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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 RETURN TO MENU
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.
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Drilling Fluids & Services
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services
Figure 1.1. Circulating System cross section 1 2 3 4 5 6 7 8 9
Pump Shock Hose / Standpipe Swivel / Top Drive Kelly / Drillpipe Bottom Hole Assembly Bit Open hole annulus Casing Shoe Casing
10 11 12 13 14 15 16 17 18
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Cased Annulus Guide Base Blow Out Prevention Stack Riser Flowline Diverter Diverter Line Shaker Mud Pits
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 subsurface 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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Drilling Fluids & Services 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. A Newpark Company -9-
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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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Drilling Fluids & Services 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 PHASE
CLASSIFICATION OF DRILLING FLUIDS SYSTEMS BASED ON THEIR FLUID Fluid Phase Water
Gas Gas Air or gas alone
Foam Air or gas with water and/or oil to form foam
Water Oil free water/brine fluids
Oil Direct Emulsion Continuous water/brine phase with emulsified oil
Oil Water free oil fluid
Invert Emulsion 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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Drilling Fluids & Services 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 Inhibit corrosion Solubilize polymers Alter charges on clays Aid inhibition
Polymers
Control fluid loss Deflocculation Flocculation Encapsulation Control viscosity Corrosion control Emulsion stabilization Prevent bit balling Control fluid loss Suspension properties
Alkaline Compounds
Acids
Cement contamination treatment Clay dispersion
Surfactants
Asphaltic derivatives
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. 2. 3.
By size; colloidal to gravel sized. By surface charge; reactive or inert. By how they entered the fluid; drilled solids or "commercial solids". A Newpark Company - 12 -
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Drilling Fluids & Services 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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Drilling Fluids & Services 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
§ § § § §
Mud tanks Product stockpile/warehouse PPE Safety Certification(s) Duties
ü On the rig
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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Drilling Fluids & Services ü Weekly Reports §
Monday/Thursday
§
ASAP with information!
§ § § §
Loads/timing Road Conditions Directions Special Instructions
ü Problems
ü Truckers
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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Drilling Fluids & Services 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
§ § §
Copies Floppy disk(s)/downloads Required Information
§ §
Timing Contents
5. Reporting ü Mud reports
ü Summaries
ü AVA Software § § §
Practice Ask Suggest
§
Timing/timeliness/duration
ü Telephone
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Drilling Fluids & Services
ü Timing/Frequency ü Crisis communications § § §
ASAP with information Customer expectations Ava Operations/sales expectations
§ § § § §
Per instructions in Ava Mud Manual or as defined by various API Bulletins Timing/timeliness/frequency Location Samples Pilot testing/laboratory analysis
§ § §
Personal Rig Fatigue
§ § §
Moving violations Tickets Other
6. Testing
7. Discussion ü Safety
ü Driving
ü Hot Shots/Deliveries § §
Insurance ADR
§ § §
Organization - planning/Notes - records Rig Hauling
§
Define/discuss
ü Duties
ü Service
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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 Sub Atomic
Example Protons,
Neutrons,
Size 0.1) and a weak base is one for which the value of the base ionization constant Kb is small ( 10-4M) is the following: Strong acids: Example 1: [HNO3] = 0.001M = C
pH = -log C
pH = -log 0.001 = 3.0 Strong bases:
Example 2: [KOH] = 0.5M = C
pH = 14 + log C
pH = 14 + log 0.5 = 14 – 0.3 = 13.7 Weak acids: [H+] ≈
Example 3: [CH3COOH] = 0.5M = C
Ka = 1.8⋅10-5
Weak bases: [OH-] ≈ Example 4: [NH4OH] = 0.5M = C
Kb = 1.8⋅10-5
pH = -log[H+]
Ka ⋅ C
[H+] ≈ Kb ⋅ C
Ka ⋅ C
= 0.003
pH ≈ 2.5
pH = 14 + log[OH-]
[OH-] ≈
Kb ⋅ C
= 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 CO 2 from the atmosphere, pure water at pH 7 is a difficult state to maintain. Why?
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Drilling Fluids & Services To understand this we have to understand the chemistry of CO 2, 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
H2CO3
H+ + HCO3-
H2O + CO2
H+ + HCO3-
Carbonic acid
With the huge amounts of CO 2 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.
H2CO3
H2O + CO2
NaHCO3 + H2O
NaOH + H2CO3
NaHCO3
NaOH + CO2
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.
NaOH + CO2
NaHCO3
NaOH + NaHCO3
H2O + Na2CO3 H2O + Na2CO3
2NaOH + CO2
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Drilling Fluids & Services
So what is Equation 1 and 3 telling us? Equation 3 says that with an excess of caustic all the CO 2 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 CO 2 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.
NaHCO3
NaOH + CO2 NaOH + NaHCO3
Equation 4
H2O + Na2CO3
Equation 5
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
Ca2+ + SO42-
CaSO4 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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Drilling Fluids & Services 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.
Ca2+ + 2OH-
Ca(OH)2 Ca2+ + 2OH- + NaHCO3
CaCO3 + NaOH + H2O
Ca(OH)2 + NaHCO3
O O 2 P P NaO O ONa + Ca(OH)2 NaO NaO
CaCO3 + Na2SO4
NaO NaO
O
O
P
P
O NaO
O Ca O
P O
O P ONa + 2NaOH O ONa ONa
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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Drilling Fluids & Services Fig. 21:
The Distribution of Carbonate Species as a Function of pH 1 0.9
% Molar Fraction
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 4
5
6
7
8
9
10
11
12
pH 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- & CO32-. If pH = 11.6 then the only ion present would be the CO32- (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 HCO 3 & 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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Drilling Fluids & Services 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 If Pf = Mf [OH-] = (2Pf – Mf) x 340 If Pf = 0
[HCO3-] = Mf x 1220
If 2Pf = Mf If 2Pf > Mf
[CO32-] = Pf x 1200 [OH-] = (2Pf – Mf) x 340 [CO32-] = (Mf – Pf) x 1200
If 2Pf < Mf
[CO32-] = Pf x [HCO3-] = (Mf
Comments Only [OH-] ions, no contaminates Only [HCO 3-] ions, will have a low pH (< 8.3) Only [CO32-] ions, two protons needed to neutralize CO32Both ions present. pH is > 11.6
1200 – 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 HCO 3- 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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Drilling Fluids & Services
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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.
F
F
mg
Figure 23
Figure 22
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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Drilling Fluids & Services 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.
Hydrophilic Head "water lover"
Hydrophobic tail, "oil lover" -
O3SO An Emulsifier
Oil -O3SO
-O 3SO
-O3SO -O 3SO
-O 3SO
-O3SO
H2O
Oil -O3SO
-O3SO -O 3SO
-O3SO
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. 3 A suspension with 100 kg/m 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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Drilling Fluids & Services 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 COOHgroup 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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:
Atmospheric Pressure
After Before ClNa+
After
Na+
H 2O
H2O Cl-
Vapor pressure
H2O
Semipermeable membrane 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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Drilling Fluids & Services 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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Drilling Fluids & Services REFERENCES 1. 2. 3. 4. 5. 6.
Stephen Hawkings, A Brief History of Time (New York: Bantom Books, 1988), 65. G. Hawley (Revised By), The Condensed Chemical Dictionary, 10th ed. (New York: Van Nostrand Reinhold Inc., 1981), 788. John M. Hunt, Petroleum Geo Chemistry and Geology (San Fransisco: W.H. Freeman and Company, 1979), 208-212. H. Van Olphen, An Introduction to Clay Colloid Chemistry, 2nd Ed. (New York: John Wiley & Sons, 1977). 23. Fred W. Billmyer, Jr., Textbook of Polymer Science, 2nd ed. (New York: Wiley Interscience, 1971), 23. Darley and Gray, Composition and Properties, 336.
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 preexisting 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. hydrocarbons are almost always located in the latter two types.
Commercial
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 Dolomite
-
CaCO3 CaMg (CO3)2
2.
Gypsum Anhydrite
-
CaSO4•2H2O CaSO4
3.
Halite
-
NaCl
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Drilling Fluids & Services 4.
Carnallite Potash Polyhalite
-
KMgCl3•6H2O KCl 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 coarsegrained 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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Drilling Fluids & Services increases the strength of the rocks and makes them more brittle. generally become harder and stronger with depth of burial.
Sedimentary formations
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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Drilling Fluids & Services 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 overpressured 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
Depth (M)
4000 3000 2000 1000 0 1
2
2.2
2.4
2.6
3
Bulk Density
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. defined by equation 9.2: Geostatic gradient
The geostatic or overburden gradient is then
= 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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Depth
Figure 3.2 Composite Overburden Stress, s, for a noramlly Compacted Formation 7000 6000 5000 4000 3000 2000 1000 0 0.19
0.2
0.21
0.22
0.23
0.24
Kg/cm2/m
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/m 3. 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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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.
H
Cl Cl
H C H H
Cl
P
Cl Cl
Cl Tetrahedral methane
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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Drilling Fluids & Services 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:
H2O + CO2
H2CO3 Al2Si2O5(OH)4 + 2KHCO3 + 4SiO2
2KAlSi3O8 + 2H2CO3 + H2O 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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Drilling Fluids & Services 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
Kaolinite Unit layer -
-
O
-
O
O
H+
H+
H+
OH
OH
OH
Illite
Unit layer
Unit layer
Unit layer -
-
O
O
K+ -O
K+ -O
Chlorite
Montmorillonite
-
O
-
-
O
K+
Ca+
-O
-O
O
O
Ca+ -O
-
-
O
-
O
-
O
Ca+ -O
-O
-O
-O
=Octahedral =Tetrahedral Figure 4.2a denotes a single tetrahedron or four sided unit. It usually contains a silicon ion (Si 4+); hence it may be referred to as the silica sheet.
O O Si O 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 Si 6O9(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 (Al 3+) 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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Drilling Fluids & Services 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 A Newpark Company - 93 -
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Drilling Fluids & Services 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 coordination 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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Drilling Fluids & Services 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 Sodium (Na+) Potassium (K+) Magnesium (Mg+2) Calcium (Ca+2)
Dehydrated ion diameter (Å) 1.90 2.66 1.30 1.90
Charge Density (charge/Å2) 0.088 0.045 0.376 0.176
Hydrated ion diameter (Å) 5.5 – 11.2 4.64 – 7.6 21.6 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 Al 2Si2O5(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. A Newpark Company - 98 -
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Drilling Fluids & Services (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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Drilling Fluids & Services 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 3 varies widely. Various cations may bind the unit layers together. 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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Drilling Fluids & Services 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 A Newpark Company - 101 -
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Drilling Fluids & Services 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 m 2. 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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Drilling Fluids & Services 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 Moisture, as shipped from point of manufacture: Wet screen analysis, residue on U.S. Sieve (ASTM) no. 200: *Viscometer dial reading at 600 rpm; *Yield point, lb/100 ft2: *Filtrate:
Specification 10% maximum 4% maximum 30 minimum 3 x PV Maximum 15.0 cm 3, maximum
* Properties of a suspension of 22.5 g of bentonite (as received) in 350 cm 3 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. A Newpark Company - 105 -
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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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Drilling Fluids & Services 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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Drilling Fluids & Services Table 4.3: Summarization of clay characteristics LAYERS
OCTAHEDRAL SHEET
EXPANSION
GROUP
Two-sheet (1:1)
Dioctahedral
Non-swelling
Kaolinite
Some swelling
Illite
Swelling
Montmorillonite
Trioctahedral
Swelling
Vermiculite
Kaolinite Dickite Narcite Illite 2 + Ca Montmorillonite Na+ Montmorillonite Vermiculite
Trioctahedral
Non-swelling
Chlorite
Chlorite varieties
Three-sheet (2:1) Four-sheet (2:1:1)
4.4
Dioctahedral
SPECIES
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services Figure 4.20: Flocculation
Table 4.4: Summary of Conditions which influence Clay Structures ENVIRONMENT Salt concentration
LESS STRUCTURE < 300 mg/l
pH Cationic concentration Polymer type
>8 Sodium Anionic, low molecular weight
4.5
MORE STRUCTURE > 3 000 mg/l Fast at 20000 mg/l < 6 and > 12 Calcium, aluminum High molecular weight
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, ferrochrome 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 A Newpark Company - 115 -
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Drilling Fluids & Services formation solids to disperse. In fact, the adsorption of lignosulfonate on clay surfaces reduces clay swelling and cleavage promoting hole stabilization and recovery of undispersed cuttings.6 Figure 4.21: Factors influencing bentonite dispersion
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Drilling Fluids & Services 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-toedge 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services Figure 4.24: Flocculation theories
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Drilling Fluids & Services 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 7 lignosulfonates. These compounds are referred to as thinners.
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Drilling Fluids & Services 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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Drilling Fluids & Services Table 4.5: Deflocculation with Lignite and Na2CO3 Parameter
600 300 Gel 0/10” pH 4.5.5
Sample 1 Base: 40 kg/m 3 bentonite 42 33 3/5 9.0
Sample 2 Base + 4 kg/m 3 CaSO4 58 49 21/18 7.9
Sample 3 Sample 2 + 4 kg/m 3 Lignite 48 43 6/12 7.4
Sample 4 Sample 2 + 4 kg/m 3 Na2CO3 51 42 8/14 8.5
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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Drilling Fluids & Services 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):
CH3
DM2HT N
CH3
Cl
DM2HT
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 Me
Me
Me Me N
Me Me
Me Me Me N
Me Me Me N
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 oilbased 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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Drilling Fluids & Services Figure 4.28: Low concentration of fully solvated organoclay with H-bonding between platelets
O
H
O
H O H
O H
H
H
O
H
H
H O
H
O H
H
H
H
H H
H O
H
O H
O
H O
H
H O H
H
H H
O
O
H O
H
H
H
H O
H
Figure 4.29: High concentration of fully solvated organoclay with tighter H-bonding between platelets
H
H O O
H
H O H
H
O H
H
O
H
H
H
O H
O H H O H
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 (% Clay content w) Montmorillonite CLAY 25-70 SOFT Illite Montmorillonite MUDSTONE 15-25 firm Illite Mix layer Treated montmoril. SHALE 5-15 hard High illite Illite SLATE 2.5 brittle Kaolin 100-80% calcium LIMESTONE carbonate 70-40% calcium MARL carbonate + 30-60% clays 10-40% calcium CALCAREOUS 15-60 firm carbonate + MUDSTONE 90-60% clays
MBT (meq/100g)
Density (g/cm3)
20-40
1.2-1.5
10-20
1.5-2.2
3-10
2.2-2.5
1-5
2.5-2.7
0
2.5-2.8
0-2
1.8-2.2
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 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.
(Tulsa: The Petroleum Publishing
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Drilling Fluids & Services
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Drilling Fluids & Services 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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Drilling Fluids & Services 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
HO OH O
OH
O OH
O OH
O
O OH
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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Drilling Fluids & Services 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: Ph3C Ph3C O
H
H
OH
O O
Acrylic acid
Ph3C H O
OH
ETC!!!
+
+ O
OH
OH
OH
O
O
OH
OH
O
OH
O
OH 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 CO 2. 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. 2. 3. 4. 5.
The number of monomers linked to form a polymer chain. The number of different types of monomers present in a polymer molecule and the order in which they occur. The shape and structure of the molecule. Electrolytic variables including the net charge, and the position and density of the charge. The chemical and structural modification of a polymer, subsequent to polymerization.
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Drilling Fluids & Services Figure 5.3 indicates how polymers may be classified according to the variables mentioned above. Figure 5.3: Classification of polymers Low MW
A
Hi MW
B
Branched
C
Alternate
D
Block
E
Random
F
Crosslinked
G
Linear HomoPolymers NonLinear
Linear
Co-Polymers
NonLinear
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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Drilling Fluids & Services 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 3dimensional 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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Drilling Fluids & Services 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 Alcohol
R OH O R Me O
Ether
Amide
R
NH2 R
O
N
Pyrrolidone
R N C O R–X
Isocyanates Alkyl halides Alkenes
R
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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Drilling Fluids & Services Table 5.2: Anionic Chemical Groups that Contribute to Reactivity of Polymers Chemical Formula
Name
O RO P O- 2M+ OO
Phosphate
R P O- 2M+ OO
Phosphonate
Carboxylate -
OM
R
+
O R S O-M+
Sulfonate
O O RO S O-M+
Sulfates
O
O R
O N
S O-M+
H
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 R N+(CH3)3Cl-
Ammonium Salts 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. A Newpark Company - 137 -
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Drilling Fluids & Services 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:
HO OH O OH
OH OH
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 nonnatural 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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Drilling Fluids & Services
Figure 5.8: O O
Na+-O
OH O
OO O
OH
O
OH
O
O OH
O-Na+
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:
O
O R
NH2
amide
H 2O
R
OH
+ NH3
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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Drilling Fluids & Services Figure 5.10: Polyacrylamide
O
NH 2 O
NH 2 O
NH 2 n
Figure 5.11: Partially Hydrolyzed (with OH) Polyacrylamide (PHPA)
O
NH2 O
OH
O
NH2 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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Drilling Fluids & Services
TABLE 5.4: Classifications of drilling fluid polymers NAME
MOLECULAR CHARGE / SHAPE WEIGHT
FUNCTION 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) Carboxymethyl cellulose (CMC HV – CMC HV)
Polyanionic Cellulose (PAC RG – PAC SL)
Xanthan Gum (XC – XCD) Lignosulfonate Lignite
Viscosity especially in completion fluids Viscosity and fluid loss control at high MW (HV)
Nonionic/Linear Anionic/Linear Diverse
Fluid loss control at low MW (LV) Viscosity control at high MW (RG)
Anionic/Linear Anionic/Linear Diverse
Fluid loss control at low MW (SL) Viscofier in fresh or salt water – 5⋅106 – 20⋅106 thixotropic properties Deflocculant and Fluid loss 103 – 20⋅103 control Deflocculant and Fluid loss 103 – 20⋅103 control
Anionic/Linear Anionic/Branched Anionic/Branched Anionic/Branched
Synthetic Polymers Polyphosphates (SAPP) Deflocculant
Anionic Acrylic Polymers
Polyacrylmide (PHPA)
Encapsulator and Clay Flocculant
Sodium Polyacrylate (PA)
Temperature stable Deflocculant Fluid Loss Reducer
Sulfonated Styrene/Maleic Anhydrite (SSMA) Sulfonated Vinyl Copolymer (VAVS)
> 3⋅106 Average 106
Anionic/Linear
7⋅103 – 10⋅106
Anionic/Linear
Hi Temp Deflocculant
1000 – 5000
Copolymer
Hi Temp Fluid Loss Control Secondary Viscofier
1⋅10 – 2⋅10
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6
Copolymer
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Drilling Fluids & Services 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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Drilling Fluids & Services 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
HO OH O
HO OH O OH
OH OH
O OH
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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Drilling Fluids & Services Figure 5.13: Hydrolysis of amide group
O
O NaOH R
NH2
amide
R
ONa
+ NH3
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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Drilling Fluids & Services 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 A Newpark Company - 147 -
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Drilling Fluids & Services 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)
O
O-
-
O
O
O
O-
-
O
O
O-
-
O
O
O
Ca++
Calcium bridges Ca O
O
-
O
5.3.4
O
Ca
O
O
O
O
O
O
OO
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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, depolymerization 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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Drilling Fluids & Services 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 3 weight. The low molecular weight polymer is about 60⋅10 and the higher molecular weight 3 polymer is about 200⋅10 , 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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Drilling Fluids & Services Figure 5.16: H H
O
Na+
Na+ H
H
N a+
Na+
O H
Na+
H
O H H
O H
Na+
H
O
N a+
A . U n h y d r a t e d a n io n ic p o ly m e r
P a r it ia l ly h y d r a t e d H
H
O
O
H
H
H H
O
H
O
H H
O
H
H H
F u lly h y d r a t e d w it h a c r y s t a ll in e la y e r o f w a t e r
O
H H H
O
H H
O
O
H
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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Drilling Fluids & Services 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. 2. 3.
Plugging or blocking pores. Increasing fluid phase viscosity 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 aminebased 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 gelbased 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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
Hydrophilic Head "water lover"
Hydrophobic tail, "oil lover" -
O3SO An Emulsifier
Oil -O3SO
-O3SO
-O3SO -O3SO
-O3SO
-O3SO
H2O
Oil -O3SO
-O3SO -O3SO
-O3SO
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. A Newpark Company - 159 -
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Drilling Fluids & Services
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 3–6 7–9 8 – 15 13 – 15 15 – 18
Application Water in Oil emulsifier Wetting agent Oil in Water emulsifier Detergent Solubilizer
Table 5.6: Water solubility according to HLB ratio HLB range 1–4 3–6 6–8 8 – 10 10 – 13 > 13
Water solubility No dispersability Poor dispersion Milky dispersion after vigorous agitation Stable milky dispersion Translucent to clear solution 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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Drilling Fluids & Services 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 3 3 straight chains of glucose residues ranging in molecular weight from 10⋅10 to 100⋅10 . The major 3 3 component, amylopectin has a molecular weight of 40⋅10 to 100⋅10 and is comprised of branched molecules.
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 O O
Na+-O
OH O
OH
OO O
O
O OH
O OH
O-Na+
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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/m 3.
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Drilling Fluids & Services A derivative product, CMHEC is made by the sequential treatment of alkali cellulose with chloroacetic 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. Crosslinking 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 A Newpark Company - 166 -
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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 3 weight is about 500⋅10 .
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Drilling Fluids & Services
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/m 3) 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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Drilling Fluids & Services •
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 costeffective 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
HO
HO O OH
O OH
OH
O
O OH
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 CO 2 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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Drilling Fluids & Services 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 O
OH
O
NH2 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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Drilling Fluids & Services 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 Deflocculant Fluid Loss Additive Flocculant Bentonite Extender
MOLECULAR WEIGHT (x 103) 7 6 3000 10000
NUMBER OF MONOMERS (x 103) 1 8 40 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
O
OH
O
OH 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 phaseseparation 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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Drilling Fluids & Services 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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Drilling Fluids & Services polymer is especially applicable in cement-contaminated systems where deflocculation is essential, especially in hot holes. Figure 5.35: Sulfonated styrene maleic anhydride (SSMA)
O
O-Na+ O O-Na+
SO2O-Na+
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Drilling Fluids & Services 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 Where: q
= A P l k µ
A•P µ•l
the flow rate = the cross section area = the pressure differential across the filter = the length of the filter bed = a constant related to the physical character of the filter bed = 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 cm 2 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 = Where: qw
= qc µ k
6.2.3
2 • k • P •A2 µ
qw • qc
• t
the volume of the filtrate at time t = the volume of the filter cake (related to the thickness of the filter cake, L, through the area of the filter cake, A) = the viscosity of the filtrate = the permeability of the filter cake
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 cm 2 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 Where: q1
= t1 t2 q2
t2 t1
The recovered volume of filtrate (cm 2) = The time at which q1, was measured = The time at which a calculated volume of filtrate is required (usually 30 min.) = The unknown volume of filtrate (cm3) at the time t2
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Drilling Fluids & Services The 30-minute filtrate volume may be predicted by measuring the volume at 7.5 minutes and doubling the value, since: 30 = 2 7.5
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 Where: t
= q2 q30
30 t
the time the sample was recorded = the volume of filtrate at t1 = 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) Where
q0
=
t30 t1
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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Drilling Fluids & Services 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 oilbased 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: qw • l • µ k = 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 cm 3, 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 Good oil production Gas production tight sandstone Filter cake Shale
5 000 - 10 000 10 - 1 000 0.1 - 1 0.002 - 0.150 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. A Newpark Company - 182 -
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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 freshwater 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 Where:
q2 q1
= q1
viscosity1 viscosity2
= unknown filtrate volume at viscosity1 (cm 3) = 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 cm 3 to 14 cm3 if the temperature were increased from 10°C to 40°C in a water-based system: 14.19 = 10 Table 6.2
1.308 0.656
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 = Where:
k1(τ /f)-v+1 µl(-v+1) k1 τ f
= the cake permeability at 1 psi = the shear stress exerted by the fluid = the coefficient of internal friction of the cakes surface
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Drilling Fluids & Services µ l (-v+1)
= viscosity = the equilibrium cake thickness = 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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Drilling Fluids & Services 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 cm 3 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 cm 3/hr for starch, 1.0 cm 3/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 cm 2/30 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: 2
pD 4
q = Where:
q n RPM C
= = = =
n • RPM C
3
filtration rate (cm /s) number of cones bit revolutions/minute 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 A Newpark Company - 186 -
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Drilling Fluids & Services 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, 1/2 and the factor (Cc / Cm - 1) . 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 6.4.3
Particle size distribution in a filter cake
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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Drilling Fluids & Services 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
1 kg/m 3 HEC in salt water 3
9 kg/m CaCO3 in salt water 3
3
1 kg/m HEC + 9 kg/m CaCO3
PV
Properties YP, Pa
Fluid loss
20
22
91.5
1
0
No control
17
9
8.2
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Drilling Fluids & Services 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
ok
good
good
ok
ok
good
x
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
good
ok
good
ok
good
x
x
Fresh water Sea water
Producing formations
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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Drilling Fluids & Services 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 cm 3, 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 A U
= = =
the force the contact area the coefficient of friction between the collars and the cake.
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Drilling Fluids & Services 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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Drilling Fluids & Services
References 1 2
Darley & Grey, Composition and Properties, 298. Darley & Grey, Composition and Properties, 310.
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Drilling Fluids & Services
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 prehydrated 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. Polymerextended 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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. 2. 3. 4.
Salt Water / Fresh Water Dispersed / Non-Dispersed Inhibitive / Non-Inhibitive 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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Drilling Fluids & Services 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. 2. 3.
Unweighted Gyp - PAC Fresh water - Gel 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 engineeringoriented 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. 2. 3.
Define the objective of the interval. Identify factors, which may prevent rapid and economical realization of the objective. 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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Drilling Fluids & Services The first step, defining the objective of an interval is usually the easiest. Most intervals have engineering objectives. Various intervals are commonly called: 1. 2. 3.
Top Hole Intermediate Hole 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) 2) 3) 4) 5) 6) 7)
Environmental & Safety Considerations Abnormal Formation Pressures High Temperatures Excessive Deviation Borehole Instability Production Zone Damage 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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Drilling Fluids & Services 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) 2) 3) 4) 5) 6) 7) 8)
Gravel and Fractured Formations Evaporate Formations Tectonic Squeezing Overpressured Shale Zones Containing Gas Hydrates Permafrost High Formation Dip 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) 2) 3) 4) 5) 6)
X-Ray Diffraction Cation Exchange Capacity Balancing Salinity Swelling Measurements Dispersion Tests 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) 2) 3) 4) 5)
Water Block Emulsion Block Oil Damage to Gas Reservoirs Particle Invasion Precipitant Formation
Other common problems, which may impede achievement of the objective on any interval, include: 1) 2) 3) 4) 5) 6 7)
Severe Loss Zones Water Flows H2S (also a safety consideration) Bacteria Differential Sticking The Formation of Hydrates (safety also) 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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Drilling Fluids & Services 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. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
12. 13. 14.
Engineering Parameters A Lithological Description Pore Pressure Prediction Casing Setting Depths A Well Profile with KOP and DOP Proposed Fluids System - Usually by Interval Chemical Concentrations Required Fluid Properties Lab Testing Results Offset Well Information Contingency Formulations and Procedures - LCM Pills - Barite Plugs - Viscosity Sweeps - Lubricity Pills - Procedures and Directives from Regulatory Agencies - Corrosion Control Program A Materials and Volume Estimate by Interval A solids Control Program Price List
The properties of the drilling fluid of particular importance are: 1. 2. 3. 4. 7.4
Density - Formation Pressure Control Rheology - Optimum Cleaning and Hydraulics Salinity or Polymer Content Alkalinity
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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Drilling Fluids & Services 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 seawaterbased 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 Sulfate Bicarbonate Bromide Borate Nitrate Phosphate Fluoride Sodium Magnesium Calcium Potassium pH
19 000 2 700 100 60 25 0.7 0.1 1.3 11 000 1 300 400 400 7.5 - 8.5
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Drilling Fluids & Services 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 PRINCIPLE COMPONENT
SPECIFIC GRAVITY
MOH'S HARDNESS
CaCO3
2.65 2.71
3
COMMERCIAL PRODUCT
MINERAL
Calcium Carbonate
Calcium Carbonate
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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Drilling Fluids & Services 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/m 3 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
APPLICATION
SECONDARY BENEFIT
Acrylic Polymer
Bentonite Extender
Fluid Loss Reducer
Polyanionic Cellulose
Substituted Cellulose Polymer
Viscosifier - used in Special Applications (Gyp / PAC)
Fluid Loss Reducer
Avagel
Bentonite
Hydrous Aluminum Silicate
Fluid Loss Viscosifier - May Require Pre-hydration Reducer
Natrosol
Hydroxy Ethyl Cellulose Derivative Cellulose
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 BioPolysaccaride
LSR Viscosifier
Fluid Loss Reducer
Avagum
Guar Gum
Natural Polysaccharide
Viscosity Sweeps in Large Holes
Drilled Solids Flocculant
TRADE NAME
MATERIAL
PRINCIPAL COMPONENT
Avabex
Polyacrylate
Policell
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Drilling Fluids & Services 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. 2. 3.
Reduction of cake permeability by deflocculation and compression. Reduction of flow-rate by viscosification of the liquid phase. 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
Avalig Avalig C
Natural Coal Product Sodium Humate
Victosal
Modified Starch
CMC
Carboxymethyll Cellulose
Policell
Polyanionic Cellulose
Filtration Control in Brackish Environments
Avapoly HT
Synthetic Polymer
Filtration Control > 200°C
APPLICATION Economical Filtration Control Filtration Control in High-temp. Saline Evnironments Filtration Control in Highly Saline Environments Economical Filtration Control
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SECONDARY FUNCTIONS Deflocculation Deflocculation Acid Soluble Some Viscosification Moderate Deflocculation in Unweighted Salt Systems Moderate Deflocculation
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Drilling Fluids & Services 7.4.5
Rheology Control Additives
Rheology control additives are generally used to extend the performance limitations of waterbased 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. 2. 3. 4. 5
Balanced Activity Cation Exchange Encapsulation Plastering (Plugging Micro fractures) 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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Drilling Fluids & Services TABLE 7.9
SHALE STABILIZATION ADDITIVES
Cation Exchangers: Potassium
Calcium
Aluminum
Encapsulators: (Polyacrylamide) (Lignosulfonates) (Most PAC's) Plastering Materials: Gilsonite HT 7.4.7
(Bituminous)
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 Kwik Seal Mica
FIBROUS OM Seal
GRANULAR Sand Seal 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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Drilling Fluids & Services 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
Ecol Lube
Zinc carbonate
Sodium Bicarbonate
Potassium Hydroxide
Avoil WA
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 CO 2. 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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, 2+ Suppression of Ca 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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Drilling Fluids & Services 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 waterbased 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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Drilling Fluids & Services 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. 2. 3. 4.
Native Solids Bentonite/Lime Bentonite 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/m 3 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/m 3) 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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Drilling Fluids & Services 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. 2. 3. 4.
Rotary Torque Hole Drag Pump Pressure 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/m 3
Water NaCO3 NaOH Bentonite Yield for several hours
Soda Ash Caustic Soda Avagel
1.0 - 3.0 1.0 - 2.0 110.0 - 140.0
Add Seawater and small amounts of Caustic Typical Properties: Funnel Viscosity Yield Point pH
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100 - 150 sec/L 25 - 40 pa 8.0 - 8.5
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Drilling Fluids & Services 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/m 3
Water NaOH Guar Gum
Caustic Soda Avagum
0.5 - 1.5 8.0 - 15.0
Funnel Viscosity Yield Point pH
100 - 200 sec/L 25 - 40 pa 8.0 - 9.0
Yield 1 - 2 Hours Typical Properties:
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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Drilling Fluids & Services TABLE 7.15
VISCO 84 SPUD MUD (SWEEP)
ADDITIVE Water Xanthan Gum NaOH
PRODUCT NAME
CONCENTRATION (kg/m 3)
Visco 84 Caustic Soda
4.0 - 8.0 0.5 - 1.5
Funnel Viscosity Yield Point pH
45 - 200 sec/L 10 - 30 pa 7.5 - 9.0
Typical Properties:
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. 2. 3. 4.
Gas or Air Mist / Foam Stiff / Stable Foam 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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Drilling Fluids & Services 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. 2. 3. 4. 5. 6.
Inexpensive Rapid ROP's Low solids, non-abrasive Easy Maintenance Resistant to Contamination Sump water may be reclaimed for building drilling fluid
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Drilling Fluids & Services 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/m 3
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
CONCENTRATION (kg/m 3)
Polymer Flocculant CaCl2 Ca(OH)2
AvapolJ Calcium Chloride Lime
1-2 L/m 3 of 50% solution .5 - 1.5 kg/m 3 (100 - 300 mg/l Ca2+) pH: 9.5 - 10.0
Fluid Density Funnel Viscosity pH Calcium
1 000 - 1 020 kg/m3 27 - 28 s/l 9.5 - 10.0 100 - 300 mg/l
Typical Properties:
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 CaCl 2 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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Drilling Fluids & Services 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 CaCl 2 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 landbased 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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Drilling Fluids & Services 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. 2. 3.
Non-Dispersed Bentonite (Gel Chemical) Low Solids (Extended Gel) 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/m 3
Freshwater NaCO3 NaOH Bentonite CMC
Soda Ash Caustic Soda Avagel CMC
1.0 - 3.0 0.5 - 0.75 45 - 75 1-6
Funnel Viscosity Density PH Fluid Loss Calcium
Above 35 s/l 1,050 – 2,000 kg/m 3 9.0 - 10.0 3 - 10 ml/30 min Less than 100 mg/l
Typical Properties:
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. 3
Usually 60 - 70 kg/m 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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Drilling Fluids & Services 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. 2. 3. 4.
Fresh Water High pH Conditions High Mechanical (Shear) Energy 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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Drilling Fluids & Services TABLE 7.18
LOW SOLIDS (EXTENDED GEL) SYSTEM
ADDITIVE
PRODUCT NAME
CONCENTRATION (kg/m 3)
Freshwater NaCO3 NaOH Bentonite Extending Polymer CMC
Soda Ash Caustic Soda Avagel Avabex Carboxy Methyl Cellulose
1.0 - 3.0 0.5 - 0.75 30 - 60 .07 - .15 1-6
Funnel Viscosity Yield Point Plastic Viscosity Density Solids pH API Fluid Loss Calcium
35 - 60 s/l 7 - 15 Pa 10 - 25 mPa•s 1 060 - 1 100 kg/m3 4 - 7% (Vol) 9.0 - 10.0 2 - 8 ml/30 min Less than 100 mg/l
Typical Properties:
The material mixing order for Extended Gel systems is similar to the previously discussed NonDispersed 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. 2.
They inhibit shale hydration at higher concentrations. They impart good filtration properties to a system. A Newpark Company - 225 -
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Drilling Fluids & Services 3. 4. 5.
They are easy to maintain and compatible with most common additives. (Most clay-water systems can be easily converted to Lignosulfonate systems). They are inexpensive. 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
CONCENTRATION (kg/m 3)
Fresh or Seawater NaOH Bentonite Lignosulfonate Polyanionic Cellulose
Caustic Soda Avagel Avafluid G71 Policell
0.5 - 6.0 70 - 100 2 - 30 1-6
Funnel Viscosity Yield Point Plastic Viscosity Density pH API Fluid Loss
38 - 150 s/l 7 - 20 Pa 15 - 50 mPa•s 1 100 - 2 200 kg/m3 10.0 - 10.5 1 - 10 ml/30 min
Typical Properties:
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/m 3 is usually sufficient to deflocculate. If massive anhydrite or salt 3 contamination is expected 10 - 20 kg/m will be necessary to control both the flow properties and the fluid loss. In extreme cases, 20 - 30 kg/m 3 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/m 3 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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
Freshwater NaCl NaOH Drilling Starch Xanthan Gum or HEC
PRODUCT NAME
CONCENTRATION (kg/m 3)
Sodium Chloride Caustic Victosal Visco XC 84
350 - 360 1.5 - 2.0 5.5 - 17.0 2.0 - 4.0
Hydroxyethyl Cellulose
2.0 - 4.0
Yield Point Plastic Viscosity pH
5 - 8 Pa 10 - 12 mP•s 9.0 - 10.0
Typical Properties:
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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Drilling Fluids & Services 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 21°C 26°C 32°C 37°C
Salt to Saturate 360 362 363 365
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/m 3) 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 recontrol 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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Drilling Fluids & Services 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 Limebased 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/m 3 excess Lime or low Lime Mud - .3 - 1.0 kg/m 3 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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Drilling Fluids & Services TABLE 7.21
GYP / PAC SYSTEMa
ADDITIVE
PRODUCT NAME
CONCENTRATION (kg/m 3)
Water NaOH Polyanionic Cellulose Low Vis. Polyanionic Cellulose Hi Vis. CaSO4 Barite
Caustic Soda Policell SL Policell RG Gypsum Barite
0.3 9.0 3.0 18.0 to 1 400 kg/m3
Funnel Viscosity Yield Point Plastic Viscosity Gel Strengths Density pH API Fluid Loss Calcium MBT Excess Gyp
56 s/l 3.5 Pa 20 mPa•S 5.0 /10.0 Pa 1 400 kg/m 3 8.5 5.0 ml / 30 min. 4 500 mg/l as low as possible 6 kg/m 3
Typical Properties:
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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Drilling Fluids & Services
Firure 7.1 Solubility of Calcium as a Function of pH and Temperature 800
Calcium Conc. mg/l
700 600 500
70oC 50oC 20oC
400 300 200 100 0 10
10.5
11
11.5
12
12.5
13
13.5
14
pH 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 A Newpark Company - 232 -
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Drilling Fluids & Services 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 CONCENTRATION (kg/m 3)
ADDITIVE Seawater KCl K2CO3 KOH Xanthan Gum CMC/PAC Polymer
PRODUCT NAME Potassium Chloride Potassium Carbonate Potassium Hydroxide Visco XC 84 CMC/PAC
100 - 150 2-6 2-6 2-4 2-4
Funnel Viscosity Yield Point Plastic Viscosity pH Calcium K+ ClFluid Loss
45 - 70 s/l 5 - 10 Pa 7 - 15 mPa•s 8.5 - 9.0 Less than 400 mg/l 50 000 - 75 000 mg/l 65 000 - 90 000 mg/l 10 - 12 ml
Typical Properties:
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 makeup 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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Drilling Fluids & Services 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/m 3 to initiate drilling. When using PHB an alternate method of mixing the system involves adding the KCl to a light (20 - 30 kg/m 3) 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/m 3. 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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Drilling Fluids & Services 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 Al 2(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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Drilling Fluids & Services TABLE 7.23
Al2(SO4)3 SYSTEM
ADDITIVE
PRODUCT NAME
CONCENTRATION (kg/m 3)
Premix: Seawater Al2 (SO4)3 NaOH
Aluminum Sulfate Caustic Soda
144 60 (to pH 7 - 8)
Active System: Seawater Al2 (SO4)3 Premix to Net 12-15 kg/m 3 Al2 (SO4)3 NaOH Caustic Visco XC 84 Xanvis Policell Polyanionic Cellulose
2 4.5 3
Typical Properties: Funnel Viscosity Yield Point Plastic Viscosity pH API Fluid Loss
42 s/l 6 Pa 6 mPa•S 9.5 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 Al 2(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 Al 2(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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Drilling Fluids & Services 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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Drilling Fluids & Services
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/m 3)
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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Drilling Fluids & Services 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/m 3 is added to provide sufficient viscosity. Caustic Soda is added (0.5 - 0.75 kg/m 3) 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/m 3 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 “gyppedover” 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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Drilling Fluids & Services • •
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/m 3 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/m 3 of Bentonite and let this hydrate as long as possible in the tanks before any more product additions. Mix between 1.5 – 3 kg/m 3 of PHPA or polyacrylamide polymers into the system. Then lower the fluid loss to 6 – 8 ml with approximately 1 – 1.5 kg/m 3 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/m 3). 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 + Na Mg2+ Ca2+ + K + NH4
Dehydrated Radius A 0.95 0.65 0.95 1.33 1.43
Hydrated Radius A *2.75 – 5.6 10.8 9.5 *2.32 – 3.8 + similar to K
-10
Where A = Angstroms or 1 x 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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Drilling Fluids & Services 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/m 3 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/m 3 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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Drilling Fluids & Services 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 Visco XC Caustic Soda Policell Polivis
Clay Stabilizer Viscosity Alkalinity Fluid Loss Clay Stabilizer
6 - 8 l/m 3 1.5 - 2.0 kg/m 3 0.2 kg/ m3 1.0 - 1.5 kg/m 3 3.3 kg/m 3 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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Drilling Fluids & Services 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/m 3 and above. A 96-h. trout LC50 occurred at a concentration of 7.8 l/m 3. 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 Visco XCD Policell SL
Viscosity Viscosity Filtration Control
3.0 – 4.0 kg/m³ 0.5 – 1.0 kg/m³ 1 – 1.5 kg/m³
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Drilling Fluids & Services Victosal Caustic Soda
Filtration Control Alkalinity
8.0 - 12.0 kg/m³ 0.4 kg/ m3
Demulsifier Bacteriacide Calcium Carbonate Calcium Carbonate
Emulsion Prevention Bacteria Control “Small Grind” “Large Grind”
as required as required 10.0 - 40.0 kg/m³ 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 Yeild Point Gel Strengths pH Fluid Loss Bacteriacide Particle size
as required 2 - 5 Pa Initially 0/10 - 2/3Pa Initially 9 - 10 7 - 10mils/30 min as required as required
Calcium Carbonate HEC Visco XCD Caustic Soda Victosal Avacid 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 3 additional 5 kg/m . 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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Drilling Fluids & Services
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 A Newpark Company - 245 -
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 waterbased 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. 2.
3. 4.
Gauge borehole - important for directional drilling, log interpretation, minimal cement volumes and good cement bonds. 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. Excellent filter cake quality that minimizes both the possibility of differential sticking and the level of formation damage in oil-bearing sandstones. 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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Drilling Fluids & Services 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) 2) 3) 4) 5) 6) 7) 8) 9)
To drill troublesome shales. To drill deep, hot holes. To drill salt, anhydrite, gypsum and potash zones. To drill and core pay zones. To drill through hydrogen sulfide (H2S) and carbon dioxide (CO2) containing formations. To decrease torque and drag when drilling directional holes. As a packer fluid for corrosion control. As a workover fluid. 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 waterbased 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) 2) 3) 4) 5) 6) 7) 8) 9) 10) 8.3
High make-up cost. Environmental restrictions including: cuttings disposal and dumping restrictions. Extra fire prevention precautions are necessary. Reduced rates of penetration in some areas. Gas intrusion can result in barite settling. Compressability of base oil makes density estimations difficult. Hole cleaning and cuttings suspension may be less effective. Rubber materials such as hoses of BOP components may dissolve rapidly in oil-based fluids. Some types of electric logs are ineffective in oil-based fluids. Gas intrusions are more difficult to detect using oil-based fluids. 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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Drilling Fluids & Services 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/m 3. 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 o
Density at 15 C 3 - kg/m Flashpoint
839
830
o
o
o
840 o
Distillate 822 884 o
Shell SOL D80 894 o
HDF 2000 808
Lamium 11C 795 o
o
Enviro –Drill 802 o
69.9 C
129 C (CC) o 79 C
132 C (OC) o 92 C
53 C (CC) o 54 C
77 C (CC) o 58 C
73 C (CC) o 74 C
102 C (OC) o 89 C
60 C (CC) o 82 C
80 C (CC) o 65 C
Kinematic Viscosity
4.20 cSt. o 20 C
3.4 cSt. o 40 C
1.6 cSt. o 40 C
5.7 cSt. o 40 C
1.84 cSt. o 21 C
3.3 cSt. o 40 C
1.7 cSt. o 40 C
N/A cSt. o 40 C
Pour Point
-20 C
-33 C
3.8 cSt. o 40 C o -55 C
Aromatics
< 12.5%
65 C)
o
o
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. A Newpark Company - 467 -
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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. 2. 3. 4. 5.
The speed of the pipe The size of the pipe versus the size of the hole The properties of the fluid, including density and viscosity The size of the bit nozzles 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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Drilling Fluids & Services 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.
Where:
R ___60N___ (log) 12W D106
D
=
R N W D d
= ROP = Rotary RPM = Force on Bit = Bit diameter = 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-tobalance 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 A Newpark Company - 469 -
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Drilling Fluids & Services 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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Drilling Fluids & Services 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 =
SIDPP
MW(#/gal) +
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. 2. 3. 4.
The Drillers Method The Wait and Weight Method The Concurrent Method 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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Drilling Fluids & Services 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/m 3 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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Drilling Fluids & Services 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. 2.
PIT - determines the maximum allowable shut-in casing pressure. Safety factor - used by some, but omitted by others, since often a low PIT value is interpreted. Fluid influx - accounts for a decrease in hydrostatic pressure when a formation fluid has entered the wellbore. Surge gradient - accounts for pressure surges against the formation when pumps are turned on. 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.
3. 4. 5.
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 Temperature oC -12
-6
-1
4
10
15
21
27
32
37
Depth (m)
0 500 1000 1500 2000
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. 2. 3. 4. 5.
Drilling Fluid Solids Chemical Additives Diesel Oil Methanol 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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Drilling Fluids & Services 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/m 3 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. 2.
Reducing the ROP Using an inhibitive fluid
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Drilling Fluids & Services 3. 6. 7. 8.
Minimizing drilled solids concentrations Installing specialized surface equipment such as a gumbo box and flowline jets Surfactants may help when added in sufficient concentrations 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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 flow
Parallel plus radial 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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Drilling Fluids & Services
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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Drilling Fluids & Services 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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Drilling Fluids & Services 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 A Newpark Company - 481 -
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Drilling Fluids & Services 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. 2. 3.
Accuracy in measurement and recording. Communication with others who may have viable input. A logical course of action stemming from proper scientific analysis. Experience is the key input at this point.
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Drilling Fluids & Services 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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