

• A million yard sticks end to end would stretch from Houston to El Paso 



Revised 2006 2-1


• 3 million grains of sand (74 microns) in line would be about the size of the Astrodome (216 

meters in diameter) 

• A water molecule and most ions increased a million times would be the size of a grain of 

sand 

• A clay particle enlarged a million times would be like a piece of poster paper six inches to six 

feet across 

In terms of reactivity, clays can be classified as either swelling or non-swelling in nature. Regardless 

of whether a clay will hydrate in water or not, the presence of clays still contribute to the viscosity, gel 

strengths, and other properties of drilling fluids. 

Structure 

Clay minerals are hydrous aluminum silicates of a layer-type lattice structure (honeycomb) with 

magnesium, iron, and potassium located either between the layers or substituted within the lattice. 

The major exceptions to this are the attapulgite-sepiolite type clays which have a chain-type structure. 

Basic components of clays are silica tetrahedrons and alumina octahedrons, arranged in a sheet-like 

structure. These sheets are bound together by shared oxygen between the sheets. 

Clays are classified into three major categories depending upon the arrangement of these structural 

units. For example, if a clay has two silica tetrahedral layers and one alumina octahedral layer, it is 

referred to as a 2:1 clay type. The structure is an alumina sheet sandwiched between two silica sheets. 

Six or seven major clay types make up most of the clay minerals. The seven clay types can be divided 

into two major groups – layered clays and chain-type clays. 

The layered clays include smectites, illites, kaolinites, chlorites, vermiculites, and mixed-layer clays. 

The chain-type clays are the attapulgite-sepiolite minerals. Since the smectites are the most important 

in terms of drilling fluids, most of this discussion will center on these clay minerals. The other clay 

minerals will be discussed only briefly. 



2-2 Revised 2006


Smectite 

Figure 2-1 

Structure of Montmorillonite 

Of the clay minerals, smectite is the least stable and the most susceptible to hydration and diagenetic 

alteration. Two other terms often associated with the smectites are montmorillonite and Bentonite. 

Montmorillonite is the name given to the clay mineral found near Montmorillon, France. The term 

was used until recently to refer to the now known smectite group of clays. Bentonite is the term 

applied to a clay type found near Fort Benton, Montana. Bentonite was formed by the alteration of 

volcanic ash by water. For this discussion, the terms smectite, montmorillonite, and Bentonite will be 

used interchangeably. 

The basic structure of Bentonite is a thin sheet-like form of alternating layers of silica and alumina. 

The figure contains diagrams of the montmorillonite structure. Each sheet would resemble a 

honeycomb three layers thick. The two outside layers would be silica tetrahedrons and the central 

layer alumina octahedrons. The layers are held together in a very intricate lattice of aluminum, silicon, 

oxygen, and hydrogen atoms. 

This clay “sheet” is a rigid crystal-like salt or diamond. If the clay sheet were pure aluminum, silicon, 

oxygen, and hydrogen, all of the charges would be equal and the sheet would be electrically neutral 

and inert. Mica is a common mineral having this characteristic. 

Since Bentonite has been exposed to seawater and other sources of cations, some of the silicon and 

aluminum cations in the structure have been replaced. Iron and magnesium typically replace 

aluminum and aluminum typically replaces silicon. This replacement causes an imbalance in charges 

in the structure. This causes the bentonite sheet to be negatively charged. This charge occurs on the 

flat surface of the sheet or the area called the basal plane. Cations (positive charged particles) are 

attracted to this negatively charged surface. The predominant cation type determines the type of 

bentonite and the degree of hydration that it will undergo. The rank of cations from those which 

promote the most amount of swelling to those which promote the least amount of swelling is lithium, 

sodium, potassium, magnesium, calcium, aluminum, and hydrogen. 



Revised 2006 2-3


Hydration Mechanics 

If a particle of dried bentonite could be enlarged so that it would be visible to the naked eye, it would 

look like a fan of cards. Each card would be composed of alternating layers of silica and alumina. 

Between the individual platelets, there would be a thin layer or layering of partially hydrated cations. 

These cations would be composed mainly of sodium, calcium, magnesium, and potassium. The origin 

of these cations was the environment into which the clay was deposited. These positive particles are 

attracted to the negative charge that exists on the surface of the clay. They loosely hold the clay 

platelets together. Even in a dehydrated state, each of the cations is surrounded by a thin layer of 

water and the entire clay platelet is surrounded by a thin layer of water. If this group of clay platelets 

is dropped in water, the outer exposed surfaces of the platelets and attached ions immediately become 

hydrated. 

As time goes on, water molecules begin to seep in between the platelets. Some of the molecules of 

water adhere to the clay platelets and some of them go to the individual cations on the platelet surface. 

In freshwater, bentonite will swell 8 to 10 times its original dry volume. This process is a form of 

osmosis and hydrogen attraction into the negative clay surfaces. The net effect of these processes is 

that the clay platelets are pried apart. This is the swelling effect that is noticed when dried bentonite is 

placed in freshwater. This process of hydration also causes the individual clay platelets to disperse 

(separate). Even in pure water, complete dispersion of all clay platelets is unlikely. The amount of 

dispersion that occurs will be dependent upon the type and number of cations that are on the clay 

surface. If the cations are divalent (two positive charges) dispersion will be less complete. Other 

factors which contribute to the amount of dispersion are temperature, mechanical agitation, and the 

purity of the water. 

When a clay platelet is fully hydrated, it is surrounded by a cloud of water and hydrated ions. The 

greatest concentration of water molecules and hydrated cations are near the surface of the clay. 

Other Clay Types 

Illite 

Figure 2-2 

Structure Illite/ Mica 

Illite is essentially a group name for non-expanding, clay-sized, dioctahedral, micaceous minerals. It 

is structurally similar to muscovite, but substitution of aluminum for silicon in the silica tetrahedron 



2-4 Revised 2006


creates a greater charge deficiency. This deficiency is frequently satisfied by potassium ions located 

between the successive clay units. Illites are essentially inert to hydration. It is the most abundant clay 

mineral found in sedimentary rocks. 

Kaolinite 

Figure 2-3 

Structure of a Kaolnite Layer 

The kaolinite group includes dioctahedral minerals and trioctahedral minerals. These minerals are 

composed of one silica (octahedral) sheet and one alumina (tetrahedral) sheet. The atoms making up 

its structure combine almost completely, resulting in a neutrally charged surface. This provides for 

very little expansion or hydration of the structure. 

Chlorite 

Figure 2-4 

Structure of Chlorites 

Chlorite is similar to the smectite minerals except for a layer of magnesium hydroxide between the 

clay sheets. This layer neutralizes the surface charge so that the chlorite is non-expandable. Chlorites 

are common constituents of argillaceous sedimentary rocks where these minerals occur in both detrital 

and authigenic forms. The basic structure of chlorites consists of negatively charged mica-like layers 

regularly alternating with positively charged brucite-like octahedral sheets. The various members of 

this group of clays are differentiated by the kind and amount of substitutions within the brucite-like 

layer and the tetrahedral and octahedral positions of the mica-like layer. 



Revised 2006 2-5


Attapulgite 

Figure 2-5 

Structure of Palygorskite 

The attapulgite, sepiolite and polygorskite clay minerals are completely different in structure and 

shape from the clay minerals discussed so far. Chemically, attapulgite is a hydrous magnesium 

alumina silicate. The structure of the attapulgite crystals consist of bundles of laths. These are hollow 

needle-like structures. When mixed vigorously with water the bundles separate into individual laths. 

The individual laths then clump together in “brush heap” type arrangements. This provides a 

viscosifying effect to the water. Since the viscosity in attapulgite suspensions is dependent on 

mechanical interference rather than electrostatic forces, it makes an excellent suspending agent in 

saltwater. 

Sepiolite is similar to attapulgite in structure and chemistry. Sepiolite-base fluids have hightemperature 

stability and have been used on many high-temperature wells. 

Mixed-Layer Clays 

Mixed-layer clays are formed by the alteration of different clay minerals. The mixed-layer clays are 

usually a combination of illite and smectite type clays. The proportion of swelling to non-swelling 

layers determines the expandability of these clay minerals. 

Base Exchange 

Base exchange in clays occurs when certain cations in solution are exchanged for others which are 

adsorbed on the crystalline surfaces of the clay. In many clays, the adsorbed cations control the 

tendency of the clay to swell and/or disperse in the presence of water. Those cations that are most 

frequently involved in the base exchange of clays are sodium, potassium, magnesium, and calcium. 

These cations are adsorbed on the clay surfaces between individual platelets and around the edges of 

the structural units. The crystalline structure of the clay mineral is not altered in the base exchange 

progress. Several factors affect base exchange in clays. 

• The relative replacement power of the available cations 

• The type of clay (see Table 2-1) 



2-6 Revised 2006


Table 2-1 Clay and Clay Minerals Base Exchange Capacity 

Clay Material 

Meg/100 g of Dry Clay 

Montmorillonite 50 - 130 

Illite 10 - 40 

Kaolinite 3 - 15 

Attapulgite-Sepiolite 10 - 35 

• The amount of charge deficiency on the clay surface 

• The concentration of the cations in solution 

• The size and type of the replacing cations 

The replacement power of various cations is controlled by two major factors: 

• The number of charges on the cation 

• The size of the hydrated cation 

In general, cations with more positive charges (polyvalent) will have greater replacement power. An 

exception to this is the hydrogen ion which often acts as a polyvalent ion. 

The most commonly occurring cations may be ranked according to their replacement power as shown 

in Table 2-2. 

Table 2-2 Order of Cation Replacibility 

Easiest 

Lithium 

Sodium 

Potassium 

Magnesium 

Calcium 

Hydrogen 

Hardest 

For example, if the concentration of calcium ions in a sodium bentonite suspension were increased, the 

calcium ions would tend to replace the sodium cations. 

The relative concentration of the various cations present has a significant effect on base exchange. 

When cations of a lower replacement power are present in greater concentration than those of a higher 

replacement power, the desired base exchange may not occur. In this situation, the lower replacement 

power cations are occupying a large number of the base exchange sites. 

Cation size is determined by the atomic radius of the cations and the amount of water required to 

hydrate the cations. Smaller cations are easier to exchange and result in less hydration. Most 

monovalent cations are smaller and allow less hydration. An exception to this is the potassium cation. 

The potassium cation is thought to prevent hydration of clays due mainly to its size. The potassium 

cation hydrates very little and has a diameter almost the same size as the spacing between the oxygen 



Revised 2006 2-7


in the outer silica tetrahedrons of the clays. Since the potassium cation fits nicely in the molecular 

structure of the clays, it is able to hold two platelets tightly together. 

The phenomenon of base exchange is used in the design of wellbore fluid systems. The basis for 

calcium and potassium fluid systems is to prevent the hydration and swelling of formation drill solids 

through the mechanism of base exchange. 

States of Clays 

In general clays exist in one of two states, either that of aggregation or dispersion. Clay particle 

association is shown in Figure 2-1. 

Figure 2-6 

Cays and Clay Minerals Particle Association 

The aggregated state occurs when the clay platelets are stacked parallel to each other, similar to a 

stacked deck of cards. Unhydrated clay exists in this state. When the clay contacts water, the nature 

of the cations holding the clay platelets together may or may not allow dispersion to take place. The 

dispersed state occurs when the clay platelets separate. Aggregated or dispersed clays can undergo 

flocculation or deflocculation. Flocculation occurs when clay platelets are electrically attracted to 

each other. The predominant area of attraction is thought to be on the edges of the clay platelets. 

The edges of the clays are thought to be predominately positively charged, as opposed to the 

negatively charged clay basal plane area. When flocculated, the individual clays can clump together in 

particles large enough to be seen by the naked eye. They are often large enough to separate and settle 

out of solution. 

Several mechanisms exist by which flocculation can occur. It is generally caused by changes in the 

electrolyte concentration, temperature, and solids crowding. Deflocculation is the reverse of the 

flocculation process. Deflocculation occurs when the clay particles remain geometrically independent 

and unassociated with adjacent particles. It is achieved by the addition of a deflocculant, a 

temperature stabilizer, or a dilution fluid. 

Chemical deflocculants are thought to adsorb on the edges of the clays, thereby neutralizing the 

positive charges and allowing the clay platelets to separate. 

Clay Identification 

The most common analysis at present to determine the type of clays in cuttings or cavings is X-ray 

diffraction. Table 2-3 is an example of an X-ray diffraction analysis of a Norway shale. It is based on 

the reflection of monochromatic radiation of known wavelength. Each atom produces a characteristic 

wave reflection which depends on its type and its position in the molecular structure. Each 



2-8 Revised 2006


mineralogical type produces a characteristic spectrum. With the help of a collection of spectra, 

mineral structures can be identified. 

Table 2-3 

Typical Mineralogical Analysis of Norway Shale 

Mineral Component Percentage 

Quartz 10 - 15 

Feldspar 1 - 2 

Calcite 

Trace 

Pyrite 1 - 2 

Illite 10 - 15 

*Mixed Layer 35 - 40 

Kaolinite 15 - 20 

Chlorite 3 - 5 

* Mixed layer clays have 25% to 50% 

expandable layers 

Sandstone 

Composition and Characteristics 

Sandstone bodies are formed in a large variety of environments and acquire a variety of shapes and 

characteristics. Because sandstone is deposited virtually everywhere, it occurs most often as a 

reservoir rock. 

Sandstone is composed of sand-sized particles, ranging in size from 1/16 mm to 2 mm, that have been 

compacted or cemented together. Its size relative to other clastic sedimentary rocks (rocks composed 

of clasts, which are fragments or grains of pre-existing rock) is shown in table 2-4. 

Table 2-4 Clastic Sedimentary Rocks 

Sediment Size Rock 

Gravel > 2 mm Conglomerate 

Sand 2 to 1/16 mm Sandstone 

Silt 1/16 to 1/256 mm Siltstone 

Clay < 1/256 mm Shale 

Sorting of sandstone particles ranges from good to poor in a rock that can be designated as coarse, 

medium or fine within the size range for sandstone. Since sandstone fragments can be of virtually any 

composition, sandstone rock itself can be designated according to its mineral composition or its 

combination of constituents. Examples are: 

• Quartz sandstone, consisting of resistant quarts grains 

• Felspathic or Arkosic sandstone with more than 20% feldspar grains 

• Greywacke, consisting of poorly-sorted grains with abundant feldspar 

• Clay matrix, some of which may be altered to chlorite 



Revised 2006 2-9


• Calcareous sandstone, composed of limestone fragments 

Clean, well-sorted sandstones can be tightly or loosely cemented and can, therefore, have a wide range 

of porosity and permeability. Many Gulf Coast sandstones, because they are clean, well-rounded, and 

weakly cemented, provide good hydrocarbon reservoirs. Certain Ordovician sandstones of the Mid- 

Continent area are some of the best-sorted, best-rounded, clean sandstones developed anywhere in the 

world. Again, being loosely cemented, they are excellent reservoirs for hydrocarbon deposits. 

Porosity and Permeability 

Porosity represents the amount of void space in a rock and is measured as a percentage of the rock 

volume. In sandstones, porosity is controlled primarily by sorting, cementation, and to a lesser extent, 

by the way the grains are packed together. Porosity is maximized when grains are all spherical and of 

equivalent size, but becomes progressively less as the gains are more angular since such grains pack 

together more closely. 

Grains pack together in one of two ways – cubic or rhombohedral as shown below. 

Figure 2-7 Structure of Montmorillonite Clay 

The figure on the left is open (cubic) packing where the porosity is about 48 percent. The close 

(rhombohedral) packing on the right has only 26 percent porosity because the grains are packed into a 

smaller space. Artificially mixed clean sand has measured porosity of about 43 percent for extremely 

well sorted sands, irrespective of grain size, decreasing to about 25 percent for poorly-sorted, medium 

to coarse sand, while very fine grained sands still have over 30 percent porosity. 

The ease with which a fluid moves through the interconnected pore spaces of a rock denotes the 

degree of permeability. Permeability of highly porous, well-sorted sand varies from 475 millidarcies 

(mD) for a coarse-grained sand to about 5 mD for a very fine-grained sand. Permeability may 

decrease for a coarse-grained sand to about 10 mD if it is poorly sorted. 

Compaction and Sedimentation 

Compaction by weight of the overlying sediments squeezes the sand grains closer together. At greater 

depths, it may crush and fracture the grains. The results are smaller pores and, therefore, lower 

porosity and a decrease in permeability. Thus, a sandstone reservoir which could produce petroleum 

at 10,000 feet might become too impermeable to be of any economic value at 20,000 feet. 



2-10 Revised 2006


Deposits of cementing material between grains of sediment, whether compacted or uncompacted, will 

bind grains together. Sediments that are tightly cemented produce hard, coherent rocks, thus 

solidifying the formation. Since this solidity reduces both porosity and permeability characteristics of 

rock, the formation loses its potential as a productive reservoir. Should this be the case, fracturing of 

very hard limestones and sandstones can greatly enhance their intrinsically low reservoir potential. 

Carbonates 

An abundant rock that often contains oil is limestone. Sometimes the limestone contains substantial 

amounts of magnesium, replacing calcium, and it then becomes dolomite. It has become customary in 

the oil business to call both limestone and dolomite carbonates to avoid making a distinction. 

Oil was first discovered in carbonate rocks in Ontario in the 1850’s and later (in the early 1900’s) in 

the Tampico region of Mexico. In the 1920’s, the carbonates of West Texas became important. By 

the 1930’s and 1940’s, the great oilfields of Iran and Saudi Arabia were found in the Asmari limestone 

of Miocene age and the Jurassic limestone, respectively. It has been estimated that half the world’s oil 

reserves are in carbonates, although there are numerically fewer carbonate than sandstone reservoirs 

outside the Middle East. 

Carbonates differ in many respects from sandstones. They are mostly formed from the remains of 

animals (shellfish) and plants (algae); they are therefore found in nearly the same place where they 

originated and were not transported and then deposited like sandstones. Calcium carbonate can easily 

be dissolved in water solutions, so that solution and re-crystallization of the carbonates after their 

deposition (diagenesis) is very common. This solution forms some of the cavities that can store oil. 

Limestones are much more brittle than sandstones, and as a result of folding or faulting they may 

break, leaving open fractures that serve as routes of fluid flow. 

Modern Carbonate Depositional Environments 

Calcium carbonate is precipitated from seawater by many types of organisms. Mollusks such as 

oysters and clams make their shells of calcium carbonate, but many other animals and plants also form 

shells which are called exoskeletons. Some animals, notably the corals, live in large colonies and 

form sturdy build-ups or reefs. These are attacked by waves and fish, producing fine calcareous mud 

that washes down the sides of the reefs. 

Naming Carbonate Rock Types 

The interpretation of carbonate facies to define zones of good reservoir properties has been held back 

by the lack of a generally accepted system for naming the different rock types. Two different 

geologists describing the same core might very well use different words. 

In 1913 A. W. Grabau proposed the words calcilucite for consolidated lime mud, calcarenite for 

limestones whose particles are sand size, and calcirudite for limestones with pebble size grains. These 

terms are simple, descriptive, and still widely used. 

Beginning about 25 years ago, it became obvious to oil company geologists that some uniformity in 

the terms used to describe carbonates was desirable. Several major oil companies developed 

classifications about the same time. The most widely used have been those of Robert Folk of the 

University of Texas, Robert Dunham of Shell, and Leighton and Pendexter of Exxon. The latter is 

similar to Folk’s. Perhaps the most practical and easily understood classification is a modification of 

Folk’s suggested by G. M. Friedman. 

Folk said that a carbonate rock consists of three textural components: grains, matrix and cement. The 

cement is clear calcite that filled or partially filled the pores after the original deposition. There are 

several different kinds of grains, of which four are the most important. These are (1) shell fragments 



Revised 2006 2-11


called “bio”; (2) fragments of previously deposited limestone, called “intraclasts”, (3) small round 

pellets, the excreta of worms and other small burrowing organisms; and (4) ooliths, spheres formed by 

rolling and coating lime particles along the bottom. 

The matrix is lime of clay particle size (lime mud). It is called micrite. The clear secondary calcite 

cement is called sparite. 

Figure 2-8 Carbonate Rock Types 

Thus, a rock consisting mainly of clear secondary calcite with intraclast grains would be called a 

“intrasparite”. A rock consisting mainly of micrite (lime mud) with grains of broken shell fragments 

would be called “biomicrite”. Biomicrite and pelmicrite are the most common limestone types. These 

eight types are shown in diagrammatically below. 

Besides these eight combinations, there are limestones consisting only of micrite and some consisting 

of the remains of upstanding reef-building organisms. So there are ten types of limestone in all. 

Diagenesis of Carbonates 

Lithification. Calcium carbonate (CaCO 3 ) is slightly soluble in water, but calcium bicarbonate 

(CaHCO 3 ) is very soluble. When carbon dioxide gas (CO 2 ) is dissolved in water, it forms carbonic 

acid (H 2 CO 3 ), which changes calcium carbonate to calcium bicarbonate. The reactions are 

complicated but may be summarized in the following equation: 

++ 

− 

+ H 

2O 

+ CO2 

↔ Ca + • 

3 

CaCO3 2 HCO 

The CaCO 3 is crystalline, the Ca ++ and 2 HCO 3¯ are ions in solution. The reaction is reversible, so that 

crystalline calcium carbonate may be either dissolved or precipitated, depending on conditions in the 

water solution. Of these, the most important is pH. When carbon dioxide dissolves in water it makes 

the water more acid, that is, it lowers the pH. Carbon dioxide is dissolved out of the air and is also 

produced by bacteria that decompose organic matter and by animals in their respiration. It is taken out 

of water by plants such as algae that use it to form organic carbonic compounds. Slight changes in pH 

(and also in Eh, which is oxidation-reduction potential) thus cause solutions to dissolve or precipitate 

calcium carbonate. 



2-12 Revised 2006


The porosity and permeability of carbonate rocks, like those of sands, are controlled by the currents 

and waves in the original depositional environment. However, the original texture is vastly altered by 

the solution and re-precipitation of calcium carbonate after burial. 

Recently deposited lime muds consist mainly of aragonite (which is a different and more unstable 

crystallographic form of calcium carbonate) and high-magnesium calcite. Consolidated limestones 

consist of low-magnesium calcite and sometimes dolomite. Profound changes take place soon after 

burial. 

When originally deposited, lime muds have a porosity of 50 percent or more, but when they are 

consolidated into limestone their porosity is generally less than two percent. Shales lose porosity by a 

compaction process that involves flattening. However, limestones are formed from lime mud by recrystallization, 

and the pores are filled by precipitation of calcite, apparently brought in from 

elsewhere, because no compaction has occurred. Oolites and fossils are not squashed and flattened. 

Consolidated limestones show abundant evidence of solution and precipitation. Micritic skeletal 

limestones often have the original shells dissolved out, leaving cavities. Irregular channels and cavities 

(vugs) formed by solution permeate some limestones. These, like fractures, are usually lined and are 

sometimes filled with clear crystalline calcite. 

Dolomitization. Limestones are often partially or completely changed to dolomite. Dolomite has 

the composition CaMgCO 3 and it is crystallographically similar to calcite. However, it has a greater 

density, less solubility in water, less ductility, and more brittleness. Obviously, waters enriched in 

magnesium permeated the calcium carbonate deposits sometime after their burial. They laid down an 

atom of magnesium and picked up one of calcium. Usually the dolomitization involved a recrystallization. 

First, dolomite crystals (rhombi) form from the micrite in a random manner. Later, the 

dolomitization micrite is dissolved, leaving intracrystalline porosity. Some of the Arabian fields 

produce from beautiful crystalline dolomite, which resembles granulated sugar. 

Types of Pores in Carbonates 

The interstitial pores in carbonates basically resemble those in sandstones. They are the open cavities 

between the grains, usually more or less clogged by mud or precipitated substances, or opened by 

water solution. However, carbonates differ from sandstones in being soluble and brittle. Because they 

are soluble, they often have large cavities called channels or vugs. Because they are brittle, they often 

have fractures that, if they are open or enlarged by solution, are also large openings. Carbonates 

therefore often – but by no means always – have a secondary porosity that may be greater than the 

primary interstitial, or matrix, porosity. The fractures may contribute only slightly to porosity but 

vastly increase the permeability. The behavior of fluids in carbonates containing only interstitial 

porosity resembles that in sandstones, but in vuggy or fractured carbonates it is entirely different. 

Permeability in Carbonates 

Carbonates are characterized by different types of porosity and have unmodal, bimodal and other 

complex pore size distributions, which result in wide permeability variations for the same total 

porosity. Although most sedimentary rocks possess significant porosity when freshly deposited, the 

rate at which these vital properties undergo reduction with age is principally due to compaction. The 

compatibility of sedimentary rock depends more on the texture than it does on composition. The 

textures of dense limestones are not effective reservoir materials because of compaction, unless they 

have been extensively fractured after they were formed. Fracturing produces secondary permeability 

meaning it was created after the rock in question was formed. The fractures create new void spaces in 

the rocks which allow fluids to move into the voids. Primary permeability occurs during the 

compaction process when the original materials are forming the rock. 



Revised 2006 2-13


Reservoir Pressure 

The fluid in the pores of reservoir rock is under a certain degree of pressure, generally called reservoir 

(or formation) pressure. A normal reservoir pressure at the oil-water contact approximates very 

closely the hydrostatic pressure of a column of salt water to the depth. The hydrostatic pressure 

gradient varies somewhat, depending on the amount of dissolved salts in the average water for a given 

area. For fresh water, it is 0.433 psi/ft of depth. For water containing 80,000 ppm of dissolved salts 

(U.S. Gulf Coast), the pressure is approximately 0.465 psi/ft. However, normal marine water is about 

35,000 dissolved salts, approximately 0.446 psi/ft. Reservoirs can contain fluids under abnormal 

pressure up to as high as 1.00 psi/ft of depth. 

Abnormal pressure may develop in isolated reservoirs as a result of compaction of the surrounding 

shales by the weight of the overburden. During this process, water is expelled from the shale into any 

zone of lower pressure. This may be into a wholly confined sandstone which does not compact as 

much as the shale. Consequently, its contained water is under a lower pressure than that in the shale. 

Ultimately, a state of equilibrium can be reached when no further water can be expelled into the 

sandstone, and its fluid pressure will approximate that of the shale. 

Since compaction of sandstones is related to the pressure of the pore fluid as well as to the pressure 

exerted by the overburden, it follows that abnormally pressured sandstones are partially supported by 

the fluid pressure and partially by grain-to-grain contact. Consequently, when the abnormal pressure 

is reduced by production, compaction of the reservoir begins to occur. Subsurface compaction can 

cause serious problems, not only in collapse of the well casing, but also because of the subsidence 

reflected at the surface. Such occurrences result in very expensive landfill and well repair costs. 

It has been demonstrated that there can be a direct relationship between subsidence and the amount of 

liquid withdrawn. Studies of the Wilmington Field in California indicated that re-pressuring by water 

injection would increase oil recovery and stop compaction. Subsidence was stopped by such a 

program, and, in places, the surface regained some of the elevation that was lost. However, work on 

sediments has shown that this compaction is not entirely reversible. Some permanent reduction of 

porosity and permeability results from permitting abnormal reservoir pressure to decline, and this may 

adversely affect the rate of production and possibly, the ultimate recovery. 

Formation Damage 

Permeability 

It is imperative that rocks containing hydrocarbons not be inhibited in their ability to produce oil or 

gas during drilling. Rocks allow the flow of a liquid or gas when their pore spaces are connected to 

form channels. This ability to flow is called permeability, and the standard unit of measure is termed 

the Darcy, named for Henry Darcy who developed a mathematical equation called Darcy's Law that 

can be used to calculate permeability. Using this equation, the permeability of a material can be 

measured if the following values are known: 

• Length and cross-sectional area of the material 

• Viscosity of the fluid flowing through it 

• Amount of pressure needed to cause the flow 

• Flow rate (i.e., the volume of fluid that flows through the material in a given amount of time) 

A piece of material one centimeter long and one square centimeter in area that will flow water at a rate 

of one cubic centimeter per second at a driving pressure of one atmosphere (14.7 psi) has a 

permeability of one Darcy. Most rocks have much less than one (1) Darcy permeability, so the most 



2-14 Revised 2006


commonly used unit of measure in the oil and gas industry is the millidarcy, which is 1 / 1000 of a Darcy. 

Devices which measure permeability, called permeameters, are used extensively to measure the 

permeabilities of formation samples. 

Causes and Remedies 

As was stated earlier, it is obvious that a rock formation's permeability should be reduced as little as 

possible when it is drilled and completed. This is difficult to avoid, however, and the reduction of 

permeability is referred to as formation damage. In the drilling fluids industry, the principal concern is 

formation damage caused by drilling fluids. Formation damage caused by drilling fluids involves the 

interaction of the drilling fluid or the filtrate with a permeable rock formation that results in a loss of 

permeability. After a formation is drilled, pressure and flow tests can sometimes be carried out to 

determine if it has experienced damage. 

The simplest form of formation damage involves the flow of the entire drilling fluid (liquids and 

solids) into the pores of the rock; this is usually called fluid invasion. If enough solid material such as 

bentonite or weighting agents accumulate in the pores, blockage and permeability loss can result. This 

type of damage can occur due to one or a combination of the following factors: 

• Poor fluid loss control 

• Excessive overbalance 

• High-formation permeability 

An example of a sandstone which experienced such invasion is shown in Figure 2-9. Fluid invasion 

can be avoided if the drilling fluid forms a stable filter cake on the borehole wall that serves as a 

barrier to invasion. One possible remedy in extreme cases is the use of bridging agents, which are 

particulate materials such as calcium carbonate that block the formation’s pores at or near the borehole 

wall. 

Figure 2-9 SEM Photomicrograph of Venezuelan Sandstone 

The permeability of this sandstone was greatly reduced by fluid invasion during a return permeability 

test. The light gray material labeled “S” in the center of the photograph are drilling fluid solids 

(barite and gel) that have plugged a pore space. Some open pore space can be seen in the lower left 

corner. 



Revised 2006 2-15


Selecting the proper size bridging agent is critical; if the size of the formation pores is known, a 

bridging agent that will block the pores without passing through them can be selected. Abrams 1 

presents guidelines for bridging agent use. 

Other forms of formation damage are more complex, involving chemical reactions between the 

drilling fluids and formations. Carbonate rocks (limestones and dolomites) are not very reactive with 

most drilling fluids, so this type of damage is most likely to occur in clastic rocks such as sandstones. 

Clastic rocks consist of a network of interconnected particles, usually quartz or feldspar, called 

framework grains. The pore spaces between these grains may be empty or filled by other minerals. 

The pore spaces in these rocks may contain clay minerals. Because clay minerals can be highly 

reactive with drilling fluids, formation damage can occur in clay-bearing clastic rocks. “Clean” 

sandstones that have no clay are not highly vulnerable to chemical formation damage since most 

framework grains are not reactive. 

If a sandstone contains expandable clays such as smectite or mixed-layer types, the potential for 

formation damage exists. If a drilling fluid causes these clays to swell by cation exchange or further 

hydration in their interlayer sites, this may cause them to detach, migrate, and plug the pores, causing 

a loss of permeability (see Figure 2-10). In rocks whose framework grains are bound together by 

expandable clays, disaggregation and borehole washout can also occur (see Figure 2-11). 

Figure 2-10 

Photomicrograph of Wilcox Sandstone 

The particles labeled “P” are clay and other fine material that have migrated and plugged a pore 

space. Mixed-layer clays are common in this sample, and exposure to a high pH lignosulfonate fluid 

caused them to swell and detach, causing a 63% loss of permeability. 

1 A. Abrams, “Mud Design to Minimize Rock Impairment Due to Particle Invasion”, SPE 5713, 1977 



2-16 Revised 2006


Figure 2-11 

Photomicrograph of Sandstone Impregnated with Clay 

Some sandstone such as this one has extensive coatings of clays on the framework grain surface. In 

this image, the clay, presumably illite, is the feather-like material filling the pore spaces between the 

quartz crystals. 

The prevention of clay swelling and resulting problems can be accomplished by minimizing fluid loss 

and using inhibitive drilling fluids. Such fluids include certain polymers, those with potassium salts 

and oil-base fluids. Clay swelling is prevented by the potassium ion because it fits well into a clay's 

interlayer sites and stabilizes its structure. Polymers tend to be adsorbed on the clay's outer surfaces 

and prevent chemical alteration in the interior sites. 

Because hydroxyl ions tend to hydrate expandable clays, drilling fluids such as lignosulfonates that are 

run at high pH can be damaging. This is part of the reason why lower pH fluids such as polymers are 

less damaging, and laboratory tests have shown that keeping the pH as low as possible in dispersed 

fluids will reduce formation damage in fluid-sensitive rocks. The base oils in oil-base fluids do not 

react with clays and, if included water is kept as the internal phase of the emulsion, an oil-base fluid 

will be highly inhibitive. 

Formation damage can also occur in clastic rocks with non-expandable clays such as kaolinite or illite. 

These clay minerals tend to form plates and fibers that are loosely attached to the pore walls (see 

Figure 2-12). 



Revised 2006 2-17


Figure 2-12 

Photomicrograph of Platy Kaolinite Crystals 

This photomicrograph is of a cluster of platy kaolinite crystals (k) that are filling a sandstone pore. 

Although these clays do not swell, they can still be made to detach and migrate if a fluid of greatly 

higher or lower salinity than the natural formation water is introduced. 

If a fluid is introduced into a rock that contains many of these clays, they can detach, migrate, and plug 

pores if the invading fluid is chemically different from the natural formation fluid. Knowledge of a 

formation's water chemistry can be helpful in designing a non-damaging fluid. Another type of 

chemical formation damage, not caused by clays, involves the precipitation of materials in the pore 

spaces due to a reaction between formation water and the drilling fluid. For example, if a formation's 

water contains abundant bicarbonate ions, it could react with a calcium-rich drilling fluid to form poreblocking 

calcium carbonate. 



2-18 Revised 2006


Laboratory Studies 

Formation damage can be studied in the laboratory using a return permeameter, a device that can 

measure the permeability of rock samples before and after exposure to drilling fluids (see Figure 

2-13). 

Figure 2-13 

Schematic Diagram of a Return Permeameter 

The cylinder in the center is a pressure cell that contains the rock sample at a specified temperature 

and pressure. A fluid or gas is flowed through from right to left in order to measure permeability, and 

then the test drilling fluid is circulated through the left side of the cell where it will contact one end of 

the core sample. The permeability is then re-measured to determine the percent return permeability. 

This device consists of a pressure chamber that contains the core sample at a certain temperature and 

pressure, flow lines for fluids and gasses, and gauges to measure pressures and flow rates in order to 

calculate permeability. After the permeability of the sample in its natural state is measured, the core is 

then exposed to a drilling or other test fluid for a specified time, and then its permeability is remeasured. 

The results of these tests are often given as percent return permeability which is simply the percentage 

of the original permeability retained by the core after exposure to the test fluid. In other words, a 

sample that experienced no damage would have 100% return permeability. The purpose of these tests 

is to evaluate a variety of drilling fluids to see which ones cause the least amount of damage. 

Some rocks are more prone than others to formation damage, so samples from the actual formation to 

be drilled are necessary to properly evaluate test fluids. Because this is useful information, many 

operators will furnish samples for return permeability testing. As more samples from a particular 

region are tested, a valuable database can be built up that can be used in selecting drilling fluids for 

use in that area. 

Besides their use in return permeability testing, formation samples can be examined by X-ray 

diffraction, scanning electron microscopy, and thin section analysis to determine the mineralogical 

content, pore structure, and how the clay minerals are distributed in the rock. The vulnerability of a 

reservoir rock to formation damage can often be predicted by using these techniques. After the cores 

are tested for return permeability, they can be examined in the scanning electron microscope for 

evidence of permeability loss. 



Revised 2006 2-19

Water–Based Drilling Fluids 

Chapter 

Three 

Water–Base Drilling Fluids

Chapter 3 


Water-base Drilling Fluids.............................................................................................................3-1 

Introduction................................................................................................................................3-1 

The Structure of Matter..............................................................................................................3-1 

Types of Bonding.......................................................................................................................3-6 

Properties of Compounds.........................................................................................................3-11 

Solubility and Solutions ...........................................................................................................3-13 

Bases and Alkalis .....................................................................................................................3-18 

Chemical Equilibria .................................................................................................................3-21 

Chemical Calculations .............................................................................................................3-23 

Common Names of Compounds used in Drilling Fluids .........................................................3-30 

Conventional (Basic) Fluid Systems........................................................................................3-31 

Air, Mist, and Foam Drilling....................................................................................................3-46 

Potassium-Base Fluids .............................................................................................................3-48 

Complex Systems.....................................................................................................................3-51 

Deepwater Drilling Fluid Systems ...........................................................................................3-62 

PYRO-DRILL ® , High-Temperature Drilling Fluid .................................................................3-62 

UNI-CAL ® Systems .................................................................................................................3-66 

GLYCOL Systems ...................................................................................................................3-67 

AQUA-DRILL SM System.........................................................................................................3-70 

ALPLEX ® – Aluminum-Based Shale Stabilizer......................................................................3-87 

PERFORMAX SM – High Performance Water Base Mud ........................................................3-93 

References..................................................................................................................................3-105 


Figure 3-1 Pictorial Representation of Atomic Structure ..........................................................3-2 

Figure 3-2 

Figure 3-3 

The Formation of Sodium Chloride as an Example of Ionic Bonding.....................3-7 

The Formation of Water and carbon Dioxide as Examples of Covalent 

Bonding....................................................................................................................3-8 

Figure 3-4 Differences in Compounds due to Chemistry ..........................................................3-8 

Figure 3-5 

Figure 3-6 

Sodium Carbonate Structure (schematic).................................................................3-9 

Polar and Non-Polar Covalent Bonding.................................................................3-10 


Revised 2006 


i

Figure 3-7 The Sodium Chloride Structure .............................................................................3-11 

Figure 3-8 Intermolecular Attractions in Water ......................................................................3-12 

Figure 3-9 

Hydration of Sodium Chloride in Water................................................................3-14 

Figure 3-10 Invert Emulsion Water Droplets in a Continuous Oil Phase .................................3-16 

Figure 3-11 

Figure 3-12 

Figure 3-13 

Figure 3-14 

Water Wetting of Clay Mineral Surfaces...............................................................3-17 

Distribution of the CO 3 - HCO 3¯- CO 3 

2¯ System in Pure Water and Seawater 

at 1 atm. as a Function of pH .......................................................................3-20 

Solubility of Calcium in a Solution Containing 4 lb/bbl Lime vs. Caustic 

Soda Addition ........................................................................................................3-22 

Pipettes and Burette Used in Chemical Analysis...................................................3-27 

Figure 3-15 Fluid Loss and Viscosity with Bentonite Prehydration .........................................3-33 

Figure 3-16 

Figure 3-17 3-73 

Figure 3-18 

Figure 3-19 

Inhibition Studies with Tertiary Clays...................................................................3-72 

Cloud Point: Temperature at Which Water and Glycol Begin to Separate...........3-74 

Cloud Points for Various Polyols in KCl Solutions...............................................3-75 

Figure 3-20 Effect of Temperature on Yield Point at 10% AQUA-COL ...............................3-77 

Figure 3-21 

Figure 3-22 

Figure 3-23 

Relative Inhibition of Tertiary Clay in KCl Solutions...........................................3-84 

Viscosity Increases with NEW-DRILL ® Additions...............................................3-85 

Reinecke Salt Results...........................................................................................3-104 


Table 3-1 Known Elements and Atomic Weights....................................................................3-4 

Table 3-2 The Periodic Table...................................................................................................3-6 

Table 3-3 Formula and Valency of Common Ions formed From Groups of Atoms................3-9 

Table 3-4 Examples of Different Bond Types .......................................................................3-12 

Table 3-5 Common polar groups in organic compounds .......................................................3-13 

Table 3-6 Solubility of Salts...................................................................................................3-14 

Table 3-7 The pH Scale..........................................................................................................3-19 

Table 3-8 Equivalent Weights................................................................................................3-24 

Table 3-9 Commonly Used Indicators ...................................................................................3-28 

Table 3-10 Common Names, Chemical Nature and Formula of Materials..............................3-30 

Table 3-11 Composition of a Typical Seawater Sample..........................................................3-33 

Table 3-12 Typical Fluid Properties after Conversion and Before Weight-up ........................3-41 

Table 3-13 Typical Fluid Properties after Conversion and Before Weight-up ........................3-45 

Table 3-14 Classifications of Air / Water Drilling Fluids........................................................3-46 



ii Revised 2006


Table 3-15 Typical Formulation for Air-Fluid Dispersions .....................................................3-47 

Table 3-16 

Component Description of the PYRO-DRILL ® System........................................3-63 

Table 3-17 PYRO-DRILL Product Concentration Guidelines for Various Fluid Types .........3-64 

Table 3-18 Basic Properties of Glycols Used in the AQUA-DRILL System ..........................3-69 

Table 3-19 Chemical Similarities Between Glycols and Alcohols ..........................................3-69 

Table 3-20 Effects of AQUA-COL ® and AQUA-COL ® D on Elastomers in a 5% 

Solution..................................................................................................................3-78 

Table 3-21 Range of Glycol Cloud Points in KCl and NaCl Brines ........................................3-79 

Table 3-22 

Table 3-23 

Table 3-24 

Table 3-25 

Table 3-26 

Table 3-27 

Table 3-28 

Table 3-29 

Table 3-30 

Table 3-31 

Recommended Ranges for Gel Strengths and Yield Points for AQUA-COL 

Systems ..................................................................................................................3-80 

Recommended Dilution Rates for AQUA-DRILL Systems..................................3-82 

Recommended Product Concentrations and Applications for the AQUA- 

DRILL System .......................................................................................................3-83 

AQUA-DRILL Applications in the North Sea.......................................................3-86 

Typical Offshore Discharges Figures for Water Base Mud Systems.....................3-87 

Basic Formulation for ALPLEX Systems..............................................................3-88 

Fluoride Electrode Correlation Chart.....................................................................3-93 

PERFORMAX System Products and Functions....................................................3-95 

PERFORMAX System Products and Concentrations............................................3-99 

Return permeability on Berea Sandstone for 20% NaCl, 12 lb/gal 

PERFORMAX .....................................................................................................3-100 


Revised 2006 


iii

Water-base Drilling Fluids 

Chapter 3 

Water-based drilling fluids, regardless of the name assigned to them, usually 

contain clays, water soluble chemicals (including salts), a pH control additive 

(hydroxyl source), and one or more organic polymers, surfactants, and 

deflocculants. 

Introduction 

In order for drilling fluid engineering to be a science and not an art, a basic understanding of the 

chemistry involved is required. This chapter attempts to provide the chemical background to the 

reactions that take place in the fluid. 

By adoption of this approach the engineer will be well equipped to deal with variations in the 

fluid properties which may occur from time to time. If the basic chemical concepts are well 

understood, then the causes of any problems can be better identified and dealt with 

The Structure of Matter 

The properties and reactions of materials can be related to the basic structures of the atoms and 

molecules of which they are formed. The difference between water and diesel, bentonite and 

sand, and so on, arises from their physical and chemical properties which are best understood in 

these terms 

Elements and Compounds 

An element is a chemically unique substance which cannot be split up into a simpler chemical 

form by chemical means. The names of the various elements are usually written as abbreviations 

to simplify chemical notation. A full list of elements and their symbols is given in Table 3-1. 

Elements can combine together to form compounds. A compound has different chemical and 

physical properties than those of the simple mixture of elements from which the compound is 

formed. Thus hydrogen and oxygen are both gases and remain gases when they are mixed 

together. However, if they are chemically combined, they form water, which is a liquid. When 

elements combine together, they do so in a fixed ratio by weight, which always remains constant 

for one particular compound. 

Atoms and Molecules 

An atom is the smallest particle of an element which can exist and still retain the same chemical 

properties of that element. Atoms are the basic building bricks of matter from which all things 

are constructed. They are the smallest units of matter which can undergo chemical change. 



Revised 2006 3-1

Water Based Drilling Fluids 

A molecule is the smallest particle of a compound which can exist and still retain the same 

chemical properties of that compound. Molecules consist of atoms chemically bonded together in 

a precise arrangement. A molecule of water consists of two atoms of hydrogen combined with 

one atom of oxygen to give a chemical formula of H 2 O. When the elements hydrogen and 

oxygen combine to form the compound water, each molecule of water consists of two atoms of 

hydrogen bonded to one atom of oxygen. 

Atomic structure 

Atoms are indivisible by chemical means, but other methods show that they are composed of 

three simpler particles. These are neutrons, protons, and electrons. 

Neutrons have no charge and are assigned a mass of one atomic mass unit, or 1 a.m.u., but carry a 

single positive charge. Electrons are much lighter, being only 1/1840 a.m.u. They carry a single 

negative charge. 

Figure 3-1 

Pictorial Representation of Atomic Structure 

The simplified picture of an atom is that of a dense nucleus containing all the neutrons and 

protons surrounded by a diffuse “cloud” of electrons which orbit the nucleus in various electron 

“shells” or orbitals. Thus the nucleus carries all the positive charge of the atom and negative 

charge is spread over a comparatively much larger area by the electron cloud. The electrons are 

equal in number to the protons so that overall the atom is electronically neutral. 

Atomic number 

The number of protons in the nucleus is called the atomic number and determines the identity of 

an atom. There are over a hundred different elements, each characterized by a different number 

of protons in the nucleus of their atoms. Hence each element has a different atomic number. 

Most elements are found in nature, though some only exist on earth by virtue of artificial 

synthesis in a nuclear reactor. 

The terms “atom” and “element” are often mixed up or left out when referring to elements by 

name. Thus “Iron has a density of 7.7” refers to the element but “Iron has an atomic number of 

26” refers to the atoms of the element iron having 26 protons in their nucleus. 

Lists of atomic numbers are given in Table 3-1. 



3-2 Revised 2006


Atomic weight 

Carbon has six protons (each of mass 1 a.m.u.) in its nucleus and thus has atomic number 6. 

Most carbon atoms have six neutrons (also each of mass 1 a.m.u.) in their nucleus and the atomic 

weight of one atom of this type of carbon is defined as 12.00000 a.m.u. The mass of the electrons 

is included in this figure, but their contribution to the total is very small. All other elements are 

compared to this on a relative scale. 

Atomic weights for all the elements are given to the nearest 0.01 a.m.u. in Table 3-1. At this 

level of accuracy, the mass of the electrons is negligible. Thus, the atomic weights might be 

expected to be whole numbers, since they are simply the sum of the number of protons and 

neutrons in the nucleus. Table 3-1 shows that this is not so. The explanation is that atoms of the 

same element can have different numbers of neutrons in their nucleus and thus different atomic 

weights. For example the majority of carbon atoms have 6 neutrons but some have 7 or even 8 

making their atomic weight 13 or 14 respectively. The atomic weight of the element carbon is an 

average of all the forms that occur, taking into account their relative abundance in nature, and is 

thus 12.01. 



Revised 2006 3-3


Table 3-1 

Element Symbol Atomic 

Number 

Known Elements and Atomic Weights 

Atomic 

Weight 

Element Symbol Atomic 

Number 

Atomic 

Weight 

Actinium Ac 89 227* Mercury Hg 80 200.59 

Aluminum Al 13 26.9815 Molybdenum Mo 42 95.94 

Americum Am 95 243* Neodymium Nd 60 144.24 

Antimony Sb 51 121.75 Neon Ne 10 20.179 

Argon Ar 18 39.948 Neptunium Np 93 237.0482 

Arsenic As 33 74.9216 Nickel Ni 28 58.71 

Astaline At 85 210* Niobium Nb 93 237.0482 

Barium Ba 56 137.33 Nitrogen N 7 14.0067 

Berkelium Bk 97 247* Nobelium No 102 259* 

Beryllium Be 4 9.01218 Osmium Os 76 190.2 

Bismuth Bib 83 208.9808 Oxygen O 8 15.9994 

Boron B 5 10.81 Palladium Pd 46 106.4 

Bromine Br 35 79.904 Phosphorus P 15 30.9738 

Cadmium Cd 48 112.41 Platinum Pt 78 195.09 

Caesium Cs 55 132.9054 Plutonium Pu 94 244* 

Calcium Ca 20 40.08 Polonium Po 84 209* 

Californium Cf 98 251* Potassium K 19 39.0983 

Carbon C 6 12.011 Praseodymium Pr 59 140.9077 

Cerium Ce 58 140.12 Promethium Pm 61 145* 

Chlorine Cl 17 35.453 Protactinium Pa 91 231.0359 

Chromium Cr 24 51.996 Radium Ra 88 226.0254 

Cobalt Co 27 58.9332 Radon Rn 86 222* 

Copper Cu 29 63.546 Rhenium Re 75 186.2 

Curium Cm 96 247* Rhodium Rh 45 102.9055 

Dysprosium Dy 66 162.50 Rubidium Rb 37 85.467 

Einsteinium Es 99 254* Ruthenium Ru 44 101.07 

Erbium Er 68 167.26 Samarium Sm 62 150.4 

Europium Eu 63 151.96 Scandium Sc 21 44.9559 

Fermium Fm 100 257* Selenium Se 34 78.96 

Fluorine F 9 18.9984 Silicon Si 14 28.0855 

Francium Fr 87 223* Silver Ag 47 107.868 

Gadolinium Gd 64 157.25 Sodium Na 11 22.9898 

Gallium Ga 31 69.72 Strontium Sr 38 87.62 

Germanium Ge 32 72.59 Sulphur S 16 32.06 

Gold Au 79 196.9665 Tantaium Ta 73 180.9479 

Hafnium Hf 72 178.49 Technetium Tc 43 98.9062 

Helium He 2 4.0026 Tellurium Te 52 127.60 

Holmium Ho 67 164.9304 Terbium Tb 65 158.9254 

Hydrogen H 1 1.0079 Thalliium Tl 81 204.37 

Indium In 49 114.82 Thorium Th 90 232.0381 

Iodine I 53 126.9045 Thulium Tm 69 168.9342 

Iridium Ir 77 192.22 Tin Sn 50 118.69 

Iron FE 26 55.847 Titanium Ti 81 204.37 

Krypton Kr 36 83.80 Tungsten W 74 183.65 

Lanthanum La 57 138.9055 Uranium U 92 238.029 

Lawrencium Lr 103 260* Vanadium V 23 50.941 

Lead Pb 82 207.2 Xenon Xe 54 131.30 

Lithium Li 3 6.941 Ytterbium Yb 70 173.04 

Lutetium Lu 71 174.97 Yttrium Y 39 88.9059 

Magnesium Mg 12 24.305 Zinc Zn 30 65.38 

Manganese Mn 25 54.9308 Zirconium Zr 40 91.22 

Mendelevium Md 101 258* 

Atomic weights quoted are the 1969 values based on carbon 12 and include the IUPAC revision 1971 

Values marked * are for the most stable or most common isotopes 



3-4 Revised 2006


Isotopes 

These different forms of the same element are called isotopes and are denoted by writing the 

atomic weight as a superscript. Thus, carbon has three isotopes; C 12 , C 13 , and C 14 . 

Hydrogen also has three isotopes, with either zero, one or two neutrons in the nucleus. The most 

common form is H 1 (99.985%). The other two isotopes have been given special names (the only 

isotopes to have been so honored). H 2 is known as deuterium (D) and H 3 is known as tritium (T). 

Tritium is radioactive, that is, it has an unstable nucleus which can emit an electron and thus 

change the tritium into a stable isotope of helium He 3 . This fact makes tritium easy to detect and 

for this reason titrated water (that is water to which T 2 O gas been added) is used as a tracer in 

formation analysis. 

Many other isotopes are also radioactive. For example, the heavy isotope of potassium, K 40 emits 

high energy radiation known as gamma rays. This gamma radiation is utilized in well logging. A 

gamma ray log shows high concentrations of potassium bearing minerals, such as micas, in a 

shale, or carnallite in a salt section. 

Molecular Weight 

The molecular weight of a compound is simply the sum of the atomic weights of the atoms it 

contains. For example, water, H 2 O, has molecular weight 18 (atomic weight of hydrogen = 1, 

atomic weight of oxygen = 16). 

The Periodic Table 

Table 3 - 2 shows the elements grouped together in a special way known as the periodic table. 

The elements are shown in order of increasing atomic number and are arranged in a series of 

column (groups IA – VIIA). This reflects an earlier classification based on the chemical 

properties of the various elements. In the modern form, elements in the same group are 

chemically related and show regular trends in chemical properties. Thus the chemical nature of 

an element is in some way related to its atomic number. This relationship involves the 

configuration of the electrons which orbit the nucleus where the number of electrons is 

determined by the atomic number. 



Revised 2006 3-5


Table 3-2 

The Periodic Table 

Types of Bonding 

Chemical Bonding 

Chemical reactions involve a rearrangement of the electron shells surrounding the atoms 

involved. This rearrangement generally produces a more stable structure and links the atoms 

together, thus producing a chemical bond. 

The most stable configuration is found to be a completely full outer shell of electrons. Simple 

chemical combination between elements can be explained by assuming that the atoms concerned 

are trying to attain this state. 

The so called “noble gases”, such as helium, neon and argon, which form group O of the periodic 

table, already possess full outer electron shells. These elements are thus extremely un-reactive 

and can only be made to combine with other elements under very specialized conditions. Other 

elements can obtain the “noble gas structure” by losing, gaining, or sharing electrons. 

Ionic Bonding 

Ionic bonding involves a transfer of one or more electrons from one atom to another. Atoms 

which have lost or gained electrons are ions. 

Electrons are negatively charged and thus, an atom that loses an electron becomes positively 

charged, as there are now more protons in the nucleus that there are electrons around it. A 

positively charged ion is called a cation and is denoted by writing a “+” sign as a superscript after 

the chemical symbol. Thus Na + is a sodium ion (one positive charge) and Mg 2+ is a magnesium 

ion (two positive charges, i.e., two electrons lost). 



3-6 Revised 2006


Atoms which gain electrons, and thus become negatively charged ions, are called anions. Thus 

Cl ⎯ is the chloride ion (one negative charge) and S 2⎯ is the sulfide ion (two negative charges, i.e., 

two electrons gained). 

Groups of atoms can also gain or lose electrons to become ions. For example, SO 2⎯ 4 is the sulfate 

ion. CO 2⎯ 3 is the carbonate ion and NH + 4 is the ammonium ion. A full list of these types of ions 

is given in Table 3-3. 

When an ionic bond forms, electrons are transferred in such a way that each atom attains a 

complete outer shell of electrons. When one electron is lost, the remaining electrons are held 

more tightly by the nucleus and it becomes progressively more difficult to remove them. True 

ionic bonds rarely exist when the transfer involves 3 or more electrons, as this procedure requires 

too much energy. 

Thus sodium, with one electron in its outer shell readily loses this electron to form the Na + ion. 

Chlorine, with seven electrons in its shell, readily accepts an electron to form the Cl ⎯⎯ ion. The 

compound sodium with chlorine, sodium chloride, is ionic and can be written Na + Cl⎯, in which 

each ion would again have a full outer electron shell. The formation of sodium chloride is 

illustrated schematically below. 

Figure 3-2 

Covalent Bonding 

The Formation of Sodium Chloride as an Example of Ionic Bonding 

Where electrons are shared between atoms, the bond said is to be covalent. This is illustrated in 

below for water and carbon dioxide. By this sharing process, the electron clouds of the atoms 

overlap such that each atom thinks it has a full outer electron shell. 



Revised 2006 3-7


Figure 3-3 

The Formation of Water and carbon Dioxide as Examples of Covalent Bonding 

Atoms can share one, two, or three electrons, thus forming single, double, or triple bonds. These 

bonds are denoted by lines joining the two atoms together. For example, carbon can form each of 

the following compounds all of which contain a single, double, and triple carbon-carbon bond, 

respectively. Although these compounds are made up of the same two elements, they differ in 

their chemistry due to the different carbon-carbon bonds present. 

H 

H 

H 

C – C 

H 

Ethane 

H 

H 

H 

C = C 

H 

H 

H 

Ethylene (Ethene) 

Valency 

Figure 3-4 

Differences in Compounds due to Chemistry 

The numbers of electrons which an atom needs to gain lose, or share to obtain a stable structure is 

called its valency. The valency of an element predicts the ratios in which it can combine with 

other elements. For example, two atoms of hydrogen (valency 1) combine with one atom of 

oxygen (valency 2) to form water. Three atoms of chlorine (valency 1) combine with one atom of 

aluminum (valency 3) to form AlCl 3. 

The table below shows that atoms with the same number of electrons in their outer shell all have 

the same valency. Thus all the group IA metals have valency 1, as do the group VIIA elements 

(which are known as the halogens). 



3-8 Revised 2006


Table 3-3 

Formula and Valency of Common Ions formed From Groups of Atoms 

Name of Ion Formula Valency 

Ammonium 

+ 

NH 4 1 

Nitrate 

+ 

NO 3 1 

Hydroxide OH¯ 1 

Hydrogen Carbonate 

HCO 3¯ 

1 

Hydrogen Sulfate HSO 4¯ 1 

Hydrogen Sulfite HSO 3¯ 1 

Dihydrogen Phosphate H 2 PO 4¯ 1 

Sulfate SO 42¯ 2 

Carbonate CO 32¯ 2 

Sulfite SO 32¯ 2 

Hydrogen Phosphate HPO 42¯ 2 

Phosphate PO 43¯ 3 

Some elements, particularly nitrogen, sulfur, and iron, can show more than one valency, as there 

is more than one way for them to obtain a stable electron configuration. The valency is written in 

brackets when describing the compound. Thus iron (II) chloride is FeCl 2 , iron (III) chloride is 

FeCl 3 . 

The concept of valency also applies to groups of atoms which carry a charge, such as the sulfate 

group SO 2⎯ 4 , which has valency 2. The valency in this case equals the number of electrons which 

have already been transferred, and thus equals the magnitude of the charge on the ion. Table 3-3 

gives the commonly occurring ions of this type. 

Determination of Bond Type 

Ionic and covalent bonding can both be present in the same compound. Figure 3-4 shows the 

structure of sodium carbonate. The two sodium ions and the carbonate ion are held together by 

ionic bonding, but the carbonate ion itself contains three covalent carbon-oxygen bonds. 

Figure 3-5 Sodium Carbonate Structure (schematic) 

In this example both types of bonding are present and are easily distinguishable. However, this is 

not always the case. Many ionic bonds have a certain amount of covalent character. This can be 

thought of as an incomplete transfer of the electrons involved so that the atom that has lost them 

still retains a small share. An example of this type of bonding would be zinc bromide, ZnBr 2 , 

which is used to prepare high density completion fluids. This compound can nominally be 

written as Zn 2+ Br⎯ 2 , but in fact the bond has considerable covalent character in that the zinc 

retains partial control over the two electrons which it has lost. 

Conversely, many covalent bonds show varying degrees of ionic character. Some atoms are 

greedy for electrons and when they enter into a covalent bond they try to take more than their fair 



Revised 2006 3-9


share. The electron orbitals are thus distorted towards them and the atoms develop partial 

charges. Water is the best known example of this. In the water molecule, the oxygen atom 

attracts far more than the two hydrogen atoms and the electrons are thus not shared equally. The 

orbitals are distorted towards the oxygen which thus develops a partial negative charge, written 

δ ⎯ . The hydrogen atoms develop a corresponding δ + charge. This type of covalent molecule is 

said to be polar. Where the electrons are shared equally, no partial charges develop and the 

molecule is non-polar. This is shown diagrammatically in 

Figure 3-6 

Polar and Non-Polar Covalent Bonding 

The tendency to attract electrons within a covalent bond is known as electronegativity. The 

electronegativity of an element depends on its position in the periodic table. 

Fluorine is the most electronegative element. It is followed by oxygen, nitrogen, and chlorine, in 

that order. The metals in groups IA and IIA are the least electronegative and are generally 

referred to as electropositive elements due to their tendency to form positively charged ions. The 

electronegative elements have the greatest tendency to form negative ions, though this is modified 

by the number of electrons needed to be gained. 

The larger atoms in groups IA and IIA lose their outer electrons very rapidly as they are a long 

way from the nucleus and shielded from it by the other electron shells. Thus, cesium and barium 

are more electropositive that sodium and magnesium respectively and more readily form cations. 

The group IA metals are more electropositive than their group IIA counterparts, as only one 

electron needs to be lost to form the stable ion. Thus potassium more readily forms K + ions, than 

calcium does Ca 2+ ions. 

The larger the difference between the electronegativity of two elements, the more likelihood there 

is of ionic bonding between them. Alternatively, if the bond is covalent, the more polar it will be. 

The electropositive elements in groups IA and IIA form strong ionic bonds and rarely, if ever, 

form covalent bonds. The metals in the middle of the table (groups IVB – IIB) are weakly 

electropositive and form either weak ionic bonds with the strong electronegative elements, or 

polar covalent bonds with the weak electronegative elements. The weakly electronegative 

elements form mainly covalent bonds but can form ionic bonds with the group IA metals. The 

strongly electronegative metals form ionic bonds with electropositive metals or polar covalent 

compounds with weakly electronegative elements. 



3-10 Revised 2006


Properties of Compounds 

Ionic Compounds 

Ionic compounds do not generally form discrete molecules. Instead, the ions tend to arrange 

themselves in a three dimensional lattice structure with each other surrounded by anions and vice 

versa. The relative number of cations to anions is the same as is written in the chemical formula. 

You will find the structure of sodium chloride illustrated in Figure 3-7. 

Figure 3-7 

The Sodium Chloride Structure 

The ions are held together in the lattice by strong electrostatic forces (ionic bonds) and it is 

difficult to force them apart. Thus ionic compounds are usually solids with high melting points 

and boiling points. The energy required to separate the ions is called the lattice energy. Lattice 

energies are usually quite large compared to other bond energies. 

Covalent Compounds 

In covalent compounds the bonds that hold together are usually quite strong, but there are strong 

forces holding the molecules together. These low intermolecular forces mean that covalent 

compounds tend to be liquids or gases, as the molecules are not sufficiently attracted to each 

other to hold them in place in a solid structure against the random molecular motion produced by 

thermal energy. 

The heaver the molecules, the more thermal energy is usually needed to separate them. Thus, 

compounds with high molecular weight usually have higher melting points and boiling points. 

The degree of polarity has a very important influence on intermolecular forces. In polar 

compounds these are increased by the attractions between the opposite partial charges, as shown 

in Figure 3-8. 

The polar attraction between molecules explains why water is a liquid, although having a lower 

molecular weight than Hydrogen Sulfide, which is a gas. (see Table 3-5) 



Revised 2006 3-11


Table 3-4 

Examples of Different Bond Types 

Example Formula Bond Type 

Potassium Chloride KCl Strongly ionic 

Iron (11) Chloride FeCl 2 Weakly ionic 

Iron (111) Chloride FeCl 3 Weakly ionic/covalent 

Carbon Tetrachloride CCl 4 Covalent, polar 

Chlorine Cl 2 Covalent, non polar 

Sodium Sulfide Na 2 S ionic 

Hydrogen Sulfide H 2 S Covalent, slightly polar 

Water H 2 O Covalent, strongly polar 

Diesel Oil 

Mixture of hydrocarbons (compounds of 

carbon and hydrogen) 

Covalent, non polar 

Figure 3-8 

Intermolecular Attractions in Water 

Organic and Inorganic Compounds 

Organic chemistry is the study of carbon compounds other than the simple carbonates, which are 

generally classified as inorganic. Organic chemistry is based around the ability of carbon to form 

chains of atoms linked by covalent bonds. These bonds are non-polar, as are the carbonhydrogen 

bonds which are also found in the majority of organic molecules. Crude oil consists of 

a mixture of organic molecules which are mainly compounds of carbon and hydrogen 

(hydrocarbons). Natural gas is mainly methane, CH 4 , the simplest organic molecule. 

Polar organic compounds are common – the molecules contain electronegative elements, such as 

oxygen and nitrogen. The table below shows the more commonly occurring polar groups. 



3-12 Revised 2006


Table 3-5 

Common polar groups in organic compounds 

GROUP 

FORMULA 

CARBOXYL 

– C 

O 

OH 

AMINE 

– C – NH 2 

AMIDE 

– C 

O 

NH 2 

HYDROXYL 

– C – OH 

SULFONATE 

– C – SO 2 H 

All of these groups are commonly found in the organic polymers used in drilling fluids. 

Inorganic compounds are the ionic ones (other than the salts of organic acids) and those covalent 

compounds which do not contain carbon. 

Solubility and Solutions 

Solutions are homogenous mixtures of various compounds. For the purposes of drilling fluids, 

only solutions in water and diesel oil will be considered. These two substances form the 

continuous liquid part of the solution, which is known as the solvent. The substance dissolved in 

the solvent is called the solute and may be solid, liquid or gas. If two liquids are soluble in each 

other, they are said to be miscible. 

Water is often described as the universal solvent, due to its ability to dissolve a large number of 

different substances. 

Many ionic compounds are soluble in water. The attractive forces between oppositely charged 

ions are reduced by the water, so that it may become possible for each individual ion to separate 

from the lattice, which thus breaks up. Each ion is normally hydrated, which means that it is 

surrounded by a shell of water molecules which, due to their polar nature, are attracted to the 

charge on the ion and are thus loosely bonded to it. This attraction of the solvent molecules to the 

ions is called solvation, in solvents other than water. 

The solution of sodium chloride in water can be written as NaCl + Water → Na + (aq) + Cl⎯ (aq) 

where (aq) denotes the hydration as depicted below. 



Revised 2006 3-13


O δ- δ + H δ+ H δ+ O δ- 

H 

H δ+ 

δ + Cl - 

H 

H δ+ 

H δ+ H δ+ 

O δ- O δ- 

Weak attraction. 

No permanent structure of water molecules 

H δ+ H δ+ 

H δ+ O δ- O δ- 

H δ+ 

H δ+ Na + 

O O δ- 

δ - H δ+ 

H δ+ H δ+ 

Strong attraction producing an order 

structure of water melecules around the ion 

Figure 3-9 

Hydration of Sodium Chloride in Water 

This ability to dissolve ionic compounds is solely due to the polar nature of water. Non-polar 

solvents, such as diesel oil, do not hydrate the ions and ionic compounds are not soluble in them. 

The salts that are soluble and insoluble are summarized in Table 3-6 The insoluble salts are 

generally those where both anion and cation are multivalent (i.e. their valency is greater than 

one). The attraction between multivalent ions is much stronger than that between univalent ions 

(with only one charge). Salts such as CaCO 3 have much higher lattice energies than salts such as 

NaCl. The hydration energies of the calcium and carbonate ions are not high enough to 

compensate for this high lattice energy and thus CaCO 3 is insoluble. In contrast, the energy 

released by hydrating sodium and chloride ions is sufficient to overcome the lattice energy of 

sodium chloride and thus NaCl is soluble. 

Solutions of a salt, or salts, in water are frequently termed brines and are a common base from 

which drilling fluids are often made up. 

Table 3-6 Solubility of Salts 

Anions 

* Soluble 

** Slightly Soluble 

*** Insoluble 

Cation OH¯ Cl¯ HCO 3¯ 

2– 

CO 3 

2– 

SO 4 S 2– 

Na + * * * * * * 

K + * * * * * * 

Mg 2+ *** * ** *** * – 

Ca 2+ ** * ** *** ** ** 

Ba 2+ * * ** *** *** * 



3-14 Revised 2006


Solubility of Covalent Compounds in Water 

Covalent compounds are generally soluble, or miscible, if they are polar. If polar groups are 

present, they tend to interact more strongly with water molecules than with each other. Thus the 

molecules split apart and the substance dissolves. There are no ions present, but each molecule is 

separated from its companions and the substance is said to molecularly dispersed. Examples of 

this type of compound include sugar, alcohol, and starch. 

Non polar covalent compounds are generally insoluble in water, as there are no strong attractive 

forces between them and the water molecules. Thus diesel oil is insoluble in water. 

Solubility of Gases in Water 

This is an important topic for drilling fluids, as small quantities of dissolved oxygen, carbon 

dioxide or hydrogen sulfide can have a large effect in making the fluid more corrosive. Hydrogen 

sulfide is also extremely poisonous and represents a real hazard to rig personnel. Carbon dioxide 

in solution can also alter the interaction between clay particles in a fluid and thus change the 

fluids rheological properties. All of these gases are soluble in water, particularly at high pressure, 

and efforts are generally made to exclude them as much as possible. 

Factors Affecting Solubility 

The maximum amount of a substance that can be dissolved under any given condition is called its 

solubility. This figure depends on the nature of the solute and solvent, and on the amount and 

type of other solutes already in solution. Most solubility’s increase when the temperature 

increases, although gases are an exception to this. The solubility of a gas decreases when the 

temperature rises, and increases when the pressure increases. The pressure effect is more 

important and gases are generally more soluble when a drilling fluid is at the bottom of a well 

than when it is on the surface. 

Other ions in solution have a very important influence. When a mixture of salts is present, the 

most soluble one suppresses the solubility of the other components. Sodium chloride and 

potassium chloride are much less soluble in concentrated magnesium chloride solutions. 

Reactions in Solution 

If two compounds which are soluble in water can react together to form an insoluble compound, 

then they will do so. Thus calcium chloride and sodium carbonate are both soluble in water on 

their own, but if they are mixed together, insoluble calcium carbonate precipitates out of solution. 

The reaction is written as follows: 

Na CO + CaCl → CaCO 2NaCl 

2 3 

2 

3 

+ 

Sodium chloride, being soluble, is left in solution. The reaction occurs because both the 

reactants, being ionic, are split up into their constituent ions in solution. When mixed together, 

the solution does not contain sodium carbonate and calcium chloride as such, but rather sodium, 

calcium, carbonate and chloride ions, and it is impossible to say which cation is associated with 

which anion. 

This type of reaction occurs very commonly in drilling fluid chemistry. It is the basis of many 

analytical tests and chemical treatments. Sodium carbonate is used, as above, to “treat out” 

soluble calcium, in order to maintain the correct chemical properties of the fluid. Silver nitrate 

(AgNO 3 ) which is soluble is used to test for chloride ions, due to the formation of insoluble silver 

chloride (AgCl). 



Revised 2006 3-15


These types of reactions also exert a strong influence on solubility. If a reaction can occur 

between two components, then their solubility’s will be interdependent. For example, the 

solubility of CMC (carboxymethylcellulose), a polymer commonly used in drilling fluids), 

depends on the concentration of calcium ions in the mud. If this exceeds a certain value, then the 

CMC precipitates out as an insoluble calcium salt. 

Intimate Mixtures of Solids, Liquids and Gases 

One characteristic of solutions is that they are homogenous mixtures. This implies that the solute 

should be split up into its constituent ions or molecules and that these should be dispersed 

uniformly throughout the solvent. Many insoluble substances apparently form homogenous 

mixtures with a liquid, but are not dissolved, as the mixture consists of very small particles of the 

substance dispersed throughout the liquid. Such a mixture is said to consist of two phases, as it 

contains two physically distinct parts. In contrast, a solution of sodium chloride in water is only 

one phase, as no physical distinction can be made between the sodium chloride and the water. 

The case of a solid mixed with a liquid or gas is called a suspension or dispersion. All drilling 

fluids are suspensions. If the particle size of the solid phase is fine enough, the solid stays in 

suspension and does not separate out under gravity. Thus a typical water-based drilling fluid 

consists of bentonite (a clay mineral) and barite (BaSO 4 ) suspended in water. Neither substance 

is dissolved, since both are insoluble and are not split up into ions or molecules. 

A liquid mixed into a different liquid with which it is immiscible is known as an emulsion. This 

is illustrated in Figure 3-10, for the case of water emulsified into oil. The water is dispersed in 

the form of fine droplets throughout the oil. The oil is known as the continuous or external phase. 

The water is called the dispersed, or internal phase. This example is the basis of the invert 

emulsion drilling fluid. These “invert” systems also contain calcium chloride dissolved in the 

water phase, and solids dispersed in the oil phase, giving an intimate mixture of three separate 

phases. 

OIL 

WATER 

Figure 3-10 Invert Emulsion Water Droplets in a Continuous Oil Phase 

A gas mixed into a liquid is called foam. Foams have been used as drilling fluids and consist of 

air dispersed in the form of bubbles throughout a continuous liquid phase (usually water). 

In a water-based drilling fluid, certain chemicals cause foaming by increasing surface tension 

stabilizing air/water mixtures. This is to be avoided as it leads to a decrease in mud weight and 

makes estimation of mud volumes very difficult. 

Dispersibility of Solids in Water 

Some solids are much more readily dispersed in water than others and the reason is again due to 

the polar character of water. Ionic compounds that are insoluble tend to disperse easily since 

water is attracted to the surfaces of the particles, which are charged, in much the same way as 

hydration of ions occurs for soluble compounds. This attraction is commonly known as water 



3-16 Revised 2006


wetting. Examples of solids which readily water wet are the rock forming silicate minerals, 

particularly clays, and the insoluble ionic compounds, such as barite (BaSO 4 ). The process is 

illustrated in Figure 3-11. 

Water wetting generally involves the formation of a monomolecular layer of water chemically 

adsorbed on to the surface of the particle. The arrangement of the water molecules depends on 

the distribution of charges, or partial charges, on the surface of the particle. The faces of clay 

minerals are normally negatively charged, thus attracting the hydrogen atoms in the water 

molecule (as in Figure 3-11). However, the edges of clay minerals usually carry positive charges 

and attract the oxygen atoms. 

Adsorbed water molecules 

H δ+ δ - δ δ - 

O 

O 

O 

H δ+ H δ+ H δ+ H δ+ H δ+ 

O 

O O 

O 

Si Si Si 

Clay 

mineral 

O 

O 

OH 

Al 

OH 

O 

O 

OH 

Al 

OH 

O 

O 

O 

Si Si Si 

O 

O 

O 

Figure 3-11 

Water Wetting of Clay Mineral Surfaces 

When water wetting occurs, the adsorbed water molecules are still attracted to the other water 

molecules in the liquid and thus the particles can be easily dispersed. This “solid-liquid” 

attraction partly accounts for the viscosity increase observed when an easily dispersed solid, such 

as bentonite is added to water. The other effect is the solid-solid interaction between the 

bentonite particles. 

Non-polar substances, as well as being insoluble in water, are difficult to disperse because there is 

no force of attraction between the surfaces of the particle and the water molecules. The particles 

are usually more attracted to each other and thus tend to stick together, inhibiting dispersion. A 

dispersion of diesel oil in water is therefore unstable if no surfactants are present. The droplets of 

diesel are more attracted to each other than to water and tend to coalesce, so that separation of the 

two phases occurs, giving a layer of diesel floating on the surface of the water. A surfactant, 

because it contains a polar and non-polar group on the same molecule, can concentrate between 

the water and oil, and thus make the two phase’s compatible, and an emulsion stable. 

Acids 

An acid is a compound containing one or more hydrogen atoms, which can be replaced by a 

metal, to form a salt. When acids are dissolved in water, they ionize to produce “hydrogen ions”. 

Strictly, these have the formula H 3 O + , but are generally denoted simply as H + , The common 

acids include hydrochloric acid (HCl), sulfuric acid (H 2 SO 4 ), and acetic acid (CH 3 COOH), which 

is an organic acid. 

The reactions with metals are illustrated by the following equations: 

2 HCl + Fe → FeCl2 

+ H 

2 

↑ 

Hydrochloric acid + iron → Iron (II) chloride + hydrogen 



Revised 2006 3-17


2CH 

3COOH 

+ 2 Na → 2CH 

3COONa 

+ H 

2 

↑ 

Acetic acid + sodium → Sodium acetate + hydrogen 

In both cases, the products are a salt and hydrogen gas. The number of hydrogen atoms that are 

available to be replaced is known as the basicity of the acid. Both hydrochloric acid and acetic 

acid are monobasic, since only one hydrogen is replaceable. Sulfuric acid is dibasic, as both of 

the hydrogen atoms can be replaced. 

Dibasic salts and tribasic acids can form salts in which not all of the hydrogen atoms are replaced. 

These are generally acidic in nature, as further replacement of hydrogen is possible. Examples 

Are: NaHCO 3 ,– sodium hydrogen carbonate, also called sodium bicarbonate, or bicarbonate of 

soda; NaH 2 PO 4 – sodium dihydrogen phosphate; and Na 2 HPO 4 – disodium hydrogen phosphate. 

Bases and Alkalis 

A base is a compound that will react with an acid to form a salt and water only. A base that is 

soluble in water is called an alkali. 

Bases are either oxides or hydroxides of metals. Alkalis are exclusively hydroxides of 

electropositive metals. Thus CuOH – copper (I) hydroxide and Fe 2 O 3 – iron (II) oxide are both 

bases, since they are both insoluble. NaOH – sodium hydroxide (caustic soda) and NH 4 OH – 

ammonium hydroxide, are both soluble and are alkalis. The reaction of an acid with a base and 

an alkali is illustrated by the following equations: 

FeO + HCl → FeCl + 2 

H 

2O 

Iron (II) oxide + hydrochloric acid → iron (II) chloride + water 

NaOH + HCl → NaCl + H 

2O 

Sodium hydroxide + hydrochloric acid → sodium chloride + water 

Both acid and base are said to be neutralized as the resulting solution is neutral, in other words, 

neither acidic (containing an acid) nor alkaline (containing an alkali). 

Other compounds react with acids to produce a salt and water, but are not strictly bases, as other 

compounds are formed in the reaction. Thus all carbonates and hydrogen carbonates are 

decomposed by acids, liberating carbon dioxide as a gas. For example: 

pH 

CaCO3 + 2 HCl → CaCl2 

+ CO2 

+ H 

2O 

Calcium carbonate + hydrochloric acid → calcium chloride + carbon dioxide + water 

This equation describes the reaction that occurs when acidizing a limestone reservoir rock to 

increase the flow of oil. A strong solution of hydrochloric acid is pumped down the well and 

reacts with the limestone (mainly calcium or magnesium carbonate), thus enlarging the fissures 

and pores in the rock and allowing the oil to flow more freely. 

Water itself is very slightly ionized under ordinary conditions. Thus a very small number of 

hydrogen and hydroxide ions exist free in solution and in equal numbers. 

H2O ↔ H+ + OH⎯ 

Water ↔ hydrogen ion + hydroxide ion 



3-18 Revised 2006


The reaction can proceed both ways and is said to be reversible. The reaction proceeds more 

easily from the right to left than from left to right. 

In one liter of pure water, there will be 10 –7 (0.0000001) moles of hydrogen ions (10 –7 grams) and 

10 –7 moles of hydroxide ions (17 x 10 –7 grams, as the molecular weight is 17). The concentration 

of H + ions, written as {H + }, is thus 10 –7 moles/liter and similarly {OH ⎯ } = 10 –7 moles/liter and 

{H + }·{OH ⎯ } = 10 –7·10 –7 = 10 –14 moles 2 /l 2 . 

The pH of a solution is defined as the negative log to the base of 10 of the hydrogen ion 

concentration. Thus pH = –log 10 {H + } where {H + } is in moles/liter. For pure water as above, 

with {H + } = 10 –7 moles/liter: 

pH = – log 10 {10 –7 } = 7 (since log 10 {10 –7 = –7} 

If an acid is added, the number of hydrogen ions in the solution increases such that the product of 

{H + }·{OH ⎯ } remains at 10 –14 (as long as the temperature remains constant). 

Thus if hydrochloric acid is added until {H + } = 10 –3 then pH = 3 and {OH – } = 10 –11 since 10 –3 x 

10 –11 = 10 –14 . The addition of an alkali to water increases {OH – }. Thus, {H + } drops and the pH 

rises above 7. If caustic soda is added to 10 pH, then {H + } = 10 –10 and {OH – } = 10 –4 . 

Acids always lower pH, alkalis always raise pH. A strictly neutral solution, with no acid or alkali 

present, has pH 7. Acid solutions have pH less than 7; alkaline solutions have pH greater than 7. 

This is illustrated below. 

Table 3-7 The pH Scale 

ACIDIC NEUTRAL ALKALINE 

pH 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 

[H + ]m/l 1 10 -1 10 -2 10 -3 10 -4 10 -5 10 -6 10 -7 10 -8 10 -9 10 -10 10 -11 10 -12 10 -13 10 -14 

[OH ⎯⎯ ]m/l 10 -14 10 -13 10 -12 10 -11 10 -10 10 -9 10 -8 10 -7 10 -6 10 -5 10 -4 10 -3 10 -2 10 -1 1 

The pH scale, running from 0 – 14, is adequate for the majority of situations, although some acids 

and alkalis, if they are very soluble, can produce pH’s outside this range. Drilling fluids are run 

at between pH 6 and pH 13.5, with the majority being moderately alkaline (pH 9 – 10.5). 

It is important to realize that pH is a logarithmic function. In pure water it takes ten times as 

much caustic soda to increase pH from 11 → 12, as from 10 → 11, as {OH – } must be increased 

by a factor of ten. 

Solutions at pH 6 – 8 are generally termed “neutral”, as they are so close to pH 7 as to make very 

little difference in properties. 

Strong and Weak Acids and Alkalis 

Strong acids are completely ionized in water such that all the molecules split up into ions. Acids 

of this type include hydrochloric and sulfuric acids. 

Weak acids are not fully ionized in concentrated solutions. The acid molecules are dispersed 

throughout the water, but only a small proportion of them split up into ions. Thus, at the same 

concentration, weak acids, such as acetic or carbonic acids, give a higher pH than strong acids, as 

there are fewer H + ions in the water. 

Similarly, strong alkalis, such as sodium and potassium hydroxides (the hydroxides of strongly 

electropositive metals) are fully ionized in solution and give higher pH’s than weak alkalis, such 

as calcium hydroxide or ammonia solution. In the case of calcium hydroxide, molecular 



Revised 2006 3-19


dispersion does not occur. The pH obtained is limited by the solubility, which about 1.6 grams of 

lime per liter at 20 º C, giving a pH of 12.5. 

Carbonic Acid and Carbonates 

Pure water at pH 7 is very difficult to obtain, because carbon dioxide from the air readily 

dissolves in it, forming a solution of carbonic acid. 

CO 2 + H 2 O ↔ H 2 CO 3 

Carbon dioxide + water ↔ carbonic acid 

Carbonic acid is a weak dibasic acid and the hydrogen carbonate ion is commonly referred to as 

the bicarbonate ion ionized to a small extent producing small numbers of hydrogen carbonate and 

carbonate ions. 

H 2 CO 3 ↔ H + + HCO 3 – ↔ 2H + + CO 3 

2– 

Carbonic acid ↔ Hydrogen ion + Hydrogen carbonate ion ↔ Hydrogen ion + Carbonate ion 

Thus distilled water frequently has a pH in the range of 4 – 6. 

If an alkali is added to water containing dissolved carbon dioxide, then the hydrogen ions 

produced by the dissociation of carbonic acid react with the alkali. The effect of this is to push all 

the reactions over to the right hand side, thus producing mainly carbonate ions at high pH (see 

Figure 3-12). This is one of the reasons for running drilling fluids at alkaline pH. Hydrogen 

carbonate ions can have a detrimental effect on the viscosity of clay based drilling fluids. By 

adding caustic soda they are converted into carbonate ions, which are less of a problem. 

100 

80 

60 

CO 2 

Mainly 

CO 2 

at low pH 

Pure Water 

Sea Water 

HCO 3 

Mainly HCO 3 

- 

ions at neutral 

pH 

CO 3 

Mainly 

CO 3 

2- ions 

at high pH 

40 

20 

0 

4 5 6 7 8 9 10 11 12 

pH 

Sea Water 

2¯ Figure 3-12 Distribution of the CO 3 - HCO 3¯- CO 3 System in Pure Water and Sea-water at 1 

atm. as a Function of pH 

Carbonates, which are soluble (only those of the Group IA metals, such as sodium), produce 

alkaline solutions by the reverse of the reactions given for carbonic acid. 

Na 2 CO 3 → 2Na + + CO 3 

2– 

Sodium carbonate → Sodium ions + Carbonate ion 

The hydrogen ions are provided by the ionization of water. Since hydrogen ions are removed, the 

pH increases. Thus sodium carbonate is occasionally used to increase pH in a drilling fluid. It is 

not as effective as caustic soda in this respect and the maximum pH that can be achieved in pure 

water is only 10.3. 



3-20 Revised 2006


Chemical Equilibria 

Many of the reactions that have been considered are examples of chemical equilibria. The 

ionization of water, written as: 

H 2 O ↔ H + + OH – 

is a description of an equilibrium. Both the forward reaction, H2O → H+ + OH– and 

the back reaction, H + + OH – → H 2 O, occur all the time at identical rates such that at one time: 

Where K is a constant, known as the equilibrium constant. 

+ − 

( H )( OH ) 

( H O) 

2 

= K 

In the case of water, where the amount of ionization that occurs is very small, the concentration 

of un-dissociated water remains constant so that: 

Therefore {H + }{OH – } = KC = 10 –14 moles 2 /liter 2 

Any one water molecule will never remain un-ionized for very long. It will be continuously 

changing from the un-ionized to the ionized state and back again. When an H + ion combines with 

an OH – ion, there is no special reason for it to combine with the same OH – ion with which it was 

formerly associated in a water molecule. Thus, the H + and OH – ions are continually changing 

partners with ions from different water molecules in an unending game of “musical chairs”. 

When something acts to change an equilibrium, it always does so such that the equilibrium 

constant remains constant. For example, when an acid is added to water, {H + } increases. Then in 

order to preserve the equilibrium, some of the hydrogen ions react with the hydroxide ions so that 

{OH – } decreases and {H + }{OH – } stays at 10 –14 moles 2 /liter 2 . 

Solubility of Lime 

The solution of slightly soluble salts is an important example of equilibria. The solution of lime 

(calcium hydroxide) in water is written:- 

And at equilibrium 

Ca(OH)2 ↔ Ca2+ + 2OH– 

2+ 

− 

( Ca )( OH ) 

{ Ca( OH ) } 

2 

2 

= K 

The {OH – } term is squared, since two OH – ions appear in the equation. For this reason the 

equilibrium is more sensitive to {OH – }, than to {Ca 2+ }. 

The un-dissociated lime remains as a solid (it is not molecularly dispersed) and has effective 

concentration of unity as long as it is present. 

If calcium ions or hydroxide ions are added to the system from an independent source, then the 

solubility of the lime will be suppressed. Thus, if caustic soda is added, {OH – } increases and 

{Ca 2+ } must decrease, so that the equilibrium is maintained. Thus the concentration of calcium in 

drilling fluids can be controlled by the addition of caustic. This is shown in Figure 3-13 (the 



Revised 2006 3-21


addition of sodium carbonate which removes all calcium as insoluble, calcium carbonate). Since 

the solubility of calcium is controlled by {OH – }, it can also be expressed as a function of pH. 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 1 2 3 4 

Caustic soda (lb/bbl) in water 

Figure 3-13 

Solubility of Calcium in a Solution Containing 4 lb/bbl Lime vs. Caustic Soda 

Addition 

Solubility of Other Compounds in Water 

The solubilities of many other compounds, other than lime, are also controlled by equilibria 

involving {OH – } and therefore, can be expressed as a function of pH. Generally, metal 

hydroxides are insoluble, thus the higher the pH, the higher {OH – } and the less soluble the metal 

becomes. Some elements with high valences form complex negatively charged anions at high pH 

and thus become more soluble. Silica, for example, forms the H 3 SiO 4 – and the H 2 SiO 4 2– ions and 

aluminum forms the aluminate ion, AlO 2 – . 

The electronegativity of an element can be looked at in terms of the charge and size of its cation. 

The group 1A metals, such as sodium and potassium, form singly charged cations which have a 

large ionic radius. As the charge on a cation increases, the size of the ion decreases. This is 

because, as electrons are lost, the nucleus exerts a greater pull on those electrons that are still left. 

Thus, reading along the third row of the periodic table (see Table 3-2), Mg 2+ is a smaller ion than 

Na + ; Al 3+ is smaller than Mg 2+ and Si4+, if it ever existed, would be smaller than Al3+ and so on, 

across the row. The other effect in determining ionic size is atomic weight. The higher the 

atomic weight, the more electrons there are and the more space they occupy. Thus, the K+ ion is 

larger than Na+ ion and similarly Ba2+ is larger than Mg 2+ . 

Hydration of Ions 

Most ions in solution are hydrated, that is they are surrounded by a shell of water molecules that 

form an organized structure around the ion. The size of this water shell depends on the intensity 

of the ions’ electric field. Thus small highly charged ions are extensively hydrated. The 



3-22 Revised 2006


attraction of water to doubly or triply charged metal ions is so strong that many of these metals 

form salts which contain chemically bound water, known as water of crystallization. Calcium 

and magnesium salts such as MgCl 2··6H 2 O or CaCl 2·2H 2 O, are common examples. If the water is 

driven off by heating, the resulting anhydrous salts absorb water readily from the atmosphere so 

that the hydrous salt reforms rapidly. Even in the hydrous form, the salts given above absorb 

water and if left standing in the open for long enough they will eventually absorb enough water to 

dissolve completely. The group 1A metals, being singly charged, are much less hydrated that the 

group IIA metals, such as calcium and magnesium. 

An important break occurs between sodium and potassium. The Na + ion of radius 0.98Å, is 

hydrated, but the K + ion, of radius 1.33Å is not hydrated, since the slight difference in size leads 

to the potassium ion having a lower electric field than the sodium ion. This means that the K + ion 

is effectively smaller than the Na + ion as it is not dragging around a shell of water molecules on 

its back. This is very important in determining the way in which these two ions react in solution 

with clay surfaces and also explains why strong potassium brines have less viscosity than strong 

sodium brines. This also explains why potassium form of clays (Illite) is more stable and is the 

basis of the potassium inhibited drilling fluids. Anions are not hydrated because they are much 

larger in size than cations. Thus the electric field around anions is not very strong. Temporary 

attraction of water molecules occurs, but no permanent structuring of the water molecules around 

the anion exists. 

Chemical Calculations 

An important aspect of drilling fluid engineering involves a careful chemical analysis of the fluid, 

as certain chemical characteristics can substantially affect the performance. Also, calculations 

have to be performed to determine treatment levels. This section deals with both these aspects. 

Concentration of Solutions 

The concentration of a solution is a measure of how much of a particular substance is dissolved in 

a certain volume or weight of solution. There are various ways of expressing this. 

1. Weight of solute per volume of solution (w/v). This is normally expressed in grams/liter 

(g/l), kilograms/meter3 (kg/m3), milligrams/liter (mg/l) or pounds per barrel (lb/bbl). 

2. Weight of solute per weight of solution (w/w). This is normally expressed as a 

percentage (%). Thus a 10% solution = 100g solute/kg solution. In lower concentrations 

it is expressed as parts per million (ppm). Thus, 1 ppm = 1 mg solute/kg solution and 1% 

= 10,000 ppm. Parts per thousand (ppt) is occasionally used as a unit, especially for sea 

water analysis. 1 ppt = 1,000 ppm = 0.1% 

3. Volume of solute per volume of solution (v/v). This is often used to describe mixtures, 

rather than true solutions, and is the unit used for retort analysis of drilling fluids. 

Thus 1% (v/v) = 1 m 3 of dispersed phase/100 m 3. 

4. Molarity (M). This is used mainly for laboratory analytical reagents. A one molar 

solution (1M) contains one mole (molecular weight in grams) dissolved in one liter of 

solution. 

5. Normality (N). Again, this is used mainly for laboratory reagents. A one normal solution 

(1N) contains one mole of solute divided by its valency in one liter of solution. 



Revised 2006 3-23


Element/Compound 

or ion 

Table 3-8 

Atomic/Molecular 

Weight 

Equivalent Weights 

Valency 

Equivalent 

Weight 

Na, Na + 23 1 23 

K, K + 39.1 1 39.1 

Mg, Mg 2+ 24.3 2 12.15 

Ca, Ca 2+ 40.1 2 20.05 

Fe(iii), Fe 3+ 55.8 3 18.6 

Cl – 35.5 1 35.5 

SO 4 

2– 

96 2 48 

H 2 SO 4 98 2 49 

HCl 36.5 1 36.5 

NaOH 40 1 40 

Ca(OH) 2 74.1 2 37.05 

CaSO 4 136.1 2 68.05 

Na 2 CO 3 106 2 53 

CaCO 3 100.1 2 50.05 

MgCO 3 84.3 2 42.15 

NaHCO 3 84 1 84 

AgNO 3 169.9 1 169.9 

NaCl 58.5 1 58.5 

Conversion of Units 

Conversion from w/v to w/w and vice versa, depends on the density of the solution, 

mg / L 

ppm = 

Density of Solution 

Or, converting the other way 

1% = 10 g/L x Density of the solution 

This relationship is ignored by many people in the oil industry who take ppm and mg/l as 

equivalent units. In a dilute solution, where the density is very close to 1.00 this is true. In heavy 

brines or weighted drilling fluids the units (ppm vs. mg/L) are very different. 

It is recommended that all analysis of drilling fluids be calculated on a w/v basis as g/l or mg/l. 

Conversions of molarity to w/v depends on the molecular weight. Thus 1M HCl contains 36.5 g 

HCl dissolved in one liter of solution, as the molecular weight is 36.5. Thus, 1M HCl = 36.5 g/l. 

Equivalent Weights 

The equivalent weight of an element or ion is: 

AtomicWeight 

equiv . wt. 

= 

Valency 



3-24 Revised 2006


For a compound, the equivalent weight equals: 

MolecularWt. 

equiv . wt. 

= 

TotalValency of " cations" 

Common equivalent weights are listed in Table 3-8. 

It can now be seen that a one normal solution contains the equivalent weight of the solute in 

grams dissolved in one liter of solution. 

For compounds of valency one, a 1M solution is identical to a 1N solution. If the valency is two, 

then a 1M solution is twice the strength of a 1N solution. 

Sulfuric acid (H 2 SO 4 ) has a molecular weight of 98 (a 1 M solution is 98 g/l) and “valency” 2. 

Thus its equivalent weight is 49 (a 1 N solution is 49 g/l). Thus, 1M H 2 SO 4 is 98 g/l. This 

compares with hydrochloric acid, HCl, where a 1M and 1N solution both contain 36.5 g/l. 

Calculation of Reacting Weights 

There are two methods: 

1. Write down the chemical formulas of the reactants and products and balance the equation 

which describes the reaction, bearing in mind the valences of the ions involved. This 

gives the ratios in which the molecules combine. Multiplying by the molecular weights 

thus gives the ratios of weights, which combine. 

An example calculation is given below. 

Calculate the weight of sodium carbonate needed to completely remove calcium from 100m 3 of a 

drilling fluid containing 1000 mg/l Ca + . 

The reaction of sodium carbonate with calcium is: 

Na 2 CO 3 + Ca 2+ → CaCO 3 + 2Na + 

from this equation, we know that 1 mole Na 2 CO 3 reacts with 1 mole of Ca 2+ 

Na 2 CO 3 molecular weight = 106 (Table 3-8) 

Ca 2+ molecular weight = 40.1 (Table 3-8) 

Thus, 106 g Na 2 CO 3 always reacts with 40.1 g of calcium. 100m 3 of drilling fluid, with Ca 2+ at 

1000 mg/l, contains 1000 x 100 mg Ca 2+ , or 100 kg Ca 2+ 

Units conversion 

1000 mg/L x 1000L/m 3 x 1 Kg/1,000,000 mg x 100 m 3 = 100 Kg 

Therefore, weight of sodium carbonate needed is: 

(106 / 40.1) x 100 kg = 264 kg 

3. This method involves the use of equivalent weights. The equivalent weights of 

elements always combine on a 1:1 basis, since the “balancing of the equation” has 

already been taken into account when dividing molecular weight by valency to 

obtain the equivalent weight. 

Referring to the previous example, sodium carbonate has equivalent weight 53, while calcium has 

equivalent weight 20.05. Therefore, when these combine, they will do so in the ration 53g 

sodium carbonate to 20.05g calcium. It is not necessary to know the formula of the reactants, nor 

of the products (or even what reaction occurs). 



Revised 2006 3-25


Thus to remove 100 kg of calcium requires (53/20.05) x 100 kg of sodium carbonate giving 264 

kg as before 

In some calculations, milliequivalents are used. This is simply 1/1000 of the equivalent weight. 

Thus 1 milliequivalent (1 me) is the equivalent weight in milligrams. 

Techniques of Chemical Analysis 

In order that a drilling fluid may function correctly, it is important to monitor its chemical 

composition. If the chemical composition varies from that required for optimum performance, 

then this variation will be detected and corrections can be made. 

Chemical analysis is nearly always done on the filtrate rather than on the drilling fluid itself. The 

reason for this is that the viscosity, solids content and even the color of the drilling fluid make 

analysis difficult or may interfere with the analysis itself. The filtrate can be used because, with 

the exception of polymers which are rarely analyzed for, it contains the same concentration of 

dissolved substances as the drilling fluid. 

Methods of Testing for Dissolved Ions 

The most common method is to take a solution of known strength (often called a standard 

solution) of a compound which reacts with the particular ion to be measured. This solution is 

added gradually to a known volume of the filtrate until the reaction is just complete. Then, 

knowing the volume of solution added, its concentration and the chemistry of the reaction that 

occurs, it is possible to work out how much of the ion under test is in the filtrate. This is the 

titration method of chemical analysis. 

This technique requires an accurate measure of the volumes of filtrate and standard solution and 

an accurate method for determining the “end point” of the reaction. This end point is the exact 

point at which all of the ions being tested for have reacted with the standard solution. 

Measurement of Volumes 

An accurate measurement of volumes is accomplished by using pipettes and burettes. These are 

glass or plastic tubes which are calibrated on the outside to measure liquid volumes. (See Figure 

3-14. 



3-26 Revised 2006


Graduation 

mark 

A. Bulb 

pipette 

B. Graduated 

pipette 

C. Burette 

Figure 3-14 

Pipettes and Burette Used in Chemical Analysis 

A bulb pipette (Figure 3-14 A) is used to measure out a certain volume, such as 5 or 10 ml, with 

far greater accuracy that a measuring cylinder. The pipette is dipped into the solution, which is 

then sucked up into the upper stem to above the graduation. 

After ensuring that there are no air bubbles trapped in the liquid, the level is then slowly dropped, 

using a finger on the top of the pipette, until the bottom of the meniscus coincides exactly with 

the graduation mark. The pipette is then removed from the liquid and the lower end wiped to 

remove liquid on the outside. The volume of liquid inside the pipette is then transferred to the 

required container by removing the finger at the top and letting the liquid drain out slowly. The 

pipette should not be blown our, nor should the last drop be shaken from the tip as this will alter 

the volume delivered. 

Bulb pipettes should never be used for any volume other than the one stated on the pipettes. The 

straight stem, or graduated pipettes (Figure 3-14 B), are usually calibrated to enable different 

volumes to be delivered. 

The burette (Figure 3-14 C), is like a graduated pipette with a tap at the bottom which controls the 

release of liquid. A burette is used for titrations as follows: 

With the tap closed, it is filled with the titrant. This is usually a standard solution which reacts 

with the ion under test. After filling, the tap is opened briefly to fill the lower part of the burette. 

The burette is then checked for air bubbles. If these exist they can usually be removed by gently 

tapping the sides of the burette or by rotating it rapidly (but carefully) between the palms of the 

hands. 

Before starting the titration, the level of titrant is recorded. The titrant is then added carefully to a 

known volume of filtrate (added by pipette to the titrating flask) until the end point is reached. 

The volume of titrant in the burette at the end point is then recorded and the volume used is 

simply the difference between this reading and initial one. 

The volume must never be allowed to drop below the last graduation mark or inaccurate readings 

will be obtained. If the end point has not been reached with the burette nearly empty, the titration 

is stopped, the volume is recorded and more titrant added to the burette with the new volume 

recorded as before. 



Revised 2006 3-27


Measurement of the End Point. 

The end point of titration is usually amplified by adding a suitable indicator to the titrating flask. 

An indicator is a chemical that changes its color when its chemical environment changes. For the 

indicator to be effective this color change must be abrupt and must occur over a very small range 

or chemical change. 

Different indicators are used for different titrations, depending on the chemicals involved. For 

acid-base titrations, phenolphthalein is commonly used. It is pink in alkaline solutions, but at pH 

8 - 8.3, it becomes colorless. The titration is stopped at this point as virtually all the alkali will 

have been neutralized at pH 8 – 8.3. The common indicators and the titrations for which they are 

used are shown below. 

Table 3-9 

Commonly Used Indicators 

Indicator Titration Color Change 

Phenolphthalein Acid/base Pink @ pH>8 – 8.3, Colorless @ pH4, Yellow @ pH 8, Red @ pH 4, Blue @ pH


Therefore, g Cl¯ in diluted filtrate = 19.1/1000 x 0.0282 x 35.5 (since atomic weight of Cl¯ is 

35.5) 

0.0282 x 35.5 = 1.0, which is why this strength of AgNO 3 is used as a standard solution. 

Calculating the concentration of Cl¯ in the solution, we have: 

mg Cl¯ = (19.1/1000 x 0.282 x 35.5) x 10 x 100 = 19.1 

Therefore, The 10 ml sample of x 100 diluted filtrate contains 19.1 mg Cl – 

The concentration in the diluted filtrate sample is thus (19.1 x 1000)/10 = 1919 mg/l and in the 

filtrate thus 1919 x 100 = 191,000 mg/l 

This corresponds roughly to the saturation value for sodium chloride at 20ºC. 

Other Methods of Analysis 

Very often it is found that there is no suitable indicator to determine the end point of a reaction. 

If this is the case, other methods must be used. 

A common solution to this problem is to add an excess of a standard solution to a known volume 

of the filtrate and precipitate the ion under test as an insoluble compound. Since excess of the 

reagent is added, all of the ions are precipitated and the amount of precipitate is thus proportional 

to the amount of the ion present in the filtrate. The amount of precipitate can be measured in 

three ways: 

1. “Gravimetric” Analysis. The precipitate is dried and weighed as accurately as possible. 

This method is rarely used on a drilling rig because of the need for expensive and delicate 

equipment and the time needed for the test. 

2. Centrifugation. The precipitate is centrifuged under standard conditions of speed and 

time and the floc volume in the centrifuge tube is measured. This is proportional to the 

weight of precipitate. The test is not particularly accurate and is comparative in nature 

rather than absolute. It is used quite commonly to measure potassium ion concentration 

and the concentration of certain polymers, as great accuracy is not usually required. 

3. “Turbidimetric” Analysis. This method is used for dilute solutions and depends on an 

estimate of the cloudiness (or turbidity) caused when the precipitate forms. The 

estimation can be done instrumentally using a photo-electric cell or it can be done by eye. 

It is again a comparative test and when the eye is used as a detecting “instrument’, there is 

no pretense of accuracy. This method is used to indicate the presence of the sulfate ion in 

drilling fluids by reaction with barium chloride solution. 

BaCl 2 + SO 4 2– → BaSO 4 ↓ + 2Cl – 

cloudy 

precipitate 

Two other techniques of analysis are occasionally used for drilling fluids. 

1. Flame Photometer. This is used for an accurate determination of sodium, potassium and 

lithium ions and depends on a measurement of the intensity of the light of a well defined 

wavelength that is emitted by these ions when they are heated. The instrument is quite 

delicate and is also fairly expensive. 

2. Colorimetric Analysis. This may be used to determine the quantities of silicon, iron or 

aluminum. These ions form colored complexes with certain chemicals. The intensity of 

color developed is proportional to the concentration of the complex and to the 

concentration of the ion under test. 



Revised 2006 3-29


Many other techniques for chemical analysis exist, but are rarely, if ever, used for drilling fluids, 

owing to the need for expensive, intricate equipment and trained operators. 

Common Names of Compounds used in Drilling Fluids 

Many different “chemicals” and minerals are used on drilling rigs. These are often known by a 

common name in the case of “chemicals”, or by their geological name in the case of minerals. 

Table 3-10 gives the main examples. 

Note that the term “lime” is used for two different compounds. This is due to historical reasons. 

Any product derived from heating limestone (mainly calcium carbonate), has been called in the 

past “lime”. Thus: 

CaCO 3 → CaO + CO 2 

This reaction produces calcium oxide (quick lime). On adding water this forms calcium 

hydroxide (slaked lime). 

CaO + H 2 O → Ca(OH) 2 

Table 3-10 

Common Names, Chemical Nature and Formula of Materials 

Common Name or Mineral Name Chemical Nature Formula 

Anhydrite Calcium Sulfate CaSO 4 

Barite or baryte or barytes Barium Sulfate BaSO 4 

Bicarbonate of soda or bicarb Sodium Hydrogen Carbonate NaHCO 3 

Calcite Calcium Carbonate CaCO 3 

Caustic or caustic soda Sodium Hydroxide NaOH 

Cement Calcium Oxide + clays CaO + clays 

Gypsum Calcium Sulfate CaSO 4 + 2H 2 O 

Lime or quick lime Calcium Oxide CaO 

Lime or slaked lime Calcium Hydroxide Ca(OH) 2 

Marble Calcium Carbonate CaCO 3 

Muriate of potash Potassium Chloride KCl 

Potash Potassium Chloride KCl 

Salt Sodium Chloride NaCl 

SAPP Sodium Acid pyrophosphate Na 2 H 2 P 2 O 7 

Soda ash Sodium Carbonate Na 2 CO 3 



3-30 Revised 2006


Conventional (Basic) Fluid Systems 

Spud Muds 

A spud fluid, often referred to as a spud mud, is normally a very simple inexpensive fluid for 

drilling the first and sometimes second intervals from surface. Under certain drilling 

environments such as reactive shales, water flows, surface gas, bit balling, and poor penetration 

rate, the spud mud requirements can be more complex. However, a typical spud mud is one of 

simplicity, low cost, and can be easily and rapidly mixed, due to the large volume requirements 

associated with large diameter surface hole in a traditional wellbore design. 

Spud fluids can vary considerably depending on lithology, make-up water, and hole size. When 

freshwater is available and surface formations contain considerable quantities of reactive clays, 

the well may be spudded with water only. As a contrast, when surface formations consist of 

loosely consolidated sand and/or gravel, it may be necessary to spud with a drilling fluid having 

good wall cake properties and sufficient viscosity to keep the hole clean. Some typical spud fluid 

practices are described below. 

Freshwater / MILGEL ® (Bentonite) 

Make-up water should be checked for calcium and magnesium. If the hardness check indicates a 

calcium ion concentration in excess of 150 mg/L, the water can be pre-treated with soda ash. As 

a rule of thumb, 10 lb of soda ash will lower the calcium by 100 mg/L in 100 bbl of water. Be 

careful to avoid over treatment with soda ash. This product can change from being beneficial in 

removing the calcium contaminant, to being detrimental by increasing the carbonate radical anion 

which is a clay flocculent After the make-up water quality is acceptable, a good spud fluid may 

be mixed by using one of the following procedures. 

1. Mix 20 to 25 lbm/bbl of MILGEL ® . Mixing rate will vary between two to 10 minutes per 

sack dependent upon the efficiency of the mixing equipment. In some cases, small 

quantities of lime may be added to bentonitic spud fluids (after bentonite is hydrated) to 

thicken the fluid and improve hole cleaning. If optimum cake quality and filtrate is 

desired it is better to use additional viscosifiers and avoid the addition of lime, a 

recognized clay flocculent and source of calcium ion. 

2. Add 10 to 12 lbm/bbl of SUPER-COL ® . The yield of SUPER-COL is approximately 

twice that of MILGEL. SUPER-COL ® results in a lower solids concentration than 

MILGEL formulations, and uses half the volume of product which may be critical on 

some wells. 

Note: 

SUPER-COL should not be used where chlorides are above 2000 mg/L or where hardness 

cannot be reduced to less than 100 mg/L. 

3. Bentonite extenders (e.g. BENEX) added to MILGEL slurries increase the viscosity of the 

suspension. Normally, two sacks of BENEX and 10 to 12 sacks of MILGEL per 100 bbl 

of fluid result in an excellent freshwater spud fluid. Depending on the quality or amount 

of peptizing on the bentonite in use these extenders may not perform as efficiently. The 

best results are obtained with BENEX when combined with a non-treated bentonite, such 

as MILGEL ® NT. A disadvantage of this system is the increased mixing complexity. 

Normally, a mixing tank with a chemical feed pump is required for mixing and adding 

extenders. Care must be taken to hydrate the bentonite extenders thoroughly to remove 



Revised 2006 3-31


lumps and so provide efficient use of these polymers, and optimum extension of the clay. 

Mixing clay extenders in a five gallon bucket with a nail hole in the bottom for dripping 

the clay extender into the flowline will work as a “poor-boy” method, but leaves a lot to 

be desired for proper metering of the product into the active system. 

Brackish Water and Seawater 

Brackish water and seawater are often used as make-up water for spud fluids on inland barge and 

offshore drilling operations. The sodium chloride content generally ranges from 10,000 to 35,000 

mg/L. Hardness ranges from 300 to 1300 mg/L depending upon proximity to river drainage. 

Although hardness may be reduced to an acceptable level by adjusting the pH to 10.5 with caustic 

soda, the chloride content cannot be treated out economically, thus it remains as a contaminant 

which suppresses the yield of bentonite. Therefore, bentonite should be pre-hydrated in fresh 

water, or other viscosifiers such as SALT WATER GEL should be considered if this water is to 

be used. 

SALT WATER GEL (attapulgite) is an effective viscosifier in a sodium chloride environment. 

Normally, 20 lbm/bbl (with good shear) is sufficient to obtain sufficient hole cleaning on surface. 

Pre-hydrated bentonite can provide additional viscosity and will also improve the quality of the 

filter cake. However, if facilities are not available for pre-hydration the addition of 5 to 6 lbm/bbl 

of MILGEL directly to the system improves cake characteristics to some extent. Attapulgite is not 

allowed in many parts of the world due to working environment concerns related to lung disease. 

A proper respirator or breathing filter mask must be used while mixing SALT WATER GEL as a 

safety measure. When the clay is in the wet state no potential working environment risks exist. 

GUAR GUM (2 to 4 lbm/bbl) is a cost-effective viscosifier in seawater and is commonly used in 

offshore environments, especially where drill water (freshwater) supplies may be limited. GUAR 

GUM viscosity decreases with increased temperature and has a temperature limit of 

approximately 150°F. GUAR GUM is typically used for viscous pills. GUAR GUM fluid should 

not be stored in the pits for greater than 24 hours due to the possibility of bacterial degradation. It 

is recommended that a bactericide/biocide be used to prevent degradation. 

Seawater is often used for fluid make-up and maintenance on inland barge and offshore drilling 

operations, primarily because of its availability and inhibitive characteristics. 

The ionic composition of typical seawater is noted below. 



3-32 Revised 2006


Table 3-11 

Composition of a Typical Seawater Sample 

Constituent 

mg/L 

Sodium 

Potassium 

Magnesium 

Calcium 

Chloride 

Sulfate 

Carbon dioxide 

10,400 

375 

1,270 

410 

18,970 

2,720 

90 

(Density above - 8.56 

lbm/gal) 

Hydration and subsequent swelling of clays and reactive shale is minimized by the sodium 

chloride, magnesium, and calcium in seawater. 

These inhibitive properties are particularly useful when drilling the surface interval of a hole with 

a non-dispersed, low pH fluid system. 

A dispersed system may be required for drilling other intervals, however. These same inhibitive 

properties make it more difficult and costly to control and maintain the rheological and filtration 

characteristics of the fluid. 

For non-dispersed seawater fluids, use a viscosifier (SALT WATER GEL, pre-hydrated 

MILGEL) and, if filtration control is necessary, use materials such as BIO-PAQ ® , CMC or MIL- 

STARCH ® and pre-hydrated MILGEL. Pre-hydrated MILGEL contributes to viscosity and filter 

cake quality and gives a slight fluid loss reduction. The advantage of pre-hydrating bentonite 

prior to its addition to salt water is illustrated below. 

Figure 3-15 

Fluid Loss and Viscosity with Bentonite Prehydration 

Pre-hydrated bentonite mixtures can be prepared by mixing 25 to 35 lbm/bbl of MILGEL in 

freshwater. To this slurry is added 0.5 to 1 lbm/bbl UNI-CAL ® and 0.2 to 0.4 lbm/bbl of caustic 

soda. To this slurry is added 10 to 15 lbm/bbl additional MILGEL. This mixture is generally 

added at an initial concentration of 25% to 30% of circulating volume, and then added as required 



Revised 2006 3-33


while drilling. A defoamer such as LD-8 may be required (0.5 to 1.5 gal/100 bbl of volume) to 

control foaming. 

As drilling progresses, it is usually desirable to disperse or deflocculate fluid solids and lower 

API filtrate. Addition of 2 to 6 lbm/bbl of UNI-CAL ® , 4 to 12 lbm/bbl of LIGCON ® or 

CHEMTROL ® X, 0.25 to 1 lbm/bbl of CMC, and caustic soda as required for a 1 to l.5 P f (10.0 to 

10.5 pH) results in a fluid with excellent flow properties and a filtrate value in the range of 4 to 8 

cc. To aid in filtrate control and cake quality, bentonite should be maintained (by Methylene 

Blue Test) in the 15 to 25 lbm/bbl range. If improved inhibition from magnesium is desired, pH 

should be maintained below 10. Magnesium begins to precipitate as magnesium hydroxide at 

higher pH ranges. Rheological properties and filtration control will be less difficult, however, if 

magnesium is precipitated. 

Seawater fluids require substantially greater additions of caustic soda for alkalinity control than 

freshwater systems. This is due in part to the loss of hydroxyl ion reacting with magnesium, drill 

solids, and commercial clay. 

In an effort to improve inhibition, lime or gypsum base seawater fluids are sometimes employed. 

UNI-CAL is normally used as a deflocculant and CMC, MIL-PAC, or MILSTARCH are 

generally required for filtration control. Although some improvements in stabilizing gumbo 

shales have been observed with this approach, the most effective method for preventing bit and 

collar balling and flow line plugging while drilling highly bentonitic gumbo shales is controlled 

drilling. This reduces the packing action of drilled solids. These hazards exist when the total 

clay solids approach or exceed 10%. In some areas of drilling activity it may be a lesser amount 

and in others a higher concentration of solids can be tolerated. It is the instantaneous penetration 

rate that is the culprit impacting the packing action. If a penetration rate of 90 feet per hour is the 

calculated rate to prevent balling, that means 90 feet per hour for the total stand. Not 20 minutes 

and then reaming the hole for the remainder of the hour. 

In summary, seawater is often used in offshore drilling operations to avoid transportation of 

freshwater. Non-dispersed seawater fluids also offer substantial inhibition against clay swelling 

and are sometimes effective in stabilizing bentonitic intervals while drilling the surface hole. If a 

dispersed fluid with low fluid loss is required, treating costs will be considerably greater than 

with comparable freshwater fluids. For this reason, seawater is often used on the surface portion 

of the hole in many operations. Chlorides are then gradually reduced with freshwater additions as 

rheological properties and filtration control requirements become more stringent. 

Saturated Salt Water Fluids 

Saturated salt water fluids are generally limited to drilling operations encountering salt 

formations. Saturated salt fluids are prepared by adding NaCl to water up to saturation and then 

adding appropriate viscosifiers and fluid loss control agents. In some instances, freshwater fluids 

are converted to salt fluids by inadvertently drilling into salt formations. At such a point a 

decision has to be made as to the route to take while drilling the salt interval. Let the formation 

saturate the fluid and start treating the system with salt tolerant additives, or stop the drilling 

process and saturate the active system or dump the active system and build a saturated salt mud 

from scratch. 

Preparation of Saturated-Salt Fluids 

Initially, sufficient salt should be added to saturate the system. At 60°F, approximately 127 lb of 

salt per barrel of freshwater is required. A volume increase of approximately 13% is obtained 

when 127 lbm/bbl of salt is added. 



3-34 Revised 2006


With good mixing conditions (good shear) 20 to 25 lbm/bbl of SALT WATER GEL generally 

yields a funnel viscosity in the range of 35 sec/qt. 

MILSTARCH should be mixed through the hopper slowly to prevent high-viscosity peaks. Four 

to six lbm/bbl of MILSTARCH usually produces a 5 to 10 cc API fluid loss, depending upon the 

amount and type of solids present. 

Caustic soda should be added to obtain a pH of 10.0 to 11.0 (l.0 or greater P f ). Higher 

alkalinities reduce the tendency to foam and minimize corrosion. Calcium and magnesium levels 

are also reduced. 

Organic deflocculants such as UNI-CAL and DESCO ® are beneficial in some instances for 

thinning (UNI-CAL offers maximum effectiveness if dissolved in freshwater prior to addition), 

but viscosity control is achieved primarily through dilution and with solids control equipment. In 

some instances, small additions of MIL-PAC or CMC have been noted to have a thinning effect 

on saturated salt fluids. 

Since MILSTARCH will begin to degrade at temperatures in excess of 250°F, it may be 

necessary to utilize supplementary additions of MIL-PAC. MIL-PAC is stable at temperatures to 

about 300°F. Salt-saturated systems display a foaming tendency, but this problem can be 

minimized or eliminated with defoamers such as LD-8 or W.O. DEFOAM. 

Starch fermentation is generally not a problem if the system is saturated with salt or if pH is 11.5 

or above. However, to insure against starch fermentation, add a suitable biocide. 

Where high salinity, salt saturated produced brines are used to prepare starch based fluids, it may 

be necessary to run the resulting system without pH control. Certain produced brines can exhibit 

an acidic pH and be high in hardness (Ca ++ and Mg ++ ) thereby negatively affecting the addition of 

Caustic Soda. In this case is usually more economical to run the system without pH control, 

therefore eliminating this measure as a means of preventing fermentation. The high salinity of 

the brine alone may not be a deterrent to fermentation. 

Anaerobic bacteria can exist in certain produced brines. Starch based systems are a food source 

for such bacteria and once exposed to these circumstances, degradation and fermentation of the 

starch can proceed at a rapid rate. It will be necessary to treat the system with a biocide to 

prevent fermentation prior to the addition of the starch. Once fermentation starts, it may be 

impossible to get enough biocide into the system to offset the problem. In this case, treatment 

with the biocide prior to adding any starch will be necessary. 

Case History No. 1 

Extremely high-density (20.0 to 21.0 lbm/gal) saturated-salt fluids are commonly employed in 

southern Iran. These fluids are prepared with barite, saturated salt water and 12 to 18 lbm/bbl of 

starch. The starch furnishes the desired filtration control. API filtrate is usually below 1 cc with 

this concentration of starch. 

The local barite often contains a high percentage of low-gravity solids and some of the formations 

penetrated are “fluid making.” For this reason, it is essential to utilize fine screen shakers and 

centrifuges. The pH is maintained in the 7.0 to 7.5 range with Caustic Soda. 

Case History No. 2 

The Nisku formation on the Western flank of the Williston Basin in Montana has been analyzed 

to contain certain strains of bacteria. Drilling this formation releases the bacteria into the mud 

system. If a starch based mud is used to drill the Nisku, it will be necessary to pre-treat the 

system with a biocide to kill the bacteria before the formation is penetrated. Otherwise, the 



Revised 2006 3-35


bacteria will attack the starch and fermentation will proceed at a rapid rate. This will be observed 

by a rapid loss of fluid loss control. 

Prehydrated MILGEL and Salt Fluids 

Pre-hydrated MILGEL salt fluids are used in top hole drilling for hole cleaning and suspension. 

The pre-hydrated MILGEL slurry increases the yield point and gel strengths due to flocculation 

of the bentonite with salt compounds. These properties give the fluid excellent carrying capacity. 

Colloidal Protected MILGEL may be pre-hydrated as follows. 

• 1.0 bbl Drill Water 

• Soda Ash (as needed) 

• 0.5 lbm/bbl Caustic Soda 

• 20 to 25 lbm/bbl MILGEL 

• 0.50 to 2.0 lbm/bbl UNI-CAL 

• 15 to 20 lbm/bbl additional MILGEL 

This slurry should be mixed thoroughly before it is added to the salty drilling fluid. 

Since pre-hydrated bentonite contributes very little to fluid loss control, normal salt water fluid 

loss control materials such as MILSTARCH should be used as required. 

The high gel strengths of these fluids contribute to the retention of air or gas. Adding small 

quantities of MIL-PAC and UNI-CAL will aid in controlling gel strengths and allow gases to 

break out of the fluid. LD-8 or the alcohol-base defoamers may also be required to control gas or 

air entrainment and foaming. 

Avoid using surface guns for fluid agitation because they tend to inject air into the system, 

foaming problems are inherent to saturated salt systems. 

High-Salt or Salt-Saturated Polymer Fluids 

High-molecular-weight polysaccharides and XAN-PLEX ® (xanthan gum) are unique because 

they perform in saturated salt water as well as freshwater. XAN-PLEX has shear thinning 

characteristics which result in very low bit viscosities with good annular viscosity recovery as 

shear rate decreases. This characteristic contributes to increased penetration rates and good hole 

cleaning. 

Under laboratory conditions these polymers start to degrade at temperatures above 250°F. 

However, this does not prevent their practical use at temperatures greater than this range. 

Polymers tend to exhibit lower viscosities as temperature increases. Viscosity may decrease to 

one-half or less when temperature is increased from 125°F to 250°F. For this reason, 

supplementing the material with small quantities of pre-hydrated MILGEL (5 to 10 lbm/bbl) 

would be advantageous. Bentonite tends to flocculate at elevated temperatures, which helps 

counteract the temperature thinning action on the polymers. 

If an API filtrate below 20 to 25 cc/30 min is desired, it is necessary to add a supplementary 

filtration control material such as BIO-LOSE ® or MIL-PAC. Small additions of MIL-PAC (0.1 

to 0.25 lbm/bbl) may have a thinning effect on these fluids if they contain flocculated drill solids. 

Although deflocculants are not normally added to this system, pre-solubilized UNI-CAL can be 

added. The pH of these fluids is usually maintained on the basic side (10.0) to minimize 

hardness. Caustic Soda is used, but should be added slowly to prevent momentary pH humps 



3-36 Revised 2006


above 11.0, which can be detrimental to the polymer. In most drilling situations (high salinity 

and pH), these polymers will not usually biodegrade. If, however, a polymer system is to be 

stored or bacterial degradation is a possibility, a preservative should be added (0.25 to 0.5 

lbm/bbl). 

Note: 

Once fermentation starts, it is too late to treat with a preservative. 

Although this system has mostly been associated with low-solids applications, it can be weighted 

if higher densities are necessary. The performance of a weighted system can be improved with a 

centrifuge and fine screens on the shakers to minimize the incorporation of drilled solids. 

Phosphate-Treated Fluids 

Phosphates are used for deflocculating drilling fluids. The ones most commonly used are sodium 

tetraphosphate (OILFOS ® ) which has a pH near 7.0 and sodium acid pyrophosphate (SAPP) 

which has a pH near 4.0. 

Sodium tetraphosphate and SAPP are most commonly used to control rheological properties in 

freshwater, low-solids systems. Treatments of 0.1 to 0.2 lbm/bbl are normally sufficient when the 

system is maintained in the 8.0 to 9.0 pH range. Care should be taken to avoid overtreatments 

which results in excessive viscosity. 

Since SAPP sequesters calcium and reduces pH, it is often used to combat cement contamination. 

The amount required depends upon the severity of the contamination. However, as a general 

guide, 0.2 lbm/bbl of SAPP will treat out approximately 200 mg/l of calcium ion. Monitor the 

chemical properties of the fluid (P m , pH, P f , Ca ++ ) carefully. When the P m to P f ratio approaches 

3:1, discontinue use of SAPP to avoid over treatment. 

Phosphates revert to orthophosphates at temperatures above 175°F. Orthophosphates will not 

thin above this temperature, but still function as a sequestering agent. Therefore, this material is 

rarely used at deeper depths, because of the temperatures normally encountered. Phosphates are 

also ineffective as dispersants in the presence of severe calcium and salt contamination. 

Under proper conditions phosphate fluids offer good rheological properties at a minimum cost. 

Caustic Soda is normally added for pH maintenance. Small quantities of tannin-type dispersants 

may further enhance deflocculation of the system. MILGEL ® is added periodically to improve 

filter cake and to reduce filtrate. 

Tannin and Lignin Fluids 

Additives rich in tannin, namely quebracho, were commonly employed as thinners prior to the 

advent of lignosulfonate. The material is derived from the quebracho tree and normally has a pH 

of 3.8. 

Most quebracho products are a quebracho extract blend. These are used primarily as a thinner in 

freshwater drilling fluids for moderate depth wells. The product is unstable at temperatures 

above 240°F. It also loses its effectiveness in environments containing excess salt (6000 to 7000 

mg/L) or calcium ion (240 mg/L). The system can be maintained at a pH as low as 9.0, but it will 

tolerate more salt and calcium contamination at pH ranges of 10.5 to 11.5. When used as a thinner 

for freshwater fluids, 1 to 2 lbm/bbl of the material is normally required. When used with lime 

fluids, 2 to 4 lbm/bbl will be needed for initial conversion. For treatment of cement 

contamination in freshwater fluids, concentrations of 1 to 2 lbm/bbl are usually sufficient. 



Revised 2006 3-37


Note: 

Quebracho, as a deflocculant, is rarely used and is only mentioned in case it is encountered 

while drilling in a remote location. 

Lignite materials (LIGCO ® , LIGCON ® , and CHEMTROL ® X) are normally used for filtration 

control and are sometimes used in low-solids, freshwater fluids as thinners. Generally, lignitic 

materials are less effective as thinners than tannates and lignosulfonates. When treating with 

lignitic materials, first add sufficient CAUSTIC SODA (1:2 to 1:4 mixture) to obtain a pH of 9.5 

to 10.5, otherwise the product is not soluble and non-functional. Treatments of 1 to 2 lbm/bbl are 

normally recommended when these materials are used as thinners in freshwater fluids. 

The tannin and lignin fluids of the 1940s and 1950s gave rise to newer modifications. Although 

there are still applications for this technology - in shallow holes - today's deeper holes often 

require higher temperature stability and broader tolerance to salt. 

The tannins most commonly to be used are DESCO ® and DRILL-THIN ® , which is a 

sulfomethylated quebracho, applicable across a wide range of pH, with the optimum being 9 to 11 

pH. Salinity tolerance from freshwater to saturated is also possible. 

DESCO ® CF is a chrome-free version of DESCO. Additional technical information on DESCO, 

DESCO CF, and DRILL-THIN can be obtained from Drilling Specialties Company technical 

literature. 

Calcium-Base Fluids 

Clay swelling is generally attributed to the penetration of water along the planar surfaces of the 

mineral, increasing the cleavage spacing between adjacent sheets. These individual clay layers 

are stacked one upon another in varying thicknesses and held together by cations such as sodium 

and calcium, which occupy sites on the silica sheets. 

The degree of volume increase depends upon the clay that is hydrated and the cation type and 

concentration in the surrounding water. Sodium clays give the greatest hydration. Because of the 

dissociation of the sodium cation, the attractive forces which bond the platelets together are 

weakened to the extent that individual sheets literally float away from each other and disperse in 

the aqueous environment. This dispersion is even greater with agitation and high pH. On the 

other hand, calcium clays exhibit considerably less hydration because the calcium ion does not 

readily dissociate from the silica sheet and attractive forces remain strong. 

For equal concentrations, sodium clays have the capacity for greater expansion than calcium 

clays. The degree of expansion decreases as the clay type changes from sodium to calcium. 

Consequently, sodium clays have greater viscosity building potential in freshwater fluids than do 

calcium clays. 

Obviously, it is not always possible to predict the type of clays that will be encountered in drilling 

operations, but we can control the type of environment to which these cuttings are exposed. 

Since the rate and degree of cation dissociation is directly related to the type and concentration of 

cations present in the surrounding water, we must also consider the process of cations leaving the 

surrounding aqueous environment and replacing the cations attached to the basal plane surface. 

The relative replacing power of one cation for another is, 

(highest) H + → Ca ++ → Mg ++ → K + → Na + → Li + (lowest). 

This indicates that the calcium ion will readily displace the sodium ion. This phenomenon is 

referred to as Base Exchange. It should be noted, however, that this process is also subject to 



3-38 Revised 2006


reverse mass action effects, i.e., sodium will displace calcium from clays if a sufficient 

concentration is present. Therefore, Base Exchange depends on the type and concentration of all 

cations present as well as the surrounding environment. 

High concentrations of calcium are added to a drilling fluid in an effort to convert sodium clays to 

calcium clays and also to create a calcium environment for incorporated cuttings to minimize 

their hydrated volume through Base Exchange. Consequently, the relative viscosity effect will be 

less. This method of controlling the hydrated volume of formation clays is often called 

inhibition. 

There are currently two main types of calcium treated fluids available. 

Lime, Ca(OH) 2 

Gypsum, CaSO 4 • 2H 2 0 

Lime Muds 

Lime fluids have been used since the early 1940s and were the first of the calcium-base fluids. 

Primary application of lime fluids has been in areas where inhibition of reactive clays was desired 

and to improve the fluid systems' tolerance for salt, anhydrite, and drilled solids. Due to their 

tendency to solidify at elevated temperatures, particularly in fluids with high solids 

concentrations, these fluids are seldom used in wells having downhole temperatures in excess of 

275° to 300°F. 

Classification of Lime Muds 

1. High-Lime Fluid 

• 5 to 10 ml Pf 

• 5 to 15 lbm/bbl excess lime 

• 80 to 120 mg/L filtrate calcium 

2. Low-Lime Fluid 

• 0.8 to 2.0 ml P f 

• 1.0 to 2.5 lbm/bbl excess lime 


3. Modified-Lime Fluid 

• 2 to5 ml P f 

• 2 to 5 lbm/bbl excess lime 


Preparation of Lime Fluids 

1. The degree of viscosity change during and after conversion to a lime fluid depends upon 

the total solids concentration of the fluid system. Therefore, dilution with water is 

necessary prior to conversion. Fine screen shakers and centrifuges are recommended for 

weighted fluids, and shakers and hydrocyclones (desilters and desanders) are desirable for 

low-weight fluids. 



Revised 2006 3-39


2. The type of clay solids present in the fluid influences the viscosity during conversion. 

Because MILGEL has a much higher base exchange capacity than most drilled clays, the 

viscosity increase is much more pronounced when converting fluids that contain high 

concentrations of MILGEL (MBT for base exchange capacity gives a general idea of 

conversion severity). 

3. The type and amount of deflocculating agents added to the fluid prior to conversion have a 

significant influence on viscosity during conversion. If a phosphate has been used, the 

conversion will normally be drastic viscosity humps which are prolonged due to the 

reaction between phosphate, lime, and solids all caught up in a mass ion impact while 

displacement and sequestering is all taking place simultaneously. 

4. Maximum agitation should be maintained in the surface active system. 

5. Pilot tests should be run prior to conversion to help determine amounts of dilution and 

concentration of conversion chemicals needed. 

6. The pits should have adequate space available to allow room for dilution. 

7. Necessary amounts of lime and deflocculant should be stacked near the hopper, and 

caustic soda should be carried to the top of the suction (mixing) pit. Lime and 

deflocculant are added through the hopper. Caustic soda is added directly to the suction 

(mixing) pit near the point of maximum agitation. 

8. Accurate circulation time should be determined so that conversion materials can be added 

at timed intervals over a period of one or two complete circulations. 

Conversion Procedure 

1. Conversion to a lime fluid should be initiated shortly after a new bit has been placed on 

bottom, i.e. once the conversion starts it should not be interrupted until the system has 

achieved stability. Best results are obtained when the conversion is made inside the 

casing prior to drilling out. 

2. The amount of material needed for conversion will vary depending upon the desired 

properties and the condition of existing fluid. Most conversions can be made as follows. 

3. Drilling fluid systems low gravity solids content has been diluted to a minimum solids 

content of 3 to 5% by volume. If the system is weighted then the calculated dilution 

volume is to be added simultaneously with the necessary chemical additions. The biggest 

concern is that after the breakover the fluids viscosity could drop so low that the barite 

may fall out of a weighted system. 

• 2 to 4 lbm/bbl deflocculant (UNI-CAL ® ) 

• 2 to 3 lbm/bbl caustic soda 

• 4 to 8 lbm/bbl lime hydrate [Ca(OH) 2 ] 

• 1 to 2 lbm/bbl MILSTARCH ® with preservatives 

• 0.5 to 1 lbm/bbl CMC 

4. The deflocculant should be started through the hopper while caustic soda is added to the 

pit. After five or six sacks of deflocculant and two or three sacks of caustic soda have been 

added, the lime additions should begin and be mixed through the hopper along with the 

deflocculant. The lime addition will cause a viscosity hump, but the system will “break 

over” when agitated and become quite fluid. If the viscosity becomes excessive, the rate 



3-40 Revised 2006


of addition of deflocculant and caustic soda should be increased along with an increase in 

water dilution. 

5. The API Filtrate is normally controlled with starch and/or CMC. Periodic additions of 

MILGEL ® normally should be accompanied by treatments with a deflocculant. 

6. After all chemicals have been added to the fluid system, a check should be made of fluid 

properties. Minor adjustments can then be made on subsequent circulations with 

additional lime, UNI-CAL ® , caustic, and a fluid loss control agent such as MIL-PAC ® . 

7. The addition of lime and MILSTARCH ® , BIO-LOSE ® , BIO-PAQ ® or CMC 

simultaneously through the hopper should be avoided because of drastic viscosity 

increases. 

8. Typical fluid properties after conversion and before weight-up are as follows. 

Table 3-12 

Typical Fluid Properties after Conversion and Before Weight-up 

Fluid Weight 

10.0 lbm/gal 

Funnel Viscosity 

40 to 44 sec/qt 


18 cP 

Yield Point 6 lb f /100 ft 2 

Gels 0/0 lb f /100 ft 2 

API Filtrate 

6 to 12 cc/30 min 

Calcium 

75 to 200 mg/L 

pH 11.5 to 12.0 

Pf 

1.0 to 2.0 ml 

Pm 

5.0 to 10.0 ml 

Excess Lime 

1.0 to 2.0 lbm/bbl (low 

lime) 

9. Occasionally, it is necessary to convert weighted fluids when dilution is not practical. In 

this case, the fluid can be converted in the surface pits and displaced down the hole in 

stages. 

Maintenance of Lime Fluids 

1. Lime fluid properties to be maintained should be determined and recorded; i.e., low-lime, 

moderate-lime, or high-lime properties. 

2. The P f and excess lime should be adjusted and maintained at near equal values. Low 

excess lime with high P f or high excess lime with low P f tends to cause rheological 

difficulties, i.e. the concentration of soluble calcium from lime is a function of pH, the 

higher the pH the less soluble. 

3. Caustic soda should be added to adjust the P f . The alkalinity of the filtrate affects the 

solubility of added lime. As the filtrate alkalinity approaches 1.0 ml, the solubility of lime 

decreases rapidly. After the 1.0 ml level is reached, solubility is only slightly affected. 

Normal additions of lime to the fluid will maintain the alkalinity of the fluid and the 

filtrate so that only small portions of caustic soda are required to maintain the desired 

alkalinity level in the filtrate. 

4. Lime is added to maintain the desired P m which controls the amount of excess lime. 

Excess lime can be calculated by the formula. 



Revised 2006 3-41


lb m /bbl Lime = .26( P m – F 1 P f ) 

where, 

F l = percent retort water, or can be estimated by, 

lb 

m /bbl excess Lime 

= 

P m – P f 

----------- 

4 

5. Fluid loss control should be maintained with CMC, BIO-LOSE, and MILSTARCH, as 

needed. 

6. Solids concentration should be kept at a minimum; otherwise, the additions of lime and 

fluid loss control materials such as starch or CMC cause undue increases in flow 

properties and gel strengths. 

7. Small additions of MILGEL to maintain proper colloidal distribution in the lime fluid is 

often necessary for maximum filtration control. 

8. Lime fluids are considered to be ideal rheological condition when they possess zero initial 

and 10-minute gels and when lime additions do not cause flow property increases. Flow 

properties are easily controlled under normal conditions with sufficient amounts of water 

and/or chemicals. 

Treatment of Contamination in Lime Fluids 

1. Salt – Lime fluids will tolerate salt contamination up to 50,000 mg/L if the fluid is in 

proper condition. Since an increase in salt increases the solubility of the calcium ion, the 

lime fluid should be treated with large concentrations of caustic soda to maintain a high P f 

which will limit the level of soluble calcium. UNI-CAL should be added as needed to 

control the rheological properties during salt contamination. 

2. Gypsum and Anhydrite – Under normal conditions, drilling of gypsum or anhydrite has 

little or no effect on a properly-treated lime fluid. However, when large quantities are 

drilled, the lime fluid may exhibit increases in flow properties and gel strengths, as well as 

increased API Filtrate. Caustic soda can be used as a pretreatment or a post-treatment to 

maintain the P f at the desired level. Lime additions are not necessary when gypsum is 

encountered until the P m begins to decrease. UNI-CAL should be added to the fluid to 

help restore and maintain flow properties. MIL-PAC, MILSTARCH, BIO-LOSE, or CMC 

should be used for filtrate control depending upon the severity of the contamination. 

3. Cement – Cement has very little effect on properly-conditioned lime fluids. If the solids 

content is in balance and sufficient UNI-CAL has been added to the fluid, little or no 

change will occur. However, when large quantities are drilled, the fluid alkalinity 

increases and calculates out as additional excess lime. This is not normally detrimental 

unless the cement concentration becomes so high that the total solids content is increased, 

in which case proper use of solids control equipment is necessary. 

4. Temperature – High-temperature gelation and solidification is a major problem with lime 

fluids. Higher alkalinity along with high-lime content of this system causes it to be more 

difficult to control when subjected to excessive temperature. Depending upon the 

concentration of low specific gravity solids and the amount of excess lime and alkalinity, 

solidification may occur at a temperature as low as 275°F. The degree of gelation or 

solidification depends upon the concentration of solids, alkalinity of the fluid, and amount 



3-42 Revised 2006


of available lime in the fluid. A lime fluid should be conditioned to handle excessive 

temperatures by dilution and centrifugation of the solids to a minimum and by reducing 

the alkalinity and excess lime content to approximately that of a low-lime fluid. 

Reduction of alkalinity and lime content should be done while diluting and adding UNI- 

CAL ® over a period of several circulations. ALL-TEMP ® or MIL-TEMP ® are beneficial 

(0.5 to 4 lbm/bbl) to prevent high temperature solidification. 

Gypsum (Gyp) Muds 

1. Gypsum fluids are maintained with higher filtrate calcium and lower alkalinity than lime 

fluids to increase their inhibiting affect on clays. 

2. Gypsum fluids are used when large sections of gypsum or anhydrite are to be drilled. 

Because of the limited solubility of CaSO 4 in water, additional gypsum or anhydrite will 

not dissolve into the fluid system but will be carried as a solid. 

3. Gypsum fluids are more resistant to salt and salt water than lime fluids, as long as solids 

are kept in line. 

4. Gypsum fluids are less susceptible to high temperature solidification than other calcium 

fluids because the alkalinity is maintained at a lower value. A temperature of 350°F is 

usually considered to be the upper limit for well-treated gypsum fluids. 

Factors Which Affect Gypsum Fluid Breakovers 

1. Since the degree of viscosity change during and after conversion to a gypsum fluid 

depends upon the total solids concentration of the fluid system, dilution with water is 

necessary prior to conversion. Good solids control equipment is strongly recommended. 

A centrifuge is recommended for weighted fluids. 

2. The type of clay solids present in the fluid influences the viscosity during conversion. 

Because MILGEL has a much higher Base Exchange capacity than most drilled clays, the 

viscosity increase is much more pronounced need when converting fluids that contain high 

concentrations of MILGEL. 

Note: 

Methylene Blue Test for Base Exchange gives a general idea of the severity of conversion. 

3. The type and amount of deflocculating agents added to the fluid prior to conversion will 

have a significant influence on viscosity during the conversion. When necessary, 

treatments should be made with small increments of UNI-CAL and caustic soda. If a 

phosphate has been used, the conversion will normally exhibit drastic viscosity humps. 

These are the result of the reaction between phosphate, lime, and solids all caught up in a 

mass ion impact while displacement and sequestering is all taking place simultaneously. 

4. Maximum agitation should be maintained in the surface active system. 

5. Pilot tests should be run prior to conversion to help determine necessary amounts of 

dilution and concentration of conversion chemicals. 

6. The pit volumes should be reduced to allow room for dilution. 

7. Necessary amount of gypsum and deflocculant should be stacked near the hopper, and 

caustic soda should be carried to the top of the suction (mixing) pit. Gypsum and 

deflocculant are added through the hopper. Caustic soda is added directly to the suction 

(mixing) pit near the point of maximum agitation. 



Revised 2006 3-43


8. Accurate circulation time should be determined so that conversion materials can be added 

at timed intervals over a period of one or two complete circulations. 

Conversion Procedure 

1. Conversion to a gypsum fluid should be initiated shortly after a new bit has been placed 

on bottom, i.e. once the conversion starts it should not be interrupted until them mud 

system has stabilized. Best results are obtained when the conversion is made inside the 

casing prior to drilling out. 

2. The amount of material needed for conversion varies depending upon the desired 

properties and the condition of existing fluid. Most conversions can be made as follows. 

• Drilling fluid systems low gravity solids content should be diluted to a minimum 

solids content of 3 to 5% by volume. If the system is weighted then the calculated 

dilution volume is to be added simultaneously with the below listed chemical 

additions. The biggest concern is after the break over the fluids viscosity could drop 

so low that the barite would fall out if a weighted system. 

• 3 to 6 lbm/bbl UNI-CAL® 

• 4 to 6 lbm/bbl gypsum (CaSO4 •2H20) 

• 1.0 lbm/bbl caustic soda 

• 0.5 to 1.5 lbm/bbl CMC, or 

• 2 to 6 lbm/bbl MILSTARCH with preservative. 

3. UNI-CAL should be started through the hopper while caustic soda is added to the pit. 

After five or six sacks of deflocculant and two or three sacks of caustic soda have been 

added, the gypsum additions should then be mixed through the hopper along with the 

UNI-CAL. The gypsum addition will cause a viscosity hump but will “break over” when 

agitated and become quite fluid. If the viscosity becomes excessive, the rate of addition of 

deflocculant and caustic soda should be increased along with an increase in water dilution. 

4. API Filtrate is normally controlled with CMC and/or MILSTARCH. Periodic additions of 

MILGEL in moderate quantities will help also help. MILGEL is usually accompanied by 

treatments of UNI-CAL. 

5. After all chemicals have been added to the fluid system, a check should be made of fluid 

properties. Minor adjustments can then be made on subsequent circulations with 

additional gypsum, UNI-CAL, caustic soda, and filtration control agents. 

6. The addition of gypsum and CMC simultaneously through the hopper should be avoided 

because of drastic viscosity increases. 

7. Typical fluid properties after conversion and before weight-up are as described below. 

8. Occasionally, it is necessary to convert weighted fluids when dilution is not practical. In 

this case, the fluid can be converted in the surface pits and displaced down the hole in 

stages. 

9. If a high pH fluid is being converted to a gypsum fluid, more water dilution and higher 

concentrations of UNI-CAL and gypsum are necessary to obtain desired properties. 

10. Abnormal foaming may occur during and immediately after conversion. This foaming is 

usually confined to the surface of the pits and can be reduced by adding a defoamer such 

as LD-8 to the pits. Mud guns should be turned off if excessive foaming persists. 



3-44 Revised 2006


Table 3-13 

Typical Fluid Properties after Conversion and Before Weight-up 

Fluid Weight 

10.0 lbm/gal 


40 to 44 sec/qt 


16 cP 

Yield Point 

6 lbf /100 ft2 

Gels 

2/10 lbf /100 ft2 

API Filtrate 

4 to 8 cc/30 min 

Calcium 

600 to 1200 mg/L 

pH 9.5 to 10.5 

Pf 0.2 - to 0.7 

Excess Gypsum 

2 to 4 lbm/bbl 

Maintenance of Gypsum Fluids 

1. Treatments of gypsum, caustic soda, UNI-CAL, and a filtration control agent are normally 

required each tour to maintain desirable properties. The amounts added depend upon 

volume, rate of penetration, amount and type of formation being drilled, and degree of 

dilution. 

2. The pH of a gypsum fluid is normally controlled between 9.0 and l0.5. Often the pH is 

slightly higher just after a conversion but can be allowed to drift back to the desired range 

as drilling progresses. The Pf should be in the 0.2 to 0.6 range. 

3. Gypsum is added to maintain filtrate calcium between 600 and 1200 mg/L. The solubility 

of the calcium greatly depends upon the alkalinity and salinity of the filtrate. 

4. Excess gypsum should be maintained above 2 lbm/bbl. This can be determined by 

titration for total calcium sulfate as shown in the Drilling Fluid Testing Procedures 

Manual. 

5. CMC, and/or MILSTARCH with a preservative or additional deflocculant can be added as 

required for desired filtration control. 

6. If starch is used for filtration control, it will be necessary to add proportional amounts of a 

preservative. 

7. Although gypsum fluids tolerate a higher concentration of colloidal solids than 

conventional fluids, solids must still be controlled at a reasonable level to obtain optimum 

rheological and filtration values. Mechanical solids control equipment such as fine screen 

shakers, hydrocyclones (low-density fluids), and centrifuges (high-density fluids) should 

be used to minimize dilution requirements. MILGEL should be added daily to provide 

proper particle size distribution. 

8. Gypsum fluids normally possess high gel strengths, but they are fragile gels and should 

not be considered alarming. Gels can be decreased by reducing total solids content and 

increasing concentration of UNI-CAL. Gypsum fluids are considered in good rheological 

condition if initial gel is less than 5 lbf /100 ft2 and ten-minute gel is less than 15 lbf /100 

ft2. 



Revised 2006 3-45


Treatment of Contamination in Gypsum Fluids 

Salt – A properly conditioned gypsum fluid can be expected to tolerate up to 100,000 mg/L salt. 

Since an increase in salt increases the solubility of the calcium ion, the filtrate alkalinity should 

be increased with caustic soda to limit the level of soluble calcium. UNI-CAL should be added as 

needed to control the rheological properties. 

Air, Mist, and Foam Drilling 

The use of air for drilling, with or without a fluid phase, is a technique that has been used in many 

areas of the world to increase penetration rates, overcome lost circulation zones, and improve 

lifting capacity. Because of inherent limitations, equipment requirements, and handling 

techniques, this is considered a highly specialized technique and is used only in selected 

applications. 

There are at least four basic methods which utilize air alone or in combination with water or a 

drilling fluid. They can be classified as follows: 

Table 3-14 

Classifications of Air / Water Drilling Fluids 

Classification Components Lift Medium 

Dusting Air alone Air 

Water misting 

Air 

Foaming agent 

Air 

Water 

Aerated fluid 

Air 

Fluid 

Fluid 

Stiff foam 

Air 

Foaming agent 

Viscosifier 

Foamed fluid 

As indicated, the systems can be classified further according to the lift media. In classifications 1 

and 2, air is the lift medium for the generated cuttings, therefore, the formation is in contact with 

air. In systems 3 and 4, the drilling fluid or foam is the external phase of the air fluid dispersion. 

Therefore, the formation is in contact primarily with the fluid phase. These two distinguishing 

factors are important with respect to their effect on the borehole. The classifications and their 

distinguishing factors are discussed below. 

Dusting 

This drilling system injects only air down hole at sufficiently high rates to carry the cuttings from 

the hole. Dusting provides minimum back pressures and produces the fastest penetration rates 

attainable with air drilling techniques. As long as the hole is dusting, there are usually few 

problems, but when water is encountered, several problems can occur. 

• A water column can build up causing loss of circulation if the formation is not competent. 

• Formation water can mix with the drill dust causing what are commonly called fluid rings. 

These rings can restrict air flow and, in some instances, cause tight hole problems. 

• The water will wet shale formations and possibly create sloughing and borehole instability. 

Where only small amounts of water are encountered during drilling operations, a drying 

agent such as silica gel may be injected into the air stream. 



3-46 Revised 2006


Mist Drilling 

To overcome some of the problems associated with water encroachment while air drilling, the 

technique of injecting a small amount of water containing a foaming agent into the air stream was 

devised. The foaming agent aids in trapping water as a mist in the circulated air stream, thereby 

removing it from the hole. Hence, the name mist drilling. Air is still the external phase of this 

dispersion and principal lift medium. Mist drilling does not overcome the problem of waterwetting 

the shale formation and, in sensitive formations, this condition may result in hole 

instability. Formation water may also enter the hole at such a rate that mist drilling becomes 

impractical. 

Aerated Fluid 

Where air or mist drilling cannot be used effectively, air is sometimes injected into the drilling 

fluid, creating an aerated condition. This technique reduces the hydrostatic head sufficiently to 

allow fluid circulation. Otherwise, it would be lost. An aerated fluid system requires high 

volumes of both air and fluid. It is often difficult to maintain satisfactory air-fluid dispersion on 

connections or during any extended period of shutdown. 

Stiff Foam 

To overcome some of the difficulties with aerated fluids, special fluid formulations have been 

developed to maintain more stable air-fluid dispersions. This has enabled the industry to prepare 

lighter fluids with excellent hole cleaning abilities. Though some operators consider the addition 

of a foaming agent to water alone to be sufficient, the normal practice is to add a viscosifier and 

film strengthening agent. This latter practice produces foam with shaving cream consistency and 

is referred to as stiff foam drilling. A typical fluid slurry composition for a stiff foam preparation 

in fresh water is as follows. 

Table 3-15 

Typical Formulation for Air-Fluid Dispersions 

SUPER-COL ® 

XAN-PLEX ® D 

caustic soda 

6 lbm/bbl 

¼ to ½ lbm/bbl 

½ lbm/bbl 

The amount of foaming agent depends on the volume of water invasion from the hole. The more 

water coming in, the more foaming agent required. The intrusion of oil has a dampening effect 

on foam. When oil is encountered, the addition of a high-molecular polyacrylate such as 

CYPAN ® may be used. 

In some cases, it may be desirable to use brackish or saline water for slurry make-up. AMPLI- 

FOAM TM should be used as the foaming agent with this type of water because it will be more 

effective in this environment. 

As mentioned earlier, air-fluid dispersions require special rig equipment. Requirements for stiff 

foam drilling are listed below: 

• Air compressor capability of 800 to 1000 ft 3 /min. 

• Rotating head 

• Blooie line – length recommended of 100 to 150 ft., size 6 to 10 in diameter. 

• Two injection pumps – triplex capable of injecting fluid rates up to 55 to 60 bbl/hr. 

• Air charts for constant recording of ft 3 /min. 

• Meter for determining gallons required. 



Revised 2006 3-47


• Bleed-off lines for air line and drillpipe. 

• String float in drill pipe. 

• Large disposal pit for retention of foam and slurry. 

• Butane or propane flare at blooie line for detection of gas. 

• Bath device for applying corrosion inhibitors to drill pipe. 

The primary objection to stiff foam drilling is that the foam must be discarded as it comes from 

the well. A satisfactory chemical or physical method of de-foaming the system has not been 

found. The cost of new slurry volume is minimized, however, by the fact that relatively lowslurry 

volumes can be circulated with good hole cleaning. Slurry injection rates may vary from 

12 to 30 gal/min depending on hole size. Twenty (20) gal/min would be typical for a 9 5 / 8 inch 

hole. 

Stiff foam densities as low as 4 lbm/gal measured at the flow line can be maintained. This not 

only results in reduced lost circulation, but provides a fluid which permits good penetration rates. 

Use of a stiff foam system is quite effective to depths of around 6000 feet. Below this depth, 

compressibility of the foam by the hydrostatic head is such that little reduction in density is 

obtained. Maintaining back pressure on the well enables a higher air/fluid ratio and, thus, 

reduced fluid density, but the operation is more complicated and has not been used extensively. 

Potassium-Base Fluids 

The use of potassium as a Base Exchange ion to stabilize drilled shales has been accepted by 

many operators in various geographic areas worldwide. Its use in the Gulf of Mexico has been 

greatly restricted due to the toxic affect of potassium on the test species, Mysidopsis Bahia 

shrimp. Potassium is widely used internationally, and comes from many sources, including; 

potassium chloride, potassium carbonate, potassium acetate, and potassium hydroxide. 

The major applications for potassium systems are, 

• Drilling soft gumbo (high water content reactive clay structure with elevated cation 

exchange capacity) formations to prevent bit balling, clay swelling, clay hydration and tight 

hole problems that are commonly associated with drilling reactive formations. 

• Drilling indurate shales such as those in the foothills of Canada and West Texas where 

excessive sloughing and borehole enlargement are common problems. This is not to 

mistaken for tectonically stressed formations. 

• Drill-in or workover fluids where the pay zone contains water sensitive clays intermixed 

with the producing formation. 

• Functioning as the first line of defense for all dispersible drill solids, i.e. preventative 

pretreatment chemistry for dispersible clay, thus enhancing solids control efficiency. 

Potassium is an effective clay swelling/hydration inhibitor, where the concentration of potassium 

to achieve the desired result is often a function of the shale being drilled. There are many areas in 

the world where successful potassium applications have been documented; however there are 

other areas such, as in the kaolinitic shales of northern South America, where failures are also 

well documented. The use of potassium in kaolinitic shales is strongly discouraged due to the 

destabilizing affect of the potassium ion on kaolinite. 

To accomplish maximum inhibition with potassium, it must be the intervening ion within the 

fluid phase of the drilling fluid. As an example, it would require a minimum of 18 lbm/bbl of 



3-48 Revised 2006


potassium chloride in sea water before the potassium ion became the dominant ion as apposed to 

magnesium, calcium, and the other cations indigenous to naturally occurring seawater. 

Potassium 

KCl is most often used to supply the major source of potassium. Most data to date indicates that 

a 3% to 5% concentration (10.7 to 18.1 lbm/bbl) is sufficient to provide inhibition of clay 

swelling and hydration. Attempts have been made to increase the inhibitive effect by increasing 

the KCl concentration up to 15% (57.6 lbm/bbl), but improved clay stability has not always been 

achieved. 

A secondary source of potassium is potassium hydroxide (KOH) which is sometimes used as an 

alkalinity agent, similar to caustic soda (NaOH). Generally, it is used in such low concentrations 

that the K + ion contribution is insignificant. Approximately 1.6 lb of KOH is required to get the 

same pH effect as one pound of caustic soda. KOH provides approximately 2000 ppm of K + ion 

for each pound per barrel added. 

Viscosifiers 

Materials used as viscosifiers in potassium-based systems include, 

• XAN-PLEX ® (xanthan gum) 

• MILGEL ® (Wyoming bentonite) 

• Colloidally protected bentonite 

• Guar gum (modified) 

• Hydroxyethylcellulose (HEC). 

PERMA-LOSE HT (Modified starch - functions as both viscosifier and filtration additive) 

The combination of 6 to 10 lbm/bbl pre-hydrated bentonite plus 1.0 lbm/bbl XAN-PLEX has 

been a commonly used viscosifying treatment. In some cases, because of shortages, guar gum 

and HEC have been used as viscosifiers. Though these products do increase viscosity, they do 

not increase carrying capacity satisfactorily; accordingly they are considered unsatisfactory 

substitutes and require higher bentonite concentrations to provide adequate hole cleaning. 

Note: 

Colloidally protected bentonite will yield higher Fann low rpm viscosities in a potassium 

chloride environment and retain this viscosity longer when compared to unprotected prehydrated 

bentonite. 

This base fluid typically exhibits an extremely high yield point, plastic viscosity ratio, and a 

relatively high filtration rate. For example, 

• PV = 5 cP 

• YP = 35 lb f / 100 ft 2 

• Filtrate (API) = 25 to 35 mL/30 min 



Revised 2006 3-49


Filtration Control Agents 

High filtration is characteristic of these fluids and almost any attempt to establish control results 

in some deflocculation. 

The materials used to reduce filtration are, 

• BIO-LOSE ® 

• BIO-PAQ ® 

• CMC HV & LV 

• MIL-PAC 

• MIL-PAC LV 

• MILSTARCH 

BIO-LOSE 

Addition of 5.7 to 11.4 kg/m 3 (2.0 to 4.0 lbm/bbl) is usually adequate for filtration control and 

elevating low-shear rate viscosity. Although it contains no biocides, BIO-LOSE resists bacterial 

degradation and is effective in both weighted and low-solids fluids over a wide pH range. 

BIO-PAQ 

Reduces filtration rate and increases low-shear rate rheological properties in brine systems 

(seawater, NaCl, KCl, and high-hardness water-base fluids) where expected bottom hole 

temperatures exceed 250°F. It also provides filtration control in divalent brines such as CaCl 2 

and CaBr 2 . Recommended treatment is 1.0 to 4.0 lbm/bbl (2.85 - 11.4 kg/m 3 ). 

CMC (HV or LV) 

CMC will provide filtration control, though it is not as effective as MIL-PAC. The same 

deflocculating effect has been observed. 

MIL-PAC 

MIL-PAC is an effective filtration control agent in KCl systems (0.5 to 1.0 lbm/bbl). It may 

exhibit a deflocculating effect on rheological properties which could drastically reduce yield point 

to plastic viscosity ratio. 

MILSTARCH 

In concentrations of 3 to 4 lbm/bbl, MILSTARCH has reduced filtration rates (15 to 20 cc) with 

no appreciable deflocculation. In order to lower filtrate to the 5 cc range, 6 to 7 lbm/bbl of starch 

are required. 



3-50 Revised 2006


Complex Systems 

NEW-DRILL ® System 

The term “low-solids/polymer” fluids include variations from a simple formulation for shallow 

drilling to much more complex formulations for a wide variety of drilling objectives. The 

“polymer fluid” of the 1990s ranges from fresh to saturated salt water, from zero clay content to 

over 20 lbm/bbl (0% to 8% by volume low-gravity solids), with pH values from near neutral (7.0) 

to as high as 11.0. This family of fluids has one primary “thing” in common. These fluids all 

achieve their performance characteristics from the presence of a protective colloid (water soluble 

organic polymer) or a combination of both protective colloids and salts. 

The performance of partially hydrolyzed polyacrylamide (PHPA) polymers such as NEW-DRILL 

is significant in encapsulating cuttings and improving solids removal efficiency. By bonding on 

sites that would otherwise react with water, these polymers “inhibit” the dispersion (physiochemical 

breakdown) of cuttings and formation solids into the fluid system. Due to their high 

molecular weight, these molecules are infinitely longer than they are wide or thick. At small 

concentrations (0.25 to 3.0 lbm/bbl) they impart a high level of cuttings encapsulation to waterbase 

fluids (even in freshwater). 

The philosophy of engineering the NEW-DRILL ® system is geared towards maintaining the low– 

gravity solids content of the mud at or below a level of 5% by volume. This solids control level 

will insure a high-quality filter cake. Higher solids content result in a thick cake conducive to 

differential sticking. 

Another objective, accomplished by the low content of drilled solids in these fluids, is a low 

impediment to fluid flow. Lower friction means lower system pressure losses as compared to a 

fluid with higher solids content. This converts to less pump wear, lower diesel consumption, and 

better opportunity for hydraulic horsepower to do work at the bit. Lower viscosities at high rates 

of shear convert to better separation (within pieces of solids removal equipment) of drilled solids 

from whole fluid. This enhances the performance of all the screens, hydroclones, and centrifuges. 

Even lower total solids content is possible when using iron oxide or ORIMATITA as a weighting 

agent. Since its specific gravity is 5.0 to 5.1, fewer solids will be present (in the ratio of 4.2 to 

5.0) at a given fluid density when compared to a barite weighted fluid. 

Materials used to control various fluid characteristics differ greatly. Although the NEW-DRILL 

family is not normally thought of as a potassium-base fluid, many NEW-DRILL fluids have used 

KCl or other K + sources as an additional inhibitor. (Confusion abounds as to whether a name 

really describes a drilling fluid.) 

A key point to note is that in some shale compositions and various areas around the world, NEW- 

DRILL alone has been effective in achieving good caliper logs. In some areas, it appears that as 

little as 1% KCl, 3% KCl, or up to 6% KCl has been effective where NEW-DRILL alone has not. 

Commonly the combination of NEW-DRILL and potassium has yielded a synergistic effect 

which outperforms either additive when independently applied. 

Many laboratory tests and field case histories have shown increased clay swelling/hydration 

inhibition with the addition of a partially hydrolyzed polyacrylamide (PHPA) to a KCl or NaCl 

type fluid. NEW-DRILL ® HP is especially effective, being able to be stored and mixed more 

effectively due to being blended with KCl. These reasons explain why NEW-DRILL HP is often 

more cost effective than competitive products claiming to have “higher activity” or being “pure” 



Revised 2006 3-51


polymer. Performance and desirable results should be the determining factors in establishing the 

value of a product or a fluid system. 

Baker Hughes Drilling Fluids uses potassium in its NEW-DRILL system, especially in the 

tectonically stressed shale encountered in the foothills of the Canadian Rockies. NEW-DRILL is 

believed to adsorb on the positive charged edges of exposed clays, reducing the water sensitivity 

of the clay formations and contributing to increased inhibition. The potassium ion is also 

absorbed on to the clay structure causing it to take on the characteristics of illite. This action 

results in the loss of polymer as well as a decrease in potassium ion concentrations as solids are 

discharged, thus requiring constant monitoring of the concentrations of each and replenishing 

them as needed. 

Mixing Procedure for NEW-DRILL System with KCl 

Add desired KCl concentration to water in the active system (see Chapter 16, Engineering Data). 

Normally 10 to 17.0 lbm/bbl meets inhibition requirements. 

Pre-hydrate MILGEL in premix tank (approximately 30 lbm/bbl) and add pre-hydrated MILGEL 

slowly (1 in. to 1½ in. stream) to KCl solution to obtain desired viscosity. Normally 6 to 8 

lbm/bbl of pre-hydrated bentonite in the KCl solution is adequate. Additional KCl will be 

required to offset the fresh water added to the system in the form of pre-hydrated bentonite. 

Note: On initial make up, where large volumes are needed for displacement, the active system 

can be filled with fresh water and the bentonite added first and pre-hydrated and then followed by 

KCl. 

Adjust pH to approximately 9 - 10 with caustic soda or KOH. 

Add ½ to l.0 lbm/bbl of XAN-PLEX ® D slowly. 

Add ¼ to ½ lbm/bbl NEW-DRILL ® . 

For additional filtration control. Use MILSTARCH or BIO-LOSE and MIL-PAC in a 2:1 ratio. If 

MIL-PAC is used, add very slowly (1/8 to ¼ lbm/bbl over a 6 to 8 hour interval) and monitor 

rheological properties. 

Maintenance 

1. Monitor potassium ion (see Fluid Testing Procedures Manual) to maintain the desired 

concentration. 

2. If desirable, pre-hydrate bentonite in premix tank. Add sufficient potassium material to 

compensate for water additions. A water meter is recommended to determine dilution 

volumes. 

3. Solids control equipment (desander, desilter, and fine screen shakers, plus a centrifuge for 

weighted systems) should be considered absolute necessities with this system. 

4. Control pH in the 8.5 to 10.0 range with caustic soda. Corrosion rates can be reduced with 

oxygen scavengers such as NOXYGEN TM . 

5. Keep entrained air out of the system by: 

• Shutting the mud hopper down when it is not in use 

• Submerging mud guns to prevent aeration 

• Judicious use of hydrocyclones 



3-52 Revised 2006


6. Filtration control in the range of 15 to 20 cc can be achieved with MIL-PAC. For further 

filtration control, it may be necessary to add MILSTARCH or BIO-LOSE or BIO-PAQ in 

a 2:1 ratio. 

7. Remember that NEW-DRILL encapsulates solids and cuttings discarded and is also 

discarded from the system. Therefore, it is recommended that NEW-DRILL be added at 

0.15 lbm/bbl for each barrel of drill water added. Also add 0.5 to 3.0 lbm/bbl to new mud 

volume built. This usually equates to about 5 to 7 lb of NEW-DRILL for each barrel of 

formation solids drilled up and discarded. This treatment will vary widely depending on 

activity of formation being drilled. 

Typical properties for this type system are, 

• Density (lbm/gal) – 8.8 to 9.2 

• PV (cP) – 4 to 6 

• YP (lbf/100 ft²)– 25 to 45 

• Gels(lbf/100 ft²)– 23/26 (high, but fragile) 

• API fluid loss – 15 to 35 cc/30 min 

• pH – 8.5 to 10.0 

• Low gravity solids (LGS) content - 3 to 5% with 5% being the maximum 

Much of the success achieved in stabilizing reactive clays with this fluid has resulted from 

awareness and control of mechanical factors, combined with inhibitive characteristics of 

potassium fluids. It is a good practice, therefore, to maintain laminar flow in the annulus while 

drilling and minimize swab and surge pressures to reduce mechanical aggravation of sloughing 

shales. 

Additives for Control and Maintenance of Properties 

Electrolytes 

NEW-DRILL ® is compatible with all concentrations up to and including saturated sodium 

chloride (NaCl). Viscosity decreases with increased concentration of electrolyte. 

NEW-DRILL ® systems have been run at concentrations of KCl up to 18% by weight. 

NEW-DRILL ® is compatible with a seawater environment although hardness of the system 

should be treated downwards with caustic soda. 

Alkalinity Control 

NaOH (caustic soda) – most common alkalinity and pH control product. 

KOH (caustic potash) – has been used frequently. Requires about 40% by weight more than 

NaOH to achieve an equivalent pH. 

Lime & gypsum – used almost exclusively to treat alkalinity imbalances due to carbonates when 

in a reactive or ionic state. Carbonates reduce the inhibitive properties of the polymers. 

Fluid Loss Control Agents 

BIO-LOSE ® – acceptable in low pH seawater system. At low pH, some preservative may be 

needed. 



Revised 2006 3-53


BIO-PAQ ® - acceptable in low pH seawater system. At low pH, some preservative may be 

needed. This product has higher temperature stability than BIO-LOSE. 

CHEMTROL ® X – effective HT/HP fluid reduction additive in seawater and high-hardness 

environments. CHEMTROL ® X is an effective deflocculant (thinner) at hardness levels of 400 

mg/L or above. It also works well at lower pH ranges of 8.0 to 9.0. 

LIGCO ® – lignite additive for fresh and seawater systems. A minimum pH of 9.5 is required. 

This product works well as an HT-HP fluid control additive and will also provide some degree of 

deflocculation and gel strength reduction 

MIL-PAC – (polyanionic cellulose) polymer-based additive for all systems. Performs more 

effectively in hardness levels of 500 mg/L or less. 

MILSTARCH – not applicable for low pH seawater systems, usually requires a preservative. 

SULFATROL ® - sulfonated asphalt product for HT-HP fluid loss reduction and to provide some 

degree of shale stabilization by plugging shale micro-fractures. 

Viscosifying Agents 

MIL-BEN ® – OCMA-grade bentonite for international (non-US) locations. Produces ½ the 

viscositiy of MILGEL ® . 

MILGEL ® – Wyoming bentonite meeting API specifications. Used sparingly for viscosity in 

maintenance treatments. Pre-hydrate bentonite for use in seawater and high-salt NEW-DRILL ® 

fluids. 

MILGEL ® NT – Untreated Wyoming bentonite meeting API specifications. Pre-hydrated 

bentonite is used in seawater and high-salt NEW-DRILL ® fluids. 

XAN-PLEX ® D – Xanthan gum additive used to increase viscosity and suspend barite and drill 

cuttings. Often used in situations where bentonite will not build viscosity, such as in a seawater 

or high salt environment. 

SALT WATER GEL ® – Attapulgite clay meeting API specifications that serves as a viscosifier in 

high salt concentration environment. Generally produces a more viscous “hump” than MILGEL 

with various polymer additions. 

Weighting Agents 

MIL-BAR ® (4.2 s.g.). – barium sulfate (barite) weight material 

ORIMATITA (5.0-5.1 s.g.) – hematite-based weighting agent that, because of its higher density 

compared to barite, provides a low-solids environment and high ROP in conjunction with the 

polymer viscosifiers. 

MIL-CARB ® (2.5-2.65 s.g.) – calcium carbonate weight material and bridging agent. MIL- 

CARB has a lower density than barite or hematite and works well as a weight material and helps 

minimize mud losses in low density NEW-DRILL Systems. MIL-CARB is also the only weight 

material that is acid soluble. 

W.O. 30 – calcium carbonate used as a bridging and/or weighting material in workover, 

completion and drill-in fluids. W.O. 30 is 95 to 98% soluble in hydrochloric acid, which 

minimizes permanent plugging of the producing formation. W.O. 30 is available in grades from 

fine to coarse. 



3-54 Revised 2006


Deflocculating Agents 

ALL-TEMP ® − Water-base deflocculant/rheological properties stabilizer with special 

applications in high temperature environments. 

NEW-THIN TM – low molecular weight polyacrylate polymer dispersed in water. Effective 

thinner in low-weight, low-solids systems. Contains no chrome or heavy metals. Hardness levels 

should be less than 500 mg for optimum thinning, the lower the hardness the more efficient the 

viscosity reduction. 

UNI-CAL ® – lignosulfonate used as a supplemental thinner if solids overload the system. 

Treatment and Control Techniques for NEW-DRILL Systems 

The composition and properties of drilling fluids are greatly affected by the formation 

contaminants encountered while drilling. Selected drilling fluid components are added to negate 

a contaminant or potential contaminant. In order to limit the scope of discussion the following 

common contaminants will be discussed: 

• Salt and salt water flows 

• Calcium or magnesium 

• Cement 

• Carbonates 

• Temperature 

• Dispersible Cuttings 

The problem of solids contamination will be considered in Chapter 4, Contamination of Water- 

Base Fluids. It should be emphasized, however, that the problems associated with all of the 

above mentioned contaminants will be magnified by the presence of solids. In all cases, limit the 

amount of undesirable reactive solids, i.e., drilled solids, should be kept to the lowest practical 

level. 

Salt Contamination 

Source 

Salt may come from make-up water, salt stringers, massive salt sections, salt water flows, and 

commercial sources. Regardless of the source it has an impact on drilling fluid properties and 

chemical selection. 

Since salt cannot be precipitated by chemical means, the only method of reducing salt 

concentration is through dilution. This will also help to reduce the problems caused from 

flocculation of clay solids by reducing the concentration of the solids in the fluid. If dilution is 

not possible due to density requirements or water availability, then treatment with chemicals may 

be necessary. 

Deflocculation – If chloride levels remain below 30,000 mg/L, then NEW-THIN can be used to 

reduce yield point and gel strength. Other deflocculants such as UNI-CAL can be used, but it 

may be necessary to increase the pH to 9.5 for this product to be effective. The dispersion of 

drilled solids can also result from the addition of a lignosulfonate and caustic to the NEW-DRILL 

system. Because of these two factors, treatment with organic thinners is not recommended unless 

viscosity reductions are not satisfactory using NEW-THIN. 



Revised 2006 3-55


API Filtrate Reduction – If reductions in API filtrate are required, additions of MIL-PAC should 

be used. Concentrations required will vary depending on the degree of reduction needed. 

Seawater/KCl Systems 

Depending upon how massive the sections of salt are, there may be little or no effect on the 

system except for an increase in chloride concentration. If reductions in rheological properties or 

API filtrate are required, the same methods of treatment as above should be used except for 

dilution. 

Saturated-Salt Systems 

If the formations being drilled are massive enough to require saturation of the fluid, several 

differences should be noted. Viscosity reductions will occur from (1) the effect of salt saturation 

on the NEW-DRILL, and (2) the shrinkage of the water envelope around the clay solids. 

Additions of a viscosifier such as XAN-PLEX may be required to maintain hole cleaning 

properties. The API filtrate will need to be controlled with either MIL-PAC, PERMA-LOSE, 

BIO-LOSE, MILSTARCH, or a combination of these polymers. Typically, a combination of 

MIL-PAC to MILSTARCH (in a 1 to 4 ratio) often gives the most economically acceptable filter 

cake. 

Effects on Fluid Properties 

In a freshwater drilling fluid, an increase in the salinity of the fluid will cause the clay solids to 

flocculate. The result of this flocculation is an increase in yield point, gel strengths, and API 

filtrate. The pH of the fluid will also be reduced slightly. 

The NEW-DRILL polymer itself is not adversely affected by increasing salt concentrations; 

however, the normal viscosity obtained from the polymer is reduced as the chloride content 

increases NEW-DRILL systems have been used effectively to inhibit shales in salt-saturated 

environments. If the NEW-DRILL system is made up from a brine such as KCl or NaCl, the 

effects from salt “contamination” will be much less severe or, in most cases, negligible. 

Salt Water Flows 

The effects of salt water flows on a NEW-DRILL system will be similar to that of drilling salt 

except for (1) reductions in fluid density of heavily weighted fluids, and (2) increases in the 

concentration of soluble cations and anions. Almost all water flows contain cations in addition to 

sodium, usually calcium and magnesium. Total hardness levels should be maintained below 500 

mg/L by maintaining the pH from 9.0 to 9.5 and using soda ash to remove residual calcium not 

removed by adjusting the pH. 

Note: 

A note of caution regarding NEW-DRILL, at elevated pH. The product will hydrolyze and 

thus loose its clay inhibitive qualities. If hardness is present and pH is elevated to the high 

pH range the calcium cation will precipitate and in so doing precipitate out the NEW- 

DRILL polymer with it. 



3-56 Revised 2006


Calcium or Magnesium Contamination 

Source 

Calcium and magnesium are closely related ions that have similar effects on fluid properties. 

These ions can originate from make-up water, salt water flows, drilling of gypsum or anhydrite, 

drilling cement, and some formations such as the Zechstein, which contains a multitude of 

problematic ions. 


Calcium and magnesium will replace sodium ions on reactive clays. This effect reduces the 

hydration of the clays and promotes flocculation. These actions increase the yield point, gel 

strength, and API filtrate of the fluid. In concentrations above 500 mg/L, the NEW-DRILL ® 

polymer will also be dehydrated and viscosity and API filtrate may become difficult to control. 

The presence of these two cations is measured collectively using the total hardness titration. The 

calcium ion can be titrated separately to determine the concentrations of each ion. 

Treatment and Control Techniques 

Magnesium – The magnesium concentration can be decreased by increasing the pH. Historically, 

the solution was to increase the pH of the fluid to 10.5 or above. At this pH level, the magnesium 

precipitates as insoluble magnesium hydroxide. A pH level this high is not normally 

recommended in the NEW-DRILL ® system. Increasing the pH level to 9.8 should reduce the 

magnesium concentration to acceptable levels. 

Calcium – Concentrations of this cation above levels of 400 to 500 mg/L are not recommended in 

the NEW-DRILL ® system. Reduction of the calcium to this range can be accomplished by 

increasing the pH to 9.0 to 9.5 and adding soda ash to remove any calcium above the 500 mg/L 

level. 

A treatment with 0.1 lbm/bbl of soda ash will remove approximately 100 mg/L of calcium. 

Cement Contamination 

Source 

In most drilling operations, cement contamination may occur when casing is cemented and plugs 

are drilled out. The severity of contamination depends on, 

• solids content 

• concentration of deflocculants 

• type of deflocculants 

• quantity of cement drilled 

• whether the cement is green or cured 

• the amount of pH increase. 


The problem with cement contamination is a result of the combination of high pH and calcium. 

The presence of solids in the fluid causes a viscosity increase, resulting from the flocculation of 

these solids due to the high pH and calcium (from drilling cement). The problem may be 

aggravated somewhat in a NEW-DRILL system because of the low pHs and low concentration of 

thinners typical in this system. If possible, use water to drill cement. 



Revised 2006 3-57



Prior to Cementing 

1. Reduce low-gravity solids to a minimum level. This can be accomplished by utilizing 

solids control equipment and dilution/displacement with water. 

2. Use pump rates sufficient to achieve turbulent flow of the drilling fluid. 

3. Pretreatment of the system with a small concentration of sodium bicarbonate or phosphate 

This will help in two ways: 

• Removes calcium as a precipitate with sodium bicarbonate or by sequestering the 

divalent cation with phosphate. 

• Reduction of the pH while drilling the cement 

Drilling Cement 

1. Avoid adding NEW-DRILL prior to, or while drilling cement. 

2. If cement is hard, small treatments of sodium bicarbonate may be made to precipitate 

calcium, reduce pH, and reduce viscosity. 

3. If the cement is “green” or soft, the method of treatment will be the same although greater 

increases in rheology may occur. This will especially be true if the solids level has not 

been lowered enough before drilling cement. 

4. Operate the solids control equipment to remove cement particles. 

5. Various acids can be used to control pH more rapidly after drilling cement (Citric, Acetic, 

hydrochloric, or phosphoric are the most commonly used.) 

Two problems can result from the use of sodium bicarbonate. 

1. Overtreatment can initially cause the fluid to thin severely. 

2. Overtreatment can cause a carbonate problem which can result in 

fluid instability and high gel strengths. 

Carbonates 

Source 

Large accumulations of soluble carbonates or bicarbonates can affect rheological properties in 

much the same way as salt or calcium. Carbonates may come from aeration of the fluid, CO 2 

from the formation, thermal degradation of organic fluid additives, and over treatment with soda 

ash or sodium bicarbonate. 


Carbonates adversely affect rheological properties in several ways. First, carbonate ions cause 

reactive clays to flocculate, thereby increasing yield point and gel strengths. Secondly, organic 

deflocculants do not function properly because of the chemical imbalances created when 

carbonates react with the hydroxyl ions in solution. Thirdly, in a NEW-DRILL ® system, there is 

some evidence to indicate an excessive concentration of carbonates in the fluid system will cause 

the NEW-DRILL ® polymer to lose some of its encapsulating ability. The concentration of 

carbonates that will create a problem is greatly dependent on the concentration of reactive solids 

in the fluid. In the NEW-DRILL ® system, reactive solids are typically maintained at very low 



3-58 Revised 2006


levels. To prevent excessive carbonate levels, it is recommended that a minimum of 100 to 200 

mg/L calcium be maintained in the fluid system and the pH be maintained in the 9.0 to 9.5 range. 


If excessive carbonates occur in a fluid system and treatment is necessary, the following methods 

are recommended. The first method is to treat the system with lime. A sufficient quantity of lime 

should be added to increase the pH to at least 9.5 and measurable calcium levels to 100 mg/L. If 

noticeable improvement in fluid properties does not occur, continued treatment is necessary. 

Treatments of 0.25 to 0.5 lbm/bbl lime may be necessary to reduce carbonates to acceptable 

levels. When treating carbonates it is best to make small, incremental additions of the chosen 

treatment and observe the results after one complete circulation. Since over-treatment with lime 

can be harmful to the NEW-DRILL system, an alternative treatment would be to use a 

combination of gypsum and lime. These chemicals should be added simultaneously to raise the 

pH and soluble calcium to the levels indicated above. An advantage of using a combination of 

gypsum and lime is to buffer the pH increases caused by using lime. A problem can also occur 

by over treating with this method as well. Careful monitoring of pH and calcium levels should be 

maintained during the treatment phase. 

Temperature 

Source 

As wells are drilled deeper, higher bottom hole temperatures are being encountered. In some 

areas with very high geothermal gradients, temperatures may approach 600°F to 700°F at depths 

as shallow as 5000 ft. These severe requirements may necessitate designing a special drilling 

fluid. Today's drilling fluids are being frequently required to function above 300°F. The NEW- 

DRILL system has been used in wells having bottom hole temperatures of 350°F, however, it is 

suggested that the PYRO-DRILL or other mud systems specifically developed for geothermal or 

high temperature/high pressure (HT-HP) be considered at temperatures above 350° F. 


As temperatures rise above 250°F, the degree of flocculation of bentonite starts to increase. This 

flocculation can be controlled to some extent with organic thinners but, above 300° to 350°F, 

these thinners also begin to degrade and lose their ability to deflocculate the system. 


The NEW-DRILL system, because of its low-solid content, is reasonably tolerant to temperatures 

up to 300° F. One problem that may occur in a NEW-DRILL system is viscosity reduction at 

elevated temperatures. Viscosity may need to be supplemented with a temperature stable 

biopolymer such as XAN-PLEX D. If the solids concentration is severe enough to create 

viscosity problems from clay flocculation, then deflocculation can be achieved using NEW-THIN 

and/or MIL-TEMP (or ALL-TEMP). API filtrate can be controlled with CHEMTROL X. 

NEW-DRILL System Benefits 

Effects on Torque and Drag 

One of the supplemental benefits with the NEW-DRILL systems is related to the low coefficient 

of friction of the polymer, coupled with its thixotropic nature and inhibitive qualities. These 

factors, in conjunction, have reduced the torque and drag experienced in the field. This has been 

particularly evident in directional holes. 



Revised 2006 3-59


The degree of torque is usually strongly influenced by the size of the cuttings bed upon which the 

pipe string is rotating. Often, the more inclined the hole, generally the larger the cuttings bed. 

This is increased by the amount of wall instability experienced (hole closure). 

Effect on Differential Sticking 

Differential pressure sticking is a condition in which the drill pipe becomes stuck against the wall 

of the wellbore because it has become embedded in the filter cake. There must be a permeable 

formation present and a pressure differential across a nearly impermeable filter cake. The quality 

of the filter cake and the rate of filtrate produced by the drilling fluid in use affect the possibility 

of differential sticking. 

NEW-DRILL fluids exhibit a compressible filter cake which helps considerably in preventing 

differential sticking. The NEW-DRILL system has accomplished this without the traditional 

liberal use of commercial bentonite. Cases of differential sticking in the field while using a 

NEW-DRILL system have been rare. In fact, highly depleted zones have been drilled utilizing 

the NEW-DRILL system with no occurrence of differential sticking. This has helped reduce fluid 

cost and prevent one of the most costly delays in drilling - stuck pipe 

Effects on Weight-On-Bit (WOB) 

Due to the reduced coefficient of friction from the NEW-DRILL, more effective collar weight is 

transferred to the bit. Less collar-to-wellbore friction has multiple benefits including less drill 

string wear. Reductions in torque of as much as 50% have been observed in the field. 

NEW-DRILL Operational Procedures 

NEW-DRILL systems have been developed through experience in several geographic areas under 

various drilling conditions. Consequently, techniques have been developed to meet the needs of 

customers at various locations. 

Methylene Blue Test (MBT) 

The performance of the NEW-DRILL System is based on a low colloid philosophy. Utilize 

solids control equipment for controlling solids content and plastic viscosity. Daily solids analysis 

must be used to monitor the solids content. Low gravity solid content is the key to proper control 

of the system. Total low gravity solids should be held in the range of 3 to 5% by volume, 

inclusive of commercial clay. Inadequate solids control equipment will cause increases in solids 

content and result in high rheological values and/or the need for a strong deflocculant such as 

UNI-CAL (lignosulfonate). 

Gel Strengths 

Gel strength values as determined by a 6-speed viscometer are generally higher for a NEW- 

DRILL system than traditional UNI-CAL lignosulfonate fluids. This illustrates the difference 

between a semi-dispersed as compared to a dispersed mud system. Also, the aqueous phase 

viscosity of the lignosulfonate system is only slightly greater than water while the NEW-DRILL ® 

system’s water is significantly thicker. It is common for 10-minute gels to reach 35 lb f /100 ft 2 . 

Drilling conditions and economics should determine the need to reduce gel strengths. Report the 

initial, 10-minute and 30-minute gel strengths on all NEW-DRILL systems. 



3-60 Revised 2006


Filtrate Ph Range 

Freshwater System 

Filtrate pH is normally controlled in the 8.0 to 10.0 range with caustic soda additions being made 

slowly using a chemical barrel. The hopper should never be used to mix caustic soda (NaOH) or 

caustic potash (KOH). Ideally, pH values of 8.0 to 9.0 are preferred for freshwater systems. 

Limit the pH to a maximum of 9.5 when UNI-CAL (lignosulfonate) is used. The pH should be 

reported on the filtrate, and not on the whole fluid. 

Seawater System 

A pH of 9.5 to 10.0 should be maintained if hardness reduction is necessary for API filtrate 

control. 

Range for Filtrate Hardness (Ca++, Mg++) 


Maintain hardness levels below 400 mg/L. A concentration of 200 to 300 mg/L calcium tends to 

show the best stability. 


If low viscosity and API filtrate values are not required, seawater systems may be run at natural 

pH and hardness. This is especially true when the objective of the system is to control gumbo 

shale. 

Filter cake quality and API filtrate control are adversely affected by high hardness. Therefore, 

when sand sections are drilled, the pH of the system may be increased to chemically suppress the 

hardness level. This aids in attaining the maximum hydration of both bentonite and polymers to 

improve the control both the cake and filtrate quality. In seawater, the pH should be raised 

initially with caustic or potassium hydroxide to a maximum value of 9.5 to 9.7. This will 

precipitate most of the magnesium. Caustic soda is the preferred product for pH increases 

because the potassium ion will have a negative effect on filtration control. Additions of soda ash 

and/or sodium bicarbonate should then be used to precipitate out calcium to the desired hardness 

level. 

Note: 

Calcium and magnesium concentrations should be measured and reported, not total 

hardness. 

API Filtrate 

A variety of products are available for API filtrate control. Laboratory and field tests have 

indicated that LIGCO ® is an effective filtrate control agent at moderate pH levels. In addition, 

LIGCO will act as a mild deflocculant. MIL-PAC is also effective for filtrate control; however, it 

may increase the viscosity to an undesirable range. MIL-PAC and MIL-PAC LV are effective in 

seawater NEW-DRILL systems. 

The filter cake quality of the NEW-DRILL system makes API filtrate values of 10 to 20 cc/30 

minutes sufficient in “most” situations. To determine cake compressibility, filtrate values should 

be measured and reported at 100, 200, or 500 psi, and at 7½ and 30-minute intervals. 

UNI-CAL Additions 



Revised 2006 3-61


Lignosulfonate additions are often unnecessary. However, UNI-CAL may be used in NEW- 

DRILL systems when excess solids cannot be mechanically removed or diluted. Avoid excessive 

thinning with lignosulfonate to insure effective hole cleaning and to prevent mechanical erosion 

of the wellbore. 

Maintain pH values from 9.0 (freshwater) to 10.5 (seawater) when using lignosulfonate. This 

increases the solubility of UNI-CAL while limiting destabilization of shales from the hydroxide 

ion. 

Deepwater Drilling Fluid Systems 

Drilling off the outer continental shelf has become more common in an effort to find significant 

hydrocarbon deposits. Water depths range from 1,000 to 8,000+ ft in deepwater wells. 

A special consideration related to deepwater exploration is gas hydrates. Gas hydrates are icelike 

crystalline solids formed by the physical reaction of gas and water under pressure. They can 

form in aqueous systems at temperatures well above the freezing point of water if the pressure is 

sufficiently high. Low temperatures, when coupled with hydrostatic pressure or pressures 

encountered during well control operations, create an environment conducive to the formation of 

gas hydrates. NF2 ® and NF3 are gas hydrate suppressors specifically designed for use in 

water-base drilling fluids. 

In addition to gas hydrates, other potential problems must be considered when designing a 

drilling fluid system for deepwater. Hole cleaning becomes critical in the surface casing due to 

the necessity for a large inside diameter (I.D.) riser. A fluid with a high effective viscosity in the 

riser, yet shear thinning for good hydraulics, is desirable. Boosting the riser with a third fluid 

pump is a common practice to aid in hole cleaning. 

Deepwater projects utilize large circulating volumes. The drilling fluid system of choice should 

be easily mixed and maintained. It is advantageous to minimize the number of additives due to 

logistics and storage space 

A growing trend is the use of riserless drilling techniques, using the Dynamic Kill Drilling (DKD) 

process with water-based mud. The DKD process uses large volumes of weighted water-based 

mud blended “on the fly” to achieve a specific density while dumping the returns to the seabed. 

This technique is used to reduce the overall hydrostatic pressure exerted by the mud column on 

deepwater formations. The fracture pressure integrity of deepwater formations is low compared 

to onshore and shelf formations. This is compounded by the depths of the water column in 

deepwater (> 1000 feet). The riser is eliminated because the hydrostatic pressure exerted by the 

mud column (within the riser), combined with the great depths (> 1000 feet), leads to hydrostatic 

pressures greater than those of the fracture gradient of the formation, which in turn can lead to 

lost circulation. Since the density of seawater is less than that of drilling fluid, the total 

hydrostatic pressure “felt” by the formation is reduced because the hydrostatic pressure exerted is 

a combination of the density of seawater, together with a component from the drilling fluid in the 

annulus. 

PYRO-DRILL®, High-Temperature Drilling Fluid 

Introduction 

The PYRO-DRILL ® system is a very flexible drilling fluid system that is used when temperature, 

contaminants, and/or borehole instability make conventional systems impractical or 

uneconomical. Components of the system have been used in geothermal wells with bottom hole 

temperatures (BHT) in excess of 600°F. This high temperature system has been formulated in 



3-62 Revised 2006


weighted freshwater and salt water fluids with excessive hardness (30,000 mg/L) and at 

temperatures approaching 500°F. 

Application 

The system can be composed of any combination of the products shown in Table 3–16 depending 

upon pH, temperature, and total hardness of the drilling fluid. As in any drilling fluid system, the 

optimum properties will be achieved when the low-gravity solids are in the proper range for the 

desired fluid density. 

Most of the PYRO-DRILL components are used in small concentrations, usually not exceeding 3 

lbm/bbl. The major parameters determining product concentrations will be density, drill solids 

content, particle size, pH, salinity, total hardness, and bottom hole temperature. Some general 

product concentration guidelines for use with the PYRO-DRILL system at varying densities, 

salinities, and hardness levels are presented in Table 3-17 PYRO-DRILL Product 

Concentration Guidelines for Various Fluid Types 

Table 3-16 Component Description of the PYRO DRILL System 

Product Description Function 

MIL-TEMP Sulfonated styrene, maleic anhydride 

co-polymer 

Provide thermal stability 

ALL-TEMP Derivatized synthetic interpolymer Water-base deflocculation 

Rheology control where BHST > 300°F 

(149°C) 

CHEMTROL X Modified lignitic polymer blend HT/HP filtration control 

Deflocculation 

KEM-SEAL AMPS/AAM co-polymer High-temperature viscosifier freshwater 

HT/HP filtration control SALT WATER 

PYRO-TROL AMPS/AM co-polymer HT/HP filtration control 

Shale stabilizer 

Lubricity 

POLYDRILL Sulfonated synthetic polymer HT/HP filtration control for high-hardness 

fluids 

Deflocculation 

PYRO-VISTM Chemically modified sugar beet 

extract 

Supplementary viscosifier for SALT 

WATER/high-hardness fluids to increase 

yield point and gel strengths 

Mixing Recommendations 

Most of the additives in the PYRO-DRILL system are polymers, therefore, they should be added 

slowly (20 to 45 min/container) through the chemical hopper for optimum blending and solubility 

of the products. In almost all cases, PYRO-DRILL system products can be added directly through 

the chemical hopper. The two exceptions are the use of PYRO-VIS ® and the use of CHEMTROL 

X in saturated salt water fluids. PYRO-VIS must be pre-hydrated and sheared extensively in a 

high-shear device prior to addition to the active system. This procedure will alleviate overtreatment 

and optimize usage of the polymer for supplementing gel strengths and yield points in 

highly saline and high hardness fluids. If facilities are available, CHEMTROL X should be presolubilized 

in freshwater with caustic soda prior to adding to a saturated salt water fluid. This 

procedure will assure optimum solubility of the CHEMTROL X in a very harsh environment 



Revised 2006 3-63


Table 3-17 

PYRO-DRILL Product Concentration Guidelines for Various Fluid Types 

Concentration Product Freshwater 

Brackish 

Water 

10.0 lbm/gal MIL-TEMP 

CHEMTROL X 

PYRO-TROL 

KEM-SEAL 

POLYDRILL 


CHEMTROL X 

PYRO-TROL 

KEM-SEAL 

POLYDRILL 


CHEMTROL X 

PYRO-TROL 

KEM-SEAL 

POLYDRILL 


CHEMTROL X 

PYRO-TROL 

KEM-SEAL 

POLYDRILL 

0.25-0.50 

0.50-2.00 

0.25-2.00 

0.75-1.50 

N/A 

0.50-0.75 

1.00-3.00 

0.50-2.00 

0.50-1.00 

N/A 

0.75-1.25 

3.00-5.00 

0.50-2.00 

1.00-2.00 

N/A 

1.50-2.00 

4.00-6.00 

1.00-2.00 

0.25-0.75 

N/A 

SALT 

WATER 

Chlorides 

(20,000- 

190,000 

mg/L) 

0.25-0.50 

0.50-2.00 

0.50-2.00 

0.75-1.50 

N/A 

0.50-0.75 

1.00-3.00 

0.50-2.00 

0.75-1.50 

N/A 

0.75-1.25 

3.00-5.00 

0.50-2.00 

0.50-1.00 

N/A 

1.50-2,00 

4.00-6.00 

1.00-2.00 

0.50-1.00 

N/A 

NOTES: 

Saturated 

SALT 

WATER 

0.25-0.50 

1.0-2.00 

1.0-3.00 

1.0-2.00 

3.0-6.00 

0.50-0.75 

2.0-4.00 

1.0-2.00 

1.0-2.00 

3.0-6.00 

0.75-1.25 

4.0-6.00 

1.0-2.00 

0.75-1.50 

3.0-6.00 

1.5-2.00 

5.0-8.00 

1.00-2.00 

0.75-1.50 

3.00-6.00 

High 

Hardness 

Ca++/Mg++ 

(5,000± 

mg/L) 

0.25-0.50 

0.50-2.00 

1.00-3.00 

4.00-8.00 

0.50-1.00 

2.00-4.00 

1.00-2.00 

4.00-8.00 

0.75-1.50 

4.00-6.00 

0.75-1.50 

4.00-8.00 

1.50-2.50 

5.00-8.00 

0.75-1.50 

4.00-8.00 

Lime 

Base 

pH ≥ 11.0 

0.50-0.75 

1.00-3.00 

∗ 

1.00-3.00 

4.00-8.00 

0.75-1.00 

3.00-5.00 

* 

1.00-2.00 

4.00-8.00 

1.00-2.00 

5.00-7.00 

* 

1.00-2.00 

4.00-8.00 

1.50-3.00 

6.00-8.00 

* 

0.75-1.50 

4.00-8.00 

• All concentrations are in lbm/bbl. To convert lbm/bbl to kg/m 3 , multiply lbm/bbl by 

2.85. 

• Product concentration ranges should build stable fluids to 500 o F (260 o C). 

• * pH levels of 11.0 or above will hydrolyze PYRO-TROL ® and reduce its effectiveness. 

• PYRO-VIS is to be used as a supplementary viscosifier only as needed. Typical 

treatments are 0.25 to 2.00 lbm/bbl, depending on density, salinity, and hardness levels. 

• AVOID OVERTREATMENT. 

N/A = Not Applicable. 

System Maintenance 

Drilling in high-temperature environments requires close monitoring of solids content, solids 

type, and particle-size distribution. Daily retort analyses and physical observations at the rig site 

should be supplemented with weekly particle-size distribution analyses (at a Field Service 

Laboratory) if penetration rates are slow, otherwise laboratory monitoring should be more 

frequent. This will enable the engineer to closely monitor solids control equipment efficiency. 



3-64 Revised 2006


Standard chemical analyses (pH, alkalinity, salinity, total hardness) must be closely monitored 

because at elevated bottomhole temperatures (350°F and above) chemical reactions are occurring 

much more rapidly. Physical properties can change radically in a fairly short time. 

Rheological parameters need to be closely watched because they affect hole cleaning and 

hydraulic parameters. Rheological properties must be checked in a thermal heat cup at 120°F so a 

standardized record can be maintained at the rig site. Hot-rolling and static aging of samples 

should be done at current bottom hole temperatures to observe thermal stability characteristics. 

Pilot testing and thermal testing of fluid samples at projected bottom hole temperatures should be 

done weekly to establish responses to possible problems. Fann 70 Viscometer tests can be used to 

observe thermal stability trends and formulate responses to problems that will help the engineer at 

the well site. 

API and HT/HP filtrate trends should be closely observed to see if properties are stable or 

degrading from temperature increases and/or contaminants. Dynamic filtration studies can be 

performed to simulate dynamic down hole conditions at the rig site. Filter cake formation and 

erosion studied under these conditions are more representative of the drilling operation than static 

tests. Cake compressibility tests can supplement the aforementioned tests by observing how 

different products will affect filter cake quality and change filtration rates. 

Advantages and Limitations of the PYRO-DRILL System 

There are many advantages to the PYRO-DRILL system. Almost all drilling fluids can be easily 

and economically conditioned with the appropriate PYRO-DRILL additives for enhanced thermal 

stability. The base fluid should be in good condition prior to treatment. 

Listed below are some of the advantages of the PYRO-DRILL system. 

• Properly maintained systems are thermally stable to 600°F+. 

• PYRO-DRILL fluids are not adversely affected by carbonates, salt water influxes, anhydrite, 

or cement provided low-gravity solids values are in the proper ranges for the respective fluid 

density. 

• The PYRO-DRILL system can provide excellent borehole stability. 

• Properly maintained systems do not cause excessive pump pressures to break circulation. 

This is especially significant for high-density and high-temperature, deep wells. 

• No excessive torque or drag is exhibited with a properly maintained system. 

• Properties are easy to maintain with the PYRO-DRILL system. 

• PYRO-DRILL systems typically exhibit low corrosion rates. This is due to the reduction in 

oxygen content of the fluid by the organic additives acting as oxygen scavengers. 

• Well costs can be significantly reduced while drilling in hostile environments because of 

previously mentioned advantages. 

One component of the PYRO-DRILL system has some minor limitations. PYRO-TROL should 

not be used in high hardness fluids (where Ca ++ and Mg ++ ≥ 5000 mg/L) or in lime-base systems 

(pH ≥ 11.0 are not recommended because of shrinkage/hydrolysis of monomer chains). 



Revised 2006 3-65


UNI-CAL ® Systems 

Lignosulfonates were introduced in the late 1950s as deflocculants for calcium-base systems. In 

the early 1960s, Milchem Drilling Fluids (Baker Hughes Drilling Fluids) introduced 

lignosulfonate to the industry as a deflocculant in drilling fluids without the presence of gypsum 

or lime. The petroleum industry has since used the material regularly in this manner. 

UNI-CAL ® , a chrome lignosulfonate product, is extremely effective in the presence of salt and 

calcium contamination and has performed well in wells with bottom hole temperatures 

approaching 400°F. 

Flocculation is the clustering of suspended colloidal particles. The two forces of attraction usually 

considered are: (1) partial valence forces, and (2) London Van der Waals forces. The two 

mechanisms generally credited with deflocculation or thinning are: (1) electro kinetic 

stabilization, which is a rather delicate form of control achieved with materials such as 

phosphates, silicates and tannins, and (2) mechanical stabilization, which is fairly rugged in 

nature. 

The latter type of stabilization is achieved through the formation of a viscous physical barrier. It 

is the result of the adsorption of an organic polyelectrolyte on the clay particles. This type of 

stabilization requires higher UNI-CAL concentrations in the system on the order of 6 to 8 

lbm/bbl. One of the unique properties of UNI-CAL is its ability to deflocculate effectively at 

relatively low pH values. This is most helpful when drilling hydroxyl-sensitive clays and shale 

formations. 

With any fluid conditioning agent, preparing a “recipe” to accurately predict the quantities of 

materials required is difficult. Therefore, the following recommendations should be viewed only 

as guidelines. 

• For top-hole drilling with freshwater fluids, 0.5 to 1.0 lbm/bbl of UNI-CAL is usually 

sufficient to establish rheological and filtration control. 

• As a deflocculant for seawater fluids, 3 to 6 lbm/bbl is usually adequate. The pH is normally 

maintained in the 10.0 to 10.5 range to suppress calcium and magnesium solubility and to 

minimize corrosion problems. 

• To obtain inhibition with UNI-CAL systems, concentrations of 6 to 8 lbm/bbl are necessary. 

Inhibition is derived from the adsorbed layers of UNI-CAL and offers a significant degree of 

protection against dispersion and swelling of clay solids. 

• For rheological stability in the presence of high bottom hole temperatures ( 350°F+), 

supplementary additions of ALL-TEMP ® are beneficial. Field test data indicates that this 

material effectively extends the thermal stability of UNI-CAL systems. ALL-TEMP 

treatment ranges between 0.5 and 3 lbm/bbl. 

• Maintenance requirements for UNI-CAL systems vary with penetration rate, hole size, fluid 

density, temperature, solids control program, and the formation being drilled. With good 

solids control, maintenance additions can range between 0.5 and 1 lbm/bbl with an average 

daily penetration rate of 100 to 200 ft. 

• Supplementary filtration control can be maintained with treatments of MILGEL 

(approximately 20 lbm/bbl in freshwater and 30 to 35 lbm/bbl in seawater) and a lignite 

material such as LIGCO or LIGCON. For temperatures above 300°F or severe salt and 

calcium contamination, CHEMTROL X would be a more effective additive. 



3-66 Revised 2006


GLYCOL Systems 

Glycol Chemistry 

Polyols (the term “polyol” includes glycols glycerols, polyalkylene glycols and alcohol 

ethoxylates) are well established shale inhibitors for water-base fluids. These compounds are 

typically added to water-base fluids at concentrations between 3% and 10% by volume. They are 

most commonly used in conjunction with a KCl/polymer-base fluid, but have also been added to 

a wide range of systems from fresh water to salt saturated fluids. 

Glycols are compounds containing two hydroxyl groups attached to separate carbon atoms in an 

aliphatic chain. Although there are a few exceptions, nearly all glycols consist solely of carbon, 

hydrogen, and oxygen. Simple glycols are those in which both hydroxyl groups are attached to an 

otherwise un-substituted hydrocarbon chain as represented by the general formula, CnH2n(OH)2. 

Note: 

The more complex glycols are given the name polyglycols and are distinguished by 

intervening ether linkages in the hydrocarbon chain, as represented by the general formula 

CnH2nOx(OH)2. 

A common method of manufacturing these simple glycols is by hydrolysis of the epoxides. These 

epoxides are polymerized in the presence of other compounds and initiators (glycols, amines, 

acids, or water) that contain active hydrogen. The end result is a vast range of products with 

varying molecular weights and characteristics. The glycols are characterized by the way in which 

the basic building blocks are arranged. The specific glycol products show a wide range of 

properties depending on the molecular weight and the composition of the polymer. In general, 

increasing molecular weights result in the following: 

• lower water solubility 

• higher viscosity 

• higher flash point 

• lower cloud point. 

Prior to considering their field application, some key aspects of glycols are discussed below. 

Simple Polyhydric Alcohols 

Glycols are dihydric alcohols containing two hydroxyl groups and are members of the general 

chemical class of polyhydric alcohols. Two commercially important glycols are ethylene glycol 

(commonly used for automotive antifreeze) and propylene glycol (a food additive). A related 

trihydric alcohol is glycerol (present in all vegetable oils and animal fats as glyceride esters). 

Other polyhydric alcohols include sugar alcohols, sorbitol, and mannitol. 

Polyglycols and Polyglycerols 

Polyglycols and polyglycerols are oligormeric or polymeric forms of the simple glycols and 

glycerols. The size and molecular weight of the polyglycols and polyglycerols increase as the 

degree of polymerization or number of repeating units in the oligomers or polymers increases. 

The properties of polyglycols and polyglycerols depend primarily on the molecular weight, 

chemistry of the repeating units, and the chemistry of the starting material. Viscosity, flash point, 

and pour point/freezing point all typically increase with increasing molecular weight, while 

biodegradability and toxicity typically decrease. 



Revised 2006 3-67


Polyethylene Glycols 

Polyethylene glycols are polyglycols made from the addition of ethylene oxide to water (or low 

molecular weight alcohols). The lower molecular weight commercial polyglycols are viscous 

liquids while the higher molecular weight materials are tough solids. All are soluble in fresh 

water at room temperature and up to near the boiling point of water. Toxicity of these products is 

low. Biodegradability of polyethylene glycols is typically good due to the linearity of the 

molecules. 

Polypropylene Glycols 

Polypropylene glycols are polyglycols made from the addition of propylene oxide to water or low 

molecular weight alcohols (although other polyhydric alcohols can also be used). All are viscous 

liquids and the higher molecular weight products (molecular weight > ~1,000) are essentially 

insoluble in water. The lower molecular weight products (molecular weight < ~1,000), however, 

tend to be soluble in fresh water (at least at room temperature) although some show inverse water 

solubility with temperature changes. Toxicity of polypropylene glycols is typically low and 

usually decreases with molecular weight. The lower molecular weight polypropylene glycols 

normally show good biodegradability, while the higher molecular weight polypropylene glycols 

are usually more resistant. 

EO/PO Copolymers 

EO/PO copolymers are polyglycols made from the random addition of both ethylene oxide (EO) 

and propylene oxide (PO) to low molecular weight alcohols (commonly methyl or butyl). The 

ratios of ethylene oxide and propylene oxide used is either close to unity, or ethylene oxide is 

used in abundance. All are viscous liquids, soluble in fresh water at room temperature, and all 

show inverse water solubility with temperature. Toxicity of EO/PO copolymers has been good 

and would be expected to decline with molecular weight. The lower molecular weight EO/PO 

copolymers tend to show acceptable biodegradability and the higher molecular weight materials 

would be expected to be more resistant. 

Polyglycerols 

Polyglycerol is, or can be thought of as, a condensation product made from the 

dehydration/condensation of glycerol. The commercial product is a blend of polyglycerol with 

polyglycol for defoaming and ease of handling. The product appears to be soluble in fresh water 

at all temperatures. The toxicity of polyglycerols is low, and biodegradability would be expected 

to be good. 

The selection of a particular polyol for use in a drilling fluid depends on the application required 

and the environment to which it will be exposed. Low molecular weight water soluble glycols 

find applications for cuttings and borehole stabilization. The scope of this document is restricted 

to detailing the theory and application of low molecular weight polyols only. 

The basic properties of glycols used in the AQUA-DRILL system are shown below. 



3-68 Revised 2006


Table 3-18 

Basic Properties of Glycols Used in the AQUA-DRILL System 

Glycol Density Mol. Wt. Freezing 

Point °F 

pH at 10% 

Flash 

Point °F 

AQUA-COL 8.4 500 < 10 7 - 10 > 200 

AQUA-COL D 8.5 380 < 15 7 - 10 > 250 

AQUA-COL S 9.1 500 < 10 7 - 10 > 212 

Glycol and glycerol have been used in water-base drilling fluids for many applications. 

Chemically related to alcohols, glycols have many of the properties of diesel and mineral oils, but 

contribute virtually no toxicity to the fluid. Having low vapor pressure at normal temperatures, 

glycols are not an inhalation hazard. The similarities between glycols and alcohols are shown 

below. 

Table 3-19 

Chemical Similarities Between Glycols and Alcohols 

Common Name Chemical Name Chemical Structure 

Wood Alcohol Methanol OH 

Drinking Alcohol Ethanol OH 

CH 3 

CH 3 

CH 2 

Rubbing Alcohol Isopropanol OH 

Antifreeze 

Ethylene Glycol 

Propylene Glycol 

CH 3 CH CH 3 

OH 

CH 2 

OH 

OH 

CH 2 

OH 

CH 3 

CH CH 2 

Glycerin Glycerol OH OH 

OH 

CH 2 

CH CH 2 

The chemistry of glycol additives can be varied to meet the demands of the product application. 

This formulation flexibility makes the AQUA-DRILL system the ideal fluid for many 

applications, including: 

• reducing pore pressure transmission into the shale matrix, thus stabilizing the shale 

• use on operations in environmentally-sensitive areas 

The full benefit and cost-effective use of glycols can only be realized when their use is 

engineered correctly. The chemistry of the glycols is such that they possess the physiochemical 

characteristics that make them capable of producing a cloud point (coming out of solution) 

behavior in the right circumstances. It is the engineering ability to control this physiochemical 

phenomenon that can make a mud a success or a failure. 

Cloud point, or more precisely the Cloud Point Temperature (CPT), is defined as that temperature 

where glycol comes out of solution as small dispersed droplets forming a “cloud”. The cloud 

point can also be referred to as the Lower Consulate Solution Temperature (LCST). The ability 

to “cloud” reduces consumption of glycol because as fluid cools, glycol goes back into solution 

and is not removed with cuttings. 



Revised 2006 3-69


Applications 

The principal application for low molecular weight water-soluble glycols is in the drilling of 

reactive shales. Wellbore stability is improved over conventional water-based drilling fluids 

because of the ability of the glycol to “cloud-out” within the shale matrix and form a physical 

barrier to reduce filtrate invasion into the shale matrix. This mechanism of minimizing water 

invasion into the matrix reduces pore pressure transmission into the shale and improves the 

strength and stability of the wellbore. The AQUA-DRILL system was the first water-based 

drilling fluid that was specifically designed to reduce pore pressure transmission into shales. Pore 

pressure transmission reduction is considered to be the primary wellbore stability mechanism of 

emulsion-based drilling fluids. 

The higher initial make-up cost of the glycol-base fluid is often entirely offset by reduced dilution 

costs. In less reactive areas, the benefits of reduced dilution can also be realized, making the fluid 

viable across a wide range of applications. Selection of the correct glycol allows partially 

saturated or salt-saturated fluids to be formulated. This extends the potential use of these fluids 

into wells where salts will be encountered. Return permeability figures obtained by several 

operators on glycol fluids indicate no detrimental effects (and perhaps even some beneficial 

effects) in using glycols across reservoir sections. This is particularly true at higher glycol 

concentrations (5% to 10% by volume). 

AQUA-DRILL System 

The AQUA-DRILL system uses glycols to stabilize shales by reducing pore pressure 

transmission into the shale matrix and was the first-generation high-performance water-based 

mud system for Baker Hughes Drilling Fluids. AQUA-DRILL is a non-toxic, non-sheening 

system that eliminates the potential environmental disadvantages associated with oil/synthetic 

base fluids. 

The Core System 

The “core” AQUA-DRILL system is comprised of the following products. 

Water Soluble Glycol 

• AQUA-COL TM – a low molecular weight glycol ether for increasing the inhibitive 

properties of fresh water and low salinity water-base fluids when drilling reactive shales. 

• AQUA-COL B - a low molecular weight glycol ether providing enhanced shale 

stabilization when using higher salt concentrations in water-base fluids. 

• AQUA-COL TM D – a low molecular weight glycol ether providing enhanced shale 

stabilization when using higher salt concentrations in water-base fluids. 

• AQUA-COL TM S – a low molecular weight polyglycol ether providing enhanced shale 

stabilization when using higher salt concentrations in water-base fluids (up to saturation). 

Polymeric Shale Inhibitor 

• AQUA-SEAL TM – a proprietary polymer to aid in preventing hydration and dispersion of 

drill cuttings, and for delivering filtration control. 

• NEW-DRILL ® – a partially hydrolyzed polyacrylamide (PHPA) polymer that provides 

cuttings encapsulation and helps reduce dispersion of cuttings. 



3-70 Revised 2006


Salt Component 

Potassium chloride, sodium chloride or formates – various salts for adjusting the system’s water 

activity coefficient to match that of the shale being drilled. Local environmental regulations 

should be consulted when selecting a salt. 

• Biopolymers - rheological control is achieved using biopolymers such as XAN-PLEX. 

• Potassium Carbonate - a source of K + ions for additional shale inhibition and alkalinity 

control (eliminating the need for caustic soda at the wellsite). 

Supplementary Products 

Several supplementary products can be used to enhance the performance of the AQUA-DRILL 

system. Applications include: 

• dynamic filtration control 

• drilling or running casing through depleted zones 

• improved rates of penetration and reduced bit-balling 

• enhanced lubricity for drilling highly-deviated wells 

• spotting applications. 

AQUA-MAGIC ® 

AQUA-MAGIC ® is a chemically-modified glycol-based material designed for all types of waterbase 

drilling fluids. AQUA-MAGIC additions are recommended whenever differential sticking 

may occur, especially while drilling high-angle wells. 

AQUA-MAGIC is added at a concentration of 2 - 4% by volume, when running casing through 

depleted zones. It is recommended to spot 10% by volume in the open hole through the zone. 

Inhibition Mechanisms 

Figure 3-15 illustrates how the addition of a glycol (AQUA-COL) improves the inhibition of a 

water-base fluid system. The inhibition mechanisms related to the AQUA-DRILL system can be 

divided into three components. 

• Pore pressure transmission 

• Capillary effects 

• Cloud point behavior 



Revised 2006 3-71


Inhibition Studies with Tertiary Clays 

Figure 3-16 

Inhibition Studies with Tertiary Clays 

Pore Pressure Transmission 

Baker Hughes Drilling Fluids has explored pore pressure transmission 

(PPT) testing for several years. PPT testing measures the formation pore 

pressure increase from filtrate invasion in very low permeability formations 

such as shales. In highly permeable formations the pressure rise from 

filtrate flow is rapidly dissipated in the formation volume and pore pressure 

is not affected. However, in very low permeability formations, the pressure 

increase from filtrate invasion declines very slowly and the pore pressure 

continues to increase with additional filtrate flow. This pore pressure 

increase reduces the effective over balance pressure. Over-balance pressure 

decline is exaggerated by wall fractures from drilling. These fractures 

increase near-wellbore permeability resulting in rapid pressure increase 

inside the wall. Reduced overbalance tends to destabilize the wellbore and 

promote sloughing. The introduction of cloud point glycols (AQUA- 

DRILL), aluminum complexes (ALPLEX) and sealing polymers 

(PERFORMAX) by Baker Hughes Drilling Fluids has greatly improved 

the osmotic effectiveness of water-based drilling fluids. 

Properly Pressured: Ideally, the hydrostatic pressure exerted by the mud 

column is higher than the formation (pore) pressure. Here, there is a 

pressure differential at the shale surface which serves as a support 

mechanism (first image) to offset over-burden pressure. 

Over Pressured: Here, drilling fluid pressure invasion (second image) 

occurs into the shale matrix. Due to the low permeability of the shale, the 

added pressure dissipates very slowly. In emulsion fluids, the capillary 

entry pressure effects strongly impede the invasion of pressure from base 

fluids (oils, esters or synthetics) because of the wetting characteristics of 

water vs. base fluids. However, in water-based muds, the capillary entry 

pressure can be very low and therefore water pressure invasion can easily 

occur in the matrix. As pressure invasion occurs, the pore pressure at the 

shale surface rapidly increases to a level equivalent to that of the mud 

column. Then, the differential pressure at the surface is reduced and 



3-72 Revised 2006


pressure support (over-balance) is lost. 

Pressure Invasion: Finally, loss of differential pressure support at the wellbore surface allows 

the over-burden pressure (weight of shale pressing down) to destabilize the invaded shale and it 

will slough off (third image) into the annulus. In this case, the pressure of the mud column is 

equal to the pressure within the shale, leaving no supporting pressure to prevent the overburden 

force from sloughing the shale. 

Capillary Effects 

Neither water-base fluids nor oil-base fluids form a solid filter cake in shale. Under normal fluid 

pressures, shales are permeable to water-base fluids but almost impermeable to oil. The stable 

behavior of shales while drilling with oil-base fluid or synthetic-base fluids is a result of capillary 

action. When oil enters a shale, it has to overcome a threshold pressure caused by the capillary 

effect between oil and the pore fluid. The capillary pressure is in the order of thousands of psi and 

is generally too large to be overcome by the fluid pressure differential. The threshold pressure, 

therefore, acts as an alternative semi-permeable membrane and provides effective fluid support to 

the wellbore. 

Oil/ Synthetic Based mud 

Water Based Mud 

Wellbore 

pressure 

Wellbore 

pressure 

Water 

Pore pressure 

Water 

Water 

Pore pressure 

Figure 3-17 

Capillary Action in Oil/Synthetic vs. Water Base Fluids 

As a consequence, shale instability with oil and synthetic drilling fluids is normally caused by 

lack of fluid support, i.e., too low of a fluid density. 

Cloud Point Behavior 

Definition 

Cloud point is a phenomenon exhibited by many glycols. The solubility of these glycols in water 

decreases as temperature increases, with materials that are fully soluble at room temperature 

forming separate phases at higher temperatures. The temperature at which the glycol and water 

separate is known as cloud point, since the previously clear solution becomes “cloudy” upon 

separation as shown in Figure 3-17 Capillary Action in Oil/Synthetic vs. Water Base Fluids 



Revised 2006 3-73


Glycol and water together 

At room temperature, the 

glycol demonstrates 

complete water solubility. 

Glycol/Water solution at cloud point 

When the solution's temperature is 

raised to the cloud point, the glycol 

becomes insoluble and begins to 

form individual droplets (micelles). 

The solution's appearance 

becomes "cloudy". 

Solution above cloud point temp. 

If the temperature remains above 

the cloud point, the seperation of 

glycol and water becomes 

distinct and both phases are 

clearly visible. 

Figure 3-18 

Cloud Point: Temperature at Which Water and Glycol Begin to Separate 

Engineering Cloud Point 

For glycols at room temperature, water solubility decreases with increasing molecular weight. 

Low molecular weight glycols are typically more soluble in freshwater systems than in high 

molecular weight glycols. Two factors control the cloud point of freshwater glycols: 

• salinity 

• glycol concentration 

An increase in either of these factors results in a lower cloud point temperature. 

When a glycol is mixed in water below the resultant solution’s cloud point, it is evenly distributed 

as minute droplets known as micelles. The micelles are stabilized by hydrogen bonding between 

the water molecules and oxygen atoms present in the glycol molecule. The stabilization process is 

known as hydration. When the temperature increases, hydration decreases until the micelles are 

no longer stable in an aqueous environment. Consequently, they coalesce in large numbers and 

form a separate phase that is distinct from the water. 

The “clouding” process is reversible. If the solution is subsequently cooled, the two phases 

recombine to form a clear, single-phase solution. Baker Hughes Drilling Fluids has engineered 

combinations of glycol concentration and salinity to design a drilling fluid where glycols are in 

solution on the surface and out of solution downhole. As bottom-hole temperatures change with 

depth, the system’s cloud point can be adjusted to maintain optimized drilling performance and 

shale stability. 



3-74 Revised 2006


Figure 3-19 

Cloud Points for Various Polyols in KCl Solutions 

The great variety of cloud point temperatures seen indicates that one polyol may not be suitable 

for all applications. Additionally, the polyol will have to be selected based upon its cloud point at 

a specified salinity. Alternatively, the cloud point of the polyol can be adjusted by altering the 

salinity of the liquid phase. Varying the polyol type and system salinity has afforded Baker 

Hughes Drilling Fluids effective control of the cloud point over a wide operating range. 

Cloud point is modified at the wellsite using the software program (available through Baker 

Hughes Drilling Fluids TITAN group) GLY-CAD ® which models the downhole behavior of all 

of drilling fluids water-soluble glycol products. With this program, the concentrations of salt and 

glycol can be engineered to match the operational needs of the drilling fluid. Depending on 

downhole conditions, such as formation temperature, the optimum blend of glycols and salts is 

determined to achieve the most effective cloud point for shale inhibition. 

Shale Inhibition and Drilling Performance 

Baker Hughes Drilling Fluids has conducted studies to examine the benefits of cloud point 

behavior on drilling performance and shale stability. The results have shown distinct performance 

benefits both above and below cloud point. Improvement in inhibition seen over a wide range of 

temperatures is directly related to the cloud point of the glycol. Cloud point is the transition point 

or start of phase separation at which the glycol changes from being water soluble to water 

insoluble. 

Explanation 

Research carried out by other investigators (SPE 28960) concluded that the glycol is adsorbed by 

the clay. During the adsorption process, water is displaced from the clay surface and ordered 

structures of polyols are formed. A weak attachment is postulated because of the observation that 

there is no rapid depletion of the polyol in the drilling fluid system. For this to be the case, there 

must be some mechanism of association and disassociation of the polyol in the circulating 

system. The nature of these structures and their stability in aqueous fluids is strongly controlled 

by the presence of potassium cations with certain polyols. 

• Under most conditions, a single polyol layer forms on the clay in the presence of potassium. 

The resulting complexes are stable in water. 



Revised 2006 3-75


• A complex containing two polyol layers is formed when potassium is absent. This complex 

is less stable in water. 

• Studies on other polyols conclude an additional contribution comes from interactions 

between polyol molecules at the clay surface. 

Polyol fluids are effective in most shale types, particularly in young or relatively non-compacted 

shales with high clay contents. Compared with, for example, KCl/polymer fluid, polyol systems 

give improved wellbore conditions and produce firmer cuttings that do not readily disperse into 

the fluid. These attributes frequently combine to give faster drilling rates, and reduced fluid 

volumes that translate into reduced drilling costs. 

Above the Cloud Point 

Above the cloud point, glycols are present as emulsions while the separate phases are continually 

intermixed by the circulating system, particularly at the bit. These emulsions block pores in the 

formation, preventing fluid invasion and consequent instability in water-sensitive formations. 

The AQUA-DRILL system can be engineered so drill cuttings at the bottom of the hole are 

initially above the system’s cloud point. A protective glycol layer forms around the cuttings as a 

result of glycol “clouding out” on its surface. This prevents the cuttings from reacting with water 

until they have risen to a point in the wellbore where the fluid temperature drops below the cloud 

point, allowing the glycol to re-dissolve into the fluid. This explains both the increased inhibition 

present when using the AQUA-DRILL system in reactive shales and the low glycol depletion 

rates seen in the field. 

Below the Cloud Point 

Glycols still provide enhanced performance below the cloud point. Field evidence has shown that 

glycols below the cloud point deliver improved shale stability. Also, laboratory studies have 

shown that shale inhibition with glycols is more effective when water-soluble, rather than waterinsoluble, 

glycols are employed. One explanation is that the glycols adsorb onto shale surfaces 

via oxygen molecules present in the glycol chain. Once the water-soluble glycols enter the 

formation, the higher formation temperature causes the glycol/water solution to phase separate insitu, 

forming an emulsion. The hydrophobic glycol droplets in the emulsion fill and block the 

shale pores, preventing further fluid invasion and stabilizing the shale. 

It can be concluded that shale inhibition and formation protection is achieved by: 

• the polyol displacing water from adsorption sites on clay minerals present in shales, and 

• blocking the formation pores from further ingress of invasive fluids by “clouding out.” 


Several operators have now carried out studies to evaluate the effect of polyols in drilling/coring 

fluids on return permeability. These studies have shown no adverse effects on the formation 

samples tested. Many suggest that the polyol actually protects the productive rock from 

impairment by the drilling fluid provided it is above the cloud point. 

As discussed earlier, the theory is that the polyol emulsion protects the formation from excessive 

fluid invasion by pore plugging just inside the rock matrix as the material “clouds out” within the 

hotter environment, thus sealing the pores against further ingress. At this point, 

surfactant/polymer interactions and complexation of surfactant with monovalent ions (such as 

potassium in solution) will occur more frequently. These reactions provide optimum benefit for 

long term borehole protection by acting as a blocking layer which compliments polymer 

additions. An additional benefit may be the inhibition of interstitial clays. 



3-76 Revised 2006


Filter Cake 

Once part of the clouding polyol in solution becomes hydrophobic, a significant improvement in 

filter cake quality is seen. Water tends to bead on the surface and the cake is easier to “peel off” 

the filter medium. 

Well Clean-Up 

Production after acidization and completion of wells has been above operator expectations. 

Unfortunately, no information on skin damage and comparisons of production rates before and 

after using polyols has been made available. It is thought that quick plugging of low permeability 

sandstones (< 20 mDarcy) by the polyol leads to minimal formation damage inside the reservoir. 

Later acidization could then reach beyond the invasion zone around the wellbore leading to a 

better clean-up and enhanced production. 

Viscosity Effect 

In general, polyols added at low concentrations (< 5%) have little effect on the viscosity of the 

drilling fluid. At increased concentrations, there will be some variation in viscosity with the 

maximum rheology obtained in the 110° to 130°F temperature range. 

Effect of Temperature on Yield Point at 10% AQUA-COL TM 

Figure 3-20 

Effect of Temperature on Yield Point at 10% AQUA-COL TM 

Environment 

As a group, low molecular weight polyols are considered low in toxicity and readily 

biodegradable. The fact that they are water soluble means that they are able to disperse in the 

water column and biodegrade easily. An added feature of polyol use in water-base fluid is the 

reduction in dilution rates due to their inhibitive nature which reduces the overall volume of 

water-base fluid products discharged to the environment. 



Revised 2006 3-77


Elastomer Testing 

The following elastomer tests (Table 3-20 Effects of AQUA-COL ® and AQUA-COL ® D on 

Elastomers in a 5% Solution) show the effect of AQUA-COL ® and AQUA-COL ® D on 

elastomers in a 5% solution. 

Table 3-20 

Effects of AQUA-COL ® and AQUA-COL ® D on Elastomers in a 5% Solution 

Product Elastomer Time (hrs) Temp (°F) Volume 

Change % 

Hardness 

Change % 

AQUA-COL ® Type D 72 250 5.92 5.3 

AQUA-COL D ® Type D 72 250 7.50 6.3 

AQUA-COL ® Type F 72 250 5.44 4.0 

Engineering Guidelines and Comments 

Premixed Fluid 

North Sea 

An existing practice in the North Sea has typically been to utilize concentrated premixes of 

AQUA-COL ® to cut down on the number of drums of glycol required at the rig-site and then to 

maintain glycol levels at 3% to 5% while drilling. A glycol premix has typically contained 80 

lbm/bbl KCl, 7% AQUA-COL ® and 5 lbm/bbl MIL-PAC ® LV. Laboratory tests were conducted 

which showed that this mixture produced a cloud point of 6°C (43°F) with complete phase 

separation at 8°C (47°F). 

Further cloud point measurements have been made to determine the highest levels of KCl and 

AQUA-COL ® which could be combined without the risk of phase separation under normal 

operating conditions. If the same ratio of salt to glycol as in the original premix is to be 

maintained, then 60 lbm/bbl KCl and 5.25% AQUA-COL ® will give a cloud point in the region 

of 24°C (75°F). This should be adequate unless there is significant heat input to the fluid resulting 

from shear during mixing. 

If the KCl concentration is reduced to 50 lbm/bbl, this will allow 7% AQUA-COL ® to be added. 

This formulation should be used if the primary requirement is to minimize the number of drums 

of glycol shipped to the rig. At 70 lbm/bbl KCl, the highest level of AQUA-COL ® which can be 

added without the cloud point dropping below 20°C (68°F) is 2%. Premixes containing more than 

60 lbm/bbl KCl should not be used in conjunction with AQUA-COL ® . 

Gulf of Mexico 

The practice of shipping premixed fluid to the rig is becoming more commonplace. The desired 

fluid properties for the anticipated interval are established and a suitable volume of liquid is 

prepared. After drilling the cement and performing the formation integrity test, the wellbore is 

displaced with the AQUA-DRILL ® fluid. A suitable high viscosity spacer of 30 to 50 bbls is 

pumped ahead of the AQUA-DRILL ® fluid. 



3-78 Revised 2006


System Preparation 

Table 3-21 Range of Glycol Cloud Points in KCl and NaCl Brines is a compilation of various 

brine and glycol cloud points. It can be used for planning purposes in lieu of the software 

program, GLY-CAD ® . However, the final system formulation should be prepared from GLY- 

CAD. 

Table 3-21 

Range of Glycol Cloud Points in KCl and NaCl Brines 

Product Brine Salt, % CPT, °F 

AQUA-COL, 1 – 10% by wt. KCl 5 - 20 42 - 130 

AQUA-COL, 1 – 10% by wt. NaCl 5 – 26 25 - 124 

AQUA-COL B, 1 – 10% by wt. KCl 5 – 20 104 - 241 

AQUA-COL B, 1 – 10% by wt. NaCl 5 – 26 62 - 225 

AQUA-COL D, 1 – 10% by wt. KCl 5 – 20 92 - 242 

AQUA-COL D, 1 – 10% by wt, NaCl 5 – 26 74 - 425 

AQUA-COL S, 1 – 10% by wt. KCl 15 – 20 195 – 286 

AQUA-COL S, 1 – 10% by wt, NaCl 15 – 26 146 - 262 

Cloud Point Maintenance Offshore 

Under normal drilling, there will be a temperature differential between BHCT and formation 

temperature. To achieve the maximum performance from cloud point glycols, it is desirable to 

maintain the cloud point within this range as close as possible. This requires that glycols are 

available so that any cloud point can be achieved between approximately 30°C (86°F) and 75°C 

(167°F). The lower end of this range (30°-40°C [86°-104°F]) can be readily achieved with 

AQUA-COL in the 2% to 3% range and KCl levels of 15 to 30 lbm/bbl. The higher end (55°C to 

75°C (131°F to 167°F) can also be achieved by utilizing AQUA-COL D at 3% to 5% together 

with higher levels of KCl. 

Note: 

All references to percentages of glycol in fluid should be interpreted to relate to the glycol 

as a percentage of the brine phase of the fluid. Adding 30 bbls glycol to 970 bbls fluid will 

only result in 3% glycol concentration if the fluid is completely unweighted and devoid of 

drill solids. In all other cases, the solids volume of the fluid should be backed out of any 

calculations relating to volume percentages of glycols. 

Rheological Properties 

The following ranges for gel strengths and yield points are recommended when drilling at rates of 

100 – 200 ft/hr in the indicated hole sizes. 



Revised 2006 3-79


Table 3-22 

Hole Size 

Recommended Ranges for Gel Strengths and Yield Points for AQUA-COL 

Systems 

Yield Point lbs/100 

sq ft 

Initial Gel lbs/100 

sq ft 

10 Min Gel 

lbs/100 sq ft 

17½" / 16" 25 - 40 5 - 10 9 - 20 

12¼" 18 - 25 4 - 8 7 - 15 

8 3/8" / 8" 10 - 15 4 - 8 7 - 15 

High and low viscosity sweeps will give further assistance in hole cleaning. In an ideal consistent 

drilling situation, occasional sweeps will serve as an indication of successful hole cleaning. A 

minimum initial gel strength of 4 lb/100 ft 2 will be required to ensure that there is no barite 

settling on surface. 

Test Procedures 

In addition to the basic fluid tests of density, rheological, and filtration properties, tests for excess 

NEW-DRILL, PHPA and AQUA-COL should be carried out. Two tests for AQUA-COL are 

available. 

Colorimetric Method (GLY-KIT) 

This is the standard method for the determination of glycols in drilling fluid filtrates. The glycol 

is extracted into dichloromethane using a blue complexing agent. The resulting blue color of the 

dichloromethane is compared to standard solutions and the concentration determined. 

Equipment 

Procedure 

• Eppendorf Model 3190 Fixed Volume Pipette, 100 μL 

• Pipette tips, 10 to 100 μL range 

• Test Solution Vials 

• Color Wheel for viewing samples and holding vials 

• Box of Kemwipes. 

1. Obtain 1 or more ml of filtrate. 

2. Attach pipette tip to pipette. 

• Press the yellow control knob down to the first stop. 

• Hold the pipette vertically and immerse tip about 3 mm into the filtrate. 

• Let the yellow control knob rise slowly to fill the tip with liquid. 

• Slide the tip out of the filtrate along the wall of the container. 

• Wipe off any droplets on the outside of the tip with a Kemwipe. 

3. Open the test vial and dispense the filtrate. 

• Hole the pipette tip at an angle against the inside of the vial. 

• Press the yellow control knob slowly down to the first stop and wait about three 

seconds. 



3-80 Revised 2006


• Press the button down to the second stop to empty the tip completely. 

• Hold the button down and slide the tip along the wall on the vial and remove. 

• Let the yellow control knob glide back to its rest position. 

• Eject the tip by pressing the tip ejector button. 

4. Cap the vial and shake for 1 minute. 

5. Allow vial to rest for 2 to 3 minutes while the phases separate. 

6. Place vial in the top of the color wheel viewer to best match its color to one of the 

standard solutions. Tilt the color wheel forward and view the % by volume glycol in the 

aqueous phase on the scale which is visible through the small hole on top of the color 

wheel and record. 

Note: 

For glycol concentrations between 5% and 10% by volume, the filtrate must be diluted 

50:50 with distilled water. (Refer to detailed instructions with equipment) 

Cloud Point Method 

This method makes use of the polyols cloud point properties. A filtrate sample is collected in a 

graduated cylinder and placed on a heating element. The temperature is raised until the filtrate 

“clouds out”. At this point, there will be a phase separation and the polyol will form a discrete 

liquid on top of the filtrate. If phase separation does not occur, then the salinity of the filtrate can 

be raised by adding KCl or salt. The approximate concentration of polyol can be expressed as a 

percentage of the total fluid phase. It must be stressed that this is an approximate guide only. 

Logistics 

In order to minimize the amount of material transported to the rig, the fluid can be shipped as a 

concentrated bulk liquid. This method has been used on numerous wells to date. Typically 3.5 to 

4 lbm/bbl MIL-PAC polymer and 5% to 5.5% AQUA-COL are mixed into 60 lbm/bbl KCl brine. 

Concentrations of AQUA-COL and polymer are such that when the brine is cut back with drillwater, 

all products are at the desired concentration. 

Only small amounts of sacked products are shipped to the rig for maintenance and contingency. 

Higher concentrations of products in the premix are not possible due to the glycol clouding out in 

the fluid plant at ambient temperatures. The inhibitive nature of the AQUA-COL fluid results in 

end of section fluid properties being similar to starting properties. The fluid is therefore ideal for 

re-use, either on the next interval or similar interval on another well. The re-use of the fluid has 

significantly reduced costs and minimized the amount discharged into the sea. 

Whole Fluid (Mud) Discharge 

Minimal dilution requirements reduce surface losses therefore little whole fluid is dumped. The 

use of AQUA-DRILL has dramatically reduced the amount of chemical discharged into the sea. 

On a recent Central Graben 17½" section, surface losses were 1230 bbls (0.29 bbls/ft). The only 

whole fluid lost was associated with the cuttings and dumping of the header box. 

Tripping Procedures 

Using the AQUA-DRILL system yields a gauge or very close to gauge hole. Therefore, it is 

important to ensure that the hole is circulated clean prior to trips. A tight hole can be experienced 



Revised 2006 3-81


on the first trip in a new hole. On rigs equipped with a top drive, it has become routine to pump 

out of new hole in stands. 

Solids Control 

A wide variety of solids control systems have been used with the AQUA-DRILL system. Good 

solids control will always be of benefit, but the system has been particularly beneficial when only 

average or poor solids control equipment was available. Reduced dispersion of solids and 

minimal clay blinding on screens makes the system more flexible than conventional polymer 

systems. 

MBT Values 

A common scenario when drilling reactive clays with conventional polymer fluids is to see a 

rapid buildup of gels and MBT requiring rapid dilution to control these properties. In the AQUA- 

DRILL system, the problem is often the reverse, i.e., low gels resulting from low MBT values 

requiring supplemental additions of XAN-PLEX ® . It is quite normal under these circumstances to 

see an MBT value of 15 after 5,000 ft of drilling a 17½" hole through reactive clay formations 

with minimal dilution. 

Dilution Rates 

Experience from past wells has provided the following expected dilution rates. The figures 

quoted below are for 4,000 ft of clay with average solids control equipment and fluid weight in 

the 11.0 to 13.0 ppg range. 

Table 3-23 

Clay Type 

Mud Weight Selection 

Recommended Dilution Rates for AQUA-DRILL Systems 

Low Reactivity 0.1 - 0.2 m 3 /m 

0.2 - 0.4 bbl/ft 

Intermediate 0.15 - 0.3 m 3 /m 

0.3 - 0.6 bbl/ft 

Highly Reactive 0.25 - 0.5 m 3 /m 

0.5 - 1.0 bbl/ft 

Hole Size 

17½" 12 1/4" 

0.05 - 0.15 m 3 /m 

0.1 - 0.3 bbl/ft 

0.15 - 0.3 m 3 /m 

0.3 - 0.4 bbl/ft 

0.2 - 0.4 m 3 /m 

0.4 - 0.8 bbl/ft 

As with any system, poor mud weight selection will mask the benefits of this improved waterbase 

fluid. An additional benefit from the improved fluid system can be lost by poor mud weight 

selection. In most cases, inadequate weight is the problem. There is no substitute for good offset 

data in well planning. 

pH Control 

The AQUA-DRILL system functions over a wide range of alkalinity values. However, to 

minimize clay dispersion, a pH in the range 8.5 to 9.5 is recommended. 



3-82 Revised 2006


AQUA-DRILL Application (North Sea) 

Product Descriptions 

Potential applications for the potassium chloride AQUA-DRILL system include a wide spectrum 

of wells. To date, the primary application has been for inhibition in tertiary clays. Details of the 

fluid system are outlined in the following pages together with general recommendations on 

system maintenance. Product applications and concentrations are listed in the following table. 

Table 3-24 

Recommended Product Concentrations and Applications for the AQUA-DRILL 

System 

Product Field Concentration Application 

Potassium Chloride (KCl) 25 - 40 lbm/bbl Inhibit clay swelling & hydration 

MIL-PAC ® LV 2 - 4 lbm/bbl Filtration control 

MIL-PAC ® R 0 - 2 lbm/bbl Filtration control 

XAN-PLEX ® D 0 - 1 lbm/bbl Rheology control 

NEW-DRILL ® 2 - 4 lbm/bbl Improve cuttings integrity 

AQUA-COL ® 2% - 5% by vol. Reduced Pressure Transmission 

Caustic soda 0.1 - 1 lbm/bbl pH control 

MIL-BAR ® As required Density control 

KCl – Potassium Chloride can be used at varying concentrations from 0 to 80 lbm/bbl 

(saturation). The product is usually shipped in its concentrated form to ease logistics. The level of 

inhibition generally increases with increasing concentration of potassium chloride. A typical 

curve is illustrated in Figure 3-20 Effect of Temperature on Yield Point at 10% AQUA- 

COL TM or tertiary clay. Several wells have been engineered using saturated potassium chloride. 

On these wells, only marginal increases in shale inhibition were observed. 

In saturated conditions, there is also the potential for formation embrittlement due to the 

movement of water from the formation into the drilling fluid. In addition, high chloride levels can 

affect log evaluation in reservoir sections. A suitable compromise on inhibition, logistics, and 

economics using KCl is to maintain the concentration in the range 25 to 40 lbm/bbl. 

Note: 

Chloride concentration will affect the cloud point of the polyol in the system and this should 

be considered when selecting the salt concentration. 



Revised 2006 3-83


Figure 3-21 

Relative Inhibition of Tertiary Clay in KCl Solutions 

MIL-PAC LV – Low viscosity polyanionic cellulose will provide a degree of polymer 

encapsulation, but its principle function is in the control of the API filtrate. MIL-PAC LV as a 

filtration control agent will impart minimal viscosity to the system. Concentrations will vary with 

filtration rate desired and overall salinity of the fluid. Normally, a treatment level of 1.43 to 5.7 

kg/m 3 (0.5 to 2.0 lbm/bbl) will provide the desired results. 

MIL-PAC R – The regular grade polyanionic cellulose functions in a similar way to the low 

viscosity version but will also impart viscosity. The ratio of MIL-PAC R to MIL-PAC LV will 

control the degree of viscosity-to-filtrate control required. MIL-PAC R will impart a significant 

level of high shear viscosity, but minimal gel strength. 

Traditionally, the gel strengths in the system were provided in part by formation clays in a 

conventional polymer system while drilling in a reactive area. However, the high level of 

inhibition provided by AQUA-COL has led to minimal increase in gel strengths. On recent wells, 

the concentration of MIL-PAC R has been decreased in favor of XAN-PLEX D polymer. 

Improved hole cleaning is a direct result of this change. To reduce fluid loss or increase viscosity, 

1.43 to 5.7 kg/m 3 (0.5 to 2.0 lbm/bbl) is normally required. 

XAN-PLEX D– Xanthan gum used to increase viscosity and gel strengths, as well as to aid in 

suspending weight materials and cuttings. Normal treatment is 2.85 kg/m 3 (1.0 lbm/bbl) to 

achieve a funnel viscosity of 35 to 38 sec/qt. 

NEW-DRILL – This is a PHPA polymer supplied in fine powder form. The high molecular 

weight of this anionic polymer is designed to encapsulate and reduce drill cutting dispersal and 

swelling. Addition of a PHPA polymer is a preventative measure and not a cure for high solids 

induced mud rheological properties. If PHPA polymer is added to a system that is solids laden, 

this will result in excessive viscosities. NEW-DRILL additions to new polymer fluid will result in 

a viscosity hump, therefore, allow a minimum of four (preferably eight) hours mixing time. If the 

drill-out formation is a clay, then it is recommended that a minimum of half the NEW-DRILL 

concentration be added prior to displacement. The level of NEW-DRILL in the system can be 

monitored using the Clapper Gas Train test. While this provides only approximate values, it will 

clearly indicate an excess of the polymer in the system. A minimum excess of 1.0 lbm/bbl is 

recommended. 



3-84 Revised 2006


Figure 3-22 

Viscosity Increases with NEW-DRILL Additions 

AQUA-COL, AQUA-COL D, and AQUA-COL S – These are low molecular weight water 

soluble polyols. The concentration is proportional to the level of inhibition. Addition of polyol to 

improve inhibition must be viewed against the increased cost of the fluid. The optimum 

concentration for clay inhibition in North Sea wells is in the range 3% to 5% by volume. The 

GLYKIT test can be used for measuring AQUA-COL concentration in the drilling mud system. 

In order to allow for (theoretical) depletion, the product concentration is usually allowed to 

increase by 0.5% to 1.0% through the interval. At high AQUA-COL concentrations (> 7.0%), 

there have been some flocculating effects in laboratory fluids. Consultation with BHDF is 

required before considering raising the active concentration above 7.0% by volume AQUA-COL. 

Caustic Soda – Caustic Soda, is used primarily for pH and alkalinity control. It minimizes the 

solubility of calcium as well as magnesium contaminants in water-base drilling fluids. Caustic 

Soda is always added to solubilize and activate LIGCO and UNI-CAL. Do not mix it through the 

fluid hopper. Dissolve it in water in a chemical barrel. One sack should be added very slowly with 

careful agitation to 189 liters (50 gal) of water in the chemical barrel. Caustic soda is a corrosive 

material and should be handled with extreme caution. 

MIL-BAR - Barium sulfate (BaSO 4 ), commonly known as barite is used to increase the density 

of all types of drilling fluids. MIL-BAR is chemically inert to all drilling fluid additives 

Selected Well Summaries 

Table 3-25 AQUA-DRILL Applications in the North Sea provides an overview of six AQUA- 

DRILL mud wells drilled in the North Sea. Data from each well was from the 17 ½” hole 

section. 



Revised 2006 3-85


Table 3-25 

AQUA-DRILL Applications in the North Sea 

Well Name 21/25-10 29/3a-5 21/25-12 30/16-13 211/29-BD- 

46 

Product Concentrations 

29/7-5 

KCl, lbm/bbl 35.00 37.60 39.58 35.52 33.83 39.19 

MIL-PAC REG, lbm/bbl 1.26 0.87 1.07 0.58 1.03 0.57 

MIL-PAC LV, lbm/bbl 2.10 2.01 3.91 1.00 1.10 2.01 

NEW-DRILL L, lbm/bbl 2.10 1.99 1.78 1.17 1.65 2.42 

XAN-PLEX D, lbm/bbl 0.56 0.31 0.47 0.49 0.80 0.60 

AQUA-COL M, % by vol 3.00 3.40 3.94 3.10 3.11 3.73 

CAUSTIC SODA, lbm/bbl 0.49 0.94 0.57 0.80 0.79 

MIL-BAR, lbm/bbl 267.00 223.90 283.30 141.89 120.00 232.30 

Typical Drilling Fluid Properties 

Fluid Weight, ppg 13.1 12.5 - 13.2 13.1 11.4 9.8 - 11.1 12.5 - 13.3 

Plastic Viscosity, cP 25 - 30 30 -35 25 - 35 20 - 25 18 - 25 34 

Yield Point, lbs/100 ft 2 25 - 30 25 - 30 28 - 32 20 - 27 20 - 34 36 

Gel Strength, lbs/100 ft 2 3-4 / 4-8 4-7 / 5-14 3-5 / 7-8 4-5 / 6-9 6 / 12 7 / 12 

MBT, lbm/bbl 5 - 15 5 - 22.5 5 - 15 5 - 11.5 5 - 20 5 - 12 

KCl, lbm/bbl 25 - 35 33 - 36 25 - 35 30 - 35 35 33 

Chlorides, g/L 45 - 55 45 - 57 35 - 45 40 - 46 55 50 

API Filtrate, cc 4.0 - 6.0 3.0 - 5.6 4.0 - 4.8 5.0 - 6.4 5.0 5.0 - 6.0 

Pf / Mf, cc 0.2 - 0.6 0.2 / 0.6 0.4 / 1.2 0.2 / 0.4 0.3 / 1.0 0.05 / 0.15 

pH 9.0 - 9.5 9.0 - 9.5 9.5 9.5 - 10.0 9.5 - 10.0 9.5 

Volume Built and Dilution Rate 

Dilution Rate, bbl/ft 0.45 0.78 0.52 0.60 1.05 0.42 

Total Volume Built, bbl 4022 7535 5063 3450 6809 4652 

Hole Stability 

All six wells showed good hole stability with logs, casing run, and cementing on all wells without 

incident. Trips off bottom in new hole were characterized by minor tight hole due to gauge 

conditions. To avoid delays, the new hole sections were pumped out using the top drive. 

Further indications of the inhibition of the fluid system were the low dilution rates and minimal 

increase in MBT. There may be further cost savings on future wells if fluids are run with less 

dilution allowing MBT's to reach levels in the range 20 to 25 lbm/bbl. No dumping of whole fluid 

is expected to be a characteristic of future wells. On Well #29/7-5, the only additional fluid built 

was that to replace fluid lost on cuttings discharged over the shaker. 

Chemical Discharge 

Routine procedures are in place to measure the amount of oil fluid discharged with cuttings. 

Similar measures to record total water-base discharges are now in place. The use of AQUA- 

DRILL has resulted in dramatic reduction in the levels of chemical discharge. The typical 

offshore discharge figures for water-base fluid systems are shown below 



3-86 Revised 2006


. 

Table 3-26 

Typical Offshore Discharges Figures for Water Base Mud Systems 

AQUA-DRILL 

0.4 - 0.8 bbls/ft 

KCl Polymer 

GYPSUM 

0.8 - 1.5 bbls/ft 

2.0 - 4.0 bbls/ft 

Logistics 

Most polymer fluids are routinely shipped as premix concentrates from the shore based fluid 

plants. The use of AQUA-DRILL and the consequent reductions in fluid volumes have reduced 

the volumes required by 40% to 70%. Typically, one or two boat movements replace the previous 

four to eight. 

Conclusions 

The AQUA-DRILL System is a proven inhibitive fluid system. Increasingly demanding 

applications will establish the degree to which it can be considered a viable replacement for oilbase 

fluids. Relatively high initial make-up costs of the system are offset by reduced dilution 

requirements. Overall, a more stable wellbore and reduced chemical discharge to the sea is 

achievable. Additional benefits such as improved lubricity and reduced formation damage require 

further qualification in the field. 

ALPLEX ® – Aluminum-Based Shale Stabilizer 

Introduction 

Laboratory results and actual field experience have shown that aluminum compounds are viable 

additives in water-base fluid systems for reducing pore pressure transmission in shales via a 

mechanism similar to that of the PERFORMAX and AQUA-DRILL Systems. 

Aluminum Chemistry 

Under alkaline (high pH) conditions, aluminum sulfate or aluminum chloride form colloidal 

aluminum hydroxide. In addition, free aluminum ions are highly flocculating to clay particles 

found in drilling fluid. The high viscosity produced by these salts is unacceptable for drilling 

operations. Consequently, a complex reaction with the aluminum ion is needed to reduce its 

tendency to precipitate. “Complex” is the general term used for this new structure. Aluminum 

salts that have been reacted to form complexes are stable in alkaline environments. The degree of 

stability depends upon the complex agent, the fluid pH, and time. ALPLEX is soluble in the form 

of an aluminate ion, Al(OH) 4¯, at pH levels above pH 10. ALPLEX becomes insoluble in the 

form of aluminum hydroxide, Al(OH) 3 , as pH decreases below pH 10. The pH of the connate 

water in shales is typically below pH 10, so the mechanism imparted by ALPLEX in plugging 

shale pores and micro fractures is driven by the change in pH from the drilling fluid and the 

formation. ALPLEX enters the pores and micro fractures in a soluble form, but then quickly 

forms an insoluble aluminum hydroxide precipitate (gel) with pH reduction in the shale matrix. 

Effectively, this precipitate acts as a barrier to prevent further fluid invasion (pore pressure 

increase) within the shale matrix. The concentration of ALPLEX must be measured using a 

Fluoride Selective Electrode (FSE) probe. Material (mass) balance CANNOT be used to 

accurately measure the ALPLEX concentration. 



Revised 2006 3-87


ALPLEX 

Overview 

ALPLEX is a dry aluminum complex, highly soluble in all water-base drilling fluids, designed to 

stabilize shales via a mechanism of reducing pore pressure transmission. Although some base 

exchange occurs, ALPLEX contains certain derivatives which are designed to form humic acid 

complexes that contribute to shale stabilization by complexation on basal hydroxides on the 

octahedral/tetrahedral sheets of formation clays (depending upon the clay type). The humic acid, 

by virtue of its chemistry will act as a dispersant and develops a needed low fluid viscosity 

without compromising the inhibitive/stabilization characteristics of the system. 

The main mechanism of shale stabilization is driven by the chemical interaction of the high pH 

filtrate with low pH connate (pores and fractures) water. This reduction of the mud filtrate pH 

will cause the aluminum hydroxide to precipitate in the shale pores and micro-fractures. Basically 

the tetrahydroxyl aluminate, Al(OH) 4¯, that is present in the higher pH filtrate of an ALPLEX 

system will precipitate into an insoluble aluminum hydroxides Al(OH) 3 when exposed to lower 

pH connate water. This crystalline form of aluminum hydroxide blocks the filtrate invasion 

(reduction in pore pressure transmission) into the shale pores and micro-fractures, thus enhancing 

the shale strength by preventing it from swelling and/or disintegrating. 

The alkalinity (pH) of the system should be managed using caustic soda, not ALPLEX. In 

freshwater systems, ALPLEX can be added directly through the mixing hopper. To increase its 

performance in salt water systems, the ALPLEX should be pre-solubilized in fresh water before 

adding it to the system. The pH of the freshwater should be increased to pH 10.5, using caustic 

soda, before adding ALPLEX to make the slurry. 

ALPLEX increases shale inhibition in all water-based mud systems using freshwater, seawater, 

sodium chloride and other salts. 

Application Guidelines 

Basic Formulation 

This basic formulation can be used in wells with bottom hole temperatures not exceeding 300°F. 

For higher BHT, special formulations may be required. 

Table 3-27 Basic Formulation for ALPLEX Systems 

Water 

Fresh to saturated NaCl 

MILGEL, lbm/bbl 5 - 15 

NEW-DRILL, lbm/bbl 1 - 3 

BIO-LOSE, lbm/bbl 2 - 3 

XAN-PLEX D, lbm/bbl 

As needed for desired yield point 

Caustic Soda, lbm/bbl As needed for pH 10.5 

ALPLEX, lbm/bbl 

1 - 6 depending on shale reactivity 

Mixing Procedure 


ALPLEX can be added directly to the circulating system through the hopper. To achieve 

maximum effectiveness, the water should be treated for any possible hardness. 



3-88 Revised 2006



1. The seawater system should be pretreated with caustic soda and soda ash to precipitate 

any magnesium and calcium. The pH of seawater should reach pH 10.5, using caustic 

soda, to precipitate most of the magnesium. This will increase the performance of the 

PHPA and eliminate pH decreases due to magnesium. 

2. The ALPLEX should be mixed in fresh water (treated with caustic soda for pH 10.5) at a 

high concentration (80 to 120 lbm/bbl) in the slug or separate pit and then fed slowly to 

the active system (10 bbls/hour+ depending on the total circulating time). 

Note: 

Do not add ALPLEX directly to untreated seawater as it will not go into solution properly.. 

3. NEW-DRILL, MIL-PAC, or BIO-LOSE should be premixed in the pretreated brine water 

and sheared adequately to enhance the performance of the polymers and prevent any 

possible blinding of the shaker screens. 

4. MIL-GEL should be pre-hydrated in fresh water to ensure good filter cake quality prior to 

adding it to the seawater system. 

5. NEW-DRILL should be well sheared prior to drilling to minimize blinding over shaker 

screens. 

6. MIL-PAC LV (0.75 to 1.0 lbm/bbl) can be substituted for BIO-LOSE (2 to 3 lbm/bbl). 

7. XAN-PLEX should be used to increase yield point for better hole cleaning. 

8. Use the FSE probe to measure the excess ALPLEX concentration. 

Note: 

Due to its strong inhibition characteristics, the initial ALPLEX treatment will depend on the 

amount of solids in the initial fluid. In unweighted fluid (CEC < 10 meg/100 , less than 2% 

LGS) the initial ALPLEX treatment should be about 1 lbm/bbl. The desired ALPLEX 

concentration in the total system should be increased as drilling progresses. This measure 

will prevent a sharp drop in rheological properties. Use the FSE probe (not mass balance) 

to accurately determine the ALPLEX concentration. 

Treatment and Maintenance 

Maintenance of ALPLEX systems is generally dictated and directly proportional to the reactivity 

of the shale being drilled. The following are maintenance guidelines for an ALPLEX system. 

1. The pH of fluid should be maintained above 10.0 with small caustic soda or ALPLEX 

additions. The pH typically varies between 10 and 11.5 depending on the ALPLEX ® 

concentration. 

2. Although the ALPLEX system is solids tolerant, the low gravity solids should be 

maintained at less than 6%. 

3. Use XAN-PLEX for sweeps instead of MIL-GEL. 

4. Use caustic soda to raise the pH of ALPLEX fluids. 

5. In seawater or high salt ALPLEX systems, use premixed lignite in freshwater for 

additional filtration control. To avoid pH drop due to additional LIGCO (lignite), 

compensate with caustic soda using a 4:1 (lignite: caustic) ratio. 



Revised 2006 3-89


6. When the fluid system becomes depleted of ALPLEX ® , any or a combination of the 

following may be observed: 

• The pH of the fluid drops below pH 10.0. 

• The cuttings over the shakers will become soft and sticky. Blinding of the shaker 

screens may occur. 

• The fluid viscosity and rheological properties will generally increase. 

• Tight spots, excessive torque and drag, and bit balling may develop. 

Aluminum Determination by Fluoride Electrode 

Equipment and Reagents 

1. pH/mv Meter (Orion or instrument capable of using a fluoride electrode and having 

concentration mode capabilities) 

2. Combination Fluoride Electrode with BNC connector - Orion 9609BN (currently supplied 

with Ionplus A Optimum Results filling solution 

3. Reference Electrode Filling Solution - Orion Ionplus A Optimum Results filling solution ( 

Orion 900061) or IONALYZER reference electrode filling solution (Orion 900001) 

4. Plastic Pipette - 0.5 or 1.0 ml 

5. Plastic Beakers (2) - 150 ml 

6. Plastic Graduated Cylinder(2) - 50 ml 

7. Pipette (3 ml) or 10cc plastic syringe 

8. Potassium Fluoride Solution - 0.0010 M (10 Standard) 

Potassium Fluoride Solution - 0.010 M (100 Standard) 

9. Acetic Acid/Potassium Acetate Buffer 

Standards Preparation for Instrument Calibration 

Note: 

Graduated cylinders, beakers, and pipettes should be rinsed with distilled water and dried 

between each use. 

1. Place 30 ml of 0.0010 M(10 Standard) Potassium Fluoride solution into a plastic 

graduated cylinder. 

2. Pour the 30 ml of 0.0010 M Potassium Fluoride solution into a plastic beaker. 

3. Deliver by pipette or 10cc plastic syringe 3 ml of the Acetic Acid/Potassium Acetate 

Buffer into the plastic beaker of 0.0010 M Potassium Fluoride solution. 

4. Swirl the beaker contents to ensure proper mixing. Allow the solution to set for five 

minutes. 

5. Place 30 ml of 0.010 M (100 Standard) Potassium Fluoride solution into a plastic 




3-90 Revised 2006



7. Deliver by pipette or 10cc plastic syringe 3 ml of the Acetic Acid/Potassium Acetate 

Buffer into the plastic beaker of 0.010 M Potassium Fluoride. 

8. Swirl the beaker contents to ensure proper mixing. Allow the solution to set for five 

minutes. 

Instrument Calibration, Measuring, and Electrode Care: 

Electrode Preparation 

The electrode is shipped without filling solution in the reference chamber. To fill from the flipspout 

bottle: 

1. Lift the spout to a vertical position. 

2. Insert the spout into the filling hole in the outer sleeve and add a small amount of filling 

solution to the chamber. Tip the electrode to moisten the O-ring at the top and return 

electrode to a vertical position. 

3. Holding the electrode by the barrel with one hand, use the thumb to push down on the 

electrode cap, allowing a few drops of filling solution to drain to wet the inner cone. 

4. Release sleeve. If sleeve does not return to its original position immediately, check to see 

if the O-ring is moist enough and repeat steps 2-4 until the sleeve has returned to original 

position. Add filling solution up to the filling hole. 

5. The probe is now ready for use 

Add filling solution each day before using electrode. The filling solution level should be at least 

one inch above the level of sample in the beaker to ensure a proper flow rate. If the filling 

solution is less than one inch above the sample solution level, electrode potentials may be erratic. 

Calibration Procedure for Orion Model 720A 

1. Fasten the electrode into the appropriate jack on the meter. 

2. Turn the instrument on and wait approximately one minute. 

3. Press [1ST] and then press [MODE]. Continue to press [MODE] until the LCD reads 

“CON” (concentration). 

4. Press [1ST], then press [CALIBRATE]. The instrument will display time, date, year, and 

when last calibrated. The instrument will then display the number of calibrators be used. 

5. Place probe in the 0.0010 (10) standard solution. 

6. Enter the # of calibrators to be used, in this case 2 , then press [YES]. The instrument will 

start to measure the concentration. A minute will elapse and the instrument will display 

“ENTER CONCENTRATION”. Enter (10) and press [YES]. 

7. Remove probe from the 0.0010 standard solution. Rinse the probe with distilled water and 

blot with a paper towel. DO NOT WIPE PROBE! 

8. Place probe in the 0.010 (100) standard. After 1 minute, the instrument will display 

“ENTER CONCENTRATION”. Enter (100) and press [YES]. 

9. The instrument will start to show several displays. Monitor the mv reading. It should 

be within the range of 55-60. (If the mv reading falls outside this range, the electrode 

should be replaced.) 



Revised 2006 3-91


The instrument is now calibrated and you are ready to proceed with the analysis of your sample. 


1. Connect electrode to meter. 

2. Press (power) key to turn on meter. 

3. Press the (mode) key until the CONC mode indicator is displayed. 

4. Place the Fluoride Selective Electrode into the 10 standard. 

5. Press (2nd cal). CALIBRATE and the time and date of the last calibration will be 

displayed. After a few seconds P1 will be displayed indicating the meter is ready for the 

first standard. 

6. When the reading is stable use the scroll keys to enter the value of the standard. To enter 

a value, press the ∧ or ∨ key. The value will flash. Press the key again and the decimal 

point will. flash. Position the decimal then press (yes). {Standard value is 10} Continue 

for each digit on the display. There are 4 1/2 digits plus a polarity sign and decimal point. 

The display will freeze for three seconds then P2 will be displayed in the lower field. 

7. Rinse electrode and place into second standard. When the reading is stable enter the value 

of the second standard {100} using the ∧ or ∨ and (yes) keys. The reading will freeze for 

three seconds then P3 will be displayed. 

8. Press (measure). The electrode slope will be displayed for a few seconds then the meter 

will advance to MEASURE mode. 

9. Rinse electrode and place into sample. Wait for a stable reading, then record fluoride 

concentration directly from the main meter display. Record ALPLEX concentration from 

the Fluoride electrode correlation chart. 

Sample Preparation for Analysis 

1. Place 30 ml of 0.010 M (100 Standard) into a plastic graduated cylinder. 

2. Transfer the 30 ml of solution to a plastic beaker. 

3. With a plastic pipette, add 0.5 ml of sample (mud filtrate) to the beaker and swirl the 

contents to ensure proper mixing. 

4. With 3ml pipette or 10cc syringe, add 3 ml of Acetic Acid/Potassium Acetate Buffer to 

the beaker. 

5. Swirl the solution to ensure proper mixing. 

ALLOW THE SOLUTION TO SIT FOR 5 MINUTES PRIOR TO TESTING. 

* Repeat steps 1-5 for each sample analysis. 

Sample Analysis 

1. Rinse the electrode with distilled water between each analysis. 

2. Blot probe dry, do not wipe dry. 

3. Prepare samples as previously described in “D” above. Place the electrode in the sample 

and record sample readings after 1 minute. 

4. Check calibration every 4 hours by analyzing the 100 standard. 



3-92 Revised 2006


5. Rinse electrode with distilled water and blot dry between each test. 

Note: 

Should your concentration readings be greater than 100, you may have forgotten to add 

buffer.. 

Table 3-28 

Fluoride Electrode Correlation Chart 

12 

10 

Fresh Water Mud 

ALPLEX, ppb 

8 

6 

4 

2 

Saturated Salt Mud 

0 

0 10 20 30 40 50 60 70 80 90 100 

Fluoride Electrode Reading 

Saturated Salt Curve Should Be Used When NaCl Concentration >18% 

Example 

1. Fresh water mud system is being 

2. 0.5 ml of sample is 

3. Concentration reading is equal to 47 

4. Residual Alplex concentration is equal to 6 

PERFORMAX SM – High Performance Water Base Mud 

Introduction 

The introduction of cloud point glycols (AQUA-DRILL), aluminum complexes (ALPLEX) and 

finally sealing polymers (MAX-SHIELD and PERFORMAX) by Baker Hughes Drilling Fluids 

has greatly improved the osmotic effectiveness of water-based drilling fluids. Recent laboratory 

tests have demonstrated that some polymer emulsions exhibit a synergic effect with aluminum 

complexes, resulting in improved Pore Pressure Transmission (PPT) performance. 

Drilling shales can result in a variety of problems from washout to complete hole collapse. Shales 

make up over 75% of drilled formations and over 70-90% of borehole problems are related to 

shale instability. Traditionally, oil-based muds (OBM) are the preferred choice for drilling 

argillaceous formations. Their application has been justified on the basis of borehole stability, 

penetration rate, filtration control, filter cake quality, lubricity, and temperature stability. As 

environmental regulations have restricted the use of diesel and mineral oil-based muds, synthetic 

and ester-based biodegradable invert emulsion drilling fluids were introduced in the 90’s. 



Revised 2006 3-93


However, the costs associated with the use of environmentally acceptable, invert emulsions 

drilling fluid systems limit the application of such systems. 

Water-based muds (WBM) are attractive replacements from both cost and environmental 

perspectives. However, conventional WBM systems have failed to meet key performance criteria 

obtained with OBM in terms of rate of penetration, bit and stabilizer balling, lubricity, filter cake 

quality, and thermal stability. Past efforts to develop improved WBM for shale drilling have been 

hampered by a limited understanding of the drilling fluid/shale interaction phenomenon. Recent 

studies of fluid-shale interactions, however, have produced fresh insights into the underlying 

causes of borehole instability. Experimental evidence reported by many researchers has shown 

that the chemical potential driving force, created from the activity difference between the drilling 

fluid and shale, can counteract the hydraulic driving force (the difference between the mud 

weight and pore pressure). A theoretical relationship, based on fundamental thermodynamic 

principles, has been postulated to support the experimental observations that osmotic pressure 

acts as a negative hydraulic pressure in its influence on water movement. 

Overview of the PERFORMAX System 

PERFORMAX is Baker Hughes Drilling Fluid’s 

3 rd generation high-performance water-base 

drilling fluid that is designed to emulate 

performance characteristics previously achieved 

only with emulsion based drilling fluids. These 

attributes include shale inhibition (reduced pore 

pressure transmission), cuttings integrity, high 

rates-of-penetration, and reduced torque and drag. 

Two features of PERFORMAXthat contribute to 

wellbore stability are: 1) ultra-fine, deformable 

sealing polymer particles in MAX-SHIELD 

(diameter: ~ 0.2 µ) that mechanically seal shale 

micro-fractures, which physically block further 

intrusion of drilling fluid filtrate into the shale 

matrix; and 2) the resin and aluminum complexes 

in MAX-PLEX, in combination with MAX- 

SHIELD, produce a semi-permeable membrane at 

the shale surface and chemically improve the 

osmotic efficiency, and reduce pressure 

transmission into shales. 

Pore pressure transmission tests clearly show that 

MAX-SHIELD effectively works in combination 

with MAX-PLEX to achieve pore pressure 

transmission characteristics previously achieved only with emulsion-based drilling fluids (oilbased 

or synthetic-based). 



3-94 Revised 2006


PERFORMAX System Applications 

Density: 

Tested to a maximum density of 16lbm/gal (1.92 s.g.) 

Salinity: Tested to a maximum temperature of 300°F (149° C) 

PERFORMAX fluids are compatible with sodium chloride concentrations up to saturation or 

potassium chloride up to 10% by weight. Sodium and Potassium Formate salts are also 

compatible. 

PRODUCT 

MAX-SHIELD 

MAX-PLEX 

NEW-DRILL ® 

MAX-GUARD 

XAN-PLEX ® D 

PENETREX ® 

MIL-PACLV 

MAX-TROL 

Table 3-29 

PERFORMAX System Products and Functions 

FUNCTION 

Sealing polymer utilized to generate semi-permeable membrane for shale stabilization. 

Secondary function is as bridging material in pore throats of depleted sands to eliminate 

differential sticking and lost circulation. 

Aluminum and resin complex that works in combination with MAX-SHIELD to 

generate semi-permeable membrane and improve well stability. 

Cuttings encapsulation and improve cuttings integrity 

Amine-based material for suppressing the hydration and swelling of reactive clays and 

gumbo. 

A high-molecular-weight xanthan gum polysaccharide that includes an enhanced 

dispersibility feature used as an effective viscosifier in most waters regardless of salinity 

or hardness 

Reduce bit balling and increase rates-of-penetration 

Low-viscosity-grade PAC material to reduce API filtrate 

Sulfonated resin for HT-HP filtrate control 

PERFORMAX Mixing Procedures at Liquid Mud Plant (LMP) 

1. The use of a shearing device is recommended. 

2. Remove all trash, solids, etc. from the water- base mixing tank 

3. In a separate tank, add fresh water and treat hardness to < 200 mg/L with soda ash. 

4. Pre-hydrate MILGEL ® at a concentration of 30 lbm/bbl with a sufficient volume of water 

to achieve a concentration 3 lbm/bbl in the final mix. For example, if the total volume of 

finished mud needed is 2000 bbl. Multiply 2000 bbl by 3 lbm/bbl = 6000 lb. of gel. 

Divide 6000 lb. by 30 lbm/bbl = 200 bbl pre-hydrated gel required.) Allow gel to hydrate 

for a minimum of 3 hours after mixing. Adjust pH of mixture to 10.8 – 11.0 with 

caustic soda. 

5. Transfer calculated volume of pre-mixed gel to give 3 lbm/bbl in the final volume to the 

clean mixing tank. For example, if the final volume in mix tank = 300 bbl. 300 bbl. * 3 

lbm/bbl = 900 lb. 900 lb. / 30 lbm/bbl = 30 bbl pre-mix.) 



Revised 2006 3-95


If mixing mud system with sacked NaCl, add calculated amount of fresh water to mixing 

tank. 

6. Add the recommended concentrations of products in the following order: 

• XAN-PLEX D 

• NEW-DRILL 

• MIL-PAC LV 

• MAX-SHIELD 

• MAX-GUARD 

• NaCl – continue shearing until salt is dissolved 

• Weighting agent 

• Adjust pH to 10.0 – 10.5 with caustic soda 

If using saturated NaCl brine follow above directions to Step #5, then: 

7. Add sufficient fresh water to pre-hydrate XAN-PLEX D, NEW-DRILL PLUS, MIL-PAC, 

and MAX-SHIELD. Allow chemicals to fully hydrate and solubilize. 

8. Add calculated amount of saturated NaCl brine. Check brine for Total Hardness and 

treat as necessary to reduce hardness 

9. Add NaCl to return salt concentration to 20% by wt. 

10. Add MIL-BAR or other weighting agent. 

11. Adjust pH to 10.0 – 10.5 with caustic soda 

Note: Do not add MAX-PLEX at the mud plant because it will deplete during transport. 

MAX-PLEX should be added in pre-hydrated form prior to or during the 

displacement. 

To prevent “fish eyes”, avoid rapid mixing of polymers unless a high-quality shear device is 

used. The mud should be blended in the mix tank until homogenous. 

If mud tests are required by the operator, take samples and add MAX-PLEX before testing. 

Premix Recommendations 

The use of pre-mix is recommended to assure solubility and hydration of polymer and other 

water-soluble components. Below are recommendations for pre-mixes with the PERFORMAX 

System. 

• In seawater or high-salt systems, MAX-PLEX should be added to the active system as a premix 

at a concentration of 100 lbm/bbl. 

• MAX-PLEX can be added directly to the mud system ONLY when using freshwater (low 

chlorides & hardness) as the makeup water. 



3-96 Revised 2006


• The bentonite content (via MBT) of the system should be less than10 lbm/bbl before adding 

MAX-GUARD. If not, then clay flocculation will occur as this product reacts with the 

reactive clays in the system. This will also consume (deplete) the concentration of MAX- 

GUARD in the system and require that additional product be added to have excess material 

available when drilling begins. 

• NEW-DRILL LV, L or PLUS should be added at concentrations up to a 1.0 lbm/bbl in a 

freshwater premix, preferably using a shear device. Do not add NEW-DRILL products in 

pre-mix containing MAX-PLEX because prior work in field tests has indicated that blinding 

and loss of MAX-PLEX material over shaker screens is increased. 

• MILPAC LV can be added to the NEW-DRILL premix at concentrations up 1 lbm/bbl. 

Seawater Systems 

Seawater should be pretreated with caustic soda and soda ash to a pH of 10.5 and to precipitate 

calcium and magnesium. MAX-PLEX should never be added directly to untreated seawater 

because elements in seawater will react with and delete an important component of MAX-PLEX. 


pH 

Deflocculants 

Hardness levels 

The minimum pH for PERFORMAX is pH 10.5. If the pH falls below this level, 

then excessive depletion of MAX-PLEX will result. MAX-PLEX concentrations 

should be carefully monitored, using the FSE method, when adding products that 

cause pH to fall below minimum value. These include: LCM materials, 

lignosulfonates, and lignite. Treat system with caustic soda prior to addition of these 

materials to counter their pH-reduction effects. If PERFORMAX is subjected to 

temperatures above 230°F, then monitor flowline pH at one to two hour intervals to 

determine if pH reduction is occurring. 

Deflocculants such as ALL-TEMP® can be used to control rheological properties. 

However, such additives are acidic in nature and will reduce the pH of the system 

causing a depletion of MAX-PLEX concentration (see pH statement above), 

therefore treatment with caustic soda to adjust system pH to the proper level is 

recommended prior to the addition of MAX-PLEX. 

Soluble Ca+2 and Mg+2 will cause precipitation of a component in MAX-PLEX. 

Total hardness should be below 400 mg/L before MAX-PLEX is added to the 

system. Ideally, hardness will be below 100 mg/L. In some situations the presence 

of aluminum compounds can interfere with total hardness and calcium 

determinations. If indicator response is suspected, the use of a masking reagent 

(triethanolamine or tetraethylenepentamine) is recommended. 



Revised 2006 3-97



MAX-SHIELD Additions 

MAX-SHIELD Concentration 

MAX-PLEX Concentration 

MAX-GUARD 

Concentration 

Although PERFORMAX is tolerant to cement contamination; drilling cement may 

cause depletion of the MAX-PLEX . Citric acid is recommended as a treatment for 

cement contamination to maintain pH at 10.5 to 11.5. If the system is not displaced, 

hardness should be reduced below 400 mg/L with soda ash, and MAX-PLEX 

filtrate concentration should be checked by FSE. Increased MAX-PLEX treatments 

may be required in response to cement contamination. 

The particle size of MAX-SHIELD is very small and additions of MAX-SHIELD 

can cause a viscosity increase due the material effectively acting like a low gravity 

solid in the system. Always pilot test before adding MAX-SHIELD and other 

products to the system. Additionally, the rate that MAX-SHIELD is added to the 

system should be from 15 – 20 minutes per 55-gallon drum. The actual rate should 

be adjusted after pilot testing and monitoring viscosity as the material is added to the 

system. 

MAX-SHIELD should be maintained at 2% to 4% by volume at all times. The 

MAX-SHIELD concentration should be monitored at all times using the 

concentrations tracking program on ADVANTAGE Drilling Fluids reporting 

package. 

The MAX-PLEX concentration is measured by a fluoride selective electrode (FSE) 

method. The rate of MAX-PLEX depletion is related to drilling, dilution and 

formation consumption rates. Variables effecting the depletion of MAX-PLEX 

include: 1) rate of penetration, 2) hardness levels and 3) pH levels. 

MAX-GUARD is a liquid clay hydration suppressant that provides superior clay 

inhibition and low dilution rates. The recommended concentration of MAX- 

GUARD is 2 - 3% by volume, and will vary based on hole size, rates-of-penetration 

and reactivity of the formation being drilled. 

Handling recommendations for MAX-SHIELD 

• All MAX-SHIELD containers which have been opened should be added to the mud. 

Partially-full containers of MAX-SHIELD should not be returned to warehouse. 

• Containers of MAX-SHIELD should not be exposed to extremely cold temperatures or 

allowed to freeze. 

pH Level Recommendation: The pH should be maintained, using caustic soda (NaOH) at 10.6 

to 11.3 at all times, while the optimal pH is 11.0. The pH should be monitored at the flowline 

frequently, particularly when drilling at high rates-of-penetration or when adding products that 

reduce pH and/or deplete MAX-PLEX. The pH electrode should be calibrated with buffers at pH 

7.0, 10.0 and 12.5. Measurement of mud pH should be performed on a 50/50 dilution of whole 

mud with de-ionized water or whole mud using a high salinity electrode. 

Recommended Lubricant: TEQ-LUBE and MIL-LUBE are recommended lubricants for this 

system. Recommended treatment is 2 to 3% by volume. If other lubricants are to be used, pilot 

tests should be conducted before the product is added to the mud system. In general, water 

soluble products will be more compatible with PERFORMAX. 

Acid Gases: Lime or gypsum additions, in combination caustic soda, can be used to treat carbon 

dioxide contamination. Be sure to check the concentration of MAX-PLEX in the system 

whenever treating with lime or gypsum, since these products deplete the aluminum component in 

MAX-PLEX. Gypsum may also cause some flocculation of the fluid, but this can be corrected 

with treatments of 0.5 to 2 lbm/bbl of ALL-TEMP. 

MIL-GARD may be used for hydrogen sulfide intrusion. 

The PERFORMAX system may be prepared for various applications with salinity as high as 

saturation for compatible salts. Actual formulations can be adjusted to meet specifications for 



3-98 Revised 2006


density, salinity, and temperature applications. Laboratory pilot tests should be prepared 

following the order of addition and mixing times. 

Table 3-30 

PERFORMAX System Products and Concentrations 

Component Concentration Function and Description 

Fresh water or Sea water* ⎯ ⎯ 

Caustic Soda 0 – 1 lbm/bbl As required for pH control 

Soda Ash 0-.5 lbm/bbl to treat seawater Removal of soluble calcium 

XAN-PLEXD 0.2 – 0.5 lbm/bbl Viscosifier 

MILGEL ® NT 

5 – 10 lbm/bbl Viscosifier for > 250°F 

3 - 8 lbm/bbl New volume at liquid mud plant 

NEW-DRILL ® LV 0.3 – 1 lbm/bbl Cuttings Encapsulate 

MAX-SHIELD 2 – 4 % by volume Shale inhibitor 

MAX-PLEX 4 – 8 lbm/bbl Shale inhibitor 

MIL-PAC ® LV 0 – 2 lbm/bbl API Fluid loss control 

MAX-GUARD 2 – 3 % by volume Clay swelling inhibitor 

PENETREX ® 

By injection, up to 3% by 

ROP Enhancer 

volume 

NaCl 0 – 109 lbm/bbl Shale inhibitor 

MAX-TROL 0 – 8 lbm/bbl HTHP FL control at high salt 

MIL-BAR ® As required for density Weighting agent 

LD - S As required to control foaming Silicone Defoamer 

Contamination and High Temperature Aging 

Laboratory testing indicates that the PERFORMAX system remains stable after solids, cement, 

and carbon dioxide contamination. Aging at 300°F conducted on a low density seawater system 

showed excellent properties after aging. 

Product Compatibility 

TEQ-LUBE ® , MIL-LUBE ® and NF3 are recommended for increased lubricity and gas hydrate 

control, respectively. Although the PERFORMAX system is compatible with most standard 

products use in water-based mud system, some products are not compatible with this system and 

should not be used. PENETREX ® should be added at a steady rate (i.e. 0.25 – 0.5 GPM) with an 

injection pump while drilling and sliding. The goal is to add the PENETREX continuously so that 

there is always a small amount of the product exiting the bit. 

Return Permeability Testing 

PERFORMAX fluids have been tested for return permeability using LVT 200 mineral oil on a 

Berea Sandstone core. Return permeability was greater than 90 percent for the 12 lb/gal fluid 

shown below. However, until reservoir characteristics of the PERFORMAX system are better 

understood, this drilling fluid system should be used for cased hole completions only. If an open 

hole completion is anticipated, PERFORMAX should be displaced with a PERFFLOW ® system. 



Revised 2006 3-99


Table 3-31 

Component 

Return permeability on Berea Sandstone for 20% NaCl, 12 lb/gal 

PERFORMAX 

Concentration 

NaOH, lbm/bbl 0.4 

NEW-DRILL ® PLUS, lbm/bbl 0.4 

XAN-PLEX ® D, lbm/bbl 0.5 

BIO-LOSE ® , lbm/bbl 2 

MAX-TROL , lbm/bbl 8 

MAX-PLEX , lbm/bbl 6 

MAX-SHIELD , volume % 3 

ALL-TEMP ® , lbm/bbl 1 

NaCl, lbm/bbl 61 

MIL-BAR ® , lbm/bbl 146 

MAX-PLEX in API filtrate, cm 3 /30 min 3.5 

% Return permeability, 200°F, 500 psi 97 

MAX-PLEX or ALPLEX ® Determination by Fluoride Electrode 

The concentration of MAX-PLEX in the filtrate can be determined by using a fluoride selective 

electrode procedure. This method indirectly determines the MAX-PLEX concentration by 

converting aluminate to aluminum cations, 

which then react with fluoride anions to produce 

a mixture of aluminum fluoride species. The 

fluoride ion excess is correlated to the available 

MAX-PLEX concentration by means of a chart. 

An FSE probe must be used to accurately 

determine the “actual” concentration of MAX- 

PLEX in the system because the material is 

depleted (consumed) during drilling. The graph 

to the right shows a comparison of MAX-PLEX 

concentration using a mass balance vs. FSE 

method of determining the available 

concentration of MAX-PLEX in the system. 

This example clearly shows that the “actual” concentration of available aluminate in MAX-PLEX 

(or ALPLEX) cannot be accurately determined using a mass balance approach to determine 

product concentration. The only accurate method to determine available MAX-PLEX (ALPLEX) 

is to use the FSE probe. 



3-100 Revised 2006


Equipment and Reagents 

1. pH/mv Meter (Orion or instrument capable of using a fluoride electrode and 

having concentration mode capabilities) 

2. Combination Fluoride Electrode with BNC connector - Orion 9609BN (currently 

supplied with Ion plus A Optimum Results filling solution 

3. Reference Electrode Filling Solution - Orion Ion plus A Optimum Results filling 

solution (Orion 900061) or IONALYZER reference electrode filling solution 

(Orion 900001) 

4. Plastic Pipette - 0.5 ml 

5. Plastic Beakers (2) - 150 ml 

6. Plastic Graduated Cylinder(2) - 50 ml 

7. Pipette (3 ml) or 10cc plastic syringe 



10. Acetic Acid/Potassium Acetate Buffer 

Standards Preparation for Instrument Calibration 

Note: 

Graduated cylinders, beakers, and pipettes should be rinsed with distilled water and dried 

between each use. 


2. Deliver by pipette or 10cc plastic syringe 3 ml of the Acetic Acid/Potassium 

Acetate Buffer into the plastic beaker of 0.0010 M Potassium Fluoride solution. 

3. Swirl the beaker contents to ensure proper mixing. Allow the solution to sit for 

five minutes. 

4. Place 30 ml of 0.010 M (100 Standard) Potassium Fluoride solution into a plastic 



6. Deliver by pipette or 10cc plastic syringe 3 ml of the Acetic Acid/Potassium 

Acetate Buffer into the plastic beaker of 0.010 M Potassium Fluoride. 

7. Swirl the beaker contents to ensure proper mixing. Allow the solution to sit for 

five minutes. 

Instrument Calibration, Measuring, and Electrode Care 

Electrode Preparation 

The electrode is shipped without filling solution in the reference chamber. To fill from the flipspout 

bottle: 



Revised 2006 3-101


1. Lift the spout to a vertical position. 

2. Insert the spout into the filling hole in the outer sleeve and add a small amount of 

filling solution to the chamber. Tip the electrode to moisten the O-ring at the top 

and return electrode to a vertical position. 

3. Holding the electrode by the barrel with one hand, use the thumb to push down on 

the electrode cap, allowing a few drops of filling solution to drain to wet the inner 

cone. 

4. Release sleeve. If sleeve does not return to its original position immediately, 

check to see if the O-ring is moist enough and repeat steps 2-4 until the sleeve has 

returned to original position. Add filling solution up to the filling hole. 

5. The probe is now ready for use. 

6. Add filling solution each day before using electrode. The filling solution level 

should be at least one inch above the level of sample in the beaker to ensure a 

proper flow rate. If the filling solution is less than one inch above the sample 

solution level, electrode potentials may be erratic. 


1. Connect electrode to meter. 

2. Press (power) key to turn on meter. 

3. Press the (mode) key until the CONC mode indicator is displayed. 

4. Place the fluoride selective electrode into the 10 standard. 

5. Press (2nd cal). CALIBRATE and the time and date of the last calibration will be 

displayed. After a few seconds P1 will be displayed indicating the meter is ready 

for the first standard. 

6. When the reading is stable use the scroll keys to enter the value of the standard. 

To enter a value, press the ∧ or ∨ key. The value will flash. Press the key again 

and the decimal point will. flash. Position the decimal then press (yes). {Standard 

value is 10} Continue for each digit on the display. There are 4 1/2 digits plus a 

polarity sign and decimal point. The display will freeze for three seconds then P2 

will be displayed in the lower field. 

7. Rinse electrode and place into second standard. When the reading is stable enter 

the value of the second standard {100} using the ∧ or ∨ and (yes) keys. The 

reading will freeze for three seconds then P3 will be displayed. 

8. Press (measure). The electrode slope will be displayed for a few seconds then the 

meter will advance to MEASURE mode. 

9. Rinse electrode and place into sample. Wait for a stable reading, then record 

fluoride concentration directly from the main meter display. Record MAX-PLEX 

concentration from the FLOURIDE ELECTRODE CORRELATION 

CHART. 

Sample Preparation for Analysis 

1. Place 30 ml of 0.010 M (100 Standard) into a plastic graduated cylinder. 

2. Transfer the 30 ml of solution to a plastic beaker. 



3-102 Revised 2006


3. With a plastic pipette, add 0.5 ml of sample (mud filtrate) to the beaker and swirl 

the contents to ensure proper mixing. If mud filtrate is going to be saved for future 

fluoride electrode testing the filtrate should be retained in a plastic container. The 

mud filtrate should never be stored in a glass container due to the tendency of the 

aluminum complex to adhere to the glass surface. 

4. With 3ml pipette or 10cc syringe, add 3 ml of acetic acid/potassium acetate buffer 

to the beaker. 

5. Swirl the solution to ensure proper mixing. 

Allow the solution to sit for 5 minutes prior to testing. 

Repeat steps 1-5 for each sample analysis. 

Sample Analysis 

1. Rinse the electrode with distilled water between each analysis. 

2. Blot probe dry, do not wipe dry. 

3. Prepare samples as previously described in “D” above. Place the electrode in the 

sample and record sample readings after 1 minute. 

4. Check calibration every 4 hours by analyzing the 100 standard. 

5. Rinse electrode with distilled water and blot dry between each test. 

Note: 

Should your concentration readings be greater than 100, you may HAVE FORGOTTEN to 

add buffer. 

Reinecke Salt Test Procedure for Residual MAX-GUARD in PERFORMAX Filtrates 

Equipment and Materials; 

1. Reinecke salt 

2. Volumetric flask – 100 ml 

3. Deionized water 

4. Pipettes 

5. Syringes (optional) 

6. Sample of MAX-GUARD 

Procedure 

1. Prepare a solution of the Reinecke Salt indicator solution by dissolving 

approximately 3% by weight of the Reinecke salt material into deionized water (or 

0.75 g per 24.25 ml water). Small amounts of the solution should be prepared 

since the shelf life is about 7–10 days at temperatures below 65°F. Shelf life 

decreases rapidly above this temperature. It is recommended to store the solution 

in a refrigerator, if possible, when not in use. (Please note: you will see some 

apparent insoluble materials at the bottom of the container; ignore). 

2. In a small vial or bottle, place about 2 ml water, 8 drops of Reinecke salt solution 

and 0.5 ml of the mud filtrate and shake. 



Revised 2006 3-103


3. If residual MAX-GUARD is present, a precipitate will be observed. A strong 

precipitate will indicate at least 1 lb/bbl excess. 

4. A standard solution of MAX-GUARD in water (at 1 or 2 lb/bbl) could be prepared 

and tested accordingly. This can give a visual indication of what to expect for the 

amount of precipitation and compare to the test filtrate results. 

Photographs of test results are described below 

Figure 3-23 Reinecke Salt Results 

PERFORMAX filtrate PERFORMAX filtrate: 

Tested with Reinecke Salt: 

positive results for residual MAX-GUARD 

Note: 

UV measurement of 0.8 lb/bbl residual for above filtrate. 



3-104 Revised 2006


References 

1. Annis, Max R., Jr., High Temperature Flow Properties of Water-Base Drilling 

Fluids, SPE Paper 1961, Fall Meeting of SPE, October 1, 1967. 

2. Ashton, M.P. and Elliot, G.P., Water-Based Glycol Drilling Muds: Shale Inhibition 

Mechanisms, SPE Paper 28818, 1994 Offshore European Conference, London, October 

25-27. 

3. Benaissa, Saddok and Clark, D. E., Aluminum Chemistry Provides Increased Shale 

Stability with Environmental Acceptability, SPE Paper 25321, SPE Asia Pacific Oil and 

Gas Conference, Singapore, February 8-10, 1993. 

4. Bland, R.G., Quality Criteria in Selecting Glycols as Alternatives to Oil-Based 

Drilling Systems, SPE Paper 27141, Second International Conference on Health, Safety, 

and Environment in Oil & Gas Exploration and Production, Jakarta, Indonesia, January 

25-27, 1994. 

5. Bland, R.G., Walker, N., Scank, V., and Henderson, P., Progress in Eliminating Oil- 

Based and Invert Emulsion Muds through Glycol Qualification, SPE Paper 35983, 

Conference on Health, Safety, and Environment, New Orleans, LA., June 12, 1996. 

6. Browning, W. C. and Perricone, A. C., Clay Chemistry and Drilling Fluids, 

Presented at The University of Texas Conference on Drilling and Rock Mechanics, 1963. 

7. Browning, W. C. and Perricone, A. C., Lignosulfonate Drilling Mud Conditioning 

Agents, AIME Presentation, October 1972. 

8. Clark, D. E. and Daniel, S., Protective Colloid System Improves Solids Removal 

Efficiency, Drilling Fluid Stability, and Drilling Performance, SPE/IADC Paper 16081, 

SPE/IADC Drilling Conference, New Orleans, Louisiana, March 15-18, 1987. 

9. Clark, Scheuerman, Rath, and Van Laar, Polyacrylamide/Potassium-Chloride Mud 

for Drilling Water Sensitive Shales, Journal of Petroleum Technology, June 1976. 

10. Chaney, P. and Sargent, T.L., Protective Colloid Muds Provide Cost-Effective 

Prevention of Wellbore Enlargement in the Gulf of Mexico, SPE Drilling Engineering, 

December 1986. 

11. Chaney, B. P. and Nelson, J., A Case History of a Trouble-Free, 20,000-ft Well: 

Teamwork Pays Off, SPE/IADC Paper 16089, SPE/IADC Drilling Conference, New 

Orleans, Louisiana, March 15-18, 1987. 

12. Chesser, B. G., Design Considerations for an Inhibitive and Stable Water-Based Mud 

System, SPE Paper 14757, IADC/SPE Drilling Conference, Dallas, Texas, February 10- 

12, 1986. 

13. Deily, Lindblom, Patton, and Holman, New Low Solids Polymer Mud Designed to 

Cut Well Costs, World Oil, July 1967. 

14. Enright, D.P., Dye, W.M., and Smith, F.M., An Environmentally Safe Water-Based 

Alternative to Oil Muds, SPE/IADC Paper 21937, 1991 SPE/IADC Drilling Conference, 

Amsterdam, March 11-14. 

15. Goins, W.C., A Study of Lime-Mud Systems, Oil and Gas Journal, January 19, 1950. 



Revised 2006 3-105


16. Halliday, W.S., Jones, T.A., and Sketcher, B. (Chevron), Polyglycol and Aluminum 

Chemistry Drilling Fluid Helps Operator Reach Projected Goals, SPE/IADC Paper 

25702, SPE/IADC Drilling Conference, Amsterdam, February 23-25, 1993. 

17. Jarrett, M.A., A New Polymer/Glycol Water-Based System for Stabilizing 

Troublesome Water-Sensitive Shales, SPE Paper 29545, SPE Production Symposium, 

Oklahoma City, April 2-4, 1995. 

18. Koenig, R. L., Polymer Mud vs. CLS-Lig in Normal Pressure Applications: South 

Texas, SPE Paper 15411, Annual Technical Conference and Exhibition of the Society of 

Petroleum Engineers, New Orleans, Louisiana, October 5-8, 1986. 

19. Lummus, J. L. and Field, L. J., Non-Dispersed Polymer Mud, Petroleum Engineer, 

March 1968. 

20. Reid, P.I. and Dolan, B., Mechanism of Shale Inhibition by Polyols in Water-Based 

Drilling Fluids, SPE Paper 28960, SPE Symposium on Oilfield Chemistry, San Antonio, 

Texas, February 14-17, 1995. 

21. Rogers, W. F., Composition and Properties of Oil Well Drilling Fluids, Third 

Edition. 

22. University of Texas, Department of Extension, Principles of Drilling Mud Control, 

Twelfth Edition. 

23. Pauling, Linus, College Chemistry, An Introductory Textbook of General Chemistry, 

Third Edition 



3-106 Revised 2006

Chapter 

Four 

Contamination of Water–Base Muds 

Contamination of 

Water–Base Muds

Chapter 4 


Contamination of Water Base Muds ..................................................................................................4-1 

Contaminant Overview ..................................................................................................................4-1 

Calcium / Magnesium Contamination........................................................................................4-2 

Cement Contamination...............................................................................................................4-3 

Anhydrite-Gypsum Contamination............................................................................................4-5 

Salt Contamination.....................................................................................................................4-6 

Carbonate / Bicarbonate Contamination ....................................................................................4-7 

Estimation of Concentration of Carbonates / Bicarbonates ...................................................4-8 

P f /M f Method..........................................................................................................................4-9 

P1 – P2 Method for Hydroxyl/Carbonate/Bicarbonate Determination. .................................4-9 

Garrett Gas Train Measurement (CO3= / HCO3¯)..............................................................4-10 

pH / Pf Method.....................................................................................................................4-10 

Equations..............................................................................................................................4-11 

Special Procedure for Low pH Fluids..................................................................................4-12 

Treatment of Carbonates ......................................................................................................4-12 

Carbon Dioxide (CO2).........................................................................................................4-13 

Hydrogen Sulfide (H2S) Contamination..................................................................................4-14 

Temperature Flocculation / Deterioration ................................................................................4-14 

Solids Contamination...............................................................................................................4-14 

Oil / Gas Contamination...........................................................................................................4-14 


Figure 4-1 Solution Species Present in Carbonate Systems as a Function of pH – 

Calculated for K 1 =3.5 x 10 -7 and K 2 = 6.0 x 10 -11 .....................................................4-7 

Figure 4-2 

Ions Present at Various pH Levels...........................................................................4-8 


Table 4-1 Comparisons of the Alkalinity Methods ..................................................................4-9 

Table 4-2 

P f /M f Alkalinity Ion Concentrations, mg/L..............................................................4-9 


Revised 2006 


i

Contamination of Water-Base Muds 

Chapter 4 

The composition and treatment of drilling fluids depends on the formation 

encountered or material added during drilling operations. Some of these materials 

under certain circumstances, along with formation cuttings, can be considered 

contaminants. This chapter summarizes the various chemical contaminants and 

describes methods of chemical control and removal of water-soluble 

contaminants. 

Contaminant Overview 

If large quantities of contaminants are encountered during drilling, certain factors must be taken 

into account depending on the contaminant, and the impact it has on the constituents of the 

drilling fluid resulting in a deviation from the desired fluid properties. These factors are 

considered individually in the following discussion of each type of contaminant. However, it 

should be noted that it is not unusual to experience more than one contaminant at a time, which 

requires an analytical approach to identify and rectify the contaminants. 

In general, a contaminant is anything that causes undesirable changes in fluid properties. Any of 

the liquid, chemical, or solid components of water-base fluids can become a contaminant in some 

given situation. 

Solids are by far the most prevalent contaminant. Commercial bentonite added in excess, drill 

cuttings, or barite may lead to unacceptable rheological and filtration properties and affect the 

drilling operation. Water or excess chemical treatment can lead to unacceptable fluid changes 

and cause unscheduled viscosifier additions. 

The contaminants of interest are those which require chemical treatment. Chemical treatments to 

remove these contaminants are possible for some and impossible for others. The important rule is 

that treatment must match the contaminant and result in a desired effect on the fluid. 

Some contaminants can be predicted and pretreated to control them. The predictable 

contaminants are cement, bad make-up water, massive salt, anhydrite formations, or gases such as 

hydrogen sulfide and carbon dioxide in areas where documentation shows a probable presence. 

These contaminants can be chemically removed in some cases before they can have an overall 

negative effect on the clays, organic deflocculants, and/or filtration additives. Pretreatment has 

advantages as long as it is not excessive and does not adversely affect fluid properties. Pretreating 

a fluid with sodium bicarbonate before drilling cement is one example. By the same 

token an over treatment of sodium bicarbonate as a pretreatment can also become a contaminant. 

Other contaminants are unpredictable and unexpected, such as those which result from small 

feed-ins with a gradual build-up of a contaminant. Predicting potential contamination problems 

while drilling an exploration well is difficult. The contaminant shows its effect by altering the 

properties of the system and, in part, is determined by the resultant properties. When 

deflocculants are slightly depleted, or after a long trip when the fluid is allowed to remain 

stagnant and subjected to elevated downhole temperatures, or after additional contaminant enters 

the system, changes become evident. It is always necessary to keep complete, accurate records of 



Revised 2006 4-1

Contamination of Water Based Fluids 

drilling fluid properties to see the gradual onset of contamination and avoid deterioration of an 

otherwise good system. 

Rig site oven testing provides necessary data for monitoring and treatment purposes. Before 

reviewing the types of chemical water fluid contaminants and their treatment, you may want to 

reread Chapter 3, Water Base Drilling Fluids, which contains some fundamental principles and 

basic definitions of water-base drilling fluid chemistry. 

Calcium / Magnesium Contamination 

The calcium and magnesium ions can be a major contaminant of water-base drilling fluids. Both 

are divalent cations which attack clay and high molecular weight polymers by the same 

mechanism. Calcium can enter the fluid as part of the make-up water or while drilling cement, 

anhydrite, or gypsum. Also, connate water from penetrated formation and saltwater flows often 

contain calcium ions and can become sources of calcium contamination. Magnesium can be 

found in make-up water, formation water, and in formations such as the carnolite salt of the 

Zechstein formations in the North Sea, and drilling operations in Saudi Arabia. In most sources of 

cationic contamination the contaminant is a mixture of cations and normally one is more 

dominate in concentration than the others. As in the case of the Zechstein formation it can vary 

from almost pure sodium chloride to predominately magnesium and potassium salts. 

Calcium contamination changes the nature of freshwater clay-based systems as shown by 

rheology and/or filtration control problems. The calcium ion tends to replace the sodium ions 

through Base-Exchange, which results in flocculation and aggregation of the clay particles. The 

bound layer of water between the clay platelets is also reduced, resulting in diminished hydration 

or swelling characteristics. 

The effects of calcium or magnesium contamination on deflocculated fluids include, 

• increased fluid loss values 

• increased yield values 

• increased gel strengths. 

The severity of calcium or magnesium contamination (the degree to which this contaminant will 

affect the fluid properties) will depend upon, 

• the amount of the contaminating ion 

• the amount, type, and distribution of solids 

• the type and quantity of drilling fluid additives present in the system. 

Calcium contamination originating from make-up water, formation water, or anhydrite is usually 

treated with soda ash (.093 lb m /bbl per 100 mg/L Ca ++ ) or sodium bicarbonate (0.0735 lb m /bbl per 

100 mg/L Ca ++ ). If the pH is below 10.0, the test specific to calcium should be employed (Betz 

indicator, NaOH, and triethanolamine solution) to insure magnesium is not present. 

Approximately 100 mg/L of Ca ++ should be left in the system to avoid over treatment. Excessive 

soda ash treatment results in excess soluble carbonates, which could lead to rheological and 

filtration control problems. 

Magnesium, most often encountered when seawater is used as make-up water, has a similar 

adverse effect on the fluid properties as does calcium. Magnesium can be precipitated with 

caustic soda as insoluble Mg(OH 2 ). Theoretically, one-half pound of caustic soda per barrel of 

fluid will precipitate approximately 430 mg/L of magnesium. Most of the magnesium ion will be 

precipitated when the pH is increased to the 10.0 pH range. Other sources of magnesium are 



4-2 Revised 2006


saltwater flows and field brines. Generally, dilution, additional filtrate control agents, 

deflocculants and caustic soda are required to restore the drilling fluid properties after magnesium 

contamination. 


In most drilling operations cement contamination occurs when the casing is cemented and cement 

plugs are drilled out. If the plug is drilled while it is still green, the severity of calcium 

contamination can be very high, as is the case when displacing should the cement return not be 

diverted before it communicates with the active system. The extent of contamination and its 

effect on fluid properties depends on solids content and type, concentration of deflocculants, 

concentration of pretreatment chemical, and the quantity of cement incorporated. 

Cement contains compounds of tri-calcium silicate, calcium silicate, and tri-calcium aluminate, 

all of which react with water to form large amounts of calcium hydroxide Ca(OH) 2 . It is the 

calcium hydroxide (lime hydrate) in solution that causes most of the difficulty associated with 

cement contamination. 

Lime in drilling fluids causes chemical reactions which can be detrimental to rheological and 

fluid loss properties. The presence of OH¯ ions increases the pH and the calcium ion affects clay 

characteristics. Significant pH increases could lead to a pH shock. Some polymers such as 

Xanthan gum or PHPA are sensitive to higher pH levels and their chemical state is altered if pH is 

too high. If cement contamination reaches a level where it is no longer practical to be treated out, 

the most contaminated fluid should be discarded. In extreme cases it may be necessary to 

displace the entire system or convert it to a calcium based fluid (lime mud). 

Freshwater, bentonitic systems will be flocculated by cement, resulting in increased rheology and 

fluid loss. The severity of flocculation depends upon the factors mentioned above. If cement 

contamination reaches a level where it is no longer practical to treat it out, dump the most 

contaminated fluid, displace the entire system out, or treat the system as a calcium-based fluid. 

To maintain a low-calcium drilling fluid, chemical treatment must be used to remove cement 

contamination. The aim of treatment is to control pH while removing calcium and excess lime 

from the system as an inert, insoluble calcium precipitate. 

Be aware that 100 lb of cement can potentially yield 79 lb of lime which is then available to react 

with the drilling fluid. The volume of one sack of cement (94 lb) in most cases is 1.1 cu ft when 

set. So, if you know the volume of cement drilled, you can make better predictions of the type of 

treatment. This can be done by assuming the maximum quantity of cement which could be put 

into the system from drilling the cement. For instance, if the diameter to be drilled is 8.5 in., each 

foot of hole contains 0.394 cu ft of cement, or 33.7 lb of cement, or 26.5 lb of lime. This is the 

maximum amount of lime that can be put into the system, assuming that all the cement drilled is 

incorporated. When cement is completely set, assume 10% is normally available for 

contamination. When cement is still soft (commonly referred to as “green” cement), as much as 

50% of the cement could be dispersed and available to react with the fluid. 

To chemically remove 100 mg/L of calcium originating from cement would require 

approximately 0.0735 lb m /bbl of bicarbonate of soda or 0.097 lb m / bbl of SAPP. Lignite 

(LIGCO ® ) will also react with lime to form a calcium salt of humic acid. Approximately 1 lb m /bbl 

of lime can be precipitated with 7 to 8 lb of lignite. Treatments in excess of this range are not 

recommended since calcium salts of humic acids may also create viscosity problems at higher 

concentrations. 

Excess lime can be estimated from the filtrate alkalinity ( P f ), fluid alkalinity (P m ), and volume 

fraction of water by retort analysis (F w ) by the following equation. 



Revised 2006 4-3


Excess lime, lb m /bbl = 0.26 (P m – F w P f ) 

Pretreating can present a problem, since it is difficult to predict the extent of contamination prior 

to drilling the cement. Overtreating with bicarbonate of soda or SAPP could be as detrimental to 

drilling fluid properties as cement contamination. Therefore, it is not advisable to pretreat with 

more than 0.5 to 0.75 lb m /bbl of bicarbonate of soda. Materials such as UNI-CAL ® and LIGCO 

are also suitable pretreating agents because they buffer the pH and aid in deflocculating the 

system. 

Consideration also should be given to low-gravity solids content prior to drilling cement since 

high clay solids content is a primary cause of flocculation when cement contamination occurs. 

This could be particularly evident in lightly treated or under-treated fluids or high-density fluids. 

Reduction of low specific gravity solids, if high, is recommended as a defense against severe 

flocculation. 

Because pH values are high when drilling cement, the quantity of calcium ion in solution may not 

exceed 200 to 400 mg/L. For this reason, much of the cement drilled remains as discrete particles 

and is available to replace the calcium that has been treated out of solution. High concentrations 

of excess lime may require many days to remove, particularly if mechanical solids removal 

devices, i.e., fine screen shakers, hydrocyclones, or centrifuges are not used. 

If cement contamination occurs immediately prior to well completion, it may be necessary to 

replace the fluid in the hole with an uncontaminated drilling fluid to serve as a packer fluid, 

should testing indicate a high temperature gellation problem. 

One approach to avoid over-treatment with bicarbonate of soda or SAPP is to treat only the 

soluble calcium ion on a circulation basis and treat the lime particles (cement) that subsequently 

go into solution on additional circulations. Generally, treatments should be discontinued when 

excess lime approaches the 0.3 to 0.5 lb m /bbl range. 

Sometimes, cement contamination is simply allowed to work its way out of the fluid over several 

days without “extra” chemical treatment. A well treated fluid could give enough protection 

against cement contamination and the often observed rheology and filtration control problems. 

Higher Ca ++ measurements, relatively high pH values, and relatively higher P m measurements 

could be carried for some time without rheology or filtration control problems with a well-treated 

fluid. 

Chemical removal of calcium ion with bicarbonate prevents further contamination, but may not 

eliminate the rheological problems caused to a dispersed system. It is usually necessary to treat 

with deflocculants, such as UNI-CAL, UNI-CAL CF, DESCO, or MIL-TEMP ® (or ALL- 

TEMP ® ) to obtain the desired rheological properties. Materials, such as CHEMTROL ® X, 

LIGCO, prehydrated MILGEL ® slurries containing UNI-CAL, CMC, or MIL-PAC TM LV could 

be used to bring filtration and filter cake characteristics back to the required levels. 

A significant problem that may occur as a result of cement contamination is high-temperature 

solidification. Since testing at ambient temperature might not identify this problem, tests which 

simulate downhole conditions should be run. The FANN Consistometer, FANN Model 70, and 

Chandler 7600 XHPHT Mud Viscometer simulate downhole temperature, shear, and pressure 

conditions, and should be used to support wellsite testing. These tests give an indication of 

solidification tendencies. To determine remedial treatments, it is recommended that pilot testing 

procedures include hot rolling and static aging testing when possible. Hot rolling and static aging 

testing more accurately simulate reactions which occur in the drilling fluid at elevated 

temperatures. 



4-4 Revised 2006


Oven testing of a fluid can be done at the wellsite and, on many wells, is considered standard 

operating procedure. Timely test results are the key for making quicker adjustments to the fluid. 

MIL-TEMP ® (or ALL-TEMP ® ) has been found to be an excellent product in cement 

contaminated drilling fluids to decrease the gel strength and high-temperature gelation properties. 

Generally, about 1 to 3 lb m /bbl of MIL-TEMP ® can correct the flow properties of a cement 

contaminated system. MIL-TEMP is a higher temperature application product and generally is 

not used for temperatures lower than 250°F to 300°F. 

Anhydrite-Gypsum Contamination 

Anhydrite and gypsum, both calcium sulfate compounds (CaSO 4 ), are sometimes encountered 

while drilling. Gypsum is calcium sulfate with water of crystallization (CaSO 4 +2H 2 0), while 

anhydrite is the anhydrous form of calcium sulfate (without water). Anhydrite may occur as thin 

stringers. In some areas, it occurs as massive beds ranging from 100 to 800+ feet thick. Anhydrite 

has also been associated with salt (stringers, inclusions, overhang, massive salt, etc.) and could 

signal potential salt contamination. 

Anhydrite contamination contributes calcium ions, which could result in flocculation. Unlike 

cement anhydrite does not cause a pH increase since it supplies a sulfate radical in lieu of an 

hydroxyl radical. The sulfate radical contributes to flocculation of clay solids only marginally. 

In lightly treated fluids, small amounts of anhydrite increase the rheological properties of a fluid. 

The severity of change depends to a great degree on the bentonite content and solids particle size 

distribution. When anhydrite goes into solution and soluble calcium increases above 200 mg/L, 

viscosity may fluctuate noticeably and fluid loss could become more difficult to control. As 

anhydrite concentrations increase toward a maximum solubility of approximately 600 mg/L Ca ++ , 

a Base Exchange or change in bentonite characteristics occurs. Flow properties tend to decrease, 

and fluid loss becomes difficult to control. Conversion to a gypsum-based fluid has occurred. If a 

gypsum fluid is acceptable, then treatments should be made specifically for a gypsum fluid. 

When anhydrite contamination occurs, there are several methods for handling it. The drilling 

fluid can be maintained as a low-calcium fluid by chemically precipitating most of the calcium 

from solution, or it can be converted to a gypsum-type system. For smaller amounts of anhydrite 

contamination, chemical removal of calcium is best achieved by adding soda ash. Approximately 

0.093 lb m /bbl of soda ash is required to precipitate 100 mg/L of Ca ++ ion, but caution should be 

exercised to avoid over-treatment. When Ca ++ ions are reduced to 100 to 150 mg/L, consider 

stopping soda ash treatment. The reaction between anhydrite and soda ash is as follows. 

CaSO 4 + Na 2 CO 3 → CaCO 3 ↓ + Na 2 SO 4 

Remember, pilot testing should support treatment specific to anhydrite contamination. 

Soluble sodium sulfate is formed from this reaction and could cause flocculation problems with 

prolonged treatments. For this reason, it is sometimes necessary to convert to a gypsum-base fluid 

when massive anhydrite is to be drilled with a freshwater system. Over treatment with soda ash 

can also cause a carbonate problem. 



Revised 2006 4-5


Salt Contamination 

Salt contamination may be a result of make-up water, drilling salt stringers, inclusions, 

overhangs, massive salt, or saltwater flows. Where solid salt is drilled in large quantities or where 

economic considerations call for the use of salt make-up water, salt water-base drilling fluid 

systems are used. In these cases, salt is not a problem. However, in freshwater fluids, salt 

becomes a contaminant. 

Salt and saltwater flow contamination cannot be removed from a drilling fluid by economical 

chemical means. The harmful effect of salt on freshwater fluids is not so much the chemical 

reaction effect of the ions as it is the mass ion electrolytic effect which changes the charge 

distribution at the clay surfaces and promotes flocculation. The resulting flocculation causes an 

increase in rheological properties and fluid loss. With higher concentrations of UNI-CAL ® , 

rheological characteristics tend to remain stable if the solids are in range, although fluid loss may 

increase. 

As high concentrations of salt are encountered, the Na + and Cl¯ ions become more abundantly 

attached or congregate near the clay surfaces and, through “mass action,” gradually dehydrate the 

reactive solids in the fluid. The shrinkage effect on the clays may then cause decreased viscosity 

and continued increase in fluid loss. 

Since salt cannot be precipitated by economical chemical means, salt concentration can be 

reduced only by dilution with freshwater. 

The choice of reconditioning agents for salt contamination in freshwater fluids depends on the 

severity of contamination. Lightly treated UNI-CAL ® drilling fluid systems can usually tolerate 

up to a concentration of 10,000 mg/L salt as long as the colloidal reactive solids are at a 

reasonable level for the fluid weight being used. As the salt content increases above 10,000 mg/L, 

rheological and fluid loss properties become increasingly difficult to control. When higher salt 

content is expected or accidentally encountered, an increase in UNI-CAL ® is necessary. The 

alkalinity of the system should be slightly higher in salt-contaminated drilling fluids to allow 

better UNI-CAL ® solubility. 

Maintaining a salt system is much easier if all chemicals, i.e., deflocculants, filtration control 

additives, viscosifiers, etc. are presolubilized or prehydrated in a premix tank. When a saltwater 

flow is encountered, the high concentration of Na + ions tends to replace some of the H + and Ca ++ 

ions at the clay surfaces which slightly reduces the pH and may increase the soluble Ca ++ . 

Fluid loss is often difficult to control with salt contamination. Prehydrated bentonite and polymertype 

materials are helpful in this situation but should be added in moderation since they can 

increase rheological properties. 

Almost all saltwater flows contain some cations other than Na + . Calcium and/or magnesium are 

commonly present. Their effects have been previously discussed. 



4-6 Revised 2006


Carbonate / Bicarbonate Contamination 

Under some conditions, large amounts of soluble carbonates or bicarbonates can accumulate in 

drilling fluid systems. These ions can adversely affect fluid properties in much the same way as 

salt or calcium sulfate. Carbonates may come from over-treatment to remove calcium or cement 

contamination. Carbon dioxide gas could be present in certain formations drilled and the 

carbonates are formed as a result of the reaction of sodium hydroxide with carbon dioxide. 

CO 2 + 2NaOH →Na 2 CO 3 + H 2 ↑ 

At higher temperatures (≥ 300°F), organics such as lignosulfonate, lignites, etc. yield measurable 

carbonates which could create fluid problems if not addressed. Barite can also be a source of 

measurable carbonates. The specific ionic radical present in the mud is a function of pH as 

presented in Figure 4-1. 

Figure 4-1 

Solution Species Present in Carbonate Systems as a Function of pH – Calculated for 

K 1 =3.5 x 10 -7 and K 2 = 6.0 x 10 -11 

Rheological properties are adversely affected in two ways when alkalinity is altered by 

bicarbonates and carbonates. First, carbonate and bicarbonate anions in the presence of clays will 

cause increases in gel strength (more noticeable with the ten-minute reading) and yield point. 

Organic deflocculants such as UNI-CAL ® require hydroxyl ions to function properly. An influx 

of CO 2 will react with hydroxyl ions and take them out of solution so they are not available to 

react with UNI-CAL ® . Heavy carbonate and bicarbonate contamination creates a condition 

where P f , pH, and solids phase could appear to be in the desired range, yet viscosity and filtration 

values do not respond to treatment. Typically, an increasing trend in M f (5.0 cc N/50 H 2 SO 4 ) 

may result in high gel strengths which can be due to increasing carbonates and bicarbonates. 

Difficulty in controlling high-temperature/high-pressure (HT/HP) filtration is also quite evident. 

Gel strengths will not normally respond to dilution and UNI-CAL ® treatments unless an adequate 

amount of caustic soda has been added to maintain the P f . 

A second problem is caused by field test procedures in detection and remedial steps for carbonate 

and bicarbonate contamination. In water, the P f and M f values can be used to reasonably 

determine the quantities of hydroxyl ions and bicarbonate/carbonate anions. However, treated 

drilling fluids contain organic acids which function as buffering agents. This can cause the M f test 

procedure to show greater amounts of bicarbonate and carbonate than are actually present. 



Revised 2006 4-7


Therefore, M f values in excess of five (5) may be indicative of carbonate and bicarbonate anions 

or could be caused from a highly treated lignosulfonate/lignite fluid as well. 

Figure 4-2 

Ions Present at Various pH Levels 

11.4 

pH 

OH¯ 

or 

OH¯ and CO 3 

= 

Filtrate pH 

8.3 

OH¯ 

or 

OH¯ and CO 3 = 

or 

CO 3 = and HCO 3¯ 

P f 

ml 

0.02N 

H 2SO 4 

4.3 

HCO 3 ¯ and CO 2 

Interfering ions 

CO 2 

The common alkalinity producing ions which can be present at various pH levels are shown in 

Figure 4-2 in relation to the P f and M f alkalinities. 

Estimation of Concentration of Carbonates / Bicarbonates 

Treatment of carbonates/bicarbonates usually means lime or gypsum and caustic soda additions 

and requires a reasonably accurate measurement of CO = 3 /HCO – 3 ions. Over treatment with either 

lime or gypsum at a high temperature could lead to temperature flocculation or solidification. 

Therefore, caution should be exercised in most cases before treating a CO = 3 /HCO – 3 problem and 

treatment amounts should be supported with documented pilot testing. Before treatment can start, 

an estimation of the amounts of carbonates in the mud should be made. 

The API has standardized three methods for the measurement of carbonates in drilling fluids. 

The recommended method is the Garrett Gas Train (GGT) which is the only method of the three 

which directly measures carbonates. All other methods use alkalinity data to infer the 

concentration of carbonates and bicarbonates in the fluid. The GGT procedure is discussed 

briefly in this chapter and a complete description of the test is given in API Bulletin RP 13B-1. 

The other two methods are the traditional P f /M f titration and the P1/P2 titration. The P1/P2 

method was developed to overcome limitations in the P f /M f method which tends to greatly over 

estimate the bicarbonate concentration, particularly in highly buffered systems. The P1/P2 

titration uses barium chloride to precipitate barium carbonate. Because barium chloride is 

poisonous and because the titrations are very sensitive, caution must be exercised when the 

method is used. Figure 4-1 compares the advantages/disadvantages of the two methods. 

A fourth alternate mathematical model has been developed using the pH/P f relation to estimate 

probable carbonate/bicarbonate concentrations and is illustrated in this chapter. 



4-8 Revised 2006


Table 4-1 

Comparisons of the Alkalinity Methods 

P f /M f Method 

The P f /M f titrations were historically the first method used to calculate carbonate concentrations. 

As stated above it tends to be inaccurate because of the buffering of organic acids and dark 

colored filtrates which make determination of endpoints difficult. Some of the inaccuracy of the 

Mf endpoint can be eliminated by titrating using a properly calibrated pH meter but this will not 

eliminate the effects of the buffering agents in the mud. 

The calculations for using the P f /M f values to determine carbonate and bicarbonate concentrations 

are shown in Table 4-2. 

Table 4-2 

P f /M f Alkalinity Ion Concentrations, mg/L 

P1 – P2 Method for Hydroxyl/Carbonate/Bicarbonate Determination. 

This carbonate determination method is based on filtrate alkalinity. Two values are determined 

and designated P1 and P2. P1 is determined by using 1 ml of filtrate mixed with 14 ml of 

deionized water plus 2 ml of 0.1N sodium hydroxide in a titrating dish. The pH of the mixture 

should be greater than 11.4. If not then another 2 ml of 0.1 N sodium hydroxide is added. Now 2 

ml of barium chloride is added to the titrating dish and then 2 to 4 drops of phenolphthalein. This 

mixture is then titrated with 0.02N sulfuric acid to a pH of 8.3 or the Pf endpoint. The number of 

mls required to reach this end point is recorded as the P1 value. To obtain P2, repeat the 

procedure but with no filtrate. Once P1 and P2 values have been obtained calculate the values of 

carbonates with the equations below. 



Revised 2006 4-9


Note: 

Barium chloride in the smallest amount is lethal and extreme caution should be observed to 

avoid ingestion 

When P 1 > P 2 

When P 1 

OH 

CO 

− 

HCO 

( mg L) = 340× 

( P 1 

− P ) 

/ 

2 

= ( mg L) = 1200× 

( P − ( P − ) ) 

3 

/ 

1 1 

P2 

( mg L) = 1220× 

( P − ) 

− 

3 

/ 

2 

P1 

( mg / L) = 1200 Pf 

= 

CO × 

3 

Garrett Gas Train Measurement (CO3= / HCO3¯) 

The Garrett Gas Train (discussed in the Fluids Testing Procedures Manual and in API Bulletin 

13B-1) is the most accurate test to determine CO 3 

= 

/ HCO 3 – concentrations. The test procedure 

determines total carbonates and does not differentiate between CO 3 

= 

and HCO 3 – . The procedure 

utilizes acid (5N sulfuric) to reduce the CO 3 

= 

/ HCO 3 – to CO 2 gas in a known volume of filtrate. 

The gas is volumetrically passed through a Dräger Tube. A Dräger Tube is a sealed glass tube 

containing chemicals that react with specific classes of compounds. When the specific compound 

passes over the chemicals they stain or change colors. In the case of carbon dioxide dräger tubes 

they stain purple in the presence of CO 2 gas. Using the measured sample volume, the Dräger 

tube’s stain length and a tube factor, the total soluble carbonates can be determined as below. 

The GGT is also recommended for sulfide (via H 2 S) analysis. For CO 3 = / HCO 3 

– 

determination in 

mg/L and consequent treatment levels, measurement should be done on the fluid filtrate to show 

soluble CO 3 = /HCO 3 – . Measurement is sometimes done on the whole fluid, but this is not the 

preferred approach. 

CO 2 (mg/L) = tube stain length x tube factor / ml of filtrate sample 

If CO 3 = /HCO 3 – is considered a contaminant, limits are often set whenever measured with a 

Garrett Gas Train since it is considered more accurate. A range of acceptable CO 3 = /HCO 3 – values 

is often set at 1000 to 3000 mg/L and should be correlated with the other fluid properties. The 

Garrett Gas Train should be kept in good working order at all times to ensure accurate 

measurements. 

pH / Pf Method 

This technique was developed from a mathematical model of carbonate equilibrium and is a 

simple test that requires a minimum of time and equipment. Calculation of CO = 3 /HCO – 3 using 

the pH/P f model should be done on a routine basis in areas where a carbonate/bicarbonate 

problem is known to exist. However, it is not without margin of error and the results should only 

be used as a guideline within the total context of what is happening to the fluid, the hole, and the 

drilling operation. 

Steps should be taken to address a CO = – 

3 /HCO 3 problem situation in a reasonable time frame 

whenever the following occurs. 

Viscosity becomes difficult to control. 



4-10 Revised 2006


The ten-minute gel strength reading shows a progressively increasing tendency. 

Fluid loss and particularly the HT/HP increases unacceptably and is difficult to control. 

Mathematical modeling of fluid chemistry indicates CO = 3 /HCO – 3 . 

Oven tests show a fluid problem. 

Calculated values using the pH/P f method can reveal a trend or even a sudden occurrence of 

CO = 3 /HCO – 3 , but these values can only be used as a guideline and thorough pilot testing should 

be done. 

Requirements for the pH/P f method are: 

1. Accurate pH – The pH of the filtrate should be determined with a pH meter. The pH of the 

fluid can be used if filtrate volume is limited. 

2. Pf – Alkalinity of the filtrate. 

3. Water Fraction – Calculated for unweighted fluids and retort cook-off for weighted fluid. 

Equations 

1. Hydroxyl concentration in mg/L (OH) 

pH - 14 

OH¯ = 17,000 x 10 

2. Carbonate concentration in mg/L (CO 3 = ) 

CO 3 = = 1200 (P f – (OH / 340)) 

HCO = 

3 

CO 

3 

9.7 

10 pH 

Bicarbonate concentration in mg/L (HCO 3¯) 

Example calculation using pH/Pf method given the values for pH and Pf 

pH = 12.6 

Pf = 5.3 cc 

OH¯ = 677 mg/L 

(OH - = 17,000 x 10 pH – 14) 

= (17,000 x (1012.6 − 14) = (17,000 x (10 − 1.4) = (17,000 x 0.039810717) = 677 

mg/l 

CO3= = 3971 mg/L 

CO3= = 1200 (Pf – (OH / 340)) = 1200 (5.3 – (677 / 340)) = 1200 (5.3 – 1.9912) = 

1200 (3.309) = 3971 mg/l 

HCO3¯ = 5 mg/L 

HCO3– = (CO3=pH – 9.7) = (3971/10 12.6– 9.7) = (3971/10 2.9) = (3971/794.328) = 

5 mg/l 

Calculation of CO 3 = /HCO 3¯ using the pH/P f model should be done on a routine basis in areas 

where a carbonate/bicarbonate problem is known to exist. However, calculated values should be 

used within the total context of what is going on with the fluid, the hole, and the drilling 

operation. 



Revised 2006 4-11


Special Procedure for Low pH Fluids 

When the pH is below 9.0 to 9.5 it is difficult to accurately titrate the Pf value. Therefore, the 

method must be modified in those cases. The procedure is as follows. 

1. Increase the pH of a sample of filtrate to 11.5 using CAUSTIC SODA (NaOH) solution 

and a pH meter. The strength of the caustic soda solution will determine how much will 

be added. It is recommended that a known Normality solution be made up and used for 

this procedure. (Forty (40) grams of caustic in one (1) liter of water is a 1 Normal 

solution.) 

2. Titrate and determine the Pf value of this altered filtrate sample and calculate the mg/L of 

total carbonates from this Pf value by multiplying it by 1200. 

3. Calculate the bicarbonates and carbonates in the original filtrate from the equations: 

where, 

( Total Carbonates ) = P ( Altered pH ) × 1200 

Y 

f 

HCO 

− 

3 

Y 

1+ 

10 

( mg / L) = 

pH − 9. 7 

− 

( mg L) Y − 

= 

CO 

3 

/ HCO 

= 

3 

Y = total carbonates at 11.5 pH, 

pH = original filtrate pH. 

Example calculation using pH/Pf method when the pH is low. 

Original filtrate pH = 8.8 

Pf of altered filtrate (11.5 pH) = 5.0 cc 

1. Total Carbonates (Y) (both CO = 3 and HCO – 3 ) = 6,000 mg/L 

Y = Pf × 1200 = 5.0× 

1200 = 6000 mg / L 

Bicarbonates = 5329 mg/L 

Y 6000 6000 

2. HCO3 = = 

= 

= 5329mg 

/ L 

( pH − 9.7) 

(8.8 − 9.7) 

1+ 

10 1+ 

10 1+ 

0.125892541 

Carbonates = 671 mg/L 

3. CO = Y − HCO = 6000−5329 

671mg 

/ L 

3 3 

= 

Treatment of Carbonates 

Removing carbonates from a mud involves adding some form of soluble calcium. Lime or 

gypsum is the most common products used to provide this source. Calcium will precipitate the 

carbonates as calcium carbonate, CaCO 3 . If the carbonates are in the HCO − 3 form they must be 

converted to the CO = 3 form before they will precipitate. This means that some form of hydroxyl 

must be present. This can come from lime (Ca(OH) 2 )or caustic soda (NaOH). In general, for low 

pH muds, lime is used to treat out bicarbonates, and for higher pH muds a combination of 



4-12 Revised 2006


treatments is used to prevent excessive pH increases. The treatment amounts given below are 

based on exact chemical reactions. In the field these chemical reactions may not be exact and 

may take time. Use these treatment amounts as guidelines and verify with accurate pilot testing. 

1. For pH’s less than 10.0 (over 50% of the carbonates are HCO3¯) use lime to treat only 

bicarbonates: 

0.00043 lbs of lime per mg/L of HCO 3¯ 

2. For pH’s above 10.0 or to maintain a constant pH while treating out carbonates: 

0.00022 lbs of lime per mg/L of HCO 3¯ 

0.001 lbs of gypsum per mg/L of CO 3 = and ½ of the mg/L of HCO 3¯ 

3. To use gypsum and caustic: 

0.00023 lbs of caustic per mg/L of HCO 3 

– 

0.001 lbs of gypsum per mg/L of HCO 3 − and CO 3 

= 

The following guidelines are recommended for treatment of carbonates: 

• Determine the amount of carbonates to treat carefully. Use more than one calculation method 

if possible; 

• pilot test; 

• when adding lime and gypsum add slowly to allow the chemical reaction to take place; 

• add the calculated treatment over several circulations; 

• check the mud on each circulation bottoms up and re-calculate the carbonates; 

• lignosulfonate additions will keep pH from rising to undesirable levels and help control 

rheological increases. 

Carbon Dioxide (CO2) 

Natural gases can contain carbon dioxide with concentrations that range from small amounts to 

relatively high proportions. Much carbon dioxide is clearly of magmatic origin found in areas 

where vulcanism is common, with large proportions resulting from local igneous activity. 

Metamorphism of limestone can result in high concentrations also. Carbon dioxide is also 

produced by the oxidation of many organic substances and crude oils. 

In a water solution the carbon dioxide converts to carbonic acid. This carbonic acid lowers pH 

and can prove damaging to many polymers. At high concentrations of carbon dioxide the 

formation of excessive amounts of soluble carbonates occurs and often results in high viscosities, 

gel strengths, and HT/HP control problems. Often calcium hydroxide [Ca(OH) 2 ] is used to treat 

out those soluble carbonates with the potential result of scale formation. Nevertheless, calcium 

hydroxide remains the most common approach to neutralizing this acid. The measurement and 

treatment of carbonates and bicarbonates was discussed earlier in subsection 

Carbonate/Bicarbonate Contamination. 



Revised 2006 4-13


Hydrogen Sulfide (H2S) Contamination 

Hydrogen sulfide as a contaminant will be briefly discussed here since, in a practical sense, safety 

is the paramount issue in dealing with H 2 S. Certainly, H 2 S can have adverse effects on a drilling 

fluid, i.e., viscosity, filtration control, and fluid chemistry, but its detection at any level should be 

determined immediately and the safety issue addressed first. High pH fluids and H 2 S scavengers 

have proven effective in controlling H 2 S concentration even at very high concentrations. The 

Garrett Gas Train is necessary to accurately determine soluble sulfides. Chemical treatment 

should maintain flow properties and filtration properties as required. See Chapter 8, Corrosion, 

for guidelines to the treatment of H 2 S contamination. 

Temperature Flocculation / Deterioration 

Many water-base fluids have a temperature limit of ±300°F. This can often be exceeded with the 

addition of temperature stabilizing additives such as MIL-TEMP ® , ALL-TEMP ® , or 

CHEMTROL ® X, etc. In planning the fluid to be used in high temperatures, an estimation of 

bottom hole temperature (BHT) should be used to make sure temperature has a minimal effect on 

the fluid. 

If the following issues are not addressed: 

• treatment to address temperature stability 

• adequate control of type, distribution, and amount of low specific gravity solids 

• provision to counter contaminants as discussed above, 

A flocculated, thick fluid off bottom can result which can lead to hole or drilling problems. 

Hot rolling and static oven testing a fluid at estimated wellsite BHST should be used to 

supplement suction pit and flowline fluid checks to counter the effects of high temperatures. 

A fluid program that addresses wellbore temperatures at all times in a given well will help in 

preventing temperature flocculation and deterioration of a fluid. Knowing product temperature 

limits and how to apply products in high temperature environments is imperative. 

Solids Contamination 

Throughout this chapter on chemical contamination, severity of fluid contamination is predicated 

on amount, type, and particle size distribution of solids. Fluids with an unacceptable 

concentration of low specific gravity solids are more likely to have a severe reaction to chemical 

contaminants. Solids should be kept to a minimum at all times. Any complete fluids program 

should include recommendations for solids control equipment and mud dilution. Solids control is 

discussed in greater detail in Chapter 10, Mechanical Solids Control. 

Oil / Gas Contamination 

In elemental composition, crude oils are mainly carbon and hydrogen with lesser and varying 

proportions of oxygen, nitrogen, and sulfur. The hydrocarbons in crude oils are generally 

categorized as aromatics, naphthenes, and paraffins, but include various hybrids. The aromatics 

are generally referred to as unsaturated with six carbon atoms in each structural ring. Asphaltic 

type crudes contain asphaltenes and resins. Crude oils can contaminate a water-base drilling 

fluid, affecting density and possibly viscosity. With high concentrations of crude in a water-base 

fluid, approved disposal of that fluid could be the appropriate action to take. The fluid properties 



4-14 Revised 2006


when affected by excessive crude volumes should be corrected with necessary weight material for 

density and appropriate additives for adjusting viscosity to desired levels. 

Crude oil is always associated with natural gas, a mixture of gases that can contain both 

hydrocarbons and non-hydrocarbons. Methane is normally the principal hydrocarbon component 

of natural gas with smaller amounts of the paraffin series present, with some detection of benzene 

and several naphthenes. Natural gases can contain large amounts of carbon dioxide, nitrogen, and 

hydrogen sulfide as non-hydrocarbon. In some cases, helium and mercaptans have been detected. 

Nearly all natural gases contain water vapor from the connate or formation water. 

Subsurface hydrocarbons can exist in the gaseous state under certain conditions of pressure and 

temperature, but separate as a liquid at the surface. Such subsurface hydrocarbon gas existing as 

surface hydrocarbon liquid is referred to as condensate. Sometimes, natural gas accumulations are 

found in association with salt water rather than liquid hydrocarbon. Generally, the nonhydrocarbon 

gases can present problems for the drilling fluid. Both carbon dioxide and hydrogen 

sulfide are discussed in this chapter. 



Revised 2006 4-15

Chapter 

Five 

Oil/Synthetic Drilling Fluids 

Oil/Synthetic Drilling Fluids

Chapter 5 


Oil / Synthetic Fluids .................................................................................................................................5-1 

Introduction............................................................................................................................................5-1 

Advantages of Oil-Base Fluids ..........................................................................................................5-1 

Disadvantages of Oil-Base Fluids......................................................................................................5-3 

Oil-base fluid applications .....................................................................................................................5-5 

Oil-based fluid chemistry.......................................................................................................................5-7 

Fundamental Chemical Concepts.......................................................................................................5-7 

Fundamental Chemical Classes .........................................................................................................5-8 

Surface Tension ...............................................................................................................................5-11 

Emulsions.........................................................................................................................................5-12 

Surfactants........................................................................................................................................5-13 

Dispersions.......................................................................................................................................5-14 

General Colloidal Systems...............................................................................................................5-16 

Non-Aqueous external phase ...............................................................................................................5-17 

Base Oils ..........................................................................................................................................5-17 

Synthetics.........................................................................................................................................5-18 

Aqueous (internal) phase .....................................................................................................................5-19 

Aw and Osmosis ..............................................................................................................................5-19 

Emulsifiers ...........................................................................................................................................5-21 

Surfactants........................................................................................................................................5-21 

Soaps................................................................................................................................................5-21 

Fatty Acids.......................................................................................................................................5-22 

Anionic Emulsifiers .........................................................................................................................5-23 

Non-ionic Emulsifiers......................................................................................................................5-23 

Colloids................................................................................................................................................5-24 

Organophilic Clay............................................................................................................................5-24 

Polymers ..........................................................................................................................................5-25 

Asphalt / Gilsonite ...........................................................................................................................5-25 

Amine Lignite ..................................................................................................................................5-26 

Lime .................................................................................................................................................5-26 

Emulsion based drilling fluids .............................................................................................................5-26 


Revised 2006 


i


CARBO-DRILL Oil-Base Drilling Fluid System............................................................................5-26 

CARBO-FAST / CARBO-TEC®....................................................................................................5-26 

MAGMA-TEQ HTHP Non-Aqueous Drilling Fluid System ......................................................5-27 

SYNTERRASM Synthetic Base Drilling Fluid System ..................................................................5-28 

SYN-TEQ Synthetic Base Drilling Fluid System............................................................................5-29 

SYN-TEQ CF Synthetic Base Drilling Fluid System......................................................................5-29 

GEO-TEQ Synthetic Base Drilling Fluid System........................................................................5-29 

Product applications and recommendations.........................................................................................5-30 

CARBO-GEL ® .................................................................................................................................5-30 

CARBO-GEL ® II .............................................................................................................................5-31 

CARBO-MIX...............................................................................................................................5-31 

CARBO-MUL / CARBO-MUL ® HT ..............................................................................................5-32 

CARBO-TEC...................................................................................................................................5-33 

CARBO-TEC® HW ........................................................................................................................5-34 

CARBO-TEC® S.............................................................................................................................5-34 

CARBO-TROL®.............................................................................................................................5-35 

CARBO-TROL® HT.......................................................................................................................5-35 

CARBO-VIS .................................................................................................................................5-36 

CHEK-LOSS ® ..................................................................................................................................5-36 

CHEK-LOSS PLUS.........................................................................................................................5-37 

MAGMA-GEL ..............................................................................................................................5-37 

MAGMA-TROL ............................................................................................................................5-38 

MAGMA-VERT ...........................................................................................................................5-38 

OMNI-COTE ® .................................................................................................................................5-38 

OMNI-LUBE ...............................................................................................................................5-39 

OMNI-MIX..................................................................................................................................5-39 

OMNI-MUL.................................................................................................................................5-40 

OMNI-PLEX ®................................................................................................................................5-40 

OMNI-TEC®...................................................................................................................................5-41 

OMNI-TROL / CARBO-TROL® A-9 ........................................................................................5-42 

6-UP .............................................................................................................................................5-42 

Oil mud product safety and handling...................................................................................................5-43 

Field mixing procedures ..................................................................................................................5-43 

Special rig equipment and precautions ............................................................................................5-43 

Displacement procedures .................................................................................................................5-44 



ii Revised 2006


Solids control with oil mud..................................................................................................................5-46 

Solids ...............................................................................................................................................5-46 

Salts..................................................................................................................................................5-50 

Formulation Tables ..............................................................................................................................5-51 

CARBO-DRILL fluid formulation tables ........................................................................................5-51 

SYN-TEQ fluid formulation tables..................................................................................................5-59 

Salt tables.........................................................................................................................................5-63 

Typical formulation guidelines by BHDF location..........................................................................5-69 

Figure 5-1 


Structures of Primary Hydrocarbon Classes and Isomerized Olefin (Synthetic 

Base) ................................................................................................................................5-7 

Figure 5-2 Dipolar Hydrogen Chloride Molecule Showing Separation of Charge ...........................5-8 

Figure 5-3 

Figure 5-4 

Figure 5-5 

Figure 5-6 

Association of Liquid Water............................................................................................5-8 

Schematic Diagram of Hydrated Sodium and Chloride Ions.........................................5-10 

Sodium and Chloride Ions Surrounded by Water Molecule Dipoles.............................5-10 

Diagram of Attraction Forces in Liquids.......................................................................5-11 

Figure 5-7 Surface Tension Causing the Capillary Rise of Water in a Small Glass Tube ..............5-12 

Figure 5-8 

Figure 5-9 

Emulsions.......................................................................................................................5-13 

Surfactant Structure (Soap)............................................................................................5-13 

Figure 5-10 Orientation of Surfactants at an Interface ......................................................................5-14 

Figure 5-11 Dispersion of a Mineral Powder ....................................................................................5-14 

Figure 5-12 Liquids on Solid Surfaces ..............................................................................................5-15 

Figure 5-13 Oil Wetting ....................................................................................................................5-16 

Figure 5-14 

Figure 5-15 

Hydrated Sodium and Chloride Ions..............................................................................5-19 

Osmosis..........................................................................................................................5-20 

Figure 5-16 Semi-Permeable Membranes .........................................................................................5-21 

Figure 5-17 

Soap Formation..............................................................................................................5-22 

Figure 5-18 Oxidation of Fatty Acids during the Manufacture of Anionic Emulsifiers ...................5-23 

Figure 5-19 

General Polyamide Emulsifier Synthesis.......................................................................5-24 

Figure 5-20 Macrostructure of Asphalt .............................................................................................5-25 

Figure 5-21 Diagram of Costs vs. Mud Weight ................................................................................5-47 

Figure 5-22 Flow Diagram for a Low to Unweighted Oil Mud ........................................................5-48 

Figure 5-23 

Flow Diagram for a Weighted Oil Mud.........................................................................5-49 


Revised 2006 


iii


Figure 5-24 Flow Diagram for a Two-Stage Centrifuge for Medium to High Weight Oil Muds .....5-49 


Table 5-1 Common Acids ................................................................................................................5-9 

Table 5-2 Common Bases ................................................................................................................5-9 

Table 5-3 Base Fluid Properties .....................................................................................................5-18 

Table 5-4 

Table 5-5 

Properties of Synthetic Materials...................................................................................5-19 

Typical Physical Properties – CARBO-GEL.................................................................5-30 

Table 5-6 Typical Physical Properties – CARBO-GEL II .............................................................5-31 

Table 5-7 

Typical Physical Properties – CARBO-MIX.............................................................5-31 

Table 5-8 Typical Physical Properties – CARBO-MUL/CARBO-MUL HT ................................5-32 

Table 5-9 

Typical Physical Properties – CARBO-TEC.................................................................5-33 

Table 5-10 Typical Physical Properties – CARBO-TEC HW .........................................................5-34 

Table 5-11 

Typical Physical Properties – CARBO-TEC S..............................................................5-34 

Table 5-12 Typical Physical Properties – CARBO-TROL ..............................................................5-35 

Table 5-13 

Typical Physical Properties – CARBO-TROL HT........................................................5-35 

Table 5-14 Typical Physical Properties – CARBO-VIS ..............................................................5-36 

Table 5-15 

Table 5-16 

Typical Physical Properties – CHEK-LOSS..................................................................5-36 

Typical Physical Properties – CHEK-LOSS PLUS.......................................................5-37 

Table 5-17 Typical Physical Properties – MAGMA-TROL ........................................................5-38 

Table 5-18 Typical Physical Properties – OMNI-COTE .................................................................5-38 

Table 5-19 Typical Physical Properties – OMNI-LUBE .............................................................5-39 

Table 5-20 

Table 5-21 

Table 5-22 

Typical Physical Properties – OMNI-MIX................................................................5-39 

Typical Physical Properties – OMNI-MUL...............................................................5-40 

Typical Physical Properties – OMNI-PLEX..................................................................5-40 

Table 5-23 Typical Physical Properties – OMNI-TEC ....................................................................5-41 

Table 5-24 

Typical Physical Properties – OMNI-TROL / CARBO-TROL.................................5-42 

Table 5-25 Typical Physical Properties – 6-UP ...........................................................................5-42 

Table 5-26 

Table 5-27 

Table 5-28 

Troubleshooting Emulsion Fluid Systems.....................................................................5-45 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-TEC Oil Fluid: 

70/ 30 and 80/20 Oil/Water Ratios ................................................................................5-51 


85/15 Oil/Water Ratio....................................................................................................5-52 



iv Revised 2006


Table 5-29 

Table 5-30 

Table 5-31 

Table 5-32 

Table 5-33 

Table 5-34 


90/10 and 95/5 Oil/Water Ratios ...................................................................................5-53 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST ® Oil 

Fluid: 70/30 and 80/20 Oil/Water Ratios......................................................................5-54 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST Oil 

Fluid: 85/15 Oil/Water Ratio ........................................................................................5-55 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST Oil 

Fluid: 90/10 Oil/Water Ratio ........................................................................................5-56 

CARBO-DRILL Products Required to Build 100 bbl 50/50 and 55/45 Oil/Brine 

Ratios .............................................................................................................................5-57 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-CORE Oil 

Fluid...............................................................................................................................5-58 

Table 5-35 Products Required to Build 100 bbl of SYN-TEQ Fluid: 70/30 and 80/20 

Synthetic/Water Ratios (SWR)......................................................................................5-59 

Table 5-36 

Products required to build 100 bbl of SYN-TEQ Fluid: 85/15 Synthetic/Water 

Ratio (SWR) ..................................................................................................................5-60 

Table 5-37 Products Required to build 100 bbl of SYN-TEQ SM Fluid: 90/10 and 95/5 

Synthetic/Water Ratios (SWR)......................................................................................5-61 

Table 5-38 SYN-TEQ Products required to build 100 bbl of SYN-CORE SM Synthetic Fluid ........5-62 

Table 5-39 Properties of Calcium Chloride Solutions at 20°C ........................................................5-63 

Table 5-40 

Table 5-41 

Properties of Sodium Chloride Brines at 20°C..............................................................5-65 

Properties of Magnesium Chloride Solutions at 20°C...................................................5-67 

Table 5-42 Typical System Types, Formulations, and Product Usage ............................................5-69 


Revised 2006 


v

Oil / Synthetic Fluids 

Chapter 5 

Oil-base fluids, like other drilling fluids, must be properly applied to derive all the benefits 

associated with them. There are obvious advantages to using these systems; otherwise they 

would have ceased to exist in the industry. Likewise, there are disadvantages which limit oil 

fluids. In situations where oil-base fluids can not be used, synthetic fluids utilizing non-toxic, 

non-sheening olefin isomers are used. These synthetic-base systems are environmentallysafer 

alternatives to traditional oil-base systems. 

Introduction 

The advantages listed below frequently outweigh the disadvantages; oil- and synthetic-base fluids 

continue to be used in difficult drilling environments and in special applications. The fluids are most 

commonly prepared as emulsions of brine water in an appropriate oil- or synthetic-base fluid. 

In the past, the commonly used oils for drilling fluids were No. 2 diesel, and low-aromatic-content, 

low-toxicity mineral oils. Crude oil has been used; however, due to safety, health and environmental 

issues, its use is now rare. Baker Hughes Drilling Fluids (BHDF) CARBO-DRILL ® systems use 

diesel or mineral oil as the base fluid. 

The development of systems that use synthetic fluids as a replacement for diesel and mineral oil have 

eliminated many of the environmental, health and safety issues traditionally associated with oil-base 

drilling fluids. These synthetic-base fluids have found application in many offshore areas where the 

discharge of fluid and cuttings from traditional oil muds are restricted. The SYN-TEQ ® system, 

prepared from various environmentally friendly base fluids, is an effective and environmentally 

acceptable substitute for the CARBO-DRILL system. 

A brief summary of the ADVANTAGES and the DISADVANTAGES of oil-base (non-aqueous) 

drilling fluids follows. Unless specifically indicated otherwise, the information contained in this 

chapter applies to both oil and synthetic base fluids. 

Advantages of Oil-Base Fluids 

1. Shale Stability and Inhibition 

Properly conditioned oil-base fluid should have a minimal effect on any shale formation. With correct 

internal phase salinities, oil fluids provide gauge holes through water sensitive shales combined with 

long-term borehole stability. This is a true statement as long as tectonic stresses are not a factor. 

2. Temperature Stability 

Oil-base fluids have application in wells with high bottom-hole temperatures. Oil-base fluids have 

shown stability in wells with logged bottom-hole temperatures in excess of 550°F (288°C). 



Revised.2006 5-1


3. Lubricity 

Torque and drag problems related to deviated well-bore, crooked hole, and sidetracks can be reduced 

considerably with the use of oil-base fluids. The lubricating properties of an oil-base fluid are a result 

of the chemical nature of the oil-wetting surfactants and the inherent lubricity of the oil itself. 

4. Resistance to Chemical Contamination 

Carbonate, evaporite, and salt formations do not adversely affect the properties of an oil-base fluid. 

CO 2 and H 2 S can be easily removed with lime. 

5. Gauge Hole in Evaporite Formations 

When drilling salts, the internal (aqueous) phase of the oil-base system becomes saturated. However, 

as the formation salts saturate the internal phase, it is not uncommon for the internal phase to become 

super saturated with salt. This will result in the precipitation of excess salts. If calcium chloride is 

precipitated, this will affect the stability reading negatively, but more importantly, it can cause waterwetting 

of mud solids and de-stabilize the system. As a reminder, the electrical stability should only 

be run on screened samples to remove any insoluble salts prior to testing; otherwise a false reading of 

near zero will be recorded. 

6. Solids Tolerance 

Drill solids are inert in oil-base fluids and less dispersible other than from that resulting from 

mechanical shear; therefore the fluids have a much higher solids tolerance. The key to solids tolerance 

is less due to volume than it is to particle size and surface area of the solids. This is why oil-base 

systems are more tolerant of solids resulting in reduced dilution requirements for solids control. 

7. Reduced Production Damage 

Oil-base fluids normally have a low fluid loss and the filtrate from a stable mud is generally all oil. 

The filtrate penetration into the formation would be less than that of filter paper as the well-bore 

surface area increases incrementally with distance from the well-bore. The filtrate from an oil-mud 

invades only a short distance into the formation production zone and therefore minimizes damage. 

8. Reduced Tendency for Differential Sticking 

A thin, slick filter cake is formed when using an oil-base fluid, minimizing the chance of differential 

sticking. Note, however, that differential sticking is still possible if drilling highly overbalanced, 

especially with a high fluid loss system. 

9. Drilling Under balanced 

The wellbore stability resulting from the use of oil-base drilling fluids allows, in some instances, 

drilling with under balanced pressure, thereby increasing the rate of penetration (ROP). 

10. Re-Use 

The excellent stability and solids tolerance of a well-conditioned oil-base fluid allows its use in 

multiple wells. Although the initial make-up cost can be expensive, the re-use of oil-base fluids can 

actually result in less expense than water-base fluids since the ability to recondition for multiple 

applications exists. 

11. Reduced Cement Cost 

Gauge hole drilling can substantially reduce cement costs. This can be of benefit in two ways – (1) 

less cement is required; and (2) a more constant flow regime can be achieved resulting in less fluids 

contamination and a cleaner well-bore prior to cementing, thereby giving a better primary cement job. 



5-2 Revised 2006


12. High Penetration Rate 

The use of lower solids content oil-base drilling fluids, combined with the advent of polycrystalline 

diamond cutter (PDC) bits, has resulted in the ability to drill with high penetration rates throughout the 

world. The modification of drilling fluid properties and bit design allows for increased penetration 

rates in all type of shales, from soft gumbo to the older hard shales. 

13. Flexibility 

With the advent of both “relaxed” oil-base fluids and low toxicity oil-base fluids, any size hole, any 

environment, and any lithology, can be drilled with a specially tailored oil-base fluid. 

14. Reduction of Stress Fatigue 

Stress fatigue of tubulars is reduced considerably when using oil-base fluids, i.e. less tubular torque 

and corrosive attack from formation acid gases. 

15. Reduced Corrosion 

Oil fluids are not corrosive since oil, instead of water, is in contact with all tubulars. 

Disadvantages of Oil-Base Fluids 

1. High Initial Cost per Barrel 

Initial make-up costs can be high. A barrel of oil-base fluid has a high initial cost and maintenance 

costs can climb substantially depending on the environments encountered. These costs fluctuate with 

the price of the oil. 

2. Mechanical Shear Required 

To achieve the emulsion stability and viscosity required, mechanical shearing is necessary to form a 

tight emulsion and disperse the organophilic platelets. This can be accomplished by using a highpressure 

pump in conjunction with special shearing devices or shearing through the drill bit. 

3. Reduced Kick Detection Ability 

H 2 S, CO 2 , and hydrocarbon gases such as methane (CH 4 ) are all soluble in oil-base fluids. If gas 

enters the wellbore, it can go into solution under pressure and as the gas moves up the hole it can 

break out of solution and expand at a very rapid rate, thus emptying the surface well-bore and reducing 

the hydrostatic pressure allowing additional kicks to be taken. If this occurs at a shallow depth, it may 

be too late to prevent a blowout. All kicks in oil-base fluids must be treated as a gas kick and 

circulated through the choke. 

4. Pollution Control Required 

Most areas where oil-base fluid is used have environmental restrictions. Rig modifications may be 

necessary to contain possible spills, collect or clean cuttings, and handle whole fluid without dumping. 

Environmentally acceptable disposal procedures must be followed when discarding cuttings and whole 

mud. 

5. High Cost of Lost Circulation 

Lost circulation with is very expensive due to the mud’s cost per barrel. The problem may not be 

curable. Therefore, it may not be practical to use of oil-base fluids where lost circulation is anticipated. 

Seepage losses are a common occurrence with oil-base fluids. Formations with low permeability and 

porosity may exhibit no losses when drilled with a water-base fluid, however, a partial or full loss of 



Revised 2006 5-3


returns may occur when drilled with an oil-base fluid. Oil-base fluids, because of their low leak-off 

values, can act as efficient fracturing fluids. 

6. Disposal Problems 

Oil-base fluid cuttings may have to be cleaned before dumping. Some environments require that 

cuttings be sent to proper disposal areas. Also, whole fluid cannot be dumped. Therefore, if solids 

need to be reduced, dilution is the only answer. Oil-base fluid volumes only increase. Eventually the 

oil-base fluid must be disposed of, possibly at considerable cost. 

7. Solids Control Equipment 

Oil-base fluids have inherently higher viscosities than water-base fluids. This increased viscosity, 

combined with the need for oil to dilute during the centrifugation process, results in less than effective 

solids removal. See Figure 5-22 thru for the recommended solids control equipment configuration. 

8. Hole Cleaning 

Hole cleaning is more difficult with oil-base fluids. Some reasons for this are – (1) no cuttings 

disperse into the fluid as with water-base fluid, requiring larger cuttings to be removed; (2) oil fluids 

are more Newtonian in behavior than water-base fluids; and (3) oil-base fluids have less thixotropic 

behavior than water-base fluids. 

9. Rig Cleanliness 

Extra effort is required to keep a rig clean when oil-base fluids are used. Special dressing areas, steam 

cleaners on the rig floor, etc., are required. 

10. Special Skin Care for Personnel May be Required 

Prolonged skin exposure to OBM and SBM results in oils being removed from the body, resulting in 

dry and cracked skin. Proper hygiene and skin moisturizers are required to alleviate this situation. 

11. Hazardous Vapors 

As hot oil-base fluid flows across high-speed shaker screens and circulates in fluid pits, toxic 

hydrocarbons may be released. Therefore, shaker and fluid pit areas must be adequately ventilated. 

12. Effect on Rubber 

Oil-base fluids can cause either shrinkage or swelling of normal rubber parts. Therefore, it may be 

necessary to change out blowout preventer (BOP) rubber components, and the Hydril, etc., to oilresistant 

rubber such as Nitrile. Diesel is worse than low-aromatic oils in this respect. Drill pipe 

rubbers will also need to be replaced. Depending on the base fluid used, shaker bonding polymers 

may also be negatively affected. 

13. Fire Hazard 

Since the oil used in oil-base fluid can burn, extra precautions are required to prevent a fire. 

Additional gas, smoke, and fire detector and protection devices are necessary, including sealed electric 

motors and sparkless switches and controls. 

14. Special Logging Tools Required 

Resistivity logs do not work in an oil-base fluid environment. 



5-4 Revised 2006


15. Gas Stripping 

Intrusion of gas into an oil-base fluid can cause the weight material to settle. This is referred to as gas 

stripping of barite, whereby the intruding gas changes the wetting characteristics of the barite surface 

area. This can be a problem when using oil-base fluids on gas wells. 

16. Aqueous Contamination 

An influx of water due to surface leaks, rain, or formation has a significant impact on the properties of 

the system. Dilution is the only recourse to correct the condition and one that is not inexpensive to 

treat. 

Oil-base fluid applications 

Drilling 

The greatest use for oil-base fluids in the period from 1935 to 1950 was for well completion, mainly in 

low-pressure or low-permeability zones. When oil-base fluid was used instead of water-base fluid, 

higher initial production was usually noted. The all-oil filtrate provided an environment in which 

water-sensitive clays did not hydrate. More recently, the advent of relaxed filtrate, low-solids oil-base 

fluids, and polycrystalline diamond cutter bits has resulted in exceptional drilling rates and cost 

savings. Oil-base fluids allow the drilling of reactive formations more efficiently than water-base 

fluids; such is evident in the North Sea. 

Perforating 

Oil-base fluid will not seal off perforations as may be the tendency when a freshwater or saltwater clay 

fluid is used. Bullets and jet charges shot in many water-base systems actually deposit hard solids and 

clay behind the shot, thereby reducing the effectiveness of the perforation job. 

Work over and Completion 

Using oil-base fluid in the open-hole section of deep, high-pressure wells simplifies running liners and 

casing. The fluid provides maximum lubrication of the borehole, reduces torque, and reduces the 

chances of differential sticking. The procedure aids the operator in the holes where close tolerances 

are involved or when landing liners in troublesome holes. The same benefits can be seen when 

running tubing and setting packers. 

Coring 

Maximum recovery is normally achieved because formation clays do not react with oil-base fluids. 

The operation is made easier by elimination of core swelling and jamming of the core barrel and 

differential sticking. 

Stuck Pipe Spots 

The majority of stuck pipe cases are caused by differential pressure sticking. Other causes are key 

seating, balled-up bits, hydrated clay, disintegrated shale formations, poor hole cleaning and washouts. 

Differential sticking can be directly related to low-quality fluid filter cake and/or high pressure 

differential between the wellbore and formation. 

When the pipe becomes partially embedded in the filter cake, it becomes a part of the cake as though it 

were a fluid solid. It is held to the cake by the pressure difference between the well-bore pressure and 

the pore pressures in the cake under the pipe. The force required to pull the pipe free is a function of 



Revised 2006 5-5


the area of pipe in contact with the cake, the pressure holding it to the cake, and the coefficient of 

friction between the pipe and cake. 

Spotting with either BLACK MAGIC ® ‚ or S.F.T. in the zone of sticking is the most successful means 

of freeing differentially stuck pipe. The asphalt in these systems seals off the water fluid-filter cake, 

which then dehydrates, dries, shrinks, and cracks. Once cracked, the oil-base fluid penetrates behind 

the stuck pipe and equalizes the pressure, thus freeing the pipe. 

High-Temperature Drilling 

Wells where temperatures are above 400°F (204°C) commonly use oil-base fluids. The 

solids/chemical tolerance of oil-base fluids is much higher than that of most water-base fluids. Also 

there is less oxidation reduction taking place in an oil-base fluid as the oxygen content is nil compared 

to that of a water base system. Consequently, certain chemicals/solids are not as highly affected by 

temperature. 

Wellbore Stability 

Soft shales can be controlled or hardened by exposure to oil-base fluids which have high-salinity water 

in the emulsified phase. Transfer of water from the shale to the oil-base fluid is attributed to osmotic 

forces across the semi-permeable membrane around the emulsified water droplets. 

Corrosive Gases 

Hydrogen sulfide and carbon dioxide bearing zones, which are hazardous to metal goods and 

damaging to water-base fluid rheology, are better controlled in an oil environment. The oil coating 

protects the metal from corrosion, and lime or scavengers can be added to control gases, if necessary. 

Salt and Contaminating Formations 

Several unsuccessful attempts using water-base fluid were made to drill through the Louann salt 

formation in North Louisiana. At temperatures above 250°F (121°C) and depths below 12,000 ft 

(3658 m), plastic flow of the salt was encountered in several wells. High-weight oil-base fluids were 

used to overcome these problems. In the North Sea, oil-base fluids have been used successfully to 

drill the Carnallite salt sections. The KCl and MgCl 2 salt sections are not washed out when drilled 

with an oil-base fluid. 

Differential Sticking 

Earlier, the application of an oil-base fluid for freeing stuck pipe was discussed. The chance of 

becoming differentially stuck while drilling with an oil-base fluid system is minimal. The oil filtrate, 

lubricity, low fluid loss, and the cake are ideal for preventing wall sticking. 

Drilling Directional Holes 

Oil-base fluid is an ideal fluid for directional work because of its thin filter cake, which gives it the 

ability to maintain a gauge hole and reduce torque. 

Packer Fluids 

Oil-base fluids are used as packer fluids because they serve as a stable non-corrosive barrier against 

corrosive formation fluids. In California, a well pack was developed which has a grease-like 

consistency that prevents transmission of the shock of earth movement to the casing. In Alaska, oilbase 

fluid casing packs are utilized between the strings of casing that pass through the permafrost 

zone. This provides insulation to the frozen ground from the warm oil being produced. 



5-6 Revised 2006


Prevent Lost Returns 

Lost returns can be prevented when drilling abnormally low pressure gradient formations by using 

low-density oil-base fluid with less than 8.0 lb m /gal (0.96 g/cm 3 ) density. 

High Density Fluids 

Oil based fluids have a higher tolerance to active and inert solids. Because of this inherit characteristic 

in combination with surface wetting agents, high density and drill solids tolerant fluids are obtainable 

with excellent rheological properties. 

Oil-based fluid chemistry 

Fundamental Chemical Concepts 

Matter is composed of small, indivisible particles called atoms. Atoms contain a small positively 

charged core, or nucleus, surrounded by negatively charged electrons. There are over 100 different 

types of atoms, and each type represents an element. Examples would be oxygen, hydrogen, carbon, 

sodium, chlorine, etc. 

Atoms are attached to one another to varying degrees. When the attraction is strong enough, atoms 

form aggregates. Aggregates bound together strongly enough to behave as units are called molecules. 

Examples are water, sugar, salt, and hydrocarbons (see ). 

Figure 5-1 

Structures of Primary Hydrocarbon Classes and Isomerized Olefin (Synthetic Base) 

Atoms in molecules have electrons in what are called chemical bonds. When atoms in a molecule 

have extreme differences in affinity for the electron, we call the bonds ionic. The electrons in ionic 

bonds are transferred from one atom to the other. An example would be sodium chloride or common 

table salt. In this example, the sodium (represented by the symbol Na) loses an electron and becomes 

positively charged (represented by Na + ). A charged atom is called an ion. Positively charged ions are 

called cations. The chlorine (represented by the symbol Cl) gains an electron and becomes negatively 



Revised 2006 5-7


charged (represented by Cl – ). Negatively charged ions are called anions. Sodium chloride can be 

represented as Na + Cl – to indicate the electron transferred. 

The two electrically charged atoms or ions of opposite charge are highly attracted to one another. This 

electrical attraction is called coulombic attraction. When atoms in a molecule have somewhat similar 

affinity for the electrons, the bond is covalent and the molecules are nonionic. The shared electrons 

are distributed over the atoms. Examples would be molecular hydrogen, molecular nitrogen, and 

hydrocarbons. 

Fundamental Chemical Classes 

If the electrons in a chemical bond are shared equally by the atoms, we call the bond nonpolar. An 

example would be molecular nitrogen. When the shared electrons in a molecule favor one atom over 

the other, the bond and the molecule are polar. An example is water. Polar molecules, while 

electrically neutral, have uneven centers of positive and negative charge due to the uneven electron 

distribution. Such molecules are called dipoles. Hydrogen chloride (gas) is a good example (see 

Figure 5-2). 

Figure 5-2 

Dipolar Hydrogen Chloride Molecule Showing Separation of Charge 

The positive end of one dipole is attracted to the negative end of other dipoles. This is referred to as 

dipole interaction and this phenomenon accounts for much of the strong attraction that polar molecules 

have for each other (see Figure 5-3). 

Figure 5-3 

Association of Liquid Water 



5-8 Revised 2006


Compounds which have easily replaceable hydrogen ions are called acids (see Table 5-1) 

Name 

Table 5-1 

Hydrochloric or Muriatic Acid 

Carbonic Acid 

Hydrofluoric Acid 

Acetic Acid 

Oleic Acid 

Naphthenic Acid 

Common Acids 

Formula 

HCl 

H 2 CO 3 

HF 

H 3 CCOOH 

CH 3 (CH 2 ) 7 CHCH(CH 2 ) 7 COOH 

C 10 H 7 COOH 

Compounds which can react with and accept hydrogen ions are called bases (see Table 5-2). 

Table 5-2 Common Bases 

Name 

Formula 

Caustic Soda, Caustic, or Sodium Hydroxide NaOH 

Soda Ash, Sodium Carbonate 

Potash, Pearl Ash, Potassium Chromate Na 2 CO 3 

Potassium Hydroxide 

K 2 CO 3 

Lime Hydrate or Lime 

KOH 

Ca(OH) 2 

Acids can react with bases to form salt and water. As an example, hydrogen chloride reacts with 

sodium hydroxide to form sodium chloride plus water. This reaction can be represented by the 

equation, 

HCl + NaOH → NaCl + H 2 O 

As discussed earlier under ionic bonds, sodium chloride, table salt, can be represented by, 

Na + Cl – 

The sodium ion and chloride ion are strongly attracted to one another through coulombic attraction. 

The two ions separate when dissolved in water. The solvent, in this case water, disassociates the salt 

crystal into its constituent ions (see Figure 5-4). This is possible due to the water molecule dipoles 

orienting around the individual ions as shown in Figure 5-5 



Revised 2006 5-9


Ions surrounded by clusters of water molecules are called hydrated ions, and the process itself, 

hydration. Hydration is not limited to ions, but occurs with neutral (but polar) molecules as well. 

Examples are sugar and alcohol. 

Figure 5-4 

Schematic Diagram of Hydrated Sodium and Chloride Ions 

Figure 5-5 Sodium and Chloride Ions Surrounded by Water Molecule Dipoles 

Hydration is a specific example of a more general phenomenon called solvation. Solvation must occur 

when one substance, called a solute, dissolves in another substance, usually a liquid, called the solvent. 

In order to dissolve, the molecules of the solute are surrounded by clusters of molecules of the solvent. 

This process is called solvation and only occurs when the molecules of the solute are similar in ionic 

strength to the molecule of the solvent. Examples are salt in water, sugar in water, fats in 

hydrocarbons. “Like dissolves like” – therefore, molecules which are very dissimilar in charge will 

not solvate and no solution occurs. Examples are salt in hydrocarbons and water in hydrocarbons. 

Compounds which are solvated or hydrated by water, such as salt or sugar, are called hydrophilic, 

meaning water-loving. Compounds which are solvated by oil, such as butter fat, are called lipophilic, 

meaning oil-loving. 



5-10 Revised 2006


Surface Tension 

A molecule in the center of a liquid is completely surrounded by other molecules and is attracted 

equally in all directions. A molecule at the air/liquid surface is attracted inwards, as a result of the 

lower concentration of attracting molecules in the air relative to the liquid. This will set up an 

imbalance of force on a surface molecule and energy must be expended in order to move molecules 

into the surface from the bulk liquid. The amount of energy required to move enough molecules to the 

surface to create a unit area of surface is called the surface energy. 

As a consequence of this imbalance of force, the surface of a liquid always tries to contract to the 

smallest possible area. As a result of this tendency to contract, the surface behaves as if it were under 

tension (see Figure 5-6). If an imaginary cut were made along the surface, a force would have to be 

applied to hold the two portions of the surface together. The force would be proportional to the length 

of the cut and would act at right angles (perpendicular) to the cut. The magnitude of the force per unit 

length is called the surface tension and is numerically equivalent to the surface energy. Surface 

energy/tension, acting to minimize surface area, causes soap bubbles and water droplets to form 

spheres (minimum surface area). Surface energy/tension also accounts for the capillary rise of water 

in small glass tubes. 

Figure 5-6 

Diagram of Attraction Forces in Liquids 

Polar molecules, such as water, because of strong dipolar attractive forces between the molecules, 

show large imbalances of force at the air/liquid surface. This strong imbalance of surface forces 

results in a high-surface energy/tension for water. Ionic solids, with even stronger ionic and 

coulombic attractive forces, show even larger imbalances of force at the air/solid surface. 



Revised 2006 5-11


Surface energies/tensions, as a result, are even higher in ionic solids such as glass, quartz, clays, barite, 

and most mineral solids. High-surface energy/tension liquids, such as water, will interact strongly 

with high-surface energy (hydrophilic) solids, such as glass, and the attractive forces are sufficient to 

overcome gravity causing water to rise in glass capillary tubes as shown in Figure 5-7. 

Figure 5-7 

Surface Tension Causing the Capillary Rise of Water in a Small Glass Tube 

Nonpolar molecules (such as hydrocarbon oils, waxes, and many plastics) show only weak attractive 

forces between molecules, small imbalances of force at the surface, and have low surface 

energies/tensions. High surface energy liquids, such as water, will not interact with low-energy 

surfaces, such as plastic, and will not rise in plastic capillaries. Low-surface energy liquids, such as 

hydrocarbon oils, will interact only weakly with any surface and show only minimal capillary rise 

regardless of the capillary material used. 

Emulsions 

Liquids which are soluble in one another are said to be miscible. An example of soluble liquids is 

water and alcohol. Liquids which are not soluble in each other are immiscible. An example would be 

water and oil. 

When immiscible liquids are mixed vigorously, one liquid will be suspended or dispersed as droplets 

in the other liquid. Such two-phase systems are called emulsions (see Figure 5-8). The dispersed or 

suspended liquid is called the internal, or dispersed, phase. The other liquid is called the external, or 

continuous, phase. 



5-12 Revised 2006


The most common types of emulsions are oil in water and water in oil. An example of oil-in-water 

emulsion is milk. Examples of water in oil emulsions include grease, margarine, and oil-base fluids. 

The first and most common emulsions studied were oil in water. Water-in-oil emulsions were studied 

later and sometimes are called invert emulsions. 

Figure 5-8 

Emulsions 

Dispersing one liquid as small droplets in another liquid increases the surface area between the two 

liquids. The surface energy/tension that exists at the interface between two liquids is called the 

interfacial energy or interfacial tension. This interfacial energy/tension tends to minimize the surface 

area and work must be performed (energy expended) to increase interfacial surface area and overcome 

these forces. A mixer can form a mechanical emulsion between two pure liquids, such as water and 

hydrocarbon, but the emulsion breaks and the two phases separate when the agitation ceases. This deemulsification 

is due to interfacial energy/tension minimizing interfacial surface area. In order to form 

a stable emulsion, a third component is necessary. 

Surfactants 

Surface active compounds are compounds that orient at interfaces or surfaces and lower surface or 

interfacial energy/tension. Surface active compounds are often called surfactants. The most common 

example is soap, as indicated in Figure 5-9. 

Figure 5-9 

Surfactant Structure (Soap) 

This compound has both a hydrophilic “head,” which is polar and ionized, and an organophilic “tail,” 

which is nonpolar (see Figure5-10). The structure is called amphiphilic to indicate the dual character 

of these compounds. Surfactants are usually elongated and only partially soluble in either oil or water. 

The degree to which surfactants are soluble in oil or water can be denoted by the hydrophiliclipophilic 

(organophilic) balance (HLB). Surfactants which are more water soluble (hydrophilic) tend 



Revised 2006 5-13


to form oil in water emulsions and have high HLB values. For example, Drilling Mud Emulsifier 

(DME) has an HLB of 7.7. Surfactants which are more oil soluble (organophilic) and form water in 

oil emulsions, have low HLB values. In addition to the HLB characteristic is the type salt or valence 

of the hydrophilic portion of the surfactant. Monovalent cations promote oil in water emulsions and 

Divalent cations promote water in oil emulsions. 

Figure 5-10 

Orientation of Surfactants at an Interface 

Surfactants orient at interfaces and lower surface energy/tension. This reduces the forces necessary to 

form new interfacial area and reduces the interfacial area after the emulsion is formed. Surfactants 

oriented at the interface also form a chemical skin around the emulsified, dispersed phase and 

mechanically stabilize the interface, thereby helping to prevent droplets from coalescing and breaking 

when colliding. Small insoluble particles will also do this by forming a mechanical emulsion. 

Examples of mechanical emulsifiers are lignite and bentonite. 

Temperature increases the frequency of droplet collisions and decreases the stability of emulsions. 

Imposing an electrical field across an emulsion will also tend to break the emulsion, which is the basis 

of the emulsion stability test for oil-base fluids. Increasing the viscosity of the external phase will 

decrease the frequency of collisions and stabilize the emulsion. 

Dispersions 

Powdered solid suspended in a liquid are called a dispersed system, or simply a dispersion. The 

internal or dispersed phase is the solid and the continuous phase is the liquid (see Figure 5-11). 

Figure 5-11 

Dispersion of a Mineral Powder 



5-14 Revised 2006


The term dispersion is also used to define the process itself which requires the solid particles to be 

coated by the liquid. 

Consider a drop of liquid on a flat solid surface. Three interfaces and three interfacial tensions ( γ ) are 

involved – solid/air (S/A), solid/liquid (S/L), and liquid/air (L/A). At equilibrium, it can be shown 

that, 

cosθ 

γS⁄ A– 

γ S⁄ 

L 

= -------------------------- 

γL A ⁄ 

If the contact angle (θ) is greater than or equal to 90°, the liquid is “nonwetting” with respect to the 

solid. The liquid tends to “bead” on the solid surface as water does on wax (see Figure 5-12). When 

the contact angle is 0°, the liquid completely wets the solid and, in fact, will spontaneously “spread” 

on the surface (i.e., water on glass). Surfactants lower the liquid/air surface tension (L/A), as 

discussed earlier, and reduce the contact angle. Surfactants often adsorb at the solid/liquid surface as 

well. This adsorbed layer alters the surface of the solid with respect to the liquid. 

Figure 5-12 

Liquids on Solid Surfaces 



Revised 2006 5-15


As indicated by Figure 5-13, the high-surface-energy (hydrophilic) mineral solid is preferentially wet 

by a high-surface-energy/tension polar liquid, such as water. Even if the surface is initially coated or 

wet with a low-surface-energy/tension hydrocarbon oil, water will displace the oil and “water-wet” the 

hydrophilic surface. Just as “like dissolves like” and “like solvates like,” “like wets like.” Adsorbing 

a surfactant, however, alters the mineral surface with the hydrocarbon tails oriented toward the oil. 

Figure 5-13 

Oil Wetting 

The surfactant “mimics” a hydrocarbon surface and lowers the surface energy of the mineral. Water, a 

high-surface energy/tension liquid, will not wet a low-energy surface and will tend to “bead up.” The 

mineral surface has been rendered “oil-wet.” Examples are waxing the paint on an automobile and 

using a wetting agent to “oil-wet” barite during weight-up of oil-base fluid systems. 

Dispersions, like emulsions, once formed, are subject to particle/particle collisions. These collisions 

can result in destabilization of the dispersion by flocculation, aggregation, and settling of the solids. 

Surfactant films help to stabilize dispersions by preventing close approach between particles. 

Temperature increases the number of collisions and decreases the viscosity of the continuous phase. 

The latter promotes settling due to Stoke's law and is a particular problem in dispersions. 

The most important source of instability occurs in combined emulsions/dispersions. Oil-base fluids 

can be considered as three-phase oil/water/ionic-mineral solid systems where oil is the continuous 

phase and water and mineral solids are dispersed. The mineral solids are hydrophilic and will 

preferentially water-wet. In the absence of surfactants, even if the mineral solid is oil-wet initially, 

water will tend to displace oil from the surface and water-wet the solids. As the solids water-wet, they 

stick together, forming larger diameter agglomerates which settle out. Altering the surface of the ionic 

solid with an adsorbed surfactant layer counteracts this tendency and promotes oil wetting. 

General Colloidal Systems 

Colloidal systems are defined as emulsions or dispersions in which the diameter of the dispersed phase 

is of the order of ≤ 1 micron (10 -6 m). The ratio of area to volume in colloidal systems is large (ratios 

of 10 6 are not uncommon) and surface effects (surface tension, adsorption, wetting) predominate the 

physical characteristics. Emulsification requires the creation of new surface area which interfacial 

tension opposes. While surfactants will minimize the problem, it is never eliminated in practical 

systems. Common minerals, such as barite, clays, calcite, quartz, etc., are ionic or polar and, as such, 

are hydrophilic and preferentially water-wet. Adsorbed surfactants alter the surface, but the inherent 

tendency remains. Dispersed phases are constantly tending to collide with each other leading to 



5-16 Revised 2006


coalescence or aggregation. Surfactants are our most important tool for controlling these destabilizing 

forces and processes. 

Non-Aqueous external phase 

Base Oils 

Hydrocarbon oils are the continuous phase in oil-base fluids. They are non-polar, low-surface 

energy/tension liquids and interact only weakly with mineral solids. This characteristic is the basis for 

the use of oil-base fluids as non-reactive, inert drilling fluids. Hydrocarbon oils will not allow clays to 

swell, which makes them ideal for drilling hydratable shales. 

The most commonly used oils today are synthetics where certain environmental regulations prevail, 

low-aromatic-content, low-toxicity mineral oils, and No. 2 diesel oil. Crude oil has been used in the 

past but finds little application in today’s modern day oil-mud drilling fluids. Crude is relatively 

cheap, often available, but may need topping to minimize flammability since a flash point greater than 

180°F (82°C) is advised. 

• Crude contains native asphaltenes and resins which can interfere with other additives. 

• Crude is usually used in “poor boy” oil-base fluids. 

No. 2 diesel oil is a moderately-priced, commonly available distillate which contains none of the 

native asphaltenes or resins in crude and is the most commonly used oil for mixing oil-base fluids. 

Diesel based systems are generally used today only in land drilling operations. Offshore drilling 

operations limit the use of diesel base systems due to the toxicity of the base oil. The aromatics in 

diesel oil can swell rubber gaskets, seals, and pipe rubbers, however, an aniline point greater than 

140°F (60°C) (the higher the aniline point, in general, the lower the concentration of aromatics) is 

recommended. Mineral oils are recommended due to lower toxicity relative to diesel oil. Most of the 

toxicity of diesel oil is associated with the aromatics, particularly the multi-ring or polynuclear 

aromatics. Low-toxicity mineral oils have low to very low concentrations of aromatics and those 

present are predominantly single-ring. Synthetics are the preferred oil in offshore drilling operations 

where environmental regulations prohibit the discharge of cuttings and/or whole mud to the sea. 

All hydrocarbon oils currently used in oil-base fluids are more viscous than water. This probably 

accounts for the lower penetration rates observed with oil-base fluids (all things being equal) relative 

to water-base fluids because of the higher viscosity at the bit. The higher viscosity oil also partially 

accounts for the lower filtration losses observed with oil-base fluids relative to water-base fluids 

because of Darcy's Law (assuming identical permeability filter cakes). See Table 5-3 for the 

properties of several oils. 



Revised 2006 5-17


Oil 

Density at 

60°F (15°C) 

(g/ml) 

Table 5-3 

Initial 

Boiling 

Point 

Diesel 0.84 383°F 

195°C 

ISO-TEQ C16-18 

(SYN-TEQ sys.) 

Exxon 

ESCAID 110 

SIPDRILL 2/0 

(PARA-TEQ sys.) 

0.792 >518ºF 

>270ºC 

0.806 394°F 

201°C 

0.760 412ºF 

211ºC 

Total HDF2000 0.808 450°F 

232°C 

Conoco LVT200 0.820 421°F 

216°C 

ALPHA-TEQ 0.778 437°F 

225°C 

EDC 99 DW 0.811 448°F 

231°C 

SARAPAR 147 

Aniline Point 

0.76 @ 

30°c 

Base Fluid Properties 

Final 

Boiling 

Point 

734°F 

390°C 

Flash 

Point 

149°F 

65°C 

NA 273ºF 

134ºC 

459°F 

237°C 

455°f 

235°C 

622°F 

328°C 

518°F 

270°C 

518°F 

270°C 

509°F 

265°C 

167°F 

75°C 

203ºF 

95ºC 

221°F 

105°C 

201°F 

94°C 

237°F 

114°C 

214°F 

101°C 

NA NA 248°f 

120°C 

Aniline 

Point 

154°F 

68°C 

Aromatic 

Content 

(wt. %) 

Viscosity at 

104°F (40°C) 

(cSt) 

25 %v/v 3.4 

180ºF NA 3.6 

162°F 

72°C 

189°F 

87°C 

192°F 

89°C 

166°F 

74°C 

147°F 

64°C 

176° 

80°C 

0.05 1.63 

< 0.1 1.75 

0.4 3.3 

1.0 2.1 

0.1 2.06 

0.0 2.28 

90°C NA 2.6 

The Aniline Point is an indicator of the detrimental effects (damage) oil will inflict on the elastomers 

(rubber compounds) that come into contact with oil-based (non-aqueous) drilling fluids. It is 

commonly referred to as a test to evaluate base oils that are used in oil muds. The test indicates if a 

particular oil is likely to damage those parts of the drilling fluid system which are constructed from 

rubber materials. 

The aniline point is called the "aniline point temperature," which is the lowest temperature (°F or °C) 

at which equal volumes of aniline (C 6 H 5 NH 2 ) and the oil form a single phase. The aniline point (AP) 

correlates roughly with the amount and type of aromatic hydrocarbons in an oil sample. A low 

Aniline Point is indicative of higher aromatic, while a high Aniline Point is indicative of lower 

aromatic content. 

It has been established through field experience that oils exhibiting an Aniline Point of less than 140º 

F (60º C) will be damaging to the elastomers (rubber parts) of a drilling fluid circulating system. The 

API has developed test procedures that are the standard for the industry. 

Synthetics 

Synthetic-base drilling fluids (SBF) use a synthetic type material as the continuous phase. The first 

SBF was used offshore Norway in March 1990. Since that time, due to the ever-changing 

environmental status of SBFs, several types of synthetic materials have been used to formulate the 

synthetic-base fluid. Baker Hughes Drilling Fluids, in April 1994, used an isomerized olefin 

(ISO-TEQ TM ) for the continuous phase of a SBF. This was the first use of the olefin which has now 

become the industry standard. Like the hydrocarbon-base fluids, the olefin-base fluid will not solvate 

or swell clays, making them ideal for drilling hydratable shales. 



5-18 Revised 2006


Unlike mineral and diesel oils which are distilled from crude oils, synthetic type materials are usually 

polymerized from ethylene. Since the synthetics are pure products made from ethylene, they contain 

no aromatics, thereby lowering the toxicity level normally associated with aromatic compounds. Like 

hydrocarbon oils, the synthetic type materials are more viscous than water. See Table 5-4 for the 

properties of several synthetic materials. 

Oil 

LAO 

(ALPHA-TEQ sys.) 

Density at 

60°F (15°C) 

(g/ml) 

Table 5-4 

Initial 

Boiling 

Point 

0.778 437ºF 

225ºC 

CLAIRSOL NS 0.815 500°C 

260°C 

SYN-TEQ CF 

(CF-2002) 

SN – 1890 

(SYNTERRA) 

0.79 482°F 

250°C 

Properties of Synthetic Materials 

Final 

Boiling 

Point 

518ºF 

270ºC 

581°C 

305°C 

626°F 

330°C 

Flash 

Point 

237ºF 

114ºC 

252°F 

122°C 

284°F 

140°C 

Aniline 

Point 

147ºF 

64ºC 

190°F 

88°C 

180°F 

82°C 

Aromatic 

Content 

(wt. %) 

Viscosity at 

104°F (40°C) 

(cSt) 

Pour Point 

(°C) 

0.1 2.06 - 12 

0.2 3.4 - 18 

< 0.001 2.9


As the concentration of ions increases, so does the concentration of water molecules tied up in 

hydration. As the concentration of water molecules tied up in hydration increases, the concentration of 

free water molecules (not involved in hydration) decreases. The availability of the water molecules in 

a solution to hydrate additional solutes can be quantified by the “activity” scale. All the water 

molecules in freshwater are available for hydration and the activity (Aw) is defined as “1”. As salt, or 

any substance that hydrates, is added, the concentration of hydrated ions or molecules increases and 

the availability of the brine molecules in the solution to hydrate any additional material decreases the 

activity (Aw). 

If two solutions of different Aw are poured together, diffusional mixing will result in a uniform Aw 

intermediately between the two. If two solutions of different Aw are separated by a semi-permeable 

membrane, an unusual situation occurs, as shown in Figure 5-15. A semi-permeable membrane is 

defined as a thin membrane which will allow water molecules to freely pass, but not salt ions. 

Water molecules in the solution of higher Aw will diffuse into the solution with lower Aw, as before, 

but not the ions. If the chamber with the solution of lower Aw is sealed, then the water diffusing 

through the membrane increases the pressure in the chamber. This is defined as osmotic pressure 

(Figure 5-15) 

Semi-permeable membranes are created between emulsified water droplets in water in oil emulsions 

and between emulsified water droplets and the formation drilled (see Figure 5-16). The layer of 

surfactant-rich oil will allow water molecules to pass, but not salt. Unless the Aw values are equal, an 

osmotic imbalance, or potential, will exist and water will migrate. 

As the concentration of salt in the aqueous phase increases and the Aw decreases, less water is 

available to solubilize and hydrate other materials. Lime, for example, is less soluble in CaCl 2 

solutions than in water. 

Figure 5-15 

Osmosis 



5-20 Revised 2006


Figure 5-16 

Semi-Permeable Membranes 

Emulsifiers 

Surfactants 

Surfactants lower surface energy/tension, as discussed earlier, and are required to emulsify the 

water/aqueous phase and “oil-wet” the mineral solids. They are amphiphilic compounds with both 

hydrophilic “heads” and organophilic “tails,” partially soluble in both water and oil. 

Surfactants are conveniently classified according to the charge on the hydrophilic “head.” The main 

classes are anionic (negatively charged), cationic (positively charged), and non-ionic (uncharged). 

The surfactants used in CARBO-DRILL SM , ISO-TEQ TM , SYN-TEQ, and SYN-TEQ CF systems 

include CARBO-TEC ® , CARBO-MUL ® HT, OMNI-MIX TM , OMNI-MUL and OMNI-TEC TM . 

Because most modern invert emulsion fluids now contain more than one emulsifier with different 

chemical structures but similar functions, they will be discussed separately. 

Soaps 

The most common anionics are soaps. Soaps were the first surfactants known and are common. They 

are usually considered in a separate class. Soaps are formed from an alkaline material such as lime 

[Ca(OH) 2 ] and “long-chain” organic acids, such as stearic acid which is derived from tallow. The lime 

saponifies the stearic acid and supplies a cation (Ca ++ in this case), also referred to as a counter ion, 

which balances the negatively charged hydrophilic head (see Figure 5-17). 

Calcium soaps are the most commonly encountered soaps in oil-base fluids, or inverts, although 

magnesium, ammonium, and amine soaps have been used. Long-chain organic acid sources include 

tall oil, asphaltic, naphthalenic, and blown-wax acids. Soaps can be pre-formed and used, or can be 

formed in the drilling fluid using lime. 

Soaps are the cheapest surfactants. Some, such as asphaltics and naphthalenic, occur naturally in some 

oils. Soaps are good emulsifiers in high pH or water-base drilling fluid systems, but less useful at 



Revised 2006 5-21


lower pH. They emulsify freshwater well, but show poor electrolyte tolerance (they lose effectiveness 

at low Aw). Thermal stability of the molecule is good as is resistance to alkaline hydrolysis (lime will 

not decompose the molecule), but some soaps gel up at low temperatures. All soaps tend to require 

additional surfactants at high solids concentration. Tall oil soap (CARBO-TEC or OMNI-TEC) is 

particularly good at dispersing DENSIMIX ® (hematite). 

Fatty Acids 

Figure 5-17 

Soap Formation 

Fatty acids are the basic components for nearly all emulsifiers and wetting agents used in the 

preparation of invert emulsions. Their demand is due primarily to their low cost and availability in 

many forms, including crude and refined tall oil, animal pitch, and others. 

Tall oil fatty acids are the most common and are obtained as a by-product of the Kraft pulping process, 

in which alkaline pulping liquor converts fatty and rosin acids present in soft pines to their 

corresponding sodium salts. These sodium salts are then removed and acidified to yield crude tall oil, 

which can either be processed into anionic emulsifiers or further refined for use in the manufacture of 

non-ionic emulsifiers. 

Chemical composition of tall oil varies with the geographical source and species of trees used in 

pulping and in the refining process. Oxidation, isomerization, adduct formation, and polymerization 

are all factors in the refining process which will influence the final tall oil product. 



5-22 Revised 2006


Anionic Emulsifiers 

Anionic emulsifiers, such as CARBO-TEC ® , are usually prepared by oxidation of crude tall oil. This 

oxidation process is shown in Figure 5-18. 

H 

- H 

CH 3 (CH 2 ) 6 - C - CH = CH (CH 2 ) 7 CO 2 H 

H 

(RH) 

• 

CH 3 (CH 2 ) 6 - C - CH = CH (CH 2 ) 7 CO 2 H 

H 

(R•) 

Figure 5-18 

R• + O 2 -- ROO• 

ROO• + RH -- ROOH + R• 

2 R• -- R - R 

R - OO• + R• -- R - OO - R 

R - OO - R -- 2 RO• 

RO• + R• -- ROR 

Oxidation of Fatty Acids during the Manufacture of Anionic Emulsifiers 

The fatty acid of the crude tall oil is converted to a water-insoluble soap by reaction with calcium 

hydroxide. Soap formation changes the relative solubility of the fatty acid, whereas air oxidation 

increases the surface activity by introducing hydrophilic oxygen groups. 

Anionic emulsifiers are used in vast amounts in the detergent industry. They are excellent at reducing 

interfacial tension, have good thermal stability, and have resistance to alkaline hydrolysis (some 

sulfated or sulfonated oils are an exception). 

Non-ionic Emulsifiers 

Non-ionic emulsifiers, such as OMNI-MUL TM , are used to provide emulsion stability in drilling fluids 

and also to facilitate wetting and dispersion of incorporated solids. These non-ionic emulsifiers tend 

to be non-ionic, although they can have slightly cationic tendencies. 

Cationics tend to adsorb strongly on mineral surfaces and are excellent oil-wetters. They also function 

excellently when emulsifying concentrated calcium chloride solutions. Thermal stability is moderate 

and resistance to alkaline hydrolysis is fair to good. 

Non-ionics reveal excellent thermal stability and have a high resistance to alkaline hydrolysis. They 

also exhibit good electrolyte tolerance. Non-ionics are usually mixed with other surfactants to 

maximize oil-base fluid temperature stability. 



Revised 2006 5-23


One of the most important factors in the formulation of the amide-type non-ionic emulsifier is the 

selection of the cross-linking agent. Shown below in Figure 5-19 is the manufacturing process for 

polyamide emulsifiers. 

Figure 5-19 

General Polyamide Emulsifier Synthesis 

Colloids 

Organophilic Clay 

Organophilic clays (CARBO-GEL ® and CARBO-VIS TM ) are the most common gelling and 

suspending additives used in oil-base fluids. Organophilic clays are usually formed by reacting a 

quaternary ammonium chloride (quat) with sodium bentonite. The cationic quat replaces a sodium ion 

on the surface of the bentonite. 

This effectively renders the surface oil wettable and allows the hydrocarbons to wet and penetrate the 

clay lattice structure and swell the organophilic clay to dispersion. While organophilic bentonite is the 

most common example, organophilic hectorite and sepiolite can be used as well. 

To obtain the full potential rheology of any organoclay, both shear and heat are required. Organoclays 

are manufactured by either a “dry” or “wet” process. The latter method produces purified clays which 

are more thermally stable, especially the hectorite base organoclays, which are more consistent in their 

performance. By varying the quat chemistry and clay type, a wide variety of organoclays are available 

which can be used with various base oils and in various temperature ranges. Maximum thermal 

stability of organoclays varies between 285°F (140°C) and 400°F (204°C). The cost of the organoclay 

grades increases with thermal stability. 



5-24 Revised 2006


Polymers 

Several polymers now have application for use in oil-base drilling fluids. These polymers increase 

fluid carrying capacity, in both diesel and mineral oil systems, and extend the viscosity temperature 

stability to in excess of 500°F (260°C). Polymers used, include elastomeric viscosifiers 

(CARBO-VIS TM HT), lightly sulfonated polystyrene polymers, fatty acids, and various dimer-trimer 

acid combinations. 

Asphalt / Gilsonite 

Asphalt is a petroleum-derived colloidal gel composed of colloidal asphaltenes, polar aromatics 

(resins), and oils (see Figure 5-20). 

Figure 5-20 

Macrostructure of Asphalt 

The most commonly encountered are those that are naturally present in crude, gilsonite (a mined 

product), and blown asphalt. The active components are the asphaltenes. Quality asphaltenes are 

highly-associating and form micelles which are thermally stable. 

The primary use of asphalt is for fluid loss control. The concentration used is 1 to 15 lb m /bbl (2.9 to 

42.8 kg/m 3 ). Asphalt also functions as a shale stabilizer at 5 to 15 lb m /bbl (14.3 to 42.8 kg/m 3 ). When 

used at higher concentrations, such as ≥ 40 lb m /bbl (114 kg/m 3 ), it functions as a viscosifier by 

increasing the base fluid viscosity. 

Quality asphalt is relatively cheap, resistant to electrolytes, alkaline hydrolysis, and is an excellent 

fluid loss control material. Asphalt also has good thermal stability. The cake is soluble in most crude 

oils, so is somewhat self-cleaning when producing the well. 



Revised 2006 5-25


Amine Lignite 

Amine lignites are prepared by reacting quats or amido amines with lignites. Variances in base 

materials and reaction conditions result in a wide variety of amine lignites, which has a direct 

influence on their performance and thermal stability. They perform adequately up to 350°F (177°C). 

Lime 

Acid gases, alkalinity, and corrosion are usually controlled with lime, Ca(OH) 2 , or quicklime, CaO, in 

oil-base fluids. 

CO2 + H2O →H2CO3 

H2CO3 + Ca(OH)2 →CaCO3 + 2H2O 

H2S + Ca(OH)2 →CaS + 2H2O 

If CO 2 is present, lime additions will be needed only if an anionic emulsifier is being used. Calcium 

hydroxide is needed to form the calcium soap. Once the soap is formed, any introduction of CO 2 in 

the fluid will not affect the fatty acid and lime reaction. 

If H 2 S is introduced to the system, the CaS compound will remain stable as long as there is excess 

lime present. Basic zinc carbonate can also be used to react with H 2 S. 

Emulsion based drilling fluids 

CARBO-DRILL ® Oil-Base Drilling Fluid System 

The CARBO-DRILL ® oil-base fluid systems are designed for maximum stability and versatility. 

Three systems make up the CARBO-DRILL system family – CARBO-FAST SM , CARBO-TEC ® , and 

CARBO-CORE ® (see Chapter 6, Reservoir Application Fluids). Formulations for the 

CARBO-DRILL system are referenced in Table 5-6 through Table 5-13 at the end of this chapter. 

CARBO-DRILL systems can be formulated with low-aromatic mineral oil instead of diesel oil as the 

external phase for drilling in environmentally-sensitive areas. Mineral oil systems are identified by 

the S.E.A. designation (i.e., CARBO-TEC ® S.E.A., CARBO-FAST SM S.E.A., and CARBO-CORE 

S.E.A). Typically, S.E.A. systems will require more organophilic clay and emulsifiers and will exhibit 

lower electrical stability (ES) values when compared to diesel systems. The CARBO-DRILL systems 

are very versatile, from relaxed to a very high-temperature stable system. CARBO-TEC S.E.A. is 

designed specifically to meet environmental requirements for drilling in the North Sea. 

CARBO-FAST SM / CARBO-TEC ® 

The CARBO-FAST system is prepared as a “relaxed” oil-loss fluid with a low colloid content, and is 

designed for rapid rates of penetration. Filtrate loss can be controlled over a wide range depending on 

the control required for a given well. 

CARBO-FAST systems can be converted to a CARBO-TEC controlled filtrate loss when low values 

are required. This is achieved by using the additional products CARBO-TEC, an anionic emulsifier, 

and CARBO-TROL, an asphaltic filtrate loss control additive. CARBO-TROL A-9, a non-asphaltic 

filtrate loss control additive, can be substituted if desired. 

The CARBO-DRILL systems can incorporate a much higher percentage of water, compared to 

conventional oil-base drilling fluid. Depending on fluid weight and CaCl 2 content, the CARBO- 

DRILL oil/water ratio can be used to the 45/55 - 60/40 range. Increased water content decreases the 

amount of oil on cuttings as they are discharged over the shaker, allowing oil-base drilling fluids to 



5-26 Revised 2006


meet cuttings discharge criteria in the North Sea. The lower oil/water ratio CARBO-DRILL S.E.A. 

system is widely used in the North Sea. 

In addition to decreasing the amount of oil associated with drill cuttings, the increase in brine content 

has also been shown to reduce the cost of the oil fluid, since less oil is necessary. 

Because of the large volume of water present, the fluid system is composed of specifically designed 

products. These CARBO-DRILL systems have been designed to cope with the high water content and 

to exhibit rheology comparable to more conventional oil-base fluid systems. The proper emulsifiers 

and oil wetting agents result in a stable system with no water in the high-temperature/high-pressure 

(HT/HP) filtrate. Field and laboratory evidence has shown that the CARBO-DRILL systems can 

incorporate additional water contamination with minimal increase in rheological properties and little 

or no water wetting of solids, even when water may be temporarily present in the HT/HP filtrate. 

The principal emulsifiers used in the North Sea high water content CARBO-DRILL S.E.A. are 

CARBO-MUL HT and CARBO-MIX. Field evidence has shown that CARBO-MUL HT/CARBO- 

MIX emulsifier’s combinations are synergistic. The ratio of these products is dependent upon the 

oil/water ratio, temperature, and fluid density. 


To achieve optimum economics when using emulsifiers and changing oil content, as well as to 

minimize the plastic viscosity of the fluid, the oil/water ratio is varied with the fluid density. 

The CARBO-DRILL systems are more tolerant of water content than most conventional oil-mud 

systems; however, they become less tolerant to large quantities of low-gravity solids as water content 

increases. Therefore, drill solids must be controlled. The use of linear motion shale shakers, 

preferably with the fluid cascaded from coarse mesh shakers (often referred to as scalping shakers) is 

recommended. Field experience has shown that solids contents up to 120 lb m /bbl (348 kg/m 3 or 13.2% 

by volume) can be tolerated. However, fluids containing above 120 lb m /bbl (348 kg/m 3 ) low-gravity 

solids should be diluted with the non to low solid laden CARBO-DRILL SYSTEM. Ideally, the lowgravity 

solids content should be less than 80 lb m /bbl (232 g/m 3 or 8.8% by volume). 

The base formulations contain emulsifiers to start a system. However, as drilling commences, drill 

solids accumulation and removal, and increases in fluid density, requires increased additions of 

emulsifiers and wetting agents. Therefore, the CARBO-DRILL systems must be engineered so that 

each system is maintained without it becoming an expensive, over-treated fluid system. Water 

breakout and/or HT/HP increases are direct indicators that additional emulsifiers/wetting agents are 

required. It is recommended that the HT/HP checks be run every eight hours so that a trend can be 

developed. Any increases in HT/HP filtrate or detections of water in the filtrate must be treated 

immediately. 

MAGMA-TEQ HTHP Non-Aqueous Drilling Fluid System 

Increasing demand for drilling deviated HTHP wells in the North Sea area has resulted in the 

development of a HTHP oil based drilling fluid with unique suspension properties to avoid commonly 

observed density differentiations under extreme conditions. The stringent environmental and 

occupational hygiene regulations in the North Sea area also limit the use of commonly used 

chemistries for oil based HTHP applications. Baker Hughes Drilling Fluid’s HTHP oil-based drilling 

fluid, MAGMA-TEQ is a state of the art response to this need. 

During the development of this system several new products were created which include a specialized 

high temperature emulsifier; MAGMA-VERT, improved fluid loss chemistry and suspension 

stabilizer; MAGMA-TROL and MAGMA-GEL, a high temperature viscosifier which also acts as 

a barite sag preventative additive. 



Revised 2006 5-27


The MAGMA-TEQ system is stable to temperatures above 400º F and exhibits minimal density 

differential under dynamic and static conditions. The system can be weighted up to densities above 

2.2 s.g. using barite or alternative weighting materials such as Ilmenite, Hematite, or Micromax. 

Typical O/W ratio is in the 85/15 to 90/10 range. The system is specifically designed for the use of 

commonly available aromatic-free base oils, and the products in the system exhibit minimal 

occupational hygiene exposure. Although the system is developed to conform to the environmental 

regulations of the North Sea area, several of the components of MAGMA-TEQ enhance the fluid 

properties in higher aromatic base oil environments such as diesel based drilling fluids. 

The static barite sag analyses are extremely good and fall well within the sag factors specified by 

several major oil companies. MAGMA-TEQ also exhibits very low amounts of supernatant oil 

(syneresis) in samples aged both static and dynamically. Field tests demonstrate that the laboratory 

formulation properties further improve during drilling conditions; as with other oil mud systems, with 

repeated shear through bit nozzles and hole temperatures from the drilling operation. 


The system should be maintained in a manner similar to that described for the CARBO-FAST / 

CARBO-TEC system previously described. 

SYNTERRA SM Synthetic Base Drilling Fluid System 

SYNTERRA SM was developed to provide an environmentally friendly, non-aqueous synthetic system 

for use primarily on land operations as an alternative to diesel based drilling fluids. The fluid design is 

similar to conventional oil-based fluids and has applications in routine drilling as well as more 

demanding applications, such as HTHP and extended reach drilling. SYNTERRA is not designed for 

use in drilling offshore if a discharge of cuttings is planned. 

The SYNTERRA system employs a unique low-kinematic viscosity synthetic base fluid; SN-1890, to 

deliver equal to diesel based fluid performance. Some of the benefits of using SYNTERRA include: 

Enhanced environmental acceptability 

Elimination of fumes commonly associated with diesel-based systems 

Occupational hygiene and environmental properties are improved compared to dieselbased 

systems 

Simple, cost-effective formulations 

Low kinematic viscosity base fluid for optimal rheology 

Thermal stability 

Minimal rheology changes with temperature 

Good hole cleaning characteristics 

Fully compatible with diesel-based systems for blending of the systems as necessary 

Some of the applications of SYNTERRA SM include: 

Land drilling 

Limited discharge sites 

Drilling within city limits 

Environmentally sensitive areas such as wet lands and reserves 

Where an alternative to diesel is desired. 



5-28 Revised 2006





SYN-TEQ Synthetic Base Drilling Fluid System 

The SYN-TEQ system provides superior performance and environmental acceptability in one 

synthetic-based drilling fluid. The system is based upon the use of a low-viscosity olefin isomer. 

Baker Hughes Drilling Fluids ISO-TEC ® base fluid is a nontoxic, isomerized olefin designed 

specifically for synthetic drilling fluid applications. The ISO-TEC base fluid is a biodegradable fluid 

and is combined with other specialized fluid additives to form the SYN-TEQ system that offers a safe 

alternative to traditional oil muds. SYN-TEQ systems can be formulated with low SWR 

(synthetic/water ratio) for cost savings and overall enhanced well economics. 

The SYN-TEQ system offers several environmental and logistical advantages over traditional oilbased 

muds. Also the system delivers superior lubricity and increased thermal stability. Together, 

these advantages make SYN-TEQ a preferred drilling fluid where the superior performance of a nonaqueous 

fluid is desired and where the use of an oil-base fluid is prohibited by environmental 

concerns. The SYN-TEQ system passes strict environmental testing, including toxicity and 

biodegradability, designed to evaluate any environmental impact. 




SYN-TEQ CF Synthetic Base Drilling Fluid System 

The SYN-TEQ CF non-aqueous drilling fluid system is designed specifically to allow the continuous 

discharge of drill cuttings to the sea. SYN-TEQ CF is compliant with the National Pollutant 

Discharge Elimination System (NPDES) permit for the Western Gulf of Mexico (2/12/02). 

SYN-TEQ CF is formulated with a minimum number of products chosen specifically for individual 

performance characteristic. The system can be used in any drilling operation requiring superior 

performance, and is recommended for deepwater operations. 

SYN-TEQ CF represents an environmental advance over previous non-aqueous systems using olefins 

as the base fluid. SYN-TEQ CF is formulated from the base fluid C16/18 isomerized olefins which 

are acknowledged by the US EPA as being an environmental benchmark in the Gulf of Mexico. 




GEO-TEQ Synthetic Base Drilling Fluid System 

GEO-TEQ is a specially formulated, environmentally responsible synthetic drilling fluid system which 

addresses the drilling performance, environmental, and geochemical needs desired in synthetic 

systems. Accordingly, GEO-TEQ uses GT-2500 as the base fluid, which through its unique 

composition will not interfere with the interpretation of naturally occurring hydrocarbon components 

during crude oil analysis. Particularly, GT-2500 enables accurate analysis of the “bio-markers”, 

Pristane and Phytane, even when the base fluid constitutes as much as 25% of the reservoir sample. 

GEO-TEQ is a synthetic drilling fluid system specifically designed to allow continued discharge of 

drill cuttings to the sea and is compliant with the National Pollutant Discharge Elimination System 

(NPDES) permit for the Western Gulf of Mexico. 



Revised 2006 5-29





Product applications and recommendations 

CARBO-GEL ® 

CARBO-GEL ® is a high-purity, wet-process, high-yielding organophilic hectorite clay used as the 

viscosifying and suspending agent in oil- and synthetic-base fluid systems. Because it is more active 

than organophilic bentonite clay, CARBO-GEL increases the carrying capacity and hole cleaning 

characteristics of oil and synthetic-base fluids. 

CARBO-GEL is exceptionally effective at maintaining the yield point values in oil and synthetic-base 

fluids after high-temperature aging. 

Concentrations of 1 to 5 lb m /bbl (2.9 to 14.3 kg/m 3 ) are usually adequate for most applications. The 

type of oil determines the concentration limits necessary for building viscosity and for gel-building 

properties. Good shear is recommended. Low-aromatic oil will require as much as three times the 

concentration of CARBO-GEL, depending upon the oil type and the water content. Pilot testing is 

highly recommended when using unfamiliar oil. 

Table 5-5 

Appearance 

Hygroscopic 

pH in H 2 O 

Typical Physical Properties – CARBO-GEL 

Tan powder 

No 

n/a 

Bulk Density 45 lbm/ft 3 (720 kg/m 3 ) 



5-30 Revised 2006


CARBO-GEL ® II 

CARBO-GEL ® II is a gel-forming organophilic clay composed of a selected grade of montmorillonite 

clay reacted with a high-purity organic compound. As an economical viscosifier, CARBO-GEL II is 

used to increase yield point and gel strength, thus improving the carrying capacity of low-weight, oilbase 

fluids. It provides excellent solids suspension and remains stable at temperatures less than 285°F 

(140°C). The recommended treatment level is 4 to 8 ppb depending on the desired yield point. 

Table 5-6 Typical Physical Properties – CARBO-GEL II 

Appearance 

White/tan powder 

Hygroscopic 

pH in H 2 O 

No 

Neutral 


CARBO-MIX 

CARBO-MIX is a high activity emulsifier for use in CARBO-DRILL oil-base fluid systems. It will 

emulsify any chloride brine or water into any base oil, and provides filtration rate control and aids oilwetting 

of solids. CARBO-MIX is thermally stable to temperatures in excess of 204°C (400°F). 

CARBO-MIX is used as an emulsifier in the CARBO-DRILL S.E.A. oil-base fluid systems with 

oil/water ratios up to 40/60. In combination with CARBO-MUL ® HT, it provides thermally stable, 

high brine content emulsions. CARBO-MIX can be used in any type of oil-base fluid with any 

combination of CARBO-MUL HT or CARBO-TEC. Normally, 0.5 to 1.5 gal/bbl (11.9 to 35.7 L/m 3 ) 

of CARBO-MIX will be required in a CARBO-DRILL system, depending upon density and total 

solids content. 

Table 5-7 

Appearance 

Flash Point 

Pour Point 

Typical Physical Properties – CARBO-MIX 

Black viscous liquid 

104°F (40°C) (PMCC) 

16°F ( 9°C) 

Density 7.9 lbm/gal (952 kg/m 3 ) 

Viscosity 

800 to 1000 cp at 68°F (20°C) 



Revised 2006 5-31


CARBO-MUL ® / CARBO-MUL ® HT 

CARBO-MUL ® is an oil-soluble, modified imidazoline (CARBO-MUL ® HT is a high-temperature 

polyamide). Both are used as emulsifiers and wetting agents for the CARBO-DRILL family of oilbase 

fluid systems. 

CARBO-MUL is compatible with a wide range of internal phase salinities and can be used to emulsify 

calcium chloride and sodium chloride brines, seawater, and freshwater in oil-base fluids. CARBO- 

MUL is substantive (adsorbs on) to mineral surfaces, reducing interfacial surface energy and rendering 

MIL-BAR, other weight materials, and drill solids oil-wet. CARBO-MUL, unlike soap surfactants, 

does not require lime hydrate in order to function effectively and is an ideal surfactant for low-colloid, 

relaxed inverts such as the CARBO-FAST oil-base fluid system. 

CARBO-MUL is used as a combination emulsifier/wetting agent in the CARBO-FAST lowcolloid/relaxed-filtrate 

oil-base fluid system, when only modest filtration control is required. No 

filtration control additives, lime, or other surfactants are typically used in these high-penetration rate 

systems. 

CARBO-MUL is also used as the wetting agent/supplemental emulsifier in the CARBO-TEC 

controlled-filtrate oil-base fluid system. CARBO-MUL is used in conjunction with CARBO-TEC, 

lime, and filtration control additives in these more highly treated systems, and can be formulated to 

withstand temperatures in excess of 400°F (204°C). 

CARBO-FAST low-colloid/relaxed-filtrate oil-base fluid systems will require 0.4 to 0.75 gal/bbl (9.5 

to 17.9 L/m 3 ) of CARBO-MUL (used as a primary emulsifier/wetting agent), depending on the 

bottomhole temperatures, solids content, and type. CARBO-TEC controlled-filtrate oil-base fluid 

systems will require 0.12 to 1.0 gal/bbl (2.9 to 23.8 L/m 3 ) of CARBO-MUL applied under similar 

circumstances. Approximately 1.0 gal (3.8 L) of CARBO-MUL per 25 (100-lb) sacks of MIL-BAR is 

normally sufficient when used as a wetting agent at weight-up. 

Table 5-8 Typical Physical Properties – CARBO-MUL/CARBO-MUL HT 

PROPERTY CARBO-MUL CARBO-MUL HT 

Appearance Dark liquid Dark liquid 

Flash Point 60°F (16°C) (ASTM D56) 170°F (77°C) (ASTM D56) 

Pour Point 10°F ( 12°C) 23°F ( 5°C) 

Density 7.7 lbm/gal (924 kg/m 3 ) 8.0 lbm/gal (952 kg/m 3 ) 



5-32 Revised 2006


CARBO-TEC ® 

CARBO-TEC ® is an anionic emulsifier used with lime hydrate to provide temperature-stable 

emulsions of water or brines in oil. CARBO-TEC exhibits a high tolerance to contaminants and high 

temperatures. CARBO-DRILL systems, prepared from CARBO-TEC, have been formulated to 

withstand temperatures greater than 400°F (204°C). 

CARBO-TEC is compatible with a wide range of internal phase salinities and can be used to emulsify 

calcium chloride and sodium chloride brines, seawater, and freshwater. CARBO-TEC, together with 

lime hydrate, will provide moderate filtration control in oil-base fluids. CARBO-TEC contains no 

aromatic solvents. 

CARBO-TEC is used in controlled filtration oil-base fluid systems. It requires lime to function 

effectively, and is used in conjunction with CARBO-MUL HT and filtration control additives in these 

systems. 

CARBO-TEC controlled filtrate oil-base fluid systems will require 0.6 to 1.7 gal/bbl (14.3 to 40.5 

L/m 3 ). Lime should be added as the activator at a concentration of 5 lb m lime per gallon (0.6 kg/L) of 

CARBO-TEC. 

CARBO-TEC functions as a passive emulsifier in CARBO-CORE systems (see Chapter 6, Reservoir 

Application Fluids). Because lime and water are necessary to activate CARBO-TEC, it will have no 

emulsification properties in the CARBO-CORE SM system unless water is incorporated. 

Table 5-9 Typical Physical Properties – CARBO-TEC 

Appearance 

Dark liquid 

Flash Point > 200°F ( 93°C ) (ASTM D56) 

Pour Point 

13°F ( 11°C) 




Revised 2006 5-33


CARBO-TEC ® HW 

CARBO-TEC ® HW is a non-ionic emulsifier for the CARBO-DRILL mineral oil-base fluid system. It 

is compatible with all other products in the CARBO-DRILL system. CARBO-TEC HW has a strong 

affinity for solid surfaces and provides a high degree of oil-wetting ability in any type mineral oil. 

Treatment with CARBO-TEC HW will result in increased emulsion stability and lower plastic 

viscosities, particularly in heavily solids-laden fluids. CARBO-TEC HW is used to treat fluids where 

solids levels have risen to high levels and emulsion stability and rheological properties have been 

compromised as a result. It is particularly effective in high water content oil-base fluids and in high 

density fluids. Pilot testing is recommended in all cases to avoid over treatment. Over treatment can 

result in settling of barite. Concentration levels will vary from 0.1 gal/bbl (2.0 L/m 3 ) in low-weight 

systems to 0.5 gal/bbl (12.0 L/m 3 ) in high density, high solids systems. 

Table 5-10 Typical Physical Properties – CARBO-TEC HW 

Appearance 

Dark brown liquid 

Flash Point > 162°F (72°C ) 

Pour Point 

Specific Gravity 

< 14°F ( 10°C) 

0.84 S.G. (7.0 lbm/gal) 

CARBO-TEC ® S 

CARBO-TEC ® S is an unsaturated polymerized fatty acid blend used to provide supplemental 

emulsion stability in invert emulsion systems. CARBO-TEC S exhibits a high tolerance to 

contaminants and high temperatures. CARBO-DRILL systems prepared with CARBO-TEC S have 

been formulated to withstand temperatures in excess of 204ºC (400ºF). CARBO-TEC S is compatible 

with a wide range of internal-phase salinities and can be used to help emulsify calcium chloride and 

sodium chloride brines, seawater, and fresh water. 

CARBO-TEC S is a supplemental emulsifier used in the controlled-filtration oil mud system. 

CARBO-TEC S requires lime to function effectively, and is used in conjunction with CARBO-MUL 

or CARBO-MUL HT and filtration control additives in these systems. CARBO-TEC S should be 

added through the hopper or directly to the suction pit if sufficient agitation is available. 

Concentrations up to 0.6 gal/bbl (14.3 L/m 3 ) may be required for controlled-filtrate mud systems. 

Table 5-11 

Appearance 

Typical Physical Properties – CARBO-TEC S 

Yellow-amber liquid 

Flash Point >93º C (>200º F) 

Density 

955 kg/m 3 (7.9 lb/gal) 



5-34 Revised 2006


CARBO-TROL ® 

CARBO-TROL ® is a blend of high molecular weight organic polymers and inorganic bridging agents 

used to improve filtration control in oil-base fluid systems. CARBO-TROL will have a minimal 

rheological effect on the drilling fluid. CARBO-TROL is compatible with most synthetic and oil-base 

fluid systems. 

Treatments of CARBO-TROL will vary with the type of oil being used, temperatures to be 

encountered, and desired filtration control properties. Pilot testing is recommended to determine 

optimum concentration. Treatment levels of 2 to 10 lb m /bbl (5.7 to 28.5 kg/m 3 ) should be adequate 

for most applications. 

Table 5-12 Typical Physical Properties – CARBO-TROL 

Appearance 

Gray powder 

Hygroscopic 

pH in H 2 O 

No 

Neutral 


CARBO-TROL ® HT 

CARBO-TROL ® HT is a high-temperature softening-point gilsonite used to improve filtration control 

in the CARBO-DRILL and CARBO-CORE (no water) oil-base fluid systems with minimal effects on 

rheological properties. 

Treatments of 2.0 to 10 lb/bbl (5.7 to 28.5 kg/m 3 ) is adequate for most applications. Example: A 

425°F (218°C) CARBO-DRILL formulation treated with 5 lb m /bbl (14.3 kg/m 3 ) CARBO-TROL HT 

results in the reduction of the 350°F (177°C) HT/HP filtrate from 10.0 to 6.0 cm 3 . 

Table 5-13 Typical Physical Properties – CARBO-TROL HT 

Appearance 

Black powder 

Hygroscopic 

No 




Revised 2006 5-35


CARBO-VIS 

CARBO-VIS is an high-yielding organophilic bentonite clay used as the viscosifying and 

suspending agent in oil- and synthetic-base fluid systems. It increases the carrying capacity and hole 

cleaning characteristics of oil and synthetic-base fluids by imparting viscosity and gel building 

characteristics to diesel oil, crude oil, mineral oil, and synthetic fluids. CARBO-VIS can be used to 

condition CARBO-DRILL or other oil-base fluid systems for use as packer fluids. Concentrations of 

1 to 5 lb m /bbl (2.85 to 14.3 kg/m 3 ) are usually adequate for most uses. Good shear is recommended 

for proper blending. 

Table 5-14 Typical Physical Properties – CARBO-VIS 

Appearance 

Tan powder 

Hygroscopic 

pH in H 2 O 

No 

n/a 


CHEK-LOSS ® 

CHEK-LOSS ® is a water-insoluble, ultra-fine, complexed cellulosic material used for controlling 

seepage and loss of circulation while drilling through depleted or under-pressured zones. CHEK- 

LOSS can be maintained in a circulating system without bypassing the shale shakers. CHEK-LOSS is 

effective in bridging micro fractured and permeable formations to control seepage loss. 

Table 5-15 Typical Physical Properties – CHEK-LOSS 

Appearance 

Brown powder 

Hygroscopic 

No 

pH in H 2 O 3.5 



5-36 Revised 2006


CHEK-LOSS ® PLUS 

CHEK-LOSS ® PLUS is a water-insoluble, ultra-fine, cellulosic material used for controlling seepage 

and loss of circulation while drilling through depleted or under-pressured zones. CHEK-LOSS PLUS 

will not preferentially water-wet when used in conjunction with oil and synthetic-based emulsion 

systems. This feature minimizes the detrimental effect on the electrical stability often experienced 

when using other cellulosic fibers. CHEK-LOSS PLUS can be maintained in a circulating system 

without bypassing the shale shakers. CHEK-LOSS PLUS is effective in bridging micro fractured and 

permeable formations to control seepage loss. 

CHEK-LOSS PLUS reduces filter cake permeability and spurt losses which help prevent differential 

sticking. CHEK-LOSS PLUS is nontoxic, temperature stable in excess of 204 °C (400 °F), and has 

minimal effect on fluid rheology. CHEK-LOSS PLUS is functional in both water and oil mud 

systems. 

CHEK-LOSS PLUS can be mixed through the hopper to control seepage losses. Sufficient agitation is 

necessary to properly disperse CHEK-LOSS PLUS. It can also be used as a sweep or slug in cases of 

lost circulation. CHEK-LOSS PLUS can be used with HEC, starch, or other polymers in heavy brines 

for sealing perforations. 

The low acidity of CHEK-LOSS PLUS will require a supplemental treatment of soda ash when used 

in water-based muds (add 0.2 lb/bbl soda ash with each 10 lb/bbl of CHEK-LOSS PLUS). A 

concentration of 11.4 to 22.8 kg/m³ (4.0 to 8.0 lb/bbl) should be used to control seepage loss. For 

application as a sweep or slug, 85.5 kg/m³ (30.0 lb/bbl) can be mixed with mud in the slugging pit and 

spotted across the thief zone. 

Table 5-16 Typical Physical Properties – CHEK-LOSS PLUS 

Appearance 

Brown powder 

Hygroscopic 

No 

pH in H 2 O 3.5 

MAGMA-GEL 

MAGMA-GEL is a specialty product, wet processed organophilic clay used as a gellant/suspension 

agent in the MAGMA-TEQ HTHP oil-based mud system. MAGMA-GEL is temperature stable to > 

425º F (218º C). Its performance is complemented by MAGMA-TROL. 



Revised 2006 5-37


MAGMA-TROL 

MAGMA-TROL is a polymeric, oil soluble product designed for HTHP filtrate control and for use in 

the environmental and occupational hygiene regulated MAGMA-TEQ HTHP oil-based drilling fluid 

developed for use in drilling deviated North Sea wells. MAGMA-TROL is temperature stable to 

greater than 1112º F (600º C). It works independently of the base fluid and has a secondary effect 

benefit of suspension stabilization. MAGMA-TROL has been field tested to 458º F (237º C) 

Table 5-17 Typical Physical Properties – MAGMA-TROL 

Appearance 

White powder, dust 

Odor 

Solubility 

No characteristic odor 

Insoluble in water 

Specific gravity, 25º C 1.030 

MAGMA-VERT 

MAGMA-VERT is a specialized, high temperature, modified amide amine used as a supplementary 

emulsifier in the MAGMA-TEQ HTHP oil-based mud system. MAGMA-TEQ is a specialized 

system specifically developed for the drilling of HTHP deviated wells in the North Sea. The system 

and its associated products such as MAGMA-VERT meet the stringent environmental and 

occupational hygiene regulations established for this area. 

OMNI-COTE ® 

OMNI-COTE ® is a thinner and solids dispersing agent for synthetic- and oil-base fluid systems. It is 

used to lower rheological properties in both CARBO-DRILL and SYN-TEQ systems if the fine solids 

content becomes excessive. 

Treatments with OMNI-COTE will vary depending on the type and quantity of drill solids in the fluid 

system. Concentrations of 0.1 to 1.0 gal/ bbl (2.38 to 23.8 L/m 3 ) are typical levels used in the field. 

All treatments should be pilot tested to determine the optimum level. 

Table 5-18 

Appearance 

Solubility 

Typical Physical Properties – OMNI-COTE 

Amber liquid 

Water insoluble 

Specific Gravity, 25º C 1.030 



5-38 Revised 2006


OMNI-LUBE 

OMNI-LUBE is an environmentally accepted polymeric fatty acid solution, which will effectively 

reduce torque and drag in most emulsion based drilling fluids. Results obtained from field 

applications indicate that the friction in fluids treated with OMNI-LUBE can be lowered by up to 25% 

compared to untreated fluids, and torque is less erratic. It is a filming type extreme pressure lubricant 

and is particularly effective in lowering steel-to-steel friction. 

OMNI-LUBE is a liquid and will not screen out of the system. As a filming type lubricant, product 

depletion will occur and will be related to the coating of drill pipe and casing in the wellbore, filter 

cake in the open hole and cuttings generated by the drill bit. OMNI-LUBE is compatible with most 

emulsion systems and suitable both in high and low aromatic base fluid environments. 

Fluid properties are not adversely affected by additions of OMNI-LUBE and the HTHP fluid loss in 

emulsion systems treated with OMNI-LUBE will generally be lowered. General engineering practices 

with respect to pilot testing additions are recommended. 

Table 5-19 

Appearance 

Typical Physical Properties – OMNI-LUBE 

Yellow-brown liquid 

Flash Point (ASTM D56) > 250º C (482º F) 

Freezing Point - 33º C (- 27º F) 

Density 

970 – 990 kg/m 3 @ 20º C 

OMNI-MIX 

OMNI-MIX is an anionic emulsifier formulation used in synthetic- and oil-base fluid systems. It is 

used as a supplemental emulsifier with OMNI-TEC and OMNI-MUL when additional fluid loss 

control is required or when needed to control water breakout and water wet solids. OMNI-MIX 

increases emulsion stability and significantly lowers the HTHP fluid loss of any hydrocarbon external 

phase system. Synthetic-base drilling fluid systems usually require 0.5 to 1.5 gal/bbl (11.91 to 35.71 

L/m 3 ) of OMNI-MIX, depending on density, total solids loading, and temperature design. 

Table 5-20 

Appearance 

Flash Point 

Typical Physical Properties – OMNI-MIX 

Black viscous liquid 

> 212° F (100° C) (PMCC) 

Pour Point 16° F ( 9° C) 


Viscosity 800 to 1000 cp at 68° F (20° C) 



Revised 2006 5-39


OMNI-MUL ® 

OMNI-MUL ® is a high-temperature, environmentally safe, polyamide used as a non-ionic emulsifier 

and wetting agent in synthetic and oil-base fluid systems. It readily stabilizes fluids under minimal 

shear, is compatible with a wide range of internal phase salinities, and can be used to emulsify calcium 

chloride and sodium chloride brines, seawater, and freshwater. OMNI-MUL is substantive (adsorbs 

on) to mineral surfaces, reducing interfacial surface energy and is a synthetic wetting agent for MIL- 

BAR, drilled solids, etc. Synthetic-base fluid systems usually require 0.5 to 1.5 gal/bbl (11.9 to 35.7 

L/m 3 ) of OMNI-MUL (used as the primary emulsifier), depending on the bottomhole temperature, 

density, and drilled solids content. 

Table 5-21 Typical Physical Properties – OMNI-MUL 

Appearance 

Dark brown 

Specific Gravity 0.928 

Flash Point 

> 200° F (93.3° C) (PMCC) 

Pour Point 40° F (4.4° C) 

pH (5% solution) 3.75 

OMNI-PLEX ® 

OMNI-PLEX ® is an anionic synthetic polymer supplied in emulsion form. It can be used alone or in 

conjunction with amine-treated organophilic clays. It is compatible with most additives commonly 

used in low toxicity mineral oil- and synthetic-base drilling fluids and is not affected by gas kicks or 

H 2 S contamination. OMNI-PLEX is thermally stable at temperatures exceeding 400° F (204° C). 

OMNI-PLEX increases viscosity levels in low toxicity mineral oil- and synthetic-base invert emulsion 

drilling fluids. It contributes primarily to YP and gel strength to provide carrying capacity for cuttings 

and suspension of weighting materials. OMNI-PLEX is added as needed to control low shear 

rheology. Normally, 1 to 4 ppb is adequate. 

Table 5-22 

Appearance 

Typical Physical Properties – OMNI-PLEX 

White liquid 

Flash Point > 250° F (121° C) 

Specific Gravity 1.08 - 1.12 



5-40 Revised 2006


OMNI-TEC ® 

OMNI-TEC ® is an anionic emulsifier used with lime hydrate to provide temperature-stable emulsions 

of water or brines in synthetic and oil-base fluid systems. OMNI-TEC exhibits a high tolerance to 

contaminants and high temperatures. SYN-TEQ systems, prepared with OMNI-TEC, have been 

formulated to withstand temperatures in excess of 400°F (204°C). 

OMNI-TEC is compatible with a wide range of internal phase salinities and can be used to emulsify 

calcium chloride and sodium chloride brines, seawater, and freshwater. OMNI-TEC, together with 

lime hydrate, will provide moderate filtration control in synthetic-base fluids. OMNI-TEC contains no 

aromatic solvents. 

OMNI-TEC is the primary emulsifier used in the SYN-TEQ SM synthetic-base fluid system. It requires 

lime to function effectively, and is used in conjunction with OMNI-MUL and filtration control 

additives in this system. Together with lime, it is recommended for increasing the thermal and 

electrical stability of all synthetic-base fluid systems. 

OMNI-TEC controlled filtrate synthetic-base fluid systems will require 0.6 to 1.7 gal/bbl (14.3 to 40.5 

L/m 3 ). Lime should be added as the activator at a concentration of 5 lb m lime per gallon of OMNI- 

TEC (0.6 kg/L). 

Table 5-23 

Appearance 

Flash Point 

Typical Physical Properties – OMNI-TEC 

Dark, brown liquid 

> 400° F ( 204° C ) (PMCC) 

Specific Gravity 0.98 



Revised 2006 5-41


OMNI-TROL / CARBO-TROL ® A-9 

OMNI-TROL / CARBO-TROL ® A-9 are temperature-stable organophilic lignites used to control 

filtration in oil- and synthetic-base fluid systems. Both provide non-asphaltic filtration control in the 

CARBO-DRILL/SYN-TEQ family of oil/synthetic fluids. OMNI-TROL / CARBO-TROL A-9 are 

readily dispersible in all oil and synthetic-base fluids, reduce filtration in oil/synthetic drilling fluids, 

and stabilize water-in-oil emulsions at temperatures not exceeding 350° F (177° C). 

Treatment levels of OMNI-TROL / CARBO-TROL A-9 will vary depending on the type of 

oil/synthetic fluid used, bottomhole temperatures encountered, and filtration control desired. 

Concentrations of 5 to 10 lb m / bbl (14.3 to 28.5 kg/m 3 ) should be adequate for most applications. 

Table 5-24 

Typical Physical Properties – OMNI-TROL / CARBO-TROL 

Appearance 

Black powder 

Hygroscopic 

pH in H 2 O 

Slightly 

Neutral 

6-UP 


6-UP is a 100% active liquid rheology modifier. It is used to increase low-shear rheology in all oilbase 

fluid systems and is effective in improving the 3 rpm and 6 rpm readings of an oil-base fluid 

without causing an increase in plastic viscosity. 6-UP is compatible with both sodium and calcium 

chloride internal phases and functions in fluids with oil/water ratios ranging from 40/60 to 90/10. 6- 

UP is thermally stable at temperatures up to 300° F (149° C) and functions under conditions of both 

high and low shear. 

6-UP can be added directly to the active fluid system, but should be added as the last ingredient (when 

mixing at the rig site) to achieve full affect. Mix the fluid as normal. Add the 6-UP only after the 

emulsion has formed and the barite has been fully wetted. 

Treatment levels are typically in the range of 0.1 to 0.4 gal/bbl (2 to 10 L/m 3 ). The final treatment 

level depends on fluid weight, oil/water ratio, and the level of increase required for the 6 rpm reading. 

High fluid weights and low oil/water ratios require the smallest treatment levels. 

Table 5-25 

Appearance 

Typical Physical Properties – 6-UP 

Pale, yellow liquid 

Flash Point 210° F (99° C) 

Pour Point > 32° F (0° C) 

Density 

0.99 g/mL 



5-42 Revised 2006


Oil mud product safety and handling 

Utilize normal precautions of employee protection when handing chemical products. Use of an 

appropriate respirator, gloves, goggles, and apron are recommended for employee comfort and 

protection. Material Safety Data Sheets are available and should be reviewed to prior to product use. 

The liquid oil-base fluid products usually contain flammable or combustible liquids and must not be 

stored around heat, sparks, or open flames. Empty containers should not be reused. 

Field mixing procedures 

1. Measure the appropriate amount of base fluid (oil or ISO-TEQ) into the mixing tank and 

circulate the oil through the hopper and fluid guns. 

2. Add CARBO-VIS or CARBO-GEL slowly to the base fluid through the hopper until well dispersed. 

3. Add proper amount of OMNI-MUL or CARBO-MUL HT through the hopper until mixed 

homogeneously with the base fluid. This should take approximately 30 minutes. 

4. For CARBO-TEC formulations add the appropriate amount of CARBO-TEC and lime through the 

hopper and allow mixing for a minimum of 45 minutes. 

5. Add brine water slowly through the hopper and allow mixing for 45 minutes. 

Note: 

If the brine water has to be made in the mixing plant by adding sacked salt to water, this 

would become the first step. 

6. For a CARBO-TEC / SYN-TEQ formulation, add the appropriate amount of CARBO-TROL or 

CARBO-TROL A-9, CARBO-TROL HT, or OMNI-TROL TM through the hopper and allow mixing 

for a minimum of 45 minutes. 

7. Add proper amount of weight material to attain desired fluid weight. To insure proper wetting and 

dispersion, slow the additions of weight material as fluid weight increases. Periodically during 

weight-up, check yield point, gels, and emulsion stability to insure proper barite suspension and that a 

stable emulsion is being formed. Slower additions of weight material may be necessary if inadequate 

shear exists and emulsion stability is not stable or is decreasing. If problems arise, refer to the 

troubleshooting information in Table 6-5 located toward the end of the chapter. 

Special rig equipment and precautions 

1. A fluid-saver box should be installed with a hose connected to the flow line to save fluid lost 

from connections and tripping the drill string. 

2. Pipe wipers will help keep the outside of the drill pipe clean during trips. 

3. High-speed shakers and fluid cleaners with the smallest screens possible are highly 

recommended. 

4. If lost circulation is a possibility, a frac tank for oil-base fluid storage on location is 

recommended. 

5. The pits should be covered if located in a rain prone area to prevent water contamination. 

6. All water valves should be closed off or disconnected around the pits to prevent inadvertent water 

contamination. 

7. Shaker screens and fluid cleaner screens should be cleaned with spray from an air gun equipped with 

an oil siphon. 



Revised 2006 5-43


8. Do not use plastic or phenolic resin type materials for lost circulation. 

9. Steam cleaners may be needed for general rig clean up. MIL-CLEAN ® diluted in water is an 

excellent cleaner for oil mud coated equipment. 

10. Volume control and dilution should be conducted with virgin drilling fluid whenever possible. 

Displacement procedures 

Displacement can occur either in casing or open hole with cased hole preferred. Prior to displacement, 

the drilling fluids engineer should make certain all pits and lines are as clean as possible. It is not 

uncommon to run a slug of base oil through the lines to clean and oil wet them. The trap doors on the 

pits can be packed with barite if necessary to help prevent leakage. 

The water-base fluid to be displaced should be diluted back to reduce yield point and gel strengths. 

This will help prevent contamination of the oil-base fluid. A water spacer of sufficient volume to 

occupy 500 to 1000 feet of annular volume should be used to chase the water-base fluid up the hole. 

This will thin the water-base fluid and thicken the oil-base fluid to help hole cleaning and removal of 

the water-base filter cake. During displacement, the drill pipe should be rotated and reciprocated 

along with a high pump rate to help prevent channeling. Once displacement commences, the pumps 

should not be shut down. 

The total strokes should be calculated for the spacer to come around to the shaker. This will help 

locate the interface. The shakers should be bypassed to remove the water-base fluid to a reserve or 

waste pit. Contaminated oil-base fluid found at the interface should also be discarded (see Table 5-26 

Troubleshooting). 



5-44 Revised 2006


Low emulsion 

stability 

Water wetting 

of solids 

Table 5-26 

Dull, grainy appearance to fluid 

High HT/HP fluid loss. 

Free H 2 O in HT/HP filtrate. 

Barite setting out. 

Blinding of shaker screens. 

Extreme cases can cause water 

wetting of solids. 

Flocculation of barite on sandcontent 

test. 

Sticky cuttings. 

Blinding of shaker screens. 

Settling of barite. 

dull, grainy appearance of fluid. 

Low electrical stability (ES). 

Free H 2 O in HT/HP filtrate. 

High filtration High HT/HP filtrate with 

increasing free H 2 O. 

Low electrical stability (ES). 

Fill on connections and trips. 

Sloughing shale. 

High 

viscosity 

Sloughing 

shale 

High PV, high YP. 

Increasing funnel viscosity. 

Increasing retort solids. 

Increase in water content. 

Fill on connections and trips. 

Torque and drag. 

Cuttings increase across shaker. 

Barite setting Low YP and gels. 

Settling of barite in heating cup. 

Lost 

circulation 

Problem 

mixing fluid at 

mixing plant 

Pit volume decreases. 

Loss of returns. 

Poor emulsions stability. 

Barite settling. 

Dull, grainy appearance to fluid. 

Fluid very thin with no yield or 

gel strengths. 

Troubleshooting Emulsion Fluid Systems 

1. Low emulsifier 

2. Super-saturated with CaCl 2 

3. Water flows 

4. Mixing fluid at mixing plant 

1. Inadequate emulsifiers 

2. Water fluid contamination 

3. Super saturated CaCl 2 

1. Low emulsifier content. 

2. Low concentration of fluid 

loss control additives. 

3. High bottom hole 

temperature. 

1. Add CARBO-MUL HT / OMNI-MUL. Add 

CARBO-TEC and lime if CARBO-TEC system. 

2. Dilute back with fresh H 2 O and add CARBO- 

MUL HT / OMNI-MUL. 

3. Add CARBO-MUL HT / OMNI-MUL. Can also 

add CARBO-TEC and lime if CARBO-TEC 

system. 

4. Maximize shear. Check electrolyte content (the 

higher the content, the harder the emulsion is to 

form) 

1. Add CARBO-MUL HT / OMNI-MUL and 

OMNI-COTE. 

2. Add CARBO-MUL HT / OMNI-MUL and 

OMNI-COTE. 

3. Dilute with fresh H 2 O and add CARBO-MUL 

HT / OMNI-MUL 

1. Add CARBO-MUL HT / OMNI-MUL. Add 

CARBO-TEC and lime if CARBO-TEC system. 

2. Add CARBO-TROL A-9 / OMNI-TROL and/or 

CARBO-TROL 

3. Add more CARBO-MUL HT / OMNI-MUL. 

Add CARBO-TEC and lime. Convert to CARBO- 

TEC system. Add more CARBO-TROL A-9 / 

OMNI-TROL and CARBO-TROL 

1. High solids content. 1. Dilute with oil, maximize solids-control 

2. Water contamination equipment. Add emulsifiers. 

3. Over treatment w/emulsifiers, 2. Add emulsifiers. If severe, also add OMNI- 

COTE. 

especially CARBO-TEC 

3. Dilute with oil 

1. Drilling under-balanced 

2. Excessive filtrate. 

3. Inadequate hole cleaning. 

4. Activity too low. 

1. Poor oil wetting of barite 

2. Inadequate suspension. 

3. Low ES, high HT/HP 

1. Increase fluid weight. 

2. Add emulsifiers. Add CARBO-TROL A-9 / 

OMNI-TROL and/or CARBO-TROL. 

3. Add CARBO-GEL to increase yield point. 

4. Adjust CaCl 2 content of internal phase to match 

formation activity. 

1. Add emulsifiers and /or wetting agents. Slow 

addition of barite. 

2. Add CARBO-GEL or viscosifying polymer. 

3. Add emulsifier. 

1. Hydrostatic pressure is greater 1. Add mica or plug. Never add fibrous or 

than formation pressure. phenolic-resin materials. If possible, reduce fluid 

weight. 

1. Inadequate shear. 

2. Very cold. 

3. Poor wetting of barite. 

4. High electrolyte content. 

Normally greater than 

350,000 ppm. 

5. Surfactant contamination 

1. Maximize the shear. 

2. Lengthen mixing times. 

3. Slow additions of barite. Add CARBO-MUL HT 

/ OMNI-MUL. If severe, add small amount of 

OMNI-COTE. 

4. Dilute back with fresh H 2 O. Once emulsion if 

formed, can add additional CaCl 2 to obtain desired 

activity. 

possible if using CaCl 2 brine that 

5. Pilot test with known CaCl 

has been used as completion or 

2 brine to determine if 

problem does exist 

work over fluid. 

It is recommended that all fluid treatments and mixing procedures be confirmed with the fluids 

coordinator prior to being initiated. Pilot testing is always recommended prior to commencing actual 

treatment of the active system. 



Revised 2006 5-45


Solids control with oil mud 

The removal of solids in oil muds is different than in a water based mud. Cuttings generated by the bit 

tend to remain more competent, making the shale shaker a much more efficient solids removal device. 

At the same time, due to the viscosity of the oil phase, hydrocyclones and centrifuges become less 

efficient. The waste generated by these devices also contains a high percentage of oil mud which can 

result in disposal problems. 

The problem becomes one of preventing solids build up in the system. It is therefore imperative to 

maximize the use of solids control equipment to remove as much of the unwanted solids as possible. 

Drill solids that are not removed by solids control equipment must be diluted. Dilution not only is 

very expensive, but it creates mud volume control problems. 

Oil muds have a very expensive liquid phase. This phase consists of base oil, brine, and surfactants. 

As we increase the density of oil muds, the cost of the solids phase goes up, but the liquid phase 

continues to be expensive. This forces us to re-think our usage of equipment. Refer to for an 

example of oil mud costs vs. density. 

In water base muds, the liquid phase is expensive when unweighted. As we weight up, at some 

density the cost of the barite becomes more expensive that the liquid phase. At higher density, we 

now concentrate our solids control on barite recovery. This is never the case with oil muds. 

Solids 

The removal of drill solids is important for the control of any mud system. It is of particular 

importance in water based fluids because of the magnitude and variety of adverse effects the solids can 

have on the system. However, in oil based mud systems, solids have historically been only 

superficially considered. This is primarily the result of the fact that in properly conditioned fluids 

there are no active drilled solids. 

It has become apparent through the use of relaxed filtrate oil based fluids that when rate of penetration 

is considered, solids have the same detrimental effect in oil based fluids as they do in water based 

muds. As the solids content increases, the rate of penetration decreases. In addition, if the solids 

remain in the system, they require treatment with oil wetting agents to maintain fluid properties and 

stability, thus adding to the expense of the system. 

If solids do build up, the standard technique of dumping and diluting is not viable because of the 

expense involved in dilution and the expense involved with disposal of the waste mud. Treatment of 

the system to reduce the effects of solids on flow properties is effective to a certain point. Surfactants 

can be added and the oil-water ratio can be increased to partially offset the effects incorporated solids. 

Nevertheless, a point will be reached where the colloidal solids content will no longer be affected by 

surfactants and the oil-water ratio can no longer be effectively increased. When this occurs, the rate of 

penetration of the fluid will already have been reduced to that of a conventional mud and the control of 

rheological properties can only be accomplished by dumping mud and diluting with oil. 



5-46 Revised 2006


Figure 5-21 

Diagram of Costs vs. Mud Weight 

As Figure 5-21 indicates, weighted muds have both an expensive liquid and solids phase. We 

therefore want to save both the liquid phase and the barite. This can be a difficult task. 

Figure 5-22 shows a flow diagram for a low to unweighted oil mud. The desander may be bypassed, 

or if run, the underflow could be screened. A mud cleaner would be used to remove sand and save 

mud. A high volume centrifuge would be used to dispose of solids. All solids should be disposed of, 

including barite, until the cost of barite is greater than the cost of dilution. 



Revised 2006 5-47


Figure 5-22 

Flow Diagram for a Low to Unweighted Oil Mud 

When using a weighted oil mud, the flow diagram shown in may be required. The mud cleaner would 

be run to remove sand and other larger particles. The centrifuge would be run for viscosity control (to 

remove fine solids). 



5-48 Revised 2006


Figure 5-23 

Flow Diagram for a Weighted Oil Mud 

Figure 5-24 

Flow Diagram for a Two-Stage Centrifuge for Medium to High Weight Oil Muds 

In Figure 5-24 it shows a two-stage centrifuge. The flow diagram is applicable to a medium to high 

weight oil mud. The concept is to use the first centrifuge to recover barite. The centrifuged mud 

would then be fed to a second centrifuge which would remove and discard fine solids. The “clean” 

mud would then be put back into the mud system and also be used for dilution of the first centrifuge. 

It has been found that as long as the “clean” mud weights 9.0 ppg or less, this procedure is 

economical. At some point in time, whole mud will have to be removed from the system for viscosity 

control. 

Shakers and centrifuges are the two primary defenses against solids build up in oil muds. Shakers 

remove a large portion of drill solids, as cuttings remain more competent in oil muds. Shakers and 

centrifuges discard the least whole mud with the solids they remove. 



Revised 2006 5-49


Salts 

Since most salts will not dissolve in oil based fluids, salts take on the aspect of just another solid in the 

system. Some small quantity of a particular salt may dissolve in the internal phase (i.e. emulsified 

water) of the mud, but this will be relatively insignificant and will generally have no effect on the 

stability of the fluid. Depending upon the type of emulsifier used, salts that may dissolve in the water 

phase may react adversely with the emulsifier. This occurs primarily when massive quantities of 

magnesium containing salts are encountered. 



5-50 Revised 2006


Formulation Tables 

CARBO-DRILL fluid formulation tables 

Table 5-27 CARBO-DRILL Products Required to Build 100 bbl of CARBO-TEC Oil Fluid: 70/ 30 

and 80/20 Oil/Water Ratios 

Maximum Temperature °F ( °C ) 

Products 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 

CARBO-TEC, gal 

CARBO-MUL HT, gal 

CARBO-TROL, 50 lb sacks 

MIL-LIME TM , 50 lb sacks 

110 

25 

10 

9 

130 

50 

15 

11 

170 

62.5 

20 

14 

170 

75 

30 

14 

190 

125 

30 

16 

70/30 OIL/WATER RATIO 

Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS TM 

(50 lb sacks) 

MIL-BAR 

(100 lb sacks) 

8.0 

8.5 

9.0 

9.5 

10.0 

66 

65 

64 

63 

61 

30 

30 

29 

29 

28 

4 

4 

5 

5 

5 

0 

27 

55 

82 

109 

10.5 

11.0 

11.5 

12.0 

12.5 

60 

59 

58 

56 

55 

27 

27 

26 

26 

25 

5 

5 

5 

5 

5 

136 

164 

191 

218 

245 

13.0 

13.5 

14.0 

14.5 

15.0 

54 

52 

51 

50 

48 

25 

24 

24 

23 

23 

5 

5 

5 

5 

5 

272 

299 

327 

354 

381 


Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS 

(50 lb sacks) 

MIL-BAR (100 lb 

sacks) 

16.0 

16.5 

17.0 

17.5 

18.0 

53 

51 

50 

48 

47 

14 

14 

14 

13 

13 

5 

5 

5 

5 

5 

445 

471 

499 

525 

552 

18.5 

19.0 

19.5 

20.0 

45 

44 

42 

41 

12 

12 

12 

11 

4 

4 

3 

3 

579 

606 

633 

659 

*Saturated NaCl or 250,000 ppm CaCl 2 water 



Revised 2006 5-51


Table 5-28 CARBO-DRILL Products Required to Build 100 bbl of CARBO-TEC Oil Fluid: 85/15 

Oil/Water Ratio 


Products 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 





100 

25 

10 

8 

115 

50 

20 

9 

140 

62.5 

20 

11 

160 

75 

30 

13 

180 

112 

30 

16 


Fluid Weight 

(lb m /gal) 

8.0 

8.5 

9.0 

9.5 

10.0 

10.5 

11.0 

11.5 

12.0 

12.5 

13.0 

13.5 

14.0 

14.5 

15.0 

15.5 

16.0 

16.5 

17.0 

17.5 

18.0 

18.5 

19.0 

Diesel 

(bbl) 

82 

80 

79 

77 

76 

74 

72 

71 

69 

68 

66 

65 

63 

62 

60 

59 

57 

56 

54 

52 

51 

49 

48 

Brine* 

(bbl) 

15 

14 

14 

14 

14 

13 

13 

13 

13 

12 

12 

12 

12 

11 

11 

11 

10 

10 

10 

10 

9 

9 

9 

CARBO-VIS TM 

(50 lb sacks) 

9 

9 

9 

9 

9 

9 

9 

9 

9 

8 

8 

8 

8 

8 

7 

7 

7 

7 

7 

7 

5 

5 

5 

MIL-BAR 


18 

50 

76 

103 

129 

156 

182 

209 

236 

262 

289 

316 

342 

369 

395 

422 

449 

475 

502 

528 

555 

582 

608 


The volumes and densities are accurate to ± 1%. Because it is not possible for a table to show formulations with 

numerous internal phase salinities and temperature stabilities, it is recommended that a material balance approach be 

utilized prior to the formulation of large quantities of CARBO-DRILL 



5-52 Revised 2006


Table 5-29 CARBO-DRILL Products Required to Build 100 bbl of CARBO-TEC Oil Fluid: 90/10 

and 95/5 Oil/Water Ratios 


Products 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 





85 

25 

10 

5 

100 

50 

20 

6 

125 

62.5 

20 

7 

140 

100 

30 

12 

170 

125 

30 

14 

90/10 Oil/Water Ratio 

Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS TM 

(50 lb sacks) 

MIL-BAR 


7.6 

8.0 

8.5 

9.0 

9.5 

88 

86 

85 

83 

82 

10 

10 

10 

10 

9 

10 

10 

10 

10 

10 

0 

22 

49 

75 

102 

10.0 

10.5 

11.0 

11.5 

12.0 

80 

78 

77 

75 

73 

9 

9 

9 

8 

8 

10 

10 

10 

10 

10 

129 

156 

183 

210 

236 

12.5 

13.0 

13.5 

14.0 

14.5 

15.0 

72 

70 

69 

67 

65 

63 

8 

8 

8 

8 

8 

7 

10 

10 

10 

10 

10 

10 

263 

290 

317 

343 

370 

397 


Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS 

(50 lb sacks) 


sacks) 

16.0 

16.5 

17.0 

17.5 

18.0 

62 

61 

59 

57 

56 

3 

3 

3 

3 

3 

8 

8 

8 

8 

7 

471 

499 

526 

553 

579 

18.5 

19.0 

19.5 

20.0 

54 

52 

50 

49 

3 

3 

3 

3 

5 

4 

3 

2 

606 

633 

660 

687 


The volumes and densities are accurate to ± 1%. Because it is not possible for a table to show formulations with 





Revised 2006 5-53


Table 5-30 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST ® Oil Fluid: 

70/30 and 80/20 Oil/Water Ratios 


Product 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 

CARBO-MUL HT, gal* 40 + 50 + 60 + 70 + 75 + 

* + 1 gal additional CARBO-MUL HT / OMNI-MUL required per 25 100-lb sacks MIL-BAR ® 


Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS TM 

(50 lb sacks) 

MIL-BAR(100 lb 

sacks) 

8.0 

8.5 

9.0 

9.5 

10.0 

70 

68 

67 

66 

65 

30 

29 

29 

28 

28 

8 

8 

8 

8 

8 

0 

29 

59 

82 

110 

10.5 

11.0 

11.5 

12.0 

12.5 

64 

62 

61 

60 

58 

27 

27 

26 

26 

25 

8 

8 

8 

8 

8 

136 

163 

191 

218 

245 

13.0 

13.5 

14.0 

14.5 

15.0 

57 

56 

55 

53 

52 

24 

24 

23 

23 

22 

8 

8 

8 

8 

8 

272 

299 

327 

353 

380 


Fluid Weight 

(lb m /gal) 

Diesel 

(bbl) 

Brine* 

(bbl) 

CARBO-VIS 

(50 lb sacks) 


sacks) 

15.5 

16.0 

16.5 

17.0 

58 

56 

55 

54 

14 

14 

14 

13 

8 

8 

8 

8 

408 

436 

463 

490 

17.5 

18.0 

18.5 

19.0 

52 

50 

49 

48 

13 

12 

12 

12 

8 

6 

6 

6 

516 

544 

572 

598 

*Saturated NaCl or 250,000 ppm CaCl 2 

The volumes and densities are accurate to ± 1 %. Because it is not possible for a table to show formulations with 





5-54 Revised 2006


Table 5-31 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST Oil Fluid: 



Product 200 (93) 250 (121) 300 (149) 350 (177) 400 (204) 

CARBO-MUL HT, gal* 40 + 50 + 60 + 70 + 75 + 

* + 1 gal addition CARBO-TROL HT /OMNI-MU required per 25 100-lb sacks MIL-BAR 


Fluid Weight 

(Lbm/gal) 

8.0 

8.5 

9.0 

9.5 

10.0 

Diesel 

(bbl) 

84 

82 

81 

79 

76 

Brine* 

(bbl) 

15 

14 

14 

14 

13 

CARBO-VIS TM 

(50 lb sacks) 

8 

8 

8 

8 

8 

MIL-BAR(100 lb sacks) 

18 

50 

76 

103 

129 

10.5 

11.0 

11.5 

12.0 

12.5 

74 

73 

71 

70 

70 

13 

13 

13 

12 

12 

8 

8 

8 

8 

8 

156 

182 

209 

236 

262 

13.0 

13.5 

14.0 

14.5 

15.0 

68 

67 

65 

64 

62 

12 

12 

12 

11 

11 

8 

8 

7 

7 

7 

289 

316 

342 

369 

395 

15.5 

16.0 

16.5 

17.0 

17.5 

61 

59 

58 

56 

54 

11 

10 

10 

10 

10 

7 

6 

6 

6 

6 

422 

449 

475 

502 

528 

18.0 

18.5 

19.0 

53 

51 

50 

9 

9 

9 

5 

5 

5 

555 

608 

608 







Revised 2006 5-55


Table 5-32 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-FAST Oil Fluid: 


Manimum Temperature °F (°C) 

Product 200 (93) 

CARBO-MUL HT, gal* 40 + 250 (121) 300 (149) 350 (177) 400 (204) 

* + 1 gal addition CARBO-TROL HT /OMNI-MU required per 25 100-lb sacks MIL-BAR ® 


Fluid Weight, 

(lb m /gal) 

Diesel, 

(bbl) 

Brine*, 

(bbl) 

CARBO-VIS 

(50 lb sacks) 


sacks) 

8.0 

8.5 

9.0 

9.5 

10.0 

88 

86 

84 

83 

81 

9.7 

9.6 

9.4 

9.2 

9.0 

10 

10 

10 

10 

10 

36 

62 

89 

115 

142 

10.5 

11.0 

11.5 

12.0 

12.5 

80 

78 

76 

75 

73 

8.9 

8.6 

8.5 

8.3 

8.1 

10 

10 

10 

10 

8 

169 

195 

222 

247 

275 

13.0 

13.5 

14.0 

14.5 

15.0 

72 

70 

68 

67 

65 

7.9 

7.8 

7.6 

7.4 

7.2 

8 

8 

8 

8 

7 

301 

328 

354 

380 

408 

15.5 

16.0 

16.5 

17.0 

17.5 

63 

62 

60 

59 

57 

7.0 

6.8 

6.7 

6.5 

6.3 

7 

7 

7 

6 

6 

434 

460 

486 

513 

541 

18.0 

18.5 

19.0 

55 

54 

52 

6.1 

6.0 

5.8 

6 

6 

6 

566 

593 

620 







5-56 Revised 2006


Table 5-33 

Fluid 

Weight, 

(lb m /gal) 

CARBO-DRILL Products Required to Build 100 bbl 50/50 and 55/45 Oil/Brine Ratios 

MINERAL 

OIL 

(bbl) 

BRINE*, 

(bbl) 

CARBO- 

MUL, 

(gal) 

50/50 OIL/BRINE RATIO 

CARBO- 

MIX, 

(gal) 

CARBO- 

TEC HW, 

(gal) 

MIL- 

LIME, 

(50 lb 

sacks) 

CARBO- 

GEL N, 

(50 lb 

sacks) 

9.0 45 49 95 54 - 8 1.5 22 

9.5 44 48 100 57 - 8 1.5 50 

10.0 43 47 105 60 - 8 1.5 77 

10.5 42 46 123 70 - 8 1.5 105 

11.0 40 45 140 80 - 8 1.5 133 

11.5 39 44 147 84 - 8 1.5 161 

12.0 37 43 154 88 10 8 1.5 188 

55/45 OIL/BRINE RATIO 

13.0 39 37 160 90 20 8 1.5 250 

13.5 38 36 175 100 25 8 1.5 276 

14.0 35 35 190 110 30 8 1.5 306 


MIL- 

BAR, 

(100 lb 

sacks) 

The volumes and densities are accurate to ±1%. Because it is not possible for a able to show formulations with numerous 

internal phase salinities and temperature stabilities, it is recommended that a material balance approach be utilized prior to the 

formulation of large quantities of CARBO-DRILL. 



Revised 2006 5-57


Table 5-34 

Fluid 

Weight, 

(lb m /gal) 

CARBO-DRILL Products Required to Build 100 bbl of CARBO-CORE Oil Fluid 

OIL, 

(bbl) 

CARBO- 

GEL, 

(50 lb sacks) 

ELASTOMERIC 

POLYMER, 

(25 lb sacks) 

MIL- 

LIME, 

(50 lb 

sacks) 

CARBO- 

TEC, 

(gal) 

CARBO- 

TROL HT, 

50 lb sacks) 

MIL-BAR, 

(100 lb 

sacks) 

7.2 98 31 6.0 2 24 24 - 

7.5 97 30 5.0 2 24 23 12 

8.0 95 28 4.5 2 24 22 39 

8.5 93 26 4.0 2 24 22 66 

9.0 92 25 4.0 2 24 22 93 

9.5 90 24 4.0 2 24 22 120 

10.0 88 22 3.5 2 24 21 147 

10.5 86 21 3.0 2 24 21 174 

11.0 85 19 3.0 2 24 20 201 

11.5 83 18 3.0 2 24 20 227 

12.0 81 16 2.5 2 24 19 254 

12.5 79 15 2.5 2 24 19 281 

13.0 78 14 2.0 2 24 19 308 

13.5 76 13 2.0 2 24 18 335 

14.0 74 12 2.0 2 24 18 361 

14.5 72 11 2.0 2 24 17 388 

15.0 71 9 1.5 2 24 17 415 

15.5 69 9 1.5 2 24 17 441 

16.0 67 8 1.2 2 24 16 468 

16.5 65 7 1.2 2 24 16 495 

17.0 63 6 1.0 2 24 15 521 

17.5 62 6 1.0 2 24 15 548 

18.0 60 5 1.0 2 24 15 575 

18.5 59 5 1.0 2 24 14 603 

19.0 57 4 0.5 2 24 14 630 


internal phase salinities and temperature stabilities, it is recommended that a material balance approach be utilized prior to the 

formulation of large quantities of CARBO-DRILL. 



5-58 Revised 2006


SYN-TEQ fluid formulation tables 

Table 5-35 Products Required to Build 100 bbl of SYN-TEQ Fluid: 70/30 and 80/20 

Synthetic/Water Ratios (SWR) 

Maximum Temperature ºF (ºC) 

Products Prod 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 

OMNI-TEC TM , gal 

OMNI-MUL TM , gal 

OMNI-TROL TM , 50 lb sacks 


110 

25 

10 

9 

130 

50 

15 

11 

170 

62.5 

20 

14 

70/30 SWR 

ISO-TEQ, 

Brine,* CARBO-GEL, 

(bbl) 

(bbl) 

(50 lb sacks) 

8.0 66 30 4 0 

8.5 65 30 4 27 

9.0 64 29 5 55 

9.5 63 29 5 82 

10.0 61 28 5 109 

Fluid Weight, 

(lb m /gal) 

170 

75 

30 

14 

190 

125 

30 

16 

MIL-BAR, 


10.5 60 27 5 136 

11.0 59 27 5 164 

11.5 58 26 5 191 

12.0 56 26 5 218 

12.5 55 25 5 245 

13.0 54 25 5 272 

13.5 52 24 5 299 

14.0 51 24 5 327 

14.5 50 23 5 354 

15.0 48 23 5 381 

80/20 SWR 

16.0 53 14 5 445 

16.5 51 14 5 471 

17.0 50 14 5 499 

17.5 48 13 5 525 

18.0 47 13 5 552 

18.5 45 12 4 579 

19.0 44 12 4 606 

19.5 42 12 3 633 

20.0 41 11 3 659 



internal phase salinities and temperature stabilities, it is recommended that a material balance approach be utilized prior 

to the formulation of large quantities of CARBO-DRILL. 



Revised 2006 5-59


Table 5-36 

Products required to build 100 bbl of SYN-TEQ Fluid: 85/15 Synthetic/Water Ratio 

(SWR) 

Maximum Temperature °F (°C) 

Products 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 





100 

25 

10 

8 

115 

50 

20 

9 

140 

62.5 

20 

11 

160 

75 

30 

13 

180 

112 

30 

16 

85/15 SWR 

ISO-TEQ, 

Brine*, CARBO-GEL, 

(bbl) 

(bbl) 

(50 lb sacks) 

8.0 82 15 9 18 

8.5 80 14 9 50 

9.0 79 14 9 76 

9.5 77 14 9 103 

10.0 76 14 9 129 

10.5 74 13 9 156 

11.0 72 13 9 182 

11.5 71 13 9 209 

12.0 69 13 9 236 

12.5 68 12 8 262 

13.0 66 12 8 289 

13.5 65 12 8 316 

14.0 63 12 8 342 

14.5 62 11 8 369 

15.0 60 11 7 395 

15.5 59 11 7 422 

16.0 57 10 7 449 

16.5 56 10 7 475 

17.0 54 10 7 502 

17.5 52 10 7 528 

18.0 51 9 5 555 

18.5 49 9 5 582 

19.0 48 9 5 608 

Fluid Weight, 

(lb m /gal) 

*Saturated NaCl or 250,000 CaCl 2 water. 

MIL-BAR, 



internal phase salinities and temperature stabilities, it is recommended that a material balance approach be utilized prior to 

the formulation of large quantities of CARBO-DRILL. 



5-60 Revised 2006


Table 5-37 Products Required to build 100 bbl of SYN-TEQ SM Fluid: 90/10 and 95/5 

Synthetic/Water Ratios (SWR) 

Maximum Temperature °F (°C) 

Products 250 (121) 300 (149) 350 (177) 400 (204) 450 (232) 





85 

25 

10 

5 

100 

50 

20 

6 

125 

62.5 

20 

7 

140 

100 

30 

12 

170 

125 

30 

14 

Fluid Weight, 

(lb m /gal) 

ISO-TEQ, 

(bbl) 

90/10 SWR 

Brine*, 

(bbl) 

CARBO-GEL, 

(50 lb sacks) 

MIL-BAR, 


7.6 88 10 10 0 

8.0 86 10 10 22 

8.5 85 10 10 49 

9.0 83 10 10 75 

9.5 82 9 10 102 

10.0 80 9 10 129 

10.5 78 9 10 156 

11.0 77 9 10 183 

11.5 75 8 10 210 

12.0 73 8 10 236 

12.5 72 8 10 263 

13.0 70 8 10 290 

13.5 69 8 10 317 

14.0 67 8 10 343 

14.5 65 8 10 370 

15.0 63 7 10 397 

95/5 OWR 

16.0 62 3 8 471 

16.5 61 3 8 499 

17..0 59 3 8 526 

17.5 57 3 8 553 

18.0 56 3 7 579 

18.5 54 3 5 606 

19.0 52 3 4 633 

19.5 50 3 3 660 

20.0 49 3 2 687 

*Saturated NaCl or 250,000 CaCl 2 water. 


internal phase salinities and temperature stabilities, it is recommended that a material balance approach be utilized prior to 

the formulation of large quantities of CARBO-DRILL. 



Revised 2006 5-61


Table 5-38 

FLUID ISO-TEQ 

WEIGHT (bbl) 

(lb m /gal) 

7.2 

7.5 

8.0 

8.5 

9.0 

9.5 

10.0 

10,5 

11.0 

11.5 

12.0 

12.5 

13.0 

13.5 

14.0 

14.5 

15.0 

15.5 

16.0 

16.5 

17.0 

17.5 

18.0 

18.5 

19.0 

SYN-TEQ Products required to build 100 bbl of SYN-CORE SM Synthetic Fluid 

98 

97 

95 

93 

92 

90 

88 

86 

85 

83 

81 

79 

78 

76 

74 

72 

71 

69 

67 

65 

63 

62 

60 

59 

57 

CARBO-GEL 

(50 lb sacks) 

31 

30 

28 

26 

25 

24 

22 

21 

19 

18 

16 

15 

14 

13 

12 

11 

9 

9 

8 

7 

6 

6 

5 

5 

4 

OMNI-PLEX 

(gallons) 

120 

110 

105 

100 

90 

90 

80 

75 

70 

60 

55 

55 

50 

50 

45 

40 

35 

30 

25 

20 

12 

12 

12 

12 

12 

MIL- 

LIME TM 

(50 lb sacks) 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

2 

OMNI-TEC 

(gal) 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

24 

OMNI- 

TROL TM 

(50 lb sacks) 

24 

23 

22 

22 

22 

22 

21 

21 

20 

20 

19 

19 

19 

18 

18 

17 

17 

17 

16 

16 

15 

15 

15 

14 

14 

MIL-BAR 


12 

39 

66 

93 

120 

147 

174 

201 

227 

254 

281 

308 

335 

361 

388 

415 

441 

468 

495 

521 

548 

575 

603 

630 



5-62 Revised 2006


Weight 

Percent 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

7.0 

8.0 

9.0 

10.0 

11.0 

12.0 

13.0 

14.0 

15.0 

16.0 

17.0 

18.0 

19.0 

20.0 

21.0 

22.0 

23.0 

24.0 

25.0 

26.0 

27.0 

28.0 

29.0 

30.0 

31.0 

32.0 

33.0 

34.0 

35.0 

36.0 

37.0 

38.0 

39.0 

40.0 

Salt tables 

Specific 

Gravity 

1.009 

1.017 

1.026 

1.034 

1.043 

1.051 

1.060 

1.068 

1.077 

1.085 

1.094 

1.103 

1.113 

1.122 

1.132 

1.141 

1.151 

1.160 

1.170 

1.180 

1.190 

1.200 

1.210 

1.220 

1.231 

1.241 

1.252 

1.262 

1.273 

1.284 

1.295 

1.306 

1.317 

1.328 

1.340 

1.351 

1.363 

1.375 

1.387 

1.398 

Density 

(lb m /gal) 

8.42 

8.49 

8.56 

8.63 

8.70 

8.77 

8.84 

8.91 

8.98 

9.05 

9.13 

9.20 

9.28 

9.36 

9.44 

9.52 

9.60 

9.68 

9.76 

9.85 

9.93 

10.01 

10.10 

10.18 

10.27 

10.36 

10.44 

10.53 

10.62 

10.71 

10.81 

10.90 

10.99 

11.08 

11.18 

11.27 

11.37 

11.47 

11.57 

11.67 

Table 5-39 Properties of Calcium Chloride Solutions at 20°C 

100% 

CaCl 2 

(lb m /bbl) 

3.53 

7.13 

10.78 

14.50 

18.27 

22.11 

25.99 

29.94 

33.95 

38.03 

42.18 

46.39 

50.69 

55.05 

59.49 

63.98 

68.55 

73.18 

77.91 

82.72 

87.59 

92.53 

97.55 

102.62 

107.82 

113.09 

118.44 

123.85 

129.39 

135.00 

140.70 

146.48 

152.32 

158.25 

164.32 

170.47 

176.76 

183.13 

189.53 

195.99 

95% 

CaCl 2 

(lb m /bbl) 

3.72 

7.50 

11.35 

15.26 

19.23 

23.27 

27.36 

31.52 

35.74 

40.03 

44.40 

48.83 

53.36 

57.95 

62.62 

67.35 

72.16 

77.03 

82.01 

87.07 

92.20 

97.40 

102.68 

108.02 

113.49 

119.04 

124.67 

130.37 

136.20 

142.11 

148.11 

154.19 

160.34 

166.58 

172.97 

179.44 

186.06 

192.77 

199.50 

206.31 

H 2 O 

Using 

100% 

CaCl 2 

(gal/bbl) 

41.93 

41.85 

41.78 

41.69 

41.60 

41.49 

41.38 

41.27 

41.14 

41.01 

40.90 

40.76 

40.65 

40.53 

40.40 

40.25 

40.10 

39.95 

39.80 

39.65 

39.48 

39.31 

39.14 

38.95 

38.76 

38.57 

38.37 

38.16 

37.96 

37.75 

37.53 

37.30 

37.06 

36.81 

36.57 

36.32 

36.06 

35.81 

35.53 

35.23 

H 2 O Using 

95% 

CaCl 2 

(gal/bbl) 

41.91 

41.81 

41.71 

41.60 

41.48 

41.35 

41.22 

41.08 

40.93 

40.77 

40.63 

40.47 

40.33 

40.18 

40.02 

39.85 

39.67 

39.49 

39.31 

39.13 

38.93 

38.73 

38.52 

38.30 

38.08 

37.86 

37.62 

37.38 

37.14 

36.90 

36.64 

36.38 

36.10 

35.81 

35.53 

35.24 

34.95 

34.65 

34.33 

33.99 

1 Volume increase from 100% salt, i.e., from retort. 

CaCl 2 

(mg/L) 

10085 

20340 

30765 

41360 

52125 

63060 

74165 

85440 

96885 

108500 

120340 

132360 

144625 

157080 

169725 

182560 

195585 

208800 

222300 

236000 

249900 

264000 

278300 

292800 

307625 

322660 

337905 

353360 

369170 

385200 

401450 

417920 

434610 

451520 

468825 

486360 

504310 

522500 

540735 

559200 

2 Volume increase from salt and water in the sacked salt. 

Chlorides 

(mg/L) 

6454 

13018 

19690 

26470 

33360 

40358 

47466 

54682 

62006 

69440 

77018 

84710 

92560 

100531 

108624 

116838 

125174 

133632 

142272 

151040 

159936 

168960 

178112 

187392 

196880 

206502 

2l6259 

226150 

236269 

246528 

256928 

267469 

278150 

288973 

300048 

311270 

322758 

334400 

346070 

357888 

Volume 1 

Increase 

Factor 

100% 

CaCl 2 

1.002 

1.004 

1.006 

1.008 

1.011 

1.013 

1.016 

1.018 

1.021 

1.024 

1.027 

1.030 

1.034 

1.037 

1.041 

1.044 

1.048 

1.051 

1.056 

1.060 

1.065 

1.069 

1.074 

1.078 

1.084 

1.089 

1.095 

1.100 

1.107 

1.113 

1.120 

1.126 

1.134 

1.141 

1.149 

1.156 

1.165 

1.173 

1.183 

1.192 

Volume 2 

Increase 

Factor 

95% 

CaCl 2 

1.002 

1.004 

1.007 

1.010 

1.013 

1.016 

1.019 

1.022 

1.026 

1.030 

1.034 

1.038 

1.041 

1.045 

1.049 

1.054 

1.059 

1.064 

1.068 

1.073 

1.079 

1.084 

1.090 

1.097 

1.103 

1.109 

1.116 

1.124 

1.131 

1.138 

1.146 

1.155 

1.163 

1.173 

1.182 

1.192 

1.202 

1.212 

1.224 

1.236 

Crystal 

lization 

Point (°F) 

31.1 

30.4 

29.5 

28.6 

27.7 

26.8 

25.9 

24.6 

23.5 

22.3 

20.8 

19.3 

17.6 

15.5 

13.5 

11.2 

8.6 

5.9 

2.8 

-0.4 

-3.9 

-7.8 

-11.9 

-16.2 

-21.0 

-25.8 

-31.2 

-37.8 

-49.4 

-50.8 

-33.2 

-19.5 

-06.9 

+4.3 

+14.4 

+24.1 

+33.4 

+42.1 

+49.6 

+55.9 

Aw 

0.998 

0.996 

0.993 

0.989 

0.984 

0.979 

0.973 

0.967 

0.959 

0.951 

0.942 

0.933 

0.923 

0.912 

0.900 

0.888 

0.875 

0.862 

0.847 

0.832 

0.816 

0.800 

0.783 

0.765 

0.746 

0.727 

0.707 

0.686 

0.665 

0.643 

0.620 

0.597 

0.573 

0.548 

0.522 

0.496 

0.469 

0.441 

0.413 

0.384 



Revised 2006 5-63


Metric Conversions 

• CaCl 2 (g/L) = CaCl 2 (lb m /bbl) × 2.85714 

• H 2 0 (mL/L) = H 2 0 (gal/bbl) × 23.8086 

• CaCl 2 (ppm) = % Wt × 10,000 

• Cl – (ppm) = CaCl 2 (ppm) × 0.639 

• mg/L = ppm × specific gravity 

Formulas 

• Salt (lb m /bbl water) = Volume increase factor ×CaCl 2 (lb m /bbl) 

• Specific Gravity 

1.0036 [0.99707 + 7.923 (10 -3 ) (% wt CaCl 2 ) + 4.964 (10 -5 ) (% wt CaCl 2 ) 2 ] 

• Volume Increase Factor * 

1.00293 + 1.04192 (10 -3 ) (% wt CaCl 2 ) + 8.94922 (10 -5 ) (% wt CaCl 2 ) 2 

• Aw 

0.99989 – 1.39359 (10 -3 ) (% wt CaCl 2 ) – 3.50352 (1 0 -4 ) (% wt CaCl 2 ) 2 

% wt CaCl 2 = [100% CaCl 2 (lb m /bbl) x % Purity CaCl 2 ]/[S.G. x 350] 

When Using CaCl 2 with Purity Other Than 95%. 

• New CaCl 2 (lb m /bbl) = 95 ×95% CaCl 2 (lb m /bbl) + % Purity 

New H 2 O (gal/bbl) = H 2 O (gal/bbl) – [New CaCl 2 (lb m /bbl) – 95% CaCl 2 (lb m /bbl) / 8.345 

Volume increase from salt = 42 + New water ** 

Example: 35% CaCl2 Brine Using 78% CaCl2 

New CaCl 2 (lb m /bbl) = 95 ×172.97 – 78 = 210.67 

New H 2 O (gal/bbl) = 35.53 – [(210.67 –172.97) / 8.345] = 31.01 

Volume increase from 78% salt = 42 + 31.01 = 1.354 

* Volume increase from 100% salt, i.e., from retort. 

** Volume increase from salt and water in the sacked salt. 



5-64 Revised 2006


Weight 

Percent 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

7.0 

8.0 

9.0 

10.0 

11.0 

12.0 

13.0 

14.0 

15.0 

16.0 

17.0 

18.0 

19.0 

20.0 

21.0 

22.0 

23.0 

24.0 

25.0 

26.0 

Specific 

Gravity 

(g/cm 3 ) 

1.007 

1.014 

1.021 

1.029 

1.036 

1.043 

1.050 

1.058 

1.065 

1.073 

1.080 

1.088 

1.095 

1.103 

1.111 

1.118 

1.126 

1.134 

1.142 

1.150 

1.158 

1.166 

1.174 

1.183 

1.191 

1.199 

Table 5-40 Properties of Sodium Chloride Brines at 20°C 

Density 

(lb m /gal) 

8.40 

8.46 

8.52 

8.58 

8.65 

8.70 

8.76 

8.83 

8.89 

8.95 

9.01 

9.08 

9.14 

9.20 

9.27 

9.33 

9.40 

9.46 

9.53 

9.60 

9.66 

9.73 

9.80 

9.87 

9.94 

10.01 

NaCl 

(lb m /bbl) 

3.5 

7.1 

10.7 

14.4 

18.2 

21.9 

25.8 

29.7 

33.6 

37.6 

41.6 

45.7 

49.9 

54.1 

58.4 

62.7 

67.1 

71.5 

76.0 

80.6 

85.2 

89.9 

94.6 

99.5 

104.4 

109.3 

H 2 0 

(gal/bbl) 

41.87 

41.75 

41.63 

41.46 

41.34 

41.18 

41.02 

40.86 

40.70 

40.54 

40.38 

40.19 

40.00 

39.85 

39.66 

39.44 

39.25 

39.03 

38.85 

38.64 

38.43 

38.22 

37.97 

37.74 

37.50 

37.27 

NaCl 

(mg/L) 

10070 

20286 

30630 

41144 

51800 

62586 

73500 

84624 

95850 

107260 

118 800 

130512 

142350 

154392 

166650 

178912 

191420 

204102 

216980 

229960 

243180 

256520 

270020 

283800 

297750 

311818 

Chlorides 

(mg/L) 

6108 

12305 

18580 

24957 

31421 

37963 

44584 

51331 

58141 

65062 

72062 

79166 

86347 

93651 

101087 

108524 

116112 

123804 

131616 

139489 

147508 

155600 

163789 

172147 

180609 

189143 

Volume 1 

Increase 

Factor 

1.003 

1.006 

1.009 

1.013 

1.016 

1.020 

1.024 

1.028 

1.032 

1.036 

1.040 

1.045 

1.050 

1.054 

1.059 

1.065 

1.070 

1.076 

1.081 

1.087 

1.093 

1.099 

1.106 

1.113 

1.120 

1.127 

Aw 

0.996 

0.989 

0.983 

0.976 

0.970 

0.964 

0.957 

0.950 

0.943 

0.935 

0.927 

0.919 

0.910 

0.901 

0.892 

0.882 

0.872 

0.861 

0.850 

0.839 

0.827 

0.815 

0.802 

0.788 

0.774 

0.759 

1 

There is minimal water in sacked NaCl, therefore, the volume increase from retort and sack additions may be 

considered the same. 



Revised 2006 5-65



NaCl (g/L) = NaCl (lb m /bbl) ×2.85714 

H 2 0 (mL/L) = H 2 0 (gal/bbl) ×23.8086 

NaCl (ppm) = % wt ×10,000 

Cl – (mg/L) = NaCl (mg/L) ×0.6066 

NaCl (mg/L) = Cl – (mg/L) ×1.65 

mg/L = ppm ×specific gravity 

Formulas 

• Salt (lb m /bbl water) = Volume increase factor × NaCl (lb m /bbl) 


1.0036 [0.99707 + 6.504 (10 -3 ) (% wt NaCl) + 4.395 (10 -5 ) (% wt NaCl) 2 ] 

• Volume Increase Factor 

1.00045 + 2.72232 (10 -3 ) (% wt NaCl) + 8.15591 (10 -5 ) (% wt NaCl) 2 

• Aw 

0.99755 – 4.3547 (l0 -3 ) (% wt NaCl) – 1.8205 (10 -4 ) (% wt NaCl) 2 



5-66 Revised 2006


Weight 

Percent 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

7.0 

8.0 

9.0 

10.0 

11.0 

12.0 

13.0 

14.0 

15.0 

16.0 

17.0 

18.0 

19.0 

20.0 

21.0 

22.0 

23.0 

24.0 

25.0 

26.0 

27.0 

28.0 

29.0 

30.0 

Specific 

Gravity 

(g/cm) 

1.008 

1.016 

1.024 

1.033 

1.041 

1.050 

1.058 

1.067 

1.076 

1.085 

1.094 

1.103 

1.112 

1.121 

1.130 

1.139 

1.148 

1.157 

1.167 

1.176 

1.186 

1.196 

1.206 

1.216 

1.227 

1.237 

1.248 

1.258 

1.269 

1.279 

Table 5-41 Properties of Magnesium Chloride Solutions at 20°C 

Density 

(lb m /gal) 

8.41 

8.48 

8.55 

8.62 

8.69 

8.76 

8.83 

8.90 

8.98 

9.05 

9.13 

9.20 

9.28 

9.35 

9.43 

9.50 

9.58 

9.66 

9.73 

9.81 

9.90 

9.98 

10.06 

10.15 

10.24 

10.32 

10.41 

10.50 

10.59 

10.67 

MgCl 2 

• 6H 2 0 

(lb m /bbl) 

7.54 

15.15 

22.92 

30.76 

38.82 

46.96 

55.24 

63.60 

72.11 

80.85 

89.73 

98.61 

107.76 

116.90 

126.35 

135.79 

145.53 

155.27 

165.28 

175.28 

185.66 

196.03 

206.78 

217.53 

228.58 

239.63 

251.02 

262.40 

274.12 

285.84 

H 2 0 

(gal/bbl) 

41.71 

41.45 

40.87 

40.28 

39.69 

39.06 

38.43 

37.80 

37.17 

36.50 

36.16 

35.83 

35.13 

34.44 

33.73 

33.01 

31.48 

29.95 

29.13 

28.31 

27.47 

26.63 

25.77 

24.91 

24.00 

23.10 

22.18 

21.25 

20.29 

19.32 

MgCl 2 

(mg/L) 

10080 

20320 

30720 

41320 

52050 

63000 

74060 

85360 

96840 

108500 

120340 

132360 

144560 

156940 

169500 

182240 

195160 

208260 

221635 

235200 

249060 

263120 

277380 

291840 

306625 

321620 

336825 

352240 

367865 

383700 

Chlorides 

(mg/L) 

7502 

15123 

22863 

30752 

38738 

46887 

55118 

63528 

72072 

80750 

89562 

98508 

107587 

116801 

126149 

135630 

145246 

154995 

164950 

175045 

185360 

195824 

206437 

217199 

228203 

239362 

250679 

262151 

273780 

285565 

Volume 1 

Increase 

Factor 

100% 

MgCl 2 

1.001 

1.002 

1.004 

1.006 

1.009 

1.012 

1.014 

1.017 

1.020 

1.023 

1.026 

1.029 

1.033 

1.036 

1.040 

1.044 

1.048 

1.052 

1.057 

1.061 

1.066 

1.071 

1.076 

1.081 

1.087 

1.092 

1.098 

1.103 

1.110 

1.116 

Volume 2 

Increase 

Factor from 

Salt 

1.007 

1.013 

1.028 

1.043 

1.058 

1.075 

1.093 

1.111 

1.130 

1.151 

1.161 

1.172 

1.195 

1.220 

1.245 

1.272 

1.334 

1.403 

1.442 

1.484 

1.529 

1.577 

1.630 

1.686 

1.750 

1.818 

1.894 

1.976 

2.070 

2.174 

Aw 

0.985 

0.981 

0.978 

0.974 

0.970 

0.964 

0.958 

0.952 

0.943 

0.934 

0.924 

0.913 

0.901 

0.888 

0.875 

0.862 

0.846 

0.830 

0.813 

0.795 

0.778 

0.760 

0.737 

0.713 

0.691 

0.669 

0.647 

0.625 

0.604 

0.582 

1 Volume increase from 100% salt, i.e., from retort. 

2 Volume increase from salt and water in the sacked salt. 



Revised 2006 5-67


• Metric Conversions 

MgCl 2 (g/L) = MgCl 2 (lb m /bbl) × 2.85714 

H 2 0 (mL/L) = H 2 0 (gal/bbl) × 23.8086 

MgCl 2 (ppm) = % Wt MgCl 2 × 10,000 

Cl – (ppm) = MgCl 2 (ppm) × 0.7442 

Formulas 

• Salt (lb m /bbl water) = Volume increase factor × MgCl 2 (lb m /bbl) 


1.00038 + 7,95497 (10 -3 ) (% Wt MgCl 2 ) + 4.38583 (10 -5 ) (% Wt MgCl 2 ) 2 


0.999074 + 1.58008 (10 -3 ) (% Wt MgCl 2 ) + 7.66303 (10 -5 ) (% Wt MgCl 2 ) 2 

• Aw 

0.986688 – 1.2334 (10 -3 ) (% Wt MgCl 2 ) – 4.16512 (10 -4 ) (% Wt MgCl 2 ) 2 



5-68 Revised 2006

Typical formulation guidelines by BHDF location 

Table 5-42 

Typical System Types, Formulations, and Product Usage 

Country Australia UK USA USA USA USA 

Classification Primary Secondary 

System Type Mineral Oil Mineral Oil Diesel HPHT Synthetic Synthetic 

Base Oil Sarapar 147 DF-1 Diesel Diesel CF-2002 ISO-TEQ 

C16/18 

System Name 

CARBO- 

DRILL 

CARBO-SEA 

Salinity, mg/L 100 – 250,000 150 – 200,000 

O/W Ratio 70/30 – 80/20 60/40 – 70/30 

Weight Range, lb/gal 9 to 13.5 10 to 15 

CARBO- 

DRILL 

EMULSIFIERS 

CARBO-MUL 3 to 4 

CARBO- 

DRILL 

CARBO-MUL HT 14 6 3 to 4 

CARBO-MIX 4 

SYN-TEQ 

CF 

OMNI-MUL 8 8 

OMNI-TEC 1 1 

CARBO-VIS 3 

VISCOSIFIERS 

SYN-TEQ 

CARBO-GEL 8 3 to 4 3 to 4 3 to 4 3 to 4 

6-UP 1 

FILTRATION CONTROL 

CARBO-TROL A-9 2 to 4 

CARBO-TROL HT 3 to 5 3 to 5 3 to 5 

PLIOLITE DF01 2 

CARBO-TRO ® A-9 

HT 

WETTING AGENTS 

2 to 4 2 to 4 2 to 4 

OMNI-COTE 0.5 1 1 1 1 

CARBO-MUL 3 to 4 

CARBO-MUL HT 3 to 4 

OMNI-MUL 3 to 4 3 to 4 



Revised.2006 5-69

Reservoir Application Fluids 

Chapter 

Six 

Reservoir Application Fluids

Chapter 6 


RESERVOIR APPLICATION FLUIDS ................................................................................................6-1 

INTRODUCTION.................................................................................................................................6-1 

PETROLEUM GEOLOGY .........................................................................................................................6-1 

Properties of Sedimentary Rocks .................................................................................................6-2 

Genesis of Sedimentary Rocks (Particles)..................................................................................6-2 

Classification of Sedimentary Rocks............................................................................................6-3 

Porosity and Permeability ..............................................................................................................6-4 

Classification of Porosity ............................................................................................................6-5 

Reservoir Fluids...............................................................................................................................6-6 

Reservoir Fluid Types.................................................................................................................6-6 

Physical Properties of Reservoir Fluids ...................................................................................6-8 

Petroleum Reservoirs ...................................................................................................................6-10 

Sandstone Reservoirs ..............................................................................................................6-12 

Carbonate Reservoir Rocks.....................................................................................................6-12 

Reservoir Traps .............................................................................................................................6-13 

Structural ....................................................................................................................................6-14 

Stratigraphic ...............................................................................................................................6-14 

Combination Trap......................................................................................................................6-15 

FORMATION DAMAGE AND PROTECTION MECHANISMS....................................................................6-16 

Introduction.....................................................................................................................................6-16 

Formation Damage Mechanisms................................................................................................6-16 

Formation Protection ....................................................................................................................6-20 

DRILL-IN FLUIDS..................................................................................................................................6-21 

Introduction.....................................................................................................................................6-21 

PERFFLOW ® System ...................................................................................................................6-22 

PERFFLOW Systems Application ..........................................................................................6-23 

Standard Systems Formulation...............................................................................................6-23 

Displacement .............................................................................................................................6-24 

Open Hole Displacement for Completion ..............................................................................6-24 

General Guidelines ...................................................................................................................6-24 

PERFFLOW Systems: General Engineering Guidelines ....................................................6-25 

CLEAR-DRILL ® Fluids..................................................................................................................6-28 

Introduction.................................................................................................................................6-28 

Function of Formates................................................................................................................6-29 

Description of System Components .......................................................................................6-31 

BIO-LOSE 90 SYSTEM................................................................................................................6-35 

Introduction.................................................................................................................................6-35 

Rheological Properties .............................................................................................................6-35 

Filtration Control ........................................................................................................................6-35 

Reservoir Considerations.........................................................................................................6-36 

Fluid Density ..............................................................................................................................6-36 

Directional Tools........................................................................................................................6-36 

Recommended Fluid Properties .............................................................................................6-36 

OMNIFLOW ® DIF SYSTEM.........................................................................................................6-36

TABLE OF CONTENTS 

System Benefits.........................................................................................................................6-36 

System Components ................................................................................................................6-37 

Typical Fluid Formulation and Properties..............................................................................6-38 

CARBO-CORE ..............................................................................................................................6-39 

Native State Drilling and Coring Fluids ..................................................................................6-39 

Components...............................................................................................................................6-39 

COMPLETION FLUIDS ..........................................................................................................................6-41 

Introduction to Clear Brines .........................................................................................................6-41 

Effects of Temperature and Pressure ........................................................................................6-42 

Calculations for Density Adjustments.....................................................................................6-43 

Salt Solubility vs. Freeze Depression.....................................................................................6-48 

Compatibility of Various Additives with Different Salt Types..................................................6-49 

Salt Tables......................................................................................................................................6-49 

WORKOVER FLUIDS ............................................................................................................................6-74 

Heavy Brines..................................................................................................................................6-75 

Workover Products....................................................................................................................6-79 

Other Workover Fluids..............................................................................................................6-80 

WELLBORE DISPLACEMENT AND CLEAN-UP PRODUCTS AND PROCEDURES .................................6-80 

Introduction.....................................................................................................................................6-80 

Displacement Objectives..............................................................................................................6-81 

Indirect versus Direct Displacement...........................................................................................6-84 

Design of Displacement Pills.......................................................................................................6-92 

Well Cleanliness Determination ..................................................................................................6-94 

End of Well Reporting and Performance Measures ................................................................6-96 

DISPLEX SM Displacement Software...........................................................................................6-97 

Pickling of Tubulars.......................................................................................................................6-98 

PACKER FLUIDS.................................................................................................................................6-101 

Requirements of a Good Packer Fluid.....................................................................................6-101 

Types of Packer Fluids...............................................................................................................6-101 

Clear Brines..............................................................................................................................6-101 

Conditioned Drilling Fluids .....................................................................................................6-102 

SALTWATER GEL Packer Fluids.........................................................................................6-103 

GEL-CMC Freshwater Packer Fluids...................................................................................6-103 

Conversion of CARBO-DRILL Fluids to a Packer Fluid ....................................................6-104 

SOFTWARE FOR COMPLETIONS AND WORKOVERS.........................................................................6-104 

Bridgewise....................................................................................................................................6-105 

Clear Brine ESD Calculator (Equivalent Static Density) .......................................................6-106 

DISPLEX.......................................................................................................................................6-109 

REFERENCES .....................................................................................................................................6-114 


FIGURE 6 - 1 ROCK CYCLE ................................................................................................................6-3 

FIGURE 6 - 2 SEDIMENTARY ROCK NOMENCLATURE.......................................................................6-4 

FIGURE 6 - 3 GRAIN PACKING AND POROSITY..................................................................................6-5 

FIGURE 6 - 4 NORMAL CRUDE OIL ....................................................................................................6-6 

FIGURE 6 - 5 OIL RESERVOIR WITH GAS CAP ..................................................................................6-7 

FIGURE 6 - 6 VOLATILE CRUDE OIL...................................................................................................6-7 

FIGURE 6 - 7 GAS CONDENSATES.....................................................................................................6-8 

FIGURE 6 - 8 MARINE SEDIMENTARY DEPOSITIONAL ENVIRONMENTS .........................................6-12 


REVISION 2006 


6-ii


FIGURE 6 - 9 STRUCTURAL AND STRATIGRAPHIC TRAPS ..............................................................6-14 

FIGURE 6 - 10 PARTICLE SIZE DISTRIBUTION OF MIL-CARB......................................................6-23 

FIGURE 6 - 11 COMPARISON OF SOLIDS CONTENT IN FLUIDS WEIGHTED WITH VARIOUS WEIGHT 

MATERIALS ......................................................................................................................................6-30 

FIGURE 6 - 12 EFFECT OF CLEAR-DRILL SALTS ON THERMAL STABILITY OF XANTHAN POLYMERS 

......................................................................................................................................6-31 

FIGURE 6 - 13 NO-WATER-ADDED CARBO-CORE TYPICAL FLOW PROPERTIES ........................6-41 

FIGURE 6 - 14 MATERIAL REQUIREMENTS FOR PREPARING SODIUM CHLORIDE SOLUTIONS.......6-76 

FIGURE 6 - 15 MATERIAL REQUIREMENTS FOR PREPARING POTASSIUM CHLORIDE SOLUTIONS.6-77 

FIGURE 6 - 16 MATERIAL REQUIREMENTS FOR PREPARING CALCIUM CHLORIDE SOLUTIONS.....6-78 

FIGURE 6 - 17 CONDITION OF HORIZONTAL WELLBORE PRIOR TO DISPLACEMENT ......................6-83 

FIGURE 6 - 18 SCOURING OF THE FILTER CAKE...............................................................................6-83 

FIGURE 6 - 19 REVERSE CIRCULATION.............................................................................................6-89 

FIGURE 6 - 20 FORWARD CIRCULATION............................................................................................6-89 

FIGURE 6 - 21 BALL DROP CIRCULATING SUB ...................................................................................6-90 

FIGURE 6 - 22 PLUG AND TURBULENT FLOW REGIMES ...................................................................6-94 

FIGURE 6 - 23 GRAPHICAL RESULTS OBTAINED FROM BAKER HUGHES DRILLING FLUIDS ESD 

CALCULATOR.................................................................................................................................6-109 

FIGURE 6 - 24 DISPLEX SIMULATION FOR DEEPWATER APPLICATIONS .....................................6-111 

FIGURE 6 - 25 SIMULATION OF WSA C06 (WSAP-16) WELLBORE DISPLACEMENT AND CLEAN-UP .. 

....................................................................................................................................6-112 

FIGURE 6 - 26 SIMULATION OF WSA C06 (WSAP-16) WELLBORE DISPLACEMENT AND CLEAN-UP .. 

....................................................................................................................................6-113 


TABLE 6 - 1 LABORATORY FLUID FORMULATIONS............................................................................6-34 

TABLE 6 - 2 INITIAL PROPERTIES OF LABORATORY FLUID FORMULATIONS....................................6-34 

TABLE 6 - 3 PROPERTIES OF LABORATORY FORMULATIONS AFTER HOT ROLLING .......................6-35 

TABLE 6 - 4 OMNIFLOW DIF PRODUCTS........................................................................................6-37 

TABLE 6 - 5 TYPICAL OMNIFLOW DIF FORMULATION ...................................................................6-38 

TABLE 6 - 6 TYPICAL OMNIFLOW DIF FORMULATION ...................................................................6-38 

TABLE 6 - 7 BRINE DENSITY DUE TO THERMAL EXPANSION............................................................6-43 

TABLE 6 - 8 OPERATIONAL DENSITIES OF VARIOUS SALTS.............................................................6-50 

TABLE 6 - 9 TYPICAL PH VALUES OF VARIOUS SALT MIXTURES.....................................................6-51 

TABLE 6 - 10 FORMULATION OF SODIUM CHLORIDE/CALCIUM CHLORIDE SOLUTION USING 

SACKED NACL (100%) AND CACL 2 (94-97%) ..............................................................................6-51 

TABLE 6 - 11 PHYSICAL PROPERTIES OF POTASSIUM CHLORIDE SOLUTIONS @ 20 0 C ..............6-52 

TABLE 6 - 12 PHYSICAL PROPERTIES OF SODIUM CHLORIDE BRINES @20 0 C ...........................6-53 

TABLE 6 - 13 PHYSICAL PROPERTIES OF AMMONIUM CHLORIDE (NH 4 CL) SOLUTIONS ..............6-54 

TABLE 6 - 14 PROPERTIES OF CALCIUM CHLORIDE SOLUTIONS @ 20°C ....................................6-55 

TABLE 6 - 15 PREPARATION OF CALCIUM CHLORIDE (CACL 2 ) SOLUTIONS USING LIQUID 11.6 

LB/GAL CACL 2 ..................................................................................................................................6-57 

TABLE 6 - 16 PREPARATION OF POTASSIUM BROMIDE BASED SOLUTIONS USING GRANULAR 

CONCENTRATED KBR .....................................................................................................................6-58 

TABLE 6 - 17 CALCIUM CHLORIDE-CALCIUM BROMIDE SOLUTION REQUIREMENTS USING 11.6 

LBM/GAL CACL 2 BRINE, 14.2 LBM/GAL CABR 2 BRINE, AND SACKED CACL 2 (FORMULATION PER 1 

BBL) ......................................................................................................................................6-59 

TABLE 6 - 18 PREPARATION OF CALCIUM BROMIDE BASED SOLUTIONS USING SOLID 94% CACL 2 

AND LIQUID 14.2 LBM/GAL CABR 2 ..................................................................................................6-61 


REVISION 2006 


6-iii


TABLE 6 - 19 PREPARATION OF SODIUM BROMIDE BASED SOLUTIONS USING 95% DRY CABR 2 ..6- 

62 

TABLE 6 - 20 PREPARATION OF SODIUM BROMIDE BASED SOLUTIONS USING 10.0 LBM/GAL NACL 

SOLUTION AND 12.4 LB/GAL NABR SOLUTION ..............................................................................6-63 

TABLE 6 - 21 PREPARATION OF SODIUM BROMIDE BASED SOLUTIONS USING SOLID NACL, 

GRANULAR CONCENTRATED NABR, AND WATER.........................................................................6-64 

TABLE 6 - 22 SODIUM BROMIDE BRINE REQUIREMENTS (USING 95% NABR)..............................6-65 

TABLE 6 - 23 CLEAR-DRILL N BRINE TABLE................................................................................6-66 

TABLE 6 - 24 CLEAR-DRILL K BRINE TABLE ................................................................................6-69 

TABLE 6 - 25 PROPERTIES OF 85% CALCIUM NITRATE SOLUTIONS (AT 25°C)............................6-73 

TABLE 6 - 26 FORMULA FOR 1 BBL OF SALTWATER GEL OF VARYING DENSITY....................6-103 

TABLE 6 - 27 FORMULA FOR PREPARING ONE BARREL OF WEIGHTED FRESHWATER PACKER 

FLUID USING MILGEL AND CMC (MV) .......................................................................................6-104 

TABLE 6 - 28 EXAMPLE RESULTS FROM BAKER HUGHES DRILLING FLUIDS ESD CALCULATOR....6- 

108 


REVISION 2006 


6-iv

RESERVOIR APPLICATION FLUIDS 


Chapter 6 

This chapter describes the categories of fluids that are used during and after the productive interval is 

drilled. All of the fluids discussed are designed to maximize well productivity. 

INTRODUCTION 

Reservoir application fluids are any fluids to which the reservoir will be exposed during drilling, 

completion and workover operation. These fluids are designed to maximize hydrocarbon 

production from the production interval(s). This is achieved by minimizing formation damage 

during drilling and completion operations and maximizing the production potential of the 

completion methodology. It is first necessary to gain an understanding of hydrocarbon reservoirs 

before examining their interactions with drilling, completion and workover fluids. 

A more thorough understanding of the purpose and application of these fluids requires some 

knowledge of the earth’s geology and of formations from which petroleum products are 

commercially produced. 

PETROLEUM GEOLOGY 

Geology is the science of the earth, its origin and development through the past, its size, shape and 

composition, the processes that are now, or have been at work on its surface, and its interior; also its 

life forms since its origin. Geology as a science has its own techniques of geological mapping and 

for reconstruction of past events. It also uses other sciences, such as chemistry, biology, physics and 

engineering methods and theories. 

Geology has the following branches: 

• Crystallography 

• Mineralogy 

• Petrology 

• Geochemistry 

• Structural Geology 

• Geophysics 

• Stratigraphy 

• Sedimentology 

• Paleontology 

• Geomorphology 



REVISION 2006 6-1


In petroleum geology, one is mainly concerned with sedimentology and stratigraphy, as well as 

structural geology. Sedimentology is concerned with the origin, transportation, deposition and 

diagenesis of sedimentary rocks. It includes their description, classification and interpretation. 

Since sedimentary rocks are the fundamental materials of stratigraphy, the stratigrapher is primarily 

concerned with sedimentology and palaeontology or the science of life through geological history. 

The stratigraphic record is a result of sedimentary processes operating through geologic time. A 

fundamental principle in sedimentation is the law of superposition. “If one series of rocks lies 

above another, then the upper series was formed after the lower series.” The solution of 

stratigraphical and structural problems begins with the systematic observation of the sedimentary 

succession exposed in surface outcrops or made available through drilling. It is important to 

remember that tectonic activity influences the thickness and character of accumulating sediments. 

From all the accumulated subsurface information, a stratigraphical column is prepared and 

subdivided according to geological age. Stratigraphy is the study of rock succession and the 

interpretation of these successions as sequences of events in the geological history of the earth. 

Properties of Sedimentary Rocks 

Most sediments are mixtures of two main components, a detrital fraction, brought on site of 

deposition from the source area, and a chemical fraction, formed at or near the site of deposition. 

Example: a clastic rock is composed mainly of detrital material. 

Texture: Detrital rocks have a fragmental texture, whereas chemical rocks have crystalline 

textures. Four components give a rock its textural characteristics; the grains, the matrix, the 

cement, and the pore space. Cement should be distinguished from the matrix. Most common 

cement materials are silica, calcite, dolomite and siderite. 

Particle properties: Described are color, size, shape, roundness, surface texture, orientation, and 

mineralogical composition. Particle properties describe both clastic and chemical rocks. Large sand 

grains imply strong transportation currents in a high energy environment, whereas large calcite 

crystals reflect particular physical and chemical conditions at the deposition areas. 

• Particle color is affected mainly by the association of different chemicals, such as iron’s 

reddish color. 

• Particle size is mainly indicative of forces and currents involved in transportation. 

• Particle shape is related to the energy and distance to which the particle was subjected 

before deposition. 

Genesis of Sedimentary Rocks (Particles) 

A sedimentary rock is the product of provenance (source area or pre-existing rock) and process. 

Weathering processes breaks down rocks at the earth’s surface to form minute particles. Erosion is 

the name given to processes which removes the product of weathering. Transport follows, and 

finally when the energy of the system is exhausted, deposition takes place. 

There are three types of weathering and two categories of weathering products. 

Chemical: Selectively oxidizes and dissolves material. 

Physical: 

Mechanical disaggregation. 



REVISION 2006 6-2


(These above categories are called residual sediments) 

Biological: Biochemical solution and physical fracturing (result of vegetation). 

Erosion has four agents: Gravity, glacial action, running water and wind. 

Note that soil is the product of biological weathering. It consists of rock debris and decaying 

organic matter. 

Figure 6 - 1 

Rock Cycle 

Classification of Sedimentary Rocks 

Five generic classes are recognized; chemical, organic, residual, ferruginous and volcanoclastic. 

1. Chemical sediments are formed directly by precipitation in a sub-aqueous environment. 

Types of evaporates and some types of lime muds. 

2. Organic sediments are composed of organic matter, both of animal and vegetable origin. 

3. Residual sediments are those left in place after weathering. 

4. Ferruginous sediments are the derivatives of the land mud rocks, and siliclastics. 

5. Volcanoclastic sediments are the product of volcanic activity. 

The above classes are sometimes divided into those which have been transported into the 

depositional environment (allocthonous) and those which are formed within the depositional area 

(autochthonous). 

This classification is important in order to establish some idea about the rocks’ origin. 

All possible mixtures of compositions and textures occur among sediments and these are studied by 

proper selection of compositional and textural end members. 



REVISION 2006 6-3


Figure 6 - 2 

Sedimentary Rock Nomenclature 

Porosity and Permeability 

A good understanding of the morphology and genesis of pores, prediction and detection within the 

earth’s crust is imperative to the petroleum industry. Porosity and permeability are related 

properties of any rock or loose sediment. 

Porosity of a rock is a measure of its voids and ability to hold a fluid. 

Total porosity is the total volume of void space expressed as a percentage of total volume of rock. 

Porosity (Ø) 

= 100 

bulk volume − grain volume 

bulk volume 

Effective porosity is the percentage of interconnected pore space. 



REVISION 2006 6-4


Permeability is a measure of the ability of a rock to permit fluid flow. 

K 

Q × M × L 

= 

P × A 

where: 

K = Permeability in darcies 

L = Length in cm of rock sample 

Q = Fluid flow rate in cm 3 /sec 

M = Viscosity (in centipoises) of test fluid 

A = Cross-sectional area of rock sample in cm 2 

P = Pressure applied in atmospheres 

Most oil and gas is produced from sandstones. Both porosity and permeability are needed for 

production. Porosity creates the spaces to hold the oil or gas. Permeability allows the oil and gas to 

flow out of the rock. 

Classification of Porosity 

Primary porosity is either inter-granular, between grains, inter-particle, or inside fossil shells. 

Secondary porosity can be inter-crystalline, as for recrystallized dolomites; fenestral, normal gaps, 

larger than grain supported interstices; moldic, formed by solution and vuggy or grading into 

cavernous. Fractured porosity is more difficult to observe. It ranges from microscopically small to 

cavernous in size. It can be formed either by tectonic activity or some non-tectonic processes, such 

as immediately beneath unconformities. This would include weathered fractures, especially in 

limestone. 

Theoretically, porosity is 

independent of grain size, but 

in practice, porosity generally 

decreases with increases in 

grain size. Also generally, 

porosity and permeability 

increase with increased 

sorting. The more spherical 

the grains, the less the 

porosity, due to the tendency 

of closer packing. 

Figure 6 - 3 

Grain Packing and Porosity 



REVISION 2006 6-5


Clays have very low porosity due to packing or compaction. Dewatering due to compaction, 

overburden (weight) increase, and dehydration, will cause a rapid decrease in porosity. Below 

6,000 feet, porosity decreases more slowly and is lost due to the re-crystallization of minerals in the 

pore spaces. 

Reservoir Fluids 

A key to the analysis of reservoir performance and production are the physical properties of the 

reservoir fluids, and the variation of these fluids during the recovery and exploitation phase. 

Petroleum fluids are a complex of naturally occurring hydrocarbon compounds within the porous 

rock or reservoir. 

These fluids may occur as vapor, liquids or solids, or any combination thereof. Their fluid state in 

the reservoir is a function of the temperature and pressure under which they exist. The chemical 

composition of petroleum deposits varies widely, but they have one thing in common, they are all 

predominantly composed of hydrogen (H) and carbon (C) with lesser quantities of sulfur (S), 

nitrogen (N) and oxygen (O). Broken down, most petroleum deposits exhibit the following 

composition: 

C = 84 - 87% 

H = 11 - 14% 

S, N, O = 0.1 – 2% 

The production or producibility of petroleum reservoirs depends upon the physical characteristics 

of the fluid within the reservoir. Of primary importance are the fluid viscosity and density, or when 

vapor and liquid exist, the relative viscosity and density of the mixture. Of equal importance are the 

volumetric variations of the fluids related to temperature and pressure. These values usually vary 

during reservoir depletion. Of great importance, therefore, is the correct and accurate sampling of 

the reservoir fluid and the laboratory analysis of the sample before production. 

Reservoir Fluid Types 

Generally four types of fluids exist: 

1. Normal Crudes – These are the hydrocarbon liquids present in the reservoir commonly called 

“crude oil”. The viscosity of these liquids can be as low as 1 cp or as high as 1000 cp or above. 

Specific gravity can vary from 0.825 up to 1.075, and color varies from amber to greenish 

black. Volumetric characteristics are related to pressure of the reservoir and can be 

demonstrated with the cell test. 

Figure 6 - 4 

Normal Crude Oil 



REVISION 2006 6-6


If only liquid (oil) is present, P A , and reservoir pressure is reduced during production, the 

specific volume of oil increases. Then, at some different pressure, P B , a bubble of free gas 

appears. This stage is called the “Bubble Point”. Further reduction of reservoir pressure, P C and 

P D , causes a change to occur. First, the quantity of gas escaping or separating from the oil 

increases continuously; second, the specific volume of gas increases; and third, the specific 

volume of reservoir oil decreases with pressure reduction below the bubble point, P B . 

The term used for the escape of gas from the reservoir oil is referred to as “gas coming out of 

solution”. Basically, the gas is just evaporation of the lighter hydrocarbon compounds; mainly 

methane and ethane. 

Reservoirs themselves can occur at any stage within the P A – P D system and are related to 

pressure and temperature existing within the reservoir section. 

If conditions are below the bubble point, geological time would normally have separated the 

gas from the oil, and the gas will be situated above the oil section in the form of a gas cap in 

the reservoir. 

Figure 6 - 5 

Oil Reservoir with Gas Cap 

2. Volatile Crude Oils – These are very similar to the above described oils, but are generally 

lighter in weight and color, lower in viscosity, and have a larger volume change with pressure. 

This is entirely due to the volatile aspect, i.e. gaseous solution, therefore, higher 

compressibility under higher pressure. 

Average viscosity is normally 0.78 to 0.85 cP. Changes due to pressure changes are 

demonstrated with the same P A – P D method. 

Figure 6 - 6 

Volatile Crude Oil 

The difference in behavior is that the larger amounts of gas (free gas) undergo much more 

shrinkage (compressibility) as pressure declines below the bubble point. 

3. Gas Condensates – These are hydrocarbon liquids mixed with natural gas instead of crude oils. 



REVISION 2006 6-7


Condensates can exist as a very light liquid phase in a gas accumulation. It is a liquid phase 

that develops from condensation of the heavier components as pressure is reduced during 

production (or, in small reservoirs, during drilling and/or kick occurrence). The phases are 

explained in the following P A – P D demonstration. 

Figure 6 - 7 

Gas Condensates 

During expansion of the compressed gas when produced, condensate forms a drop of liquid 

from the heavier hydrocarbon compounds. This point is called the “Dew Point” of a reservoir. 

The condensate liquid will reach a maximum depending on the pressure reductions, but then 

after further reduction, will return to another droplet within the system. This is referred to as 

the dew point pressure at the reservoir. Any further reduction of pressure after the dew point 

pressure will result in a single phase gas system with gas expansion in proportion to pressure 

reduction. 

Any reservoir can be, as with oil reservoirs, anywhere between point P A and P D . With 

conditions at or below P C , the reservoir would be called a normal condensate reservoir. If 

conditions are above the P C stage, the term retrograde condensate reservoir is applied. This 

term implies an increase in liquid (condensate) with a decrease in pressure, rather than a 

decrease or evaporation under normal conditions. 

The viscosity of a gas condensate is normally 0.05 cP or less, but can be as high as 0.5 cP; with 

a specific gravity of 0.7 to 0.78. 

4. Dry Gas Reservoir – This refers to a system that contains only light hydrocarbons which exist 

only in the vapor phase or gas phase under all reservoir conditions. 

A system consisting of only dry gas is usually composed of up to 98% by volume methane. As 

a result, such reservoirs show an increase in specific volumes due to reduction of reservoir 

pressures, in agreement with the laws of expansion of compressible fluids. 

Physical Properties of Reservoir Fluids 

Petroleum, or more commonly, oil, has several physical properties. They are; density, viscosity, 

shrinkage, and gas in solution. 

Density is defined as the weight of oil per unit of volume and is expressed at a particular 

temperature and pressure. To eliminate the different units used, the petroleum industry has 

generally adopted the API Unit as the measurement of density. The API unit is derived as follows: 



REVISION 2006 6-8


First the Specific Gravity (SG) is obtained by: 

SG = 

Density of Oil 

Density of Water 

The temperature at which the measurement is taken should also be noted, i.e. at 60°F for both. 

141.5 

° API = – 131.5 

SG 

or 

SG 

= 

141.5 

131.5 + ° API 

Therefore, if the SG is 1.0 for water, the °API value would be 10°. Oil with an °API value greater 

than 10° would be lighter than water. 

The previously described reservoir fluids have the following ranges API gravity and Specific 

Gravity. 

Type of Fluid SG °API 

Crude Oil 0.82 – 1.07 41.1 – 0.7 

Volatile Oil 0.78 – 0.85 49.9 – 35.0 

Gas/Condensate 0.70 – 0.78 70.6 – 49.9 

Fresh Water 1.00 10.0 

It can be seen that lighter mixtures have the lower density, SG, and that SG is a function of 

composition. 

°API gravity indicates the market value of the oil. The higher the ºAPI gravity, the more valuable is 

the oil. This is due to lighter oil containing more valuable products, such as gasoline. 

°API gravity is measured with a calibrated hydrometer reading density, specific gravity or °API 

gravity directly. 

Viscosity is basically the physical property which influences the ability of a fluid to flow. Flow rate 

is inversely proportional to fluid viscosity. A high pressure is needed to displace very viscous oil. 

Viscosity (μ), like density (ρ), is a function of fluid composition, pressure and temperature. The 

unit used for viscosity is centipoises (cP). 

1 Poise = force in dynes/cm 2 to move a fluid at a rate of 1 cm/sec through an area of 1 cm 2 ; as a 

reference water has a viscosity of 1 cp at 68°F or 20°C. 



REVISION 2006 6-9


The Shrinkage of oil is related to its changes in density, therefore, it is also related to the 

composition, pressure and temperature of the fluid. Shrinkage is used to measure the change in 

liquid volume in the reservoir from one pressure to another; for example, as the oil moves from the 

reservoir to the surface tanks. Normally liquid volumes in a reservoir shrink to a lesser volume as 

the reservoir pressure declines, except for the retrograde conditions in reservoirs. 

Shrinkage is expressed in B O . B O is the formation volume factor. The B O factor is related to the 

amount of oil in the reservoir and the amount in the tanks on surface. 

Volume in reservoir 

B O 

= 

Volume at surface 

Classification of Oil 

Crude oil chemistry is relatively complex with a typical crude oil containing several thousand 

different compounds belonging to eighteen different hydrocarbon series. A complete chemical 

analysis of crude oils, in terms of compounds present, is a difficult, if not impossible task. Less 

complete types of analysis (e.g. by the amounts of lumped elements present) are often useful for 

determining its physical characteristics. 

Difficulty in classifying oils by the chemical composition of their constituents has led to 

widespread use of simpler, less technical classifications. These classifications focus on 

differentiating between paraffin base and asphalt base oils. The distinction between paraffin base 

and asphalt base oils serves only as a broad classification. Most asphaltic oils contain traces of 

solid paraffins, and most paraffin oils contain some asphaltic residue. Some oils, said to be of 

“mixed base”, will respond to the tests for both paraffin and asphalt in equal degrees. The tests for 

classifying oil are described below. 

Paraffin base oils are oils in which paraffins predominate. When cooled to low temperatures, these 

oils yield an appreciable amount of light colored wax that is not readily attacked by acids or 

dissolved by ether chloroform, or carbon bisulphide. 

Asphalt base oils are oils in which asphalt predominates. After slow distillation, these oils yield a 

lustrous, solid residue, usually jet black in color, which exhibits a conchoidal fracture and which 

dissolves in the previously mentioned solvents. 

Often the only classification made on crude oils is made based upon its API° gravity. 

Petroleum Reservoirs 

Petroleum is produced from the pores between or within the grains of a rock. In order for a rock to 

be a reservoir, it must contain sufficient porosity and permeability to permit commercial production 

of hydrocarbons. Porosity is a measure of the percent of pores or voids which a rock contains. The 

figure below illustrates the position of pores in a typical sandstone reservoir. Oil and gas occurs 

within the pores or voids between the individual sand grains. Typical sandstone reservoirs contain 

porosity values of 10 to 35%. Permeability is a measure of the ability of the pore fluid to move 

from one void to another. Permeability can be envisioned as a “pipeline” between the pores. 

The pore in a typical reservoir may contain gas and/or oil. However, all reservoirs contain varying 

amounts of water. The water may occur as a thin film around the grains or it may be present as 

droplets. Water free oil has been produced from reservoirs which contain up to 50% water. 



REVISION 2006 6-10


Most of the prolific oil production and indeed most of the 

giant oilfields are in sandstones. Sandstones generally exhibit 

high primary permeability as well as secondary permeability 

characteristics. For example, most of the oil and gas produced 

in Russia is from clastic reservoir rocks. Much of the 

production from the USA has also been from clastic reservoir 

rocks. There are some notable exceptions. The Permian Basin 

of the south-western U.S.A. is a carbonate (limestone) 

reservoir as are the majority of the huge oilfields in the 

Middle East. 

Sandstones and limestones are two distinct rock types. 

Compositionally, sandstone is formed through inorganic and 

clastic processes. Erosion of land surfaces containing all types of existing rocks creates sediments 

which are transported into a basin where compaction occurs, creating sandstone rock. Looking 

closely at the sediments, one would see that it contains pebbles, sand grains, and other bits and 

pieces of rocks. All the sediment of this kind is referred to as clastic rocks, meaning accumulated 

particles of broken rock and of skeletal remains. The clastic materials are held together in the rock 

by cement, generally silica. 

Limestones (carbonates) are primarily made of the mineral calcite. They are the result of sediment 

formed by precipitation of minerals from solution in water, either the result of biochemical 

reactions or by inorganic chemical processes. Inorganic processes mean that calcite is precipitated 

directly from water; small spheroidal grains, about the size of sand grains, called oolites are found 

on the floor of oceans. They are composed of calcium carbonate (CaCO 3 ). Oolites found in 

limestones mean that they were formed in ancient oceans. Cave deposits are also calcite, but they 

are formed in a wet cave on land. 

Biochemically formed limestones are created by the action of plant and animal life that extract 

calcium carbonate (CaCO 3 ) from the water in which they live. The CaCO 3 may be either 

incorporated into the skeleton of the organism or precipitated directly. Regardless of the 

mechanism, when the organism dies, it leaves behind a quantity of CaCO 3 and over geologic time 

thick deposits of this material build up. Reefs are examples of such accumulations. 

Another precipitant is the mineral CaMg(CO 3 ) 2 ; it occurs in large concentrations and it forms a 

rock called dolomite. It is not the result of direct precipitation in sea water, but rather is formed by 

replacement of pre-existing deposits of calcite. 

The manner in which the type of rock creating the reservoir rock was formed is important in 

understanding the reservoir behavior. The manner in which they were derived creates essential 

differences as it affects their fundamental properties of porosity and permeability. Primary 

permeability is dependent upon the manner of formation. Sandstones generally have greater 

primary permeability than limestone unless the latter is a reef, or similar, structure. Clastic 

sedimentary rocks tend to be more porous because of the uniqueness of their origin. They are the 

result of erosion and transportation; these two processes tend to cleanse the material of everything 

but silica sand grains and they are often of similar size and shape. Carbonates on the other hand, 

tend to have greater secondary permeability because they are more soluble and reactive. Fractures 

and faults within carbonates (which are highly soluble) tend to enlarge in size and lateral extent 

when water flows through these fractures and faults. 



REVISION 2006 6-11


Figure 6 - 8 

Marine Sedimentary Depositional Environments 

Sandstone Reservoirs 

The term sand refers to a particular grain size (62 μm – 2 mm), not to a particular composition. The 

performance of the sandstone as a reservoir rock, its combination of porosity and permeability, 

depends upon the degree to which it is truly a sand. Texture should reflect similar sized grains, not 

a combination of coarse and fine grained material. The best sandstone reservoirs are those that are 

composed primarily of quartz grains of sand size, silica cement, with minimal fragmented particles. 

The quality of the initial sandstone reservoir is a function of the source area for the material, the 

depositional process, and the environment in which the deposition took place. Sandstone reservoirs 

2 

are commonly 25 meters (80 ft.) thick, are lenticular and linear spatially, and less than 250 km 

(100 mi. 2 ) in area. They range in age from the oldest being Cambrian (in Algeria) to the youngest 

being Pliocene (Caspian region in Ukraine). In the U.S.A., two-thirds of the sandstone reservoirs 

are Cenozoic in age. 

Sandstone reservoirs form extensive stratigraphic traps. Many of the sandstones change 

composition, e.g. to a shale, within the sandstone unit; at this point they are said to pinch out. 

Others represent ancient upland river channels that have left sand in the channel that has converted 

to sandstone. Often these sand channels are stacked one on top of another which means that 

hydrocarbons are free to migrate between the reservoirs. Other sandstone reservoirs are deltaic in 

origin, meaning they represent ancient river deltas similar to the Mississippi River delta that 

extends into the Gulf of Mexico. Successive sandstone layers exist in the subsurface that were 

created in alternating marine and terrestrial environments. Sandstone reservoir rocks are the result 

of a number of processes that can occur on dry land as well as beneath the sea. 

Carbonate Reservoir Rocks 

The most interesting and perhaps impressive aspects of carbonate reservoir rocks are their fossil 

content. Fossils rage from the very small single cell to the larger shelled animals. Prior to the 

1920’s, carbonate reservoir rocks were relatively rare and prior to 1950 they were all regarded as 

essentially organic rocks. This changed when textural studies of carbonates in Iraq and the 

Bahamas showed that carbonates are also the result of inorganic processes. Most carbonate rocks 

are deposited at or in very close proximity to the site of creation. Transportation of material is less 

common and sorting is essentially non-existent. The “best-sorted” carbonate rocks are oolites in 

which the “grains” are the same size and shape. Oolites are not “sorted” at all, but they are formed 

with the sizes and shapes that they have in the carbonate rock and were cemented in place. 



REVISION 2006 6-12


Most carbonates begin as skeletal assemblages. They are the accumulation of the remains of 

carbonate secreting animals and plants. Carbonates may form on gently sloping platforms such as 

continental shelves in shallow, warm saline water. The resulting rock forms layers of limestone in 

the subsurface that extend spatially over great distances as in the case of the Michigan Basin or the 

Cretaceous in Europe. Carbonates may also form as linear or continuous reef trends, as in the case 

of the Cretaceous reef structure in South Louisiana. 

Porosity and permeability are greatly reduced in ancient carbonate reservoir rocks due to 

compaction and cementation. Porosity tends to increase as a result of secondary processes of 

leaching and dolomitization of the limestone that occurs after the carbonate rock was formed. 

Recent carbonate sediments have higher porosity values, but porosity is always reduced during 

burial and compaction which may reduce the thickness of a limestone bed by 25% under no more 

than a few hundred meters of overburden. Dolomitization enables a carbonate reservoir rock to 

resist compaction. Dolomites are normally less porous than limestones at shallow depths, but they 

retain their porosity better during burial and are less affected by compaction. Therefore they tend to 

be better reservoir rocks because they contain more voids that hydrocarbons can fill. 

Carbonate reservoirs represent a broader range of producibility than do the more common 

sandstone reservoirs. The most prolific and sustained production rates come from carbonate 

reservoirs. Carbonate reservoirs can also be at the other extreme in terms of hydrocarbon 

production. Many carbonate reservoirs will not yield their oil and gas at all unless they are 

artificially fractured. On average, and despite some outstanding carbonate reservoirs, sandstone 

reservoirs produce more hydrocarbons per unit volume of reservoir. 

Reservoir Traps 

Where hydrocarbons exist today in the subsurface depends upon the juxtaposition of source rocks, 

reservoir fluids, and reservoir traps. There are two types of migration when discussing the 

movement of petroleum, primary and secondary. Primary migration refers to the movement of 

hydrocarbons from within source rock and into reservoir rock. Secondary migration refers to the 

subsequent movement of hydrocarbons within reservoir rock; the oil and gas has vacated the source 

rock and has entered the reservoir rock. 

A trap consists of an impervious stratum that overlies the reservoir rock thereby preventing 

hydrocarbons from escaping upward and laterally. This impervious stratum is called a roof, or cap, 

rock; it intervenes to collect and hold hydrocarbons underground. The roof/cap forms a seal, or 

barrier, which creates the needed conditions for a pool. Trap material must have a lower 

permeability than the existing rock material through which the hydrocarbons are flowing. The rock 

forming the seal is also referred to as a capping bed. Porosity controls the volume of hydrocarbons 

present in a given trap while permeability controls the volume of hydrocarbons that can be 

extracted from the trap. 

Most of the hydrocarbons that form in sediments do not find a suitable trap and eventually flow to 

the surface along with formation water. It is estimated that less than 0.1% of all organic matter 

originally buried becomes trapped in an oil pool. The greatest ratio of hydrocarbon pools to volume 

of sediment is found in rock no older than 2.5 million years and almost 60% of all oil discovered is 

found in strata of Cenozoic age. 

There are three basic types of hydrocarbon traps: 



REVISION 2006 6-13


Structural 

Structural traps are created when the seal or barrier is concave upward (looking from below). The 

geometry is formed by tectonic processes after deposition of the reservoir beds involved. 

There are two types of structural traps: 

1. Folds result in the physical bending (deformation) of the rock units without breaking. The 

simplest form is an anticline – creating an Anticline Trap. The rock units undergo bending 

very slowly over long periods of geologic time. These types of traps are often found adjacent to 

mountain ranges. 

2. The second type of structural trap is a Fault Trap. These are the result of fractures (breaks) 

within the rock units where one side has moved relative to the other side. Faulting may be the 

sole cause of the formation of a trap or more commonly, faults form traps in combination with 

other structural features such as folding which is common along the Gulf coast region of 

Louisiana. Often an oil field is the result of multiple faulting, forming many structural traps 

containing hydrocarbons. 

Figure 6 - 9 

Structural and Stratigraphic Traps 

Stratigraphic 

Stratigraphic traps are created when the seal or barrier is formed by changes in lithology or rock 

type (which also controls porosity and permeability), during the deposition of the reservoir beds 

involved. Lithological variations may be depositional, as in the cases of reefs, channels, and sand 

bars. Lithological variations may also be post-depositional in nature; truncations occur where 

erosion has removed a significant portion of an existing tilted structure followed by deposition of 

another lithological rock unit, the latter forming the roof rock and thus becoming the capping bed. 



REVISION 2006 6-14


Combination Trap 

The geometry of a combination trap is the result of a combination of tectonic processes and 

changes in lithology. A common trap that would be an example of a combination trap is a salt 

dome. A salt dome is a mass of NaCl (sodium chloride) generally of a somewhat cylindrical shape 

and with a diameter of about 2 km near the surface, though the size and shape of the dome can 

vary. This mass of salt has been pushed upward from below through the surrounding rock and 

sediments into its present position. The source of the salt lies in a deeply buried layer that was 

formed in the geologic past. 

Salt is an evaporite. It exhibits no inherent rock structure. It is subject to deformation resulting 

from applied pressure and temperature. Salt beds are formed by the natural evaporation of sea 

water from an enclosed basin. In the North Sea area this occurred during the Triassic period. 

Subsequently, the precipitated salt layer is buried by successive layers of sediments over geologic 

time until segments of it begin to flow upward due to increasing overburden pressure toward the 

surface of the earth. The origin of salt domes is best explained by the plastic-flow theory. 

Salt has a density of 2.2 SG under standard conditions. At a depth of about 12,000 feet, the mass of 

the overlying sediments exerts a compressive, downward force. The combination of this applied 

pressure (overburden) and accompanying increase in temperature (geothermal) causes a density 

decrease and salt begins to flow like a plastic substance. A small fracture in the overlying, higher 

density sediments or a slightly elevated mass of salt above its surroundings would trigger the 

upward movement. Once this upward salt movement begins, salt from elsewhere in the salt bed 

moves into the region surrounding the salt plug to replace the salt that is flowing upward to form 

the salt plug. The upward movement of the salt plug, or dome, continues as long as there is 

sufficient source of salt “feeding” the dome or until the upward movement is halted by a more rigid 

formation. Once equilibrium is reached, upward movement of the salt dome ceases, but may begin 

again if sufficient sediments are added to the weight of the overburden which again increases the 

load pressure on the parent salt mass. Salt domes come in all sizes and shapes, but all have certain 

characteristics. For example, they have a cap rock. The cap rock is composed of limestone located 

at the top of the dome followed by, in descending order, gypsum, anhydrite, and finally rock salt. 

The average cap rock is between 300 to 400 feet thick, but cap rocks up to 1,000 feet thick are 

known to exist. Cap rock is created as the salt dome ascends through the overlying materials. The 

top of the dome dissolves as it rises through the sediments and the residual constituents of the salt 

become concentrated at the top of the rising plug becoming three layers: limestone, gypsum, and 

anhydrite. The anhydrite zone represents the less soluble components of the salt that accumulated 

as the halite was dissolved by pore fluids. The anhydrite zone locally contains abundant celestite 

that probably formed as the result of interaction with external Sr-bearing brine. The calcite zone 

formed by bacterial alteration of sulfate accompanying hydrocarbon destruction. The calcite zone 

contains significant amounts of sulfide minerals and oil. The sulfide-rich calcite zone is dominated 

by locally massive iron sulfides. These sulfide concentrations resulted from the interaction of deep 

heated metal-bearing formational brines with bacterially derived reduced sulfur in the ambient cool 

ground waters. 

The cap rock of some salt domes, and sometimes the rock salt itself, is found to overhang, or drape 

down, the side of the main salt mass. It is commonly found to overhang on one or two sides. The 

reason for the overhang probably is dependent upon the nature of circulating waters in the 

sediments through which the dome is ascending. Salt is soluble and dissolves, but the cap rock is 

not very soluble and is left more intact. Thus the appearance of the cap rock “overhanging” the 

main salt body is the result of the dissolving of the salt body within the subsurface, but not 

dissolving the cap rock. Cap rock has all the characteristics of a petroleum reservoir and often 



REVISION 2006 6-15


contains hydrocarbons. Cap rock also contains free sulfur. Free sulfur is present in cap rock of 

almost all salt domes, but it appears in commercial quantities only in salt domes that have a thick 

limestone cap. 

FORMATION DAMAGE AND PROTECTION MECHANISMS 

Introduction 

The objective of a well completion or workover is to establish or re-establish unrestricted 

communication between the wellbore and an oil or gas producing formation. Any restriction to 

flow around the wellbore reduces the maximum flow potential and possibly the ultimate 

hydrocarbon recovery. If the restriction is the result of formation porosity or permeability 

impairment, it is called formation damage. Other factors that cause a reduction in flow rate into the 

wellbore are turbulence, partial completion, partial formation penetration (i.e., not drilled deep 

enough), and poor perforation practices. These are called pseudo-damage because they are not the 

result of pore-size or permeability reduction. Discussion in this section is limited to factors that 

cause formation damage and to measures that can be used to protect the formation from damage 

during drilling, completion and workover operations. 

Formation Damage Mechanisms 

Formation damage may be the result of physical, chemical, or bacterial alteration of the producing 

formation rock and/or in-situ fluids from contact either with whole fluids or with components of a 

drilling and/or completion and workover fluid. The mechanisms of formation damage from 

invading fluid generally include: 

• plugging of pore spaces on the face of the formation by a mud-cake during drilling. 

• dispersion of clays or other minerals contained in the rock matrix. 

• water-blocking. 

• narrowing of fine pore spaces (capillaries) through adsorption of water-soluble polymers. 

• dislodgement of fine particulates contained within the pore spaces to lodge in pore throats. 

• chemical precipitation of solution salts. 

• emulsion formation. 

• change in rock wettability. 

• presence of sulfate-reducing or slime-producing bacteria and their precipitated byproducts. 

• swelling of in-situ clays to fill pore spaces. 

During drilling, the density of the drilling fluid is usually maintained to give a hydrostatic pressure 

greater than the formation fluid pressure to prevent a possible well blow-out. Therefore, as new 

formation is exposed by the drill bit, drilling fluid is forced into the formation by the positive 



REVISION 2006 6-16


differential drilling fluid column pressure. Particles smaller than the formation pores are introduced 

into the formation during mud spurt loss, but they rapidly bridge on the pore throats in the near 

wellbore formation. Particles larger than the formation pores accumulate at the formation face, 

initiating a mud cake build-up. The invasion of whole drilling fluid is stopped quickly by the mud 

cake, and only filtrate is allowed to penetrate the formation. 

Unless the formation is exceptionally permeable or fractured, the plugging of the formation by 

drilling fluid solids is very near the wellbore and usually can be by-passed easily by perforating 

after production casing is set. However, if the casing and formation are perforated in drilling fluid, 

this formation face damage is transferred into the perforation channel and can become even more 

difficult to remove than the mud cake on the face. Removal is complicated, because of the 

tendency of the drilling fluid in the perforations to dehydrate and form a cement-like plug. 

A second type of solids plugging can occur when fine drill solids or drilling fluid additives 

penetrate the formation to depths beyond the near wellbore region. These solids migrate into an 

ever increasing number of radial passageways. This increase is due to the radial flow geometry. 

When the well is flowed during production, if the invading particles do not traverse the entry route 

in reverse, they are likely to become lodged in narrow passageways and block further fluid flow. 

The problem is exacerbated when unfiltered brine, such as a completion or workover fluid, 

containing a low solids content is used as a working fluid. After reviewing other models proposed 

to describe wellbore impairment by internal cake formation in the rock matrix, van Velzen and 

Leerlooijer, in agreement with Maly, concluded that, for fluids with low solids content, the degree 

of impairment depends on particle/pore-size ratio and inflow velocity. When inflow velocities are 

greater than 3.94 inch/minute, the generally accepted “1/3 to 1/7 rule” applies. This rule states that 

particles larger than one-third of the pore throat diameter will bridge at the pore opening on the 

formation phase to form an external filter cake, while particles between one-third and one-seventh 

of the pore throat diameter will invade the formation and be trapped to form an internal plug. 

However, for low fluid flow velocities (i.e., < 0.8 inch/minute), a “1/3 to 1/7 rule” is probably more 

applicable. It may be logically concluded from these references that it is better to have either a very 

dirty or a very clean fluid in contact with the formation rock than a slightly dirty one. 

Solids plugging also can occur from the swelling or migration of clays or non-clay minerals within 

predominantly sandstone formations. Clay and other fine particles are held on the pore surfaces by 

a variety of forces including, London, van der Waals, electrostatic, Born repulsion, hydrodynamic, 

and gravitational. These particles can be mobilized when these forces are altered by fluid flow 

and/or chemically incompatible fluids. 

Montmorillonites and mixed-layer clays are typical examples of swelling clays. In the presence of 

fresher water than that originally contained in the pore space, montmorillonites with a high content 

of sodium can swell to many times their original volume. This swelling plugs pore openings and 

reduces porosity and permeability. While smectites are the principal forms of swelling clays, illites 

also can swell when they coexist with smectites. 

Kaolinite has a platelet structure similar to smectites clays but exhibits little or no swelling 

characteristics. This group of clays usually is attached loosely to the host rock and can be 

mobilized by the infiltration of fluids with salinities below the critical salt concentration for 

colloidally induced particle release or with flow rates high enough to exceed the critical shear stress 

necessary to carry the fine particles away from the pore surfaces. Other clay or mineral types with 

needle-like or regular crystalline shapes may be affected similarly by the chemistry of invading 

fluids, whether they are the filtrate of drilling fluid or the whole fluid of completion and workover 

brines. These mobilized fines then migrate until they are trapped at pore restrictions (the pore 



REVISION 2006 6-17


throat) and thus reduce the permeability of the rock. Mobilization, migration, and retention of clays 

and other fine particles have been recognized as the major formation damaging factors in sandstone 

formations. If these fines are trapped near the wellbore, very significant production losses occur 

because of the reduction in the number of alternative flow paths into the borehole. The prevention 

of formation damage by clay swelling and fines migration requires detailed information about the 

composition of the producing formation and expert planning based on the analysis of the 

information gathered. 

A secondary source of solids that can cause formation damage is the precipitation from solution of 

insoluble salts or colloidally suspended particulates created when completion or workover fluids 

contact incompatible connate water. For example, when calcium brines come in contact with 

connate water containing CO 2 , insoluble calcium carbonate (CaCO 3 ) may precipitate and plug 

near-well-bore pore spaces. Whenever high-density calcium and/or zinc brines are used, formation 

of salt precipitates is possible when the connate water contains significant amounts of the anions 

2− 2− 2− 

3− 

− 

CO 

3 

, SO 

4 , S , PO 

4 

, F , or dissolved NaCl. NaCl precipitates because it is less soluble that 

the corresponding calcium or zinc chlorides or bromides; this precipitation is a problem if it occurs 

in tight formations where it may be difficult to contact with fresh water to cause dissolution. Also, 

because of their physical and chemical properties, heavy brines or oil-based drilling fluids filtrates 

may cause the precipitation of asphaltenes and paraffins from the in-situ hydrocarbons. Dilution of 

calcium and zinc completion brines with formation connate water may also cause precipitation of 

the corresponding hydroxide because of the rise in the pH of the diluted solution. Finally, the 

subject brine may interact with the rock matrix to loosen fines and/or cause precipitation of oxides 

or silicates. 

Formation damage may also be the result of a change in the nature of the fluid wetting the surface 

of the pore space, i.e., a wettability change. Because of the chemical makeup of the silica (sand) 

and clays that compose the majority of the world’s producing formations, water has a greater 

affinity for the exposed solid surfaces than does oil. Both the water and the exposed solid surfaces 

in these formations are polar. Water is attracted to the surface, where it forms a film over and 

around each surface and particle. Unless the oil in place consists of components other than large 

molecules of hydrogen and carbon, the hydrocarbon is non-polar and thus is only weakly attracted 

to the solid surface. Given these conditions, the formation is water-wet. If, however, the 

hydrocarbon has been oxidized or otherwise contains polar groups, such as carboxyls, amines, 

amides, sulfonates, and thiols, the partial polarity of the hydrocarbon may actually be such that it is 

attracted to the rock surface. Water is displaced, and the formation rock is oil-wet. 

When the wettability changes, it does so non-uniformly; i.e., some of the pore surfaces remain 

water-wet and some become oil-wet. Because the relative permeabilities of water and oil are 

different, and depend on the nature of the fluid wetting the pore surface, a zoning effect results and 

hydrocarbon productivity is impaired. The formation is more permeable to oil when the formation 

is water-wet because the oil flows through the center of the pores that compose the larger flow 

channels while water stays in the narrower channels and along the rock surfaces. Conversely, the 

formation is more permeable to water when the formation is oil-wet because the water is not 

restrained by its affinity for the polar surfaces of the rock and is less viscous that the oil. 

Sometimes the change from water-wet to oil-wet causes a well that is producing almost no water to 

begin producing almost all water. Wettability changes can be caused by the presence of surface 

active agents in the drilling, completion, or workover fluids used to penetrate the productive zone 

of the formation. Agents such as detergents and lubricants in water based drilling fluids and oilwetting 

agents in oil based fluids are the most likely causes of wettability changes. Excessive use 



REVISION 2006 6-18


of surfactants in completion fluids to prevent emulsion formation between the working fluid and 

the formation hydrocarbons may also change the characteristic wetting of the formation rock. 

The natural tendency of water to wet polar surfaces contributes to another formation damage 

mechanism called water-block. The significant force of attraction between water molecules and the 

polar molecules at the surface of a solid is evidenced by the spontaneous rise of water in a glass 

capillary tube. The height to which the liquid column rises is dependent on its density, surface 

tension, and the radius of the capillary tube. The maximum height is reached when the hydrostatic 

pressure of the liquid column equals that of the forces causing the liquid to rise. The hydrostatic 

pressure is then equal to the capillary pressure. Mathematically: 

2σ 

(cosθ 

) 

gh L 

ρ = 

r 

where, 

g = the gravitational constant, ft/sec 2 

h L = equilibrium height of the liquid, feet 

ρ = the liquid density, lbm/gal 

σ = the liquid surface tension, dynes/cm 

θ = the contact angle between the immiscible liquid interface and the solid surface 

r – radius of the capillary, inches 

The term gh L ρ is the force driving the liquid into the capillary and is the mathematical description 

of the capillary pressure. As is apparent from this relationship, the pressure required to remove 

water from a water-wet formation pore is inversely proportional to the radius of the pore. Capillary 

pressure promotes the displacement of oil by water but resists the displacement of water by oil. In 

most reservoirs, native pressures are great enough to overcome capillary pressure. However, in low 

pressure and tight, low permeability formations, the capillary pressures resisting displacement of 

water by oil may be significant enough to cause permanent impairment. The problem of waterblock 

is especially serious in the near-wellbore region, where the pressure drop of the oil/water 

interface approaches zero. The probability of water-block increases as the volume of fluid lost to 

the formation increases. 

Another cause of capillary impairment is in-situ emulsification of in place oil with 

completion/workover fluids. Even in the absence of commercial surfactants, concentrated salt 

solutions have an inherent tendency to form mechanical emulsions with crude oil. Stable 

mechanical emulsions are formed by mixing normally immiscible fluids at high shear rates. In-situ 

emulsification is possible because, while the total volume of flow may be low, the rate of shear at 

the constrictions in the flow channels and pore throats is high. Because the viscosity of oil/brine 

emulsions is very high, their movement through the rock is severely restricted. As the emulsion 

droplets become trapped in the capillary pore spaces, called an emulsion block, the effective 

permeability of the formation rock is impaired. 

Large, polar, water soluble polymers used for viscosity and filtration control may adsorb on the 

rock matrix in pore spaces and thus reduce the flow channels available for hydrocarbon movement. 

Removal of these polymers is difficult both because of the strong attraction and because the 

polymers are not mutually soluble in water and hydrocarbons. The slime produced by sulfate 

reducing bacteria is similar to water soluble polymers and has essentially the same effect on 

permeability. Sulfate reducing bacteria are very resistant to hostile environments, such as salt 



REVISION 2006 6-19


solutions and high temperatures and pressures. They are ubiquitous environmental organisms that 

are usually introduced through untreated drilling, completion and workover fluids. 

Formation Protection 

To ensure the best possible prospect for reducing or eliminating formation damage during drilling, 

completion and workover activity, a compilation should be made of all the information available on 

the well and the producing formation. Geological information may be obtained from logs, 

production formation cores, and mineralogy (with good samples, independent mineralogical 

analysis is possible). A well history, including depth, bottomhole temperature, type of drilling fluid 

and/or the nature of any fluids previously in contact with the producing formation, and composition 

of produced fluids, especially gases, will help immeasurably with planning to prevent formation 

damage. If practical, a laboratory evaluation should be made of a formation core to determine 

permeability and fluid compatibility and to ascertain potential detrimental interactions. When all 

the examinations and analyses are complete, the optimum fluid(s), additives, and procedures 

designed to minimize formation damage can be recommended. 

Even without the extensive analysis recommended, it is generally prudent to follow some generally 

accepted practices to prevent formation damage during drilling, completion and workover. First, 

filtered brine usually reduces the chance of both introducing foreign particles into the formation 

and causing water sensitive clays to swell. Second, use of an empirically selected surfactant helps 

reduce the chance of emulsion formation, wettability change, and even fines migration. Third, 

selection of a chemically compatible drill-in/completion/workover fluid reduces the probability of 

insoluble salt precipitation. 

Of all the possible mechanisms to prevent formation damage during drilling, completion or 

workover, the most significant is the prevention of fluid loss. This sometimes is accomplished by 

increasing the viscosity of the working fluid. Because flow rate in porous media is inversely 

proportional to viscosity, increasing the viscosity of the working fluid at bottomhole conditions can 

significantly reduce the loss of fluid to the formation. The most common practice from preventing 

loss of fluid to the formation is to use a combination of increased viscosity and salt or calcium 

carbonate based particles to bridge the pore spaces on the formation face. Both these materials are 

acid soluble and therefore can be removed by acid treatment if they are not otherwise removed by 

washing or production of the well. 

In a study designed to find and use the best practice for preventing formation damage during 

workover operations in Prudhoe Bay, Dyke and Crockett reached the following conclusions: 

1. The primary cause of formation damage during workovers was the invasion of fine solids 

and debris from downhole operations, such as near perforation, milling and scraping. 

Stopping fluid losses prevents the entry of these fines into the formation. 

2. Loss control material (LCM) pills, when properly formulated, usually clean up easily from 

perforations and even more readily from open hole formation face, leaving no formation 

damage. Badly formulated pills cause severe damage. 

3. The loss of clean, i.e. filtered fluids during completion/workover operations has little effect 

on future productivity when the formation has relatively high permeability. 

4. Tight formations that inherently take small amounts of fluid are most likely to be damaged 

by the loss of fluid. Fluid loss is therefore more important in these wells. 

5. In non-fractured wells, viscous pills are capable of reducing, but not stopping, fluid loss. 

To be effective in stopping fluid loss, graded particulates must be added to the viscous pill 

to seal the formation. 



REVISION 2006 6-20


6. In fractured wells, both coarse and fine solids may cause irreversible damage. If the intent 

is to stop the loss of fluid, special care must be taken to ensure that any bridging materials 

added to the LCM contain materials coarse enough to bridge the fractures at the formation 

face. If, in addition to the bridging materials, fluid dilatency can be achieved, the 

probability of success in stopping fluid loss is markedly improved. 

7. Finally, when working with less than salt saturated fluids, it is prudent to use an 

antibacterial agent to inhibit the growth of slime producing bacteria so that these bacteria 

are not injected into the producing formation. 

DRILL-IN FLUIDS 

Introduction 

The rapid growth of extended reach and horizontal wells using open hole completion techniques 

was a key factor in the popularity of reservoir drill-in fluids. Their popularity has resulted in an 

emphasis on the practices used while drilling into the reservoir. Now that drilling down to the payzone 

and drilling in the pay-zone are viewed as two distinct steps, oil and gas producers require 

that service companies demonstrate an expertise in both drilling and completion operations. This 

cross-functional approach has resulted in a steady improvement in drill-in fluid formulations. 

Donovan and Jones described the qualities desired in an optimally formulated drill-in fluid. Their 

ideal drill-in fluid would: 

1. conform to all acceptable health, safety, and environmental standards 

2. bridge all exposed pore openings with specially sized bridging material 

3. deposit a non-erosive filter cake that is easily and efficiently removed during the 

completion phase, and 

4. retain desirable drilling fluid properties. 

Horizontal wells drilled and completed in unconsolidated sand reservoirs have become feasible, 

due to new technology and completion methods. Wells of this type require sand control such as 

long open hole gravel packs or the installation of mechanical sand exclusion devices (slotted liners, 

pre-packed screens, etc.). 

Usually the wells are drilled with conventional drilling fluids to the top of the pay-zone and casing 

is set. The cement is then drilled out to the casing shoe and the shoe tested. The drilling fluid is 

then displaced with a “low damage potential drilling fluid” generally consisting of polymers, 

viscosity enhancers, and insoluble particles for building a filter cake. The particles are usually 

graded salt (NaCl) or graded calcium carbonate (CaCO 3 ). 

These compounds are used because they are soluble in under saturated brines or hydrochloric acid. 

One problem with prior art filter cakes is that they are often difficult to remove requiring high 

pressures to do so. Under such conditions, damage results to the formation. Such damage is 

believed to occur because the filter cake invades the formation and becomes “cemented” thereto 

and must be forcibly removed at high pressure; the forceful removal is thought to cause damage to 

the permeability of the formation. 

After the open hole interval has been drilled to total depth, the gravel pack screen or sand exclusion 

device is placed in the open hole interval. To do this, it becomes necessary to circulate the drilling 

fluid from the open hole so that the well can be gravel packed or the sand exclusion setting can be 



REVISION 2006 6-21


tested. To do this it is necessary to perform a displacement of the drilling fluid with a solids-free 

completion brine, sometimes viscosified with a water soluble polymer, e.g. xanthan gum 

derivative. Concern about the physical erosion of the filter cake with the completion fluid is also 

always an issue. That is, the filter cake should be durable and stable enough to permit the 

completion or other operation to take place and protect the well bore during the entire operation. 

The ideal drilling fluid or drill-in fluid would mechanically seal all pore openings exposed to the 

wellbore, stay intact during completion operations, then be easily removed by production of oil and 

gas. Problems arise in designing these fluids because production zones vary in pressure, 

permeability, porosity, and formation configuration. Generally, fluids used to control fluid leak-off 

in permeable formations require an initial high pressure spike before removal can begin - from 

about 300 to 500 psi. This pressure spike is indicative of damage to the original permeability of the 

permeable formation. It would be desirable if fluids could be devised which would easily form an 

impermeable filter cake to prevent the loss of expensive completion fluids to the formations and 

which effectively protect the original permeable formation during various completion operations 

such as a gravel packing or wellbore workovers. At the same time, however, it is also highly 

desirable for the filter cake to be easily removable at the beginning of production, causing little or 

no damage to the formation. 

Water-soluble organic polymers, such as HEC, have been used to slow the leak-off rate of a clear 

fluid into a permeable formation. However, these polymers will not effectively control the leak-off 

rate. This can only be controlled by bridging the pore opening with rigid or semi-rigid particles of 

sufficient size and number. Bridging materials used for this purpose (e.g., oil-soluble resins, gel 

pills, sized salt, and benzoic acid) rely upon breakers or dissolution to remove them. Unfortunately, 

these methods have not always been effective, resulting in considerable formation damage or 

unsatisfactory leak-off control. 

PERFFLOW ® System 

Baker Hughes Drilling Fluids has developed systems based upon a bridging technique which not 

only positively controls leak-off of the fluid into the formation, but also provides a bridging zone 

that can be easily and effectively removed by the produced fluid. PERFFLOW systems provide 

effective leak-off control over a wide range of permeabilities. Depending on the type of completion 

programmed for the well, usually no breakers or fluids to dissolve the bridging solids are required; 

removal is accomplished by flowing the well. 

PERFFLOW 's fluid loss control mechanism involves the mechanical bridging of properly sized 

particles on pore throat openings. The graph below illustrates the particle size distribution of the 

graded calcium carbonate (MIL-CARB) used in PERFFLOW. Note the broad particle size 

distribution available to bridge a wide range of permeability, from a few milli-Darcys to over 10 

Darcys 



REVISION 2006 6-22


Percent Less Than 

100 

80 

60 

40 

20 

0 

1 1.5 2 3 4 6 8 12 16 24 32 48 64 96 128 192 

Particle Size, μ 

Figure 6 - 10 

Particle Size Distribution of MIL-CARB 

PERFFLOW Systems Application 

Three product compositions are available to prepare PERFFLOW fluids: W-307, W-306, and 

PERFFLOW DIF. W-307 is used in preparing PERFFLOW fluids utilizing sodium chloride or 

potassium chloride brines. W-306 and PERFFLOW DIF are used in preparing PERFFLOW fluids 

utilizing potassium chloride, sodium chloride, calcium chloride, calcium bromide and zinc 

bromide, formate brines or mixtures of these brines. 

Standard Systems Formulation 

LOW-DENSITY PERFFLOW Systems (9.2- 10.5 ppg) 

1. Preferred Barrel Formulation: 

• 1 PERFFLOW DIF (55 lb/25 kg bag) plus 0.94 bbl of brine 

• 0.94 bbl of brine includes 2% to 4% KCl 

• 1 gal/100 bbls X-CIDE ® 102 (25% by volume glutaraldehyde) 

2. Optional Barrel Formulation: 

• W-306 (5 or 55 gallon) @ 2.00 gpb to YP = 20 or W-307 (5 or 55 gallon) @ 2.50 gpb to 

YP = 20 

• 1 MIL-CARB TM (50 lb bag) 

• Final volume contains 2% to 4% KCl; brine volume to 1 bbl 

• 1 gal/100 bbls X-CIDE 102 (25% by volume glutaraldehyde) 

HIGH-DENISTY PERFFLOW Systems ( > 10.5 ppg ) 

1. Preferred Barrel Formulation: 

• 1 PERFFLOW DIF (55 lb/25 kg bag) YP = 20 

• 2 to 3 ppb Magnesium Oxide to buffer pH = 8.0 



REVISION 2006 6-23


• 0.94 bbl of brine (no KCl) 


2. Optional Barrel Formulation: 

• W-306 (5 or 55 gallon) @ 2.00 gpb to YP= 20 

• 1 MIL-CARB (50 lb bag) 

• 2 to 3 ppb Magnesium Oxide to buffer pH = 8.0 

• Brine volume to 1 bbl 


Displacement 

Prior to building or loading the PERFFLOW system, all pits and lines should be cleaned and 

flushed with water/seawater. Cement and float equipment should be drilled with the existing fluid 

prior to displacing the hole with PERFFLOW. Best results can be achieved if the hole can be 

circulated with seawater prior to the PERFFLOW displacement. The circulating rate should be as 

high as possible with pipe rotation to minimize channeling. Pump a 25 to 30 barrel caustic pill 

followed by a 25 to 30 barrel high viscosity (3 gal/bbl W-306) pill then follow with the 

PERFFLOW system. 

Open Hole Displacement for Completion 

At total depth, a short trip to the casing should be made and a high viscosity 25 barrel pill pumped 

and circulated to surface. The drilling assembly should be pulled out of the hole and a hole opener 

picked up and washed to bottom. The hole and casing can be displaced with a filtered completion 

fluid at this time. A 20 barrel pill with 3.0 gallons per barrel W-306 in water should be pumped to 

separate the two fluids. If any tight hole was experienced or concern for lost circulation exists, a 

PERFFLOW polymer pill (W-306 without calcium carbonate) can be spotted to cover the open 

hole plus 500 ft inside the casing. In this case, the workstring should be pulled 250 ft inside the 

casing. The casing is then circulated until clean brine is returned to the surface. Pull the hole opener 

out of the hole, then rig up and run in the hole with the completion assembly. 

General Guidelines 

• The pH should be controlled from 8.0 to 9.0. 

• All solids control equipment should be run while drilling cement. Sodium bicarbonate will 

aid in lowering the pH and will precipitate soluble calcium. Pre-treat the active fluid 

system with 1 ppb of Sodium bicarbonate before drilling cement. 

• High viscosity sweeps will be used throughout the operation. These sweeps should have a 

yield point greater than 50. All sweeps should be at least 100 barrels to increase their 

effectiveness. 

• Wiper trips are an important tool in gauging hole conditions. A wiper trip at least every 500 ft 

can detect a build-up of pressure identified by swabbing. 

• Packing fraction refers to that state when a fluid begins to exhibit semi-plastic tendencies due 

to solids. For example, the packing fraction of bentonite in freshwater is approximately 5% 



REVISION 2006 6-24


by volume while barite would be about 65% by volume. Balling and lost circulation are 

frequent problems while drilling conductor, surface or any large diameter hole. Generally, 

this is a function of the concentration of drilled cuttings in the annulus. High 

concentrations of active clay (gumbo) cuttings in the annulus result in cuttings adhering 

together on the bit and pipe. In addition, cuttings increase fluid density and hydrostatic 

pressure. Factors affecting the cuttings concentration are penetration rate, circulating rate, 

and cuttings transport efficiency. The following equation provides the maximum 

penetration rate for a given circulation rate and desired cuttings concentration. 

PERFFLOW Systems: General Engineering Guidelines 

The potentially severe borehole problems intrinsic with horizontal drilling can be minimized 

dramatically with the selection of a non-damaging drilling fluid system possessing optimum holecleaning 

and lubrication capabilities. 

Drilling fluids for vertical wells are often chosen primarily for their ability to control the formation 

surrounding the reservoir. By modifying the fluid properties and dynamics, these same fluids, in 

many cases, have been used to drill horizontally. 

In this regard, it is important to devote particular attention to the cleaning, lubrication, and 

maximum pay zone protection capabilities of the fluid system. For gravel packed completion, pay 

zone protection is extremely important. Damage to the formation will inhibit perforation filling, 

open hole performance, and reduce well productivity. It is extremely important to obtain a clean 

interface between the gravel pack sand and the formation sand. 

As with vertical wells, deciding which fluid system, or combination of systems, to use in a 

horizontal application depends upon the geology of the prospect, historical successes and failures, 

environmental constraints, and the experience of the fluid company and operator. 

When planning a drilling fluids program for a horizontal well, it is often advantageous to view the 

prospect in the same manner as the production engineer – from the downhole objective up. For 

gravel pack purposes, this usually requires the use of drill-in fluids. 

The drill-in fluid should be designed to minimize damage to the reservoir. If the proposed drill-in 

fluid design conflicts with fluid designs up-hole, then a change in the fluid program may be 

warranted. The carrying capacity, inhibition, and lubricity of the fluid should suit the formations 

drilled and the prospective well profile. 

PERFFLOW DIF fluids were designed to be used as drill-in fluid systems. A drill-in fluid 

possesses the desirable properties of a good drilling fluid and provides the necessary attributes of a 

completion fluid. In this respect, PERFFLOW DIF should be the only fluid the producing 

formation sees during the final drilling operation. This point, however, brings up the question as to 

when the fluid should be introduced into the drilling operation. 

Even though a PERFFLOW DIF fluid can be formulated to handle most hole conditions during 

the drilling operation, it may be more economical and effective to use conventional fluids such as 

oil-base fluids, PHPA systems, or simple bentonite-base fluids for most of the drilling operation. 

When to introduce the PERFFLOW DIF becomes a judgment call on the part of the drilling and 

production engineers. The following guidelines and comments are provided to assist in making this 

decision. 



REVISION 2006 6-25


Under-reaming Operation 

• Where a cased hole exists to the top of the pay zone and it is desired to drill and under-ream 

for an open-hole completion, PERFFLOW DIF can be introduced to drill the pilot hole but 

must be used before starting the under-reaming operation so that the final exposed producing 

formation sees only the drill-in fluid. In most cases, it may be best to change to the drill-in 

fluid while in the casing to avoid delay once the drilling operation has started. Displacement 

would also be more efficient in the cased hole, and exposure of the formation to two different 

fluids would be avoided. 

• Where an old perforated cased hole exists through the pay zone and it is desired to cut a 

section through the pay zone and to under-ream, the rheological properties and hole cleaning 

capacity of the PERFFLOW DIF system can be adjusted to effectively carry steel cuttings 

out of the hole; thus PERFFLOW DIF can be used as the cutting fluid. This adjustment, 

however, will likely require treatment with additional W-306, W-307 or certain products such 

as BIOZAN ® or XANVIS ® to obtain higher flow properties than are normally maintained. 

Therefore, if the existing fluid in the casing is deemed adequate to do the milling operation, 

then it may be more economical to use it and then change to PERFFLOW DIF before 

initiating the under-reaming operation. 

Drilling and Completing Horizontal Section 

PERFFLOW DIF fluid can be used to cut a window and to drill the build section of the horizontal 

well. Whether to use the PERFFLOW DIF fluid for this purpose depends upon the same reasoning 

used in the under-reaming operation. If the existing fluid in the casing is deemed satisfactory for 

the milling operation and will effectively stabilize the formation to be immediately drilled, then it 

may be more economical to use that fluid. Where the existing fluid will require extensive treatment 

or a complete change-out, then consideration should be given to using the PERFFLOW DIF fluid 

for this purpose. 

Extended Drilling Required from Casing Point/Kick-Off Point 

Since PERFFLOW DIF is to be used as the drill-in fluid, it does not contain any highly active drill 

solids such as clays. Therefore, using the PERFFLOW DIF to drill several thousand feet of hole 

prior to encountering the producing formation may not be the best choice, unless the operator is 

prepared to replace a significant volume with clean PERFFLOW DIF fluid prior to drilling into 

the pay-zone. 

Mixing Procedures 

Ensure all pits, lines and pumps are clean and have been flushed with water/seawater prior to 

mixing. Mixing sequence depends on the products being used. When mixing the W-306 or W-307 

products, the following mixing order is recommended. 



REVISION 2006 6-26


Water / Brine 

0.87 - 0.90 bbl 

W-306 / W-307 2.0 - 2.5 gal/bbl 

MIL-CARB TM 

X-CIDE ® 102 

KCl 

50 lbs/bbl 

0.01 - 0.015 gal/bbl 

1% - 3% (optional) 

Product selection of W-306 or W-307 is dependent on the density of the mix water that will be 

used. In freshwater, KCl, or sodium chloride brines, either the W-306 or W-307 can be used. Once 

selection of a specific product (W-306 or W-307) has been made, do not mix the two products 

together in the same system as they will not perform up to specification. 

In higher brine weights, (above 10.0 ppg NaCl), W-306 is the product of choice. When 

mixing W-306 in heavy brines (above 11.0 ppg CaCl 2 ), it is recommended to use some type of 

shearing device that would also increase the temperature of the mix water to the range of 140°F to 

150°F. 

As noted in the above formulation, KCl additions are optional. KCl additions are recommended for 

additional inhibition should shale stringers be encountered while drilling the production zone. Also, 

if time is available, the W-306 and W-307 products should be allowed to disperse in the mix 

water/brine for 1 to 2 hours before the additions of MIL-CARB TM are made. 

The following mixing order is recommended if PERFFLOW DIF is used: 

Water / Brine 

PERFFLOW® 

X-CIDE® 102 

Magnesium Oxide 

KCl 

0.94 bbl 

55 lbs/bbl 

0.01 - 0.015 gals/bbl 

3 lbs/bbl 

1% - 3% (optional) 

The PERFFLOW DIF product can be mixed in all ranges of brines. When using divalent salts 

such as CaCl 2 , it is recommended to use 3 lbs/bbl of Magnesium Oxide as a pH buffer. Once all the 

PERFFLOW DIF has been mixed, and should additional viscosity be required, small additions of 

W-306 can be added to the system. Prior to these additions, pilot testing should be performed to 

determine the exact quantity needed. 

If displacement volumes are to be mixed on location, care should be taken when mixing the initial 

volume. Small batch mixes are recommended at first in order to prevent any calcium carbonate 

from settling out of the system versus trying to mix large volumes of fluid in a poorly agitated fluid 

tank. Should time constraints prohibit mixing small amounts of fluid, consideration should be given 

to adding a small quantity ( 1 / 8 to 1 / 4 lb/bbl) of XANVIS ® , BIOZAN ® , or XC POLYMER to the mix 

water before the PERFFLOW additions are initiated in order to prevent any calcium carbonate from 

settling out of the system. 



REVISION 2006 6-27


Typical Properties 

Brine KCl NaCl CaCl 2 

Fluid Weight, ppg 9.2 9.7 11.4 

Funnel Viscosity, sec/qt 40 - 50 40 - 50 40 - 50 

Plastic Viscosity, cP 10 - 20 15 - 25 20 -30 

Yield Point (YP), lb/100ft 2 20 - 25 20 - 25 20 -30 

Gel Strengths, lb/100ft 2 4 / 7 4 / 7 4 / 7 

API Fluid Loss, ml/30 min < 4 < 4 < 4 

pH 8.5 - 9.0 8.5 - 9.0 7.5 - 8.5 

Troubleshooting 

Problem Possible Cause Recommended Action 

Increase in API 

Filtrate 

Increase in 

Rheological 

Properties 

Decrease in 

Rheological 

Properties 

Slugging Pipe for 

trip 

Sliding 

1. Shift in particle size 

2. Polymers degrading 

3. Bacterial problem 

1. Shift in particle size 

2. Incorporated solids 

Polymers degrading 

Air entrapment 

BHA Configuration 

Hole Geometry 

1. Pilot test to determine displacement volume 

required. 

2. Pilot test with W-306 TM / 307 TM or BIO-LOSE TM . 

3. Pilot test 1 gallon X-CIDE® 102 per 100 bbls 

fluid. 

1. Pilot test to determine displacement volume 

required. 

2. MBT increased, pilot test for displacement 

volume. 

Pilot test with W306/307, XANVIS®, BIOZAN® or 

XAN-PLEX D Polymer to determine treatment level. 

Add 1/8 to 1/4 gallon LD-8 ® per 10 bbls of slug 

volume. Use salt for some portion of the slug weight 

Add 3% TEQ-LUBE ® 

Foaming High Surface Tension Elevate pH to 9.0. Add defoamer LD-8 ® 

Stuck Pipe Aggressive build rate Consult stuck pipe pills section of manual 

CLEAR-DRILL ® Fluids 

Introduction 

To balance the formation pressures experienced down-hole, conventional drilling fluids are 

required to cover a wide density range. In the majority of cases, the required fluid density has been 

achieved by the addition of insoluble minerals, typically barite, which are suspended in the fluid by 

a viscosifier. The CLEAR-DRILL family of drilling fluids departs from this standard technology 



REVISION 2006 6-28


by utilizing a variety of highly soluble formate salts to achieve the required density. By selecting 

the correct salt, any density in the range 1.0 (8.34 ppg) to 2.35 S.G.(19.6 ppg) can be achieved with 

a solids-free system. 

The advantages of a solids-free system are significant. The plastic viscosity of a fluid is greatly 

affected by the quantity of suspended solids. Consequently, clear brine systems will exhibit lower 

plastic viscosities than conventional fluid systems. This will result in lower equivalent circulating 

densities (ECD) and lower pressure losses downhole, resulting in greater drilling efficiency. These 

two effects are particularly important in slim hole drilling where, because of the narrower pipe and 

annulus diameters, the reduction of downhole pressure losses and ECDs is essential to ensure good 

rates of penetration while preventing fracturing of the formation. 

Environmental considerations are playing an increasingly significant part in drilling activities 

throughout the world, and drilling fluids have come under particularly close scrutiny, both onshore 

and offshore, in terms of their environmental potential. The CLEAR-DRILL system has been 

developed partly in response to environmental pressures for cleaner drilling fluid systems. This has 

been achieved by utilizing biodegradable salts with very low acute toxicity in conjunction with 

benign polymers and by eliminating the routine use of weighting materials, many of which contain 

quantities of heavy metals such as lead, cadmium, and mercury. 

Clearly, no system can be acceptable solely on environmental grounds; a high level of performance 

must also be present. Fluids in the CLEAR-DRILL system provide optimum rheological 

properties, excellent stability and a very high degree of inhibition to reactive shales. The absence of 

barite helps to ensure that the CLEAR-DRILL fluids are non-damaging to the pay zone, thus 

eliminating the need for more complicated “drill-in” fluids. Other salts such as sodium chloride or 

potassium chloride can be used as bridging materials, providing the necessary fluid loss control 

with materials which are readily removed during the well clean-up operation. The CLEAR- 

DRILL system comprises three brines: sodium formate, potassium formate, and cesium formate. 

All these salts can be used either to formulate solids-free drilling fluid systems or in conjunction 

with conventional weighting materials to build regular drilling fluids. 

Function of Formates 

The use of clear brines for drilling is not a new idea. Sodium chloride and calcium chloride have 

been available for many years and the former, in particular, has been widely used as the basis for 

low-weight drilling fluids. These brines however, have significant limitations. Sodium chloride is 

limited to a maximum density of 1.2 S.G. (10.0 ppg) while calcium chloride brines suffer from a 

high degree of incompatibility with the majority of polymers used in conventional drilling fluids. 

The use of highly soluble salts to provide density rather than insoluble weighting materials can 

have a major effect on solids loading within the system. The benefit of a clear brine system 

increases with increasing density as shown in the figure below. 



REVISION 2006 6-29


Comparison of Solids Content in Muds Weighted with Various 

Weight Materials 

35 

30 

%Solids Volume 

25 

20 

15 

10 

CaCO3 

Barite 

5 

CLEAR-DRILL 

0 

1.0 1.1 1.2 1.3 1.4 1.5 1.6 

Mud Weight (SG) 

Figure 6 - 11 

Comparison of Solids Content in Fluids Weighted with 

Various Weight Materials 

In order to provide drilling fluids based on clear brines which can cover a wide range of densities 

and exhibit a high degree of compatibility with viscosifying and fluid loss polymers, other salts are 

needed. Formates were selected because of their very high solubilities and, initially, as a result of 

their excellent compatibility with xanthan polymers. The relationship between formate salts and 

xanthan polymers is synergistic in terms of thermal stability; the higher the formate salt 

concentration, the higher the temperatures at which xanthan polymers retain their viscosity. This 

relationship is illustrated in the figure below. 



REVISION 2006 6-30


220 

Effect of CLEAR-DRILL Salts on Thermal Stability of Xanthan 

Polymers 

200 

Transition Temperature (°C) 

180 

160 

140 

120 

CLEAR-DRILL N 

CLEAR-DRILL K 

100 

0 10 20 30 40 50 60 70 80 

Salt Concentration (% w/w) 

Figure 6 - 12 

Effect of CLEAR-DRILL Salts on Thermal Stability of Xanthan 

Polymers 

Further investigation revealed that formates are compatible with all commonly used drilling fluid 

polymers. Sodium and potassium formates are readily available and the use of these products on 

their own, or in combination, can provide brines with densities up to approximately 1.58 S.G. (13.2 

ppg). 

A further advantage of formates is that they will not react with any cations to produce insoluble 

salts, thus minimizing the possibility of producing precipitates downhole upon contact with 

formation water. In particular, all the divalent metal formates are readily soluble in water. 

Additionally, the toxicity of formates is generally very low, both to mammalian and aquatic 

species, thus enabling environmentally benign fluids to be formulated for use in sensitive areas. 

The complete absence of chlorides from the system allows easy disposal of waste fluid into fresh 

water systems, a significant benefit when drilling on land. 

Description of System Components 

CLEAR-DRILL ® N 

CLEAR-DRILL N (sodium formate) is a crystalline white powder, highly soluble in water, giving 

mildly alkaline brines up to a density of 1.35 S.G. (11.2 ppg). The product can also be supplied as a 

concentrated brine. 

• System applicability: CLEAR-DRILL N 

• Temperature limitations: Stable at 250°C (482°F) 

CLEAR-DRILL ® K 



REVISION 2006 6-31


CLEAR-DRILL K (potassium formate) is a crystalline white powder, highly soluble in water 

giving mildly alkaline brines up to a density of 1.58 S.G. (13.2 ppg) The product can also be 

supplied as a concentrated brine. 

• System applicability: CLEAR-DRILL K. 


CLEAR-DRILL ® C 

CLEAR-DRILL C (cesium formate) is a crystalline white powder, highly soluble in water giving 

alkaline brines up to a density of 2.35 S.G.(19.6 ppb). It is commercially available. 

• System applicability: CLEAR-DRILL C 


Weighting Materials in CLEAR-DRILL ® Brines 

Conventional weighting materials can be used in CLEAR-DRILL brines to provide fluids above 

the normal density ranges available for the solids-free systems with the exception of barite in 

CLEAR-DRILL K solutions with densities above 1.30 SG (10.8 ppg, 45% by weight). Calcium 

carbonate, hematite (DENSIMIX), and manganese tetraoxide (MICROMAX) can all be utilized. 

High concentrations of CLEAR-DRILL K (i.e. above 1.50 S.G. (12.5 ppg)) result in the partial 

solubilization of barium sulphate to provide levels of soluble barium up to 2,000 mg/l, depending 

on time of exposure, temperature and barite availability. This phenomenon has not been observed 

in lower density CLEAR-DRILL K solutions, or in other formate solutions even at saturation. 

Products Used in CLEAR-DRILL Fluids 

XAN-PLEX ® D / Xanthan Gum Polymer 

XAN-PLEX D Polymer is the primary viscosifier for all systems where temperatures are not 

expected to exceed 150°C (302°F). These polymers provide the best rheological profile of any 

commonly available polymer and result in shear-thinning fluids under dynamic flow with good gel 

structures under static conditions. In addition, there is a marked degree of synergy between xanthan 

polymers and concentrated formate solutions which results in a demonstrable increase in the upper 

temperature limit for these products. 

• System applicability: ALL 

• Temperature limitations: Up to 150°C (302°F) 

KEM-SEAL ® 

KEM-SEAL is a synthetic copolymer of AMPS and alkylacrylamide and has proven thermal 

stability to temperatures in excess of 250°C (482°F). KEM-SEAL also provides filtration control 

under high temperature conditions and is resistant to most types of contamination. 




REVISION 2006 6-32


• Temperature limitations: Up to 250°C (482°F). For high temperature applications where 

prolonged exposure to conditions over 150°C (302°F) will occur, then KEM-SEAL is used as 

the primary viscosifier. 

MIL-PAC TM LV 

MIL-PAC LV can be added in significant quantities to a CLEAR-DRILL fluid to obtain the 

required filtration control without contributing to viscosity. 


• Temperature limitations: Up to 120°C (248°F). For low to moderate temperature applications, 

up to 120°C (248°F), MIL-PAC LV is the normal additive for fluid loss control in formatebase 

systems. For higher temperatures, MIL-PAC LV is replaced with KEM-SEAL ® . 

Calcium Carbonate 

Calcium carbonate can be used as a bridging agent or as a weighting material. Dolomite (calcium 

magnesium carbonate) or graded, ground marble can also be used. 



MICROMAX 

MICROMAX (manganese tetraoxide – Mn 3 O 4 ) is a water-insoluble, acid soluble, dispersible 

weighting material for drilling fluids with ideal properties for providing high density fluids. The 

material has a specific gravity of approximately 4.8 @ 20°C, resulting in a roughly 15% volume 

reduction of solids compared to barite. Although somewhat harder than barite, MICROMAX is 

slightly less abrasive than barite because the particle shape is predominantly spherical, thus 

providing a higher density while avoiding the abrasivity problems normally associated with 

hematite. The particle shape and size (typically less the one micron) are also responsible for nonimpairment 

of return permeabilities and the low impact that the product has on plastic viscosity as 

particle-to-particle interactions are minimized. 



Standard Laboratory Formulations and Properties 

These data represent a cross-section of the laboratory work carried out Shell Oil Company’s 

laboratories in The Hague and in Baker Hughes Drilling Fluids’ laboratories as part of a joint 

venture research project between Shell and Baker Hughes Drilling Fluids. 



REVISION 2006 6-33


1.20 SG 1.32 SG 1.44 SG 1.56 SG 1.68 SG 2.24 SG 

CLEAR-DRILL N, g 128.1 219.8 - - - - 

1.58 SG CLEAR-DRILL K Brine, ml - - 257.0 327.0 237.4 

2.25 SG CLEAR-DRILL C Brine, ml - - - - 65.1 345.0 

Water, ml 292.0 242.9 93.0 23.3 - - 

XC ® Polymer, g 1.0 0.5 0.75 0.5 0.5 1.0 

MIL-PAC TM LV, g 2.0 2.0 2.0 2.0 1.0 1.0 

KEM-SEAL ® , g - - - 2.0 - - 

Citric Acid, g - - - - 1.0 2.0 

Soda Ash, g 0.5 0.5 0.5 0.5 0.5 0.5 

W.O. TM 30 , fine, g 10.0 10.0 10.0 10.0 10.0 10.0 

Table 6 - 1 

Laboratory Fluid Formulations 

Properties 1.20 SG 1.32 SG 1.44 SG 1.56 SG 1.68 SG 2.24 SG 

Fann 600 rpm 48 57 47 55 29 45 

Fann 300 rpm 32 34 30 35 19 31 

Fann 200 rpm 25 26 23 24 15 25 

Fann100 rpm 18 16 15 15 10 18 

Fann 6 rpm 5 4 4 4 3 6 

Fann 3 rpm 4 3 3 3 2 5 

Gels (lbs/100 ft 2 ) 5/6 3/5 4/5 3/5 3/6 6/7 

PV (cP) 16 23 17 20 10 14 

YP (lbs/100 ft 2 ) 16 11 13 15 9 17 

pH 10.5 10.2 10.6 11.0 10.2 10.8 

API Filtrate, ml 4.0 0.7 1.8 0.4 3.5 3.0 

HT/HP (250°F/121°C), ml 14 20 17 14 20 20 

Table 6 - 2 

Initial Properties of Laboratory Fluid Formulations 



REVISION 2006 6-34


Post H/R (250ºF/121°C) 1.20 SG 1.32 SG 1.44 SG 1.56 SG 1.68 SG 2.24 SG 

Fann 600 rpm 36 45 50 60 31 45 

Fann 300 rpm 25 27 33 37 20 30 

Fann 200 rpm 20 20 25 29 16 24 

Fann 100 rpm 14 12 17 18 11 16 

Fann 6 rpm 4 3 5 4 4 5 

Fann3 rpm 3 2 4 3 3 4 

Gels (lbs/100 ft 2 ) 4/4 2/3 4/6 3/5 4/6 4/5 

PV (cP) 11 18 17 23 11 15 

YP (lbs/100 ft 2 ) 14 9 16 14 9 15 

pH 10.2 10.0 10.3 10.8 10.2 11.3 

API Filtrate, ml 5.5 5.5 3.2 2.5 3.6 3.4 

HT/HP (250F/121°C), ml 22 26 20 19 22 20 

Table 6 - 3 

Properties of Laboratory Formulations after Hot Rolling 

BIO-LOSE ® 90 SYSTEM 

Introduction 

The BIO-LOSE 90 system was developed by Baker Hughes Drilling Fluids for use as a low solids 

horizontal drilling fluid which would provide low dynamic fluid loss and rheological parameters 

which are compatible with long horizontal sections. Its primary use is in fractured formations, both 

sand and calcareous. The primary viscosifier used is DRISPAC ® , with BIO-LOSE ® added to 

control filtration. BIO-LOSE is a non-fermenting chemically modified starch which does not 

require any biocides and can be used over a wide pH range in most water-base fluids. The third 

product required in the make-up of a BIO-LOSE 90 system is MIL-BREAK 943, which will 

prevent any emulsification from occurring as drilling progresses. When mixed according to Baker 

Hughes Drilling Fluids guidelines, no further additives will be required. 


The BIO-LOSE 90 system can easily be adjusted to the operator’s specifications if changes in 

rheological properties are required. The Yield Point is usually maintained at 6 to 8 lb/100 ft 2 to 

ensure the system will be in turbulent flow. 

Filtration Control 

Under normal conditions, the API Filtrate ranges from 5.0 to 6.0 cc/30 min. A very tight filter cake 

will be formed and laboratory tests have shown the dynamic filtrate to be very low. The 

concentration of BIO-LOSE required is 13 to 14 kg/m 3 (6.0 – 6.5 lbm/gal). 



REVISION 2006 6-35


Reservoir Considerations 

After drilling over 180 wells with the BIO-LOSE 90 system, Baker Hughes Drilling Fluids has 

found this fluid system to be compatible with formation fluids. Laboratory testing is available and 

return permeability tests have been conducted on this fluid system with favorable results. The 

presence of an emulsification inhibitor ensures that minimal formation damage will occur as the 

reservoir is penetrated. 

Fluid Density 

The BIO-LOSE 90 system can be maintained in a density range of 8.5 to 8.6 lb/gal if 

adequate solids control equipment is available. The solids content of the fluid should be monitored 

closely and if the level climbs above 2%, consideration should be given to discarding some fluid. 

In most cases, Baker Hughes Drilling Fluids recommends that the hole volume be displaced with 

fresh fluid every 500 to 600 ft of new hole. 

Directional Tools 

In the BIO-LOSE 90 system, there are no additives which could prove detrimental to the 

directional drilling equipment. If a bridging agent is required, Baker Hughes Drilling Fluids 

recommends the addition of various grades of calcium carbonate, which will not affect the 

performance of downhole tools. Drilling fluid losses have been minimal when using the BIO- 

LOSE 90 system without any bridging agent – even when drilling a carbonate zone where the 

primary porosity comes from micro-fracturing. 

Recommended Fluid Properties 

Fluid Density 

8.5 – 8.6 lb/gal 


35 - 45 sec/qt 

Yield Point 4 – 8 lb/100 ft 2 

pH 7.5 - 8.0 

API Filtrate 

4.0 - 6.0 cc/30 min. 

MILBREAK 943 

0.5% - 1.0% by volume 

OMNIFLOW ® DIF SYSTEM 

System Benefits 

The OMNIFLOW ® DIF system is a specially formulated, invert emulsion, drill-in and completion 

fluid using an approved external phase oil. This system is designed to minimize formation damage 

by using carefully selected surfactants at minimal concentrations to avoid emulsion blocking. MIL- 

CARB bridging agent has been chosen for the system as its wide particle size distribution is suited 

for bridging most reservoirs. OMNIFLOW ® DIF system’s simple formulation is designed for easy 

filter cake lift off. OMNIFLOW ® DIF system’s organic continuous phase and internal phase 

activity make the system ideal for long term control of sensitive shales encountered before and 

while drilling the reservoir. Characteristically for an invert emulsion system, the OMNIFLOW 

DIF system exhibits minimal pore-pressure penetration and is stable at high downhole 



REVISION 2006 6-36


temperatures and pressures. OMNIFLOW ® DIF is formulated to maximize low shear-rate 

viscosity, an essential requirement for optimal hole cleaning. 

System Components 

The following products are utilized in the OMNIFLOW ® DIF system. 

Component 

External Phase 

Product 

Synthetic or Mineral Oil 

Brine Phase Brine (usually CaCl 2 ) 

Viscosifier 

Emulsifier 

Addition Filtration Control 

Bridging Agent 

Weighting Agent 

Table 6 - 4 

CARBO-GEL 

OMNI-MUL 

DFE-433 

MIL-CARB 

MIL-BAR 

OMNIFLOW DIF Products 

OMNI-MUL ® is an emulsifier specially selected for the system. A concentration of 1 gal/bbl 

(23.81 L/m 3 ) of this product provides sufficient emulsification and aids in filtration control while 

not contributing significantly to formation damage. The concentration of OMNI-MUL ® may have 

to be increased in formulating fluids for high temperature/high density applications. 

DFE-433: Generally, at temperatures below 250°F (121°C) no filtration control agents are required 

as the system has inherently low filtration values due to the emulsifier and bridging agent 

combination. However, at higher temperatures, especially approaching 300°F, the addition of DFE- 

433 may be required to control filtration to within acceptable levels. Laboratory tests show that 

DFE-433 has marginal effect on the lift-off pressures and return permeability results. 

CARBO-GEL ® is the recommended viscosifier for the OMNIFLOW ® DIF system. 

Concentrations of up to 8.0 ppb (22.9 Kg/m3) have been laboratory tested and no adverse effects 

on lift-off pressures or return permeability results have been noted. 

MIL-CARB ® : A concentration of 50ppb (143 Kg/m 3 ) of MIL-CARB ® should be maintained in 

the system for effective bridging. 

Continuous Phase (Base Oil) : OMNIFLOW ® DIF may be formulated with any type of synthetic 

or mineral oil or diesel. The choice of oil makes no difference to the lift-off pressures and return 

permeability results. 

Salinity of Brine Phase 

Any salinity may be used in formulating OMNIFLOW ® DIF. The level of salinity in the system 

should be chosen in the normal way for invert emulsion fluids. If required, the salinity of the brine 

phase may be increased to allow a reduction in barite concentration. Care should be taken not to 

increase salinity to a concentration greater than saturation, particularly for CaCl 2 brine. 



REVISION 2006 6-37


Densities 

The system can currently be formulated to a maximum density of 14.5 ppg (1.74 sg). In 

formulations with densities above 14.0 ppg (1.68 sg), excess barite tends to plug both gravel and 

screens. Adjusting the OWR in order to reduce the barite concentration does not improve return 

permeability results. 

Drilled Solids 

Maintaining the drilled solids content at


CARBO-CORE 

Native State Drilling and Coring Fluids 

The CARBO-CORE system is a no-water-added oil-base fluid system used as a native state coring 

and drilling fluid. It is used whenever potential invasion of water or oil filtrate with surfactants, 

into producing reservoirs must be avoided. The CARBO-CORE system is temperature stable, 

even after contamination with water. Should contamination be severe, it can be converted to a 

CARBO-FAST or CARBO-TEC ® system. 

A drilling fluid that minimizes changes in water/formation wettability and water saturation in a 

producing reservoir will result in maximum permeability and oil production. Invasion of water 

filtrate into producing reservoirs can alter connate water saturation. Invasion of oil filtrate, 

containing strong surfactants, can possibly alter the wettability characteristics of the formation. A 

naturally water-wet sand may become oil-wet if the filtrate contains strong surfactants. 

The alteration of water saturation and/or wettability characteristics can result in errors in predicting 

and evaluating reservoir performance based on core data. In some cases these actions may also 

decrease production after the well is completed. 

No-water-added oil-base coring fluids have been used previously to retrieve unaltered cores for 

laboratory analysis. These cores are used to better define water saturation, connate water salinities, 

and oil water contacts. Cores that are recovered are also used to determine reservoir permeability 

and porosity as well as for laboratory flow tests to better define the reservoir characteristics. This 

technology is now present as the drilling fluid, CARBO-CORE. 

Lease crude has been used, and is preferable as a drilling or coring fluid when unaltered cores are 

required. However, density requirements, or the lease crude characteristics, may make its use 

impracticable. 

CARBO-CORE is prepared with minimum surfactants and a near zero water content, using 

mineral or diesel oil. 

Components 

Base Oils 

CARBO-CORE fluids may be prepared with lease crude, No. 1 diesel, No. 2 diesel, mineral oil, or 

a combination of oils to meet individual requirements. If lease crude is used, it must be free of 

emulsion breakers and filming amine corrosion inhibitors, which can alter wettability 

characteristics. Lease crude must also have an aniline and flash point above the desired minimum. 

High viscosity lease crude may be blended with mineral oil or diesel to the desired viscosity range. 

No. 1 diesel oil or mineral oil is more desirable than No. 2 diesel, since No. 2 diesel may contain 

additives that may cause formation contamination. Pilot testing is recommended prior to the use of 

various oils due to their solubility and viscosity differences. 

Water Phase 

CARBO-CORE systems are prepared without water. However, 2% to 5% water may be 

incorporated during displacement of a water-base fluid. However, if the water content is in excess 



REVISION 2006 6-39


of 5% to 10%, depending upon the type of shale and/or cores being drilled, the system should be 

displaced, diluted, or converted to a standard controlled activity CARBO-DRILL ® system. 

Mixing Procedures 

Because water content is contrary to the design of the CARBO-CORE system, special care must 

be taken when mixing and displacing the system. 

The mixing tank should be clean and all lines flushed with diesel or a used CARBO-DRILL 

system which is then discarded. Pump the required amount of base oil, add the emulsifier and add 

the required amount of viscosifiers. The application of heat, up to 180°F (82°C), will increase 

dispersion of product, evaporate water, decrease mixing time, and result in a more stable system 

overall. The calculated amount of CARBO-TROL ® HT should be added as quickly as possible, 

based upon the mixing system available. 

After a satisfactory dispersion, with adequate viscosity, has been made, weight material may be 

added to obtain the desired density. If additional viscosity is necessary, small additions of 

viscosifiers may be used. 

Displacement 

Because a low to zero water content is desired in this system, the displacement procedure can have 

a tremendous effect upon the overall system performance. Ideally, casing should be run and the 

cement plug be pumped with the CARBO-CORE fluid. 

If this is not possible, displacement prior to drilling out of casing is highly recommended. 

Displacement at high flow rates while rotating and reciprocating the drillpipe will minimize water 

contamination. In situations where water content must be maintained near zero, displacements have 

been made using a standard CARBO-DRILL oil-base fluid to displace the water-base fluid, 

followed by the CARBO-CORE system. 

Water Contamination 

The CARBO-CORE system has proven to be temperature stable even after contamination with 

water, as indicated in the figure below. Because the rate of osmotic transfer of water from the fluid 

to the shale increases as the water content increases, small quantities of water should not greatly 

affect the stability of the shale. 



REVISION 2006 6-40


Figure 6 - 13 

No-Water-Added CARBO-CORE Typical Flow Properties 

However, should water contamination exceed 5% to 10%, it is recommended to dilute with oil, 

displace the system with new fluid, or simply convert the CARBO-CORE to a conventional 

CARBO-DRILL SM system. This can be accomplished with the addition of calcium chloride to 

reduce the activity of the water phase to a desired range. Further additions of CARBO-MUL ® HT 

and CARBO-TEC TM will maintain fluid stability as the water content increases. 

COMPLETION FLUIDS 

Introduction to Clear Brines 

Proper completion fluid selection is an important parameter directly related to the success of any 

well. The invasion of dirty fluids into the formation will cause damage or severe impairment to the 

productivity or injectivity of a well. Clear solids-free brines have gained widespread acceptance as 

part of a general practice for completion and workover applications due to their ability to meet the 

following desired properties and performance. 

• Non-damaging to the formation 

• Density ranges to provide sufficient hydrostatic pressure 

• Economical 

• Commercially available 

• Environmentally safe and friendly 

• Low corrosion rates 

• Stable under in-situ conditions 



REVISION 2006 6-41


The term brines refers to solutions prepared from dissolved salts in water or naturally occurring 

seawater or formation waters. Brines are considered non-formation damaging because they can 

deliver the appropriate density desired and can be filtered to remove particulates which would 

cause potential damage. The selection of appropriate brine based on the above criteria will deliver a 

system which minimizes hydration and dispersion of formation clays and is compatible with most 

additives used during completion and workover. The additives typically used in completion and 

workover are surfactants, viscosifying agents, bactericides, corrosion inhibitors, etc. 

Clear brines are used for a wide variety of completion and workover applications. 

• Packer fluids 

• Kill fluids 

• Under-reaming fluids 

• Drill-in fluids 

• Drilling fluids 

• Perforating fluids 

• Gravel packing fluids 

Factors of most importance when selecting a brine for a particular application is density, formation 

damage, crystallization, and, of course, economics. Many different types of salt can be used. Some 

can be used as an individual salt to achieve the desired properties or can be utilized as mixed salt 

type brine systems. Costs, density, and formulations can be drastically different based on the brine 

type and crystallization point desired. Generally, the higher the density and lower crystallization 

point desired, the higher the cost. Consequently, it is imperative to formulate the proper brine 

density and its desired properties at optimum cost. 

Effects of Temperature and Pressure 

Temperature 

• Volume expansion 

• Density decrease 

• Crystallization 

Pressure 

• Compressibility 

• Well control 



REVISION 2006 6-42


Brine Density, lb/gal Expansion Compressibility 

8.4 - 9.0 0.00017 3.8 E-6 

9.1 - 11.0 0.00025 1.5 E-6 

11.1 - 14.5 0.00033 1.4 E-6 

14.6 - 17.0 0.00040 1.4 E-6 

17.1 - 19.2 0.00048 1.5 E-6 

Table 6 - 7 Brine Density Due to Thermal Expansion 

Average Temperature = (BHST + Surface Temperature) ÷ 2 

Average Density = Density @ 68°F (20°C) - ((Avg. Temp. – 68°F) × Correction Factor) 

Density Correction due to Compression 

Hydrostatic Pressure [Bars] = (Depth [m] × Avg. S.G. × 0.0981) 

Average Pressure = Bars ÷ 2 

Pressure Correction = S.G. + (Avg. Bars × Correction Factor) 

Calculations for Density Adjustments 

Increase Density for Single Salt Brines 

1. Determine weight and volume of system to be weighted. 

2. Using the data from the formulation tables, determine the following: 

Brine Density lb/gal bbl Water/bbl lb Salt/bbl 

D original W o S o 

D final W f S f 

3. From this data, the required additions can be calculated as follows: 

V 

Salt additives = 

O 

( W S − S 

O 

W 

f 

f 

O 

) 

Example 

where V o = original volume (bbl) 

Increase 400 bbl of 9.5 lb/gal CaCl 2 to 10.5 lb/gal CaCl 2 . 



REVISION 2006 6-43


Brine Density lb/gal bbl Water/bbl lb Salt/bbl 

9.5 .954 65.1 

10.5 .904 125 

CaCl 2 addition = 400 (---------------------------- .954 )( 125) 

– 65.1 = 26,725 lbs 

.904 

Final volume = 400 .954 --------- = 422 bbl 

.904 

Therefore, 400 bbl of 9.5 lb/gal CaCl 2 fluid and 26,725 lbs 94-97% CaCl 2 will yield 422 bbl of a 

10.5 lb/gal fluid. 

Increase Density of a CaCl 2 /CaBr 2 Fluid with Dry Calcium Bromide 

1. Determine weight and volume of system to be weighed. 

2. Using the data from the formulation tables, determine the following: 

Brine Density lb/gal bbl Water/bbl lb 94% CaCl 2 /bbl lb 95% CaBr 2 /bbl 

D original W o Cl o Br o 

D final W f Cl f Br f 

From this data, the required additions can be calculated as follows: 

Water addition = 

CaBr 2 addition = 

V o ( Cl o W f – W o ) 

-------------------------------------------- 

Cl f 

V o ( Cl o Br f – Br o ) 

--------------------------------------------- 

Cl f 

Final volume 

= 

Cl 

V o 

o ------- 

Cl f 

Example 

Increase 400 bbl of 13.4 lb/gal fluid to 14.0 lb/gal with concentrated 95% CaBr 2 . 



REVISION 2006 6-44


Brine Density lb/gal bbl Water/bbl lb 94% CaCl 2 /bbl lb 95% CaBr 2 /bbl 

13.4 .762 149.2 154.5 

14.0 .738 134.0 206.1 

Water addition = 400 (--------------------------------- 149.2 )(.738) 

– .762 = 23.9 bbl 

134.0 

CaBr 2 addition = 400 ------------------------------------ ( 149.2) ( 206.1) 

– ( 154.5) 

= 29, 

991 lbs 

134.0 

Final volume = 400 149.2 ------------ = 445 bbl 

134.0 

Therefore, 400 bbl of 13.4 lb/gal fluid and 23.9 bbl of water and 29,991 bbl of 95% CaBr 2 will 

yield 445 bbl of a 14.0 lb/gal fluid. 

Increase Density with Heavier Liquid Brine 

1. Determine the following: 

D o = Original brine density 

D h = Density of heavier brine 

D f = Final brine density 

V o = Original brine volume 

2. From this data, the required additions can be calculated as follows: 

Volume of heavy brine = 

V o ( D h – D 

------------------------------- o) 

– 

D h 

D f 

Final Volume = V o + volume of heavy brine 

Example 

Increase 400 bbl of 13.2 lb/gal fluid to 13.7 lb/gal using a 15.1 lb/ gal brine. 

D o = 13.2 

D h = 15.1 

D f = 13.7 

V o = 400 

Volume of brine to add ( 15.1 ) = 

400( 13.7 – 13.2) - = 142.9 bbl 

15.1 – 13.7 

Final volume = 400 + 142.9 = 542.9 bbl. 



REVISION 2006 6-45


Therefore, 142.9 bbl of 15.1 lb/gal brine blended with 400 bbl of 13.2 lb/gal fluid yields 542.9 bbl 

of 13.7 lb/gal fluid. 

Decrease Density with Lighter Liquid Brine 

1. Determine the following: 

D o = Original brine density 

D l = Density of lighter brine 

D f = Final brine density 

V o = Original brine volume 

2. From this data, the following additions can be calculated: 

Final Volume = V o + volume of light brine 

Example 

Volumeof light brine 

Decrease 400 bbl of 14.5 lb/gal fluid to 13.0 lb/gal with a 9.5 lb/ gal brine. 

D o = 14.5 

D l = 9.5 

D f = 13.0 

V o = 400 

Vo 

= 

D 

( D − D ) 

400 14.5 −13.0 

Volumeof 

brineto add ( 13 .0) 

= 

= 171bbl 

13.0 − 9.5 

Final volume = 400 + 171 = 571 bbl. 

Therefore, 171 bbl of 9.5 lb/gal brine added to 400 bbl of 14.5 lb/gal fluid yields 571 bbl of 13.0 

lb/gal fluid. 

Increase Density after Dilution with Fresh Water 

1. Determine weight and volume of original system (D o , V o ) 

2. Determine density of the diluted brine and estimate the volume. 

D 1 

D d = Density of diluted brine (lb/gal) 

f 

o 

− 

f 

( ) 



REVISION 2006 6-46


V e = Estimated volume brine (bbl) 

3. Using data from the formulation tables, determine the following: 

D o = Brine density (lb/gal) 

W o = bbl water/bbl 

Cl o = lb 94% CaCl 2 /bbl 

Br o = lb 95%/bbl 

4. Determine amount of fresh water incorporated into system: 

W 

V e( 

D o – D d ) 

d = ------------------------------- 

D o – 8.335 

5. Determine materials required to increase density back to the original density: 

CaCl 2 required 

= 

W d 

W o 

( )Cl 

-------------------- o 

CaBr 2 required 

= 

W d 

( )Br 

-------------------- o 

W o 

Final volume 

= 

V e 

+ W d 

--------------------- 

W o 

Example 

400 lbs of a 14.5 lb/gal brine while being used in a well became diluted with fresh water. The 

density of the diluted brine was found to be 14.1 lb/gal and the volume estimated at 450 bbl. How 

much CaCl 2 and CaBr 2 are required to increase density back to the original? 

Vo = 400 bbl 

Ve = 450 bbl 

De = 14.1 lb/gal 

D o = 14.5 lb/gal 

W o = .718 bbl 

Cl o = 121.3 lb 

Br o = 248.9 lb 



REVISION 2006 6-47


6. Amount of fresh water incorporated: 

W d 

= 

450 14.5 – 14.1 

----------------- ( ------------------------ ) = 29.2 bbl 

14.5 – 8.335 

CaCl 2 addition 

CaBr 2 required 

= 

= 

(---------------------------- 29.2)121.3 

= 4,933 lbs 

.718 

( 29.2 

---------------------------- )248.9 

= 10,122 lbs 

.718 

Final volume 

= 

450 + 29.2 

------------------------- = 667 bbl 

.718 

Therefore, 4,933 lbs of CaCl 2 and 10,122 lbs of CaBr 2 added to 450 bbl of 14.1 lb/gal fluid will 

yield 667 bbl of original 14.5 lb/gal brine 

Salt Solubility vs. Freeze Depression 

Crystallization 

Ice Crystals 

Fresh water ice crystals begin to form when the solution drops below the freeze depression curve. 

In other words, salts dissolved in water below their maximum solubility limit for that solution 

depress the freezing point of the solution. 

Salt Crystals 

These crystals occur when a particular salt is added above its maximum solubility at a particular 

temperature, or when the temperature drops below the curve at which the salt can be in solution. 

Problems 

Several potential problems can be caused by the formation of ice and salt crystals. 

• Density will begin to decrease as ice forms or salt comes out of solution and is removed as 

the fluid circulates over the shakers. 

• Formation damage can occur as salt crystals plug the pore throats. 

• Viscosity increases with crystallization due to solids crowding. 



REVISION 2006 6-48


Corrosion Data (mils per year) 

30 Day Test N-80 Steel 

Brine Type 

Density lbs/gal 

Temperature (°F) 

70° 150° 250° 350° 

Cor. Rte, 

mpy 

Cor. Rte, 

mpy 

Cor. Rte, 

mpy 

Cor. Rte, 

mpy 

NaCl 10.0 0.5 1.5 0.2 0.1 

NaBr / NaCl 11.2 0.4 0.7 0.1 0.1 

CaCl 2 11.6 0.1 0.2 0.7 1.9 

CaCl 2 / CaBr 2 13.6 0.3 0.9 1.6 3.0 

CaCl 2 / CaBr 2 15.1 0.1 0.5 2.4 6.6 

Note: No corrosion inhibitor 

Table 6 – 8 Corrosion Rate vs Temperature in 30-Day Test N-80 Steel 

Compatibility of Various Additives with Different Salt Types 

Monovalent Salts 

Oxygen Scavengers 

Scale Inhibitors 


Sodium Hydroxide 

Ca(OH) 2 (Lime) 

Defoamers 

Many different Viscosifiers 

Other Surfactants 

Divalent Salts 


Scale Inhibitors 


Viscosifiers (HEC, W-306, and starches) 

Defoamers 

Salt Tables 

The following salt tables came from three sources. 

The potassium chloride table is from the CRC Handbook of Chemistry and Physics, 62nd edition. 

The sodium chloride table is from Staples and Nuttall, Journal of Physical Chemistry Reference 

Data, 1977, Volume 6. 

The calcium chloride table is from Clarke and Grew, Journal of Physical Chemistry Reference 

Data, 1985, Volume 14. 



REVISION 2006 6-49


The tables are divided into the following columns. 

1. Percent wt = the anhydrous solute weight percent, g solute/100 g solution. 

2. Specific gravity = the ratio of the mass of a body at 20°C to the mass of an equal 

volume of water at 4°C. 

3. Density, lb m /gal = specific gravity converted to pound per gallon units. The density of 

water is assumed to be 8.33 lb m /gal. 

4. lb m of salt/bbl of solution = the pounds of salt in a barrel solution of the given density. 

5. Gallons of water per barrel of solution = the gallons of water to make up one barrel 

of solution of the given density. 

6. Salt, mg/L = the concentration of salt in mg/L of solution. 

7. Chlorides, mg/L = the concentration of chlorides in mg/L. 

8. Volume increase factor = the volume increase that will occur when the specified 

weight of salt is added to the specified volume of fresh-water. The value in 8 is used for 

retort corrections. 

9. Crystallization point, °F = the crystallisation point of a solution containing the 

specified concentration of salt. 

10. Aw = the activity of the solution. This value has also been called Formation Activity 

Coefficient (FAC) in previous manuals. This value, regardless of the term applied to it, 

is a measure of the fluid's potential to absorb water. 

Salt % by Weight (as dry salt) Max. Density (ppg) 

KCl 24.2% 9.7 

NaCl 26.0% 10.0 

HCOONa 73.8% 11.1 

NaBr 44.7% 12.7 

HCOOK 75.0% 13.1 

CaCl 2 37.6% 11.6 

CaBr 2 51.9% 14.2 

CaCl 2 /CaBr 2 17.5% CaCl 2 / 46.1% CaBr 2 15.1 

CaBr 2 /ZnBr 2 22.8% CaBr 2 / 52.8% ZnBr 2 19.2 

ZnBr 2 77.0% ZnBr 2 21.0 

Table 6 - 8 Operational Densities of Various Salts 



REVISION 2006 6-50


Salt Typical pH Values ** 

11.1 ppg HCOONa 8.0 to 8.5 

11.6 ppg CaCl 2 6.5 to 7.5 

13.0 ppg HCOOK 8.0 to 8.54 

14.2 ppg CaBr 2 6.5 to 7.5 

15.1 ppg CaCl 2 / CaBr 2 6.0 to 7.0 

16.0 ppg CaCl 2 / CaBr 2 / ZnBr 2 4.5 to 5.0 




** pH measured directly on undiluted brine 

Table 6 - 9 

Typical pH Values of Various Salt Mixtures 

Density, 

lb/gal (70°F) 

Sp. Gr. NaCl, (100%) CaCl 2 , (94-97%) 

lbm/bbl lbm/bbl 

10.1 1.21 88 29 0.887 

10.2 1.22 70 52 0.875 

10.3 1.24 54 72 0.875 

10.4 1.25 41 89 0.876 

10.5 1.26 32 104 0.871 

10.6 1.27 25 116 0.868 

10.7 1.28 20 126 0.866 

10.8 1.30 16 135 0.864 

10.9 1.31 13 144 0.862 

11.0 1.32 10 151 0.859 

11.1 1.33 8 159 0.854 

Table 6 - 10 

Fresh Water, 

bbl 

Formulation of Sodium Chloride/Calcium Chloride Solution 

using Sacked NaCl (100%) and CaCl 2 (94-97%) 



REVISION 2006 6-51


1 

Percent 

Weight 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

7.0 

8.0 

9.0 

10.0 

11.0 

12.0 

13.0 

14.0 

15.0 

16.0 

17.0 

18.0 

19.0 

20.0 

21.0 

22.0 

23.0 

24.0 

2 

Specific 

Gravity 

1.005 

1.011 

1.017 

1.024 

1.030 

1.037 

1.044 

1.050 

1.057 

1.063 

1.070 

1.077 

1.084 

1.091 

1.097 

1.104 

1.111 

1.119 

1.126 

1.133 

1.140 

1.147 

1.155 

1.162 

Table 6 - 11 

3 

Density 

(lb m /gal) 

8.37 

8.42 

8.47 

8.53 

8.59 

8.64 

8.69 

8.75 

8.80 

8.86 

8.90 

8.97 

9.03 

9.08 

9.12 

9.20 

9.26 

9.32 

9.38 

9.44 

9.51 

9.56 

9.64 

9.68 

4 

KCl 

(lb m /bbl) 

3.5 

7.1 

10.7 

14.4 

18.1 

21.8 

25.6 

29.4 

33.3 

37.3 

41.2 

45.3 

49.4 

53.5 

57.6 

61.9 

66.1 

70.5 

74.9 

79.3 

83.9 

88.4 

93.1 

97.7 

5 

H 2 0 

(gal/bbl) 

41.8 

41.6 

41.4 

41.3 

51.1 

40.9 

40.7 

40.5 

40.4 

40.2 

40.0 

39.8 

39.6 

39.4 

39.1 

38.9 

38.7 

38.5 

38.3 

38.0 

37.8 

37.6 

37.4 

37.1 

6 

KCl 

(mg/L) 

10000 

20200 

30500 

41000 

51500 

62200 

73000 

84000 

95100 

106300 

117700 

129200 

140900 

152700 

164600 

176700 

188900 

201300 

213900 

226600 

239500 

252400 

265700 

278900 

7 

Chlorides 

(mg/L) 

4756 

9606 

14506 

19499 

24493 

29582 

34718 

39950 

45229 

50556 

55977 

61447 

67011 

72623 

78282 

84038 

89840 

95737 

101730 

107770 

114000 

120040 

126473 

132643 

8 

Volume 

Increase 

Factor 

1.005 

1.009 

1.013 

1.017 

1.022 

1.026 

1.031 

1.035 

1.039 

1.045 

1.050 

1.055 

1.061 

1.066 

1.072 

1.078 

1.084 

1.090 

1.097 

1.104 

1.111 

1.117 

1.125 

1.132 

9 


Point 

( o F) 

31.2 

30.3 

29.5 

28.6 

27.8 

26.9 

26.1 

25.2 

24.3 

23.4 

22.4 

21.4 

20.4 

20.0 

18.5 

17.0 

16.0 

15.0 

14.0 

13.0 

22.0 

34.0 

48.0 

59.0 

Physical Properties of Potassium Chloride Solutions @ 20 0 C 

* There is minimal water in sacked KCI, therefore, the volume increase from retort and sack 

additions may be considered the same. 


• KCl (g/L) = KCl (lb m /bbl) x 2.85714 

• H 2 0 (mL/L) = H 2 0 (gal/bbl) x 23.8086 

• KCl (ppm) = % wt x 10,000 

• mg/L = ppm x specific gravity 

• Cl – (mg/L) = KCl (mg/L) x 0.476 

• KCl (mg/L) = Cl – (mg/L) x 2.101 

• K + (mg/L) = Cl – (mg/L) x 1.103 

• Cl – (mg/L) = K + (mg/L) x 0.907 



REVISION 2006 6-52


Formulas 

• Salt (lb m /bbl water) = Volume increase factor × KCl (lb m /bbl) 

• Specific Gravity = 1.00056 + 1.22832 (10 -6 )(Cl – , mg/L) 

• Volume Increase Factor = 1 + (2.775 × 10 -7 )(Cl – ) 1.105 

1 

Percent 

Weight 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

7.0 

8.0 

9.0 

10.0 

11.0 

12.0 

13.0 

14.0 

15.0 

16.0 

17.0 

18.0 

19.0 

20.0 

21.0 

22.0 

23.0 

24.0 

25.0 

26.0 

2 

Specific 

Gravity 

1.007 

1.014 

1.021 

1.029 

1.036 

1.043 

1.050 

1.058 

1.065 

1.073 

1.080 

1.088 

1.095 

1.103 

1.111 

1.118 

1.126 

1.134 

1.142 

1.150 

1.158 

1.166 

1.174 

1.183 

1.191 

1.199 

3 

Density 

(lb m /gal) 

8.40 

8.46 

8.52 

8.58 

8.65 

8.70 

8.76 

8.83 

8.89 

8.95 

9.01 

9.08 

9.14 

9.20 

9.27 

9.33 

9.40 

9.46 

9.53 

9.60 

9.66 

9.73 

9.80 

9.87 

9.94 

10.01 

4 

NaCl 2 

(lbm/bbl) 

3.5 

7.1 

10.7 

14.4 

18.2 

21.9 

25.8 

29.7 

33.6 

37.6 

41.6 

45.7 

49.9 

54.1 

58.4 

62.7 

67.1 

71.5 

76.0 

80.6 

85.2 

89.9 

94.6 

99.5 

104.4 

109.3 

5 

H 2 O 

(gal/bbl) 

41.87 

41.75 

41.63 

41.46 

41.34 

41.18 

41.02 

40.86 

40.70 

40.54 

40.38 

40.19 

40.00 

39.85 

39.66 

39.44 

39.25 

39.03 

38.85 

38.64 

38.43 

38.22 

37.97 

37.74 

37.50 

37.27 

6 

NaCl 

(mg/L) 

10070 

20286 

30630 

41144 

51800 

62586 

73500 

84624 

95850 

107260 

118800 

130512 

142350 

154392 

166650 

178912 

191420 

204102 

216980 

229960 

243180 

256520 

270020 

283800 

297750 

311818 

7 

Chlorides 

(mg/L) 

6108 

12305 

18580 

24957 

31421 

37963 

44584 

51331 

58141 

65062 

72062 

79166 

86347 

93651 

101087 

108524 

116112 

123804 

131616 

139489 

147508 

155600 

163789 

172147 

180609 

189143 

8 

Volume a 

Increase 

Factor 

1.003 

1.006 

1.009 

1.013 

1.016 

1.020 

1.024 

1.028 

1.032 

1.036 

1.040 

1.045 

1.050 

1.054 

1.059 

1.065 

1.070 

1.076 

1.081 

1.087 

1.093 

1.099 

1.106 

1.113 

1.120 

1.127 

9 


Point ( o F) 

31.0 

30.0 

28.8 

27.7 

26.5 

25.3 

24.1 

22.9 

21.5 

20.2 

18.8 

17.3 

15.7 

14.1 

12.4 

10.6 

8.7 

6.7 

4.6 

2.4 

0.0 

2.5 

5.2 

+1.4 

+15.0 

+25.0 

10 

Aw 

0.996 

0.989 

0.983 

0.976 

0.970 

0.964 

0.957 

0.950 

0.943 

0.935 

0.927 

0.919 

0.910 

0.901 

0.892 

0.882 

0.872 

0.861 

0.850 

0.839 

0.827 

0.815 

0.802 

0.788 

0.774 

0.759 

Table 6 - 12 

Physical Properties of Sodium Chloride Brines @20 0 C 

a. There is minimal water in sacked NaCl, therefore, the volume increase from retort and sack 

additions 


• NaCl (g/L) = NaCl (lb m /bbl) × 2.85714 

• H 2 0 (mL/L) = H 2 0 (gal/bbl) × 23.8086 

• NaCl (ppm) = % wt × 10,000 

• Cl - (mg/L) = NaCl (mg/L) × 0.6066 

• NaCl (mg/L) = Cl - (mg/L) × 1.65 




REVISION 2006 6-53


Formulas 

• Salt (lb m /bbl water) 

Volume increase factor × NaCl (lb m /bbl) 


1.0036 [0.99707 + 6.504 (10 -3 )(% wt NaCl) + 4.395 (10 -5 )(% wt NaCl) 2 ] 

or 1+ 1.94 (10 -6 )(Cl – , Mg/L) 0.95 


1.00045 + 2.72232 (10 -3 )(% wt NaCl) + 8.15591 (10 -5 )(% wt NaCl) 2 

or 1 + 5.88 (10 -8 ) (Cl – , Mg/L) 1.2 

• Aw 

0.99755 – 4.3547 (10 -3 )(% wt NaCl) – 1.8205(10 -4 )(% wt NaCl) 2 

Density 

lb/gal 

Specific 

Gravity @ 60°F 

lbs NH 4 Cl per bbl 

Brine 

bbls Water per 

bbl Brine 

% Weight 

NH 4 Cl 

8.4 1.007 7.0 0.990 1.98 

8.45 1.013 10.5 0.981 3.00 

8.5 1.020 19.0 0.969 5.30 

8.6 1.031 30.0 0.940 8.40 

8.7 1.044 42.0 0.919 11.50 

8.8 1.055 53.0 0.900 14.40 

8.9 1.068 65.0 0.881 17.40 

9.0 1.079 77.0 0.860 20.40 

9.1 1.128 88.0 0.840 23.00 

9.2 1.103 100.0 0.819 25.90 

9.5 1.139 135.0 0.750 33.90 

Table 6 - 13 

Physical Properties of Ammonium Chloride (NH 4 Cl) Solutions 



REVISION 2006 6-54


1 

% wt 

2 

Specific 

Gravity 

3 

Density 

(lb m /gal) 

4a 

100 

CaCl 2 

(lb m /bbl) 

4b 

95% 

CaCl 2 

(lb m /bbl) 

5a 

H2O 

Using 

100% 

CaCl 2 

(gal/bbl) 

5b 

H2O 

Using 

95% 

CaCl 2 

(gal/bbl) 

6 

CaCl 2 

(mg/L) 

7 

Chlorides 

(mg/L) 

8a* 

Volume 

Increase 

Factor 

100% 

CaCl 2 

8b** 

Volume 

Increase 

Factor 

95% 

CaCl 2 

9 

Crystal 

lisation 

Point (°F) 

10 

AW 

1 

2 

3 

4 

5 

1.009 

1.017 

1.026 

1.034 

1.043 

8.42 

8.49 

8.56 

8.63 

8.70 

3.53 

7.13 

10.78 

14.50 

18.27 

3.72 

7.50 

11.35 

15.26 

19.23 

41.93 

41.85 

41.78 

41.69 

41.60 

41.91 

41.81 

41.71 

41.60 

41.48 

10085 

20340 

30765 

41360 

52125 

6454 

13018 

19690 

26470 

33360 

1.002 

1.004 

1.006 

1.008 

1.011 

1.002 

1.004 

1.007 

1.010 

1.013 

31.1 

30.4 

29.5 

28.6 

27.7 

0.998 

0.996 

0.993 

0.989 

0.984 

6 

7 

8 

9 

10 

1.051 

1.060 

1.068 

1.077 

1.085 

8.77 

8.84 

8.91 

8.98 

9.05 

22.11 

25.99 

29.94 

33.95 

38.03 

23.27 

27.36 

31.52 

35.74 

40.03 

41.49 

41.38 

41.27 

41.14 

41.01 

41.35 

41.22 

41.08 

40.93 

40.77 

63060 

74165 

85440 

96885 

108500 

40358 

47466 

54682 

62006 

69440 

1,013 

1.016 

1.018 

1.021 

1.024 

1.016 

1.019 

1.022 

1.026 

1.030 

26.8 

25.9 

24.6 

23.5 

22.3 

0.979 

0.973 

0.967 

0.959 

0.951 

11 

12 

13 

14 

15 

1.094 

1.103 

1.113 

1.122 

1.132 

9.13 

9.20 

9.28 

9.36 

9.44 

42.18 

46.39 

50.69 

55.05 

59.49 

44.40 

48.83 

53.36 

57.95 

62.62 

40.90 

40.76 

40.65 

40.53 

40.40 

40.63 

40.47 

40.33 

40.18 

40.02 

120340 

132360 

144625 

157080 

169725 

77018 

84710 

92560 

100531 

108624 

1.027 

1.030 

1.034 

1.037 

1.041 

1,034 

1.038 

1.041 

1.045 

1.049 

20.8 

19.3 

17.6 

15.5 

13.5 

0.942 

0.933 

0.923 

0.912 

0.900 

16 

17 

18 

19 

20 

1.141 

1.151 

1.160 

1.170 

1.180 

9.52 

9.60 

9.68 

9.76 

9.85 

63.98 

68.55 

73.18 

77.91 

82.72 

67.35 

72.16 

77.03 

82.01 

87.07 

40.25 

40.10 

39.95 

39.80 

39.65 

39.85 

39.67 

39.49 

39.31 

39.13 

182560 

195585 

208800 

222300 

236000 

116838 

125174 

133632 

142272 

151040 

1.044 

1.048 

1.051 

1.056 

1.060 

1.054 

1.059 

1.064 

1.068 

1.073 

11.2 

8.6 

5.9 

2.8 

-0.4 

0.888 

0.875 

0.862 

0.847 

0.832 

21 

22 

23 

24 

25 

1.190 

1.200 

1.210 

1.220 

1.231 

9.93 

10.01 

10.10 

10.18 

10.27 

87.59 

92.53 

97.55 

102.62 

107.82 

92.20 

97.40 

102.68 

108.02 

113.49 

39.48 

39.31 

39.14 

38.95 

38.76 

38.93 

38.73 

38.52 

38.30 

38.08 

249900 

264000 

278300 

292800 

307625 

159936 

168960 

178112 

187392 

196880 

1.065 

1.069 

1.074 

1.078 

1.084 

1.079 

1.084 

1.090 

1.097 

1.103 

-3.9 

-7.8 

-11.9 

-16.2 

-21.0 

0.816 

0.800 

0.783 

0.765 

0.746 

26 

27 

28 

29 

30 

1.241 

1.252 

1.262 

1.273 

1.284 

10.36 

10.44 

10.53 

10.62 

10.71 

113.09 

118.44 

123.85 

129.39 

135.00 

119.04 

124.67 

130.37 

136.20 

142.11 

38.57 

38.37 

38.16 

37.96 

37.75 

37.86 

37.62 

37.38 

37.14 

36.90 

322660 

337905 

353360 

369170 

385200 

206502 

216259 

226150 

236269 

246528 

1.089 

1.095 

1.100 

1.107 

1.113 

1.109 

1.116 

1.124 

1.131 

1.138 

-25.8 

-31.2 

-37.8 

-49.4 

-50.8 

0.727 

0.707 

0.686 

0.665 

0.643 

31 

32 

33 

34 

35 

1.295 

1.306 

1.317 

1.328 

1.340 

10.81 

10.90 

10.99 

11.08 

11.18 

140.70 

146.48 

152.32 

158.25 

164.32 

148.11 

154.19 

160.34 

166.58 

172.97 

37.53 

37.30 

37.06 

36.81 

36.57 

36.64 

36.38 

36.10 

35.81 

35.53 

401450 

417920 

434610 

451520 

468825 

256928 

267469 

278150 

288973 

300048 

1.120 

1.126 

1.134 

1.141 

1.149 

1.146 

1.155 

1.163 

1.173 

1.182 

-33.2 

-19.5 

-6.9 

+4.3 

+14.4 

0.620 

0.597 

0.573 

0.548 

0.522 

36 

37 

38 

39 

40 

1.351 

1.363 

1.375 

1.387 

1.398 

11.27 

11.37 

11.47 

11.57 

11.67 

170.47 

176.76 

183.13 

189.53 

195.99 

179.44 

186.06 

192.77 

199.50 

206.31 

36.32 

36.06 

35.81 

35.53 

35.23 

35.24 

34.95 

34.65 

34.33 

33.99 

486360 

504310 

522500 

540735 

559200 

311270 

322758 

334400 

346070 

357888 

1.156 

1.165 

1.173 

1.183 

1.192 

1.192 

1.202 

1.212 

1.224 

1.236 

+24.1 

+33.4 

+42.1 

+49.6 

+55.9 

0.496 

0.469 

0.441 

0.413 

0.384 

Table 6 - 14 Properties of Calcium Chloride Solutions @ 20°C 



REVISION 2006 6-55



Formulas 

• CaCl 2 (g/L) = CaCl 2 (lbm/bbl) × 2.85714 

• H 2 O (mL/L) = H 2 O (gal/bbl) × 23.8086 

• CaCl 2 (ppm) = % wt × 10,000 

• Cl – (ppm) = CaCl 2 (ppm) × 0.639 


• Salt (lb m /bbl water) 

• Volume increase factor × CaCl 2 (lb m /bbl) 


• 1.0036 [0.99707 + 7.923 (10 -3 )(% wt CaCl 2 ) + 4.964 (10 -5 )(% wt CaCl 2 ) 2 ] 

• Volume Increase Factor * 

• 1.00293 + 1.04192 (10 -3 )(% wt CaCl 2 ) + 8.94922(10 -5 )(% wt CaCl 2 ) 2 

• Aw 

0.99989 – 1.39359 (10 -3 )(% wt CaCl 2 ) – 3.50352 (10 -4 )(% wt CaCl 2 ) 2 

100% CaCl 

% wt CaCl 2 

( lb /bbl m 

) × % Pur ity CaCl 2 

2 

= -------------------------------------------------------------------------------------------- 

S.G × 350 

When Using CaCl 2 with Purity other than 95% 

New CaCl 2 (lb m /bbl) = 95 x 95% CaCl 2 (lb m /bbl) ÷ % Purity 

⎡ NewCaCl 

NewCaCl2 

,( gal / bbl) 

= H 

2O,( 

gal / bbl) 

− ⎢ 

⎣ 

Volume increase from salt (gal) = 42 ÷ New water ** 

Example: 35% CaCl 2 Brine Using 78% CaCl 2 

New CaCl 2 (lb m /bbl) = 95 x 172.97 ÷ 78 = 210.67 

New H Ogal/bbl 

2 

( ) = 35.53– 210.67 

-------------------------------- 

– 172.97 

= 31.01 

8.345 

Volume increase from 78% salt = 42 ÷ 31.01 = 1.354 

* Volume increase from 100% salt, i.e., from retort 

** Volume increase from salt and water in the sacked salt. 

2 

,( gal / bbl) 

− 95% CaCl 

8.345 

2 

,( gal / bbl) 

⎤ 

⎥ 

⎦ 



REVISION 2006 6-56


Ve* 10 4 

Density 

lb/gal 

8.4 

8.5 

8.6 

8.7 

8.8 

8.9 

3.33 9.0 

9.1 

9.2 

9.3 

9.4 

3.00 9.5 

9.6 

9.7 

9.8 

9.9 

2.89 10.0 

10.1 

10.2 

10.3 

10.4 

2.6 10.5 

10.6 

10.7 

10.8 

10.9 

2.4 11.0 

11.1 

11.2 

11.3 

11.4 

2.39 11.5 

11.6 

Table 6 - 15 

Specific 

Gravity 

@ 68°F 

1.01 

1.02 

1.03 

1.04 

1.06 

1.07 

1.08 

1.09 

1.10 

1.11 

1.13 

1.14 

1.15 

1.16 

1.17 

1.19 

1.20 

1.21 

1.22 

1.23 

1.25 

1.26 

1.27 

1.28 

1.29 

1.31 

1.32 

1.33 

1.34 

1.35 

1.37 

1.38 

1.39 

bbl 11.6 

CaCl 2 per 

bbl Brine 

0.022 

0.052 

0.083 

0.113 

0.144 

0.174 

0.203 

0.233 

0.264 

0.294 

0.325 

0.356 

0.390 

0.420 

0.450 

0.480 

0.510 

0.540 

0.571 

0.601 

0.632 

0.663 

0.694 

0.724 

0.755 

0.785 

0.820 

0.850 

0.880 

0.910 

0.940 

0.970 

1.00 

bbl Water 

per bbl 

Brine 

0.978 

0.948 

0.917 

0.887 

0.856 

0.826 

0.797 

0.767 

0.736 

0.706 

0.675 

0.644 

0.610 

0.580 

0.550 

0.520 

0.490 

0.460 

0.429 

0.399 

0.368 

0.337 

0.306 

0.276 

0.245 

0.215 

0.180 

0.150 

0.120 

0.090 

0.060 

0.030 

0.000 

Crystalliztion 

Point, °F 

+31 

+30 

+28 

+27 

+25 

+23 

+21 

+19 

+17 

+15 

+12 

+9 

+6 

+3 

1 

6 

11 

16 

22 

28 

34 

41 

48 

55 

51 

31 

15 

0 

+12 

+23 

+34 

+43 

+53 

Weight % 

CaCl 2 

Preparation of Calcium Chloride (CaCl 2 ) Solutions Using 

Liquid 11.6 lb/gal CaCl 2 

1.0 

2.0 

4.0 

5.0 

6.0 

7.0 

9.0 

10.0 

11.0 

12.0 

14.0 

15.0 

16.0 

17.0 

19.0 

20.0 

21.0 

22.0 

23.0 

25.0 

26.0 

27.0 

28.0 

29.0 

30.0 

31.0 

32.0 

33.0 

34.0 

35.0 

36.0 

37.0 

38.0 

* Determined by ASTM methods 

Ve = expansion factor gal/gal/°F; used with density adjustment calculations. 

Example: 

To prepare 10 bbl of 11.0 lb/gal CaCl 2 from 11.6 lb/gal liquid CaCl 2 : 

Add 10 × 0.264 = 2.6 bbl of 11.6 lb/gal CaCl 2 to 10 × 0.736 bbl of fresh water. 



REVISION 2006 6-57


Example: 

Density 

lb/gal 

8.3 

8.6 

8.7 

8.8 

8.9 

9.0 

9.1 

9.2 

9.3 

9.4 

9.5 

9.6 

9.7 

9.8 

9.9 

10.0 

10.1 

10.2 

10.3 

10.4 

10.5 

10.6 

10.7 

10.8 

10.9 

11.0 

11.1 

11.2 

11.3 

11.4 

11.5 

Table 6 - 16 

bbl Water per 

bbl Brine 

1.000 

0.985 

0.980 

0.974 

0.967 

0.962 

0.956 

0.954 

0.947 

0.942 

0.937 

0.932 

0.928 

0.922 

0.916 

0.911 

0.905 

0.901 

0.895 

0.888 

0.883 

0.878 

0.872 

0.865 

0.858 

0.854 

0.847 

0.842 

0.835 

0.829 

0.824 

To prepare 10 bbl of 10 lb/gal KBr: 

10 × 0.911 = 9.1 bbl water 

10 × 100.8 = 1,008 lbs KBr 

Add 1,008 lbs KBr to 9.1 bbl water. 

bbl KBr per 

bbl Brine 

- 

15.1 

21.9 

28.1 

34.8 

40.8 

47.0 

52.6 

58.6 

64.7 

70.6 

76.6 

82.3 

88.5 

94.8 

100.8 

106.9 

112.7 

119.0 

125.4 

131.4 

137.6 

143.8 

150.6 

157.0 

162.6 

169.2 

175.5 

181.2 

188.2 

194.2 

% KBr 

- 

4.2 

6.0 

7.6 

9.3 

10.8 

12.3 

13.6 

15.0 

16.4 

17.7 

19.0 

20.2 

21.5 

22.8 

24.0 

25.2 

26.3 

27.5 

28.7 

29.8 

30.9 

32.0 

33.2 

34.3 

35.2 

36.3 

37.3 

38.3 

39.3 

40.2 


Point, °F 

(LCTD) 

32 

30 

30 

29 

28 

27 

27 

26 

26 

25 

24 

23 

22 

22 

21 

19 

18 

17 

16 

15 

14 

12 

13 

20 

27 

33 

41 

49 

57 

66 

75 

Preparation of Potassium Bromide Based Solutions Using 

Granular Concentrated KBr 



REVISION 2006 6-58


Brine Density at 60 o F 

(lb m /gal) 

11.6 lb m /gal CaCl 2 

(bbl) 

14.2 lbm/gal CaBr 2 

(bbl) 

94 to 97% CaCl 2 

(Flakes or 

Pellets) (lb) 


Point 

( o F) 

11.7 0.9714 0.0246 3.5 +45 

11.8 0.9429 0.9429 6.9 +51 

11.9 0.9143 0.0738 10.4 +52 

12.0 0.8857 0.0984 13.9 +54 

12.1 0.8572 0.1229 17.4 +55 

12.2 0.8286 0.1475 20.8 +55 

12.3 0.8000 0.1722 24.3 +56 

12.4 0.7715 0.1967 27.8 +56 

12.5 0.7429 0.2213 31.2 +57 

12.6 0.7143 0.2459 34.7 +58 

12.7 0.6857 0.2705 38.2 +58 

12.8 0.6572 0.2951 41.7 +58 

12.9 0.6286 0.3197 45.1 +59 

13.0 0.6000 0.3443 48.6 +59 

13.1 0.5714 0.3689 52.1 +60 

13.2 0.5429 0.3935 55.5 +60 

13.3 0.5143 0.4181 59.0 +60 

13.4 0.4851 0.4432 62.6 +61 

13.5 0.4572 0.4672 66.0 +61 

13.6 0.4286 0.4919 69.4 +62 

13.7 0.4000 0.5165 72.9 +62 

13.8 0.3714 0.5411 75.4 +63 

13.9 0.3429 0.5656 79.8 +63 

14.0 0.3143 0.5903 83.3 +64 

14.1 0.2857 0.6149 86.8 +64 

14.2 0.2572 0.6394 90.3 +64 

14.3 0.2286 0.6640 93.7 +65 

14.4 0.2000 0.6886 97.2 +65 

14.5 0.1715 0.7132 100.7 +65 

14.6 0.1429 0.7378 104.2 +66 

14.7 0.1143 0.7624 107.6 +66 

14.8 0.0858 0.7869 111.1 +67 

14.9 0.0572 0.8116 114.6 +67 

15.0 0.0286 0.8361 118.0 +67 

15.1 0.0000 0.8608 121.5 +68 

Table 6 - 17 

Calcium Chloride-Calcium Bromide Solution Requirements 

Using 11.6 lbm/gal CaCl 2 Brine, 14.2 lbm/gal CaBr 2 Brine, and 

Sacked CaCl 2 (Formulation per 1 bbl) 



REVISION 2006 6-59


Conversions 

ppm CaCl 2 = % wt × 10,000 

ppm Cl – = ppm CaCl 2 × .64 

Formulas 

When using 78% CaCl 2 

( / bbl) = 95% CaCl2 × 1. 218 

lb m 

⎡78% 

CaCl2 

,( lb 

New H 

2O,( 

gal / bb /) = H 

2O,( 

gal / bbl) 

− ⎢ 

⎣ 

m 

/ bbl) 

− 95% CaCl ,( lb 

8.345 

2 

m 

/ bbl) 

⎤ 

⎥ ⎦ 



REVISION 2006 6-60


CaCl 2 / CaBr 2 Density at 60 o F (15° C) 

lb m /gal lb m /ft 3 lb CaCl 2 

per bbl Brine 

Example: 

11.7 

11.8 

11.9 

12.0 

12.1 

12.2 

12.3 

12.4 

12.5 

12.6 

12.7 

12.8 

13.0 

13.1 

13.2 

13.3 

13.4 

13.5 

13.6 

13.7 

13.8 

13.9 

14.0 

14.1 

14.2 

14.3 

14.4 

14.5 

14.6 

14.7 

14.8 

14.9 

15.0 

15.1 

Table 6 - 18 

87.52 

88.26 

89.01 

89.76 

90.51 

91.26 

92.00 

92.75 

93.50 

94.25 

95.00 

95.74 

97.24 

97.99 

98.74 

99.48 

100.23 

100.98 

101.73 

102.48 

103.22 

103.97 

104.72 

105.47 

106.22 

106.96 

107.71 

108.46 

109.21 

109.96 

110.70 

111.45 

112.20 

112.95 

193.39 

191.00 

188.42 

185.85 

183.28 

180.70 

178.13 

175.56 

172.99 

170.41 

167.83 

165.27 

160.12 

157.54 

154.97 

152.40 

149.82 

147.26 

144.68 

142.12 

139.54 

136.98 

134.40 

131.84 

129.26 

126.68 

124.11 

121.54 

118.97 

116.39 

113.82 

111.25 

108.67 

106.10 

bbl 14.2 CaBr 2 

per bbl Brine 

0.0254 

0.0507 

0.0762 

0.1016 

0.1269 

0.1524 

0.1778 

0.2032 

0.2286 

0.2540 

0.2794 

0.3048 

0.3556 

0.3810 

0.4064 

0.4318 

0.4572 

0.4826 

0.5080 

0.5334 

0.5589 

0.5842 

0.6069 

0.6351 

0.6604 

0.6858 

0.7113 

0.7366 

0.7620 

0.7875 

0.8128 

0.8382 

0.8637 

0.8891 

bbl Fresh Water 

per bbl Brine 

0.8163 

0.7924 

0.7683 

0.7443 

0.7203 

0.6963 

0.6723 

0.6483 

0.6243 

0.6003 

0.5762 

0.5523 

0.5042 

0.4802 

0.4562 

0.4322 

0.4082 

0.3842 

0.3602 

0.3361 

0.3121 

0.2882 

0.2641 

0.2401 

0.2161 

0.1921 

0.1681 

0.1441 

0.1201 

0.0961 

0.0721 

0.0481 

00.241 

0.0000 

Preparation of Calcium Bromide Based Solutions Using Solid 

94% CaCl 2 and Liquid 14.2 lbm/gal CaBr 2 

To prepare 10 bbl of 13.0 lb m /gal CaBr 2 from minimum 94% solid CaCl 2 and 14.2 lb m /gal liquid 

CaBr 2 : 

Add 10 × 160.1 = 1600 lbs of solid CaCl 2 to 10 × 0.35 = 3.5 bbl of 14.2 lb m /gal CaBr 2 and 10 × 

0.50 = 5.0 bbl of fresh water. 



REVISION 2006 6-61


Example: 

Brine Density 

bbl Fresh Water 

lb m /gal lb m /ft 3 per bbl Brine 

11.0 

11.1 

11.2 

11.3 

11.4 

11.5 

11.6 

11.7 

11.8 

11.9 

12.0 

12.1 

12.3 

12.4 

12.5 

12.6 

12.7 

12.8 

12.9 

13.0 

13.1 

13.2 

13.3 

13.4 

13.5 

13.6 

13.7 

13.8 

13.9 

14.0 

14.1 

14.2 

14.3 

82.28 

83.03 

83.78 

84.52 

85.27 

86.02 

86.77 

87.52 

88.26 

89.01 

8976 

90.51 

92.00 

92.75 

93.50 

94.25 

95.00 

95.74 

96.49 

97.24 

97.99 

98.74 

99.48 

100.23 

100.98 

101.73 

102.48 

103.22 

103.97 

104.72 

105.47 

106.22 

106.96 

0.889 

0.887 

0.884 

0.878 

0.869 

0.867 

0.864 

0.863 

0.849 

0.849 

0.848 

0.840 

0.831 

0.830 

0.821 

0.819 

0.810 

0.808 

0.797 

0.796 

0.794 

0.791 

0.789 

0.778 

0.775 

0.772 

0.761 

0.758 

0.755 

0.751 

0.748 

0.744 

0.740 

lb 95% CaBr 2 per 

bbl Brine 

150.8 

155.9 

160.9 

167.4 

174.5 

179.6 

184.7 

188.9 

198.3 

202.6 

207.0 

214.1 

225.8 

230.3 

237.7 

242.4 

250.0 

254.8 

266.5 

267.4 

272.3 

277.3 

282.4 

290.4 

295.6 

300.8 

309.0 

314.3 

319.7 

325.1 

330.5 

335.9 

341.5 

Table 6 - 19 Preparation of Sodium Bromide Based Solutions Using 95% 

Dry CaBr 2 

To prepare 10 bbl of 13.0 lb m /gal CaBr 2 from 95% solid CaBr 2 : 

Add 10 × 267.4 = 2,675 lbs of 95% CaBr 2 to 10 × 0.796 = 7.9 bbl of fresh water. 



REVISION 2006 6-62


Density (lb m /gal) 

10.0 

10.1 

10.2 

10.3 

10.4 

10.5 

10.6 

10.7 

10.8 

10.9 

11.1 

11.2 

11.3 

11.4 

11.5 

11.6 

11.7 

11.8 

11.9 

12.0 

12.1 

12.2 

12.3 

12.4 

bbl 10.0 NaCl per 

bbl Brine 

1.000 

0.958 

0.917 

0.875 

0.833 

0.792 

0.750 

0.708 

0.667 

0.625 

0.583 

0.500 

0.458 

0.417 

0.375 

0.333 

0.292 

0.250 

0.208 

0.167 

0.125 

0.083 

0.042 

0.000 

bbl 12.4 NaBr per 

bbl Brine 

0.000 

0.042 

0.083 

0.125 

0.167 

0.208 

0.250 

0.292 

0.333 

0.375 

0.417 

0.500 

0.542 

0.583 

0.625 

0.667 

0.708 

0.750 

0.792 

0.833 

0.875 

0.917 

0.958 

1.000 

Crystallization Point 

( o F) (LCTD) 

Table 6 - 20 Preparation of Sodium Bromide Based Solutions Using 10.0 

lbm/gal NaCl Solution and 12.4 lb/gal NaBr Solution 

* Data being reconfirmed 

Example: 

To prepare 10 bbl of 11.0 lb m /gal NaBr: 

10 × 0.583 = 5.8 bbl 10.0 lb m /gal NaCl 

10 × 0.417 = 4.2 bbl 12.4 lb m /gal NaBr 

Add 5.8 bbl of 10.0 lb m /gal NaCl to 4.2 bbl 12.4 lb m /gal NaBr. 

30 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

23 

28 

32 

36 

39 

46 



REVISION 2006 6-63


Density 

lb m /gal 

10.0 

10.1 

10.2 

10.3 

10.4 

10.5 

10.6 

10.7 

10.8 

10.9 

11.0 

11.1 

11.2 

11.3 

11.4 

11.5 

11.6 

11.7 

11.8 

11.9 

12.0 

12.1 

12.2 

12.3 

12.4 

12.5 

12.6 

12.7 

Table 6 - 21 

* Data being reconfirmed 

Example: 

bbl Water per 

bbl Brine 

0.886 

0.883 

0.880 

0.877 

0.874 

0.871 

0.868 

0.865 

0.862 

0.859 

0.856 

0.853 

0.850 

0.847 

0.844 

0.841 

0.838 

0.835 

0.832 

0.829 

0.826 

0.823 

0.820 

0.818 

0.815 

0.812 

0.809 

0.806 

To prepare 10 bbl of 11.0 lb m /gal NaBr: 

10 × 0.856 = 8.6 bbl water 

10 × 69.3 = 693 lbs NaCl 

10 × 92.8 = 928 lbs NaBr 

bbl NaCl per 

bbl Brine 

110.0 

106.0 

102.0 

97.8 

93.7 

89.6 

85.6 

81.5 

77.4 

73.4 

69.3 

65.2 

61.2 

57.1 

52.9 

48.8 

44.8 

40.7 

36.6 

32.6 

28.5 

24.4 

20.4 

16.3 

12.2 

8.1 

4.1 

0 

lb NaBr 

per bbl Brine 

0 

9.3 

18.6 

27.9 

37.1 

46.4 

55.7 

65.0 

74.3 

83.6 

92.8 

102.0 

111.0 

121.0 

130.0 

139.0 

149.0 

158.0 

167.0 

177.0 

186.0 

195.0 

204.0 

214.0 

223.0 

232.0 

242.0 

251.0 

Crystallization Point, °F 

(LCTD) 

30 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

* 

37 

41 

47 

49 

53 

56 

60 

63 

Preparation of Sodium Bromide Based Solutions Using Solid 

NaCl, Granular Concentrated NaBr, and Water 

Add 693 lbs NaCl and 928 lbs NaBr to 8.6 bbl of water. 



REVISION 2006 6-64


Brine @ 20°C (68° F) 

Requirements for 1 bbl 

Brine 

Requirements for 1 M 3 of 

Brine 

Crystal Point** 

ppg S.G. H 2 O gals NaBr lbs H 2 O/M 3 s NaBr kgs °F °C 

8.4 1.007 41.81 4.08 0.996 11.65 31.0 -0.6 

8.5 1.019 41.66 9.60 0.992 27.38 30.0 -1.1 

8.6 1.031 41.51 15.07 0.988 42.99 29.0 -1.7 

8.7 1.043 41.35 20.60 0.984 58.77 29.0 -1.7 

8.8 1.055 41.18 26.15 0.981 74.62 28.0 -2.2 

8.9 1.067 41.02 31.70 0.977 90.44 26.0 -3.3 

9.0 1.079 40.85 37.39 0.973 106.68 25.0 -3.9 

9.1 1.091 40.69 42.92 0.969 122.45 24.0 -4.4 

9.2 1.103 40.51 48.55 0.965 138.52 23.0 -5.0 

9.3 1.115 40.34 54.20 0.961 154.64 22.0 -5.6 

9.4 1.127 40.17 59.84 0.956 170.72 21.0 -6.1 

9.5 1.139 39.99 65.52 0.952 186.92 20.0 -6.7 

9.6 1.151 39.81 71.21 0.948 203.15 19.0 -7.2 

9.7 1.163 39.64 76.91 0.944 219.42 18.0 -7.8 

9.8 1.175 39.46 82.58 0.939 235.62 16.0 -8.9 

9.9 1.187 39.27 88.33 0.935 252.01 15.0 -9.4 

10.0 1.199 39.09 94.05 0.931 268.34 14.0 -10.0 

10.1 1.211 38.90 99.81 0.926 284.75 12.0 -11.1 

10.2 1.223 38.72 105.56 0.922 301.18 11.0 -11.7 

10.3 1.235 38.53 111.33 0.917 317.62 10.0 -12.2 

10.4 1.247 38.34 117.09 0.913 334.07 8.0 -13.3 

10.5 1.259 38.16 122.86 0.909 350.52 6.0 -14.4 

10.6 1.271 37.97 128.62 0.904 366.96 5.0 -15.0 

10.7 1.283 37.78 134.41 0.900 383.48 4.0 -15.6 

10.8 1.295 37.59 140.19 0.895 399.98 2.0 -16.7 

10.9 1.307 37.40 146.02 0.890 416.62 0.0 -17.8 

11.0 1.319 37.20 151.87 0.886 433.30 -2.0 -18.9 

11.1 1.331 37.00 157.71 0.881 449.96 -3.0 -19.4 

11.2 1.343 36.80 163.58 0.876 466.72 -5.0 -20.6 

11.3 1.354 36.61 169.40 0.872 483.32 -7.0 -21.7 

11.4 1.366 36.41 175.28 0.867 500.08 -9.0 -22.8 

11.5 1.379 36.21 181.14 0.862 516.79 -11.0 -23.9 

11.6 1.391 36.02 186.98 0.858 533.47 -14.0 -25.6 

11.7 1.402 35.81 192.83 0.853 550.16 -16.0 -26.7 

Table 6 - 22 

Sodium Bromide Brine Requirements (using 95% NaBr) 

**Due to variances in salt impurities and nucleation sites, it is recommended to reconfirm the 

crystal points prior to field use. 



REVISION 2006 6-65


Table 6 - 23 

CLEAR-DRILL N Brine Table 

HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

0.5 5.01 999.2 1.0024 8.360 1.0008 1694 1.76 0.996 

1.0 10.05 996.6 1.0049 8.371 1.0034 3397 3.53 0.992 

1.5 15.11 994.2 1.0076 8.392 1.0059 5109 6.32 0.989 

2.0 20.20 991.7 1.0102 8.415 1.0083 6829 7.13 0.986 

2.5 25.32 989.4 1.0129 8.438 1.0107 8560 8.96 0.982 

3.0 30.47 987.0 1.0157 8.461 1.0131 10301 10.81 0.979 

3.5 35.65 984.7 1.0186 8.485 1.0155 12051 12.67 0.979 

4.0 40.86 982.4 1.0215 8.509 1.0179 13813 14.56 0.972 

4.5 46.10 980.2 1.0245 8.534 1.0202 15586 16.46 0.968 

5.0 51.38 977.9 1.0275 8.559 1.0226 17367 18.39 0.965 

5.5 56.68 975.7 1.0306 8.585 1.0249 19161 20.33 0.961 

6.0 62.02 973.4 1.0337 8.611 1.0273 20966 22.30 0.958 

6.5 67.39 971.2 1.0368 8.637 1.0297 22782 24.29 0.955 

7.0 72.80 968.9 1.0400 8.663 1.0321 24609 26.30 0.951 

7.5 78.24 966.7 1.0432 8.690 1.0345 26447 28.33 0.948 

8.0 83.71 964.4 1.0464 8.716 1.0369 28297 30.38 0.946 

8.5 89.21 962.1 1.0496 8.743 1.0394 30157 32.46 0.941 

9.0 94.75 958.8 1.0528 8.770 1.0419 32030 34.55 0.938 

9.5 100.32 957.4 1.0560 8.797 1.0444 33913 36.67 0.935 

10.0 105.83 956.1 1.0593 8.824 1.0470 35808 38.82 0.932 

10.5 111.57 952.7 1.0626 8.851 1.0496 37714 40.99 0.928 

11.0 117.24 950.3 1.0668 8.878 1.0523 39631 43.18 0.925 

11.5 122.96 947.8 1.0691 8.906 1.0550 41560 45.40 0.922 

12.0 128.68 945.4 1.0724 8.933 1.0578 43600 47.64 0.919 

12.5 134.46 942.9 1.0758 8.960 1.0606 45451 49.91 0.916 

13.0 140.26 940.4 1.0789 8.987 1.0634 47413 52.20 0.913 

13.5 146.10 937.8 1.0822 9.015 1.0663 49387 54.53 0.909 

14.0 151.97 935.2 1.0855 9.042 1.0693 51372 56.87 0.906 

14.5 157.88 932.6 1.0888 9.070 1.0723 53368 59.25 0.903 

15.0 163.81 930.0 1.0921 9.097 1.0763 55375 61.65 0.900 

15.5 169.79 927.3 1.0964 9.125 1.0784 57394 64.09 0.897 

16.0 175.79 924.5 1.0987 9.152 1.0816 59424 66.55 0.893 

16.5 181.83 921.8 1.1020 9.180 1.0848 61466 69.04 0.890 

17.0 187.91 919.1 1.1053 9.207 1.0880 63519 71.56 0.887 

17.5 194.01 916.3 1.1086 9.235 1.0914 65583 74.11 0.884 

18.0 200.16 913.5 1.1120 9.263 1.0947 67660 76.69 0.880 

18.5 206.33 910.6 1.1153 9.291 1.0982 69748 79.30 0.877 

19.0 212.56 907.7 1.1187 9.318 1.1016 71848 81.95 0.873 

19.5 218.79 904.9 1.1220 9.346 1.1052 73960 84.63 0.870 

20.0 226.08 901.9 1.1254 9.374 1.1087 76084 87.34 0.866 



REVISION 2006 6-66


CLEAR-DRILL N Brine Table continued 

HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

20.5 231.40 899.0 1.1288 9.403 1.1124 78220 90.09 0.863 

21.0 237.75 896.0 1.1322 9.431 1.1160 80369 92.87 0.859 

21.5 244.15 893.0 1.1358 9.459 1.1198 82530 95.69 0.856 

22.0 250.58 890.0 1.1390 9.488 1.1236 84704 98.54 0.852 

22.5 257.05 887.0 1.1424 9.517 1.1274 86892 101.43 0.848 

23.0 253.56 883.9 1.1459 9.546 1.1313 89092 104.36 0.844 

23.5 270.11 880.9 1.1494 9.574 1.1362 91305 107.32 0.840 

24.0 276.69 877.8 1.1529 9.604 1.1392 93532 110.33 0.836 

24.5 283.32 874.7 1.1564 9.633 1.1433 95773 113.37 0.832 

25.0 289.99 871.5 1.1600 9.663 1.1474 98027 116.46 0.828 

25.5 296.70 868.4 1.1635 9.692 1.1515 100296 119.58 0.823 

26.0 303.46 865.2 1.1671 9.722 1.1557 102579 122.75 0.819 

26.5 310.25 862.1 1.1708 9.752 1.1600 104876 125.96 0.814 

27.0 317.09 858.9 1.1744 9.783 1.1643 107188 129.22 0.810 

27.5 323.97 855.7 1.1781 9.813 1.1687 109515 132.62 0.805 

28.0 330.90 852.4 1.1818 9.844 1.1731 111857 135.87 0.800 

28.5 337.87 849.2 1.1855 9.875 1.1776 114213 139.26 0.795 

29.0 344.89 845.9 1.1893 9.907 1.1822 116586 142.70 0.790 

29.5 351.95 842.5 1.1931 9.938 1.1868 118973 146.19 0.785 

30.0 359.08 839.3 1.1969 9.970 1.1914 121376 149.73 0.780 

30.5 366.22 836.0 1.2007 10.002 1.1962 123794 153.32 0.775 

31.0 373.42 832.7 1.2046 10.034 1.2010 126228 156.96 0.770 

31.5 380.66 829.3 1.2085 10.066 1.2059 128678 160.66 0.764 

32.0 387.96 826.9 1.2124 10.099 1.2108 131143 164.41 0.759 

32.5 396.29 822.5 1.2163 10.132 1.2158 133623 168.22 0.753 

33.0 402.68 819.0 1.2202 10.165 1.2210 136119 172.08 0.748 

33.5 410.11 815.6 1.2242 10.198 1.2262 138630 176.00 0.742 

34.0 417.58 812.1 1.2282 10.231 1.2314 141157 179.98 0.736 

34.5 425.10 808.5 1.2322 10.264 1.2368 143698 184.02 0.731 

35.0 432.66 806.0 1.2362 10.297 1.2423 146253 188.12 0.725 

35.5 440.26 801.4 1.2402 10.331 1.2479 148823 192.29 0.719 

36.0 447.90 797.7 1.2442 10.364 1.2536 151407 196.52 0.713 

36.5 455.59 794.0 1.2482 10.397 1.2594 154004 200.82 0.708 

37.0 463.30 790.3 1.2522 10.431 1.2654 156613 205.19 0.702 

37.5 471.06 786.5 1.2562 10.464 1.2714 159236 209.62 0.696 

38.0 478.85 782.7 1.2601 10.497 1.2776 161868 214.13 0.691 

38.5 486.57 778.8 1.2641 10.530 1.2840 164512 218.71 0.685 

39.0 494.52 774.9 1.2680 10.562 1.2905 167165 223.37 0.680 

39.5 502.40 770.9 1.2719 10.595 1.2972 169827 228.10 0.675 

40.0 510.29 766.8 1.2757 10.627 1.3041 172497 232.91 0.670 

40.5 518.21 762.7 1.2795 10.658 1.3111 175173 237.81 0.665 

41.0 526.14 758.5 1.2833 10.690 1.3184 177855 242.78 0.660 



REVISION 2006 6-67


CLEAR-DRILL N Brine Table continued 

HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

41.5 534.09 754.2 1.2870 10.720 1.3259 180540 247.84 0.656 

42.0 542.04 749.9 1.2906 10.750 1.3336 183227 252.99 0.651 

42.5 549.99 745.4 1.2941 10.780 1.3415 185916 258.23 0.647 

43.0 557.93 740.9 1.2975 10.808 1.3497 188601 263.56 0.643 

43.0 557.93 740.9 1.2975 10.808 1.3497 188601 263.56 0.643 

43.5 565.87 736.3 1.3009 10.836 1.3581 191284 268.98 0.640 

44.0 573.79 731.6 1.3041 10.863 1.3669 193962 274.51 0.636 

44.5 581.69 726.8 1.3072 10.889 1.3759 196633 280.13 0.633 

45.0 589.58 721.9 1.3101 10.913 1.3863 199293 286.86 0.630 

45.5 597.40 716.9 1.3130 10.937 1.3950 201941 291.68 0.628 

46.0 605.19 711.7 1.3156 10.959 1.4051 204574 297.61 0.626 

46.5 612.92 706.5 1.3181 10.980 1.4155 207188 303.66 0.624 

47.0 620.59 701.1 1.3204 10.999 1.4264 209782 309.82 0.622 

47.5 628.19 695.6 1.3225 11.016 1.4377 212350 316.10 0.620 

48.0 635.71 689.9 1.3244 11.032 1.4494 214891 322.50 0.619 

48.5 643.13 684.1 1.3260 11.046 1.4617 217400 329.02 0.618 

49.0 650.45 678.2 1.3274 11.058 1.4746 219874 335.67 0.617 

49.5 657.65 672.1 1.3286 11.067 1.4878 222307 342.45 0.616 



REVISION 2006 6-68


Table 6 - 24 

CLEAR-DRILL K Brine Table 

HCOOK 

(Wt%) 

HCOOK 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

K (mg/L) lbs HCOOK/ 

(Potassium) bbl H 2 O 

Activity 

0.5 5.02 999.9 1.0032 8.358 1.0001 2331 1.76 0.996 

1.0 10.06 998.0 1.0063 8.382 1.0020 4677 3.53 0.994 

1.5 15.14 996.0 1.0094 8.408 1.0040 7037 5.32 0.993 

2.0 20.25 994.0 1.0124 8.433 1.0061 9411 7.13 0.991 

2.5 25.39 991.8 1.0154 8.459 1.0082 11799 8.96 0.989 

3.0 30.55 989.7 1.0164 8.484 1.0106 14201 10.81 0.987 

3.5 35.75 987.4 1.0214 8.508 1.0127 16616 12.67 0.986 

4.0 40.97 985.1 1.0243 8.533 1.0161 19044 14.56 0.984 

4.5 46.23 982.8 1.0273 8.567 1.0175 21486 16.46 0.982 

5.0 51.51 980.4 1.0302 8.581 1.0200 23841 18.39 0.980 

5.5 56.82 978.0 1.0331 8.606 1.0225 26409 20.33 0.978 

6.0 62.16 975.5 1.0359 8.629 1.0261 28890 22.30 0.975 

6.5 67.52 973.0 1.0388 8.653 1.0277 31384 24.29 0.973 

7.0 72.92 970.5 1.0417 8.677 1.0304 33892 26.30 0.971 

7.5 78.34 967.9 1.0446 8.701 1.0331 36412 28.33 0.969 

8.0 83.79 966.3 1.0474 8.725 1.0359 38946 30.38 0.968 

8.5 89.27 962.7 1.0503 8.749 1.0387 41493 32.46 0.964 

9.0 94.78 960.1 1.0531 8.772 1.0416 44063 34.55 0.961 

9.5 100.32 957.4 1.0560 8.798 1.0445 46627 36.67 0.959 

10.0 105.88 954.7 1.0588 8.820 1.0476 49214 38.82 0.956 

10.5 111.48 951.9 1.0617 8.844 1.0505 51815 40.99 0.954 

11.0 117.11 949.2 1.0646 8.868 1.0535 54430 43.18 0.951 

11.5 122.76 946.4 1.0675 8.892 1.0566 57058 45.40 0.948 

12.0 128.45 943.6 1.0704 8.916 1.0597 59700 47.64 0.946 

12.5 134.16 940.8 1.0733 8.940 1.0629 62357 49.91 0.943 

13.0 139.91 938.0 1.0762 8.965 1.0661 65028 52.20 0.940 

13.5 145.68 935.1 1.0791 8.989 1.0694 67713 54.53 0.937 

14.0 151.49 932.3 1.0821 9.014 1.0726 70413 56.87 0.934 

14.5 157.33 929.4 1.0851 9.039 1.0760 73128 59.25 0.931 

15.0 163.21 928.5 1.0881 9.063 1.0793 75858 61.65 0.928 

15.5 169.11 923.6 1.0911 9.088 1.0827 78603 64.09 0.925 

16.0 175.05 920.7 1.0941 9.114 1.0862 81363 66.55 0.922 

16.5 181.02 917.7 1.0971 9.139 1.0896 84139 69.04 0.918 

17.0 187.03 918.8 1.1002 9.164 1.0931 86930 71.56 0.915 

17.5 193.07 911.8 1.1033 9.190 1.0967 89737 74.11 0.911 

18.0 199.14 908.9 1.1064 9.216 1.1003 92561 76.68 0.908 

18.5 205.25 905.8 1.1095 9.242 1.1039 95401 79.30 0.905 

19.0 211.40 902.9 1.1126 9.268 1.1076 98257 81.95 0.901 

19.5 217.58 899.8 1.1158 9.295 1.1113 101130 84.63 0.897 

20.0 223.80 896.8 1.1190 9.321 1.1151 104019 87.34 0.894 

20.5 230.06 893.8 1.1222 9.348 1.1189 106926 90.09 0.890 

21.0 236.34 890.7 1.1254 9.375 1.1227 109850 92.87 0.886 



REVISION 2006 6-69


CLEAR-DRILL K Brine Table continued 

HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

21.5 242.67 887.6 1.1287 9.402 1.1266 1121791 95.69 0.882 

22.0 249.04 884.5 1.1320 9.429 1.1305 116750 98.54 0.878 

22.5 255.44 881.4 1.1363 9.457 1.1345 118726 101.43 0.874 

23.0 261.88 878.3 1.1386 9.485 1.1386 121721 104.36 0.870 

23.5 268.36 875.2 1.1420 9.513 1.1426 124733 107.32 0.866 

24.0 274.88 872.0 1.1453 9.541 1.1467 127763 110.33 0.862 

24.5 281.44 868.9 1.1487 9.569 1.1509 130812 113.37 0.858 

25.0 288.04 865.7 1.1522 9.598 1.1552 133880 116.46 0.854 

25.5 294.68 862.5 1.1556 9.626 1.1594 136966 119.58 0.849 

26.0 301.36 859.3 1.1591 9.666 1.1638 140071 122.75 0.845 

26.5 308.08 856.0 1.1626 9.684 1.1682 143194 125.96 0.841 

27.0 314.84 852.8 1.1661 9.714 1.1726 146337 129.22 0.836 

27.5 321.65 849.5 1.1696 9.743 1.1772 149499 132.52 0.832 

28.0 328.49 846.2 1.1732 9.773 1.1817 152680 135.87 0.827 

28.5 336.38 842.9 1.1768 9.802 1.1864 155880 139.26 0.823 

29.0 342.30 839.6 1.1804 9.832 1.1911 159100 142.70 0.818 

29.5 349.27 836.2 1.1840 9.863 1.1958 162340 146.19 0.813 

30.0 356.29 832.8 1.1876 9.883 1.2007 165599 149.73 0.809 

30.5 363.34 829.4 1.1913 9.923 1.2056 168877 153.32 0.804 

31.0 370.44 826.0 1.1950 9.954 1.2106 172176 156.96 0.799 

31.5 377.58 822.6 1.1987 9.985 1.2157 175494 160.66 0.794 

32.0 384.76 819.1 1.2024 10.016 1.2209 178833 164.41 0.789 

32.5 391.98 815.6 1.2061 10.047 1.2261 182191 168.22 0.786 

33.0 399.25 812.1 1.2099 10.078 1.2314 185569 172.08 0.780 

33.5 406.56 808.5 1.2136 10.109 1.2368 188967 176.00 0.775 

34.0 413.92 804.9 1.2174 10.141 1.2423 192386 179.98 0.770 

34.5 421.32 801.3 1.2212 10.173 1.2479 196824 184.02 0.765 

35.0 428.76 797.7 1.2250 10.204 1.2536 199283 188.12 0.760 

35.5 436.24 794.0 1.2289 10.236 1.2594 202762 192.29 0.756 

36.0 443.77 790.3 1.2327 10.268 1.2653 206261 196.52 0.750 

36.5 451.34 786.6 1.2366 10.300 1.2713 209780 200.82 0.745 

37.0 458.96 782.9 1.2404 10.333 1.2773 213320 205.19 0.740 

37.5 466.62 779.1 1.2443 10.365 1.2835 216879 209.62 0.735 

38.0 474.32 775.3 1.2482 10.398 1.2899 220459 214.13 0.730 

38.5 482.06 771.4 1.2521 10.430 1.2963 224059 218.71 0.725 

39.0 489.85 767.6 1.2560 10.463 1.3028 227679 223.37 0.719 

39.5 497.68 763.7 1.2600 10.495 1.3095 231320 228.10 0.714 

40.0 505.56 759.7 1.2639 10.528 1.3163 234981 232.91 0.709 

40.5 513.48 755.7 1.2679 10.581 1.3232 238662 237.81 0.704 

41.0 521.44 751.7 1.2718 10.594 1.3303 242363 242.78 0.699 

41.5 529.45 747.7 1.2758 10.627 1.3376 246084 247.84 0.694 

42.0 537.50 743.6 1.2798 10.660 1.3448 249826 252.99 0.689 



REVISION 2006 6-70



HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

42.5 545.58 739.5 1.2837 10.694 1.3523 253587 258.23 0.684 

43.0 553.73 735.3 1.2877 10.727 1.3599 257369 263.56 0.678 

43.5 561.91 731.2 1.2917 10.760 1.3677 261171 268.98 0.673 

44.0 570.13 726.9 1.2958 10.794 1.3756 264993 274.51 0.668 

44.5 578.40 722.7 1.2998 10.827 1.3838 268836 280.13 0.663 

45.0 586.71 718.4 1.3038 10.861 1.3920 272697 285.85 0.658 

45.5 595.06 714.1 1.3078 10.894 1.4005 276580 291.68 0.653 

46.0 603.46 709.7 1.3119 10.928 1.4091 280482 297.61 0.648 

46.5 611.90 705.3 1.3159 10.962 1.4179 284405 303.66 0.643 

47.0 620.38 700.8 1.3200 10.996 1.4269 288348 309.82 0.638 

47.5 628.91 696.4 1.3240 11.029 1.4360 292312 316.10 0.632 

48.0 637.48 691.8 1.3281 11.063 1.4454 296296 322.50 0.627 

48.5 648.10 687.3 1.3322 11.097 1.4550 300300 329.02 0.622 

49.0 654.76 682.7 1.3362 11.131 1.4648 304325 335.67 0.617 

49.5 663.48 678.1 1.3403 11.166 1.4747 308370 342.45 0.612 

50.0 672.21 673.5 1.3444 11.199 1.4850 312436 349.37 0.607 

50.5 681.00 668.7 1.3485 11.233 1.4954 316522 358.43 0.602 

51.0 689.84 664.0 1.3526 11.267 1.5081 320630 363.63 0.597 

51.5 698.72 659.2 1.3567 11.302 1.5170 324758 370.98 0.592 

52.0 707.65 654.4 1.3609 11.336 1.5281 328908 378.48 0.587 

52.5 716.62 649.5 1.3650 11.370 1.5396 333079 386.15 0.581 

53.0 725.64 644.7 1.3691 11.405 1.5512 337272 393.97 0.576 

53.5 734.71 639.7 1.3733 11.439 1.5632 341486 401.96 0.571 

54.0 743.82 634.8 1.3774 11.474 1.5754 345722 410.13 0.566 

54.5 752.98 629.8 1.3816 11.509 1.5879 349981 418.48 0.561 

55.0 762.19 624.7 1.3858 11.544 1.6007 354262 427.01 0.556 

55.5 771.45 619.7 1.3900 11.579 1.6138 358566 436.73 0.551 

56.0 780.76 614.6 1.3942 11.614 1.6272 362893 444.65 0.546 

56.5 790.12 609.4 1.3984 11.649 1.6409 367243 453.78 0.541 

57.0 799.54 604.2 1.4027 11.684 1.6550 371618 463.12 0.535 

57.5 809.00 599.0 1.4070 11.720 1.6694 376016 472.68 0.530 

58.0 818.52 593.8 1.4112 11.756 1.6841 380440 482.46 0.526 

58.5 828.09 588.5 1.4155 11.791 1.6992 384888 492.49 0.520 

59.0 837.71 583.2 1.4199 11.827 1.7147 389363 502.75 0.514 

59.5 847.40 577.8 1.4242 11.864 1.7306 393864 513.27 0.509 

60.0 857.14 572.5 1.4286 11.900 1.7469 398391 52706 0.504 

60.5 866.94 567.0 1.4330 11.937 1.7635 402946 535.11 0.498 

61.0 876.80 561.6 1.4374 11.973 1.7807 407529 546.45 0.493 

61.5 886.72 556.1 1.4418 12.010 1.7982 412141 558.08 0.487 

62.0 896.71 550.6 1.4463 12.048 1.8162 416783 570.02 0.482 

62.5 906.76 545.0 1.4508 12.085 1.8347 421454 582.28 0.476 

63.0 916.88 539.5 1.4564 12.123 1.8537 426167 594.87 0.471 



REVISION 2006 6-71



HCOONa 

(Wt%) 

HCOONa 

(g/L) 

Initial H 2 0 

(mL/L) 

Density 

(S.G.) 

Density 

(ppg) 

Correc. 

Factor 

Sodium 

(mg/L) 

lbs 

HCOONa 

/bbl H 2 O 

Activity 

63.5 927.07 533.8 1.4599 12.181 1.8732 430893 607.81 0.465 

64.0 937.32 528.2 1.4646 12.200 1.8932 435661 621.10 0.459 

64.5 947.66 522.5 1.4692 12.239 1.9138 440463 634.77 0.453 

65.0 958.06 516.8 1.4739 12.278 1.9349 445300 648.83 0.447 

65.5 968.55 511.1 1.4787 12.318 1.9567 450173 663.30 0.441 

66.0 979.11 505.3 1.4835 12.358 1.9790 455083 678.19 0.436 

66.5 989.76 499.5 1.4884 12.398 2.0020 460032 693.53 0.429 

67.0 1000.49 493.7 1.4933 12.439 2.0267 465020 709.33 0.423 

67.5 1011.31 487.8 1.4982 12.480 2.0500 470049 725.61 0.416 

68.0 1022.22 481.9 1.5033 12.522 2.0751 476121 742.41 0.409 

68.5 1033.23 476.0 1.5084 12.565 2.1009 480237 759.74 0.403 

69.0 1044.33 470.0 1.5135 12.608 2.1275 486397 777.63 0.396 

69.5 1055.54 464.1 1.5188 12.651 2.1549 490805 796.11 0.389 

70.0 1066.84 458.0 1.5241 12.695 2.1832 495861 815.20 0.381 

70.5 1078.26 452.0 1.5294 12.740 2.2124 501167 834.94 0.374 

71.0 1089.79 445.9 1.5349 12.788 2.2425 506525 855.35 0.366 

71.5 1101.43 439.8 1.5405 12.832 2.2736 511937 876.49 0.358 

72.0 1113.20 433.7 1.5461 12.879 2.3058 517405 898.38 0.350 

72.5 1126.09 427.5 1.5518 12.927 2.3390 522931 921.07 0.341 

73.0 1137.10 421.3 1.5677 12.976 2.3734 528517 944.59 0.333 

73.5 1149.25 416.1 1.5636 13.026 2.4090 534164 969.01 0.324 

74.0 1181.54 408.8 1.5697 13.075 2.4459 539876 994.36 0.314 

74.5 1173.98 402.6 1.5758 13.126 2.4841 545655 1020.71 0.305 

75.0 1186.56 398.2 1.5821 13.179 2.5238 551503 1048.11 0.294 



REVISION 2006 6-72


Table 6 - 25 

Properties of 85% Calcium Nitrate Solutions (at 25°C) 

Percent 

Weight 

Specific 

Gravity 

(g/cm 3 ) 

Density 

(lb/gal) 

85% 

Ca(NO 3 ) 2 

H 2 O Using 

85% 

Ca(NO 3 ) 2 

(L/m 3 ) 

Ca(NO 3 ) 2 

(mg/L) 

Calcium 

(mg/L) 

Volume 

Increase 

Factor 85% 

Ca(NO 3 ) 2 

1 1.005 8.39 10 997 10089 2080 1.002 0.998 

2 1.012 8.45 20 993 20043 4191 1.007 0.995 

3 1.019 8.5 30 989 30762 5327 1.011 0.993 

4 1.026 8.56 41 985 41349 8490 1.016 0.990 

5 1.033 8.62 51 980 52105 10680 1.021 0.988 

6 1.040 8.68 62 976 63036 12897 1.025 0.985 

7 1.047 8.74 73 972 74143 15142 1.030 0.983 

8 1.054 8.80 84 968 85429 17416 1.034 0.980 

9 1.061 8.85 95 963 96898 19718 1.039 0.977 

10 1.068 8.91 106 959 108552 22050 1.044 0.974 

11 1.075 8.97 118 954 120395 24411 1.049 0.972 

12 1.082 9.03 129 950 132429 26802 1.054 0.969 

13 1.090 9.09 141 945 144657 29224 1.059 0.966 

14 1.097 9.15 152 940 157083 31676 1.064 0.963 

15 1.104 9.21 164 935 169708 34160 1.069 0.960 

16 1.111 9.27 175 930 182538 36676 1.074 0.956 

17 1.119 9.34 189 925 195573 39224 1.080 0.953 

18 1.126 9.40 201 920 208818 41805 1.086 0.950 

19 1.134 9.46 214 915 222274 44419 1.092 0.948 

20 1.141 9.52 226 910 235946 47067 1.098 0.942 

21 1.149 9.58 239 905 249836 49748 1.104 0.939 

22 1.156 9.65 252 899 263948 52464 1.111 0.935 

23 1.164 9.71 265 894 278283 56215 1.117 0.931 

24 1.171 9.78 279 888 292846 58001 1.124 0.927 

25 1.179 9.84 292 882 307538 60823 1.132 0.922 

26 1.187 9.91 306 876 322664 63681 1.139 0.918 

27 1.195 9.97 320 871 337925 66576 1.147 0.913 

28 1.203 10.04 334 865 353426 69508 1.155 0.909 

29 1.211 10.10 348 858 369169 72477 1.163 0.904 

30 1.219 10.17 362 852 385156 75484 1.172 0.898 

31 1.227 10.24 377 846 401392 78530 1.181 0.893 

32 1.235 10.31 392 839 417878 81614 1.190 0.888 

33 1.243 10.38 406 833 434618 84738 1.200 0.882 

34 1.252 10.44 421 826 451615 87901 1.210 0.876 

35 1.260 10.51 437 820 468872 91105 1.220 0.870 

36 1.268 10.59 452 813 486392 94349 1.231 0.864 

37 1.277 10.66 468 806 504178 97634 1.242 0.857 

38 1.286 10.73 484 799 522232 100961 1.253 0.851 

39 1.294 10.80 500 791 540558 104329 1.265 0.844 

A w 



REVISION 2006 6-73


Properties of 85% Calcium Nitrate Solutions (at 25°C) continued 

Percent 

Weight 

Specific 

Gravity 

(g/cm 3 ) 

Density 

(lb/gal) 

85% 

Ca(NO 3 ) 2 

H 2 O Using 

85% 

Ca(NO 3 ) 2 

(L/m 3 ) 

Ca(NO 3 ) 2 

(mg/L) 

Calcium 

(mg/L) 

Volume 

Increase 

Factor 85% 

Ca(NO 3 ) 2 

40 1.303 10.87 516 784 559159 107740 1.278 0.837 

41 1.312 10.95 532 776 578038 111193 1.291 0.829 

42 1.321 11.02 549 769 597197 114690 1.304 0.821 

43 1.33 11.10 566 761 616640 118230 1.318 0.814 

44 1.339 11.17 583 753 636370 121815 1.332 0.805 

45 1.348 11.25 600 745 656389 125444 1.347 0.797 

46 1.357 11.33 617 737 676701 129117 1.362 0.788 

47 1.367 11.41 635 729 697308 132837 1.377 0.779 

48 1.376 11.49 653 720 718214 136602 1.394 0.770 

49 1.386 11.57 671 712 739421 140413 1.410 0.760 

50 1.396 11.65 689 703 760933 144271 1.428 0.751 

A w 

WORKOVER FLUIDS 

Many functions of a workover fluid are the same as functions of a drilling fluid. A workover fluid 

must: 

• Provide sufficient hydrostatic pressure to prevent formation fluids from entering the wellbore 

• Be able to clean the hole with reasonable pump pressures and annular velocities 

• Prevent excessive fluid (filtrate or whole workover fluid) losses to the formation 

• Be stable at the maximum well temperature 

• Provide maximum protection against formation damage. 

The likelihood of a well being damaged can be much greater during workover operations than 

during drilling operations. In the past it was a common practice to use drilling fluid materials 

(barite, clays, filtration control agents, and chemicals) for preparing and maintaining workover 

fluids. This practice has resulted in formation damage and loss of productivity in a significant 

percentage of the wells worked over with these fluids. 

Completion operations such as acidizing and fracturing, which are designed to open up a formation 

and increase production, also increase the potential for invasion of the formation by the workover 

fluid when remedial work is required. 

Damage to the formation occurs when: 

• solids contained in the workover fluid lost to the formation plug pores and reduce its effective 

permeability 



REVISION 2006 6-74


• swelling of expandable clays in the producing formation is caused by the invading fluid 

• there is particle movement within the sandstone 

• the fluid lost to the formation forms a viscous emulsion with formation fluids or changes the 

interfacial tension resulting in reduced production 

• enough fluid is lost to the formation to flush the hydrocarbons away from the wellbore, thus 

allowing water from a water drive to enter the wellbore 

For a well to return to full production after workover operations, the fluid lost to the formation 

during workover should be minimized and the solids and chemicals lost to the formation must be 

removed. 

Simply producing the well may be sufficient to flush these solids from the formation face. The 

smaller clay and barite particles, however, are carried deep into the formation where they lodge and 

cannot be flushed out, thus permanently impairing the productivity of the well. 

Heavy Brines 

Many of these problems can be avoided by using solids-free workover fluids. By using diesel oil (a 

fire hazard) or various brines (sodium chloride, calcium chloride, calcium bromide, or zinc 

bromide), it is possible to have solids-free workover systems with a density range of 7.0 to 19.2 

lb m /gal. The maximum operational densities in pounds per gallon which may be achieved with 

various salts are shown in the tables above. The use of these brines as workover and completion 

fluids has increased dramatically over recent years due to their non-damaging characteristics. In 

addition to heavy brines being used as workover fluids, they are also used as packer fluids, 

perforating fluids, and gravel pack fluids. 

Calcium chloride has a greater solubility than sodium chloride and, at higher concentrations of 

these mixed salts, the sodium chloride can come out of solution. As much sodium chloride as 

possible should be used for a given weight to reduce cost when these two salts are used. 

The properties of calcium chloride solutions can be found in the preceding tables. The material 

requirements for preparing chloride and bromide solutions are also found in the preceding tables. 

The solubility of calcium bromide increases with temperature, and much of it may precipitate from 

higher density solutions if the solution is allowed to cool. Requirements of a calcium chloride and 

calcium bromide solution can be found in the preceding tables. 

Unfortunately, solids-free workover fluids cannot do everything that is required of a workover 

fluid. They do not have the carrying capacity needed to clean the hole, and they have no filtration 

control or means of controlling lost returns. In addition, when calcium bromide or zinc bromide is 

needed for density requirements, these fluids can be very expensive. 



REVISION 2006 6-75


50 

Pounds of Sodium Chloride per Barrel of Solution 

120 

100 

80 

60 

40 

Sodium Chloride 

(100% NaCl) 

Water 

45 

40 

35 

30 

25 

20 

15 

Gallons of Water perBarrel of Solution 

10 

20 

5 

0 

0 

8 8.5 9 9.5 10 10.5 

Solution Weight in Pounds per Gallon [lbm/gal] at 60F 

Figure 6 - 14 

Material Requirements for Preparing Sodium Chloride 

Solutions 



REVISION 2006 6-76


50 

Pounds of Potassium Chloride per Barrel of Solution 

100 

80 

60 

40 

Potassium Chloride 

(100% KCl) 

Water 

45 

40 

35 

30 

25 

20 

15 

Gallons of Water perBarrel of Solution 

20 

10 

5 

0 

0 

8 8.5 9 9.5 10 

Solution Weight in Pounds per Gallon [lbm/gal] at 60F 

Figure 6 - 15 

Material Requirements for Preparing Potassium Chloride 

Solutions 



REVISION 2006 6-77


220 

50 

Pounds of Calcium Chloride per Barrel of Solution 

200 

180 

160 

140 

120 

100 

80 

60 

Calcium Chloride 

(94-97% CaCl2) 

Water 

45 

40 

35 

30 

25 

20 

15 

Gallons of Water per Barrel of Solution 

40 

10 

20 

5 

0 

0 

8 8.5 9 9.5 10 10.5 11 11.5 12 

Solution Weight in Pounds per (lbm/gal) at 60F 

Figure 6 - 16 

Material Requirements for Preparing Calcium Chloride 

Solutions 



REVISION 2006 6-78


Workover Products 

Various materials have been used in an effort to give the desired characteristics to brine workover 

fluids while retaining the solids-free benefits. These materials have had varying degrees of success. 

Hydroxy Ethyl Cellulose (HEC) is a non-ionic viscosifier widely used in workover applications. 

Baker Hughes Drilling Fluids markets this compound under the trade name W.O. 21L. HEC 

hydrates in almost all types of brines and is also effective in reducing filtration. 

HEC is made by reacting alkali cellulose with ethylene oxide in the presence of isopropyl alcohol. 

HEC is made in several viscosity grades depending on the number of side chains and the molecular 

weight. HEC is almost completely acid soluble. HEC, like guar gum, is susceptible to bacterial 

degradation. The use of an antifoaming agent, such as W.O. TM DEFOAM, may be necessary when 

adding HEC to brine solutions. 

Xanthan gum, or XAN-PLEX D, is a high molecular-weight natural polysaccharide produced by 

the bacterial fermentation of the micro-organism Xanthomonas campestreis. This polymer is 

slightly anionic and shows good solubility in sodium chloride, potassium chloride, and to a lesser 

extent, calcium chloride brines. 

The main advantage of xanthan gum as a viscosifier over guar gum or HEC is that the gel structure 

that is formed with xanthan gum in solution is superior, thereby resulting in greater hole cleaning 

efficiency. Although xanthan gum is somewhat susceptible to bacterial degradation, a biocide is not 

required in most applications. 

Guar gum has been used widely as a viscosifier for workover fluids. Guar gum is a non-ionic, 

branched-chain, high molecular-weight polysaccharide which is obtained from the seeds of the 

guar plant. Guar gum is soluble in almost any type of water except zinc bromide due to its nonionic 

nature. Though its physical appearance in solution would indicate that it has near solids-free 

characteristics, it too can plug formations in much the same manner as clays. 

Recent modifications of guar gum have resulted in a material with a lower residual content (after 

acidizing). These derivatives, hydroxypropyl guars, have greatly improved the performance of guar 

gum. Guar gum also swells when exposed to certain chemicals such as isopropyl alcohol, which is 

used in some sand fixation processes. Guar gum is susceptible to bacterial degradation. Use of a 

biocide, such as DRYOCIDE TM , is recommended. 

To obtain fluid loss control in a brine workover or completion fluid, it may be necessary to add 

solid fluid-loss control agents. The most common additive used is sized calcium carbonate, such as 

W.O. TM 30. Calcium carbonate comes in fine, medium, and coarse grades depending on the pore 

size or fractures present in the producing zones. Calcium carbonate is acid soluble, thus offering 

protection against the plugging of producing formations. Other fluid-loss control agents used in 

workover and completion fluids include oil-soluble fluid-loss resins, sized NaCl crystals, and iron 

carbonate. 

Lost circulation materials (LCM) for workover and completion fluids include calcium carbonate, 

oil soluble resins, or fluid loss blends that are normally formulated into pills of 20 to 50 bbl. Baker 

Hughes Drilling Fluids markets calcium carbonate as W.O. TM 30 (fine and coarse) and 

MIL-CARB TM . All of these materials are normally acid soluble. Fluid loss blends generally 

include carbonates, viscosifying polymer, and dispersing agents. 



REVISION 2006 6-79


These pills may contain up to 50 lb m /bbl of the particular LCM material chosen and are usually 

pumped directly across from the thief zone and allowed to sit for at least two hours before 

circulation is attempted. This procedure is repeated until circulation is regained. 

Both calcium chloride and calcium bromide are non-corrosive, but oxygen can dissolve in these 

brines causing oxygen corrosion. Oxygen scavengers such as NOXYGEN TM will effectively 

remove oxygen from these types of brines. Brines containing zinc will be acidic, thus they are 

corrosive. Film forming inhibitors (such as AMI-TEC TM ) are the additives of preference for 

combating this type of corrosion. 

BRINE-PAC ® , because it is effective against corrosion by oxygen, carbon dioxide, and hydrogen 

sulfide, is a convenient all-purpose corrosion additive. Corrosion will increase as greater 

temperatures are encountered. 

Mixing heavy brines can generate considerable heat and care must be taken to prevent the 

inhalation of any dust particles from the dry products. The use of protective goggles, masks, rubber 

gloves, and protective aprons should be mandatory for all rig personnel working with heavy brines. 

These brines are hygroscopic and can dry out skin and irritate eyes. Emergency showers and eye 

wash stations should be provided on the rig floor and pits. All personnel should be familiar with the 

Material Safety Data Sheets (MSDS) of all products. 

Other Workover Fluids 

Alternative workover fluids to heavy brines that have been utilized in the past include acid soluble 

carbonate materials such as calcium carbonate or iron carbonate (siderite) which are used as 

weighting agents. When using calcium carbonate, densities up to 14 lb m /gal can be achieved while 

densities of up to 18 lb m /gal (2.1 S.G.)can be obtained using iron carbonate as the weighting agent. 

Advantages of these types of workover additives include lower cost, resistance to crystallization, 

and greater fluid loss control. 

Oil-base fluids can also be utilized as workover fluids in certain applications. The advantage of oilbase 

fluids over water-base fluids is that the oil filtrate does not damage water-sensitive formations, 

and low-density fluids can be formulated for depleted production zones. Conventional oil-base 

fluid formulations for drilling applications have disadvantages for workover situations including 

oil-wetting of producing zones caused by surfactants in the fluid, emulsion blockage, and solids 

invasion. 

WELLBORE DISPLACEMENT AND CLEAN-UP PRODUCTS AND 

PROCEDURES 

Introduction 

Transfer of the completion/workover fluid to the wellbore by displacing the fluid already present is 

one of the most important procedures of the completion/workover operation. The objective of the 

displacement is to replace all of the fluid in the wellbore, usually drilling mud, so that a minimal 

amount of displacing fluid is contaminated. Displacements typically follow a simple two step 

procedure comprising the conditioning the current wellbore fluid and then displacing with 

completion fluid (direct displacement) or by first displacing with water {sea or fresh) followed by 

the completion fluid (indirect displacement). The purpose of conditioning the drilling fluid is to 

disperse and evenly distribute into the wellbore fluid any solids that may be clinging to the casing 



REVISION 2006 6-80


wall, the formation face, and transfer pipes. The rheological properties of the fluid to be displaced 

can then be adjusted to make it flow more easily when the actual displacement takes place. 

During the drill-in phase, wellbore sections become exposed to mud and mud particles. Drilled 

solids become attached to the casing and become a part of the filter cake in the open wellbore. 

Regardless of the type of completion, these foreign particles, if not removed from the wellbore, 

may damage the reservoir and the completion assembly. Some completion methods will require a 

more thorough cleansing process than others. 

The procedures described below are generalized recommendations. 

Displacement Objectives 

The basic displacement objective is the same regardless of the completion type or procedure. For 

example, if a drilling fluid is being displaced to drill-in fluid, contamination of the drill-in fluid may 

occur and spacers must be incorporated to avoid intermingling. Likewise, when a drilling fluid or 

drill-in fluid is displaced to clear brine, the solids-free brine will become contaminated and similar 

safeguards are required. 

A successful displacement should accomplish the following: 

• Remove mud and unwanted debris from the open-hole, casing and riser (if applicable). 

• Maintain the integrity of the mud and completion fluid interface. 

• Minimize rig time. 

• Minimize brine filtration and expense. 

• Minimize waste and disposal costs. 

• Minimize the need for stimulation and promote a clean, undamaged and productive wellbore. 

Pre-Displacement Considerations 

A. Cleaning the Wellbore 

B. Indirect versus Direct Displacement 

C. Forward versus Reverse Circulation 

D. Clean-out String Bottom Hole Assembly 

E. Conditioning the Mud System 

F. Surface Pits and Equipment Cleanup 

G. Design of Displacement Pills 

Cleaning the Wellbore 

It is always desirable to have a clean wellbore. Historically, some problems have been encountered, 

especially during the completion phase, due to insufficient displacement and well clean up. 

• Junk and solids can both prevent future well intervention activity or interfere with the running 

of perforating guns 

• Solids and junk both result in the inability to run the completion process, typically by early 

setting of packers 

• Solids and gunk have both caused problems functioning CIV/FIV type valves requiring bailer 

runs or coiled tubing intervention 

• Gunk offers a serious risk to formation damage if serious losses occur 

• Debris on top of wire line plugs can prevent their recovery 



REVISION 2006 6-81


The objective of the clean out operation is to remove all kinds of debris from the well. An absolute 

definition of debris is hard to give, but can generally be described under three categories: 

Solids generated during the well construction process typified by: 

• barite from settled mud 

• cuttings from cement and formation because of poor hole cleaning 

• steel shavings from milling operations 

• scale and rust from poorly conditioned tubulars 

Junk introduced to the well e.g.: 

• solids from surface equipment due to poor surface clean-out 

• foreign materials from BOP and seal stacks 

• cement plugs and float equipment after drill out 

• perforation debris 

• dropped objects from drill floor 

Gunk formed from the fluids used in the well: 

• pipe dope 

• synthetic mud at low temperature 

• gelled oil based mud from mixing with water 

The first step in the well clean up process is to clean the casing (and possibly the riser). To help 

evaluate the relative effectiveness of methods to clean a wellbore, a short description of the 

displacement objective is in order. 

The following figures illustrate the likely condition of the wellbore after drilling. (The figure and 

the following description, is primarily for open hole, but the description will also be fully applicable 

for cased holes). Not only is this section of the hole filled with drilling mud (typically one that has 

been conditioned prior to pulling out of the hole with the drill bit), but there is also a bed of drill 

solids on the low side of a horizontal wellbore. In addition, there is a static filter cake (dehydrated 

fluid) on top of the dynamic cake. This static cake is made up of polymer residue and trapped drill 

solids. To remove this material, the drilling fluid must be displaced from the hole with clear brine 

or seawater and then, the filter cake must be scoured. Displacement of the drilling fluid is best 

accomplished through the use of a viscous “push pill” followed by clear fluid. The purpose of the 

viscous push pill is to remove as much mud as possible in a “piston-like” process. To achieve this, 

the pill should have a yield point 1 to 2 times higher than the mud being displaced. This is typically 

achievable with a 1.5-ppb xanthan gum system. To further ensure a piston-like displacement, the 

density should be ~0.1 to 0.2 ppg heavier than the drill-in fluid. 



REVISION 2006 6-82


Drill-in 

Fluid 

Static 

Filter Cake 

Cuttings 

Bed 

Formation 

Filter Cake 

Figure 6 - 17 

Condition of Horizontal Wellbore Prior to Displacement 

Once the drill-in fluid has been displaced, the filter cake must be scoured. The figure below 

illustrates this process. Critical to the success of hole cleaning is to maximize the fluid velocity 

near the wellbore wall. For this reason it is important to fully maintain turbulent flow if possible. 

To assist in remaining turbulent, low viscosity fluids are desired for this process. While low 

viscosity fluids help to maximize velocity near the wall, it is commonly assumed that their use also 

makes it somewhat more difficult to remove solids from the wellbore. To carry solids completely 

out of the wellbore, elevated flow velocities are required. 

Figure 6 - 18 

Scouring of the Filter Cake 



REVISION 2006 6-83


Numerous laboratory studies have been conducted concerning the flow velocity required to 

completely remove drill solids from a high-angle wellbore. The general conclusions from all of 

these studies indicate that there is a critical velocity (CTFV-Critical Transport Fluid Velocity) that 

must be exceeded to ensure a complete sweep of the wellbore. If the fluid velocity is below this 

value (SCFF – Sub-Critical Fluid Flow), cuttings will start to accumulate in the wellbore. This 

accumulation continues until the flow velocity over the top of the cuttings bed exceeds the CTFV, 

at which time an equilibrium condition is created. 

It has been determined that through these testing programs, the most difficult wellbore angle to 

clean is between 65° and 75°. However, the increase in required flow velocity only varies slightly 

over the complete range of well deviations for 55° to 90°. Since the transport mechanism changes 

from rolling to lift, studies indicate that the critical velocity is significantly lower at wellbore 

deviations from vertical to about 50°. 

To summarize, it was observed in flow loop simulations that the removal of a cuttings bed with a 

viscosified fluid was in fact detrimental in high angle wellbores (assuming zero to low drill pipe 

rotation), and that low viscosity fluids are more beneficial. 

Based on these studies and in-house work, Baker Hughes Drilling Fluids has settled on a value of 5 

ft/sec (300 ft/min) as the recommended flow velocity to clean out the wellbore for particles. In 

addition, this displacement rate has been tested and proved effective in numerous field applications, 

especially before screen and gravel placement. 

Indirect versus Direct Displacement 

There are two general types of displacement used in the oil industry today. One is an indirect 

displacement and the other is a direct displacement. Each type has its advantages and 

disadvantages. Utilize BHDF’s DISPLEX Simulation Model to determine the pill volumes 

required for spacer contact times and flow rates. 

Indirect Displacement 

An indirect displacement is usually associated with a displacement of the mud system to seawater 

(or drill water) in a drilling liner or production casing before displacing to the next fluid system. 

For example, if oil-based drilling mud is in use, the operator may wish to displace and clean the 

drill string and casing with seawater before displacing to brine. The seawater would be preceded 

by a series of spacers and solvents to clean and water-wet the casing. With this method, a thorough 

cleansing can occur with minimal product usage due to the circulation of inexpensive water. Later, 

the displacement to the clean brine will occur without contamination. 

For indirect displacements, a good cement bond log is necessary because high differential pressures 

on the casing could cause a breakdown of cement or collapse of the casing. 

Indirect displacements may also be recommended for the production casing. In this instance, the 

drill-in fluid would be displaced to drill-water before finally being displaced to clear brine. 

Caution must also be exercised in this displacement because a possible reduction in hydrostatic 

pressure across the production interval could lead to casing collapse. 



REVISION 2006 6-84


Improved direct displacement techniques (specialized spacers) and increased daily rig costs have 

reduced the use of indirect displacements. 

The indirect displacement involves the use of forward or reverse circulation. The complete 

displacement process includes two phases; (1) displacement of the drilling fluid in the wellbore to 

seawater or drill water and (2) displacing the seawater to the next drilling fluid or brine. 

Deviated wellbores represent unique hole cleaning challenges. As wellbore inclination increases, 

axial particle slip shifts to radial particle slip, causing the cuttings to fall to the low side of the 

borehole, thus increasing the transport difficulty. 

As hole angles approach horizontal inclinations, displacements in deviated wells utilize 

increasingly greater spacer volumes and high annular velocities to move mud debris out of the 

wellbore. Some operators are more willing to displace the casing to seawater or drill water (an 

indirect displacement) because the larger water volumes are inexpensive and longer pump times are 

possible. The second phase, displacement to the drilling fluid or brine, is intended to clean and 

water-wet the casing and requires less pump time. 

Water-Base System (WBM) to Brine 

General Procedure 

Pre-Displacement 

Run the workstring to bottom and condition the mud. 

Displace the WBM to Water 

Pump a viscous push pill containing Xanthan Gum spaced between the mud and seawater. The 

spacer viscosity should be ~150-300 sec/qt and formulated by adding 3 lb Xanthan Gum per bbl 

seawater. The volume of the viscous push pill should cover approximately 1000 feet of annulus. 

Follow the pill with seawater and circulate and filter to the operator-specified limit. 

Displace Seawater to Brine 

Pump viscosified seawater containing CASING WASH TM 100. Circulate at least one hole volume. 

Follow with a viscous Seawater/ Xanthan Gum spacer between brine and seawater. The viscous 

spacer should cover 500 to 2000 feet of widest annular diameter. 

Follow with filtered brine until operator’s turbidity requirements are achieved. 

Oil-Base/Synthetic-Base System to Brine 

General Procedure 

Invert emulsion systems having highly aromatic oils will contain hydrocarbons in the slop water. 

Proper containment will be necessary to avoid unlawful discharge of these fluids. Additionally, all 

spacers should be disposed of as per regulations, or the operator’s specific requirements. See 

attached additional information on proposed treatment of oil-contaminated water and brine. 




REVISION 2006 6-85


Run the workstring to bottom and condition the mud. 

Displace the OBM/SBM out of the casing with seawater/drill water 

Pump a 50 bbl spacer of base oil or synthetic fluid before the seawater. This spacer is optional but 

can be recovered in the OBM/SBM. 

Push Pill 

Follow the base oil spacer with a Spacer/Push Pill. Viscosify and weight up a seawater spacer to 

0.2 ppg heavier than the mud. The spacer viscosity should be 1 to 2 times the mud viscosity. The 

volume should cover at least 1000 feet of largest annular diameter. The density, viscosity and 

surfactant (FLOW-CLEAN TM ) in the spacer will help push oily debris out of the wellbore and 

initiate the water-wetting process. 

Seawater Flush 

Follow the spacer with seawater for two wellbore volumes. 

Water-Wetting Spacer 

FLOW-SURF TM or FLOW-SURF TM PLUS will chemically detach, dissolve and remove the mud 

residue from all casing surfaces, out of the wellbore and finalize the water-wetting process. Typical 

concentration of solvent is 5-10%. 

Volume is determined and optimized based on surface area of tubulars, saturation volume, 

Reynolds number, annular velocity, contact time and pump rate. Normally spacer volume is 1000 

to 2000 ft of the largest annular volume. Contact time required is normally 2.5 to 10 minutes. 

Viscous Spacer 

Viscous Xanthan Gum / Seawater spacer between FLOW-SURF TM spacer and filtered brine. 

Volume = ± 1000 feet of largest annular diameter. 

Clean Brine 

Follow the viscous spacer with clean brine and filter to operator’s turbidity requirements. 

Direct Displacement 

A direct displacement may be defined as one that uses a series of relatively small spacers between 

the original drilling fluid and the next fluid system, i.e. drill-in fluid or clear brine. This method is 

often favored because the rig time (cost) is reduced. Improved procedures and solvents have 

advanced significantly, reducing the number of spacers required to clean the open-hole and casing 

effectively. 

A direct displacement differs from an indirect displacement, primarily by omitting the 

displacement to seawater step. The direct displacement utilizes very effective solvent and 

surfactant spacers to clean and water-wet the casing so that you can “directly” displace the 

wellbore to the final displacement fluid in a single operation. 

Water-Base System to Brine 



REVISION 2006 6-86



Once the well has reached TD, circulate a minimum of one bottoms-up and short trip into the 

casing. Go back to bottom and circulate a minimum of one bottoms-up. If well conditions are 

stable, clean the mud pits and surface equipment by flushing sufficiently with seawater/drillwater 

to remove all residue of drilling mud. 

Weighted Lead Spacer 

This spacer is designed to push the mud out of the wellbore. The spacer density should be slightly 

heavier (0.2 ppg) than the mud being displaced. YP = 1.5 times the YP of the mud. Spacer volume 

is based on the wellbore geometry and sufficient to cover 500 to 1000 feet of the largest annular 

diameter. 

Circulating Rate 

Pump at the maximum safe rate with the minimum rate determined by the wellbore configuration. 

Pump by conventional (forward) circulation. Rotate and reciprocate the pipe while pumping but do 

not reciprocate pipe while spacers or interface is near the end of the workstring. Do not shut down 

during displacement. 

Casing Cleanup Spacer 

CASING-WASH TM 100 is used to chemically remove the mud and other materials from the metal 

surfaces and carry them out of the wellbore. The volume is calculated at 0.5% to 1% of the casing 

volume and is mixed in water or brine at 5-8% by volume. The highest concentration is 

recommended when the fluid being displaced contains oil or other hydrocarbon additives. 

Viscosified Spacer 

This high yield point spacer will carry any remaining solids out to the casing or open hole and 

prevent contamination of the completion fluid. The spacer volume is based on wellbore 

configuration – usually filling 500 to 1000 feet of the largest annular volume. 

Filtered Brine 

Filtered completion brine should be circulated one full circulation or until cleanliness specifications 

are met. Dispose of the spacers as per established procedures. 

Oil Based System to Brine 

Optional Lead Spacer 

50 bbl of mineral or diesel oil can provide a good cleansing action on the casing and remove a 

significant amount of debris. This is a cost effective procedure but is optional depending on 

capabilities at the rig-site to recover and store the contaminated oil for future use. 

Push Pill 

Follow the base oil spacer with Spacer/Push Pill. Viscosify and weight up a seawater spacer to 0.2 

ppg heavier than the mud. The yield point should be a higher (1.5 times greater) to promote a good 

displacement without the commingling of the base oil or mud with the spacer. The volume should 

cover at least 1000 feet of largest annular diameter. The density, viscosity and surfactant in the 

spacer will help push oily debris out of the wellbore and initiate the water-wetting process. This pill 

should contain FLOW-CLEAN TM . 



REVISION 2006 6-87


Water-Wetting Spacer 

FLOW-SURF TM or FLOW-SURF TM PLUS will chemically detach, dissolve and remove the mud 

residue from all casing surfaces, flush out of the wellbore and finalize the water-wetting process. 

Typical concentration of solvent is 5-10%. 

Volume is determined and optimized based on surface area of tubulars, saturation volume, 

Reynolds number, annular velocity, contact time and pump rate. Normally spacer volume is ±1000 

ft of the largest annular volume. Contact time required is normally 2.5 to 10 minutes. 

Viscous Spacer 

Viscous Xanthan Gum / Seawater spacer between A-312N spacer and filtered brine. 

Volume = ±1000 feet of largest annular diameter. 

Clean Brine 

Circulate the filtered completion brine for one circulation or until cleanliness specifications are 

met. Dispose of all spacers as per regulations. 

General Displacement Considerations 

The displacement of mud from an annulus is a complex physical phenomenon. The main driving 

forces, which can be used to enhance the displacement, are: 

• fluid viscosity and density 

• pump rate and frictional forces 

• circulation of fluid 

High pump rates will nearly always be better (even in laminar flow); they reduce the boundary 

layer thickness on the casing wall. Turbulence is best to ensure 100% access of the clean up pills. It 

is recommended to use circulating sub to allow higher flow rates. 

In deviated wells the eccentricity of the displacement string reduces displacement efficiency and 

rotation and/or reciprocation is crucial for effective displacement. As steel surface is getting water 

wet, the effectiveness of pipe rotation may be diminished. If Advantage Torque and Drag 

simulation indicates high torque, it should be programmed to use friction reducer additive in the 

displacement fluid. 

Displacement must not stop once pills are in the annulus. Even very short stoppages will allow 

fluids to mix and increase the interface. Interfaces between fluids also increase with hole angle. 

Circulate to warm mud and use fine shakers when possible. At low temperature (



Push Pill 

Drill-In Fluid 

Casing Scrapers 

Stabilizers 

Figure 6 - 19 

Reverse Circulation 

Drill-In Fluid 

Push Pill 


Casing Scrapers 

Stabilizers 

Figure 6 - 20 

Forward Circulation 

However, there is a serious drawback to the reverse circulating technique. First, the drawback is 

that the friction pressure from pumping the entire length of the workstring at a high rate is imposed 

at the bottom of the wellbore, rather than at the surface. Secon, it also eliminates the possibility of 

rotating the workstring during displacement due to the closed BOP. 

Clean-out String Bottom Hole Assembly 

The following equipment can be used to clean and remove debris from the inside of casing: 

Casing scrapers should be used on the workstring in accordance with the casing schematic for 

each casing. Each casing section should have a scraper/brush placed not more than 100 feet above 

each casing shoe. These devices will help remove any solids that may adhere to the casing walls so 

the displacement fluid can move them out of the hole. A casing scraper should create maximum 

contact with internal diameter of casing, and be of a one-piece design with full drill pipe strength 

with no weak internal connections. Casing scrapers should enable rotation at rates up to 50 rpm, but 

conventional scrapers are not built for extended rotation or drilling, i.e. extensive rotation at the 

same spot should be avoided. Rotation and reciprocation of the drill pipe is recommended during 

displacement and clean up. Casing brushes are not considered necessary if an effective scraper is 



REVISION 2006 6-89


selected. If a brush is used it should be redressed after each application. Non-rotating scrapers are 

also available. 

Circulating subs should be used to enable high circulating rates. There are two major different 

types of circulating subs: ball drop type and weight-set sub. 

The ball drop type is the most common used. The circulation ports are opened by dropping a 

chrome-steel ball down the drill string, and then starting the mud pumps. With 1000 – 2000 psi 

fluid pressure, the ball shears the pin holding the sleeve, the ball and sleeve then drop, opening the 

ports and diverting the downhole flow. (See figure below) 

Figure 6 - 21 

Ball drop circulating sub 

Once the flow has been diverted, it can not be re-diverted and the ability to circulate to the bottom 

of the well is lost. This type of circ. sub allows rotation and reciprocation of the clean out string 

while circulating. Circulating subs should be installed above mud-motor and at every casing size 

increase, where Advantage Hydraulic simulations indicate that it will be necessary to achieve high 

enough circulating rate. A multifunction ball opening circulating sub is available in the market, but 

the failure rate has been high in some regions. 

The weight-set circulating tool relies on maintaining weight set down on the tool to maintain the 

circulation path, all circulation is at one point. These tools should be run with the clutch option 

allowing drill pipe to be rotated independently of the pipe inside the liner. This tool can be actuated 

as many times as required. 

Junk catcher should be used if there is any concern about debris or junk in the well. Baker Oiltools 

has a Junk catcher called ‘The Wellbore Custodian’. This is designed to seek out junk, collect it and 

the carry it to surface. The fluid passing through is being filtered through stainless steel screen. 

When RIH the tool will act as a boot basket allowing collection of large debris using fluid flow as it 

passes through the tool. When pulling out of hole, the bypass is closed and the tool now diverts 

fluid through the filter media capturing the debris. 

Magnets should be used to remove ferrous steel debris and swarf (metal filings, shavings, etc.). The 

downhole magnet is used to assist with cutting and milling debris removal where either low annular 

velocity, or with well fluids that have poor carrying capacity, is used. Typical locations of the 

magnets are just above the scrapers. 

Conditioning the Mud System 



REVISION 2006 6-90


A well-conditioned fluid will be easier to displace from a wellbore. The mud should be circulated 

and conditioned at normal flow line temperatures while reducing its viscosity and gels, but not to 

the point where it can no longer suspend weight material. When adjusting the rheology, the flow 

characteristics of the mud improve, making it easy to circulate and evenly disperse the solids prior 

to removal. 

Surface Pits and Equipment Clean-up 

Attention should be made to ensure the well and / or circulating system is not re-contaminated after 

the clean up. It is important that all areas coming into contact with the well are cleaned prior to the 

well clean up. 

Pit management and cleaning is a critical element for providing clean brine all through the well. 

With increasing restriction on pit access and pressure on time, management of pits and cleaning 

needs to be carefully considered by the rig team. Draft plan including pumping schedules and pit 

requirements must be discussed with all relevant personnel. 

Right pit washing tools will reduce the requirement for pit entry and reduce waste generated. The 

effectiveness of these systems relies on use of an effective detergent at ambient surface 

temperatures. All areas that require cleaning shall be cleaned by circulating a detergent pill for a 

minimum of 20 minutes, and then flushed with sea / drill water. 

Pit cleaning not only carries HSE risks associated with pit entry and waste volumes generated, poor 

cleaning of pits and surface lines can seriously affect clean up efficiency. Effective isolation 

between pits is very important to avoid contamination. 

The suggested checklist is a guideline for checking out equipment / areas that should be cleaned. 

The list has to be adjusted to the actual and relevant equipment on rig. 

AREA / EQUIPMENT 

Pits – (All where Completion fluid 

will be stored) 

Sand traps 

Degasser 

Mud Cleaner 

Mud Ditches 

Pumps 

Header Box 

Shakers 

Gumbo 

Poor Boy 

Trip Tank 

Trip Tank Fill Line 

Trip Tank Overflow Line 

Standpipe Manifold 

Top Drive 

Chicksans 

CLEANED 

PRIOR TO 

PUMPING 

CLEANED 

DURING 

PUMPING 



REVISION 2006 6-91


Choke Manifold 

Buffer Tank 

Choke & Kill Manifold 

Mud Pump Charging Pumps 

Mixing Pumps 

Rig Pumps 

Choke Lines 

Upper Kill Line 

Lower Kill Line 

Reverse Circulating Line 

Overboard Lines 

Pit Gun Lines (All) 

Transfer Lines: 

To & From All Pits 

To & From Filter Unit 

Diverter 

Equalizing Lines 

Lines to Drill floor 

Hole Fill Pump 

Pop Off Lines 

Bleed Off Lines 

Kill Pump 

Solids Handling Equipment 

Hose to Boat 

Relief Overboard (Cmt.) 

Mud Cleaner Pump 

H.P. Suction Manifold 

Transfer line to cmt. unit 

Strainers 

Surface Cleaning Procedure 

a) Pump the surface volume of mud into containers suitable for transfer to final destination. 

Remove any solids build-up in pits, corners and discharge areas by mechanical means. A vacuum 

system will greatly enhance the solids cleanup of the surface equipment. Also, with a high 

temperature/high-pressure washer, external areas can be cleaned thoroughly. Mix 1-2 drums of 

detergent into 100-150 bbls of water and flush all hoses, lines and pumps thoroughly, taking 

returns back to the same pit. Pump this at the maximum safe rate. 

b) Using the same fluid as in Step a) above and with the pipe rams closed, pump through all 

choke/kill lines, manifold and rig floor standpipe equipment to thoroughly remove all OBM or 

SBM residue. Pump at the maximum safe rate. Dispose of as per operator procedures. 

Design of Displacement Pills 

To ensure effective mud displacement and water wetting of the casing, the displacement pills need 

to be designed carefully, especially when oil based muds are in use. Major functions for these pills 

are: 

• disperse and thin the drilling fluid 

• compatible with the drilling fluids 



REVISION 2006 6-92


• lift out debris and junk 

• water wet pipe surface 

• remove pipe dope 

• effectively displace mud 

The best fluid for thinning the mud is the continuous phase of the mud. 50-75 bbl of the base oil can 

be pumped in the case of oil based muds. For water based mud pumping 50 bbl of water as the first 

displacement pill will effectively thin the mud. Before any displacement the compatibly of the spacers 

with the mud and the ability to water wet steel surfaces should be checked at room temperature and 

85° C (185° F) to confirm compatibility (in deep water lower temperature tests may be necessary). All 

tests should be done on field mud samples to ensure mud is representative. In high mud weight the risk 

of inducing barite sag needs to be considered, because displacement pills can thin the mud to the point 

it can no longer support barite. 

Water pumped without surfactants to displace oil muds (e.g. for an inflow test) prior to clean up, can 

form gunk, which are not broken down by subsequent clean up pills. Aggressive solvents are required 

to remove gunk and pipe dope. 

XAN-PLEX TM D and Xanthan Gum are the preferred materials for mixing viscous pills. When 

mixed in calcium brines, these require special procedures by lowering pH before adding the 

polymer, and then raise pH to get the fluid viscous. HEC-viscosified fluids do not have good solids 

support. Polymers should be checked for suitability at the anticipated bottom hole temperature. 

Lead Spacer (Push Pill) Systems 

The function of a lead spacer is to move the drilling fluid from the wellbore without contacting 

other incompatible fluids. Moving a system from a wellbore is best accomplished by utilizing a 

high pump rate, pipe rotation and a viscous (weighted) spacer. The high viscosity helps maintain 

the integrity of the spacer by enabling it to stay in “plug” or laminar flow at high pump rates. The 

spacer must be large enough to allow for 5 to 10 minutes contact time based on the pump rate. 

Pipe rotation helps break up the gelled pockets of mud that may accumulate in some sections of the 

annulus, especially in highly deviated wellbores. If required, the density of the lead spacer should 

be adjusted for well control reasons and should be at least or slightly more dense than the fluid 

being displaced. Although the lead spacer may be in plug flow, the middle spacer systems are 

moving in turbulent flow and will remove any residual debris. It is recommended that each spacer 

cover at least 1000 feet of the annulus at its largest diameter. 



REVISION 2006 6-93


Turbulent Plug 

V=O 

Figure 6 - 22 

Plug and Turbulent Flow Regimes 

Contact Time 

Spacer contact time in the wellbore is determined by the volume and type of spacer, the annular 

flow rate, the fluid and density being displaced and the wellbore configuration. Contact time is 

critical in the cleanup process because removal of debris occurs gradually as a spacer flushes past 

the wellbore surface. In most applications, the contact time may vary somewhere between 2.5 to 

10 minutes. The concentration of the solvent in the spacer also plays a significant role in cleanup, 

especially in the removal of oil-base and synthetic-base residue. In these and other applications, 

the volume of the spacer and the displacement rate determine the contact time. Usually the 

displacement rate is based on the annular flow rate needed to achieve turbulent flow, however, hole 

or rig conditions may limit the pump output. Once the volume is calculated for optimum contact 

time at the agreed-upon displacement rate, the appropriate solvent concentrations can be optimized. 

For the removal of oil/synthetic debris, concentration requirements are calculated based on the 

surface area of the wellbore (casing or open-hole). Programs are available to calculate precise 

contact time requirements for specific applications. 

HSE needs to be considered for all chemicals used. Mixtures of displacement pills and mud have to 

be separated from the active mud and packer fluid for disposal (zero discharge issues). 

Well Cleanliness Determination 

The determination of how clean the well is usually based on the cleanliness of fluids returning from 

the wellbore. The most common measures are normal turbidity units (NTU) and solids content, 

neither actually relate to what is left in the well. Junk baskets or equivalent equipment do give 

some positive indication of solids removal. Other indicators of a clean well are torque and drag 

(related to the increasing friction coefficient because of the fluid coating the casing walls being 

washed away) and cleanliness of the clean up string when pulled to surface. Rust in return from the 

pumped seawater or brine (if oxygen scavenger is not used) is also an indicator of a clean well. 



REVISION 2006 6-94


Turbidimeter (nephelometer) 

The measurement of brine clarity (solids content) is not a direct measurement of the concentration 

of suspended particles but a measurement of the scattering effect that such particles have on light. 

On-site measurement of brine turbidity with a portable nephelometer is quick and easy. Field 

testing has shown that this turbidity method is a useful way to evaluate brine quality and is most 

often used to decide when to stop displacement to brine after clean up. 

The procedure only places a relative value on the presence or absence of solids in a particular 

sample. The unit of measurement for turbidity is called a nephelometer turbidity unit (NTU). The 

absolute NTU value of brine is specific to each fluid and can be only used for comparison values to 

the same fluid. The absolute NTU reading is dependent on fluid color, solids distribution, air 

entrapment, etc. Each operator or completion procedure will have specific requirements for NTU 

reduction. Typical requirements are 50 – 100 NTU. 

The field use of a turbidimeter is recommended as a guide only. For example, during filtration, 

when the NTU values are no longer falling, no further gains in fluid quality will be made without 

making some change to the filtration process. 

Solids Content 

Measurements of solids content can be taken using a portable electrical centrifuge. For most 

operations, a solids content of < 0.05% is acceptable. For gravel packing this should be reduced to 

0.02% 

NTU and solids content are not directly related. Solids content will only assess materials collected 

at the bottom of the test tube during centrifuging. 

These tests use sample sizes of a few mls and it is difficult to draw conclusions about a well with 

an annular volume of 500 bbl. 0.1% vol/vol solids is equal to more than one ft 3 of solids deposited 

for tubing contents of 200 bbl. 

When clear fluids are pumped without adding oxygen scavenger, rusty coloured fluid will, after 

some circulation, return to surface. Corrosion products in return fluids give high NTU values. To 

deal with the problem of rust (as a result of oxidation of water wet steel surfaces) impacting 

turbidity readings, a little acid (HCl) should be added after the initial reading. When the well is 

displaced to packer fluid, it should always be inhibited with oxygen scavenger. 

Where the string is rotated during clean up the increase in torque can be used as an indicator of 

clean well. The coefficient of friction in sea water/brine is more than twice that of OBM. Typical 

friction factors for OBM is 0.12-0,15 and 0.20-0.29 for seawater/brine. 

For critical wells, e.g. high angle wells/where milling has occurred/previous problems with debris 

etc, it is recommended to use ‘Wellbore Custodian’ or similar junk basket. If the junk basket is 

pulled full it should be re-run. 

Visual inspection of the clean up string after pulling out of the hole will give a good indication of 

the cleanliness of the well. If it is mud free and water wet, the mud displacement and clean out has 

been successful. If the string is mud coated, a junk basket should be run. 



REVISION 2006 6-95


End of Well Reporting and Performance Measures 

Effective reporting of well clean up is crucial for developing best practice and looking for 

opportunities to improve or reduce cost. 

Key elements for reporting are: 

• Daily events to include all time associated with clean up 

• Record of measurements (e.g. NTU/solids content) 

• Tracking of performance (e.g. time to reach NTU target/interface volumes) 

• Lessons learned 

• Target time vs. actual 

• Tracking of brine, i.e. volumes received, built, lost, sent for reclamation 

A report should capture the following areas: 

• Fluid designs and properties 

• Flow rates 

• Pill volumes 

• Volumes circulated 

• Interface volumes 

• Equipment used 

• Materials used and costs 

• Pipe movement during displacement 

• Time breakdown 

• Fluids cleanliness vs. time during circulation 

• Surface clean up 

• Target vs. actual for cost and time 

• Pipe movement and torque measurements 

Identification of performance parameters to be measured should include: 

HSE Related: 

• Days Away from Work Injuries 

• Recordable Injuries and Illnesses 

• All Accidental, uncontained spills or discharges 

• Total Manhours on site for this service and operation 

Cost Related: 

• Total Completion Fluids Cost 

• Planned Cost 

• Filtering Related Cost 

• Total Cased Hole Volume 

• Total Spacer Fluids Pumped and Cost 

• Total Completion Fluid Volume and Cost 

• Completion Fluid Type 

• Completion Fluid Density 

• Completion Fluid Turbidity Requirement (NTU's) 

• Completion Fluid Solids Requirements (Vol%) 

Efficiency Related: 



REVISION 2006 6-96


• Total Non-Productive Rig Time (NPT) Hours Related to this Service 

• Total Non-Productive Rig Cost (NPC) 

• Total NPT Incidents related to this service, (Number of Occurrences (> 0.5 hrs) 

Quality Related: 

• People Related Failure, Number of Occurrences 

• Mechanical (Equipment) Failure, Number of Occurrences 

• Design Limit Related Failure, Number of Occurrences 

• Objectives Defined, Number 

• Objectives Met, Number 

Examples of performance to be measured: 

• Brine returns NTU to be as low as possible above value of fluid in pits 

• Clean returns after circulating as few hole volumes as possible 

• Minimize interface volumes between pills 

DISPLEX Displacement Software 

Displacements of drilling or drill-in fluids to clear brine are critical for most completion operations. 

Without a well-planned displacement to the completion fluid, completion tool setting failures or 

wellbore damage may compromise a project’s objectives. A wellbore clean up of casing and openhole 

section requires careful planning from a chemical, rheological and mechanical perspective. In 

addition, the calculations required to accurately model an efficient displacement are multifarious 

because of varying trajectories, tubular configurations, circulating sub requirements, wellbore 

intervals, fluid properties and requisite pump rates. 

Furthermore, in cases where geometry differences require varying pump rates due to multiple 

spacer systems, a single accurate planning tool helps the operator implement a safer displacement 

process. Using more accurate rheological models, such as the Herschel Bulkley model for drilling 

fluids, helps predict the pressure losses more accurately. Not withstanding these complexities, the 

displacement parameters must be modeled so that every operation, including cased and open-hole 

intervals, utilize the proper chemistry and mechanical energy to safely clean and remove unwanted 

wellbore debris. 

Baker Hughes Drilling Fluids utilizes proprietary displacement software (DISPLEX ) for planning 

and executing displacement operations. Each displacement fluid (mud, spacer and brine) can be 

individually customized based on the rheological behavior. Available models to choose from are 

the Bingham Plastic, Power Law and Hershel Bulkley models. The individual characterization of 

each spacer allows for proper pressure management during the displacement process. Complex 

rheological models, such as Hershel Bulkley, more accurately describe the rheological behavior of 

thixotropic fluids such as the drilling fluid and viscous push pills while the others, such as the 

Bingham model, accurately model the Newtonian fluids. 

A list of capabilities and benefits of this modeling software are given below: 

• A detailed pressure analysis table enables the user to adjust the pumping schedule to achieve 

maximum displacement rates without exceeding the formation fracture pressure. 

• Flow-in and flow-out information is continuously available. 

• ECD and pressure profiles with respect to time and depth are generated in tabular or in 

simulation mode. 



REVISION 2006 6-97


• Pressure, ECD and flow profile information relative to time and volume is recorded. 

• Forward and reverse circulation scenarios are available, including back pressure options. 

• Up to nine (9) fluids in the annulus and drill string may be included. 

• Five (5) different pump rates per spacer system are allowed, including separate fluids in the 

choke, kill and booster lines. 

• Each fluid can have different flow properties and use a different rheological model. 

• The model will show and account for free fall and allows for back pressure if needed to either 

control the free-fall or provide automatic calculation for maintaining the pressure for well 

control. 

• A “circulation sub” in the work string may be modeled for pressure and flow control. 

• Minimum required pump rates calculated to move fluids in a turbulent flow regime. 

• Color coding of the data allows for easy identification of problems. 

• A full 2D, dynamic flow pattern simulator allows the user to visualize the simulation process. 

• Last-minute changes in the displacement program are easily entered at the rig locations to 

account for any operational modifications or, in the case of pump failure, the pump schedule 

can be easily re-calculated and adjusted for new parameters. 

• Open-hole displacement modeling allows different clean-up spacers for both the open-hole 

and casing. 

• Multiple fluid densities may be input to provide a safe overbalance. Animation features 

visually verified for fluid top during the entire process. 

• Models deepwater operations and provides flexibility for pumping multiple spacer systems at 

different rates to clean the casing and the riser. Choke, kill and boost lines can be used for 

either pumping down or taking returns as the process dictates. 

• A volume calculator provides all the pertinent information about the wellbore. This reduces 

the planning time and possibility of error regarding contact time and spacer volumes. 

Baker Hughes Drilling Fluids has developed a suite of spacer/displacement products as described 

below. 

Pickling of Tubulars 

Baker Hughes Drilling Fluids has developed DOPE-FREE and DOPE-FREE Zn. These are 

highly effective pipe pickling solvents with proven success in dissolving a wide range of pipe 

dopes from downhole tubulars. They may be used to completely remove oil, grease and residue 

from the casing, work string, tubulars, pits and lines. 

DOPE-FREE TM in combination with the pipe pickling acid works to eliminate stubborn pipe scale, 

rust, cement, mud contamination and other foreign debris that can cause major well bore damage 

and even costly failures during well completion operations. 

DOPE-FREE is primarily used to pickle the workstring or tubing during the preparation for a 

completion operation. 

Recommended Treatment 

Each fluid should be pumped separately to the end of the workstring at the desired pump rate, and 

reversed out. A minimum of three (3) tubing volumes of brine should be reverse circulated after the 

acid treatment. A typical sequence and volume of the treating fluids are: 1) 210 gal of DOPE- 

FREE. 2) 420 gal of 15% HCl containing: • 1 gal of corrosion inhibitor • 2 gal of silt suspending 



REVISION 2006 6-98


agent • 20 lb of Iron sequestering agent. Capture the pickling acid solution at surface and dispose of 

according to local, state and federal regulations. 



REVISION 2006 6-99




REVISION 2006 6-100


PACKER FLUIDS 

Packer fluids are fluids, either clay-laden or without solids, which are left in the annular space 

between the tubing and casing. 

Packer fluids for the most part have been drilling fluids conditioned to be left in the hole on 

completion of the well. Under normal situations of low temperatures and normal pressures, this 

approach has usually been satisfactory. Not until the advent of lime fluid in the late 1940s and early 

1950s did packer fluids attain industry attention. Lime fluids, when exposed for prolonged periods 

of time to high temperature, may set to a non-pumpable solid state from the chemical reaction of 

clays, silica, lime, and caustic soda, which forms the cement-like substance tobermorite. This 

condition becomes severe at about 250°F. Such fluids prevent unseating of the tubing from the 

packer and pulling of the tubing during workover operations. Literally, these “set” fluids have to be 

drilled out. 

The problem of lime fluids focused considerable attention on packer fluid requirements. Since then, 

a number of approaches to the design of packer fluids have evolved. 

Requirements of a Good Packer Fluid 

The primary purpose of packer fluids is to provide sufficient hydrostatic pressure to protect the 

casing from excess formation pressures. Hydrostatic pressure is obtained by using soluble salts 

such as NaCl, CaCl 2 , CaBr 2 , ZnBr 2 , and insoluble materials such as barite and calcium carbonate. 

A packer fluid should be thermally stable at bottomhole temperatures. It should have sufficient 

gel properties for adequate suspension of barite in weighted systems, but be easily sheared down 

during pumping or pulling operations. 

The packer fluid should be non-corrosive. It should not form scales or produce gaseous byproducts 

such as H 2 S or CO 2 . It should not react with metal to produce inter-granular crystallization 

or changes in the metallurgical structure of the steel. 

A packer fluid should be free of solids settling on the packer. Gel properties in solids systems 

must be controlled to prevent sedimentation. Salt solutions must not form scales or produce 

insoluble sediments which could settle on the packer. 

Types of Packer Fluids 

Clear Brines 

Brine solutions are sometimes used as completion and packer fluids instead of conventional drilling 

fluid systems. There are two primary advantages to salt brines. 

1. A clean, particle-free medium minimizes formation damage during completion 

operations (cleaner perforations, good sand control, more successful plastic squeeze 

jobs, etc.). 

2. Fluids do not settle or solidify in the tubing-casing annulus to complicate workover 

jobs. Also, a reliable circulating fluid capable of retaining any formation pressures in the 



REVISION 2006 6-101


well is available at all times. All brines discussed in the previous sections are commonly 

used for this application. 

Conditioned Drilling Fluids 

This category probably represents the largest group used as packer fluids. Conditioning drilling 

fluids for use as packer fluids is generally done as a matter of economics rather than performance. 

Since an investment has been made in the drilling fluid, why not use it as a packer fluid? In the 

early 1960s, lime fluids, for the most part, were replaced with systems like UNI-CAL® and low pH 

gypsum fluids. Solidification was less of a problem with these systems, and the industry felt they 

could serve as packer fluids if properly conditioned. 

The primary advantages of using an existing drilling fluid for a packer fluid are availability and 

economics. Considerable expenditures are necessary when a new system is prepared because of 

material costs, rig time, and disposal of the existing fluid. 

Gelation and formation damage are potential problems when existing drilling fluids are put into 

packer fluid service. This is because of the high concentrations of colloidal solids which are 

generally present. These solids can be tolerated while drilling since the system can be conditioned 

periodically. Under static conditions, however, gelation may progress to the point that the fluid 

cannot be pumped when remedial work is required. Also, if cement and/or saltwater enter the 

system during workover operations, colloidal solids can flocculate and severely affect rheological 

properties. 

The inert solids (barite and sand) contained in a drilling fluid are not acid-soluble and may result in 

permanent blockage of the production zone. Also, drilling fluids usually are relatively low in 

electrolyte content, thus the filtrate could contribute to clay swelling and permeability damage. 

Since the well was drilled with the fluid, it is not likely that further surface or near surface damage 

to the formation will occur. On the other hand, perforating and fracturing expose undamaged 

formations. This work should be done with a solids-free or acid-soluble system, if at all possible. 

The initial cost advantages of utilizing an existing drilling fluid as a completion and/or packer fluid 

is quite appealing. Long range costs related to drilling fluids (excessive gelation, settling, formation 

damage, etc.) should be considered, however, before selecting them as packer fluids. 

If existing drilling fluids are to be used as packer fluids, the following steps should be taken prior 

to placing them in the hole. 

1. Reduce low-gravity solids by centrifuging or diluting to a maximum of 4%. 

2. Adjust the pH of the fluid to 11.5 to 12.5 with caustic soda. 

3. Add additional deflocculant to compensate for that lost through dilution and 

centrifuging. 

4. Add SALT WATER GEL ® and/or MILGEL ® to increase viscosity to the desired 

level. 

5. Treat the fluid with an oxygen scavenger (NOXYGEN TM ) and a biocide. MUD-PAC ® 

contains a biocide and corrosion inhibitor suitable for this purpose. 



REVISION 2006 6-102


6. Run static aging tests at operational temperature. 

SALT WATER GEL Packer Fluids 

A number of low energy suspension systems to be used as packer fluids have been investigated in 

the laboratory as well as in the field. The most satisfactory results have been obtained from the 

SALT WATER GEL packer fluid. Although this type of system may exhibit some subsidence in 

the fluid column, no difficulties in workover operations have been reported. 

The addition of an oxygen scavenger (NOXYGEN) and a biocide is recommended as a 

precautionary measure against corrosion and bacterial degradation. 

Material requirements for 1 bbl of SALT WATER GEL packer fluid for varying densities are 

contained in the table below. 

Fluid Weight 

(lb m /gal) 

14 

14 

14 

16 

16 

16 

18 

18 

18 

Table 6 - 26 

Lime 

(lb m /bbl) 

0.25 

0.25 

0.25 

0.25 

0.25 

0.25 

0.25 

0.25 

0.25 

SALT WATER 

GEL (lb m /bbl) 

8 

10 

12 

8 

10 

12 

8 

10 

12 

GEL-CMC Freshwater Packer Fluids 

MIL-BAR 

(lb m /bbl) 

307 

301 

296 

420 

418 

416 

528 

527 

527 

Water 

(gal/bbl) 

32.9 

32.8 

32.7 

29.8 

29.7 

29.6 

26.6 

26.5 

26.5 

Formula for 1 bbl of SALTWATER GEL of Varying Density 

GEL-CMC packer fluids have been used on operations with bottomhole temperatures up to 275°F. 

These fluids perform well because they can be pumped out when workover operations are required. 

These packer fluids utilize freshwater, MILGEL ® , CMC (medium viscosity), MIL-BAR®, 

NOXYGEN TM (oxygen scavenger), and caustic soda. A bactericide can be added for additional 

corrosion protection. 

The composition and mixing procedure for various densities are shown in the table below. To the 

measured amount of water required, add caustic soda, MILGEL, CMC (MV), and MIL-BAR. For 

fluid weights above 14 lb m /gal, start with a portion of the water required to avoid settling on the 

initial addition of MIL-BAR. 



REVISION 2006 6-103


Fluid 

Weight 

Desired 

(lb m /gal 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

Suggested 

Funnel 

Viscosity 

(sec/qt) 

45 - 55 

50 - 60 

55 - 65 

55 - 75 

60 - 80 

65 - 85 

75 - 90 

75 - 100 

75 - 100 

75 - 100 

Table 6 - 27 

Fresh 

Water 

(bbl) 

0.91 

0.87 

0.82 

0.79 

0.76 

0.72 

0.68 

0.65 

0.61 

0.57 

Caustic 

Soda 

(lb) 

0.36 

0.35 

0.33 

0.32 

0.30 

0.29 

0.27 

0.33 

0.43 

0.46 

MILGEL 

(lb) 

10.9 

9.5 

8.3 

7.1 

6.0 

5.0 

4.1 

3.3 

2.5 

1.7 

CMC (MV) 

(lb) 

1.82 

1.73 

1.66 

1.58 

1.51 

1.44 

1.37 

1.31 

1.22 

1.15 

MIL-BAR 

(lb) 

145 

200 

255 

310 

365 

420 

475 

530 

585 

640 

Formula for Preparing One Barrel of Weighted Freshwater 

Packer Fluid Using MILGEL and CMC (MV) 

Conversion of CARBO-DRILL Fluids to a Packer Fluid 

The CARBO-DRILL ® oil-base fluid system will make an excellent packer fluid with minor 

conditioning. Since oil-base fluids are electrical insulators, corrosion will be minimal in the 

CARBO-DRILL system. The CARBO-DRILL system is also significantly more temperature 

stable than water-base fluids. In addition, the CARBO-DRILL system environment is not 

conducive to bacterial growth. 

When using the CARBO-DRILL system as a packer fluid, it should be treated with approximately 

0.25 gal/bbl of CARBO-MUL ® HT for added temperature and emulsion stability. If the 

bottomhole temperature exceeds 350°F, 0.25 to 0.50 gal/bbl of CARBO-TEC TM and the 

appropriate amount of lime should also be added. 

The CARBO-DRILL system used must have adequate yield point and gel strengths to support 

barite and drill solids for long periods of time. Enough CARBO-GEL ® should be added to provide 

a 25 to 40 lb f /100 ft 2 yield point. Be sure the newly added CARBO-GEL has had adequate shear 

through the bit to insure maximum yield. Pilot testing is very useful in estimating the amount of 

CARBO-GEL needed. 

If there is a chance of CO 2 or H 2 S intrusion, enough lime should be added to provide for 4 to 6 

lb m /bbl excess lime. If H 2 S is expected, a hydrogen sulfide scavenger (MIL-GARD ® ) can also be 

added. 

SOFTWARE FOR COMPLETIONS AND WORKOVERS 

Baker Hughes Drilling Fluids has developed software specifically for use on completion and 

workover operations. This software is designed for use during the planning and operations phases 

of these operations. 



REVISION 2006 6-104


Bridgewise 

Bridgewise is a bridging technology designed by Baker Hughes Drilling Fluids to maximize 

hydrocarbon recovery from reservoirs. 

Bridgewise calculates the optimum blend of available calcium carbonate additives required to 

effectively bridge reservoir pore openings of known size. By utilizing a particle size distribution 

(PSD) database, Bridgewise allows the user to select the appropriate concentration and product 

ratio to provide maximum formation protection. This proprietary calculator is primarily used as a 

reservoir drill-in well planning tool, but in areas where there is a history of loss of circulation, 

Bridgewise may be used to select an appropriate LCM blend. 

Features and Benefits 

• Includes a choice of bridging rules 

• Abrams 1/3 Rule 

• Kaeuffer SQRT Rule 

• Vickers Rule 

• Selects fit-for-purpose products 

• Acid soluble products 

• LCM materials 

• User defined products 

• Uses core data for PSD (Particle Size Distribution) selection 

• Pore size in μm (microns) 

• Winland permeability/porosity 

• Permeability 

• Utilizes a PSD database 

• MIL-CARB Series 

• FLOW-CARB series 

• Locally analyzed product 

• Allows S.I. or Oilfield Units 

Bridging Rules 

Several calculation methods (rules) are available and can be used to compare the recommended 

output values of each. However, scores of tests comparing spurt and total filtration volumes and 

formation damage lead Baker Hughes Drilling Fluids to introduce the “Vickers Rule”. This rule 

offers an improvement over the often used Abrams and Kaeuffer Rules by selecting a more 

effective PSD of graded calcium carbonate for the entire range of expected pore sizes. 

The Vickers Rule has been validated in numerous laboratory tests. 



REVISION 2006 6-105


Lab Validation 

Bridgewise calculations have been validated in 

the permeability lab using cores of known pore 

size. Bridging efficiency evaluations based on 

long-term mud-off times (24-48 hours) were used 

to demonstrate the performance of various PSD 

blends. 

In a recent drill-in fluid evaluation, tests were 

conducted on a field core having a pore diameter 

range between 3 to 35 μm (d50 = 20 μm). 

Bridgewise calculations suggested that MIL- 

CARB and FLOW-CARB 10 would be the 

optimum product mix for this core. The core was 

tested and similar cores were tested with blends 

suggested by the Abrams and Kaeuffer rules. The 

lab results confirmed that the Vickers Rule 

provided the best recommendation for controlling 

spurt and total filtrate volumes relative to the 

other PSD blends. More significantly, after 48 

hour dynamic and static exposure tests were 

completed, higher regain permeability results were also achieved. 

Clear Brine ESD Calculator (Equivalent Static Density) 

Introduction: 

When planning for a completion, or while on location, the brine engineer must be able to predict 

the effective hydrostatic pressure exerted by the brine completion fluid in the wellbore. He must 

know what fluid density to procure in order to have the effective downhole density required to 

balance formation pressures under static conditions. Brine fluids can expand and therefore their 

densities are reduced as fluid temperatures increase. Since the temperature of the wellbore 

increases with depth, the effective hydrostatic pressure of the brine column changes as the 

temperature changes. Conversely, brine fluids are somewhat compressible, offsetting some of the 

effect of thermal expansion. Thus, the net change in the brine column density must be calculated in 

advance to ensure adequate well control and to minimize client completion fluid costs. 

The temperature/pressure correction software program for clear brine developed by Baker Hughes 

Drilling Fluids is known as the Clear Brine ESD Calculator. Baker Hughes Drilling Fluids’ 

Technology Group developed this calculator in response to the needs of field operations. 

Background: 

Before the development of the ESD Calculator, the industry used theoretical models to calculate 

the changes in density of brine due to temperature and pressure changes. The results derived from 

these models have not always been in close agreement with experimentally determined values at 

elevated temperatures and pressures for most of the brine blends used in the field. Furthermore, the 

change in density versus temperature and pressure are different for each brine type or blend. 



REVISION 2006 6-106


In 1984, Dow Chemical (Krook and Boyce, SPE 12490, 1984) developed experimental data for 

input into a working method for determining the effect of temperature and pressure on brine 

density. The model used the following equation. 

Where: 

ΔP t = (ΔP d x 10 -3 )β -– (ΔT x 10 -2 ) α 

ΔP t = Change in density resulting from temperature and pressure, lb/gal 

ΔP d = Pressure difference, psi 

ΔT = Temperature difference, °F 

β = Compressibility factor, lb/gal/100 °F 

α = Expansion factor, lb/gal/1000 psi 

If the values of α and β are known for a particular brine, the change in density can be calculated. 

Although the industry had taken a step forward in estimating clear brine downhole densities, the 

compressibility and expansion factors for most mixed-salt brine combinations were unavailable. 

The ESD Calculator has resolved this issue and developed a database of compressibility and 

expansion factors for most of the mixed-salt brine compositions. To complete the program, the 

Baker Hughes Drilling Fluids ESD Calculator provides calculated density values at 20 different 

TVD increments along the wellbore. 



REVISION 2006 6-107


Program Usage: 

Clear Brine ESD 

Operational Info 

Operator: International Oil and Gas 

Well Name: Well #1A 

Location: Offshore Gulf of Mexico 

Date: September 15, 2002 

Analyzed by: Brine Engineer 

Salt Info 

Depth/temperature table 

Density @ surface: 12.5 ppg Depth(ft) Temp.(F) Grad.(F/ft) 

Final TVD: 6000 ft Surface 0 80 

TCT: 60 o F 1000 60 -0.0200 

BHT: 223 o F 3000 125 0.0325 

BHP: 8900 psi 5000 190 0.0325 

Pressure Margin: -5037 psi 

Brine Composition: CaBr2/CaCl2 

Equivalent Static Density Table 

Density (lbm/gal) 

Depth (ft) Temp.(F) Local ESD Pres. (psi) 

80 12.50 12.50 

300 74 12.52 12.52 195 

600 68 12.54 12.53 391 

900 62 12.56 12.54 587 

1200 67 12.55 12.55 783 

1500 76 12.53 12.54 978 

1800 86 12.50 12.54 1173 

2100 96 12.48 12.53 1368 

2400 106 12.45 12.52 1562 

2700 115 12.43 12.51 1756 

3000 125 12.40 12.50 1950 

3300 135 12.38 12.49 2143 

3600 145 12.35 12.48 2335 

3900 154 12.33 12.46 2528 

4200 164 12.30 12.45 2720 

4500 174 12.28 12.44 2911 

4800 184 12.25 12.43 3102 

5100 193 12.23 12.42 3293 

5400 203 12.20 12.40 3483 

5700 213 12.18 12.39 3673 

6000 223 12.15 12.38 3863 

Table 6 - 28 

Example Results From Baker Hughes Drilling Fluids ESD 

Calculator 

Using the ESD Calculator is very simple and requires only basic input information. There are three 

categories for user input. They are as follows: 

• Operational information, 

• Salt information (Salt TCT is taken into account for mixed brines) , and 

• Depth/temperature/brine composition information. 



REVISION 2006 6-108


Once the data is entered in the category sections, the program generates a tabular printout of the 

ESD versus depth. This form can be printed for use in a brine program or for general information. 

In addition to the Equivalent Static Density Table, a graph can be printed indicating the change in 

ESD and Brine Pressure versus Depth. An example of each output is given below. 

Operator: 

International Oil and Gas 

Well Name: Well #1A 

Location: 

Offshore Gulf of Mexico 

Temp.(F) 

ESD 

Pres. (psi) 

0 

1000 

2000 

3000 

Depth (ft) 

Depth (ft) 

Depth (ft) 

4000 

5000 

6000 

7000 

0 50 100 150 200 250 

Temp. (f) 

12.35 12.40 12.45 12.50 12.55 12.60 

Fluid Weight (ppg) 

0 1000 2000 3000 4000 5000 

Pressure (psi) 

Figure 6 - 23 

Graphical Results Obtained from Baker Hughes Drilling 

Fluids ESD Calculator 

DISPLEX 

DISPLEX is state-of-the-art displacement and spacer management software that closely monitors 

downhole pressures and pump rates to ensure optimum contact time for an effective wellbore and 

casing clean-up. Some of its features are: 

• Multiple fluids and spacer capability 

• 3D wellbore visualization 

• Multiple rheological model options 

• Open hole completion 

• Spacer contact times 

• Flow profiles (turbulent or laminar) 

• Surface equipment limitations 



REVISION 2006 6-109


• Pump pressures 

• Deepwater application 

Spacers 

• User can choose one spacer or multiple spacer fluids. 

• If “multiple spacer fluids” option is selected: 

• In annulus - up to 9 different fluids with fluid interface locations and their individual 

rheological properties 

• Inside pipe - up to 9 different fluids with fluid interface locations and their individual 

rheological properties 

• Inside choke/kill/boost lines – 1 fluid and its rheological properties 

DISPLEX Simulation for UNOCAL INDONESIA 

The attached DISPLEX simulation was executed for UNOCAL INDONESIA for the purpose of 

demonstrating its benefits with respect to wellbore clean-up and cost savings from proper spacer 

selection, optimized contact time, proper displacement rates and reduced circulation time. 

For this simulation, some pipe size selections were estimated but this does not reduce the value of 

the output. There are several scenarios available to choose from with respect to the rig and 

location. The example illustrated below is a deepwater scenario where the 2-step method has been 

used. The 2-step method for deepwater applications uses the DISPLEX program to clean the 

bottom casing strings up to the top of the riser through the coke and kill lines. Once the clean-up 

spacers and brine have reached the surface (Stage 1 completed), then an additional clean up spacer 

system is pumped back down the choke and kill lines to clean the riser (Stage 2). 

Because of field success in deepwater clean up applications, the following spacer sequence has 

been selected: 

• Base oil spacer – begins the cleaning and is recycled into the used oil-based mud. DISPLEX 

calculated the flow rate for this spacer to be in turbulent flow for best cleaning. 

• Viscosified mud spacer – pushes debris up the hole dislodged by the turbulent base-oil 

spacer. 

• Lead solvent cleaner (Viscosified and Weighted FLOW-CLEAN) – continues the cleaning 

process. This pill is non-aqueous. 

• Second solvent cleaner (neat FLOW-CLEAN) – continues the cleaning process. To this 

point the wellbore has not seen any aqueous solution which is the key to using small pill 

volumes. 

• Water-wetting spacer (FLOW-SURF or CASING WASH 300) – water-wets the casing. 

This spacer represents the first time the wellbore is contacted with water (brine). 

• Final viscous sweep (HEC viscosified brine) – sweeps any remaining solids up the hole 

• Completion brine 

As mentioned for Stage 1, the spacer system will be circulated to the surface via the kill and choke 

lines. Stage 2 of the displacement is for riser cleaning, and in this case, the riser cleaning pill is 

circulated down the kill line, choke and booster lines and finally up the riser, isolating the 

previously cleaned casing. DISPLEX will calculate the time, strokes, pump pressure and pump 

rate required circulate the various pills to surface so that the various spacers are in the proper flow 



REVISION 2006 6-110


regime (laminar or turbulent). For reduced rig time and more efficient cleaning, turbulent flow 

rates for the spacers and brine have been chosen. 

Below are found diagrams of various stages in the displacement for this WSA C06 (WSAP-16) 

applications. In a separate file, are found the DISPLEX printout of all the pumping schedules for 

this simulation. 

Figure 6 - 24 

DISPLEX Simulation for Deepwater Applications 

Operation 2 

Stage 1 Stage 2 

Pumping down the work string, (left figure) to clean casing and pumping down the 

kill/choke/booster lines (right figure) for the riser clean-up. 



REVISION 2006 6-111


Figure 6 - 25 

Simulation of WSA C06 (WSAP-16) Wellbore Displacement 

and Clean-up 

Casing Clean-Up 

Oil base mud being 

displaced up the kill 

and choke lines 

In stage 1 the 

riser volume is 

stationary 

Leading edge of base 

oil spacer moving up 

Weighted/viscosified 

non-aqueous spacer 

Neat, non-aqueous 

spacer 

Leading edge 

clear brine fluid 

entering the 

kill/choke line 

Weighted/viscosified 

non-aqueous spacer 

Viscous HEC brine 

spacer 

Clear Brine 



REVISION 2006 6-112


Figure 6 - 26 

Simulation of WSA C06 (WSAP-16) Wellbore Displacement 

and Clean-up 

Riser Clean-Up 

Leading edge of Casing 

Wash 300 being pumped 

down the kill/choke line 

lines 

Note Turbulent flow 

pattern 

OBM in laminar 

flow 

Casing Wash 300 

spacer shown 

completely in riser 

in turbulent flow 

followed by clear 

brine 

Isolated casing with no 

flow in stage 2 



REVISION 2006 6-113


REFERENCES 

1. Louisiana State University, Louisiana Energy & Environmental Resource & Information Centre, 

www.leeric.lsu.edu/bgbb/ 

2. Completion and Workover Fluids, K. L. Bridges, SPE Monograph Series, 2000. 

3. van Velzen, J.F. G and Leerlooijer, K., Impairment of a Water-Injection Well by Suspended Solids : 

Testing and Prediction, SPEPF, August 1993. 

4. Maly, G.P., Minimizing Formation Damage – 2. Attention to System Details Helps in prevention of 

Damage, Oil & Gas Journal, 29 March, 1976. 

5. Ali, S.A. et al, Test High-Density Brines for Formation Water Interaction, Petroleum Engineer 

International, July 1994. 

6. Leontaritis, K,J. and Charles, R.E., A systematic Approach for the Prevention and Treatment of 

Formation damage Caused by Asphaltene Deposition, SPEPF, March 1994. 

7. Sutton, G.D. and Roberts, L.D., Paraffin Precipitation During Fracture Stimulation, Journal of 

Petroleum Technology, September 1974. 

8. Dyke, G.G. and Crockett, D.A., Prudhoe Bay Workovers: Best Practices for Minimising Productivity 

Impairment and Formation Damage, Paper SPE 26042 presented at the 1993 SPE Western Regional 

Meeting, Anchorage, 26 – 28 May. 

9. Jones, T.A. And Daves, T., Reservoir Drill-in Fluids: Selection Criteria, Testing Protocol and 

Operational Procedures, AADE Drilling Fluids Conference, Houston, Texas, 3 – 4 April 1996. 

10. Donovan, J.P. and Jones, T.A., Specific Selection Criteria and Testing Protocol Optimise Reservoir 

Drill-in Fluid Design, SPE paper 30104, presented at the European Formation Damage Control 

Conference in The Hague, the Netherlands, 15 – 16 May, 1995. 



REVISION 2006 6-114

Borehole Problems 

Chapter 

Seven 

Borehole Problems

Chapter 7 


BOREHOLE PROBLEMS...............................................................................................................7-1 

HOLE STABILITY PROBLEMS ..........................................................................................................7-1 

Introduction ................................................................................................................................7-1 

The Mechanisms of Wellbore Instability – Mechanical Aspects........................................7-2 

Preventative Action – Mechanical..........................................................................................7-4 

Symptoms and Remedial Action ............................................................................................7-6 

The Mechanisms of Wellbore Instability – Chemical Aspects ...........................................7-6 

Preventative Action – Chemical..............................................................................................7-7 

Symptoms and Remedial Action ............................................................................................7-8 

Special Cases ...........................................................................................................................7-9 

INHIBITIVE WATER BASED DRILLING FLUIDS...............................................................................7-11 

Shale Hydration.......................................................................................................................7-11 

Shale Hydration Inhibition......................................................................................................7-12 

Pore Pressure Transmission.................................................................................................7-13 

Pore Pressure Transmission Inhibition................................................................................7-14 

Silicate Based Drilling Fluids.................................................................................................7-15 

Cloud Point Glycols ................................................................................................................7-17 

LOSS OF CIRCULATION.................................................................................................................7-21 

Preventive Measures .............................................................................................................7-22 

Seepage Loss .........................................................................................................................7-23 

Partial Loss ..............................................................................................................................7-24 

Severe (or Total) Loss of Returns........................................................................................7-26 

Loss Circulation Prevention by “Stress Cage” Technique................................................7-32 

DRILLSTRING STICKING ................................................................................................................7-34 

Spotting Fluids.........................................................................................................................7-36 

Remedial Procedures Using Spotting Fluids......................................................................7-37 

Alternate Methods for Freeing Stuck Pipe ..........................................................................7-40 

Other Causes of Drillpipe Sticking and Remedial Correction ..........................................7-42 

LUBRICITY .....................................................................................................................................7-43 

HIGH BOTTOMHOLE TEMPERATURES..........................................................................................7-45 

Mechanisms of Thermal Degradation..................................................................................7-45 

Temperature Limits.................................................................................................................7-46 

Extending Temperature Limits..............................................................................................7-47 

Drilling Fluid Properties..........................................................................................................7-47 

Symptoms and Remedial Action ..........................................................................................7-49 

Planning ...................................................................................................................................7-51 

REFERENCES ................................................................................................................................7-52 

BAKER HUGHESDRILLING FLUIDS 

REVISION 2006 7-i 

REFERENCE MANUAL



TABLE 7 - 1 FORMULA FOR PREPARING ONE BARREL DIASEAL M WEIGHTED SLURRY WITH 

FRESH WATER, BAY WATER, OR SEA WATER .......................................................................7-24 

TABLE 7 - 2 FORMULA FOR PREPARING ONE BARREL SOLU-SQUEEZE WEIGHTED SLURRY 

WITH FRESH WATER, SATURATED SALT WATER (SSW), OR OIL .........................................7-26 

TABLE 7 - 3 MAGNE-SET SLURRY FORMULATIONS ....................................................................7-29 

TABLE 7 - 4 MAGNE-SET ADDITIVE CONCENTRATIONS - SACKS PER 25 BBL ...........................7-29 

TABLE 7 - 5 FORMULATION FOR ONE (1) BARREL OF UN-WEIGHTED X-LINK AS FUNCTION OF 

TEMPERATURE..........................................................................................................................7-31 

TABLE 7 - 6 FORMULATIONS TO BUILD 100 BARRELS OF WEIGHTED X-LINK PLUG ..................7-32 

TABLE 7 - 7 LUBRICANTS.................................................................................................................7-35 

TABLE 7 - 8 BLACK MAGIC SFT MATERIAL REQUIREMENTS - FORMULATION PER 100 BBL . 7-38 

TABLE 7 - 9 MIL-SPOT 2 MATERIAL REQUIREMENTS - FORMULATION PER 50 BBL ..............7-39 

TABLE 7 - 10 BIO-SPOT MATERIALS REQUIREMENT - FORMULATION PER 100 BBL..................7-39 

TABLE 7 - 11 DRILLING FLUIDS PRODUCTS TEMPERATURE LIMITATIONS....................................7-47 


FIGURE 7 - 1 FORMS OF MECHANICAL INSTABILITY.........................................................................7-3 

FIGURE 7 - 2 DEFINING “MUD WEIGHT WINDOW”............................................................................7-3 

FIGURE 7 - 3 MECHANICS OF MAX-SHIELD.................................................................................7-15 

FIGURE 7 - 4 TEMPERATURE SEQUENCE OF GLYCOL CLOUD POINT FORMATION......................7-17 

FIGURE 7 - 5 PHASE CONDITIONS OF CLOUD POINT FORMATION................................................7-18 

FIGURE 7 - 6 TYPICAL PPT DATA FOR VARIOUS FLUIDS..............................................................7-19 


REVISION 2006 


7-ii

BOREHOLE PROBLEMS 


Chapter 7 

Wellbore problems are the result of many circumstances, not the least of which is 

misinformation resulting from inadequate planning. Drilling fluids are not the sole cause of 

wellbore problems; they are however, the first line of defense to correct them. 

HOLE STABILITY PROBLEMS 

Introduction 

The maintenance of wellbore stability is one of the most critical considerations in any drilling 

operation. As a minimum, an unstable wellbore will reduce drilling performance and in the 

worst case could result in the loss of the hole through borehole collapse. 

Wellbore instability can occur as a result of mechanical effects, chemical effects, or a 

combination of both. In simple terms, mechanical effects are usually related to drilling fluid 

density (drilling fluid density too high or too low) or drilling practices (rate of penetration, 

inadequate hole cleaning, vibration effects, torque and drag and frequency of trips), whereas 

chemical effects are drilling fluid type related (inappropriate drilling fluid type or inhibition 

level for the formation being drilled). The following sections give more detail on this, and 

provide a guide to minimize wellbore instability in the planning, implementation and drilling 

phases. 

Common Misconceptions 

Before detailing aspects of hole stability problems some popular misconceptions must be 

dispelled. 

• Many in the industry believe that well control purposes alone dictate the required mud 

weight. They also assume that hole collapse is simply a result of drilling with 

insufficient drilling fluid density. Thus, the perception is that drilling with a nominal 

overbalance for well control will also ensure hole stability. The logic behind these 

beliefs is flawed. Weak formations may need overbalance in excess of 1000 psi to 

prevent hole collapse, whereas some mudstones can be drilled problem free in 

“underbalanced” conditions. 

• It is common to assume that increasing drilling fluid density is always the answer to hole 

instability problems. This is not always correct. Increasing drilling fluid density can 

amplify problems. For instance, more rapid failure could occur in fractured rocks, 

whereas in some porous formations the resulting higher filtration rates and thicker 

filter cakes could promote differential sticking. 



REVISION 2006 7-1


• Many believe that the use of an invert emulsion drilling fluid will prevent any problems 

occurring while drilling in shales. Hole instability can still occur particularly if the 

drilling fluid density or water phase salinity is inappropriate. 

• It must be recognized that drilling fluid recommendations based on theoretical models are 

liable to be unreliable and often require “fine tuning” to give sensible, practical drilling 

fluid densities. Area experience is a better guide. 

• Too great of an emphasis is often placed on annular velocity in the process of hole 

enlargement. Reducing API filtrate and increasing inhibition and overbalance will 

often have more beneficial effects than reducing annular velocity. 

The Mechanisms of Wellbore Instability – Mechanical Aspects 

Unconsolidated Formations 

This type of formation would usually be associated with top hole intervals, but may also be 

encountered in fault zones or in unconsolidated reservoirs. Unconsolidated formations have no 

cohesive strength. Consequently when they are drilled with a clear fluid that exerts no 

confining stress on the wall of the hole the formation will slough into the hole. Most commonly 

the unconsolidated formation will be sand. However, in some tectonically active areas, a fault 

zone will be encountered that contains rock flour and unconsolidated rubble. 

Preventative and Remedial Action 

• Drilling this type of formation with a drilling fluid that has good filtration characteristics 

will produce a filter cake on the rock. The pressure drop across this cake will impart 

cohesive strength and a gauge, or near gauge, hole can often be achieved. The drilling 

fluid should contain bridging solids (usually calcium carbonate or fibrous seepage loss 

material) to promote the rapid build-up of a filter cake. If a cake is not quickly 

established the turbulent flow at the bit will produce washed out hole. 

• Use the minimum flow rate that will clean the hole to prevent the erosion of the filter 

cake. 

• Consider the use of a drilling fluid with good low shear rate viscosity so that high pump 

rates are not required. Xanthan gum polymer (XAN-PLEX ® D) and mixed metal 

hydroxide (MMH) have an application in these cases. 

• Do all that is possible to avoid the mechanical removal of the filter cake – minimize trips, 

minimize reaming and back-reaming, avoid rotating stabilizers next to the unconsolidated 

formation. 

• The use of a drilling fluid known to have enhanced fracture sealing capabilities may help 

to stabilize fault zone rubble beds. Specific drilling fluid systems and additives can be 

designed for this application. 



REVISION 2006 7-2


Competent Formations 

There are two extremes of mechanical hole 

instability, referred to as compressive failure 

and formation breakdown (Figure 7 - 1). 

Compressive failure occurs when the drilling 

fluid density is too low – this results in hole 

closure (tight hole) or hole collapse. In 

contrast to this, formation breakdown occurs 

if the drilling fluid density is too high. 

Drilling fluid pressure may induce a fracture 

or open a natural fracture system, leading to 

massive mud losses. 

In general, hole sections containing 

shales/mudstones will collapse if given 

insufficient support, and sands/carbonates 

will lead to mud losses and/or differential 

sticking if drilled with too high an 

overbalance. 

Figure 7 - 1 Forms of Mechanical Instability 

To drill a hole section with little or no instability problems requires the maximum drilling fluid 

density tolerated by the 

sand/carbonates to exceed the 

minimum drilling fluid density 

required to support the mudstones. 

These upper and lower bounds to 

the drilling fluid density define the 

“mud weight window” (see Figure 7 

- 2). The wider the window the 

easier the well is to drill. 

Conversely, the narrower the 

window the more difficult it is to 

contain the drilling fluid density 

within the stable region, and hence 

the risk of wellbore instability is 

much greater. 

Figure 7 - 2 Defining “Mud Weight Window” 

In certain highly tectonically stressed regions (e.g. foothills of the Casanare region in 

Colombia) the collapse gradient in the shales can exceed the fracture gradient in the sands, 

even for nominally vertical wells. In such cases there is no drilling window and it is impossible 

to select a drilling fluid density to simultaneously avoid both losses and collapse. Hence, one or 

both forms of instability must be tolerated to some extent. 



REVISION 2006 7-3


In general a mud weight window will exist. The “width” of the window will depend on a 

number of operator controlled factors, but primarily well inclination. Increased well inclination 

will usually reduce the width of the mud weight window (Figure 7 - 2), thus increasing the risk 

of straying from the region of safe mud weights. Hence, Extended Reach Drilling (ERD) wells 

are typically more prone to instability than other more conventional wells drilled in the region. 

Another factor strongly influencing the integrity of the hole is the open hole time. Even stable 

shales are seldom stable for an indefinite period and the longer the open hole time the greater 

the risk that instability will occur. This is particularly the case when using water based drilling 

fluids. Increased hole section length and therefore increased open hole time are a natural 

consequence of drilling ERD wells. Where possible, a gradual increase in drilling fluid density 

can be effective in combating this time element and can stabilize the formation for a longer 

period. 

When assessing ERD options in a region previously drilled with conventional wells, the 

primary hole stability consideration is to assess the impact of trajectory on the mud weight 

window. If conventional drilled wells have proven difficult to drill due to a narrow mud weight 

window, then serious thought must be given as to whether a casing program can be designed to 

combat the increased risks projected in the ERD well. 

Preventative Action – Mechanical 

Pre Drilling 

The purpose of any data collection is to attempt to define the optimum drilling window for 

offset wells and to project that window to planned wells. Without any offset well data then 

there is little value in any wellbore stability study. 

The data of most value are: 

• Drilling and Completion reports from offset wells (which may contain much of the other 

information listed below). 

• Details of any formation stress tests including Leak Off Test (LOT) and Formation 

Integrity Test (FIT). 

• Daily mud properties. 

• Details of any drilling fluid losses encountered. 

• Details of any pipe sticking and/or excess reaming. 

• Composite logs, dipmeter or borehole geometry logs, any caliper logs, density logs and 

sonic logs. 

• Description of any major faulting in the region (normal, strike-slip, etc). 

Planning Stage 

Well Inclination 



REVISION 2006 7-4


• Allow for increases in drilling fluid density of between 0.5 ppg and 1.0 ppg per 30 

degrees inclination through shale/mudstone sections to combat hole collapse. Only local 

experience will determine at which end of the scale to be. 

• No increase in drilling fluid density with hole inclination is necessary across permeable 

formations, e.g. sands. Formations with reasonable matrix permeability can usually be 

drilled with nominal overbalance, regardless of well trajectory or formation strength. 

• Be aware that the fracture gradient may reduce with increased angle. 

Fracture Gradient 

• Recognize that the fracture gradient for a hole section is more likely to be controlled by a 

carbonate or sand rather than the shale within which the LOT was performed (see Figure 

7 - 2). 

• On ERD wells, drilling high pressure reservoirs may prove extremely difficult due to a 

very tight mud weight window between taking a kick and experiencing losses. The extent 

and effect of ECDs need careful consideration at the planning stage. 

• During appraisal, consider performing micro-fracture tests (essentially a LOT taken 

beyond the point of breakdown) to better determine the fracture gradient in formations 

that may prove to be critical in an ERD well. 

Regional Stress State 

• Process any dipmeter or borehole imaging log data to determine in situ stress directions. 

This may help to interpret any problems seen during the drilling operation and thus 

hasten corrective actions. 

• In highly tectonically stressed regions, drilling up dip of the major faults may provide a 

larger mud weight window than drilling down dip, cross dip or vertically. 

• The in situ stress state near a salt diapir is highly disturbed, such that well trajectories 

which approach the diapir normal to its surface provide a larger mud weight window than 

trajectories tangential to its surface. 

Casing Program 

• Having planned for an increased drilling fluid density to control shales in an ERD well, 

assess whether the planned casing setting depths still provide sufficient mud weight 

window. 

• In ERD wells the drilling fluid density required to drill a normally pressured reservoir is 

often significantly less than that required to prevent collapse in the cap rock. The setting 

of the production casing should minimize or exclude the presence of cap rock in the 

reservoir hole section, thus allowing the reservoir to be drilled with a normal 

overbalance. 



REVISION 2006 7-5


General 

• Oil-based drilling fluids often allow a lower drilling fluid density to be used to prevent 

collapse in shales. This provides a larger mud weight window. 

• The risk of instability in highly laminated shales may be reduced when adopting a 

trajectory normal to bedding. 

Symptoms and Remedial Action 

• The onset of cavings from a formation while it is being drilled may indicate underbalance 

conditions. An increase in drilling fluid density or a reduction in ROP may help. 

• The onset of cavings more than a few hours after drilling a shale indicates that the benefit 

of the initial overbalance has been lost. This is a result of the migration of filtrate into the 

formation causing near wellbore pressure increases. An increase in drilling fluid density 

and/or a reduction in API filtrate are likely to help. 

• Often an improvement in LOT value can be observed as the section is drilled. Consider 

repeating the LOT where low values have originally been obtained. 

• Even in normally stressed regions the mud weight window may be influenced by well 

azimuth. Be prepared to increase the drilling fluid density in wells with azimuths subparallel 

to the maximum horizontal stress direction. 

• Controlling API filtrate to a minimum is particularly important in ERD wells and all hole 

sections, not simply in the reservoir section. 

• Swab and surge pressures may trigger instability in weak or highly fractured shales. 

Particular care is required when running in and pulling out of hole sections with such 

formations present. Pressure While Drilling (PWD) measurements indicate that surge 

pressure equal to 1.5 ppg (0.18 S.G.) can be generated not just when tripping, but also on 

connections made with a top drive. 

• Unless absolutely necessary, do not reduce the drilling fluid density while drilling if a 

shale is present in the open hole section, otherwise the risk of hole instability is greatly 

increased. If operational difficulties necessitate a drilling fluid density reduction then the 

slower this is done the better. 

The Mechanisms of Wellbore Instability – Chemical Aspects 

Chemical wellbore instability is due to chemical interaction between the formation being 

drilled and the drilling fluid. This can occur in two main types of formation: 

• Shales 

• Salt formations 

In both cases, it is an interaction with water which causes instability. Thus, chemical stability 

is always minimized by using oil based drilling fluids. 



REVISION 2006 7-6


When shales react with water, they can soften, disperse, swell and crack. These effects can 

cause a wide range of operational problems such as tight hole, hole enlargement, ledging, bit 

balling and caving. 

To minimize these problems, it is important to characterize the shale type at the planning stage 

of a well, and to use an appropriately designed drilling fluid. 

In salt formations, chemical instability occurs if the formation is soluble in water. The use of an 

incorrectly formulated fluid will lead to uncontrollable washouts in these situations. Formation 

types which exhibit this behavior are: 

• Halite (NaCl) 

• Carnallite (KMgCl 3 .6H 2 O) 

• Bischofite (MgCl 2 . 6H 2 O) 

• Sylvite (KCl) 

• Polyhalite (K 2 Ca 2 Mg(SO 4 ) 4 . 2H 2 O) 

Preventative Action – Chemical 

Pre Drilling 

• When planning a well, first decide if shales or salts will be encountered. Offset well data 

and drilling fluid reports will be particularly useful. 

• Design the casing/well program to minimize the length of time reactive formations are 

exposed to the drilling fluid. Because shales have very low permeability (10 -9 – 10 -6 D), 

they may appear stable for a time, but water can penetrate leading to time delayed effects. 

This process is known as pore pressure transmission and can be countered by the use a 

cloud point glycols, silicate and aluminate based drilling fluids. 

• Characterize shale types by XRD (X-ray Diffraction) analysis. This technique should also 

be supported by laboratory inhibition tests, which are best done on preserved shale. 

• Watch out for inter-bedded formations (e.g. salt stringers in shale or reactive shale in 

competent shale). A drilling fluid system compatible with both formation types will be 

required. 

• The best way to minimize chemical instability in shales or salt sections is to use an oil 

based drilling fluid. High performance water based drilling fluids should be given serious 

consideration as alternatives. A cost/benefit analysis should aid the final selection 

process. 

• Do not rely on chemical - mechanical wellbore stability models to design the drilling 

fluid. There is invariably insufficient input data, and they do not take account of specific 

chemical reactions. 



REVISION 2006 7-7


Oil-Based Drilling Fluid –Engineering Comments 

• Oil-based mud (OBM) water phase salinity must be at least as high as the pore fluid 

salinity of the shale. This will prevent water entering the shale by osmosis. 

• When drilling salt formations, OBM salinity should be high (e.g. 300,000 mg/l chloride), 

to minimize salt dissolution into the water phase of the drilling fluid. 

• Synthetic-based mud (SBM) (pseudo oil based drilling fluids) should be considered 

where environmental constraints restrict the use of conventional oil. Shale inhibition is 

equally effective in these systems. 

• In micro-fractured shales, use a very low HPHT filtrate drilling fluid (< 3 ml), and add 

fracture sealing additives. 

Water-Based Drilling Fluid –Engineering Comments 

• If water-based mud (WBM) is to be used, carry out a screening program at an early stage 

to allow optimization. 

• Water based drilling fluids are less lubricating generally than oil based drilling fluids, 

therefore expect higher torque in high angle wells. It may be necessary to add lubricants 

to the system. 

• In salt sections, it is important to match the fluid to the type of salt. Salt saturated drilling 

fluids (NaCl) are used for simple halites; mixed salt systems are available for complex 

salts such as Carnallite. 

• Use a low filtrate drilling fluid (e.g. API < 5ml, HPHT (250°F < 14 ml) in microfractured 

shales, and add fracture sealing additives. 


Having planned the well using all available data, the risk of mechanical and/or chemical 

borehole instability will be limited. It is important that should instability occur it should be 

identified and suitable remedial action should be adopted. 

Indication of the condition of the hole can be inferred from torque and drag measurements, the 

condition and quantity of cuttings seen at the shale shakers and variations in drilling fluid 

volumes. 

• When drilling shales, monitor cuttings quality as a qualitative measure of inhibition. Very 

soft cuttings will mean insufficient chemical inhibition or, in the case of OBM, would 

suggest that the water phase salinity is too low. 

• High torque values would suggest tight hole, possibly requiring an increase in drilling 

fluid density or an increase in inhibition to reduce the swelling of clays. 

• A sudden appearance of large or increased volume of “cuttings” at the shale shakers is 

indicative of wellbore caving. 



REVISION 2006 7-8


• An unplanned increase in drilling fluid rheological properties could be due to a build up 

of fine solids in the drilling fluid which in turn could be an indication of poor inhibition 

or hole washout. 

• The downhole loss of whole drilling fluid would indicate that the formation was being 

fractured by the use of too high a drilling fluid density. 

• Difficulty running in the hole could be attributed to ledges, swelling clays or caving 

formations. 

The caliper log can be run at section TD. The gauge of the hole will give an indication of 

whether drilling fluid density and inhibition was at a correct level for that interval. If an 

oriented 4-arm caliper is used, information on stress orientations can be obtained. A typical 

indication of stress induced borehole instability is the presence of an oval rather than a circular 

hole. Information regarding the two horizontal in situ stresses can be deduced from this type of 

log. Knowing the direction of the stresses is valuable when planning development wells as the 

well directions least prone to hole problems can be established. 

Special Cases 

Salt Formations 

• Drilling near a salt diapir (salt intrusion as in salt dome) presents a special case because 

of the altered in situ stresses near to the diapir. The behavior of wells within a few 

hundred meters of a diapir may be totally different to wells only a kilometer or so away. 

In general hole problems are accentuated near a diapir. 

• The maintenance of gauge or near gauge hole is important when drilling massive salt 

formations. Greatly washed out hole will probably result in a poor cement job. This in 

turn will allow salt behind the casing to creep, impinging on the casing and, in extreme 

cases cause the casing to buckle. 

• Stuck pipe is a common problem when drilling salt formations. Salt formations tend to 

creep and impinge on the drillstring. The only way to stop this process is to drill with a 

drilling fluid density equivalent to overburden gradient (approximately 19 ppg in the 

Southern North Sea and 17 ppg in the Gulf of Mexico). In practice the rate of creep can 

often be reduced to acceptable levels at lower drilling fluid densities, typically 14.0 ppg. 

The use of eccentric bits to slightly increase the diameter of the hole has proved 

beneficial in some operations. Figure 7 – 3 describes the approximate mud weight to 

control salt creep as a function of hole temperature and hole depth. 

• Drilling massive salt sections with OBM/SBM generally produces an in-gauge hole. In 

many cases, the creep of the salt results in the drill bit becoming stuck. Pumping a slug 

(5 – 10 bbl) of fresh water down the drill pipe past the bit generally frees the bit. The 

small volume of water should not affect the stability of the OBM, but the system should 

be treated with additional salt to bring the water phase salt concentration back to required 

levels. 



REVISION 2006 7-9


Figure 7 - 3 

Approximate Mud Weight Required to Control Salt Creep 

Coal Formations 

Coal is a very brittle formation with low compressive strength. It is usually highly fractured 

and in areas of high tectonic stress can instantly collapse into the borehole when the horizontal 

stress is relieved by the bit – stuck pipe is often the end result. High drilling fluid densities can 

rarely be used to stabilize the coal formation because of their inherent low fracture gradients. 

The recognized technique to drill coal is to limit penetration rates so that the stresses are given 

a chance to equilibrate and so that the blocky pieces of coal can be removed from the hole. 

Good hole cleaning is essential – it may be necessary to modify the cleaning capacity of the 

drilling fluid while drilling coal. The properties can be restored to normal when the coal has 

been drilled. Alternatively viscous, weighted sweeps can be used to enhance hole cleaning – 

this is particularly appropriate if the coal seam is anticipated to be thin. 



REVISION 2006 7-10


Should the pipe become stuck in coal, and circulation is possible, experience shows that 

spotting a high pH pill around the coal can help to free the pipe. 

Where the coal seam is not tectonically stressed and geological information regarding the seam 

is required care must be taken with fluid properties and drilling practices. Seat earths and 

marine bands both provide valuable information about the coal but both are easily washed out. 

When coring with water based drilling fluids a low filtrate should be utilized and jet velocity 

should be minimized. There is some evidence that these fractured rocks can be stabilized with 

products such as Gilsonite and SULFATROL ® . 

INHIBITIVE WATER BASED DRILLING FLUIDS 

There has been extensive research into inhibitive drilling fluids in an attempt to control 

wellbore instability by means of shale control. Shale control continues to dominate research due 

to the fact that shale instability remains one of the largest contributors to troublesome drilling 

and increased costs. 

“Today's definition of an inhibitive fluid is much broader than simply the inhibition of the 

swelling of highly expanding clays such as Montmorillonite. It means a fluid that exhibits 

minimal reactivity with the borehole and more specifically with the broad range of shales and 

other argillaceous formations.” This statement by B.G. Chesser of Baker Hughes Drilling 

Fluids typifies the type of thinking that has guided the evolution of inhibitive fluid systems over 

the years. 

The goal of inhibitive water based drilling fluid design is generally to prevent 

hydration/swelling of the clay minerals and to minimize pore pressure transmission. 

Shale Hydration 

All classes of clay minerals absorb water, but smectites take up much larger volumes than do 

other classes, because of their expanding lattice. For this reason, most of the studies on clay 

swelling have been made with smectites, particularly with montmorillonite. 

Two swelling mechanisms are recognized: crystalline and osmotic. Crystalline swelling (also 

called surface hydration), results from the adsorption of mono-molecular layers of water on the 

basal crystal surfaces – on both external, and, in the case of expanding lattice clays, the interlayer 

surfaces. The first layer of water is held on the surface by hydrogen bonding to the 

hexagonal network of oxygen atoms. Consequently, the water molecules are also in hexagonal 

coordination. The next layer is similarly coordinated and bonded to the first, and so on with 

succeeding layers. The strength of the bonds decreases with distance from the surface, but 

structured water is believed to persist to distances of 75 – 100 Å from an external surface. 

The structured nature of the water gives it quasi-crystalline properties. Thus, water within 10 Å 

of the surface has a specific volume about 3% less than that of free water. (Compared with the 

specific volume of ice, which is 8% greater than that of free water.) The structured water also 

has a viscosity greater than that of free water. 

The exchangeable cations influence the crystalline water in two ways. First, many of the 

cations are themselves hydrated, i.e., they have shells of water molecules (exceptions are NH 4 + , 

K + , and Na + ). Second, they bond to the crystal surface in competition with the water molecules, 



REVISION 2006 7-11


and thus tend to disrupt the water structure. Exceptions are Na + and Li + , which are lightly 

bonded and tend to diffuse away. 

When dry montmorillonite is exposed to water vapor, water condenses between the layers, and 

the lattice expands. The energy of adsorption of the first layer is extremely high, but it deceases 

rapidly with succeeding layers. 

Osmotic swelling occurs because the concentration of cations between the layers is greater than 

that in the bulk solution. Consequently, water is drawn between the layers, thereby increasing 

the c-spacing and permitting the development of diffuse double layers. Although no semipermeable 

membrane is involved, the mechanism is essentially osmotic, because it is governed 

by a difference in electrolyte concentration. Osmotic swelling causes much larger increases in 

bulk volume than does crystalline swelling. 

Shale Hydration Inhibition 

To minimize the effects of water on shale, two aspects of the hydration can be modified. One is 

to replace sodium and calcium ions on the exchange sites of the swelling clay, montmorillonite, 

with a cation (very often potassium) or with an amine such as those in CLAY-TROL and 

MAX-GUARD. The second approach is to encapsulate shale cuttings with PHPA (NEW- 

DRILL®) and thus hinder their physical degradation. This encapsulation makes it easier for 

the surface solids equipment to remove these solids from the drilling fluid. 

Various inhibitive systems are formulated with water soluble salts such as: sodium chloride, 

potassium chloride, potassium carbonate, calcium sulfate, calcium chloride and calcium 

hydroxide. The cations contained in these systems are adsorbed onto the clay surface through a 

cation exchange process. The adsorption of these cations onto the clay surface reduces the 

ability of the clay to hydrate and swell. The reduction in clay swelling is due to the amount or 

thickness of the water film associated with that particular cation. 

When clays containing low order replacement cations (monovalent cations) are exposed to 

water, the cations hydrate and dissociate from the clay surface forcing the clay platelets apart. 

The distance that the platelets separate is governed by the hydration radius of the cation. A 

higher replacement order cation having a smaller hydration radius and a greater affinity for the 

clay structure can now displace the low order cation reducing the separation between the 

platelets and reversing the swelling tendency. 

The most commonly occurring cations may be ranked according to their replacement power as 

follows, 

Li + , Na + , K + , Mg ++ , Ca ++ , Al +++ 

Increasing Order of Replacement 

Potassium chloride systems have been used with a great deal of success around the world while 

calcium-base systems (lime and gypsum fluids) have been used with varying degrees of 

success. 

The mechanisms by which PHPA polymers stabilize shale cuttings are adsorption, bridging, 

and flocculation. The long chain polymer can attach itself to shale particles through adsorption, 

sometimes referred to as encapsulation. This encapsulation process forms bridges between 

many shale particles and thus links these particles together preventing or greatly limiting 



REVISION 2006 7-12


dispersion. The encapsulation action of this polymer enhances the physical integrity of shale 

cuttings. It therefore gives more strength against mechanical degradation while the cutting is 

in transport out of the wellbore. 

The hydrated layer formed when the polymer adsorbs onto the shale particles is permeable, and 

other water molecules will eventually react with the shale particles causing shale hydration and 

swelling. This process could lead to disintegration, but due to the presence of the PHPA 

polymer, the shale particle remains intact. This suggests that the benefits gained from PHPA 

are indeed of a mechanical nature and the ability of this polymer to reduce swelling is a kinetic 

effect. 

Pore Pressure Transmission 

The most important factor in maintaining shale stability is preventing pressure increases in the 

shale matrix. Pore pressure increases, and differential pressure support decreases, when drilling 

fluid filtrate invades the shale. Wall support is lost with the reduction in differential pressure 

and the shale can then easily slough into the annulus. Shale (borehole) stability is achieved 

when pressure increases in the matrix are reduced and differential pressure support is 

maintained. The problem of pressure invasion is exacerbated by shales having low 

permeability, which slows the rate at which pressure can dissipate. This typically confines the 

added pressure in the shale to the vicinity of the near-wellbore surface. 

Pressure transmission in emulsion systems is managed by the generation of a semi-permeable 

membrane and the osmotic potential pressure difference between the shale and emulsion fluid. 

Sources of the semi-permeable (selective) membrane of OBM/SBM proposed in the literature 

include the oil film and emulsifiers/surfactants surrounding the emulsion. Calcium chloride in 

the internal phase reduces water-phase activity and creates an osmotic pressure differential at 

the borehole wall. Additionally, pressure invasion in emulsion systems is suppressed by the 

capillary entry pressure that must be overcome in order to force oil into the water-wet pore 

throat. 

Conventional water based drilling fluids are poor in drilling weak rocks like shales. These 

require an effective radial support stress, provided by drilling fluid overbalance, for stability. 

Overbalance, however, also drives the flow of drilling fluid filtrate and diffusion of drilling 

fluid pressure into the shale, causing a number of destabilizing effects. The most profound of 

these is near-wellbore pore pressure elevation which destroys effective drilling fluid pressure 

support. The in situ stresses may now overcome the strength of the shale, causing plastic 

deformation and failure. OBM and SBM are restricted from invading shales due to capillary 

threshold pressures. Improvement of WBMs involved reducing the filtrate flow J v into shales, 

which can be described by: 

Where: 

J v = k ( ∆P – σ ∆ Π ) / η 

k = shale permeability, 

η = filtrate viscosity, 

∆P = the hydraulic overbalance, 



REVISION 2006 7-13


σ = the membrane efficiency 

∆ Π =- the osmotic pressure defined by: 

∆ Π = 

RT ln 

V w 

⎡ a 

⎢ 

⎣a 

sh 

w 

df 

w 

⎥ 

⎦ 

⎤ 

where: 

T = temperature, 

R = the gas constant, 

V 

w 

= the partial molar volume of water, 

df 

a and = the shale and drilling fluid water activities respectively. 

sh 

w 

a w 

These equations show that there are four methods for reducing J v: 

1. Reducing the flow of drilling fluid filtrate by increasing the filtrate viscosity η ; 

2. Reducing the flow of drilling fluid filtrate by reducing the shale permeability k ; 

3. Balancing the flow of drilling fluid filtrate into the shale driven by overbalance ∆P by a 

backflow of pore water driven by the combined osmotic pressure σ ∆ Π ; 

4. Combining the above mechanisms. 

Pore Pressure Transmission Inhibition 

Emulsion drilling fluids are the ultimate membrane generating systems and provide superior 

drilling performance primarily because of their ability to reduce pressure transmission in shale. 

Preventing pressure invasion in shale using WBM is a formidable obstacle due to the technical 

difficulty of generating an efficient membrane while remaining cost-competitive with 

OBM/SBM. A significant technology gap in High Performance Water Based Drilling Fluid 

(HPWBM) occurs when the system cannot generate a membrane approaching that of 

OBM/SBM. PERFORMAX is designed to closely emulate the shale stabilizing 

mechanisms of an emulsion system by generating a selective membrane and creating an 

osmotic pressure difference between the drilling fluid and the shale. 

The mobility of solutes in shale determines membrane efficiency of drilling fluids. The shale 

essentially acts as a semi-permeable (selective) membrane because the clay-rich matrix hinders 

the movement of solutes. The shale matrix can be made more selective, thus further reducing 

the mobility of solutes, by decreasing shale permeability. 

Other water based drilling fluids also generate selective membranes using various products 

including cloud point glycols, silicates and ALPLEX®. In PERFORMAX a two-prong 

approach is used to generate the membrane. This is done by reducing shale permeability using 

both mechanical and chemical means. MAX-SHIELD, a deformable sealing polymer, 

having an extremely small particle size, is used to mechanically bridge micro-fractures on the 

exterior of the shale matrix. 



REVISION 2006 7-14


Figure 7 - 4 Mechanics of MAX-SHIELD 

The polymer is stable and 

maintains its particle size 

distribution even in the presence 

of high salt concentrations. The 

particle size of the polymer is such 

that the polymer bridges fractures 

on the shale surface. The 

deformable nature of the polymer 

allows it to mould itself along the 

fracture which improves bridging 

(plugging) efficiency. 

Aluminum chemistry (MAX- 

PLEX) is used to form an 

internal bridge via precipitation 

within the shale matrix. The aluminum complex is soluble at the drilling fluid pH, but 

precipitates as it enters the shale matrix due to a reduction in pH, reaction with multi-valent 

cations, or a combination of both. 

Silicate Based Drilling Fluids 

Drilling fluids based on soluble silicates for the control of “heaving shale” were first 

introduced in the 1930’s. These drilling fluids, based on high concentrations of soluble silicates 

(i.e. 20 – 50% v/v) were successful in drilling over 100 wells in the Gulf Coast area, but were 

difficult to control because of high rheological properties, which caused their use to be 

discontinued until they were re-introduced in the late 1960’s. At this time it was found that 

most shales could also be stabilized with more dilute solutions (less than 20% v/v, typically 5 – 

10% v/v) of sodium and potassium silicates, the latter systems being the more effective. 

Adding simple salts (e.g. KCl, K 2 CO 3 , NaCl) or non-ionic solutes (e.g. glycerol, ethylene 

glycol) contributed significantly to shale stability. This additional stabilizing effect was 

attributed to shale dehydration through an osmotic gradient generated by the solutes. Three 

wells were drilled with these fluids but they did not achieve acceptance. In the 1990’s silicates 

re-emerged. The following developments enabled re-introduction of these fluids: 

• Understanding of the causes of the problematic control of rheological properties of 

previous silicate drilling fluids. 

• The availability of compatible, high-performance polymer-based rheological property 

modifiers and filtration control agents. 

• Advances in solids removal equipment. 

• A better understanding of wellbore stability problems in general. It is now better 

appreciated that drilling success is not governed by drilling fluid chemistry alone, but 

also involves such critical factors as drilling fluid density, hole cleaning capacity, 

swab/surge etc. 



REVISION 2006 7-15


Liquid sodium or potassium silicates are solutions of water soluble glasses, which are primarily 

manufactured by fusing either soda ash (Na 2 CO 3 ) or potash (K 2 CO 3 ) with silica (SiO 2 ) sands at 

high temperatures (1000 - 1200°C): 

M 2 CO 3 + nSiO 2 → M 2 O . n(SiO 2 ) + CO 2 

Where M is either Na + or K + and n identifies the molecular ratio (i.e. the number of SiO 2 

molecules relative to one M 2 O molecule) and is typically in the range 1.5 – 3.3 for commercial; 

products. 

The pH of silicate solutions is a function of the molecular ratio, but is always high; pH 

decreases with increasing ratio, i.e. when the silicate becomes more siliceous and less alkaline. 

When pH is lowered artificially (e.g. by the addition of acid) in relatively high concentration 

silicate solutions, the anionic silicate oligomers will polymerize and gel. Gelation is most rapid 

at neutral pH. Gelation times are lowered by the presence of mono-valent salts. Most 

importantly, silicates react almost instantaneously with dissolved polyvalent cations such as 

Ca 2+ and Mg 2+ to form insoluble precipitates. 

Soluble silicate starts out as monosilicate which polymerizes rapidly to form negatively charged 

oligomers. At a pH of 11 – 12 (which is the pH of field drilling fluid formulations), 

polymerization halts because of mutual repulsion when relatively small oligomers have been 

formed. Such oligomers are still small enough to penetrate the tiny pores in the shale fabric 

(typically a few nanometers in diameter), transported by diffusion or hydraulic flow. Having 

entered the shale pore network, the following may happen: 

1. Pore fluid pH is close to neutral (pH ≈ 7) in virtually all shales. When the oligomers are 

diluted down to this neutral pH, they may overcome their mutual repulsion and coagulate, 

forming 3-D gel networks. 

2. In all shale pore fluids, there are free polyvalent ions present (e.g. Ca 2+ and Mg 2+ ), that 

will instantaneously react with the oligomers to form insoluble precipitates. 

The gelled / precipitated silicates now become a means of stabilizing shales, as they: 

a) Provide a physical barrier that prevents further drilling fluid filtrate invasion and 

pressure penetration. Thus, the wellbore and shale formation are effectively (pressure) 

isolated. Note that the gelation / precipitation process occurs very rapidly and is 

completed before significant fluid loss and pressure invasion has occurred. 

b) Enhance the efficiency of the shale-drilling fluid membrane. Silicates are well known for 

their membrane building potential. To prevent destabilizing osmotic water flow from the 

drilling fluid to the shale the water activity of the silicate-based drilling fluid should be 

at least balance the shale activity (i.e. a ≤ a ). 

df 

w 

The presence of solutes, in particular simple monovalent salts like NaCl and KCl, , is 

synergistic in various ways: 

• Monovalent cations like Na + and K + may exchange at the shale clay surfaces for Ca 2+ and 

Mg 2+ , which then become available for precipitating silicate. 

sh 

w 



REVISION 2006 7-16


• High salt concentration helps in the deposition of silicates as a gel by lowering 

characteristic gel times. 

df sh 

• Solutes can be used to balance the drilling fluid and shale activities (i.e. a 

w 

= a 

w 

) to 

prevent osmotic water flow from the drilling fluid to the shale. It may be desirable to 

lower the water activity of the drilling fluid even further (i.e. a ≤ a ) using an excess 

of solutes. The resulting dehydration and pore pressure decrease may benefit shale 

stability. 

Cloud Point Glycols 

The organics typically used in high-performance water-based drilling fluid systems are to 

reduce filtrate losses, provide suspension properties, improve lubrication and to stabilize watersensitive 

formations such as shales. In the 1990’s polyglycols were introduced for stabilization. 

Polyglycol chemistry, characteristics and benefits of their use in drilling are well documented. 

Most of the applications gave been with the use of a supplemental inorganic electrolyte, 

typically potassium chloride, to aid in performance. This has allowed the use of less expensive 

polyglycols in many cases. The use of chloride salts is undesirable in land-based drilling due to 

disposal problems and where the high conductivity from the electrolyte interferes with the 

sensitivity of induction logs during exploratory drilling. Use of an alternative electrolyte, such 

as potassium acetate or formate is feasible. 

Polyglycol Chemistry and Application 

Polyglycols, as used in the drilling industry, are oligomers of polypropylene glycol or 

polyethoxylated and propoxylated short chain alcohols such as butanol. The chameleonic or 

TAME (Thermally Activated Mud Emulsion) polyglycols are the most widely used. They are 

c 

h 

a 

r 

a 

c 

t 

e 

r 

i 

s 

e 

d 

Figure 7 - 5 Temperature Sequence of Glycol Cloud Point Formation 

characterized by their inverse solubility in water with temperature. These polyglycols are 

typically miscible with water at lower temperatures but, when heated, will eventually separate 

into two distinct liquid phases as the polyglycol becomes partially insoluble in the aqueous 

phase (See figure above). The temperature at which this occurs is defined as “Cloud Point” or 

“Cloud Point Temperature” (CPT) due to the scattering of the light by droplets of the 

polyglycol-rich phase which separate. This phenomenon is reversible as the separated phase redissolves 

once the temperature is lowered below the CPT. The exact CPT of a polyglycol 



REVISION 2006 7-17 

df 

w 

sh 

w


solution is a function of the specific polyglycol used, its concentration and the presence of 

other dissolved materials, especially electrolytes. 

The CPT for a given polyglycol and aqueous phase forms a locus of CPT’s with concentration, 

or CPT curve, as shown in the figure below. Below the curve the polyglycol forms a single 

solution in water, but if the temperature of the solution is increased above the curve the 

solution will separate into two disticnt phases. The composition of the two phases is defined 

strictly by the temperature of the system and is given by the temperature of an isotherm (any 

horizontal line in the figure below) with the curve at the two points. 

250 

Cloud Point Temperature, F 

Temperature, Degrees F 

200 

165- 

150 

135- 

100 

50 

5% Glycol at 165F 

2% in solution 3% out of solution 

5% in solution 0% out of solution 

5% Glycol at < 135F 

0 

2% 5% 

0 1 3 4 6 7 8 

Glycol content, Weight weight % 

Polyglycol 

, volume % 

Figure 7 - 6 Phase Conditions of Cloud Point Formation 

Baker Hughes Drilling Fluids’ proprietary software GLY-CAD will perform CPT calculations 

and is the recommended tool for designing CPT glycol fluids. 

The significance of the CPT is somewhat controversial, as the exact mechanism by which 

polyglycols stabilize clays and shales is debated. Polyglycols form complexes with clays. This 

fails to account for the wide variability in efficiency seen in various polyglycols. Most of the 

laboratory studies showing efficient and effective shale stabilization as well as the successful 

field applications have used polyglycol solutions at or near their CPT. This clearly suggests 

that the CPT is important, but the exact mechanism is elusive. Laboratory studies eventually 

provided insight into the importance of CPT and provided a mechanism by which chameleonic 

or TAME polyglycols provide highly efficient shale stabilization. 



REVISION 2006 7-18


Polyglycol Shale Stabilization Mechanism 

Below the CPT, the soluble polyglycols viscosify the drilling fluid filtrate. This filtrate will 

invade the shale, but the rate of invasion is retarded by the viscosity enhancement. When the 

temperature is above the CPT, the polyglycol solution becomes thermodynamically unstable, 

triggering phase separation of the polyglycols to form a concentrated emulsion. In this macromolecular 

state, the polymers can no longer enter the shale and are also very ineffective at 

closing off the shale pore throats. Therefore, they do not have an effect on reducing fluid 

invasion of shales. Note, however, that not all of polyglycol will cloud out at the CPT. In fact, 

just above the CPT the majority of the polyglycol product remains in solution and determines 

the viscosity of the continuous phase. The dissolved fraction of polymers will enter the shale 

pore system unrestricted, and again the rate of pressure transmission is retarded by a factor 

equal to the filtrate viscosity enhancement. The soluble polyglycol fraction will only cloud-out 

if temperature is raised far beyond the CPT. As an example, for a certain 5% polyglycol 

solution with a CPT of 60°C, 100% phase separation will not occur unless temperature is raised 

above 90°C. 

The discussions above emphasize the role of viscosity, and may be an explanation why good 

results have been obtained in the field with clouding polyglycols used far below or above the 

cloud point, and polyglycols that have no CPT. It should be noted, however, that relatively 

high concentrations (>10% v/v) of polyglycols are necessary to obtain the desired viscosity 

effects. 

Under realistic downhole circulating conditions, a drilling fluid at bottom-hole circulating 

temperature (BHCT) contacts a shale at a higher bottom-hole static temperature (BHST), i.e. a 

drilling fluid/shale temperature gradient exists. Thus when a drilling fluid invades a shale, it 

heats up, thereby changing temperature dependent fluid properties. 

300 

2 - 3% Sea Salt 

20% NaCl Solution 

200 

20% NaCl + PHPA 

Pressure (psi) 

150 

100 

20% NaCl + PHPA + 3.5% v/v Aquacol D 

50 

0 

80/20 Synthetic / 20% CaCl2 

0 5 10 15 20 25 30 35 40 

Hours 

Figure 7 - 7 Typical PPT Data For Various Fluids 



REVISION 2006 7-19


The above figure shows pore pressure transmission results from various fluids. The 20% NaCl 

+ PHPA + 3.5% v/v AQUA-COL D is a cloud point glycol fluid designed to cloud out in 

the simulated drilling fluid/shale temperature gradient. A lower pore pressure build-up was 

obtained with the polyglycol fluid than with the other water based fluids. The difference is too 

great to be attributed to viscosity effects. It is believed that the following mechanism explains 

this difference. A polyglycol solution is designed with a CPT that coincides with the BHCT, 

i.e. at the bit the polymers are just starting to cloud out. This solution invades the shale under 

the influence of hydraulic and diffusion gradients, and will experience temperature elevation 

due to the higher Bottom Hole Static Temperature (BHST). Temperature induced phase 

separation now occurs and emulsions are formed in situ, filling the shale pores. Possible, phase 

separation forces the polymers onto the shale surfaces, coating them and changing their 

wettability. The fraction of polymers deposited in situ now becomes a barrier that restricts 

further fluid invasion and drilling fluid pressure penetration. Thus, the wellbore and shale pore 

system are isolated and the shale is effectively stabilized. 

Design Criteria for Polyglycol Drilling Fluids 

1. The polyglycol molecules should be small enough to invade the shale pore network to 

form an emulsion in situ. Typically, the molecular weight of the additives should be in 

the range 500 – 2000 a.w.u. High molecular weight (>100,000) polyglycols are 

restricted from entering shales due to their size, and will therefore not be effective in 

closing off the shale pores. 

2. The polyglycols should display cloud point behavior. 

3. The CPT of the polyglycol solution should be tailored to coincide with the BHCT, in 

order to fully exploit the temperature gradient between the wellbore and the formation 

(BHST). The CPT may be changed in several ways: 

• As polyglycols with different chemical composition will have different CPTs, the 

right polyglycol may be chosen for the set of circumstances; 

• The CPT can be influenced by changing salt content of the drilling fluid; 

It is noted that matching the CPT to BHCT may be difficult when a long shale section 

is drilled with continuously increasing BHCTs. There are two ways to tackle this 

problem: 

• The drilling fluid contains a blend of polyglycols with different cloud points, such 

that glycols will cloud out at every BHST encountered; 

• The salt content of the drilling fluid is depleted while drilling the section : lowering 

the salinity will raise the CPT of the polyglycols. 

Note: All of the above are most easily adjusted by use of GLY-CAD. 



REVISION 2006 7-20


LOSS OF CIRCULATION 

Reference is made in this section to: Prevention and Control of Lost Circulation: Best 

Practices, Reference Manual 750-500-104, by Atlantic Richfield & Baker Hughes Drilling 

Fluids, February 1999. 

Loss of circulation is the loss of whole drilling fluid to exposed formations. This will occur where 

there is a permeable zone with openings of sufficient size to permit entrance of whole fluid, 

and/or the hydrostatic pressure is greater than the formation fracture pressure. 

Improved drilling fluid technology, a greater understanding of hydraulics, and drilling practices 

have greatly reduced the incidence of loss of circulation in most areas. However, in spite of 

continued research to improve technology, loss of circulation problems still adversely affect 

many drilling operations. Resulting treatments, extra casing strings, increased drilling time, and 

drastically altered drilling programs greatly increase the overall drilling cost on these wells. 

In general, the two classes of loss of circulation are, 

• those inherent to the formation or natural loss of circulation 

• those of a mechanical nature caused by poor drilling techniques 

There are four types of loss of circulation zones in these classes. 

1. Zones of normal strength which have been fractured by the use of high-density or highviscosity 

drilling fluids or by pipe handling pressure surges 

2. Zones that are naturally fractured or containing joints and fissures 

3. Zones that are coarsely permeable, such as gravels and some conglomerates 

4. Zones that are cavernous, such as limestones and dolomites, with vugular or “honeycomb” 

porosity large enough to take whole drilling fluid 

Loss of circulation into all of these zones can be precipitated by improper control of drilling fluid 

density, flow properties, or pressure fluctuations. Field studies have shown that excessive drilling 

fluid pressure fluctuations are often the main cause of loss of circulation. Factors that influence 

the magnitude of pressure fluctuations include fluid rheological properties, speed of pipe 

movement (surge pressure), relative diameter of the components (drillstring to borehole 

diameter), and volumetric flow rate. 

Pressure surges cannot be blamed for all loss of circulation, although this is a key variable. For 

example, drilling fluid may be lost to fractures or cavernous formations that cannot support a 

normal hydrostatic head. Conversely, in some areas high hydrostatic pressures that are necessary 

to control high formation fluid pressures cause loss of circulation in adjacent formations. 

Preventive measures must be tailored to the area and the nature of the loss. 



REVISION 2006 7-21


Preventive Measures 

Prevention of lost circulation is very important due to the difficulties in curing the problem once 

it occurs. Measures to combat loss of circulation should include the following: 

• Use minimum drilling fluid densities consistent with formation pressures and borehole stability 

requirements. 

• Evaluate area well data and drilling parameters to aid in proper placement of casing strings. In 

many areas, it is possible to estimate formation pressures with shale density, drilling rates (“d” 

exponent), and log data. If pore pressure is known, it is generally possible to predict the 

fracture gradient accurately. 

• Loss of circulation problems to known porous or finely fractured zones may be pre-treated 

with a fine bridging material such as MIL-PLUG ® , MILMICA ® , LC-LUBE, MIL- 

CARB, and/or CHEK-LOSS ® . However, fine shaker screens will remove a large 

percentage of these additives from the fluid system. Occasionally, shaker screens are bypassed 

in order to keep these products in the system without having to continuously replace what the 

shaker screens are discarding. This practice is detrimental to solids control but, at times, can be 

justifiable. To prevent the build-up of solids in the fluid system, lost circulation pills are 

spotted in the area of loss in an attempt to cure the problem. When circulated out of the hole, 

the lost circulation material is removed from the system at the shale shakers. It should be 

recognized that the addition of these and other LCM may contribute to increased 

drilling fluid rheological properties, thereby increasing pressure loss and the aggravation 

of lost circulation. The application of LCM under these conditions should be carefully 

considered. 

• Surge pressures, circulating pressure losses, and pressures occurring while breaking circulation 

after trips could contribute to loss of circulation. The surge pressures should be calculated 

using ADVANTAGE SM engineering software on critical operations to determine safe piperunning 

speeds and to predict effects of fluid rheological properties. Annular friction losses 

while circulating may require alteration of flow properties and circulating rate to prevent 

losses. 

On deep, hot holes, gelation of drilling fluid may cause loss of returns during attempts to break 

circulation. Tests with the Fann Consistometer, Fann Model 70/75 Viscometer, high temperature 

high pressure aging cells and shearometers can be utilized to predict the degree of gelation and 

assist in determining proper corrective treatment. When breaking circulation, upward movement 

and rotation of drillstring will reduce pressures. Standpipe chokes (hand adjustable choke 

installed on standpipe with bypass line discharging into mud pit) if installed, would be useful to 

aid in breaking circulation with a slow, gradual increase in standpipe pressure. Procedures for 

predicting surge/swab pressures are outlined in the section dealing with basic hydraulics 

equations. 

Annular restrictions due to balled bits, collars, and stabilizers are not uncommon while drilling 

gumbo shales. Reduction in annular size, regardless of the cause, can impose additional pressure 

against the formation which may result in loss of circulation. Preventive measures to be 

considered are; 



REVISION 2006 7-22


• Use of fluid additives such as MIL-LUBE ® , BIO-DRILL ® , PENETREX ® , or the 

environmentally friendly TEQ-LUBE ® or LUBE 622 minimizes the build-up of clay solids on 

the drillstring and bit. 

• Controlled penetration rates may be necessary in troublesome zones. 

• Improved hydraulics may alleviate bit balling in some cases. 

• Inhibitive fluids such as CARBO-DRILL ® , SYN-TEQ ® , ALPLEX ® , PERFORMAX 

and potassium-base and/or calcium-base drilling fluids (lime and gypsum fluids) may provide 

sufficient protection against swelling and sticky shale. Plastic deformation (flow of shales into 

wellbore) may be controlled or minimized with these systems. In most cases, however, it is 

necessary to increase drilling fluid density to restrain plastic flow of shales. 

• Wellbore deviation also must be considered as a factor in wellbore constriction. In deviated 

wellbores of 30 degrees and higher the cuttings bed forms on the low side of the annulus and 

with improper hole cleaning the cuttings bed will build, reducing the annular opening. These 

beds travel up the wellbore in dune-type movements. That is, as the bed reaches a given height 

of deposition it will be washed higher up the wellbore to be deposited until a deposition height 

reaches a sufficient height to be washed again. This movement of the cuttings bed causes 

pressure fluctuations within the annulus, due to varying wellbore diameter restrictions. These 

cuttings beds are unstable and tend to “avalanche” (slide back down the hole). These 

avalanches can, in the worst case, cause packing-off of the annulus. It is recommended to run 

hole cleaning simulations in ADVANTAGE in order to identify, and if possible remedy, the 

formation of cuttings beds. 

Another possible cause of annular restriction is wall cake build-up. This problem is normally 

associated with low annular velocities, high filtrate values, and permeable formations. It can 

generally be alleviated by reducing the API Filtrate (thinner wall cake) and/or the differential 

between fluid hydrostatic and formation pressures. 

Seepage Loss 

Seepage loss (


20 feet per minute with a 17½ inch bit and a flow rate of 500 gal/min could result in a fluid 

density increase from 10.0 to 13.6 lb m /gal in the annulus. While this may be an extreme example 

of a fluid density increase when drilling large diameter holes at a high penetration rate, it 

effectively describes the situation. Remedial procedures for this problem would be (1) decrease 

penetration rate, (2) increase pump rate, or (3) circulate several minutes after drilling each drill 

pipe joint down. Real time annular pressure sensors have proven extremely useful in monitoring 

these conditions. 

Partial Loss 

Partial loss (25–100 bbl/hr WBM or, 10–30 bbl/hr OBM) is generally associated with coarsely 

permeable zones (gravel beds or vugular limestones), faulty cement jobs, and induced or existing 

fracturing. As noted earlier, a defective cement job is normally solved by cement squeezes. Loose 

to coarsely permeable and finely fractured zones may be cured by adding materials such as 

medium MILPLUG ® , MIL-SEAL TM , MIL-CEDAR FIBER TM , Kwik-Seal, MIL-FIBER ® , 

MILFLAKE ® and SOLUFLAKE TM (acid soluble). If loss is severe, mix a concentration of lost 

circulation material (30 to 40 lb m /bbl of MIL-SEAL, for example) into a portion of the system 

and spot opposite the loss zone. After spotting this material, pull into the casing and wait six to 

eight hours. 

Another technique which has been successful with partial fluid loss is squeezing the loss zone 

with high filter loss slurries such as SOLU-SQUEEZE or Diaseal M. The addition of 10 to 20 

lb m /bbl of MIL-SEAL to this slurry will generally improve the chances of success. Mixing 

procedures for Diaseal M are given in Table 7-1. When applying a high fluid loss slurry, squeeze 

slowly (½ to 1½ bbl/min) with low squeeze pressures (50 to 100 psi). Normally, final squeeze 

pressures should not exceed 0.1 psi per foot of depth. Obviously, for low squeeze pressures, it is 

desirable to have an accurate, low-pressure gauge for reading annular pressures. 

 

Density 

Diaseal M 

MIL-BAR ® Water 

(lbm/gal) (lb) (sacks) (sacks) 

(bbl) 

9 50 1.00 0.0 0.87 

10 50 1.00 0.6 0.84 

11 47 0.94 1.2 0.80 

12 42 0.84 1.8 0.77 

13 38 0.76 2.3 0.74 

14 34 0.68 2.9 0.70 

15 31 0.62 3.5 0.67 

16 28 0.56 4.0 0.63 

17 25 0.50 4.6 0.60 

18 22 0.44 5.2 0.56 

Example: 100 bbl of 14 lb m /gal Diaseal M slurry required 68 sacks Diaseal M, 

290 sacks MIL-BAR, 70 bbl water, and MIL-PLUG if desired 

Table 7 - 1 Formula for Preparing One Barrel Diaseal M Weighted Slurry with Fresh Water, 

Bay Water, or Sea Water 



REVISION 2006 7-24


If water-absorbing materials such as MIL-SEAL are employed, it is advisable to add a reduced 

quantity of Diaseal M and observe the effect of lost circulation material on viscosity prior to 

adding the remainder. 



REVISION 2006 7-25


1 Density, 

lbm/gal 

FW, 

bbl 

Water or Oil SOLU-SQUEEZ MIL-BAR ® 

SSW, 

bbl 

Oil, 

bbl 

FW, 

lbs 

SSW, 

lbs 

Oil, 

lbs 

FW, 

lbs 

SSW, 

lbs 

10.0 0.90 - 0.876 85.2 - 85.2 60 - 115 

12.0 0.83 0.88 0.805 71.6 83 71.6 180 90 230 

14.0 0.76 0.81 0.735 58.6 71 58.6 290 220 342 

16.0 0.69 0.74 0.666 47.8 59 47.8 400 340 454 

18.0 0.62 0.66 0.596 36.8 46 36.8 520 460 564 

Table 7 - 2 Formula For Preparing One Barrel SOLU-SQUEEZE Weighted Slurry with 

Fresh Water, Saturated Salt Water (SSW), or Oil 

Note 1: Depending on rig mixing equipment minor modifications to the formulation may be required. At mud weights below 12 

lbm/gal, viscosity can be increased with small amounts of XAN-PLEX D. At higher mud weights, viscosity can be reduced with water 

dilution if necessary. Pilot test for optimum results. 

Note 2: At mud weights above 14 lbm/gal, depending upon rig mixing equipment, small amounts of OMNI-COTE may needed to help 

oil wet the SOLU-SQUEEZ pill. Always pilot test as over - treatment with OMNI-COTE can cause barite settling. At low mud 

weights, small additions of CARBO-GEL can be added if viscosity is too low. 

Severe (or Total) Loss of Returns 

Severe or Total drilling fluid loss (>100 bbl/hr WBM or, >30 bbl/hr OBM) may occur as a 

result of a faulty cement job around the casing shoe, induced or natural fractures, or coarsely 

permeable zones such as gravel or reef structures. Total loss may be cured with cement (neat or 

bentonite cement for 14.5 to 15.5 lb m /gal slurries and gilsonite cement for slurries with densities 

below 14.5 lb m /gal). 

Four basic squeeze slurries designed for the most severe or total loss of returns are: (1) Diesel Oil 

Bentonite Cement, (2) Water Organophilic Clay Plug, (3) MAGNE-SET ® , and (3) X-LINK. 

Details of each squeeze follows: 

Loss to faulty cement jobs can best be remedied by squeeze cementing. However, in some cases 

(such as inability to pull out of hole for squeeze tool due to kicking formation), it may be 

necessary to utilize a squeeze slurry. Loss to induced fractures (hydrostatic head of fluid column 

exceeds fracture gradient) may best be remedied by the use of soft plugs, diesel oil-bentonitecement 

squeezes, or diesel oil-bentonite squeezes. Diesel oil-bentonite-cement squeezes are 

prepared by adding 2 sacks of cement and 2 sacks of MILGEL ® for each barrel of diesel. Final 

volume of this mixture is 1.39 bbl. When this slurry is spotted and enters the thief zone, it comes 

in contact with the water-base fluid which causes the bentonite to hydrate forming a plastic plug. 

DIESEL OIL BENTONITE CEMENT SQUEEZE 

Procedure for mixing and spotting diesel-bentonite squeeze slurry is as follows. 

2 Oil, 

lbs 

1. Pull out of hole and locate loss zone with temperature or radioactive survey. Run in hole openended 

to top of loss zone. 



REVISION 2006 7-26


2. Mix slurry volume equivalent to or greater than open-hole volume below point of loss. For 100 bbl 

of slurry, add 154 sacks of MILGEL, 154 sacks of cement, and 72 bbl of diesel. 

3. Pump 5 bbl of diesel in front of slurry to serve as a buffer between drilling fluid and squeeze slurry. 

Start pumping slurry and continue until slurry reaches bit (follow slurry with another 5 bbl diesel 

spacer). After slurry reaches the bit, close preventers and begin pumping drilling fluid into annulus at 

rate of 2 bbl/min while displacing slurry, from drillpipe, at a rate of 4 bbl/min. After pumping ½ of 

slurry, reduce pump to ½ speed (1 bbl/min annulus and 2 bbl/min on drillpipe). After pumping ¾ of 

slurry, attempt “hesitation” squeeze pressure of approximately 100 to 500 psi. Under-displace slurry 

so that approximately 1 bbl remains in drillpipe. 

4. Pull out of hole and wait eight to ten hours to allow slurry to set. 

Diesel oil-bentonite squeezes (400 lb of MILGEL per bbl of diesel) are run in a similar manner, 

but will have a lower set strength than diesel oil-bentonite-cement squeezes. 

WATER ORGANOPHILIC CLAY PLUG 

In oil based drilling fluids, the reverse of an oil bentonite plug is used, the water organophylic 

clay plug (reverse gunk squeeze). In oil based drilling fluids, a clay which has been chemically 

treated to render it oil dispersible is used to provide viscosity. This Organophylic clay will not 

yield in water but will yield in oil in the presence of water. Thus, if a high concentration of 

Organophilic clay dispersed in water is pumped to the loss zone, on contact with oil based drilling 

fluid, it will form a strong solid material. 

1. The gel used in the reverse gunk-squeeze will yield with OBM, and should therefore not 

come into contact with OBM until the gunk exits the drill string. Preventing OBM from 

entering the batch tank and associated lines is imperative. 

2. For the reverse gunk squeeze to work properly, the bit must be located just above the loss 

zone so that the gunk will yield in the loss zone. 

3. Pumping OBM down the annulus, simultaneously with pumping down the drill string, 

will ensure that the gunk mixes with the OBM, and prevents the gunk from being 

squeezed into a zone above the bit, which could stick the drill string. 

4. Performing an open hole squeeze with the drill string across permeable zones can result 

in differential sticking of the drill string. Therefore, it is important to keep the squeeze 

pressure on the annulus low, and minimize the time the drill string is stationary. Do not 

reciprocate the drill string while the annular preventer is closed, as the gunk may mix 

across the BHA and stick the pipe. 

5. This type of pill cannot be reversed out of the pipe. 


1. Ensure that the cementing unit and cementing batch tank are clean. 

2. Mix reverse gunk pill in the cementing batch tank: 



REVISION 2006 7-27


Formulation (typical) for 1 bbl mix: 

Water 0.55 bbl 

Defoamer 

0.15 gallons 

Soda Ash 

1.22 lbs 

Bentone 128 210 lbs 

Placement of the Plug 

• Run in hole with open ended drillpipe and place the bottom of the drillpipe +/- 1 joint 

above the thief zone. Pump the gunk pill down the open ended drill pipe, with 5 bbl water 

spacer ahead and behind as spacer. If well-bore pressure or conditions prevent the drill 

string being pulled out of the hole, those involved should evaluate the possibility of 

displacing this mix through the drill string and bit. 

• Displace with drilling fluid until the water ahead reaches the bottom of the drillpipe. 

• Close the annular preventer. 

• Squeeze gunk with the two cement unit pumps; 

• Pump No.1: Pump down DP at 2 BPM 

• Pump No.2: Pump down annulus at 0,5 BPM 

• Squeeze down total gunk pill volume (until all water is cleared from the drill pipe). 

• Pull drill pipe well above gunk. 

• Hold the squeeze pressure for 30 to 60 minutes. 

• Carefully place weight on the gunk pill to test the pill firmness. A maximum period of 3 

hours should be given for the gunk to set up. 

MAGNE-SET ® SQUEEZE SYSTEM 

Description 

MAGNE-SET, used as an alternative to cement plugs, offers these advantages in addition to 

quick-mixing. MAGNE-SET can be mixed in the mud pits or slug tank. 

• This material may be spotted with the drill bit in place. 

• MAGNE-SET has very little effect on the fluid system. 

• MAGNE-SET contains no diesel and does not affect the toxicity of the fluid system 

as diesel would. 

Table 7-3 and Table 7-4 give slurry formulations. 



REVISION 2006 7-28


Slurry 

Volume 

(bbl) 

10 

20 

25 

30 

35 

40 

45 

50 

Water 

Volume 

(bbl) 

6 

12 

15 

18 

21 

24 

27 

30 

MAGNE- 

SET 

(sacks) 

64 

128 

160 

192 

224 

256 

288 

320 

Table 7 - 3 MAGNE-SET Slurry Formulations 

Bottomhole 

Temperature 

( °F ) 

Pounds per Barrel 

MAGNE- 

SET 

Accelerator Retarder Thinner 

90 - 110 

110 - 130 

130 - 150 

150 - 170 

170 - 190 

190 - 210 

106 

123 

139 

160 

160 

160 

54 

37 

21 

⎯ 

⎯ 

⎯ 

4 

5 

1 

⎯ 

6 

11 

Table 7 - 4 MAGNE-SET Additive Concentrations - Sacks per 25 bbl 

Recommended Treatment (MAGNE-SET ® ) 

For most lost circulation problems, a slurry of 25 or 50 bbl of MAGNE-SET is sufficient. A 

small extra quantity should be mixed to allow for any residual slurry that cannot be pumped from 

the tank or pit. 


1. Add water to a clean pit or tank. 

2. Dissolve the proper amount of MAGNE-SET retarder in the water. 

3. Dissolve the proper amount of MAGNE-SET ® thinner in the water/MAGNE-SET retarder 

solution. 

4. Add MAGNE-SET powder to the solution until weight is 14.0 lb m /gal. If foaming occurs, add 

W.O. TM DEFOAM. 

⎯ 

⎯ 

⎯ 

⎯ 

⎯ 

3 



REVISION 2006 7-29


5. Mix for approximately five minutes after addition of last sack. Mix until the material forms a 

smooth blend. 

6. When MAGNE-SET accelerator is used, it should be added last to the slurry, mixed just enough for 

proper dispersion, and pumped downhole in a non-stop operation. 

Note: The weight of the blended slurry should be 14.0 lb m /gal to assure optimum 

performance. The weight is reduced by adding water and increased by adding MAGNE-SET. 

Typical Pumping Procedure 

1. If possible, locate the lost circulation zone. 

2. Pull drillstring above the lost circulation zone. 

3. Pump the MAGNE-SET slurry into the drillpipe. 

Note: 

Clean the empty tank or pit with water, or flush with fluid from the active system. 

4. Using fluid from the drilling fluid system, pump the MAGNE-SET slurry down to the lost 

circulation zone. Pump slurry at maximum rate. 

5. If required by hole conditions, the MAGNE-SET slurry can be squeezed into the formation using 

standard squeeze procedures. 

6. P 

ull up above the top of the MAGNE-SET slurry. 

7. A 

llow MAGNE-SET to cure for eight hours, keeping the annulus full if possible. 

X-LINK ® SYSTEM 

Baker Hughes Drilling Fluid’s X-LINK system combines advanced, cross-linking polymers 

with bridging agents to provide quick, reliable control of fluid loss. In addition, X-LINK offers a 

proven means of controlling the more severe circulation losses resulting from large fractures or 

vugular spaces. 

X-LINK pills are temperature-activated and setting time is controlled through the addition of 

accelerator (X-LINK ® ACR) or retarder (X-LINK ® RTR) during mixing, thereby eliminating 

the risk of premature setting at the surface or while pumping through the bottom hole assembly. 


The mixing of an X-LINK pill does not require any specialized equipment and can be 

accomplished at the rig site. A 40 lb. bag of X-LINK makes one barrel of pill. Set-up time is 

controlled by the well’s bottom hole temperature (BHT). It is vital that the well’s temperature 

profile be known prior to the X-LINK application. A supplemental retarder is required for use in 

wells possessing bottom hole temperatures greater than 150º F (65° C). In addition, an 



REVISION 2006 7-30


accelerator is available for cold water applications. X-LINK pills can be used in water, syntheticor 

oil-base drilling fluids. 

In the event an X-LINK pill is mixed but not pumped, it can be bled back into the active mud 

system. If no accelerator is used, there is no danger from gelation in the tank provided retarder 

was used in the formula. If an accelerator was used, the pill can be diluted with water to a 1% 

solution to eliminate cross-linking. 

Once the X-LINK pill sets, it is easily drilled or reamed and can be removed from the mud 

system over conventional shale shakers. 

Temperature, 

ºF 

X-LINK, 

lbs/bbl 

Accelerator, 

lbs/bbl 

Retarder, 

lbs/bbl 

Retarder, 

gal/bbl 

Pumpable 

Time, min 

Set Time, 

min 

60 40 0.3 27 90 

120 40 0.078 80 150 

150 40 5.85 0.53 90 180 

200 40 10.4 0.95 90 180 

250 40 15.6 1.42 90 180 

300 40 17.6 1.60 90 180 

Table 7 - 5 Formulation for One (1) Barrel of Un-weighted X-LINK as Function of 

Temperature 



REVISION 2006 7-31


Temp 200º F 250º F 300º F 

Density, lb//gal 

H2O, bbl 

X-LINK, sks 

RTR, gal 

MIL-BAR, sks 

H2O, bbl 

X-LINK, sks 

RTR, gal 

MIL-BAR, sks 

H2O, bbl 

X-LINK, sks 

RTR, gal 

MIL-BAR, sks 

12 87 87 86 192 87 87 117 191 87 87 138 190 

13 83 83 82 247 83 83 112 246 83 83 132 245 

14 80 80 78 303 80 80 107 302 80 80 126 301 

15 76 76 75 359 76 76 102 359 76 76 120 357 

16 72 72 71 414 72 72 97 413 72 72 114 413 

17 68 68 67 470 68 68 92 469 68 68 108 468 

Table 7 - 6 Formulations to Build 100 Barrels of Weighted X-LINK Plug 

Other Types of Remedial Techniques 

Extremely severe drilling fluid losses, such as those encountered while drilling cavernous zones 

and depleted reservoirs may require specialized techniques, such as drilling with air, drilling with 

stiff foam, drilling with aerated fluid (using either an injection string run on outside of the casing 

string or using concentric drillpipe), drilling with a mud-cap, or drilling blind until the loss zone 

is cased off. With the exception of drilling blind, the methods noted above require special 

equipment and preparation and should be planned before drilling operations begin. 

It should be noted that severe corrosion problems may be encountered with aerated fluids if 

preventive measures are not taken. 

Lost Circulation Prevention by “Stress Cage” Technique 

Induced losses occur when the drilling fluid density, required for well control and to maintain a 

stable wellbore, exceeds the fracture resistance of the formations. A particular challenge is the 

case of depleted reservoirs. There is a drop in pore pressure as the reserves decline, which 

weakens hydrocarbon-bearing rocks, but neighboring or inter-bedded low permeability rocks 

(shales) may maintain their pore pressure. This can make the drilling of certain depleted zones 

virtually impossible – the drilling fluid density required to support the shale exceeds the fracture 

resistance of the sands and silts. The potential prize is clear if a way can be devised to strengthen 

the weak zones and thereby access these difficult reserves. In fact, the value of wellbore 

strengthening is much more wide-ranging and includes the following applications/benefits: 

• Access to additional reserves (depleted zones) 

• Reduced drilling fluid losses in deepwater drilling 

• Loss avoidance when running casing or cementing 



REVISION 2006 7-32


• Elimination of casing strings 

• An alternative option to expandable casing 

Various studies have investigated wellbore strengthening with a view to preventing drilling fluid 

losses. One method suggests using temperature changes to alter the stress state around the 

wellbore. Drilling fluid heaters can be used to heat the circulating fluid and increase the nearwellbore 

stresses, thereby giving a strengthening effect. However, this method might be difficult 

to control and would not be suitable in wells with an already high bottom hole temperature. In an 

alternative approach a method was developed to allow small fractures to form in the wellbore 

wall, and to hold them open using bridging particles near the fracture opening. The bridge must 

have a low permeability that can provide pressure isolation. Provided the induced fracture is 

bridged at or close to the wellbore wall this method creates an increased hoop stress around the 

wellbore, which is referred to as a “stress cage” effect. The aim is to be able to achieve this while 

drilling by adding appropriate materials to the drilling fluid. Short fractures are best and so it is 

necessary to arrest the fracture growth very quickly as the fracture starts to form. This means high 

concentrations of bridging additives will be preferable. The additives need to be physically strong 

enough to resist the closure stresses, and sized to bridge near the fracture mouth to produce a near 

wellbore stress cage. Assuming an opening width of 1 mm, the particle size distribution of the 

fluid would need to range from the colloidal clays up to values approaching 1 mm, to give a 

smooth particle size distribution and produce a low permeability bridge. 

In permeable rocks the particle bridge need not be perfect because fluid that passes through the 

bridge will leak away from within the fracture into the rock matrix. Thus, there will be no 

pressure build-up in the fracture and the fracture cannot propagate. Achieving a stress cage effect 

in permeable rocks is straightforward. If the drilling fluid contains particles that are too small to 

bridge near the fracture mouth, the fracture could still become sealed by the build-up of a filter 

cake inside. Fracture gradients observed in sands are usually higher than predicted by theoretic 

models, probably due to the presence of solids in the drilling fluid and the deposition of filter 

cake. 

In low permeability rocks such as shale the bridge will need to have an extremely low 

permeability to prevent pressure transfer into the fracture and fracture propagation. “Ultra-low 

fluid loss muds” with HPHT filtrates as low as 0.1 ml are thought be beneficial to wellbore 

strengthening. The driving force for bridge formation across a shale fracture needs to be 

considered carefully. The initial rush of fluid into the fracture when it forms will deposit the 

bridging solids at the fracture mouth, but a pressure difference across the bridge is required to 

hold it in place. Pressure decay into the shale matrix behind the bridge will be minimal especially 

with oil-based drilling fluids, which have an added sealing action due to interfacial tension 

(capillary pressure) effects. In water-based drilling fluids, there may be a slow pressure leak-off 

into the shale, but the challenge would then be to produce water based drilling fluid with an ultralow 

filtrate so that the bridge at the fracture mouth has a sufficiently low permeability. 

• Laboratory studies and field experience have shown calcium carbonate and graphitic 

blends (LC-LUBE) as one of the best ways to reduce mud losses into fractures. 

• The fluid should contain a smooth/continuous range of particle sizes ranging from clay 

size (around 1 micron) to the required bridging width. 

• Ideal packing theory (the d ½ rule) is useful for selecting the optimum size distribution in 

low density drilling fluids. 



REVISION 2006 7-33


• High particle concentrations are best and at least 30 ppb of bridging mix is required for 

an efficient seal. 

• In the laboratory fracture sealing has been successful up to 300°F and 4000 psi 

overbalance pressure in some tests. 

• Drilling fluid density is not a critical factor in forming a successful bridge. 

• The bridging material can be used in pills if the section can first be drilled with a drilling 

fluid density below the fracture gradient, and then subsequently strengthened by 

squeezing a pill across the weak zone. 

On the Brent field in the UK North Sea, in the depleted reservoir zone, experience has shown that 

the use of LC-LUBE can add approximately 900 - 1250 psi to the fracture propagation pressure. 

Recommended LC-LUBE concentration in the active system is 6 – 20 ppb, though on Brent 20 

ppb was used. 

DRILLSTRING STICKING 

The primary causes of stuck drillpipe include: 

• differential-pressure sticking 

• key seating 

• junk in hole and/or collapsed casing 

• wellbore instability (sloughing shale or plastic deformation of shale or salt) 

• inadequate hole cleaning due to rheological properties, hydraulics, or hole 

enlargement. 

Many instances of stuck pipe are a result of wall sticking (differential pressure sticking) which 

usually occurs in the drill collars and bottomhole assembly because of the increased surface area 

exposed to the wellbore. This section will deal primarily with this problem and related preventive 

and remedial measures. 

Differential pressure or wall sticking is the result of the force holding the pipe against a 

permeable zone while the pipe is motionless. This force is roughly equivalent to the differential 

between hydrostatic and formation pressures and the surface area upon which the force is acting. 

Also important, but more difficult to define, is the friction which exists between the pipe and 

filter cake. The friction coefficient will vary with the fluid’s chemical composition and the type of 

solids in the filter cake (coefficient is considerably higher for barite than for bentonite). 

The equation suggested by Outmans to describe sticking force is, 

where, 

F = f × A × S 

F = friction between drillstring and wall cake, or the total pulling force in pounds that would be 

necessary to pull pipe free, 

A = area of contact between filter cake and pipe (in. 2 ), 



REVISION 2006 7-34


S = pressure existing between pipe and wall cake in psi. During sticking process, this pressure 

will range from 0 initially to that differential pressure which exists between the hydrostatic of the 

fluid column and the formation. 

f = coefficient of friction between the pipe and wall cake (laboratory data indicates coefficient of 

friction values ranging from approximately 0.07 for invert emulsions to approximately 0.40 for 

low solids, native fluids). 

The above equation indicates that the sticking force may be reduced by altering the following 

physical properties of a drilling fluid. 

• Control fluid densities at lowest practical level consistent with control of formation pressure 

and borehole stability. 

• Monitor filtration and wall cake properties with emphasis on a thin wall cake. Evaluate effect 

of time and temperature on the wall cake. The filter cake thickness of two fluids may be equal 

in an API filtrate test (100 psi for 30 minutes), whereas the cake thickness could vary greatly 

with an increase in time, pressure, or temperature. Static conditions produce filter cakes of 

greater thickness as compared to dynamic conditions where the filter cake continues to erode 

due to fluid flow. 

• Control drilled solids at the lowest practical level. 

• Utilize additives which aid in reducing friction coefficient and sticking coefficient. 

• Severe conditions may dictate the use of an oil/synthetic fluid system such as CARBO- 

DRILL ® /SYN-TEQ ® . This type of fluid offers maximum protection against wall sticking. 

Other preventive measures against differential sticking are, (1) reduce area of contact between 

collars and wall cake with spiral collars and/or stabilizers, and (2) minimize interruption of 

pumping, particularly when the drillstring is not in motion. 

Most instances of differentially stuck pipe are preceded by increases in torque and drag. Many 

lubricants have been developed to minimize torque and drag, which in turn should reduce the 

chances of differential sticking. Some of these lubricants are shown in Table 7-6 and will be 

discussed in more detail under the section titled, Lubricity. 

Product 

LUBRI-FILM ® 

MIL-LUBE TM 

AQUA-MAGIC ® 

Initial 

Recommended 

Treatments 

4 lb m /bbl 

0.5% to 2.0% 

1.0% to 8.0% 

Maintenance 

Dependent upon fluid dilution 



Table 7 - 7 Lubricants 



REVISION 2006 7-35


Spotting Fluids 

Baker Hughes Drilling Fluids offers a variety of spotting fluids which are designed for use in 

every drilling environment. These spotting fluids may be used in either weighted or un-weighted 

systems. 

• BLACK MAGIC ® – a compound with a premium-grade, high melting point asphalt in 

diesel oil. Barite is added at the rigsite to the liquid solution. 

• BLACK MAGIC ® LT – contains a premium-grade asphalt compounded in a low-toxicity 

mineral oil. Barite is added at the rigsite to this liquid solution. 

• BLACK MAGIC ® SFT ® – (Sacked Fishing Tools) is a dry mixture of optimum size air-blown 

asphalt, lime, fatty acids, and dispersants in a powdered form. This sack product is stored at the 

rigsite and mixed with low-toxicity mineral oil, #2 diesel, or synthetic fluids. 

• BIO-SPOT ® – a non-toxic, oil free, water soluble spotting fluid concentrate. BIO-SPOT ® can 

be mixed rapidly and contributes virtually no toxicity to water-base fluid systems. BIO-SPOT 

is recommended for use when the use of oil and toxic surfactant blends are undesirable. 

• MIL-SPOT TM 2 – a liquid blend of a long chain fatty acid pitch, an emulsifier, and gellant. 

MIL-SPOT 2 can be used in #2 diesel, low-toxic mineral oils or synthetic fluids. 

• MIL-FREE - a liquid concentrate containing a long-chain fatty acid compound reacted with a 

surfactant. Can be used with any base oil and is recommended for freeing differentially stuck 

pipe in water-base drilling fluids when an un-weighted spotting fluid can be safely used. 

Spotting Fluid Placement 

The success of spotting fluids frequently depends upon time elapsed between sticking and 

placement of the spotting fluid. If the spotting fluid can be placed adjacent to the area of sticking 

within half an hour, the pipe may come free within one to two hours. If several hours have 

elapsed prior to placement of spotting fluid, 10 to 15 hours may be required for the pipe to come 

free. For this reason, spotting fluid materials should be kept on the rig and mixing facilities 

should be available to facilitate prompt placement. 

Even with prompt placement, it is essential that the spotting fluid is placed in the zone of sticking 

and that the fluid does not migrate too rapidly. When spotting diesel oil and MIL-FREE ® in lowdensity 

fluids, it would be advisable to calculate annular volume around drill collars and double 

this calculated quantity. This extra volume will compensate for hole enlargement. It will also 

allow a slight under displacement of drillpipe so that 1 to 2 bbl/hr of solution can be pumped to 

compensate for migration. 

When stuck pipe occurs with weighted fluids, a spotting fluid should be used with a density equal 

to or slightly higher than the drilling fluid in the annulus to avoid migration. Time elapsed 

between sticking the pipe and placement of the spotting fluid has such a drastic effect on the 

ability of the spotting fluid to free the pipe that consideration should be given to spotting an unweighted 

pill if possible. 



REVISION 2006 7-36


Grogan Technique 

Accurate placement of spotting fluid is difficult when hole enlargement has occurred and the 

spotting fluid must be placed some distance above the drill collars. Grogan outlined one 

technique for spotting a fluid which is lighter than the drilling fluid in use. This procedure utilizes 

the casing pressure observed after displacing spotting fluid from the drillstring and the relative 

gradients of drilling fluid and spotting fluid. For example, a casing pressure of 200 psi is noted 

after displacing a 6.8 lb m /gal spotting fluid into the annulus containing 10.8 lb m /gal drilling fluid. 

Calculated length of column of spotting fluid would initially be equivalent to observed casing 

pressure divided by fluid gradient, less spotting fluid gradient. 

Subsequently after pumping drilling fluid equivalent to volume of spotting fluid, a casing 

pressure of 150 psi is observed, which would indicate that the column length is 721 feet [150 lb / 

(.562 – .354) = 721 ft] and that the top of column is 1682 feet off bottom. This procedure can be 

continued until placement of spotting fluid is achieved. When spotting fluid density equals 

drilling fluid density, this technique will not apply and it will be necessary to use more than the 

calculated volume to compensate for error caused by hole enlargement. 

Remedial Procedures Using Spotting Fluids 

If the drillpipe becomes stuck, it must first be determined where the pipe is stuck. This may be 

accomplished by the following practices. 

• Stretch Indication – The drillpipe is pulled into tension with the amount of stretch and force 

required to stretch the pipe recorded. Then, a calculation can be made which will give an 

approximation as to where the pipe is stuck. This is not an accurate test especially in a deviated 

hole as it may give false results. 

• Freepoint Indicator Tool – An electric wireline tool called a freepoint tool is run inside the 

drillpipe on wireline. The pipe is worked up and down and torqued up as the tool is run down 

the hole. When the tool no longer indicates pipe movement, the point of differential sticking 

has been located. This is the most accurate means of determining exactly where the drillstring 

is stuck. 

One method of freeing stuck pipe is to spot oil/synthetic which contains a surfactant. MIL- 

FREE ® is used only as an un-weighted spotting fluid in water-base fluids. Approximately 2 

gallons of MIL-FREE is added to each barrel of oil/synthetic that is required to cover the zone of 

stuck pipe. 

Recommended Treatment (BLACK MAGIC SFT) 

For 100 bbl of prepared BLACK MAGIC ® SFT, thoroughly mix the following amounts of 

materials, shown in Table 7-8, to obtain the desired fluid weights. 



REVISION 2006 7-37


Density (lb m /gal) 

Un-weighted 

10.0 

12.0 

14.0 

16.0 

18.0 

Base Oil* 

(bbl) 

70 

64 

62 

57 

54 

49 

BLACK 

MAGIC SFT 

(sacks) 

136 

124 

113 

102 

91 

81 

Water 

(bbl) 

12 

11 

7 

6 

3 

3 

MIL-BAR ® 

(sacks) 

0 

135 

240 

345 

455 

560 

* Base Oil: Low-toxicity mineral oil, #2 diesel or synthetic (140°F Aniline Point Minimum) 

Table 7 - 8 BLACK MAGIC ® SFT Material Requirements - Formulation per 100 bbl 


1. Clean mixing pit and flush pump with water. 

2. Add oil as per chart. 

3. Add BLACK MAGIC ® SFT through hopper with agitation. 

4. Add water and agitate to a smooth blend. 

5. Add MIL-BAR and agitate to a smooth blend. 

6. To increase viscosity, add BLACK MAGIC ® SFT. 

7. To reduce viscosity, add oil. 

Recommended Treatment (MIL-SPOT 2) 

1. Prior to mixing, thoroughly clean a slug tank with drillwater or seawater and flush out mixing 

lines. 

2. Fill the slug tank with the required amount of oil as determined from Table 7-9. 

3. Add the required amount of MIL-SPOT 2 spotting fluid, followed by the required amount of 

seawater or drillwater. 

4. Add MIL-BAR to achieve desired fluid weight. All materials can be mixed as fast as required. 

5. Barite varies in quality and different barites, especially flotation varieties, can have a marked effect 

on rheological properties. Pilot test if barite is poor quality. 



REVISION 2006 7-38


Fluid Density 

(lbm/gal) 

Diesel 

Volume 

(bbl) 

MIL-SPOT 2 

(55-gal drum) 

Water 

(Seawater or 

Drillwater) (bbl) 

MIL-BAR (lb) 

8.0 

29.0 

4 

14.6 

1925 

10.0 

26.7 

4 

13.7 

6600 

12.0 

26.4 

4 

10.5 

11,750 

14.0 

26.0 

4 

6.9 

17,650 

16.0 

24.9 

4 

4.5 

22,750 

18.0 

23.4 

4 

2.5 

27,900 

NOTES: 

1. The relative volumes of oil/water must be adhered to for each density. 

2. To obtain fluid densities between those listed in the table is a simple case of extrapolation. 

3. All these fluids are designed for yield point values of ± l6 lb f /100 ft 2 . Increasing oil content 

decreases viscosity; increasing water content increases viscosity, but also increases tendency of 

solids to become water wet. 

4. Employ maximum agitation in the slug pit when mixing barite. 

Table 7 - 9 MIL-SPOT 2 Material Requirements - Formulation per 50 bbl 

Recommended Treatment (BIO-SPOT) 

Spot at least enough BIO-SPOT spotting fluid to cover the entire stuck pipe interval, but 

preferably not less than 100 bbl (see Table 7-10). 

Density 

(lb m /gal) 

BIO-SPOT 

(bbl) 

Water (bbl) 

MIL-BAR 

(sacks) 

8.7 

100 

0 

0 

10.0 

95 

0 

74 

12.0 

87 

0 

185 

14.0 

80 

0 

297 

16.0 

65 

7 

410 

18.0 

50 

14 

523 

Table 7 - 10 BIO-SPOT Materials Requirement - Formulation per 100 bbl 


1. Thoroughly clean mixing pit. Flush pump and mixing lines with water and drain, if possible, to 

minimize dilution of the BIO-SPOT fluid. 

2. Add correct volume of BIO-SPOT concentrate for desired volume and fluid density. 



REVISION 2006 7-39


3. Add correct volume of water (if required) and agitate until thoroughly blended. 

4. Add MIL-BAR (or weight material) to the desired density and agitate until thoroughly blended and 

smooth. 

Note: Weighted spotting fluid at this point should be pumpable yet have sufficient body to 

suspend weight material. If spotting fluid is not pumpable, treat lightly with UNI-CAL®. 

5. If the chloride concentration of the drilling fluid is greater than 60,000 mg/L, placement of a 25 to 40 

bbl freshwater NEW-DRILL ® spacer ahead of the BIO-SPOT as well as behind the BIO-SPOT is 

recommended. Spacers are not required if the chloride concentration is less than 60,000 mg/L. 

6. Pump spotting fluid at normal pumping rates. 

Alternate Methods for Freeing Stuck Pipe 

Other methods of freeing stuck drill strings include the following. 

Altering Fluid Density 

Reducing drilling fluid density may result in freeing stuck pipe. This method would not be 

feasible if pressure reduction allowed formation fluids to enter the wellbore. Often it is also time 

consuming and expensive. 

Drillstem Test Tool 

Stuck pipe has also been freed by utilizing a drillstem test (DST) tool above the point of sticking 

and releasing pressure below packer. This sudden reduction in pressure may, however, result in 

unstable shales falling into the wellbore and an influx of formation fluids from permeable zones. 

This technique should be used with extreme caution. 

U-Tube Technique 

The U-Tube Technique offers the advantage of speed without the inherent cost involved in 

reduction of drilling fluid density. Basically, the U-Tube method involves displacing a portion of 

the fluid in the upper part of the drillstring with a lighter fluid such as diesel oil or water, then 

allowing annulus fluid to flow back on the drillpipe side until equilibrium is obtained. The 

hydrostatic pressure reduction desired by lowering fluid level in the annulus can be calculated. 

Example 

While drilling at 8000 feet, the drillstring stuck while running a survey. Hole size is 8½ inch and 

drillpipe is 4½ inch. Casing size is 9 5 / 8 inches and is set at 3000 feet. 

Drilling fluid density is 10.6 lb m /gal, and it is desired that hydrostatic pressure be reduced by 250 

psi on bottom. Water is to be used to lighten hydrostatic on the drillpipe side. 



REVISION 2006 7-40


V 

w 

= 

⎡ C 

Ph 

⎢ 

⎣W 

a 

m 

C 

dp 

+ 

W − W 

m 

0.052 

d 

⎤ 

⎥ 

⎦ 

⎡ 0.0538 0.0142 

250 

⎢ 

+ 

⎣ 10 .6 10 .6 − 8.34 

= 

0.052 

⎤ 

⎥ 

⎦ 

= 54 .6 

⎡ ⎛ V ⎞⎤ 

⎡ ⎛ 54 ⎞⎤ 

P 

max 

= 0.052⎢ 

m d 

⎢ ⎜ ⎟ = 

0.0142 

⎥ 

⎢ 

⎜ ⎟ 

⎣ ⎝ C 

dp ⎠⎥⎦ 

⎣ ⎝ ⎠⎦ 

( ) ⎜ 

w 

W −W 

⎟⎥ 

= 0.052 ( 10.6 − 8.34) 446. 9 

V 

a 

⎛ C 

a 

= P 

⎜ 

h 

⎝ 0.052× 

W 

m 

⎞ ⎛ 0.0538 ⎞ 

⎟ = 250⎜ 

⎟ = 244.0 

⎠ ⎝ 0.052× 

10.6 ⎠ 

where, 

V w = bbl of light fluid to be pumped into drillpipe 

P h = desired pressure reduction at 8000 ft 

C a = annular capacity between drillpipe and casing in bbl/ ft 

W m = fluid weight (lb m /gal) 

C dp = Capacity of drillpipe in bbl/ft 

P max = pressure required to displace required volume of light fluid 

V a = amount of light fluid which will flow back to obtain equilibrium 

W d = weight of the displacement fluid. 

A reduction of 250 psi in bottom hole pressure would result in an equivalent drilling fluid density 

of 10.0 lb m /gal at total depth. 

Caution should be exercised with this method, since a drop in fluid level could reduce hydrostatic 

pressure to a value less than formation pressure allowing a kick. In the above example, fluid level 

is lowered 454 feet which would result in an equivalent drilling fluid density of 9.0 lb m /gal at the 

casing shoe. 

If the well flows, it will be necessary to circulate out through the choke utilizing a balanced 

bottomhole pressure technique. Caution should be exercised if reverse circulation is attempted 

since all circulating pressure losses below the casing shoe (annular friction loss from casing to bit 

and friction losses through nozzles, collars, drillstring, etc.) would be imposed at the casing shoe 

and could induce lost returns. 

The primary advantages of this technique are that drilling fluid properties do not have to be 

altered and hydrostatic pressure can be reduced slowly, minimizing the possibility of hole 

sloughing or kicks. Also, with this method the displacing fluid does not normally come into 

contact with the wellbore. 

If remedial procedures do not free stuck pipe, it may be necessary to wash over the fish. It should 

be noted that wash pipe would have greater tendency to stick than the drillstring, therefore, 



REVISION 2006 7-41


drilling fluid properties (downhole filtrate and rheological properties) should receive special 

consideration. 

Other Causes of Drillpipe Sticking and Remedial Correction 

Key Seating 

Key seating is another possible cause of pipe sticking. Key seats are the result of sharp hole angle 

changes causing the drillpipe rotation to wear a groove on one side of the hole. This groove 

would be the approximate diameter of the drillpipe or tool joints. When pulling out of the hole, 

the drill pipe and tool joints may pull through the groove, but the larger diameter drill collars 

would become stuck. 

To avoid key seating, the most important thing to do is minimize abrupt angle changes. When 

drilling directional wells, the rate of deviation change (dogleg severity) should be controlled to 

avoid any sharp changes in direction or angle. String reamers can be used to smooth out abrupt 

angles. 

The development of a key seat may not occur over the course of one bit run, but rather over a 

number of bit runs. Evidence of key seat development can be observed when the drill pipe 

encounters increasingly excessive drag in the same section of hole on repetitive trips. 

When key seating does occur and the pipe becomes stuck, the following corrective measures are 

suggested. 

• Work pipe downward (if possible) while pumping. 

• Avoid excessive pull on the drill string as this will in all probability compound the problem by 

pulling pipe further into the key seat. 

• Increase the concentration of friction reducing materials in the fluid (see Table 7-6). 

• In some cases a special “driving” tool consisting of a length of casing concentric around a 

second joint of smaller diameter casing with the annulus full of cement (for weight) is used to 

“hammer” the drill string downward and out of the key seat. The inside length of casing has an 

ID large enough to slide over a drill pipe guide and impact on a robust seat (“anvil”) mounted 

on a sub inserted into the stuck drill pipe. 

Foreign Objects 

Foreign objects entering the wellbore may also result in stuck pipe. In this case, friction reducing 

materials will probably not help. Working the pipe up and down and rotating when possible are 

primary remedial actions. 

Formation Caving 

Formation caving can also result in stuck drillstrings. The severity of sticking is affected by 

quantity and size of cavings and how well the drilling fluid is cleaning the hole. The remedial 

action to be taken is to start circulating to clean the hole and run sweeps to improve cleaning 

action. 



REVISION 2006 7-42


Fluid Density 

Insufficient drilling fluid density can also be a contributing factor. Care should be taken, 

however, in how much the drilling fluid density is increased since differential sticking and loss of 

circulation can result from excessive hydrostatic pressure. 

LUBRICITY 

Control of drilling fluid lubricity becomes extremely important in holes experiencing severe 

torque and drag. These problems are most pronounced in a directional or excessively deviated 

hole, and considerable effort has been directed to their solution. The application of extremepressure 

(EP) lubricants in drilling fluids was first conceived in 1958. These lubricants were 

originally introduced to increase bit life but, as work progressed, noticeable reductions of torque 

and drag expanded the development of lubricants for aqueous fluids. 

The problem associated with developing effective lubricants derives from the fact that some 

lubricating products form a good boundary layer of protection but, under extreme pressures and 

the associated high temperatures produced from friction, these lubricants breakdown. A 

comprehensive testing of lubricants should include the use of an EP tester in combination with a 

sticking coefficient apparatus. The EP tester cannot simulate conditions that are found when the 

drillpipe contacts filter cake, but an approximation can be made using a stickometer which uses 

actual filter cake to conduct the test. 

Laboratory experience indicates that the Falex Lubricant Tester is a reliable laboratory test to 

predict effectiveness of lubricants under extreme pressure conditions (see Fluids Testing 

Procedures Manual). With the Falex Tester, properties are evaluated by comparing torque 

measurements at varying increments of loading among a series of test samples, including a base 

sample. Reductions in torque as compared to the base fluid are generally indicative of lubricant 

effectiveness. The Falex Lubricant Tester has been modified for use with drilling fluids. This 

device measures the torque generated between two steel surfaces in the presence of drilling fluid. 

The readings are converted into coefficient of friction. 

Laboratory measurements are valid in selecting lubricants, but these results alone will not always 

predict effectiveness under downhole conditions. Variables such as temperature, quantity and 

nature of solids generated and long-term effect of the drilling fluid in use are often difficult to 

analyze. The ultimate test is obviously the results achieved under actual drilling conditions. 

Some general conclusions obtained from laboratory data and substantiated by field experience are 

noted below. 

• Minimum concentrations of drilled solids generally result in improved lubricity. 

• The effectiveness of diesel oil as an EP lubricant is greatly reduced when it is tightly 

emulsified in a system. Diesel oil offers maximum lubricity when added continuously in small 

quantities to the suction pit while drilling. The information on diesel oil obtained from 

laboratory testing using the lubricity tester differs from results obtained using the sticking 

coefficient instrument. This device indicates that emulsified oil in a water-base fluid system 

does impart lubricity. This is most likely due to the oil becoming embedded in the filter cake 

and thus lubricating the filter cake. Diesel oil emulsified with a surfactant to preferentially oilwet 

metal surfaces will thereby impart fair lubricity. Surface-active materials are generally 



REVISION 2006 7-43


restricted, to an un-weighted or non-dispersed drilling fluid since they tend to promote 

flocculation. 

• Asphaltic materials offer limited lubricity. Maximum effectiveness as a lubricant is attained 

when used in a fluid which contains a percentage of diesel oil. These materials are employed 

primarily to assist in stabilizing sloughing shale sections. 

Baker Hughes Drilling Fluids offers a selection of lubricants designed to function in a variety of 

conditions. What follows is a brief description of these products. 

LUBRI-FILM ® is an extreme-pressure lubricant which promotes formation of an insoluble 

lubricant film on the surface of metal. This film of metallic “soap” provides lubrication at loads 

much greater than those of general borehole lubricants. LUBRI-FILM is particularly well suited 

for deep, hot holes where friction and wear between casing and drillpipe are of primary concern. 

Since LUBRI-FILM deposits a tenacious, long-lasting film, it can provide lubricity for extended 

periods with no maintenance additions. Most borehole lubricants, on the other hand are dependent 

on frequent additions to maintain lubricity. 

Benefits derived from LUBRI-FILM, other than improved lubricity, are the 

corrosion protection afforded by the metallic soap film. Increased bit life of 

30% to 100% has also been observed after additions of LUBRI-FILM. 

Note: Unlike some EP lubricants, LUBRI-FILM contains no sulfur which may produce 

sulfide cracking. 

MIL-LUBE TM provides and extreme pressure lubrication. MIL-LUBE is effective over a wide 

range of loading conditions. MIL-LUBE is a blend of surfactants and modified fatty acids 

designed for use in all types of water-base drilling fluids. Under extreme pressure conditions, 

MIL-LUBE forms a lubricating film on metal surfaces that resists removal. Sticking coefficient 

is reduced with MIL-LUBE, thus minimizing differential sticking. When using MIL-LUBE, the 

pH of the drilling fluid should be controlled at 9.5 or below which will give the best performance 

and resistance to greasing-out or high-temperature degradation. 

AQUA-MAGIC TM was designed for use in environmentally-sensitive areas. AQUA-MAGIC is 

a very low-toxicity lubricant which will not create a sheen on receiving waters or on U.S. EPA 

(Environmental Protection Agency) laboratory sheen tests. AQUA-MAGIC may be used in unweighted 

or weighted, freshwater or seawater fluids. AQUA-MAGIC is most efficient at a pH of 

9.5 or below. 

CARBO-DRILL ® /SYN-TEQ ® and similar oil/synthetic fluid systems offer the highest degree of 

lubricity that can be achieved with drilling fluids. In some extremely high angle and crooked 

holes, oil-base fluids have been introduced to reduce drag and torque to acceptable levels. 

TEQ-LUBE ® II is an environmentally-acceptable composition which will effectively reduce 

torque and drag in most water-base drilling fluids. It contains water-dispersible, extreme pressure 

lubricants and a specially selected glycol carrier. Because it is water-soluble, TEQ-LUBE ® II 

will not sheen. TEQ-LUBE ® II will function up to very high tool joint contact loads and 

provides an effective lubricant in a wide range of water-base drilling fluids and conditions. 



REVISION 2006 7-44


OMNI-LUBE is an environmentally acceptable polymeric fatty acid solution which will 

effectively reduce torque and drag in most emulsion-based drilling fluids. Results obtained from 

field tests of OMNI-LUBE indicate that friction can be lowered by up to 25% as compared to 

untreated fluids, and torque is less erratic. 

LC-LUBE is chemically inert, sized graphite which can be used effectively as a general borehole 

lubricant. It is environmentally acceptable and is applicable in water-, synthetic-, or oil-based 

fluids. LC-LUBE can also be effective in reducing the probability of stuck pipe. It has little 

effect on the rheological properties of drilling fluid. It has high compressive strength and because 

of its excellent bridging properties, it is also used to control loss of circulation (partial and 

seepage losses) in drilling fluids. 

LC-GLIDE is a spherical, synthetic-graphite product used for torque and drag reduction during 

drilling, wireline and casing running operations. Its spherical shape provides a high performance 

alternative to glass and copolymer beads typically used for torque and drag reduction. It has an 

advantage over the beads in that when it is crushed it becomes graphite particles which still have 

lubricious properties, whereas when the beads are crushed the resultant particles are not 

lubricious. 

LUBE-622 is a non-toxic, biodegradable lubricant which can be used effectively in salt based 

systems. 

MIL-GRAPHITE is environmentally acceptable graded graphite used primarily to enhance 

lubricity and sliding and is applicable in water, synthetic, or oil-based fluids. 

The PENETREX ® family of products is designed to reduce bit-balling and improve penetration 

rates in water-based systems up to 400% over untreated systems. Products making up this family 

are: PENETREX for offshore operations, PENETREX L for land operations, and PENETREX 

NS, for North Sea applications. 

HIGH BOTTOM HOLE TEMPERATURES 

Mechanisms of Thermal Degradation 

From the drilling fluid point of view high temperatures can be considered as those above which 

conventional drilling fluid additives begin to thermally degrade at an appreciable rate. The 

degradation leads to loss of product function, and system maintenance becomes difficult and 

expensive. The majority of drilling fluid treatment chemicals derived from natural products begin 

to degrade at temperatures between 250 and 275°F. However, many systems designed for hot 

wells are based on clay and contain lignosulphonates and ignites and can exhibit temperature 

stability up to approximately 350°F. However, management of these drilling fluids above 300°F 

can be difficult and expensive. 

Thermal degradation can be simplistically thought of as the result of putting so much energy into 

a chemical substance that some portion of its structure can break off or change form. Similar 

results can be effected at lower temperatures by the presence of certain chemicals. Oxygen (from 

air) can promote oxidation; water (present in the drilling fluid) can promote hydrolysis. Whatever 

the cause, or particular chemical reaction involved, the end result is that at higher temperatures 

formerly stable drilling fluids become difficult to control. Unfortunately elevated temperatures 

are usually not the only stresses experienced by drilling fluids in high BHT wells. Often chemical 



REVISION 2006 7-45


contaminants such as the acid gases hydrogen sulfide and carbon dioxide are also present. Very 

frequently high drilling fluid densities and considerable drilling depths are part of the overall 

picture. Long trip times, which leave static, solids laden drilling fluid exposed to high levels of 

contaminants, put many high temperature drilling fluids in exceptionally challenging 

environments. Thermal degradation of drilling fluid additives (generating CO 2 ), can result in 

unstable rheological and filtration properties. 

High temperatures both disperse and flocculate bentonite suspensions. Hydration of 

Montmorillonite (the major constituent of commercial bentonite) increases with temperature and 

pressure and an increased number of clay platelets are split from aggregated stacks. A greater 

number of particles are then present in the suspension and the viscosity of the suspension 

increases. The split of aggregated stacks presents fresh surfaces for the adsorption of hydroxyl 

ions producing a consequential drop in pH. This combination of increased surface area and drop 

in pH will tend to increase flocculation within the suspension. Under downhole conditions this 

creates a demand for alkali and deflocculant additions. If sufficient deflocculant is not present, or 

the deflocculant itself is thermally degrading, severe flocculation or gelation can occur. This 

condition is most commonly reached on a trip and problems re-establishing circulation can be 

created. The actual temperature that triggers thermal flocculation depends on the fluid’s 

composition. The type of bentonite, the type and concentration of drilled solids, the type and 

concentration of deflocculant and the ionic composition of the liquid phase, all have an effect on 

the flocculation process. The reaction of calcium ions with colloidal clays in a high alkalinity 

environment can result in the formation of cement-like calcium-alumino-silicates. In these 

situations extremely high gels can develop and, in the worst case, the drilling fluid may solidify. 

Temperature effects on polymer drilling fluids are mainly due to the effects of temperature on the 

constituent polymers. In most cases polymer drilling fluids are low solids fluids and all have a 

degree of inhibition to clay hydration. The problem of increased clay hydration, seen in bentonite 

drilling fluids, is rarely a problem in polymer systems. The polymers are, however, susceptible to 

thermal degradation. Cleavage of the polymer chain can be accompanied by chemical 

modification of the attached groups. The two primary reactions responsible for polymer 

breakdown are oxidation and hydrolysis. Both of these processes can be controlled, to some 

degree, by the maintenance of pH in the range 9.5 – 10.5 and by the use of oxygen scavengers. 

The polar interactions between charged clays and polymers that take place in water based drilling 

fluids do not occur in the non polar phase of a non-aqueous-based drilling fluid. Only relatively 

weak hydrogen bonding can occur. These weak forces are readily broken by increases in 

temperature so thermal degradation of non-aqueous-based drilling fluids is not common. 

Temperature Limits 

The following tables give approximate decomposition temperatures, or practical thermal 

application limits, for water based drilling fluids products and systems. Correctly formulated nonaqueous-based 

drilling fluids can perform effectively on wells with bottom hole temperatures as 

high as 500°F (275°C). 



REVISION 2006 7-46


Drilling Fluid Products 

Generic Type Temp Limit °F Temp Limit °C 

Guar Gum 

Starch 

Biopolymers 

HT Starch 

CMC and PAC 

Lignosulphonate 

Standard Lignite 

Modified Lignite 

Synthetic Polymers 

225 

250 

250 – 275 

275 

275 

250 – 325 

300 – 350 

350 – 450 

400 - 500 

107 

120 

120 – 135 

135 

135 

120 – 160 

150 – 175 

175 – 230 

205 - 260 

Table 7 - 11 Drilling Fluids Products Temperature Limitations 

Drilling Fluid Systems 

Generic Type Temp Limit °F Temp Limit °C 

Non Dispersed Polymer 

NDP – High Temperature Formulation 

Bentonite/FCL 

Bentonite/FCL/Lignite 

Bentonite/Modified Lignite/polymer Blends 

Synthetic Polymers (PHPA, PA, SSMA, VSA, etc.) 

275 

350 

300 

350 

400 

400 - 500 

Table 7 - 12 Drilling Fluids Systems Temperature Limitations 

135 

175 

150 

175 

205 

205 - 260 

Extending Temperature Limits 

To increase the temperature stability of drilling fluids products and systems it is necessary to 

inhibit the mechanisms that cause product failure and/or to substitute parts of a system that are the 

first to lose product function. 

The life of polymers can be extended by minimizing the reactions that cause severing of the 

polymer chains. Primarily these reactions are hydrolysis and oxidation. Hydrolysis can be 

minimized by maintaining a pH in the range 9.5 – 10.5 and oxidation can be avoided by the use 

of an oxygen scavenger. This approach alone will extend the thermal stability of most systems by 

approximately 25°F. Some heavy metals are believed to catalyze the breakdown reactions and 

products are available that “mop up” these elements. When polymers are used in formate brines 

their thermal stability is increased by as much as 50°F. This is largely due to the formate brines 

being powerful antioxidants. 

Drilling Fluid Properties 

Both temperature and pressure can have significant effects on drilling fluid properties. 



REVISION 2006 7-47


Density 

It is important to realize that drilling fluid density can vary significantly with temperature. This 

variation is represented by a decrease in density with increasing temperature and is due to the 

volumetric thermal expansion of the fluid phase. This is particularly true of oil based drilling 

fluids as the oil continuous phase has a greater coefficient of expansion than does water. 


In commonly utilized oilfield drilling fluids all rheological properties decrease with increasing 

temperature. However under downhole conditions this effect may be reduced by increased 

pressures and may be completely reversed (i.e. viscosity will increase) by the increased hydration 

and flocculation of commercial clays and drilled solids. The presence in the wellbore of 

contaminants such as calcium, magnesium and carbon dioxide can, under high temperature 

conditions, cause the rheological properties of a water based drilling fluid to increase to such an 

extent that it become un-pumpable. The viscosity of oil based and synthetic fluids also increases 

with applied pressure. 

Filtrate 

Both API and HPHT filtrate increase with increasing temperature. This is largely due to loss of 

product function, and to changes in filter cake compressibility with changing temperatures. 

Above differential pressures of 100 psi pressure increases alone have little effect on clay based 

drilling fluid filtrate indicating the effects of compressible filter cakes. 

In general, polymers maintain their filtration control function well beyond the temperature at 

which they lose any viscosifying capabilities. This is due to the fact that even short, broken 

polymer chains are capable of functioning as filtrate control agents but not as viscosifiers. 

Alkalinity 

Temperature increases the rate and extent of most chemical reactions. The increased yield of 

clays results in more sites being available for reaction with ions, particularly hydroxyl ions. The 

end result of this is a reduction in alkalinity and an increase in flocculation. In oil based drilling 

fluids increased reaction of lime with surfactants greatly increases with temperature and 

reductions in drilling fluid alkalinity are common, particularly after lengthy trips. Often the 

performance of the drilling fluid will be hindered by a lack of a sufficient excess of lime. 

Methylene Blue Test (MDBT) 

When using a water based drilling fluid the MBT is one of the most meaningful tests available to 

indicate the general condition of the drilling fluid. The results of this test give an indication of the 

amount and size of active clays in the drilling fluid. In normal wells a non-dispersed polymer 

drilling fluid should, for example, have an MBT no greater than 20 lb/bbl. In high density drilling 

fluids 15 lb/bbl. should be considered the upper limit. High temperatures can rapidly increase the 

yield of commercial bentonite and reactive solids; this in turn will produce a rapid increase in 

values obtained from MBT tests. Drilling fluids with high MBTs are susceptible to contaminants 

that would not normally cause problems in low solids drilling fluids (e.g. calcium, carbonates, 

etc.). 



REVISION 2006 7-48


Flash Point 

When using an oil based drilling fluid on HPHT wells, the flowline temperature can approach the 

flash point of the base oil particularly when drilling deep 12 ¼” intervals. Usually bottom hole 

temperatures are too low to cause a problem in 17 ½” hole and circulation rates in smaller hole 

diameters allow the drilling fluid time to cool as it comes up the annulus. High return drilling 

fluid temperatures can have adverse effects on elastomers, can produce undesirable volumes of 

fumes and present a fire risk. Careful management of surface pits can facilitate cooling of the 

drilling fluid, but the effect is usually minimal. Some operators advocate the use of mud coolers 

(heat exchangers) and there is some evidence that, in the right application, this approach can 

prove effective. 


Symptoms 

Typical symptoms of problems associated with high temperatures are: 

• High viscosity and gel strengths 

• Increased filtrate 

• Decreased alkalinity 

These problems may manifest themselves as: 

• Difficulty in breaking circulation 

• Difficulty in running tools to bottom 

• Difficulty in degassing circulated drilling fluid 

• Differential sticking tendency 

The first indications of thermal deterioration of the drilling fluid system will be seen in bottoms 

up samples after trips. Trips tend to be lengthy on HPHT wells and the drilling fluid will have 

been exposed to near bottom hole temperature for long periods. It is important that bottoms up 

drilling fluid is tested and the results used as an indicator of future problems should remedial 

treatment not be made. 

Remedial Action – Water Based Drilling Fluid 

• Increased Rheological Properties 

• Add water – due to increased surface area of clays, increased downhole filtration and 

surface evaporation drilling fluids at high temperature rapidly become dehydrated. 

• Decrease solids content – reducing the percentage of low gravity solids in the drilling 

fluid will facilitate the control of rheological properties and improve product 

performance. 

• Add deflocculants – If bottoms up samples indicate that the drilling fluid is becoming 

excessively viscous it might be beneficial to increase the concentration of 



REVISION 2006 7-49


deflocculant/dispersant. Alternatively substitute the existing product for one better suited 

to the bottom hole temperature. Baker Hughes Drilling Fluids’ additives to improve the 

thermal stability of water-base systems are MIL-TEMP ® , a low-molecular-weight copolymer, 

and ALL-TEMP ® , a sulphonated synthetic inter-polymer. Additions of MIL- 

TEMP or ALL-TEMP (0.3 to 3 lb m /bbl) to existing water-base fluids aid in stabilizing 

rheological and filtration properties under severe temperature conditions. Laboratory and 

field data indicate that these materials are effective at temperatures above 600°F. Care 

must be exercised when increasing product concentration. Most chemicals will take up 

free water and this can negate any beneficial affects of deflocculation. 

• Increased Filtrate 

• Add HTHP filtrate reducer – if it is apparent that the filtrate cannot be controlled 

economically with existing products a more thermally stable product should be used. 

Often this appears an expensive option but usually proves cost effective. Baker Hughes 

Drilling Fluids’ additives for filtration control at high temperatures are: 

o 

o 

o 

PYRO-TROL ® , an AMPS/AM co-polymer. Has minimal effect on rheological 

properties. Normal treatments are 0.75 – 2.0 lb m /bbl. 

KEM-SEAL ® PLUS, an AMPS/AAM co-polymer. In fresh water will increase 

viscosity. In brines effect on viscosity is appreciably less. Normal treatment 

levels are 0.25 – 2.0 lb m /bbl. 

CHEMTROL ® X, a lignite/polymer blend. Has a minimal effect on viscosity. 

At temperatures greater than 400°F, caution should be exercised due to CO 2 

from thermal degradation. Normal treatment levels are 1.0 to 10.0 lb m /bbl. 

Remedial Action – Oil Based Drilling Fluid 

• Increased Rheological Properties 

• Add base oil – increased filtrate and surface evaporation reduces the total oil content of 

the drilling fluid and, if not replaced, will in effect, “dehydrate” the system. 

• Add oil wetting agents – by ensuring that all solids are oil wet the inter-particle 

reactions between them are reduced. This results in reductions in viscosity and gel 

strengths. Care must be taken when adding wetting agents. They are usually concentrated 

products that prove very effective thinners for clay based rheological properties in oil 

based drilling fluids. Over treatment can reduce suspension characteristics to levels that 

will promote inefficient hole cleaning and may allow barite sag to occur. 

• Increased HPHT filtrate 

• Often increases in HPHT filtrate can be readily, and economically, remedied by the 

addition of sufficient lime to restore a good (2 – 3 lb m /bbl) excess in the drilling fluid. If 

this is not effective, increased levels of emulsifiers may be required. Ultimately the 

addition of a dry powder filtrate reducer (MAGMA-TROL) may be required. 



REVISION 2006 7-50


Planning 

The successful application of a fluid in an HPHT environment is greatly influenced by pre-job 

planning. Prior to drilling an HPHT interval contingencies must be in place to ensure that the 

potential fluid problems, common on HTHP wells, can be anticipated and corrected. 

Drilling Fluid Selection 

The type of drilling fluid that will be chosen for a particular application will depend very much 

on factors other than just the ultimate bottom hole temperature. 

The location of the well may have an influence on selection. If the well is to be drilled in a 

particularly remote or environmentally sensitive area the use of a non-aqueous-based drilling 

fluid, the commonly preferred option for high temperature applications, may be restricted. 

The anticipated formations and contaminants are important factors in drilling fluid selection. 

Highly dispersed water based drilling fluids may not, for example, be appropriate to drill reactive 

shales or formations where CO 2 or brine flows are predicted. CO 2 can have dramatic negative 

effects on water based drilling fluids that do not contain lime. However water based drilling 

fluids, heavily treated with lime can be particularly difficult to stabilize at high temperatures. 

Polymer based drilling fluids are subject to degradation by various means at high temperature. 

It can be seen that neither clay nor polymer based fluids are ideal for high temperature 

environments. However, by careful choice of materials, relative to the anticipated environment, 

water based drilling fluids can be run, with some difficulty, on wells with BHT up to 500°F. 

Non-aqueous-based drilling fluids have a distinct HSE disadvantage for HPHT applications in 

that gas is soluble in these fluids under downhole conditions. Gas is not soluble in water based 

drilling fluids. 

Water based drilling fluids are much less effected by temperature and pressure than non-aqueousbased 

drilling fluids. This makes hydraulic modeling and ECD control appreciably more 

straightforward in water based fluids. 

It is therefore essential that an appropriate drilling fluid system is selected for HPHT applications 

and that, as part of the planning process, the formulation of the chosen system is optimized for the 

anticipated downhole environment and contaminants. 



REVISION 2006 7-51


REFERENCES 

1. Hole Problem Data Package, BP, XTP Sunbury, April 1996. 

2. Kelly, John, Jnr., Drilling Problem Shales, (Two Parts) Oil and Gas Journal, June 3 

and June 10, 1968. 

3. Chesser, B.G. and Perricone, A.C., A Physico Chemical Approach to the Prevention of 

Balling of Gumbo Shales, SPE Paper 4515, Presented at Annual Fall Meeting of SPE of 

AIME, Las Vegas, Nevada, September 30 - October 3, 1973. 

4. Clark, Scheuerman, Rath, and Van Laar, Polyacrylamide/ Potassium-Chloride Mud from 

Drilling Water-Sensitive Shales, Journal of Petroleum Technology, June 1976. 

5. Chenevert, M.E., Shale Control with Balanced Activity Oil Continuous Muds, SPE Paper 

2559, Fall Meeting, September 29, 1969. 

6. Messenger, J.U., How to Combat Lost Circulation, (Three Parts) Oil and Gas Journal, 

May 13, May 20, and May 27, 1968. 

7. Stieiger, R.P. and Leung, P.K., Quantitative Determination of the Mechanical Properties 

of Shales, SPE Paper 18024, Presented at the Annual Technical Conference, Houston, 

Texas, October 2-5, 1988. 

8. Beihoffer, T.W., Dorrough, D.S., and Schmidt, D.D., The Separation of Electrolyte 

Effects from Rheological Effects in Studies of Inhibition of Shales with Natural Moisture 

Content, SPE Paper 18032, Presented 1988. 

9. Sheu, J.J. and Perricone, A.C., Design and Synthesis of Shale Stabilizing Polymers for 

Water Based Drilling Fluids, SPE Paper 18033, Presented 1988. 

10. Yew, C.H., Chenevert, M.E., Wang, C.L., and Osisanya, S.O., Wellbore Stress 

Distribution Produced by Moisture Adsorption, SPE Paper 19536. 

11. Aadnov, B.S., Rogaland, U., and Chenevert, U., Stability of Highly Inclined Boreholes, 

SPE Paper l6052, Presented at the SPE Drilling Conference in New Orleans, Louisiana, 

March 15-18, 1987. 

12. Davis II, N. and Todman, C.E., New Laboratory Tests Evaluate the Effectiveness of 

Gilsonite as a Borehole Stabilizer, IADC/SPE Paper 17203, Presented at the IADC/SPE 

Drilling Conference in Dallas, Texas, February 28 - March 2, 1988. 

13. Chesser, B.G., Design Considerations for an Inhibitive; and Stable Water-Based Mud 

System, IADC/SPE Paper 14757, Presented at the IADC/SPE Drilling Conference in Dallas, 

Texas, February 10-12, 1986. 

14. Gray, G.R. and Darley, H.C.H., Composition and Properties of Oil Well Drilling 

Fluids, Gulf Publishing Company, Fourth Edition, 1980, pp 155 – 160. 

15. IDF, Technical Manual 



REVISION 2006 7-52


16. Dye, B. et al, Design Considerations for High Performance Water-Based Muds, AADE 

Paper AADE-04-DF-HO-14, presented April 2004. 

17. van Oort, E. et al, Silicate-Based Drilling Fluids: Competent, Cost-effective and Benign 

Solutions to Wellbore Stability Problems, IADC/SPE Paper 35059, 1996. 

18. Bland, R.G., et al, Low Salinity Polyglycol Water-Based Drilling Fluids as Alternatives 

to Oil-Based Mud, SPE Paper 29378, Presented 1995. 

19. Steiger, R.P., Fundamentals and Use of Potassium/Polymer Drilling Fluids to Minimize 

Drilling and Completion Problems Associated with Hydratable Clays, SPE Paper 10100, 

Presented 1981. 

20. Operation Manual Fluids – NOR-OP-FL1-2003 

21. Aston, M.S. et al, Drilling Fluids for Wellbore Strengthening, SPE/IADC Paper 87130, 

Presented 2004. 

22. Davison, J.M., et al, Extending the Drilling Operating Window in Brent: Solutions for 

Infill Drilling in Depleting Reservoirs, SPE Paper 87174, Presented 2004. 

23. Helmick, W.E. and Longley, A.J., Pressure Differential Sticking Drill Pipe and How It 

Can Be Avoided or Relieved, API Meeting, Los Angeles, California, May 16-17, 1975. 

24. Grogan, Gene E., How to Free Stuck Drill Pipe, Oil and Gas Journal, April 4, 1966. 

25. Laboratory and Field Test Data on Borehole Lubricants, Milpark (Baker Hughes 

Drilling Fluids) Technical Memorandums. 

26. Moses, P.L., Geothermal Gradients, API Paper 926-6- K, March 1961. 

27. Annis, Max R., Jr., High Temperature Flow Properties of Water-Base Drilling Fluids, 

SPE Paper 1861, Presented at the Fall Meeting of SPE, October 1, 1967. 

20. Dye, William, et. al., Drilling Processes: The Other Half of the Barite Sag 

Equation, SPE Paper 80495, Presented at the SPE Asia Pacific Oil and Gas 

Conference and Exhibition held in Jakarta, Indonesia, September 9-11, 2003 

21. Leyendecker, E.A., and Murray, S. C., Properly Prepared Oil Muds Aid Massive Salt 

Drilling, World Oil, April 1975 



REVISION 2006 7-53

Corrosion 

Chapter 

Eight 

Corrosion

Chapter 8 


CORROSION...........................................................................................................................................8-1 

INTRODUCTION.......................................................................................................................................8-1 

FACTORS AFFECTING CORROSION RATE ...............................................................................................8-1 

Temperature .......................................................................................................................................8-1 

Pressure..............................................................................................................................................8-2 

pH.......................................................................................................................................................8-2 

Dissolved Salts...................................................................................................................................8-2 

CORROSIVE AGENTS AND TREATMENTS................................................................................................8-2 

Oxygen (O 2 ) .......................................................................................................................................8-2 

Carbon Dioxide (CO 2 ) .......................................................................................................................8-3 

Hydrogen Sulfide (H 2 S).....................................................................................................................8-4 

CORROSIVITY OF VARIOUS FLUIDS........................................................................................................8-7 

USE OF CORROSION COUPONS ...............................................................................................................8-8 

Ring Coupons.....................................................................................................................................8-8 

Ring Placement and Scheduling ........................................................................................................8-9 

Handling of Corrosion Rings .............................................................................................................8-9 

Calculation of Corrosion Rate..........................................................................................................8-10 

CORROSION TREATMENT TIPS .............................................................................................................8-10 

Oxygen Scavengers..........................................................................................................................8-10 

NOXYGEN..................................................................................................................................8-10 

Film-Forming Amines .....................................................................................................................8-11 

AMI-TEC.....................................................................................................................................8-11 

KD-700 ........................................................................................................................................8-11 

KD-40 ..........................................................................................................................................8-12 

Scale Inhibitor..................................................................................................................................8-12 

SCALE-BAN ...............................................................................................................................8-12 

PACKER FLUID TREATMENT ................................................................................................................8-12 

Water-Base Drilling Fluid................................................................................................................8-13 

Brine Water......................................................................................................................................8-13 

Invert Emulsion Fluids.....................................................................................................................8-14 


FIGURE 8- 1 CONDUCTIVITY OF BRINES...................................................................................... 8-15 

FIGURE 8- 2 OXYGEN SOLUBILITY VERSUS SALINITY.................................................................. 8-16 

FIGURE 8- 3 OXYGEN SOLUBILITY IN FRESH WATER VERSUS TEMPERATURE (AT ONE 

ATMOSPHERE) .......................................................................................................................... 8-17 

FIGURE 8- 4 SALT (KCL & NACL) CONCENTRATION VS. CORROSION RATE............................ 8-17 

FIGURE 8- 5 EFFECT OF PH ON CORROSION OF IRON ............................................................... 8-18 

FIGURE 8- 6 APPROXIMATE DISTRIBUTION OF H 2 S, HS – , AND S = AS A FUNCTION OF PH....... 8-18 



REVISION 2006 8-i



TABLE 8- 1 THE EFFECTS AND SYMPTOMS OF H 2 S EXPOSURE ...........................................................6 

TABLE 8- 2 RING FACTORS AND FORMULAS (FOR ALL METAL RINGS).................................................9 

TABLE 8- 3 AMINE QUANTITIES FOR SLUG TREATMENT ....................................................................11 

TABLE 8- 4 KD-700 TREATMENT LEVELS IN WATER-BASED DRILLING FLUIDS ...............................12 

TABLE 8- 5 KD-40 TREATMENT LEVELS IN WATER-BASED DRILLING FLUIDS..................................12 


REVISION 2006 


8-ii

CORROSION 

CORROSION 

Chapter 8 

Corrosion is the destruction of a metal by chemical or electrochemical reaction with its 

environment. 

INTRODUCTION 

Corrosion is a severe and costly problem in the drilling industry. Because the tubular goods are 

mostly iron and many drilling fluids are water-based, corrosion is inevitable. Four conditions must 

be met, however, before corrosion can occur. 

1. An anode and a cathode must exist. 

2. The anode and cathode must be immersed in a conductive medium. 

3. A potential difference between the anode and cathode exists. 

4. There must be a coupling to complete the electrical circuit. 

The anode and cathode exist on the drillpipe itself. The drilling fluid may serve as the electrolytic 

medium, and the coupling is created by the drillpipe steel. The potential difference is due to the 

crystalline structure and different metals used in the drilling pipe alloy. 

FACTORS AFFECTING CORROSION RATE 

Several factors affect the rate at which corrosion proceeds. Most of these factors are interrelated 

and have a compound effect on the corrosion rate. The basic relationships are as follows: 

Temperature 

Two different effects occur. 

1. As temperature increases, the corrosion rate increases. If all other factors remain constant, 

the corrosion rate doubles for each 55°F (13°C) increase in temperature. 

2. Increasing temperature decreases the solubility of corrosive gases (O 2 , CO 2 , H 2 S), thus 

decreasing the corrosiveness of the fluid due to these gases. Note that “solubility” here 

refers to the solubility of gas at surface pressure, and does not include chemical reactions 

of gases such as CO 2 and H 2 S with the fluid. 



REFERENCE MANUAL

CORROSION 

Pressure 

Increasing pressure increases the solubility of most corrosive gases. Entrained, or trapped air 

rapidly goes into solution in the fluid as the pressure increases, when the fluid is pumped 

downhole. This dramatically affects the oxygen content of the fluid, increasing corrosiveness. 

pH 

Generally, for steel components, corrosion rate decreases as pH increases. At ambient 

temperatures, as the pH increases, corrosion rates rapidly decrease. Rates are much slower in 

alkaline fluids than in acidic fluids. Little reduction in corrosion rate is obtained as pH is increased 

above 10.5 (see Figure 8 - 5). 

For aluminum drill pipe and components, corrosion rates increase with increasing; pH. This is due 

to the formation of soluble aluminum compounds at high pH. If aluminum components are used in 

the drill string, the pH should be maintained in the range of 6 – 9. 

Dissolved Salts 

The effect of salt concentration is twofold. 

1. As salt concentration increases, conductivity rises increasing the corrosion rate (see Figure 

8 - 1). 

2. Increasing the salt concentration, however, reduces oxygen solubility, (see Figure 8 - 2), 

thereby decreasing corrosion rate. The overall effect is a brief rise in corrosion rate due to 

conductivity until the salt concentration reaches approximately 18,000 mg/L (Cl – ). Above 

this range, as salt concentration increases, oxygen solubility and corrosion rates decrease 

(see Figure 8 - 3 and Figure 8 - 4). 

CORROSIVE AGENTS AND TREATMENTS 

Oxygen (O 2 ) 

1. Source – Atmosphere. Water additions, solids removal, gas separation equipment and 

mixing equipment generally increase oxygen content. 

2. Reactions – Oxygen corrosion of Iron (Fe) is cathodic depolarization reaction. Basically, 

this is what happens when water and oxygen are present. 



REFERENCE MANUAL

CORROSION 

Cathode 

Anode 

1st Step O 2 + 4H + + 4e – →2H 2 O Fe → Fe ++ + 2e − 

2nd Step 

Combined: 2Fe + O 2 + 4H + → 2Fe ++ + H 2 O 

Fe ++ can be further oxidized: 

4Fe ++ + O 2 + (4 + 2x) H 2 O → 2FeO 3 + H 2 O + 8H + 

Note: 

Oxygen is required to drive the reaction at the Cathode to supply (OH – ) for the 

reaction at the Anode. 

3. Attack Types – Pitting, localized (deep pits) or general (evenly distributed shallow pits are 

characteristic). Oxygen results in an etching form of corrosion attack.. 

4. Treating Agents 

• NOXYGEN TM L – Liquid ammonium bisulfite (NH 4 )HSO 3 

• AMI-TEC TM – Film-forming amine (see CO 2 Treating Methods) 

• KD-40 – Film-forming organophosphate corrosion inhibitor. 

• KD-700 – Film-forming organophosphate corrosion inhibitor which also acts as a scale 

inhibitor. 

5. Treating Methods – Inject via chemical pump into the pump suction. Adjust injection 

rates to maintain the sulfite at 75 to 125 mg/L sulfite residual (at the flowline). Where 

filtrate calcium levels are untreatable, or excess lime is present, maintain only an 

indication of sulfite residual. 

Carbon Dioxide (CO 2 ) 

1. Source – Formations and bacterial degradation of certain fluid additives. 

2. Reactions. 

• CO 2 + H 2 O → H 2 CO 3 (Carbonic Acid) 

• H 2 CO 3 + Fe ++ → FeCO 3 + H 2 

3. Attack Type – Severe pitting (worm-eaten appearance). 

4. Treating Agents. 

• Caustic soda – NaOH. 

• Lime – Ca(OH) 2. 

• AMI-TEC – Film-forming amine. 



REFERENCE MANUAL

CORROSION 

• KD - 700 – Scale inhibitor 

5. Treating Methods – Where the intrusion of CO 2 is not severe, neutralization with 

caustic soda and lime, or gypsum by maintaining a pH of 10.0 or higher may be the 

easiest and most cost-effective method. If lime or gypsum is used, SCALE-BAN TM 

should also be used to inhibit the deposition of calcium carbonate scale on the drillpipe. 

This type of scale can aggravate oxygen corrosion cells. Therefore, NOXYGEN 

treatments may have a favorable effect at reducing corrosion. 

When a CO 2 influx has become severe, or where neutralization requires large treatments, several 

steps may be necessary to minimize the corrosive effect on the drillstring. 

• When possible, raise the fluid weight to stop the influx. 

• MIL-TEMP ® or ALL-TEMP ® treatments can be extremely effective at controlling 

rheological properties which will minimize the entrapment of CO 2 and O 2 . The MIL- 

TEMP ® or ALL-TEMP ® will also minimize the flocculating effects of lime additions 

which are essential to precipitate carbonates and balance alkalinities. 

Use AMI-TEC, KD–700 or SCALE BAN TM to form a protective film on the drillstring. 

AMI-TEC should be used with solids-laden fluids. Treatment is accomplished by pumping a 25 

to 35 gal “batch” down the drillpipe on a regular basis. A “batch” is prepared by mixing AMI- 

TEC, diesel oil and/or ISO-TEQ ® in a 1:5 to 1:20 ratio depending on the level of protection 

required. The batch size (number of gallons) depends on the length of the pipe to be coated and the 

annular diameter. KD-700 may be used in all water-based drilling fluids. KD-700 contains an 

organophosphate filming agent. 

In order to effectively maintain an inhibitive film with amines, tourly treatments are recommended. 

Note: 

Entrainment of excessive amounts of amines into drilling fluids may 

result in flocculation of the system, therefore avoid over-treatment. 

• Continue to treat with caustic soda and lime to neutralize the acid gas. In addition, 

treat the system with SCALE-BAN to prevent scale deposition. Treatment with 

SCALE-BAN is 3 to 5 gal per 1000 bbl initially, and 1 to 2 gal each day thereafter. 

• Testing Procedures – Monitor alkalinities and pH periodically to ensure that carbonates are 

precipitated and solubility of carbon dioxide is minimized. The Garrett Gas Train for 

carbonates is necessary to properly monitor the fluid system quantitatively. 

Hydrogen Sulfide (H 2 S) 

WARNING! 

Hydrogen Sulfide Gas is highly poisonous and 

extremely corrosive. Small concentrations in air may be 

fatal in just a few minutes (See Table 8-1). When H 2 S is 

expected, thoroughly familiarize yourself with protective 

measures in advance. 



REFERENCE MANUAL

CORROSION 

1. Source – Formations are the primary source with bacterial and thermal degradation of 

fluid additives contributing minor amounts. 

2. Reaction – H 2 S + Fe ++ + H 2 O → FeS + 2H + 

3. Attack Type – Severe pitting, hydrogen embrittlement or sulfide stress corrosion 

cracking, also generalized pitting and black sulfide coating. Black sulfide coating is 

apparent as a black powder or scale on the drillstring. 

4. Treating Agents 

• Caustic soda – NaOH 

• Lime – Ca(OH) 2 

• MIL-GARD ® – 2ZnCO 3 × 3Zn(OH) 2 

• MIL-GARD ® L – Zinc ammonium NTA 

• MIL-GARD ® FE – Iron based scavenger designed to be used where zinc compounds are 

not environmentally acceptable 

5. Treating Methods – The most effective method of controlling H 2 S involves the use of 

MIL-GARD ® (to scavenge sulfides) in conjunction with pH control, using caustic soda 

and/or lime, to minimize embrittlement. 1 

MIL-GARD ® preventative treatment is recommended at 2-3 lb m /bbl (1 lb m /bbl = 500 

mg/L sulfide) 

MIL-GARD ® FE preventative treatment is recommended at 0.05 gal/bbl (0.12 vol%). 

Treatments of 0.1 gal/bbl (0.24%) will treat approximately 100 ppm H 2 S. 

6. Caustic soda and/or lime should be used in the fluid system to establish an alkaline 

environment. In an alkaline environment, H 2 S is reduced to soluble sulfides which have 

less of a tendency to cause hydrogen embrittlement (see Figure 8 - 6). However, since 

soluble sulfides present in the system are corrosive and will revert to H 2 S if a reduction in 

pH occurs, do not rely on this approach for total control. 

1 Chemical Scavengers for Sulfides in Water-Base Drilling Fluids, Garrett, R. L., Clark, R. K., Carney, L.L., 

and Grantham, C.K., SPE 7499, Journal of Petroleum Technology, June 1979. 



REFERENCE MANUAL

CORROSION 

H 2 S 

(%) 

0 – 2 

Minutes 

2 – 15 Minutes 15 – 30 Minutes 30 Minutes - 1 

Hour 

0.005 0.010 Mild 

conjuctivitis; 

respiratory 

tract irritation 

0.010 0.015 Coughing, irritation of 

eyes, loss of sense of 

smell 

Disturbed 

respiration; 

pain in eyes; 

Sleepiness 

0.015 0.020 Loss of sense of smell Throat and eye 

Irritation 

Throat 

irritation 

Throat and eye 

irritation 

1 – 4 Hours 4 – 8 Hours 8 – 48 Hours 

Salivation and 

mucous 

discharge; 

sharp pain in 

eyes; coughing 

Difficult 

breathing; 

blurred vision; 

light shy 

Increased 

symptoms 

Serious 

irritating 

effects 

Hemorrhage 

and death 

0.025 0.035 Irritation of eyes loss of 

sense of smell 

Irritation of eyes 

Painful 

secretion 

tears; 

weariness 

of 

Light shy; 

nasal catarrh; 

pain in eyes; 

difficult 

breathing 

Hemorrhage 

and 

death 

0.035 0.045 Irritation of eyes loss of 

sense of smell 

Difficult 

respiration 

coughing 

Irritation of eyes 

Increased 

irritation of 

eyes and nasal 

trac; dull pain 

in head 

weariness; 

light shy 

Dizziness; 

weakness; 

increased 

irritation; death 

Death 

0.050 0.060 Coughing; 

collapse; 

unconsciousness 

Respiratory 

disturbances; 

irritation of eyes 

Collapse 

Serious eye 

irritation; 

palpitation of 

heart; 

few cases of death 

Severe pain in 

eyes and head; 

dizziness; 

trembling of 

extremities; 

great 

weakness and 

death 

0.060 - 0.070 

0.080 - 0.100 

0.150 

Collapse; 

Unconsciousness, 

Death 

Collapse; 

Unconsciousness, 

Death 

Table 8- 1 

The effects and Symptoms of H 2 S Exposure 

MIL-GARD ® , MIL-GARD ® FE, or MIL-GARD ® L are used to effectively scavenge all forms 

of sulfide present in the system. The reaction of MIL-GARD ® with sulfides is irreversible, 

forming insoluble zinc sulfide (ZnS), and will occur within a pH range of 3.4 to 14. 



REFERENCE MANUAL

CORROSION 

7. Recommended Treatment 

• NaOH and/or Ca(OH) 2 for pH 10.0 or above. 

• MIL-GARD ® : 2 to 3 lb m /bbl (1 lb m /bbl = 500 mg/L sulfide) 

or 

MIL-GARD ® L: 55 gallons per 1000 bbls of drilling fluid to scavenge 50 – 80 ppm H 2 S. 

or 

MIL-GARD ® FE : 0.1 gal/bbl (0.24%) will treat approximately 100 ppm H 2 S. 

Note: 

MIL-GARD ® L should be used in clear fluids such as drillwater and brines, as 

MIL-GARD ® will settle. Maintain excess MIL-GARD ® in the system when H 2 S 

is suspected or known to be present. Use the Garrett Gas Train to monitor 

excess MIL-GARD ® concentration. 

In the event MIL-GARD ® is unavailable, the next best method to treat for H 2 S involves pH control 

using lime, a filming amine to coat the pipe such as AMI-TEC , or KD–700, and SCALE- 

BAN to prevent scale deposition. Control the pH at 10.5 or above using lime. Do not use caustic 

soda alone, because caustic reacts to form sodium sulfide (Na 2 S) which is extremely soluble and 

H 2 S may be released from the fluid if the pH drops. Lime is recommended instead because it forms 

calcium sulfide (CaS) which is not as soluble and may precipitate from the system. Use AMI- 

TEC or KD-700 to provide a film on the drillpipe to protect against sulfide corrosion. 

Note: 

The use of the Garrett Gas Train and sulfide indicating Dräger Tubes is 

necessary to properly monitor the fluid system for quantitative information on 

sulfides. Techniques utilizing lead acetate paper discs are used only to indicate 

the presence of sulfides in relative concentration. 

When testing for the presence of sulfides in a fluid, it is extremely important that the filtrate used 

be as fresh as possible. In addition, the filtrate should be taken from a sample of fluid freshly 

collected at the flowline. Minimize exposure of the fluid or filtrate to the atmosphere as this 

reduces the accuracy of the test. 

CORROSIVITY OF VARIOUS FLUIDS 

• Non-dispersed – Oxygen entrapment and high dissolved oxygen contents caused by high gel 

strengths and yield points cause these fluids to be regarded as corrosive. This is exacerbated by 

these fluids often having a low pH. 

• Low Solids – Corrosive due to the same rheological conditions as with Non-Dispersed fluids. 

• Polymer Fluids – Usually have lower pH and may contain salts which increase the fluid 

conductivity. Also, these fluids often have rheological properties which allow entrapment of 

oxygen, resulting in high oxygen content. NEW-DRILL ® and PYRO-DRILL ® fluids routinely 

have low corrosion rates. This phenomenon has been observed even when operating in the more 

corrosive environments. Some polymers are natural O 2 scavengers; others are scale inhibitors, 

etc. 



REFERENCE MANUAL

CORROSION 

• Saturated Salt Fluids – Oxygen solubility is low but conductivity is high; chlorides increase 

pitting attack. These fluids may have moderately high oxygen contents due to O 2 entrapment. 

• Dispersed – Slightly corrosive; less oxygen entrapment due to lower gel strengths and yield 

points. In addition, most dispersants have some oxygen scavenging ability. 

• Lignosulfonates – Slightly corrosive due to same conditions indicated in Dispersed. 

Lignosulfonates are, to a certain degree, natural oxygen scavengers. In addition, lignosulfonate 

fluids usually have a pH high enough (9.0 or greater) to greatly reduce corrosion. However, 

where salts are present, conductivity may be increased, thereby increasing corrosivity. 

• Synthetic and Oil-Based Fluids – Considered non-corrosive 

Note: 

Aluminum drillpipe forms an aluminum oxide coating or film that protects it 

from corrosion in many environments. This film is quite stable in neutral 

conditions but is attacked by alkalinities. Therefore, when using aluminum 

drillpipe, the pH of the fluid should be at 9.0 or below. 

USE OF CORROSION COUPONS 

Ring Coupons 

The most effective method of measuring the corrosivity of a drilling fluid involves the use of preweighed 

ring coupons. These rings are sized to fit into the relief groove in the tool joint box. These 

rings are placed in the drillstring and exposed to the fluid for a period of time during the drilling 

operation. After exposure to the system for a minimum of 40 hours, the rings are retrieved, cleaned, 

and reweighed in the laboratory to within 1/10 milligram. The difference between the initial and 

final weights (or the weight lost) is attributed to corrosion, and the corrosion rate is calculated and 

reported as lb m /ft 2 /year or mils/year. The term mils/year refers to the loss of metal in thousandths of 

an inch per year. Two types of rings are available, bare uncoated steel and steel rings having a hard 

plastic backing. See Table 8 - 2. 



REFERENCE MANUAL

CORROSION 

Factors 

Coupon Dimensions 

Series Ring Size mils/yr Series Ring Size mils/yr Series 

F 

H 

K 

N 

P 

3½" E.H. 

3½" I.F. 

4" F.H. 

4" I.F. 

4" E.F. 

4½" F.H. 

4½" E.H. 

4½" I.F. 

280 

252 

207 

195 

193 

F 

H 

203 

192 

189 

3½" E.H. 

3½" I.F. 

4" F.H. 

Same as 4½" E.H. 

Same as 3½" I.F 

2 15 / 16 " 

3 5 / 16 " 

3 13 / 16 " 

280 

252 

3½" 

3 13 / 16 " 

4 3 / 16 " 

R 5" F.H. 219 215 3 17 / 32 " 4 1 / 32 " 

5" E.H Same as 4½" I.F. 

V 5½" F.H. 188 184 4 1 / 32 " 4 5 / 8 " 

5½" E.H. Same as 5" I.F. 

X 5½" I.F. 148 145 4 7 / 8 " 5 l9 / 64 " 

6" E.H. Same as 5½" I.F 

Table 8- 2 Ring Factors and Formulas (for all metal rings) 

F 

H 

7 / 16 " 

7 / 16 " 

7 / 16 " 

5 / 16 " 

11 / 32 " 

7 / 16 " 

Ring Placement and Scheduling 

Placement – Corrosion coupons (rings) are normally placed in the crossover sub above the drill 

collars, and/or in the kelly saver sub, or fluid saver sub above the TIW valve. 

Scheduling – Ring coupons should be run in the drillstring for a minimum of 40 hours. In every 

instance, the time must be reported as accurately as possible, even if the coupon is left in the string 

for several days. 

Handling of Corrosion Rings 

1. Leave the ring in the shipping envelope until immediately prior to placement in the 

drillstring. DO NOT HANDLE THE RING PRIOR TO RUNNING IT. 

2. Wipe the recessed area inside the box end of the tool joint clean of excess fluid and pipe 

dope. 

3. Carefully place the ring down into the recess with the beveled side down. Care should be 

taken to be sure that the ring lays flat within the recess, to avoid mechanical damage when 

the joint is made up. 

4. Record on the shipping envelope the location of the ring coupon and the date and time of 

placement in the string. Run the ring coupon in the drillstring for a minimum of 40 hours, 

but not more than 120 hours. 

5. If the string is out of the hole for an extended time, remove the ring coupon and replace it 

with a new corrosion ring coupon when trip-back in the hole in begins. 



REFERENCE MANUAL

CORROSION 

6. After the run, carefully remove the ring coupon, preventing any mechanical damage that 

could cause a weight loss. 

7. Immediately upon its removal from the string, wash off any excess fluid and fluid solids 

adhering to the ring coupon. Wipe dry and apply a light coat of grease or heavy oil to the 

ring coupon to protect it from atmospheric corrosion. Do not use pipe dope. 

8. Rewrap the ring coupon and record on the shipping envelope the requested information. 

Be sure to record the date and time the ring coupon was installed and removed as well as 

the fluid type and any corrosion control techniques and treatments in effect during the ring 

coupon run. Ship the ring coupon to the processing lab as soon as possible. 

Calculation of Corrosion Rate 

The corrosion rate, based on weight loss (from corrosion coupon analysis), is calculated as follows. 

Corrosion Rate, 

lb 

m 

/ 

ft 

2 

/ yr = 

( K )( Weight Loss, 

gm) 

ExposureTime, 

hr 

2 

Mils / yr = lb / ft / yr × 24.6 

m 

Where: 

K = a constant used for the area of the ring coupon exposed and is printed on the shipping 

envelope. 

Note: 

Constants for plastic coated rings are significantly different and should not be 

interchanged. 

CORROSION TREATMENT TIPS 


NOXYGEN 

NOXYGEN is a liquid and is packaged in 55 gal drums. Best application is by chemical 

injection pump into the suction line. Initial injection rate should be as high as the pump will allow, 

reducing the rate as necessary to obtain the required sulfite residual at the flowline. Maintain 75 to 

125 mg/L sulfite residual. Large diameter boreholes with high circulation rates will require higher 

chemical injection rates. All fittings and valves on the chemical injection equipment should be of 

good quality stainless steel. All fittings should be air tight. Avoid copper and brass fittings. 



REFERENCE MANUAL

CORROSION 

Film-Forming Amines 

O.D. 

Weight/ft 

T & C 

Nominal 

3½" 09.50 

13.30 

15.50 

4" 11.85 

14.00 

15.70 

4½" 13.75 

16.60 

20.00 

5" 16.25 

19.50 

5½" 21.90 

24.70 

Table 8- 3 

I.D. 

2.992" 

2.764" 

2602" 

3.476" 

3.340" 

3.240" 

3.958" 

3.826" 

3.640" 

4.408" 

4.276" 

4.778" 

4.670" 

(1000) 

Linear Feet 

per Gallon 

2.7382 

3.2082 

3.6201 

2.0283 

2.1973 

2.3348 

1.5644 

1.6745 

1.8501 

1.2614 

1.3407 

1.0738 

1.1240 

Amine Quantities for Slug Treatment 

Minimum Slug 

10,000 ft or Less 

in Gallons 

Additional Slug/ 

1000 ft Below 

10,000ft 

08.0 1.00 

12.0 1.25 

15.0 1.50 

19.0 2.00 

23.0 2.50 

AMI-TEC 

AMI-TEC TM may be applied by spraying, dipping, or by “batch” treatments. During trips when 

spraying is not feasible, it is possible to treat the pipe by placing 15 to 20 gal of amine/diesel or 

amine/ISO-TEQ ® “batch” in the annulus below the flowline, and 5 to 10 gal of “batch” inside the 

pipe after it will “pull dry.” In this manner, the pipe may be coated inside and out on trips. AMI- 

TEC TM is oil-soluble and water-dispersible. The addition of AMI-TEC TM to a fluid system can 

cause severe rheological problems and the above recommended treatment with this material should 

minimize its entrainment in the fluid. 

KD-700 

KD-700 is designed to prevent oxygen related corrosion and inhibit the formation of carbonatebased 

scale. It may be used in water-based drilling fluids, aerated drilling fluids, and in mist 

drilling applications. KD-700 is a water-soluble, oil/synthetic dispersible compound and may be 

mixed in solids-free drilling fluid (brines, etc.) in closed systems. This product is organophosphatebased 

and is stable at temperatures up to 350°F. KD-700 forms a strong, protective film on metal 

surfaces and protects tubular goods from oxygen related corrosion. Also, it is effective against acid 

gas corrosion. It has little to no effect on fluid rheological properties. KD-700 disperses readily 

in drilling fluids and may be added through the mud hopper. The recommended initial 

concentration of KD-700 depends on the corrosivity of the drilling environment. For drilling 

fluid systems, typical rates are in the table below. 



REFERENCE MANUAL

CORROSION 

Corrosivity of Drilling Environment 

Initial Treatment, 

gal/100 bbl fluid 

KD-700, ppm 

in mud filtrate 

KD-40 

Table 8- 4 

Low 5 250 

Moderate 10 450 

Severe 15 850 

KD-700 Treatment Levels in Water-Based Drilling Fluids 

KD-40 is a water soluble corrosion inhibitor designed to prevent oxygen related corrosion in 

water-based drilling fluids, aerated drilling fluids and in mist and foam drilling applications. KD- 

40 is an organophosphate formulation that forms a strong, protective film on metal surfaces. KD- 

40 has little or no effect on fluid rheological properties and is effective in fresh water and brine 

water systems under 400 ppm Ca +2 or Mg +2 . KD-40 prevents oxygen related corrosion and is 

effective against acid gas corrosion. KD-40 is effective to 400°F. KD-40 disperses readily in 

drilling fluids and should be added through the mud hopper or chemical barrel. Treatment rates 

depend on the corrosivity of the drilling environment. Residual levels of KD-40 can be 

determined with an organophosphate analytical test kit. 

Corrosivity of Drilling Environment 

Initial Treatment, 

gal/100 bbl fluid 

KD-40, ppm in mud filtrate 

Low to Moderate 2 - 5 150 - 300 

Table 8- 5 

Scale Inhibitor 

SCALE-BAN 

Severe 7 - 12 450 – 700 

KD-40 Treatment Levels in Water-Based Drilling Fluids 

SCALE-BAN is a chemical inhibitor that interrupts and deforms the normal crystalline growth 

pattern of carbonate scales. SCALE-BAN is required in very low concentrations; as little as 3 to 

5 ppm in the system is effective at inhibiting scale formation. Visual inspection of the drillpipe will 

indicate if treatment levels are sufficient. 

When scale is formed, oxygen concentration cells develop beneath the scale, and severe localized 

pitting develops. SCALE-BAN is suggested anytime carbonate gas may be present or when lime 

is used in significant quantities in the circulating system. Where scale deposits are already present 

on the pipe, sandblasting or other cleaning is required to remove the scale. SCALE-BAN will 

not remove existing scale from the pipe. 

PACKER FLUID TREATMENT 

Packer fluids are fluids left between casing and tubing. Casing packs are fluids left between casing 

and open hole. While these fluids may be left in place for a variety of reasons, the principal reasons 



REFERENCE MANUAL

CORROSION 

are (1) to inhibit corrosion and extend the life of the tubular goods, and (2) to provide a hydrostatic 

column for control of pressures in the event of a casing or tubing leak. 

Packer fluids are formulated from three types of basic fluids – water-base drilling fluids, brine 

water, and oil or synthetic fluids. The techniques for formulating a packer fluid are as follows. 

Water-Base Drilling Fluid 

1. Raise the gels to prevent the settling of solids for the extended periods over which the 

fluid will be stagnant. A high temperature-high pressure Cameron test cell can be used to 

provide a stable test environment. 

2. Raise the pH to 11.0 with caustic soda. 

3. Blend 2 - 5 gal of KD-40 corrosion inhibitor uniformly into each 100 bbl of fluid for 

low to moderate corrosion rate protection. This concentration will yield 150 – 300 ppm 

KD-40 in the mud filtrate. For high corrosion rates, increase the concentration of KD- 

40 to 7 – 12 gal per 100 bbl of packer fluid. This concentration of KD-40 will yield 

450-700 ppm KD-40 in the mud filtrate. Residual levels of KD-40 corrosion 

inhibitor in the filtrate can be determined with an organophosphate analytical test kit. The 

quantity of KD-40 used will depend on the type and severity of the corrosion problems 

expected and on the fluid type used. 

4. Corrosion rates should be monitored with drill pipe corrosion coupons. 

Brine Water 

1. To raise the pH for NaCl and KCI to 10.0 - 10.5, use caustic soda (NaOH) or caustic 

potash (KOH). To raise the pH for high-density brines (i.e., CaCl 2 , CaBr 2 , ZnCl 2 , and 

ZnBr 2 ) and combinations of these brines, do not use caustic soda to try to raise the pH. 

Instead, use small amounts of lime (CaOH 2 ) and raise the pH only when absolutely 

necessary. 

2. Add BRINE-PAC ® to the brine water at a concentration of 55 gal per 150 - 200 bbl brine. 

In severely corrosive areas it may be necessary to increase the concentration of BRINE- 

PAC ® . Do not use BRINE-PAC ® with brines containing solids. 

3. Do not circulate or aerate brine water containing BRINE-PAC ® as this will expend the 

oxygen scavenger. 

4. In areas where H 2 S is a problem, add 6 to 12 lb m /bbl of MIL-GARD ® R to control 

sulfide corrosion. 

5. BRINE-PAC ® 2000 is a high temperature corrosion inhibitor for high density brines such 

as calcium and zinc bromide. It is stable up to 450°F and completely soluble in high 

density calcium and zinc brines. BRINE-PAC ® 2000 forms a tough long lasting coating 

on metal surfaces to resist penetration of dissolved organic gases, hydrogen sulfide and 

carbon dioxide. The recommended treatment is 10 – 15 gallons per 100 bbl of brine. 

6. BRINE-PAC ® 1500 is a filming amine type corrosion inhibitor for treatment of low to no 

solids brines. It is water soluble and is effective in fresh water and sodium, potassium and 



REFERENCE MANUAL

CORROSION 

calcium brines at temperatures up to 300°F. BRINE-PAC ® 1500 forms a tough long 

lasting coating on metal surfaces to resist penetration of dissolved organic gases, 

hydrogen sulfide and carbon dioxide. The recommended treatment is 5 – 15 gallons per 

100 bbl of brine 

Invert Emulsion Fluids 

1. In oil or synthetic fluids, the external phase (oil) is nonconductive and, therefore, basically 

non-corrosive. Chemical inhibitor additions to oil fluids are not necessary. 

2. Increase the emulsion stability of the system with treatments of CARBO-TEC ® / OMNI- 

TEC TM and lime. This will provide the stability required for long-term packer fluid 

service. 

3. Raise the yield point and gel strengths with CARBO-GEL ® to prevent solids settling and 

minimize segregation. For high-temperature applications, CARBO-GEL ® / CARBO- 

VIS TM can be supplemented with CARBO-VIS TM HT. Cameron cell testing can be used 

to provide a formulation with stable properties. 

4. Increase the excess lime concentration to 5 lb m /bbl as a precautionary measure against 

possible H 2 S intrusion. MIL-GARD ® (not MIL-GARD ® R) may also be added. 



REFERENCE MANUAL

CORROSION 

2200 

2000 

Conductance Mho/cmi x 10000 

1800 

1600 

1400 

1200 

1000 

800 

600 

0 50 100 150 200 250 300 

mg/L Chlorides X 1000 

Figure 8- 1 

Conductivity of Brines 



REFERENCE MANUAL

CORROSION 

10 

9 

8 

7 

mg/L O2 

6 

5 

4 

3 

2 

1 

0 

0 50 100 150 

mg/L Chlorides x 1000 

Figure 8- 2 

Oxygen Solubility versus Salinity 



REFERENCE MANUAL

CORROSION 

Figure 8- 3 

Oxygen Solubility In Fresh Water Versus Temperature (at one 

atmosphere) 

18 

mg Loss in Weight 

16 

14 

12 

10 

8 

NaCl 

KCl 

6 

0 0.5 1 1.5 2 2.5 

Normality of Solution 

Figure 8- 4 

Salt (KCl & NaCl) Concentration vs. Corrosion Rate 



REFERENCE MANUAL

CORROSION 

Figure 8- 5 

Effect of pH on Corrosion of Iron 

Figure 8- 6 

Approximate Distribution of H 2 S, HS – , and S = as a Function of pH 



REFERENCE MANUAL

Chapter 

Nine 

Hydraulics 

Hydraulics

Chapter 9 


HYDRAULICS ..................................................................................................................................9-1 

INTRODUCTION ................................................................................................................................9-1 

RHEOLOGY.......................................................................................................................................9-1 

Rheological Terms.......................................................................................................................9-1 

Generalized Flow Curves............................................................................................................9-2 

Rheological Models.....................................................................................................................9-3 

DRILL STRING AND ANNULAR HYDRAULICS ...................................................................................9-9 

Fluid Velocity ..............................................................................................................................9-9 

Power Law Constants, n and K .................................................................................................9-11 

Effective Viscosity......................................................................................................................9-11 

Reynolds Number ......................................................................................................................9-12 

Flow Regime and Critical Reynolds Number............................................................................9-13 

Critical Flow Rate .....................................................................................................................9-13 

Fanning Friction Factor............................................................................................................9-14 

Friction-Loss Pressure Gradient...............................................................................................9-15 

Equivalent Circulating Density .................................................................................................9-16 

BIT HYDRAULICS...........................................................................................................................9-16 

Nozzle Velocity ..........................................................................................................................9-17 

Pressure-Drop Across Bit..........................................................................................................9-17 

Hydraulic Horsepower and Impact Force.................................................................................9-18 

Jet Selection...............................................................................................................................9-19 

SWAB AND SURGE .........................................................................................................................9-20 

Equivalent Fluid Velocity..........................................................................................................9-21 

Flow Regime..............................................................................................................................9-22 

Surge or Swab Pressure ............................................................................................................9-22 

Equivalent Fluid Weight............................................................................................................9-22 

Gel-Breaking Pressure ..............................................................................................................9-23 

CUTTINGS TRANSPORT ..................................................................................................................9-23 

Laminar Flow Condition ...........................................................................................................9-25 

Turbulent Flow Condition .........................................................................................................9-26 

Cuttings Transport ....................................................................................................................9-26 

Transport Efficiency ..................................................................................................................9-26 

Cuttings Concentration .............................................................................................................9-27 

SUMMARY......................................................................................................................................9-28 

HYDRAULICS EXAMPLE.................................................................................................................9-29 

Bit Hydraulics............................................................................................................................9-34 

Swab and Surge.........................................................................................................................9-36 

Cuttings Transport ....................................................................................................................9-36 

Cuttings Concentration .............................................................................................................9-37 

NOMENCLATURE ...........................................................................................................................9-38 

REFERENCES..................................................................................................................................9-40 


REERENCE MANUAL 

REVISIOIN 2006 9-i



FIGURE 9 - 1 DIAGRAM FOR RHEOLOGICAL DEFINITIONS..................................................................9-2 

FIGURE 9 - 2 VISCOSITY OF A SIMPLE NEWTONIAN FLUID.................................................................9-2 

FIGURE 9 - 3 VISCOSITY OF A NON-NEWTONIAN FLUID.....................................................................9-3 

FIGURE 9 - 4 VISCOSITY PROFILES OF XANTHAN, HEC AND GUAR, IN 2% KCL, 75°F .....................9-4 

FIGURE 9 - 5 IDEALIZED POWER LAW FLUID......................................................................................9-5 

FIGURE 9 - 6 APPLICATION OF POWER LAW FOR 2.5 LB/BBL XANTHAN GUM IN 3% KCL USING DATA 

FROM 1022 AND 511 SEC -1 ...........................................................................................................9-6 

FIGURE 9 - 7 IDEALIZED BINGHAM PLASTIC FLUID............................................................................9-7 

FIGURE 9 - 8 IDEALIZED HERSCHEL-BULKLEY FLUID........................................................................9-8 

FIGURE 9 - 9 FLOW IN AN ECCENTRIC ANNULUS WITH INNER CYLINDER ROTATION......................9-11 

FIGURE 9 - 10 CUTTINGS TRANSPORT ..............................................................................................9-24 

FIGURE 9 - 11 WELL SCHEMATIC......................................................................................................9-30 


TABLE 9 - 1 REYNOLDS NUMBER SUMMARY..................................................................................9-32 


REVISION 2006 

Page ii 

REFERENCE MANUAL

HYDRAULICS 

HYDRAULICS 

Chapter 9 

A detailed understanding of the role drilling fluids hydraulics play in drilling operations is 

required to adequately support drilling operations. Drilling fluids personnel must understand the 

different concepts, models, and sets of equations which can be used to plan, optimize, and 

calculate the hydraulics of a drilling operation. They must also be aware of the strengths and 

limitations of the engineering software used for hydraulics simulations. 

INTRODUCTION 

Hydraulics calculations are recommended to be carried out using ADVANTAGE SM Engineering 

Software. This is the most accurate tool available to Baker Hughes Drilling Fluids personnel for 

performing hydraulics and hole cleaning simulations. The contents of this chapter are related to 

ADVANTAGE SM Hydraulics and Hole Cleaning. 

The calculation of the various hydraulic parameters of a drilling operation are very important in 

order to control the many variables of the drilling fluid in such a manner that the well can be 

completed safely, with minimum damage to the borehole formations, and at the lowest possible 

cost. The optimization of any particular hydraulic parameter will primarily depend upon the 

location of the drilling operation. For example, it is pointless to maximize bit hydraulic horsepower 

or impact force when drilling in soft formations where the penetration rate is limited by the time 

required to make a connection in the drillstring. 

It is common practice to calculate a number of hydraulic parameters and include this information 

on the fluid report. If any of these parameters are not optimal, alterations to fluid properties, pump 

rate, or even bit nozzles may be made to compensate. This comprehensive approach is desirable 

and is the main reason for developing computer programs such as ADVANTAGE SM Hydraulics 

and Hole Cleaning. The following sections describe the hydraulic parameters and corresponding 

equations used in a drilling operation. 

RHEOLOGY 

Rheology is the study of flow and deformation of matter, including liquids and solids. It is critical 

to remember this definition and be aware that it is not possible to measure, increase, decrease, or 

optimize rheology. Instead we can do this to viscosity or to rheological properties. 

Rheological Terms 

To better understand the impact of rheological properties, Figure 9-1 can be used to provide a 

definition of some basic rheological terms. This illustration depicts the forces acting on a liquid 

between two one square meter plates, which are separated by one meter. The bottom plate is 

stationary and the top plate is moved at a rate of one meter per second. The amount of force 



REVISION 2006 9-1

HYDRAULICS 

required to do this is measured in Newtons. Shear Stress (τ) is defined as the force required to 

move a given area of the fluid. In this case one Newton is required for each square meter of area. 

Figure 9 - 1 Diagram for Rheological Definitions 

The units of shear stress are Newtons per square meter, also known as Pascals. Alternative units for 

shear stress are dynes per square centimeter and pounds force per square inch. Shear Rate (γ& ) is 

defined as the rate of movement of the fluid between the plates. It is determined by dividing the 

velocity difference between the plates by the distance between them. This can also be called the 

velocity gradient. In this case, the shear rate or velocity gradient is one meter per second per meter 

of fluid and is thus measured in reciprocal seconds (sec -1 ). Viscosity (η) is defined as the ratio of 

shear stress over shear rate. Consequently, the units are Newton seconds per square meter or Pascal 

seconds. Another common unit is the Poise (dyne second/centimeter 2 ). One centipoise is equal to 

one milliPascal second (1cP = 1 Pa.s). NOTE: in oilfield literature, μ is most often substituted with 

η to designate viscosity. 

Generalized Flow Curves 

Figure 9-2 illustrates the viscosity versus shear rate curve for water, a simple Newtonian fluid. For 

a Newtonian fluid, viscosity is independent of shear rate. 

Figure 9 - 2 Viscosity of a Simple Newtonian Fluid 

When a water-soluble polymer is added to water, the curve changes dramatically, as indicated in 

Figure 9-3. 



REVISION 2006 9-2

HYDRAULICS 

Figure 9 - 3 Viscosity of a Non-Newtonian Fluid 

Of significance, there is usually a region at both low and high shear rates where viscosity is 

independent or nearly independent of shear rate, and a section in between that exhibits strong shear 

rate dependence. This middle region is usually referred to as the power law region. In some fluids, 

it can be difficult to reach shear rates that are high or low enough to observe the upper and lower 

Newtonian regions. 

Fluids are generally classified as Newtonian (shear rate independent) or Non-Newtonian (shear rate 

dependent). Newtonian fluids follow a simple relationship between shear stress and shear rate. 

Their viscosity is a constant as described by the slope of the line in a linear plot of shear stress 

versus shear rate (Figure 9-2). Air, water and light hydrocarbon oils are examples of Newtonian 

fluids. 

where: 

τ = μ & γ .............................................................................................(1) 

τ = Shear stress 

µ = Viscosity 

γ& = Shear rate 

The viscosity of Non-Newtonian Fluids at a specific shear rate can also be defined by Equation 2; 

however, for these fluids, viscosity will vary depending on the shear rate. 

Rheological Models 

Several mathematical models have been developed to describe the shear stress/shear rate 

relationship on Non-Newtonian fluids. These models are used to characterize flow properties in an 

effort to determine the ability of a fluid to perform specific functions. Misapplication of rheological 

data can result in an over-simplification or exaggeration of fluid features, accompanied by the 

failure to perform a specific task. In order to optimize fluid performance, an in-depth discussion of 

data acquisition, rheological models and their inherent limitations is necessary. 

Rheological evaluation of oil field fluids is generally accomplished using concentric cylinder 

viscometers. Typically, these instruments provide a limited number of shear rates ranging from 5.1 

to 1022 sec -1 . Data generated with these instruments are analyzed using empirical models 

developed to describe the flow of Non-Newtonian fluids. The most frequently applied models are 



REVISION 2006 9-3

HYDRAULICS 

the Bingham Plastic, Power Law and Herschel-Bulkley models. While the Bingham model may 

have sufficed during the evolution of clay based drilling fluids, it is deficient when describing the 

overall behavior of polymer or invert emulsion drilling fluids. Furthermore, the presence of an 

upper and lower Newtonian region, coupled with a region of power law behavior (Figure 9-3), 

makes the interpretation and application of rheological data a challenging task. This is further 

complicated by the fact that the onset of Newtonian behavior varies, depending on the viscosifier 

or fluid system under consideration (Figure 9-4). 

Power Law Model 

Figure 9 - 4 Viscosity Profiles of Xanthan, HEC and Guar, in 2% KCl, 75°F 

One of the more widely used models for describing the behavior of oil field fluids is the power law 

model. This model (Equation 2) is valid for the linear, i.e. center section, of the curve shown in 

Figure 9-3. In the power law model, the viscosity term from the Newtonian model is replaced with 

a constant, K, termed the consistency index, which serves as a viscosity index of the system. The 

consistency index has the unusual set of units, Force-sec n /Area. In addition, the shear rate term is 

raised to the n th power, thus the term power law. The factor, n, is called the power law index which 

indicates the tendency of the fluid to shear thin. As the value of the flow behavior index deviates 

from one, the fluid becomes increasingly non-Newtonian. 

τ 

& 

n 

= K γ ……………………………………………………………………. (2) 

where: 


K = Consistency index 


n = Power law exponent 



REVISION 2006 9-4

HYDRAULICS 

Figure 9 - 5 Idealized Power Law Fluid 

When the log of the shear stress is plotted against the log of the shear rate (Figure 9-5), a straight 

line with a slope equal to n and an intercept (at a shear rate of one) equal to log K, results. A plot of 

the log of the viscosity versus log of the shear rate also results in a straight line. 

Most polymer solutions and invert emulsion drilling fluids are pseudoplastic. In this case, increased 

shear rate causes a progressive decrease in viscosity. This is due to alignment of the polymer 

chains, or structural elements of the fluid, along the flow lines. For pseudoplastic fluids, the value 

of the flow behavior index, n, ranges from about 0.1 to < 1.0. When the n value is equal to 1.0, the 

power law reduces to the Newtonian model. The further that n is reduced from 1.0 the more the 

fluid deviates from Newtonian behavior. Although this is one of the most popular models used, no 

known fluid exhibits power law behavior over the entire range of shear rate conditions. Therefore, 

the primary drawback is the limited shear rate range over which it is valid. Care must be taken to 

use data within the power law region to accurately calculate parameters (n and K). For example, 

with xanthan gum, calculating n and K from 600 rpm (1022 sec -1 ) and 300 rpm (511 sec -1 ) on a 

concentric cylinder viscometer, will result in inaccurately high n and low K values as compared to 

values obtained at lower shear rates. As a result, at shear rates below 1.0 sec -1 , predicted viscosities 

using these inaccurate n and 0 values will be much lower than measured values (Figure 9-6). 



REVISION 2006 9-5

HYDRAULICS 

Figure 9 - 6 Application of Power Law for 2.5 lb/bbl Xanthan Gum in 3% KCl Using 

Data from 1022 and 511 sec -1 

This example illustrates the need to apply this model within the power law region of a particular 

fluid to assure accurate predictions of viscosity. 

Bingham Plastic Model 

The other two parameter model which has been widely used in drilling fluid applications is the 

Bingham Plastic model (Equation 3). Fluids that exhibit Bingham Plastic behavior are 

characterized by a yield point (τ 0 ) and a plastic viscosity (μ p ) that is independent of the shear rate 

(Figure 9-7). 

τ = τ 0 + μ p γ& ……………………………………………………………… (3) 

where: 


τ 0 = Yield point 

μ p = Plastic viscosity 




REVISION 2006 9-6

HYDRAULICS 

Figure 9 - 7 Idealized Bingham Plastic Fluid 

The presence of a yield stress means that a certain critical shear stress must be exceeded before 

flow can begin. If the fluid exhibits a linear increase in shear stress with shear rate after the yield 

value is exceeded, it is called a Bingham Plastic fluid. While some fluids exhibit a yield point, most 

oil field fluids show shear rate dependence after flow is initiated. This model is interesting but not 

very useful in describing the behavior of polymer or invert emulsion fluids. In the oil field, the 

Bingham Plastic model has been used to describe the behavior of some clay based drilling fluids 

and a few cement slurries. An extension of the Bingham Plastic model to include shear rate 

dependence is the Herschel-Bulkley model, described later. 

There are several models that involve the use of three or more adjustable parameters. It is necessary 

to include a third parameter to describe the flow of fluids in the upper or lower Newtonian region 

as well as the power law region. 

Herschel-Bulkley Model 

Fluids that exhibit a yield point and viscosity that is stress or strain dependent cannot be adequately 

described by the Bingham Plastic model. The Herschel-Bulkley model (Figure 9-8) corrects this 

deficiency by replacing the plastic viscosity term in the Bingham Plastic model with a power law 

expression (Equation 4). 

where: 

τ = τ 0 + Kγ& n ………………………………………………………………….. (4) 


τ 0 = Yield point 


n 

γ& = Power law expression 

This model is useful for describing a wide range of fluids used in oil field operations. The model is 

reduced to the power law if there is no yield stress and to the Bingham model if n = 1. The primary 

limitation of this and all other models that cannot be linearized is curve fitting to evaluate model 

parameters. Computers and non-linear curve fitting techniques have overcome this problem. Many 

publications have shown the usefulness of the three parameter Herschel-Bulkley model and this 



REVISION 2006 9-7

HYDRAULICS 

model is generally accepted as the best available for describing the flow properties of drilling 

fluids. 

Robertson-Stiff Model 

Figure 9 - 8 Idealized Herschel-Bulkley Fluid 

The Robertson-Stiff equation, like the Herschel-Bulkley model, is a three variable model. Like the 

Herschel Bulkley model it has been found to provide very close approximations for pressure losses 

in the circulating system in most drilling situations. The Newtonian, Bingham Plastic and power 

law models are specific cases of the Roberson-Stiff model. 

In ADVANTAGE SM a least squares method is used to determine the rheological parameters for the 

Robertson-Stiff model also. This considers all the available Fann readings to determine the 

rheological parameters for the Robertson-Stiff model. If Plastic Viscosity and Yield Point are 

entered instead of Fann readings, the Fann readings at 300 and 600 [RPM] can be recalculated. 

Additionally, the 10sec gel strength can be used to approximate the Fann reading at 3 [RPM]. 

where: 

τ = K× 

n 

( γ + ) ...........................................................................................(5) 

0 

γ 



γ 0 = Shear rate intercept 

γ = Shear rate 

n = Power law index 

Rheological Models in ADVANTAGE 

In ADVANTAGE Reporting it is possible, and recommended, to input at least Fann readings for 

600, 300, 200, 100, 6 and 3 rpm. The 10 second, 10 minute and 30 minute gel strengths are also 

entered. From these numbers the Plastic Viscosity and Yield Point are derived along with n and k 

for the power law model. 

The hydraulics equations in ADVANTAGE SM Reporting are API 13-D equations and utilize the 

power law. These equations do not account for the effect of temperature and pressure on fluid 



REVISION 2006 9-8

HYDRAULICS 

density and rheological properties. This means that in most situations that the results will contain 

inaccuracies. It is important to be aware of this and the causes of the inaccuracies. 

In ADVANTAGE SM Engineering there are two hydraulics models – the BP model and the BHI 

model. These two models and the rheological models they use will now be discussed separately. 

BP Model 

The desired input parameters are the Fann readings – preferably at least the 600, 300, 200, 100, 6 

and 3 rpm readings - plus the 10 second and 10 minute gels. If only Plastic Viscosity and Yield 

Point are entered instead of the Fann readings the Bingham model will be used for hydraulics 

equations. If the Fann readings are entered, then Herschel Bulkley will be used for pressure loss 

calculations. The cuttings concentration in the drilling fluid is not taken into account in ECD 

calculations. The BP model does not allow for temperature and pressure effects on fluid 

density and rheological properties. 

BHI Model 

The Robertson-Stiff and Herschel Bulkley models most accurately model drilling fluids, with the 

Herschel Bulkley being the recommended model for calculating pressure losses. It is not advisable, 

nor technically correct, to change models in order to get the best fit between modeling results and 

field data. 

In the BHI model it is possible to use Fann 35 data or Fann 75 data, though the latter is more 

accurate, especially when using invert emulsion drilling fluids. In Spreadsheet Hydraulics the 

Fann 35 readings are used and system and bit pressure losses are calculated at ten different flow 

rates using the selected model. The Calc. Fann Fit button can be selected in order to check which 

model best fits the viscometer readings. The default model in the hole cleaning mode for annular 

pressure loss calculations is the Herschel Bulkley model. A selected model can be used to calculate 

drill string and drill bit pressure losses. In System Mud Hydraulics with Hole Cleaning Herschel 

Bulkley is used for annular pressure loss calculations using the input flow rate. In the HT-HP 

mode Fann 70 / 75 data must be entered corresponding to the temperature and pressure conditions 

in the well. When hole cleaning is taken into account the Herschel Bulkley model is used to 

calculate annular pressure losses, but the manually selected model is used for all other pressure 

losses. In this mode either spreadsheet Hydraulics or System Mud Hydraulics may be selected. 

DRILL STRING AND ANNULAR HYDRAULICS 

This section on drill string and annular hydraulics is designed to create a basic understanding of 

how the various calculations are carried out. The discussion below is based on the use of the power 

law rheological model. In ADVANTAGE Engineering, the rheological model can be selected and 

this directly affects hydraulics calculations as different values are derived for the various factors 

using the different models. The most commonly used models are the Herschel-Bulkley and 

Roberson-Stiff models, and of these the Herschel-Bulkley is recommended as it is capable of fitting 

data from power law fluids, Bingham Plastic fluids and power law fluids with a yield stress. 

Fluid Velocity 

The flow of drilling fluid through the surface equipment, drill string, and annulus may be 

considered to be flow through a series of circular pipes. The diameter and cross-sectional area in 



REVISION 2006 9-9

HYDRAULICS 

each portion of the circulating system vary from one part to the other. If the volumetric flow rate 

through the circulating system remains constant, then the speed or velocity of the drilling fluid 

changes in relation to the cross-sectional area for that particular part of the system. The highest 

velocities occur where the diameter is the smallest. The fluid velocity is the first and most 

important step in making hydraulic calculations in the drilling operation. 

For fluid velocity in the drill string, 

where: 

V 

0.408Q 

p = ----------------- 

D 2 

V p = fluid velocity in pipe, ft/sec 

Q = volumetric flow rate, gal/min 

D = inside diameter of the pipe, in. 

For fluid velocity in the annulus, 

V 

0.408Q 

a = ----------------------------------- 

(D 2 ) 2 – ( D 

2 1 ) 

where: 

V a = annular velocity, ft/sec 

Q = volumetric flow rate, gal/min 

D 2 = hole diameter, in. 

D 1 = outside diameter of the drill pipe/collar/etc, in. 

Note that the above equations describe average flow rate in the drill string and the annulus. In the 

annulus on a directional well there will be a series of velocities in the annulus. Figure 9-9 

illustrates the fluid velocity distribution in an eccentric annulus with a rotating inner cylinder. 

This is the type of flow pattern to be expected in a deviated well. 



REVISION 2006 9-10

HYDRAULICS 

Figure 9 - 9 Flow in an Eccentric Annulus with Inner Cylinder Rotation 

Power Law Constants, n and K 

As described above, the consistency factor, K, describes the thickness of the fluid and is somewhat 

analogous to the effective viscosity. The flow behavior index, n, indicates the degree of non- 

Newtonian behavior. These two constants can be calculated from any two values of shear rate/shear 

stress relationships. When readings are obtained from a V-G meter at 600 rpm, 300 rpm, and 3 

rpm, two sets of n and K can be developed corresponding with fluid flow inside the drill pipe and 

fluid flow in the annulus. This is done to improve the accuracy of hydraulic calculations in the drill 

pipe or annulus since the Power Law Model does not exactly describe the behavior of drilling 

fluids. 

To obtain the power law constants corresponding to fluid flow inside the drill pipe, the 600 rpm 

and 300 rpm readings are used. 

n 

p 

⎛ θ 

= 3.32log 

⎜ 

⎝ θ 

5.11× 

θ 

= 

1022 

n p 

600 

600 

300 

⎞ 

⎟ 

⎠ 

To obtain the power law constants corresponding to fluid flow in the annulus, the 300 rpm and 

3 rpm (or initial gel strength) readings are used. 

n a 

⎛ θ 

= 0.5 log 

⎜ 

⎝ θ 

5.11× 

θ 

K 

a 

= 

n 

5.11 a 

300 

300 

3 

⎞ 

⎟ 

⎠ 

where, 

n = flow behavior index, dimensionless 

K = consistency factor, poise. 

Effective Viscosity 

Since all drilling fluids are shear-thinning to some degree, the viscosity of the fluid changes with a 

change in the shear rate. In order to calculate other hydraulic parameters, the effective viscosity at a 

given rate of shear must be known. By definition, effective viscosity is the viscosity of a 

Newtonian fluid that exhibits the same shear stress at the same rate of shear. 

The equation for effective viscosity in pipe is: 

96V 

n p – 1 

μe p 

= 100K p 

p ------------ 

D 

where, 



REVISION 2006 9-11

HYDRAULICS 

μ ep 

= 

effective viscosity inside pipe, cp 

K p = power law constant, poise 

V p = bulk fluid velocity in pipe, ft/sec 

D = inside diameter of the pipe, in. 

n p = power law constant for pipe 

The equation for effective viscosity in the annulus is: 

where: 

144V 

μ e 100K a 

a ------------------ n a – 1 

= 

a 

D 2 – D 1 

µ ea = the annular effective viscosity, cp 

K a = power law constant, poise 

V a = annular fluid velocity, ft/sec 


D 1 = outside pipe diameter, in. 

n a = power law constant for annulus 

Reynolds Number 

After calculating the effective viscosity, μ e , as a function of fluid velocity and power law constants, 

the Reynolds Number is calculated to determine the flow regime of the fluid (i.e., laminar, 

transitional, or turbulent flow). 

The equation for Reynolds Number inside the pipe is: 

where: 

928( V p )( 

D p )ρ 

Re p = ------------------------------------- 

3n 

μ ep 

----------------- p + 1 n p 

4n p 

Re p = Reynolds Number inside the pipe 

V p = fluid velocity inside the pipe, ft/sec 

D p = inside diameter of the pipe, in. 

ρ = fluid density, lb m /gal 

μe p 

= effective viscosity inside pipe, cp 

n p = power law constant for pipe 

To obtain the Reynolds Number in the annulus: 

928V 

Re a ( D 2 – D 1 )ρ 

a = ------------------------------------------ 

2n a + 1 

μ e 

----------------- n a 

a 3n a 

where: 

Re a = Reynolds Number in the annulus 

V a = fluid velocity in the annulus, ft/sec 



REVISION 2006 9-12

HYDRAULICS 




μ ea 

= effective viscosity in the annulus, cp 

n = power law constant for the 

a 

annulus 

Flow Regime and Critical Reynolds Number 

As discussed in the Rheology section of Chapter 2, fluid flow may be laminar, transitional, or 

turbulent. In the experiments conducted by Osborne Reynolds in 1883, he found in observing the 

flow of water in a circular pipe that the onset of turbulent flow began at a calculated Reynolds 

Number of 2000 and was completely turbulent flow at a Reynolds Number of 4000. He then 

defined a Reynolds Number between 2000 and 4000 as transitional flow – neither completely 

laminar nor turbulent. 

Since drilling fluids don't behave exactly like the flow of water, the Reynolds Numbers at which 

flow changes from laminar to turbulent flow is not the same as water. The following equations 

have been developed to determine the critical Reynolds Number (Rec) at which the flow regime 

changes. 

Laminar Flow 

Rec < 3470 – 1370n 

Transitional Flow 

3470 – 1370n ≤Rec ≤4270 – 1370n 

Turbulent Flow 

Rec > 4270 – 1370n 

Critical Flow Rate 

In the drilling operation, it is usually desirable to have laminar flow in the annulus. In order to have 

laminar flow, the critical Reynolds Number for laminar flow (3470 – 1370n a ) in the annulus must 

not be exceeded. It is then easy to calculate the critical flow rate for the critical Reynolds Number 

in two steps. 

First, obtain the critical velocity by solving the following equation: 

Where: 

V 

c 

⎡ 

⎢ 

⎢ 

= 

⎢ 

⎢ 

⎢ 

⎣ 

( 3470 −1370 

)( 100) 

928ρ 

( D − D ) 

V c = critical annular velocity, ft/sec. 

2 

na 

1 

K 

a 

⎡ 2n 

a 

+ 1⎤ 

⎢ ⎥ 

⎣ 3n ⎦ 

⎡ 144 ⎤ 

⎢ ⎥ 

⎣D 

2 

− D1 

⎦ 

a 

1−n 

a 

na 

⎤ 

⎥ 

⎥ 

⎥ 

⎥ 

⎥ 

⎦ 

1 

2−na 



REVISION 2006 9-13

HYDRAULICS 

Then solve for Q c , 

where: 

Q c 

= 2.45( V c )[( D 2 ) 2 – ( D 1 ) 2 ] 

Q c = critical flow rate, gal/min 

Fanning Friction Factor 

The Fanning Friction Factor (f) expresses the resistance to flow of a fluid at the pipe wall and is a 

function of the Reynolds Number and of the surface conditions at the wall. 

Laminar flow in pipe, 

f 

p 

= 16 

Re 

p 

Transitional flow in pipe, 

f 

⎡Re 

p 

− 

= ⎢ 

⎣ 

p 

( 3470 −1370n 

) 

800 

p 

⎤ 

⎥ 

⎦ 

× 

⎡ 

⎢ 

⎢⎣ 

a 

− 

16 

⎤ 

+ 

⎥⎦ 

⎥ 

( 4270 −1370np 

) 3470 −1370np 

3470 −1370np 

16 

where: 

log n 

p 

3.93 

a = 

+ 

50 

1.75 − log n 

b = 

7 

Turbulent flow in pipe, 

p 

f p 

= 

-------- 

a 

b 

Re p 

where: 

logn a p + 3.93 

= ----------------------------- 

50 

1.75 – logn b = ----------------------------- 

p 

7 

Laminar flow in annulus, 

f = 

a 

24 

Re 

a 



REVISION 2006 9-14

HYDRAULICS 

Transitional flow in annulus, 

⎡Rea 

− 

f 

a 

= ⎢ 

⎣ 

where: 

( 3470 −1370n 

) 

800 

a 

⎤ 

⎥ 

⎦ 

× 

⎡ 

⎢ 

⎣ 

a 

b 

( 4270 −1370n 

) 3470 −1370n 

a 

3470 −1370n 

a 

a 

− 

24 

⎤ 

⎥ + 

⎦ 

24 

log n 

a = 

50 

a + 

3.93 

1.75− 

log n 

b = 

7 

a 

Turbulent flow in annulus, 

f a 

= 

------------ 

a 

b 

Re a 

where: 

a = 

n a 

log + 3.93 

----------------------------- and b = 

50 

Friction-Loss Pressure Gradient 

1.75 – logn ----------------------------- a 

7 

The total pressure required to circulate the drilling fluid includes not only the pressure drop across 

the bit nozzles, but also the friction losses throughout the surface system, drillstring, and annular 

sections. The appropriate friction factor (from previous section) is substituted into the Fanning 

equation to determine the friction-loss pressure gradient. The appropriate values must be used for 

each section of pipe or annulus sections with different diameters. 

Friction-Loss gradient in pipe: 

where: 

P 

------ p 

L m 

= 

2 

( f p ) ( V p ) ( ρ) 

---------------------------------- 

25.81D 

P p 

L m 

------ = pressure loss per measured depth, psi / ft 

and, 

f p = friction factor (laminar, transitional, or turbulent) 

V p = bulk velocity in pipe, ft/sec 



REVISION 2006 9-15

HYDRAULICS 


D = inside diameter of pipe, in. 

Friction-loss gradient in annulus: 

P 

P a = ------ a 

× A n nu l a r L e n g t h 

L m 

where: 

P a 

------ 

L m 

= 

2 

( f a ) ( V a) ( ρ) 

------------------------------------- 

25.81( D 2 – D 1 ) 

P a 

------ = pressure loss per measured depth, psi / ft 

L m 

and, 

f a = friction factor (laminar, transitional, or turbulent) 

V a = bulk velocity in annulus, ft/sec 




Equivalent Circulating Density 

The pressure required to overcome the total friction losses in the annulus, when added to the 

hydrostatic pressure of the fluid, gives the Equivalent Circulating Density (ECD) as follows. 

where: 

ECD 

= 

ΣP 

-------------------------------- a 

+ ρ 

(.052)( TVD) 

ECD = equivalent circulating density, lb m /gal 

ΣP a = sum of the friction loss in all annular intervals, psi 

TVD = true vertical depth, ft 


Note: Temperature and pressure affect both the density of fluids and their rheological properties, 

both of which affect the ECD. 

BIT HYDRAULICS 

Conventional bits incorporate a number of nozzles through which the drilling fluid is forced at high 

velocity. This fluid velocity results in hydraulic forces that affect penetration rate, bit cleaning, and 

other parameters. While it is desirable to have most, if not all, of these parameters at an optimum 



REVISION 2006 9-16

HYDRAULICS 

value, such gains must not be made at the expense of some other detrimental effect. For example, 

maximizing penetration rate may not necessarily result in the lowest cost per foot of drilled hole. 

Other factors such as reduced bit life or pack-off of drilled cuttings in the annulus may increase 

cost. As with all hydraulic parameters, bit hydraulics should be used in an overall hydraulic 

evaluation of the drilling operation. Optimizing bit hydraulics tends to be more critical with water 

based drilling fluids than with invert emulsion drilling fluids. 

Nozzle Velocity 

The velocity of the drilling fluid is determined by the circulation rate and the total area of the 

nozzles in the bit. Even if the jet nozzles are of different sizes, the velocity is the same through 

each. In other words, the velocity is independent of the individual diameters of the nozzles due to 

the mechanics of fluid flow through an orifice. 

First calculate the total nozzle area. 

2 2 

2 

( J 1 ) + (J 2 ) + ... + ( J n ) 

A t 

= ------------- --------------------------------------------- 

1303.8 

where: 

A t = total nozzle area, in 2 . 

J n = nozzle size, 32nds of an inch (i.e., 11, 12, etc.) 

Then nozzle velocity: 

Q 

Vn 

= 

3.117A 

t 

where: 

V n = nozzle velocity, ft/sec 

Q = flow rate, gal/min 

A t = total nozzle area, in. 2 

Pressure-Drop Across Bit 

When the drilling fluid passes through the jet nozzles, a pressure-drop due to friction losses occurs. 

This pressure-drop has a number of important applications, such as optimizing hydraulic 

horsepower or impact force of the fluid on the formation and improving chip removal and bit 

cleaning. The bit nozzles are designed to maximize the portion of pressure loss in the circulating 

system that may be used to perform work on the formation. Analysis of pressure-drop through an 

orifice such as a jet nozzle can be complicated; however, nozzle coefficients have been empirically 

determined that account for turbulence and velocity through the orifice. The total pressure-drop 

across the bit is derived from an energy balance called Bernoulli's Equation and includes a nozzle 

coefficient of 0.95. It is calculated by, 

P n 

= 

--------------------------------------------------------------------- 

156( ρ )Q 2 

J 1 ) 2 2 

[( 

+ ( J 2 ) + ... + ( J n ) 2 

] 2 



REVISION 2006 9-17

HYDRAULICS 

where: 

P n = total pressure-drop across bit, psi 



J n = nozzle size, 32nds of an in. (i.e., 11, 12, etc.). 

Hydraulic Horsepower and Impact Force 

Hydraulic horsepower is the product of pressure and flow rate, whereas impact force is the product 

of fluid density, flow rate, and velocity. Both horsepower and impact are measures of the amount 

of work from the drilling fluid available at the bit, although derived differently. Additionally, both 

parameters are affected by the circulation pressure losses in all parts of the circulation system. 

Hydraulic horsepower at the bit is given by: 

where: 

HHP = QP n 

1714 

HHP = hydraulic horsepower, hp 


P n = total pressure-drop across bit, psi. 

Some operators prefer to analyze the ratio of hydraulic horsepower to hole area. This is 

calculated by: 

2 ( 1.2732) 

HHP 

HHP / in = 

2 

D 

where: 

Impact force is given by: 

where: 

HHP/in 2 = hydraulic horsepower per in. 

D = hole size or bit size, in. 

F i 

ρ( Q)V = ------------------- n 

1932 

F i = impact force, lb f 



V n = nozzle velocity, ft/sec. 

2 



REVISION 2006 9-18

HYDRAULICS 

Jet Selection 

When optimizing a hydraulics program, it is sometimes desirable to maximize either the hydraulic 

horsepower or the impact force within the constraints of minimum and maximum flow rates and 

maximum standpipe pressure. A detailed derivation of maximizing either parameter is not given 

here, however, a common assumption is that maximum hydraulic horsepower occurs when 65% of 

the total available standpipe pressure is developed at the bit. Correspondingly, maximum impact 

force occurs when 48% of the total available standpipe pressure is developed at the bit. It can be 

easily seen that maximizing both hydraulic horsepower and impact force cannot be done 

simultane ously. The calculation for maximizing either hydraulic horsepower or impact force 

involves finding a total nozzle area required to develop the specified pressure loss at the bit, and 

then simply selecting the required number and available nozzle sizes that give the total nozzle area. 

It should be noted that the jet nozzles need not be all of the same size. 

It is sometimes necessary to run a bit with large nozzles in order to circulate lost circulation 

material. This frequently causes a great decrease in hydraulic horsepower or impact force. 

Downhole motors, MWD and LWD equipment all contribute significantly to drill string pressure 

losses. These pressure losses may be so great as to restrict the ability to optimize bit hydraulics. 

However, in many cases, it is possible to maintain reasonably good hydraulics by reducing the 

number of nozzles. For example, two 16 / 32 in. nozzles have approximately the same area as three 

13 

/ 32 in. nozzles. 

To find the total jet area for maximum hydraulic horsepower or impact force, 

where: 

A t 

Q 

= --------------------------------------------------- 

2.96 (---------------------------- 1238.5 )CP 

1/2 

ρ 

A t = optimum total nozzle area, in. 2 


P = available standpipe pressure, psi 

ρ = fluid density, lb m/gal 

C = Constant: 0.65 for maximum HHP, 

0.48 for maximum impact force, 

0.59 for HHP-Impact compromise. 

Once the total jet area is obtained, simple algorithms are used to back-calculate jet sizes. The 

following algorithms show how jet sizes can be obtained for any number of jets. 

J 1 

= 1303.797 1 ⁄ 2 

---------------------A t 

N 

1303.797 

J --------------------- ⎛ 

2 

N – 1 

A ( J ⎞ 

= ⎜ – t 130 ------- 

1) 

--------------⎟ 

⎝ 3.797⎠ 

2 

1/2 



REVISION 2006 9-19

HYDRAULICS 

where: 

2 2 1/2 

1303.797 

J ---------------------A ⎛ ( J 1 ) + ( J 2 ) ⎞ 

3 = ⎜ – ------------------------------- 

N – 2 ⎝ 

t ⎟ 

1303.797 ⎠ 

J 

1303.797 

--------------------- 4 

N– 

3 

A J 1) 

2 2 2 

⎛ ( + (J 2) + (J 3 ) ⎞ 1/2 

= ⎜ – -------------------------------------------------- 

⎝ 

t ⎟ 

1303.797 ⎠ 

2 2 

J 

1303.797⎛ ( J 

N – 3 --------------------- A 1 ) + ... + J N – 4 ⎞ 1/2 

= ⎜ 

4 t – ------------------------------------------⎟ 

⎝ 1303.797 ⎠ 

2 2 

J 

1303.797⎛ ( J 

N – 2 --------------------- A 1 ) + ... + J N – 3 ⎞ 1/2 

= ⎜ 

3 t – ------------------------------------------⎟ 

⎝ 1303.797 ⎠ 

2 2 

J 

1303.797⎛ ( J 

N – 1 --------------------- A 1 ) + ... + J N – 2 ⎞ 1/2 

= ⎜ 

2 t – ------------------------------------------⎟ 

⎝ 1303.797 ⎠ 

2 2 

J 

1303.797⎛ ( J 

N --------------------- A 1 ) + ...+ J N – 1 ⎞ 1 ⁄ 2 

= ⎜ 

1 t – ---------------------------------------- ⎟ 

⎝ 1303.797 ⎠ 

N = the number of jets desired 

J 1 , J 2 , etc. = the jet size in 32nds of an in., which must be rounded to the nearest whole 

number (i.e., 11, 12, etc.). 

ADVANTAGE SM Engineering programs contain the necessary tools to recommend bit nozzle sizes. 

SWAB AND SURGE 

Tripping into or out of a wellbore involves movement of the drillstring within a non-circulating 

fluid colum n. Many blowouts have occurred when tripping out of the hole, while lost-returns 

problems are often associated with trips back into the hole. The common factor in both cases is the 

movement of the drillstring and its effect on hydrostatic pressure, typically at the last casing seat 

and at total measured depth. Swab and surge pressures are caused by the combined effects of 

viscous drag of the drilling fluid on the drillstring and annular velocity due to displacement of the 

drilling fluid by the drillstring. 

The key variables influencing swab and surge pressures are: 

• Wellbore geometry – Such factors as gauge hole, cuttings beds and washouts can have a 

very strong effect on the wellbore geometry. 

• Fractures pressures, pore pressures and depleted zones – These determine how high/low 

pressure surges a wellbore will safely tolerate. 

• Drilling fluid density and rheological properties – Gel strengths are considered in 

calculations and directly impact the pressure necessary to initiate fluid flow. 

• Tripping speed – This is the most easily controlled variable and is the one that is used by 

ADVANTAGE SM Engineering to limit swab and surge 

pressures. 



REVISION 2006 9-20

HYDRAULICS 

Swab and surge pressures can be calculated by a method similar to that used for calculating annular 

circulating pressures. The greatest problem is determining fluid flow rate in the annulus when the 

pipe is open-ended since the distribution of flow between pipe bore and annulus cannot be found 

by any simple method. However, assumptions can be made which will simplify the analysis. 

If an assumption is made in which the pipe is closed, or the entire fluid flow rate is in the annulus, 

then the analysis will lead to swab or surge pressures equal to or probably exceeding the true swab 

or surge pressures. 

Alternatively, to assume the pipe is open-ended and fluid levels in pipe and annulus remain equal is 

a rarely justifiable and subsequent swab and surge pressure calculated will usually be too low. 

Another alternative procedure considers the pipe bore and annulus where a U-tube fluid level in the 

pipe and annulus are not equal – where the sum of pressure losses in the pipe bore and bit equals 

the sum of pressure losses in the annulus. This procedure requires a trial and error solution due to 

the uncertainty of the fluid level in the pipe bore. 

Finally, when calculating swab or surge pressures, the calculated value should be checked against 

the pressure required to break the gel strengths of the fluid. If the calculated swab or surge pressure 

is less than the sum of the pressures required to break the gel strengths, the gel-breaking pressure 

should be used. 

ADVANTAGE SM Engineering contains swab and surge calculation modules. This is Baker Hughes 

Drilling Fluids’ recommended tool for performing swab and surge analysis. The discussion below 

explains some of the background to swab and surge calculations. 

Equivalent Fluid Velocity 

When moving the drillstring through a stationary fluid column, an equivalent fluid velocity due to 

the speed of pipe movement can be calculated. Since the combination of fluid movement and 

viscous drag has an effect on the swab or surge pressure, Burkhardt's constant is introduced in 

order to account for the viscous drag effect. It is common practice to assume Burkhardt's constant 

is equal to 0.45, as any error introduced by this assumption will be on the side of safety. 

To find the equivalent fluid velocity in the annulus: 

where: 

⎛ (D 

V m = 0.45 + -------------------------------- 1 

⎜ 

--- 2 2⎟ ⎞ V p 

⎝ ( D 2) – ( D 1) ⎠ 

) 2 

V m = equivalent fluid velocity, ft/min 

D 1 = outside diameter of the pipe, in. 


V p = average maximum speed of pipe movement, ft/min 

The average speed of pipe movement, V P , can be determined by one of the following 

methods: 

1. Measurement of the time required to run or pull one stand of pipe from slips to slips, divided 

into 1.5 times th e stand length. 



REVISION 2006 9-21

HYDRAULICS 

where: 

V p 

= ----------- 

90L s 

t 

L s = stand length, ft 

t = time from slips to slips, sec 

2. Measurement of the time required for the middle joint of a three-joint stand to pass through the 

rotary table divided into the joint length. 

where: 

V p 

= 

Flow Regime 

60L 

---------- j 

t 

L j = joint length, ft 

t = time through rotary table, sec 

The possibility of turbulent flow in the annulus must be considered in surge and swab calculations. 

The equivalent fluid velocity may be compared to the critical flow rate for the annular section of 

interest previously calculated if the fluid properties or pipe diameters have not changed. If changes 

have occurred, calculate a new critical flow rate by following the steps outlined earlier. 

Surge or Swab Pressure 

The appropriate Fanning Friction Factor for annular flow and Friction-Loss Pressure Gradient are 

used to obtain the surge or swab pressure loss in each interval. 

Equivalent Fluid Weight 

In order to be meaningful, the surge or swab pressure and resulting equivalent fluid weight must be 

compared to some fracture gradient or pore pressure. The pressure drops in each annular interval 

are summed together, very similar to the steps used to obtain the Equivalent Circulating Density. 

When running pipe in the hole, the equivalent fluid weight due to the surge pressure is: 

EMW =ρ + 

∑ P 

( 0.052)( TVD) 

a 

When pulling pipe out of the hole, the equivalent fluid weight due to the swab pressure is, 

EMW =ρ − 

∑ P 

( 0.052)( TVD) 

a 

where: 

EMW = equivalent fluid weight, lb m /gal 




REVISION 2006 9-22

HYDRAULICS 

∑P a = sum of the pressure loss in each annular interval, psi 

TVD = true vertical depth, ft 

If the equivalent fluid weight due to the surge pressure exceeds the fracture gradient, at some point 

in the open hole, loss of circulation may occur. Likewise, if the equivalent fluid weight due to swab 

pressure is less than the formation pore pressure, at some point in the open hole, a kick, or even a 

blowout, may occur. 

These preceding steps and equations are useful approximations for surge and swab calculations 

when the time required running or pulling pipe can be measured. For planning purposes, it would 

also be useful to calculate the time required so as not to exceed a fracture gradient or pore pressure. 

This type of calculation is done through iterations of time (t) and is one of the programs contained 

SM 

within ADVANTAGE Engineering. 

Gel-Breaking Pressure 

When pipe is started back in the hole after a trip, the fluid will have been at rest for some period of 

time. The pressure required to break the downhole gel strength of the fluid can be significant, 

especially if the gel strengths are progressive. The primary reason for measuring 30-minute gel 

strength is to determine the progressive or fragile nature of the gel strengths. If the gel strengths are 

significantly high and progressive, the resulting surge or swab pressure could lead to well control 

problems. 

Gel strengths are a function of many factors, including time and temperature. By utilizing the 30- 

minute gel strength, the time factor can be partially taken into account for fragile gels, as long as 

the fluid is temperature stable at the bottomhole temperature. If the calculated swab or surge 

pressure is less than the sum of the gel-breaking pressures for each section of annulus, the gelbreaking 

pressures should be used. 

To find the gel-breaking pressure: 

P g 

4Lτg 

= ----------------------------------- 

1200( D – D ) 

2 

1 

where, 

P g = gel breaking pressure, psi 

L = Length of annular section, ft 

τ g = 30-minute gel strength, lb f /100 ft 2 



The equivalent fluid weight is calculated using the earlier equations. 

CUTTINGS TRANSPORT 

One of the primary functions of a drilling fluid is to bring drilled cuttings to the surface. Inadequate 

hole cleaning can lead to a number of problems including fill, packing-off, stuck pipe, and 

excessive hydrostatic pressure. 



REVISION 2006 9-23

HYDRAULICS 

The ability of a drilling fluid to lift cuttings is affected by many factors, and there is no universally 

accepted theory which can account for all observed phenomena. Some of these parameters are fluid 

density and rheological properties, annulus size and eccentricity, annular velocity and flow regime, 

pipe rotation, cuttings density, and size and shape of the cuttings. 

Figure 9-10 shows some general features of cuttings transport in laminar flow. If the particles are 

of irregular shape, they are subjected to a torque caused by the shearing of the fluid. If the drillpipe 

is rotating, a centrifugal effect causes particles to move toward the outer wall of the annulus in 

straight holes and helps keep cuttings moving, which minimizes the cuttings bed in horizontal 

holes. Nonetheless, cuttings transport rates are strongly dependent on particle size and shape, 

which, during a drilling operation, are both irregular and variable. 

The only practical way to estimate cuttings transport or slip velocity of cuttings is to develop 

empirical correlations based on experimental data. Even with this approach, there is quite a wide 

disparity in the results obtained by different authors. 

Particle slip velocity calculations are based upon particle Reynolds Numbers, drag coefficients, and 

size of cuttings. Simplifications are made that allow the slip velocity to be determined. 

Figure 9 - 10 Cuttings Transport 

ADVANTAGE SM Engineering is the recommended tool for conducting hole cleaning simulations 

and calculations. The discussion below describes some of the theories involved in cuttings 

transport. 



REVISION 2006 9-24

HYDRAULICS 

Laminar Flow Condition 

Find the boundary shear rate, 

186 

γ b = -------------- 

D c ρ 

where, 

γ b = boundary shear rate, sec -1 

D c = particle diameter, in. 

ρ = fluids density, lb m /gal 

Find the shear stress developed by the particle: 

τ = 7.9 T 20.8 – 

p ( ρ) 

where, 

τ p = particle shear stress, lb f /100 ft 2 

T = particle thickness, in. 


Find the shear rate developed by the particle using the annular power law constants for the fluid: 

1 

⎛ 

γ p 

= ------ 

τ p⎞ n ---- 

a 

⎜ ⎟ 

⎝K a ⎠ 

where, 

γ p = particle shear rate, sec -1 

τ p = particle shear stress, lb f /100ft 2 

n a = annular flow behavior index 

K a = annular consistency factor, poise 

If γ p < γ b 

, the slip velocity is determined by: 

( 

V s = 1.22τ p ---------------------- 

γp) ( D c ) 

ρ 

1/2 

where, 

V s = slip velocity, ft/min 

τ p = particle shear stress, lb f /100 ft 2 

γ 

-1 

p = particle shear rate, sec 

D c = particle diameter, in. 



REVISION 2006 9-25

HYDRAULICS 


If γ p > γ b , the slip velocity is determined by the equation below, slip velocity of a particle in 

turbulent flow. 

Turbulent Flow Condition 

Find the particle shear stress: 

where: 

τp 

= 7.9 T( 20.8 – ρ) 

τ p = particle shear stress, lb f /100 ft 

2 

T = particle thickness, in. 

ρ = fluid density, lb m /gal. 

Slip velocity of a particle in turbulent flow is: 

where: 

V s 

16.62τp 

= ------------------ 

ρ 


τ f /100 ft 2 

p = particle shear stress, lb 


Cuttings Transport 

The cuttings transport for each different hole geometry is obtained by subtracting the slip velocity 

of the cuttings from the annular velocity in that particular section of the hole by: 

where: 

Vt 

= V a − V s 

V t = cuttings transport, ft/ min 

V a = annular velocity × 60, ft/min 


Transport Efficiency 

Perhaps more important than an actual cuttings transport value is the cuttings transport 

efficiency, which is simply the ratio of cuttings transport to annular velocity, defined by: 

E t 

V t 

----- × 100 1 V s 

= = ⎛ – ----- ⎞ × 100 

⎝ ⎠ 

V a 

V a 

where, 



REVISION 2006 9-26

HYDRAULICS 

E t = transport efficiency, %. 

Note: If the slip velocity is zero, the transport efficiency is 1, or 100%. 

Cuttings Concentration 

Due to the slip velocity of cuttings in the annulus, the concentration of cuttings in the annulus 

depends upon the transport efficiency as well as the volumetric flow rate and the rate at which 

cuttings are generated at the bit (ROP and hole size). Experience has shown that cuttings 

concentration in excess of five (5) volume % can lead to a pack-off, tight hole, or stuck pipe. When 

drilling in soft formations, where pipe connections in the drillstring are made as rapidly as possible, 

the cuttings concentration may easily exceed 5%, if ROP is uncontrolled. The cuttings 

concentration is calculated by: 

where, 

C a 

( ROP)D 2 

= ---------------------------- × 100 

14.71 ( E t)Q 

C = cuttings concentration, vol % 

a 

D = hole diameter, in. 

E t = transport efficiency, % 


ROP = rate of penetration, ft/hr 

The ROP is obtained by measuring the time it takes to drill a length of pipe and dividing that length 

by the time. For instance, a stand length for a top-drive is 100 ft and it is drilled down in 20 min, 

then the ROP is 100 ft/20 min × 60 min/hr = 300 ft/hr. 

When the cuttings concentration exceeds five (5) volume %, the effect on hydrostatic pressure and 

equivalent circulating density can be substantial. The change in hydrostatic pressure depends upon 

the density of the cuttings as well as the concentration of the cuttings in that section of hole. The 

effective fluid weight due to the cuttings concentration in that section of hole is calculated by, 

where: 

ρ e 

= 

C a 

( SG c )( 8.34) 

⎛-------- 

⎞ + 

⎝100⎠ 

ρ⎛1 

⎝ 

C a 

– -------- ⎞ 

100⎠ 

ρ e = effective fluid weight due to cuttings concentration, lb /gal m 

SG c = specific gravity of the cuttings 

C a = cuttings concentration, vol % 




REVISION 2006 9-27

HYDRAULICS 

SUMMARY 

SM 

ADVANTAGE Engineering is Baker Hughes Drilling Fluids’ preferred tool for carrying out all 

hydraulics and hole cleaning analyses. The hydraulics calculations in ADVANTAGE SM Reporting 

use API equations and are less accurate than those used in ADVANTAGE SM Engineering. 



REVISION 2006 9-28

HYDRAULICS 

HYDRAULICS EXAMPLE 

The following is a manually worked example demonstrates the steps involved in performing 

hydraulics calculations. 

Drilling a deviated hole, with the following information: 

• 4½" drillpipe, 16.60 lb m /ft; I.D. = 3.326" 

• 300 ft. of 7¼" drill collars; I.D. = 2.8125" 

• Last casing 13 3 / 8 " 61 lb m /ft; I.D. = 12.515" 

• Hole size 9 7 / 8 " 

• 9 7 / 8 " HTC J33 bit; Jets = three #12 

• Fluid density = 15.3 lb m /gal. 

• PV = 32 cps 

• YP = 19 lb f /100 ft 2 

• Initial gel = 5, (use as 3 rpm reading) 

• 10 - min gel = 12 

• 30 - min gel = 15 

• Flow rate = 375 gal/min. 

• Maximum available standpipe pressure = 3500 psi 

• Fracture gradient at shoe = 16.5 lb m /gal 

• Fracture gradient at TD = 17.0 lb m /gal 

• Pore pressure at shoe = 14.0 lb m /gal 

• Pore pressure at TD = 14.7 lb m /gal 



REVISION 2006 9-29

HYDRAULICS 

Figure 9 - 11 Well Schematic 

1. Find fluid velocity in drillpipe, drill collars, and annulus: 

• Drillpipe 

( 375) 

2 

( 3.826) 

0.408Q 

0.408 

V p 

= = = 10.45 ft /sec 

2 

D 

• Drill collars 

( 375) 

( 2.8125) 

0.408 

V p 

= = 19.34 ft /sec 

2 

• Annulus of drill collar and open hole 

V 

0.408Q 

a = ----------------------------------- = 

(D 2 ) 2 – ( D 

2 1 ) 

• Annulus of drillpipe and open hole 

V 

0.408( 375 ) 

a = ------------------------------- = 1.98 ft/sec 

9.875 2 – 4.5 2 

• Annulus of drillpipe and casing 

---------------------------------- 

0.408( 375 ) = 3.40 ft/ sec 

9.875 2 – 7.25 2 



REVISION 2006 9-30

HYDRAULICS 

2. 

V 

0.408( 375 ) 

a = ---------------------------------- = 1.12 ft/ sec 

12.515 2 – 4.5 2 

Find the power law constants n and K. 

θ 600 = 83 

θ 300 = 51 

θ 3 = 5 

• Inside drillpipe and drill collar 

n = 3.3 

p 2 

• Annulus 

θ600 

log--------- = 3.32log 

83 

----- = 0.70 

51 

θ 300 

5.11 × θ 

K 600 

p = -------------------------- 

1022 n p 

= 

5.11 

---------------------- × 83 

= 3.32 

1022 0.70 

3. Find the effective viscosity. 

θ300 

n a = 0.5 log --------- = 0.5 log 

51 

----- = 0.50 

5 

• Drillpipe 

θ 3 

5.11 

K × θ300 

a = ------------------------- = ---------------------- 

5.11 × 51 

= 11.53 

511 n a 

511 0.50 

μe p 

= 

100K p 

96V 

------------ p 

D 

n p – 1 

= 

100 3.32 ( ) 

96 

----------------------- ( 10.45 ) 0.70 – 1 

= 62.45 c p 

3.826 

• Drill collar 

μ ep 

= 100( 3.32 

96 19.34 

) ------------------------ ( ) 0.70 – 1 

= 47.34 cp 

2.8125 


144V 

μ e a 

100K a 

a ------------------ n a – 1 

= 

D 2 – D 1 

= 

100 11.53 ( ) 

----------------------------- 

144( 3.40) 

0.50 – 1 

= 84.43 cp 

9.875 – 7.25 


μ e a 

= 100( 11.53 

144 1.98 

) -------------------------- ( ) 

0.50 – 1 

= 158.31 cp 

9.875 – 4.5 


μ e a 

= 100( 11.53) 

----------------------------- 

144( 1.12) 

0.50 – 1 

= 257.03 cp 

12.515 – 4.5 



REVISION 2006 9-31

HYDRAULICS 

4. 

Calculate the Reynolds Number. 

• Drillpipe 

----------- ( 928) ( 10.45 )( 3.826) 15.3 

Re ( ) 

p = ------------------------- 

928( Vp 

) ( D p )ρ 

= ------------------------------------------------------------------ 

1 

- n p 

( 62.45) 3 ( 0.70 

- = 8465 

3n ) + 1 

4n --------------------------- 0.70 

p + 

μ ep 

----------------- 

p 40.70 ( ) 

• Drill collar 

Re ( 928 )( 19.34) ( 2.8125) ( 15.3) 

p = --------------------------------------------------------------------- 

( 47.34) 30.70 

= 15,192 

--------------------------- ( ) + 1 

0.70 

4( 0.70) 


928V 

Re = ------------------------------------------- 

a ( D 2 – D 1 )ρ ( 928) ( 3.40) ( 9.875 – 7.25) ( 15.3) 

a = ------------------------------------------------------------------------------- 

---------------- n a 

( 84.43) 20.5 

= 1300 

2n ------------------------ ( ) + 1 

0.50 

a + 1 

μe a 

3n a 3( 0.5) 


Re ( 928 )( 1.98) ( 9.875 – 4.5) ( 15.3) 

a = ---------------------------------------------------------------------------- 

( 158.31) 2 ( 0.5 

= 827 

------------------------ ) + 1 

0.50 

30.5 ( ) 


Re ( 928 )( 1.12) ( 12.515 – 4.5) ( 15.3) 

a = ------------------------------------------------------------------------------- 

( 257.03) 2 ( 0.5 

= 429 

------------------------ ) + 1 

0.50 

30.5 ( ) 

5. Find the flow regime in each section. 

• Pipe 

Variable Re Flow 

Drill pipe 8465 Turbulent 

Drill collar 15192 Turbulent 

Drill collar – open hole 1300 Laminar 

Drill pipe – open hole 827 L aminar 

Drill pipe – casing 429 Laminar 

Table 9 - 1 Reynolds Number Summary 

Re c = 3470 – 1370( n p ) = 3470 – 1370( 

0.70) = 2511 

Re c = 4270 – 1370 ( n p ) = 4270 – 1370( 

0.70 ) = 3311 

• Annulus 

Re c = 3470 – 1370( n a ) = 3470 – 1370( 0.50 ) = 2785 

Re c = 4270 – 1370( n a ) = 4270 – 1370( 0.50) = 3585 



REVISION 2006 9-32

HYDRAULICS 

6. Calculate the critical flow rate for the annular sections of the open hole. 


2n + 1 n 

( 3470 – 1370n a )( 100 

a a -------------- 

1 

)K a 

----------------- 2 – n 

3n 

a 

a 

V = ------------------------------------------------------------------------------- 

c 

928ρ( D – D 

144 

2 1 ) -------------------- 1 – ------------- n a 

D – D 2 1 

[ 3470 – 1370( 0.5) 

]( 100 )( 11.53) ------------------------ 20.5 ( ) + 1 0.5 

30.5 ( ) 

V c 

= --------------------------------------------------------------------------------------------------------------------- 

144 

928( 15.3) ( 9.875 – 7.25) 

----------------------------- 1– 

0.5 

9.875 – 7.25 

--------------- 

1 

2– 

0.5 

= 

5.58 ft/sec 

Q 

2 2 

2 2 

( 2.45) V [( D ) − ( D ) ] = ( 2.45)( 5.58)( 9.875 −7.25 

) 615gal / min 

c 

= 

c 2 1 

= 


[ 3470 – 1370( 0.5) 

]( 100) ( 11.53) ------------------------ 20.5 ( ) + 1 

0.5 

30.5 ( ) 

V c = -------------------------------------------------------------------------------------------------------------------- 

144 

928( 15.3)( 9.875 – 4.5 ) -------------------------- 1 – 0.5 

9.875 – 4.5 

Q c = ( 2.45) ( 4.40 )( 9.875 2 – 4.5 2 ) = 833 gal/min 

-------- 

1 

2 – 0.5 

= 

4.40ft/sec 

7. Calculate the Fanning Friction Factor. 

• Drillpipe (Turbulent) 

logn g + 3.93 

a p + 3.93 lo 

= ------------------------------ = --------------------------------------- ( 0.70) 

= 0.0755 

50 

50 

1.75 – logn 1.75 – log( 0.7 

b = ----------------------------- p 

= ----------------------------------- ) = 0.2721 

7 

7 

f 

a 

p = --------------- = ----------------------- 

0.0755 

= 0.0064 

( Re p ) b 8465 0.2721 

• Drill collar (Turbulent) 

f 

0.0755 

p = ---------------------------- = 0.0055 

15,192 0.2721 

• Drill collar-open hole (Laminar) 



REVISION 2006 9-33

HYDRAULICS 

24 

f a = -------- 

Re a 

= 

24 

----------- = 0.0185 

1300 

• Drillpipe-open hole (Laminar) 

24 

f a = -------- = 0.0290 

827 

• Drillpipe-casing (Laminar) 

24 

f a = -------- = 0.0559 

429 

8. Calculate the Friction-Loss Pressure Gradient. 

• Drillpipe 

P p 

------ 

L m 

2 

f p ( V p ) ( ρ ) 

= ---------------------------- = 

25.81D 

There is 10,200 ft of drillpipe. 

P p 

= 

9. Find the equivalent circulating density. 

(-------------------- 

0.0064) 

------------------------------------ ( 10.45 2 )( 15.3) 

= 0.1083 psi/ft 

( 25.81) ( 3.826) 

( 0.1083 psi/ft )( 10,200 ft ) = 1105 psi 

ECD 

= 

ΣP 

-------------------------------- a 

+ ρ 

(.052)( TVD) 

= 

14.5 + 10.5 + 49 

--------------------------------------- + 15.3 = 15.45 l b 

(.052)( 9600 

m /gal 

) 

Bit Hydraulics 

1. Calculate total nozzle area. 

A t 

= 

2. Calculate nozzle velocity. 

2 2 2 

( J 1 ) + ( J 2 ) + (J 3 ) 

-------------------------------------------------- 

1303.8 

= 

12 

------------------------------------- 2 + 12 2 + 12 2 

= 0 .3 3 1 3 i n . 2 

1303.8 

V n 

Q 

= ------------------ = 

3.117A t 

3. Calculate pressure-drop across bit. 

375 

--------------------------------------- = 363 ft/sec 

( 3.117) ( 0.3313) 

P n 

= 

----------------------------------------------------------- 

156( ρ)Q 2 

[ J ) 2 2 

+ ( J 2 ) + (J 3) 2 2 

] 

( 1 

= 

( 156) ( 15.3) ( 375 

-------------------------------------------- ) 2 

= 1799 psi 

( 12 2 + 12 2 + 12 2 ) 2 

Note: The standpipe pressure should be equal to all of the friction loses downhole plus the 

pressure drop across the bit. In this example, standpipe pressure = 1105 + 130 + 14.5 + 10.5 + 

49 + 1799 = 3108 psi 



REVISION 2006 9-34

HYDRAULICS 

4. Calculate hydraulic horsepower and impact force. 

QP ( 

HHP n ) 

-------------- = ( 375 

------------------------------ ) 1799 

= - ( ) = 394 hp 

1714 1714 

1.2732 

--------------------------------- ( )( 394 

HHP/in. 2 1.2732 

= ( )HHP 

= ---------------------------------- ) = 5.14 hp/in. 2 

D 2 ( 9.875) 2 

F ( 15.3) ( 375) 363 

i = ------------------------------------------- ( ) = 1078 lb 

1932 

f 

5. Calculate total nozzle area to maximize HHP or Impact Force. For maximum HHP, C = 0.65. 

A t 

= ------------------------------------------------------------- 

Q 

2.96 ( 1238.5 )( C ) ( P 

--------------------------------------- ) 1/2 

ρ 

For maximum impact, C = 0.48 

= 

------------------------------------------------------------------------- 

375 

2.96 ( 1238.5 

= 0.2952 i n. 2 

)(.65) ( 3500 

------------------------------------------------- ) 1/2 

15.3 

6. Select jet sizes. 

375 

A t = ------------------------------------------------------------------------- 

2.96 ( 1238.5 

= 0.3435 in. 2 

-------------------------------------------------- )(.48) ( 3500 ) 1/2 

15.3 

For 3 jets, N = 3; maximum HHP 

1 

1303.797 

⁄ 2 

1 

1303.797 

⁄ 2 

J 1 = ---------------------A 

N t = ---------------------0.2952 ( ) = 11 .3 → 11 

3 

⎛ 

2 

1303.797 

( J 

------------------ A 1 

) 

1/2 ⎜ t 

– ----------------- 

N – 1 ⎜ 1303.797⎟ ⎟⎞ = ------------------ 1303.797 

3 – 1 

0 .295 2 – ----------------- 

11 2 

⎝ 

⎛ 1303.797⎠ 

⎞ 1/2 = 11.49 → 11 

⎝ 

⎠ 

2 

⎛ 

1303.797 

( J 

---------------- A 1 

) + ( J 2 

) 2 ⎞ 1/2 

⎜ – -------------------------⎟ 

1303.797 

N – 2 ⎜ t 1303.797 ⎟ 

---------------- ⎛ 

3 – 2 

0.2 952 – 

11 

----- 2 --- 

+ 

-------- 

11 2 

-⎞ 1/2 = 

= 11.59 → 12 

⎝ 1303.797 ⎠ 

⎝ 

⎠ 

J 2 = 

J 3 

= 

For jets, N = 2; maximum HHP 

J 1 

Therefore, for maximum HHP with 3500 psi on the standpipe, we would choose 3 jets of 11, 11, and 

12. 

J 

2 

= 

= 

1/2 

1303.797 1303.797 

---------------------A t = --------------------- ( 0.2952 ) 1/2 = 13.87 → 14 

N 

2 

2 

(J 1 ) 

t --------------------- 

N– 

1 ⎝ 

⎜ 1303.797⎠ 

⎟ ⎞ 1/2 

1303.797⎛ 

--------------------- A – 

= 

1303.797 --------------------- ⎛ 

2– 

1 

A – --------------------- 

142 

⎞ 1/2 = 13.74 14 

⎝ t 1303.797⎠ 

→ 

Therefore, for maximum HHP with 3500 psi on the standpipe, we would choose 2 jets of 14 and 

14. 



REVISION 2006 9-35

HYDRAULICS 

Exercise: Calculate the jet sizes required for 3 jets and 2 jets for the total nozzle area for 

maximum impact force in the above example. 

Answer: 3 jets: 12, 12, 13 

2 jets: 15, 15 

Practice: Calculate the jet sizes for HHP-impact compromise for a PDC bit with five jets. 

Answer: 9, 9, 9, 9 

Swab and Surge 

Exercise: Following the preceding example calculations, calculate the EMW due to running pipe 

in the hole after a trip. 

Are the gel strengths progressive or fragile? 

Cuttings Transport 

Laminar Flow in Annulus 

Assume: 

Particle thickness, T = 3 / 8 in. = 0.375 in. 

Particle diameter, D c = ¾ in. = 0.750 in. 

1. Find the boundary shear rate. 

186 

γ b = ------------- = ------------------------ 186 

= 63.4 sec – 1 

D c ρ 0.75 15.3 

2. Find the shear stress developed by the particle. 

τ p = 7.9 T( 20.8 – ρ) 

= 7.9 ( 0.375) ( 20.8 – 15.3) = 11.35 lb f /100 ft 2 

3. Find the shear rate developed by the particle. 

γ p 

= ⎛ ⎞ 

n a 

= ⎛11.35 

------------ ⎞ 

⎝ ⎠ ⎝11.53⎠ 

τp 

----- 

K a 

--- 

1 

4. γ p < γ b , slip velocity is determined by, 

6. Calculate the transport efficiency. 

------ 

1 

0.50 

= 

γ b = 0.97 sec – 1 

⎡γ 

p 

D ⎤ 

c 

⎡ 0.97 0.75 ⎤ 

V = 1.22τ 

p ⎢ ⎥ = 1.22 11.35 ⎢ ⎥ 

⎢⎣ 

ρ ⎥⎦ 

⎣ 15.3 ⎦ 

5. Calculate the cuttings transport for casing drillpipe annulus. 

1/ 2 

( )( ) ( )( ) = 5.97 6.0 ft / min 

V t = V a – V s = ( 1.12 ft/sec × 60 sec/min ) – 6.0 = 61.2 ft/m in 

E t = 

V t 

61.2 

----- × 100 = ------------------------- × 100 = 

V a ( 1.12) ( 60) 

91% 

or 

⎛ V ⎞ 

s 

⎛ 6.0 ⎞ 

Et = 1 − ⎜1 

− 100 1 

100 91% 

V 

⎟ × = ⎜ − ⎟ × = 

⎝ a ⎠ ⎝ ( 1.12)( 60) 

⎠ 




1/ 2 

s 

=

HYDRAULICS 

Cuttings Concentration 

We have timed a stand of pipe 93 ft long drilled down in 14 minutes with a top drive. 

1. Calculate the ROP. 

Operator wants to make some hole! 

2. Calculate the cuttings concentration in the annulus after drilling down this stand. 

C ( ROP)D 2 

a 

= ------------------------ 

14.71( 

E 

t ) × 100 = 

Q 

(--------------------------------- 398.6) ( 9.875 ) 2 

× 100 = 7.7% 

14.71( 91) ( 375) 

3. Calculate the effective fluid weight due to this enormous cuttings concentration. Assume SG c = 

2.2. 

ρ 

= 

⎛ C C ⎞ ⎛ 7.7 ⎞ ⎛ 7. 7 ⎞ 

⎜ ⎟ + ⎜ − ⎟ 

⎝ 100 ⎠ ⎝ 100 ⎠ ⎝ 100 ⎠ ⎝ 100 ⎠ 

a ⎞ ⎛ a 

( SG )( 8.34) ⎜ ⎟ +ρ ⎜1 

− ⎟ = ( 2.2)( 8.34) 15.3 1 15.53lb / gal 

e c 

= 

What do you need to recommend to the Drilling Foreman? 

m 



REVISION 2006 9-37

HYDRAULICS 

NOMENCLATURE 

A t 

C 

C a 

D 

D 1 

D 2 

D c 

D p 

ECD 

EMW 

E t 

f a 

f p 

F i 

HHP 

J 

K 

K a 

K p 

L 

L j 

L m 

L s 

n 

n a 

n p 

N 

P a 

P g 

P n 

P p 

Q 

Q c 

ROP 

Re a 

Area, total 

Nozzle constant 

Cuttings concentration 

Diameter 

Outside diameter, pipe 

Hole diameter 

Diameter, particle 

Inside diameter, pipe 

Equivalent circulating density 

Equivalent fluid weight 

Efficiency, transport 

Friction factor, annulus 

Friction factor, pipe 

Impact force 

Hydraulic horsepower 

Nozzle size 

Consistency factor 

Consistency factor, annulus 

Consistency factor, pipe 

Length 

Length, joint 

Length, measured 

Length, stand 

Flow behavior index 

Flow behavior index, annulus 

Flow behavior index, pipe 

Number of nozzles 

Pressure loss, annulus 

Pressure, gel breaking 

Pressure loss, nozzle 

Pressure loss, pipe 

Flow rate, bulk 

Flow rate, critical 

Rate of penetration 

Reynolds Number, annulus 



REVISION 2006 9-38

HYDRAULICS 

Re c 

Re p 

SG c 

t 

T 

TVD 

V a 

V c 

V m 

V n 

V p 

V s 

V t 

γ 

γ b 

γ p 

θ 3 

θ 300 

θ 600 

Reynolds Number, critical 

Reynolds Number, pipe 

Specific gravity, cuttings 

Time 

Thickness, particle 

True vertical depth 

Velocity, annular 

Velocity, critical 

Equivalent velocity, fluid 

Velocity, nozzle 

Velocity, pipe 

Velocity, slip 

Transport, cuttings 

Shear rate 

Shear rate, boundary 

Shear rate, particle 

3 rpm reading 

300 rpm reading 

600 rpm reading 

μ Effective viscosity, annulus 

e a 

μ Effective viscosity, pipe 

e b 

ρ 

ρ e 

τ 

τ g 

τ p 

Fluid density 

Fluid weight, effective 

Shear stress 

Gel strength, 30 min. 

Shear stress, particle 



REVISION 2006 9-39

HYDRAULICS 

REFERENCES 

1. ADVANTAGE SM Training Manual, Baker Hughes Drilling Fluids 

2. ADVANTAGE SM “Help”, ADVANTAGE SM Engineering Software 

3. Kelco Oil Field Group Inc., Rheology Technical Bulletin, 1994. 

4. API Bulletin 13D, The Rheology of Oil-Well Drilling Fluids, (May 1985 Edition), 

American Petroleum Institute, Dallas. 

5. Burkhardt, J. A., Wellbore Pressure Surges Produced by Pipe Movement, Journal of Petroleum 

Technology, June 1961. 

6. Dodge, D. W. and Metzner, A. B., Turbulent Flow NonNewtonian Systems, American Institute 

of Chemical Engineering Journal, 5 (2), June 1959. 

7. Fann Instrument Corporation, Operating Instructions - Fann Viscometers. 

8. Fontenot, J. E. and Clark, R. K., An Improved Method for Calculating Swab and Surge 

Pressures in a Drilling Well, SPE Journal, October 1964. 

9. Gray, G. R. and Darley, H. C. H., Composition and Properties of Oil Well Drilling Fluids, Gulf 

Publishing Co., 1979. 

10. Hopkin, E. A., Factors Affecting Cuttings Removal During Rotary Drilling, Journal of 

Petroleum Technology, June 1967. 

11. Schuh, F. J., Computer Makes Surge Pressure Calculations Useful, Oil and Gas Journal, August 

3, 1964. 

12. Theory and Applications of Drilling Fluid Hydraulics, Exploration Logging, Inc., July 1983. 

13. Walker, R. E and Korry, D. E., Field Method of Evaluating Annular Performance of Drilling 

Fluids, SPE, Paper 4321, 1973. 

14. Walker, R. E. and Mayes, T. M., Design of Muds for Carrying Capacity, Journal of Petroleum 

Technology, July 1975. 



REVISION 2006 9-40

Chapter 

Ten 

Mechanical Solids Control 

Mechanical Solids Control

Chapter 10 


MECHANICAL SOLIDS CONTROL..................................................................................................10-1 

DRILLING FLUIDS.................................................................................................................................10-1 

Classification of Solids..................................................................................................................10-1 

Low Gravity Solids Concentration...........................................................................................10-3 

EFFECTS OF SOLIDS ON RHEOLOGICAL PROPERTIES ......................................................................10-5 

Current Solids Control Techniques.............................................................................................10-6 

Vibrating Screen Separators ...................................................................................................10-7 

Solids Removal by Centrifugal Force...................................................................................10-10 

Hydrocyclones .........................................................................................................................10-11 

Fluid (Mud) Cleaners ..................................................................................................................10-14 

Centrifuges ...................................................................................................................................10-15 

RMS Centrifuge ...........................................................................................................................10-18 

General Operation of the RMS Centrifuge ..........................................................................10-18 

Closed-Loop Systems ............................................................................................................10-18 

Typical Equipment Configurations........................................................................................10-20 

Calculations Used in Solids Control Evaluations ...................................................................10-22 

NOMENCLATURE................................................................................................................................10-24 


FIGURE 10 - 1 AVERAGE SOLIDS RANGE OF WATER-BASE DRILLING FLUIDS (FRESHWATER) .............10-2 

FIGURE 10 - 2 DRILLING FLUID REQUIRED IF DISCARD STREAM FROM ALL SOLIDS PROCESSING 

EQUIPMENT AVERAGES 30% BY VOLUME SOLIDS ..........................................................................10-4 

FIGURE 10 - 3 TYPICAL SCREEN MOTIONS..............................................................................................10-8 

FIGURE 10 - 4 CROSS-SECTIONAL VIEW OF HYDROCLONE OPERATION...............................................10-12 

FIGURE 10 - 5 TYPICAL CYCLONE PERFORMANCE (COMPARISON BY SIZE) .........................................10-14 

FIGURE 10 - 6 SOLID BOWL DECANTING CENTRIFUGE.........................................................................10-16 

FIGURE 10 - 7 PROCESS RATE OF BARITE RECOVERY DECANTING CENTRIFUGE.................................10-17 

FIGURE 10 - 8 RMS SEPARATION CHAMBER.........................................................................................10-18 

FIGURE 10 - 9 CLOSED LOOP SOLIDS SYSTEM – UNWEIGHTED FLUID .................................................10-19 

FIGURE 10 - 10 CLOSED LOOP SOLIDS SYSTEM – WEIGHTED FLUIDS ..................................................10-20 

FIGURE 10 - 11 UNWEIGHTED FLUID: CENTRIFUGE PROCESSING ACTIVE SYSTEM .............................10-20 

FIGURE 10 - 12 UNWEIGHTED FLUID: CENTRIFUGE PROCESSING HYDROCYCLONE UNDERFLOW......10-21 

FIGURE 10 - 13 WEIGHTED WATER-BASE FLUID: SINGLE-STAGE CENTRIFUGING (BARITE RECOVERY) 

.......................................................................................................................................................10-21 

FIGURE 10 - 14 WEIGHTED FLUID: TWO STAGE CENTRIFUGING .........................................................10-22 


TABLE 10 - 1 API CLASSIFICATION BY PARTICLE SIZE...........................................................................10-2 

TABLE 10 - 2 THE DISINTEGRATION OF SOLIDS......................................................................................10-6 

TABLE 10 - 3 ASTM SIEVE DESIGNATION ............................................................................................10-10 

TABLE 10 - 4 RECOMMENDED HYDROCLONE FEED HEAD REQUIREMENTS (PRESSURES BASED ON 9 

LBM/GAL FLUID).............................................................................................................................10-13 



REVISION 2006 10-i

MECHANICAL SOLIDS CONTROL 


Chapter 10 

Drilling fluid maintenance costs can decrease greatly when proper solids control techniques are 

utilized. A drilling fluids engineer must be thoroughly knowledgeable of available solids control 

techniques in order to maximize drilling fluid performance and minimize costs 

DRILLING FLUIDS 

Adverse effects caused by drilled solids account for a major portion of drilling fluid maintenance 

expenditures. Drilled solids are the number one contaminant of all drilling fluids. Considering that 

a 12¼ in. gauge hole drilled to 10,000 ft would result in 1,327,000 lb or more of drilled solids, the 

above statement is not surprising. Overall drilling costs can also be severely affected by the 

quantity of drilled solids incorporated into the system. These effects include the following: 

• Increased drilling fluid maintenance costs. 

• Greater difficulty in maintaining optimum rheological properties. 

• Increased frequency/opportunity of differential sticking. 

• Reduced penetration rate. 

• Decreased bit life and increased rate of wear on pump parts. 

• Increased circulating pressure losses, and consequently increased possibility of lost 

circulation. 

• Increased tendency for a well to swab on trips, possibly contributing to pressure control 

problems. 

A solids control program should consider the drilling fluid as well as the formations to be drilled 

prior to selecting equipment for a particular operation. Care should be taken to operate the selected 

equipment efficiently and in the correct sequence to prevent overloading any individual unit. 

It would be desirable in most cases to remove all drilled solids. Although this is possible with the 

use of chemical enhancement prior to separation, it is not always the most economical approach. 

The goal of a solids control system is to achieve the balance between mechanical solids separation 

and dilution that will result in drilled solids being maintained at an acceptable level with minimum 

cost, while maintaining property specifications. This is achieved when the cost of the required 

dilution fluid is at a minimum. 

Classification of Solids 

Solids can be classified into categories based on specific gravity and particle size. 



REFERENCE MANUAL


• Specific Gravity (S.G.) – Solids in drilling fluids can be separated essentially into two density groups, 

high and low specific gravities. High specific gravity will refer to those solids with a specific gravity 

of 4.2 and above. High specific gravity materials are used for drilling fluid density increases, the 

most commonly used of which are barite (4.2 s.g.), and hematite (5.0 s.g.). Low specific gravity 

solids may range from a low of 1.6 to 2.9 for dense lime. Drilled solids have a specific gravity in the 

range of 2.1 to 2.8. Most solids analysis calculations use 2.6 as the assumed S.G. of all drilled solids. 

• In a drilling fluid containing only low-gravity solids and fresh water, the concentration of solids will 

be a function of fluid density. The same relationship exists if a drilling fluid is composed only of 

barite and water. If a drilling fluid contains low-gravity and high-gravity solids, then the solids 

content will vary between the two ranges at a particular density. Figure 10-1 illustrates the effect of 

specific gravity and solids concentration on fluid density. 

Figure 10 - 1 Average Solids Range of Water-Base Drilling Fluids (Freshwater) 

• Particle Size – Fluid solids are measured in microns because of their small size. A micron (µ) is a unit 

of measure in the metric system and is 1 / 1000 of a millimeter. To better illustrate the relative size of a 

micron, there are 25,400 microns to the inch. API classification of solids by size range is listed in 

Table 10-1. Commercial clays such as MILGEL ® contain predominantly particles which are smaller 

than 2 microns, or colloidal in size. 

Particle 

Size, microns 

Greater than 2000 

2000 to 250 

250 to 74 

74 to 44 

44 to 2 

Less than 2 

Particle 

Classification 

Coarse 

Intermediate 

Medium 

Fine 

Ultra-Fine 

Colloidal 

Table 10 - 1 API Classification by Particle Size 

Sieve 

Size 

10 

60 

200 

325 

400 

– 

Even though drilled solids initially may be relatively coarse, they rapidly disintegrate into smaller 

particles due to chemical dispersion and mechanical action of the bit and drillstring. The rate of 

disintegration will vary with formation, type of drilling fluid, bit exposure time, annular transport 



REFERENCE MANUAL


time, annular circulating rate, degree of deviation, and mechanical abrasion from the drillstring. 

Disintegration can be shear dependent. It is extremely important to remove as many of the drilled 

solids as possible on the first circulation. 

Low Gravity Solids Concentration 

Most fresh water-base drilling fluids use bentonite for viscosity and filtration control. Low density 

fresh water drilling fluids may contain approximately two (2) volume % bentonite or about 18 

lbs/bbl to achieve desirable properties. As mud density increases, the concentration of bentonite 

required decreases. Polymer based fluids may not use bentonite for this purpose by the substitution 

of other synthetic materials to achieve similar controls. 

Experience has shown that the low gravity solids concentration should be controlled and 

maintained at specific levels for optimum fluid performance. Experience with the economics of 

solids control has indicated that the specific level for low gravity solids concentration falls between 

4 and 6 percent. Since bentonite concentration can be approximately 2 volume %, this leaves room 

for only 2 - 4 volume % drill solids. 

Various publications have addressed the issue of drilling and mud economics. The subjects of 

“dilution” vs. “displacement” have been considered. Since waste disposal has become a major 

economic factor in drilling operations today, emphasis has been placed on the proper selection and 

operation of mechanical solids control equipment. This has resulted in concentrating the volume of 

“dry” drill solids requiring disposal and therefore has minimized the need for building large 

volumes of dilution mud to achieve optimum fluid performance. 

Dr. Leon Robinson presents an economic analysis that bears repeating. In his article 1 , Robinson 

states that since drilling fluid costs vary greatly, a particular well situation needs to be analyzed. 

That involves the cost of fluid associated with each barrel of discarded drill solids which can be 

calculated. Using the data in Figure 10 - 2, if the drilling fluid target solids is 4 volume % and the 

system has a 60% removal efficiency, 9.6 bbl of drilling fluid will be discarded with each barrel of 

drilled solids discarded. Assuming a $50/bbl fluid cost, 1000 bbl of drilled solids would require 

$480,000 for new drilling fluid. 

If the drilling fluid target solids can be increased to 6 volume % and the removal efficiency 

increased to 70%, only 4.7 bbl of drilling fluid must be built for each barrel of discarded drill 

solids. Again, for a $50/bbl fluid, the same 1000 bbl of drilled solids discarded would cost 

$235,000. 

1 Robinson, L., How to Optimize Solids Control Economics, Efficiency, Handbook by Derrick Equipment 

Co., “Solids Control Manual for Drilling Personnel”. 



REFERENCE MANUAL


Figure 10 - 2 Drilling Fluid Required if Discard Stream From All Solids Processing 

Equipment Averages 30% by Volume Solids 

The Methylene Blue Test (MBT) is used to determine the Cation Exchange Capacity (CEC) of 

fresh water-base drilling fluid. The test measures the concentration of all active clays present in the 

drilling fluid. Correcting the test results for commercial bentonite concentration allows the 

concentration of all other clays to be estimated. Using the MBT test allows the concentration of 

drilled solids to be estimated and the drilling fluid treated/processed accordingly to achieve a 

predetermined drilled solids concentration. Efforts to reduce the drill solids concentration to lower 

levels can result in unnecessary drilling fluid maintenance expense. 

Oil or synthetic-based systems, along with certain polymer systems, because of their inherently 

inhibitive nature, do not experience the same low gravity solids problems particular to fresh waterbase 

drilling fluids. 

The API Recommended Practices 13C contains a field method for evaluating the total efficiency of 

the drilling fluid processing system in water-based fluids. This procedure depends upon accurate 

dilution volume information. The API procedure uses the dilution volume over a given interval to 

compute a dilution factor, DF, which is the volume ratio of actual mud dilution required to 

maintain a desired solids concentration with no solids removal equipment. The dilution factor is 

used to determine the total solids removal efficiency of the system. The API procedure is as 

follows: 

1. Over a desired interval length, obtain accurate water additions and retort data. 

2. From the retort data, calculate: 

a. The average drilled solids concentration in the mud, ks. 

b. The average water fraction of the mud, kw. 



REFERENCE MANUAL


3. Calculate the volume of drilled solids, Vm: 

Vw 

Vm = 

kw 

4. Calculate the volume of drilled solids, Vc: 

2 

Vc = 0.000971× 

D × L×W 

5. Calculate the dilution volume required if no solids were removed Vd: 

Vd 

Vc 

= 

ks 

6. Calculate the dilution factor, DF: 

DF = Vm 

Vd 

7. Calculate the total solids removal performance, Et: 

Et = ( 1− 

DF ) 

Multiply the result by 100 to calculate a percentage 

The accuracy of the API procedure depends somewhat on a relatively constant solids concentration 

in the mud, constant surface circulating volume, and consistent averaging techniques over the 

interval of interest. The total solids removal performance by this method should be reported at 

frequent intervals during the course of drilling the well.. 

EFFECTS OF SOLIDS ON RHEOLOGICAL PROPERTIES 

A brief review of the effects of drilled solids on the flow properties of water-base drilling fluids is 

necessary to assist in determining the effectiveness and need of solids control. 

Plastic viscosity is largely due to mechanical friction between solid particles in the drilling fluid, 

and to a lesser degree the friction between solid and liquid. The plastic viscosity value depends 

primarily on the size, shape and concentration of solids in the system, and the viscosity of the 

liquid phase. Day-to-day trends in plastic viscosity can give an indication of an increasing degree 

of fineness within the solids concentration and can be utilized as a guide in determining the 

necessity for centrifuging and dilution. 

Yield point and gel strength indicate the degree of attractive forces existing between particles in the 

system. Chemical treatment is usually indicated when high yield and gel values are present. 

Dilution or mechanical removal of solids may also reduce yield and/or gels. These attractive forces 

are related to the distance between the particles. Either of these actions will result in increased 

particle separation. 



REFERENCE MANUAL


Dispersion of Surface Area - Removal of particles of very fine size produces greater viscosity 

reductions than does the removal of an equivalent volume of coarser particles due to differences in 

2 

surface area. For example, a cubic foot of formation has 6 ft of surface area, whereas this same 

piece of formation broken up into cubic micron-size particles would have a combined surface area 

of 1,828,800 ft 2 or 42 acres. The volume % solids that would result from incorporation of these 

particles in a fluid would be the same in both cases, but a considerable change in the volume of 

water to wet the surface would occur. Obviously, a solids problem can develop without an increase 

in solids volume if the particles are degraded into smaller sizes. Table 10-2 describes the increase 

in surface area as a solids cube is broken down into smaller pieces. 

Number of Cube 

Divisions 

Total Number 

Pieces 

Individual Cube 

Size, inches 

Total Surface Area, 

square inches 

0 1 1 6 

1 8 1/2 12 

2 64 1/4 24 

3 512 1/8 

48 

4 4096 1/16 96 

5 32768 1/32 192 

6 262144 1/64 384 

7 2.0972 x 10 6 1/128 768 

8 1.6772 x 10 7 1/256 1536 

9 

8 

1. 3421 x 10 1/512 3072 

10 1.0737 x 10 9 1/1024 6144 

15 3.5184 x 10 13 1 /32768 1966081 

Table 10 - 2 The Disintegration of Solids 

Current Solids Control Techniques 

The methods by which drilled solids can be removed are as follows: 

• Displacement – reduces solids by discarding the solids laden fluid and replacing it with a 

drilled solids free fluid 

• Dilution - additions of clean/clear fluids which is the most expensive method of controlling 

drill solids 

• Mechanical removal – accomplished with shale shakers, desanders, desilters, centrifuges, etc. 

• Settling – restricted 

to low-viscosity, low-density fluids and requires a large settling pit to 

allow particles the necessary time to settle out of suspension. 

The higher the concentration of drill solids in a discard, the more favorable the displacement or 

mechanical removal method. The purpose of mechanical control is to minimize dilution 



REFERENCE MANUAL


requirements by discarding solids in the highest concentration possible. The basic mechanical 

solids removal equipment available falls into two categories – screening devices and enhanced 

settling devices. 

Dilution vs. Displacement 2 

Dilution, as previously stated, is the most expensive and therefore the least desirable method for 

controlling drill solids. In this case, a program of continuous dilution results in the dilution of the 

already diluted fluid in each circulation cycle. Continuous fluid treatment to control chemical 

concentrations, rheological and filtration properties, and density maintenance is required. A more 

practical and economic method once considered is displacement. In this case, a measured volume 

of the drilled solids contaminated drilling fluid is dumped and replaced with an equal volume of 

drilled solids free fluid having the proper density, chemistry, rheological, and filtration 

characteristics. In order for this procedure to be cost effective, the surface volume should be 

maintained at minimum levels. 

The concept of dilution vs. displacement economics has taken on other significance since the 

disposal of fluids/solids/drilled cuttings came under more strict environmental regulation. Current 

practices involve the minimization of all drilling fluids/solids waste. The application and effective 

operation of mechanical solids removal equipment will minimize fluid dumping requirements. 

Mechanical solids removal equipment should be sized and operated to remove maximum drilled 

solids possible on a “first pass” basis. This will minimize the opportunity for drilled solids being 

broken down into smaller sizes by repeated passage through the circulating system. This practice 

will minimize dilution and dumping requirements. 

The various types of solids removal equipment are described below. 

Vibrating Screen Separators 

Vibrating screens (shale shakers) are the first mechanical devices in the solids control system to 

process the fluid. Maximizing the removal of solids at this point will increase the efficiency of the 

remainder of the solids equipment utilized. 

In unweighted fluid systems, maximum removal with shakers will reduce the solids loading on the 

desander, thus lowering the chance of an overload condition, which in turn, will lower the chance 

of overloading the downstream desilter. The cascading effect of a solids control system points out 

the importance of having each piece of equipment operate to its maximum potential, thus allowing 

the downstream units to do the same. Since the operation of the shaker affects the remainder of the 

equipment, it must be sized and utilized correctly for the system to remove the maximum amount 

of solids. 

Fine screen shakers should be used on any operation where optimum solids control is desired, but 

they are particularly suited for operations employing weighted fluids, high-cost fluid-phase fluids, 

and oil-base fluids. When weight material is carried in the fluid system, the options for removing 

solids without removing the weight material are limited to screening and centrifuging. If weighted 

2 Beasley, R.D. and Dear, S.F. III, A Process Engineering Approach to Drilling Fluids Management, SPE 

19532, Presented at the 64 th Annual Technical Conference, San Antonio, TX, October 8-11, 1989 



REFERENCE MANUAL


oil fluids are used, then even centrifuging is not feasible because of economic and environmental 

reasons. Dual centrifuging an oil or synthetic is done to strip and clean mud plant fluids In this 

case, it is very important to have optimum solids removal at the shale shaker. It would be contrary 

to sound engineering practices to spend thousands of dollars for an oil-base fluid system or any 

inhibited system to retain “cuttings integrity” without utilizing the most efficient solids control 

equipment available. An inhibited system (such as CARBO-DRILL SM or NEW-DRILL ® ) cannot 

achieve its full potential and be cost-effective if the cuttings are re-circulated and ground down into 

very fine particle sizes. 

Two basic designations are used for shakers presently in the field – rig (scalper shaker) and highspeed 

shakers. Normal operation of scalper shakers would typically employ the use of screens in 

the 10- to 40-mesh range. The removal of large drill cuttings at this stage will increase the 

efficiency of the downstream high-speed shakers. The term high-speed refers to a unit that is 

capable of operating with fine screens. These units also are commonly referred to as linear motion, 

premium, and high-efficiency shakers. The term high-speed had its origin with some of the early 

improved shakers that operated with speeds in the range of 3600+ rpm. Although very few shakers 

have this speed on the vibrator shaft at present, the term stuck. Linear motion refers to the action 

that the vibrating assembly transmits to the screen deck, in this case a reciprocating motion. Figure 

10-2 demonstrates three typical screen motions. 

Figure 10 - 3 Typical Screen Motions 

Regardless of the particulars of the machine, the most important point to remember is that the goal 

is to remove the maximum amount of solids, and this is done by running a screen with the smallest 

openings. If we assumed the average particle size of formation solids (in fluid returns) was 80% 

finer than 838 microns and 70% larger than 178 microns, theoretically only 20% could be removed 

with the 20-mesh screen, whereas 70% could be rejected with the 80-mesh screen. 

Fine shaker screens come in a multitude of designations, and no single measurement adequately 

describes a screen's solids removal capabilities and throughput. Mesh is the linear measurement of 

the number of openings per inch. The aperture is the actual opening dimension which controls the 

maximum size particle that can pass through a screen. Two screens with the same mesh, if woven 

with different diameter wires, will have different apertures. 



REFERENCE MANUAL


The current API screen designation system states that no fewer than the following minimum 

elements be stated: 

• Equivalent Aperture in microns 

• Conductance (Kilodarcies/mm) 

• Non-blanked area (ft 2 ) 

• Manufacturer’ Designation / Part Number 

Optional but recommended information includes: 

• Manufacturer’s name 

• Country of manufacture or assembly 

This description is sufficient for single-layered screens, but with the advent of multiple-layered 

screens and bonded screens, this designation falls short in describing the effective cut point of a 

screen, the ability to pass fluid and the actual screen area available to pass fluid. 

A new description is recommended to be attached to all screen panels and will call for, 

• cut point at D-50 and D-95 

• conductance 

• percentage of total screen area available for screening. 

A D-50 cut point is defined as the point measured in microns where 50 volume % of the solids are 

larger than the size specified and 50% are smaller than the specified micron size. D-95 indicates 

that 95% are smaller and 5% are larger than the micron size specified. See Figure 10-4 for some 

typical solids distribution curves and the indicated D-50 points. 

Conductance is defined as the permeability of the screen cloth divided by the thickness of the cloth, 

and is usually given in kilodarcys per millimeter (kd/mm). Permeability of the screen is a function 

of the opening size and the wire geometry. Basically, it is a measure of the ease with which fluid 

will flow through the screen. No units will be indicated on screen conductance designation, as this 

will be a relative measurement. 

Commonly manufactured screen cloths come in square mesh and rectangular mesh. These are used 

to build screens in many combinations from single layers, for the coarser meshes, to every 

conceivable combination of square and rectangular meshes stacked together. The square mesh 

removes more randomly shaped solids than a rectangular mesh having the same minimum aperture 

dimension. For the same minimum aperture on one dimension, the rectangular screen has a higher 

fluid capacity since the percent open area is greater. Also, the rectangular screen can be woven of 

heavier wires, thus offering a potential for longer screen life. This longer life and increased 

throughput versus lower solids removal potential are typical tradeoffs to be considered when 

selecting a screen. 

Table 10-3 lists U.S. Test Sieve Numbers. These sieve numbers each have a standard opening size 

given in microns. The sieve number refers to the mesh count of the given screen. Cut points of 

screens will be referred to commonly either using the sieve number or the micron cut point. 



REFERENCE MANUAL


Test Sieve Opening, µm Test Sieve Opening, 

No. No. µm 

5 4000 60 250 

6 3350 70 212 

7 2800 80 180 

8 2360 100 150 

10 2000 120 125 

12 1700 140 106 

14 1400 170 90 

16 1180 200 75 

18 1000 230 63 

20 850 270 53 

25 710 325 45 

30 600 400 38 

35 500 450 32 

40 425 500 25 

45 355 635 20 

50 300 

Table 10 - 3 ASTM Sieve Designation 3 

The number usually given in screen designations can be misleading. It can refer to micron opening 

size, number of openings per inch, U.S. Test Sieve equivalent opening size, sum of wires in each 

direction, or average cut point related to U.S. Test Sieve screens. 

Two common screen cloths used for the manufacture of screens are market grade (MG) and tensil 

bolting cloth (TBC). These terms refer to wire sizes used in the manufacturing of the screens, 

market grade being a coarser wire than tensil bolting cloth. Some manufacturers use wire diameters 

finer than tensil bolting cloth to achieve a greater open area on the screen while maintaining the 

mesh count. This results in a weaker wire that will pass larger solid particles. 

Solids Removal by Centrifugal Force 

All mechanical devices for solids control, excluding vibrating screens, depend upon particle 

separation by size and specific gravity of particles. Examination of the equation describing the 

settling rate of particles indicates that the settling velocity of a particle depends upon particle size, 

particle density, liquid density, liquid viscosity and the gravitational force induced. The 

relationship of these factors is demonstrated by Stokes' equation for settling velocity. 

where, 

V 

G d 

= 

2 

( )( − ) 

D S 

D M 

μ 

V = settling rate, cm/sec 

3 ISO API RP 13C July 2004 



REFERENCE MANUAL


G = the gravitational constant, cm/sec 2 

d = the diameter of the particle, cm 

D S = density of the particle, S.G. 

D M = density of the fluid, S. G. 

µ = viscosity of the fluid, centipoise 

In general, 

• The smaller of two particles of the same specific gravity has a lower settling velocity. 

• The heavier of two particles of equal diameter will settle faster. 

• The higher the fluid density, the lower the settling velocity. 

• The higher the viscosity, the lower the settlin g velocity. 

For example, it can be calculated that a barite particle (4.2 specific gravity and 4-microns in 

diameter) will settle at approximately the same rate as a low-gravity particle (2.6 specific gravity) 

having a diameter of 6 microns. 

Hydrocyclones 

Hydrocyclones are used for desanding, desilting and salvaging barite. Figure 10-4 is a crosssectional 

view illustrating the operating principle of a hydrocyclones. 



REFERENCE MANUAL


Figure 10 - 4 Cross-Sectional View of Hydrocyclone Operation 

Desanding hydroclones are usually 6 inches or larger in diameter. As the name implies, desander 

hydroclones are designed to handle large volumes of fluid and remove essentially all low-gravity 

particles above 74 microns, the sand designation size. The desander is economical and performs 

very well in low solids, inexpensive drilling fluids. 

Desanders, operated with a spray discharge, will normally make a 30-micron median cut on low- 

drilling fluids. Median cut implies that there is a 50-50 chance for 

gravity solids in low-density 

particles of 30 microns and above to be ejected through the underflow opening, normally called the 

apex valve. Median cut is called the D-50 cut point. A 30-micron median 

cut on low-gravity solids 

would be equivalent to a 20-micron median cut on barite. Since quality barite normally contains 

40% of particles greater than 20 microns in size, it would be economically impractical in most 

cases to desand a weighted drilling fluid. An exception to this would be in higher viscosity drilling 

fluids where the median cut point would be greatly increased. In these cases, it may be practical to 

desand a weighted drilling fluid for short intervals providing the barite content of the underflow is 

closely monitored. 

Hydroclones are normally rated using water which provides the minimum viscosity possible. This 

results in reported cut points that are comparable from one unit to the next, but do not give realistic 

numbers that can be related to a drilling fluid. Because the cut point is directly proportional to the 

viscosity of the fluid, the actual performance on a viscosified fluid will be much higher than the 

manufacturer's specifications. Remember, cut points mentioned here are based on optimum 

conditions. 

Twelve inch diameter desander cyclones are the most common and will process approximately 500 

gal/min with 75 ft feed head. This is equal to 35 psi when a 9 lb m /gal is being processed. Sufficient 

cyclones should be utilized to process 1.25 to 1.5 times the maximum circulating rate. The back 

flow in the fluid pit, caused by this excess of processing capacity from the desander discharge pit to 

the suction pit, will ensure that all of the fluid is processed. In each and every case where 

hydrocyclone solids processing equipment is being utilized, fluid back flow is important 



REFERENCE MANUAL


Desilters are hydroclones which are normally 4 in. in diameter and will process 50 to 80 gal of 

fluid per minute per cone depending on manufacturer. Feed head requirements range from 75 to 96 

ft with the most common requirement being 75 ft. Desilters with a spray discharge will make a 16- 

to 18-micron median cut on low-gravity solids. A sufficient number of cones should be provided to 

process 1.25 to 1.5 times the circulating rate for maximum efficiency. 

It is most important that desilters be employed at the start of an operation and run almost 

continuously until a weighted drilling fluid is required. If desilting is delayed or utilized only parttime, 

the recycled drilled solids will rapidly degrade into particle sizes too small to be removed by 

the desilter. 

The general operating parameters for hydrocyclones is presented in Table 10 – 4 as follows: 

Press 

(psi) 

2" 4" 6" 12" 

Head Vol Press Head Vol Press Head Vol Press Head 

(ft) (gpm) (psi) (ft) (gpm) (psi) (ft) (gpm) (psi) (ft) 

Vol 

(gpm) 

35 75 20 35 75 60 35 75 100 35 75 500 

Table 10 - 4 Recommended Hydrocyclone Feed Head Requirements (Pressures based 

on 9 lbm/gal fluid) 

The quantity of solids removed from an unweighted system by a hydrocyclone can be calculated as 

follows. 

W S = 97(D μ – 8.33)(Q µ ) 

where, 

Ws = lb solids removed per hour per cone 

Dµ= density of underflow, lb m /gal 

Qµ = underflow rate, gal/min. 

Smaller diameter hydrocyclones (usually 2 inches in diameter) have been used for barite salvage. 

Under ideal conditions, these cones will make a D-50 cut on barite in the 4- to 6-micron range and 

a 7- to 10-micron out on low-gravity solids. Barite recovery efficiency is less than that obtained 

with a centrifuge which should give D-95 cut in the 4- to 6-micro range. 

Figure 10-4 illustrates approximate performance curves for various diameter hydrocyclones. These 

curves are for low-gravity solids in unweighted drilling fluids. 



REFERENCE MANUAL


Fluid (Mud) Cleaners 

Figure 10 - 5 Typical cyclone Performance (Comparison by Size) 

The hydroclone/screen combination consists of a bank of desilters which are mounted over a fine 

mesh vibrating screen (140- to 200-mesh). The desilter underflow is processed by the fine screen. 

Particles removed by the screen are discarded and the fluid processed through the screen is returned 

to the active system. The effluent or desilter overflow is also returned to the active system. The 

fluid cleaner is essentially a fine screen shaker. Its primary purpose is to remove that portion of 

sand-sized or larger particles that pass through the rig shaker. Ideally, a 200-mesh screen would be 

desirable on the fluid cleaner, however, a 140- to 150-mesh screen is generally necessary to 

minimize barite losses. 

Fluid cleaners are not recommended on low-weight systems which can utilize a desilter, since the 

desilter will remove more solids down in the fine range. On the other hand, on unweighted systems 

with very expensive liquid phases, the fluid lost at the desilter underflow may be economically 

prohibitive (oil fluids, polymer-KCl fluids, etc.). In these cases, a fluid cleaner may be of assistance 

in the control of drilled solids. 

The fluid cleaner is not a centrifuge and does not replace a centrifuge on weighted systems. 

However, this device does fill a gap if premium shakers are not employed with a weighted drilling 

fluid. Rig shakers may only be able to use an 80-mesh screen which removes drilled solids larger 

than 178 microns. The centrifuge removes drilled solids smaller than 4- to 6-microns, so it is 

apparent that a particle that passes through the 80-mesh screen will be retained in the system until it 

is ground down to the 4 to 6 micron range. Utilizing a fluid cleaner with 200-mesh screens would 

give a 74-micron cut and fill the gap. 

Removal of particles in the 74 to 178 micron range with the fluid cleaner could produce the 

following benefits. 



REFERENCE MANUAL


• Improved filter cake quality (less coarse drilled solids) results in a less-permeable, less-porous cake. 

Improved cake quality (thinner and tougher) can minimize wall sticking and reduce frictional forces 

between drillstring and wellbore. 

• A decreased concentration of drilled solids contributes to improved rheological properties and 

reduced fluid maintenance costs. 

Centrifuges 

Centrifuges use centrifugal force, as do hydroclones, to shorten and/or control the settling time 

required to separate solids from liquids. Centrifuges utilize an external force to rotate a separation 

chamber and increase centrifugal force. This G-force can be calculated using the following 

formula. 

where, 

G = G-force 

G = 0.0000142(r 2 )(d) 

r = revolutions per minute 

d = inside diameter of the bowl in inches. 

Practical application of the barite recovery centrifuge for processing drilling fluids considers the 

following. 

1. It is a common misconception that centrifuges separate low-gravity solids from barite, but this 

would only be possible if all barite in a system was above 3 to 4 microns and all low-gravity 

solids were below the 4 to 6 micron range. Under field operating conditions, approximately 10% 

of barite is below 3 microns in size and 20% to 50% of low-gravity solids are below 6 microns 

in size. The solids removed with a centrifuge are the very fine particles which have a greater 

relative effect on rheology than the coarser particles. 

2. Centrifuging will not eliminate the need for water. Water will still be required to replace that lost 

through the centrifuge and to the wellbore. Dilution requirements will however, be reduced and 

drilling fluid maintenance cost reduction can be expected. This is particularly true in areas where 

reactive formation solids are prevalent. 

3. Day-to-day trends in plastic viscosity can give an indication of how fast solids concentration is 

increasing and can be used as a guide for operating the centrifuge and/or addition of water. 

Bentonite content, as measured by Cationic Exchange Capacity (CEC) using the Methylene 

Blue Test (MBT), and solids content, as determined by retort analysis, can also be of assistance 

in determining the need for centrifuging and/or water additions. 

There are basically three types of decanting centrifuges. The types are grouped depending on the 

G-force, rpm, cut point, and feed capacity. 

1. Barite Recovery Centrifuge – Used primarily for viscosity control. These centrifuges 

operate in an rpm 

range of 1600 to 1800 rpm and generate a G-force from 500 to 700 

Gs. Cut point will be between 6 to 10 microns for low-gravity solids and 4 to 7 microns 



REFERENCE MANUAL


for high-gravity solids. Feed rates normally run from 10 to 40 gpm depending on the 

density of the whole fluid. This centrifuge will strip barite above the cut point from the 

fluid and discard the liquid phase with the remaining fine solids. 

2. High Volume Centrifuge – Used primarily for discarding low-gravity solids from the 

fluid. It is so named because processing rates range from 100 to 200 gpm. Normal rpm 

ranges from 1900 to 2200 rpm. G-forces average about 800 Gs. The cut point attained is 

from 5 to 7 microns on unweighted fluid applications. 

3. High Speed Centrifuge – Used for removal of low-gravity solids from unweighted fluid 

systems and as second centrifuge in dual-centrifuging applications. This group of 

centrifuges turn from 2500 to 3300 rpm. G-forces created by these units range from 

1200 to 2100 Gs. Cut point can be as low as 2 to 5 microns. Feed rates will range from 

40 to 120 gpm depending on application and the fluid to be processed. 

The term dual-centrifuging comes from the use of two centrifuges in tandem. Effluent from a barite 

recovery unit is used to feed the second centrifuge. The benefit of this operation is that some solids 

can be removed from the low end of the size range without the loss of the fluid phase. 

For example, if the barite recovery unit is making a cut at 8 microns, then the fluid feed to the 

second centrifuge will basically have solids 8 microns and smaller. The second centrifuge should 

be capable of achieving higher Gs than the first and make a cut in the 2- to 5-micron range. The 

fluid phase is returned to the fluid and the solids discarded from the system. As demonstrated, this 

combination of centrifuges does not remove the ultra-fine and colloidal solids from the system, but 

it does remove solids that may be degradating down to that range. This will prolong the need for 

dilution and displacement of the fluid. Dual centrifuging has possible economic justification in 

situations where environmental restrictions will not allow reserve pits, or where the liquid phase of 

the fluid has high economic value. It needs to be remembered, though, that the use of these units 

will not solve any solids problems with the fluid, only delay them. 

The principle of the decanting centrifuge is illustrated in Figure 10-6 

Figure 10 - 6 Solid Bowl Decanting Centrifuge 



REFERENCE MANUAL


Some suggested guidelines for operation of barite recovery decanting centrifuges are: 

1. Effluent viscosity – 35 to 37 sec/qt. 

2. Effluent density – 9.5 to 9.7 lb m /gal. It may be greater if excessive quantities of barite are near 

colloidal. 

3. Underflow density – usually 20 to 23 lb m /gal. It may be less depending on volume of low-gravity 

solids in the barite size range. 

4. 

5. 

Bowl speed – 1600 to 1800 rpm 

Dilution of feed fluid – 25% to 75% (10.5 to 11.5 lb m /gal). Dilution rate increases as viscosity 

and density increase. 

6. Process rate – see Figure 10-7. 

7. Percentage of low gravity solids removed - normally 30% to 60%. 

8. Chemical removal – underflow of decanting centrifuge will contain 15% to 30% of chemicals 

present in original drilling fluid. 

9. Volume decrease – 70% to 85% of fluid centrifuged. Depends on volume of solids in the 

recoverable range. 

10. ALWAYS WASH OUT THE CENTRIFUGE THOROUGHLY PRIOR TO SHUT DOWN 

Figure 10-7) illustrates comparative processing capabilities for decanting centrifuges and 

concentric cylinder (RMS) centrifuges. 

Figure 10 - 7 Process Rate of Barite Recovery Decanting Centrifuge 



REFERENCE MANUAL


RMS Centrifuge 

There is an alternative to the use of a decanting-bowl centrifuge for barite recovery. It is the RMSnot 

make 

type centrifuge. This type unit is particularly applicable where rig-up restrictions will not allow use 

of a decanting-type unit. Although this unit is capable of handling more fluid, it tends to 

as fine a cut on the barite as a decanting unit does. Also, because the returned phase is wetter, it 

will contain a higher percentage of undesirable solids. 

General Operation of the RMS Centrifuge 

The separation chamber of the centrifuge consists of a stationary case and a perforated cylinder 

which revolves concentrically within the case. The combined discharge from two metering pumps 

supplies a fluid/water mixture which is introduced to the separator chamber annulus between the 

stationary case and the rotating perforated cylinder. As the diluted mixture enters the case, the 

rotation exposes all solid particles to centrifugal force, moving them away from the rotor and 

toward the case wall. The condensed phase moves through the case along the walls and exits at the 

underflow port. The lighter phase moves toward the center of the perforated cylinder and exits 

through the overflow tube. 

Figure 10-8 is a schematic of an RMS separation chamber. 

Closed-Loop Systems 

Figure 10 - 8 RMS Separation Chamber 

Closed-loop systems describe any operation where no reserve pit is utilized. This is commonly due 

to environmental restrictions, but may be caused by space limitations, cost to build and close the 

pit, or expense of the liquid phase. Depending on the economics of disposing of excess fluid and 

cuttings, the system may consist of no additional equipment on the rig to a full-blown system that 

includes all the mechanical equipment necessary to achieve maximum solids removal and a 

dewatering operation to finish the removal of all excess solids. 

The function of a closed-loop operation, where disposal costs are high, is to minimize the haul-off 

by condensing the discards to the minimum volume. For instance, if 9 lb m /gal fluid is hauled off, 



REFERENCE MANUAL


then you would only be removing 45.5 lb of solids for each bbl removed. If you would condense 

these solids by use of a centrifuge to 40% by volume solids, then for each bbl hauled off, 363.9 lb 

of solids would be removed. To achieve this same pounds of removal with whole fluid would 

require hauling 8 bbl of fluid. This would represent an 8 to 1 savings in hauling cost and disposal 

cost. 

The term closed-loop system, when only mechanical equipment is employed to remove the solids, 

is more often than not a misnomer. That is, there is a limit on how long the operation of the fluid 

system can go before fluid has to be displaced due to solids build up. The fact is, mechanical 

equipment screens, centrifuges, etc. cannot economically remove solids that are in the colloidal 

size range. If the closed-loop system is rated at 85% solids removal efficiency, then the other 15% 

of the solids will have to be removed by displacing whole fluid. Not “opening up” the loop to 

remove these excess solids is a common operational problem and will result in a fluid system that 

has flow properties and fluid loss that are hard to control. This in turn causes chemical additions 

above normal to counteract the excess of colloidal solids and the “loop” will ultimately have to be 

“opened” to discard the excess solids. 

Figures 10-9 and 10-10 depict the arrangement of mechanical solids removal equipment on a 

closed-loop system for unweighted and weighted fluid systems respectively. The addition of the 

dewatering system will make the closed-loop complete and allow it to truly reflect the name 

“closed-loop system.” This is achieved by removing the excess 

solids that remain in the fluid after 

the mechanical processing. 

Figure 10 - 9 Closed Loop Solids System – Unweighted Fluid 



REFERENCE MANUAL


Figure 10 - 10 Closed Loop Solids System – Weighted Fluids 

Typical Equipment Configurations 

Figures 10-11, 10-12, 10-13, and 10-14 describe the proper arrangement of equipment for common 

drilling situations. Note that the figures also indicate the positioning of the weirs between the 

compartments to control the flow direction of the fluid being processed. 

Figure 10 - 11 Unweighted Fluid: Centrifuge Processing Active System 



REFERENCE MANUAL


Figure 10 - 12 Unweighted Fluid: Centrifuge Processing Hydrocyclone Underflow 

Figure 10 - 13 Weighted Water-Base Fluid: Single-Stage Centrifuging (Barite 

Recovery) 



REFERENCE MANUAL


Figure 10 - 14 Weighted Fluid: Two Stage Centrifuging 

The dewatering system operates by destabilizing the fluid chemically, which causes coagulation of 

the solids, and then by chemically flocking the solids. “Flocked” solids and liquid are then 

separated by use of a centrifuge or screwpress to achieve maximum concentration of the solids in 

the discard and maximum return of the solids-free liquid to the fluid system. 

The benefits vary when utilizing a dewatering system depending on the fluid type. Besides the 

primary benefit of reduced haul-off, reduction in fluid maintenance can be realized for two reasons, 

(1) the amount of solids carried in the fluid can be controlled without total dependence on chemical 

thinners and, (2) any soluble materials in the liquid phase will be returned to the system after the 

flocculation process. However, it should be noted that some additives are removed depending on 

the ionic charge of the chemical flocculants and the concentration used. This will reduce the cost 

of fluid built to replace that lost with the solids. 

Calculations Used in Solids Control Evaluations 

The following equations are based on the fact that the specific gravity (S.G.) of the fluid is equal to 

the sum of the specific gravity times the volume fraction of each of its components. In these 

simplified equations, the fluid will consist of three basic components – liquid, low-gravity solids, 

and high-gravity solids. 

S M = (V W )(S W ) + (V LG )(SLG) + (V HG )(S HG ) 

1. Average spec ific gravity of solids in water-base fluids. 

• Freshwater fluid 

S 

a 

= 

[ 0.12( 

D )] 

V 

m 

s 

−V 

w 



REFERENCE MANUAL


• Saltwater fluid 

S 

a 

= 

[ 0.12( D )] − [( V )( S )] 

m 

V 

sc 

wc 

w 

V 

= 1. 0 − 

sc 

V wc 

Volume of saltwater corrected (V wc ) and specific gravity of the water (S w ) are obtained from the 

appropriate salt table in Chapter 6, Reservoir Application Fluids. 

2. Volume fraction solids in freshwater fluid containing all low-gravity solids (2.6 S.G.) 

( ) 

V s 

= 0.075 

Dm 

−8.33 

3. Volume fraction of barite (4.2 S.G.) and low-gravity solids 

b 

( S 6)( V ) 

V 0. 

625 − 2. 

= 

a 

sc 

V 

lg 

= V sc 

−V b 

4 Volume fraction of hematite (5.0 S.G.) and low-gravity solids 

h 

( S 2. )( V ) 

V = 0.417 

− 6 

a 

sc 

V 

lg 

= V sc 

−V h 



REFERENCE MANUAL


NOMENCLATURE 

Cl 

D m 

S a 

S m 

S w 

Total chloride in mg/L (titration value) 

Fluid density, lb m /gal 

Specific gravity of solids (average) 

Specific gravity of fluid 

Specific gravity of water 

V Volume of barite, MIL-BAR ® 

b 

V h Volume if hematite, DENSIMIX ® 

V hg 

V lg 

V s 

V sc 

V w 

V wc 

Volume of high-gravity solids* 

Volume of low-gravity solids* 

Volume of solids* 

Volume of solids corrected for NaCl* 

Volume of water* 

* Expressed as a decimal fraction. 

Volume of water corrected to include NaCl* 



REFERENCE MANUAL

Horizontal & Extended 

Reach Drilling 

Chapter 

Eleven 

Horizontal & Extended Reach Drilling

Chapter 11 


HORIZONTAL & EXTENDED-REACH DRILLING .........................................................................11-1 

INTRODUCTION...............................................................................................................................11-1 

EXTENDED REACH DRILLING..............................................................................................................11-1 

HORIZONTAL TECHNIQUES .................................................................................................................11-3 

Long-Radius Technique ...............................................................................................................11-3 

Medium-Radius Technique..........................................................................................................11-3 

Short-Radius Technique ..............................................................................................................11-5 

Ultra-Short Radius Technique.....................................................................................................11-6 

Horizontal Techniques Summary................................................................................................11-7 

DRILLING FLUID PROPERTIES AND SELECTION.................................................................................11-7 

Borehole Instability........................................................................................................................11-8 

Cause..........................................................................................................................................11-8 

Control.........................................................................................................................................11-8 

Shale Interaction........................................................................................................................11-9 

Classifications ........................................................................................................................11-9 

Hole Cleaning ..............................................................................................................................11-11 

Flow Characteristics................................................................................................................11-11 

Fluid Viscosity..........................................................................................................................11-11 

Cuttings Bed Formation..........................................................................................................11-13 

Hole Cleaning Sweeps ...........................................................................................................11-14 

Short Tripping ..........................................................................................................................11-14 

Drill String Rotation .................................................................................................................11-14 

Turbulence................................................................................................................................11-15 

ADVANTAGE Hole Cleaning Modeling ...............................................................................11-15 

Hole Cleaning Guidelines ......................................................................................................11-17 

Torque and Drag .........................................................................................................................11-18 

Fluid Lubricity...........................................................................................................................11-18 

Filter Cake ............................................................................................................................11-20 

Formation Damage .....................................................................................................................11-21 

Examining the Formation .......................................................................................................11-21 

Core Permeability Testing......................................................................................................11-22 

Recommended Fluid Parameters.............................................................................................11-24 

REFERENCES.....................................................................................................................................11-26 


FIGURE 11 - 1 MEDIUM-RADIUS APPLICATIONS INDUSTRY ERD WELLS........................................11-2 

FIGURE 11 - 2 SCHEMATICS OF MEDIUM-RADIUS APPLICATIONS. ..................................................11-4 

FIGURE 11 - 3 SCHEMATICS OF WELLBORE RADIUS IN UNSTABLE FORMATIONS..........................11-5 

FIGURE 11 - 4 SCHEMATIC OF ULTRA-SHORT RADIUS ....................................................................11-6 

FIGURE 11 - 5 RANGE OF SHEAR RATES IN THE FLUID CIRCULATION SYSTEM ...........................11-12 

FIGURE 11 - 6 EFFECTIVE VISCOSITY VS SHEAR RATE .................................................................11-12 

FIGURE 11 - 7 ADVANTAGE HOLE CLEANING EXAMPLE 1..........................................................11-16 

FIGURE 11 - 8 ADVANTAGE HOLE CLEANING EXAMPLE 2..........................................................11-16 

FIGURE 11 - 9 COMPARISON OF LUBRICITY COEFFICIENTS – BAROID LUBRICITY TESTER .........11-19 

FIGURE 11 - 10 PERMEAMETER SCHEMATIC DIAGRAM....................................................................11-22 

FIGURE 11 - 11 RETURN PERMEABILITY DATA ON COOK INLET CORES .........................................11-23 



REVISION 2006 11-i



TABLE 11-1 SHALE COMPOSITION.............................................................................................. 11-9 

TABLE 11-2 COMPARISON OF DRILLING FLUIDS...................................................................... 11-25 


REVISION 2006. 


11-ii

HORIZONTAL AND EXTENDED REACH DRILLING 

Chapter 11 

HORIZONTAL & EXTENDED-REACH 

DRILLING 

Horizontal and Extended Reach Drilling techniques are commonly used in the development 

phase of oil and gas fields. These types of operations present many challenges in drilling fluid 

design. 

INTRODUCTION 

Horizontal and extended-reach drilling are not new technologies. Variations of these techniques 

were in use 50 years ago. With current state-of-the-art equipment, wells that were once considered 

marginal and uneconomical potentially become high-return development projects. 

Compared to a vertical well, a horizontal hole or extended reach well in a productive formation 

increases the total percent of the wellbore drilled through the pay zone, resulting in these benefits. 

• Accelerated production rates 

• Total recovery improvement 

• Through reductions in pressure gradients, water and gas coning problems are limited. 

Operators make use of these technologies to improve and accelerate the replacement of reserves. 

According to several surveys of oil and gas producers worldwide, over 50% of wells drilled in the 

near future will utilize horizontal and extended-reach technologies. 

Horizontal and extended-reach terms are often used synonymously, but in fact they are 

fundamentally different. One definition of a horizontal well states that a well is considered 

horizontal if the producing reservoir is penetrated with the intent of never leaving that stratum. 

Therefore, a well does not have to be 90° to be classified as a horizontal well. A prospect can be 

defined as an extended-reach well when the wellbore is over 60° to 70° with a horizontal 

displacement of 10,000 ft. Such wells are drilled with a single-bend or steerable motor that can be 

rotated from the surface. No formal accepted definitions have been established however, and the 

above examples are meant to show the differences only. 

EXTENDED REACH DRILLING 

Extended Reach Drilling (ERD) has evolved from simple directional drilling to horizontal, lateral, 

and multi-lateral step-outs. ERD employs both directional and horizontal drilling techniques and 

has the ability to achieve horizontal well departures and total vertical depth to deviation ratios 

beyond the conventional experience of a particular field. ERD can be defined in terms of reach/true 

vertical depth (TVD) ratios. An extended reach well is commonly defined as a well having a reach 



REVISION 2006 11-1


to TVD ratio in excess of 2:1. Relative difficulty is a function of both reach/TVD ratio and absolute 

TVD, commonly referred to as Aspect ratio. 

Constraints to successful ERD include downhole drill string and casing movement, applying 

weight to the drill bit, possible buckling of casing or drill string, and running casing successfully to 

the bottom of the well. Tension may be a primary concern in vertical wells, but in ERD, torsion 

may be the limiting factor. Running normal weight drill pipe to apply weight 

TVD BRT (ft) 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

Industry ERD Wells 

Departure (m) 

0 2,000 4,000 6,000 8,000 10,000 12,000 

0 

1,000 

2,000 

3,000 

4,000 

Industry ERD Envelope 

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 

Departure (ft) 

5,000 

6,000 

7,000 

8,000 

9,000 

TVD BRT (m) 

Courtesy, K&M Technology 

Figure 11 - 1 

Medium-Radius Applications Industry ERD Wells. 

to the bit in ERD can lead to buckling of the drill pipe and rapid fatigue failure. Conventional 

drilling tools are prone to twist-off, because of unanticipated failure under the high torsional and 

tensile loads of an extended reach well. Torque can be significantly reduced with the use of nonrotating 

drill pipe protectors. Advanced equipment for an ERD well may include wider diameter 

drill pipe, additional mud pumps, enhanced solids control, higher capacity top drive, more 

generated power and invert emulsion drilling fluids. ERD requires longer hole sections, which 

require longer drilling times. The result is increased exposure of destabilizing fluids to the 

wellbore. The superiority of invert emulsion drilling fluids versus water based-fluids in ERD is 

widely recognized. Conventional water based fluids may not provide the inhibition or confining 

support of invert emulsion drilling fluids. 

Extended reach drill string design involves a) determining expected loads, b)selecting drilling 

string components, c) verifying each component’s condition, d) setting operating limits for rig 

team, and e) monitoring conditions during drilling. Economic issues in drill string planning include 

availability, logistics, and cost. Rig and logistics issues include storage space, accuracy of load 



REVISION 2006. 11-2


indicators, pump pressure/volume capacity, and top drive torque output. Hole issues include hole 

cleaning, borehole stability, hydraulics, casing wear, and directional objectives. 

Extended reach drilling from land locations has been used instead of offshore locations in several 

locations including the BP development at Wytch Farm, England, and the TOTAL project in Tierra 

Del Fuego. 

HORIZONTAL TECHNIQUES 

The industry has categorized three directional techniques as they relate to the radius formed by the 

curve of the well. These are long-radius, medium-radius, and short-radius. A fourth technique, 

ultra-short radius, is used much less frequently. A discussion of all of these techniques follows. 

Long-Radius Technique 

A long-radius well can be defined as a borehole with at least one hole section in which well 

inclination is increased at 1° to 10°/100 ft. Most of these wells are drilled with conventional 

downhole hardware. The kick-off point may be near the surface to allow the target to be reached at 

the correct depth. Due to the length of the build section, several hole sizes and casing strings may 

be necessary before the long-radius well reaches its objective. Long-radius wells are not normally 

taken to the horizontal due to excessive drag and torque. 

For example, a build rate of 4°/100 ft results in a radius departure of 1432 feet before the well 

reaches horizontal. 

The length of the radius equates to the measured depth that must be drilled to reach a given 

inclination. With a 4°/100 ft build rate noted above, controlled drilling of more than 2250 feet is 

required. 

An explanation of these calculations follows: The drilling of 2250 feet to achieve a deviation of 

90 0 which puts the drilling on a horizontal plane represents drilling ¼ of a complete circle. The 

circumference of a circle is defined by 2πr. Four (4) x 2250 = 9000. Dividing 9000 by 2π gives 

1432. 

Medium-Radius Technique 

A medium-radius lateral can be defined as a borehole with at least one hole section in which a well 

inclination is increased at 10° to 20°/100 ft. A majority of the horizontal wells use this technique. 

Medium-radius wells suit a wide variety of applications (see Figure 11-2), and have been 

successfully drilled off-shore in the North Sea, across the Gulf Coast, in the Rockies, and on the 

north slope of Alaska. 



REVISION 2006. 11-3


The nature of a reservoir has some effect on the suitability of medium-radius drilling, but much less 

so than with long-radius. Fractured reservoirs, like the Austin Chalk, may be the most economical 

use of the medium-radius technique to date. 

Figure 11 - 2 

Schematics of Medium-Radius Applications. 

The reduced vertical depth needed for medium-radius wells is an advantage of this technique. A 

medium-radius well requires less lease space to reach a horizontal target than a long radius well. A 

typical medium-radius curve requires less than 500 feet of departure, while a long-radius curve 

requires over 1400 feet. 



REVISION 2006. 11-4


Figure 11 - 3 

Schematics of Wellbore Radius in Unstable Formations 

Other advantages include reduced torque and drag. Also, no special equipment is necessary as in 

the case of the short-radius well. As a result, more equipment is available for these types of 

wellbores. 

An unstable or problematic formation yields the most unpredictable variation in build rate and 

vertical target accuracy. This situation is one of the most influential factors in determining which 

horizontal technique to use. 

Many troublesome zones are normally penetrated in the vertical section of a medium-radius well, 

and can be cased off before drilling the build and lateral sections. The shorter length of curved 

wellbore has proven less troublesome to operators than extended-reach wells (see Figure 11-3). 

Short-Radius Technique 

Short-radius drilling encompasses a wider range of build rates than any of the others discussed. 

Short-radius drilling is best defined by the use of flexible or articulated tooling to drill doglegs 

ranging from 1° to 3°/ft. 

The best use of this technique is for wells in leases of limited size. A short-radius and/or re-entry 

well could be turned to lateral and completed with less displacement than a typical long-radius well 

at 45°. This would make short-radius drilling quite attractive on leases less than 80 acres in size. 

Problems with this technique involve small hole sizes, downhole tool problems, and being able to 

hit a small target with consistency. Other difficulties involve completion techniques. 



REVISION 2006. 11-5


The small departure and limited depth required for short-radius wells makes them suitable in 

formations topped with problem-causing lithology or reservoirs. 

For example, in a thin lime bed topped with 1500 feet of heaving shale, a long-radius well would 

develop most, if not all, inclination in the trouble zone, while a short-radius well develops little or 

no angle in the shale. Thus, in a short-radius well, a troublesome zone can be cased off before 

critical hole drilling begins (see Figure 11-3). 

Ultra-Short Radius Technique 

The newest method of horizontal drilling is the ultra-short radius technique. This method uses highpressure 

fluid to jet a semi-horizontal borehole, the radius of which turns in a matter of inches 

rather than feet. 

The ultra-short radius technique uses specialized equipment and requires some wellbore 

enlargement in the vicinity of the lateral target. Hole sizes ranging from 2 in. to 6 in. are a function 

of formation and the jetting head used, while lateral departure is limited to several hundred feet. 

In limited terms, the ultra-short radius technique may be defined as a system having virtually no 

build section, with a lateral placed by means other than rotary bit drilling. 

Even though a hole could be jetted into hard rock, this system is clearly more suitable for soft, 

easy-to-penetrate formations, such as oil or tar sands. Ultra-short methods may also be feasible for 

solution mining and shallow ground water clean-up projects as well. As with any soft or 

unconsolidated formation, hole stability and integrity are primary concerns (see Figure 11-4). 

Figure 11 - 4 

Schematic of Ultra-Short Radius 



REVISION 2006. 11-6


Horizontal Techniques Summary 

The single most critical aspect of horizontal and extended-reach drilling is choosing the appropriate 

build rate (radius) to facilitate entrance of the reservoir at the target point. The following tables 

summarize the relative advantages and disadvantages of the three main horizontal drilling 

techniques with respect to reservoir/target entrance. 

Short-Radius 

Target Height Build Rate KOP Above TD 

5 to 20 ft 1° - 3°/ft ± 25 ft 

Short-radius techniques yield high build-rate predictability and good reservoir entrance control for 

very thin reservoirs. Drawbacks of the short-radius system include poor directional control 

(azimuth), poor correction ability, and limited lateral extension. 

Medium-Radius 


15 to 100 ft 10° - 20°/100 ft ± 250 ft 

Medium-radius techniques yield fair build-rate predictability and fair reservoir entrance control for 

moderately thin reservoirs. However, medium-radius drilling provides for good directional control 

(azimuth), good correction ability, and good lateral extension. The technique is applicable over the 

widest range of conditions. 

Long-Radius 


> 100 ft 1° - 10°/100 ft 1500 - 2000 ft 

Long-radius techniques offer fair build-rate predictability and poor reservoir entrance accuracy. 

Advantages include good directional control (azimuth), good correction ability, and great lateral 

extension. The major drawback is the increased costs associated with additional target control and 

measured footage. 

In summary, thin reservoirs requiring little extension should be drilled using short-radius 

techniques. Conversely, thick reservoirs requiring large lateral extensions should utilize long-radius 

techniques. Medium-radius drilling can be applied over a wide range of applications. For this 

reason, the majority of current wells employ medium-radius build rates. 

DRILLING FLUID PROPERTIES AND SELECTION 

It is common knowledge among drilling engineers and drillers that borehole problems can be 

considerably more severe in a directional hole than in a vertical well. The problems are magnified 

as the hole angle and horizontal displacement increases. Although most of these reactions are 

mechanical in nature, much can be done to alleviate them by proper selection and maintenance of 

the drilling fluid. For example, if a water-base fluid is being used, lubricants can be added to lower 

the coefficient of friction between the drill string and borehole or casing. Inhibiting salts can be 

added to reduce the interaction of the drilling fluid with the exposed formations, thereby improving 

borehole stability. 



REVISION 2006. 11-7


There are a number of drilling factors influenced by the drilling fluid, but the following are of 

primary concern in drilling a horizontal well. 

• Borehole instability 

• Hole cleaning 

• Torque and drag 

• Formation damage 

• Barite sag 

• Hydraulics 

Borehole Instability 

Borehole instability is one of the more costly, but relatively common problem associated with 

drilling oil and gas wells. Not only can it impede drilling, it can result in loss of the hole. The term 

normally conjures thoughts of borehole collapse with accompanying stuck pipe. This is one of the 

more critical reactions of borehole instability, but it can manifest itself in more subtle ways such as 

hole-fill, bridges, hole enlargement, or hole size reduction. 

These reactions lead to other associated problems including increased torque and drag, logging 

difficulties, poor cement jobs, and increased drilling days, all of which add significantly to the 

drilling cost. It should be pointed out that the discussions to follow do not cover hole enlargement 

problems from weakly consolidated sands, or rubble zones that erode from the hydraulic action of 

the drilling fluid. 

Cause 

In simple terms, the primary cause for hole instability occurs when the rock surrounding the hole 

fails to support the load that was previously taken by the removed rock. This removal results in a 

stress concentration around the wellbore. If the rock strength is sufficient to absorb this stress, the 

borehole will remain stable. If not, it will fail. Aadnoy, et al, found that borehole collapse is caused 

mainly by shear and tensile failure, while fracturing of the wellbore is predominantly caused by 

tensile failure. However, even if the rock is strong enough to withstand this stress concentration, 

exposure to the drilling fluid may weaken it to the point that failure will occur. 

Control 

The first consideration to controlling borehole instability is to increase the fluid density. By having 

the wellbore pressure carry some of the load, the stress of the borehole wall is reduced and 

compressive failure may be averted. However, if the fluid density is increased too much, a tensile 

fracture may occur, resulting in loss of circulation. 

Bradley showed through his stress cloud analyses, that the fluid weight required to prevent collapse 

increases significantly with increasing hole angle, while the fluid weight that can be tolerated 

before fracturing occurs (loss of circulation) decreases with increasing hole angle. These findings 

are confirmed by the work of Aadnoy and Chenevert and others. This places strict tolerances on the 

fluid density range that must be maintained in high-angle wells. Increases in mud weight of 

between 0.5 ppg and 1.0 ppg per 30 degrees inclination through shale/mudstone sections are 

usually necessary to prevent combat hole collapse. Experience in the local area will determine 

where in this range to be. The additional annular pressure losses when circulating – ECD - can lead 



REVISION 2006. 11-8


to the selection of a suitable drilling fluid density being even more difficult. The extent and effect 

of Equivalent Circulating Density (ECD) needs careful consideration. 

No increase in mud weight with hole inclination is necessary across permeable formations such as 

sands. Formations with reasonable matrix permeability can be drilled with nominal overbalance, 

regardless of well trajectory or formation strength. Fracture gradient may decrease with increased 

inclination. 

In locally tectonically stressed areas, e.g. Colombia, the collapse gradient may exceed the fracture 

gradient, even in vertical wells. In this case one or both of lost circulation and hole collapse must 

be tolerated to some degree. Thus, there is a limitation that can be accomplished by fluid weight, 

and it is therefore imperative that the virgin strength and integrity of the rock be maintained as 

much as possible. 

Shale Interaction 

Interaction of the fluid with the formation which produces instability is primarily related to shale 

bodies. Shales, which include other classifications such as mudstones, siltstones, and claystones, all 

contain a relatively high percentage of hydratable and expandable clays. Typical mineral 

compositions of a young marine shale and an older indurated shale are shown in Table 11-1. 

It is the interaction of these clays with the water phase of the fluid that weakens the shale structure. 

The absorption of water by the shales through capillarity or diffusion causes instability by creating 

internal stress, weakening of cementing components of the shale, and lubricating micro-fractures 

that may exist. 

Classifications 

Shales can be classified into three broad categories: 

1. Soft, sticky shales 

2. Dispersive shales 

3. Hard, brittle shale 

Component 

Quartz 

Feldspar 

Calcite 

Dolomite 

Illite 

Mixed Layer 

Kaolinite 

Chlorite 

Typical Gumbo Shale, Gulf of 

Mexico, % Composition 

5 - 10 

Trace 

2 - 3 

2 - 3 

20 - 25 

50 - 55* 

5 - 10 

5 – 10 

* Mixed layer has 50% expandable layers 

** Mixed layer has 25% - 35% expandable layers 

Table 11 - 1 Shale Composition 

Vicksburg Formation, Starr 

County, Texas, % Composition 

10 - 15 

2 - 3 

10 - 15 

⎯ 

25 - 30 

35 - 40** 

3 - 5 

5 - 10 



REVISION 2006. 11-9


These classifications obviously overlap, with the soft, sticky shales exhibiting some dispersion and 

the dispersive shales showing a tendency to ball on the bit and bottom-hole assembly. In general, 

however, these descriptions can be used to differentiate the behavioral characteristics of shale. 

• The sticky composition, often referred to as gumbo shale, is characteristic of many young 

marine shales and offers a challenge to the directional driller to gain and maintain angle if the 

balling cannot be controlled. 

• The dispersive shales manifest their behavior by being easily subdivided into their integral 

parts, resulting in excessive fluid solids, high fluid viscosities, and borehole enlargement. 

• The hard, brittle shales exhibit the classic behavior of spalling and sloughing with the 

associated problems – hole cleaning, hole fill, hole wash-out, bridges, and pack off. 

Extreme differences in behavior exist between the hard shale and the softer rock upon exposure to 

a freshwater clay-base fluid. The soft shale balls into a plastic mass while the hard shale 

disintegrates into slivers. 

An interesting point to consider is that once the hole has become essentially horizontal in the 

production zone, whether it be sandstone or carbonate rock, less borehole stability problems might 

be expected. Since the horizontal section of the borehole is being contained in one particular body 

of rock, there should be fewer discontinuities than going from one formation to another, and there 

would be fewer zones of weakness, unless of course, the production zone is highly fractured or 

faulted. 

Drilling Fluid Selection 

The proper selection and composition of the drilling fluid will depend upon the type or types of 

shale to be drilled. Invert emulsion fluids (oil or synthetic external-phase emulsions) can be 

prepared with the internal water phase containing sufficient electrolyte to show zero or even 

negative water absorption. Preventing water absorption by the formation effectively controls 

swelling and maintains the virgin cohesive strength between formation particles. Thus, oil fluids 

with the proper salinity of the internal water phase are extremely effective in stabilizing 

troublesome shale formations. 

Unfortunately, oil-base fluids have the disadvantage of being prone to loss of circulation and more 

difficult to regain circulation with than water-base systems. Nance reported that the density of the 

oil fluid needs to be maintained 2 lb m /gal below the lowest calculated fracture pressure for the 

exposed hole to minimize the probability of loss of circulation. Since the fluid density range 

narrows with increasing hole angle, this requirement could become a limiting factor for oil fluids in 

horizontal wells. The environmental aspect of oil fluids is also a deterrent to their use in some 

areas. 

Therefore, if the horizontal well is to be drilled in a troublesome shale area, there could be a need 

to select a water-base fluid that provides the most stable environment possible. Unlike the 

controlled activity oil-base fluids, water-base fluids expose the formation to water wetting 

regardless of the electrolyte content of the fluid. To counteract this effect requires a fluid that not 

only controls the swelling of the expandable clays in the shale, but also is capable of retarding 

dispersion as discussed in shale classification above. Although these two phenomena are related, 

they must be controlled by different mechanisms. 



REVISION 2006. 11-10


Stabilization 

The swelling activity is controlled by adjusting the electrolyte content of the fluid to minimize 

expansion of the clays. Lime and gypsum-treated fluids have long been used for this purpose, but 

basically do not satisfy the inhibition needs of the more troublesome shales. The potassium ion is 

an effective swelling inhibitor and is used extensively for this purpose through the addition of 

potassium salts. The concentration of potassium utilized ranges from several hundred mg/L to over 

60,000 mg/L. The most cost-effective potassium concentration, however, appears to be in the 3000 

to 7000 mg/L range. In marine environments, seawater or seawater with additional sodium 

chloride, are good alternates to potassium. The tendency for the shale to disperse or subdivide into 

discrete particles appears to be best controlled by the addition of an adsorptive, high molecular 

weight water-soluble polymer. 

One of the more effective polymers for this purpose is the partially hydrolyzed polyacrylamide 

with molecular weight in excess of 15 million. These anionic polymers adsorb on to the surface of 

the cuttings and borehole wall to act as a binder or elastic coating to retard dispersion. 

Another approach to stabilizing the hard brittle shales that contain natural or induced microfractures 

is the use of water-dispersible asphalt or asphaltines. The addition of these type materials 

appear to plug the micro-fractures, or perhaps even surface pore throats to retard further fluid 

invasion. This action has proven very effective in certain shales and can be applied in most waterbase 

fluids. 

Hole Cleaning 

Cleaning cuttings from a vertical hole has been covered extensively by numerous investigators. 

Hole cleaning in a vertical hole is essentially a matter of overcoming the slip velocity of the 

cuttings with sufficient annular velocity and carrying capacity of the drilling fluid. Although any 

velocity greater than the settling velocity of the largest cutting will theoretically lift all the cuttings 

to surface eventually, too low an annular velocity will lead to an undesirable high concentration of 

cuttings in the annulus. Experience has shown that cuttings concentrations more than 5% by 

volume cause tight hole or stuck pipe when circulation is stopped. 

Flow Characteristics 

Theoretically, turbulent flow is more effective than laminar flow, not only because of the higher 

annular velocities required to reach this flow regime, but it also provides a flatter velocity profile 

that reduces edge-wise slip of the cuttings. On the other hand, turbulent flow may cause erosion 

and hole enlargement. Although a competent formation may not erode even if the flow is turbulent, 

others will erode because of weakening upon exposure to the drilling fluid, or by having been 

fractured by tectonic movements. It may become impractical or impossible with the existing rig 

equipment to maintain turbulent flow in any particular well, especially in washed-out or enlarged 

sections. Also, certain fluid motors have limits which will not allow the fluid to be pumped fast 

enough to reach turbulence. For this reason, it may be more desirable or necessary to increase the 

viscosity of the fluid to improve carrying capacity. 

Fluid Viscosity 

The structural viscosity of the fluid can be increased to improve lift without greatly affecting rate 

of penetration. This type of fluid is referred to as a shear thinning fluid and its behavior is 

illustrated in Figure 11–5, which describes shear rate to the various flow regimes in the wellbore. 





Settling Barite Particle 

Drill Pipe 

Annulus 

Drill Collars 

H.C.* 

Bit 

0.01 0.1 1 10 100 1,000 10,000 100,000 1,000,000 

*H.C = Hydroclones 

SHEAR RATE (1/sec) 

Figure 11 - 5 

Range of Shear Rates in the Fluid Circulation System 

700 

600 

500 

Viscosity, cP 

400 

300 

200 

100 

0 

1 10 100 1000 

Shear Rate, sec -1 

Figure 11 - 6 

Effective Viscosity vs Shear Rate 

Note that the effective viscosity of the fluid is quite low at bit shear rates, but relatively high in the 

annular region for maximum lift. Effective viscosity is the viscosity of the fluid at a specific shear 

rate and should be determined for the section of the hole being examined. Calculation and 

application of the effective viscosity concept is given in Chapter 1, Fundamentals of Drilling 

Fluids, or API Bulletin 13D. 

The hole-cleaning concepts of annular velocity and effective viscosity for vertical holes also apply 

to high-angle and horizontal wells, but the inclined annulus poses several problems not 

encountered in vertical holes. 





Cuttings Bed Formation 

Radial slip velocity increases with increasing angle of inclination, forcing more cuttings to the low 

side of the annulus, which eventually results in the formation of a cuttings bed. Tomren, et al, 

reported from their work that bed formation was dramatic in the 40° to 50° angle with the bed 

sliding downward against the flow, resulting in a very high cuttings concentration. 

The fact that a cutting bed forms is a serious problem, but the instability of the bed in this critical 

angle of the well makes the problem even more severe. High torque and drag resulting from the 

high cutting concentration at the lower part of the angle can obviously result in stuck pipe or loss of 

circulation. Tomren, et al, also reported that a cutting-bed formation was almost instantaneous at 

angles of inclination greater than 60°, but that the bed did not slide downward. Thus at angles 

greater than 60°, the bed depth continues to build until the fluid velocity in the restricted annulus 

reaches a level that causes cuttings movement, and equilibrium rate is established. Cuttings 

removal is complicated by the eccentric annuli as well as pipe movement, with increasing 

eccentricity decreasing cleaning ability while pipe movement provides some assistance. 

Although there is a general agreement on the role of drilling fluid rheological properties related to 

hole cleaning in a vertical hole, there appears to be far less agreement on its effect in high-angle 

wells. Okrajni and Azar concluded from their work that in the turbulent flow regime, the cuttings 

transport is generally not affected by the fluid rheological properties (yield value and yield 

point/plastic viscosity ratio) in hole angles from 0° to 90°. 

In the laminar flow range, however, they observed that the annular cuttings concentration was 

lower for higher yield point/plastic viscosity (YP/PV) ratios throughout the entire range of hole 

inclinations. Thus, maintaining a greater structural viscosity in the fluid did improve cuttings 

removal in laminar flow, which became more evident at lower annular fluid velocities. Brown, et 

al, reported that water gave remarkably better cleaning than a polymer drilling fluid below angles 

of 50°, probably due to the turbulence of water versus the polymer. 

Unfortunately, the polymer used in their study was hydroxyl ethyl cellulose (HEC), which is not a 

structure-building polymer. HEC will exhibit visco-elastic behavior, however, which retards water 

from breaking into turbulent flow and thus may have decreased the effectiveness of the HEC fluid 

as compared to water. Thus, it is important to realize that if the drilling fluid is being circulated in 

laminar flow, it should possess true thixotropic properties, or as described above, possess shear 

thinning properties. 

The cuttings bed in the greater than 60° angle portion of the hole is of concern, but the instability of 

the bed in the 40° to 60° angles appears to cause the most problems and be the most difficult to 

clean. According to Jefferson and Zamora, at about 30°, beds (although unstable) first start to form. 

Beds become thicker and more stable with increasing angle, but retain the strong tendency to slump 

or slide downward. This tendency diminishes as the inclination approaches 60°, after which sliding 

caused by gravity stops. The maximum angle for oil and synthetic based drilling fluids usually 

exceeds that for water based drilling fluids when cuttings do slide downward and cause pack-offs. 

It has been reasoned that if the bed is disturbed periodically, its size can be altered to minimize the 

size of the avalanche of cuttings when the hole pump is shut-off. One way of attempting to 

accomplish this is through the use of sweeps. 





Hole Cleaning Sweeps 

Hemphill and Rojas conducted an in depth study of hole cleaning sweeps for coiled tubing 

operations, i.e. static drill string.. They concluded that high-density sweeps were more effective 

than high-density high-viscosity sweeps based on field measurements. The higher viscosity of the 

latter caused flow diversion to the high side of the wellbore. Not surprisingly, high-viscosity 

sweeps also performed poorly. 

Sewell and Billingsley concluded that the best hole cleaning sweeps were high-density lowviscosity 

sweeps, with a density 3 – 4 ppg higher than that of the drilling fluid. They made the 

following recommendations: 

• Calculate sweep height in the vertical part of the annulus, and added hydrostatic head in the 

annulus. 

• Rotate at 80+ rpm while pumping the sweep, 180+ rpm is preferred. It is not recommended 

to pump a weighted sweep while sliding. 

• Keep pumping until the sweep is out of the hole. If pumping stops while the sweep is in the 

deviated hole, it falls out of the “jet stream” and re-deposits captured fines. 

• Avoid increasing the viscosity of the weighted sweep. 

• Plan to run 3 – 4 sweeps to achieve desired results when hole cleaning problems are 

indicated. One sweep will probably not be sufficient to remedy an existing situation. 

• Avoid checking for flow or closing the annulus with the weighted sweep in the drill pipe. 

• If desired for preventative maintenance: 1) schedule sweeps every 6 – 8 hours or 500 – 

1000 feet (whichever comes first, unless the hole dictates greater frequency); barite/silt 

build-ups are dependent on time and footage: and 2) pump a sweep while circulating 

bottoms up before tripping, and another once back on bottom. 

Power et. al. concluded that high-density sweeps were more effective than high-viscosity sweeps. 

They strongly advocated the use of sweep reports, which should be standard practice in any drilling 

fluids operation. 

Short Tripping 

Another technique that has proven helpful in controlling problems created by the cuttings bed in 

the high-angle portion of the well is to make periodic short trips. Tripping the bit through the bed 

not only assures that the bottom hole assembly and bit can be pulled through it, but the action 

should agitate the bed to the point that a portion will slide down the hole and subsequently be 

picked up when circulation is commenced. The time intervals for these short trips will be 

determined by the torque and drag conditions that exist in any particular well. Lacking specific 

well history, a general rule of thumb is to short trip at least once for every 500 feet of new hole. 

Drill String Rotation 

The industry is in total agreement that drill string rotation improves hole cleaning, especially in 

hole sizes less than 17 ½”. The general opinion in the industry is that the optimum drill string 

rotation rate is approximately 120 rpm. It is believed that the drill string rotation improves hole 

cleaning by mechanically disturbing the cuttings bed on the low side of the hole. There could also 

be effects due to skewing the velocity profile in the wellbore and the creation of Taylor Vortices. 





The recognition of the impact of drill string rotation on hole cleaning was one of the factors that 

encouraged the use of rotary steerable systems. 

Turbulence 

Bottom hole assembly design becomes important because the flow restrictions of some of the 

components, such as the measurement-while-drilling tools or positive displacement motors, may 

not allow sufficient flow to reach turbulence in the annulus. Turbulence can, of course, be induced 

at some constant flow rate by decreasing the annular area. This may be more difficult to 

accomplish in a horizontal well because of limitations on the design of drill strings and tool 

assemblies. An increase in the effective viscosity of the drilling fluid will decrease the Reynolds 

Number, and thus increase the flow rate required to obtain turbulent flow. Thus, a lower effective 

viscosity fluid may be desirable in the horizontal well, but attention must also be given to cleaning 

the larger diameter portion of the upper hole or possible washed-out sections where it is impractical 

to maintain turbulent flow. 

It is interesting to point out a basic fact between static fluid pressure and dynamic fluid pressure. 

Static fluid pressure is a function of true vertical depth, while dynamic fluid pressure, or ECD, is a 

function of measured depth. Thus, the ECD will continue to increase, albeit slowly, even after the 

hole becomes essentially horizontal. The fracture pressure could be reached if the hole was 

extended to sufficient depth and the fluid density is close to the fracture gradient. 

ADVANTAGE Hole Cleaning Modeling 

Baker Hughes Drilling Fluids’ ADVANTAGE SM hole cleaning simulator is an invaluable 

engineering tool. Hole cleaning analysis is a critical technology for annular pressure management. 

The hole cleaning of highly deviated wells is so complex that it can only be adequately analyzed 

with the use of a simulator. The hole cleaning models within the Advantage System Engineering 

software can be used to predict minimum flow rate for hole cleaning (optimization mode) or to 

analyze cuttings transport and cuttings bed formation based on a user-defined flow rate (analytical 

mode). The hole cleaning model is based on the balance of forces acting on cuttings in the annulus. 

Advantage System hole cleaning models provide the drilling engineer with a useful tool for 

identifying areas in the wellbore where problems related to hole cleaning may occur. Input 

parameters include cutting size and density, mud weight and rheology, ROP, survey, drill string, 

wellbore geometry and flow rate. The models uses a force balance analysis within each grid and 

identifies the most difficult grid for hole cleaning. 

Advantage System hole cleaning modeling is routinely used in well planning and drilling phases to 

predict hole cleaning efficiency and analyze cuttings beds. This information is useful in identifying 

the location and size of cuttings beds, and their impact on annular pressure (ECD). In many 

instances, the root cause of annular pressure spikes and increases is poor hole cleaning (annular 

cuttings loading) rather than flow rate or drilling fluid properties 

Further information on ADVANTAGE hole cleaning modeling is available in the ADVANTAGE 

manual and is provided during ADVANTAGE training. There follows two examples from 

ADVANTAGE simulations. 





Figure 11 - 7 ADVANTAGE Hole Cleaning Example 1 

Figure 11 - 8 ADVANTAGE Hole Cleaning Example 2 





Figures 11-7 and 11-8 above illustrate very well the usefulness of the ADVANTAGE hole cleaning 

modeling. The only difference between the two examples is that the drilling fluid density in Figure 

11-7 is 11.0 ppg and in Figure 11-8 is 13.0 ppg. This change in density reduces the flow rate 

necessary to clean the hole from 760 to 569 gpm. 

Because of the many variables involved in hole cleaning it is absolutely essential to use a simulator 

to study the combined effects and be able to examine “what if?” situations. 

Hole Cleaning Guidelines 

The single most important factor related to hole cleaning in deviated wells is flow rate. During 

directional drilling operations drilled cuttings will settle on the low side of the hole and form a 

stationary bed if insufficient annular fluid velocity is used. The critical flow rate required to 

prevent cuttings bed formation can be determined from ADVANTAGE. 

Typically few hole cleaning problems exist in vertical or horizontal sections. Most problems 

associated with hole cleaning are seen on deviated wells and occur in the 40 – 60 degree section 

where gravity effects can cause cuttings beds to slump down the hole. 

Typical flow rates to aim for in ERD wells: 

Hole Size 

Typical Flow Rates 

17 ½” 1100 gpm minimum. Some rigs achieve 1250 – 1400 gpm. 

12 ¼” Aim for 1100 gpm (although 800 – 1000 gpm is typically achieved). If 

1000 gpm is not achievable, ensure tripping procedures are in place for 

poorly cleaned hole. 

8 ½” Aim for 500 gpm. 

When correctly designed, both laminar and turbulent flow regimes will effectively clean a deviated 

well. In general increasing the viscosity of a fluid in laminar flow will improve hole cleaning as 

will a reduction of the viscosity of a fluid in turbulent flow. It is important that one or other regime 

is selected and that the transition zone between the two is avoided. 

Generally viscous fluids in laminar flow are preferred because: 

• It is possible to achieve higher cleaning capacity. 

• Viscous fluids give better transport in the near-vertical sections. 

• Viscous fluids have better suspension characteristics when circulation is stopped. 

• It is difficult to achieve “turbulent flow” except in small hole sizes. 

Experience has shown that good drilling fluid rheological properties are extremely important to 

hole cleaning when drilling a high angle well. Studies show that the effects of drilling fluid 

rheological properties and annular flow regime are mutually dependent. In the laminar flow regime, 

increasing fluid viscosity will improve hole cleaning and this is particularly effective if the Yield 

Stress is high. In the turbulent regime, however, reducing fluid viscosity will help removing 

cuttings. Therefore the drilling fluid rheological properties should be designed to avoid the 

transitional flow regime. For hole sizes above 8 ½”, the annular flow is laminar under most 





circumstances. Therefore it is necessary to specify a minimum Yield Stress. The optimum level 

required is best established based on field data and experience. 

A higher ROP requires a higher flow rate to clean the hole. It is good practice to drill the hole with 

a steady ROP and select the required flow rate for hole cleaning accordingly. Before making a 

connection, the hole should be circulated at the normal flow rate to clear the cuttings from around 

the BHA. Depending upon the hole angle and length of BHA, a circulation time of 5 to 10 minutes 

is often required. 

Before tripping out, the hole should be circulated at the normal flow rate until the shakers are clean, 

and the drill pipe be rotated at maximum speed/reciprocated in the mean time. This may require up 

to 3 bottoms-ups, depending on the hole angle and hole size. Below are listed the recommended 

number of bottoms-up prior to tripping. 

Torque and Drag 

Hole Angle, deg 8 ½” 12 ¼” 17 ½” 

0 – 10 1.3 1.3 1.5 

10 – 30 1.4 1.4 1.7 

30 – 60 1.6 1.8 2.5 

60+ 1.7 2.0 3.0 

Overall friction can become so great in an extended-reach well or horizontal section that the drill 

string can only be rotated with great difficulty. Needless to say, this condition is conducive to stuck 

pipe. Obviously, this coefficient of friction will be significantly affected by the lubricating 

properties of the drilling fluid. 

Many of the causes of torque and drag are mechanical, while others are related to hole geometry. 

Several, however, can be directly attributed to the drilling fluid. Since wall contact with the drill 

string will be extremely high in a horizontal hole, it is imperative that the lubricating characteristics 

of the fluid be considered. 

Fluid Lubricity 

Lubricating qualities of a drilling fluid are normally measured in the laboratory by use of a 

lubricity tester. Coefficient of friction between steel wear pieces, or between steel and ceramic 

surfaces, is normally determined. Although the coefficient of friction, as measured in these tests, 

cannot be applied directly to any particular borehole, it can be used for relative comparisons 

between different drilling fluids and/or lubricating additives. A comparison of the coefficients of 

friction of several fluid types, as determined by the Baroid lubricity tester, is described in Figure 

11-9. 





Figure 11 - 9 

Comparison of Lubricity Coefficients – Baroid Lubricity Tester 

Note that the lubricity coefficient of the oil-base fluid is relatively low. This fact correlates well 

with field operations where oil fluids generally show good lubricating properties. 

However, as noted in the section on borehole stabilization, oil-base fluids may not prove a viable 

option where formations are prone to loss of circulation, or environmental regulations prohibit their 

use. It is interesting to note that oil tightly emulsified in a water-base fluid (oil in water emulsion) 

generally imparts very little lubricity to the system. Water is obviously the external wetting phase 

and the emulsified oil droplets are not available for lubricating purposes. Diesel or mineral oils 

contain no chemically-reactive components for boundary lubrication. 

It is generally believed that Wyoming bentonite forms the basis of a good lubricating fluid because 

of its slippery nature. At light loads this appears to be the case, but at loads comparable to field 

conditions, the film strength of the clay is inadequate and very high coefficient of frictions can be 

observed. As noted in Figure 11-9, the clay-based lignosulphonate fluid shows a relatively high 

coefficient of friction. Although this type of fluid has been the most prevalent water-base fluid used 

for the past 25 years, from a lubricity standpoint, it is not the best choice for an extended-reach or 

horizontal well. 

As noted in Figure 11-9, the polymer-based fluid, which contains 3 lb m /bbl of a high molecularweight 

partially-hydrolyzed polyacrylamide, shows a significantly lower coefficient of friction than 

that of the clay-based lignosulphonate fluid. This improved lubricity of the polymer-based fluid is 

inherent in the polymer's behavior. The long chain polymers slide by one another creating a 

boundary layer between the two sliding surfaces. Modifications of the vinyl co-polymer have also 

been used to gain additional lubricity. In fact, combinations of these type of polymers with special 

lubricants are beginning to show friction coefficients approaching those of oil fluids (see Figure 

11-9). Fortunately these fluids can be formulated to meet strict environmental regulations. Since 





the polymers are also being added for shale stabilization and/or filtration control, the added 

advantage of improved lubricity is even more significant. 

There are numerous additives on the market today being sold as drilling fluid lubricants. Many of 

these are of little value, and, in fact, can be harmful by adversely affecting other fluid properties 

such as viscosity, filtration control, and indirectly, fluid cost. Thus, careful evaluation and pilot 

testing should be carried out in selecting the best lubricant. Drilling fluid lubricants can be broadly 

characterized as anti-wear (extreme pressure lubricants) and modified film lubricants. 

Extreme pressure (EP) lubricants were developed to decrease bit bearing wear prior to the 

development of sealed bearing bits. EP additives are primarily used today to decrease casing wear 

at high-load points. They commonly contain modified fatty acids, which, according to Browning, 

react with the metal oxide surfaces of the pipe through a chemi-sorption reaction to maintain their 

lubricating action at high friction temperatures. 

Bol reported that the commercial lubricants he tested partially prevented adhesive wear, but effects 

were not reproducible in his full scale casing-wear tester. He correctly points out, however, that 

wear and friction have to be evaluated separately. 

Modified film lubricants, on the other hand, are considered general borehole lubricants, and 

perform more effectively at lower loads. These form continuous films by absorbing layer upon 

layer, with the thickness of the film making and breaking with the amount of load applied. They 

may be completely displaced at a very high load point, such as might occur between drillpipe and 

casing in an high-angle portion of the well, but in general, they show sufficient tenacity to serve as 

a lubricant between the drillstring and the open hole. Concentration effects are very important for 

most of these compounds, and normally at least 2% by volume are required before any significant 

improvement is observed. Most of these additives are hydrocarbon-based, though recent 

developments have made available formulations to meet non-hydrocarbon environmental 

regulations. 

Filter Cake 

Although much of the exposed wellbore will usually consist of shales with very low permeability, a 

large portion will be shale-sands and sandstones with fluid filter cake deposited on their surfaces. 

Thus, the lubricity coefficient between the pipe and filter cake becomes important. 

Most drilling personnel characterize a desirable cake as one that is thin and tough with a leathery 

texture. This describes a cake that is highly deflocculated, with relatively low water content. In 

effect, this leathery surface results in a high-lubricity coefficient with the surface of the cake 

resisting shear. 

Certainly a thin cake is desirable, but it is even more important to have a cake where its outer 

surface will shear or glide along with the rotating pipe surface. To obtain this property, the filter 

cake must have relatively high water content, be highly compressible, and possess a very slick 

surface. 

In permeable formations it is essential that the drilling fluid contain the correct concentration of 

bridging materials and that the bridging material (often calcium carbonate) has a particle size 

distribution suitable for the formation being drilled. This will help to minimize the thickness of the 

filter cake deposited and in so doing will aid in minimizing friction. 

Wyoming bentonite tends to give this characteristic in fresh water under light loads, but in the 

presence of drilling contaminants such as gypsum and salt, or in a highly deflocculated 





environment, tends to lose much of this property. The water-soluble organic polymers provide a 

lubricating and shearable surface. As described above, the natural lubricity of the partiallyhydrolyzed 

polyacrylamide is a factor in imparting lubricity to the fluid, but this property also 

carries over into the filter cake surface. The polymer maintains considerable water in the cake 

surface, even in the presence of contaminating electrolytes, and produces a much slicker and more 

lubricating surface than the clay-based systems. 

One facet of torque in a horizontal hole that cannot be easily answered is the relationship of the 

drillstring against the inevitable cuttings bed that is formed. Questions can be asked as to what 

extent does the drillstring extend into this bed, and to what degree is the bed compacted? The 

answers become even more elusive in the steeper angles of the hole, where the cuttings bed is more 

dynamic and transitional. Regardless of the final effect of all the parameters of the cutting bed 

issue, it would appear that the lubricating properties of the drilling fluid remain important. 


The obvious reason for drilling a horizontal well is to expose more of the producing zone to the 

wellbore for increased production. Thus, the importance of preventing formation damage during 

drilling and completion of the horizontal well is just as important as it is in its vertical counterpart. 

In fact, it may be more important since the increased cost of drilling the horizontal well must show 

additional production for its justification. A 50% damage or permeability loss in a potential 500 

bbl/day horizontal well represents a considerably greater loss in production than a 50% damage in a 

100 bbl/day vertical hole through the same reservoir. 

Sandstone production is by far the most susceptible reservoir rock to damage or permeability loss 

during drilling and completion operations. Though formation damage may be caused by poor 

drilling and completion practices, one of the primary causes is due to exposure to the drilling and 

completion fluid. 

This loss, attributable to the fluid, can be caused by one or more of the following occurrences: 

• Particle transport from the drilling fluid into the production zone, subsequently plugging pore 

throats. 

• Fluid filtrate reacting with expandable clays in the rock to decrease pore throat diameters. 

• Particle movement within the permeable rock due to dispersion of clays and other minerals 

from quartz surfaces. 

• Wettability changes of the formation from exposure to the drilling fluid filtrate. 

• Interaction of fluid filtrate with formation fluids to form water - insoluble precipitants. 

The effect of these actions on the permeability of sandstones has been the subject of a considerable 

investigation. In almost all cases, some damage is caused by the drilling and completion fluid. The 

primary objective is to limit this damage as much as possible. Consequently, selection of the 

drilling and completion fluid becomes an extremely important function in drilling the horizontal 

well. 

Examining the Formation 

Where possible, a thorough examination of the formation should be made to determine its 

susceptibility to damage and to identify the mechanisms of damage. This analysis is of 

considerable value in selecting the drilling or completion fluid for a particular formation. 





The examination of a core from the formation should include a petrographic analysis and mineral 

composition by X-ray diffraction and scanning electron microscope. This information can be 

coupled with data from return permeability tests of core plugs to choose the least damaging fluid. 

Droddy, et al, utilized these analytical procedures for fluid selection on an argillaceous sandstone 

from the Wilcox Formation, for example. By combining the findings of the petrological and 

mineralogical analyses with return oil-permeability tests, it was possible to make a comprehensive 

selection of the drilling fluid for this formation. 

Core Permeability Testing 

The formation damage test involves a sequence of flow tests in a liquid permeameter as shown 

schematically in Figure 11-10. 

Figure 11 - 10 

Permeameter Schematic Diagram 

The core is mounted in a Hassler-type cell, evacuated, and then saturated with simulated formation 

water. The initial oil permeability, K (i, oil), is determined by flowing a filtered mineral oil through 

the core under constant pressure until irreducible water content is obtained. This state is indicated 

by a constant flow rate and stabilized differential pressure. The downstream or borehole face of the 

core is then exposed to the test fluid under pressure for a period of time. Oil flow is then initiated in 

the original direction of flow (formation to borehole) under the same initial pressure until the flow 

rate and differential pressure stabilize. The permeability to oil at this point is the return oil 

permeability, K (r, oil). 

The ratio of K (r, oil) to K (i, oil) is expressed as the percent return permeability, % K (r, oil). A 

return permeability of 90% is considered good, since a permeability loss after fluid off of 10% or 

more is commonly experienced, even with the least damaging fluids. 





The effects of several drilling fluid types on the return permeability of a Cook Inlet Alaska core 

from the Middle Ground Shoal Field are given in Figure 11 - 11. Note that the oil fluid gave a very 

good return permeability as did the polymer-base fluid with 3% KCl. Since the formation contained 

a significant amount of expandable clays, the performance of these two fluids can most likely be 

attributed to their swelling inhibiting properties. 


Return Permeability Data on Cook Inlet Cores 

In other formations, particle dispersion and movement may be the primary source of damage. 

Lignosulphonates are excellent deflocculating agents, and thus produce extremely fine particle-size 

dispersion, particularly in high pH fluids. This can result in considerable particle transport into the 

core or particle movement within the core. In formations where this condition exists, 

lignosulphonates fluids can produce considerable damage with return permeabilities below 50%. 

Sandstones containing kaolinite packets are particularly susceptible to particle plugging. The 

packets can become dispersed from the quartz surface and migrate to plug a pore throat. Fluids that 

enhance dispersion thus increase the plugging effect. 

In general, with all other factors equal, the lower the permeability of the formation, the more 

subject it is to damage. This, no doubt, is due to the smaller pore openings of the lower permeable 

rock. Rock factors such as grain mineralogy, grain size, grain shape, and grain packing all exert an 

influence on the size of the pore throats. There is no specific permeability that the problem of pore 

plugging becomes acute, but certainly rocks with permeabilities below 100 md can be highly 

susceptible. 

In summary, both the horizontal and vertical permeabilities of the formation are important in a 

well. Since the vertical permeability of the rock is normally lower than its horizontal permeability, 

significant differences may occur in their susceptibility to damage. Thus, when analyzing cores 





from a horizontal well, one should examine a core plug from both the horizontal and vertical 

planes. 

Recommended Fluid Parameters 

• Velocity – One of the major obstacles to overcome in horizontal and ERD drilling is hole 

cleaning. In vertical holes, cuttings have room to settle without causing problems. In 

horizontal wells, cuttings only have to settle 4+ inches to form a cuttings bed. Research and 

practical experience has shown that cuttings bed formation is analogous to sand dunes on an 

ocean beach. The bed moves in a wave fashion up the hole. If sufficient annular velocity is 

not present, the bed thickens until it reaches equilibrium, which usually occurs when 

turbulent flow conditions exist. With water, turbulent flow is easily obtained since viscosity is 

in the denominator of the turbulent flow equation, and water has a viscosity of 1. Fluids other 

than water require more pump output to approach turbulent flow conditions. Practical 

experience in other industries has proven that materials can be transported in water slurries if 

the fluid velocity is between 3 and 7 ft/sec. 

• Rheological Properties – Ideally one would want a true thixotropic fluid to drill horizontally. 

In effect, two different conditions exist simultaneously. One occurs in the vertical portion of 

the hole where larger diameter casing may be set, or wash-outs in the open hole occur. In that 

case, a fluid having a high Yield Stress, or if the fluid is visco-elastic, the initial gel strength 

needs to be elevated. The opposite is needed in the horizontal section from a hole-cleaning 

point of view. Here one wants water for the reasons pointed out earlier. Compromises are the 

result. If casing is set into the zone of interest, or if formations up-hole are not a problem, 

then water may be possibly combined with occasional sweeps. 

• Surface Apparatus – Special attention must be placed on the solids removal equipment at the 

surface. Solids removal efficiency must be continually monitored so that unwanted 

particulate material is not retained in the fluid system that may negatively affect fluid weight 

or filter cake quality, resulting in lost circulation or increased torque and drag. The cost of 

problems that may occur due to not doing this correctly may far outweigh the cost of 

equipment needed. 

• Common Fluid Utilized – Table 11 - 2 is a comparison of drilling fluids utilized in horizontal 

wells which can vary depending upon the area in question, historical preference, 

environmental constraints, fluid company experience, and operator. Types have included gel 

and water, oil based fluids, polymers, and in some cases, sized-salt systems. Combinations of 

the above, as well as other fluids have been tried. 





Fluid Type Advantages Disadvantages 

Oil Fluids 

Co-Polymer 

Gel / Water 

Clear Water/ 

Polymer Sweeps 

Sized Salt 

Inhibitive 

Lubricity 

Formation damage 

Somewhat inhibitive 

Some lubricity 

Some formation protection 

Less expensive than Oil Fluid 

Inexpensive 

Environmentally safe 

Simple 

Inexpensive 

Excellent under balanced 

Minimum damage some 

formations 

Ultra simple 

Lubricity 

Minimal damage 

Table 11 - 2 

Environmental 

Loss circulation 

Expensive 

(Not thixotropic, Solids removal difficult) 

Moderately expensive 

Must consider solids 

Non-inhibitive 

Can damage formation 

Poor lubrication 

(Limited by pore pressures) 

Disposal 

Solids removal 

Cost 

Comparison of Drilling Fluids 

Originally, fears over anticipated torque and drag saw the use of oil fluids. In medium-radius wells, 

this problem is not severe and oil fluids are not used as frequently as before for that purpose. Oil 

fluids are frequently run where the source rock is shale, or where casing is not set through 

troublesome formations. 

Other fluids utilized are water-supplemented with occasional polymer sweeps such as partially 

hydrolyzed polyacrylamides (PHPAs).These fluids are ideal in certain formations which don't react 

to the water. 

Water, as mentioned earlier, is kept in turbulence easily, provides optimum hole cleaning, is 

relatively cheap, and requires only minimal sweeps to keep the hole clean. 

Sized-salt fluids are super-saturated (where bottom hole temperature is not too high) and contain 

salt crystals free to plug off the formation, thus reducing filtrate invasion. The salt is easily cleaned 

up by pumping fresher water, thus dissolving the crystals. 





REFERENCES 

1. Aadnoy, B. S. and Chenevert, M. E., Stability of Highly-Inclined Boreholes, SPE/IADC 

16052, Presented at the 1987 Drilling Conference. 

2. Bradley, W. B., Mathematical Concept - Stress Cloud Can Predict Borehole Failure, Oil and 

Gas Journal, February 19, 1979. 

3. Bradley, W.B., Failure of Inclined Wellbores, Transactions of the ASME, Journal of Energy 

Resources Technology, December 1979, Vol. 101 / 239 

4. Chenevert, M. E., Shale Control with Balanced Activity Oil-Continuous Muds, Journal 

Petroleum Technology, October 1970, pp. 1309-1316; Trans AIME, Vol. 249. 

5. Nance, W. B., How to Select Oil Mud Applications, Petroleum Engineer International, January 

1984, pp. 30-38. 

6. O'Brien, D. E. and Chenevert, M. E., Stabilizing Sensitive Shales with Inhibited Potassium- 

Based Drilling Fluids, Journal Petroleum Technology, September 1973, p. 189; Trans AIME, 

Vol. 255. 

7. Chesser, B. G., Design Considerations for an Inhibitive and Stable Water-Base Mud System, 

SPE Drilling Engineering, December 1987, pp.331-336. 

8. Clark, R. K., Scheuerman, R. K., Rath, H., and van Laar, H., Polyacrylamide/Potassium - 

Chloride Mud for Drilling Water-Sensitive Shales, Journal Petroleum Technology, June 1976, 

pp. 719-727; Trans AIME, Vol. 261. 

9. Bol, G. M., The Effect of Various Polymers and Salts on Borehole and Cuttings Stability in 

Water-Base Shale Drilling Fluids, SPE/IADC 14802, Presented at the 1986 Drilling 

Conference, Dallas, Texas. 

10. Davis, Neal and Tooman, C. E., New Laboratory Tests Evaluate the Effectiveness of Gilsonite 

Resin as a Borehole Stabilizer, SPE Drilling Engineering, March 1989. 

11. Walker, R. E. and Mayes, T. M., Design of Muds for Carrying Capacity, Journal Petroleum 

Technology, July 1975, pp. 893-900. 

12. Sifferman, R. T., Myers, G. M., Haden, E. L., and Wall, H. A., Drill-Cuttings Transport in Full- 

Scale Vertical Annuli, Journal Petroleum Technology, November 1974, pp. 1295-1302. 

13. Hopkin, E. A., Factors Affecting Cuttings Removal During Rotary Drilling, Journal Petroleum 

Technology, June 1967, pp. 807-814; Trans AIME, Vol. 240. 

14. William, C. E. and Bruce, G. H., Carrying Capacity of Drilling Fluids, Trans AIME, Vol. 192, 

195, pp. 111- 120. 

15. API Bulletin 13D, The Rheology of Oil-Well Drilling Fluid, Second Edition, May 16, 1985. 





16. Tomren, P. H., Iyoho, A. W., and Azar, J. S., Experimental Study of Cuttings Transport in 

Directional Wells, SPE Drilling Engineering, February 1986, pp. 43-56. 

17. Okrajni, S. S., and Azer, J. J., The Effects of Mud Rheology on Annular Hole Cleaning in 

Directional Wells, SPE Drilling Engineering, August 1986, pp.297-308. 

18. Jefferson, D., and Zamora, M., Hole Cleaning and Suspension in Horizontal Wells, 3 rd Annual 

North American Conference on Emerging Technologies – Coiled Tubing and Horizontal Wells 

– Calgary, May 15 – 16, 1995. 

19. Brown, N. P., Bern, P. A., and Weaver, A., Cleaning Deviated Holes: New Experimental and 

Theoretical Studies, SPE/IADC Paper 18636, Presented at the 1989 SPE/IADC Drilling 

Conference, February 28 - March 3, 1989. 

20. Hemphill, T. and Rojas, J.C., Drilling Fluid Sweeps: Their Evaluation, Timing and Applications, 

SPE 77448. 

21. Sewell, M. and Billingsley, J., An Effective Approach to Keeping the Hole Clean in High-Angle 

Wells, World Oil, October 2002, pp. 35 – 39. 

22. Power, D.J., Hight, C., Weisinger, D. and Rimer, C., Drilling Practices and Sweep Selection for 

Efficient Hole Cleaning in Deviated Wellbores, SPE 62794. 

23. Hole Problem Data Package, BP, XTP, Sunbury, April 1996. 

24. Mondshine, T. C., Drilling Mud Lubricity, Oil & Gas Journal, December 7, 1970, pp. 70-77. 

25. Papay, A., G., Oil-Soluble Friction Reducers Theory and Application, Journal of the American 

Society of Lubrication Engineers, Vol. 39, pp. 419-426. 

26. Browning, W. C., Potentials of EP Lubricants in Oil Well Drilling Muds, Presented April 24, 

1957, First Gulf Coast Drilling and Production Practice Meeting. 

27. Bol, G. M., Effects of Mud Composition on Wear and Friction of Casing and Tool Joints, SPE 

Drilling Engineering, October 1986, pp. 369-376. 

28. Nowak, J. and Krueger, R. F., The Effect of Mud Filtrates and Mud Particles upon the 

Permeabilities of Cores, Drilling and Production Practice, API, 1951, p. 164. 

29. Krueger, R. F. and Vogel, L. C., Damage to Sandstone Cores by Particles from Drilling Fluids, 

Drilling and Production Practices, API, 1954. 

30. Khiler, K. C. and Fogler, H. S., Water Sensitivity of Sandstones, SPEJ 55, 1983. 

31. Gray, D. H. and Rex, R. W., Formation Damage in Sandstones Caused by Clay Dispersion and 

Migration, Paper presented at the 14th Netherlands Conference on Clays and Clay Minerals, 

London. 

32. Sharma, M. M. and Yortsos, Y. C., Permeability Impairment Due to Fine Migration in 

Sandstones, Seventh SPE Symposium on Formation Damage Control, February 26-27, 1986, 

pp. 91-102. 





33. Droddy, M. J., Jones, T. A., and Shaw, D. B., Drill Fluid and Return Permeability Tests of South 

Texas Wilcox Cores, SPE 17159, Presented at the SPE Formation Damage Control Symposium, 

Bakersfield, CA, February 8-9, 1988. 




Pressure Prediction and Control 

Chapter 

Twelve 

Pressure Prediction and Control

Chapter 12 


PRESSURE PREDICTION AND CONTROL..................................................................................1 

FORMATION PRESSURE.....................................................................................................................1 

Normally Pressured Formations................................................................................................1 

ABNORMAL FORMATION PRESSURES...............................................................................................2 

HOW TO RECOGNIZE ABNORMAL PRESSURE ZONES......................................................................3 

METHODS OF FORMATION PRESSURE PREDICTION .......................................................................4 

Seismic..........................................................................................................................................4 

Shallow Gas..............................................................................................................................4 

Deeper Gas ..............................................................................................................................4 

ELECTRIC LOG ANALYSIS..................................................................................................................5 

Sonic Logs ....................................................................................................................................7 

DRILLING PARAMETERS USED TO INDICATE AN ABNORMAL PRESSURE ZONE ...........................11 

Increased Rate of Penetration.................................................................................................11 

Rotary Torque ............................................................................................................................12 

Changes in Drag on Connections ...........................................................................................12 

Change in Pit Volume ...............................................................................................................12 

The “d” Exponent .......................................................................................................................13 

Gas Content of Drilling Fluid ....................................................................................................14 

Changes in Cuttings ..................................................................................................................15 

Shale Density .............................................................................................................................15 

Flowline Temperature ...............................................................................................................15 

Chloride Trends..........................................................................................................................16 

Paleo Information.......................................................................................................................16 

CONTROLLING FORMATION PRESSURE..........................................................................................16 

Preplanning to Prevent or to Handle Kicks Safely................................................................16 

Kick Recognition ........................................................................................................................17 

Kicks While Drilling ....................................................................................................................17 

Kicks While Tripping Out of the Hole......................................................................................19 

Kicks While Tripping Into the Hole ..........................................................................................20 

Behavior of Gas in the Wellbore..............................................................................................20 

Rise of Gas without Expansion............................................................................................20 

Rise of Gas with Uncontrolled Expansion..............................................................................21 

Rise of Gas with Controlled Expansion..................................................................................21 

Shut-In Drillpipe and Casing Pressures .................................................................................22 

Fluid Weights and Pressures...................................................................................................23 

Equivalent Circulating Density.................................................................................................24 

U-Tube Concept.........................................................................................................................26 

Closing Procedure .....................................................................................................................29 

Procedure for Closing Well In While on Bottom................................................................29 

Procedure for Closing Well In While Tripping....................................................................30 

PRESSURE CONTROL METHODS ....................................................................................................31 

The Wait and Weight Method of Well Control .......................................................................31 

Baker Hughes DRILLING FLUIDS Well Control Kill Sheet .................................................33 

SPECIAL PROBLEMS ........................................................................................................................34 

Barite Plugs ................................................................................................................................35 

Procedure to Set Barite Plugs .............................................................................................35 


REVISED 2004 

TRAINING MANUAL 

i


Procedure for Preparing Barite Plug for Oil-Base Fluid...................................................36 

Field Mixing Procedure for Barite Plugs (Nonsettling) .....................................................37 

Gas Kicks in Invert Emulsion Fluids .......................................................................................37 

Pit Volumes.............................................................................................................................38 

Flow Rate Increases..............................................................................................................38 

Flow Checks ...........................................................................................................................38 

Shut-In Pressures ..................................................................................................................38 

Subsea Well Control..................................................................................................................38 

Low Formation Fracture Gradients .....................................................................................39 

Shallow Gas............................................................................................................................39 

Kick Detection ........................................................................................................................39 

Choke Line Friction................................................................................................................39 

Riser Collapse / Displacement / Trapped Gas..................................................................40 

Gas Hydrates..........................................................................................................................40 

Commonly Used Equations in Pressure Control ..................................................................40 

Hydrostatic Pressure (psi) ....................................................................................................40 

Pressure Gradient (psi/ft) .....................................................................................................40 

Pressure Expressed as Equivalent Fluid (Mud) Weight (EMW).....................................40 

Fluid (Mud) Weight to Balance a Kick ................................................................................41 

Determination of the Nature of Invading Fluids.................................................................41 

Maximum Casing Pressure Resulting from a Gas Kick * ................................................41 

Maximum Volume Increase while Circulating Out a Kick * .............................................41 

Formation Pressure or Bottomhole Pressure....................................................................41 

Maximum Initial Shut-In Casing Pressure which will Exceed Fracture Gradient .........41 

MIL-BAR® Required to Weight up 1 bbl of Fluid **..........................................................41 

NOMENCLATURE ..............................................................................................................................42 

REFERENCES ...................................................................................................................................43 


FIGURE 12 - 1 TECTONIC ACTIVITIES ..................................................................................................2 

FIGURE 12 - 2 STRUCTURAL FEATURE................................................................................................3 

FIGURE 12 - 3 INTERVAL TRANSIT TIME ..............................................................................................5 

FIGURE 12 - 4 LOG DEPICTING ABNORMAL PRESSURE ZONES.........................................................6 

FIGURE 12 - 5 CONDUCTIVITY PLOT VS. DEPTH FOR LOG IN FIGURE 12- 4 .....................................6 

FIGURE 12 - 6 SHALE TRANSIT TIME VS. DEPTH ................................................................................8 

FIGURE 12 - 7 REDUCTION IN BHP CORRESPONDING TO A SURFACE-OBSERVED REDUCTION IN 

FLUID WEIGHT DUE TO GAS CUT FLUID ....................................................................................19 

FIGURE 12 - 8 RISE OF ONE BARREL OF GAS WITH CONTROLLED EXPANSION ............................22 

FIGURE 12 - 9 KILL FLUID WEIGHT ....................................................................................................24 

FIGURE 12 - 10 SYSTEM PRESSURE LOSSES...................................................................................25 

FIGURE 12 - 11 “U” TUBE STATIC.....................................................................................................26 

FIGURE 12 - 12 “U” TUBE CIRCULATING ..........................................................................................27 

FIGURE 12 - 13 “U” TUBE SHUT IN ...................................................................................................28 

FIGURE 12 - 14 “U” TUBE CIRCULATING WITH CHOKE ...................................................................29 


REVISION 2006 


12-ii



TABLE 12 - 1 PREDICTED PRESSURE GRADIENTS VS. CONDUCTIVITY OR RESISTIVITY RATIOS......12-7 

TABLE 12 - 2 PREDICTED PRESSURE GRADIENT VS. SONIC LOG DEPARTURE (AT OBSERVED-AT 

NORMAL)...................................................................................................................................12-9 

TABLE 12 - 3 HOW VARIABLES AFFECT LOGS ...............................................................................12-10 

TABLE 12 - 4 BARITE SLURRY WEIGHT / VOLUME RELATIONSHIP (BARITE SPECIFIC GRAVITY = 4.2) 

.................................................................................................................................................12-35 

TABLE 12 - 5 BARITE PLUGS FOR OIL-BASE FLUIDS (1 BBL OF 18.0 LB M /GAL SLURRY) ................12-36 


REVISION 2006 


12-iii

PRESSURE PREDICTION AND CONTROL 

Chapter 12 


All sedimentary rocks are porous to some degree. The pore spaces are filled with fluids – 

liquids, gases or a combination – which are under pressure. A fundamental function of 

drilling fluids is to control these downhole pressures as the failure to do so can result in 

catastrophic consequences, both in terms of HSE and financial. 

FORMATION PRESSURE 

Overburden is the combined weight of the rock grains and the fluids contained within the pore 

spaces. For example, a rock grain density of 2.65 g/cm 3 combined with a pore fluid density of 

1.07 g/cm 3 and 34% porosity would result in an average density of 2.12 g/cm 3 [(2.65 × 0.66) + 

(1.07 × 0.34) = 2.12 g/cm 3 ] would exert an overburden pressure of approximately 0.92 psi/ft. 

(2.12 × 8.34 × 0.052 = 0.92 psi/ft). Overburden with normal pore pressure varies from 

approximately 0.84 psi/ft near the surface to 1.0 psi/ft at 20,000 ft in the Gulf Coast area. 

The relationship between overburden pressure gradient, pore pressure gradient, and rock grain 

pressure gradient can be expressed as follows, 

where, 

P o 

P o 

= P f + P c 

= overburden pressure gradient, psi/ft 

P f = fluid pressure (pore pressure) gradient, psi/ft 

P c = rock grain pressure gradient, psi/ft. 

Normally Pressured Formations 

Pore pressures in normally pressured zones are equivalent to the average hydrostatic pressure 

exerted by the fluid contained in the pore spaces above the depth of interest. In the Louisiana 

and Texas Gulf Coast area, empirical data indicates a normal pressure gradient of 

approximately 0.465 psi/ft. This gradient corresponds to a fluid weighing approximately 9.0 

lb m /gal or one having a salinity of approximately 80,000 mg/L Cl – . It should be noted that this 

is an average pressure gradient. Obviously, near surface freshwater formations could have a 

pressure gradient near that of freshwater (0.433 psi/ft or 8.34 lb m /gal). 

In the Mid-Continent areas most sediments were deposited in the presence of freshwater. 

Consequently, normal pore pressure is approximately equal to the gradient of freshwater (0.433 

psi/ft or 8.34 lb m /gal in equivalent fluid weight). 



REVISION 2006 12-1


ABNORMAL FORMATION PRESSURES 

Formation pressures in excess of normal formation pressures for an area are referred to as 

abnormal pressures. The fundamental difference between normally and abnormally pressured 

rocks is that in abnormally pressured zones the pore fluids no longer communicate 100% 

efficiently with the water table (surface communication). Some mechanism is providing a seal 

or cap to interfere with the fluid column and preventing it from achieving normal hydrostatic 

equilibrium. Abnormal pressure gradients in excess of l.0 psi/ft have been recorded, but they 

generally do not exceed 0.91 psi/ft. Some of the causes given for abnormal formation pressures 

are: 

• Compaction disequilibrium is a common cause of abnormal pressure. This is especially true in 

rapid filling (Tertiary) sedimentary basins. Rapid sedimentation rates accompanied by thick, lowpermeability 

shale sections and growth faults entrap pore fluids. This process restricts the ability 

of the fluids in the sediments to escape as in a normal compaction situation. When entrapped pore 

fluids are coupled with overburden pressures, then abnormal pressures are generated. Examples 

are seen in the Gulf of Mexico, the North Sea and the Niger Delta. 

• Tectonic activities such as salt and shale intrusions, faulting, folding, etc., may contribute to 

abnormal pressures (see Figure 12-1). In the figure below the sand has been elevated while 

retaining its pore pressure and is thus abnormally pressured at its uplifted depth. 

Abnormally pressured sand 

Figure 12 - 1 Tectonic Activities 

• Structural features such as dipping lenses and anticlines having normal pressures in the deeper 

part of the zone can transmit pressure to the higher section of the zone, resulting in abnormal 

pressure (see Figure 12-2). Also uplifting of “rafts” in salt domes can cause severe overpressures 

due to the effectiveness of the seal of the surrounding salt. 

• Hydrocarbon generation and migration are amongst the most significant factors in the generation 

of over-pressures. The hydrocarbon that produces the greatest over-pressures is gas. Gas expands 

much more than oil or water, and whenever it is trapped, it reduces the hydrostatic control. 

Adequate drainage is required to prevent pressure increases. The movement of hydrocarbons into 

permeable zones capped by impermeable zones often generates overpressures. 



REVISION 2006 12-2


Abnormal Pressure 

Charged Sand 

Normal Pressure 

Figure 12 - 2 Structural Feature 

• Diagenesis is the physical/chemical transformation of one rock or mineral into another. Many 

minerals will undergo a chemical metamorphosis at relatively low temperatures. A classic 

example is the conversion of gypsum to anhydrite (CaSO 4·2H 2 O to CaSO 4 ) in which there is a 

total volume change of about 50% with the expulsion of water. If this water is not allowed to 

migrate this could generate substantial pressure increases within a sealed zone. 

Diagenesis of clay minerals is often associated with over-pressured and troublesome 

shales/mudstones/claystones. Younger argillaceous sediments are often rich in smectite 

clay – montmorillonite. These clays have a high surface area to which up to ten layers of 

water can bond. The result is a low density “swelling clay”. Smectite clays go through a 

number of changes with burial. Initially, increasing pressure will drive out the loosely 

bound water, but as the number of layers is reduced, the pressure required to drive out the 

remaining layers increases. Ultimately, only high temperature and chemical processes 

will release the last layer, which can be bound with metallic cations. When smectites 

within a shale are subjected to lithostatic pressure and a temperature of 67 – 81°C (153 - 

178ºF) the penultimate (next to last) layer will be displaced. A further rise in temperature 

to 172 – 192°C (342 - 378ºF) is required to drive off the last layer, which is very closely 

bound between the clay plates. Interfering with the migration of freed water may lead to 

the generation of over-pressures. At the threshold temperature for the loss of the 

penultimate water layer is also the point at which smectites can turn into illites. 

Depending on the type of smectite, the availability of available cations like K + will satisfy 

the surface charges in place of water and collapse the clay into more compact illite. The 

remaining water is released into the porosity created by the reduction in clay volume. It 

appears that the denser illite can reduce vertical permeability and thus hinder the natural 

migration of fluids. This may explain why over-pressures are often associated with zones 

containing 40 to 50% illite. 

• Formations that have been charged from water floods, casing leaks, or underground blowouts. 

HOW TO RECOGNIZE ABNORMAL PRESSURE ZONES 

Abnormal pressure zones are often associated with under-compacted shales. This change in 

shale characteristic generally results in, 



REVISION 2006 12-3


• Change in normal porosity, usually an increase 

• Change in formation fluid content and density 

• Change in shale conductivity, usually an increase. 

METHODS OF FORMATION PRESSURE PREDICTION 

Because many formations have abnormally high fluid pressures, it is extremely important to 

know about these pressures in planning and executing drilling operations. Prior to drilling, 

there are two means of predicting the location of abnormal pressure zones – (1) seismic data 

from the area to be drilled and, (2) electric log data from offset wells drilled near the proposed 

location. 

Seismic 

Since the abnormally pressured zones have not compacted normally with depth, the velocity of 

sound waves traveling through these formations is reduced. These reductions are measured, 

plotted, and converted to an amount of abnormal pressure. Seismic interpretation can be 

applied to the detection of two different types of abnormal pressured gas zones, shallow and 

deep. 

Shallow Gas 

Formations containing gas tend to absorb sound waves. Formations above gas sands will be 

highly reflective, whereas the gas sands will be absorptive. On a seismic profile, the gas sand 

will show up as a “bright” spot. Shallow gas sands have been responsible for numerous 

offshore blowouts, so their detection before drilling is important. 

Deeper Gas 

Abnormally pressured formations at deeper depths are more difficult to detect; the more 

geological information available in an area, the greater accuracy in detecting these zones; the 

more velocity profiles taken in an area, the better the definition of the normal compaction 

trend. The seismic data yields curves representing sonic velocities of the formation to be 

drilled. 

Different lithologies have different velocity profiles. Therefore, a thorough knowledge of the 

geology of an area aids in the interpretation of seismic information. The unit used to measure 

the velocity is a value referred to as interval velocity. Interval velocity is the speed of sound 

through an interval of formation and the reciprocal of interval transit time. 

The interval transit times are usually plotted on logarithmic scale versus a linear depth scale 

(see Figure 12-3). A normal line (±70 µ sec/ft @ 10,000 ft.) is drawn and extended into the 

abnormal pressure interval and compared to the extrapolated shale line (±90 µ sec/ft @ 10,000 

ft). Comparison between the observed value and the extrapolated value is a measure of the 

amount of abnormal pressure. Common sources of error in velocity analysis include dipping 

beds, faults, multiple reflections, curved ray paths, processing, and interpretation. An interval 

transit time for limestone (±50 µ sec/ft @ 10,000 ft.) is shown for comparison purposes. The 

seismic wave travels faster through the harder rocks and is slowed down by the presence of 



REVISION 2006 12-4


increased pore pressures present in shale which is an indicator of underlying higher pressure 

formations. 

Depth, ft 

Interval Transit Time, μ sec/ft 

ELECTRIC LOG ANALYSIS 

Figure 12 - 3 Interval Transit Time 

Abnormally pressured zones can be predicted by analyzing changes in shale conductivity 

recorded on induction logs. Steps in the procedure are: 

1. Obtain shale conductivity (C s ) readings from an induction log. 

2. Make a plot of C s vs. depth on semi-log paper. 

3. Draw the best straight line through the shale conductivity plot. 

4. A sharp change in direction by some of the plotted points generally indicates the 

presence of an abnormal pressure zone. 

5. Record the ratio of shale conductivity observed to normal conductivity of that shale 

(see Figure 12-4). 



REVISION 2006 12-5


6. Depending on the formation from which the readings are taken, calculate the ratio 

of observed conductivity to normal conductivity. Refer to Table 12-1 to obtain 

predicted pressure gradient in the form of equivalent fluid weight. 

Figure 12 - 4 Log Depicting Abnormal Pressure Zones 

Figure 12 - 5 Conductivity Plot vs. Depth for Log in Figure 12- 4 



REVISION 2006 12-6


Pressure 

Gradient 

in Equivalent 

Fluid Weight 

(lb m /gal) 

10.0 

10.5 

11.0 

11.5 

12.0 

12.5 

13.0 

13.5 

14.0 

14.5 

15.0 

15.5 

16.0 

17.0 

17.5 

MIOCENE- 

OLIGOCENE 

South Louisiana 

1.09 

1.15 

1.20 

1.28 

1.34 

1.43 

1.53 

1.65 

1.78 

1.93 

2.10 

2.33 

2.60 

3.58 

5.00 

Ratio: Observed Conductivity / Normal Conductivity 

Or: Normal Resistivity / Observed Resistivity 

FRIO 

FORMATION 

S. Texas Gulf Coast 

1.34 

1.55 

1.78 

1.97 

2.18 

2.43 

2.68 

2.96 

3.33 

3.60 

3.95 

4.31 

4.67 

5.72 

WIL COX 

FORMATION 

S. Texas Gulf Coast NORTH SEA 

.08 

.13 

1.22 

1.28 

1.39 

1.50 

1.64 

1.80 

2.00 

2.21 

2.44 

2.71 

3.03 

4.0 

1.50 

1.76 

1.95 

2.30 

2.60 

2.90 

3.25 

3.60 

3.85 

4.2 

SOUTH 

CHINA SEA 

1.32 

1.50 

1.65 

1.80 

2.00 

2.20 

2.45 

2.65 

2.85 

3.1 

4.5 3.30 

3.54 

3.70 

NOTE: Plot conductivity values for shale on 3-cycle semi-log paper. 

Table 12 - 1 Predicted Pressure Gradients vs. Conductivity or Resistivity Ratios 

Example 

Figure 12-4 shows an example of an IES log. From the plot in Figure 12-5, it can be easily seen 

that a marked trend of normal pressure zone is obtained until a depth of approximately 11,000 

feet. At this point, the sharp change indicates that an abnormal pressure zone has been 

encountered. Figure 12-5 shows the conductivity plot versus depth for the log in Figure 12-4. 

Sample calculations from Figure 12-5: 

• For abnormal pressure zone at 13,000 feet, 

• Shale conductivity observed = 1670 

• Shale conductivity normal = 630 

Calculate the ratio of observed conductivity to normal conductivity: 

If the formation were of Miocene-Oligocene geologic age, Table 12-1 indicates a formation 

pressure equivalent to approximately 16.1 lb m /gal drilling fluid density. 

Sonic Logs 

Sonic log data is used in a manner similar to the conductivity method of pressure prediction. 

Sonic logs measure transit time of sound for fixed distance through formations (the same as the 

seismic information). Interval transit time (microseconds per foot) decreases as formation 



REVISION 2006 12-7


porosity decreases because a denser material transmits sound waves at a higher velocity than a 

less dense material. Porosity generally decreases at a near linear rate as a function of depth in 

normally near a straight line with gradual reduction in travel time as a function of depth. 

Increased shale porosity (which usually indicates a change in compaction and abnormal 

pressures) would produce an increase in shale travel time. Figure 12-6 is a plot of shale transit 

time versus depth. Note the normal compaction trend indicating normal formation pressures 

down to approximately 11,000 feet. Below this depth, shale travel time values begin to increase 

in relation to extrapolated normal compaction line, indicating abnormal formation pressures. 

Figure 12 - 6 Shale Transit Time vs. Depth 



REVISION 2006 12-8


Pressure 

Gradient in 

Equivalent 

Fluid Weight 

(lb m /gal 

9.0 

9.5 

10.0 

10.5 

11.0 

11.5 

12.0 

12.5 

13.0 

13.5 

14.0 

14.5 

15.0 

15.5 

16.0 

16.5 

17.0 

17.5 

18.0 

U.S. GULF 

COAST 

Miocene- 

Oligocene 

to - tn 

2.5 

5.0 

6.5 

8.0 

10.5 

13.0 

15.0 

17.0 

19.0 

21.0 

24.5 

28.0 

33.0 

38.0 

43.0 

48.0 

FRIO 

FORMATION 

S. Texas 

Gulf Coast 

to - tn 

10.7 

13.0 

15.4 

17.7 

20.0 

22.5 

25.0 

27.8 

30.3 

33.0 

36.0 

39.25 

42.50 

46.25 

52.0 

WILCOX 

FORMATION 

S. Texas 

Gulf Coast 

to - tn 

9.2 

11.6 

14.0 

16.4 

8.8 

21.3 

23.8 

26.4 

29.0 

31.8 

34.5 

37.5 

40.5 

44.5 

48.5 

WEST- 

TEXAS 

to - tn 

4.0 

6.0 

8.0 

10.0 

12.0 

15.5 

19.0 

22.0 

25.0 

28.0 

32.0 

36.0 

40.0 

45.0 

50.0 

54.5 

59.0 

63.0 

67.0 

NORTH 

SEA 

to - tn 

2.0 

7.0 

9.5 

13.3 

17.0 

21.0 

25.0 

29.5 

34.0 

41.0 

48.0 

51.0 

54.0 

57.0 

NOTE: Plot observed shale travel time on 3-cycle semi-log paper. 

Table 12 - 2 Predicted Pressure Gradient vs. Sonic Log Departure (At Observed- 

At Normal) 

Example 

SOUTH 

CHINA SEA 

to - tn 

3.0 

7.0 

11.0 

15.0 

19.0 

22.5 

26.0 

29.0 

32.0 

34.5 

37.0 

39.5 

42.0 

Figure 12-6 indicates a departure from extrapolated normal travel time of approximately 35 

sec/ft at 13,000 feet. Utilizing the Miocene-Oligocene column of Table 12-2, a pore pressure 

equivalent to 15.8 lb m /gal drilling fluid density is predicted. 

As mentioned, abrupt changes in salinity of pore water in shales can lead to erroneous pressure 

prediction when using resistivity or conductivity logs. Other variables which may affect logs 

are noted in Table 12-3. 

Some suggestions for selecting the shale data points to be used in formation pressure prediction 

are: 

• Select clean shales in intervals of low spontaneous potential (SP) deflection and uniform 

conductivity or sonic readings. 

• Shales selected for data points should be at least 20 feet thick with points obtained from the 

center of section, if possible. 

• The most reliable shale readings are usually the higher conductivity values midway between sand 

intervals. 



REVISION 2006 12-9


• Shale stringers within massive sand sections tend to exhibit high, unreliable readings. 

• Avoid shale readings immediately above a known gas sand. These readings will characteristically 

display high, unreliable values. 

• If available, the caliper survey should be scanned for excessive hole enlargement. Excessive 

enlargement can create a skip in signal on sonic logs and lead to erroneous data. 

• Avoid plotting silty or limey shales by inspecting the SP curve. Minimum SP values will result in 

more reliable data. 

• Scan log prior to plotting for scale changes or error in tie-back on subsequent log runs. 

• Utilize available well data to verify predicted pressures (formation tests, “d” exponent plots, well 

kick data, etc.). 

Factor 

Salinity changes 

Swelling clays 

Hole enlargement 

Limey shales 

Resistivity markers 

Age change 

Bentonite clays 

Improper calibration 

Tool malfunction 

x = Affected 

s = Sometimes Affected 

Short 

Normal 

x 

x 

x 

x 

x 

x 

s 

s 

Conductivity 

x 

s 

x 

x 

x 

s 

s 

Transit 

Time 

Table 12 - 3 How Variables Affect Logs 

x 

x 

x 

x 

s 

s 

Bulk 

Density 

x 

x 

x 

x 

s 

s 



REVISION 2006 12-10


DRILLING PARAMETERS USED TO INDICATE AN 

ABNORMAL PRESSURE ZONE 

Although attempts at predicting actual formation pressures are important it should be realized 

that they are just predictions. While drilling, several indicators of abnormal zones must be 

watched so that early detection is possible. The most common methods used to detect abnormal 

pressure zones in their assumed order of occurrence are: 

• Increased rate of penetration 

• change in rotary torque 

• change in drag on connections 

• change in pit volume 

• variation from normal “d” exponent and its modified d xc exponent 

• gas content of drilling fluid 

• variances in shape and size of shale cuttings 

• shale density 

• flowline temperatures 

• chloride ion content of drilling fluid 

• paleo information. 

All the above indicators will not be present at any one time. Rig personnel, however, must be 

able to recognize these indicators and interpret correctly those which are present on a particular 

job. Experience has shown that when more than one indicator exists, a cross-checking system 

which uses one indicator to verify others helps eliminate many potential drilling problems 

related to abnormal pressures. 

Increased Rate of Penetration 

Rate of penetration is one of the most widely accepted methods of determining changes in pore 

pressure. There are, however, variables other than pore pressure which affect rate of 

penetration. They are, 

• lithology changes 

• hydraulics (bottom-hole cleaning) 

• bit weight 

• bit type 

• bit condition 

• rotary speed 

• drilling fluid properties. 

There is no way to control lithology. It is, therefore, paramount when using penetration rate as 

a detection method to control the other governing variables as closely as possible. 



REVISION 2006 12-11


A uniform decrease in rate of penetration of shales normally occurs with depth. This decrease, 

which results from increased compaction and density of the shales, can be related to the 

differential between hydrostatic pressure and pore pressure. The magnitude of change in 

differential pressure is the key to changes in penetration rates. 

While drilling a transition zone, drilling fluid density should be maintained as low as possible 

so that any change in pore pressure will be reflected in penetration rate. As pore pressure 

increases, rate of penetration will increase. Any excessive overbalance in drilling fluid density 

will decrease the differential pressure and partially mask the formation pressure increases. 

As mentioned, the inability to control lithology presents a serious problem. Generally, a sudden 

large increase in penetration rate may indicate a lithology change. To prove or disprove such a 

conclusion, the other parameters of abnormal pressure detection must be carefully evaluated. 

Rotary Torque 

During a normal drilling operation, rotary torque gradually increases with depth due to the 

effect of wall contact of the drillstring on the wellbore. Any abrupt changes from this gradual 

trend indicates a twist-off of the drillstring, a locked cone on the bit, a washout in the 

drillstring, or a change in formation pore pressure. The actual condition is usually determined 

by an experienced driller. 

Increased pore pressure causes larger amounts of shale cuttings to come into the wellbore and 

the bit teeth will take larger bites into the formation. The increased amount of shale tends to 

stick or impede bit rotation. Rotary torque will not be easy to interpret as an indicator where 

hydrostatic pressure is greater than formation pressure in deviated holes or when drilling from 

a floating vessel. 

Changes in Drag on Connections 

When drilling in a balanced or near-balanced situation, an increase in drag can occur while 

making a connection in an abnormally pressured zone. This increase is caused by the extra 

shale cuttings which enter the wellbore when abnormal pressure is encountered. 

Because of the plastic nature of some pressured shales, as shown by Darley, the hole may close 

in around drill collars and bit, and drag increases. Drag, much like rotary torque, can be 

masked as an indicator while drilling deviated holes or drilling from a floating vessel. 

Change in Pit Volume 

An increase in pit volume (rigs now employ pit totalizers to monitor this variable) is an 

indication of formation fluids entering the wellbore while drilling. Drilling ahead should be 

interrupted. Mud returns should be monitored for the increasing presence of background gas. 

Circulation may also be interrupted for a short period to observe for any flow from the annulus. 

Caution should be exercised in this case, as the chance of becoming differentially stuck 

increases if all pipe movement and circulation is interrupted. 



REVISION 2006 12-12


The “d” Exponent 

The “d” exponent method of detecting and predicting the magnitude of pressure abnormalities 

while drilling is a useful tool in some areas. Improvement in plotting techniques has refined the 

method to the extent that pressure gradients in many areas can routinely be predicted with an 

accuracy of approximately 0.010 to 0.025 psi/ft, the equivalent of 0.2 to 0.5 lb m /gal of fluid 

weight. The value of formation pressure information during drilling operations is readily 

apparent. Properly utilized, this information can reduce the incidence of blowouts and 

significantly reduce the use of unnecessarily heavy fluids, thereby increasing penetration rate 

and reducing drilling costs. Preparation of the “d” exponent plots is uncomplicated and requires 

no special equipment. The required information – penetration rate, rotary rpm, weight on bit, 

and hole diameter – is routinely available at the wellsite. 

In 1965, Bingham suggested that the relationship between penetration rate, weight on bit, 

rotary speed, and bit diameter can be expressed by the following general equation, 

where, 

R = penetration rate 

R ⎡W 

⎤ = K 

N ⎢ 

⎣ D ⎥ ⎦ 

N = rotary speed 

K = a constant 

W = weight on bit 

D = hole diameter 

d = exponent. 

In 1966, Jorden and Shirley of Shell Oil Company introduced the “d” exponent concept. Earlier 

investigators had established the inverse relationship between penetration rate and the pressure 

differential between the fluid column and the formation. Jorden and Shirley advanced the idea 

that while drilling normally pressured formations with constant fluid weight, the pressure 

differential increases with depth and decreases as abnormally pressured formations are 

encountered. Under constant drilling conditions and uniform rock properties, these changes in 

differential pressure result in gradually decreasing penetration rate through normally pressured 

formations and an increase in penetration rate through abnormally pressured formations. Thus, 

if it were possible to hold the entire drilling variables constant, a simple plot of penetration rate 

versus depth could be used as a pressure detection tool. 

Similarly, if all variables other than rotary speed, weight on bit, and hole size are held constant, 

the relationship between the “d” exponent in the Bingham equation and pressure differential 

would show recognizable trends when the “d” exponent is plotted versus depth. Solving 

Bingham's equation for “d” and adding constants to permit use of common oilfield units, 

Jorden and Shirley introduced the “d” exponent equation, 

d 

d = 

R 

log 

60N 

12W 

log 

6 

10 D 



REVISION 2006 12-13


where, 

R = ft/hr 

N = rpm 

W = lb 

D = diameter in inches. 

As predicted, plotting “d” as calculated from this equation versus depth does establish 

recognizable trends in normally pressured formations and recognizable deviation from these 

trends as abnormal pressures are encountered. 

In 1971, Rehm and McClendon proposed that if it were possible to correct for fluid weight, the 

“d” value could be related directly to formation pressure rather than to differential pressure. 

They suggest making a correction by multiplying the basic “d” value by the ratio of the normal 

fluid weight pressure gradient for the area to the actual fluid weight being used. 

⎛ Normal Fluid Weight 

d xc = d 

⎟ ⎞ 

⎜ 

⎝ Fluid Weight in Use ⎠ 

Use of this correction factor gives excellent results and permits graphic determination of 

pressure gradients in abnormally pressured zones. 

Gas Content of Drilling Fluid 

Increases in the gas content of a drilling fluid was recommended as an indicator for detecting 

abnormal pressure zones as early as 1945 (Pixler). Since experience has shown that gas cutting 

is not always a result of an under-balance condition, correct interpretation of gas cutting trends 

is imperative. 

Gas may be entrained in the fluid column as a result of the following conditions. 

• When a formation containing gas is drilled, cuttings and cavings containing gas are circulated up 

the hole. Hydrostatic pressure on these particles is reduced. Gas in the particles expands and is 

released to the drilling fluid system, cutting the weight. In such cases, increasing fluid weight will 

not stop the gas cutting. This condition can be verified by reducing drilling rate or by stopping 

drilling and circulating bottoms up. 

• While drilling a pressured formation, the differential between the hydrostatic fluid column 

pressure and formation pressure is reduced. During a connection or trip, the piston effect of 

upward pipe movement can swab formation gases and fluids into the wellbore. As the fluid or gas 

is circulated up the annulus, gas (if present) will expand. When detected, the gas is generally 

concentrated and reaches the surface at the same time, thereby showing a significant gas cut. 

When using gas in the drilling fluid as an indicator of abnormal pressure, a gas detector unit of 

some type is required. A trend of background gas and connection gas can be noted as drilling 

progresses. Both background gas and connection gas normally increase slowly with depth. Any 

sudden increase in background or connection gas should be watched carefully and taken as a 

possible warning of increasing pore pressure. 



REVISION 2006 12-14


Changes in Cuttings 

Shale cuttings from an abnormally pressured zone are larger than those from a normally 

pressured zone. They are characterized by sharp and angular edges, while normal pressure 

shale cuttings are generally small and flat with rounded edges. 

The variables which determine the size and shape of shale cuttings are: 

• mineralogical, chemical, and physical properties 

• type of drilling fluid system 

• circulation rate 

• hole geometry 

• downhole agitation. 

Gas or saltwater or a combination of the two in the over-pressured shale helps support some of 

the overburden. Hottman and Johnson proposed one method to explain this. Over-pressure in 

the shale, if not offset by equal or greater hydrostatic pressure from the drilling fluid, will 

create a condition which aids the spalling (sloughing) action of the shale. 

H.C.H. Darley and Chenevert found that shales develop pressure if certain fluids are allowed 

into the pores. The abnormally pressured shales then act much like popcorn – exploding into 

the wellbore – if forces across the face of the wellbore are not equalized. 

Shale Density 

Shales which are normally pressured have undergone normal compaction and their densities 

increase uniformly with depth. This uniform increase allows shale density to be predicted. Any 

reduction from the extrapolation can be interpreted as a zone of higher pore pressure. The 

primary problem of relying on shale density is that the shale cuttings must be circulated to the 

surface before measurements can be made. 

Flowline Temperature 

Due to abnormal pressures exerted on fluids in a transition zone, above normal temperatures 

occur. A normal trend of flowline temperatures can be plotted. A change of 2° to 6°F above 

this trend can be an indication of a transition zone. In addition to indicating a pore pressure 

change, changes in flowline temperature can also be attributed to: 

• an increase in circulation rate 

• a change in solids content of the drilling fluid 

• a change in drilling practices 

• an increase in bit torque. 

The temperature curve, although not definitive, is still an additional indicator to help make a 

decision to stop drilling or increase existing fluid weights. 



REVISION 2006 12-15


Chloride Trends 

Changes in the chloride ion content of the drilling fluid are a valid pressure indicator, but 

changes are difficult to establish unless there is close control and analysis of fluid properties. 

Most methods currently available to make routine chloride ion tests are inadequate to show 

subtle changes. An alternative to actually measuring the chloride content of the filtrate is 

continuous monitoring of the resistivity of the fluid both into and out of the hole. 

Paleo Information 

Abnormally high pore pressures are frequently related to certain environmental conditions 

within a given geologic time period. This depositional environment is marked by the presence 

of certain fossils. Should examination of cuttings reveal these fossils, then the operator should 

be alerted to the potential problem of encountering abnormally high pore pressures. 

CONTROLLING FORMATION PRESSURE 

Control of formation pressure is one of the primary functions of drilling fluids. The hydrostatic 

pressure exerted by the fluid column is the most important method of controlling formation 

pressure. Whenever formation pressure exceeds the total amount of pressure exerted on the 

formation, formation fluids may enter the wellbore causing a kick. A kick is defined as any 

unscheduled entry of formation fluids into the wellbore. Early recognition of a kick and prompt 

initiation of control procedures are the keys to successful well control. If kicks are not detected 

early enough or controlled properly when detected, a blowout can occur. 

Preplanning to Prevent or to Handle Kicks Safely 

The cornerstone of a safe, efficient drilling program is prediction of pressure gradient, fracture 

gradient, and fluid densities based on drilling, geological, and physical experience in the area. 

This has been discussed in the first part of this chapter. 

On exploratory wells, or in areas where little information is available, it is necessary to focus 

on drilling parameters such as penetration rate, modified “d” exponent, gas readings and trends, 

fluid temperature, fluid conductivity, etc., and to run confirmation logs when drilling 

parameters indicate changes in pressure gradient. In fact, these drilling parameters should be 

monitored even in areas where information is available. The preliminary drilling plan is merely 

a guideline and does not eliminate the possibility of unexpected changes in pressure gradient. 

Blowout frequency for exploratory drilling is about double that of the average for all drilling 

operations. 

Preplanning on the rig should give consideration to the following aspects of the operation. 

• Assignment of responsibilities. Each crew member should know who will perform various 

surveillance tasks, coordinate well kill procedures, and operate the choke. 

• Periodic inspection and testing of well control and detection equipment to insure kicks can be 

detected and contained. 

• Pit drills should be conducted on a regular basis by all crew members to condition the crew to 

execute proper kick control procedures. 



REVISION 2006 12-16


• Preventive training. It is absolutely essential that personnel be thoroughly trained in prevention 

and containment of kicks. After a well kicks, it is too late to learn how to execute an engineered 

approach to kick control. 

Kick Recognition 

Early detection is necessary for successful control of a well kick. The severity of the kick 

depends not only on the differential between drilling fluid hydrostatic and formation pressures, 

but on the kick volume as well. Early detection and prompt well closure is usually the 

responsibility of the rig crew. 

To help the rig crew recognize kicks and execute proper control procedures, pit drills should be 

conducted on a routine basis. Pit drills can be initiated by a company man or rig tool pusher 

manually activating pit level or flow indicators, and observing the reaction time of the driller 

and crew. Drills conducted while drilling should include raising the kelly and stopping the 

pump to check for flow. The Blowout Preventers are normally not closed unless an actual flow 

exists. Drills while tripping may include installing a safety valve in the drillstring if the pipe is 

inside casing. If drills are conducted on a routine basis as part of company policy, the rig crew 

becomes conditioned to execute proper control measures in a minimum amount of time. 

Kicks While Drilling 

A kick occurs while drilling when the pressures of the formation drilled exceed the total 

pressures of the circulating fluid column (hydrostatic pressure plus annular pressure loss, i.e., 

P ECD 

• drilling break 

• increase in flow rate 

• increase in pit volume 

• circulating pressure drop 

• well flowing with pumps off 

• increase in chloride content of fluid at the flow line 

• gas cut fluid or increasing gas concentration in the fluid. 

Drilling break – This is one of the first indications of a kick. For hydrocarbons or water to 

enter the wellbore, there must be a permeable section containing a pressure greater than that 

exerted by the fluid column. In soft sandstones, this condition usually causes a sudden increase 

in drilling rate. The magnitude of the increase varies, but an increase of 200% to 300% is not 

unusual in soft sediments. Any significant drilling break should be checked for flow. This is 

done by stopping the pump and checking the flowline to see that flow stops. If the well 

continues to flow, it should be shut-in and checked for pressures. 

In hard formations, a reverse break to a slower drilling rate may indicate a sand or limestone 

section. In this case, the increase in drilling rate with flow into the wellbore is masked by 

harder formations. However, a reverse break can also be the first indication of an overpressured 

formation. 



REVISION 2006 12-17


Flow rate increase – The entrance of any fluid into the wellbore will cause the flow rate to 

increase. This occurs shortly after, or concurrently with, the drilling rate increase. Since the 

intruding fluid is almost always lighter than the drilling fluid, a continued flow from the 

reservoir tends to lighten the fluid column causing further increase in flow. The most common 

flow sensor, a paddle in the flow line, allows measurement of flow increases if the flowline is 

not full. A full or almost full flowline restricts paddle movement making it difficult to show an 

increase in flow. 

Pit volume increase – An increase in pit volume occurs as the result of two separate processes. 

First, the increased flow rate increases fluid volume in the pits. In addition, if the kick contains 

gas, gas expansion causes a further increase in flow rate and pit volume. Pit volume totalizers 

used on the rig can be adjusted to read increases accurately, but pit levels should be monitored 

visually as a back-up. The surface area of a standard fluid tank on a land rig is approximately 8 

ft by 30 ft, or 240 ft 2 . This is close to 3½ barrels of fluid per inch of depth. With a normal set of 

three fluid pits, a one inch change would represent a 10.7 barrel volume change. 

Circulating pressure decrease – Because of the imbalance between the hydrostatic column in 

the drillpipe and annulus after penetrating an abnormal zone, it may take less pump pressure to 

circulate the fluid. Flow rate increase and pit volume increase would normally be observed 

before a circulating pressure decrease. 

Well flows with the pump off – This indicates that reservoir fluid is flowing into the wellbore. 

Chlorides increase – Formation fluids may have higher chloride contents than the make-up 

water being used in the fluid system. Fluid systems with chlorides above 100,000 mg/L may 

not show any change when formation fluids enter the fluid system. 

Gas cutting – Changes in trends of trip gas, connection gas, and background gas can be a valid 

tool for detecting formation pressure changes. If gas cutting occurs, the source of the gas must 

be determined. Drilling should be halted and the hole circulated for a sufficient time to remove 

the cuttings from the hole. If the gas originates from cuttings, the value will decrease to a 

normal level after the hole is circulated clean. If gas cutting persists, it may indicate an 

underbalance. The slip velocity of cuttings can be quite high in low-density, low-viscosity 

fluids, and the time required to clean the hole may be considerably greater than calculated 

circulating time. It should also be borne in mind that when formations containing gas are 

drilled, some gas will always show up at the surface. There is no way to prevent this from 

happening, regardless of fluid weight. Normal levels of background gas will vary from one 

area to another. 

The degree to which gas cutting affects hydrostatic pressure is an often misunderstood factor. 

Gas cutting causes only very slight reductions in hydrostatic pressure. Normally, gas cutting of 

50% on the surface does not significantly reduce bottom-hole pressures (BHP), since it is less 

than the normal increases due to annular pressure loss. 

Referring to Figure 12-7, if an 18 lb m /gal drilling fluid is cut to 9.1 lb m /gal at the shaker, and if 

the gas is evenly distributed from top to bottom of the hole, the reduction in BHP at 10,000 ft is 

only 95 psi, equivalent to reducing the fluid weight by 0.2 lb m /gal. 



REVISION 2006 12-18


Figure 12 - 7 Reduction in BHP Corresponding to a Surface-Observed Reduction 

in Fluid Weight Due to Gas Cut Fluid 

If no flow occurs when the pump is shut down, hydrostatic pressure and fluid weight are 

sufficient. There could be a slug of gas in the annulus that could later cause trouble and caution 

is indicated, but gas cutting by itself is not serious. A very small amount of gas at bottom hole 

conditions can gas cut a large amount of fluid at surface conditions. Drilling a porous sand, a 

bridged hole with trapped gas or circulation of bottoms-up after a trip will often produce these 

results. 

Kicks While Tripping Out of the Hole 

It has been estimated that 50% or more of all kicks occur while tripping. The main reasons for 

these kicks are generally poor practices and neglect on the part of rig crews. Two major 

incidents cause kicks while tripping out of the hole. 

1. Failure to fill the hole often enough or failure to add fluid to the hole equivalent to 

the displacement of pipe removed. Depending on the displacement of the pipe 

withdrawn, there will be a corresponding drop in fluid level (assuming no swabbing 

has occurred) which may lower the hydrostatic pressure enough to allow the well to 

kick. 

For example, five stands of 4½ in. drillpipe (16.6 lb m /ft 93 ft stands) withdrawn from an 

8½ in. hole would result in a fluid level drop of 45½ ft. Whereas, five stands of 6¾ in. × 

2¾ in. drill collars (93 ft stands) would result in a fluid level drop of 263½ ft. 

Frequency for filling the hole is a function of fluid gradient, hole diameter, pipe 

displacement, and formation pressure. 



REVISION 2006 12-19


2. Another problem associated with tripping is swabbing. Swabbing is compounded 

by bit or collar balling, the viscous drag of fluid on the pipe, and the speed at which 

the pipe is pulled from the hole. Swabbed pressure reductions due to viscous drag 

can be calculated using ADVANTAGE engineering software. Swab pressures 

should be controlled by observing safe drilling practices. If swabbing problems are 

anticipated, a maximum “safe” tripping speed should be calculated and adhered to 

by the rig crew. 

To detect kicks while tripping, an accurate measurement of the volume of fluid required to 

keep the hole full must be made. This is best accomplished using a calibrated tank called a trip 

tank. If the volume of fluid required to fill the hole is less than the displacement of the pipe 

withdrawn from the hole, a kick is indicated and remedial steps should be taken. 

Kicks While Tripping Into the Hole 

When drilling with fluid gradients near the fracture gradient of exposed formations, surge 

pressures caused by viscous drag of the fluid on the drillstring may result in lost circulation. If 

lost circulation occurs, the decrease in pressure depends on how far the fluid level falls. If the 

fluid level falls enough, the corresponding decrease in hydrostatic pressure may be sufficient to 

allow formation fluids to enter the wellbore and cause a kick. A practical approach to 

recognizing this problem is to observe pit level increase versus amount of drillpipe run into the 

hole, and to observe the flowline on each stand run to insure that fluid returns are maintained. 

Behavior of Gas in the Wellbore 

To properly understand the problems of killing a kick, it is necessary to understand some of the 

things that can and cannot be done successfully. Gas expansion and the gas laws are basic 

concepts that should be understood to help prevent problems in controlling kicks. 

The simple form of the general gas law states that gas expands as pressure on the gas is 

reduced or that if gas is not allowed to expand, the pressure in the gas remains the same. This 

statement is modified by the effect of the temperature and the type of gas, so that 

mathematically the general gas law is, 

where, 

PV 

1 

T Z 

1 

1 

1 

= 

P2V 

T Z 

P = gas pressure 

V = gas volume 

T = temperature 

Z = compressibility factor 

1 = the first set of conditions (bottom-hole conditions) 

2 = the second set of conditions (up-hole conditions). 

Rise of Gas without Expansion 

A practical application of the gas laws can be illustrated by considering a 10,000 ft well with 

10 lb m /gal fluid and 1 bbl of gas that has been swabbed in on a connection. The well was shut- 




2 

2 

2


in and the gas bubble circulated to the surface by holding the pit volume constant (preventing 

the gas from expanding). For this example, the effect of temperature and compressibility is 

ignored. 

The bottom-hole pressure in the well is 5200 psi, and the gas volume is one bbl. If the gas is 

circulated half way up the hole, there will be 2600 psi of fluid pressure above the gas bubble, 

but the pressure in the gas bubble will still be 5200 psi according to the general gas law. 

The surface annular pressure will be 2600 psi, which is the difference between the pressure in 

the gas bubble and the fluid pressure above it. The bottom-hole pressure will be the pressure of 

the fluid column, 5200 psi, plus the surface annular pressure, 2600 psi, for a total of 7800 psi. 

The surface pressure and the wellbore pressure will continue to increase as the bubble is moved 

up the hole without being allowed to expand. When it reaches the surface, the surface pressure 

will be 5200 psi and the bottom-hole pressure 10,400 psi, or the equivalent of 20 lb m /gal fluid. 

Long before the bubble gets to the surface, fracture pressures will be exceeded and an 

underground blowout will occur. 

In earlier years, this technique of Constant Pit Volume, or Barrel-In/Barrel-Out, was used to 

kill wells. Although this method works for water flows, it almost always results in lost 

circulation and an underground blowout when the formation fluid contains gas. 

Rise of Gas with Uncontrolled Expansion 

The opposite extreme of circulating the gas out of a well without holding any pressure on it is 

equally bad. In the same circumstances, one bbl of gas is swabbed into the well, but the well is 

not closed in and the pump is turned ON to circulate the bubble out of the hole. 

When the gas is half-way up the hole, it has expanded to 2 bbl. When the gas was at the bottom 

of the hole, the 1 bbl “column” of gas was only about 12½ ft long. Halfway up the hole, it is 25 

ft long and three quarters the way up the hole, the gas has expanded to 32 bbl and occupies 

about 400 ft of annulus. The 400 ft of gas has reduced the bottom-hole pressure by about 200 

psi and more gas is probably entering the wellbore. 

Circulating a gas bubble up without holding some surface pressure will unload the hole and 

cause a blowout. The technique of trying to “out run” a well kick is risky because the bet is that 

the formation has such low permeability that the well could hardly blow out. Trying to outrun a 

well kick works occasionally because the kick may be water and, because the pumping rate is 

increased, the bottom-hole pressure is increased by the amount of the annulus friction loss. It 

still remains a risky endeavor and leads to more failures than successes. 

Rise of Gas with Controlled Expansion 

The proper way to handle a gas bubble in a well is to put enough pressure on the gas to keep 

the bottom-hole pressure constant. This is the basic idea behind proper well control techniques. 

Using the previous illustration, one bbl of gas has been swabbed into the hole but allowed to 

expand in a controlled manor by using an adjustable choke at the surface. When the gas bubble 

is half-way up the hole, the casing pressure would have to be 14 psi to keep the bottom-hole 

pressure constant. When the gas is at 2500 ft, the casing pressure would have to be about 28 psi 

(Figure 12-8). At 1200 ft, the casing pressure would have to be about 57 psi. 



REVISION 2006 12-21


This type of calculation can be difficult, time consuming, and will never be very accurate 

because the type of gas, its solubility, and the actual configuration of the gas “bubble” is 

unknown. The drillpipe pressure techniques described later do away with having to make this 

type of calculation. 

Figure 12 - 8 Rise of One Barrel of Gas With Controlled Expansion 

Shut-In Drillpipe and Casing Pressures 

Drillpipe and casing pressures are used in well control to determine working pressures. The 

drillpipe pressure gauge or pump pressure gauge is in reality a bottom-hole pressure gauge. 

After a well kick, when the pump is off and the well is shut-in, the drillpipe is a long gauge 

stem that reaches to the bottom of the hole. The drillpipe pressure gauge reads the bottom-hole 

pressure as seen from the gauge stem. If the drillpipe were empty, the surface gauge would 

read bottom-hole pressure. But the drillpipe is not empty, so the gauge reading shows the 

difference between bottom-hole pressure and the fluid column pressure in the drillpipe. So, 

shut-in drillpipe pressure is the difference between the pressure exerted by the fluid column in 

the drillpipe and the bottom-hole pressure. It is the kick pressure. 

Casing pressure will normally always be higher than drillpipe pressure because the kick gas or 

water will normally be lighter than the fluid. This makes the fluid column pressure in the 

annulus less than the full column of fluid in the drillpipe. So, the annulus surface pressure will 

be higher than the drillpipe pressure. 

To determine the fluid weight needed to control a kick, the formation pressure must be known. 

This may be obtained from the pressure on the drillpipe. Since fluid inside the drillpipe will not 

be contaminated, the pressure on the drillpipe plus the hydrostatic pressure of the fluid column 

equals formation pressure. Shut-in drillpipe pressure can be determined by: 

• Reading directly from a gauge at the surface. If there is a back pressure valve in string then, 

• Start pump slowly, continue until fluid moves or pump pressure increases suddenly. 



REVISION 2006 12-22


• Watch annulus pressure, stop pump when annulus pressure starts to increase. 

• Read drillpipe pressure at this point. 

• If annulus pressure increased above original pressure, this would indicate trapped pump pressure 

and the amount of increase must be subtracted from the shut-in drillpipe pressure. 

This procedure should be repeated until the same value is read two consecutive times. 

or 

• If a predetermined circulating pressure has been measured at a circulation rate which will be used 

to kill the well then, 

• Open choke and start pump slowly, holding annulus pressure at same level as shut-in annulus 

pressure. 

• Bring pump speed up to predetermined kill rate, keeping annulus pressure constant. 

• Read pump pressure; subtract predetermined circulating pressure from pumping pressure. The 

remainder will be shut-in drillpipe pressure. 

Fluid Weights and Pressures 

Drillpipe pressure (or casing pressure) can be converted to Equivalent Fluid (Mud) Weight 

(EMW) and vice versa. In the following discussion on fluid weight increase, the equation used 

to convert pressure to fluid weight (lb m /gal) is, 

Fluid Weight 

Increase, 

lb 

m 

/ gal 

SIDP 

= 0. 052× 

( TVD) 

Where: 

SIDP = 260 psi, 

TVD = 10,000 ft, 

Fluid weight = 12. 0 lb m /gal. 

260 psi 

Fluid weight increases, lbm / gal = 

= 0.5lbm 

/ gal 

0.052× 

10,000 ft 

This is th e fluid weight increase needed to balance formation pressure. 

Therefore, 

Initial fluid weight 

Required weight increase 

Total 

12.0 lb m /gal 

+ 0.5 lb m /gal 

12.5 lb m /gal 

When pressure is held on the circulating system with an adjustable choke, the additional 

pressure is felt throughout the system, including at the bottom of the hole and at the drillpipe 

pressure gauge. As fluid weight is increased to kill a kick, the pressure held by the choke is 

replaced by hydrostatic pressure from the heavier fluid. Thus, the choke is adjusted as heavier 



REVISION 2006 12-23


fluid is pumped into the well. See Figure 12-9. This is further explained in the Wait and 

Weight Method of well control. 

Equivalent Circulating Density 

Figure 12 - 9 Kill Fluid Weight 

It has been mentioned previously, that when the mud pump is running, the bottom-hole 

pressure is increased by the annulus friction loss. When the fluid is moving up the hole, the 

friction of the fluid against the drillpipe, the wellbore sides, and the fluid viscosity all combine 

to create a friction pressure that resists flow. The annular pressure loss is that part of the pump 

pressure that it takes to pump the fluid in the annulus. This pressure value reacts against the 

bottom of the hole and increases bottom-hole pressure. The actual fluid weight, plus the 

increase in bottom-hole pressure due to the annulus friction loss, can be expressed as an 

equivalent fluid weight and is referred to as Equivalent Circulating Density (ECD). 

ECD, 

lb 

m 

/ gal = Fluid Weight + 

Annular frictionloss 

TVD × 0.052 

( psi) 

ADVANTAGE engineering software contains a field proven ECD simulator. This simulator 

can be run in the HPHT mode where it uses Fann 70 / 75 data for downhole rheological 

properties and retort and PVT data to calculate downhole densities. This results in an extremely 



REVISION 2006 12-24


capable tool if the correct input data is used. For water based drilling fluids, as they are not so 

strongly influenced by temperature and pressure the normal Fann 35 data should be sufficient. 

The practice of using PV / YP for hydraulics calculations should be avoided. 

The total pump pressure when circulating is the friction required to move the fluid through the 

drilling system. The bit nozzles can take 50% to 60% of the pressure drop with most of the rest 

being lost in the drillpipe. These pressures do not affect bottom-hole pressure because the 

pressure losses occur before the fluid enters the annulus. 

The pressures in the circulating system, shown in Figure 12-10, can be divided as follows. 

Surface system (2) 

Drillpipe (3) 

Drill collars (4) 

Bit jets (5) 

Annulus flow (6) 

Pump pressur e (standpipe gauge) 

(1) = The sum of the above 

The annulus flow (6) puts pressure on the open hole. This is the annular pressure element in the 

ECD. 

BHP = Hydrostatic pressure + Annular friction loss 

Figure 12 - 10 System Pressure Losses 



REVISION 2006 12-25


U-Tube Concept 

The interrelation of formation pressure and hydrostatic pressure is more easily understood if 

the well is thought of as being a large U-tube as shown in Figure12-11. The sum of the 

pressures on the drillpipe side of the U-tube must be equal to the sum of the pressures on the 

annulus side. 

Sum of Pressure - Drillpipe Side 

• Hydrostatic pressure = 5200 psi 

• Shut-in drillpipe pressure (SIDP) = 0 psi 

• Bottomhole pressure = 5200 psi + 0 psi = 5200 psi 

Sum of Pressure - Casing Side 

• Hydrostatic pressure = 5200 psi 

• Shut-in casing pressure (SICP) = 0 psi 

• Bottomhole pressure = 5200 psi + 0 psi = 5200 psi. 

Figure 12 - 11 “U” Tube Static 

With the pump off and hydrostatic pressure overbalancing formation pressure (0.052 x 10,000 

ft x 10 lb m /gal = 5200 psi) both gauges equal zero. When fluid column pressures on both sides 

of the U are equal to each other and equal to or greater than formation pressure, no formation 

fluid can enter the wellbore. Both sides of the U stand full of fluid with zero surface pressure. 

The purpose of the well control system is to circulate heavy fluid into the hole. The method of 

circulation, then, is basic to the system of well control. It is not usually desirable to run the 

fluid pump at full speed while circulating out a kick because the pressures required would 

probably exceed the pressure limit of the pump. For this reason, a kick is usually circulated out 

at about half normal pump speed. The pressure required to circulate the fluid through the U- 

tube at some reduced pump rate is called the Reduced Circulating Pressure (RCP) (see Figure 

12-12). 



REVISION 2006 12-26


Other names for RCP are, 

• Slow Circulating Pressure 

• Kill Rate Pressure 

• Pre-Recorded Circulating Pressure. 

Figure 12 - 12 “U” Tube Circulating 

This pump pressure should be obtained by circulating at a predetermined circulation rate. The 

corresponding pressure on the standpipe gauge is the RCP. This pressure should be recorded 

each hour or when significant fluid property changes are made. Higher fluid weights require 

higher pressures for any given circulation rate. The increase can be determined by a simple 

ratio, 

where, 

P 1 = old circulating pressure 

P 2 = new circulating pressure 

MW l = old fluid weight, 

MW 2 = new fluid weight. 

⎛ MW 

P 

2 

= P 

⎜ 

1 

⎝ MW 

2 

1 

⎟ ⎞ 

⎠ 

Note: 

If pressure is held on the annulus, this pressure adds to the standpipe, 

and is also felt at the bottom of the hole. 

When bottomhole pressure becomes less than formation pressure, formation fluids can intrude 

into the wellbore as shown in Figure 12-13. 



REVISION 2006 12-27


Figure 12 - 13 “U” Tube Shut In 

A gain in pit volume equal to the volume of intruding fluid will then occur. When the well is 

shut in, pressure on the drill pipe will be equal to the difference between formation pressure 

and hydrostatic fluid pressure. Since hydrostatic pressure can be calculated from the known 

height and weight of the fluid column inside the effect represents a pressure gauge by which 

formation pressure can be determined. 

Formation pressure = Hydrostatic pressure + SIDP 

The following is a summary of the pressures in Figure 12-13. 

Drillpipe Pressures 

Formation pressure @ 10,000 ft - Hydrostatic Pressure @ 10 lb m /gal fluid = Drillpipe psi 

5700 psi - 5200 psi = 500 psi 

Annulus Pressures = Hydrostatic Pressure 

1000 ft × 0.052 × 1.0 lb m /gal = 52 psi (1000 ft gas) 

9000 ft × 0.052 × 10.0 lb m /gal = 4680 psi (9000 ft fluid) 

Total Hydrostatic Pressure 

52 psi + 4680 psi = 4732 psi (column) 

Casing Pressure 

5700 psi (Formation pr essure) - 4732 psi (Hydrostatic pressure) = 968 psi (Casing pressure) 

When circulating out a kick at a reduced pump rate, it is necessary to hold pressure on the 

drillpipe gauge in addition to the reduced circulating pressure. This is accomplished by 

circulating through an adjustable choke. When beginning a kill operation, this additional 

pressure equals the SIDP (see Figure 12-14). 



REVISION 2006 12-28


Thus, 

where, 

ICP = RCP + SIDP 

Figure 12 - 14 “U” Tube Circulating With Choke 

ICP = initial circulating pressure 

RCP = reduced circulating pressure 

SIDP = shut-in drillpipe pressure. 

For our example, 

RCP = 900 psi 

SIDP = 500 psi 

ICP = 900 + 500 = 1400 psi. 

Closing Procedure 

If any of the previously discussed warning signs are observed and a flow (with pump off) is 

detected, the following generalized procedures should be initiated. 

Procedure for Closing Well In While on Bottom 

1. Position kelly so that tool joints are clear of sealing elements. 

2. Stop pumps, check for flow. 



REVISION 2006 12-29


3. If flow is noted, open the HCR-valve and close the BOP with the annular preventer. 

4. Record shut-in drillpipe and casing pressures. 

5. Record volume gain and mark pits. 

6. Weigh fluid in suction pits. 

7. Check blowout preventer and manifold for leaks. 

8. Check flowline and choke exhaust lines for flow. 

9. Check accumulator pressure. 

10. Initiate well kill procedures. 

Procedure for Closing Well In While Tripping 

1. If a flow is detected, install and close a safety valve. 

2. Position tool joints and close annular preventer. 

3. Install an inside preventer and open safety valve. 

4. Record casing pressure. 

5. Check blowout preventer stack and manifold for leaks. Check valves for correct 

position. 

6. Check accumulator pressure. 

7. Begin stripping to bottom. 

It is always easier and requires less fluid density to kill a well with the bit at or near the bottom 

of the hole. If a well kicks while drilling, the pipe should not be pulled into the casing. If the 

kick is caught quickly enough, there is less danger of pipe sticking. If the pipe is off bottom 

(making a trip, etc.) at the time of the flow, the pipe should be returned to bottom, if at all 

possible. If necessary, it should be stripped in. 



REVISION 2006 12-30


PRESSURE CONTROL METHODS 

Pressure control is normally a field level activity. The methods of killing well kicks which are 

presented here have been developed for rig site personnel. The procedures for killing a 

threatened blowout must be kept simple, but not oversimplified to the extent of losing their 

effectiveness. 

The three basic, most common well-control methods employ procedures to maintain a constant 

bottomhole pressure on the wellbore while formation fluids are circulated to the surface. This 

is accomplished by using an adjustable choke which can be opened or closed to control 

wellbore pressures. Three variations of the balanced bottom hole pressure are as follows: 

• Building fluid density in the pits before circulating (Wait and Weight). 

• Begin circulating out the bubble and weighting up simultaneously (Concurrent Method). 

• Circulate well clean of formation fluids, shut pumps down and close well in. Then build fluid 

density in pits before circulating heavy fluid (Driller's Method). 

Note: When a kick cannot be circulated out, or there is no way to 

communicate with the bottomhole pressure, the only way to 

control bottomhole pressure is by use of the volumetric method. 

Of these three methods, the Wait and Weight Method is the most commonly used. It is 

discussed below and a sample problem with a completed kill sheet is included to illustrate the 

use of this technique. 

The Wait and Weight Method of Well Control 

The Wait and Weight Method of Well Control is the most satisfactory method of well control 

since it causes the lowest annular pressures and is the quickest way of reducing the pressures 

on the wellbore. It does require a period of shut-in time while the fluid weight is being 

increased, so there is some danger of the pipe becoming stuck. 

If the rig does not have adequate fluid mixing equipment, one of the other constant bottomhole 

pressure methods may be more satisfactory. On most large rigs, marine rigs, and rigs with subsea 

stacks, the Wait and Weight Method is the preferred method. 

In the Wait and Weight Method, the well is shut in until the fluid weight is increased in the pits 

and the well is killed according to a completed worksheet. 

As an example, the well is shut in after a kick and the following information is recorded. 



REVISION 2006 12-31


Shut-In Drillpipe Pressure (SIDP) 

Shut-In Casing Pressure (SICP) 

Pit Volume Increase 

Depth 

Hole Size 

Drillpipe 

500 psi 

650 psi 

15 bbl 

12,000 ft 

8½ in. 

5 in., 19½ lb m /ft IEU 

Collars 210 ft, 7" × 3" 

Casing 

Pump 

Kill Rate 

Kill Rate Pressure 

9 5 / 8 " @ 10,000 ft, 47 lb m /ft N80 

6 × 16 Duplex 

30 spm 

750 psi 

The fluid weight increase is calculated and the fluid weight in the pits is increased. While the 

fluid weight in the pits is being increased a Well Control Kill Sheet is filled out. The 

information on the Kill Sheet is completed as follows: 

• Basic Data – Record the basic data necessary to make the well kill calculations. Circulating 

pressures and pump outputs should be pre-recorded. 

• Record – Pressures and pit level gains. 

Calculate 

Initial Circulating Pressure = Slow Circulating Pressure + SIDP 

New Fluid Density = (SIDP) / (0.052) / (TVD) + Old Fluid Density 

Final Circulating 

New FluidDensity 

pressure = 

Old Fluid Density× 

SlowCirculating pressure 



REVISION 2006 12-32


Baker Hughes DRILLING FLUIDS Well Control Kill Sheet 

BASIC DATA 

RECORD 

a. True Vertical Depth (TVD) ft k. Shut-in Drillpipe Pressure (SIDP) psi 

b. Measured Depth (MD) ft l. Shut-in Casing Pressure (SICP) psi 

c. Fluid (Mud) Weight (M.W.) ppg m. Kick Volume bbl 

d. Drillpipe Volume bbl CALCULATE 

e. Riser Volume bbl n. Initial Circulating Pressure (ICP): 

SCP + SIDP = ICP: _________ + _________ = ________ 

f. Pump Output bbl/stk 

g. Drillpipe Strokes stks o. New Fluid (Mud) Weight: 

SIDP / .052 / Depth + Old M.W. = New M.W. 

_________ / .052 / _________ + _________ = _________ ppg 

h. Strokes to Displace Riser stks 

i. Slow Circulating Pressures (SCP): 

Riser or Casing 

Pump #1: _________ psi @ _________ SPM 

Pump #2: _________ psi @ _________ SPM 

Choke Line (SUBSEA) 

Pump #1: _________ psi @ _________ SPM 

Pump #2: _________ psi @ _________ SPM 

j. Choke Line Friction (CLF): 

SCP Choke Line SCP Riser = CLF 

_________ _________ = _________ 

3000 

p. Final Circulating Pressure (FCP): 

New M.W. / Old M.W. × SCP = FCP 

_________ / _________ × _________ = _________ psi 

q. Maximum Allowable Casing Pressure: 

(Fracture M.W. Present M.W.) × Casing Depth × .052 

( _________ _________ ) × _________ × .052 = _________psi 

GRAPHICAL ANALYSIS OF PUMPING SCHEDULE 

2000 

1000 

Pump Strokes 

Pressure 

Fluid (Mud) Wt 

Minutes 



REVISION 2006 12-33


Graphical Analysis of Pumping Schedule – Divide the time (strokes) to displace the drillstring 

into even increments on the bottom of graph. Use 50, 100, or 200 stroke increments to utilize 

the maximum amount of graph. Plot initial circulating pressure at time or strokes 0. Plot final 

circulating pressure at time or strokes required to displace the drillpipe. Draw a straight line 

between the two points. 

When ready to circulate, open the choke slightly until there is some flow through the choke and 

then start up the pump. Break circulation and bring the pump up to the predetermined kill rate. 

While the pump is being brought up to speed, hold the casing pressure at the shut-in value with 

the adjustable choke. 

Note: 

On rigs with subsea Blow-Out Preventer (BOP) stacks, the casing 

pressure is allowed to drop by the amount of the pressure loss in the 

choke line. 

When the pump is up to the kill rate, the drillpipe pressure should be adjusted to the initial 

circulating pressure by using the adjustable choke. 

As the new fluid is being pumped down the drillpipe, reduce the drillpipe pressure according to 

the graph on the worksheet. The pump pressure will drop from the initial circulating pressure to 

the final circulating pressure over the time that the new fluid takes to fill the drillpipe (the 

surface to bit travel time). If there is gas in the kick, the annular pressure can be expected to 

rise and pit volume will increase as the gas comes to the surface. 

When kill fluid is at the bit, the final circulating pressure should be maintained constant by 

keeping the pump strokes constant and adjusting the choke as required. Continue to circulate 

holding the final circulating pressure until the new fluid is circulated around. If calculations 

and procedures have been followed correctly, the well should be dead. 

After the new fluid reaches the surface, the pumps should be shut down, and the well checked 

for flow. If no flow occurs, the well is dead. Depending upon the operating company, the well 

may be circulated for a time, a short trip may be made, drilling may commence, etc. If the well 

continues to flow, it should be shut in and kill procedures initiated again. 

SPECIAL PROBLEMS 

There are numerous well kill situations which develop that may require the use of special 

techniques to bring under control. These are typical problems that may develop. 

• Nearing fracture gradient limitations 

• Plugged bit 

• Plugged choke 

• Lost circulation 

• Well flows while tripping or out of the hole, etc. 

It is not the scope of this chapter to cover these problems. The operator's representative is 

normally responsible for handling these situations. 



REVISION 2006 12-34


Barite Plugs 

One special situation that will require the supervision of the drilling fluids engineer is the 

mixing of a barite plug. If during a well kick situation, the fracture gradient of the formation is 

exceeded, an underground flow will occur. This condition is signaled by a loss of gauge 

response and loss of returns. If the drill string is above both the loss zone and flowing zone, it 

should be stripped to bottom, if possible. If this is not practical, a lost circulation squeeze may 

plug the loss zone and allow circulation of fluid of required density. 

If pipe is below fractured zones, it is sometimes possible to spot heavy fluid on bottom through 

drillpipe and pump light fluid down the annulus. In some instances, a balance point can be 

reached by this method and flow can be stopped. One method for killing underground blowouts 

is to bridge off the flowing zone with a barite plug. 

Barite plugs seal the wellbore in four ways. 

1. Due to low viscosities and yield points, barite may settle to form a solid plug in the 

hole. 

2. Their high density increases the hydrostatic head on the active zone and helps 

prevent additional influx of formation fluid. 

3. Due to their high fluid loss, they may dehydrate to form a solid plug of barite in the 

hole. 

4. Their high fluid loss may also cause the hole to slough and bridge itself. 

Procedure to Set Barite Plugs 

The barite-water-phosphate slurry is usually mixed with the cementing equipment, pumped 

through the drillpipe and spotted on bottom. The bit jets do not have to be removed. Fresh 

water should be used, because barite does not settle as desired in sea water. Add SAPP to the 

mixing water before adding barite. This keeps the slurry thin to promote settling. The optimum 

amount of phosphate ranges from 0.2 to 0.7 lb m /bbl in the mixing water. A one-quart fluid cup 

of powdered SAPP weighs 2.5 lb. Use CAUSTIC SODA with SAPP to adjust pH to 8 to 10 

range (approximately 0.25 lb m /bbl). If TSPP is used, CAUSTIC SODA is not required. In high 

temperatures, phosphates will not be effective and lignosulfonates can be used. Up to 6 lb m /bbl 

may be required. 

Slurry 

Density 

(lb m /gal) 

18.0 

19.0 

20.0 

21.0 

22.0 

Water 

(gal/bbl 

26.9 

25.3 

23.7 

22.2 

20.6 

Barite 

(sacks/bbl) 

5.30 

5.94 

6.43 

6.95 

7.50 

Slurry Volume/ 

Sack of Barite 

(bbl/sack) (ft 3 /sack) 

0.189 

0.168 

0.156 

0.144 

0.133 

1.060 

0.945 

0.873 

0.807 

0.748 

Table 12 - 4 Barite Slurry Weight / Volume Relationship (Barite Specific Gravity 

= 4.2) 

Follow these steps in mixing and placing a barite plug (see Table 12-4). 

1. Choose a slurry weight between 18 and 22 lb m /gal. 



REVISION 2006 12-35


2. Determine how many feet of barite plug in the open hole are desired. 

3. Calculate the bbl of slurry and sacks of barite required, and add an extra 10 bbl. 

4. Mix the slurry and pump it into the drillpipe. 

5. Displace the slurry so that the height of the barite plug in the drillpipe is 2 bbl 

higher than the top of the barite plug in the annulus. 

6. Break connections and pull up immediately above the plug. If possible, circulate on 

top of the plug. 

7. If possible, circulate for several hours. 

Barite settling is inherently slow and often the results are unpredictable. Failure rates for barite 

plugs increase when hydrostatic kill conditions are not maintained. 

Table 12-5 gives the materials and procedures necessary for mixing a barite plug for an oilbase 

fluid. 

Materials 

Diesel Oil 

CARBO-MUL ® 

OMNI-COTE ® 

MIL-BAR ® 

Quantities 

24.6 gal 

0.5 gal 

0.5 gal 

576 lb 

Table 12 - 5 Barite Plugs for Oil-Base Fluids (1 bbl of 18.0 lb m /gal Slurry) 

Procedure for Preparing Barite Plug for Oil-Base Fluid 

1. Clear all lines that will be used to pump the plug of water or water wet materials. 

This may require flushing the lines with diesel oil. 

2. To the appropriate amount of diesel oil, add the required CARBO-MUL ® HT and 

OMNI-COTE ® simultaneously and mix for 10 minutes. 

3. Mix the required MIL-BAR ® with the diesel/CARBO-MUL HT/ OMNI-COTE 

mixture and displace continuously into the hole with the pumping unit 

Note: 

Any base fluid may be substituted for the diesel oil, but the formulation 

must be adjusted to account for the base fluid density. 

Spot the diesel oil/barite plug in the same manner as a water-base plug. 

Barite Plug Example 

• Open hole = 8.5 in. 

• Height of barite plug desired = 500 ft 

• Weight of slurry desired = 18.0 lb m /gal 

⎛ 8.5 

2 

Volume of Barite Slurry = ⎟ ⎞ 

⎜ x 500 ft = 35 bbl 

⎝1029.4 

⎠ 



REVISION 2006 12-36


Total Volume = (35 bbl + 10 bbl) = 45 bbl 

• Materials to mix 45 bbl slurry 

Water = 26.9 × 45 = 1121 gal = 29 bbl 

SAPP = 0.5 × 29 = 14.5 lb 

Caustic Soda = as needed 

Barite = 5.3 × 45 = 239 sacks 

Total Slurry Volume = 239 × 0.189 = 45 bbl 

A non-settling barite plug using lignosulfonate as a thinner has been recommended by some. 

The materials required are listed below. One advantage of lignosulfonate is that it can be used 

in either fresh or sea water. It is recommended that the plug be non-settling and designed to 

provide a hydrostatic kill. The reasoning is that it is more reliable than a barite plug designed to 

settle. A settling plug can also be formulated if desired. 

Field Mixing Procedure for Barite Plugs (Nonsettling) 

(1 bbl of 21 lb m /gal Density) 

1. Prepare mix water equal to 54% of final volume. 

2. Mix, 

• Water (fresh or sea), 0.54 bbl 

• Lignosulfonate, 15 lb 

• Caustic Soda, 2 lb 

• XANPLEX D, 1 lb 

• Defoamer, if needed 

For settling pill, omit XANPLEX D Polymer 

3. Add barite to mix water to prepare the final slurry. 

A 21 lb m /gal slurry will require 700 lb of barite per finished bbl. 

Gas Kicks in Invert Emulsion Fluids 

Detection of gas kicks while drilling with an invert emulsion fluid is made more difficult 

because of the solubility of gas in oil. The amount of solubility is dependent on (1) 

composition of the formation gas, (2) composition of the oil used in the fluid, (3) pressure, and 

(4) temperature. Even a low volume influx that goes undetected will rapidly expand when it 

reaches the surface and cause unloading of fluid from the hole. This reduces bottomhole 

pressure, allows additional gas influx, and an uncontrolled situation (blowout) can develop. 

The key to well control in oil fluids is quick detection and proper shut-in procedures. 

The problem lies in that the normal surface responses to gas kicks in oil fluids are dampened 

because of the solubility of the gas in the oil. The rig crews must be aware of the differences in 

responses to gas kicks in oil fluids and be prepared to detect small changes in pit levels, flow 



REVISION 2006 12-37


rates, and flow checks. The behavior of each kick detection parameter and how it is affected by 

gas kicks in oil fluids are discussed separately. 

Pit Volumes 

When a fluid enters the wellbore, the addition of this volume is observed at the surface. 

Because instruments and techniques used to detect these increases have a limited amount of 

sensitivity, it may take 10 or more bbl of formation fluid to be noticed at the surface. With gas 

in water-base fluids, this happens fairly quickly after influx because the gas begins to migrate 

since it is insoluble. In oil-base fluids, the gas is soluble and, therefore, will mix in and migrate 

very little until almost to the surface. In oil-base fluids, it is important to be able to detect very 

small pit gains quickly. This may require some modifications of pit level measurement 

techniques. 

Flow Rate Increases 

Flow rate increases in oil-base fluids are much smaller than in water-base fluids for the same 

reasons as cited earlier. In some cases, they have been about one-half as much. These smaller 

changes may go undetected by the rig crew or “flow shows”. Special care needs to be taken 

when fluid additions are made to the active system to insure all volume changes are accounted 

for. 

Flow Checks 

Stopping the pumps and checking for flow shortly after taking a kick may not give a definite 

indication that a kick has occurred. Even in water-base fluids, gas migration and expansion will 

not be occurring immediately. A shutdown period as long as 10 minutes may be necessary 

before flow can be detected. 

Shut-In Pressures 

Due to the compressibility of the gas and oil in the fluid, it may take longer for pressures to 

stabilize. Normally, a 30- to 60-minute period is recommended after shutting the well in to 

allow pressures to stabilize in water-base fluids. In an oil fluid, this may take 1.5 to 2 times 

longer. 

In conclusion, the ability of the rig crew to adjust to the differences of gas kicks in oil fluids 

will determine how successfully the kick is controlled. The entire crew needs to be trained 

concerning these differences and how they are to be handled. 

Subsea Well Control 

Drilling from floaters and semi-submersible rigs has always provided challenges in well 

control situations, but drilling in water depths of 7000 ft and deeper has accentuated those 

problems. A brief discussion of the main well control problems that may occur in deep water 

drilling follows. 



REVISION 2006 12-38


Low Formation Fracture Gradients 

Fracture gradients decrease as the water depth increases. This is a function of the reduction in 

overburden pressure because the sediments are replaced by water. As a comparison, the 

calculated fracture gradient at 3000 ft on land in the Gulf Coast is 13.6 lb m /gal in normally 

pressured formations. At the same depth in 1000 ft of water the fracture gradient is 11.3 

lb m /gal. This lower fracture gradient requires more casing strings to be run offshore and closer 

attention to maximum allowable casing pressures. 

Shallow Gas 

The presence of shallow gas pockets in offshore sediments poses special problems to the 

drilling operations. As discussed earlier, seismic methods are being used to detect these zones. 

If shallow gas zones are detected in the area to be drilled, one method of dealing with the 

problem is to drill small diameter pilot holes into the sands. The sands are penetrated and the 

gas depleted from the zone through use of diverters at the surface. 

If the shallow gas is not detected, it is essential that proper methods of diverting the gas at the 

surface be available. Quick action is necessary to prevent the hole from being completely 

unloaded of fluid. Another method used to handle shallow gas is to divert the flow to the sea 

floor. Before this is done, careful analysis of the prevailing currents and winds in the area must 

be conducted. 

Kick Detection 

The movement of the rig and large volumes of fluid in the riser causes kick detection to be 

more difficult on floaters. It is important that the rig crew pay close attention to all abnormal 

pressure and kick indicators, regardless of how small the change. 

New developments in measurement-while-drilling (MWD) technology are aimed at detection 

of gas influxes on a real-time basis. Currently, the information obtained from MWD tools 

(resistivity and gamma ray data) lags behind the bit depth by the distance the tool is above the 

bit, usually about 30 ft. 

A technique has been developed which involves measuring the annular acoustic responses of 

the MWD tool. A pressure transducer is installed on the bell nipple and continually monitors 

the amplitude and character of the MWD pulses as they travel through the fluid. If gas from the 

formation enters the wellbore, the physical properties of the fluid are altered, thereby changing 

the way the acoustic signals travel through the fluid. If these changes can be measured and 

detected at the surface, this would mean earlier detection of gas influxes. 

Choke Line Friction 

The riser choke lines, manifolding, stack port, and expansion lines all exert a pressure loss on 

the well that varies according to choke line size and increases with water depth. The riser choke 

line pressure loss is found by comparing the pressure loss while circulating through the riser 

with the pressure loss while circulating through the kill line. The total back pressure on the 

annulus when circulating through the choke line equals the casing pressure gauge reading plus 

the choke line pressure loss. At the end of the kill procedure, additional pressure equal to the 

total choke line friction will be imposed against the annulus. In situations where fracture 



REVISION 2006 12-39


gradients are low, it may be necessary to take special precautions to avoid breaking down a 

formation. 

Riser Collapse / Displacement / Trapped Gas 

After formation gas has been circulated from the wellbore through the choke lines and the well 

is dead, a small volume of gas can be trapped in the sub-sea BOP between the choke line and 

uppermost closed BOP. If this trapped gas is not removed before opening the stack, its 

expansion can deplete the riser of fluid and cause another kick, collapse of the riser, or both. It 

is critical that before the BOPs are opened, (1) the riser has been displaced with kill fluid and 

(2) trapped gas has been removed from the BOP stack. A technique that has been proven 

successful is discussed by Shaunessy, et al. 

Gas Hydrates 

Gas hydrates are an ice-like mixture of natural gas and water. Their formation is a function of 

pressure and temperature. At low temperatures (30°F to 40°F), hydrate formation can occur at 

low pressures (40 to 400 psi). In the deepwater depths being drilled in the Gulf Coast, 

temperatures at the sea floor can be as low as 40°F. There have been several instances while 

killing kicks where the formation of gas hydrates has plugged choke lines and BOP stacks, 

making well control difficult or impossible. 

The suppression of hydrate formation can be accomplished by increasing the chloride 

concentration of the drilling fluid. Fluid systems with chlorides in the 150,000 mg/L (≈ 21% by 

wt.) range will suppress hydrate formation by 26°F. These fluid systems have been used to 

prevent the formation of gas hydrates. A discussion of the components of these systems can be 

found in Chapter 1, Fundamentals of Drilling Fluids. 

Other potential hydrate suppressors are methanol, glycol, and oil. Problems with the use of 

these additives relate to their toxicity levels and their use may be prohibitive because of 

handling and disposal requirements. Another option is to insulate and heat the subsea well 

control equipment but, at present, the technology to do this has not been developed. 

Commonly Used Equations in Pressure Control 

Hydrostatic Pressure (psi) 

Pressure Gradient (psi/ft) 

Hydrostatic Pressure = 0.052 x MW 1 x TVD 

Pressure Gradient = MW 1 x 0.052 

Pressure Expressed as Equivalent Fluid (Mud) Weight (EMW) 

EMW = 

0.052P s 

× TVD 

+ MW 1 



REVISION 2006 12-40


Fluid (Mud) Weight to Balance a Kick 

MW 2 = MW 1 + 

SIDP 

0.052 × TVD 

Determination of the Nature of Invading Fluids 

W 1 = MW 1 - 

SICP − SIDP 

0.052 × L 

Maximum Casing Pressure Resulting from a Gas Kick * 

P csg max = 200 

( 

2 

P )( V )( MW ) 

C 

Maximum Volume Increase while Circulating Out a Kick * 

V gain max = 4 

( P)( 

V )( C) 

MW 

2 

* Even with the solubility of gas in oil, these formulas will hold true in oil-base fluids. 

Formation Pressure or Bottomhole Pressure 

BHP = (MW 1 x 0.052 x TVD) + SIDP 

Maximum Initial Shut-In Casing Pressure which will Exceed Fracture 

Gradient 

SICP max = (F mw – MW 1 ) x 0.052 x TVD s 

MIL-BAR® Required to Weight up 1 bbl of Fluid ** 

Sacks of MIL-BAR to weight up 1 bbl of fluid = 

14.7 ( MW2 

− MW1 

) 

35.0 − MW 

2 

** Specific Gravity of Barite = 4.2 



REVISION 2006 12-41


NOMENCLATURE 

psi/ft 

Pressure gradient of a column of fluid 

units 

MW 1 Initial fluid (mud) weight or fluid (mud) weight in hole lb m /gal 

MW 2 Required or maximum anticipated fluid (mud) weight lb m /gal 

EMW 

P s 

F mw 

TVD 

TVD s 

ICP 

FCP 

SIDP 

SICP 

Equivalent fluid (mud) weight 

Surface pressure imposed on a fluid column 

Fracture point (pressure integrity) of a formation 

True vertical depth 

True vertical depth of casing shoe 

Initial circulating pressure 

Final circulating pressure 

Shut-in drillpipe pressure 

Shut-in casing pressure 

lb m /gal 

psi 

lb m /gal 

W 1 Density of fluids invading wellbore lb m /gal 

L 

P 

V 

Length of the column of invading fluids in the annulus 

Formation pressure in thousands of psi (Example: 8000 would be 

expressed as 8.0 in the equation) 

Pit gain 

feet 

feet 

psi 

psi 

psi 

psi 

feet 

psi 

bbl 



REVISION 2006 12-42


REFERENCES 

1. Baker Hughes DRILLING FLUIDS, Formation Pressure Evaluation, Reference 

Guide, Rev. B January 1996. 

2. Barker, J. W. and Gomez, R. K., Formation of Hydrates During Deepwater 

Drilling Operations, Journal of Petroleum Technology, March 1989, pp. 297-301. 

3. Bryant, T. S. and Grosso, D. S., Gas Influx Detection Using MAD Technology, 

IADC/SPE 19973, Presented at the 1990 IADC/SPE Drilling Conference, Houston, 

Texas. 

4. Dawson, Rapier and Morrison, Betty, Barite-plug Design for Better Well Control, 

Oil and Gas Journal, March 8, 1982, pp. 176-187. 

5. Eaton, Ben A., Fracture Gradient Prediction and Its Application in Oilfield 

Operations, SPE Journal, October 1969, p. 1353. 

6. Fertl, Walter H. and Timko, Donald J., Parameters for Identification of 

Overpressure Formations, Paper No. 3223, SPE of AIME, 1971. 

7. Goins, W. C. Jr., How to Prevent Blowouts, World Oil, October 1968. 

8. Goins, W. C., Jr. and O'Brien, T. B., Blowouts and Well Kicks: What you Need to 

Know About Them, Oil and Gas Journal, June 20, 27, July 4, and October. 5, 1962. 

9. Goins, W. C. Jr. and Sheffield, Riley, Blowout Prevention, 2nd Edition Gulf 

Publishing Company, 1983. 

10. Hornung, M. R., Kick Prevention, Detection, and Control: Planning and Training. 

Guidelines for Drilling High Pressure Gas Wells, SPE Paper 19990. 

11. Hottmann, C. E. and Johnson, R. K., Estimation of Formation Pressures from Log- 

Derived Shale Properties, Journal of Petroleum Technology, June 1965. 

12. Jorden, J. R. and Shirley, 0. J., Application of Drilling Performance Data to 

Overpressure Detection, Journal of Petroleum Technology, November 1966. 

13. Rehm, B., and McClendon, R.T., “Measurement of Formation Pressure From 

Drilling Data,” 46 th AIME Fall Meeting, New Orleans, October 1971. 

14. Matthews,W.R. and Kelly, John, How to Predict Formation Pressure and Fracture 

Gradient, Oil and Gas Journal, February 1967. 

15. Messenger, J. U., Barite Plugs, Presented at Spring Meeting of the Southwestern 

District Division of Production, API, Lubbock, Texas, March 1969. 

16. O'Brien, T.B., Handling Gas in an Oil Mud Takes Special Precautions, January 

1981, pp. 83-86. 



REVISION 2006 12-43


17. Rotary Drilling, University of Texas, Petroleum Extension Service, Home Study 

Series, Unit 3, Lesson 3, Blowout Prevention. 

18. Thomas, David C., Lea, Jr., James F., and Turek, E.A., Gas Solubility in Oil-Based 

Drilling Fluids: Effects on Kick Detection, Journal of Petroleum Technology, June 

1984, pp. 959-968. 

19. Safety Considerations for Offshore Rigs, Ocean Industry, June 1986, pp. 36-37. 

20. Shaughnessy, John M., Jackson, Curtis W., Warren, Ronald, Well Control 

Technique Removes Trapped Gas from a Subsea BOP, Oil and Gas Journal, 

December 2, 1985, pp. 55-60. 



REVISION 2006 12-44

Deepwater Drilling Fluids 

Chapter 

Thirteen 

Deepwater Drilling Fluids

Chapter 13 


INTRODUCTION .................................................................................................................................1 

DKD DRILLING ...................................................................................................................................2 

SELECTING DRILLING FLUIDS FOR DEEPWATER ..........................................................................3 

AQUEOUS VS NON-AQUEOUS DRILLING FLUIDS...............................................................................4 

AQUEOUS SYSTEMS AND ADDITIVES ...............................................................................................6 

NON-AQUEOUS SYSTEMS .................................................................................................................8 

LOST CIRCULATION.........................................................................................................................9 

INTRODUCTION...................................................................................................................................9 

WELLBORE BREATHING...................................................................................................................10 

HYDRATES ........................................................................................................................................11 

INTRODUCTION.................................................................................................................................11 

GAS HYDRATES ...............................................................................................................................11 

HYDRATE FORMATION & OCCURRENCE.....................................................................................12 

IN-SITU HYDRATES.....................................................................................................................13 

Associated Problems ................................................................................................................ 13 

Drilling.......................................................................................................................................... 13 

Cementing................................................................................................................................... 14 

HYDRATE FORMATION IN DRILLING FLUID...................................................................................... 14 

HYDRATES PREDICTION .................................................................................................................. 15 

HYDRATE FORMATION DURING WELL CONTROL INCIDENTS......................................................... 16 

HYDRATE INHIBITION ....................................................................................................................... 17 

Thermodynamic Inhibition ........................................................................................................ 17 

GAS HYDRATES IN THE BOP.......................................................................................................... 19 

Spotting Procedure.................................................................................................................... 19 

Procedure For Evacuating Gas From The BOP ................................................................... 19 

HYDRAULIC MODELING SOFTWARE........................................................................................ 20 

INTRODUCTION................................................................................................................................. 20 

TEMPERATURE MODELING.............................................................................................................. 20 

Presmod...................................................................................................................................... 20 

ADVANTAGE SM .............................................................................................................................. 23 

ADVANTAGE SM Engineering Hydraulics ............................................................................... 23 

ADVANTAGE SM HTHP Analysis.............................................................................................. 23 

HOLE CLEANING AND BARITE SAG ......................................................................................... 24 

INTRODUCTION.................................................................................................................................24 

HOLE CLEANING TOOLS & TECHNIQUES........................................................................................25 

BARITE SAG .....................................................................................................................................25 

ECD MANAGEMENT .......................................................................................................................25 

REFERENCES...................................................................................................................................26 



REVISION 2006 13-i



FIGURE 13 - 1 DKD EXAMPLE.....................................................................................................13-2 

FIGURE 13 - 2 GAS HYDRATE STRUCTURE I ............................................................................13-11 

FIGURE 13 - 3 BASIC UNIT OF GAS HYDRATE..........................................................................13-11 

FIGURE 13 - 4 GAS HYDRATES IN SEAWATER (PHASE DIAGRAM).........................................13-13 

FIGURE 13 - 5 IDEALIZED GAS HYDRATE PRESSURE/TEMPERATURE PLOT ..........................13-14 

FIGURE 13 - 6 TYPICAL BOP RISER ARRANGEMENT...............................................................13-16 

FIGURE 13 - 7 HYDRATE PHASE EQUILIBRIUM CONDITIONS ...................................................13-17 

FIGURE 13 - 8 GAS HYDRATE EQUILIBRIUM CHART ................................................................13-18 

FIGURE 13 - 9 TEMPERATURE AT START OF DRILLING............................................................13-20 

FIGURE 13 - 10 TEMPERATURE AT END OF DRILLING................................................................13-22 

FIGURE 13 - 11 TEMPERATURE AFTER 78 HOURS NON-CIRCULATING....................................13-22 

FIGURE 13 - 12 DEEPWATER WELL EXAMPLE............................................................................13-24 


TABLE 13 - 1 STRENGTHS AND WEAKNESS OF AQUEOUS AND NON-AQUEOUS FLUIDS...........13-4 

TABLE 13 - 2 INVESTIGATIVE SOLUTIONS TO THE WEAKNESS OF AQUEOUS AND NON-AQUEOUS 

SYSTEMS........................................................................................................................................5 

TABLE 13 - 3 PERFORMAX SYSTEM LIMITATIONS ....................................................................13-7 

TABLE 13 - 4 PERFORMAX SYSTEM PRODUCTS AND FUNCTIONS............................................13-8 


REVISION 2006 


13-ii

DEEPWATER DRILLING FLUIDS 

DEEPWATER DRILLING FLUIDS 

Chapter 13 

Deepwater drilling operations have grown to encompass large areas of the globe as oil companies 

search for and develop large hydrocarbon reserves. These are extremely high cost operations and offer 

considerable opportunities for drilling fluids to play a problem solving role. 

INTRODUCTION 

Deepwater drilling operations started as early as the 1960’s. Activity steadily grew throughout the 

70’s and by the late 80’s the activity, primarily in the Gulf of Mexico and Brazil, had stimulated the 

market to the point that both retro-fitting rigs and even some new-builds were commercially viable. 

Interest in deepwater continued to grow spurring worldwide activity in such areas as Trinidad, 

Australia, Indonesia, Malaysia, Brunei, the entire west coast of Africa, West of Shetlands, the far 

North Sea, Norway, Atlantic coast of Canada and Egypt. The area of greatest activity has traditionally 

been the Gulf of Mexico, though other areas have shown much promise for future growth. 

Deepwater drilling operations face many challenges, many of them fluids related. Identification of the 

challenges and integrating the applicable deepwater fluid system must be thought out carefully. 

Deepwater wells present unique technical and operational challenges for drilling fluid systems, 

including: 

• High daily operational costs 

• Lost circulation 

• Fluid selection and design 

• Solids transport 

• Wellbore stability, including low fracture gradients 

• Shallow hazards 

• Gas hydrates 

• Salt 

• Reservoir productivity 

• Environmental compliance 

• Large fluid volumes 

• Low seabed temperatures 

• Elevated bottom hole temperatures 

• Annular pressure build-up 

• Logistics 



REVISION 2006 13-1


Shallow water flows, or pressurized gas zones, can present difficult technical challenges deserving 

special focus in the planning and execution phases of deepwater projects. These shallow hazards can 

cause such events as lost circulation, hole erosion, poor cement jobs, foundation instability, gas 

hydrates, casing buckling and in the worst cases, hole abandonment. 

Shallow water flows can occur in zones 500 to 3,500 feet below the sea bed. Shallow gas sands are to 

be found at similar depths and require a sealing mechanism. Typically, wells are drilled riserless 

through these zones, using seawater and bentonite sweeps. Once a shallow hazard is detected there 

are two realistic alternatives: 1) spot a kill fluid and run casing or 2) drill ahead with a weighted fluid. 

Baker Hughes Drilling Fluids developed its Dynamic Kill Drilling (DKD) methodology to 

facilitate drilling ahead with a weighted fluid to facilitate a “push” of the casing setting depth. 

DKD DRILLING 

The development of DKD began in 1999 as a tool to address shallow hazards. Since its inception, 

continuous and concurrent improvements have been made to all facets of the process. There are 

essentially four areas, within the DKD process on which to focus: 1) pre-planning software, 2) 

equipment, 3) training and 4) field service. 

The DKD process employs a dual gradient concept, consisting of the seawater hydrostatic above the 

mud line and the ability to vary the hydrostatic below the mud line through drilling fluid density 

variations. 

MODU 

MODU 

4,500’ 

Water Depth 

8.55# Sea Water 

3,000’ 

OH 

11.00 x .052 x 7,500 

Total PSI 

4,290.00 PSI 

12.50 x .052 x 3,000 

2000.70 PSI 

4,290 - 2000.70 

2,290.70 PSI 

7,500’ 

11.00# Fluid 

2,290.70 /.052 / 3,000 = 

14.68 PPG 

Figure 13 - 1 

DKD Example 

The above figure illustrates the dual gradient principle. As can be seen, the hydrostatic pressure on 

bottom is a combination of the seawater and drilling fluid columns. 



REVISION 2006 13-2


The DKD process blends specially formulated 16.0 ppg drilling fluid with seawater or calcium 

chloride, or both components, to generate a fluid with a predetermined density and rheological 

properties. This procedure is executed using specialized proprietary equipment and techniques. 

Extensive pre-planning is required in order to determine the mud weight that will be used and the 

volume of fluid that is required. A rig survey is carried out to ensure that all the necessary 

components for a successful DKD process are present or identified for modification. Prior to 

execution of the job, the DKD unit, which consists of a shearing device and flow control equipment, 

is set up on-site. Once on the job, the unit has to be rigged up, and a diverse group of logistic issues 

must be immediately addressed in order for the procedure to be effective. 

A detailed description of the entire DKD Process can be found in the DKD Best Practices Manual. 

SELECTING DRILLING FLUIDS FOR DEEPWATER 

Drilling fluid selection for deepwater drilling operations can be an extremely complex matter due to 

the many different considerations, including fluid compressibility/expansion as a function of wellbore 

temperatures, hydrate suppression, possible evaporate sequences, well path, environmental 

restrictions and perhaps most importantly, well costs. Deepwater technical challenges also include 

shale reactivity, formation damage and drilling and completing in unconsolidated sands. 

Environmental and safety issues are, as always, of paramount importance. Often, the most practical 

result of the fluid selection process is compromise. 

In deepwater drilling, the use of a fluid that delivers all the well-specific performance issues is 

essential. Inhibitive fluids with low dilution and consumption rates are of considerable benefit in 

minimizing rig logistics, cost and maximizing fluid performance. Typical riser volumes may range 

from 1,000 to 3,000 bbl (160 to 500m 3 ) and circulating volumes from 2,500 to 5,000 bbl (400 to 800 

m 3 ), depending on water depth, hole size and total depth of the well. As demonstrated by this 

example, large fluid volumes are normally associated with deepwater wells. This is the result of 

multiple casing string requirements and/or production requirements. Fluid volume needed to fill the 

riser and pits should not be confused with dilution volume. Fluid dilution requirements are the direct 

result of hole size (cuttings generated), Solids Removal Efficiency (SRE - cuttings removed) and the 

desired drilled solids content of the fluid. The fluid type can enhance SRE and certain fluid types can 

incorporate higher solids content without significantly degrading the fluid’s performance. 

Nevertheless solids removal equipment deserves a great deal of focus in the planning and execution 

of deepwater projects. 

Solids removal efficiency is the vital factor in the control of low gravity solids (LGS) and minimizing 

dilution volume and associated costs. Optimum solids control equipment would include four linear 

motion shale shakers, ideally preceded by four scalping shakers. The deployment and use of 

centrifuges should be considered in association with the mud weight, type of fluid system and 

discharge requirements. A water base system may require one or more barite recovery centrifuges. A 

synthetic invert emulsion may have an external phase that has more economical value than other fluid 

components and therefore be most important to recover. Discharge of cuttings may require a host of 

equipment, including a dryer and centrifuge for LGS and oil separation. Each project should be 

evaluated on its economic merits. Whenever possible it is desirable to utilize a drilling fluid which is 

environmentally acceptable for cuttings discharge and exhibits the required fluid characteristics. 



REVISION 2006 13-3


AQUEOUS VS NON-AQUEOUS DRILLING FLUIDS 

The first fluids decision to make for a deepwater operation is whether the fluid is to be aqueous or 

non-aqueous. Both types of fluids have been used with a great deal of success in deepwater 

operations. 

Table 13 - 1 

Strengths and Weakness of Aqueous and Non-Aqueous Fluids 

Non-Aqueous Strength / Aqueous Weakness 

Aqueous Strength / Non-Aqueous Weakness 

ROP 

Wellbore stability 

Gas hydrate suppression 

Cuttings integrity => hole cleaning 

BHA – bit balling 

Trip frequency 

Temperature stability 

Lost circulation 

Environmental characteristics 

Ballooning 

Reservoir characterization 

Gas solubility / kick detection 

Cost/bbl 

Infrastructure requirements 

The above table compares some of the weaknesses and strengths of aqueous and non-aqueous fluids. 

Each well must be looked at individually and the above components weighed to decide whether or not 

to use an aqueous fluid, e.g. if kick detection is of vital importance then an aqueous fluid is best as 

gas is not soluble in water and so gas kicks are more easily detected. During the decision phase one 

should also look at the weaknesses and their possible solutions. 



REVISION 2006 13-4


Table 13 - 2 

Investigative Solutions to the Weakness of Aqueous and Non- 

Aqueous Systems 

Aqueous 

Non-Aqueous 

Weakness Solution Weakness Solution 

ROP 

BHA / bit balling 

Bit hydraulics 

Bit selection 

Additives 

Proven deepwater 

systems 

Lost circulation 

Permanent seal 

High Fluid Loss 

LCM’s 

Cross link polymer 

Wellbore stability 

Inhibitive systems 


systems 

Environmental 

Synthetic products 

Cuttings drying 

Skip & ship 

Cuttings integrity => 

hole cleaning 

Maximized hydraulics 

Riser booster 

Ballooning 

Hydraulics software 

Pressure tool 

Gas hydrate 

suppression 

Ethylene glycol 

Spotting procedures 

Salt 

Reservoir 

characterization 

“Tag” fluid 

Trip frequency 

Additives to enhance 

PDC bit performance 

Gas solubility 

Kick detection 

procedures 


systems 

Knowledge of area 

Temperature 

stability 

Geothermal 

technology 

Cost/bbl 

Economic modeling 

Overall well cost 

Infrastructure 

requirements 

Economic modeling 

Risk Analysis 

As the industry has moved from drilling in 1,000’ of water depth to greater than 10,000’ of water 

depth, Baker Hughes Drilling Fluids has developed new systems and processes to meet the increasing 

challenges. Solutions developed include advanced systems and specialized fluid additives, new 

laboratory and field instrumentation, and a complete rigsite management program. 

Changes in environmental regulations, coupled with more demanding well profiles, led to the 

widespread development of “Pseudo-Oil” muds. An understanding of kinematic viscosities and 

temperature effects on rheological properties led Baker Hughes Drilling Fluids to introduce a 

Synthetic Fluid, with an Isomerized Olefin (20) base, in 1994. This was the first deployment of an 

IO, which subsequently became the industry standard in the Gulf of Mexico. 



REVISION 2006 13-5


AQUEOUS SYSTEMS AND ADDITIVES 

Baker Hughes Drilling Fluids is constantly striving to develop water based fluids capable of 

replacing invert emulsion fluids for application on deep water drilling operations. Recent 

developments include a calcium chloride based system, CLAY-TROL®, a clay inhibitor additive 

and PERFORMAX, a new high performance water based drilling fluid. Additionally, Baker 

Hughes Drilling Fluids is the leader in glycol technology, being the first to introduce a deepwater 

system in 1991 - AQUA-DRILL - based on cloud-point glycol technology. A short discussion on 

various aqueous systems and products which have proven suitable for deepwater operations 

follows. Further information on these products and systems is available elsewhere in this manual. 

AQUA-DRILL is a cloud-point glycol system which slows or prevents pore pressure transmission 

in its clouded state and enhances cuttings integrity while in solution. These characteristics are known 

to benefit wellbore stability and enhance SRE, major assets of a non-aqueous fluid. The ability to run 

salt - NaCl or KCl - in this system addresses both added inhibition and gas hydrate suppression needs. 

PERFORMAX is Baker Hughes Drilling Fluids new 3 rd generation high-performance water-base 

drilling fluid that is designed to emulate performance characteristics previously achieved only with 

emulsion based drilling fluids. These attributes include shale inhibition (reduced pore pressure 

transmission), cuttings integrity, high rates-of-penetration, and reduced torque and drag. Two features 

of PERFORMAX that contribute to wellbore stability are: ultra-fine, deformable sealing polymer 

particles in MAX-SHIELD (diameter: ~ 0.2 µm) mechanically seal shale micro-fractures, which 

physically block further intrusion of drilling fluid filtrate into the shale matrix; the resin and 

aluminum complexes in MAX-PLEX, in combination with MAX-SHIELD, can produce a 

semi-permeable membrane at the shale surface and chemically improve the osmotic efficiency, and 

reduce pressure transmission into shales. Pore pressure transmission tests clearly show that MAX- 

SHIELD effectively works in combination with MAX-PLEX to achieve pore pressure 

transmission characteristics previously achieved only with emulsion-based drilling fluids (oil-based 

or synthetic-based). 



REVISION 2006 13-6


PERFORMAX System Limits 

Density 

Tested to a maximum density of 16 lbm/gal (1.92 sg) 

Temperature Tested to a maximum temperature of 300°F (149° C) 

Salinity 

PERFORMAX fluids are compatible with sodium chloride 

concentrations up to saturation or potassium chloride up to 10% by 

weight. Sodium and Potassium Formate salts are also compatible. 

Table 13 - 3 

PERFORMAX System Limitations 

PERFORMAX System Products and Function 

PRODUCT 

MAX-SHIELD 

Salinity 

MAX-PLEX 

FUNCTION 

Sealing polymer utilized to generate semi-permeable membrane for 

shale stabilization. Secondary function is as bridging material in pore 

throats of depleted sands to eliminate differential sticking and lost 

circulation. 

Enhance clay inhibition and general osmotic pressure. 

Aluminum and resin complex that works in combination with MAX- 

SHIELD to generate semi-permeable membrane and improve well 

stability. 



REVISION 2006 13-7


NEW-DRILL® 

Cuttings encapsulation and improved cuttings integrity 

Table 13 - 4 PERFORMAX System Products and Functions 

Salt/polymer fluids have been used since the outset for deepwater applications. Baker Hughes 

Drilling Fluids dominated the Gulf of Mexico (GoM) deepwater market for many years with a 20% 

NaCl/PHPA system. These systems were traditionally utilized in the North Sea and Gulf of Mexico. 

The North Sea utilized a KCL component for added inhibition while the GoM, was restrained from 

using KCL due to environmental discharge regulations. Inherent to both systems was a level of gas 

hydrate suppression due to an elevated salt content. Glycols may be added to these systems to further 

improve hydrate suppression. 

Silicate drilling fluid systems have a long history in the oilfield, first being introduced in the 1930’s 

and known as “protective silicate muds”. After some success at drilling heaving shales, they were 

abandoned due to problems of achieving stable rheological properties in conjunction with the 

introduction of natural organic dispersants. They were reintroduced in the 90’s and again were 

mostly discontinued due to their tendency of polymerizing to form a silica gel, unacceptable lubricity 

and accretion. Silicates may have specialty applications in certain deepwater applications, for 

example to strengthen weak top hole formations such as oozes. 

PENETREX® is a Rate-of-Penetration (ROP) enhancer and bit-balling prevention additive. It was 

introduced in 1997 to address ROP issues associated with water base mud and PDC bit applications. 

Outstanding results were obtained in a DEA-90 study performed on a full scale drilling simulator. 

The same results have been realized as PENETREX ® has been applied in field operations. 

CLAY-TROL® was introduced in 1999 as a shale stabilizer to address hydration tendencies of 

young shale in the Gulf of Mexico. CLAY-TROL® has proven to be an excellent stabilizer and its 

amphoteric chemistry makes it a versatile product. It has been used successfully in several deepwater 

projects. 

MAX-GUARD is the primary class hydration and swelling suppressant of the PERFORMAX 

system. Clay and gumbo inhibition is achieved by limiting water adsorption and providing improved 

cuttings integrity. MAX-GUARD effectively inhibits reactive clays and gumbo from hydrating and 

becoming plastic, which provides a secondary benefit of reducing the tendency for bit balling. MAX- 

GUARD can be readily added to the mud system without effecting viscosity or filtration properties. 

NON-AQUEOUS SYSTEMS 

Non-aqueous fluids are the fluids of choice for many operators for deepwater wells. As discussed 

previously, this brings with it a great deal of challenge. In order to meet these challenges Baker 

Hughes Drilling Fluids has developed a variety of non-aqueous fluids for deepwater operations. 

The SYN-TEQ® system was developed in response to environmental restrictions on the discharges 

associated with mineral oil based systems. SYN-TEQ® was developed using a low-viscosity, nontoxic, 

biodegradable, isomerized olefin- ISO-TEQ®- as the base fluid. Since then a variety of base 

fluids have been used in SYN-TEQ® formulations, including: 

• Linear alpha olefin, ALPHA-TEQ 

• Linear paraffin, PARA-TEQ 



REVISION 2006 13-8


• CF-2002, a base fluid designed to conform to the Gulf of Mexico discharge regulations that 

came into effect in 2002 

• PT-3500, an iso-alkane paraffin 

SYN-TEQ® is an alternative to oil-based mud drilling fluids and is environmentally acceptable in 

many parts of the world. High lubricity, high resistance to contaminants such as carbon dioxide, 

and an ability to maintain a stable wellbore with no sloughing shales are key system attributes. The 

system is stable over a wide temperature range; 30°F–500°F (-1°C–260°C) and can be formulated 

with low synthetic-to-water ratios. Where oil-based mud performance is desired but environmental 

restrictions prevent its use, SYN-TEQ® is a viable alternative. Long-reach and highly deviated 

wells benefit from the system’s high lubricity, effective in reducing torque and drag. A low leak-off, 

removable filter cake makes SYN-TEQ® an ideal fluid for coring operations and in poorly 

producing formations that cannot tolerate significant invasion damage. 

NEXES is a "new generation" ester-based emulsion system. It is formulated to meet client 

expectations by providing superior drilling performance, and benchmark environmental 

compliance. The continuous phase, NX-3500, is a unique ester molecule specifically designed to 

address technical concerns that have long plagued other ester base fluids, namely (1) kinematic 

viscosity, (2) hydrolysis stability, and (3) elastomer compatibility. In addition to the base fluid, 

NEXES employs other components chosen for their optimized performance. NX-3500 is not a 

GoM compliant base fluid. 

CARBO-DRILL® is Baker Hughes Drilling Fluids’ invert emulsion system in which the external 

phase is either diesel, mineral or enhanced mineral oil. This fluid has been used on several 

deepwater wells using low aromatic mineral oils as the base fluid. The system delivers optimized 

drilling performance, including excellent penetration rates, enhanced lubricity and superior 

wellbore stability. Discharge of cuttings generated using CARBO-DRILL® may be regulated by 

local environmental agencies. 

LOST CIRCULATION 

INTRODUCTION 

Lost circulation problems in deepwater are aggravated by low fracture gradients, tight casing/hole 

clearances, and drilling fluids made more dense and more viscous by low fluid temperatures. Lost 

circulation can be more dangerous in deepwater than in shallower water due to the potential for 

hydrate formation in the BOP from migrating gas. The risk of lost circulation can be reduced by the 

use of hydraulic simulators such as those in ADVANTAGE and PRESMOD. These tools can be used 

to establish guidelines for drilling and tripping. 

Experience has shown that lost circulation is a greater problem with invert emulsion fluids than with 

water based fluids. The reasons are numerous and are stated below: 

• Though water base and invert emulsion drilling fluids have similar fracture initiation 

pressures, invert emulsion systems have lower fracture propagation pressures. This means 

that once losses are initiated they are more difficult to cure with an invert emulsion system. 

• Invert emulsion systems’ densities and viscosities are increased to a greater degree by the 

colder temperatures at the seabed. These increases intensify surge pressures and can cause 

lost circulation. 

• Invert emulsion systems are normally considerably more expensive in cost per barrel than 

water based fluids. Thus lost circulation is considerably more expensive and more noticeable. 



REVISION 2006 13-9


• Logistics are normally more complex for invert emulsion fluids than for water based fluids. 

For invert emulsion the base fluid has to be transported by boat to the rig, often over 

considerable distances, whereas seawater can often be used as the base fluid in water based 

systems. 

Successful management of lost circulation in deepwater operations should include identification of 

possible loss zones, optimization of drilling hydraulics, and a well thought out contingency plan for 

the handling of possible lost circulation. 

Loss of circulation in a production zone offers additional challenges. Normally, only acid soluble 

materials should be added while the production zone is exposed. An engineering program is available 

to take much of the guess work out of this process. Bridgewise is the new bridging technology 

designed by Baker Hughes Drilling Fluids to maximize hydrocarbon recovery from reservoirs. 

Bridgewise calculates the optimum blend of available calcium carbonate additives required to 

effectively bridge reservoir pore openings of known size. The Bridgewise calculator is available 

on BakerHughesDirect/DRILLING FLUIDS/Toolbox/OnLine Tools and Resources. 

WELLBORE BREATHING 

Wellbore breathing refers to the situation where losses are experienced while drilling ahead and then 

fluid volume recovered when the pumps are turned off. This is often a problem in deepwater 

operations where the difference in fracture gradient and pore pressure in any given hole section may 

be relatively small. The magnitude of the losses and gains can vary from 25 to 250 barrels. 

These loss and gain situations are caused by near-wellbore radial tensile and circumferential tensile 

failures. Fractures are initiated when the ECD exceeds the fracture initiation pressure. These fractures 

open and accept fluid. When the pumps are shut down, the fluid in the fractures returns to the 

wellbore. Typically, fluid is steadily lost during circulation/drilling and is regained when flow is 

static/during connections. Thermal stresses can also induce losses and gains in some cases. 

Since loss and gain problems result from the initiation of fractures that do not continue to propagate, 

mitigation steps will be the same as for lost circulation in general. It is recommended to pre-treat the 

system with LCM if this sort of problem is expected. LC-LUBE is an ideal material for this 

application as it is an effective LCM while neither detrimentally effecting viscosity nor filtration 

control. It exhibits excellent sealing and bridging properties due to the deformable nature of the 

material when particles are packed together under compression. It is able to effectively strengthen 

fractured and porous formations by plugging fracture/pore throats and prevention of fracture 

propagation and pore pressure penetration.DEA studies showed calcium carbonate to be an effective 

lost circulation material. LC-LUBE and calcium carbonate, together with CHEK-LOSS FINE, or 

CHEK-LOSS PLUS are the recommended materials for pre-treatment of the drilling fluid. The 

recommended concentrations are 5 – 10 ppb LC-LUBE, 10 – 15 ppb calcium carbonate and 5 ppb 

CHEK-LOSS FINE, giving a total LCM concentration of 20 – 25 ppb. 



REVISION 2006 13-10


HYDRATES 

INTRODUCTION 

Gas hydrates are crystalline solids formed by low molecular weight hydrocarbon gas molecules 

combined with water. The interaction between the water and the gas is physical in nature and is not a 

chemical bond. They are formed and remain stable over a limited range of temperatures and pressures 

and exist in a number of structure types depending upon the gas composition. 

Gas hydrate concerns cover two distinctly different situations, i.e. naturally occurring gas hydrates 

and the formation of gas hydrates in drilling fluids. The formation of hydrates in drilling fluids during 

a shut-in is the most likely hydrate-associated hazard in deepwater drilling. 

GAS HYDRATES 

A number of unusual problems encountered during drilling for hydrocarbons in deep, cold marine 

environments have been attributed to gas hydrates. Gas hydrates are small molecules formed when 

water and the components of natural gas combine thermodynamically to form crystalline, clathrate 

compounds. A total of seven different structures have been postulated. However, to date only three 

different structures have been seen (Structure I, Structure II, Structure H) when hydrocarbons combine. 

The basic unit of each structure is the pentagonal dodecahedron. 

Figure 13 - 2 

Gas Hydrate 

Structure I 

Figure 13 - 3 

Basic Unit of 

Gas Hydrate 

Clathrates are complexes formed between two chemicals in which one type of molecule completely 

encloses the other molecule in a crystal lattice. In the case of gas hydrates, hydrogen bonded water 

molecules form a cage-like structure that surrounds gas molecules, forming a solid substance with a 

high gas density. Agglomeration of these structures can form naturally occurring accumulations or 

blockages in lines and valves in drilling equipment. 



REVISION 2006 13-11


Dodecahedron 

Gas hydrates are crystalline structures consisting of hydrogen 

bonded water lattices providing a cage like structure that host 

molecules of natural gas. These gas molecules are trapped in 

the middle of the cage with their repulsive energy stabilizing 

the strong hydrogen bonds of the water lattice. Common 

hydrate structures may contain eight to twenty-four cavities, 

with each cavity having a single molecule of gas. The final 

composition of the gas hydrates being approximately 15 % 

gas and 85 % water. Gas Hydrates are described as gas 

concentrators with the breakdown of a unit volume of 

methane hydrate at a pressure of one atmosphere producing about 160 unit volumes of gas. 

HYDRATE FORMATION & OCCURRENCE 

Hydrates are found naturally in the sediments in deep cold marine environments. They may also be 

incorporated into the formation. 

Gas hydrates are formed by anaerobic bacteria digesting organic matter (detritus) under the ocean 

floor. During the digestion process mainly 

Gas Hydrates Offshore Sakhalin Island methane is produced along with small 

amounts of carbon dioxide, hydrogen 

sulfide, propane, and ethane. The produced 

gases rise, dissolving in the water between 

the ocean sediments. 

When the temperature, and pressure 

conditions at the ocean bottom are 

appropriate (high pressure and low 

temperature) hydrates are formed. In 

addition to the formation of hydrates, vast 

reservoirs of methane gas often form 

beneath hydrate layers. Methane hydrate is 

stable in ocean floor sediments at water 

depths greater than 1000 ft (300 m), and 

where it occurs, it is known to cement 

loose sediments in a surface layer several 

hundred meters thick. 

When hydrates are incorporated into the 

formation they have to be maintained during the drilling operation to avoid the collapse of the 

surrounding seabed. 



REVISION 2006 13-12


Figure 13 - 4 

Gas Hydrates in Seawater 

(Phase Diagram) 

Depth (km) 

0 

0.3 

1 

2 

3 

4 

Methane Hydrate & 

Sea Water - Stable 

Methane Gas 

& Sea W ater 

- Stable 

0 10 20 30 

Temperature °C 

Gas Hydrate Stability Curve 

To the left is a curve representing the stability 

of gas hydrates in sea water. Pressure and 

temperature are two of the major factors 

controlling where the hydrate (solid) or 

methane gas will be stable. Whether or not gas 

hydrate actually forms depends on the amount 

of gas available. 

IN-SITU HYDRATES 

In-situ hydrates can exist at various depths below the seabed and may be encountered while drilling in 

deepwater virtually anywhere in the world where there are sufficiently high pressures to favor hydrate 

formation. Gas may exist below the in-situ hydrates. 

Associated Problems 

1. Maintaining competency of in-situ hydrates while drilling and cementing 

2. Maintaining static well conditions while drilling and cementing in gas/water 

3. Obtaining a competent cement job in a gas environment 

Problem Resolution: It may be possible to drill the in-situ hydrate section without incurring hydrate 

dissociation. Dissociation of the hydrates will lead to an enlarged hole section which will negatively 

impact both the cement bond/hydraulic seal and lateral casing support. To maintain the in-situ 

hydrates in a competent state, special attention needs to be paid to the annular temperature during 

drilling, cementing and cement transitional period. 

Drilling 

• Simulations can be performed to predict fluid circulating temperatures inside the drill pipe 

and in the annulus. 

• If annular temperature does not exceed the hydrate equilibrium temperature, nothing more is 

necessary. 

• If annular temperature exceeds the hydrate equilibrium temperature, several options should 

be explored: 

• Increasing the mud weight, thus pressure in the annulus, if fracture pressure will allow 

• Utilize lecithin to retard the rate of dissociation 

• Reduce the target depth of the surface casing, so as to reduce the annular temperature 



REVISION 2006 13-13


Cementing 

• Cementing across in-situ hydrates offers a challenge not yet solved by the industry (i.e., API): 

• Cement has an exothermic reaction during transition. 

• Hydrates are endothermic during dissociation 

• Dissociation of in-situ hydrates by cement can lead to a gas filled void behind casing and 

negatively impact the cement bond. 

• Foam cement should be used due to: 

• The accelerated right-angle set and reduced transition time. 

• Lower exothermic temperature when setting over conventional cement 

• Past success in shallow gas environments 

• The foam cement should be specifically designed to meet these well criteria. All foam 

cements are not created equally (stability, quality control, insulating maximization, and 

stiffness). 

• Cement should be designed to expand. 

• Weight of cement should be maximized for hydrate stability. 

Weighted mud should be employed to drill the hole section below structure pipe. 

• The increase in annular pressure will be advantageous to the stability of the in-situ hydrates 

• Free gas, below the in-situ hydrates, will need to be controlled. 

• A Dynamic Kill Drilling device should be utilized to supply weighted fluid 

HYDRATE FORMATION IN DRILLING FLUID 

Hydrate formation in drilling fluids is a relative new experience off shore. Temperature, pressure and 

gas composition determines the conditions for hydrate formation. Solidification occurs as the 

temperature decreases and/or the pressure increases. 

Figure 13 - 5 

Idealized Gas Hydrate Pressure/Temperature Plot 

Pressure (psi) ----> 

Catastrophic 

Nucleation 

C o o lin g 

C yc le 

H eating C ycle 

Point of 

Dissociation 

Tem perature (F) ----> 

As the temperature of the fluid decreases and/or pressure is increased, seed crystals or hydrate nuclei 

are formed. At a critical pressure / temperature / gas combination, catastrophic nucleation and 

encapsulation of gas into the hydrate structure occurs. At elevated pressures and low temperatures in 

deep water drilling ( > 500m and below 10°C) hydrate formation is promoted. This process is 



REVISION 2006 13-14


represented diagrammatically in the figure above. Presuming there are no other “helper” gases to 

promote hydrate formation, then the lower molecular weight of the hydrocarbon, the greater the 

resistance to hydrate formation. Thus the hydrate formation is decreased in the following order: 

Methane < Ethane < Propane < Isobutane 

The cold sections of the well that are exposed to the sea such as the riser, choke & kill lines and the 

BOP are the most probable location for the hydrates formation. When the drilling fluid is being 

circulated, the combination of heat generated from the actual circulating and the geothermal heat will 

maintain the temperature of the fluid in the riser above the critical temperature at which hydrates are 

formed. However when there are circulation breaks for tripping or logging, the drilling fluid must 

have the hydrate inhibitive capacity to keep the fluid in the cold areas of the well hydrate free. 

Invert emulsion drilling fluids, which are very commonly used on deepwater drilling operations, are 

extremely effective hydrate inhibitors. They are not hydrate preventers, as hydrates may be formed 

given the right pressure-temperature-water content-calcium chloride concentration combination. 

HYDRATES PREDICTION 

The WHyP (Westport Hydrate Prediction) program used by Baker Hughes Drilling Fluids is a 

thermodynamic hydrate equilibrium prediction program that is based upon the statistical 

thermodynamic theory of van der Waals and Platteeuw. It also incorporates the hydrate temperature 

suppression methods developed using the Young-Yousif model. 

The WHyP program has a wide array of input choices and modes that can be used. The design mode 

is a unique feature that calculates the appropriate amount of inhibitor to suppress hydrates at a given 

temperature and pressure. The prediction mode allows the user to enter a fluid composition and the 

program will generate the hydrate equilibrium line for that particular fluid. Characterizing this fluid 

composition can be completed in a number of ways; by weight percentage, by filtrate density and 

resistivity, and measured water activity. The program will predict hydrate equilibrium curves up to 

10,000 psi. 

The WHyP program was designed by, and for, drilling fluids personnel and caters towards deepwater 

applications. Fluids with up to three different types of inhibitors may be entered as inputs. The 

program also has a wide array of inhibitor selections, such as NaCl, KCl, CaCl 2 , Sodium and 

Potassium Formates, Methanol, and several types of glycols. The program defaults to using Green 

Canyon Gas, but also allows the user to enter a known gas composition. 

Although based upon statistical models, the WHyP program is supported by over 150 temperature 

suppression points that were measured experimentally on various mixed salts and glycols solutions. 

This large supporting database allows WHyP to be accurate as well as flexible to the needs of the 

drilling fluids personnel. The WHyP program is accurate to within 2K psi when using the weight 

percentage method, or 4K psi by using the filtrate or water activity methods. 

Baker Hughes Baker Hughes Drilling Fluids has been using WHyP to assist with the design of 

hydrate inhibiting fluids since 1997 . The program’s mixed salt/glycol capability differentiate it from 

other hydrate prediction programs. 



REVISION 2006 13-15


HYDRATE FORMATION DURING WELL CONTROL INCIDENTS 

Hydrate formation may be accelerated during the drilling operations as a result of gas influx (kick). 

A critical situation, in respect to gas hydrate formation, may arise during well control incidents when 

the well is shut in. 

A typical kick is detected at 10 bbl of pit gain. By the time the well is shut-in, the kick volume could 

reach 50-60 bbl. Depending on the hole and drill pipe size, the kick could reach a height of 1500 – 

2000 ft. (457 - 610m.) Although the kick fluid leaves the formation at a high temperature, with an 

extended shut-in period it can cool to sea bed temperature. With high enough mud hydrostatic 

pressure at the mudline, hydrates could form in the BOP stack, choke and kill lines. 

Two procedures are used by the industry to shut-in wells during a gas kick: the soft shut-in and the 

hard shut-in procedures. In the soft shut-in, the hydraulically operated choke line valve is opened, the 

annular BOP is closed, and finally the adjustable choke is slowly closed. This procedure is applied 

with the intention of reducing shock loads on the casing shoe. 

Figure 13 - 6 

Typical BOP Riser 

Arrangement 

The hard shut-in procedure 

requires opening the hydraulically 

operated choke line valve and 

then closing the ram, with the 

adjustable choke remaining closed 

at all time. This procedure takes 

considerably less time and thus 

allows less influx into the well, 

reducing wellbore pressures 

during killing operations. 

However, because of the concern 

over possible shock loads, the soft 

shut-in method has historically 

been preferred by the operators. 

To achieve successful kick 

containment, the Blowout 

Preventor (BOP) must operate 

properly and the choke and kill 

lines must remain clear for 

circulation. Consequently, and as 

a safety precaution, the drilling 

fluid must have good hydrate 

inhibition properties. 

The risers on deep water drilling 

rigs are partially insulated with 

the floatation material attached to 

them. The BOP and choke and 

kill lines are normally exposed to sea water. Insulation will help reduce the rate of heat transfer 

during lengthy shut-in periods. In very deep water situations insulation may not provide adequate 

protection even after long circulation periods. 



REVISION 2006 13-16


HYDRATE INHIBITION 

Historically, most of the work on gas hydrate inhibition has been aimed at the prevention of hydrate 

formation during the production and transportation phase of hydrocarbons. 

Listed below are the three inhibitive mechanisms utilized: 

• Thermodynamic inhibition 

• Kinetic inhibition 

• Prevention of hydrate agglomeration 

Traditionally, hydrate suppression has been accomplished by a thermodynamic approach. High 

concentrations of hydrate inhibitors such as salts, glycols or alcohols were added to the flow line. A 

more modern approach is the use of low concentration inhibitors that time-delay or minimize the 

amount of hydrate crystals formed (kinetic approach). The third approach, anti-aggregation, does not 

stop the formation of hydrates but prevents the hydrates from agglomerating into large crystalline 

masses or plugs. This effectively prevents a dramatic increase in the transported fluid’s viscosity. 

It should be noted that many of the solutions employed in mitigating gas hydrate issues in 

downstream operations are not applicable to drilling applications due to environmental constraints. 

Thermodynamic Inhibition 

In drilling fluids the principal method for hydrate inhibition is thermodynamic. As stated in the 

previous section thermodynamic hydrate inhibition is extensively used in petroleum production. 

These inhibitors which are added to the drilling fluid lower the chemical potential of the aqueous 

phase. The hydrate equilibrium pressures and temperatures are measured for distilled water. When 

the water is treated with the thermodynamic inhibitor, the phase boundaries are shifted to the left and 

upward. Thus the inhibitor effectively reduces the temperature and increases the pressure at which 

the hydrates are formed. The most common thermodynamic hydrate inhibitors are glycols, salts and 

glycerol. 

A typical phase equilibrium plot is given in the following figure. 

Figure 13 - 7 

Hydrate Phase Equilibrium Conditions 

10000 

With 

Inhibitor 

1000 

Pure 

Water 

100 

30 40 50 60 70 80 90 

TEMPERATURE (°F) 

• On a weight to weight basis, the hydrate suppression effectiveness (ΔT) of differing salts can 

be expressed in the following order: 

NaCl > KCl> CaCl 2 > NaBr>Na Formate> Calcium Nitrate 



REVISION 2006 13-17


• The ability to form hydrates in SBM is related to the gas type, with higher salinities required 

for heavier gases. 

Fluids that provide additional gas hydrate suppression and fluids that can be formulated at lower 

densities than traditional deep water fluids is the focus of ongoing work at Baker Hughes Drilling 

Fluids. These fluids utilize low molecular weight organic compounds for enhanced gas hydrate 

inhibition. NF3 (No Freeze, No Frac, No Formation Instability) is the sequel to Baker Hughes 

Drilling Fluids’ first product of this type, referred to as NF2 ® (No Freeze, No Frac). NF3 has a 

lower specific gravity than NF2® and has the additional function of benefiting borehole stability 

as well as providing gas hydrate inhibition. NF3 can be added to standard deep water, water 

based drilling fluids at concentrations from 5% to 40% by volume depending on the degree of gas 

hydrate and shale inhibition desired. The ability to use NF3 at these various concentrations will 

allow flexibility between the required density, amount of shale inhibition, and the amount of gas 

hydrate inhibition desired. 

NF2 ® , a low molecular weight, environmentally friendly glycol, is ideal for deepwater applications 

where high gas hydrate suppression and low fluid density (due to low fracture gradients) is 

required. NF2 ® is compatible in both fresh and salt water (up to and including saturated brines) 

drilling fluids. NF2 ® is particularly useful in formulating pills for choke and kill lines whenever 

favorable conditions exist for the formation of gas hydrates. 

These products have been successfully incorporated into inhibitive water based fluid systems in the 

Gulf of Mexico and elsewhere. A major operator in the GoM utilized the unique characteristics of 

these products in their world record setting water depth well of 7,800 ft. (2377 m.) with great 

success. A 9.3 ppg (1.12 sg) fluid was built using salt and 10% NF3 yielding a fluid capable of 

suppressing hydrates in 7799 ft. (2377 m.) of water, or in the presence of 7799 ft. (2377 m) of 

hydrostatic pressure and a sea floor temperature 36°F (2 0 C). 

Figure 13 - 8 

Gas Hydrate Equilibrium Chart 



REVISION 2006 13-18


10000 

x 

5000 

2500 

HPLC Water 

10 % NaCl 

10 % NaCl/30% NF2 

20% NaCl 

20% NaCl/ 10 % NF2 

23% NaCl 

23% NaCl/30% HF100 

x 10% NaCl/40% NF2 

23% NaCl / 30% NF2 

1000 

** 

30 35 40 50 60 70 80 90 100 

Temperature (F) 

Potential Hydrate Formation 

GAS HYDRATES IN THE BOP 

** No Hydrate Formation 

w/ 23% NaCl / 30% NF2 

at 10,000 PSI & 30 F 

Hydrates are most likely to form in the choke & kill lines and the BOP, as these are exposed to the 

lowest temperature and the highest pressures. The plugging of the well control equipment presents the 

greatest hazard potential. In order to prevent hydrate formation during a kick situation a suitable fluid 

may be spotted across the BOP and in the choke and kill lines. It is recommended to spot a suitable 

fluid across the BOP in the event of a gas kick 

Spotting Procedure 

1. Close lower-most pipe rams. In this manner, the kill line, BOP stack (above lower pipe rams), 

and choke line can be displaced 

2. Displace kill line and BOP stack with predetermined strokes. Once the fluid has cleared upper 

annular preventers, close preventers, open choke line, and displace same. 

3. Close pipe rams above and closest to choke line and begin well killing procedure, 

4. After the well is dead, there is potential for trapped gas above the closed pipe rams and below 

the annular preventers. A rapid expansion could cause riser collapse. 

Procedure For Evacuating Gas From The BOP 

1. Close bottom-most pipe rams and annular preventers. 

2. Pump mud through the kill line. When this pill returns at the choke line, stop pumping. 

3. Allow any gas to evacuate from the stack taking returns to the gas buster. 

4. Displace the kill line, BOP stack and choke line with kill weight mud. 

5. Open annular preventer, close diverter bag (i.e. diverter lines are open), and displace riser 

with kill weight mud. 

6. After riser has been circulated with kill mud, open lower pipe rams and check for flow. 



REVISION 2006 13-19


HYDRAULIC MODELING SOFTWARE 

INTRODUCTION 

In deepwater drilling operations it is extremely important to have control over the Equivalent Static 

Density (ESD) and the Equivalent Circulating Density (ECD) at all times. This is due, in part, to the 

young formations associated with deepwater drilling and the types of fluid normally employed to drill 

these wells. Overwhelmingly, invert emulsions are used in deepwater, with the external phase being 

decided by environmental regulations or operator policy. Invert emulsions are very inhibitive and 

offer excellent rates-of-penetration. There are a host of other advantages to invert emulsions covered 

early in this section (see section titled: AQUEOUS VS NON-AQUEOUS DRILLING FLUIDS). 

Non-aqueous fluids are compressible and expandable under the wide range of temperatures and 

pressures they are subjected to in a deepwater environment. Therefore, it is imperative that 

corrections are made to the fluid properties to compensate for the temperature and pressure effects on 

the whole mud density and rheological characteristics under downhole conditions. 

Baker Hughes Drilling Fluids has two state-of-the-art modeling programs to assist in analytical 

solutions for our customers; Presmod, which is primarily used to determine dynamic temperature 

profiles and ADVANTAGE SM , which is Baker Hughes Drilling Fluids proprietary hole cleaning and 

hydraulics model. 

TEMPERATURE MODELING 

Presmod 

Presmod is a dynamic hydraulics/temperature simulator. Presmod is capable of predicting ECD, 

ESD and temperature profiles of the annulus and drill string as a function of time. However, Presmod 

should not be used to predict ECD since the program assumes 100% hole cleaning, regardless of flow 

rate or other hole cleaning variables. 

For deepwater applications, Presmod is primarily used to predict dynamic temperature profiles when 

there is potential for the occurrence of gas hydrates. In practice, Presmod is used for the following 

scenario: 

An upper section of a deepwater well is drilled with an aqueous fluid which is limited by the amount 

of salt that can be added due to density restrictions. Also, the volume of liquid additives (glycols, 

alcohols, etc.) necessary to ensure against hydrate formation is cost prohibitive and would be 

detrimental to the performance of the fluid system. The section is drilled to total depth (TD) and the 

fluid reaches a circulating temperature profile. The two issues to address are: 

1. What will be the final annular circulating temperature? And in particular, what is the 

temperature at the mud line when drilling ceases, prior to tripping out to run pipe? 

2. Under non-circulating conditions, how long will it take for the annular temperature to cool 

down to a temperature favorable for hydrate formation in the event of a kick? 

The primary strength of Presmod can be demonstrated in the solutions to these questions and is 

illustrated by Figures 1 thru 3 below. 

Figure 13 - 9 

Temperature at Start of Drilling 



REVISION 2006 13-20




REVISION 2006 13-21



Temperature at End of Drilling 


Temperature After 78 Hours Non-Circulating 



REVISION 2006 13-22


ADVANTAGE SM 

ADVANTAGE SM is Baker Hughes Drilling Fluids’ integrated platform for all well planning, 

reporting and analysis services. This is a modular platform which allows for customized features 

depending on services being provided. Drilling Fluids Services include the comprehensive Daily 

Fluids Reporting system as well as the Engineering Software System. Engineering Software consists 

of Hydraulics and Swab and Surge Analysis 

All services above share data within a common integrated multi-well relational database. Data 

entered in Reporting Applications can be readily loaded into the Engineering Applications for 

rapid analysis. The Engineering Applications themselves are integrated. Analyses can be run for 

Hydraulics, Hole Cleaning, HTHP, and Swab & Surge predictive results at one time with the 

common dataset either for pre-well planning purposes, or daily operational data. 

Standard output reports from all Engineering Applications include Input Data and Calculated 

Results. In addition, ancillary reports (such as drill string and survey listings) are available. Also, 

all Engineering modules have interactive on screen graphic presentations of results. These results 

can be cut and pasted into standard MS Office applications (as graphics or data) for supplemental 

output. 

More specific information on ADVANTAGE SM Modules is provided below. 

ADVANTAGE SM Engineering Hydraulics 

Advantage Hydraulics provides sophisticated mathematical hydraulics and hole cleaning models. 

It is designed to give the best available estimate of the flow rate required to maintain effective hole 

cleaning. The program has been developed by a combination of theoretical modeling and field 

verification. 

Hydraulics calculates the following: 

• Total system pressure loss 

• Maximum and minimum allowable flow rates for the given hole and drillstring configurations 

• Annular velocities 

• Hydraulic horsepower at the bit 

• Equivalent circulating density (ECD) 

• Can be set to run several standard rheology models including: Bingham Plastic, Power Law, 

Newtonian, Hershel-Bulkley and Robertson-Stiff. 

ADVANTAGE SM HTHP Analysis 

When ADVANTAGE SM is run in the HTHP analysis mode, it considers the influence of pressure 

and temperature on the mud density and viscosity. The temperature profile can either be calculated 

or defined. The calculation of downhole density based on pressure and temperature requires the 

knowledge of the mud density profile. This can be provided by mud density measurements or by 

calculating the density based on the mud components. The results are displayed graphically in the 

Hydraulics Results Window. The calculation of mud rheological properties requires Fann70 

readings. These data must cover the range of pressures and temperatures expected in the well. The 

calculation performed is similar to a System Mud Hydraulics calculation. Additional results are 

created. There is an effective mud weight and a temperature profile report. Both are available 



REVISION 2006 13-23


graphically too. The downhole mud density and the rheological parameters are available as 

diagrams. 

The figure below is a typical ADVANTAGE SM output for a deepwater well. Note the tabular data on 

the left side of the Figure 13 - 12 or the graph in Figure 13 - 12 labeled “Downhole Density” 

indicates the ESD at the bottom of the wellbore is 12.73 ppg and the surface mud weight is only 12.5 

ppg. This is due to the pressure and temperature effects on compressibility and expandability on 

SBM’s and OBM’s. 


Deepwater Well Example 

HOLE CLEANING AND BARITE SAG 

INTRODUCTION 

Removing cuttings from the wellbore is the most important function of the drilling fluid. Whether the 

wellbore is being drilled on land, the offshore continental shelf, or in deepwater, the drill bit cannot 

advance if the cuttings are not removed. In deepwater wells the implications of not cleaning the 

wellbore are: spikes in ECD, numerous short trips, back reaming, poor cement jobs, stuck drill pipe, 

stuck casing/liner, etc. The bottom line results usually mean increased well costs to the operator and 

an unhappy client of the mud company. 

Barite sag is defined as the variation in mud weight seen at the flow line. This is usually observed 

after extended periods without circulation. At times barite sag will result in similar problems to those 

seen with inadequate hole cleaning. 



REVISION 2006 13-24


HOLE CLEANING TOOLS & TECHNIQUES 

Riser booster pumps, i.e., pumps assigned solely to circulate the marine riser, are used to increase the 

flow rate in the marine riser and so enable efficient cuttings transport in the riser. Riser booster pumps 

commonly increase the flow rate in the annulus by 500 gallons per minute. This increase in the flow 

rate in the riser has a negligible effect on ECD due to the low pressure drop in the riser. Riser booster 

pumps are necessary due to the often dramatic diameter changes at the riser. This is most marked in 

12 ¼” and smaller hole diameters. The ADVANTAGE SM engineering software allows the user to 

evaluate the effectiveness of various riser boost rates 

The same basic principles for hole cleaning are as valid in deepwater as in all drilling operations. The 

recommended method to evaluate hole cleaning is by use of the hole cleaning model within 

ADVANTAGE SM . If the HPHT mode is selected in ADVANTAGE SM and the requisite temperature 

gradients, PVT of the base oil and Fann® 70/75 data are provided, ADVANTAGE SM will perform 

the hole cleaning analysis using downhole rheological properties. 

BARITE SAG 

Barite sag is as much an issue in deepwater wells as all other wells. Barite sag is a genuine risk as 

efforts are made to minimize rheological properties in order to minimize ECD and minimize cold 

water rheological properties. Care must be taken to avoid barite sag when reducing and 

recommending rheological properties. 

ECD MANAGEMENT 

On many deepwater wells effective ECD management is one of the main factors in the successful 

drilling of a well. This often involves running the rheological properties as low as possible without 

causing hole cleaning or barite sag problems. The correct way to do this is by continual use of the 

engineering software in ADVANTAGE SM , taking regular samples for Fann® 70/75 testing and 

confirming that the low shear viscosity is sufficient to minimize the risk of barite sag. 

ECD optimization should always be one of the steps during well planning, using planned well 

geometries and fluid properties. ADVANTAGE SM Engineering is the correct tool for this type of 

work. 

Recommending, and implementing, good drilling practices is an integral part of ECD management. 

These include controlling rates of penetration, short trips, tripping rates, casing running speeds, 

methods for initiating circulation and drilling fluid properties. 



REVISION 2006 13-25


REFERENCES 

1. Zamora, M., Broussard, P.N., Stephens, M.P., The Top 10 Mud-Related 

Concerns in Deepwater Drilling Operations, SPE Paper 59019, 2000 SPE 

International Petroleum Conference and Exhibition, Villahermosa, Mexico, 1 

– 3 February 2000. 

2. Johnson, M., Rowden, M., Riserless Drilling technique Saves Time and Money 

by Reducing Logistics and Maximizing Borehole Stability, SPE Paper 71752, 

2001 SPE Annual Technical Conference and Exhibition, New Orleans, USA, 30 

September – 3 October 2001. 

3. Baker Hughes Drilling Fluids, Dynamic Kill Drilling, Best Practices Manual, 

October 2003. 

4. Bleier, R., Selecting a Drilling Fluid, SPE Paper 209986, Journal of Petroleum 

technology, July 1990. 

5. Cameron, C.B., Drilling Fluids Design and Field Procedures to Meet the Ultra 

Deepwater Drilling Challenge, SPE Paper 6601, 24th SPE Nigeria Annual 

Technical Conference and Exhibition, Abuja, Nigeria, 7 - 9 August 2000. 

6. Elward-Berry, J., Rheologically Stable Deepwater Drilling Fluid Development 

and Application, SPE Paper 27453, IADC/SPE Drilling Conference, Dallas, 

USA, 15 – 18 February, 1994. 

7. Carlson, T., Hemphill, T., Meeting the Challenges of Deepwater Gulf of Mexico 

Drilling with Non-Petroleum Ester-Based Drilling Fluids, SPE Paper 28739, 

SPE International Petroleum Conference & Exhibition, Veracruz, Mexico, 10 – 

13 October, 1994. 

8. Zevallos, M.A.L., Chandler, J., Wood, J.H., Reuter, L.M., Synthetic-Based 

Fluids Enhance Environmental and Drilling Performance in Deepwater 

Locations, SPE Paper 35329, SPE International Petroleum Conference & 

Exhibition, Villahermosa, Mexico, 5 – 7 March, 1996. 

9. Friedheim, J., Area-Specific Analysis Reflects Impact of New Generation Fluid 

Systems on Deepwater Exploration, SPE Paper 47842, IADC/SPE Asia Pacific 

Drilling Conference, Jakarta, Indonesia, 7 – 9 September, 1998. 

10. Paul, D., Mercer R., Bruton, J., The Application of New Generation CaCL 2 Mud 

Systems in the Deepwater GOM, SPE Paper 59186, IADC/SPE Drilling 

Conference, New Orleans, USA, 23 – 25 February, 2000. 

11. Power, D., The Top 10 Lost Circulation Concerns in Deepwater Drilling, SPE 

Paper 81133, SPE Latin America and Caribbean Petroleum Engineering 

Conference, Port-of-Spain, Trinidad, 27 – 30 April, 2003. 



REVISION 2006 13-26


12. Tare, U.A., Whitfill, D.L., Mody, F.K., Drilling Fluid Losses and Gains: Case 

Histories and Practical Solutions, SPE Paper 71368, SPE Annual Technical 

Conference and exhibition, New Orleans, USA, 30 September – 3 October, 

2001. 

13. Schofield T.R., Judzis, A., Yousif, M., Stabilization of In-Situ Hydrates 

Enhances Drilling Performance and Rig Safety, SPE Paper 38568, SPE Annula 

Technical Conference and Exhibition, San Antonio, USA, 5 – 8 October, 1997. 

14. Szeczepanski, R., Edmonds, B., Brown, N., Hamilton, T., Research Provides 

Clues to Hydrate Formation and Drilling-Hazard Solutions, Pages 52 – 56, 

Oil& Gas Journal, March 9, 1998. 

15. Halliday, W., Clapper, D.K., Smalling, M., New Gas Hydrate Inhibitors for 

Deepwater Drilling Fluids, SPE Paper 39316, IADC/SPE Drilling conference, 

Dallas, USA, 3 – 6 March, 1998. 

16. Yousif, M.H., Young, D.B., A Simple Correlation to Predict the Hydrate Point 

Suppression in Drilling Fluids, SPE Paper 25705, SPE/IADC Drilling 

Conference, Amsterdam, Netherlands, 23 – 25 February, 1993. 

17. Grigg, R.B., Lynes, G.L., Oil-Base Drilling Mud as a Gas Hydrates Inhibitor, 

SPE Paper 19560, SPE Annual Technical Conference and Exhibition, San 

Antonio, October 8 – 11, 1989. 

18. Ebeltoft, H., Yousif, M., Soergaard,E., Hydrate Control During Deepwater 

Drilling; Overview and New Drilling-Fluids Formulations, SPE Paper 68207, 

SPE Drilling & Completion, March 2001. 



REVISION 2006 13-27

Chapter 

Fourteen 

Fluids Environmental Services 

Fluids Environmental Services


Chapter 14 


FLUIDS ENVIRONMENTAL SERVICES..........................................................................................14-1 

INTRODUCTION...............................................................................................................................14-1 

FES MANAGEMENT SYSTEM.......................................................................................................14-3 

THE SIX STEPS ................................................................................................................................14-4 

Step One – Determining Expectations.......................................................................................14-4 

Step Two – Data Analysis............................................................................................................14-6 

Step Three – Setting Goals .......................................................................................................14-10 

Step Four – Detailed Planning ..................................................................................................14-11 

Step Five - Execution..................................................................................................................14-13 

Step Six - Continuous Improvement and Learning ................................................................14-18 

BEST OPERATING PRACTICES.................................................................................................14-20 

Volume Reduction.......................................................................................................................14-20 

Waste Minimisation.....................................................................................................................14-22 

Recommendations to Reduce Surplus Volumes and Wastes at the Rig Site ...................14-23 

Recommendations to Reduce Surplus Slop Waste at the Rig Site.....................................14-23 

WASTE TRANSPORT AND DISPOSAL......................................................................................14-26 

Skip & Ship...................................................................................................................................14-26 

Cuttings Fixation..........................................................................................................................14-27 

Bioremediation.............................................................................................................................14-27 

Landfarming .................................................................................................................................14-27 

Thermal Treatment......................................................................................................................14-28 

Other Thermal Treatments ........................................................................................................14-29 

Possible Uses of Waste .............................................................................................................14-29 

SLOP SEPARATION ......................................................................................................................14-30 

Introduction...................................................................................................................................14-30 

Benefits of Using Slop Treatment Technology .......................................................................14-30 

Equipment Set-Up and Operation.............................................................................................14-31 

Equipment Details .......................................................................................................................14-33 

Handling OBM Slops Onshore ..................................................................................................14-35 

CUTTINGS SLURRIFICATION AND RE-INJECTION...............................................................14-35 

Introduction to Cuttings Slurrification/Re-Injection .................................................................14-35 

Cuttings Slurrification..................................................................................................................14-36 

Injection Theory ...........................................................................................................................14-36 

Injection Process .........................................................................................................................14-37 

Operating Considerations ..........................................................................................................14-37 

Lithology Concerns .....................................................................................................................14-38 

Surface Equipment Requirements............................................................................................14-38 

Casing Programme .....................................................................................................................14-39 

Monitoring Procedures ...............................................................................................................14-39 

Main Components of CRI System ............................................................................................14-40 

Cuttings Slurrification Package .................................................................................................14-40 

CUTTINGS DRYER ........................................................................................................................14-49 

FILTRATION SERVICES ...............................................................................................................14-53 

Filtration of Wellbore Clean-up Returns...................................................................................14-53 



REVISION 2006 14-i


Filtration of Gravel Pack Carrier Fluids....................................................................................14-53 

Produced Water Treatment .......................................................................................................14-53 

Seawater Injection.......................................................................................................................14-53 

Fluid Analysis...............................................................................................................................14-54 

Waste Water Treatment .............................................................................................................14-54 

Filtration Equipment Technical Information.............................................................................14-54 

Analysis Equipment ....................................................................................................................14-62 


FIGURE 14 - 1 EXAMPLE OF FES PERFORMANCE CRITERIA DATABASE............................................14-9 

FIGURE 14 - 2 EXAMPLES OF GOALS THAT CAN BE DEFINED FOR A PROJECT ..............................14-11 

FIGURE 14 - 3 THOROUGH PLANNING ENSURES PROCESS OPTIMISATION .....................................14-13 

FIGURE 14 - 4 EXAMPLE OF DAILY SOLIDS CONTROL / WASTE MANAGEMENT REPORT ................14-15 

FIGURE 14 - 5 EXAMPLE OF A DAILY FES REPORT ...........................................................................14-16 

FIGURE 14 - 6 EXAMPLE OF A WEEKLY FES REPORT.......................................................................14-17 

FIGURE 14 - 7 EXAMPLE OF A LESSONS LEARNED REGISTRY ..........................................................14-18 

FIGURE 14 - 8 EXAMPLES FROM AN AFTER ACTION REVIEW REPORT .............................................14-19 

FIGURE 14 - 9 TYPICAL RIG SITE WATER AND OILY WASTE HANDLING SYSTEM (OFFSHORE)......14-24 

FIGURE 14 - 10 SCHEMATIC OF SET-UP OF A TYPICAL SLOP TREATMENT SCENARIO ON AN 

OFFSHORE RIG..............................................................................................................................14-31 


TABLE 14 - 1 EXAMPLES OF PERFORMANCE CRITERIA FOR DATA ANALYSIS ....................................14-7 


REVISION 2006 


14-ii

FLUIDS ENVIRONMENTAL SERVICES 

Chapter 14 


The strengthening of environmental regulations around the world has changed the way 

service companies and their customers view the provision of drilling fluids. Ignoring the 

effects on the environment from mixing, transporting, cleaning, re-using and disposing of 

mud and cuttings is no longer an option. Baker Hughes Drilling Fluids FES (Fluids 

Environmental Services) includes a broad range of services and equipment to complement 

its drilling fluids services. The application of the services described here is subject to the 

environmental conditions of a project that, in many instances, determine the selection and 

design of the drilling fluid. 

INTRODUCTION 

The objective of Baker Hughes Drilling Fluids Environmental Services (FES) is to provide an integrated 

solution to the management of drilling fluids and the associated drilling waste generated, addressing the 

operation from waste generation to final disposal. 

FES follows the waste management hierarchy as the guideline to manage all the issues affecting the 

operation. The waste management hierarchy aims at reducing the overall impact of the drilling 

activities to the environment: 

Reduce 

Minimize the volume of waste and reduce 

environmental risks 

Reuse 

Maximize the use of materials and resources for 

the same process 

Recycle 

Recover part or all of the waste to be used in a 

new process or to begin the process over again 

Respon 

sible 

Use methods and technologies that minimize the effect 

on the environment and use the least amount of resources 



REVISION 2006 14-1


The waste management hierarchy requires a range of services that can be applied during each stage of 

the process according to the characteristics of a particular project and the customer. 

I – Waste Minimization 

Approaches 

Synthetic-based and oil-based 

mud generate less cuttings 

than water-based mud 

II - Recycle or Reuse 

Approaches 

Road spreading when roads 

benefit from application of 

waste 

III - Disposal Approaches 

Land spreading or land 

farming 

Coiled tubing drilling 

Directional/horizontal drilling 

Use of less toxic components 

and additives for mud 

Air drilling 

Reuse synthetic-based and oilbased 

mud 

Use cleaned cuttings for fill or 

cover material 

Restoration of wetlands with 

clean cuttings 

Use cuttings as aggregate for 

concrete or bricks 

Thermal treatment with fluid 

recovery 

Road spreading 

Burial in onsite pit or offsite 

landfill 

Discharge to ocean 

Salt cavern disposal 

Underground injection 

Thermal treatment 

Biotreatment (e.g., 

composting, vermiculture) 

There are three main types of services within Baker Hughes Drilling Fluids FES product line: 

• Management Systems: The FES Process is based on the Total Quality Management concept. 

It aligns the goals and activities of each project with the expectations of the customers, 

assuring that lessons are learned and best practices are retained within the organization and 

can be applied to future jobs. 

• Best Operating Practices: These consist of several recommended procedures to minimize the 

volume of waste. BOP’s encompass planning and execution of drilling fluids, solids control, 

waste management and supporting activities that affect the quantity and quality of waste 

generated. 

• Waste Management Services: Technologies specifically designed to collect, treat and 

discharge drilling waste. 

This approach means Baker Hughes Drilling Fluids can provide closer co-ordination, quicker 

response time and better control of the project. 

The benefits to the operator include: 

• Rapid project deployment: The initial project set up time is greatly reduced as Baker Hughes 

Drilling Fluids FES will take on many of the responsibilities to ensure full environmental 

compliance 



REVISION 2006 14-2


• Baker Hughes Drilling Fluids HSE will provide assistance with obtaining the drilling 

approval 

• Potential risks are identified to minimize the impact of drilling operations on the 

environment. 

• The operator’s personnel are freed to concentrate on the operational big picture rather than 

the smaller details. 

• Paths of communication, roles and responsibilities are clearly defined 

• Operating efficiency is maximized through the use of Key Performance Indicators 

• The logistics involved in the transportation of all fluids and the associated waste are managed 

• An accurate audit trail to keep track of all drilling waste is provided 

• A system of continual learning detects problems and highlights areas for improvement 

FES MANAGEMENT SYSTEM 

The FES methodology should be expected to achieve the following: 

The FES Management System is a Total Quality Management 

process for the planning, execution, logistics and reporting of the 

total drilling fluids cycle present in every drilling operation. It is 

designed to reduce overall drilling project costs by providing 

single chain of command focus and aligning all associated fluids 

service lines towards common pre-determined goals to minimize 

waste generation and maximize fluids recovery/re-use. The 

ultimate objective is to focus the efforts of everyone involved, to 

make the process more efficient for the benefit of the customer, 

the environment and the service companies themselves. 

• Improvement of the coordination of drilling fluids, solids control equipment and waste 

management services. Rational use of resources, planning ahead and better communication 

are some of the tools to better coordinate these services. 

• Optimization of Solids Control Equipment performance. The efficiency of the solids control 

equipment (SCE) can have a major impact both on the condition of the mud as well as the 

volume of waste. Poorly operated SCE can result in unnecessary losses of drilling fluid in the 

form of overly wet discharge from the centrifuges and residual fluid attached to cuttings. 

• Optimization of waste management through waste segregation to reduce costs and volumes 

to maintain. 

• Improvement in the quality of the information collected in the project about drilling waste. 

Accurate measurement of volumes, characteristics and sources of each type of waste will 



REVISION 2006 14-3


have a significant effect on the ability to optimize processes in the future. Better information 

will give a clearer picture of the project status and will make it possible to build a continuous 

improvement system. 

Slops 

& 

Boat 

Eco 

Centres 

Drillin 

g 

SC 

Dr 

Cuttings 

Processi 

THE SIX STEPS 

C 

Filtratio 

n 

Pit 

Cuttings 

The process consists of six clearly defined steps. Each one is described below including the forms that 

need to be filled out. 

This FES Process map has been developed to aid the optimization and planning of the drilling fluid life 

cycle. It is a systematic approach designed to ensure that all of the issues mentioned are addressed and 

that the deployment will be carried out with a high level of competence and service. 

Step One – Determining Expectations 

The first step in the process is determining the expectations, or needs, of the project, or well, in order 

to plan for a successful job. When every member of a team is aware of firm, clear expectations from 



REVISION 2006 14-4


the customer, it facilitates an effective delivery of results. Examples of project expectations include: 

finishing date for production requirements, environmental issues, logging requirements or casing 

requirements, projects costs, etc. 

PROJECT OVERVIEW 

Operator: 

A.N. OPERATOR 

Project or Well Name: Xxxx 

Location: 

Xxxx 

Well Type: Land Offshore Deepwater 

Brief project 

description: 

Services to be 

provided: 

First batch of 6 well, then second batch of 11 wells. 

16 Producing, 1 Water Injection 

Fluids Cuttings handling Disposal 

Solids control Transportation Cleaning 

Screens 

Completions 

3 rd Party Contractors: 

Team Members: 

Date: 

Company Service Contact 

Oil Tools 

SCE & CRI 

Cement 

Expectations Details Source 

H.S.&E.: 

Zero LTI for DF 

Environmental: 

OOC80L 

Drilling Economics: Within AFE 



REVISION 2006 14-5


Early production: 

Enhanced production: 

Other: 

Zero Skin Damage in production Zones 

Figure 1 - Example of a Set of Expectations for a Project 

Step Two – Data Analysis 

The second step is data collection, analysis and benchmarking. Historical data pertaining to the 

project or well is collected from offset wells, if applicable, or similar type wells if offset data is not 

available. This data may include, but is not limited to, days per 10,000 feet, cost, non-productive time 

analysis, drilling fluid volumes consumed, drilling fluid volume lost to the formation, pore pressure 

versus depth, non-productive time, cuttings volume per foot, cost of waste management, etc. The 

data is analyzed to determine percentile rankings, benchmarks and possible bottlenecks and/or risks. 

The type of data to collect and analyze will depend upon the expectations and conditions of the 

operation. A list of commonly used parameters is included in Table 14 - 1. 



REVISION 2006 14-6


Well Information 

• Drilling fluid type 

• AFE days 

• AFE depths 

• AFE well cost 

• Actual days 

• Actual well cost 

• Well Non Productive Time (NPT) 

Technical 

• Mud properties as per program (%) 

• Field procedures followed (%) 

• Corrosion procedures 

• Waste management procedures 

• Mud losses control by LCM procedures 

• Daily hydraulic report 

• Daily hole cleaning report 

• Recap updated 

• Stuck pipe incidents 

• Hole cleaning incidents 

Cost 

• Drilling fluids engineering cost 

• Drilling fluids chemical cost 

• Solids control engineering cost 

• Solids control equipment ( SCE) cost 

• Waste management cost 

HSE 

• Lost Time Incidents 

• Safety meetings 

• Number of environmental incidents 

• Spill incidents 

• Disposed waste in non authorized areas 

• Internal audits 

Hole Size 

• Total volume used 

• Mud recycled 

• Mud sent back to liquid mud plant 

• Surface losses 

• Liquid waste volume 

• Solid waste volume 

• Mud lost downhole 

• Cement waste 

KPI’s 

• % Well NPT 

• % Total mud cost to well cost 

• % Total SCE cost to well cost 

• % Waste management cost to well cost 

• % FES cost to well cost 

• Mud cost / ft drilled 

• SCE cost / ft drilled 

• Waste management cost / ft drilled 

• Section dilution rate 

• Liquid waste / ft drilled 

• Solid waste / ft drilled 

Table 14 - 1 Examples of Performance Criteria for Data Analysis 



REVISION 2006 14-7


Information from offset wells is entered into a database. The database will be used in step three as a 

benchmark to establish achievable goals for the project based on historic performance. 

Performance Criteria 

8½" 

Salt Sat. 

8½" 

Perflow 

5⅞" 

Perflow 

Well 

Information 

Well Name 

209 209 209 

Mud Type Salt Sat Perflow Perflow 

FES Program Available y y Y 

AFE Days 107 107 107 

AFE Depth ( Meters) 301 0 831 

AFE Well Cost (US$) $11,296,510 $11,296,510 $11,296,510 

Actual Days 18 20 50 

Actual Depth ( Meters) 95 444 1,178 

Actual Well Cost (US$) $2,416,246 $3,778,611 $9,894,104 

Well Non Productive time 

(Days) 0.00 0.30 0.44 

HSE Lost Time Incidents (LTI) 0 0 0 

Safety Meetings 

Internal Audits 

Internal Inspections 

Technical 

Mud Properties as per Program 

(%) 

100% 90% 90% 

Mud Losses control by LCM 

n/a y y 



REVISION 2006 14-8


Procedure 

Stuck pipe incidents 0 0 0 

Hole Cleaning incidents 0 0 0 

Cost Drilling Fluids Engineering cost 17,350 12,800 40,000 

Drilling Fluid Chemical cost 68,664 148,592 234,332 

Solids Control Engineering 

Cost 

9250 6033 21,316 

Solids Control Equipment Cost: 13,634 8892 31,417 

Mesh Screens 1875 341 2045 

KPI's % Total Mud Cost to Well Cost 2.8% 10.9% 3.8% 

% Total SCE to Well Cost 0.6% 0.7% 0.5% 

Mud Cost US$ / M drilled $722.78 $334.67 $198.92 

SCE US$ / M drilled $143.52 $20.03 $26.67 

Liquid Waste/M drilled (M3/M) 0.087 0.093 0.054 

Solid Waste/M drilled (M3/M) 0.051 0.050 0.023 

Number of environmental 

incidents 0 0 0 

Figure 14 - 1 Example of FES Performance Criteria Database 



REVISION 2006 14-9


Step Three – Setting Goals 

Goals for the project or well are then set using the benchmarks and risks determined in the previous 

step. Goal management includes: 

a) Defining what is needed to attain the goal. 

b) What is the end result of the goal? 

c) How will the goal be tracked? 

d) Who is responsible for the goal? 

When goals are agreed upon between team members, they are discussed with all personnel involved 

in the project. This enables all members to be aware and focus on the tasks before them. 

Furthermore, those goals have to be in alignment with the expectations for the project in order for 

them to have an impact on the overall performance of the operation. 



REVISION 2006 14-10


Figure 14 - 2 Examples of Goals That Can Be Defined For a Project 

The FES system requires a continuous tracking of progress throughout the operation. For each 

parameter, a reporting frequency needs to be agreed upon. More importantly, using the results as 

feedback in the design of better practices or during the planning phases of future wells will ensure 

that the process does produce improvements in the quality of the services provided. 

Step Four – Detailed Planning 

The fourth step is to generate a detailed plan for the operation that addresses all technical hurdles. 

This includes details collected during the examination of historical data and the goals for the project. 

A meeting with key project personnel such as drilling engineers, rig supervisors, drilling fluids 

engineers, and FES coordinators is held to discuss the critical issues that may include: 

• HSE issues 

• Hydraulics 

• Sweep programs 

• Minimum flow rates for hole cleaning 

• Fluid properties 

• Pipe rotation and rates of penetration 

• Tripping guidelines 

• Lost circulation prevention and cure 



REVISION 2006 14-11


• Swab and surge calculation for running and pulling speeds 

• QA procedures for ISO 14001 

• Solids control equipment performance 

• Waste segregation and disposal 

• Training requirements 

Based on the results of the meeting, a FES plan is prepared that will identify the main technical and 

logistical obstacles for drilling fluids, completion fluids, solids control and waste management 

activities. The plan should define the procedures and processes to overcome those potential problems 

and establish tracking and reporting protocols for the relevant data needed to measure performance. 



REVISION 2006 14-12


Figure 14 - 3 Thorough Planning Ensures Process Optimisation 

Step Five - Execution 

The fifth step is the execution of the plans and capturing lessons learned. All of the previous steps 

should lead to a more effective operation and the FES system is designed to ensure that all relevant 

information is captured. It is important in this phase to capture ideas and changes to the original plans 



REVISION 2006 14-13


in order to improve performance. The system should provide the tools for reporting and distributing 

lessons learned and best practices. 

Every person involved in the project should be familiarized with the key documents that constitute the 

FES system: 

• Roles and responsibilities description: Detailed description of duties and items specific to 

operations. 

• Daily reports: Templates used to record properties, activities and values. 

• Weekly reports: Template used to examine performance and take appropriate action if it is 

falling short of achieving the objectives. 

• Lessons Learned: Template used to track and report lessons learned and suggestions for 

improvement. 

• Drilling Practices: Specific practices that affect the FES performance. The key element is 

effective communication between team members to implement the plan and provide feedback 

about results and possible improvements. 

• Personnel skill assessments and training matrix: A template summarizing the existing pool of 

skills among personnel in the project, the minimum proficiency requirements based on the 

project scope and the plan to develop each competency. 

Data is recorded on a daily and weekly basis, with the reporting format being tailored to the 

operator’s needs. Where Baker Hughes Drilling Fluids is also contracted to handle the waste 

management, a reporting structure is put in place to track the waste from the rig to its final disposal or 

recycling point, regardless of the manner 

of process being used. The aims are to ensure a complete 

audit trail, give accurate volumes, and conform to ISO 14001 requirements and to provide a 

methodology for waste reduction. 



REVISION 2006 14-14


Baker Hughes INTEQ Fluids Environmental Services 

Daily SCE/Waste Management Report 

Operator 

Contractor 

Report Number 

Operators Rep 

Contractor Rep 

Date 

Address 

Current Activity 

Field 

Well Name 

Rig 

Block 

Hole Size 

inches Drilling Hours 

Depths (m) 

> 

Shakers 

Dryer 

Mud Recovered From 

Centrifuges 

0 

typhoon 

Dryer 

0 0 

Top Screen Feed ppg Saved bbls Mode dryer active 

Lower Back Returns Saved ppg Bowl RPM 

Lower Front gauge hole Saved mT Bowl PSI 

Beach mT / day + Oil bbls Diff LPM 

Underflow ppg Downtime + Oil ppg Feed GPM 

Discharge % + Oil mT Feed ppg 

gauge hole Blend bbls Centrate 

mT / day Blend ppg Pump Hrs 

Downtime Blend mT Downtime 

Shaker Retort 

Dryer Retort 

Mud Recovered From 

Centrifuge Retort 

0 Sample 1 Sample 2 Sample 3 Dryer Retort 

0 0 

Average ppg 

Average ppg Average ppg Average ppg 

LGS mT/day LGS mT/day LGS mT/day LGS mT/day 

HGS mT/day HGS mT/day HGS mT/day HGS mT/day 

Oil bbls/day 

Oil bbls/day Oil bbls/day Oil bbls/day 

Mud bbls/day 

%ROC (g/kg) 

Mud bbls/day %ROC (g/kg) 

Mud bbls/day 

%ROC (g/kg) 

Mud bbls/day 

Cake GPM 

Centrate GPM 

HGS ppb 

LGS ppb 

%ROC (g/kg) 

Solids Control Equipment 

Shakers solids feed Dryer Centrifuge (dryer) 

Centrifuge (active) 

Daily (kg) 

liquid feed 

Wet Solids 

Cumm 

0 

0 0 

solid discharge 

Mud 

Daily(m3) 

Cumm 

0 0 

0 

lost on solids lost on solids lost on solids 

Daily(m3) 

Base Fluid 

Cumm 

0 

0 

0 

Hole Size (Inches) 

Total 

Volumes (m3) 

B.F Recovered 

Daily 

Well 

0 

Mud Recovered 0 

PIT NUMBER 

1 

2 

3 

4 

5 

6 

7 

8 

Volume Before Cut 

Back (m3) 

Volume After Cut 

Back (m3) 

Total 

Volume Lost (m3) 

Product 

Escaid 110 

Mil - Bar 

Cal. Chloride (95%) 

Carbogel 

Carbomul HT 

Carbotec S 

Mil-Lime 

Surf-Cote 

LC Lube 

Mil Carb 

Soluflake M 

Daily Vol. Discharged 

(kg) 

Remarks 

FES Engineers: 

Figure 14 - 4 Example of Daily Solids Control / Waste Management Report 



REVISION 2006 14-15


OPERATOR 

Brunei shell petroleum 

CONTRACTOR 

Ensco 

DATE 

04/05/04 

OPERATOR REP(S) 

MR JIMMY RIDDLE 

CONTRACTOR REP 

MRS JIMMY RIDDLE REPORT NUMBER 

2 

ADDRESS 

Sunny street KB 

RIG 

Ensco 51 

WATER DEPTH (ft) 

60 

WELL NAME 

FA-12 12 

PROJECT / PLATFORM 

0 

BLOCK 

38270 

CURRENT ACTIVITY 

DRILLING 12.5" HOLE 

FIELD 

Fairley 

Well Information 

HSE 

WELL PERFORMANCE 

Bit Diameter ( in ) 12 1/2 

Actual Target Actual 

Target 

Start Depth ( m ) 1072 

LTI (FES) 

1 0 NPT FES 

2.08% 

0.00% 

End Depth ( m ) 1572 

Spills (FES) 

1 0 FES Cost / m 

$8.22 

$0.00 

Drilled ( m ) 500 

Man Hours (FES) 

120 0 OBM Lost on SCE (m3) 

41.59 

0.00 

Average ROP (m/hr) 22 

STOP CARDS 

13 0 m3 OBM lost/1 K m drilled 

36.20 

0.00 

Retention On Cuttings (g/kg) 

AVERAGE FOR ALL SCE Interval 1 Interval 2 Interval 3 

OIL ON CUTTINGS ( % by Weight) 

g/kg per Sampling Interval 13.00 17.00 18.00 

Mass Balance Interval 1 ROC % (g/kg) 


SHAKERS ONLY Interval 1 Interval 2 Interval 3 

ROC % Benchmark (g/kg) 


g/kg per Sampling Interval 120.00 125.99 126.67 

Well Average ROC (%BF Well) 

Daily ROC (g/kg) 

Well ROC (g/kg) Ave. Benchmark 

16.00 0.00 

124.22 

21 

Base Oil Discharged Daily Cumulative 

B.O Discharged-Shakers (m³) 

24.13 39.59 

B.O Discharged-Dryer (m³) 

9.00 - 

18 

B.O Discharged- Dryer Centrifuge (m³) 

90.00 1.00 

B.O Discharged-Active Centrifuge (m³) 

2.00 1.00 

TOTAL B.O Discharged-SCE (m³) 

125.13 41.59 

15 

Fluid Type Daily Cum. 

OBM-Shaker Discharge - 5.23 - 

% Shaker Discharge To Sea - 

OBM-Dryer Discharge petrofree 15.00 3.00 

Centrifuge (Dryer) Discharge petrofree 4.00 45.00 

Centrifuge (Active) Discharge petrofree 2.00 1.00 

OBM Losses Other petrofree - 0.00 

OBM Spill (Overboard) petrofree 1.00 1.00 

Trip Losses - - - 

Total OBM Fluid Discharged petrofree 27.23 50.00 

WBM Fluid - 0.00 0.00 

Completion Fluid - 0.00 0.00 

0 

Spacers - 0.00 0.00 

0 1 Days 

2 3 

Waste Wash Water - 0.00 0.00 

Solids Discharged (kg) 

FES Cost ($) 

OBM Cuttings 

Daily 

Daily Cum. Daily Cum. Cum. 

FES Supervisor 

Discharged (Shakers) 114622 341890 550.00 

$ 1,100.00 

$ 

Third Party Solids Control Cost 750.00 $ 

$ 770.00 

Discharged (Dryer) 137 411 Solids control Equip. $ 1,665.00 $ 3,330.00 Rig Cleaning $ 

10.00 $ 

20.00 

Discharged (Dryer Centrifuge) 200 400 Solids cont. personnel $ 450.00 $ 900.00 Transportation $ 

10.00 $ 

20.00 

Solids Discharged (Active Centrifuge) 1 2 Rig up/Rig Down $ 200.00 $ 300.00 Fluids Disposal $ 

10.00 $ 

20.00 

WBM Cuttings 

Fluids Discharged To Sea 

Shaker Screens $ 200.00 $ 300.00 

Total 

Benchmark 

Daily Cum. Shaker Screens Repair 200.00 

$ 300.00 

$ 

5,217.00 $ 

$ Cumulative Drilling fluid Cost - 

Generated 0.00 0.00 Cuttings Handling $ 10.00 $ 20.00 Cum. BHI Cost $ 

7,120.00 $ 

- 

Discharged to Sea - 0.00 Cuttings Disposal 

$ 10.00 $ 20.00 FES Cost 

$ 

12,337.00 $ 

- 

Disposed (Shipped to Shore) Overboard - 0.00 

OBM 

WBM 

Completion 

Spacers 

Fluid discharged to Sea 

Fluid 

Down hole losses (Drilling) 

Fluid left behind casing 

Evaporation Losses 

OBM VOLUME ANALYSIS (m³) 

Unscheduled Discharges (See Comments) 

Fluid Recovered (m³) 

TOTAL 

SOLIDS CONTROL INFORMATION 

Type Daily Cum. 

petrofree 2.00 1.00 

0.00 - 0.00 

0.00 - 0.00 

Spacers - 0.00 

Daily 

Cum. 

0.00 0.00 

0.00 0.00 

0.00 0.00 

0.00 0.00 

0.00 0.00 

0.00 0.00 

Centrifuge Data Cent. 1 Cent. 2 Cent. 3 Dryer 

Equipment Type/Model DE-1000 DE-1000 DE-1000 J S 110 

Bowl Speed 4000 4000 4000 300 

Back Drive Speed 3000 3000 

3000 - 

Feed Rate 302.83 302.83 

302.83 1000 

Weight In 12.8 12.8 

12.8 15.3 

Weight Out 12.2 12.2 

12.2 12 

Discharge Weight 0.6 0.6 

0.6 3 

Hours Run 2 2 

8 24 

Down Time (hrs) 0 0 0 0 

Utilisation (%) 100.0 100.0 100.0 100.0 

SHAKER(S) DATA 1 2 3 4 5 6 

Equipment Type/Model VSM100 VSM100 VSM100 VSM100 VSM100 VSM100 

Screen Type / Size 165X4 165X4 165X4 165X4 165X4 165X4 

Screen Changes 4 4 4 4 4 4 

Repair Screen Change 4 4 4 4 4 4 

Weight in 12.2 12.2 12.2 12.2 12.2 12.2 

Weight out 12.2 12.2 12.2 12.2 12.2 12.2 

Discard Weight 12.2 12.2 12.2 12.2 12.2 12.2 

Hours Run 24 24 24 24 24 24 

Down Time (hrs) 0 0 0 0 0 

0 

Utilisation (%) 100.0 100.0 100.0 100.0 100.0 100.0 

FES Engineers: 

ce: Offi 

JASON BODMER MR CHOMPOO 

Baker Hughes INTEQ 

Fluids And Environmental Services Daily Report 

Brunei shell petroleum 

O.O.C % (by weight) 

12 

9 

6 

3 

Depth 

Total FES Cost, $US 

0 200,000 400,000 600,000 800,000 1,000,000 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

BENCHMARK TARGET CUMULATIVE TOTAL FES COST 

Comments: 

WELL WELL WELL, WHAT DO WE DO NOW 

HIGH STREE BRUNEI 

Telephone : 

666 666 666 

Figure 14 - 5 Example of a Daily FES Report 



REVISION 2006 14-16


Figure 14 - 6 Example of a Weekly FES Report 



REVISION 2006 14-17


Lessons Learned Registry 

Index 

Number 

Date Well Name Problem / Concern Impact Solution / Innovation Benefit 

Success 

or Failure 

$ Impact (+ for 

$ spent, - for $ 

saved) 

Contact for 

additional 

information 

Figure 14 - 7 Example of a Lessons Learned Registry 

Step Six - Continuous Improvement and Learning 

The final step in the FES process is a formal review and validation of the lessons learned during the 

well or project. The idea is to compare the actual results with the goals and expectations defined at the 

beginning of the project. The objective is to improve the process for future operations. 

There are six questions asked during the After Action Review (AAR): 

• What were the plan and the goals for the well or project? 

• What was done and/or accomplished? 

• What were the differences between the plan and what was accomplished? 

• Why did these differences occur? 

• How do we sustain and promote what was done right? 



REVISION 2006 14-18


• How do we improve or eliminate what was done incorrectly? 

There are several key aspects that need to be considered when performing a review: 

• Identify weaknesses and strengths during the process. 

• Distribute lessons learned throughout the organization. 

• Assign responsibilities for implementing new actions. 

• Perform a self-assessment review of those involved in the project. 

Examples from an After Action Review are shown below. 

Figure 14 - 8 Examples from an After Action Review Report 



REVISION 2006 14-19


BEST OPERATING PRACTICES 

Reducing the volume of waste and containing those substances with higher potential for pollution is 

critical to improve the environmental performance under a FES system. A key area for improvement 

is in the segregation and accounting of wastes. As a rule, treatment costs are higher as the 

concentration of hydrocarbon increases. If wastes free from hydrocarbons are commingled with oily 

residues then a larger than necessary volume of waste containing hydrocarbons is being treated. 

Likewise, poor accounting at both the rig site and at the waste treatment center could lead to 

differences between volume of waste sent and received. It is important that it is realized that all waste 

is not the same and even though it is waste, it needs to be tracked as carefully as any other asset. This 

is of particular importance to the operator as it is related to liability, duty of care and ownership of 

any waste. 

Volume Reduction 

An important part of the FES strategy is to reduce the overall volumes of fluids produced from the 

drilling and completion of each well. By reducing excess volume there will be a corresponding 

reduction in waste, bringing further cost benefits. 

The main sources of excess fluids volume are: 

a) Discharges of WBM 

• Limited fluids recycling and reuse. 

Water based drilling fluids by their nature are more readily biodegradable and have a shorter “shelf 

life” than oil based drilling fluids. As they are generally less inhibitive than OBM they tend to 

become solids laden more readily and require expensive separation processes to remove the 

incorporated drilled solids. 

In the past very little effort was spent on evaluating the economical and environmental potential of 

reusing WBM fluids in offshore operations. This was primarily due to the perception that the 

incremental cost of shipping, reconditioning and storing these fluids would be prohibitive. This is 

particularly evident when the water-based system is being replaced by an oil based system. Many 

drilling installations do not have the capacity or the facilities to handle two types of drilling fluids 

simultaneously and marine vessels do not have sufficient tanks to transport both systems 

independently. 

For onshore operations, dewatering techniques are used in the closed loop mud systems (CLMS) as 

an alternative to direct discharge of WBM drilling fluids. This process eliminates the use of reserve 

pits and recirculation pits or sumps, in the treatment and removal of drill solids from drilling fluids. 

The dewatering techniques used in this process combines conventional solids control equipment with 

chemically enhanced dewatering methods to remove the ultra-fine solids from the drilling fluid and 

dispose of it as a dry waste. The application of these techniques has grown in usage to become an 

integral part of routine drilling operations. 

Dewatering methods were initially used to treat the liquid drilling waste in a reserve pit, removing the 

solids and discharging the cleaned fluid. As the economic and environmental pressures grew to go to 

a CLMS operation, the use of coagulation and flocculation chemical technology in conjunction with 

decanting centrifuges and specialized dewatering equipment became the preferred method for drilling 



REVISION 2006 14-20


operations. The active water-based drilling fluid is dewatered with chemically enhanced 

centrifugation, removing the fine drilled solids and returning the clear water to the system. 

The solids are discarded to a collection bin and the clear water is returned to the active system. 

Depending on chemical content, the solids can be land-farmed on the location, restoring it to original 

form, or hauled off to a disposal area. 

In areas where solids water content is closely monitored, the use of drying mechanisms has been 

implemented to complement the typical centrifugation equipment to further reduce the volume of 

waste. The drying systems used include: 

• High impact drying shakers. 

• Centrifugal cuttings dryers (i.e. Baker Hughes Drilling Fluids’ Typhoon). 

• Filter presses. 

b) Excess Dilution and Mud Retention on Cuttings (OBM & WBM). 

The volume of dilution is a direct function of the efficiency of the solids control equipment. Waste is 

generated because of (1) build up of solids in the drilling fluid that result in higher dilution rates 

and (2) excess of liquid bonded to the solids particles removed by the solids control equipment. A 

balance has to be achieved between these two options to find the preferred specifications that will 

maximize the reduction in the volume of waste. 

The efficiency of the solids control equipment can have a major impact both on the condition of the 

drilling fluid as well as the volume of waste. Wet cuttings obviously weigh more and take up more 

space than drier cuttings, which ultimately increases the transport and treatment costs. 

Additionally, this is drilling fluid that is effectively being thrown away when it could easily be 

retained within the system for further use. 

Shakers that aren’t being operated at their optimum can force the driller to cut the pump strokes in 

order to prevent mud being discharged over the end of the screens. This can result in poor hole 

cleaning and slower ROPs. 

By monitoring the SCE and waste management this will ensure the SCE is being run at optimal 

efficiency, treatment costs should be reduced and unnecessary fluid losses avoided, which will 

ultimately save money. 

An efficient solids control system requires continuous actions and monitoring to ensure a proper 

operation. At a minimum the following actions should be carried out: 

• Adherence to the API R13B rules for solids control systems efficiency determination. 

• Definition of the recommended operational parameters for each piece of equipment for each 

section. This is an expected set of values (i.e. feed rates, dryness, output weights) for each 

piece of solids control equipment and for each section that is at least required to guarantee a 

minimum level of efficiency commensurate with the drilling requirements. These values will 

be decided in conjunction with the parties in charge of their operation. 

• Continuous monitoring of compliance with the recommended parameters. 



REVISION 2006 14-21


• Periodic testing of individual solids control equipment to establish their solids removal 

efficiency, following the API R13C rule. 

Waste Minimization 

In addition to the reduction of the volume of fluids and cuttings, it is also critical to minimize the 

amount of other wastes produced as part of the operation in order to mitigate the environmental 

impact of drilling activities. 

a) Tank cleaning (Rigs, supply boats, onshore tanks). 

• Frequent changes in fluid type carried. 

• Excess residues in tanks as a result of inefficient design. 

• Logistics limitations and poor planning. 

• Limited storage space on rigs, vessels and onshore. 

• Poor practices. 

Tank cleaning of marine vessels, trucks and installation tanks is a major source of waste. Vessel tanks 

are frequently cleaned after each shipment. On many occasions the tank is then refilled with a similar 

product to the previous shipment, making the cleaning operation unnecessary. 

Sharing vessels between operators, who use different base oils, normally necessitates cleaning tanks 

between shipments. Most vessels are not able to dedicate tank space to specific product types, which 

also leads to tank cleaning between shipments. 

Many boat tanks were not designed specifically to carry drilling fluids. In some cases this leads to 

excessive volumes being left in the tanks which become non-recoverable volume that ultimately gets 

included in the waste stream instead of being recovered for use. Most often this can be avoided by 

proper planning. 

b) Slop water 

• Poor drainage design - no segregation of type of fluid rainwater, waste oil etc. all gathered 

into one tank. 

• Large oil / water interfaces when displacing to or from the well. 

When using OBM, all the drains run into a common collection system. This collects all run-off 

including rainwater that may have been contaminated with OBM. The contaminated “slop water” is 

then shipped to shore for processing. Additional contaminated water is generated from vessel tank 

cleaning, cleaning skips and cleaning big bags once the contaminated cuttings have been removed. 

c) Cuttings Transportation Systems 

• Use of skips and big bags leads to extensive cleaning with high associated wastes. 

Many operators currently use big bags and skips to transport OBM cuttings to waste sites for 

disposal. This generates additional waste. Skips can sometimes collect water en route and this water is 

contaminated with oil from the cuttings even if they are in big bags. This water then has to be 

collected and treated. The skip also has oil contamination within it that requires 

cleaning before 

shipment, generating more oily slop waste. 



REVISION 2006 14-22


The big bags when emptied need cleaning before final disposal, again this leads to additional oily slop 

waste. Plus the big bags themselves are an unnecessary waste item. 

d) Packaging 

• Mixing on rigs results in large amount of waste packaging - sacks, drums, plastic wrapping, 

pallets, etc. 

Current drilling fluid practice is to ship many individual components to the installations for fluid 

building and maintenance. Considerable packaging waste is generated in this process. While recent 

advances in offshore plant have made some improvement in this area, there is still excessive 

packaging waste to be disposed of. 

Recommendations to Reduce Surplus Volumes and Wastes at the Rig Site 

The following procedures and actions can be applied to reduce surplus volumes and waste at the rig 

site: 

a) Reviewing the primary solids control equipment and plumbing to identify the best-in-class 

equipment and /or layout for each installation to reduce dilution by removing low gravity solids 

before they become included into the system. This approach will dramatically reduce both the 

volumes of fluids and waste to be handled and subsequently processed. A reduction of more than 

10% in dilution and discharges from this action can be expected. 

b) Ensuring the correct screens are used for each formation encountered considerably reduces the 

number of shaker screens utilised on each well. 

c) The installation and correct use of efficient centrifuges for density reductions will greatly reduce 

the volume of dilution fluid normally used for density decreases. This reduces the need to dump 

or handle excessive volumes. 

d) The use of these recommendations will reduce the cost of building unnecessary fluid for dilution 

and the volume of surplus fluid that would subsequently need to be handled and shipped to shore 

for processing. 

Recommendations to Reduce Surplus Slop Waste at the Rig Site 

a) The preferred approach for handling oil contaminated water is, where ever possible, to reduce 

the unnecessarily excessive volume of clean water that is incorporated into the waste that will be 

shipped for treatment. This may be achieved as follows: 

• Segregate drains that are likely to contain heavy hydrocarbons with minimal water (i.e. crane 

containment, pump, engine and compressor skids) directly to a waste oil containment tank 

and handle separately. 

• Re-route drains from areas that are likely to contain limited hydrocarbons and filter this 

through oil specific filter medium or collect it into a skimmer tank to remove any gravity- 

separated oil prior to discharging or disposal. 

• All drilling package drains (i.e. drill floor, mud treatment areas) should be routed to an OBM 

slop waste storage tank. This slop can then either be shipped to shore for processing or 

processed on site, space and deck load permitting. If an on site process is feasible then the 

concentrated OBM waste could be reused in the system, providing it was contained close to 

or less than the water percentage of the mud system. 

• Use a mud vacuum system to recover all drilling fluid spills back into the active system 

before they enter the drains. This will 

reduce the cost of processing slop waste. 



REVISION 2006 14-23


• Reduce water used for rig washing etc. by limiting the use of water hoses and replacing them 

with a high pressure washer system. This greatly reduces the water that would subsequently 

require processing. 

The main benefits from this approach include: 

• Reducing the required storage for collecting slop for shipping to shore. 

• Reducing the cost to ship, clean tanks and process a product, which is generally ±80% water, 

will offset the cost of implementing these changes. 

Engine Room 

Cranes etc. 

Main Decks 

Rig Floor 

& 

M.P.A. Drains 

Pump Room 

& 

Chem. Store Drains 

Waste Oil 

Container 

Slop 

Storage 

Vacuum 

Unit 

Floc-Tank 

Skimmer 

Tank 

Oily 

Slop Waste 

Oil Specific 

Filter 

Bag filters 

Activated 

Charcoal 

Discharge 

at




REVISION 2006 14-25


WASTE TRANSPORT AND DISPOSAL 

When an operator decides to go to zero discharge, there are two main options for handling the waste, 

either cuttings re-injection or skip and ship. Cuttings re-injection is a very effective disposal option 

that fully complies with zero discharge to the surface environment. It is discussed later in this section. 

When waste is transported from an offshore rig to the shore, there are several equipment options that 

depend upon the infrastructure in the drilling area, the type of final disposal treatment and the 

logistical limitations of the operator. 

Skip & Ship 

Skip & ship: use of cutting boxes that can be easily lifted between the rig and transport vessel and 

from the vessel to shore on to trucks. These containers are built according to marine safety 

specifications and provide an efficient means to transfer waste for long distances. Using sealed 

containers has the following advantages: 

a) The sealed containers are designed to enable them to be stacked on top of each other, thus 

reducing deck space to store them. 

b) The containers are easily handled by offshore cranes making them safer to handle than big 

bags. The containers are designed to DNV standards and can be easily stacked. 

c) Prevents both rain and sea water being incorporated into the waste stream. 

d) Reducing water in the solids waste improves the efficiency of both thermal desorption and 

incineration processes. 

The skips or cutting boxes are usually 

manufactured to hold 12 bbls (1.90 m 3 ) or 25 

bbls (3.81 m 3 ). 

Determining the number of cutting boxes 

required to satisfy the waste transportation 

demands of the operation is very important. Rigs 

have very limited footprint available for storing 

idle equipment and weight limitations per unit of 

area. In addition, transport vessels are expensive 

so an optimum use of their capacity and time is 

important to reduce the waste management cost 

of the project. 

When estimating the number of boxes needed for each section, the following factors have to be taken 

into account: 

- Footage to be drilled in the section - Turnaround time for cutting boxes 

- Hole size - Dry waste density 

- Average footage per day - Drilling fluid density 

- Skip capacity - Oil-water-ratio of the drilling fluid 

- Filling up level of cutting boxes (percentage) - Base oil density 

- Estimated liquid content in the waste 



REVISION 2006 14-26


A simplified version of a cutting box requirements calculator can be found in the toolbox section of 

the BakerHughesDirect website. 

Bulk Transport Systems: These are systems that use larger containers to store and transport the waste 

between the rig and the final disposal site. A loading/unloading system is installed on both ends to 

transfer the waste to the sealed containers. Usually, pneumatic equipment such as blowers (pushing 

action) and vacuum units (pulling action) is employed for this operation. 

Cuttings Fixation 

Cuttings fixation, also known as cuttings stabilization, blends dry material with the moist cuttings to 

achieve bonding and drying. Three materials are commonly used in the blending process; activated 

lime, fly ash, and kiln dust. The availability and cost of the blending material will determine which 

one is the most economical to use, with lime the material of choice. The EPA recognizes that 

activated lime does an excellent job in solidifying non-hazardous waste and recommends it for use in 

oilfield and industrial applications. 

The bonding material is blended with the "cuttings" in ratios that promote stabilization of the wet 

cuttings. The blending process is performed using a pug mill auger and feed hopper, allowing proper 

mixing of the bonding material with the cuttings. This "stabilized" material can then be used as road 

fill, made into bricks for building purposes, or is buried in pits and covered. 

Bioremediation 

Bioremediation uses naturally occurring micro-organisms, such as bacteria, fungi, or yeast to degrade 

harmful chemicals into less toxic or non-toxic compounds. These micro-organisms break down a 

wide variety of organic compounds (hydrocarbons) found in nature and are considered nature's 

recyclers. Certain species of soil bacteria process hydrocarbons as a food source converting the 

contaminants into carbon dioxide, water and fatty acids. 

The micro-organisms are applied to the contaminated soils through tilling or spraying. Nutrients can 

then be added for enhanced activity of the micro-organisms and to promote the biodegradation of the 

hydrocarbons. Third party companies provide the equipment and services for the successful 

bioremediation of hydrocarbon contaminated soil and water. 

Landfarming 

Land farming or land treatment is an economical technique for the mixing of the appropriate type of 

drilling solids and liquids with the soil found at that location. This eliminates the transfer of the waste 

material to another site and typically enhances the soil's productivity. 

Soil samples should be analyzed to determine the condition of the location prior to the drilling 

operation and establish background parameters. During the operation, appropriate drilling wastes can 

be stacked on location or stored in pits, while material containing contaminants such as salt or oil 

should be contained separately. Once drilling operations are complete, the waste material can be 

applied to soil and ploughed until dryness and adequate mixing has occurred. Samples are tested to 

meet the state regulatory requirem ents , i. e. 29-B Louisiana. In some cases, fill material is added to 

meet the state specifications. 



REVISION 2006 14-27


Thermal Treatment 

There are several methods of thermal treatment (desorption) of drilling waste, the most common 

being indirect thermal desorption: 

The externally heated rotary dryer is sealed on either end to limit oxygen entering the system, and 

vapor exiting. The dryer shell heats cuttings to between 600 and 900°F by conductive heat transfer. 

Retention time within the drum varies between 20 and 30 min. to thoroughly heat and vaporize all of 

the liquids. Cleaned cuttings exit as dry, inert dust, and are re-hydrated with water to a manageable 

consistency prior to non-hazardous disposal or use in construction materials, e.g., bricks, road base or 

cover for a sanitary landfill. 

The hot oil and water vapors are filtered through a high-temperature, fabric-filter bag-house for fine 

particulate removal, and subsequently condensed into liquid by means of a shell and tube condenser 

system cooled by a closed-loop cooling tower. The fluid then passes through an oil / water separator 

system, with recovered water used as makeup water for the cooling tower and cuttings re-hydration, 

and recovered oil returned to the client for reuse in the mud system (or other use), with a small 

portion used to fuel the self-contained, thermal-desorption process. 

Air emissions from the system are well below EPA's 1990 Clean Air Act for Particulate Matter, SOx, 

NOx and VOCs, and EPA has designated this type of system as "BDAT" (Best Demonstrated 

Available Technology) for cleanup 

of hydrocarbon-contaminated soils. 



REVISION 2006 14-28


Other Thermal Treatments 

Distillation 

Distillation enables solids and liquids and the different constituents of liquid mixtures to be separated, 

relying on the fact that the constituents of liquid mixtures evaporate at different temperatures. 

Two types of processes are available: 

• Thermo-mechanical conversion and cracking (TCC) where the drill cuttings are subjected to 

distillation/cracking with water and oil being boiled off. In some cases the vapors are 

condensed to allow recovery; 

• Thermal stripping which is carried out a lower temperature. This means the oil is not cracked 

and can be re-used. 

The resulting treated cuttings can potentially be re-used although they may contain elevated 

concentrations of heavy metals and chloride salts. The latter can be removed through chloride 

stripping. 

Solvent Extraction 

Solvent extraction relies on mixing cuttings with a suitable solvent to form a fluid emulsion, which 

can then be distilled to allow separation. There is no thermal damage to the oil, which can therefore 

be re-used. 

Combustion 

Incineration has been used for the disposal of organic waste which is highly toxic, highly flammable 

and/or resistant to biological breakdown. The process normally leaves a solid residue or ash, which 

can be disposed of to landfill. Energy requirements are directly related to water content and therefore 

costs for the incineration of materials such as drill cuttings could be high if the cuttings have a high 

water content. 

Stabilization 

Chemical and physical stabilization can be used to modify the cuttings into a more usable form or into 

less hazardous waste. This can be carried out by solidification, effectively encapsulating the waste 

into a solid mass to minimize the possibility of leaching. Organic polymers or inorganic additives can 

be used to improve the stability of the mass. The main problem with such treatments is that may result 

in the total volume of waste increasing. However, they require minimal energy input and result in 

minimal emissions to air. 

Possible Uses of Waste 

Concrete Products 

Use in the construction industry as a concrete/cement mix aggregate has frequently been touted as a 

suitable reuse option for treated drill cuttings. During this study a number of construction companies 

expressed an interest in using the cuttings in this manner. To identify more precisely which concrete 

products might be suitable, treated drill cuttings were analyzed by the Concrete Technology Unit of 



REVISION 2006 14-29


th e University of Dundee. Preliminary findings found the treated cuttings to be high in chlorides, 

barite and sulfates. High chloride levels make the cuttings unsuitable for steel reinforced concrete. 

Barite is insoluble but also contains toxic elements and this toxicity will necessitate leachate testing of 

concrete products. From these analyses the Concrete Technology Unit suggest that, subject to further 

testing, treated drill cuttings would be appropriate for use as a binder filler with Portland cement, in 

pre-cast units, as an activator or as an aggregate. A cuttings processing facility, in partnership with a 

brick manufacturer, have previously attempted to manufacture bricks from treated cuttings. The first 

batch was successful but the quality of the bricks in the second batch was poor. The problem was 

thought to be in the variability of the cuttings geology found in the second batch of drill cuttings. The 

conclusion to the trial was therefore that given the unpredictable nature of the cuttings feedstock, their 

use in brick manufacture would be impractical. 

Coastal Defense 

The maintenance of coastal integrity is often achieved through the construction of sea walls. The high 

salinity of treated drill cuttings has been identified as a restriction on some possible reuse options. 

Reuse in a saline environment would reduce or remove this restriction. Therefore, use as a concrete 

mix aggregate for sea wall structures is a reuse possibility. However, further research may be required 

to confirm the suitability of treated drill cuttings as a concrete mix aggregate for sea wall structures. 

Land Reclamation 

Land is commonly reclaimed from the sea during the development of coastal regions. This process 

involves the filling of cells previously isolated from the sea with a general fill material. Treated drill 

cuttings have been identified as a possible fill material for such developments. 

Roads and Cycle Paths 

The creation of roads and cycle paths can require a considerable volume of construction material. For 

example, a 5m 2 area of surface construction would require approximately 1.8 tons of cuttings. Road 

and path construction have therefore been identified as possible reuse options for treated cuttings. 

SLOP SEPARATION 

Introduction 

Slops represent a challenging type of waste. They are usually composed of emulsified non-aqueous fluids, 

commercial solids, drill cuttings and fresh or sea water. They are too contaminated to be returned to the drilling 

fluid active system without compromising its performance. Normally they are sent to a disposal site where they 

have to be treated to comply with most environmental regulations around the word. Because of their complex 

composition, slop treatment creates unusually heavy stress on the waste processing systems which are designed 

to deal with one or two contaminants and a relatively stable waste flow. The use of simple technologies to 

separate valuable components before they reach the disposal stage can create important product recycling 

opportunities while reducing negative effects on the environment. 

Benefits of Using Slop Treatment Technology 

• Operator cost for slop treatment greatly reduced 

• Slop treatment is carried out close to where it is generated 



REVISION 2006 14-30


• Improved working environment 

• Reduced CO 2 pollution due to reduced transportation of slops 

• Increased reuse of brine 

• Chemical consumption for treating slop reduced because fluids are separated using 

mechanical methods 

• Regeneration of drilling fluids is made nearer to the user; i.e. on rig 

• Decreased transportation costs 

Equipment Set-Up and Operation 

The fluid being processed consists of oil contaminated brines, seawater, soap, freshwater and water 

generated at the surface from drilling and completion operations. After the shaker screens, the 

decanter unit removes the solids by a mechanical process, exposing the fluid to 3000 G. The fluid is 

then transferred to the separator unit for oil removal. The disc-stack separator unit also uses a 

mechanical process, exposing the fluid to 10,000 G, thereby reducing the oil content to less than 40 

ppm (mg/l). In order to further reduce the oil content of the water to be discharged, a guard filter 

consisting of oil absorbing cartridge filters is installed to polish the fluid after separation. The 

hydrocarbon content is measured before the fluid is reused or discharged to the sea. 

FLUID 

WELL 

TEMP. 

50-60° C 

FROM 

OIL 

BRINE 

COLLECTING 

TANK / PIT 

20°C 

SHAKER 

320 US MESH 

SIZE 

SOLIDS 

TO 

SLUDGE 

TANK 

OIL 

CONTAINER 

Baker 

Separator 

Baker 

Decanter 

SOLIDS 

CONTAINER 

OIL 

ABSORBING 

CARTRIDGE 

FILTERS 

HC > 40 mg/l 

IR 

HYDROCARBON 

HC < 40 mg/l 

REUSE OR 

DISCHARGE 

Figure 14 - 10 Schematic of Set-up of a Typical Slop Treatment Scenario on 

an Offshore Rig 



REVISION 2006 14-31


SEPARA 

DECA 

The sample bottles in the figure above illustrate the process from slop water to discharged water. 

Experienced offshore operators adjust the decanter unit to discharge solids at the most effective cut 

between solids and fluid phase. Once the decanter unit has been correctly set up, the liquid phase can 

go directly into the separator unit for oil separation. Once again an effective cut between the phases 

is essential: At this stage the cut point between the oil and water phases is made as close to the oil 

phase as possible, minimizing the volume of oil waste for disposal. The relatively large fluid volume 

from the clean fluid outlet is discharged to the sea with an oil content less than 40 ppm. The separator 

is capable of processing fluid to an oil-in-water content less than 15 ppm, if necessary. 



REVISION 2006 14-32


Equipment Details 

Brine separator Unit, electric driven, zone II. 

The Baker Hughes Drilling Fluids separator is a non-waste generating brine treating unit, which uses 

internal forces of 10000 G to separate brine / water / oil / sludge / particulates. Conventional methods 

would require large amount of chemicals, manpower and filters to process the same fluid. 

The separator includes a modified disc bowl centrifuge designed to handle brines with a density of up 

to 1.80 SG at a process flow rate of 10 – 15 m 3 / h. The bowl is self-ejecting for automatic removal of 

solids, i.e. the centrifuge is self-cleaning to avoid unnecessary shutdowns. This concept allows 

simultaneous separation of brine, oil and particulates up to 0.5 mm. 



REVISION 2006 14-33


Decanter Unit , CA 458 

FEED 

- Handles up to 60% solids in fluid 

- Uses 3000 G internal forces 

- Field tested weight reduction of drilling 

fluid from 1.65 SG down to 1.24 SG 

- Capacity: 10 - 15 m 3 / hr 

- Dimensions: 4.0 m x 1.2 m x 1.8 m 

- Weight: 4,000 kg 

DISCHARGE 

CLARIFIED LIQUID 

DISCHARGE 

SOLIDS 

Filtration and Separation 

Filtration skid with pump 

Separator 

The filtration skid was developed to handle small volumes of slop water more cost effectively. This 

unit has three filtration pods with the possibility of combining three different types of filters. For 

example: load the first pod with a 50 micron size filter for coarse media, 25 micron filters for medium 

size particles in the second pod and 10 micron filters in the last pod. The last pod can also be used as 

an oil absorbing pod. The first two pods only contain six cartridge filters, so if a small volume of 

drilling fluid is fed accidentally into the unit, only 6 - 12 filters become blocked and need to be 

replaced. The same scenario using a conventional dual filter unit would block 50 - 100 filters. There 



REVISION 2006 14-34


is an integral pump on the skid, which provides the capability of feeding the filters directly from the 

slop holding tanks. 

For small volume applications: 

• Filtration skid for solids and oil removal 

For large volume applications: 

• Filtration skid for solids removal 

• Separator unit for oil removal 

Handling OBM Slops Onshore 

All contaminated water returned to shore for treatment can be transferred to a holding tank for 

analysis. Once the extent of the contamination has been established then appropriate treatment can be 

undertaken. 

The standard cleaning process is to pump the fluid through a mixing tank while injecting a coalescing 

agent. The fluid then flows into a separation flotation tank where the oil is skimmed off and collected 

in a waste oil storage tank. The aqueous phase and settled “oil wet” solids will be passed through a 

D.E. filter press to remove the solids. 

The water collected will be pumped through an oil specific filtration medium and activated charcoal 

filters. The water will then be analyzed to confirm that the oil concentration is


• Does not discharge hydrocarbon waste to the air. 

• Is an inexpensive process, relative to many environmental solutions which are not permanent. 

Downhole cuttings injection technology is used by many operators to dispose of drilled cuttings at the 

rig site. Developing sou nd slurrification and injection meth 

ods has played an important role in 

expanding the utilization of cuttings re-injection. A clear, concise understanding of what happens 

downhole during the cuttings re-injection operation is critical to successfully implementing this 

technology and completing a project successfully. 

Cuttings Slurrification 

Cuttings generated by the drilling operation are removed from the drilling fluid using conventional 

solids control equipment, and then transported to the cuttings slurrification system using blowers, 

vacuums, screw conveyors, and/or slides. When the cuttings reach the CRI system, they are 

transformed (slurrif ied) into pumpable slurry by mixing sea water and/or chemicals with the drilled 

cuttings at approximately a two to one ratio. 

The finer the grinding of the cuttings, the less chemical is needed and the smaller quantities of slurries 

generated per length of hole drilled. While the cuttings/water/chemicals are blended, the cuttings are 

reduced to a predetermined particle size distribution/viscosity by grinding and shearing them with 

specially modified centrifugal pumps, and possibly mills, into a homogeneous mixture. 

The resulting slurry is usually pumped to an additional onboard storage tank prior to either reinjection 

back into the formation (as explained below) or for pumping to a stand-by vessel for onward 

shipment to a dedicated intra-field injection platform/rig. There it is usually reduced in viscosity and 

then re-injected back into the dedicated well and formation. 

Injection Theory 

Complex modeling techniques have been created to establish fracturing parameters for increased 

hydrocarbon production in tight and porous, brittle and ductile formations. These models have 

proven to work well as a guide for CRI services. 

To utilize the fracture models, an experienced CRI subsurface engineer must temper the fracture 

design with cuttings injection experience to adequately judge how the formations are impacted by 

injection operations. This is due to CRI consisting of a different set of parameters than those that the 

fracture models were designed for. The fracture models for hydrocarbon simulation are designed for: 

• High rates of injection to prevent sand-out. 

• Injection with specific brittle particles that are large when compared to cuttings slurry 

particles 

• No distribution of particle size. 

• High fluid horsepower at the formation face. 

• Short duration pumping. 

• Slurry rheological properties that have low fluid loss and are ultimately designed to create the 

maximum fracture that can be obtained. 

Disposal of cutting slurries is exactly the opposite: 



REVISION 2006 14-36


• Particles are small in size, soft/ductile in nature. 

• Pumped at low rates for long periods of time. 

• Purposely designed to keep the fluid horsepower low. 

• Generally high in fluid loss. 

• Designed to impact the formation minimally - large fractures are not desired. 

Injection Process 

A fter a homogeneous slurry is prepared and conditioned to site specific properties, the cuttings slurry 

is then injected through a dedicated conduit, such as the annular space between two strings of casing 

(annular injection) into the exposed formation. The cutting slurries are pumped at planned rates into 


When the pressure increase resulting from the pumping operation exceeds the strength of the exposed 

formation rock and the natural pore pressure, the formation allows the cutting slurries to flow into the 

formation. If the rheology/physical properties and pumping methods are correct, the formation will 

safely hold large amounts of cuttings. 

Operating Considerations 

A variety of operational details must be dealt with to properly plan the project. Successful operations 

dictate that the majority of the work is done in the planning stage. Some of the details include: 

• Identifying suitable cuttings disposal/sealing formations. 

• Selecting surface equipment. 

• Designing the casing programs. 

• Designing the injection programs and contingency planning. 

• Plug prevention in the annulus and the formation. 

• Preventing cutting slurries from breaching to the surface or contaminating potable water 

zones. 

• The impact on existing producing wells or future wells to be drilled. 

• Quality control/monitoring of injection procedures 

• Abandonment of waste disposed to permanently entomb the waste. 

• Obtaining regulatory approval. 

Characteristics of the subsurface environment, sealing formations, injection zone, slurry properties, 

drilling plans, subsurface slurry disposal dimensions and other elements directly impact each of these 

operational considerations. Of the various technical details that must be evaluated, the least 

understood but of equal importance, are those questions associated with downhole considerations: 

• Into what formation can the cuttings slurry be injected? 

• How will the cuttings slurry be contained? 

• In what direction will the cuttings slurry propagate? And how 

far? 



REVISION 2006 14-37


• How significant an impact will the cuttings slurry have on nearby wellbores/formations? 

• How will the cuttings slurry affect existing wells and future drilling plans? 

• What volume of cuttings slurry can be safely disposed of? 

• What forces will be put on the well casing? 

• How can the cuttings slurries be injected in order to minimize formation impact? 

• How can the annulus and the formation be protected? 

• When the formation changes, what does the CRI operator do next? 

Lithology Concerns 

An accurate description of the various lithologies and the transition depths from one lithology to 

another is integral in determining where injection of the cuttings slurry should take place. 

The disposal formation must be able to readily accept the cuttings slurry, and must also be massive 

enough to accommodate the volume of cuttings produced. 

The target formation should not contain natural fractures or faults that might communicate the slurry 

to the surface or to formations containing potable water. Additionally, the disposal formation must be 

associated with some type of seal mechanism that will adequately restrict the slurry to the specified 

formation interval. 

A review of mechanical property logs, cores, leak off tests, pore pressures, mud logs and other data 

from offset wells is a very useful tool when addressing these issues. Fracture modeling, although 

currently designed for hydrocarbon stimulation operations, has proven useful for estimating the size 

and shape of the disposal plumes. 

Seismic data can be utilized for identification of natural vertical fracturing that could make the project 

fail and can be utilized to define the formation properties, such as fracture pressures, pore pressures, 

and other elements crucial to CRI. 

Surface Equipment Requirements 

The type of surface equipment required to process the drilled cuttings is based on a number of 

parameters established after addressing downhole considerations. The properties of the drill cuttings 

dictate the type of grinding equipment required. Modified centrifugal pumps designed to reduce the 

size of the cuttings using high shear rates are most effective when processing cuttings from soft, 

hydratable shale formations. All modified centrifugal pumps are not the same. In those instances 

where a sizable quantity of hard cuttings will be processed, the use of a mechanical grinder should be 

considered. 

Proven equipment durability, manpower, requirements, utilities, ease of installation/time requirements 

and contingency plans must all be considered when designing the surface equipment system. Proper 

system design is important since any downtime for repairs or maintenance directly impacts the 

drilling process. In zero discharge operations, the rig cannot drill if the CRI surface equipment is not 

adequately designed and installed to stay ahead of the drill rate/surge conditions. The costs 

associated with CRI increases rapidly when the drilling 

progress is negatively impacted. 



REVISION 2006 14-38


Casing Program 

The casing program is developed once the injection zone and sealing formations have been identified. 

The cement integrity of the surface casing defines the upper sealing boundary of the injection zone 

and the top of cement for the intermediate casing string provides the lower boundary. 

It should be borne in mind that the injection plume takes the path of the least resistance, and 

ac cordingly, will likely be initiated at the casing shoe and could grow vertically upward and outward 

from that point, depending on a variety of conditions. For this reason, the casing shoe needs to be set 

at an adequate depth below the top of the specified injection zone. 

In theory, the height of the top of the cement for the intermediate casing string is planned such as to 

make certain that the length of exposed formation will allow for desired downward fracture growth. 

Experience in designing the subsurface injection profile and related casing/cement programs is 

paramount to successfully implement the technology. To ignore the required engineering experience 

and judgment in this phase of the operation and in later evaluation of formation changes will result in 

failure. 

Monitoring Procedures 

No matter how well the project is planned there is always the possibility of a breakdown which may 

result in disposal failure. Negative impacts on the existing drilling program, on future wells and to the 

environment are risked if proper quality control of the slurry and the surface operation is not 

maintained. The quality control procedures should monitor, at minimum, the following: 

• Pressure impact on nearby wells. 

• Disposal plumes, direction and location. 

• Injection rate, total volume and pressure. 

• Disposal slurry properties, density, funnel viscosity, rheological properties and particle size. 

• Equipment condition. 

• Experience level of operators/management. 

In many cases, a meeting with the appropriate regulatory agencies will not be necessary, but adequate 

communication is always crucial to gaining the agency’s understanding and approval. Obtaining early 

regulatory input has two primary advantages: 

• Allows the operator to comply with pertinent regulations. 

• Provides the operator with an opportunity to hear concerns of regulatory personnel so that 

special needs can be addressed and appropriate changes made to the work plan. 

Early dialogue makes it possible to resolve concerns and issues while developing the cuttings 

injection plan. 



REVISION 2006 14-39


Main Components of CRI System 

COMPONENT 

FUNCTION 

OPERATED / 

MONITORED BY 

Cu ttings Screw Conveyor Transport cuttings from shakers to CRI Slurry FES Engineer / 

Tank 

Drilling Crew 

Optional Vacuum System Transport cuttings from shakers to CRI Slurry FES Engineer / 

Continuous Discharge Tank 


Vacuum Hopper 

CRI Slurry Tank Mix cuttings with seawater and reduce to a FES Engineer 

controlled slurry 

CRI Seawater Supply Seawater used to produce slurry FES Engineer 

CRI Classification Shaker Control slurry particle size to D90, 300 microns FES Engineer 

CRI Roller Mill Aid breakdown of hard rock and cemented sands FES Engineer 

CR I Holding Tank Temporary storage of classified slurry to allow FES Engineer 

control of viscosity prior to re-injection 

CRI HP Injection Pump Injection of slurry from holding tank into annulus FES Engineer 

of injection well 

CRI Slurry Injection Line Dedicated line to selected re-injection well FES Engineer / 


Injection Well Annulus & Act as conduit for slurry from surface to FES Engineer / 

Formation formations below the shoe Drilling Crew 

Charge Pump 

Provides sufficient suction pressure to the high 

pressure pump 

FES Engineer 

Cuttings Slurrification Package 

FEATURES 

• Designed to DNV 2-7-1 and DNV Certified 

• Zone 1 rated 

• Two lift system for quick mechanical and electrical installation 

• Agitated tanks 

• Adjustable jet / impingement nozzles and wear plates fitted to the slurry tank 

• 30% increase in holding tank capacity 

• Overflow from holding tank to slurry tank 



REVISION 2006 14-40


• Manual handling assessments on all equipment 

• Positive valve isolations on tanks 

• 100% contingency 

• Provision for additional grinding pumps 

• Flexibility to suit all cuttings transfer systems i.e. slurry flush, auger, vacuum 

• Meets offshore noise test requirements 



REVISION 2006 14-41


PROCESSING TIME 

2 x Grinder Pumps 

Slurry BBLs Out Drill Rate 

Hole 

4 x Grinder Pumps 

Section Drill Rate BBLs Slurry 



REVISION 2006 14-42


Generation Per Hour Ft/hr 

Ft/hr Out Per Generation 

Per Hour 

(3:1) 

Hour Per Hour 

(3:1) 

100 17 ½” 150 

120 30 

120 16” 180 

210 12 ¼” 310 

45 180 

350 + 8 ½” 350 + 

= 2 Bbl/min = 3 Bbl/min 



REVISION 2006 14-43


DIMENSIONS AND WEIGHTS 

Item 

1 

2 

Description 

Dimensions (m) 

L x W X H 

Dry Weight (kg) 

Slurry Package ‘Lift’ 

Slurry Tank 8.0m 3 5.8 x 2.9 x 3.5 13,800 

Holding Tank 11.0m 3 

Shaker and Roller Mill 

Package ‘Lift’ 

Operating Weight 

(kg) 

24,700 kg When full 

of 1.3 sg fluid 

2.7 x 1.7 x 2.1 3,500 NA 

3 Handrails and Davit To suit 2,500 NA 

Total 

Combined Package 

Assembly on Rig 

Including Access 

Platforms and 

Handrails 

5.8 x 4.7 x 5.6 19,800 44,500 

ELECTRICAL POWER REQUIREMENTS 

(440 Volts ± 10%, 3 phase, 60 Hz, EExde IIC T4, IP56) 

1 Grinder Pump Motor No:1 CD250M-4 64-kW 




1 Charge Pump CD180L-4 26-kW 

1 Slurry Tank Agitator Motor CD132M-4 8.5-kW 

1 Holding Tank Agitator Motor CD132M-4 8.5-kW 

1 Roller Mill Hydraulic Power Pack Motor CD132M-4 8.5-kW 

1 Classification Shaker Motor CD112M-4 4.8-kW 

Total Installed Power 

313-kW 



REVISION 2006 14-44


DIESEL IN JECTION PUMP 

Description 

Zone Two High Pressure Pumping Unit. 

Environmental 

Fully soundproofed to 80dB(A) and built to the highest standards and current legislation. Engine 

meets the required emission controls and legislation including. IMO Marpol 73/78 Annex VI – 

Regulations for the Prevention of Air Pollution from Ships (NOx Technical Code) 

Engine 

Detroit 60 Series, 600BHP, 530 – 580 HHP MAX 

Fuel Consumption 

31.1 gallons per hour under full load 

Fuel Capacity: 600 liters 

Centrifugal Pump 

4” x 3” x 13” c/w mechanical seal 

Maximum head 120 psi. 

Suction – 4” 

Triplex Pump 

4” Fluid End 

Maximum Pump Rate – 9 BPM 

Maximum Pump Pressure – 8000 PSI 



REVISION 2006 14-45


Discharge – 2” 

Alternative Fluid Ends available 

Control Panel 

Engraved stainless steel control panel giving central control and visual display of rates, pressures etc. 

Safety 

Built to the new ATEX directive (equipment and protection systems intended for use in potentially 

explosive atmospheres). Emergency stop, fuel stop, fail safe system. Platform control shut downs 

available pneumatic or electric. Designed and manufactured in accordance with the current DCR 

regulations. 

Certification 

Certified to allow the duty holder to demonstrate compliance with the requirements of SI 913. 

Dimensions 

En gine Skid 4571mm (L) X 2438mm (D) X 2820mm (H) 

Pump Skid 2438mm (L) X 2438mm (D) X 2820mm (H) 

Combined 7009mm (L) X 2438mm (D) X 2820mm (H) 

Weight Data 

Engine Skid Gross Weight: 14,000 kg 

Pump Skid Gross Weight: 8,000 kg 

ELECTRICALLY DRIVEN INJECTION PUMP 

Description 

Zone 1, High pressure pumping unit with variable speed inverter drive. 



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Environmental 

Acoustically clad to reduce noise levels to 78dbA. Zero atmospheric emissions. 

Triplex pump 

Maximum pumping rate 3.15 bbl/min at 2500psi. 

Maximum pressure 5000psi at 26 gpm 

Controls 

Remote control from operator station with local maintenance control panel. 

Safety 

Built to the new ATEX directive, can be tied in with platform shut down controls. 

Dimensions 

Length 

Width 

Height 

3600mm 

2062mm 

2220mm 

Weight 

Total Gross Weight: 8,000 kg 

Includes 

• Safe area variable speed inverter drive. (Zone 1 enclosure available as option). 

• Zone 1 operator’s panel. 

• Noise hood. 



REVISION 2006 14-47


• High and low pressure dampers. 

• Anti vibration mounts 

• Relief valve PED compliant. 

• Lifting beam and sling set. 

• Suction and discharge pressure transducers. 



REVISION 2006 14-48


DATA ACQUISITION LOGGER 

Features 

• Zone 1 Rated 

• Explosion Proof 

• Safety Shutdown 

• Reads: 

• Pressures 

• Tank Levels 

• Amps 

• Adjacent well pressures 

• Pump strokes 

• Pump rate (bbls) 

• Total Volumes (bbls) 



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CUTTINGS INJECTION OVERVIEW 

BAKER HUGHES DRILLING FLUIDS TRAINING MANUAL 

REVISION 2006 14-50


TRANSF ER OPT ION 1 – SLURRY FLUSH 


REVISION 2006 14-51


TRANSFER OPTION 2 –CONVEYOR 


REVISION 2006 14-52


TRANSFER OPTION 3 –VACUUM 


REVISION 2006 14-53

FLUIDS 

ENVIRONMENTAL SERVICES 

TRANSFER OPTION 4 –DENSE PHASE BLOWER 


REVISION 2006 14-54


CUTTINGS DRYER 

With waste reduction at source a major part of any drilling operation Baker Hughes Drilling Fluids 

FES provides cuttings dryers to reduce the volume of the drill cuttings waste being generated at the 

rig site. The cuttings dryer should be positioned down stream of the rig’s solids control equipment 

prior to discharge into onboard containment equipment. The Typhoon Dryer is a high capacity 

vertical centrifuge with a rotating cone - complete with spiral flights. On entering the cone 

laundering area the cuttings are forced against a fixed screen/basket by the centrifugal action, this 

separates the bulk of the fluids from the solids into two phases. The solids phase continues through 

the dryer and self discharges into a skip/box/conveyance below with the liquid phase draining to the 

feed tank. The fluid phase is normally returned to the drilling fluid tanks after being centrifuged. 

Features 

• Low Profile-Space Saver 

• OOC


Typical Cuttings Dryer Arrangements 

BAKER HUGHES DRILLING FLUIDS REFERENCE MANUAL 

REVISION 2006 14-50



REVISION 2006 14-51



REVISION 2006 14-52


FILTRATION SERVICES 

Baker Hughes Drilling Fluids FES is capable of providing filtration equipment, personnel and 

consumables to perform the following operations. 

• Filtration of wellbore clean-up returns 

• Filtration of sand control gravel-pack carrier fluids 

• Well test produced water treatment 

• Filtration of injection water 

• Mud pit cleaning 

• Fluid analysis (solids and oil-in-water) 

Filtration of Wellbore Clean-up Returns 

Filtration equipment and procedures planning for a wellbore clean-up depends on many variables 

including the type of drilling fluid, level of cleanliness required, space limitations and the completion 

fluid type. BHDF FES provides different package options to suit the customer ranging from a single 

cartridge filter unit using filter elements to a twin filter press package using diatomaceous earth filter 

media. Expected flow rates, flow duration and solids loadings all have different impacts on the type 

of equipment chosen. 

During the completions planning stages, BHDF FES will obtain the maximum amount of information 

so as to recommend the most suitable filtration system for the job, e.g. generally BHDF FES would 

recommend cartridge units for filtration (polishing) of relatively clean fluids whereas a filter press 

system would be recommended for dealing with fluids with higher solids contamination. 

Filtration of Gravel Pack Carrier Fluids 

Gravel pack carrier fluids need to be filtered to a high specification due to the potential of causing 

solids entrapment within the gravel and the near wellbore formation area. Almost all gravel pack 

filtration equipment consists of a twin filter press package in order to ensure a constant supply of 

filtered fluid with 90% by volume of all solids remaining being below 10micron. 

Produced Water Treatment 

BHDF FES experience includes filtering oily water during well testing, platform decommissioning, 

and tanker water discharge. Filtration of produced and oily water typically consists of a three stage 

process consisting of gravity separation in a surge tank and then solids removal and oil absorption, 

using special non-leaching absorption filter media in cartridge filter units. The overboard discharge is 

tested for hydrocarbons using the extraction method and an infra-red spectrophotometer. 

Seawater Injection 

During a seawater injectivity test, the requirement for high volumes of polished seawater necessitates 

the use of cartridge filter units due to their ability to polish fluids at high flow rates. Depending on 

the flow rates, one or more cartridge units may be used in parallel. 



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Fluid Analysis 

Analysis of oilfield completion fluids is performed using a variety of equipment including turbidity 

meters, laboratory centrifuges, laser particle counters and infra-red spectrophotometers. BHDF FES 

offshore filtration engineers are all trained in the operation of the above equipment and prepare 

reports required by the operation. 

Waste Water Treatment 

BHDF FES is developing a method for removing solids, hydrocarbons and chemicals from waste 

water contaminated with oil based drilling fluid water so that the water quality will satisfy regulatory 

discharge levels for disposal. The process involves the use of a decanter centrifuge, a high speed disk 

stack centrifuge, settling tanks and fine filtration, whilst testing will include solids, hydrocarbons, 

chemical oxygen demand and pH. 

Filtration Equipment Technical Information 

Diatomaceous Earth Filtration Filter Press Systems 

A diatomaceous earth filter press works on the principle of starting with a significantly large surface 

area onto which a permeable filter cake is built until the internal plate recesses are completely filled 

with the filter cake, at which point the plates are then opened for cleaning of fluids. 

A diatomaceous earth unit usually requires two filtration engineers on any shift to operate but has the 

advantage of being able to filter large volumes of fluids with a high solids loading. The surface areas 

of typical diatomaceous earth units range from 600 sq. ft. to 1200 sq. ft. and in many cases two units 

are used in order to maintain a constant supply of filtered completion fluid. 

The process starts with the filter plate screens being pre-coated in order to build the initial filtration 

surface. The function of the screens is not to act as a filter, but rather to provide a surface onto which 

a pre-coat cake of diatomaceous earth may be built. The pre-coat, consisting of a diatomaceous earth 

slurry is circulated through the filter press via a separate tank (slurry tank) until the diatomaceous 

earth is retained on the screens and the base fluid begins to return to the slurry tank in a clear state. 

Once complete (usually around 5-10 minutes), the filter press is ready to receive the feed of dirty 

fluid for filtration. 

The solids typically found in completion fluids are barite and clay which can build up a nonpermeable 

cake and blind the filter press screens very quickly. In order to counter this effect, a 

volume of body feed or diatomaceous earth slurry is also injected into the dirty fluid upstream of the 

filter press so that the filter cake maintains a level of permeability. The quantity of body feed is 

adjusted according to the level of solids in the feed fluid. 

The higher the solids in the feed, the more body feed required to maintain the permeability. The 

importance of a good pre-coat and body feed cannot be over emphasized, and becomes very apparent 

when a badly prepared filter press is prematurely blocked at a critical time during a gravel pack or 

wellbore clean-up job. A good pre-coat prevents the barite and clays from coming into contact with 

the screens, and enables the cake to be removed easily when cleaning. When used correctly, 

diatomaceous earth filtration systems are the best choice for wellbore clean-up and gravel packing 

jobs. 

• Used for brine filtration with heavy barite or clay solids loadings. 



REVISION 2006 14-54


• Can convert highly contaminated fluids to clear fluids efficiently. 

• Economic first pass filtration for high volumes. 

• Used in conjunction with downstream cartridge type ‘polishing’ unit. 

Filter Press Unit 

Technical Specifications 

DNV 2.7-1 Certified Lifting Frame 

Si ze of plates 

1200mm x 1200mm 

Surface area 

up to 1200 sq ft 

Number of plates 36 - 48 

Inlet 

4 inch 

Outlet 

4 inch 

D imensions and Weight 4.8m x 1.6m x 2.2m 

Weight 

8,000kg 

Flow Capacity 

2 to 12 bbl/min (depending on feed pressure and feed quality) 

Maximum Working Pressure 7 bar 

Utility requirements 

Rig air (for opening and closing ram) 

Rig feed Pump. 

Integrated Pre-Coat Slurry Mixing Tank 

Pre-coating a Filter Press 



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A typical 1000 sq ft filter press uses approximately 85 kg of D.E. to produce a 3mm pre-coat on the 

internal screens. To ensure that the pre-coat solids form a uniform cake on the plate screens, the filter 

press is circulated with diluted pre-coat slurry before introducing the balance of the diatomaceous 

earth pre-coat solids. The slurry mix tank will circulate to “clear” at the end of the pre-coat cycle 

indicating that all of the diatomaceous earth pre-coat solids have been captured on the filter plate 

screens. 

Body Feed 

The filtration of slurries which contain gelatinous, slimy, and/or compressible solids typically results 

in poor filter performance; e.g. low flow rates, short cycle times, high operating pressures and low 

filter efficiency. The addition of non-compressible solids (Diatomaceous Earth) to the inlet slurry 

being filtered can cancel or significantly reduce these undesirable effects and improve the 

performance level of the filtration operation. A body-feed therefore can be defined as the solids 

which are added to process slurry for the purpose of enhancing the filterability of the slurry. The 

addition of body-feed will change the physical characteristics of the cake solids by increasing its 

permeability (reducing the resistance). The amount of body-feed required cannot be accurately 

predicted due to the many variables involved. A good starting point is to use a 1:1 ratio of body feed 

solids to suspended solids in the feed and then adjust the injection rate of the body feed so as to obtain 

the optimum performance which: 

• Minimizes the initial filter differential pressure. 

• Prevents a rapid increase in the rate of differential pressure. 

• Prevents terminal differential pressure until the filter press plate recesses are fully utilized. 

• Slimy, gelatinous and highly compressible solids (barite and clay) typically require higher 

body-feed addition rates to effect cake permeability. 



REVISION 2006 14-56




V essels & pipework: ASME Div VIII 

Integrated Pre-coat and divert manifolds 

Integrated Hose Basket 

Dimensions 3.8m Long x 1.8m Wide x 1.86m High 

Weight 

5000kg empty (7 500 kg with water) 

Flow Capacity 

Up to 18bbl/min 

Max Working Pressure 

7bar 

Utility requirements 

Rig air 

Pre-coat Pump 

3” Diaphragm 

Body-Feed Pum p 

1.5” Diaphragm 

Powder Hydration Pump 2” Diaphragm 

Inlet 

4 inch 

Outlet 

4 inch 

Reduced hose requirement due to integrated components resulting in a safer working environment. 

Powder Handling System 



REVISION 2006 14-57


Features 

• Internal fluidizing system. 

• Large capacity means no re-filling 

offshore 

• Filtered vent for added personnel 

protection. 

• Pressure relief valve. 



Dimensions 

2.2m x 2.2m x 3.3m High 

Weight Empty 

3100kg 

Load Capacity 

4000kg Diatomaceous Earth 

Gross Weight 

7100kg 

Utility requirements Rig air 

Diatomaceous Earth Filter Medium 



REVISION 2006 14-58


Diatomite is the fossilized remains of microscopic unicellular plants which lived in ancient water 

bodies. It is known for its unique cylindrical geometry; which has high strength, high pore volume 

and low resistance to flow, thereby making it an excellent selection for filtration. 

The filtration of slurries containing gelatinous, slimy, and/or compressible solids (barite and clay) 

typically results in poor filter performance; e.g. low flow rates, short cycle times, high operating 

pressures and low filtration efficiency. The addition of non-compressible and highly permeable solids 

(diatomaceous earth) to the slurry being filtered can cancel or significantly reduce these undesirable 

effects and improve the performance level of the filtration operation. 

The addition of diatomaceous earth to the slurry being filtered will alter the physical characteristics of 

the formed cake solids by increasing its permeability and reducing the resistan ce to the flow of the 

fluid. 

Typical dose rates (guideline): 

Pre-coating: 1 kg per square meter of filter plate screen. 

e.g. 1200 sq meter = 120kg diatomaceous earth. 

Body-feed: 1:1 (or more) volume ratio of diatomaceous earth to solids in slurry being filtered. 

Highly compressible solids ( barites and clay) typically require higher body-feed addition rates to 

affect cake permeability. 



REVISION 2006 14-59


Cartridge Filtration Unit 

Mainly used for polishing new brines and filtering seawater and fresh water. By using absolute rated 

filter elements a guaranteed cut in the ‘size’ of the contaminating particle is achieved. The maximum 

flow rate through each of these units is 18 barrels/minute and for this reason, they are usually 

considered as the first option when planning completion fluid filtration. The cartridge unit is easy to 

operate and only requires one operator per shift. Fluids that are heavily contaminated with soft 

compressible solids like barite and clay (which have a low permeability when compacted) tend to 

block the elements very quickly resulting in numerous and costly change-outs. They are also 

installed downstream of a diatomaceous earth filtration system and fitted with 2 micron absolute filter 

elements in order to provide a final polish. These robust units are widely used in the oilfield industry 

and require little maintenance. 

• Variety of cartridge types and ratings available. 

• Can filter brine, acid, diesel, gels. 

• Best suited to relatively clean fluids like seawater or pre-filtered brine. 



CE Pressure Equipment Directive 

Number of cartridges 

50 

Cartridge type 

63mm x 

1000mm 

Tank diameter 

600mm 

Material 

stainless steel 

Maximum working pressure 7 bar 

Design temperature 

100 o C 

Design code ASME VIII div. 1 

Interconnecting pipework 4” serial / parallel / bypass 

Drain 

1” pipework flange terminated 

Standard gauges 

in/outlet 0-160psi 

Weight (empty) 1700 kg 

Dimensions 

2100mm x 1150mm x 2200mm 



REVISION 2006 14-60


Absolute Rated Pleated Filter Elements 

A beta 5000 absolute rated range of highly efficient, 

cost effective pleated process filters. Elements are 

manufactured in accordance with ISO 9002 using the 

highest quality materials where applicable. 

Absolute cartridges are available in a wide range of 

micron ratings extending from 2 microns to 100 

microns as measured by the industry standard OSU F2 

particle challenge test, using fine/coarse A.C. test dust. 

Higher temperatures and differential pressures can be 

accommodated using stainless steel cores and end 

caps. 


Filter media 

Core material 

Dimensions (approx) 

Seal material 

End details 

Single closed end, single open end type 222 fitting. 

Micron ratings 2, 5, 10, 20, 50 & 100 (absolute) 

Recommended Operating Conditions 

Maximum temperature 

Maximum flow rate 

Absolute Rated Pleated Filter Elements 

65ºC @ 20psid. 

The diameter of the largest, hard, non-deformed particle which will pass through a filter medium 

under specific test conditions, verified using automatic particle counters upstream and downstream of 

the filter under test. Absolute filters are utilized in critical applications where guarantee of filtrate 

quality is required at all times throughout the life of the filter. They have a higher unit cost than their 

nominal counterparts. Absolute rated filters are often used in combination with nominal rated filters 

to optimize economics and filtration efficiency e.g. absolute rated cartridge filters downstream of a 

diatomaceous earth filter press. 

Nominal Rated Wound Filter Elements 

Glass fiber/Polyester 

Polypropylene 

Diameter 63mm, length 1000mm 

Buna O-Ring 

Maximum change out differential pressure 4 bar 

4m 3 /hour per 1000mm element. 

A less defined rating, which is usually expressed as a percentage removal efficiency at a given 

particle size (90%) removal of particles of 5 microns and above, nominal rated filters are generally 

used as “bulk” solids removal filters or as cost effective pre-filtration to absolute filters. Nominal 

rated filters are normally not given a true removal rate as their efficiency will vary through the life of 

the filter cycle, e.g. the efficiency will increase if a uniform cake of debris is built up on the upstream 



REVISION 2006 14-61


surface, or conversely the efficiency will decrease if the filter media flexes under the build up of 

differential pressure and the release of captured debris takes place. 

Hydrocarbon Absorption Filter Elements 

Hydrocarbon absorption filters are made of treated polypropylenes or polymers and are modified so 

that they chemically bond to hydrocarbons. Some of these filters will begin to release the 

hydrocarbons once they are saturated, while others will absorb the hydrocarbons into the polymeric 

structure until they solidify and prevent any further flow through the filters. 

Analysis Equipment 

Turbidity (NTU) Turbidity Meters 

The Portable Turbidity Meter operates on the nephelometric principle of turbidity measurement. The optical 

system includes a tungsten-filament lamp, a 90 0 detector to monitor scattered light and a transmitted light 

detector. The instrument’s microprocessor calculates the ratio of the signals from the 90 0 and transmitted light 

detectors. The ratio technique corrects for interferences from color and compensates for fluctuations in lamp 

intensity, providing long term calibration stability. 

A turbidity Meter is used to measure the level of turbidity or cloudiness of a fluid. The readings will 

not give any indication of what is causing the fluid to be turbid, however it can be concluded that a 

high reading warrants further testing using more sophisticated equipment. The turbidity meter is a 

useful tool for quick analysis and should only be used to provide an indication of changing 

cleanliness rather than a conclusion that the fluid is within the cleanliness specification required. 

Percent Solids Laboratory Centrifuge 

The electric bench top centrifuge is used to provide a visual assessment of the amount of particulate in the fluid. 

They are best suited to measuring solids or oil in heavily contaminated fluids as the final readings are taken 

visually and are useful when determining the solids content trend during a wellbore clean-up. The laboratory 

centrifuge is also relatively easy to operate and requires no more than a 5 minute spin cycle to determine a 

reasonably accurate reading. A 100ml sample is poured into a glass vial that is placed in a counter balanced 

receptacle where it is spun at speed creating high gravitational forces that separate the different constituents by 

their densities e.g. oils to the top, water or brine in the middle and solids at the bottom of the glass vial. The 

glass vial is calibrated so that the user can determine the level of contamination as a percentage of the total 

volume tested. 

Particle Counting and Size Distribution Laser Analyzers 

A laser particle analyzer is used to count the number of particles in filtered fluids within pre-set size 

bands ranging from 2 microns to 200 microns. These units are best suited for measuring particles in 

filtered fluids if accurate readings a re to be achieved. Unfiltered fluids can cause blockages in the 

internal components of thes e instruments. 

During well stimulation work and gravel packing the requirement is normally for a pre-filtered fluid 

that is filtered to 2 micron absolute with 99.9% removal efficiency. 

A laser analyzer is sensitive enough to measure the 

will print the readings for future safekeeping. 

remaining particles at various micron sizes and 



REVISION 2006 14-62

Chapter 

Fifteen 

Glossary of Terms 

Glossary of Terms

GLOSSARY OF TERMS 

Chapter 15 


The following is a glossary of terms associated with the drilling and development of wellbores. 

Absorption - The penetration or apparent disappearance of molecules or ions of one or more 

substances into the interior of a solid or liquid. For example, in hydrated bentonite, the planar water 

that is held between the mica-like layers is the result of absorption. 

Abnormal Pressure - A subsurface condition in which the pore pressure of a geologic formation 

exceeds or is less than the expected, or normal, formation pressure. When impermeable rocks 

such as shales are compacted rapidly, their pore fluids cannot always escape and must then support 

the total overlying rock column, leading to abnormally high formation pressures. Excess pressure, 

called overpressure or geopressure, can cause a well to blow out or become uncontrollable during 

drilling. Severe under-pressure can cause the drillpipe to stick to the under-pressured formation. 

Acid - Any chemical compound containing hydrogen capable of being replaced by positive elements 

or radicals to form salts. In terms of the dissociation theory, it is a compound which, on dissociation 

in solution, yields excess hydrogen ions. Acids lower the pH. Examples of acids or acidic substances 

are hydrochloric acid, tannic acid, and sodium acid pyrophosphate. 

Acidity - The relative acid strength of liquids as measured by pH. A pH value below 7. See pH. 

Accretion - The mechanism by which partially hydrated cuttings stick to parts of the bottomhole 

assembly and accumulate as a compacted, layered deposit. 

Acid Gas - A gas that can form acidic solutions when mixed with water. The most common acid 

gases are hydrogen sulfide [H 2 S] and carbon dioxide [CO 2 ] gases. Both gases cause corrosion; 

hydrogen sulfide is extremely poisonous. Hydrogen sulfide and carbon dioxide gases are obtained 

after a sweetening process applied to a sour gas. 

Adhesion - The force which holds together unlike molecules. 

Adsorption - A surface phenomenon exhibited by a solid (adsorbent) to hold or concentrate gases, 

liquids, or dissolved substances (adsorptive) upon its surface, a property due to adhesion. For 

example, water held to the outside surface of hydrated bentonite is Silicate or water. 



REVISION 2006 15-1


Aeration - The technique of injecting air or gas at controlled rates into a drilling fluid for the purpose 

of reducing hydrostatic head. Compare Air Cutting. 

Aerobic - Referring to a condition or a situation in which free oxygen exists in an environment. 

Agglomerate - The larger groups of individual particles usually originating in sieving or drying 

operations. 

Agglomeration - The grouping of individual particles. The formation of groups or clusters of 

particles (aggregates) in a fluid. In water or in water-base mud, clay particles form aggregates in a 

dehydrated, face-to-face configuration. This occurs after a massive influx of hardness ions into 

freshwater mud or during changeover to a lime mud or gyp mud. Aggregation results in drastic 

reductions in plastic viscosity, yield point and gel strength. It is part of wastewater cleanup and 

water clarification. Alum or polymers cause colloidal particles to aggregate, allowing easier 

separation. 

Aggregate - A group of two or more individual particles held together by strong forces. Aggregates 

are stable to normal stirring, shaking, or handling as powder or a suspension. They may be broken by 

drastic treatment such as ball milling a powder or by shearing a suspension. 

Aggregation - Formation of aggregates. In drilling fluids, aggregation results in the stacking of the 

clay platelets face to face. The viscosity and gel strength decrease in consequence. 

Air Cutting - The inadvertent mechanical incorporation and dispersion of air into a drilling-fluid 

system. Compare Aeration. 

Air Drilling - A drilling technique whereby gases (typically compressed air or nitrogen) are used to 

cool the drill bit and lift cuttings out of the wellbore, instead of the more conventional use of liquids. 

The advantages of air drilling are that it is usually much faster than drilling with liquids and it may 

eliminate lost circulation problems. The disadvantages are the inability to control the influx of 

formation fluids into the wellbore and the destabilization of the borehole wall in the absence of the 

wellbore pressure typically provided by liquids. 

Alkali - Any compound having marked basic properties. See Base. 

Alkalinity - The combining power of a base measured by the maximum number of equivalents of an 

acid with which it can react to form a salt. In water analysis, it represents the carbonates, bicarbonates 

hydroxides, and occasionally the borates, silicates, and phosphates in the water. It is determined by 

titration with standard acid to certain datum points. See API RP 13B* for specific directions for 

determination of phenolphthalein (Pf) and methyl orange (Mf) alkalinities of the filtrate in drilling 

fluids and the alkalinity of the fluid itself (Pm)' Also see Pf, Mf, and Pm. 



REVISION 2006 15-2


Aluminum Stearate - An aluminum salt of stearic acid used as a defoamer. See Stearate. 

Amorphous - The property of a solid substance which does not crystallize and is without any 

definite characteristic shape. 

Analysis, Fluid - Examination and testing of the drilling fluid to determine its physical and chemical 

properties and condition. 

Anhydrite - See Calcium Sulfate. Anhydrite is often encountered while drilling. It may occur as thin 

stringers or massive formations. 

Anhydrous - Without water. 

Anaerobic - Pertaining to systems, reactions or life processes of species, such as bacteria, in which 

atmospheric oxygen is not present or not required for survival. 

Aniline Point - The lowest temperature at which equal volumes of freshly distilled aniline and oil 

which is being tested are completely miscible. This test reveals the cyclic compound characteristics 

of an oil (naphthenic, asphaltic, aromatic, mid-continent, etc.) of the oil. The aniline point of diesels 

or crude oils used in drilling fluid is also an indication of the deteriorating effect these materials may 

have on natural or synthetic rubber. The lower the aniline point of an oil the more severe it usually is 

in damaging rubber parts. 

Anion - A negatively charged atom or radical, such as CI¯, OH¯, S0 4 = etc., in solution of an 

electrolyte. Anions move toward the cathode (positive electrode) under the influence of an electrical 

potential. 

Annular Velocity - The velocity of a fluid moving in an annulus of specific dimensions. 

Annulus or Annular Space - The space between the drillstring and the wall of the hole or casing. 

Annular Flow – The flow of fluids in the annulus or annular space. The rate of flow in the annulus 

or annular space is commonly expressed in ft/min, or meters/min. 

Antifoam - A substance used to prevent foam by greatly increasing the surface tension. Compare 

Defoamer. 

Anomaly - An entity or property that differs from what is typical or expected, or the measurement of 

the difference between observed and expected values of a physical property. Anomalies can be of 

great interest in hydrocarbon and mineral exploration because they often indicate hydrocarbon 

and mineral prospects and accumulations, such as geologic structures like folds and faults. 



REVISION 2006 15-3


Geochemical anomalies at the surface of the Earth can also indicate an accumulation of 

hydrocarbons at depth. Geophysical anomalies, such as amplitude anomalies in seismic data and 

magnetic anomalies in the Earth's crust, can also be associated with hydrocarbon accumulations. 

API - Abbreviation for American Petroleum Institute, a trade association founded in 1919 with 

offices in Washington, DC, USA. The API is sponsored by the oil and gas industry and is recognized 

worldwide. Among its long-term endeavors is the development of standardized testing procedures 

for drilling equipment, drilling fluids and cements, called API Recommended Practices ("RPs"). The 

API licenses the use of its monogram (logo), monitors supplier quality assurance methods and sets 

minimum standards for materials used in drilling and completion operations, called API 

Specifications ("Specs"). The API works in conjunction with the International Standards 

Organization (ISO). 

API Gravity - The gravity (weight per unit volume) of crude oil or other related fluids as measured 

by a system recommended by the American Petroleum Institute. It is related to specific gravity by the 

following formula: 

Deg API 

= 

141.5 

−131.5 

Specific Gravity 

Apparent Viscosity - The viscosity (shear stress) a fluid appears to have on a given instrument at a 

stated rate of shear (shear stress/shear rate relationship) . It is a function of the Bingham properties 

of plastic viscosity and yield point. The apparent viscosity in centipoises, as determined by the 

direct-indicating viscometer, which is equal to 1/2 of the 600-rpm Fann Viscometer reading. See also 

Viscosity, Plastic Viscosity, and Yield Point. In a Newtonian fluid, the apparent viscosity is 

numerically equal to the plastic viscosity. 

Asphalt - A natural or mechanical mixture of solid or viscous bitumens found in natural beds or 

obtained as a residue from petroleum. Asphalt, blends containing asphalt, and altered asphaltic 

materials (e.g., air-blown, chemically modified, etc.) have been added to certain drilling fluids for 

such varied purposes as a component in oil-base fluids, lost-circulation material, emulsifier, 

fluid-loss-control agent, wall-plastering agent, etc. 

Asphaltenes - Organic materials consisting of aromatic and naphthenic ring compounds containing 

nitrogen, sulfur and oxygen molecules. The asphaltene fraction of crude is defined as the organic part 

of the oil that is not soluble in straight-chain solvents such as pentane or heptane. Asphaltenes exist 

as a colloidal suspension stabilized by resin molecules (aromatic ring systems) in the oil. The 

stability of asphaltic dispersions depends on the ratio of resin to asphaltene molecules. The 

determination of the quantity of resin is important in estimating the potential damage created by 



REVISION 2006 15-4


asphaltenes. Asphaltene precipitates as a result of pressure drop, shear (turbulent flow), acids, 

solution carbon dioxide [CO 2 ], injected condensate, mixing of incompatible crude oils or other 

conditions or materials that break the stability of the asphaltic dispersion. For example, in matrix 

acidizing, iron ions in solution favor the precipitation of asphaltene deposits. 

Attapulgite - A needle-like clay mineral composed of magnesium-aluminum silicate. Major 

deposits occur naturally in Georgia, USA. Attapulgite and sepiolite have similar structures and both 

can be used in salt-water mud to provide low-shear rate viscosity for lifting cuttings out of the 

annulus and for barite suspension. Attapulgite and sepiolite are sometimes called "salt gel," or Salt 

Water Clay. Attapulgite has no capability to control the filtration properties of the mud. For use as 

an oil-mud additive, the clay is coated with quaternary amine, which makes it oil-dispersible and 

provides gel structure but does not improve the filter cake, unlike organophilic bentonite clay. 

Atom - According to the atomic theory, the smallest quantity of an element which is capable of 

existing alone or in combination with electrons. 

Atomic Weight - The relative weight of an atom of an element as compared with the weight of 1 

atom of oxygen, using 16 as the weight of 1 atom of oxygen. 

Bactericide - An additive that kills bacteria. Bactericides are commonly used in water muds 

containing natural starches and gums that are especially vulnerable to bacterial attack. Bactericide 

choices are limited and care must be taken to find those that are effective yet approved by 

governments and by company environmental policy. Bactericides are also called Biocides and can 

be used to control sulfate-reducing bacteria, slime-forming bacteria, iron-oxidizing bacteria and 

bacteria that attacks polymers. 

Balanced-Activity Oil Mud – An oil-base mud in which the activity , or vapor pressure, of the brine 

phase is balanced with that of the formations drilled. Although long shale sections may not have a 

constant value for vapor pressure, a w , the oil mud will adjust osmotically to achieve an “average” a w 

value. Dynamic (autopilot) balance of mud salinity and drilled shales is maintained because as water 

moves into or out of the mud, it also moves out of or into the shale. As water transfer continues 

during drilling, the mud’s water phase will be either diluted or concentrated in CaCl 2 as needed to 

match the average a w value of the shale section and cuttings exposed to the mud. 

Balance, Fluid - A beam-type balance used in determining fluid density. It consists primarily of a 

base, graduated beam, with constant-volume cup, lid, rider, knife edge, and counterweight. 

Barite, Barytes, Heavy Spar Ore - Natural barium sulfate used for increasing the density of drilling 

fluids. If required, it is usually upgraded to a specific gravity of 4.20; an API Standard specification. 

The barite mineral occurs in white, greenish, and reddish ores or crystalline masses. 



REVISION 2006 15-5


Barite Plug - A plug made from barite weighting materials that is placed at the bottom of a wellbore. 

Unlike a cement plug, the settled solids do not set solid, yet a barite plug can provide effective and 

low-cost pressure isolation. A barite plug is relatively easy to remove and is often used as a 

temporary facility for pressure isolation or as a platform enabling the accurate placement of 

treatments above the plug. 

Barite Sag - Terminology used to describe the settling of barite under minimal dynamic conditions 

so as to increase the density of the fluid column on the bottom while the density of fluid at the top of 

the column decreases. The term does not refer to nor does it reflect the hard settling of barite in the 

form of a solid plug. 

Barium Sulfate - BaSO 4 . See Barite. 

Barrel - A volumetric unit of measure used in the petroleum industry consisting of 42 gal (U.S.). 

Barrel Equivalent - A laboratory unit used for evaluating or testing drilling fluids. One gram of 

material, when added to 350 ml of fluid is equivalent to 1 lb of material when added to one 42-gal 

barrel of fluid. 

Base - A compound of a metal, or a metal-like group, with hydrogen and oxygen in the proportion to 

form an OH radical, which ionizes in aqueous solution to yield excess hydroxyl ions. Bases are 

formed when metallic oxides react with water. Bases increase the pH. Examples are caustic soda and 

lime. 

Base Exchange - The replacement of cations associated with the clay surface by those of another 

species, e.g. the conversion of sodium clay to calcium clay. 

Basicity - base pH value above 7. 

Beneficiation - Chemical treatment or mechanical processes that improve a mineral or ore for its 

designed use. For example, barite and bentonite are beneficiated in order to help them meet certain 

specifications for use in drilling fluids. 

Bentonite - A plastic, colloidal clay, largely made up of the mineral sodium montmorillonite, a 

hydrated aluminum silicate. For use in drilling fluids, bentonite has a yield in excess of 85 bbl/ton of 

20 cps viscosity. The generic term "bentonite" is neither an exact mineralogical name, nor is the clay 

of definite mineralogical composition. 

Bioassay - A laboratory test or other assessment utilizing a living organism, such as mysid shrimp, to 

determine the effect of a condition to which the organism is exposed. Such tests are performed under 



REVISION 2006 15-6


controlled environmental conditions and duration. Bioassay tests of drilling fluids are required by 

governmental agencies throughout the world prior to discharge of mud or cuttings. The organisms 

used in bioassays are those found in the area that would be most affected by contact with the 

proposed drilling fluid. The dosage of interest is typically the lethal concentration, known as LC 50 

that will kill 50% of the population of organisms in a given period of time. 

Bicarb - See Sodium Bicarbonate. 

Blooie Line - Flow line for air or gas drilling. 

Blowout - An uncontrolled escape of drilling fluid, gas, oil, or water from the well caused by the 

formation pressure being greater than the hydrostatic head of the fluid in the annulus. A blowout 

may consist of salt water, oil, gas, or a mixture of these. If reservoir fluids flow into another 

formation and do not flow to the surface, the result is called an underground blowout. 

Boiler house - To falsify a report with fictitious data. 

Brackish Water - Water containing low concentrations of chloride regardless of the type soluble 

salt. 

Break Circulation - To initiate movement of the drilling fluid after it has been quiescent in the hole. 

Breakout - A separation of the drilling fluid with a visible layer of liquid on the surface. This is 

applicable in both invert and water based fluids. 

Bridge - An obstruction in a well formed by intrusion of subsurface formations. 

Brine - Water saturated with or containing a high concentration of common salt (sodium chloride); 

hence, any strong saline solution containing such other salts as calcium chloride, zinc chloride, 

calcium nitrate, etc. 

Bromine Value - The number of centigrams of bromine which are absorbed by 1 gram of oil under 

certain conditions. This is a test for the degree of saturation of a given oil. 

Brownian Movement - Continuous, irregular motion exhibited by particles suspended in a liquid or 

gaseous medium, usually as a colloidal dispersion. 

BS or BS & W - Basic sediment, or basic sediment and water. A reference to undesirable sediments 

or water incorporated in produced fluids. 



REVISION 2006 15-7


Buffer - Any substance or combination of substances which, when dissolved in water, produces a 

solution which resists a change in its hydrogen ion concentration upon the addition of acid or base. 

Cable-Tool Drilling - A method of drilling a well by allowing a weighted bit at the bottom of a cable 

to fall against the formation being penetrated. See Rotary Drilling. 

Cake Consistency - According to APIRP 13B. such notations as "hard." "soft." "tough." "rubbery ... 

"firm." etc.. may be used to convey some idea of cake consistency. 

Cake Thickness – The thickness measurement of filter cake deposition by a drilling fluid against a 

porous medium, most often following the standard API filtration test. Cake thickness is usually 

measured in 1/32 of an inch. See-Filter Cake and Wall Cake. 

Calcium - An alkaline earth element with a positive valence of 2 and an atomic weight of about 40. 

Calcium compounds are indigenous to the hardness of water. It is also a component of lime, gypsum, 

limestone, etc. 

Calcium Carbonate - CaCO 3 . A water insoluble, yet acid soluble calcium salt sometimes used as a 

weighting material (limestone, oyster shell, etc.), in specialized drilling fluids. It is also used as a unit 

and/or standard to report hardness. 

Calcium Chloride - CaCI 2 . A hydroscopic salt used in both oil and water based drilling fluids for 

inhibition control. Used in completion fluids for inhibition and to increase the density of clear brines. 

Calcium Contamination - Dissolved calcium ions in sufficient concentration to impact undesirable 

properties in a drilling fluid, such as flocculation, reduction in yield of bentonite, increase in fluid 

loss, etc. See also Calcium Carbonate. 

Calcium Hydroxide - Ca(OH) 2 . The active ingredient of slaked lime. It is also the main constituent 

in cement (when wet). This material is referred to as "lime" in field terminology. 

Calcium-Treated Fluid - Calcium-treated fluids are drilling fluids to which quantities of soluble 

calcium compounds have been added or allowed to remain from the formation drilled in order to 

impart special rheological and inhibition properties. 

Calcium Sulfate - (Anhydrite: CaSO 4 ; plaster of paris: CaSO 4 x ½H 2 O and gypsum: CaSO 4 x 2H 2 0). 

Calcium sulfate occurs in fluids as a contaminant from the formation drilled or may be added to 

certain fluids to impart special properties of inhibition and/or rheology. 

Carrying Capacity - The ability of a circulating drilling fluid to transport cuttings out of the 

wellbore. Carrying capacity is an essential function of a drilling fluid, synonymous with 



REVISION 2006 15-8


hole-cleaning capacity and cuttings lifting. Carrying capacity is determined principally by the 

annular velocity, hole angle and flow profile of the drilling, but is also affected by mud density, 

cuttings size and pipe position and movement. 

Cation - The positively charged particle in the solution of an electrolyte. Which under the influence 

of an electrical potential, moves toward the anode (negative electrode). Examples are: Na + , H + , NH 4 + , 

Ca ++ , Mg ++ , Al +++ . 

Cation-Exchange Capacity (CEC) - The quantity of positively charged ions (cations) that a clay 

mineral or similar material can accommodate on its negatively charged surface, expressed as million 

equivalent per 100 g, or more commonly as milliequivalent (meq) per 100 g. Clays are 

aluminosilicates in which some of the aluminum and silicon ions have been replaced by elements 

with different valence, or charge. For example, aluminum (Al +++ ) may be replaced by iron (Fe ++ ) or 

magnesium (Mg ++ ), leading to a net negative charge. This charge attracts cations when the clay is 

immersed in an electrolyte such as salty water and causes an electrical double layer. The 

cation-exchange capacity (CEC) is often expressed in terms of its contribution per unit pore volume, 

Q v See Methylene Blue Capacity. 

Caustic or Caustic Soda - See Sodium Hydroxide. 

Cave-In - See Sloughing. Cave-in is a severe form of wellbore instability where as the formation 

falls into the annulus from the wellbore wall. 

Cavernous Formation - A formation having voluminous voids, usually the result of dissolution by 

formation waters which or may not be still present. 

cc or Cubic Centimeter - A metric-system unit for the measure of volume. It is essentially equal to 

the milliliter and commonly used interchangeably. One cubic centimeter of water at room 

temperature weighs approximately 1 g. 

Cement - A mixture of calcium aluminates and silicates made by combining lime and clay while 

heating. Slaked cement contains about 62.5 percent calcium hydroxide, which is the major source of 

trouble when cement contaminates fluid. 

Centipoise (Cp) - A unit of viscosity equal to 0.01 Poise. Poise equals 1 g per meter-second. and a 

centipoises is 1 g per centimeter-second. The viscosity of water at 20°C is 1.005 cp (1 cp = 0.000672 

lb/ft-sec). 

Centrifuge - A device for the mechanical separation of high-specific gravity solids from a drilling 

fluid. Normal application is on weighted fluids to recover weight material and discard drill solids. 

The centrifuge uses high-speed mechanical rotation to achieve this separation as distinguished from 



REVISION 2006 15-9


the cyclone type separator in which the fluid energy alone provides the separating force. See Cyclone 

and Desander. 

Chemicals - In drilling-fluid terminology, a commercial additive used to alter drilling fluid physical 

or chemical properties. 

Chemical Barrel - A container used to make additives soluble prior to being discharged into the 

mud system. 

Chromate - A compound in which chromium has a valence of 6, e.g., sodium bichromate. Chromate 

may be added to drilling fluids either directly or as a constituent of chrome lignites or chrome 

lignosulfonates. In certain areas, chromate is widely used as an anodic corrosion inhibitor, often in 

conjunction with lime. The plus 6 valence chrome compounds carry environmental restraints. 

Chrome Lignite - Mined lignite, usually leonardite, to which chromate has been added and/or 

reacted. The lignite can also be causticized with either sodium or potassium hydroxide. 

Circulation - The transport of drilling fluid through the circulating system back to the original 

starting point which is usually the suction pit. The time of travel from point A back to point A is 

referred to as the circulating time. 

Circulation, Loss of (or Lost) - The result of whole drilling fluid escaping into the formation by 

way of crevices or porous media. It is the loss of whole mud to the formation. 

Circulation Rate - The volume flow rate of the circulating drilling fluid usually expressed in gallons 

or barrels per minute, i.e. a unit of time to discharge a given volume. 

Clabbered - A slang term commonly used to describe moderate to severe flocculation of fluid due to 

various contaminants; also called "gelled up". 

Clay - A plastic, soft, variously colored earth, commonly a hydrous silicate of alumina, formed by 

the decomposition of feldspar and other aluminum silicates. See also Attapulgite, Bentonite, High 

Yield, Low Yield, and Natural Clays. Clay minerals are essentially insoluble in water but disperse 

under hydration, shearing forces such as grinding, velocity effects, etc., into the extremely small 

particles varying from submicron to 100-micron sizes. 

Clay Extender - Any of several substances, usually high molecular weight organic compounds that, 

when added in low concentrations to a bentonite or to certain other clay slurries, will increase the 

viscosity of the system, e.g., polyvinyl acetatemaleic anhydride copolymer. See Low Solids Fluids. 



REVISION 2006 15-10


Cloud Point - The temperature at which a solution of a surfactant or glycol starts to form micelles 

(molecular agglomerates), thus becoming cloudy. This behavior is characteristic of nonionic 

surfactants, which are often soluble at low temperatures but “cloud out” at some point as the 

temperature is raised. Glycols demonstrating this behavior are know as “cloud-point glycols” and 

are used as shale inhibitors. The cloud point is affected by salinity, being generally lower in saline 

fluids. 

CMC - See Sodium Carboxymethylcellulose. 

Coagulation - In drilling-fluid terminology, a synonym for flocculation: Coalescence-The change 

from a liquid to a thickened curd-like state by chemical reaction. Also the combination of globules in 

an emulsion caused by molecular attraction of the surfaces. 

Cohesion - The attractive force between the same kind of molecules, i.e. the force which holds the 

molecules of a substance together. 

Colloid - A state of subdivision of matter which consists either of single large molecules or of 

aggregations of smaller molecules dispersed to such a degree that the surface forces become an 

important factor in determining its properties. The size and electrical charge of the particles 

determine the different phenomena observed with colloids, e.g., Brownian movement. The sizes of 

colloids, range from l x l0 -7 cm to 5 x l0 -5 cm (0.001 to 0.5 microns) in diameter, although the particle 

size of certain emulsoids can be in the micron range. 

Colloidal Composition - A colloidal suspension containing one or more. colloidal constituents. 

Colloidal Suspension - A aqueous solution which contains particles of matter 1 micron or less in 

size. 

Conductivity - A measure of the quantity of electricity transferred across unit area per unit potential 

gradient per unit time. It is the reciprocal of resistivity. Electrolytes may be added to the drilling fluid 

to alter its conductivity for logging purposes. 

Connate Water - Water that was trapped in sedimentary deposits with deposition of sediment, as 

distinguished from migratory waters (have flowed into deposits after they were laid down). 

Consistency - The viscosity of a nonreversible fluid, in poises, for a certain time interval at a given 

pressure and temperature. 

Consistometer - A thickening-time tester having a stirring apparatus to measure the relative 

thickening time for fluid or cement slurries under predetermined temperatures and pressures. See 

API RP 10, “Recommended Practice for Testing Oil Well Cements and Cement Additives, American 

Petroleum Institute, Dallas, Texas, March, 1965, 14th Edition”. 



REVISION 2006 15-11


Contamination - The presence in a drilling fluid of any foreign material that may tend to produce 

detrimental properties. 

Continuous Phase - The fluid phase which completely surrounds the dispersed phase that may be 

colloids, oil, etc. 

Controlled Aggregation – Condition in which the clay platelets are maintained stacked by a 

polyvalent cation, such as calcium, and are deflocculated by use of a thinner. 

Conventional Fluid - A drilling fluid based on commercial bentonite and fresh water to achieve 

viscosity and filtration characteristics. 

Copolymer - A substance formed when two or more substances polymerize at the same time to yield 

a product which is not a mixture of separate polymers but a complex having properties different from 

either polymer alone. See Polymer. Example are polyvinyl acetate - maleic anhydride copolymer 

(clay extender and selective flocculant), acrylamidecarboxylic acid copolymer (total flocculant), etc. 

Corrosion - The adverse chemical alteration of a metal or the eating away of the metal by air, 

moisture, or chemicals; usually an oxide is formed. This is caused by the corrosive environment 

promoting an electrical cell and the transfer of ions. 

Crater – A funnel-shaped deformation of the formation at the surface of a wellbore due to blowout, 

underground water flow, or loss of formation structural integrity. 

Creaming of Emulsions - A separation between the internal and external phases of an emulsion with 

the lighter phase on top and the denser phase on bottom. When oil muds are stagnant, the less dense 

oil phase rises and the denser aqueous phase settles. The settling or rising of the particles of the 

dispersed phase of an emulsion as observed by a difference in color shading of the layers formed. 

This can be either upward or downward creaming, depending upon the relative densities of the 

continuous and dispersed phases. This behavior is not necessarily related to emulsion weakness, nor 

does it portend breaking of the emulsion, as does coalescence. 

Created Fractures - Induced fractures by means of hydraulic or mechanical pressure exerted on the 

formation by the drilling fluid or a frac – fluid. Hydrocarbon based fluids are more prone to create 

induced fractures due to their low “leak off” values which causes further propagation of the fluid into 


Cuttings - Small pieces of formation that are the result of the shearing, chipping, and/or crushing 

action of the bit. See Samples. 



REVISION 2006 15-12


Cycle (Circulation) Time, Fluid – The time of a cycle, or down the hole and back to the surface is 

the time required in minutes for the pump to move the drilling fluid in the hole back to the pump. The 

time cycle equals the barrels of fluid in the total circulating system divided by barrels per minute 

pump output. 

Cyclone - A device for the separation of various particles from a drilling fluid, most commonly used 

as a desander. The fluid is pumped tangentially into a cone, and the fluid rotation provides enough 

centrifugal force to separate particles by mass weight. See Centrifuge. 

Cuttings Bed - The collection of drill cuttings in a particular location due to a lack of carrying 

capacity of the drilling fluid as a result of diminished fluid velocity. This particular phenomenon is a 

characteristic of horizontal hole drilling where the cuttings tend to settle and collect in beds on the 

bottom side of the hole where the fluid velocity is at a minimum. 

Darcy - A unit of permeability. A porous medium has a permeability of 1 Darcy when a pressure of 

1 atm on a sample 1 cm long and 1 sq cm in cross section will force a liquid of l-cp viscosity through 

the sample at the rate of 1 cc/sec. 

Deflocculant - A thinning agent used to reduce viscosity or prevent flocculation; sometimes 

incorrectly called a “dispersant.” Most deflocculants are low-molecular weight anionic polymers 

that neutralize positive charges on clay edges. 

Deflocculation - Breakup of flocs of gel structures by use of a thinner. 

Defoamer or Defoaming Agent - Any substance used to reduce or eliminate foam by reducing the 

surface tension. Compare Antifoam. 

Dehydration - Removal of free or combined water from a compound. 

Diesel-Oil Plug - See Gunk Plug. 

Deliquescence - The liquefaction of a solid substance due to the solution of the solid by adsorption of 

moisture from the air, e.g., calcium chloride. The term deliquescence is often used interchangeably 

with the term hydroscopic. 

Density - Matter measured as mass per unit volume expressed in pounds per gallon (lb m /gal), grams 

per cubic centimeter, and pounds per cubic ft (lb m /cu. ft). Density is commonly referred to as 

"weight." 

Desander - See Cyclone. 



REVISION 2006 15-13


Diatomite - A soft, silica-rich sedimentary rock comprising diatom remains that forms most 

commonly in lakes and deep marine areas. 

Diatomaceous Earth - An infusion earth composed of siliceous skeletons of diatoms and being very 

porous. Sometimes used for combating lost circulation and as an additive to cement; also has been 

added to special drilling fluids for a specific purpose of application. Also used as a filtering medium 

to remove undesirable solids from clear fluids (usually brines). 

Differential Pressure - The difference in pressure between the hydrostatic head of the drilling-fluid 

column and the formation pressure at any given depth in the borehole. It can be positive, zero, or 

negative with respect to the hydrostatic head. 

Differential-Pressure (Wall) Sticking – When part of the drillstring (usually the drill collars) 

becomes embedded in the filter cake resulting in a non-uniform distribution of pressure around the 

circumference of the pipe. The conditions essential for sticking require a permeable formation and a 

pressure differential across a nearly impermeable filter cake and drillstring. 

Diffusion - The spreading, scattering, or mixing of a material (gas, liquid, or solid). 

Dilatant Fluid - A dilatant or inverted plastic fluid usually made up of a high concentration of well 

dispersed solids which exhibits a non- linear consistency curve passing through the origin. The 

apparent viscosity increases instantaneously with increasing rate of shear. The yield point, as 

determined by conventional calculations from the direct-indicating viscometer readings, is negative; 

however, the true yield point is zero. 

Diluent - Liquid added to dilute or thin a solution. 

Direct-Indicating Viscometer - See Viscometer, Direct-Indicating. 

Dispersant - Any chemical which promotes the subdivision of the dispersed phase by neutralization 

of counter charges. 

Dispersed Phase - The scattered phase (solid, liquid, or gas) of dispersions. The particles are finely 

divided and completely surrounded by the continuous phase. 

Dispersion (of Aggregates) - Subdivision of aggregates. Dispersion increases the specific surface of 

the particle; hence results in an increase in viscosity and gel strength. 

Dispersoid - A colloid or finely divided substance. 



REVISION 2006 15-14


Dissociation - The splitting up of a compound or element into two or more simple molecules, atoms, 

or ions. Applied usually to the effect of the action of heat or solvents upon dissolved substances. The 

reaction is reversible and not as permanent as decomposition; i.e., when the solvent is removed, the 

ions recombine. 

Distillation - Process of first vaporizing a liquid and then condensing the vapor into a liquid (the 

distillate), leaving behind non-volatile substances, the total solids of a drilling fluid. The distillate is 

the water and/or oil content of a fluid. 

Dog-Leg - The "elbow" caused by a sharp change of direction in the wellbore. 

Drilling In - The operation during the drilling procedure at the point of drilling into the pay 

formation. 

Drilling Fluid, Fluid, or Drilling Mud - A fluid formulated with chemicals to obtain specific 

chemical and physical characteristics for circulating during the rotary drilling process. 

Drilling Out - The drilling procedure used when the cement is drilled out of the casing before further 

hole is made or completion attempted. 

Drill-Stem Test (DST) - A test to determine whether oil and/or gas in commercial quantities have 

been located in the reservoir. 

Dynamic - The state of being active or in motion; opposed to static. 

Electric Logging - Electric logs are run on a wire line to obtain information concerning the porosity, 

permeability, fluid content of the formations drilled, and other information. The drilling fluid 

characteristics may need to be altered to obtain good logs with interpretable data. 

Electrical Stability Test - A test for oil-base and synthetic-base muds that indicates the emulsion 

and oil-wetting qualities of the sample. The test is performed by inserting the ES probe into a cup of 

120ºF (48.8ºC) mud and pushing a test button. The ES meter automatically applies an increasing 

voltage (from 0 to 2000 volts) across an electrode gap in the probe. Maximum voltage that the mud 

will sustain across the gap before conducting current is displayed as the ES voltage. The ES readings 

have been studied and were found to relate to an oil mud’s oil-wetting of solids and to stability of the 

emulsion droplets in a complex fashion not yet completely understood. 

Electrolyte - A substance which dissociates into charged positive and negative ions when in solution 

or a fused state and which will then conduct an electric current. Acids, bases, and salts are common 

electrolytes. 



REVISION 2006 15-15


Emulsifier or Emulsifying Agent - A chemical additive used to lower the surface tension between 

two immiscible liquids which do not mix. Emulsifiers may be divided, according to their behavior, 

into ionic and non-ionic agents. The ionic types may be further divided into anionic, cationic, and 

amphoteric, depending upon the ionic nature of the active groups. 

Emulsion - An intimate mixture of two immiscible liquids one dispersed in the other in small 

droplets or particles. Emulsions may be mechanical, chemical, or a combination of the two. They 

may be oil-in-water or water-in-oil types. 

Emulsoid - Colloidal particles which take up water. 

End Point - Indicates the end of some operation or when a definite change is observed. In titration, 

this change is frequently a change in color of an indicator which has been added to the solution or the 

disappearance of a colored reactant. 

Engineer, Fluid - One versed in drilling fluids whose duties are to manage and maintain the various 

types of oil-well fluid programs. 

EP Additive - See Extreme-Pressure Lubricant. 

Epm or Equivalents Per Million - Unit chemical weight of solute per million unit weights of 

solution. 

Equivalent Circulating Density - For a circulating fluid, the equivalent circulating density in 

lbs/gal equals the hydrostatic head (psi) plus the total annular pressure drop (psi) divided by the depth 

(ft) multiplied by 0.052. 

Equivalent Weight or Combining Weight – The atomic or formula weight of an element, 

compound, or ion divided by its valence. Elements entering into combination always do so in 

quantities proportional to their equivalent weights. 

Extreme-Pressure Lubricant - Additives which, when added to the drilling fluid, impart 

lubrication to the bearing surfaces when subjected to extreme pressure conditions, noted as a 

reduction in friction, torque, and drag. 

Fault - Geological term denoting a formation break, upward or downward, in the subsurface strata. 

Faults can significantly affect the selection of fluids and casing program design. 

Fermentation - The decomposition process of natural occurring organic molecular structures, e.g., 

starch in which a chemical change is brought about by enzymes, bacteria, or other micro-organisms. 

Often referred to as "souring". 



REVISION 2006 15-16


Fiber or Fibrous Materials - Any tough stringy material used to prevent loss of circulation or to 

restore circulation. In field use, fiber generally refers to the larger fibers of plant origin. 

Filling The Hole - Pumping drilling fluid continuously, or intermittently into the well bore to 

maintain a constant fluid level near the surface, as the drillpipe is withdrawn, i.e. to fill the remaining 

void with drilling mud as the drillpipe is removed from the annulus. The purpose is to maintain a 

constant level of hydrostatic pressure to avoid the danger of blowout, water intrusion, and/or caving 

of the well bore. 

Fill-Up Line - The line through which fluid is added to the hole via the riser. 

Filter Press - A pressurized cell, fitted with a filter medium, used for evaluating filtration 

characteristics of a drilling fluid while it is either static or stirred (to simulate circulation) in the test 

cell. Generally, either low-pressure, low-temperature or high-pressure, high-temperature devices are 

used. 

Filter Cake - The suspended solids of a drilling fluid that are deposited on a porous medium during 

the process of filtration. See also Cake Thickness. 

Filter-Cake Texture (or Quality) - A subjective description of a filter cake. The physical 

properties of a cake as measured by toughness, slickness, and brittleness. See also Cake 

Consistency. 

Filter-Cake Thickness - A measurement of the solids deposited on filter paper in 32nds of an inch 

during the standard 30-minute API filter test. See Cake Thickness. In certain areas, the filter-cake 

thickness is a measurement of the solids deposited on filter paper for a 7 minute duration. 

Filter Loss - See Fluid Loss. 

Filter Paper – Sized, porous paper for filtering liquids. API filtration test specifies one thickness of 

9-cm filter paper Whatman No. 50, S&S, No.576, or equivalent. 

Filter Press - A device for determining fluid loss of a drilling fluid having specifications in 

accordance with API RP 13B. 

Filtrate- The liquid fraction of a drilling fluid that is forced through a porous medium during the 

filtration process. For test, see Fluid Loss. 

Filtration - The process of separating suspended solids from their liquid by forcing the latter through 

a porous medium. Two types of fluid filtration occur in a well - dynamic filtration while circulating, 

and static filtration when the fluid is at rest. 



REVISION 2006 15-17


Filtration Rate - See Fluid Loss. 

Fishing - Operations on the rig for the purpose of retrieving from the well bore sections of pipe, 

collars, junk, or other obstructive items which are in the hole. 

Fish Eye - A slang term for a globule of partly hydrated polymer caused by poor dispersion during 

the mixing process (commonly a result of adding the product too fast for the shearing ability of the 

hopper). Fish eyes consist of a granule of unhydrated polymer surrounded by a gelatinous covering 

of hydrated polymer which inhibits water from completing the hydration process. Thus, once 

formed, fish eyes do not disperse and the byproduct is removed by the shaker screens and discarded. 

Fish eyes are notorious for plugging off (blinding) the shaker screens thereby resulting in loss of 

drilling fluid with the discharged cuttings. 

Flat Gel - A condition wherein the ten-minute gel strength is essentially equal to the initial gel 

strength. 

Flipped - The reversal of an emulsion; a separation between two immiscible fluids into two separate 

phases, i.e. no longer dispersed. 

Flocculate - A process whereby the electromagnetic attraction between suspended particles 

dominate the particle alignment under quiescent conditions thereby resulting in increased gel 

strengths of the fluid. 

Flocculating Agent - Substances, such as most electrolytes, some polysaccharides, certain natural or 

synthetic polymers, that bring about the thickening of the consistency of a drilling fluid. In Bingham 

Plastic fluids, the yield point and gel strength increase. 

Flocculation - Loose association of particles in lightly bonded group’s, i.e., non-parallel association 

of clay platelets. In concentrated suspensions, such as drilling fluids, flocculation results in gelation. 

In some drilling fluids, flocculation may be followed by irreversible precipitation of colloids and 

certain other substances from the fluid, e.g., red beds. 

Flocs - See Flocculates. 

Fluid - A fluid is a substance readily assuming the shape of the container in which it is placed. The 

term includes both liquids and gases. It is a substance in which the application of every system of 

stresses (other than hydrostatic pressure) will produce a continuously increasing deformation without 

any relation between time rate of deformation at any instant and the magnitude of stresses at that 

instant. 



REVISION 2006 15-18


Fluid Flow - The state of fluid dynamics of a fluid in motion is determined by the type of fluid (e.g., 

Newtonian plastic, pseudoplastic, dilatant), the properties of the fluid such as viscosity and density, 

under a given set of conditions and fluid properties, the fluid flow can be described as plug flow, 

laminar (called also Newtonian, streamline, parallel, or viscous) flow, or turbulent flow. See above 

terms and Reynolds Number. 

Fluidity - The reciprocal of viscosity. The measure of rate with which a fluid is continuously 

deformed by a shearing stress. Ease of flowing. 

Fluid Loss - Measure of the relative amount of fluid lost (filtrate) through permeable formations or 

membranes when the drilling fluid is subjected to a pressure differential. For standard API filtration 

test procedure, see API RP 13B. 

Fluorescence - Instantaneous re-emission of light, of a greater wave length, than that light originally 

absorbed. 

Foam - Foam is a two-phase system, similar to an emulsion, where the dispersed phase is a gas or air. 

Foaming Agent - A substance that produces fairly stable bubbles at the air-liquid interface due to 

agitation, In air or gas drilling, foaming agents are added to turn water influx into aerated foam. This 

is commonly called "mist drilling." 

Formation Damage - Damage to the productivity of a well resulting from invasion into the 

formation by fluid particles or fluid filtrate. Asphalt from crude oil will also damage some 

formations. See Mudding Off. 

Formation Sensitivity - The tendency of certain producing formations to adversely react with 

invading fluid filtrates. 

Functions of Drilling Fluids - The most important function of drilling fluids in rotary drilling is to 

bring cuttings from the bottom of the hole to the surface. Some other important functions are - control 

subsurface pressures, cool and lubricate the bit and drill string, deposition of an impermeable wall 

cake, etc. 

Funnel Viscosity - See Marsh Funnel Viscosity, 

Galena - Lead sulfide (PbS). Technical grades (specific gravity about 7) are used for increasing the 

density of drilling fluids to points impractical or impossible with barite. 

Garrett Gas Train - An instrument used for quantitative analysis of sulfides and carbonates. 

Specific test methods have been published by API. The oil-mud procedure analyzes active sulfides 



REVISION 2006 15-19


and uses whole mud samples, whereas the water-base mud procedure tests filtrate. The GGT unit is 

a clear, plastic block that contains three interconnected chambers. A carrier gas is used to flow an 

inert gas through the chambers. The sample is placed in chamber #1 and is acidified to release 

sulfides as H 2 S and carbonates as CO 2 . The appropriate Dräger tube is used to measure the effluent 

gas that is evolved from the sample. 

Gas Cut - Gas entrained by a drilling fluid. See Air Cutting. 

Gas Hydrate - A crystalline solid consisting of water with gas molecules in an ice-like cage 

structure. Water molecules form a lattice structure into which many types of gas molecules can fit. 

Most gases, except hydrogen and helium, can form hydrates. C 1 to n C 5 hydrocarbons, H 2 S and CO 2 

readily form hydrates at low temperature and high pressure. Gas-cut muds can form hydrates in 

deepwater drilling operations, plugging BOP lines, risers and subsea wellheads, causing a 

well-control risk.. Gas hydrates are thermodynamically suppressed by adding antifreeze materials 

such as salts or glycols. Gas hydrates are found in nature, on the bottom cold seas and in arctic 

permafrost regions. 

Gel - A term used to identify highly colloidal, high yielding, viscosity- building commercial clays, 

such as bentonite and attapulgite clays. 

Gelation - Association of particles to form a continuous structure of charged clays, the state of which 

can be face to face, face to edge, and edge to edge forming a continuous network structure held 

together by electronic charges. 

Gel Cement - Cement having a small to moderate percentage of bentonite added as filler and/or to 

reduce the slurry weight. See Gunk Plug. 

Gelled - A state of a colloidal suspension in which shearing stresses below a certain finite value fail 

to produce permanent deformation. The minimum shearing stress that will produce permanent 

deformation is known as-the shear or-gel-strength of the gel. Gels commonly occur when the 

dispersed colloidal particles have a great affinity for the dispersing medium, i.e., are lypophilic. 

Thus, gels commonly occur with bentonite in water. For their measurement, see Gel Strength, 

Initial and Gel Strength, 10-Minute. 

Gelled Up - Oil-field jargon usually referring to any fluid with high gel strength and/or highly 

viscous properties, often a state of severe flocculation. 



REVISION 2006 15-20


Gel Strength - The ability or the measure of the ability of a colloid to form gels. Gel strength is a 

pressure unit usually reported in lbs/100 sq ft. It is a measure of the same inter-particle forces of a 

fluid as determined by the yield point except that gel strength is measured under static conditions, 

yield point under dynamic conditions. The common gel-strength measurements are initial and 

ten-minute gels. See also Shear and Thixotropy. 

Gel Strength, Initial - The measured initial gel strength of a fluid is the maximum reading 

(deflection) taken from a direct-reading viscometer after the fluid has been quiescent for 10 sec. It is 

reported in lbs/100 sq ft. See API RP 13B for details of test procedure. 

Gel Strength, 10 Minute – The measured to-minute gel strength of a fluid is the maximum reading 

(deflection) taken from a direct-reading viscometer after the fluid has been quiescent for l0 min, The 

reading is reported in lbs/l00 sq ft. See API RP 13B for details of test procedure. 

Geothermal Gradient - The rate of increase in temperature per unit depth in the earth. Although the 

geothermal gradient varies from place to place, it averages 25 to 30ºC/km (15ºF/1000 ft). It is 

particularly important to know the geothermal gradient in an area when designing the drilling mud 

program for a deep well. The downhole temperature can be estimated by adding the surface 

temperature to the product of the depth and the geothermal gradient. 

Gpg or Grains per Gallon - ppm equals gpg x 17.1. 

Gravity, Specific – The ratio of the mass of a body to the mass of an equal volume of water at 4ºC. 

For example, 1 mL of water weighs 1 gm at 4ºC (i.e. the density is 1 gm/mL). One mL of barite 

weighs 4.2 g (it’s density is 4.2 gm/mL). The ratio of the two equal volumes of material is 4.2g/1g 

and the specific gravity is 4.2. 

Grains per Gallon - Equal to the number of grains of a given substance in one U.S. gallon of water. 

One grain = 1/7,000 pound and one U.S. gallon of water weighs 8.33 pounds. Hardness can be 

expressed in terms of ppm (parts per million). Conversion of parts per million or milligrams per liter 

into grains per gallon is accomplished by dividing the parts per million (or milligrams per liter) by 

17.1 to convert to grains per gallon. 

Greasing Out - Certain organic substances, usually fatty-acid derivatives, which are added to 

drilling fluids as emulsifiers, extreme pressure (EP) lubricants, etc., may react with such ions as 

calcium and magnesium that are in, or will subsequently come into the system. An essentially 

water-insoluble greasy material separates out. 

Gum - Any hydrophilic plant polysaccharides or other derivatives which when dispersed in water, 

swell to produce a viscous dispersion or solution. Unlike resins, they are soluble in water and 

insoluble in alcohol. 



REVISION 2006 15-21


Gumbo - A generic term for soft, sticky, swelling clay formations that are frequently encountered in 

surface holes offshore or in sedimentary basins onshore near seas. This clay fouls drilling tools and 

plugs piping, both sever problems for drilling operations. It is a nonspecific type of shale that 

becomes sticky when wet and adheres aggressively to surfaces. It forms mud rings and balls that can 

plug the annulus, the flowline and shale-shaker screens. Gumbo is likely to contain appreciable 

amounts of Ca ++ smectite clays. It is dispersed in a water mud, causing rapid accumulations of 

colloidal solids. 

Guar Gum - A naturally occurring hydrophilic polysaccharide derived from the seed of the guar 

plant. The gum is chemically classified as a galactomannan. Guar gum slurries made up in clear, 

fresh, or brine water possesses pseudo-plastic flow properties. 

Gunk Plug or Squeeze - A slurry in crude or diesel oil containing any of the following materials or 

combinations - bentonite, cement, attapulgite, and guar gum (never with cement), used primarily in 

combating lost circulation. The plug may or may not be squeezed. 

Gunning the Pit - The mechanical agitation of the drilling fluid in a pit by means of, a high pressure 

fluid gun, electric mixer, or agitator. 

Gyp or Gypsum - See Calcium Sulfate. Gypsum is often encountered while drilling. It may occur 

as thin stringers or massive formations. 

Hardness (of Water) - The hardness of water is due principally to the calcium and magnesium ions 

present in the water and is independent of the accompanying acid ions. The total hardness is 

measured in terms of parts per million of calcium carbonate or calcium and sometimes equivalents 

per million of calcium. For hardness tests, see API RP 13B. 

Heaving - The partial, intermittent, or complete collapse of the walls of a hole resulting from internal 

pressures due primarily to swelling from hydration or formation gas pressures. See Sloughing. 

Heterogeneous - A substance that consists of more than one phase and is not uniform, such as 

colloids, emulsions, etc. It has different properties in different parts. 

High-pH fluid - A drilling fluid with a pH range above 10.5, a high-alkalinity fluid. 

High-Yield Drilling Clay - A classification given to a group of commercial drilling-clay 

preparations having a yield of 35 to 50 bbl/ton and intermediate between bentonite and low-yield 

clays. High- yield drilling clays are usually prepared by peptizing low-yield calcium montmorillonite 

clays or, in a few cases, by blending some bentonite with the peptized low-yield clay. 



REVISION 2006 15-22


Homogeneous - Of uniform or similar nature throughout; or a substance or fluid that has at all points 

the same property or composition. 

Hopper, Jet - A device to facilitate the addition of drilling fluid additives to the system. 

Horizontal Drilling - A subset of the more general term “directional drilling,” is used where the 

departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are 

designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling 

upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting 

it as deviation from vertical. Because a horizontal well typically penetrates a greater length of the 

reservoir, it can offer significant production improvement over a vertical well. 

Humic Acid - Organic acids of indefinite composition in naturally occurring leonardite lignite. The 

humic acids are the most valuable constituent. See Lignin. 

Hydrate - A substance containing water combined in the molecular form (such as CaSO 4 x 2H 2 0), a 

crystalline substance containing water of crystallization. 

Hydration - The act of a substance to take up water by means of absorption and/or adsorption. 

Hydrogen Ion Concentration - A measure of the acidity or alkalinity of a solution, normally 

expressed as pH. See pH. 

Hydrogen Embrittlement - The process whereby steel components become less resistant to 

breakage and generally much weaker in tensile strength. While embrittlement has many causes, in 

the oil field it is usually the result of exposure to gaseous or liquid hydrogen sulfide (H 2 S). On a 

molecular level, hydrogen ions work their way between the grain boundaries of the steel, where 

hydrogen ions recombine into molecular hydrogen (H 2 ), taking up more space and weakening the 

bonds between the grains. The formation of molecular hydrogen can cause sudden metal failure due 

to cracking when the metal is subject to tensile stress. 

Hydrolysis - Hydrolysis is the reaction of a salt with water to form an acid and base. For example, 

soda ash (Na 2 CO 3 ) hydrolyzes basically, and hydrolysis is responsible for the increase in the pH of 

water when soda ash is added. 

Hydrometer - A floating instrument for determining the specific gravity or density of liquids, 

solutions, and slurries. A common example is the fluid weight hydrometer used to determine the 

density of fluid. 

Hydrophile - A substance usually in the colloidal state or an emulsion, which is wetted .by water, i.e. 

it attracts water or water adheres to it. 



REVISION 2006 15-23


Hydrophilic - A property of a substance having an affinity for water or one that is wetted by water. 



REVISION 2006 15-24


Hydrophilic-Lypophilic Balance (HLB) - Surfactants are characterized according to the “balance” 

between the hydrophilic (“water –loving”) and lypophilic (“oil loving”) portions of their molecules. 

The hydrophilic-lypophilic balance (HLB) number indicates the polarity of the molecules in an 

arbitrary range of 1-40, the the most commonly used emulsifiers having a value between 1 and 20. 

The HLB number increases with increasing hydrophilicity. According to the HLB number, 

surfactants may be utilized for different purposes. 

Function 

HLB 

Range 

Antifoaming Agent 1 to 3 

Emulsifier, 

water-in-oil 

3 to 6 

Wetting Agent 7 to 9 

Emulsifier, 

oil-in-water 

8 to 19 

Detergent 13 to 15 

Solubilizer 15 to 20 

Oils also have HLB values assigned; however, this “HLB” is relative as to whether an oil-in-water 

emulsion is to be stabilized. Emulsifiers should have similar HLB values to that of the respective oils 

in order to achieve maximum stabilization. Mineral oil has an assigned HLB number of 4 when a 

water-in-oil emulsion is desired, and a value of 10.5 when an oil-in-water emulsion is to be prepared. 

Accordingly, the HLB number of the emulsifier should also be around 4 and 10.5, respectively. The 

desired HLB numbers can also be achieved by mixing lypophilic and hydrophilic surfactants. The 

overall HLB value of the mixture is calculated as the sum of the fraction times the individual HLB. 

Hydrophobe - A substance, usually in the colloidal state, not wetted by water. 

Hydrophobic - Descriptive of a substance which repels water. 



REVISION 2006 15-25


Hydrostatic Head - The pressure exerted by a column of fluid, usually expressed as pounds per 

square inch. To determine the hydrostatic head in psi at a given depth, multiply the depth in feet by 

the density in pounds per gallon by 0.052. 

Hydroxide - A designation that is given for basic compounds containing the OH = radical. When 

these substances are dissolved in water, they increase the pH of the solution. See Base. 

Hygroscopic - The property of a substance enabling it to absorb water from the air. 

Indicator - Substances in acid-base titrations which, in solution, change color or become colorless as 

the hydrogen ion concentration reaches a definite value, these values varying with the indicator. In 

other titration such as chloride, hardness, and other determinations, these substances change color at 

the end of the reaction. Common indicators are phenolphthalein, potassium chromate, etc. 

Inhibited Fluid - A drilling fluid having an aqueous phase with a chemical composition that tends to 

retard and even prevent (inhibit) appreciable hydration (swelling) or dispersion of formation clays 

and shale through chemical and/or physical means. See Inhibitor (Fluid). 

Inhibitor (Corrosion) - Any agent which, when added to a system, slows down or prevents a 

chemical reaction or corrosion. Corrosion inhibitors are used widely in drilling and producing 

operations to prevent corrosion of metal equipment exposed to hydrogen sulfide, carbon dioxide, 

oxygen, saltwater, etc. Common inhibitors added to drilling fluids are filming amines, chromates, 

and lime. 

Inhibitor (Fluid) - Substances generally regarded as drilling fluid contaminants, such as salt and 

calcium sulfate, are called inhibitors when purposely added to fluid so that the filtrate from the 

drilling fluid will prevent or retard the hydration of formation clays and shales. 

Initial Gel - See Gel Strength, Initial. 

Interfacial Tension - The force required to break the surface between two immiscible liquids. The 

lower the interfacial tension between the two phases of an emulsion, the greater the ease of 

emulsification. When the values approach zero, emulsion formation is spontaneous. See Surface 

Tension. 

Interstitial Water - Water contained in the interstices or voids of formations. 

Invert Oil-Emulsion Fluid - An invert emulsion is a water-in-oil emulsion where fresh or saltwater 

is the dispersed phase and diesel, crude, or some other oil is the continuous phase. Water increases 

the viscosity and oil reduces the viscosity. 



REVISION 2006 15-26


Iodine Number - The number indicating the amount of iodine absorbed by oils, fats, and waxes, 

giving a measure of the unsaturated linkages present. Generally, the higher the iodine number the 

more severe the action of the oil on rubber. 

Ions - Acids, bases, and salts (electrolytes) when dissolved in certain solvents, especially water, are 

more or less dissociated into electrically charged ions or parts of the molecules, due to loss or gain of 

one or more electrons. Loss of electrons results in positive charges producing a cation. A gain of 

electrons results in the formation of an anion with negative charges. The valence of an ion is equal to 

the number of charges borne by it. 

Jetting - The process of periodically removing a portion of, or all of, the water, fluid and/or solids, 

from the pits, usually by means of pumping through a jet nozzle arrangement. 

Kelly - A heavy square or hexagonal pipe that works through a like hole in the rotary table and 

rotates the drill string. The kelly contains a fluid path through which the drilling mud can be pumped 

down through the drill string. The kelly is connected on its upper end to the swivel which allows it to 

be rotated, thereby rotating the drillstring. 

Kelly Bushing - An adapter that serves to connect the rotary table to the Kelly. The Kelly bushing 

has an inside diameter profile that matches that of the Kelly, usually square or hexagonal. It is 

connected to the rotary table by large steel pins that fit into mating holes in the rotary table. The 

rotary motion from the rotary table is transmitted to the bushing through the pins, and then to the 

Kelly itself through the square or hexagonal flat surfaces between the Kelly and the Kelly bushing. 

The Kelly then turns the entire drillstring. 

Kelly Cock - A valve in the Kelly that allows pressure to be shut off and prevent reverse flow of 

fluids from the drill string. 

Kelly Hose - A large diameter (3 to 5 inch inside diameter, high-pressure flexible line used to 

connect the standpipe to the swivel. This flexible piping arrangement permits the kelly (and, in turn 

the drill string and bit) to be raised or lowered while drilling fluid is pumped through the drill string. 

The simultaneous lowering of the drillstring while pumping fluid is critical to the drilling operation. 

Key Seat - That section of a hole, usually of abnormal deviation and; relatively soft formation, which 

has been eroded or worn by drill-pipe to a: size smaller than the tool joints or collars. This keyhole 

type configuration will not allow these members to pass when pulling out of the hole causing the drill 

string to become stuck. 

Killing A Well - Bringing a well that is blowing out under control. Also; the procedure of circulating 

water and fluid into a completed well before starting well-service operations. 



REVISION 2006 15-27


Kill Line - A line connected to the annulus below the blowout preventers (BOP) for the purpose of 

pumping into the annulus while the preventers are closed. 

Kinematic Viscosity - The kinematic viscosity of a fluid is the ratio of the viscosity (e.g., cp in 

g/cm-sec) to the density (e.g., g/cc) using consistent units. In several common commercial 

viscometers, the kinematic viscosity is measured in terms of the time of efflux (in seconds) of a fixed 

volume of liquid through a standard capillary tube or orifice. See Marsh Funnel Viscosity. 

LC 50 - The lethal concentration of a substance reported in ppm that kills 50% of a population of test 

organisms, such as mysid shrimp, in a standard, controlled laboratory bioassay test. In offshore 

drilling operations, the LC 50 number is used to determine whether waste mud or cuttings can be 

discharged into the water. The larger the LC 50 ppm number from the test, the less toxic the sample is 

to the organism. If the LC 50 number is 1,000,000 ppm the sample is presumably nontoxic according 

to the test protocol. 

Laminar Flow - Fluid elements flowing along fixed streamlines which are parallel to the walls of the 

channel of flow. In laminar flow, the fluid moves in plates or sections with a differential velocity 

across the front which varies from zero at the wall to a maximum toward the center of flow. Laminar 

flow is the first stage of flow in a Newtonian fluid. It is the second stage in a Bingham plastic fluid. 

This type of motion is also called parallel, streamline, or viscous flow. See Plug and Turbulent 

Flow. 

Leonardite - A naturally occurring oxidized lignite. See Lignins. 

Lignins, Mined or Humic Acids - Mined lignins are naturally occurring special lignite, e.g., 

leonardite, that are produced by strip mining from special lignite deposits. The active ingredient is 

the humic acid. Mined lignins are used primarily as thinners, which may or may not be chemically 

modified. However, they are also widely used as mechanical emulsifiers. 

Lignosulfonates - Organic drilling-fluid additives derived from by-products of sulfite paper 

manufacturing process from coniferous woods. Some of the common salts, such as the ferrochrome, 

chrome, calcium, and sodium, are used as universal dispersants while others are used selectively for 

calcium-treated systems. In large quantities, the ferrochrome and chrome salts are used for fluid loss 

control and shale inhibition. 

Lime - Commercial form of calcium hydroxide. 

Lime-Treated Fluids - Commonly referred to as "lime-base" fluids. These high-pH systems contain 

most of the conventional freshwater additives to which slaked lime has been added to impart special 

properties. The addition of lime creates a state in which the majority of clay particles are in an 

aggregated state producing near zero flat gel strengths. The alkalinities and lime contents vary from 

low to high. 



REVISION 2006 15-28


Limestone - See Calcium Carbonate. 

Live Oil - Crude oil that contains gas and has not been stabilized or weathered. This oil can cause gas 

cutting when added to fluid and is a potential fire hazard. 

Logging - See Fluid Logging and Electric Logging. 

Loss of Circulation - See Circulation, Loss of. 

Loss of Head or Friction Loss - See Pressure Drop Loss. 

Lost Circulation Additives - Materials added to a drilling fluid to control or prevent lost circulation. 

These non-soluble materials are added in varying amounts and are classified as fiber, flake, or 

granular. 

Lost Returns - See Circulation, Loss of. 

Low-Colloid Oil Mud - An oil mud designed and maintained with a minimum of colloid-sized 

solids, typically by omitting fatty-acid soaps and lime, and minimizing organophilic clays and 

fluid-loss additives. Low-colloid oil mud, also called a relaxed filtrate oil mud, increases drilling 

rate. A disadvantage is that filter cake formed on sands is not tight, can quickly become very thick, 

and can cause pipe to stick by differential pressure. 

Low-Gravity Solids - A type of drilling-fluid solid having a lower density than the barite (4.20 

g/cm 3 ) or hematite (5.505 g/cm 3 ) that is used to weight up a drilling mud, including drill solids plus 

the added bentonite clay. Low gravity solids are normally assumed to have a gravity of 2.6 g/cm 3 

Low-Solids Fluids - A designation given to any type of fluid where high performing additives, e.g., 

CMC, have been partially or wholly substituted for commercial or natural clays, for comparable 

viscosity and densities (weighted with barite), a low-solids fluid will have a lower volume-percent of 

low gravity solids content. 

Low-Yield Clays - Commercial clays chiefly of the calcium montmorillonite type having a yield of 

approximately 15 to 30 bbl/ton. 

Lypophile - A substance usually colloidal and easily wetted by oil. 

Lypophilic - Having an affinity for the suspending medium, such as bentonite in water. 



REVISION 2006 15-29


Lypophilic Colloid - A colloid that is not easily precipitated from a solution, and is readily 

dispersible after precipitation by the addition of a solvent. 

Lypophobic - A colloid that is readily precipitated from a solution and cannot be re-dispersed by 

addition of the solution. 

Marsh Funnel - An instrument used in determining the Marsh funnel viscosity. The Marsh funnel is 

a container with a fixed orifice at the bottom so that when filled with 1500 cc freshwater, 1 qt (946 

rnL) will flow out in 26 seconds. For 1000 cc out, the efflux time for water is 27.5 seconds. See API 

RP 13B for specifications. 

Marsh Funnel Viscosity - Commonly called the funnel viscosity, the Marsh Funnel viscosity is 

reported as the number of seconds required for a given fluid to flow 1 qt through the Marsh funnel. In 

some areas, the efflux quantity is 1000 cc. See API RP I3B for instructions. See also Kinematic 

Viscosity 

Meniscus - The curved interface between two immiscible phases in a tube, such as in a pipette or 

graduated cylinder. Liquid volumes should be read at the bottom of a curved meniscus by alignment 

of the bottom of the meniscus. For water and liquids that wet the glass, the meniscus is concave. For 

nonwetting liquids, such as mercury, the meniscus is convex. 

Mesh - A measure of fineness of a woven material, screen, or sieve; e.g.; a 200-mesh sieve has 200 

openings per linear inch. A 200-mesh screen with a wire diameter of 0.0021 in. (0.0533 mm) has an 

opening of 0.074 mm, or will pass a particle of 74 microns. See Micron. 

Methylene Blue Test - A test to determine the amount of clay-like materials in a water-base drilling 

mud based on the amount of methylene blue dye absorbed by the sample. Results are reported as 

“MBT” and also as “lb m /bbl, bentonite equivalent” when performed to API specifications. See 

Cation-Exchange Capacity (CEC). 

M f - The methyl orange alkalinity of the filtrate, reported as the number of milliliters of 0.02 Normal 

(N/50) acid required per milliliter of filtrate to reach the methyl orange end point (pH 4.3). 

Mica - A naturally occurring flake material of varying size used in combating lost circulation. 

Chemically, an alkali aluminum silicate. 

Micelles - Organic and inorganic molecular aggregates occurring in colloidal solutions. Long chains 

of individual structural units chemically joined to one another and lay side by side to form bundles. 

When bentonite hydrates, certain sodium, or other metallic ions go into solution, the clay particle 

plus its atmosphere of ions is technically known as a micelle. See Oil-Emulsion Water. 



REVISION 2006 15-30


Micron (µ) = MU - A unit of length equal to one millionth part of a meter, or one thousandth part of 

a millimeter. 

Millidarcy - 1/l000 Darcy. See Darcy. 

mL or Milliliter - A metric system unit for the measure of volume. Literally 1/1000th of a liter. In 

drilling fluid analysis work, this term is used interchangeably with cubic centimeter (cc). One quart is 

about equal to 946 mL. 

Mist Drilling - A method of Rotary drilling whereby water and/or oil is dispersed in air and/or gas as 

the drilling fluid. 

Mixed-Metal Hydroxide (MMH) - A compound containing hydroxide anions in association with 

two or more metal cations. MMH particles are extremely small and carry multiple positive charges. 

They can associate with bentonite to form a strong complex that exhibits highly shear-thinning 

properties, with high and fragile gel strengths, high yield point (YP), and low plastic viscosity (PV). 

MMH muds are used as nondamaging drilling fluids, metal-reaming fluids (to carry out metal 

cuttings) and for wellbore shale control. Being anionic, MMH mud is sensitive to anionic 

deflocculants and small anionic polymers, such as polyphosphates, lignosulfonate or lignite. 

Molecular Weight - The sum of the atomic weights of all the constituent atoms in the molecule of an 

element or compound. 

Molecule - When atoms combine, they form a molecule. In the case of an element or a compound, a 

molecule is the smallest unit which chemically still retains the properties of the substance in mass. 

Monkeyboard - The small platform that the derrickman stands on when tripping pipe. 

Montmorillonite - A clay mineral commonly used as an additive to drilling fluids. Sodium 

montmorillonite is the main constituent in bentonite. The structure of montmorillonite is 

characterized by a form which consists of a thin platey-type sheet with the width and breadth 

indefinite, and thickness that of the molecule. The unit thickness of the molecule consists of three 

layers. Attached to the surface are ions that are replaceable. Calcium montmorillonite is the main 

constituent in low-yield clays. 

Mud - A water- or oil-base drilling fluid whose properties have been altered by solids, commercial 

and/or native, dissolved and/or suspended. Used for circulating out cuttings and many other 

functions while drilling a well. Mud is the term most commonly given to drilling fluids. See Drilling 

Fluids. 



REVISION 2006 15-31


Mud Additive - Any material added to a drilling fluid to achieve a particular physical or chemical 

attribute to the fluids properties. 

Mudding Off - Commonly thought of as reduced formation productivity caused by the penetrating, 

sealing, or plastering effect of a drilling fluid. 

Mudding Up - Process of mixing fluid additives to achieve some desired purpose not possible with 

the former fluid, which has usually been water, air, or gas. 

Mud House - A structure at the rig to store and shelter sacked materials used in drilling fluids. 

Mud Logging - A method of determining the presence or absence of oil or gas in the various 

formations penetrated by the drill bit. The drilling fluid and the cuttings are continuously tested on 

their return to the surface, and the results of these tests are correlated with the depth or origin. 

Mud-Mixing Devices - The most common device for adding solids to the fluid is by means of the jet 

hopper. Some other devices for mixing are eductors, paddle mixers, electric stirrers, fluid guns, 

chemical barrels, etc. 

Mud Pit - Earthen or steel storage facilities for the surface fluid system. Mud pits which vary in 

volume and number are of two types, circulating and reserve. Mud testing and conditioning is 

normally done in the circulating pit system. 

Mud Program - A step by step procedural plan based on prior knowledge of all known drilling 

parameters before actual drilling is initiated. When the unexpected arises in the actual drilling then 

deviation from the mud program in may be required. These departures can be planned for in advance 

and included in the program as contingency procedures should the mud program require altering. 

Deviation from the mud program is normally encountered when drilling wildcat type wells. 

Mud Pumps - Pumps at the rig used to circulate drilling fluids. 

Mud Scales - See Balance, Fluid. 

Mud Still- An instrument used to distill oil, water, and other volatile material in a fluid to determine 

oil, water, and total solids contents in volume-percent. Should the fluid contain dissolved 

components such as salts the volume of liquid fraction distilled will require adjustment. 

Natural Clays - Natural clays, as opposed to commercial clays, are clays that are encountered when 

drilling various formations. The yield of these clays varies greatly, and they may or may not be 

purposely incorporated into the fluid system. 



REVISION 2006 15-32


Neat Cement – A slurry composed of Portland cement and water. 

Neutralization - A reaction in which the hydrogen ion of an acid and the hydroxyl ion of a base unite 

to form water, the other ionic product being a salt. 

Newtonian Flow - See Newtonian Fluid. 

Newtonian Fluid - The basic and simplest fluids from the standpoint of viscosity consideration in 

which the shear force is directly proportional to the shear rate.. These fluids will immediately 

begin-to- move when a pressure or force in excess of zero is applied. Examples of Newtonian fluids 

are water, diesel oil, and glycerin. The yield point as determined by direct-indicating viscometer is 

zero. 

Non-Conductive Fluid - Any drilling fluid, usually oil-base or invert- emulsion fluids, whose 

continuous phase does not conduct electricity, e.g., oil. The spontaneous potential (SP) and normal 

resistivity cannot be logged, although such other logs as the induction, acoustic velocity, etc., can be 

run. 

Normal Pressure - The pore pressure of rocks that is considered normal in areas in which the change 

in pressure per unit of depth is equivalent to hydrostatic pressure. The normal hydrostatic pressure 

gradient for freshwater is 0.433 pounds per square inch per foot (psi/ft), and 0.465 psi/ft for seawater 

with 100,000 ppm total dissolved solids (a typical Gulf Coast water). 

Normal Solution - A solution of such a concentration that it contains 1 gram-equivalent of a 

substance per liter of solution. 

Oil Base Mud (OBM) - The term "oil-base mud" is applied to a special type drilling fluid where oil 

(usually diesel oil) is the continuous phase and water the dispersed phase. Oil-base muds contain 

emulsifiers, wetting agents, viscosifiers, filtration control agents, and water (usually brine) 

emulsified into the system. These muds are also referred to as “non-aqueous” fluids as the major, or 

continuous phase is not water. These systems may also be formulated from more environmentally 

acceptable synthetic oils and are then referred to as “synthetic oil-base muds” (SOBM) 

Oil/Brine Ratio - Ratio of the volume percent oil to the volume percent water in an oil mud, where 

each is a percent of the total liquid in the mud. OWR is calculated directly from the retort analysis of 

an oil mud, but the brine content is calculated from the water content by using the chloride and 

calcium titration data. For example, if a mud contains 60 vol.% oil and 20 vol.% brine, the oil 

percentage is [60/(60 + 20)]100 = 77% and the water percent is [18/(60 + 18)] = 23%. That OWR is 

written as 77/23. 

Oil Content - The oil content of any drilling fluid is the amount of oil in volume-percent. 



REVISION 2006 15-33


Oil-In-Water Emulsion Fluid - Commonly called "emulsion fluid." Any conventional or special 

water-base fluid to which oil has been added. The oil becomes the dispersed phase and may be 

emulsified into the fluid either mechanically or chemically. 

Oil-Wet - Pertaining to the preference of a solid to be in contact with an oil phase rather than a water 

or gas phase. Oil-wet rocks preferentially imbibe oil. Generally, polar compounds or asphaltenes 

deposited from the crude oil onto mineral surfaces cause the oil-wet condition. Similar compounds 

in oil-base mud also can cause a previously water-wet rock to become partially or totally oil-wet. 

Solids in an oil mud must be oil-wet for the mud to remain stable. Water-wet solids in an oil mud 

will create an unstable system with the solids agglomerating and either being removed by the shale 

shaker, or sticking to and building up on tubulars such as the drill pipe. This situation is aggravated 

by high shear, i.e. inside the drill pipe or drill collars where the solids will build up and cause 

undesirable increases in pump pressure. 

Packer Fluid - Any fluid placed in the annulus between the tubing and casing above a packer. Along 

with other functions, the hydrostatic pressure of the packer fluid is utilized to reduce the pressure 

differentials between the formation and the inside of the casing and across the packer itself. 

Particle - A minute unit of matter, usually a single crystal, of regular shape with a specific gravity 

approximating that of a single crystal. 

Parts-Per Million - See-ppm. 

Parallel Flow - See Laminar Flow. 

Pay Zone or “Pay” - The formation drilled that contains oil and/or gas in commercial quantities. 

Penetration, Rate of - The rate in feet per hour at which the drill proceeds to deepen the well bore 

and is commonly referred to as Rate of Penetration (ROP). 

Peptization - An increased dispersion due to the addition of electrolytes or other chemical 

substances. See Deflocculation and Dispersion. 

eptizing Agent - A product that enhances dispersion of a substance (such as clay) into colloidal 

form. Peptizing agents for drilling-mud clays are sodium carbonate, sodium metaphosphates, 

sodium polyacrylates, sodium hydroxide and other water-soluble compounds, even common table 

salt, NaCl, if added at low concentration. 

Peptized Clay - A clay to which a chemical agent has been added to increase its initial yield. For 

example, soda ash is frequently added to calcium montmorillonite clay. 



REVISION 2006 15-34


Percent - For weight -percent, see ppm. Volume-percent is the number of volumetric parts of any 

liquid or solid constituent per 100 like volumetric parts of the whole. Volume-percent is the most 

common method of reporting solids, oil, and water contents of drilling fluids. 

Permeability - Normal permeability is a measure of the ability of rock to transmit a one-phase fluid 

under conditions of laminar flow. Unit of permeability is the Darcy. 

P f - The phenolphthalein alkalinity of the filtrate, reported as the number of milliliters of 0.02 Normal 

(N/50) acid required per milliliter of filtrate to reach the phenolphthalein end point. 

pH - An abbreviation for potential hydrogen ion. The pH numbers range from 0 to 14, 7 being 

neutral, and are indices of the acidity (below 7) , or alkalinity (above 7) of the fluid. The numbers are 

a function of the hydrogen ion concentration in gram ionic weights per liter which, in turn, is a 

function of the dissociation of water as given by the following expression: 

( H )( OH ) 

H 

2 

O 

= 

K H O 

2 

= 1× 

10 

−υ 

The pH may be expressed as the logarithm (base 10) of the reciprocal (or the negative logarithm) of 

the hydrogen ion concentration. The pH of a solution offers valuable information as to the immediate 

acidity or alkalinity, as contrasted to the total acidity or alkalinity (which may be titrated). 

Phosphate - Certain complex phosphates, usually sodium tetraphosphate (Na 6 P 4 O 13 ) and sodium 

acid pyrophosphate (SAPP, Na 2 H 2 P 2 O 7 ), are used either as fluid thinners or for treatment of various 

forms of calcium-and magnesium contamination 

Pilot Testing - A method of predicting behavior of fluid systems by mixing quantities of fluid or 

fluid additives, then testing the results. 

Plastic Flow - See Plastic Fluid. 

Plastic Fluid - A complex, non-Newtonian fluid in which the shear force is not proportional to the 

shear rate. A definite pressure is required to start and maintain movement of the fluid. Plug flow is 



REVISION 2006 15-35


the initial type of flow and only occurs in plastic fluids. Most drilling fluids are plastic fluids. The 

yield point as determined by direct-indicating viscometer is in excess of zero. 

Plasticity - The property possessed by some solids, particularly clays and clay slurries, of changing 

shape or flowing under applied stress without developing shear planes or fractures. Such bodies have 

yield points, and stress must be applied before movement begins. Beyond the yield point, the rate of 

movement is proportional to the stress applied, but ceases when the stress is removed. See Fluid. 

Plastic Viscosity - The plastic viscosity is a measure of the internal resistance to fluid flow 

attributable to the amount, type, and size of solids present in a given fluid. It is expressed as the 

number of dynes per sq cm of tangential shearing force in excess of the Bingham yield value that will 

induce a unit rate of shear. This value, expressed in centipoises is proportional to the slope of the 

consistency curve determined in the region of laminar flow for materials obeying Bingham's Law of 

Plastic Flow. When using the direct-indicating viscometer, the plastic viscosity is found by 

subtracting the 300-rpm reading from the 600-rpm reading. 

Plug Flow - The movement of a material as a unit without shearing within the mass. Plug flow is the 

first type of flow exhibited by a plastic fluid after overcoming the initial force required to produce 

flow. 

P m - The phenolphthalein alkalinity of the fluid (mud) reported as the number of milliliters of 0.02 

Normal (N/50) acid required per milliliter of fluid to reach the phenolphthalein end point. 

Polyalkalene Glycol - A polymer or copolymer of an alkaline oxide, such as polyethylene glycol 

(PEG), a polymer of ethylene oxide with general formula HO(CH 2 CH 2 O)nH, or polypropylene 

glycol (PPG) which is a polymer of propylene oxide. PAGs are effective shale inhibitors and have 

effectively replaced the earlier polyglycerols. 

Polymer - A substance formed by the union of two or more molecules of the same kind linked end to 

end into another compound having the same elements in the same proportion but a higher molecular 

weight and different physical properties, e.g., paraformaldehyde. See Copolymer. 

Pore Plugging Apparatus (PPA) – A device for the study of filter cake deposition. Drilling fluid 

filter cake is deposited on a filter media and evaluated for potential differential pressure sticking 

characteristics. 

Pore Pressure Transmission (PPT) - The ability of a sedimentary rock of minimum porosity and 

permeability, i.e. shale, to transmit fluid pressure across a given cross section, longitudinally as well 

as horizontally. 

Porosity - The amount of void space in a formation rock usually expressed as percent voids per bulk 

volume. Absolute porosity refers to the total amount of pore space in a rock regardless of whether or 



REVISION 2006 15-36


not that space is accessible to fluid penetration. Effective porosity refers to the amount of connected 

pore spaces, i.e., the space available to fluid penetration. See Permeability. 

Potassium - One of the alkali metal elements with a valence of 1 and an atomic weight of about 39. 

Potassium compounds, most commonly potassium hydroxide (KOH) or potassium chloride (KCl) 

are sometimes added to drilling fluids to impart special properties, usually inhibition. 

Pound Equivalent - A laboratory unit used in pilot testing. One gram or pound equivalent, when 

added to 350 mL of fluid, is equivalent to 1 lbm/bbl. 

Parts Per Million (ppm) - Unit weight of solute per million unit weights of solution (solute plus 

solvent), corresponding to weight- percent except that the basis is a million instead of a hundred. The 

results of standard API titrations of chloride, hardness, etc. are correctly expressed in milligrams 

(mg) per liter but not in ppm. At low concentrations mg/L is about numerically equal to ppm. A 

correction for the solution specific gravity or density in g/mL must be made as follows: 

ppm = 

mg / L 

solution Density, 

gm / L 

% by wt = 

mg / L 

( 10,000)( solution Density, 

gm / L) 

ppm 

= 

10,000 

Thus, 316,000 mg/L salt is commonly and erroneously called 316,000 ppm or 31.6 percent, which 

correctly should be 264,000 ppm and 26.4 percent, respectively. 

Precipitate - Material that separates out of solution or slurry as a solid. Precipitation of solids in a 

drilling fluid may follow flocculation or coagulation such as the dispersed red-bed clays upon 

addition of a flocculation agent to the fluid. 

Prehydration - The addition of a mud product to fresh water prior to adding it into the mud system. 

Bentonite clay and XC polymers are two additives whose performance improves by hydration in 

fresh water before adding them to a highly-treated or salty mud system. 



REVISION 2006 15-37


Preservative - Usually paraformaldehyde. Any material used to prevent starch or any other 

substance from fermenting through bacterial action. 

Pressure-Drop (Loss) - The pressure lost in a pipeline or annulus due to the resistance to flow. 

Factors such as velocity of the liquid in the pipeline, the properties of the fluid, the state of the pipe 

wall, and the-alignment of the pipe are all additive in the resistance to flow or pressure drop: In 

certain fluid-mixing systems, the loss of head can be substantial. 

Pressure Surge - A sudden, usually short-duration, increase in pressure. When pipe or casing is run 

into a hole too rapidly, an increase in the hydrostatic pressure results, which may fracture exposed 

formations enough to create lost circulation. 

Pseudoplastic Fluid - A complex non-Newtonian fluid that does not possess thixotropy. A pressure 

or force in excess of zero will start fluid flow. The apparent viscosity or consistency decreases 

instantaneously with increasing rate of shear until at a given point the viscosity becomes constant. 

The yield point as determined by direct- indicating viscometer is positive, the same as in Bingham 

plastic fluids; however, the true yield point is zero. An example of a pseudoplastic fluid is guar gum 

in fresh or saltwater. 

Quaternary Amine - A cationic amine salt in which the nitrogen atom has four groups bonded to it 

and carries a positive charge. Quaternary amines are used as oil-wetting agents, corrosion and shale 

inhibitors and bactericides. 

Quebracho - A drilling-fluid additive used extensively for thinning or dispersing to control viscosity 

and thixotropy. It is a crystalline extract of the quebracho tree consisting essentially of tannic acid. 

Quicklime - Calcium oxide, CaO. Used in certain oil-base fluids to neutralize the organic acid. 

Quiescence - The state of being quiet or at rest (being still). Static. 

Radical - Two or more atoms behaving as a single chemical unit, i.e., as an atom, e.g., sulfate, 

phosphate, nitrate. 

Rate of Shear - The rate at which an action, resulting from applied forces, causes or tends to cause 

two adjacent parts of a body to slide relatively to each other in a direction parallel to their plane of 

contact. Generally referred to in reciprocal seconds (sec -:l ). 

Resin - Semi-solid or solid complex, amorphous mixture of organic compounds having no definite 

melting point nor tendency to crystallize. Resin may be a component of compounded materials that 

can be added to drilling fluids to impart special properties to the system, wall cake, etc. 



REVISION 2006 15-38


Resistivity - The electrical resistance offered to the passage of a current; expressed in ohm-meters; 

the reciprocal of conductivity. Freshwater fluids are usually characterized by high resistivity, 

saltwater fluids by a low resistivity. 

Resistivity Meter - An instrument for measuring the resistivity of drilling fluids and their filter 

cakes. 

Reverse Circulate - The method by which the normal flow of a drilling fluid is reversed by 

circulating down the annulus and up and out the drillstring. 

Reynolds Number - A dimensionless number (Re) that occurs in the theory of fluid dynamics. The 

diameter, velocity, density and viscosity (consistent units) for a fluid flowing through a cylindrical 

conductor are related as follows: 

Re = (Diameter)(Velocity)(Density)/(Viscosity) 

or 

Re = (D) (V)p/u 

The number is important in fluid hydraulics calculations for determining the type of fluid flow, i.e., 

whether laminar or turbulent. The transitional range occurs approximately from 2000 to 3000; below 

2000 the flow is laminar, above 3000 the flow is turbulent. 

Rheology - The science that deals with deformation and flow of water. 

Rotary Drilling - The method of drilling wells that depends on the rotation of a column of drillpipe 

to the bottom of which is attached a bit. A fluid is circulated to remove the cuttings. 

Salt - In fluid terminology, the term salt is applied to sodium chloride, NaCI. Chemically, the term 

salt is also applied to anyone of a class of similar compounds formed when the acid hydrogen of an 

acid is partly or wholly replaced by a metal or a metallic radical. Salts are formed by the action of 

acids on metals, or oxides and hydroxides, directly with ammonia, and in other ways. 

Saltwater Clay - See Attapulgite Clay. 

Saltwater Fluids - A drilling fluid containing dissolved salt (brackish to saturated). These fluids 

may also include native solids, oil, and/or such commercial additives as clays, starch, etc. 



REVISION 2006 15-39


Sample Fluid - A drilling fluid possessing properties to bring up suitable drilled rock cutting 

samples. 

Samples - Cuttings obtained for geological information from the drilling fluid as it emerges from the 

hole. They are washed, dried, and labeled as to the depth 

Sand - A loose granular material resulting from the disintegration of rocks most often silica. 

Sand Content - The sand content of a drilling fluid is the insoluble abrasive solids content rejected 

by a 200-mesh screen. It is usually expressed as the percentage bulk volume of sand in a drilling 

fluid. This test is an elementary type in that the retained solids are not necessarily silica nor may not 

be altogether abrasive. For additional information concerning the kinds of solids retained on the 

200-mesh screen (> 74 micron), more specific tests would be required. See Mesh. 

Sand Trap - A small pit, typically located immediately after the shaker screens, which is used as a 

settling pit to separate coarser solids that accidentally bypass the shakers. Mud enters the pit at one 

side and exits via an overflow at the other. Sand traps are dumped periodically to remove the settle 

solids, or alternatively the contents can be processed over a fine screen or with a centrifuge. 

Saturated Solution - A solution is saturated if it contains at a given temperature as much of a solute 

as it can retain. At 68°F, it takes 126.5 lb m /bbl salt to saturate 1 bbl of freshwater, which will result in 

1.13 bbls of saturated salt solution. See Supersaturation. 

Screen Analysis - Determination of the relative percentages of substances, e.g., the suspended solids 

of a drilling fluid, passing through or retained on a sequence of screens of decreasing mesh size. 

Analysis may be by wet or dry methods. Referred to also as "sieve analysis." See Mesh. 

Sealing Agents - Any of many materials added to drilling fluids to restore circulation by 

mechanically sealing off the thief zone or zones into which whole fluid has flowed. 

Seawater Fluids - A special class of saltwater fluids where seawater is used as the fluid phase. 

Seconds API - A unit of viscosity as measured with a Marsh funnel according to API procedure. See 

APIRP 13B and Marsh Funnel Viscosity. 

Sequestration - The formation of stable calcium, magnesium, iron complex by treating water or 

fluid with certain complex phosphates that do not precipitate but stay suspended in a non-reactive 

neutralized state. 

Sequestering Agent - A chemical whose molecular structure can envelop and hold a certain type of 

ion in a stable and soluble complex. Divalent cations, such as hardness ions, form stable and soluble 



REVISION 2006 15-40


complex structures with several types of sequestering chemicals. When held inside the complex, the 

ions have a limited ability to react with other ions, clays or polymers. 

Set Casing - The installation of pipe or casing in a well bore. Usually requires “mudding up”, 

reconditioning or at least checking the drilling fluid properties. 

Shale - Fine-grained clay rock with slate-like cleavage, sometimes containing an organic oil-yielding 

substance. 

Shale Shaker - Any of several mechanical devices for removing cuttings and other large solids from 

the fluid. Typically a vibrating screen. 

Shear (Shearing Stress) - An action, resulting from applied forces, which causes or tends to cause 

two contiguous parts of a body to slide relatively to each other in a direction parallel to their plane of 

contact. 

Shearometer - A device used as an alternative method for measuring gel strengths. See API RP 13B 

for specifications and procedure. 

Shear Strength - A measure of the shear value of the fluid. The minimum shearing stress that will 

produce permanent deformation. See Gel Strength. 

Side Tracking - See Whipstock. 

Sieve Analysis - See Screen Analysis. 

Silica Gel - A porous substance consisting of SiO 2 . Used on occasion as a dehydrating agent in air or 

gas drilling where small amount of water is encountered. 

Silicate Mud - A type of shale-inhibitive water mud that contains sodium or potassium silicate as the 

inhibitive component. High pH is a necessary characteristic of silicate muds to control the amount 

and type of polysilicates that are formed. Mud pH is controlled by addition of NaOH (or KOH) and 

the appropriate silicate solution. Silicate anions and colloidal silica gel combine to stabilize the 

wellbore by sealing microfractures, forming a silica layer on shales and possibly acting as an osmotic 

membrane, which can produce in-gauge holes through troublesome shale sections that otherwise 

might require an oil mud. Good solids control practices are very important in the control of silicate 

mud properties. Silicate muds are not recommended to be used while drilling the pay zone. 



REVISION 2006 15-41


Silt - Materials that exhibit little or no swelling whose particle size generally falls between 2 microns 

and API sand size, or 74 microns (200-mesh). A certain portion of dispersed clays and barite for the 

most part also fall into this same particle-size range. 

Skid - Moving a rig from one location to another, usually on tracks where little dismantling is 

required. 

Slide - To drill with a mud motor rotating the bit downhole without rotating the drillstring from the 

surface. This operation is conducted when the bottomhole assembly has been fitted with a bent sub 

or bent housing mud motor, or both, for directional drilling. Sliding is the predominant method to 

build and control or correct hole angle in modern directional drilling operations. By controlling the 

amount of hole drilled in the sliding versus the rotating mode, the wellbore trajectory can be 

controlled precisely. 

Slip Velocity - The difference between the annular velocity of the fluid and the rate at which a 

cutting is removed from the hole. 

Sloughing - The partial or complete collapse of the walls of a hole resulting from incompetent, 

unconsolidated formations, high angle or repose, and wetting along internal bedding planes. See 

Heaving and Cave-In. 

Slug the Pipe - A procedure before pulling the drillpipe whereby a small quantity of heavy fluid is 

pumped into the top section of the drillstring to cause an unbalanced column. As the pipe is pulled, 

the heavier column in the drillpipe will fall, thus keeping the inside of the drillpipe dry at the surface 

when the connection is unscrewed. 

Smectite Clay - A category of clay minerals that have a three-layer crystalline structure (one 

alumina and two silica layers) and that exhibit a common characteristic of hydrational swelling when 

exposed to water. Montmorillonite is a well-known smectite clay mineral. Its sodium form, 

bentonite, is a widely-used water mud additive. It is also used as an oil-mud additive when made 

oil-dispersible by surface treatment. 

Soap - The sodium or potassium salt of a high molecular-weight fatty acid. When containing some 

metal other than sodium or potassium, they are called "metallic" soaps. Soaps are commonly used in 

drilling fluids to improve lubrication, emulsification, sample size, defoaming, etc. 

Soda Ash - See Sodium Carbonate. 

Sodium - One of the alkali metal elements with a valence of -1 and an atomic weight of about 23. 

Numerous sodium compounds are used as additives to drilling fluids. 



REVISION 2006 15-42


Sodium Bicarbonate - NaHCO 3 . A material used extensively for treating cement contamination and 

occasionally other calcium contamination in drilling-fluids. It is the half -neutralized sodium salt of 

carbonic acid. 

Sodium Bichromate - Na 2 Cr 2 O 7 . Also correctly called "sodium dichromate." See Chromate. 

Sodium Carbonate - Na 2 CO 3 - A material used extensively for treating out various types of calcium 

contamination- It is commonly called "soda ash." When sodium carbonate is added to a fluid, it 

increases the pH of the fluid by hydrolysis. Sodium carbonate can be added to salt (NaCl) water to 

increase the density of the fluid phase. 

Sodium Carboxymethylcellulose - Commonly called CMC. Available in various viscosity grades 

and purity. An organic material used to control filtration, suspend weighting material, and build 

viscosity in drilling fluids. Used in conjunction with bentonite where low-solid fluids are desired. 

Sodium Chloride - NaCl. Commonly known as salt. Salt may be present in the fluid as a 

contaminant or may be added for any of several reasons. See Salt. 

Sodium Chromate - Na 2 CrO 4 . See Chromate. 

Sodium Hydroxide - NaOH. Commonly referred to as "caustic" or "caustic soda." A chemical used 

primarily to impart a higher pH. 

Sodium Polyacrylate - A synthetic high molecular weight polymer of acrylonitrile used primarily as 

a fluid loss control agent. 

Sodium Silicate Fluids - Special class of inhibited chemical fluids using as their bases sodium 

silicate, salt, water, and clay. 

Solids Concentration or Content - The total amount of solids in a drilling fluid as determined by 

distillation includes both the dissolved and the suspended or undissolved solids. The suspended 

solids content may be a combination of high and low-specific gravity solids and native or 

commercial solids. Examples of dissolved solids are the soluble salts of sodium, calcium, and 

magnesium. Suspended solids make up the wall cake; dissolved solids remain in the filtrate. The total 

suspended and dissolved solids contents are commonly expressed as percent by volume, and less 

commonly as percent by weight. 

Solubility - The degree to which a substance will dissolve in a particular solvent. 

Solute - A substance which is dissolved in another (the solvent). 



REVISION 2006 15-43


Solution - A mixture of two or more components that form a homogeneous single phase. Example 

solutions are solids dissolved in liquid, liquid in liquid, gas in liquid. 

Solvent - Liquid used to dissolve a substance (the solute). 

Sour Gas - A general term for those gases that are acidic either alone or when associated with water. 

Two sour gases associated with oil and gas drilling and production are hydrogen sulfide (H 2 S) and 

carbon dioxide (CO 2 ). Sulfur oxides and nitrogen oxides, generated by oxidation of certain sulfur or 

nitrogen bearing materials, are also in this category but not found in the anaerobic conditions of the 

subsurface. 

Souring - A term commonly used to mean fermentation. 

Specific Gravity - See Gravity, Specific. 

Specific Heat - The number of calories required to raise 1 gram of substance 1 degree Centigrade. 

The specific heat of a drilling fluid gives an indication of the fluid's ability to keep the bit cool for a 

given circulation rate. 

Spudding In - The starting of drilling operations for a new hole. 

Spud Mud - The fluid used when drilling starts at the surface, often a thick bentonite-lime slurry. 

Spurt Loss - See Surge Loss. 

Squeeze - A procedure whereby slurries of cement, fluid, gunk plug, etc. are forced into the 

formation by pumping into the hole while maintaining a back pressure, usually by closing the rams. 

Stability Meter - An instrument to measure the breakdown voltage of invert emulsions. 

Stacking a Rig - Storing a drilling rig upon completion of a job when the rig is to be withdrawn from 

operation for a period of time. 

Starch - A group of carbohydrates occurring in many plant cells. Starch is specially processed (pre 

gelatinized) for use in fluids to reduce filtration rate and occasionally to increase the viscosity. 

Without proper protection, starch is subject to bacterial degradation resulting in the fermentation and 

the alteration of fluid properties. 

Static - Opposite of dynamic. See Quiescence. 



REVISION 2006 15-44


Streaming Potential - The electrokinetic portion of the spontaneous potential (SP) electric-log 

curve which can be significantly influenced by the characteristics of the filtrate and fluid cake of the 

drilling fluid that was used to drill the well. 

Streamline Flow - See Laminar Flow. 

Stearate - Salt of stearic acid, which is saturated, 18 carbon fatty acid. Certain compounds, such as 

aluminum stearate, calcium stearate, zinc stearate, have been used in drilling fluids for one or more 

of the following purposes: defoamer, lubrication, air drilling in which a small amount of water is 

encountered, etc. 

Stuck - A condition whereby the drillpipe, casing, or other devices inadvertently become lodged in 

the hole. Can be the result of numerous conditions including but not limited to; sloughing (caving) of 

the well bore, formation swelling, salt flow (migration), differential pressure sticking, key seating, 

junk in the hole, dogleg, etc. 

Sulfide Scavenger - A chemical that removes all three soluble sulfide species, H 2 S, S -2 and HS - , and 

forms a reaction product that is irreversible by chemical reaction, nonhazardous and noncorrosive. 

Zinc compounds are commonly used to precipitate ZnS and decrease the concentration of all three 

sulfides that are in equilibrium in a solution to a very low concentration. For water mud, zinc basic 

carbonate, and for oil mud, zinc oxide, are recognized to be effective sulfide scavengers. Oxidation 

of sulfides to form other types of sulfur compounds will remove sulfides from a mud, but slowly and 

with less certainty. 

Supersaturation - If a solution contains a higher concentration of a solute in a solvent that would 

normally correspond to its solubility at a given temperature, this constitutes supersaturation. This is 

an unstable condition, as the excess solute separates when the solution is needed by introducing a 

crystal of the solute. The term "supersaturation" is frequently used erroneously for hot salt fluids. 

Surface-Active Materials - See Surfactant. 

Surfactant - A material which tends to concentrate at an interface. Used in drilling fluids to control 

the degree of emulsification, aggregation, dispersion, interfacial tension, foaming, defoaming, 

wetting, etc. 

Surfactant Fluid - A drilling fluid which contains a surfactant. Usually refers to a drilling fluid 

containing surfactant material to effect control over degree of aggregation and dispersion or 

emulsification. 

Surface Tension - Generally the force acting within the interface between a liquid and its own vapor 

which tends to maintain the area of the surface at a minimum and is expressed in dynes per 



REVISION 2006 15-45


centimeter. Since the surface tension of a liquid is approximately equal to the interfacial tension 

between the liquid and air, it is common practice to refer to values measured against air as surface 

tension, and to use the term "interfacial tension" for measurements at an interface between two 

liquids, or a liquid and a solid. 

Surge Loss - The flux of fluids and solids which occurs in the initial stages of any filtration before 

pore openings are bridged and a filter cake is formed. Also called "spurt loss." 

Suspensoid - A mixture consisting of finely divided colloidal particles floating in a liquid. The 

particles are so small that they do not settle but are kept in motion by the moving molecules of the 

liquid (Brownian movement). 

Swabbing - When pipe is withdrawn from the hole in a viscous fluid or if the bit is balled, a suction 

is created. This process can cause a reduction in hydrostatic head resulting in the intrusion of 

formation fluids, or in some cases, collapse of the formation into the well bore. 

Swelling - See Hydration. 

Synergism, Synergistic Properties - Term describing an effect obtained when two or more products 

are used simultaneously to obtain a certain result. Rather than the results of each product being 

additive to the other, the result is a multiple of the effects. 

Tannic Acid - Tannic. acid is the active ingredient of quebracho and other quebracho substitutes 

such as mangrove bark, chestnut extract, etc. 

Temperature Survey - An operation to determine temperatures at various depths in the hole. This 

survey is used to find the location of inflows of water into the hole, where doubt exists as to proper 

cementing of the casing and for other reasons. 

Ten-Minute Gel - See Gel Strength, Ten-Minute. 

Thermal Decomposition - The chemical breakdown of a compound or substance by temperature 

into simple substances or into its constituent elements. Starch thermally decomposes in drilling fluids 

as the temperature approaches 300°F. 

Thinner - Any of various organic agents (tannins, lignins, lignosulfonates, etc.) and inorganic agents 

(pyrophosphates, tetraphosphates, etc.) that are added to a drilling fluid to reduce the viscosity and/or 

thixotropic properties. 



REVISION 2006 15-46


Thixotropy - The ability of fluid to develop gel strength with time. That property of a fluid which 

causes it to build up a rigid or semi-rigid gel structure if allowed to stand at rest, yet can be returned 

to a fluid state by mechanical agitation. This change is reversible. 

Tighten Up Emulsion - Drilling fluid jargon to describe condition in some systems to which oil has 

been added and the oil breaks out and rises to the surface. Any chemical or mechanical means which 

will emulsify the free oil is known as "tightening up." 

Titration - A method or process of using a standard solution for the determination of the amount of 

some substance in another solution. The known solution is usually added in a definite quantity to the 

unknown until a reaction is complete. 

Tool Joint - A drillpipe coupler consisting of a pin and box of various designs and sizes. The internal 

design of tool joints has an important effect on fluid hydraulics. 

Torque - A measure of the force or effort applied to a shaft causing it to rotate. On a rotary rig this 

applies especially to the rotation of the drill stem in its action against the bore of the hole. Torque 

reduction can usually be accomplished by the addition of various drilling-fluid additives. 

Total Depth (TD) - The greatest depth reached by the drill bit. 

Total Hardness - See Hardness of Water 

Tour - A person's turn in an orderly schedule. The word, which designates the shift of a drilling 

crew, is pronounced as if it were spelled t-o-w-e-r. 

~ 

Turbulent Flow - Fluid flow in which the velocity at a given point changes constantly in magnitude 

and the direction of flow; pursues erratic and continually varying courses. Turbulent flow is the 

second and final stage of flow in a Newtonian fluid; it is the third and final stage in a Bingham plastic 

fluid. See Velocity Critical and Reynolds Number. 

Twist-Off – Separation of the drill string caused by the severing of a joint of drillpipe. Can be 

caused by the bit becoming stuck inadvertently while the rotary table continues to rotate the drill 

string to the point of pipe failure. 

Ultraviolet Light - Light waves shorter than the visible blue-violet waves of the spectrum. Crude oil 

colored distillates, residium, a few drilling-fluid additives, and certain minerals and chemicals 

fluoresce in the presence of ultraviolet light. These substances, when present in fluid, may cause the 

fluid to fluoresce. 



REVISION 2006 15-47


Univalent – Monovalent - See Valence. 

Valence or Valency - The valence is a number representing the combining power of an atom, i.e., the 

number of electrons lost, gained, or shared by an atom in a compound. It is also a measure of the 

number of hydrogen atoms with which an atom will combine or replace, e.g., an oxygen atom 

combines with two hydrogens, hence has a valence of 2. Thus, there are mono-, di-, tri-, etc. valent 

ions. 

Valence Effect - In general, the higher the valence of an ion, the greater the loss of stability to 

emulsions, colloidal suspensions, cross-linking etc. these polyvalent ions will impart. 

Velocity - Time rate of motion in a given direction and sense. It is a measure of the fluid flow and 

may be expressed in terms of linear velocity, mass velocity, volumetric velocity, etc. Velocity is one 

of the factors which contribute to the carrying capacity of a drilling fluid. 

Velocity, Critical - That velocity at the transitional point between laminar and turbulent types of 

fluid flow. This point occurs in the transitional range of Reynolds numbers of approximately 2000 to 

3000. 

V-G Meter or Viscosity-Gravity Viscometer - The name commonly used for the direct-indicating 

viscometer. See Viscometer. 

Vibrating Screen - See Shale Shaker. 

Viscometer - An apparatus to determine the viscosity of a fluid or suspension. Viscometers vary 

considerably in design and methods of testing. 

Viscometer, Direct- Indicating - Commonly called a.”V-G meter” The-instrument is a 

rotational-type device powered by means of an electric motor or hand crank, and is used to determine 

the apparent viscosity, plastic viscosity, yield point, and gel strengths of drilling fluids. The usual 

speeds are 600 and 300 rpm. See API RP I3B for operational procedures. 

Viscometer, Stormer - A rotational shear viscometer used for measuring the viscosity and gel 

strength of drilling fluids. This instrument has been superseded by the direct-indicating viscometer. 

Viscosimeter - See Viscometer. 

Viscosity - The internal resistance offered by a fluid to flow. This phenomenon is attributable to the 

attractions between molecules of a liquid, and is a measure of the combined effects of adhesion and 

cohesion to the effects of suspended particles, and to the liquid environment. The greater this 

resistance, the greater the viscosity. See Apparent Viscosity and Plastic Viscosity. 



REVISION 2006 15-48


Viscosity, Funnel - See Funnel Viscosity. 

Viscous Flow - See Laminar Flow. 

Volatile Matter - Normally gaseous products, except moisture, given off by a substance, such as gas 

breaking out of live crude oil that has been added to a fluid. In distillation of drilling fluids, the 

volatile matter is the water, oil, gas, etc. that is vaporized, leaving behind the total solids which can 

consist of both dissolved and suspended solids 

Wall Cake – Mud solids deposited on the wall of the wellbore opposite permeable formations in the 

form of filter cake resulting from filtration of the liquid fraction of the fluid. 

Wall Sticking - See Differential-Pressure Sticking. 

Water-Base Fluid - Common conventional drilling fluids. Water is the suspending medium for 

solids and is the continuous phase, whether or not oil is present. 

Water Block - Reduction of the permeability of a formation caused by the invasion of water into the 

pores (capillaries). The decrease in permeability can be caused by swelling of clays, thereby shutting 

off the pores, or in some cases by a capillary block of the pores due to surface tension phenomena. 

Water-In-Oil Emulsion - See Invert Oil-Emulsion Fluid. 

Water Loss - See Fluid Loss. 

Weight - In fluid terminology, this refers to the density of a drilling fluid. This is normally expressed 

in lb m /gal, lb m /ft 3 , or kg/m 3 . 

Weight Material - Any of the high specific gravity materials used to increase the density of drilling 

fluids. This material is most commonly barite but can be galena, etc. In special applications, 

limestone (CaCO 3 ) also called a weight material. 

Well Logging - See Electric Logging and Fluid Logging. 

Wetting - The adhesion of a liquid to the surface of a solid. 

Wetting Agent - A substance or composition which, when added to a liquid, increases the spreading 

of the liquid on a surface or the penetration of the liquid into a material. 

Whipstock - A device inserted in a well bore used for deflecting or for directional drilling. 



REVISION 2006 15-49


Whole Mud Dilution - A dilution process which involves selective dumping of the active system 

(such as sand traps and “bottoms up” mud) and replacement of the lost volume with fresh mud. This 

process has proved economical with inhibitive water-base systems and is the only method that 

actually removes colloidal size particles. Water dilution of the mud recovered from the 

aforementioned circumstances to reduce low gravity solids concentration, does not remove the 

undesirable solids which remain in the mud and require additional chemical treatment. 

Wildcat - A well in unproved territory, 

Workover Fluid - Any type of fluid used in the workover operation of a well. 

Yield - A term used to define the quality of a clay by describing the number of barrels of a given 

centipoise slurry that can be made from a ton of the clay. Based on the yield, clays are classified as 

high-, medium-, low-yield bentonite, etc. types of clays. 

Yield Point - In drilling-fluid technology, yield point means yield value. Of the two terms, yield 

point is by far the most commonly used expression. See Yield Value. 

Yield Value - The yield value (commonly called "yield point") is the resistance to initial flow, or 

represents the stress required to start fluid movement. This resistance is due to electrical charges 

located on or near the surfaces of the particles. The values of the yield point and thixotropy, 

respectively, are measurements of the same fluid properties under dynamic and static states. The 

Bingham yield value, reported in Ib/l00 sq ft, is determined by the direct-indicating viscometer by 

subtracting the plastic viscosity from the 300-rpm reading. 

Zero-Zero Gel - A condition wherein the drilling fluid fails to form measurable gels during a 

quiescent time interval (usually 10 minutes). 

Zeta Potential - Electrokinetic potential of a particle as determined by its electrophoretic mobility. 

This electrical potential causes colloidal particles to repel each other and stay in suspension. 

Zinc Chloride - ZnCI 2 . A very soluble salt used to increase the density of water to points more than 

double that of water. Normally added to a system first saturated with calcium chloride. 



REVISION 2006 15-50

BAKER HUGHES - Drilling Fluids Reference Manual

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