94061838 drilling fluids manual

ava Drilling Fluids & Services

Drilling Fluids Manual

ava S.p.A. Via Salaria, 1313/C 00138 Rome, Italy

Tel: +39 06 8856111 Email: [email protected] Internet: www.avaspa.it Version 1 November 2004

This manual is provided without warranty of any kind, either expressed or implied. The information contained in this manual is believed to be accurate, however AVA S.p.A, Newpark Drilling Fluids, LLC and any of its affiliates, will not be held liable for any damages, whether direct or indirect which result from the use of any information contained herein. Furthermore, nothing contained herein shall be construed as a recommendation to use any product in conflict with existing patents covering any materials or uses.

Drilling Fluids & Services

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TABLE OF CONTENTS CHAPTER 1 GENERAL DUTIES AND FUNCTIONS OF DRILLING FLUIDS

CHAPTER 2 BASIC CHEMISTRY

CHAPTER 3 GEOLOGY

CHAPTER 4 CLAY CHEMISTRY AND PROPERTIES

CHAPTER 5 POLYMER CHEMISTRY

CHAPTER 6 FLUID LOSS CONTROL

CHAPTER 7 WATER BASED FLUIDS

CHAPTER 8 OIL BASED FLUIDS

CHAPTER 9 BOREHOLE STABILITY

CHAPTER 10 FLUID DESIGN

CHAPTER 11 SOLIDS CONTROL

CHAPTER 12 UNDERBALANCED DRILLING AND FOAM

CHAPTER 13 RHEOLOGY

CHAPTER 14 PRODUCTION ZONE DRILLING

CHAPTER 15 CORROSION

CHAPTER 16 PROBLEM SOLVING WITH DRILLING FLUIDS


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CHAPTER 1 GENERAL RIG DUTIES AND FUNCTIONS OF DRILLING FLUIDS 1.1 KEY POINTS AND SUMMARY 1.2 ROTARY DRILLING TECHNIQUE - INTRODUCTION TO DRILLING FLUIDS 1.3 PRINCIPLE FUNCTIONS OF DRILLING FLUIDS

1.3.1 Improve Cuttings Removal Rates 1.3.2 Control Sub-surface Pressures 1.3.3 Suspend and Release Solids 1.3.4 Maintain Borehole Stability 1.3.5 Protect Producing Formations 1.3.6 Control Corrosion Rates 1.3.7 Seal the Wall of the Borehole 1.3.8 Aid in Maximizing Penetration Rates 1.3.9 Aid in the Retrieval and Interpretation of Formation Data 1.3.10 Cool and Lubricate the Bit and Drill String 1.3.11 Other Functions

1.4 COMPOSITION OF DRILLING FLUIDS 1.5 PROPERTIES OF DRILLING FLUIDS 1.6 DUTIES AND RESPONSIBLITIES OF A MUD ENGINEER REFERENCES


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1.1 KEY POINTS AND SUMMARY Drilling Fluids Technology is continually changing and improving. These changes are usually initiated by the need to improve drilling and production economics. Today many types of specialized fluids exist, which perform a diverse number of functions. The physical properties and chemical constituents of these fluids are designed, monitored and altered to suit one or more function at a time. These functions may be prioritized - either by design or when a solution to a specific situation is required. Drilling fluids usually contain a fluid phase and a solid phase. The fluid phase may consist of air, oil or water or a combination of these. The solid phase may consist of formation material and solid materials added to contribute to a certain function. 1.2 ROTARY DRILLING TECHNIQUE - INTRODUCTION TO DRILLING FLUIDS The application of Science and Technology to boring holes through the earth’s crust is a dynamic process. Documentation suggests that rotary drilling rigs with circulating systems were being used as early as the mid-nineteenth century.1 Since then, improving the economics of petroleum production has been a driving force behind the advancement of drilling technology. More recently, concerns regarding the safety of personnel and the protection of the environment have played an equal role in this technology. Today, the process of rotary drilling still has some similarities to the methods used over a century ago. A cutting head or bit is attached to a series of connected hollow pipes. The outside diameter of the pipe is smaller than that of the bit. This configuration is suspended from a set of traveling blocks such that it can be run partly in compression and partly in tension. The part in compression (the lower part) supplies the force on the bit. The bit is rotated clockwise as viewed from above. Drilling fluid is pumped down the inside of the pipe and through the bit. As the bit cuts through the rock, the cuttings are flushed away by the drilling fluid. The fluid continues to transport the cuttings to the surface through the annular space between the pipe and the wall of the hole. At the surface, the cuttings are separated and discarded. The Drilling Fluid is cleaned, and treated with chemicals before being pumped down the pipe again. The general arrangement of a drilling rig, mud pits, drill pipe, bit and casing is shown in Figure 1.1.


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Figure 1.1. Circulating System cross section

1 Pump 10 Cased Annulus 2 Shock Hose / Standpipe 11 Guide Base 3 Swivel / Top Drive 12 Blow Out Prevention Stack 4 Kelly / Drillpipe 13 Riser 5 Bottom Hole Assembly 14 Flowline 6 Bit 15 Diverter 7 Open hole annulus 16 Diverter Line 8 Casing Shoe 17 Shaker 9 Casing 18 Mud Pits


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A drilling operation can usually be divided into three distinct parts. The first involves drilling to the targeted depth or pay-zone. This is done in a series of intervals of decreasing diameter. The objective is to complete this part as quickly as possible, therefore the Drilling Fluid is designed to aid to this end. Steel casing is lowered and cemented into place at the end of each interval. While waiting for the cement to set, the physical or chemical properties of the Drilling Fluid may be adjusted to suit the conditions and demands presented by the next sequence of formations to be penetrated. The second part of the drilling operation begins once the potential pay zone is reached. Here the objective changes. It becomes essential to minimize formation damage caused by contaminated Drilling Fluids. Specialized drill-in fluids may be used to aid in hydrocarbon detection or to protect potential production zones. The final stage occurs when the well is completed. The casing and cement are perforated. The hydrostatic forces exerted on the formation are reduced enough to allow the fluids in the formation to flow to surface, or a pump is installed or steam is injected etc. The fluids used in this stage can have a significant influence on the productivity of the formation. Many operators are using various types of completion fluids regularly. As exploration and production costs increase, greater emphasis is placed on the role of drilling and completion fluids. The Petroleum Industry recognizes that both the design and management of Drilling Fluid systems play an important role in the success of a drilling operation. This is the case in terms of reduced drilling time and in increased productivity. Thus, Drilling Fluid technology continues to be a dynamic and multi-disciplinary science. 1.3 PRINCIPLE FUNCTIONS OF DRILLING FLUIDS Drilling Fluid was probably first used to aid in the transport of drilled cuttings to the surface.2 As the drilling industry evolved, additional functions became both apparent and necessary. Today, Drilling Fluid serves several principle functions. The chemical and physical properties of any Drilling Fluid depend on its components. The composition of a fluid may be altered or designed, in order to improve the efficiency of a certain function. When this is done it is likely that other properties or functions will also be affected. The efficiency of some functions can be affected by more than one property. An example of this is the influence of both density and viscosity on the rate of penetration. The functions of Drilling Fluids do have a practical order of importance. It is generally accepted that the transport of cuttings and the control of sub-surface pressures are essential functions. Other functions may take precedent at certain stages of the drilling program. Minor or inherent functions are listed in section 1.3.11. 1.3.1 Improve Cuttings Removal Rates As drilling proceeds, a great deal of emphasis is placed on the Drilling Fluid’s ability to remove the drilled cuttings. The term hole cleaning is used frequently and the cuttings returning to surface are observed continuously. Any changes in the size, shape, consistency, or the net volume of cuttings are noted. If the material returning to surface contains cavings or sloughings, adjustments to fluid properties are considered.


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The cuttings must be removed as quickly as possible to prevent annular blockage. This can become more complicated in deviated wells where the cuttings tend to form a cuttings bed on the low side of the hole. Further, the cuttings generated in some formations tend to be reactive in water-based solutions. They may chemically degrade or disperse as a function of time. Usually mechanical degradation occurs also. Cuttings may degrade to beyond the point of capture by the solids removal equipment on surface, contributing to rheological or density-associated problems. Several properties and parameters influence cuttings removal rates. The primary ones are the viscosity and velocity of the transporting fluid. The viscosity may be expressed in terms of funnel viscosity, yield point, consistency index, plastic viscosity, apparent viscosity, effective viscosity and annular viscosity - depending on the specific application and the mathematical model used. An accurate prediction of a fluid’s ability to transport cuttings can be quite complicated, since most Drilling Fluids are non-Newtonian or shear thinning. In non-Newtonian fluids, the effective viscosity decreases as the shear rate (velocity in this case) is increased. By using mathematical models for a given fluid, its behavior under various dynamic conditions may be predicted. Thus the correct combination of velocity and viscosity may be applied. Other parameters affect the cuttings removal rate. These include the density of both the fluid and the cuttings, and the size and shape of the cuttings. The mathematical modeling of fluid behavior and the mechanisms of cuttings transport are discussed in detail in the section on Rheology. 1.3.2 Control Sub-surface Pressures The prediction, detection and control of sub-surface pressures are an integral part of any drilling operation. Safety and environmental concerns are the main motives for devoting attention to sub-surface pressures. As depth increases, the weight of the overlaying rock exerts increased pressure on the formation being penetrated. Usually the pore size in the rocks is reduced. The bulk or net density of the formation increases and any liquid or gas trapped in the rocks is subjected to increasing pressure. The pressure profile of a well (pore pressure vs. depth) can be predicted through seismic or extrapolated from offset well data. Unfortunately, pressure prediction is not always accurate and pressure profiles are seldom linear. For the sake of simplicity, pressures may be reported as the equivalent fluid density required to balance the formation pressure. The pressure profile of a well or an interval may also be expressed in terms of its relationship to a column of fresh water of equal height. That is; over, under, or normally pressured. Two mechanisms may contribute to problems associated with drilling with an underbalanced fluid column. The first is related to stress relief and may result in borehole collapse. In tertiary or plastic formations the symptoms are evident as squeezing. Often the remedy is mechanical - wiping the hole. At times it is necessary to revert to increasing the fluid density to contain squeezing. The second is related to the pressure exerted on the connate fluids. If the pressure exerted by the Drilling Fluid doesn't exceed the pore pressure, formation fluids will flow into the well bore. The results of an uncontrolled, flowing well can be disastrous. In competent formations, over pressured shales may enter the wellbore at an excessive rate. Increased flowline gas levels may accompany this phenomenon. In this case the usual remedy is also to increase the fluid’s density. Both the value of the density and the fluid constituents contributing to that value are monitored closely during drilling operations. Several problems may result if the density is too high (over-


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balanced). These include borehole fracturing, slower penetration rates and rheological problems caused by the build-up and size degradation of the fluid’s solid phase. Rheological properties are also important when considering the effective density of the fluid column. Changing the viscosity can alter the equivalent circulating density and increase the surge / swab effect when reciprocating pipe. The effect of fluid density on various drilling parameters is discussed during Rheology, Hole Stability and Problem Solving. 1.3.3 Suspend and Release Solids Since most Drilling Fluids consist of materials in suspension as well as in solution, it is imperative that particles composing the solid phase remain suspended. If particle settling is adverse, the result can be costly. Problems such as barite settling on packers, or fill and bridges after trips or while logging take time to correct. When circulation is stopped, certain constituents of the fluid should form a greater degree of structure and gelation should occur. The degree to which this happens is a function of time and is defined as the thixotropic properties of the fluid - indicated by the fluid’s gel strengths. Thixotropic properties should be controlled. They shouldn't be so excessive that circulation can’t be resumed easily. They should be reversible such that after shearing for a reasonable time, the fluid returns to its original viscosity. This is necessary because at surface the fluid must have the ability to release the cuttings and high viscosity impairs the efficiency of the solids removal equipment. Thixotropic properties of Drilling Fluids are discussed in the chapters on Clay Chemistry and Rheology. 1.3.4 Maintain Borehole Stability Problems involving the stability of the borehole always require time and expense to correct. Occasionally a drilling operation fails when the problem can't be rectified in a timely manner. The cause or combinations of causes to this problem vary and the solutions are diverse. Drilling successfully through a problem formation may be entirely dependant on the Drilling Fluid’s formulation, maintenance and modification. Contributing factors to borehole instability include easily erodible formations such as evaporates or permafrost. Or, the formation might be fractured - with a weak matrix - unable to withstand overburden stresses. Many shales are hydratable and / or swelling, with a tendency to slough after a certain time of exposure to drilling fluid. Effects of over pressured shales are sometimes extremely difficult to correct and they may contain dangerous levels of gas. Overburden or tectonic forces may cause wells to squeeze making it difficult to pull pipe, log or run casing. There are several Drilling Fluid properties that can contribute to the maintenance of borehole stability. The treatment and mechanisms vary depending on the cause or the potential cause. An adjustment to the viscosity might alter the annular flow regime enough to prevent erosion. Raising the specific gravity may be the only requirement for successful drilling through over pressured zones. A wide range of inhibitive fluids has been developed. In some, the ionic content of the liquid phase has been altered with various salts. The effects of these fluids may be beneficiated with encapsulating polymers. In many areas, operators have found that drilling with oil-based fluids has proven to be by far the best solution to borehole stability problems. Drilling Fluid testing procedures and reporting formats are designed to monitor the particular properties and parameters that contribute to the maintenance of borehole stability. This volume contains a chapter on Borehole Stability.


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1.3.5 Protect Producing Formations As production costs rise, increasing emphasis is placed on protecting producing formations from potential damage caused by contact with borehole fluids. This protection can at times, be a primary function of the fluid. Specialized drill-in, completion, and work over fluids are designed and used in specific and localized applications. Usually formation damage is attributed to the reduction in size, or the plugging of the rock’s natural porosity. Generally the mechanisms that cause damage may be classified into two groups: Plugging associated with solids (including precipitates) and plugging associated with fluid filtrate.3 Fluid properties that may influence the success of a non-damaging fluid application include, density, solids content, fluid loss and filtrate characteristics, viscosity, and the fluid’s ability to limit corrosion. The background, theory and design parameters of non-damaging fluids are discussed later in the manual. 1.3.6 Control Corrosion Rates All metal components including drilling tools, casing and rig components must perform in a corrosive environment. The results of excessive corrosion include casing failure, damage to surface equipment and failure of down hole production tools. Corrosion mechanisms encountered in drilling operations are usually related to dissolved oxygen, carbon dioxide or hydrogen sulfide. Occasionally all three may be present. Usually the fluid is maintained in an alkaline state to help impede corrosion rates. A broad range of chemical additives is available to combat specific corrosion related problems. Corrosion is discussed later in the course. 1.3.7 Seal the Wall of the Borehole Drilling Fluids usually have a specific gravity sufficient to offset or counter-balance formation pressures. This aids in supporting the rock and preventing formation fluids from entering the wellbore. When the fluid column is overbalanced usually some fluid is lost to the formation. The degree of loss depends on the pressure differential, the size of the pores in the rock and the size and type of particles or bridging agents in the fluid. If fluid is lost to the formation, several adverse affects may result. Whole fluid losses can be expensive - especially in the case of oil-based fluids. Kick detection becomes hampered if losses are continual while drilling. When the liquid phase or filtrate of the fluid is lost to the formation, the solid phase becomes deposited as a cake on the wall of the hole. This cake may be of sufficient consistency to cause the pipe to become stuck. Filtrate invasion may also affect other Drilling Fluid functions, including the influence of the fluid on borehole stability or the protection of producing formations. The main methods of gauging the filtration characteristics of a Drilling Fluid include conducting API filtration or high temperature / high-pressure filtration tests on the fluid. Other more involved tests may be employed if required. The results of these tests are reported in volume of filtrate per time unit, and cake thickness. The actual characteristics of the cake may be vitally important in problem formations.


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Many different materials are available to effectively seal the wall of the borehole. They range in sized from colloidal clays to golf-ball and larger sized materials. Their application depends on the severity of the problem, and type of Drilling Fluid used. Fluid Loss Control is studied in detail in a chapter of this volume. 1.3.8 Aid in Maximizing Penetration Rates For years, substantial research has been directed at maximizing the Rate of Penetration (ROP) while drilling. Several factors, including bit design, Bottom Hole Assembly design, bit hydraulics, force on the bit, RPM, and Drilling Fluid properties have all proven to affect the ROP. The justification for the research is mainly economical. Drilling time is reduced and interval lengths can be increased. Numerous studies have been conducted and models examined in an attempt to correlate Drilling Fluid properties with changes to penetration rates. The fluid’s spurt loss4, certain filtration characteristics5, solids characteristics and density all have an effect on the ROP. Several Drilling Fluid properties are involved in a graphical model, called chip hold-down pressure. It attempts to correlate the pressure differential between the Drilling Fluid column and the formation pore pressure with drilling rates. Certain fluid properties are also considered when optimizing the Hydraulic Horsepower at the bit. The effect of various fluid properties on penetration rates is discussed throughout this volume. 1.3.9 Aid in the Retrieval and Interpretation of Formation Data Many methods for evaluating production potential exist. Some are conducted while drilling, while others are carried out when an interval is complete. The proper adjustment and maintenance of Drilling Fluid properties may aid most evaluation techniques. The rheological properties are important in terms of cuttings transport if accurate analysis of formation tops is to be made. The particle size distribution of various solid phase components should also be considered when running telemetry equipment or while coring. The thixotropic properties should be controlled - both to allow for accurate flowline gas detection and to prevent solids settling while testing or logging. The fluid’s ionic content may be adjusted to aid electric logging results. Tracer elements may be incorporated into the fluid to aid in evaluation of recovered formation fluids after drill stem testing. The minimization of formation damage caused by fluids remains the area of greatest concern when considering the topic of retrieval and interpretation of formation data. This function is an important part of Drilling Fluids design. 1.3.10 Cool and Lubricate the Bit and Drill String While drilling ahead, a considerable amount of heat is generated by the frictional forces of the rotating bit and drill string. This heat cannot be totally absorbed by the formation and must be conducted away by the drilling fluid. A quantity of heat is then lost at the surface. Lubrication is to a limited extent provided by the liquid phase and solids deposited on the wall as a filter cake. However, when drilling conditions become adverse, operators rely on improved Drilling Fluids formulation to aid in extending their engineering parameters. Wells are becoming deeper, hotter and more deviated - sometimes horizontal or "S" shaped. The Drilling Fluid should have the ability to minimize the influence of rotary torque and hole drag on well design. Various friction-reducing Drilling Fluid additives have been developed and several methods are


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available to test their effectiveness on given fluids. Rotary torque and hole drag are discussed in greater detail in the chapter on Problem Solving with Drilling Fluids. 1.3.11 Other Functions There are several other functions or roles which Drilling Fluids may serve. Although they are considered in drilling program design, fluid properties are not usually altered to enhance them. They include; contributing to drill string buoyancy, driving downhole motors and telemetry equipment, and the transport of data such as MWD and pore pressure data to surface. Areas which are not functions but extremely important considerations, include the impact of a particular Drilling Fluid system or its components on the safety and protection of personnel and the environment. In most areas of the world these considerations take precedent over the benefit of any other functions of Drilling Fluids. 1.4 COMPOSITION OF DRILLING FLUIDS Drilling Fluids usually consists of two components; the fluid phase and the solid phase. The fluid phase may consist of either a single fluid, or two immiscible fluids (an emulsion or foam). If two fluids are used they are usually formulated to contain a discontinuous or dispersed phase within a continuous phase. A general classification of Drilling Fluids based on their fluid phase is outlined in table 1.1. TABLE 1.1 CLASSIFICATION OF DRILLING FLUIDS SYSTEMS BASED ON THEIR FLUID PHASE Fluid Phase Gas Water Oil Gas

Foam

Water

Direct Emulsion

Oil

Invert Emulsion

Air or gas alone

Air or gas with water and/or oil to form foam

Oil free water/brine fluids

Continuous water/brine phase with emulsified oil

Water free oil fluid

Continuous oil phase with emulsified water/brine

Various materials (solutes) may be dissolved in the fluid phase to change or control certain properties of the fluid. A general classification of Drilling Fluids solutes is given in table 1.2.


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TABLE 1.2 DRILLING FLUIDS SOLUTES a Solute

Function

Solute

Function

Salts/Ionic Compounds

Increase density (completion brines) Aid inhibition Prevent solution of evaporites Used as tracers Adjust water activity

Polymers

Control fluid loss Deflocculation Flocculation Encapsulation Control viscosity

Alkaline Compounds Inhibit corrosion Solubilize polymers Alter charges on clays Aid inhibition

Surfactants Corrosion control Emulsion stabilization Prevent bit balling

Acids Cement contamination treatment Clay dispersion

Asphaltic derivatives Control fluid loss Suspension properties

a) Note that not all substances are soluble in both oil and water The benefit of gas-based fluid systems is realized in rapid penetration rates. Its application is limited to competent, low-pressured formations. As formations become wet, mist, foam or stable foam must be used. Water is the most commonly used continuous phase due to its low cost and availability. Because water is a polar medium it has the advantage of being able to dissolve many different substances. This feature may also contribute to undesirable effects. Water dissolves gases, which cause corrosion. The ionic compounds, which make up evaporate formations, are easily dissolved by water - sometimes resulting in severe hole erosion. Most formation clays have an affinity for water. The expansion forces generated when they adsorb water are often strong enough to contribute to borehole instability. To overcome these effects, various solutes may be incorporated into the water phase. These have led to a general classification and nomenclature of water-based fluids systems, many of which have been designed with some form of inhibition in mind. Water-Based Fluids and their components are discussed later in this course. Oil-based fluids have been commercially available since the 1940's. The disadvantages inherent in water-based fluids may be overcome when oil becomes the continuous phase. This is due to the non-polar nature of oil. It will not solubilize salts or react with clays. Most oil-based fluids are an emulsion, with brine making up the dispersed phase. Oil-based fluids may be formulated with diesel oil, or a more environmentally compatible low toxicity oil. Oil-based fluids and their components are presented following the chapter on Water-Based Fluids. The solid phase of Drilling Fluids consist of particles held in suspension by the liquid phase. There are several ways of classifying solids in Drilling Fluids: 1. By size; colloidal to gravel sized. 2. By surface charge; reactive or inert. 3. By how they entered the fluid; drilled solids or "commercial solids".


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4. By their specific gravity; high or low gravity solids. Drilled solids are derived from the formation. Although the presence of drilled solids may improve filtration, viscosity or density characteristics, other additives perform these functions more efficiently. Drilled solids are usually low gravity solids. Excessive concentrations of drilled solids are undesirable (contaminants) as they contribute to abrasiveness and make rheological properties difficult to control. The degree of tolerance a fluids system has for drilled solids depends on the concentration of "commercial solids" and the availability of deflocculants within the system. Commercial solids are non-soluble materials that are added purposely to a fluid system to control a property. They may be broadly classified into five different functional groups as outlined in table 1.3. The impact of the solid phase of Drilling Fluids is discussed throughout both volumes of this manual. TABLE 1.3 FUNCTIONS OF SOLID PHASE ADDITIVES GROUP

FUNCTION

EXAMPLES a

Weighting agents

Increase specific gravity

Barite, Hematite

Clays Increased viscosity, aid in bridging, increase lubricity

Montmorillonite, Sepiolite

Bridging agents Seal porosity Fiber, Flakes, Resins, Salts

Solid phase torque reducers Reduce rotary torque & hole drag Graphite, Teflon beads, Bentonite

Hole stabilization additives Plug microfractures Asphalts, Gilsonite

a Note: The examples given do not constitute a complete list. 1.5 PROPERTIES OF DRILLING FLUIDS The properties of Drilling Fluids may be divided into two groups: physical properties and chemical properties. The physical properties of a Drilling Fluid are usually influenced to some degree by both the liquid and solid phases of the fluid. The chemical properties, which are considered important, are influenced by constituent solutes including ionic species, polymers and other dissolved compounds. Various physical and chemical properties are incorporated into fluid design, monitored and reported - especially when they pertain to a specific application or problem. These applications include formation damage, high pressures, hole stability, high temperatures, contaminating formations and friction. Generally the properties applicable to the majority of fluids systems include specific gravity and viscosity characteristics. Properties particular to specific fluids are outlined in Volume II of this manual. The procedures for testing these properties are also outlined in Volume II.


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1.6 DUTIES AND RESPONSIBLITIES OF A MUD ENGINEER The purpose of this section is to discuss the various aspects of the day-to-day activities of an Ava Drilling Fluids Mud Engineer. As a representative of Ava, the most important skill you must possess is the ability to communicate with all the stakeholders (e.g. Office operations, technical service, sales; truckers; rig supervisors; crews). An open discussion of the points below will give you an idea of the issues a Mud Engineer from Ava S.p.A. will deal with on a daily basis. 1. Safety ü Driving

§ Night driving § Hours on the road § Conditions § Defensive driving

ü On the rig

§ Mud tanks § Product stockpile/warehouse § PPE § Safety Certification(s) § Duties

ü Testing equipment

§ HTHP § Chemicals § Pipettes § Laboratory § Samples/shipping

ü Warehouse/Products

§ MSDS § ADR § Product Data Sheets

ü Cellular phone

§ Hands Free § Timing/Duration

2. Communication ü Cellular phone

§ Hands Free § Timing/Duration


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ü Weekly Reports

§ Monday/Thursday

ü Problems

§ ASAP with information!

ü Truckers

§ Loads/timing § Road Conditions § Directions § Special Instructions

ü Engineer/Drilling Foreman/Toolpush

§ Mud Program § Drilling Program § Troubleshooting § Special Operations § Loads/timing

ü Derrickman/Rig Crew

§ Current mud properties/operations § Obstacles/Questions/Concerns § Mud Program Implementation § Drilling Program – pre-planning § Troubleshooting § Special Operations – cementing, logging, coring, running casing § Loads/timing – OBM/WBM/Special additives § Mixing Instructions – verbal/written § MSDS § ADR

3. Communication ü Technical Services/Sales

§ Current mud properties/operations § Obstacles/Questions/Concerns § Mud Program Implementation § Drilling Program – pre-planning § Troubleshooting – Vital link to Ava customers § Samples – product/mud/solids § Special Operations – cementing, logging, coring, running casing § Loads/timing – OBM/WBM/Special additives


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4. Logistics ü Programmed products

§ Rig suitability § Availability § Quantities § Customer expectations

ü Warehouse inventory

§ Availability § Quantities § Ordering § Timing – warehouse/rig § Pre-planning

ü Substitutions

§ Weights/clays § Polymers – PHPA’s, Xanthan, FLC, other § LCM § Lubricants § Defoamers

ü Crisis management

§ Lost circulation § Pressure control § Critical Sour operations

5. Reporting

ü Mud reports

§ Copies § Floppy disk(s)/downloads § Required Information

ü Summaries

§ Timing § Contents

ü AVA Software

§ Practice § Ask § Suggest

ü Telephone

§ Timing/timeliness/duration


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ü Timing/Frequency

ü Crisis communications

§ ASAP with information § Customer expectations § Ava Operations/sales expectations

6. Testing

§ Per instructions in Ava Mud Manual or as defined by various API Bulletins

§ Timing/timeliness/frequency § Location § Samples § Pilot testing/laboratory analysis

7. Discussion ü Safety

§ Personal § Rig § Fatigue

ü Driving

§ Moving violations § Tickets § Other

ü Hot Shots/Deliveries

§ Insurance § ADR

ü Duties

§ Organization - planning/Notes - records § Rig § Hauling

ü Service

§ Define/discuss


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References 1 H.C.H. Darley & George R. Gray, Composition and Properties of Drilling and Completion

Fluids, 5th ed. (Houston: Gulf Publishing Company, 1988), 38 ; all subsequent citations are to this edition.

2 Darley and Gray, Composition and Properties, 38. 3 Thomas O. Allen and Allan P. Roberts, Production Operations, 3rd ed. (Tulsa: Oil and

Gas Consultants International, 1989), 2: 68, 69; All subsequent citations are to this edition.

4 Darley & Gray, Composition and Properties, 416. 5 Darley & Gray, Composition and Properties, 422.


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CHAPTER 2 BASIC CHEMISTRY 2.1 KEY POINTS AND SUMMARY 2.2 BASIC DEFINITIONS

2.2.1 The Fundamental Units of Substances 2.2.2 Quantifying these Units 2.2.3 Chemical Formulas and Equations

2.3 CHEMICAL BONDING

2.3.1 Electron Shells, Ions and Valency 2.3.2 Ionic Bonding 2.3.3 Covalent and Mixed Bonding 2.3.4 Other Atomic Influences

2.4 SOLUTIONS

2.4.1 Types of Solutions 2.4.2 The Hydration of Ions 2.4.3 Water Solubility 2.4.4 Oil Solubility 2.4.5 Dispersions and Dispersability 2.4.6 Colloidal Systems and Suspensions 2.4.7 Equilibrium and Precipitation 2.4.8 Drilling Fluids: Multi-phase Homogenates

2.5 CHEMICAL CALCULATIONS

2.5.1 Molarity and Normality 2.5.2 Concentrations in Solutions and Suspensions 2.5.3 Converting and Calculating

2.6 ACIDS AND BASES

2.6.1 pH 2.6.2 Ionization Constant 2.6.3 Acids and Bases 2.6.4 Practical pH

2.6.5 Alkaline Drilling Mud's 2.7 SURFACE CHEMISTRY

2.7.1 Surfaces 2.7.2 Surface Tension 2.7.3 Emulsion and Foam 2.7.4 Surface Charges 2.7.5 Other Surface Phenomena 2.7.6 Semi permeable Membranes and Osmotic Pressure 2.7.7 Altering Surface Chemistry


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2.1 KEY POINTS AND SUMMARY Ava Drilling Fluids has included this chapter to serve as an introduction to petroleum and mud chemistry, and should be used as a review, or as a quick reference. As with any science it would be impossible to include every facet of chemistry within this short introduction. Therefore, for the sake of succinctness, mainly the concepts and terms that apply to drilling fluids are addressed here. Some concepts are expanded upon later in the manual, as required for a better understanding of specific chemical phenomena. It is recommended that any reader who has an additional interest in basic chemistry, turn to a first year text book such as Chem One by Waser, Trueblood and Knobles, published by McGraw-Hill. 2.2 BASIC DEFINITIONS 2.2.1 Fundamental Units of Substances If you put a cube of sugar in your hand it will have a specific amount of weight associated with it, or in scientific terms, the cube of sugar has a specific mass (for argument sake it’s weight or mass = 1 gram). The term mass refers to the quantity of matter contained in a particle or body. On the other hand, the term matter refers to anything that has mass or occupies space. The constituents and the behavior of matter are of concern and interest to scientists and lay-people alike. Matter exists in three generally accepted states solids, liquids and gases. There are several ways to classify matter. One simple method is to group matter by particle size as outlined in Table 2.1. Table 2.1 Name Example Size Visibility Sub Atomic Protons, Neutrons,

Electrons

<<1x10-12 meters Inference by high

speed bombardment

Atoms Elements <1x10-9 meters X-rays

Molecules Groups of atoms <1x10-8 meters Electron microscopes

Compounds/materials Groups of molecules 1x10-8 meters to

visible

Microscopes to the

human eye


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Fig 1 & 2 are both high powered microscopic pictures of some common materials, notice the ordered structure of the Plexiglas compared to the random order of the emulsion.

Fig. 1. A picture of Plexiglas. Each particle is 2x10-6 meters in length.

Fig. 2. A picture of oil in water or an emulsion.

In the 19th & 20th Century, scientists have come to understand what constitutes the basic building blocks of matter. Today, some of the smallest particles known are quarks, anti-quarks and gluons. Combinations of these particles give rise to mesons, baryons, and combinations of these particles give rise to neutrons, protons, and electrons and before you know it you have a cube of sugar in your hand. For interest sake, Quarks, discovered in 1969, exist in at least six different “flavors”: up, down, strange, charm, top and bottom. Each flavor comes in three “colors”, red, green and blue1.


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Protons, Electrons and Neutrons At a sub-atomic level matter is made up of three particles, protons, electrons and neutrons. If you picture an atom as a small sphere, the core of that sphere is made up of neutrons (n, neutral, atomic mass unit (AMU) = 1.009), protons (p, positive charge, AMU = 1.0) and orbiting that core (like satellites) are electrons (e, negative charge, AMU = 0.0005). An atom with a specific number of protons is classified as an element. The element carbon (C) has six protons, six electrons and 6 neutrons for an atomic weight of 12.011. An atom has equal numbers of protons and electrons (net charge = 0), but can vary in the number of neutrons present in the core. Elements that have extra neutrons but the same number of protons are called isotopes. Isotopes have similar chemical properties but differ in mass. Carbon-14 (14C, AMU = 14, used in archeology to carbon date artifacts) is an isotope of carbon with two additional neutrons. Carbon has 7 different isotopes. Neutrons and protons are held together by nuclear forces. Of interest is the removal or addition of electrons to an atom. By adding an electron (-1) to an atom, we would have a negative (–1) charge, i.e. a negative ion (anion). If we took an electron away, the atom would have a net positive (+1) charge, i.e. a positive ion (cation). This is important, as this is the foundation to understanding the interactions between clays, rocks and mud systems. There are currently 111 known elements. It is believed that all of the matter in the universe is composed of these elements. Theoretical physicists believe that the lightest elements were formed in less than half an hour, from a primordial mixture of neutrons and electromagnetic radiation. Table 2.2 lists the known elements in an order that groups elements of like properties together and it is called the “Periodic Table of the Elements”.


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Table 2.2: Periodic table of the Elements (Mendeleev)

Alkaline metals: Group I (1A) Alkaline earth metals: Group II (2A) Transition metals: Groups 3B, 4B, 5B, 6B, 7B, 8, 1B, 2B Non metals: Groups III, IV, V, VI, VII (3A, 4A, 5A, 6A, 7A) Halogens: Group VII (7A) Noble gas: Group VIII (8A) Lanthanides: From Cerium to Lutetium Actinides: From Thorium to Lawrencium


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Chemicals Two or more elements may combine chemically to form a molecule (or compound). A molecule can be as simple as two hydrogen atoms H2 (hydrogen gas, fig. 3) or as complex as C10H14N2 (nicotine, fig. 4). A molecule consists of differing atoms (elements) arranged in a specific order and are represented by a chemical formula. Chemical formulas can be visualized by drawing out chemical structures based on the known geometry of the atoms and how they interact with each other. With 111 elements, the possible numbers of molecules are limitless.

H H

N

N

CH3Fig 3. Hydrogen gas

Fig 4. Nicotine Bonds hold atoms together; these bonds are complex interactions between the protons and electrons of both atoms. To make a bond between two atoms you must add energy to the two atoms, force them close together and a bond will form. A bond between two atoms contains a lot of energy, although orders of magnitude lower than the energy holding an atom together. Think about the difference between breaking a chemical bond (TNT explosion) and an atom (an atom bomb explosion)! Most reactions are reversible so if you add enough energy you will be able to break the bond between the two elements, which will release the energy stored in the bond (usually released as heat). If more energy is required to break a bond than is released by the bond the reaction is called endothermic i.e. a thermal cracker adds energy to break apart hydrocarbons. If more energy is released when the bond breaks than is required to break the bond then the reaction is called exothermic i.e. conventional explosives. An exothermic reaction can also be as simple as dissolving a bag of caustic soda in water. The heat required to break apart the ionic lattice (lattice energy) is less than the energy given off as water rushes to hydrate the ions (hydration energy); therefore caustic or caustic potash will give off large amounts of energy in the form of heat when dissolved in water. Salt on the other hand is endothermic when dissolved in water i.e. the lattice energy is greater than the hydration energy. See fig. 5.


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Figure 5

Energy comes in many different forms, chemical reactions (stored energy), heat, light, sound or an electric current. An example of a chemical reaction is the formation of water. A liquid formed by the combination of two elements, hydrogen and oxygen (which are gasses) in the presence of heat. Water can be reacted back into hydrogen and oxygen by adding energy in the form of an electric current (electrolysis).

2H2O H2 + O2e-1

PtH2 + O2

Spark

All of the chemicals added to drilling fluids are molecules or chemical compounds; some of the more common ones are listed in Table 2.3


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Table 2.3 Name Chemical formula Common Name Aluminum sulfate Al2(SO4)3 Barium sulfate BaSO4 Barite Calcium bromide CaBr2 Calcium chloride CaCl2 Calcium carbonate CaCO3 Limestone Calcium hydroxide Ca(OH)2 Hydrated lime Calcium oxide CaO Quick lime Calcium sulfate CaSO4 Anhydrite Calcium sulfate bis-hydrate CaSO4⋅2H2O Gypsum Hydrochloric acid HCl Potassium chloride KCl Potash Potassium hydroxide KOH Caustic Potash Sodium bicarbonate NaHCO3 Bicarb Sodium bromide NaBr Sodium carbonate Na2CO3 Soda ash Sodium chloride NaCl Salt Sulfuric acid H2SO4 Zinc bromide ZnBr Notice in this list of chemical compounds that they are all salts of some kind! This gives us an important distinction. Compounds or molecules that have no carbon/hydrogen in them are classified as inorganic compounds; a common example of an inorganic compound would be table salt. Compounds that have a carbon/hydrogen atoms contained within the molecule are classified as organic compounds of which oil would be a common example. Molecules have very different properties from each other and when they group together they tend to form into structures that are common to us; compare a sugar cube, a coffee cup and water. Sugar molecules in large quantities stack together (like CD’s stacked in a tower) in the form of a crystal. Styrene Fig. 6 is chemically reacted together to give polystyrene (plastic cup), a macromolecule.

Styrene

Int.

x

Polystyrene

Fig 6

Water molecules at room temperature are clustered together and randomly float around bumping into each other. This gives us a property we recognize as liquid water. These three compounds all have very different states from each other. What if we bring the temperature of the water down to – 20°C, then what happens? The water molecules slow down enough to stack together and crystallize to give ice. A structure similar to the sugar cube. Almost all compounds have the three physical states associated with them


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(liquid, solid, gas), water is one which we all have experience with. Most other types of chemicals require extreme conditions to change there phase from liquid to gas or solid. One of the ways to make sodium metal and chlorine gas is to heat table salt past 430°C to melt it. If you bring air down to – 177°C then it would turn into a liquid. Other common terms of solids classification a drilling engineer will use are crystals (above), colloids and macromolecules. Colloids can be described as compounds that are held in a liquid by their interaction with the surrounding fluid, a common colloid is blood. In drilling mud’s clays are colloids. Drilling fluid polymers are macromolecules, and they consist of many thousands if not millions of repeating molecules put together in a chain. Geologists define a mineral as a naturally occurring, inorganic crystalline solid that has a definite chemical composition and possesses characteristic physical properties. Molecules often combine in an ordered, repeating structures to form crystals, the normal form of the solid state of matter. The arrangement of the ions, atoms, or molecules in a crystal comprises a definite pattern called a lattice (see fig 5). 2.2.2 Quantifying these Units Atoms and elements may be categorized by several different methods. The Periodic Table is one way of classifying elements which most of us are familiar with. The chief function of the periodic table is to serve as a fundamental framework for the systematic organization of chemistry. Figure 7 depicts the key to a simple rendition of the periodic table shown in Table 2.2. The top number 6 represents the atomic number of carbon, the C is the symbol of carbon and the 12.01 is the atomic weight. Fig. 7

Other varieties of the periodic table provide a much more in-depth description of the characteristics and properties of elements. The elements are sometimes classified as either metals or non-metals. Metals are described as elements whose compounds form positive ions in solution and whose oxides form hydroxides rather than acids with water. The atomic number is simply the number of protons of each atom of an element. It is the main identity parameter of each element. (Each element has a different number of protons and hence, a different atomic number). Since atoms are electrically neutral, the atomic number is also the same as the number of negatively charged electrons orbiting the nucleus of that atom. The atomic weight of an element refers to the total mass of all the constituents of each of its atoms, including protons, neutrons and electrons. The mass of one proton is equal to one atomic mass unit (AMU). The mass of a neutron is 1.009 AMU and an electron is 0.000544 AMU. Since the mass of an electron is so minute and the mass of a neutron is almost 1, one would think that the atomic weight of an element would be a whole number. A look at Table 2.2 shows this is not true. The reason is, that the atomic weight is an average of the weights of all of the isotopes or species of atoms of an element. The atoms of individual elements all have the same atomic number, equal to the number of protons in the nucleus. In most cases each atom’s nucleus has an equal number of neutrons. An


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isotope of an element is composed of atoms with one or more extra neutrons in their nuclei. This gives the isotope a larger atomic weight, increasing the average atomic weight of the element; hence the atomic weight can be a fraction. Twenty-one elements have no isotopes, each consisting of only one kind of atom. The remaining natural elements have from 2 to 10 isotopes each. The 12C is the international standard of atomic weight. Its nucleus has 6 protons and 6 neutrons. When 7 neutrons are present, its atomic weight becomes 13 and the element is called carbon 13 with the abbreviation denoted by a superscript (13C). Radioactive isotopes decay, emitting energy in the form of particles. Ultimately a new, more stable element is formed. Tritium is a man-made radioactive isotope of hydrogen, used occasionally in drilling fluids. Because it decays at a known rate (a 12.5 year ½ life) and concentrations are identified easily, it makes a good tracer. The term molecular weight is used regularly in this manual. It is a chemical term, which simply refers to the sum of the atomic weights of the atoms in a molecule. The molecular weight of the common natural gas methane (CH4) is 16.043, the atomic weight being…

C=12.0114H=4x1.0079

H H

H H

CH416.04

16.031300C 74.87% H 25.13%

2.2.3 Chemical Formulas & Equations Several types of formulas serve to designate chemical compounds, each type conveying different information. The empirical formula of a compound is the ratio of moles of each element present in the compound, expressed in the form of small whole numbers. The empirical formula of any compound can be expressed as small whole numbers because atoms are indivisible. If the ratio of moles were 1Fe:1.5O, as it is in iron (III) oxide, the empirical formula would be written as Fe2O3. Structural formulas provide information on the detailed atomic arrangement in a compound. The ensuing text shows structural formulas when explaining covalent bonding. The structural formula for acetylene is...

C C HH or HH

fig 8

Chemical equations are used to show the reactions of substances in terms of their formulas, relative numbers of reactants and the products involved. By definition chemical equations should be balanced. They should show the same number of each atom on both sides and the net charge should be the same on both sides. Balancing an equation can mean re-arranging it to fit this definition. For example, an unbalanced equation:

C3H8O + O2 CO2 + H2Oheat

The simplest procedure is to first balance an atomic species that appears in only one compound on each side, starting with C.


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C3H8O + O2 3CO2 + H2O

heat H also appears in only one compound on each side. H can be balanced by putting 4H2O on the right.

C3H8O + O2 3CO2 + 4H2Oheat

Since there are now 10 oxygen atoms on the right there must be 10 on the left. There is already one atom of O in each molecule of C3H8O, therefore:

C3H8O + 4.5O2 3CO2 + 4H2Oheat

Fractional coefficients are acceptable. 2.3 CHEMICAL BONDING The preceding text explained that a compound is a combination of two or more elements combined chemically. A chemical bond is an attractive force between atoms, which is strong enough to permit the combined aggregate to function as a unit. In simple terms, a bond is formed when protons from the other atom are sharing electrons from the other atom. There are three principal types of chemical bonds that are important. These include: ionic, covalent, and hydrogen bonds. Table 2.4 Summary of Chemical Bonds

Bond Type Length (nm) Strength (kcal/mole) in water Covalent 0.15 90

Ionic 0.25 3 Hydrogen 0.30 1

2.3.1 Electron Shells, Ions and Valency (oxidation state) A simplified method for understanding the way in which electron orbitals are arranged around an atomic nucleus is to consider the valence-bond (VB) model. Electrons are arranged in shells (s, p, d or f), orbits or electron clouds around the nucleus. Figure 9 shows an s orbital and the p orbitals, the most important in forming ionic or covalent bonds. These figures represent the theoretical pathways the electrons follow.


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s orbital1p orbital

1 s orbital& 1 p oribtal 2p orbitals 3p orbitals

fig 9

The closest or first shell, s has the lowest energy level and may contain a maximum of 2 electrons. The energy levels increase with the distance from the nucleus. The next orbital p may contain a maximum of 6 electrons one in each lobe. Table 2.5 helps to explain the arrangement of electrons in the first twenty elements. Table 2.5 Electron orbitals in the first 20 elements Number of electrons per orbital Element Atomic number 1 s 2 s 2 p 3 s 3 p 4 s Valence electronsHydrogen 1 1 1 Helium 2 2 0 Lithium 3 2 1 1 Beryllium 4 2 2 2 Boron 5 2 2 1 3 Carbon 6 2 2 2 4 Nitrogen 7 2 2 3 5 Oxygen 8 2 2 4 6 Fluorine 9 2 2 5 7 Neon 10 2 2 6 0 Sodium 11 2 2 6 1 1 Magnesium 12 2 2 6 2 2 Aluminum 13 2 2 6 2 1 3 Silicon 14 2 2 6 2 2 4 Phosphorus 15 2 2 6 2 3 5 Sulfur 16 2 2 6 2 4 6 Chlorine 17 2 2 6 2 5 7 Argon 18 2 2 6 2 6 0 Potassium 19 2 2 6 2 6 1 1 Calcium 20 2 2 6 2 6 2 2 When electrons arrange themselves around a nucleus, the innermost shells are always filled first. Electrons also have a tendency to try to keep the other shells of an atom full. Table 2.5 shows that these shells are not always filled. Sodium (Na) for example, has 2 electrons in the first s shell, 2 in the second s shell, 6 in the second p shell, but only 1 in the third s shell. Islands of Stability Three elements in table 2.4 have zero valence electrons, helium, neon, and argon. These elements are called noble gases and are known to be the most inert elements in the universe.


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The reason for this inertness has to do with the electrons surrounding these elements. The orbitals surrounding the noble gases are completely full. Hence the electronic charges of these elements are entirely balanced and utterly un-reactive towards other electrons. With this knowledge we can look at every other element and say in a generalized way that (octet rule) “all other elements will lose or gain only enough electrons to get that element to a noble state” or every element wants to be a noble element! In terms of electrons every element wants to fill the s orbitals (2 electrons) and the p orbitals (6 electrons). In simple terms we can look at sodium and say it wants to get to neon so it will lose one electron and become a Na+ cation. The energy required to remove that electron is called the ionization potential (IP), fig 10. The IP for sodium = 118 Kcal/mole Fig. 10

Na Na+ + e-1 ∆Ho=IP Elements in the first row are known to have low IP’s and are known to be electropositive elements. Elements to the far right of the periodic table (halogens) are known to be electronegative. These elements have an electron affinity (EA) i.e. they love electrons because it makes them have a noble type electronic structure fig 11. The EA for fluorine to go to a fluorine anion = 78.3 Kcal/mole. Fig. 11

F + e-1 F-1 −∆Ho=EA Electropositive (alkali metals) and electronegative (halogen) elements tend to lose and gain electrons so easily they form pairs of ions. This type of bonding is described as ionic bonding. For compounds in the middle of the table the energy required to lose or gain enough electrons to get to a noble state is high, for carbon to have an electronic state similar to He the IP = 1480 Kcal/mole! Fig. 12

C C4+ + 4e-1 ∆Ho=1480.7Kcal/mole Consequently these elements get to their octet (2+6) state by sharing electrons. Bonds in which two (or more) electrons are shared are described as covalent bonds. Fig. 13

+ 4HC H

H

H CH

Carbon thinks that it is neon and hydrogen thinks it is helium, and the molecule is very stable. Elements that have the greatest electronegativity are in the far top right of the periodic table; those with the weakest are in the lower left of the periodic table. This is important because when you have two elements joined together by a covalent bond, the more electronegative atom will concentrate more of the electron density to itself. This creates a dipole moment and can be used to visualize where a charge potential resides on a molecule.


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Fig. 14

C F C O Al C B Cl

dipole moment(+) (-)

These are not full +/- charges more like hints of charges (δ). But these hints can be powerful enough to create viscosity in a drilling mud. 2.3.2 Ionic Bonding An ionic bond results from the electrostatic attraction between oppositely charged ions. This bond may be thought of as the transfer of an electron from one atom to another such that two oppositely charged ions result. The energy of these bonds varies depending on where the element is in the periodic table top right or bottom left. Thus it requires more energy to break an ionic bond between two small ions (top of table). Ionic crystals are substances in which oppositely charged ions are packed together in a highly regular three-dimensional array, held together chiefly by ionic bonds. In sodium chloride crystals, equal numbers of Na+ ions and Cl- ions occur in an intermittent regular pattern. It is important to realize that sodium chloride crystals do not contain actual NaCl molecules, but only Na+ and Cl- ions. This applies also to molten sodium chloride or an aqueous solution of sodium chloride. These properties are applicable to all ionic compounds. The compounds listed in Table 2.3 are all ionic compounds. Fig. 15

O

S

O

O-1-1O

Sulfate (SO4

-2) (fig 15) is called a divalent anionic compound because it is a compound with a net, double negative charge. Sodium (Na+) is a monovalent cation. 2.3.3 Covalent and Mixed Bonding Lewis first proposed the idea that covalent bonds involved shared pairs of electrons in 1916. However, it was not until the development of Quantum Mechanics (the theory developed from Plank’s Quantum Principle and Heisenberg’s Uncertainty Principle) that a clear understanding of covalent bonding became possible. Because of its simplicity, the Lewis model is still commonly used today. This section does not consider Quantum Mechanics. Like ionic bonding, the effect of covalent bonding is to satisfy the atom’s tendency to obtain a full electron shell. A single bond involves the sharing of 2 electrons. Double and triple bonds share 4 and 6 electrons respectively. Bonds of intermediate multiplicity also exist. When a molecule is depicted on paper using a structural formula, these bonds are described using single, double or triple lines between atoms. Unshared outer electrons are sometimes represented by dots:


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Fig. 16

CH3

CH2 OH

CH2

CH CHCH2

C C HH

Ethanol Butadiene Acetylene

H2NNH2

1,6-diamniohexane

When electron pairs are shared by two nuclei, the bonding electrons are relatively localized in the region of the two nuclei. Frequently a degree of delocalization occurs when the shared electrons have a choice of orbitals. In a covalently bonded molecule, the center of the positive charge may not coincide with the center of the negative charge (this depends on the electronegativity of the two atoms). When this occurs, the molecule retains electric dipole moments. When the dipole moments are permanent, the molecule is said to be polar. Water is a polar molecule. The end with the oxygen atom has an overall net negative charge, while the end with the two hydrogen atoms has an overall net positive charge. (The center of the positive charge is halfway between the two H atoms). The effect is as though the oxygen was keeping the hydrogen’s electrons for longer than its fair share of time. This electrical effect helps many ionic compounds such as salts; dissolve in covalent compounds like water (see fig 5). Oil is an example of a non-polar liquid. Fig. 17

HO

H

2δ−

δ+ δ+

OH Η

Dipole in water Electron orbitals in water Covalent bonds provide strong attraction between the atoms comprising a molecule (see table 2.4). However, the forces between individual molecules are not necessarily as ridged in covalent compounds as ionic compounds. Therefore covalent compounds usually retain less structure than ionic compounds. That is, they tend to be liquids or gases at normal temperatures. In most cases, covalent compounds with higher molecular weights have higher boiling points. The degree of polarity of a compound can also influence its boiling point, since a greater attraction between molecules impedes thermally induced random molecular motion. This is why the H2S is a gas, even though it is heavier than H2O, a liquid. Mixed-bonding is fairly common in nature. The term refers to a molecule whose components have both ionic bonds and covalent bonds. CaCO3 is an example; CO3 is a covalent molecule ionically bonded to a calcium 2 plus cation. Table 2.3 gives some examples. 2.3.4 Other Atomic Influences Van der Waals forces and hydrogen bonds play an important role in both clay chemistry and polymer chemistry.


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Weak attractive forces may exist between uncharged atoms or molecules even in the absence of any tendency to form covalent bonds. Collectively these are known as Van der Waals forces. Van der Waals forces are of very short range compared to the range of electrostatic forces between ions. Van der Waals forces act as attractive forces between the unit layers in clay suspensions. One example is the forces, which act between molecules with permanent dipoles - polar molecules. Another example is an attractive force called the Dispersion Force or London Force. This force can act on atoms and molecules with no permanent dipoles or charge distribution. It results when two atoms or molecules come close enough to deform the electronic charge distribution of the given atom or molecule. This induces dipole moments in them. A hydrogen bond is an attractive force or bridge occurring in polar compounds such as water. Here, a hydrogen atom of one molecule is attracted to two unshared electrons of another. The hydrogen atom is the positive end of one polar molecule. It forms a linkage with the electro negative end of another such molecule. In the formula below, the hydrogen atom in the center is the “bridge”. Fig. 18

Hydrogen bonds are much weaker than covalent bonds, but they have a pronounced effect on the properties in which they occur2. This pertains to melting points, boiling points and crystal structure. Hydrogen bonding contributes to the viscosification characteristics of Xanthan gum and the encapsulating characteristics of PHPA polymers.


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A metallic bond is found in metals: valence electrons of each atom are not bonded to atoms but belongs to the overall metal; they function as glue that holds together all the atoms of the solid. 2.4 SOLUTIONS 2.4.1 Types of Solutions A solution may be defined as a uniformly dispersed mixture at the molecular or ionic level. (Sometimes a solution is incorrectly referred to as a homogeneous mixture, but in its strict sense the term homogeneous refers to the chemical constitution of a compound or element.) In a true solution one or more substances called solutes are uniformly dispersed in one or more other substances called the solvent. Solutes may be present in water, usually in the form of molecules (sugars) or ions (salts). Solutes may also be gaseous or liquid. When two liquids exhibit mutual solvency they are said to be miscible. Solvents can either be polar or non-polar. The most common solvent is water. It is highly, polar, whereas hydrocarbon solvents are non-polar. The proportion of substances in a solution depends on their limits of solubility. The solubility of one substance in another is the maximum amount that can be dissolved at a given temperature and pressure. A solution containing such a maximum amount of solute is said to be saturated. A state of super-saturation can be created i.e. by heating water more sugar can be dissolved in the water. Such solutions are unstable in practical use because if the temperature changes drastically the solute may spontaneously precipitate or settle out as small, particulate solid compounds. Supersaturated salt solutions are used as completion fluids – with the salt particles acting as pore plugging agents. Saturation is discussed again in the subsection, Water Solubility. A solute, which imparts ionic conductivity when dissolved in water, is called an electrolyte. A familiar example is sodium chloride. In the solid state it exists as an ionic compound. But when dissolved in water, individual Cl- and Na+ ions separate and the water becomes a better electric conductor see Fig 5. Non-electrolytic substances usually dissolve as chargeless molecules. The resultant solution does not efficiently conduct a current. 2.4.2 The Hydration of Ions The term hydration refers to the solvation of ions in water. The strong affinity of water molecules for dissociated ions causes them to acquire a film of highly bound water molecules as depicted in Fig 5. The density of the charge on the ion affects the strength of the bond. Some salts, especially those with multi-valent ions such as calcium are called hydrous; they actually adsorb water from the atmosphere. If the water is removed by heating, the crystals are called anhydrous. The size of the ion also contributes to the strength of attachment of water molecules, increasing with decreasing size. Hydration increases the effective diameter of an ion. The exact number of water molecules associated with any given ion is difficult to specify, especially if the number of free or available H2O molecules are limited. Many uncharged molecules in aqueous solutions can be hydrogen bonded to water molecules, for example NH3.


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2.4.3 Water Solubility The solubility of molecules is a complex subject in which the principles of electrolytic dissociation, diffusion and thermodynamics play controlling roles. For our purposes it is worthwhile to note the following points. An important generalization is that substances with similar intermolecular attractive forces tend to be soluble in one another. “Like dissolves like.” That is, many non-polar substances are soluble in non-polar solvents and many ionic compounds are soluble in polar solvents. Because water is highly polar, it is an excellent solvent. Many ionic compounds are soluble in water. The hydration energies of these compounds (their affinity for water) are greater than their lattice energy (the strength of the bond holding the ion in place, within the crystal). Stated in another way: a substance will dissolve in water if the forces of attraction between water molecules and the ions (or ionic compounds) in the solid are greater than the forces of attraction between oppositely charged ions in the crystal. Table 2.7: Relative Water Solubilities of Some Common Compounds Containing Ionic Bonds Water Solubility Cation Anion Compound Water Solubility Cation Anion Compound Soluble Na+ OH- NaOH Slightly Soluble Mg2+ HCO3

- Mg(HCO3)2 Na+ Cl- NaCl Mg2+ S2- MgS Na+ HCO3

- NaHCO3 Ca2+ OH- Ca(OH)2 Na+ CO3

2- Na2CO3 Ca2+ HCO3- Ca(HCO3)2

Na+ SO42- Na2SO4 Ca2+ SO4

2- CaSO4 Na+ S2- Na2S Ca2+ S2- CaS K+ OH- KOH Ba2+ HCO3

- Ba(HCO3)2 K+ Cl- KCl K+ HCO3

- KHCO3 Insoluble Mg2+ OH- Mg(OH)2 K+ CO3

2- K2CO3 Mg2+ CO32- MgCO3

K+ SO42- K2SO4 Ca2+ CO3

2- CaCO3 K+ S2- K2S Ba2+ CO3

2- BaCO3 Mg2+ Cl- MgCl2 Ba2+ SO4

2- BaSO4 Mg2+ SO4

2- MgSO4 Zn+2 S-2 ZnS Ca2+ Cl- CaCl2 Fe+2 S-2 FeS Ba2+ OH- Ba(OH)2 Ag+ Cl- AgCl Ba2+ Cl- BaCl2 Ba2+ S2- BaS Al3+ SO4

2- Al2(SO4)3 Table 2.7 shows the relative water solubilities of several commonly used ionic compounds. Usually, crystals composed of monovalent ions such as NaCl have the lowest lattice energy and are the most soluble. Crystals that contain multi-valent ions such as BaSO4 (Ba2+, SO4

2-) may not be soluble in water at all. Their lattice energy is too high. Crystals such as CaCO3 (Ca2+, CO3

2-) although not soluble in water, can be dissolved in aqueous solutions having a higher degree of polarity than water such as HCl. Sized CaCO3 is employed as a pore-plugging solid phase in some drill-in or completion fluids. The CaCO3 is later solubilized with an acid wash, leaving open porosity. Some lattice bonding energy may be lost as heat (exothermic) during solvation. This can be seen in practice especially when mixing NaOH or CaCl2.


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Many covalent compounds are also able to solvate in water. They qualify under our definition of solutes because they molecularly disperse in water. A degree of molecular polarity is necessary for solvation to occur. Sugars, starches and alcohols are examples of polar, covalent compounds that are water-soluble. Non-polar covalent compounds, including oils and asphalts are usually insoluble in water. When a solution is in contact with additional pure solute, further solvation depends on the concentration of solute already in solution. A solution is said to be saturated when a state of dynamic equilibrium exists between dissolved solute and any excess solid solute. That is, the number of ions or molecules escaping from the crystal lattice into the solution is the same as those leaving the solution to re-join the crystal lattice. Again, the concentration of solute in a saturated solution is called its solubility (s). Two liquids may be mutually soluble in all proportions, water and ethanol for example. For such solutions the term solubility is meaningless since saturation is unattainable. The solubility of most of the chemicals used in drilling fluids increases with temperature. This is an important consideration when drilling evaporates such as the prairie evaporite with saturated drilling fluids. In order to ensure formation dissolution does not occur, supersaturated solutions are often used. Calculations and pilot testing should be made at bottom hole, static temperatures. Fig 19 demonstrates the effect that temperature can have on two different compounds. Solubility of chemicals is related to the following equilibrium reaction:

A + B ⇒ AB↓ Ks = [A]⋅[B] Where Ks is a constant depending on temperature and is called solubility product. Solubility is suppressed if other compounds with common ions are present in solution. Example 1: Calculate the solubility of AgCl, having Ks = 10-10.

S = [Ag+] = [Cl-] = sK = 10-5M

Three cases are possible: • If [A]⋅[B] < Ks: no precipitation of salt occurs • If [A]⋅[B] = Ks: saturated solution • If [A]⋅[B] > Ks: precipitation of salt occurs (AB↓)


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Fig. 19: KNO3 black line, NaCl dotted line.

0

50

100

150

200

250

0 10 20 30 40 50 60 70 80 90 100

Temperature (oC)

So

lub

ility

g/1

00g

Wat

er

A further consideration is that the presence of other ionic or molecular species in a given solution will suppress the solubility of the chemicals or salts to be added. Generally when two salts are present in solution the most soluble one suppresses the solubility of the other one. Water-based drilling fluids are good solvents for most gases. These include, CH4 (methane), O2 (oxygen) and the so-called acid gases, H2S (hydrogen sulfide) and CO2 (carbon dioxide). The solubility of these gasses decreases as the temperature rises and increases with pressure in water-based solutions. At about 2438 m (8000 ft) the solubility of methane in water is 100 times greater than at surface and at 6095 m (20000 ft) it is about 300 times greater3. Furthermore, water at temperatures above 100°C can actually lose its polar nature, enabling it to dissolve a larger portion of non-polar compounds such as hydrocarbons. Both solid and gaseous solutes may exist in solution in concentrations beyond their saturation levels; a supersaturated solution has no solids or bubbles. It cannot contain solid impurities and it cannot be agitated. For our purposes, the term supersaturation refers to a solution containing a high enough concentration of solute (usually a salt) that crystals appear in the fluid. 2.4.4 Oil Solubility Most base oils are a blend of non-polar hydrocarbons. They act as good solvents for many non-polar compounds. These include asphalt tar, wax and resins (extrusions from tree bark). For this reason resins and waxes are used as bridging solids in oil reservoirs. The solubility of some substances is increased in oils of higher aromatic content. Elastomers (rubber components) are an example of this. Ionic salts are insoluble in oil-based systems. Gases have an insignificant


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amount of intermolecular bonding strength when compared to ionic crystals. For this reason most gases are miscible in both water-based and oil-based fluids. Generally, the solubility of gas in oil is influenced (increased) by pressure, to a much greater degree than in water. This makes the detection of a gas hydrocarbon influx more difficult in oil-based fluids. The saturation point of a gas in a liquid is sometimes called the bubble point. An equal amount of gas dissolved (as opposed as entrained) in an oil-based fluid will not reach the bubble point until a much shallower depth than gas dissolved in a water-based fluid. In fact, the solubility of gas in oil is unlimited for any specific temperature condition, whenever the pressure is higher than the critical pressure for that gas. 2.4.5 Dispersion and Dispersability Dispersion is a two phase system where one phase consists of finely divided particles distributed through a bulk phase. The term dispersability refers to the inherent ability of the internal phase particles to accomplish this. Under controlled conditions the uniformity of a dispersion can be increased by wetting or dispersing agents. Table 2.8 shows the possible combinations of gas, liquid and solids (our preceding definition of the states of matter) that can form dispersions.

Table 2.8 The Possible Dispersion Systems Internal Phase External Phase Example Gas Liquid Foam Solid Gas Aerosol (smoke) Gas Solid Styrofoam Liquid Gas Fog Liquid Liquid Emulsions Solid Liquid Paint Solid Solid Concrete

Various derivatives of the word disperse, are used through this manual. For our purposes, the term disperse can be thought of as the sub-division of particle aggregates. In water-based systems, both ionic and covalent compounds may be easily dispersed even if they do not dissolve. Dispersion is dependant on residual surface charges, which interact with the polar water molecules. For example, the negative charge on the surface of most clays attracts the positive end of water, molecules, forming a tightly bonded layer of water around the clay particle. Other available water molecules may form successive layers contributing to particle separation and an increased degree of dispersion. This phenomenon is sometimes called water wetting. Brownian motion, induced movement of the particles contributes to greater uniformity. (Brownian motion is caused by the impact of moving liquid molecules on the particles; it increases as the temperature increases.) Most polar or charged substances disperse readily in water. Barite, sometimes called inert, is a good example. Non-polar substances such as oil do not. The molecules in oil have a greater affinity for each other and tend to coalesce. That is, they are immiscible in water. Non-polar substances that do not actually dissolve in base oils are usually readily dispersible in them. Gilsonite is an example. Certain surfactants can cause polar substances such as clays to behave as through they were non-polar, enabling them to disperse in oil.


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2.4.6 Colloidal Systems and Suspensions A colloid is a very fine particle. One definition (Webster) lists three criteria necessary to qualify as a colloid. A substance must be in such a state of division as to: 1. Prevent passage through a semi-permeable membrane 2. Consist of particles too small for resolution with an ordinary light microscope. 3. In solution or suspension fail to settle out and diffracts a beam of light. H. van Olphen4 provides a good definition of the term colloidal solution and the distinction between it and a suspension, as the terms relate to clay particles. Early researchers noted that clay appears to dissolve in water just like common salt. However, observations of clay “solutions” made with ultra-microscopes showed particles against the dark field of observation. (The image in an ultra-microscope results from indirect light being reflected off the particle and into the objective lens). These particles were moving due to a translational Brownian motion, indicating they were indeed particles. The image intensity varied, indicating the particles were rotating and therefore not spherical. Fig. 20: Transmission EM of clay colloid

Hence, the “solution” was actually a dispersion of very fine particles. Such dispersion is now called a colloidal solution or sol, if the dimensions of the particles are such that they do not settle within a reasonable time. If the particles settle more rapidly, the dispersion is called a suspension. The word “settle” contradicts point 3 of Webster’s definition. The distinction between a colloidal solution and a suspension is “entirely arbitrary; there is no difference in principle.”4

The borderline between colloidal solution and suspension is usually chosen at an equivalent spherical radius or Stokes radius of 1 µm. Today, a colloidal dispersion is said to contain particles ranging in size from 1 mm (10-3 m) down to 1 nm (10-9m). A colloidal system or dispersion may exist in all of same forms or possibilities as the dispersion system as outlined in Table 2.8. The


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dispersed particles exist in an internal or discontinuous phase, within an external or continuous phase. In colloidal systems they are called “kinetic units”, and may be gas, liquid, solid or macromolecules such as polymers. To refer to the dispersed particles as “colloids” might be confusing; a water-in-oil emulsion can be a colloidal system, but water is seldom referred to as a colloid. The particles in hydrous (water is the external phase) colloidal systems fall into two main classifications:

1. HYDROPHOBIC COLLOIDS: This term is somewhat misleading since the particles do not actually repel the solvent (for our purposes, water) as the term suggests. An example is a dispersion of clay particles. The bar represents 1 µm.

2. HYDROPHILLIC COLLOIDS: These particles display a remarkable greediness for water,

for example polymeric gums. It is recognized that most dissolved natural and synthetic gums can be considered true solutions, therefore hydrophilic colloids are sometimes called polyelectrolyte solutions. (An exception is most cross-linked polymers, which usually do not completely dissolve).5

Emulsions and foams are other examples of colloidal systems, which make up drilling fluids. In a water-in-oil emulsion, brine droplets less than a µm in diameter constitute the internal phase.

Table 2.9 Size Versus Surface Area In Cubes Cube dimension # Of Cubes Surface Area 1.0 cm 1 6 cm2 1.0 mm 1000 60 cm2 0.01 mm 1x109 6000 cm2 1.0 µm 1x1012 6 m2 0.01 µm 1x1018 60 m2

Table 2.9 shows how the surface area of 1-cm cube increases as the cube is divided into increasingly smaller cubes. In the colloidal size range, the surface area of the particles is so much larger than their relative volume, that unusual phenomena occur in solutions where they are present. When the viscosity of the external phase is high enough, gravity may be unable to cause settling. The large surface area also immobilizes much more water. Crystalline water is more viscous. The effect also promotes an increased degree of particulate associations and interactions. This can impart increased viscosity and gelation characteristics to even a hydrophobic colloidal system – even when the particles, such as barite particles are relatively inert.


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2.4.7 Equilibrium and Precipitation Physical equilibrium is the term used when two or more phases of a system change at the same rate so that the net change in the system is zero. An example is the liquid-to-vapor, vapor-to-liquid interchange in an enclosed system. This system reaches equilibrium when the number of molecules leaving the liquid is equal to the number entering it. Chemical equilibrium is a condition in which a reaction and its opposite or reverse reaction occur at the same rate, resulting in a constant concentration of reactants. The double arrow is the customary symbol for an equilibrium reaction. For example, ammonia in water creates ammonium hydroxide. The reaction is at equilibrium when ammonia molecules form and ammonium hydroxide decompose at equal rates.

NH3 + H2O NH4+OH-

Or for water:

H2O H+ + OH-

What this means is that in an H2O solution, each water molecule does not have to keep all of its component ions indefinitely. Molecules may exchange ions as often as they wish. A number that relates the concentrations of starting materials and products of a reversible chemical reaction to one another is called the equilibrium constant, K. At a given temperature, K is constant regardless of the quantities of the substances. When K is known, it is often possible to predict concentrations of products, when those of the starting materials are known. Precipitation occurs when a solid material “falls” out of solution. If a hot salt solution (in water) is fully saturated with salt, as it cools salt will precipitate out of solution, the scientific term for this is crystallization. It can also describe the process whereby two types of dissolved ions or molecules combine to form an insoluble (solid) compound called a precipitate. Sometimes the reaction is indicated by a downward vertical arrow although precipitates do not necessarily drop out of a viscofied suspension.

CaSO4 + Na2CO3 CaCO3 + Na2SO4 The precipitation of various substances is used in both the chemical analysis and in the removal of contaminating ions from drilling fluids. A common example is the treatment of anhydrite (CaSO4) contamination. Precipitation may cause desirable components of drilling fluids to drop out of suspension. An example occurs with Xanthan Polymer in the presence of both high calcium and pH. Drilling fluids contain so many ionic species and are subject to so many influences (temperature, pressure, contaminants) that it can be extremely difficult to predict reactions and events, including saturation point, equilibrium and precipitation.


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2.4.8 Drilling Fluids: Multi-phase Homogenates Table 1.1 provided a general classification of drilling fluids based on their fluid phase. Actually most drilling fluids are multi-phase systems or homogeneous or uniformly blended mixtures. Probably the most complex example is an oil-based fluid. Describing the constituents and phases of an oil-based fluid uses much of the terminology and concepts explained in the previous three sections. Up to four physical states exist: water, oil, solids and gas. The fluid qualifies as a colloidal solution, specifically an emulsion according to our preceding definition. The oil is the external phase and the water, solid and any entrained gas are the internal phases. Both oil and water are solvents, the water containing dissolved salts up to saturation and the oil containing polymers, gasses and other solutes. After viscosification, the introduction of larger sized commercial solids like barite and also native solids, qualifies the fluid as a proper suspension also. All of the constituents of the fluid work together to provide its various properties. These in turn contribute to the functions of the fluid as outlined in Chapter One. When analyzing a sample, the drilling fluid engineer attempts to discern the concentrations of all the constituents. This is done through specific tests, or by extrapolating from calculations. After proper analysis, modifications may then be made to the individual concentrations of constituents, which will change the properties and enhance the ability of the fluid to perform its functions. 2.5 CHEMICAL CALCULATIONS 2.5.1 Molarity and Normality Stoichiometry is the aspect of chemistry that deals with the quantitative relationships among reactants and products. The mole concept is used for solving problems in stoichiometry. Balanced equations are very important because they provide the mole ratios. These ratios can be used to convert quantities of reactants or products to moles, grams, or number of molecules.

Physicists, and some chemists, measure the masses of individual atoms in kg, g, or atomic mass units. For most chemists, however, the mass of a single atom is inconveniently small and the molar mass (mole) of a substance is used. The molar mass of an atom is the mass of a very large number of identical atoms, one mole of atoms. One mole of atoms is by definition that number of atoms which exist in exactly twelve grams of carbon of isotopic mass twelve (12C). This number is called the Avogadro number, NA, and the best current determination of its value is 6.02 x 1023. This mole is just a number. So 1 mole = 6.02 x 1023 particles (either atoms or molecules).

Mole (mol) = MW

gweight )(

MW = molecular (or atomic) weight

Molar Atomic Masses of Elements

The molar mass of an atom is simply the mass of one mole of identical atoms. However, most of the chemical elements are found on earth not as one isotope but as a mixture of isotopes, so the


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atoms of one element do not all have the same mass. Chemists therefore distinguish the molar atomic mass of an isotope, which is the mass of one mole of the identical atoms which form that isotope, from the molar atomic mass of an element, which is the mass of one mole of the atoms of the various isotopes of that element having the natural abundances as they are found on earth. For many elements the variation found in the natural abundances limits the accuracy with which the molar atomic mass of that element can be known. Table 2.10: Relative Atomic Masses of the Chemical Elements Element Symbol Atomic

weight Atomic number

Oxidation states (valency)

Density

ACTINIUM Ac 227,0278 89 3 10,07 ALUMINUM Al 26,98154 13 3 2,7 AMERICIUM Am (243) 95 6;5;4;3 13,6 ANTIMONY Sb 121,75 51 5;3;-3 6,68 ARGON Ar 39,948 18 1,784* ARSENIC As 74,9216 33 5;3;-3 5,72 ASTATINE At (210) 85 7;5;3;1;-1 BARIUM Ba 137,33 56 2 3,5 BERKELIUM Bk (247) 97 4;3 BERYLLIUM Be 9,01218 4 2 0,53 BISMUTH Bi 208,9804 83 5;3 9,8 BORON B 10,81 5 3 2,34 BROMINE Br 79,904 35 5;1;-1 3,12 CADMIUM Cd 112,41 48 2 8,65 CALCIUM Ca 40,08 20 2 1,55 CALIFORNIUM Cf (251) 98 3 CARBON C 12,011 6 4;2;-4 2,62 CERIUM Ce 140,12 58 3;4 6,78 CESIUM Cs 132,9054 55 1 1,87 CHLORINE Cl 34,453 17 7;5;3;1;-1;-3 3,17* CHROMIUM Cr 51,996 24 2;3;6 5,8 COBALT Co 58,9332 27 2;3 8,9 COPPER Cu 63,546 29 1;2 8,96 CURIUM Cm (247) 96 3 13,6 DYSPROSIUM Dy 162,5 66 3 8,54 EINSTEINIUM Es (252) 99 ERBIUM Er 167,26 68 3 9,05 EUROPIUM Eu 151,96 63 3;2 5,26 FERMIUM Fm (257) 100 FLUORINE F 18,9984 9 -1 1,696* FRANCIUM Fr (223) 87 1 GADOLINIUM Gd 157,25 64 3;2 7,89 GALLIUM Ga 69,72 31 3 5,91 GERMANIUM Ge 72,59 32 4 5,32 GOLD Au 196,9665 79 3;1 19,3 HAFNIUM Hf 178,49 72 4 13,1 HELIUM He 4,0026 2 0,1787* HOLMIUM Ho 164,9304 67 3 8,8 HYDROGEN H 1,0079 1 1 0,0899* INDIUM In 114,82 49 3 7,31


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Element Symbol Atomic weight

Atomic number


Density

IODINE I 126,9045 53 7;5;1;-1 4,92 IRIDIUM Ir 192,22 77 6;4;3;2 22,5 IRON Fe 55,847 26 2;3 7,86 KRYPTON Kr 83,8 36 3,74* LANTHANUM La 138,9055 57 3 6,7 LAWRENCIUM Lr (260) 103 LEAD Pb 207,2 82 4;2 11,4 LITHIUM Li 6,941 3 1 0,97 LUTETIUM Lu 174,967 71 3 9,84 MAGNESIUM Mg 24,305 12 2 1,74 MANGANESE Mn 54,938 25 2;3;4;6;7 7,43 MENDELEVIUM Md (258) 101 MERCURY Hg 200,59 80 2;1 13,53 MOLYBDENUM Mo 95,94 42 2;3;4;5;6 10,2 NEODYMIUM Nd 144,24 60 3 7 NEON Ne 20,179 10 0,901* NEPTUNIUM Np 237,0482 93 6;5;4;3 20,4 NICKEL Ni 58,7 28 2;3 8,96 NIOBIUM Nb 92,9064 41 3;5 8,55 NITROGEN N 14,0067 7 5;4;3;2;-3 1,251* NOBELIUM No (259) 102 OSMIUM Os 190,2 76 8;6;4;3;2 22,4 OXYGEN O 15,9994 8 -1;-2 1,429* PALLADIUM Pd 106,4 46 4;2 12 PHOSPHORUS P 30,97376 15 5;4;3;-3 1,82 PLATINUM Pt 195,09 78 4;2 21,4 PLUTONIUM Pu (244) 94 6;5;4;3 19,8 POLONIUM Po (209) 84 4;2 9,4 POTASSIUM K 39,0983 19 1 0,86 PRASEODYMIUM Pr 140,9077 59 3;4 6,77 PROMETHIUM Pm (145) 61 3 6,475 PROTACTINIUM Pa 231,0359 91 5;4 15,4 RADIUM Ra 226,0254 88 2 5 RADON Rn (222) 86 9,91* RHENIUM Re 186,207 75 7;6;4;2;-1 21 RHODIUM Rh 102,9055 45 4;3;2 12,4 RUBIDIUM Rb 85,4678 37 1 1,53 RUTHENIUM Ru 101,07 44 8;6;4;3,2 12,2 SAMARIUM Sm 150,4 62 3;2 7,54 SCANDIUM Sc 44,9559 21 3 3 SELENIUM Se 78,96 34 6;4;-2 4,8 SILICON Si 28,0855 14 4 2,33 SILVER Ag 107,868 47 1 10,5 SODIUM Na 22,98977 11 1 0,97 STRONTIUM Sr 87,62 38 2 2,6 SULFUR S 32,06 16 6;4;2;-2;-4 2,07 TANTALUM Ta 180,9479 73 5 16,6 TECHNETIUM Tc (98) 43 7 11,5 TELLURIUM Te 127,6 52 6;4;-2 6,24


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Element Symbol Atomic weight

Atomic number


Density

TERBIUM Tb 158,9254 65 4;3 8,27 THALLIUM Tl 204,37 81 3;1 11,85 THORIUM Th 232,0381 90 4 11,7 THULIUM Tm 168,9342 69 3;2 9,33 TIN Sn 118,69 50 2;4 7,3 TITANIUM Ti 47,9 22 3;4 4,5 TUNGSTEN W 183,85 74 6;5;4;3;2 19,3 UNNILHEXIUM Unh (263) 106 UNNILPENTIUM Unp (262) 105 UNNILQUADIUM Unq (261) 104 URANIUM U 238,029 92 6;5;4;3 18,9 VANADIUM V 50,9415 23 2;3;4;5 5,8 XENON Xe 131,3 54 5,89* YTTERBIUM Yb 173,04 70 3;2 6,98 YTTRIUM Y 88,9059 39 3 4,5 ZINC Zn 65,38 30 2 7,14 ZIRCONIUM Zr 91,22 40 4 6,49 Chemists deal with elements as they are naturally found. In actual fact it is very difficult to separate isotopes. Chemists like to deal with the atomic mass or atomic weight of 1 mole of a substance. The weighted molar atomic mass of an element as it naturally occurs will be referred to simply as the atomic mass of the element from now on. Example 1: What is the atomic mass of Pb? Look on the periodic table and find Pb. You'll find the mass number listed as 207.2.

1. One atom of Pb weights 207.2 amu. 2. One mole of Pb atoms weights 207.2 grams. That is 1 mole or 207.2 grams of Pb

contains 602,000,000,000,000,000,000,000 atoms of Pb. Example 2: The sum of individual atoms can be used to find the mass of a molecule. The mass of hydrogen peroxide, H2O2 would be calculated like this:

1. H2O2 has 2 hydrogen atoms and 2 oxygen atoms in it. 2. Therefore the mass is 2 x H + 2 x O = 2 x 1.01 amu + 2 x 16.00 amu = 2.02 + 32.00 =

34.02 amu. So one molecule of hydrogen peroxide weighs in at 34.02 amu. A mole of hydrogen peroxide would weigh 34.02 grams.

The periodic table provides you with individual atomic masses. If you know the number and type of elements in a molecule you can add up the individual masses to find the molecular mass or molecular weight. Example 3: Find the molecular mass of calcium phosphate, Ca3(PO4)2 The molecule has 3 calcium atoms, 2 phosphate atoms and 8 O atoms in it. Stop and verify this for yourself. The Ca has a subscript 3 with it. The P has an assumed 1 and the O has a 4.


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However the PO4 group has a set of brackets around it with a subscript 2. The 2 means multiply everything inside the brackets by 2. So we end up with the 2 P and 8 O atoms. Calculation: 3 x Ca = 3 x 40.08 amu = 120.24 amu

2 x P = 2 x 30.97 amu = 61.94 amu 8 x O = 8 x 16.00 amu = 128.00 amu

The total of the individual types of atoms is 120.24 amu + 61.94 amu + 128.00 amu = 310.18 amu. One molecule of calcium phosphate weighs 310.18 amu and a mole of it would weigh 310.18 grams. Example 4: Find the mass in grams of 1.0 mole of NaOH and then find how many moles are in 500g of Caustic soda. Add up the atomic weights of the atoms using the periodic table: Na O H 22.99 + 15.99 + 1.008 = 39.988 1 mole of NaOH weighs 39.988g The number of moles in 500 g of NaOH is calculated by: 500 g / 39.988 = 12.505 moles These examples show the advantage of using atomic mass units when individual atoms and molecules are considered. The term molarity is indicated by a capital M. A molar solution refers to a concentration in which one mole (molecular weight in grams) of a substance is dissolved in enough solvent to make one liter of final solution. Molar quantities are proportional to the molecular weights of substances. Because molar weights of different substances contain the same number of molecules, equal volumes of one molar solution will contain the same number of molecules of the solute. For example, if 1 mole of potassium hydroxide is needed for a given reaction, one can use 1 liter of a one molar (1M) solution or 2 liters of a 0.5 M solution. Molarity is a weight/volume expression. Because one mole of HCl weighs 39.99 g, 1M HCl = 39.99 g/l.

Molarity (M) = V

mole

mole = moles of solute V = volume of solution (litres) The term molality (m) is indicated by a lower case m. A molal solution refers to a concentration in which the amount of solute is stated in moles and the amount of solvent (not final solution) is stated in kg. One mole if NaCl added to 1 kg of solvent is a 1 molal concentration.

Molality (m) = W

mole

mole = moles of solute


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W = weight of sovent (kg) The term normality (N) is often used to express concentrations in solutions, especially in the reagents used in our chemical analysis. An understanding of the term equivalent weight is necessary to explain normality. In its simplest form, the term equivalent weight (EW) means the atomic or molecular weight of an ion, atom or molecule divided by its (charge) valency. The atomic weight of Mg2+ is 24.30 and its valency is 2, making its equivalent weight 12.15.

Normality (N) = V

equiv equiv (eq) =

EWgweight )(

EW = n

MW

equiv = equivalents of solute V = volume of solution (litres) Weight = weight of solute EW = equivalent weight MW = molecular (or atomic) weight n = number of H+, OH-, or e- involved in the reaction considered

There is a very simple relationship between normality and molarity:

N = n × M

Normality then, refers to a solution having 1 gram equivalent per one liter of final solution. A 1 normal solution contains one equivalent weight of the solute in grams dissolved in one liter of final solution. For substances with a valency of one, a 1N solution is identical to a 1M solution. For substances with a valency of two, then a 1M solution is twice the strength of a 1N solution.

• For an acid or basic reaction, n is the number of H+ or OH- provided by a formula unit of acid or base.

Example 1: A 3M H2SO4 solution is the same as a 6N H2SO4 solution.

A 0.01M HCl solution is the same as 0.01N HCl solution.

Example 2: A 1M Ca(OH)2 solution is the same as a 2N Ca(OH)2 solution.

A 5N KOH solution is the same as 5N KOH solution.

• For a redox reaction, n is the number of e- involved.

Example 3: MnO4- + 5e + 8H+ ⇒ Mn+2 + 4 H2O

EW (KMnO4) = 5

MW = 158/5 = 31.6

A 1M KMnO4 solution is the same as a 5N KMnO4 solution.


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Example 4: MnO4- + 3e + 2H2O ⇒ MnO2 + 4OH-

EW (KMnO4) = 3

MW = 158/3 = 52.7

A 1M KMnO4 solution is the same as a 3N KMnO4 solution.

• For a precipitimetric and chelometric reaction, n depends on the stoichiometry of reaction.

Example 5: Ag+ + Cl- ⇒ AgCl↓

EW (AgNO3) = MW (AgNO3) = 169.9

A 1M AgNO3 solution is the same as a 1N AgNO3 solution.

Example 6: (EDTA)-2 + Ca+2 ⇒ Ca(EDTA)

EW (Na2(EDTA)) = MW (Na2(EDTA)) = 370.2

A 1M Na2(EDTA) solution is the same as a 1N Na2(EDTA) solution.

Note: sometimes molar and normal concentrations are expressed as fraction of 1M or 1N solutions: A N/50 H2SO4 solution is the same as a 1/50 = 0.02N H2SO4 solution. A M/100 Na2(EDTA) solution is the same as a 1/100 = 0.01M Na2(EDTA) solution. 2.5.2 Concentrations in Solutions and Suspensions All of the constituents of drilling fluids are reported as concentrations. This includes soluble salts and polymers as well as insoluble materials such as drilled solids, barite and bentonite. Knowing how certain concentrations are influencing fluid properties enables a drilling fluid engineer to effectively modify his system to suit the hole conditions being encountered. By combining specific concentrations with a known specific gravity, mass balance analysis can become extremely accurate. This helps in analyzing the effectiveness of products and planning future wells. The petroleum industry uses both the S.I. (International System) and Imperial System of units for quantifying concentrations. Usually one of three methods is used to describe a volume or weight relationship between the fluid phase and either the solid phase or a solute. These are: 1. volume/volume (v/v) 2. weight/volume (w/v)


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3. weight/weight (w/w) 1. Volume/Volume The v/v relationship is the easiest to understand. This is used when adding liquid additives to a system. It is reported as, gal/bbl, ml/L, L/m3 or sometimes %v/v, as in 8% spotting fluid. NOTE: to avoid errors in concentrations when mixing liquid additives, consider the final volume of fluid required. Example 1: Exactly 8% spotting fluid is to be mixed to net exactly 12 m3 (12000 L) of final fluid. (Ignore any barite requirement).

1. Starting volume: 12000 – (12000 x 0.08) = 11040 L

2. Volume of spotting fluid: 12000 L – 11040 L = 960 L

Adding 8% of 12 m3 to 12 m3 of water would result in 13 m3 final volume with a concentration of 7.4%! The v/v relationship is also used to describe retort analysis. In oil-based fluids it is actually v/v/v or oil/water/solids. Often v/v concentrations are expressed as percent. It is important to state that it is a “volume %” or “% by volume”, not a “weight %”. The amount of oil retained on cuttings us usually expressed as v/v, L/m3. 2. Weight/Volume The best method of defining concentration of solute in solution or solids in suspension is by the w/v relationship. The familiar units in the Imperial system are pounds per barrel (ppb). In S.I. system mg/L is used to describe minute units and kg/m3 or g/L are used when defining large concentrations. The best aspect of the S.I. system is that all units of weight and volume are multiples of 10. No conversion factors are necessary. For example, when pilot testing, if the best concentration is 2.6 grams of polymer in one liter (almost a quart) of testing fluid (w/v = g/l), then 2.6 kg/m3 of product should be added to the system. The w/v relationship is the easiest method to use in mass-balance calculations since weight can refer to solute and solid.

1000 mg/L = 1.0 g/L = 1.0 kg/m3 3. Weight/Weight The weight of solute per weight of solution, w/w relationship is another common method of reporting concentrations. Minute concentrations expressed in parts per million (ppm) usually (not always) implies ppm as a w/w relationship. Salt solutions and completion brines are often expressed in terms of %w/w for example a 4% solution of KCl. This usually implies a w/w relationship and can be converted to ppm by the following formula:

10000 ppm (w/w) = 1% by weight.


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When a w/w relationship is used to express concentrations, the following points must be stressed:

• when referring to a solute as a percentage concentration it is appropriate to state % by weight.

• ppm does not have to mean w/w • ppm is not the same as mg/l except when the s.g. of a solution is 1.0.

API RP 45 states: “It is the recommendation of the committee that mg/L be adopted as the unit of concentration and the value of s.g. be included as an integral part of the water analysis”. This practice was recommended because too many independent labs recorded erroneous concentrations, because they used mg/L and ppm interchangeably. The recommendation provides adequate data for those who “must” use the w/w relationship. 2.5.3 Converting and Calculating Converting from one method of reporting concentrations to another or one system of units to another usually requires the specific gravity of a substance. Table 2.11 shows the specific gravity of some common drilling fluid additives. Listed below are some expressions which are useful in drilling fluid engineering. Remember, when adding any soluble substance to a solution which is not saturated, the volume increase is not linear. Tables must be used when adding salts. Table 2.11: Specific Gravity Of Common Drilling Fluid Additives

Water Soluble Additives Water Insoluble Additives Product Specific Gravity Product Specific Gravity

NaOH 2.13 BaSO4 4.2-4.3

NaCl 2.16 CaCO3 2.7-2.95

NaCO3 2.51 Galena (PbS) 6.5

Na2CO3 2.2 Diesel Oil 0.84-0.9

CaCl2 2.51 Clay 2.4-2.7 KCl 1.99 Cement 3.1-3.2

Al2(SO4)3 2.71 FeCO3 3.7

CaSO4 2.96 1. Convert from mg/l to ppm and back:

mg/L = ppm x s.g. ppm = ..

/gs

Lmg

Example 1: 300 mg/L of CaCO3 corresponds to 300/2.65 = 113.2 ppm of CaCO3


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2. Convert from density to volume in solution (this does not apply to soluble substances):

d = Vm

V = dm

m = V⋅d

1.0 g/cm3 = 1.0 g/ml = 1.0 kg/L = 1.0 t/m3

d = density (or s.g.), g/cm3 or kg/L V = volume, L or m3 m = mass, kg or t Example 2: Calculate the volume increase by addition of 15 t of barite: V = (15 t) / (4.25 t/m3) = 3.5 m3 3. Convert from %v/v to %w/w to %w/v:

%w = F

M

ddv ⋅%

%v = M

F

ddw ⋅%

%v = volume percentage of material %w = weight percentage of material dM = specific gravity of material (g/cm3) dF = specific gravity of fluid

kg/m3 = %w⋅dF⋅10 %w = 10

/ 3

⋅Fdmkg

kg/m3 = %v⋅dM⋅10 %v = 10

/ 3

⋅Mdmkg

kg/m = concentration of material 4. Concentration and quantity calculations: There are several methods available for calculating concentrations based on chemical reactions. The following example is used to explain one procedure. Example 1: A 150 m3 drilling fluid system contains 830 mg/l Ca

+2. How many kg of soda ash is required to

precipitate all of the calcium? First balance the equation as explained in the preceding text:

Na2CO3 + Ca2+ CaCO3 + 2Na+


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It is true that Na+ does not react with the Ca+2, but since the treatment is made with Na2CO3 and not CO3

-2, the 2Na+ is a factor. This equation is stating that 1 mole of CO3

-2 will react with exactly 1 mole of Ca2+. Thus, using the periodic table the weight ratios of each may be determined: MW (Na2CO3) = 106 MW (Ca) = 40 The ratio is 106/40. This means 106 g (or moles) of Na2CO3 will always combine with 40 g (or moles) of Ca+2. The concentration of calcium, 830 mg/l is the same as 0.83 kg/m3. Thus:

Na2CO3 = 40

10683.0 ⋅ = 2.20 kg/m3

Therefore 2.20 kg/m3 of soda ash is required to treat out all of the calcium. Example 2: Calculate molar concentration of 96% sulfuric acid (H2SO4), having density of 1.835 g/cm3. (MW = 98)

M = MW

d 10% ⋅⋅ N =

EWd 10% ⋅⋅

% = %w/w concentration d = specific gravity of solution (g/cm3) MW = molecular weight of substance EW = equivalent weight of substance Concentration of solution is therefore approx 18M or 36N. 5. Titrations and dilutions: When a diluting a solution, the number of moles of substance remains the same: only the volume of solvent changes. For that reason, the following formula can be used for diluting solutions:

V1⋅N1 = V2⋅N2 V = volumes of solutions (ml or L) N = normal concentrations (not molar!) That formula is also used when titrating substances: at the endpoint of titration the number of equivalents of titrating solution is equal to that of titrated substance. Example 1: Prepare 500 ml of 0.01N solution, stating from 5N one.

500 ml⋅0.1N = V⋅5N V = 10 ml Take 10 ml of 5N solution and dilue with water to 500 ml.


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Example 2: 5.0 ml of AgNO3 0.1N have been used to titrate 1 ml of filtrate. What is the concentration of chloride ions? 5.0 ml⋅0.1N = 0.5 meq AgNO3 = meq Cl- (= mmol Cl-) mgCl- in 1.0 ml of filtrate = mmol⋅MW = 0.5⋅35.45 = 17.72 mg mg/L Cl- = 17.72⋅1000 = 17720 mg/L 2.6 ACID AND BASES In 1923, J. N. Bronsted in Denmark and T. M. Lowry in England independently, and almost simultaneously, proposed the modern "protonic" or Bronsted-Lowry theory of acid-base behavior. According to the Bronsted-Lowry concept, “an acid is any compound or ion which can give up a proton, while a base is any compound or ion which can accept a proton.”

A molecular species which can either accept or give up a proton is said to be amphiprotic. Thus the water molecule is amphiprotic, since it can give up a proton, H2O ⇒ H+ + OH-, to form the hydroxyl ion OH-. Alternatively, water can accept a proton to form the hydronium ion H3O

+, according to the equation H+ + H2O ⇒ H3O

+. The above two equations can be combined to give the dissociation equation for water: 2H2O ⇒ H3O

+ + OH-.

The Bronsted-Lowry concept is an extension of the Arrhenius concept in that “bases, being sources of hydroxide, can accept protons; on the other hand acids, being sources of protons, can accept hydroxide.” Ammonia and amines will also accept protons to form the corresponding ammonium ions, so the existence of NH4OH is no longer necessary to explain the action of ammonia as a base. The Bronsted-Lowry concept also is useful in protonic solvents other than water, such as liquid ammonia or glacial acetic acid, where the Arrhenius concept is not useful. We will, however, generally confine our discussion to aqueous solutions because they are so much more important.

Lewis Acids and Bases

The basic principles of the Lewis theory of acid-base behavior were also set down in 1923, by the American physical chemist G. N. Lewis. The Lewis definitions of acids and bases are even more inclusive than the Bronsted definitions. The Lewis definitions are that “an acid is an electron-pair acceptor and a base is an electron-pair donor.”

HN

HH

Since a base like ammonia (above) has a lone pair of electrons, it can be considered to "donate" them to a proton in forming the conjugate acid NH4

+. The Lewis definitions are used to explain the effect of compounds such as AlCl3, which acts as an acid in non-aqueous organic solvents, on organic reactions. In protonic solvents, however, they are far less useful than are the Bronsted definitions.


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2.6.1 pH A Simple Definition

pH is a logarithmic measure of hydrogen ion concentration, originally defined by Danish biochemist Søren Peter Lauritz Sørensen in 1909:

pH = - log[H+] where log is a base-10 logarithm and [H+] is the concentration of hydrogen ions in moles per liter of solution (M). According to the Compact Oxford English Dictionary, the "p" stands for the German word for "power", potenz, so pH is an abbreviation for "power of hydrogen". The pH scale was defined because the enormous range of hydrogen ion concentrations found in aqueous solutions make using H+ molarity awkward. For example, in a typical acid-base titration, [H+] may vary from about 0.01M to 0.0000000000001M. It is easier to write "the pH varies from 2 to 13". The hydrogen ion concentration in pure water around room temperature is about 1.0 × 10-7M. A pH of 7 is considered "neutral", because the concentration of hydrogen ions is exactly equal to the concentration of hydroxide (OH-) ions produced by dissociation of the water (Kw).

Kw = [H+]⋅[OH-] = 10-7M x 10-7M = 10-14 M2

Increasing the concentration of hydrogen ions above 1.0 × 10-7 M produces a solution with a pH of less than 7, and the solution is considered "acidic". Decreasing the concentration below 1.0 × 10-7 M produces a solution with a pH above 7, and the solution is considered "alkaline" or "basic". So: • 0 < pH < 7: acidic solution • pH = 7: neutral solution • 7 < pH < 14: alkaline solution pH is often used to compare solution acidities. For example, a solution of pH 1 is said to be 10 times more acidic than a solution of pH 2, because the hydrogen ion concentration at pH 1 is ten times the hydrogen ion concentration at pH 2. This is correct as long as the solutions being compared both use the same solvent. You can't use pH to compare the acidities in different solvents because the neutral pH is different for each solvent. For example, the concentration of hydrogen ions in pure ethanol is about 1.58 × 10-10 M, so ethanol is neutral at pH 9.8. A solution with a pH of 8 would be considered acidic in ethanol, but basic in water! 2.6.2 Ionization Constant The inherent or intrinsic strength of an aqueous acid (or base) is its ability to remove a proton from (or donate a proton to) the solvent water or other ions and molecules in aqueous solutions. For quantitative comparisons between different aqueous acids or bases, this ability is compared with the ability of the solvent water itself. The reaction used is the reaction which corresponds to the ionization equilibrium whose equilibrium constant is called the ionization constant. In other words, “strengths of acids and bases are expressed quantitatively in terms of the values of their ionization constants.”

Aqueous ionization constants are quantitative measures of the tendency of the acid or base to either donate a proton, written as H3O

+ or often simply H+, or accept a proton from water. The greater the value of the equilibrium constant, the greater the percentage of the acid or base that


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will be in ionized form. As a generalization, we can use the value of the ionization constant equal to 0.1 as the point of distinction between a strong acid and a weak acid. Thus a strong acid is one for which the value of the acid ionization constant Ka is large (>> 0.1) and a weak acid is one for which the value of the acid ionization constant Ka is small (<< 0.1). Likewise, a strong base is one for which the value of the base ionization constant Kb is large (>> 0.1) and a weak base is one for which the value of the base ionization constant Kb is small (<< 0.1).

HA D H+ + A- Ka = [ ] [ ][ ]HA

AH −+ ⋅

BOH D OH- + B+ Kb = [ ] [ ][ ]BOH

OHB −+ ⋅

AH = acid (i.e. HCl, H2SO4) A- = conjugate base (i.e. Cl-, SO4

-2) BOH = base (i.e. NaOH, NH4OH) B+ = conjugate acid (Na+, NH4

+)

There are only a few common strong acids: HCl, HNO3, HClO4 and H2SO4. In the case of sulfuric acid, H2SO4, only the ionization of the proton from H2SO4 to give HSO4

- is strong; the ionization of HSO4

- to give SO42- is not strong, but weak. Common strong bases include NaOH and KOH. On

reaction with water, CaO gives the strong base Ca(OH)2 and for that reason CaO is considered a strong base also, as are the oxides of sodium and potassium.

Using the values of the ionization constant as quantitative measures of acid strength is equivalent to the qualitative statement that a strong acid is an acid for which loss of the proton to water is essentially complete, while a weak acid is an acid for which loss of the proton is incomplete. Likewise, a strong base is a base for which acquisition of a proton from water is essentially complete while a weak base is a base for which acquisition of a proton is noticeably incomplete.

2.6.3 Acids and Bases If we look at the two definitions (above) of an acid–base pair they are both telling us different things! The ionization constant tells us exactly how strong the acid is, the pH tells us the concentration of protons [H+] in solution! For Mud Engineers pH is the more important of the two, because by knowing the concentration of [H+] we can figure out the concentration of the alkaline ions in solution and base judgments of mud quality upon these results. In general terms, acids in water solutions have the following properties.

1. Sour taste (not recommended). 2. The ability to make litmus dye turns red. 3. The ability to make other indicators change to characteristic colors. 4. The ability to react with and dissolve certain metals to form salts. 5. The ability to react with abase or alkaline to form salts

Acids are classified as strong or weak according to their ability to donate their proton or concentration of the hydrogen ions in solution. Sulfuric acid (H2SO4) is a strong acid (pH < 1), (higher concentration of protons), while carbonic acid (H2CO3) is a weak acid (pH = 3). Water is


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so weak that is classified as neutral (pH = 7). Strong acids are corrosive and dangerous to skin, eyes and mucous membranes. Common organic acids have different nomenclature but all share a common acid functionality.

• Carboxylic acids (has a COOH group) • Fatty acids (has a COOH group) • Amino acids (has a COOH group) • Dicarboxylic acids (contains 2 COOH groups)

Some common organic acids

CH3 OH

O

H OH

O

CO2H

HH

CO2HHO

H H

CO2H

Formic AceticCitric

Inorganic acids or mineral acids, include: sulfuric (H2SO4), hydrochloric (HCl), hydrofluoric (HF), nitric (HNO3) and phosphoric (H3PO4). The disassociation reaction for organic and mineral acids is the same.

CH3 OH

O

Acetic Acid

H+ +CH3 O-

O

Proton

HCl H+ + Cl-

Hydrochloric acid Proton In general terms, bases in water solutions have the following properties.

1. Bitter taste. 2. The ability to make litmus dye turns blue. 3. The ability to make other indicators turn characteristic colors. 4. The ability to react with acids to form salts.

Bases are classified as strong or weak according to their ability to accept a proton or decrease the concentration of the hydrogen ions in solution. Potassium hydroxide (KOH) is a strong base (pH = 14), while sodium bicarbonate (NaHCO3) is a weak base (pH=8.4). Basic solutions range in pH from 7.1 to 14. Like acids, strong bases are corrosive to skin, eyes and mucous membranes.


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Common bases include:

NaOH KOH Ca(OH)2 NaHCO3 NaCO3

Caustic sodaSodium Hydroxide

Caustic potashPotassium hydroxide

Hydrated limeCalcium hydroxide

BiCarbsodium bicarbonate

Soda AshSodium carbonate

In solution they form ions that react with protons, with a net result of decreasing the proton concentration and raising the pH.

NaOH Na+ + OH- NaHCO3 Na+ + HCO3-

A reaction occurs with an acid

Na+ + OH- + HCl HOH + NaCl Na+ + HCO3

- + HCl HOH + NaCl +CO2 And the final equation can be written as acid + base = a salt plus water

NaOH Na+ + OH- NaHCO3 Na+ + HCO3-

Na+ + OH- + HCl HOH + NaCl Na+ + HCO3- + HCl HOH + NaCl +CO2

NaOH + HCl HOH + NaCl NaHCO3 + HCl HOH + NaCl +CO2

In the case of carbonate and bicarbonate ions we see an additional byproduct, carbon dioxide. As a mud engineer contact with organic bases is limited but common organic bases include amines. The following reaction shows a basic amine reacting with an acid, notice how the reaction is a Lewis type reaction (a base donates its electrons). The equation is base + acid = salt.

CH3N

H

H

Methyl amine

+ HCl

Acid

CH3N

H

HH

+ Cl-

Amine salt The disassociation reaction for organic and mineral bases is different! All nitrogen compounds behave this way, including ammonia.


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Ammonia

+ HCl

Acid

HN

H

HH

+ Cl-

Ammonium salt

NH

H

H

Ammonia is an inorganic base but behaves like an organic base. As you can see when using ammonium salts in large quantities, if an acid gas pocket is drilled we would see ammonia gas at the surface. 2.6.4. Practical pH pH is a value representing the alkalinity or the acidity of an aqueous solution. Mathematically pH is defined as the negative log of the hydrogen ion concentration of a solution:

pH = -log [H+] where [H]+ is the concentration of the hydrogen ion in mol/L. For example a 0.01M HCl solution has pH = -log[0.01] = 2 The pH of pure water is 7.0. When adding caustic (NaOH) to a solution the concentration of H+ ions decreases because the product of OH- and H+ is a constant (Kw). This relationship is illustrated in Table 2.12. When considering the effect of pH in practical terms, it is worth noting, that to raise the pH from 9.0 to 10.0 the concentration of OH- ions must be increased by a factor of 10 times.

Table 2.12 pH and concentration of H+ and OH-

pH [H+] [OH-] 14 1.00⋅10-14 1.00⋅100 13 1.00⋅10-13 1.00⋅10-1 12 1.00⋅10-12 1.00⋅10-2 11 1.00⋅10-11 1.00⋅10-3

10 1.00⋅10-10 1.00⋅10-4 Increasing alkalinity 9 1.00⋅10-9 1.00⋅10-5 8 1.00⋅10-8 1.00⋅10-6 7 1.00⋅10-7 1.00⋅10-7 Neutral 6 1.00⋅10-6 1.00⋅10-8 5 1.00⋅10-5 1.00⋅10-9 4 1.00⋅10-4 1.00⋅10-10 Increasing acidity 3 1.00⋅10-3 1.00⋅10-11 2 1.00⋅10-2 1.00⋅10-12 1 1.00⋅10-1 1.00⋅10-13 0 1.00⋅100 1.00⋅10-14


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A simple way to calculate pH of strong or weak acids and bases (with only one H+ or OH-) having concentration C (C > 10-4M) is the following:

Strong acids: pH = -log C Example 1: [HNO3] = 0.001M = C pH = -log 0.001 = 3.0

Strong bases: pH = 14 + log C Example 2: [KOH] = 0.5M = C pH = 14 + log 0.5 = 14 – 0.3 = 13.7

Weak acids: [H+] ≈ CKa ⋅ pH = -log[H+]

Example 3: [CH3COOH] = 0.5M = C Ka = 1.8⋅10-5 [H+] ≈ CKa ⋅ = 0.003 pH ≈ 2.5

Weak bases: [OH-] ≈ CKb ⋅ pH = 14 + log[OH-]

Example 4: [NH4OH] = 0.5M = C Kb = 1.8⋅10-5 [OH-] ≈ CKb ⋅ = 0.003 pH ≈ 14 – 2.5 = 12.5 The solubility of various compounds is affected by pH as well as temperature (see Figure 2.5). This is because there is a relationship (equilibrium constant) between OH- and other ions besides H+. 2.6.5 Alkaline Drilling Muds As a mud engineer understanding the chemistry behind the mud system is important, it allows you to correct problems as they are developing in the hole as a result of what is being drilled through. A problem that occurs with great frequency is the sudden change in alkalinity of the fluid. Drilling fluids normally have a pH in the alkaline or basic range. When considering a fluid with a pH of 10, one can think of a fluid with 10-10 hydrogen ions and 10-4 hydroxyl ions. However, as we know alkalinity can be due to ionic species other than OH-. For example, a 0.1N solution of sodium bicarbonate (NaHCO3) has a pH of 8.4, and a 0.1N solution of sodium carbonate (NaCO3) has a pH of 11.6. Carbonate and bicarbonate species are added intentionally to treat anhydrite or cement contamination. They may also be present unintentionally, derived from CO2 gas, starch degradation, biopolymer degradation, or from the solvation of the formation rock itself. Because water has the ability to dissolve CO2 from the atmosphere, pure water at pH 7 is a difficult state to maintain. Why?


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To understand this we have to understand the chemistry of CO2, H2O, and OH-. As CO2 dissolves in water it forms carbonic acid but in a water solution an acid readily dissociates to give the ionic species, a proton and a bicarbonate ion.

H2O + CO2 H2CO3 Carbonic acid

H2CO3 H+ + HCO3-

H2O + CO2 H+ + HCO3-

With the huge amounts of CO2 in the atmosphere this explains why distilled water has a pH of roughly 5.5. But what happens if we have a mud system pH of 12 made up with caustic? The reaction is as follows.

NaOH + H2CO3NaHCO3 + H2O

NaOH + CO2 NaHCO3

H2O + CO2 H2CO3

Equation 1

So as CO2 dissolves in an alkaline mud system the caustic reacts with the acid to give sodium bicarbonate and water. So what happens if the amount of caustic is huge?

NaOH + NaHCO3 H2O + Na2CO3 Equation 2 The caustic continues to react with the newly formed bicarbonate to generate water and sodium carbonate, a very basic solution! So let’s do this again and put all these equations together. Our mud has a pH of 12 and is made up of caustic and we have just drilled through a sweet acid gas pocket.

2NaOH + CO2 H2O + Na2CO3

NaOH + NaHCO3 H2O + Na2CO3

NaOH + CO2 NaHCO3

Equation 3


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So what is Equation 1 and 3 telling us? Equation 3 says that with an excess of caustic all the CO2 will be converted to carbonates in this case sodium carbonates. If there is not enough caustic in the mud to do this then equation 1 says that CO2 will make sodium bicarbonate. One important aspect to remember is those reactions that are under equilibrium (double arrows) can go in both directions, if they are not influenced by any outside sources i.e. heat, or a large concentration of one reagent. Equilibrium is just that, an equal concentration of reagents and products on both sides of the equation. Therefore if you have a water based system that introduces a huge concentration of CO2, the reaction will generate an increased amount of bicarbonate ions until the system balances itself out. If the system was acidic and you introduced large quantities of bicarbonate, the reaction would generate H2O and CO2, until the system balanced itself. A good way to think of equilibrium is as a type of “buffered” reaction, where reagents and products interchange until there is balance. If an outside source is influencing a reversible reaction in our case a large concentration of one reagent, then these reactions can become essentially irreversible.

H2O + Na2CO3

NaOH + CO2 NaHCO3 Equation 4

Equation 5NaOH + NaHCO3 Therefore, if large concentrations of CO2 are drilled (or if large amounts of caustic have been added), a mud system containing hydroxide ions will use up all the available hydroxide ions (or CO2) to make bicarbonates. If there are still available hydroxide ions then these will react with the bicarbonates to give carbonates. If there is an excess of hydroxide in the mud then all bicarbonates will be convert to carbonates. If there is an excess of CO2 in the system then all the caustic would be used up and only bicarbonates would be present. Another important reaction is drilling anhydrite (CaSO4) which causes a build up of Calcium ions; this can cause problems with clay and mud viscosity. To treat it, sodium carbonate is added

CaSO4 Ca2+ + SO42-

Ca2+ + SO42- + Na2CO3 CaCO3 + Na2SO4

CaSO4 + NaHCO3 CaCO3 + Na2SO4

which creates calcium carbonate that is practically insoluble in water and precipitates out of the mud system. The other reaction of interest is drilling cement. Cement contains calcium silicates and aluminum silicates all of which react with water to form Ca(OH)2. This can cause the pH to rise dramatically and cause serious problems with your mud system. To treat calcium hydroxide contamination you


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can add sodium bicarbonate or SAPP (sodium acid pyrophosphate) both work in the same manner to bind free calcium in solution and remove it from the mud.

Ca(OH)2 Ca2+ + 2OH-

Ca2+ + 2OH- + NaHCO3 CaCO3 + NaOH + H2O

Ca(OH)2 + NaHCO3 CaCO3 + Na2SO4

NaOP

O

ONaO

P

O

ONaNaO

+ Ca(OH)2ONa

P

O

OONa

P

O

OONa

NaOP

O

ONaO

P

O

ONaO

Ca + 2NaOH

2

Sodium acid pyrophosphate reaction with calcium The relationship of carbonic acid vs. bicarbonate vs. carbonate is shown graphically in figure 21 (below).


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Fig. 21:

The Distribution of Carbonate Species as a Function of pH

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

4 5 6 7 8 9 10 11 12

pH

% M

ola

r F

ract

ion

H2CO3 HCO3- CO3--

This graph illustrates an important point, as you increase the pH with caustic the concentration of carbonic acid falls as the bicarbonate climbs to a maximum. As you further increase the pH the bicarbonate disappears and is replaced by carbonate ions. You can use this information to estimate the types and concentrations of bicarbonate, carbonates and hydroxides in your mud, this is called the Pf/Mf Method. Pf/Mf alkalinity If we took a pH reading of a mud sample, looking at the graph above, we could deduce the types of ions in solution. If pH > 11.6 (excess OH-), the only species you could test for would be OH- & CO3

2-. If pH = 11.6 then the only ion present would be the CO3

2- (any OH- present would increase the pH). If pH < 11.6, then there would be no OH- (as it is all used up to convert bicarbonate to carbonate): only HCO3

- & CO32-.

If the pH < 8.3 there would be only HCO3- & H2CO3.

The fifth and final case would be if there were no other ions present except the hydroxide ions you added.


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All these ion concentrations can be estimate in the field by the Pf/Mf Method. (There are other methods that will be covered later in this manual but the theory is the same). The method involves taking a small filtrate sample, finding the pH, adding a pH color indicator (phenolphthalein indicator is pink above pH 8.5) and titrating (just as the pink color disappears) with 0.02N H2SO4. The volume of acid added to make the pink disappear equals the Pf. Another indicator is added to the filtrate sample (bromocresol green, apple green color below pH 4.5) and acid 0.02N H2SO4 is added just to the point where the liquid turns green and the volume recorded. That second volume of acid is equal to the Mf. Table 2.13 Pf/Mf Method Comments If Pf = Mf [OH-] = (2Pf – Mf) x 340 Only [OH-] ions, no contaminates

If Pf = 0 [HCO3-] = Mf x 1220 Only [HCO3

-] ions, will have a low pH (< 8.3)

If 2Pf = Mf [CO32-] = Pf x 1200

Only [CO32-] ions, two protons needed to neutralize

CO32-

If 2Pf > Mf [OH-] = (2Pf – Mf) x 340

[CO32-] = (Mf – Pf) x 1200 Both ions present. pH is > 11.6

If 2Pf < Mf [CO32-] = Pf x 1200

[HCO3-] = (Mf – 2Pf) x 1220 Both ions present. pH is between 11.6 and 8.3

By knowing the concentration and quantity of acid required to neutralize an alkaline solution and by using pH dependant color indicators, the concentration of species may be calculated. An excessive concentration of either HCO3

- or CO32- can become, in essence a contaminant.

2.7 SURFACE CHEMISTRY – COLLOIDS REVISITED

The formal study of colloids began in the latter part of the 19th century with the studies of Thomas Graham. The first colloids studied were gelatins and glues, and so Graham used the Greek work “kolla”, meaning glue, as the root for his newly coined term.

Colloidal particles may be gaseous, liquid, or solid. They may occur in various types of suspensions, e.g. solid/gas (aerosol), solid/solid, liquid/liquid, liquid/solid (emulsion), gas/liquid (foam). It may be useful to observe that a suspension is any system in which small solid or liquid particles are more or less evenly dispersed in a second medium, typically a gas or a liquid.


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Colloid examples: a) Clay, b) Cement, c) Latex or blood, d) Polymers

In the size range of colloidal particles, the surface area of the particle is so much greater than its volume that some unusual behavior is observed, e.g. the particles do not settle out by gravity (i.e. they neither float nor sink). Many macromolecules are at the lower limit of this size range (a nanometer). The upper limit to colloidal particle size is commonly taken to be the size at which the particles become visible in an optical (i.e. light) microscope (about 1 micrometer). Natural colloidal systems include rubber latex, milk, blood, and egg-white.

Aerosols are suspensions of liquid or solid particles in a gas. The particles are often in the colloidal size range, making many aerosols colloidal suspensions. Fog (water/air) and smoke (C/air) are common examples of natural aerosols. Fine sprays such as those used with perfumes, insecticides, inhalants, anti-perspirants, and paints are man-made aerosols.

An emulsion is a stable mixture of two or more immiscible liquids held in suspension by small amounts of substances called emulsifiers. Small carbohydrate polymers like starch (which are


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themselves colloidal in size) often act as emulsifiers by coating the surfaces of the dispersed phase and thus preventing coalescence. Such emulsifying agents are called protective colloids as they protect the dispersed phase from coalescence and subsequent separation. Long-chain alcohols and fatty acids can also act as emulsifiers by "solubilizing" the dispersed phase by virtue of the formers solubility in the dispersing medium (often water).

These emulsifying agents are called detergents. Commercial polymerization reactions are often carried out in emulsion form. Floor and glass waxes, many drugs, photographic coatings, and paints are all examples of emulsion systems.

Foams are dispersions of gases in liquids or solids. If the gas globules are of colloidal size, the foam is colloidal foam. Yeast breads are examples of solid foams. Shaving cream and whipped cream are good examples of liquid foams. Useful foams for automobile seats and mattresses are made from natural and synthetic (e.g. polystyrene, polyurethane) latexes. Metal and concrete foams are also possible.

Any of these surfaces and interfaces can, and commonly do, occur in drilling fluids. 2.7.1 Surfaces Surfaces can be very complex, and the majority of this science is beyond the scope of this chapter. Suffice it to say that there are two major properties; surface area and electronic charge. What do we mean by surface area? As explained above the smaller the particle gets the greater the surface area becomes. Surface area is also a function of the interior of the particle, if the material is porous (like a sponge) then liquid or gases can travel through the interior spaces. Clay is like a sponge; in fact with some clay a handful has as much surface area as a football field. Fully dispersed kaolinite clay can have a surface area of 15 m2/g, and a bentonite close to 800 m2/g. The other property is electronic charges. Think about a copper wire, how does an electric current travel down a wire? At an atomic level there are “holes” where electrons can travel through the copper atoms and areas with electron density and deficiency. When a charge is applied to a wire, the electrons travel through these holes from a low electron density to a high electron density. Most surfaces have both these properties in varying degrees. These properties can influence (catalyze) or be part of a chemical reaction. They can form a semi-permeable membrane and channel water. They can provide pores to “store” atoms and bind atoms. They can also bind together and form colloids and suspensions. With drilling fluids these properties can influence viscosity, emulsified brine droplets, barite particles etc. Knowledge of the nature of a surface allows for a better understanding and control of drilling fluid properties. For example, the surface of steel usually has a net negative charge when in an aqueous environment. When a cationic surfactant is added to the fluid, its molecules bond to the steel, providing a defensive coating from a corrosive environment.


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2.7.2. Surface Tension

Surface tension is the force at the surface of a liquid due to adhesive forces of the liquid molecules for the walls of the container and the attractive forces of the molecules of liquid for each other. When the adhesive forces of the molecules for the walls of the container are greater than the attractive forces between the liquid molecules, then the surface of a liquid confined to a narrow diameter container will curve downward forming a concave surface called a meniscus. Most important examples are water solutions. The water adheres to the surface of the container greater than the water molecules are attracted to each other. We do not see this downward curvature when the surface area is great, but if the liquid is confined to a small diameter tube such as a graduated cylinder, pipette, burette, or volumetric flask then the surface tension is great enough to noticeably distort the surface. In such cases when we are trying to read the liquid surface level such as measuring a liquid in a graduated cylinder, then one should make the reading at eye level and the lowest curvature of the meniscus should be read.

When the adhesive forces against the walls of the container are less than the intermolecular forces, then the surface of a confined liquid will bulge upward slightly forming a convexed surface. Again, such a surface should be read at eye level and the topmost part of the surface should be read. Surface tension helps to explain why the feathers of a duck can help the duck float on water.

Although molecules in a liquid are electrically neutral in nature, there are often small attractive forces between them. These attractive forces (called Van der Waals forces) are caused by the asymmetrical charge distribution inside the molecules. Within a body of a liquid, a molecule will not experience a net force because the forces by the neighboring molecules all cancel out (Figure 22). However for a molecule on the surface of the liquid, there will be a net inward force since there will be no attractive force acting from above the molecule (Figure 22). This inward net force causes the molecules on the surface to contract and to resist being stretched or broken. Thus the surface is under tension and has Surface tension.

Figure 22 Figure 23

mg

F F

Due to the surface tension, small objects will "float" on the surface of a fluid. A needle will float on water! This can be seen in Figure 23. When an object is on the surface of the fluid, the surface under tension will behave like an elastic membrane. There will be a small depression on the surface of the water. The vertical components of the forces by the molecules on the object will balance out the weight of the object. Surface tension also occurs at the interface between a solid and gas, a solid and a liquid and between two immiscible liquids.


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This is why water forms beads and soap forms bubbles. The degree of polarization in a liquid, determines the degree of imbalanced attractive forces in it. This net force is called the fluid’s surface energy. Surface tension is measured in dynes/cm. At 20°C the surface tension of water is 72.7 dynes/cm, decreasing to 67.9 dynes/cm at 50°C. 2.7.3 Emulsion and Foam An emulsion is a stable mixture of two or more immiscible liquids held in suspension by small concentrations of substances called emulsifiers. As a drilling fluid term, the word emulsion applies to small oil drops, the dispersed or discontinuous phase, in water the continuous phase. Invert emulsions employ oil as the continuous phase, while water is the dispersed phase. In an invert emulsion system, the emulsified water drops may at times be sub-micron size. This creates a proportionately large surface area.

-O3SO

An Emulsifier

-O3SO-O3SO

-O3SO

-O3SO

-O3SO-O3SO

-O3SO

-O3SO -O3SO

-O3SO

Oil

OilH2O

Hydrophobic tail, "oil lover"Hydrophilic Head"water lover"

A water in oil emulsion Normally the interfacial tension between oil and water is high, the two phases separate when agitation ceases. This occurs so as to minimize the interfacial area. Emulsifiers lower the interfacial tensions such that one phase may remain dispersed in another without mechanical agitation. Emulsifiers work by two mechanisms. 1. The first involves the reduction of surface tension at the dispersed phase interface. This

occurs because the molecules have a dual solubility property (hydrophilic and hydrophobic head or tails). The second involves the adhesion to and the coating of the dispersed phase, to prevent coalescence.

2. The second mechanism also promotes the oil wetting of and subsequent reduction in reactivity of solid phases including steel and rock. One important fact to remember with emulsifiers is that “like is attracted to like”, so in the case of oil wetting barite, a hydrophilic head will surround the barite while the hydrophobic tail works to hold the barite in the oil phase.


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Foams are similar to emulsions in that they have two phases; one dispersed, usually air and one continuous. In a mist, the water is the dispersed phase. Foams and mists are colloidal systems where the reduction of surface tension by the addition of surfactants is essential6. Foams are used to help remove formation water when air drilling, clean solids from the well bore when completing or working over wells in depleted reservoirs and as an insulating medium in Arctic wells. 2.7.4 Surface Charges Many of the surfaces of the various phases and components of drilling fluids are electrically charged. The origin of these charges can be attributed to several mechanisms. The nature and strength of the charges is dependant on these mechanisms and the nature of the environment (fluid) the components are in. Dislocations are variations or defects from the perfect order or symmetry in a crystal lattice. Dislocations may involve a missing atom or hole, an atom from a different element, a complete extra plane of atoms, or a shift of one or more lattice units relative to the lattice plane of its neighbor. The result may be an impartation of new properties to the crystal. These might affect hardness, conductivity and surface charge. The substitution of ions of different valency within a crystal lattice generates charge deficiencies within the crystal which may be manifested as surface charges. This commonly occurs in the clay minerals used in drilling fluids.

A broken crystal lattice often introduces new surface charges to the system. This effect is readily seen as the pH dependant edge charges on clays. The effect is also manifested with other ionic crystals such as barite. The surface charges on barite crystals cause suspensions to become increasingly thixotropic as the barite particle size is reduced that is, the surface area is increased. A suspension with 100 kg/m3 of barite might have flat gel strengths if the average particle size is 50 µm. If the D50 is reduced to 4 µm the fluid might not be pumpable. The molecular water orientation around a barite particle creates a repulsion regime similar (though smaller) to that of clays. This is why when enough barite is added to water it remains in suspension without


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viscosifiers. Recall that both caustic and SAPP are added to barite plugs to decrease settling time.

The dissociation of functional surface groups is the mechanism for determining the surface charge of oxides. When ions dissociate from polymer molecules, the surface charge may change, changing the behavior of the polymers. An example is the dissociation of Na+ from the COOH- group on CMC. When this occurs the molecule retains a net anionic character, enabling it to elongate. Adsorption means the congregation of and adherence of the atoms, ions or molecules of a gas or liquid to the surface of another substance, called the adsorbent. This definition describes the processes whereby the majority of adjustments to drilling fluid properties are attained. These include ions and water being adsorbed onto clay surfaces, polymers and clays adsorbing onto each other, emulsifiers adsorbing onto brine droplets or surfactants adsorbing onto steel. In solutions the adsorption process is normally accompanied by desorption of the original water. The adsorbed species may also exchange with a previously adsorbed species. The adsorption of a polymer molecule onto a clay surface displaces several water molecules, increasing the free water available to the system, a favorable reaction. However, the adsorption of ions onto clay surfaces best exemplifies the influence of the effect of adsorption on fluid properties. Because the surfaces of clays are electrically charged, a double layer of oriented water molecules surrounds each clay platelet. The closest layer, the bound layer is tied to, and moves with the clay. The outside layer, the diffuse layer has more freedom. The zeta potential is the electric potential in the double layer at the particle/liquid interface. The double layer causes plates to repel. However, the presence of cations reduces the size of the double layer, reducing the zeta potential. This lowers the repulsive forces between particles. When attractive forces predominate, particle associations increase causing an increase in viscosity. The degree to which the zeta potential is reduced depends on the valence of the added cation, especially if low valence ions are replaced by higher valence ions. The ratio of the comparative effect is 1, 10 or 500 for monovalent, divalent and trivalent ions respectively. The ability to manipulate the zeta potential is essential to control the properties of all colloidal clay systems. As drilled cuttings enter a drilling fluid system, their surfaces invariably adsorb components of the fluid. These include water, ions, molecules, especially hydroxyl groups, polymers and surfactants. In order to retain consistent fluid properties, these materials must be replaced continuously.


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2.7.5 Other Surface Phenomena Wettability is the term used to describe the tendency of a fluid to spread out evenly on the surface of a solid. The degree of wettability is dependant on the surface tension of both the solid and the liquid. Mercury beads up and does not wet glass because the surface tension of mercury is too high. Water does not wet Teflon because the surface tension of Teflon is too low. Preferential wettability describes a system of two immiscible liquids and a solid, where one liquid preferentially wets the solid. Adhesion refers to the state in which two surfaces are held together by interfacial forces. These forces may consist of valence forces or interlocking action or both. A liquid will adhere to a solid if the attraction of its molecules to the solid surface is greater than their mutual attraction. Solids can also adhere, if they are capable of being bonded by force. When two pieces of white-hot iron are hammered together, they become welded – they adhere. The same mechanism causes sticky drilled solids to adhere to each other and the bit and drill string, when they are forced into intimate contact by the weight of the drill string. Friction is a resistance that is encountered when two surfaces slide or intend to slide past each other. There is a distinction between dry, mixed and fluid friction and also between static and kinetic friction. The friction between moving fluid layer interfaces or between the fluid and the surface of the pipe is often measured in pressure units. The friction between the pipe surface and the borehole is measured as rotary torque and hole drag. On deviated wells, rotary torque and hole drag can become excessive enough to warrant the addition of friction reducing additives. Catalysis, one of the most important occurrences in nature, refers to the lowering of the energy required to break (or form) a chemical bond between two atoms. The catalyst works by bringing the atoms of a bond to be broken (or formed) into close proximity of another atom which will make or break the selected bond. The electronic configuration of the surface molecules of a catalyst contributes to its working mechanisms. Reactants may bond at the surface of a solid catalyst. This is known as chemisorption. It results in changing the nature of the chemisorbed molecules and the catalyst. Catalysts are very specific they only react to break (or form) certain types of bonds. 2.7.6 Semipermeable Membranes and Osmotic Pressure Osmosis occurs when there are different concentrations of a solvent on either side of a semipermeable membrane. In order for osmosis to occur, the membrane must be permeable to the solvent in question but not to the solute (selective membrane). Osmosis tends to equalize the concentrations of the solvent on either side of the membrane. If the solution on one side of the membrane is pure solvent and the membrane is impermeable to the solute, the concentrations on either side of the membrane can never be equal. However, at a certain point, the pressure of the solution against the membrane will prevent any further flow from the side with the pure solvent. The pressure at this point is called the osmotic pressure. A semipermeable membrane is a micro-porous structure which acts as a filter in the range of molecular dimensions. Thus it allows the passage of ions, solvents and very small particles. It is impermeable to macro molecules, such as proteins and polymers and solute species such as colloidal materials. Figure 24 shows a semipermeable membrane separating an NaCl solution and a solvent, water. Under atmosphere pressure, more solvent molecules pass through the membrane in the direction of the NaCl solution than in the reverse direction. Thus the solution becomes continuously more dilute. This means the vapor pressure of the pure solvent is greater


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than the atmospheric pressure above the NaCl solution. For the two phases to be in equilibrium the vapor pressure must be the same in each solution. Fig. 24:

Before

Atmospheric Pressure

Na+

Cl-

Cl-

Na+

Semipermeable membrane

H2O

H2OH2O

After

After

Vaporpressure

The vapor pressure of the solution may be raised by increasing the pressure above the NaCl solution but not above the water. The amount of excess pressure required reaching a point of equilibrium – where there is no passage of solvent through the membrane – is called the osmotic pressure. Osmotic pressure is not exerted by solute molecules. It is a pressure that must be applied to the ionized solution to achieve equilibrium with the pure solute. The term water activity (Aw) is used to describe the tendency of water vapor to move from an area of low salt concentration to a high concentration. In the case of invert emulsion fluids, the passage of water vapor from the emulsified water droplet into the formation or vice versa is dependant upon the osmotic pressure differential between the brine phase and the formation water. This phenomenon is an extremely important consideration when formulating and maintaining invert emulsion fluids.


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2.7.7 Altering Surface Chemistry The essence of effective drilling fluid formulation and management relies heavily on the ability to control the behavior of individual components, through the manipulation of their surface chemistry. When the chemistry on the surface of a component is altered, the way it interacts with other components changes. One or many properties of the fluid may change as a result. Surface active agents are called surfactants. They include emulsifiers, many polymers, foamers and soaps. They are usually polymers or long chain molecules, although an ion which alters surface chemistry could be correctly called a surface active agent. The following examples are included to help in understanding the scope of this paragraph. Emulsifiers act on the surface of emulsified brine droplets, lowering surface tension. They change the preferential wettability of solids such that they become oil wet or water wet. Clay surfaces are altered by polymers in several ways. Encapsulators reduce clay hydratability by bonding to the clay. Deflocculants seek out positive edge sights on clays, eliminating their effect. Flocculants act as a bridge between clay surfaces, increasing viscosity. Most polymers reduce drill string function losses. Foamers and defoamers both act directly on surfaces and interfaces. Some surfactants are designed to lower clay adhesion to drilling tool surfaces. Others bond to steel tools and pipe surfaces to protect them from corrosive environments, while still others effectively reduce rotary torque and hole drag. Surfactants are used to control the wettability characteristics of the pore throat surfaces in production zones. Ionic species are often added to drilling fluids to alter the surface chemistry of its components. Various cations are used as flocculants or shale stabilizers, while anions are often used as deflocculants.


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REFERENCES 1. Stephen Hawkings, A Brief History of Time (New York: Bantom Books, 1988), 65. 2. G. Hawley (Revised By), The Condensed Chemical Dictionary, 10th ed. (New York: Van

Nostrand Reinhold Inc., 1981), 788. 3. John M. Hunt, Petroleum Geo Chemistry and Geology (San Fransisco: W.H. Freeman

and Company, 1979), 208-212. 4. H. Van Olphen, An Introduction to Clay Colloid Chemistry, 2nd Ed. (New York: John

Wiley & Sons, 1977). 23. 5. Fred W. Billmyer, Jr., Textbook of Polymer Science, 2nd ed. (New York: Wiley -

Interscience, 1971), 23. 6. Darley and Gray, Composition and Properties, 336.


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CHAPTER 3 GEOLOGY 3.1 SEDIMENTRY FORMATIONS

3.1.1 Sediments and How They are Formed 3.1.2 Common Sedimentary Rocks

3.2 THE GEOSTRATIC GRADIENT 3.2.1 Normal Pore Pressure Gradients 3.2.2 Abnormal Pore Pressure Gradients 3.2.3 Subnormal Pore Pressure Gradients


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3.1 SEDIMENTRY FORMATIONS 3.1.1 Sediments and How They are Formed Geologists categorize rocks into three main groups: igneous, metamorphic and sedimentary. Igneous rocks are formed from the solidification of magma, molten rock, which is mainly silica, sometimes containing dissolved gasses and solid minerals. Metamorphic rocks are produced by the transformation of pre-existing rock into texturally or mineralogically distinct new rock. This transformation is caused by heat or pressure or both, but without the rock melting in the process. Most hydrocarbons are found in the third type - sedimentary rocks, therefore most drilling takes place through sedimentary formations. Sediment is the collective name for solid particles that originate either from the erosion of pre-existing rocks or from chemical precipitation from solution, including secretion from organisms. Three fourths of the surface of the continents is covered with a layer of sedimentary rock. Sediments can be classified by size; from gravel to sand to silt to clay. (Clay in this sense refers to size only - thus quartz can be "clay sized"). Sediment grains are often moved by water in the form of rivers, rain, waves or glaciers. Rounding and sorting of grains occurs during transportation. Deposition occurs when the transported material comes to rest and settles. Successive layers of sediments are usually deposited on top of each other. Layers are called beds and may vary in consistency or composition. They are deposited horizontally. Lithification is the term given to a group of processes that convert loose sediment to sedimentary rock. These include compaction (consolidation), cementation, or crystallization. Often consolidation is imperfect and pore spaces are left between the grains. When water flows through these spaces, precipitates often from a cementing matrix. A sedimentary rock consisting of grains bound by cement into a ridged framework is said to have a clastic texture. Sedimentary rocks, which develop by precipitation and the growth of crystals, are said to have a crystalline texture. Crystalline rocks lack both cement and pore space. Three categories of sedimentary rocks exist: organic, chemical and clastic. Commercial hydrocarbons are almost always located in the latter two types. Organic sediments such as coal accumulate from the remains of organisms such as plant remains. Chemical sediments include evaporates and carbonates. Evaporate rocks are formed from crystals that precipitate when seawater or saline lakes evaporate. Gypsum (CaSO4) and rock salt (NaCl) are examples. Usually seawater has a fairly consistent composition. The chapter on Water-Based Fluids has a table showing the typical composition of seawater. When seawater evaporates the various salts precipitate out in a specific order determined by their solubility after the following fashion: 1. Carbonates - CaCO3 Dolomite - CaMg (CO3)2 2. Gypsum - CaSO4•2H2O Anhydrite - CaSO4 3. Halite - NaCl


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4. Carnallite - KMgCl3•6H2O Potash - KCl Polyhalite - K2Ca2Mg(SO4) 4•2H2O Note that only the fourth stage contains extremely soluble magnesium and potassium salts. This stage of evaporation is seldom reached. If it is, new influxes of sea water often wash these salts away and the cycle begins again with the precipitation of carbonates and gypsum. The North Sea's Zechstein Formation is an example of a "complex evaporate". containing various combinations of all the precipitates listed above. Carbonate rocks can be formed from organism induced, or inorganic chemical precipitation, or by the cementation of accumulated shell fragments. Limestone (mostly CaCO3) and dolomite (CaMg(CO3)2) are examples. Limestone’s made from shell; algae or coral fragments are called bioclastic. These can also be called an organic rock.1 Although hydrocarbon reservoirs are more abundant in sandstone formations, the majority of the world's hydrocarbon production is from carbonate reservoirs. This is due to the number of large carbonate reservoirs in the Middle East.2 Most sedimentary rocks are clastic sedimentary rocks. These are formed from cemented fragments of pre-existing rocks. In most cases they have been eroded and transported before being deposited. Clastic rocks are often classified by their grain size. Conglomerate is a coarse-grained rock formed by the cementation of rounded gravel. Breccia is similar, but the grains are more angular. Sandstone is a medium-grained sedimentary rock formed by the Lithification of sand grains. Often clay and silt occupy part of the matrix between the grains. Fine-grained rocks are called shale, siltstone and mudstone. They typically undergo pronounced consolidation as they lithify, although consolidation itself doesn't usually convert sediment into sedimentary rock. Clastic formations composed of sand and silt are called arenaceous, while those composed of clays or clay-silt mixtures are called arigillaceous. While drilling, it is possible to encounter clastic rocks in various stages of consolidation, including the clay minerals discussed in the Clay Chemistry chapter. Consolidation is analogous to a pile of wet sponges where the weight of the sponges above drives the water out of the sponge below, with most of the water being squeezed from the bottom sponge. The model assumes that the water is free to escape or drain away. As a consequence, the water content decreases and the bulk density of the matrix increases with depth of burial. Figure 9.1 shows a theoretical curve of how the formation density can change with depth assuming free drainage. When first deposited, clastic sediments are soft and contain large amounts of water. Consolidation is reversible at this stage and shallow sediments can be easily re-dispersed into individual grains. These are called unconsolidated formations. However, as the sediment becomes more compressed, the particles are brought closer to each other and the pressure between the mineral grains or the intergranular stress begins to increase. These sediments usually contain enough water to retain a plastic character. Plastic in this sense means that they are capable of deformation without rupture. Further changes, described as diagenesis (see chapter 4) can take place as the sediment ages and the chemical and physical environment changes. This may involve increased pressure, increased temperature and changes in pore fluid composition. For example, under suitable conditions, montmorillonite can lose silica and water and take up potassium to form the more stable mineral illite. These influences can change the mineralogy of clays. Siliceous or calcareous formation water creates silica or calcium carbonate, which bonds the minerals together. Inter-crystalline bonding


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increases the strength of the rocks and makes them more brittle. Sedimentary formations generally become harder and stronger with depth of burial. Complete consolidation isn't necessarily the end of the process. The discourse of the earth's crust is on-going and various influences can alter sedimentary rocks, especially structurally. The most notable is the upheaval and deformation caused by tectonic forces. These can result in steeply inclined or dipped bedding planes. 3.1.2 Common Sedimentary Rocks Some common reservoir rocks are listed below. They are typically characterized by having a solid rock matrix and a void space or pore volume. Important properties of these rocks include porosity, permeability, fluid saturation and bulk density. Sandstones are made up of quartz grains with some feldspar or igneous rock fragments present. These grains are compacted into cemented sand masses and are held together with calcite, silica, iron oxide or various types of clays. Shales are compacted clays and can contain quartz grains, calcium carbonate or organic matter. Breccia is made up of fracture bits of other rocks cemented together and are common along fault zones. Conglomerate is a type of breccia although made up of more rounded, granular pieces of rock. Typically found farther away from breccia and exposed to more wearing forces. Limestone is composed of calcium carbonates, originating from seawater or shells and skeletons of plants and animals. Dolomite is a limestone with some of the calcium replaced by magnesium. Chalk is a type of limestone composed of cemented shells and small fragments. Marl is a mix of limestone 35-65% and shale. Reef is another limestone composed primarily of corals and other marine life. Chert is a rock composed of a dense, hard and compacted form of silica.


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3.2 THE GEOSTATIC GRADIENT The term gradient refers to the rate of change in a given pressure value, with depth. The weight of the combined mass of the formation rock and pore fluids is referred to as the bulk density of the formation. Most of the sedimentary rock, which we drill through, has a specific gravity in the order of 2.6 g/cm3. A tight formation, or one with limited porosity might have a bulk density of close to this value. A young, wet formation, or an oil or gas bearing one could have a bulk density of 2.0 g/cm3 or less. Knowing the formation bulk density helps predict under or over-pressured zones. It is also an input into solids control and hole cleaning efficiency calculations. Shale bulk density is directly related to shale resistivity and to a function of shale transit time (sonic log). A plot of either of these may reveal anomalies in bulk density.

Figure 3.1 A bulk Density Curve for a Normally Consolidated Formation

0

1000

2000

3000

4000

1 2 2.2 2.4 2.6 3

Bulk Density

Dep

th (

M)

The mass of rock and pore fluid creates a geostatic pressure, sometimes called the overburden load or stress, S. This may be expressed as equation S = ρ?b • d Where, ρ?b is the bulk density and d is depth. The geostatic or overburden gradient is then defined by equation 9.2: Geostatic gradient = S d Normal geostatic gradients range from 2.0 to 2.5 kPa/m. Figure 3.1 illustrates that the bulk density isn't necessarily a linear function of depth. Thus the above equations can only be used over short sections and the stress or gradient integrated for the whole section. The relationship between depth of burial and overburden stress is given in Figure 3.2.


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Figure 3.2 Composite Overburden Stress, s, for a noramlly Compacted Formation

01000200030004000500060007000

0.19 0.2 0.21 0.22 0.23 0.24

Kg/cm2/m

Dep

th

3.2.1 Normal Pressure Gradients When the sediment has compacted sufficiently for grain-to-grain contact to be established, the overburden load or stress, S, is supported by both the mineral grains and the fluid in the remaining spaces. The relationship is expressed in equation 9.3: S = s + Pp where s represents the intergranular or matrix stress and Pp represents the pore pressure. Normally, where the formation is freely drained and the pore spaces are interconnected, Pp is given by equation 9.4:

Pp = ρ f • d where ρ f is the pore density and d is the depth. The actual gradient should be calculated by:

ρ f Gradient = d • .00981

where the gradient is in kPa/cm and d is kg/m3. The density of the pore fluid is mainly dependent on the salinity as water is essentially incompressible. A variation in pressure gradient can result from a reduction in fluid density with depth as the formation temperature increases. Formation pore pressure gradients are typically in the range from 9.8 to 11.5 kPa/m. 3.2.2 Abnormal Pore Pressure Gradients The preceding description of the pressure regime varying smoothly with depth isn't always encountered. Abnormal pressures occur when fluids expelled by compacting sediments cannot migrate freely to the surface. One of the most important data inputs required for designing casing


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and drilling fluid programs is the pore pressure profile. There are a number of causes of this anomalous behavior. In argillaceous, mainly clay formations, water might not escape during the drainage stage. That is, the rate of expulsion is unable to keep pace with the rate of compaction. Shale formations having high concentrations of clay may have permeabilities approaching 10-6 millidarcies, so water drainage is very slow. The presence of montmorillonite can compound the problem further. It has been established beyond doubt that geo-pressures found in the Gulf Coast at depths of 3 000 m are associated with diagensis.3 This relates to the expulsion of water when montmorillonite is transformed to illite. There is also a definite correlation between formation Bentonite content and abnormal pressures in some areas of the North Sea. On the other hand, aranaceous-sandy-formations, which aren’t capped by an impervious formation, may have permeabilities in the range of 1 to 103 mullidarcies, and thus drain quite readily. In over-pressured formations, sometimes called geo-pressured formations, the analogy made to the wet sponges now has some of the sponges wrapped in plastic so the water can't escape. In this situation the weight of the other sponges is born mainly by the fluid rather than the solid phase. Geo-pressured formations may be encountered at fairly shallow depths in several areas of the world. Included are the North Sea's Forties Field, the Beaufort Sea's Amauligak Field and the Gulf Coast. Figure 3.3 shows how a variance from a normal bulk density curve indicates the presence of shallow geo-pressure at a North Sea location. Extremely high geo-pressures are only found at considerable depth. These are often associated with diagenesis, especially in Gulf Coast Wells below 3,000 m. Tectonic activity may initiate the disturbance of normally pressured formations by faulting, lateral sliding, folding or intrusion. These movements can place a formation out of equilibrium with the normal pressure regime. If migrating interstitial fluids are sealed, by impermeable formations such as shales, the pressure regime can eventually become abnormal. Salt is also impermeable to migrating fluids and can easily dissolve and then re-crystallize in a different shape. Thus formations directly under a salt formation often have abnormally high pore pressures because fluids trying to escape as a result of consolidation are unable to. Further, if the salt is forced into a dome it may exert abnormal stresses on adjacent formations. The abnormal conditions should be as closely defined as possible by careful interpretation of seismic or offset well data. Wells that are close to each other may have quite different pressure profiles. They often require separate drilling programs due to details such as whether they are drilling up or down dip to a folded formation or near to a salt dome.


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3.2.3 Subnormal Pore Pressure Gradients The pore pressure gradient can also be less than that of fresh water. This occurs in producing gas formations where production has drawn-down the original pore pressure. Or, the interstitial fluid may have migrated previously, leaving void pores with zero pressure. In both cases, the remaining rock matrix must now support more or all of the overburden stress. If the overburden stress exceeds the strength of the matrix - its yield stress value - the matrix will fail and the ground at surface or the seabed can actually sink. This is called subsidence. The most notable occurrence of such a phenomena is in the North Sea's Ekofisk field. When penetrating or completing in formations with subnormal gradients, the volume of fluid lost to the formation is usually high. Special precautions, such as the addition of bridging solids may have to be included in the Fluids program to minimize fluid-induced formation damage. Occasionally full circulation returns can't be established regardless of the number of golf-balls and


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tons of cement pumped down the wellbore. In some areas operators drill blind or without returns through these formations. A situation where two different pore pressure gradients exist in the same interval of open hole can be difficult at best. A rapid transition to overpressure can cause blowouts while drilling. If the combination of shut in casing pressure and fluid hydrostatic pressure exceeds the matrix strength or the pore pressure of the formation above, loss of fluid and even wellbore fracturing can occur. In this case a good indication of pressures and volumes is unattainable and the result could be an underground blowout. If the escaping, pressurized pore fluid fractures the formation to the surface, loss of ground integrity can and has caused rigs to sink out of sight. In some areas, such as the Beaufort Sea, pore pressure reversals are encountered. Here a column of drilling fluid may be lost when the bit penetrates a formation having a lower pore pressure.


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REFERENCES 1 Charles C. Plummer, David McGeary, Physical Geology, 4th ed. (Dubuque, IOWA: Wm.

C. BORWN PUBLISHERS, 1988).120. 2 Allen and Roberts, Production Operations, Vol 1, 3. 3 Darley and Gray, Composition and Properties, 349.


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CHAPTER 4 CLAY CHEMISTRY AND PROPERTIES 4.1 KEY POINTS AND SUMMARY 4.2 THE ORIGIN AND BASIC STRUCTURES OF CLAY MINERALS 4.2.1 The Chemical Weathering of Feldspar 4.2.2 Building Units 4.2.3 Isomorphous Substitution 4.2.4 Associated Cations 4.2.5 Broken Edge Charges 4.3 DESCRIPTIONS OF COMMON CLAY MINERALS 4.3.1 Kaolinite 4.3.2 Illite 4.3.3 Smectites 4.3.4 Chlorite 4.3.5 Mixed Layer Clays 4.3.6 Attapulgite and Sepiolite 4.4 FORCES BETWEEN CLAY PARTICLES 4.4.1 Attractive Forces 4.4.2 Repulsive Forces 4.5 THE BEHAVIOUR OF CLAYS IN DRILLING FLUIDS 4.5.1 Dispersion 4.5.2 Flocculation 4.5.3 Aggregation 4.5.4 Deflocculation 4.5.5 Viscosity in Water-based Systems 4.5.6 Viscosity in Oil-based Systems 4.5.7 Gelation 4.6 FORMATION CLAYS 4.6.1 Diagenesis 4.6.2 Sediments 4.6.3 Clay Analysis


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4.1 KEY POINTS AND SUMMARY Clay minerals almost always constitute a percentage of the solid phase of drilling fluids. They may be added intentionally to control certain properties, or they may become entrained in the fluid while drilling through formations containing clays. Clay minerals are crystals. They are formed through the weathering process, or alteration of parent minerals such as feldspar. Most clay minerals are plate-like in shape. Each Platelet is composed of many repeating unit layers, stacked on top of each other. Unit layers are thin and flat. Each unit layer is composed of two or more sheets.

There are two different types of sheets which can combine to form unit layers. They are named after their geometric shape, or tetrahedral and octahedral sheets. Often there are variances in the chemical composition of these sheets. These chemical variances and the order, in which the sheets are stacked to form unit layers, impart various properties to different clay minerals.

CH H

H

H

Tetrahedral methane

Cl

P

Cl

Cl Cl

ClCl

Octahedral phosphorus hexachloride Frequently the chemical variations in the composite sheets cause charge deficiencies within individual unit layers. This usually results in an overall negative charge on the flat surface of a unit layer. Charges also exist on the broken edges of clay minerals. In a suspension these broken edge charges are influenced by the pH.


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Common clays include kaolinite, illite, smectite and chlorite. Bentonite is a variety of smectite – the most common clay in the drilling fluid industry. This chapter examines the structural and behavioral differences of the most common clay minerals. The properties which clays impart to suspensions depend partly on how individual clay platelets interact both with each other and the fluid. The balance between attractive forces and repulsive forces between clay plates is the most important factor governing the physical properties of clay suspensions. Most clays have an affinity for water and some may swell when they become water wet. The selection of a drilling fluid is often related to the reactions between the clay or shale intervals and the drilling fluid. If not properly formulated, the drilling fluid can strongly alter the stability of these formations, affecting the stability of the wellbore. The clays found in production sands can swell or move when contacted by water, causing formation damage. A basic understanding of the composition of clay minerals facilitates a better comprehension of how and why they behave in certain environments. Once this comprehension is achieved, the environment of a suspension may be altered to induce clays to behave beneficially. 4.2 THE ORIGIN AND BASIC STRUCTURES OF CLAY MINERALS Clay may be described as a natural, fine grained, earthy material which develops plasticity when moistened. Clay minerals include any group of hydrous silicates of aluminum and other metals. They are generally classified as aluminum silicates. Clay minerals are most often formed when sediments are deposited and compacted. Other minerals which are common in sedimentary rock may contain a percentage of clay minerals. X-ray diffraction and chemical analysis indicates that all clay minerals are layered and crystalline. Chemically, they all contain large amounts of aluminum, silicon and oxygen or hydroxyl. They may also contain smaller amounts of iron, magnesium, calcium, potassium and sodium. It is these latter constituents which give individual clay minerals their own unique properties. Clays may be classified according to particle size in either geological or oil field terms. Clay crystals process some unique properties. They usually consist of wafer-like structures called unit layers. Unit layers consist of two long axes and one short but definable axis, usually in the order of 10 Å. This results in a large surface area. Unit layers process electrical charges which exist on the broken edges, and on the flat surface of the layers.


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In clay minerals, many unit layers are repeated or stacked to constitute each clay mineral. Each unit layer is composed of thin, flat sheets, which differ in structure. In mineralogical terms, these individual sheets are sometimes also referred to as layers. For example, illite is sometimes called three-layer clay because each unit layer contains three sheets. In this chapter, for the sake of simplicity, the term sheet is used to describe the (octahedral and tetrahedral) sheets which combine to form unit layers. The term unit layer is used to describe the layers which are stacked to form a clay mineral. 4.2.1 The Chemical Weathering of Feldspar Clay minerals may originate from the weathering process of a parent rock, or by other processes such as the alteration of volcanic rock in situ. Many clay minerals originate from weathered feldspar minerals. The weathering of the mineral feldspar is an example of how an original crystal can be altered by weathering to form an entirely different type of crystal. When feldspar – a framework silicate – reacts with the H+ ion from H2CO3 (formed from CO2 and H2O) it forms clay minerals, which are sheet silicates. The general process may be stated:

2KAlSi3O8 + 2H2CO3 + H2O

H2O + CO2 H2CO3

Al2Si2O5(OH)4 + 2KHCO3 + 4SiO2

Feldspar Clay Silica

This process occurs when rainwater acquires carbon dioxide as it soaks into soil. The hydrogen ion provided by the slightly acidic water reacts with the feldspar – becoming incorporated into the clay mineral. When hydrogen moves into the crystal structure, it replaces potassium from the feldspar. The potassium ion and the original bicarbonate ion are removed by the moving water. Some of the silicon from the feldspar is also removed. The new crystal is called a clay mineral. This weathering process applies to K feldspar (orthoclase) forming potassium salts, and Na feldspar and Ca feldspar (plagioclase) forming sodium and calcium salts respectively. It should be noted that in his book, “Clay Mineralogy”, Ralph Grim points out that several clay minerals have been synthesized from various mixtures of crystalline minerals and reagents at various temperatures and pressures. This applies to some of the clays discussed in this chapter, including kaolinite, illite and smectite. In fact kaolinite has been formed from a variety of parent minerals including leucite. Grim states: "An acid rock containing considerable quantities of potassium as well as magnesium… will yield illite and smectite. If the content of magnesium is low, illite will be the only product, and if the content of potassium is low, smectite will be the only product. Rapid removal of the potassium and magnesium leads to the formation of kaolinite". The resultant clay minerals are often transported and deposited as sediments. Sedimentation is a geological process discussed both at the end of this chapter and at the beginning of the chapter entitled Borehole Stability.


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4.2.2 Building Units There are only two types of the thin, flat sheets which combine to form the unit layers which make up clay crystals. They are named after the geometric co-ordination of their constituent atoms, or tetrahedral and octahedral sheets. The order in which sheets are stacked to form unit layers and the methods by which they are bound together, serves to classify clay minerals. Figure 4.1 shows a simplified example of four common types of layered clay minerals. Figure 4.1

OHOH OH

-O-O -O

H+ H+ H+

Kaolinite

Unitlayer

-O-O -O

Illite

Unitlayer

-O-O -O

K+ K+ K+

-O-O -O

Montmorillonite

Unitlayer

-O-O -O

Ca+ Ca+ Ca+

-O-O -O

Chlorite

Unitlayer

-O-O -O

=Octahedral

=Tetrahedral

Figure 4.2a denotes a single tetrahedron or four sided unit. It usually contains a silicon ion (Si4+); hence it may be referred to as the silica sheet.

O

SiOO

O A tetrahedral subunit (SiO44-)

fig. 4.2a The silicon atom is located in the center of the tetrahedral an equal distance from four oxygen atoms. In some cases the center may be empty or the silicon may be replaced by magnesium or iron. Figure 4.2b illustrates that three of the four oxygen atoms of each tetrahedron are shared by three neighboring tetrahedron to form a sheet of composition Si6O9(OH)6.


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Figure 4.2b: Side view of the tetrahedral sheet

The extent of this sheet is indefinite. The shared oxygen atoms can be seen to form a plane or basal surface. When viewed from above (Figure 4.2c) a hexagonal void can be seen in the network of silicon - oxygen – silicon bonds. Figure 4.2c:

Figure 4.3a shows a single octahedral or eight sided unit. It usually contains an aluminum (Al3+) ion in octahedral co-ordination with 6 hydroxyl ions. In some cases the center of the octahedron may be empty, or the aluminum may be replaced by other metals – magnesium or iron. Figure 4.3b illustrates how hydroxyls are shared between individual octahedron, as they combine to form sheets. The area extent of octahedral sheets is also indefinite. The octahedral sheet usually has a balanced charge structure. When the octahedral metal ions are aluminum (trivalent), only two out of every three center sites can be filled. In this case the sheet is termed dioctahedral. Its composition is Al2(OH)6 – the mineral gibbsite. When the metal atoms are magnesium (divalent) all the spaces are filled to balance the charge structure and the sheet is termed trioctahedral. In this case the composition is Mg3(OH)6, the mineral brucite.


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Figure 4.3:

The tetrahedral and octahedral sheets have dimensions such that they may be bonded by sharing common oxygen atoms. Figure 4.7 shows an example of a single tetrahedral sheet bound to a single octahedral sheet forming a unit layer two sheets thick. This is the mineral kaolinite. Note how the apex of each tetrahedron points toward the octahedral sheet. The oxygens at these apices displace two out of three hydroxyls originally present on the octahedral sheet. This forms a bond of common oxygen atoms between sheets, creating the unit layer. In the case of two sheet clay, there is an oxygen network on one basal surface and a hydroxyl network on the other. When three sheets combine to form one repeating unit, an octahedral sheet is always located between two tetrahedral sheets. Again, tetrahedron apices point towards the octahedral sheet. Two thirds of the octahedral hydroxyls are displaced and common oxygen atoms are shared


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between sheets. In this case, both basal surfaces of the layer consist of an oxygen network. Figure 4.8 shows how illite is formed from this type of three-sheet layer. Tetrahedral (silica) and octahedral (aluminum) sheets combine naturally to form unit layers. The bonding between sheets is covalent, helping to stabilize charges in the unit layer. The ratio of tetrahedral to octahedral sheets can be 1:1, 2:1 or 2:1:1 in a given unit layer. When the unit layers are stacked together they form a structure called the crystal lattice.1 The distance between a plane in a unit layer and the corresponding plane in the next unit layer is called the c-spacing or basal spacing (see Figure 4.4). This distance is about 9 Å in three-layer minerals and 7 Å in two layer minerals. The unit layers are held together by van der Waals forces and secondary valences between adjacent atoms.2 The lattice tends to cleave between the exposed basal surfaces. The structure of the four clay minerals encountered most frequently in the drilling industry is shown in Figures 4.7, 4.8, 4.9 and 4.12. Figure 4.4: An expanding lattice

4.2.3 Isomorphous Substitution The octahedral and tetrahedral sheets as described are in perfect charge balance. However the ions occupying the center sites may be replaced by ions of similar or lower charge. For example, the tetrahedral silicon atom may be replaced by aluminum or iron. These ions have the same co-ordination dimensions but cannot accept all of the electrons donated by the surrounding four oxygen atoms. This substitution creates a surplus of electrons and a negative charge within the clay structure. This is termed a charge deficiency and is in fact the distinction between clay minerals and some other types of minerals – including the smectite prototypes (see 4.3.3). Similarly, magnesium or iron may replace aluminum and create a negative charge in the


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octahedral sheet. This structural feature, where silicon or aluminum ions are replaced is called isomorphous substitution or like ion replacement. It usually creates negative charges in the sheet. These charges do not vary with pH. Different clay minerals are characterized by different patterns of isomorphous substitution, giving that mineral its own characteristics. The two variables are the extent and the position of substitution. 4.2.4 Associated Cations and Cation Exchange Capacity (CEC) The negative charges created by isomorphous substitution are usually countered by the close association of a cation on the basal surfaces of unit layers. The nature of the cations’ hydration energy has a significant influence on the structure of the clay and its properties. Table 4.1: Diameters of Cations in the Dehydrated and Hydrated Form

Ion Dehydrated ion diameter (Å)

Charge Density (charge/Å2)

Hydrated ion diameter (Å)

Sodium (Na+) 1.90 0.088 5.5 – 11.2 Potassium (K+) 2.66 0.045 4.64 – 7.6 Magnesium (Mg+2) 1.30 0.376 21.6 Calcium (Ca+2) 1.90 0.176 19.0 The extent of the interaction of water with the charged ion depends on the charge density of the ion. Different ions have a range of sizes depending on the number of electrons in the atom. The sizes of dehydrated cations are given in Table 4.1. The charge density is the charge on the ion divided by the surface area. This has been calculated for the common ions. Tightly associated water forms layers around the cation, as illustrated in Figure 4.5. • Magnesium has the highest charge density and forms the largest hydrated ion. • The other divalent ion, calcium, also forms a large hydrated ion with a high charge

density. • Sodium forms an intermediately hydrated ion. • Potassium forms a weak complex.


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Figure 4.5: Orientation of water molecules near a cation

This shows that there are large differences between the energy of hydration of the commonly occurring ions. These differences in cationic hydration energy are important when considering the hydration energy of clays with different exchanged cations. Cations usually associate in the crystal lattice at the site nearest the excess electrons resulting from isomorphous substitution. The nature of the association between the cation and this site depends on several factors. These include: • The nature of the isomorphous substitution site; • The type of cation; • The relative concentrations of competing cations. Higher valency ions are usually adsorbed preferentially. A study by S.B. Hendricks et al in 1940 suggested that the order of preference or the replacing power is usually:

H+> Ba++> Sr++> Ca++> Cs+> Rb+> K+> Na+> Li+ This order may vary between types of clay and concentrations of cations. The fact that hydrogen is so strongly adsorbed makes cation exchange pH dependant. The ability of clay to absorb cations is termed its cation exchange capacity or CEC. It is expressed in milli-equivalents of the cationic dye methylene blue absorbed by each one hundred grams of dry clay (meq/100g). In some clay such as montmorillonite and illite, the majority of the exchange sites are located on the basal surfaces. In the case of kaolinite, the broken bonds at the edges of the crystal account for the majority of the exchange sites. This explains the relatively low colloidal activity of kaolinite


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when compared to montmorillonite. Montmorillonite, having a higher CEC value, swells to a greater degree, contributing to higher viscosities at lower concentrations. A field test based on the adsorption of methylene blue, tests the approximate value of the CEC of the whole fluid. This test does not determine cationic species. Clays also have the ability to exchange anions, but to a much lesser degree than their cation exchange capacities. 4.2.5 Broken Edge Charges The balanced charge structure in a clay crystal is broken when the crystal is fractured. (Broken edge charges are generated for all fractured ionic crystals, including barite and calcium carbonate.) A feature of clay minerals is that they are built up from weakly basic aluminum hydroxide and weakly acidic silicic acid. The basic groups in the clay react with hydrogen ions, and the acidic groups react with the hydroxyl ions to generate predominantly positive or negative charges on the edges. • At neutral pH, the broken edge charges are close to equilibrium. • When alkaline conditions are created, predominantly negative edge charges are soon

established. The action of breaking clay crystals and reacting the exposed aluminum ions with hydroxyl ions occurs continuously in drilling fluids. It is one reason why caustic soda must be continually added to maintain a desired alkalinity. The treatment levels of caustic can be minimized if the concentration of clay solids is kept low.

• Acidic pH values are not normally used in drilling fluids, but the clays in sandstone reservoirs may be exposed to acids during stimulation procedures. If this process alters clay charge distributions and disturbs the clays, blockage of formation pores may result. This phenomenon is explained in greater detail in the chapter on Production Zone Drilling, Completion and Workover Fluids. The development of pH dependant charges on fractured crystal edges occurs in all clay minerals.

Figure 4.6: Broken edge charges on a clay crystal


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4.3 DESCRIPTIONS OF COMMON CLAY MINERALS 4.3.1 Kaolinite (Two sheets per unit layer) Kaolinite is two-sheet clay. That is, the unit layers consist of one octahedral sheet and one tetrahedral sheet. The general formula for kaolinite is Al2Si2O5(OH)4, a diagrammatic sketch of the 1:1 structure of kaolinite is given in Figure 4.7. Figure 4.7: Kaolinite structure

The sheets are bonded together in the covalent manner described in section 4.2.1. The oxygens at the tetrahedral apices displace two out three octahedral hydroxyls. This leaves both, a hexagonal shaped oxygen surface and a hydroxyl surface exposed on each layer. Very few if any isomorphous substitutions occur in either sheet, resulting in balanced charges within the layer. Unit Layers are stacked such that tetrahedral oxygens oppose octahedral hydroxyls. Consequently strong hydrogen bonding exists between unit layers. This prevents lattice expansion or swelling, resulting in low viscosity suspensions. Few, if any cations are adsorbed on the basal surfaces. Kaolinite typically has CEC in the range of 3 – 15 meq/100g of dry clay. The natural crystals are well ordered and do not readily disperse in water. They may consist of about 100 unit layers in a book like structure. Charges on the platelets are usually broken edge charges which are pH sensitive. Platelets carry a characteristic double layer of oriented water of 10 and 400 Å thickness respectively. Kaolinite is believed to posses the greatest tendency to migrate when considered in the context of formation damage caused by particle migration.


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(Dickite is a type of Kaolinite found in sandstone reservoirs). Kaolinite may be transformed to chlorite or illite with depth and age. Kaolinite is found extensively in marine deposits and shale. It is used in the ceramics and paper making industries. 4.3.2 Illite (Three sheets per unit layer) Illite is three-sheet clay. It may be described as mica which contains some water. The unit layers in illite consist of an octahedral sheet located between two tetrahedral sheets. The prototype clays are trioctahedral biotite, and dioctahedral muscovite. Figure 4.8 depicts the 2:1 structure of muscovite. Note the location of the potassium ion. The general formula for muscovite may be written as KAI3Si3O10(OH)2. Figure 4.8: Illite (muscovite) structure


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The three sheets are bonded together in the familiar covalent manner described in section 4.2.1. Unlike montmorillonite, the majority of the isomorphous substitutions in illite occur in the tetrahedral sheet. Usually aluminum replaces silicon. If substitutions occur in the octahedral sheet, magnesium or iron usually replaces aluminum. Potassium is always located in the cation exchange site between unit layers. It fits neatly into the hexagonal hole in the exposed oxygen network. Illite is common in marine sediments and it is the presence of this potassium which causes the deflection in gamma-ray logs, indicating the presence of shale. Unlike montmorillonite, the charge deficiency is situated in the two outside sheets. Therefore the bond between unit layers is strong. Potassium normally cannot be exchanged. In degraded illite the potassium may be leached from between layers making it possible for other cations to interact with the clay. Thus, some illite may disperse in water and hydration and cation exchanges may occur at the surfaces of illite aggregates. This promotes some tendency to hydration and c-spacing increase. Potassium stabilizes illite, due to the small hydrated diameter of the potassium ion (see table 4.1). The normal CEC of illite is between 10 – 40 meq/100g of dry clay. 4.3.3 Smectites (Three sheets per unit layer) The smectite group of clays has been classified by the American Petroleum Institute (API Project 55). This classification is based on: • Their prototype mineral – talic or pyrophylette; • The degree of isomorphous substitution; • The species of atoms substituted. Familiar members of the smectite group include: talic, hectorite, vermiculite and montmorillonite. Because of its swelling characteristics, montmorillonite is the best known and most studied of the smectites. Smectites are three-sheet clays. An octahedral sheet is located between two tetrahedral sheets. Figure 4.9 depicts the 2:1 structure of sodium montmorillonite. The general formula for montmorillonite may be written as 2[(Al2-xMgx)Si4O10(OH)2] + exchange cation. The three sheets are bonded together in the covalent manner described in section 4.2.1. Bonding between unit layers is weak because oxygen basal surfaces oppose each other. The forces bonding the layers are reduced further because, unlike illite, the majority of the isomorphous substitutions and their resultant charge deficiencies occur in the octahedral or middle sheet. Here, magnesium or iron is substituted for aluminum. Aluminum is sometimes substituted for silicon in the tetrahedral sheet. The net charge deficiency in montmorillonite is dependent on the degree of substitution and varies widely. Various cations may bind the unit layers together.3 The two types of montmorillonite applicable to the drilling industry are calcium montmorillonite and sodium montmorillonite (bentonite). In 1926, Ross and Shannon redefined the term bentonite to limit it to clays produced by the alteration of volcanic ash in situ. Under ordinary conditions, a smectite with sodium as the exchange ion frequently has one molecular water layer, and the c-spacing is about 12 Å. With calcium, there are frequently two molecular water layers.


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Because the bonding is weak, the crystal lattice cleaves easily. Since the majority of substitutions occur in the octahedral sheet, cations occupying exchange sites between unit layers don't completely lose their ionic character. The tetrahedral sheet prevents them from coming close enough to the charge deficiency site. This residual ionic character creates an attraction for polar molecules. Figure 4.9: Smectite (montmorillonite) structure

If water is allowed to satisfy this, attraction an increase in c-spacing results. The c-spacing increase is greatest when sodium occupies the exchange site. Sodium, being monovalent may


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only satisfy a basal surface charge deficiency of one. On the other hand, the divalent calcium ion can satisfy a charge deficiency of two, and more readily associate with two adjacent layers. Thus, smaller quantities of sodium montmorillonite will provide higher viscosities in suspensions. Calcium montmorillonite can be converted to sodium montmorillonite using a process involving sodium carbonate. The swelling pressure of sodium montmorillonite is so strong that crystals may separate into individual unit layers. When unit layers separate, the sodium may disassociate with the sheet leaving a net negative charge on the face of the sheet. The charges on the broken edges of montmorillonite vary with pH. Dimensions of hydrated sodium montmorillonite particles have been measured using various electro-optical techniques.4 When single, three-sheet unit layers occur in a suspension the hydrated radius could be as large as 230 Å. If a particle were enlarged to something we could touch it might look like a coin 1 mm (0.04 inch) thick with a diameter of 25 mm (1.0 inch). In fact, if one of gram of pure sodium montmorillonite was able to hydrate to single unit layers, the dimensions would be about 800 m2. In a drilling fluid application, one is concerned with either exploiting or nullifying the swelling characteristics of smectites. When bentonitic formations are penetrated, their tendency to hydrate and swell can cause problems such as mud rings, bit balling and borehole instability. Some inhibitive fluid systems are designed around the dimensional and charge relationships between the clay’s hexagonal oxygen networks and cations such as potassium, aluminum and calcium. Bentonite is purposely added to some drilling fluid systems to improve viscosity, suspension, lubricity and filtration characteristics. Viscosity or resistance to flow is provided by the large flat shape of the sheets, but it is the electrostatic charges on the sheets which make bentonite unique. These charges cause water in the vicinity of the clay plate to become structured or crystalline. When the suspension is at rest, the plates align themselves to satisfy any inherent charge deficiencies in the suspension. Structure is built up and resistance to flow (viscosity) increases. When enough shear or motion is applied to the suspension to break some of this alignment, the structure degrades. Resistance to flow then decreases and the fluid becomes thinner (Figure 4.10). Figure 4.10: Shear thinning: the alignment of bentonite at rest and in motion


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A shear-thinning fluid makes an ideal drilling fluid. This building and breaking of structure can be repeated infinitely in bentonitic fluids. The thin, flat shape of bentonite particles provides most water based systems with superior fluid loss and cake characteristics. Individual plates tend to lay flat against any surface where a pressure differential exists (Figure 4.11). Figure 4.11: Effect of bentonite on filtration and cake properties


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Operators usually require that the bentonite they purchase meet a certain standard such as the API specifications (Table 4.2). Natural supplies of good quality bentonite are being depleted. Suppliers may peptize or beneficiate bentonite with polymers to meet operator or API specifications. Over-peptization can cause the polymers to act as a flocculant – with adverse results. Specifically, a Ben-Ex type viscosity hump may occur and the viscosity will decrease. This has prompted both API and others to develop tests for the degree of peptization in commercial bentonite. The results of these tests may be reported as the peptization index (see volume II). The CEC of montmorillonite is 70 – 130 meq/100g of dry clay. When bentonite is used to viscofy a non polar, oil-based fluid it must first be treated with a cationic amine. This makes the clay hydrophobic or oil wettable (organophilic). Table 4.2 Bentonite Requirements for API Specification (section 4) Parameter Specification Moisture, as shipped from point of manufacture: 10% maximum Wet screen analysis, residue on U.S. Sieve (ASTM) no. 200: 4% maximum *Viscometer dial reading at 600 rpm; 30 minimum *Yield point, lb/100 ft2: 3 x PV Maximum *Filtrate: 15.0 cm3, maximum

* Properties of a suspension of 22.5 g of bentonite (as received) in 350 cm3 of distilled water; stirred 20 minutes; allowed to stand overnight (16 hours); re-stirred 5 minutes before testing. Test to be made as stated in API RP-13A, " Drilling fluids Specifications". 4.3.4 Chlorite (four sheets per layer) Chlorite’s repeating unit is composed of four sheets. Figure 4.12 describes the 2:1:1 structure of chlorite. The general formula is 2[(SiAl)4(MgFe)3O10(OH)2] + (MgAl)6(OH)12 Figure 4.12: Chlorite structure


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A tri-octahedral sheet where some aluminum is replaced with magnesium is referred to as the brucite sheet. It alternates with a three-sheet configuration similar to that seen in smectites and illites. There is some substitution of aluminum for magnesium in the brucite sheet, giving it a net positive charge. In the three-sheet configuration, some silicon ions are replaced by aluminum, resulting in a net negative charge. These charges balance the structure of the unit layer and bind the brucite sheet to the three-sheet configuration. This results in a low net charge in chlorite, although the bonding between unit layers is strong.


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The CEC of chlorite is 10 – 40 meq/100g of dry clay. The reason this is higher than the CEC of kaolinite is because in certain degraded chlorites, part of the brucite layer is missing. This permits some degree of inter-layer hydration and lattice expansion. 4.3.5 Mixed Layer Clays The term "mixed layer" clays is usually included in X-ray diffraction analysis. In some formations mixed layer clays account for a fairly large percentage (greater than 10%) of the clay fraction. Mixed layer clays often contain one or more representatives from the smectite (expanding) group. The sequence of layers may be ordered or random. Usually these clays hydrate, cleave and disperse to a greater extent than most other clay mineral lattices. 4.3.6 Attapulgite (salt gel) and Sepiolite (thermal gel) Attapulgite and sepiolite may contain tetrahedral and octahedral structures. They are dissimilar from the clays previously discussed because their overall structure does not consist of flat layers. Instead, individual particles have a long, thin, needle-like shape. These needles occur in bundles and are referred to as laths. Because of the shape of these clays, their use is prohibited in some areas. Attapulgite has a fibrous texture and a chain structure. Four silica tetrahedrons occur on either side of the octahedral sheet with their apices directed towards the octahedral sheet. These structural units alternate in a checker board pattern, and a series of channels is left between them. These channels contain "zeolitic" water, and can contain up to 4 water molecules per unit cell. This water is strongly bound to the structure. There is a cleavage plane along the axis, parallel to the silica chains, so that the mineral crystals have a needle-like shape, typically 1 µm long and 0.01 µm wide. The surface area can adsorb moderate quantities of water, contributing to viscofying properties. These clays don’t hydrate and disperse in the normal manner. The maximum viscosity in suspensions is achieved by shearing the clays enough to degrade the bundles into individual needles or laths. Shearing of the particles requires maximum agitation in order to yield this clay fully. The CEC of sepiolite is 10 – 35 meq/100g of dry clay. Because both surface area and charge are relatively low, ionic species in solution have little effect on the rheological properties of these clays. This makes them resistant to ionic contamination causing flocculation. The smaller surface area also causes them to be more resistant to thermal or mechanical flocculation (see Figure 4.13). Sepiolite exhibits the best rheological properties at high temperatures.


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Figure 4.13: Differences between bentonite and sepiolite

100 °C 200 °C

100 °C 200 °C

Bentonite particles begin to aggregate or

stick together Sepiolite needles have a small area of

inter-action The disadvantages of attapulgite and sepiolite are, poor filtration characteristics due to their brush heap structures and concerns regarding safety to personnel stemming from the fibrous nature of the clay crystals.


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Table 4.3: Summarization of clay characteristics

LAYERS OCTAHEDRAL SHEET EXPANSION GROUP SPECIES

Two-sheet (1:1) Dioctahedral Non-swelling Kaolinite Kaolinite Dickite Narcite

Some swelling Illite Illite Dioctahedral

Swelling Montmorillonite Ca+2 Montmorillonite

Na+ Montmorillonite Three-sheet

(2:1)

Trioctahedral Swelling Vermiculite Vermiculite Four-sheet

(2:1:1) Trioctahedral Non-swelling Chlorite Chlorite varieties

4.4 FORCES BETWEEN CLAY PARTICLES The preceding text and the review on basic chemistry both discuss the surface charges common to most clay minerals. In both fresh and saline environments, inter-particulate attraction and repulsion forces operate simultaneously. • The attractive forces are inherent and are not affected by salinity. • On the other hand, the repulsive forces decrease with increasing salt concentration.

In fresh water the repulsive forces dominate and the solution is stable. In salt water, the repulsive forces are reduced to where the attractive forces dominate and particle associations begin to form.5 The ensuing text attempts to explain how these mechanisms work.

4.4.1 Attractive Forces A major attractive force between unit layers in clays are short range electrostatic forces called Van der Waals forces. These forces are important in holding clay crystals together. Van der Waals forces may be defined as the weak attractive forces that act on neutral atoms and molecules. They may arise because of the polarization induced in each of the particles by the presence of other particles. Electrons in atoms normally occupy symmetrical orbitals around the charged nucleus. However, the symmetry may be instantaneously disturbed, setting up a dipole or charge separation. This dipole then generates an attractive force in a neighboring atom. These forces are weak and only operate over short distances, but they can be significant for relatively large surfaces such as clay platelets. The relationship between attractive energy, repulsive energy and separation distance is shown in Figure 4.14. These forces are independent of ion concentration or type.


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Figure 4.14: Van der Waals forces’ dependence on distance between 2 clay platelets

The attraction between clay platelets can also be increased by the presence of polyvalent cations such as calcium or aluminum. Cations cannot associate with more than one charge deficiency on a given unit layer. If the ions carry more than one charge they may form a bridge between clay particles increasing the level of structure in the suspension. This is illustrated in Figure 4.15, showing calcium bridges on the edge or between the faces of two clays. Edge-to-edge and edge-to-face associations may be formed quickly. Face-to-face association is a more stable form of association but takes longer to form and may require higher levels of calcium.


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Figure 4.15: Flocculation of clays by polyvalent cations

Long chain polymers may also form bridges between the clay platelets as illustrated in Figure 4.16. The polymer increases the degree of interaction between the clay platelets and hence the viscosity. The chapter on Polymer Chemistry explains how longer chain polymers have a more noticeable effect on viscosity.


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Figure 4.16: Action of anionic polymers

4.4.2 Repulsive Forces The negative charges on the surface of a clay particle attract cations. These cations are usually hydrated themselves. The layer of water molecules next to the particle is bound to and moves with the particle. It is termed the stern layer or bound layer. The layer of water molecules next to the stern layer is called the diffuse layer. The density or concentration of any cations in the diffuse layer decreases as the distance from the particle increases. The ions in this layer may move independently of the particle. The interface between the stern layer and the diffuse layer is called the shear plane. Together these layers are termed the electrostatic double layer, represented in Figure 4.17. The double layer surrounding bentonite particles may extend 200 Å or more from the surface. Figure 4.17: Electrical double layer


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The effect of the electrostatic double layer causes clay platelets to repel. This effect is termed double layer repulsion. The thickness of the diffuse layer is reduced as either the cationic concentration or valency in the solution is increased. When this occurs, particles are able to approach each other more closely before repulsive energies become strong enough to act. Figure 4.18 shows the effect of salt on the repulsive forces of charged particles. Figure 4.18: Effect of salt concentration on repulsive forces of charged particles

In a suspension, the charges developed on broken clay platelet edges are influenced by the pH. The negative charge density is increased at higher pH values because hydroxyl ions neutralize positive edge sites. The influence of pH on charge density is demonstrated by measuring the mobility of the clay between two charged plates. Figure 4.19 shows the electrophoretic mobility increasing rapidly between pH 8-10. This indicates the benefit of increased pH when dispersing bentonite and less dispersive conditions are created at lower pH values. (Above pH 12, the dispersive affect may diminish to a point where is reversed. That is, clay particles begin to approach each other more closely.)


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The electronegative character of a clay particle can be increased by the adsorption of negatively charged low molecular weight molecules called polymers. They adsorb onto the positive edge sites and increase the overall negative charge density. These molecules increase the repulsive forces between the particles and are termed deflocculants. The decrease in inter-particulate forces also decreases the viscosity. Therefore, they are also called thinners. Figure 4.19: Electrophoretic mobility of Na-montmorillonite as a function of pH

Any process which changes the charge density on clay particles influences the net interactive forces between the particles. In general, it may be stated that as the environment of a suspension becomes more cationic in nature, clays tend to build more structure. Conversely, structure may degrade as the environment of the suspension becomes more anionic. Table 4.4 summarizes some of the factors which contribute to the formation or degradation of clay structures. The overall effect of attractive and repulsive forces in a range of salt environments is shown in Figure 4.20. Note that at low electrolyte concentrations repulsive forces are able to offset the attractive forces and the clay particles are repelled. As the electrolyte concentration is increased, the thickness of the diffuse layer is reduced and the repulsive forces diminish to a point where the attractive forces dominate.


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Figure 4.20: Flocculation

Table 4.4: Summary of Conditions which influence Clay Structures ENVIRONMENT LESS STRUCTURE MORE STRUCTURE Salt concentration < 300 mg/l > 3 000 mg/l

Fast at 20000 mg/l pH > 8 < 6 and > 12 Cationic concentration Sodium Calcium, aluminum Polymer type Anionic, low molecular weight High molecular weight

4.5 THE BEHAVIOUR OF CLAYS IN DRILLING FLUIDS Wyoming bentonite is the most common viscofying clay used in drilling fluids. When a bentonite suspension is considered, it is easy to imagine perfectly dispersed clay plates, each fully hydrated with its own double layer. Actually this is never the case. Non-dispersed aggregates always exist in bentonite suspensions. Soon after drilling commences, an increasing concentration of formation clays becomes entrained in the system. It is probable that most clay-based fluid systems eventually contain several or all of the clay minerals. As drilling continues, the pH or the ionic environment of the suspension may change. Ultimately a complete array of particle association types may exist in a fluid at any given time. For this reason, the classification of clay particle associations simply refers to the net or average effect from all types of associations existing in a fluid. These associations are limited to four terms: Dispersion, flocculation, aggregation and deflocculation. The basic definition of aggregation and dispersion denotes the physical number of existing particles, aggregation meaning less and dispersion meaning more. The terms flocculation and deflocculation refer to the interactions between particles and the colloidal structure derived as a result of these interactions.


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These terms are occasionally misused in our industry. The most common misuse is an outright exchange of the term dispersion for deflocculation. Their co-use may also be quite confusing. The terms flocculated / aggregated and flocculated / dispersed correctly refer to possible average particle associations in clay suspensions. However, these have only limited application to most drilling fluids and will only be touched on in this text. 4.5.1 Dispersion As a drilling fluids term, dispersion may mean either the mechanical subdivision of particle aggregates in a suspension or the electrochemical subdivision of clay platelet stacks. Both processes may occur simultaneously and the net result is the same. There is an increase in the number of clay particles. The term dispersion does not apply to the process of deflocculation. The ability of bentonite to disperse is initially dependant on its ability to attract polar molecules (see section 4.3.3). It must then continue to hydrate or adsorb water. The adsorption mechanisms of water on clay surfaces are not fully understood, but the most accepted theory is the one of hydrogen bonding. The surfaces of clay minerals are made up of either hydroxyl groups or oxygen atoms arranged in a hexagonal pattern, which can coincide at points with a similar pattern in a hydrogen-bonded water structure. Analysis of the hydration of smectites shows that the swelling of montmorillonite takes place in a step-wise fashion. The reason for this is thought to be a step-wise formation of discrete monomolecular water layers. It is necessary for the c-spacing to increase before separation of individual unit layers can occur. As they separate, the viscosity of the suspension increases because more separated layers cause an increased resistance to flow. Further, a larger surface area causes more water to become crystalline or structured close to each layer. Figure 4.21 shows diagrammatically the possible resultant structures of clay plates when various factors influencing dispersion are introduced. As an aid to understanding these factors, test results on actual fluids have been included. • It can be seen with sample B and C that better dispersion occurs if hydration time or

temperature is increased. At higher temperatures increased Brownian motion accelerates the dispersion process.

• Sample D indicates that mechanical agitation increases the dispersion of bentonite. This effect becomes very apparent when tertiary formations are drilled using high nozzle velocities. Particle size decreases while low-gravity solids (LGS) and dilution rates increase.

• The effect of pH is shown in sample E where the net negative charge at clay platelet edges has been increased. This relates to the electrophoretic mobility increase discussed previously.

• Samples G and H show how dispersion is inhibited by the cations sodium and calcium. In the case of the sodium solution, there is no attempt made by hydrated (larger) sodium to exchange with sodium between the unit layers in bentonite. In the case of calcium, the resultant properties are similar to the sodium properties, but at a much lower concentration. This is because divalent cations can associate with two charge deficiency sites – one on each of two unit layers. Divalent calcium is more readily exchanged with the sodium in bentonite and forms a stronger bond. Calcium is added purposely to some fluids to inhibit the dispersion of formation clays.

• Sample I shows the effect of encapsulating polymers on dispersion. The polymer, ferro-chrome lignosulfonate has been used in this example. The results indicate that the addition of lignosulfonates to the make-up water for pre-hydrated bentonite batches is a questionable practice unless it is added last. They also aid in dispelling the idea that lignosulfonates cause


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formation solids to disperse. In fact, the adsorption of lignosulfonate on clay surfaces reduces clay swelling and cleavage promoting hole stabilization and recovery of un-dispersed cuttings.6

Figure 4.21: Factors influencing bentonite dispersion


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4.5.2 Flocculation Usually a flocculated system is evidenced in resultant rheological properties. Initially the fluid becomes thicker. The funnel viscosity, yield point and gel-strengths increase. Gel strengths also become progressive. This happens because as the clays become more structured the resistance to flow increases. These structures or particle associations are often quite fragile and may temporarily break during periods of shear. Thus, as suspensions become flocculated, they usually become more shear thinning. It has been theorized that substantial increases to the yield point indicate edge-to-edge associations and that progressive gel strengths indicate edge-to-face associations. Increased structure also serves to degrade the fluid loss and cake characteristics of the fluid. This is because it is difficult for associated clay platelets to lay flat against a point of pressure differential. The electrostatic double layer surrounding bentonite particles in a suspension becomes compressed as the concentration of cations increases. At the point where attractive forces become dominant, particle associations, called flocs begin to form. The critical concentration of cations where this occurs is called the flocculation value. The flocculation value for a given suspension may be determined by increasing the cationic concentration in the suspension. Before flocculation the fluid appears cloudily. As flocculation begins, individual flocs become large enough to drop out of suspension. They may even be seen by the naked eye, as in the case of the floc-water fluid systems described in the chapter on Water-Based Fluids. These particle associations sediment, leaving a clear supernatant fluid. The actual volume of sediment depends upon how closely or loosely the particles are associated. It should be noted that if the clay concentration is high enough, the division of supernatant and sediment might only occur after centrifugation. Most drilling fluids are not subjected to such forces for more than a few seconds during solids separation. They normally remain homogeneous. Thus a flocculated drilling fluid is usually diagnosed through changes in its rheological properties. (See Figure 14.24.) In most drilling fluids, there is a sufficient quantity of soluble salts to provide some degree of flocculation or structure building. If the concentration of both clay and cation is strong enough, individual flocs will build a continuous gel structure. The flocculation of clay sheets may be described in three ways as illustrated in Figure 4.22. They include; edge-to-edge, edge-to-face and face-to-face associations. In a given suspension it is likely that all of these associations occur simultaneously. The net effect on the fluid's properties results from an average influence of these associations. It is assumed that the initial stages of flocculation involve mainly edge-to-edge and edge-to-face associations. Cation induced edge-to-edge associations may be more common at higher pH, where positive sites at clay edges have been satisfied by hydroxyls. The area of contact in face-to-face associations is vastly greater than the others. Therefore it takes more time and higher concentrations of cations to form them. However, they are much more stable (difficult to re-disperse). Face-to-face flocculation may be correctly defined as aggregation (see Figure 4.23). Aggregation is discussed in section 4.4.5.


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Figure 4.22: Flocculated particle associations

Particle associations may also form when excessive heat is applied to a clay suspension. In this case flocculation occurs when the Brownian motion induced movement of the clay particles increases such that their normal repulsive forces are overcome. The particles become stuck together. This phenomenon is termed thermal flocculation (see Figure 4.23).


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Figure 4.23: Dispersion, flocculation and aggregation with various salts

The pH of the suspension may also influence particle associations. In a very low pH environment, hydrogen bonding between clay platelets may initiate aggregation. High pH environments may result in severe flocculation. This may be caused by an OH- bridge occurring between positively charged edges of clay plates, or edge-to-edge flocculation. This phenomenon is very apparent when drilled solids concentrations (especially illite) are high and particle size is low. It may become almost impossible to mix a sack of caustic into the active system. Figure 4.24 shows some of the factors which can contribute to flocculation in clay systems. A basic understanding of flocculation mechanisms can be extremely useful. Particle associations may be seen as a benefit in terms of the contribution which increase particle size makes to settling velocity. In fact, various polymers called selective flocculants may be used to increase the settling rates of different types of clays. This technique applies to drilling or sump fluids being cleaned or centrifuged and to clear water drilling fluids. The cleaning characteristics of some fluids may be enhanced by flocculation. This is usually done to clean large debris from the hole.


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Figure 4.24: Flocculation theories


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4.5.3 Aggregation The term aggregation as it applies to clays in drilling fluids may refer to the un-hydrated groups of clay stacks as they occur naturally. More often the term refers to the particle associations resulting from the reduction in size of the diffuse layer surrounding the clay platelets. This usually occurs in a strong cationic environment. Cations approach and associate with exchange sites on the basal surface of hydrated unit layers. The associated cations attract the basil surface of another clay platelet such that clay platelets begin to form stacks or aggregates similar to their original un-hydrated aggregates. This structure does not necessarily form instantaneously. It usually starts as flocculation. As the environment becomes more cationic with either concentration or valency, face-to-face associations increase. Thus aggregation may be thought of as extreme flocculation and a net decrease in the number of suspended particles. This is opposed to dispersion where there is a net increase in the number of particles. Figure 4.24-G shows how the properties of a base fluid are affected by the introduction of aluminum. Figure 4.23 plots gel-strengths, indicating where aggregation begins. Aggregated clays exhibit poor suspension and viscosity characteristics. This is because fewer particles and less surface area provide less resistance to flow. Figure 4.25: Flocculated aggregates

Unlike flocculated suspensions, the effects of aggregation are difficult to reverse. In practice, this is seen after treating the effects of a contaminating polyvalent cation. Free cations may be precipitated in the normal manner, and loose particle associations may be deflocculated with an appropriate thinner. However, high gel-strengths usually remain for sometime afterward. Thus, it is important to treat either the cause (precipitate) or the effects (deflocculate) of contaminating cations before aggregation occurs. Because total dispersion seldom occurs, clay aggregates usually exists in suspensions. They also exist due to the face-to-face particle associations induced by polyvalent cations. In either case these aggregates may form flocs themselves. The associations may be either edge-to-edge or edge-to-face (see Figure 4.25). Thus, a flocculated / aggregated suspension can exist. 4.5.4 Deflocculation The term deflocculation refers to the process whereby particle associations or flocs are reversed. Structure is broken and resistance to flow is decreased. This usually begins as the environment of the suspension becomes more anionic in nature. Specifically, flocculation may be prevented or reversed by the addition of certain complex anions, notably polyphosphates, tannins and lignosulfonates.7 These compounds are referred to as thinners.


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It is believed that thinners are adsorbed at the edges of clay plates. The mechanism may be either chemisorption or anion exchange at the crystal edge with the large multivalent anions of the thinner. Raising the pH also neutralizes some of the positive charges on the clay edges. Thus, maintenance of alkaline pH conditions will help to stabilize clay-based drilling fluid systems. Figure 4.26: Effect of thinners

Figure 4.21-I demonstrated that lignosulfonate exhibited the ability to impede dispersion. The same mechanism applies to other long-chain anionic molecules, some of which are used primarily as thinners. Many types of thinner are acidic in nature. Sodium hydroxide is added to clay suspensions with these thinners to help to solubilize them and to maintain the pH in the suspension. If sodium exchanges with the native cations in the clay cuttings, increased dispersion of the cuttings may occur as a result. Thus, in this case, deflocculation and dispersion may occur simultaneously. It is important that drilling fluid engineers are aware of this effect so that excess amounts of thinner are not added. The dispersive effect of the thinners may be offset by the presence of preferentially adsorbed cations including potassium. Table 4.5 shows that precipitation can be an effective means of deflocculation. This practice is used in the field and is often complimented with the addition of thinners. Often fluid systems are pre-treated with chemicals which will precipitate expected contaminants. In this way the flocculation / deflocculation process may be avoided altogether. Conversely, if an evaporate interval is extensive, the expected contaminant may be added to saturation levels purposely, to avoid hole erosion. In this case, thinners must also be added simultaneously.


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Table 4.5: Deflocculation with Lignite and Na2CO3

Parameter Sample 1 Sample 2 Sample 3 Sample 4 Base: 40 kg/m3

bentonite Base +

4 kg/m3 CaSO4 Sample 2 +

4 kg/m3 Lignite Sample 2 +

4 kg/m3 Na2CO3 600 42 58 48 51 300 33 49 43 42 Gel 0/10” 3/5 21/18 6/12 8/14 pH 9.0 7.9 7.4 8.5

4.5.5 Viscosity in Water-Based Systems The processes of hydration and dispersion increase the number of clay sheets in a suspension. As they begin to interfere with each other, hinder each others movement, and align themselves, viscosity is imparted to the suspension. Clay minerals impart viscosity to water-based systems because of properties related to their colloidal size and their surface charges. Viscosity is the result of clay-clay interactions and interactions between clay and the water phase, solids or polymers. These interactions are created by weak chemical bonds which can usually be broken by a shearing force. The types of interactions between clay particles have been described as flocculation and deflocculation respectively. A careful balance between the state of flocculation and deflocculation imparts the optimum flow properties to the suspension. The surfaces of clays contain hydroxyl or oxygen groups which form hydrogen bonds with water molecules. Water also bonds with sites on the crystal edges. This results in a zone of structured or crystalline water closely associated with the clay. Thus, the introduction of clays into water reduces the volume of free water – also building structure and resistance to flow. Reactions between clays and polymers depend on several factors. The strength and the site of adsorption depend on the chemical character of the polymer. Generally, negatively charged polymers adsorb on positive edge sites. Most drilling fluid polymers are of this type. The chapter on polymers explains how factors such as salinity, molecular weight, pH and charge density affect clay-polymer interactions. 4.5.6 Viscosity in Oil-based Systems Clays are also used to viscofy oil-based fluids. Organophillic clays do not occur naturally; therefore they were not previously discussed. A brief description of their nature will proceed the discussion of their behavior. Smectites have the ability to adsorb certain organic molecules on their surfaces. Reacted organophilic clays are based in this property. They are made organophillic by replacing exchangeable cations with an organic molecule – typically a quaternary ammonium salt:

Na+Clay- + R4N+Cl- R4N+Clay- + NaCl The most commonly used clay is montmorillonite (bentonite).


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Hectorite is used when superior temperature stability properties are required. Hectorite, a smectite has no aluminum, its structural charge results from the substitution of lithium for magnesium. The most common type of cation is dimethyl dihydrogenated tallow amine (DM2HT):

NCH3

CH3

DM2HT

DM2HT

Cl

The structure of the resultant clay plate is shown in Figure 4.27. The clay platelet coated with the organic molecule is now able to disperse in a suitable organic medium. Figure 4.27: Treatment of Na-montmorillonite with ammonium salt

MeNMe

Me

Me

MeNMe

Me

Me

MeNMe

Me

Me

A Na Montmorillonite surface

Many theories have been advanced to explain how organophilic clays function; the most widely accepted being the formation of hydrogen bonds between solvated clay platelets. The size of the cationic molecule reacted onto the clay surface determines the spacing of the structure. Weak Van der Waals forces between alkyl chains may account for some of the structure of organically treated clay, but the predominant bonding forces are due to hydrogen bonding at the exposed oxygen and hydroxyl groups on the clay platelet edges. A polar molecule such as glycol, or alcohol can be added to induce hydrogen bonding, but in most normal oil-based drilling fluids, sufficient water is present to activate the clays and induce a structural development. When low concentrations of bentonite-based organoclay are used a two dimensional structure is formed. This is shown in Figure 4.28. The alkyl chains attached to the clay surface are fully solvated giving rise to evenly spaced beds of clay platelets, which bond to give the supporting structure, allowing weighting agents and cuttings to be held in suspension.


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Figure 4.28: Low concentration of fully solvated organoclay with H-bonding between platelets

OH H

O

HH

OH

HOH H

OH H

OH H

OHH

OHH O

HH

O

HH

O

H

H

OH

H

OHH

OH

H

OH

HO

H H

Figure 4.29: High concentration of fully solvated organoclay with tighter H-bonding between platelets

OH H

O

HH

OH

H

OH H

OHH

O

HH

OH

H

OH

H

As the concentration of organoclay is increased the inter-platelet spacing is gradually decreased until it reaches a distance determined by the alkyl chains. This is shown in Figure 4.29. This gives rise to a three dimensional structure that imparts changes in rheological properties leading to higher viscosities and gel strengths.


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Since the rheological properties imparted by organophilic clay are both pseudo-plastic and thixotropic in nature (refer to the Rheology chapter) an increase in clay concentration does not show as fast as a rise in plastic viscosity as it does in yield point. The reason for this is that the greater bonding forces have more effect on rheology than simply increasing the solids concentration would have. 4.5.7 Gelation Gelation in water based fluids may occur at salt concentrations below the flocculation point if clay concentrations are high enough. When diffuse layers interfere with each other, clay platelets align themselves to a position of minimum free energy. Several theories exist, regarding the possible particle associations which contribute to gelation. These theories encompass the entire particle associations previously discussed. The important considerations which lead to effective drilling fluids management are the trends in the values obtained from measuring the strength of gel structures. For example, the presence of contaminating ions may be detected through increased gel strengths before they are seen in filtrate titrations. Some contaminants may never been seen in filtrate titrations. High gel strength measurements made at elevated temperatures are usually the first indication that the mean average particle size in the suspension is degrading. Progressive gel strengths indicate that some type of flocculation has occurred. (Progressive means, the strength of the gel structure is much greater after 10 minutes in a static state than after only 10 seconds at rest). In a highly shear-thinning / thixotropic fluid, extremely progressive gel strengths may impede the fluid’s ability to clean by the Bottom Hole Assembly. Sufficient cleaning structure may not be re-established until further up the annulus. In drilling fluids, the maximum extent of gelation should be established quickly and should not be excessive. Prior to the cessation of circulation for long periods such as logging, a better indication of fluid’s gelation characteristics can be made. This involves measuring the gel strength at bottom hole temperatures over a more realistic period of time. 4.6 FORMATION CLAYS 4.6.1 Diagenesis The term diagenesis refers to the process whereby sediments are converted to more competent rock through combined physical and chemical influences, over time. The chemical influences on sedimentary deposits may include solution / dissolution, leaching and changes in pH conditions caused by bacterial action or the release of acidic gasses. The physical influences include pressure and temperature. Generally montmorillonite is associated with the youngest sediments. It is formed under basic conditions, often in association with volcanic ash and seawater. As young sediments are compacted, water is squeezed out of the unit layers and released as free water. Generally the structure of clay changes from the smectite type to the non expanding types. The result depends on the environment in which compacting occurs. Acidic environments and fresh water conditions favor the formation of kaolinite. Kaolinite may also be formed by leaching of feldspars and is often encountered in sandstone reservoirs. Montmorillonite may be transformed into illite and then to mica as dehydration continues.


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If compacting occurs in a saline or marine environment, chlorite may be formed through magnesium fixation by montmorillonite. Chlorite clays may be precipitated in sandstone reservoirs and form the cementing mineral. When mixed layer clays are found, it is an indication that diagenesis is in progress. Various investigators have reproduced the diagenetic process in laboratories, using different reagents – usually under normal temperatures and pressures. Illite, chlorite and kaolinite have been produced from smectites.8 4.6.2 Sediments Some borehole stability problems may be attributed to the reaction of formation clays to the drilling fluid. Essentially, the exposure of stressed sediment to the drilling fluid may re-hydrate the clays. When this causes increased stress, erosion or plastic deformation may occur. Sedimentary formations are characterized by the type and concentration of mineral present and by the pressure regime involved during consolidation. The amount of in situ water is dependant upon the latter. Table 4.6 lists a classification of sediments. The chapter on Borehole Stability contains a more in-depth review of sediments. Table 4.6: Typical Classifications of Sediments TYPE Water content (%

w) Clay content

MBT (meq/100g)

Density (g/cm3)

CLAY 25-70 SOFT Montmorillonite

Illite 20-40 1.2-1.5

MUDSTONE 15-25 firm

Montmorillonite Illite

Mix layer

10-20 1.5-2.2

SHALE 5-15 hard Treated montmoril.

High illite 3-10 2.2-2.5

SLATE 2.5 brittle Illite

Kaolin 1-5 2.5-2.7

LIMESTONE 100-80% calcium

carbonate 0 2.5-2.8

MARL 70-40% calcium

carbonate + 30-60% clays

0-2 1.8-2.2

CALCAREOUS MUDSTONE

15-60 firm

10-40% calcium carbonate +

90-60% clays 0-5 1.3-1.8

Clays are found in production sands in small but significant quantities. The clays deposited with the sand are termed detrital. With the passage of time, clays and associated minerals undergo diagenesis and new clay crystals may be formed. They form on the surface of the sand, occupying an important position as a potentially water wet material lining the pore throats. The clay minerals described in this chapter all commonly occur in sandstone reservoirs. They respond to the same changes in the chemical environment that have been described for drilling fluids. Drill in, Completion and Production fluids may be designed to minimize the tendencies of certain clays to cause pore throat blockage by swelling or migrating. This subject is discussed in greater detail in the chapter on Production Zone Drilling, Completion and Workover Fluids.


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4.6.3 Clay Analysis Various types of clay analysis are performed by companies involved with drilling fluids. Tests are conducted on commercial clays to ensure they will perform in field applications. Often, tests are conducted on formation clays to discern the best methods of insuring formation stability while drilling. Understanding the mechanisms behind clay swelling and dispersion has led to the development of several types of inhibitive, water-based drilling fluid systems. These systems use one, or a combination of three possible means of reducing clay swelling. These include: • Increasing the attractive forces or cationic environment to reduce electro-static repulsion

(bentonite won't hydrate in calcium solutions); • Controlled cation exchange as in potassium salt fluids; • The use of various types of encapsulating polymers. Formation clays may be collected for sampling during the course of drilling a well. The most representative samples are obtained from clay which is scraped from the Bottom Hole Assembly on a bit trip. If this sample is dry inside, interference to the test results caused by drilling fluid induced cation exchange may be minimized. Also, commercial bentonite concentrations won't have to be factored out of the results. Several methods are available which evaluate the type and concentration of clay minerals present in a hydrating and / or swelling formation. The first step in solving clay related problems is usually to perform an X-ray diffraction analysis. This technique indicates the presence and concentration of all minerals in the bulk sample, including quartz, dolomite, etc. The clay fraction itself is also categorized, indicating the percentages of all clay minerals including mixed layer clays. Knowing the types and percentages of clays present, leads to further tests, involving specific inhibiting fluids. These include: • Shale inhibition tests; • Capillary-suction timer tests; • Dispersion tests. These results lead to the application of the most efficient inhibition mechanisms for a given formation. The optimum concentrations of inhibiting chemicals may also be determined from these tests.


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References 1 H.C.H. Darly & George R. Gray, Composition and Properties of Drilling and Completion

Fluids, 5th ed. (Houston: Gulf Publishing Company, 1988), 146. 2 Darley and Gray, Composition and Properties, 146. 3 Preston L. Moore, Drilling Practices Manual (Tulsa: The Petroleum Publishing

Company, 1974), 80. 4 Darley & Gray, Composition and Properties, 150. 5 van Olphen, H. , An Introduction to Clay Colloid Chemistry, 2nd ed. (New York: John

Wiley & Sons, 1977), 12. 6 Browning, W. C. & Perricone, A. C. Lignosulfonate Drilling mud conditioning agents,

SPE Paper 432, Annual meeting, Oct. 7 - 10, 1962. 7 Darley & Grey, Composition and Properties, 167. 8 Ralph E. Grim, Clay Mineralogy, 2nd ed. (New York: McGraw-Hill Book Company,

1968), 488.


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CHAPTER 5 POLYMER CHEMISTRY 5.1 KEY POINTS AND SUMMARY 5.2 INTRODUCTION TO POLYMER CHEMISTRY AND TERMINOLOGY 5.2.1 Building Units 5.2.2 Some Characteristics of Drilling fluid Polymers 5.2.3 Charges on Polymer Molecules 5.2.4 Categorizing Drilling fluid Polymers 5.2.5 Polymer Modification 5.3 POLYMER STABILITY 5.3.1 Wellbore Temperatures 5.3.2 Chemical Stability 5.3.3 Electrolytic Effects 5.3.4 Biological Stability 5.3.5 Shear Stability 5.3.6 Lab Measurements 5.3.7 Operational Aspects 5.4 FUNCTIONS OF POLYMERS IN DRILLING FLUIDS 5.4.1 Viscosity 5.4.2 Fluid Loss Control 5.4.3 Shale Stabilization 5.4.4 Flocculation and Extension 5.4.5 Deflocculants 5.4.6 Surfactants 5.5 POLYMER DESCRIPTIONS 5.5.1 Starch and Modified Starch 5.5.2 CMC and PAC 5.5.3 HEC 5.5.4 GUAR Gum 5.5.5 Xanthan Gum 5.5.6 Scleroglucan 5.5.7 Lignosulfonate 5.5.8 Polyacrylamide 5.5.9 Polyacrylates 5.5.10 Polyalkylene glycols 5.5.11 Descriptions of other Polymers


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5.1 KEY POINTS & SUMMARY Since starch was first used in Drilling fluids over 50 years ago, the development and application of various polymers has become an accepted norm in Drilling fluids engineering. Polymers enhance many functions of Drilling fluids from lubrication to viscosity, in fact, polymers are able to enhance or perform almost all of the functions of Drilling fluids as outlined in chapter 1. Factors affecting the performance of polymers include: shear conditions, time, temperature, salinity, alkalinity and the presence of microorganisms. When polymers are used during drill-in or completion operations, the possibility of formation pore plugging and the polymers’ solubility in acid must be considered. The diversity in both the composition and properties of drilling fluid polymers makes a critical examination of the factors involved in polymer selection imperative. This chapter begins with a brief look at polymer chemistry. Functions of polymers and their relationship to the environment of the solution are discussed next. Finally, descriptions of some of the most common drilling fluid polymers are given. This chapter should be considered as an introduction to drilling fluid polymers. 5.2 INTRODUCTION TO POLYMER CHEMISTRY AND TERMINOLOGY 5.2.1 Building units The term polymer refers to large or macromolecules which are built up from small, simple chemical units called repeating units or monomers. A single polymer may contain thousands of monomers. Figure 5.1 depicts a single cellulose monomer. Figure 5.1: Cellulose monomer

OH

OHO

O

O

OH

O

OH

OOH

HO

Monomeric unit In the 19th century the term colloid was proposed to distinguish polymers from materials which exist in crystalline form. Today a colloid is often defined as a substance which consists of particles too small for resolution with an ordinary light microscope, diffracts a beam of light, and in suspension fails to settle out. Most drilling fluid polymers are termed organic colloids.


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Polymers may be found in nature and in fact, some have been used for thousands of years. These include natural resins, gums, asphalt and amber. The term polymerization refers to the natural formation of, or the synthesis of polymers. It may be considered as the process whereby monomers are joined together to form polymers. The longer the reaction takes place the longer the polymer. Figure 5.2:

OHO

Acrylic acid

Ph3C

OHO

H

OHO

OHO

HPh3C

OHO

HPh3C +

OHO

+ ETC!!!

O OH OHO OHO

n

n-polyacrylic acid The sale of monomeric compounds is a base industry. Polymer manufacturers purchase various types of monomers and synthesize polymers by proprietary methods (fig 5.2). Variables to the polymerization environment include pH, temperature, time and the medium in which the process occurs. Polymerization can occur in the water phase of an oil emulsion or in liquid CO2. 5.2.2 Some characteristics of Drilling fluid’s polymers Many types of polymers are used in the Drilling fluids industry today. (Polymer functions are discussed in Section 5.3). The ways in which polymers behave and alter the properties of a solution depend on several variables in the polymer's molecular structure. These are incorporated into the composition of individual polymers. Often, only small variances in a polymer's structure can drastically change its affect in a solution. Variables, which affect polymer characteristics, include: 1. The number of monomers linked to form a polymer chain. 2. The number of different types of monomers present in a polymer molecule and the order in

which they occur. 3. The shape and structure of the molecule. 4. Electrolytic variables including the net charge, and the position and density of the charge. 5. The chemical and structural modification of a polymer, subsequent to polymerization.


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Figure 5.3 indicates how polymers may be classified according to the variables mentioned above. Figure 5.3: Classification of polymers

Low MW A Linear

Hi MW

B

HomoPolymers

Non-Linear Branched

C

Alternate

D

Block

E Linear

Random

F Co-Polymers

Non-Linear Crosslinked

G

The number of monomers in the chain specifies the length of the polymer chain. This number is usually referred to as the degree of polymerization or DP. The molecular weight of a molecule refers to its mass. It is the sum of the atomic weights of its constituent atoms. The molecular weight of a polymer molecule is not "the chain length" as is sometimes claimed. Rather, it is the product of the mass of its monomers and its degree of polymerization. In a given polymer, the terms molecular weight, degree of polymerization, and chain length are usually interdependent. That is, when the numerical value of one increases, the value of the others also increases. This is the reason why the terms are sometimes used interchangeably. When polymers are being synthesized, the ultimate degree of polymerization may be controlled by either the solubility of the polymer chains or by controlling the number of "terminating monomers" (fig 5.4). In free radical polymerization this may be accomplished when two free radicals react to annihilate each other.1


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Figure 5.4:

Ph3C + Ph3C Ph3CCPh3

Chain termination The molecular weight of an individual polymer is extremely important. Identical polymer structures may act either as a clay flocculant or deflocculant in a drilling fluid, depending on the polymer's molecular weight. Molecular weights of drilling fluid polymers typically vary from thousands to millions. Figure 5.3A and 5.3B indicate two polymers with similar constituent monomers but dissimilar molecular weights. For an application such as selective flocculation where a polymer's effectiveness is critically dependant on its molecular weight, its molecular weight distribution curve becomes another important factor. In the case of the wide distribution curve, it is possible and probable that molecules on the extreme right or left side of the curve will interfere with, and reduce the effectiveness of the polymer. This is where quality control plays an important function in manufacturing drilling fluid polymers. When two types of monomers are present, the molecule may be defined as a co-polymer. Figures 5.3D – 5.3G show some of the possible structures of co-polymers. Unfortunately, the 3-dimensional aspects of these cannot be depicted on paper. Polymers with 3 different types of monomers are termed terpolymers. Polymer shape may be categorized broadly into 3 groups: linear, branched and cross-linked. A cross-link defines a covalent bond joining two polymer molecules at a point along at least one of the chains, (as opposed to at the end of the chain). Cross-linking may be induced by the introduction of a cross-linking agent as depicted in Figure 5.3G. Polymers in drilling fluid solutions are often cross-linked by a free cation. Cross-linking may radically alter the properties of both the polymer and the resultant solution. This is caused either by the increase in molecular weight and / or a reduction in the solubility of the molecule after cross-linking. The shape of a solvated polymer molecule is important because it affects the way the polymer reacts to other (especially insoluble) components of the solution. The ultimate shape of a polymer molecule is dependant on several factors. 5.2.3 Charges on Polymer Molecules Drilling fluid polymers may carry electrostatic charges. When they do, they are termed polyelectrolytes. An electrolyte is a substance that, when dissolved in a suitable solvent, becomes an ionic conductor. The behavior of solvated polymers is dependant on their ionic character. Drilling fluid polymers may be categorized as: 1. Nonionic 2. Anionic 3. Cationic Drilling fluid polymers are usually anionic or nonionic since cationic polymers tend to flocculate clays. Chemical reactivity can be built into a polymer either by the polymerization of monomers of different chemical character or by chemically modifying an existing polymer.


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Table 5.1 lists the common nonionic chemical groups typical of drilling fluid polymers. An important function of these is that they all readily form hydrogen bonds with water. This contributes to the polymer molecule's ability to hydrate and ultimately to solvate. Because nonionic polymers have no dissociable inorganic radical, they have greater stability in highly saline environments.2 Starch, Guar Gum, and Hydroxyethyl Cellulose (HEC) are all nonionic polymers. Table 5.1: Non-Ionic Chemical Groups that Contribute to Reactivity of Polymers

Chemical Formula Name R OH Alcohol

OR Me

Ether

R NH2

O

Amide

NO

R

Pyrrolidone

R N C O Isocyanates R – X Alkyl halides

R Alkenes

The Clay Chemistry Chapter (4) explained that, as the concentration of available anions increased in a fluid suspension, the strength of the associations of clay particles became less prevalent. Generally, low molecular weight, anionic polymers impart less viscosity to a fluid and are therefore desirable in systems containing solids. By controlling certain parameters such as the degree of polymerization, anionic polymers can be made to contribute to a desired degree of viscosity. Figure 5.20 shows anionic polymer acting as a deflocculant, while Figure 5.19 shows the same polymer, but with a higher molecular weight performing as a bridging agent or flocculant. CMC (carboxymethyl cellulose), PAC (polyanionic cellulose) and PHPA (partially hydrolyzed polyacrylamide) are common examples of anionic polymers. Typical anionic groups are given in Table 5.2. The most common group is the carboxylate group found in CMC and Polyacrylates. The sulfonate group is common in calcium tolerant polymers.


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Table 5.2: Anionic Chemical Groups that Contribute to Reactivity of Polymers

Chemical Formula Name

RO P

O

O-

O-2M+

Phosphate

R P

O

O-

O-2M+

Phosphonate

R O-M+

O

Carboxylate

R S

O

O

O-M+

Sulfonate

RO S

O

O

O-M+

Sulfates

R N

O

H

S

O

O-M+

O

Amido-sulfonates

When inorganic anions became dissociated from a polymer chain, the polymer becomes cationic or positively charged. Cationic polymers are not commonly used in Drilling fluids because of their flocculation effect on clays. They serve mainly as emulsifiers and wetting or surface-active agents. Table 5.3 lists some cationic chemical groups, which contribute to drilling fluid polymer reactivity. Table 5.3: Cationic Chemical Groups that Contribute To Reactivity of the Polymer

Chemical Formula Name

R NH3+Cl- Ammonium Salts

R N+(CH3)3Cl- Quaternary Ammonium Salts The charges or functional groups on polymer chains can cause variances in the shape of the molecule in solution, depending on the environment of the solution. If the functional groups on a polymer molecule are similar, their natural repulsion in solution causes the molecule to stretch out. This tendency may be either limited or enhanced, depending on the nature of the environment. The effectiveness of a polymer molecule in solution is extremely dependant on its shape. This is especially applicable to branch-type viscofying and filtration control polymers.


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5.2.4 Categorizing Drilling fluid Polymers Drilling fluid polymers are often classified after their origin, as follows: 1. Natural polymers 2. Modified natural polymers (sometimes called semi-synthetic) 3. Synthetic polymers. Natural polymers originate in nature as plant constituents or exudates. The monomers of natural drilling fluid polymers are carbohydrate-type (sugar like) molecules (fig 5.5). The monomer for either cellulose or starch is glucose. Figure 5.5:

O

OH OH

OHOH

HO

Glucose How can the same monomer give two different polymers? Polymers that are very different from each other, for one you can eat starch but not cellulose (fig 5.6).


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Figure 5.6:

Every second glucose is turned backwards and linked to the polymer. Most natural polymers are variations on this theme. When a natural polymer is altered by chemical means, it is called a modified or semi-synthetic polymer. Natural polymers are modified to enhance certain characteristics of the polymer. These might include: water solubility, salt tolerance, tolerance to multivalent cations and resistance to bacterial degradation. CMC, modified starch, HEC, CMHEC are all examples of modified polymers (figure 5.7).


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Figure 5.7:

Synthetic polymers are usually manufactured by using chain-reaction polymerization, starting with fairly simple monomers. These bonds are difficult to break, making synthetic polymers less susceptible to various types of degradation than natural polymers. The reason for this is the non-natural manufacture of synthetic polymers, which inhibits enzymatic degradation. In most instances this is beneficial unless degradation characteristics are required, as in the case of well stimulation with acid. The selection of monomeric types becomes more diverse as the specific applications for synthetic polymers increase. 5.2.5 Polymer Modification The length, shape, charge and type of functional group may be altered on a polymer molecule subsequent to polymerization. This is done to enhance the effectiveness of the molecule with respect to a drilling fluid property or function. These might include solubility, resistance to harsh environments and specialized functions such as encapsulation. Although the process is usually complicated, ultimately the cost-effectiveness of the product is improved. One such process, defined by the term degree of substitution (DS) is performed on the cellulose group of polymers. The cellulose monomer depicted (previously) in Figure 5.1 is by itself, insoluble in water. It is made soluble by reacting one or more of its functional groups (an OH group) with chloroacetic acid in the presence of a base. CH2COO-Na+ is substituted for H+.


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Figure 5.8:

OH

OHO

O

O

O

O

OH

OOH

O

O

Na+-O

O-Na+O

Substituted Monomeric unit

The expression CH2COO- is a form of CH2COOH, which is referred to as a carboxyl group, a monovalent anion, typical of organic acids. After the reaction, the molecule is referred to as carboxymethyl cellulose (CMC). The carboxyl group imparts solubility to the cellulose monomer (fig 5.8). Further, in solution the sodium ion disassociates easily, leaving negative sites along the chain. The mutual repulsion of these sites helps the chain to stretch out, increasing the viscosity of the solution. Originally there were three OH groups on the cellulose unit, each capable of substitution. In the case of CMC, the term degree of substitution refers to the average number of carboxyl groups on the chain per unit cell or monomer. Hydrolysis is a term used to describe the reaction of water (hydro) on a type of functional group to give two or more new compounds (fig 5.9). Figure 5.9:

R NH2

O

H2OR OH

O

+ NH3

amide carboxylic acid It typically means the replacement of a functional group in this case NH2 with OH. As a Drilling fluid term it usually refers to a process whereby the polyacrylamide (copolymer) molecule is restructured to perform certain functions more effectively. A 30% hydrolyzed polyacrylamide performs very efficiently as a shale encapsulator (fig 5.10).


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Figure 5.10: Polyacrylamide

O NH2 NH2O NH2O

n

Figure 5.11: Partially Hydrolyzed (with OH) Polyacrylamide (PHPA)

O NH2 OHO NH2O

n Different degrees of hydrolysis promote increased efficiency of the polymer with respect to other functions. These can include filtration control and clay flocculation. Partially hydrolyzed polyacrylamide is referred to as PHPA. Sulfonation is another process, which alters the structure of a polymer molecule. Phosphate and especially sulfate reduce a polymer's tendency to form complexes with multivalent cations such as calcium. Calcium tolerance can be increased when certain functional groups such as carboxylate are replaced with sulfate (see Table 5.2). The prefix "sulfonated" is added to the polymer name to indicate this process has occurred. Sulfonated styrene maleic anhydride is a good example. A classification of types and functions of drilling fluid polymers is given in Table 5.4.


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TABLE 5.4: Classifications of drilling fluid polymers

NAME FUNCTION MOLECULAR WEIGHT CHARGE / SHAPE

Natural Polymers

Starch (Corn, Potato Starch, …)

Fluid loss control in saline Environments 40 – 105 Anionic/Branched

Linear

Guar Gum Viscosity in fresh or saline solutions. Fluid Loss Control ≈ 2⋅105

Nonionic/Branched (May have some anionic groups)

Modified Polymers

Hydroxyethyl cellulose (HEC)

Viscosity especially in completion fluids Nonionic/Linear

Carboxymethyl cellulose (CMC HV – CMC HV)

Viscosity and fluid loss control at high MW (HV) Fluid loss control at low MW (LV)

Diverse

Anionic/Linear

Anionic/Linear

Polyanionic Cellulose (PAC RG – PAC SL)

Viscosity control at high MW (RG) Fluid loss control at low MW (SL)

Diverse Anionic/Linear

Anionic/Linear

Xanthan Gum (XC – XCD)

Viscofier in fresh or salt water – thixotropic properties 5⋅106 – 20⋅106 Anionic/Branched

Lignosulfonate Deflocculant and Fluid loss control 103 – 20⋅103 Anionic/Branched

Lignite Deflocculant and Fluid loss control 103 – 20⋅103 Anionic/Branched

Synthetic Polymers

Polyphosphates (SAPP) Deflocculant Anionic

Acrylic Polymers

Polyacrylmide (PHPA) Encapsulator and Clay Flocculant

> 3⋅106 Average

106 Anionic/Linear

Sodium Polyacrylate (PA)

Temperature stable Deflocculant Fluid Loss Reducer

7⋅103 – 10⋅106 Anionic/Linear

Sulfonated Styrene/Maleic Anhydrite (SSMA)

Hi Temp Deflocculant 1000 – 5000 Copolymer

Sulfonated Vinyl Copolymer (VAVS)

Hi Temp Fluid Loss Control Secondary Viscofier 1⋅106 – 2⋅106 Copolymer


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5.3 POLYMER STABILITY Polymers contain chemical bonds and functional groups, which may undergo reactions initiated by wellbore conditions. These include temperature, pressure, oxygen, pH, trace metals, free radicals and shear rates. This section examines the influence these conditions may have on the stability of polymers. The significance of laboratory tests compared to field experience is also discussed. The term polymer degradation refers to a type of cleavage in the polymer molecule or chain, usually at the weakest bond. The term de-polymerization is sometimes used to express this effect. Degradation does not refer to a reduction in product effectiveness caused by a structural collapse of the molecule. There are a number of processes, which contribute to polymer degradation. These may destroy the monomer, monomer bonds, the acetyl linkage or cause a chemical alteration in side chains or functional groups. 5.3.1 Wellbore Temperatures The temperature of the earth’s crust tends to increase with depth at a rate defined as the geothermal gradient, expressed in °C/Km (or °F/100 ft). The heat flow in the upper crust is derived from conducted heat from the lower crust and mantle, and radiogenic heat in the upper crust. These factors generate a range of geothermal gradients from 8 – 50 °C/Km depending on the location. Temperature influences the rate of chemical reactions, approximately doubling for every 10°C rise in temperature. Temperature gradients are discussed thoroughly in the chapter on High Temperature Drilling. Thermal degradation or decomposition is a factor which limits the use of most drilling fluid polymers. As the wellbore temperature increases, this degradation may be compensated for by the addition of fresh polymers. However, the rate of decomposition increases with temperature until eventually it becomes extreme. This can lead to undesirable conditions, especially if the degrading polymer is a viscofier, and Barite begins to settle. One should also be aware of the difference in the dynamic and static rates of degradation. Under static conditions, the fluid in the hole is subjected to much higher temperatures for longer time periods without having the benefit of supplementation with fresh polymers. Generally, organic polymers begin to degrade at a static temperature of 80 °C. There are differences in thermal stability within this group due to the influences of branching and substitution. The temperature limitations depend very much on the individual manufacturing process so it is wrong to class the temperature stability simply by polymer type. Sharp increases in the rates of degradation occur at 110 °C for most starch-based polymers and at 140 °C for most cellulose derivatives. Lignosulfonates are usually more stable, they begin to degrade at around 120 °C. Drilling fluid properties must be controlled with synthetic polymers in high temperature wells. The maintenance of fluid properties at elevated temperatures is most easily achieved when the system is deflocculated. If the expected static wellbore temperature exceeds the stability of organic deflocculants, then synthetic products must be used. Many hot wells are also over-pressured and most high temperature / high pressure drilling fluid systems are specifically tailored to individual wells. This usually requires extensive testing of


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products and systems to insure optimum product compatibility and system performance. The more highly substituted CMC’s, cross linked starch and Xanthan Gum all exhibit better tolerance to higher temperatures. 5.3.2 Chemical Stability Variations in the chemical environment can have a profound affect on the chemistry and structure of polymer molecules. Actual de-polymerization may occur. Degradation or change in the chemistry of the side chains may also occur. The pH, oxygen content, and the availability of metal ions are the most significant contributors to chemical degradation. Natural polymers are the most susceptible to chemical degradation because they usually have a glycosidic bond or an acetyl bond (see Figure 5.12). The glycosidic bond undergoes hydrolysis under alkaline and acid conditions with the minimum rates at pH values of 8.5 – 9.5. The bond can also undergo oxidative scission, which may be catalyzed by metal ions such as iron and nickel. The degradation may take place through a free radical reaction. The intentional degradation or de-polymerization of those natural polymers containing an acetyl bond is accomplished by the exposing them to hydrochloric acid. (An acetyl bond is a carbon atom bonded singly to two oxygen atoms and at least one hydrogen atom as depicted in Figure 5.12) Figure 5.12: Starch unit

O

OOH

OHOH

HO

O

OH OH

OH

HO

Acetyl link Higher degrees of substitution in Cellulose polymers reduce the rate of chemical degradation – probably by introducing a steric factor into the reaction, blocking the susceptible sites. Thus, the more highly substituted types of CMC, referred to as PAC are more resistant to chemical degradation. Xanthan Gum is more stable, possibly because of the side chains and helical structure. Unprocessed starch is very susceptible to chemical degradation but cross linking and substitution can raise the stability to that of Xanthan Gum. The relatively low degree of substitution of HEC makes this polymer one of the more susceptible to chemical degradation, especially in acidic environments. The carbon-carbon bond of the synthetic polymers is considerably more stable than the glycosidic bond of the natural polymers. However, at higher temperatures, the side chains of any polymer may undergo reactions such as hydrolysis (fig 5.13). An example is the hydrolysis of an amide group under alkaline conditions, to an acid salt with the evolution of ammonia.


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Figure 5.13: Hydrolysis of amide group

R NH2

O

NaOHR ONa

O

+ NH3

amide Sodium carboxylate Yang and Treiber3 did work on the chemical stability of polyacrylamides in water flood applications in 1985. Their results indicated that, although degradation was increased by metal ions, pH, and redox reactions, mainly the oxygen content of the fluid governs the rate and extent of degradation. Thermo-oxidative degradation of synthetic polymers may occur by the combination of oxygen with metals to create hydro-peroxides, these molecules break down easily affording oxygen radicals that can cleave bonds in polymers. When attempting to enhance the chemical stability of drilling fluid polymers, the pH of the fluid should be adjusted in the range 8.5-9.5 with moderate levels of caustic. Some systems use magnesium or potassium hydroxide as a buffer. Another approach is to minimize the oxidative and free radical reactions by adding in radical scavengers, such as phenolic (C6H5O

-) groups and oxidizable groups such as an aldehyde that are preferentially oxidized. Nitrogen compounds also neutralize free radicals and buffer the system. Inorganic compounds such as sulfur and sodium sulfite are also very good oxygen scavengers. Lignosulfonates and tannin extracts also provide the phenolic groupings. 5.3.3 Electrolytic Effects The relationships between the ionic character of a polymer molecule and the electrolytic environment were discussed briefly in Section 5.2.3. In solutions, polymers with similar ionic charges on their functional groups tend to elongate. This is due to the mutual repulsion of these charges. (See Figure 5.14a). The pH of the solution can affect the nature of the functional groups and thus, the ionic character of the molecule. When this effect changes the degree of repulsion or attraction within the molecule, its shape in the solution can change.


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Figure 5.14: Salting out effect (increase of salt concentration) on aqueous solutions of polymers

The addition of a salt to a solution (salting out) usually reduces the electrostatic repulsion of the functional groups along the polymer molecule. If this occurs, the polymer's structure collapses as shown in Figure 5.14b and c. Because the effective surface area of the polymer is reduced, there is less interaction between the polymer and the other components of the fluid. The most noticeable effect is usually a reduction in viscosity. The introduction of nonionic functional groups to a given molecule may enhance its effectiveness in saline environments. An example of this is the addition of ethylene oxide to CMC to form CMHEC. Polymer molecules in solutions may also be affected by the presence of multivalent ions. Free calcium ions can collapse the structure of a polymer molecule, netting a similar affect that salts cause. Calcium and other multivalent cations can also effectively crosslink or bridge polymers, resulting in decreased viscosity, solubility, and eventual precipitation (see Figure 5.15). The adverse effect of calcium on Xanthan Gum is increased at higher pH values. This is probably due to the precipitation of polymer-metal hydroxide complexes. All of the viscosity characteristics of


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an Xanthan Polymer system can be destroyed permanently if cement contamination is severe. The effect of drilling anhydrite on PHPA is to cause a sharp reduction of sediment in the standard floc test. If Polyacrylate or Polyacrylamide contain high degrees if carboxylate groups, the partial hydrolysis of functional groups can be accelerated by the presence of multivalent cations. Figure 5.15: Effect of multivalent ions (Ca+2)

Ca++

O-O

O

O-

O-O

O

O-

O-O

O

O-

O-O O

O-Ca

O

OO

O

Ca O

OO

O

Calcium bridges

5.3.4 Biological Stability All living organisms produce a variety of proteins needed to carry out functions that let them survive and grow. Enzymes are a specialized form of a protein that allows reactions to occur easier then normal, pretty much like a catalyst. An enzyme is a complex protein made from 20 different types of amino acids. One of the main sources of energy for all living organisms is carbohydrates, like starch, which is made up of glucose molecules. Enzymes are used to break down carbohydrate polymers so that the glucose units can be used for energy. Bacteria are microscopic organisms present in almost any type of media or surface. They are present on your hands, your car and in water. Natural polymers in water based mud systems can be susceptible to bacterial degradation. When you provide an energy source for the bacteria they can grow very rapidly and if left unchecked, could completely “eat” the entire natural polymer in your mud.


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Natural polymers are susceptible to biological degradation because of the enzymes bacteria use to degrade the polymer. Starch is most susceptible as it is a "storage" carbohydrate. Chemical treatment and cross-linking of the chains in starch increases its resistance to biological degradation. When starch is used in salt saturated systems, degradation is reduced substantially. Other polymers, which support biological growth, include Xanthan Gum and Guar Gum. The substitution of some of the functional groups on cellulose polymers makes them much more resistant. Elevated temperatures and salinity may increase bacterial growth, while high pH conditions inhibit it. However, the enzymes themselves, if they are present, are not possible to eliminate. It is important to recognize in advance, when a fluid environment might promote the bacterial degradation of a polymer proposed for use. Bacterial degradation, with a complete loss of fluid loss properties throughout the entire system can and has occurred in a matter of a few hours. If Sulfate-Reducing Bacteria (SRB) are present, a by-product, H2S may be released at surface in lethal concentrations. Synthetic polymers are not usually susceptible to bacterial degradation because enzymes are not used to make the polymers. In some cases killing the bacteria with a bactericide does not remove your problem. The enzymes contained within the bacteria are still breaking down the polymers in the mud. Denaturing the enzymes will eliminate the problem from the mud system. 5.3.5 Shear Stability If the concentration of a given polymer is high enough, the interaction between adjacent molecules may increase their effective molecular weight. The breakdown of these "aggregates" may lead to a partial loss of some properties, especially viscosity. A decrease in the degree of these molecular associations is sometimes referred to as the aging effect. This is known to occur in static solutions. It is thought to be caused when aggregates disentangle due to segmental motion of chains or Brownian movement of the fluid. Increased agitation or shear can accelerate this effect. Although the results are not as noticeable as other types of degradation and can be remedied with fresh additions of polymer, Drilling fluid Engineers should be aware that they exist. Some applications for PHPA polymers require that they be added through a chemical barrel. Studies have shown that when electric agitators are used, the shear rates generated can be excessive enough to irreversibly break polymer chains. This can effectively reduce the polymer's ability to function as an encapsulator. 5.3.6 Lab Measurements Lab testing does not always provide an accurate prediction of polymer performance under field conditions. The temperature regime generated by a hot rolling oven may give longer exposure time to higher temperatures if the oven is set at the bottom hole temperature. This is due to the rapid temperature equilibration of the metal containers. The entrained oxygen levels in lab fluids can be higher than those of a real fluid system since the mixing procedure promotes oxygen saturation. Tests have shown that scavenging the oxygen by such processes as nitrogen purging and application of a vacuum increases polymer temperature stability in the laboratory. The stainless steel used in high temperature aged cells can catalyze


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oxidative degradation. These ions might not be present at such high concentrations in a real fluid system. The most important factor is that the laboratory tests generally use pressures in the range 500 – 2000 psi rather than the very high pressures that are present in the actual circulating system. This is important because a de-polymerization reaction tends to increase the volume occupied by the molecule. Since elevated pressures reduce the rate of a reaction and volume increase, de-polymerization can be substantially lower in a real situation. This phenomenon was well illustrated where PAC was successfully used in a well with a BHT of over 200 °C. Samples from the well were tested with the conventional equipment and the fluid deteriorated significantly. When it was aged at the appropriate pressure as well as temperature, it tested as found in field practice. Care must be taken when laboratory results are used to select systems for field use. Ideally the test should be conducted at the same temperature regime and pressure conditions, as those expected in the field. The laboratory measurements, which are normally carried out, measure changes in properties when tested under normal laboratory conditions. For example, viscous properties are usually measured at atmospheric pressure and at a maximum temperature of 95 °C. Fluid loss is measured under static conditions with a maximum temperature of 200 °C and differential pressure of 500 psi. The viscous properties particularly may be different if measured at realistic down-hole temperature and pressure conditions. When using polymers, the maximum amount of data should be collected and field conditions monitored carefully to ensure that the drilling fluid is operating as designed. 5.3.7 Operational Aspects Most polymers are supplied in powder form and must be mixed on site. In order for them to function properly, a two-step process must occur. 1. The first step involves dispersing the dry polymer in the solution. Dispersion means the

subdivision of particles. When the powdered particles are properly dispersed, water molecules can quickly penetrate the solid polymer network and hydrogen bond to available sites on the polymer chain. This causes the polymer to swell, exposing new bonding sites. Eventually a layer of partially immobilized water molecules surrounds the molecule. The result is a swollen gel. The time for this process to occur efficiently may be reduced if either the shear rate or the temperature of the solution is increased. When a polymer molecule is fully hydrated, its effective size or hydrodynamic volume is larger than its molecular size.

If the dry product is mixed to quickly, wetting of the exterior affects a barrier. This prevents further penetration of water and subsequent dispersion of polymer particles. The resultant polymer balls are called fish-eyes. Their presence indicates a need for slower mixing, increased shear or a surface wetting agent.

A surface wetting agent can be used to overcome the high surface tensions and wetting energies involved when adding polymers to water and salt solutions. When either liquid or powdered PHPA polymers are mixed through a barrel, salt, such as KCl, may be added to the water first. The cation, K+ impedes hydrogen bonding and subsequent swelling. Again the fluid remains thin. (Divalent ions should not be used for this purpose). A further addition of DSTR-1-WBM to the salt system accelerates the hydration of the dispersed polymers.


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2. The second step is the solution process. Here the gel gradually disintegrates into a true solution. (A true solution is a single-phase, liquid system). For some very high molecular weight polymers, this may take days or weeks. Consider natural rubber dissolving into diesel oil. Agitation may speed up the solution process.

It has been theorized that branched polymers are more readily soluble than their linear

counterparts of the same chemical type and molecular weight. On the other hand, cross linked polymers probably do not dissolve, but only swell, if in fact they interact with the solution at all.4

When maintaining a drilling fluid system which employs polymers (sometimes four or five different types are used together) it is important to know the limitations of each product. This pertains to well bore conditions and the fluid's electrolytic and biological environment. The difference between static and dynamic degradation and performance should also be considered. Further, the limitations of the available surface equipment dictates the time required for mixing and should also be taken into consideration. When contaminants such as cement, anhydrite or bacteria are expected, the application of proper pre-treatments becomes mandatory. Two polymers may either compliment or hinder each other’s performance. The necessity for pilot testing on site and in the laboratory cannot be stressed enough, especially when changing products or concentrations. 5.4 FUNCTIONS OF POLYMERS IN DRILLING FLUIDS. 5.4.1 Viscosity In some drilling or completion fluid systems, polymers may be the sole viscofier. In order for a polymer to impact viscous characteristics into a solution, chemical interactions must occur. These include polymer-polymer, polymer-water or polymer-solids interactions. Polymer-solids interactions are discussed later, in the section on flocculation and extenders. Viscofying polymers are usually anionic, high molecular weight molecules. When added to a solution, water molecules hydrogen bond to available sites along the polymer chain. This may happen after dissociation of sodium or other ions from a functional site. The polymer begins to extend or stretch out when sites of like charge begin to mutually repel (Figure 5.16). As the molecule hydrates, the solution's resistance to flow increases. Structured or crystalline water may surround the molecule contributing to further viscosity. The chances of the polymer molecules interacting with each other, or with other components of the system are increased if the molecules in solution are longer or higher in molecular weight. This is seen in Figure 5.17 for two chemically identical polymers, differing only in molecular weight. The low molecular weight polymer is about 60⋅103 and the higher molecular weight polymer is about 200⋅103, or about three times longer. The higher the molecular weight, the fewer molecules are required to obtain a given viscosity. Since the polymer costs on a weight basis are essentially the same, the higher molecular weight type is used to increase viscosity.


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Figure 5.16:

A . U n h y d ra te d a nio n ic p o ly m e r

N a +

N a +

N a +

N a +

N a +

N a +

HO

H

N a +

H

OH

H O

H

H

OH

HOH

P a r it ia l ly h y d ra te d

F u lly h y d r a t e d w ith ac r y s t a ll in e la y e r o f w a te r

H OH

H

OH

H

OH

H

OHH

OH

H

OH H

OHH O

H

H

OH

Figure 5.17: Viscsity of HEC polymers against concentration of 2 different MW

A non-linear relationship usually exists between the concentration of a given polymer and the viscous properties it imparts. A typical curve relating the concentration of HEC to viscosity is given in Figure 5.17. This shows how the viscous properties of HEC are built up slowly at low concentrations. Initially there are insufficient molecules for them to interact with each other. Eventually a concentration is reached when there are enough molecules in solution to ensure


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entanglement and the viscosity increases very rapidly. The initial slow response to a change in properties as the concentration is increased is often observed in drilling fluid formulation. Care must be taken not to over treat during this slow response stage. Mixing different polymer types may increase polymer-polymer interactions. The resulting viscosity may be greater than the sum of the viscosities of the two systems. This is termed a synergistic effect and is observed for a number of polymer systems, including Guar Gum and Xanthan Gum. Any factor that causes the polymer molecule to shrink or coil up will also reduce the viscosity of the solution. It was shown earlier that the shape of a polymer molecule, which contained ionized groups, would change to a collapsed coil in higher concentrations of salt. This reduction in size also reduces the viscosity. Not all polymers have salt sensitive viscous properties. Non-ionic polymers such as Hydroxyethyl Cellulose (HEC) or Guar Gum will not exhibit these effects. This is also true for Xanthan Gum, due to its rigid helical structure. When divalent cations are added to a polymer fluid system, the effect may be rapid precipitation – or loss of solubility due to crosslinking. Both result in a viscosity reduction. After polymerization, Cellulose polymer is partially neutralized by the addition of NaOH to form sodium carboxylate groups (COO-Na+). When the polymer is placed in solution, it becomes soluble due to the ionization of these groups. However, if the pH of the solution is adjusted to an alkaline level, greater solubility will be attained as more ionized sites on the polymer chain are formed. If the alkalinity is lowered, a reduction in the number of these sites can reduce the viscosity. 5.4.2 Fluid Loss Control The polymers used to reduce the fluid loss in Drilling fluids are generally anionic, straight chain, and of moderately high molecular weight. Fluid loss reduction is achieved by three mechanisms; some polymers enhance or contribute to all three: 1. Plugging or blocking pores. 2. Increasing fluid phase viscosity 3. Deflocculating clays. The polymer molecule itself may cause blockage of a pore throat if the throat is small enough (about one micron or less). For this process to occur, the polymer must not be completely soluble. Starch and asphalt derivatives can function in this manner. Polymers may also contribute to pore throat blockage by adhering to suspended colloidal particles such as clays and effectively increasing their diameter. Fluid loss reduction may also be achieved if the viscosity of the solution is increased. This effect relates to Darcy's Law and is explained in the chapter on Fluid Loss. Polymers, which contribute to this effect, are in the high molecular weight category. They include Guar and Xanthan Gum, HEC, and high-viscosity Cellulose polymers. If these polymers are ionic, they may also act as a bridge between clay particles. This promotes increased blockage through larger particle size. Anionic polymers promote the dissociation or deflocculation of suspended solids. This results in closer packing of cake forming materials, especially clays, reducing the filtration rate. This process is discussed in the chapter on Clay Chemistry. Figure 5.18 illustrates this effect. The anionic charge density and molecular weight of the polymer dictates its effectiveness as a


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deflocculant. Lignosulfonates, low molecular weight Cellulose derivatives, and Polyacrylates are the most effective. Figure 5.18: Fluid loss in a flocculated (left) and a deflocculated (right) system

As the environment of a fluid changes, limitations are placed on the selection of fluid loss additives. Limiting conditions include pH, salinity, hardness and temperature. As these conditions become more adverse, it becomes necessary to reduce the molecular weight, reduce the (anionic) charge density, or eliminate polymers containing an acetyl linkage. In fresh water solutions, cellulose derivatives may be used to complement the fluid loss reducing effect of clays. As salinity or hardness increases, highly substituted Cellulose (PAC) or starch may be used. Starch, being nonionic is best in saturated salt systems. Guar is effective in calcium environments. In oil based environments Gilsonite HT is used to reduce whole mud losses. Gilsonite is a coal / asphaltenic material that is pulverized to various mesh sizes to help in pore blocking. As the wellbore temperature increases, consideration must be directed to polymer performance with respect to fluid loss, especially under dynamic conditions. • Starch and Starch derivatives are usually effective to 100 °C; • Cellulose derivatives and Biopolymers may remain stable for short periods at up to 140

°C; • Above 140 °C, Acrylate or Acrylamide products are necessary; • Above 200 °C, Vinylsulfonate or Vinylamide polymers should be used. The temperature limitations of polymers are not always sharply defined and other factors must also be considered. For example CMC may lose its viscosification characteristics at temperatures far lower than its maximum fluid loss stability temperature. Polyacrylate may lose its effectiveness at relatively low temperatures if calcium concentrations are high.


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5.4.3 Shale Stabilization The term shale stabilization usually refers to a mechanism which retards the water adsorption and the subsequent swelling / dispersion process common to most shales and clays. Most polymers available to our industry are able to, and have been used to, stabilize shales to some degree. This includes Cellulose derivatives, Xanthan Gum, Starch, Lignosulfonates and even nonionic types such as HEC. Several methods are commonly used to determine or compare the performance of various polymers on different shales. However, the actual mechanisms contributing to this effect are still mainly theoretical. Descriptions of these mechanisms include: lowering the fluid's erosive action through friction reduction, polymer adsorption onto the surface of the shale, and blocking – resulting in slowing base exchange and hydration. Adsorption of polymer onto the surface of shales is believed to be the most effective method of stabilization. This adsorption is sometimes called encapsulation. Nonionic polymers such as HEC, may adsorb into clay surfaces regardless of the surface charge. Anionic polymers must either adsorb onto positive edge sites or link to the surface through ligand exchange with aluminum at an edge site. One theory suggests that hydrogen bonding occurs between the polymer and the water-wet surface of the clay. Another very interesting theory suggests that it is possible to establish covalent bonds between the polymer molecule and the quartz matrix typical of most clay formations. Regardless of the actual mechanism, encapsulation is believed to be a relatively fast process. If the polymer chain is long enough, each molecule is able to attach to several available surface sites. This attachment links the sites and retards layer separation. Polymers used specifically for encapsulation purposes are usually polyacrylamides. The necessity to inhibit the hydration of medium-hard to hard illite-containing formations prompted their development. Consideration of this process demands a closer examination of the term encapsulation. Even the hydrodynamic volumes of high molecular weight polymers are relatively small compared to the surface area of cuttings. It is conceivable that actually only a partial, protective polymer layer forms on the clay, contributing to both increased lubricity and hydration dispersion inhibition. Shev and Perricone postulate that this partial layer, being highly hydrated is not impermeable to water molecules. Eventually hydration and swelling occur, due to both diffusion and osmotic pressure.5 Therefore, for longer term borehole stability applications, the PHPA molecule should have additional help. The effectiveness of PHPA is usually enhanced when it is used with AVA HighPerm (an amine-based compound) or KCl. Potassium ion diffusion and exchange with inter-layer shale cations is probably slow relative to polymer adsorption at the borehole surface. The combination of a fast acting polymer and a strong exchange cation would explain the excellent field results when a KCl / PHPA system is used. An added benefit of any encapsulating polymer is that it impedes the dispersion of drilled cuttings as they travel up the annulus. Highly dispersive montmorillonite-type formations are effectively controlled with variations (extremely high molecular weight, i.e. 10 million) of PHPA, without the benefit of KCl. The short retention time of cuttings in the annulus makes this application feasible.


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Extensive research has been conducted on the encapsulating properties of Lignosulfonates. Debate has followed the research. Ava Drilling Fluids considers Lignosulfonates to be good encapsulators for specific applications. 5.4.4 Flocculation and Extension The term flocculation means an increase in the degree or number of particle associations in a suspension (see flocculation, Chapter 4). Polymers flocculate solid particles by linking them into large agglomerates. If the mass of linked particles becomes great enough, gravity causes them to drop out of suspension. Stokes Law explains how this works, (Chapter 14 on Rheology). Flocculating polymers are used to clean some Drilling fluids by causing undesirable solids to settle. They may also be used to extend or increase the viscosifying properties of commercial clays. Flocculating and extending polymers are usually high molecular weight, anionic molecules, quite similar in nature – with the exception of their linear shape – to the polymers used for primary viscosification. Figure 5.11 shows how interparticulate associations are increased as clay adsorbs bridging polymers. The performance of these polymers depends on several factors. There is an optimum range of molecular weight – 10⋅106 is average. A polymer with a similar chemical structure to a flocculant but with a lower molecular weight can act as deflocculant. Chain linearity is important. Cross-linked polymers exhibit reduced solubility and cause a reduction in the degree of interactions with particles by inactivating or immobilizing sections of the chain. The weight: branching and crosslinking reduce length ratio. The charge distribution on the chain is important in terms of solubility, chain extension and the degree of interaction with suspended particles. Figure 5.19: Interaction between charged particles is increased when high molecular weight

anionic polymers are introduced to a suspension containing charged particles.

Polymers are used as flocculants in clear water drilling applications. Here the introduction of a cation, usually calcium, to the suspension is necessary for the best results. In this case the cation acts as a link between the negative face of a clay particle and the anionic polymer. As


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particles agglomerate they become massive enough to drop out of suspension, resulting in clear fluid at the suction pit. If clay particles contain montmorillonite species, a total flocculant must be used. These polymers work on all clay types. When montmorillonite formations are not present a selective flocculant should be used. This is a nonionic / anionic polyacrylamide blend. Since this polymer does not act on bentonite particles, sump fluids may be reused to make-up gel-based systems. The concentrations of flocculating polymers in clear water drilling applications must be monitored closely to avoid flocculating solids in the well bore. The operational aspects of clear-water drilling fluids are discussed in chapter 8, Water-Based Fluids. Selective flocculants may also be introduced to bentonite suspensions to enhance agglomeration and settling of drilled solids without interfering with bentonite concentrations. This process usually occurs in combination with centrifugation. Wide ranges of selective flocculants are available for this purpose. Polymer bridges are used to link bentonite particles in suspension. These polymers are termed extenders. They improve the suspension and carrying abilities of a gel system without the further addition of solid particles. Gel systems with good properties may be attained with less than 4%v total solids and less than 10 kg/m3 of bentonite. The operational aspects of extended gel systems are also discussed in the chapter on Water-Based Fluids. The chapter on Clay Chemistry explains how extending polymers are sometimes blended with dry Bentonite to improve its performance. 5.4.5 Deflocculants The term deflocculation refers to a reduction in the number of, or degree of particle associations in a colloidal suspension. As this process occurs, the viscosity of the suspension decreases. This is why deflocculants are sometimes called thinners. These products are always anionic and of low molecular weight. As a result, they are adsorbed onto the positive edge sites of clay plates; causing the plates to behave as through they were completely anionic. Thinners are used to control rheological properties when influences such as salts, temperature or solids cause increased viscosity. Figure 5.20 depicts the method by which thinners work.


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Figure 5.20: Low molecular weight, non-ionic polymers reduce the number and strength of clay particle associations, thus reducing viscosity

Small molecules such as polyphosphates and short chain polyacrylates are often used to deflocculate clay suspensions. The inter-particulate repulsive forces can be increased however, if the molecule is physically large. This introduces a sterical factor, which physically prevents the particles from approaching each other. Lignosulfonates are examples of such molecules. They are more effective at keeping a system deflocculated in adverse environments such as high salt or hardness. Inputs into product selection are dependent on several parameters including, wellbore temperature, and environmental restrictions, expected severity of the flocculation and the alkalinity of the fluid system. Deflocculating polymers often exhibit synergistic effects. 5.4.6 Surfactants Today's drilling fluids rely on polymers to perform several other functions. These may be of critical importance in a given situation. The structure of these polymers can be complicated and often their mechanisms are not fully understood. Surfactants are a large family of compounds, which can perform various functions in drilling fluids. They are sometimes called surface-active agents. They alter the properties of a fluid, usually lowering the tension at the point of contact between two immiscible fluids or between the fluid and solids. This means that the surfactant molecule must consist of two distinct sets of functional groups, one on either end.


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Usually one group is polar and seeks polar substances. The polar group is soluble in water, and is termed hydrophilic. The other end is non-polar and seeks non-polar substances. If it lacks any affinity for water, it is termed hydrophobic and if it is soluble in oil, it is termed lipophilic. Figure 5.21 depicts a surfactant used for emulsifying water in oil. Figure 5.21: Surfactant used for emulsifying water in oil

-O3SO

An Emulsifier

-O3SO-O3SO

-O3SO

-O3SO

-O3SO-O3SO

-O3SO

-O3SO -O3SO

-O3SO

Oil

OilH2O

Hydrophobic tail, "oil lover"Hydrophilic Head"water lover"

A water in oil emulsion

Surfactants can be formulated to act at the following interfaces: 1. Air / water: Foamers Defoamers 2. Water / Steel: Corrosion inhibitors Lubricants Detergents 3. Oil / Water: Direct emulsions Invert emulsions 4. Clay / Water: Dispersants 5. Oil / Clay: Oil wetting compounds 6. Steel / Clay: Detergents Surfactants may be classified by their overall net charge after solvation and dissociation of groups or parts. That is, they are non-ionic, cationic or anionic.


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Non-ionic surfactants can be long chain polymers. These can limit the expansion of clays by competing with water for adsorption sites on clay surfaces. Other non-ionic products are adsorbed at oil-water interfaces. These contain lipophilic and hydrophilic groups. They are commonly used as emulsifiers. They lower the energy (shear) and temperature required to make an emulsion stable. They can be synthesized from alcohol anhydrides and ethylene to suit specific applications. The chemical nature of the two chains and the HLB number determine how they will perform. The HLB number expresses the hydrophilic: lipophilic ratio by weight. The higher is the ratio, the more water-soluble is the molecule. Figure 5.13 depicts an anionic surfactant acting as a water-in-oil emulsifier. Table 5.5: Different application according to HLB ratio

HLB range Application 3 – 6 Water in Oil emulsifier 7 – 9 Wetting agent

8 – 15 Oil in Water emulsifier 13 – 15 Detergent 15 – 18 Solubilizer

Table 5.6: Water solubility according to HLB ratio

HLB range Water solubility 1 – 4 No dispersability 3 – 6 Poor dispersion 6 – 8 Milky dispersion after vigorous agitation 8 – 10 Stable milky dispersion

10 – 13 Translucent to clear solution > 13 Clear solution

Cationic surfactants are electrostatically attracted to the negatively charged surfaces of clays and other minerals. They are usually the salt of a fatty acid amine or polyamine. A solvated, dissociated molecule may consist of a large organic / cationic group and a small inorganic / anionic group. Anionic surfactants dissociate into a large organic / anionic group and a simple inorganic cation. The best example is soap such as sodium oleate (fig 5.22). Figure 5.22: Sodium oleate

O

O-Na+

These are able to adsorb onto the positive edge sites of clays and at water / oil interfaces. Surfactants are often blended to accomplish more than one purpose. For example, a spotting fluid should oil-wet the pipe and dehydrate the filter cake. Other surfactants perform more than one function, such as when an emulsifier also acts as an oil wetting agent.


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5.5 POLYMER DESCRIPTIONS The following text examines some of the common types of polymers used in Drilling fluids today. It is by no means a complete list, but it should serve to provide some interesting general information on polymers. The discussion includes, how some polymers are manufactured, the ability of a single type of polymer to serve more than one function, and how they are altered to diversify their functions or extend their limitations in a fluid environment. Although many variations of polymers exist, the types considered in-depth here include Cellulose, Xanthan Gum and Lignin-type natural or modified polymers and, Acrylate and Acrylamide synthetic polymers. 5.5.1 Starch and Modified Starch Starch was the first polymer to be used in any significant qualities in drilling fluids. Although starch may impart various properties, its primary use is for fluid loss reduction. It is the principal component of the seeds of cereal grains such as corn, wheat and rice and of tubers such as potato and tapioca. Figure 5.23: Potato cell

Starch grains (figure 5.23) consist of a tough outer cell wall made of amylopectin, surrounding a substance know as amylose. Both are polysaccharide-type carbohydrates. Amylose consists of straight chains of glucose residues ranging in molecular weight from 10⋅103 to 100⋅103. The major component, amylopectin has a molecular weight of 40⋅103 to 100⋅103 and is comprised of branched molecules.


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Figure 5.24:

Processing (fig 5.24) involves rupturing the cell wall and the expansion of the amylose under the combined influence of heat and chemical treatment such as acids and peroxides. This process is called pre-gelatinization and produces a water dispersible product. A temperature stable grade of starch may be prepared by cross-linking. Potato starch is usually a superior product due to its low levels of fat and protein. Production includes a drying stage, which uses a heated drum, producing products that exhibit higher temperature stability. Corn produces acceptable products and is cheaper than potato starch. Wheat starch is a less acceptable product due to the high protein content, leading to foam problems and lower biological stability. Starch disperses in water to form colloidal, essentially nonionic low viscosity particles which plug the pores in the filter cake. The product has excellent application as a fluid loss additive in salty systems, particularly in salt saturated systems and hard brines. Starch products are subject to degradation caused by bacteria, mold and yeast. In systems where the pH is less than 12 or where salt saturation has not been reached a biocide should be added along with the starch. The rate of bacterial decomposition is reduced if the system temperature is either very cold or above 70 °C. Most starch products are also subject to thermal degradation at temperatures above 90 °C and to shear degradation to a degree. Starch is precipitated with calcium at higher pH levels. Besides the cross-linking to increase temperature stabilization, starch products may be modified to include a biocide. They may also be designed to contribute to more desirable (reduced) rheological properties, or to aid in inhibiting shale dispersion. Cationic starch products reduce the fluid loss in lime / chloride fluids where normal pre-gelatinized starch will not.


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5.5.2 CMC and PAC Cellulose derivatives are the most widely used organic polymers. Sodium carboxymethyl cellulose is a non-toxic, colorless, odorless powder. Since it does not normally ferment, it is more cost effective than starch if hard brines or salt saturated fluids are not being used. One of the important variables in CMC products is polymer chain length or degree of polymerization (DP). This can be varied over a wide range by the choice of cellulose source. Cotton linters are used for long chain viscosity products. Medium and low viscosity varieties used for filtrate reduction use wood pulp cellulose, perhaps using chemicals to de-polymerize the cellulose. The DP of these ranges from 500 to 2000. This semi-synthetic polymer is produced by the reaction of chloro-acetic acid on caustic soda treated cellulose to form carboxymethyl cellulose (CMC). Cellulose is first treated with aqueous caustic soda solution to form "alkali cellulose". The second stage is the reaction of chloro-acetic acid with the alkali cellulose to form CMC with the structure (fig 5.8). The by-products of the reaction are salt and sodium glycolate. The salt is removed by washing to form a pure grade (up to 99%) product. Technical grades are usually in the order of 80% pure Na+ CMC. Figure 5.8: CMC monomeric unit

OH

OHO

O

O

O

O

OH

OOH

O

O

Na+-O

O-Na+O

Substituted Monomeric unit There are three potential reaction sites (hydroxyl groups) on each CMC glucose unit. An important variable is the number of hydroxyl groups that have reacted with CH3COO-Na+, or the degree of substitution (DS). The maximum DS is 3 but an average value of 0.45 will produce a water-soluble product. The higher the DS, the greater the solubility and ability to retain water within its structure and hence exhibit improved fluid loss control properties. Drilling fluid CMC has a DS of about 0.8. Products with higher levels of DS – about 1.0 – are called polyanionic cellulose (PAC). CMC´s with higher DS values require higher levels of reagent. This also increases the residual salt content such that some degree of purification or salt removal may be required. Both these aspects increase the cost of production. However, the stability of the molecule to salt is also improved. This is clearly shown in Figure 5.25 where the viscosities two CMC´s with different DS values are given as a function of the NaCl content. The viscosity of the more highly substituted polymer is essentially stable to the effects of the salt.


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Figure 5.25: Effect of increasing DS in CMC on the viscosity as salt concentration is raised.

The three main variables, molecular weight, degree of substitution, and purity or salt content, generate a wide range of products, which have a number of diverse applications. CMC is an anionic polymer that adsorbs onto clays. The length of the solvated molecule may be affected by the degree of substitution and salt concentration. Low viscosity types are used to lower fluid loss in fresh water, bentonite-based systems, and in saline conditions up to saturation. The molecule may exhibit deflocculation effects especially in flocculated systems, as it has a low molecular size and increases the net negative charge on the clay particles. Low viscosity CMC may be sold either purified or unpurified (CMC LVP, CMC LVS, CMC LVT). High viscosity types are used to develop shear thinning characteristics in water-based fluids. They also control fluid loss effectively at low concentrations, especially the higher molecular weight varieties. The apparent viscosities of CMC suspensions are high at low shear rates. The viscosity of CMC suspensions decreases substantially with temperature. High viscosity CMC may be sold either purified or unpurified (CMC HVP, CMC HVS, CMC HVT). Thermal degradation of CMC begins to accelerate rapidly at temperatures above 140 °C. The anionic CMC molecules are susceptible to form insoluble complexes with polyvalent cations such as calcium or aluminum. The potential for these problems is reduced in the more highly substituted PAC types. CMC can be used in lime-based systems if the calcium level is reduced to below 500 mg/l. The high viscosity grades of PAC posses inhibitive properties when used in sufficiently high concentrations, due to the adsorption of the polymer on the solids.


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5.5.3 HEC Hydroxyethyl cellulose is a nonionic, cellulose-based polymer. It has a specific application as a viscofier in solids-free completion brines. HEC is a linear molecule, which may be up to two microns in length. In solution it forms a random coil, such that its effective length is about 20% of its molecular length. The coil shape provides good viscosity characteristics. Since it is flexible, it becomes elongated when in motion. This contributes to well-developed shear thinning qualities in an HEC solution. HEC exhibits some filtrate reducing characteristics, but is not normally used in Drilling fluids because it exhibits no thixotropic properties. Figure 5.26 shows the HEC molecule and its acetyl linkage. HEC is the most acid soluble, least damaging viscofying polymer – explaining its wide use in completion brines. It is non-ionic so its dimensions do not change in the presence of electrolytes, making it relatively stable in most moderate, basic environments. HEC does have both shear and temperature limitations, although magnesium oxide may stabilize HEC, enabling it to perform at temperatures as high as 130 °C. HEC has a tendency to foam when mixing. Figure 5.26:

The production process is based on the reaction between alkali cellulose and ethylene oxide to produce molecules with the structure shown in Figure 5.26. The first reaction is with the hydroxyl groups of the cellulose to attain water solubility. The degree of substitution is controlled at range of 0.9 – 1.0. The ethylene oxide may also react with the substituted chains. The level of "molar substitution" refers to the total number of moles of ethylene oxide per cellulose unit. It usually ranges from 1.8 – 2.0. The molecular weight, degree of substitution, extent of molar substitution, and the uniformity of substitution all contribute to the net effect of the polymer. HEC is used in concentrations of 0.6 to 6.0 kg/m3.


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A derivative product, CMHEC is made by the sequential treatment of alkali cellulose with chloro-acetic acid followed by ethylene oxide. The degree of substitution of CMC groups is in the low range of 0.6 – 0.8. This initial treatment opens up the cellulose chains so the successive ethylene oxide treatment is carried out uniformly on the molecule to a molar substitution level of 0.3 – 1.6. The uniform distribution of the anionic groups renders the molecule much more resistant to the precipitation effects of multivalent ions such as calcium. The product is relatively expensive because it is processed twice, but has found application in more extreme environments including high temperatures and hard brines. CMHEC is used as a fluid loss reducer and retarder in oil well cement slurries. 5.5.4 Guar Gum Guar Gum is a natural, essentially non-ionic polymer that has an excellent application as a viscofier for spud-in fluids, that is, short duration fluids. Guar solutions hydrate readily, exhibiting shear thinning character and insensitivity to salts and various multivalent ions. Guar Gum is sometimes used in low concentrations to flocculate drilled solids and guar derivatives have been used for viscosification in solids free-workover fluids. Guar also exhibits limited filtrate reduction and wellbore stabilization characteristics. Guar is derived from the seeds of the guar plant, cultivated in India, Pakistan and Texas. The plant develops pods, each of which contains five or six seeds. The seeds undergo a multistage process of grinding and sifting to separate the guar containing endosperm from the outer hull and the germ. The result is a polysaccharide consisting of a linear backbone of polymannose, substituted at every other unit by a short galactose branch. This is illustrated in Figure 5.27. Figure 5.27: Guar Gum structure

The mannose units are linked to each other by means of glycosidic bonds. The molecular weight of guar is in the order of 20⋅103. Note that each repeating unit has 9 potentially reactive OH groups, able to form guar derivatives. Usually the derivatives have the same basic structure as guar. Chemical treatments to guar produce variations, which are more biologically and thermally stable. Additives can be incorporated into the formulation to improve its ability to disperse. Cross-linking with borax is sometimes used to increase its viscosification characteristics. Viscosification is accomplished by the normal association and hindrance mechanisms. Structured water in the vicinity of the molecule augments this. Guar Gum is prone to bacterial degradation unless protected by either a biocide or high salinity or pH. However, high pH and hardness


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together may inhibit the dispersion of guar or initiate its precipitation through cross-linking. Normally guar degrades rapidly at temperatures above 60 °C, limiting its use to shallow wells. Thermal degradation is a permanent loss in viscosity due to cleavage of the acetyl bond, resulting in depolymerization and is not merely a temperature-thinning phenomenon. 5.5.5 Xanthan Gum Xanthan Gum (XC polymer), is an anionic, water-soluble polysaccharide biopolymer. It is produced by the action of the bacteria Xanthomonas Campestris on carbohydrates. It is classified as a natural polymer, although it is actually processed. It has been used as a viscofier and suspending agent in fresh or salt-water solutions since the middle 1960´s. Its superior cleaning, shear thinning and suspension properties at low concentrations, combined with its stability in saline environments, make it very cost effective. It has a particular application in remote locations where transportation costs are high, and in fact, it is the sole viscofier in certain Arctic and Offshore applications. The polymer also functions as a fluid loss control agent in that its molecular size contributes to a filter cake plugging effect. It is compatible with other filtrate reducers such as bentonite and CMC. Xanthan Gum has desirable properties for workover and completion applications. Xanthan Gum (fig 5.28) is extracted as the polysaccharide formed as a coating on each bacterium. The bacteria are grown under aerobic conditions with a suitable source of carbohydrate such as sugar solution and minerals. Fermentation conditions are carefully controlled. The viscosity increases to a point where the bacteria are precipitated with isopropyl alcohol before being, filtered, washed, dried and milled. Figure 5.28: Xanthan gum biopolymer structure

The major sugars are D-glucose, D-mannose, D-glucuronic acid. The monomer consists of a linear backbone of glucose residues linked with D-mannose, D-glucuronic acid residues which have a 3 unit long side chain attached to them. The carboxyl groups on the side chains make the polymer anionic. The result is the complex, branched or network structure, shown above. The polymer chains associate to form a double helix as shown in Figure 5.29 and Figure 5.30. The interacting polymer chains form a rod-like molecule with a molecular weight of about 20 million and dimensions of about 2 – 10 microns long and 0.2 – 0.6 microns in diameter.


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Figure 5.29: XC polymer network

Variations on the effect of Xanthan Gum may be attained if it is cross-linked with various chromium compounds. The viscosification characteristics of Xanthan can behave in a synergistic manner with other polymers such as CMC, HEC and Starch. Figure 5.30: Helical structure of Xanthan Gum

At low shear rates, the molecules form a complex, aggregate network through hydrogen bonding and entanglement. This network accounts for the polymer's viscosity and suspension properties. Shear thinning (see the chapter on Rheology) results from the disaggregation of this network and


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alignment of individual polymer molecules in the direction of the shearing force (fig 5.31). The rigid, helical structure ensures that the molecular dimensions do not change excessively with increasing salt concentrations. Figure 5.31: Effect of shear on XC polymer network

Although the viscous properties of Xanthan Gum are not affected by salt or moderate temperatures, several other influences can be detrimental to its performance. In the presence of divalent cations and high pH (an environment encountered when drilling green cement) it can be precipitated. It is also subject to degradation by microorganisms and enzymes. Therefore, when it is used to make up kill mud the pH should be maintained above 11.0. In packer fluid applications, a biocide should be used. Thermal degradation of Xanthan Gum begins at around 75 °C. 5.5.6 Scleroglucan Scleroglucan is a non-ionic, water-soluble biopolymer produced through fermentation. Aqueous solutions of scleroglucan exhibit exceptional shear-thinning rheology and good suspending ability. The advantages of scleroglucan in comparison to other biopolymers are higher thermal stability, pH stability and tolerance of divalent cations such as Ca++ / Mg++. Scleroglucan shows much higher thermal stability than Xanthan gum and can be used up to 140 °C (285 °F) whereas Xanthan gum shows a gradual viscosity decrease starting at 70 °C (155 °F). pH does not influence the performance of scleroglucan over a broad range from pH 1 to 12. Scleroglucan is a regularly branched polysaccharide of the scleroglucan type (see fig. 5.32). It is produced through aerobic fermentation of a carbohydrate by a fungus filamentum: its molecular weight is about 500⋅103.


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Figure 5.32: Scleroglucan structure

In an aqueous solution, three of these scleroglucan molecules adopt a triple-helical conformation and can be described as rigid rods. Under static conditions, these rods form a web-like structure. The resulting gel provides excellent carrying capacity. As scleroglucan is non-ionic, it tolerates high amounts of mono-, di- and tri-valent cations like Na+, K+, Ca++, Mg++, and Fe+++. Characteristics of scleroglucan include: • high low shear rheology • thermally stable up to 285 °F (140 °C) • stable at pH 1 to 12 • completely tolerant to NaCl, NaBr and KCl • tolerant to high calcium levels • compatible with common drilling fluid and cement additives • non-damaging to the formation • environmentally safe Scleroglucan is used in concentrations of 0.5 to 5 ppb (1.5 – 15 kg/m3) depending on application. In long-term fresh water applications at temperatures below 80 °C (175 °F) the addition of a biocide is recommended to preserve the biopolymer. In brine applications it is recommended to disperse scleroglucan first in lower density brine and then add salt to the required density. The heat developed during the salt addition will greatly enhance the hydration of scleroglucan. Scleroglucan shows fastest solubility at or above 60 °C (140 °F). Scleroglucan provides an exceptional shear-thinning (visco-elastic) rheology with high yield point, low plastic viscosity and high low-end readings. The result is excellent static and dynamic carrying capacity with low pump pressure being sufficient to move the fluid. Typical fluid systems for which scleroglucan can be used include: • fresh and seawater mud • lime and gypsum mud • salt saturated mud • silicate mud • CaCl2 and CaBr2brines • K-formate brines


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• Low-bentonite mud 5.5.7 Lignosulfonates Lignosulfonates and chrome Lignosulfonates (CLS) are strongly anionic by-products of the sulfite process used to separate cellulose pulp from wood. They are the most widely used deflocculants in water-based Drilling fluids. Deflocculating a clay suspension, results in a cost-effective reduction in fluid loss and cake thickness. This is discussed in the Fluid Loss, Chapter 6 and the Clay Chemistry, Chapter 4. Lignosulfonate products are often used to augment primary fluid loss reduction products. Lignosulfonates have the ability to stabilize oil-in-water emulsions. The absorption of Lignosulfonate on clay surfaces reduces swelling and cleavage, promoting hole stabilization and the recovery of un-dispersed cuttings. Figure 5.33: Lignin and lignosulfonate polymers derive from hydration of sugars to give aromatic

(phenol-type) compounds

OH

HO

OH

O

O

OH

OH

HO

OO

Lignosulfonate contains complex structures that include aromatic (phenol) rings and acid groups. Lignins are formed by the removal of water from sugars to afford aromatic structure Figure 5.21. Browning6 postulated that the structure was a ridged ellipsoid from which short chains containing sulfonic and hydroxyl groups protrude. The structure of the molecule is tight which minimizes swelling tendencies. It is hydrophilic and capable of hydrogen bonding. Molecular weights vary from 1000 to 20000. Manufacturing process variables and the choice of reagents have led to numerous patents and many Lignosulfonate products. Common generic types include calcium, chrome, ferro-chrome and chrome-free products. The deflocculation mechanisms stem from the adsorption of the non-ionic lignosulfonate micelles onto the positive edges of clay particles. This results in encapsulation if the concentration is high enough. The emulsion stabilization mechanism is derived from adsorption at the oil-water interface. The sulfonate groups provide stability to most types of ionic contamination. Thermal degradation usually begins to affect deflocculation properties at about 120 °C. The thermal degradation or biodegradation of chrome Lignosulfonates can contribute to the formation of CO2 and H2S, however, the addition of chromate increases its temperature stability. Adding sodium hydroxide increases the solubility of all lignosulfonate products.


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5.5.8 Polyacrylamide Partially Hydrolyzed Polyacrylamide (PHPA) polymers are synthetic, anionic, acrylamide / sodium-acrylate co-polymers. These polymers have been used successfully throughout the world to aid in the maintenance of borehole stability by encapsulating or surrounding hydratable shales. This encapsulation effect can also contribute to a reduction in overall drilling costs by eliminating sloughing and reducing the tendency of drilled cuttings to disperse in the annulus. This promotes increased solids control efficiency, a reduction in lost time due to mud-rings, and less tendency towards bit-balling. PHPA is also used as a clear-water drilling flocculant. The lubricating properties of PHPA polymers have been well documented. Polymerizing acrylamide monomers in acrylic acid makes PHPA. The acid converts some of the amides on the acrylamide chain to carboxylates. This process is called hydrolysis (mentioned in section 4.2). Figure 5.34 shows an acrylamide – acrylate co-polymer. The degree of hydrolysis imparted to a PHPA molecule depends on the specific function it is required to perform. • A 30% hydrolyzed PHPA contributes to hole stability; • A 10% hydrolyzed molecule contributes to water clarification by flocculation; • A 70% hydrolyzed molecule contributes to filtration control. The structure of PHPA is generally linear although cross-linking is possible. Molecular weights vary but are usually extremely high. Some of the best PHPA polymers include the Alcomer series. Figure 5.34: PHPA acid structure

O NH2 OHO NH2O

n

The encapsulation mechanisms of PHPA are believed to be either attraction of the molecule to positive, clay edge sites and / or hydrogen bonding. The reason the 30% hydrolyzed PHPA provides the best inhibition characteristics are believed to be because the charged sites on the chain match the general spacing of the clay plates. In the case of reduction in bit balling, the mechanism is thought to be due to the attraction of the cationic amide groups to the steel surface of the string and bit. The carbon link in all synthetic polymers, including PHPA renders them both, thermally and biologically stable. Excessive concentrations of multi-valent cations, such as calcium, magnesium and aluminum do affect PHPA performance. When drilling through soluble anhydrite (CaSO4) the volume of sediment in the standard PHPA floc test begins diminishing at 200 – 300 mg/l of total filtrate hardness. The assumption that the test has been affected, and the polymer remains functional is incorrect. The polymer is actually coiled up as in Figure 5.34 and is effectively useless. Polyacrylamide polymers can be susceptible to oxidative degradation at higher temperatures, especially in the presence of metal ions and acidic conditions. The shear degradation mentioned earlier in the chapter is usually only noticeable after prolonged rates of excessive shear, such as when a batch is left standing in a chemical barrel with a high-speed electric agitator running.


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5.5.9 Polyacrylates Polyacrylates are non-ionic synthetic polymers used to control fluid loss and deflocculate clays at moderately high temperatures. Higher molecular weight varieties are able to extend bentonite and flocculate as shown in Table 5.7. Very low molecular weight polyacrylates are used in the formulation of scale inhibition products. TABLE 5.7 Relationship between molecular weight and function for polyacrylate FUNCTION MOLECULAR WEIGHT (x 103) NUMBER OF MONOMERS (x 103) Deflocculant 7 1 Fluid Loss Additive 6 8 Flocculant 3000 40 Bentonite Extender 10000 14 Polymerization occurs in an aqueous solution, beginning with a vinyl monomer. The molecular shape is believed to be linear. Figure 5.34 depicts the structure of polyacrylate. The molecular weight can vary substantially. The carbon-carbon backbone of this group makes them resistant to temperature to 200°C, and to bacterial degradation. They can also have a synergistic effect with lignosulfonates. The first polyacrylate products were highly sensitive to high hardness levels. However, recent modifications have enabled them to be used in seawater systems and where anhydrite is common. Figure 5.34: n-polyacrylic acid

O OH OHO OHO

n 5.5.10 Polyalkylene glycols The sudden onset of turbidity of a non-ionic surfactant solution on raising the temperature is called “cloud point”. At somewhat higher temperature the solution begins to separate into 2 phases: one is an aqueous solution containing monomolecular dispersed species of surfactant without micellar aggregates; the other is a phase rich in non-ionic surfactant with solubilizate and water dissolved in it. The presence of a solubilizate affects the cloud point and the phase-separation temperature. The cloud point phenomenon of polyalkylene glycols is due to the formation of giant micelles: when they become very large, the turbidity (cloud point) becomes perceptible even to the naked eye. The hydration of ether oxygens of polyoxyethylene group is the main factor in keeping the non-ionic surfactant in solution. The increase of temperature causes partial dehydration and finally results in the separation of the surfactant-rich phase. Non-ionic surfactants having a longer polyoxyethylene group show a higher cloud point by virtue of a greater capacity to hydrate. The cloud point is rather insensitive to the concentration of


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surfactant itself, but is appreciably influenced by the presence of certain additives: electrolytes suppress the cloud point in proportion to their concentration. The onset of clouding in drilling fluids has been associated with increased lubricity, a reduction in fluid loss, and an increase in shale stabilization. The cloud point phenomenon has been exploited to produce ‘thermally activated’ fluids where the mud composition is formulated to give glycol separation at the drill bit or lower well bore region, the glycol re-dissolving in the cooler upper sections of the well. 5.5.11 Descriptions of other Polymers The following text describes other drilling fluid polymers, which are less common than the ones previously discussed. They are by no means less important. As drilling conditions become increasingly adverse with respect to temperature and abnormal formation pressures, some of these products are becoming much more common. Lignin or lignite is used extensively in many areas as a deflocculant and fluid loss reducer. Lignite products are natural, anionic, long-chain molecules similar to Lignosulfonates. Leonardite, a low-grade coal is the lignitic material used in Drilling fluids. Lignite has the ability to reduce fluid loss, stabilize emulsions and stabilize fluid properties against the effects of high temperatures. Lignite may be modified using reagents such as Sodium Hydroxide (causticized lignite). Unmodified lignite is not as effective in calcium-contaminated or saline fluids. Sodium Polyphosphates are large anionic, synthetic molecules used mainly as thinners. They are produced by heating orthophosphates and removing the water or by melting the anhydrous components together. The product is then ground. Sodium acid pyrophosphate or SAPP (Na2H2P2O7) is the most common type. Figure 4.26 shows a polyphosphate molecule associating with a positive clay edge. Its acidic nature makes it effective in treating cement contamination by reducing pH. It also precipitates calcium. Polyphosphates are not as effective in saline environments above 10000 mg/l Cl-. High temperature applications are limited also, due to their revision back to flocculating orthophosphates prior to reaching 100 °C. SAPP is sometimes used on shallow land wells to prevent "mud rings" – See the chapter 8, Water-Based fluids. VSVA (vinylsulfate / vinylamide) polymers are becoming increasingly common as wellbore temperature conditions become more adverse. VSVA is an anionic synthetic co-polymer, which in some cases actually works better as the Drilling fluid environment gets worse. The main function of VSVA is filtrate reduction. The API filtrate test does not always provide an accurate indication of temperature-induced changes to fluid loss values. HTHP values however, may noticeably increase at temperatures of 100 °C or more, depending on the fluid system and products being used. VSVA polymers have a molecular weight of 1 – 2 million. This provides moderate viscosification properties – a secondary function. The vinyl backbone and carbon-carbon bonds make it stable to over 200 °C. The sulfonate groups provide a strong charge density, allowing the polymer to be extremely tolerant to multivalent cations and also to function as a rheological stabilizer. VSVA polymers are tolerant to moderate solids concentrations and are able to stabilize sensitive shales to a degree. SSMA (Sulfonated Styrene Maleic Anhydride) is a short-chain synthetic co-polymer. It is a deflocculant used in solids-laden fluids where temperatures are high enough to limit the use of Lignosulfonates, Lignites and Polyacrylates. The carbon-carbon bonds make it stable to 260 °C. The sulfonate groups render it effective in electrolytic environments where Polyacrylaltes fail. This


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polymer is especially applicable in cement-contaminated systems where deflocculation is essential, especially in hot holes. Figure 5.35: Sulfonated styrene maleic anhydride (SSMA)

SO2O-Na+

OO

O-Na+

O-Na+


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REFERENCES 1 Fred W. Billmyre Jr., Textbook of Polymer Science 2nd ed. (New York: John Wiley

E. and Sons, 1971), 5; all subsequent citations are to this edition. 2 Darley and Grey, Composition and Properties, 179. 3 Yang S. H. and Triber L. E., Chemical Stability of Polyacrylamide Under Similar Field

Conditions. SPE paper 14232, September 1985. 4 Billmyre, Polymer Science , 24. 5 Jim J. Sheu and Charles Perricone, Design and Synthesis of Shale Stabilizing

Polymers for Water Based Drilling fluids. SPE paper 18033. 6 Browning, Lignosulfonate, Stabilized Emulsions in Oil Well Drilling fluids, JPT, June

1955.


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CHAPTER 6 FLUID LOSS CONTROL 6.1 KEY POINTS & SUMMARY 6.2 STATIC FILTRATION

6.2.1 Darcy's Law 6.2.2 Static Filtration 6.2.3 Practical Static Fltration 6.2.4 The Relationship Between Filtrate Volume and Time 6.2.5 The Relationship between Filtrate Volume and Pressure. 6.2.6 Filter Cake Permeability 6.2.7 The Influence of Particle Associations on Cake Permeability 6.2.8 The Effects of Temperature

6.3 DYNAMIC FILTRATION

6.3.1 Equations for Dynamic Filtration 6.3.2 Practical Dynamic Filtration 6.2.3 Filtration beneath the Bit.

6.4 FLUID LOSS CONTROL IN WATER-BASED FLUIDS

6.4.1 Bridging Solids 6.4.2 Cake Forming Solids 6.4.3 Product Selection

6.5 FLUID LOSS CONTROL IN OIL-BASED FLUIDS

6.5.1 Cake Formation 6.5.2 Colloidal Solids 6.5.3 Formulation for High Fluid Loss 6.5.4 Comparison of Static and Dynamic Filtration Rates.

6.6 RELATIONSHIP TO HOLE PROBLEMS

6.6.1 Differential Sticking 6.6.2 Formation Damage 6.6.3 Borehole Stability


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6.1 KEY POINTS & SUMMARY Whole fluids and filtrate lost into the formation during the course of drilling and completing a well may have a direct effect on one or more functions of the drilling fluid. These functions include the maintenance of borehole stability, the protection of producing formations, the reduction of friction and the improvement of penetration rates. Several mathematical models describe the relationship of filtrate loss to pressure, temperature and time. However, predicting dynamic filtrate loss rates from static values is difficult. The mechanisms of fluid loss reduction in all fluid types generally relate to the type, size and relationship between filter cake constituents. The viscosity of the liquid phase is also a factor. The selection of the proper combination of filtrate reducing mechanisms and additives may entail a substantial amount of background laboratory work. The on-sight evaluation of product performance and the implementation of well thought-out strategies can lead to a reduction in problems associated with fluid loss. 6.2 STATIC FILTRATION 6.2.1 Darcy's Law In the middle of the 19th century, a French engineer, H. D'arcy developed equations for the rate of flow of water through sand filtration beds. His work was expanded to include viscosity in the following equation: Equation 6.1, Darcy's law:

q = k A • P µ • l

Where: q = the flow rate A = the cross section area P = the pressure differential across the filter l = the length of the filter bed k = a constant related to the physical character of the filter bed µ = the viscosity A filter has a permeability of one Darcy when water, with a viscosity of 1 cp, flows at a rate 1 cm3 / sec through an area of 1 cm2 with a pressure gradient of 1 atmosphere per cm. The oil-field unit is the millidarcy (md) which is equal to 10-3 Darcy. 6.2.2 Static Filtration In the case of static filtration, the filter cake increases in thickness as the liquid fraction is removed by the filtration process. This leaves a filter cake containing solids and some liquid. As the filter cake grows in thickness, the filtration rate is reduced. It can be shown by integration of a differential from of equation 6.1, the cumulative filtrate volume as a function of time can be given by the following equation:


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Equation 6.2

qw2 = 2 • k • P •A2

µ • qw qc • t

Where: qw = the volume of the filtrate at time t qc = the volume of the filter cake (related to the thickness of the filter cake, L,

through the area of the filter cake, A) µ = the viscosity of the filtrate k = the permeability of the filter cake 6.2.3 Practical Static Filtration Equation 6.2 can be rewritten as: Equation 6.3:

qw = A • C1/2 • t1/2 Where C is a new constant incorporating the constant terms: Equation 6.4

C = 2 • k • P

µ • qw qc

These equations predict a linear correlation between the cumulative filtrate volume and the square root of time. These are plotted for a typical drilling fluid system in figure 6.1. The initial part of the curve deviates from the predicted straight line because of two factors. There may be an initial loss, termed the spurt loss. This occurs when an unrepresentative volume of filtrate, including solids is lost through the filter medium because there are insufficient solids to block the pores in the filter paper. The time allocated for measuring the spurt loss ceases when individual drops begin flowing from the discharge nipple. Secondly, error is introduced in the initial stages as the filter paper is wetted and the volume between the paper, wire mesh support and discharge point is filled. This varies with different types of equipment and the state of dryness of the equipment at the start of the measurement.


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Figure 6.1 Relationship between cumulative filtrate volume and time for static filtration If the spurt loss is greater than the void volume, the extrapolated linear part of the curve in Figure 6.1 has a positive intercept in the x axis. If the spurt loss is low there may be a negative intercept. In practice, equation 6.3 is modified to include this spurt loss, qo, so the equation becomes: Equation 6.5

qw - qo = A • C1/2• t1/2

The standard API filtration test cells for the filtrate volume to be measured at room temperature over a 30 minute period through a filter area of 45 cm2 and a differential pressure of 100 psi. 6.2.4 The Relationship Between Filtrate Volume and Time When a drilling fluid is filtered through paper at a constant temperature and pressure, the volume of filtrate is proportional to t . This relationship may be expressed algebraically as: Equation 6.6, Relationship between Filtrate Volume and Time:

q2 = q1 t2 t1

Where: q1 = The recovered volume of filtrate (cm2) t1 = The time at which q1, was measured t2 = The time at which a calculated volume of filtrate is required (usually 30 min.) q2 = The unknown volume of filtrate (cm3) at the time t2


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The 30-minute filtrate volume may be predicted by measuring the volume at 7.5 minutes and doubling the value, since:

30 7.5 = 2

Equation 6.6 may also be arranged to obtain a value for filtrate volume at 30 minutes, if the 30 minute time period has been exceeded.

q30 = q2 30t

Where: t = the time the sample was recorded q2 = the volume of filtrate at t1 q30 = the volume of filtrate at 30 minutes A factor called the zero error may be applied to these equations. This term is related to the discrepancy in the linear relationship shown in Fig. 8.1, where the curve does not intersect the orgin. Zero refers to the fluid loss at time zero, or the spurt loss. When correcting for spurt loss, equation 8.6 becomes:

q30 - q0 = (q30 - q0) t30 t1

Where q0 = the volume of spurt loss filtrate Certain API product specifications require a fluid loss value, including bentonite, drilling starch and CMC. When testing is conducted, the spurt loss and void volume effects are eliminated by measuring the fluid loss between 7.5 and 30 minutes, since this is the linear part of the curve. The volume is doubled to arrive at a valve comparable to the volume collected in 30 minutes. 6.2.5 The Relationship between Filtrate Volume and Pressure. Equation 6.2 predicts that the accumulated volume of filtrate, Qw, should be proportional to the square root of the applied pressure. A log-log plot of filtrate volume versus pressure should yield a straight line with a slope of 0.5. This relationship is not observed for drilling fluids because the filter cake is compressible to a degree that is dependent on the fluid type. The cake permeability decreases as pressure increases. The relationship may be expressed as: Equation 6.7:

q aPx Where x is the slope, x varies with the compressibility of the cake but is always less than 0.5. The effect of pressure on filtration rates is a direct function of the compressibility of the cake. Cakes formed from bentonite alone are so compressible that the slope may be zero and the volume of filtrate is constant with respect to pressure. This is due to the shape of bentonite particles and their tendency to align themselves parallel to the plane of pressure differential.


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Cakes formed from other clays have been found to have x exponents ranging from zero to 0.2. When angular solids are introduced into a fluid the value of the x exponent increases. In oil-based fluids there is an additional factor. This is the increase in the viscosity of the oil due to the increase in pressure. This tends to reduce the expected value of the slope as the pressure is increased. 6.2.6 Filter Cake Permeability The permeability of the filter cake can be determined by measuring filtrate volume and cake thickness at the end of the 30 minutes filtration period. This is not easy task due to the poor definition of the top of the filter cake. Equation 6.2 can be rewritten as:

k = qw • l • µ

2 • P • A • t

When l is given in millimetres, then for the standard API test: Equation 6.8:

k = qw • l • µ • (8.95) • 10-3 As an example, for fresh water where, µ is 1, a 2 mm thick filter cake and a fluid loss of 10 cm3, the filter cake permeability is 180 • 10-3md. Permeabilities of drilling fluid filter cakes are typically in the range 10-2 md to 250 • 10-3 md. Filtration tests against supports with different permeabilities have established that, the permeability of the filter cake is the controlling factor - where the formation has a permeability of about one millidarcy. Typical permeabilities of formations are given in Table 6.1 which shows that the fluid loss is critical in sandstones but not in shale formations. Table 6.1 Range of Permeabilities of Typical Formations Formation Type

Range of permeability, millidarcies

Very Coarse sandstone

5 000 - 10 000

Good oil production 10 - 1 000 Gas production tight sandstone 0.1 - 1 Filter cake 0.002 - 0.150 Shale 0.000001

6.2.7 The Influence of Particle Associations on Cake Permeability Colloidal particle associations in drilling fluid suspensions are discussed in the section on Clay Chemistry. It also dicusses the influence of various flocculants on fluid loss. When a clay suspension is flocculated it means that the degree of clay structure is increased. A loose, open network is formed. This network persists to a degree within the cake, increasing its permeability. In a deflocculated suspension, clay particles are free to lay flat. An overlapping, uniform distribution pattern is created against the plane of pressure differential. Deflocculating chemicals also serve to toughen the cake and enhance particle size distribution.


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In some cases the addition of water to the fluid may influence the nature of the particle associations and actually reduce the fluid loss. This may result from a reduction of the net cation concentration or as an aid to dispersion (more particles) in solids laden fluids. In a dehydrated suspension there is competition between all constituents for free water. When water is added, clays and polymers hydrate properly, contributing to lower fluid loss values. Cake permeabilities of flocculated fluids may be in the order of 10-2 md, those of untreated fresh-water fluids in the order of 10-3 md, and fluids treated with thinning agents, in the order of 10-4md.1 6.2.8 The Effects of Temperature The volume of filtrate varies with the square root of the viscosity of the liquid phase: Equation 6.8:

q2 = q1 viscosity1 viscosity2

Where: q2 = unknown filtrate volume at viscosity1 (cm3) q1 = known filtrate volume at viscosity2 (cm3) Theoretically, decreasing the viscosity will increase the fluid loss. Table 6.2 shows the effect of temperature in the viscosity of water and 6% NaCl brine. Using Equation 6.8 and Table 6.2 it can be seen that the filtrate volume would be increased from 10 cm3 to 14 cm3 if the temperature were increased from 10°C to 40°C in a water-based system:

14.19 = 10 1.308 0.656

Table 6.2 The Viscosity of Water and 6% Sodium Chloride Brine at Various

Temperatures

Temperature

(°C)

Temperature

(°F)

Viscosity water

(cp)

Viscosity Brine

(cp)

0 32 1.792 -

10 50 1.308 -

20.2 68.4 1.000 1.110

30 86 0.801 0.888

40 104 0.656 0.733

60 140 0.469 0.531

80 176 0.356 0.408

100 212 0.284 -


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Temperature

(°C)

Temperature

(°F)

Viscosity water

(cp)

Viscosity Brine

(cp)

140 284 0.196 -

160 320 0.174 -

180 356 0.150 -

200 392 0.134 -

220 428 0.121 -

260 500 0.1004 -

300 572 0.086 -

This viscosity relationship doesn't have a practical application for real drilling fluids. In clay suspensions an increase in temperature can contribute to better hydration and dispersion of commercial clays, ultimately reducing the filtrate volume. At higher temperatures, the viscosity effect may be compounded by several factors. The increased solubility of contaminating ions increases the effect of flocculation on cake permeability. The thermal flocculation of suspended clays also increases filtrate volume. The degradation of most organic filtration control additives usually begins when temperatures exceed 100°C, continuing at a non-linear (increasing) rate as temperature increases. Accurate prediction of filtrate volumes at elevated temperatures can't be made from measurements recorded at lower temperatures. Therefore, most operators require that high temperature, high pressure (HTHP) fluid loss and cake values be reported when static downhole temperatures exceed 50 - 60°C. Using the actual bottom-hole temperatures for testing gives the most realistic results if establishing a trendline is required. 6.3 DYNAMIC FILTRATION 6.3.1 Equations for Dynamic Filtration It is generally accepted that downhole filtration rates are higher under dynamic conditions than they are under static conditions. This is because the filter cake build up is not a continual process. At some point, it begins to become eroded by the flow of fluid past it. H. D. Outman´s equation for dynamic filtration is expressed as: Equation 6.9 Dynamic filtration:

q = k1(τ /f)-v+1

µl(-v+1)

Where: k1 = the cake permeability at 1 psi τ = the shear stress exerted by the fluid f = the coefficient of internal friction of the cakes surface


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µ = viscosity l = the equilibrium cake thickness (-v+1) = a function of the compressibility of the cake Experimental conditions used in laboratories have been so diverse that a critical evaluation of this equation isn't possible. However, in general the predicted output values have been supported. Since the thickness of the filtercake is limited by mechanical erosion, the viscosity factor may be more important in dynamic filtration than in static filtration. 6.3.2 Practical Dynamic Filtration Figure 6.2 depicts H.D. Outman's static and dynamic filtration and cake thickness regime in a borehole. When the formation is first exposed there is an initial spurt loss of whole fluid until the pores are bridged by solids. The cake then builds in thickness to an equilibrium point. During this stage cake formation is influenced by pressure (compressibility) and the erosion and redepositing of particles into it. When the equilibrium cake thickness and permeability is reached the relationship between filtrate volume and time becomes linear. Studies have indicated that the time required to reach equilibrium dynamic filtration rates vary from 2 hours to over 25 hours.

Figure 6.2 Relative static and dynamic filtration in the borehole. (From Outmans. Courtest Soc. Petrol. Eng. J. Copyright 1963 by SPE-AIME)

It has been commonly observed that the filtration rate increases as the flow rate increases as predicted in Equation 6.9. The means of obtaining the shear rate and the fluid loss rate varies from experiment to experiment. In some studies, the fluid is pumped in an annulus and in others, the shear is generated by a mechanical wiping action. Annular velocities vary and in some tests the flow is turbulent.


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Most studies have shown that there is a general correlation between static and dynamic fluid loss. However, there have been cases where a decrease in the dynamic rate occurred when annular velocity increased. Increases in the dynamic rate have been observed where concentrations of fluid loss additives including polyacrylate, CMC and starch have been increased. (This effect is less noticeable when a static cake has been deposited first.) Studies have also indicated that although the addition of diesel oil to water-based fluids reduces the API fluid loss value, the downhole dynamic fluid loss usually increases substantially. One study by Kueger using a bentonite-based fluid with different additives showed that there was a considerable difference between the performance of the additives. For example a dispersed lignosulfonate fluid with an API fluid loss of 11.0 cm3 had the same dynamic fluid loss as a starch fluid with an API fluid loss of 4.0 cm3. At the same static fluid loss value, the three fluids had differential dynamic rates that ranged from 0.7 cm3/hr for starch, 1.0 cm3/hr for CMC and 1.8 cm3/hr for polyacrylate. Other work has shown that some polymer-based fluids had much lower dynamic fluid losses than bentonite fluids. This was associated with the effect of the viscosity of the liquid phase in polymer fluids. The effects of high temperatures on dynamic filtration are considered to be comparable to those observed with static filtration. Mass balance (water consumption) studies have indicated that real dynamic fluid loss rates are usually lower that those predicted from Equation 6.9. In reality, experience dictates which HTHP or API fluid loss values are required to successfully penetrate specific formations in certain areas. The units used to report the dynamic fluid loss have not been standardized and comparisons between reported values are difficult. A standard flow rate and differential pressure have not been defined. The dynamic fluid loss rate should be expressed as cm3/45 cm2/30 minutes so that comparisons can be made with the static API test. 6.2.3 Filtration beneath the Bit. Because of the abrasive action of the bit teeth and the erosive effect of the jets, very little filter cake forms on the bottom of the hole. Filtration beneath the bit is restricted to an internal mud cake that forms in the pores of the rock just ahead of the bit.2 Equation 8.10 has been used to predict filtration rates at the bottom of the hole while drilling. Equation 8.10, Bottom hole filtration:

q = pD2 4

n • RPM C

Where: q = filtration rate (cm3/s) n = number of cones RPM = bit revolutions/minute C = a constant incorporating permeability, pressure and viscosity Studies which have examined filtration rates beneath the bit show no apparent correlation to API or HTHP filtration rates. A theory, the chip hold-down pressure (CHDP) relates the differential pressure between the fluid column and the formation pore pressure to the bit's penetration rate. As the theory relates to dynamic conditions, the filtration characteristics of the drilling fluid may apply. This theory postulates that when a bit tooth penetrates, and a chip is removed, the void space must be filled


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with fluid. If the fluid enters the space the "instant" the rock is fractured the chip is easily removed. If a longer time is taken to fill the fracture, the chip becomes subjected to the full weight of the fluid column - becoming more difficult to remove. The fluid's spurt loss may be the most important filtration characteristic when dynamic CDHP is considered. 6.4 FLUID LOSS CONTROL IN WATER-BASED FLUIDS 6.4.1 Bridging Solids In order to prevent the loss of whole fluid, a filter cake must be formed on a porous formation. Solids help to bridge the pore throats. It been shown that the smallest particle that can block a pore throat has a diameter one third the pore throat opening, as shown in figure 6.3.

Figure 6.3 Minimum size of particles to block a pore Whole drilling fluid may be lost to the formation before a sufficiently large number of particles have lodged on the pore throats. This loss is the spurt loss. The required diameter of the bridging solids can be obtained from the relationship between the diameter of the pores and the permeability. In conventional sandstone formations, the pore throat diameter in microns approximates the square root of the permeability measured in millidarcies. Thus, a 100 millidarcy sand will have a pore throat diameter of about 10 microns. This throat will be bridged by a three micron diameter particle. For most formations the solids present in barite and clay are able to form the bridge. When designing non-damaging, work-over and completion fluids the pore throat size is usually known. When determining the required bridging material and its size, it is important to consider the particle size distribution curve. For a given particle size, a wide curve could be more effective - even at a lower concentration, than a narrow curve (see figure 6.4).


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Figure 6.5 Particle size distribution curve

Loses in more permeable formations such as coarse sands, fractures and vuggy formations may require the addition of lost circulation material. A large variety of materials have been used to prevent or cure lost circulation. 6.4.2 Cake Forming Solids The concentration of solids, their size distribution, shape, and the association between the particles are all important factors which affect the permeability of the filter cake. The ideal size arrangement would be a log normal distribution from the bridging size down to sub-micron sizes. Each size range creates a new pore system which in turn needs to be blocked by finer solids. This continues down to the sub-micron size range. This effect is achieved in a weighted fluid treated with bentonite, but may be deficient in low density fluids that containing only drilled solids. Equation 6.2 can be rewritten to relate the fluid loss to the volume fraction of solids in the filter cake, Cc, and the volume fraction of solids in fluid Cm: Equation 6.11 Fluid loss vs cake solids

qw = (Cc / Cm - 1)1/2 This equation states that there should be a linear relationship between the fluid loss volume, qw, and the factor (Cc / Cm - 1)1/2. Figure 6.5 depicts a practical view of both the particle size distribution and the extent of filtrate invasion in a porous formation.


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Figure 6.5 Particle size distribution in a filter cake

6.4.3 Product Selection When considering fluid loss reducing additives in water-based fluids, it is important to understand that there are no set laws governing their selection. A drilling fluid program may require a combination of two additives on one interval, and a completely different additive on the next. A sea water / polysaccharide fluid may exhibit an acceptable inherent fluid loss, requiring no augmentation from other products. A flocculated KCl / polyacrylamide fluid may derive its fluid loss characteristics from several additives. Once the required API or HTHP fluid loss value has been determined the selection of the proper additive must include the following consideration: 1. Will it tolerate higher electrolytic conditions? Some polymers, including CMC

and polyacrylate don't exhibit good fluid loss reducing qualities in the presence of high concentrations of soluble salts.

2. Will it tolerate the expected static bottom hole temperature? Most organic

polymers begin to degrade when they are exposed to temperatures above 100°C.

3. Can it be used in a weighted system? High solids concentrations may limit the

availability of free water in a system and / or effect rheological properties. Fluid loss control additives requiring comparably higher concentrations, such as starch may not be feasible. On the other hand, polyacrylates and lignosulfonates may effectively reduce the fluid loss and control rheology.


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4. Does it require a preservative? When a fluid loss additive has the potential to bacterially degrade it becomes necessary to add a biocide. Biocides must be environmentally acceptable, and maintained at specified concentrations.

5. Will it aid in minimizing formation damage? Producing formations may be

invaded by filtrate containing unsolublilzed polymers. Those polymers having an acetal linkage in their repeating unit may be broken more efficiently at a later stage.

6. Is it the most cost effective product? If more than one additive meets the

above criteria, then availability and economics dictate the selection. There are several situations where the addition of two or more products compliment each other providing a net cost reduction.

In order to reduce the permeability of the filter cake, there must be some colloidal particles present. Bentonite forms an effective particle, with many of the particles being less than 0.05 microns. Their thin plate-like shape allows them to act like tiles on a roof. The associations between the platelets can, however be substantially altered as the chemical environment is changed. As the salinity increases, the effectiveness of bentonite as a fluid loss additive decreases and other colloidal solids must be added. An effective product in salt water conditions, up to saturation, is pre-gelatinized starch. Starch releases many water swollen sub-micron sized particles into suspension. Derivatives of lignin, such as sulfonated resins, form colloidal particles in solution and reduce the permeability of a filter cake. Polymers adsorbed onto clay particles can act as fluid loss additives, particularly under extreme conditions of temperature and high salinity. Equations for both static and dynamic fluid loss show an inverse relationship between the fluid loss and the viscosity of the filtrate. An additive that increases the viscosity of the filtrate usually lowers the filtration rate. In practice this situation may be synergistic because the pores in a well developed filter cake may approach the actual size of the hydrated "water soluble" polymer. Thus the polymers are concentrated at the pore throat contributing to the bridging effect. This applies to polymers such as high viscosity carboxymethylcellulose (CMC), high viscosity hydroxyethylcellulose (HEC) and xanthan gums. Another synergitic mechanism can be illustrated from the fluid loss characteristics of calcium carbonate and HEC both alone and together as detailed in Table 6.3. Neither the polymer or the calcium carbonate provide any fluid loss control, but together the calcium carbonate provides a fine enough support for the polymer to more effectively prevent the flow through the filter cake. Table 6.3 Properties of Calcium Carbonate and HEC Solutions

Formulation PV Properties YP, Pa

Fluid loss

1 kg/m3 HEC in salt water 20 22 91.5

9 kg/m3 CaCO3 in salt water 1 0 No control

1 kg/m3 HEC + 9 kg/m3 CaCO3 17 9 8.2


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Table 6.4 lists some applications of some common water soluble fluid loss reducers. This table does not constitute a complete picture since some of the products mentioned may be altered chemically to extend the range of their performance abilities. Table 6.4 General table relating polymer selection to cost-effectiveness in water-based

systems.

Starch

CMC hi-vis

CMC lo-vis

PAC hi-vis

PAC lo-vis

Lignite family

Polyacrylate

Fresh water ok good good ok ok good x

Sea water good x x good good good good

High calcium ok x x ok good good x

High temperature x x x x x ok good

High solids x x ok x good good good

Bacteria x good good good good good good

Producing formations good ok good ok good x x Prior to drilling, if questions pertaining to product selection remain, laboratory testing may be necessary to determine the most effective additives. This usually involves testing the performance of proposed additives under various influences including time, temperature and pressure. During the course of drilling, situations may arise which demand an on-sight re-evaluation of product use. These situations include high concentrations of colloidal solids, electrolytes, increased temperatures etc. It is always necessary to first pilot test the effects of each change in even product or concentration implemented. Some polymers develop viscosity in the presence of salt, while others become ineffective at high concentrations and others fail to perform in the presence of certain ions. 6.5 FLUID LOSS CONTROL IN OIL-BASED FLUIDS 6.5.1 Cake Formation Most aspects of fluid loss control in oil-based fluids are comparable to those in water-based fluids. However, there are some important differences which generate quite different fluid loss properties and give oil-based fluids important advantages. Solids must be present to form the bridge and pack together to form a cake as in water-based fluids. These are typically composed of weighting agents, clays, asphalt derivitives and drilled solids. These solids are made oil wet by the presence of the surfactants. (They repel water and attract oil.) 6.5.2 Colloidal Solids The emulsified water droplets in oil-based fluids effectively act as deformable particles. Having diameters less than one micron, they form excellent plugging agents. They are surrounded by


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surfactant molecules and are repelled from oil wetted surfaces through interference of the hydrocarbon chains. Evidence of this mechanism comes from observations. These include the fact that the fluid loss decreases as the water content increases, and the addition of oil wetting surfactants help to prevent water from coming through with the oil in the filtrate. Conversely, if a high fluid loss is required, then the level of surfactants is reduced. Apart from emulsified water, other colloidal particles are present. The amine treated clay added for viscosity also provides particles that act as filter cake plugging agents. Amine treated lignite derivatives and finely ground asphalts may also be added to increase the level of oil-wetted colloidal sized particles. 6.5.3 Formulation for High Fluid Loss In some situations, the naturally low fluid loss characteristics of oil-based fluids has led to particularly low penetration rates when compared to drilling with equivalent density water-based fluids. (This problem has been reduced to a degree by the introduction of polycrystalline diamond bits.) It was found, particularly when drilling hard rock, that oil-based fluids having a high fluid loss improved the penetration rate. The API filtration rate of an oil-based fluid can be adjusted so that it is zero. A measurable filtrate volume can only be obtained with higher temperatures, where the viscosity of the oil is lower, and higher pressures, such as 500 psi rather than 100 psi. If the colloidal solids are left out of the formulation and lower levels of emulsifiers or different emulsifiers are used, the fluid loss can be increased up to 30 cm3 in the API test. The lower state of oil-wetting of the filter cake solids allows more oil and water to penetrate the filter cake. 6.5.4 Comparison of Static and Dynamic Filtration Rates. Recent studies examining the relationship between the static and dynamic fluid loss in oil-based fluids have found an initial dynamic fluid loss that was of the same order of magnitude as the static fluid loss. When measured in the same units of cm3 /30 min/45 cm3, both were in the range of 2 - 10 cm3 with a differential pressure of 500 psi and a temperature of 120°C. 6.6 RELATIONSHIP TO HOLE PROBLEMS 6.6.1 Differential Sticking Differential sticking occurs when the drill collars or bottom hole assembly, lie against a portion of the hole when the pipe is stationary. The fluid in the filter cake is forced into the formation increasing the contact area between the pipe and the filter cake. There is potential pressure (pm - pf) acting to force the pipe against the wall. This is the difference in the pressure exerted by the fluid column (pm) and the pore pressure (pf) in the formation. This pressure is increased at higher hole angles. The force require to pull the pipe free is given by the following equation: Equation 6.11:

F = A (pm - pf) U where: F = the force A = the contact area U = the coefficient of friction between the collars and the cake.


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In practice the pressure is not as high as that given in the equation because the pore pressure close to the wellbore is higher than the formation pressure. Also, the pores have usually been damaged by the filter cake. Reduction in the contact area can be made by use of fluted or spiralled drill collars and stabilizers. The fluid density should also be kept to a minimum value consistent with well control requirements. Differential sticking usually occurs in porous sand formations. Hence, it is important for drilling fluid engineers to be aware of filtration and, especially, cake characteristics when drilling through sand formations. On-sight evaluations often lead to adjustments to these characteristics, thereby avoiding the problem. The coefficient of friction of the filter cake can be reduced if the filter cake is thin and the lubricating properties are well developed through the addition of lubricants. Oil-based fluids exhibit properties which minimize the chances of becoming differentially stuck. The fluid loss values can be low, filter cakes are thin and the high concentration of surfactants and water droplets in the filter cake make its coefficient of friction very low. In water-based fluids, differentially stuck pipe is usually freed by spotting oil. The oil will not enter the pore system of a water-based fluid, so the pressure exerted by the fluid column can compress the filter cake and reduce the contact area. The oil should be weighted to the same density as the drilling fluid to keep it from migrating. The effectiveness of the oil may be enhanced with the addition of specialized surface active compounds. 6.6.2 Formation Damage Formation damage and the design of drilling and completion fluids for production zones is discussed in detail in its own chapter. The two main concepts are firstly, that the volume of the filtrate should be minimal so that the depth of invasion will not be small and secondly, that the filtrate which does invade the production zone should not alter the permeability of the formation. While drilling in the production zone, there should be an adequate concentration of bridging solids of appropriate size. Porous formations can then be quickly sealed off and whole fluid invasion can be limited. This is important because colloidal sized particles in the fluid can cause formation damage. Solids that are added are sometimes chosen so that they can be removed at some later stage. Sized salt crystals are added to brine systems as these can be removed by fresh water washes. Calcium carbonate may be added as it can be removed with an hydrochloric acid wash. Resins may be added if an oil soluble bridge is desired. It is important to add solids so that a competent filter cake can be formed. A proper cake will help to clean the invading filtrate of damaging colloidal sized solids and polymers. Consideration should also be given to the possible reaction between the filtrate and the formation fluids and solids. For example, the pore fluids of some formations contain concentrations of soluble barium. This can be precipitated to form a damaging scale of barium sulfate, if the drilling or completion fluid contains sulfate ions. Some formations contain significant quantities of clay minerals in the pore throats. An alkaline or fresh water filtrate can disperse these clays, causing them to block the pore throats. Several other examples of relations between filtrate and formation fluids are discussed in Chapter 15, Production Zone Drilling. Low fluid loss and a thin filter cake will also minimise these effects.


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6.6.3 Borehole Stability The topic of Borehole Stability is considered in Chapter 10, where the influence of system design on the stability of the formation is discussed. A key to maintaining borehole stability is that the rocks are partially supported by the pressure exerted by the fluid. Further, the fluid or filtrate should not react with the rocks. Theoretically, these objectives will be met if a dense enough fluid could lay down an impervious coating on the hole wall as the hole is drilled. It has been found that control of fluid loss in formations such as shales (where permeability of the rocks is less than of the natural filter cake) can add to the stability of the formation. Also, movement of the formation into the hole creates a zone where the permeability is higher due to the formation of micro-fractures. If these fractures can be sealed then the partially failed rock can be supported by the fluid's weight. Inhibitive polymeric muds such as the partially hydrolyzed polyacrylamide (PHPA) will act in this manner. Additives such as gilsonite and sulfonated resins will also act to seal the fractures, particularly in the more brittle formations.


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References 1 Darley & Grey, Composition and Properties, 298. 2 Darley & Grey, Composition and Properties, 310.


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CHAPTER 7 WATER-BASED FLUIDS 7.1 KEY POINTS AND SUMMARY 7.2 HISTORY OF WATER-BASED FLUIDS 7.3 DRILLING FLUID SELECTION

7.3.1 Categorizing Water-Based Fluids 7.3.2 Selecting a Drilling Fluid 7.3.3 Planning a Drilling Fluid Program

7.4 COMPONENTS OF WATER-BASED FLUIDS

7.4.1 Make-Up Water 7.4.2 Weighing Agents 7.4.3 Viscosifiers and PHB 7.4.4 Filtration Control Additives 7.4.5 Rheology Control Additives 7.4.6 Shale Stabilization Additives 7.4.7 Lost Circulation Materials 7.4.8 Conditioning Chemicals 7.4.9 Inorganic

7.5 WATER-BASED SYSTEMS

7.5.1 Mixing, Converting and Displacing 7.5.2 Spud Mud 7.5.3 Low-Density Fluids 7.5.4 Clear Water Systems 7.5.5 Gel-Based Systems 7.5.6 Salt Saturated Systems 7.5.7 Calcium Systems 7.5.8 KCl Systems 7.5.9 Aluminum Sulfate Systems 7.5.10 PHPA Systems 7.6 Ava Drilling fluids Systems

7.6.1 Spud Muds 7.6.2 Water Drilling 7.6.3 Bentonite / Chemical Muds 7.6.4 Dispersed Muds 7.6.5 Inhibitive Drilling Fluid Systems


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7.1 KEY POINTS AND SUMMARY Today, so many different types of water-based systems are in use that it is difficult to list or even categorize them all. This chapter attempts to offer ideas and assistance to those with the task of selecting a drilling fluid and planning a drilling fluid program. Various components of drilling fluids are included and described, as a quick reference for those experienced in drilling fluid engineering or as an aid for those beginning their careers. The final part of the chapter describes some of the systems currently being used by Ava Drilling Fluids. A brief history of the generic fluid is followed by a description of how to mix and maintain some of Ava's specific systems. 7.2 HISTORY OF WATER-BASED FLUIDS The use of water to aid in the removal of the cuttings generated by percussion drilling dates back to 1,000 B.C. in China. The use of water as a cuttings removal medium for rotary drilling was patented in the United States by Robert Beart in 1844. In 1887 M.J. Chapman patented a clay containing mixture for its "plastering properties". The wall-building characteristics of clays soon became recognized throughout the U.S. and by 1913 the higher density of clay fluids was seen as means of pressure control. In 1922 Barite was used to increase the specific gravity of drilling muds. U.S. patent was issued for the addition of heavy minerals to drilling mud in 1926. This ushered in the primary age of drilling fluids technology. During the 1920's, specific products were developed to treat or improve certain properties of drilling fluids. In 1928, Bentonite as an additive for overcoming hole problems gained widespread use. By 1929 a specific blend of Barite and Bentonite was made available and in 1930 the first proprietary thinning agent was introduced. The next three decades saw a remarkable increase in drilling fluids research and development. This came about as the industry saw that improvements in drilling fluids technology benefited both drilling and production economics. This was a time when a variety of drilling fluid systems were developed, some of which are still in use today. Because these systems used a wide range of components, and retained different properties, the development of testing procedures and techniques also began at this time. During this period the majority of the technological advancement in drilling fluids occurred in the United States. The use of dissolved salt for control of borehole stability was patented in 1931. Salt systems were developed and used extensively in the 1930's. The use of salt systems promoted using pre-hydrated Bentonite, Attipulgite clay and Gelatinized Starch. In the late 1930's high pH fluids were used because of their superior flow characteristics and tolerance for drilled solids. High pH fluids were the predecessor of the "lime muds" used in the 1940's and early 50's. The 1950's saw the development and advancement of oil emulsion fluids, low solids fluids viscosified with CMC, and gypsum treated fluids. Gyp fluids were developed in Western Canada as a means of drilling anhydrite formations. This marked an end to the absolute U.S. domination of the advancement of drilling fluids technology. The 1960's and seventies saw the industry turn its attention toward the development of synthetic polymers, inhibitive fluid systems and invert emulsion systems, discussed in Chapter 8. Polymer-extended gel systems were introduced in 1960. Also in that year, the use of Potassium as an inhibitor was successfully applied in Venezuela. In 1967 KCl / Gel / XC Polymer fluid was used to drill permafrost in Northern Canada. Shell Polymer Mud (SPM) was being developed for use in


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the 1970's in Western Canada. This was the first KCl / PHPA fluid. PHPA systems became common in many other areas during the 1970's. In the 1980's increased attention was directed toward environmental concerns. New low-toxicity products and systems were developed, including low-tox oil-based fluids and phosphate fluids. The issue of hot holes was also addressed, resulting in the development of exceptionally tolerant products and systems. This Manual addresses both, low-tox oil-based systems, and high temperature water-based systems. The age of horizontal drilling required better lubricants with modified rheological properties. These requirements were often combined with a non-damaging fluid system application. Table 7.1 classifies various drilling fluid systems by the decade in which they gained acceptance and became widely used in our industry. The 1990's and beyond hold increasing challenges for the advancement of drilling fluids technology. TABLE 7.1 THE EVOLUTION OF DRILLING FLUID SYSTEMS 1890 - 1920

Water / Clay

1920's

Water / Barite / Bentonite

1930's

Salt Systems

1940's

Lime Systems

1950's

GYP Systems Oil Emulsions

1960's

Low Solids Systems Invert Emulsions

1970's

KCl / PHPA Systems

1980's

High Temperature Formulations Lo-Toxicity Invert Emulsions


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7.3 DRILLING FLUID SELECTION 7.3.1 Categorizing Water-Based Fluids Throughout the short history of oil well drilling fluids, various authorities and suppliers have classified fluids systems into various broad categories. This exercise becomes increasingly difficult as the selection of various systems becomes more diverse. Table 7.2 shows how three separate authorities have recently classified water-based fluids. TABLE 7.2 CLASSIFYING WATER BASED FLUIDS Composition & Properties of Drilling & Completion Fluids*

World Oil (After API and IADC)

United States Environmental Protection Agency Approved Generic Fluids Systems

Air / Mist / Foam

Air / Mist / Foam

Seawater / Potassium / Polymer

Water Dispersed Seawater/Lignosulfonate

Spud Mud Non-Dispersed Lime Mud

Salt Water Systems Calcium Treated Non-Dispersed Mud

Lime Systems Polymer Systems Spud Mud

Gyp Systems Low Solids Seawater / Freshwater Gel Mud

CL-CLS Systems Saturated Salt Lightly Treated Lignosulfonate Freshwater / Seawater Mud

Potassium Systems Workover Lignosulfonate Freshwater Mud

Oil-Based Fluids Oil-Based Fluids

* Gulf Publishing Company, Houston, Texas Others classify water-based systems more broadly. These include: 1. Salt Water / Fresh Water 2. Dispersed / Non-Dispersed 3. Inhibitive / Non-Inhibitive 4. Clay Fluids / Polymer Fluids A problem exists in that sometimes the systems or functions fall into more than one category. For example, when a fresh-water system is densified to stop overpressured shales from spalling, it also becomes a type of inhibitive system. Most drilling fluids systems today are flexible. That is, all water-based systems can be dispersed, most Bentonite systems contain some polymer - even if it’s the peptizing agent, and most


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polymer systems contain at least some (formation) clay. A PHPA system is an inhibitive system and a polymer system, in salt or fresh water, but PHPA may also be a component of a Gel and a potassium system. Today, drilling fluid systems are often generically classified by their density, base fluid, and principal ingredient, for example: 1. Unweighted Gyp - PAC 2. Fresh water - Gel 3. Weighted - Seawater - Polymer The drilling fluid systems described later in this chapter are included because they are frequently used by Ava. 7.3.2 Selecting a Drilling Fluid As oil wells become more difficult to drill, the problem of selecting the best drilling fluid can become fairly complex. Today, there are so many fluid systems available that the analysis is sometimes computer assisted. There are no approved criteria for drilling fluid selection. Different operators have their own policies and processes. Often one operator will identify and successfully use a drilling fluid system adjacent to another operator using a different system, just as successfully. The worst case occurs when a fluid system must be replaced, or when a drilling operation fails because an inappropriate fluid system was chosen. Contingency planning should be a part of all drilling fluids programs. Time spent mixing, circulating or conditioning drilling fluids due to an oversight in the planning phase can be expensive. Mixing, displacement and spotting procedures should be carefully planned in advance to avoid lost time. The most efficient selection of casing setting depths is often influenced by the ability to drill and case formations with the same density and type of fluid. Often an interval has an engineering-oriented or geology-oriented objective. A good drilling fluid will aid in meeting these objectives and often enhance them. Engineering parameters are extended if interval lengths can be increased, and if geological evaluation can be improved with proper fluid formulation. Thus, if the selection of a drilling fluid system seems complicated, it is often advantageous to initially consider each interval separately. Then a step-by-step process can be implemented in the search for the best fluid system. Ava suggests using the following steps. (Other operators and service companies use variations of this): 1. Define the objective of the interval. 2. Identify factors, which may prevent rapid and economical realization of the

objective. 3. Select a drilling fluid system(s) with respect to all of the demand criteria of the

interval. (Obviously, it would be best if one system could be used throughout the well).


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The first step, defining the objective of an interval is usually the easiest. Most intervals have engineering objectives. Various intervals are commonly called: 1. Top Hole 2. Intermediate Hole 3. Main Hole or Slim Hole Top hole or surface hole, may actually be up to three intervals. Offshore Arctic wells usually drill glory hole, conductor hole and surface hole. The engineering priority for top holes is to cement a string of casing (pipe) in place such that while drilling successive intervals, excessive sub-surface pressures must be directed up through it. Drilling fluid systems used to drill top hole are often called Spud Muds. Intermediate hole may consist of one or more intervals. The objective is to drill to the producing formation as quickly as possible. Geological evaluation is usually conducted as drilling proceeds. Sometimes engineering tasks such as kicking-off or steering are also performed on intermediate hole. Pressures and borehole stability often dictate the length of an intermediate interval. Sometimes an intermediate interval uses two types of drilling fluid systems such as in the Rocky Mountain region where air or clear water is used prior to "mud up". Often it isn't necessary to set intermediate casing - main hole is drilled from under the surface casing shoe. The main hole or slim hole is the interval that penetrates the producing formation. The objective is geological. The goal of an exploration well is to evaluate the production potential of a formation. With production wells, the objective is to penetrate the zone without damaging its ability to allow fluids to flow into the wellbore. (A good exploration well often ends up being a production well). Often engineering objectives must also be met on main hole. An example is a well drilled horizontally through a producing zone. The second step in drilling fluid selection involves identifying the factors, which might prevent the objective of the interval from being met in a timely and economical manner. It is the function or functions of the drilling fluid system to overcome these limiting factors. (See Chapter 1 for a review of the functions of drilling fluids). Some areas of concern are listed below: 1) Environmental & Safety Considerations 2) Abnormal Formation Pressures 3) High Temperatures 4) Excessive Deviation 5) Borehole Instability 6) Production Zone Damage 7) Others Usually formation damage or high temperatures are not a problem on top hole. However, it is possible for the other limiting factors to occur on any interval. A primary objective of any drilling fluid research is to instill environmental and safety considerations into system and product development. The same concerns apply when choosing a fluid system to drill with. In some locations, certain fluid systems are not environmentally acceptable. These might include - but are not limited to - salt systems, high pH systems or chrome containing systems. High temperatures, overpressures and excessive deviation are all conditions or problems, which can be minimized or alleviated with proper drilling fluid design. Usually the components and properties of water-based fluids begin to become adversely affected at temperatures above


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100°C. Water - based systems specially formulated to perform at high temperatures are discussed in a separate chapter of this Manual. Abnormal formation pressures rule out the use of low density, low cost fluids. On high angle wells, fluid formulation may have to be modified in order to enhance cuttings cleaning characteristics. Low shear rate viscosities, flow regimes and lubricity characteristics may be the most important fluid properties on these wells. The competency of the formation usually dictates the flow regime and thus the fluid system and properties. The problem of cleaning in inclined holes is discussed in the chapter on Rheology, Cleaning and Pressure Losses. Borehole stability problems can occur on any interval. The term borehole instability usually refers to holes becoming either bigger or smaller due to one of a number of possible causes. Some examples are listed below: 1) Gravel and Fractured Formations 2) Evaporate Formations 3) Tectonic Squeezing 4) Overpressured Shale 5) Zones Containing Gas Hydrates 6) Permafrost 7) High Formation Dip 8) Water Sensitive Formations The last example, water sensitive formation presents one of the most intricate issues when attempting to identify the potential problems in an interval. In a new field, it is important to obtain and analyze as much data as possible from various formations, so that future drilling fluid systems can be changed or modified appropriately. Prior to drilling offset wells, logs can provide data on formation dip, geology, temperature and pressure / fracture gradients, and in situ water content. While drilling, shale samples should be obtained for laboratory testing. A well-preserved core sample is by far the best source of data. The best swelling inhibition mechanism can often be predicted if data is analyzed properly. Analytical tests include: 1) X-Ray Diffraction 2) Cation Exchange Capacity 3) Balancing Salinity 4) Swelling Measurements 5) Dispersion Tests 6) Various Types of Stress Tests Samples may be tested in different fluids using different inhibition mechanisms, various concentrations of chemicals or even a combination of 2 mechanisms. (In a KCl / Polymer system the encapsulating polymer uses a physical mechanism while the potassium ion uses a chemical inhibiting mechanism). Often a reduction in cake permeability and fluid loss is all that is required to control problems resulting from water sensitive clays. Selection of the proper fluid loss additive is discussed in Chapter 5 and Chapter 6. The chapter on Borehole Stability (10) makes it clear that hole instability is a complex problem, especially when the relationship between drilling fluid chemistry and borehole stability is addressed. The objective of main or sum hole is usually to penetrate the zone of interest for evaluation or exploitation purposes. Proper evaluation or full production may be affected if the wellbore fluid causes production zone damage. The chapter on Production Zone drilling, (14) expands on the following damage mechanisms and how they can be avoided:


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1) Water Block 2) Emulsion Block 3) Oil Damage to Gas Reservoirs 4) Particle Invasion 5) Precipitant Formation Other common problems, which may impede achievement of the objective on any interval, include: 1) Severe Loss Zones 2) Water Flows 3) H2S (also a safety consideration) 4) Bacteria 5) Differential Sticking 6 The Formation of Hydrates (safety also) 7) Special Logging Requirements The third step, deciding on a system, is a matter of assessing the available options, keeping in mind the demand criteria of each interval and any environmental regulations. Shale analysis often points towards one obvious choice - such as oil-based fluid. When several alternatives exist, different factors can help narrow the choice down. The most obvious is to attempt to choose a fluid, which can be used on most or all of the intervals. Other eliminating factors are listed below: 1. Safety - Personnel - Environment - Equipment 2. Logistics - Remoteness of Location & Transportation - Season - Weather Conditions - Using the Least Number of Fluid Systems per Well - Complimentary Equipment Requirements - Testing & Lab Equipment - Bulk-Handling Equipment - Mixing Equipment - Solids Control Equipment - Storage Facilities - Cuttings Treatment Equipment - Filtration Equipment 3. Economics - Availability of Base Fluid & Chemicals - Maintenance Costs - Buy-back Possibilities - Disposal Problems 4. Bit Hydraulics and ROP Optimization 5. Past Experiences - Often aids in Selection, by a Process of Elimination


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7.3.3 Planning a Drilling Fluids Program Formulating a drilling fluids program is usually carried out in conjunction with the Operator's geology and engineering departments. Some Operators choose to formulate their own drilling fluids programs. Often they request one from a service company - sometimes as part of a bid package. The drilling fluid program should address all possible issues and propose appropriate contingency plans. It may include: 1. Engineering Parameters 2. A Lithological Description 3. Pore Pressure Prediction 4. Casing Setting Depths 5. A Well Profile with KOP and DOP 6. Proposed Fluids System - Usually by Interval 7. Chemical Concentrations 8. Required Fluid Properties 9. Lab Testing Results 10. Offset Well Information 11. Contingency Formulations and Procedures - LCM Pills - Barite Plugs - Viscosity Sweeps - Lubricity Pills - Procedures and Directives from Regulatory Agencies - Corrosion Control Program 12. A Materials and Volume Estimate by Interval 13. A solids Control Program 14. Price List The properties of the drilling fluid of particular importance are: 1. Density - Formation Pressure Control 2. Rheology - Optimum Cleaning and Hydraulics 3. Salinity or Polymer Content

4. Alkalinity 7.4 COMPONENTS OF WATER-BASED FLUIDS Classifying the constituent chemicals, which are blended together to make various drilling fluid systems, is a somewhat arbitrary task. This is because so many different chemicals affect more than one property or more than one function. An example is the affect that Lignosulfonate has on both the rheological properties and the fluid loss properties. In some systems PAC is the primary viscosifier, Gyp-PAC systems are used by some North Sea Operators. However, in an unweighted KCl/Polymer fluid the addition of even small amounts of PAC will cause deflocculation and loss of cleaning properties. The water-based fluid components described in the ensuing text can usually be added to most water-based systems providing the proper procedures are followed. It is the combination and proportions of these components, which make up individual fluid systems. This section has been included in this Manual as a quick reference. For more in-depth descriptions of water-based and other drilling fluid components, consult the Ava Product Data Book, or call you’re nearest Ava Technical Service Department.


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7.4.1 Make-up Water Water is the most important single substance involved in water based drilling fluids technology. The functions of water include; provision of the initial viscosity; solvation of salts, suspension of colloids and transfer of heat. The availability and chemical content of the make-up water must be considered in the planning stage of any well. Some of the unusual characteristics of water were discussed in the chapter on Basic Chemistry. They include: high surface tension, high heat of vaporization, the ability to form hydrogen bonds, the ability to cause dissociation of ionic crystals such as salts, and bases, and the fact that hydrated ions and particles exhibit modified properties. Water is essentially incompressible; therefore, increased resistance to flow due to volume reduction is negligible. The temperature effects on water's properties are also minimal, although temperature does have pronounced effects on the properties of water-based fluids. Unlike most other substances, water expands when it freezes under normal pressure. These characteristics of water affect each step in the drilling operation from spud to completion. In some locations the availability of fresh water eliminates the choice of certain fluid systems and dictates complementary equipment such as premix tanks. Often hard water must be treated chemically or fresh water must be fabricated from seawater before chemicals and products can be added. Fabricated water is called drill-water on offshore rigs. Brackish water and seawater contain a wide variety of solvated ions. For this reason it is often necessary to alter fluid system formulations when commercial products are added to seawater-based fluids. The obvious step is to designate a premix tank, for prehydrating Bentonite. However, the performance of many water-soluble polymers is also affected when they are used in a salty / hard environment. This applies especially to viscosifying and filtrate reducing polymers. Usually concentrations have to be increased to obtain properties similar to those obtained with fresh water. Table 7.3 shows the concentrations of some of the ions found in a typical seawater analysis. TABLE 7.3 TYPICAL SEAWATER ANALYSIS

ION

CONCENTRATION (mg/L)

Chloride 19 000 Sulfate 2 700 Bicarbonate 100 Bromide 60 Borate 25 Nitrate 0.7 Phosphate 0.1 Fluoride 1.3 Sodium 11 000 Magnesium 1 300 Calcium 400 Potassium 400 pH 7.5 - 8.5


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7.4.2 Weighting Agents Drilling fluids are densified or weighted up to perform one of two functions as outlined in chapter one. That is, to control sub-surface pressures or stabilize incompetent formations. For a material to be a viable solid phase weighting agent, it must have a high specific gravity, be non-abrasive, readily available, economical and safe. Table 7.4 lists the solid phase weighting materials supplied by Ava. TABLE 7.4 WEIGHTING AGENTS COMMERCIAL PRODUCT

MINERAL

PRINCIPLE COMPONENT

SPECIFIC GRAVITY

MOH'S HARDNESS

Calcium Carbonate

Calcium Carbonate

CaCO3

2.65 2.71

3

Ferrowate

Iron Carbonate

FeCO3

3.7 - 3.9

3.5 - 4.0

Barite

Barium Sulfate

BaSO4

4.2 - 4.5

2.5 - 3.5

Plus-5

Hematite

Fe2O3

4.9 - 5.3

5.5 - 6.5

Barite is by far the most common weighting material. It is easily dispersed, and virtually insoluble in water. It is almost completely inert in water-based systems and is relatively non-abrasive. Table 7.5 lists the API qualifications for Barite. Note the spec for calcium. Some impure grades of Barite contain quantities of Calcium Sulfate, which is a contaminant in water-based fluids. Volume II of this Manual contains equations for densifying with Barite. TABLE 7.5 BARITE REQUIREMENTS FOR API SPECIFICATION Specific Gravity: 4.20, minimum Wet Screen Analysis: Residue on U.S. Sieve (ASTM) no. 200: 3.0% maximum Residue on U.S. Sieve (ASTM) no. 325: 5.0% minimum Soluble Alkaline Earth Metals as Calcium: 250 ppm, maximum The other products are utilized because they have specific applications. Salts can be used to increase the density in water-based fluids to a limited density range. Salts can be used as solid phase weighting materials in saturated systems - see the chapter on Production Zone Fluids. The


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Calcium Carbonate products are used mainly as bridging or weighting materials for both oil and water-based production zone fluids. They are soluble in HCl. Galena isn't normally used in drilling fluids because it is expensive and it requires special handling. However, it is an excellent contingency product where control of a blowout is required. Slurries up to 3800 kg/m3 can be prepared with Galena. 7.4.3 Viscosifiers and PHB Viscosifiers are added to drilling fluids to improve their cleaning and suspension functions. Primary viscosifiers for water-based fluids are normally clays or polymers. Any primary viscosifier must interact with the base fluid to some degree. This is accomplished by the shape and / or surface changes on the particle or molecule. The best viscosifiers impart both psuedoplastic and thixotropic properties to a fluid. The selection of the most appropriate product is dependant upon economics, logistics and the expected fluid environment. Other chemicals including salts and bridging polymers may enhance the properties imparted by the primary viscosifiers. Table 7.6 lists some of the viscosifiers Ava supplies. It can be seen that all of the products are either clays or polymers. TABLE 7.6 VISCOSIFIERS TRADE NAME

MATERIAL

PRINCIPAL COMPONENT

APPLICATION

SECONDARY BENEFIT

Avabex

Polyacrylate

Acrylic Polymer

Bentonite Extender

Fluid Loss Reducer

Policell

Polyanionic Cellulose

Substituted Cellulose Polymer

Viscosifier - used in Special Applications (Gyp / PAC)

Fluid Loss Reducer

Avagel

Bentonite

Hydrous Aluminum Silicate

Viscosifier - May Require Pre-hydration

Fluid Loss Reducer

Natrosol

Hydroxy Ethyl Cellulose

Cellulose Derivative

Completion Brine Viscosifier

Minimal Damage

Visco XC 84

Xanthan Gum

Bio-Polysaccharide

Viscosifier - All Water Based Fluids

Fluid Loss Reducer

Visco XCD

Xanthan Gum

Modifed Bio-Polysaccaride

LSR Viscosifier

Fluid Loss Reducer

Avagum

Guar Gum

Natural Polysaccharide

Viscosity Sweeps in Large Holes

Drilled Solids Flocculant


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Bentonite is often used as the primary viscosifier in systems using seawater, produced brine, gyp or a commercial salt. In these systems Bentonite must be prehydrated in fresh water. The slurry is referred to as prehydrated Bentonite or PHB. When prehydrating Bentonite, 110 - 140 kg/m3 is usually added to fresh water. The clay yield can be improved if; the water is warm and well agitated, the calcium is removed and the pH adjusted to about 9. Several hours should be allowed for hydration and dispersion to occur. Often lignosulfonate is added to PHB to allow for the addition of extra Bentonite and to provide better stability (duration) in terms of viscosity and filtration characteristics in the saline environment. This is also a good way of maintaining a slight concentration of lignosulfonate in a flocculated system such as a KCl/Polymer fluid. Since lignosulfonate has clay encapsulating properties, as much Bentonite as possible should be added to the PHB mixture prior to adding the lignosulfonate. 7.4.4 Filtration Control Additives Filtration control additives are blended into water-based fluids to reduce the amount of liquid phase forced into the formation rock. Up to three different mechanisms are used by these products: 1. Reduction of cake permeability by deflocculation and compression. 2. Reduction of flow-rate by viscosification of the liquid phase. 3. Pore plugging. Thus, viscosifiers and deflocculants usually aid in fluid loss reduction. Often fluid loss reducing agents complement one another in a synergistic manner, similar to that of viscosifiers. Refer to the chapter on Fluid Loss for a more detailed description of fluid loss mechanisms. Table 7.7 lists some of the filtration control additives offered by Ava. For a complete list, refer to the Ava Product Data Book. TABLE 7.7 FILTRATION CONTROL ADDITIVES TRADE NAME

PRINCIPLE COMPONENT

APPLICATION

SECONDARY FUNCTIONS

Avalig Natural Coal Product Economical Filtration Control Deflocculation Avalig C Sodium Humate Filtration Control in High-temp.

Saline Evnironments Deflocculation

Victosal Modified Starch Filtration Control in Highly Saline Environments

Acid Soluble

CMC Carboxymethyll Cellulose Economical Filtration Control Some Viscosification

Policell Polyanionic Cellulose Filtration Control in Brackish Environments

Moderate Deflocculation in Unweighted Salt Systems

Avapoly HT Synthetic Polymer Filtration Control > 200°C Moderate Deflocculation


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7.4.5 Rheology Control Additives Rheology control additives are generally used to extend the performance limitations of water-based fluids. This usually means temperature limitations and solids concentration tolerance. These products are called deflocculants or thinners. Products which reduce the required concentration of a primary viscosifier are called extenders or flocculants. Deflocculants (thinners) reduce most rheological and thixotropic properties by decreasing the degree and strength of the colloidal particle associations in drilling fluid suspensions. On the other hand, flocculants increase the degree and strength of these associations. The chapter on Clay Chemistry provides a more detailed explanation of these mechanisms. Table 7.8 shows some of the deflocculants offered by Ava. TABLE 7.8 DEFLOCCULANTS C0MMERCIAL NAME

PRINCIPLE COMPONENT

APPLICATION

SECONDARY FUNCTIONS

SAPP

Sodium Acid Pyrophosphate

Powerful Deflocculant. Prevents Mud Rings

Calcium Precipitation

Avafluid G71

Ferro Chrome Lignosulfonate

Deflocculant in all Water-based Systems

Filtration Control

Avathin

Acrylic Acid

Deflocculant in all water based Systems

Filtration Control

Polifluid

Sodium Salt Polycarboxilc Acid

Effective Thinner Up To 250°C

Filtration Control

7.4.6 Shale Stabilization Additives The topic of borehole stability is so far reaching, it has been mentioned in most of the chapters in this manual. Shale stabilization itself is a broad term lacking definition and method. The preceding text, "Selecting a drilling fluid" mentioned several methods of determining the best stabilizer for water-sensitive clays formations. Depending on the specific nature of the shale, any of several available materials may impart favorable results. Mechanisms, which are recognized as contributors to borehole stability are: 1. Balanced Activity 2. Cation Exchange 3. Encapsulation 4. Plastering (Plugging Micro fractures) 5 Increased Fluid Density These mechanisms are discussed in the chapter called Borehole Stability. Table 7.9 shows some of Ava's encapsulating and plastering products, which contribute to the stabilization of shales.


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TABLE 7.9 SHALE STABILIZATION ADDITIVES Cation Exchangers: Potassium Calcium Aluminum Encapsulators: (Polyacrylamide) (Lignosulfonates) (Most PAC's) Plastering Materials: Gilsonite HT (Bituminous) 7.4.7 Lost Circulation Materials Lost circulation materials (LCM) are used to stop excessive losses of whole drilling fluid to permeable or fractured formations. Lost circulation materials are classified as flaky, granular or fibrous. Mechanisms for stopping losses include, matting, bridging and plugging. Many substances have been recommended for regaining circulation. Table 7.10 shows some of the lost circulation products supplied by Ava. Table 7.10 Lost Circulation Materials FLAKY

FIBROUS

GRANULAR

Kwik Seal OM Seal Sand Seal Mica Granular Avacarb

Flaky materials include cellophane, mica and wood chips. They are best for plugging and bridging porosity and microfissures. Fibrous materials include pulverized sugar cane stalks, cotton fibers and wood fibers. They work by penetrating and forming a mat on fractures or pores which other fluid solids can build on. Granular products include diatomaceous earth, ground walnut hulls and calcium carbonate. They work by plugging pores and microfissures. Many products contain a mixture or proprietary blend of these. Often, the choice of which product to use is based on trial and error, experimentation, or previous experience in an area. Lost circulation materials are often incorporated into various lost circulation plugs and slurries, including cement slurries, "gunk plugs" etc. In Chapter 16, the problem of lost circulation is discussed in greater detail. 7.4.8 Conditioning Chemicals Ava offers a complete array of conditioning chemicals for water-based drilling, completion and workover fluids, some of which are listed in Table 7.11. A close study of the table indicates that


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many of these products are used to alter fluid chemistry or properties, usually for the purpose of negating or minimizing various problems encountered while drilling with water-based fluids. TABLE 7.11 CONDITIONING CHEMICALSa

Alkalinity and pH

Surfactant

Lubricant

Corrosion Inhibitor

Bacteriacide

Foamers/ Defoamers

Spotting Fluids

Emulsifier

Caustic Soda Soda Ash

Avadeter

Ava Greenlube

Deoxy SS

Avacid 50

Avasil

Avatensio

Avoil PE

Lime Gypsum

Avasurfo

Avalube

Incorr

Avacid F/25

Avafoam S1

Deblock S

Avoil SE

Sodium Bicarbonate

Ecol Lube

Zinc carbonate

Avoil WA

Potassium Hydroxide

Avades 100

a Descriptions of these and other conditioning chemicals are found in the Ava Product Data Book pH and alkalinity control many drilling fluid system properties. The solubility and effectiveness of most water-based drilling fluid components are improved at proper pH conditions, including drilling fluid clays, polymers and thinning chemicals. Alkalinity is important in terms of suppressing the solubility of contaminating ions and molecules such as Ca2+, Mg2+, H2S and CO2. Surfactants are used to alter the surface chemistry of drilling fluid components, steel pipe, or formation material. They modify or reduce surface tension at the interface of various water-based fluid phases. Surfactants are used to combat bit balling and cuttings sticking to drilling tools. This results in better ROP's and easier wiper trips. Surfactants are discussed in detail in the Polymer Chapter (5). Lubricants are used to reduce rotary torque and hole drag in deep, directional holes. Today holes are being drilled with both a kick-off point and a drop-off point. That is, they are "S" shaped. Ava has been involved in planning and servicing several such wells which built to 60°, then dropped to 30°, with a horizontal displacement of almost 3,000 m - with water-based fluids. The selection and compatibility of both solid phase and liquid phase lubricants is tested using fairly elaborate equipment. Before using solid phase lubricants, remember to double-check on their compatibility with mud motors, telemetry equipment and coring equipment, at the proposed concentrations. Corrosion inhibitors are a broad class of conditioning chemicals. They are expected to work in corrosive environments by various mechanisms or combinations of mechanisms. Corrosive gasses include H2S, CO2 and 02, or any combination of all three. Several factors affect corrosion


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rates, including temperature and pressure. Table 7.11 lists 13 different corrosion inhibitors supplied by Ava. For a more in-depth discussion, turn to the chapter on Corrosion (16). Bactericide is the generic name given to any substance that kills bacteria. Bactericides vary greatly in their potency and specificity. They may include other organisms, chemical compounds or even short-wave radiation. Bacterial growth may result in the destruction of drilling fluid polymers - resulting in a loss of filtration or suspension properties. Sulfate Reducing Bacteria (SRB) can generate H2S gas in concentrations high enough to be lethal. Microorganisms produce enzymes, which also attack and decompose organic materials. The enzymes however can't be treated out or destroyed. Thus the selection of the proper bactericide is extremely important. Foam in drilling fluids is undesirable because slush pump and solids equipment efficiency rates are hampered by it. Foam also increases corrosion rates and leads to erroneous PVT estimates. When not treated properly, severe foaming problems can lead to a complete inability to pump. Defoamers are used to reduce the tendency of brackish or salt-water fluids to foam. Defoamers are also used to remove entrained air or gas from fresh water fluids. They work by reducing the surface tension of bubbles. Because so many variables can contribute to foaming problems, pilot testing is often conducted at the rig to aid in choosing the most efficient product. Spotting fluids are used to aid in freeing differentially stuck drill pipe. They often contain a blend of several constituents. The main working mechanism involves drying or dehydrating the filter cake. Oil is occasionally added to water-based fluids to improve certain properties. Up to 10% and more oil may become entrained in a water-based fluid after an oil-bearing formation has been drilled. If the water and oil phase are immiscible, in the mud pits, an emulsifier must be added. Often, a lignosulfonate product suffices adequately. 7.4.9 Inorganics Inorganic chemicals perform a diverse number of functions in water-based fluids, including, densification contaminant precipitation, corrosion control, pore plugging and alkalinity control. Mixtures of these compounds can be blended to assimilate the composition of evaporate intervals. Table 7.12 lists a brief description of some of the inorganic chemicals supplied by Ava.


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TABLE 7.12 INORGANIC COMPOUNDSa NAME

ABBREVIATION

DESCRIPTION

USES

Ammonium Bisulfite

NH4HSO3

White Crystals

Oxygen Scavenger

Calcium Bromide

CaBr2

White Powder

Heavy Clear Brines

Calcium Chloride

CaCl2

White Granules/Flakes

Calcium Treated Fluids Heavy Clear Brines Freeze Point Depression Vapor Pressure Equalization Flocculated Water Systems

Calcium Hydroxide

Ca(OH) 2

Soft White Powder

Calcium Treated Fluids Alkalinity Control

Magnesium Chloride

MgCl2

White Crystals

Stability in Complex Salt Zones

Potassium Chloride

KCl

White or Pink Crystals

Potassium Treated Fluids

Potassium Hydroxide

KOH

White Pellets or Flakes

Alkalinity Control in K+ Fluids

Sodium Bicarbonate

NaHCO3

White Powder

Treatment for Cement Contamination

Sodium Chloride

NaCl

White Crystals

Brine Formulation, Evaporate Drilling, Freeze Point Depression, Bridging Agent

Sodium Hydroxide

NaOH

White Beads or Flakes

Alkalinity Control, Suppression of Ca2+ Solubility Suppression of Corrosion, Product Solubilization Soluble Sulfide Control

Sodium Sulfite

Na2SO3

White Crystals

Oxygen Scavenger

Zinc Carbonate

ZnCO3

White Powder

Soluble Sulfide Precipitant

a Descriptions of these and other conditioning chemicals are found in the Ava Product Data Book


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7.5 WATER-BASED SYSTEMS Some of the most common fluid types and systems used by Ava are described in the following text. This does not constitute a complete list of our systems. It is often necessary to alter water-based system composition, to suit specific applications. Often completely new systems are designed to perform specialized functions. The fluid formulations and operational aspects described in this text are often changed and expanded upon. This takes place regularly when a program is written for a particular well. 7.5.1 Mixing, Converting and Displacing There is usually a preferred sequence for mixing the various water-based fluid components. The system descriptions attempt to explain the reasons for this. When new chemicals are introduced or concentrations are changed, it is always a good idea to pilot test first. You’re nearest Ava Technical Services Department is equipped with good database and library, manned by experienced drilling fluid Engineers. It is their job to provide answers and suggestions to questions you might have regarding systems, components, compatibility or problems. Some of the drilling fluid systems described here, such as Gyp or Salt are often fabricated by converting existing systems as drilling proceeds. Here again pilot testing is recommended. This will indicate a need for alternate chemicals or procedures. It is always a good idea before converting any systems to ensure the proper equipment is available and functioning. All necessary chemicals including contingency chemicals should be available and ready to mix. There should be a written plan of action. All personnel involved, including the Drilling Engineer, Driller, Derrickman and Roustabout should understand their role in the procedure, step-by-step. When converting clay / water systems where flocculation, viscosity humps or other changes are expected keep accurate records of properties, especially suction tank values. Try to keep the system properties as even as possible. Chemical analysis made on an uneven system makes subsequent treatments, concentrations and procedures a stab in the dark at best. If the suction tank properties do begin to fluctuate the driller is usually able and willing to slow the pump down long enough to adjust chemical addition rates and the corresponding suction tank properties. Drilling fluid systems are usually displaced to alternate systems just prior or just after drilling out a casing shoe. Usually displacements are not conducted while drilling ahead. In most cases the displacement procedure is discussed between the operator and Ava prior to drilling the well and included in the Drilling fluid program. 7.5.2 Spud Muds Spud muds are used to drill surface holes. Usually the main function of a spud mud is to clean. Surface hole bits have bigger teeth generating bigger cuttings. Because surface holes are of such large diameter (up to 36"), annular velocities are low, even at maximum pump rates. This means that spud mud viscosities are usually high. When choosing a spud mud, the two main considerations are the formation pressure gradient and the availability and type of make-up water. Often surface formations are underpressured, lost circulation is a problem and fluid densities must be kept low. Occasionally abnormal pressures or overburden stresses are encountered on top hole. In these cases, the spud mud must retain the ability to suspend Barite.


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Spud mud systems and components must conform to certain criteria. The products must be able to be mixed rapidly, using simple recipes, and the systems must be economical. The amount of material usage should be minimized, especially on floating rigs where deck space is limited and returns are directed to the sea floor. Make-up water analysis is always essential prior to mixing any fluid system; especially spud muds. Contaminants such as calcium or magnesium must be precipitated before many commercial additives can be expected to perform properly. On land, top hole is usually drilled with one of the following spud mud systems: 1. Native Solids 2. Bentonite/Lime 3. Bentonite 4. Extended Bentonite The funnel viscosity of these systems is usually maintained at 40-60 s/l until casing depth is reached, where it might be raised to 80-120 s/l to facilitate running casing. In some areas, its advisable to spud with, and maintain a viscosity above 150 s/l until the 11 and 9-inch drill collars are drilled down. The improved cleaning characteristics reduces time spent laying down big collars - when difficulty is encountered making connections in incompetent formations such as gravel. When lost circulation or gravel is encountered, the viscosity should be raised to 150 s/l or higher. Other important properties include pH, alkalinity and density. Spud muds are often discarded after use. Native solids systems are used in areas where "mud making" clays are encountered. The well is spudded with fresh water, and viscosity builds naturally. Caustic, Lime or Bentonite may be added to these systems as required to increase the viscosity. The wall-building and suspension characteristics of these fluids are poor. Gel/Lime slurries are often used on shallow surface holes. Usually about 60 kg/m3 of Bentonite is added to fresh water until a funnel viscosity of 35 - 40 s/l is obtained. The system is flocculated with small quantities of Lime (Ca(OH)2) through a chemical barrel when a viscosity increases is required. The ratio of Gel to Lime should be about 35:1. The mistake most often made with this system is that Lime is added before enough Bentonite has been added. This leaves excess calcium in the system, inhibiting the yield of subsequent Bentonite additions. Bentonite and extended Bentonite systems are also used for land-based drilling, usually when the surface interval is longer than 2 - 3 days. The procedure is to increase and maintain the pH of fresh water at 9 with about 0.75 kg/m3 Caustic Soda. Bentonite is added to the desired funnel viscosity allowing time for hydration. When an extending polymer such as Avabex is used 0.5 kg is mixed with each 10 sxs of Bentonite. The advantages of these systems include; good cleaning and hydraulics, better wall plastering and hole stability, lower solids concentrations and higher ROP's. If the low gravity solids content is kept low enough (less than 150 kg/m3) then the fluid can usually be used on the next interval. Offshore, top hole is usually drilled with seawater and viscosity sweeps. Continuous viscosification becomes expensive since, when drilling without a riser, there are no fluid returns to the rig. Some Operators can recover sweep fluid through an airlift system, stung into the TGB. Returns, including cement, and sweep effectiveness can then be analyzed at the header box, sweeps can be recovered and surface gas can be monitored.


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Initially, sweeps should be large enough to cover 10-15 m of annulus and they should be pumped every 15m or so. When drilling through permafrost or gas hydrate baring formations, sweeps should be chilled first. If coolers are not available, viscosifiers should be added to cold seawater just prior to pumping the sweep. It is advantageous and cost effective to use readily dispersible polymers such as Avagum (Guar Gum) for this purpose. Since cuttings can't normally be seen, the ultimate frequency and size of viscosity sweeps should be dictated by hole conditions. Drilling parameters indicating insufficient cleaning include excessive: 1. Rotary Torque 2. Hole Drag 3. Pump Pressure 4. Fill on Connections It is imperative that good communication between the Mud Engineer and Driller be maintained at all times during surface hole. The Driller is the first man on the rig to know when the drilling fluid Engineer's spud mud strategy needs re-evaluation. Occasionally continuous viscosification is necessary when flowing sand is present. If squeezing formations remain persistent, densification of the fluid can be beneficial. Upon completion of the interval, "bottoms up" is usually circulated several times. The hole is then displaced with 1.5 - 2 times gauge volume, with viscosified and/or densified fluid. This is done to keep solids suspended or to maintain borehole stability while logging and running casing. Bentonite-based systems and sweeps are often used in a variety of ways to spud on and offshore wells. Drill water / bentonite systems can be used. Sometimes they are flocculated with Lime, or extended with a polymer such as Avabex. More often, PHB and seawater are blended just prior to being pumped. This promotes flocculation and reduces the required amount of drill water. (It also increases the fluid loss). Table 7.13 shows a typical drill water / Bentonite formulation. Other variations of clay-based spud muds which have been used in offshore applications include Bentonite / CMC and Attapulgite or Sepiolite systems. TABLE 7.13 BENTONITE / SEAWATER SPUD MUD ADDITIVE

PRODUCT NAME

CONCENTRATION kg/m3

Water NaCO3 Soda Ash 1.0 - 3.0 NaOH Caustic Soda 1.0 - 2.0 Bentonite Avagel 110.0 - 140.0 Yield for several hours Add Seawater and small amounts of Caustic Typical Properties: Funnel Viscosity 100 - 150 sec/L Yield Point 25 - 40 pa pH 8.0 - 8.5


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Guar systems are often used to drill top hole on land based and offshore locations. Guar is mixed with relative ease (10 - 15 min/sack), providing good properties with an optimum of hydration time, usually 1 - 2 hours. Guar provides good suspension properties at low concentrations and reasonable cost. Guar also provides some filtration control characteristics. Guar gum is insensitive to pH fluctuations, salt and multivalent cations. Guar systems being stored should be kept cool and treated with a bacteriacide. Table 7.14 shows a typical guar formulation. TABLE 7.14 GUAR SPUD MUD ADDITIVE

PRODUCT NAME

CONCENTRATION kg/m3

Water NaOH Caustic Soda 0.5 - 1.5 Guar Gum Avagum 8.0 - 15.0 Yield 1 - 2 Hours Typical Properties: Funnel Viscosity 100 - 200 sec/L Yield Point 25 - 40 pa pH 8.0 - 9.0

Some Operators especially in Arctic offshore areas use Xanthan Gum systems. There are three important reasons why this is so: 1. Transportation costs to the Arctic are high. It is almost as cheap to viscosify a

cubic meter of seawater with 5 kg of XC Polymer as it is to use 100 kg of Bentonite.

2. Arctic spud muds should be chilled prior to pumping. Warm spud mud melts the

permafrost, resulting in gas hydrate release or washouts. Systems and sweeps built with Xanthan Gum are less apt to plug mud coolers than systems built with Guar Gum.

3. Xanthan is more dispersible in cold seawater than many other products. (With a

good shearing hopper, it can and has been mixed at 1 min/sack). This is important because, if continuous viscosification is required, Xanthan must be added to new, cold seawater and pumped away immediately. There is no sense pumping any fluid once its above 3 - 4°C.


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TABLE 7.15 VISCO 84 SPUD MUD (SWEEP) ADDITIVE

PRODUCT NAME

CONCENTRATION (kg/m3)

Water Xanthan Gum Visco 84 4.0 - 8.0 NaOH Caustic Soda 0.5 - 1.5 Typical Properties:

Funnel Viscosity 45 - 200 sec/L Yield Point 10 - 30 pa pH 7.5 - 9.0

Table 7.15 provides a recipe for a typical Xanthan (XCD) sweep. When continuously viscosifying with Xanthan the concentration and mixing rate is best determined at the well site. It is dependant on both the required yield point and the pump rate. 7.5.3 Low Density Fluids Low density fluids are sometimes called gas-based or reduced pressure drilling fluids. The original purpose of these fluids was either to avoid loss of circulation or reduce the amount of water lost into production zones. Improved rates of penetration and longer bit life soon became well-known secondary benefits. These systems can be classified as follows: 1. Gas or Air 2. Mist / Foam 3. Stiff / Stable Foam 4. Aerated drilling fluid Dry gas drilling was first patented in 1866 and is still used in many areas today. When drilling with gas or air, enough volume must be supplied to generate annular velocities in the range of 900 m/min. Care must be taken to avoid the risk of down hole fires and explosions. The intrusion of formation water into the wellbore (above 0.3 m3/h), creates problems resulting from the aglomeration of sticky cuttings. Mud rings or seal rings begin to form in the annulus. The injection of small amounts of drilling fluid or water containing a foaming surfactant results in a mist or foam drilling fluid. The foaming surfactant mixes with the formation water. This increases carrying capacity, permitting the removal of water from the hole at lower annular velocities. As much as 80 m3/h of water can be removed with foam. The first stable foam drilling fluids were developed by the U.S. atomic energy commission for use in drilling large diameter holes. The original recipe included: water, Soda Ash, Bentonite, Guar Gum and a foaming agent. Subsequent recipes are more resistant to contamination. Stiff foam fluids have the consistency of shaving cream. They are used when: an air drilling operation encounters a water flow, for clean out and remedial work. For drilling permafrost, foam has low head conductivity and low heat capacity, or as the primary drilling fluid. The composition of foam at any temperature can be expressed as a liquid volume fraction. The particle lifting ability of foam increases as liquid volume fraction decreases. Phillips Petroleum first used aerated drilling fluids in 1953. Various systems have been employed to inject air into the drilling fluid and thereby reduce hydrostatic head. These include,


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injecting air into the standpipe, injecting air into the annulus; and using a dual drill string-one within the other. Often the company providing the compressors and other air drilling equipment helps in supplying air drilling fluid chemicals. The Mud Engineer should be available to monitor corrosion rates, supply proper corrosion inhibition chemicals and maintain a specified drilling fluid system ready for instant mud-up. Although air drilled holes are usually close to gauge, often the dry formation absorbs a substantial amount of drilling fluid after mud-up. The drilling fluid engineer should usually have 30 - 40% excess volume available in the event that this happens. The rate of loss should also be monitored to ensure that it decreases with time. If not, lost circulation material must be added. Some areas are notorious for exhibiting stress relief problems (sloughing) 2-3 days after mud up. Often it is a good idea to have viscous sweeps available, should this occur. 7.5.4 Clear Water Systems Many land-based operations employ a clear-water system under the surface casing shoe to a specified mud-up depth. The advantages of these systems are economical: a cheap system and a rapid rate of penetration. The application of clear-water systems is limited to areas of normal formation pressure, and where borehole stability is not a major concern. There are three methods of drilling with clear-water. The easiest one involves using the water available at the location by itself. Needless to say, this type of drilling uses copious volumes of water. However, where lost circulation is so severe that it can't be remedied this could be a viable option. Either a good pumping system or many water trucks supply water to the suction tank, and drilling "blind" proceeds with no returns to surface Sodium Acid Pyrophosphate (SAPP) is a strong deflocculant. SAPP is discussed in chapter 5. SAPP / water fluids are used to drill under the surface casing shoe, usually on shallow wells to minimize mud rings and bit balling in clay formations. SAPP systems are only recommended for drilling up to about 600 m of open hole. Circulation is established through the sump, which should contain at least 100 m3 of water. Enough Sodium Bicarbonate or SAPP should be added initially to treat out the cement between the float and shoe and in the rat hole. One kg or one viscosity cup of SAPP should be added to the drill pipe on each connection. SAPP can also be added to the suction put at 1 kg for each 10 m of new hole drilled. If mud rings or bit balling become severe, a SAPP slug may be pumped. This involves mixing about 20 kg of SAPP into a chemical barrel and adding it as close to the pump suction as possible. While drilling with SAPP the density should be maintained as low as possible with regular additions of water. SAPP water systems are not normally used to make up subsequent drilling fluid systems. Flocculated water systems are used in many areas where conditions permit deeper (up to 2000 m) water drilling. The main advantages of flocculated water include: 1. Inexpensive 2. Rapid ROP's 3. Low solids, non-abrasive 4. Easy Maintenance 5. Resistant to Contamination 6. Sump water may be reclaimed for building drilling fluid


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When drilling with flocculated water, polymers are added to the circulating system at surface, usually near the shale shaker. These polymers become attracted to drilled solids, causing them to aggregate. The increased effective diameter of the aggregates promotes rapid settling. The objective of this system is to supply completely clear water to the pump suction. Several types of flocculant are available. Typical chemical concentrations and fluid properties for this system are outlined in Table 7.16. Calcium Chloride is used to increase the effectiveness of the flocculant. Other salts may also be used, if required for borehole stability or in environmentally sensitive areas: Potassium Chloride 10 - 30 kg/m3 Diammonium Phosphate 8 - 15 kg/m3 Ammonium Sulfate 8 - 15 kg/m3 Gypsum 2 - 3 kg/m3 TABLE 7.16 FLOCCULATED WATER SYSTEM ADDITIVE

PRODUCT NAME


Polymer Flocculant AvapolJ 1-2 L/m3 of 50% solution CaCl2 Calcium Chloride .5 - 1.5 kg/m3 (100 - 300 mg/l Ca2+) Ca(OH)2 Lime pH: 9.5 - 10.0 Typical Properties:

Fluid Density 1 000 - 1 020 kg/m3 Funnel Viscosity 27 - 28 s/l pH 9.5 - 10.0 Calcium 100 - 300 mg/l

The sump should be large enough to accommodate 300 - 400 m3 of water. An earthen dyke is usually constructed up the middle of the sump. This forces the flowing water to channel, increasing the available settling time. Solids may also be flocculated in the rig tanks; however, this substantially increases the chemical requirements. Initially 500 - 800 kg of CaCl2 are added to the drilling water. Cement from the shoe joint and rat hole is not treated out. Ca(OH)2 is added with the initial treatment of CaCl2 to raise the pH to 9.5 - 10.0. This usually requires 200 - 400 kg of Lime. This pH level minimizes corrosion and maximizes polymer solubility. In some areas the system is run at neutral pH, resulting in better gauge holes. In these systems gypsum is substituted for lime. Normally 1 kg of the flocculating polymer is added to 15 - 20 l of diesel fuel and stirred. This mixture is then added to a chemical barrel full of water. It's best if the chemical barrel is equipped with an electric agitator. The flocculant mixture should be added at the shaker continuously while drilling, at a rate of 1 kg for each m3 of new formation drilled. Maintaining the system usually requires the addition of 50 - 100 kg of CaCl2 and 25 - 75 kg of Lime or Gyp each 8 hours. 15 - 30 m3 of fresh water are also added each 8 hours.


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If the water at the pump suction becomes dirty or cloudy the usual procedure is to add approximately 200 - 300 kg of CaCl2 over one circulation. If this treatment fails, pilot testing becomes imperative. Varying amounts of CaCl2 or flocculant are added to a glass jar containing the cloudy drilling fluid. Observations are made to discern which product or combination decreases particle-settling time most efficiently. If this fails, the next step is to try a different type of flocculant. Care should be taken to ensure that too much flocculant isn't added. When this occurs, "flocs" can be observed in the returning fluid, upstream of where new flocculant is being added. This indicates that flocculation and settling is occurring in the annulus. Further considerations when running flocculated water systems include: 1. If using diammonium phosphate or ammonium sulfate, all of the cement must first be

treated out with Sodium Bicarbonate. In this case, to avoid the release of free ammonium, the pH should be maintained below 7.8.

2. Annular velocities should be maintained at 40 - 50 m/min. Surveys should be made off

bottom when possible. It is advisable to circulate 15 - 20 min. prior to stopping tools to survey, trip or repair.

3. Fill on connections usually indicates the need to change to viscosified drilling fluid. The

clear-water drilling interval can often be extended if viscous sweeps are pumped intermittently.

4. If the sump water is to be used for future make-up water, Calcium Chloride and Lime

additions should be discontinued 6 - 8 hours prior to mud-up depth. Selective flocculant additions can be made right up to mud up depth. The calcium concentration of the sump water should be lowered to 60 - 80 mg/l prior to initiating Bentonite additions. Often a concentrated batch of prehydrated Bentonite is kept on standby ready to blend with fresh water, if an "instant" mud-up is required.

7.5.5 Gel-Based Systems Gel-based (Bentonite) drilling fluids systems are by far the most common systems used for land-based drilling. Since their inception in the 1920's, they have been used throughout the world to successfully drill through many types of formations and conditions. Ongoing research and development has provided a diverse array of proven complimenting components and chemicals for these systems. Hence, Gel-based systems may be modified to address one, or several specific drilling fluid functions. Gel-based drilling fluids often provide the most economical combination of desired characteristics, imparting good suspension properties and lifting capacity, favorable shear thinning characteristics, and good fluid loss and wall building properties. In a fresh water environment, hydration forces are strong enough to separate natural Bentonite aggregates. Separation into individual unit layers is possible. Unit layers are about 10 angstroms thick and between 100 and 1 000 angstroms square. The shape of these hydrated platelets imparts resistance to flow or viscosity to a clay suspension. When a shearing force (movement) is applied to a Bentonite suspension, the platelets align themselves in a direction parallel to the force. Resistance to flow then decreases, explaining the shear-thinning nature of Bentonite suspensions. This thin-flat shape also provides good fluid loss characteristics to the suspension. Because the clay platelets have surface charges, they align themselves to positions of minimum free energy when the suspension is at rest. This accounts for the thixotropic properties exhibited


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by Bentonite suspensions. The preceding mechanisms and terminology are explained in greater detail in the Clay Chemistry chapter. Bentonite systems have many permutations, including systems, which incorporate various borehole stability components. There are three types of basic Bentonite systems:

1. Non-Dispersed Bentonite (Gel Chemical) 2. Low Solids (Extended Gel) 3. Dispersed Bentonite (Lignosulfonate)

Please note that the terms Non-Dispersed and Dispersed refer to the degree of imparted deflocculation in a Gel suspension. When the Industry talks about a "dispersed" system, it actually means a deflocculated system. Accurate colloidal chemistry terminology would replace the word dispersed with deflocculated. (When dry Bentonite aggregates hydrate and disperse in a premix tank the solution becomes thicker - not thinner.) When Lignosulfonate is added, clay particles dissociate, the suspension is deflocculated and it becomes thinner. Similarly, the Industry term "non-dispersed" refers to a system, which has not been deflocculated with a thinner. These terms are discussed in greater detail in the Clay Chemistry chapter. Non-Dispersed Bentonite systems are often called Gel Chemical systems. Table 7.17 lists the components, concentrations and properties typical of Gel Chemical fluids. TABLE 7.17 NON-DISPERSED BENTONITE SYSTEM ADDITIVE

PRODUCT NAME

CONCENTRATION kg/m3

Freshwater NaCO3 Soda Ash 1.0 - 3.0 NaOH Caustic Soda 0.5 - 0.75 Bentonite Avagel 45 - 75 CMC CMC 1 - 6 Typical Properties:

Funnel Viscosity Above 35 s/l Density 1,050 – 2,000 kg/m3 PH 9.0 - 10.0 Fluid Loss 3 - 10 ml/30 min Calcium Less than 100 mg/l

Complimenting components for these systems include most of the water-soluble products outlined previously in this chapter. The mixing order of this system is important. For best results, fresh water should be used. Excessive salt (>5 000 mg/l) and hardness interfere with the hydration and effectiveness of the Bentonite. Soda Ash should be used to treat the calcium in the make-up water to less than 40 mg/l. The pH should be adjusted to 9.5 - 10.0 prior to adding Bentonite. The Bentonite should be added slow enough that balling and clogging is eliminated. The initial yield depends in part on the quality of the surface equipment. Normally the slurry becomes thicker with time and agitation. Usually 60 - 70 kg/m3 of quality Bentonite will produce a slurry with a funnel viscosity of 38 - 42 s/l. This concentration provides a natural fluid loss of approximately 12 - 15 ml/30 min.


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The yield point of this system should be maintained at a sufficient value to provide effective hole cleaning characteristics and Barite suspension with additions of Gel as required. In an unweighted system, the plastic viscosity value in mPa•s is usually about twice the value of the yield point in Pa. The plastic viscosity (PV) increases as the solids concentration in the system increases. The PV value should be maintained as low as possible by running proper solids control equipment and by dumping and dilution. The pH should be maintained between 9.0 and 10.0 with additions of Caustic Soda. This aids in hydrating the Bentonite, reducing corrosion rates, and minimizing the solubility of contaminants. The fluid loss may be readily lowered with CMC polymer providing contaminating electrolytes are not present in the system. The calcium content should be kept below 80 mg/l with Soda Ash. A residual concentration of soluble calcium (30 - 80 mg/l) left in the system insures that carbonate related problems will not develop. When chloride concentrations exceed 5 000 mg/l it is advisable to prehydrate the Bentonite prior to adding it to the active system. When drilling ahead with this system, appropriate volumes of fresh water and Bentonite should be added to the system to avoid dehydration, especially as the system temperature increases. A Non-Dispersed system is not a low solids system; it is prone to rapid solids build up, especially at high rates of penetration. Therefore the solids content should be monitored closely and controlled properly. Once the average particle size degrades to beyond the capabilities of the available solids equipment, expensive whole fluid dumping and dilution becomes imperative. Because the surfaces of Bentonite platelets are electrically charged, this system is inclined to react unfavorably to many types of ionic contaminants. These include most salts, which are encountered while drilling through evaporate formations and the acid gasses, H2S and CO2. It should be noted that the physical and chemical conditions, which promote the most efficient dispersion of Bentonite particles and the best control of Non-Dispersed Bentonite system properties, are: 1. Fresh Water 2. High pH Conditions 3. High Mechanical (Shear) Energy 4. Low Calcium Concentrations These same conditions are advantageous to the hydration and dispersion of formation shales and clays. Often asphaltic derivatives or PHPA are added to these systems to impart shale inhibition properties. Low Solids Systems are often referred to as Extended Gel Systems. These systems have been used successfully in various areas since the early 1960's. They may be used in most areas where a Non-Dispersed system can be used. The most important advantage of Low Solids systems is that they promote faster rates of penetration (ROP). They are also less abrasive and easy to maintain. Low solids systems exhibit good rheological properties. They usually contain no more than 4-7% solids by volume. The system employs an anionic polymer of medium to high molecular weight. This polymer attaches to positive edge sights on two or more clay plates, linking or bridging the plates together. This results in an increase in viscosity, caused by a soluble molecule and not an insoluble particle. Therefore a desired degree of viscosity in a given suspension may be achieved with fewer solid particles. This markedly improves ROP's where the system is used. Extending polymers are discussed in greater detail in the chapter on Polymer Chemistry. Table 7.18 outlines the products, concentrations and properties of Extended Gel systems. Note that premium quality Bentonite is used.


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TABLE 7.18 LOW SOLIDS (EXTENDED GEL) SYSTEM ADDITIVE

PRODUCT NAME


Freshwater NaCO3 Soda Ash 1.0 - 3.0 NaOH Caustic Soda 0.5 - 0.75 Bentonite Avagel 30 - 60 Extending Polymer Avabex .07 - .15 CMC Carboxy Methyl Cellulose 1 - 6 Typical Properties:

Funnel Viscosity 35 - 60 s/l Yield Point 7 - 15 Pa Plastic Viscosity 10 - 25 mPa•s Density 1 060 - 1 100 kg/m3 Solids 4 - 7% (Vol) pH 9.0 - 10.0 API Fluid Loss 2 - 8 ml/30 min Calcium Less than 100 mg/l

The material mixing order for Extended Gel systems is similar to the previously discussed Non-Dispersed system. The extending polymer is mixed through the hopper along with the Bentonite. The maintenance and value range of the pertinent properties including YP, pH, fluid loss and calcium concentration is also similar to the Non-Dispersed gel system. More attention is usually paid to fluid density, solids content and solids control efficiency when running these systems. Generally an upper density limit of 1100 kg/m3 (about 6-10% volume solids) is tolerated before dumping and diluting are initiated. Contaminating ions and acid gasses are detrimental to the performance of Low Solids systems. When peptized or extended Bentonite is used with extending polymers, there is a risk that flow properties especially gel strengths will be adversely affected (reduced). This was especially so with the vinyl acetate, maleic acid (VAMA) co-polymer used until the middle 1980's, where over treatment of polymer would drastically reduce the viscosity. The acrylate co-polymers used as extenders today don't actually cause a viscosity hump, but when they are used in conjunction with peptized gel, it is difficult to attain sufficient gel strengths or satisfactory low-end rheology. Dispersed (Lignosulfonate) Systems were first used on the early 1950's to control the flow properties of Lime Muds. Today these systems have gained widespread acceptance, they are not just limited to calcium-based systems. Lignosulfonate systems are the most common systems used today in the Gulf of Mexico. They are usually the most economical systems to use in environments where a contaminant or high temperatures would adversely affect the rheological properties of a Non-Dispersed system. Lignosulfonate systems make gel-viscosifed, water based fluids rheologically tolerant to virtually every type of contaminant. This includes reactive clays, high solids, salts, hardness, acid gasses and moderate temperatures. They can be formulated from both fresh water and seawater. Other advantages are realized when Lignosulfonate systems are used. These include: 1. They inhibit shale hydration at higher concentrations. 2. They impart good filtration properties to a system.


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3. They are easy to maintain and compatible with most common additives. (Most clay-water systems can be easily converted to Lignosulfonate systems).

4. They are inexpensive. 5. They are good emulsifiers at up to 10% oil content. Lignosulfonates are high molecular weight anionic polymers. They have a relatively high negative charge density. They function by bonding to positive edge sights on clay platelets. This effectively causes the clay plates to have an overall negative charge. Thus individual clay plates repel. Further discussion on the topics of deflocculation and Lignosulfonates is presented in the Clay Chemistry chapter (4) and the Polymer Chemistry chapter (5). Table 7.19 shows the components concentrations and properties typical of Lignosulfonate systems. TABLE 7.19 DISPERSED (LIGNOSULFONATE) SYSTEMS ADDITIVE

PRODUCT NAME


Fresh or Seawater NaOH Caustic Soda 0.5 - 6.0 Bentonite Avagel 70 - 100 Lignosulfonate Avafluid G71 2 - 30 Polyanionic Cellulose Policell 1 - 6 Typical Properties:

Funnel Viscosity 38 - 150 s/l Yield Point 7 - 20 Pa Plastic Viscosity 15 - 50 mPa•s Density 1 100 - 2 200 kg/m3 pH 10.0 - 10.5 API Fluid Loss 1 - 10 ml/30 min

Lignosulfonate systems can be built as such or they can be converted from non-dispersed clay / water systems. Usually Gel / Chemical systems are converted to Lignosulfonate systems prior to encountering an expected contaminant. The properties of Lignosulfonate systems may be modified with a wide range of additives to suit most drilling conditions. The concentration of Lignosulfonate depends on the type and expected severity of the contaminant and the concentration of reactive clays in the system. If only minor stringers of anhydrite are expected 2 - 4 kg/m3 is usually sufficient to deflocculate. If massive anhydrite or salt contamination is expected 10 - 20 kg/m3 will be necessary to control both the flow properties and the fluid loss. In extreme cases, 20 - 30 kg/m3 of Lignosulfonate is used in a system. High concentrations such as these are used to inhibit temperature-induced dispersion of formation clays, minimize HTHP fluid loss values and treat extremely severe contamination. Often a Gel Chemical system is treated with 10 - 12 kg/m3 of Lignosulfonate before drilling into an H2S zone. The excess Lignosulfonate serves to dampen the flocculating effects of both the H2S and the ZnCO3 scavenger, if it is being used. Often the best method of converting to a Lignosulfonate system is to simply watch closely and maintain the desired rheological properties in the suction tank, either with additions of Lignosulfonate or Bentonite. This becomes imperative if the severity of the contaminant is unknown. If the contaminant is an electrolyte, Bentonite will have to be prehydrated first. Both Caustic Soda and an alcohol-based defoamer should also be available when adding Lignosulfonate, since it is acidic and has a tendency to foam. Usually Lignosulfonate


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should be mixed about 5:1 or 6:1 with Caustic. This ratio will decrease if CaSO4 is the contaminant. Once the system is built, it is extremely simple to maintain. The YP and gel strengths are controlled with PHB or Lignosulfonate as required. A lower YP : PV ratio and a higher n value (shear-thinning index) are to be expected. This is because most of the clay particle associations have been broken chemically leaving less or none at all to be broken by mechanical shearing forces. Thus the system is not very shear thinning. Usually PAC polymers are added if additional fluid loss control is required. The higher degree of substitution in these polymers makes them more tolerant to the various contaminants the system is being used to drill through. The acidic nature of most Lignosulfonate products requires that substantially more Caustic be added to the system. This requires close monitoring. (pH 10.0 - 11.0 is acceptable). If the pH is allowed to drop, flocculation and foaming often occur. If the pH becomes too high, free hydroxyls and/or sodium ions may lead to increased dispersion of certain reactive formation clays, promoting borehole instability. A permutation of Lignosulfonate systems uses a modified tannin extract (DESCO) to deflocculate. DESCO works well in neutral pH environments (7.9 - 8.3). Lignosulfonate systems have disadvantages. These can usually be overcome if one is aware that they exist. Because Lignosulfonate systems have such a good resistance to drilled solids contamination, ROP's may be lower if drilled solids are high. Often they are used in tertiary formations where controlled drilling is practiced, so the reduction in ROP isn't a concern. Fluid temperature can affect the performance of these systems because when Lignosulfonates are degraded by heat, both H2S and CO2 may be produced. The temperature limitations of Lignosulfonate systems may be extended with lignins, resins and asphaltic derivatives. 7.5.6 Salt Saturated Systems Salt Saturated systems gained widespread use both in the Permian Basin of West Texas and in the Gulf Coast in the middle 1930's. These fluids were developed for drilling through salt beds and salt domes. When extensive salt intervals are penetrated with an undersaturated solution, the salt formation tends to solvate, or enter the solution often resulting in severely "washed-out" holes. The poor performance of Bentonite in salty environments led to the application of attipulgite clays as viscosifiers in 1937. The inferior cake-building characteristics exhibited by these clays resulted in drilling problems including differential sticking and sloughing shale. Starch was soon found to be the most economical material for improving cake characteristics. Not all drilling fluid systems containing salts have to be saturated. Systems are often used which are formulated from produced brines or seawater exhibiting various degrees of salinity. Some systems are formulated with specific salt concentrations, optimized to control bentonitic formations; KCl systems are discussed later in the chapter. The salinity of water-based systems is sometimes increased to enhance SP or resistivity log results, or to freeze depress drilling or packer fluids. The basic formulation, concentrations, and properties for a salt saturated system are shown in Table 7.20. This formulation is often modified to suit specific purposes. Many components can be substituted with more appropriate products if required. These include: PAC, Guar, PHB, Attipulgite, Lignosulfonates, Lignites and Resins. Usually an existing water / clay system is converted to a salt saturated system prior to penetrating the evaporate interval. When salt is added to these systems the suspended clays invariably become extremely flocculated. Pilot testing can provide a good indication regarding the


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necessary procedures, in terms of chemicals required while converting, mixing order, and how many circulations it will take. TABLE 7.20 SALT SATURATED SYSTEM ADDITIVE

PRODUCT NAME


Freshwater NaCl Sodium Chloride 350 - 360 NaOH Caustic 1.5 - 2.0 Drilling Starch Victosal 5.5 - 17.0 Xanthan Gum Visco XC 84 2.0 - 4.0 or HEC Hydroxyethyl Cellulose 2.0 - 4.0 Typical Properties: Yield Point 5 - 8 Pa Plastic Viscosity 10 - 12 mP•s pH 9.0 - 10.0

Prior to adding the salt, it is usually necessary to dilute the existing system back with water, sometimes as much as 40%. Ideally the funnel viscosity should be lowered to about 35 sec/l, if hole conditions permit. Caustic Soda may be added at this time. The salt should be added next. Be sure to allow enough tank volume for the addition of the salt. Saturated salt solutions require about 320 kg/m3 NaCl depending on temperature. For each cubic meter of fresh water to be saturated, about 360 kg of NaCl should be added. This will result in a volume increase of about 140 liters. In a saturated NaCl solution the salt will account for about 12% of the final volume. Refer to the salt tables in the appendix of this manual. Care should be taken to monitor the suction tank viscosity. If it becomes excessive, appropriate amounts of thinner should be added. Remember a viscosity hump occurs as the clays become flocculated. Once enough salt has been added to initiate aggregation the viscosity will decrease. When the salt has been mixed, Starch can be added at about 10 - 15 min/sack. The rheology should again be monitored when mixing the starch. If fish-eyes or screen blinding is evident, reduce the rate of starch addition to 20 - 30 min/sack. When drilling salt formations, plastic yielding of the salt may be encountered. At shallow depths, the deformation may be slow enough that the hole can be kept in gauge by reaming. Slight under saturation can sometimes prove beneficial, if the brine dissolves the salt, compensating for the plastic flow. However, if the salinity is too low, too much salt is dissolved, resulting in excessive hole enlargement. In some cases, an increase in hydrostatic pressure can overcome the plastic flow without the risk of dissolving formation salt. Because salt sections are mechanically weak, some washouts that occur can be attributed to mechanical erosion rather than chemical solution. To counter this, annular velocities should be kept fairly low until the BHA has past the salt zone. Nozzle velocities should be restricted to less


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than 95 m/sec by using larger nozzles. The consequent reduction in hydraulic horsepower at the bit should not affect drilling rates due to the softness of the salt. The solubility of salt in water increases slightly with increasing temperature. Care should be exercised when using a saturated salt system, as the brine may be saturated at surface temperature, but may be under-saturated at bottom hole temperature. When a saturated salt system is being used, it is advisable to maintain at least 10 - 15 kg/m3 of excess salt in the system to ensure saturation at down hole temperatures. The chloride concentration should be maintained at 190,000-193,000 mg/l, and salt crystals should be evident at the shaker. Temperature Salt to Saturate 21°C 360 26°C 362 32°C 363 37°C 365 Saturated salt systems can be thinned with Lignosulfonates for the short term, but this may not provide long-term results. A reduction in viscosity is best achieved through a reduction in the system solids content. In some instances, small additions of PAC or CMC (0.75 - 1.5 kg/m3) can be beneficial in deflocculating and thinning a salt saturated mud. If the diluent is not saturated salt water, undersaturation of the fluid will occur. If it is necessary to build volume or reduce viscosity while salt is being drilled, a small stream of undersaturated water can be run into the shaker box or some other point ahead of the shaker. Dissolving the salt cuttings will then saturate the water. The shaker may also be by-passed to collect drilled salt in the tanks. Water is slowly added and the salt cuttings gunned so that they dissolve. (This procedure is permissible only if there are no accumulations of solids in the pit.) Saturated salt water systems may require a bactericide. On occasion, the fluid loss will increase rapidly and not reduce for any appreciable period of time after a normal starch addition. Such a system may not have fermentation odors, but frequently, the addition of a biocide will result in re-control of the fluid loss properties with normal quantities of starch. Any system, which is saturated with a given ion, has a reduced capacity for absorbing oxygen. Therefore saturated salt systems can't be as corrosive as some other water-based systems. Sodium sulfite additions (oxygen scavenger) should be, however, initiated immediately after salt saturating the system. A residual sulfite concentration of 200 mg/l should be maintained in the fluid at all times. High concentrations of salt tend to foam when agitated. It is recommended that discharges from hoppers, solids removal equipment, etc., should be below the level of the fluid in the pits. This procedure will also reduce corrosion and lead to less scavenger consumption. Generally, the best defoamers for these systems are high alcohol types, that is, 2 or tri ethyl hexanol.


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7.5.7 Calcium Systems Calcium-based drilling fluids gained widespread use in the Gulf Coast area during the 1940's. Although the reason for their development remains obscure, the most likely explanation is that they exhibited excellent tolerance to the anhydrite (CaSO4) contamination commonly encountered in East Texas. Gypsum was used in Canada in the 1950's. Modifications and subsequent development of products to control the system properties have led to a widespread application of Calcium-based systems in several locations worldwide. Today Calcium Systems are often used for their inhibitive properties. The calcium ion provides an economical source of shale hydration inhibition, when used in conjunction with an encapsulator. Systems used for this purpose usually employ Gypsum (CaSO4), are of low pH, and not deflocculated. Calcium-Based systems are still often used to drill through evaporate formations containing anhydrite. In this case the system is usually deflocculated, with the pH running about 10.8. Again, Gypsum is usually the source of calcium. The primary inhibitive mechanism of these water based systems, stems from the ability of the solvated calcium ion to exchange. This occurs with the sodium ion in montmorillonite clays and to a lesser extent the potassium ion in illites. The calcium ion, being divalent is able to satisfy 1 charge deficiency sight on each of 2 clay platelets. In the active fluid this promotes first clay flocculation then aggregation. This same mechanism inhibits the dispersive, hydration forces in formation clays. Cation exchange in clays is explained in the Clay Chemistry chapter (4). This text considers mainly gyp systems. Their use is more common than Lime systems today because they are more temperature stable than Lime systems. (At temperatures in excess of 130°C a reaction between clays, calcium and Caustic Soda can cause a simple cement to form and the drilling fluid can actually solidify). Further, Lime systems because of their high pH are less inhibitive than gyp systems when they are formulated with seawater. This is because the clay inhibition effect normally realized from magnesium supplied by the seawater is lost when magnesium is precipitated as magnesium hydroxide, Mg(OH)2 starting at about pH 10. A Lime-based system using potassium hydroxide rather than sodium hydroxide is still in use. These systems can work well. It is postulated that the calcium ion stabilizes the montmorillonite clays and the potassium ion stabilizes illitic clays. These systems may use a polysaccharide deflocculant derived from starch. (Lime systems may be classified as High Lime Mud - 1.75 - 5 kg/m3 excess Lime or low Lime Mud - .3 - 1.0 kg/m3 excess Lime). Table 7.21 shows the formulation, concentrations and properties of a Gyp/PAC. The PAC (PolyAnionic Cellulose) plays an important role as a fluid loss reducer, viscosifier and an encapsulator. The encapsulation mechanism typical of several types of drilling fluid polymers is explained in the Clay Chemistry Chapter (4).


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TABLE 7.21 GYP / PAC SYSTEMa ADDITIVE

PRODUCT NAME


Water NaOH Caustic Soda 0.3 Polyanionic Cellulose Low Vis. Policell SL 9.0 Polyanionic Cellulose Hi Vis. Policell RG 3.0 CaSO4 Gypsum 18.0 Barite Barite to 1 400 kg/m3 Typical Properties:

Funnel Viscosity 56 s/l Yield Point 3.5 Pa Plastic Viscosity 20 mPa•S Gel Strengths 5.0 /10.0 Pa Density 1 400 kg/m3 pH 8.5 API Fluid Loss 5.0 ml / 30 min. Calcium 4 500 mg/l MBT as low as possible Excess Gyp 6 kg/m3 a This formulation represents an initial make-up, not a conversion. Gyp/PAC systems are usually built as opposed to converted. The formulation of this system begins with the addition of a Biocide and Caustic Soda to the water. The Biocide suppresses sulfate reduction and H2S production at the lower pH valves used. The low-viscosity PAC is added next, followed by the high viscosity PAC to the desired yield point. The Gypsum is blended into the system next followed lastly by the Barite. Properties are maintained fairly easily by blending in batches of premixed chemicals. The pH of the active system is usually maintained at 8.0 - 8.5 if adjustments to specific properties are required they are usually made to the premix batches prior to blending premix into the active system. When Gyp Systems are used to drill through anhydrite, an existing Gel/Chemical system is usually converted into a gyp System, or allowed to convert "naturally" to a Gyp System. The best rheological stability is attained when the calcium concentration has passed the saturation point. Sometimes a "viscosity hump" occurs as the calcium concentration increases. A reduction in viscosity and fairly stable rheology occurs after saturation. This phenomenon is caused as the clays in the system change from a flocculated to an aggregated state. Gypsum solubility, as well as the corresponding calcium content is a function of pH. Thus pH control is important in maintaining the proper level of free calcium. Figure 7.1 depicts the solubility of calcium as a function of pH. Remember, the solubility will be suppressed further if other ions are present in the solution.


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Firure 7.1 Solubility of Calcium as a Function of pH and Temperature

0

100

200

300

400

500

600

700

800

10 10.5 11 11.5 12 12.5 13 13.5 14

pH

Cal

ciu

m C

on

c. m

g/l

70oC50oC20oC

Strict attention must be paid to both the pH and the viscosity when allowing a system to "gyp over" naturally, since both the anhydrite and the Lignosulfonate reduce the pH. System formulation and properties are similar to those outlined in Table 7.19 (Lignosulfonate Systems), however, the pH is maintained at 10.0 - 11.0. At this pH the soluble calcium content runs between 600 - 1 000 mg/l. The temperature limitation of most gyp treated fluids is approximately 150°C although this can be extended through the use of temperature stable organic polymers. 7.5.8 KCl Systems The effect of the potassium ion on Bentonite swelling was first studied in the mid 1950's. Potential benefits were seen in the increased permeability of sandstone cores when they were exposed to filtrate containing potassium. Black and Hower offered an explanation of why the inhibiting properties of potassium were superior to Calcium Chloride or Sodium Chloride in 1968. They postulated that potassium has a hydrated diameter, which would favor its exchange for other cations on clay surfaces. This mechanism is discussed in chapter 4. KCl systems gained popularity in the 1970's as a superior method of drilling both mechanically incompetent formations such as highly dipped shales and gumbo or mud making formations. The inhibiting mechanisms of KCl are often augmented with an encapsulating polymer. Polyacrylamide polymers are most often used for this purpose. A properly formulated KCl system exhibits very good rheological characteristics. An unweighted system usually has a high YP/PV ratio, especially if clays are a component. The shear thinning index or n value often runs at .02 - .04 (as solids concentrations increase, this value also increases). The low n value imparts a flat velocity profile, ensures a thin fluid at the bit and better solids control equipment efficiency. Typically the gel strengths are high, however, there are usually "fragile", ensuring a relatively low pump pressure required to break circulation. The system is reasonably shear stable and temperature stable to about 120°C. It is compatible with


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most water-based products. Although KCl systems containing clays are flocculated, the fluid loss may be reduced to 2 - 4 ml with polymers. At low fluid loss values, filter cakes are thin and slick. Deflocculants are often components of these systems. Because KCl systems are flocculated, they are reasonably tolerant to ionic contaminants such as anhydrite. Today K+ salt systems are used, which incorporate non-chloride anions so as to be more environmentally friendly. There isn't really a "basic" system. In fact the K+ ion can be added to almost any water-based system to act as an inhibitor. Table 7.22 describes a commonly used KCl system. This formulation is used offshore for drilling gumbo formations such as the Miocene Oligocene and Eocene formations. In North Sea drilling the K ion is maintained at a relatively high concentration. This is necessary because the North Sea formations contain higher concentrations of Smectite Clays. Note that the formulation in Table 7.22 uses K2CO3 and KOH rather than the more commonly used Na2CO3 and NaOH. This is because both theory and experience indicate that clay dispersion is reduced when the sodium concentration is minimized. If the sodium concentration is high, sodium can and will exchange with other ions in clays such as the calcium in calcium montmorillionite making it more dispersable. The pH is also kept fairly low, to inhibit dispersion. The effect of pH on dispersion is discussed in the Chapter 4. TABLE 7.22 A TYPICAL OFFSHORE KCL SYSTEM ADDITIVE

PRODUCT NAME


Seawater KCl Potassium Chloride 100 - 150 K2CO3 Potassium Carbonate 2 - 6 KOH Potassium Hydroxide 2 - 6 Xanthan Gum Visco XC 84 2 - 4 CMC/PAC Polymer CMC/PAC 2 - 4 Typical Properties:

Funnel Viscosity 45 - 70 s/l Yield Point 5 - 10 Pa Plastic Viscosity 7 - 15 mPa•s pH 8.5 - 9.0 Calcium Less than 400 mg/l K+ 50 000 - 75 000 mg/l Cl- 65 000 - 90 000 mg/l Fluid Loss 10 - 12 ml

In areas where illite containing formations are mechanically incompetent, the system imparts borehole stability characteristics at lower concentrations of potassium. K systems used in the Rocky Mountain Regions of North America typically have 30 – 40 kg/m3 of K+ (16,000 – 21,000 mg/l K+). These systems usually use prehydrated Bentonite as the viscosifier. A natural fluid loss of 80 - 100 ml is usually allowed until the zone of interest is reached. North American systems typically have a higher pH, usually maintained with sodium hydroxide. This is because the make-up water is fresh and it contains little sodium. Further, a high pH is required to reduce the solubility of the H2S encountered in the Rocky Mountain region.


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To formulate a KCl system, calculate the required volumes and concentrations first. When PHB is used designate and completely isolate a premix tank. Treat out the hardness and adjust the alkalinity of the water in both the active pits and the premix tank. It is important to leave enough room in the active pits to allow the addition of PHB and KCl. Polymers should be added to the make-up water next since the ability of some polymers to hydrate is suppressed in a saline environment. Good shear and a moderate mixing rate promote the best efficiency and value in polymers. If possible, the polymers should be agitated and allowed to hydrate for 6 - 8 hours before adding the KCl. KCl may be added rapidly if the tanks have adequate jetting and agitation. If PHB is being used it is usually added last. The net concentration of Bentonite in the active system should be 30-45 kg/m3 to initiate drilling. When using PHB an alternate method of mixing the system involves adding the KCl to a light (20 - 30 kg/m3) Bentonite slurry. When this method is used it is imperative that a good supply of thinners is available. A viscosity hump similar to the situation described for Salt saturated systems will occur at a KCl concentration of about 20-30 kg/m3. When circulation through the bit is initiated, moderate shear degradation will occur. This is a result of polymer or Bentonite structure being broken mechanically. The effect is more noticeable when PHB is a component of the system, but it isn't adverse. Shaker screen blinding is not uncommon during the first one or two circulations. The usual procedure is to use fairly coarse screens initially. Monitoring and maintaining the K+ ion concentration is the most important aspect in managing this system. The drilling fluids program will suggest an optimum concentration of potassium for inhibiting a given formation. This value is usually based on past experience in a given area and on laboratory work performed on that shale. As drilling commences the potassium ion becomes depleted and must be replenished. The rate of depletion provides an indication of how reactive the shales are. In new areas or on exploration wells the potassium concentration may have to be adjusted as drilling proceeds. While drilling gumbo, the appearance of soft mushy cuttings at surface is a good indication that the potassium concentration should be increased. Other indicators include a drilled solids increase, a CEC increase and the occurrence of tight hole or mud rings. When necessary, the drilling fluids Engineer should attempt to recover shale samples for laboratory analysis. Hydration inhibition testing will provide a better guideline on subsequent wells. Because KCl systems are flocculated they don't tolerate high solids concentrations as well as some other water-based systems. Therefore a good solids control program should be implemented in conjunction with the system. Equipment monitoring and efficiency analysis is imperative if chemical treatment costs are to be minimized. One of the best means of defense against a solids build-up in tertiary formations is to keep bit nozzle velocities as low as possible. This minimizes the mechanically induced dispersion of drilled solids. Simply tripping through young formations can and often does generate literally tonnes of drilled solids, especially in deviated wells. Therefore, the solids laden bottoms up fluid should be dumped in situations where the solids control equipment can't keep up with the penetration rate. Although KCl systems are flocculated, the associations of clay particles and polymers in the suspension are usually weak. That is they are easily broken mechanically. This provides the shear thinning character typical of the system. Structure is also readily degraded with chemical deflocculants. Thus the addition of even small amounts of an anionic polymer such as PAC to a KCl system can cause a marked decrease in viscosity. The effect is more noticeable if the initial YP/PV ratio is high. Deflocculants lower the YP/PV ratio (raise the n value). Therefore a reduction in YP/PV ratio should not be interpreted as a problem due to increasing solids, unless the density increases. A reduction in the YP/PV ratio should not be interpreted as a solids particle size


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degradation problem unless the gel strengths increase. The addition of deflocculants to KCl systems extends both temperature limitations and their ability to be densified. The initial and ten-minute gel strength are generally high and flat when the system is flocculated, however, they are also fragile. This is apparent as the viscometer dial falls back quickly and to a large degree, when the structure is broken. In a highly shear thinning fluid, flat gel strengths are best. Flat means that the value of the 10-second gel is close to or equal to the 10-minute value. Flat gel strengths indicate that interparticulate structure or carrying capacity is re-established soon after the fluid has been sheared at the bit. The Rheology chapter expands on this concept in the subsection, Thixotrophy. KCl systems are prone to oxygen entrainment and moderate foaming. Foaming can sometimes result from the addition of amines during the KCl prilling (conversion to granules) process. A slight pH increase often reduces the foam. Any KCl system should be implemented in conjunction with a good corrosion control program. The most efficient oxygen scavenger is catalyzed sodium sulfite. The sulfite concentration should be monitored and maintained at 200 - 400 mg/l. Corrosion coupons should be used. Most operators and contractors maintain that an acceptable corrosion rate is 25 - 35 mpy. 7.5.9 Aluminum Sulfate Systems In the early 1970's a patent filed by Reed proposed the use of an aluminum complex to aid in inhibiting clay swelling in completion and waterflood applications. Milchem Incorporated of Houston was granted a patent entitled "Process for the Inhibition of Swelling of Shale in Aqueous Alkaline Medium" in 1974. Subsequent modifications produced a product, which was a dry blend of an aluminum salt and a ligand acid. In 1985 a system was successfully implemented, which employed a sodium aluminum oxide / aluminum sulfate compound. The system has been used in both the American and Canadian sectors of the (Arctic) Beaufort Sea. Implementation of this system has virtually eliminated the bit balling and mud ring problems characteristic of the tertiary sequences in this area. This has resulted in cost savings (elimination of downtime) in excess of a million dollars per well in some locations. Although the aluminum ion is strongly cationic, the clay swelling inhibition mechanism of this system is not attributed to cation exchange. Shale hydration inhibition tests show Al3+ alone to be a less effective inhibitor than K+. The Al2(SO4)3 blend is added to solution along with NaOH such that a specific OH : Al molar ratio is attained. A six sided molecule (hexamer) forms. This shape mimics fairly closely the hexagonal structure on the basal surface of many clays. These hexamers are not really soluble; they behave more like a colloid. The pH of the solution is a good indication of what the molar ratio actually is. If the solvent is seawater, a certain amount of NaOH will precipitate dissolved salts. The pH also affects the behavior of the solution. At either high or low pH values, the solution will assume a gel-like consistency. It is theorized that the Al(OH)3 rings promote clay stabilization by satisfying the charges on the clays they contact. The mechanism, which reduces cuttings stickiness, is likely due to a reduction in the double layer and zeta potential of clay plates, when the aluminum compound is introduced. Table 7.23 shows the concentrations and properties typical of the systems used in the Beaufort Sea.


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TABLE 7.23 Al2(SO4)3 SYSTEM ADDITIVE

PRODUCT NAME


Premix:

Seawater Al2 (SO4)3 Aluminum Sulfate 144 NaOH Caustic Soda 60 (to pH 7 - 8) Active System:

Seawater Al2 (SO4)3 Premix to Net 12-15 kg/m3 Al2 (SO4)3 NaOH Caustic 2 Visco XC 84 Xanvis 4.5 Policell Polyanionic Cellulose 3 Typical Properties:

Funnel Viscosity 42 s/l Yield Point 6 Pa Plastic Viscosity 6 mPa•S pH 9.5 API Fluid Loss 8 ml The Al2(SO4)3 should be premixed in a clean, segregated tank. The Al2(SO4)3 compound should be added first, then the NaOH. Emphasis should be placed on safety when adding the Caustic. It should be added through the grate on the tank, not through the hopper. If available a chemical barrel is the safest way to add Caustic Soda. The active system should be formulated in the normal manner. Chemical additions should be added to net the concentrations given in Table 7.2.4 after the Al2(SO4)3 premix has been added. First the total hardness should be treated to below 150 mg/l with Soda Ash and the pH raised to 9 with Caustic. The polymers may be added next. They should be allowed to hydrate properly prior to adding salt. (KCl is often used for freeze point depression in the Arctic). Enough Al2(SO4)3 premix should be added to net an active system concentration of 12 - 15 kg/m3 of Al2(SO4)3. As drilling proceeds, the Al2(SO4)3 concentration is maintained by observing the condition of the cuttings on the shaker. They should appear as free-flowing aglomerates. Sticky cuttings, bit balling or mud rings are indications that the Al2(SO4)3 concentration is being depleted or is insufficient. Quantitative monitoring of aluminum levels is difficult in the field. The method used in the onshore laboratory requires extremely low pH values. At low pH values the test may measure reacted aluminum also resulting in an unreliable indication of available aluminum.


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7.5.10 PHPA Systems Today several varieties of the system are used in various locations throughout the world. PHPA polymer systems are used where shale hydration inhibition is required. Usually KCl is a component of the system. The polyacrylamide polymer has active groups which make the polymer highly surface active, and an effective shale encapsulator, as well as having a filming effect on metal surfaces, thereby reducing or eliminating bit and BHA balling. The inhibition mechanism provided by the PHPA/KCl combination is discussed in the chapter on Polymers - see encapsulation. The PHPA system used by Ava is called the Avapolyvis System. Avapolyvis systems have all the advantages of a shear thinning, low solids polymer drilling fluid with shale stabilizing characteristics. Some of these advantages are listed below: 1. Sloughing shale in both hard shales and younger, soft shales are effectively

controlled by the encapsulation mechanisms. Further stabilization is obtained partially by running the system at lower pH values - reducing the dispersion of the formation.

2. ROP optimization is achieved by improved bit hydraulics due to lower solids

concentrations. The high lubricity of the polymer also helps in this respect - torque and drag are reduced. Equipment is less subject to wear due to the higher lubricity and protective polymer film on the equipment.

3. Surge, swab and circulation pressures are better controlled and help reduce loss

of circulation and stuck pipe, as well as kicks caused by swabbing during bit trips. 4. Cementing and formation evaluation are improved due to less erosion of the

wellbore. 5. Bit balling and the build-up of drilled cuttings on the bit, and BHA is reduced due

to the surface activity of the polymer creating a protective film on the metal surfaces.

6. Improved solids control will minimize the dilution cost. Density and viscosity are

better controlled by the low content of solids. 7. Compatibility with most products makes the system flexible and adaptable and

possible to break over to other systems if desired. 8. The system is environmentally acceptable both ecologically and for the working

environment.


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7.6 AVA DRILLING FLUID SYSTEMS 7.6.1 Spud Muds Native Clays If the surface hole contains bentonitic clays and shales. The hole is normally spudded with fresh water and the pH is adjusted in order to improve hydration of clays. The viscosity is adjusted as required for proper hole cleaning. Bentonite / Caustic Slurry If there is a strong possibility for lost circulation and sloughing (gravel), the well is spudded with a light Bentonite / Caustic slurry in order to provide borehole stability. • Treat out calcium contamination with Soda Ash (Sodium Carbonate) • Adjust the pH to 8.5 – 9 with Caustic Soda (Sodium Hydroxide 0.5 – 0.75 kg/m3) • Mix Bentonite at 3 – 5 minutes per sack raising the viscosity to 40 – 50 s/L (50 – 60 kg/m3) Bentonite / Lime Slurry This is an economical way to achieve higher funnel viscosities. However, not recommended unless lost circulation is encountered. • Bentonite must first be mixed and allowed to hydrate • Lost Circulation Materials (LCM) are added, these include; Sawdust, Cellophane and other

fibrous materials • Then Lime (Calcium Hydroxide) is added to raise the viscosity (clay is flocculated) 7.6.2 Water Drilling SAPP Water (Sodium Acid Pyrophosphate) Used for short water sections, no longer than 600 m. • Drill out surface casing cement with water • While drilling ahead, SAPP is added down drill-pipe in order to disperse drilled solids and

prevent the formation of “mud rings”. • To control mud rings drilling detergent or polymer thinners may also be added. • Density is controlled with the addition of fresh water (dump and dilute). • SAPP water washes are also effective in helping remove filter cakes (disperses Gel and

drilled solids comprising the filter cake).


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Flocculated Water Clear water drilling is most often used to drill upper hole sections. Penetration rates are increased when drilled solids are not present. Flocculation is initiated with what is known as a primary coagulant. A polymer flocculant is then added to settle out the drilled solids. The primary coagulant is a calcium source (Ca2+) or Gypsum (CaSO4-2H2O). Polymer flocculants normally used : These are anionic polyacrylamides, which attach themselves to the coagulated drilled solids and accelerate the settling process (sedimentation rate). • The sump is filled with at least 100 – 200 m3 of fresh water. This volume of water is

necessary for proper settling time. • The calcium ion concentration is raised and maintained at approximately 300 – 400 mg/L with

Gypsum. • Polymer flocculant is then added through a chemical barrel full of water at the flowline

returns. The polymer combines with the already coagulated drilled solids and settles solids in the sump.

• If drilling a water section sumpless, the calcium ion concentration must be at 600 – 800 mg/L. In addition, more flocculating polymer is required in order to facilitate the settling process with the reduced volume.

• Floc water is used for mud up by simply reducing the calcium ion to less than 60 mg/L with Soda Ash (Sodium Carbonate). Lowering the calcium ion will allow Bentonite to properly hydrate and build viscosity.

7.6.3 Bentonite / Chemical Muds This is the most common mud system in use. It provides the necessary carrying capacity and fluid loss control. • Viscosity is achieved with Sodium Montmorillonite (Bentonite / Gel).

Usually, 45 – 55 kg/m3 is added to provide sufficient viscosity. • Caustic Soda is added (0.5 - 0.75 kg/m3) to control the pH at 8.5 – 9.0 for proper hydration of

the Bentonite and added polymers. • PAC materials (polyanionic cellulose) are mixed in order to lower the fluid loss and provide a

thin tight filter cake. Once the viscosity has been raised to 40 – 45 s/L it normally requires 1 kg/m3 of PAC to reduce the API fluid loss to 8 – 10 ml.

• A lower fluid loss is desirable in order to minimize water invasion into the formation. Fluid invasion can cause formation damage and unstable bore hole conditions. A high fluid loss results in thicker filter cakes and can cause problems with the drill-pipe sticking.

7.6.4 GYP Muds (Dispersed Muds) If massive amounts of anhydrite (calcium sulfate) are to be drilled, the mud system is “gypped-over” in order to drill the anhydrite without any further contamination effects from soluble Calcium. • Mud-up with a standard Bentonite / Chemical mud.


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• Prior to the suspected formation containing anhydrite, the pH is raised to 10 – 10.5 with Caustic Soda and maintained. Anhydrite is less soluble in this pH range, therefore hole washout in minimized.

• Prior to the formation containing anhydrite, the system is pretreated with thinners in order to semi-disperse the system. Normally, Desco CF (quebracho) or Avafluid G71 (treated lignosulfonate) is added in concentrations between 3 – 10 kg/m3 depending on how massive the anhydrite. Further contamination effects are controlled with Desco CF or Avafluid G71, Caustic and a polymer thinner as required.

7.6.5 Inhibitive Drilling Fluid Systems Bentonite / PHPA Mud This fluid contains PHPA (partially hydrolyzed polyacrylamide), which provides shale encapsulation. It protects water sensitive shales from hydrating and sloughing into the wellbore. Water sensitive shales include the Fernie and Blackstone formations (these contain bentonitic clays / smectite, which can readily hydrate). • Fill tanks with fresh water, be sure tanks have been cleaned. • Treat out calcium with Soda Ash and increase the pH to 8.5 – 9.0 with Caustic Soda. • Mix no more than 40 kg/m3 of Bentonite and let this hydrate as long as possible in the tanks

before any more product additions. • Mix between 1.5 – 3 kg/m3 of PHPA or polyacrylamide polymers into the system. • Then lower the fluid loss to 6 – 8 ml with approximately 1 – 1.5 kg/m3 of Policell SL material

(polyanionic cellulose). • The viscosity is then maintained with Visco XC 84 at around 1 – 3 kg/m3. The Gel content is

normally kept low (MBT of 30 – 40 kg/m3). • PHPA polymer is added directly into the suction compartment while drilling ahead. Normally

in concentrations of 1 kg over 5 m new hole drilled. This polymer encapsulates shales due to its size and prevents further hydration of shales and subsequent sloughing.

• System is characterized by lower plastic viscosities and high yield points giving an excellent hole cleaning fluid.

Table 7.25 IONIC RADIUS OF COMMON IONS IN DRILLING FLUIDS ION Dehydrated Radius A Hydrated Radius A Na+ 0.95 *2.75 – 5.6 Mg2+ 0.65 10.8 Ca2+ 0.95 9.5 K+ 1.33 *2.32 – 3.8 NH4

+ 1.43 similar to K+ Where A = Angstroms or 1 x 10-10 m. * A range is given because different techniques for measuring the ion radius give rise to different values The Potassium ion K+ and Ammonium ion NH4+ have a small ionic radius and can fit neatly into the hexagonal holes in the silica layer and very effectively neutralize the charge deficiency in that layer.


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Potassium Sulfate Muds This salt is commonly used as a source of potassium (K+ ion). The absence of the chloride ion as in potassium chloride KCl makes this salt more environmentally acceptable. A 3% - 5% concentration of potassium sulfate is effective in preventing the hydration of smectite clays. This ion's size allows it to penetrate the clay layers and prevent the further intrusion of water. The formation of a water layer which is necessary for a clay's hydration is then prevented. When drilling through water sensitive shales, the use of potassium systems has had much success. In order to provide further protection against swelling and subsequent sloughing, polymers such as PHPA (partially hydrolyzed polyacrylamide) are generally added. Potassium brines have had proven success as completion fluids. This brine can protect producing formations from certain types of formation damage. A very small percentage of swelling clays within an oil producing sandstone can cause severe blockage of a producing zone by blocking pore throats and interstitial pore space. Swelling can also dislocate non-sensitive clays such as kaolinite and illite, which can migrate and cause pore blockage. The use of an inhibitive salt will reduce clay swelling damage and particle migration in freshwater sensitive zones. • Dump and clean mud tanks, the system should be initially free of all drilled solids. Fill with

fresh water and raise the pH to 8.5 – 9.0 with approximately 0.75 kg/m3 Caustic Soda. • Mix 30 Kg/m3 of Potassium Sulfate through mud hopper if a 3% K+ ion concentration is

desired. • Then mix between 2 – 4 kg/m3 of encapsulating polymer in order to give added inhibitive

qualities. • Next, mix 3 – 4 kg/m3 of PAC (polyanionic cellulose) to give the required filtration control. • Salt systems are corrosive in nature, recommend the addition of 3 – 5 L/m3 of a corrosion

inhibitor such as Incorr and 1 – 1.5 l/m3 Deoxy SS as an oxygen scavenger. • In a separate premix tank, pre-hydrate approximately 80 – 90 kg/m3 of Bentonite. Let this

slurry hydrate for as long as possible. • Displace the hole to the potassium sulfate water and begin raising the viscosity with the

addition of pre-hydrated Bentonite over 2 or more circulations. • The addition of chemical thinners may be required to control flocculation and subsequent

viscosity increases. • Maintain the MBT at 30 – 40 kg/m3 with the addition of pre-hydrated Bentonite. • Supplement the viscosity with the addition of Visco XC 84 (Xanthan Gum). Potassium Formate (KCOOH) Potassium Formate is an excellent source of the potassium ion. This organic salt is also biodegradable making it environmentally acceptable. The salt is a 72% active solution and when diluted back to 5 % v/v gives a K+ ion concentration of approximately 25,000 ppm. As a powerful anti-oxidant, this product can protect viscosifiers and fluid loss polymers against thermal degradation up to temperatures of at least 150oC. Common polymer additives in this system would include Xanthan Gum, Starch and PAC materials. With respect to formation damage, potassium formate is compatible with formation waters containing sulphates and carbonates, thereby reducing the chances of permeability impairment by salt precipitation. A solution of this salt in fact will dissolve scales such as calcium sulfate and barium sulfate (dependent on concentration).


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AVAPERM System Description Avaperm is a chloride free, clay inhibitor that is 100% soluble in water. As a clear liquid, it is the principal constituent in Ava / Newpark’s HiPerm mud system. There are two ammonium ions associated with the HiPerm molecule making it a divalent cation source. Therefore, after exchange the product is not leached out, as can be the case with the monovalent potassium ion. The hydrated ionic radius of the ammonium ion allows this product to effectively inhibit water sensitive shales. Shale dispersion as well as core flow testing has proven this material to be more beneficial than potassium chloride and potassium sulfate at inhibiting clay hydration. Ava / Newpark HiPerm can actually impart a permanent permeability increase in sandstone reservoirs containing swelling clay. (As the clay dehydrates, the void volume within the pore system increases, resulting in a permeability increase). In testing, when fresh water is finally passed through the plug, the permeability remains higher than the brine baseline that was initially established. Some added benefits include; biodegradability; non-oil wetting; non-foaming; and low-toxicity. Basic Formulation

Product Function Concentration Avaperm Clay Stabilizer 6 - 8 l/m3 Visco XC Viscosity 1.5 - 2.0 kg/m3

Caustic Soda Alkalinity 0.2 kg/ m3 Policell Fluid Loss 1.0 - 1.5 kg/m3 Polivis Clay Stabilizer 3.3 kg/m3 by mass balance

Mixing HiPerm can be added directly to the mud system either through the hopper or directly to the active mud over an agitator.

Maintenance

Due to its unique structure, analysis of HiPerm concentrations by a direct method is possible, however it is best conducted in the lab.

Notes

HiPerm is effective in any pH range, however increased concentration will be required above a pH of 10.5.


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Cleanup

Avaperm is approved for all freshwater disposal operations including the strict Landspraying While Drilling (LWD) criteria. Microtox testing of Ava / Newpark HiPerm resulted in a “pass” evaluation at concentrations of 10 l/m3 and above. A 96-h. trout LC50 occurred at a concentration of 7.8 l/m3. A 120-h lettuce seed emergence test resulted in greater than 80% emergence at 420 mg of HiPerm per kg. Avapolyoil/DEEPDRILLTM INHIBITOR The Avapolyoil/DeepDrillTM drilling fluid system has been used successfully in order to provide inhibition of water sensitive shales. This drilling fluid system performs like an oil-based drilling fluid without the associated environmental problems. Measurements of CO2 evolution on the drilling fluid have found this system to be “readily biodegradable” and thus environmentally friendly. Avapolyoil/DeepDrillTM is a blend of Methyl Glucoside and Polyglyerine. The Methyl Glucoside component forms a semi-permeable membrane. Due to the osmotic pressure differential created, water is actually pulled from shales. In this way hardening of shales is observed similar to that observed with Invert emulsions. Shale swelling and subsequent instability has been eliminated. The Avapolyoil/DeepDrillTM system displays excellent filtration control as compared to other inhibitive clay-free water based fluids, without the need for bridging materials such as calcium carbonate. This drilling fluid has given higher return permeabilities. Increased rates of penetration, reduced torque and drag and elimination of bit balling make this fluid an attractive alternative to other water based drilling fluid systems. Avabiovis (Gel-Free Drilling Fluids)

System Description

Avabiovis is a cost-effective, low damage drilling fluid designed for drilling horizontal wells where acid stimulation is planned. The system uses acid soluble polymers that can be easily broken with acid as well as enzymes or oxidizers. Natrosol (HEC) is the primary viscosifier since it it breaks cleanly – without residuals. Visco XCD, a clarified xanthan, is added if thixotropic properties are required. Because Visco XCD has a charge and is branched, it may be more conducive to creating emulsions than HEC. Acid soluble sized calcium carbonates may be used as bridging agents if required for seepage loss reduction when overbalanced drilling. There are many sizes and grades of Calcium Carbonate available. Ava has a good deal of experience designing these types of bridging systems to ensure efficient size distribution and concentration as well as proper field implementation.

Basic Formulation

Product Function Concentration Natrosol Viscosity 3.0 – 4.0 kg/m³ Visco XCD Viscosity 0.5 – 1.0 kg/m³ Policell SL Filtration Control 1 – 1.5 kg/m³


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Victosal Filtration Control 8.0 - 12.0 kg/m³ Caustic Soda Alkalinity 0.4 kg/ m3 Demulsifier Emulsion Prevention as required Bacteriacide Bacteria Control as required Calcium Carbonate “Small Grind” 10.0 - 40.0 kg/m³ Calcium Carbonate “Large Grind” 10.0 - 40.0 kg/m³

Mixing

Ensure make-up water is pretreated with a biocide. It is possible to build a concentrated system and dilute it while displacing if pit volume is limited. Displace to Avabiovis system after drilling cement with water. Once the system is fully displaced, add Sodium Bicarbonate as required. Add the HEC and slowly, reducing the addition rate if “fisheyes” are observed. Small additions of defoamer may be required. Add Victosal at 30 min/sack, if necessary to reduce fluid loss. Add the Sized CaCO3 - starting with the smallest size first. Adjust the pH if necessary with Caustic Soda. Demulsifier should be added next. Finally add Visco XCD slowly if necessary to adjust rheology up and attain gel strength.

Maintenance

Density as required Calcium Carbonate Yeild Point 2 - 5 Pa Initially HEC Gel Strengths 0/10 - 2/3Pa Initially Visco XCD pH 9 - 10 Caustic Soda Fluid Loss 7 - 10mils/30 min Victosal Bacteriacide as required Avacid Particle size as required Calcium Carbonate Notes Recommend keeping the system in turbulence if practical. Start with coarse mesh shaker screens. The centrifuge can be used - after running for a short period and evaluating its benefit. Dumping and settling will constitute a large portion of “equipment work share”. Mud dumped into buried tanks could be recovered after the solids have settled. If seepage losses occur, add larger sized carbonates to the active system starting with an additional 5 kg/m3. If losses are expected to be more severe, have a pill made up – consisting of active mud with additional carbonates added. If it appears that solids are settling on top of telemetry equipment during trips, displace the inside pipe volume with liquid mud system constituents only (no CaCO3) prior to tripping. If inside pipe volume must be weighted, then ensure gel strengths of that fluid are adequate to suspend all solids.


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CHAPTER 8 OIL-BASED FLUIDS 8.1 Key points and summary 8.2 Oil-based systems

8.2.1 General Description 8.2.2 Advantages 8.2.3 Disadvantages

8.3 Base Oil

8.3.1 The Structure of Base Oils 8.3.2 The Structure of Hydrocarbons 8.3.3 Analytical Terms 8.3.4 Base Oil Specifications

8.4 Brine phase

8.4.1 Balanced Activity 8.4.2 Oil to Water Ratio

8.5 Emulsifiers 8.6 Viscosity control 8.7 Fluid loss control 8.8 Solids and Solids control

8.8.1 Solids in Oil-Based Systems 8.8.2 Decreasing the Mud Density 8.8.3 Solids Control

8.9 Formulation and maintenance

8.9.1 Preparation 8.9.2 Formulation 8.9.3 Properties 8.9.4 Displacement Procedures 8.9.5 Maintenance 8.9.6 Spacers for Cementing

8.10 Drilling problems and trouble shooting

8.10.1 High Viscosity 8.10.2 Fill on Trips and Connections 8.10.3 Hole Cleaning in Large Diameter, Inclined Holes 8.10.4 High Filtration 8.10.5 Emulsion Breaking 8.10.6 Water Wet Solids 8.10.7 Salt Water Flows 8.10.8 Acid Contamination 8.10.9 Differential Sticking 8.10.10 Gas Kicks 8.10.11 Cuttings Disposal


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8.10.12 Losses to the Formation 8.11 Testing oil-based fluids

8.11.1 Emulsion Stability 8.11.2 Density 8.11.3 Rheology 8.11.4 HPHT Filtration 8.11.5 Chloride Determination 8.11.6 Alkalinity Estimation 8.11.7 Calcium Chloride Estimation 8.11.8 Sodium Chloride Estimation 8.11.9 Retort Analysis


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8.1 KEY POINTS & SUMMARY In many aspects oil-based fluid can be described as an ideal fluid because the interaction with the formation is minimal. The main advantages of this situation are that the borehole is stable for an extended time period and the cuttings can come to the surface solids removal equipment in such a size range that a significant proportion can be removed. This reduces the volume of fluid that is used. The main feature is a continuous low viscosity oil phase. This reduces the reaction with the polar or water wetting formations. The oil phase also contains solids such as the weighting material and drilled solids. Again, because of the nonpolar nature of the oil, the viscosity affects of the solids are minimal. Surfactants are used to make the solids oil wet and, more importantly, to emulsify the brine phase. The emulsifiers are a special group of chemicals characterized by the presence, in the one molecule, of two contrasting groups, one with strong attractive forces for water and the other attracting strongly to oil. To stabilize invert of emulsions an oil soluble surfactant must be used. The brine phase contains salts to control the activity of the brine preventing it from being drawn from the fluid into the formation. The factors affecting the activity are detailed in the text. This is a very important factor in formulating an oil fluid. It is not just the oil that prevents the water entering the formation but also the high salinity of the brine phase. Viscosity control is difficult in oil-based fluids and relies on the use of surfactant treated bentonite. The viscosity mechanism is due to water adsorbed on the clay platelets. Fluid loss control is very well developed in oil-based fluids and relies on colloidal particles including colloidal sized water droplets, and differences in wettability. The fluid loss control may be so well developed that the penetration rate is seriously limited. Therefore, invert systems can be designed to have high fluid loss characteristics. Oil-based systems possess properties that are highly desirable and are not obtainable with water-based systems. One of these is the very low level of reaction with the formation, combined with minimal penetration of the fluid phase of the fluid into the formation. This leads to maximum borehole stability over a prolonged time span. The high level of inhibition immediately leads to a number of important operational advantages such as: 1. Gauge borehole - important for directional drilling, log interpretation, minimal

cement volumes and good cement bonds. 2. Efficient removal of drilled solids as they have not been mechanically degraded

by a hydration reactions. This eliminates the need for excessive dilution to control drilled solids, and results in reusable fluid at the end of the well.

3. Excellent filter cake quality that minimizes both the possibility of differential sticking and the level of formation damage in oil-bearing sandstones.

4. Oil-based fluids have friction coefficients at least 50% lower than those of a water-based fluid treated with lubricants. This factor is crucially important when designing a drilling program that utilizes long, high angle holes. Physical limitations of pipe strength and rotary table mean that certain holes should only be drilled with oil-based fluid.

No water-based fluid system has been designed that offers these advantages.


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8.2 OIL-BASED SYSTEMS 8.2.1 General Description Invert emulsion drilling fluids, because of their chemical composition, offer many advantages over water-based fluids. Invert fluids have a continuous phase which is usually either diesel oil or a low toxicity oil (for environmentally sensitive areas) and an aqueous interior phase. The interior water phase is normally a brine solution, formulated with either calcium chloride (CaCl2) or sodium chloride (NaCl). Typically, the brine is emulsified into the oil in droplets less than a micron in diameter. Brine may constitute from 10-40% of the invert emulsion. Invert emulsion drilling fluids are generally used where drilling problems not easily handled by water-based fluids are expected, or in situations where the invert drilling fluid is more economical. The major advantage offered by invert fluids, is increased borehole stability. The following list presents some of the situations where invert emulsion drilling fluids are used: 1) To drill troublesome shales. 2) To drill deep, hot holes. 3) To drill salt, anhydrite, gypsum and potash zones. 4) To drill and core pay zones. 5) To drill through hydrogen sulfide (H2S) and carbon dioxide (CO2) containing formations. 6) To decrease torque and drag when drilling directional holes. 7) As a packer fluid for corrosion control. 8) As a workover fluid. 9) To minimize the likelihood of differential sticking. Invert drilling fluids provide excellent rheological, filtration and oil wetting characteristics which are easily adaptable to various pressure, temperature and wellbore conditions. In addition, these fluids are stable in the presence of high electrolyte concentrations, soluble gases and high temperatures. Invert emulsion drilling fluids are composed of an oil phase, brine phase and specialty additives. Each of these three groups serves important functions in the preparation of a stable invert emulsion (water-in-oil) and in the maintenance of required drilling fluid properties. The additives required in an invert emulsion drilling fluid include emulsifiers, filtration control additives, lime, organophilic clays and weighting agents. 8.2.2 Advantages The advantages and related benefits of oil-based fluids may be summarized as follows: ü A maximum level of shale hydration inhibition is realized. A properly conditioned oil mud

should have no effect on a shale formation. Therefore, gauge hole can be drilled through water-sensitive shales. This leads to improved cement bonding and reduced cement requirements. Improved log response and better cuttings removal are also beneficially affected.

ü The non-polar environment results in consistent fluid properties, low chemical

maintenance costs, stability under high temperature conditions, minimal effects on properties from drilled solids, good resistance to salt and gypsum contamination and good protection to drill string against the corrosive gases H2S and CO2.


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ü Formulation for low fluid loss results in low torque, especially in deviated holes, minimized

differential sticking problems, and low formation damage factors in oil reservoirs. ü Formulation for high fluid loss results in high rates of penetration. The low solids content

and reduction in cuttings stickiness when using oil-based fluids also improves penetration rates.

ü More competent cuttings at surface increase shale shaker workshares. Oil-based fluids

have a higher drilled solids tolerance, which can reduce dilution requirements. ü Due to the excellent stability and solids tolerance, oil mud can sometimes be used for

more than one well. The re-use of oil mud can actually be cheaper than using water-based fluids in some cases.

ü Oil-based fluids have application on wells with high bottom hole temperatures. Oil fluids

have shown stability in wells with logged BHT's of 300°C. ü Low aromatic oil-based fluids result in improved rig conditions, low odor, clean handling

on the rig, minimal effects on the marine environment, low viscosity - imparting improved rheological priories and high flash point giving extra safety.

ü Other advantages include: flexibility with respect to formulation and application, reduced

corrosion rates and a reduction in tubular stress fatigue. 8.2.3 Disadvantages The disadvantages of oil-based fluids may be summarized as follows: 1) High make-up cost. 2) Environmental restrictions including: cuttings disposal and dumping restrictions. 3) Extra fire prevention precautions are necessary. 4) Reduced rates of penetration in some areas. 5) Gas intrusion can result in barite settling. 6) Compressability of base oil makes density estimations difficult. 7) Hole cleaning and cuttings suspension may be less effective. 8) Rubber materials such as hoses of BOP components may dissolve rapidly in oil-based fluids. 9) Some types of electric logs are ineffective in oil-based fluids. 10) Gas intrusions are more difficult to detect using oil-based fluids. 8.3 BASE OIL The liquid phases of an invert fluid are oil and emulsified water. Solids are contained solely in the oil phase. Generally, the water content does not exceed 50% by volume of the liquid phase. Therefore the properties of the oil greatly influence the overall properties of the fluid. The essential function of the base oil is to provide a non-polar continuous phase and thus avoid the polar interactions between the drilling fluid and the formation (hydration) that takes place in a water-based fluid.


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It is important when drilling with an invert emulsion that all solids, the formation and the drilling equipment be wetted with oil only. Therefore, enough oil must be present in the system to insure that all components are oil wet. Under normal conditions, invert emulsion drilling fluids containing a minimum of 70% oil should insure proper oil wetting at fluid densities up to 2,200 kg/m3. Some invert emulsion fluids use diesel oil as it provides stable emulsions at an economical price. Low toxicity oils, can be used in place of diesel oil for invert emulsion drilling in environmentally sensitive areas. HSE issues Recently, concern has been raised from several industry associations about the use of high-risk base oils in drilling muds systems. Fluids with a flash point below 61oC (PMCC) and high aromatic contents should be considered high risk. Care should be taken when using such base oils to minimize any problems that might arise. When using base oil always read the MSDS carefully, and follow the MSDS recommendations for safe handling procedures. Always try to limit your exposure to hydrocarbon airborne mists. Avoid skin contact and if not possible use a recommended barrier cream to keep it off your skin. If your clothing should become soaked with hydrocarbons a change of coveralls is recommended. You should always wear eye protection, gloves (hydrocarbon resistant), boots (hydrocarbon resistant) and coveralls (slicker suits) when using hydrocarbon-based fluids. Always follow safe work practices! As a result, operating companies have started using alternative base oils with lower aromatic contents and higher flash points. Mud systems formulated with these lower aromatic oils provide several advantages. Besides reducing the health hazards normally associated with exposure, the degradation of elastomers is reduced, as is liability associated with transporting and handling as well as any disposal issues. Despite the higher cost, many operators feel there is value added in using low aromatic hydrocarbons for drilling. Base oil table: Properties of Available Base Oils Properties Drillsol HT 40N IA-35 Diesel Distillate

822 Shell SOL D80

HDF 2000

Lamium 11C

Enviro –Drill

Density at 15oC - kg/m3

839 830 828 840 884 894 808 795 802

Flashpoint IRP (>61oC)

75oC CC) 129oC (CC)

132oC (OC)

53oC (CC)

77oC (CC)

73oC (CC)

102 oC (OC)

60oC (CC)

80oC (CC)

Aniline Point IRP (>65oC)

69.9oC 79oC

92oC 54oC 58oC 74oC 89oC 82oC 65oC

Kinematic Viscosity

4.20 cSt. 20oC

3.4 cSt. 40oC

3.8 cSt. 40oC

1.6 cSt. 40oC

5.7 cSt. 40oC

1.84 cSt. 21oC

3.3 cSt. 40oC

1.7 cSt. 40oC

N/A cSt. 40oC

Pour Point -20oC -33oC

-55oC -34oC -45oC <-24oC -45oC

Aromatics < 12.5% <2.2%

<0.01%

33% high 1.90% < 1%

BTEX IRP (<0.01 wt%)

<0.02% <0.002%

TMB IRP (<0.3 wt%)

1.4%

Microtox (on leachate)

Fail Pass Pass Fail Pass (charcoal)

Pass Pass (EPS 1/RM/24


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8.3.1 The Structures of Various Base Oils Base oils can be broken down into two categories, synthetics and hydrocarbons. Synthetics are base oils that are synthesized from other molecules and are generally very pure substances. Synthetics include: linear alpha olefins (C12, C14, C16 or C18) made from ethylene.

C14 alpha olefin Isomerized (C12, C14, C16 or C18) olefin again made from ethylene. The double bond is randomly isomerized along the carbon change. This isomerization drastically affects the viscosity and the pour point of the synthetic oil.

C14 olefin

C14 olefin Esters, are typically made from the esterification of vegetable oils with alcohols.

O

O

Ester Iso-paraffins are made from paraffic hydrocarbons by a series of reactions with hydrogen and platinum catalysts, this also decreases the aromatic content of the base oil.

Iso-paraffin


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One of the main properties of the synthetic base oils is that they are very biodegradable and tend not to be toxic to marine organisms. The main drawback is the price because of all the processing required to make the molecules, the costs of these fluids tend to be quite high. 8.3.2 The Structure of Hydrocarbon Base Oils Hydrocarbon base oils are composed of hydrocarbons (i.e. diesel C10-C18), and come from refined crude oil feed stocks. The composition of oils is quite complex with (typically) over 200 different molecules, but the structures can be simply described in terms of three classes of hydrocarbons. Paraffin’s have a general formula CnH2n-2. They can have a linear arrangement of molecules where each carbon is attached to two carbon atoms or branched where the carbon can be attached to three or four carbon atoms. These structures are given in Figure 8.1a for a C-10 paraffin. Higher paraffinics can increase the viscosity and give problems with high viscosities at low temperatures.

C10H22142.28

142.172151C 84.42% H 15.58%

Decane

Naphthenes have a cyclic structure with the carbon atoms typically forming a six-membered ring. There may be more than one ring fused onto another. These structures are given in Figure 8.1b. Naphthenes are better solvents than paraffins and provide good flow properties at low temperatures. They may be prepared by hydrogenation of aromatic hydrocarbons.

C6H1284.16

84.093900C 85.63% H 14.37%

C10H18138.25

138.140851C 86.88% H 13.12%

Aromatic hydrocarbons contain carbon-carbon double bonds, which have a higher level of polar character due to the additional electrons in the bonds rather than saturated bonds in paraffins and naphthalenes. The structure is given in Figure 8.1c. The polar character contributes to the solvency of the oil that is well developed. Water is more soluble in aromatic hydrocarbons than in other hydrocarbons. The greater solvency power means that the toxic and carcinogenic properties of oils are more closely related to the aromatic fraction. Therefore, the toxicity can be reduced by removal of aromatic hydrocarbons. This can be done by essentially two methods of hydrogenation and solvent extraction. The aromatic fraction also gives a characteristic odor so its removal makes the oil more pleasant to use.


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C6H678.11

78.046950C 92.26% H 7.74%

C7H892.14

92.062600C 91.25% H 8.75%

Benzene Toluene

Complex hydrocarbons can also be present such as those shown in Figure 8.1d where there are paraffinic side chains on napthenic or aromatic groups.

C10H12132.21

132.093900C 90.85% H 9.15%

8.3.3 Analytical Terms The following terms are used to describe some of the characteristics of base oils: Flash Point - is the temperature at which oil vapors form a flammable mixture with air. Volatile, light, products like gasoline have a flash point below 5°C. A flash point of 61°C or higher is recommended. Fire point - is the temperature at which vapors will ignite and burn steadily. This parameter is less important than the flash point. A point of 93°C or higher is usually required. Bubble point - is the temperature at which the oil starts to boil. An oil with a low initial boiling point (IPB) will give off more vapor at the shakers than an oil with a high boiling point. A final boiling point (FBP) can be defined to exclude health hazardous Poly-Aromatic-Compounds (PAH). The aniline point of the oil is widely used as an indication of how likely the oil-based drilling fluid will degrade specific elastomers (rubber). The standard test for the aniline point of a mineral oil is ASTM procedure D-611. This method measures the solvency power of the test oil for the aromatic chemical, aniline. Aniline solubility in an oil increases as the temperature of the oil increases. The temperature of complete solubility (where a specific volume aniline dissolves in a specific volume test oil to form a non-cloudy solution) is called the aniline point. The lower the temperature at which complete aniline solubility occurs, the more like the oil will damage rubber goods. Based on experience with diesel fuel, an aniline point of at least 150°F is desirable to


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minimize degradation of blowout preventer elastomers, pump swabs, shaker-screen cushions, etc. In cold climates, the pour point of base oil is a key factor in handling characteristics of a drilling fluid, particularly in solids separation. The specific pour point needed for base oil depends on local climate conditions. The pour point of oil is the lowest temperature at which the material can be freely poured. The pour point of oil is measured by cooling a sample in 5°F increments. The test container is tilted at each temperature level. The first temperature at which the tilted sample shows no movement within 3 seconds is called the pour point. One of the key characteristics for a mineral oil is its aromatic content. Several different analytical methods measure the aromatic content of oil. Three of these are: the fluorescent indicator adsorption method; an ultraviolet light method; and an infrared light method. Each method gives repeatable results. The UV (ultraviolet) method is used for oils containing less than 2% aromatics, and FIA (fluorescent indicator adsorption) and IR (infrared) methods are used for oils containing more than 2% aromatics. For proper comparison of the aromatics content of mineral oils, it is necessary that the analytical results be from the same tests. In the fluorescent indicator adsorption method the fluid is passed through a column of silica gel adsorbent. The aromatic compounds are separated from the other hydrocarbon compounds according to their unique adsorption affinities for silica gel. The aromatic content is calculated from the length of the aromatics adsorption zone in the column. The value from this method is a total aromatic content. In the ultraviolet light method the UV light adsorbing of the oil is measured within the wavelength range of 260 to 275 nanometers. Based on prior instrument calibration, this is converted into an aromatics concentration. This concentration represents the total amount of aromatic molecules in the oil. In the infrared light method, the adsorption of infrared light at a specific wavelength (1,630 nanometers) is measured. This method measures only the carbon in the aromatic rings and not the total aromatics. Any side chains on the aromatic rings are not included in the concentration calculated from the infrared method. Users of mineral oils should know the method(s) used to determine aromatic contents, especially when comparing various mineral oils. Table 8.1 shows the result for mineral oils tested with the different techniques. Note that in most of these cases the aromatic content quoted from infrared analysis is lower than that determined by FIA. Some mineral oils used in the North Sea are tested using the infrared method, whereas mineral oils in the U.S. are typically tested with FIA or UV methods. This difference has led to confusion in comparing the aromatic content of mineral oils.


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TABLE 8.2: AROMATIC CONTENT OF DIFFERENT BASE OILS USING THREE TESTING TECHNIQUES Base Oil Tested FIA UV IR

Mineral Oil A 20 - 13

B 4 - 4

C 16 - 12

D - 0,8 -

E 16 - 14

F - 0,2 -

Diesel Fuel 30 - 25

The density of the base oil is recorded to give an indication of the lowest possible mud weight for that particular oil. It is desirable that the viscosity of the base oil shows little variation with temperature, an indication of such variation can be obtained from comparison of viscosities taken at 40°C and 100°C. 8.3.4 Base Oil Specifications Invert drilling fluids were traditionally formulated with diesel oil as it met the requirements of viscosity and flash point; it was readily available at the rig site and relatively inexpensive. A typical analysis is given in Table 8.1. It shows the high and variable content of aromatic hydrocarbons. The oil has good solvency and formed stable emulsions. However, concern grew for the toxic properties of diesel based fluids to the rig personnel and to the marine environment when oil contaminated cuttings were disposed of at sea. The response was to use more highly refined oils specifically designed to oil well drilling. A range of typical specification is also given in Table 8.1. The wide range of properties of the oils given in Table 8.1 stems from differences in the feed stock available to the oil companies, processing capabilities and also from the priority given to a particular properties of the oil. The viscous properties of base oil are important and should be determined over a wide temperature range. The fluid may be exposed to temperatures below 5°C and should not become too viscous to pump. The pour point should not be above -10 to -15°C. The properties of the oil influence the performance of the emulsifiers and the organoclay viscosifiers. Generally these additives perform better in oils with higher aromatic levels. Base oils are detrimental to elastomers as they may swell and dissolve the rubber. The higher the aniline point the lower the solvency. The refined oils tend to be less harmful than diesel oil.


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8.4 THE BRINE PHASE 8.4.1 Balanced Activity The brine phase contributes to the rheological and filtration properties of the drilling fluid. The inclusion of a brine or water phase in an invert emulsion ensures that desirable non-Newtonian properties are incorporated into the drilling fluid. An important aspect of the brine phase is referred to as "activity". The term activity, in a drilling sense, describes the tendency for the movement of water vapor from an area of low salt concentration to an area of high salinity. The water activity (Aw) is measured as a fraction of the vapor pressure of water or relative humidity. In an invert emulsion drilling fluid the brine phase is not isolated from the formation by the oil phase. Water vapor may pass from the brine droplet into the formation or vice-versa depending upon the osmotic pressure differential between the brine phase and the formation. The osmotic pressure of the formation or brine phase is a measure of the activity and salinity of the formation and brine. The concentration of salt in the brine phase will largely determine whether water will flow from the brine to the formation, from the formation into the brine phase or whether there will be no net movement of water in either direction. Table 8.3 presents different activities (Aw) for saturated salt solutions. TABLE 8.3: WATER ACTIVITIES (AW) FOR SATURATED SOLUTIONS OF VARIOUS SALTS AT 20°C. Salt Solution

Water Activity (A W)1

Distilled H2O 1.00

KCl 0.86

NaCl 0.76

MgCl2 0.33

CaCl2 0.32 1. Solutions that are not in the saturated state will have higher Aw values. The ideal practice when drilling would be to have balanced activities between the formation water and the drilling fluid brine phase. A balanced activity would mean that no net water migration between the formation and brine phase would occur. The desirable balanced activity condition may not always be possible during the drilling program since formation activities can be variable. In practice, the brine phase is often run with a lower Aw value (higher salt concentration) than those values expected in the formation. This results in a small net movement of water vapor from the formation into the drilling fluid. Figure 8.2 shows how the Aw changes with depth.


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Figure 9.2 Variation of Formation Activity with Depth for a Normally Consolidated Sediment

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0.7 0.75 0.8 0.85 0.9 0.95

Aw

Dep

th (

m)

To achieve a balanced activity between the invert emulsion brine phase and the formation, an accurate activity measurement of the formation must be known. Formation activity is best taken from consolidated pressures either calculated from density logs or from assumptions of the density gradient. Brine activities are most often adjusted using sodium chloride (NaCl), or calcium chloride (CaCl2). When drilling through rock salt sections or where high activities are expected, sodium chloride is the preferred brine phase component. Calcium chloride is a general-purpose brine phase for inverts as its activity is easily adjusted to shales of varying activities. TABLE 8.4 CALCIUM CHLORIDE BRINE DATA (SEE ENGINEERING FIELD MANUAL). TABLE 8.5 SODIUM CHLORIDE BRINE DATA (SEE ENGINEERING FIELD MANUAL). The formulation of an invert fluid generally requires the oil content to be greater than the water content so an oil to water ratio (O/W) of 50/50 is probably a minimum at the present time. The solids contained in the system must be entrained in the oil phase so the oil content of the system, on a volume basis, should be kept constant. Therefore, the oil content should increase as density increases.


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TABLE 8.6: VARIATION OF OIL WATER RATIO AND MUD DENSITY MUD DENSITY RANGE

Oil / Water Ratio

SG CONVENTIONAL HIGH WATER CONTENT

1.0-1.2 50/50 50/50

1.2-1.32 65/35 50/50

1.32-1.5 70/30 55/45

1.5-1.68 75/25 60/40

1.8-1.92 80/20 65/35 An indication of the relationship between O/W ratio and density is given in Table 8.6 for conventional fluids and those formulated with stronger surfactants. Higher levels of oil will impart a higher level of stability to the system providing a greater resistance to brine flows and solids invasion. Higher oil content allows the rheological properties to be adjusted to higher ratios of yield point to plastic viscosity or lower n values. These properties may be considered more favorable from a point of view of hole cleaning properties. High water content fluid formulations are used to lower the cost of the fluid and also lower the levels of oil discharged after treatment on shaker screens. These advantages are gained at higher risks of the mud 'flipping' and higher plastic viscosities. The colloidal sized water droplets interact with each other and contribute to the rheological properties, particularly the plastic viscosity. Table 8.7 gives the range of properties typically found for an invert oil mud with density of 1200 kg/m3. This shows that in high oil content systems the ratio of Plastic Viscosity to Yield Point (PV / YP) could be adjusted to be near 1/1. In systems with a high water content it is nearer to 3/1, indicating a decrease in the shear thinning character. This may adversely influence cuttings transport. By comparison, the 100% oil mud exhibits low plastic viscosities. TABLE 8.7: TYPICAL RHEOLOGICAL PROPERTIES FOR A 1,200 KG/M3

INVERT OIL MUD WITH DIFFERENT RATIOS OF OIL/WATER

Oil/Water Ratio

Plastic Viscosity CP

Yield Point lb/100 ft2

50/50 35-45 20

70/30 20-25 20

95/5 10-15 20 8.5 EMULSIFIERS Preparation of a stable water-in-oil emulsion is dependent upon two factors: the size of the brine droplets and the efficiency of emulsifiers that produce and maintain the emulsion. Smaller water or brine droplets are produced at higher rates of mixing or shear with a more stable, tighter emulsion resulting. A tighter emulsion is generally more viscous than a less stable emulsion. The smaller brine droplets in a tight emulsion are less likely to coalesce when they collide than larger droplets. It is the function of the emulsifiers to isolate the brine droplets and prevent any coalescence.


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Emulsifiers are also important in ensuring that solids in the invert emulsion are preferentially wetted by the continuous oil phase. Without oil wetting characteristics, the solids, especially barite would become water wet and the overall result would be poor emulsion stability. Invert systems use a blend of emulsifiers formulated to ensure emulsion stability for any brine at a range of brine concentrations. The primary emulsifier is an alkyl fatty acid emulsifier. Addition of lime to the primary emulsifier converts an "inactive" emulsifier into its "active" or working form. This activation with lime may be depicted in Figure 8.3.

OH

O

Fatty acid

Ca(OH)2

Activated fatty acid

2

O

O

O

OCa

The hydrophilic portion of the active emulsifier form is intimately associated with the brine droplet at the oil-brine interface, while the hydrophobic portion of the emulsifier is dissolved in the continuous oil phase. In addition to the primary emulsifier other emulsifiers called secondary emulsifiers are required to produce a stable invert emulsion for invert drilling fluids. These emulsifiers however, do not require the addition of lime or any other chemical for emulsifier activity to be realized. Their structures are depicted in Figure 8.4.

The hydrophilic portion of the emulsifier has functionalities being hydroxyl (OH), amine (NH2) and / or amide (CONH2), which are associated with the brine phase of the emulsion. Preparation of a stable emulsion for the low toxicity systems requires a more powerful emulsification system than


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that normally needed for diesel-based systems. This is because a number of the low toxicity oils are inherently more difficult to emulsify due to the low aromatic content. When formulating an invert emulsion drilling fluid it is important to have sufficient emulsifier(s) present to be able to coat the brine phase completely. Coalescence of brine droplets and a resultant loss of emulsion stability will occur if insufficient emulsifier is present. Figure 8.5 represents a stable brine droplet in an oil matrix in an invert system.

Brine droplet

OilOil

Oil

Figure 9.5 Emulsified Brine 8.6 VISCOSITY CONTROL The viscous properties of an invert emulsion fluids are developed by; oil, emulsified water, oil wetted solids (weighting agents such as barite and drilled solids) and specially processed bentonite treated with quaternary amines (organoclays). Thus the viscous properties are determined to a significant degree by the oil/water ratio and the fluid density. The shear thinning character and thixotropic properties is specifically developed by the organoclay. The level of viscosifier required will be decreased by an increase in density and water content. The major contribution to non-Newtonian rheology is derived from organoclays. These are bentonites in which the inorganic exchangeable cations sodium, calcium and magnesium have been displaced by quaternary amines such as dimethyl, di (hydrogenated tallow) ammonium chloride or dimethyl, benzyl, ammonium chloride. These cationic surfactants change the wetting character of the bentonite from being water wettable to being oil wettable. The viscosity properties have to be developed by the dispersion of the stacks of clay platelets. This is achieved to some extent by mechanical factors such as shear intensity, shear time, and temperatures. Polar compounds such as the aromatic molecules in diesel oil or water also play an important role. Adsorption of these molecules opens up the sheets and aids the dispersion process. Water is required to create the conductive medium in which ionic bonds and other polar interactions can develop between the clay sheets.


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The use of organoclays is thus quite complex and will depend on many factors such as those listed below: ü Shear intensity and time ü Base oil characteristics ü Type of organoclay - ü Clay type - montmorillonite, hectorite, ü Clay processing ü Quaternary amine ü Emulsifier type ü Temperature application

These factors should be taken into account when selecting the clay and the viscosity response should be determined for the particular formulation. The use of oil-based systems with high yield points in deviated wells has lead to the development of a number of polymers that assist the viscosity developed by clays. This allows oil mud’s to exhibit highly shear thinning rheology. One group of polymers is described as oil soluble polymers. These are incorporated into the clay. The other group of products is synthetic latex products that contribute to both fluid loss control and viscosity. They are presented as an emulsion. 8.7 FLUID LOSS CONTROL Invert emulsion drilling fluids typically have small fluid loss values under high temperature-high pressure test conditions. Although test conditions cannot completely model for downhole situations, it is likely that low fluid loss values do occur downhole during the drilling program. There are a number of reasons for the low fluid loss values. When the invert fluid contained in the annulus contacts the formation walls there is a small initial loss of oil to the formation. The brine phase then acts as an impermeable membrane along the formation walls to retard the movement of oil into the formation. In addition, the oil phase of invert fluids does not readily enter the water-wet formations due to a high interfacial tension between the oil and formation water. In addition to the filtration control imparted by the oil and brine phases of invert emulsions, invert systems employ supplemental fluid loss control materials. These materials are high temperature stable and oil dispersible. Asphaltic bitumen is the most common fluid loss additive used. Amine treated lignite may be used in the place of asphaltic bitumen. Relaxed oil muds have been designed for fast drilling, with a HP/HT fluid loss as high as can be tolerated. A relaxed oil mud has the same chemical composition as an ordinary oil-based fluid. The difference being that the former fluid system is run on the borderline between functioning and breaking down. To relax an oil mud and increase the fluid loss, base oil, CaCl2 brine or water need to be added to the mud without the usual additions of emulsifiers, oil wetting agents etc. The additions of the emulsifiers and so on would change the mud system back towards a stable system. Relaxed oil muds require rigorous pilot testing and continual monitoring. In order to relax a conventional oil mud, large increases in volume have to be expected due to the amount of dilution that is required.


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8.8 SOLIDS AND SOLIDS CONTROL 8.8.1 Solids in Oil-Based Systems All materials in an invert emulsion should be kept oil wet; this is especially important for the weighting agents since it often constitutes a large amount of the solids content of the invert. If barite, the usual weighting agent, is allowed to become water wet, the barite will not suspend in the invert. An invert drilling fluid containing water-wet barite will be unstable and often take on a dull, grainy appearance. In a manner similar to most drilling fluids, invert emulsion formulations should contain a minimum of drilled solids. The use of solids control equipment should efficiently remove the normally non-dispersed drilled solids contained in the invert system. Although drilled solids are normally oil-wetted and are thus not dispersed, the solids will disrupt the invert system by attracting water from the brine phase in an attempt to stabilize their environment in the oil phase. The presence of drilled solids in invert systems has the same adverse effects on the rate of penetration as in water-based systems. Their presence requires treatment with oil wetting agents, which can be expensive. These requirements impose an upper limit on the solids content of the oil mud at a given oil/water ratio. Hence it is very important to optimize the use of the available solids control equipment. The primary control of drilled solids as accomplished by the use of fine screen, high-speed shale shakers, hydrocyclones and centrifuges. 8.8.2 Solids Control A major limiting factor regarding solids control with oil-based fluids, as opposed to water-based fluids, is the important fact that any dumping (transfer to a storage pit) or dilution of the system will result in unwanted volume increases which becomes logistically difficult to store offshore and very expensive to transport ashore for disposal. It is therefore imperative to maximize the use of solids control equipment to remove as much drilled solids as possible. Drilled solids that are not removed by solids control equipment must be diluted. Shale shakers remain the best line of defense for controlling drilled solids concentrations in oil-based systems. The advent of high-speed linear motion shakers has improved solids control efficiency - leading to reduced costs. In an unweighted system, the desilter may be bypassed or if run, the underflow could be screened. A mud cleaner would be used to remove sand and save fluid. A high volume centrifuge can 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. In weighted systems, the mud cleaner can be run to remove sand. The centrifuge would only be run for viscosity control. In unweighted water-based fluids, the liquid phase is the most expensive phase. As the density is increased there is a point where the cost of the barite becomes more expensive than the liquid phase. At this density, efforts are concentrated on barite recovery. This is not the case in oil fluids. Hence it is necessary to try and recover both the liquid phase and the barite, yet discard as much of the drilled solids as possible. In a two-stage centrifuge system, the first centrifuge to recover is barite. The centrifuged fluid would then be fed to a second (high speed) centrifuge, which would remove and discard ultra fine solids. The "clean" fluid would then be put back into the mud system and also be used for dilution of the first centrifuge. As long as the clean mud weight is not excessive, this procedure can be


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economical. At some point in time, whole fluid will have to be removed from the system for viscosity control. 8.9 FORMULATIONS AND MAINTENANCE 8.9.1 Preparation Often minor modifications to drilling rig components must be made in order to realize the economical benefits and safety requirements of oil-based fluids. The following considerations should be addressed:

1. All centrifugal pump lubricators should be changed from water to grease or diesel fuel to minimize the risk of unwanted water additions.

2. All rubber components of the circulating system (BOP parts, pump parts, etc.) should be

changed to an oil resistant material such as Neoprene.

3. If a kelly cock valve is not available on the rig, one should be installed and used to minimize lost volume on connections, etc.

4. A mud bucket should be rigged up and used regularly on trips to avoid loss of volume.

5. A lined cuttings pit or a cuttings catch tank of sufficient volume to contain the anticipated

cuttings volume will confine the cuttings in a workable manner.

6. A cuttings conveyor to move cuttings from the shaker to the cuttings holding tank or sump is required.

7. The surface tanks should be covered and drain lines installed to ensure that rain or snow

run off does not result in unwanted water additions to the system.

8. All water lines should be secured. Cleaning on the rig, especially around the mud tanks should be done with diesel fuel.

9. A diesel fuel wash gun should be installed at the shaker.

10. The rig floor around the rotary table should be sealed with 3" - 6" plate welded on its

edge.

11. A drain from the rotary table area should connect to a drip pan located below the rotary table. Any spillage can be returned to the active system via another drain connected to the flow line or a sand trap. The drainage from the floor outside the main working area should be connected to the normal offshore drainage system.

12. A collector pan should be installed at the pipe rack with drainage to the drip pan below

the rotary table in normal circumstances and diverted to the normal rig drainage system during heavy rain.

13. The normal rig drainage system should be modified in the areas where there is contact

with oil-based fluid. All open drains to the sea should be sealed, and diverted to a central collecting tank for treatment/disposal. The drainage outside the general oil base contact areas should be the normal offshore system.


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14. An outside pipe wiper should be placed below the rotary bushing to reduce spillage

during trips. Inside wipers will also reduce spillage in the racking area.

15. The drill floor rathole and mousehole must be sealed. This can be accomplished by welding a reducer to the end of the pipe with a valve on it. Any oil mud that accumulates in either pipe can then be drained into a drum and pumped back to the mud system or disposed of properly.

16. All possible spill areas should be sealed off with 3" - 6" plate. This includes the mud

pump area, centrifugal pump locations, and mud hoppers. The concept is to localize and contain all spills so that they can be soaked up with absorbents and disposed of.

17. Safeguards against oil spills should be taken. The liberal use of oil absorbent materials

and a good rig wash detergent are recommended to keep a clean rig site.

18. Adequate ventilation should be provided in the mud processing areas. 8.9.2 Formulation Invert system formulations are usually fairly flexible enabling them to meet the required properties for specific applications. Drilling fluid programs contain the specific concentrations of all additives required for individual systems. When mixing a new invert system, planning is important. Adequate tank space, materials and mixing equipment are necessary to achieve the most economical use of system components.

1. The mixing order of chemicals is also extremely important in order to achieve a stable system. The mixing order usually proceeds as follows:

2. Fill the mixing tank with the required volume of base oil.

3. Add total volumes of emulsifiers and fluid loss additive. Mix products thoroughly because

shear is necessary to obtain the most stable emulsion.

4. If a premix tank is available, adding the salt to the water over a 30-minute period with agitation should premix the brine phase. Add the brine slowly to the mixing tank under maximum shear after the diesel and chemicals have been mixed as in step 2. Premixed brine may be stored for later use.

5. Add the lime and shear. Maximum invert stability is achieved with maximum shear and

time.

6. Add clay while circulating in increments no larger than 5.0 kg/m3. The product requires 1-2 circulations to yield.

8.9.3 Properties The following list of properties outlines a general set of guidelines for running invert systems, although a wide range of fluid properties is possible.


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Density Maintain as low as formation pressures will allow by ensuring proper operation of solids removal equipment.

Funnel Viscosity Maintain at 35-40 s/l (room temperature) by small additions of

organoclay (0.7 kg/m3). Insure that viscosity measurements are accompanied by a flow line temperature reading.

Plastic Viscosity Optimum value is 15-20 mPa•s and is usually maintained by

controlling solids. PV may be reduced by the addition of oil and increased by adjusting the oil/brine ratio. An increase in fluid density will result in higher PV's.

Yield Point 1.5-4.0 Pa initially. Raise yield point by adding organoclay. A

decrease in yield point occurs by the addition of oil. Fluid Loss High temperature/high pressure (250oF, 3400 kPa) filtrate should be

less than 8-10 ml and contain no water. The HT/HP fluid loss test may be performed at various temperatures, including wellbore temperature.

Emulsion Stability Emulsion stability should exceed the static bottom hole temperature

or 250 (whichever is greater). Low emulsion stability may be accompanied by water in the HT/HP filtrate. If no water is present in the HT/HP filtrate, and low emulsion stability is observed in the invert system, suspect highly conducting salts or solids in the invert. Some operators require emulsion stability values of above 250.

Gel Strength The gel strength ideally should be 2/4 Pa. Higher gel strengths

indicate either a degrading emulsion (increase in water content) or excessive solids build-up.

NOTE: All rheological data (plastic viscosity, yield point and gel

strength) and emulsion stability should be attained at a constant temperature. Commonly, a temperature of 50oC (120oF) is used.


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8.9.4 Displacement Procedures In order to properly displace the hole from a water-based system to an invert the following procedures should be used:

1. Reduce the rheological properties of the water-based fluid.

2. If possible, displace prior to drilling out. Always displace on bottom.

3. Clean the surface equipment and mud pits thoroughly and reseal all gates and troughs.

4. Prepare a weighted spacer (25 kg/m3 heavier than the active mud).

5. Add additional emulsifier / surfactant or base oil / wetter to the first 10-15 m3 of fluid to be pumped.

6. Oil-wet the shaker screens with a mixture of base oil and surfactant.

7. Displace to invert mud by pumping first the weighted spacer, then the treated mud,

followed by the new invert mud. Keep the pump rate constant.

8. Work the pipe while displacing.

9. Dispose of any contaminated (interface) fluid.

10. Spot-check the oil/water ratio several times over the first 2-3 circulations.

11. Reduce shaker screen sizes as soon as possible. 8.9.5 Maintenance Oil-based fluid maintenance is much easier than with water-based fluids mainly because the drilled solids do not build up in the mud. The properties therefore stay much more stable and maintenance essentially requires new volumes to replace the volume of new hole and the fluid removed with the drilled solids. The fluid loss test is the most indicative test of changes in emulsifier level. A change in the fluid loss and, particularly, water in the filtrate is a good indication that the emulsifier level is becoming depleted. The treatment should be made with the range of emulsifiers normally used. The total water content of the mud should be carefully monitored and additions of new volume made as accurately as possible to ensure that the water activity of the brine is correct. 40-45 s/l is the desired funnel viscosity range but will be governed by Yield Point requirements. The flowline temperature should be reported with funnel viscosity measurements. Fluid velocities of 40-45 m/min should provide good hole cleaning, although higher velocities may be required if hole cleaning problems are noted or suspected. The plastic viscosity (PV) of low density invert fluid should be 8 - 12 mPa•s. All rheology testing should be performed at 50oC (122oF) and the temperature should be reported on the mud report. PV is most affected by solids concentration and oil/water ratio. The PV can be decreased by


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increasing the oil content or by dilution with low solids invert mud. If desired, lowering the oil to brine ratio can increase the PV. The Yield Point initially should be maintained at 4-8 Pa. The YP can be increased with additions of organoclay at 0.7 kg/m3 per circulation. The YP can be decreased with the addition of base oil or with certain surfactants. HP/HT testing should be performed at the estimated BHT +10oC (or 90oC) and at a differential pressure of 3450 kPa (500 psi). The filtrate should contain no free water. If free water is observed in the filtrate, the emulsion should be tightened with additional emulsifier additions. The ES should be maintained as required and can be increased with additional surfactants. Should an influx of water occur, or a reduction of the oil/water ratio is desired, calcium chloride 94% powder only should be mixed into the active system. If calcium chloride 77% flake is used, it must be pre-solubilized in water prior to its addition to the active system. Maintain the excess Lime content at 2.0 kg/m3. This excess is required as Lime is essential to ensure that the emulsion will not break down due to water wet solids, water flow or brine flow. The Lime reacts with the fatty acids in the emulsifier to form stable calcium soaps. Excess Lime will also act as an H2S scavenger in invert mud should sour fluids enter the system. Maintain the density as low as formation pressures will allow by efficient use of the available solids removal equipment. 8.9.6 Spacers for Cementing There are two main reasons why a spacer is needed when cementing a well, which has been drilled with an oil-base fluid:

1. The mixing of a cement slurry and an oil-base mud usually produces a highly gelled mass. This can cause high friction pressures with danger for lost circulation, and channels of gelled mud remaining in the annulus after the cement is in place. In severe cases the cement mud mixture can be unpumpable and result in a failure to displace the mud and cement to the desired position.

Low activity oil muds (high salinity water phase) may also result in flash setting of the cement. The spacer must therefore be compatible with both cement and mud, and shall prevent, mixing of the two systems.

2. The oil mud leaves the hole and casing walls with a film of oil on the surface, which

results in a poor bonding of the cement. The spacer should remove this oil film, and convert the oil-wet surface to a water-wet state and thus improve the cement bonding.

The term "flush-fluid" is used to characterize a fluid designed to wash and dilute a drilling fluid in a well bore in preparation for the cement slurry. For an oil-base mud a spacer is usually water solution with demulsifying agents, which thin and disperse the mud, thereby aiding in its removal. A flush may also contain, in addition to the demulsifying agents, a fluid loss additive. Spacer fluids are designed to separate incompatible fluids and to water-wet the formation and pipe.

In addition to fulfilling the two main goals, a spacer must also:


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1. Exhibit good fluid loss control in order to maintain its rheological properties.

2. Suspend weighting material up to the same density as the cement slurry (usually the

spacer has a density between the mud and cement slurry).

3. Be stable at high temperature and high pressure.

4. Be reasonably easy to mix and handle in the field.

The most significant factors regarding mud removal from annular space can be summarized as follows:

1. The casing must be centralized in the borehole. In an eccentric annulus mud may not be

removed from the narrow part.

2. Casing movement, either rotation or reciprocation, aids mud removal. Pipe motion with scratchers improves mud displacement in areas of hole enlargement.

3. The mud should be conditioned properly, that is low PV and YP and in particular low 10-

minute gel.

4. The displacement fluids should be in turbulent flow. If it is not possible to apply velocities causing turbulence, the spacer viscosity should be higher than the mud viscosity. At equal displacement rates, a thin spacer fluid in turbulent flow is more effective than a thick spacer in laminar flow.

Ava Drilling Fluids has information on several cement spacers, which are recommended for use with oil-base fluids. According to the marketing information they should all fulfill the requirements stated above. 8.10 DRILLING PROBLEMS AND TROUBLE SHOOTING 8.10.1 High Viscosity High viscosity can be caused by water or solids contamination. Changes in the oil/water ratio or the solids content are the usual indicators. Remedial measures include adding base oil, increasing solids control efficiency and increasing density to control water flows. 8.10.2 Fill on Trips and Connections Fill is usually an indication that the rheological properties, specifically the gel strengths, are inadequate. This can coincide with low gel strength readings and residue in viscometer cups; it can also be an indication of possible water wetting. 8.10.3 Hole Cleaning in Large Diameter, Inclined Holes This problem often occurs with invert systems because they exhibit low shear rate values, which are lower than comparable water-based fluids. The condition is evidenced when excessive time is spent back-reaming on trips. Latex polymers have been developed which increase low shear rheology alone. This problem can usually be reduced when enough polymer is added to increase the 3 and 6 rpm readings to between 15 and 20.


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8.10.4 High Filtration High filtration rates are usually caused by inadequate concentrations of emulsifiers and lime. Often water is present in the filtrate. The usual treatment is to add primary emulsifier and lime along with a fluid loss reducing agent. 8.10.5 Emulsion Breaking Emulsion breaking is usually caused by an inadequate concentration of emulsifiers or a lack of proper shear or water-wet solids. Usually the ES decreases and water is observed in the filtrate. Oil can sometimes be observed on the surface of the pits. The system takes on a dull, grainy appearance. Usually adding proper emulsifiers and lime along with prolonged agitation will rectify the problem. 8.10.6 Water Wet Solids Severe settling and a soft mushy appearance of cuttings on the shaker screens indicate that the solids (and hole) are becoming water wet. Adding a wetting agent will eliminate the problem, which is typical on drillouts. 8.10.7 Salt and Salt Water Flows Salt water flows and drilling through salt may result in decreased emulsion stability. Water wetting of solids, increased viscosity and reduced oil/water ratios are also indicators. Add emulsifiers and lime when drilling through salt. Add oil, lime, emulsifiers and possibly barite when a salt-water flow occurs. 8.10.8 Acid Contamination Acid contamination is caused by an intrusion of either CO2 or H2S. Decreasing alkalinity is the best indicator. Add lime to maintain the system alkalinity. When excessive H2S is present, add ZnO. 8.10.9 Differential Sticking Differential sticking of the drill string could be a problem across under pressured, porous, permeable zones. To minimize the risk of stuck pipe, some modifications to the mud system and to drilling practice are suggested. Reduce the HP/HT fluid loss to less than 10 cc's prior to penetrating zones with suspected porosity. Have small contingency stockpile of "325" and "O" grind Calcium Carbonate bridging agent available. These products should be added to the system if losses of whole fluid to the hole are suspected. Avoid stopping the drill collars opposite any zone known to have high porosity and permeability. 8.10.10 Gas Kicks Gas kicks while drilling with invert systems are often difficult to detect. This is due to the increased solubility of gas in oil. Detection equipment and well control procedures are extremely important when drilling with oil-based fluids. The following gives the critical (bubble-point) pressure for gases most often encountered while drilling with oil-based fluids. Methane CH4 = 4641 kPa.


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Hydrogen Sulfide H2S = 9008 kPa. Carbon dioxide CO2 = 7387 kPa. 8.10.11 Cuttings Disposal Many different forms of cuttings removal equipment are available today. Each method has had varying degrees of success. Oil mud cuttings can be 50 - 60% oil mud. To prevent pollution of the surrounding environment, these cuttings can either be hauled away to a disposal site or be processed (composted) so that they may be dumped on location, assuming environmental controls allow the cuttings to be dumped offshore. Many variations of a wash system have been tried. Cuttings have been sprayed or immersed into a wash solution of water/soap. The solids removed by shale shakers, mud cleaners and centrifuges have also been washed in the solvents. Heat systems have included a grinder/burner combination and a fluidized bed. Retort systems have been built to evaporate the oil and water of the cuttings, and then separate the condensed oil and water in an oil/water separator. Capacities are usually low. 8.10.12 Losses to the Formation A number of different materials have been used to control seepage losses while drilling with invert fluids. Losses of invert fluid due to seepage are often controlled by addition of sized calcium carbonate. Particle size of the calcium carbonate is of great importance so as to be able to insure adequate formation plugging and to keep fluid loss at a minimum. The calcium carbonate should have some particles in the barite size range in order to fill formation pores as well as some larger, coarser particles to provide bridging properties. Gilsonite derivatives are an alternative seepage loss material. It is non-fluorescent material with a mean particle size in the 60-150 mesh range. When it is added to an invert fluid the particles will swell in time to 1.5-2 times their normal size. If excessive whole fluid losses to the formation are expected, a water-based fluid should be used.


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8.11 TESTING OIL-BASED FLUIDS 8.11.1 Emulsion Stability EQUIPMENT: OFI STABILITY METER ESM-3013 Procedure: 1. Place the fluid in a non-conductive container and heat to 50°C. (Same

temperature used in Rheology). 2. Insert probe into fluid ensuring that end is totally immersed. 3. Turn dial on meter to 10, then depress button for 10 seconds. 4. While depressing test button, turn dial slowly until the light above the dial turns

red. 5. Double the reading on the dial to determine stability of the emulsion in volts. 6. Clean probe immediately after use. Discussion of results: There are many variables involved in the stability of an invert emulsion, thus the emulsion stability value should be considered with the data from a complete mud check. As a rule of thumb however, emulsion stability should be at least 250 volts or equal to the bottom hole temperature (whichever is greater). 8.11.2 Density EQUIPMENT: MUD BALANCE Procedure: The method for obtaining the density of an invert mud is identical to that used for a water-based fluid. Insure that the invert mud's temperature is approximately room temperature (i.e. 20-25°C) before weighing. Conversion calculations: kg/m3 = Specific Gravity x 1 000 kg/m3 = pounds/gal. x 119.826 kg/m3 = pounds/ft3 x 16.051 8.11.3 Rheology EQUIPMENT: MARSH FUNNEL The procedure for obtaining viscosity of an invert fluid and a water-based fluid are identical.


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EQUIPMENT: RHEOMETER Procedure: 1. An invert emulsion drilling fluid is normal preheated in a non-conductive container before shear stress values are obtained. Normally a temperature of 50°C is used. Calculations: Plastic viscosity (PV) in milli pascals = θ600 - θ300

Gel strength in pascals = θ3 2 for 10 s. or 10 min.

Yield Point (YP) in pascals = θ300 - P.V.

2

8.11.4 HT/HP Filtration All invert systems should be tested in the following manner for filtration loss since API - 30 minute (100 psi) does not give accurate fluid loss values for invert drilling fluids at anticipated wellbore temperatures and pressures. Procedure: 1. Connect the heating jacket to 110 volts or correct voltage for unit before test is to

be made. Place a thermometer in the thermometer well. Preheat the heating jacket to 150°C (or the desired temperature). Adjust the thermostat in order to maintain constant temperature.

2. Load the cell taking care not to fill the cell closer than 10 mm (one-half inch) from top to allow for expansion.

3. Place the cell into the heating jacket with both top and bottom valve-stems closed. Transfer thermometer-to-thermometer well in cell.

4. Place the pressure unit on the top valve and lock in place. Place the bottom pressure receiver and lock in place. Apply 700 kPa (100 psi) to both pressure units with valve stems closed. Open top valve and apply 700 kPa (100 psi) to the fluid while heating.

5. When sample reaches 150°c increase the pressure of the top pressure unit to 4 100 kPa (600 psi) and open the bottom valve to start filtration. Collect the filtrate for 30 min. maintaining temperature ±3°C. If desired, record surge volume after 2 seconds. If back pressure rose above 700 kPa (100 psi) during the test, cautiously reduce the pressure by drawing off a portion of the filtrate. Record the total volume.

6. The filtrate volume should be corrected to a filter area of 45.8 cm2. (The filter area is 22.9 cm2, double filtrate volume and report.)

7. At the end of the test, close both valve stems. Back T-screw off and bleed pressure from both regulators. CAUTION: Filter cell will still contain approximately 3,400 kPa (500 psi). Maintain cell in upright position and cool to room temperature before releasing cell pressure.


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8.11.5 Chloride Determination Method 1: Silver Nitrate Titration Procedure: To 100 ml of a 1:1 mixture of xylene / isopropranol, add one ml of oil mud. Stir, then dilute the mixture with 75 ml distilled water. Add ten drops of phenolphthalein indicator. Titrate with 0.1N H2SO4 until the pink color disappears. Then add one ml of potassium chromate indicator to the mixture, and titrate the solvents/water phase with 0.1N AgNO3 until the color changes from yellow to brick red. Adequate ventilation should be maintained using this procedure to avoid inhalation of the organic solvents. Calculations:

(1) If 0.1N silver nitrate is used: g/l Cl- = VT*3.545 g/l NaCl = VT*5.845

(2) If 1N silver nitrate is used: g/l Cl- = VT*35.45 g/l NaCl = VT*58.45

Method 2: Mercuric Nitrate Titration Procedure: To 100 ml of a 1:1 mixture of xylene / isopropranol, add one ml of oil mud. Stir, then dilute with 75 ml distilled water. Acidify to pH 3 or less with 5N sulfuric acid. Add one ml of bromophenol blue-diphenyl carbazone indicator solution, and titrate the solvent/water phase with 0.1N mercuric nitrate to a blue-violet endpoint (stir rapidly near endpoint). Adequate ventilation should be maintained using this procedure to avoid inhalation of the organic solvents. Calculations: Identical to silver Nitrate Titration 8.11.6 Alkalinity Estimation Procedure: To 100 ml of a 1:1 mixture of xylene / isopropanol, add on ml of oil mud. Add 75 ml of distilled water and 5 drops of phenolphthalein indicator. While rapidly stirring, titrate entire mixture with N/10 (0.1N) H2SO4 until the pink color disappears permanently.* Adequate ventilation should be maintained using this procedure to avoid inhalation of the organic solvents. Calculations: Alkalinity (Mp) is number of ml of N/10 H2SO4 required Lime content in kg/m3 = Mp x 3.69


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*Note: After pink color disappears, the determination of chloride using silver nitrate titration may be performed on the same test solution. 8.11.7 Calcium Chloride Estimation Procedure: To 100 ml of a 1:1 mixture of xylene / isopropanol, add one ml of oil mud. While stirring, add 75 ml of distilled water, two ml of strong buffer and 10-15 drops of manver. While stirring rapidly, titrate slowly the entire mixture with standard titraver to a blue-grey endpoint. Adequate ventilation should be maintained using this procedure to avoid inhalation of the organic solvents. Calculation: CaCl2 kg/m3 = 1.14 (ml of STD. titraver) - 1.5 (kg/m3 Ca(OH)2) 8.11.8 Sodium Chloride Estimation To the proceeding procedure, apply the following calculations. Calculation: NaCl kg/m3 = 16.5 (ml AgNO3 or Hg(NO3)2 - 1.06 (kg/m3 CaCl2) 8.11.9 Retort Analysis EQUIPMENT: EXTERNAL HEATED MINI STILL Procedure: 1. Fill the chamber with a freshly obtained mud sample. 2. Place the lid on the chamber allowing any excess mud to escape. 3. Remove the lid from the chamber being careful not to remove any fluid adhering

to the lid. 4. Add 5-6 drops of liquid steel wool or pack steel wool around the upper portion of

the immersion heater. The solid steel wool will give better oil/water separation. 5. Screw the lower retort chamber into the upper chamber while maintaining both

chambers in an upright position. 6. Attach the assembled retort to the condenser. 7. Add a drop of wetting agent (aerosol) to a graduated centrifuge tube and place it

under the drain of condenser. Heating is usually 20-30 minutes, depending on fluid type.

8. Centrifuge sample if necessary to separate the oil and water layers. CALCULATIONS: OIL/WATER RATIO Oil/water ratio is calculated as follows:

O = R oil

R oil + R water X 100


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W = R water

R oil + R water X 100

where: O = percent oil in liquid phase W = percent water in liquid phase R = retort percentage CALCULATIONS: CORRECTED RETORT VALUES Corrected retort values for solids and brine are calculated by using the expansion coefficient

Ex = D water

D brine x (1 - % W/W salt)

Then,

Rc solids = R solids

Ex

Rc brine = R water + (R solids - Rc solids) where: Ex = expansion coefficient of water to brine D = density in kg/L (from Calcium Chloride brine data sheet) %(W/W) Salt = percentage salt in brine on a weight basis. Use decimal fraction (data

obtained from Calcium Chloride brine data sheet - Table II). Oil/brine ratio is then calculated as follows:

O = R oil

R oil + Rc brine X 100%

B = Rc brine

R oil + Rc brine X 100%


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CHAPTER 9 PRESSURE GRADIENTS, ROCK MECHANICS AND BOREHOLE STABILITY 9.1 KEY POINTS AND SUMMARY 9.2 ROCK MECHANICS AND BOREHOLE STRESSES

9.2.1 Stress Regimes in Undisturbed Rocks 9.2.2 Mechanical Properties of Rocks 9.2.3 Stresses around a Borehole 9.2.4 Mechanical Stability 9.2.5 Stress Relief with Fluid Density 9.2.6 Borehole Fracturing and Fluid Induced Stresses 9.2.7 The Stability of Inclined Boreholes

9.3 INTERACTIONS BETWEEN DRILLING FLUID AND ROCK

9.3.1 Water Adsorption 9.3.2 Inhibition Mechanisms 9.3.3 The Time Factor

9.4 ASSESSING BOREHOLE STABILITY MECHANISMS AND SEVERITY 9.4.1 Lab Testing The Physio/Chemical Relationship Between Drilling Fluid and Rock


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9.1 KEY POINTS & SUMMARY Drilling a hole that is stable long enough to evaluate and run casing is a major concern of our industry. Borehole failure is directly responsible for the loss of millions of dollars each year. Money and time are spent “jarring” on pipe, freepointing, washing-over, fishing, plugging-back and side-tracking. Other consequences include excessive time spent reaming, pumping out and doglegs resulting from poor string stabilization. Several varieties of sedimentary rocks exist and various types of wellbore failure may occur. These include squeezing due to overburden stresses, hydration-induced spalling, sloughing due to bedding plane inclination or weak rock, and expansion due to pore pressure release. These causes may be compound mechanically. If the drilling fluid column isn't dense enough, overburden stress can force the formation rock to fail. If the fluid is too dense, its radial stress can fracture the rock. Fluid seepage into the rock can cause chemically induced instability problems. Fluid may be pushed into the rock via hydrostatic pressure or pulled out via osmotic or hydration mechanisms. An insight into the causes of borehole instability is essential for Drilling Fluid Engineers to identify the proper steps to rectify such problems. 9.2 ROCK MECHANICS AND BOREHOLE STRESSES 9.2.1 Stress Regimes in Undisturbed Rocks When the sediment has compacted sufficiently for grain-to-grain contact to be established, the overburden load or stress, S, is supported by both the mineral grains and the fluid in the remaining spaces. The relationship is expressed in equation 9.1: S = s + Pp Where s represents the intergranular or matrix stress and Pp represents the pore pressure. Normally, where the formation is freely drained and the pore spaces are interconnected, pore pressure, Pp is given by equation 9.2: Pp = ρf • d Where ρf is the pore fluid density and d is the depth. The actual gradient should be calculated by: ρf Gradient = d • .00981 Where the gradient is in kPa/m and d is kg/m3. The density of the pore fluid is mainly dependent on the salinity as water is essentially incompressible. A variation in pressure gradient can result from a reduction in fluid density with depth as the formation temperature increases. Formation pore pressure gradients are typically in the range from 9.8 to 11.5 kPa/m. Undisturbed rock is in a stress regime determined by the overburden stress but modified by other factors such as rock movements and the drainage of pore fluid. Since rocks are rigidly confined they are in equilibrium with the in situ stresses. Stresses can be considered as components


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acting in three directions at right angles to each other. The simplest case is when the three principal stresses are equal. The vertical stress sv is given by the relationship, equation 9.3: sv = sv - Pp Often the forces are not equal and three possible arrangements can occur, as shown in Figure 9.1. s1 is always termed the greatest principal stress, s2 is the intermediate stress and s3 is the least principal stress.

Typical values for the total stress in Western Canada are given in Table 9.1. TABLE 9.1 TYPICAL VALUES OF TOTAL STRESSES IN ELMWORTH Location

Depth

Minimum Horizontal Stress MPa

Maximum Horizontal Stress MPa

69-11w6 2021 m 39.7 61.8 94 P 1 2095 m 34.5 54.0

9.2.2 Mechanical Properties of Rocks The mechanical properties of rocks can be determined using a triaxial cell. A core is held in a sleeve that can be pressurized to apply equal horizontal stresses. A variable load can then be applied vertically. Measurement of the amount of deflection for a given load allows a stress-strain curve to be developed. Figure 9.2 shows simple stress-strain curves for rocks. When looking at these curves, remember, that stress may be related to pressure - such as the overburden pressure.


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The stress on a rock is opposed by its matrix strength, until a yield stress value is reached. Here the rock will yield or begin to deform. This deformation is called plastic behavior. It may occur in soft formations until a peak strain has been reached at which point the rock will fail. In brittle rocks the yield stress may almost equal the peak strain. Note that the deformation of rock depends on the stress between the grains and is independent of the pore pressure. Therefore, the effective integrannular or matrix stress is equal to the applied load or overburden, less the pore pressure. The peak strength is defined as the maximum stress on the curve and the peak strain is the corresponding strain. The curves show that after failure, the rock retains some strength if it is confined. The strength of rock increases with confining pressure. This is because the internal friction and hence strength has been increased as the grains are pressed closer together. Thus, there is a trend for increased strength of rocks with depth of burial. Brittle rocks fail suddenly and are characterized by rocks that have substantial intergranular bonding (cohesive strength) such as sandstones, bound by silica cements, and older shales that have been extensively dewatered. In plastic rocks the internal resistance to deformation is low. It is typified by shales with relatively high levels of water content (15-30%) and also rock salt. Plastic rocks have a relatively higher proportion of post peak strength than brittle rocks. Typical values of the unconfined compressive strength of sandstone and mudstone are 30 MPa and 14 MPa respectively. 9.2.3 Stress Around a Borehole The process of drilling a hole in stressed rock removes support and creates conditions in which the rock is in unconfined compression. The load is transferred to a zone of "hoop" stresses that are tangential to the sides of the wellbore. These are called the tangential stress, represented by st in Figure 9.3. The magnitude of the tangential stress is related to the magnitude of the stress field around the hole operating at right angles to the wellbore. This is illustrated in Figure 9.3.


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When the stresses in the initial rock are all equal (s1=s2=s3) the magnitude of the tangential stress will be 2s1. This situation is not normally encountered. The orientation of the wellbore in the stress field is an important factor when drilling deviated holes or when drilling in tectonically altered rocks. If the stresses at right angles to the wellbore are not equal then the tangential stresses will not be symmetrical and the well may tend to fail in the direction of the least stress. In this case, there is a tendency towards oval holes or breakouts, with the short axis pointing towards the direction of greatest stress. It is therefore, important that the direction of the hole relative to the stress regime in the rock is understood as fully as possible. Different sedimentary rocks can behave differently when they are penetrated if they are under one of the aforementioned stress regimes. In some cases when problems are expected, modifying the drilling fluid program can help. 9.2.4 Mechanical Stability This subsection looks at borehole stability in terms of the mechanical properties of the rocks alone. The effects of drilling fluid chemistry are discussed later. When the effective stresses acting upon the rock are less than its elastic limit, deformation is elastic and is usually negligible, perhaps requiring minor reaming. In deep wells and close to gauge slim holes this movement may cause problems such as pinched or stuck bits. This is illustrated in Figure 10.4a.


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When the effective tangential stresses acting upon the rock exceed its strength the resulting deformation is plastic, but the failed rock is still under a confining pressure, as shown in Figure 10.4b. Thus a zone of plastically deformed rock is formed around the wellbore. This failed rock can expand into the wellbore. The plastic deformation zone extends into the rock a sufficient distance until the borehole reaches a point of stable equilibrium. Here the stress at the wall is reduced to the pressure exerted by the drilling fluid. This situation is stable if the failed rock is not eroded away.

The resultant radius of the hole and the depth of this plastic failed zone depend on both the mechanical properties of the rocks, as defined by the ductility and cohesive strength and on the stress distribution within the plastic and elastic zones. The size of the plastic zone can be estimated from the rock properties and the initial horizontal stresses. This may be relatively small for brittle rocks such as sandstones and shales. Here the ratio of the outer radius of the plastic zone can be 1.1 - 2.5 times the radius of the hole. It can be much larger for plastic formations such as young shales and salt. The width of the plastic zone required for stability also increases with increases in horizontal stresses. This analysis shows that the common drilling practice is to induce mechanical stresses in the wellbore that are only partially relieved by the pressure of the fluid in the hole. If these stresses go beyond the range of the mechanical stability of the rock, borehole collapse will eventually occur. 9.2.5 Stress Relief with Fluid Density The element of rock near the wellbore is subjected to large compressive forces acting on the unconfined rock. If the hole is filled with a fluid then a radial stress s1

r, is exerted against the rock, which is equal to the pressure exerted by the fluid Ph. The effective radial stress actually only amounts to the difference between the hydrostatic pressure and the pore fluid pressure, Ph - Pp. The radial stress means that the rock is no longer unconfined, but confined triaxially. This increases its effective strength. The radial stress also acts to reduce the tangential stress, but the


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major effect on supporting the hole is due to the added confining pressure. Thus the effective stress at the wellbore is again given in equation 9.4: s = Stotal-Pp Normally, the radial stress exerted by the fluid column is sufficient to enable drilling to proceed. Usually drilling fluid is densified to control abnormal pore pressures, however, certain borehole stability problems require fluid density to be increased. There are four practical applications where raising the fluid density might serve to rectify a stress relief problem. However, the limited success rate and the prohibitive cost require close consideration prior to adding Barite. These formations include: 1. Squeezing Tertiary Formations 2. Tight-over-Pressured, Gas Baring Shales 3. Hydratable/Sloughing Shales 4. Gas Hydrate Baring, Formations It is drilling industry practice to place the wellbore in compression and not eliminate totally the tangential stresses with hydrostatic pressure. This deliberately creates potentially unstable hole conditions. The key to success is to drill a hole that is only stable for the time required to case it. There are a number of reasons for not balancing the hoop stresses by keeping the fluid density at minimal values. A single factor that has a critical influence on well costs is the time taken for drilling and completion. Time compounds the errors with each delay, contributing to increased problems. Thus drilling rates need to be maximized - consistent with a stable borehole. The time dependency of borehole stability problems is discussed further in this text. Raising the fluid density can adversely affect several functions of the fluid loss characteristics. Briefly, these include raising the chip hold down pressure, extending the limit of filtrate invasion and increasing the potential for differential sticking. In addition the fluid rheology can be affected as barite is added. 9.2.6 Borehole Fracturing and Fluid Induced Stresses Fluid density can serve to effectively reduce some stability problems caused by overburden stresses. This is accomplished by offsetting tangential stresses in the rock with radial stresses provided by the fluid column. However, if the radial stresses become excessive, they may induce further stability problems. Another reason for minimizing the fluid density is to keep the wellbore in compression. This is because the tensile strength of rock is considerably less than the compressive strength. The term tensile strength refers to the greatest longitudinal stress a substance can bare without tearing apart. This may be up to a factor of 1:4, depending on the rock type and the confining stresses. This is because the compressive strength comes from frictional contact between the mineral grains and the strength of the rock is increased if the confining pressure is increased. If the fluid column pressure exceeds the tensile strength plus the compressive stress, fractures will be induced in a direction at right angles to the least principal stress. In most cases the least principal stress is in the horizontal direction and so the fracture initiates along the axis of the vertical hole, as shown in Figure 9.5.


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Breakout

Sh

Sh

Sh

Sh

Induced fracture

Figure 9.5 Drilling conditions become difficult when the stresses at right angles to the direction of the wellbore, S1 and S2 in Figure 9.1 are not equal. This condition is known as stress anisotropy. If the ratio of the stresses is in the region of 1:5 the hole assumes an oval section. At higher stress ratios, the rock can be failing and enlarging in the direction of the least stress and may be fractured in the direction of the greatest stress. This is illustrated in Figure 9.5 for a vertical well. Fracturing of the rock considerably increases the risk of hole failure because the integrity of the rock is lost. Here, the pore pressure of the fractured rock becomes equal to the drilling fluid pressure. The drilling fluid may begin to act as a lubricant between elements of the failed rock. A further problem is the financial and logistical consequences as considerable volumes of fluid may be lost. Pressure surges that induce fractures can occur when drill pipe is run into the hole too quickly. The surge pressure depends on the configuration of the hole and drilling assembly, the rate at which the pipe is lowered, and the rheological properties of the drilling fluid particularly the gel strengths. The problem can occur even when running the pipe through casing because the hydraulic stress can be conducted by the fluid towards the open hole interval. The formation can also be fractured if the annulus is packed off by mud rings, cavings or by drawing the pipe up into a bed of cuttings while circulating. This latter case is especially a problem when pulling out of a deviated wellbore, particularly when circulating with top a drive. The fluid pressure can also be increased if the cuttings are allowed to build up in the annulus. This happens when excessive drilling rates exceed the cuttings transport ability of the drilling fluid. The formation is often fractured when a cement slurry is pumped behind the casing since the minimum cement density is usually around 1.8 sg which is often higher than the fracture gradient. In the pre-planning stage of the well, the fluid density that will fracture the well should be calculated so that the conditions of fracture can be avoided. Most operators conduct a pressure integrity test prior to drilling ahead in a new hole interval. This involves deliberately fracturing the formation rock by applying pressure against it until the rock breaks. The results are used to calculate the equivalent fluid density capable of breaking down the formation. This value is then used as an upper limit for fluid density or shut-in casing pressure during well control procedures.


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An important consideration in hydraulic design relates to the degree of fluid-induced stresses, which may be applied to the formation rock while circulating. These result from hydraulic horsepower and friction loss, imparted to the hole by the drilling fluid as it travels up the annulus. These stresses when excessive can be erosive - resulting in over gauge hole and its associated problems. As a result, annular velocity parameters and laminar flow regimes may take precedent over bit hydraulic parameters in softer formations. The most notable case is permafrost, where bit nozzles are open and annular velocities are kept below 2.0 m/min; especially important when opening 26" pilot hole to 36". The effect of annular velocity is less detrimental in deeper, more competent formations and may not be a factor in hydraulic design. In fact, calculations on drilling fluid shearing forces at the borehole wall show that fluid shear stresses are 5 to 6 orders of magnitude less than borehole hoop stresses in deep holes.1 9.2.7 The Stability of Inclined Boreholes An important factor controlling wellbore stresses is the orientation of the principle stresses in the formation relative to the direction of the wellbore. Normally, the largest stress acts vertically, thus inclination of the wellbore away from the vertical brings the component of the larger stress into play, increasing the compressive stresses. The sides of the deviated hole are also subjected to increased mechanical stress and abrasion due to the rotation of the drill pipe. Rocks, particularly shales, may not exhibit the same strength in all directions. Shales, for example, are much weaker in the direction of the bedding plane or dip compared to the direction perpendicular to the bedding plane. This is due to the plate-like structure of the clays and the preferential orientation of their crystals. The weaker formation may lead to premature fracture that normally wouldn't occur in a straight hole. A further factor in inclined wells is the increase in time required for orientation and changes to the steering assembly. Techniques such as measurement while drilling (MWD), stearable downhole motors and Polycrystalline Diamond Compound (PDC) bits have helped to reduce the time taken to drill directional holes. The requirement for additional support can be calculated from knowledge of the stress field and the mechanical properties of the rocks. This often calls for higher fluid densities than those used for a vertical well. 9.3 INTERACTIONS BETWEEN DRILLING FLUID AND ROCK 9.3.1 Water Adsorption The previous discussion, considered the problem of borehole stability in terms of the mechanical factors only, and ignored any influence of the drilling fluid chemistry and properties on the mechanical properties and the stress regime of the formation rocks. The potential for a formation to absorb water depends on the mineralogy. Water has a very strong affinity for mineral surfaces, particularly the clay minerals. Therefore it is highest for shales, particularly when they contain illite, montmorillonite and mixed layer clays. The consolidation process applies pressure that forces clay surfaces closer together and displaces the water. The work done in the consolidation process builds up a potential in the clays to adsorb the water. Therefore the potential of the formation to adsorb water is dependent on the consolidation history as well as the mineralogy. Clay surfaces are charged and may retain ions of opposite charge. In the de-watering process the water leaving the sites between layers can have a lower salinity than the water retained as


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the pore fluid. If the clays are then exposed to water having a lower salinity than the pore water then diffusive forces can force the water into these laminar sites. This process is often referred to as osmotic swelling. It is an important process in sodium exchanged montmorillonite but is not significant in calcium varieties. The adsorption of water by clays is also controlled by changes in the structure of the shale. These may be caused by both precipitation of intergranular cement materials and by stronger short range Van de Waals bonding forces, which play a more important role, as the clays are forced closer to each other. Therefore, diagenetic processes and de-watering can reduce the swelling pressure generated by the contact of water with the shales. Older, brittle formations can often fail too, if they consist of hydratable - usually mixed layer and illitic shales. Osmotic swelling and hydration can result in a slow decline in the tensile strength of the rock. Water may either penetrate the bedding planes or the layers between the crystals. Any fracture planes, perpendicular to the bedding planes may also be penetrated. The process may require time, but eventually when the rock fails, large pieces or cavings invade the wellbore. This failure may be almost instantaneous, resulting in stuck pipe. Cleaning cavings dictates that special attention is paid to fluid rheology and circulation rates. The cleaning problem is compounded if this sloughing results in an over gauge interval. The extent of the reaction of water with the formation rock is a complex function of a number of factors related to the composition of rocks, the pressures generated in the consolidation process, the salinity of the pore water and the extent of diagenetic processes. These reactions may increase the tangential stresses past the plastic limit causing the rock to fail. They may also decrease the net strength of the rock. The magnitude of swelling stress has been determined in laboratory studies. These have included water adsorption data, studies on the compaction process by measuring the compaction pressures required to de-water a sample, and by measuring the change in stresses of a sample directly by using strain gauges. These studies have shown that stresses in the order of 7 - 70 MPa (1,000 – 10,000 psi) can be generated and that the type of drilling fluid used can modify their magnitude. It is important to attempt to distinguish between hole failure due to mechanical stress arising from hoop stresses and chemical stress arising from reaction of the formation with drilling fluid and filtrate. 9.3.2 Inhibition Mechanisms Fluids formulated with freshwater and high pH create conditions where clay hydration forces are strongest. In other words, freshwater fluids have minimal inhibitive character. Here, the chemical swelling stresses in the wellbore are very high and borehole instability is most likely to be observed. In young sediments, the hydration stresses may be sufficient to break down the forces holding the shale together resulting in continual failure of the wellbore. Young cuttings, also subjected to the hydration stress, break down to colloidal sized particles in the annulus that cannot be removed at the surface other than by dumping. The result is a badly washed out hole, poor directional control, poor log response, high cement costs and high drilling fluid costs. Drilling fluid chemistry or properties may be adjusted by the addition of various components to the fluid. There are four different mechanisms whereby drilling fluid chemistry can alleviate or minimize borehole stability:


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1. Balanced Activity (Invert Emulsion Fluids) 2. Cation Exchange (Salt Systems – K+, Ca2+, Al2(S04)3) 3. Encapsulation (PHPA, Amines) 4 Increase in Filtrate Viscosity (All Oil Systems) 5 Cementation of shale porosity matrix (Sodium Silicate Systems) 6. Plastering (Asphaltic Derivatives) A wide range of drilling fluid types have been designed in an attempt to minimize the chemical induced stress arising from water adsorption. These have been described in more detail in the Chapters 8 + 9, on Water Based Fluids and Oil Based Fluids. Apart from raising the density and engineering the well trajectory, there are several methods of controlling the physio-chemical interactions between drilling fluid and rock in an effort to arrest the actual hydration and swelling tendencies of shale. All of these methods have been studied and are well documented. They include the following: Balanced Activity or Vapor Exchange is discussed in SPE 2559. Fluids using this mechanism include Invert systems and Methyl Glucoside / Deep Drill. Invert oil emulsion fluids essentially eliminate hydration-induced stress in clays. A semi-permeable membrane (the oil phase in OBM) must be present in order for this to occur efficiently. This membrane is permeable to water but not to dissolved salts. It separates the water in the shale from the water in the internal phase of the oil based mud. When salt is dissolved into the water phase of the oil based mud to lower the activity to less than that of the shale, water vapor moves from the shale toward the brine phase. Osmotic pressure can thus be used to offset the swelling pressure of the shale. Generally, loss of formation water is the preferred situation as it may strengthen the shale. The changes in water content in the fluid can be large enough to be monitored so the salinity can be adjusted as it strives towards equilibrium. The continuous oil phase also eliminates polar interactions between fluid and clay crystals. (Hence when borehole stability problems are only expected to be moderate, “all oil” systems are sometimes used for drilling). The lower stress levels, low filtrate invasion and high lubricity make oil-based fluids very effective. Oil-based fluid is expensive and excessive seepage or lost circulation problems can make its use prohibitive. There is also concern over its environmental impact and the costs incurred to eliminate this factor. These and other factors have generated a need for the development of water-based fluids with higher levels of inhibitive properties. The addition of Methyl glycoside to water based mud lowers the activity of the system in a manner similar to calcium chloride in an OBM. The Methyl Glucoside solute becomes fixed in the near borehole surface of the shale, establishing an effective semi permeable membrane that allows the solvent (water) to move from the shale to the mud under a chemical potential that exceeds the hydraulic potential tending to force water into the shale. Advanced testing (SPE 27496) clearly shows that shale exposed to this system remains intact. Further, the shale is actually harder in the vicinity of the simulated well bore that was tested. Cation Exchange is discussed in SPE 4232. Examples of typical salts used for this purpose include KCL or K2SO4 systems. Strong or more efficient cations such as potassium or calcium added to the drilling fluid, change out with weak cations situated between the unit layers in swelling clays. The strong cations effectively prevent water from entering the clay lattice – slowing hydration and dispersion. This effect is significant and can be demonstrated by the fact


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that sodium bentonite does not hydrate and disperse efficiently in saltwater. This reaction depends on the concentration of the ion, the nature of the ion and the formation minerals. Calcium has a very high affinity for montmorillonite and may be the most efficient exchange ion. Being multivalent, it can collapse or impede expanding sheet structures. Potassium has a high affinity for illite and mica clays. It replaces calcium from montmorillonite and tends to reduce clay swelling due to the lower hydration energy of the ion. Various salts are used to control the hydration tendencies of both tertiary and older shale types. Calcium exchange systems use Lime and Gypsum in excess to provide a reserve of calcium ions. When Lime is added there is a potential to form a calcium silicate precipitate with free silica and thereby strengthen the rock. The potassium ion may be added as the alkali, KOH, or more commonly as KCl although the acetate and carbonate salts have been used where the chloride ion presents an environmental problem. The ammonium ion has been used as an alternative to the potassium, in areas where the potassium ion causes environmental concern. Aluminum, (Al2(SO4)3), has been used successfully in tertiary formations where highly reactive clays readily disperse in the annulus. When used in proper concentrations, the aluminum can actually cause these particles to aggregate to a point where they are big enough to be screened out. Laboratory studies show the exchange ion effect can reduce clay swelling significantly (in the order of 50 - 70%), particularly with Potassium Chloride. The result depends on the salt levels and the type of shale being studied. KCl levels of between 3 - 8% are generally effective. The influence of salt on electrostatic repulsive forces and the ion exchange forces does reduce the swelling stress but does not prevent water from contacting the shales. The exchange reactions are relatively slow and the reaction rate is controlled by diffusion. Encapsulation is discussed in SPE 10100. Examples include PHPA (partially hydrolyzed polyacrylamide), or Amine systems. Polymer molecules are designed with their side chains spaced apart so that they match the c-spacing on broken clay edges. The broken-edge clay charges are pH dependant but for the most part are positive. The anionic (negative) charges on the polymer side chains hydrogen-bond to the clay, slowing the rate of hydration and dispersion generating a cohesive network on the mineral surface. This reduces the mobility of the water and strengthens the rock. An important feature of the application of this concept is that the polymer concentration should be high enough to ensure sufficient polymer is adsorbed at a level where it is effective. Increase in Filtrate Viscosity is discussed in SPE 2400. Examples include Pure-oil systems and the Mixed Metal Hydroxide system (AvaMMH). If the viscosity of the base fluid or filtrate is high, the capillary pressure required to push fluid into a shale porosity matrix is increased. If the viscosity is great enough, the hydrostatic head will still not be high enough to exceed the capillary pressure – whereas filtrates with the viscosity of water can easily penetrate the shale matrix, initiating hydration and swelling. Cementation of shale porosity matrix is explained in SPE 38569. This is the inhibition mechanism used in Sodium Silicate Systems. Silicates react with the Ca++ and Mg++ ions present on chalk surfaces and in shale pore throats by gelling in the low-pH pore fluids of shales. The precipitates / gels that are formed, plug and coat the rock near borehole wall, preventing filtrate from entering the formation.


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Some stress relief and unconsolidation related problems can be difficult to combat with either drilling fluid density or chemical alteration. These include: 1. Unconsolidated Gravel or Sand 2. Coal Seams 3. Permafrost 4. Gas Hydrate Bearing Formations 5. Heaving Gumbo 6. Highly Fractured Shales In these cases, the solution could involve wiping the hole, cooling the drilling fluid, raising the viscosity or using an asphalt derivative such as Gilsonite. These materials have proven to be successful in inhibiting fractured formations such as the Belly River Shale found in the Western Plains. (Fractured / sloughing formations are evidence as incessive, large-blocky cavings on the shaker. These cavings may have white calcarious fracture lines throughout). The topic of drilling fluid selection and design as it related to borehole stresses and other considerations is discussed in Chapter 8, Water-Based Fluids. 9.3.3 The Time Factor Almost any hole is potentially unstable. The stresses contributing to instability usually increase with time. Besides inhibitive fluids systems, drilling techniques such as top drives, motors, PDC bits and MWD systems have all aided in reducing the time taken to drill and case an interval. Since many stability problems are time-dependant, interval lengths can increase as drilling techniques improve. Drilling economics dictate that the time factor should never be neglected. In many instances it may be more economical to sidetrack a problem interval than to compound the problem by spending time cleaning and fishing. Delayed failure may occur almost instantaneously in coal or gas hydrate formations. More competent shales may withstand borehole stresses for longer periods - even weeks. When these rocks finally fail, excessive amounts of cavings may be removed before the hole stabilizes, only to have a reoccurrence at the same depth some time later. Squeezing gumbo must be wiped at regular time intervals, sometimes several times before unimpeded bit trips can be made or casing lowered. With the exception of frozen hydrate and some types of rubble and coal formations, the build up of tangential or mechanical stresses at the wellbore does not occur instantaneously. The time factor often depends on the relationship between the level of radial stress or fluid density and the rock characteristics. The rate of transfer of stress into the intact rock should be fast enough to prevent the build-up of stress past the plastic failure point. The long-term mechanical strength of the rock is lower than the short-term strength as the failure zone extends into the formation. The hydration reactions between the drilling fluid and the formation also have time dependent factors. A hydration reaction exhibits a time dependency due to the rate-limiting diffusion processes of water and various ions into the rock. This process may be impeded as expansion of the yielded rock leads to a reduction in permeability. The fluid is driven into the formation by the same pressure that is supporting the rock (Ph - Pp). Fluid invasion is related to this pressure and the altered permeability of the stressed rock. The filtrate is also pulled into the formation due to the affinity of the rocks for water. The hydration energy depends on consolidation pressure and mineralogy. Osmotic forces may also be significant. The rate of progress of the filtrate front decreases with distance from the wellbore as the filtrate fans out into the formation. Hydration


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effects are essentially removed with the use of oil-based fluids. Drilling fluid with a different temperature may generate thermal stresses in the rock, which can also be classified as a function of time as the rock equilibrates with the new temperature conditions. 9.4 ASSESSING BOREHOLE STABILITY MECHANISMS AND SEVERITY There are two “disciplines” involved when assessing borehole stability. The first is the familiar discipline of studying the physio/chemical relationship between drilling fluid and rock. The second has to do with rock mechanics – the strength of the rock, the tectonic and overburden influences on wellbore stability as well as other influences such as the orientation of the bedding planes relative to the wellbore. Computer models are available to assist in predicting severity of breakout at various wellbore diameters, inclination and mud densities. When possible, output data is normalized by studying wells drilled in the area. The problem is that the output may be able to tell us what density and angle are best, but may be a little fuzzy on what type of fluid to use. Some can’t even predict the benefit of using OBM. Recently, wellbore stability models have begun to integrate physio/chemical subroutines into them. 10.4.1 Lab Testing – The Physio/Chemical Relationship Between Drilling Fluid and Rock Capillary Suction Timer Testing involves pulverizing dried cuttings and placing them in a cylinder that sits on top of blotter paper. The fluid to be tested is poured into the cylinder and makes its way down through the cuttings toward the paper. This fluid us usually just makeup water and inhibitor. As the fluid seeps out the bottom of the cylinder, it closes an electric circuit, starting the timer. As the fluid works its way out through the blotter paper, it completes a second circuit, stopping the timer. The idea is that the longer the time, the greater the degree of interaction between fluid and rock. With an inhibitive fluid, the time will be faster as it won’t tend to adsorb onto or absorb into the rock. The problem with the test is that a candidate fluid with a high inherent viscosity will perform poorly as it will travel at a slower rate due to its thickness. For example, a PHPA fluid performs poorly with this test. In Hot Roll Dispersion Tests, cuttings are dried and screened to a minimum size, then weighed. They are placed into the candidate solution and hot rolled at moderate temperature for 16 hours. They are then removed, screened and dried again. After weighing, the weight loss is compared to the other candidates. A diesel blank is also run to get an idea of the portion of weight loss attributable to mechanical attrition with that shale. (In most of these tests it is a good idea to run a diesel blank as well as a fresh water blank to assist with the comparison). The problem with the test is that an inhibitor whose mechanism involves a vapor exchange or pore pressure reduction may not work efficiently on a cutting where pore fluids and pressure and geometry are no longer native state. For example, both diesel and PHPA may look good on this test, whereas KCl may not. In a Dynamic Pellet Test, cuttings are ground up into a fine powder. They are compressed into pellets with a washer on either end, and a nail sticking up through the middle. The nail is held in a drill press and the pellet is immersed into the candidate fluid and spun for a time. The weight loss is then compared to that incurred with the other fluids. The problem with the test is that reconstituted pellets are nothing at all like the shale they were made from. If you place one bentonite pellet in a 5% KCl solution and another into a fresh water solution the pellet in the KCl will disintegrate immediately. The pellet in the fresh water solution will get a fuzzy layer on the outside but will remain intact. The fresh water readily hydrates the pellet outside, creating a type of barrier. On the other hand the KCl attacks the pellet vigorously – perhaps because of its high polarity.


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In Clay Ball Tests, balls of clay are placed in test solutions. The clay ball that shows the least weight increase after time was soaking in the most inhibitive fluid for that clay. Again, tests conducted on cuttings may be affected by alterations in pore pressure, volume, activity. Particle size may vary on tests where cuttings are pulverized. It’s a good idea to run blanks when possible. The Downhole Simulation Cell (DSC) is acknowledged by industry to be the best apparatus available for ascertaining the effects of a drilling fluid on a given shale. This equipment is set up in the OGS Lab in Houston. A shale core is mounted in a cylinder where a sand pack surrounds the core. It is important that the core is preserved. Preserving it insures that its fluid saturation’s and hardness remain “native state”. The sand pack is oil saturated. Stresses are applied and temperature is raised to simulate actual drilling conditions. A hole is drilled through the core using the candidate fluid. As drilling commences, the pressure of the sand pack surrounding the core is monitored. If the pressure increases, it means that the fluid is entering the core. If this pressure decreases, it means that fluid is moving out of the rock and into the drilling fluid. When drilling is complete, the fluid is circulated for a time. At the end of the test the degree of hole enlargement is measured. The hardness of the rock is also measured. This is clearly the best method of comparing the overall inhibition characteristics of each fluid. An idea of the actual inhibition mechanism may also be gleaned from the test.


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REFERENCES 1 Woodland, David C., Borehole Instability in the Western Canadian Overthrust Belt. SPE

Drilling Engineering March 1990.


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CHAPTER 10 FLUID DESIGN 10.1 KEY POINTS AND SUMMARY 10.2 SELECTING A DRILLING FLUID

10.2.1 The First Step 10.2.2 The Second Step

10.2.3 The Third Step 10.3 PLANNING A DRILLING FLUIDS PROGRAM


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10.1 KEY POINTS AND SUMMARY As oil wells become more difficult to drill, the problem of selecting the best drilling fluid can become fairly complex. There are no approved criteria for drilling fluid selection. Different operators have their own policies and processes. Often one operator will identify and successfully use a drilling fluid system adjacent to another operator using a different system - just as successfully. The worst case occurs when a fluid system must be replaced, or when a drilling operation fails because an inappropriate fluid system was chosen. Contingency planning should be a part of all drilling fluids programs. Time spent mixing circulating or conditioning drilling fluids due to an oversight in the planning phase can be expensive. Mixing, displacement and spotting procedures should be carefully planned in advance to avoid lost time. The most efficient selection of casing setting depths is often influenced by the ability to drill and case formations with the same density and type of fluid. Often an interval has an engineering-oriented or geology-oriented objective. A good drilling fluid will aid in meeting these objectives and often enhance them. Engineering parameters are extended if interval lengths can be increased, and if geological evaluation can be improved with proper fluid formulation. Thus, if the selection of a drilling fluid system seems complicated, it is often advantageous to initially consider each interval separately. Then a step-by-step process can be implemented in the search for the best fluid system. 10.2 SELECTING A DRILLING FLUID Consider using the following steps: 1. Define the objective of the interval. 2. Identify factors which may prevent rapid and economical realization of the

objective. 3. Select a drilling fluid system(s) with respect to all of the demand criteria of the

interval. (Obviously, it would be best if one system could be used throughout the well).

10.2.1 The First Step Defining the objective of an interval is usually the easiest. Most intervals have engineering objectives. Various intervals are commonly called: 1. Surface Hole 2. Intermediate Hole 3. Production Hole or Slim Hole Top hole or surface hole, may actually be up to three intervals. Offshore Arctic wells usually drill a glory hole, conductor hole and surface hole. The engineering priority for top holes is to cement a string of casing (pipe) in place such that while drilling successive intervals, excessive sub-surface pressures must be directed up through it. Drilling fluid systems used to drill top hole are often called Spud Muds. Intermediate hole may consist of one or more intervals. The objective is to drill to the producing formation as quickly as possible. Geological evaluation is usually conducted as drilling proceeds.


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Sometimes engineering tasks such as kicking-off or steering are also performed on intermediate hole. Pressures and borehole stability often dictate the length of an intermediate interval. The production hole or slim hole is the interval, which penetrates the producing formation. The objective is geological. The goal of an exploration well is to evaluate the production potential of a formation. With production wells, the objective is to penetrate the zone without damaging its ability to allow fluids to flow into the wellbore. (A good exploration well often ends up being a production well). Often engineering objectives must also be met during intermediate hole. An example is a well drilled horizontally through a producing zone. 10.2.2 The Second Step In drilling fluid selection involves identifying the factors, which might prevent the objective of the interval from being met in a timely and economical manner. It is the function or functions of the drilling fluid system to overcome these limiting factors. Some areas of concern are listed below: 1) Environmental & Safety Considerations 2) Abnormal Formation Pressures 3) High Temperatures 4) Excessive Deviation 5) Borehole Instability 6) Production Zone Damage 7) Others Usually formation damage or high temperatures are not a problem on top hole. However, it is possible for the other limiting factors to occur on any interval. A primary objective of any drilling fluid research is to instill environmental and safety considerations into system and product development. The same concerns apply when choosing a fluid system to drill with. In some locations, certain fluid systems are not environmentally acceptable. These might include, but are not limited to, salt systems, high pH systems or chrome containing systems. High temperatures, and overpressures are conditions or problems, which can be minimized or alleviated with proper drilling fluid design. Usually the components and properties of water-based fluids begin to become adversely affected at temperatures above 100°C. Water - based systems specially formulated to perform at high temperatures are becoming increasingly effective. Abnormal formation pressures rule out the use of low density, low cost fluids. On high angle wells, fluid formulation may have to be modified in order to enhance cuttings cleaning characteristics. Low shear rate viscosities, flow regimes and lubricity characteristics may be the most important fluid properties on these wells. The competency of the formation usually dictates the flow regime and thus the fluid system and properties. The problem of cleaning in inclined holes is discussed in chapter 14. Borehole stability problems can occur on any interval. The term borehole instability usually refers to holes becoming either bigger or smaller due to one of a number of possible causes. Some examples are listed below: 1) Gravel and Fractured Formations 2) Evaporate Formations 3) Techtonic Squeezing 4) Overpressured Shale 5) Zones Containing Gas Hydrates 6) Permafrost


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7) High Formation Dip 8) Water Sensitive Formations The last example, water sensitive formation presents one of the most intricate issues when attempting to identify the potential problems in an interval. In a new field, it is important to obtain and analyze as much data as possible from various formations, so that future drilling fluid systems can be changed or modified appropriately. Prior to drilling offset wells, logs can provide data on formation dip, geology, temperature and pressure / fracture gradients, and in situ water content. While drilling, shale samples should be obtained for laboratory testing. A well-preserved core sample is by far the best source of data. The best swelling inhibition mechanism can often be predicted if data is analyzed properly. Analytical tests include: 1) X-Ray Diffraction 2) Cation Exchange Capacity 3) Balancing Salinity 4) Swelling Measurements 5) Dispersion Tests 6) Various Types of Stress Tests Samples may be tested in different fluids using different inhibition mechanisms, various concentrations of chemicals or even a combination of 2 mechanisms. (In a KCl / polymer system the encapsulating polymer uses a physical mechanism while the potassium ion uses a chemical inhibiting mechanism). Often a reduction in cake permeability and fluid loss is all that is required to control problems resulting from water sensitive clays. Borehole Stability makes it clear that hole instability is a complex problem - especially when the relationship between Drilling Fluid chemistry and borehole stability is addressed. The objective of main or sum hole is usually to penetrate the zone of interest for evaluation or exploitation purposes. Proper evaluation or full production may be affected if the wellbore fluids cause production zone damage. The following damage mechanisms can cause a decrease in well productivity: 1) Water Block 2) Emulsion Block 3) Wettability Alteration 4) Particle Migration

5) Precipitates 6) Clay Swelling

Other common problems, which may impede achievement of the objective on any interval, include: 1) Severe Loss Zones 2) Water Flows 3) H2S (also a safety consideration) 4) Bacteria 5) Differential Sticking 6 The Formation of Hydrates (safety also) 7) Torque


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10.2.3 The Third Step Deciding on a system is a matter of assessing the available options, keeping in mind the demand criteria of each interval and any environmental regulations. Shale analysis often points towards one obvious choice, such as oil-based fluid. When several alternatives exist, different factors can help narrow the choice down. The most obvious is to attempt to choose a fluid that can be used on most or all of the intervals. Other eliminating factors are listed below: 1. Safety - Personnel - Environment - Equipment 2. Logistics - Remoteness of Location & Transportation - Season - Weather Conditions - Using the Least Number of Fluid Systems per Well - Complimentary Equipment Requirements - Testing & Lab Equipment - Bulk-Handling Equipment - Mixing Equipment - Solids Control Equipment - Storage Facilities - Cuttings Treatment Equipment - Filtration Equipment 3. Economics - Availability of Base Fluid & Chemicals - Maintenance Costs - Buy-back Possibilities - Disposal Problems 4. Bit Hydraulics and ROP Optimization 5. Past Experience - Often aids in Selection, by a Process of Elimination 10.3 PLANNING A DRILLING FLUIDS PROGRAM Formulating a drilling fluids program is usually carried out in conjunction with the Operator's geology and engineering departments. Some Operators choose to formulate their own drilling fluids programs. Often they request one from a service company - sometimes as part of a bid package. The drilling fluid program should address all possible issues and propose appropriate contingency plans. It may include: 1. Engineering Parameters 2. A Lithological Description 3. Pore Pressure Prediction 4. Casing Setting Depths 5. A Well Profile with KOP and DOP 6. Proposed Fluids System - Usually by Interval 7. Chemical Concentrations


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8. Required Fluid Properties 9. Lab Testing Results 10. Offset Well Information 11. Contingency Formulations and Procedures - LCM Pills - Barite Plugs - Viscosity Sweeps - Lubricity Pills - Procedures and Directives from Regulatory Agencies - Corrosion Control Program 12. A Materials and Volume Estimate by Interval 13. A solids Control Program 14. Price List The properties of the drilling fluid of particular importance are: 1. Density - Formation Pressure Control 2. Rheology - Optimum Cleaning and Hydraulics 3. Salinity or Polymer Content

4. Alkalinity 5. Fluid Loss Characteristics


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CHAPTER 11 SOLIDS CONTROL 11.1 KEY POINTS & SUMMARY 11.2 SOLIDS AS A CONTAMINANT

11.2.1 Sources of Solids 11.2.2 Size Definition 11.2.3 Effects of Excessive Solids 11.2.4 Benefits of Solids Control

11.3 SOLIDS CONTROL EQUIPMENT

11.3.1 General Layout 11.3.2 Gumbo Box 11.3.3 Shale Shakers 11.3.4 Sand Trap and Degasser 11.3.5 Hydrocyclones 11.3.6 Mud Cleaners 11.3.7 Decanting Centrifuges

11.4 SOLIDS IN DRILLING FLUIDS

11.4.1 Unweighted Systems 11.4.2 Weighted Systems 11.4.3 Systems in Transition 11.4.4 Solids in Oil-Based Fluids

11.5 CONTROLLING SOLIDS

11.5.1 Solids Analysis 11.5.2 Particle Size Analysis 11.5.3 Dilution


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11.1 KEY POINTS AND SUMMARY The solids in drilling fluids are either added to perform a specific function and are thus desirable solids, or added as a contaminant and are undesirable. Desirable solids include lost circulation material, which can generate problems due to the relatively large size. Weighting agents have a range of densities that are higher than the drilled solids and are thus removed relatively easily by gravity separation. Clays such as bentonite are added to exploit their colloidal properties and perform their function better than the clays derived from shale deposits. Undesirable solids consist of the cuttings and the fine colloidal material caused by hydration and dispersion. The inhibitive properties of the mud as well as the type of formation are important factors, which influence the size and shape of the cuttings that will have to be removed at the surface. Mud circulation rate, drilling rate and hole size control the loading of cuttings in the mud. Solids removal equipment techniques attempt to separate the various solids in the mud on the basis of their size and density. A primary piece of solids removal equipment is the shale shaker. These have seen significant development in both the cloth and the mode of vibration of the screen. It is important that as large a proportion as possible of the mud solids is removed at this stage. The sand trap is an unstirred settling tank with a rapid dump valve that protects the rest of the system in the event that the shakers are by-passed. Hydrocyclones generate a centrifugal force by pumping the mud into a cone where solids slide down to the bottom and the cleaned mud exists at the top. The size of the separated solids depends on the diameter of the cone. Mud cleaners are used in weighted muds and discharge 5-10 cm (2-4 inches) hydrocyclones onto a fine vibrating screen. Centrifuges generate a gravitational force by rotating the mud in a bowl. The solids are continually scraped away so the process can be continuous. They are expensive machines to operate but offer the most control. They can be used alone to remove solids totally or in tandem to recover weighting material and then to remove solids and recover a liquid phase. They have particular application in the more expensive polymer based muds and oil based muds. The solids removal equipment should be arranged so that the larger sized solids are removed before the finer sized solids. The equipment is sized and used according to the flow rate and type of mud that is being used. The use of solids removal equipment plays an important role in controlling the properties and hence performance of the mud. Properly designed and operated equipment will give better mud properties at lower costs. 11.2 SOLIDS AS A CONTAMINANT Most people involved with drilling recognize that excessive concentrations of entrained solid particle are the most serious and adverse form of drilling fluid contaminant. No drilling fluid system is immune to solids contamination, and virtually all-drilling operations employ some form of mechanical solids removal equipment. Until the introduction of oil field decanting centrifuges in 1952, solids were removed by using settling pits (gravity) and rudimentary (coarse) vibrating screens. 6-inch hydrocyclones were introduced in 1954 with more efficient 4-inch cones following in 1962. In 1966 very fine, mesh screens were introduced, with hydrocyclone/screen combinations becoming available in the early 1970's. The 1980's saw the introduction of high performance, linear motion shakers with high-speed centrifuges also becoming commonplace.


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11.2.1 Sources of Solids Chapter one described several ways of classifying solids in drilling fluids. Briefly they were: 1. By size; colloidal to gravel sized. 2. By surface charge; reactive or inert. 3. By how they entered the fluid; drilled solids or "commercial solids". 4. By their specific gravity; high or low gravity solids. This chapter is primarily concerned with the third method, how they entered the fluid. Commercial solids are sometimes called desirable solids. These materials are non-soluble additives, which an operator pays for, to enhance a specific function of his fluid. They include: weighting agents, clays, bridging agents, torque reducers and certain hole stabilization additives. On the other hand, drilled solids are sometimes called undesirable solids. The source of these solids is the formation rock, which the bit is penetrating. The term Solids Control refers to methods by which concentrations of drilled solids are monitored and controlled. Drilled solids are transported by the Drilling Fluid, up the annulus to be removed at the surface. The rate at which drilled solids are generated and become entrained in the drilling fluid (their concentration) depends on the hole size, ROP, and cuttings transport ratio. The nature of the formation being drilled, the inhibitive nature of the Drilling Fluid, the nozzle velocity and the flow rate influence the character of the drilled solids on their way to surface. Character in this context refers mainly to particle size. If the formation is hard, old rock, or if the drilling fluid is inhibitive, drilled solids particle size degradation is usually minimal. In certain formations, using an uninhibited fluid often results in adverse particle size degradation. As cuttings come to surface confining pressures are reduced, allowing hydration reactions to speed up. Soft tertiary shales in the North Sea may produce cuttings at surface where 60 - 80% of the solids are less than 200 microns with many less than 10 microns. An invert emulsion system eliminates the hydrational stresses causing these same cuttings to arrive at the surface essentially the same size as they were at the bit. Mechanical degradation occurs when nozzle velocities are excessive or when turbulent flow regimes are being used. It also occurs in deviated wells where the cuttings are jammed between the pipe and the low side of the hole. Mechanical degradation can also occur at surface where drilled solids are subjected to extreme forces, inside solids removal equipment. The size of the returning solids also depends on the relationship between the bit type and the formation type. A PDC bit drilling through a soft formation may generate cuttings 1 cm - 2 cm diameter whereas a diamond bit in hard shale could generate cuttings 0.1 cm or smaller. Studies have indicated that at a given rotary RPM, drilled solids become coarser as the ROP increases. In virtually every drilling operation, there will be solids generated at the bit, and mechanically degraded in the circulating system, which are so small that they are beyond the point of being captured by solids removal equipment. The goal of solids control is to keep solids in this size range at a minimal concentration, such that dilution volumes are minimized.


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11.2.2 Size Definition In order to effectively proceed with a discussion of small particles and how to effectively control them in a drilling fluid environment, an appreciation of size is necessary. The universal unit for describing small sizes in the micron (µ) which is 1/1000 of a millimeter. Table 11.1 gives the sizes of some common materials in microns. TABLE 11.1 SIZES OF SOME MATERIALS AND SENSES IN MICRONS

Material/Sense

Diameter in Microns

Human Hair 30 - 200

Polen 10 - 100

Portland Cement Dust 3 - 100

Milled Flour 1 - 80

Talcum Powder 5 - 50

Red Blood Corpuscles 7.5

Human Eye Resolution, Normal 40 (min.)

Cosmetic Preparations 35 (max.)

Face and Lip Skin Sensitivity 35 (min.)

Finger Tip Sensitivity 20 (min.)

Between-Teeth Sensitivity 6 - 8 (min.)

Human Eye Resolution, Absolute 6 - 8 (min.)

The size of the solids entrained in a Drilling Fluid system range from particles measured in millimeters down to colloidal sized particles less than a micron in diameter. Drilling Fluid solids may be classified by size in the following manner: Colloidal Solids <2 µ Silt-sized solids 2µ-74µ Sand-sized solids above 74µ or Cuttings-sized solids any size removed by shakers Some authorities use the term clay-sized interchangeably with colloidal-sized. This can cause confusion because the term colloidal refers to size alone. Barite, bentonite and dolomite can all exist in a drilling fluid as colloidal-sized solids. 11.2.3 Effects of Excessive Solids Generally as the concentration of solid particles in a Drilling Fluid system increases, the properties of the fluid become altered. These in turn can affect certain drilling parameters. The effects of solids on both Drilling Fluid properties and on drilling parameters are always adverse. They include:


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1. An increase in rheological properties (PV, YP and gel strengths) 2. An increase in filtration rate and wall thickness, compared to Bentonite. 3. An increase in the potential to become differentially stuck 4. An increase in the potential to lose circulation 5. A reduction in penetration rate 6. A decrease in bit life 7. An increase in chemical treatment requirements (cost) 8. An increase in abrasive wear on equipment The rate or concentration of solids, which will adversely affect properties or parameters, depends on the nature of the solids themselves. Three parameters contribute to the nature of solids in Drilling Fluids. 1. Specific gravity 2. Reactivity (surface charge) 3. Size (net surface area per unit of weight) If the specific gravity of solids is high, as in the case of barite (SG = 4.2) then a smaller volume concentration and surface area is required to achieve a given density. This reduces chemical treatment requirements and cost, since all solids adsorb both free water and commercial chemicals. The reactivity of the solids is also an important consideration. Solid particles retaining a high surface charge density cause adverse rheology first. Clays are the worst offenders. The surface charges on clay particles attract polar molecules such as water and commercial additives including polymers, salts and sodium hydroxide. This reduces both the free water in the system and the chemicals, which were added to purposely control certain properties. Most water-based systems can tolerate the addition of 150 kg/m3 of barite far more easily than 150 kg/m3 of bentonitic formation solids from a rheological perspective. Barite is sometimes called an "inert" solid because its surface charge is low. Because Barite is an ionic crystal it does have broken edge charges. These charges although small, make it necessary to add thinners to a mud system at higher concentrations of barite. The size of the solids entrained in a drilling fluid also dictates when mud properties and drilling parameters will be affected. Size is directly related to surface area. Table 2.9 shows the surface area of a 1 cm square cube as it is broken into increasingly smaller fractions. Because the surfaces of solid particles are charged, a high surface area to weight ratio causes problems more quickly. 120 kg/m3 of drilled solids with a median average particle size (D50) of 40 microns will not adversely affect the rheological properties of a water-based mud. If the D50 is allowed to degrade (mechanically or chemically) to 1.5 microns the gel strengths will become excessive. 11.2.4 The Benefits of Solids Control The benefits of controlling the concentration and type of solids in Drilling Fluids are directly related to cost savings and security. Cost savings include: 1. Reduced chemical requirements 2. Lower cleanup costs 3. Longer bit and equipment life 4. Improved penetration rates


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Security means: 1. Reducing the chances of becoming differentially stuck. 2. Increasing the chances of being able to break circulation after a trip, without

fracturing the formation. 3. Enhancing hole cleaning, higher YP/PV ratios and lower n values contribute to a

flatter velocity profile in the annulus. 4. Reducing the chances of losing circulation. 5. Reducing the surge and swab pressures when moving pipe. 11.3 SOLIDS CONTROL EQUIPMENT Various prices of solids control equipment are incorporated into the surface mud system. These are designed to remove various sized undesirable solids. Although equipment design is continuously improved and can constitute a large capital cost, (over $200,000.00 for certain centrifuges) nothing exists which is able to remove all of the solids in a given fluid. Further, no equipment exists which is able to differentiate between a given barite particle and a slightly larger drilled solid particle. Some centrifuges are able to remove particles down to the colloidal range. Unfortunately particles are being continuously generated at the bit and degraded in the annulus which are 1 micron and smaller. If these solids enter the Drilling Fluid at a rate faster than the volume of new mud is being built to fill the hole, then at some point dumping and diluting will be necessary. This point will be reached at an earlier stage if larger solids are being introduced to the system at a rate, which exceeds the capacity of the available solids equipment. The goal of solids control is to run and maintain the proper equipment, configured in the proper manner, as efficiently as possible, such that the whole mud dumping and dilution is minimized. 11.3.1 General Layout There are almost as many solids control equipment configurations as there are drilling rigs. Most rigs have at least one inefficiency in their configuration. When designing or modeling a surface pit system the two key points in terms of solids control are simplicity and versatility. The pieces of equipment should be separated. That is, the overflow from one piece should discharge into the suction compartment for the next piece of equipment downstream. Provisions should be made for a means of backflowing if the overflow rate of any piece of equipment is greater than the circulation rate. A versatile system is one where the desilter cone underflow can be directed either over a screen, or to the dilution ditch (sump) or to the centrifuge suction. The centrifuge should sit on a pit close to the suction pit, above an agitator. It should also be close to the dilution ditch. This way it can be used for Barite recovery or solids discard without having to install elaborate plumbing. As solids are brought to surface they should have to contend with some or all of the following pieces of equipment in this order: 1. Gumbo Box 2. Shale Shakers 3. Sand Trap 4. Degasser 5. Desander 6. Desilter / Mud Cleaner 7. Centrifuge Figure 11.1 depicts a general solids equipment configuration exhibiting good versatility. All pits with the exception of the sand trap should be agitated with the proper sized agitator. Mud guns


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are a component of most pit systems. Proper agitation insures good mixing, less entrained gas and a proper feed to the solids equipment. The mud skimmer located just prior to the suction compartment makes it possible to maintain a static volume in the upstream tanks. This allows for easier volume monitoring (kick detection) since the suction tank is the only one that fluctuates.

Figure 11.1 General configuration of solids control equipment 11.3.2 Gumbo Box or Chain Most offshore rigs are equipped with a gumbo box. This is a small compartment 5-10 m3, located upstream of the shale shakers. It is designed to reduce the cuttings load on the shale shakers when mud rings, gumbo, or large chunks of formation are returning to surface. Different types of gumbo boxes have been designed. Some like the one in figure 11.1 are similar to a sand trap, with a large pneumatic valve on the bottom. This allows for rapid dumping. Others consist of sloping parallel bars. The mud passes through the bars and on to the shale shakers while the gumbo slides down the bars to the dilution ditch. 11.3.3 Shale Shakers The mud flow from the flow line must pass over a shale shaker. A shale shaker is a vibrating screen. There are normally two or three units acting in parallel. Some models may operate two or more sizes of screens in series (double deck shakers). Bypass valves are present to divert the mudflow away from the screens if required. The shale shaker is the first and therefore the most important device for removing solids from the mud so great care should be taken in its selection, maintenance and operation. Screen size selection should be evaluated on the basis of the expected maximum flow rate, hole size, penetration rate, type of mud, density of the mud and the type of formation. At shallow depths where hole sizes are large and penetration rates rapid, the screen size may be coarser


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than is desired. The screen opening should not be the same size as the particles being separated as this leads to rapid screen plugging. The range of mesh sizes with corresponding size of screen opening is given in Table 11.2. Typically the minimum mesh size is 100 mesh (150 microns). Advances have been made in the design of the screens, giving longer life and rapid screen changing capabilities. TABLE 11.2 IADC-API Designations of representative Test Screens Test Screen

API - IADC Designation a

Wire Diameter Calculated

(Microns)

U.S.S. No. 50 API 50x50 (295,33.7) 213

U.S.S. No. 80 API 80x80 (177,31) 140.5

U.S.S. No. 100 API 100x100 (149,35.2) 102

TYLER No.150 API 150x150 (104,37) 65.2

U.S.S. No.200 API 200x200 (74,340) 53

U.S.S. No. 325 API 325x325 (44,31.7 34 a The API Designation shows mesh count, opening in microns and percent open area in that order.

The volume of liquid able to pass through any screen depends on: mesh opening size, percent open area, weave of screen, speed and amplitude of vibration, type of motion, fluid rheology, solids content of liquid, and feed rate and type of oversized solids. The following guidelines apply to operating shale shakers efficiently: 1. The mesh of the screen used should be the minimum size that will tolerate the

present flow rate. At least 75% of the screen should be covered with liquid mud. 2. If throughput capacity is reduced due to sticky particles reducing the open area,

increase the mesh size. Avoid using a hard jet-spray (spray bars) to aid in initiating cuttings movement.

3. If throughput capacity is reduced due to plugging by near - aperture sized

particles, decreasing the screen size will usually help. In the case of massive sand, oblong mesh screens are usually least apt to blind.

11.3.4 Sand Trap and Degasser The purpose of sand traps is to provide a gravity-settling compartment for solid particles, which have bypassed the shaker either intentionally or through a torn screen. The drilling fluid passing through the screens should flow directly into a sand trap. A sand trap is a small compartment (5-15 m3) with sloping sides and a dump valve at the bottom. The sand trap should not be used as a suction tank for any piece of surface equipment, nor should it be agitated. The fluid exit from the sand trap should be over a retaining weir to the next, stirred compartment.


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A degassing unit is essential if efficient solids control efficiency is to be realized. This is because centrifuges pumps feeding hydrocyclones lose efficiency where they are pumping gas-cut mud. Provision for degassing equipment should be made between the sand trap and the first hydrocyclones. 11.3.5 Hydrocyclones A hydrocyclone develops centrifugal forces by circulating the fluid in a circular path as shown in Figure 11.2. The fluid is pumped through centrifugal pumps to a pressure of about 40 psi, entering the cone tangentially near the top of the cone. The spiral motion generates centrifugal forces that throw the larger, denser particles to the outside of the cone discharging at the bottom. Near the bottom of the cone, the clean mud reverses direction and spirals up towards the top. A hollow cylinder, the vortex finder, extends from the top of the cone and forms the overflow outlet for the cleaned mud. The diameter of the cone, the feed rate and pressure, the mud density and the relative diameters of the solids discharge opening and the vortex finder are all critical parameters that determine the performance of the hydrocyclone. The operating parameters are summarized in Table 11.3. TABLE 11.3 Summary of Parameters of Hydrocyclones Hydrocyclone CMS

Diameter Inches

Feed Rate Gallons per Minute (per cone)

Median Cut Point

30.5 12 400 100

20 8 Desander 150 50

15.25 6 100 30

10 4 Desilter 50 15-30

5 2 Desilter 25 10-25


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Figure 11.2 Hydrocyclone nomenclature The cyclones can either be run in a "balanced" or "chokebottom" mode. The balanced design creates a slight vacuum at the bottom discharge, drawing in air. This gives a drier discharge of solids but there is a higher risk of blocking. A "chokebottom" mode retains a positive pressure in the cone and a wetter discharge but the risk of blocking is minimized. The number of cones and pump rate are ideally set at about 125% of the mud flow rate so that the cleaned mud can dilute the incoming mud. The following are some practical suggestions, which may be considered when operating hydrocyclones: 1. Run hydrocyclones continuously when using unweighted mud. Use a mud

cleaner for weighted mud. 2. Use the proper cone feed pressure, and keep the cones unplugged. Using a fine

screen shale shaker or 12 inch desanders will reduce loading on 4-in. cones operating downstream. Size both desander and desilter units to process at least 125% of the mud flow rate. Each unit should return mud to the next compartment downstream of its suction. The suction, feed, and overflow lines should be sized with appropriate diameters and minimum lengths, and in accordance with good centrifugal pump installation practices.

3. Keep the cones in spray discharge. Plugging of the inlet manifold or the

individual cone inlets may cause loss of whole mud from the bottom, of the cone. The discharge manifold should be close to atmospheric pressure; backpressure


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or a partial vacuum in this manifold will shift the cones away from their proper balance. An easy way to maintain atmospheric pressure is to insert an open pipe into the overflow line.

4. When water is being added to the mud, it should be added upstream of the

desilter in order to reduce the mud viscosity and improve efficiency of the desilter. Chemicals, bentonite, or other mud additives should be added to the system downstream of the desilter.

5. Air entrainment in the cone overflow will be reduced if the overflow line slopes

down at an angle rather than dropping vertically. This line should stop at the surface of the mud in the tank. Note that the cones are designed to pull air into the mud; thus air entrainment cannot be eliminated when using hydrocyclones.

6. When Barite is not the most valuable material in the mud, hydrocyclones may be

appropriate for solids control. For example, a 1.38 s.g. KCl/XC mud might contain only $57/m3 worth of barite and $125/m3 worth of other additives. Use of cones to remove some drilled solids and some barite might be cheaper than diluting and rebuilding new mud.

7. When a weighted system is unacceptably abrasive, hydrocyclones may be run

for one or two circulations to strip out the sand. 11.3.6 Mud Cleaners A mud cleaner is a device that has hydrocyclones mounted such that their underflow falls on a fine-mesh vibrating screen. When operating properly, a mud cleaner combines the high processing rate of the cones with the sharp cut and dry discharge of a vibrating screen. The solids that leave the bottoms of the cones but do not pass through the screen are discarded. The cone overflow and the material going through the screen are both returned to the active system. Commercial mud cleaners are circular or rectangular in shape. Most drilling operations restrict mud cleaner use to weighted systems, usually higher than 1250kg/m3. Most mass-balance studied, system evaluations and particle size analysis performed by Anchor indicate that the actual low gravity solids removal "workshare" performed by mud cleaners is not that impressive. When deciding on whether a mud cleaner should be used it is important to select the proper screen size. Fresh unsheared barite in the system would require a screen of about 150-200 (104µ−74µ) mesh to be installed initially. This doesn't make much sense if the shakers are equipped with 210 mesh screens. After the barite has been sheared finer screens may be installed. At this point the screen underflow should be analyzed to discern the value of the barite being recovered and the amount of low gravity solids being returned to the system. 11.3.7 Decanting Centrifuges Decanting centrifuges are an integral part of most solids control programs. New advances in centrifuging technology have enabled some machines to rotate at 3,500+ RPM, generating a force of over 2,000 times the force of gravity while feeding at 150 U.S. gpm. These parameters enable centrifuges to separate solids particles down to 2 µ.


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FeedMud In

SolidsEffluent

Figure 11.3 Figure 11.3 shows a cutaway view of a centrifuge. Mud enters the machine through the feed pipe on the right side. Often it is desirable to dilute the feed mud with water. This lowers the viscosity, enhancing the efficiency of the machine, thereby lowering the cut point. If the feed mud is diluted, mud and water must be metered in order to perform proper efficiency analysis. Feed mud is discharged into the scroll feed chamber, where it is distributed to the scroll. The mud is thrown outwards to the bowl, where its speed soon approaches that of the rotating bowl. Note that the flights on the scroll do not touch the bowl. The space between the bowl and the flights is called the clearance tolerance and is usually about 1/8". A cake of solid particles occupies this space along the entire inside diameter of the bowl. This cake rotates at the same speed as the bowl, with the bowl. The liquid mud occupies a cylindrical space beginning at the cake and on towards the body of the scroll. This fluid is referred to as the pond. The depth of the pond may be varied by adjusting the height of the weirs at the liquid discharge end of the machine. The pond depth for most machines varies from between 1.5" to 2.5". The length of the pond from the liquid discharge end of the bowl to the point where it stops somewhere along the inclined or tapered part of the bowl is called the clarification length. It is generally accepted that most solids separation occurs at the surface of the pond. Solid particles are centrifugally forced through the pond toward the cake. The bowl and the scroll both rotate in the same direction. All centrifuge specifications include a gear ratio. In most machines the scroll turns slightly slower than the bowl. (If it didn't the flights would rotate at the same speed as the cake.) Because the scroll rotates at a different speed, it acts like a screw or auger. The effect is to cause the flights to move horizontally to the left in relation to the bowl. As the flights pass by the cake they scoop solid particles from the surface of the cake and augur them towards the solids discharge end of the machine. Most machines are equipped with a gear ratio of between 50:1 and 80:1. When a machine has a gear ratio of 50:1 it means that for every 50-bowl revolutions the scroll turns 49 times. To verify


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this, open the cover on the centrifuge and look through the solids discharge port at the tapered end. Place a chalk mark on the flight, in line with a chalk mark on the bowl. Rotate the bowl by hand one time. When the port returns after one revolution, the chalk marks will be separated by a space of about 7°. The sound emanating from most centrifuges oscillates. By counting the number of oscillations in one minute and multiplying by the numerator in the gear ratio it is possible to determine the RPM the machine is operating at. The distance between the flights is called the pitch. This distance is usually 70 mm - 100 mm. For each differential revolution the solids are transported along the cake a distance of 1 x pitch length. Some scrolls have double lead flighting in which case solid particles are transported a distance of 2x pitch per differential revolution. Some machines are manufactured with tungsten carbide tiles on the tips of the lead flights. This is an excellent innovation since this is where most of the wear occurs in the interior of the machine. In fact if the torque-actuated mechanism (usually a shear pin) continuously triggers a shut down, it often means that the tips of the flights are worn. The tips are tapered, and as they wear the clearance tolerance increases. This not only increases the thickness of the cake, but also increases the contact area between flight and cake. The resulting increase in friction is what usually causes the torque-activated mechanism to trip. The solids are augured along the length of the bowl toward the solids discharge ports. Eventually they reach a point somewhere along the tapered (conical) part of the bowl where they leave the effluent or pool. The area from the pool to the discharge ports is called the beach. It is here that the solids reach a "dry" state. Increasing the pond depth can reduce the length of the beach. As the length of the beach is reduced the solids discharge becomes wetter. The inclination of the beach angle in almost all centrifuges is between 8.5 and 10°. The fluid, which leaves the machine, must flow between the flights in a direction counter to which the flights are moving in relation to the bowl. That is to the left in figure 11.3. The flights act as channels and the fluid spirals along the parameter of the inside of the bowl to the discharge ports. This regime is called helical flow - common to most centrifuges. The effluent capacity (pond volume) of most large bowl (14"x 48") centrifuges is about 10 - 13 US gallons, depending on the pond depth. The retention time of any volume of liquid in the machine is between 4 and 5 seconds depending on the feed rate. In other words the fluid moves through the flights with enough velocity to be in turbulent flow if the viscosity isn't excessive. It has been theorized that this turbulence could hamper separating efficiency by scooping solids from the cake back into the effluent. As a result some manufacturers are providing flights with openings in them such that the fluid may travel directly (and slowly) to the discharge ports - without having to spiral along the outside perimeter of the bowl. This type of flow is called co-axial flow. The internal flow regime does not effect effluent retention time. Anchor Drilling Fluids has developed equations, which generate a theoretical cut point for any given decanting centrifuge. Inputs into these equations include: G Force Imparted Particle Density Fluid Density Fluid Viscosity Pool Depth Flow Rate Volume of fluid


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The following rules of thumb apply to centrifuging drilling fluids: The most important parameter in centrifuging is the G Force a given machine can generate. G Force can be calculated by: G Force = 0.0000142 (RPM2) (Diameter - Inches) The Diameter should be calculated from the surface of the pond on one side of the bowl to the surface of the pond on one side of the bowl to the surface of the pond on the other side of the bowl since the majority of separation occurs on the surface of the pond. Decreasing the pond depth will make the solids discharge drier - the beach length is increased. However this will also reduce the fluid retention time in the machine, reducing the allotted time for a particle to separate (to reach the cake). This does not increase the cut point as dramatically as one would expect. This is because the particle has less distance to fall through a shallower pond. Increasing the feed rate substantially increases the cut point by reducing the fluid retention time. Theoretically, increasing the feed rate from 100 U.S. GPM to 200 U.S GPM would increase the cut point in a given machine from 3.45µ to 4.90µ??? all other factors being equal. Many drilling people are concerned about the throughput capacity of centrifuges. Most machines are being designed to process substantially less volume than the circulation rate. What they fail to understand is that the solids processing rate of a given machine is a much more definitive number. For example if the ROP in a 215.9 mm hole interval is 10 m/h, 950 kg of drilled solids are being added to the mud system each hour. If the shaker is removing 800 kg/h, and the centrifuge is removing 150 kg/h then the mud density will not increase, even if the centrifuge is only processing 50 U.S. GPM. 11.4 SOLIDS IN DRILLING FLUIDS 11.4.1 Unweighted Systems Solids control in unweighted systems is a logical exercise. The shale shaker screens are sized such that the smallest possible screens are installed. The desander is operated usually if the whole mud sand content exceeds 1/4% by volume, or if its underflow density is reasonably higher than the active system density. The desilter is normally run continuously - even while tripping. Its efficiency can be minimized by calculating the number of kg of low gravity solids discharged per hour at different operating pressures and aperture diameters. Before changing aperture diameters the L.G.S discharge for two cones with different aperture sizes can be analyzed and compared on an individual basis. The desilter discharge is usually directed into a catch tank where it is blended with the whole mud feeding the centrifuge. This set up is called a closed loop system. Analysis should be performed regularly on all equipment when running an unweighted system. 11.4.2 Weighted Systems A weighted system usually has a density in excess of 1250 kg/m3. Again the smaller shaker screen size is used. Desanders are not normally operated, unless on a one circulation-at-a-time basis to control the sand at less than 1%. Often hydrocyclones are used also on a circulation


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basis - sometimes over screens - as mud cleaners. When the centrifuge is operated it is used to recover barite in the underflow. The liquid phase is discarded. Weighted systems have less tolerance for drilled solids. In highly weighted systems - above 2 000 kg/m3 all of the solids especially reactive drilled solids are competing for water. When the median average particle size, sometimes called D50, is low (below 5-7µ) and drilled solids concentrations are high, commercial additives such as polymers cannot function efficiently. Therefore it is essential to run any solids control equipment efficiently at the outset, discarding drilled solids before they degrade. Whole mud dumping and dilution is expensive in weighted systems. It is important to analyze the discharge of all equipment diligently in order to discern the value of the barite and the nature of the drilled solids being discarded. Anchor Drilling Fluids supplies some customers with on-sight particle size analysis. The important feature to watch is trends in rheology, especially gel strengths. The 10 minute gel strength measured a high temperatures will begin to increase long before the room temperatures gel strength if the majority of particles approach colloidal size. This indicates a need to operate the centrifuge in barite recovery mode for one or two circulations. In this mode colloidal particles are discharged along with the effluent (overflow) while barite greater than 2-6 µ is recovered to the suction tank. Figure 11.4 shows how a centrifuge affects the particle size distribution curve in a weighted system.

Drill Solids

0 10 20 40 60 80 100 200 400 600 800

% S

olid

s

Particle size (equivalent diameter in microns)

Commercial clay

GUMBO &CUTTINGS

SANDSILT

SHAKER OPERATING RANGE

GUMBO CHAIN

DESILTER OPERATING RANGE

CENTRIFUGE OPERATING RANGE

DESANDER OPERATING RANGE


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11.4.3 Systems in Transition Systems with densities ranging from 1150 - 1300 kg/m3 can be called transition systems (ORMSBY, 1983). Under these conditions, desilting is continued, often intermittently, supplementing further density increases with barite. Some operators prefer to leave the desilters off although this leads to increased abrasiveness. Others separate coarse drilled solids by discharging the cone underflows onto a screen. In the case of transition systems each case must be assessed separately, according to system particle size and the equipment available. 11.4.4 Solids In Oil Based Systems Oil-Based Systems have a much greater tolerance to drilled solids than do water-based systems. The solids do not hydrate, soften and disperse into the fluid because they are inert in terms of chemical activity in a fluid with oil as the continuous phase. Solids are however, degraded mechanically. Drilled solids should be removed as efficiently as possible as soon as they are generated, before they break up onto fine solids. The presence of drilled solids has the same adverse effects on rate of penetration as in water-based systems. Their presence also requires treatment with oil wetting agents, which can be expensive. Oil wetting the solids imposes an upper limit on the solids content of the oil mud at a given oil/water ratio. 11.5 CONTROLLING SOLIDS 11.5.1 Solids Analysis As solids control technology evolves, it has become clear that progress and success is dependant upon two factors. These are the degree of accuracy of measurement and standardization of reporting procedures. Today simply measuring and reporting underflow densities and rates is no longer an acceptable method of gauging system performance. If effective recommendations are to be made, all of the solids, including barite, must be monitored methodically through the entire circulating system. This includes differentiation between solids lost as pure solids or as entrained solids when dumping whole fluid. In order to obtain reliable results, from calculations, several parameters should be monitored and updated regularly. These include barite density and brine density. Commercial solids including salts, polymers and non-volatile additives should be factored out of calculations. C.E.C. of bentonite and formation solids may be monitored where applicable. Any incomplete condensation of base oil is corrected for retorts and should be calibrated regularly. The formation bulk density and connate fluid density may be factored into calculations where applicable. To improve accuracy in mass-balance calculations an AVC (microwave) moisture analyzer is sometimes used - instead of a retort. Daily reporting is designed with two functions in mind. It should help with detection and correction of current inefficiencies. It should also be structured so that it serves as the main input into the final analysis and recommendations.


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11.5.2 Particle Size Analysis The cut point of a given piece of solids equipment refers to the size of particle, which upon entering the machine has a 50% chance of being ejected in the underflow. The D50 of any fluid containing suspended particles refers to the median average particle size. A cut point for a given machine can be approximated, if the D50 of the underflow and the D50 of overflow are known. 11.5.3 Dilution When particles are returning to surface which are too small to be separated by the existing solid control equipment, or when they are being generated too rapidly for the existing equipment to handle, dumping and dilution with new mud is often necessary. The point where this occurs depends on density or gel strength limitations. Dilution serves to lower the concentration of solids in all size ranges. After diluting with water the D50 will remain unchanged. However in order to maintain system properties new chemicals must be added in proportion to the amount of water to be added. Diluting systems containing barite can be extremely expensive. The following rules of thumb apply to, and should be considered before diluting: 1. Dump and dilute to reduce the drilled solids concentration before weighting up. 2. Dump dirty mud before adding fresh water and chemicals. 3. When drilling soft formation where solids build up is a problem, reducing

excessive nozzle velocities can result in an immediate and dramatic reduction in the daily dilution volume required.

4. Running the desander, dumping the sand trap or gumbo box, or allowing some

mud to run over the shakers is almost always a better alternative than simply dumping whole mud.

5. If whole mud must be dumped - plan ahead and dump mud at bottoms up after a

trip. This mud is usually heavier than active mud. Cases have been documented in long intervals of deviated open hole where simply tripping pipe generated 30 metric tons of drilled solids into the active system. If gas monitoring is required at bottoms - up simply turn the shakers off.

6. Instead of sending mud overboard, put it in a spare tank. This alleviates anxiety,

especially when drilling top hole.


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CHAPTER 12 UNDERBALANCED DRILLING AND FOAM 12.1 KEY POINTS AND SUMMARY 12.2 DRILLING CONTROL SYSTEMS

12.2.1 Controlling the Inflow from the Formation 12.2.2 Solids Control

12.3 DRILLING FLUID SYSTEMS 13.3.1 Air and Nitrogen 13.3.2 Water, and Hydrocarbons 13.3.3 Foam Systems 13.3.4 Foam Stability 13.3.5 Corrosion


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12.1 KEY POINTS AND SUMMARY The API definition of underbalanced drilling is as follows, “When the hydrostatic head of the drilling fluid is intentionally designed to be less than the pressure of the formation being drilled, the operation will be considered underbalanced.” Furthermore, “The lighter hydrostatic head of the drilling fluid may occur naturally or may be induced by adding natural gas, nitrogen or air to the liquid phase of the drilling fluid. Whether induced or natural, the lighter hydrostatic head may result in an influx of formation fluids, which must be circulated from the well and controlled at the surface.” From a practical point of view, underbalanced drilling has a number of advantages in comparison to overbalanced drilling. Essentially, underbalanced drilling is an effective method to control lost circulation, differential pipe sticking, increased ROP, eliminate post drilling formation stimulation, increased bit life, alleviate certain types of formation damage and can help in drilling through abnormally pressured gas bearing formations. 12.2 DRILLING CONTROL SYSTEMS Operators prefer to drill underbalanced primarily to, ü Reduce formation damage, (zero skin, zero solids) ü Eliminate lost circulation ü Increase ROP ü Maximize the production from the formation being drilled

When designing an underbalanced drilling program consideration must be made to; the magnitude of surface pressures, method of pipe rotation (top drive or rotary table), the nature of the reservoir fluids and gases to be encountered and the type of drilling fluid system to be used. An example of a closed loop underbalanced drilling system is shown in figure 13.1. If the formation being drilled is sour (H2S), drilling is done with nitrogen in a closed loop system. If the formation is sweet, air and an open tank / pit system can also be used.


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12.2.1 Controlling the Inflow from the Formation The key to drilling underbalanced is a blowout prevention system (BOP) figure 13.2. It has a number of functions, which include: ü Control of annular pressure while drilling. ü Backup control in case of diverter failure. ü Annular pressure adjustment. ü Well shut in.

Figure 12.1; shows a generic surface circulating system.


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Figure 12.2 BOP stack for underbalanced drilling operations The BOP allows you to control and optimize pressure drawdown and manage the hydrocarbon influx at the surface. 12.2.2 Solids Control An integral part of drilling underbalanced is solids control, which can directly impact fluid density. It is very important that solids are kept to a minimum as a high fluid density can; reduce ROP, increase lost circulation and returned solids can create skin damage.


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12.3 DRILLING FLUID SYSTEMS 12.3.1 Air and Nitrogen A large number of systems have been used over the years to drill underbalanced. Straight air systems are used to drill hard rock sections and shallow subnormally pressured gas wells. Where there is a risk of downhole fires, nitrogen (an inert gas) is used. Gas injection in normally or overpressurized reservoirs is not usually required. The underbalanced drilling conditions are maintained by controlling the hydrostatic pressure exerted by the column of drilling fluid. If the formation pressures are greater the reservoir will flow naturally into the wellbore with the hydrocarbons being separated at surface. However if lift and hole cleaning become issues, gas can be injected down the drill string. 12.3.2 Water, and Hydrocarbons A liquid medium is usually present and is used to achieve better hole cleaning. These liquids could be anything from formation water, crude oil, diesel, distillate, water based polymer systems or formic acid. One method for drilling underbalanced is a nitrified fluid. Upwards of 70% of all underbalanced horizontal drilling is done with nitrogen systems using water, crude oil or diesel. In designing a system attention must be made to the compatibility of the drilling fluid with respect to the formation fluids. If an overbalanced situation arises, the generation of emulsions in the formation could develop with two incompatible fluids. This could lead to severe skin damage and reduced production. 12.3.3 Foam Systems Stable foam provides another dimension to underbalanced drilling. A foam system traps a gas phase in the liquid phase, thereby reducing the density of the fluid. This is done with surfactants, which are mixed with the gas, fed into the liquid tank and mixed thoroughly. To achieve better hole cleaning and foam stability, polymers are added to the liquid phase, typically water. Some of the polymers used are: Guar gum, HEC, PAC and Xanthan. Some of the advantages of stable foam are: ü Efficient hole cleaning ü Suspends cutting when circulation has been halted ü Reduces connection times ü Increases ROP ü Eliminates cutting and fluid slugs ü Reduces torque and drag on the drill string ü Lower fluid densities ü Better retention of inert gas

Polymers are used to give viscosity to the liquid phase; consequently, a thicker fluid retains the gas phase more readily. As the foam is injected downhole the entrained gas is compressed as the pressure increases. As the foam picks up cuttings and travels up the annulus the gas expands aiding in hole cleaning. Cuttings are removed at the surface as defoamer is added to the mud system to remove the


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trapped gas and reduce the apparent viscosity, then the polymer fluid is processed through the solids control equipment. Surfactants and gas are remixed into the mud system and reinjected downhole. 12.3.4 Foam Stability The factors that affect the quality of the foam can come from 2 sources. On the surface you have issues with the additions of chemicals, are they compatible with the surfactants making the foam? Have you added too much of the surfactants? Have you increased the liquid rate, but not the surfactant, reducing your foam quality? Downhole foam quality is affected by an influx of formation liquids. Water, oil and brine will all affect the foam and thin it out. Foam quality can also be affected by the concentration of drilled solids. 12.3.5 Corrosion In the presence of oxygen, hydrogen sulfide, carbon dioxide, and formation brine, the corrosion rates on exposed steel can be high. The exact reasons for this are explained in Chapter 16, but needless to say, corrosion inhibition is important in under balanced drilling. Maintaining a high pH (>10) is the primary means to control corrosion, with caustic or magnesium oxide dissolved in the liquid phase. Secondary corrosion inhibitors are filming agents that coat exposed steel surfaces and can be sprayed on surface equipment. If extreme corrosion conditions exist an inhibitor can be injected (in a pill form) prior to commencement of underbalanced drilling operations.


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CHAPTER 13 RHEOLOGY 13.1 KEY POINTS AND SUMMARY 13.2 BASIC TERMS 13.2.1 Shear Stress 13.2.2 Shear Rate 13.2.3 Viscosity 13.3 RHEOLOGICAL MEASUREMENTS 13.3.1 The Marsh Funnel 13.3.2 Direct Indicating Viscometers 13.3.3 Brookfield Viscometers 13.3.4 Other tools for measurement 13.4 FLUID MODELS 13.4.1 Newtonian Fluids 13.4.2 The Bingham Plastic Fluid Model 13.4.3 The Power Law Fluid Model 13.5 ANNULAR RHEOLOGY 13.5.1 The Modified Power Law 13.5.2 Annular Shear Rate 13.5.3 Annular Viscosity 13.6 THIXOTROPY 13.7 THE EFFECTS OF TEMPERATURE AND PRESSURE 13.8 VELOCITY PROFILES 13.9 STOKES LAW 13.10 OPTIMIZING CUTTINGS REMOVAL RATES 13.10.1 Optimizing Annular Velocity 13.10.2 Optimizing Rheological Properties 13.10.3 Calculating the Maximum Safe ROP 13.11 CLEANING IN INCLINED PROFILES 13.12 PRACTICAL APPLICATION OF CUTTINGS REMOVAL THEORIES 13.13 FLOW REGIMES 13.13.1 Reynolds Number 13.13.2 Critical Velocity and Pump Output 13.13.3 The Fanning Friction Factor 13.13.4 The Friction Factor Graphically 13.13.5 The Friction Factor Mathematically 13.14 PRESSURE LOSSES 13.14.1 Annular Pressure Losses


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13.14.2 Pipe Pressure Losses 13.14.3 Bit Pressure Losses 13.14.4 Pressure Losses in Surface Connections 13.14.5 Total System Pressure Losses 13.15 BIT HYDRAULICS 13.16 EQUIVALENT CIRCULATING DENSITY


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13.1 KEY POINTS AND SUMMARY Because most drilling fluids are shear thinning, the viscosity of a given fluid varies as a function of its velocity. Most drilling fluids are also thixotropic. Thus, a certain amount of time is required for a drilling fluid to establish an equilibrium viscosity at a given shear rate. Viscosity may also be markedly influenced by temperature and pressure. Rheology is a science that uses a combination of mathematical and empirical means. It attempts to predict the behavior of drilling fluids as they are subjected to the influences of velocity, time, temperature and pressure. This chapter discusses the industry-accepted methods of discerning the combined affect of these influences on the thickness of a fluid - in both static and dynamic conditions. These methods are then applied to a discussion of cuttings transport and hole cleaning. Faster and safer rates of penetration may be achieved when an understanding of flow regimes and the correct use of cleaning equations are applied. Field experience is equally valuable in terms of accessing the performance of a given fluid. The objective is to determine the best means possible of ascertaining the concentration of cuttings in the annulus. Finally, the section deals with methods of predicting pressure losses in the various components of the circulating system. ROP optimization through bit hydraulic design is also discussed. 13.2 BASIC TERMS The term viscosity applies to how thick a fluid is. It is a value which denotes the degree of resistance to flow a given fluid exhibits. Oil well drilling fluids are classified into two groups by the way in which their viscosities behave when the fluid is set in motion. A Newtonian fluid has a consistent and predictable viscosity at any flow rate. Water is a Newtonian fluid. In a non-Newtonian fluid, the viscosity varies as the flow rate changes. With the exception of water and some oils, drilling fluids are non-Newtonian. As force or shear is applied to a drilling fluid and its velocity is increased, its viscosity should decrease. This happens because suspended and associated particles in the fluid are mechanically forced apart. The structure that provided the initial resistance to flow becomes degraded to some degree. Thus, drilling fluids are termed shear thinning. Shear thinning fluids move in one of two ways, depending on their velocity. A slow moving fluid resembles an assemblage of layers sliding by one another, with the middle layer having the highest velocity. This is known as laminar flow, shown in Figure 13.1. As the fluid's velocity increases, there is a point where the layered structure degrades to a random motion. This is termed turbulent flow. When motion is ceased, particles are able to re-associate. The fluid forms a gel-like structure. The degree to, and the rate at which this structure is built and broken may be measured and defined. The quality allows most drilling fluids to be defined as thixotropic.


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Figure 13.1. Drilling Fluid in the Annulus in Laminar Flow. The arrows denote the velocity of the layers as they slide (shear) by one another. Rheology may be properly defined as the science, which studies how variations in flow-rate, pressure and time influence the deformation of the internal structure and consequently the flow characteristics of a fluid. The proper application of this science is important in calculating and predicting the behavior and influence of drilling fluids on the following parameters:

1. Hole cleaning efficiency. 2. Friction losses in the drill pipe or annulus. 3. Surge pressures and kick tolerance. 4. Fluid parameters at the bit including; nozzle velocity, friction loss, viscosity and power

and force expended. 5. Equivalent circulating density. 6. The ability to suspend solids and the extent of gelation. 7. The extent of hole erosion.

13.2.1 Shear Stress (τ??) The dial deflection on any oil field viscometer provides an indication of the shear stress in a moving fluid. The term shear in a drilling fluid application means; the action or stress resulting from applied forces that causes two continuous or touching parts of a body to slide relatively to each other. Their direction is parallel to their plane of contact. The parts of a body in this definition refer to the layers of fluid sliding by one another in the case of laminar flow.


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Shear stress is considered the force required to sustain fluid flow. It is a measurement of force per unit area, Equation 13.1, Shear Stress: Shear stress = Force Area In colloidal suspension, shear stress may be considered either normal (perpendicular – top part of figure 13.2) stress or tangential (angled – bottom part) stress. The resultant units are the same as the units used in expressing pressure.

Figure 13.2. The force per unit area between moving layers in

Laminar flow is a Measurement of Shear Stress. In Figure 13.2, if a force of 10 dynes were applied to each square centimeter of the top plate to keep it moving, then the shear stress would be 10 dynes per cm2. (Note: a Newton meter is 10 dynes and 10 dynes / cm2 is a Pascal, the m kg s unit for pressure.) As the top plate slides by the bottom plate at a given velocity, a shear stress of similar magnitude is exerted on the bottom plate. Subsequent plates or layers would have similar stress relationships. The same shear stress would be found at any level in the fluid. This means the pressure is constant throughout the fluid. Shear stress is constant as long as the flow system geometry is constant. The units are pressure units! Drilling fluid shear stress measurements are small. Therefore the units used are multiples or sub-multiples of the normal units of pressure used on the rig. In Imperial units, pounds per 100 ft2 are used and in SI units Pascals are used.


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The stress in moving fluid systems originates when inter-molecular or inter-particulate bonds are broken. In most Newtonian fluids, such as water, there is only one level of bond (hydrogen bonded water) so there is a linear relationship between shear stress and motion. Shear stress varies with the velocity of the fluid. In shear thinning fluids, the relationship between motion and shear stress may be difficult to predict. If a drilling fluid produces a 300 RPM viscometer dial reading of 30, the 600 RPM dial reading is always less than 60. 13.2.2 Shear Rate (γ?)

Figure 13.3. In Laminar flow, the shear rate at any point is the slope of the velocity profile at that point.

Shear rate may be directly related to the speed at which a viscometer rotor turns. It is the velocity gradient, defined by the slope of the velocity profile at any given point on that profile - see Figure 13.3. In this context, the term velocity profile applies to laminar flow regimes.

Figure 13.4. Velocities between shearing layers. The velocity within each layer is the same. The space between the plates (Figure. 13.4) is filled with fluid. If the bottom plate moves to the left at 10 mm/s and the top plate slides parallel to it at a constant velocity of 100 mm/s, the fluid velocity may be found at any point within the fluid layer. Shear rate is a measurement of the rate at which one layer of fluid slides by another layer. This results in a velocity (v) gradient, ∆v. This measurement divided by the distance between the


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layers results in a unit of shear rate. A velocity gradient relationship must include units of time. Equation 13.2 shows how the final units of shear rate reciprocal seconds, are derived: Equation 13.2, Shear Rate:

Shear rate = γ = Dvd

Va = 100 mm/s Vb = 10 mm/s d = 1 mm

γ = va - vb

d

γ = (100 - 10) mm/s

1 mm

γ = 90

mms

1mm

γ = 90 1s

γ = 90 s-1

The reciprocal second is the standard unit of shear rate. It is the same for both the Imperial and SI unit systems. When using a Fann Viscometer, the rotor RPM value multiplied by 1.704 gives the shear rate in reciprocal seconds. 13.2.3. Viscosity ( µ ) Viscosity is the measurement of a fluid's thickness. It is the property of the fluid that enables it to develop and maintain an amount of shearing stress, which depends on the velocity of flow. A fluid must offer continued resistance to flow to remain viscous. As a drilling fluids term, viscosity is often synonymous with resistance to flow. The term viscosity may be defined mathematically as: The ratio of the tangential frictional force per unit area to the velocity gradient perpendicular to the direction of flow. This ratio may be expressed as, Equation 13.3, Viscosity: Viscosity = Shear stress Shear rate or,


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µ = ???τγ

This relationship enables certain predictions to be made about the fluid when it is in motion. For example, in a normal drilling fluid, a given shear stress is necessary to maintain a constant shear rate. In a thin fluid a much smaller shear stress is required to maintain the same shear rate:

µ =???τγ ∴ γ =???

τµ

Normal fluid

γ =???τµ , 4 =???

205

Thick fluid Thin fluid

4 =???6015 , 4 =???

82

Further, at equal values of shear stress, as the viscosity increases, the shear rate must decrease: τ? = γ • µ 20 = 5 •??4 20 = 2 •??10 In other words, if 20 is the maximum allowable pressure before the pop valve blows, and the shear rate (changes with velocity) is 5 then we can have a maximum viscosity of 4. If cement contamination is encountered and the viscosity increases to 20, then we must slow the pump down so that the shear rate is reduced to 2 or the pressure (shear stress) will exceed 20 and the pop valve will blow. The relationship between µ, τ? and γ is important in terms of velocity profiles and pressure regimes in drilling fluids. Since several units of measurement are used to denote shear stress values, the viscosity may also be reported in several units. Table 13.1 explains the derivations of these units.


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TABLE 13.1 Units of Shear Stress and Viscosity System Force Shear

Stress (Pressure)

Pressure Stress Unit

Fann Viscosimeter Spring constant

µ = tg

Viscosity Unit

Equivalents

m kg s

10 dynes

N•mcm2

Pascal (Pa) Base Unit

for pressure and yield

stress

.511

10 dynes/cm2

s-1

1 N•m2 = 10 dynes/cm2

c g s

1.0 dyne

dynecm2

dPa

5.11

dynes/cm2

s-1

Poise

Base Unit

1 dyne = 1 g•cm/s2

Imperial

0.01 dyne

0.01 dyne

cm2

mPa

511

0.01 dyne/cm2

s-1

Centipois

e (cps) Base Unit

1 cps = 1 mPa•s

(mPa•s is an alternate viscosity unit in SI)

Imperial

1.0 lb Force

1.0 lb F 100 ft2

Base Unit for Yield Stress

1.067

lb/100 ft2

s-1

1 lb/100 ft2 = .4788

Pa 1 lb/100 ft2 = 4.788

dyne/cm2 American 1.0 lb

Force 1.0 lb F

ft2

(.0069 Psi) 0.01067 lb/1.0 ft2

s-1 Reyn

Base Unit 1 Reyn = 14.88 Poise

The normal cgs unit of viscosity is the Poise. This is equal to the viscosity that would require a shearing force of 1 dyne to move 1 cm2 of either of two parallel layers 1 cm apart with a velocity of 1 cm/s relative to the other layer. This definition assumes the space between the layers is filled with fluid. Centipoise, or 0.01 x Poise, is a convenient viscosity unit, since the viscosity of water at room temperature is approximately one centipoise. The shear stress / shear rate curves given in Figure 13.5 can be re-plotted - as curves of viscosity, as a function of shear rate as shown in Figure 13.6. These curves show that the viscosity of Newtonian fluids is constant as shear rate changes. Drilling fluids exhibit a reduction in viscosity as the shear rate increases.


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Figure 13.5 Velocities between shearing layers. The velocity within each layer is the same.

Figure 13.6. Viscosity as a function of Shear Rate. 13.3 RHEOLOGICAL MEASUREMENTS Several methods are used for determining the rheological properties of drilling fluids. They range from quick field tests to fairly complicated laboratory analysis. The hole cleaning characteristics of


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drilling fluids are influenced by shear rates, shear stresses, pressure and temperature. Problem situations may necessitate an attempted simulation of all of these influences. 13.3.1 The Marsh Funnel The Marsh Funnel is a simple and reliable device that may be used to measure the consistency of the drilling fluid. It consists of a funnel of defined dimensions. A measurement is made of the time taken for 946 cm3 (a US quart) of fluid to flow through an aperture. The result of the test is given in seconds. The efflux time for fresh water at 21°C is 25 seconds. In some countries the cup is filled up to the 1-liter mark. The value is used to indicate changes in fluid flow properties. It provides no data on the shear thinning or gelation character of the fluid and there is no control on the temperature of measurement. Resistance to flow, time dependent structuring and density of the fluid influences the Marsh Funnel viscosity. 13.3.2. Direct Indicating Viscometers The most suitable instrument for measuring the rheological parameters of a drilling fluid is a concentric rotating sleeve and bob instrument called a viscometer. The essential elements are shown in Figure 13.7.

Figure 13.7 Direct Indicating Viscometer Rotation of the sleeve (or rotor) at a range of speeds simulates a range of shear rates in the annulus. The fluid layer in a Fann viscometer is 1 mm thick. It is assumed that this fluid moves at the same speed as the rotor or sleeve. In order for the bob to stay stationary, a torque is


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created on the spring. This torque is indicated by the deflection of the dial, which is calibrated in degrees. The symbol theta (θ) is commonly used to represent the dial deflection. θ 600 expresses the dial deflection reading, at a rotor speed of 600 RPM. The RPM of hand crank viscometers is maintained at a constant speed through the use of a slip-gear. All viscometers should be calibrated regularly. The instrument dimensions have been designed such that Bingham Plastic fluid model values are easily calculated from the dial deflection at rotor speeds of 600 and 300 RPM. The rotor constant for a Fann viscometer is 1.704. This means that the dimensions of the bob and rotor are such that the shear rate generated by a given RPM is calculated by: Shear rate (γ) in s-1 = RPM x 1.704 The shear stress value is a function of the strength of the spring. To obtain a value for shear stress in a desired unit of measurement, the value of the dial deflection may be multiplied as follows: Shear Stress Spring Constant N/m2 (Pascals) = θ x .511 dynes/cm2(dPa - obtain Poise) = θ x 5.11 0.01xdynes/cm2(mPa) = θ x 511 lb/100 ft2 = θ x 1.076 The base unit of viscosity in the cgs system is termed Poise. It represents a force of 1 dyne/cm2/s-1. When the spring constant 5.11 is used to calculate shear stress, the resultant viscosity is expressed in poise.

µ =???τγ =????

5.11q1.704RPM • ??

dyne/cm2

s-1 = Poise

When the spring constant 511.0 is used, the viscosity is expressed in centipoise. The shear stress divided by the shear rate is known as the apparent or effective viscosity. In an oil field viscometer, the shear stress at a 1° dial deflection is 1 x 5.11 or 5.11 dynes per cm2. The shear rate at 1 RPM is 1 x 1.704 S-1. Therefore:

µe ?=???τγ = ?

5.111.704 = 3 (poise/degree/RPM)

= 300 (cps/degree/RPM) Any rotating viscometer will indicate the effective viscosity of a fluid at any RPM in cps by, Equation 13.4, Effective Viscosity:

µe = 300 • ?θ

RPM = cps


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This expression describes the "effective viscosity" of a fluid as defined by Newton. Consider the following examples: θ?600 = 46 θ?300 = 38 a) µ at 300 RPM: b) µ at 600 RPM:

µe = 300 • ?θ300RPM µe = 300 • ?

θ600RPM

????? = 300 • ?38300 ?????= 300 • ?

θ600600

= 38 cps = θ600

2

= 462

= 23 cps The expression in example b above defines the apparent viscosity of a fluid, Equation 13.5, Apparent Viscosity:

µa = ?θ600

2 = cps

The apparent viscosity and effective viscosity are useful numbers for comparison purposes. For example, the value for the annular viscosity, explained later in this text is expressed in cps. Comparing it to the numerical value for effective or apparent viscosity may attain a feeling for the magnitude of this value in real terms. This may be done while visually observing the fluid adjacent to the rotor. This comparison along with the knowledge that the viscosity of water approaches 1 cps, aids in visualizing the fluid thickness in various annular intervals. 13.3.3 Brookfield Viscometers When operators began drilling large diameter (444.5 mm and 311.15 mm) deviated step out wells in the North Sea, hole-cleaning problems became more common when oil mud’s were used. The shear rate is small in large diameter holes because the velocity is low. Oil based mud’s behave differently than water based mud’s at the low shear rate ranges encountered in these holes. Their viscosity is lower at these rates. The problem is magnified in high angle wells since the cuttings bed that forms on the low side of the hole slides more readily when the cuttings are oily. In the early 1990’s operators and drilling fluid companies began to research methods of modifying low shear rate rheology in oil-based systems. TABLE 13.2 shows a sample of Brookfield Shear Rates using a LV+ #4 Spindle.


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TABLE 13.2 Sample of Brookfield Shear Rates

Shear Rate (Sec-1) Using Cylindrical Spindle LV+ #4 on Brookfield Model DV-II + Viscometer - independent of viscometer model, sample viscosity and temperature.

Speed (RPM) Shear Rate (Sec -1)

0.3 0.0627 0.5 0.1045 0.6 0.1254 1.0 0.2090 2.0 0.4180 5.0 1.0450

10.0 2.0900 20.0 4.1800 50.0 10.4500 100.0 20.9000

14.3.4 Other tools for measurement Several types of low temperature, low pressure, and concentric cylinder viscometers are available. The range of effective viscosity these are capable of measuring varies from 1 - 300 cps in simple hand-cranked models, to 1 – 300,000 cps in variable speed models. Portable viscometers are limited to fluid temperatures of 90°C. Two other accepted methods of measuring rheological properties are worth mentioning. A glass capillary viscometer is able to measure low shear rates and stresses. Power Law values may be calculated with this instrument. A shearometer tube is a similar instrument that is used to measure the gel strengths of a fluid that has been hot rolled. Measurement of rheological parameters at elevated temperature and pressure is a difficult engineering problem that has been solved by a number of instrument makers. The Huxley-Bertram Viscometer has a bob in a high-pressure cell that is driven with a magnetic coupling. The stress measurements are determined by a strain gauge immersed in the fluid. Also available are the Fann 50 viscometer (6 895 kPa, 260°C) and the OBI, BHC viscometer (137,000 kPa, 340°C). 13.4 FLUID MODELS Fluid models are essentially equations that describe the relationship of shear rate to shear stress, or shear rate to viscosity, in a fluid. These relationships may be plotted as a line on a graph called a consistency curve or flow curve. In this manner the viscosity of the fluid at various shear rates may be extrapolated. The viscosity at different shear rates may also be calculated. Rheological data may be shown on linear, log-log or semi-log graphs. It is preferable to show shear stress (τ) on the vertical axis. Values used on the (τ) axis may be expressed in dynes/cm2, lb/100 ft2, dial readings, or effective viscosity. Either shear rate as s-1 or RPM is usually indicated on the horizontal axis. Fluid models that have been used to define drilling fluid behavior include:


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1. Newtonian Model 2. Bingham Plastic Model 3. Power Law Model 4. Modified Power Law Model 5. Power Law with Yield Stress 6. Casson Model 7. Ellis Model The first 4 types are discussed in this document. 13.4.1 Newtonian Fluids A rheogram is a graph which plots shear rate against shear stress. The resultant consistency curve may be used to predict the fluid's behavior at a wide range of shear rates and stresses. Each fluid model has its own characteristic rheogram. Isaac Newton derived a flow model to describe the behavior of viscous fluids in motion. He stated: "The resistance which arises from the lack of slipperiness originating in a fluid, other things being equal, is proportional to the velocity by which the parts of the fluid are being separated from each other." This statement accurately describes the behavior of water, salt water, glycerin etc. In Newtonian fluids, the shear stress is directly proportional to the shear rate: τ ∝ γ When shear stress, τ is plotted against shear rate, γ, a straight line passing through the origin results as depicted in Figure 13.8. The steeper the slope, the thicker the fluid.

Figure 13.8. Newtonian Flow Curves.?


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The slope (rise / run) of the flow curve is the same at all shear rates, and is actually the viscosity of the fluid. Since the viscosity is constant over a wide range of shear rates, it is fairly easy to predict the behavior of Newtonian fluids at any given rate of shear, shown in Figure 13.9 and given by:

µ =?τγ ∴ τ = γ • µ

µ =??τγ =??

riserun =???

τ2-τ1

γ2-γ1

Figure 13.9. Calculating Newtonian Viscosity. In a Newtonian fluid the viscosity is constant (k), therefore:

µ = τγ ???or: τ = γ?•?µ

or: τ = γ?•?k Newtonian fluids are not normally used as drilling fluids. The flow curve passing through the origin indicates that little or no stress is required to initiate movement. Thus, Newtonian fluids have no definable yield point. Another major disadvantage is that the viscosity is constant. Thus, if the fluid is thick enough to suspend barite and cuttings, it might be too thick at the bit or while passing through solids equipment to perform properly.


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In an ideal drilling fluid, µ should decrease as γ increases. Drilling fluids should be shear thinning. The curve in Figure 13.6 shows that this is the case, since a tangent to any point on the curving line would show the fluid is thinning as the shear rate is increased. 13.4.2 The Bingham Plastic Fluid Model

Figure 13.10. Bingham plastic Rheogram.

E. C. Bingham first recognized plastic fluids in 1922. His fluid model was presented in a book entitled "Fluidity and Plasticity". This model has been used extensively to describe drilling fluids. It’s application projects only a moderately accurate indication of fluid behavior at the low annular shear rates which drilling fluids are subject to. However, the two outputs values, yield point and plastic viscosity, indicate the degree of contribution by various mechanisms to fluid behavior. These include drilled solids concentration and particle size, and the level and source of interactions between particles. These outputs values also indicate the ability of the fluid to carry and suspend solid particles. For this reason Bingham plastic fluid values have become the most accepted standard of measurement for drilling fluids. Most industry personnel relate yield point and plastic viscosity to certain conditions and behavior characteristics of drilling fluids. The composition of a non-Newtonian fluid affects the shear stress / shear rate relationship in the fluid. The particles in drilling fluid suspensions cause the suspension to behave approximately in accordance with Bingham's theory at higher shear rates. Bingham's theory states that a finite stress must be applied to initiate flow, and that at greater stresses the flow characteristics exhibit Newtonian behavior.


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Newton's model used only one (constant) value to describe the viscosity. Bingham's model is similar but it uses two values to describe thickness. Again the flow curve is a straight line when plotted on linear coordinates. The slope of the line denotes the viscosity in a manner similar to Newtonian viscosity. In Bingham plastic fluids this is called the plastic viscosity or PV. In Bingham's model the entire flow curve is shifted upwards indicating the point where an applied stress is of sufficient magnitude to initiate movement or flow. This value is termed the yield stress or yield point ( τy or YP ). Newtonian Bingham Plastic

µ?=?τγ =??

riserun = k τy = YP

τ? = k•γ ??τ?=? (k) • ?γ? + YP ??τ?=?YP + (k) • ?γ?

??k = ??riserun =?PV

Equation 13.6, The Bingham Plastic Fluid Model: τ = YP + (PV) ( γ ) An advantage of this model is that only two measurements or shear stress (?τ1 and τ2) at two defined shear rates (γ1 and γ2) must be made as shown in Figure 13.9. The mathematical analysis is easier if γ2 is twice γ1. τ1 and τ2 represent the dial deflection values on a Fann

viscometer, where the shear rates at γ1?and γ2 are 511 s-1 (300 RPM) and 1022 s -1 (600 RPM) respectively. The dimensions of the Fann viscometer have been designed such that the PV and YP values may be made mentally. Note that the yield point is actually a shear stress (or pressure) value and not a viscosity value: Equation 13.7, Plastic Viscosity: PV = θ600-???θ300?= mPa • s Equation 13.8, Yield Point: YP = θ?300 - PV = lb/100ft2

= 4.788 (θ?300 - PV) = dynes/cm2 (dPa)

= 0.4788?(θ?300 - PV) = Pascals (The unit used in some metric based countries) Generally:

YP = θ?300 - PV

2 = Pascals


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The Plastic Viscosity of a Bingham Plastic fluid may be exposed as a value that relates to: 1. The slope of the fluid's consistency curve 2. The viscosity at high shear rates 3. The concentration and size of suspended solids. Plotting γ with τ ?in a Bingham plastic fluid produces a straight line. The slope of the line is the plastic viscosity. Thus, the plastic viscosity indicates the rate of shear stress increase with shear rate increase.

Figure 13.11 Two Bingham Plastic fluids with similar yield points and dissimilar Plastic Viscosities. In Figure 13.11, fluid A has a higher PV than fluid B and therefore has a higher shear stress (τ2) than fluid B (τ1) at a given shear rate (γ1). This indicates that fluid A will require more energy (pump horsepower / pressure) to move it through the circulating system at a given velocity. This is an important consideration when choosing drilling rig components or designing hydraulic programs when oil-based fluids are required. These fluids characteristically exhibit a higher plastic viscosity in relation to yield point than do water-based fluids. Plastic viscosity is defined as it relates to shear rate. At the bit, where shear rates may approach 100,000 s-1 then:

µ? =?τγ =??

YPγ =

YP100 000 = 0

and:


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1, τ = YP+(PV•γ)

2, µ = τγ

1&2, µ = YP+(PV•γ)

γ

?= YPγ +

PV•γγ

? = 0 + PV µ = PV Thus, PV has been used as a numerical indication of a Bingham Plastic fluid's viscosity, in cps at very high shear rates. Plastic viscosity may also be defined as it relates to the concentration of, and the median average size of, solids in suspension. This relationship is evidenced when the PV decreases disproportionately less than the YP, when a deflocculant is added to a suspension. However, an increase in the solids concentration or a decrease in the average solids size is usually accompanied by a greater percentage increase in PV. In oil-based fluids the PV generally increases as the proportion of water is increased. The equation for Plastic Viscosity as it applies to drilling fluids measured with Fann viscometers is derived follows:

Figure 13.12 Derivision of Plastic Viscosity equation.

PV = riserun =

τ 600 - τ 300γ 600 - γ 300


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= 511 • q600 - 511 • θ300

1.7034 • 600 - 1.7034 • 300 τ = θ?• 511 (for cps)

= 511 (θ600 - θ300)

511 γ = RPM?• 1.704

= θ600 - θ300 = cps The yield point or yield stress of a Bingham plastic fluid may be expressed as a value that relates to: 1. The point where the consistency curve intersects the shear stress axis on a τ versus γ

graph. In other words, the amount of stress required to initiate movement in the fluid. 2. The degree of structure building due to particle associations in a suspension, relating to

the ability of a fluid to clean and suspend solids. The point where a Bingham plastic consistency curve intersects the shear stress axis is termed the yield stress or yield point. The value of this point is expressed in shear stress units, similar to pressure. Viscosity units cannot be derived since there is no shear rate along this axis. The yield point increases much more rapidly with relation to the plastic viscosity when viscosifying clays or polymers are added to a suspension. The disproportional increase also applies when salts are introduced and the suspension is flocculated. Thus, the yield point is a good indication of the degree of structure building, due to particle associations in the suspension. An increasing degree of structure contributes to a greater initial resistance to flow - measured in force per unit area. Therefore the value of yield stress is sometimes related to a fluid's ability to carry and suspend solids - even though it is not a viscosity measurement. When particle associations are electro-chemically degraded, or deflocculated, the yield point decreases more rapidly in relation to the plastic viscosity. Thus the yield point may be thought of as a value representing the type of relationships colloidal particles have, whereas the plastic viscosity represents the number and size of particles in suspension.


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Figure 13.13 The effect of internal structure on the Bingham Plastic rheogram.

Figure 13.13 attempts to show that the larger degree of particulate structure in fluid A contributes to: 1. More initial resistance to flow 2. Higher yield point 3. Better carrying capacity 4. Better suspension qualities 5. Reduced energy expenditure at higher shear rates. This Figure also expresses the limitations of using apparent viscosity alone to provide an accurate indication of flow properties.


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The value of yield stress is expressed in pressure units, helping to indicate the degree of structure building in a suspension. However, the value of YP is not an efficient means of predicting circulating system pressure losses or the pressure required to re-establish circulation. This is because true plastic flow is never observed in practice. At shear stresses below the yield point, a slow plug flow is always observed.

Figure 13.13 The Bingham Plastic model compared to a typical Drilling Fluid plotted on linear coordinates. Using a glass capillary viscometer, H. Green observed plug flow through a microscope at pressures below the yield point. He was able to conclude that there was no absolute yield point in Bingham Plastic fluids. Thus a true YP is indeterminable. This behavior may be more easily understood if the consistency curve of a typical drilling fluid is compared to the Bingham Plastic curve in Figure 13.5. It can be seen that Bingham's equation would predict higher than actual annular shear stresses at low annular shear rates. Hence, the term Bingham yield point has been defined as the shear stress required to initiate laminar flow in a colloidal suspension. This value may be close to 75% of the calculated yield point. It is seldom used in a field application partly because plug flow can co-exist with laminar flow in Bingham Plastic fluids flowing through round pipes. The equation for yield stress as it applies to drilling fluids measured with Fann viscometers is derived as follows:


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Figure 13.14 Derivision of yield stress as it applies to drilling fluids measured with Fann viscometers. 1. x = τ300 - (τ600 - τ300) 2. τ = .511θ (to obtain pa) 3. YP = .511θ300 - (.511θ600 -.511θ300) = .511θ300 - .511(θ600 - θ300) ( )θ600 - θ300 = PV = .511θ300 - .511PV = .511 (θ300 - PV)

= θ300 - PV

2 = Pa

or: 1lb/100ft2 = .4788Pa

YP = .511 (θ300 - PV)

.4788

= 1.067 (θ300 - PV)

= θ300 - PV = lb/100ft2


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Once the YP and PV values have been determined, the Bingham Plastic equation, τ = YP + (PV) ( γ?) may be used to determine a shear stress value for any given shear rate. Also, the ratio of YP : PV is an accepted method of discerning the degree of shear thinning character a given fluid retains. The higher the ratio the thinner the fluid becomes as the shear rate is increased. The actual behavior of most drilling fluids, when subjected to shear rates below 511 s-1 is indicated by the line as it curves downward in Figure 13.13. Thus the assumption of Bingham Plastic (linear) behavior at low shear rates becomes less valid as the shear rate decreases. 13.4.3 The Power Law Fluid Model

Figure 13.15 The Power Law Rheogram.

Most drilling fluids may be defined as pseudoplastic. That is, when γ is plotted with τ using liner coordinates, the consistency curve slopes or curves toward the origin. At higher shear rates the curve approaches linearity. When a line is extrapolated from the linear portion to intersect the shear stress axis, the point of intersection is termed the pseudo yield point - hence the term pseudoplastic. In terms of linear coordinates, the power low fluid model is the most accurate means of predicting the behavior of pseudoplastic fluids in laminar flow regimes. Note the similarities of the two curves in Figure 13.5. An ideal Power Law fluid, when plotted as τ versus γ? using log-log coordinates produces a straight line as in Figure 13.16. The value, n, represents the slope of the line. K is the intercept at the shear stress axis when γ = 1s-1. The equation for the Power Law consistency curve is written: Equation 13.9, The Power Law Fluid Model: τ =??K • γ?n


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Figure 13.16 The consistency curve of an ideal Power Law Fluid, plotted Logarithmically.

The power law expression may be compared to a logarithmically expressed Newtonian equation:1 ( τ = K γ?n ) Power Law: log τ = log K + n log γ Newtonian: log τ = log µ + n log γ (?τ = µ γ ) The difference in equations is the value of the slope, n. The power law may also be compared to the Bingham plastic equation:

Intercept: Slope:

Power Law: log τ = log K + n log γ Bingham Plastic: τ = YP + PV γ Both models use two values to describe thickness. The Power Law is a superior fluid model for defining both the thickness at realistic shear rates and the shear thinning characteristics of a fluid. The use of Power Law values is preferred in equations that predict fluid behavior in the annulus. The values for n and K may be calculated with any 2-speed Fann viscometer. The derivations of the equations are shown in Figure 7.17.


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n = slope K = τ?when γ?= 1s-1

n =

riserun

τ = K γ n

=

log θ600 - log θ300log 1022 - log 511

K =

τγn

= log θ600 - log θ300

.301

Spring Constant:

= 3.32 (log θ600 - log θ300)

K = θ600

1022n x

5.11

=dyne/cm2

s-1

Equation 7.10:

n = 3.32 log θ600θ300

Equation 7.11:

K = θ300511n x

5.11

= dyne•s/cm2

Shear stress units cancel - leaving n dimensionless

K = θ600

1022n x

1.067

=lb/100ft2

s-1

Equation 7.11b:

K = θ300511n x

1.067

= lb•s/100ft2


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n is probably the single most qualitative rheological parameter. Sometimes termed the shear-thinning index, it accurately indicates the degree of shear thinning character a given fluid retains. In shear thinning fluids n is always less than 1.

Figure 13.18 Different values of n.

In shear thinning fluids, when the value of n decreases, it indicates that the shear thinning character has increased. The significance of the value of n is realized when one observes how it decreases with the addition of clays or polymers. n also decreases as the number or degree of particle associations increase in a suspension. This is especially true when a system becomes flocculated. Conversely, as the concentration of effectively inert solids increases, or their median average particle size decreases, the n value goes up. This is also the case when deflocculants are added to any water-based fluid. The value of n also increases as the percent water is increased in oil-based fluids. This is why the brine phase is sometimes described as "acting like a solid". The relationship of the value of n to the shear thinning character of a drilling fluid may be explained thus: IF, 1 τ = Kγ n

AND, 2 µ = τ γ

THEN, 1 + 2 µ = K • γ n

γ or K • γ n

γ 1 or K • γ?n • γ?-1 finally: K • γ?(n-1)

AND,


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Equation 13.12, Power Law Viscosity: µe = K γ?(n-1)

µe = K γ?(n-1)

EXAMPLE: IF, n = .4 THEN, n -1 = -0.6 AND, γ (n-1) = γ -0.6

OR, = 1

γ 0.6 Here as γ increases the denominator increases, decreasing

the value of the whole number. For shear thinning fluids, n is less than 1 therefore n-1 is less than 0. That’s why γ n-1 decreases as shear rate increases.

AGAIN, µ = K γ n-1 γ n-1 Decreases at higher γ decreasing the value of µ??? AND, ∴ µ Decreases at higher γ In round pipes, the velocity profile of both Pseudoplastic fluids and Bingham plastic fluids has a central flattish area. In Bingham Plastic fluids this is due to un-sheared or plug flow behavior. In Power Law Fluids it occurs because the local shear rate decreases towards the center of the pipe. Since the shear stress remains constant throughout, the local viscosity increases.


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Figure 13.19 Bingham Plastic and Pseudoplastic Flow Profiles. The value of n may be used to predict the velocity profile of pseudoplastic fluids with Metzners2 equation:

v V =

1+3n1+n

1-

rR

n+1n

Where v is the velocity at radius r, V is the mean velocity and R is the pipe radius. Figure 13.20 shows velocity profiles for several values of n, calculated from the above equation. The average velocity is 5 ft/s in all cases. Velocity profiles are discussed in greater detail later in this chapter.


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Figure 13.20 Velocity profiles at different n values .(From Metzner)

K is a proper viscosity term which is defined as the ?τ intercept of the power law flow curve when γ = 1 s-1. K is numerically equal to τ at this point. This may be expressed on a log-log graph, as in Figure 13.16, or arithmetically by: ?τ = K γ?n WHEN: γ = 1 s-1 THEN: γ?n = 1 (1 to the power of anything is 1) ∴ τ =?K • 1 τ =?K Therefore, if equation 13.11 results in a value of 5 dyne • s/cm2, or 5 poise - see table 13.1, the shear stress value at 1 s-1 is 5 dyne /cm2 or 0.5 Pascals. The Pascal is the API approved, and industry accepted unit for K - Bulletin 13D, equation 5.19. If operators require that K be reported in mPa • s - numerically the same as centipoise and a better unit for comparison purposes, then the spring constant 511 must be used in equation 13.11. Equation 13.12 shows that the denominator, a shear rate unit ( s-1 ) is raised to a dimensionless power, leaving only a shear rate value, netting a viscosity value, dyne • s/cm2.


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The value of K may be related to the viscosity in Newtonian fluids, where n = 1, by: IF: n = 1 THEN: τ = K γ 1 AND: τ = K γ

THEN: K = τ γ = µ

Since the value of K represents the viscosity at low shear rates, it is a better unit than YP for gauging the suspension capabilities of a drilling fluid. Recall that YP is merely a measurement of shear stress. When suspended solids slip through a shear thinning fluid, they create their own shear regime around them as they fall. This is termed the particle shear rate - discussed later in the chapter. The particle shear rate is in the same order of magnitude as 1 s-1. Figure 13.21 shows how a higher value for K applies at this shear rate.

Figure 13.21 Particle suspension ability as indicated by K.

Power Law values provide the best representation of drilling fluid behavior. However, the use of YP and PV has become so common in field operations it is difficult to change. YP and PV values are often used as treating mechanisms, indicating a need for chemical additions, solids control or dilution. n and K values are most often used for quantitative calculations concerning pressure losses and carrying capacity.3 Other fluid models are also used to predict drilling fluid behavior. The Power Law with Yield Stress is worth mentioning since the reader should now be equipped to relate to it. It is expressed as: τ =?τy + K γ n


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Note that in this model, three terms are used to express thickness. Graphed using linear coordinates the consistency curve is shown in Figure 13.22

Figure 13.22 The Power Law with Yield Stress Rheogram.

13.5 ANNULAR RHEOLOGY Substantial research has been conducted in an attempt to aid in applying rheological measurements to the dynamic conditions found in the wellbore. A better understanding of fluid behavior aids in improving hole-cleaning efficiency, optimizing bit hydraulics and penetration rates, and in reducing pressure losses and induced stresses on the formation. Variations in shear rate, temperature and pressure all affect the rheological properties in the annulus. One method of discerning annular properties is to use a log - log plot of shear rate versus viscosity, called a Rheo-plot. Once a log-log consistency curve is drawn, an approximation of the effective viscosity at any point in the circulating system may be found. Mathematical equations also attempt to predict down-hole fluid behavior such as viscosity, shear rate or friction loss. Inevitably these methods fall somewhat short of actual values. This is unavoidable since several input values including particle size, hole geometry and pipe smoothness are difficult to quantify. In terms of hole cleaning, and pressure losses, if values are attained from equations, parameters such as flow rates or fluid properties may be optimized prior to drilling. The HyCalc hydraulics software program allows for instantaneous evaluation of the effect that changing any input parameter may have on all annular properties at any point in the annulus.


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13.5.1. The Modified Power Law The Power Law is an equation that describes a straight line on a log-log graph. When drilling fluid values are input on a log-log graph of shear rate versus shear stress, the line is not always straight. Thus, the value of n, the slope, may vary at various points on the line causing the value for K to also be inaccurate. Hence, n and K values might not predict exact fluid behavior during different shear regimes. The modified Power Law derives values for n and K at shear rates that approach annular shear rates. Power Law values obtained from low shear rate measurements may provide more accurate input into annular pressure loss and annular viscosity equations. When using a two-speed viscometer, API Bulletin 13D recommends using 600 RPM and 300 RPM values when calculating n for use in pipe pressure loss calculations. The 300 RPM and 3 RPM (or initial gel strength) are used when calculating n for use in annular pressure loss calculations. When a multi-speed viscometer is used, n and K may be calculated from any two shear rate - shear stress pairs. API Bulletin 13 D recommends that annular calculations be made with n and K values calculated from shear rates ranging from 10 s-1 to 200 s-1. These are called na and

Ka. Pipe calculations may be made with n and K values (np, Kp) obtained in the 200 s-1 to 1000

s-1 range.

Equation 13.2 described shear rate as ∆vd . When a fluid is moving in an annulus, the velocity

expression becomes the actual annular velocity. Annular velocity may be expressed as: Equation 13.13, Average Velocity in the Annulus:

SI UNITS: va = 1273000 • Q

Dh2 - Dp2 = m/min

BASIC: va = 1273000 ? Q / (Dh^

2 - Dp^2) = m/min

WHERE: Q = Pump Output (m3/min) Dh = Hole Diameter (mm) Dp = Pipe Diameter (mm)

IMPERIAL UNITS: va = 1030 • QDh2 - Dp2

= ft/min

WHERE: Q = Pump Output (bbl/min) Dh = Hole Diameter (inches) Dp = Pipe Diameter (inches) The equation for the velocity inside the drill pipe is included here for comparison purposes. It is used in pressure loss calculations:


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Equation 13.14, Average Velocity in the Drill Pipe:

SI UNITS: vp = 1273000 • Q

IDp2 = m/min

BASIC: vp = 1273000 ? Q / IDp^2 WHERE: Q = Pump Output (m3/min) IDp = Inside Diameter of Pipe (mm) IMPERIAL UNITS: Substitute as the constant 1030, as in Equation 13.13 Darley and Gray4 suggest determining the annular shear rate at the pipe wall by:

γw =

2n+1

3n •

12va

Dh-Dp

WHERE: va = Annular Velocity (ft/s) Dh/Dp = Diameter Hole/Pipe (ft) Once the shear rate in the annulus is known, na and Ka may then be determined by using viscometer values at the appropriate shear rate range. Darley and Gray use 100 RPM and 6 RPM in their example. Actually any two appropriate values can be used. The two extreme values for γw can be found by calculating γw at the largest and smallest annular areas.

The shear thinning expression

2n+1

3n is used in several annular rheology equations to

compensate for the pseudoplastic nature of non-Newtonian fluids. In API Bulletin 13D, the shear thinning expression is omitted from the annular shear rate equation. The constant has been changed to allow for more realistic input units:

γw = 144•va Dh-Dp

WHERE: va = Annular Velocity (ft/s) Dh/Dp = Diameter Hole/Pipe (ft) If the velocity is expressed in ft/min, the constant becomes 2.4. The examples above illustrate that different versions of the γw equation exist. Their constants depend on the input units and measurement system used. API Bulletin 13D recommends converting all data to consistent SI units before making calculations. The results should then be converted back to the desired units. Darley and Gray suggest; "This procedure is to be recommended because it simplifies the calculations and lessens the possibility of mistakes". Ava uses the following expression to obtain a value for shear rate at the annular wall: Equation 13.15, Shear Rate at the Annular Wall:


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SI UNITS: γ wa =

2n+1

3n •

200 • va

Dh-Dp = s-1

OR: BASIC: γ wa = (2 • n + 1) / (3 • n) • (200 • va) / (Dh - Dp) = s-1

WHERE: va = Annular Velocity (m/min) Dh/Dp = Diameter Hole/Pipe (mm)

IMPERIAL UNITS: γ wa =

2n+1

3n •

2.4 • va

Dh-Dp = s-1

WHERE: va = Annular Velocity (ft/min) Dh/Dp = Diameter Hole/Pipe (inches) This shear rate calculated at the annular areas of interest provides an insight into the viscometer shear rates which na and Ka should be calculated at. na and Ka may then be input into annular pressure loss or viscosity equations. The modified Power Law equations are: Equation 13.16, The Modified Power Law Shear Thinning Index:

ALGEBRAIC: n' =

1

LOG γhigh - LOG γlow • LOG

θ high

θ low

BASIC: n' = 1 / (Log (γ high) - Log (γ low))*Log (θ high / θ low) Equation 13.17, The Modified Power Law Consistency Index:

ALGEBRAIC: K' = θhigh

γ highn • 5.11 = Poise

BASIC: K' = θhigh / (γ high ^n) * 5.11 = Poise

IMPERIAL: K' = θhigh

γ highn • 1.067 = lb • s/100 ft2

Whenever n is calculated at shear rates where the higher shear rate is twice the value of the lower shear rate, the constant 3.32 may be used in equation 13.16 Where the higher shear rate is not twice the value of the lower shear rate the constant must be calculated by:

1

LOG γhigh - LOG γlow


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The HyCalc hydraulics calculator calculates and compares all viscometer and annular shear rates. The user chooses the appropriate viscometer RPM and dial readings to obtain Modified Power law results. 13.5.2 Annular Shear Rate (γwa) For Newtonian fluids, the general equation for the average annular shear rate may be written as:

γ wa =

200•va

Dh-Dp = s-1

va = Annular Velocity (m/min) Dh/Dp = Diameter Hole/Pipe (mm) A Non-Newtonian or shear thinning fluid is influenced by velocity. Non-Newtonian fluids become thinner as their velocity increases. Therefore, n is a factor - and the equation is modified by:

2n+1

3n

This expression is sometimes called the shear thinning expression. Figure 13.18 described how shear-thinning fluids always have an n value of less than 1, while Newtonian fluids have an n value equal to 1.

In Newtonian fluids: n = 1 and

2n+1

3n = 1

In shear thinning fluids: n < 1 and

2n+1

3n > 1

This may more than double the value of the annular shear rate. The average annular shear rate or nominal shear5,6 rate - as a Modified Power Law value may expressed by: Equation 13.18, Shear Rate at the Annular Wall:

SI UNITS: γ?'wa =

2na+1

3na •

200 • va

Dh-Dp = s-1

BASIC: γ?'wa = (2*na + 1) / (3*na) • (200*va) / (Dh-Dp)= Sec-1

WHERE: va = Annular Velocity (m/min) Dh-Dp = Diameter Hole/Pipe (mm)

IMPERIAL UNITS: γ 'wa =

2na+1

3na •

2.4 • va

Dh-Dp = s-1

WHERE: va = Annular Velocity (ft/min)


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Dh-Dp = Diameter Hole/Pipe (inches) This is the same expression as equation 13.15 but may incorporate the modified Power Law, na value. Various authorities use different denotations and constants for this expression after the following fashion: Authority: Darley/Gray API P.L. Morre Kelco Name: γ at wall γ at wall γann(average) γann(average) Constant: 12 144 2.4 2.4 unit of velocity: ft/s ft/s ft/min ft/min unit of diameter: ft inches inches inches use of shear thinning yes no yes no correction factor: In all cases, the resultant value is the same if the shear-thinning factor is included and the units are input properly. As a fluid becomes more shear thinning, the annular shear rate at a given velocity increases: If: va = 40 m/min Dh = 216 mm Dp = 127 mm When: n = .75, γ = 100 s-1 n = .50, γ = 120 s-1 n = .25 γ = 180 s-1 Almost all of the subsequent cleaning and pressure loss equations in this chapter incorporate and depend on the value of the annular shear rate. Drilling Fluid Engineers should be aware that the annular shear regime is influenced by the rotation and reciprocation of the drill string. The equation for the shear rate at the drill pipe (inside) wall is given below.7 Note that the constant has changed, as has the shear thinning expression. Although it is possible to use modified power law values in the shear thinning expression, most authorities including API do not. The shear rates inside the pipe are a close enough approximation of those at 600 RPM and 300 RPM in the Fann viscometer. Equation 13.19, Shear Rate at the (inside) Pipe Wall:

SI UNITS: γ wp =

3n+1

4n •

133•vp

IDp = s-1

BASIC: γ wp

= (3 ? n + 1) / (4 ? n) ? (133 ? vp / IDp) = S-1


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WHERE: vp = Average Bulk Velocity in Pipe (m/min) IDp = Inside Diameter of Pipe (mm)

IMPERIAL UNITS: γ wp =

3n+1

4n •

1.6•vp

IDp = s-1

WHERE: vp = Average Bulk Velocity in Pipe (ft/min) IDp = Inside Diameter of Pipe (inches) 13.5.3 Annular Viscosity (µ e a ?)

The value of γ'wa , shear rate at the annular wall is an important input into annular pressure loss

equations. It may also be used to calculate a close approximation of the effective viscosity in the annulus in both Bingham Plastic and Power Law fluids by: Bingham Plastic: 1. τ = YP + (PV) γ'wa

2. µ = τ γ

1 + 2. µea = YP + (PV) γ'wa

γ'wa

Power Law: 1. τ = K (γ'wa )n

2. µ = τ γ

1 + 2. µea = K(γ'wa)n

γ'wa

API Bulletin 13D recommends using the annular shear rate value expressed by equation 13.15 on a shear rate / viscosity Rheo Plot to determine the annular viscosity. This method works well. The annular shear stress may also be calculated for Power Law fluids. Equation 13.20, Shear Stress at the Annular Wall:

IF: γ wa =

200 va

Dh - Dp •

2n+1

3n = s-1


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AND: τ = Kγ?n

SI UNITS: τwa = K

200 va

Dh - Dp •

2n+1

3n n

= dynes/cm2

BASIC: γ wa = K ? ((200 ? va) / (Dh - Dp) ? (2 ? n + 1) / (3 ? n)) ^n

WHERE: va = Annular Velocity (m/min) Dh/Dp = Diameter Hole/Pipe (mm) K = Consistency Index (Poise)

IMPERIAL UNITS: τwa = K

2.4 va

Dh - Dp •

2n+1

3n n

= dynes/cm2

WHERE: va = Annular Velocity (ft/min) Dh/Dp = Diameter Hole/Pipe (inches)

K = Consistency Index (lb/100ft2) Since the values for annular shear rate (equation 13.15) and annular shear stress (equation 13.20) may be calculated, an even closer approximation annular viscosity may be calculated by:

µa = τa γa =

equation 14.15 equation 14.20 = Poise

or:

µa =

K

200 va

Dh - Dp •

2n+1

3n n

200 va

Dh - Dp

= Poise

Note: the shear thinning expression

2n+1

3n has been omitted from the denominator. This can

create difficulties in subsequent calculations. In SI units the equation may be expressed as: Equation 13.21, Annular Viscosity after Moore:

SI UNITS: µea =

200 • Va

Dh-Dp •

2n+1

3n

n •

0.5K( )Dh-DpVa

= mPa•s

BASIC: µea = (((200?Va/(Dh-Dp)) ? (2?n+1)/(3?n))^n) ? (0.5?K?(Dh-Dp)/Va) = mPa•s WHERE: Va = Annular Velocity (m/min)


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Dh/Dp = Diameter Hole/Pipe (mm) K = Consistency Index (Poise) The constant 0.5 above, is the inverse of the constant 200 in the denominator of the previous annular viscosity equation, multiplied by 100 to convert the input value K, expressed in poise, to the resultant mPa•s. IMPERIAL UNITS:

µea =

2.4 • Va

Dh-Dp •

2n+1

3n

n •

200K( )Dh-DpVa

= cps

WHERE: Va = Annular Velocity (ft/min) Dh/Dp = Diameter Hole/Pipe (inches)

K = Consistency Index (lb/100ft2) Although equation 13.21 is accepted by Moore and others, it is difficult to check the answer by:

?µa = τa γa

for example,if: Va = 40 m/min Dh = 216 mm Dp = 127 mm n = .75 K = Poise then: τwa (from equation 13.20 ) = 158 Dynes/cm2

γwa (from equation 13.15 ) = 100 s.

µea should = 1.58 poise or 158 cps

but, using equation 13.21 results in 175 cps This is because the shear thinning correction expression was omitted from the denominator, or the annular shear rate expression. Ava's Hydraulics software use a form of equation 13.12 to obtain an annular viscosity value γ in equation 13.12 is substituted with γwa .

Equation 13.22, Effective Annular Viscosity using Modified Power Law Inputs:

SI UNITS: µ'ea = 100 K' γwa ( )n'a - 1 = mPa • s

BASIC: µ'

ea = K' ? γwa ^ (n'a - 1) ? 100 = mPa • s

WHERE: K' = Consistency Index (Poise)


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γwa = Shear Rate at Annular Wall (s-1)

IMPERIAL UNITS: µ'ea = 478 K' γwa ( )n'a - 1 = cps

WHERE: K' = Consistency Index (lb/100ft2) γwa = Shear Rate at Annular Wall (s-1)

NOTE: If K was calculated in Imperial units, but the constant 1.067 in Equation 13.11b

was omitted, the constant in Equation 13.22 (Imperial units) becomes 511. Where applicable, modified Power Law values should be input into equation 13.22. API uses the 300 RPM and 3 RPM viscometer readings, but others use 100 and 6 RPM. The Ava Hydraulics calculator lists all of the annular shear rates as determined from equation 13.15. The user may pick any 2-viscometer shear rates that most closely approximate the prevailing annular shear rates. An even greater degree of accuracy is attained when a variable speed viscometer is used. Then the shear rates can be exactly matched. The derivation for equation 13.22 is apparent in equation 13.12. When the values from the previous example are used in equation 13.22 the result is 158 cps. Thus, the equation allows for easier cross-referencing. The τwa expression is entirely omitted from equation 13.22 - making it shorter and easier to input into a computer program. Equation 13.22 does not require the use of a multi-speed viscometer, whereas both Rheo plots and other equations do, including Moore's equation 18 on page 107 of his book. (If Moore had not omitted the shear thinning expression from his equation 13, his answer would have been 110 cps instead of 132.5 cps in his example 8 on page 109 - in essence nullifying his argument). Annular viscosity, µea , is an input value in lifting capacity and other hydraulic equations. It is a

good tool for comparing the effect of various influences on annular properties. Example 1 below shows that, although the yield point, annular velocity and geometry remain constant, notably different values for µea may exist. Example 2 shows the effect of annular velocity alone on

annular viscosity. Example 1: Where: Dh = 216 mm Dp = 127 mm va = 40 m/min When: θ600 = 26 θ600 = 90 θ300 = 23 θ300 = 55 YP = 10 Pa YP = 10 Pa µea = 44 cps µea = 88 cps

Example 2: Where: Dh = 216 mm Dp = 127 mm


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θ600 = 30 θ300 = 25 YP = 10 Pa When: va = 60 m/min va = 20 m/min µea = 41 cps µea = 92 cps

The equation for viscosity inside the drill pipe is included here for comparison purposes. The only difference between it and equation 13.22 is that Modified Power Law values are not required. The viscometer shear rates at 600 RPM and 300 RPM are a close enough approximation of drill pipe shear rates. Equation 13.23 is used in pressure loss calculations. Equation 13.23, Effective Viscosity Inside Drill Pipe:

SI UNITS: µep = 100 K γwp ( )n - 1 = mPa • s

BASIC: µep = K ? γwp ^ (n - 1) ? 100 = mPa • s

WHERE: K = Consistency Index (Poise) γwp = Shear Rate at pipe Wall (s-1)

IMPERIAL UNITS: µep = 478 K γwp ( )n - 1 = cps

WHERE: K = Consistency Index (lb/100ft2) γwp = Shear Rate at pipe Wall (s-1)

NOTE: If K was calculated in Imperial units, but the constant 1.067 in Equation 13.11b

was omitted, the constant in Equation 13.22 (Imperial units) becomes 511. 13.6 THIXOTROPY When a colloidal suspension is at rest, the tendency for particles to align themselves to positions of minimum free energy is termed gelation. This subject is discussed in the Clay Chemistry Chapter. A fluid exhibiting gelation or structure building characteristics may be termed thixotropic. After a period of rest of thixotropic fluid will not flow until a stress applied to the fluid becomes greater than the strength of the gel structure. At this point the gel strength is numerically equal to the yield stress. Both are measured in Pascals or lb/100 ft2. In most thixotropic fluids, the stress or pressure necessary to maintain movement decreases with time. This is because the resistance to flow or viscosity decreases with time, as particle associations are mechanically degraded. At a constant rate of shear, eventually a balance point is reached. Here, the structure building forces are in equilibrium with the disrupting forces. The viscosity at this given rate of shear stays constant. If the rate of shear is changed, time will be expended until a new equilibrium viscosity, typical of the new shear rate is attained. Thus, the viscosity of a thixotropic fluid is time dependent as well as shear dependant. The term thixotropy describes, not only the degree of structure building over time, but also the time


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required to reach a new constant viscosity when the shear rate is changed. The proper definition of the term thixotropy may be expressed as: A reversible isothermal change in viscosity with time, at a constant rate of shear. Most drilling people are concerned with the first part of the definition of thixotropy. That is, the degree of structure building characteristics a fluid retains. Figure 13.23 depicts some possible curves that can result when plotting gel strengths with time. The nomenclature is useful but by no means "official". This Figure demonstrates the relationship between particle associations in a suspension and the fluid properties used to diagnose them, as described in the Chapter 4.

Figure 13.23 Characterization of Gel Structure. Gel strengths are measured in shear stress units or units of pressure: τ = θ3 • .511 = Pa or τ = θ3 • 1.067 = lb/100 ft2 Unfortunately a direct correlation cannot be made from the gel strength value to the pump pressure required to re-establish circulation after long periods of rest. Even when bottom hole temperatures are used for measurement, the usual rest period allowed between laboratory measurements is only 10 minutes. Studies have indicated that real drilling fluids may take up to


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12 hours before maximum gelation is reached. Figure 13.24 illustrates that two fluids with similar 10-minute gel strength values, may be entirely dissimilar after longer periods of time.

Figure 13.24 Two fluids with the same 10 minute gel strength, having markedly dissimilar gel strengths after 10 hours. Equations designed to predict long-term gel strength values have had limited success. Prior to logging or testing a common and useful practice is to measure gel strengths after an extended period. If high testing temperatures and evaporation pose a problem, a thin layer of oil may be applied to the top of the sample. The most accurate method of predicting long-term gelation characteristics involves recording the gel strength value at 3 points in time. These are usually 10 seconds, 10 minutes and 30 minutes. The sample should always be sheared at 600 RPM until the original apparent viscosity is established, prior to each rest period. Once these values are known a curve may be plotted on a log paper. A better approximation of a fluid's characteristic after long rest periods may be extrapolated as an extension of this curve. Equation 13.24, Pump Pressure Required to Initiate Circulation:

P = gx • S • K

a

WHERE: P = Pump pressure required to break circulation (KPa) K = Correction constant gx = Predicted Gel strength (Pa)


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S = Contact surface (cm2) a = Cross sectional area (cm2) The constant K corrects for empirical input data such as hole gauge, pipe smoothness etc. The output value in this exercise is beneficial in intervals with low formation integrity. In close to balance situations, circulation should be established slowly. The following points should be considered when supervising drilling fluid systems that exhibit thixotropic properties: 1. During measurement equilibrium viscosity should be established at each shear rate,

before recording stress values. 2. Samples should be sheared to a stress value that approximates the original equilibrium

600 RPM value, prior to resting for the 10 minute gel strength interval. 3. A laboratory should attempt to re-establish the equilibrium viscosity of a field sample,

prior to recording rheological properties. 4. The thixotropic nature of drilling fluids can adversely affect pressure loss and cleaning

calculations. After being subjected to bit shear rates of 100,000 s-1, a fluid may not have time to establish equilibrium viscosity in any given annular interval.

5. Flat gels, similar values for 10 second and 10-minute readings, are preferred over

progressive gels. It is generally accepted that fluids with flat gels establish structure in the annulus in a timelier manner.

6. Excessive gel strength values increase the surge and swab pressures induced when pipe

is reciprocated. Therefore, the gel strength values should not be higher than those necessary to suspend solids when circulation is stopped.

7. When gel strengths are excessive, breaking circulation at kill speed will reduce the

chances of fracturing exposed formations. Rotating the pipe prior to starting the pump may reduce the pressure required to establish circulation.

13.7 THE EFFECTS OF TEMPERATURE AND PRESSURE Drilling fluids are often expected to perform under extremely adverse conditions. Pressures at T.D. may be as high as 130,000 kPa, where temperatures as high as 300°C may exist. The viscosity of a drilling fluid may be quite different down hole than it appears at surface. Usually it is thinner but it may also be thicker. A product that reduces the viscosity at surface may actually increase it down hole.


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Figure 13.25 The viscosity of water as a function of temperature. In physical terms, an increase in temperature decreases the viscosity of the liquid phase. Figure 13.25 shows the viscosity of water as a function of temperature. In chemical terms, the reaction of hydroxides with clays begins at about 100°C. In highly alkaline fluids, the reaction may cause severe flocculation. As the temperature increases, electrochemical effects may also be seen. Entrained salts solubilize more readily. These salts alter the existing balance between both the CEC of the clays and the ionic equilibrium of the suspension. Any resultant changes in colloidal particle associations are usually manifested as rheological changes. Elevated temperatures also excel the degradation of the polymers that contribute to rheological properties. High pressure can force the components of the fluid closer together increasing the degree of interactions between colloidal particles, increasing the viscosity. The effect of pressure is minimal for water-based fluids as water is essentially incompressible, however, the effect is significant for oil based fluids. The viscosity of given base oils may be measured and plotted at various temperatures under pressure in the laboratory. Correction factors may then be applied to calculate annular viscosity values obtained from measurements made at the rig.


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13.8 VELOCITY PROFILES Velocity profiles have been discussed previously in this chapter. In laminar flow regimes a velocity profile in the annulus peaks somewhere between the pipe wall and the wall of the hole as in Figure 13.1. This is because there is more friction at each wall than there is between the shearing fluid layers. If there were no friction in the annulus the profile would be flat. Figure 13.19 shows how plug flow could exist within a laminar profile in Bingham Plastic Fluids. Figure 13.20 shows that fluid properties - especially the shear-thinning index - affect profiles to some degree. Figure 13.29 shows the profiles that are explained in the following text.

Figure 13.29 Velocity Profiles in various Flow Regimes. (The profile in turbulent flow is an average.)

The flow regime of a fluid traveling up the annulus dependents on: the type and degree of structure within the fluid, the velocity of the fluid, and to some degree the inclination of the well. In a Newtonian fluid such as water, the hydrogen bonds providing the viscosity are relatively weak. There is not much order within the fluid as it moves and the flow regime is usually turbulent.


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In a drilling fluid such as a clay suspension, the structured clay particles contributing to the viscosity are much stronger. There is a greater degree of order within the fluid as it moves. The flow regime is usually laminar. Layers shear past each other in an "ordered" manner as in Figure 13.1. However, if enough energy is applied to the suspension in terms of shear rate or velocity, this order may be degraded to where the flow regime changes to turbulent. The velocity profile of a turbulent flow regime is almost flat, whereas the velocity profile of a laminar flow regime is peaked. If enough structure exists within the fluid, and its velocity is low enough, little or no shearing between fluid layers occurs. This regime is termed plug flow. Its profile is flat, similar to that of turbulence. Here, the velocity in all parts of the plug area is the same, whereas the velocity profile in the turbulent regime represents an average. As the width of the plug flow area increases, the efficiency and ability of the fluid to remove cuttings also increases.

Figure 13.30 Cross sectional Flow Regime.


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Figure 13.30 shows a cross sectional velocity profile. If µ?=? τ γ and τ is constant, across the

profile, then toward the edges, if the shear rate increases, the effective viscosity must decrease.

Shear rate is the velocity related input -

? vd Furthermore, although the shear rate is higher

nearer the wall, the net velocity, with respect to the center of the profile could be lower. If the viscosity and velocity are lower near the wall, cleaning problems should occur here. This affect may be compounded when more than one magnitude of force acts on a flat cutting at the same time, also illustrated in Figure 13.30.

Figure 13.31 The effect of Pipe Rotation and Flow Regimes on disks in an annulus. (from Williams and Bruce, SPE 1951).


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In 1950 a study conducted by Williams and Bruce examined the effects of flow regimes and pipe rotation on cuttings transport. Figure 13.31 describes some of their conclusions, showing that a drilled cutting caught up near the annular wall, might ultimately have a downward motion, even at higher pump rates. The conclusions from this study indicated:

1. Turbulent flow, with its flat profile is the best flow regime for removing cuttings. (Subsequent studies have not always agreed with this.)

2. Pipe rotation imparts a helical motion to the cuttings near the drill pipe improving

removal rates. (Subsequent studies show this effect lessens as annular velocity increases.)

3. Low viscosity fluids were generally best in terms of cleaning efficiency. (This

conclusion has been refuted in more recent studies)8 4. Annular velocities of 30 - 40 m/min were adequate for cleaning when using water.

This too has since been challenged 9. Both the flow regime and the velocity profile within that regime should be considered when optimizing cuttings removal rates. An interesting illustration of velocity profiles can be made at the rig. Use a dye such as phenolphthalein to draw a line perpendicular to the direction of fluid flow down a through in the pit room. Unless the flow is turbulent, a profile similar to the ones in Figure 13.29 will result. 13.9 STOKES LAW Stokes Law is expressed in an equation that attempts to predict the terminal or maximum settling velocity of a particle as it falls through a fluid. This velocity is termed its slip velocity. In laminar flow regimes Stokes Law gives the terminal settling velocity:

vs = K g Dpt2

K • sp.gr.p - sp.gr.f

µ

In turbulent flow regimes the expression becomes:

vs = Kdpt (sp.gr.p - sp.gr.f)

sp.gr.f

WHERE: vs = Slip Velocity K = Input/output unit conversion constants g = Gravitational constant Dpt = Diameter of particle sp.gr.p = Specific gravity of particle sp.gr.f = Specific gravity of fluid µ = Viscosity


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From a drilling fluid engineering perspective, it is interesting to note the various inputs and their mathematical relationships. Note that thickness is not an input in the turbulent flow expression. When using Stokes Law, it is important to consider the following: 1. The particle diameter input expresses the diameter of a sphere. Drilled cuttings are

irregular in shape and exist in a wide range of sizes. Drilled cuttings may degrade in size on their way up the annulus.

2. Tests have shown that the velocity of the fluid the particle is slipping through does not

affect slip velocity.

3. As a particle falls through a non-Newtonian fluid, it causes a shear regime to exist in the vicinity of the particle. The fluid becomes thinner around the particle, a phenomena which must be accounted for. The term Particle Reynolds Number (NRept) expresses

the flow regime near the cutting. A value of over 2,000 (dimensionless) is considered turbulent.

Moore provides the easiest method of calculating slip velocity accurately: 1. Determine the slip velocity from equation 13.25. 2. After determining the slip velocity, determine the particle Reynolds number from equation

13.26. 3. If the particle Reynolds number is more than 2,000, equation 13.27 should be used to

calculate a new value for slip velocity. Moore says, "If the operator is in doubt about whether the flow around the particle is turbulent or laminar, the equation giving the lowest slip velocity for the specific problem should be used."

Equation 13.25, Slip Velocity:

SI UNITS: vs = 0.42 Dpt (2516 - ρ ).667

ρ.333 • µ .333

BASIC: vs = 0.42 ? Dpt (2516 - ρ)^.667/ (ρ?̂.333 ? µ ^.333 ) WHERE: Vs = Slip Velocity (m/min) Dpt = Diameter Particle (mm)

ρ = Density Fluid (kg/m3) µ = Viscosity (mPa • s)

IMPERIAL UNITS: vs = 175 Dpt (21 - ρ ).667

ρ.333 • µ .333

WHERE: vs = Slip Velocity (ft/min) Dpt = Diameter Particle (inches) ρ = Density Fluid (lb/gal) µ = Viscosity (cps)


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(The constants 21 and 2516 represent the specific gravity of drilled cuttings in lb/gal and kg/m3). Equation 13.26, Particle Reynolds Number:

SI UNITS: NRept = 0.01686 • ρ • vs • Dpt

µ

BASIC: NRept = (.01686 ? ρ ? Vs ? Dpt) / µea

WHERE: NRept = Particle Reynolds Number (Dimensionless

ρ = Density of Fluid (kg/m3 ) vs = Slip Velocity (m/min) Dpt = Diameter Particle (mm) µea = Viscosity (mP • s)

IMPERIAL UNITS:

NRept = 15.47 • ρ • vs • Dpt

µea

WHERE: NRept = Particle Reynolds Number (Dimensionless

ρ = Density of Fluid (lb/gal ) vs = Slip Velocity (ft/min) Dpt = Diameter Particle (inches) µea = Viscosity (cps)

Equation 13.27, Slip Velocity in Turbulent Flow:

SI UNITS: vst = 6.85

Dpt (2516 - ρ)

1.5 x ρ

12 = m/min

BASIC: vst = 6.85 (Dpt ? (2516 - ρ) / (1.5 ? ρ))^0.5 = m/min

WHERE: Dpt = Particle Diameter (mm)

ρ = Fluid Density (kg/m3) vst = Slip Velocity (Turbulent) (m/min)

IMPERIAL:

vst = 113.4

Dpt (21 - ρ)

1.5 x ρ

12 = ft/min

WHERE: Dpt = Particle Diameter (inches) ρ = Fluid Density (lb/gal) vst = Slip Velocity (Turbulent) (ft/min)


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Since there are no velocity or viscosity inputs in this equation, it follows that a particle will fall at the same rate through various intervals as long as its Reynolds number remains above 2,000. As a particle or cutting travels up the annulus, it is net velocity may be calculated by: Equation 13.28, Net Particle Velocity: vpt = va - vs WHERE: vpt = Particle Velocity va = Annular Velocity vs = Slip Velocity The flat velocity profile of a turbulent flow regime insures that when the annular velocity exceeds the slip velocity, the cuttings will be removed. However, if the velocity profile is parabolic, the annular velocity and slip velocity are simply averages across the profile. Cuttings near the pipe or annulus wall might not be removed. That is, the particle velocity could be negative. In practice this is often seen in hole sections such as wash outs or in rat holes under casing shoes, where the annular geometry changes. The net particle velocity may be used to arrive at two meaningful values; residence or retention time and transport ratio. Particle retention time may be expressed as: Equation 13.29, Particle Retention Time:

Rt =

Interval 1 Depth (m)

Particle Velocity (m/min) +

Interval 2 Depth (m)

Particle Velocity (m/min) + ......n

WHERE: n = all hole intervals The hole cleaning efficiency of a drilling fluid is expressed as the ratio of particle velocity to annular velocity. This is termed the transport ratio or lifting capacity. Equation 13.30, Transport Ratio:

TR = VptVa

• 100 = %

WHERE: vpt = Particle Velocity Va = Annular Velocity The value for transport ratio is the final output in mathematical modeling of hole cleaning efficiency. It is a value that considers any fluid properties, hole geometry or pump rate, which could affect the removal rate of a given particle. Generally 50% is an acceptable value for transport ratio in gauge holes. In out of gauge holes, a rule of thumb is to strive for a value of 75%. At 75%, even the cuttings near the pipe and annular wall should be removed efficiently, minimizing annular loading.


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Mathematical models have been made which take particle shape into consideration. Output values are elaborate including the method by which it falls, that is, fluttering, tumbling etc. 13.10 OPTIMIZING CUTTINGS REMOVAL RATES. Because the cuttings slip, the concentration of cuttings in the annulus depends on both the transport ratio and the rate cuttings are generated at the bit. Experience and studies have shown that cleaning related problems start when the concentration of cuttings in the annulus exceeds 5% by volume. This is a rule of thumb only, not a law of nature. It is a good practice however, to consider this value prior to stopping circulation for long periods of time. Equation 13.31 shows how to calculate the volume % of cuttings in the annulus. Equation 13.31, Calculating the Volume % of Cuttings in an Annulus:

Ca% =

Rt • ROP • Volume/Depth Unit

Annular Volume • 100

WHERE: Ca% = Volume % Cuttings in Annulas Rt = Retention Time (Hours) ROP = Rate of Penetration (m/h or ft/h) Vol/Depth Unit = Volume of Cuttings (m3/m or bbl/ft) Annular Volume = Annular Volume (m3 or bbl) The input value: Vol/Depth Unit, may be adjusted to reflect a known formation bulk density. 13.10.1 Optimizing annular velocity In competent formations, high flow rates will not cause erosion, even if the flow is turbulent. The shear stresses exerted by drilling fluid movement on the hole walls are in the order of Pascals (lb/100 ft2) where compressive strengths of competent sedimentary rock is in the order of thousands of kilo Pascals (thousand of pounds per square inch). Sifferman et al measured the decrease in transport ratio of artificial cuttings as a function of the annular velocity for different fluids. These results, shown in Figure 13.32 indicate that the ratio tends to level off as the annular flow rate increases. Also the ratio is strongly dependent on the viscosity of the fluid, particularly at lower annular velocities.


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Figure 13.32 Cuttings Transport Ratio as a function of Annular Velocity.

Zamora calculated the minimum annular velocity required to keep the cuttings concentration less than 4% for the various fluids shown in Figure 13.33.


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Figure 13.33 Minimum Annular Velocities to keep cuttings concentrations less than 4%. Figure 13.33 shows that at some point, the effect that increasing the annular velocity has on transport ratio diminishes. The above models become meaningless when the following formation types are penetrated: 1. Tertiary (Incompetent) 2. Highly Fractured 3. Evaporates 4. Permafrost In these types of formations, it is necessary to optimize the combination of velocity and annular rheology to minimize hole erosion or washout. As the annular velocity increases, so does the level of friction at the wall of the hole. Increasing levels of energy are transferred to the wall. The first three formation types are easily erodible because the cementing matrix or bonds between constituents is weak. Even oil-based fluids will not prevent fractured formations from eroding at high annular velocities. In permafrost, cleaning and erosion depend on the optimum combination of three inputs: viscosity, velocity and temperature. In the Beaufort Sea, several operators have been successfully opening 660 mm holes to 914 mm using cold seawater alone. To avoid the possibility of eroding the permafrost, pump rates are kept at 0.5 m3/min, netting an annular velocity of 1.6 m/min by 127 mm drill pipe. The ROP is held at 50 m/hr. Particle size analysis applied to the equations and models discussed in this


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chapter were used to develop this technique. This simply proves that high annular velocities are not always necessary. 13.10.2 Optimizing rheological Properties In general, the more, shear thinning, and the less thixotropic fluid the more desirable it will be for hole cleaning purposes. Shear thinning character indicates predominantly structural viscosity. The YP/PV ratio increases and the n value decreases as structural viscosity increases. The n value will always decrease when: 1. The system becomes flocculated 2. Solids are removed 3. Viscosifying polymers or clays are added Increasing a fluid's shear thinning character enhances hole cleaning by two mechanisms. First, the effective viscosity increases in enlarged sections where fluid velocities are low. Second, as n decreases, the velocity profile becomes flatter. Low shear rates and high local viscosities prevail over a larger area of the annular radius. Certain authorities claim that lowering the value of n reduces the effective viscosity since: µe = K( γ?) n-1 This assumes that the annular shear rate must be constant, across the velocity profile that, as we have seen, it is not (see Figure 13.30). This is why annular γ is expressed by API as γwall. Various studies and field experience agree that the YP value is an efficient rheological parameter for gauging cleaning ability. However, the value for K as a viscosity unit is actually a better indicator, especially at low shear rates. Recall that K represents the shear stress in dynes/cm2 at a shear rate of 1 s-1. In terms of cleaning if a fluid is extremely thixotropic, its equilibrium viscosity may never be attained as it encounters changing annular shear regimes. This effect is discussed in the preceding text. The best practice is to keep the gel strengths flat. Progressive gel strengths indicate that the time required to build the desired degree of structure might be excessive, impeding the cleaning characteristics of the fluid. 13.10.3 Calculating the Maximum safe ROP The approach to this question involves rearranging equation 13.31. Equation 13.32, Calculating the Maximum Safe Rate of Penetration:

ROPm = AnnVol • 5%

Rt • Vol

Depth Unit • 100

WHERE: ROPm = Maximum Safe ROP This is the method used by the Ava Hydraulics Calculator. The output value is usually increased if a known formation bulk density is factored into the (vol/depth unit) value.


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A close look at equation 13.32 reveals that if the optimum annular velocity is being used, retention time Rt, remains the only variable input parameter, Rt must be reduced. That is, the particle velocity must be increased. In short, to reduce Rt without changing the annular velocity, either the fluid density or the annular viscosity must be increased. The largest margin of error when using equation 13.32 occurs when pilot hole is being drilled in tertiary formations. Often, usually because of excessive pump rates, the hole erodes. As it becomes larger, the value for "volume of cuttings per depth unit" increases to an indeterminable degree. 13.11 CLEANING IN INCLINED PROFILES Several in depth studies have recently been conducted in an attempt to attain a better understanding of how hole inclination affects cuttings transport. In inclined wells, the same forces act on a cutting. That is, the gravity and the moving fluid. However, they are no longer opposed 180°. This causes a "resultant" velocity vector. The situation, illustrated in Figure 13.34 shows the settling velocity vs, which as a resultant force, is acting to deposit cuttings on the lower side of the hole. The cuttings only have to fall a relatively short distance and they accumulate on the bottom.

Figure 13.34 Settling velocity in angled holes.

A research group at Tulsa University, led by Azar has reported the results of a series of laboratory experiments using an annulus of 5 inches by 1.9 inches and flow rates up to 200 gpm. Their conclusions can be summarized as follows: 1. Three separate situations can be applied to cuttings transport: region 1 (0° to 30°), region

2 (30° to 55°), and region 3 (55° to 90°). Deviation from vertical to 10° essentially produces no change in cuttings transport.


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2. The volume % of cuttings in the annulus is an important parameter to consider when

assessing cuttings transport in directional wells. The highest annular cuttings concentration is experienced at angles of inclination in the 40° to 45° range. This is especially true when relatively low flow rates are used.

3. Flow rate has a dominant effect on annular hole cleaning. 4. Laminar flow is best in the range of low-angle wells (0° to 45°), while in high angle wells

(55° to 90°) turbulent flow is best. In the range of intermediate inclination (45° to 55°), turbulent and laminar flow have generally similar effects.

5. In turbulent flow regimes, cuttings transport is not generally affected by the rheological

properties of the fluid in all three regions. 6. In laminar flow regimes, higher yield point values reduce the annular cuttings

concentration and provide better transport. This effect is pronounced in Region 1 and becomes slight or even negligible in Region 3.

7. Adverse effects on cuttings transport caused by annulus eccentricity is not significant for

low-angle wells (Regions 1 and 2) in either laminar or turbulent flow. The effect becomes moderate in Region 3 under turbulent flow and significant when the flow becomes laminar.

8. The beneficial effects of YP and n value are greater at lower annular velocities. Lower n

values provide better cuttings transport at all hole inclinations. 9. At higher deviation a bed of cuttings may develop at low flow rates. For a given flow rate,

the thickness of this bed increases with deviation, up to an angle where it becomes independent of deviation. A measurable torque was observed in the transport experiments because of the presence of the cuttings bed.

11. For given conditions of deviation and flow rate, the bed thickness is strongly influenced by

drill pipe eccentricity, but only moderately influenced by fluid viscosity. This is because drill pipe position alters the annular flow rate, a more important factor than the viscosity.

12. After cuttings injection has ceased, the cleaning rate of the settled cuttings increases with

an increase in rotary speed, particularly in Region 3. 13. Generally, it can be concluded that the trends observed during annulus-cleaning

experiments are similar to those observed in the cuttings-transport experiments. Figure 13.35 shows the effects of fluid velocity on annular cuttings concentrations at different angles. This shows the transition of transport mechanisms as hole angle changes.


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Figure 13.35 Effects of inclination on Cuttings Transport. Another study conducted by Martin et al in 1987 included the following points: 1. The average minimum rising velocity required to efficiently transport cuttings, reaches a

maximum at inclinations between 30° and 60°. 2. Thixotropic fluids are undesirable because they effectively immobilize the layer of cuttings

next to the wall. 3. High fluid density enhances cuttings transport. 4. Drill string rotation helps by knocking cuttings from the bed back into the annulus. The reason that angles in the 45° range present such problems is easy to picture. When the drill string is in tension it is always pulled to the high side of the hole at this angle. It is almost impossible for the pipe to stir the cuttings back into the main stream. As angles approach horizontal, part of the string may be on the low side eliminating the bed. At angles less than 45° non-concentric rotation is again possible. Many offshore field developments are carried out by drilling deviated wells radiating from a central platform. Practical experience has allowed some specific guidelines to be drawn up. These are summarized in Table 13.3. Emphasis has been placed on maintaining annular velocities as high as possible. The use of 6 5/8 inch drill pipe for 17 1/2 inch and 12 1/2 inch holes has made a significant improvement in hole cleaning. When oil-based fluids are used to drill high-angle / large diameter (311 mm) holes, special consideration must be given to the low shear rate rheology. Although a water-based fluid may


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have exactly the same 600 RPM and 300 RPM values, as an oil-based fluid, the oil-based fluid characteristically exhibits lower shear stress values at the lower shear rates typical of large diameter holes. In these situations, software programs are often necessary in order to ascertain the real cleaning abilities of an oil-based fluid. If a computer is not available a good rule of thumb is to maintain 3 RPM and 6 RPM readings in the range of 15° on the viscometer dial. A problem with deviated drilling is that the well may contain intervals that range from vertical, through 45° and up to almost horizontal. Conditions that may suit one situation might not suit another. Often the best solution is to use annular velocities as high as possible, recognize that there is a bed of cuttings on the low side of the hole and anticipate that back reaming with the pumps on will occur as the pipe is pulled out of the hole. This operation is much more efficient where a top drive unit is used. Table 13.3 Summary of Optimized Hole Cleaning for Different Angles of Deviation

0° - 30° 30° - 55°

55° - 90°

Flow Regime Laminar Laminar or Turbulent if turbulent flow possible Flow rate Maximize Maximize Maximize YP Maximize up to 12 Not critical 2 - 5 n value Low Not critical Not critical PV Minimize Not critical Not critical Cuttings bed None Always forms. Always forms formation Back ream Back ream with pumps with pumps

13.12 PRACTICAL APPLICATION OF CUTTINGS REMOVAL THEORY Ultimately, inefficient hole cleaning costs time. Cleaning problems usually do not occur instantaneously. Drilling Fluid Engineers are partly responsible for recognizing signals that may point to pending problems. These include: 1. Fill on connections, surveys, and trips. 2. Increased torque, drag, and pump pressure. 3. Clean shakers. 4. Back flow on connections. Although the equations and methods presented in this manual are the best available and reliable, shortcomings are possible. The factors contributing to this are related to input data. They include the incorrect estimation of: 1. Pump efficiency. 2. Hole size, affects the shear rate, annular velocity, and volume calculations. 3. Particle size, cuttings may be over twice the size down hole.


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4. Annular shear rate, all annular calculations are based on the equation for annular shear

rate that contains an empirical constant obtained at the annulus wall. Fortunately this represents the worst-case scenario, where viscosity and velocity are lowest. The annular shear regime is further complicated by pipe rotation.

5. Rheological properties, incorrect estimation of the affects of pressure, temperature. In most cases a practical approach may be as helpful as a scientific one. Pumping a viscous sweep while drilling or prior to or after tripping may be beneficial. If large cuttings or cavings or washed-out intervals exist, a sweep will usually help. This may indicate a need to increase the active system viscosity. The terminal settling velocity of these cuttings may be determined at the rig. When cuttings are dropped into a large graduated cylinder settling velocities through drilling fluid may be observed. The shape of the cuttings on the screens may tell a tale. Round or smooth cuttings could indicate that they tumbled in a washed out area for a time. Specific cleaning problems - including bit balling, mud rings, wash outs etc., are discussed in Chapter 20. 13.13 FLOW REGIMES The following points pertaining to flow regimes have been discussed up to now: 1. Fluid characteristics have an influence on velocity profiles (see Figure 13.20). 2. Certain flow regimes exhibit a velocity profile typical of that regime (see: Figure 13.3). 3. A particle Reynolds number is the resultant value of a mathematical means of describing

the flow regime in the vicinity of a particle falling through fluid. 13.13.1 Reynolds Number This same concept, Reynolds Number, may be used to predict the flow regime in a pipe or annular interval. A Reynolds number is an empirical value. The concept and equations have been rigorously tested under varying influences including: diameters, flow rates, fluid types and pipe smoothness. This testing has indicated that the change from laminar flow (flow in layers) to turbulent flow (chaotic flow) in Newtonian fluids occurs at a value of between 2,000 to 3,000. Below a value of 2,000, flow is fully laminar and above a value of 3,000, flow is fully turbulent. A transition zone exists between the two values. In the case of non-Newtonian fluids, as the degree of shear-thinning character increases, the Reynolds number where flow becomes fully turbulent also increases. Each flow regime (laminar, transition and turbulent) may exist in Newtonian and non-Newtonian fluids. Figure 13.37 depicts the three types of flow regimes in round pipes.


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Laminar flow (in layers)

SlowVelocity

Increasein velocity

Transition state

Turbulent flow

More Velocity

Figure 14.37 It should be noted that an accepted assumption regarding flow regimes is that they exist separately in a given pipe or annulus. All pressure loss calculations are based on this assumption. In fact, in all flow regimes the velocity at the pipe wall is zero. Therefore in the case of turbulent flow, the regime must be laminar for a certain distance out from the wall, changing to transition, then turbulent. See Figure 13.38.


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Low velocity - LaminarMedium velocity - transtion

Medium velocity - transtionLow velocity - Laminar

High velocity - turbulent

Figure 14.38 Turbulent flow The Reynolds number concept describes two forces acting in a moving fluid:

1. The inertial force, a force that tends to create chaos in the fluid. 2. The viscous force, a force that tends to restore order in a fluid. The relationship between the fluid's state of flow and these forces may be written: State of Flow α Inertial Force Viscous Force or:

State of Flow α (Density)(Velocity)(Diameter)

Viscosity

This relationship indicates that decreasing any component of the inertial force will reduce the Reynolds number. Note that pipe diameter, velocity and fluid density are all contributing factors. Conversely, raising the viscosity will reduce the number. The following is a chronological short summary describing how to proceed with Reynolds number calculations: 1. Calculate the mean fluid velocity - va, in the annulus (Equation 13.13) or the pipe vp

(Equation 13.14). 2. Calculate the viscosity inside the annulus, µ'

ea (Equation . 14.22) or the pipe

µep (Equation . 14.23) . Or use a γ vs µ log - log graph.

3. Calculate the Reynolds number in the annulus NRea with Equation 13.33 or in the pipe

with Equation 13.34. Equation 13.33, Reynolds Number in the Annulus:


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SI UNITS: NRea = va (Dh - Dp) ρ

60 µ'ea

BASIC: NRea = va (Dh- Dp) ρ / ( µ'

ea ? 60)

WHERE: va = Average Velocity in Annulus (m/min) Dh = Outer Annulus Diameter (mm) Dp = Inner Annulus Diameter (min)

ρ = Fluid Density (kg/m3) µ'

ea = Effective Annular Viscosity (mPa • s)

IMPERIAL UNITS: NRea = 15.47 va (Dh- Dp) r

m'ea

WHERE: va = Average Velocity in Annulus (ft/min) Dh = Outer Annulus Diameter (inches) Dp = Inner Annulus Diameter (inches) ρ = Fluid Density (lb/gal) µ'

ea = Effective Annular Viscosity (cps)

If µ'

ea is being obtained from a log-log graph of γ vs µ, it is necessary to first calculate γ?'wa from

Equation 13.18. Equation 13.34, Reynolds Number in the Pipe:

SI UNITS: NRep = vpIDp ρ60 µep

BASIC: NRep = vp* IDp ? ρ / (µep * 60 )

WHERE: vp = Average Velocity in Pipe (m/min) IDp = Pipe (Inside) Diameter (mm)

ρ = Fluid Density (kg/m3) µep = Effective Viscosity Inside Pipe (mPa • s)

IMPERIAL UNITS: NRep = 15.47 vpIDp ρ

µep

WHERE: vp = Average Velocity in Pipe (ft/min) IDp = Pipe (Inside) Diameter (mm) ρ = Fluid Density (lb/gal) µep = Effective Viscosity Inside Pipe (cps)


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If µep is being obtained from a log-log graph of γ vs µ, it is necessary to calculate γwp

from

Equation 13.19 before calculating the Reynolds number. 13.13.2 Critical Velocity and Pump Output Reynolds number equations may be re-written algebraically to calculate a critical velocity or critical pump output. This value is simply the annular velocity or the flow rate where the fluid is definitely in turbulent flow. These equations use shortcuts. Therefore output values are often very inaccurate - seldom confirming API values. The equations are included in this text, so that when only a hand-held calculator is available, a number can still be generated. Equation 13.35, Critical Velocity in the Annulus:

SI UNITS: vca =

9 • 104K

ρ

12-n

200

DhDp •

2n+1

3n

n2-n

BASIC: (90 000 • K/ ? )^(1/(2-n)) * ?((200/(Dh-Dp)) * ((2 * n+1)/(3 *• n))) ^ (n/(2-n)) WHERE: vca = Critical Velocity in Annulus (m/min) K = Consistency Index (Poise) ρ = Fluid Density (kg/m3) n = Shear Thinning Index Dh = Hole Diameter (mm) Dp = Pipe (Outside) Diameter (mm)

IMPERIAL UNITS: vca =

3.88•104K

ρ

12-n

2.4

DhDp •

2n+1

3n

n2-n

WHERE: vca = Critical Velocity in Annulus (ft/min)

K = Consistency Index (lb/100 ft2) ρ = Fluid Density (lb/gal) n = Shear Thinning Index Dh = Hole Diameter (inches) Dp = Pipe Diameter (inches) The value for Vca may be input into Equation 13.13 to produce a value for the pump output at which flow is turbulent: Equation 13.36, Critical Pump Output:

SI UNITS: Qc = vca(Dh2-Dp2)

1273000 = m3 /min

BASIC: Qc = vca (Dh2 - Dp2) / 1273000


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WHERE: Qc = Critical Pump Output (m3/min) vca = Critical Velocity in annulus (m/min) Dh = Hole Diameter (mm) Dp = Pipe (Outside) Diameter (mm)

IMPERIAL UNITS: Qc = vca(Dh2-Dp2)

1030 = bbl/min

WHERE: Qc = Critical Pump Output (bbl/min) vca = Critical Velocity in Annulus (ft/min) Dh = Hole Diameter (inches) Dp = Pipe (Outside) Diameter (inches) 13.13.3 The Fanning Friction Factor ( f ) In turbulent flow, the velocity profile denotes the resultant average velocity. This is because the actual velocity fluctuates randomly as in Figure 13.37. Because of this local randomness, the real slope of the profile can't be determined. Therefore the shear rate can't be calculated and a meaningful shear stress (pressure) / shear rate relationship is unobtainable. Regardless of the fluid type or flow regime, friction exists at the pipe wall. It is related to the roughness of the pipe and the nature of the fluid. This friction induces increased resistance to flow especially while the regime is in turbulence. The degree of friction is expressed by a second dimensionless value termed the Fanning friction factor (f). Together the Fanning friction factor and the Reynolds number may be used to predict pressure gradients. The value of the Fanning friction factor may be calculated for Newtonian fluids in turbulent flow or laminar flow. Its value is then input into a pressure loss gradient equation. Drilling fluids are usually non-Newtonian. In power low fluids, the velocity required to induce turbulent flow increases, as the fluid becomes more shear thinning. Thus the value of n is a factor when determining the specific Reynolds number indicating where flow is fully turbulent. As the value of n decreases, the Fanning friction factor also decreases - reducing the pressure loss gradient. A figure in older versions of API 13D depicts the relationship between n, f and NRea. The Fanning friction factor is an input in pressure gradient equations. It may be

determined graphically or mathematically. The graphical method will be considered first. 13.13.4 The Friction Factor Graphically Part A - For Flow in the Annulus ( fa ):

Required Inputs: 1, NRea (Equation. 13.33)

2, n' (Equation. 13.16) Step 1, Find the CRITICAL Reynolds number from Figure 13.39.


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Match the calculated value for n' (Equation. 13.16) with the closest value of n on the right side of the graph. Follow the closest solid "n value" line to where it intersects the line named ANNULUS. It is best if you extrapolate your own "n value" line. Move vertically down from the intersection to the bottom of the graph. Read the CRITICAL Reynolds number on the x axis. If it is lower than the Reynolds number calculated from Equation 13.33 then the flow regime is turbulent. If it is higher, then the flow regime is laminar. Step 2, Find the Fanning Friction Factor - fa . If the flow regime is turbulent: Locate the calculated annular Reynolds number (NRea - Equation. 13.33) on the bottom

horizontal axis in Figure 13.39. Draw a line up from that point to the line that denotes the value of n' calculated from equation 13.33. From that intersection, read the fanning friction factor on the left vertical axis - directly opposite.

If the flow regime is laminar, calculate fa from Equation 13.37:

Equation 13.37,The Fanning Friction Factor in the Annulus, Laminar Flow:

fa = 24

NRea

Part B - For Flow Inside Drill pipe ( fp ):

Required Inputs: 1, NRep (Equation. 13.34) 2, n (Equation. 13.10) Step 1, Find the CRITICAL Reynolds number from Figure 13.39. Step 1 is similar to Step 1 in Part A, but this time the line on the graph marked PIPE must be used. Step 2, Find the Fanning Friction Factor - fp . If the flow regime is turbulent: Using the calculated pipe Reynolds number, (NRep - Equation. 13.34), follow the same

procedure as described in Part A. If the flow regime is laminar, Calculate fp from Equation 13.38:

Equation 13.38, The Fanning Friction Factor in the Pipe - Laminar Flow:

fp = 16

NRep


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13.13.5 The Friction Factor Mathematically The Fanning friction may be found without the aid of a graph. API endorses the following equations. API doesn't use modified Power law values to compute the friction factor, thus, they won't be used here. The HyCalc hydraulics calculator gives the user the option of using modified Power law inputs when calculating the friction factor. The key is to input values which yield the closest approximation of the actual standpipe pressure. If this is done regularly, actual pressure predictions will be more accurate. The inputs, n and NRe are dimensionless, as is the output f. Therefore, these formulas work with any measurement system. Part A: Identify the Flow Regime: (The same steps apply for pipe and annulus) Three Logical Tests: Equation 13.39, Test For Laminar Flow: Test lam: IF NRe < 3470 - 1370n, Flow is Laminar

Equation 13.40, Test For Turbulent Flow: Test turb: IF NRe > 4270 - 1370n, Flow is Turbulent Equation 13.41, Test For Transitional Flow: Test trans: IF NRe > 3470 - 1370n, and

IF NRe < 4270 - 1370n, Flow is Transitional WHERE: n = The Shear Thinning Index NRe = The Reynolds Number in either the Pipe or Annulus When programming these in BASIC, use a nested IF / THEN / ELSE statement. On an electronic spreadsheet use a nested logical "IF" function. An example Excel Spreadsheet Hydraulics Calculator could use the following: IF (NRe < 3470 - 1370n, "LAM", IF (NRe > 4270 - 1370n, "TURB", "TRANS")). Part B: Calculate the Friction Factor: Equation 13.37, The Fanning Friction Factor in the Annulus - Laminar Flow:

fa = 24

NRea

Equation 13.38, The Fanning Friction Factor in the Pipe - Laminar Flow:

fp = 16

NRep


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Equation 13.42,The Friction Factor in Turbulent Flow: If turbulent flow was identified in either the pipe or the annulus, use the following steps, substituting the appropriate Reynolds Number:

ALGEBRAIC: fturb = a

NReb

BASIC: fturb = ((log n + 3.93) / 50) / NRe^((1.75 - log n) / 7) WHERE: fturb = The Friction Factor in Turbulent Flow

a = Log n + 3.93

50

b = 1.75-Log n

7

NRe = Reynolds Number in Pipe or Annulus When calculating the pressure loss in more than one annular interval, it is best to calculate the value of a and b once - and then refer to them. Then Equation 13.42 becomes: BASIC: ftu = a / NRe^b - making the program run faster. Equation 13.43, The Friction Factor in Transitional Annular Flow:

ALGEBRAIC: fatr =

NRea - c

800 •

a

(4270-1370n)b -

24

c + 24c

BASIC: fatr = ((NRea - c) / 800) • ((a / (4270 - 1370 • n)^b) -(24 / c)) + 24 / c

WHERE: NRea = Reynolds Number in The Annulus fatr = The Friction Factor in Transitional Annular Flow

a = Log n + 3.93

50

b = 1.75-Log n

7

c = 3470 - 1370n Equation 13.44, The Friction Factor in Transitional Pipe Flow:

ALGEBRAIC: fptrans =

NRea - c

800 •

a

(4270-1370n)b -

16

c + 16c


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13.14.1 Annular Pressure Losses The following equation calculates the annular friction loss (pressure gradient). Multiply this value by the length of each annular interval. Equation 13.45, The Annular Pressure Loss Gradient:

SI UNITS: ∆Pa = fava2ρ

(Dh - Dp) 1800 = KPa/m

BASIC: ∆Pa = fa ? va^2 ? ρ / (Dh - Dp) 1800 WHERE: fa = Friction Factor (Annulus) va = Average Velocity in Annulus (m/min)

ρ = Fluid Density (kg/m3) Dh = Hole Diameter (mm) Dp = Pipe Diameter (mm)

IMPERIAL UNITS: ? Pa = fava2ρ

(Dh - Dp) 92870 = PSI/ft

WHERE: fa = Friction Factor (Annulus) va = Average Velocity in Annulus (ft/min) ρ = Fluid Density (lb/gal) Dh = Hole Diameter (inches) Dp = Pipe Diameter (inches) 13.14.2 Pipe Pressure Losses The following equation calculates the pipe friction loss (pressure gradient). Multiply this value by the length for each section of similar inside diameter. Equation 13.46, The Pipe Pressure Loss Gradient:

SI UNITS: ∆Pa = fava2ρ

IDp 1800 = KPa/m

BASIC: ? Pa = fa ? va^2 ? ρ / IDp1800 WHERE: fa = Friction Factor (Pipe ) va = Average Velocity in Pipe (m/min)

ρ = Fluid Density (kg/m3) IDp = Inside Diameter of Pipe (mm)

IMPERIAL UNITS: ? Pp = fava2ρ

IDp 92870 = PSI/ft

WHERE: fa = Friction Factor (Pipe)


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Vp = Average Velocity in Pipe (ft/min) ρ = Fluid Density (lb/gal) IDp = Inside Diameter of Pipe (inches) 13.14.3 Bit Pressure Losses Bit pressure losses are calculated using Equation 13.47: Equation 13.47, Friction Loss Through Bit Nozzles:

SI UNITS: DPn = ρ Q2 277778

(Dn12 + Dn22 + Dn32 +....)2 = kPa

BASIC: ∆Pn = (ρ ? Q^2 ? 277778) / (Dn21 + Dn22+...)^2 WHERE: Pn = Nozzle Pressure Loss (kPa)

ρ = Fluid Density (kg/m3) Q = Flow Rate (m3/min) Dn = Nozzle Diameter (mm)

IMPERIAL UNITS: ∆Pn = ρ Q2 156

(Dn12 + Dn22 + Dn32 +....)2 = Psi

WHERE: Pn = Nozzle Pressure Loss (psi) ρ = Fluid Density (lb/gal) Q = Flow Rate (U.S. gpm) Dn = Nozzle Diameter (1/32 inch) The Eastman Christensen equations for diamond bit pressure losses are as follows: RADIAL FLOW:

Pressure Loss (Bar) = 7.3188 • ρ0.61 • Q

TFA (1 BAR = 100 kPa)

FEEDER COLLECTOR SYSTEM:

Pressure Loss (Bar) = 24.738 • ρ0.34 • Q1.47

TFA1.76 (1 BAR = 100 kPa)

WHERE: ρ = Fluid Density (kg/l) Q = Flow rate (l/min) TFA = mm2 13.14.4 Pressure Losses In Surface Connections These losses are a result of the fluid passing through the surface connections from the mud pump to the top of the drill pipe. This includes the standpipe, kelly hose, swivel, wash pipe, gooseneck and kelly. The pressure loss depends upon the size of the rig and the amount of


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piping throughout the surface connections. The bit and pump manufacturers outline four different cases that apply to most rigs. TABLE 13.4 Surface connection combinations

NO. 1

NO. 2

NO. 3

NO. 4

COMPONENT

I.D.

(mm)

Equiv. Length

(m)

I.D.

(mm)

Equiv. Length

(m)

I.D.

(mm)

Equiv. Length

(m)

I.D.

(mm)

Equiv. Length

(m) Standpipe

76

12.2

89

12.2

102

13.7

102

13.7

Hose 51 13.7 64 16.8 76 16.8 76 16.8 Swivel, Washpipe, Gooseneck and Elbows

51

6.1

64

7.6

64

7.6

76

9.1 Kelly 57 12.2 83 12.2 83 12.2 102 12.2 Equiv. Length of 76 mm I.D.

200m

76m

45m

30m

Factor 1.0 0.36 0.22 0.15 To estimate the pressure losses throughout the surface equipment, the following formula may be used: Equation 13.48, Pressure Losses in Surface Connections: SI UNITS: Psc = 0.35 • Factor •?ρ? • Q WHERE: Psc = Pressure Loss - Surface Connections (kPa) Factor = From Table 7.2 (Dimensionless) ρ? = Fluid Density (kg/m3) Q = Pump Output (m3/min) The pressure losses throughout the surface connections are generally minimal and can be estimated to be from 100 kPa to 250 kPa. 13.14.5 Total System Pressure Losses The pressure losses in the entire circulating system may be estimated by summing the values obtained from the previous 5 equations. Equation 13.49, Total System Pressure Losses: Pt = Pa + Pp + Pn + Psc = Kpa/psi

WHERE: Pt = Total System Pressure Losses Pa = Annular Pressure Loss Pp = Pipe Pressure Loss


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Pn = Bit Nozzle Pressure Loss Psc = Surface Connection Pressure Loss In general, the pressure loss in the annulus comprises 2-5% of the total system pressure loss - the standpipe pressure. The drill pipe pressure loss may account for 20-45% while the bit pressure loss is from 50-75%. 13.15 BIT HYDRAULICS When planning a well, operators must choose a rig with enough pumping capability to complete drilling it to the projected total depth. This capability is expressed in terms of power. Once a well profile and casing program are complete, the optimum flow rate may be determined for each interval. This value depends on the proposed fluid properties and the expected formation competency. Efficient bit cleaning, cuttings removal and maintenance of borehole gauge, all depend on the volumetric flow rate. Ava recommends using the following guidelines when determining the optimum flow rate: TABLE 13.5 Flow Rates

NOZZLE VELOCITY

FORMATION TYPE

MAXIMUM VELOCITY

m/s

ft/s

Hard as req'd as req'd Medium 115 380 Soft 90 300 Tertiary 60 200 Fractured 60-90 200-300 Permafrost 15 50

ANNULAR VELOCITY

m/min

ft/min

Hard 50 160 Medium 40 130 Soft 30 100 Tertiary 20 65 Fractured 20-40 65-130 Permafrost

1.0 3.0

Table 13.5 is simply a guideline. If a tertiary formation is sticky and bit balling is a problem, a nozzle velocity of only 40 m/s may be insufficient to clean the bit. However, doubling the nozzle velocity may necessitate increasing the dilution rate. Similarly, the annular velocity guidelines may have no relevance when drilling pilot hole. Each situation demands input from experience and knowledge of the area. Once the optimum valve for volumetric flow rate has been established, ROP maximization may be addressed. The following excerpt from a paper by Dr. H.A. Kendall of Mobil Oil offers a brief history of the two methods used today:


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"Early investigation had shown that penetration rate increased with both rotary speed and weight and further that effective weight utilization was to some extent dependent upon the circulation rate and also the jet nozzle velocity. This gave rise to the maximum QV program or commonly called "jet impact" program, justified by its proponents who believe that cutting removal is dependent upon the blasting effect of the jet striking the bottom of the hole. Later investigators who were concerned primarily with down hole mud operated devices chose to consider hydraulic horsepower which has a greater physical significance to oilfield engineers than jet impact: the term "bit hydraulic horsepower" came into usage, justified by its proponents who believed that cutting removal is dependent upon the amount of fluid energy expended at the bit". Impact can be related to the product of flow rate and velocity and power to the product of flow rate and pressure. With either theory, pump liner size, nozzle size and flow rates must be optimized. Many papers have been published which discuss the attributes of each theory. Most operators have their own individual ideas and policies. The following equations show how the various values are derived: Equation 13.50, Nozzle Velocity:

SI UNITS: Vn = Q 21220

∑n=1

n=mDn

2

= m/s

BASIC: Vn = 21220 ? Q / (Dn12 + Dn22+ ....) m/s WHERE: Q = Flow Rate (m3/min) Dn = Nozzle Diameter (mm)

IMPERIAL UNITS: Vn = Q 418.3

∑n=1

n=mDn

2

= ft/s

WHERE: Q = Flow Rate (U.S. gpm)) Dn = Nozzle Diameter (1/32nds inch) Equation 7.51, Hydraulic Power: SI UNITS: HP = Pn • Q • 0.01667 = kW (Kilowatts) BASIC: HP = Pn ? Q ??.01667 WHERE: Pn = Nozzle Pressure Loss (kPa)

Q = Flow Rate (m3/min)

IMPERIAL UNITS: HP = Pn • Q1714 = HP (Horsepower)


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WHERE: Pn = Nozzle Pressure Loss (psi) Q = Flow Rate (U.S. gpm) Anywhere from 2.5 - 5.0 horsepower per square inch is considered acceptable. Optimization occurs when 1/2 to 1/3 of the available pump horsepower is used at the bit. The available horsepower at surface is calculated by: Hydraulic P. = Maximum Allowable Surface Pressure • Maximum Flow Rate = HP 1714 or: Hydraulic P. = Max. Allowable Surf. Pr. • Max. Q • .01667 = KW This value changes with different lines sizes. Equation 13.52, Impact Force:

SI UNITS: IF = ρ Q vn

60 = N (Newtons)

BASIC: IF = ρ Q Vn / 60 = N WHERE: IF = Impact Force (N) ρ = Fluid Density (kg/m3) Q = Flow Rate (m3/min) vn = Nozzle Velocity (m/s)

IMPERIAL UNITS: IF = ρ Q vn1932 = Pounds Force

WHERE: IF = Impact Force (lb F.) ρ = Density (lb/gal) Q = Flow Rate (U.S. gpm) vn = Nozzle Velocity (f/s) 13.16 EQUIVALENT CIRCULATING DENSITY The value for hydrostatic pressure gradient may be used to calculate the (Static) pressure at any measured depth by multiplying it by the true vertical depth at that point. This value is termed hydrostatic head. Be sure to multiply by true vertical depth. Equation 13.53, Hydrostatic Pressure Gradient: SI UNITS: ∆Ph = .00981 • ρ WHERE: ∆Ph = Hydrostatic Pressure Gradient (kPa/m)

ρ = Fluid Density (kg/m3) IMPERIAL UNITS: ∆Ph = .052 • ρ


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WHERE: ∆Ph = Hydrostatic Pressure Gradient (psi/ft) ρ = Fluid Density (lb/gal) When the fluid is in motion, an additional pressure due to friction is applied to the wall. This effect is the same as if the fluid density had been increased. Thus the term, equivalent circulating density (ecd) is used when the fluid is in motion. The value for ecd is an important consideration, especially when drilling in close-to-balance situations. The equation for equivalent circulating density is expressed as: Equation 13.54, Equivalent Circulating Density:

SI UNITS: ecd = ρ +

Pa

0.00981 • md = kg/m3

BASIC: ecd = ρ + (Pa / .00981 * md) = kg/m3 WHERE: ρ = Fluid Density (kg/m3) Pa = Total Annular Pressure Loss (kPa) md = Measured Depth (m)

IMPERIAL UNITS: ecd = ρ +

Pa

0.052 • md = lb/gal

WHERE: ρ = Fluid Density (lb/gal) Pa = Total Annular Pressure Drop (psi) md = Measured Depth (ft)


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REFERENCES 1 Moore, P.L., Drilling Practices Manual, 1st ed. (Tulsa: The Petroleum Publishing

Company, 1974), 106; all subsequent citations are to this edition. 2 Metzner, A.B., Non-Newtonian Technology: Fluid Mechanics and Transfers, (N.Y.:

Academic Press, 1956), 87. 3 Moore, Drilling Practices, 106. 4 Darley and Gray, Composition and Properties, 220. 5 Moore, Drilling Practices, 107. 6 Darley and Gray, Composition and Propertiesm, 251. 7 Darley and Gray, Composition and Properties, 220. 8 Hopkin, E.A., "Factors Affecting Cuttings Removal During Rotary Drilling", Journal of

Petroleum Technology, (June 1967), p. 807-814. 9 Zeidler, H.V., "An Experimental Analysis of Transport of Drilled Particles", Society of

Petroleum Engineers Journal, (Feb 1972), p. 39-48.


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CHAPTER 14

PRODUCTION ZONE DRILLING

14.1 KEY POINTS AND SUMMARY

14.2 INTRODUCTION

14.3 ASSUMPTIONS

14.4 REVIEW OF FORMATION DAMAGE MECHANISMS

14.4.1 Fluid - Fluid Interactions 14.4.2 Fluid - Rock Incompatibilities

14.5 THE PROCESS

14.5.1 Step 1: Identify The Characteristics of the Fluid-Rock System. 14.5.2 Step 2: Postulate Relative to the Presence and Severity of Discrete Impairment

Mechanisms. 14.5.3 Step 3: Validate and Quantify the Impairment Mechanisms. 14.5.4 Step 4: Design & Optimize to Mitigate All Impairment Mechanisms. 14.5.5 Step 5: Design the Bridging System if Required. 14.5.6 Step 6: Choose & Test Whole Fluid

14.6 CONCLUSIONS


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14.1 KEY POINTS AND SUMMARY As open hole completion’s, horizontal wells, multi-laterals and underbalanced drilling become more common place, greater emphasis is being placed on the selection and design of drilling and completion fluids. The problem of assessing fluid compatibility with hydrocarbon reservoirs is ongoing and usually unique to each reservoir. This problem becomes most visible after resources have been expended to drill, with unsatisfactory results in productivity.

The objective of this chapter is to present a process designed to use the best available methodologies and laboratory techniques to assist in the design and selection of fluids, which will be most compatible with the reservoir. Ultimately the goal is to drill zero skin wells. The process addresses fluid design issues from both a bridging or solid phase perspective and a liquid phase perspective. Optimization relative to design such as chemical selection and concentrations are an integral part of the process.

Using this process will reduce uncertainty regarding fluid selection and the impact of the fluids on productivity. Ultimately it is meant to assist in both increasing well productivity and reducing the requirement for expensive stimulation. The process may lead to innovation, resulting in new systems or products. It may be applied when designing workover and completion fluids or for drill-in fluids including overbalanced or underbalanced applications.

14.2 INTRODUCTION The potential to reduce wellbore productivity while conducting drilling completion and workover procedures has been addressed extensively in petroleum related literature. Productivity impairment was originally recognized in field cases where development wells produced only small volumes of fluid upon completion or where producing wells produced less after work-over procedures. In other instances, where drill stem tests taken while drilling deep wells indicated potentially good production from shallow zones, difficulty was experienced in attaining production from those zones which had remained in contact with drilling muds for an extended time.1

Investigations of specific damage mechanisms is an ongoing pursuit. Bates et al discussed the influence of clay content on water conductivity of oil sands in 1946.2 Nowak et al studied the effect of mud filtrates and mud particles on permeability in 1951.3 Various models which consider formation damage have quantifiable outputs such as Skin Effect,4 Productivity Index5 and Formation Damage Index Number.6 Methods of preventing formation damage continue to be tested, developed and documented.

A greater percentage of wells are now designed as open hole completions, where perforating past the damaged zone is impractical. Consequently sophistication in fluids testing procedures has increased and frequently operators test whole fluids against their rock. Often fluid samples are obtained from multiple sources. Return permeability tests7 are regularly used to select the “best” fluid. Unfortunately, if an adequate candidate isn’t found, the data are usually insufficient to redefine the direction testing should take. The process described herein helps to categorize and quantify discrete damage mechanisms. Fluid design is systematically optimized for all damage issues such that ultimately the fluid is compatible with the reservoir.

In actual practice the first line of defense against formation impairment is to keep foreign fluids and solids out of the rock. Thus, when drilling overbalanced, designing an efficient sealing cake or “bridging system”8 becomes essential. However the very nature of bridging systems denotes spurt loss associated invasion. Further, since the efficiency of any bridging system diminishes due to both mechanical degradation and through pore throat heterogeneity, only the effective design of the base fluid will provide assurance that the best overall fluid was chosen to drill the reservoir.


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14.3 ASSUMPTIONS

The focus when designing any fluid whether it is ROP, borehole stability or reservoir compatibility may be subordinated to other criteria such as cost, safety, environmental acceptability and operational feasibility. The process described in this paper functions independently from other design criteria, assuming they have been met and the net result is a safe, acceptable fluid. Further, the efficient execution of the process depends on the quality of the team implementing it. A cross-functional team or asset team should be assigned to the project. Representation should include geology, reservoir, geophysics, production, completions and drilling as well as special core analysis and drilling fluids expertise.

14.4 REVIEW OF FORMATION DAMAGE MECHANISMS

Common formation damage mechanisms have been categorized in different manners by various authors.9 They include:

14.4.1 Fluid - Fluid Interactions

Emulsion blocking - a viscous suspension of two immiscible fluids (usually oil and filtrate), which physically restricts flow. Drilling fluid components, particularly oil-wet ultra fines, or asphaltenes may stabilize emulsions.

Precipitates and Scales, are caused by incompatibilities between filtrates and connate fluids or by dissolution/precipitation of mineral grains. Some precipitates, which could cause physical plugging, include: CaSO4, CaCO3, CaF2, BaSO4, SrCO3, SrSO4.

Parrafins and Asphaltenes, especially associated with underbalanced drilling where the reductions in temperature and pressure associated with the production of crude oil result in asphaltic or waxy sludges being deposited on or in the near-wellbore pore throat system. Asphaltenes act as cationic particles with a potential to oil-wet rock. Mixing of incompatible oil-based filtrates with in-situ liquid hydrocarbons may also result in de-asphalting of the produced crude oil in some situations.

14.4.2 Fluid - Rock Incompatibilities

Migrating Clays - kaolinite has a tendency to shear away from pore throat walls and migrate and plug if interstitial velocities and electrolytic conditions are adverse (i.e., pH above 8.5 or low salinity). Other loosely attached in-situ clays or fines may also be susceptible to migration.

Swelling Clays - include smectites and mixed layer clay which expand when contacted by fresh or low salinity water-based filtrates.

Phase Trapping/Blocking - refers to adverse relative permeability effects associated with the retention of invaded aqueous or hydrocarbon fluids.

Chemical Adsorption/Wettability Alteration - some polymers in water-based fluids and surfactants in oil-based fluids are able to physically adsorb onto rock surfaces plugging pore throats (due to their large size) or altering wettability, substantially reducing permeability.


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Solids Invasion - when pulverized drilled solids or commercial solids (clays, weighting or bridging solids) become fine enough to enter into the pore throat system, permanent plugging can result.

Other damage mechanisms - include grinding and mashing of solids by the drill string, spontaneous counter current imbibition effects10 and glazing and surface damage effects caused by insufficient heat conductive capacity of circulating fluids.

14.5 THE PROCESS

A process is “a series of actions, changes or functions bringing about a result”. The steps are as follows:

Step 1. Identify the characteristics of the fluid-rock system.

Step 2. Postulate relative to the presence and severity of discrete impairment mechanisms.

Step 3. Validate and quantify the impairment mechanisms.

Step 4. Design and optimize to mitigate all impairment mechanisms.

Step 5. Design the bridging system if required.

Step 6. Test and select whole fluid.

A chart depicting the process is shown at the end of this paper (Figure 14.1).

IDENTIFY CHARACTERISTICS

OF THE ROCK - FLUID SYSTEM

POSTULATE ON IMPAIRMENT

MECHANISMS

VALIDATE IMPAIRMENT

MECHANISMS

DESIGN AND OPTIMIZE TO

MITIGATE IMPAIRMENT

MECHANISMS

DESIGN BRIDGING SYSTEM IF REQUIRED

TEST WHOLE FLUID

ROCK TYPERESERVOIR TYPE

DEPTHTEMPERATURE

PRESSUREPOROSITY

PERMEABILITYPORE THROAT SIZE

WETTABILITYSATURATION'S

SWELLING CLAYSMOBILE CLAYS

ACID GASMOBILE PARTICLESCOMPLETION TYPEHISTORY & OTHER

ISSUES

OIL-WATER TEST

PRECIPITATES

MIGRATING CLAYS

SWELLING CLAYS

PHASE TRAPPING / BLOCKING

WETTABILITY ALTERATION

SOLIDS INVASION

OIL - OIL TESTWATER-WATER TEST

CRITICAL VELOCITY TEST

CLAY SWELLING TEST

PHASE TRAP TEST

BEST DEMULSIFIER

BEST WAX, SCALE, ALKALINITY CONTROL

BEST CATION

BEST CATION OR POLYMER

BEST ALCOHOL, OIL, IFT REDUCERS

YBASE FLUID

Y

Y

CALCIUM CARBONATE

(ACID SOLUBLE)

SIZED SALT(WATER SOLUBLE)

SIZED RESIN(OIL SOLUBLE)

FIBER(FOR OIL WELLS)

THRESHOLD PRESSURE

REGAIN PERMEABILITY

LEAKOFF RATE

EFFECTIVENESS OF STIMULATION

THIN SECTION PETROGRAPHY

DENOTES SEVERITY OF SOLIDS INVASION

Y

Y

Y

Y

Y

Y

Y

Y

Y

WETTABILITY TESTAPI RP 42

REDESIGN IS POSSIBLE

YMODIFY SURFACTANT

PACKAGE

EMULSION BLOCKING

Figure 14.1 Fluid design flow chart

14.5.1 Step 1: Identify the Characteristics of the Fluid-Rock System.

The first step is to secure all available data relative to the reservoir. In producing fields, most of


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the data is often available; it’s just a matter of assembling it. This is usually the case when designing for horizontal wells. In some instances relatively inexpensive testing may be required to complement existing data. At this point the relevance or importance of data to the fluid system design may not be apparent. The following information should be assembled prior to commencement of step 2:

1. Reservoir rock type: limestone, dolomite, sandstone, and conglomerate.

2. Reservoir type: oil, heavy oil, gas, and gas condensate.

3. Depth: true vertical depth.

4. Temperature.

5. Pressure: from offset DST’s, AOF measurements or stabilized shut in pressures from offset wells.

6. Porosity/Permeability: charts should be available from routine core analysis done on close offset wells. Figure 14.2 provides a typical example of this.

1

10

100

1000

1 10 100

porosity (%)

per

mea

bili

ty (

md

)

Figure 14.2 Porosity verses permeability

7. Pore throat size curves are available from mercury injection capillary pressure analysis (Figure 14.3) or SEM analysis - which is possible to conduct using only a rock chip or drill cutting.


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8. Wettability analysis: USBM/AMOTT capillary pressure/wettability test. As shown in figure 14.4

9. In-situ fluid saturations: initial water saturation (Swi) and initial oil saturation (Swo) obtained from low invasion cores or accurate log analysis.

0

500

1000

1500

2000

0 50 100 150 200

EQUIVALENT SPHERICAL PORE THROAT RADIUS - MICRONS

Figure 14.3 Pore throat radius

-200

-150

-100

-50

0

50

100

150

200

0 0.2 0.4 0.6 0.8

Water Saturation (fraction)

Cap

illar

y P

ress

ure

(kP

a)

Sw IncreasingSw Decreasing

1.0

Figure 14.4 Wettability

10. Fluids analysis: both connate water and oil analysis are important in predicting incompatibilities. Often “synthetic” formation brine is used for laboratory compatibility testing if connate water isn’t available. Table 14.1 depicts a typical water analysis.


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Table 14.1 Typical water analysis

ION PPM

Na 39,600

K 225

Ca 1245

Mg 647

Ba 2.3

Sr 1.8

Fe 2.2

Cl 64,439

HCO3 220

CO3 23

SO4 1,100

11. In most reservoirs, especially sandstones, it is essential to quantify the presence of clay and other fine particulates. This is best achieved using one or a combination of X-Ray diffraction (XRD) - see Figure 14.5, scanning electron microscopy (SEM) and thin section petrography. XRD analysis is usually used first to detect and quantify the presence of clays because it is inexpensive. Studying thin section or SEM micrographs can facilitate more stringent investigation of the nature and association or condition of clay minerals or other particulates.

Figure14.5 SEM images of Clays

12. The presence of acid gas may dictate the need for specialized fluid ingredients such as scavengers, alkalinity additives or corrosion control products.

13. Knowing the reservoir history, completion / stimulation plan or other pertinent information may lead to alterations in fluid design. For example acid stimulation as a completion technique may not be an option if the well path is in close proximity to the water contact. This may reduce the benefit of using an acid soluble bridging system. Or if plans include running a wire-wrapped screen, a cellulose “matting system” might incorporate a carefully selected enzyme breaker to degrade the cellulose.


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14.5.2 Step 2: Postulate Relative to the Presence and Severity of Discrete Impairment

Mechanisms.

Once the characteristics of the reservoir have been assembled, the entire team can discuss the probability of specific damage mechanisms occurring. Assistance with this step may be acquired in a number of ways. Networking with other experts is often profitable. Wall charts such as Core lab’s “Formation Damage Assessment and Control chart”, SynerTech’s “Reservoir Sensitivities of Alberta Sandstone Formations” or tables such as Table 14.29 or Table 14.310 by Bennion et al are often helpful. At this point true consensus isn’t required because individual theories are tested at the next step.

TABLE 14.2 Potential Formation Damage Mechanism in Different Reservoir Types Damage

Mechanism Fluid-Fluid

Incompatibility Rock-Fluid

Incompatibility Solids

Invasion Phase

Trapping Chemical

Adsorption Fines

Migration Biological Damage

Effect of High Over-

balance Homogeneous Sand-Clean

POSS POSS POSS POSS POSS UNL POSS POSS

Homogeneous Sand-Dirty

POSS PROB POSS POSS PROB PROB POSS POSS

Laminated Sand-Clean

POSS POSS POSS POSS POSS UNL POSS POSS

Laminated Sand-Dirty

POSS PROB POSS POSS PROB PROB POSS POSS

Unconsolidated Sand

POSS POSS PROB UNL POSS POSS POSS PROB

Fractured Sand Permeable Matrix

POSS POSS PROB POSS POSS POSS POSS PROB

Fractured Sand Low Permeability Matrix

POSS UNL PROB POSS POSS UNL POSS PROB

Homogeneous Carbonate

PROB UNL POSS PROB POSS UNL POSS POSS

Fractured Carbonate Impermeable Matrix

PROB UNL PROB POSS UNL UNL POSS PROB

Fractured Carbonate Permeable Matrix

PROB UNL PROB POSS POSS UNL POSS PROB

Vugular Carbonate

PROB UNL PROB UNL UNL UNL POSS PROB

PROB Probable damage mechanism under most conditions

POSS Possible damage mechanism under specific conditions UNL Unlikely damage mechanism under majority of conditions


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Source: D. Brant Bennion, F. Brent Thomas, Douglas W. Bennion, Ronald F. Bietz: “Fluid Design to Minimize Invasive Damage in Horizontal Wells”, presented at the Canadian SPE/CIM/CANMET International Conference on Recent Advances in Horizontal Well Applications, March 20-23, 1994, Calgary, Canada, No. HWC94-71. TABLE 14.3 Initial Permeability to Air (mD)

Severity of Aqueous Phase Trap

Sw <10%

Sw 10-20%

Sw 20-30%

Sw 30-50%

Sw >50%

k < 0.1 mD Severe Severe Moderate Moderate Mild0.1 < k < 1 mD Severe Moderate Mild Mild Slight1 < k < 10 mD Severe Moderate Mild Slight Unlikely10 < k < 100 mD Moderate Mild Slight Unlikely Unlikely100 < k < 500 mD Mild Mild Unlikely Unlikely Unlikely500 mD+ Slight Unlikely Unlikely Unlikely Unlikely

Permeability reductions associated with definitions:

Severe = greater than 90% reduction in oil/gas permeability Moderate = 50-90% reduction in oil/gas permeability Mild - 20-50% reduction in oil/gas permeability Slight = 0-20% reduction in oil/gas permeability Unlikely - permeability reduction unusual

14.5.3 Step 3: Validate and Quantify the Impairment Mechanisms.

At this point samples of reservoir rock, oil, connate water and make-up water, can be collected for testing. When collecting oil and water it is essential to gather untreated samples. Often connate water must be synthesized - this is acceptable as extremely close replications are possible.

Most design programs incorporate “special” core analysis requiring small core plugs, usually 3.81 cm in diameter, 4-7.5 cm in length, to be cut from full diameter cores. Typically better quality rock is selected, since the majority of fluids will be produced from this rock. Careful selection and restoration of the plugs is a pre-requisite for effective special core analysis. Magnetic resonance imaging is a recommended technique for screening core plugs. This is because sandstone plugs with similar permeability and porosity may have markedly different internal characteristics including laminations and cross - bedding or they may even be impermeable on one side. MRI imaging of carbonate plugs clearly shows vugular hetrogenieties as well as the nature and length of the fractures within the plug.

Since preserved cores are seldom available, it is usually necessary to restore extracted core plugs to their original wettability and water/oil saturations. This procedure is conducted at reservoir temperature, using real reservoir fluids. This may require 6 – 8 weeks for oil reservoirs and somewhat less time for gas reservoirs. Therefore the project time line should be constructed to account for this restoration time.

Emulsion testing should be performed wherever there is a possibility of filtrate mixing with oil. API RP 42 is a simple procedure, which can be used in the lab or the field to test for emulsions. Water (25 ml) and oil (75 ml) are mixed together with fine solids and stirred at 14,000 RPM for 30 seconds. The emulsion is poured into a 100 ml cylinder and volumes of water breakout are recorded at various time intervals. This procedure is sometimes modified in that it is conducted at reservoir temperature and occasionally without the solids.


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Filtrate, Connate Water Compatibility Analysis should be conducted, if the water analysis indicates dissolved solids. This involves combining the two samples in equal proportions and raising the temperature to reservoir temperature while stirring slowly. If precipitates are not observed, the test should be continued by raising the pH with sodium hydroxide. Computer software is also available to conduct this type of work in an analytical fashion.

Oil - Oil Compatibility Testing should be done if an oil continuous fluid is a candidate for drilling. This test measures the particulate population when varying ratios of crude oil and base oil are combined. The objective of the test is to insure that the actual sum of the particulates in the combined fluid does not exceed the calculated sum. Typical test results are shown in Figure 14.6.

2000

2200

2400

2600

2800

3000

3200

3400

3600

3800

4000

0 50 100 150

P e rcent Oil 1 Mixed With Oil 2

Tot

al A

gg

rega

te S

olid

s in

S

yste

m (

mg)

Id e a l MixingS o l v e n c yE x c e s s P re c ip itate

Figure 14.6 Oil - Oil Compatibility

Clay Migration Testing, sometimes called a critical velocity test uses a small core plug, restored as previously described. The plug is mounted in a holder where reservoir conditions including stresses, temperatures and pressures may be simulated. In this test an inert fluid such as formation brine is passed through the core in a series of increasing velocities. The permeability to the fluid is measured at each flow rate. The critical velocity is that velocity where mobile fines such as bitumen or kaolinitic clays begin to dissociate or to shear off pore walls, plugging the pore throats. A change in permeability will occur at the critical velocity. The relative impact of this velocity on well productivity may be extrapolated by comparing rates of fluid leak-off in regain permeability tests or by calculating interstitial velocities at expected production rates. Figure 14.7 shows graphically the results of a critical velocity test.


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0 . 0 0 0 0

0 . 0 1 0 0

0 . 0 2 0 0

0 . 0 3 0 0

0 . 0 4 0 0

0 . 0 5 0 0

0 . 0 6 0 0

0 . 0 7 0 0

0 . 0 8 0 0

0.00

23

0.00

45

0.02

26

0.04

53

0.11

32

0.22

63

0.45

26

0.90

52

1.81

00

V e lo c i ty ( c m /s )

Per

mea

bilit

y (m

d)

C R I T I C A L

V E L O C I T Y

Figure 14.7 Clay velocity test

Clay Swelling Testing, uses a restored core plug mounted in a manner similar to that described for a critical velocity test. Baseline permeability to (usually saline) formation brine is established after several pore volumes have passed through the plug. Sensitivity to fresh water due to swelling clay is measured as a reduction in permeability when fresh or low salinity water is passed through the core. If the permeability hasn’t been shut off completely, the baseline permeability can usually be re-established by switching back to formation brine. This increase back to baseline permeability would indicate that dissolved salts are aggregating the hydrated clays - causing them to occupy less space in the pore throat system. Figure 10 graphically depicts typical clay swelling test results. Many types of clay can also deflocculate if electrostatic equilibrium, which is holding the clays bound in place are disrupted by, increases in pH or reduction in system salinity.

Phase Trap Testing 11 can quantify the relative permeability effects associated with the retention of water or oil. To do the test, a core plug is restored to its in-situ wettability and fluid saturation’s. In an aqueous phase trap test, the plug is restored to sub-irreducible water saturation. The plug is mounted in a core holder where reservoir conditions are simulated. Permeability to gas is measured. The plug is slowly injected with produced brine, establishing irreducible water saturation. Permeability to gas is then measured again, at pressure resembling the available drawdown at reservoir conditions. If the second permeability is lower, damage due to phase trapping alone has been quantified. Figure 14.8 shows the results of a phase trap test.


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-5

0

5

10

15

20

25

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Test Time

Per

mea

bili

ty

INITIAL CONDITIONS

EXPOSURE

TO BRINE

3500 kPa

70 kPa350 kPa

700 kPa

7000 kPa

Figure 14.8 Phase trap test

Wettability Testing may also be conducted after API RP 42 to insure that surfactant treatments leave the rock in their natural state. The procedure varies depending on whether the surfactant is water soluble or oil soluble. Since not all rocks will exhibit strongly water-wet or strongly oil-wet character, the results of this type of test may be difficult to interpret.

14.5.4 Step 4: Design & Optimize to Mitigate All Impairment Mechanisms.

The objective at this stage in the process is to select the two or three best available methods for mitigating each identified damage mechanism and test them against each other. Starting points relative to concentrations or properties should be based on experience. When one method is shown to be the best, the next step is to optimize the concentration. For example in the emulsion test previously described, if a stable emulsion is noted, the test should be repeated with different demulsifiers added to the filtrate before mixing. Once the most effective demulsifier is identified the concentration should be optimized in order to tell if more is better or if less is just as effective.

When dealing with precipitate problems the chemistry may be complex. It is often advisable to procure supplier expertise, however the same steps in the process apply.

Migrating clays can be controlled to a degree by controlling alkalinity, with the addition of certain polyvalent metal ions, and by controlling the rate at which fluids flow through the pore throat system - by enhancing fluid filtration control properties and by bringing the well on gradually during the production process.

Swelling clays can be controlled with certain cations or polymers. A clay swelling test may be extended to include flooding the core with one or more possible candidate clay stabilizers and charting the results as depicted in Figure 14.9. Note how the cation actually improves permeability by dehydrating the swelling clays. Again the object is to determine not only the best remedy, but also its most cost-effective concentration or application.


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0

0 . 0 5

0 .1

0 . 1 5

0 .2

0 . 2 5

0 .3

0 . 3 5

0 .4

0 1

2.1

3.1

7.1

8.2

8.6

14.2

23.9

27.4

29.3

32.3

P o r e V o l u m e

Per

mea

bilit

y

F O R M A T I O N

B R IN E3 % K C L F R E S H W A T E R

Figure 14.9 Typical clay swelling test

Phase trap mitigation may require the proper application of a surface tension reducing additive such as a surfactant or alcohol. In some instances of aqueous phase trapping, a base oil may offer the best results.

Wettability - if API RP 42 wettability testing indicates an adverse reaction to any surfactant such as a defoamer or torque reducer, testing should be conducted to determine a suitable replacement.

At the end of this step in the process the components of the candidate fluid(s) should be selected. In tight, complicated reservoirs the testing results may be less than what had been hoped for. This may lead to the selection of an alternate base fluid such as an oil or an alternate method such as underbalanced drilling. However the benefits of the study can be applied to underbalanced drilling or to future reservoir work, including EOR work.

14.5.5 Step 5: Design the Bridging System if Required.

When fluid contacts the formation there is a spurt loss of whole fluid, which continues until solid bridging particles block the pore throats. A properly designed filter cake has three basic layers.12 The primary bridge consists of large particles and is formed with the initial spurt loss. The secondary bridge is formed as smaller bridging solids mixed with colloidal particulates layer over the top of the primary bridge. The final seal is a polymer film.12 The construction of this thin, impermeable cake (less than 1.5 mm thick in properly designed fluids) proceeds rapidly as progressively smaller granular particles pack tightly into any remaining openings.In 1977 Abrams13 concluded that: “Muds that contain bridging material that meets the 1/3 rule for bridging impairs rock to depths less than 1 inch. The rule requires that the mud must contain bridging material with diameters greater or equal to 1/3 the formation median pore size at concentration levels of at least 5 % by volume of the mud solids. In 1980 Mahajan8 recognized that fluid loss polymers enhanced bridging efficiency and provided better return permeability in an HEC/sized carbonate fluid. He also pointed out that other work concluded that relative to HEC/calcium


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carbonate solutions the one third rule “might not hold.” The draw back to the rule is that it refers to median pore and particle sizes as opposed to distribution curves. In general broader distribution curves are most efficient.

Figure 14.10 shows the resolution attained when a pore throat size distribution curve is compared to a particle size distribution curve. The most efficient concentration of bridging solids will to a degree depend on how tight the reservoir is. Effective shut-off (i.e. no down hole losses) can be achieved with as little as 1.0% (w/w) sized carbonate. In more porous rock, up to 5.0% may be needed.

0

1000

2000

0 50 100 150 200

EQUIVALENT SPHERICAL PORE THROAT RADIUS -

MICRONS

0

1000

2000

0 50 100 150 200

PARTICLE SIZE MICRONS

Figure 14.10

Bridging on fractures is a more difficult matter. Loeppke et al14 studied bridging at the fracture face. Their data suggests that a slot (fracture) size:particle size ratio of 0.8 to 1.0 at a concentration of 1.5% - 4.5% w/w was efficient for bridging fracture faces. This pertained to blocky materials - where particle size means that 95% of the particles were less than that size.

Sharma15 recommended using low annular velocities to deposit cellulose fibers on fracture faces because fibers were more efficient than solid, blocky material. Tietard15 proposed a method of using real time LWD of natural fracture width to determine the best LCM particle size distribution.

The nature of the reservoir and the planned completion technique are what drives bridging system design. Sized carbonates are inexpensive and commonly used in both water and oil-based systems in all types of reservoirs where HCL treatments are possible to conduct. Close attention should be paid to the quality (ie. acid solubility) of the product. A disadvantage to using carbonates is that they are not soluble in formation fluids. Thus if fine particles are lost too far back into the formation during high loss periods, they may be beyond the reach of acid. Calcium carbonate is thermally stable and has a specific gravity of 2.7.


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Sized oil soluble resin particles are used in water-based systems for drilling both carbonate and sandstone oil reservoirs. Resin has an advantage in that it eventually dissolves even when carried back into the reservoir. Typical resin has a softening point of 162°C and a SGr of 1.02. The solubility of resin should always be tested using “live” crude from a close offset well.

Sized salt (NaCl) systems can be used in all reservoirs containing some connate water. They may be carried either in viscosified oil or in salt saturated water. Salt is thermally stable with a SG of 2.18.

Cellulosic fibers make extremely effective sealants. However fibers are only about 40% soluble in acid. Therefore caution is advised prior to use in fractured reservoirs or where a slotted liner will be run. Fiber cakes rely mainly on drawdown, requiring a physical push from formation fluids for removal. Therefore they may not be applicable in gas wells where drawdown is less than sufficient. Some suppliers are experimenting with enzymes, which “break” cellulose fibers.

Table 14.4 shows some bridging materials and their relative sizes while Table 14.5 depicts a bridging material selection chart.

TABLE 14.4 Bridging Materials and Their Relative Sizes PRODUCTS MICRONS

(minimum) MICRONS (maximum)

D50 MAX MESH

100 Mesh Resin 1 140 24 100

30 Mesh Resin 1 541 40 30

4 Mesh Resin 1 4760 4

Fine Salt 10 300 80 40

Medium Salt 100 1100 450 16

Coarse Salt 800 10000 3000 7/16”

Carbonate - Micro 1 22 3.5 325

Carbonate - 325 1 44 9 325

Carbonate - Bridgit XF 1 125 25 100

Carbonate - Fine grind 1 350 82 40

Carbonate - Zero grind 1 500 88 30

Carbonate - Supercal 88 840 451 20

Carbonate - Bridgit F 176 2000 506 10

Carbonate - Feed Grit 500 2000 1076 10

Carbonate - Poultry Grit 500 4760 1752 4

Carbonate - Bridgit M 480 4800 4

Carbonate - Bridgit C 3300 6300 1/4”

Carbonate - Bridgit XC 6300 9500 3/8”

Cellulose - Coarse 45 2000 354 10

Cellulose - Fine 2 353 70 40


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TABLE 14.5 Bridging Material Section Chart CaCO3 Resin Salt Cellulose Gas Well YES NO YES NO * Oil Well YES YES YES YES Sandstone YES YES YES YES Carbonate YES YES YES YES Acid Soluble YES NO NO PARTLY Water Soluble NO NO YES NO Oil Soluble NO YES NO NO Enzyme Cleanup NO NO NO YES Water-base Carrier YES YES YES YES Oil-base Carrier YES NO YES YES

* unless fairly prolific drawdown is available

14.5.6 Step 6: Choose & Test Whole Fluid

Choosing the whole fluid is a matter of combining the one or two best candidate bridging systems with one or two of the best base fluid candidates. Regain permeability testing is conducted using core plugs that have similar characteristics. The test involves mounting a restored core plug in a holder and applying overburden stresses at reservoir temperature. Baseline permeability to the oil or gas is established by flowing it in direction D1. Drilling fluid is then flowed across the face of the plug at overbalance pressure such that filtrate penetrates the plug in direction D2. The volume of fluid lost versus time is recorded and plotted. Finally, the flow of formation fluid is again directed through the plug in direction D1. The permeability is again calculated showing any reduction attributable to the mud. The results of these tests allow a quantifiable comparison of more than one drilling fluid system on the reservoir rock. Figure 13 shows a schematic of a typical apparatus used for reservoir condition overbalanced drilling fluid evaluations. There have been several important advancements in laboratory evaluation techniques recently17. They include:

1. Dynamic leak off testing where fluids are able to flow across the face of the core.

2. Full diameter and crossflow leak off apparatus, which provides up to 40 times the exposed cross sectional area for work on highly heterogeneous rock.

3. Techniques for artificially inducing fractures.

4. Apparatus to simulate underbalanced drilling.

5. Threshold pressure regain procedures - designed to determine both the point at which formation fluids initially penetrate the damaged rock and the permeability expected at the maximum expected drawdown gradient.

6. Pressure tapped cores, which allow for the evaluation of sectional permeabilities.

7. Spontaneous imbibition tests - designed to measure counter current imbibition of drilling fluid into the reservoir while maintaining underbalanced conditions.

Figure 14 shows a typical presentation of regain test results while Figure 15 indicates the rate and the calculated depth of fluid invasion into the core. Note the units on the y axis are converted to “field” units. After the test has been conducted, a simulated stimulation can be conducted on the plug. This might include an underbalanced acid wash or an acid squeeze. Saving the core for petrographic analysis after the test may indicate the actual depth of invasion of particulates or the dislocation of reservoir fines.


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Damage mechanisms which are difficult to simulate and test for include damage caused by:

1. Bacterial growth. (Long term testing required.)

2. Grinding and mashing of fines into near wellbore pore throats by drillstring rotation.

3. Glazing caused by inefficient heat removal.

14.6 CONCLUSIONS

1. A process has been presented which follows an analytical progression of information gathering, discussion, validation of theories and design optimization.

2. Technology is available to allow the process to focus on identification and design around discrete damage mechanisms.

3. Following the process will achieve the objective of assurance for all stakeholders that the best effort has been expended to secure a zero skin well.


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REFERENCES

1. P.H. Monaghan, R.A. Salathiel, B.E. Morgan, et al: Laboratory Studies of Formation Damage in Sands Containing Clays, Society of Petroleum Engineers (1959) No. 1162-G

2. T.G. Bates., Gruver, R.M. and Yuster, S.T.: “Influence of Clay Content on Water Conductivity of Oil Sands”, Oil Weekly (October 21, 1946) 48.

3. T.J. Nowak and R.F. Kreuger: “The Effect of Mud Filtrates and Mud Particles upon the Permeability of Cores”, Drill. and Prod. Proc. API (1951) 164.

4. A.F. Van Everdingen: “The Skin Effect and its Influence on Well Productivity”, Trans AIME Vol. 198 (1953) 171-176.

5. “Pseudosteady-State Flow Equation and Productivity Index for a Well With Noncircular Drainage Area”, Society of Petroleum Engineers (1978) No. 7108.

6. P.B. Basan, NL Erco: “Formation Damage Index Number: A Model for the Evaluation of Fluid Sensitivity in Shaly Sandstones” Society of Petroleum Engineers (1985) No. 14317.

7. D. Brant Bennion, F. Brent Thomas, Douglas W. Bennion: “Laboratory Coreflood Tests to Evaluate and Minimize Formation Damage in Horizontal Wells”, Presented at the Petroleum Society of CIM Horizontal Well Seminar - The Canadian Perspective, November 18, 1991, Calgary, Alberta, Canada.

8. Naresh C. Mahajan, Bruce M. Barron, Brinadd Company: “Bridging Particle Size Distribution: A Key Factor in Designing of Non-Damaging Completion Fluids”, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc., Society of Petroleum Engineers (1980) No. 8792.

9. D. Brant Bennion, F. Brent Thomas, Douglas W. Bennion, Ronald F. Bietz: “Fluid Design to Minimize Invasive Damage in Horizontal Wells”, presented at the Canadian SPE/CIM/CANMET International Conference on Recent Advances in Horizontal Well Applications, March 20-23, 1994, Calgary, Canada, No. HWC94-71.

10. D.B. Bennion and F.B. Thomas: “Underbalanced Drilling of Horizontal Wells: Does It Really Eliminate Formation Damage?”, Society of Petroleum Engineers, Inc., (1994) No. 27352.

11. D.B. Bennion, R.F. Bietz, F.B. Thomas, M.P. Cimolai: “Reductions in the Productivity of Oil and Low Permeability Gas Reservoirs Due to Aqueous Phase Trapping”, JCPT (Nov 1994, Volume 33. No. 9) JCPT94-09-05.

12. Brine-Add literature at http://www.brine-add.com.

13. A. Abrams, Shell Development Co.: “Mud Design to Minimize Rock Impairment Due to Particle Invasion”, Society of Petroleum Engineers (1977) No. 5713.

14. Loeppke, Gelan E., David A. Glowka, Elton K. Wright: “Design and Evaluation of Lost Circulation Materials for Severe Environments”, Society of Petroleum Engineers (1990) No. 18022.

15. Di Jiao and Mukul M. Sharma: “Mud Induced Formation Damage in Fractured Reservoirs”, Society of Petroleum Engineers, Inc., (1995) No. 30107.

16. Olivier Lietard, Tessa Unwin, Dominique Guillot and Mike Hodder: “Fracture Width LWD and Drilling Mud / LCM Selection Guidelines in Natural Fractured Reservoirs”, Society of Petroleum Engineers Inc., (1996) No. 36832.

17. D.B. Bennion, F.B. Thomas, R. Bietz and D.W. Bennion: “Advances in Laboratory Coreflow Evaluation to Minimize Formation Damage Concerns With Vertical / Horizontal Drilling Applications”, CADE/CAODC Spring Drilling Conference, April 19-21, 1995, No. 95-105.


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18. P.L. Churcher, Fred J. Yurkiw, Ron F. Bietz and D. Brant Bennion: “Properly Designed Underbalanced Drilling Fluids Can Limit Formation Damage”, Oil and Gas Journal, April 29, 1996.


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CHAPTER 15 CORROSION 15.1 KEY POINTS 15.2 CORROSION PROCESSES

15.2.1 Energy and Electrochemical Reactions 15.2.2 Corrosion Cells 15.2.3 Types of Corrosion 15.2.4 Drill Pipe

15.3 CORROSIVE ENVIRONMENTS IN DRILLING FLUIDS

15.3.1 Dissolved Oxygen 15.3.2 Dissolved Carbon Dioxide 15.3.3 Dissolved Hydrogen Sulfide

15.4 FACTORS WHICH INFLUENCE CORROSION RATES

15.4.1 Soluble Salts 15.4.2 pH 15.4.3 Temperature and Microorganisms

15.5 CORROSION DETECTION AND MONITORING

15.5.1 Corrosion Detection 15.5.2 Corrosion Monitoring 15.5.3 Determining the Cause

15.6 CORROSION INHIBITION

15.6.1 Mechanical Removal of Corrosive Gasses 15.6.2 Alkalinity and Filming Amines 15.6.3 Oxygen Scavengers 15.6.4 Carbon Dioxide Treatment 15.6.5 Hydrogen Sulfide Treatment 15.6.6 Oil-Based Fluids

15.7 MORE ON H2S

15.7.1 The Origin of H2S 15.7.2 Properties of H2S 15.7.3 Hydrogen Imbrittlement, SSC and Hydrogen Blistering 15.7.4 H2S Detection 15.7.5 H2S Treatment


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15.1 KEY POINTS AND SUMMARY Metals corrode because they are used in environments, which are chemically unstable. Only copper and the precious metals (gold, silver, platinum, etc.) are found in nature in their metallic state. All other metals, including iron (the metal most commonly used) are processed from minerals or ores into metals that are inherently unstable in their environments. Gold is the only metal which is thermodynamically stable at room temperature, in air. All other metals are unstable and have a tendency to revert to their more stable mineral forms. Some metals form protective ceramic films (passive films) on their surfaces and these prevent, or slow down, their corrosion. Stainless steel forms a passive film that is only about a dozen atoms thick, but this passive film is so protective that stainless steel is protected from corrosion. Using metals that form naturally protective passive films can prevent corrosion, but these alloys are usually expensive and other methods have been developed to control corrosion. Corrosion may be defined as the deterioration of a material usually a metal, as a result of a reaction with its environment. Energy must be added to the metal (smelting) in order for corrosion to occur. The more energy required to refine a metal, the greater its tendency to corrode. Corrosion usually occurs in environments containing water, CO2, O2 or H2S. In order for corrosion to proceed a complete electric current called a corrosion cell must exist. Several different types of corrosion commonly occur and affect drilling rig components. Corrosion rates may be accelerated if dissolved CO2, O2 or H2S exist in the Drilling Fluid. Other factors influencing the rate of corrosion include, salinity, pH, temperature and the presence of microorganisms. Various types of corrosion can be detected and monitored. Once a specific cause and rate have been identified, it becomes possible to take the correct remedial action to prevent further corrosion. An H2S environment is both extremely corrosive and dangerous to personnel. H2S can cause hydrogen imbrittlement, sulfide, stress cracking and hydrogen blistering. Methods of detecting and treating H2S should be familiar to Drilling Fluid Engineers. 15.2 CORROSION PROCESSES 15.2.1 Energy and Electrochemical Reactions To physically create a hole in the wall of a piece of pipe requires energy of some form, either mechanical or heat energy. Similarly, the corrosion process requires energy. Corrosion involves the reaction of a metal with its environment. Both the metal and the environment may supply the required energy. Stable metals such as oxides, carbonates and sulfides exist in nature. To change an ore into a more useful refined product requires an impartation of energy. There is a natural tendency for a refined metal to revert back to its lower energy level. This occurs through reaction with water, CO2, O2 or H2S and other components commonly found in nature. The tendency of a metal to corrode depends on how much energy was required to refine it. Highly refined alloys are subject to more rapid corrosion because they have more stored energy available to supply corrosion processes. Table 15.1 compares metals with corrosion tendencies.


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TABLE 15.1 ELECTROMOTIVE SERIES AND NERST POTENTIAL Refining Energy

Metal

Volts

Corrosion Potential

High energy

Potassium, K+

-2.92

Very eager to corrode

to refine to Sodium, Na+ -2.72 metal Magnesium, Mg++

Aluminum, Al+++ Zinc, Zn++ Iron, Fe++ Lead, Pb++ Copper, Cu++

-2.34 -1.67 -0.76 -0.44 -0.13 +0.34

Low energy Mercury, Ng++ +0.80 Least eager to required to Silver, Ag+ +0.80 Corrode - stable refine metal Gold, Au+ +1.68 Metal

During the corrosion process, energy is transferred between a metal and its environment by the displacement of electrons. Aqueous corrosion is an electrochemical process requiring a conductive solution such as water, or a salt solution. A complete electrical circuit must be formed. If a metal is placed in a solution of one of its salts the metal ions tend to pass into solution, leaving the metal negatively charged with respect to the solution. Only a small number of ions leave the metal and they are held close to the surface by its negative charge. The magnitude of the negative charge, the Nernst Potential, is a characteristic of the metal and the concentration of the salt solution. Table 15.1 lists the voltage, compared to a hydrogen electrode, of a number of metals. The order is known as the electromotive series. The metals with the high negative potential are very reactive and have a high tendency to ionize. For example, potassium metal reacts violently with water, zinc reacts with acid and gold is stable even in concentrated acids. Electrochemical cell

To create an electrochemical cell we need two metals with differing Nernst potentials. If we start with copper (+0.34) and zinc (-0.76), both metals undergo similar oxidation reactions:

Cu » Cu+2 + 2e-

and

Zn » Zn+2 + 2e-

The electrons freed by the oxidation reactions are consumed by reduction reactions.


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On the copper the reduction reaction is:

4H+ +O2 +4e- » 2H2O

The corrosion rate of the copper is limited by the amount of dissolved oxygen in acid.

On the zinc the reduction reaction is:

2H+ +2e- » H2

The hydrogen ions are converted to hydrogen gas molecules and can actually be seen bubbling off from the acid.

If we now connect the two metal samples with a wire and measure the electricity through the connecting wire, we find that one of the electrodes becomes different in potential than the other and that the corrosion rate of the copper decreases while the corrosion rate of the zinc increases. By connecting the two metals, we have made the copper a cathode in an electrochemical cell, and the zinc has become an anode. The accelerated corrosion of the zinc may be so much that all of the oxidation of the copper stops and it becomes protected from corrosion. This method of corrosion control is called cathodic protection.


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The reaction at the copper (cathode) becomes:

2H+ +2e- » H2

The voltage of the copper shifts to a point where hydrogen ion reduction can occur at the copper surface. The oxidation (corrosion) of the copper cathode may completely stop due to the electrical connection to the zinc anode.

The reaction at the zinc (anode) remains the same,

Zn » Zn+2 + 2e-

but the reaction rate increases due to the fact that the surface area of the clean (uncorroding) copper surface can now support a reduction reaction at a high rate.

Thus connecting these two metals virtually stopped the corrosion of the copper and increased the corrosion rate of the zinc. We say that the zinc cathodically protected the copper from corrosion. Cathodic protection is a common means of corrosion control.

15.2.2 Corrosion Cells The underlying principle of corrosion is that cations from a metal high in the series displace cations lower in the series. Thus zinc replaces hydrogen but silver will not. The corrosion process requires an electrical circuit to be constructed, which consists of four parts:


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The Anode is the point where the metal highest in the electromotive series, dissolves and goes into solution, often by an oxidation process that releases an electron and the metal ion. The equation for iron is:

Fe0 à Fe++ + 2e- Metal does not dissolve at the cathode although a chemical reaction does take place. If oxygen is absent hydrogen can be evolved:

2H+ + 2e- à H2 gas Or if oxygen is present in neutral or basic conditions:

O2 + 2H2O + 4e- à 4OH- A solution capable of conducting electricity is called an electrolyte. This is the third part of the circuit. Water is an example. Dissolved salts increase the conductivity of the solution. The anode and cathode must be connected by some means that will act as an electronic conductor, in order to complete the circuit. Drill pipe is a good example. Electrochemical activity is the fundamental cause of corrosion. Steel is primarily an alloy of iron and carbon, and on a microscopic level improperly mixed i.e. not homogeneous. In an aqueous environment iron carbide acts as the cathode, iron the anode, the steel conducts the electricity and water or drilling fluid acts as the electrolyte. All the components for an electrochemical cell are present, as illustrated in Figure 15.1. This reaction will cause what is termed general corrosion.


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Differential Aeration Cell Corrosion occurs when there is oxygen present and an obstruction present such as pipe scale, rust or barriers such as drill pipe protectors. The barrier generates a difference in the concentration of oxygen called a redox potential, which can cause current to flow and corrosion to proceed. The cell is illustrated in Figure 15.2.

On the surface of the pipe, where there is a higher concentration of oxygen, the ferrous ion in the rust (ferrous oxide) gives up an electron to form the ferric ion as follows:

Fe2+ à Fe3+ + e-


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and in the presence of oxygen the cathode reaction is:

O2 + 2H2O + 4e- à 4OH- The anodic reaction, of the iron metal, under the barrier is:

Fe0 à Fe2+ + 2e- The overall reaction forms ferric hydroxide:

4Fe2+ + 6H2O + 4e- à 4Fe(OH)3 The corrosion pits formed, result in pipe failure at a faster rate than generalized corrosion. To minimize this problem, rust (iron oxide) and scale should be removed from the pipe to prevent the barrier from forming. Oxygen levels in the fluid can be lowered by treatment with oxygen scavengers, which in turn will lower the redox potential. The pipe can be coated with a surfactant film, which will remove the electrolyte-water and salt. This treatment is often used when pulling the pipe out of the hole. 15.2.3 Types of Corrosion The destruction of metal can be caused by many separate mechanisms. Often several of these occur simultaneously. One type of corrosion may lead to another type. Understanding these mechanisms aids in the analysis and treatment of drill string and casing corrosion problems. Uniform Attack is a common form of corrosion. Here the entire surface of the pipe is

corroded evenly, resulting in a general thinning of the metal. Two Metal or Galvanic Corrosion occurs when two different types of metal are in close

contact. The metal with the most corrosion resistance becomes the cathode. The corrosion is usually localized near the point of contact. When this situation is unavoidable, a large anode should be used with a small cathode. Proper drill string design will minimize this type of corrosion.

Oxygen dissolved in drilling fluid initiates crevice corrosion in areas where the fluid is

stagnant. This includes shielded areas such as tool joints. Initially a cathodic reaction occurs where any dissolved oxygen reacts. When the oxygen is depleted the electrolytic nature of the fluid changes such that the surface of the crevice becomes an anode, where metal corrosion takes place.

Pitting Corrosion is the most destructive type of corrosion. It may occur in a crevice or

on a smooth metal surface. It occurs when the anode and cathode regions do not change position on the metal surface. Each pit represents a part of the metal surface where an anodic reaction has occurred. Pits can eventually become deep cracks, leading to unequal stress distribution along the drill string. Environments which promote pitting include; high-velocity, moderate salinity, low pH and aeration.


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Figure 15.3 Corrosion pitting in steel

Metal is attacked preferentially along the grain boundaries. This type of attack is called

intergranular corrosion. Improper heat treatment of alloys, or high temperature exposure such as welding may cause precipitation of metal constituents. This results in a discontinuous grain boundary, where corrosion rates are accelerated.

The combination of corrosion and the abrasive action of drilling fluids causes increased

corrosion rates in localized areas. This is termed erosion corrosion. This type of attack is likely to occur on the inside of the drill string, where fluid velocities are high. The result is a washout or hole in the drill string. The use of inhibitors can often reduce this form of corrosion.

Selective leaching corrosion occurs in alloys. It results from the oxidative removal of

one elemental metal from the solid alloy, while the less reactive metal remains. An example is the selective corrosion of zinc in brass.

Cavitation corrosion usually occurs in pumps. Pulsative pressures cause vaporization in

the fluid. The formation and collapse of bubbles at the metal surface results in a sponge-like appearance with deep surface pits. Cavitation corrosion can be minimized if adequate feed head is maintained.

Corrosion due to variances in fluid flow rates is often common where turbulent flow is used. The result is usually localized, resulting from the combined affects of corrosion and erosion. The variation in fluid flow may also cause variations in concentrations of corrodants and depolarizers resulting in a more selective attack of metals.

Stress corrosion and cracking of drill pipe results from the combined effects of the fluid

environment and the stresses on the metal. Stress cracking can occur in most alloys although the corrodants may vary with different alloys. Drill pipe is subject to stresses described as static and cyclic. The static stress is caused by the tension on the pipe in the drilling mode due to drill string support. Rotation causes cyclic stresses, which can lead to failure in the form of fatigue cracks. Notches, pits and other irregularities on the surface and tool joints are where these cracks are initiated. They can be detected under UV light.


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Figure 15.4 Stress cracks in steel

The time to failure is reduced by an increase in the concentrations of specific corrodants, an increase in stress and an increase in the hardness and strength of the steel. Stress cracking produces a network of cracks, which penetrate the metal at right angles to the tensile stress. The deepest part of the crack or the point of greatest stress is anodic towards the wider cathodic part of the crack as shown in Figure 15.4. This means that any metal that goes into solution or corrodes will do so from the deepest part of the crack, making the crack still deeper. Thus cyclic bending of the pipe and the corrosivity of the drilling fluid combine to accelerate the rate at which the crack will propagate and cause eventual failure.

Hydrogen Imbrittlement is caused by the entrapment of atomic hydrogen within the

crystal structure of the steel. This causes the steel to lose tensile strength and ductility. Time to failure by hydrogen imbrittlement is increased with H2S concentration, stress and strength and hardness of the steel.

Hydrogen can also cause Hydrogen Blistering. Hydrogen atoms form hydrogen

molecules (gas) at defective points in the steel. This may cause blistering, which appears as bumps on the metal surface. The hydrogen gas cannot penetrate the crystal structure of the steel. As the pressure of the gas increases, the metal may part - resulting in a blister on the surface.

15.2.4 Drill Pipe Pure iron is both ductile and fairly weak. To improve its strength, 0.2 - 1.0% carbon is incorporated into the iron to form the alloy steel. This results in a much harder material, however it is not often completely homogeneous. Areas exist where the metal consists of pure iron (Fe0) while other areas consist of iron carbide (Fe3C). The essentially different materials are two of the components required to establish a corrosion cell - discussed previously. Corrosion in oil well drill pipe is subject to and controlled by both chemical and mechanical influences. Chemical influences include dissolved gasses, electrolytes, pH and temperature. The mechanical influences include stress, strained areas and the number of cycle loadings. Every metal has a stress limit, above which there is no rebound of the metal. Each metal type has a different yield or tensile strength. However, if metals are cyclically stressed than they can fail at stresses far below this yield strength. There is a bottom limit, called the endurance limit, below which failure will not occur even if stressed cyclically for indefinite periods. Generally, this endurance limit is 40 - 60% of the yield strength with the harder steels having higher yield strengths and therefore, higher endurance limits.


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A historical approach to fatigue damage should always be considered. A piece of metal can be regarded as having a useful life of x number of hours at a given stress. As this limit approaches the pipe should be replaced. If a pipe is successfully taken from hard service and put then into lesser service conditions but above the endurance limit, failure will still occur when the time limit runs out. If a corrosive environment is also present, then the fatigue life of a metal is substantially reduced. This combination of cyclical stress and corrosion effects is known as corrosion fatigue and is most likely to cause a drastic failure than anything else. Because pitting can cause a more rapid failure than overall corrosion, it should be regarded as a condition to avoid. A strained area such as a hammer dent or an indentation left by a pipe wrench corrodes at an accelerated rate. This is because the strained area is anodic to surrounding unstrained areas. The drill pipe slip area is subjected to more cycle loading than the pin area or the center of the tube. When a connection is made, pipe is pulled from fluid into air. A film (less than 50 Å) of Fe(OH)2 or Fe(OH)3 is formed on the exposed surface, except where the slip dies contact the tube. When drilling is resumed, the surface coated with the iron hydroxide film becomes cathodic to the small slip contact area. Highly localized corrosion is initiated at these points. Usually the tool joint shields the slip contact area from any wiping action, which would lessen the affect. Joints above the drill collars are subjected to the most adverse stresses and bending moments. Tool joints and drill collars decrease the wiping affect and the oxygen supply is greater than it is further up the annulus. Several techniques have been used to reduce drill pipe failure. These include: Plastic Coating Regular Inspection Programs Design of Solid Master Bushing & Long Slips pH Adjustment Inhibiting Chemicals 15.3 CORROSIVE ENVIRONMENTS IN DRILLING FLUIDS Oxygen, carbon dioxide, and/or hydrogen sulfide are the primary cause of most oilfield corrosion problems. If these gasses could be eliminated from drilling fluids, most corrosion problems could be effectively controlled. Figure 15.5 denotes the comparative corrosiveness of these gasses.


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Figure 15.5 Comparative corrosiveness of three common gases in water solutions

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PPM gas in water (O 2x1, CO2x50, H2Sx100)

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l (M

PY

)

15.3.1 Dissolved Oxygen Oxygen is the most adverse of the three gasses in that it is the most prevalent and it can be damaging at concentrations of less than 1 mg/L. Dissolved oxygen is the major cause of drill pipe corrosion. The reactions at the anode are called oxidation reactions. This means that electrons are being lost. In the following equation, iron (Fe0) atoms lose two electrons to form ferrous ions (Fe2+):

Fe0 à Fe2+ + 2e- Therefore the iron atoms are said to be oxidized. The Fe2+ ions can be oxidized still further. If dissolved oxygen is present, the Fe2+ ions are oxidized to Fe3+ giving up electrons to form iron oxide or rust:

2 Fe2+ + 1.5 O2 à Fe2O3 (rust) In both the equations above, oxidation of iron is occurring because the iron is losing electrons. Combining the anodic equation and the cathodic (O2) equation: Anode: Fe0 à Fe2+ + 2e- Cathode: O2 + 2H2O + 4e- à 4OH- Combining: 4Fe0 + 6H2O + 3O2 à 4Fe(OH)3 Above pH 4.0, ferric hydroxide is insoluble and precipitates as shown in the equation. Oxygen corrosion is often evidenced in the form of pitting, because a differential aeration cell is formed.


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Oxygen accelerates corrosion in two ways. Firstly it acts as a depolarizer by removing electrons - accepting hydrogen ions at the cathode. This allows the reaction to proceed quickly. The rate is influenced by the rate at which the oxygen can diffuse to the cathode. Secondly, the oxidation of ferrous (Fe2+) ions to ferric (Fe3+) ions causes the reaction to speed up if the pH is above 4.0. This is because the ferric hydroxide is precipitated above pH 4.0, removing iron ions from solution. The cathodic reaction speeds up because of the disturbance in the equilibrium by the removal of iron. At very high levels of oxygen the precipitate of ferrous hydroxide can form at the surface forming a protective film. Flocculated systems often maintain a constant high level of oxygen as long as they are circulated. Deflocculated systems containing concentrations of lignosulfonate or lignite contain significantly lower oxygen levels because of their oxygen scavenging ability. Oil-based systems usually contain only insignificant quantities of dissolved oxygen. 15.3.2 Dissolved Carbon Dioxide Carbon dioxide is present in most formation fluids as a component of formation gases and in solution in water and oil. When carbon dioxide dissolves in a solvent, it forms carbonic acid, decreasing the pH of the solvent and increasing its corrosiveness. A mixture of carbon dioxide and oxygen is more corrosive than oxygen alone. Carbon dioxide is more soluble than oxygen. Corrosion resulting from carbon dioxide is usually evidenced as pitting. The amount of CO2 available in a solution is a function of pH. When CO2 is encountered, the usual procedure is to add sodium hydroxide to maintain the pH at 9.0-10.0. This prevents carbonic acid from forming by:

CO2 + H2O à H2CO3

H2CO3 à H+ + HCO3-

HCO3

- à H+ + CO32-

When massive amounts of CO2 are encountered calcium hydroxide may be required to neutralize the acid. The resulting calcium carbonate precipitate tends to form scales - setting up corrosion cells. This tendency may be offset with the proper use of scale inhibitors and by stripping and washing the pipe during trips. Degassers must be used when drilling CO2 generating formations. Sodium hydroxide and lime react with carbon dioxide as follows:

2NaOH + CO2 + H2O à Na2CO3 + 2H2O

Ca(OH) 2 + CO2 + H2O à CaCO3 + 2H2O


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15.3.3 Dissolved Hydrogen Sulfide Hydrogen sulfide is very soluble in water and dissolves to form a weak acid. This reacts with iron to form iron sulfides, manifested as black deposits on the pipe:

H2S + Fe2+ à FeS + 2H+ Hydrogen ions may enter the steel instead of evolving at the surface. This results in hydrogen embrittlement. The combination of H2S and CO2 is more aggressive than H2S alone. Small quantities of O2 in the presence of H2S can be disastrous. H2S corrosion is discussed in greater detail at the end of this chapter. 15.4 FACTORS THAT INFLUENCE CORROSION RATES 15.4.1 Soluble Salts Salt water systems are usually conducive to higher corrosion rates. However at neutral pH, salts are not primary corroding materials. Dissolved salts usually accelerate corrosion rates if one of the three corrosive gasses is present. The main effect is a reduction in electrical resistance of the electrolyte. In low resistivity solutes, current flow is greater and anodic and cathodic areas can interact at greater distances. This promotes increased corrosion rates. Increasing the salt concentration reduces the solubility of dissolved gasses such as oxygen. Figure 15.6 shows the effect of increasing the salt concentration in aerated water. At a certain concentration the corrosion rate begins to decrease until it is eventually below that of distilled water.

Figure 15.6 Corrosion rates of carbon steel in aerated salt water

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0 3.5 6 10

Dissolved salt concentration % by wt

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Different types of salt can influence corrosion rates. Alkaline salts such as sodium carbonate, trisodium phosphate and sodium silicate may act as corrosion inhibitors. Acid salts such as aluminum chloride and magnesium chloride cause corrosion at rates similar to other acids at the same pH. Alkali metal salts such as sodium sulfate or potassium bromide affect the corrosion rate in a similar manner as NaCl or KCI. Alkaline earth salts such as calcium chloride are slightly less corrosive than alkali metal salts. 15.4.2 pH Corrosion rates are strongly affected by pH values. Figure 15.7 shows the affect of pH on oxygen corrosion rates. In general oxygen corrosion decreases with an increase in pH up to about pH 12.0, then increases above that. Maintaining an alkaline pH environment reduces the solubility of hydrogen sulfide. Alkaline pH values also prevent dissolved carbon dioxide from reverting to carbonic acid.

Figure 15.7 The effect on the corrosion rate

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15.4.3 Temperature and Microorganisms In general a region of higher temperature becomes anodic to a region of lower temperature if a more powerful influence is absent. An overall increase in temperature usually increases general corrosion rates, although the tendency for steel to crack decreases at higher temperatures. High temperature treatments can remove hydrogen from steel - actually restoring the original properties to the steel. Several species of bacteria exist in water-based drilling fluids. These contribute to increased corrosion rates by forming patches of slime under which differential aeration cells may be established. The most severe bacteria-related corrosion problems result from H2S generated by sulfate-reducing bacteria (SRB). These are discussed in greater detail at the end of this chapter.


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15.5 CORROSION DETECTION AND MONITORING 15.5.1 Detection and Detection Devices Evidence that corrosion is occurring is often detected initially by visually examining damaged equipment. The equipment may be broken, cracked, pitted or visibly worn. Usually there are residues of corrosion reaction products on the surface. Several methods are used in an attempt to detect corrosion before it becomes visibly noticeable. These include ultra violet pipe inspection, wall thickness and internal diameter calipers, ultrasonic thickness gauges and radiographic imaging. 15.5.2 Corrosion Monitoring Apart from measuring material loss on pipe and equipment using the aforementioned methods, the drilling industry uses two techniques for monitoring corrosion while drilling is underway. These are: 1. Monitoring the fluid environment for materials that promote accelerated corrosion.

These include low pH and O2, CO2 and H2S gas concentrations. 2. Monitoring the relative corrosiveness of drilling fluids with sensors and devices,

and assuming equipment corrosion rates are proportional.

The first technique is relatively straight foreword. The system pH is monitored regularly. An abnormal decrease in pH usually denotes an influx of foreign material into the wellbore. If CO2 or H2S is suspected, concentrations may be measured using a Garrett Gas Train and appropriate action may be taken. H2S is often monitored using a specific ion electrode. Measuring and maintaining a concentration of excess oxygen scavenger in the fluid most easily monitors entrained oxygen levels. There are several devices being marketed that measure or extrapolate corrosion rates while drilling proceeds. The most common are: 1. Galvanic probes. These detect changes in corrosivity as a function of current

flow between dissimilar metal electrodes. 2. Corrosion coupons. These exhibit weight loss, pitting, scales and hydrogen

embrittlement.

Galvanic probes are usually steel and brass mounted on a threaded plug. When the rods are immersed in an aerated saline solution, the dissimilar metal couple generates a small electrical current. The current varies in strength with the amount of oxygen present. Corrosion coupons or rings are more reliable than galvanic probes. The rings are usually made from AISI 4130 composition steel. They are coated on three sides with plastic. This prevents galvanic corrosion between the ring and the pipe from occurring. The inside surface is exposed to the drilling fluid. Each ring has a unique identification number and an information record sheet. The record sheet should be filled out prior to installing the ring and after it is removed.


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Usually 2 rings are run simultaneously. One is placed in the saver sub and the other is located above the drill collars. The ring should be installed bevel-down, with clean, dry gloves. Care should be taken to insure the pipe is clean in order to prevent interferences with joint make-up and / or damage to the ring. The ring should remain in the string for around 90 hours in order to obtain the best results. When the ring is removed from the drill string it should be wiped dry with a clean cloth. The ring should be immediately coated with oil or grease and placed in the plastic bag provided. Coating the ring with pipe dope may initiate galvanic corrosion. In the lab the ring is cleaned and weighed. The rate of corrosion is usually reported in mils per year (mpy). Various operators have different ideas about what an acceptable value is, although 25 mpy is usually considered tolerable. The ring is observed for the presence of scales and pitting. Hydrogen embrittlement is also tested. These conversion factors apply to 7.86 S.G. steel. Kg/m2/yr = mpy X 0.20 #/Ft2/yr = mpy X 0.04 15.5.3 Determining the Cause Where drill pipe and drill collar rejections and failures occur at a higher-than-average rate, steps must be taken to determine the cause or combination of causes of corrosion. The first step is usually to perform an in-depth analysis of drilling fluid chemistry. Often the cause is obvious. Improper adjustment of pH, or an insufficient oxygen scavenger concentration can be alleviated quickly. Alkalinity analysis may indicate an H2S or CO2 intrusion. These can be verified by using other procedures such as the HACH test or Garret Gas Train tests or hydrogen embrittlement tests. Corrosion coupon analysis is often the most reliable method of determining the cause. Tests on corrosion scale deposits can provide helpful information when analyzing corrosion problems. The scale forms on the surface of the metals as corrosion occurs. The best source for this scale is from the surface of the corrosion rings used in determining the corrosion rate. These tests should be a routine part of the analysis of corrosion rings. If handled properly the rings should contain only freshly deposited scale. Any scale obtained from the drill string should be suspect since it could easily come from old deposits formed during storage or with previous use on other wells. However if instant, on-sight analysis is required scales can sometimes be removed from the drill bit. The three major types of corrosion deposits, iron oxides, iron carbonates and iron sulfides can be distinguished by their dissolution in 15% hydrochloric acid solution. By using this test along with additional observations, these three types of scale can be identified. The usual procedure is to drop about 1.0 cm3 of the scale deposit into the acid solution. Dissolved oxygen can react with corroded iron to form various iron oxides. Iron oxide scales can dissolve in 15% HCl without the evolution of a gas or detectable anion. Some forms of iron oxides will have only limited solubility. Millscale (Fe3O4) may not dissolve at all, but will usually be attracted to a magnet. The only observation is the formation of a yellowish solution (this color will also occur with the other iron scales).


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The sulfide ion, reacts with corroded / dissolved iron to form iron sulfides (FeS). Iron sulfides readily dissolve in 15% HCL with the evolution of free hydrogen sulfide. When this occurs a faint smell of hydrogen sulfide (rotten eggs) is evident - this gas is very toxic. H2S gas can be detected by placing a dampened lead acetate paper just above the surface of the reaction. The paper should turn dark. If some doubt exists after a short time, either dip part of the paper just under the surface of the reaction, or draw the gas into an H2S Dräger Tube. When FeS is present, the original scale sample usually turns black. Carbon dioxide dissolves in a basic drilling fluid to form carbonate or bicarbonate anions depending on pH. The anions react with corroded iron to form various iron carbonate and iron bicarbonate scales. When these scales are dissolved in 15% HCl they will readily evolve effervescent carbon dioxide gas. This gas will be odorless and not change color of the Hach paper. If doubt exists regarding the nature of the gas, draw it into a CO2 Dräger tube and observe the results. An alternative test for the detection of iron sulfide scales involves the direct application of a solution of sodium arsenite to the scale covered steel surface. The presence of iron sulfide scale is confirmed by the formation of a bright yellow precipitate on the surface. Disregard a clear yellow color with no precipitate. Table 15.2 lists some observations, which may lead to the probable cause of equipment failure. TABLE 15.2 CORROSION PIT TROUBLESHOOTING CHART APPEARANCE

SOURCE

CORROSION BI-PRODUCT

TEST

TREATMENT

Worn or abraded areas with numerous small pits

Erosion by metal or solids in an H2S, O2, or CO2 environment

Visual

Reduce fluid velocity or solids content. Install pipe protectors

Rust Deposits - Shallow widespread pitting or deep pits under rust nodules

Oxygen from water additions, or aerated Drilling Fluid

Iron Oxides Rapid depletion of O2 scavenger. Scales semi-soluble in 15% HCl. Scales attracted to magnet.

Increase sulfite additions, add scale inhibitor or filming amines if required. Eliminate air entrapment use Defoamer as required.

Round bottom connecting pits with sharp sides. Some grey deposits but pit bottoms are bright

Carbon Dioxide Attach

Iron Carbonates or Calcium Carbonates

Effervescence in 15% HCl.

Maintain basic pH with Caustic Soda to neutralize acid gas.


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APPEARANCE

SOURCE

CORROSION BI-PRODUCT

TEST

TREATMENT

Small conical pits with steep sides and smooth edges. Pits filled with black deposit.

Hydrogen Sulfide attack

Iron Sulfides Effervescence in 15% HCl with emission of H2S. Sodium Arsenite solution causes bright yellow precipitate. Dark film on exposed equipment

Raise pH. Precipitate Sulfides with suitable metal compounds.

15.6 CORROSION INHIBITION The main objective when controlling corrosion is to slow down the corrosion process such that equipment is protected economically during its useful life. Any measure that eliminates one of the four electro-chemical processes of corrosion will prevent corrosion. Therefore if either the anodic oxidation, the cathodic reduction, the transport of ions in the electrolyte or the conduction of electrons between electrodes is prevented the corrosion stops. The petroleum industry uses many methods and combinations of methods to achieve this, including the following: 1. Mechanical removal of corrosive gasses. 2. Chemical treatments. 3. Plastic pipe and pipe lining. 4. Special alloys. 5. Reduction in temperature and velocity. 6. Cathodic protection. Drilling fluids properties are expected to make contributions to the characteristics of the first two methods. Drilling fluids corrosion is treated three ways: 1. Mechanical removal of corrosive gasses. 2. General treatment that aids in the prevention of all types of corrosion. 3. Specific treatments for the inhibition of corrosion resulting from individual

materials.

15.6.1 Mechanical Removal of Corrosive Gasses It has been pointed out that most corrosion in the petroleum industry can be traced to the presence of oxygen, carbon dioxide and hydrogen sulfide. At surface, where the pressure is limited to atmospheric pressure these gasses may be entrained rather than dissolved. The first line of defense is to prevent the intrusion of these gasses. When dealing with H2S and CO2, this is often possible by densifying the drilling fluid to a point where the intrusion is controlled. However, in the case of a slow influx, it is not always possible to detect such an intrusion instantly. If an H2S intrusion is due to sulfate reducing bacteria, using a biocide and increasing the pH can eliminate the problem chemically.


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Unfortunately oxygen is the most common contributor to corrosion. The oxygen source is never attributed to down hole mechanisms or rock formations. It is introduced to a fluid partly through the make-up water, and most often air entrained due to agitation at surface. In severe situations foaming may impede the ability to pump the fluid. Surface agitation and air entrainment can occur at virtually any point in the surface circulating system where the fluid is in motion. Sources often include fluid vortexing above agitators, solids equipment discharge and especially mixing hopper discharge. Often it is necessary to shut down hoppers when they aren't in use and fabricate the discharge such that it is under the surface of the fluid in the pits. Chemical defoamers are usually effective in reducing air entrainment. Mechanical degassers are able to remove any type of entrained gas. Several varieties exist including centrifugal, vacuum and stripping (poorboy) degassers. Degassers should be the first piece of equipment down-stream of the sand trap. In severe situations poorboy degassers may be installed at solids equipment discharge points. 15.6.2 Alkalinity and Filming Amines (General Treatment) The proper maintenance of pH is the first line of defense against corrosion. Alkaline environments can inhibit chemical reactions, electro-chemical corrosion and hydrogen damage. In acidic environments hydrogen ions can directly attack steel. The potential for hydrogen embrittlement remains high in such an environment. Dissolved carbon dioxide and the resultant carbonic acid can corrode steel at an increased rate in a weakly basic environment. Likewise hydrogen sulfide causes corrosion in weakly acidic conditions. Maintaining a fairly strong basic environment will minimize these types of corrosion. At pH 9 or above, hydrogen ions are effectively neutralized and free carbon dioxide, carbonic acid and hydrogen sulfide will not exist, although carbonate and sulfide ions will remain in solution. The time required for pipe failure in the presence of sulfide ions at this range can be many times longer than when hydrogen sulfide is present in an acidic environment. The corrosion cells formed on steel surfaces generate areas of positive and negative charge at the anode and cathode respectively. Positively charged surfactants (cationic amines) absorb on the cathode and reduce the rate of reaction. Film forming inhibitors do not find general application in drilling fluids because they are also absorbed on clays. They do, however, have application in completion brines and packer fluids. Another good application is to use the concentrated inhibitor as a slug treatment prior to pulling the pipe. This coats the pipe so that the corrosion rate is reduced while the pipe is racked in the derrick. 15.6.3 Oxygen Scavengers Excessive levels of oxygen can be reduced by the addition of a suitable scavenger such as sodium sulfite or ammonium sulfite. Without oxygen dissolved in the drilling fluid, the cathodic reactions can be minimized. Sulfite reacts with oxygen to form sulfates:

O2 + 2Na2SO3 à 2NaSO4 Pumping the oxygen scavenger into the pump suction line best makes treatment. Treatment levels are dependent on the type of inhibitor - which may contain a catalyst to increase the rate of reaction. Lignosulfonate and lignite are susceptible to oxidation reactions. They act as effective oxygen scavengers. These chemicals when combined with a high pH will impart lower corrosion rates to most water-based systems. An excess sulfite concentration of 200-300 mg/L is recommended for most situations.


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15.6.4 Carbon Dioxide Treatment An influx of CO2 gas will decrease the pH and increase carbonate and bicarbonate species in the fluid. To combat CO2, the pH should be maintained and the resulting contaminants removed. The addition of lime, Ca(OH) 2, will raise the pH and precipitate carbonates and bicarbonate as calcium carbonate: Ca(OH) 2 + H2O + CO2 à 2H2O + CaCO3 ppt Treatment with caustic causes the following reaction: 2NaOH + CO2 + H2O à? 2H2O + NaCO3 The reaction with caustic may cause rheology problems if excessive amounts of NaCO3 are formed. 15.6.5 Hydrogen Sulfide Treatment When hydrogen sulfide is expected, chemical pre-treatments should be made. Increasing the pH will surpress the solubility of most sulfide species. If the problem stems from sulfate reducing bacteria a suitable bacteriacide should be added to the system. Smaller levels of H2S are effectively treated with zinc carbonate. 15.6.6 Oil-Based Fluids The continuous oil phase, assisted by oil wetting surfactants, eliminates the electrolyte such that corrosive reactions cannot take place. Oil-based fluids can be used in particularly hostile corrosive environments such as high temperature, oxygen, and carbon dioxide. This may be crucial in deep wells where the mechanical stresses on the drill string are high. Oil based fluids also provide a non-corrosive packer fluid. 15.7 MORE ON H2S Considerable attention has been devoted to the subject of hydrogen sulfide dangers during drilling, completion and workover operations. Hydrogen sulfide can be dangerous to personnel, cause failure of drill pipe (fig 15.8) and tubular goods, and the destruction of testing tools and wire lines. Less severe problems include the incompatibility of hydrogen sulfide and drilling fluids and the obscurement of test results for other ions contained in drilling fluid filtrates, which are important to successful drilling practices.

Figure 15.8


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15.7.1 The Origin of Hydrogen Sulfide Hydrogen sulfide may enter the drilling fluid system from formation fluids containing H2S, from bacterial action on sulfur compounds commonly present in the drilling fluid, from thermal degradation of sulfur containing drilling fluid additives (such as lignosulfonates), or from chemical reactions with tool joint thread lubricants that contain sulfur. The most common sulfide producing bacteria species is called Desulfobvibrio. They reduce sulfates present in the drilling fluid to form hydrogen sulfide by reacting with cathodic hydrogen in the following manner: SO4

2-+ 10H- à H2S + 4H2O These species are completely anaerobic. H2S may also be generated by species of the genus Clostridia. These species are thermophilic, meaning they favor elevated temperatures. 15.7.2 Properties of H2S Hydrogen Sulfide is a colorless gas, with a rotten egg odor and a sweetish taste. Hydrogen sulfide is soluble in water, alcohol, oil and many other solvents. It has a specific gravity of 1.19 with reference to air. It burns with a blue flame and produces sulfur dioxide, which is a gas that has a very irritating effect on the eyes and lungs. Hydrogen sulfide is considered a weak acid and it is extremely toxic to humans and corrosive to metals. Hydrogen sulfide ionizes in two stages: HS- + OH- à S2- + H2O These reversible reactions are a function of pH as shown in figure 15.9. Note that the sulfide is in the form of H2S up to about pH 6.0 as HS- from pH 8.0 – 11.0, and as S2- above pH 12.0. This ionization scheme is important and must be considered when planning an approach to combating hydrogen sulfide in drilling fluids.

Figure 15.9 Equilibrium of the aqueous system, H2S, HS-

& S2- with relative concentrations versus pH.

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The most harmful form as far as toxicity to humans is concerned is the molecular hydrogen sulfide in the gaseous state. When in the gaseous form, Hydrogen Sulfide can escape from fluids and being heavier than air, will collect around the working area of a rig - often causing sickness and death. Hydrogen cracking of metals has been related to the first ionization step of hydrogen sulfide, H2S à H+ + HS- The atomic hydrogen absorbs into the crystal lattice of the metal. Here it combines with more atomic hydrogen and becomes molecular hydrogen, which creates pressure and causes cracking. If the pH of a system is high enough so only the S2- ions exist, then the S2- is harmless to metal goods and humans. However, the presence of S2- makes the system potentially dangerous. Carbon dioxide, a salt water flow, or more hydrogen sulfide may reduce the pH of the system- converting the S2- ions to dangerous HS- ions or molecular hydrogen sulfide. 15.7.3 Hydrogen Imbrittlement, SSC and Hydrogen Blistering Hydrogen embrittlement is sometimes called sulfide stress cracking or SSC. However, the two mechanisms are slightly different. Neither hydrogen embrittlement nor SSC should be confused with hydrogen blistering. Both hydrogen blistering and hydrogen embrittlement result from the penetration of atomic hydrogen into the metal lattice. Atomic hydrogen atoms are produced when H2S and HS- dissociate on the surface of metal to form H+ ions. If H+ ions combine to form molecular hydrogen, they will enter the fluid as a gas. If the H+ ions combine with an electron at the surface of the pipe, atomic hydrogen is formed. Atomic hydrogen is the only species capable of diffusing through steel. H+ + e- à H0 Hydrogen embrittlement is believed to be caused by the diffusion of atomic hydrogen into an existing crack in the metal. When the metal is a hard, high strength steel, the combination of ductility loss and the increase in local internal pressure raises the stress level in the metal so that failure occurs at lower than normal tensile stress levels. Cracking failure is often sudden and if tensile stress is high enough, the crack propagates completely through the metal. Hydrogen embrittlement can be "reversed" by baking the metal at high temperatures. Sulfide stress cracking is believed to be a result of the rapid dissolution of the metal along the line of an advancing crack while in the presence of H2S.

Metal à ??Metal2+ + 2e- Penetration of atomic hydrogen into soft, low-strength steels can produce internal fractures or blisters. Hydrogen Blistering occurs when atomic hydrogen atoms combine to form molecular hydrogen (gas) inside the metal. This doesn't occur often in drill pipe because of its hardness. It is a frequent occurrence in storage tanks. 15.7.4 H2S Detection Several methods are available to detect and monitor H2S levels in drilling fluids. These include: 1. HACH Test 2. Garrett Gas Train 3. Ion Selective Electrodes 4. Ambient Air Monitors


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In many instances an initial H2S intrusion may not be detected by any means. This occurs if soluble sulfide species react with heavy metals, such as iron or copper entrained in the system, and is precipitated. Certain drilling fluid systems may have the ability to precipitate over 200 mg/L of soluble sulfides, depending on the type and size (surface area) of the metals available. When sulfides are expected or suspected the HACH test is often used as a means of obtaining a qualifying result. That is, simple detection. Initially the HACH test should be performed on whole fluid. The Alka-Seltzer tablets will reduce the pH, possibly liberating some previously precipitated sulfides. The HACH test is simple and fast enough to be run by rig personnel every few hours. Once sulfides have been detected, reasonably accurate quantitative measurement can be made using a Garrett Gas Train. Often initial measurements are made using whole fluid. Once a scavenger has been added, measurements are usually made to filtrate. This is because when acid is added to whole test fluid, previously scavenged (precipitated) sulfides can be liberated. When the test is performed on filtrate, generally only those sulfides which haven't been scavenged, will be detected. The precipitated species do not readily pass through the filter cake and paper. The Garrett gas train can measure from one to ten thousand mg/L of sulfides. Electronic measurements may be carried out continuously using ion selective electrodes. The sensors are placed in the shaker box and the readout is shown on a panel. The electrodes are specific for the OH- and S2- ions. The H2S concentration is calculated from these measurements. The values should not be considered to be extremely accurate. The electrodes must be calibrated regularly. 15.7.5 H2S Treatment Maintenance of pH values above 9.0 and the presence of filming inhibitors will prevent serious problems with hydrogen sulfide contamination at lower concentrations. However at higher levels, specific treatments must be used. Alkalinity is the best method of buying time and protecting people and pipe from hydrogen sulfide until other remedial action can be taken. Refer once again to figure 15.9, which shows the ionization of hydrogen sulfide. More detailed studies have shown that at very alkaline conditions this equilibria favors a higher concentration of HS- species. It is not possible, even in saturated sodium hydroxide solutions to force the equilibrium:

HS- + OH- à S2-+ H2O, so far to the right that all of the sulfur is present in the form of S2- ions. However, as the S2- ions are precipitated by a metal as the metal sulfide, the equilibrium will be shifted to the right. If a high pH is maintained then an influx of hydrogen sulfide will produce sulfide ions. Sulfide ions do not contribute to corrosion of drill pipe and if hydrogen ions are not available there can be no hydrogen sulfide gas formed. However, the sulfide ions are potentially dangerous if the pH becomes low, so they should be removed. Maintaining an alkaline environment and keeping close check on the sulfides, which can be treated out, can safely control an influx of hydrogen sulfide. Most filming inhibitors used in the industry are amine fatty acid salts, formulated into either oil soluble, or oil soluble / water dispersible materials. The inhibitor molecule may be described as having a polar end and an oil soluble end. The polar end will adhere to solid surfaces, such as steel. The oil soluble end absorbs a film of oil that protects the surface.


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Inhibitors are used in either continuous or periodic treatments. The main requirements for treatment are to contact the metal surface with sufficient inhibitor for a long enough time to obtain a good film coating. New treatments should be made at regular intervals to maintain the film. The primary disadvantage of filming inhibitors is the difficulty in coating the metal surface completely. Filming agents are either sprayed or painted on the pipe at surface, or batch-slugged down the drill pipe while drilling. Most scavengers function through either surface adsorption or ionic precipitation. If the scavenger is based on surface adsorption, the system must be thoroughly mixed to assure that enough random collision takes place between the hydrogen sulfide and the scavenger to assure completion of the process. In the ionic reactions, the characteristics of the scavengers must assure the variables - such as pH - are conducive to using the additive. Zinc compounds are currently being used to minimize the effects caused by hydrogen sulfide in drilling muds. The basic zinc reaction is as follows:

Zn2+ + S2- à ZnS Note that this reaction occurs primarily in high pH environments necessary for the development of the divalent sulfide ion. The most common form of zinc is from the zinc carbonate compound. The commercial grade contains approximately 55% by weight of zinc. 0.35 kg/m3 of zinc carbonate will scavenge up to 500 mg/L sulfides. It is a manufactured, non-stoichiometric compound with a formula similar to the following:

3 Zn(OH)2 • 2 ZnCO3 The pH of the drilling fluid environment has several other effects on the application of the zinc carbonate as a scavenger. The zinc ion available for reactions is high when the pH is below 8.0 or above 11.5, but is low when 8.0 to 11.5. Unfortunately, most effective drilling fluids have a pH ranging from 9.0 to 11.0, indicating that zinc ions are not at their maximum concentration levels If the pH is greater than 11.0, zinc ions increase the solubility of the basic zinc carbonate. The zinc ions are formed as a result of the abundance of hydroxyl ions that combine with the zinc ions.

Zn2+ + 3 OH- à? Zn(OH)3-

Zn(OH)3- + OH- à Zn(OH)4 +2e-

Although zinc carbonate is an effective scavenger, problems such as the following may be associated with the compound: 1 Concentrations above 8.5 kg/m3 in weighted, high solids systems develop high

gel strengths. Carbonate concentrations must be controlled. 2 The zinc ion may cause a reaction similar to calcium contamination in some

muds. 3 The compound by itself does not prevent hydrogen embrittlement. 4 Since its specific gravity is roughly the same as barite, it may settle in fluids such

as brines that have a low carrying capacity. Zinc held in chelate form is a type of sulfide scavenger marketed for use in drilling fluids. A zinc chelate is designed to provide a water soluble form of zinc over a wide pH range, so that the zinc


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ion will be available to react quickly with sulfides entering the system. If properly chelated, the zinc ion will not be captured by clay surfaces, reducing flocculation. To accomplish sulfide scavenging and yet avoid clay flocculation, the zinc chelate must have a stability constant of proper magnitude. The presently used chelate ligands are aliphatic amine acids or their salts. Water-soluble chelates are used in brines and low gel-strength fluids because they do not settle out. The amount of zinc that can be held in chelate form currently ranges up to 20 wt%, with the scavenging capacity directly related to this zinc percentage. 0.35 kg/m3 of zinc chelate will scavenge up to 200 mg/L sulfides. Excess lime may be used in invert systems for controlling pH and for neutralizing small volumes of H2S. However, the reaction of lime with H2S is reversible and lime may not be effective in controlling large volumes of H2S. Oil soluble, strongly basic amines or zinc oxide are sometimes used in invert systems for scavenging hydrogen sulfide. The mechanisms and the net affect of zinc oxide as an H2S scavenger in external-oil phase systems is currently being debated.


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REFERENCES 1 Loyd W. Jones Corrosion and Water Technology for Petroleum Producers (Tulsa: Oil &

Gas Consultants International Inc, 1988), 3.


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CHAPTER 16 PROBLEM SOLVING WITH DRILLING FLUIDS 16.1 KEY POINTS AND SUMMARY 16.2 CHEMICAL CONTAMINANTS 16.2.1 Make-Up Water 16.2.2 Calcium 16.2.3 Carbonates 16.2.4 Salt 16.2.5 Formation Fluid Influx

16.2.6 H2S 16.2.7 Bacteria

16.3 STUCK PIPE 16.3.1 Problem Formations 16.3.2 Differential Sticking 16.3.3 Key Seating 16.3.4 Sloughing 16.3.5 Other Sticking Mechanisms 16.4 LOST CIRCULATION 16.4.1 Causes 16.4.2 Identifying and Locating the Loss Zone 16.4.3 Lost Circulation Materials 16.4.4 Lost Circulation with Oil-Based Fluids 16.4.5 Lost Circulation in Horizontal Wells 16.4.6 Spotting Pills 16.4.7 Methods of Preventing Lost Circulation 16.5 ABNORMAL PRESSURES 16.5.1 Common Causes of Fluid Influx 16.5.2 Detection 16.5.3 Methods of Control 16.5.4 Shallow Gas 16.5.5 Kick Tolerance 16.5.6 Gas Hydrates 16.6 OTHER COMMON PROBLEMS 16.6.1 Lubricity 16.6.2 Mud Rings and Bit Balling 16.6.3 Foam 16.6.4 Permafrost 16.7 HORIZONTAL DRILLING 16.7.1 Horizontal Drilling Techniques 16.7.2 Advantages of Horizontal Wells 16.7.3 Problem Areas 16.7.4 Drilling Fluid Design 16.8 TREND ANALYSIS


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16.1 KEY POINTS AND SUMMARY Drilling fluid contaminants include anything that causes undesirable changes to system properties. Chemical contaminants include: calcium, salts and formation fluids and gasses. A contaminant can often be predicted and a pre-treatment program may be initiated. When contamination occurs unexpectedly, careful analysis of a fluid's chemical and physical properties is imperative in order to correctly identify it. Concentrations of treating chemicals must be calculated accurately, as they themselves can become contaminants. Stuck pipe is a costly, time-consuming problem. It can occur anywhere in the world. Stuck pipe usually occurs in known problem formations. These include: erodible, dipping, stressed, overpressured and hydratable formations and coal. Stuck pipe mechanisms include: differential sticking, key seating and sloughing. When any type of wellbore fluid is lost into the formation rock, the situation is termed lost circulation. Lost circulation mechanisms are related to formation pore size, fluid particle size and the hydrostatic pressure of the fluid column. Lost circulation materials (LCM) are categorized by their nature and their size. The techniques used to combat lost circulation depend on the severity of the problem. Oil-based fluids generally exhibit a higher rate of loss in a given formation than water-based fluids. The influx of formation fluids into the wellbore poses a costly and dangerous scenario. Several common causes have been identified. They include: abnormal pressures, insufficient fluid density, lost circulation, failure to keep the hole full and swabbing. Detecting changes and transitions in pore pressure values is important - as is detecting actual influx. There are several accepted methods of controlling an influx. All require shutting the well in using blowout prevention equipment. All require alertness and training on the part of drill crews. Kick tolerance equations have been developed to minimize the chances of a blowout. Shallow gas and gas hydrates are becoming more of a concern as exploration continues to move into deep water and Arctic areas. Hydrates are a solid combination of methane gas and water and can be encountered insitu or created while drilling. Other problems encountered while drilling include: friction, mud rings, foam and permafrost. Horizontal drilling techniques vary depending on the rate of angle build. The advantages of a horizontal hole are related to increased production and better economics. Drilling fluids formulated for this application should first be designed to protect the formation and second to impart the best possible carrying capacity. 16.2 CHEMICAL CONTAMINANTS Almost any of the materials encountered or added intentionally to drilling fluids can under certain conditions be considered contaminants. Some contaminants can be predicted and pre-treated. These include: cement, anhydrite, salt, make-up water and H2S. Other contaminants are more difficult to discern and treat. These include CO2, water influx and bacteria. Eventually these contaminants show their effects by altering the properties in a system.


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16.2.1 Make-Up Water Water is the most important ingredient in all water-based drilling fluid systems. It dissolves or suspends all of the other ingredients, which make up the system. The drilling fluid engineer prior to adding chemicals should check all sources of water. In some situations it may be more economical to use better quality source of water, than to chemically treat out alkaline or brackish water. The most common contaminants found in make-up water include: 1. Calcium and Magnesium Salts 2. Carbonates and Bicarbonates 3. Sulfates

4. Chlorides 5. Bacteria

If there is any doubt as to the purity of the make-up water, a sample should be sent to a water analysis laboratory. 16.2.2 Calcium Cement is a common source of calcium contamination in water-based fluids. Cement is used to cement the casing, or to plug a hole back, so that a new hole can be drilled. Cement may also be spotted in the hole in an attempt to stop lost circulation. As cement and barite are both commonly handled pneumatically, there is also the opportunity for contamination of the barite by cement during the transportation of the bulk product. Cement, which has not completely set, is called "green" cement. Green cement is often encountered in the interval immediately under the last casing shoe - the rathole. Cement is made from a mixture of calcium carbonate, clays and iron and aluminum oxides, heated to form a cement clinker. It is then ground to a fine powder and blended with about 2% gypsum to control the set time. Cement consists of 70% free lime, gypsum, magnesia and calcium silicates, calcium aluminates and calcium aluminoferrite. The ratio of the components influences the setting time and strength of the cement. The addition of water generates an exothermic reaction as the calcium oxide is hydrated. During the setting process a crystal growth (calcium sulphoaluminate), links the cement particles into a solid matrix. The effect of the calcium contamination is due to the addition of calcium oxide (CaO) which reacts with water to release calcium and hydroxide:

CaO(s) + H2O ⇔ Ca2+(OH)-2

The contamination is due to the effect of the calcium ion and the hydroxide ion. Anhydrite (CaSO4) is formed by evaporation of seawater. It is one of the least soluble components of seawater. Therefore it precipitates first as the hydrated salt, gypsum (CaSO4 2H2O), which is dehydrated by higher pressures and temperatures. Stringers of anhydrite are commonly encountered. The effect is contamination due to the calcium and sulfate ion:

CaSO4+ 2H2O ⇔ CaSO4 2H2O ⇔ Ca2+ + SO42-

Anhydrite Gypsum


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Hard brines can also contain calcium ions, entering the drilling fluid system as a brine. This type of contamination increases the calcium and the chloride ion concentrations. Seawater also contains significant levels of calcium and magnesium typically in the order of (350-400 and 1100-1300 mg/L respectively). The effect of calcium contamination depends on both the drilling fluid system and the source of calcium. Gypsum and lime muds are conditioned with excess levels of gypsum or lime, so anhydrite or cement has little effect. Salt saturated systems are not markedly influenced by the presence of gypsum but cement contamination may precipitate anionic cellulose polymers (CMC and PAC). Oil-based systems are not susceptible to calcium contamination. Freshwater sodium bentonite systems are most susceptible to calcium ion contamination. In these systems, the ion causes clay flocculation by forming an ionic bridge, which in turn causes an increase in both viscosity (particularly gels and yield point) and fluid loss. Calcium contaminated water-based systems exhibit an increase in the calcium ion in the filtrate. Cement causes the pH and alkalinity to increase, while anhydrite usually causes the pH and alkalinity to decrease. Anhydrite also increases the sulfate concentration. The solubility of calcium decrease as pH increases. Once saturation levels have been attained, either the cement or the anhydrite will exist in the system as solid particles. Therefore it is imperative that the solids removal equipment is running efficiently. Calcium ion contamination can be treated either by reaction with sodium carbonate (soda ash) or sodium bicarbonate (bicarb). Sodium Bicarbonate will react with both the calcium and the hydroxide. Therefore it is the preferred product for treating cement:

Ca2+ + OH- + NaHCO3 → CaCO3↓ + H2O + Na+ To chemically remove 1 mg/L of calcium originating from cement requires approximately .0021 kg/M3 of Bicarb. Before drilling cement, Sodium Bicarbonate is often added as a pre-treatment at concentrations of 1-3 kg/M3, depending on pilot test results. The actual treatment depends on the severity of the contamination. Often it is advisable to discard severely cement-contaminated fluid. Sodium acid pyrophosphate (SAPP) can also be used to treat out excessive cement contamination. SAPP has a three-fold effect in combating cement contamination. It reduces the pH, deflocculates, and removes calcium. Treatment varies, but normally 0.25 - 0.75 kg/M3 is sufficient to deflocculate a system. A treatment of 0.0028 kg/M3 of SAPP will chemically remove 100 mg/L of calcium originating from cement. SAPP should not be used when bottom hole temperatures exceed 80°C. Aluminum Sulfate and Barium Carbonate are also used to treat cement contamination. Soda Ash is used in treating Anhydrite contamination because it does not reduce the pH. The reaction may be stated:

CaSO4 + Na2CO3 → CaCO3↓ + Na2SO4 0.00265 kg/m3 of Soda Ash will treat out 1 mg/l of calcium. Prior to encountering anhydrite stringers, water-based systems are often pre-treated with 1.5 kg/M3 or 2.0 kg/M3 of Soda Ash or to where the carbonate alkalinity runs about 1,000 mg/L. Over treatment with either Soda Ash or Sodium Bicarbonate can adversely affect system properties such that these products themselves become contaminants.


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16.2.3 Carbonates There are several sources of soluble carbonates in drilling fluids: 1. Carbon dioxide entrained in the formation being drilled 2. Decomposition of Lignosulfonates 3. Formation brines - often associated with calcium chloride 4. Over treatment with Soda Ash or Sodium Bicarbonate 5. Make-up water 6. The atmosphere (CO2 entrained in the drilling fluid through surface agitation) 7. Zinc Carbonate additions The carbonate species depends on the system pH. Below a pH of 4.0 - as in the case of some formation brines - the following equilibrium exists, with the formation of carbonic acid:

CO2 + H2O ⇔ H2CO3 At higher pH values between 4.3 and 8.3 bicarbonate species increase in concentration:

H2CO3 + NaOH ⇔ HCO3- + Na+ + H2O

Above pH 8.3 the predominant ion is the carbonate:

HCO3- + NaOH ⇔ CO3

2- + Na+ + H2O The change in ion distribution as a function of the pH described in these equations is shown in Chapter 2. Excessive levels of soluble carbonates in a clay / water system causes the viscosity and gel strengths to increase and not respond to the normal treatments and concentrations of deflocculants. The symptoms may appear similar to a gradual drilled solids build up, however a carbonate problem doesn't cause the solids content to increase. Chemical analysis may help identify the problem. The indicators can often include a decrease in pH with an increase in Pf. Or Mf increasing much faster than Pf. The soluble calcium is also reduced as it reacts with the carbonate ions to form insoluble calcium carbonate. Carbonate can be measured directly with a Garrett Gas Chain. This method determines both carbonate and bicarbonate as carbon dioxide. Treatment for carbonate contamination in a water-based system involves the addition of a calcium source. This precipitates carbonate as calcium carbonate. Normally lime or gypsum is used. (Addition of lime to a solids laden system at high temperatures can cause severe rheological and filtration control problems.) Carbonates up to 500 mg/l should not create problems but treatment should be considered at levels over 1,000 mg/l if gel strengths begin to increase. Treatments should be pilot tested to ensure they are optimum and there is not an underlying problem with drilled solids. When treating CO3

- problems with lime, caution should be exercised, since high pH may result. .0012 kg/M3 of Lime with treat 1 mg/L of CO3

- .0028 kg/M3 of Gypsum will treat 1 mg/L of CO3


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Gypsum is usually used when the system pH is above 10.0 - 11.0, since the solubility of lime is depressed at high pH. If carbonates are a continual problem then Gyp or Lime drilling fluid systems should be considered. 16.2.4 Salt Sodium chloride is encountered in formation water, seawater, and evaporite sequences. Sodium chloride contaminates by flocculating the clays in the system beginning at concentrations above about 5,000 mg/l. The effect on the fluid properties depends on the system in use - however in general the following will be observed: 1. Viscosity will initially increase, followed by a decline if the contamination persists. 2. Yield point will increase. 3. Gels will become higher 4. pH will usually diminish somewhat depending on the nature of the salt influx. 5. Filtrate will increase 6. Chloride content in the filtrate will increase. There is no practical treatment for salt contamination other than dilution and the addition of salt tolerant materials - such as polymers to substitute for bentonite. Rheological and fluid loss properties are usually controlled with Lignosulfonates. If lignite is used for deflocculation, care needs to be exercised. Under certain conditions of alkalinity, when in the presence of salt, lignite is not soluble and remains as a colloidal solid compounding rheology problems. Alkalinity often drops when salt contamination occurs and caustic soda should be added to counteract this. At some point, a decision may have to be made - whether to allow the salt in the formation to wash out with the attendant risk of cave-ins, poor cuttings transport, excessive use of cement and poor cement bond - or to saturate the system with salt. 16.2.5 Formation Fluid Influx Formation fluids entering the wellbore at a rapid rate are cause for immediate concern. The subject is discussed later in the chapter. When formation fluids enter at a slower rate, the effects on system properties can be adverse. Formation fluids include: 1. Gasses (C1-C15 Hydrocarbons) 2. Oils and Waxes (C15 and above) 3. Fresh Water 4. Brackish Formation Fluid 5. Drilling Fluid Gases, usually hydrocarbons are non-miscible in water therefore, they mix poorly with water based drilling fluids and usually exist as two separate physical states (gas & water). The resulting gas bubbles contained within the water are very easy to detect. However, this is not the case in hydrocarbon based drilling muds, because the gases are mutually soluble in each other. Dissolved high pressure gases are very hard to detect until the pressure drops on the drilling fluid, at which time the gas will vigorously come out of solution (termed a bubble point). This makes kick detection very difficult. An oil influx may have little or no effect on the properties of an oil-based fluid. However emulsifiers must be added to a water-based fluid when an oil influx occurs. Excessive oil may create disposal concerns on the cuttings after the well is finished.


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Oil or water entering a system usually reduces the density. When water enters an oil-based system, the brine phase chlorides decrease. When an influx of water occurs with a water-based system it is often necessary to perform mass balance calculations to determine the salinity of the influx. In formations exhibiting low-pressure integrity, prolonged seepage losses can result in a slow influx of drilling fluid after several days. Although the affects on system properties are not usually adverse, volume calculations become difficult. A rapid influx of drilling fluid should be treated like a kick. The difference is that the rate of flow will diminish with time. 16.2.6 H2S Hydrogen sulfide may be encountered as a formation gas formed by the decomposition of organic matter. H2S can also be generated by the action of anaerobic bacteria on sulfur or sulfate compounds entrained in the drilling fluid. Hydrogen sulfide is extremely: dangerous, flammable, explosive when mixed with air (4.3-46%), highly toxic and corrosive acidic gas. It is colorless and denser than air and tends to settle in low areas such as the sub-structure, cellar and near the mud pits. H2S is toxic above 10 ppm and impairs the sense of smell at low concentrations. Petroleum Industry Training in H2S safety is required to work in areas, which might have H2S concentrations greater than 10 ppm. Hydrogen sulfide dissolves in oil but does not undergo any chemical reaction, so it is not corrosive. It will react with the alkalinity provided by the lime, to form calcium sulfide:

H2S + Ca(OH)2 → CaS + 2H2O Calcium sulfide is not stable and will release hydrogen sulfide as the pH decreases. In water-based systems the gas dissolves and disassociates in water: H2S ⇔ H+ + HS- ⇔ 2H+ + S2- The acid conditions created by the gas can lead to flocculation due to rapid loss of pH with consequential thickening and loss of fluid loss control. The first defense against hydrogen sulfide is to reduce its solubility by forming the sulfide ion with the addition of an alkali. This reaction is reversible should the pH decrease, so it should only be viewed as a temporary measure. Insoluble and stable metal sulfides can be formed with iron and zinc. Iron oxide and zinc carbonate or a zinc chelate is added to form the stable iron or zinc sulfides. The affect of sulfides on drilling fluids is reviewed in greater detail in the chapter on Corrosion. 16.2.7 Bacteria Several types of bacteria can attack drilling fluid system components, ultimately causing properties to deteriorate. The sulfate reducing bacteria (SRB) are anaerobic. That is, they don't require oxygen to live. Bacteria can generate H2S or enzymes. Systems containing starch or a


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sulfate source are especially susceptible. Cases have been documented where bacteria have completely destroyed the fluid loss properties of starch systems in less than an hour. In other instances, SRB's have been responsible for the release of lethal quantities of H2S gas at surface. In systems employing starch, a bacterial attack is evidenced by a reduction in fluid loss properties and a foul, rotten odor at the shaker. When sulfate-reducing bacteria are at work, the first indication is a reduction in pH, usually at bottoms-up. Soluble sulfides can be detected with a HACH test kit or Garrett Gas. See Corrosion Chapter for more on H2S. 16.3 STUCK PIPE The drill string can become stuck in the hole due to several phenomena. In many cases a combination of two or more mechanisms may result in sticking. The normal mechanisms are as follows: 1. Differential pressure sticking 2. Key seating 3. Undergauge hole 4. Large particles sloughing into the hole

When drill pipe and drilling tools become stuck in the hole, time is lost. Decisions must be made quickly because the time dependency of borehole stability problems poses an increased risk. The first course of action is to analyze the symptoms and the events leading up to the problem to hopefully discern the sticking mechanism. Attempts are made to either jar the pipe free, "spot" pipe freeing fluid, or to back-ream out. Often a free point tool is run on a wire line - indicating where the pipe is actually stuck. If the initial attempts to free the pipe are unsuccessful, a decision must be made, whether to leave the stuck pipe in the hole and side track (drill a new hole) around it, or recover the stuck pipe by washing over it with larger diameter pipe. In either case the drill string must be parted or shot off above the free point. This is done by imparting reverse torque into the string and detonating an explosive charge at a tool joint above the freepoint. During washing operations, debris is cleaned from around the outside of the stuck pipe (now called the fish) by drilling it out with the larger diameter wash pipe. The mill on the end of the wash pipe can actually "machine" the steel blades off of stabilizers. Once enough of the fish has been washed over, the wash pipe is pulled and a tool called an overshot is run into the hole on the end of the drill pipe. It securely screws over the fish, cutting its own threads. Once this is achieved, another freepoint tool is usually run and the string is again shot off above the free point. This washing over and recovery process continues until the entire pipe is recovered. When a well is sidetracked, cement is spotted above the fish. The top of the cement plug is then polished off with a bit - often contaminating the drilling fluid in the process. Directional equipment is used to steer the well away from the plug so that a new hole is started. Often this leaves several hundred thousand dollars worth of stuck drilling tools in the hole. 16.3.1 Problem Formations Mechanisms which contribute to stuck pipe situations almost always stem from a "problem" formation or sequence. In the majority of cases proper fluid planning before entering the formation in question can minimize these problems. These formations are listed first, as an aid to understanding the more specific situations, detailed in the chapter. When a potential problem formation is about to be (or has been) penetrated, the drilling fluid engineer should be able to suggest certain adjustments to the properties of his fluid, as a contingency against becoming


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stuck. For example, when drilling overbalanced through porous sand, consideration should be given to reducing the fluid loss and improving the cake and lubricity characteristics of the drilling fluid. See the Chapter on Fluid Design for further information. Erodible formations include soft tertiary sequences, evaporites, permafrost and some highly fractured formations. The erosion mechanism may stem from excessive fluid velocities, temperature or undersaturation in the case of evaporites. The net effect is the same - the hole becomes enlarged. Enlarged holes pose difficulties with hole cleaning, log analysis, directional control, cement volume and bonding and production. Overguage holes can also cause problems with stuck pipe. In the case of fractured formations, the "erosion" may be an instantaneous slippage, resulting in stuck pipe. Once an interval becomes overguage, the fluid velocity in that interval decreases. As a result of this, and with time, fluid gelation can occur in the interval. Cuttings become "piled up" or "packed off", static in the thick fluid. (The same mechanism often occurs in the rathole under the last casing shoe.) When these cuttings are disturbed the hole "unloads" often causing the pipe to become stuck. When these cuttings are eventually cleaned the geologist may often identify cuttings from all of the sequences in that interval. The disturbance, which liberates the cuttings, often stems from a viscosity reduction. A viscosity reduction allows fluid to channel through the packed-off cuttings. Also more hydraulic power is imparted to the wall. The entire scenario, where packed off cuttings slough as a result of a viscosity reduction is sometimes called "shocking the hole". Dipping formations usually occur in older geological sequences, often close to mountain ranges. Directional control is often difficult in these areas, as the bit tends to "walk" up-dip, if the dip angle is less then 45°; and the down-dip, if the angle is above 45°. Dipped formations tend to slip into the borehole - posing cleaning problems, often resulting in stuck pipe if the slippage is instantaneous and massive. As a result of changing directions of highly dipped formations “Dog Legs” can occur, discussed later in this chapter. Formations, which are tectonically stressed, contribute to pipe sticking especially if the formation has a degree of plasticity. This occurs in tertiary sequences and in some evaporites such as salt domes. Similar formations, which are subject to overburden stress, can also cause stuck pipe. In both cases the wellbore diameter is reduced - such that it becomes difficult or impossible to pull drill collars and stabilizers through it. Sometimes a pump pressure increase can indicate that this is occurring, but usually not in time. In areas where this occurs, it is usually seen as a time dependant phenomena. In other words, if a wiper trip is made every so many hours, drilling ahead can proceed normally. A four arm caliper log showing an elliptical hole usually indicates tectonic stresses while a round hole indicates overburden stresses are at play. Formations, which are under pressured or over pressured, also contribute to stuck pipe situations. In tight (low permeability) high-pressured shales, spalling may occur rapidly. These formations characteristically drill much faster than they ream. It is difficult to achieve a reduction in gas units - and cuttings, which return, are usually sharp and half-moon shaped. Often an increase in fluid density alleviates this problem In under pressured formations - especially sandstones, the potential to become differentially stuck is especially high. Differential sticking is discussing in the ensuing text. Formations which are hydratable are perhaps the most difficult to predict and assess. These formations hydrate, swell and slough-in, all as a function of time. The sloughing can be instantaneous, resulting in stuck pipe. Various drilling fluid systems have been developed which increase the time taken for sloughing to occur. Coal can cause expensive drilling problems including; stuck pipe, tight hole and severe hole enlargement. Sloughing coals will have abnormally high penetration rates (drilling break). The


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combination of a large volume of cuttings and sloughing debris will cause hole loading and failure to remove solids from the hole. This will lead to the annulus packing off, causing stuck pipe. As many of the coal seams encountered in Western Canada are thin bedded with sand / shale sequences, these thin beds can also collapse causing stuck pipe. Lignitic coals can cause Bentonite systems to deflocculate, leading to rheology control problems. In the event of a “drilling break”, good drilling practice should dictate at the indication of an increase of penetration rate, drill in 1-2 meters, pick off bottom, work pipe and circulate the hole clean. Caution should be exercised to avoid drilling too much coal too quickly. Monitor rheology very closely when drilling coal sections. 16.3.2 Differential Sticking Differential sticking occurs only when the drill pipe or more usually the collars come into contact with sticky filter cake by a porous and permeable formation, usually sands or limestone. A further requirement is that the hydrostatic head of the fluid column must exceed the pore pressure of the permeable formation. This occurs most frequently when high mud weights are being employed to control pressures in slim hole. Differential sticking can occur when the pipe is rotating in inclined boreholes. Figure 16.1a shows that while the pipe is being rotated, the drill collar penetrates only a short distance into the (dynamic) wall cake. When rotation is stopped, a static cake also forms - increasing the contact area between the pipe and the hole.

The symptoms of differentially stuck pipe must be recognized early. They include: 1. Inability to rotate 2. Inability to move pipe up or down 3. Full fluid returns with no standpipe pressure increase. If jarring or rotating attempts to pull free are unsuccessful a spotting pill is prepared and spotted in the entire open hole interval by the stuck zone. The spotting pill consists of oil or diesel oil, often


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with a lubricant / surfactant incorporated into it. Sometimes spotting pills are formulated from glycol when drilling in environmentally sensitive areas. A spotting pill works by several mechanisms: 1. A reduction in hydrostatic head 2. Filtercake dehydration 3. A reduction in the coefficient of friction between the pipe and the cake 4. A reduction in the adhesive forces between the solids in the filter cake.

(Adhesion is explained in Chapter 2.) Spotting pills can be weighted or unweighted. The formulation for spotting pills is outlined in Volume Two of this manual. They should be pumped slowly to avoid dissipation. Volumes and strokes should be calculated accurately, and the answers compared with someone else's. Often the pill can be seen on the geolograph chart. When it reaches the bit - the standpipe pressure drops. Once the pill is spotted, the pump should be stopped. At this point, there should still be plenty of pill fluid inside the drill pipe. Even a weighted pill can migrate up the annulus. Therefore every 1/2 hour about 0.1 M3 of new pill fluid should be pumped. While the pill is soaking, the pipe should be worked, reciprocated and rotated, at regular time intervals. Usually these pills work, but it isn't unusual for them to take 4-6 hours, so patience is required. At surface the pill should be isolated and discarded, blending it in to the active system can affect properties. Several steps can be taken to avoid differential sticking. Spiral drill collars and blade stabilizers reduce the contact area between the pipe and the wall cake. Good drilling practices are imperative. Pipe should not be stopped for long periods when collars are by porous formations. Pipe rotation should be maintained while running wire line tools. Fluid properties can be adjusted. The fluid density and solids content should be reduced. A liquid phase lubricant may be added. The fluid loss value and filter cake characteristics are the most important properties to control when differential sticking is possible. The HTHP fluid loss value should be low and the cake should be slick and tough. On exploration wells the drilling fluid Engineer should establish good communication with the geologist. When sand intervals are encountered, consideration should be given to reducing the fluid loss. Modern MWD equipment can often detect sand in real time, with gamma ray data. 16.3.3 Key Seating Key seating is a phenomenon that occurs in crooked holes or holes with dog-legs. The drill pipe, in tension, pushes against the high side of the hole as illustrated in Figure 16.2. The continuous rotation of the pipe wears a groove in the wall, the same size as the pipe. Sticking occurs when attempting to pull the larger drill collars and drilling tools through the key seat. Indications of key seat sticking include: 1. The ability to pump - unimpeded 2. The ability to work the pipe down but not up 3. The ability to rotate easily at string weight (no over pull) 4. Rotary torque decreases when the hook load is reduced The best course of action from a drilling fluid standpoint is to positively identify key seating. This involves identifying the free point and correlating it with the well inclination - obtained from directional surveys. Remember, pipe rotation is possible in a key seat but difficult when differentially stuck. Incorrectly diagnosing the problem could result in mistreatment at great expense. Once the pipe is stuck in a key-seat, back-reaming and working the pipe is sometimes successful - although in most instances, backing off and washing over are required.


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The Rocky Mountain Region in North America is called "Crooked Hole Country". Formations are dipped and folded so severely that a geological sequence is often encountered 3 times in the same well. To minimize dog-leg severity extremely stiff (packed) drilling assemblies are utilized. These often include a near-bit stabilizer, a large diameter drill collar, and 2 or 3 more full gauge - blade stabilizers - close in. A tool called a Key-Seat Wiper is placed between the drill collars and heavy weight pipe. This tools reams out key-seats as drilling proceeds. Even when packed assemblies and key-seat wipers are used, key seat sticking still occurs.


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16.3.4 Sloughing Several types of formations may eventually slough into the wellbore, ultimately causing the pipe to become stuck. These include: 1. Fractured shales 2. Hydratable/swelling shales 3. Poorly consolidated sand 4. Overpressured shales Sloughing often occurs rapidly, without warning. Occasionally evidence that the problem is developing is seen as increased cuttings or cavings on the shakers, or increased rotary torque or pump pressure. Stuck pipe due to sloughing may be indicated by the following: 1. The inability to rotate pipe 2. The inability or a restricted ability to pump 3. The inability to reciprocate pipe In order to rectify this situation the string must usually be worked or jarred. Often it is necessary to back off and wash over. Preventing a recurrence of the problem is partly a function of the drilling fluid. The first step is to ensure that the particles that caused the sticking were not normal drill cuttings. If they were, then the system's rheology should be adjusted. If sloughing occurred, the density, fluid loss and inhibition characteristics should be reviewed and adjusted. Standard procedure for combatting sloughing is also to increase the rheology to assist in keeping the hole clean. A further problem may be turbulent flow, increasing viscosity will prevent this. 16.3.5 Other Sticking Mechanisms The following situations can also contribute to stuck pipe. These are mainly mechanical, not usually related to the drilling fluid. Changes in the bottom hole assembly may cause sticking while running in if the hole is deviated. An assembly that is less flexible, with more gauge stabilizers than that used to drill the hole can become stuck in gauge hole sections with only slight angle changes. Occasionally physical obstructions may be introduced to the wellbore by the drilling operation. Typical items are bit cones, logging tools, wire line, casing shoes and various items described as junk that fall in from the rig floor. 16.4 LOST CIRCULATION The geophysical phenomena leading to sub-normal formation pressures are discussed in the Borehole Stability Chapter. Lost circulation is defined as a loss of quantities of drilling or completion fluids or cement slurries into wellbore voids. Effectively curing lost circulation is an important factor in maintaining both well control and borehole stability.


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16.4.1 Causes One or more of the following causes losses: 1. Formation pore spaces are too large, or the particles in the fluid are too small to

allow filter cake formation. 2. Hydrostatic pressure is sufficient enough to force wellbore fluids into the pore

spaces. 3. Hydrostatic pressure causes a natural fracture to open up and take wellbore fluid. 4. Hydrostatic pressure induces fractures in weak formations. Note that three of the causes involve hydrostatic pressure. Lost circulation is commonly located at or near the casing shoe. As the fluid density is increased to contain increasing pore pressure, losses can occur in the upper, relatively weak zones. In deeper holes lost circulation may be due to mechanically induced fractures, caused by: 1. Running drill pipe or casing into the hole too rapidly. 2. The bit becoming plugged while running pipe. 3. Bit and drill collars becoming balled up. 4. Excessive fluid density. The severity of losses is classified by volume per time unit. The categories are as follows: 1. Seepage Losses: up to 1.6 m3/h 2. Partial Losses: 1.6 m3/h to no returns 3. Complete Losses: no returns to surface 16.4.2 Identifying and Locating the Loss Zone There are four classifications of formations or zones where lost circulation can occur. In Porous and Permeable Sands and gravel, losses start as a gradual reduction in pit volume. If drilling proceeds, the losses could become complete. These zones usually occur near the surface. Vugular formations are usually located in limestone. Losses here can be sudden (located at the bit) and complete. On occasion the bit may drop a few inches before the loss. Natural fractures may occur in any type of rock. Usually these losses are partial but may progress to complete loss as drilling proceeds or if the fluid density increases. Losses to induced fractures may be sudden and complete. They are often accompanied by an increase in pump pressure and tight hole. If the fluid density is constant, losses due to induced fracturing are usually near the bit. If the fluid density or pressure is increased, losses could be anywhere. Induced fractures may be incurred during well control operations.


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Locating the loss zone, sometimes called the thief zone is important in order to place the specific lost circulation treatment by the zone. Several electronic methods are available to aid in locating the thief zone. These include spinner/temperature surveys and gamma ray logs. 16.4.3 Lost Circulation Materials (LCM) Various types of materials have been used to stop lost circulation. LCM can be classified by its size: 1. Fine, often used for seepage losses 2. Medium, used for partial losses 3. Coarse, used for partial and complete losses or by its nature 1. Flaky 2. Fibrous 3. Granular The severity of the losses and past experience in an area dictate the best course of remedial action. There are 5 standard techniques used to combat lost circulation today. Each one is successively more complicated than the previous one. Choosing which technique to start with depends on the severity of the losses: 1. Pull up and wait. The bit is pulled above the loss zone and the hole left static for

4-6 hours. 2. Spot LCM by the loss zone. 3. Spot high filter loss slurry by the loss zone. Often these are squeezed. 4. Spot or squeeze a plug by the loss zone. Plugs can consist of bentonite/diesel

mixtures or various types of cement slurries. 5. Drill ahead without returns. (Drilling blind) Losses in permeable formations are usually remedied with granular or flake type materials. Using all three types heals fractured formations. Porous formations respond to fibrous materials, which are often squeezed. In severe cases porous formations must be plugged with a gel/diesel (gunk) plug or with cement. A knowledge of the formation and the area helps in sizing the material. When deciding on the concentration of material to be used the following guidelines apply: 1. For seepage losses 10-60 kg/m3 of LCM may be circulated through the active

system with the shaker bypass open. This is usually done on surface hole, where the system will be discarded any way. When a pill is spotted to control seepage losses, usually 60-100 kg/m3 of LCM is used.

2. If losses are partial, 115-230 kg/m3 of LCM is spotted in pill form. 3. When losses are complete, 230-430 kg/m3 of LCM is spotted in pill form.


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16.4.4 Lost Circulation with Oil-Based Fluids There is evidence that lost circulation occurs more frequently and is more difficult to rectify when drilling with oil-based fluid than with water-based fluids of equivalent density. The fracture pressures for oil-based fluid can be 0.1-0.2 s.g. less than for water-based fluids. Petroleum Engineer states that more than 80% of offshore wells drilled with oil-based fluid (with a density above 1.80 s.g.) experienced problems with lost circulation. Fracture pressures appear to be even lower with mineral oil than with diesel oil systems. Several theories have been advanced to explain why this phenomena occurs: 1. Fracture gradients in many formations may be lowered by the effect of down hole

temperature and pressure on the physical properties of the oil. The thinning effect causes the oil to penetrate more readily into permeable formations. There is evidence that this might lower fracture pressures as compared to a relatively non-penetrating water-based fluid.

2. The compressibility (relative to water) of oil can result in an increase in fluid

density. 3. There are relatively low concentrations of colloidal particles in oil-based fluids to

help plug microfractures. 4. The formation is usually naturally water-wet. Therefore oil entering a fracture

must have a convex surface and will not completely fill the microfracture and plug it. This is in contrast to a water-based fluid.

As a preventive measure when drilling with an oil-based system, it is a good idea to keep a 15 m3 LCM pill, mixed in oil, on hand. The pill should be prepared before drilling commences. Every precaution should be taken to avoid fracturing the formation with oil-based system. With an oil-based system, an induced fracture will often not heal. This is in contrast to water-based fluids where an induced vertical fracture often heals by itself. The remedial material and technique to cure the lost circulation should be matched to the severity of the loss. For minor losses such as seepage loss and slow rate partial loss bridging agents (LCM) are used in oil-based systems in much the same manner as in water-based systems. Often sized calcium is mixed into the active system, as a daily treatment, while drilling proceeds. If bridging agents do not control the loss effectively a high filter loss slurry squeeze should be tried. 16.4.5 Lost Circulation in Horizontal Wells In 1986 Zurdo, Georges and Martin wrote an SPE paper entitled Mud and Cement for Horizontal Wells.1 In it they discussed the difficulties encountered by some operators in plugging fractured thief zones in horizontal wells. Their tests showed that: 1. The upper half of the circumference of the wellbore is usually only slightly

plugged, whereas the lower part is usually plugged. Although light LCM may have countered the effects of gravity - most types of light LCM were unsuitable for the type of loss (fractures) they were studying.


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2. LCM mixtures provided the best results. Adding LCM elements of similar size to the fracture provided support structure for other LCM to build on.

3. Results improved when the drilling fluid was made thicker and when LCM

concentrations were increased to levels (>200 kg/m3) exceeding conventional levels.

4. The slower the placement regime (pump output) the less time is required for

complete plugging to occur. 16.4.6 Spotting Pills It is normal practice to use reserve fluid to mix LCM pills, however, fresh fluid can be made using a simple recipe with sufficient viscosity to suspend the solids, but with no fluid loss control additives. Prior to spotting any pill the bit should be pulled up above the loss zone. Most LCM pills will not plug a normal jet bit. However, with turbines the use of LCM cannot be recommend without opening the circulating ports. The pill should be displaced gently and spotted at the loss zone. The pill should remain static for two to four hours before the pumps are started again. This should be done gently and the circulation rate increased slowly while carefully monitoring the pit volumes. If required, a gentle squeeze can be applied to the pill by initially circulating just above the loss zone. High filtrate loss, fibrous-type pills may be squeezed by closing the hydril and applying about 400-600 kPa standpipe pressure. In many cases a well will heal itself if left static while keeping the annulus topped up. This is a good procedure to try first. Monitoring the amount of fluid needed to keep the well full gives an indication as to whether or not the hole is healing. In extreme circumstances the annulus can be topped up with water. Care should be taken as this will result in further decreases in hydrostatic head. 16.4.7 Methods of Preventing Lost Circulation When drilling in areas where lost circulation is encountered, it is important to have detailed information about the formation pore pressure, pore size and fracture strength. Engineering and drilling practices should adhere strictly to prescribed programs. In these areas, drilling with the lowest safe density should minimize the hydrostatic pressure of the fluid column. The equivalent circulating density (ECD) can be minimized by adjusting rheological properties to within safe limits. Circulation should be broken cautiously while slowly pulling the pipe. Drilling rates should be controlled to avoid overloading the annulus with cuttings. 9 out of 10 drilling problems originate from drilling too fast. 16.5 Abnormal Pressures An abnormally pressured formation is a formation where the pore pressure exceeds the fresh water pressure gradient. In any formation where the pore pressure exceeds the pressure exerted by the column of wellbore fluid, the pore fluid will flow into the wellbore. This situation can occur in almost any area where oil wells are drilled. When it happens remedial decisions and measures must be made instantly in order to avert disaster. A discussion of the geological reasons for the existence of abnormal pressures is given in the chapter entitled Pressure Gradients, Rock Mechanics and Borehole Stability. Much literature is available on pressure detection and control.


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Most operators also have their own procedures and policies. Therefore the subject of well control is dealt with in general terms in this section. Continuing and updated well control education should be a normal part of drilling fluid engineering. Drilling fluid engineers should always take the initiative to become familiar with well control regulations and policies at each jobsite. A thorough knowledge of the area and the drilling fluids program are also necessary. In a well control situation the drilling fluid engineer is an integral part of a team. This job is not always simply limited to monitoring volumes and densities. He should be prepared to offer input in terms of his observations, suggestions and experience. 16.5.1 Common Causes of Fluid Influx When formation or pore fluids enter the wellbore unintentionally, the term kick is used. When control over the influx is lost, the kick becomes a blowout. The majority of blowouts are attributable to human error. Most fluid influxes occur while the pipe is being pulled out of the hole. Some of the common causes of fluid influx are discussed here. Abnormal pressures can cause a kick if they are incorrectly anticipated or not anticipated at all. In some cases the transition to overpressure is almost instantaneous, occurring within a few meters. Insufficient fluid density can cause a kick, especially while tripping with a close-to-balance fluid column. Here the actual fluid density is less than the equivalent circulating density (ECD). When circulation is stopped there is insufficient hydrostatic pressure to contain the formation fluids. Other contributors to this mechanism can include insufficient gas removal at surface or leaving water running into the active system while making a connection. Lost circulation can often induce a kick. This happens because the hydrostatic pressure exerted on the formation decreases with the height of the fluid column. Failing to keep the hole full while tripping is a primary cause of kicks. If drilling fluid isn't added to compensate for the volume loss due to the removal of pipe, the annulus fluid level will drop - reducing the hydrostatic pressure. Several measurement techniques are usually used to monitor the amount of fluid the hole is taking. Swabbing occurs when the drill pipe is pulled too fast. Suction is created behind the pipe because the drilling fluid does not fill the void as fast as the pipe is being pulled. Pressure changes due to pipe movement are affected by: 1. The speed of the pipe 2. The size of the pipe versus the size of the hole 3. The properties of the fluid, including density and viscosity 4. The size of the bit nozzles 5. The amount of formation material clinging to the pipe 16.5.2 Detection An attempt to predict the pore pressure gradient is usually made while most wells are in the programming stage. Offset well data, shale resistivity logs, acoustic logs and seismic data are used to locate or predict trends. The chapter on Pressure Gradients, Rock mechanics and Borehole Stability contains a diagram showing a direct correlation between a change in the


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formation bulk density and a transition to overpressure. When drilling is underway, a variety of methods are available for detecting a transitional increase in pore pressure or an actual influx of formation fluids. With the advent of sophisticated measurement while drilling (MWD) equipment, changes in the pore pressure may be extrapolated. Correlating gamma ray and resistivity deflections can indicate a change from a shale to a sand and imply whether the sand is water-wet or oil-wet. Pore pressure transitions can also be predicted mathematically with an equation having an output value called the "d" exponent, a dimensionless number. The d exponent is related to the differential pressure - between the drilling fluid and the pore fluid. This value is used to adjust the drilling fluid density. The d exponent usually increases with depth, but as the formation becomes overpressured, it will decrease. The d exponent is derived from a fundamental drilling equation, which the penetration rate (ROP) to: weight on bit, rotary speed, bit size and formation durability. R D = ___60N___ (log) 12W D106 Where: R = ROP N = Rotary RPM W = Force on Bit D = Bit diameter d = Drilling exponent This method of pore pressure prediction has certain disadvantages. For any degree of accuracy to be attained, several of the drilling parameters must remain constant simultaneously. The equation does not consider drilling fluid properties, hydraulic values or flow rates. However, the method is often quite accurate. Most operators install equipment at the shaker which will detect and record the volume of formation gas returning from the wellbore. Gas is reported in specific units or as a %. This method is one of the most reliable and widely used methods of detecting a transition to overpressure while drilling. Gas is often located in the same formation as oil and water - but is detected first, since it is located at the top of a reservoir. An increase in gas units often triggers a mud density increase. When circulation is stopped, gas will feed into the wellbore. Thus the gas units can be expected to increase at bottoms up after a trip or a connection. Returning gas is classified as Background Gas, Trip Gas, or Connection Gas. When the background gas levels remain fairly constant, the ratio of connection gas over background gas is monitored. In close-to-balance situations some operators perform a "feed in test". Here the pipe is reciprocated near bottom with the pumps off. This is done in an attempt to swab formation gas into the wellbore. Usually drilling ahead ceases until the gas returns to surface. The role played by the drilling fluid engineer during these proceedings is to ensure that the drilling fluid properties - especially viscosity and gel strengths - are low enough that the gas can break out of the fluid on surface. The condition of the gas removal equipment on surface is also an important consideration. Pumping circulated formation gas back down the hole must be avoided. There are several methods of detecting a formation fluid influx once it has occurred. Most of these involve changes - usually increases - in active circulating volume. It is extremely important


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for the drilling fluid Engineer to monitor and record his fluid volumes at all times. Any adjustments to the active volume must be recorded and reported to those operating volume-recording equipment. Adjustments to active volume means: dilution, dumping, solids equipment, discharge, barite addition and volume transfers. While drilling, an influx may be manifested as drilling fluid cut with formation fluid. This could be gas, oil or water. The actual evidence could be visual: gas bubbles or oil, physical: a density or viscosity change or chemical: a fluctuation in filtrate salinity or an increase in the volume fraction of oil. While drilling ahead, sensing devices monitor the rate at which fluid returns from the wellbore. An increase in this rate triggers an alarm. If the rate of formation fluid influx is too slow for these devices to record, monitors which record the surface pit volume are expected to trigger alarms when the pit volume increases. Often these systems have more than one back-up. When a high-return flow or a pit gain is encountered, a flow check is performed. Here the pipe is pulled off bottom and the pump stopped. The well is left static for 10-30 minutes. Observations are made both visually and with recording devices. Any indication that the well is flowing immediately initiates well-kill operations. Other, less reliable indications that an influx or a pore pressure transition is occurring include: variations in ROP, pump pressure, rotary torque, or string weight. Indications of an influx while tripping usually involve the hole not taking the calculated volume of drilling fluid, or when the pipe will not pull dry. Both of these situations usually initiate a flow check. 16.5.3 Methods of Control There are three approaches to controlling a flowing formation fluid. The method chosen depends on the severity of the influx. Primary Control is the use of the hydrostatic head of the drilling fluid to overbalance the formation pressure preventing foreign fluids from entering into the wellbore. Secondary control is the use of blowout prevention equipment to control the well in the event that primary control is lost. Tertiary control is the use of cement or barite plugs to control the flow if secondary control is lost or in danger of being lost. Primary control is usually initiated when one of the previously discussed methods of detecting a transition to overpressure occurs There are four recognized methods of containing a formation fluid influx by using secondary control methods. Since all of these methods have variations, the drilling fluid Engineer should become familiar with each operators procedures when he arrives on location. All of these methods involve shutting the well in. This means that either the annular preventer or the pipe rams are closed. In other words the formation pressure is not allowed to escape. Procedures for shutting a well in vary from onshore to offshore locations and depend on whether the influx occurred while drilling or during a trip.


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When the well is shut in, pressure builds both inside the drill pipe and the casing. Shut in time should usually not exceed 15-20 minutes. This is enough time to allow the well to become stabilized, where pressures cease to increase. During this period, if the casing pressure approaches the value required to physically break the formation rock below the last casing shoe, or burst the casing, the pressure must be allowed to escape. Once the well has stabilized, the shut in casing pressure (SICP) and the shut in drill pipe pressure (SIDPP) are recorded. Of these, the shut in drill pipe pressure value is the most important. The SIDPP is the same as the standpipe pressure. The drill pipe acts as a conduit. Actual downhole formation pressures are rapidly transmitted up the inside of the drillpipe to surface. When reading the SICP, a phenomenon known as Pressure Inversion may occur, causing variations in SICP values. A pressure inversion occurs when a well is shut in. The gas influx begins to rise up the annulus. Because the well is shut in, the gas can't expand as it rises. Because it can't expand it eventually carries the actual bottom-hole formation pressure to the surface. Once the SIDPP stabilizes, the density increase required to kill the well can be calculated by: 1. lb/gal = MW(#/gal) + SIDPP

0.052 x depth

Add this output value to the current drilling fluid density to obtain the density required to safely drill ahead with. The condition of the well will dictate which method of well control will be implemented. They include: 1. The Drillers Method 2. The Wait and Weight Method 3. The Concurrent Method 4. The Low Choke Method The details of these methods as outlined in this text are not complete: The Drillers Method uses two circulations to control the kick. The first circulation involves circulating the kick out of the hole while maintaining the initial circulating drill pipe pressure until the kick has been circulated out. The well can then be shut in while the active system density is raised to kill density. When this is accomplished the densified fluid is pumped down the pipe, while the casing pressure is held constant. When the densified fluid reaches the bit, the circulating pressure on the drill pipe at that moment is maintained until the densified fluid returns to surface. The Wait and Weight Method of well control is the most common. Here the well is shut in while the density in the pits is raised to the calculated kill density. The pipe is displaced to this fluid at a constant (reduced) speed. When the fluid reaches the bit, the pump speed is held constant and a final circulating drill pipe pressure is maintained with the choke, until the heavier fluid returns to surface. The greatest concern when using this method is the time taken to build the kill fluid. If the influx is gas, the rising bubble will eventually bring the formation fluid to surface, possibly exceeding the formation integrity at some point. The Concurrent Method is similar to the two previously described methods. The kick is circulated out of the well and during the same circulation; the active system is densified to balance the formation pressure. This method works well as long as enough trained people are available to supply barite to the pit room at a rapid enough rate.


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The Low Choke Method of well control is used where the shut in casing pressure exceeds the maximum limitations. Here the choke is used to hold as much back pressure on the casing as possible while circulating as rapidly as possible, while mixing barite. Crews working in the pit room should attempt to salvage as much returning drilling fluid as possible. Once the bubble is located inside the casing, consideration should be given to the reduced hydrostatic in the wellbore due to the difference between the gas and the fluid density. (Since the choke is partly open, the gas may expand on its way up the annulus). The gas expansion law simply stated says that: 1. A given volume of gas multiplied by the pressure at which that gas is contained is

always constant. 2. If a given volume of gas is allowed to expand from one volume to a larger

volume, then its pressure is multiplied by its volume in one instance is equal to its pressure times its volume in the other instance.

While circulating out a liquid kick such as salt-water or oil, the original shut in casing pressure should be the maximum casing pressure needed to kill the well. This is not so with a gas kick since the gas must expand on it’s way up the annulus. If secondary control of a well is lost, cement plugs and barite plugs are pumped 16.5.4 Shallow Gas The term shallow gas is usually defined as gas from shallow sand zones often occurring before surface casing has been set. "Shallow gas represents one of the most serious operational problems today in the drilling for oil and gas". This was the conclusion of the West Vanguard commission in October 1985. Prior to drilling, shallow gas occurrences are often predicted with seismic techniques. Offset well data is also used. However it is not always possible to prevent the occurrence of shallow gas flow. These flows are difficult to handle for several reasons. At shallow depths reaction times are reduced. Often, blow out preventers have not been installed because casing hasn't been set. If blow out preventers are installed, operators are often hesitant to hold back pressure for fear of losing formation integrity. If a shallow gas situation occurs while drilling without a riser, there are virtually no meaningful input parameters available for contingency planning. Most operators concur in general that on any location where shallow gas is likely to occur, and even if it isn't likely, kill mud should be kept on hand. Usually this is weighted to about 200 kg/m3 above the active system density. Often two times the expected hole volume at surface hole T.D. is kept on hand. (If this fluid is not used it is blended in to the active system on subsequent intervals.) When shallow gas is encountered the diverter is closed, and the kill mud is pumped as quickly as possible. During this procedure the pump should not be stopped for any reason. When the kill mud is gone the well may be observed. If it continues to flow usually all of the remaining drilling fluid is pumped away.


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16.5.5 Kick Tolerance The term kick tolerance is the name given to an equation, which effectively describes where the next casing setting depth should be. Drilling beyond that depth would jeopardize the operation in terms of being unable to safely contain formation pore pressures. Various operators and government agencies have developed their own kick tolerance equations. Inputs into these equations include: 1. PIT - determines the maximum allowable shut-in casing pressure. 2. Safety factor - used by some, but omitted by others, since often a low PIT value

is interpreted. 3. Fluid influx - accounts for a decrease in hydrostatic pressure when a formation

fluid has entered the wellbore. 4. Surge gradient - accounts for pressure surges against the formation when pumps

are turned on. 5. Riser margin - accounts for failure or removal of the marine riser. Here the

hydrostatic gradient supplied by the drilling fluid from the connector to the rotary table is replaced by a seawater gradient from the connector to sea level and an atmospheric gradient from sea level to the rotary table.

16.5.6 Gas Hydrates Hydrates are what are known as an inclusion compound. In these compounds, guest molecules fit into cavities formed by the host molecules. When the host molecule is water and the guest molecule is a natural gas - usually methane - the inclusion compound is called a natural gas hydrate. These solid molecules are similar to ice. Gas hydrates encountered in the formation while drilling are called in situ hydrates. One cubic foot of gas hydrate may contain more than 170 cubic feet of natural gas. Pressure / temperature equilibrium curves have been established for various combinations of water and gas. These can be extrapolated into temperature / depth curves as shown in Figure 16.3.2

Figure 16.3 Temperature vs Depth for Methane Hydrate

0

500

1000

1500

2000

-12 -6 -1 4 10 15 21 27 32 37

Temperature oC

Dep

th (

m)

Pressure gradient = 9.84 kPa/m


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The presence of other components such as ethane and propane shift the methane equilibrium curve to the right. The exception is nitrogen, which shifts the curve to the left. The addition of salt lowers the decomposition temperature of hydrates - similar to depressing the freeze point of pure water. Hydrates may co-exist with water or gas. The gas content in the drilling fluid increases as hydrate intervals are penetrated. The source of the gas stems from decomposing hydrates as they travel up the annulus where they are exposed to higher temperatures and less pressure. Hydrate decomposition also occurs around the wellbore. Increasing mud weight to prevent gas influx due to hydrates is not very effective since equilibrium hydrate pressures are much greater than normal hydrostatic mud pressures.3 Conventional logging techniques are used to detect hydrates. Extensive decomposition cannot have occurred for this to be effective. Inputs into the overall diagnosis include: resistivity, sonic, gamma ray, caliper, SP and density/neutron porosity. The decomposition of hydrates in the wellbore causes problems with well control, borehole stability and borehole gauge, affecting casing, logging and cementing design criteria. Hydrates may be found below permafrost. In the Canadian Arctic, the best line of defense has been to cool the drilling fluid using the mud coolers (heat exchangers) on board most of the offshore vessels. Diagnosing hydrates while drilling is difficult. Often the background gas units do not respond normally (decrease) to an increase in fluid density. On rare occasions formation material containing hydrates may be seen at surface. This material looks like normal cuttings, but when squeezed in your hand it fizzes and pops. These cuttings burn violently, so keep them away from open flames. Hydrates can also be a problem in deep water drilling. Hydrates can form in sub sea equipment while circulating out a gas kick, or while the well is shut in. Extreme water depths can create temperature and pressure conditions suitable for the formation of hydrates. It is known that certain substances suppress hydrate formation. In other words, their presence requires that at a given pressure a lower temperature is required for hydrates to form. These include: 1. Drilling Fluid Solids 2. Chemical Additives 3. Diesel Oil 4. Methanol 5. Seawater This shows that impurities in the liquid phase have an inhibiting effect on the ability of hydrates to form. With respect to chemical additives it has been postulated that polar compounds may identify with water molecules and inhibit hydrate formation in a similar manner to alcohols.


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16.6 OTHER COMMON PROBLEMS 16.6.1 Lubricity Friction is a resistance that is encountered when two surfaces slide or intend to slide past each other. The friction we deal with in oil well drilling is seen when the pipe is rotated (rotary torque, measured in amps, foot pounds and Newton meters) and when the pipe is hoisted (hole drag, measured in pounds force or deca Newtons). Up to 90% of the energy input into rotary drilling is used to overcome torque and drag. As a well becomes deviated from vertical, with numerous direction changes, the more contact points between the pipe and the wellbore exist, and the greater the friction. In an extremely deviated well such as a horizontal well, or one with an "S" shaped profile, frictional forces can be excessive enough, such that pipe rotation is difficult. Measurements of torque and drag indicate that steel-on-steel torque and drag are higher than steel on rock. This is due to the lower friction coefficient in the filter cake. Generally if a rig has reached its power limit prior to running casing, it will not be possible to drill out without taking remedial steps. In horizontal wells and "S" shaped profiles using conventional water-based systems, we have seen solid-phase lubricants yield far superior results in terms of torque and drag than liquid-phase lubricants. Walnut hulls and especially graphite and Teflon beads often show the best results. Glass beads should be avoided especially for steel-on-steel torque since they often become pulverized, it's like pumping sand down the hole. Liquid-phase lubricants work well when they are used as spotting fluids. These pills contain a mixture of solid-phase and liquid-phase lubricants added to active drilling fluid. The pill is spotted in a troublesome area of the hole prior to tripping or pulling out to run casing. Many operators have successfully been reducing torque and drag by up to 30% by simply adding Bentonite to the active system. Initially 5-10 kg/m3 is added, followed by daily treatments. The Bentonite should always be added dry even in a salt system. 16.6.2 Mud Rings and Bit Balling Mud rings are formed from two separate mechanisms. The first involves drilling rapidly through formations containing high percentages of swelling clays. These clays are greedy for water - often they can't get enough. They tend to aggregate into balls (mud rings) as they are circulated up the annulus. By the time they reach the surface they are apt to plug up all of the primary mud handling equipment including the diverter, flow line, sand trap, shaker box and dilution ditch. The second mechanism occurs after a wiper trip when drilling through squeezing plastic formations. Chunks of formation are scraped from the wall of the hole as the bit and BHA are pulled through it. Again these aggregate balls cause problems when they finally reach surface. Although the effect is the same as the previously described "mud ring" these formation chunks are distinguished by being "dry" inside. Down time due to mud rings may be minimized by: 1. Reducing the ROP 2. Using an inhibitive fluid


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3. Minimizing drilled solids concentrations 6. Installing specialized surface equipment such as a gumbo box and flowline jets 7. Surfactants may help when added in sufficient concentrations 8. Adding a dispersant such as SAPP

Bit Balling occurs in the same type of formation as mud rings and for similar reasons, that is, cuttings stickiness due to their greediness for water. The mechanism of adhesion, described in Chapter 2 is also a factor. Bit balling can slow the ROP to zero. Usually the same mechanisms, which minimize mud rings, also help with bit balling. Once a bit is balled up a concentrated surfactant can help. Often rapid drill string rotation, off bottom is tried. Some brave drillers rotate to bottom with the pump off and apply weight to the bit. This may help but there is a danger of plugging the jets. 16.6.3 Foam Foaming can become a problem on any drilling fluid system although certain systems are known for their foaming tendencies. These include: Lignosulfonate, salt saturated and HEC Systems. Foam is desirable in a drilling fluid only when a foaming agent is intentionally added. In all other cases it can and often does cause problems with the drilling fluid. Causes of Foam include: 1. Formation gas bleeding into the wellbore or gas released from cuttings as they

travel up the annulus. 2. Surface agitation. Air becomes entrained in the fluid because hoppers and solids

equipment discharge above the surface of the fluid in the pits. 3. Air leaks in the pump suction. 4. Air trapped in the pipe after tripping. 5. Over treatment with surfactants. 6. Chemical causes - including: amines introduced by adding amine treated salts.

Sodium hydroxide added to an ammonium system. Foam affects drilling fluid properties by increasing the viscosity and gel strengths and by decreasing the plastic viscosity and density. Foam makes accurate density analysis difficult, increases corrosion rates, reduces annular hydrostatic head, and accelerates the wear on slush pumps, including the power-end components, crossheads and crosshead pins. When foaming occurs, remedial action must be prompt. As in any problem it is best to determine the cause before prescribing a remedy. Often this is difficult and in severe cases drilling may be suspended if the pumps are unable to maintain adequate suction. To reduce foaming, the fluid should be thinned, if possible. Submerge all discharges and roll the tanks with submerged guns to aid in removing bubbles. An alcohol-based defoamer may be added to the system at recommended concentrations. Often a 2-ethyl hexanol proves to be the best. Occasionally raising the pH or adding fresh bentonite to the system will dispel the foam. Spraying the surface of the pits with a fine spray of diesel, or water, or diluted alcohol also helps.


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Pilot test by adding the proposed treating chemicals to glass jars. Agitate the samples and observe the results. 16.6.4 Permafrost Permafrost has been described as a soil or rock which has been exposed to temperatures of below 0°C continuously for a period of two or more years. Permafrost can be located anywhere in an area just below surface to a depth of about 1000 m. It is estimated that 20% of the earth's surface has a permafrost layer. The water content of permafrost may range from zero to 100%. Pure ice lenses may exist in permafrost from a few centimeters to over 1 m in thickness. High resistivities and acoustic velocities often identify permafrost. Low mud gas readings also indicate the presence of permafrost. Often gas levels and formation pore pressures are high immediately beneath permafrost. Permafrost is extremely erodible, being affected by both the temperatures and the velocity of the drilling fluid. Most rigs used for permafrost drilling have heat exchangers for reducing the drilling fluid temperature. These use cold seawater as a heat exchange medium. Often the coldest seawater is located with a submersible pump. It may be as low as 0 - 0.5°C in the case of Arctic Offshore Drilling. This may reduce the suction tank temperatures to 0.5°C - 1.0°C. Although this seems cold, it will still melt the permafrost. Therefore, flow rates must be kept extremely low. Pumping large volumes of fluid by a permafrost interval accelerates erosion rates. When drilling any well that penetrates a permafrost zone, special consideration must be given to long and short-term abandonment. A frozen annulus is difficult to re-enter and freezing fluids may burst casing as they expand. Water-based drilling fluids are often freeze depressed with certain salts. If a fluid is not freeze depressed it becomes necessary to factor in the time required to freeze depress enough fluid to spot by the permafrost prior to hanging off. Packer fluids must also be freeze depressed, or made from oil-based ingredients. 16.7 HORIZONTAL DRILLING 16.7.1 Horizontal Drilling Techniques There are three techniques used in turning a vertical well into a horizontal well. Short radius technology reaches the horizontal direction most quickly (30-90/m drilled) by the use of articulated drive pipe to provide the torque, and unique curved drilling assemblies. This technology has advantages in small production fields. In formations topped with formations that are difficult to drill, easier near vertical wells can be drilled, followed by the short radius section into the reservoir. In addition, it has been found that short radius technology can more accurately hit a TVD (true vertical depth) target because of its fast build up rate and short curve. Short radius technology has particular application as a technique to redrill and complete a vertical well. Present systems drill relatively small holes (4 3/4 to 6 1/2 in.) and limited length (60-120 m). Due to the small size and tight radius MWD technology cannot be used. Medium radius systems use special motors for the angle build section and steerable motors for the horizontal section to achieve build-up rates of up to 65°/100 m. MWD techniques are used and horizontal intervals have been drilled up to 1000 m in length in a 3 m thick pay zone. Long radius techniques use steerable motors or rotary assemblies with build rates of up to 20°/100 m. Longer horizontal distances can be achieved in larger hole distances. Torque and drag and targeting are the most common problems using this technique.


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16.7.2 Advantages of Horizontal Wells The flow into a vertical and horizontal well are compared in Figure 16.4. This shows that from a side view, flow to a vertical well appears parallel while flow to horizontal well combines parallel and radial flow. From a top view, parallel flow occurs in a horizontal flow, compared to radial flow in a vertical well. The higher proportion of parallel flow in a horizontal well means that the pressure differential between the formation and the well can be lower in the horizontal well than in the vertical well. This allows more efficient drainage and recovery of the reservoir and will lessen the coning effect where water is drawn into the well from below.

Vertical well

Parallel flow Radial flow

Horizontal well

Parallel plus radial flow Parallel flow

Figure 16.4 Side View Top View Horizontal wells have particular application in vertically fractured reservoirs where the chances of intersecting a fracture are significantly increased, as illustrated in Figure 16.5. The drainage in thin reservoirs can be dramatically improved by horizontal drainage. Multiple induced fracturing of tight gas formations has been a particularly good application for horizontal well drilling, as illustrated in Figure 16.5. Productivity is proportional to the length of the production zone but is always greater than comparable vertical holes by ratios varying from 2-10 times. Given that the drilling cost ratio is about 1.5, it can be seen that horizontal drilling offers substantial economic advantages.


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Figure 16.5 Typical applications for horizontal wells 16.7.3 Problem Areas One area of concern is directional control. The hole must stay within the targeted formation. Excessive deviation and correction leads to dog legs which significantly increase rotary torque and drag. The lubricating properties of the drilling fluid system are also vital, since the drill string rests on the bottom of the hole. Lubricity limits the bit weight and the torque limits of the pipe or the rig in turn it controls the length of the horizontal section. Well completion using traditional cementing and perforation techniques is not always successful. This is due to both the poor cement job, which tends to leave the top of the pipe uncemented and the difficulty of positioning the perforation gun.


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Open hole completion or pre-packed gravel completions are most common. This means that no new communication to the reservoir (no perforations) will be made, so limiting fluid loss and ensuring that the filtrate is non-damaging reduce the potential for formation damage. Production from the well is susceptible to sand blocking, as the produced sand will tend to accumulate on the downside of the hole. These problems require that particular attention be paid to drilling fluid properties. 16.7.4 Drilling Fluid Design Drilling fluids can minimize or eliminate a number of problems associated with horizontal well drilling and production. From the drilling perspective, problems with borehole stability, hole cleaning and high torque and drag are considerations which must be addressed in drilling fluid design. Producing wells of this type can also be aided or compromised by drilling fluid system choices. Problems with reservoir damage due to drilling fluids or permeability reduction due to interaction between the drilling fluids and reservoir fluids must also be considered. The geology of the project area can have a pronounced effect on the choices for drilling fluids. The type of reservoir (carbonates, sandstones, conglomerates), the intergranular cementing, the nature of the capping shale and other factors must be considered. The design criteria of the reservoir engineering group and geologists must be met to maximize the potential for good production. These considerations may eliminate the use of an oil-based drilling fluid where the unconsolidated sandstone or conglomerate is cemented with heavy, bitumic oil which could be dissolved by the oil-based fluid or, they may suggest the use of an oil-based fluid where the capping shale or an uphole shale is extremely water sensitive. They may require the use of a highly saline brine-based fluid to minimize swelling of interstitial clays in the producing zone. They may dictate the use of a fluid with a very low fluid loss and tight filtercake in cases where production may be hampered by solids migration into the production zone. Or they may eliminate the use of certain products or systems where emulsion blocking or formation of precipitates in the zone are known to be hazards. In drilling a horizontal well the largest stress, normally acting in the vertical direction, will generate the highest tangential stresses. This is normally achieved by higher drilling fluid density. The stress field should be determined as accurately as possible from calculations of the overburden pressure, pore pressure and leak off tests in adjoining wells. The mechanical properties of the rock can be determined from offset cores. This data can be used to calculate the optimum fluid density as the hole angle varies. A consequence of raising the density is to approach the fracture gradient where the rock fails in tension. Care must be taken to minimize pressure excesses through pipe movement (swab and surge pressure). Higher densities increase the filtration rate and the chances of differential sticking. Cuttings transport efficiency is a function of the annular velocity viscosity, gel strength, density and the angle of the hole. In a horizontal well, various sections will have deviation from 0° - 90°. The forces acting on a drilled cutting are gravity and the force carrying the particle out of the hole. As the hole angle changes, the relative direction of these forces changes. This is discussed in the chapter on Rheology. Between 30-60° the annular velocity should be two or three times higher than that required for vertical hole sections because of rapid formation of a bed of cuttings. In a horizontal well the bed will form instantaneously but is stable and will not slide as is the case for the wells around 45°. In high angle wells (55° to 90°) turbulent flow is more effective than laminar flow but it is difficult to achieve in practice in weighted systems due to pump output limitations. The low shear viscosity measured at 3 and 6 rpm on the Fann Viscometer should also be high, especially in oil-based systems where a 3 rpm reading of 15+ is recommended.


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The annular velocity should be as high as possible, consistent with the pressure drop available. Drill string rotation helps keep the cuttings bed disturbed. A low viscosity pill pumped in turbulent flow may be most effective at destabilizing the cuttings bed. Poor cuttings transport and the formation of a bed of cuttings should be anticipated. Back reaming and flushing the hole may eventually be the only way to clean the hole. Proper filtration control is essential in drilling horizontal wells in the production zone in order to reduce the incidence of differentially stuck pipe, maintain wellbore stability and minimize formation damage. The relationship between fluid loss control and these problems is fully discussed in chapters on Fluid Loss and Borehole Stability. Differential sticking problems will increase if the differential pressure between the fluid column and the pore pressure is high; the filter cake is thick and the fluid loss rate high. These factors, combine with gravitational forces pulling the pipe against the low side of the hole in the horizontal section, mean that the static and dynamic fluid loss values, measured at down hole temperatures, should be as low as possible. Drilled solids should be kept to a minimum and the filter cake should be thin, tough and slippery. Lubricants help in this regard. The producing formation will be contacted with drilling fluid and subjected to filtrate invasion. Many wells are completed without cemented casing and perforation due to difficulties with those techniques at very high angles. Prepacked liners and slotted casing are commonly used. Therefore, since there is no contact with undamaged formation by perforation, every care must be taken to ensure minimal formation damage. Formation damage mechanisms are discussed in the chapter entitled Production Zone Drilling, Completion and Workover. Well design must consider the friction generated between the string and the walls and the casing and the influence of the drilling fluid make-up on this factor. Rotary torque must be kept within the working limits of both the rotary drive system and the drill string. Drag forces while pulling out the hole must be within the tensile strength limits of the pipe and derrick. In summary, the design of the drilling fluid for horizontal well drilling applications must take into consideration the geological characteristics of the horizontal interval. The first consideration is to pick the least damaging fluid. In wells where high formation integrity is expected, such as in a limestone or dolomite zone or a very consolidated, well cemented sandstone or conglomerate, use of a fluid with low rheological properties and turbulent flow will probably give the best results. The degree of control of the fluid loss will be dictated by the potential of damage to the zone by solids migration, by swelling or dispersion of the clay fraction or by differential sticking tendency caused by drilling overbalanced into the zone. The use of physical torque reducers, weighting agents or lost circulation materials will be dictated by the potential of the targeted zone to have trouble with these problems. 16.8 TREND ANALYSIS One of the most important aspects of drilling fluid engineering and problem solving is the ability to recognize and analyze trends. Trend analysis is directly dependant upon accurate record keeping. This not only includes drilling fluid properties but also includes chemical treatments, dilution rates and drilling and lithological parameters. Drilling parameters include torque, drag, fill on bottom and ROP. Lithological Parameters include: cuttings type and characteristics and return gas units. Trends can be like road signs - pointing to potential problems. They can also be subliminal - often going unnoticed until it becomes costly to correct the problem. Slight changes in drilling


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fluid properties with no apparent explanation may be an indication that something abnormal is occurring somewhere in the system. Often graphing several properties and drilling parameters together, aids in correlating anomalous behavior. Be sure to graph properties versus time and depth. If certain properties drift slowly from the norm, it's a good idea to communicate this to as many people as possible. For example, if the drilling fluid engineer notes that excessive sharp cavings are returning to surface, he may verify that the shale is overpressured by discussing gas unit and pore pressure trends with the mud logger, then comparing his notes with in/out densities for the last several meters and hours. The driller may also verify these observations if he states, for example, that it is more difficult to wash and ream an interval than it was to drill it. Once a trend has been established it becomes important to determine the cause. The first step is to eliminate obvious analytical mistakes. Be sure the mud balance is calibrated and that all users are using the same one. Check to make sure that testing chemicals are still within their effective shelf life. Re-calculate numbers and confer with other drilling fluid engineers to ensure that all checks are being done the same way and that titration endpoints are the same. Often the cause is obvious, as in the case of drilling an evaporite such as salt or anhydrite. Sometimes the cause is subtler, as in the case of an acid gas influx. The most important considerations to remember when analyzing trends and predicting potential problems include: 1. Accuracy in measurement and recording. 2. Communication with others who may have viable input. 3. A logical course of action stemming from proper scientific analysis. Experience is

the key input at this point.


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REFERENCES 1. Zurdo, C., Georges, Cl., Martin, M., Mud and Cement for Horizontal Wells, SPE 15464,

1986. 2. Goodman, M.A., In situ Gas Hydrates - Past Experience and Exploration Concepts,

Enertech Engineering and Research Co. 3. Katz, D.A., Depths to Which Frozen Gas Fields (Gas Hydrates) May be Expected, JPT,

April, 1971.


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