Drilling Fluids Engineering Manual Version 2.2
Drilling Fluids Engineering Manual Version 2.2
Drilling Fluids Engineering Manual FOREWORD Developing cost-effective solutions to the most complex drilling and completion demands is the cornerstone of M-I L.L.C. That commitment is reflected in this manual, which was designed to provide the novice and experienced alike a deeper understanding of the overall drilling process and, in particular, its relationship to drilling fluid technology. The M-I SWACO* Drilling Fluids Engineering Manual reflects the very latest advancements in the chemical composition, testing, and maintenance of oil-, water- and synthetic-base drilling fluids. In addition, the reader will receive an in-depth examination of fluid properties and how they can be modified and specially engineered to control the full range of drilling concerns, including lost circulation, stuck pipe, pressure control and corrosion.
Furthermore, special applications such as air drilling, hightemperature, high-pressure, deepwater and coiled tubing are covered in detail. Today, wells are drilled routinely in deeper water, with higher downhole pressures and temperatures and with extended reaches unimaginable a few years ago. These critical applications require the very latest in technology to help the operator and contractor reach their objectives safely and cost-effectively. This manual is dedicated to that mission. For more information, please visit our Web site at http://www.miswaco.com. To forward any comments and/or recommendations, please do so through our address [ protected].
DISCLAIMER AND HOLD HARMLESS The information, data, interpretations and recommendations provided by M-I L.L.C. in this Drilling Fluids Engineering Manual are based in part upon information provided by others, are advisory only and may be rejected by the reader. You must realize that in using this manual there are many variables to consider which cannot be condensed so as to be completely covered by this manual. Thus this manual is not a primer to be followed blindly by a novice but is merely a ready reference which may be helpful in jogging the memory of those who are experienced. Accordingly, by using this manual, you agree that M-I SWACO and its personnel shall not be liable for, and that you shall defend, indemnify and hold M-I SWACO and its personnel harmless from and against, any and all claims, causes of action and liabilities for: &#; property injury that results from pollution due to a blowout, seepage or uncontrolled well flow, including cleanup and control of the pollutant, &#; property injury that results from reservoir or underground damage, including loss of hydrocarbons therefrom or the wellbore itself, &#; personal injury, death or property injury that results from the performance of services to control a wild well to protect the safety of the general public or to prevent depletion of vital natural resources, &#; the cost of control of a wild well, underground or above the surface, and &#; personal injury, death and other property loss or damage, regardless of any combination of the sole or concurrent, active or passive negligence or fault (strict liability) or a contractually assumed obligation of, or other breach of duty or warranty by, the indemnitees. The foregoing shall inure to the benefit of M-I SWACO and its parents, and its and their divisions, subsidiaries and affiliates.
©, , , , M-I L.L.C. All rights reserved. *Mark of M-I L.L.C. ^All other marks are the property of their respective owners. GMC...R2 (E) Litho in U.S.A.
Table of Contents
Chapter 1: Introduction Chapter 2: Functions Chapter 3: Testing Water-Mud Testing Section 1. Density of Fluid (Mud Weight) ................................................................................. 3.3 Section 2. Viscosity....................................................................................................................... 3.4 Section 3. Filtration ..................................................................................................................... 3.7 Section 4. Sand Content ........................................................................................................... 3.11 Section 5. Liquid and Solid Content ........................................................................................ 3.12 Section 6. Hydrogen Ion Concentration (pH) ......................................................................... 3.15 Section 7. Chemical Analysis of Water-Base Drilling Fluids ................................................... 3.17 Section 8. Chemical Analysis Relating to Corrosion ............................................................... 3.32 Section 9. Resistivity ................................................................................................................. 3.39 Section 10. Glycol Testing Procedure ....................................................................................... 3.40 Section 11. KLA-GARD* Concentration ...................................................................................... 3.41 Section 12. Permeability Plugging Test Procedure ................................................................... 3.43 Section 13. Brookfield Viscometer ............................................................................................ 3.45 Section 14. Drill Pipe Corrosion Ring Coupons ...................................................................... 3.48 Oil-Mud Testing (Including Diesel Oil, Mineral Oil and Synthetic Fluids) Section 1. Aniline Point Determination .................................................................................. 3.52 Section 2. Density (Mud Weight) ............................................................................................. 3.52 Section 3. Viscosity and Gel Strength ...................................................................................... 3.53 Section 4. Filtration ................................................................................................................... 3.55 Section 5. Activity ..................................................................................................................... 3.57 Section 6. Electrical Stability ..................................................................................................... 3.57 Section 7. Liquid and Solids ..................................................................................................... 3.58 Section 8. Chemical Analysis of Oil-Base Drilling Muds ........................................................ 3.59 Pilot Testing .............................................................................................................................. 3.64
Chapter 4: Water-Base Chemistry Chapter 4A: Basic Chemistry Atomic Structure ....................................................................................................................... 4A.3 Valence ...................................................................................................................................... 4A.6 Electron Shell ............................................................................................................................ 4A.7 Ionic Bonding ........................................................................................................................... 4A.7 Covalent Bonding ..................................................................................................................... 4A.9 Compounds ............................................................................................................................. 4A.11 Formulas .................................................................................................................................. 4A.12 Stoichiometry - Stoichiometric Reactions ............................................................................. 4A.13 Equivalent Weight .................................................................................................................. 4A.13 Balancing an Equation ........................................................................................................... 4A.14 Solubility ................................................................................................................................. 4A.15 pH and Alkalinity ................................................................................................................... 4A.18 Acids, Bases and Salts .............................................................................................................. 4A.20 Table of Contents
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Osmosis ................................................................................................................................... 4A.22 Titrations ................................................................................................................................. 4A.23 Concentrations of Solutions .................................................................................................. 4A.24 Mixtures, Solutions, Emulsions and Dispersions .................................................................. 4A.26 Common Chemical Reactions in Mud Chemistry ............................................................... 4A.26 Chapter 4B: Clay Chemistry Types of Clays ........................................................................................................................... 4B.2 Cation Exchange Capacity (CEC) ............................................................................................ 4B.7 Composition of Clay-Water Muds ........................................................................................... 4B.8 Principles of Chemical Treatment .......................................................................................... 4B.18 Chapter 4C: Contamination and Treatment Anhydrite or Gypsum Contamination .................................................................................... 4C.2 Cement Contamination ........................................................................................................... 4C.4 Carbonate Contamination ....................................................................................................... 4C.7 Salt Contamination ................................................................................................................ 4C.14 Saltwater Flows ....................................................................................................................... 4C.16 Hydrogen Sulfide (H2S) Contamination ............................................................................... 4C.17 Quick Reference for Recognizing and Treating Contaminants ............................................ 4C.18
Chapter 5: Rheology and Hydraulics Rheology ....................................................................................................................................... 5.1 Rheological Models .................................................................................................................... 5.13 Stages of Flow ............................................................................................................................. 5.19 Hydraulics Calculations ............................................................................................................ 5.20 Pressure-Loss Calculations ........................................................................................................ 5.23 Hydraulics Example Problem..................................................................................................... 5.31
Chapter 6: Polymer Chemistry and Applications Chapter 7: Filtration Control Fundamentals of Filtration ........................................................................................................... 7.2 Fluid-Loss-Control Additives ..................................................................................................... 7.12
Chapter 8: Solids Control Fundamentals .............................................................................................................................. 8.1 Classification of Particle Sizes ..................................................................................................... 8.3 Methods of Solids Separation ..................................................................................................... 8.5 Rig-Ups ....................................................................................................................................... 8.20 Guidelines for Proper Operation of Shale Shakers .................................................................. 8.23 Maintenance and Trouble Shooting of Desanders and Desilters ............................................ 8.24 Guidelines for Proper Operation of Decanting Centrifuges ................................................... 8.25
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Chapter 9: Engineering Calculations U.S. Oilfield and Metric Units...................................................................................................... 9.1 General Wellbore Calculations ................................................................................................... 9.3 Calculating Pit and Tank Capacity and Volume ........................................................................ 9.4 Capacity, Volume and Displacement .......................................................................................... 9.7 Calculating Pump Output ......................................................................................................... 9.12 Annular Velocity ........................................................................................................................ 9.15 Circulation Times ...................................................................................................................... 9.16 Hydrostatic Pressure .................................................................................................................. 9.17 Example Problems ..................................................................................................................... 9.18 Material Balance ........................................................................................................................ 9.23 Solids Analysis ............................................................................................................................ 9.31 Solids Calculation in Complex Brines ...................................................................................... 9.35 The Mud Report ......................................................................................................................... 9.37 Salt Tables ................................................................................................................................... 9.40
Chapter 10: Water-Base Systems Unweighted Clay-Water Systems ............................................................................................. 10.2 SPERSENE* System ........................................................................................................................ 10.4 Calcium-Treated Drilling Fluids ................................................................................................ 10.6 SPERSENE/XP-20* Seawater System ........................................................................................... 10.11 Saturated Saltwater System ..................................................................................................... 10.12 Inhibitive Potassium Systems ................................................................................................. 10.14 DURATHERM* System ................................................................................................................. 10.17 ENVIROTHERM* System ............................................................................................................... 10.18 POLY-PLUS* System .................................................................................................................... 10.20 DRILPLEX* System ...................................................................................................................... 10.23 GLYDRIL* System ....................................................................................................................... 10.24 SILDRIL* System ......................................................................................................................... 10.26
Chapter 11: Non-Aqueous Emulsions Emulsion Fundamentals ........................................................................................................... 11.3 Additives .................................................................................................................................... 11.6 Systems ...................................................................................................................................... 11.9 Properties ................................................................................................................................... 11.9 Controlled Activity ................................................................................................................. 11.15 Oil or Synthetic Ratio (O/W or S/W) ..................................................................................... 11.16 Gas Solubility .......................................................................................................................... 11.17 Gas Stripping of Barite ............................................................................................................ 11.18 Water-Wet Solids ..................................................................................................................... 11.18 Hydrogen Sulfide ..................................................................................................................... 11.21 Lost Circulation ....................................................................................................................... 11.22 Solids Control .......................................................................................................................... 11.23 Cementing in Non-Aqueous Muds ........................................................................................ 11.25
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Packer Muds ............................................................................................................................ 11.26 Casing-Pack Fluids ................................................................................................................... 11.27 Workover Fluids ...................................................................................................................... 11.28 Troubleshooting Oil Muds ...................................................................................................... 11.29 Calculations ............................................................................................................................. 11.32 Brine Salinity ........................................................................................................................... 11.39
Chapter 12: Oil-Base Systems Systems ...................................................................................................................................... 12.2 Products ................................................................................................................................... 12.10 Properties ................................................................................................................................. 12.14 Displacements ......................................................................................................................... 12.17 Lost Circulation ....................................................................................................................... 12.19 Packer Muds ............................................................................................................................ 12.19
Chapter 13: Synthetic Systems General Systems Descriptions ................................................................................................... 13.2 Systems and Formulations ........................................................................................................ 13.3 Mixing Procedure .................................................................................................................... 13.10 Maintenance ............................................................................................................................ 13.10 Testing ...................................................................................................................................... 13.11 Calculations ............................................................................................................................. 13.11 Chemistry of Synthetics .......................................................................................................... 13.12 Environmental Health and Safety Issues ............................................................................... 13.15 Special Applications for Synthetic-Base Muds ....................................................................... 13.17 Synthetic-Base Mud Problems and Applications ................................................................... 13.19 Test Procedure for Determining Oil (or Synthetic) and Water Content from Cuttings for Percentages Greater Than 10% ................................................................. 13.20
Chapter 14: Lost Circulation Causes of Lost Circulation ........................................................................................................ 14.2 Preventive Measures .................................................................................................................. 14.4 When Lost Circulation Occurs ................................................................................................. 14.7 Corrective Measures ................................................................................................................ 14.11 Techniques for Treating Lost Circulation in Oil-Base Muds ................................................. 14.23
Chapter 15: Stuck Pipe Mechanical Sticking .................................................................................................................. 15.2 Differentially Stuck Pipe ........................................................................................................... 15.8 Common Stuck Pipe Scenarios ............................................................................................... 15.10 Methods and Procedures for Freeing Stuck Pipe ................................................................... 15.11 Pipe-Stretch Estimate of Stuck Zone........................................................................................ 15.23 Worksheet: Freeing Stuck Pipe ................................................................................................ 15.24 Stuck Pipe &#; Hole Packoff ...................................................................................................... 15.26 Stuck Pipe &#; Well Geometry/Differential ............................................................................. 15.27
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Chapter 16: Shale and Wellbore Stability Shale Deposition and Sedimentary Rocks ................................................................................ 16.2 Clay Chemistry .......................................................................................................................... 16.8 The Earth&#;s Stresses .................................................................................................................. 16.10 Mechanical Stress Failure ........................................................................................................ 16.14 Chemical Interactions ............................................................................................................. 16.19 Physical Interactions ............................................................................................................... 16.23 Wellsite Analysis ...................................................................................................................... 16.24
Chapter 17: Pressure Prediction Subsurface Pressures ................................................................................................................... 17.1 Normal Pressure ......................................................................................................................... 17.3 Abnormal Pressure ..................................................................................................................... 17.3 Detection and Evaluation of Abnormal Pressures .................................................................... 17.9 Pore-Pressure Plotting .............................................................................................................. 17.13 Advances in Pressure Prediction from Seismic Data .............................................................. 17.16
Chapter 18: Pressure Control Three Levels of Pressure Control .............................................................................................. 18.1 Subsurface Pressures .................................................................................................................. 18.3 Indications of Increasing Formation Pressures ........................................................................ 18.5 Pressure/Transition Zone Analysis After Drilling ................................................................... 18.15 Pressure Loss ............................................................................................................................ 18.19 U-Tube Analysis ....................................................................................................................... 18.25 Pressure Control ...................................................................................................................... 18.28 Special Problems ...................................................................................................................... 18.45
Chapter 19: Corrosion Fundamentals ............................................................................................................................ 19.1 Galvanic Series, Commercial Metals and Alloys in Seawater .................................................. 19.6 Metallurgy .................................................................................................................................. 19.7 Corrosion Factors ....................................................................................................................... 19.7 Corrosion Control ................................................................................................................... 19.16 Corrosion-Control Products .................................................................................................... 19.16 Corrosion Measurements ........................................................................................................ 19.21 Packer Fluids ............................................................................................................................ 19.24 Hazards and Characteristics of H2S ........................................................................................ 19.25
Chapter 20: Special Problems Chapter 20A: Barite Sag ....................................................................................................... 20A.1 Chapter 20B: Hole Cleaning ................................................................................................ 20B.1 Chapter 20C: Displacements and Cementing ................................................................... 20C.1
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Chapter 21: Special Fluids Chapter 21A: Reservoir Drill-In Fluids ............................................................................... 21A.1 Chapter 21B: Completion and Workover Fluids ............................................................... 21B.1 Chapter 21C: Coring Fluids ................................................................................................. 21C.1 Chapter 21D: Air Drilling .................................................................................................... 21D.1
Chapter 22: Special Operations Chapter 22A: Deepwater ...................................................................................................... 22A.1 Chapter 22B: Drilling Salt .................................................................................................... 22B.1 Chapter 22C: HTHP .............................................................................................................. 22C.1 Chapter 22D: Milling ........................................................................................................... 22D.1 Chapter 22E: Coiled-Tubing Drilling .................................................................................. 22E.1
Chapter 23: Health, Safety and Environmental Minimizing Pollution ................................................................................................................ 23.1 Measuring Pollution .................................................................................................................. 23.3 Managing Pollution .................................................................................................................. 23.7 Waste Management Options for Drilling Fluids and Cuttings ............................................... 23.8 Environmental, Health and Safety Regulations ..................................................................... 23.11
Appendix Appendix A: Product Cross-References ...................................................................................... A.1 Appendix B: Glossary .................................................................................................................. B.1 Appendix C: Index ..................................................................................................................... C.1
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CHAPTER
1
Introduction
The Origins, Migration and Trapping of Petroleum and Exploring For It THE
&#;the word &#;petroleum&#; is derived from the Latin words for &#;rock&#; (petra) and &#;oil&#; (oleum)&#;
ORIGIN OF PETROLEUM
During certain geologic ages, when the climate was suitable, petroleum began as organic material derived from plants and animals which grew in abundance. As these organisms went through their cycles of growing and dying, buried organic material slowly decayed and became our present-day fossil fuels: oil, gas, coal and bitumen. Oil, gas and bitumen were dispersed in the sediments (usually clay-rich shales). Over millions of years, these organic-laden shales expelled their oil and gas under tremendous pressures from the overburden. The oil and gas migrated into permeable strata below or above them, then migrated further into traps that we now call reservoirs. It&#;s interesting to note that the word &#;petroleum&#; is derived from the Latin words for &#;rock&#; (petra) and &#;oil&#; (oleum), indicating that its origins lie within the rocks that make up the earth&#;s crust. These ancient petroleum hydrocarbons are complex mixtures and exist in a range of physical forms &#; gas mixtures, oils ranging from thin to viscous, semi-solids and solids. Gases may be found alone or mixed with the oils. Liquids (oils) range in color from clear to black. The semi-solid hydrocarbons are sticky and black (tars). The solid forms are usually mined as coal, tar sand or natural asphalt such as gilsonite. As the name &#;hydrocarbon&#; implies, petroleum is comprised of carbon atoms and hydrogen atoms bonded together; the carbon has four bonds and the hydrogen has one. The simplest hydrocarbon is methane gas (CH4). The more complex hydrocarbons have intricate structures, consisting of multiple carbon-hydrogen rings with carbon-hydrogen side chains. There are often traces of sulfur, nitrogen and Introduction
1.1
other elements in the structure of the heavier hydrocarbons.
THE
MIGRATION AND TRAPPING OF PETROLEUM
Sedimentary rocks. Oil is seldom found in commercial amounts in the source rock where it was formed. Rather, it will be found nearby, in reservoir rock. These are normally &#;sedimentary&#; rocks &#; layered rock bodies formed in ancient, shallow seas by silt and sand from rivers. Sandstone is the most common of the sedimentary rock types. Between the sand grains that make up a sandstone rock body there is space originally filled with seawater. When pores are interconnected, the rock is permeable and fluids can flow by gravity or pressure through the rock body. The seawater that once filled the pore space is partially displaced by oil and gas that was squeezed from the source rock into the sandstone. Some water remains in the pore space, coating the sand grains. This is called the reservoir&#;s connate water. Oil and gas can migrate through the pores as long as enough gravity or pressure forces exist to move it or until the flow path is blocked. A blockage is referred to as a trap. Carbonate rock, limestones (calcium carbonate) and dolomites (calciummagnesium carbonate) are sedimentary rocks and are some of the most common petroleum reservoirs. Carbonate reservoirs were formed from ancient coral reefs and algae mounds that grew in ancient, shallow seas. Organic-rich source rocks were also in proximity to supply oil and gas to these reservoir rocks. Most limestone strata do not have a matrix that makes them permeable enough for oil and gas to migrate through them. However, many limestone reservoirs contain Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
1
&#;oil and gas accumulate&#; in traps&#;
Structural Traps
Introduction
fracture systems and/or interconnecting vugs (cavities formed when acidic water dissolved some of the carbonate). These fractures and vugs, created after deposition, provide the porosity and permeability essential for oil to migrate and be trapped. Another carbonate rock, dolomite, exhibits matrix permeability that allows fluid migration and entrapment. Dolomites also can have fracture and vugular porosity, making dolomite structures attractive candidates for oil deposits. Salt domes. A significant portion of oil and gas production is associated with salt domes which are predominately classified as piercement-type salt intrusions and often mushroom shaped. Piercement-type domes were formed by the plastic movement of salt rising upward through more dense sediments by buoyant forces resulting from the difference in density. The surrounding strata (sand, shale and carbonate) is deformed by this upward Formation containing saltwater
Formation containing gas
Formation containing oil
________________________ ________________________ ________________________ ________________________ ________________________
Sand
________________________
Clay or shale
Limestone
Oil
Gas
Saltwater
Figure 1a: Anticlinal trap.
________________________ ________________________ ________________________
Formation containing saltwater
Formation containing oil
Formation containing saltwater
________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Sand
Clay or shale
Limestone
Oil
Gas
Saltwater
Figure 1b: Fault trap. Introduction
1.2
intrusion of salt forming stratigraphic and structural traps (see Figure 2c). These traps are formed around the flanks and under the overhang of salt domes in the sandstone layers that were faulted and folded by the movement of the salt. Being impermeable to oil and gas, salt forms an excellent barrier for the accumulation of hydrocarbons. Salt layers. Major oil and gas reservoirs have been found in recent years beneath horizontal salt beds. Until recently, it was a mystery what was beneath these extruded salt layers called salt sills, salt sheets and salt lenses. They could not be explored economically by drilling, and seismic interpretation through plastic salt was unreliable. Now, &#;sub-salt&#; formations can be evaluated through modern three-dimensional seismic analysis to identify potential reservoirs. Once likely formations are located, wells are drilled through the salt layer to determine if oil and gas deposits exist. Traps. Oil, gas and water slowly migrate through permeable rocks, driven by natural forces of gravity (buoyancy) and pressure gradients. When they meet an impermeable barrier, they can go no farther, so oil and gas accumulate. This barrier is generally referred to as a trap. Varying densities make the gas phase rise, while the water settles to the lowest point, and the oil remains in the middle. Traps are categorized as structural or stratigraphic. Structural traps result from a local deformation such as folding and/or faulting of the rock layers. Examples of structural barriers are anticline traps, fault traps and traps associated with salt domes (see Figures 1a, 1b and 2c). Stratigraphic traps are formed by geological processes other than structural deformation and relate to variations in rock properties (lithology). The remains of an ancient limestone or dolomite coral reef buried by impervious sediments is an example. An ancient, Revision No: A-0 / Revision Date: 03·31·98
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Introduction
Stratigraphic Traps
Formation containing saltwater
Formation containing oil
Surface
Salt
________________________ ________________________ ________________________ ________________________
Sand
________________________
Clay or shale
Limestone
Oil
Gas
Saltwater
Surface
Figure 2a: Stratigraphic trap. Organic reef embedded in shale and wedging out sand.
________________________ ________________________ ________________________
Formation Formation Formation Formation containing containing containing containing saltwater oil saltwater oil
Formation containing saltwater
Salt
________________________ ________________________ ________________________ ________________________
Formation Formation containing containing saltwater oil
________________________ ________________________ ________________________
Sand
Clay or shale
Limestone
Oil
Gas
Surface
Formation Formation containing containing saltwater oil
Saltwater
Figure 2b: Unconformity trap.
&#;determining the likelihood of oil and gas in the trapped region&#;
sand-filled river bed that has been silted out by clay is another type of stratigraphic trap. Sedimentary layers may change laterally in lithology or may die out and reappear elsewhere as a different rock type. Such changes can cause a lateral decrease in porosity and permeability, creating a trap (see Figure 2a). Another type of stratigraphic trap is an unconformity. Unconformities occur where a succession of rock strata, including the future oil reservoir, have been uplifted, tilted, eroded and are subsequently overlain by sediments which form an impermeable barrier. An unconformity represents a break in the geologic time scale (see Figure 2b).
EXPLORING
FOR PETROLEUM
Locating petroleum: Knowing that petroleum traps exist is one thing, but pinpointing traps far below the Introduction
1.3
Salt
Figure 2c: Typical salt structure development (from Geology of Petroleum, A. I. Levorson).
earth&#;s surface is quite another. Then determining the likelihood of oil and gas in the trapped region is yet another concern. Many methods have been used to locate petroleum traps, but the most important methods are aerial surveying, geological exploration, geophysical (seismic) exploration and exploratory drilling. Aerial and satellite. Surveys from high altitudes give a broad picture of a geographic area of interest. Major surface structures such as anticlines and faulted regions can be clearly observed by these methods. This information Revision No: A-0 / Revision Date: 03·31·98
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1
&#;seismic exploration in which shock waves&#;
Introduction
helps locate areas where more detailed study is warranted. In the early years of petroleum exploration, visualization from an aircraft or mapping river and creek drainage patterns were successful surveying techniques. Modern aerial and satellite surveying is more sophisticated allowing a number of features to be evaluated, including thermal anomalies, density variations, mineral composition, oil seepage and many others. Surface geological exploration. Observations by trained geologists of rock outcrops (where subsurface layers reach the surface), road cuts and canyon walls can identify lithology and assess the potential for hydrocarbon source rocks, reservoir-quality rocks and trapping mechanisms in an area under study. Much has been learned about ancient deposits from studying modern river deltas, for example. Detailed geologic maps, made from these observations, show the position and shape of the geologic features and provide descriptions of the physical characteristics and fossil content of the strata.
Geophysical exploration. Through the use of sensitive equipment and analytical techniques, geophysicists learn a great deal about the subsurface. Chief among these techniques is seismic exploration in which shock waves, generated at the surface and aimed downwards, are reflected back to the surface as echoes off the strata below. Because rocks of varying density and hardness reflect the shock waves at different rates of speed, the seismologist can determine depth, thickness and type of rock by precisely recording the variances in the time it takes the waves to arrive back at the surface. Modern 3-D seismic has improved the success rate of the exploration process, especially in areas beneath salt, as discussed above. Continual improvements in seismic measurement and the mathematical methods (algorithms) used to interpret the signals can now give a clearer &#;picture&#; of subsurface formations. Other geophysical methods use variations in the earth&#;s gravity and magnetic properties to detect gross features of subsurface formations.
________________________ ________________________
Drilling for Petroleum
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
DRILLING
METHODS
When it has been established that a petroleum reservoir probably exists, the only way to verify this is to drill. Drilling for natural resources is not a new idea. As early as A.D., brine wells as deep as 3,500 ft (1,067 m) were drilled in China, using methods similar to cable tool drilling. Cable tool drilling. This was the method used by pioneer wildcatters in the nineteenth and early twentieth centuries and is still used today for some shallow wells. The method employs a heavy steel drill stem with a bit at the
Introduction
1.4
bottom, suspended from a cable. The tool is lifted and dropped repeatedly. The falling steel mass above the bit provides energy to break up the rock, pounding a hole through it. The hole is kept empty, except for some water at the bottom. After drilling a few feet, the drill stem (with its bit) is pulled out and the cuttings are removed with a bailer (an open tube with a valve at the bottom). The cable tool method is simple, but it is effective only for shallow wells. Progress is slow because of the inefficiency of the bit and the need to pull the tools frequently to bail out cuttings.
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CHAPTER
1
Introduction
Rig Components 16
36
17
22 35
18
3 19
5
5
5
12
33
4
11
28 10 13 14
20
1 1 1
8
9
7
27
6
32
15 2
31
23
26 29
21
24 30
2
34
29
25
Figure 3: Diagrammatic view of rotary drilling rig (after Petex). Circulating System 11. Mud pits 12. Mud pumps 13. Standpipe 14. Rotary hose 15. Bulk mud storage 16. Mud return line 17. Shale shaker 18. Desilter 19. Desander 10. Degasser 11. Reserve pits
Introduction
Rotating Equipment 12. Swivel 13. Kelly 14. Kelly bushing 15. Rotary table Hoisting System 16. Crown block 17. Monkeyboard 18. Traveling block 19. Hook 20. Drawworks
21. Substructure 22. Drilling line Well-Control Equipment 23. Annular blowout preventer 24. Ram blowout preventers 25. Accumulator unit 26. Choke manifold 27. Mud-gas separator Power System 28. Generators
1.5
Pipe and Pipe-Handling Equipment 29. Pipe racks 30. Catwalk 31. V-door 32. Rathole Miscellaneous 33. Doghouse 34. Cellar 35. Hoisting line 36. Gin pole
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1
&#;keep the bit cool and lubricated, and to remove the rock cuttings&#;
Introduction
Rotary drilling. Rotary rigs are used for a variety of purposes &#; drilling oil, gas, water, geothermal and petroleumstorage wells; mineral assay coring; and mining and construction projects. The most significant application, however, is oil and gas drilling. In the rotary method (introduced to oil and gas drilling in about ), the drill bit is suspended on the end of a tubular drillstring (drill stem) which is supported on a cable/ pulley system held up by a derrick (see Figure 3). Drilling takes place when the drillstring and bit are rotated while the weight of the drill collars and bit bears down on the rock. To keep the bit cool and lubricated, and to remove the rock cuttings from the hole, drilling fluid (mud) is pumped down the inside of the drillstring. When it reaches the bit, it passes through nozzles in the bit, impacts the bottom of the hole and then moves upward in the annulus (the space between the drillstring and the wellbore wall) with the cuttings suspended in it. At the surface, the mud is filtered through screens and other devices that remove the cuttings, and is then pumped back into the hole. Drilling mud circulation brought efficiency to rotary drilling that was missing from cable tool drilling &#; the ability to remove cuttings from the hole without making a trip to the surface. Equipment for rotary drilling is illustrated in Figure 3.
DRILL
BITS
A good place to begin the description of rotary drilling equipment is where the action takes place &#; at the drill bit. As it rotates under the weight of the drillstring, the bit breaks up or scrapes away the rock beneath it. Early rotary bits were &#;drag bits&#; because they scraped at the rock. Because they resembled the tail of a fish, they earned the name &#;fishtail bits.&#; They were effective in drilling soft formations, but their blades
Introduction
1.6
wore out quickly in hard rock. An improved rotary bit was needed and in the early s, the roller cone bit was introduced. Roller cone (rock) bits. A roller cone bit &#; also known as a rock bit &#; has either two or three cone-shaped cutters that roll along as the bit is turned. The surface of the rolling cone has teeth that contact most of the hole bottom as the cones roll over the surface (see Figure 4a). These bits drill by fracturing hard rock and by gouging softer rock. There is also some scraping action because the cones&#; axes are off-center compared to the center of rotation. Weight on the bit, rotational speed, rock hardness, differential pressure, and drilling fluid velocity and viscosity affect how fast bits drill. Nozzles in the bit&#;s body give the mud extra velocity, creating a jetting action as it exits through the bit. This contributes to faster drilling. Rock bits are classified according to the types of bearings and teeth they have. Bearing types include (1) nonsealed roller bearings, (2) sealed roller bearings and (3) journal bearings. When referring to bits by the type of teeth they have, the terms: (1) milled tooth and (2) Tungsten Carbide Insert (TCI) are used. Bearing design is important to a bit&#;s service life; sealed bearings and journal bearings provide longer life than unsealed bearings, but they are more expensive. A rock bit&#;s teeth &#; their shape, size, number and placement &#; are important to drilling efficiency in different formations. Milled tooth bits have teeth that are machined from the same metal billet as the cone (see Figure 4c). In some cases the teeth have hardfacing applied for extra life. This type is designed for soft to medium formations where long teeth can gouge out the rock. The teeth on insert bits are actually tungsten carbide studs
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CHAPTER
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Introduction
inserted into holes drilled into the cones (see Figure 4a). TCI bits drill by generating a crushing action, for harder and more abrasive formations. Some insert bits are enhanced with special inserts that feature a layer of polycrystalline diamond applied over the tungsten carbide. This gives them an even longer service life than tungsten carbide alone.
Diamond and PDC bits. Fixed-cutter bits with diamond cutting surfaces are used for drilling medium to hard formations, when extra-long bit life is needed or for special coring operations. Single-piece, fixed-cutter bits use either natural diamond chips or man-made diamond wafers as cutters. Natural diamond bits use industrial-grade, natural
Types of Bits
Figure 4a: Rock bit (TCI type).
________________________ ________________________ ________________________
Figure 4b: PDC bit.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Figure 4c: Milled tooth rock bit.
Figure 4d: Natural diamond core bit.
________________________
Introduction
1.7
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CHAPTER
1
PDC bits are very durable and efficient&#;
Introduction
diamonds set in a steel matrix on the cutting area, as shown on the natural diamond core bit in Figure 4d. During rotation, the exposed natural diamonds drag and grind out the hole. Man-made diamond cutters, called Polycrystalline Diamond Cutters (PDC), are configured so that the cutters shear the rock beneath the bit producing large cuttings and high penetration rates (see Figure 4b). PDC bits are in demand for drilling in many types of rock, but especially for long sections of medium-hard formations. PDC bits are very durable and efficient offering higher penetration rates and long bit life. A variety of PDC bit designs are manufactured to optimize drilling particular formations. Typically PDC bits drill faster in shales than in sandstones and are used most often to drill long shale sections. Both types of diamond bits work in a manner similar to older style fishtail drag bits because they scrape the rock.
Introduction
1.8
THE
DRILLSTRING
Starting at the bottom, a basic drillstring for rotary drilling consists of the (1) bit, (2) drill collars and Bottom-Hole Assemblies (BHAs), and (3) drill pipe (see Figure 5). The BHA is located just above the bit and consists of drill collars combined with one or more bladed stabilizers (to keep the BHA and bit concentric), possibly a reamer (to keep the hole from becoming tapered as the bit diameter wears down) and other tools. MWD tools and mud motors are generally located low in the BHA, usually just above the bit. Sometimes, a set of &#;jars&#; is located near the top of the BHA. Jars can free stuck pipe by giving a hammering action when they are set-off by pulling hard. Drill collars are thick-walled, heavy joints of pipe used in the BHA to provide weight to the bit. Usually, one of the collars is made of non-magnetic metal so that a magnetic compass tool (survey tool) can be used to determine the inclination of the lower BHA and bit without interference from magnetic metals. Each joint of drill pipe is approximately 30 ft (9.1 m) long, and has a box (female connection) welded onto one end and a pin (male connection) welded to the other. These threaded couplings (tool joints) must be strong, reliable, rugged and safe to use. They must be easy to make up (connect) and break out (disconnect). Outer diameters for drill pipe range from 23&#;8 to 65&#;8 in. The hollow drillstring provides a means for continuous circulation and for pumping drilling mud under high pressure through the bit nozzles as a jet of fluid. The blast of mud knocks rock cuttings from under the bit, gives a new rock surface for the cutters to attack and starts the drill cuttings on their trip to the surface. This transmission of hydraulic horsepower from Revision No: A-2 / Revision Date: 12·31·06
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Introduction
Mud flow in Mud flow out
Kelly
Casing
Mud
Cement
Tool joint
Drill pipe
Regardless of bit type, it must be rotated&#;
Annulus
Crossover sub
Drill collar
Bottom-hole assembly
Open hole
Stabilizer
Mud motor MWD/LWD
Stabilizer Drill bit
Figure 5: Drillstring components.
the mud pumps to the bit is a very important function of the mud. Coiled-tubing drilling. This method employs a continuous string of coiled tubing and a specialized, coiled-tubing drilling rig. Rather than drilling with separate joints of the traditional, largediameter, rigid drill pipe, the drillstring is smaller-diameter, flexible tubing. Unlike drill pipe which is screwed together to form the drillstring, and which must be disconnected into stands that are racked in the derrick during trips, the tubing comes rolled on a reel that unwinds as drilling progresses and is subsequently rewound onto its spool during trips. The coiled-tubing method greatly facilitates lowering and retrieving the drilling assembly. Introduction
1.9
Traditionally, coiled-tubing rigs have been used for workover and completion operations where mobility and compact size were important. With the development of downhole mud motors which do not require the use of a rotating drillstring to turn the bit, coiledtubing units are now functioning as true drilling rigs.
DRILL
BIT ROTATION
Regardless of bit type, it must be rotated in order to drill the rock. There are three methods used to turn the bit downhole: 1. The drillstring and bit are turned by a rotary table and kelly. 2. The drillstring and bit are rotated by a &#;top-drive&#; motor. 3. Only the bit is rotated by a hydraulic mud motor in the drillstring. (The drillstring can be held still or rotated while using a mud motor, as desired.) Rotary table and kelly. A rotary table is a gear- and chain-driven turntable mounted into the rig floor that has a large open center for the bit and drillstring. The rotary table kelly bushing is a large, metal &#;donut&#; with a 4-, 6- or 8sided hole at its center. This bushing can accept a special piece of 4-, 6- or 8-sided pipe, called the kelly. The kelly, which is about 40 ft (12.2 m) long, is turned by the kelly bushing in the rotary table, just as a hex nut is turned by a wrench. The kelly is free to slide up and down in the kelly bushing so it can be raised while a 30-ft (9.1-m) joint of drill pipe (the topmost joint in the drillstring) is attached to its bottom. The drill pipe is then lowered into the hole until the bit touches bottom, and the kelly can be rotated. The driller starts the rotary table, and as the bit drills down, the kelly moves down, too. When the top end of the kelly is level with the bushing (at rig floor level), the kelly is broken out from the drill pipe, raised while another joint is added, and the process of drilling down is repeated. In order for Revision No: A-2 / Revision Date: 12·31·06
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Higher bit RPM results in improved ROP&#;
Introduction
the drilling mud to get into the drillstring, a rotary hose and mud swivel are attached to the top of the kelly to supply mud from the mud pumps. The swivel is a hollow device that receives mud from the stand pipe and rotary hose and passes it through a rotating seal to the kelly and into the drillstring. One disadvantage of the kelly/rotary arrangement is that while pulling pipe with the kelly disconnected, no mud can be pumped and pipe rotation is minimal. Top drive. A top-drive unit has important advantages over a kelly/ rotary drive. A top-drive unit rotates the drillstring with a large hydraulic motor mounted high in the derrick on a traveling mechanism. Rather than drilling one 30-ft (9.1-m) joint before making a connection, top drives use 3-joint (90-ft [27.4-m]) &#;stands&#; of drill pipe and greatly reduce the number of connections and the time to make a trip. One key advantage &#; the driller can simultaneously rotate the pipe while going up or down over a 90-ft (27.4-m) distance in the hole and circulate mud. This allows long, tight spots to be quickly and easily reamed without sticking the pipe. Due to these advantages, top drive units are being installed on most deep rigs and offshore rigs. Mud motor. While the first two rotation methods involve turning the drill pipe in order to turn the bit, this method is different. In this case, there is a hydraulic motor (turbine or positive-displacement mud motor) mounted in the BHA near the bit. During drilling, hydraulic energy from the mud passing through the motor turns the bit. This is achieved through the use of multiple rotor/stator elements inside the motor which rotate a shaft to which the bit is attached. This offers several advantages. Mud motors can achieve much higher bit
Introduction
1.10
rotational speeds than can be achieved by rotating the entire drillstring. Less energy is required to turn just the bit. The hole and casing stay in better condition, as does the drillstring, when only the bit (and not the pipe) rotates. Higher bit RPM results in improved Rate of Penetration (ROP), and vibration is less of a problem. Mud motors are used extensively for directional drilling where it is essential to keep an orienting tool positioned in the desired direction.
MWD
AND
LWD
In &#;the old days,&#; when a driller wanted to check the angle of a directional well, or when he wanted to log the well to obtain certain downhole or formationrelated information, he was faced with only one course of action. He had to stop drilling and run special measurement or logging instruments down into the wellbore; sometimes this involved pulling the entire drillstring before measurement could proceed.
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Introduction
Today, there are sophisticated electronic instruments that can perform Measurement While Drilling (MWD) and Logging While Drilling (LWD) functions while the drilling process continues uninterrupted. The measurements they perform are varied, and while they are important to the driller, there is another factor that is more important to mud engineers. That is the fact that both MWD and LWD instruments transmit their findings back to the surface by generating pulse waves in the drilling mud column inside the drillstring. For that reason, mud conditions (density, viscosity, gas entrainment, etc.) will be especially important on rigs that are running MWD and LWD instruments.
DERRICK&#;S
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
HOISTING SYSTEM
Drilling rigs must have tremendous power to lift and suspend the weight of long drillstrings and casing strings. This hoisting system must have the capacity to overcome any resistance caused by tight spots in the hole and pull-on or &#;jar&#; stuck pipe. While the weight of the equipment is suspended from the top of the derrick, the lifting power comes from an engine or motor operating the drawworks. The drawworks controls a reel of wire cable which runs through a system of pulleys to reduce the mechanical requirements. Here&#;s an overview. A stationary block (crown block) is mounted at the top of the derrick, and a movable block (traveling block) is suspended by cable, also known as wire rope. One end of this wire rope, the drum line, is wound around the drum of the drawworks, and then it is passed between the sheaves of the crown block and sheaves of the traveling block several times. The dead end of the wire rope, dead line, is secured to the base of the
derrick. This multi-sheave block and tackle system offers high mechanical advantage to the hoisting system. On the bottom of the traveling block there is a large hook. During drilling, a rotary swivel hangs from the hook on a bail. The swivel provides a rotating pressure seal so that mud can flow under pressure down the kelly and into the drillstring. The hook also suspends the drillstring, which is being turned by the kelly. Drawworks and tongs. While tripping, the swivel (with the kelly attached) is set aside. Devices called elevators hang on the hook to hoist the drillstring out of the hole. When making a trip, threejoint stands (about 90 ft [27.4 m] of drill pipe) are pulled. While a stand is being unscrewed and placed back into the derrick, the rest of the drillstring weight is supported from the rotary table by pipe slips that grip the pipe below the tool joint. Tool joints are made up tight or broken-out using pipe tongs (large pipe wrenches). A spinning chain is used to rotate the joints together rapidly. A mechanical cathead is the device that pulls the spinning chain and pulls the pipe tongs. The friction cathead, with a rope around it, allows the rig crew to perform various tasks, such as light pulling and hoisting. The friction cathead and mechanical cathead operate off the cat shaft. The drawworks has in it a large drum hoist used to wrap and pull the wire rope (drilling line), as mentioned earlier. On the drum is the main brake, which has the ability to quickly stop and hold the weight of the drillstring. When heavy loads are being lowered, the main brake is assisted by a hydraulic or electric auxiliary brake, or retarder, to absorb the great amount of energy developed by the mass of the traveling block, hook assembly and drillstring.
________________________ ________________________
Introduction
1.11
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1
&#;the driller controls the brake, catheads&#;
Introduction
Driller&#;s console. Located next to the drawworks is the driller&#;s control console. From this vantage point, the driller controls the brake, catheads, rotary table (or top drive), the rate at which the drillstring is pulled or lowered, mud pump speed, and other important functions.
MUD
CIRCULATION AND SOLIDS REMOVAL
The mud then travels down the drillstring to the bit.
A logical place to begin the discussion of a mud circulation system is at the mud pumps (see Figure 6). These pumps and the engines that power them, represent the &#;heart&#; of the mud system just as the circulating mud is the lifeblood of the drilling operation. Mud pumps are positive-displacement piston pumps, some of which produce up to 5,000 psi (344.7 bar). They are powered by diesel engines or electric motors. To produce the required pressure and flow rate for a specific set of
drilling conditions, the correct piston and liner sizes must be selected for the pumps and the right nozzle sizes must be specified for the bit. This is called hydraulics optimization, and it&#;s a key factor in efficient drilling. After exiting the mud pump at high pressure, the drilling fluid travels up the standpipe, a long, vertical pipe attached to the derrick leg, then through the kelly hose (rotary hose), through the swivel and down the kelly. The mud then travels down the drillstring to the bit. A bit will usually have two or more nozzles (jets) which accelerate the mud to a high velocity. This jet of mud scours the bottom of the hole to keep the bit cutters clean and keep a fresh rock surface for the bit to attack. From the hole bottom, the mud moves upward in the annular space between the drillstring and the wellbore, carrying the cuttings generated by the bit.
Standpipe
________________________
Swivel
Kelly hose Mud pump
________________________
Discharge line
Kelly
Mixing hopper
________________________ ________________________ ________________________ ________________________
Suction line
________________________
Mud pits
Drill pipe
Shale shaker
________________________
Flow line
________________________ ________________________ ________________________ ________________________
Drill collar
________________________ ________________________
Bit
________________________
Figure 6: Mud circulating system. Introduction
1.12
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Introduction
The mud and its load of cuttings flow out of the &#;bell nipple&#; and through a large-diameter, sloping pipe (flow line) onto one or more vibrating wire-mesh screens mounted on the shale shaker. The idea is that the mud falls through the screens and most of the cuttings (which are bigger than the screen&#;s mesh) are separated from the circulating system. When the mud falls through the screen, it drops into a settling pit. These pits are large, rectangular, metal tanks with pipe or troughs connecting them. The settling pit is not stirred so that any remaining larger solids can settle out of the mud. From the settling pit, the mud moves into stirred mud pits downstream where gas, sand and silt are removed. After that, the mud moves to the suction pit where the pumps pull it out for recirculation downhole. The suction pit is also used for the addition of treating chemicals and mud conditioning additives. A mud hopper with a venturi is used in this pit for adding dry additives such as clays and weighting agents.
BLOWOUT ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
PREVENTERS
A drilling mud should have sufficient density (mud weight) to prevent (hydrostatically) any gas, oil or saltwater from entering the wellbore uncontrolled. Sometimes however, these formation fluids do enter the wellbore under great pressure. When this happens, a well is said to &#;take a kick.&#; It is especially risky if the fluid is a gas or oil. To guard against the dangers of such events, rigs are usually equipped with a stack of Blowout Preventers (BOPs). Depending on the well depth and other circumstances, there will be several BOP units bolted together and then to the surface casing flange. One or more of these BOPs can be engaged to seal off the wellbore if a kick occurs. Multiple BOPs in the stack provide flexibility and redundancy in case of a failure.
________________________
Introduction
1.13
At the top of the BOP stack is a bagtype preventer commonly referred to as an Annular or a Hydril. This unit contains a steel-ribbed, elastomeric insert which can be expanded hydraulically to seal the annulus. Below the bag preventers are the ram-type preventers with hydraulically driven rams that close against the pipe or against themselves, thrusting in from opposite sides of the pipe. These preventers can be pipe, blind or shear rams. Pipe rams have heads with a concave shape to grip the pipe and form a seal around it; they accomplish the same function as the bag preventer but are rated at higher pressure. Blind rams come together over the hole to form a fluid-tight seal against one another in the event the pipe is not in the well or if it has parted and fallen down into the wellbore. Shear rams sever the pipe before sealing together. Below the blowout preventers is the drilling spool. It has an opening in its side to allow drilling mud and the kick fluids to be pumped out. A high-pressure choke line connects to the spool with a special back-pressure valve (the choke) in the line. During well-control procedures, the choke is used to hold back-pressure on the annulus while heavier mud is pumped down the drillstring to kill the kick. If the invading fluid contains gas, the gas must be removed from the mud exiting the well. Gas-cut mud from the choke is sent to a mud-gas separator vessel. The gas is flared and the mud is returned to the pits for reconditioning.
CASING
AND LINER
When a well is being drilled, exposed formations must be periodically covered and protected by steel pipe. This is done for several reasons &#; to keep the hole from caving in, to protect the formations being drilled and/or to isolate different geological zones from each other. These protective pipes are called casings and liners. Casing refers to pipe Revision No: A-2 / Revision Date: 12·31·06
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1
Several methods are used to identify geological strata&#;
Introduction
that starts at the surface or mud line and extends down into the borehole. The term liner applies to pipe whose upper end does not reach the surface or mud line but is inside and overlaps the bottom of the last casing or liner. Casing and liners are either totally or partially cemented in place. Casing. Two, three or more casing strings may be run in a well, with the smaller pipe being run inside the larger sizes, and the smaller ones going deeper than the larger. The &#;surface casing&#; is run and cemented at a depth to protect freshwater aquifers and to avoid mud seepage into shallow sand and gravel beds; it might be set at about 2,000 ft (609.6 m). The next string is the &#;intermediate&#; casing. It is run and cemented when there&#;s a need to change the mud to a density that can&#;t be tolerated by the exposed formations or by the surface casing. Below the intermediate casing may be another string of casing or a liner. Liners. It may not be necessary, economical or practical to line the entire, already-cased hole all the way to the surface just to protect the lower open hole. This is especially true as the hole nears total depth and becomes smaller. So a liner is run from the bottom of the hole, up into the casing, overlapping it by several hundred feet. Liners are held in place inside the casing by special tools called liner hangers. The practice of running a liner protects the last open hole interval, which often includes the reservoir section.
CEMENTING After a string of casing or a liner has been properly landed in the hole, a cement slurry is mixed and quickly pumped down the inside of the casing (or liner). Pressure drives it out the bottom and up into the annular space between the pipe and the hole wall. Cement is followed downhole by just enough fluid to push all but the Introduction
1.14
last part of it out of the casing or liner. Once all the cement hardens, that small quantity still inside the casing or liner is drilled out and the hole proceeds into a few feet of new rock beyond the end of the casing. Then the casing or liner is pressure-tested to see how much mud weight it will be able to hold, for future reference. If it fails the test, a remedial cement job (squeeze) may be required. Once the cement job passes the pressure test, drilling can resume.
MUD
LOGGING
Several methods are used during the drilling of a well to identify geological strata by age and type, and to look for signs of oil and gas. Mud logging is one of these methods. It involves examination of the cuttings for lithology and fluorescence as evidence of oil called shows. By analyzing the gases in the mud returning from downhole, the presence of hydrocarbons is determined. Depth, ROP and other parameters are correlated with oil shows and lithologic changes.
CORING
AND CORE ANALYSIS
A valuable reservoir evaluation method is core analysis. A core is a piece of the actual rock taken from the reservoir under study. Cylindrical pieces of rock (cores) several feet long can be obtained by drilling with a special coring bit attached to a core barrel. The bit cuts only the outer circumference of the formation, and the cylinder of rock that remains is captured inside the core barrel. Small sidewall cores can be obtained with wireline logging equipment after a zone is drilled. Cores are examined to some extent on the rig by a geologist, but they are usually sent to a core analysis laboratory for full evaluation. Labs can directly measure porosity, permeability, clay content, lithology, oil shows and other valuable formation parameters. Revision No: A-2 / Revision Date: 12·31·06
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Introduction
Coring is expensive and is used only when necessary to have the best, direct data about the formation.
DRILL-STEM AND FORMATION-INTERVAL TESTING Drill-Stem Testing (DST) and Formation-Interval Testing (FIT) are two similar methods used to measure directly the production potential of a formation, to capture samples of the fluids from the zone tested, and to obtain pressure and temperature data. A DST is a temporary completion through the drill pipe, using a retrievable packer/tester at the bottom of the string. The packer is set to seal off the annulus, and the tester tool is opened to allow flow from the open zone. Then the tester is closed, the packer is unseated and the drillstring is pulled out of the hole. A sample of fluid is captured. Instruments contained in the tool record the pressure and temperature. An FIT is run into the hole on a wireline rather than the drillstring. The tool seats itself against the side of the hole. A fluid sample is taken, and pressure and temperature are measured. The FIT is then pulled out of the well to capture the sample under pressure. The sample can be transferred, under pressure, to another container for shipment to a laboratory for fluid analysis.
WIRELINE
&#;[Logs] measure the electrical, acoustical and/or radioactive properties of the formations.
LOGGING
The most widely used method of formation evaluation is wireline logging. Specialized tools run into the wellbore measure the electrical, acoustical and/or radioactive properties of the formations. An electrical cable connects the tool to a recording unit on the surface where the signals from the tool are amplified and recorded or digitized for computerized analysis. Logs can be used to locate and identify formations in the well and
Introduction
1.15
for geological correlations with nearby wells. Various logs can indicate lithology, porosity, permeability, fluid type (oil, gas, freshwater, saltwater), fluid contacts and, to some extent, where to find the best part of the reservoir. Logs measure downhole pressures, temperatures and the hole size. Logs also check casing wear and the integrity of the cement bond behind the casing.
DIRECTIONAL
DRILLING
Until recently, most wells were drilled vertically, but more and more, situations today require an increasing number of wells to be drilled at high angles or even horizontally (90° from vertical). In addition to high angles, radical changes in direction (azimuth) can now be made up to 180°. There are many and varied reasons for doing this, but most of them are economic, environmental and/or technical. Deviated wells can access more of the reservoir than would be reached if holes were simply drilled vertically. Horizontal drainholes have become a technical success and are steadily increasing in number. In one application, the directional wellbore intersects several adjacent, but isolated and discrete, vertical fractures with a single drainhole (as in the Austin Chalk). In another, the directional well exposes a longer producing section such as in a thin or lens-type reservoir. Due to the enormous expense of offshore drilling, one platform usually serves as the &#;launch pad&#; for several, highly deviated, long-reach wells to cover most or all of a big reservoir. These wells constitute an extendedreach drilling project such as is common in the North Sea, Gulf of Mexico and other areas. In some cases, the deviated hole may have changes in azimuth direction and inclination, resulting in an S- or U-shaped configuration.
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Introduction
Producing Petroleum WELL
&#;casing prevents the formations from collapsing&#;
COMPLETION
The next step, after setting casings and liners, is the completion phase of a well. Completion simply means making the well ready to produce oil and gas under controlled pressures and flow rates. Figure 7 shows the four common completion techniques. In all four, the casing prevents the formations above the producing zone from collapsing into the wellbore. If the producing formation is strong enough, as in the case of limestone, a length of casing can be cemented immediately above it, leaving the producing formation unsupported. This is called an open hole completion. If the reservoir rock needs support, other methods can be used: Perforated casing or liner. In this method, casing or liner is run all the way through the producing zone and cemented in place. Then, holes are shot Cement Casing to surface
________________________
Producing formation
________________________ ________________________
________________________ ________________________ ________________________ ________________________ ________________________
Gun perforated holes
Producing formation
________________________ ________________________
Cement Casing to surface
(a) Open-hole completion
Cement
Casing to surface Liner hanger and packer
(b) Gun-perforated completion
Cement
Casing to surface
PRODUCTION
Liner hanger and packer
Producing formation
Slotted liner
Producing formation
Slotted liner Gravel
________________________ ________________________ ________________________ ________________________ ________________________
(c) Liner completion
(d) Gravel-packed liner
Figure 7: Bottom-hole arrangement of some types of completions. Introduction
(by explosive charge) through the casing and cement, into the formation. These perforations are created with a perforating gun that is lowered into the hole on a wireline. The gun is then fired electrically, and powerful, shaped charges perforate the pipe and the zone at predetermined intervals. Once the perforations have been made, oil and/or gas can flow into the casing. Perforated or slotted liner. In the second method, a pre-perforated or slotted liner (with holes or slots that are level with the producing zone) is hung from the bottom of the last string of casing. If the producing formation is weak or poorly consolidated, sand and other solids will be carried into the well as the oil or gas is produced. To prevent this &#;sand production,&#;the slotted or perforated liner may contain a wire-wrapped or a prepacked-gravel protective layer to keep the sand from entering the wellbore. Gravel packing. Another approach that is helpful if the producing formation is weak (such as loose sand), and must be supported or held back, is the conventional gravel pack. A gravelpacking operation consists of circulating and placing carefully sized gravel into the annular space between the liner and the wellbore wall. The pack forms a permeable layer to exclude any formation particles from the wellbore that become loose during production.
1.16
TUBING
A string of pipe (tubing) through which oil and gas are produced is a production string. It is hung inside the casing or liner. Tubing sizes range between 3&#;4 and 41&#;2 in. in diameter, with the most common sizes being 23&#;8, 27&#;8 and 31&#;2 in. Because of its relatively high ratio of wall thickness to diameter, tubing can withstand much more pressure than the
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CHAPTER
1
Pumping is an economical method of lifting oil&#;
Introduction
casing, permitting high-pressure reservoirs to be safely controlled and produced. In a high-pressure completion, the casing/tubing annulus is sealed off near the bottom with a tubing packer. (A packer is a sealing device which can expand to seal an annular space between two concentric pipes.) With a packer set and sealed, oil and gas flow into the cased hole below the packer then into the tubing and up to the surface where pressure and rate are controlled by surface valves and chokes. If a well produces from two or more zones, a multiple-zone packer must be used to accommodate production from different zones flowing into a single tubing string. Another alternative is to complete the well with multiple tubing strings and use multiple packers to direct oil and gas production from each zone into separate tubing strings. A stable, non-corrosive packer fluid is left static in the annular space above the packer and surrounding the tubing. This fluid will be left in place for years. Packer fluids are needed to help balance pressure and mechanical forces on the casing, tubing and packer.
PRODUCTION ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
EQUIPMENT
Once the well has been completed, it is ready to be put on-line and start producing. At the surface, a variety of equipment comes into play at this stage. This equipment will vary from well to well and will change as a given well becomes depleted. A fundamental consideration is whether the reservoir has enough internal pressure to flow naturally or whether it must be assisted. If the well flows without assistance, then only a wellhead will be required. The wellhead (Christmas tree) is a series
of flow-control valves, chokes and gauges mounted on spools. From the Christmas tree, the oil and gas move to a separator, perhaps a heater/treater to break any emulsion and prepare the oil for transfer to a storage tank or oil pipeline, and prepare the gas for a pipeline. Gas may have to be compressed before being put into a pipeline.
PUMPING
METHODS
If reservoir pressure is too low to force the oil, gas and water to the surface, some type of artificial lift is needed. Pumping is an economical method of lifting oil to the surface. The pump itself is located downhole, below the level of standing oil. A reciprocatingtype (plunger) pump lifts oil on the upstroke and refills the pump on the downstroke. A sucker rod from the pump up to the surface is connected to a pump jack. Downhole electrical pumps are another commonly used method for getting oil and water to the surface. They are placed downhole and are powered by electricity supplied by a cable. Another common method for lifting oil is gas-assisted lift or simply gas lift. This method uses gas (from the same well or another source) injected into the oil column downhole to lift the fluids. Gas is injected under pressure into the casing/tubing annulus through a series of gas-lift valves. Fluids (oil and water) that are above the gas-inlet port are displaced upwards, becoming less dense as they rise to the surface because of the gas that&#;s been injected into them. Gas, oil and water can be lifted this way until it is no longer economical.
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Introduction
1.17
Revision No: A-0 / Revision Date: 03·31·98
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2
Functions
Introduction
The duty of those charged with drilling the hole&#;
The objective of a drilling operation is to drill, evaluate and complete a well that will produce oil and/or gas efficiently. Drilling fluids perform numerous functions that help make this possible. The responsibility for performing these functions is held jointly by the mud engineer and those who direct the drilling operation. The duty of those charged with drilling the hole &#; including the oil company representative, drilling contractor and rig crew &#; is to make sure correct drilling procedures are conducted. The chief duty of the mud engineer is to assure that mud properties are correct for the specific
drilling environment. The mud engineer should also recommend drilling practice changes that will help reach the drilling objectives.
Drilling Fluid Functions
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Drilling fluid functions describe tasks which the drilling fluid is capable of performing, although some may not be essential on every well. Removing cuttings from the well and controlling formation pressures are of primary importance on every well. Though the order of importance is determined by well conditions and current operations, the most common drilling fluid functions are: 11. Remove cuttings from the well. 12. Control formation pressures. 13. Suspend and release cuttings. 14. Seal permeable formations. 15. Maintain wellbore stability. 16. Minimize reservoir damage. 17. Cool, lubricate, and support the bit and drilling assembly. 18. Transmit hydraulic energy to tools and bit. 19. Ensure adequate formation evaluation. 10. Control corrosion.
11. Facilitate cementing and completion. 12. Minimize impact on the environment.
1. REMOVE
CUTTINGS FROM THE WELL
As drilled cuttings are generated by the bit, they must be removed from the well. To do so, drilling fluid is circulated down the drillstring and through the bit, entraining the cuttings and carrying them up the annulus to the surface. Cuttings removal (hole cleaning) is a function of cuttings size, shape and density combined with Rate of Penetration (ROP); drillstring rotation; and the viscosity, density and annular velocity of the drilling fluid. Viscosity. The viscosity and rheological properties of drilling fluids have a significant effect on hole cleaning. Cuttings settle rapidly in low-viscosity fluids (water, for example) and are difficult to circulate out of the well. Generally, higher-viscosity fluids improve cuttings transport.
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Functions
2.1
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
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The use of shearthinning, thixotropic fluids with high LowShear-Rate Viscosity&#;
The rate at which a cutting settles in a fluid&#;
Functions
Most drilling muds are thixotropic, which means they gel under static conditions. This characteristic can suspend cuttings during pipe connections and other situations when the mud is not being circulated. Fluids that are shearthinning and have elevated viscosities at low annular velocities have proven to be best for efficient hole cleaning. Velocity. Generally, higher annular velocity improves cuttings removal. Yet, with thinner drilling fluids, high velocities may cause turbulent flow, which helps clean the hole but may cause other drilling or wellbore problems. The rate at which a cutting settles in a fluid is called the slip velocity. The slip velocity of a cutting is a function of its density, size and shape, and the viscosity, density and velocity of the drilling fluid. If the annular velocity of the drilling fluid is greater than the slip velocity of the cutting, the cutting will be transported to the surface. The net velocity at which a cutting moves up the annulus is called the transport velocity. In a vertical well: Transport velocity = Annular velocity &#; slip velocity (Note: Slip velocity, transport velocity, and the effects of rheology and hydraulic conditions on cuttings transport will be discussed in detail in another chapter.) Cuttings transport in high-angle and horizontal wells is more difficult than in vertical wells. The transport velocity as defined for vertical wellbores is not relevant for deviated holes, since the cuttings settle to the low side of the hole across the fluid&#;s flow path and not in the direction opposite to the flow of drilling fluid. In horizontal wells, cuttings accumulate along the bottom side of the wellbore, forming cuttings beds. These beds restrict flow, increase torque and are difficult to remove. Two different approaches are used for the difficult hole-cleaning situations found in high-angle and horizontal wellbores: Functions
2.2
a) The use of shear-thinning, thixotropic fluids with high Low-ShearRate Viscosity (LSRV) and laminar flow conditions. Examples of these fluid types are biopolymer systems, like FLOPRO*, and flocculated bentonite slurries like the Mixed Metal Hydroxide (MMH) DRILPLEX* system. Such drilling fluid systems provide a high viscosity with a relatively flat annular velocity profile, cleaning a larger portion of the wellbore cross section. This approach tends to suspend cuttings in the mud flow path and prevent cuttings from settling to the low side of the hole. With weighted muds, cuttings transport can be improved by increasing the 3 and 6 RPM Fann dial readings (indications of LSRV) to 1 to 11&#;2 times the hole size in inches and to use the highest possible laminar flow rate. b) The use of a high flow rate and thin fluid to achieve turbulent flow. Turbulent flow will provide good hole cleaning and prevent cuttings from settling while circulating, but cuttings will settle quickly when circulation is stopped. This approach works by keeping the cuttings suspended with turbulence and high annular velocities. It works best with low-density, unweighted fluids in competent (not easily eroded) formations. The effectiveness of this technique can be limited by a number of factors, including large hole size, low pump capacity, increased depth, insufficient formation integrity, and the use of mud motors and downhole tools that restrict flow rate. Density. High-density fluids aid hole cleaning by increasing the buoyancy forces acting on the cuttings, helping to remove them from the well. Compared to fluids of lower density, high-density fluids may clean the hole adequately even with lower annular velocities and lower rheological properties. However, mud weight in excess of what is needed Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
2
Higher rotary speeds also aid hole cleaning&#;
Functions
to balance formation pressures has a negative impact on the drilling operation; therefore, it should never be increased for hole-cleaning purposes. Drillstring rotation. Higher rotary speeds also aid hole cleaning by introducing a circular component to the annular flow path. This helical (spiral- or corkscrew-shaped) flow around the drillstring causes drill cuttings near the wall of the hole, where poor hole-cleaning conditions exist, to be moved back into the higher transport regions of the annulus. When possible, drillstring rotation is one of the best methods for removing cuttings beds in high-angle and horizontal wells.
2. CONTROLLING
FORMATION
PRESSURES
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As mentioned earlier, a basic drilling fluid function is to control formation pressures to ensure a safe drilling operation. Typically, as formation pressures increase, drilling fluid density is increased with barite to balance pressures and maintain wellbore stability. This keeps formation fluids from flowing into the wellbore and prevents pressured formation fluids from causing a blowout. The pressure exerted by the drilling fluid column while static (not circulating) is called the hydrostatic pressure and is a function of the density (mud weight) and True Vertical Depth
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Functions
2.3
(TVD) of the well. If the hydrostatic pressure of the drilling fluid column is equal to or greater than the formation pressure, formation fluids will not flow into the wellbore. Keeping a well &#;under control&#; is often characterized as a set of conditions under which no formation fluid will flow into the wellbore. But it also includes conditions where formation fluids are allowed to flow into the wellbore &#; under controlled conditions. Such conditions vary &#; from cases where high levels of background gas are tolerated while drilling, to situations where the well is producing commercial quantities of oil and gas while being drilled. Well control (or pressure control) means there is no uncontrollable flow of formation fluids into the wellbore. Hydrostatic pressure also controls stresses adjacent to the wellbore other than those exerted by formation fluids. In geologically active regions, tectonic forces impose stresses in formations and may make wellbores unstable even when formation fluid pressure is balanced. Wellbores in tectonically stressed formations can be stabilized by balancing these stresses with hydrostatic pressure. Similarly, the orientation of the wellbore in high-angle and horizontal intervals can cause decreased wellbore stability, which can also be controlled with hydrostatic pressure. Normal formation pressures vary from a pressure gradient of 0.433 psi/ft (9.79 kPa/m) (equivalent to 8.33 lb/gal [1 kg/L] freshwater) in inland areas to 0.465 psi/ft (10.52 kPa/m) (equivalent to 8.95 lb/gal [1.07 kg/L]) in marine basins. Elevation, location, and various geological processes and histories create conditions where formation pressures depart considerably from these normal values. The density of drilling fluid may range from that of air (essentially 0 psi/ft), to in excess of 20.0 lb/gal (2.4 kg/L) (1.04 psi/ft [23.52 kPa/m]). Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
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Functions
Often, formations with sub-normal pressures are drilled with air, gas, mist, stiff foam, aerated mud or special ultralow-density fluids (usually oil-base). The mud weight used to drill a well is limited by the minimum weight needed to control formation pressures and the maximum mud weight that will not fracture the formation. In practice, the mud weight should be limited to the minimum necessary for well control and wellbore stability.
3. SUSPEND AND RELEASE CUTTINGS
Drilling muds must suspend drill cuttings&#;
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Drilling muds must suspend drill cuttings, weight materials and additives under a wide range of conditions, yet allow the cuttings to be removed by the solids-control equipment. Drill cuttings that settle during static conditions can cause bridges and fill, which in turn can cause stuck pipe or lost circulation. Weight material which settles is referred to as sag and causes a wide variation in the density of the well fluid. Sag occurs most often under dynamic conditions in high-angle wells, where the fluid is being circulated at low annular velocities. High concentrations of drill solids are detrimental to almost every aspect of the drilling operation, primarily drilling efficiency and ROP. They increase the mud weight and viscosity, which in turn increases maintenance costs and the need for dilution. They also increase the horsepower required to circulate, the thickness of the filter cake, the torque and drag, and the likelihood of differential sticking. Drilling fluid properties that suspend cuttings must be balanced with those properties that aid in cuttings removal by solids-control equipment. Cuttings suspension requires high-viscosity, shearthinning thixotropic properties, while solids-removal equipment usually works more efficiently with fluids of lower viscosity. Solids-control equipment is
not as effective on non-shear-thinning drilling fluids, which have high solids content and a high plastic viscosity. For effective solids control, drill solids must be removed from the drilling fluid on the first circulation from the well. If cuttings are recirculated, they break down into smaller particles that are more difficult to remove. One easy way to determine whether drill solids are being removed is to compare the sand content of the mud at the flow line and at the suction pit.
4. SEAL
PERMEABLE FORMATIONS
Permeability refers to the ability of fluids to flow through porous formations; formations must be permeable for hydrocarbons to be produced. When the mud column pressure is greater than formation pressure, mud filtrate will invade the formation, and a filter cake of mud solids will be deposited on the wall of the wellbore. Drilling fluid systems should be designed to deposit a thin, low-permeability filter cake on the formation to limit the invasion of mud filtrate. This improves wellbore stability and prevents a number of drilling and production problems. Potential problems related to thick filter cake and excessive filtration include &#;tight&#; hole conditions, poor log quality, increased torque and drag, stuck pipe, lost circulation, and formation damage. In highly permeable formations with large pore throats, whole mud may invade the formation, depending on the size of the mud solids. For such situations, bridging agents must be used to block the large openings so the mud solids can form a seal. To be effective, bridging agents must be about one-half the size of the largest opening. Bridging agents include calcium carbonate, ground cellulose and a wide variety of seepage-loss or other fine lost-circulation materials.
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Functions
2.4
Revision No: A-0 / Revision Date: 03·31·98
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Functions
Depending on the drilling fluid system in use, a number of additives can be applied to improve the filter cake, thus limiting filtration. These include bentonite, natural and synthetic polymers, asphalt and gilsonite, and organic deflocculating additives.
Wellbore stability is a complex balance&#;
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5. MAINTAIN
WELLBORE STABILITY
Wellbore stability is a complex balance of mechanical (pressure and stress) and chemical factors. The chemical composition and mud properties must combine to provide a stable wellbore until casing can be run and cemented. Regardless of the chemical composition of the fluid and other factors, the weight of the mud must be within the necessary range to balance the mechanical forces acting on the wellbore (formation pressure, wellbore stresses related to orientation and tectonics). Wellbore instability is most often identified by a sloughing formation, which causes tight hole conditions, bridges and fill on trips. This often makes it necessary to ream back to the original depth. (Keep in mind these same symptoms also indicate holecleaning problems in high-angle and difficult-to-clean wells.) Wellbore stability is greatest when the hole maintains its original size and cylindrical shape. Once the hole is eroded or enlarged in any way, it becomes weaker and more difficult to stabilize. Hole enlargement leads to a host of problems, including low Functions
2.5
annular velocity, poor hole cleaning, increased solids loading, fill, increased treating costs, poor formation evaluation, higher cementing costs and inadequate cementing. Hole enlargement through sand and sandstone formations is due largely to mechanical actions, with erosion most often being caused by hydraulic forces and excessive bit nozzle velocities. Hole enlargement through sand sections may be reduced significantly by following a more conservative hydraulics program, particularly with regard to impact force and nozzle velocity. Sands that are poorly consolidated and weak require a slight overbalance to limit wellbore enlargement and a good-quality filter cake containing bentonite to limit wellbore enlargement. In shales, if the mud weight is sufficient to balance formation stresses, wells are usually stable &#; at first. With water-base muds, chemical differences cause interactions between the drilling fluid and shale, and these can lead (over time) to swelling or softening. This causes other problems, such as sloughing and tight hole conditions. Highly fractured, dry, brittle shales, with high dip angles, can be extremely unstable when drilled. The failure of these dry, brittle formations is mostly mechanical and not normally related to water or chemical forces. Various chemical inhibitors or additives can be added to help control mud/shale interactions. Systems with high levels of calcium, potassium or other chemical inhibitors are best for drilling into water-sensitive formations. Salts, polymers, asphaltic materials, glycols, oils, surfactants and other shale inhibitors can be used in water-base drilling fluids to inhibit shale swelling and prevent sloughing. Shale exhibits such a wide range of composition and sensitivity that no single additive is universally applicable.
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Functions
Oil- or synthetic-base drilling fluids are often used to drill the most watersensitive shales in areas with difficult drilling conditions. These fluids provide better shale inhibition than water-base drilling fluids. Clays and shales do not hydrate or swell in the continuous phase, and additional inhibition is provided by the emulsified brine phase (usually calcium chloride) of these fluids. The emulsified brine reduces the water activity and creates osmotic forces that prevent adsorption of water by the shales.
6. MINIMIZE
Protecting the reservoir from damage&#;is a big concern.
FORMATION DAMAGE
Protecting the reservoir from damage that could impair production is a big concern. Any reduction in a producing formation&#;s natural porosity or permeability is considered to be formation damage. This can happen as a result of plugging by mud or drill solids or through chemical (mud) and mechanical (drilling assembly) interactions with the formation. Frequently, formation damage is reported as a skin damage value or by the amount of pressure drop that occurs while the well is producing (drawdown pressure). The type of completion procedure and method will determine which level of formation protection is required. Functions
2.6
For example, when a well is cased, cemented and perforated, the perforation depth usually allows efficient production, even if near-wellbore damage exists. Conversely, when a horizontal well is completed with one of the &#;openhole&#; methods, a &#;reservoir drill-in&#; fluid &#; specially designed to minimize damage &#; is required. While the effect of drilling fluid damage is rarely so extensive that oil and/or gas cannot be produced, consideration should be given to potential formation damage when selecting a fluid for drilling potential reservoir intervals. Some of the most common mechanisms for formation damage are: a) Mud or drill solids invading the formation matrix, plugging pores. b) Swelling of formation clays within the reservoir, reducing permeability. c) Precipitation of solids as a result of mud filtrate and formation fluids being incompatible. d) Precipitation of solids from the mud filtrate with other fluids, such as brines or acids, during completion or stimulation procedures. e) Mud filtrate and formation fluids forming an emulsion, restricting permeability. The possibility of formation damage can be determined from offset well data and studies of formation cores for return permeability. Drilling fluids designed to minimize a particular problem, specially designed reservoir drill-in fluids or workover and completion fluids, all can be used to minimize formation damage.
7. COOL,
LUBRICATE AND SUPPORT THE BIT AND DRILLING ASSEMBLY
Considerable frictional heat is generated by mechanical and hydraulic forces at the bit and where the rotating drillstring rubs against the casing and wellbore. Circulation of the drilling fluid cools the bit and drilling assembly, Revision No: A-1 / Revision Date: 02·28·01
CHAPTER
2
The lubricity of a particular fluid is measured by&#;
Hydraulic energy can be used to maximize ROP&#;
Functions
transferring this heat away from the source, distributing it throughout the well. Drilling fluid circulation cools the drillstring to temperatures lower than the bottom-hole temperature. In addition to cooling, drilling fluid lubricates the drillstring, further reducing frictional heat. Bits, mud motors and drillstring components would fail more rapidly if it were not for the cooling and lubricating effects of drilling fluid. The lubricity of a particular fluid is measured by its Coefficient of Friction (COF), and some muds do a better job than others at providing lubrication. For example, oil- and synthetic-base muds lubricate better than most waterbase muds, but lubricants can be added to water-base muds to improve them. On the other hand, water-base muds provide more lubricity and cooling ability than air or gas. The amount of lubrication provided by a drilling fluid varies widely and depends on the type and quantity of drill solids and weight material, plus the chemical composition of the system &#; pH, salinity and hardness. Altering mud lubricity is not an exact science. Even after a thorough evaluation, with all relevant factors considered, application of a lubricant may not produce the anticipated reduction in torque and drag. Indications of poor lubrication are high torque and drag, abnormal wear, and heat checking of drillstring components. But be aware that these problems can also be caused by severe doglegs and directional problems, bit balling, key seating, poor hole cleaning and incorrect bottom-hole assembly design. While a lubricant may reduce the symptoms of these problems, the actual cause must be corrected to resolve the problem. The drilling fluid helps to support a portion of the drillstring or casing string weight through buoyancy. If a
Functions
2.7
drillstring, liner or casing string is suspended in drilling fluid, it is buoyed by a force equal to the weight of the mud displaced, thereby reducing hook load on the derrick. Buoyancy is directly related to the mud weight, so an 18-lb/gal (2.2-kg/L) fluid will provide twice the buoyancy of a 9-lb/gal (1.1-kg/L) fluid. The weight that the derrick can support is limited by its mechanical capacity, a consideration that becomes increasingly important with increased depth as the weight of the drillstring and casing becomes tremendous. While most rigs have sufficient capacity to handle the drillstring weight without buoyancy, it is an important consideration when evaluating the neutral point (where the drillstring is in neither tension nor compression). However, when running long, heavy strings of casing, buoyancy can be used to provide a significant benefit. Using buoyancy, it is possible to run casing strings whose weight exceeds a rig&#;s hook load capacity. If the casing is not completely filled with mud as it is lowered into the hole, the void volume inside the casing increases buoyancy, allowing a significant reduction in hook load to be used. This process is referred to as &#;floating in&#; the casing.
8. TRANSMIT
HYDRAULIC ENERGY TO TOOLS AND BIT
Hydraulic energy can be used to maximize ROP by improving cuttings removal at the bit. It also provides power for mud motors to rotate the bit and for Measurement While Drilling (MWD) and Logging While Drilling (LWD) tools. Hydraulics programs are based on sizing the bit nozzles properly to use available mud pump horsepower (pressure or energy) to generate a maximized pressure drop at the bit or to optimize jet impact force on the bottom of the well. Hydraulics programs
Revision No: A-2 / Revision Date: 12·31·06
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2
Functions
are limited by the available pump horsepower, pressure losses inside the drillstring, maximum allowable surface pressure and optimum flow rate. Nozzle sizes are selected to use the available pressure at the bit to maximize the effect of mud impacting the bottom of the hole. This helps remove cuttings from beneath the bit and keep the cutting structure clean. Drillstring pressure losses are higher in fluids with higher densities, plastic viscosities and solids. The use of smallID drill pipe or tool joints, mud motors and MWD/LWD tools all reduce the amount of pressure available for use at the bit. Low-solids, shear-thinning drilling fluids or those that have dragreducing characteristics, such as polymer fluids, are more efficient at transmitting hydraulic energy to drilling tools and the bit. In shallow wells, sufficient hydraulic horsepower usually is available to clean the bit efficiently. Because drillstring pressure losses increase with well depth, a depth will be reached where there is insufficient pressure for optimum bit cleaning. This depth can be extended by carefully controlling the mud properties.
9. ENSURE
Accurate formation evaluation is essential to the success&#;
ADEQUATE FORMATION EVALUATION
Accurate formation evaluation is essential to the success of the drilling operation, particularly during exploration drilling. The chemical and physical properties of the mud affect formation evaluation. The physical and chemical wellbore conditions after drilling also influence formation evaluation. During drilling, the circulation of mud and cuttings is monitored for signs of oil and gas by technicians called mud loggers. They examine the cuttings for mineral composition, paleontology and visual signs of hydrocarbons. This information is recorded on a mud log that shows lithology, ROP, gas detection and
Functions
2.8
oil-stained cuttings plus other important geological and drilling parameters.
Electric wireline logging is performed to evaluate the formation in order to obtain additional information. Sidewall cores also may be taken with wirelineconveyed tools. Wireline logging includes measuring the electrical, sonic, nuclear and magnetic-resonance properties of the formation to identify lithology and formation fluids. For continuous logging while the well is being drilled, LWD tools are available. Drilling a cylindrical section of the rock (a core) for laboratory evaluation also is done in target production zones to obtain desired information. Potentially productive zones are isolated and evaluated by performing Formation Testing (FT) or DrillStem Testing (DST) to obtain pressure and fluid samples. All of these formation evaluation methods are affected by the drilling fluid. For example, if the cuttings disperse in the mud, there will be nothing for the mud logger to evaluate at the surface. Or, if cuttings transport is poor, it will be difficult for the mud logger to determine the depth at which the cuttings originated. Oil muds, lubricants, asphalts and other
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2
Dissolved gasses&#;can cause serious corrosion problems&#;
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Functions
additives will mask indications of hydrocarbons on cuttings. Certain electrical logs work in conductive fluids, while others work in non-conductive fluids. Drilling fluid properties will affect the measurement of rock properties by electrical wireline tools. Excessive mud filtrate can flush oil and gas from the near-wellbore region, adversely affecting logs and FT or DST samples. Muds that contain high potassium ion concentrations interfere with the logging of natural formation radioactivity. High or variable filtrate salinity can make electrical logs difficult or impossible to interpret. Wireline logging tools must be run from the surface to bottom, with the actual measurement of rock properties being performed as the tools are pulled up the hole. For optimum wireline logging, the mud must not be too thick, it must keep the wellbore stable and it must suspend any cuttings or cavings. In addition, the wellbore must be neargauge from top to bottom, since excessive bore enlargement and/or thick filter cakes can produce varying logging responses and increase the possibility of sticking the logging tool. Mud for drilling a core is selected based on the type of evaluation to be performed. If a core is being taken only for lithology (mineral analysis), mud type is not a concern. If the core will be used for waterflood and/or wettability studies, a &#;bland,&#; neutral-pH, water-base mud without surfactants or thinners will be needed. If the core will be used for measuring reservoir water saturation, a bland oil mud with minimal surfactants and no water or salt is often recommended. Many coring operations specify a bland mud with a minimum of additives.
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10. CONTROL
CORROSION
Drillstring and casing components that are in continual contact with the drilling fluid are susceptible to various Functions
2.9
forms of corrosion. Dissolved gasses such as oxygen, carbon dioxide and hydrogen sulfide can cause serious corrosion problems, both at the surface and downhole. Generally, low pH aggravates corrosion. Therefore, an important drilling fluid function is to keep corrosion to an acceptable level. In addition to providing corrosion protection for metal surfaces, drilling fluid should not damage rubber or elastomer goods. Where formation fluids and/or other downhole conditions warrant, special metals and elastomers should be used. Corrosion coupons should be used during all drilling operations to monitor corrosion types and rates. Mud aeration, foaming and other trapped-oxygen conditions can cause severe corrosion damage in a short period of time. Chemical inhibitors and scavengers are used when the corrosion threat is significant. Chemical inhibitors must be applied properly. Corrosion coupons should be evaluated to tell whether the correct chemical inhibitor is being used and if the amount is sufficient. This will keep the corrosion rate at an acceptable level. Hydrogen sulfide can cause rapid, catastrophic drillstring failure. It is also deadly to humans after even short periods of exposure and in low concentrations. When drilling in high H2S environments, elevated pH fluids, combined with a sulfide-scavenging chemical like zinc, should be used.
11. FACILITATE
CEMENTING AND COMPLETION
The drilling fluid must produce a wellbore into which casing can be run and cemented effectively and which does not impede completion operations. Cementing is critical to effective zone isolation and successful well completion. During casing runs, the mud must remain fluid and minimize pressure surges so that fracture-induced lost circulation does not occur. Running Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
2
The mud should have a thin, slick filter cake.
Functions
casing is much easier in a smooth, ingauge wellbore with no cuttings, cavings or bridges. The mud should have a thin, slick filter cake. To cement casing properly, the mud must be completely displaced by the spacers, flushes and cement. Effective mud displacement requires that the hole should be neargauge and the mud must have low viscosity and low, non-progressive gel strengths. Completion operations such as perforating and gravel packing also require a near-gauge wellbore and may be affected by mud characteristics.
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12. MINIMIZE
IMPACT ON THE ENVIRONMENT
Eventually, drilling fluid becomes a waste product, and must be disposed of in accordance with local environmental regulations. Fluids with low environmental impact that can be disposed of near the well are the most desirable. In most countries, local environmental regulations have been established for drilling fluid wastes. Water-base, oilbase, non-aqueous and synthetic-base fluids all have different environmental considerations, and no single set of
environmental characteristics is acceptable for all locations. This is due mainly to the changing, complex conditions that exist around the world &#; the location and density of human populations, the local geographic situation (offshore or onshore), high or low rainfall, proximity of the disposal site to surface and underground water supplies, local animal and plant life, and more.
SUMMARY Recommending a drilling fluid system should be based on the ability of the fluid to achieve the essential functions and to minimize anticipated well problems. Although the functions discussed in this chapter may provide guidelines for mud selection, they should not be the sole basis for selecting a drilling fluid for a well. The selection process must be founded on a wide experience base, local knowledge and consideration of the best technology available. Mud selection. Initially, anticipation of well problems helps in selecting a particular drilling fluid system for a particular well. However, other considerations may exist that dictate use of a different system. The cost, availability of products and environmental factors are always important considerations. But it is usually the oil company representatives&#; experience and preferences that are the deciding factors. Many wells are drilled successfully with fluids that were not selected for performance alone. The success of these wells results from experienced mud engineers who adapt the drilling fluid system to meet the unique conditions encountered on each well. Mud properties vs. functions. Different mud properties may affect a particular mud function. Even if the mud engineer changes only one or two properties to control a given drilling
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Functions
2.10
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
2
Drilling fluid engineering almost always requires tradeoffs&#;
Functions
fluid function, another may be affected as well. Mud properties should be recognized for their influence on all functions and the relative importance of each function. For example, formation pressure is controlled primarily by changing mud weight, but the influence of viscosity on annular pressure losses and Equivalent Circulating Density (ECD) should be considered to avoid lost circulation. When functions clash. Drilling fluid engineering almost always requires tradeoffs in treating and maintaining the properties needed to accomplish the required functions. A high mud viscosity might improve hole cleaning, yet it might lower hydraulic efficiency, increase drill solids retention, slow the penetration rate, and change dilution and chemical treatment requirements. Experienced drilling fluid engineers are aware of these tradeoffs and understand how to improve one function while minimizing the impact of mud property changes on other functions.
Functions
2.11
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CHAPTER
3
Testing
Water-Mud Testing ............................................................................................. 3.3 Section 1. Density of Fluid (Mud Weight) .............................................................. 3.3 Section 2. Viscosity ............................................................................................................ 3.4 A) Marsh Funnel .......................................................................................................................... 3.4 B) Rotational Viscometer ............................................................................................................ 3.5
Section 3. Filtration ........................................................................................................... 3.7 A) API Fluid Loss ......................................................................................................................... 3.7 B) High-Temperature, High-Pressure (HTHP) Filtration ............................................................ 3.8 C) Filter-Cake Compressibility .................................................................................................. 3.11
Section 4. Sand Content ................................................................................................ 3.11 Section 5. Liquid and Solid Content ....................................................................... 3.12 A) Procedure: Retort ................................................................................................................. 3.12 B) Methylene Blue Capacity ..................................................................................................... 3.14 C) Methylene Blue Capacity of Shale ...................................................................................... 3.14 D) Flocculent Efficiency Test .................................................................................................... 3.15
Section 6. Hydrogen Ion Concentration (pH) .................................................... 3.15 A) Indicator Sticks ..................................................................................................................... 3.15 B) pH Meter ............................................................................................................................... 3.16
Section 7. Chemical Analysis of Water-Base Drilling Fluids ........................ 3.17 A) Alkalinity (Pf, Mf, Pm and Lime Content) ........................................................................... 3.17 B) Garrett Gas Train (GGT) Test for Carbonates ...................................................................... 3.19 C) Chloride (Cl&#;) ........................................................................................................................ 3.21 D) Calcium &#; Qualitative ........................................................................................................ 3.22 E) Total Hardness ....................................................................................................................... 3.22 F) Hardness in Dark Filtrates ..................................................................................................... 3.23 G) Sulfate ................................................................................................................................... 3.25 H) Potassium (K+) ....................................................................................................................... 3.26 I) Nitrate Ion Concentration .................................................................................................... 3.28 J) PHPA Polymer Concentration ............................................................................................... 3.30
Section 8. Chemical Analysis Relating to Corrosion ...................................... 3.32 A) Zinc oxide (ZnO) and Basic Zinc Carbonate (ZnCO3&#;Zn(OH)2) ....................................... 3.32 B) Iron Sulfide Scale (Qualitative) ............................................................................................ 3.33 C) Hydrogen Sulfide (H2S) ....................................................................................................... 3.33 D) Phosphate ............................................................................................................................. 3.35 E) Oxygen Scavenger: SO32&#; Content ........................................................................................ 3.38
Section 9. Resistivity ....................................................................................................... 3.39 Section 10. Glycol Testing Procedure ..................................................................... 3.40 A) Refractometer ........................................................................................................................ 3.40 B) Dual-Temperature Retort Analysis for Glycol Systems ....................................................... 3.40 C) Chemical Determination of Glycol Using Centrifuge ....................................................... 3.41
Section 11. KLA-GARD* Concentration ..................................................................... 3.41
Testing
3.1
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Section 12. Permeability Plugging Test Procedure ........................................... 3.43 Section 13. Brookfield Viscometer ........................................................................... 3.45 Section 14. Drill Pipe Corrosion Ring Coupons ................................................ 3.48 A) Ring Coupon Monitoring Procedure ................................................................................... 3.49 B) Laboratory Coupon Analysis ................................................................................................ 3.49 C) Calculation of Corrosion Rates ............................................................................................ 3.50
Oil-Mud Testing (Including Diesel Oil, Mineral Oil and Synthetic Fluids) .............................................. 3.52 Section 1. Aniline Point Determination ............................................................... 3.52 Section 2. Density (Mud Weight) .............................................................................. 3.52 Section 3. Viscosity and Gel Strength .................................................................... 3.53 A) Marsh Funnel ........................................................................................................................ 3.53 B) Rotational Viscometer .......................................................................................................... 3.53
Section Section Section Section Section
4. Filtration ......................................................................................................... 3.55 5. Activity ............................................................................................................ 3.57 6. Electrical Stability ...................................................................................... 3.57 7. Liquid and Solids ........................................................................................ 3.58 8. Chemical Analysis of Oil-Base Drilling Muds .............................. 3.59
A) Alkalinity (Pom) (VSA&#;API) ................................................................................................... 3.59 B) Salinity &#; Chlorides in the Whole Mud ............................................................................. 3.59 C) Whole Mud Calcium Calculation ....................................................................................... 3.60 D) Sulfides .................................................................................................................................. 3.62
Pilot Testing ............................................................................................................... 3.64
Testing
3.2
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Water-Mud Testing The API has recommended standard methods of conducting field and laboratory tests for drilling fluids and detailed procedures may be found in the API publication, &#;Recommended Practice: Standard Procedure for Field Testing
Water-Based (Oil-Based) Drilling Fluids,&#; API RP 13B-1, 13B-2 and supplements (also see 13I for Laboratory Testing Drilling Fluids, 13J for Testing Heavy Brines and supplements).
Section 1. Density of Fluid (Mud Weight) Instruments The density (commonly referred to as mud weight) is measured with a mud balance of sufficient accuracy to measure within 0.1 lb/gal (0.5 lb/ft3 or 5 psi/ 1,000 ft of depth). For all practical purposes, density means weight per unit volume and is measured by weighing the mud. The weight of mud may be expressed as a hydrostatic pressure gradient in lb/in.2 per 1,000 ft of vertical depth (psi/1,000 ft), as a density in lb/gal, lb/ft3 or Specific Gravity (SG) (see Table 1).
SG =
lb/gal lb/ft3 g or or 8.345 62.3 cm3
Table 1: Conversion table for density units.
MUD
BALANCE
Description The mud balance (see Figure 1) consists principally of a base on which rests a graduated arm with cup, lid, knife edge, level vial, rider and counterweight. The constant volume cup is affixed to one end of the graduated arm, which has a counterweight at the other end. The cup and arm oscillate in a plane perpendicular to the horizontal knife edge, which rests on the support, and are balanced by moving the rider along the arm.
Testing
3.3
Figure 1: M-I SWACO* mud balance.
Calibration 1. Remove the lid from the cup and completely fill the cup with pure or distilled water. 2. Replace the lid and wipe dry. 3. Replace the balance arm on the base, with the knife edge resting on the fulcrum. 4. The level-bubble should be centered when the rider is set on 8.33 lb/gal (1 kg/L). If not, adjust using the calibration screw in the end of the balance arm. Some balances do not have calibration screws and must have lead shot added or taken out through the calibration cap. Procedure 1. Remove the lid from the cup, and completely fill the cup with the mud to be tested. 2. Replace the lid and rotate until firmly seated, making sure some mud is expelled through the hole in the lid.
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3. Wash the mud from the outside of the cup, and dry it. 4. Place the balance arm on the base, with the knife edge resting on the fulcrum. 5. Move the rider until the graduated arm is level, as indicated by the level vial on the beam. 6. At the edge of the rider closest to the cup, read the density or weight of the mud. 7. Report the result to the nearest scale division, either in lb/gal, lb/ft3, psi/1,000 ft of depth or Specific Gravity (SG).
8. For balances not showing the desired scale, the equations shown in Table 1 may be used. Mud gradient: psi/ft = 0.052 x lb/gal = 0. x SG = 0. x lb/ft3 SG kg/cm2/m = 10 141.5 SG at 60° F (15.6° C) = 131.5 + °API Where: °API = American Petroleum Institute gravity
Section 2. Viscosity Instruments The Marsh funnel is used for routine field measurement of the viscosity of drilling mud. The Fann V-G meter is used to supplement the information obtained from the Marsh funnel, particularly with respect to the gel characteristics of the mud. The V-G meter is capable of giving the apparent viscosity, plastic viscosity, yield point and gel strengths (initial and timed).
A) MARSH
FUNNEL
Description The Marsh funnel (see Figure 2) is 6 in. (152.4 mm) in diameter at the top and 12 in. (304.8 mm) long. At the bottom, a smooth-bore tube 2 in. (50.8 mm) long having an inside diameter of 3&#;16 in. is attached in such a way that there is no constriction at the joint. A wire screen having 1&#;16-in. openings, covering one-half of the funnel, is fixed at a level of 3&#;4 in. (19 mm) below the top of the funnel.
Testing
3.4
Figure 2: Marsh funnel.
Calibration Fill the funnel to the bottom of the screen (1,500 mL) with freshwater at 70±5° F (21±3° C). Time of outflow of 1 qt (946 mL) should be 26 sec ±0.5 sec. Procedure 1. With the funnel in an upright position, cover the orifice with a finger and pour the freshly collected mud sample through the screen into a clean funnel until the fluid level reaches the bottom of the screen (1,500 mL).
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2. Immediately remove the finger from the outlet and measure the time required for the mud to fill the receiving cup to the 1-qt mark on the cup. 3. Report the result to the nearest second as Marsh funnel viscosity. Report fluid temperature in degrees Fahrenheit or Centigrade.
B) ROTATIONAL
VISCOMETER
Description Direct-indicating viscometers are rotational types of instruments powered by an electric motor or a hand crank. Drilling fluid is contained in the annular space between two concentric cylinders. The outer cylinder or rotor sleeve is driven at a constant RPM (rotational velocity). The rotation of the rotor sleeve in the fluid produces a torque on the bob or inner cylinder. A torsion spring restrains the movement of the bob, and a dial attached to the bob indicates displacement of the bob. Instrument constants have been adjusted so that plastic viscosity and yield point are obtained by using readings from rotor sleeve speeds of 600 and 300 RPM. Specifications: Direct-indicating viscometer Rotor sleeve Inside diameter 1.450 in. (36.8 mm) Total length 3.425 in. (87 mm) Scribed line 2.30 in. (58.4 mm) above the bottom of sleeve. 1 Two rows of &#;8-in. (3.2-mm) holes spaced 120 degrees (2.09 radians) apart, around rotor sleeve just below scribed line. Bob Diameter 1.358 in. (34.5 mm) Cylinder length 1.496 in. (38 mm) Bob is closed with a flat base and a tapered top.
Testing
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Torsion spring constant 386 dyne-cm/degree deflection Rotor speeds: High speed: 600 RPM Low speed: 300 RPM The following are types of viscometers used to test drilling fluids: 1. Hand-cranked instrument has speeds of 600 and 300 RPM. A knob on the hub of the speed-change lever is used to determine gel strength. 2. The 12-volt, motor driven instrument also has speeds of 600 and 300 RPM. A governor-release switch permits high shearing before measurement, and a knurled hand-wheel is used to determine gel strength. 3. The 115-volt instrument (see Figure 3) is powered by a two-speed synchronous motor to obtain speeds of 600, 300, 200, 100, 6 and 3 RPM. The 3-RPM speed is used to determine gel strength.
Figure 3: V-G meter laboratory model.
4. The variable speed 115- or 240-volt instrument is powered to obtain all speeds between 625 and 1 RPM. The 3-RPM speed is used to determine gel strength.
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1) PROCEDURE
FOR APPARENT VISCOSITY,
2) PROCEDURE
PLASTIC VISCOSITY AND YIELD POINT
FOR GEL
STRENGTH DETERMINATION
DETERMINATION
1. Place recently agitated sample in a thermocup and adjust surface of mud to scribed line on the rotor sleeve. 2. Heat or cool the sample to 120° F (49° C). Stir slowly while adjusting the temperature. 3. Start the motor by placing the switch in the high-speed position with the gear shift all the way down. Wait for a steady indicator dial value, and record the 600 RPM reading. Change gears only when motor is running. 4. Change switch to the 300-RPM speed. Wait for a steady value and record 300-RPM reading. 5. Plastic viscosity in centipoise = 600 reading minus 300 reading (see Figure 4). 6. Yield Point in lb/100 ft2 = 300 reading minus plastic viscosity in centipoise. 7. Apparent viscosity in centipoise = 600 reading divided by 2. θ600 Deflection (dial units)
3
Slope = plastic viscosity θ300
1. Stir sample at 600 RPM for approximately 15 sec and slowly lift the gear assembly to the neutral position. 2. Shut motor off and wait 10 sec. 3. Flip switch to the low-speed position and record maximum deflection units in lb/100 ft2 as initial gel. If the dial indicator does not return to zero with motor off, do not reposition. 4. Repeat 1 and 2, but allow 10 min, then place switch in the low-speed position and read maximum deflection units as the 10-min gel. Report measured temperature. Care of Instrument Clean instrument by running at high speed with rotor sleeve immersed in water or other solvent. Remove rotor sleeve by twisting slightly to release lock pin. Wipe bob and other parts thoroughly with clean, dry cloth or paper towel. CAUTION: The bob is hollow and can be removed for cleaning. Moisture will occasionally collect within the bob and should be dried out with a pipe cleaner. Immersion of the hollow bob in extremely hot mud (>200° F [>93° C]) could result in a very dangerous explosion. NOTE: Never immerse meter in water.
Intercept = yield point
300 Speed (rpm)
600
Figure 4: Typical flow curve for a drilling mud.
Testing
3.6
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Section 3. Filtration Description The filtration or wall-building property of a mud is determined by means of a filter press. The test consists of determining the rate at which fluid is forced through the filter paper. The test is run under specified conditions of time, temperature and pressure. The thickness of the solid filter cake deposited is measured after the test. The filter press being used should meet specifications as designated in the API Recommended Practice and conducted in the manner suggested. The API fluid loss is conducted at surface temperature at 100 psi (6.9 bar) pressure, and is recorded as the number of milliliters lost in 30 min. Instruments This instrument (see Figure 5) consists of a mud cell assembly, pressure regulator and gauge mounted on the top of the carrying case or the top part of the car laboratory unit. The cell is attached to the regulator by means of a coupling adapter by simply inserting the male cell coupling into the female filter press coupling and turning clockwise 1&#;4 turn. Some cells do not have this locking device, and are just inserted into the proper coupling. The cell is closed at the bottom with a lid fitted with a screen (or grid), by placing the lid firmly against the filter paper and turning to the right until hand tight. This forces the sheet of filter paper against the O-ring previously fitted in the base of the cell. Pressure is supplied by a small cartridge of carbon dioxide gas. A bleed-off valve is provided to release the pressure prior to uncoupling the cell. Do not use N2O, nitrous oxide (Whippets).
Testing
3.7
Figure 5: An example of an API filter press.
A) API
FLUID LOSS
Procedure 1. Have air or gas pressure of 100 psi (6.9 bar) available. 2. Remove the lid from the bottom of the clean and dry cell. Place the O-ring in an undamaged groove, then invert to fill. Any mechanical damage could prevent it from sealing. Seal the inlet with a finger. 3. Fill the cell with mud to within 1 &#;4 in. (6.3 mm) of O-ring groove. Place filter paper (Whatman No. 50 or equivalent) on top of O-ring. Place the lid on the filter paper with the flanges of the lid between the flanges of the cell, and turn clockwise until hand tight. Turn the cell over and insert the male cell coupling into the female filter press coupling and turn either direction to engage. 4. Place a suitable graduated cylinder under the filtrate opening to receive the filtrate.
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5. Open the inlet valve applying pressure to the cell. (A rapid fluctuation downward of the needle can be seen as pressure fills the cell.) 6. The normal API test period is 30 min. At the end of the test, close the valve. Pressure will be shut off at the source, and the pressure will bleed off automatically. Remove the cell. 7. Report the fluid loss in milliliters unless otherwise specified. 8. Disassemble the cell, discard the mud and use extreme care to save filter paper with a minimum of disturbance of the cake. Wash the cake gently to remove excess mud. Measure the thickness of the filter cake and report in 1 &#; 32 of an inch.
B) HIGH-TEMPERATURE, HIGH-PRESSURE (HTHP) FILTRATION MB style (API #II) HTHP filter press Description The instrument (see Figures 6 and 7) consists of a heating jacket with thermostat, cell plate assembly, primary pressure assembly and back-pressure receiver. The capacity of the mud cell is 160 mL with a filter area of 3.5 in.2 (22.6 cm2). Filtrate receiver holds 15 mL, and up to 100 psi (6.9 bar) backpressure can use a glass tube. If a higher back pressure is to be used, a stainless-steel tube should replace the glass. A routine test can be conducted at 300° F (149° C) and 500 psi (34.5 bar) differential pressure. High-temperature fluid loss is recorded as double the number of milliliters lost in 30 min. Procedure 11. Plug heating jacket cord into proper power source and allow instrument to preheat. Place thermometer in well in heating jacket and adjust thermostat to obtain 10° F (&#;12° C) above desired test temperature. 12. Close the inlet valve on the cell and invert the cell. Testing
3.8
Figure 6: HTHP filter press (disassembled).
13. Take the mud from the flow line and fill to within 1&#;2 in. (12.7 mm) of the O-ring groove to allow for expansion. 14. Place one circle of filter paper in groove and place the O-ring on top of paper. Use Whatman No. 50 paper or equivalent. 15. Place the cell plate assembly over the filter paper and align the safety locking lugs. 16. Evenly tighten cap screws finger tight and close the discharge valve. 17. With cell plate assembly down, place cell in heating jacket with all valves closed. Transfer the thermometer to the cell&#;s thermometer well. 18. Place CO2 cartridge in primary pressure assembly and tighten cartridge holder until cartridge is punctured. The regulator and bleed-off valve should be closed. 19. While lock ring is lifted, slide primary pressure assembly onto the top &#;slide coupling&#; and release the lock ring. 10. Place 100 psi (6.9 bar) pressure on top valve, then open it to pressurize unit. This pressure will minimize boiling while sample is heating. 11. Always use the back-pressure receiver to prevent vaporization of the filtrate at test temperatures near boiling or higher. Place and Revision No: A-2 / Revision Date: 12·31·06
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activate a CO2 cartridge into the back-pressure receiver assembly. 12. Slide back-pressure assembly into place with slotted lock ring. 13. Apply 100 psi (6.9 bar) pressure to the bottom pressure unit with this valve still closed. 14. After the temperature has reached the desired range (300° F [149° C]), as noted by the cell thermometer, increase pressure on top cell regulator from 100 to 600 psi (6.9 to 41.4 bar) while maintaining 100 psi (6.9 bar) on the bottom regulator. Open bottom cell valve one turn, and start timing test. 15. Maintain 100 psi (6.9 bar) on the receiver during the test. If it rises, drain a little filtrate to maintain the 500 psi (34.5 bar) differential. Maintain temperature ±5° F (&#;15° C). 16. After 30 min filtration, close bottom cell valve and then close top cell valve. 17. Back off both regulator T-screws and bleed pressure from both regulators. 18. Drain filtrate into graduated cylinder and read volume. Double the reading to report. Remove receiver. 19. Disconnect primary pressure assembly by lifting lock ring and slip assembly off. CAUTION: Cell still contains pressure.
Figure 7: HTHP filter press (MB style - API #II). Testing
3.9
20. Maintain cell in upright position and cool to room temperature, then bleed off cell pressure; do not blow mud through valve. 21. Invert cell, loosen cap screws (use Allen-head wrench if necessary) and disassemble. Thoroughly clean and dry all parts.
API #I STYLE HTHP FILTER PRESS (HOLLOW TAPERED-TIP STEM) The standard HTHP fluid loss test is run at a temperature of 300° F (148° C) and a differential pressure of 500 psi (34.5 bar). Description 1. Heating jacket mounted on a stand. 2. A sample cell rated to a working pressure of 1,000 psi (68.9 bar) (filter area of 3.5 in.2 [22.6 cm2]). 3. Thermometer or electronic thermocouple (readings to 500° F [260° C]). 4. Top assembly regulator with the ability to regulate 1,000 psi (68.9 bar) from any pressure source used. 5. Filtrate receiver (100 mL recommended) designed to withstand a working back pressure of at least 500 psi (34.5 bar). 6. Graduated cylinder for filtrate collection. NOTE: Extreme caution should be used in running an HTHP test. Maintain all equipment in a safe working condition. Testing at temperatures of 300° F (149° C) or less 11. Plug heating jacket into correct voltage for the unit. Place thermometer in the thermometer well on the outside of jacket. 12. Preheat jacket to 10° F (&#;12° C) above the test temperature and maintain if needed, by adjusting the thermostat. Check all O-rings and replace as needed. 13. Agitate the mud sample for 10 min and pour into the cell making sure the valve stem on the cell body is closed. The cell should not be filled Revision No: A-2 / Revision Date: 12·31·06
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closer than 1&#;2 in. (12.7 mm) from the top of the lip. 14. Place a piece of filter paper (Whatman No. 50 or equivalent) on top of the lip. 15. Seat lid properly, align and tighten Allen screws. Make sure that both valve stems are closed and then place the cell into the heating jacket. With a twisting motion lock the cell in the jacket. NOTE: The cell body fits in the jacket with the end containing the filter paper on the bottom. 16. Transfer the thermometer to the cell body thermometer well. 17. Place the pressure unit on the top valve and lock into place with a locking pin. 18. Place the bottom low-pressure receiver to the bottom valve and lock into place (see Figure 8). 19. Apply 100 psi (6.9 bar) to both pressure units and open top valve stem 1&#;4 turn counterclockwise. 10. When the test temperature is reached, increase the pressure of the top pressure unit to 600 psi (41.4 bar) and open the bottom valve stem 1 &#;4 turn clockwise to begin filtration. The filtrate is to be collected in a graduated cylinder for a period of 30 min. 11. While testing, the test temperature should be maintained within ±5° F
Aging Temperature °F °C 212 100 250 121 300 149 350 177 400 205 450 232
Water Vapor Pressure kPa psi 101 14.7 207 30 462 67 931 135 1,703 247 2,917 422
Figure 8: HTHP filter press (API #I style) (disassembled).
(&#;15° C). Drain some filtrate when the back pressure exceeds 100 psi (6.9 bar). 12. After 30 min close both valves and back the regulator T-screws off. Bleed the filtrate and pressure from the bottom receiver and then bleed the pressure from the top regulator. Remove top regulator and receiver. Remove the cell from the heating jacket and cool to room temperature in an upright position. CAUTION: Cell still contains pressure. Coefficient of Volume Expansion for Water at Saturation Pressure 1.04 1.06 1.09 1.12 1.16 1.21
Suggested Applied Back Pressure kPa psi 689 100 689 100 689 100 1,104 160 1,898 275 3,105 450
Note: Do not exceed equipment manufacturer&#;s recommendations for maximum temperatures, pressures and volumes.
Table 2: Vapor pressure and volume expansion of water between 212 and 450° F (100 and 232° C) with suggested back pressure.
Testing
3.10
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13. While allowing the cell to cool, measure the amount of collected filtrate and double the results. Record as milliliters of filtrate along with the test temperature. 14. After the cell has cooled, bleed the pressure carefully from the top stem opposite the filter paper. Close the valve and then open the other end carefully to bleed off any pressure. Disassemble after there is no remaining pressure, and discard mud sample. Visually observe and note the condition of the filter cake. It can be measured in 1&#;32 of an inch. Testing at temperatures between 300 to 400° F (149 to 233° C) The same basic procedure is used except the 500-mL cell and nitrogen pressure manifold is suggested:
1. When heating the sample, 450 psi (31 bar) can be placed on both pressure units. When the test begins, the top pressure is raised to 950 psi (66 bar )and the bottom pressure is maintained at 450 psi (31 bar). 2. Temperatures over 350 to 400° F (176.6 to 204.4° C) require the use of porous stainless-steel disc (Dynalloy X5 or equivalent) in place of filter paper (see API RP 13B-1 and 13B-2). 3. Time for heating sample should not exceed 1 hour.
C) FILTER-CAKE
COMPRESSIBILITY
The test is run using the same procedure at 300° F (149° C), but 200 psi (14 bar) is applied to the cell body and 100 psi (6.9 bar) is applied to the bottom receiver. The 100 and 500 psi (6.9 and 34.5 bar) differential values are compared.
Section 4. Sand Content Instruments The sand content of mud is estimated by the use of a sand-screen set. The screen test, because of its simplicity of operation, is widely used in the field.
Figure 9: Sand content set.
SAND
CONTENT SET
Description The sand content set (see Figure 9) consists of a 21&#;2-in. (63.5 mm) diameter sieve, 200 mesh (74 micron), a funnel to fit the sieve and a glass measuring tube marked for the volume of Testing
3.11
mud to be added in order to read the percentage of sand directly in the bottom of the tube, which is graduated from 0 to 20%. Procedure 1. Fill the glass measuring tube to the indicated mark with mud. Add water to the next mark. Cover the mouth of the tube with the thumb and shake vigorously. 2. Pour the mixture onto the screen, add more water to the tube, shake and again pour onto the screen. Repeat until the wash water is clear. Wash the sand clean that is retained on the screen. 3. Fit the funnel down over the top of the sieve. Insert the tip of the funnel into the mouth of the glass tube. Wash the sand from the screen into the tube by means of a fine spray of water. Allow the sand to settle. From the graduations on the tube, read the percent by volume of sand. Revision No: A-2 / Revision Date: 12·31·06
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Section 5. Liquid and Solid Content Instruments A mud retort with &#;oven&#; heating capability is used to determine the quantity of liquids and solids in a drilling fluid. Internal-probe heater retorts are not recommended. A sample of mud (either 10-, 20- or 50-mL retorts are available) is placed in the cup and the lid added to expel some fluid. This ensures a correct volume. It is heated until the liquid components have been vaporized. The vapors are passed through a condenser and collected in a graduated cylinder that usually is graduated in percent. The volume of liquid, oil and water, is measured directly in percent. The solids, both suspended and dissolved, are determined by subtracting from 100% or by reading the void space at the top. Description
A) PROCEDURE:
RETORT
1. Allow the mud sample to cool to room temperature. 2. Disassemble retort assembly and lubricate sample cup threads with high-temperature grease (NeverSeez). Fill sample cup almost level full of the fluid to be tested. Put sample cup cover in place by rotating firmly, squeezing out excess fluid to obtain the exact volume &#; 10, 20 or 50 mL required. Clean spills from cover and threads. 3. Pack fine steel wool into the upper expansion chamber, then screw sample cup into expansion chamber. The steel wool should trap the solids boiled out. Keep assembly upright so that mud does not flow into the drain tube. 4. Insert or screw the drain tube into hole at end of condenser, seating firmly. The graduated cylinder which is calibrated to read in percent should be clipped in place on the condenser. Testing
3.12
Figure 10: Retort.
5. Plug power cord into the correct voltage and keep power on until distillation stops, which may require 25 min depending on the characteristics of oil, water and solids content. 6. Allow the distillate to cool to room temperature. 7. Read the percentage of water, oil and solids directly from the graduate. A drop or two of aerosol solution will help define the oil-water interface, after reading the percent solids. 8. At end of the test, cool completely, then clean and dry retort assembly. 9. Run a pipe cleaner through condenser hole and retort drain tube to clean and maintain full openings. NOTE: Do not allow drain tube to become restricted. Percent by volume solids analysis, weight method (calculation by weight difference using conventional retort) 1. Equipment needed: Mud balance. Conventional 20 cm3 (oven-type) retort. Analytical balance accurate to 0.01 g.
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2. Four measurements are taken: A. Mud weight. B. Weight of retort (including steel wool and cup). C. Weight of retort with whole mud. D. Weight of retort with mud solids. Procedure 1. Ready the retort with steel wool and sample cup. Determine the weight in grams. This is value B.
2. Disassemble retort and add mud to fill sample cup. Measurement of volume or use of lid is unnecessary as volumes are calculated in this weigh-in/out procedure. Weigh the reassembled retort. This is value C. 3. Run retort as usual collecting distillate (water and any oil). 4. Allow the retort to cool and reweigh the assembly. This is value D.
Calculation Calculate: 1. Mud density (g/cm3); SGMUD = mud wt (lb/gal) x 0.. 2. Grams of mud in retort: g of mud = Value C &#; Value B. 3. Grams or cm3 water distilled: Value C &#; Value D. Compute volume % solids: (C &#; B) &#; SGMUD x (C &#; D) Fraction of solids = C&#;B % solids = 100 x volume fraction solids Example: Four measurements from a field mud: A) 12.70 lb/gal B) 317.45 g C) 348.31 g D) 332.69 g Thus: #1 = 12.70 lb/gal
[0.
g/cm3 lb/gal
] = 1.523 g/cm
3
#2 = 348.31 &#; 317.45 = 30.86 g of mud #3 = 348.31 &#; 332.69 = 15.62 g of water 30.86 &#; 1.52 x 15.62 Volume fraction solids = 30.86 7.12 Fraction of soli = 30.86 Fraction of solid
= 0.
% solids = 100 x 0. = 23.07%
Testing
3.13
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B) METHYLENE
BLUE CAPACITY
Field procedure for determining cation exchange capacity Equipment 1. Syringe, 3 mL, burette 10 mL. 2. Micropipette, 0.5-mL. 3. Erlenmeyer flask, 250-mL with rubber stopper. 4. Burette or pipette, 10-mL. 5. Graduated cylinder, 50-mL. 6. Stirring rod. 7. Hot plate. 8. Filter paper: 11 cm diameter, Whatman No. 1 or equivalent. Reagents 1. Methylene blue solution: 1 mL = 0.01 milliequivalents 3.74 g USP-grade methylene blue (C16H18N3SCl&#;3H2O) per liter. 2. Hydrogen peroxide, 3% solution. 3. 5 N sulfuric acid solution. Procedure 1. Add 2 mL of mud (or suitable volume of mud to require 2 to 10 mL of reagent) to 10 mL of water in the Erlenmeyer flask. Add 15 mL of 3% hydrogen peroxide and 0.5 mL of 5 N sulfuric acid solution and mix by swirling before heating. Boil gently for 10 min. Dilute to about 50 mL with water. NOTE: Drilling muds frequently contain substances in addition to bentonite that absorb methylene blue. Treatment with hydrogen peroxide is intended to remove the effect of organic materials such as CMC, polyacrylates, lignosulfonates and lignites. 2. Add methylene blue solution, 0.5 mL at a time, from the burette or pipette to the flask. After each addition, insert rubber stopper and shake contents of the flask for about 30 sec. While the solids are still suspended, remove a drop from
Testing
3.14
the flask with a glass rod and place on filter paper. The endpoint of the titration is reached when the dye appears as a greenish-blue ring surrounding the dyed solids. 3. When the greenish-blue tint spreading from the spot is detected, shake the flask an additional 2 min and place another drop on the filter paper. If the greenish-blue ring is again evident, the endpoint has been reached. If the ring does not appear, continue as before until a drop taken after shaking 2 min shows the greenish-blue tint. 4. Record the mL of methylene blue solution used. 5. Methylene blue capacity of mud English system MBC (lb/bbl) = (cm3 of methylene blue/cm3 of mud) x 5 Metric system MBC (kg/m3) = (cm3 of methylene blue/cm3 of mud) x 14.25
C) METHYLENE
BLUE CAPACITY
OF SHALE
Methylene blue capacity (bentonite equiv.) English system MBC (lb/bbl) = CEC x 5 Metric system MBC (kg/m3) = CEC x 14.25 Cation exchange capacity for shales Approximately 1 g of dried ground shale is accurately weighed and placed in a 150-mL Erlenmeyer flask and 50 mL of deionized water is added. The shale slurry is gently boiled with 0.5 mL 5 N sulfuric acid for 10 min. The slurry is allowed to cool and is titrated in 0.5 mL increments with 0.01 N methylene blue solution. CEC in milliequivalents/100 g shale = mL of methylene blue g of shale titrated
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D) FLOCCULENT
EFFICIENCY TEST
Procedure 1. Measure 100 mL of drill water directly from rig flow line into a graduated cylinder. 2. Add 1 mL of 1%&#; flocculent solution to the graduated cylinder. 3. Invert the graduated cylinder slowly 3 to 4 times and set it on a flat surface. 4. Record the time (in sec) required to form the flocs and settle to the 40 cm3 line on the graduated cylinder. 5. Repeat the procedure with each flocculent. If no flocs form, then a
flocculent would not be required at that time. Repeat this test daily or every other day. 6. The flocculent with the fastest time is the correct one to use. NOTE: To determine if flocculent is needed in clear water drilling, collect a sample of water where it returns to the suction pit and run a floc test. &#; 1% flocculent solutions are made by adding 1 g of the correct flocculent to 100 mL of distilled water and stirring until dissolved.
Section 6. Hydrogen Ion Concentration (pH) Purpose Field measurement of drilling fluid (or filtrate) pH and adjustments to the pH are fundamental to drilling fluid control. Clay interactions, solubility of various components and effectiveness of additives are all dependent on pH, as in control of acidic and sulfide corrosion processes. Two methods are used for measuring the pH of freshwater drilling mud: a modified colorimetric method, using plastic backed test strips (sticks); and the potentiometric method, employing the glass-electrode electronic pH meter. The plastic strip method is frequently used for field pH measurements, but is not the preferred method. It is reliable only in very simple water muds. Mud solids, dissolved salts and chemicals, and dark-colored fluids cause errors in pH plastic strip values.
A) INDICATOR
STICKS
Description The &#;colorpHast pH indicator&#; sticks (see Figure 11) are coated with indicators of such nature that the color is
Testing
dependent on the pH of the fluid in which the stick is placed. Standard color charts are supplied for comparison with the test stick, allowing estimation of pH to 0.5 pH units over the entire pH range. Procedure 1. Place an indicator stick in the mud and allow it to remain until the color has stabilized, usually less than a minute. Rinse the stick off with deionized water but do not wipe. 2. Compare the colors of the stick with the color standard provided and estimate the pH of the mud. 3. Report the pH of the mud to the nearest 0.5 pH units.
3.15
Figure 11: pH indicator sticks.
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B) PH
METER
Description The recommended method for pH measurement of drilling fluid is with the glass-electrode electronic pH meter similar to the Orion model No. 201. This meter is accurate and gives reliable pH values, being essentially free of interferences. Measurements can be made quickly and easily, automatically adjusting slope and temperature compensation. Equipment 1. pH meter (e.g. Orion 201). 2. Glass pH electrode. 3. Buffer solutions (4, 7 and 10 pH). 4. Accessory equipment: a. Soft-bristle brush. b. Mild liquid detergent. c. NaOH, 0.1 M, to recondition electrode. d. HCl, 0.1 M, to recondition electrode. e. Distilled or deionized water. f. Soft tissues to blot electrodes. g. Glass thermometer, 32 to 212° F (0 to 100° C). Procedure 11. Obtain sample of fluid to be tested and allow it to reach 75±5° F (24±3° C). 12. Allow buffer solutions to also reach the same temperature as the fluid to be tested. For accurate pH measurement of the test fluid, buffer solution and reference electrode must all be at the same temperature. The pH of the buffer solution indicated on the container label is only at 75° F (24° C). If attempting to calibrate at another temperature, the actual pH of the buffer at this temperature must be used. Tables of the buffer pH values at various temperatures are available from the supplier and should be used in the calibration procedure.
Testing
3.16
13. Clean electrodes-wash with distilled water and blot dry. 14. Place probe into pH 7.0 buffer solution. 15. Turn on meter, wait 60 sec for reading to stabilize. If meter reading does not stabilize, see cleaning procedures. 16. Measure temperature of pH 7.0 buffer solution. 17. Set this temperature on &#;temperature&#; knob. 18. Set meter reading to &#;7.0&#; using &#;calibration&#; knob. 19. Rinse and blot probe dry. 10. Repeat operations in Steps 6 through 9 using pH 4.0 or 10.0 buffer. Use pH 4.0 for low pH sample or pH 10.0 for alkaline sample. Set meter to &#;4.0&#; or &#;10.0&#; respectively, using the &#;temperature&#; knob. 11. Check the meter with pH 7.0 buffer again. If it has changed, reset to &#;7.0&#; with &#;calibration&#; knob. Repeat Steps 6 through 11. If meter does not calibrate properly, recondition or replace electrodes as given in cleaning procedures. 12. If meter calibrates properly, rinse and blot dry the electrodes. Place in sample to be tested. Allow about 60 sec for reading to stabilize. 13. Record measured pH along with the temperature of sample tested. Indicate whether mud or filtrate was tested. 14. Carefully clean the electrodes in preparation for next usage. Place in storage bottle with electrode through the cap. Use pH buffer 7.0 to store the electrode. Deionized water is usually not desired to store the electrode. If it is not used for a prolonged time remove any batteries. 15. Turn meter off and close cover to protect instrument.
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Figure 12: Orion or suitable pH meter.
Cleaning procedures 1. Cleaning the electrodes will be necessary periodically, especially if oil or clay particles coat the face of the glass electrode or the porous face of the reference electrode. Clean the electrodes with the soft-bristle brush and mild detergent. 2. Reconditioning electrodes may be necessary if plugging becomes severe,
as indicated by slow response, drifting of readings, or if &#;slope&#; and &#;calibration&#; cannot be mutually set. 3. Recondition by soaking electrodes for 10 min in 0.1 molar HCl followed by rinsing in water and soaking for 10 min in 0.1 molar NaOH and rinsing again. 4. Check electrodes for response by performing calibration steps. 5. Only qualified individuals should attempt this next step. If no response, soak electrode for a maximum of 2 min in 10% NH4F&#;HF solution (CAUTION: This is a strong and toxic acid). Repeat calibration steps. 6. Replace electrode system if above steps fail to recondition it.
Section 7. Chemical Analysis of Water-Base Drilling Fluids A) ALKALINITY (Pf, Mf, Pm LIME CONTENT)
AND
Equipment The following materials are required to determine the alkalinity and lime content of drilling fluids: 1. Standardized acid solution, 0.02 N (N/50); sulfuric or nitric acid (NOTE: Standardized 0.1N (N/10) acid solution may also be used, but it is converted to the equivalent mL 0.02 N by multiplying by 5). 2. Phenolphthalein indicator solution. 3. Methyl orange/brom cresol green indicator solution. API recommends methyl orange (yellow to pink). 4. Titration vessel, 100 to 150 mL, preferably white. 5. Graduated pipettes: one 1-mL and one 10-mL. 6. Stirring rod. 7. One 1-mL syringe. 8. Glass-electrode pH meter (suggested). Testing
3.17
1) PROCEDURE FOR (Pf AND Mf)
FILTRATE ALKALINITY
1. Measure 1-mL filtrate into the titration vessel, and add 5 mL deionized water. 2. Add 2 or more drops of phenolphthalein indicator. If the solution turns pink. 3. Add 0.02 N acid drop by drop from the pipette with stirring, until the pink color just disappears. If the sample is so colored that the color change of the indicator is masked, the endpoint is taken when the pH drops to 8.3, as measured with the glass electrode pH meter. (The sample can be diluted with distilled water.) 4. Report the phenolphthalein alkalinity of the filtrate, Pf, as the number of mL of 0.02 N acid required per mL of filtrate to reach the end point.
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5. To the same sample used for measuring Pf, add 3 to 4 drops of methyl orange/brom cresol green indicator; a green color will develop. 6. Titrate with 0.02 N acid until the color changes to yellow. This will occur at pH of 4.3. 7. The Mf is reported as the total mL of acid used for Pf plus this last titration. Example: If 0.5 mL acid was used to titrate the phenolphthalein endpoint, the Pf is 0.5. If an additional 0.3 mL acid was used to titrate to the methyl orange endpoint, the Mf is 0.8. BaCl2 procedure: 1. Measure 1 mL of filtrate into a titration vessel. 2. Add 2 drops of 10% barium chloride solution (NOTE: BaCl2 is poisonous; do not pipette with mouth). 3. Repeat Steps 2 through 4 for the Pf titration. 4. As a rule of thumb, if the BaCl2 PAlkalinity is one-half or less than the previous Pf titration, carbonate contamination exists. Example: If 1 mL acid was used to titrate to the endpoint for Pf, the Pf is 1.0. If 0.4 mL acid was used to titrate to the PAlkalinity endpoint with BaCl2, the BaCl2 value is 0.5. Thus, carbonate contamination exists because the BaCl2 is less than one-half the Pf. 2) PROCEDURE
FOR MUD ALKALINITY
(Pm)
Measure 1 mL of mud into the titration vessel using the syringe. Dilute the mud sample with 25 mL of distilled water. Add 5 drops of phenolphthalein indicator and, while stirring, titrate quickly with 0.02 N acid or 0.1 N acid until the pink color disappears. If the sample is so colored that the color change of the indicator is masked, the end point is taken when the pH
Testing
3.18
drops to 8.3 as measured with the glass electrode. Report the phenolphthalein alkalinity of the mud, Pm, as the number of mL of 0.02 N (N/50) acid required per mL of mud. If 0.1 N acid is used, Pm = 5 x mL of 0.1 N acid per mL mud. 3) PROCEDURE
FOR LIME CONTENT
Determine the Pf and Pm, as described in the preceding paragraphs. Determine the volume fraction of water in the mud, Fw (decimal fraction of water), using the value from the retort test. Report the lime content of the mud in lb/bbl calculated from the following equation: Lime (lb/bbl) = 0.26 x (Pm - FwPf). 4) FILTRATE
ALKALINITY:
P1
AND
P2
Equipment 11. Standard sulfuric acid solution, 0.02 N (N/50). 12. Sodium hydroxide solution, 0.1 N (N/10). 13. Barium chloride solution, 10%. 14. Phenolphthalein Indicator. 15. Deionized water. 16. pH strips or glass electrode pH meter. 17. Titration vessel, 100 to 150 mL, preferably white. 18. Pipette: one 1-mL, one 2-mL and one 10-mL. 19. Graduated cylinders: one 25-mL and one 5- or 10-mL. 10. Stirring rod. Procedure: P1 - P2 1. Measure 1 mL of filtrate into the titration vessel and add 24 mL of deionized water. 2. Add 2 mL of 0.1 N sodium hydroxide and stir well. Measure the pH with the pH strip or pH meter. If the pH is 11.4 or greater, proceed to the next step. If the pH is less than 11.4, add another 2 mL of 0.1 N sodium hydroxide.
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3. Using the graduated cylinder, measure 2 mL of barium chloride and add to the titration vessel. Add 2 to 4 drops of phenolphthalein with stirring. NOTE: Do not use your mouth to pipette; the barium chloride solution is poisonous. 4. Immediately titrate the mixture with standard sulfuric acid to the first disappearance of the pink color (or to pH 8.3 with the pH meter). The color may reappear after a short time; do not continue the titration. 5. Report the alkalinity, P1, as the mL of 0.02 N sulfuric acid required to titrate to the phenolphthalein endpoint. Procedure: P2 (blank) 1. Omit the filtrate, but otherwise repeat the procedure for P1, using exactly the same quantities of water and reagents. Titrate using the same procedures as for P1. 2. Report the alkalinity, P2, as the mL of 0.02 N sulfuric acid required to titrate to the phenolphthalein end point. Calculations Within limitations, the various ionic alkalinities can be calculated as follows: When P1 > P2 OH&#; (mg/L) = 340 x (P1 &#; P2) CO32&#; (mg/L) = 1,200 x [Pf &#; (P1 &#; P2)] When P1 < P2 HCO3&#; (mg/L) = 1,220 x (P2 &#; P1) CO32&#; (mg/L) = 1,200 x Pf
B) GARRETT GAS TRAIN (GGT)
TEST
FOR CARBONATES
Purpose This procedure uses the Garrett Gas Train, analyzing the soluble carbonates on a filtrate sample of water-base drilling fluid. The CO2 Dräger tube responds to the CO2 gas passing through it by turning purple. The stain length is primarily sensitive to the amount of
Testing
3.19
CO2 present, but it is also sensitive to the flow rate and the total gas volume passed through the tube. Therefore, for more accurate results, the gas exiting the gas train must first be captured in a 1-L bag to allow the CO2 to mix uniformly with the carrier gas. The CO2 Dräger tubes are very sensitive to incorrect use. The filtrate must be free of solids. Therefore, the first spurt of the filtrate should be discarded, because it may contain CaCO3 particles that can cause errors on the high side. The contents of the bag are passed from the bag through the Dräger tube using 10 strokes of the Dräger hand pump. This technique will draw exactly 1 L of gas through the tube. Equipment 11. Deionized water. 12. Octyl alcohol defoamer. 13. Sulfuric acid, approximately 5 N, reagent grade. 14. Garrett Gas Train apparatus. 15. Dräger CO2 analysis tube, &#;CO2 100/a&#; labeled 100 to 3,000 ppm. Factor = 2.5 (be sure to check to see if the factor has changed). 16. Dräger 1-L bag, #. 17. Dräger &#;Multigas Detector&#; hand vacuum pump. 18. Glass stopcock, 8 mm, 2-way bore. 19. Hypodermic syringes: one 10-mL with 21 gauge needle (for acid), one 10-mL, one 5-mL and one 2.5-mL. 10. N2O gas cartridges (e.g. Whippets). Bottled nitrogen or helium gas can also be used. Do not use Whippets in any other test. Procedure 11. Be sure the gas train is clean, dry and on a level surface. 12. With the regulator backed off, install and puncture a N2O cartridge. Do not use compressed air or a CO2 cartridge. 13. Add 20 mL deionized water to Chamber 1.
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Figure 13: Garrett Gas Train.
14. Add 5 drops of defoamer to Chamber 1. 15. Install the top on the gas train and hand-tighten evenly to seal all O-rings. 16. Attach the flexible tubing from the regulator onto the dispersion tube of Chamber 1. 17. Inject with syringe an accurately measured sample of filtrate into Chamber 1, (see Figure 13). Flow carrier gas through train for 1 min to purge air from system. Stop gas flow. 18. Install one end of a piece of flexible tubing into the stopcock which is fitted directly into the gas bag. Have the gas bag fully collapsed. Fit the other end of the tubing onto the outlet tube of Chamber 3. 19. Slowly inject 10 mL sulfuric acid into Chamber 1 through the rubber septum using the hypodermic syringe and needle. Gently shake the gas train to mix acid with sample in Chamber 1. 10. Open the stopcock on the gas bag. Restart N2O flow gently and allow gas bag to fill. When bag is full do not burst it, shut off N2O flow and close the stopcock. Immediately proceed to Step 11. 11. Remove the tubing from Chamber 3 outlet and re-install it onto the upstream end of the CO2 Dräger tube after breaking off the ends of the Dräger tube (observe that the arrow indicates gas flow direction). Testing
3.20
Attach Dräger hand pump to other end of Dräger tube. 12. Open stopcock on bag. With hand pressure, fully depress the hand pump, then release so that gas flows out of the bag and through the Dräger tube. Operate the hand pump 10 strokes, which should essentially empty the gas bag. 13. Observing a purple stain on the Dräger tube means CO2 was present in the gas bag. Record the stain length in units marked on the Dräger tube. 1) DRÄGER 1 Carbonate Range (mg/L) 25 - 750 50 - 1,500 100 - 3,000 250 - 7,500
TUBE IDENTIFICATION
2 Sample Volume (mL) 10 5 2.5 1
3 Dräger Tube Identification CO2 100/a CO2 100/a CO2 100/a CO2 100/a
4 Tube Factor 2.5 &#; 2.5 &#; 2.5 &#; 2.5 &#;
&#;
NOTE: Tube factor &#;2.5&#; applies to new tubes, CO2 100/a (cat. no. ) with scale 100 to 3,000. Old tubes use tube factor 25,000 with scale 0.01 to 0.3%.
Table 3: Sample volumes and tube factor to be used for various carbonate ranges.
Calculations Using the measured sample volume, the Dräger tube&#;s purple stain length and tube factor or 2.5 (see Table 3), calculate the soluble carbonates in the filtrate sample using the following equation: tube stain length x 2.5 CO2 (mg/L) = mL of sample filtrate NOTE: The gas train apparatus MUST be cleaned after each use or the acid used will cause severe damage to the equipment. To clean the gas train, remove the flexible tubing and remove the top. Wash out the chambers with warm water and mild detergent, using a brush. Use a pipe cleaner to clean the passages between chambers. Wash, rinse and then blow out the dispersion tubes with air or N2O gas. Rinse the unit with deionized water and allow to drain dry. Do not use the Nitrous oxide for any other test, or as a gas source. Revision No: A-3 / Revision Date: 02·01·09
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Testing
It can cause an explosion if misused in other applications. (NEVER use them as a gas source for High-Temperature, HighPressure (HTHP) cell or filtration &#; only GGT for carbonates.) &#;
C) CHLORIDE (Cl ) Purpose The salt, or chloride, test is very significant in areas where salt can contaminate the drilling fluid. This would include the majority of the world&#;s oilfields. The salt may come from makeup water, sacks, stringers, beds or saltwater flows. Equipment The following materials are required to determine the chloride ion concentration in the mud filtrate. 1. Silver nitrate solution, 0.N or 0.282N (strong) AgNO3, stored in an amber or opaque bottle. 2. Potassium chromate indicator solution. 3. Acid solution 0.02 N sulfuric or nitric acid. 4. Distilled water. 5. Two graduated pipettes: one 1-mL and one 10-mL. 6. Titration vessel, 100 to 150 mL, preferably white. 7. Stirring rod. Procedure 1. Measure 1 or 2 mL of filtrate into a titration vessel. 2. Add the amount of acid required in the Pf titration. 3. Add 25 mL of distilled water and 10 drops of potassium chromate solution. Stir continuously and titrate with standard silver nitrate solution drop by drop from the pipette, until the color changes from yellow to orange-red and persists for 30 sec. 4. Record the number of mL of silver nitrate required to reach the endpoint. (If over 10 mL of 0.282N silver
Testing
3.21
300 200 150 100 Salt (mg/L x 1,000)
3
50 40 30 20 10 5 4 3 2 1 .1
.2 .3.4.5
1 2 3 4 5 10 15 20 30 Salt (% by weight)
Figure 14: Salt milligrams per liter vs. salt percent by weight.
nitrate solution are used, consider repeating the test with a smaller, accurately measured sample of filtrate or use a dilution with factor.) Calculations If the chloride ion concentration of the filtrate is less than 10,000 mg/L, use the 0. N silver nitrate solution equivalent to 0.001 g Cl&#; ion per mL. Report the chloride ion concentration of the filtrate in milligrams per liter, calculated as follows: Cl&#; (mg/L) = mL of 0. N silver nitrate x 1,000 mL of filtrate If the chloride ion concentration of the filtrate is greater than 10,000 mg/L, use the 0.282 N silver nitrate (equivalent to 0.01 g Cl&#; ion per mL). Report the chloride concentration of the filtrate in mg/L, calculated as follows: Cl&#; (mg/L) = mL of 0.282 N silver nitrate x 10,000 mL of filtrate For any normality silver nitrate: N x 35,000 x mL used Cl&#; (mg/L) = mL of filtrate sample
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D) CALCIUM -
E) TOTAL
QUALITATIVE
Purpose Water containing a large amount of dissolved calcium and magnesium salts is referred to as &#;hard water.&#; The common evidence of hardness in water at home is the difficulty of producing a lather with soap. In many oil fields, the water available for use is quite hard. Drilling clays have low yields when mixed in hard water. The harder the water, the more bentonite it takes to make a satisfactory gel mud. In extreme cases it has been found economical to treat the water chemically before using it for mixing mud, but it is not generally economical to do this. Frequently, however, where there is a choice of two or more sources of water for the rig, it may be desirable to make a simple test to select the softer of the two. Field engineers are familiar with the effects on the mud when anhydrite (calcium sulfate) or gyp formations are drilled. Calcium may be picked up in drilling cement plugs and sometimes in penetrating sections of limey shale. Any extensive calcium contamination can result in high water loss and high gels. The detrimental effect of cement on increased Pm is due to the high alkalinity (lime) content. Equipment The following materials are required to qualitatively determine the presence of calcium and/or magnesium. 1. Test tube. 2. Dropper bottle of saturated solution of ammonium oxalate. Procedure Place 1 to 3 mL of filtrate in test tube. Add a few drops of saturated ammonium oxalate. The formation of a white precipitate indicates the presence of calcium. Record as light, medium or heavy.
Testing
3.22
HARDNESS
1) CALCIUM
AND MAGNESIUM TOGETHER
QUANTITATIVE
Equipment 11. EDTA (Standard Versenate) solution 0.01 M (1 mL = 400 mg Ca2+ or 1,000 mg CaCO3). 12. Strong buffer solution (ammonium hydroxide/ammonium chloride). 13. Calmagite Indicator solution. 14. Titration dish, 100 to 150 mL, preferably white. 15. Three graduated pipettes: one 1-mL, one 5-mL and one 10-mL. 16. Graduated cylinder, 50 mL. 17. Distilled water. 18. Stirring rod. 19. 8N NaOH or KOH solution. 10. Calcon Indicator or Calver II. 11. Porcelain spoon/spatula. 12. Masking Agent: 1:1:2 mixture volume triethanolamine: tetraethylenepentamine: water (API). Determining the total hardness of water or mud filtrate can be done by performing Part A as shown. This test is performed to obtain the ppm total hardness reported as calcium for the mud report form. It may be required to determine the concentration of magnesium as well as calcium. In this case, use the procedure described in 2) CALCIUM AND MAGNESIUM SEPARATELY. This measures calcium specifically, rather than reporting the Mg2+ as Ca2+. After the calcium is known, the magnesium concentration is calculated from the difference in the two titrations. Caustic soda (called &#;calcium buffer solution&#; here) precipitates the magnesium as the hydroxide, and the calcium is titrated with an indicator that is specific for calcium. Procedure (total hardness as Ca2+) 1. Add approximately 20 mL of distilled water to titration vessel. 2. Add 1 mL of the water or filtrate to be tested. Revision No: A-2 / Revision Date: 12·31·06
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3. Add 1 mL of strong buffer solution (NH4OH base). 4. Add about 6 drops of Calmagite and mix with a stirring rod. A wine red color will develop if calcium and/or magnesium is present. 5. Using a pipette, titrate with Standard Versenate Solution, stirring continuously, until the sample first turns to blue with no undertint of red remaining. Record the number of mL of Standard Versenate solution used. (If magnesium is to be measured as in Procedure 2, record this value as &#;A&#; mL.) Calculations Total hardness as Ca2+ (mg/L) = mL of Standard Versenate x 400 mL of sample CaCO3 (mg/L) = mL of Standard Versenate x 1,000 mL of sample Occasionally in dark-colored filtrate, it is difficult to see the endpoint to determine total hardness. The following method can be used to better observe the endpoint. Calculations remain the same. 1. Add approximately 20 mL of distilled water to titration vessel. 2. Add 1 mL filtrate to titration dish (0.5 mL accurately measured can be used if the endpoint cannot be seen with a 1 mL sample). 3. Add 1 mL Masking Agent. 4. Add 1 mL of strong buffer solution. 5. Add 6 drops Calmagite Indicator and stir. 6. Using a pipette, titrate with Standard Versenate solution until the color changes to blue/green. Record the number of mL used and calculate the same as before. Calculations Total hardness as CaCO3 (mg/L) = mL of Standard Versenate x 1,000 mL of sample
Testing
3.23
2) CALCIUM
AND MAGNESIUM SEPARATELY
1. Add approximately 20 mL of distilled water to the titration vessel. 2. Add the same amount of water or filtrate to be tested as performed in the previous hardness test. 3. Add 1 mL Masking Agent. 4. Add 1 mL of 8N NaOH or KOH and 1&#;4 porcelain spoonful (0.2 g) of Calcon Indicator and mix with a stirring rod. 5. Titrate with Standard Versenate solution until the indicator turns from wine red to blue with no undertint of red remaining. Record the number of mL of Standard Versenate required (record this value as &#;B&#; mL). Calculations B x 400 Calcium (mg/L) = mL of sample Magnesium (mg/L) =
F) HARDNESS 1) TOTAL
(A &#; B) x 243 mL of sample
IN DARK FILTRATES
HARDNESS IN DARK FILTRATES
QUANTITATIVE
Purpose Occasionally there is difficulty in accurately titrating for hardness concentration in dark-colored filtrates due to the subtle change in color of the filtrate when the endpoint is reached. Thus, the following method has been developed and is recommended only when the previous hardness test procedure becomes difficult or impossible. Equipment 11. Acetic acid: glacial (caution). 12. Calcon or Calver II Indicator (specific for Ca2+). 13. Sodium hypochlorite 5.25% (Clorox^). 14. Calmagite Indicator. 15. Sodium hydroxide; 8N NaOH. 16. Masking Agent. 17. Standard Versenate solution 0.01 Molar. 18. Strong buffer solution.
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19. Beaker, 100-mL. 10. Graduated cylinders, two 10-mL. 12. Graduated pipette, 10-mL. 13. Hot plate. 14. Volumetric pipette, 1-mL. 15. Porcelain spoon/spatula for solid indicator addition. Method I (includes all metals which are titrated by Versenate solution) CAUTION: Work in well-ventilated area. Do not breathe fumes. 1. Using a 1-mL volumetric pipette, transfer 1 mL of filtrate to a 100-mL beaker. 2. Add 10 mL Clorox (be sure it is fresh as it will deteriorate with time). Swirl to mix. 3. Add 1 mL of acetic acid and swirl to mix. 4. Heat to boiling on high heat and boil for 5 min. Maintain volume by adding deionized water. 5. Remove the beaker from the hot plate and let it cool to room temperature. Wash down sides of the beaker with deionized water. 6. Add 1 mL strong buffer solution and swirl to mix. 7. Add 6 drops of Calmagite and mix. A wine red color will develop if hardness is present. 8. Using a pipette, titrate with Standard Versenate solution, stirring continuously, until the sample turns to blue with no undertint of red remaining. The color change will be purple to slate gray with dark filtrates. Record the number of mL Standard Versenate solution used. Calculations Total hardness as Ca2+ (mg/L) = mL Standard Versenate x 400 Method II (includes calcium and magnesium reported as Ca2+) 1. Using a 1-mL volumetric pipette, transfer 1 mL of filtrate to a 100-mL Pyrex^ beaker. 2. Add 10 mL Clorox (be sure Clorox is fresh). Swirl to mix. Testing
3.24
3. Add 1 mL of acetic acid and mix. 4. Heat to boiling and boil for 5 min. Maintain volume by adding deionized water. 5. Remove the beaker from the hot plate and let it cool to room temperature. Wash down the sides of the beaker with deionized water. 6. Add 1 mL of strong buffer solution and swirl to mix. 7. Add 1 mL of Masking Agent and mix. 8. Add 6 drops of Calmagite and mix. A wine red color will develop if calcium and/or magnesium is present. 9. Using a pipette, titrate with Standard Versenate, stirring continuously, until the sample turns blue with no undertint of red remaining. Record the number of mL of Standard Versenate used. This is Value A. Calculations Total hardness as Ca2+ (mg/L) = A x 400 2) CALCIUM
AND MAGNESIUM SEPARATELY
1. Using a 1-mL volumetric pipette, transfer 1 mL of filtrate to a 100-mL Pyrex beaker. 2. Add 10 mL Clorox and swirl to mix. 3. Add 1 mL acetic acid and mix. 4. Heat to boiling and boil for 5 min. Maintain volume by adding deionized water. 5. Remove the beaker from the hot plate and let it cool to room temperature. Wash down the side of the beaker with deionized water. 6. Add 1 mL calcium buffer (sodium hydroxide) and mix (precipitates Mg2+). 7. Add 1 mL Masking Agent and mix. 8. Add 1&#;4 spoonful (0.2 g) of Calcon Indicator and mix. A wine red color will develop if calcium is present. 9. Titrate with Standard Versenate until the indicator turns from wine red to blue with no under tint of red remaining. Record the number of mL Standard Versenate required. This is Value B. Revision No: A-2 / Revision Date: 12·31·06
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Calculations Calcium (mg/L) = B x 400 Magnesium (mg/L) = (A - B) x 243
G) SULFATE 1) QUALITATIVE
Purpose The sulfate ion is present in many natural waters due to the solvent action of water on the minerals in the earth. Anhydrite (calcium sulfate) is a slightly soluble contaminant encountered in drilling in certain areas. Frequently it is desirable to know the sulfate ion content in the filtrate. Sulfate ion concentrations around 2,000 mg/L could contribute to high viscosity and fluid-loss control problems. Equipment The following materials are required to qualitatively determine the presence of sulfate: 1. Test tube. 2. Dropper bottle of 10% barium chloride solution. (POISON. Do not pipette by mouth.) 3. Dropper bottle of strong nitric acid. Procedure Place about 3 mL of filtrate in a test tube. Add a few drops of barium chloride solution. The formation of a white precipitate indicates the presence of sulfates and/or carbonates. Add a few drops of concentrated nitric acid. If the precipitate dissolves, it is carbonate; if not, it is sulfate. Record the amount of precipitate remaining after the acid treatment as light, medium or heavy. 2) AVAILABLE (UNREACTED)
CALCIUM SULFATE
Purpose When running gyp muds it is necessary to know how much available gyp (calcium sulfate) is available in the system. Equipment 11. Masking Agent: 1:1:2 mixture by volume of triethanolamine: tetraethylenepentamine: water. 12. Deionized water. Testing
3.25
13. Calmagite Indicator. 14. Standard Versenate solution 0.01 Molar. 15. Strong buffer solution. 16. Beaker, 400-mL. 17. Calibrated beaker at 250 mL volume mark. 18. Hot plate. 19. Pipettes: 1-mL, 2-mL and 10-mL. 5-mL syringe. 10. Titration vessel, 100- to 150-mL, preferably white. 11. Mud still (retort). Procedure 11. Add 5 mL of mud to calibrated beaker, then add 245 mL water to make final volume at 250-mL calibration mark. 12. Heat to 160° F (71.1° C) and stir for about 15 to 20 min. Stir while heating if possible. (If there are no heating facilities available, stir for 30 min.) 13. Cool with stirring and make up the volume to exactly 250 mL with water using the calibrated container. 14. Filter with the filter press, discarding first cloudy portion of filtrate, and retain only clear filtrate. 15. To 10 mL of filtrate add 1 mL of Strong Buffer and 6 drops of Calmagite Indicator. 16. Titrate with Standard Versenate solution, stirring continuously until sample turns blue (or green for dark-colored filtrate) with no undertint of red remaining. Record the number of mL Standard Versenate solution used (Vt). 17. Clean the titration vessel and add approximately 20 mL water. 18. Add 1 mL of filtrate from the mud. 19. Add 1 mL of Strong Buffer solution. 10. Add 1 mL of Masking Agent. 11. Add 6 drops of Calmagite and mix with a stirring rod. 12. Titrate with Standard Versenate solution, stirring continuously until sample turns to blue (or green for Revision No: A-2 / Revision Date: 12·31·06
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Testing
dark-colored filtrate) with no undertint of red remaining. 13. Record the number of mL of Standard Versenate solution used (Vf). Calculations Available CaSO4 (lb/bbl) = 2.38 x Vt &#; [0.2 x (Fw x Vf)] Where: Vt = Number of mL Standard Versenate solution used to titrate 10 mL of clear filtrate in Step 6. Vf = Number of mL Standard Versenate solution used to titrate 1 mL of mud filtrate in Step 13. Fw = Freshwater fraction of mud obtained with mud still. Water %/100 = Fw.
H) POTASSIUM (K+) When it is necessary to determine the potassium ion concentration, either of the following procedures can be used effectively. Procedure I may be accurately used for any concentration of potassium ion. Procedure II is a quick method, used for high concentrations of potassium. 1) PROCEDURE I &#; POTASSIUM BELOW 5,000 mg/L (STPB METHOD)
Equipment 1. Standard Sodium Tetraphenyl Borate (STPB) solution. 2. Quaternary Ammonium Salt (QAS) solution, hexadecyltrimethyl ammonium bromide. 3. Sodium hydroxide (NaOH) solution (20%); 20 g/80 mL deionized water. 4. Bromophenol blue indicator. 5. Serological (graduated) pipettes: one 2-mL in 0.1-mL subdivisions, two 5-mL and two 10-mL. 6. Graduated cylinders: two 25-mL and two 100-mL. 7. Funnel: 100-mL. 8. Filter paper. 9. Beakers: two 250-mL and deionized water.
Testing
3.26
Procedure 1. Place the proper amount of filtrate into a 100-mL graduate, using Table 4 to determine sample size. Be sure to use a pipette to measure the amount of filtrate and/or diluted sample. 2. Add 4 mL of NaOH with a 5-mL pipette, 25 mL of STPB solution measured with a 25-mL graduate and enough deionized water to bring the level of the solution up to the 100-mL mark. 3. Mix and allow to stand 10 min. 4. Filter into a clean 100-mL graduated cylinder. If the filtrate is cloudy, the solution must be refiltered. 5. Transfer 25 mL of clear filtrate (measured with a 25-mL cylinder) into a 250-mL beaker. 6. Add 15 drops of bromophenol blue indicator. 7. Titrate with QAS solution until color changes from purple-blue to lightblue. Record mL of QAS solution used. Continue titration to 25 mL to ensure end point has been reached and no purple-blue color remains. If possible, use magnetic stirrer with light. Do not use a titration dish. Ratio of QAS to STPB = mL QAS ÷ 2 If ratio is other than 4.0±0.05, it must be used as a correction factor in the calculation of mg/L K+. Calculations (25 &#; mL of QAS) x 1,000 K+ (mg/L) = mL of filtrate If correction factor is necessary: K (mg/L) = mL of QAS x 4 25 &#; x 1,000 ratio of QAS to STPB +
[ (
)]
mL of filtrate1 1
For calculation, use mL filtrate from Procedure No. 1, labeled mL filtrate 1 (calculations). This procedure is called a back titration. Step 2 precipitates the potassium from solution. The potassium ion is filtered out in Step 4. Titration Revision No: A-2 / Revision Date: 12·31·06
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Testing
with the QAS solution determines the amount of unreacted STPB solution. 2) PROCEDURE II &#; POTASSIUM PERCHLORATE METHOD)
ION (SODIUM
Equipment 1. Standard sodium perchlorate solution: 150.0 g NaClO4 per 100 mL distilled water. NOTE: Sodium perchlorate is explosive in the dry state, if heated to a high temperature or allowed to contact organic reducing agents. The perchlorate is not hazardous if kept water wet. They will decompose harmlessly if dispersed in a bucket of water and then disposed of properly. 2. Standard potassium chloride solution, 14.0 g KCl made up to 100 mL with distilled water. 3. 10 mL clinical centrifuge tubes, Kolmer-type only; Corning . 4. Centrifuge, horizontal-swing rotor head (manual or electrical) capable of producing approximately 1,800 RPM. 5. Standard calibration curve for potassium chloride. Preparation 1. Calibrate the centrifuge. a. If electrical centrifuge is used, calibrate to 1,800 RPM using rheostat. b. If manual centrifuge is used, fairly constant 1,800 RPM can be obtained as follows: 1. Determine the number of revolutions of the rotor per each Estimated ppm K+ Over 100,000 50,000 - 100,000 20,000 - 50,000
turn of the crank; i.e., very slowly turn the crank and count the number of revolutions of the rotor head during one turn of the crank. 2. Determine the number of crank turns it takes to get 1,800 revolutions of the rotor head. 3. To maintain a constant speed for 1 min, take the required number of crank turns and divide by 12. This will give the number of crank turns needed per 5 sec. 4. Now, look at the second hand of your watch. Start cranking rapidly and count the number of crank turns in 5 sec. If the number is greater than 10, slow down a little and count turns for another 5 sec. Continue adjusting your speed until the required number of turns is achieved and becomes natural. 2. Preparation of standard calibration curve for potassium chloride (see Figure 15 or use the following to prepare curve). a. Prepare standards over the range of 1 to 8% KCl by adding appropriate mL of standard potassium chloride solution (0.5 mL for each 3.5 lb/bbl) to centrifuge tube and dilute to 7 mL with distilled water. b. Add 3 mL of sodium perchlorate solution to each tube.
Sample Preparation Take 1 mL filtrate, add 9 mL distilled water. Mix and use 1 mL solution for sample. Take 1 mL filtrate, add 9 mL distilled water. Mix and use 2 mL solution for sample. Take 1 mL filtrate, add 9 mL distilled water. Mix and use 5 mL solution for sample.
Filtrate (mL) 0.10 0.20 0.50
10,000 - 20,000 4,000 - 10,000
Take 1 mL undiluted filtrate. Take 2 mL undiluted filtrate.
1.00 2.00
2,000 - 4,000 250 - 2,000
Take 5 mL undiluted filtrate. Take 10 mL undiluted filtrate.
5.00 10.00
NOTE: It is important to check the concentration of QAS solution vs. the STPB solution at monthly intervals. To determine the equivalent QAS, dilute 2 mL of the STPB solution in titration vessel with 50 mL distilled water. Add 1 mL sodium hydroxide solution and 10 to 20 drops of the bromophenol blue indicator. Titrate with the QAS solution until the color changes from purple-blue to light-blue.
Table 4: Potassium sample sizes. Testing
3.27
Revision No: A-2 / Revision Date: 12·31·06
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Testing
c. Centrifuge for 1 min at 1,800 RPM and read the precipitate volume immediately. d. Rinse tubes and dispose of the liquid properly. e. Plot mL of precipitate vs. potassium chloride content (lb/bbl) on rectangular graph. Procedure 1. Measure 7 mL of filtrate into centrifuge tube. Add 3 mL of the sodium perchlorate solution to the tube (if potassium is present, precipitation occurs at once). DO NOT AGITATE! Centrifuge at constant speed, approximately 1,800 RPM for 1 min and read the precipitate volume immediately. Rinse the precipitate from the tube into a bucket of water. NOTE: To ensure all potassium has been removed, add 2 to 3 drops of the sodium perchlorate to the centrifuge tube after centrifuging. If a precipitate is formed, the total amount of potassium ion was not measured; sample must be diluted as in Note 2. 2. Determine the potassium chloride concentration by comparing the precipitate volume measured with the standard curve (see Figure 15). 3. Report the potassium concentration as lb/bbl KCl or kg/m3. Calculations The potassium concentration may also be reported as a weight % of KCl. lb/bbl KCl (wt %) = 3.5 lb/bbl x 2.853 = kg/m3 K+ (mg/L) = 1,500 x KCl (lb/bbl) NOTE 2: These two calculations assume a filtrate specific gravity of 1.00. If the concentration of KCl exceeds 21 lb/bbl, the accuracy can be improved by performing an appropriate dilution to keep the test result in the 3.5 to 21 lb/bbl range. The volume in the tube should be made up to 7 mL with Testing
3.28
Precipitate (mL)
3
1.40 1.30 1.20 1.10 1.00 0.90 0.80 0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00 0
Example plot (construct a similar calibration curve for actual chemicals)
Dilute sample volume to keep test result 2.0 1.50-1.60 1.5
1 &#;4 Teaspoon 0.90 1.25 0.50 0.75 0.80 0.60 0.75
1 &#;2 Teaspoon 1.80 2.50 1.10 1.50 1.60 1.20 1.50
1 Teaspoon 3.60 5.00 2.30 3.00 3.20 2.40 3.00
1 Tablespoon 10.80 15.00 6.60 9.60 12.60 7.60 10.00
1.4 1.2 2.32 4.30 2.04 2.3-2.6 2.20 1.5
0.40 1.00 1.30 1.50 1.00 1.00 0.60 0.50
1.00 1.75 2.30 3.50 2.50 2.00 1.30 1.50
2.00 3.50 4.90 8.00 5.00 4.00 2.40 3.00
6.50 11.00 12.60 25.00 15.00 12.00 7.70 9.00
2.8 1.2
1.00 0.50
2.25 1.50
4.50 3.00
13.00 10.00
4.20 2.75 2.70 2.30-2.60 1.45 2.5 1.5-1.6 1.98 1.10-1.40 1.65 2.16
2.08 0.50 1.00 0.98 0.63 1.00 0.50 1.90 1.00 0.75 1.50
4.17 0.80 2.50 1.95 1.25 3.00 1.00 3.10 2.00 1.50 3.00
8.33 2.00 5.00 2.90 2.50 6.00 2.00 6.10 4.00 3.00 6.00
25.00 5.80 15.00 6.70 7.50 20.00 8.00 19.10 12.00 10.50 18.00
2.20-2.40 1.90 2.51 2.16 1.2-1.5 1.05
0.70 1.15 1.60 0.72 0.50 0.75
1.50 2.30 3.00 1.45 1.00 1.50
3.00 4.60 6.00 2.90 2.00 3.00
8.80 13.80 17.80 8.70 6.00 10.00
1.20 1.50 1.60 1.50 1.57 1.5 1.83
0.50 0.60 0.85 0.50 1.00 1.00 1.17
1.00 1.00 1.70 1.00 2.00 1.90 2.33
2.00 2.00 3.40 2.00 3.00 3.60 4.67
6.00 5.80 10.20 8.00 9.00 10.70 14.00
Table 7: Approximate spoon weights for common oilfield products.
Testing
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Basic Chemistry
Introduction Chemistry is the study of matter&#;
Mud engineers deal with chemistry every day. Chemistry is the study of matter, including its composition, its properties, and its transformation into, or reaction with, other substances (chemical reactions). Matter is something that has mass and occupies space. Mass is a measure of the quantity of matter or the amount of material something contains. Mass is one of the fundamental quantities upon which all physical measurements are based. Mass causes matter to have weight in a gravitational field and inertia when in motion. The weight of something is the force of gravity acting on a given mass and is directly proportional to the mass times the gravitational force (acceleration). Common units for mass are grams (g) and pounds-mass.
Volume is a measure of the quantity of space occupied by matter. Common oilfield units of volume are gallons (gal), barrels (bbl), cubic feet (ft3), liters (l) and cubic meters (m3). Density is defined as the ratio of mass divided by volume. Common oilfield units of density are pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), kilograms per cubic meter (kg/m3) and grams per cubic centimeter (g/cm3). Specific gravity is a special expression of density often used for liquids and solids. It is the ratio of a substance&#;s density divided by the density of pure water at a stated temperature, usually 4°C. Likewise, the density of gases is often expressed as a &#;gas gravity,&#; or the ratio of the density of a particular gas divided by the density of pure air at standard conditions.
Classification of Matter ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
All substances fall into one of three physical states: &#; Solid &#; Liquid &#; Gas Solids usually have higher density than liquids and gases. They are substances which are not fluid and, therefore, do not flow when force is applied. Solids do not readily conform to the shape of their container. Liquids usually have a density less than solids, but greater than gases. Liquids will readily conform to the shape of their container. Both liquids and gases are fluids which &#;flow&#; when a force is applied. Gases not only conform to, but expand, to fill their container. All substances can also be separated into one of two categories: Basic Chemistry
4A.1
&#; Homogeneous (pure substances) &#; Heterogeneous (mixtures of substances) An example of a homogeneous material would be table salt, wherein each grain is identical in chemical composition. An example of a heterogeneous (non-uniform) material would be riverbed gravel; it is a mixture of rocks &#; from a variety of sources &#; having different chemical composition, appearance and properties. Drilling fluids and most materials found in nature are mixtures. Homogeneous materials (pure substances) are occasionally found in nature, but more often are manufactured by processing to separate dissimilar materials or to remove impurities. Pure substances can be identified because they are homogeneous and Revision No: A-0 / Revision Date: 03·31·98
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Elements cannot be broken down or subdivided into simpler substances&#;
Basic Chemistry
have uniform composition, no matter how they are subdivided or where they are found. Pure substances can be separated into one of two distinct categories: &#; Elements &#; Compounds Elements cannot be broken down (decomposed) or subdivided into simpler substances by ordinary chemical methods. Elements are the basic building blocks of all substances and have unique properties. Compounds can be reduced into two or more simpler substances (either elements or groups of Element (Latin) Aluminum Arsenic Barium Boron Bromine Cadmium Calcium Carbon Cesium Chlorine Chromium Copper (cuprium)
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Fluorine Hydrogen Iodine Iron (ferrum) Lead (plumbum) Lithium Magnesium Manganese Mercury (hydrargyrum) Nickel Nitrogen Oxygen Phosphorus Potassium (kalium) Silicon Silver (argentum) Sodium (natrium) Sulfur Tin (stannum) Titanium Zirconium Zinc
elements). A pure substance is a compound if it can be subdivided into at least two elements. All compounds are formed by the combination of two or more elements. If a pure substance cannot be separated into two or more elements, it must be an element. It is convenient to refer to an element with an abbreviation called a symbol rather than the full name. Table 1 contains the chemical name, symbol, atomic weight and common valence (electrical charge) of the elements of most interest to the drilling fluid industry.
Symbol Al As Ba B Br Cd Ca C Cs Cl Cr Cu
Atomic Weight 26.98 74.92 137.34 10.81 79.90 112.40 40.08 12.01 132.91 35.45 52.00 63.55
Common Valence 3+ 5+ 2+ 3+ 12+ 2+ 4+ 1+ 16+ 2+
F H I Fe Pb Li Mg Mn Hg Ni N O P K Si Ag Na S Sn Ti Zr Zn
19.00 1.01 126.90 55.85 207.19 6.94 24.31 54.94 200.59 58.71 14.00 16.00 30.97 39.10 28.09 107.87 22.99 32.06 118.69 47.90 91.22 65.37
11+ 13+ 2+ 1+ 2+ 2+ 2+ 2+ 5+ 25+ 1+ 4+ 1+ 1+ 22+ 4+ 4+ 2+
Table 1: Common elements.
________________________
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Basic Chemistry
Atomic Structure
Atoms are the basic building blocks for all matter&#;
The mass of either a proton or a neutron is roughly 1,837 times greater than the mass of an electron.
All matter is composed of discrete units called atoms. The atom is the smallest unit into which an element can be divided and still retain the element&#;s unique chemical properties. Atoms are the basic building blocks for all matter; they are the smallest units of an element that can combine with atoms from another element. Atoms of different elements have different properties. Atoms are neither created nor destroyed in chemical reactions. Atoms contain three subatomic particles: &#; Protons &#; Neutrons &#; Electrons The atom has two distinct zones: a small, dense nucleus, which contains the protons and neutrons, surrounded by a diffuse cloud of electrons. The size of an atom depends almost entirely on the amount of volume occupied by the electron cloud of the atom, while virtually all the mass is located in the nucleus (see Figure 1). The nucleus is approximately spherical, 10 &#; 4 angstrom (Å) or 10&#;14 m in diameter and contains protons and neutrons only. A proton has a positive charge while a neutron has no charge. The electron cloud, or shell, also is approximately spherical, 1 Å or 10 &#;10 m in diameter and contains only electrons, which orbit the nucleus much like a miniature solar system. An electron has a negative charge equal in strength to the positive charge of a proton. In neutrally charged atoms
Diffuse cloud of light electrons (&#;) orbiting the nucleus in structured shells.
Nucleus is compact and dense, containing heavy protons (+) and neutrons (neutral).
Figure 1: Atomic structure.
(no valence), the number of electrons is equal to the number of protons so that the net charge of the atom is neutral. Some atoms can gain or lose electrons so that a charged atom, called an ion, is formed. When an electron is lost, a positive charge results. A positively charged ion is called a cation. Similarly, when an electron is gained, a negatively charged &#;anion&#; is formed. The mass of either a proton or a neutron is roughly 1,837 times greater than the mass of an electron. Due to this huge difference in mass, the mass of the protons and neutrons in the nucleus account for the approximate total mass of the atom (see Table 2). Particle Proton Neutron Electron
Charge Positive (1+) None (neutral) Negative (1-)
Mass (g) 1. X 10 &#; 24 1. X 10 &#; 24 0. X 10 &#; 24
Table 2: Mass and charge of subatomic particles.
Basic Chemistry
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The lightest and simplest element is hydrogen&#;
Each element may have several atomic structures called isotopes&#;
Basic Chemistry
The nucleus of an atom is very dense; approximately 1,770 tons/in.3 (98,000 kg/cm3). The electron cloud has a diameter 10,000 times larger than the nucleus. The larger volume of the low-density electron cloud balances the high density of the nucleus to an average density of 2 to 20 g/cm3. The lightest and simplest element is hydrogen, which has only one proton in each nucleus. Naturally occurring atoms contain between 1 and 93 protons in their nucleus. Heavier atoms, with even more protons, have been created in laboratories, but are unstable and do not occur naturally. All atoms that have the same number of protons in their nuclei have identical chemical properties and are called elements. There are 92 naturally occurring elements which, in various combinations, form the physical world. The number of protons (p+) in the nucleus is used to define each element and is called the &#;atomic number&#; (z). Hydrogen, with just one proton, has an atomic number of 1. The sum of the number of protons and neutrons (n) in the nucleus of an atom is called the &#;atomic mass number&#; (a), a = p+ + n. Each element may have several atomic structures called isotopes, each with a different number of neutrons in its nucleus, giving each a different atomic weight. Although these isotopes of an element will have different atomic weights, they will have identical chemical properties, and form compounds with the same properties. Isotopes are written with the atomic number (z) as a subscript before the chemical symbol and the atomic mass number (a) as a superscript ( zaX). Hydrogen has three isotopes. The most common isotope of hydrogen has no neutron in its nucleus (11H), the second most common isotope has one neutron (21H) and the third isotope contains two neutrons (31H). All
Basic Chemistry
4A.4
three of these isotopes contain only one proton in the nucleus. The atomic mass scale is a relative mass scale based on the mass of the carbon isotope, 126 C, which has a mass of exactly 12.0 atomic mass units (amu). This scale is used to simplify expressing such small values of mass for each isotope of each element. The mass of one neutron, or one proton, is roughly equal to 1 atomic mass unit (amu). The atomic weight of an element is equal to the weighted average mass of all the isotopes of the element on the atomic weight scale. For example, the three hydrogen isotopes, 11H, 21H and 3 1H, have masses of 1., 2. and 3. atomic mass units, respectively. The fraction of each isotope that occurs in nature are 0., 1.5 x 10 &#; 4 and 10 &#;11. The atomic weight of hydrogen, therefore, is: (0.) 1. + (1.5 x 10 &#;4) 2. + 10 &#;11 (3.) = 1.. Some combinations of neutrons and protons are not stable in the nucleus of an atom. These unstable nuclei will break apart naturally, or &#;decay,&#; to form atoms of entirely different elements. This &#;decay&#; is a nuclear (physical) reaction which involves neither a chemical reaction with oxygen nor a biological activity normally associated with chemical decay. Isotopes that are subject to nuclear decay are said to be radioactive. When an atom decays, it releases subatomic particles and energy (radioactivity). Radioactivity is widely used for laboratory analytical evaluations of chemicals and minerals. Some wellbore evaluation logs use either a radioactive source or natural background radiation to identify and evaluate formations and formation fluids. Atoms of one element bond with atoms of other elements to form compounds either by transferring electrons (ionic bonding) or by sharing electrons (covalent bonding). Bonding
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Two or more elements can combine to form a compound.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Basic Chemistry
is the combination of attractive forces between atoms which make them act as a compound or unit. The manner in which bonding occurs has important implications for a compound&#;s physical properties. Two or more elements can combine to form a compound. Elements in a compound are bound together by shared electrons. Compounds have different chemical and physical properties than the elements from which they are formed. For instance, both hydrogen and oxygen are gases at standard conditions, but when combined to form water, they exist as a liquid. Table 3 lists the chemical name, formula and common name for the most common compounds of interest to the drilling fluids industry. The smallest unit into which a compound can be divided is a molecule, a combination of tightly bound atoms. Name Formula Common Name Silver nitrate AgNO3 &#; Aluminum oxide Al2O3 Alumina Barium sulfate BaSO4 Barite Barium carbonate BaCO3 Mineral witherite Barium hydroxide Ba(OH)2 &#; Calcium hydroxide Ca(OH)2 Hydrated lime Calcium sulfate CaSO4 Anhydrite (anhydrous) Calcium sulfate CaSO4 &#; 2H2O Gypsum (hydrous) Calcium carbonate CaCO3 Limestone, marble, calcite Calcium chloride CaCl2 &#; Calcium oxide CaO Quick lime, hot lime Hydrochloric acid HCl Muriatic acid Hydrogen oxide H2O Water Sulfuric acid H2SO4 &#; Hydrogen sulfide H2S &#;
________________________
Molecules are composed of two or more chemically bonded atoms. Atoms in a molecule always combine in particular ratios and with specific orientations. Molecules cannot be divided into any smaller unit and still retain the compound&#;s unique chemical properties. The composition of a compound can be described by a simple chemical formula using the atomic symbols and subscript numbers which show how many of each atom are in the simplest molecule. For example, the smallest particle of carbon dioxide is one molecule with one carbon atom bonded to two oxygen atoms and can be represented by the chemical formula CO2. Groups of atoms bonded together also can be ions (polyatomic ions). For example, the hydroxyl ion, OH&#;, is an anion with a net 1- charge, or one extra electron. The ammonium ion, NH4+, is a polyatomic cation with a 1+ charge. Name Magnesium oxide Magnesium hydroxide Nitric acid Potassium chloride Sodium hydroxide Sodium bicarbonate Sodium chloride
Formula MgO Mg(OH)2
Common Name Mag ox &#;
HNO3 KCl NaOH
Aqua fortis Muriate of potash Caustic soda
NaHCO3 NaCl
Baking soda Salt
Sodium carbonate Na2CO3 Sodium sulfate Na2SO4&#;10H2O Sodium acid pyrophosphate Sodium tetraphosphate Silicon dioxide Zinc carbonate Zinc sulfide Zinc oxide
Na2H2P2O7
Soda ash Salt cake, Glauber&#;s salt SAPP
Na6P4O13
Phos
SiO2 ZnCO3 ZnS ZnO
Quartz, silica &#; &#; &#;
Table 3: Common compounds.
________________________ ________________________ ________________________ ________________________ ________________________
Basic Chemistry
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Basic Chemistry
Valence
Valence determines which elements or ions will combine and in what ratio they will combine.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
The valence of an element or ion is the number of electrons it can gain, lose or share in order to become a stable, neutrally charged compound. The hydrogen atom is selected as the reference and has one positive bond, or a valence of 1+. Valence determines which elements or ions will combine and in what ratio they will combine. For example, one atom of chlorine (Cl) combines with one atom of hydrogen (H, 1+ valence) to form hydrochloric acid (HCl), so chlorine must have a 1- valence. One oxygen atom (O) combines with two hydrogen atoms to form water (H2O), so oxygen has a 2- valence. One sodium atom (Na) combines with one chlorine atom (Cl, 1- valence) to form salt (NaCl), so sodium must have a valence of 1+. One atom of calcium (Ca) combines with two atoms of chlorine to form calcium chloride (CaCl2), so calcium must have a 2+ valence. Following the same line of reasoning, the valence of K in KCl must also be 1+. If we consider the compound H2SO4, we see that the valence of the sulfate group or ion (SO4) must be 2- since there are two hydrogen atoms. The sulfate ion (SO42&#;) is taken as a complete unit. In the case of caustic soda (NaOH), since Na has a valence of 1+, then the hydroxyl ion (OH) must have a valence of 1-. For calcium hydroxide (lime), since calcium has a valence of 2+ and the hydroxyl ion has a valence of 1-, then there must be two hydroxyl ions in the
compound Ca(OH)2. Many elements, such as iron, chrome, nickel, chlorine and sulfur, can have several valences. Valence also is often referred to as the &#;oxidation state&#; (as it is listed later in Table 5). Table 4 is a list of common elements and ions (groups) with their respective symbols and valences. Element Hydrogen Oxygen Potassium Sodium Calcium Magnesium Aluminum Zinc Iron Silver Carbon Phosphorus Sulfur Chlorine Ion or Group Hydroxide Oxide
Symbol H O K Na Ca Mg Al Zn Fe Ag C P S Cl Symbol OH O
Valence 1+ 21+ 1+ 2+ 2+ 3+ 2+ 3+, 2+ 1+ 4+ 5+ 2+,4+,6+ 1-,1+,3+,5+,7+ Valence 12-
Carbonate Bicarbonate Sulfate Sulfite Sulfide Nitrate Nitrite Phosphate Ammonium Acetate Formate Thiocyanate
CO3 HCO3 SO4 SO3 S NO3 NO2 PO4 NH4 C2H3O2 CHO2 SCN
+ 111-
Table 4: Common symbols and valence.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
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Basic Chemistry
Electron Shell
The outermost orbit is designated as the valence electron orbit (valence shell)&#;
Electrons orbit the nucleus of an atom in orderly arrangements called electron shells. Each shell can hold only a specific maximum number of electrons. The first orbital or shell must not contain more than two electrons and, in general, each succeeding shell cannot contain more than eight electrons. Each subsequent shell has an orbit of larger diameter. Completely filled shells form stable (less reactive) structures, i.e., they tend not to accept or give up electrons.
Individual atoms generally begin by having a balanced electrical charge (with the same number of electrons as protons), but can give up or accept electrons to fill shells. The outermost orbit is designated as the valence electron orbit (valence shell) because it determines the valence an atom will have. The arrangement of elements called the &#;Periodic Table&#; lines up elements with the same number of electrons in the &#;valenceshell&#; into columns (see Table 5).
Ionic Bonding
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
As shown in Figure 2, sodium and chlorine form the sodium chloride compound by sodium losing and chlorine gaining an electron (called ionic bonding) to form filled outer electron shells. The sodium atom (atomic number 11) has 11 protons and 11 electrons; therefore, the 11 electrons are arranged with two in the first shell, eight in the second shell and only one electron in the third shell. The one electron in the outermost &#;valence-shell&#; makes sodium want to give up one electron when combining with other atoms to form a stable structure with its last shell filled. If one electron is lost (1- charge), sodium would become an ion with a 1+ charge, or valence. The chlorine atom (atomic number 17) has 17 protons and 17 electrons. The electrons are arranged with two in the first shell, eight in the second shell and seven in the third shell. The seven electrons in the outermost &#;valenceshell&#; make chlorine want to gain one electron to fill its last shell. If one electron is gained, chlorine would become an ion with a 1- charge or valence. Thus, the combination of one atom of sodium and one atom of chlorine forms the stable sodium chloride compound, Basic Chemistry
4A.7
Sodium atom
Chlorine atom
11+
17+
1 electron outer shell
7 electrons outer shell Neutral atoms
11+
17+
Transfer of an electron
+
&#; Ionic bond
11+
Transfered electron
Na+ ion
17+
Cl&#; ion Each has 8 electrons outer shell Sodium chloride compound
Figure 2: Electron shells and ionic bonding.
Revision No: A-0 / Revision Date: 03·31·98
Basic Chemistry
4A.8
4b
91 Pa
90 Th
104
178.49
72 Hf
91.22
40 Zr
47.90
22 Ti
**Actinides
+3
+3
+3
+3
59 Pr
(227)
89** Ac
138.
57* La
88.
39 Y
44.
21 Sc
58 Ce
(226)
+2
+2
+2
+2
+2
+2
3b
*Lanthanides
(223)
88 Ra
87 Fr
+1
137.34
132.
87.62
56 Ba
85.467
55 Cs
+1
38 Sr
37 Rb
+1
40.08
20 Ca
19 K
39.102
24.305
22.
+1
12 Mg
+1
11 Na
4 Be
2a
9.
+1
+1 -1
6.94
3 Li
1.008
1a
+4
+4
+2 +3 +4
92 U
60 Nd
105
180.947
73 Ta
92.
41 Nb
50.941
23 V +2 +3 +6
+5
+3 +5
+2 +3 +4 +5
93 Np
61 Pm
183.85
74 W
95.94
42 Mo
51.996
24 Cr
+6
+6
94 Pu
62 Sm
186.2
75 Re
98.
43 Tc
+4 +6 +7
+4 +6 +7
+2 +3 +4 54. +7
95 Am
63 Eu
190.2
76 Os
101.07
44 Ru
55.847
26 Fe
96 Cm
64 Gd
192.22
77 Ir
102.
45 Rh
58.
27 Co
+3 +4
+3
+2 +3
97 Bk
65 Tb
195.09
78 Pt
106.4
46 Pd
58.71
28 Ni
+2 +4
+2 +4
+2 +3
1b
98 Cf
66 Dy
196.
79 Au
107.868
47 Ag
63.546
29 Cu
Table 5: Periodic table.
+3 +4
+3
+2 +3
8
Group 8
Oxidation states
Transition elements
25 Mn
118.69
Symbol Atomic weight
+2 +4
7b
Key 50 Sn
6b
Atomic number
5b
+1 +3
+1
+1 +2
99 Es
67 Ho
200.59
80 Hg
112.40
48 Cd
65.37
30 Zn
2b
+1 +2
+2
+2
100 Fm
68 Er
204.37
81 Tl
114.82
49 In
69.72
31 Ga
26.
13 Al
10.81
5 B
3a
+1 +3
+3
+3
+3
+3
101 Md
69 Tm
207.2
82 Pb
118.69
50 Sn
72.59
32 Ge
28.086
14 Si
12.011
6 C
4a
+2 +4
+2 +4
+2 +4
+2 +4 -4
+2 +4 -4
102 No
70 Yb
208.
83 Bi
121.75
51 Sb
74.
33 As
30.
15 P
+3 +5
+3 +5 -3
+3 +5 -3
+3 +5 -3
+1 +2 +3 +4 +5 -1 14. -2 -3
7 N
5a
103 Lr
71 Lu
(209)
84 Po
127.60
52 Te
78.96
34 Se
32.06
16 S
15.
8 O
6a
+2 +4
+4 +6 -2
+4 +6 -2
+4 +6 -2
-2
+1 +5 -1
+1 +5 +7 -1
-1
(210)
85 At
+1 +5 +7 126. -1
53 I
79.904
35 Br
35.453
17 Cl
18.
9 F
7a
0
(222)
86 Rn
131.30
54 Xe
83.80
36 Kr
39.948
18 Ar
20.17
10 Ne
4.
2 He
0
0
0
0
0
0
4A
1 H
CHAPTER
Basic Chemistry
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4A
Atoms with one, two and three valence electrons find it easier to give away electrons&#;
Basic Chemistry
NaCl. The one sodium valence electron is transferred from the sodium atom to the outer shell of the chlorine atom. Why does sodium give up its electron and why does chlorine accept it? The theory dealing with the behavior of atoms assumes that every atom tries to achieve a full outer electron shell with eight electrons. Atoms with one, two and three valence electrons find it easier to give away electrons, whereas those with four, five, six and seven find it easier to accept them. In the case of sodium and chlorine, sodium gives one electron, resulting in a net charge of +1, and chlorine takes on one electron, resulting in a net charge of 1. Neither atom is considered neutral with these changes. The sodium atom has become an ion with a positive
charge (written as Na+) and the chlorine atom has become an ion with a negative charge (written as Cl&#;). The evidence to support electron transfer and the formation of ions is the phenomenon that melted NaCl is a conductor of electricity, and if a current is applied to the molten salt, sodium metal collects at the negative pole of the cell (cathode) and chlorine gas collects at the positive pole (anode). Thus, the sodium ion is called the cation and the chloride ion is called the anion. In writing the name of a compound, the cation is usually written first. Since sodium gives up an electron, it is said to be electropositive, and since it readily gives up this electron, it is said to be strongly electropositive.
Covalent Bonding
&#;covalent bonding is the simultaneous sharing of electrons.
The sharing of electron pairs to form bonds between atoms is called covalent bonding. Unlike sodium chloride, where there is a transfer of electrons (ionic bonding), covalent bonding is the simultaneous sharing of electrons. Both water and hydrogen gas are good examples of compounds with covalent bonds (see Figure 3). In a water molecule, one electron from each of the two hydrogen atoms is shared with the six electrons in oxygens&#; second electron shell to fill it with eight electrons. Likewise, each hydrogen atom in a water molecule shares one of the six electrons from the oxygen atom&#;s second electron shell to fill its first electron shell with two electrons. Compounds with a high degree of electron sharing have strong interatomic forces with weak intermolecular forces. The weak intermolecular forces usually are not sufficient to maintain a rigid structure. Because of this, covalently bound compounds are often liquids and gases. Basic Chemistry
4A.9
Hydrogen bonding: Some covalent compounds have incomplete sharing of the electron in the bond. This results in partial postive and negative charges on the atoms arranged in a manner which polarizes the molecule. In water (H2O), for example, the two hydrogen atoms remain partially positive and the oxygen atom remains partially negative. The negative charges of oxygen dominate one side of the molecule, while the postive charges of the hydrogen atoms dominate the other side, forming a polar molecule (see Figure 4). The hydrogen atoms of water molecules are attracted to the oxygen atoms of other nearby water molecules. This attraction of the positive hydrogen pole of one molecule to the negative oxygen pole of another molecule is referred to as hydrogen bonding. The forces of hydrogen bonding are estimated to be only one-tenth to onethirtieth as strong as those of covalent bonding. These weak bonds easily Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4A
Basic Chemistry
Water: 2 Hydrogen atoms
Oxygen atom
Water (H2O)
Combine to form
________________________ ________________________
1+
1+
________________________ ________________________ ________________________
Covalent bond
8+
________________________
8+
Shared electrons
________________________ ________________________ ________________________
1+
1+
________________________ ________________________ ________________________
1 electron outer shell
6 electrons outer shell
Each atom has full outer shell
Hydrogen gas: 2 Hydrogen atoms
Combine to form
Hydrogen gas (H2)
________________________ ________________________ ________________________
1+
1+
Covalent bond
1+
Shared electrons
1+
Figure 3: Covalent bonding of water and hydrogen gas.
The polarity of water explains some of the phenomena seen in drilling fluids.
alternate between molecules and change association, i.e., making and breaking bonds between nearby molecules. Hydrogen sulfide (H2S) is a gas even though its a heavier molecule than water (H2O), because the charge distribution is not polar. The two hydrogen atoms have only weak positive charge and the sulfur is only weakly negative, forming a balanced structure. The lack of a strong polar structure allows the individual molecules to diffuse into a gas under standard conditions. The polarity of water explains some of the phenomena seen in drilling fluids. Clays and shales are strongly charged, complex structures. The attraction of the water molecule&#;s charges to the charge sites of clay platelets leads to clay hydration. Clays have a strong negative charge on their large planar surface and positive charges along their thin edges. The positive hydrogen side of the water molecule is attracted to and will hydrogen bond to the large negative Basic Chemistry
4A.10
Water molecule (H2O)
H+ Hydrogen side positive charge
O2&#;
Oxygen side negative charge
H+ Polar charge orientation
H+ O2&#;
H+ H+
O2&#; H+
H+ H+
O2&#;
O2&#; H+
H+
H+ Attraction of positive hydrogen side to negative oxygen side
O2&#;
H+
Figure 4: Polar molecule and hydrogen bonding in water.
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CHAPTER
4A
Basic Chemistry
O
O
H
H
H
O H
O H
H
&#;
O
O
O
Si
O
Si
O
O
O
O
Al
Al
O
O
Si +
Clay H
O
H
OH
+
O
Si
H O
O
O
Al
Al
O
O
O
O
O
O
H
O
Si +
OH
H
OH
Si O
O
H
O
H O
Si +
O
Si
+
Alumina layer OH O
&#;
H
Silica layer
H
Hydrogen bonded water
O H
Silica layer
O
H
H
O H
+
O
O
Si
O
O OH
O
O
Si
Al
Hydrogen bonded water H
O
Al OH
H
Si
Al
O H
+
H O
Si
Al
H
H
O
Si O
+
H
H
O
Si O
O H
H
OH
Si O
O
Si
H O
H
OH
+
H
O H
+
H
O
H
O
H O
Figure 5: Hydration of clay by water through hydrogen bonding.
Ionic bonding is as strong as covalent bonding and both are much stronger than hydrogen bonding.
clay surface. This water adsorption can be many water layers thick, spreading and swelling adjacent clay layers (see Figure 5). Cation exchange (exchange of ionic bonded cations) within a clay can displace the water of hydration and flocculate the clay particles, because their bonds are stronger than water&#;s weak hydrogen bonds. Many compounds contain both covalent and ionic bonds. Soda ash (Na2CO3) is an example of a compound that contains both covalent and ionic
bonds. The bonds between the carbon and oxygen in the carbonate group (CO32 &#;) are covalent (electron sharing), while the bonds between the sodium ion (Na+) and the carbonate group are ionic (electron transfer). When soda ash dissolves, the sodium dissociates from the carbonate group, while the carbon and oxygen of the carbonate group continue to function as a single unit. Ionic bonding is as strong as covalent bonding and both are much stronger than hydrogen bonding.
Compounds A compound is a substance that is composed of elements in definite proportions. Common table salt is an ionic compound; it can be broken down into the elements sodium (Na) and chlorine (Cl). The following apply to all compounds:
Basic Chemistry
4A.11
&#; The composition of a compound is always the same; it is definite and exact. &#; Elements lose their identity (their characteristic properties) when they combine to form a compound. &#; A compound is homogeneous.
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CHAPTER
4A
Basic Chemistry
Formulas
A compound&#;s formula represents one molecule of the compound.
The sum of the atomic weights of the atoms in a chemical formula is called the formula weight.
Since a specific compound always contains the same elements combined in exactly the same ratio, it is possible to represent its composition by means of a formula. A compound&#;s formula represents one molecule of the compound. Atoms and chemical compounds do not react with or form just one molecule at a time. Instead, millions of molecules and atoms are reacting simultaneously. Due to their small size, it is impossible to count the number of atoms involved in chemical reactions. Weight is used to measure the quantity of chemicals involved in chemical reactions. Since one atom of sodium weighs 22.99 amu and one atom of chlorine weighs 35.45 amu, then based on ratio, the atoms in 22.99 g of sodium would combine with the exact number of atoms in 35.45 g of chlorine to form salt. This principle of ratio works for any unit of measure &#; grams, pounds, kg, tons, etc. &#; but the gram is the unit of measure most commonly used. When expressed in grams, the atomic weight corresponds to 6.023 x atoms. This amount is one &#;gram-atom&#; molecular weight or &#;mole.&#; A mole is a quantitative unit of measure that contains the exact number of atoms, molecules or formula units which have a mass in grams equal to the atomic, molecular or formula weight. A mole of an element contains the same number of chemical units (atoms, molecules or units) as exactly 12 g of carbon 12, or Avogadro&#;s number; 6.023 x of chemical units. A common usage of the mole is the formula weight expressed in grams. For NaCl (salt), the formula weight is 58.44, so one mole of sodium chloride would be 58.44 g.
Basic Chemistry
4A.12
The number of atoms of an element in a compound&#;s formula is equal to the number of moles of that element needed to make one mole of the compound. In water, two moles of hydrogen react with one mole of oxygen to form one mole of water. Expressed on a weight basis, hydrogen (atomic weight 1.01) combines with oxygen (atomic weight 16.00) in the ratio of 2.02 g of hydrogen to 16.00 g of oxygen; i.e., a ratio of two moles of hydrogen to one mole of oxygen. The formula, therefore, is H2O. Carbon (atomic weight 12.01) combines with oxygen in the ratio of 12.01 g of carbon to 32.00 g of oxygen to form carbon dioxide. The formula, therefore, is CO2. The subscript 2 refers only to the oxygen, and means that there are two oxygen atoms per molecule. Atoms in a formula which do not have a stated subscript, such as the carbon atom, are understood to have a subscript of 1. The sum of the atomic weights of the atoms in a chemical formula is called the formula weight. If the chemical formula of a substance is the molecular formula, the formula weight is also the molecular weight. Thus, the formula weight of NaCl is 58.44. This value is obtained by adding the atomic weight of sodium (22.99) to the atomic weight of chlorine (35.45). A specific compound always contains the same elements combined in exactly the same ratio by weight and the composition is represented by the simplest formula that describes the compound. CaCl2, Fe2O3 and BaSO4 are examples of formulas of compounds.
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CHAPTER
4A
Basic Chemistry
Stoichiometry - Stoichiometric Reactions Stoichiometry deals with the quantities and exact ratios of substances which react.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
The reason compounds contain fixed ratios of elements is because atoms react with other atoms according to their valence. As discussed previously, atoms react according to these ratios based on the fixed weights of each atom involved. Determination of the
weights is called &#;stoichiometry&#;. Stoichiometry deals with the quantities and exact ratios of substances which react. Stoichiometric calculations allow the exact weight and ratio of chemicals which will react to be determined so that a desired result can be achieved.
Equivalent Weight In many cases, chemical testing and reactions are done with unknown materials. Because we don&#;t know the exact composition, it is often convenient to express results in terms of &#;equivalents&#; of a standard compound instead of moles. For example, in mud engineering, we titrate water-base mud filtrate to measure &#;total hardness&#; and express the result as if it were all calcium. This total hardness titration actually measures both magnesium and calcium, so we are expressing the total hardness in calcium &#;equivalents.&#; The equivalent weight is defined as the formula weight of an element, compound or ion divided by how many times it takes part in a specific reaction. As an example, for acids the number of hydrogen atoms in the chemical formula determines the equivalent weight. Acids react by donating protons (hydrogen ions). Suppose sulfuric acid (H2SO4, formula weight 98) is used to reduce pH. The reaction can be written as: H2SO4 + 2OH&#; &#; 2H2O + SO42&#;
One mole of H2SO4 reacts with two moles OH&#;. From this standpoint, 1&#;2 mole of sulfuric acid is equivalent to one mole of hydroxyl. To remove only one mole of OH&#;, then only 1&#;2 mole of H2SO4 is needed. On a formula weight basis this would be 98 ÷ 2 or 49 g. Therefore, the equivalent weight of H2SO4 is 49 g. To consume the same amount of OH&#; using hydrochloric acid (HCl, formula weight 36.5) which has only one hydrogen atom, then the reaction can be written as: HCl + OH&#; &#; H2O + Cl&#; Since one mole of HCl reacts with just one mole of OH&#;, then the equivalent weight of hydrochloric acid is its formula weight, 36.5 g. By this equivalent weight method, 49 g of H2SO4 is equivalent to 36.5 g of HCl. Using this principal if pilot testing in the laboratory shows that it takes 36.5 lb/bbl of HCl to neutralize a high pH fluid, and only H2SO4 was available to use at the rig, then 49 lb/bbl of H2SO4 would also neutralize the fluid.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Basic Chemistry
4A.13
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4A
Basic Chemistry
Balancing an Equation
Chemical equations must always have an equal number of each atom&#;
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
One of the first steps involved in determining stoichiometric reactions is to balance the chemical equation. Chemical equations must always have an equal number of each atom on both sides of the equation. If all of the reactants and products are known, the best approach is to single-out one element of known valence and balance the entire equation on the basis of that element. Many elements can have more than one valence, which complicates the process. If present, oxygen should be used to balance the equation. The arrow or arrows indicate chemical reactions or transformations and should be considered to be like an equals sign (=) in mathematics. Consider the following unbalanced equation involving the reaction between iron (Fe3+) and oxygen (O2&#;) producing iron oxide: Fe3+ + O22&#; &#; Fe23+O32&#; This equation is not balanced with respect to the number of atoms or valence charges. Starting with oxygen, the equation is not balanced since there are two oxygen atoms on the left side and three on the right. First, balance the number of oxygen atoms, then the iron atoms. The valence charges are also not balanced, with four negative charges (2 x 2-) on the left and six negative charges (3 x 2-) on the right. If a 2 is used in front of the iron oxide and a 3 in front of the oxygen, the equation then becomes: Fe3+ + 3O22&#; &#; 2Fe23+O32&#; The number of oxygen atoms and negative charges are now balanced.
________________________
Now, however, the iron must be balanced. As a result of balancing the oxygen atoms, there is now one iron atom on the left and four iron atoms (2 x 2) [with 12 positive charges, 2 x 2 x 3+] on the right. In order to completely balance the equation, there must be four iron atoms on the left with 12 positive charges on the left. If a 4 is placed before the iron, the equation is balanced: 4Fe3+ + 3O22&#; &#; 2Fe23+O32&#; Stoichiometrically, four moles of iron combine with three moles of oxygen to yield two moles of iron oxide. Consider the following problem: Using the reaction from above, how many grams of oxygen would be required to react with 140 g of iron to produce iron oxide? 4Fe + 3O2 &#; 2Fe2O3 4 moles iron + 3 moles oxygen &#; 2 moles iron oxide atomic weight Fe = 55.85, so 4 moles Fe = 4 x 55.85 = 223.4 g atomic weight O &#; 16, so 3 moles O2 = 3 x 2 x 16 = 96 g Since only 140 g of iron is used (not 223.4), the ratio of 140 divided by 223.4 can be multiplied times the 96 g of oxygen to determine the amount of oxygen needed to react with 140 g of iron. Oxygen required = 140 g Fe x 96 g O2 = 223.4 g Fe 60.2 g O2 Therefore, it takes 60.2 g of oxygen to react with 140 g of iron to produce iron oxide.
________________________ ________________________ ________________________ ________________________ ________________________
Basic Chemistry
4A.14
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4A
Basic Chemistry
Solubility SOLUTIONS ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
If sugar is added to water, it will dissolve, forming a solution of sugar in water. The solution is homogeneous when no particles of sugar can be seen. The sugar is referred to as the solute; it is the substance that is dissolved. The water is referred to as the solvent; it is the substance that does the dissolving. Small additions of sugar will dissolve until a point is reached at which the solution is unable to dissolve additional sugar. This will be indicated when the crystals that are added drop to the bottom of the glass and will not dissolve, even if the contents of the glass are well stirred. A solution which has dissolved all the solute that it is capable of dissolving at a given temperature is said to be saturated and this quantity of solute is referred to as its solubility.
EFFECTS
Many ionic compounds are soluble in water.
H+
H+ O 2&#;
H+
H+
O 2&#;
O 2&#;
H+ Na+ H+
H+
O 2&#;
O 2&#; H+
H+
O
2&#;
H+
H+
Sodium ion is compact with relatively strong bonds with water.
H+ O 2&#; H+ O 2&#; H+
+
H
H+
OF BONDING
The solubility of compounds in polar solvents, like water, can generally be explained by their bonding. Polar covalent compounds, such as CO2, usually are soluble in water. When their attraction to water&#;s hydrogen bonds is greater than their attraction to the charges of other molecules of the compound, the molecules of the compound will disperse into solution. Nonpolar covalent compounds, such as methane (CH4), are usually insoluble in water and other polar solvents, but are often dispersable in nonpolar solvents, such as diesel oil. When nonionic compounds dissolve, they become molecularly dispersed not ionized. Many ionic compounds are soluble in water. If the forces of attraction between the water molecules and the ions are greater than the forces holding the ions in their crystals, the ions will attract a &#;shell&#; of water molecules and be freed from their crystalline lattice, as shown for sodium chloride (see Figure 6). Basic Chemistry
H+
4A.15
Cl&#;
O 2&#; H+
O 2&#; H+
H+ H+ O 2&#;
H+
Chlorine ion is larger with weaker bonds with water.
Figure 6: Ionization of sodium chloride in water.
Salts (compounds) with either monovalent cations (sodium (1+) in soda ash, Na2CO3) or monovalent anions (chlorine (1-) in calcium chloride, CaCl2) are usually soluble in water. The salts of multivalent cations combined with multivalent anions (calcium (2+) and sulfate (2-) [in gypsum CaSO4, for example]) are usually insoluble or only sparingly soluble. The forces holding ions together in the salts of multivalent cations and multivalent anions are much greater than the forces holding the ions together in
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4A
Ionic bonded compounds dissolve or solubilize into ions&#;
Basic Chemistry
the salts of either monovalent cations or monovalent anions. Ionic bonded compounds dissolve or solubilize into ions, whereas covalent bonded compounds are soluble as molecules. Brines are solutions of a high concentration of soluble salts and are more viscous than freshwater because the dissolved salts reduce the free water by attracting large shells of water around themselves, restricting the free movement of the water. Ionic compounds are generally insoluble in nonpolar solvents such as diesel oil.
QUANTIFYING
SOLUBILITY
The quantity of solute that will dissolve in a quantity of solvent to give a saturated solution is referred to as the solubility of the solute in the solvent. Solubility of a solid, liquid or gas in a liquid is generally expressed in units of grams of solute per 100 g of water. Table 6 lists the degree of solubility of several common compounds used in drilling fluids.
Water-base drilling fluids are generally maintained in the 8 to 12 pH range&#;
Solubility (g per 100 g Compound Common Name water) NaOH Caustic soda 119 CaCl2 Calcium chloride 47.5 NaCl Sodium chloride (table salt) 36 KCl Potassium chloride 34.7 Na2CO3 NaHCO3 CaSO4 Ca(OH)2 MgCO3 CaCO3 Mg(OH)2 BaSO4 ZnO
Soda ash Sodium bicarbonate Anhydrite Lime Magnesium carbonate Limestone Milk of magnesia Barite Zinc oxide
21.5 9.6 0.290 0.185 0.129 0. 0. 0. 0.
Table 6: Solubility of common chemicals.
FACTORS
AFFECTING SOLUBILITY
&#; Temperature &#; pH (acid or base) &#; Ionic environment (salinity) &#; Pressure
Basic Chemistry
4A.16
1. Temperature. Solubility increases with increased temperature for most solids and liquids. The solubility of gases usually decreases with increasing temperature. 2. pH. pH is a measure of the relative acid or base character of a solution (described in detail later). The solubility of many chemicals is a function of pH. Some chemicals, such as the multivalent salts of hydroxide and carbonate, are more soluble in acidic conditions. Other chemicals are soluble only over a neutral pH range, and still others (organic acids such as lignite and lignosulfonate) are more soluble as pH increases to >9.5. Calcium and magnesium ions are soluble at acid to neutral pH, but become less soluble at high pH, as shown for calcium in Figure 7. As the hydroxide ions increase with pH, they react with the calcium and magnesium to precipitate calcium hydroxide and magnesium hydroxide. Other compounds, such as carbonate and sulfide ions, change species with increasing pH. For instance, CO2, a gas, reacts with water to become carbonic acid at low pH. It will react with hydroxide to form bicarbonate ions in a neutral pH range and finally carbonate ions at high pH (see Figure 8). The solubility of many mud chemicals is a function of the pH of the solution. For instance, not only are lignite and lignosulfonate more soluble above pH 9.5, but products like DUO-VIS* (xanthan gum) are more effective in the 7 to 11 pH range. Other additives are sensitive to high pH. Products like POLY-PLUS* (PHPA) hydrolyze and become less effective at high pH (>10.5). Most individual mud products have an optimum pH range for maximum performance. Water-base drilling fluids are generally maintained in the 8 to 12 pH range for improved chemical solubility and performance, as well as for anti-corrosion and safety reasons. Mud engineers should familiarize themselves with these Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
Basic Chemistry
&#;in solution, the compound with the lowest solubility will precipitate first. ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
1,000 900 800 700 600 500 400 300 200 100 0
100 Ca(OH)2 added to NaOH solutions 68° F (20° C)
the left
HCO3-
0 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Caustic soda (lb/bbl)
HCO3-
60 Increasing salinity 40 shifts curves to 20
0
CO32 -
CO2
80 Percent
Filtrate calcium (mg/L)
4A
2
4
HCO36
8 pH
10
12
14
Figure 7: Decreasing solubility of calcium with increasing pH.
Figure 8: Carbonate-bicarbonate equilibrium.
ranges and maintain the drilling fluid system within the optimum pH range. 3. Ionic environment (salinity). Of particular importance to mud engineering is the chlorides concentration, or salinity. An increase in salinity generally increases the solubility of other salts and additives and will affect such chemical reactions as precipitation. For example, calcium sulfate (gypsum and anhydrite) has its greatest solubility in a 15% salt solution, wherein it is four times as soluble as it is in freshwater. This trend decreases as the salinity approaches saturation. Lime (calcium hydroxide) also is more soluble at moderate salinity. Even polymers, which are sensitive to precipitation by divalent cations and other conditions, are more stable in saline environments. The ionic environment of the solvent has a great impact on the chemical reactions that will take place and the stability of various products. 4. Pressure. An increase in pressure increases the solubility of a gas in a
liquid, but has practically no effect on the solubility of liquids and solids. This increased solubility of gas is particularly important when we consider the downhole chemical environment, where intruding or entrained gases are subjected to high pressure and may be solubilized. The importance of the relative solubility of chemicals is that in solution, the compound with the lowest solubility will precipitate first. For example, if calcium chloride (high solubility) were mixed into water, it would ionize into calcium and chloride ions. Then, if soda ash (moderately soluble) were added, it would ionize into sodium and carbonate ions, and calcium carbonate (low solubility) would precipitate immediately as the soluble calcium and soluble carbonate ions react. Relative solubility can be used to determine what chemical to add to remove an undesirable chemical. The other ions which are present in the solvent affect solubility.
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Revision No: A-2 / Revision Date: 12·31·06
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Basic Chemistry
pH and Alkalinity pH
The pH value is used to describe the acidity or basicity of solutions.
The (aq) indicates that the ions are dissolved in water, forming an aqueous solution.
The pH value is used to describe the acidity or basicity of solutions. The pH value is defined as the negative log of the hydrogen ion concentration. Low pH values correspond to increasing acidity and high pH values correspond to high basicity. A change of one pH unit corresponds to a ten-fold increase in hydrogen ion concentration. Water is a weak electrolyte which exists in nature as molecules of H2O. It can ionize to form hydronium (H3O+) and hydroxyl (OH&#;) ions. The ionization of water is statistically rare, with only one molecule in 556 million being ionized. Water is in equilibrium with the above ions according to the following equation: 2H2O H3O+ (aq) + OH&#; (aq) The (aq) indicates that the ions are dissolved in water, forming an aqueous solution. Since water ionizes itself, the process is called autoionization. This equilibrium with the hydronium and hydroxide ions provides the basis for the classification of acids and bases. Acids are substances that add hydrogen ions, (H+), when dissolved in water, increasing the hydronium concentration [H3O+]. The concentration for different ions is indicated by the chemical being shown in brackets, such as [H+] for the concentration of hydrogen ion. The equilibrium expression for the autoionization process is: Kw = [H+] [OH&#;] This type of equilibrium expression is used frequently to describe equilibrium conditions of related chemical species. The equilibrium constant is given the symbol Kw, where the subscript (w) refers to water. At 25°C, Kw = l.0 x 10&#;14,
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Kw depends on temperature (increases Kw) and ionic concentration of the solution (salinity). Kw, the product of [H+] and [OH&#;], remains constant providing the temperature is constant. In a neutral solution, the concentration of hydrogen [H+] is equal to the concentration of hydroxide [OH&#;]; therefore, each would have a concentration of 1.0 x 10&#;7, and the solution would have a pH of 7.0. If [H+] increases, the [OH&#;] decreases and the solution becomes more acidic. Likewise, if the [OH&#;] increases, then the [H+] must decrease and the solution becomes more basic. H+ (aq) and OH&#; (aq) ions are always present in aqueous solutions in equilibrium with the solvent. H+ (aq), and OH&#; (aq) can react with other ions, influencing the concentrations of other ions in the solution. For this reason, reference to the concentrations of H+ (aq) and OH&#; (aq) are made. To assist in this reference, the terms pH and pOH are defined as: pH = - log [H+] pOH = - log [OH&#;] A convenient relationship between pH and pOH is found by taking the negative logarithm (indicated by a p) of Kw, which gives: pKw = -log Kw = -log [H+] -log [OH&#;] Using the definitions of pH and pOH, given above, we find that at 25°C: pKw = pH + pOH since Kw = l.0 x 10 &#;14, then pKw = - log Kw = 14, which gives pH + pOH = 14 This relationship of acids and bases with values for pH and [H+] plus pOH and [OH&#;] is shown in Figure 9.
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Alkalinity is not the same as pH&#;
Basic Chemistry
pH 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14
[H+] 1 10&#;1 10&#;2 10&#;3 10&#;4 10&#;5 10&#;6 10&#;7 10&#;8 10&#;9 10&#;10 10&#;11 10&#;12 10&#;13 10&#;14
Acids
Neutral
Bases
[OH&#;] 10&#;14 10&#;13 10&#;12 10&#;11 10&#;10 10&#;9 10&#;8 10&#;7 10&#;6 10&#;5 10&#;4 10&#;3 10&#;2 10&#;1 1
pOH 14 13 12 11 10 9 8 7 6 5 4 3 2 1 0
removed from the solution, and the pH remains neutral. Again, if the salt contains the cation of a strong base and the anion of a strong acid, the solution will remain neutral. However, if the salt contains the cation of a strong base and the anion of a weak acid, its solution will be basic (increasing pH), as is the case with Na2CO3 (soda ash). Conversely, if the salt contains the cation of a weak base and the anion of a strong acid, its solution will be acidic (decreasing pH). Naturally, if an acid is added, the pH would decrease, whereas the pH would increase if a base were added to a neutral solution.
Figure 9: pH scale, acids and bases.
Note that low pH values correspond to acids and low pOH values correspond to basic solutions. A change of one pH or pOH unit corresponds to a change in molar concentration by a factor of 10. A solution with a pH of 2 is not twice as acidic as a solution with a pH of 4; it is 100 times as acidic as a solution with a pH of 4. Remember, the value of Kw changes with temperature and ionic concentration (salinity) so that pH values measured with an electronic pH probe may not be valid unless the instrument (meter or probe) and measurement are compensated for the temperature of the liquid and the salinity of the fluid. High-salinity pH measurements may require the use of a special &#;saltcompensated&#; pH probe. As discussed previously in regard to salts, when NaCl (a neutral salt formed by the combination of a strong acid and a strong base) is dissolved in water, the Na+ ions do not combine with OH&#; ions (to reduce pH), because NaOH is a strong base. Likewise, the Cl&#; ions do not combine with H+ ions (to increase pH) because HCl is a strong acid. As a result, neither H+ ions nor OH&#; ions is
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ALKALINITY Alkalinity titrations determine OH&#;, HCO3&#; and CO32&#; concentrations by measuring the amount of acid required to reduce pH. Borates, silicates, phosphates, sulfates and organic acids (like lignite) also can enter into the titration and/or treatment calculations based on alkalinity values. Alkalinity is the combining power of a base measured by the quantity of acid which can react to form a salt. In mud engineering, phenolphthalein alkalinity (P) is reported as the number of milliliters of 0.02 N H2SO4 (water-base muds) required to titrate a milliliter of filtrate (Pf) or mud (Pm), reducing the pH to 8.3. The methyl orange filtrate alkalinity (Mf) measures the acid required to reduce pH to 4.3. Alkalinity is not the same as pH, although their values usually trend in the same direction. A strong base, such as Caustic Soda, added to pure water would show this correlation between alkalinity titration values and pH, as shown in Table 7; however, due to the presence of HCO3&#;, CO32&#; &#; as well as calcium and magnesium &#; in oilfield waters and drilling fluids, no correlation should be made.
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Basic Chemistry
pH 7 8 9 10 11 12 13 14
NaOH (lb/bbl) 0. 0. 0. 0. 0.014 0.14 1.4 14
Pf OH&#; (cc 0.02N H2SO4) (ppm) 0. 0. 0. 0.017 0. 0.17 0.005 1.7 0.05 17 0.5 170 5 1,700 50 17,000
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Table 7: Relationship of pH and alkalinity for pure water.
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This table shows how small concentrations of caustic soda (NaOH) in pure water cause relatively high pH values and filtrate alkalinity. To observe the effect of a more complex ionic environment, compare the higher amount of caustic required to increase pH in seawater as shown later in Figure 10. Alkalinity measurements (Pf, Mf and other values) are used to calculate
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hydroxyl, bicarbonate and carbonate concentrations as described in API 13B-1, Section 8, Table 8.1, and in the Testing chapter. Because the Mf value can be an unreliable indication of bicarbonate contamination if organic acids or organic salts (like lignite or acetate) are used, an alternative procedure uses a pH measurement and the Pf value to calculate the carbonate and bicarbonate concentration. These calculations help monitor and diagnose carbon dioxide, bicarbonate and carbonate contamination. In addition, these values give the mud engineer a more thorough understanding of the ionic and buffering environment of the mud system, far beyond what can be learned from a pH value alone.
Acids, Bases and Salts
All acids contain hydrogen.
Acids can be described as substances which have a sour taste, cause effervescence in contact with carbonates, turn blue litmus red and react with bases, alkalis, and certain metals to form salts. All acids contain hydrogen. Acids are termed as &#;strong&#; or &#;weak,&#; according to the concentration of hydrogen ion (H+) that results from ionization. Bases can be described as having a bitter taste, a &#;slippery&#; feeling in solution, an ability to turn red litmus paper blue, and an ability to react with acids to form salts. Bases do not cause effervescence in contact with carbonates. Acids react with bases to form salts. A base is termed strong or weak, depending on the quantity of the molecule which disassociates into hydroxyl ions (OH&#;) in solution.
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Both acids and bases can be either strong or weak, depending on the elements in the compound and their valence. Salts are simply combinations of the anion (negative ion) from an acid and the cation (positive ion) from a base. A salt may be neutral or have a tendency toward the acid or base side, depending on the relative strengths of the respective ions or groups. As discussed previously, the combination of a weak acid and a strong base forms an alkaline salt, while the combination of a strong acid with a weak base forms an acidic salt, and the combination of a strong acid with a strong base forms a neutral salt. Table 8 is a list of the most common acids, bases and salts that are used in drilling fluids.
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Basic Chemistry
Chemical Name Hydrochloric acid Sulfuric acid Nitric acid Phosphoric acid Carbonic acid Citric acid Sodium hydroxide Potassium hydroxide Magnesium hydroxide Sodium carbonate Calcium hydroxide Calcium oxide Sodium chloride Potassium chloride Calcium chloride Calcium sulfate
Common Name Muriatic acid &#; Aqua fortis Orthophosphoric Soda (sparkling) &#; Caustic soda Caustic potash Magnesium hydrate Soda ash Slaked lime Quicklime Rock salt Potash (muriate of) &#; Anhydrite (gyp)
Formula HCl H2SO4 HNO3 H3PO4 H2CO3 H3C6H5O7 NaOH KOH Mg(OH)2 Na2CO3 Ca(OH)2 CaO NaCl KCl CaCl2 CaSO4 ( &#; 2H2O )
Type Acid (strong) Acid (strong) Acid (strong) Acid (mod. weak) Acid (weak) Acid (weak) Base (strong) Base (strong) Base Base (weak) Base (strong) Base (strong) Salt Salt Salt Salt
Table 8: Common acids, bases and salts.
BUFFER
Many oilfield liquids and mud-treating chemicals are buffered solutions.
SOLUTIONS
Certain solutions called buffer solutions resist large pH changes when a base or acid is added to a solution. Many oilfield liquids and mud-treating chemicals are buffered solutions. Buffer solutions generally consist of either a weak acid and a salt that contain the same anion or a weak base and a salt that contain the same cation. The buffering action of a solution consisting of a weak acid plus a salt of the acid comes about because: (1) added base reacts with the weak acid to form more of the common ion and (2) added acid reacts with the common ion to produce the weak acid. An example of a weak acid is carbonic acid (H2CO3). An example of a weak base is ammonium hydroxide (NH4OH). If a small amount of strong acid, such as HCl, is added to pure water or to a dilute solution of acid in water, the hydrogen ion concentration (pH) of the water or solution is noticeably increased. If the same small amount of acid is instead added to a buffered
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solution of a weak acid and the soluble salt of that acid, the increase in hydrogen ion concentration (pH) is so slight that for all practical purposes it is negligible. The anions of the salt of the weak acid have taken the H+ ions as fast as they were added and have reacted with them to form more of the weak acid. The net result is that the hydrogen ion concentration has changed only very slightly; and the pH is little changed. This phenomenon can take place very easily when the mud engineer is titrating (with an acid) the alkalinity endpoints. In fluids with high carbonates, bicarbonates and hydroxides, as soon as carbonates are converted to bicarbonates, a buffer solution begins to develop which resists changes in pH. Triethanolamine, lime and magnesium oxide are all chemicals used to buffer pH-sensitive mud systems. Buffering can be highly beneficial to maintain stable fluid properties and to resist the detrimental effects of various contaminants.
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Basic Chemistry
ELECTROLYTE
All solutions of ionic compounds are electrolytes.
Substances whose water solutions conduct electricity are called electrolytes and contain both positive and negative ions. All solutions of ionic compounds are electrolytes. All acids, bases and salts are electrolytes. Electrovalent compounds are formed by transfer of electrons (ionic bonds); in the process, positive and negative ions are produced. The resulting solid compounds (salts and hydroxides) all have an ionic crystal lattice structure. This means that, in the case of these electrovalent compounds, the ions are formed when the compound is formed. They exist before the compound is dissolved in water. When such a compound is dissolved, the ionic crystal lattice is broken down and the ions disassociate in solution; the water merely acts as a solvent. Typical equations to illustrate the disassociation of these already existing ions are: Salt: NaCl = Na+ + Cl&#; (as shown in Figure 6) Lime: Ca(OH)2 = Ca2+ + 2OH&#;
Since the ability of a solution to conduct electricity is dependent upon the presence of ions, it can be concluded that solutions that are excellent conductors contain high concentrations of ions (completely ionized), while solutions that are poor conductors contain low concentrations of ions (not completely ionized). Electrolytes that are completely ionized are called strong electrolytes, whereas those that are not completely ionized are called weak electrolytes. With very few exceptions, salts are strong electrolytes. Most hydroxides (except Mg2+) are strong electrolytes and accordingly classified as strong bases. Acids such as HCl, H2SO4 and HNO3 are strong electrolytes and, therefore, are classified as strong acids; most others are moderately weak and are classified as weak acids. Pure water is a weak electrolyte, and not as conductive as salt solutions.
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Osmosis is a phenomenon that takes place when two solutions of greatly different solute concentration (salinity) are separated by a semi-permeable membrane. During osmosis, there is a net movement of solvent (water) through the membrane from the solution with a lower solute concentration (lower salinity) to the solution with the higher solute concentration (higher salinity). Therefore, osmosis will tend to transfer solvent until the two solutions have a similar solute concentration (salinity). The driving forces in this process are the difference in solute concentration and the character of the semi-permeable membrane.
The &#;activity&#; of a solution is a measure of the vapor pressure or &#;relative humidity&#; and is related to solute concentration (salinity). Water would have an activity of 1.0; higher salinity reduces activity. In drilling water-sensitive shales, it is desirable for the drilling fluid and formation to have a similar activity to minimize the transfer of water from the drilling fluid to the formation. Oiland synthetic-base fluids have the potential to transfer water from their emulsified water phase (usually calcium chloride brine) if its activity is higher than the activity of the formation through osmosis.
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Revision No: A-1 / Revision Date: 02·28·01
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Basic Chemistry
Titrations The chemical tests made in mud analyses are called titrations.
Chemicals used to determine the endpoint in titrating are called indicators.
The chemical tests made in mud analyses are called titrations. Titrations are procedures which use standard solutions of a known concentration (N1) to determine the unknown concentration (N2) of a sample of known volume (V2). The basic equation involving this quantitative analysis is: V2 x N2 = V1 x N1 Solving this equation for N2 gives the following: V N2 = 1 x N1 V2 For a known sample volume (V2), using an indicator and titrating with a solution of known concentration (N1), it is possible to determine the unknown concentration (N2) of the sample by measuring the volume (V1) required to reach the endpoint. Proper procedures are outlined in the Testing chapter for quantitative measurements using standard solutions for determining the Indicator Phenolphthalein Methyl orange/ brom cresol green Methyl orange Brom cresol green Thymolphthalein
important chemicals. Care should be exercised to follow the exact procedure. Formulas are also provided which will enable the engineer to make the necessary calculations without having to convert units.
INDICATORS Chemicals used to determine the endpoint in titrating are called indicators. Indicators are compounds that change color with either a change in pH or a change in chemical concentration. The color changes of acid-base indicators do so at a specific pH value. Different indicators change color in acidic, neutral or basic pH conditions. Chemical indicators are used which change color in the presence of calcium, magnesium chlorides and bromides. Table 9 lists the most common indicators used in mud analysis with the titrating chemical used and the color change the indicator undergoes at a specific condition.
Original Color Pink/red: pH >8.3 Green: pH >4.3
Color Change Colorless: pH 3.8 Colorless: pH 10) Ca2+ + 2NaOH &#; Ca(OH)2&#; + 2Na+ (pH >11) Caustic soda is used to reduce the magnesium and calcium in seawater by first precipitating magnesium as Mg(OH)2, and then increasing pH to suppress the solubility of calcium and precipitate lime. If lime is used in seawater it, too, will remove magnesium, but the resulting calcium levels will be very high and are undesirable. Gulf of Mexico seawater requires 1.5 to 2 lb/bbl caustic soda (4.3 to 5.7 kg/m3) to precipitate all magnesium, then convert the
calcium to lime, resulting in a pH >11.0 (see Figure 10). In seawater, the preferred treatment for magnesium removal is caustic, while the preferred treatment for calcium removal is soda ash.
10
Mg removed &#; Ca begins to convert to Ca(OH)2
9
Magnesium begins to precipitate as Mg (OH)2
8
7
0
0.5
1.0 1.5 2.0 Caustic soda (lb/bbl) Seawater: pH 8.0, 390 mg/L Ca, 1,300 mg/L Mg, 19,000 mg/L Cl
2.5
Figure 10: pH vs. caustic soda for seawater. Basic Chemistry
4A.27
Revision No: A-3 / Revision Date: 02·01·09
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Basic Chemistry
CARBONATE AND BICARBONATE CONTAMINATION
&#;H2S should always be precipitated with a source of zinc&#;
Bicarbonate (HCO3&#;) and carbonate (CO32&#;) contamination can occur through the conversion of CO2 gas, mentioned above, or from the thermal degradation of organic additives such as lignite and lignosulfonate and from biodegradation of starch and other additives, among other sources. These ions can be removed with calcium. However, since calcium bicarbonate Ca(HCO3)2 is soluble, all bicarbonates must be converted into carbonates (above a pH of about 11) before they can be completely precipitated as calcium carbonate. The removal of bicarbonates and carbonates can be achieved with any source of soluble calcium under conditions of constant pH (if pH is high enough) or by increasing the pH with caustic soda in the presence of calcium. Lime (Ca(OH)2) is preferred for converting HCO3&#; to CO32&#; and then precipitating the carbonates as CaCO3, especially if the system pH will not be elevated to >11. 2HCO3&#; + Ca(OH)2 &#; CaCO3&#; + OH&#; + H2O CO32&#; + Ca(OH)2 &#; CaCO3&#; + 2OH&#; When a constant pH value must be maintained, a combination of gyp and lime treatments is required: Ca(OH)2 + 2HCO3&#; &#; CaCO3&#; + CO32&#; + 2H2O CaSO4 &#; 2H2O + CO32&#; &#; CaCO3&#; + SO42&#; + 2H2O
HYDROGEN SULFIDE (H2S) CONTAMINATION
Hydrogen sulfide is a poisonous and dangerous acidic gas&#;
Hydrogen sulfide is a poisonous and dangerous acidic gas encountered in many formations and produced fluids. It can quickly deaden senses and can be fatal even at low concentrations. H2S is characterized by its typical &#;rotten egg&#; smell. For safety reasons, it should be neutralized immediately with caustic
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soda or lime to increase the pH to >11.5 to form sulfide (S2&#;), then precipitated with a source of zinc. Neutralization with caustic soda: 2NaOH + H2S 2Na+ + S2&#; + 2H2O (at pH >11.5) Neutralization with maintaining excess lime: H2S + Ca(OH)2 &#; Ca2+ + S2&#; + 2H2O (pH >11.5) Converting hydrogen sulfide into just sulfide by increasing pH is not a permanent reaction. If the pH were to drop into the acid region, sulfide will convert back into the poisonous hydrogen sulfide form. For this reason, H2S should always be precipitated with a source of zinc, such as zinc oxide. Removal by precipitation with treatments of zinc oxide (ZnO): H2S + ZnO &#; ZnS&#; + H2O
REMOVAL OF OXYGEN WITH OXYGEN SCAVENGER Dissolved oxygen will cause increased corrosion and can be removed with treatments of a chemical containing sulfite. Liquid ammonium bisulfite solutions are the most common oxygen scavengers and react with oxygen as follows: NH4HSO3 + 1&#;2 O2 + OH&#; &#; NH4 + SO3 + H2O; SO3 + 1&#;2 O2 &#; SO42&#; Soluble calcium may react to form calcium sulfite, which has a maximum solubility of about 43 mg/L in cold water and less in hot water. The sulfite residual at the flow line should not be expected to exceed this level if the mud contains high levels of calcium.
ACID
TREATMENTS
The filter cakes containing acid-soluble weight materials, such as calcium carbonate used for non-damaging reservoir drill-in fluids, are often removed from the well with hydrochloric acid treatments.
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Basic Chemistry
Calcium carbonate dissolution using hydrochloric acid: CaCO3 + 2HCl &#; CaCl2 + CO2&#; + H2O
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PHOSPHATES
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Sodium Acid Pyrophosphate (SAPP) and other phosphates will react with and precipitate calcium according to the following reaction: Na2H2P2O7 + H2O &#; 2NaH2PO4; 2NaH2PO4 + 3Ca(OH)2 &#; Ca3 (PO4)2&#; + 4H2O +2NaOH Although the reaction has caustic as a byproduct, pH is still reduced, since SAPP is a weak acid and the reaction leaves only two hydroxyl groups for every six original hydroxyl groups.
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EFFECT
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OF LIGNITE ON CALCIUM
Lignite contains calcium (from 1.5 to 5%) as part of its chemical makeup. Organic acids like lignite also have the ability to tie up calcium chemically. This complexed calcium exists as a solid particulate (flock) and may not be large
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enough to be removed by mechanical means. The filter cake will filter out most of the calcium complexed with the lignite. However, some lignitecomplexed calcium will pass through the filter cake and paper so that it will be collected with the filtrate. During the titration of filtrate calcium, the readily available calcium is titrated first. As the titration continues, the complexed calcium solubilizes and this, too, will be titrated. This complexed calcium is not available for chemical reactions in mud systems. One lb/bbl of solubilized lignite has the potential to complex 200 mg/L calcium. Keep in mind that although the calcium titration may show a sufficient excess of calcium, none may be available to react with carbonate and bicarbonate groups. So, it may be possible to be experiencing a carbonate problem even though some calcium is titrated in the filtrate when using lignite as an additive.
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Clay Chemistry
Introduction
&#;it is necessary to understand basic clay chemistry in order to properly control water-base muds.
&#;clay minerals&#; are used to provide viscosity, gel structure and fluid-loss control.
A thorough understanding of clays can be the mud engineer&#;s most valuable tool. Clay may be added intentionally, such as M-I GEL*, or it may enter the mud as a major contaminant through dispersion of drill solids. In either case, it becomes an active part of the system. For this reason, it is necessary to understand basic clay chemistry in order to properly control water-base muds. Clay chemistry is also important with regard to interactions between waterbase muds and shales which affect wellbore stability. Clay is a broad term commonly used to describe sediments, soils or rocks consisting of extremely fine-grained mineral particles and organic matter. A good example is the clays (or sometimes called gumbo clays) found in the backyard or along riverbanks. These clays are often soft and plastic when wet, but become hard when dry. This &#;soft when wet, hard when dry&#; physical property can be related to the presence of certain clay minerals. Clay is also used as a group term for particles with a size less than 2 microns in diameter, which includes most of the clay minerals. Clay minerals are fine-grained aluminum silicate minerals having well-defined microstructures. In mineralogical classification, clay minerals are classified as layered silicates because the dominant structure consists of layers formed by sheets of silica and alumina. Each sheet is a thin, plate-like structure and is called a unit layer. A typical layered silicate mineral, for example, is mica or vermiculite, which can be split into thin layers along the cleavage planes. Most clay minerals are platy in morphology. Depending on the repeating units of the structure,
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clay minerals can be further classified as to the ratio of silica to alumina layers such as 1:1, 2:1 and 2:2, as well as according to whether they are layered or needle-shaped clay minerals. In the drilling fluids industry, certain clay minerals such as smectite, a major component of bentonite, are used to provide viscosity, gel structure and fluid-loss control. Formation clays are unavoidably incorporated into the drilling fluid system during drilling operations and they may cause various problems. Thus, clay minerals can be beneficial or harmful to the fluid system. The term bentonite is used for commercially-mined sodium montmorillonite (which is a form of smectite) that is used as an additive for drilling mud (i.e. M-I GEL or M-I GEL SUPREME*). Geologically, bentonite is a bed of altered volcanic ash. One of the biggest deposits of this volcanic ash occurred over 60 million years ago in areas of North America now known as the Blacks Hills of Wyoming and South Dakota, and the Big Horn Mountains of Wyoming. Bentonite clay mined in Wyoming actually comes from this volcanically deposited bentonite bed. Bentonite clay mined in other areas of the world may be from other types of geological deposits. Because of their small particle sizes, clays and clay minerals are analyzed with special techniques such as x-ray diffraction, infrared absorption and electron microscopy. Cation Exchange Capacity (CEC), water adsorption and surface area are some of the properties of clay minerals that are often determined in order to better characterize clay minerals as well as to minimize drilling problems.
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Clay Chemistry
Types of Clays
Clays exist in nature with a stacked or layered structure&#;
Separating these packs into multiple layers is known as dispersion.
There are a large number of clay minerals, but those with which we are concerned in drilling fluids can be categorized into three types. The first type are needle-shaped, non-swelling clays like attapulgite or sepiolite. It is believed that the shape of the particles is responsible for the clay&#;s ability to build viscosity. The natural fine crystal size and needle shape causes it to build a &#;brush heap&#; structure in suspension and thereby exhibit high colloidal stability even in the presence of high electrolyte concentration. Owing to their shape and non-swelling characteristics, these clays exhibit very poor filtration control. For this reason, attapulgite is primarily used as a viscosity builder in saltwater muds and sepiolite is most often used as a supplemental viscosifier for geothermal and high-temperature fluids. These clays are rarely, if ever, present in formation shales. M-I SWACO sells attapulgite under the name SALT GEL* and sepiolite under the name DUROGEL*. The second type are the plate-like, non-swelling (or slightly swelling) clays: illite, chlorite and kaolinite, discussed later. The third type are the plate-like, highly swelling montmorillonites. The second and third types of clay minerals are found in formation shales in the following order in decreasing amounts: (1) illite, (2) chlorite, (3) montmorillonite and (4) kaolinite. Because these clays are present in drilled formations, they become dispersed in the drilling fluid system in varying amounts. The montmorillonite in shales is usually calcium montmorillonite since it is in equilibrium with the formation water, which is normally rich in calcium.
Clay Chemistry
4B.2
Sodium montmorillonite (Wyoming bentonite, M-I GEL and M-I GEL SUPREME) is also normally added to a mud to increase viscosity and reduce fluid loss. The filtration and rheological properties of the mud become a function of the amounts of various clays contained in the mud. Since the montmorillonite is intentionally added to a mud to control these properties, the other clay types may be considered contaminants, as they are not as effective as a commercial clay. Clays exist in nature with a stacked or layered structure, with each unit layer roughly 10 angstroms (Å) thick. This means there are about a million layers of clay per millimeter of thickness. Each clay layer is highly flexible, very thin and has a huge surface area. An individual clay particle can be thought of as being much like a sheet of paper or a piece of cellophane. One gram of sodium montmorillonite has a total layer surface area of 8,073 ft2 (750 m2)! In freshwater, the layers adsorb water and swell to the point where the forces holding them together become weakened and individual layers can be separated from the packs. Separating these packs into multiple layers is known as dispersion. This increase in number of particles, with the resulting increase in surface area, causes the suspension to thicken. Figure 1 is an actual photomicrograph of a bentonite particle. Note that it resembles a fanned-out deck of cards. Several of the plate-like particles can be seen overlapping each other. It is this characteristic shape of the particles that produces the so-called &#;shingling&#; effect that is so important to fluid-loss control.
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CHAPTER
4B
Clay Chemistry
2µ
2µ
ca Sili a min Alu ca Sili
Tetrahedral Octahedral Tetrahedral
One unit layer
10 Å
Figure 2: Idealized montmorillonite particle.
sheets. Three-layer clays are built of unit layers composed of two tetrahedral sheets on either side of one octahedral sheet, somewhat like a sandwich (see Figure 2). Two-layer clays are built of unit layers consisting of only one tetrahedral and one octrahedral sheet. Clays can either be electrically neutral or negatively charged. For example, pyrophyllite [Al2Si4O10 &#; (OH)2], a neutral clay, as shown in Figure 3, is similar to the negatively charged montmorillonite.
Figure 1: Photomicrograph of bentonite particles.
Clays can either be electrically neutral or negatively charged.
Clays are usually either of the twolayer type like kaolin or three-layer type such as montmorillonite, chlorite or illite. Each plate-like clay particle consists of a stack of parallel unit layers. Each unit layer is a combination of tetrahedrical (pyramid) arranged silica sheets and octahedrical (eightfaced) arranged alumina or magnesia
All surface charges balance
&#;
O
&#;
O
O
Si O
+
&#;
O
O
Si
Si
O
O
+
Al
O
O
Si +
Si O
&#;
+
O
O
Si
Si
O
O
OH
OH Al
O
O
Al OH
O
Si O
+
Al OH
Si O
&#;
+
O
Si
O
O
O
O
Si +
O
O
O
+
+
O O
Silica layer
O Al
Si O
+ Si
Al OH
Si O
O
OH
Al
O
O
Si OH
Al
O
O
Si O
OH O
&#;
Alumina layer
Silica layer
Figure 3: Electrically neutral pyrophyllite.
Clay Chemistry
4B.3
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CHAPTER
4B
Clay Chemistry
MONTMORILLONITE CLAYS (THREE-LAYER CLAYS) ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
If just one atom of magnesium (Mg2+) is substituted for one atom of aluminum (Al3+) in the lattice structure (arrangement of atoms), it will then possess a surplus electron or negative charge (see Figure 4). The net negative charge is compensated by the adsorption of cations (positive ions) on the unit layer surfaces, both on the interior and on the exterior surfaces of the stack. The cations that are adsorbed on the unit-layer surfaces may be exchanged for other cations and are called the exchangeable cations of the clay. The quantity of cations per unit weight of the clay is measured and reported as the CEC. The cation may be a singlecharge ion such as sodium (Na+) or a double-charge ion such as calcium (Ca2+) or magnesium (Mg2+). Thus, we have sodium montmorillonite, calcium montmorillonite and/or magnesium montmorillonite. Although Wyoming bentonite is generally described as sodium montmorillonite, the exchangeable calcium and magnesium may constitute 35 to 67% of the total exchange capacity. The most typical property of montmorillonites is that of interlayer swelling (hydrating) with water (see Figures 5 and 6). Na+
&#;
O
&#;
O
O
Si O
+
O
Si
Si
O
O
Mg
O
+
Si +
O
Al OH
Si O
O
+
&#;
O
O
Si
Si
O
O
O
O
O
Si O
+
+
&#;
O
Si
Al OH
Si O
O
Na+
O
O
O Si +
O
O
Mg
Al
O
O
O
OH
O
+
+
O O
Silica layer
O Al
Si O
+ Si
OH
Si O
O Si
OH Al
CLAYS)
Illites have the same basic structure as montmorillonites, but they do not show interlayer swelling. Instead of the substitution of Mg2+ for Al3+ as in montmorillonite, illite has a substitution of Al3+ for Si4+, still giving a negative charge. The compensating cations are primarily the potassium ion (K+), as shown in Figure 6. The net negative lattice charge that results from these substitutions, by compensating potassium ions, is usually larger than that of montmorillonite by as much as one and a half times.
OH
OH Al
ILLITES (THREE-LAYER
Surface-bonded cations Surplus negative charges
&#;
O
In addition to the substitution of magnesium (Mg2+) for aluminum (Al3+) in the montmorillonite lattice, many other substitutions are possible. Thus, the name montmorillonite often is used as a group name including many specific mineral structures. However, in recent years, the name smectite has become widely accepted as the group name, and the term montmorillonite has been reserved for predominantly aluminous members of the group. This group of minerals includes montmorillonite, hectorite, saponite, nontronite and a number of other specific minerals.
Si O
OH O
&#;
Alumina layer
Silica layer
Figure 4: Substitution of Mg 2+ for Al 3+ causing a negative-charged particle.
Clay Chemistry
4B.4
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CHAPTER
4B
Clay Chemistry
Tetrahedral alumina
OH
Octahedral silica OH
Interlayer distance
OH
Tetrahedral alumina
Exchangeable cations nH2O (adsorbed water)
Swelling
Next unit layer tetrahedral alumina
Oxygens and
OH
Hydroxyls
Aluminum, iron, magnesium
Silicon, ocassionally aluminum
Figure 5: Structure of smectite.
Only the potassium ions on the external surfaces can be exchanged for other cations.
The spacing between unit layers is 2.8 Å. The ionic diameter of the K+ is 2.66 Å. This allows the K+ to fit snugly between unit layers forming a bond that prevents swelling in the presence of water. Since the unit layers do not swell and separate when exposed to water, the potassium ions (K+) between the unit layers are not available for exchange. Only the potassium ions on the external surfaces can be exchanged for other cations. Among the 2:1 clay minerals, smectite, illite, and mixed layers of illite and smectite are encountered during drilling
Clay Chemistry
4B.5
shale formations and often cause various problems in borehole stability and drilling fluid maintenance. The troublesome nature of these clay minerals can be related to the weakly-bonded interlayer cations and weak layer charges that lead to swelling and dispersion upon contact with water. With increasing burial depths, the smectite gradually converts into illite/smectite mixed-layer clays and finally to illite and mica. As a result, shale formations generally become less swelling but more dispersive in water with increasing depth.
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4B
Clay Chemistry
CHLORITES (THREE-LAYER
Kaolinite does not contain interlayer cations or surface charges&#;
CLAYS)
Chlorites are structurally related to the three-layer clays. In their pure form they will not swell, but they can be made to swell slightly with alteration. In these clays, the charge-compensating cations between montmorillonitetype unit layers are replaced by a layer of octahedral magnesium hydroxide, or brucite (see Figure 6). This layer has a net positive charge because of some replacement of Mg2+ by Al3+ in the brucite layer. Chlorite is often found in old, deeply buried marine sediments and normally does not cause significant problems unless present in large quantities. The cation exchange capacity of chlorite varies from 10 to 20 meq/100 g, primarily due to broken bonds. The interlayer distance of chlorite is usually about 14 Å. Chlorite also may form mixedlayer clays with other clay minerals such as smectite. The resultant mixedlayer clay would have the properties of both types of clay minerals.
KAOLINITES (TWO-LAYER
CLAYS)
Kaolinite is a non-swelling clay that has its unit layers bound tightly together by hydrogen bonding. This prevents expansion of the particle because water is unable to penetrate the layers. Kaolinite does not contain interlayer cations or surface charges because there is little or no substitution in either tetrahedral or octahedral sheets. However, some minor charges can come from broken bonds or impurities. Therefore, kaolinite has a relatively low cation exchange capacity (5 to 15 meq/100 g). Kaolinite is commonly found as a minor to moderate constituent (5 to 20%) in sedimentary rocks such as shales and sandstones. A summary of clay minerals is shown in Table 1 and a schematic comparison of the various clay structures shown in Figure 6.
Group Kaolinite Talc Smectite Vermiculite
Structure 1:1 layer 2:1 layer 2:1 layer 2:1 layer
Charge Nil Nil 0.3 - 0.6 1.0 - 4.0
Exchange Cation None None Na+, Ca2+, K+, Mg2+ K+, Mg2+
Illite Mica Chlorite Sepiolite Palygorskite
2:1 layer 2:1 layer 2:2 layer 2:1 chain 2:1 chain
1.3 - 2.0 2.0 Variable Nil Minor
K+ K+ Brucite layer None None
Interatomic Distance (Å) 7.2 9.3 11 - 15 14 - 15
Swelling None None Variable Variable
10 10 14 12 10.5
Nil None Nil Nil Nil
Table 1: Commonly encountered clays.
Clay Chemistry
4B.6
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CHAPTER
4B
Clay Chemistry
H2O
H2O
H2O
H2O
Mg(OH)2
KK
H2O
KK H2O
H2O 1 crystal
Mg(OH)2 1 crystal
H2O H2O
Mg(OH)2
H2O Sepiolite Needle-shaped clay
Mg(OH)2
KK
1 crystal
KK
H2O
H2O
KK
Mg(OH)2
H2O
H2O
1 crystal
H2O Kaolinite
H2O Chlorite (Mg(OH)2 = brucite sheet)
KK
H2O Illite (K = potassium)
Plate-like, non-swelling clays 1 crystal
1 crystal H2O
b
H2O
1 crystal H2O H2O
1 crystal a
Mg(OH)2
KK
c
1 crystal H2O
H2O
H2O
Chlorite type
Illite type
H2O
&#;a&#; Has the properties of chlorite &#;b&#; Has the properties of montmorillonite &#;c&#; Has the properties of illite
H2O Montmorillonite Plate-like, swelling clays
Mixed-layer clays
Figure 6: Clay structure comparison.
Cation Exchange Capacity (CEC)
The quantity of cations per unit weight of clay is&#; the CEC.
The compensating cations that are adsorbed on the unit-layer surface may be exchanged for other cations and are called the exchangeable cations of the clay. The quantity of cations per unit weight of clay is measured and reported as the CEC. The CEC is expressed in millequivalents per 100 g of dry clay (meq/100 g). The CEC of montmorillonites is within the range of 80 to 150 meq/100 g of dry clay. The CEC of illites and chlorites is about 10 to 40 meq/100 g, and for kaolinites it is about 3 to 10 meq/100 g of clay. The Methylene Blue Test (MBT) is an indicator of the apparent CEC of a clay. Clay Chemistry
4B.7
When this test is run on a mud, the total methylene blue exchange capacity of all the clay minerals present in the mud is measured. It is normal procedure to report the Methylene Blue Capacity (MBC) as the equivalent amount of Wyoming bentonite required to obtain this same capacity. It is important to note that the test does not directly indicate the amount of bentonite present. However, an estimate of the amount of bentonite and solids in the mud can be calculated if one considers that the average drill solids have about 1/9 the CEC of bentonite, and if the amount of drill solids Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4B
&#;any cation to the left will replace any cation to its right.
Clay Chemistry
present in the mud is calculated from a retort analysis. This estimation of the quantity of added bentonite and drill solids can be made more exact by measuring the MBC of the drill cuttings. This procedure can be helpful in estimating both the amount and quality of the clays in the mud. In order to have some idea of which cations will replace other cations in the exchange positions, the following is generally accepted and is arranged in decreasing preference: H+ > Al3+ > Ca2+ > Mg2+ > K+ > NH4+ > Na+ > Li+ In other words, any cation to the left will replace any cation to its right.
The relative concentration of each cation also affects this cation-exchange preference. Even though calcium is more difficult to replace than sodium, if the ionic concentration of Na+ is significantly higher than Ca2+, then sodium will displace calcium. Cation exchange may result from a change in temperature since many compounds have different solubility-to-temperature relationships. Some of the common calcium salts, such as CaSO4, decrease in solubility at high temperatures while most sodium compounds increase in solubility. As the Na+/Ca2+ concentration increases, there is a tendency for the Ca2+ on the clay to be replaced by Na+ from solution.
Composition of Clay-Water Muds In most areas, commercial clays&#;are added to water when preparing a water-base mud.
In most areas, commercial clays, such as M-I GEL and M-I GEL SUPREME, are added to water when preparing a waterbase mud. The clays serve a dual purpose: (1) to give viscosity to the drilling fluid, and (2) to deposit a filter cake that will seal permeable formations in order to limit filtration losses and prevent stuck pipe. In some areas, drilling can be performed starting with water and allowing the drill solids to be incorporated, resulting in sufficient properties to allow the well to be drilled. In other situations, polymer-base systems are used where no clays are added to the formulation. Clay-water muds have water as the liquid continuous phase in which certain materials are held in suspension and other materials dissolved. Numerous mud additives are used to obtain special properties but, basically, all components can be divided into three categories. 1. The water phase is the continuous phase of the mud. Depending on location and/or available water,
Clay Chemistry
4B.8
this may be freshwater, seawater, hard water, soft water, etc. It is not uncommon to use a variety of brine solutions from salty up to saturation as the base liquid to build a water-base system. 2. The reactive-solids phase is composed of commercial clays, incorporated hydratable clays and shales from drilled formations that are held in suspension in the fluid phase. These solids are treated chemically to control the properties of the drilling fluid. Various additives will be used to obtain desirable properties. 3. Inert solids refer to those solids in suspension that are chemically inactive. These may be inert drill solids such as limestone, dolomite or sand. Barite is added to the drilling fluid to increase the fluid density and is also an inert solid. The remainder of this chapter will discuss the behavior of the reactive solids in the water phase and how this affects mud properties. Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
Clay Chemistry
HYDRATION
The thickness of the adsorbedwater film is controlled by the type and amount of cations&#;
OF CLAYS
The bentonite crystal consists of three layers: an alumina layer with a silica layer above and below it. The clay platelet is negatively charged and has a cloud of cations associated with it. If a significant amount of these cations are sodium, the clay is often called sodium montmorillonite. If they are primarily calcium, then the clay is called calcium montmorillonite. Depending on the cations present, the interlayer spacing of dry montmorillonite will be between 9.8 (sodium) and 12.1 Å (calcium) and filled with tightly bound water. When dry clay contacts freshwater, the interlayer spacing expands, and the clay adsorbs a large &#;envelope&#; of water. These two
phenomena allow clays to generate viscosity. As shown in Figure 7, calcium-base bentonites only expand to 17 Å, while sodium bentonite expands to 40 Å. The thickness of the adsorbed-water film is controlled by the type and amount of cations associated with the clay. Water adsorbed to the large, flat, planar surfaces comprises the major part of the total water retained by hydratable clays. Divalent cations such as Ca2+ and Mg2+ increase the attractive force between platelets, thus decreasing the amount of water that can be adsorbed. Monovalent cations such as Na+ give rise to a lesser attractive force and allow more water to penetrate between the platelets. Calcium montmorillonite
Ca2+
17 Å Ca2+
Silica Alumina Silica
Ca2+
10 - 12 Å
Ca2+ Hydration water
1-2µ Na+ Na+
+ water Na+
Sodium or calcium montmorillonite
Na+
Na+ Na+ 40 Å
Na+
Na+
Sodium montmorillonite
Figure 7: Comparison of swelling for calcium and sodium montmorillonite.
Clay Chemistry
4B.9
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CHAPTER
4B
A cation may serve as a bond to hold the clay mineral particles together&#;
&#;colligative properties are basically measurements of the reactivity of the clay.
Clay Chemistry
Because sodium bentonite swells four times as much as calcium bentonite, sodium bentonite will generate four times the viscosity. A more comprehensive discussion of the role which calcium-base exchange plays in calciumtreated systems is covered in the WaterBase Systems chapter. Smectite, in addition to adsorbing water and cations on external surfaces, absorbs water and cations to surfaces between layers in its crystalline structure. The ability of smectite to adsorb water is much greater than other clay minerals. The ability to adsorb water, the quantity of exchangeable cations (CEC) and the surface area are closely related phenomena that are sometimes termed colligative properties of clay. These colligative properties are basically measurements of the reactivity of the clay. Because CEC is easy to measure, it is a practical method to assess clay or shale reactivity. The CEC of clay can be measured with a methylene blue titration. When measuring the CEC, 0.01 N methylene blue solution is used so the number of milliliters of methylene blue solution needed to reach the end point is equal to meq/100 g. The range of CEC for pure clay mineral materials is shown in the following table: Clay Smectite Illite Chlorite Kaolinite
CEC (meq/100 g) 80 - 150 10 - 40 10 - 40 3 - 10
Table 2: CEC range for pure clay mineral materials.
Smectite is clearly much more reactive than other clay mineral materials. Shales containing smectite are the most watersensitive and hydrate the most. Shales containing other clay minerals have less ability to hydrate but still may be
Clay Chemistry
4B.10
water-sensitive. Most shales contain several types of clay in varying amounts. The reactivity of a shale depends on the types and amounts of clay minerals present in the shale. Often the CEC is a better measure of clay reactivity than the mineralogical analysis inferred from X-ray diffraction analysis.
CATIONIC
INFLUENCE ON HYDRATION
As pointed out previously, the relative replacing power of one cation by another is shown in the following series: H+ > Al3+ > Ca2+ > Mg2+ > K+ > NH4+ > Na+ > Li+ A cation may serve as a bond to hold the clay mineral particles together, thereby decreasing hydration. Multivalent cations tie layers together more firmly than monovalent cations, usually resulting in aggregation of the clay particles. Potassium, a monovalent cation, is the exception to the rule. The adsorbed cations may become hydrated and attract a water envelope with a definite shape. The size and shape of the hydrated cation affects its ability to fit between interlayer clay surfaces and influences both clay swelling and clay hydration. Spaces within the crystalline montmorillonite layers is 2.8 Å. Small ions, like potassium, that can fit between clay layers are more easily and permanently exchanged. In addition, cations that become large when hydrated expand the interlayer distances to promote clay hydration. Calcium is a good example, having a hydrated diameter of 19.2 Å. Lithium is another example, having three water molecules and a hydrated diameter of 14.6 Å. Monovalent cations with large hydrated diameters cause the most swelling and dispersion. Multivalent cations with small hydrated diameters are the most inhibitive.
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Clay Chemistry
Table 3 lists the ionic diameter (crystalline) and hydrated diameter of cations common to drilling fluids. Once hydrated cations are adsorbed in the interlayer region, they can be dehydrated with time and exposure to high temperatures so that the interlayer distances actually shrink and become less reactive (see ion fixation discussed in the following section). Cation
Chemical reactions between clay and potassium ions are unique&#;
&#;smectite clays in the Gulf of Mexico have undergone at least some degree of alteration&#;
Li+ Na+ K+ NH4+ Mg2+ Ca2+ Al3+
Ionic Diameter Hydrated Diameter (Å) (Å) 1.56 14.6 1.90 11.2 2.66 7.6 2.86 5.0 1.30 21.6 1.98 19.2 1.00 18.0
Table 3: Ionic radii and hydration radii of common cations.
CLAY
REACTIONS WITH POTASSIUM IONS
Chemical reactions between clay and potassium ions are unique when compared to other ions. The ion exchange model does not fully explain the interaction of potassium with clay. Special attention will be paid to this process because of the widespread use of potassium in drilling and completion fluids to stabilize reactive shales. Even in U.S. offshore applications, where the potassium level must be maintained below 5% for environmental reasons, this small concentration of ions can help stabilize active shale formations because ion fixation can occur in some smectite clays when they are exposed to potassium. According to Eberl (), there are two ways that potassium can become associated with clay minerals: 1. Ion exchange (discussed earlier). 2. Ion fixation.
Clay Chemistry
4B.11
The ion exchange reaction is governed by the law of mass action; that is the rate of exchange depends on the concentration of the ions (i.e. the higher the ratio of K ion to Na ion, the faster the rate of exchange of K+ for Na+). In addition to ion exchange, ion fixation will occur in clays with a high layer charge. This increases the selectivity of the clay for potassium by an order of magnitude. Montmorillonite clays, such as Wyoming bentonite and some gumbo-type shales which were deposited in potassium-depleted environments, are selective to potassium. Based on theoretical calculations, Eberl finds that potassium fixation in smectite clays will occur if the layer charge is high and will shift the equilibrium toward preferential cation exchange with potassium. In the Gulf Coast, the smectite content of the shales and gumbos is derived from the weathering of igneous and metamorphic rock or recycled sedimentary smectite ultimately derived from igneous and metamorphic rock. Furthermore, the smectite clays in the Gulf of Mexico have undergone at least some degree of alteration by the process known as burial diagenesis. This diagenetic alteration can be subdivided into a two-step reaction. The first step is the creation of high-layercharged smectite by the substitution of aluminum for silicon in the tetrahedral layer of the smectite. The high-layercharged smectite is then converted to illite (actually mixed-layer illite/smectite) by fixation of potassium. This fixation of potassium occurs in nature even with a high sodium-to-potassium ratio in the pore solution.
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4B
&#;linking processes must be understood in order to understand and control rheological changes in drilling fluids.
Clay Chemistry
There is enough potassium available to allow smectite layers to transform to illite layers in many geological settings. In other geological settings, the complete transformation cannot occur because potassium is in short supply. In geological settings where transformation of smectite layers to illite layers has been limited by the unavailability of potassium, high-layer-charged smectite can diagenetically develop. This is the case with Gulf Coast smectite clays. They will generally have a high-layer charge, and a higher portion of the charge will arise in the tetrahedral layer which should be more selective toward potassium at lower temperatures. Therefore, when potassium becomes available from drilling mud, even seawater muds with a high sodium-to-potassium ratio, the conversion of high-layer-charged smectite layers to illite layers will occur. The effect of this reaction is to stabilize the shale. In some gumbo shales, the highlayer-charged smectite layers coexist with lower-layer-charged smectite layers. The low-layer-charged smectite layers will not fix potassium and, in cases where the potassium concentration is greatly exceeded by sodium, will behave according to classical ion exchange theory. Thus, increasing the potassium-to-sodium ratio in the mud will help saturate the low-layer-charged smectite layers with potassium and provide additional shale stabilization.
CLAY-PARTICLE-LINKING
PROCESSES
important to the rheology of clay suspensions. These linking processes must be understood in order to understand and control rheological changes in drilling fluids. The thin flat, plate-like particles of clay have two different surfaces. The large face or planar surface is negatively charged and the thin, edge surface is positively charged where the lattice is disrupted and a broken bond surface exposed. These electrical charges and exchangeable cations make up an electrical force field around the clay particles that determines how these particles interact with one another. If the exchangeable ions are dissociated from the clay surface, the repelling force between the flat negatively-charged plates is large, and the plates will be dispersed from one another. Complete dispersion is rare and probably can only occur in dilute suspensions of purified sodium montmorillonite. Usually, some degree of linking between particles occurs. Clay particles associate in one of the following states: aggregation, dispersion, flocculation or deflocculation (see Figure 8). They can be in one or more states of association at the same time with one state of association predominating. Aggregation (face to face)
Dispersion
Flocculation (edge to face) (edge to edge)
Deflocculation
In addition to knowing the amount and quality of the clays in a mud, it is necessary to know the state of association of the clay particles. The various linking processes of clay particles are Figure 8: Association of clays.
Clay Chemistry
4B.12
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CHAPTER
4B
&#;deflocculating chemicals are often referred to as mud thinners.
&#;yield of clays is defined as the number of barrels of 15-cP mud that can be obtained from one ton of dry material.
Clay Chemistry
Aggregation (face-to-face linking) leads to the formation of thicker plates or packets. This decreases the number of particles and causes a decrease in the plastic viscosity. Aggregation can be caused by the introduction of divalent cations to the drilling fluid, such as Ca2+. This could occur from additions of lime or gypsum or by the drilling of anhydrite or cement. After an initial increase, the viscosity will decrease with time and temperature to some value lower than it was originally. Dispersion, the reverse of aggregation, leads to a greater number of particles and to higher plastic viscosities. Clay platelets are normally aggregated before they are hydrated and some dispersion takes place as they hydrate. The degree of dispersion depends on the electrolyte content of the water, time, temperature, the exchangeable cations on the clay and the clay concentration. Lower salinity, longer times, higher temperatures and lower hardness lead to more dispersion. Even Wyoming bentonite will not completely disperse in water at room temperature. Flocculation refers to edge-to-edge and/or edge-to-face association of particles, leading to the formation of a &#;house of cards&#; structure. This causes an increase in viscosity, gelation and fluid loss. The severity of this increase is a function of the forces acting on the linked particles and the number of particles available to be linked. Anything that increases the repelling forces between particles or shrinks the adsorbed water film, such as the addition of divalent cations or high temperature, promotes flocculation. Deflocculation is the dissociation of flocculated particles. The addition of
Clay Chemistry
4B.13
certain chemicals to the mud neutralizes the electrochemical charges on the clays. This removes the attraction that results in edge-to-edge and/or edge-toface bonding between clay particles. Since deflocculation results in a reduction in viscosity, deflocculating chemicals are often referred to as mud thinners. Deflocculation also aids in allowing the clay particles to lay flat in the filter cake to reduce fluid loss.
YIELD
OF CLAYS
The yield of clays is defined as the number of barrels of 15-cP (centipoise) mud that can be obtained from one ton of dry material. Figure 9 illustrates why 15 cP was chosen as the defining value for yield. The critical part of the curve for all types of clay appears at 15 cP. Large additions of clay up to 15 cP promotes little viscosity increase, whereas, small amounts of clay have a pronounced effect on viscosity above 15 cP. This is not only true with commercial clays but for hydratable drill solids as well. It is also relevant that a 15-cP clay suspension will support barite in weighted-mud systems. This graph can be very useful to the mud engineer. For a given viscosity of the various clays, data relative to slurry density, percent solids by weight, yield in barrels-per-ton, percent solids by volume and pounds solids per barrel of mud may be obtained. For example, about 20 lb/bbl of bentonite (M-I GEL) is required to produce a 15-cP viscosity mud. From the graph, then, it would contain 51&#;2% solids by weight, yield 100 bbl/ton, have 21&#;2% solids by volume and weigh about 8.6 lb/gal (1 kg/L).
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CHAPTER
Clay Chemistry
8.5
9.0
Slurry density (lb/gal) 10.0 10.5
9.5
11.0
11.5
12.0
60
Sub-be ntonit e
M-I GEL
50
SALT GEL
Specific gravity of solids = 2.4
40
30
Na tiv ec lay
Viscosity (cP)
4B
20
10
0
0
5
10
200 100 75
2
10
15
25 30 Solids (% wt)
35
50 40 30 25 20 18 16 14 Yield (bbl/ton of 15-cP mud) 4
20
20
6
30 40
50
8
10
12 14 Solids (% vol)
16
100 Solids (lb/bbl)
150
75
40
12
18
45
10
20
200
50
9
25
8
30
250
Figure 9: Viscosity curves resulting from different clay solids.
The yield would be less if a clay takes up less water. By comparison, if subbentonite was used to produce a 15-cP viscosity mud, it would contain 18% solids by weight, yield only 28 bbl/ton, have 81&#;2% solids by volume and would weigh almost 9.4 lb/gal (1.1 kg/L). Clays have many applications in drilling muds. Increasing the viscosity of a drilling mud may best be accomplished with the least amount of solids by adding a clay which has the highest yield (M-I GEL). Lower fluid-loss values can be obtained with bentonite since coarse and medium-sized particles are normally produced from the formation. The quality of the mud will Clay Chemistry
4B.14
be improved by utilizing high-quality Wyoming bentonite. M-I GEL and M-I GEL SUPREME are both Wyoming bentonites. They differ in that M-I GEL is treated with very small amounts of polymer (peptized) to increase its yield, while M-I GEL SUPREME is a non-treated bentonite. M-I GEL meets API Specification 13A, Section 4 &#;Bentonite&#; specifications. M-I GEL SUPREME meets API Specification 13A, Section 5 &#;Non-Treated Bentonite&#; specifications. M-I SWACO also sells OCMA bentonite which meets API Specification 13A, Section 6 &#;OCMA Bentonite&#; specifications. NOTE: OCMA is the acronym for Oil Companies Materials Association. Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
Clay Chemistry
FACTORS
AFFECTING THE YIELD OF CLAYS
Hydration and dispersion of dry clay are greatly affected if the makeup water contains salt or various metallic ions. For example, many drilling muds are prepared with seawater for economy and convenience. A typical analysis of seawater might contain the following components: Components Sodium Chloride Sulfate Magnesium Calcium Potassium Bromine Other components
Parts per Million (mg/L) 10,550 18,970 2,650 1,270 400 380 65 80
Viscosity (cP)
Hydration and dispersion of dry clay are greatly affected if the makeup water contains salt or various metallic ions.
30 25 20
Salt solution
15
Calcium solution
10 5 0 0 0
50
100 150 200 250 Salt (mg/L x 1,000) 1.5 3.0 4.5 6.0 7.5 Calcium (mg/L x 1,000)
300 9.0
Figure 10: Viscosity effect when adding bentonite to water containing various concentrations of salt or calcium.
NOTE: Brackish water could contain the same components, but at different concentrations.
&#;hydration of freshwater clays decreases rapidly with increasing concentrations of these ions.
Water containing any salt concentration can be saturated with an additional salt. Saturated saltwater contains about 315,000 mg/L sodium chloride. Approximately 120 lb/bbl of salt is required to saturate freshwater. Figure 10 shows the effect of various concentrations of these ions upon the hydration of bentonite. In general, it can be stated that the hydration of freshwater clays decreases rapidly with increasing concentrations of these ions. This phenomenon is more apparent in Figures 11 and 12. Demonstrated in these examples is the hydration of two identical cubes of bentonite, the first in freshwater and the second in salty water. Figure 11 shows the bentonite cube initially in a beaker of freshwater and then again 72 hr later. Hydration and consequent swelling is readily apparent. Figure 12 shows the bentonite cube initially in the salty water and again 72 hr later. It is obvious that little or no hydration has occurred. Water containing calcium or magnesium is referred to as &#;hard&#; water. To obtain more viscosity from the clay, one Clay Chemistry
4B.15
Initial
72 hr later
Figure 11: Hydration of bentonite in freshwater.
Initial
72 hr later
Figure 12: Hydration of bentonite in salty water.
practice is to &#;soften&#; the water with soda ash and caustic soda to precipitate calcium and magnesium. When high chloride concentrations exist, the only method of reducing the concentration is by dilution with freshwater. When the makeup water is salty, SALT GEL (attapulgite) may be used Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
Clay Chemistry
Figure 13: Photomicrograph of attapulgite particles.
&#;attapulgite clay will build similar viscosity in any type of makeup water&#;
for achieving viscosity. Attapulgite is a unique mineral. Its crystalline structure is needle-like as shown in Figure 12. Its ability to build viscosity is independent of the makeup water. At the same concentration, SALT GEL in any type water would give about the same viscosity as M-I GEL in freshwater. The ability to build viscosity does not depend on hydration, but rather upon the extent to which the bundles of needles are sheared. The resultant viscosity is created by two elements: 1. The formation of brush-heap structures by the shearing forces. A simple analogy would be similar to straw stirred into water. 2. Attractive forces between particles created by broken-bond charges on the edges of needles broken by the shearing force. Since the attapulgite clay will build similar viscosity in any type of makeup
1 &#;4 bbl of 30-lb/bbl prehydrated bentonite slurry
+
3
water, a question might be &#;Why not always use attapulgite?&#; The answer would be (1) greater cost, (2) lack of filtration control due to particle shape and (3) rheology characteristics are more difficult to control. Bentonite can be used as an effective viscosifier in saltwater if it is first prehydrated in freshwater then added to the salty water. It is beneficial to maintain a 9 to 10 pH and treat the prehydrated bentonite slurry with a deflocculant before adding it to the salty water. In this way, the initial flocculation followed by a loss of viscosity from dehydration in the saltwater environment is reduced. This is shown in Figure 14. A slurry consisting of 30 lb/bbl bentonite was prepared and allowed to hydrate. It was then added to a barrel equivalent of water having a concentration of 100,000 mg/L sodium chloride. From this figure, it is obvious that the clay is dispersed in the saltwater and the rheological properties show that the clay is performing its function. Much of this viscosity will be eventually lost through dehydration over time, but a portion will always remain. The resultant viscosity will always be substantially higher than making an addition of dry clay directly to the saltwater.
&#;4 bbl of 100,000-mg/L NaCl water
=
1 bbl slurry with properties AV = 47, PV = 15 and YP = 63
Figure 14: Addition of prehydrated bentonite to saltwater.
Clay Chemistry
4B.16
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CHAPTER
Clay Chemistry
70
60
60
50
50
40
Viscosity (cP)
Viscosity (cP)
4B
40 30
30 20
20
10
10
0 0
1
2 3 4 Salt (mg/L x 1,000)
5
6
0 1
2 3 4 5 Calcium x 100 (mg/L)
6
Figure 15: Effect of calcium on prehydrated bentonite.
&#;all drilling muds&#; should have a pH above 7.
An entirely different reaction occurs when salt or calcium is added directly to a bentonite slurry prepared and hydrated in freshwater. Figures 15 and 16 demonstrate this reaction. To be noted is the initial increase and subsequent decrease in viscosity previously discussed under clay particle associations. Figure 15 represents initial viscosity increase due to flocculation caused by the addition of the divalent cation Ca2+. This in turn causes aggregation of the particles and a viscosity decrease due to dehydration and decreased number of particles. Figure 16 shows essentially the same thing except that flocculation and the aggregation are caused by mass action of the Na+ due to its high concentration.
EFFECT
OF PH
Figure 16: Effect of salt on prehydrated bentonite.
considerations, since pH does affect viscosity, is selection of the most desirable pH range for optimizing the rheological properties of the drilling fluid. From the graph it can be observed that the viscosity of a bentonite suspension is lowest in the pH range of 7 to 9.5. This is one reason why most water-base drilling fluids are run in this range. Increased dispersion of clay results when pH is above 9.5, increasing the viscosity of the drilling fluid. 70 60 50 Viscosity (cP)
0
40 30 20
It is relevant at this time to also consider the effect of pH on the yield of bentonite. Figure 17 illustrates the viscosity of a bentonite slurry as the pH is varied. Most all drilling muds are treated to be alkaline, i.e., they should have a pH above 7. One of the primary
Figure 17: Effect of pH on Wyoming bentonite.
Clay Chemistry
Revision No: A-2 / Revision Date: 12·31·06
4B.17
10 0 0
2
4
6 pH
8
10
12
CHAPTER
4B
Clay Chemistry
In previous discussions, the emphasis has been toward getting the most viscosity from the smallest addition of material. The significance of pH is that the viscosity created by values above 10 is sometimes out of proportion to
what is considered to be desirable mud properties. For obvious reasons, such as safety and corrosion, drilling muds are rarely operated in the acidic range with a pH below 7.
Principles of Chemical Treatment Viscosity is the result of frictional as well as electrical forces existing in a mud system.
Viscosity is the result of frictional as well as electrical forces existing in a mud system. As drilling progresses, solids are incorporated into the drilling mud. They will be ground and broken into very fine particles, causing an increase in the viscosity of the mud, unless these solids are removed from the system. Drilling various contaminants will also cause flocculation and an increase in viscosity. Evaluating the rheological properties of the mud will enable the mud engineer to quickly determine the cause of trouble and the proper treatment to reduce viscosity. Water is effective for reducing viscosity if solids are high, but it is not the most economical treatment if abnormal viscosity is caused by chemical flocculation (as indicated by a high yield point and gels). There are organic and inorganic anionic additives that can be used to effectively reduce flocculation. The primary effect of anionic viscosityreducing chemicals is believed to be a neutralization of residual broken-bond cationic charges. The mechanism of this action in water-clay suspensions is to reduce that portion of viscosity due to attractive forces between the particles without substantially affecting
Clay Chemistry
4B.18
that portion of viscosity due to hydration of the clay minerals. Anionic materials are adsorbed on the edges of the clay particles to satisfy the residual broken-bond cationic charges. Anioniccharged chemicals commonly used for the treatment of drilling mud include phosphates, tannins, humic-acid lignins (lignite), lignosulfonates and lowmolecular-weight synthetic polymers. This adsorption changes the balance of forces acting on the clay particle from an attractive force (flocculation) to a repulsive force (deflocculation). Instead of being drawn together, the particles repel or tend to avoid contact with one another. Chemical treating agents reduce flocculation in clay-water drilling fluids by one or more of the following mechanisms. 1. Removing the contaminant by precipitation. 2. Reducing the effects of the contaminant by complexing the contaminate (sequestering). 3. Neutralizing flocculation by satisfying cationic charges on the clay particles. 4. Encapsulating or forming a protective film around the clay particle.
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4B
Clay Chemistry
PHOSPHATES The two principal phosphates used in drilling mud are: 1. Sodium Acid Pyrophosphate (SAPP) pH of 4.8. 2. Sodium Tetraphosphate (STP or PHOS) pH of 8.0.
&#;phosphates are powerful anionic dispersants&#;
Phosphates are used principally in low-pH muds and spud muds.
These phosphates are powerful anionic dispersants and only a small treatment will produce maximum viscosity reduction. The amount of treatment for simple dispersion rarely exceeds 0.2 lb/bbl. This means that for a 1,000-bbl system, only 200 lb (90.7 kg) would be required to thin the fluid. The phosphates can be added directly through the hopper or from the chemical barrel. If added from the chemical barrel, approximately 50 lb (22.7 kg) of phosphate is mixed with a barrel of water. The solution is then added directly to the mud uniformly over one circulation. Phosphates are used principally in low-pH muds and spud muds. They lower viscosity in two ways: (1) they neutralize attractive forces by being adsorbed on the surface of solids, and (2) they remove calcium and magnesium. The low pH of SAPP and its ability to remove calcium makes it an excellent treating agent for cement contamination. The phosphates are seldom used by themselves in mud treatment; rather, they are used to supplement control along with caustic soda and an organic thinner. If SAPP (pH of 4.8) were used continuously by itself, the mud would eventually become acidic. This could be detrimental and lead to severe corrosion and excessive viscosity. PHOS
Clay Chemistry
4B.19
has a more neutral pH (8.0) that makes it more applicable for routine mud-thinning treatments. The application of phosphates for treatment is limited. The materials are not effective mud thinners at moderate temperatures. If the mud temperature is much in excess of 175°F (79.4°C), the phosphates revert to orthophosphates. As orthophosphates, they may become flocculants rather than deflocculants. This does not rule out the application of phosphates for sequestering calcium at higher temperatures. As orthophosphates, they still have the ability to decrease calcium, although their thinning power is decreased. The phosphates also do not perform effectively at higher salt concentrations.
LIGNITE The basic lignite used for viscosity control is TANNATHIN* (pH 3.2). Lignite is less soluble at low pH, so to be effective the pH of the mud must be in the alkaline range or the lignite must be presolubilized in a high-pH slurry before being added to the mud system. Caustic soda is usually added with low-pH lignite additives. In field use, the ratio of caustic soda to TANNATHIN will range from 1:6 to 1:2. The lignins are best added through the mud hopper. TANNATHIN performs best in mud systems with pH values that range from 9 to 10.5. CAUSTILIG* is a causticized lignite that has a pH of about 9.5. K-17* is a potassium hydroxide-neutralized lignite with a pH of about 9.5. XP-20* (pH 10) is a prereacted chrome lignite used primarily in conjunction with SPERSENE* (chrome lignosulfonate). It complements the performance
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
Lignite additives help form oil-in-water emulsions&#;
Clay Chemistry
of SPERSENE in the M-I SWACO Chrome Lignosulfonate System (CLS or SPERSENE/XP-20 system). As an integral part of the SPERSENE/XP-20 mud system, XP-20 is a drilling-fluid stabilizer and emulsifier. It decreases fluid loss and contributes to the inhibitive properties of the mud. It is the primary thermal stabilizer in the hightemperature DURATHERM* system. The application of XP-20 is not limited to SPERSENE/XP-20 and DURATHERM systems, and can be used in a wide variety of deflocculated water-base systems for fluid-loss control, thinning and increased thermal stability. Lignite additives help form oil-inwater emulsions and are generally not effective at high calcium concentration. They are only moderately effective at higher salt concentrations.
LIGNINS Lignins are a group of products similar to lignite and lignosulfonate that come from chemically-treated tree bark. Quebracho is a lignin/lignite blend designed to provide thinning and fluidloss control. In general, tannin products are more soluble than alternative chemicals in lower-pH muds. They are more effective at lower temperatures and high-salinity environments as compared
Clay Chemistry
4B.20
to lignite-base additives. Tannins are usually more expensive and provide a shorter-term effect as compared to both lignite and lignosulfonate. Desco^, from Drilling Specialties Co., a chrome lignin, and Desco CF, a chrome-free lignin, are widely used as thinners.
LIGNOSULFONATES The lignosulfonates include SPERSENE, a chrome lignosulfonate; SPERSENE CF, a chrome-free lignosulfonate; and SPERSENE I, a ferro-chrome lignosulfonate. These additives are versatile materials that have wide applications in many deflocculated water-base systems. They work well at all levels of alkaline pH, can be used at elevated salt levels and are effective in the presence of higher calcium levels. Lignosulfonate additives have a low pH (about 3.0). For this reason, caustic soda should be added along with all SPERSENE treatments. The amount of caustic will vary according to the type mud being run, but usually at one part caustic for four parts SPERSENE. It not only reduces viscosity and gel strength, but when used in sufficient quantities, it reduces water loss and provides an inhibitive environment. Additions of SPERSENE are generally made through the mixing hopper.
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
Clay Chemistry
APPLICATION
Plastic viscosity, yield point and gel strengths are the important factors.
Figure 18 demonstrates the changes of viscosity that occur when plastic viscosity and yield-point values are altered by chemical contamination and treatment. The data can be analyzed to determine the effect on both the funnel viscosity and apparent viscosity by varying material additions to promote changes, then interpreting the rheological values. Whether measured in seconds/quart with the funnel or in cP with the viscometer, the apparent viscosity is composed of two components: (1) solids content and nature of these solids, and (2) the electro-chemical attraction between the solids. As contaminants are introduced and/ or the solids content is increased, the viscosity increases. If the Marsh-funnel viscosity increases, then the apparent viscosity will usually increase. It is also true that if one decreases, the other will usually decrease. However, if only the apparent viscosity were measured, this value is of little use for mud control. Plastic viscosity, yield point and gel strengths are the important factors. Plastic viscosity is more of a measure of the structural viscosity that is determined by the solids concentration. Yield point and gels are more a measure of clay hydration and flocculation. Yield points and gels in clay free xanthan polymer muds are less affected by normal contamination, flocculation/deflocculation and anionic chemical thinning.
Clay Chemistry
4B.21
The principles of chemical treatment in a clay-water fluid are shown in Figure 18: 1. Introducing 1&#;2 lb/bbl of cement caused flocculation to occur due primarily to calcium contamination. Both the funnel viscosity and the apparent viscosity increase. Examination of the graph reveals that this viscosity change was brought about by increasing the yield point (increased attractive forces or flocculation). Little or no change was experienced in plastic viscosity because plastic viscosity is due primarily to solids. 2. Ten % water was added to demonstrate that water has little effect on reducing yield point (flocculation). Water does not remove calcium, which is the cause of flocculation or high attractive forces. Water can only increase the separation of the solids, but does not change the association of the clays or alter yield point. 3. The addition of 1 lb/bbl of PHOS (for removing calcium) produces a tremendous decrease in both the funnel and apparent viscosity. This was brought about by lowering the yield point. The yield point was reduced because PHOS reduces calcium and deflocculates the clay particles. It is also shown that this addition of chemical had little or no effect upon plastic viscosity.
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CHAPTER
Clay Chemistry
100
80
Funnel vi scosity
Funnel viscosity (sec/qt)
120
60
80 Apparent viscosity Plastic viscosity
AV, PV and YP (cP or lb/100 ft2)
4B
60
40
Yield point
20
A
B
C
D
E
F
G
H
I
0 Base mud
10% water 1/2 lb/bbl cement
200 lb/bbl M-I BAR* 1 lb/bbl PHOS
10% water 1/4 lb/bbl PHOS
1/4 lb/bbl PHOS 1/4 lb/bbl cement + 10 lb/bbl clay
10% water
Figure 18: Principles of chemical treatment.
Clay Chemistry
4B.22
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
4B
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Clay Chemistry
4. The second viscosity increase (Part D) was caused by the addition of 200 lb/bbl of barite (inert solids) to increase mud weight. The apparent viscosity change is almost the same as before, but for an entirely different reason. This viscosity change resulted from raising plastic viscosity. The addition of more solids increased the friction between solids because the total surface area of the solids increased. Yield point increased only slightly because the solids are closer together. Any attractive force will be more effective because the distance between particles is reduced. However, the funnel and apparent viscosity increased primarily because of increased plastic viscosity. The correct mud treatment here would be to add water. 5. 1&#;4 lb/bbl of PHOS was added to demonstrate that a slight reduction in viscosity can be obtained by lowering the yield point, and to also show that chemical treatment alone will not reduce high viscosity from solids. Viscosity remained high even after the treatment. 6. Adding water is the correct treatment to reduce viscosity. Ten % by volume water was added and the plastic viscosity was reduced. Both the funnel and apparent viscosities decreased significantly because they are a function of plastic viscosity. The yield point decreased only slightly. 7. Adding both a chemical contaminant and reactive solids causes the third viscosity increase, increasing both yield point and plastic viscosity. The 1 &#;4 lb/bbl of cement increased the yield
Clay Chemistry
4B.23
point as in Part A. Plastic viscosity was increased by adding 10 lb/bbl of clay for the same reason as the viscosity increased in Part D by the introduction of solids. There is, however, one great difference. The clay solids hydrate and take up water. With less free water available, the friction is increased considerably with only a small amount of solids. For a unit volume of solids, hydratable drill solids will always increase viscosity more than inert solids. The correct treatment here is the addition of both chemical thinners and water for dilution to lower both plastic viscosity and yield point. 8. Addition of chemicals lowered viscosity for the same reason as in Part C. 9. Addition of water lowered viscosity for the same reason as in Part F. The following generalization can be made for the most economic control of flow properties to obtain optimum conditions: 1. An increasing yield point, accompanied by little or no changes in the plastic viscosity, may be reduced or controlled by the addition of chemical thinners in a clay-water system. 2. An increasing plastic viscosity, accompanied by little or no changes in yield point, may be reduced or controlled by water or the use of mechanical solids-control equipment to discard undesirable solids. 3. Simultaneous large increases in both yield point and plastic viscosity can be reduced or controlled by both of the above.
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4C
Contamination and Treatment
Introduction A contaminant is any type material&#; that has a detrimental effect on the physical or chemical characteristics of a drilling fluid.
A contaminant is any type material (solid, liquid or gas) that has a detrimental effect on the physical or chemical characteristics of a drilling fluid. What constitutes a contaminant in one type of drilling fluid may not necessarily be a contaminant in another. Low-gravity, reactive solids are contaminants all drilling fluids have in common. These solids consist of drilled solids incorporated into the system or through over-treatment with commercial clays. Economically, drilled solids and the problems associated with their control have greater impact on mud costs than other type of contamination. However, the primary focus here is on the following common chemical contaminants of water-base muds: 1. Anhydrite (CaSO4) or gypsum (CaSO4&#;2H2O). 2. Cement (complex silicate of Ca(OH)2). 3. Salt (rock salt, makeup water, seawater, magnesium, calcium and sodium chloride, and connate water). 4. Acid gases, including carbon dioxide (CO2) and hydrogen sulfide (H2S). With the exception of the acid gases, these chemical contaminants are directly related to ion exchange reactions with clays. Therefore, the concentration of the clay-type solids in a water-base mud has a direct relationship on how severely the chemical contaminant affects the mud properties. The Methylene Blue Capacity (MBC) is a good indication of the concentration of clay-type solids. Muds with MBC levels below 15 lb/bbl are less affected by chemical contamination. An ion exchange reaction can occur when sodium bentonite is exposed to chemical environments containing high concentrations of other metallic
Contamination and Treatment
4C.1
ions, initially flocculating, then possibly chemically converting the bentonite to a lower-yielding clay. This affects the amount of adsorbed water and the size, shape and association of particles, resulting in unstable rheology and fluid-loss control. The severity of these contaminants made it necessary to develop mud systems that could tolerate them. These systems include lignosulfonate muds, low-colloid polymer muds, lime muds, gyp muds and salt muds. Many of these systems are deliberately pretreated with lignosulfonate, salt (sodium chloride) and calcium-containing materials such as lime or gypsum. Therefore, when additional concentrations of these contaminants are encountered, they have minimal effect on the systems. The primary purposes of this chapter are: &#; To reveal the source(s) of each chemical contaminant. &#; To describe how each affects mud properties. &#; To describe how to use mud property changes to identify the contaminant. &#; To describe how to treat the mud to restore the original properties. Since changes in physical mud properties such as increased rheology and fluid loss due to flocculation are similar regardless of which chemical contaminant is present, the changes in physical properties indicate only that a contaminant exists. An analysis of the changes in chemical properties is necessary to identify the contaminant. Therefore, the sources, effects and treatment options of each chemical contaminant are discussed in detail. A quick-reference guide and tables, in metric and English units, are included at the end of the chapter (see Tables 2, 3 and 4).
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4C
Contamination and Treatment
Anhydrite or Gypsum Contamination
Anhydrite and gypsum are both calcium sulfate and nearly identical in chemical composition.
The solubility of CaSO4 is controlled by pH, salinity and temperature.
There are few areas in the world where anhydrite or gypsum is not drilled. Anhydrite and gypsum are both calcium sulfate and nearly identical in chemical composition. Gypsum (CaSO4&#;2H2O), with its attached water, is more soluble than anhydrite (CaSO4). The severity of this contaminant depends primarily on the amount drilled. If only a small amount of a contaminant is encountered, it can be tolerated by precipitating the calcium ion. If large amounts are encountered, the mud system should be converted to a calcium-base system. Both lime and gyp-base calcium systems can tolerate anhydrite or gypsum contamination without adversely affecting the mud properties. The initial effect of calcium contamination on a bentonite-base mud system is high viscosity, high gel strengths and increased fluid loss. The extent to which these properties are affected is a function of concentration of the contaminant, the concentration of reactive solids and the concentration of chemical deflocculants in the drilling fluid. As shown below, when calcium sulfate solubilizes in water, it ionizes into calcium and sulfate ions. CaSO4 Ca2+ + SO42&#; The solubility of CaSO4 is controlled by pH, salinity and temperature. Increased pH and temperature decreases the solubility of gyp while increased mud chlorides increases the solubility. The solubility of calcium sulfate is reversible and will reach some level of equilibrium with the chemical environment.
Contamination and Treatment
4C.2
DETECTION FACTORS The first indication of anhydrite or gypsum contamination is an increase in physical properties, including funnel viscosity, yield point and gel strengths. Chemical tests must be performed to identify which chemical contaminant is present since the increase in these physical properties is also the first indication of other types of chemical contamination. The main indications of gyp or anhydrite contamination include: 1. An increase in filtrate calcium. This may not be apparent initially if there is an excess of carbonate, bicarbonate or phosphate ions present in the mud, or if the pH of the mud system is being increased. But when the solubilized gyp depletes these chemicals, a reduction in pH occurs because the pH of gyp (6 to 6.5) is very low. This reduction in pH will result in a large increase in filtrate calcium, since the solubility of calcium is inversely proportional to pH. 2. Reduction of the pH and alkalinity, and an increase in filtrate calcium, are the most reliable indicators. 3. Due to the relatively limited solubility of anhydrite and gypsum, cuttings may contain traces of the mineral. Many times, this is evidenced by the presence of small, white, mushy balls of acid-soluble material on the cuttings. 4. The qualitative test for the sulfate ion should indicate an increase. However, this test also detects the sulfonate ion. The test is meaningless if lignosulfonate is used as the primary deflocculant unless a comparison is made with uncontaminated mud.
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
4C
Contamination and Treatment
TOLERATING ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
THE CONTAMINANT
Treating the mud for gyp/anhydrite contamination: 1. Increase the concentration of deflocculant in the system. Lignosulfonate and lignite are both effective deflocculants in the presence of calcium. This treatment may be sufficient, depending on the amount of anhydrite or gypsum drilled. Lignite chelates the calcium ion, thereby removing it. If there is too much calcium, soda ash (Na2CO3) may be required to precipitate it out. 2. The pH must be maintained in the range of 9.5 to 10.5 with caustic soda (NaOH) or caustic potash (KOH). This pH range limits the solubility of gyp and enhances the performance of the lignosulfonate. 3. Any one of the following chemicals may precipitate an increase in filtrate calcium. Precipitating the calcium with a source of carbonate ions is extremely effective. Due to the low pH of anhydrite/gyp (6 to 6.5), soda ash is the preferred carbonate because it has a higher pH (11 to 11.4) than bicarbonate of soda (8 to 8.5). When soda ash is mixed in water, the pH increases due to the formation of a hydroxyl ion, as shown: 2Na2CO3 + H2O HCO3 + CO3 + 4Na+ + OH&#; (pH 11.3)
Contamination and Treatment
4C.3
A similar reaction occurs when sodium bicarbonate is used as the precipitant. By-products of the reaction are chemical compounds such as calcium bicarbonate (Ca(HCO3)2), a highly soluble material (depending on the pH). With additional caustic soda to maintain the pH above 9.7, the bicarbonate ion converts to carbonate. It then reacts with the filtrate calcium to precipitate CaCO3. However, the interim period during which the bicarbonate ion is present can create problems almost as serious as the contamination itself. Therefore, soda ash is preferred over sodium bicarbonate. Do not over-treat with soda ash or bicarbonate. Use Table 2 to calculate the amount of additive needed. Phosphates also have the ability to complex filtrate calcium. This reaction produces an insoluble calcium phosphate. Common available materials of this type are: Sodium Acid Pyrophosphate (SAPP) &#; Na2H2P2O7 (pH 4.8) Sodium Tetraphosphate (STP or PHOS) &#; Na6P4O13 (pH 8.0) Phosphates are limited by their relatively low temperature stability (approximately 200° F [93.3° C]). They convert to orthophosphates above this temperature. As such, they are not effective as deflocculants but are still capable of removing calcium. However, soda ash is the preferred product for treating out calcium from anhydrite or gyp at temperatures above 200° F (93.3° C).
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CHAPTER
4C
Contamination and Treatment
CONVERTING THE SYSTEM TO A CALCIUM-BASE SYSTEM
&#;add calcium sulfate to convert the system to a calciumbase mud system.
When massive sections of anhydrite or gypsum are drilled, the amount of contamination makes it virtually impossible to maintain desirable flow properties and fluid-loss control. Therefore, it is necessary to add calcium sulfate to convert the system to a calcium-base mud system. The mud may be converted to a gyp mud by treating with caustic soda, lignosulfonate and additional gypsum. A gyp mud is a low-pH system, but large amounts of caustic soda are required to maintain the pH in the desired range of 9.5 to 10.5. A viscosity hump (increase) will occur as the additional gyp is added, but with proper water, caustic and lignosulfonate additions, the mud will break over after one circulation, and the viscosity will decrease. Gypsum is added until it has no detrimental effect on the mud properties and then maintained in excess (5 to 8 lb/bbl) to feed the chemical reactions occurring. Typical calcium levels range from 600
to 1,200 mg/L in a gyp mud, depending on the pH. The mud may also be converted to a lime mud by applying the chemical treatment just outlined. To convert to a lime mud, additional lime is added instead of gypsum and is maintained in excess. To maintain lime in excess, most of the lime must remain insoluble. Therefore, the pH of the lime mud must be controlled in excess of 11.5 by additions of caustic soda and lime. The caustic soda reacts with the calcium sulfate to produce additional lime as shown by the following equation: 2NaOH + CaSO4 Ca(OH)2 + Na2SO4 The resulting lime-treated mud requires an abnormal amount of caustic soda to maintain excess lime if large amounts of anhydrite or gypsum are drilled. Therefore, a gyp mud is usually preferred. Both muds require the addition of a fluid-loss control agent that is not too calcium sensitive such as POLYPAC * R, POLY-SAL*, RESINEX*, etc.
Cement Contamination
&#;cement can have very detrimental effects on the mud properties.
The probability of drilling cement exists on every well drilled. The only circumstances under which cement is not a contaminant is when clear water, brines, calcium-base muds and oil-base muds are used, or when the cement is well cured. The most widely used mud system is the low-pH bentonite system. In this case, cement can have very detrimental effects on the mud properties. The severity of the contaminant depends on factors such as previous chemical treatment, solids type and concentration, the amount of cement
Contamination and Treatment
4C.4
drilled, and the extent to which it has cured in the hole. Keep in mind that bulk barite is occasionally contaminated with cement during transportation or at the rig and can cause severe cement contamination, even when it&#;s not expected. The initial effect of cement contamination is high viscosity, high gel strengths and loss of fluid-loss control. This is the result of an increase in the pH and the adsorption of the calcium ion onto the clay particles, causing flocculation.
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4C
Contamination and Treatment
Cement is a complex silicate of lime, Ca(OH)2. When solubilized in water or the water phase of a drilling fluid, an abundance of hydroxyl ions (OH&#;) is produced. Ca2+ + 20H&#; (pH 1: The fluid is dilatant, shearthickening (drilling fluids are not in this category). A comparison of a typical drilling fluid to a shear-thinning, Newtonian and dilatant fluid is shown in Figure 17. The effect of &#;n&#; on flow profile and the velocity profile is very important for shear-thinning, non-Newtonian fluids. As the velocity profile becomes flatter (see Figure 18) the fluid velocity will be higher over a larger area of the annulus so that hole cleaning will be greatly improved. This is one of the reasons that low &#;n&#;-value fluids like FLOPRO provide such good hole cleaning. The consistency index &#;K&#; is the viscosity at a shear rate of one reciprocal second (sec&#;1). It is related to a fluid&#;s viscosity at low shear rates. A fluid&#;s hole-cleaning and suspension effectiveness can be improved by increasing the &#;K&#; value. The consistency index &#;K&#; is usually reported as lb-sec&#;n/100 ft2, but may be reported in other units. The terms &#;K&#; and &#;n&#; only have real relevance when associated with a specific shear rate. However, where a fluid curve Revision No: A-2 / Revision Date: 12·31·06
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5
Rheology and Hydraulics
log n= log
Velocity
K= n = 1.0 n = 0.667 n = 0.5 n = 0.25 n = 0.125
Figure 18: Effect of Power Law &#;n&#; on velocity profile.
is described by a finite number of measurements, the line segments for those particular measurements describe &#;K&#; and &#;n.&#; &#;K&#; and &#;n&#; values can be calculated from mud viscometer data. The general equations for &#;n&#; and &#;K&#; values are:
( ) ( ) Θ2 Θ1 ω2 ω1
Θ1 ω1n
Where: n = Power Law index or exponent K = Power Law consistency index or fluid index (dyne sec&#;n/cm2) Θ1 = Mud viscometer reading at lower shear rate Θ2 = Mud viscometer reading at higher shear rate ω1 = Mud viscometer RPM at lower shear rate ω2 = Mud viscometer RPM at higher shear rate
RELATING (K, N)
TO
(PV, YP)
In clay-base drilling fluids, both the plastic viscosity and yield point of
Shear rate (sec&#;1) 1
10
100
1,000
1,000 Base &#; k = 0.95, n = 0.85 Case 1 &#; k = 1.30, n = 0.83 Case 2 &#; k = 0.65, n = 0.89 Case 3 &#; k = 6.00, n = 0.67
In clay-base drilling fluids, both the plastic viscosity and yield point of the mud affect the &#;K&#; coefficient.
Effective viscosity (cPs) (µe)
(3)
PV 4 4, Y P
32
(1) 100
Base
PV 36, YP 10 PV 30, Y P8
(2)
PV 28, YP 4
10
1
2
3
6
Shear rate (rpm x 100)
Figure 19: Power Law &#;K&#; and &#;n&#; relationship to Bingham PV and YP.
Rheology and Hydraulics
5.16
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&#;pipe Power Law equations should be used whenever the shear rate is greater than 170 sec&#;1.
Rheology and Hydraulics
the mud as shown in Figure 19 affect the &#;K&#; coefficient. Three cases are shown: (1) solids build-up, (2) decreasing solids and (3) flocculation due to contamination. Case 1. Plastic viscosity has increased over that of the &#;base&#; due to solids increase with very little change in yield point. The viscosity curve is essentially parallel to the base curve, thus there is little change in &#;n.&#; The overall viscosity has increased; therefore, &#;K&#; is a higher number. Case 2. Plastic viscosity decreased due to solids removal; yield point also is reduced. As with Case 1, the viscosity curve is essentially parallel and there is little change in &#;n.&#; &#;K&#; decreases due to a decrease in overall viscosity. Case 3. Yield point and plastic viscosity increased due to contamination and solids increase. The ratio of YP to PV is greatly affected by the resultant flocculation and &#;n,&#; the slope of the viscosity curve, decreased in value. &#;K&#; increases as a function of the changed slope (&#;n&#;) and the overall increase in viscosity. The bulletin, &#;Recommended Practice on the Rheology and Hydraulics of OilWell Drilling Fluids&#; (API Recommended Practice 13D Third Edition, June 1, ), recommends two sets of rheological equations, one set for inside pipe (turbulent conditions) and one set for the annulus (laminar conditions). The pipe Power Law equation is based on the mud viscometer 300and 600-RPM (Θ300 and Θ600) readings. When the shear rates (511 and 1,022 sec&#;1) are substituted in the &#;n&#; and &#;K&#; equations and the equations are simplified, they become: Θ600 log Θ300 Θ np = = 3.32 log 600 1,022 Θ300 log 511 5.11Θ300 5.11Θ600 Kp = or 511np 1,022np
( ) ( )
Rheology and Hydraulics
5.17
The annular Power Law equations are developed in the same manner, but use the 3- and 100-RPM (Θ3 and Θ100) values. By substituting the shear rates (5.1 sec&#;1 and 170 sec&#;1, respectively) into the general equation, they simplify to: Θ100 log Θ3 Θ na = = 0.657 log 100 170.2 Θ3 log 5.11 5.11Θ100 5.11Θ3 Ka = or 170.2na 5.11na
( ) ( )
These annular equations require a 100-RPM (Θ100) viscometer reading. This is not available on two-speed VG meters. The API recommends that an approximate value be calculated for the 100-RPM reading when using two-speed VG meter data: 2(Θ600 &#; Θ300) Θ100 = Θ300 &#; 3 General Power Law equation for effective viscosity (cP): µe = 100 x Kγ n&#;1 Effective viscosity, pipe: µep (cP) = 1.6 x Vp (np&#;1) 3np + 1 100 x Kp D 4np
(
) (
)
Effective viscosity, annulus: µea (cP) = 2.4 x Va (na&#;1) 2na + 1 100 x Ka D2 &#; D1 3na
(
) (
np
)
na
Where: D = ID drill pipe or drill collars D2 = ID hole or casing D1 = OD drill pipe or drill collars Although the API refers to these equations as being annular and pipe Power Law equations, the shear rate in the annulus may fall in the range best described by the pipe equations. The shear rate in the pipe can fall in the range best described by the annular equations. In either of these cases, the Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
Power Law equations that provide the best fit for the data should be used. Generally, the pipe Power Law equations should be used whenever the shear rate is greater than 170 sec&#;1.
MODIFIED POWER LAW
The modified Power Law&#;can approximate more closely the true rheological behavior of most drilling fluids.
As mentioned above, the API has chosen the Power Law model as the standard model. The Power Law model, however, does not fully describe drilling fluids because it does not have a yield stress and underestimates LSRV, as shown previously in Figure 14. The modified Power Law or HerschelBulkley model can be used to account for the stress required to initiate fluid movement (yield stress). The diagrams shown in Figures 20 and 21 illustrate the differences between the modified Power Law, the Power Law and Bingham Plastic models. Clearly, the modified Power Law model more closely resembles the flow profile of a typical drilling mud. A Fann VG meter has been used to get the dial readings at 600, 300 and 3 RPM. First, the three models are shown on rectangular coordinate paper (Figure 20), and then on log-log paper (Figure 21). In each case, the modified Power Law is between the Bingham Plastic model, which is highest, and the Power Law, which is lowest. The modified Power Law is a slightly more complicated model than either the Bingham Plastic model or the Power Law. However, it can approximate more closely the true rheological behavior of most drilling fluids. Mathematically the Herschel-Bulkley model is: τ = τ0 + Kγ n Where: τ = Shear stress τ0 = Yield stress or stress to initiate flow K = Consistency index γ = Shear rate n = Power Law index Rheology and Hydraulics
5.18
Shear stress (τ)
Rheology and Hydraulics
Bingham Plastic model
Modified Power Law Power Law Shear rate (γ)
Figure 20: Rheological model comparison.
Log shear stress (τ)
5
Bingham Plastic model
Modified Power Law Power Law Log shear rate (γ)
Figure 21: Log plot rheological model comparison.
In practice, the yield stress has been accepted to be the value for the 3-RPM reading or initial gel on the VG meter. Converting the equations to accept VG meter data gives the equations for &#;n&#; and &#;K.&#; Θ2 &#; Θ0 log Θ1 &#; Θ0 n= ω2 log ω1 Θ &#; Θ K= 1 n 0 ω1
( ) ( )
Where: n = Power Law index or exponent K = Power Law consistency index or fluid index (dyne sec&#;n/cm2) Θ1 = Mud viscometer reading at lower shear rate Θ2 = Mud viscometer reading at higher shear rate Θ0 = Zero gel or 3-RPM reading ω1 = Mud viscometer (RPM) at lower shear rate ω2 = Mud viscometer (RPM) at higher shear rate
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5
Rheology and Hydraulics
Stages of Flow
&#;true yield stress is related to the force needed to &#;break circulation.&#;
Rheology and Hydraulics
5.19
Wellbore Stage 6
Turbulent flow Drill pipe
The drilling fluid is subject to a variety of flow patterns during the process of drilling a well. These flow patterns can be defined as different stages of flow as depicted in Figure 22. Stage 1 &#; No flow. Most drilling fluids resist flow strongly enough so that pressure must be applied to initiate flow. The maximum value of this force is the true yield stress of the fluid. In a well, the true yield stress is related to the force needed to &#;break circulation.&#; Stage 2 &#; Plug flow. When the true yield stress is exceeded, flow will commence as a solid plug. In plug flow, the velocity will be the same across the pipe diameter or annulus except for the fluid layer against the conduit wall. The flow of toothpaste from a tube is often used as an example of plug flow. The velocity profile of plug flow is flat. Stage 3 &#; Plug to laminar flow transition. As the flow rate is increased, shear effects will begin to influence the layers within the fluid and reduce the size of the plug in the center of flow. The velocity will increase from the wellbore to the edge of the central plug. The velocity profile is flat across the plug that has the highest velocity, and tapers or decreases to zero at the conduit wall. Stage 4 &#; Laminar flow. As the flow rate is increased, the flow rate and wall effects on the fluid continue to increase. At some point, the central plug will cease to exist. At this point, the velocity will be highest in the center of flow and diminish to zero at the conduit wall. The velocity profile will resemble a parabola. The velocity of the fluid is related to the distance from the annulus or pipe wall. Inside a pipe, the flow can be depicted as a series of telescoping layers with each layer toward the center having a higher velocity. All of the fluid across the pipe or annulus will
Stage 5
Transition flow
Stage 4
Complete streamline
Stage 3
Incomplete streamline
Stage 2 Plug flow
Stage 1
No flow
Figure 22: Stages of flow.
be moving in the direction of flow, but with different velocities. This stage of orderly flow is called laminar for the layers or laminae described by the differing velocities. Stage 5 &#; Laminar to turbulent flow transition. As the flow rate increases, the orderly flow will begin to break down. Stage 6 &#; Turbulent flow. As the flow rate continues to increase, the orderly flow will be completely disrupted, and the fluid will swirl and eddy. The bulk movement of fluid will continue to be along the annulus or Revision No: A-0 / Revision Date: 03·31·98
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While drilling, the drillstring is almost always in turbulent flow, and the resulting increases in pressure loss can limit the flow rate.
Rheology and Hydraulics
pipe in one direction, but at any point within the body of fluid, the direction of movement will be unpredictable. Under these conditions the flow is turbulent. After these conditions are reached, any further increases in the flow rate will only increase the turbulence. These flow stages have several different implications. The pressure required to pump a fluid in turbulent flow is significantly higher than the pressure required to pump the same fluid in laminar flow. Once the flow is turbulent, increases in the flow rate increase the circulating pressure geometrically. In turbulent flow, doubling the flow rate will increase the pressure by a factor of four (22). Increasing the flow rate
three times will increase the pressure loss eight times (23). While drilling, the drillstring is almost always in turbulent flow, and the resulting increases in pressure loss can limit the flow rate. The pressure losses associated with turbulent flow in the annulus can be critical when the Equivalent Circulating Density (ECD) approaches the fracture gradient. In addition, turbulent flow in the annulus is associated with hole erosion and washouts in many formations. In susceptible zones, the hole will erode to a diameter where the flow reverts to laminar. When drilling these zones, the flow rate and the mud&#;s rheological properties should be controlled to prevent turbulent flow.
Hydraulics Calculations
It is&#; imperative to optimize drilling-fluid hydraulics by controlling the rheological properties&#;
Once the rheological properties for a fluid have been determined and modeled to predict flow behavior, hydraulics calculations are made to determine what effect this particular fluid will have on system pressures. The critical pressures are total system pressure (pump pressure), pressure loss across the bit and annular pressure loss (converted to ECD). Many wells are drilled under pressure limitations imposed by the drilling rig and associated equipment. The pressure ratings of the pump liners and surface equipment and the number of mud pumps available limit the circulating system to a maximum allowable circulating pressure. As wells are drilled deeper and casing is set, the flow rate will be decreased in the smaller diameter holes. The circulating pressures will increase because of the increased length of the drillstring
Rheology and Hydraulics
5.20
and annulus as well as the possibly smaller-diameter drillstring. The mud pump liners will be changed to have smaller diameters and higher pressure ratings. This will increase the maximum allowable circulating pressure. Under any set of hole conditions, a theoretical limit is imposed on the flow rate by the maximum allowable circulating pressure. Circulating pressures, and consequently the flow rate, are directly related to the wellbore and tubular geometry used, including special Bottom-Hole Assembly (BHA) equipment, as well as the fluid&#;s density and rheological properties. It is therefore imperative to optimize drillingfluid hydraulics by controlling the rheological properties of the drilling fluid to avoid reaching this theoretical limit. This is especially true in extended-reach drilling.
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Rheology and Hydraulics
GUIDELINES FOR HYDRAULICS OPTIMIZATION
The major goal of hydraulics optimization is to balance well control, hole cleaning, pump pressure, ECD and pressure drop across the bit.
The maximum allowable circulating pressure and circulating rate are limited assets that can be wasted or maximized. Rheology and hydraulics calculations provide the means for adjusting the mud&#;s properties, the flow rate and the bit nozzles to optimize these assets under the constraints imposed by the rig equipment. The major goal of hydraulics optimization is to balance well control, hole cleaning, pump pressure, ECD and pressure drop across the bit. The fluid&#;s density and rheological properties are the parameters that affect this hydraulic efficiency. If it is assumed that fluid density is maintained at a minimal safe level for well control and wellbore stability, hydraulics optimization is then dependent on the fluid&#;s rheological properties and the flow rate. In many cases, downhole equipment such as downhole motors, thrusters, and measurement-while-drilling and logging-while-drilling instrumentation has a minimum flow rate requirement to properly function. This leaves fluid rheological properties as the only variable in the optimization process.
API
HYDRAULICS EQUATIONS
With one exception, the formulae in this chapter are generally consistent with those in the API bulletin, &#;Recommended Practice on the Rheology and Hydraulics of Oil-Well Drilling Fluids&#; (API Recommended Practice 13D Third Edition, June 1, ). The API equations determine, use and report velocities in the annulus and pipe in feet per second. M-I SWACO reports velocities in feet per minute. In this chapter, the API formulae have been modified to determine and use velocities in feet per minute. The M-I SWACO computer and calculator software (PCMOD 3, HYPLAN, RDH and QUIKCALC3) use these hydraulics Rheology and Hydraulics
5.21
equations. There is an example problem at the end of this chapter to demonstrate the use of these equations. Fluids in laminar flow &#;act&#; differently than fluids in turbulent flow. These differences make it necessary to use different equations to determine the pressure losses in laminar and turbulent flow. Different equations are also required to calculate the pressure losses in the annulus and drillstring because of different geometries. The first step in hydraulics calculations is to determine which stage of flow is occurring in each geometric interval of the well. The velocity of the fluid in each of these intervals can be determined with the equations below.
AVERAGE
BULK VELOCITY
The API refers to the velocity of fluid flowing in an annulus or pipe as the bulk velocity. This assumes that all of the fluid is flowing at the same velocity with a flat profile and no instantaneous velocity differences as occurs in turbulent flow. It is basically an average velocity. Average bulk velocity in pipe (Vp): 24.48 x Q (gpm) Vp (ft/min) = D2 (in.) Average bulk velocity in annulus: 24.48 x Q (gpm) Va (ft/min) = (D22 &#; D12)(in.) Where: V = Velocity (ft/min) Q = Flow ratio (gpm) D = Diameter (in.)
REYNOLDS
NUMBER
The Reynolds number (NRe) is a dimensionless number that is used to determine whether a fluid is in laminar or turbulent flow. The assumption is made in &#;Recommended Practice on the Rheology and Hydraulics of Oil-Well Drilling Fluids&#; (API Recommended Practice 13D Third Edition, June 1, ), that a Reynolds number less than Revision No: A-2 / Revision Date: 12·31·06
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A Reynolds number greater than 2,100 indicates turbulent flow.
Rheology and Hydraulics
or equal to 2,100 indicates laminar flow. A Reynolds number greater than 2,100 indicates turbulent flow. Earlier API hydraulics bulletins and many hydraulics programs that predate the current API hydraulics bulletin define laminar and turbulent flow differently. The general formula for Reynolds number is: V Dρ NRe = µ
CRITICAL
VELOCITY
The critical velocity is used to describe the velocity where the transition occurs from laminar to turbulent flow. Flow in the drill pipe is generally turbulent. The equations for critical velocity in the pipe and in the annulus are listed below. Critical flow rate can be calculated from these equations. Critical pipe velocity (Vcp): Vcp (ft/min) = 1 38,727 x Kp (2 &#; n) x ρ
Where: V = Velocity D = Diameter ρ = Density µ = Viscosity
(
The Reynolds number for inside the pipe is: 15.467 x Vp Dρ NRep = µep The Reynolds number for the annulus is: 15.467Va (D2 &#; D1)ρ NRea = µea
)
(n 1.6 3n + 1 2 &#; n) x D 4n
(
)
Critical pipe flow rate: V D2 Qcp (gpm) = cp 24.51 Critical annular velocity (Vca): Vca (ft/min) = 1 25,818 x Ka (2 &#; n) x ρ
(
)
n 2n + 1 (2 &#; n) 2.4 x (D2 &#; D1) 3n
(
)
Critical annular flow rate: V (D22 &#; D12) Q ca (gpm) = ca 24.51
Where: D = ID drill pipe or drill collars D2 = ID hole or casing D1 = OD drill pipe or drill collars µep = Effective viscosity (cP) pipe µea = Effective viscosity (cP) annulus
Rheology and Hydraulics
5.22
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Rheology and Hydraulics
Pressure-Loss Calculations CIRCULATING
The sum of interval pressure drops is equal to the total system pressure loss&#;
SYSTEM
The circulating system of a drilling well is made up of a number of components or intervals, each with a specific pressure drop. The sum of these interval pressure drops is equal to the total system pressure loss or the measured standpipe pressure. Figure 23 is a schematic of the circulating system. This figure can be simplified to Figure 24 that illustrates the relative flow area of each interval. There can be any number of subintervals within the categories listed in the table below. 0 1 2 3 4 5 6 7
Top drive or kelly Standpipe
Fluid in Casing or riser
Drill pipe
Standpipe/top drive/ kelly Inside drill pipe Inside drill collars Inside downhole tools Bit nozzle Annulus open hole/drillstring Annulus liner/drillstring Annulus casing or riser/drillstring
The total pressure loss for this system can described mathematically as: PTotal = PSurf Equip + PDrillstring + PBit + PAnnulus Each of these pressure groups is broken down into their component parts and appropriate calculations.
Fluid out
Standpipe gauge
Liner
Drill collars Open hole
Downhole tools Bit
Figure 23: Schematic of a circulating system.
0
1 7
2
6
3 4
5
Figure 24: Simplified circulation system.
Rheology and Hydraulics
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Rheology and Hydraulics
SURFACE
Surface pressure losses include losses between the standpipe pressure gauge and the drill pipe.
EQUIPMENT PRESSURE LOSSES
Surface pressure losses include losses between the standpipe pressure gauge and the drill pipe. This includes the standpipe, kelly hose, swivel, and kelly Case 1 2 3 4
TOP
Standpipe 40 ft (12 m) long, 3-in. ID 40 ft (12 m) long, 31&#;2-in. ID 45 ft (14 m) long, 4-in. ID 45 ft (14 m) long, 4-in. ID
Hose Swivel, etc. 45 ft (14 m) long, 20 ft (6.1 m) long, 2-in. ID 2-in. ID 55 ft (17 m) long, 25 ft (7.6 m) long, 21&#;2-in. ID 21&#;2-in. ID 55 ft (17 m) long, 25 ft (7.6 m) long, 3-in. ID 21&#;2-in. ID 55 ft (17 m) long, 30 ft (9.1 m) long, 3-in. ID 3-in. ID
DRIVE SURFACE CONNECTIONS
There is no current standard case for top drive units. The surface connections of most of these units consist of an 86-ft (26.2-m) standpipe and 86 ft (26.2 m) of hose with either a 3.0- or 3.8-in. ID. In addition, there is an &#;S&#; pipe that is different on almost every rig.
DRILLSTRING
PRESSURE LOSSES
The pressure loss in the drillstring is equal to the sum of the pressure losses in all of the drillstring intervals, including drill pipe, drill collars, mud motors, MWD/LWD/PWD or any other downhole tools.
FRICTION
FACTOR
Before calculating the pressure loss, the Fanning friction factor (fp) is calculated next with different equations being used for laminar and turbulent flow. This friction factor is an indication of the resistance to fluid flow at the pipe wall. The friction factor in these calculations assumes a similar roughness for all tubulars.
Rheology and Hydraulics
or top drive. To calculate the pressure loss in the surface connections, use the API pipe formula for pressure loss in the drill pipe. Common surface equipment geometries are listed in the table below.
5.24
Kelly 40 ft (12 m) long, 21&#;4-in. ID 40 ft (12 m) long, 31&#;4-in. ID 40 ft (12 m) long, 31&#;4-in. ID 40 ft (12 m) long, 4-in. ID
Eq. Length 3.826-in. ID 2,600 ft (792 m) 946 ft (288 m) 610 ft (186 m) 424 ft (129 m)
If the Reynolds number is less than or equal to 2,100: 16 fp = NRep If the Reynolds number is greater than 2,100: log n + 3.93 50 fp =
(
NRep[
PIPE
)
]
1.75 &#; log n 7
INTERVAL PRESSURE LOSS
Drillstring (including drill collars) intervals are determined by the ID of the pipe. The length of an interval is the length of pipe that has the same internal diameter. The following equation is used to calculate the pressure loss for each drillstring interval. f V 2ρ xL Pp (psi) = p p 92,916D Where: Vp = Velocity (ft/min) D = ID pipe (in.) ρ = Density (lb/gal) L = Length (ft)
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________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Rheology and Hydraulics
PRESSURE
LOSSES THROUGH MOTORS AND TOOLS
If the drillstring contains a downhole motor; an MWD, LWD or PWD tool; a turbine or a thruster, their pressure losses must be included in the system pressure losses when calculating the system&#;s hydraulics. These pressure losses can significantly change the pressure available at the bit, as well as bypass flow around the bit. The pressure loss through MWD and LWD tools varies widely with mud weight, mud properties, flow rate, tool design, tool size and the data transmission rate. Some manufacturers publish pressure losses for their tools but these pressure losses can be conservative, because they are usually determined with water. The pressure loss through Positive Displacement Motors (PDM) (Moyno), thrusters and turbines is higher than the losses across MWD and LWD tools and subject to even more variables. With a PDM or thruster, increased weight on the bit increases the torque and pressure loss across the motor. The pressure drop through a turbine is proportional to the flow rate, the mud weight and the number of drive stages in the turbine. The pressure loss across motors and turbines cannot be accurately determined by formula, but, again, this pressure loss data is available from the suppliers.
PRESSURE
LOSS AT THE BIT (FRICTION PRESSURE LOSS IN THE NOZZLES)
In the case of coring or diamond bits, the Total Flow Area (TFA) and appropriate conversion factors are substituted into the equation to give: ρQ2 Pbit (psi) = 10,858(TFA)2 Where: ρ = Density (lb/gal) Q = Flow ratio (gpm) TFA = Total Flow Area (in.2)
TOTAL
ANNULUS PRESSURE LOSSES
The total annular pressure loss is the sum of all of the annular interval pressure losses. Annular intervals are divided by each change in hydraulic diameter. A change in drillstring outside diameter and/or a change in casing, liner or open hole inside diameter would result in a hydraulic diameter change. As with the drillstring pressure loss equations, the friction factor must first be determined before calculating the pressure loss for each annular section.
FRICTION
FACTOR ANNULUS
If the Reynolds number is less than or equal to 2,100: 24 fa = NRea If the Reynolds number is greater than 2,100: log n + 3.93 50 fa =
(
NRea[
)
]
1.75 &#; log n 7
The pressure loss across the bit is calculated with the following equation: 156ρQ2 Pbit = 2 2 2 + Dn2 + Dn3 + &#;)2 (Dn1
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Rheology and Hydraulics
ANNULUS
The pressure loss for each interval must be calculated separately and added together for the total annular pressure loss.
INTERVAL PRESSURE LOSS
HORSEPOWER AT BIT
The bit hydraulic horsepower cannot exceed the total system hydraulic horsepower. QPBit hhpb = 1,740 Where: Q = Flow rate (gpm) PBit = Bit pressure loss (psi)
Where: D2 = ID hole or casing (in.) D1 = OD drill pipe or drill collars (in.)
HYDRAULIC HORSEPOWER PER SQUARE INCH OF BIT AREA
EQUIVALENT
CIRCULATING DENSITY
The pressure on a formation while circulating is equal to the total annular circulating pressure losses from the point of interest to the bell nipple, plus the hydrostatic pressure of the mud. This force is expressed as the density of mud that would exert a hydrostatic pressure equivalent to this pressure. This equivalent mud weight is called the Equivalent Circulating Density (ECD). ECD (lb/gal) = Pa (psi) ρ (lb/gal) + 0.052 x TVD (ft) Excessive ECD may cause losses by exceeding fracture gradient on a well. It is important to optimize rheological properties to avoid excessive ECD.
BIT
Low hydraulic horsepower at the bit can result in low penetration rates and poor bit performance.
HYDRAULIC
The pressure loss for each interval must be calculated separately and added together for the total annular pressure loss. This equation is used to calculate the individual interval pressure losses. faVa2ρ x Lm Pa (psi) = 92,916 (D2 &#; D1)
HYDRAULICS CALCULATIONS
In addition to bit pressure loss, several other hydraulics calculations are used to optimize the drilling performance. These include hydraulic horsepower, impact force and jet velocity calculations.
HYDRAULIC
HORSEPOWER
The recommended hydraulic horsepower (hhp) range for most rock bits is 2.5 to 5.0 Horsepower per Square Inch (HSI) of bit area. Low hydraulic horsepower at the bit can result in low penetration rates and poor bit performance.
Rheology and Hydraulics
5.26
HSI =
1.27 x hhpb Bit Size2
Where: Bit Size = Bit diameter (in.)
SYSTEM
HYDRAULIC HORSEPOWER
hhpSystem =
PTotalQ 1,714
Where: PTotal = Total system pressure losses (psi) Q = Flow rate (gpm)
NOZZLE
VELOCITY (FT/SEC):
Although more than one nozzle size may be run in a bit, the nozzle velocity will be the same for all of the nozzles. Nozzle velocities of 250 to 450 ft/sec (76.2 to 137.2 m/sec) are recommended for most bits. Nozzle velocities in excess of 450 ft/sec (137.2 m/sec) may erode the cutting structure of the bit. 417.2 x Q Vn (ft/sec) = 2 2 2 + Dn3 +&#; Dn1 + Dn2 Where: Q = Flow rate (gpm) Dn = Nozzle diameter (1 &#;32 in.)
PERCENT
PRESSURE DROP AT THE BIT
It is generally desired to have 50 to 65% of surface pressure used across the bit. P %ΔPBit = Bit x 100 PTotal
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
Generally, the goal is to use 50 to 65% of the maximum allowable circulating pressure to the bit.
Rheology and Hydraulics
HYDRAULIC IMPACT FORCE (IF) IF (lb) =
VnQρ 1,930
Where: Vn = Nozzle velocity (ft/sec) Q = Flow rate (gpm) ρ = Density (lb/gal)
IMPACT
FORCE/IN.2
IF (psi) =
BIT
1.27 x IF (lb) Bit Size2
HYDRAULICS OPTIMIZATION
In many areas of the world, rock bit hydraulics can be optimized to improve rate of penetration. There are a lot of factors that effect ROP including bit size, bit type, bit features, formation type and strength, and bit hydraulics. In hard rock areas, bit/formation interaction has a greater impact on ROP than bit hydraulics. Bit hydraulics may be optimized on hydraulic impact, hydraulic horsepower, hydraulic horsepower per square inch of hole beneath the bit or nozzle velocity. Generally, the goal is to use 50
to 65% of the maximum allowable circulating pressure to the bit. Systems are considered optimized for impact force when the pressure loss at the bit is equal to 50% of the circulating pressure. When the pressure loss at the bit is equal to approximately 65% of the circulating pressure, the system is considered optimized for hydraulic horsepower. Figure 24 compares optimization by hydraulic horsepower and impact force. There is a tradeoff in optimizing with respect to one aspect vs. the other. In the soft formations typical of offshore wells, the only limit on the penetration rate may be the connection time. The jetting action is not as critical. Under these conditions, high flow rates and turbulence beneath the bit to reduce balling of the bit and BHA (bit, collars, etc.) and cleaning the wellbore are the primary concerns. For these conditions, the bit can be optimized for impact force and flow rate. When optimized for impact force, approximately 50% of the maximum allowable
3,000 Pressure loss, impact force and hydraulic horsepower
5
2,750 Maximum allowable surface pressure
2,500
Bit pre ssu re l oss
2,250 2,000 1,750
d an ng i r st ill Dr
Optimized for hydraulic horsepower
1,500
s se os l lar nu an
Optimized for impact force
1,250 1,000
Hydraulic impact force
750 500 power Hydraulic horse
250 0 0
50
100
150
200 250 Flow rate (gpm)
300
350
400
450
Figure 25: Effect of flow rate on pressure loss and bit hydraulics. Rheology and Hydraulics
5.27
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
5
Care should be taken to not &#;optimize the nozzles down&#; to a size that will not permit the use of lostcirculation material.
Rheology and Hydraulics
circulating pressure will be lost at the bit. When drilling hard shales at greater depths, chip hold-down and fines beneath the bit are the limiting factors for penetration rates. Under these conditions, relatively small increases in the penetration rate can lower well costs significantly. Jetting action is critical and drilling rates are improved when the bit is optimized for hydraulic horsepower with 65% of the maximum allowable circulating pressure loss at the bit.
LIMITATIONS
OF OPTIMIZING FOR PERCENT PRESSURE LOSS AT THE BIT
While there is a need to achieve optimum drilling performance, there are upper limits to acceptable hydraulics. Excessive nozzle velocities may damage the cutting structures of bits and shorten bit life. Nozzle shear rates in excess of 100,000 sec&#;1 have been associated with hole washout. In addition to upper limits there are also lower acceptable limits. Selecting the bit nozzles for 50 or 65% of the circulating pressure loss at the bit without considering the circulating system as a whole can create problems. As a well is drilled deeper, the pressure losses in the drillstring and annulus increase if the flow rate is maintained. As this occurs, a smaller percentage of the maximum allowable circulating pressure will be available for use at the bit. It will become impossible to maintain the flow rate and the bit pressure loss at 65% of the maximum allowable circulating pressure. If the circulating rate is decreased, the pressure losses in the drillstring and annulus will decrease. The nozzles can then be sized to maintain the bit pressure loss at 65% of the maximum allowable surface pressure. Although the percent pressure loss at the bit can be maintained by decreasing the flow rate, the horsepower at the bit and the
Rheology and Hydraulics
5.28
circulating rate will decrease with depth and drilling performance can suffer. The flow rate must be maintained at adequate levels for hole cleaning, even though the bit pressure loss becomes less than desired. Care should also be taken to not &#;optimize the nozzles down&#; to a size that will not permit the use of lost-circulation material. This problem is sometimes avoided by blanking one of the nozzles and sizing the remaining nozzles for the total flow area. With one of the nozzles blanked, the bit can be optimized with larger-size nozzles. Optimum flow rates change with the type of formation being drilled, the hole size, hole angle, and whether the bit is optimized for impact force or hydraulics. Use a hole cleaning computer model such as the M-I SWACO VIRTUAL HYDRAULICS software or RDH, or charts for deviated wells to determine an appropriate flow rate.
DOWNHOLE
TOOLS, BYPASSED FLOW
Downhole tools can also affect the ability to optimize bit hydraulics. Some (but not all) MWD and LWD tools bypass up to 5% of the flow. This bypassed fluid does not reach the bit and must be subtracted from the flow to the bit when optimizing bit hydraulics. The full flow rate (not reduced by the bypassed volume) is used for calculating annular hydraulics and pressure losses in the drill pipe and drill collars. The MWD and LWD manufacturer&#;s representative should be contacted to determine if a specific tool bypasses flow, how much it bypasses and the estimated pressure loss through the tool. The bearing sections of both PDMs and turbines require a portion of the flow for cooling. This fluid is directed to the annulus and bypasses the bit. The bypassed volume depends on a number of different variables, but usually ranges
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
Using extended nozzles&#;can increase the jet intensity on the formation.
Drag reduction is the tendency of a fluid to delay the onset of turbulent flow.
Rheology and Hydraulics
from 2 to 10% of the total flow rate. This bypassed fluid must be subtracted from the flow to the bit when optimizing bit hydraulics. The full flow rate (not reduced by the bypassed volume) is used for calculating annular hydraulics and pressure losses in the drill pipe and drill collars. The PDM or turbine manufacturer&#;s representative should be contacted to determine the specific volume that is bypassed and the estimated pressure loss through the motor.
BOTTOM-HOLE
CLEANING
In addition to providing energy at the face of the bit, the drilling fluid should also effectively remove the cuttings from beneath the bit to maximize ROP by avoiding &#;redrilling.&#; Cleaning can be improved by several means, none of which affect the way pressure losses and energy at the bit are calculated. Increasing the intensity of the jet action from the nozzles on the face of the formation beneath the bit by extending nozzles will improve bottom-hole cleaning. Blanking a nozzle will permit better crossflow beneath the bit. A center jet improves cone cleaning to avoid bit balling. The jet action is greatest as the mud exits the nozzles and diminishes with distance from the nozzles through interaction with the surrounding mud. Using extended nozzles that place the exits closer to the bottom of the hole can increase the jet intensity on the formation. Jet intensity can also be maintained by using asymmetric nozzle sizes (increasing the size of one nozzle while reducing the size of the others). This will maintain the desired total flow area and pressure loss at the bit while giving greater jetting intensity from at least one of the nozzles. The proximity of the nozzle to the bottom of the hole is often described with the H/D ratio, where H is the distance of the nozzle from the bottom of the hole and D is the nozzle diameter. This H/D ratio Rheology and Hydraulics
5.29
1.0 lb/bbl
l b/bb 1.5 l
Flow rate (bpm)
5
l b/bb 0.5 l
Water
Pressure loss (psi)
Figure 26: Drag reduction with FLO-VIS.
will indicate the intensity of the jetting action. The full intensity of the jet is maintained in the center of flow at H/D ratios of 8 or less and falls off rapidly at higher ratios. Increasing the nozzle diameter will lower the H/D ratio, but it also lowers the nozzle velocity and pressure drop through the bit. PDC bit nozzle placement is designed to effectively remove cuttings from beneath the bit. The nozzle layout is also important to effectively cool the cutter faces.
DRAG
REDUCTION
Drag reduction is the tendency of a fluid to delay the onset of turbulent flow. The result of this delay is decreased pressure loss. Figure 26 shows how increasing the concentration of FLO-VIS reduces circulating pressure. Several long-chain polymers (POLY-PLUS, FLO-VIS, DUO-VIS, HEC) promote drag reduction. A drop in pump pressure can be observed when these materials are added to the system. Drag reduction is a very complex behavior. It is not completely understood, and there is no model to predict or compensate for it. Drag reduction can be very time- and solids-dependent. The pump pressure increases gradually on subsequent circulations as the polymers are broken down or envelop solids.
VIRTUAL HYDRAULICS The VIRTUAL HYDRAULICS computer program from M-I SWACO uses the vast Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
5
&#;the maximum reduction in hydrostatic pressure is called the swab pressure.
Rheology and Hydraulics
number of variables that affect drilling fluid hydraulics to produce a clearer picture of the viscosities and pressure losses that are occurring under downhole conditions. It incorporates not only field viscosity data but also high-temperature and high-pressure viscosity to better predict the behavior of invert systems under non-standard conditions. VIRTUAL HYDRAULICS software is also capable of accounting for subtle changes in pipe and wellbore geometry that heretofore had been averaged across an interval. The information produced by this program is extremely accurate and can be validated with downhole pressure measurement devices.
SWAB
AND SURGE PRESSURES
When the drillstring is picked up to make a connection or trip out of the well, the mud in the annulus must fall to replace the volume of pipe pulled from the well. The hydrostatic pressure is momentarily reduced while the mud is falling in the annulus. This action is referred to as swabbing and the maximum reduction in hydrostatic pressure is called the swab pressure. Swab pressures are related to the frictional pressures of the mud flowing in the annulus to displace the drillstring, not the reduction in hydrostatic pressure due to the lower mud level in the annulus. If the swab pressure is greater than the hydrostatic pressure safety margin (overbalance pressure), formation fluids will be swabbed into the wellbore. When the drillstring or casing is lowered or run into the well, mud is displaced from the well. The frictional pressure losses from the flow of mud in the annulus as it is displaced by the pipe causes pressures in excess of the hydrostatic pressure of the column of mud in the wellbore. The elevated pressures caused by running the drillstring AVSwab-Surge (ft/min) =
Rheology and Hydraulics
into the well are called surge pressures. If the surge pressure plus the hydrostatic pressure exceed the fracture gradient, the formation will be fractured with resultant loss of circulation. Swab and surge pressures are related to the mud&#;s rheological properties; the mud&#;s gel strengths; the speed at which the pipe is pulled from, or run into, the well; the annular dimensions; and the length of drillstring in the well. The rheological properties affect swab and surge pressures in the same manner as they affect annular pressure losses. Increases in either the plastic viscosity or the yield point will increase the swab and surge pressures. The velocity of the mud being displaced is different for each annular space and is directly related to the velocity of drillstring movement, whether tripping in or out of the well. Since the maximum (not average) swab and surge pressures must be less than the pressures needed to swab the well in or break the formation down, swab and surge pressures must be calculated for the maximum drillstring velocity when tripping. This is generally calculated as one-and-one-half times the average drillstring velocity. VMaxDrillstring (ft/min per stand) = stand length (ft) 1.5 x x 60 sec/min seconds per stand The annular velocity is calculated for each interval based on the drillstring displacement for that interval. The drillstring displacement is adjusted accordingly for free flow from or into the drillstring (no float, plugged bit, etc.) or for plugged drillstring where the displacement plus capacity of the drillstring is used. The annular velocity must be calculated for each annular space. These annular velocities should be substituted
VMaxDrillstring (ft/min) x drillstring displacement (bbl/ft) annular capacity (bbl/ft) 5.30
Revision No: A-2 / Revision Date: 12·31·06
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5
The object of calculating swab and surge pressures is to determine safe pulling and running speeds and minimized trip times.
Rheology and Hydraulics
into the API equations for the annular pressure losses for each interval. The swab and surge pressures are then calculated in the same manner as the ECD. The object of calculating swab and surge pressures is to determine safe pulling and running speeds and minimized trip times. This is done by changing the maximum or minimum time per stand and recalculating the swab and surge pressures until times per stand are found where the swab and surge pressures plus the hydrostatic pressure is approximately equal to the formation pressure and fracture pressure. This time per stand is only relevant for the present length of drillstring in the well.
As pipe is removed from the hole, the drillstring length decreases and the bottom hole assembly will be pulled into large diameter casing. This will make it possible to pull each stand faster without risk of swabbing in the well. When tripping in to the well, the length of drillstring will be increasing and the annular spaces will decrease as the BHA is run into smaller diameters. This will require that the running time per stand be increased to avoid fracturing the formation. The swab and surge pressures should be calculated at either 500- or 1,000-ft (152- or 305-m) intervals.
Summary
Controlling the mud&#;s rheological properties can optimize the performance while operating within the mechanical limits imposed by the rig.
Drilling performance is directly related to the mechanical limitations imposed by the drilling rig. Controlling the mud&#;s rheological properties can optimize the performance while operating within the mechanical limits imposed by the rig. The mud&#;s rheological properties
should be controlled to deliver as much of the rig&#;s maximum allowable circulating pressure as possible to the bit by reducing the parasitic pressure losses in the surface connections, drillstring and annulus without compromising hole cleaning or solids suspension.
Hydraulics Example Problem PROBLEM: MD/TVD: 12,031 ft (3,667 m) Surface casing: 2,135 ft (651 m) of 133&#;8-in. 61 lb/ft (28 kg/ft) Intermediate casing: 10,786 ft (3,288 m) of 95&#;8-in. 40 lb/ft (18 kg/ft) Bit: 85&#;8 in. Nozzles (1&#; 32 in.): 11, 11, 11 Surface connections: Case 3 Drill pipe: 41&#;2 in., 16.6 lb/ft (7.5 kg/ft) Drill collars: 390 ft (119 m) of 7 in. x 21&#;4 in. Surface pressure: 3,000 psi (207 bar) Rheology and Hydraulics
5.31
Mud weight: 12.8 lb/gal (1.5 kg/L) Funnel viscosity: 42 sec/qt Plastic viscosity: 19 cP Yield point: 15 lb/100 ft2 (7 Pa) Initial gel: 8 lb/100 ft2 (4 Pa) Flow rate: 335 gpm (1,268 L/min) Calculations: Hydraulics calculations use a series of formulae that must be used in sequence. Since the mud velocity and viscosity change every time the internal diameter of the drillstring and annulus diameter changes, hydraulics must be calculated for each length of drillstring and annulus that has a different diameter. Although the same values are calculated for the annular and Revision No: A-2 / Revision Date: 12·31·06
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5
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Rheology and Hydraulics
drillstring intervals, different formulae are used to compensate for the differences in flow in the drillstring and annulus. The sequence of calculations for each interval is as follows: &#; &#;n&#; and &#;K&#; values. &#; Bulk velocity. &#; Effective viscosity. &#; Reynolds number. &#; Friction factor (one of two different formulae will be used depending on the value of the Reynolds number). &#; Interval-pressure loss. The annular interval-pressure losses are totaled and used to calculate the equivalent circulating density. Pipe (drillstring) equations and the equivalent hydraulic pipe length of the surface connections are used to calculate the pressure loss of the surface connections. The sum of the pressure losses in the surface connections, drillstring, downhole tools, bit and annulus should approximate the surface pressure. Θ300 = PV + YP = 19 + 15 = 34 Θ600 = Θ300 + PV = 34 + 19 = 53 Θ100 = Θ300 &#; Θ100 = 34 &#;
2PV 3
2 x 19 = 21 3
The API annular hydraulics formulae use the 100-RPM VG meter reading. If six-speed mud viscometer data is available, use the 100-RPM reading rather than the calculated value. Intermediate casing ID: 8.835 in. Open hole interval: MD &#; casing length 12,031 &#; 10,786 ft = 1,245 ft (3,667 &#; 3,288 m = 379 m) Surface connection Case 3, equivalent length (ft): 610 ft (186 m) of 3.826-in. ID pipe Drill pipe ID: 3.826 in.
Rheology and Hydraulics
5.32
Drill pipe length: MD &#; collar length 12,031 &#; 390 ft = 11,641 ft (3,667 &#; 119 m = 3,548 m) of 41&#;2 in. x 3.826 in.
ANNULAR
GEOMETRY:
Interval #1: Length: 10,786 ft (3,288 m); casing ID: 8.835 in.; drill pipe: 41&#;2 in. Start from the surface, with the drill pipe in casing as the first interval. The first interval length will be the shorter of the two, the casing length, 10,786 ft (3,288 m). The drill pipe is 855 ft (261 m) longer than the casing (11,641 &#; 10,786). This 855-ft (261-m) portion of the drill pipe will be used to calculate the length of the next interval. Interval #2: Length: 855 ft (261 m); open hole ID: 85&#;8 in.; drill pipe: 41&#;2 in. Determine the length of the next geometry interval using the 855 ft (261 m) of drill pipe that extends below the casing and the next hole interval, 1,245 ft (379 m) of open hole. The shorter of the two, the drill pipe, determines the length of the second interval, 855 ft (261 m). The open hole is 390 ft (119 m) longer (1,245 &#; 855) than the drill pipe. This length will be used to determine the length of the next geometry interval. Interval #3: Length: 390 ft (119 m); open hole ID: 85&#;8 in.; drill collars: 7 in. The next drillstring interval consists of 390 ft (119 m)of drill collars. This length is equal to the length of the remainder of the open-hole interval from Interval #2; therefore the length of the final geometry interval is 390 ft (119 m).
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
5
________________________ ________________________ ________________________ ________________________
Rheology and Hydraulics
np = 3.32 log
________________________ ________________________
________________________ ________________________
( ) 53 34
5.11Θ600 1,022np
Kp =
5.11 x 53 = 3.21 1,.64
SURFACE
________________________ ________________________ ________________________
Pp =
Vp =
Vp (ft/min) = Vp =
24.48 x Q (gpm) D2 (in.)
24.48 x 335 560.23 ft/min = 3. (170.8 m/min)
Effective viscosity: µep (cP) = 1.6 x Vp 100 x Kp D µep =
(
) (
)
(
) (
)
(np&#;1)
1.6 x 560.23 100 x 3.21 3.826
3np + 1 4np
np
3 x 0.64 + 1 x 4 x 0.64
(0.64&#;1)
0.64
fp =
Effective viscosity: µep (cP) = 1.6 x Vp 100 x Kp D µep =
)
Rheology and Hydraulics
7
) (
)
1.6 x 560.23 3.826
(0.64&#;1)
x
np
3 x 0.64 + 1 4 x 0.64
0.64
Friction factor: Since the Reynolds number is greater than 2,100, use the turbulent equation. log n + 3.93 50 fp =
)
NRep[
log (0.64) + 3.93 50
[
(
3np + 1 4np
Reynolds number: 15.467 x VpDρ NRep = µep
]
8,667 = 0.
)
100 x 3.21
1.75 &#; log n 7
1.75 &#; log (0.64)
) (
(
)
(
(
(np&#;1)
15.467 x 560.23 x 3.826 x 12.8 48.96 = 8,667
15.467 x 560.23 x 3.826 x 12.8 NRep = 48.96 = 8,667
(
24.48 x 335 560.23 ft/min = 3. (170.8 m/min)
NRep =
Reynolds number: 15.467 x VpDρ NRep = µep
Friction factor: log n + 3.93 50 fp =
24.48 x Q (gpm) D2 (in.)
= 48.96 cP
= 48.96 cP
NRep[
0. x 560.232 x 12.8 x 610 92,916 x 3.826 = 41.53 psi (2.9 bar)
Velocity:
Velocity: Vp (ft/min) =
fpVp2ρ x Lm 92,916 D
DRILLSTRING INTERVAL #1 (DRILL PIPE):
CONNECTION:
________________________ ________________________
Pp (psi) =
= 0.64
Kp =
________________________ ________________________
Pressure loss:
Pipe &#;n&#; and &#;K&#; values: Θ np = 3.32 log 600 Θ300
fp =
]
]
1.75 &#; log n 7
(
)
log (0.64) + 3.93 50
[ 8,667
1.75 &#; log (0.64) 7
]
= 0.
5.33
Revision No: A-2 / Revision Date: 12·31·06
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5
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Rheology and Hydraulics
Pp =
________________________ ________________________ ________________________ ________________________ ________________________
________________________ ________________________ ________________________ ________________________
Pp (psi) =
0. x 560.232 x 12.8 x 11,641 92,916 x 3.826 = 792.52 psi (54.6 bar)
DRILLSTRING INTERVAL #2 (DRILL COLLARS): Vp (ft/min) = Vp =
24.48 x Q (gpm) D2 (in.)
24.48 x 335 1,619.91 ft/min = (493.7 m/min) 2.252
Effective viscosity: µep (cP) = 1.6 x Vp 100 x Kp D µep =
(
100 x 3.21
) (
)
) (
)
(
(np&#;1)
x
1.6 x 1,619.91 2.25
(0.64&#;1)
x
3np + 1 4np
np
3 x 0.64 + 1 4 x 0.64
0.64
= 27.6 cP
Friction factor: Since the Reynolds number is greater than 2,100, use the turbulent equation. log n + 3.93 50 fp =
)
]
1.75 &#; log n 7
(
)
log (0.64) + 3.93 50
[ 26,144
1.75 &#; log (0.64) 7
( ) ( ) 21 8
= 0.275
Annular &#;K&#; value: 5.11Θ3 Ka = 5.11na 5.11 x 8 = 26.1 5.110.275 INTERVAL #1 (8.835-IN. DRILL PIPE):
4.5-IN.
CASING X
15.467 x 1,619.91 x 2.25 x 12.8 27.6 = 26,144
fp =
na = 0.657 log
ANNULAR
NRep =
NRep[
0. x 1,619.912 x 12.8 x 390 92,916 x 2.25 = 277.84 psi (19.2 bar)
Annular pressure losses: Annular &#;n&#; value: Θ100 na = 0.657 log Θ3
Ka =
Reynolds number: 15.467 x VpDρ NRep = µep
(
Pp =
fpVp2ρ x Lm 92,916 D
Total drillstring pressure loss: PDrillstring = Pp1 + Pp2 + &#; PDrillstring = 792.52 + 277.84 = 1,070.36 psi (73.8 bar)
Bulk velocity:
________________________ ________________________
Pressure loss:
Interval pressure: fpVp2ρ x Lm Pp (psi) = 92,916 D
Annular velocity: 24.48 x Q (gpm) Va (ft/min) = (D22 &#; D12) 24.48 x 335 (gpm) Va = 8. &#; 4.52 (in.) = 141.86 ft/min (43.2 m/min) Effective annular viscosity: µea (cP) = 2.4 x Va (na&#;1) 2na + 1 100 x Ka x D2 &#; D1 3na µea =
(
100 x Ka
(
) (
) (
2.4 x 141.86 8.835 &#; 4.5
(0.275&#;1)
x
)
na
)
2 x 0.275 + 1 3 x 0.275
0.275
= 131.22 cP
]
= 0.
Rheology and Hydraulics
5.34
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5
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Rheology and Hydraulics
Annular Reynolds number: 15.467 x Va x (D2 &#; D1) x ρ NRea = µea 15.467 x 141.86 x (8.835 &#; 4.5) x 12.8 131.22 = 927.82
NRea =
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Friction factor (if the Reynolds number is less than 2,100, use laminar equation): 24 fa = NRea 24 fa = = 0. 927.82 Annular interval pressure loss, annular interval #1: faVa2ρ x Lm Pa (psi) = 92,916 x (D2 &#; D1) 0. x 141.862 x 12.8 x 10,786 92,916 x 8.835 &#; 4.5 = 177.94 psi (12.3 bar)
Pa =
ANNULAR INTERVAL #2 (85 &#;8-IN. HOLE X 41 &#;2-IN. DRILL PIPE):
(
) ( (0.275&#;1)
x
0. x 151.472 x 12.8 x 855 92,916 x (8.625 &#; 4.5) = 15.34 psi (1.1 bar)
ANNULAR INTERVAL #3 (85 &#;8-IN. X 7-IN. DRILL COLLARS):
HOLE
Bulk velocity: 24.48 x Q (gpm) D22 &#; D12 (in.) 24.48 x 335 Va = = 322.99 ft/min 8. &#; 72 (98.4 m/min)
Va (ft/min) =
100 x 26.1
(
) (
) (
2.4 x 322.99 8.625 &#; 7
(0.275&#;1)
)
na
)
2 x 0.275 + 1 3 x 0.275
0.275
= 35.48 cP
) (
2.4 x 151.47 8.625 &#; 4.5
Pa =
(
Effective annular viscosity: µea (cP) = 2.4 x Va (na&#;1) 2na + 1 100 x Ka x D2 &#; D1 3na µea = 100 x 26.1
Annular interval pressure loss: faVa2ρ x Lm Pa (psi) = 92,916 x (D2 &#; D1)
Effective annular viscosity: µea (cP) = 2.4 x Va (na&#;1) 2na + 1 100 x Ka D2 &#; D1 3na µea =
OPEN
Annular velocity: 24.48 x Q (gpm) Va (ft/min) = D22 &#; D12 (in.) 24.48 x 335 Va = 8. &#; 4.52 Va = 151.47 ft/min (46.2 m/min)
(
Friction factor (if the Reynolds number is less than 2,100, use the laminar equation): 24 fa = NRea 24 fa = = 0. 1,024.68
)
na
)
2 x 0.275 + 1 3 x 0.275
0.275
Annular Reynolds number: 15.467 x Va x (D2 &#; D1) x ρ NRea = µea 15.467 x 322.99 x (8.625 &#; 7) x 12.8 35.48 = 2,928.7
NRea =
= 120.72 cP Annular Reynolds number: 15.467 x Va x (D2 &#; D1) x ρ NRea = µea 15.467 x 151.47 x (8.625 &#; 4.5) x 12.8 120.72 = 1,024.68
NRea =
Rheology and Hydraulics
5.35
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________________________ ________________________ ________________________ ________________________ ________________________
Rheology and Hydraulics
Friction factor (if the Reynolds number is greater than 2,100, use the turbulent equation): (log n + 3.93) 50 fa =
(
NRea[
________________________ ________________________
fa =
________________________
________________________
________________________ ________________________
]
1.75 &#; log n 7
(
)
(log (0.275) + 3.93) 50
2,928.70 = 0.
________________________
________________________
)
[
1.75 &#; log (0.275) 7
]
Annular pressure loss: faVa2ρ x Lm Pa (psi) = 92,916 x (D2 &#; D1)
________________________
Pa =
________________________
0. x 322.992 x 12.8 x 390 92,916 x (8.625 &#; 7) = 16.66 psi (1.1 bar)
Equivalent circulating density: Total annular pressure loss at TD: PAnnulus = Pa1 + Pa2 + &#; PAnnulus = 177.97 + 15.34 + 16.66 = 209.97 psi (14.5 bar) Equivalent circulating density at TD: ρc (lb/gal) = PAnnulus (psi) ρ (lb/gal) + 0.052 x TVD (ft) 209.97 ρc = 12.8 + 0.052 x 12,031 = 13.14 lb/gal (1.6 kg/L)
BIT
HYDRAULICS:
Pressure loss through nozzles or bit pressure loss: 156 x ρ x Q2 PBit (psi) = 2 2 2 &#; 2 ) + Dn3 (Dn1 + Dn2 2 156 x 12.8 x 335 PBit = (112 + 112 + 112)2 = 1,700 psi (117.2 bar) Percent pressure loss at bit: P %ΔPBit = Bit x 100 PTotal 1,700 %ΔPBit = x 100 = 57% 3,000
Rheology and Hydraulics
5.36
Bit nozzle velocity: 417.2 x Q (gpm) Vn (ft/sec) = 2 2 2 + Dn3 + &#; (in.) Dn1 + Dn2 417.2 x 335 112 + 112 + 112 = 385 ft/sec (117.3 m/sec)
Vn =
Hydraulic impact: V (ft/sec) x Q (gpm) x ρ (lb/gal) IF (lb) = n 1,930 385 x 335 x 12.8 IF (lb) = 1,930 = 855 lb (387.8 kg) Impact force/in.2: 1.27 x IF (lb) IF (psi) = Bit Size2 (in.) 1.27 x 855 14.6 psi IF (psi) = = (1 bar) 8. Hydraulic horsepower at bit: Q (gpm) x PBit (psi) hhpb = 1,740 335 x 1,700 HHPb = = 327.3 hhp 1, Hydraulic horsepower per square inch: 1.27 x hhpb (hhp) HSI = Bit Size2 (in.) 1.27 x 327.3 HSI = = 5.58 hhp/in.2 8. Total calculated pressure loss: The calculated pressure losses for the system (surface connections, drillstring, downhole tools, bit and annulus) should closely approximate the circulating (standpipe) pressure. PTotal = PSurf Equip + PDrillstring + PBit + PAnnulus PTotal = 41.53 + &#; (792.52 + 277.84) + &#; 1,700.0 + (177.97 + &#; 15.34 + 16.66) = 3,021.9 psi (208.4 bar) This is acceptably close to the recorded circulating pressure of 3,000 psi (206.8 bar).
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
6
Polymer Chemistry and Applications
Introduction sources. Other, more-specialized polymers are modified natural polymers, while still other more-sophisticated polymers are derived from synthetics. The unlimited potential of polymer development makes polymers applicable to virtually every drilling fluid function. With polymer technology, it is possible to analyze a situation on a molecular level and design a polymer with the specific properties to address the situation. For this reason, polymers have an unlimited future in drilling fluids.
Polymers have been used in drilling fluids since the s, when cornstarch was introduced as a fluid-loss-control additive. Since that time, polymers have become more specialized and their acceptance has increased accordingly. Polymers are part of practically every water-base system in use today. Indeed, some systems are totally polymerdependent and are termed broadly as polymer systems. A wide array of polymers is available today. Some polymers &#; like starch, for instance &#; originate from natural
Polymer Chemistry and Applications
A polymer is a large molecule comprised of small, identical, repeating units.
degree of polymerization. Polymers typically have a degree of polymerization greater than 1,000. Polyethylene is an example of a homopolymer. Homopolymers contain only one monomer. Other examples of homopolymers are polypropylene and polystyrene. Copolymers are polymers that are prepared from two or more types of monomers. The monomers can be present in various ratios and in different positions in the chain. Copolymerization offers a great deal more flexibility in designing polymers.
A polymer is a large molecule comprised of small, identical, repeating units. The small, recurring units are called monomers. Polymerization occurs when the monomers are joined together to form the large polymer molecule. Polymers may have molecular weights in the millions or they may consist of only a few repeating units. Polymers that have only a few repeating units are called oligomers. To express the written formula for a polymer, the empirical formula of the simple recurring unit is expressed to the nth degree. For instance, the simplest polymer is polyethylene ((C2H4)n). Ethylene is the result of the polymerization of the monomer ethylene (CH2=CH2). During the polymerization process, the double bond is lost and the polymer polyethylene is formed. n(CH2=CH2) &#; (CH2 &#; CH2)n ethylene polyethylene The resulting polyethylene polymer consists of a long chain of &#;n&#; repeating units. The number of times that the monomers are repeated is known as the
Polymer Chemistry and Applications
STRUCTURE
OF POLYMERS
Polymers&#; structures are classified as linear, branched or crosslinked. Examples are given below. Linear
Example: CMC (Carboxymethylcellulose), PHPA (Partially Hydrolyzed Polyacrylamide) and HEC (Hydroxyethylcellulose).
6.1
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6
Polymer Chemistry and Applications
animals and bacteria fermentation. The final product must go through some processing &#; at least harvesting, separating, grinding and drying &#; before bagging. Natural polymers have more complex structures than synthetic polymers, and they typically have higher molecular weights as well. Natural polymers also are less temperature-stable than synthetic polymers and have a lower tolerance to degradation by bacteria. Natural polymers used in drilling fluids are composed of polymerized sugar molecules and belong to a class of compounds called polysaccharides. The monomers are the sugar units and they contain carbon:hydrogen:oxygen in the ratio of 6:12:6 (see Figure 1). Polymerization of the sugar units occurs through a condensation reaction wherein water is removed from the individual sugar units. The resulting polysaccharide consists of the sugar units linked together through common oxygen atoms. Polysaccharides have a C:H:O ratio of 6:10:5 or C6(OH2)5. The backbone linkage of natural polymers is more complicated than that of synthetic polymers. The backbone consists of carbohydrate ring structures and the oxygen atoms that link the rings together. Synthetic polymers have a much simpler carbon-carbon linkage.
Branched
Example: Starch and xanthan gum. Crosslinked
Example: Crosslinked xanthan gum There is an infinite possibility of structural variations. Some of the structural possibilities that affect the performance of polymers are listed below. &#; Type of monomer or monomers. &#; Molecular weight. &#; Type and extent of subsequent chemical modification on the polymer. &#; Number of branching or crosslinking groups in the polymer chain.
CLASSIFICATION
&#;polymers used in drilling fluids come in three types&#;
OF POLYMERS
Polymers in drilling fluids can be classified in three ways. They can be classified according to their chemistry, such as anionic or nonionic; they can be classified by their function, such as viscosifier or filtration-control additive; or they can be classified simply by their origin. For this chapter, polymers are classified by their origin. The polymers used in drilling fluids come in three types: &#; Naturally occurring. &#; Modified naturally occurring. &#; Synthetically derived.
NATURAL
CH2OH H
H
OH
H
HO
OH H
OH
Figure 1: Glucose.
POLYMERS
Natural polymers are polymers produced in nature, without Man&#;s intervention. These materials are derived from natural sources such as plants,
Polymer Chemistry and Applications
O
H
Starch is a natural polymer which comes from a variety of plant and grain sources, with corn and potato starches being the most important 6.2
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CHAPTER
6
Polymer Chemistry and Applications
CH2OH
________________________
O
H
________________________
CH2OH O
H
H
H
CH2OH O
H
H
CH2OH
H
H
O
H
H
H
H
________________________ ________________________
&#;O
________________________
OH
H
H
OH
α
O
OH
H
H
OH
________________________
O
OH
H
H
OH
O
OH
H
H
OH
&#;
Figure 2: Amylose. O&#;
________________________ ________________________
6 CH2
________________________
Oα
O
O H&#;OH
O
________________________
O O
________________________
O
O x
________________________ O
________________________
y
α O
________________________ ________________________
O
O
αO
4 3 O
H&#;OH O
1
O
O
x
O
O
&#;O
y
Figure 3: Amylopectin.
Starch in its raw form is not watersoluble&#;
pregelatination. Once dispersed, the starch hydrates water. It is subsequently dried and bagged as the final product. It is non-ionic and soluble in saturated saltwater as well as freshwater. MY-LO-JEL* is a cornstarch consisting of an average of about 25% amylose and 75% amylopectin. POLY-SAL* is a potato starch which is slightly different from cornstarch. Potato starch has a slightly higher molecular weight than cornstarch and also has a higher concentration of amylose to amylopectin. For these reasons, it functions somewhat differently. POLY-SAL has greater tolerance to hardness and a slightly higher temperature stability than MY-LO-JEL. It also produces slightly more viscosity. The biggest drawback to the use of starches is their tendency to ferment.
source for drilling fluids. Starch consists of two polysaccharides: amylose and amylopectin. Amylose, a chain of carbohydrate rings, makes up the straight chain backbone of the starch molecule. Amylopectin is a highly branched chain of carbohydrate rings that branches off from an amylose backbone. The ratios of the amylose and amylopectin fractions determine the properties of the starch. Starch in its raw form is not watersoluble; it simply floats around as starch particles. To make starch effective in drilling fluids, it is necessary to rupture the protective shell coating of amylopectin to release the inner amylose. The starch granules are heated until the cells rupture, which allows the amylose to disperse. This process is known as Polymer Chemistry and Applications
6.3
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6
Xanthan gum is classified as a natural polymer&#;
Polymer Chemistry and Applications
process. Xanthan is water-soluble, slightly anionic and highly branched. It has a molecular weight in the 2 to 3 million range, which is relatively high for drilling fluids. Xanthan is a five-ring, repeating structure consisting of a two-ring backbone and a three-ring side chain. The backbone consists of glucose residues identical in structure to cellulose. Branching off the backbone are three-ring side chains of additional sugar residue. Attached to the side chains are various functional groups (carbonyl, carboxyl, hydroxyl and others) which give xanthan its unique viscosifying properties. The long branching structure of the polymer, coupled with the relatively weak hydrogen bonding among the side groups, imparts unique viscosifying properties to xanthan. When a certain concentration of the polymer is reached, hydrogen bonding develops among the polymer branches and the result is a complex, tangled network of weakly bound molecules. The electrostatic interactions are weak, however, and when shear is applied to the system, the
They are natural biodegrading materials that must be preserved with a biocide when used in drilling fluids. POLY-SAL contains a biocide in the product. A second limitation of starch is its low thermal stability. Starch degrades rapidly when exposed to prolonged temperatures exceeding 225° F (102° C). Some environments are more conducive to bacterial degradation than others. The worst environments center around bioactive makeup water. Stagnant pond water is the worst source, although any water sourced through rivers or streams should be considered suspect. Higher temperatures, neutral pH conditions and fresher waters accelerate bacterial growth. Bacterial problems in highsalt systems and high-pH environments are less likely; however, they do occur after time. Xanthan gum is classified as a natural polymer although it is actually obtained in its bacterially produced form rather than in its natural form. The bacteria Xanthomonas campestris produces the gum during its normal life cycle via a complex enzymatic
CH2OH
CH2OH O
O O
O
OH
O
OH
OH O
CH2OCCH2 O
OH HO COOOM&#; O
O
OH CH2 COOOM&#;
O
O
O
OH
C OH CH2
M&#; &#; Na, K, 1&#;2/Ca
OH
O
Figure 4: Structure of xanthan gum. Polymer Chemistry and Applications
6.4
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6
Modified natural polymers are very common in drilling fluids.
Polymer Chemistry and Applications
used instead of loading a fluid with clay solids to obtain viscosity and suspension. This is beneficial in many ways, most notably by maintaining optimum suspension and carrying capacity in fluids without increasing solids loading. This property makes xanthan gum the polymer of choice for increasing viscosity in extended-reach and horizontal wells, especially when the wells involve low annular velocities. Xanthan has several properties that make it an ideal polymer for clay-free &#;reservoir drill-in&#; and workover/completion fluid applications. It viscosifies brines, including seawater, NaCl, KCl, CaCl2, NaBr and, to some extent, even CaBr2. It is degradable with oxidizers (bleach) or enzymes, and is acid-soluble for easy clean-up. It develops gel strengths and easily suspends acidsoluble materials like CaCO3. FLO-VIS is a special, clarified version of xanthan. The clarified version has been processed to remove any bacterial residue for clean fluid applications.
attractive forces holding the polymers together are pulled apart. As the hydrogen bonding breaks, the viscosity of the fluid thins. When the shear is removed, the polymer chains resume their intermolecular hydrogen bonding and their original viscosified state returns. Xanthan polymer produces pseudoplastic or shear-thinning fluids and gel structures. As the shear is increased, viscosity is progressively decreased. When the shear is removed, the original viscosity of the fluid is completely recovered. Under high-shear-rate conditions &#; in the drillstring, for instance &#; the viscosity of the mud system decreases. Under the very high shear rates experienced in the drill bit nozzles, the fluid thins dramatically until it behaves almost like water. Under lower-shearrate conditions &#; in the annulus, for instance &#; hydrogen bonding forms again and viscosity increases. Under static conditions, xanthan fluids display thixotropic characteristics providing gels. Xanthan gum and a similar biopolymer called welan gum are two of only a few commercial polymers that produce thixotropic properties (gels) in water-base fluids. The concentration of xanthan necessary to develop thixotropic properties depends on the makeup water. Only 0.5 lb/bbl may be sufficient for a highly weighted freshwater system while it may take 2 to 3 lb/bbl in a KCl or a high-salinity NaCl system. In highsalinity brines, xanthan polymer &#; like other water-base polymers &#; does not hydrate easily and, to some extent, remains coiled. In freshwater, the polymer expands and the polymer branches come in contact, allowing hydrogen bonding and the resulting thixotropy to develop more easily. Xanthan gum (such as DUO-VIS* and FLO-VIS*) is added to drilling fluids for a number of applications. Most often, it is used as a clay substitute to impart thixotropic properties. Xanthan gum is Polymer Chemistry and Applications
MODIFIED
NATURAL POLYMERS
Modified natural polymers are very common in drilling fluids. Cellulose and starch are two natural polymers that frequently are used to produce modified natural polymers. The modified versions can have substantially different properties than the original, natural polymers. For drilling fluids, nonionic natural polymers &#; such as cellulose and starch &#; are modified to polyelectrolytes. Polyelectrolytes. Many polymers are not water-soluble and therefore are not applicable to water-base drilling fluids &#; unless they are modified. To obtain water solubility, polymers are sometimes modified to polyelectrolytes. This modification involves an alteration of the repeating unit of the polymer. A polyelectrolyte is a polymer that dissolves into water, forming polyions and counter ions of the opposite charge. A 6.5
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6
Polymer solubility is affected by pH.
Polymer Chemistry and Applications
CONCENTRATION
As the polymer hydrates water&#; viscosity increases.
occurs when polymers become entangled with one another by clinging to a limited amount of water.
polyion has charges that repeat along the polymer chain. The charges can be positive, as in a cationic polymer, or negative, as in an anionic polymer. A few examples of cationic polymers exist, but most often polymers in drilling fluids are negatively charged. The effectiveness of a polyelectrolyte depends on the number of available sites on the polymer which, in turn, depends on the following factors: &#; The concentration of the polymer. &#; The concentration and distribution of the ionizable groups. &#; The salinity and hardness of the fluid. &#; The pH of the fluid. With an increasing number of ionized sites on the polymer, it tends to extend and uncoil. This is due to mutual charge repulsion that elongates and stretches the polymer into a configuration that gives the maximum distance between like charges. In spreading out, the polymer exposes the maximum number of charged sites. Spreading out allows the polymer to attach to clay particles and to viscosify the fluid phase.
PH EFFECTS
Polymer solubility is affected by pH. The pH often determines the extent of the ionization of the functional groups along the polymer chain. For instance, the most common functional group found in water-base polymers is the carboxyl group. The ionized carboxyl group is a distinguishing feature in most anionic polymers including CMCs, PHPAs and xanthan gums, to name a few. O&#; C O
Figure 5: Ionized carboxyl group.
As seen in Figure 5, the ionized carboxyl group has a double-bonded oxygen and a single-bonded oxygen on the terminal carbon. Ionization is accomplished by reacting the carboxyl group with an alkali material such as caustic soda. By ionizing the previous insoluble carboxyl group, solubility of the polymer occurs (see Figure 6).
EFFECTS
As discussed, polymers assume a stretched or elongated configuration when dissolved in the water phase of a drilling fluid. This configuration is not rod-like but twisted and curled to obtain the maximum distance between like charges on the polymer. In dilute concentrations, the polymer hydrates a thick envelope of water (about 3 or 4 water molecules). There is an electrostatic repulsion between these envelopes, whose surfaces are large when the fully extended shape is assumed. This large surface area contributes to the viscosity effects of the polymer. As the polymer concentration increases, the envelopes of water surrounding the polymers decrease. As more polymer vies for less water, the effect is an increase in viscosity. This Polymer Chemistry and Applications
O&#;
O NaOH
C
C O
OH Insoluble
Soluble
Figure 6: Polymer solubility.
The sodium carboxylate group draws water to it through its anionic charged site. When the polymer is added to water, the sodium ion releases from the polymer chain and leaves behind a negatively charged site. The polymer is now anionic and free to hydrate water. As the polymer hydrates water, the envelope
6.6
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CHAPTER
6
&#;calcium and magnesium ions hydrate even more water than the sodium ion.
Salt limits the availability of water in which a polymer can hydrate and expand.
Polymer Chemistry and Applications
(Polyanionic Cellulose) or xanthan gum may require twice their normal concentration, or even more, to perform in a saline environment.
surrounding the polymer increases in size, and viscosity increases. The optimum solubility of the carboxyl group occurs from 8.5 to 9.5 pH. Enough caustic to reach 8.5 pH is necessary to ionize and make the polymer soluble. If greater amounts of caustic soda are added, the viscosifying characteristics are suppressed slightly. If a pH reversal occurs &#; i.e., the solution pH drops to acid conditions (less than 7) &#; then the carboxylate group returns to its original carboxyl form and the polymer loses its solubility.
SALINE
DIVALENT
When divalent ions such as calcium and magnesium are present in a drilling fluid, their effect on the system can be dramatic. Like the sodium ion, which also hydrates water and limits overall water availability, calcium and magnesium ions hydrate even more water than the sodium ion. This makes polymer hydration in their presence very inefficient. Anionic polymers have an additional problem with calcium in that calcium reacts with the anionic group on the polymer. In doing so, the polymer becomes flocculated and can be dropped from the system. For this reason, soda ash is often recommended to treat calcium from the system. Polymers that are only slightly anionic, such as xanthan gum, and polymers that are nonionic, such as starch, are not precipitated by calcium. They are affected, however, by the strong hydration characteristic of calcium and their efficiencies are diminished in its presence.
EFFECTS
Salinity plays a very big role in determining the effectiveness of a polymer. Salt inhibits the unwinding, elongating effect that occurs when a water-soluble polymer is added to water. Rather than uncoiling and expanding, the polymer takes a comparatively smaller, balled shape and its solubility is likewise reduced. This results from the greater competition for water. Salt limits the availability of water in which a polymer can hydrate and expand. As salinity increases, polymers neither hydrate as much water nor increase viscosity as readily. When salt is added to a freshwater system in which polymers are fully extended, the addition usually triggers a viscosity hump. As salt hydrates water and strips it from the polymers, the system may be at least temporarily destabilized, and an increase in viscosity occurs. Polymers become entangled with drill solids and other polymers while shrinking back to their balled state. Once the polymers assume their balled state, viscosity is greatly reduced. Typically, the effectiveness of polymers in saline environments is reduced, but this can be overcome with additional treatment. For instance, PAC
Polymer Chemistry and Applications
CATION EFFECTS
CELLULOSE
DERIVATIVES
Cellulose is a natural polymer that is insoluble in water. To become a useful additive in drilling fluids, it is modified to Carboxymethylcellulose (CMC). CMC is an example of a polyelectrolyte. Figures 7 and 8 show how the repeating ring structure for cellulose is modified by introducing the anionic carboxymethyl group. Now the modified polymer, through the anionic group, has an affinity for water and is water-soluble.
6.7
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CHAPTER
6
Polymer Chemistry and Applications
________________________ ________________________
H HO
H OH
________________________ ________________________ ________________________ ________________________
CH2OH
OH
H
OH
O
H
O
H
OH
H
O H
H
H
O
H
OH
O
H
H H
CH2OH
CH2OH
OH
O
H
H H
H
OH
H
H
OH
O CH2OH
n
________________________
Figure 7: Cellulose.
________________________ ________________________ H
CH2OCH2COO&#;Na+
OH
________________________ HO
________________________
OH
________________________
OH
O
H H
H
I H
H
H
O
H
CH2OCH2COO&#;Na+
OH
O
H
H
4
________________________ ________________________
H
H
O
OH
H
O
CH2OCH2COO&#;Na+
H H
H
H
O
H
H
OH
O
CH2OCH2COO&#;Na+
OH
OH
n
________________________
Figure 8: Sodium carboxymethylcellulose, D.S. = 1.0.
The degree of polymerization refers to the number of times the ring structure is repeated.
figure above, there is exactly one substitution on each ring structure. That means the D.S. is 1. In the example above, the substitution occurred only on the methyl hydroxy (-CH2OH) group. Substitution also could have occurred at either of the two hydroxyl (-OH) groups, giving a potential D.S. of 3. Water solubility is achieved when the D.S. reaches 0.45. The typical D.S. range for CMC is 0.7 to 0.8. High-viscosity CMC has the same D.S. as medium- or low-viscosity CMC. The only difference is their respective D.P. Relatively higher substituted CMC often is called Polyanionic Cellulose (PAC). PAC has the same chemical structure and the same D.P. as CMC; only the D.S. for the two polymers is different. The typical D.S. range for PAC is 0.9 to 1.0. The higher D.S. produces a polymer that is more soluble than CMC. This makes the performance of PAC generally better than that of CMC. Both materials perform about the same in
Carboxymethylcellulose is formed by the reaction of the sodium salt of monochloroacetic acid (ClCH2COONa) with cellulose. A substitution occurs most often at the (-CH2OH) group to form a soluble polyelectrolyte. The properties of sodium carboxymethylcellulose are dependent on several factors: &#; The Degree of Substitution (D.S.). &#; The Degree of Polymerization (D.P.). &#; The uniformity of the substitution. &#; The purity of the final product. The degree of polymerization refers to the number of times the ring structure is repeated. The ring structure is the repeating structure that defines the polymer. The higher the D.P., the higher the molecular weight. Viscosity increases as the D.P. for CMC increases. High-viscosity CMC has a higher molecular weight than low-viscosity CMC. The degree of substitution refers to the number of substitutions that occur on a single repeating ring structure. In the sodium carboxymethylcellulose
Polymer Chemistry and Applications
6.8
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CHAPTER
6
POLYPAC R is a high-quality polyanionic cellulose.
________________________ ________________________ ________________________
Polymer Chemistry and Applications
freshwater, but in saline and hard waters, PAC outperforms CMC. Sometimes CMC and PAC &#; with identical D.P., D.S and purity &#; perform differently. This is due to the uniformity (or lack of uniformity) of the substitution along the chain. A good-quality CMC or PAC has uniform substitution along the polymer. A poorly performing CMC or PAC may have substitution occurring at only one end or in the middle of the polymer. This results in a polymer with limited solubility and, therefore, poor performance. POLYPAC* R is a high-quality polyanionic cellulose. It provides fluid-loss control in freshwater, seawater, NaCl and KCl systems. It forms a thin, tough, pliable filter cake which limits the loss of filtrate to permeable formations. It also produces excellent viscosity in both saltwater and freshwater. POLYPAC R is recommended over CMC for use in seawater, saltwater and waters with soluble calcium levels above 400 mg/L. A table with the technical specifications and limitations of CMC and PAC is found below. Product PAC LV PAC HV
Mol. Wt 140-170 200-225
D.P. 850-1,000 1,130-1,280
D.S. 0.9-1.0 0.9-1.0
CMC LV CMC HV
40-170 200-225
850-1,000 1,130-1,280
0.7-0.8 0.7-0.8
________________________
HEC (Hydroxyethylcellulose) is another type of modified cellulose polymer. It is produced by soaking cellulose in a caustic soda solution, then reacting the alkali cellulose with ethylene oxide. The result is a substitution of hydroxyethyl groups on the hydroxymethyl and hydroxyl sites. Even though the polymer is non-ionic, the hydroxyethyl groups have sufficient affinity with water to make the polymer water-soluble. In addition to the D.S., the structure of the polymer is affected also by the D.P. of the ethoxylated side chains. The D.P. of the side chains is called the Molar Substitution (M.S.), or the average number of ethylene oxide molecules that have reacted with each cellulose unit. Once a hydroxyethyl group is attached to each unit, it can further react with additional groups in an end-to-end formation. As long as ethylene oxide is available, this reaction can continue. The greater the M.S., the greater the water solubility of the polymer and, therefore, the greater the tolerance to salt and hardness. Typically, M.S. values range from 1.5 to 2.5 for HEC. HEC is used primarily for viscosity and fluid-loss-control in workover and completion fluids. It is compatible with most brines including seawater, KCl, NaCl, CaCl2 and CaBr2. It is a very clean polymer and is acid-soluble,
Table 1: CMC and PAC.
________________________ ________________________
CH2OCH2CH2OCH2CH2OH
________________________ ________________________ ________________________ ________________________ ________________________
H
OCH2CH2OH
O H H
H
H
Cellulose + C
C
OH
OH
O H H
H
H
H
O
H O
O H H Ethylene oxide
CH2OCH2CH2OH
OH
H
n
________________________ ________________________
Figure 9: Hydroxyethylcellulose.
________________________ ________________________
Polymer Chemistry and Applications
6.9
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CHAPTER
6
&#;HEC&#;does not react as strongly with charged surfaces as do ionic polymers.
________________________ ________________________ ________________________ ________________________ ________________________
Polymer Chemistry and Applications
ring structure. Also like CMC, the substitution occurs most readily at the hydroxymethyl group. THERMPAC* UL, a carboxymethyl starch, controls fluid loss with a minimum increase in viscosity in most water-base drilling fluids. It is an alternative to PAC materials in systems requiring tight filtration control and low rheological properties. THERMPAC UL performs more like a CMC material than a starch. It has a temperature stability similar to CMC and PAC (up to 300° F [149° C]) and does not require a bactericide. THERMPAC UL is most effective when applied in drilling fluids containing less than 20,000 mg/L Cl&#; and 800 mg/L Ca2+. It performs at any pH level and is compatible with all water-base systems. Hydroxypropyl starch. Another example of modified starch is Hydroxypropyl (HP) starch. It is produced by reacting starch with propylene oxide. The resulting modified starch is nonionic and is water-soluble. The modification actually adds to the water solubility of the starch. As with CMS and HEC, the substitution occurs at either the hydroxymethyl group or at either of the two available hydroxyl groups on the ring structure. Also like CMC and CMS, the substitution occurs most readily at the hydroxymethyl group. The result is a substitution of propoxylated groups. The D.P. of the propoxylated groups is known as the
which makes it ideally suited for gravelpacking and other operations where the completion fluid contacts the production interval. Since HEC is non-ionic, it does not react as strongly with charged surfaces as do ionic polymers. This further enhances its role as a completion fluid additive. HEC has a temperature limitation of 250° F (121° C). It is not affected greatly by pH (above 10 pH, there may be a minor loss of viscosity) and it is resistant to bacteria. It is not a thixotropic polymer (does not generate gel structures for suspension) and, in fact, provides little if any Low-Shear-Rate Viscosity (LSRV), although it produces a great deal of overall viscosity. Starch derivatives. As stated earlier in this chapter, starch is useful in many applications without chemical modification. But with chemical modification, starch derivatives can be made to have different properties. Starch can be modified in such a way that it no longer is susceptible to bacterial degradation. It also can be made significantly more temperature-stable with simple modifications. A few examples of modified starches are given below. Carboxymethyl Starch (CMS). Another example of a modified polymer is carboxymethyl starch. Like CMC, carboxymethyl starch undergoes a carboxylate substitution at either the hydroxymethyl group or at either of the two hydroxyl groups on the
________________________ ________________________
CH2OH
________________________
CH2OCH2COO&#; O
H
H
________________________ &#;O
O
H
H
OH
H
H
OH
α
O
CH2OH O
H
H
H
________________________
CH2OCH2COO&#; H
OH
H
H
OH
O
O
H
H
H
H
OH
H
H
OH
O
OH
H
H
OH
&#;
________________________ ________________________ ________________________
n
Figure 10: Carboxymethyl starch, D.S. = 1.0.
________________________ ________________________
Polymer Chemistry and Applications
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6
Polymer Chemistry and Applications
CH3 CH2OH O
H
H
O
H
H
CH3
OH
H
H
OH
α O
H
O
H
H
OH
H
H
OH
O
CH3
CH2OCH2 &#; CH &#; OCH2 &#; CH &#; OH O
H
H
H
&#;O
CH3
CH2OCH2 &#; CH &#; O &#; CH2 &#; CH &#; OH CH2OH
H
H
OH
H
H
OH
O
OH
H
H
OH
n
&#;
Figure 11: Hydroxypropyl starch, D.S. = 0.5, M.S. = 2.0.
&#;FLO-TROL contributes to LSRV.
Molar Substitution (M.S.). The M.S. is the average number of propylene oxide molecules that have reacted with each starch unit. Once a hydroxypropyl group is attached to each unit, it can react further with additional groups in an end-to-end formation. The reaction of propylene oxide with starch has similarities to the reaction of cellulose with ethylene oxide. In each case, substitution occurs with a repeating structure that must be defined by its M.S. Many types of HP starch are available. The properties vary with the D.P., the D.S. and the degree of polymerization of the substituted group (M.S.). FLO-TROL*. An HP starch used primarily for fluid-loss-control in FLOPRO* systems. It works in conjunction with calcium carbonate to form an easy-toremove, acid-soluble filter cake. Like starch, FLO-TROL is compatible with most makeup brines including seawater, NaCl, KCl, CaCl2, NaBr, CaBr2 and formate brines. It does not require a bactericide. FLO-TROL has unique viscosifying characteristics that make it suitable for &#;reservoir drill-in&#; fluid applications. Unlike PAC products, FLO-TROL contributes to LSRV. It works synergistically with FLO-VIS to increase LowShear-Rate Viscosity (LSRV). Recommended FLO-TROL concentrations are 2 to 4 lb/bbl for most applications, although higher concentrations are used to achieve lower filtration rates. Temperature stability for FLO-TROL Polymer Chemistry and Applications
is better than most starch materials. It is thermally stable to 250° F (121° C) in brine applications. Mor-Rex. An enzyme-hydrolyzed cornstarch which has been chemically modified to a maltodextrin. The hydrolysis of the starch results in a product that is much lower in molecular weight (less than 5,000) and imparts a slightly anionic character to the polymer. Mor-Rex has been used in limebase drilling fluids almost exclusively. This is due primarily to its tendency to increase the calcium solubility in a lime-base fluid environment. In such an environment, the Mor-Rex polymer is further hydrolyzed and Ca2+ attaches to the free carboxylate groups formed during hydrolysis. This results in an increased concentration of soluble calcium. In other words, a lime-base system treated with Mor-Rex contains more soluble calcium than the same lime-base system without Mor-Rex. It is thought that the additional Ca2+ provides additional inhibition benefits. Functionally, Mor-Rex acts as a deflocculant, which is consistent with its size and anionic character. Typical concentrations for Mor-Rex in a lime/ Mor-Rex system are 2 to 4 lb/bbl. Like traditional starch, it is thermally stable to about a 200° F (93° C) circulating temperature and requires a bactericide.
SYNTHETIC
POLYMERS
Synthetic polymers are chemically synthesized, usually from petroleumderived products. Unlike natural and modified natural polymers, synthetic 6.11
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6
Synthetic polymers afford an almost unlimited flexibility in their design.
Polymer Chemistry and Applications
polymers are &#;built up&#; from relatively smaller molecules. Synthetic polymers afford an almost unlimited flexibility in their design. They can be tailormade to fit almost any application. Their size and chemical composition can be made to produce properties for almost any function. Frequently, synthetic polymers are prepared from substituted ethylene. The polymerization process occurs through an addition reaction wherein the substituted ethylene groups are added to the end of the polymer chain. In the figure below, the substituted group &#;A&#; can be any functional group. CH2 = CH | A Note the carbon-carbon backbone and the unlimited substitution possibilities. The carbon-carbon backbone is a more stable linkage than the carbon-oxygen linkage encountered earlier with starchand cellulose-base polymers. The carboncarbon linkage is resistant to bacteria and has temperature stability in excess of 700° F (371° C). The substitution groups most likely will degrade before the carbon-carbon linkage. Polyacrylate. The polymerization of acrylic acid and the subsequent neutralization with sodium hydroxide yields the polymer Sodium Polyacrylate (SPA). SPA is an anionic polymer that can function either as a deflocculant or a fluid-loss control additive, depending on the molecular weight of the polymer. H
H
H
H
C
CH
C
CH
COO&#;Na+
COO&#;Na+
During the drilling of a well, the interaction between the drilled solids has a profound effect on the properties of the mud. There is a natural tendency for flocculation to occur (see Figure 13). Flocculation results in an overall increase in the rheological properties of the drilling fluid.
Figure 13: Flocculation of drill solids.
SPA functions as a deflocculant at low molecular weights (less than 10,000). It is highly anionic and adsorbs on the active solids in drilling fluids. The adsorbed polymer neutralizes the positive charges on aggregated particles, which results in mutual repulsion and deflocculation. This is best accomplished with a small polymer. Shortchain polymers create maximum adsorption on the particle surfaces and eliminate the flocculating effect that occurs when one polymer adsorbs to several particles (see Figure 14).
Figure 12: Sodium polyacrylate.
Polymer Chemistry and Applications
6.12
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6
Polymer Chemistry and Applications
20 lb/bbl bentonite equivalent and the mud weight is less than 12 lb/gal (1.4 kg/L). TACKLE* is also affected by soluble calcium, although it is still effective in seawater applications. Copolymerization. So far, this chapter has dealt only with homopolymers, i.e., polymers prepared from identical units (or monomers). It is possible to start with more than one type of monomer and undergo polymerization and end up with a copolymer. A copolymer contains two or more different types of monomers. Through copolymerization, polymers can be made which have different properties than any of the homopolymers alone. Adding more monomers creates a completely new dimension for design possibilities. It is possible to use more than a single monomer to impart specific properties to the finished polymer product. For instance, one monomer can be used to extend temperature stability and a second monomer can be used to inhibit shale. TACKLE is an example of a copolymer. It is prepared from two monomers: sodium acrylate (as in SPA) and a monomer known in the industry as AMPS (2-acrylamido-2-methyl propane sulfonic acid). The AMPS monomer provides a sulfonate group that imparts greater temperature stability and tolerance to solids, salinity and hardness than the sodium acrylate group alone.
SPA &#;
&#;
&#; +
+ &#;
+
+
&#;
+
+
&#;
+
+
+ &#;
&#; &#; + +
&#; + &#;
A copolymer contains two or more different types of monomers.
TACKLE is an example of a copolymer.
+
+ &#; &#; +
&#; +
&#; +
Figure 14: Diagram of SPA and clays.
Many mud companies use lowmolecular-weight sodium polyacrylate as their primary deflocculant for lowsolids, non-dispersed and other polymer systems. It can be prepared as a dry powder but usually is available in liquid form. SPA functions at much lower concentrations than lignosulfonates. Typically, concentrations of 0.25 to 1.0 lb/bbl are sufficient to control rheological properties. SPA does not depend on alkaline pH and can tolerate temperatures to 500° F (260° C). It performs best in polymer systems but is sometimes used as a stand-alone product in spud mud and in geothermal applications. SPA is sensitive to high concentrations of solids. Since it is a surface-active material, it can get overwhelmed in a high-solids environment. It works best when the CEC of the mud is less than nCH = CH2 + nCH = CH2
CH
x y Monomer A Monomer B
CH2
CH
y
x
CH2
n
Figure 15: Copolymerization.
Polymer Chemistry and Applications
6.13
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6
&#;SP-101 has a stabilizing effect on drilled cuttings.
Polymer Chemistry and Applications
other polymer systems like PHPA. In addition to providing fluid-loss control, SP-101 has a stabilizing effect on drilled cuttings. SP-101 attaches to clay particles and provides some encapsulation of the drilled cuttings. Sometimes, a viscosity hump is seen when SP-101 is first added to a system. Once the polymer is worked into the system at a sufficient concentration to encapsulate the solids, the system thins back and stabilizes. Typically, this concentration occurs at about 1 lb/bbl, but it can be slightly more or less, depending on the solids load. SP-101 is an effective deflocculant, especially in high-temperature applications and polymer applications. While SP-101 does not provide the immediate thinning effect that is seen with TACKLE, it provides stabilization of the rheological properties when the concentration exceeds 1 lb/bbl. SP-101 is very effective at stabilizing the rheological properties of many freshwater systems including PHPA; geothermal; and low-solids, non-dispersed systems. Polyacrylamide/polyacrylate copolymer. Partially Hydrolyzed Poly Acrylamide (PHPA) is often used to identify the copolymer polyacrylamide/polyacrylate. The end product of a PHPA is the same polymer that is formed by a polyacrylamide/polyacrylate copolymerization. Even though the product is frequently referred to as PHPA, it actually is made by the copolymerization of acrylamide and sodium acrylate monomers. For the sake of simplicity, the material will be referred to as PHPA. The properties of PHPA are affected by the molecular weight and by the ratio of the carboxyl groups to the amide groups. Polyacrylamide by itself is insoluble, so it must be copolymerized with sodium acrylate to obtain water solubility. Copolymerization with sodium acrylate results in an anionic polymer that is water-soluble. The ratio
AMPS is a fairly expensive monomer; however, it can give high temperature stability in the presence of contaminants, which is more than PAC and modified starch can give. CH2
CH
C=O
NH
CH3
C
CH3
CH2
SO3&#; 2-Acrylamido-2-methyl propane sulfonic acid
Figure 16: AMPS monomer.
TACKLE&#;is more functional in seawater than lowmolecularweight SPA.
TACKLE, due to the AMPS monomer, has greater contamination resistance and tolerance to solids than SPA alone. Like SPA, it still is better suited to polymer systems and low-solids, non-dispersed applications. It also has trouble controlling viscosity in a high-solids environment. However, it is more functional in seawater than low-molecular-weight SPA. SP-101* is a medium-molecular-weight (±300,000) polyacrylate used primarily for fluid-loss control. It is stable to very high temperatures (>400° F [204.4° C]) and is often applied in geothermal applications. Like TACKLE, it is not pHdependent or subject to bacterial degradation, but it is susceptible to soluble calcium contamination. It is recommended that soluble calcium be maintained at a concentration of 300 mg/L or less for optimum performance. It is most effective in freshwater systems. SP-101 is most often used in lowsolids, non-dispersed systems and
Polymer Chemistry and Applications
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Polymer Chemistry and Applications
shale-inhibiting properties, it also provides drilled cuttings encapsulation and viscosity in freshwater systems. The shale-inhibition feature of PHPA occurs when the polymer attaches to clays on the wellbore and blocks the hydration and dispersion that normally occurs. The anionic carboxyl groups attach to the positive charges on the edges of the clay particles. Since the polymer has a high molecular weight and is relatively long, it combines with several sites along the wellbore. This has the effect of coating the wellbore and restricting water from entering the clay. The same effect is seen on the drilled cuttings. The polymer helps preserve the integrity of the cuttings, which allows for much easier cuttings removal at the surface. PHPA also aids in shale stabilization by thickening the water phase. PHPA increases the viscosity of the drilling fluid filtrate, which has the effect of limiting the filtrate depth of invasion. Although water may penetrate far into a shale, a thick polymer filtrate faces much greater resistance due to the rapid buildup of capillary pressures. This has the effect of reducing the amount of filtrate water available for hydration. It also limits the ability of a filtrate to enter a small fissure or fracture plane within a shale. Shale studies have established that a 70:30 ratio of acrylamide units to acrylate units is optimum for drilling fluids. This often is referred to as 30% hydrolysis. It has also been determined
of sodium polyacrylate to acrylamide at the beginning of the process determines the ratio of the two functional groups on the final copolymer. The two monomers that make up the copolymer are shown below. CH = CH2
CH = CH2
C COO&#;Na+ Sodium acrylate
O NH2 Sodium acrylamide
Figure 17: Sodium acrylate/acrylamide.
PHPA also aids in shale stabilization by thickening the water phase.
During copolymerization, the two monomers are linked together in a random fashion to form a linear, carboncarbon backbone. The resulting copolymer has carboxyl groups and amide groups randomly distributed along its backbone. The resulting copolymer is shown in Figure 18. Note that due to the carbon-carbon linkage, the polymer has exceptional thermal stability and is resistant to bacteria. Also note that the polymer is anionic, meaning it is affected by hardness and cationic surfaces like those found on clays. POLY-PLUS*. The most commonly used PHPA in drilling fluids is the highmolecular-weight version which is prepared with 65 to 70% acrylamide and the remaining percentage acrylate. Molecular weights range up to 20 million. POLY-PLUS is used as a shale inhibitor and solids-encapsulating polymer in freshwater, seawater, NaCl and KCl systems. In addition to its CH2
CH
CH2
CH
C O
CH2
CH
C NH2
O
C O&#;
O
NH2
n
Figure 18: PHPA.
Polymer Chemistry and Applications
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6
One of the drawbacks to PHPA is its sensitivity to soluble calcium.
Polymer Chemistry and Applications
that higher-molecular-weight polymers encapsulate shale better than low-molecular-weight polymers. As mentioned earlier, it is necessary to copolymerize with sodium acrylate to achieve water solubility; however, a 100% polyacrylate does not provide as much inhibition as the 70:30 ratio. Even at similarly high molecular weights, the 70:30 ratio provides better shale inhibition. It is thought that a high-molecularweight polyacrylate has too much affinity with the positive charges on clays. Similar to lignosulfonates, as the polymer remains in the system and attaches to active clay edges both in the fluid system and on the wellbore, strong attractive forces may actually pull the clays apart and cause them to disperse into the system. The amide group helps by providing some distance between the strongly anionic carboxyl groups and the cationic sites on the clay particles. When the amide groups and the carboxyl groups are distributed evenly along the polymer chain, the bulkiness of the amide group prevents the carboxyl group from getting too close to the clay charges and breaking the clays apart. The acrylamide group also has an affinity with the clay surface, but it is a relatively weak hydrogen bond compared to the strong ionic interaction between the carboxyl group and positively charged edges on clay particles. The acrylamide group is capable of forming hydrogen bonds along the clay surface. While not nearly as strong as the ionic interaction taking place alongside, it serves to hold the polymer/clay interaction in place as well as to provide distance between the free charges. In a salt environment, PHPA is still very effective in a shale-stabilizing capacity, although its concentration must be increased to obtain a significant effect on filtrate viscosity. As the Polymer Chemistry and Applications
6.16
salinity of the water increases, the PHPA does not hydrate free water as readily, and the polymer remains somewhat coiled. This leads to a decrease in the viscosifying characteristic of the polymer. The polymer is still anionic, however, and is still adsorbed on the active sites on the wellbore. Applying PHPA to salt-base drilling fluids simply means that more PHPA polymer must be added to obtain the same encapsulating and filtrate-thickening effects. Since salt muds, particularly KCl muds, impart a great deal of shale stabilization on their own, a salt PHPA mud offers exceptional shalestabilization characteristics. The salt or KCl provides excellent shale stabilization and the PHPA provides a viscosified filtrate that limits invasion depth. One of the drawbacks to PHPA is its sensitivity to soluble calcium. Like polyacrylate, the anionic carboxyl site reacts with calcium. This is particularly a problem in freshwater systems, where calcium can precipitate the PHPA polymer as well as whatever solids the polymer is adsorbed on. In some cases, PHPA functions as a flocculant in the presence of calcium, particularly when the solids content of the drilling fluid is low. When the solids content is low and calcium is introduced, flocculation occurs and the solids precipitate and settle out of the mud. In high-solids systems, the introduction of calcium flocculates the system and very high viscosities result. In a salt mud, the PHPA polymer remains relatively coiled and is not as susceptible to the flocculating effects of soluble calcium. It is still affected by Ca2+, at least to some extent. Since the Ca2+ reacts directly on the polymer with an anionic site, that anionic site is no longer available for an active wellbore site. In short, more polymer must be used to overcome the effect of calcium. It is recommended to treat soluble calcium to below 300 mg/L in PHPA Revision No: A-2 / Revision Date: 12·31·06
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6
Removing calcium from the system requires adding a carbonate source&#;
Hydrolysis of the PHPA polymer&#;is insignificant until a pH of 10 is reached&#;
Polymer Chemistry and Applications
PHPA
AS A BENTONITE EXTENDER, SELECTIVE FLOCCULANT AND TOTAL FLOCCULANT
systems. This is easier to perform in low-solids, low-density applications, particularly when the solids are not that hydratable. When the solids concentration is relatively high, such as a mud weight over 10 lb/gal (1.2 kg/L) and an MBT above 20 lb/bbl bentonite equivalent, then it is more difficult to treat calcium. Removing calcium from the system requires adding a carbonate source, such as soda ash or bicarbonate of soda, which may flocculate the system. A similar analogy is made with magnesium contamination. Magnesium also is attracted to the anionic carboxyl site. To treat magnesium, it is necessary to increase the pH to the 10.0 to 10.5 level. Since the reaction that occurs at that pH is reversible, the pH must be maintained at that high level to prevent the now-insoluble magnesium from becoming soluble again. PHPA systems are non-dispersed systems and do not tolerate alkaline pH easily. Like any non-dispersed system, the addition of caustic soda has a flocculating effect on PHPA systems. The hydroxide ion (OH&#;) is very reactive and goes straight to the unprotected clays in the system. The result is the same that is seen when caustic soda is added to spud mud, which is flocculation. Hydrolysis of the PHPA polymer occurs at any pH, but it is insignificant until a pH of 10 is reached, when a more rapid hydrolysis begins. The hydrolysis is nowhere complete at pH 10, but since hydrolysis results in the release of ammonia gas (NH3), which is very noticeable at low concentrations at the rig site, it is something to avoid. Hydrolysis is actually a fairly slow process at pH 10, taking a very long time for the reaction to proceed through the coiled polymer. The process can be accelerated by high temperatures. At temperatures above 300° F (149° C), hydrolysis occurs at a much higher rate.
Polymer Chemistry and Applications
Depending on its molecular weight and ratio of acrylamide to acrylate monomers, PHPA can serve several functions in a water-base drilling fluid. GELEX*. An example of PHPA used as a bentonite extender. When the conditions are right, very low concentrations of PHPA can extend the viscosity of bentonite. When the total solids of the system are less than 4% by volume, and the total bentonite concentration is less than 20 lb/bbl, PHPA can attach to the positive sites on a bentonite clay particle. With the bentonite particle attached to part of the polymer and the remaining polymer free to hydrate and/or attach to other clay particles, the result is an increase in viscosity. In effect, the PHPA polymer is hydrated and uncoiled and in suspension with colloidal bentonite particles. For PHPA to extend the yield of bentonite effectively, several conditions other than bentonite and total solids concentrations must be met. First, the system must be a freshwater system and relatively free of calcium (< 200 mg/L) for the bentonite to hydrate properly. Second, the amount of polymer must be in the 0.05 to 0.1 lb/bbl concentration range. Third, no dispersants &#; or any other additive that adsorbs to the bentonite &#; can be in the system. The process of extending bentonite is fragile and limited to low-solids, nondispersed applications. The addition of only a small amount of PHPA causes an immediate increase in viscosity. As the concentration of PHPA is increased, the viscosity reaches a maximum value and then, as additional polymer is added, breaks back. The effective range of polymer concentration is very narrow. Too little polymer concentration, and the system is little more than a gel slurry with a low concentration of bentonite. 6.17
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Polymer Chemistry and Applications
&#; Rheological properties of the system. &#; Geometry and size of the settling pit. &#; Retention time. &#; Temperature.
Overtreat with polymer, and the system thins out too much. The degree of bentonite extension depends on the following factors: &#; The MW and the ratio of acrlyamide to acrylate. &#; The size and hydration of the particle. &#; The salinity and hardness of the makeup water. &#; The concentration of the PHPA polymer.
PHPA also can be used as a flocculant.
It is recommended that FLOXIT be mixed in dilution water at a concentration of 1 to 2 lb/bbl before adding it to the system. Again, pilot testing is necessary to determine the optimum concentration.
HIGH-TEMPERATURE
FLOXIT*. PHPA also can be used as a flocculant. Flocculation is the process by which individual particles are connected in loosely bound, large aggregates by a flocculating polymer. The resulting mass of linked particles increases to the point at which the solids agglomeration falls out of suspension. Settling is most effective when the system is static. The mechanism involved in flocculation is very much like the mechanism used for bentonite extension. PHPA is also effective in both applications. It should be noted that PHPA is not as effective at flocculating systems that contain bentonite. Since bentonite breaks up into colloidal-size, hydrated solids, bentonite does not settle. The small hydrated particles do not have enough density to settle. The use of FLOXIT is limited to clearwater drilling applications. Once solids build in the water or the system is weighted, the product is no longer useful. Determining the optimum concentration of FLOXIT must be determined by pilot testing. The effectiveness of the flocculation depends on the interaction of the polymer with the solids, which in turn depends on the following: &#; Hydratability of the solids. &#; The concentration of the solids. &#; Salinity of the water. &#; Hardness of the water. &#; Chemical characteristics of the polymer. &#; Polymer concentration.
Polymer Chemistry and Applications
SYNTHETIC POLYMERS
Due to the thermally stable carboncarbon linkage that makes up the backbone of synthetic polymers, hightemperature polymers are synthetically derived. Several high-temperature polymers are available for drilling fluids. A number of them are prepared from the AMPS (2-acrylamido-2-methyl propane sulfonic acid) monomer. AMPS was covered earlier in this chapter in conjunction with TACKLE. AMPS is used in the preparation of TACKLE to improve tolerance to solids, salinity and hardness at high temperatures. AMPS is also used to improve the high-temperature tolerance to contaminants in fluid-loss-control additives. Examples of copolymers and terpolymers that incorporate the AMPS monomer or other sulfonated monomers are the Hoechst&#;s Hostadrill ^, Drilling Specialties&#; Driscal-D^ and SKW&#;s Polydrill^. The manufacturers of these materials claim that their respective polymers withstand salt and hardness at temperatures to 400° F (204° C). Chemical structures for Hostadrill and Polydrill are given in Figures 19 and 20. An example of a high-temperature polymer that functions to prevent hightemperature gelation is a Sulfonated Styrene Maleic Anhydride (SSMA) copolymer. Generally, it is applied to wells at high temperatures prior to logging runs and at other times when the drilling fluid is not circulated for an 6.18
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6
________________________
Polymer Chemistry and Applications
CH2
CH
________________________ ________________________
CH2
CH
CH2
C=
N
NH
C=O
extended period of time. It has the effect of maintaining stable gel strengths at high temperatures. It is not a fluid-loss control additive or a deflocculant (see Figure 21).
CH C=O
CH3
NH2
________________________ ________________________
H3C
C
CH3
CH
CH
CH2
________________________ ________________________
SO3Na
________________________
CH
O=C
n
Figure 19: Hostadrill .
CH2
C=O O
SO3Na
________________________ ________________________
OH
CH
n
Figure 21: SSMA.
________________________ OH
________________________
R&#;
________________________ ________________________ ________________________
CH2
C
CH2
SO3&#;Na+
C
SO3&#;Na+
n
Figure 20: Polydrill.
Polymer Chemistry and Applications
6.19
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CHAPTER
7
Filtration Control
Introduction A basic drilling fluid function is to seal permeable formations and control filtration (fluid loss). Potential problems related to thick filter cakes and excessive filtration include tight hole, increased torque and drag, stuck pipe, lost circulation, poor log quality, and formation damage. Adequate filtration control and the deposition of a thin, low-permeability filter cake are often necessary to prevent drilling and production problems. Potential problems from excessive filter-cake thickness: 1. Tight spots in the hole that cause excessive drag. 2. Increased surges and swabbing due to reduced annular clearance. 3. Differential sticking of the drillstring due to increased contact area and rapid development of sticking forces caused by higher filtration rate. 4. Primary cementing difficulties due to inadequate displacement of filter cake. 5. Increased difficulty running casing.
Potential problems from excessive filtrate invasion: 1. Formation damage due to filtrate and solids invasion. Damaged zone too deep to be remedied by perforation or acidization. Damage may be precipitation of insoluble compounds, changes in wettability, changes in relative permeability to oil or gas, formation plugging with fines or solids, and swelling of in-situ clays. 2. Invalid formation-fluid sampling test. Formation-fluid flow tests may give results for the filtrate rather than for the reservoir fluids. 3. Formation-evaluation difficulties caused by excessive filtrate invasion, poor transmission of electrical properties through thick cakes, and potential mechanical problems running and retrieving logging tools. Erroneous properties measured by logging tools (measuring filtratealtered properties rather than reservoir fluid properties). 4. Oil and gas zones may be overlooked because the filtrate is flushing hydrocarbons away from the wellbore, making detection more difficult.
Mud flow Fine solids Filter cake Bridging solids Filtrate invasion Sand matrix Formation fluids
Figure 1: Filtration characteristics.
Filtration Control
7.1
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CHAPTER
7
Filtration Control
Fundamentals of Filtration
The API has standardized two static filtration test procedures.
Mud systems should&#;seal permeable zones as quickly as possible&#;
Drilling fluids are slurries composed of a liquid phase and solid particles. Filtration refers to the liquid phase of the drilling mud being forced into a permeable formation by differential pressure. During this process, the solid particles are filtered out, forming a filter cake (see Figure 1). If the liquid phase also contains an immiscible liquid &#; such as a brine in an oil-base mud &#; then the immiscible liquid droplets will also be deposited in the filter cake and will assist in filtration control. Permeability refers to the ability of fluid to flow through porous formations. Mud systems should be designed to seal permeable zones as quickly as possible with thin, slick filter cakes. In highly permeable formations with large pore throats, whole mud may invade the formation (depending on the size of the mud solids). In such situations, bridging agents must be used to block the openings so the mud solids can form a seal. Bridging agents should be at least one-half the size of the largest openings. Such bridging agents include calcium carbonate, ground cellulose and a wide variety of other lost-circulation materials. Filtration occurs under both dynamic and static conditions during drilling operations. Filtration under dynamic conditions occurs while the drilling fluid is circulating. Static filtration occurs at other times &#; during connections, trips or when the fluid is not circulating. The American Petroleum Institute (API), low-pressure, lowtemperature and the High-Temperature, High-Pressure (HTHP) filtration and filter-cake measurements made by the mud engineer are static tests. These tests are very good at evaluating the overall filtration tendencies of the mud and are somewhat indicative of the laminar flow, dynamic filtration Filtration Control
7.2
characteristics. More sophisticated, labor-intensive tests using laboratory instruments are available for measuring dynamic filtration, but they are not practical for routine testing.
STATIC
FILTRATION TESTS
The API has standardized two static filtration test procedures. One is the lowpressure, low-temperature test and the other is the HTHP filtrate test. Normally, the low-pressure, low-temperature test is referred to as the &#;API filtration test.&#; The API filtration procedure is run for 30 min at ambient temperature with 100 psi (6.9 bar) differential pressure across the filter paper. Temperature variations affect this test, so care should be taken to run it at about the same temperature each time. In the temperature range from 70 to 140° F (21.1 to 60° C), the filtrate volume will increase about 50% or approximately 10% for each 15° of temperature increase. The API filtrate is reported as the cubic centimeters (cm3) of filtrate collected after 30 min. The thickness of the API filter cake deposited during the API filtration test is reported in 1&#;32 of an inch. In some areas, operators require metric measurements, and the filter-cake thickness is reported in millimeters (mm). The HTHP test is run for 30 min at 300° F (148.9° C) or a temperature near the formation temperature with 500 psi (34.5 bar) differential pressure across the filter paper. This test is run at temperatures as low as 200° F (93.3° C) and as high as 450° F (232.2° C). The HTHP filtrate is reported as two times (2x) the cubic centimeters (cm3) of filtrate collected after 30 min. The filtrate volume is doubled because the HTHP filtration cell has one-half the filtration area of the API filtrate cell. The thickness of the HTHP filter cake deposited during the HTHP filtration test is reported in either 1 &#;32 of an inch or millimeters (mm). Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
This high rate of initial filtration is called the spurt loss.
Darcy&#;s law, a classical fluid-flow model, helps to identify the factors that affect filtration.
Filtration Control
The filtrate receiver for HTHP testing is pressurized to prevent heated filtrate from flashing off as steam. This pressure must be greater than the vapor pressure of water at the test temperature. At test temperatures of 300° F (148.9° C) or lower, the receiver pressure is run at 100 psi (6.9 bar) with the cell pressure at 600 psi (41.4 bar). For test temperatures greater than 300° F (148.9° C), the receiver pressure in the HTHP test should be determined from the water vapor pressure at the test temperature. The top assembly or cell pressure is run at the receiver pressure plus 500 psi (34.5 bar), to create the standard 500 psi (34.5 bar) pressure differential. Whatman No. 50 filter paper or its equivalent is used at test temperatures below 350° F (176.7° C). Filter paper chars (burns) at temperatures approaching 400° F (204.4° C). Dynalloy X-5 stainless steel disks or an equivalent should be used instead of filter paper at test temperatures greater than 350° F (176.7° C). Dynalloy X-5 disks are NOT reusable. Another type of HTHP static filtration test, the Permeability Plugging Apparatus (PPA), is used occasionally to evaluate the filtration rate through simulated cores (aloxite or ceramic disks). This test is called the Permeability Plugging Test (PPT) and measures a &#;spurt loss&#; and a 30-min fluid loss at very high pressures (500 to 2,500 psi [34.5 to 172.4 bar]) and high temperatures. The PPA is a modified HTHP cell with a floating piston and hydraulically pressurized mud chamber. The unit has the simulated core located in the top of the cell and filtrate is collected from the top.
FILTRATION
THEORY
For filtration to occur, three conditions are required: 1. A liquid or a liquid/solids slurry fluid must be present. 2. A permeable medium must be present. Filtration Control
7.3
3. The fluid must be at a higher pressure than the permeable medium. During drilling, a fluid is circulated through the well. Permeable zones such as sandstones are drilled, and the hydrostatic pressure of the mud column is usually kept at a pressure higher than the pore pressure. Once these conditions are satisfied, a filter cake of mud solids will build up on permeable formations. Meanwhile, the liquid phase of the mud, the filtrate, will flow through the filter cake and into the formation. The filter-cake thickness and depth of filtrate invasion are controlled by the concentration of solids, differential pressure, permeability of the filter cake and length of exposure time. At the initial exposure of a permeable formation to a drilling fluid, when the mud solids are building a low-permeability filter cake on the wellbore, a high rate of filtration occurs and fine mud solids invade the formation. This high rate of initial filtration is called the spurt loss.
STATIC
FILTRATION
Static filtration occurs under static conditions, i.e., any time the mud is not circulating. Several factors control the filtration rate under such conditions. Darcy&#;s law, a classical fluid-flow model, helps to identify the factors that affect filtration. It also can be used to illustrate filtrate volume and cake thickness. Darcy&#;s law applies to the flow of fluids through permeable materials (sand, sandstone or mud filter cake). It can be used to relate filtration rate to permeability, cross-sectional area, differential pressure, filtrate viscosity and filter-cake thickness (see Figure 2). For the flow of filtrate through a filter cake, the permeability of the filter cake is the controlling permeability, since it is much lower than the permeability of the formation. Darcy&#;s law can be written as: Revision No: A-3 / Revision Date: 02·01·09
CHAPTER
7
Filtration Control
P1
ΔP
A
k
q µ
h
Figure 2: Illustration of Darcy&#;s law flow.
k A ΔP µh Where: q = Filtrate flow rate (cm3/sec) k = Permeability (darcies) A = Area, cross sectional (cm2) ΔP = Pressure differential (atmospheres) µ = Viscosity (cP) h = Thickness of filter cake (cm) As this equation illustrates, fluid loss is lower with lower filter-cake permeability, smaller area and lower differential pressure. Filtration also decreases with increasing filtrate viscosity and increasing filter-cake thickness, if the thicker filter cake has the same permeability. During static periods, the filter-cake thickness increases with time, but the rate of deposition decreases with time. A thick filter cake can cause a number of problems and is undesirable. Therefore, static filtration is a primary concern, and it is desirable to have the lowest practical fluid loss for any given drilling situation. The filtration rate of a drilling fluid is evaluated by measuring the volume of filtrate collected over a standard period of time. For this reason it is desirable to modify Darcy&#;s law to determine filtrate volume VF. The filtration rate, q, is equal to the change in filtrate volume divided by the change in time, dVF/dt. The filter-cake thickness, h, can be defined mathematically as: q=
&#;it is desirable to have the lowest practical fluid loss&#;
Filtration Control
(VF) FSLDS-MUD A [FSLDS-CAKE &#; FSLDS-MUD ] Where: VF = Volume filtrate FSLDS-MUD = Volume fraction solids in mud FSLDS-CAKE = Volume fraction solids in filter cake Substituting this into Darcy&#;s law and solving (integrating) for the filtrate volume: 2kt[FSLDS-CAKE &#; FSLDS-MUD]ΔP VF = A µ (FSLDS-MUDV) Where: t = Time This equation shows that filtrate volume is related to area and to the square roots of time, permeability and differential pressure. So, filtrate volume is lower with shorter periods of time, lower filtercake permeability and lower differential pressure. Filtrate volume is also inversely related to the square roots of viscosity and the mud solids fraction. So, filtrate volume will be lower with increased filtrate viscosity. The effect of solids concentrations is complex and does not influence filtrate volume to the same degree as do the other variables. From this relationship, it is often helpful to use filtration measurements, VF1, made at one set of conditions to predict filtration, VF2, at another set of conditions. h=
P2
7.4
&#;
FACTORS
AFFECTING FILTRATION
Time. When all other conditions are constant (pressure, area, viscosity, permeability), the filtration rate and filter-cake growth become progressively slower with time, as predicted by Darcy&#;s law. To predict the filtrate volume, VF2, over a time period of interest, t2, from a filtration measurement, VF1, made at a time period, t1, the filtrate volume collected will be a function of the square root of the ratio of the two time intervals:
Revision No: A-0 / Revision Date: 03·31·98
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7
Filtration Control
40 35
Fluid loss (cm3)
30 25 20 15 10 5 Spurt loss (constant error) 0
0
1
2
3
4
5 6 7 8 Square root of time (min-1/2)
9
10
11
12
Figure 3: Relationship of fluid loss to square root of time.
VF2 = VF1
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
&#;
t2 t1
Where: VF2 = Unknown filtrate volume at time t2 VF1 = Filtrate volume at time t2 t2 = Time period of interest t1 = Time period for VF1 If the filtrate volume, VF1, is measured after 1 hr and again after 4 hr, the second filtrate volume, VF2, will be 2 times the volume of the first filtrate, not 4 times the volume. 4 = VF1 x 2 VF2 = VF1 1 If the filtrate volume is known for one test time, the volume can be predicted for a second test time. The API filtration test time is 30 min. It is common field practice to use a 71&#;2-min test time and double the filtrate volume to estimate the 30-min API value. 30 = VF1 x 2 VF2 = VF1 7.5 Caution: This practice can lead to gross errors in the reported API filtrate volume. If the mud has a high spurt loss, the doubled 71&#;2-min filtrate volume will be greater
&#;
&#;
Filtration Control
7.5
than the true API 30-min filtrate volume. If the mud has a low filtration rate, the volume of filtrate which fills the empty flow path in the filter cell before fluid is collected (hold-up volume) will make the doubled 71&#;2-min filtrate volume lower than the true API 30-min filtrate volume. The API HTHP filtration test must always be run for 30 min. The thermal effects and cell hold-up volume make a 71&#;2-min HTHP test meaningless. As Figure 3 illustrates, the filtration rate is linear when the filtration volume is plotted against the square root of time or on a semi-log scale. The filtrate volume increases in direct proportion to the square root of time. A straight line plotted at various times does not ordinarily go through the origin; therefore, at least two points on the line must be used to extrapolate to longer time periods. A high spurt loss will cause the line to have a positive intercept on the yaxis, as in Figure 3. The positive intercept simply indicates that a spurt of filtrate passed through the filter paper before a cake was formed, restricting Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
7
Filtration Control
30 C 25
Filtrate volume (cm3)
Mud 1 20
15 B
10 B'
Mud 2
C'
5 All tests at 300° F (148.9° C)
X- A 0 100
200
300 Pressure (psi)
400
500
Figure 4: Effect of pressure-cake compressibility.
Filter-cake compressibility and permeability reduction are desirable&#;
the flow of filtrate. A low fluid loss and a dry cell with high hold-up volume will cause a negative y-axis intercept. This is because some filtrate must fill the empty flow path and drain line before the first drop can be collected, so the true filtrate volume is not collected. This error is most pronounced during short-time-period measurements and may be somewhat canceled by the spurt loss. Pressure differential &#; filter-cake compressibility. When all other conditions are constant (time, area, viscosity and permeability), the filtrate volume at two different pressures should be proportional to the square roots of the pressures, as predicted by Darcy&#;s law. But the filter cake of most drilling fluids is compressible, so the permeability decreases with increasing pressure. Filter-cake compressibility and permeability reduction are desirable features that limit filtration and filter-cake thickness. High-quality bentonite, when properly hydrated, is one of the best materials for increasing filter-cake compressibility. Regardless Filtration Control
7.6
of filter-cake compressibility, however, higher differential pressure usually causes higher filtration rates. Filter-cake compressibility can be evaluated by measuring the filtrate volume at two significantly different pressures. One method compares the filtrate volume collected at 500 and 100 psi (34.5 and 6.9 bar), as shown in Figure 4. The two mud samples compared had the same API filtrate, labeled Point A. The high-temperature, 100-psi (6.9-bar) tests are labeled Points B and B&#;, while the HTHP filtrate is labeled Point C and C&#;. (Another common test procedure compares two tests run at 200 and 100 psi [13.8 and 6.9 bar] and ambient temperature.) These high-pressure tests, using an HTHP cell, can be performed at ambient or elevated temperatures. If the mud solids form a compressible cake, the higher-pressure-filtrate volume should be only slightly higher than the lower-pressure filtrate. An incompressible filter cake will result in the higher-pressure-filtrate volume predicted by Darcy&#;s law. This is equal to the lower-pressure-filtrate volume, Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
Filtration Control
VF1, times the square root of the ratio of ΔP2/ΔP1. ΔP2 VF2 = VF1 ΔP1 Where: VF2 = Unknown filtrate volume at differential pressure ΔP2 VF1 = Filtrate volume at differential pressure ΔP1 ΔP2 = Pressure differential of interest ΔP1 = Pressure differential for VF1 This relationship should not be used to estimate filtration characteristics at another pressure. However, a comparison between VF2/VF1 and the square root of ΔP2 /ΔP1 is sometimes used to judge filter-cake compressibility. A VF2/VF1 ratio less than the square root of ΔP2 /ΔP1 indicates a compressible filter cake. The square root of ΔP2 /ΔP1 will indicate the slope of the line as plotted on Figure 4. Mud 1 (B&#;-C&#;) has a highly compressible filter cake as demonstrated by a negative slope. Mud 2 (B-C) has a relatively incompressible filter cake with a positive slope. The square root of ΔP2 /ΔP1 for Mud 2 (incompressible cake) is 2.0, which approaches the multiplier of 2.23, (&#;500/100), calculated by Darcy&#;s law. Filter-cake permeability. Filter-cake permeability is the limiting factor that controls filtration into the formation. The size, shape and ability of the particles to deform under pressure are all important factors in the control of permeability. Slurries with high concentrations of small particles form filter cakes of lower permeability. Generally, colloidal-size particles (less than 2 microns), such as bentonite, provide the highest amount of the fluid-loss control. Optimum control, however, is obtained by having a wide range of particle sizes. Smaller particles seal openings between the larger particles to form a low-permeability cake. Flat particles with large surface area, such as bentonite, can form a filter
&#;
Filter-cake permeability is the limiting factor that controls filtration&#;
Filtration Control
7.7
cake that resembles the shingled roof of a house. Flat particles are more effective than spherical or irregularly shaped particles since they form a more closely packed cake. In addition, as mentioned above, filter cakes that contain bentonite are compressible. Hydrated, high-quality bentonite is essential in obtaining a low-permeability filter cake. Bentonite particles are small (many less than 0.05 microns); have a large surface area; have a flat, plate-like shape and can be deformed easily. As the hydration of the particles is increased, the permeability of the resulting filter cake is decreased. Freshwater bentonite filter cakes have a permeability of about 1 microdarcy. Low filter-cake permeability limits fluid loss and filter-cake thickness. Filter-cake permeabilities are measured in microdarcies. Reservoir permeability is measured in millidarcies. A good cake is about 1,000 times less permeable than the permeable formation on which it is deposited. Filter-cake quality is dependent on optimizing the solids composition of the fluid so the concentration of drill solids does not impair the performance of the bentonite and the filtration-control additives. In a highly permeable formation with large pore openings, a bridging material may be required to prevent the flow of whole mud into the formation. Large particles must be laid down first to plug the large openings and start the deposition of a filter cake. Such bridging agents must be at least one-half the size of the largest openings. Medium and small particles seal the successively smaller holes that remain. The colloidal clays, other mud additives, filtration-control additives, asphalt, gilsonite and drops of emulsified oil (or brine) further reduce permeability. Bridging agents include calcium carbonate, ground cellulose (M-I-X* II) and a wide variety of other lost-circulation materials. Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
Filtration Control
Temperature °F °C 68 20 86 30 104 40 122 50 140 60 158 70 176 80 194 90 212 100 230 110 248 120 250 121 266 130 284 140
Viscosity of water cP 1.005 0.801 0.656 0.549 0.469 0.406 0.356 0.316 0.284 0.256 0.232 0. 0.212 0.196
Temperature °F °C 300 148.9 320 160 338 170 350 176.6 356 180 374 190 392 200 410 210 428 220 446 230 450 232.2 500 260 550 287.7 572 300
Viscosity of water cP 0.184 0.174 0.160 0. 0.150 0.142 0.134 0.127 0.121 0.116 0. 0. 0. 0.086
Table 1: Viscosity of water at various temperatures.
Increased temperature decreases the filtrate viscosity&#;
Filter-cake thickness and filtration rate are square-root related to filtercake permeability (like the relationship to time). This relationship is not used, however, due to the difficulty of measuring and controlling changes in filter-cake permeability. Viscosity. When all other conditions are constant (time, area, pressure, permeability), the filtrate volume with two filtrates with different viscosities is inversely related to the square root of the viscosity ratio, as predicted by Darcy&#;s law. Increases in filtrate viscosity reduce fluid loss and filter-cake thickness. Many filtration-control additives increase filtrate viscosity and reduce filter-cake permeability. Increased temperature decreases the filtrate viscosity, which in turn increases fluid loss. Due to this reduction in filtrate viscosity, all muds have increased fluid loss at increased temperature, whether the base liquid is water, brine, oil or synthetic. One exception is a newly prepared freshwater bentonite mud, which may have a reduced fluid loss when first exposed to slightly elevated temperatures due to increased dispersion and hydration of bentonite particles. Filtration Control
7.8
Although water is not considered viscous, changes in temperature affect its viscosity enough to increase filtrate volume significantly. Table 1 gives the viscosity of water at various temperatures. Using this data and the equation below, the filtrate volume at a different temperature can be estimated. The relationship of filtrate volume to changes in viscosity is: µ2 VF2 = VF1 µ1 Where: VF2 = Unknown filtrate volume with filtrate viscosity µ2 VF1 = Filtrate volume with filtrate viscosity µ1 µ1 = Filtrate viscosity for VF1 (at temperature 1) µ2 = Filtrate viscosity of interest (at temperature 2) If the fluid loss at 68° F (20° C) is 5 cm3, then the fluid loss at a Bottom-Hole Temperature (BHA) of 300° F (148.9° C) can be estimated by the change in filtrate viscosity. The viscosity of water at 68° F (20° C) is 1.005 cP and at 300° F (148.9° C) is 0.184 cP. Substituting into the equation, this increase in temperature would increase the fluid loss to:
&#;
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
Filtration Control
VF2 = 5
= 5&#; 5.46 &#; 1.005 0.184 = 5 X 2.34 = 11.7 cm
3
Viscous polymer fluids can be used to control filtration called leak-off&#;
Equal concentrations of different solids will have vastly different fluid losses.
Caution: This example uses an extreme change in temperatures. This type of calculation is more accurate for smaller temperature changes. At extreme temperatures, clays may flocculate, increasing the permeability of the cake, and filtrationcontrol additives may degrade, making these methods inaccurate. This method is most useful for determining the thermal stability of a fluid. Thermally stable fluids have HTHP fluid loss values closer to calculated values. Fluids with highly viscous filtrates &#; such as brines with high concentrations of biopolymers &#; can control fluid loss based on viscosity alone. Viscous polymer fluids can be used during both drilling and workover operations to control filtration (called leak-off during completion operations) with ultra-high viscosity. This is true even when these fluids contain no bridging agents and few solids, so that a true filter cake is not deposited. Polymer fluids that exhibit non-Newtonian behavior (become more viscous at low shear rates) are preferred for this application. As these fluids flow radially into the formation away from the wellbore, the shear rate decreases due to the larger flow area of the increasing diameter. This lower shear-rate flow allows the viscosity to recover (increase), reducing filtration even more.
Figure 5: Deflocculated mud. Filtration Control
7.9
Figure 6: Flocculated mud.
Solids composition and orientation. Solids in muds range from highly reactive clays and biopolymers to unreactive solids such as calcium carbonate, barite and hematite. The shape, size and distribution of the solid particles; the ratio of reactive solids to nonreactive solids; and the way the solids react to their chemical environment determine how the solids will affect the filtration rate. Equal concentrations of different solids will have vastly different fluid losses. Deflocculation and dispersion of clays also are important for filtration control. Figure 5 is a picture of a deflocculated mud in which there is a smooth flow with no evidence of clay platelets held together by electrochemical charges. Bentonite and clay particles are very thin, flexible solids with large, planar surfaces. It is convenient to think of a bentonite particle being like a microscopic piece of cellophane or wet sheet of paper. When the clay platelets are deflocculated, they are deposited in more of a flat orientation in the filter cake. They overlap to obtain a lowpermeability filter cake with good filtration control. However, if the mud system is flocculated, the bentonite particles will not lay flat but will orient themselves in an edge-to-face matrix, which causes high-permeability filter cakes and poor filtration control. Figure 6 is a picture of a flocculated mud in which the flow is not smooth Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
7
Desirable drilling fluids solids include weight materials&#;
Filtration Control
and the clay platelets form groups of particles with edge-to-edge orientation (flocks). When this occurs, the filtrate can pass easily between the porous flocks, resulting in high filtration rates. This can be corrected by adding chemical deflocculants, which neutralize the electrochemical charges on the clays or by using filtration-control additives, which are more effective for flocculated fluids. Deflocculants allow the clay platelets to disperse and overlap to provide a tougher filter cake. High solids concentrations are also detrimental to effective fluid-loss control. When the solids are too high, the available water is not adequate to solubilize the deflocculants or to allow the filtration-control additives to function. Therefore, treatments act as additional solids, compounding the situation and do not function as intended. This is a classic problem in deflocculated systems with lignosulfonate and complex salt muds with starch. In this case, adding liquid for dilution or new volume allows the chemicals to be effective, resulting in a reduction in filtration rates. The increase in filter-cake thickness with time also can be minimized by controlling the undesirable low-gravity solids content of the mud. Solids must be considered not only in terms of the volume percent, but also with regard to the quality and function. Desirable drilling fluids solids include weight materials, viscosifiers, filtrationcontrol additives and various other chemical additives. Hydrated Wyoming bentonite is highly compressible and beneficial in water-base filter cakes. Drilling in shales generates clay-rich drill solids, but they are much less hydratable and compressible than premium bentonite. A clay&#;s ability to hydrate can be predicted by its Cation Exchange Capacity (CEC), with higher values indicating greater hydration. The CEC of a mud&#;s
Filtration Control
7.10
low-gravity solids is a good indicator of its overall solids quality. The Methylene Blue Test (MBT) can be used to determine the equivalent pounds per barrel (lb/bbl) of bentonite in a mud and is a measure of the CEC. The concentration of drill solids and bentonite in the mud can be &#;roughly&#; calculated from the retort, chlorides and MBT with a material balance solids analysis. For good filtration control, the drill solids content of the mud should be kept as low as practical. A rule of thumb many operators use is to keep the drill solids below a ratio of 2 lb (0.9 kg) of drill solids for every 1 lb (0.5 kg) of bentonite, as per the PCMOD* calculated D:B ratio. The function of weight material is not related either to filtration control or cake quality. In most circumstances, the concentration of weight material cannot be reduced. The use of a weight material of higher density may improve cake quality by lowering the mud&#;s total solids content. The use of 5.0 Specific Gravity (SG) hematite (FER-OX*) instead of 4.2 SG barite (M-I BAR*) will reduce the volume of weight material in a mud by roughly 20%. Weight material does not contribute to cake compressibility, but often provides a particle size distribution that aids in primary bridging and particle plugging of permeable formations. Care should be taken when evaluating HTHP fluid loss. Both HTHP and API filter cakes should be examined for weight material settling, which will be indicated by a distinct layer of weight material on the filter medium. Weight material settling can lead to inaccurate filtrate values. But more important, it may indicate settling at downhole temperatures and the need for increased rheology.
DYNAMIC
FILTRATION
Dynamic filtration is significantly different from static filtration, often with considerably higher filtration rates. No direct correlation exists Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
As soon as the bit exposes permeable rock, dynamic filtration begins.
Dynamic filter cakes are thinner and firmer than static filter cakes.
Filtration Control
between API and HTHP static filtration measurements and dynamic filtration. Experience has shown that a mud which exhibits good static filtration characteristics and stability will have satisfactory performance under actual drilling conditions, indicating the dynamic fluid loss is in a satisfactory range. As soon as the bit exposes permeable rock, dynamic filtration begins. An overbalance in hydrostatic pressure will cause immediate filtrate flow into the formation at a high rate. As filtration continues, larger mud solids bridge porous formations and a filter cake begins to form &#; under dynamic conditions. As with static filtration, the permeability of the filter cake limits filtration, not the permeability of the formation. The turbulence of the fluid flow at the bit and adjacent to the drill collars tends to keep these filtration rates high by eroding the cake. Under dynamic conditions, filtration rates do not decrease with time as with static filtration. What&#;s more, the filter cake does not continue to increase in thickness. Instead, an equilibrium of filter-cake deposition and hydraulic erosion is established so the dynamic filtration rate becomes somewhat constant. It may not be true erosion as much as it is the tendency of the fluid motion to hinder the deposition of solid particles in an organized manner. The filter-cake equilibrium is governed chiefly by the characteristics of the mud solids (particle size, composition and concentration), and to a lesser degree by hydraulic conditions (turbulent or laminar flow) and filtrate viscosity. Dynamic filter cakes are thinner and firmer than static filter cakes. As drilling continues, the wellbore is subjected to changing conditions. Once the drill collars are past the permeable formation, laminar flow conditions normally prevail and hydraulic erosive forces are reduced. Under laminar conditions, Filtration Control
7.11
dynamic filtration rates are considerably lower than under turbulent conditions, and some correlation can be made to static filtration characteristics. During connections and trips, static conditions deposit a static filter cake and filtration rates are reduced (square root of time). Once circulation is resumed, the static cake deposited on the dynamic cake begins to be eroded (possibly completely, depending on hydraulic conditions) until once again it reaches equilibrium at a constant filtration rate. Studies have identified several important differences between dynamic filtration and static filtration. One difference is the effect of emulsified oil or other immiscible liquids. While these nonsoluble liquids reduce static fluid loss and filter-cake thickness, they actually increase dynamic filtration by making the filter cake less cohesive and more erodible. Another difference is that increasing the concentration of filtration-control polymers to decrease the API fluid loss to ultra-low levels may actually increase dynamic filtration. These differences are due mostly to changing the resistance to erosion of the filter cakes. Dynamic filter cakes deposited by flocculated fluids are thicker but more cohesive than cakes made by deflocculated fluids. The flocculated filter cakes&#; resistance to erosion appears to be related to the clay solids being held together by electrostatic charges. Filter cakes from deflocculated fluids appear to be more erodible because their charges are neutralized. This does not mean that flocculated fluids would be preferred on a dynamic filtration basis. The undesirable higher filtration rate and the increased filter-cake thickness outweigh any possible benefit from a tougher, less-erodible filter cake. As with static filtration, fluids and filter cakes containing a sufficient amount of high-quality bentonite produce the lowest filtration rates, thinnest filter cakes and most desirable overall filtration characteristics. Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
7
Filtration Control
Fluid-Loss-Control Additives
Three clays are used as mud additives: attapulgite, sepiolite and sodium bentonite.
FOR
WATER-BASE DRILLING FLUIDS
Several types of filtration-control additives are used in water-base muds. Recommendations for treatment are based on the mud system and its chemical environment. Clays. Clays are classified into groups based on mineralogy. Each group may contain a wide variety of subgroups with significantly different properties. Similar clays can be formed in slightly different geological environments, and this affects the purity and characteristics of a particular clay source. Three clays are used as mud additives: attapulgite, sepiolite and sodium bentonite. M-I GEL* and M-I GEL SUPREME* are sodium bentonite (or sodium montmorillonite), which is a member of the smectite group of clays. Attapulgite (SALT GEL*) and sepiolite (DUROGEL*) are needle-shaped clays used as mechanical colloidal viscosifiers in high-salinity brines. They do not provide filtration control and will not be discussed further in this chapter.
API-grade bentonite is the primary clay used in water-base drilling fluids and usually comes from Wyoming, hence the name &#;Wyoming&#; bentonite (sodium bentonite). It has one of the highest yields (i.e., it generates the largest volume of mud at a given viscosity) and is one of the most hydratable clays found anywhere; it is considered a premium product. Wyoming bentonite is the best product to use in formulating a mud with good filter-cake properties and filtration control. Bentonite not only provides filtration control, but also increases viscosity; therefore, quantities should be limited in weighted and high-temperature applications to the 7.5 to 15 lb/bbl range. Unweighted fluids often use 15 to 30 lb/bbl bentonite, depending on the makeup water chemistry and the desired viscosity. Any concentration above 7.5 lb/bbl will provide a good basis for filter cake and filtration characteristics. Bentonite particles are very thin, sheet-like or plate-like particles with a
Wyoming bentonite
Weight percent
API-grade bentonite is the primary clay used in water-base drilling fluids&#;
Sub-bentonite
Small _____________________________________ Particle size ____________________________________ Large Wyoming bentonite has a larger percent of small particles as compared to other clays and provides superior rheological and filtration properties.
Figure 7: Particle size bentonite. Filtration Control
7.12
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
&#;the platelet structure allows bentonite to lay flat in the filter cake and seal it&#;
The total drill solids content and the ratio of drill solids to bentonite must be controlled&#;
Filtration Control
large surface area. Under microscopic examination, they look like thin, flat, flexible pieces of cellophane or sheets of wet paper. Premium-ground bentonite has a high percentage of particles of less than one micron in width (see Figure 7). While this may seem small, clay platelets have a thickness of only about 10 angstroms. These dimensions give bentonite platelets a very high diameter-to-thickness ratio (1,000 to 1) and a very high surface area per unit of weight (~45 m2/g). When deflocculated, the platelet structure allows bentonite to lay flat in the filter cake and seal it in a manner often compared to shingles on a roof. Sodium bentonite surfaces have a high electro-charge density. This high charge density promotes hydration in freshwater by attracting many layers of water molecules to its surface. These hydrated bentonite particles deform and compress readily under pressure and form very low-permeability, lowporosity filter cakes. An indication of the amount of water bound to a hydrated bentonite platelet can be seen by retorting a freshwater bentonite filter cake. These filter cakes will contain about 85 volume percent water and only 15 volume percent bentonite. Sodium bentonite does not hydrate as rapidly or as much in water containing salts or calcium. In seawater or hard water, the filtration rate will be uncontrollable without the addition of deflocculants and/or supplementary filtration-control additives. Bentonite performance in salt or calcium muds can be greatly enhanced by prehydrating it in freshwater and treating it with deflocculants before adding it to the mud system. Bentonite that has been prehydrated and deflocculated may be used in saturated salt systems to improve the HTHP filtration. Prehydrated bentonite will eventually flocculate and dehydrate when
Filtration Control
7.13
added to salt or calcium muds. When this happens, additional treatments of prehydrated bentonite will be needed to maintain the system&#;s properties. To prehydrate bentonite: 1. Add the makeup water to the prehydration pit and treat the calcium to less than 100 mg/L with soda ash. (Do not treat the calcium to zero, since doing so may result in carbonate contamination!) 2. Add 30 to 40 lb/bbl of M-I GEL or 40+ lb/bbl M-I GEL SUPREME to the makeup water, through the hopper. 3. Stir and shear the bentonite slurry for 3 to 4 hr. 4. For low-pH, non-dispersed mud systems, skip steps 5 and 6. 5. Add 0.5 to 1.0 lb/bbl of caustic soda to the prehydrated bentonite through the chemical barrel and shear for an additional hour. 6. Add 0.5 to 1.5 lb/bbl of either SPERSENE* or SPERSENE CF to the prehydrated bentonite through the hopper. 7. Stir and shear the deflocculated, prehydrated bentonite at least one hour before adding it to the mud system. Dry bentonite can be added to inhibitive mud systems (calcium, potassium, salt, etc.) just to change the particle-size distribution. These fine, bentonite particles may act as bridging agents for other polymeric filtration-control agents, even though the bentonite is not hydrated. However, it is generally preferable to use prehydrated bentonite, if possible. The total drill solids content and the ratio of drill solids to bentonite must be controlled to optimize a drilling fluid&#;s properties and performance. The total volume percent of low-gravity solids should be kept within predefined limits by dilution or through the use of solidscontrol equipment. Centrifuges used
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
Polymers are the filtrationcontrol products used most often in water-base muds.
Starches are often classified as &#;non-ionic&#; materials&#;
Filtration Control
for barite reclamation discard bentonite. Periodic bentonite treatments should be made when centrifuging. Polymers. Polymers are the filtrationcontrol products used most often in water-base muds. They can range from natural starches and modified cellulose to sophisticated synthetic polymers capable of providing filtration control under high temperatures and hostile conditions. These polymers are sometimes classified by their action within a mud system, as well as by their chemistry. The classification by action is based on whether the polymer adsorbs onto the solids or viscosifies the fluid phase. Most common fluid-loss polymers will not only viscosify the fluid phase, but when used in sufficient concentration, will adsorb to solids, providing encapsulation. Care should be taken when adding polymers to muds because of the possible interactions with other mud-system chemicals. For field operations, it is recommended that pilot testing be performed before using an unfamiliar filtration-control additive. Polymers reduce fluid loss in several ways: 1. Plugging of openings of the filter cake by polymer particles. 2. Encapsulating solids forming a larger deformable coating or film which reduces the permeability of the filter cake. 3. Viscosification of the liquid phase. Figure 8 illustrates the increase in liquid-phase viscosity as the concentrations of several filtration-control additives are increased. Figure 9 shows the fluid loss, plastic viscosity and yield point of the several filtrationcontrol additives in a seawater mud with 30 lb/bbl of M-I GEL and 40 lb/bbl of simulated drill solids. Starch. Starch, a natural carbohydrate polymer, has been used to control filtration in drilling fluids since
Filtration Control
7.14
the s. It is widely available as yellow (untreated) and white (modified) starch. Starches can be used in seawater, salt water, hard water and complex brines. The most economical and widely used starches are made from corn or potatoes, but starches made from other agricultural products are also available. Most of the starch used for filtration control is processed by separating and heating the starch grains to rupture their amylopectin shell. This releases amylose, which absorbs water and swells to form sponge-like bags. Amylose lowers the filtration by reducing the free water in the system and plugging the filter cake&#;s pores. Starches processed in this manner are said to be pregelatinized. The performance of these starches should not be affected by pH, salinity, hardness or temperatures of less than 250° F (121.1° C). Starches are often classified as &#;non-ionic&#; materials, although they may have a very slight anionic character. Starch is sometimes used as a viscosifier in brine fluids, but starch solutions are more Newtonian and will not provide suspension for cuttings and weight material. MY-LO-JEL pregelatinized corn starch is an economical filtration-control additive that is effective in all makeup waters from freshwater to saturated salt water. It is subject to fermentation unless the mud is a saturated-salt system or the pH is >11.5. If one of these conditions is not satisfied, an appropriate biocide (also called bactericide or preservative), acceptable under local regulations, should be used to prevent fermentation. Once fermentation begins, bacterial enzymes may be present, making further additions of starch ineffective even after the active bacteria are eliminated with biocide. Starch is subject to rapid degradation at temperatures above 250° F (121.1° C).
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7
Starches&#; often require a minimum concentration before significant decreases in fluid loss are observed.
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Filtration Control
Normal concentrations of MY-LO-JEL range from 3 to 8 lb/bbl, depending on water chemistry and desired fluid loss. Starches like MY-LO-JEL often require a minimum, threshold concentration before significant decreases in fluid loss are observed. Daily treatments are required to maintain desired concentrations. POLY-SAL* is a preserved potato starch used for fluid-loss control in virtually every type of water-base mud, from freshwater to saturated salt and calcium systems. POLY-SAL is an effective filtration-control additive for drilling evaporite (salt) and hydratable shale sections. It is also very effective for stabilizing the filtration and rheology of high-salinity workover brines. POLY-SAL is thermally stable to about 250° F (121.1° C), after which it begins to experience thermal degradation. Normal concentrations of POLY-SAL range from 2 to 6 lb/bbl, depending on water chemistry and desired fluid loss. Starches like POLY-SAL often require a minimum, threshold concentration before significant decreases in fluid loss are observed. Daily treatments are required to maintain desired concentrations. FLO-TROL* is a modified starch used for fluid-loss control primarily in the non-damaging FLOPRO* reservoir drill-in fluid system. It is unique in that it actually helps increase low-shear-rate viscosity in the FLOPRO system, whereas most other starches decrease this property. It can be used in other water-base mud systems, especially high-salinity workover and completion brines. FLO-TROL is thermally stable to above 250° F (121.1° C), after which it begins to experience thermal degradation. Concentrations of FLO-TROL range from 2 to 6 lb/bbl, depending on water chemistry and desired fluid loss. Starches like FLOPRO often require a minimum concentration before significant decreases in fluid loss are Filtration Control
7.15
observed. Daily treatments are required to maintain desired concentrations. THERMPAC* UL is a modified-starch filtration-control additive designed for use in most water-base systems, including freshwater, seawater, salt and lowsolids muds. It has an Ultra-Low (UL) viscosity and does not generate as much viscosity as many other starches or cellulose additives. THERMPAC UL is not subject to bacterial degradation. Its effectiveness decreases in high-salinity (>100,000 mg/L chlorides) and highhardness (>800 mg/L) fluids. Ultralow-viscosity PAC products, such as POLYPAC* UL, should be used for saturated salt systems. THERMPAC UL is subject to thermal degradation at temperatures in the 250 to 275° F (121.1 to 135° C) range. THERMPAC UL reduces fluid loss in fresh or salt water. Normal concentrations range from 0.5 to 2.0 lb/bbl, depending on the water chemistry and desired fluid loss. Sodium Carboxymethylcellulose (CMC) is a modified natural polymer used for filtration control. The structure of CMC is a long-chain molecule that can be polymerized into different lengths or grades. The material is commonly made in three grades, each varying in viscosity, suspension and fluid-loss-reduction qualities. The three grades are High-Viscosity (HV), medium- or regular-viscosity (R), and Low-Viscosity (LV). The CMC polymer also is available in purities ranging from a 75% technical grade to a 99.5+% refined grade. Technical-grade CMC contains sodium chloride salt, a byproduct of the manufacturing process. CMC is an effective fluid-loss control additive in most water-base muds. It works particularly well in calciumtreated systems, where it acts to stabilize properties. CMC is not subject to bacterial degradation and performs well at an alkaline pH. CMC&#;s effectiveness decreases at salt concentrations greater Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
SP-101 is especially useful in polymer systems&#;
POLYPAC R increases viscosity and reduces fluid loss in fresh or salt water.
Filtration Control
than 50,000 mg/L. CMC is subject to thermal degradation at temperatures exceeding 250° F (121.1° C). The grade of CMC used will depend on which properties are desired. When viscosity as well as low fluid loss is desired, high- or medium-viscosity CMC is used. Low-viscosity CMC will reduce fluid loss with minimal increase in the viscosity. Because it is slightly anionic, the addition of small quantities of low-viscosity CMC may act as a thinner in low-solids, nondispersed muds. Normal concentrations vary with the different grades, but range from 0.5 to 3.0 lb/bbl, depending on the water chemistry and desired fluid loss. POLYPAC R Polyanionic Cellulose (PAC) is a modified natural polymer designed for use in most water-base systems, including freshwater, seawater, salt and low-solids muds. It is a high-molecularweight, polyanionic cellulose similar to CMC, but has a higher degree of substitution. It is the most widely used fluid-loss control additive and is generally a much better product than CMC. POLYPAC R is not subject to bacterial degradation and performs well at an alkaline pH. Its effectiveness decreases in saturated salt fluids. Ultra-low-viscosity PAC products, such as POLYPAC UL and POLYPAC SUPREME UL, should be used for saturated salt systems. POLYPAC R is subject to thermal degradation at temperatures exceeding 275° F (135° C). It is anionic and may thin in non-dispersed muds. POLYPAC R increases viscosity and reduces fluid loss in fresh or salt water. Normal concentrations range from 0.5 to 2.0 lb/bbl, depending on the water chemistry and desired fluid loss. POLYPAC SUPREME R polyanionic cellulose is high-quality polyanionic cellulose designed to function in more demanding conditions. It can be used in most water-base systems, including freshwater, seawater, salt and low-solids muds. POLYPAC SUPREME R is available in a UL-viscosity grade, which performs Filtration Control
7.16
better in high-salinity fluids. POLYPAC SUPREME R is not subject to bacterial degradation and performs well at an alkaline pH. It is subject to thermal degradation at temperatures exceeding 275° F (135° C). POLYPAC SUPREME R is anionic and may thin in non-dispersed muds. POLYPAC SUPREME R increases viscosity and reduces fluid loss in fresh or salt water. Normal concentrations range from 0.5 to 2.0 lb/bbl, depending on the water chemistry and desired fluid loss. SP-101* sodium polyacrylonitrile is a medium-molecular-weight, acrylic copolymer sometimes referred to as a sodium polyacrylate. It is a calciumsensitive, synthetic polymer. It is stable at high-temperatures and does not degrade bacterially. In addition to increasing the liquid phase viscosity to decrease fluid loss, the long-chain SP-101 molecule can adsorb onto the edges of clay particles (encapsulation), further reducing filter-cake permeability. SP-101 is especially useful in polymer systems such as POLY-PLUS, POLYPAC R seawater and GELEX* LowSolids, Non-Dispersed (LSND) systems. When SP-101 is added to the system, at least 0.5 lb/bbl should be added rapidly, then maintained at or above this concentration level at all times. This quick treatment reduces the viscosity &#;hump&#; that will occur if the mud contains high solids. It is important to increase the concentration of SP-101 above the critical polymer concentration to reduce viscosity. Normal concentrations range from 0.5 to 2.0 lb/bbl, depending on the water chemistry and desired fluid loss. SP-101 should not be used in muds that contain more than trace amounts of calcium. The calcium should be precipitated with soda ash before adding SP-101. It has been used in 400+° F (204.4° C) temperatures and has application in deep, hot holes.
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
Chemical thinners reduce filtration rates&#;
Filtration Control
RESINEX* is a resin/lignite complex which provides both filtration control and improved thermal stability. It is non-viscosifying, and can be used at temperatures in excess of 400° F (204.4° C) and in the presence of moderate concentrations of electrolytes. It has broad application and can be used in virtually any waterbase mud. RESINEX can be used in high-density muds where increases in viscosity are detrimental. Normal concentrations range from 2 to 6 lb/bbl. RESINEX has many field-proven benefits: &#; Non-viscosifying fluid-loss control. RESINEX controls fluid loss but does not significantly increase viscosity. It will have about the same effect on viscosity as an equal amount of lignite. &#; Filter cake improver. RESINEX reduces the filter-cake thickness and permeability by providing a better distribution of colloid-size particles. &#; Rheology stabilizer. RESINEX stabilizes the rheological properties of waterbase muds exposed to hostile conditions and helps prevent gelation. &#; Thermal stabilizer. RESINEX is temperature stable and controls fluid loss to temperatures >400° F (>204.4° C). &#; Salt tolerant. RESINEX reduces filter cake permeabilities in muds with salinity ranging from freshwater to 110,000-mg/L chlorides. &#; Hardness resistant. RESINEX functions in fluids with soluble calcium and magnesium. This makes RESINEX ideally suited for use in seawater, gyp and lime muds. &#; Economical. RESINEX outperforms many additives on a cost/performance basis, especially in high-hardness and high-temperature applications.
Filtration Control
7.17
CHEMICAL
THINNERS
Chemical thinners reduce filtration rates by deflocculating the clays, by increasing the fluid phase viscosity and by changing the solids distribution. Quebracho, TANNATHIN*, XP-20*, SPERSENE CF and SPERSENE are effective at deflocculating and lowering fluid loss. SPERSENE and XP-20 help provide filtration control at temperatures far beyond those in which starch or CMC can be used effectively. They are not subject to bacterial degradation in active mud systems and can be used effectively in high-salt or high-calcium concentrations. SPERSENE and XP-20 will reduce both the API and the HTHP fluid losses. At temperatures above 315° F (157.2° C), more XP-20 than SPERSENE should be used. XP-20 is stable at temperatures above 450° F (232.2° C) and should be used (when applicable) to provide fluid-loss control in hightemperature, dispersed systems. Note: SPERSENE and XP-20 contain trivalent chrome (a more acceptable form) which may not be acceptable for all applications, depending on local environmetal regulations and considerations.
OIL- AND SYNTHETIC-BASE DRILLING FLUIDS The API fluid loss of these systems is normally zero, or too low to be an effective measure. The filtration rate of oil muds, unless otherwise noted, refers to the HTHP filtration. The oldest oil-base systems were &#;alloil&#; and did not contain added brine. They usually contained 1 to 5 volume percent water as a contaminant from formation fluids. All-oil systems are still used for special applications like coring and where changes caused by strong emulsifiers cause formation damage. These systems often use
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CHAPTER
7
Most oil- and synthetic-base fluids are emulsions.
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Filtration Control
asphaltic materials and organophilic clay for filtration control and viscosity. Some systems use viscosity modifiers designed for lubricating oil and other, more sophisticated chemicals for viscosity and filtration control. Most oil- and synthetic-base fluids are emulsions. Their fluid phase is an emulsion with oil or synthetic as the continuous phase and brine as the emulsified phase. These systems contain from 10 to 50 volume percent brine, usually calcium chloride. The emulsified brine forms colloid-sized droplets, which are immiscible in the oil or synthetic. These brine droplets become trapped in the filter cake and reduce filter-cake permeability and fluid loss. Invert emulsion muds may contain emulsifiers, wetting agents, organophilic clays, asphalts and/or amine-treated lignite, polymers, lime and weight material. The chemistry of these additives and their interrelationships are complex and are discussed in greater detail in the chapters dealing with oil- and synthetic-base muds. The filtration rate of invert-emulsion muds is affected by additives other than the filtration-control additives. Base liquid. The oil- or syntheticbase liquid can affect filtration rates and the choice of additives that must be used to control filtration. The viscosity of the base fluids will only slightly affect filtration rates, as per Darcy&#;s law. In regions where extremely cold winters can be expected, anti-gellants are added to fuel oils during the cold periods. These anti-gellants can make diesel oil unsuitable for use in drilling fluids. Field tests cannot detect these anti-gellants, but pilot testing can determine if diesel oil is suitable for use in invert emulsions. Brine. Invert emulsion muds use either sodium chloride or calcium
chloride brine in the internal phase of the emulsion. The emulsified brine phase acts as a fine colloidal solid in invert emulsion muds and the small droplets contribute significantly to filtration control. The brine content affects many properties and is not increased simply to reduce fluid loss. This is especially true in weighted muds, where the increased brine acts like a solid, increasing the viscosity. Emulsifiers. Although emulsifiers are not true filtration-control additives, they can reduce filtration by increasing the emulsion strength if the emulsion is unstable. Indications that more emulsifier is needed are a low or decreasing trend in the Electrical Stability (ES) and/or water in the collected HTHP filtrate. A sufficiently stable emulsion should be established before treating with filtration-control additives. If an emulsifier requires lime to be activated, excess lime should be maintained in the mud. Wetting agents. Solids (clays, drill solids and weight material) must be &#;wetted&#; by the base liquid or they will tend to settle, increasing both viscosity and fluid loss. The appropriate wetting agents and emulsifiers should be used in sufficient concentrations to keep all solids adequately &#;wet.&#; If sufficient wetting agent is not present, adding it will reduce the rheological properties. Pilot testing can determine whether an increased wetting agent is needed. Viscosifiers. The primary viscosifier in invert emulsion muds is organophilic clay. Although this clay does not hydrate, it will reduce the filtration rate by providing a colloidal solid for forming a basic filter cake. Filtration-control additives. The primary filtration-control additives for invert emulsion muds are asphalt, gilsonite (natural asphalt), aminetreated lignite and various other resins
________________________
Filtration Control
7.18
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
7
&#;&#;solids-free&#; and &#;clear&#; are often used to describe brines used for drilling&#;
Filtration Control
and specialized polymers. The asphaltic materials usually provide better filtration control than the amine-treated lignite at equal concentrations and temperature. Some operators prohibit asphaltic materials for fear they may damage formation permeability. Local environmental regulations and M-I SWACO* policies should be considered before using VERSATROL* or any other asphaltic materials in a synthetic-base mud.
WORKOVER
AND COMPLETION BRINES
The terms &#;solids-free&#; and &#;clear&#; are often used to describe brines used for drilling into production zones, setting gravel packs, and for other completion and workover operations. Occasionally, calcium carbonate and sized salt (sodium chloride) are used in these brines to prevent lost circulation (leak-off). Ideally, these brines are free of acid-insoluble solids (clays, sand, barite, etc.). Sodium chloride, calcium chloride, sodium bromide, calcium bromide, and sometimes zinc bromide brines are used for these applications. Zinc bromide brines are not widely used because they are corrosive and very expensive.
Brines can provide density for well control without introducing potentially damaging solids to the formation. The high salinity also inhibits the swelling of formation clays. Although these brines are not as damaging to the formation as freshwater or seawater, their loss must be controlled. Filtration-control additives for these systems usually consist of polymers and bridging agents. The most often-used polymer for viscosity is Hydroxyethylcellulose (HEC). Polymers are used for viscosity and fluid-loss control. Bridging agents are required to plug formation openings that are too large to be plugged by polymers. M-I SWACO supplies large, medium and fine grinds of sized calcium carbonate (marble or limestone) particles for use as bridging agents. Typical median particle sizes for these products are: coarse (104 microns), medium (43 microns) and fine (13 microns). The average particle size for a bridging agent should be at least one-half the size of the pore opening. Since grind sizes cover a much broader range than just the median particle size, there will be enough large particles to initiate bridging.
Summary
Offset well records are the best tools for determining the level of fluid-loss control required&#;
Fluid loss should not be considered an absolute value. Rather, it should be considered only an indication of the filtration properties of the mud in the well. Because many variables influence filtration properties, it is impossible to predict actual fluid loss to the formation from static tests. Offset well records are the best tools for determining the level of fluid-loss control required to drill a given well safely and successfully. Formations that are not water-sensitive can be drilled with a mud having an API fluid loss of 20 cm3. Conversely,
Filtration Control
7.19
water-sensitive shales that slough, heave and hydrate may require a mud with an API fluid loss of 5 cm3 or less. The mud engineer should recommend changes to the mud system to obtain acceptable drilling results based on the conditions for a particular well and the symptoms observed, i.e., tight hole, sticking tendencies, sloughing shale, etc. Experience in an area will serve as a guide to determine the fluid-loss specifications for a drilling mud program. Every effort should be made to drill with the &#;right&#; level of fluid loss &#;
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
that level at which drilling or production problems are avoided. Filtrates that are lower than necessary will increase the mud cost and may decrease drilling rates. Filtration that is too high will cause tight hole, sticking, shale sloughing and other problems mentioned earlier. With increasing well depth, it is necessary to reduce fluid loss to prevent problems. Consequently, it is common to drill a surface hole with a mud having a fluid loss of 20 cm3, then complete the well with a mud having a fluid loss of 2 cm3. It is necessary for the mud engineer to acquaint himself with the fluid-loss requirements of the area in which he is working. Acceptable filtration rates will vary from one area to another and are dependent on the formation, depth, differential pressure, temperature and mud type. Once the desired value is established, fluid-loss control may be accomplished by applying the principles previously stated. Briefly, they are: minimizing drill solids, optimizing the colloidal solids and
using the appropriate filtration-control additive. Figures 8 and 9, combined with Table 2, can be helpful in selecting a fluid-loss additive for a particular application. Table 2 shows the effectiveness of each fluid-loss-control agent in different types of mud systems. Before applying any of the fluid-loss control agents, consider the following factors: 1. Can it be used in the presence of calcium? 2. Can it be used at high salt concentration? 3. Will it need a preservative? 4. Will it function at the required temperature? 5. Will it produce an unacceptable change in viscosity? 6. Will it support weight material with a minimum amount of solids? 7. Is it economical for the particular operation? 8. Is it the most efficient agent under the given circumstances?
*R
35
PAC
30
20
* 01 -1 P S
Te ch .
Reg .C MC
25
C M C
POLY
With increasing well depth, it is necessary to reduce fluid loss to prevent problems.
Filtration Control
Apparent viscosity (cP)
7
15
10
5
0
MY-LO-JEL* RESINEX* 0
1
2
3
4 5 6 7 Chemical concentration (lb/bbl)
8
9
10
Figure 8: Viscosity vs. concentration, filtration-control additives. Filtration Control
7.20
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CHAPTER
Filtration Control
30
Plastic viscosity Yield point Fluid loss
Base Blank 6 lb/bbl RESINEX Reg. CMC 11&#;2 lb/bbl Tech. CMC 11&#;2 lb/bbl MY-LO-JEL 4 lb/bbl SP-101 11&#;2 lb/bbl POLYPAC R 11&#;2 lb/bbl Mud contains sea water 30 lb/bbl - M-I GEL* 40 lb/bbl - Drill solids
10
0
50
40
20
Plastic viscosity (cP)
60
30
Fluid loss (cm3 API)
Yield point (lb/100 ft2)
7
20
10
0 Blank
RESINEX*
Reg. CMC
Tech. MY-LO-JEL* SP-101* POLYPAC* R CMC
Figure 9: Flow properties and effectiveness in various treatments. POLY-SAL* MY-LO-JEL*
CMC (reg.)
CMC (LV) SP-101* RESINEX* POLYPAC* UL
________________________
Low pH freshwater mud F F&#; E E E&#; F E High pH freshwater mud F E E E E&#; F E Seawater or brackishwater mud F F&#; E E NU E E Saturated seawater mud E E F F NU NU G Lime-treated mud E E G G NU E G KCl mud E E&#; E E NU F E Gyp mud G F&#; E E NU E E E &#; Excellent results NU &#; Not used G &#; Good results &#; Preservative needed F &#; Fair results &#; Soluble calcium should be kept as low as possible Note: Where extremely low fluid loss is desired, starch gives better results than CMC. Where better suspension qualities are desired, CMC or POLYPAC R will give better results than either starch or SP-101.Where extremely high salt concentrations are present, starch, SP-101 or POLYPAC UL will give better results than CMC.
________________________
Table 2: Effectiveness of fluid-loss agents in various water-base muds.
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7.21
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
8
Solids Control
Introduction The types and quantities of solids present in drilling mud systems determine the fluid&#;s density&#;
The types and quantities of solids present in drilling mud systems determine the fluid&#;s density, viscosity, gel strengths, filter-cake quality and filtration control, and other chemical and mechanical properties. Solids and their volumes also influence mud and well costs, including factors such as Rate of Penetration (ROP), hydraulics, dilution rates, torque and drag, surge and swab pressures, differential sticking, lost circulation, hole stability, and balling of the bit and the bottom-hole assembly. These, in turn, influence the service life of bits, pumps and other mechanical equipment. Chemicals, clays and weight materials are added to drilling mud to achieve various desirable properties. Drill solids,
consisting of rock and low-yielding clays, are incorporated into the mud. These solids affect many mud properties adversely. Nevertheless, since it is not possible to remove all drill solids &#; either mechanically or by other means &#; they must be considered a continual contaminant of a mud system. Solids removal is one of the most important aspects of mud system control, since it has a direct bearing on drilling efficiency. Money spent for solids control and for solving problems related to drill solids represents a significant portion of overall drilling costs. Solids control is a constant problem &#; every day, on every well.
Fundamentals
________________________ ________________________
Drilling mud solids may be separated into two categories: Low-Gravity Solids (LGS), with Specific Gravity (SG) in the 2.3 to 2.8 range, and High-Gravity Solids (HGS), with SG of 4.2 or higher. Weight materials such as barite or hematite comprise the HGS category and are used to achieve densities greater than
10.0 lb/gal (SG>1.2). Drill solids, clays and most other mud additives fall into the LGS category and often are the only solids used to obtain densities up to 10.0 lb/gal (SG 74 microns) are classified as sand. Ninety-seven percent of good-quality barite ( 2,000 ft (610 m)
SITUATION 1
20A.8
A 15.3-lb/gal (1.84 SG) polymer mud is being used in a 58°, 12.25-in. (311-mm) hole. The ΔMW for this mud is 1.3 lb/gal (156 kg/m3). The angled hole length is 450 ft (137 m). The mud is estimated to be in laminar flow. Referring to the previously given Sag Index factors: Ka = 0.7 Kd = 0.5 Kf = 1.0 Kh = 0.5 Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20A
Barite Sag
Substituting the values into Equation 4 gives: Si = ΔMW x Ka x Kd x Kf x Kh Si = 1.3 x 0.7 x 0.5 x 1.0 x 0.5 Si = 0.
Substituting the values into Equation 4 gives: Si = ΔMW x Ka x Kd x Kf x Kh Si = 0.5 x 1.0 x 0.8 x 1.0 x 0.8 Si = 0.32
SITUATION 3
COMMENT
An 11.2-lb/gal (1.34 SG) seawater lignosulfonate mud is being pumped through a 1,500-ft (457-m) cased hole with a diameter of 17.5 in. (445-mm). Borehole angle is 45°ΔMW is 0.5 lb/gal (60 kg/m3). The mud is in laminar flow. Referring to the previously given Sag Index factors: Ka = 1.0 Kd = 0.8 Kf = 1.0 Kh = 0.8
The Si results from these examples indicate that the mud system in Situation 3 has a greater potential for sag-related problems than the fluids in the other cases, even though it has the lowest ΔMW. Since it may be difficult to reduce the ΔMW for the last mud, the key to reducing sag-related problems lies with flow rate, rotation and drilling practices.
Barite Sag Guidelines WELL
PLANNING
&#; Well type. Directional wells of >30° inclination drilled with mud densities of >12 lb/gal (>1.44 SG) are likely candidates for sag problems. Due to the potentially narrow margin between pore pressure and fracture gradient, extended-reach and directional deepwater wells are particularly critical. The available flow rates for these wells may be limited due to pressure losses and tools. &#; Well environment. Temperature and pressure affect mud design. High temperatures cause mud thinning and increase sag tendencies. In HTHP wells, rheological measurements are important across the full range of temperature and pressure. &#; Angle and well profile. The most critical angles for sag are 60 to 75°. &#; Casing design. Avoid casing designs and situations that give rise to low annular velocities.
Barite Sag
20A.9
&#; Hole diameter. Sag problems have occurred in hole sizes larger than about 6 in. (152 mm) Annular clearance, eccentricity and drill pipe diameter are all key factors.
MUD
PROPERTIES AND TESTING
&#; Mud type. Sag can occur in all mud types that use weight material to achieve density. Sag may be noticeably less in water-base muds if reactive formations are being drilled. &#; Mud weight. Densities >12 lb/gal (>1.44 SG) are prone to sag in directional wells. &#; Rheology. Elevated low-shear rheology and gels help reduce sag. Claybase rheology modifiers may be more effective than fatty acid products in freshly built OBMs and SBMs. For some muds used in deepwater applications, rheology adjustments to counteract effects of low temperatures can exacerbate sag.
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CHAPTER
20A
Barite Sag
&#; Yield stress. The LSRYP is a good indicator for sag-related rheological properties. For most wells, LSRYP should be maintained above the 7 to 15 lb/100 ft2 (3 to 7 Pa) range. Larger hole sizes typically require higher LSRYP values. &#; Testing. Sag tests should be conducted in the laboratory during well planning and in the lab/field while drilling. HTHP wells may require HTHP testing under expected hole conditions. &#; Oil/water ratio. Oil/synthetic additions thin OBMs and SBMs, and increase sag potential. Rheology modifiers can compensate for viscosity loss; however, some rheology modifiers require a sufficient amount of water to be available. &#; Surfactant concentration. Wettingagent levels in non-aqueous fluids must be sufficient to prevent barite agglomeration. Overtreatment should be avoided to prevent undesirable reductions in viscosity. &#; Fluid-loss additives. Under certain circumstances, sag problems can be aggravated by viscosity reductions caused by fluid-loss control additives. This reinforces the need to assess specific mud formulations and interactions.
OPERATIONAL
PRACTICES
&#; Operations at flow rates. Barite sag is predominantly a dynamic settling problem in which beds are formed during periods of low circulation rates. Long periods at low flow rates exacerbate sag, even if other key variables are within proper limits. Beds should be removed prior to tripping out using high flow rates and rotary speeds. &#; Density variation. A definite sign that sag has occurred are wide variations in mud density while circulating bottoms-up after a trip. For serious sag &#; especially when coupled with a low fracture gradient at the casing Barite Sag
20A.10
shoe &#; it may be necessary to stop circulating, trip out and stage back in. The goal would be to prevent lost circulation when heavy mud from the bottom is above the shoe. &#; Bed disturbance. Because they are inert, particles in barite beds tend to be only loosely attracted. Barite beds are easily disturbed by operations such as logging and tripping. These perturbations may fluidize the beds and increase slump, slide or flow, even at angles to 75°. &#; Time between trips. Beds formed under dynamic conditions can slump during static periods. Beds formed at medium angles slump faster, but beds in the 60 to 75° range can be considerably thicker and give more problems. It may be necessary to stage in the hole if there are extended periods between trips. &#; Rotary vs. sliding. For a given set of conditions, sag is lowest when the pipe is rotating at >75 RPM and eccentric. Sag is worst when the drill pipe is stationary and eccentric. Pipe rotation can minimize bed formation and even help remove existing beds. Rotary wiper trips often are beneficial after extended periods of sliding. &#; Mud conditioning prior to cementing. Avoid overtreatment of the mud to reduce viscosity prior to running casing and/or cementing. Excessive dilution dramatically increases the likelihood of sag.
WELL
SITE MONITORING
&#; Mud weight. After trips, mud weight in and out should be measured (at least every 15 min) while circulating bottoms-up. In HTHP applications, mud-weight adjustment for temperature is necessary. Use of a pressurized balance helps obtain good data with gas-cut mud. &#; Sag indicators. The mud-weight differential while circulating bottomsup should be used to calculate and Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20A
Barite Sag
record sag tendencies (Sag Register). Well site monitoring tests such as the M-I SWACO Viscometer Sag Test can help with field data correlations to measure the impact of remedial treatments. &#; Standpipe pressure. Fluctuations in standpipe pressure may occur as slugs of light and heavy mud pass through the bit nozzles and other restrictive parts of the circulating system. Also, higher standpipe pressures may indicate if annular sag packoff is occurring.
Barite Sag
20A.11
&#; Torque and drag. High torque and overpull can indicate that barite beds are forming on the low side of the hole. &#; Mud losses and gains. Unexpected losses may occur as heavy mud in the annulus reaches near-vertical sections of the well and rapidly increases hydrostatic pressure. The opposite effect can occur with light mud, which could cause the well to flow.
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20B
Hole Cleaning
Introduction Hole cleaning is one of the basic functions of a drilling fluid.
Hole cleaning is one of the basic functions of a drilling fluid. Cuttings generated by the bit, plus any cavings and/or sloughings, must be carried by the mud to the surface. Failure to achieve effective hole cleaning can lead to serious problems, including stuck pipe, excessive torque and drag, annular packoff, lost circulation, excessive viscosity and gel strengths, high mud costs, poor casing and cement jobs, and slow drilling rates. This chapter presents hole-cleaning fundamentals, key parameters and practical field guidelines. Well profile and geometry
&#; Hole angle (inclination) and doglegs &#; Casing/hole and drill pipe diameters &#; Drillstring eccentricity &#; Specific gravity &#; Particle size and shape &#; Reactivity with mud &#; Mud properties &#; Annular velocity &#; Annular velocity profile &#; Flow regime &#; Mud weight &#; Viscosity, especially at low shear rates &#; Gel strengths &#; Inhibitiveness &#; Bit type &#; Penetration rate &#; Differential pressure &#; Pipe rotation
Cuttings and cuttings-bed characteristics
Flow characteristics
Mud properties ________________________ ________________________ ________________________
Drilling parameters
________________________ ________________________ ________________________
Cuttings transport is affected by several interrelated mud, cuttings and drilling parameters, as shown in Table 1. Hole angle, annular velocity and mud viscosity generally are considered to be the most important. The primary methods used to improve most hole-cleaning problems is to increase the flow rate (annular velocity), mud viscosity and pipe rotation, when in laminar flow. For many difficult hole-cleaning situations, particularly vertical sections, there is some critical, or &#;threshold,&#; viscosity required to obtain satisfactory hole cleaning.
Table 1: Parameters affecting hole cleaning.
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Hole Cleaning
20B.1
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
Figure 1a: Forces acting on a cutting FVISC
flo w
FGRAV
FBUOY
M ud
Figure 1b: Velocity components action on a cutting
AX IA L
VHELICAL V
Cuttings and particles that must be circulated from the well have three forces acting on them as shown in Figure 1a: (1) a downward force due to gravity, (2) an upward force due to buoyancy from the fluid and (3) a force parallel to the direction of the mud flow due to viscous drag caused by the mud flowing around the particle. These forces cause the cuttings to be carried in the mud stream in a complex flow path which is often helical. A simplified illustration of the velocity components acting on a particle is shown in Figure 1b: (1) a downward slip velocity due to gravitation forces, (2) a radial or helical velocity due to rotation and velocity profile, and (3) an axial velocity parallel to the mud flow. Hole cleaning in vertical wells is perhaps the best understood process and the simplest to optimize. High-angle and extended-reach wells typically present the greatest hole-cleaning challenges. However, other simpler well types can be equally as troublesome under certain circumstances. Successful hole-cleaning practices in one situation do not always apply to another.
Cutting
flo w
Cuttings and particles that must be circulated from the well have three forces acting on them&#;
Hole Cleaning
VSLIP
M ud
20B
Figure 1: Forces and velocity components acting on a cutting.
Particle-Settling Mechanisms The hole-cleaning process must counteract gravitational forces acting on cuttings to minimize settling during both dynamic and static periods. Three basic settling mechanisms can apply: (1) free, (2) hindered and (3) Boycott settling. The first two relate to vertical wells, while all three can exist in directional wells. Basic settling patterns are illustrated in Figure 2, using the M-I SWACO Zag Tube, a demonstration device composed of three clear tubes connected by 135° elbows. The fluid in the Zag Tube is slightly viscosified freshwater; the simulated cuttings are aluminum flakes (glitter). Hole Cleaning
20B.2
Modified hindered settling
Boycott settling
Hindered settling
Boycott settling
Boycott settling
Boycott settling
Figure 2: Hindered and Boycott settling using Zag Tube. Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20B
Free settling occurs when a single particle falls through a fluid without interference&#;
Hindered settling is a more realistic settling mode for near-vertical and nearhorizontal intervals&#;
Hole Cleaning
Free settling occurs when a single particle falls through a fluid without interference from other particles or container walls, similar to what might occur in the center of a large water pit. The so-called &#;terminal settling velocity&#; depends on the density difference between fluid and particle, fluid rheology, particle size and shape, and the flow regime around the particle. In turbulent flow, settling velocity is independent of rheology. In laminar flow around the particle, Stokes&#; law applies for free settling, and was developed for spherical particles, Newtonian fluids and a quiescent fluid. Stokes&#; law is: gC DS2 (ρS - ρL) VS = 46.3µ Where: VS = Slip or settling velocity (ft/sec) gC = Gravitational constant (ft/sec2) DS = Diameter of the solid (ft) ρS = Density of solid (lb/ft3) ρL = Density of liquid (lb/ft3) µ = Viscosity of liquid (cP) This equation is a mathematical expression of events commonly observed; i.e., the larger the difference between the density of the cutting and the density of the liquid (ρS &#; ρL), the faster the solid will settle. The larger the particle is (DS2), the faster it settles and the lower the liquid&#;s viscosity (1/µ), the faster the settling rate. Understanding free settling is important because it forms the basis for the relationships which apply to verticalwell hole cleaning. Generally, Stokes&#; law is modified to incorporate equivalent viscosity for circulating nonNewtonian fluids and non-spherical cuttings. The terminal settling velocity under free settling is called the slip velocity.
Hole Cleaning
20B.3
Hindered settling is a more realistic settling mode for near-vertical and near-horizontal intervals, particularly in small-diameter holes and where high cuttings concentrations are present with high Rate of Penetration (ROP). Hindered settling occurs when fluid displaced by falling particles creates upward forces on adjacent particles, thereby slowing down their slip rate. The net result is still an overall downward movement, but the settling rate is always less (hindered) than for single, individual particles, hence the name. Interference from the hole walls and drill pipe also slows down the settling rate of nearby particles. Hindered settling is most important in vertical wells. Coupled with the long settling distance, it helps explain why hole-cleaning is less problematic in vertical wells. Boycott settling, an accelerated settling pattern which can occur in inclined wellbores, is named after the physician who first reported that particles in inclined test tubes settle 3 to 5 times faster than in vertical ones. Boycott settling is the consequence of rapid settling adjacent to the high (top) and low (bottom) sides of inclined wellbores. This causes a pressure imbalance which drives the lighter, upper fluid upwards and any cuttings beds on the low side downwards. Angles from 40 to 60° are particularly troublesome. At relatively low flow rates, mud flows mainly along the high side and accelerates or enhances the Boycott effect. High flow rates and pipe rotation can disrupt the pattern and improve hole cleaning.
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CHAPTER
20B
Hole Cleaning
Key Parameters Affecting Hole Cleaning
________________________ ________________________ ________________________ ________________________
Range Near-vertical I Low II Intermediate III High IV
Angle (degrees) 0 - 10 10 - 30 30 - 60 60 - 90
The limits of each range should be considered only as guidelines, since all are affected by bed stability, borehole roughness, cuttings characteristics and drilling fluid properties, among others. Figure 3 illustrates relative hole-cleaning difficulty based on angle. In vertical and near-vertical wells, cuttings beds do not form, but failure to properly transport and suspend cuttings can cause fill on bottom or bridging in doglegs. In directional wells, the build section in the intermediate range typically is the most difficult to clean, because cuttings beds can slide or &#;slump&#; opposite the direction of flow. Boycott settling
can exacerbate the problem. Sliding tendencies start dissipating at angles greater than about 60°, due to the corresponding decrease in the gravitational force vector.
I
II
III
IV
Difficulty
Four holecleaning ranges based on hole angle have been identified&#;
The effects of different hole-cleaning parameters have been identified in laboratory flow-loop tests. The following comments represent the integration of M-I SWACO experimental results with broad-based, related field observations and measurements. Well profile and geometry. Four hole-cleaning ranges based on hole angle have been identified:
0
30 60 Inclination (degrees)
90
Figure 3: Hole cleaning difficulty vs. inclination.
All four ranges may co-exist in the same directional well. For most cases, fluid properties and drilling practices should strive to minimize problems in the most critical interval. Hole-cleaning factors considered optimum for one interval may be inadequate in another. For example, requirements differ for large-diameter casing (which severely limits annular velocity), the build interval (which promotes cuttings-bed formation and sliding) and the production formation drilled horizontally (which may be shear sensitive and tend to wash out).
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Cuttings and Cuttings-Bed Characteristics Specific gravity, particle size and shape, and reactivity with the drilling fluid are some of the important drill-cutting and cuttings-bed characteristics. Their key consequences are listed here according to angle range: &#; Near-vertical and low ranges: cuttings concentration (little to no bed).
&#; Intermediate range: cuttings concentration, bed thickness and propensity for slumping. &#; High range: bed thickness and physical characteristics. Specific gravity depends on the formations drilled and ranges from about 2.0 to 2.8, somewhat denser than most
________________________
Hole Cleaning
20B.4
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20B
If not properly supported, cuttings can accumulate&#;
Hole Cleaning
muds. Bit type, penetration rate and bottom-hole differential pressure determine initial size and shape. Larger cuttings are generated by long-tooth bits, high penetration rates and lower differential (or underbalanced) pressures. The largest particles are cavings or sloughings created by overpressured shales and unstable wellbores. Cuttings can be physically altered by reaction with the mud (dispersion), reaction with themselves (aggregation) and mechanical degradation (big cuttings ground down into smaller ones). Cavings, sloughings and other large particles not easily transported out of the well may re-circulate in the annulus until ground by the rotating drillstring into smaller, more easily transported sizes. If not properly supported, cuttings can accumulate at the bottom of the well (fill), in large-diameter casing strings, in doglegs (bridges), on the low side of inclined intervals (beds), as mud rings in washout zones, and just above the collars or Bottom-Hole Assembly (BHA) (plugs and packoffs). &#;Plugs&#; and stuck pipe can be caused by dragging collars and elements up through pre-existing
beds. Figure 4 shows a cuttings bed formed in a highly inclined annulus. Cuttings accumulations can be difficult to erode or re-suspend, so mud properties and drilling practices which minimize their formation should be emphasized. Clearly, cuttings which remain in the flow stream do not become part of a bed or accumulation. Mud suspension properties are important, especially at low flow rates and under static conditions. During circulation, viscous drag forces acting on cuttings in beds or in washouts often prevent sliding, even at angles less than about 50 to 60°. At pump shut-off, however, the cuttings accumulations can &#;avalanche,&#; subsequently packing off the annulus. Cuttings beds, such as those formed in directional wells, can take on a wide range of characteristics that impact hole-cleaning performance. For example, clean sand drilled with a clear brine will form unconsolidated beds which tend to roll rather than slide downwards, and are conducive to hydraulic and mechanical erosion. On the other hand, reactive shales drilled with a water-base mud
Mud flow
Circulating cuttings Cuttings bed
Mud flow Circulating cuttings
Drill pipe
Cuttings bed
Figure 4: Cuttings bed in highly inclined well.
Hole Cleaning
20B.5
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
20B
Increasing annular velocity will always improve hole cleaning&#;
Hole Cleaning
can form thick filter-cake-like beds which are very difficult to remove without aggressive hydrodynamic and mechanical action. Flow characteristics. Cuttings transport efficiency is largely a function of annular velocity and the annular velocity profile. Increasing annular velocity will always improve hole cleaning, though it still must work in concert with other well parameters to ensure good hole cleaning. In a fully concentric annulus, flow is evenly distributed around the drillstring as illustrated in Figure 5a. Thus, there is an equal distribution of fluid energy for cuttings transport, regardless of fluid rheology. This profile is generally assumed for vertical intervals. However, the drillstring tends to lay on the low side of the hole in inclined sections, shifting or &#;skewing&#; the velocity profile (as shown in Figure 5b), the result of which is not conducive to cuttings transport. Cuttings accumulate on the bottom of the hole adjacent to the drill pipe where the mud flow is minimal. In this situation, pipe rotation is critical to achieve effective hole cleaning. Figure 5b clearly shows that,
Figure 5a: Concentric drill pipe and Newtonian fluid.
Figure 5b: Eccentric drill pipe and non-Newtonian fluid. Figure 5: Effect of eccentricity and rheology on flow profile.
without pipe rotation, non-Newtonian behavior in laminar flow can exacerbate the skewed profile. As illustrated in Figure 6, pipe rotation in fluids with elevated Low-ShearRate Viscosity (LSRV), such as FLOPRO
1. Rotation moves cuttings from underneath pipe. 2. To the top of the cuttings bed. 3. Up into the mud flow stream. 4 and 5. Transporting the cuttings along the well path.
5 4 3
low df Mu
2 1
Cuttings bed
e Pip ation rot
Figure 6: Rotation lifts cuttings into the flow stream. Hole Cleaning
20B.6
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20B
Turbulent flow is considered by some to be a prerequisite for good hole cleaning&#;
Hole Cleaning
and DRILPLEX* systems, can dramatically improve hole cleaning. This rotation lifts cuttings from the low side of the hole back into the flow stream and induces a helical flow pattern which can be very effective for hole cleaning, even at low annular velocities. Conditions for which the velocity profile is relatively insensitive to pipe rotation include (1) turbulent flow, (2) concentric pipe and (3) low-viscosity fluids, especially clear brines. Furthermore, rotation may not be possible, as in coiled-tubing drilling and slide directional drilling to build angle. Turbulent flow is considered by some to be a prerequisite for good hole cleaning in some applications, such as
small-diameter holes in highly competent formations. Turbulent eddies and high velocities are consistent with good hole cleaning, except when drilling easily eroded formations. Any washouts created by turbulence reduce annular velocity and systematically degrade performance. Unfortunately, turbulence is difficult to achieve and maintain in larger-diameter holes and when using viscosified fluids where suspension is required. There are many conditions for which full turbulence in an eccentric annulus is not practical to achieve. The open regions above eccentric pipe achieve turbulence at much lower flow rates than those on the low side which contains cuttings beds.
Mud Properties
Mud weight helps buoy cuttings and slow their settling rate&#;
Generally speaking, different drilling fluid types provide similar cuttings transport if their downhole properties also are similar. However, selection of optimum properties requires careful consideration of all related parameters. Clearly, mud properties must be maintained within certain limits to be effective without being destructive or counter-productive. Properties of particular interest to hole cleaning include mud weight, viscosity, gel strengths and level of inhibition. Mud weight helps buoy cuttings and slow their settling rate (as shown by Stokes&#; law), but it is really not used to improve hole cleaning. Instead, mud weights should be adjusted based only on pore pressure, fracture gradient and wellbore-stability requirements. Vertical wells drilled with heavy muds normally have adequate hole cleaning as compared to highly deviated directional wells drilled with low-density fluids. Wellbore instability is a special case where mud weight clearly targets the Hole Cleaning
20B.7
cause, rather than the symptoms, of hole-cleaning problems. As a rule, formations drilled directionally require higher mud weights to prevent borehole failure and sloughing into the annulus. What can appear as a holecleaning problem at the surface, in fact, can be a stress-related problem which should be corrected by increasing the mud weight. Alternative actions to improve cuttings transport may help but will not eliminate the basic problem. Mud viscosity helps determine carrying capacity. For vertical wells, yield point historically has been used as the key parameter which was thought to affect hole cleaning. More recently, evidence concludes that Fann 6- and 3-RPM values are better indicators of carrying capacity (even in vertical wells). These values are more representative of the LSRV which affects hole cleaning in marginal situations. Coincidentally, most viscosifiers (clays, for example) added to increase yield point also increase 6- and 3-RPM values. One Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
20B
Gel strengths provide suspension under both static and low-shear-rate conditions.
Hole Cleaning
common rule of thumb is to maintain the 3-RPM value so that it is greater than the hole size (expressed in inches) in high-angle wells. The Low-Shear Yield Point (LSRYP), calculated from 6- and 3-RPM values, has also gained broad acceptance for quantifying LSRV: LSRYP = (2 x θ3rpm) - θ6rpm LSRYP can play an even more important hole-cleaning role in directional wells, if it is applied in accordance with the specific well conditions. For example, in laminar flow, there is a clear correlation between improved hole-cleaning performance and elevated LSRYP, especially in conjunction with the rotation of eccentric pipe. On the other hand, low LSRYP values are preferred for turbulent-flow hole cleaning, because turbulence could be achieved at lower flow rates. Despite its inherent advantage as a general-purpose hole-cleaning indicator, LSRYP is not recommended for the FLOPRO system and other polymer systems which exhibit visco-elastic properties. FLOPRO viscosity at very low shear rates can be considerably higher than that of fluids with similar 6-RPM, 3-RPM and LSRYP values. This unique
rheological behavior is the signature characteristic of FLOPRO fluids and one of the keys to their success as premier horizontal reservoir drill-in fluids. Elevated LSRVs make it possible to achieve superb hole cleaning at much lower flow rates than conventional systems. LSRYP is an extrapolated value just like its yield-point counterpart in the Bingham Plastic Model. As such, LSRV for FLOPRO systems should be measured using a Brookfield viscometer running at 0. sec&#;1 (0.3 RPM with a #2 spindle). Although not a direct measurement of viscoelasticity, Brookfield viscosity correlates well with hole-cleaning performance of FLOPRO in the field. Gel strengths provide suspension under both static and low-shear-rate conditions. Although closely related to viscosity, gel strengths sometimes are overlooked with regard to their effects on hole cleaning. Quickly developing gels which are easily broken, as is the case for FLOPRO systems, can be of significant help. Excessively high and/or progressive gels, on the other hand, should be avoided because they can cause or exacerbate a number of serious drilling problems.
Basic Models Except for Stokes&#; law, settling and hole-cleaning mechanisms are quite complex and difficult to model, even if some key parameters are assumed or disregarded. In fact, analytical solutions for annular Boycott settling may not be possible using conventional numerical techniques. It is for this reason that the models provided in this section focus on vertical wells.
Hole Cleaning
20B.8
There are several good correlations for slip velocity. M-I SWACO computer programs use the method developed by Walker and Mayes. The equations which follow are based on their work. They apply in vertical sections, but have reduced application in inclined intervals. Cuttings are considered to be disks falling edgewise through the mud. The resisting shear stress on the
Revision No: A-3 / Revision Date: 02·01·09
CHAPTER
20B
CTR is a useful method for normalizing the rise velocity.
Hole Cleaning
cutting Fp depends on the particle thickness and the density difference between cuttings and mud: Fp (lb/100 ft2) = 7.4 x [hC x ((8.34 x Gp) &#; W)]0.5 Where: hC = Particle thickness (in.) Gp = Particle specific gravity W = Mud weight (lb/gal) Units for Fp are chosen to allow direct comparison to the mud rheogram plotted from viscometer data. If the entire rheogram curve lies above a shear stress equal to Fp, then cuttings are fully suspended and will not settle. If Fp crosses the rheogram curve, the intersection point is the equivalent particle shear rate Rp (RPM). The slip velocity then depends on whether flow around the particle is laminar or turbulent. The transition shear rate Rc is: 109 Rc (RPM) = dc x W0.5 Where: dc = Cutting diameter (in.) Slip velocity, VSLIP is then calculated by: dc x Rp 0.5 VSLIP = 1.7 x Fp x W0.5 for laminar (Rp < Rc) or Fp VSLIP (ft/min) = 17.72 x W0.5 for turbulent (Rp > Rc)
[
&#;the difference between the annular velocity and the slip velocity is known as the transport or &#;rise&#; velocity
]
Cuttings concentration (Cconc) is perhaps the best indicator for cuttings transport in vertical intervals. Experience over the years has shown that drilling problems escalate when the CCRIT exceeds a threshold value (about 5%). Cconc is calculated by: Cconc (% volume) = 1.667 x ROP x Db2 2 (Dh &#; Dp2) x (VANN &#; VSLIP) and the critical annular velocity (VANNCRIT) to maintain a specific Cconc is defined by: VANNCRIT (ft/min)= 1.667 x ROP x Db2 + VSLIP (Dh2 &#; Dp2) x Cconc
In a circulating fluid, the difference between the annular velocity (VANN) and the slip velocity is known as the transport or &#;rise&#; velocity (VRISE): VRISE = VANN &#; VSLIP This VRISE equation applies only to vertical intervals because it assumes VANN and VSLIP exist along the same axis. Perfect hole cleaning occurs as
Hole Cleaning
VRISE approaches VANN. Hole cleaning is poor for low values of VRISE and clearly deficient for negative values (VSLIP > VANN). Cuttings Transport Ratio (CTR) is a useful method for normalizing the rise velocity. This allows hole-cleaning performance in different intervals to be compared directly. CTR (% by volume) values range from 0% for &#;very poor&#; and 100% for &#;perfect&#; cleaning. Empirical results have suggested that CTR values greater than 50% may be suitable for most vertical wells. This corresponds to an annular velocity twice that of the slip velocity. (V &#; VSLIP) CTR (%) = 100 x ANN VANN
20B.9
Where: ROP = Penetration rate (ft/hr) Db = Bit diameter (in.) Dh = Hole/casing diameter (in.) Dp = Pipe OD (in.) VANN = Annular velocity (ft/min) VSLIP = Slip velocity (ft/min) NOTE: Pipe eccentricity and rotation have minimal effects in vertical intervals and are not considered.
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
20B
Hole Cleaning
Relationships for directional intervals are not straightforward. Some models are available, but most are incomplete. The danger is that exclusion of factors, such as gel strength, pipe rotation, eccentricity, low-shear viscosity, interaction among different intervals and others, can lead to wrong conclusions. Fuzzy logic technology (the basis for artificial intelligence) is emerging as the
best approach to evaluate hole-cleaning performance at all angles and is the method of choice for M-I SWACO software. Fuzzy logic works well with missing and incomplete data, both common to hole-cleaning analysis. Performance is described using words (poor, fair, good and very good) rather than numbers.
Hole-Cleaning Criteria Clearly, ratios below 1.0 indicate that a holecleaning problem exists.
Opinions vary on what constitutes &#;good&#; hole cleaning. From a practical perspective, hole cleaning is adequate if no operational problems are encountered. This implies that hole-cleaning requirements vary among different wells and even different intervals in the same well. Poor cleaning would naturally be assumed if cuttings were not observed on shaker screens. Drilling reactive shales using a highly dispersive waterbase mud will limit cuttings observed at the shaker. Other physical indicators of poor cleaning include hole fill in vertical wells, cuttings beds in directional wells, mud rings, bridges and packoffs. Unfortunately, high cuttings volumes on the screens do not automatically signal excellent cuttings transport. Comparison between the volume of cuttings generated by the bit to the volume of hole drilled is one of the field techniques available to measure hole-cleaning efficiency. Zero-discharge and no-cuttings-discharge operations are examples where cuttings volumes are monitored because they must be boxed and transported for disposal. Typically, the ratio of surface to downhole cuttings volume varies from about 1.5:2.2, but the ratio should only be used as a trend to highlight potential
Hole Cleaning
20B.10
problems. Clearly, ratios below 1.0 indicate that a hole-cleaning problem exists. A drawback to this technique is its inability to identify large cuttings which remain downhole until they grind down into particles that are small enough to be carried to the surface. There are several techniques for predicting downhole cleaning performance when direct measurements are not possible. In vertical sections, minimum annular velocity, slip velocity, rise velocity, cuttings transport ratio and cuttings concentration are the most common. In directional wells, cuttings-bed thickness also is a good, although not definitive, indicator. Unlike hole fill in vertical wells, cuttings-bed thickness cannot be measured. At one time, minimum annular velocity was the traditional criterion for &#;good&#; hole cleaning. Velocities from 100 to 120 ft/hr (30.5 to 36.6 m/hr) were considered adequate, although dependence on hole size was evident. For very large holes (>171&#;2 in.) where 100-ft/min (30.5-m/min) velocity was not achievable, mud yield point was increased significantly to provide adequate hole cleaning. A flocculated gel fluid is a common system used for this purpose.
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CHAPTER
20B
Hole Cleaning
Minimum Transport Velocity (MTV) is a recent technique applicable to directional wells. This concept presumes that a hole interval can be efficiently cleaned if all cuttings are either suspended in the flow stream or in beds moving upwards in the direction of
flow. The annular velocity should meet or exceed a calculated MTV value for both conditions. It would appear that MTV values are conservative, but the concept has been refined by field data and has been used successfully.
Hole-Cleaning Guidelines
________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
When establishing hole-cleaning guidelines, it is important to review relationships among the parameters in Table 1 and to recognize that some can be both independent and dependent variables. Often, one parameter, such as formation type, will determine how to approach hole cleaning. For example, a typical horizontal well drilled through a very competent Austin Chalk formation might use a brine reservoir drill-in fluid. It follows that these parameters would be appropriate &#; turbulent flow, high annular velocity, low fluid viscosity and gels, with minimal effects from pipe eccentricity and rotation. On the other hand, an unconsolidated-sandstone, horizontal interval would dictate tight filtration control and laminar flow. Elevated low-shear rheology and flat gels would be suitable, especially if the eccentric pipe can be rotated. Listed below are practical hole-cleaning guidelines aimed at field use. They are grouped according to general (all wells), vertical/near-vertical wells and directional wells (including horizontal).
GENERAL 1. Use the highest possible annular velocity to maintain good hole cleaning, regardless of the flow regime. Annular velocity provides the upward impact force necessary for good cuttings transport, even in directional and horizontal wells. 2. Rely on mud rheology and gel strengths for suspension and transport capabilities. Hole Cleaning
20B.11
3. Control drill to manage difficult hole cleaning situations only as a last resort. Penetration rate determines the annular cuttings load. The negative implications of limiting drill rate are self-evident. 4. Take advantage of top drives, if available on the rig, to rotate and circulate (backream) when tripping out. 5. Continually monitor parameters affecting hole-cleaning, and react accordingly. Always consider the consequences of changes on other operations. 6. Measure mud rheology under downhole conditions, especially in deepwater and High-Temperature, High-Pressure (HTHP) applications. 7. For deepwater wells with a largediameter riser, add a riser pump to increase riser annular velocity. 8. Avoid using highly dispersive muds that might help cleaning, but can create a mud solids problem.
VERTICAL
AND NEAR-VERTICAL WELLS
1. Keep cuttings concentration less than 5% (by volume) in order to minimize drilling problems. 2. For efficiency and cost considerations, use a mud viscosity selected based on hole size and slip velocity calculations. Further increase yield point and LSRYP only when holecleaning problems have been encountered or are imminent.
Revision No: A-3 / Revision Date: 02·01·09
CHAPTER
20B
Hole Cleaning
3. Maintain LSRYP between 0.4 and 0.8 times the hole diameter in inches unless hole conditions dictate otherwise. Yield point and LSRYP for highly dispersed muds typically are low, so higher annular velocities may be required. 4. Use periodic high-density/highviscosity sweeps to correct cleaning problems. Do not run sweeps unless hole conditions warrant. Sweeps should be >0.5 lb/gal (>0.1 kg/L) heavier than the mud and should be combined with vigorous fluid and mechanical agitation, if possible. 5. Monitor the hole for symptoms of cuttings accumulation, fill and bridges. 6. Do not expect pipe rotation to help hole cleaning, especially in larger-diameter holes.
DIRECTIONAL
WELLS
11. Use hole-cleaning techniques to minimize cuttings-bed formation and subsequent slumping which can occur in 30 to 60° hole sections. 12. Utilize elevated-viscosity fluids from the start, because cuttings beds are easy to deposit, but difficult to remove. 13. Maintain LSRYP between 1.0 and 1.2 times the hole diameter in inches when in laminar flow. 14. Treat mud to obtain elevated, flat gels for suspension during static and low-flow-rates periods.
Hole Cleaning
20B.12
15. For optimum performance from FLOPRO fluids, maintain Brookfield viscosity above 40,000 cP. 16. Schedule periodic wiper trips and pipe rotation intervals for situations where sliding operations are extensive and bed formation is expected. 17. When using FLOPRO systems for coiled-tubing drilling, periodically run wiper trips to remove cuttings beds. For re-entry wells with large casing, select the best compromise to clean both the horizontal and casing intervals. 18. Rotate pipe at speeds above about 50 RPM if possible to prevent bed formation and to help remove preexisting beds. Fully eccentric pipe combined with proper LSRYP values can provide best results. 19. Increase mud weight to correct wellbore stresses problems masquerading as hole-cleaning problems. 10. Recognize that turbulent flow across the annulus may be difficult to achieve and maintain. 11. Consider drilling small-diameter, competent, horizontal intervals using turbulent flow. Low-viscosity fluids enter a state of turbulence at lower flow rates than viscous ones. Any beds which form can be eroded by the high flow rates required for turbulent flow. 12. Expect little help from viscous sweeps, unless they are accompanied by high flow rates and pipe rotation and/or reciprocation.
Revision No: A-3 / Revision Date: 02·01·09
CHAPTER
20C
Displacements and Cementing
Introduction
A displacement occurs when one fluid replaces another in the wellbore.
&#; Reverse circulation. The new fluid is pumped down the annulus and the existing fluid is displaced up and out of the drillstring or tubing. This procedure is most commonly used when a lighter fluid is used to displace a heavier fluid (see Figure 2).
Down annulus
Up drill pipe
Fluid displacements are a common procedure in the drilling, completing and workover of wellbores. A displacement occurs when one fluid replaces another in the wellbore. This chapter will discuss two separate displacement categories. The first covers standard fluid displacements including waterbase muds, oil-base muds, syntheticbase fluids, completion fluids and workover fluids. The second category covers cementing displacements. There are a number of different displacement procedures used in wellbore operations. Listed below are some of the more common procedures. &#; Conventional or standard displacement procedure. The new fluid is pumped down the drill pipe or tubing to displace the existing fluid up and out of the annulus. This is the normal method of wellbore circulation (see Figure 1).
&#; Bullhead or squeeze displacement. The new fluid is pumped down the wellbore and the existing fluid is displaced into the formation with no returns to the surface. This procedure can occur down tubing or between casing strings (see Figure 3).
Up annulus
Down drill pipe
Figure 2: Reverse circulation.
Figure 1: Conventional displacement. Displacements and Cementing
20C.1
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
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Displacements and Cementing
Up casing annulus
Down drill pipe
Down wellbore or casing Out into formation
Figure 3: Bullhead displacement.
Figure 4: Annular casing displacement.
&#; Annular casing displacement. The new fluid is pumped down the drill pipe or tubing and through a port or
collar in the casing string to displace the existing fluid in the casing annulus (see Figure 4).
Factors Affecting Displacements If a lowerdensity fluid is displacing a higherdensity fluid, it is advantageous to reverse circulate.
Other displacement procedures are used in cementing, gravel packing and fracturing operations. There are a number of factors that are critical in designing a successful displacement procedure. These factors include the following: &#; Fluid density. &#; Fluid viscosity. &#; Sweeps and spacers. &#; Fluid condition. &#; Rotation and reciprocation. &#; Rig equipment. &#; Pumping operations. &#; Wellbore deviation. The impact of these factors must be considered in order to optimize Displacements and Cementing
20C.2
displacement procedures. Each of these factors will be discussed in some detail. Fluid density. In a standard or conventional displacement procedure, it is desirable to have the displacing fluid heavier than the fluid being displaced. When the heavier fluid reaches the bottom of the well, the heavier fluid will tend to sink while the lighter existing fluid will tend to float or be suspended, thereby aiding in maintaining separation. If a lower-density fluid is displacing a higher-density fluid, it is advantageous to reverse circulate. In this procedure the lighter fluid should be pumped down the annulus, displacing the heavier fluid up and out of the drill Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
20C
When isolation spacers are utilized to separate two incompatible fluids, they should be more viscous than either fluid&#;
It is very important to have a drilling fluid in good condition prior to displacement.
Displacements and Cementing
pipe or tubing. Commingling of these fluids may occur in the tubing, but this procedure will minimize the interface when a lighter fluid is displacing a heavier fluid. Wellbore pressures and pressure-drop values should be calculated prior to utilizing the reverse circulation procedure. Improper use of this procedure may cause wellbore damage and/or lost circulation. It is possible to have effective displacement procedures between fluids with different densities, even when the optimum displacement technique cannot be used. This is accomplished by utilizing the proper spacers, sweeps and flow rates. NOTE: When displacing fluids with different densities, it is imperative that there is a complete understanding of the downhole pressures throughout the displacement process. Inadequate pressure analysis has caused wellbore-control situations including blowouts and lost circulation. Fluid viscosity. Fluid viscosity is important in displacement procedures. The most desirable situation is to displace a thin existing fluid with a viscous fluid. When isolation spacers are utilized to separate two incompatible fluids, they should be more viscous than either fluid, to keep the two incompatible fluids from commingling. In general, the viscosity of the displacing fluid should be higher than the fluid to be displaced. Sweeps and spacers. Sweeps and spacers serve several different functions in the displacement process. They are used to separate the displaced from the displacing fluid; they are used to clean the wellbore of mud cake; and they are used to change the wettability of the wellbore. Sweeps and spacers can be adjusted to any desired fluid density and fluid viscosity, and they can include surfactants and detergents. Sweeps and spacers must be of sufficient volume so they prevent commingling of the displaced and displacing fluids. They must be of sufficient length to allow enough Displacements and Cementing
20C.3
contact time to clean or change the wettability of the wellbore. Spacers and sweeps can be made from freshwater, brine, oil, synthetic fluid and specialty chemicals. Additional information about spacers can be found in the discussion concerning actual displacement procedures. The most basic function for all spacer design is to thin the mud in the hole so that it will be removed from the well and to viscosify the mud being placed in the well so that the leading edge of this displacing mud is as viscous as possible. Having the leading edge of the displacing mud as viscous as possible results in plug flow with a flat velocity profile and minimizes the contamination and commingling of the two fluids. Using this concept, if only one spacer is to be used, it is preferred to use water to displace a waterbase mud with an oil-base mud or oil to displace an oil-base mud with a water-base mud. It is frequently beneficial to use some kind of marker to more clearly identify when the leading edge of the displacing mud reaches the shaker. Many times the returning mud is being dumped at the shaker and it is difficult to see the transition from one mud to another. Often a fine to medium lost-circulation material (such as NUT PLUG*) can be mixed into one of the spacers or into the first portion of the displacing mud as a marker. Fluid condition. It is very important to have a drilling fluid in good condition prior to displacement. A drilling fluid with high solids, high viscosity and high gel strengths will be difficult to remove from the wellbore. When displacing a drilling fluid to a completion brine, it is absolutely essential that the drilling fluid be in good condition for displacement purposes to minimize formation damage and solids contamination of the solids-free completion brine.
Revision No: A-2 / Revision Date: 12·31·06
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20C
Always displace at the highest flow rate possible.
Settling can be controlled by maintaining an elevated Low-ShearRate Viscosity.
Displacements and Cementing
Rotation and reciprocation. The drill pipe or tubing will be in close proximity with the wall of the hole or casing in various parts of the wellbore. When the pipe is not centered, fluids tend to channel up through the larger side of the hole, leaving old fluid behind the drill pipe on the narrow side of the hole. The best way to eliminate this problem is to rotate and reciprocate the pipe during displacement. Rotating and reciprocating forces the mud from poorly circulated areas into the flow stream, allowing for a more uniform displacement. Rotation also increases the degree of turbulence of the fluid. If the pipe remains static, some fluid may be bypassed causing potential contamination. If the pipe cannot be rotated, reciprocation is still beneficial. If displacements are taking place with a coiled tubing unit, special pulling procedures can be utilized to achieve effective displacements. Rig equipment. In most displacement situations, all rig surface equipment must be thoroughly cleaned prior to displacement. This includes pits, lines, pumps, solids-control equipment, well-control equipment and hoppers. In some displacement scenarios, additional pumping and filtration equipment may be required to maintain fluid cleanliness. Pumping operations. Displacement should be at a pump rate high enough to provide turbulent flow. The velocity profile in this case is flat, with a small
Displacements and Cementing
20C.4
boundary layer minimizing the commingling of fluids. If turbulence cannot be achieved, better fluid removal is found when maximum flow energy is used, even if the fluid is in laminar flow. Always displace at the highest flow rate possible. Once displacement has begun, do not stop pumping operations. If operations are stopped, commingling of fluids will occur. Prior to beginning displacement, all pressures, volumetric and pump-stroke calculations should be made. Prior to commencement of displacement, a rig meeting should be called so that all personnel know their responsibilities. Wellbore deviation. Many of the factors which influence vertical wellbore displacement become even more critical in deviated wellbores. Results of investigations into deviated wellbore mud displacements indicate that Boycott settling of solids can result in a &#;bed&#; or mud and solids channel on the low side of the annulus which is virtually impossible to displace. This type of settling can occur at any time when circulating a high-angle well. Settling can be controlled by maintaining an elevated Low-Shear-Rate Viscosity (LSRV). This value is dependent on wellbore deviation, hole size, fluid type, availability of pipe rotation and solids loading. Effective displacements can still be achieved with the use of high pump rates, adequately sized and properly designed spacers and effective pipe rotation/reciprocation.
Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
20C
Displacements and Cementing
Types of Fluid Displacements There are many different types of fluid displacements that occur during wellbore operations. Listed below are several of the more common types of fluid displacements. &#; Water-base mud to water-base mud. &#; Water-base mud to oil-base mud. &#; Oil-base mud to water-base mud. &#; Water-base mud to completion brine. &#; Oil-base mud to completion brine. Each of these displacement types will be discussed, and an example of a displacement procedure will be presented. Water-base mud to water-base mud. The displacement of one water-base mud to another is a relatively common occurrence in the drilling process. These displacements can occur for a variety of reasons, such as when changing mud systems at casing points or even during an open-hole section. They include but are not limited to: &#; Displacements to reservoir drill-in fluids. &#; Displacements to brine-base muds. &#; Displacements for environmental reasons. &#; Displacements because of geological reasons. &#; Displacements to improve drilling performance.
Cased-hole displacements offer several significant advantages over openhole&#;
Cased-hole displacements offer several significant advantages over open-hole displacements. These include known wellbore volumes, improved well control, no problems with wellbore stability and reduced possibility of cross-contamination of displacement fluids. Either conventional displacement procedures or reverse-circulation displacement procedures can be used when the displacement occurs inside casing. There are normally four different situations where displacements can occur during casing-point operations. The first occurs during casing cementing operations, when the new fluid is Displacements and Cementing
20C.5
used to displace the cement from inside the casing and &#;bump&#; the plug. The second situation takes place just prior to drilling the cement, the float collar and the casing shoe. The third occurrence in which displacement can occur is after drilling the cement and float collar, but prior to drilling the casing shoe. The fourth is after the cement, float collar and casing shoe have been drilled. Displacement occurs just before or just after the formation-integrity test. Open-hole displacements are more difficult than casing-point displacements because of potential hole washouts and the inability to make precise volume calculations. Open-hole displacements with incompatible fluids can cause significant wellbore instability situations. In planning open-hole displacements it is essential to maintain adequate downhole hydrostatic pressure to maintain wellbore control. Open-hole displacements in producing formations must take into consideration the potential for formation damage. Successful open-hole displacements can take place with proper prior planning, proper spacer design and good well site execution. Displacements from freshwater- to brine-base muds can potentially cause significant problems. These fluids need to be displaced with adequate spacers because detrimental flocculation can occur if the fluids commingle. Following is an example of a waterbase mud to water-base mud conventional displacement (intermediate mud to &#;bland&#; coring fluid): &#; Hold predisplacement meeting. &#; Drill out casing shoe and perform formation integrity test. &#; Condition existing water-base mud to reduce viscosity and gels. &#; Wash and drain mud pits and flush all lines with water. &#; Pump 50 bbl of water with solvent. Revision No: A-1 / Revision Date: 02·28·01
CHAPTER
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________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________ ________________________
Displacements and Cementing
&#; Pump 50 bbl of viscosified water with 3 lb/bbl of a viscosifier such as FLO-VIS. &#; Pump displacing fluid at as high a pump rate as practical. &#; Rotate and reciprocate pipe. &#; Monitor pump strokes. &#; Divert &#;old&#; mud for disposal. &#; Switch to closed-loop circulation when new fluid returns and circulates over shakers. Water-base mud to oil-base mud. In many drilling programs, the surface and intermediate casing sections are drilled with water-base muds. The deeper intervals in the well are drilled with oil- or synthetic-base muds. In general, the primary requirements in this displacement situation are to minimize rig time, minimize contamination of the oil- or synthetic-base mud. This is generally accomplished with either one water-base spacer or a water-base followed by a viscous oil-base spacer. Following is an example of waterbase mud to oil-base mud conventional displacement: &#; Hold predisplacement meeting. &#; Condition water-base mud to reduce viscosity and gels. &#; Wash and drain mud pits and lines with water. &#; Fill pits with oil-base muds. &#; Pump sufficient volume to obtain 200 to 500 linear annular feet of water spacer. &#; Pump sufficient volume to obtain 200 to 500 linear annular feet of viscosified oil spacer. &#; Pump oil mud. &#; Monitor pump strokes. &#; Pump at as high a rate as practical. &#; Rotate and reciprocate pipe. &#; Use large-mesh screens on shakers. &#; Divert water-base mud for disposal. &#; Switch to closed-loop circulation when oil-base fluid returns and circulate over shaker. Displacements and Cementing
20C.6
Oil-base mud to water-base mud. An oil-base or synthetic-base mud to a water-base mud displacement usually occurs just prior to the producing interval. This is a situation in which the oilbase or synthetic-base mud provides superior drilling performance in the upper sections of the wellbore above the producing interval, but could damage the producing formation or when a formation evaluation log requires water-base mud. Another situation that may require displacing an oil- or synthetic-base mud with a water-base mud occurs when lost circulation is encountered. The oil- or synthetic-base fluid may be displaced from the hole with a less expensive water-base mud. Successful spacer design is essential for these displacements to be effective. Following is an example of oil-base mud to water-base mud conventional displacement: &#; Hold predisplacement meeting. &#; Condition water-base mud to reduce viscosity and gels. &#; Wash and drain mud pits and lines. &#; Fill pits with water-base mud. &#; Pump sufficient volume to obtain >200 linear annular feet of oil spacer. &#; Pump 25 to 50 bbl of viscosified water space with 3 lb/bbl of a viscosifier such as FLO-VIS. &#; Pump water-base mud. &#; Monitor pump strokes. &#; Rotate and reciprocate pipe. &#; Divert oil mud returns to storage &#; Switch to closed-loop circulation when water-base mud returns and circulate over shaker. Water-base mud to completion brine. In this type of displacement, it is essential to remove all of the waterbase mud and any residual filter cake from the well prior to displacing with the completion brine. This can be accomplished with adequate spacers and surfactant washes. Any residual Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
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Displacements and Cementing
mud or mud filter cake can cause a reduction in potential production. Following is an example of the reverse displacement of 10-lb/gal (1.2-kg/L) water-base mud to 9-lb/gal (1.1-kg/L) completion brine: &#; Hold predisplacement meeting. &#; Rig up reverse circulate; pumping down annulus and taking returns through drill pipe. &#; Clean and drain pits, pumps and lines. &#; Pump 50 bbl viscosified spacer with surfactant. &#; Pump 50 bbl brine spacer with chemical wash (optional). &#; Pump 50 bbl viscosified completion brine. &#; Pump completion brine. &#; Monitor pump strokes. &#; Divert water-base mud to disposal. &#; Switch to closed-loop circulation when completion brine returns and circulate and filter completion fluid. Oil-base mud to completion brine. In this situation, it is important not only to remove the oil-base mud and filter cake but the wellbore needs to be made water-wet rather than oilwet. This type of displacement creates the potential for an emulsion to form which can negatively impact production potential. Adequate spacers and solvent washes must be utilized if this type of displacement is to be effective.
Displacements and Cementing
20C.7
Following is an example of 10.5-lb/gal (1.3-kg/L), oil-base mud to a 9.2-lb/gal (1.1-kg/L) completion brine conventional displacement: &#; Hold predisplacement meeting. &#; Pump 50 bbl of low viscosity oil-base mud. &#; Pump 50 bbl of viscosified brine spacer with surfactant. &#; Pump 10 bbl chemical wash. &#; Pump 50 bbl viscosified completion brine. &#; Pump completion brine. &#; Monitor pump strokes. &#; Divert oil-base mud to storage. &#; Switch to closed-loop circulation when completion brine returns and circulate and filter completion brine. The following is a checklist of items that should be considered when developing a displacement plan: &#; Fluid types, density and viscosity. &#; Potential formation damage. &#; Environmental. &#; Wellbore safety, pressure control. &#; Wellbore deviation, geometry. &#; Spacer size and composition. &#; Flow rates, pump efficiencies. &#; Volumetric calculations. &#; Ability to rotate and reciprocate. &#; Calculated pressure schedule and wellbore pressures.
Revision No: A-2 / Revision Date: 12·31·06
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Displacements and Cementing
Cementing Displacement Considerations Having a drilling fluid with properties optimized for displacement with cement is the single most important factor in obtaining total mud removal.
Pipe movement helps break up gelled pockets of mud and loosen cuttings that may accumulate within the pockets.
Extensive studies have shown the foremost factor affecting cement placement is the effective displacement of drilling fluids from the annulus. Cementing studies have determined that a high frequency of cement failures can be attributed to incomplete mud displacement from the annulus which results in mud channels in the cement. These mud channels effectively provide a conduit for the migration of fluids that cause lost production and/or corroded casing and do not allow the cement to form an effective annular pressure seal. Removal of mud and filter cake is imperative to obtaining a good cement job. The primary factors influencing mud removal are: &#; Drilling fluid properties. &#; Pipe movement. &#; Pipe centralization. &#; Flow rate. &#; Spacers or flushers. &#; Contact time. &#; Density differences. &#; Hole size and washout. Drilling fluid conditioning. Having a drilling fluid with properties optimized for displacement with cement is the single most important factor in obtaining total mud removal. Mud removal is influenced by the following factors: &#; Mud properties. Mud properties need to be adjusted to fluid type, hole angle and wellbore conditions. Mud properties should be adjusted after casing is run. Mud properties required for good cementing may not be the same as those required for successful pipe running. In many areas it is common practice to increase viscosity and gels prior to running casing to provide adequate suspension of any cuttings or cavings. Yet low viscosity fluids are most desirable for obtaining a good drilling fluid displacement and cement job. Displacements and Cementing
20C.8
&#; Fluid loss. Decreasing filtrate loss results in a thin filter cake. This increases the proportion of mud in the hole which is more easily removed than filter cake. Generally, an API fluid loss of 7 to 8 cm3/30 min is sufficient. High-Temperature, HighPressure (HTHP) fluid loss should be not more than twice the API fluid-loss value. &#; Gel strength. A non-thixotropic mud with low non-progressive gels is desirable for good mud removal. The key parameters governing the ability to remove the mud from the well are low yield point and 10-sec, 10-min and 30-min gel strengths. A well-conditioned mud should have relatively low viscosity, yield point and gel strengths. In addition, these properties allow turbulent flow to be achieved at lower flow rates. &#; Circulation. Circulate prior to cementing until well-conditioned mud is being returned to the surface. This may take two or more circulations. Pipe movement. Following closely behind mud conditioning in importance is the need to employ pipe movement, rotation and reciprocation, both before and during cementing. Pipe movement helps break up gelled pockets of mud and loosen cuttings that may accumulate within the pockets. Pipe movement can also help offset negative effects of poorly centralized pipe. Mechanical scratchers attached to the casing can further enhance the beneficial effects of pipe movement. Reciprocation appears to be the better method when the pipe is well centralized. Rotation appears to be best when the pipe is highly uncentralized. Pipe centralization. Pipe centralization is another important factor in obtaining high displacement efficiency. Revision No: A-0 / Revision Date: 03·31·98
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Displacements and Cementing
The cement displays a strong tendency to bypass mud where the casing is eccentric. Cement tends to follow the path of least resistance, i.e. the wide side of the annulus. Centralizers improve casing standoff and centralization, thereby equalizing the distribution of forces exerted by the cement slurry as it flows up the annulus. Generally, a 70% standoff is the objective sought for good centralization. Since perfect pipe centralization (100%) is impossible, it should be used in conjunction with other methods. Flow rates. There are three flow regimes in which a non-Newtonian fluid (such as cement) may exist: turbulent flow, laminar flow and plug flow.
The highest displacement efficiency occurs under turbulent flow conditions.
&#; Turbulent flow. The greatest displacement efficiencies consistently occur at the highest displacement rates, regardless of the flow regime of the cement slurry. The highest displacement efficiency occurs under turbulent flow conditions. However, if turbulent flow cannot be achieved, displacement is consistently better at the highest flow rate attainable under like conditions for similar slurry compositions. If turbulent flow cannot be achieved, using a preflush should be considered: &#; &#; When mud weights are low, it may be advantageous to use a lightweight scavenger slurry (flush) in turbulence ahead of the primary cement. &#; &#; When mud weights are higher, the use of a spacer or flush which is easily put into turbulence is recommended. Several spacers and
Displacements and Cementing
20C.9
flushes can be used. A good general recommendation for a turbulent flush volume is enough for a 10-min contact time, or 1,000 ft (305 m) of annular volume. &#; Laminar flow. Viscous nonNewtonian fluids like cement tend to stay in laminar flow over a broad range of shear rate or annular velocity. For many instances, it is impossible to pump cement in turbulent conditions due to concerns for lost circulation and other reasons. When in turbulent flow, fluids exhibit less scrubbing action on wellbore surfaces and do not achieve as good fluid or filter-cake removal. &#; Plug flow. In theory, plug flow is the second best flow regime. However, studies have shown that if turbulence cannot be achieved, better mud removal is found when maximum flow energy is used, even if the slurry is in laminar flow. Thus, maximum flow rates are always desirable if conditions permit. Spacers or flushes. Fluids as simple as water or as complex as weighted spacers are beneficial displacement aids because they separate unlike fluids, cement slurry and they remove gelled mud. This promotes a better cement bond, thus helping avoid potential fluid incompatibility. Many specialized spacer formulations have been designed for specific applications, ranging from well control to reactive spacers that react with chemical components of mud filter cake to improve cement bonding.
Revision No: A-2 / Revision Date: 12·31·06
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Field studies show that a contact time of 10 min with the slurry in turbulent flow enhances the chances of a good cement job.
Displacements and Cementing
Contact time. Contact time is the amount of time a fluid flows past a particular point in the annular space. Field studies show that a contact time of 10 min with the slurry in turbulent flow enhances the chances of a good cement job. Studies also show that contact time is not a major factor if the slurry is not in turbulent flow. Density differences. Density differences do not appear to be a major factor except in extreme cases. A very light cement will not remove a dense mud as well as a dense cement will remove a light mud. The only recommendation
regarding density differences is that the cement slurry should have a higher density than the drilling fluid or have a density high enough to maintain well control. Hole size. The optimum annular space clearance recommended for good mud removal is for the hole size to be 1.5 to 2 in. (38 to 51 mm) larger than the casing size. Annular clearances larger than 2 in. (51 mm) can be dealt with, but those smaller than 1.5 in. (38 mm) make cementing significantly more difficult.
Other Cementing Factors Although gas flow may not be apparent by pressure at the surface, it may occur between zones and damage the cement job.
Another factor to consider in obtaining a good cement job is gas flow. Although gas flow may not be apparent by pressure at the surface, it may occur between zones and damage the cement job. Several methods can be used to help prevent damaging the cement job. Wiper plugs. Both a top and bottom wiper plug should be used to separate unlike fluids and prevent contamination of the shoe joint. Waiting-on-cement time. Wait on cement to develop adequate compressive strength before pressure testing the casing or drilling out. Times should be based on the results of cement lab testing, not on the basis of cement samples taken during the cement job itself. Provided that the float equipment is holding, release all pressure on the casing at the conclusion of the cementing job. Cement fall-back in &#;rathole.&#; Where casing is to be set off-bottom, a heavy, viscous pill should be spotted in the rathole. The pill will prevent the
Displacements and Cementing
20C.10
cement and the &#;rathole&#; fluid from trading places due to density differences. The pill should be heavier than the cement to prevent gravity migration. Cementing deviated wellbores. Many of the factors which influence vertical wellbore cementing become even more critical in deviated wellbores. Conditioning of the drilling fluid is still the most important factor, but different mud qualities are required for good displacements. Results of studies into deviated wellbore mud displacement and cementing indicate that settling of solids from the drilling fluid results in cutting beds and a channel on the low side of the annulus which is virtually impossible to displace. Clearly there are two requirements in these situations: (1) Circulating cuttings from the well and (2) obtaining good mud removal below the eccentric casing. A special coordinated effort between mud engineer and cementer should be made to achieve an acceptable cement job in high-angle and horizontal wells.
Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
21A
Reservoir Drill-In Fluids
Introduction Reservoir drill-in fluids are specially designed, nondamaging drilling fluids for use in reservoir intervals.
Reservoir drill-in fluids are extremely important in horizontal wells&#;
Reservoir drill-in fluids are specially designed, non-damaging drilling fluids for use in reservoir intervals. They are formulated to maximize drilling performance as they minimize formation damage, thereby preserving potential well productivity. Generally, conventional drilling fluids cannot be converted into reservoir drill-in fluids. Conventional drilling fluids can cause serious damage to productive reservoirs. This impact can be minimized somewhat by reducing fluid loss and controlling progressive gel strengths. These practices reduce fluid invasion into the formation and assist in obtaining zonal isolation when cementing casing strings. For conventional cased and perforated completions, the perforations usually penetrate past any near-wellbore damage. Elevated drawdown pressures and larger-diameter perforations can assist in reducing the effects of formation damage caused by conventional drilling fluids. In open-hole completions (wells completed without cementing the casing through the producing formation), the fluid and filter cake must be able to be removed without remedial clean-up treatments. Reservoir drill-in fluids are specially designed to reduce formation damage and improve cleanup in such wells. Reservoir drill-in fluids are extremely important in horizontal wells, where low drawdown pressures make clean-ups more difficult. Gravel packs and prepacked screens restrict the size of solids that can be produced back from the well; therefore, solids-laden conventional drilling fluids should be avoided when drilling horizontal intervals through producing zones. Instead, non-damaging reservoir drill-in fluids should be used. A variety of fluids can be used as reservoir drill-in fluids, including water-, Reservoir Drill-In Fluids
21A.1
oil- and synthetic-base fluids. Fluid selection depends on formation type, formation fluid composition, formation damage mechanism and completion method. Most wells drilled with reservoir drill-in fluids are completed without cementing and perforating a casing or liner through the producing zone. The following steps are the recommended selection process for an appropriate reservoir drill-in fluid (see Figure 1): 1. Identify the formation type and permeability. 2. Select the completion type. 3. Select the reservoir drill-in fluid. 4. Select the clean-up method. Formation damage can be quantified by several means. In the laboratory, relative measurements such as return permeability, filter-cake solubility and lift-off pressure are used to compare the suitability of a fluid for drilling a specific formation. In the field, calculated skin factors and productivity indices are used to measure damage to the formation. A reservoir drill-in fluid should have the following characteristics: 1. Formation damage control: a) The reservoir drill-in fluid should not contain clays or acid-insoluble weight materials which can migrate into the formation and plug pores. b) It should be formulated with breakable or acid-soluble viscosifiers, fluid-loss materials and properly sized plugging agents, all of which limit fluid loss to the formation and assure good clean-up. c) The filtrate should be formulated to prevent clays in the producing zone from swelling, migrating or plugging the formation.
Revision No: A-1 / Revision Date: 02·28·01
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Reservoir Drill-In Fluids
Permeability type
Matrix
Zonal isolation
Fractured
Rock type
Needed
Not needed
Highly
Competent formation
Chalk or limestone Keys: Prevent gelled mud or filter cake from blocking fractures. Underbalanced &#;flow drilling&#; has been used in the Austin Chalk. Reservoir drill-in fluid: Inhibition is not necessary. Clear water, polymer/salt/water and low-solids drilling fluids. Clean-up/stimulation: Acid treatment.
May collapse
Cased, cemented and perforated completion Keys: To obtain a good cement job, the hole must be in-gauge and clean. Perforations can usually penetrate near wellbore damage. Difficulty in cementing and perforating long horizontal intervals make this option unattractive. Reservoir drill-in fluid: Oil- or waterbase drilling fluids with elevated lowshear-rate rheology are recommended to obtain excellent hole cleaning without washing out the formation. Clean-up/stimulation: Zonal isolation allows acid or fracture stimulation. Open hole completion Keys: Good bridging and filter-cake quality are needed to prevent solids from entering the pore network. Filter cake removal during clean-up can be assisted with tools that will scratch and scrape the filter cake. Reservoir drill-in fluid: Bridging particles are required to assure filtercake quality; regardless of fluid type. Polymer additives in water-base fluid are used for rheology and filtration control. Hole cleaning can be accomplished either by turbulent flow with low-viscosity fluid or by laminar flow with high-viscosity fluid. Clean-up/stimulation: Either acid wash or brine with polymer breakers.
No Shale Keys: Prevent water adsorption by shale and resulting swelling, sealing the fractures. Reservoir drill-in fluid: Inhibition is necessary and oil-base mud is preferred. Inhibitive, low-solids, water-base muds can be used.
Sand production
(consolidated)
Yes (unconsolidated)
Prepacked liner or screen completion Keys: Prepacked liners and screens are used for sand control when production begins. Weight materials and bridging agents from conventional drilling fluids can potentially block these devices. Use either ultrafine (small enough to pass through the screen) or soluble bridging agents. Reservoir drill-in fluid: Biopolymer-base fluid provides elevated, low-shearrate rheology for hole cleaning. Fluid-loss control is achieved with polymeric or starch additives. Sized-salt or calcium carbonate bridging agents result in soluble filter cake. Alternatively, ultrafine bridging particles can be used. Clean-up/stimulation: Acid will dissolve calcium carbonate or sized-salt filter cake. Sized salt can be cleaned up with undersaturated brine. Polymer breakers will help remove viscosifiers and fluid-loss control agents.
Preopened liner completion Keys: Preopened liners include slotted, preperforated, predrilled, etc. Particle bridging of pore openings and filter-cake quality are needed as in open-hole completions. Ease of filter cake removal is important because scraping tools cannot be used. Reservoir drill-in fluid: Bridging particles are required to ensure filtercake quality, regardless of fluid type. Acid-soluble or breaker-degradable polymer additives for rheology can help with filter cake removal. Calcium carbonate or sized-salt bridging agents can be cleaned up easily. Clean-up/stimulation: Acid wash or brine with polymer breakers.
Figure 1: Guide for selecting non-damaging reservoir drill-in fluids.
Reservoir Drill-In Fluids
21A.2
Revision No: A-1 / Revision Date: 02·28·01
CHAPTER
21A
Reservoir Drill-In Fluids
d) The filtrate should be compatible with formation fluids so that it will not precipitate mineral scales. e) The fluid and filtrate should not change the wetting characteristics of the formation from either water-wet to oil-wet or from oil-wet to water-wet. f) The filtrate should not form emulsions with formation fluids and block the formation. 2. Drillability: a) The reservoir drill-in fluid should provide good hole-cleaning, lubricity and inhibition. b) It should minimize hole enlargement and provide wellbore stability. 3. Compatibility with completion equipment and procedures: a) Particles should be sized for formation pore throat bridging yet be small enough to pass through completion equipment. b) The fluid should be formulated with acid-soluble, water-soluble, oxidizer-degradable or solventsoluble materials, which will not cause precipitates or emulsions.
c) Breakers should be compatible with formation fluids and reservoir drill-in fluid filtrate. Susceptibility to different types of formation damage varies greatly and is dependent on the formation type and well conditions. Some formations tolerate a wider range of reservoir drill-in fluid composition more than others. When production is from carbonate fractures, as it is in the Austin Chalk formation, significant amounts of insoluble materials can be tolerated without a significant reduction in productivity. Usually, fluids which invade these types of formations can be produced back from the well. Lowerpermeability sandstones and depleted or unconsolidated sandstone reservoirs do not tolerate fluid and particle invasion without causing extensive damage. Detailed knowledge of the formation, permeability, pore pressure, mineralogy and formation fluid composition must be called upon to assist in selecting the proper reservoir drill-in fluid.
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Reservoir Drill-In Fluids
21A.3
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CHAPTER
21A
Reservoir Drill-In Fluids
Formation-Damage Mechanisms
Compressible and deformable solids&#;are the most difficult&#; to remove.
A number of detrimental mechanisms restrict production and reduce the amount of recoverable reserves. Some of the most common ones are described below, with potential prevention techniques. Solids plugging. Formation pore throats can be plugged by solids contained in a drilling fluid and cause formation damage. These solids can be added materials, such as commercial clays, drilling fluid chemicals or incorporated drill solids. Compressible and deformable solids, such as hydrated clays, are the most difficult (or impossible) to remove. In addition, solids can plug the completion assembly, restricting production. To prevent plugging, solids added to a reservoir drill-in fluid should be sized appropriately to bridge formation pore throats, and only acidsoluble materials should be used (see Figure 2). A D90 particle size equal to the larger pore throat diameters, and a bridging agent concentration above 2% by volume, will provide excellent plugging and a good base for filter-cake deposition. Reservoir drill-in fluid filter cakes trap fine solids &#; which can cause considerable damage &#; and prevent their entry into the formation. If solids in the reservoir drill-in fluid are too fine to bridge and initiate a filter cake on the face of the wellbore, they will invade the reservoir matrix and can build an internal filter cake resulting in Poor bridging Mud invasion
Good bridging No mud invasion Filter cake Filtrate
Mud particles No filter cake
Figure 2: Bridging comparison. Reservoir Drill-In Fluids
21A.4
formation damage. A filter cake on the face of the formation is much easier to remove than one inside the formation. To reduce the likelihood of particle invasion, an aggressive solids-control program should be used to remove drill solids during their first circulation from the well. If drill solids are allowed to be recirculated, they will degrade in size and disperse, creating an accumulation of fine solids. Minimizing the overbalance also will help reduce the depth of solids invasion and, hence, the amount of formation damage. Formation clay hydration and/or migration. Sandstone formations vary from clean (containing only sand) to very dirty (containing significant quantities of clay). These interstitial clays can hydrate, deform or migrate, causing formation damage when exposed to drilling fluid filtrate, cement or other fluids such as acid and spacers. This impedes the flow of reservoir fluids during production. A variety of inhibitive fluids can prevent the swelling and migration of formation clays. These include oil- and synthetic-base fluids, as well as fluids which are compatible with the formation clays. Completion fluids may include produced brines, high-salinity brines and water-base fluids that use potassium chloride or other clay-stabilizing chemical additives. Emulsion blocking. An emulsion of reservoir drill-in fluid filtrate and formation fluid can occur, causing formation damage and restricting the flow of reservoir fluids during production. Emulsion blocking may be caused by fine solids in the fluid filtrate combined with asphaltines in the oil, by surfactants or emulsifiers in the fluid emulsifying formation fluids, or by exposing certain crude oils to a chemical environment that reacts to form emulsifiers. Oil- and syntheticbase fluids may alter formation wettability, releasing water to be emulsified. In Revision No: A-1 / Revision Date: 02·28·01
CHAPTER
21A
Reservoir Drill-In Fluids
water-base fluids, filtrate compatibility can be tested and adjusted with alternative formulations and non-emulsifiers. Reducing fluid loss from the reservoir drill-in fluid also minimizes the depth of potential emulsion damage. Scaling. Chemical incompatibility between the reservoir drill-in fluid and the formation or formation fluids can cause a precipitate (scale) to form,
which results in formation damage. The most common example of this is a calcium-containing filtrate that reacts with soluble carbonates or sulfates in formation fluids to form a calcium carbonate or calcium (&#;gyp&#;) scale. Knowing formation fluid composition and designing a compatible reservoir drill-in fluid can eliminate this potential problem.
Reservoir Drill-In Fluid Types and Applications
FLOPRO systems&#;are designed for trouble-free drilling&#;
Acid or oxidizers can be used to clean up&#;
A wide variety of options exists for choosing reservoir drill-in fluids. The selection of the most appropriate reservoir drill-in fluid depends not only on potential formation damage mechanisms, but also on the type of formation to be drilled and the completion method to be used. Temperature, density and known drilling problems also must be considered. Listed below are some potential reservoir drill-in fluid options and the primary application for each. Clear fluids with viscous sweeps. Clear water or brine reservoir drill-in fluids can be used for mechanically competent formations that are not adversely affected by the intrusion of large volumes of fluid into the reservoir. These non-viscosified fluids are often used in fractured limestones and dolomites, as well as in reef formations; fractured sandstones; and clean, low-permeability sandstones. These fluids require turbulent flow and high-viscosity sweeps to clean the hole adequately. The high-viscosity sweeps should be free of clay, and should be composed of Hydroxyethylcellulose (HEC) or xanthan gum (DUO-VIS*, FLO-VIS*). Flocculants may be used to precipitate drilled solids in the surface system and maintain a clear fluid. These wells, drilled in competent formations, are Reservoir Drill-In Fluids
21A.5
generally completed open-hole or with a slotted or perforated liner. HEC fluids. Hydroxyethylcellulosebase fluids can be used under conditions similar to those in which the clear fluids discussed above are, i.e., in competent formations. HEC provides carrying capacity, but has minimal gel structure and poor suspension characteristics. The low-shear rheology and suspension characteristics can be enhanced by adding xanthan gum (DUO-VIS or FLO-VIS). HEC will viscosify a variety of fluids from freshwater to salt-saturated fluids such as sodium, potassium and calcium chlorides, as well as sodium, calcium and zinc bromides. However, HEC provides only limited filtration control. Further filtration control must be achieved with starch-base additives such as FLO-TROL* or POLY-SAL*. Again, wells in competent formations are generally completed open-hole or with a slotted or perforated liner. Acid or oxidizers can be used to clean up the HEC, xanthan and starch polymers prior to production, if desired. FLOPRO*. FLOPRO systems are rheologically engineered, minimal solids, non-damaging reservoir drill-in fluids designed for trouble-free drilling of producing formations subject to damage from conventional drilling fluids. This system has particular application Revision No: A-2 / Revision Date: 12·31·06
CHAPTER
21A
The polymerbase FLOPRO systems have an ultra-high LSRV&#;
Reservoir Drill-In Fluids
in horizontal wells drilled in unconsolidated reservoirs. Vertical wells and other formation types also benefit from the level of performance and degree of protection provided by FLOPRO. To minimize formation damage by clays, FLOPRO systems use polymers for both rheology and filtration control. The polymer-base FLOPRO systems have an ultra-high, Low-Shear-Rate Viscosity (LSRV) compared to alternative systems or typical clay-base drilling fluids. The elevated LSRV provides excellent cuttings suspension in highangle and horizontal wellbores and reduces hole erosion. The high LSRV is critical, not only for optimized hole cleaning and drilling performance, but also for minimizing filtrate invasion and the invasion of whole fluid into the formation. LSRV is measured with a Brookfield viscometer at 0. sec&#;1 (equivalent to 0.037 RPM with a VG meter). FLOPRO systems contain only a Grind Size Finer than 40 mesh Finer than 200 mesh Finer than 325 mesh Median (µ)
Fine &#; &#; >99% 6-9
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Medium &#; 70 - 80% &#; 35 - 45
Coarse >99% 100 NaCl > KCl. As different types of salts are drilled, this complex equilibrium can shift. Calcium chloride is the &#;preferred&#; salt. It will stay in solution at a higher concentration when other salts are added to the fluid, although some calcium chloride can be displaced by the other salts. Another reason for dissolution is related to temperature effects. As shown in Figures 2 and 3, salts are more soluble at higher temperatures and their mutual solubility relationships change with increased temperature. More salt will go into solution downhole at higher temperatures. As
Drilling Salt
22B.4
the circulating fluid approaches the surface, the temperature will decrease, crystallizing salt, and a portion of the salt crystals will be removed by solidscontrol equipment. As circulation continues, the fluid is reheated downhole, and there is more capacity for salt to go into solution. This heating and cooling cycle is repeated on each subsequent circulation, resulting in greater salt dissolution and a larger hole diameter. Chemical crystallization inhibitors and heated mud pits (discussed later) can be used to maintain saturation downhole. This change in solubility with temperature also indicates that salt crystals should always be present at the flow line when drilling salt. If crystals are absent, the mud is probably not saturated under downhole conditions. 100 Salt solubility (% wt)
chloride, the calcium chloride will go into solution and sodium chloride will be precipitated. Depending on the solubility of each salt, a mutual solubility equilibrium will be reached. Figure 1 shows the mutual solubility for calcium, sodium and potassium chloride salts.
CaCl2
80
MgCl2 60
KCl
40
NaCl
20 0
0
50
100 150 200 250 Temperature (° C)
300 350
Figure 2: Effect of temperature on solubility of individual salts. 80 CaCl2 (% wt)
22B
375° F (190° C)
60
202° F (95° C) 122° F (50° C)
40
86° F (30° C) 20
32° F (0° C)
0 0
5
10
15 20 25 NaCl (% wt)
30
35
Figure 3: Effect of temperature on mutual solubility.
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22B
Drilling Salt
Deformation &#; Plastic Flow controlled to an acceptable level during the interval of time it takes to drill the section. The force extruding the salt is equal to the weight of overburden. This means that mud weights can be very high. Generally speaking, the greater the depth of burial, the higher the mud weight. Mud weights required for drilling salts can be in excess of 20.0 lb/gal (2.4 SG). As shown in Figure 4, the mud weight required to reduce salt creep to less than 0.1% per hour can be estimated from the formation temperature and depth. In the case of a completed well, salt can flow sufficiently to collapse casing. In some cases, the movement of the salt is so slow, it takes years before this problem is manifested. High-strength casing and a good cement job after drilling a nearly gauge wellbore tend to distribute the salt loading more evenly over the interval, thereby reducing the potential for casing collapse. Experience has shown that it is a good practice to use a high-compressive-strength, salt-saturated-resistant cement and high-strength casing designed for 1.0 psi/ft collapse.
16 18
350 400
250 300
500 450
14
200
12
150
10 Temperature ° F 100
A salt can flow sufficiently to close off the wellbore and stick the drillstring.
Salt sections exhibit plastic-flow characteristics under sufficient temperature and pressure. Although it is difficult to correlate the magnitudes required to initiate plastic salt flow because of the variety of environments, it is a known fact that a salt section tends to be more sensitive to temperature and pressure than the adjacent formations. Salt formations are rarely plastic or problematic if they are at depths of less than 5,000 ft (1,524 m), at temperatures below 200° F (93° C) or less than 1,000 ft (305 m) thick. In the case of salt beds, the deformation can be much less apparent. When a well is drilled through a salt section, stress within the salt is relieved and the salt flows toward the wellbore. For this reason, salt sections should be shorttripped and reamed on a regular basis. A salt can flow (&#;creep&#;) sufficiently to close off the wellbore and stick the drillstring. Freshwater sweeps can be used to dissolve the salt that is creeping and to liberate stuck pipe. A freshwater pill of 25 to 50 bbl is usually sufficient to free stuck pipe. Good drilling practices can also minimize salt-deformation problems. Drilling each joint or stand and wiping over that section prior to making the next connection will help ensure the salt has been opened sufficiently and stabilized. Regular wiper trips back through the salt to casing will also help ensure the hole has remained open. Increasing the mud weight is the only practical way to control the rate at which the wellbore closes. The closure may never be eliminated, but it can be
Depth (1,000 ft)
&#;a salt section tends to be more sensitive to temperature and pressure than the adjacent formations.
20 22 24 26 28 30 8
10
12 14 16 18 Mud weight (lb/gal)
20
22
Figure 4: Mud weight required to control salt creep. Drilling Salt
22B.5
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CHAPTER
22B
Drilling Salt
Well Control
Salt is also a trap or barrier to the migration of oil, gas and waters.
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It is important to understand the subsurface stress and pressure environment near and in salt structures. Because salt is less dense (about 2.1 SG) than the surrounding formations, it tends to be buoyed or float in the subsurface environment over geological time. This accounts for the formation of salt domes and salt migration. Due to these forces and movements, the stresses around and in salt structures can be great and troublesome to stabilize. The boundary zones between the salt and surrounding formations are often geologically complex mixtures of highly altered and disturbed rocks. It is not uncommon for there to be a very narrow window of mud weight which will control formation pressures and fluids without causing lost circulation. Salt is also a trap or barrier to the migration of oil, gas and waters. This is one of the reasons so much drilling and production occurs near salt formations. It is also the reason why there are so many hole problems at salt boundary zones. In subsalt drilling it is believed that trapped water may cause these boundary zones to be saturated with water, almost mud-like and very weak, with no real formation strength. Both shales and sands cannot be compacted under these conditions and may have retained their original soft, unconsolidated constitution, regardless of age. In these situations, the formations are very dispersive and fracture easily (losing circulation), yet kick with only small changes in mud weight. Since salt is plastic, the rock stress environment is different from shale, sand or carbonate formations. In shale, the maximum stress is normally in the vertical direction, and there is an overburden/pore/intergranular-pressure situation. In salt, the pressures and stresses are equal in all directions because it is Drilling Salt
22B.6
a plastic material. This causes all of the overburden to be translated into pore pressure, and as the salt section is drilled, all of the weight of the salt will be added to the overburden and may need to be equalized with increased mud weight. Salt has a specific gravity of about 2.1, so for some situations, the mud weight in a salt section may need to be increased by 0.9 psi/ft, depending on the section length and temperature. If compressed fluids within a porous formation underlying salt sections are trapped by the deposit of impermeable salt above, reservoir pressure of the fluids below this salt deposit will probably equal the overburden pressure. Salt sections are often associated with other evaporite or carbonate sections, anhydrites, limestones and dolomites, which can contain permeability and porosity in the form of vugs or fractures. In some cases, these pore spaces are filled with salt, but in many places, there are fluids, gas, oil or brine, under high pressure. In some cases, fractures within the salts contain fluids. Most salts are self healing; therefore fractures usually will not exist, but high-pressure kicks have occurred in the fractured salts in Michigan. Gas associated with these formations can be carbon dioxide, hydrogen sulfide, methane or hydrocarbon liquids. The drilling fluid should have sufficient density to control the pressure. In many cases there is a fine line between controlling a kick and losing circulation, due to the fractured and weak nature of these formations. Lostcirculation material selection can be limited due to the elevated viscosity of the fluid as well as reduced free water. The drilling fluid should also be treated to counteract or remove the contaminants, as discussed in the Revision No: A-1 / Revision Date: 02·28·01
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22B
Drilling Salt
Contamination and Treatment chapter. Density should be increased to eliminate the influx of fluids. Carbon dioxide should be treated out by raising the pH >10 with lime. Precipitation from increasing the pH may cause excessive viscosity, pilot test in complex divalent
salts. Hydrogen sulfide should be treated by raising the pH >11 with lime or caustic soda and using a zinc-base sulfide scavenger, such as zinc oxide, zinc carbonate or SV-120* in sufficient concentration to remove the sulfides.
Recrystallization Recrystallization is the result of lowering the temperature of a supersaturated salt solution or the introduction of a more soluble salt.
Salt has been reported to build up on the casing shoe sufficiently to prevent tripping a bit out of the hole.
Recrystallization is the result of lowering the temperature of a supersaturated salt solution or the introduction of a more soluble salt. The least soluble salt is the first to recrystallize. One problem with recrystallization is that the mass of small crystals have a huge surface area, which is preferentially waterwet to a high degree and difficult to oil-wet in invert-emulsion fluids. In oilbase systems, these particles quickly adsorb wetting agent and emulsifier, resulting in fluid instability. Crystal growth begins on a nucleation site. This can be the surface of a drilled solid, casing or solids-control equipment surfaces. In many cases, recrystallization will be most evident at shakers where the screens will become plugged and blinded by aggregated solids and salt crystals. In addition to salt recrystallizing as individual particles, salt can recrystallize downhole in the form of massive agglomerations. Salt has been reported to build up on the casing shoe sufficiently to prevent tripping a bit out of the hole. Water-wet solids have built up on the inside of drill pipe, causing an increase in standpipe pressure. This mass of salt can be removed with freshwater sweeps. The potential for this type of recrystallization can be minimized by controlling the solids in a fluid with a good solids-control program.
Drilling Salt
22B.7
During drilling, lower temperatures are encountered in deepwater risers and on the surface. In northern climates, it has been observed that recrystallization problems are more severe during the spring and fall when there is a greater variance in surface temperatures between day and night. In the summer, as well as winter, the temperature will generally fluctuate less between day and night, although the difference between downhole temperatures and surface temperatures is greater in the winter. In some cases, heated surface mud systems have been used to keep the mud in a saturated condition to prevent recrystallization. Chemical salt-precipitation inhibitors are sometimes employed in water-base muds to prevent recrystallization by maintaining super-saturation of the brine. These materials interfere with the crystal structure formation. Often these materials only raise the saturation point of the brine and do not overcome the recrystallization problem. Sufficient inhibitor concentration is required to prevent recrystallization. While drilling salt, the system is dependent on the inhibitor. If the inhibitor concentration is not maintained or is depleted on drilled solids, severe recrystallization can occur.
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CHAPTER
22B
Drilling Salt
Treating Invert Emulsion Fluids While Drilling Salt It is best to pretreat an invertemulsion system for drilling salt&#;
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It is best to pretreat an invert-emulsion system for drilling salt, particularly for the highly soluble calcium/magnesium salts. The following guidelines will help maintain fluid stability while drilling salt with an invert system. 11. Maintain a high synthetic:water or oil:water ratio to reduce the impact of potential water or brine contamination of the system and minimize the volume of the aqueous phase available to dissolve salt. 12. Monitor the salt composition of the water phase of the mud to keep it from being supersaturated with one of the monovalent cations. For halite formations, this means using the binary salt titrations and calculations as described in the NonAqueous Emulsions chapter. If the sodium-chloride concentration of the internal phase increases, it may be necessary to first treat the mud with emulsifier and wetting agent then add water and possibly even calcium chloride to the system. Neither water nor dry salt should be added to a system if it is exhibiting fluid loss or emulsion instability. 13. Run the rheology at lower acceptable levels, in order to minimize any viscosity increase which will occur from a brine influx. 14. Under &#;normal&#; drilling conditions monitoring HTHP fluid loss and Electrical Emulsion Stability (abbreviated simply &#;ES&#;). Use these values as a guide to determine daily emulsifier treatments, which should be in the range of 0.25 to 0.5 lb/bbl for each emulsifier. Before drilling the salt formation, the mud should be treated with 1.0 lb/bbl of emulsifier and wetting agent. Determine the HTHP fluid loss at two temperatures (for instance 300° F and 250° F
[149 and 121° C]). The highertemperature test results will provide an early indication of any emulsion weakening. 15. Check &#;flow line&#; HTHP, sand content and ES on a regular basis. These properties will provide early indications of mud problems. Sand content measurements are essential as water-wet solids will show up as a high sand content due to the aggregation of the solids (including barite) into sand-sized particles. If the sand content rises significantly against the background level, then a mud problem may exist. This must be checked upstream of the shakers otherwise any larger water-wet particles will have been screened out. 16. Drilling salt formations may result in erratic ES readings. Monitor the emulsion stability by using the HTHP results. 17. Measure the magnesium, calcium and excess lime content. The actual Mg2+ content of the mud may remain unchanged as Mg(OH)2 will be precipitated and taken out of the system by the shakers, resulting in low Mg2+ contents. While drilling, the following will indicate an influx of magnesium salts: &#; Lime content drops sharply. &#; Plastic Viscosity (PV) increases. &#; Oil:water ratio decreases. &#; HTHP decreases (due to Mg(OH)2 plugging the filter paper). 18. If H2S is a potential hazard, a zincbase sulfide scavenger, such as zinc oxide or zinc carbonate, should be carried in inventory as a contingency product in the event of an influx. Measure the sulfide concentration regularly using the Garrett Gas Train.
________________________
Drilling Salt
22B.8
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CHAPTER
22B
Drilling Salt
19. Maintain an excess lime content of between 3 to 5 lb/bbl. This should be determined using the direct titration method. The back titration method can give erratic results due to the interference of Mg(OH)2. 10. In order to ensure adequate oilwetting whenever barite is added to the system, the concentration of emulsifiers/wetting agents should be increased. 11. In order to anticipate potential mud instability during any possible mud weight increases, a pilot weight-up tolerance test should be performed prior to drilling and regularly while drilling salt.
Drilling Salt
22B.9
WEIGHTING-UP
TEST:
1. Take a quart or liter sample of mud from the active system. 2. Add barite to raise mud weight by 3 lb/gal (0.36 SG) for mud weights 15 lb/gal, add enough barite to increase the density to 18 lb/gal (2.2 SG). 3. Perform a complete mud check on the above mud including HTHP at 300° F (149° C). 4. If the results from the mud check indicate mud instability, then treatments of base oil, emulsifiers and wetting agents, possibly with water additions, should be pilot tested.
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CHAPTER
22C
HTHP
Introduction Classifying a well as High-Temperature (HT) or High-Temperature, HighPressure (HTHP) usually elevates it to a &#;critical and difficult&#; status. Wells are classified as HTHP when their formation pressures exceed a 15-lb/gal (1.8 kg/L) equivalent and when static bottom-hole temperatures are greater than 350° F (177° C). Corresponding downhole pressures may require mud weights as high as 20 lb/gal (2.4 kg/L) to maintain well control. In traditionally overpressured and hothole areas, such as South and East Texas, Mobile Bay, Mexico, Northeast Brazil, the North Sea, Italy, and Yugoslavia, it is not uncommon for formation temperatures to exceed 400° F (204° C). In many geothermal and deep gas wells, such high temperatures are the rule, rather than the exception. In geothermal drilling, for instance, it is not uncommon to have temperatures above 350° F (177° C) at depths as shallow as 2,500 ft (762 m). In such situations, flow line
temperatures become excessive (>200° F or 93° C) and mud coolers often are required. After trips, the mud may become so hot that it will flash to steam during the initial bottoms-up circulation. Historically, properly formulated HT oil-base systems have provided better temperature stability than water-base muds, thereby making them preferred for HTHP wells. However, due to evertightening environmental restrictions, low-colloid (reduced active solids), water-base systems have been developed which are suitable for the HTHP environment. The continuous development of new HT additives exhibiting increased temperature stability promises to make water-base fluid systems an even more viable alternative to oil-base muds in the future. Increased emphasis on solids control, improved wellsite engineering and the appropriate testing regime has increased the use &#; and success &#; of HTHP water-base muds.
Effects of Temperature When exposed to high temperatures, all muds become thinner to a point, then stabilize before reaching their thermal limit. Figure 1 illustrates the effects of high temperatures on the plastic viscosity of a water-base mud. As shown, up to a temperature of 225° F (107° C), the plastic viscosity of the mud decreases with temperature at essentially the same rate as the viscosity of the water. Up to a temperature of 300° F (149° C), however, the plastic viscosity begins to increase slowly. Above 300° F (149° C), the mud most likely will thicken quite rapidly. The initial decrease in viscosity should be considered, since it will affect hole-cleaning and other downhole functions. HTHP
22C.1
50 Mud Plastic viscosity (cP)
Classifying a well as HT or HTHP usually elevates it to a &#;critical and difficult&#; status.
40
Water (normalized)
30 20 10 0 0
50
100 150 200 250 Temperature (° F)
300 350
Figure 1: Thermal thinning of water-base mud compared to water (after Annis, SPE ).
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CHAPTER
22C
&#;the abnormal pressures experienced in HTHP wells require higher mud densities.
HTHP
When static downhole temperatures become excessive, both gelation and excessive viscosity become major concerns. Rheological properties affect many downhole parameters, including Equivalent Circulating Density (ECD), hole cleaning, barite sag, surge/swab pressures during tripping, pump pressures and bit hydraulics. Instruments like the Fann Model 50 for water-base muds and the Fann Model 70/75 for oil- and synthetic-base fluids can measure this change in properties. Such measurements can then be used in the VIRTUAL HYDRAULICS computer program to model and estimate the behavior of the fluid. VIRTUAL HYDRAULICS contains TPRO*, a circulating temperature simulator to estimate mud temperatures and properties. Rheology takes on an even greater importance in deep HTHP wells where the typically smaller hole diameter increases ECD pressures. Correspondingly, the abnormal pressures experienced in HTHP wells require higher mud densities. The increasing solids concentration of even the non-reactive weight material will also reduce the thermal stability of the fluid as the amount of &#;free,&#; or available, base liquid is reduced by the surface area of the solids. Excessive
HTHP
22C.2
viscosity and gelation increase the possibility of lost circulation. The temperature stability of a mud can be determined easily by static heat-aging, as described at the end of the chapter, and measuring the static shear strength and properties after aging. The static shear strength is similar to gel strength and is measured with a special shear tube and weights. The risk of becoming differentially stuck increases in an HTHP well because the mud weight needed to control pressures may be much higher than the pressure in other exposed formations. If the high temperatures cause the fluid loss to become unstable, then stuck pipe will be a significant concern. It is critical to monitor and control the HTHP fluid loss at the bottom-hole temperature. Contamination also will have a destabilizing affect on filtration control and will reduce the thermal stability. If contamination is anticipated, additional filtration and plastering materials may be required. The lubricity of the filter cake is an important factor in avoiding stuck pipe, especially in extended-reach, highangle wells. Since oil-base and synthetic fluids exhibit better lubricity than waterbase systems, they may be preferred for highly deviated wells.
Revision No: A-3 / Revision Date: 02·01·09
CHAPTER
22C
HTHP
The MBT of the CEC of a water-base mud is an excellent measure of the reactive solids content.
The detrimental effects of drill solids at high temperatures have been welldocumented. At low temperatures, a fluid can tolerate large amounts of reactive solids with little adverse effect. However, at high temperatures, reactive solids flocculate and begin to gel, resulting in high viscosity and possibly solidification. The specific temperature at which a fluid will become unstable depends on the type of solids and their concentration, as well as the degree of chemical treatment. As shown in Figure 2, increasing the concentration of bentonite above 9 lb/bbl in an unweighted water-base mud causes a significant decrease in temperature stability as indicated by the increasing 30-min gel strength. Bentonite is more reactive than drill solids, but an increased drill-solids concentration will have the same effect. The amount of bentonite or drill solids that a mud will tolerate, and remain stable at a particular temperature, decreases as the mud weight increases. As shown in Table 2 for the DURATHERM* system, the amount of bentonite is decreased in the formulation as the mud weights increase. The specific temperature limit decreases with increasing reactive solids content. To improve and stabilize the rheology of high-temperature water-base fluids, anionic materials are used to prevent flocculation. This helps prevent gelation. Anionic thinners include organic materials such as lignosulfonate (SPERSENE*) and lignite (TANNATHIN*), as well as synthetic polymers like TACKLE* and
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30-min gel strength (lb/100 ft2)
Effect of Reactive Solids 140 120 27 lb/bbl
100
(Too high to measure at 300° F) 18 lb/bbl
80 60 40
9 lb/bbl
20 0 0
75
150 225 300 Temperature (° F)
375
Figure 2: Effect of bentonite concentration on thermal stability (after Annis, SPE ).
DURALON*. These anionic materials adsorb to the edges of clay platelets, thereby neutralizing the cationic edge charges and preventing flocculation. Reactive solids include bentonite, added for viscosity and filtration, plus drill solids that contain shale and clay materials. The Methylene Blue Test (MBT) of the Cation Exchange Capacity (CEC) of a water-base mud is an excellent measure of the reactive solids content. For many HTHP waterbase muds, the MBT must be kept below a 15-lb/bbl equivalent. To minimize the adverse effects of high temperature on mud properties, it is important to: &#; Maintain low reactive solids content. &#; Properly treat the system with thermalstabilizing additives for rheology and filtration control. &#; Buffer pH at a level to extend the effectiveness of additives and reduce the impact of contamination.
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Fluid Selection
If contamination is anticipated, then oil-base muds are preferred&#;
A number of factors must be taken into consideration when selecting a fluid for HTHP wells. These include: &#; Temperature. The thermal stability of both the entire system and the associated additives must be determined. &#; Wellbore stability. Since most HTHP wells do not contain as many watersensitive formations as normal wells, shale stability is usually more a function of mud weight. However, in selecting a fluid system, it is still important to determine the chemical or water sensitivity of the various formations to be drilled. &#; Mud density. As a general rule, lowdensity fluids are more easily formulated. For higher-density applications, either oil-base systems or dispersed water-base systems will be required. For exploratory drilling in which the required mud weight schedule is not well known, water-base muds are suggested because the problem of
gas solubility makes it difficult to detect kicks with oil-base systems. &#; Contamination. It is critical to anticipate possible contamination. This includes gases such as hydrogen sulfide (H2S) and carbon dioxide (CO2), or salts and other contaminants. If contamination is anticipated, then oil-base muds are preferred because they are less susceptible to most chemical contaminants. &#; Environmental/safety considerations. Environmental restrictions often impact mud selection. The system selected must comply with local regulations and be capable of maintaining control of the well. &#; Economic considerations. The base cost of the system, anticipated penetration rates, logistics, solids-control efficiency and the probability of lostcirculation zones must all be considered when deciding whether to use an oil-, synthetic- or water-base mud.
Geothermal Drilling
Low-density, water-base muds are almost always used for geothermal drilling.
Much of the criteria for selecting mud systems for HTHP oil and gas wells also holds true in drilling geothermal wells. The primary differences are in the pressures encountered, the densities used, the frequency and severity of the lost circulation encountered, and the type of formation fluids produced. Since pressures in most geothermal wells are subnormal to normal, weight material is rarely required. Low-density, water-base muds are almost always used for geothermal drilling. Once the reservoir network is drilled, lost circulation usually occurs because reservoir pressures are significantly lower than the hydrostatic pressure of water. The drilling fluid should be temperaturestable so that lost fluid does not solidify HTHP
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and impair production. Geothermal drilling fluids have been developed that use sepiolite (DUROGEL), a rodor needle-shaped clay similar to attapulgite (SALT GEL). Sepiolite does not flocculate and cause gelation at high temperatures, but because of its shape, sepiolite is not a good filtration-control additive. Normally, formulations use 10 to 20 lb/bbl sepiolite or a blend of 5 to 10 lb/bbl sepiolite plus 5 to 10 lb/bbl bentonite. Whether geothermal production is &#;dry&#; (no liquid water) or &#;wet&#; steam (which is liquid downhole and will flash to steam near the surface), also has a bearing on the mud system used to drill the production interval. In formations with dry steam production, Revision No: A-2 / Revision Date: 12·31·06
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air is often used to drill the reservoir underbalanced, producing steam as drilling continues. In wet-steam or hotwater reservoirs, either water or aeratedwater systems are used. Air drilling is not possible in most wet-steam reservoirs since the water influx will be too great. Regardless of type, the drilling fluid proposed for any HTHP well must have been tested under simulated conditions at the maximum temperature expected. Both rheology and fluid loss should be measured and stabilized. It is essential that the mud engineer be made completely aware of the performance of all additives under variations in downhole temperature. It is highly recommended that the number of products used in a high-temperature formulation be limited. This simplifies the mud
engineering aspect of the formulation at the wellsite and avoids confusion. If a water-base system is used, it must be carefully monitored throughout the course of the well, and the formulation may need to be changed as the temperature increases with depth. The dilution rate of HTHP drilling fluids depends on the type of mud and the solids-control equipment used. The rate of evaporation in an oil-base mud can increase both the water-phase salinity (decreasing stability) and the oil-to-water ratio. Water-base fluids will require regular dilution to maintain an acceptably low solids content and MBT value. A discussion of the procedures and equipment employed to test HTHP fluid systems follows at the end of this chapter.
Oil-Base Mud Systems
&#;these systems&#;are inherently more temperaturestable and resist the effects of most drilling contaminants.
Oil-base systems are sensitive to both temperature and pressure. As mentioned, these systems historically have been preferred for drilling hot and highly pressured wells, because they are inherently more temperature-stable and resist the effects of most drilling contaminants. Oil-base fluids thin with increasing temperature and expand so that viscosity and downhole density may be different from that measured on the surface. Fortunately, due to compression, high pressures with high-density fluids counteract this expansion. Normally, oil-base fluids for HTHP applications do not require extensive additional treatments or frequent dilution. Formulations should be made with special high-temperature organophilic clays like VERSAGEL* HT and should use a high concentration (5 to 15 lb/bbl) of high-temperature-softening-point asphaltic materials like VERSATROL* to
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increase viscosity and decrease fluid loss. For hostile environments in which acid gases are anticipated, the excess lime content should be kept at a higherthan-normal level (>10 lb/bbl). However, oil muds will not solve all the problems inherent in drilling an HTHP well. Some of their limitations include: &#; Lost circulation. Can be very expensive when running these systems and is often difficult to control. &#; Gas-kick detection. The solubility of the gas within the system makes kick detection difficult. &#; Barite stripping. Gas influxes decrease viscosity of the fluid phase, causing barite to strip or settle. &#; Environmental. May not comply with local regulations. &#; Logging. Some exploratory situations require logs that must be run in water-base fluids.
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Water-Base Mud Systems
&#;water-base fluids are preferable environmentally and have a lower unit cost.
Conventional water-base systems are sensitive to temperature, but are not very compressible. Generally, water-base fluids are preferable environmentally and have a lower unit cost. However, they are less resistant to contamination and do not provide the same level of lubricity as oil-base fluids. By controlling the concentration of bentonite and active solids, and by employing stabilizing additives, hightemperature, low-colloid, water-base systems can be formulated. Critical to the successful application of water-base systems are superior solids control and adequate dilution. As discussed previously, active clays can promote gelation and other rheological problems at high temperatures. In low-colloid systems, the concentrations of bentonite and active drill solids are minimized. Generally, in an 18-lb/gal (2.2 kg/L) mud, the bentonite concentration should be reduced to about 5 lb/bbl. As discussed, when designing a water-base system for HTHP applications, the bentonite concentration must be kept low, and the concentration of reactive solids should be monitored using the methylene blue test. With the low gel content of these systems, barite settling would appear to be a real possibility, but this has not been encountered in the field. In one case cited in the literature, a wellbore had not been circulated for 40 days. Upon recirculation, the properties of the water-base system had deviated little since the original displacement. No settling was observed, and the system exhibited an extremely high tolerance for temperature.
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Since the circulating fluid temperature in HTHP wells is significantly less than that of the formation temperature, products are not exposed to the highest temperatures, except during trips. When temperatures increase during trips, viscosifiers like Polyanionic Cellulose (PAC) and xanthan polymers may degrade, but they do not produce contaminating by-products. These viscosifying polymers, which are used above their temperature limit, are called &#;sacrificial&#; viscosifiers. Although the viscosifying benefit of the polymers will be lost, it will be offset with an increase in viscosity from the thermal flocculation of reactive solids. Thus, the suspension and viscous properties are maintained, alleviating the possibility of settling. Further, product consumption is limited to the small quantity of drilling fluid exposed to higher formation temperatures. Using an alternative viscosifier such as sepiolite (DUROGEL) or attapulgite (SALT GEL) helps achieve an adequate viscosity without using too much bentonite. In water-base systems, low-gravity solids should be maintained at less than 6%, drill solids
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