How Do Drilling Fluids Work?

Cuttings in Circulating Driling FluidsSource: Oil & Gas UK

Drilling deeper, longer and more challenging wells has been made possible by improvements in drilling technologies, including more efficient and effective drilling fluids. Drilling fluids, also referred to as drilling mud, are added to the wellbore to facilitate the drilling process by suspending cuttings, controlling pressure, stabilizing exposed rock, providing buoyancy, and cooling and lubricating.

As early as the third century BC, the Chinese were using drilling fluids, in the form of water, to help permeate the ground when drilling for hydrocarbons. The term "mud" was coined when at Spindletop in the US, drillers ran a herd of cattle through a watered-down field and used the resulting mud to lubricate the drill.

While the technology and chemistry of drilling fluids have become much more complex, the concept has remained the same. Drilling fluids are essential to drilling success, both maximizing recovery and minimizing the amount of time it takes to achieve first oil.

Purposes Of Drilling Fluid

During drilling, cuttings are obviously created, but they do not usually pose a problem until drilling stops because a drillbit requires replacement or another problem. When this happens, and drilling fluids are not used, the cuttings then fill the hole again. Drilling fluids are used as a suspension tool to keep this from happening. The viscosity of the drilling fluid increases when movement decreases, allowing the fluid to have a liquid consistency when drilling is occurring and then turn into a more solid substance when drilling has stopped. Cuttings are then suspended in the well until the drill is again inserted. This gel-like substance then transforms again into a liquid when drilling starts back up.

Drilling fluids also help to control pressure in a well by offsetting the pressure of the hydrocarbons and the rock formations. Weighing agents are added to the drilling fluids to increase its density and, therefore, its pressure on the walls of the well.

Another important function of drilling fluids is rock stabilization. Special additives are used to ensure that the drilling fluid is not absorbed by the rock formation in the well and that the pores of the rock formation are not clogged.

The longer the well, the more drill pipe is needed to drill the well. This amount of drill pipe gets heavy, and the drilling fluid adds buoyancy, reducing stress. Additionally, drilling fluid helps to reduce friction with the rock formation, reducing heat. This lubrication and cooling helps to prolong the life of the drillbit.

Drilling FluidsSource: OSHA

Types Of Drilling Fluids

Drilling fluids are water-, oil- or synthetic-based, and each composition provides different solutions in the well. If rock formation is composed of salt or clay, proper action must be taken for the drilling fluids to be effective. In fact, a drilling fluid engineer oversees the drilling, adding drilling fluid additives throughout the process to achieve more buoyancy or minimize friction, whatever the need may be.

In addition to considering the chemical composition and properties of the well, a drilling fluid engineer must also take environmental impact into account when prescribing the type of drilling fluid necessary in a well. Oil-based drilling fluids may work better with a saltier rock. Water-based drilling fluids are generally considered to affect the environment less during offshore drilling.

Disposal of drilling fluids after they are used can also be a challenge. Recent technological advances have established methods for recycling drilling fluids.

Drilling Fluid Functions

Fig. 1. Drilling fluid (mud)

Drilling fluid is an important component in the drilling process. A fluid is required in the wellbore to:

Cool and lubricate the drill bit,

Remove the rock fragments, or drill cuttings, from the drilling area and transport them to the surface,

Counterbalance formation pressure to prevent formation fluids (such as oil, gas, and water) from entering the well prematurely (which can lead to a blowout), and

Prevent the open (uncased) wellbore from caving in.

Drilling Fluid Types

There are several types of drilling fluids used depending on the drilling conditions encountered:

Water-based muds are used most frequently. The base may be either:

fresh water, or

salt water.

Oil-based muds.

Synthetic materials. The oil and gas extraction industry has developed many new oleaginous (oil-like) base materials from which to formulate high-performance drilling fluids.

A general class of these fluids is called synthetic materials, such as

The vegetable esters,

Poly alpha olefins,

Internal olefins,

Linear alpha olefins,

Synthetic paraffins,

Ethers, and

Linear alkylbenzenes, among others.

Air and foam fluids may be used in drilling wells.

These fluids are less dense than drilling muds.

Drilling Fluid Additives

Fig. 2. Additive mixing hopper

Drilling muds typically have several additives. (Air and foam fluids typically do not contain many additives because the additives are either liquid or solid, and will not mix with air and foam drilling fluids.) The following is a list of the more significant additives:

Weighting materials, primarily barite (barium sulfate), may be used to increase the density of the mud in order to equilibrate the pressure between the wellbore and formation when drilling through particularly pressurized zones. Hematite (Fe2O3 ) sometimes is used as a weighting agent in oil-based muds (Souders, 1998).

Corrosion inhibitors such as iron oxide, aluminum bisulfate, zinc carbonate, and zinc chromate protect pipes and other metallic components from acidic compounds encountered in the formation.

Dispersants, including iron lignosulfonates, break up solid clusters into small particles so they can be carried by the fluid.

Flocculants, primarily acrylic polymers, cause suspended particles to group together so they can be removed from the fluid at the surface.

Surfactants, like fatty acids and soaps, defoam and emulsify the mud.

Biocides, typically organic amines, chlorophenols, or formaldehydes, kill bacteria and help

reduce the souring of drilling mud.

Fluid loss reducers include starch and organic polymers and limit the loss of drilling mud to under-pressurized or high-permeability formations.

Drilling fluid typesThere are several different types of drilling fluids, based on both their composition and use. The three key factors that drive decisions about the type of drilling fluid selected for a specific well are:

Cost Technical performance Environmental impact.

Selecting the correct type of fluid for the specific conditions is an important part of successful drilling operations.

Contents

 [hide] 

1 Classification of drilling fluidso 1.1 Water-based fluids

1.1.1 Nondispersed sytems 1.1.2 Dispersed systems 1.1.3 Saltwater drilling fluids 1.1.4 Polymer drilling fluids

o 1.2 Drill-in fluidso 1.3 Oil-based fluidso 1.4 Synthetic-based drilling fluidso 1.5 All-oil fluidso 1.6 Pneumatic-drilling fluidso 1.7 Specialty products

1.7.1 Lost-circulation materials 1.7.2 Spotting fluids 1.7.3 Lubricants 1.7.4 Corrosion, inhibitors, biocides, and scavengers

2 References3 Noteworthy papers in OnePetro4 External links5 See also

Classification of drilling fluidsWorld Oil’s annual classification of fluid systems[1] lists nine distinct categories of drilling fluids, including:

Freshwater systems Saltwater systems Oil- or synthetic-based systems Pneumatic (air, mist, foam, gas) “fluid” systems

Three key factors usually determine the type of fluid selected for a specific well:

Cost Technical performance Environmental impact

Water-based fluids (WBFs) are the most widely used systems, and are considered less expensive than oil-based fluids (OBFs) or synthetic-based fluids (SBFs). The OBFs and SBFs—also known as invert-emulsion systems—have an oil or synthetic base fluid as the continuous(or external) phase, and brine as the internal phase. Invert-emulsion systems have a higher cost per unit than most water-based fluids, so they often are selected when well conditions call for reliable shale inhibition and/or excellent lubricity. Water-based systems and invert-emulsion systems can be formulated to tolerate relatively high downhole temperatures. Pneumatic systems most commonly are implemented in areas where formation pressures are relatively low and the risk of lost circulation or formation damage is relatively high. The use of these systems requires specialized pressure-management equipment to help prevent the development of hazardous conditions when hydrocarbons are encountered.

Water-based fluidsWater-based fluids (WBFs) are used to drill approximately 80% of all wells. [2] The base fluid may be fresh water, seawater, brine, saturated brine, or a formate brine. The type of fluid selected depends on anticipated well conditions or on the specific interval of the well being drilled. For example, the surface interval typically is drilled with a low-density water- or seawater-based mud that contains few commercial additives. These systems incorporate natural clays in the course of the drilling operation. 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: nondispersed and dispersed.

Nondispersed sytems

Simple gel-and-water systems used for tophole drilling are nondispersed, as are many of the advanced polymer systems that contain little or no bentonite. The natural clays that are incorporated into nondispersed systems are managed through dilution, encapsulation, and/or flocculation. A properly designed solids-control system can be used to remove fine solids from the mud system and help maintain drilling efficiency. The low-solids, nondispersed (LSND) polymer systems rely on high- and low-molecular-weight long-chain polymers to provide viscosity and fluid-loss control. Low-colloidal solids are encapsulated and flocculated for more efficient removal at the surface, which in turn decreases dilution requirements. Specially developed high-temperature polymers are available to help overcome gelation issues that might occur on high-pressure, high-temperature (HP/HT) wells.[3] With proper treatment, some LSND systems can be weighted to 17.0 to 18.0 ppg and run at 350°F and higher.

Dispersed systems

Dispersed systems are treated with chemical dispersants that are designed to deflocculate clay particles to allow improved rheology control in higher-density muds. Widely used dispersants include

lignosulfonates, lignitic additives, and tannins. Dispersed systems typically require additions of caustic soda (NaOH) to maintain a pH level of 10.0 to 11.0. Dispersing a system can increase its tolerance for solids, making it possible to weight up to 20.0 ppg. The commonly used lignosulfonate system relies on relatively inexpensive additives and is familiar to most operator and rig personnel. Additional commonly used dispersed muds include lime and other cationic systems. A solids-laden dispersed system also can decrease the rate of penetration significantly and contribute to hole erosion.

Saltwater drilling fluids

Saltwater drilling fluids often are used for shale inhibition and for drilling salt formations. They also are known to inhibit the formation of ice-like hydrates that can accumulate around subsea wellheads and well-control equipment, blocking lines and impeding critical operations. Solids-free and low-solids systems can be formulated with high-density brines, such as:

Calcium chloride Calcium bromide Zinc bromide Potassium and cesium formate

Polymer drilling fluids

Polymer drilling fluids are used to drill reactive formations where the requirement for shale inihbition is significant. Shale inhibitors frequently used are salts, glycols and amines, all of which are incompatible with the use of bentonite. These systems typically derive their viscosity profile from polymers such as xanthan gum and fluid loss control from starch or cellulose derivatives. Potassium chloride is an inexpensive and highly effective shale inhibitor which is widely used as the base brine for polymer drilling fluids in many parts of the world. Glycol and amine-based inhibitors can be added to further enhance the inhibitive properties of these fluids.

Drill-in fluidsDrilling into a pay zone with a conventional fluid can introduce a host of previously undefined risks, all of which diminish reservoir connectivity with the wellbore or reduce formation permeability. This is particularly true in horizontal wells, where the pay zone can be exposed to the drilling fluid over a long interval. Selecting the most suitable fluid system for drilling into the pay zone requires a thorough understanding of the reservoir. Using data generated by lab testing on core plugs from carefully selected pay zone cores, a reservoir-fluid-sensitivity study should be conducted to determine the morphological and mineralogical composition of the reservoir rock. Natural reservoir fluids should be analyzed to establish their chemical makeup. The degree of damage that could be caused by anticipated problems can be modeled, as can the effectiveness of possible solutions for mitigating the risks.

A drill-in fluid (DIF) is a clean fluid that is designed to cause little or no loss of the natural permeability of the pay zone, and to provide superior hole cleaning and easy cleanup. DIFs can be:

Water-based Brine-based Oil-based Synthetic-based

In addition to being safe and economical for the application, a DIF should be compatible with the reservoir’s native fluids to avoid causing precipitation of salts or production of emulsions. A suitable nondamaging fluid should establish a filter cake on the face of the formation, but should not penetrate too far into the formation pore pattern. The fluid filtrate should inhibit or prevent swelling of reactive clay particles within the pore throats.

Formation damage commonly is caused by:

Pay zone invasion and plugging by fine particles Formation clay swelling Commingling of incompatible fluids Movement of dislodged formation pore-filling particles Changes in reservoir-rock wettability Formation of emulsions or water blocks

Once a damage mechanism has diminished the permeability of a reservoir, it seldom is possible to restore the reservoir to its original condition.

Oil-based fluidsOil-based systems 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 downhole temperatures Contaminants Stuck pipe and torque and drag

Oil-based fluids (OBFs) in use today are formulated with diesel, mineral oil, or low-toxicity linear olefins and paraffins. The olefins and paraffins are often referred to as "synthetics" although some are derived from distillation of crude oil and some are chemically synthesised from smaller molecules. The electrical stability of the internal brine or water phase is monitored to help ensure that the strength of the emulsion is maintained at or near a predetermined value. The emulsion should be stable enough to incorporate additional water volume if a downhole 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 lignitic, asphaltic and polymeric materials are added to help control HP/HT(High pressure/High temperature) fluid loss. Oil-wetting is essential for ensuring that particulate materials remain in suspension. The surfactants used for oil-wetting also can work as thinners. 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 shales 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 shales.

The ratio of the oil percentage to the water percentage in the liquid phase of an oil-based system is called its oil/water ratio. Oil-based systems generally function well with an oil/water ratio in the range from 65/35 to 95/5, but the most commonly observed range is from 70/30 to 90/10.

The discharge of whole fluid or cuttings generated with OBFs is not permitted in most offshore-drilling areas. All such drilled cuttings and waste fluids are processed, and shipped to shore for disposal. Whereas many land wells continue to be drilled with diesel-based fluids, the development of synthetic-based fluids (SBFs) in the late 1980s provided new options to offshore operators who depend on the drilling performance of oil-based systems to help hold down overall drilling costs but require more environmentally-friendly fluids. In some areas of the world such as the North Sea, even these fluids are prohibited for offshore discharge.

Synthetic-based drilling fluidsSynthetic-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 can be used to:

Maximize rate of penetrations (ROPs) Increase lubricity in directional and horizontal wells Minimize wellbore-stability problems, such as those caused by reactive shales

Field data gathered since the early 1990s confirm that SBFs provide exceptional drilling performance, easily equaling that of diesel- and mineral-oil-based fluids.

In many offshore areas, regulations that prohibit the discharge of cuttings drilled with OBFs do not apply to some of the synthetic-based systems. SBFs’ cost per barrel can be higher, but they have proved economical in many offshore applications for the same reasons that traditional OBFs have: fast penetration rates and less mud-related nonproductive time (NPT). SBFs that are formulated with linear alphaolefins (LAO) and isomerized olefins (IO) exhibit the lower kinematic viscosities that are required in response to the increasing importance of viscosity issues as operators move into deeper waters. Early ester-based systems exhibited high kinematic viscosity, a condition that is magnified in the cold temperatures encountered in deepwater risers. However, a shorter-chain-length (C8), low-viscosity ester that was developed in 2000 exhibits viscosity similar to or lower than that of the other base fluids, specifically the heavily used IO systems. Because of their high biodegradability and low toxicity, esters are universally recognized as the best base fluid for environmental performance.

By the end of 2001, deepwater wells were providing 59%; of the oil being produced in the Gulf of Mexico.[4] Until operators began drilling in these deepwater locations, where the pore pressure/fracture gradient (PP/FG) margin is very narrow and mile-long risers are not uncommon, the standard synthetic formulations provided satisfactory performance. However, the issues that arose because of deepwater drilling and changing environmental regulations prompted a closer examination of several seemingly essential additives.

When cold temperatures are encountered, conventional SBFs might develop undesirably high viscosities as a result of the organophilic clay and lignitic additives in the system. The introduction of SBFs formulated with zero or minimal additions of organophilic clay and lignitic products allowed

rheological and fluid-loss properties to be controlled through the fluid-emulsion characteristics. The performance advantages of these systems include:

High, flat gel strengths that break with minimal initiation pressure Significantly lower equivalent circulating densities (ECDs) Reduced mud losses while drilling, running casing, and cementing

All-oil fluidsNormally, 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 fluidsCompressed 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 Foam[5]

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.

Except when drilling through high-pressure hydrocarbon- or fluid-laden formations that demand a high-density fluid to prevent well-control issues, using pneumatic fluids offers several advantages [6]:

Little or no formation damage Rapid evaluation of cuttings for the presence of hydrocarbons Prevention of lost circulation Significantly higher penetration rates in hard-rock formations

Specialty productsDrilling-fluid service companies provide a wide range of additives that are designed to prevent or mitigate costly well-construction delays. Examples of these products include:

Lost-circulation materials (LCM) that help to prevent or stop downhole mud losses into weak or depleted formations.

Spotting fluids that help to free stuck pipe. Lubricants for WBFs that ease torque and drag and facilitate drilling in high-angle environments. Protective chemicals (e.g., scale and corrosion inhibitors, biocides, and H2S scavengers) that

prevent damage to tubulars and personnel.

Lost-circulation materials

Many types of LCM are available to address loss situations:

Sized calcium carbonate Mica Fibrous material Cellophane Crushed walnut shells

The development of deformable graphitic materials that can continuously seal off fractures under changing pressure conditions has allowed operators to cure some types of losses more consistently. The application of these and similar materials to prevent or slow down the physical destabilisation of the wellbore has proved successful. Hydratable and rapid-set lost-circulation pills also are effective for curing severe and total losses. Some of these fast-acting pills can be mixed and pumped with standard rig equipment, while others require special mixing and pumping equipment.

Spotting fluids

Most spotting fluids are designed to penetrate and break up the wall cake around the drillstring. A soak period usually is required to achieve results. Spotting fluids typically are formulated with a base fluid and additives that can be incorporated into the active mud system with no adverse effects after the pipe is freed and/or circulation resumes.

Lubricants

Lubricants might contain hydrocarbon-based materials, or can be formulated specifically for use in areas where environmental regulations prohibit the use of an oil-based additive. Tiny glass or polymer beads also can be added to the drilling fluid to increase lubricity. Lubricants are designed to reduce friction in metal-to-metal contact, and to provide lubricity to the drillstring in the open hole, especially in deviated wells, where the drillstring is likely to have continuous contact with the wellbore.

Corrosion, inhibitors, biocides, and scavengers

Corrosion causes the majority of drillpipe loss and damages casing, mud pumps, bits, and downhole tools. As downhole temperatures increase, corrosion also increases at a corresponding rate, if the drillstring is not protected by chemical treatment. Abrasive materials in the drilling fluid can accelerate corrosion by scouring away protective films. Corrosion, typically, is caused by one or more factors that include:

Exposure to oxygen, H2S, and/or CO2

Bacterial activity in the drilling fluid High-temperature environments Contact with sulfur-containing materials

Drillstring coupons can be inserted between joints of drillpipe as the pipe is tripped in the hole. When the pipe next is tripped out of the hole, the coupon can be examined for signs of pitting and corrosion to determine whether the drillstring components are undergoing similar damage.

H2S and CO2 frequently are present in the same formation. Scavenger and inhibitor treatments should be designed to counteract both gases if an influx occurs because of underbalanced drilling conditions.

Maintaining a high pH helps control H2S and CO2, and prevents bacteria from souring the drilling fluid. Bacteria also can be controlled using a microbiocide additive.

References

1. ↑  World Oil 2004 Drilling, Completion and Workover Fluids. 2004. World Oil 225 (6): F-1.2. ↑  Oilfield Market Report 2004. Spears & Assoc. Inc., Tulsa,

Oklahoma, www.spearsresearch.com.3. ↑  Mason, W. and Gleason, D. 2003. System Designed for Deep, Hot Wells. American Oil and

Gas Reporter 46 (8): 70.4. ↑  Deepwater Production Summary by Year, Gulf of Mexico Region, Offshore Information.

Minerals Management Service, U.S. Dept. of the Interior, www.gomr.mms.gov/homepg/offshore/deepwatr/summary.asp.

5. ↑  Lyons, W.C., Guo, B., and Seidel, F. 2001. Air and Gas Drilling Manual. New York: McGraw-Hill.

6. ↑  Negrao, A.F., Lage, A.C.V.M., and Cunha, J.C. 1999. An Overview of Air/Gas/Foam Drilling in Brazil. SPE Drill & Compl14 (2): 109-114. SPE-56865-PA. http://dx.doi.org/10.2118/56865-PA

Drilling fluidFrom Wikipedia, the free encyclopedia

This article is about fluids used when drilling a well. For fluids used with drill bits during metal working, see cutting fluid.

This article includes a list of references, but its sources remain unclear because it has insufficient inline citations.Please help to improve this article by introducing more precise citations. (June

2008)

Driller pouring anti-foaming agent down the rod string on a drilling rig

Barite powder used for preparation of water base mud

In geotechnical engineering, drilling fluid is used to aid the drilling of boreholes into the earth. Often used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells. Liquid drilling fluid is often called drilling mud. The three main categories of drilling fluids are water-based muds (which can be dispersed and non-dispersed), non-aqueous muds, usually called oil-based mud, and gaseous drilling fluid, in which a wide range of gases can be used.

The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoidformation damage and to limit corrosion.

Contents

1   Types of drilling fluid

2   Function

o 2.1   Remove cuttings from well

o 2.2   Suspend and release cuttings

o 2.3   Control formation pressures

o 2.4   Seal permeable formations

o 2.5   Maintain wellbore stability

o 2.6   Minimizing formation damage

o 2.7   Cool, lubricate, and support the bit and drilling assembly

o 2.8   Transmit hydraulic energy to tools and bit

o 2.9   Ensure adequate formation evaluation

o 2.10   Control corrosion (in acceptable level)

o 2.11   Facilitate cementing and completion

o 2.12   Minimize impact on environment

3   Composition of drilling mud

4   Factors influencing drilling fluid performance

5   Drilling mud classification

o 5.1   Dispersed systems

o 5.2   Non-dispersed systems

6   Mud engineer

7   Compliance engineer

8   See also

9   References

10   Further reading

11   External links

Types of drilling fluid[edit]

Many types of drilling fluids are used on a day-to-day basis. Some wells require that different types be used at different parts in the hole, or that some types be used in combination with others. The various types of fluid generally fall into a few broad categories:[1]

Air: Compressed air is pumped either down the bore hole's annular space or down the drill string itself.

Air/water: The same as above, with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.

Air/polymer: A specially formulated chemical, most often referred to as a type of polymer, is added to the water & air mixture to create specific conditions. A foaming agent is a good example of a polymer.

Water: Water by itself is sometimes used.

Water-based mud (WBM): Most basic water-based mud systems begin with water, then clays and other chemicals are incorporated into the water to create a homogeneous blend resembling something between chocolate milk and a malt (depending on viscosity). The clay (called "shale" in its rock form) is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel". Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment.

Oil-based mud (OBM): Oil-based mud is a mud where the base fluid is a petroleum product such as diesel fuel. Oil-based muds are used for many reasons, including increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special

considerations, including cost, environmental considerations such as disposal of cuttings in an appropriate place, and the exploratory disadvantages of using oil-based mud, especially in wildcat wells. Using an oil-based mud interferes with the geochemical analysis of cuttings and cores and with the determination of API gravitybecause the base fluid cannot be distinguished from oil returned from the formation.

Synthetic-based fluid (SBM) (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): Synthetic-based fluid is a mud where the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less than an oil-based fluid. This is important when men work with the fluid in an enclosed space such as an offshore drilling rig. Synthetic-based fluid poses the same environmental and analysis problems as oil-based fluid.

On a drilling rig, mud is pumped from the mud pits through the drill string where it sprays out of nozzles on the drill bit, cleaning and cooling the drill bit in the process. The mud then carries the crushed or cut rock ("cuttings") up the annular space ("annulus") between the drill string and the sides of the hole being drilled, up through the surface casing,where it emerges back at the surface. Cuttings are then filtered out with either a shale shaker, or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits let the drilled "fines" settle; the pits are also where the fluid is treated by adding chemicals and other substances.

Fluid Pit

The returning mud can contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas. Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certifiedequipment is commonly installed, and workers are advised to take safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure properties which optimize and improve drilling efficiency, borehole stability, and other requirements listed below.

Function[edit]

The main functions of a drilling mud can be summarized as follows:

Remove cuttings from well[edit]

Mud Pit

Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to do so depends on cutting size, shape, and density, and speed of fluid traveling up the well (annular velocity). These considerations are analogous to the ability of a stream to carry sediment; large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water. The mud viscosity is another important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Fly Ash Absorbent for Fluids in Mud Pits

Other properties include:

Most drilling muds are thixotropic (that is, they become a gel under static conditions). This characteristic keeps the cuttings suspended when the mud is not moving during, for example, maintenance.

Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning.

Higher annular velocity improves cutting transport. Transport ratio (transport velocity / lowest annular velocity) should be at least 50%.

High density fluids may clean hole adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings). But may have a negative impact if mud

weight is in excess of that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning purposes.

Higher rotary drill-string speeds introduce a circular component to annular flow path. This helical flow around the drill-string causes drill cuttings near the wall, where poor hole cleaning conditions occur, to move into higher transport regions of the annulus. Increased rotation are the best methods in high angle and horizontal beds.

Suspend and release cuttings[edit]

Must suspend drill cuttings, weight materials and additives under a wide range of conditions.

Drill cuttings that settle can causes bridges and fill, which can cause stuck-pipe and lost circulation.

Weight material that settles is referred to as sag, this causes a wide variation in the density of well fluid, this more frequently occurs in high angle and hot wells.

High concentrations of drill solids are detrimental to:

Drilling efficiency (it causes increased mud weight and viscosity, which in turn increases

maintenance costs and increased dilution)

Rate of Penetration (ROP) (increases horsepower required to circulate)

Mud properties that are suspended must be balanced with properties in cutting removal

by solids control equipment

For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well. If re-circulated, cuttings break into smaller pieces and are more difficult to remove.

Conduct a test to compare the sand content of mud at flow line and suction pit (to determine whether cuttings are being removed).

Control formation pressures[edit]

If formation pressure increases, mud density should also be increased, often with barite (or other weighting materials) to balance pressure and keep the wellbore stable. Unbalanced formation pressures will cause an unexpected influx of pressure in the wellbore possibly leading to a blowout from pressured formation fluids.

Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity. If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.

Well control means no uncontrollable flow of formation fluids into the wellbore.

Hydrostatic pressure also controls the stresses caused by tectonic forces, these may make wellbores unstable even when formation fluid pressure is balanced.

If formation pressure is subnormal, air, gas, mist, stiff foam, or low density mud (oil base) can be used.

In practice, mud density should be limited to the minimum necessary for well control and wellbore stability. If too great it may fracture the formation.

Seal permeable formations[edit]

Mud column pressure must exceed formation pressure, in this condition mud filtrate invades the formation, and a filter cake of mud is deposited on the wellbore wall.

Mud is designed to deposit thin, low permeability filter cake to limit the invasion.

Problems occur if a thick filter cake is formed; tight hole conditions, poor log quality, stuck pipe, lost circulation and formation damage.

In highly permeable formations with large bore throats, whole mud may invade the formation, depending on mud solids size;

Use bridging agents to block large opening, then mud solids can form seal.

For effectiveness, bridging agents must be over the half size of pore spaces / fractures.

Bridging agents (e.g. calcium carbonate, ground cellulose).

Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).

Maintain wellbore stability[edit]

Chemical composition and mud properties must combine to provide a stable wellbore. Weight of the mud must be within the necessary range to balance the mechanical forces.

Wellbore instability = sloughing formations, which can cause tight hole conditions, bridges and fill on trips (same symptoms indicate hole cleaning problems).

Wellbore stability = hole maintains size and cylindrical shape.

If the hole is enlarged, it becomes weak and difficult to stabilize, resulting in problems such as low annular velocities, poor hole cleaning, solids loading and poor formation evaluation

In sand and sandstones formations, hole enlargement can be accomplished by mechanical actions (hydraulic forces & nozzles velocities). Formation damage is reduced by conservative hydraulics system. A good quality filter cake containing bentonite is known to limit bore hole enlargement.

In shales, mud weight is usually sufficient to balance formation stress, as these wells are usually stable. With water base mud, chemical differences can cause interactions between mud & shale that lead to softening of the native rock. Highly fractured, dry, brittle shales can be extremely unstable (leading to mechanical problems).

Various chemical inhibitors can control mud / shale interactions (calcium, potassium, salt, polymers, asphalt, glycols and oil – best for water sensitive formations)

Oil (and synthetic oil) based drilling fluids are used to drill most water sensitive Shales in areas with difficult drilling conditions.

To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are used to reduce water activity and creates osmotic forces to prevent adsorption of water by Shales.

Minimizing formation damage[edit]

Skin damage or any reduction in natural formation porosity and permeability (washout) constitutes formation damage

Most common damage;

Mud or drill solids invade the formation matrix, reducing porosity and causing skin effect

Swelling of formation clays within the reservoir, reduced permeability

Precipitation of solids due to mixing of mud filtrate and formations fluids resulting in the

precipitation of insoluble salts

Mud filtrate and formation fluids form an emulsion, reducing reservoir porosity

Specially designed drill-in fluids or workover and completion fluids, minimize formation damage.

Cool, lubricate, and support the bit and drilling assembly[edit]

Heat is generated from mechanical and hydraulic forces at the bit and when the drill string rotates and rubs against casing and wellbore.

Cool and transfer heat away from source and lower to temperature than bottom hole.

If not, the bit, drill string and mud motors would fail more rapidly.

Lubrication based on the coefficient of friction. Oil- and synthetic-based mud generally lubricate better than water-based mud (but the latter can be improved by the addition of lubricants).

Amount of lubrication provided by drilling fluid depends on type & quantity of drill solids and weight materials + chemical composition of system.

Poor lubrication causes high torque and drag, heat checking of the drill string, but these problems are also caused by key seating, poor hole cleaning and incorrect bottom hole assemblies design.

Drilling fluids also support portion of drill-string or casing through buoyancy. Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick.

Weight that derrick can support limited by mechanical capacity, increase depth so weight of drill-string and casing increase.

When running long, heavy string or casing, buoyancy possible to run casing strings whose weight exceed a rig's hook load capacity.

Transmit hydraulic energy to tools and bit[edit]

Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.

Limited to:

Pump horsepower

Pressure loss inside drillstring

Maximum allowable surface pressure

Optimum flow rate

Drill string pressure loses higher in fluids higher densities, plastic viscosities and solids.

Low solids, shear thinning drilling fluids such as polymer fluids, more efficient in transmit hydraulic energy.

Depth can be extended by controlling mud properties.

Transfer information from MWD & LWD to surface by pressure pulse.

Ensure adequate formation evaluation[edit]

Chemical and physical mud properties and wellbore conditions after drilling affect formation evaluation.

Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.

Wireline logging measure – electrical, sonic, nuclear and magnetic resonance.

Potential productive zone are isolated and performed formation testing and drill stem testing.

Mud helps not to disperse of cuttings and also improve cutting transport for mud loggers determine the depth of the cuttings originated.

Oil-based mud, lubricants, asphalts will mask hydrocarbon indications.

So mud for drilling core selected base on type of evaluation to be performed (many coring operations specify a blend mud with minimum of additives).

Control corrosion (in acceptable level)[edit]

Drill-string and casing in continuous contact with drilling fluid may cause a form of corrosion.

Dissolved gases (oxygen, carbon dioxide, hydrogen sulfide) cause serious corrosion problems;

Cause rapid, catastrophic failure

May be deadly to humans after a short period of time

Low pH (acidic) aggravates corrosion, so use corrosion coupons[clarification needed] to monitor corrosion type, rates and to tell correct chemical inhibitor is used in correct amount.

Mud aeration, foaming and other O2 trapped conditions cause corrosion damage in short period time.

When drilling in high H2S, elevated the pH fluids + sulfide scavenging chemical (zinc).

Facilitate cementing and completion[edit]

Cementing is critical to effective zone[clarification needed] and well completion.

During casing run, mud must remain fluid and minimize pressure surges so fracture induced lost circulation[clarification needed] does not occur.

Mud should have thin, slick filter cake, wellbore with no cuttings, cavings or bridges.[clarification

needed]

To cement and completion operation properly[clarification needed], mud displace by flushes and cement.[clarification needed] For effectiveness;

Hole near gauges[clarification needed]

Mud low viscosity[clarification needed]

Mud non progressive gel strength[clarification needed]

Minimize impact on environment[edit]

Mud is, in varying degrees, toxic. It is also difficult and expensive to dispose of it in an environmentally friendly manner. A Vanity Fair article described the conditions at Lago Agrio, a large oil field in Ecuador where drillers were effectively unregulated.[citation needed]

Composition of drilling mud[edit]

Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (barite), calcium carbonate (chalk) or hematite. Various thickenersare used to influence the viscosity of the fluid, e.g. xanthan gum, guar gum, glycol, carboxymethylcellulose, polyanionic cellulose (PAC), or starch. In turn, deflocculants are used to reduce viscosity of clay-based muds; anionic polyelectrolytes (e.g. acrylates, polyphosphates, lignosulfonates (Lig) or tannic acid derivates such as Quebracho) are frequently used. Red mud was the name for a Quebracho-based mixture, named after the color of the red tannic acid salts; it was commonly used in 1940s to 1950s, then was made obsolete when lignosulfonates became available. Other components are added to provide various specific functional characteristics as listed above. Some other common additives include lubricants, shale inhibitors, fluid loss additives (to control loss of drilling fluids into permeable formations). A weighting agent such as barite is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an unwanted (and often dangerous) influx of formation fluids.

Factors influencing drilling fluid performance[edit]

Three factors affecting drilling fluid performance are:[2]

The change of drilling fluid viscosity

The change of drilling fluid density

The change of mud pH

Drilling mud classification[edit]

They are classified based on their fluid phase, alkalinity, dispersion and the type of chemicals used.

Dispersed systems[edit]

Freshwater mud – Low pH mud (7.0–9.5) that includes spud, bentonite, natural, phosphate treated muds, organic mud and organic colloid treated mud. high pH mud example alkaline tannate treated muds are above 9.5 in pH.

Water based drilling mud that represses hydration and dispersion of clay – There are 4 types: high pH lime muds,low pH gypsum, seawater and saturated salt water muds.

Non-dispersed systems[edit]

Low solids mud – These muds contain less than 3–6% solids by volume and weight less than 9.5 lbs/gal. Most muds of this type are water-based with varying quantities of bentonite and a polymer.

Emulsions – The two types used are oil in water (oil emulsion muds) and water in oil (invert oil emulsion muds).

Oil based mud – Oil based muds contain oil as the continuous phase and water as a

contaminant, and not an element in the design of the mud. They typically contain less

than 5% (by volume) water. Oil-based muds are usually a mixture of diesel fuel and

asphalt, however can be based on produced crude oil and mud

Mud engineer[edit]

Main article: mud engineer

"Mud engineer" is the name given to an oil field service company individual who is charged with maintaining a drilling fluid or completion fluid system on an oil and/or gas drilling rig. This individual typically works for the company selling the chemicals for the job and is specifically trained with those products, though independent mud engineers are still common. The role of the mud engineer or more properly Drilling Fluids Engineer is very critical to the entire drilling operation because even small problems with mud can stop the whole operations on rig. The internationally accepted shift pattern at off-shore drilling operations is personnel (including mud engineers) work on a 28 day shift pattern, where they work for 28 continuous days and rest the following 28 days. In Europe this is more commonly a 21 day shift pattern.

In offshore drilling, with new technology and high total day costs, wells are being drilled extremely fast. Having two mud engineers makes economic sense to prevent down time due to drilling fluid difficulties. Two mud engineers also reduce insurance costs to oil companies for environmental damage that oil companies are responsible for during drilling and production. A senior mud engineer typically works in the day, and a junior mud engineer at night.

The cost of the drilling fluid is typically about 10% (may vary greatly) of the total cost of drilling a well, and demands competent mud engineers. Large cost savings result when the mud engineer and fluid performs adequately.

Mud Pit with Fly Ash

The mud engineer is not to be confused with mudloggers, service personnel who monitor gas from the mud and collect well bore samples.

Compliance engineer[edit]

The compliance engineer is the most common name for a relatively new position in the oil field, emerging around 2002 due to new environmental regulations on synthetic mud in the United States. Previously, synthetic mud was regulated the same as water-based mud and could be disposed of in offshore waters due to low toxicity to marine organisms. New regulations restrict

the amount of synthetic oil that can be discharged. These new regulations created a significant burden in the form of tests needed to determine the "ROC" or retention on cuttings, sampling to determine the percentage of crude oil in the drilling mud, and extensive documentation. It should be noted that no type of oil/synthetic based mud (or drilled cuttings contaminated with OBM/SBM) may be dumped in the North Sea. Contaminated mud must either be shipped back to shore in skips or processed on the rigs.

A new monthly toxicity test is also now performed to determine sediment toxicity, using the amphipod Leptocheirus plumulosus. Various concentrations of the drilling mud are added to the environment of captive L. plumulosus to determine its effect on the animals.[citation needed] The test is controversial for two reasons:

1. These animals are not native to many of the areas regulated by them, including the Gulf of Mexico

2. The test has a very large standard deviation and samples that fail badly may pass easily upon retesting

See also[edit]

Directional drilling

Driller (oil)

Drilling rig

Formation evaluation

MWD (measurement while drilling)

Roughneck

Underbalanced drilling

Mud Gas Separator

Mud systems

Oil well control

References[edit]

1. ̂  Oilfield Glossary

2. ̂  "According the change of drilling fluid to understand under well condition". Drilling Mud

Cleaning System. 27 December 2012. Retrieved 26 September 2013.

Further reading[edit]