1. Introduction The Origins, Migration and Trapping of Petroleum and Exploring For It Introduction 1.1 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 the word petroleum is derived from the Latin words for rock (petra) and oil (oleum) THE 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 bitu- men were dispersed in the sediments (usually clay-rich shales). Over millions of years, these organic-laden shales expelled their oil and gas under tremen- dous 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. Its 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 earths crust. These ancient petroleum hydrocar- bons are complex mixtures and exist in a range of physical forms gas mix- tures, 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 sim- plest hydrocarbon is methane gas (CH4). The more complex hydrocar- bons have intricate structures, consist- ing of multiple carbon-hydrogen rings with carbon-hydrogen side chains. There are often traces of sulfur, nitrogen and 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 sedimen- tary rock types. Between the sand grains that make up a sandstone rock body there is space originally filled with seawater. When pores are inter- connected, 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 par- tially 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 reservoirs 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 (calcium- magnesium carbonate) are sedimentary rocks and are some of the most com- mon 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 per- meable enough for oil and gas to migrate through them. However, many limestone reservoirs contain

2. Introduction CHAPTER 1 Introduction 1.2 Revision No: A-0 / Revision Date: 033198 fracture systems and/or interconnect- ing vugs (cavities formed when acidic water dissolved some of the carbon- ate). These fractures and vugs, created after deposition, provide the porosity and permeability essential for oil to migrate and be trapped. Another car- bonate rock, dolomite, exhibits matrix permeability that allows fluid migra- tion 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 predomi- nately 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 sur- rounding strata (sand, shale and car- bonate) is deformed by this upward 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 reser- voirs 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, dri- ven by natural forces of gravity (buoy- ancy) and pressure gradients. When they meet an impermeable barrier, they can go no farther, so oil and gas accu- mulate. 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 geo- logical 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 sedi- ments is an example. An ancient, Structural Traps Figure 1a: Anticlinal trap. Figure 1b: Fault trap. oil and gas accumulate in traps Formation containing saltwater Formation containing saltwater Formation containing saltwater Sand Clay or Limestone Oil Gas Saltwater shale Formation containing oil Formation containing gas Formation containing oil Sand Clay or Limestone Oil Gas Saltwater shale _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

3. Introduction Introduction 1.3 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 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 earths 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 sur- veying, geological exploration, geo- physical (seismic) exploration and exploratory drilling. Aerial and satellite. Surveys from high altitudes give a broad picture of a geographic area of interest. Major sur- face structures such as anticlines and faulted regions can be clearly observed by these methods. This information determining the likelihood of oil and gas in the trapped region Figure 2c: Typical salt structure development (from Geology of Petroleum, A. I. Levorson). Stratigraphic Traps Figure 2a: Stratigraphic trap. Organic reef embedded in shale and wedging out sand. Figure 2b: Unconformity trap. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ Formation containing saltwater Formation containing oil Formation containing saltwater Formation containing saltwater Formation containing saltwater Formation containing oil Formation containing oil Formation containing saltwater Formation containing oil Formation containing oil Formation containing saltwater Surface Salt Surface Salt Surface Salt Sand Clay or Limestone Oil Gas Saltwater shale Sand Clay or Limestone Oil Gas Saltwater shale

4. Introduction CHAPTER 1 Introduction 1.4 Revision No: A-0 / Revision Date: 033198 helps locate areas where more detailed study is warranted. In the early years of petroleum exploration, visualiza- tion from an aircraft or mapping river and creek drainage patterns were suc- cessful 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 lithol- ogy and assess the potential for hydro- carbon 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 exam- ple. 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 seis- mic 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 dif- ferent 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, espe- cially in areas beneath salt, as discussed above. Continual improvements in seismic measurement and the mathe- matical methods (algorithms) used to interpret the signals can now give a clearer picture of subsurface forma- tions. Other geophysical methods use variations in the earths gravity and magnetic properties to detect gross features of subsurface formations. seismic exploration in which shock waves 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 1100 A.D., brine wells as deep as 3,500 ft 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 cen- turies and is still used today for some shallow wells. The method employs a heavy steel drill stem with a bit at the 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 bot- tom). The cable tool method is simple, but it is effective only for shallow wells. Progress is slow because of the ineffi- ciency of the bit and the need to pull the tools frequently to bail out cuttings. Drilling for Petroleum _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

5. 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 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 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 Introduction Introduction 1.5 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 Figure 3: Diagrammatic view of rotary drilling rig (after Petex). 16 36 22 35 18 17 3 19 12 4 20 33 13 14 15 32 10 11 6 8 9 7 27 29 29 23 2421 25 2 2 1 1 28 5 5 5 1 34 26 31 30 Rig Components

6. Introduction CHAPTER 1 Introduction 1.6 Revision No: A-0 / Revision Date: 033198 Rotary drilling. Rotary rigs are used for a variety of purposes drilling oil, gas, water, geothermal and petroleum- storage 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 1900), 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 sur- face, the mud is filtered through screens and other devices that remove the cut- tings, 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 drill- string, 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 wore out quickly in hard rock. An improved rotary bit was needed and in the early 1900s, 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 bits 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) non- sealed 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 bits service life; sealed bearings and journal bearings provide longer life than unsealed bearings, but they are more expensive. A rock bits 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 hard- facing applied for extra life. This type is designed for soft to medium for- mations where long teeth can gouge out the rock. The teeth on insert bits are actually tungsten carbide studs keep the bit cool and lubricated, and to remove the rock cuttings

7. Introduction Introduction 1.7 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 inserted into holes drilled into the cones (see Figure 4a). TCI bits drill by gener- ating 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 car- bide. 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 for- mations, 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 dia- mond 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. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

8. Introduction CHAPTER 1 Introduction 1.8 Revision No: A-0 / Revision Date: 033198 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 dia- monds 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 manufac- tured to optimize drilling particular for- mations. 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. THE DRILLSTRING Starting at the bottom, a basic drill- string 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), pos- sibly 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 pro- vide 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 mag- netic metals. Each joint of drill pipe is approxi- mately 30 ft 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 (dis- connect). 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 transmis- sion of hydraulic horsepower from PDC bits are very durable and efficient

9. Introduction Introduction 1.9 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 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, large- diameter, 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. Traditionally, coiled-tubing rigs have been used for workover and completion operations where mobility and com- pact size were important. With the development of downhole mud motors which do not require the use of a rotat- ing drillstring to turn the bit, coiled- tubing 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 drill- string. The rotary table kelly bushing is a large, metal donut with a 4-, 6- or 8- sided 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 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 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 the drilling mud to get into Regardless of bit type, it must be rotated Casing Mud flow out Mud flow in Cement Annulus Open hole Drill bit Kelly Tool joint Drill pipe Drill collar Mud Bottom-holeassembly Crossover sub Stabilizer Mud motor MWD/LWD Stabilizer Figure 5: Drillstring components.

10. Introduction CHAPTER 1 Introduction 1.10 Revision No: A-0 / Revision Date: 033198 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 discon- nected, 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 joint before making a connection, top drives use 3-joint (90-ft) stands of drill pipe and greatly reduce the number of connections and the time to make a trip. One key advan- tage the driller can simultaneously rotate the pipe while going up or down over a 90 ft 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 ele- ments inside the motor which rotate a shaft to which the bit is attached. This offers several advantages. Mud motors can achieve much higher bit 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 con- dition, as does the drillstring, when only the bit (and not the pipe) rotates. Higher bit RPM results in improved Rate of Penetration (ROP), and vibra- tion 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 formation- related information, he was faced with only one course of action. He had to stop drilling and run special measure- ment or logging instruments down into the wellbore; sometimes this involved pulling the entire drillstring before measurement could proceed. Higher bit RPM results in improved ROP

11. Introduction Introduction 1.11 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 Today, there are sophisticated elec- tronic instruments that can perform Measurement While Drilling (MWD) and Logging While Drilling (LWD) functions while the drilling process continues uninterrupted. The meas- urements 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 col- umn inside the drillstring. For that reason, mud conditions (density, vis- cosity, gas entrainment, etc.) will be especially important on rigs that are running MWD and LWD instruments. DERRICKS 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 draw- works controls a reel of wire cable which runs through a system of pulleys to reduce the mechanical requirements. Heres 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 draw- works, 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 trip- ping, 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, three- joint stands (about 90 ft 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 spin- ning 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. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

12. Introduction CHAPTER 1 Introduction 1.12 Revision No: A-0 / Revision Date: 033198 Drillers console. Located next to the drawworks is the drillers 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 low- ered, mud pump speed, and other important functions. MUD CIRCULATION AND SOLIDS REMOVAL 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. 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 its 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. the driller controls the brake, catheads The mud then travels down the drillstring to the bit. Standpipe Swivel Kelly hose Suction line Mud pits Shale shaker Flow line Mud pump Discharge line Mixing hopper Kelly Drill pipe Drill collar Bit _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ Figure 6: Mud circulating system.

13. Introduction Introduction 1.13 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 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 screens 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 (hydro- statically) 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. At the top of the BOP stack is a bag- type preventer commonly referred to as 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 hydrauli- cally 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 con- cave 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-pres- sure 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 drill- string 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 cov- ered and protected by steel pipe. This is done for several reasons to keep the hole from caving in, to protect the for- mations being drilled and/or to isolate different geological zones from each other. These protective pipes are called casings and liners. Casing refers to pipe _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

14. Introduction CHAPTER 1 Introduction 1.14 Revision No: A-0 / Revision Date: 033198 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. The next string is the intermediate casing. It is run and cemented when theres a need to change the mud to a density that cant 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, eco- nomical 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, overlap- ping 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 cas- ing (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 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 lithol- ogy and fluorescence as evidence of oil called shows. By analyzing the gases in the mud returning from downhole, the presence of hydrocarbons is deter- mined. Depth, ROP and other parame- ters 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 spe- cial coring bit attached to a core barrel. The bit cuts only the outer circumfer- ence of the formation, and the cylin- der 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. Coring is expensive and is used only Several methods are used to identify geological strata

15. Introduction Introduction 1.15 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 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 retriev- able 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 pres- sure 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 ship- ment to a laboratory for fluid analysis. WIRELINE LOGGING The most widely used method of for- mation 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 computer- ized analysis. Logs can be used to locate and identify formations in the well and for geological correlations with nearby wells. Various logs can indicate lithol- ogy, 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, tem- peratures 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 addi- tion 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 ver- tically. 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 off- shore 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 extended- reach drilling project such as is com- mon in the North Sea, Gulf of Mexico and other areas. In some cases, the devi- ated hole may have changes in azimuth direction and inclination, resulting in an S- or U-shaped configuration. [Logs] measure the electrical, acoustical and/or radioactive properties of the formations.

16. Introduction CHAPTER 1 Introduction 1.16 Revision No: A-0 / Revision Date: 033198 _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ WELL 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 com- pletion techniques. In all four, the cas- ing 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 (by explosive charge) through the cas- ing 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 for- mation is weak or poorly consoli- dated, sand and other solids will be carried into the well as the oil or gas is produced. To prevent this sand pro- duction,the slotted or perforated liner may contain a wire-wrapped or a pre- packed-gravel protective layer to keep the sand from entering the wellbore. Gravel packing. Another approach that is helpful if the producing forma- tion is weak (such as loose sand), and must be supported or held back, is the conventional gravel pack. A gravel- packing operation consists of circulat- ing 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. PRODUCTION 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 Producing Petroleum Figure 7: Bottom-hole arrangement of some types of completions. casing prevents the formations from collapsing Producing formation Casing to surface Cement Producing formation Slotted liner Casing to surface Liner hanger and packer Cement Producing formation Slotted liner Casing to surface Liner hanger and packer Cement Gravel Producing formation Gun perforated holes Casing to surface Cement (a) Open-hole completion (b) Gun-perforated completion (c) Liner completion (d) Gravel-packed liner

17. Introduction Introduction 1.17 Revision No: A-0 / Revision Date: 033198 CHAPTER 1 casing, permitting high-pressure reser- voirs to be safely controlled and pro- duced. 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 bal- ance 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 reciprocating- type (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 dis- placed upwards, becoming less dense as they rise to the surface because of the gas thats been injected into them. Gas, oil and water can be lifted this way until it is no longer economical. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ Pumping is an economical method of lifting oil

18. Functions Functions 2.1 Revision No: A-0 / Revision Date: 033198 CHAPTER 2 The objective of a drilling operation is to drill, evaluate and complete a well that will produce oil and/or gas effi- ciently. Drilling fluids perform numer- ous functions that help make this possible. The responsibility for perform- ing 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 representa- tive, drilling contractor and rig crew is to make sure correct drilling proce- dures are conducted. The chief duty of the mud engineer is to assure that mud properties are correct for the specific drilling environment. The mud engi- neer should also recommend drilling practice changes that will help reach the drilling objectives. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ The duty of those charged with drilling the hole Introduction 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 opera- tions, 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 circu- lated down the drillstring and through the bit, entraining the cuttings and car- rying them up the annulus to the sur- face. 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 rheolog- ical 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. Drilling Fluid Functions

19. Functions CHAPTER 2 Functions 2.2 Revision No: A-1 / Revision Date: 022801 Most drilling muds are thixotropic, which means they gel under static con- ditions. This characteristic can suspend cuttings during pipe connections and other situations when the mud is not being circulated. Fluids that are shear- thinning 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 veloci- ties 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 rele- vant for deviated holes, since the cut- tings settle to the low side of the hole across the fluids flow path and not in the direction opposite to the flow of drilling fluid. In horizontal wells, cut- tings 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: a) The use of shear-thinning, thixo- tropic fluids with high Low-Shear- Rate Viscosity (LSRV) and laminar flow conditions. Examples of these fluid types are biopolymer systems, like FLO-PRO, and flocculated ben- tonite slurries like the Mixed Metal Hydroxide (MMH) DRILPLEXsystem. 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 sus- pend 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 (indi- cations 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 cut- tings from settling while circulating, but cuttings will settle quickly when circulation is stopped. This approach works by keeping the cuttings sus- pended with turbulence and high annular velocities. It works best with low-density, unweighted fluids in competent (not easily eroded) for- mations. The effectiveness of this technique can be limited by a num- ber of factors, including large hole size, low pump capacity, increased depth, insufficient formation integ- rity, 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 The rate at which a cutting settles in a fluid The use of shear- thinning, thixotropic fluids with high Low- Shear-Rate Viscosity

20. to balance formation pressures has a negative impact on the drilling opera- tion; therefore, it should never be increased for hole-cleaning purposes. Drillstring rotation. Higher rotary speeds also aid hole cleaning by intro- ducing a circular component to the annular flow path. This helical (spiral- or corkscrew-shaped) flow around the drill- string 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 rota- tion is one of the best methods for removing cuttings beds in high-angle and horizontal wells. 2. CONTROLLING FORMATION PRESSURES As mentioned earlier, a basic drilling fluid function is to control formation pressures to ensure a safe drilling oper- ation. Typically, as formation pres- sures increase, drilling fluid density is increased with barite to balance pres- sures and maintain wellbore stability. This keeps formation fluids from flow- ing into the wellbore and prevents pres- sured 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 (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 condi- tions under which no formation fluid will flow into the wellbore. But it also includes conditions where formation fluids are allowed to flow into the well- bore 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 bal- anced. Wellbores in tectonically stressed formations can be stabilized by balanc- ing these stresses with hydrostatic pres- sure. 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 (equivalent to 8.33 lb/gal freshwater) in inland areas to 0.465 psi/ft (equiva- lent to 8.95 lb/gal) in marine basins. Elevation, location, and various geo- logical processes and histories create conditions where formation pressures depart considerably from these nor- mal values. The density of drilling fluid may range from that of air (essentially 0 psi/ft), to in excess of 20.0 lb/gal (1.04 psi/ft). Functions Functions 2.3 Revision No: A-0 / Revision Date: 033198 CHAPTER 2 _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ Higher rotary speeds also aid hole cleaning

21. Functions CHAPTER 2 Functions 2.4 Revision No: A-0 / Revision Date: 033198 Often, formations with sub-normal pressures are drilled with air, gas, mist, stiff foam, aerated mud or special ultra- low-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 cut- tings, weight materials and additives under a wide range of conditions, yet allow the cuttings to be removed by the solids-control equipment. Drill cut- tings that settle during static condi- tions can cause bridges and fill, which in turn can cause stuck pipe or lost cir- culation. 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 drill- ing 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, shear- thinning 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 drill- ing 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 com- pare 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; for- mations must be permeable for hydro- carbons to be produced. When the mud column pressure is greater than forma- tion 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 for- mation to limit the invasion of mud fil- trate. This improves wellbore stability and prevents a number of drilling and production problems. Potential prob- lems related to thick filter cake and excessive filtration include tight hole conditions, poor log quality, increased torque and drag, stuck pipe, lost cir- culation, 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 cal- cium carbonate, ground cellulose and a wide variety of seepage-loss or other fine lost-circulation materials. Drilling muds must suspend drill cuttings _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

22. Functions Functions 2.5 Revision No: A-0 / Revision Date: 033198 CHAPTER 2 Depending on the drilling fluid sys- tem in use, a number of additives can be applied to improve the filter cake, thus limiting filtration. These include bentonite, natural and synthetic poly- mers, asphalt and gilsonite, and organic deflocculating additives. 5. MAINTAIN WELLBORE STABILITY Wellbore stability is a complex balance of mechanical (pressure and stress) and chemical factors. The chemical composi- tion 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 pres- sure, wellbore stresses related to orienta- tion and tectonics). Wellbore instability is most often identified by a sloughing formation, which causes tight hole con- ditions, 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 hole- cleaning 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 annular velocity, poor hole cleaning, increased solids loading, fill, increased treating costs, poor formation evalua- tion, 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 suffi- cient 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 addi- tives 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, gly- cols, 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. _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ Wellbore stability is a complex balance

23. Functions CHAPTER 2 Functions 2.6 Revision No: A-1 / Revision Date: 022801 Oil- or synthetic-base drilling fluids are often used to drill the most water- sensitive shales in areas with difficult drilling conditions. These fluids pro- vide better shale inhibition than water-base drilling fluids. Clays and shales do not hydrate or swell in the continuous phase, and additional inhi- bition 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 FORMATION DAMAGE Protecting the reservoir from damage that could impair production is a big concern. Any reduction in a producing formations natural porosity or perme- ability is considered to be formation damage. This can happen as a result of plugging by mud or drill solids or through chemical (mud) and mechani- cal (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. For example, when a well is cased, cemented and perforated, the perfora- tion depth usually allows efficient pro- duction, even if near-wellbore damage exists. Conversely, when a horizontal well is completed with one of the open- hole 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 mecha- nisms 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 prob- lem, specially designed reservoir drill-in fluids or workover and completion flu- ids, all can be used to minimize forma- tion 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 drill- string rubs against the casing and well- bore. Circulation of the drilling fluid cools the bit and drilling assembly, Protecting the reservoir from damageis a big concern.

24. Functions Functions 2.7 Revision No: A-0 / Revision Date: 033198 CHAPTER 2 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 lubri- cates 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 water- base 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 sys- tem pH, salinity and hardness. Altering mud lubricity is not an exact science. Even after a thorough evalua- tion, with all relevant factors consid- ered, 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 compo- nents. But be aware that these prob- lems 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 drillstring, liner or casing string is sus- pended 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 fluid will provide twice the buoyancy of a 9-lb/gal 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 considera- tion when evaluating the neutral point (where the drillstring is in neither ten- sion nor compression). However, when running long, heavy strings of casing, buoyancy can be used to provide a sig- nificant benefit. Using buoyancy, it is possible to run casing strings whose weight exceeds a rigs hook load capac- ity. 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 signifi- cant 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 maxi- mize 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 maxi- mized pressure drop at the bit or to optimize jet impact force on the bot- tom of the well. Hydraulics programs are limited by the available pump The lubricity of a partic- ular fluid is measured by Hydraulic energy can be used to maximize ROP

25. Functions CHAPTER 2 Functions 2.8 Revision No: A-0 / Revision Date: 033198 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 small- ID 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 drag- reducing characteristics, such as polymer fluids, are more efficient at transmit- ting 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 ADEQUATE FORMATION EVALUATION Accurate formation evaluation is essen- tial to the success of the drilling opera- tion, 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 cut- tings 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 informa- tion is recorded on a mud log that shows lithology, ROP, gas detection and 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 wireline- conveyed tools. Wireline logging includes measuring the electrical, sonic, nuclear and magnetic-resonance proper- ties of the formation to identify lithol- ogy and formation fluids. For continuous logging while the well is being drilled, LWD tools are available. Drilling a cylin- drical section of the rock (a core) for lab- oratory evaluation also is done in target production zones to obtain desired information. Potentially productive zones are isolated and evaluated by per- forming Formation Testing (FT) or Drill- Stem 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 dis- perse in the mud, there will be noth- ing 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 Accurate formation evaluation is essential to the success

26. Functions Functions 2.9 Revision No: A-0 / Revision Date: 033198 CHAPTER 2 muds, lubricants, asphalts and other 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 affect- ing logs and FT or DST samples. Muds that contain high potassium ion con- centrations 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 log- ging, 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 near- gauge from top to bottom, since exces- sive 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 wet- tability 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 cor- ing operations specify a bland mud with a minimum of additives. 10. CONTROL CORROSION Drillstring and casing components that are in continual contact with the drilling fluid are susceptible to various forms of corrosion. Dissolved gasses such as oxygen, carbon dioxide and hydrogen sulfide can cause serious cor- rosion 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 pro- tection 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 cor- rosion threat is significant. Chemical inhibitors must be applied properly. Corrosion coupons should be evalu- ated to tell whether the correct chemi- cal 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 well- bore 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 comple- tion. During casing runs, the mud must remain fluid and minimize pressure surges so that fracture-induced lost Dissolved gassescan cause serious corrosion problems _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________ _______________________

27. Functions CHAPTER 2 Functions 2.10 Revision No: A-0 / Revision Date: 033198 circulation does not occur. Running casing is much easier in a smooth, in- gauge wellbore with no cuttings, cav- ings 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 near- gauge and the mud must have low vis- cosity 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. 12. MINIMIZE IMPACT ON THE ENVIRONMENT Eventually, drilling fluid becomes a waste product, and must be disposed of in accordance with local environmen- tal regulations. Fluids with low envi- ronmental impact that can be disposed of near the well are the most desirable. In most countries, local environmen- tal regulations have been established for drilling fluid wastes. Water-base, oil- base, non-aqueous and synthetic-base fluids all have different environmental considerations, and no single set of environmental characteristics is accept- able for all locations. This is