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Drilling fluids
- 1. Click to edit Master subtitle style Drilling Fluids AAPG SU SC Check every slide as some slides may include nether NOTES.
- 2. Outline Introduction. Basic Function of Drilling Fluids. Types of Drilling Fluids. Drilling Fluid Tests. Challenges Related to Drilling Fluids. Solids Control and Waste Management.
- 3. Introduction • Drilling-fluid system commonly known as the Mud System. • Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions. • The Capacity of the surface system usually is determined by the rig capacity which is determined by the well design.
- 4. Outline Introduction. Basic Function of Drilling Fluids. Types of Drilling Fluids. Drilling Fluid Tests. Challenges Related to Drilling Fluids. Solids Control and Waste Management.
- 5. Basic Functions of Drilling Fluids 1. Transport Cuttings to Surface. 2. Primary Well-Control Method. 3. Preserve Wellbore Stability. 4. Minimize Formation Damage.
- 6. Basic Functions of Drilling Fluids (Cont.) 5. Cool and Lubricate the Drill String. 6. Provide Information About the Wellbore (Mud Logging).
- 7. Outline Introduction Basic Function of Drilling Fluids Types of Drilling Fluids Drilling Fluid Tests Challenges Related to Drilling Fluids Solids Control and Waste Management
- 8. Types of Drilling Fluids Water-based fluids. Oil-based fluids. Synthetic-based fluids. All-Oil Fluids. Pneumatic-Drilling Fluids.
- 9. Outline Introduction. Basic Function of Drilling Fluids. Types of Drilling Fluids. Drilling Fluid Tests. Challenges Related to Drilling Fluids. Solids Control and Waste Management.
- 10. Drilling Fluid Tests There are two types of tests: Field Tests The drilling-fluids specialist in the field (Mud Engineer) conducts a number of tests to determine the properties of the drilling- fluid system and evaluate treatment needs. Laboratory Tests Extensive testing of fluid is performed in the design of the fluid; either to achieve fluid characteristics or to determine the performance limitations of the fluid.
- 11. Drilling Fluid Tests Field Tests:
- 12. Drilling Fluid Tests Field Tests: (Cont.)
- 13. Drilling Fluid Tests Field Tests: (Cont.)
- 14. Drilling Fluid Tests Field Tests: (Cont.)
- 15. Drilling Fluid Tests Laboratory Tests:
- 16. Outline Introduction Basic Function of Drilling Fluids Types of Drilling Fluids Drilling Fluid Tests Challenges Related to Drilling Fluids Solids Control and Waste Management
- 17. Challenges Related to Drilling Fluids • All drilling challenges relate to the fundamental objective of maintaining a workable wellbore throughout the well-construction process. • A workable wellbore can be drilled, logged, cased, cemented, and completed with minimal nonproductive time. • The design of the drilling-fluid system is central to achieving this objective.
- 18. Challenges Related to Drilling Fluids (Cont.) Loss of Circulation •Lost circulation always causes nonproductive time that includes the cost of rig time and all the services that support the drilling operation. Solutions Leak-off Test (LOT) Formation Integrity Test (FIT)
- 19. Challenges Related to Drilling Fluids (Cont.) Stuck Pipe •Stuck pipe often is associated with well-control and lost-circulation events, the two other costly disruptions to drilling operations, and is a significant risk in high-angle and horizontal wells. Reasons Solutions • Lubricants for WBFs • Spotting Fluids
- 20. Challenges Related to Drilling Fluids (Cont.) Barite Sag • Barite or weight material sag is a problem of drilling mud and it occurs when weighting materials separate from liquid phase and settle down. • Dangers • Solutions Light Mud Heavy Mud
- 21. Outline Introduction Basic Function of Drilling Fluids Types of Drilling Fluids Drilling Fluid Tests Challenges Related to Drilling Fluids Solids Control and Waste Management
- 22. Solids Control and Waste Management Fundamental Concepts: • Contamination of drilling fluids is a signal if the rig either is not making hole or soon will be stuck in the hole it is making. • Before the mechanical solids-removal equipment, dilution was used to control solids content in the drilling fluid. • The typical dilution procedure calls for dumping a portion of the active drilling-fluid volume to a waste pit and then diluting the solids concentration in the remaining fluid by adding the appropriate base fluid, such as water or synthetic oil.
- 23. Solids Control and Waste Management(Cont.) 1- Solids Concentration • Increasing solids concentration in drilling fluid is a problem for the operator, the drilling contractor, and the fluids provider. • Increasing solids content in a drilling fluid leads to a lower ROP and other problems such as: • High viscosity and gel strength. • High torque and drag. • Stuck pipe caused by filtrate loss. • Poor cement jobs caused by excessive filter cakes.
- 24. Solids Control and Waste Management(Cont.) 2- Particle Size and Surface Area • Drilled solids vary in size from < 1 μm to 15,000 μm in average particle diameter. • Colloidal-sized particles are < 2 μm (average particle diameter) and will not settle out under gravitational forces. • Ultra-fines range from 2 to 44 μm and are unlikely to settle out of a drilling fluid unless it is centrifuged.
- 25. Solids Control and Waste Management(Cont.) 2- Particle Size and Surface Area (Cont.) • In bentonite particles, the exposed surfaces of fine drilled solids contain charges that increase the viscosity and gel strengths of the drilling fluid. • The viscosity and fluid loss properties of a drilling fluid are difficult to control with high concentrations of drilled solids that are < 20 μm. • Today, fluid-technology advances have solved many of the problems that contribute to fines buildup in drilling fluids.
- 26. Solids Control and Waste Management(Cont.) 3- Separation by Settling • Hydro-cyclones, centrifuges, and settling tanks rely on settling velocity to concentrate and separate solids from slurry. • Settling velocity is described mathematically by Stokes’ law which states that the settling velocity is inversely proportional to the viscosity of the liquid or slurry. • Stokes’ Low Vs the settling velocity because of G-force, d the particle diameter, ρp the density of the particle, ρl the density of the liquid, g the acceleration or G-force, η the viscosity of the liquid 𝑉𝑠 ∝ 𝑑2(𝜌 𝑝 −𝜌 𝑙) 𝜂
- 27. Solids Control and Waste Management(Cont.) 4- Screen Selection • Screens are the only solids-control devices that are changed to handle changes in fluid properties or drilling conditions. • Screens generate the bulk of drilling waste and reclaim the bulk of the mud. • Screens must be able to handle the full circulation rate. • Screens are the only devices on a rig that separate solids on the basis of size as mentioned before.
- 28. Solids Control and Waste Management(Cont.) 4- Waste Volumes • The combined waste volume of cuttings that are created while drilling and the excess or spent drilling fluid might be the best measure of performance and cost savings offered by a fluids system. • Minimizing the volume of spent mud and cuttings is the key to effective waste management. • The increase in volume of the wet cuttings stems only partly from the added volume of cavings, washouts, or drilling a non-gauge hole.
- 29. Solids Control and Waste Management(Cont.) Total Fluids Management • This process design is the key to help improve the economics and minimizing the environmental impact of drilling activities. • The most important questions during the planning of the project 1. What equipment best suits the drilling-fluid program and waste-disposal options? 2. What are the solids loading and liquid loading that the equipment must handle? 3. How much time will it take to install equipment, and who will install it? 4. Are pumps, piping, chutes, conveyors, etc., adequate for the intended service?
- 30. Solids Control and Waste Management (Cont.) Total Fluids Management (Cont.) 5. Is there enough power on the rig for the proposed equipment set? 6. Is the space available to install the proposed equipment set? 7. Can the drilling-fluid program be modified to assist the mud- and cuttings-treatment system? 8. What information needs to be collected and reported? 9. What training needs to take place before startup? 10. What safety issues need to be addressed? 11. What environmental issues need to be addressed? 12. What contingency or emergency operations need to be planned?
- 31. Outline Introduction. Basic Function of Drilling Fluids. Types of Drilling Fluids. Drilling Fluid Tests. Challenges Related to Drilling Fluids. Solids Control and Waste Management.
Notas del editor
- The drilling-fluid system, commonly known as the “mud system”, is the single component of the well-construction process that remains in contact with the wellbore throughout the entire drilling operation. Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions. Advances in drilling-fluid technology have made it possible to implement a cost-effective, fit-for-purpose system for each interval in the well-construction process. The active drilling-fluid system comprises a volume of fluid that is pumped with specially designed mud pumps from the surface pits, through the drill string exiting at the bit, up the annular space in the wellbore, and back to the surface for solids removal and maintenance treatments as needed. The capacity of the surface system usually is determined by the rig size, and rig selection is determined by the well design. For example, the active drilling-fluid volume on a deep water well might be several thousand barrels. Much of that volume is required to fill the long drilling riser that connects the rig floor to the seafloor. By contrast, a shallow well on land might only require a few hundred barrels of fluid to reach its objective. A properly designed and maintained drilling fluid performs several essential functions during well construction.
- Transport Cuttings to Surface: Transporting drilled cuttings to surface is the most basic function of drilling fluid, to accomplish this, the fluid should have adequate suspension properties to help ensure that cuttings and commercially added solids such as barite weighing material do not settle during static intervals. Prevent Well-Control Issues: The column of drilling fluid in the well exerts hydrostatic pressure on the wellbore. Under normal drilling conditions, this pressure should balance or exceed the natural formation pressure to help prevent an influx of gas or other formation fluids. As the formation pressures increase, the density of the drilling fluid is increased to help maintain a safe margin and prevent “kicks” or “blowouts”. However, if the density of the fluid becomes too heavy, the formation can break down. Preserve Wellbore Stability: The wellbore should remain stable under static conditions while casing is run to bottom and cemented. The drilling-fluid program should indicate the density and physicochemical properties most likely to provide the best results for a given interval. Minimize Formation Damage: Drilling operations expose the producing formation to the drilling fluid and any solids and chemicals contained in that fluid. Some invasion of fluid filtrate (liquid phase) and/or fine solids into the formation is inevitable. However, this invasion and the potential for damage to the formation can be minimized with careful fluid design that is based on testing performed with cored samples of the formation of interest.
- Cool and Lubricate the Drill string: The bit and drill string rotate at relatively high revolutions per minute (rev/min or RPM) all or part of the time during actual drilling operations. The circulation of drilling fluid through the drill string and up the wellbore annular space helps reduce friction and cool the drill string. The drilling fluid also provides a degree of lubricity to aid the movement of the drill pipe and bottom hole assembly (BHA) through angles that are created intentionally by directional drilling and/or through tight spots that can result from swelling shale. Provide Information About the Wellbore: Because drilling fluid is in continuous contact with the wellbore, it reveals substantial information about the formations being drilled and serves as a conduit for much data collected down hole by tools located on the drill string and through wireline-logging operations performed when the drill string is out of the hole.
- Water-based fluids WBFs: They are used to drill approximately 80% of all wells. The base fluid may be fresh water, seawater, brine or saturated brine. The type of fluid selected depends on anticipated well conditions or on the specific interval of the well being drilled. Some commercial BENTONITE or ATTAPULGITE also may be added to aid in fluid-loss control and to enhance hole-cleaning effectiveness. After surface casing is set and cemented, the operator often continues drilling with a WBF unless well conditions require displacing to an oil- or synthetic-based system. WBFs fall into two broad categories: non dispersed and dispersed. Simple gel-and-water systems used for top hole drilling are non dispersed, as are many of the advanced polymer systems that contain little or no BENTONITE . The natural clays that are incorporated into non dispersed systems are managed through dilution, encapsulation, and/or flocculation. Oil-based fluids OBFs: They were developed and introduced in the 1960s to help address several drilling problems: Formation clays that react, swell, or slough after exposure to WBFs, increasing down hole temperatures, contaminants, and stuck pipe and torque and drag. Oil-based fluids in use today are formulated with diesel, mineral oil, or low-toxicity linear PARAFFINS (that are refined from crude oil). The emulsion should be stable enough to incorporate additional water volume if a down hole water flow is encountered. Barite is used to increase system density, and specially-treated ORGANOPHILIC BENTONITE is the primary VISCOSIFIER in most oil-based systems. The emulsified water phase also contributes to fluid viscosity. ORGANOPHILIC LIGINITIC materials are added to help control low-pressure/low-temperature (LP/LT) and HP/HT fluid loss. Oil-based systems usually contain lime to maintain an elevated pH, resist adverse effects of hydrogen sulfide (H2S) and carbon dioxide (CO2) gases, and enhance emulsion stability. Shale inhibition is one of the key benefits of using an oil-based system. The high-salinity water phase helps to prevent shale from hydrating, swelling, and sloughing into the wellbore. Most conventional oil-based mud (OBM) systems are formulated with calcium-chloride brine, which appears to offer the best inhibition properties for most shale. Synthetic-Based Drilling Fluids: Synthetic-based fluids were developed out of an increasing desire to reduce the environmental impact of offshore drilling operations, but without sacrificing the cost-effectiveness of oil-based systems. Like traditional OBFs, SBFs help maximize ROPs, increase lubricity in directional and horizontal wells, and minimize wellbore-stability problems such as those caused by reactive shale. Field data gathered since the early 1990s confirm that SBFs provide exceptional drilling performance, easily equaling that of diesel- and mineral-oil-based fluids. All-Oil Fluids: Normally, the high-salinity water phase of an invert-emulsion fluid helps to stabilize reactive shale and prevent swelling; however, drilling fluids that are formulated with diesel- or synthetic-based oil and no water phase are used to drill long shale intervals where the salinity of the formation water is highly variable. By eliminating the water phase, the all-oil drilling fluid can preserve shale stability throughout the interval. Pneumatic-Drilling Fluids: Compressed air or gas can be used in place of drilling fluid to circulate cuttings out of the wellbore. Pneumatic fluids fall into one of three categories: air or gas only, aerated fluid, or foam. Pneumatic-drilling operations require specialized equipment to help ensure safe management of the cuttings and formation fluids that return to surface, as well as tanks, compressors, lines, and valves associated with the gas used for drilling or aerating the drilling fluid or foam.
- Field Tests: Although drilling fluid companies might use some tests that are designed for evaluating a proprietary product, the vast majority of field tests are standardized according to American Petroleum Institute Recommended Practices (API RP) for WBFs and OBFs, respectively. Laboratory Tests: In the laboratory setting, testing and equipment are available to determine toxicity, fluid rheology, fluid loss, particle plugging, high-angle sag, dynamic high-angle sag, high-temperature fluid aging, cuttings erosion, shale stability, capillary suction, lubricity, return permeability, X-ray diffraction, and particle-size distribution (PSD). The most popular drilling-fluids suppliers are: Halliburton (Baroid) Baker Hughes Schlumberger (M-I SWACO) Newpark Scomi
- Viscosity exhibited when a specific quantity of fluid is poured through a marsh funnel (typically recorded in seconds per quart).
- API defines sand-sized particles as any material larger than 74 microns (200 mesh) in size.
- Indication of variations from base-fluid formulation caused by surface treatment or contamination from down hole formations. Chemicals are added to drilling fluids for specific purposes. Examples are: Caustic Soda (NaOH), Caustic Potash (KOH), Lime (Ca(OH)2), Chemical de-flocculant (mud thinner), Lignosulfonates (organic acid), Soda Ash (Na2CO3) and Starch.
- Toxicity tests generally are used for offshore applications. An approved laboratory can perform the proper testing to ensure compliance of the fluid or its components.
- loss of Circulation: Losing mud into the oil or gas reservoir can drastically reduce or even eliminate the operator's ability to produce the zone. Prevention is critical, but because lost circulation is such a common occurrence, effective methods of remediation are also a high priority. Because of high cost of most weighted, treated drilling-fluid systems, LCM (lost circulation material) routinely is carried in the active system on many operations in which probable lost-circulation zones exist, such as in a “rubble” zone beneath salt or in a known depleted zone. Other conditions that are prone to loss of circulation include natural and induced fractures, formations with high permeability and/or high porosity, and jugular formations (e.g., limestone and chalk). When a loss zone is encountered, the top priority is keeping the hole full so that the hydrostatic pressure does not fall below formation pressure and allow a kick to occur. The hydrostatic pressure may be purposely reduced to stop the loss, as long as sufficient density is maintained to prevent well-control problems. Loss zones also pose a high risk of differential sticking. Rotating and reciprocating the drillstring helps reduce this risk while an LCM treatment is prepared. If the location of the loss zone is known, it might be advisable to pull the drillstring to above the affected area. Severe lost-circulation problems that do not respond to conventional treatments might be curable by spotting a hydra-table LCM pill and holding it under gentle squeeze pressure for a predetermined period. At down hole temperatures, the LCM pill expands rapidly to fill and bridge fractures, allowing drilling and cementing operations to resume quickly, sometimes in 4 hours or less. Alternatively, rapid-set LCM products are available that react quickly with the drilling fluid after being spotted across the loss zone and form a dense, flexible plug that fills the fracture and adheres to the wellbore. In some cases, this type of plug has proved so effective that the natural fracture gradient of the formation actually increased, allowing the operator to resume drilling and increase the mud weight beyond constraints established before the treatment. Leak-of Test (LOT): Conducting an accurate leak-off test is fundamental to preventing lost circulation. The LOT is performed by closing in the well and pressuring up in the open hole immediately below the last string of casing before drilling ahead in the next interval. On the basis of the point at which the pressure drops off, the test indicates the strength of the wellbore at the casing seat(shoe), typically considered one of the weakest points in any interval. However, extending an LOT to the fracture extension stage can seriously lower the maximum mud weight that may be used to safely drill the interval without lost circulation. Consequently, stopping the test as early as possible after the pressure plot starts to break over is preferred. Formation Integrity Test (FIT): to avoid breaking down the formation, many operators perform a FIT at the casing seat to determine whether the wellbore will tolerate the maximum mud weight anticipated while drilling the interval. If the casing seat holds pressure that is equivalent to the prescribed mud density, the test is considered successful and drilling resumes. When an operator chooses to perform a LOT or a FIT, if the test fails, some remediation effort, typically a cement squeeze, should be carried out before drilling resumes to ensure that the wellbore is competent.
- Stuck Pipe: Complications related to stuck pipe can account for nearly half of total well cost, making stuck pipe one of the most expensive problems that can occur during a drilling operation. Stuck pipe is often associated with well-control and lost-circulation events, the two other costly disruptions to drilling operations, and is a significant risk in high-angle and horizontal wells. Drilling through depleted zones, where the pressure in the annulus exceeds that in the formation, might cause the drillstring to be pulled against the wall and embedded in the filter cake deposited there. The internal cake pressure decreases at the point where the drillpipe contacts the filter cake, causing the pipe to be held against the wall by differential pressure. In high-angle and horizontal wells, gravitational force contributes to extended contact between the drillstring and the formation. Properly managing the lubricity of the drilling fluid and the quality of the filter cake across the permeable formation can help reduce occurrences of stuck pipe. Mechanical causes for stuck pipe include keyseating, pack off from poor hole-cleaning, shale swelling, wellbore collapse, plastic-flowing formation (i.e., salt), and bridging. Preventing stuck pipe can require close monitoring of early warning signs, such as increases in torque and drag, indications of excessive cuttings loading, encountering tight spots while tripping, and experiencing loss of circulation while drilling. Depending on what the suspected cause of sticking is, it might be necessary to increase the drilling-fluid density (to stabilize a swelling shale) or to decrease it (to protect the depleted zone and avoid differential sticking). A drilling fluid's friction coefficient is an important factor in its effectiveness in preventing stuck pipe and/or enabling stuck pipe to be worked free. OBFs and SBFs (Oil-based fluids and Synthetic-based fluids)offer the maximum lubricity; inhibitive WBFs (Water-based fluids)can be treated with a lubricant (typically 1 to 5% by volume) and formulated to produce a thin, impermeable filter cake that offers increased protection against sticking. High-performance-polymer WBFs that are designed specifically to serve as alternates to OBFs and SBFs exhibit a high degree of natural lubricity and might not require the addition of a lubricant. Lubricants for WBFs. The quality of the emulsion is important to a lubricant’s performance in WBF. If the lubricant is too tightly emulsified, it no longer functions as a lubricant. If the emulsion is too loose, there is a risk that the lubricant will destabilize into a stringy, semisolid material. Overtreatment with lubricants might cause flocculation of the drilling fluid because of oil-wet solids. Film strength is the main indicator of lubricant performance; generally, the higher the strength, the better the lubricant performance. However, environmental issues might arise with the use of certain high-film-strength lubricants. For this reason, alcohol/glycol-type lubricants, considered to be more environmentally friendly, have gained popularity. Maximum film strength is required under high-pressure conditions and where elevated torque and drag measurements indicate a high risk of stuck pipe. Sulfurized oils (e.g., sulfurized olefin) have proved effective under these conditions. High-film-strength lubricants generally demonstrate increased thermal stability. Other lubricant types include glass, plastic, and ceramic beads. Spotting fluids Spotting fluids are used to free stuck pipe are formulated to first crack the filter cake and then provide sufficient lubricity to allow the pipe to be worked free. Time is the key factor in successfully freeing stuck pipe. Spotting fluids routinely are included in rig site inventory so that the spotting fluid can be applied as soon as possible after the pipe sticks, ideally within 6 hours. The length of free pipe may be estimated on the basis of drillstring stretch measurements, allowing the operator to determine the stuck point and deliver the spotting fluid as accurately as possible. If circulation is possible, decreasing the drilling-fluid density might relieve differential sticking; however, stuck pipe might be caused by a well kick combined with loss of circulation in a higher zone, which would eliminate the option of an intentional reduction in mud weight.
- Barite sag: It can occur in high-angle wells (possibly at 35°, but increasingly likely at ≥ 50°, then diminishing as the interval approaches 75 to 90°). The most severe sag incidents typically occur in the 45 to 65° range. Sag causes a decrease in drilling-fluid density, which is particularly noticeable when circulating bottoms up after a long non circulating period. The barite falls to the low side of the wellbore and slides toward the bottom, creating an accumulation of weighted silt around the lower part of the drillstring.
- The fundamentals behind the process of solid control. • Solids concentration matters—increasing solids content is detrimental to fluid performance. • Economics matter—mechanical removal of solids costs less than dilution. • Volume matters—the volume of waste generated is indicative of performance. • Size matters—fine solids are the most detrimental and difficult to remove. • Stokes’ law matters—viscosity and density affect gravity separations. • Shaker-screen selection matters—shaker screens make the only separation based on size. • Footprint matters—the space available for equipment on rigs always is limited.