Training Manual

OFFSHORE DRILLING AND COMPLETIONS TRAINING MANUAL

c 1996 DRIL-QUIP, INC.

This document is the property of DRIL-QUIP, Inc and shall not be copied or used for any purpose other than that for which it is supplied without the express written authorization of DRIL-QUIP, Inc., 13550 Hempstead Hwy., Houston, Texas 77040, U.S.A.

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How Oil and Gas Reservoirs AccumulateIntroduction ................................................................................ 1 Sedimentary Rocks ..................................................................... 1 The Formation of Oil and Gas ................................................... 2 Underground Traps for Oil and Gas ........................................ 3 Anticlinal and Dome Traps ........................................................ 4 Fault Traps .................................................................................. 4 Stratigraphic Traps .................................................................... 4 Salt Dome Traps ......................................................................... 5 Reservoir Pressures .................................................................... 5 Pressure Gradients ..................................................................... 5

Table of Contents

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How Oil and Gas Reservoirs Accumulate

Introduction This chapter provides a general outlook of the following: How reservoirs of oil and gas accumulate How drilling for these reservoirs is done With few exceptions, all naturally occurring oil and gas that comes from wells, drilled on land and offshore, is found in layers or beds of sedimentary rocks deposited millions of years ago. The first chapter in this manual is devoted to the formation of sedimentary rocks and trapped accumulations of oil and gas. Sedimentary Rocks Sedimentary rocks, or derived rocks, are formed by the erosion and decomposition of uplifted land masses. Years ago, these uplifted land masses of basement rock were predominantly made up of granites and basalts formed into hills and mountain ranges. These mountains and hills were exposed to the elements of sun, wind, rain, frost, etc. which gradually caused small fragments of the base rocks to break off and get washed or blown down to a lower level. Some of the minerals, such as silicates and carbonates, also dissolved and went into solution.

How Reservoirs of Oil and Gas Accumulate

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The natural drainage system of streams and rivers finally deposited these rock particles and dissolved minerals into lakes, swamps, river deltas and the sea. In many cases, the beds of these lakes, swamps, river deltas and seas became sinking sedimentary basins. This meant that more and more deposition, or sedimentation, could take place as the bed of the sedimentary basin was sinking. As the deposits of sediments got thicker and thicker, the lower layers were exposed to increasing compressive loads called overburden and increasing temperatures occurred as the sediments got deeper. Under the conditions of increasing load and temperature, the sediments became compacted. Coupled with the chemical action of silicates and carbonates coming out of solution, the deposited fragments became cemented together into a combined rock. The cementing medium of silicon (quartz) or calcium carbonates (calcite) make up nearly one third of the combined rocks formed in this way. The types of rocks formed by this process are shales, clays, siltstones, sandstones and gravels. They are classified as clastic sedimentary rocks. This type of sedimentation and rock formation has been occurring for nearly 500 million years and is still very obvious today. The thickness of marine sedimentary rocks have been measured in excess of 60,000 feet. The Formation of Oil and Gas This is not the only form of sedimentation that occurs. The decomposition of dead animal and plant life, both land and marine, have also been taking place on a large scale in the previously referenced sinking sedimentary basins. The organic and skeletal matter from these dead animals and plants became trapped in the water borne sediments and were also buried by additional deposits of sediment and organic matter.Figure 1.1. Anticlinal or Dome Traps

The most prolific source of organic matter deposited and trapped in this manner comes from very small dead marine animals, particularly those with protective shell structures. 2

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This occurred on such a massive scale that very thick layers of sediments were formed entirely from dead microorganisms with protective calcareous shells and skeletons. Coral reefs are an example of this type of deposit. As these organic derived deposits were buried deeper and deeper by subsequent layers, they were subjected to increasing compressive loads and temperatures. The fragments of shell and skeletons became cemented together, and the organic matter consolidated. Rocks formed by this process include limestone, dolomite, chalk and coal. Naturally occurring oil and gas are formed by the effects of pressure, temperature and chemical and bacterial action on the trapped organic matter in sediments that has decomposed into various constituents. The layer of sedimentary rock where this decomposition has taken place is known as the source rock. Almost all sedimentary rocks are deposited in a water environment. As oil is lighter than water and gas is lighter than oil, it is not unexpected that these constituents will try to separate themselves with gas at the top, oil in the middle and water at the bottom. Underground Traps for Oil and Gas As the majority of rocks are permeable (allow passage of fluids and gases through interconnected pores in the rock), the natural tendency for oil and gas is to migrate upwards through the permeable formations until they can escape at the surface. This process has continued slowly throughout time and is still evident today in oil and gas seeps at the surface. This upward migration of oil and gas is occasionally halted by an impervious barrier (one with little or no effective permeability) or cap rock. The oil and gas then start to accumulate in the rocks below the cap rock. The rocks below the cap rock are known as reservoir rocks. A typical cap rock is very compacted with no interconnected pore space, such as a shale or clay. Typical reservoir rocks include sandstones, siltstones and limestones. Figure 1.2. Fault Trap In terms of natural occurrence in sedimentary rocks, shales account for about 50%, sandstones and siltstones about 25%

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and limestones also about 25%. This simple picture of oil and gas formation and accumulation in neat horizontal beds of rock is complicated by movement in the Earth's crust. These movements are created by massive forces of tension and compression in the Earth's crust which have caused land masses to separate and push up into hills and mountain ranges. Anticlinal and Dome Traps These movements affect the layers of sedimentary rocks causing them to form anticlinal or dome structures (upward folds). Synclines are downward folds. When these anticlines or domes have an impermeable layer or cap rock within their structure, they form a very nice trap for the oil and gas migrating upwards (Figure 1.1). Fault Traps Earth movements also cause the layers of sedimentary rocks to tilt. Any migrating oil and gas can escape upwards through the tilted rock formations which ultimately become exposed and eroded at the Earth's surface. The same forces of tension and compression in the Earth's crust can also cause the rock formations to separate at a plane of weakness. Forming a fault, the rock formations move relative to one another along the fault plane. Sometimes this faulting in tilted sedimentary rocks will place an impervious barrier next to the migrating oil and gas. In this manner, a fault trap is created and an accumulation of the oil and gas can occur (Figure 1.2). Stratigraphic Traps Another form of trap can be created when tilted rock formations are exposed at the Earth's surface and, in turn, are weathered and eroded by the elements. This eroded surface becomes the bed of a sinking sedimentary basin. Subsequently, an impervious layer of sedimentary rock is laid on top of the tilted rock formation as the formations sink once again. Over time, the migrating oil and gas in the tilted formation is

Figure 1.3. Stratigraphic Trap

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trapped by the impervious layer of rock. This form of trap is called a stratigraphic trap (Figure 1.3). Salt Dome Traps Another form of trap for oil and gas accumulations is associated with salt domes. These traps are formed when a massive plug of salt tries to move upwards through denser layers of rock. The layers of rock above the salt dome are forced into a folded structure and, with the correct layers of rock in place, a trap for oil and gas is formed. It must be pointed out that not all salt dome structures are traps for oil and gas simply because oil and gas accumulations werent there in the first place. Historically, the very high success ratio for finding oil and gas associated with salt domes, particularly in America, lead the early drillers to believe that oil and gas had its origins in the actual salt. As explanied, this is not the case, just a popular misconception (Figure 1.4). What is obvious is that the erosion and the process of creating sediments of oil containing formations is a constant cycle. All parts off this cycle have occurred (and are still occurring) throughout history. Reservoir Pressures The formation of oil and gas has generally occurred at some considerable depth which accounts for the fact that most reservoirs of oil and gas are under pressure. This knowledge should help with the understanding that drilling holes into these reservoirs requires due care and attention. During drilling operations, the reservoir pressure needs to be overbalanced by the hydrostatic column of drilling fluid in the well bore as the hole is drilled through the cap rock into the reservoir. A rough pressure gradient of 1/2 psi/ft. can be used to calculate an estimated reservoir pressure. For instance, a reservoir 10,000 ft. below the surface would have an approximate pressure of 5,000 psi. Pressure Gradients Fresh water has a pressure gradient of 0.433 psi/ft. and sea

Figure 1.4. Salt Dome Trap

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water has a pressure gradient of 0.443 psi/ft. Simple multiplication quickly reveals that a sea-water column of 10,000 ft. only exerts a pressure of 4,430 psi which is insufficient to overbalance a 5,000 psi reservoir. This tells us that a heavier fluid is required for adequate control of the reservoir pressure. This concept is fundamental to all drilling and production operations and explains why pressure control of formation fluids and gases is given the highest priority in the oil industry, as oil and gas flowing out of control are extremely dangerous and potentially life threatening.

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Equipment Used in Rotary DrillingIntroduction ................................................................................. 7 Drilling Bit ................................................................................... 9 Drill Collar Sub ........................................................................... 9 Drill Collars ................................................................................. 9 Drill Pipe .................................................................................... 10 Kelly Saver Sub ......................................................................... 10 Kelly and Kelly Bushing ........................................................... 10 Kelly Cock .................................................................................. 11 Swivel .......................................................................................... 11 Travelling Block and Hook ...................................................... 12 Crown Block and Drilling Line................................................ 12 Mast or Derrick ......................................................................... 12 Support Systems ........................................................................ 13 Drilling Fluid Circulation System ........................................... 13 Mud Pump or Slush Pump ....................................................... 13 Standpipe and Standpipe Valve ............................................... 13 Rotary Hose ............................................................................... 14 Bell Nipple and Return Flowline ............................................. 14 Shale Shaker .............................................................................. 14 Running and Pulling System .................................................... 15 Drawworks ................................................................................. 15 Brake System ............................................................................. 15 Rotating System......................................................................... 15 Rotary Table .............................................................................. 15 Rotary Beams ............................................................................ 16 Master Bushings ........................................................................ 16 Elevators and Links .................................................................. 16 Drilling Fluids ............................................................................ 17 Top Drive Drilling ..................................................................... 19

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Equipment Used in Rotary Drilling

Introduction The purpose of this section of the manual is to give a brief overview of the equipment and systems used to drill and complete a well for production. As the training course continues into offshore drilling and production, it will be seen that the equipment and systems used on land have been adapted for offshore use but the primary functions of the equipment have not changed at all. Figure 2.1 is an illustration of a land drilling operation and Figure 2.2 illustrates the configuration of a land rotary drilling rig that will be used to describe the equipment involved in rotary drilling. The primary function of the drilling rig used in the oil industry is to drill a hole that penetrates an oil or gas reservoir in a safe and timely manner. Starting from the bottom of the hole, the drilling bit is the business end of the whole system as it is the only piece of equipment that actually makes hole. All of the rest of the equipment can be considered as the support system; to raise and lower the bit into the hole; to rotate the bit with controlled weight; to flush the cuttings from the bit/rock interface as the hole is drilled; and to provide fluid pressure control as the bit penetrates beds of rock that may contain gas,

Figure 2.1. Illustration of a land drilling operation


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Configuration of a Rotary Drilling Rig

CROWN BLOCK DRILLING LINE

WATER TABLE

MAST OR DERRICK STRUCTURE TRAVELING BLOCK GOOSENECK ROTARY HOSE STAND PIPE HOOK SWIVEL KELLY COCK KELLY MUD PUMP OR SLUSH PUMP STAND PIPE VALVE

KELLY BUSHINGS ROTARY TABLE RIG FLOOR ROTARY BEAMS KELLY SAVER SUB SUBSTRUCTURE

GROUND SUCTION PIT SETTLING PIT BLOWOUT PREVENTER STACK SHALE SHAKER CASING HEAD CEMENTED CASING CASING SHOE DRILL PIPE ANNULUS RETURNS WELLBORE CEMENTED CONDUCTOR RETURN FLOWLINE BELL NIPPLE CELLAR

LEGENDDRILLING FLUID CIRCULATION PATH

DRILL COLLARS DRILL COLLAR SUB DRILLING BIT

Figure 2.2

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oil or water at high pressures. Drilling Bit The most common bit used in rotary drilling is the roller cone bit and its most common form is the three-cone, or tri-cone, bit. Each roller cone is equipped with teeth that chip off fragments of the rock as the bit rotates and the roller cones roll over the bottom of the hole. The resulting chips or cuttings have to be cleared from the drilling face. This is accomplished by the circulation of the drilling fluid down through the inside of the bit, and back to the surface in the annulus return. Many improvements have been made to roller cone bits over the years including the introduction of nozzles, or jets, that utilize teeth with hardened inserts and larger and better bearings. All of these improvements have been made in order to increase penetration rates and extend the life of the bit. The bit has a threaded pin up. This connection is threaded for right-hand make up, with the thread being very coarse and rugged, machined on a taper. This form of tool joint is very common in drill pipe, drill collars and drilling assemblies. Drill Collar Sub The next piece in the drilling assembly is a short, heavy-walled pipe section with a tool joint box up/box down configuration. This short section of heavy-walled pipe is called a drill collar sub, or substitute, and is made up to the tool joint pin of the drilling bit.

Figure 2.3. Photo of a typical drilling bit

STABILIZER

DRILL COLAR

STABILIZER

DRILL COLLAR

Drill Collars STABILIZER The next section of the drilling assembly is made up of drill BIT BIT collars. Drill collars are usually 30' heavy-walled, high-grade steel pipe that have right-hand tapered tool joints in a box up/ Figure 2.4. Illustration of two typical pin down configuration which is the most common way that bottom hole assemblies oilfield tubulars are used.

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The number of drill collars required in the drilling assembly will depend on the expected range of weight that will be applied to the drill bit. The required weight on the bit is achieved by letting a certain length of the drill collars act on the bit as a compressive load while the drilling string is turned to the right. The rest of the drill collars and the attached drill pipe above will be kept in tension. The balance point between compression and tension is called the neutral point and it appears to be one of the more common points of failure for drill collar tool joints. Drill Pipe As already mentioned, drill pipe is used above the drill collar section of the drill string. Drill pipe has a thinner wall section than drill collars and is made from high-grade steel pipe. It is equipped with tapered, right-hand threaded tool joints boxup/pin down. Drill pipe normally comes in 30' lengths. Kelly Saver Sub At the top of the drill string is the kelly and it's attached kelly saver sub. The kelly saver sub is a short section of heavywalled, high-grade steel pipe with tool joints box up/pin down. As the name implies, this sub is a protective tool which remains attached to the kelly and is a replacement item when the tool joint pin on the saver sub is worn out or damaged after numerous connections and disconnections to drill pipe. Kelly and Kelly Bushing The kelly is made from high-grade steel pipe with a square or hexagonal section. It is usually 40' long for rotary drilling operations on land. The square or hexagonal section fits into a corresponding square or hexagonal hole in the kelly bushing. The kelly bushing is equipped with drive pins which fit into corresponding holes in the rotary table. When the rotary table is rotated to the right (clockwise), the kelly bushing is turned to the right. This rotates the kelly, which also rotates the attached drill string and rotary bit, to the right.

Figure 2.5. Photo of a typical kelly and kelly bushing

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As the bit makes more hole, the kelly moves down through rollers in the kelly bushing until another 30' section or more of hole has been drilled. The whole drill string and kelly are then pulled up until the kelly bushings are picked up out of the rotary table so that the last drill pipe connection can be broken (unscrewed) to insert another length of drill pipe. In this operation, the kelly and kelly bushing are handled together. The threaded connection at the top of the kelly is a left-hand thread as the right-hand rotation applied to the kelly during drilling operations would effectively unscrew right-hand threaded connections above the rotary table. Kelly Cock The next piece of equipment above the kelly is the kelly cock. The kelly cock is a safety valve which can be closed manually with a quarter turn. Remotely-operated kelly cocks are also available. The purpose of the kelly cock is to provide a means Figure 2.6. Photo of a typical kelly of closing in pressure inside the drill pipe string in the event and kelly cock that higher than expected pressures are encountered during the drilling of the hole. The kelly cock will normally be equipped with left-hand threaded connections box up/pin down. Swivel The upper box connection of the kelly cock mates with the pin down connection of the next major piece of equipment, namely the fluid swivel. This extremely important unit supports the weight of the entire drilling assembly on a large, sealed bearing housed in the swivel. This bearing allows the drill string to rotate without rotating the swivel body. The swivel has a fluid inlet through which the circulating drilling fluid is Figure 2.7. Photo of a typical crown pumped through the bore of the sealed bearing and then into block the bore of the kelly and attached drill string. The upper part of the swivel body is equipped with a large, heavy bail through which the hook of the travelling block is passed.

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Travelling Block and Hook The travelling block and hook form part of the hoist mechanism which enables the drilling assembly to be lowered into, or pulled out, of the hole. On standard exploration drilling rigs, the travelling block will usually house 6 large pulley wheels, wire or sheaves. The travelling block is strung with interconnecting drilling line, or cable, to the crown block integrated into the top of the mast or derrick structure. Crown Block and Drilling Line The crown block also has 6 large sheaves and the stringing is accomplished by reeving the drilling line around the sheaves on the travelling block and crown block. One end of the drilling line is anchored at the foot of the mast or derrick structure. This line is known as the dead line. The other end of the line is wound onto the cable drum of the hoist mechanism, or drawworks, on the rig floor. This line is the fast line. The stringing of the drilling line does not necessarily use all the sheaves of the travelling block and the crown block. The drilling line may use 4, 5 or 6 of the sheaves. The number of sheaves selected will determine if 8-line stringing (4 sheaves), 10-line stringing (5 sheaves) or 12-line stringing (6 sheaves) is being used. The fewer lines used in the stringing means faster hoisting or lowering speeds, but decreases the load carrying capacity. The more lines used in the stringing means slower hoisting and lowering speeds, but increases the load carrying capacity. Mast or Derrick The large mast or derrick structures that support the crown block and all of the load carried by, and including, the travelling block and hook, are commonly rated at 1,100,000 lbs. to 1,300,000 lbs. maximum load capacity. The height of most land exploration masts or derricks does not exceed 150'. The reason for this height arises from the need to accommodate the travelling block and hook while pulling the drill pipe out of the hole, usually 3 joints at a time. This is called a thribble and is

Figure 2.8. Photo of a typical derrick

Figure 2.9. Photo of a typical mud pump.

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approximately 90' in length. The length of 3 interconnected joints of drill pipe is called a stand. These stands are racked in a vertical manner within the mast or derrick structure. Support Systems The topics thus far have covered the equipment required to drill a hole. However, the hole could not be drilled without the means to circulate the drilling fluid, raise and lower the drilling assembly and rotate the drill string. All of these support functions can be operated independently of one another as well as collectively in any combination required. The following notes will discuss these support functions. Drilling Fluid Circulation System (Refer to Figure 2.2) Mud Pump or Slush Pump In the drilling of exploratory or development wells, a very large pump is required to maintain a circulation system. The oilfield pumps used for this purpose are called mud pumps or slush pumps. They are large, positive displacement duplex or triplex pumps. By changing the piston and liner sizes, the piston stroke and the strokes per minute of these pumps can deliver volumes in excess of 1,000 gallon per minute and output pressures over 6,000 psi. The drive units or prime movers for mud pumps are usually diesel engines. Power transmission from the engine to the pump is usually by way of V-belts and grooved pulleys mounted on drive shafts.Figure 2.10. Typical standpipe valve manifold

Standpipe and Standpipe Valve The drilling fluid is delivered under pressure to the standpipe through the standpipe valve. The standpipe valve is a safety valve and performs a function similar to the kelly cock valve when unexpected pressure anomalies occur in the drilling operation. It can be operated manually usually with a quarter turn from the fully open position to the fully closed position. The standpipe is made from high-grade steel and is normally attached to a leg of the mast or derrick structure. The high Figure 2.10.A Photo of a typical pressure drilling fluid passes through the standpipe and standpipe

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gooseneck at the upper end of the standpipe into the flexible rotary hose. The other end of the rotary hose is connected to the inlet on the swivel which provides the fluid path into the drilling string. Rotary Hose The rotary hose is exposed to very tough conditions in it's service life. It has to be flexible as it is connected to the swivel which goes up and down in the mast or derrick as the drilling assembly is raised or lowered during drilling operations. The rotary hose has to withstand high pumping pressures as well as high temperatures from the drilling fluid, particularly as the hole gets deeper and abrasive action of the drilling fluid. Pressure ratings for rotary hoses are found in the range of 5,000 psi to 10,000 psi working pressure depending on the service anticipated. Rotary hoses vary in length, but 75' is the normal length for land drilling. The drilling fluid passes through the bore of the kelly, the string of drill pipe, the section of drill collars and the jets, or nozzles, in the bit at the bottom of the hole. From here, the drilling fluid returns carrying the cuttings from the action of the drilling bit up the annular space between the drill string and well bore to the surface. Bell Nipple and Return Flowline Here the fluid passes through the blowout preventer (B.O.P.) stack mounted on a casing head or wellhead spool, and then into the bell nipple mounted on top of the B.O.P. stack. The drilling fluid then enters the return flowline which directs the fluid over the vibrating screen of the shale shaker.Figure 2.12. Typical bell nipple discharge line and shale shaker

Figure 2.11. Photo of a typical rotary hose

Shale Shaker The purpose of the shale shaker is to separate the cuttings from the drilling fluid so that they are removed from circulation and collected as samples for examination. The strained drilling fluid then drops into the settling pit. The settling pit gives the drilling fluid time to drop the very fine particles of and intoformationthat have become entrained in the drilling fluid. The drilling fluid then passes over a partition in the settling

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tank the suction pit where it is picked up by the suction pipe of the mud pump, and the circulation cycle starts all over again. Running and Pulling System Drawworks As previously mentioned, the drawworks (hoist mechanism) provides the means to reel in the drilling line (fast line) onto a large drum as it raises the travelling block, hook and drilling assembly. The drawworks also lets out the drilling line as the drilling assembly is lowered. The drawworks is usually powered by large diesel engines or electric motors and has various gear selections to alter the winch speed of the drum pulling in the drilling line. Brake System The drawworks is also equipped with a very powerful brake system that is controlled by the driller as the drilling assembly and drill pipe is lowered into the hole. The amount of the load being lowered into the hole is measured by a weight indicator sensing mechanism which is attached to the dead line. The readout from the weight indicator sensor is transmitted to a large scale dial that the driller can observe on his console. During drilling operations, it is this weight readout that tells the driller how much weight is being applied to the bit. Drilling rigs are generally equipped with a dual braking system, a mechanical braking system and an electric or hydraulic braking system. Rotating SystemFAST LINE

CROWN BLOCK

DEADLINE DRILLING LINE (8 LINES ARE STRUNG)

TRAVELING BLOCK DRILLING HOOK DEADLINE ANCHOR

DRUM

DRAWWORKS DRUM BRAKE STORAGE REEL

Figure 2.13. Illustration of drawworks, brake, and hoisting system

Rotary Table table and bottom of the block and hook. The means to rotate the drilling assembly is provided by the rotary table which is usually powered by a diesel or electric prime mover. A large rotary chain, engaging sprockets mounted on the drive shafts, is the normal means of power transmission from the prime mover to the rotary table. The rotary table itself is a very large, rugged piece of equipment. It

Figure 2.14. Photo of a typical rotary

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is mounted on very large steel beams, called rotary beams, at the rig floor level. Rotary Beams These rotary beams are integrated into the substructure which supports the entire derrick structure. The rotary table is positioned centrally below the crown block. The center section of the rotary table rotates while the main section remains firmly anchored. The center opening is normally 17-1/2" to 27-1/2" on land based rigs. Offshore, the central opening of rotary tables are larger, normally 37-1/2" to 49-1/2". Master Bushings For easy removal, the master bushings are split in half. Each half sits into a matching recessed profile in the center of the rotary table. When in place, the master bushings have a tapered, central hole that provides the seat for the drill pipe slips. The drill pipe slips are used to wedge around and support the drill pipe string at the rotary table. This function is required when adding another joint of drill pipe, or single, and when the drill pipe is tripped (pulled or run) in and out of the hole. The kelly bushing fits into the rotating center section of the rotary table and around the kelly. As the center section of the rotary table rotates, so does the kelly bushing, the kelly, the connected drill pipe and drilling assembly. Elevators and Links A set of elevators and bails are required on the rig site for each size casing and tubing used to drill the well. These items are sized by the outside diameter and anticipated weight of each string of pipe. These tools provide a rapid means for running and pulling pipe while the kelly, kelly bushing, swivel and rotary hose is stored in the "rathole". Elevators are generally rental items, but are occasionally supplied by the casing crew. For the larger casing sizes, slips are sometimes an integral part of the elevator for easier handling due to the size and weight.

Figure 2.15. Photo of a typical substructure.

Figure 2.16. Photo of casing elevator suspended by links from the block and hook.

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This concludes the main functions needed to drill a hole. They are pumping, rotating, raising and lowering. As our earlier discussion on oil and gas reservoirs mentioned, the need for control of formation pressures must be constantly addressed while drilling a hole. The next section will address the function of drilling fluid as a medium to control these pressures. Drilling Fluids This subject is a major topic in its own right. The purpose of the following discussion is to highlight the primary functions of drilling fluids. These functions are summarized below. 1. Control pressures of formations penetrated. This is achieved by ensuring that the hydrostatic column of drilling fluid exerts a pressure on the formation that is higher than the water, oil or gas pressure in the formation. This prevents entry of the formation fluids or gases into the wellbore. 2. Clear the cuttings from between the drilling bit and the cutting face on bottom. This is achieved by the large volume of drilling fluid blasting through the nozzles on the bit that is positioned to clear the freshly cut face. This jetting action also provides a hydraulic cutting action which can be significant in some rock formations. 3. Remove the cuttings from the hole. This is achieved by its carrying properties, directly related to its gel strength, and the upward velocity of the annulus return. 4. Cool and lubricate the drilling assembly. The cooling is achieved by providing a cooler drilling fluid from the suction pit and circulating out the hot drilling fluid generated downhole by the cutting action of the bit and the deeper, hotter formations. The drilling fluid provides lubrication by lessening the frictional losses between the drill string, the walls of the drilled hole, and at the cutting face between the bit and rock.

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5. Consolidate the walls of the drilled hole to prevent the caving-in, or collapse, of certain types of rock into the wellbore. This is achieved by the drilling fluids capacity to deposit a thin "mud cake" on the walls of the hole. The mud cake forms because the hydrostatic pressure of the drilling fluid is greater than the formation pressure and a natural loss of drilling fluid to the formation occurs. Large losses of drilling fluid are prevented by the mud cake forming on the walls of the hole, just as a filter cake forms in any filtration process. By keeping a small pressure differential (100 - 150psi) between the hydrostatic column of the drilling fluid and the formation pressure, the loss of drilling fluid to the formation is also minimized. The simplest drilling fluid is water, either fresh water or sea water, and it is commonly used to drill the shallow sections of the hole. Although water is very good for penetration rates, it has poor properties for preventing the collapse, or caving in, of the sides of the hole, particularly where the formations are unconsolidated or have thick beds of natural clay. During the drilling of shallow hole sections, the re-circulated water will pick up clay minerals which will hydrate in the water forming a natural slurry or thin mud. These hydrated clay minerals will form a gel with the water which improves the cutting carrying properties of the mud along with its higher viscosity. Water-based muds as drilling fluids have undergone many improvements over the last hundred years with the addition of specially prepared bentonite clays that form very stable gels or muds. Saltwater clays have also been used extensively. Low solids mud have been introduced using cellulose-based gels as the clay substitute in the mud. Oil-based muds have been used for many years, particularly where water loss from a conventional mud is seen that cause formation problems or damage. As has been stressed in previous notes, the pressure control of formations containing water, oil or gas accumulations needs constant attention. Controlling the density of the drilling 18

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fluid, or mud, also controls the bottom hole pressure exerted by the mud on the formation. This is achieved by adding weighting materials to the mud. The most widely used weighting material is barites (barium sulfate). It is added to the mud as a finely powdered mineral that stays suspended in the mud. The gel strength of the mud is very important in ensuring that the barites stays suspended and not drop out as a sediment, particularly when the mud is not being circulated. Barites are about 4.2 times denser than water. Top Drive Drilling In the early eighties, top drive units, one of the most significant technical advances in drilling, were put into service. Instead of turning the drill pipe with a kelly and rotary table, a top drive unit is suspended from the traveling block assembly and turns the drill string with a direct hook-up eliminating the need for the kelly, kelly bushing, and rotary table drive. The unit rides up and down a rail mounted to the derrick, giving it stability and keeping the drill string centered over the hole. Figure 2.17. Typical Permanent Top The top drive is powered by either electric or hydraulic motors Drive which generate the equivalent rpm and torque as like-sized rotary drives. Top drive units generally have two integral kelly cocks, a manual and a remote hydraulic. There are two types of top drives, permanent (Figure 2.17) and portable (Figure 2.18), permanent being the only means of drilling and portable being a removable assembly as a secondary means of drilling using many components of the rotary drive configuration. On both permanent and portable top drives, the stand pipe and rotary hose must be extended to allow the top drive to travel to the top of the derrick. Since the drilling power source can now be positioned at the top of the derrick, two to three stands can be drilled at a time, depending on the height of the derrick.

Permanent drives have an integrated swivel and are mounted to the traveling block, while the portable unit is suspended from the existing swivel, block and hook assembly. On Figure 2.18. Typical Portable TopDrive

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permanent top drive systems, the rotary table is replaced by a master bushing and slip bowls to facilitate the use of casing and tubing slips. On portable drives, the kelly bushing is removed from the rotary and slip bowl inserts are used in its place to facilitate hanging off the drill string to make up joints. Other advantages of the top drive system include the continuous rotation and circulation going in, or out of, the hole and that the connections can be made up, or broken out, at any point in the derrick. The links extend forward from the top drive unit hydraulically and allow the elevators to pick up pipe at the V door and monkey board. In general, top drive units provide enhanced well control and reduce the chances of sticking pipe while running in and out of the hole.

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Drilling a Well on LandIntroduction ............................................................................... 21 Primary Conductor ................................................................... 21 Starting Head............................................................................. 22 Mud Riser .................................................................................. 22 Starting to Drill Ahead ............................................................. 22 Running Casing ......................................................................... 24 Installing the Casing Hanger ................................................... 28 Blowout Prevention and Control ............................................. 29 Ram Type Preventers ............................................................... 30 Annular Preventers ................................................................... 31 Controlling a Potential Blowout .............................................. 32 Choke and Kill Lines ................................................................ 33

Table of Contents

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Drilling a Well on Land

Introduction This chapter of the manual assumes that the drilling rig is in place with all the support systems ready to spud in, or commence drilling. The land rig diagram in the previous chapter can be used as a reference. Primary Conductor Most of the wells drilled on land will require a short section of large diameter pipe, or casing, be installed in the cellar floor. This primary conductor can be driven into place using a diesel, or steam hammer, or can be lowered into a pre-drilled hole and cemented in place. The purpose of the primary conductor is to prevent loose soil and unconsolidated rock formations from caving in, or collapsing, into the drilled section of hole. The collapse, or wash out, of unconsolidated surface formations can plug the hole and, in severe cases, can undermine the drilling rig to such an extent that the location has to be abandoned and the rig moved to an adjacent site. The primary conductor may range in size from 16" to 30" for most land drilling operations and the lengths used will depend on the local conditions varying from a few feet up to 500 ft. or more. The pressure requirements and ratings of these primary conductors are extremely low as they are not usually expected to contain more than average formation pressure, but are mainly in place to provide a primary conduit for the

CONDUCTOR

Figure 3.1. Illustration of the cellar deck and the primary conductor installed


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drilling assembly and prevent formation collapse. Figure 3.1 shows the primary casing in place.ROTARY TABLE ROTARY TABLE RIG FLOOR RIG FLOOR

RISER

DRILL PIPE

Starting Head If the primary conductor pipe has been driven into place, the excess amount above the cellar floor will be cut off and a starting head will be welded to the primary conductor. If casing has been used that is equipped with a casing thread or specialty connector, the drilling operator will have drilled enough hole and spaced out the lengths of casing so that when the casing is cemented in place, the last connection is positioned at the cellar floor level. This makes it very convenient to attach a starting head with a matching thread or specialty connector. The starting head is equipped with a large, lowpressure flange or hub face looking up. It can have two side outlets and also have an internal landing profile for the first casing hanger. Mud Riser A mud riser is a short length of large diameter pipe with matching flange, or hub face, to the starting head and is either bolted or clamped to the starting head. The upper end of the short length of riser is equipped with a bell nipple, or flow nipple, which has an outlet made up to the mud return flow line. The purpose of the riser is to provide a conduit for the drilling fluid returns and rock cuttings as the well is drilled. In some areas of the world, a large bag-type blowout preventer, or custom designed flow diverter system, may be installed on the starting head. This is usually only done if a long length of primary conductor has been installed and shallow pockets of formation gas are anticipated. The riser and bell nipple are installed on top of the blowout preventer, or flow diverter, either as separate units or integrated into the equipment design. Figure 3.2 illustrates the conventional drilling set-up. Starting to Drill Ahead As can be seen from the illustration in Figure 3.2, the bit with bit sub have been connected to a short length of the drill collar which, in turn, has been connected to the kelly. The mud

CELLAR STARTING HEAD

DRILLING BIT

Figure 3.2. Preparing to drill out for surface casing

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pumps are started and the drilling fluid, usually water for surface hole, is circulated down through the bit, back up the annulus, through the mud return flowline and then back to the suction pit. The rotary table drive is then engaged and the kelly bushings are rotated by the rotary table as the kelly starts to turn to the right. The drawworks braking system is then let off slowly to lower the rotating drilling assembly until the bit starts to take weight on the bottom of the hole. Drilling proceeds until the kelly has been drilled down to the top of the kelly bushings. The hole is circulated to clear the cuttings and the mud pumps and rotary are stopped. The kelly, with attached drilling assembly, is pulled out of the hole until the kelly bushings lift out of the rotary table exposing the connection between the kelly and the short length of drill collars. Slips and a safety collar will be set to suspend the drilling assembly. This connection is broken (unscrewed) and the kelly is then stabbed and made up to the next length of drill collar which has been placed in the mouse hole. The kelly and the additional length of drill collar are then made up to the drill collar joint sitting in the rotary table. The kelly is then picked up so that the downward load on the slips is relieved. This enables the slips to be removed and the drilling assembly, once again, be lowered back into the hole and drilling will be started up again. The process of drilling off the kelly and adding singles to the drill string proceeds until the hole reaches the required depth (or casing point). The depth of the hole will be recorded as a measurement in feet below the kelly bushings (KB). When the casing point is reached, the bit is pulled a few feet off of the bottom and the hole is circulated to remove all cuttings from the hole. When Figure 3.3. Surface casing being run

ROTARY TABLE

RIG FLOOR

RISER

SURFACE CASING

CELLAR STARTING HEAD

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A

B

CEMENTING HEAD TOP WIPER PLUG BOTTOM WIPER PLUG CASING SLIPS

the hole is declared clear of cuttings, the drilling assembly is pulled out of the hole and the sections of drill pipe or drill collars will be stood back in the derrick or mast as triples (occasionally as doubles in small drilling masts). If the drill collars and drill pipe sizes need changing for the next section of hole, they will be broken down into singles and put out on the pipe racks. Running Casing The next step in drilling the well is to run steel casing into the hole and cement it in place (Figure 3.3). The purpose of the steel casing is to provide a protective sleeve in the section of hole just completed. When cemented, it prevents the rock formations and fluids from entering the well bore during the next drilling stage. The size, grade of steel and wall thickness of the casing will also be selected to contain the higher formation pressures expected as the hole is drilled deeper. Running the successive strings of casing and production tubing in and out of the hole during these operations is called "tripping in" and "tripping out". This is accomplished by using elevators as referenced in the equipment section of the manual. These elevators latch around the casing or tubing and provide a landing shoulder for the casing coupling or the tubing upset. The elevator attaches to the hook on the traveling block by means of bails. As each joint is lowered into or pulled from the hole, slips are set around the pipe in the rotary, or in a portable slip bowl called a "spider", allowing the elevator to be removed and used to pick up the next joint of pipe to be made up or removed from the string. This process is repeated until all the pipe is in or out of the hole. The lengths of casing used are generally 30' long, and equipped with a threaded pin end and a threaded box end or coupling. The normal method of running threaded casing is box up/pin down. The first joint of casing run is the shoe joint, so named because it has a casing shoe or guide shoe at the lower end which is rounded to form a smooth guide for the casing as it is lowered into the hole. Sometimes, the casing shoe has a one

BELL NIPPLE

STARTING HEAD

DRILLING FLUID

FLOAT COLLAR

FLOAT SHOE

Figure 3.4. Setup for Cementing casing into place

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A

B

CEMENTING HEAD TOP WIPER PLUG

CEMENT

BOTTOM WIPER PLUG

DRILLING FLUID

FLOAT COLLAR

FLOAT SHOE

way float valve in its body which allows fluid to pass down through the center part of the shoe, but does not allow fluid to come back the other way. This float valve becomes imA B CEMENTING HEAD portant during the cementing process. If the hole has been drilled through a series of swelling or sloughing shale sections, the float shoe can TOP WIPER PLUG get plugged and not function correctly. In areas where this problem is anticipated, the float valve may be included in a float collar which is run in the casing string one or two joints above the guide shoe. All of the joints of casing are measured on the pipe racks before they go into the CEMENT hole. The measurements are totalled to ensure that the casing shoe ends up a few feet DRILLING FLUID from the bottom of the hole. As the casing is being run, it is normal practice to fill up the inside of the casing every BOTTOM WIPER PLUG few joints with drilling fluid. If this is not done, the casing FLOAT COLLAR tends to float as the float valve prevents entry of drillFLOAT SHOE ing fluid into the casing. 1. Setting Up to Cement Casing. Figure 3.4 shows the cement head (with top and bottom cementing plugs in place) and a simple manifold with two

Figure 3.5. Cementing operation in progress

Figure 3.6. Cement being displaced

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valves (A & B) attached to the cement head. Two manually operated release bars release the cement plugs as required.A B

CEMENTING HEAD

2. Cementing in Progress. The cement slurry, in it's most basic form, is simply powdered cement and water mixed to a pre-determined density that has been pumped into the cement head with valve A open and valve B closed. The release bar for the bottom cementing plug has been pulled back and the plug is shown moving down the casing at the interface between the drilling fluid and the cement slurry. The purpose of the rubber-finned cement plug is to ensure that the usually denser cement slurry does not channel down through the drilling fluid, which could ultimately cause poor quality cement to end up in the annulus. The ball float valve in the float collar is open and the drilling fluid is being forced down the casing, through the casing shoe, up the annulus, and return to the mud pits through the return flowline (Figure 3.5). 3. Displacement in Progress. The bottom cement plug has reached the float collar and an increase in pump pressure will have sheared out the center section of the plug allowing cement slurry to bypass the plug. The cement slurry is shown passing through the casing shoe and up into the annulus. The less dense drilling fluid is shown being displaced out of the annulus. Also, the top cementing plug has been released and drilling fluid is being pumped into the cement head and casing through the open valve B with valve A now closed. The volume of cement slurry used on the cement job will have been calculated to ensure that good quality cement completely fills the annulus and the casing below the float collar. The top rubber-finned cement plug is used to ensure that there is no mixing at the drilling fluid and cement slurry interface, as this could possibly cause poor cement to get positioned around the casing shoe (Figure 3.6). 4. Cement in Place. The displacement of the cement slurry has been completed and the top plug has bumped and sealed on the bottom plug.

DRILLING FLUID

CEMENT TOP WIPER PLUG BOTTOM WIPER PLUG FLOAT COLLAR CEMENT FLOAT SHOE

Figure 3.7. Cement in place around the casing

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An immediate rise in pump pressure would have signified this event and the pumps would have been shut down. The expected volume of displacement fluid would also have been calculated before the cement job and a very close watch would have been kept on the volume of drilling fluid taken from the displacement pit at the surface and/or the pump strokes of the displacing pump. With the pumps shut off, a valve in the displacement line would be opened to see if there was any flow-back from the casing. If there is no flow-back, it would signify a successful cement job as the float valve in the float collar is holding the heavier cement slurry in the annulus from U-tubing back into the casing. This means that the cement head and cementing lines can be removed; the excess cement slurry from the starting head up to the bell nipple can be washed out; and the next step of setting the casing hanger can take place before the cement slurry hardens. Four hours is about the normal setting time for cement slurry after it is mixed. However, various additives to the cement can accelerate or retard the setting time (Figure 3.7). The cement job just described is fairly typical of all cement jobs performed to cement casing in a hole. There are innumerable variations to the methods used and it is not unusual to see cement jobs performed with only one plug or without any cement plugs. On occasion, triple cement plugs might be used, particularly on long casing strings where the cementing may be done in stages. The choice of method used depends on many factors; the ability of the formation to accept the increased hydrostatic head from a column of cement slurry; the requirements of local regulatory bodies requiring the complete shut-off of particular formations (usually fresh water aquifers); the particular policies of the oil company drilling the well; etc. When the cement hardens, it seals off the annulus in the well which prevents migration of fluids or gases from one formation to another. The hardened cement also provides protection to the casing string from potentially corrosive subsurface

Casing Hanger

Casing Hanger opened Figure 3.8. Illustration of a typical slip type hanger

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water. A good cement job will also enhance the burst strength capacity of the casing. Installing the Casing Hanger The next step in drilling the well is to install a casing hanger into the starting head so that the suspended casing load can be taken in the starting head. The casing hangers used for land drilling are normally split or hinged so that they can be wrapped around the casing and slid down the casing to the landing shoulder in the starting head (Figure 3.8). Before this can be done, the riser must be disconnected from the starting head and lifted up to expose the casing suspended from the rotary table above. The wraparound type hanger is installed into the starting head. The casing hanger will be equipped with a bulk type seal that seals against the casing and against the prepared profile of the starting head. The casing hanger will also have internal slips to grip the casing. The slips are set on a taper so that the downward load forces the slip elements to grip the casing more firmly. Most casing hanger designs rely on the weight of the suspended casing acting through the slips to activate the seal between the casing and housing. Other designs have the seals independent of the weight set action. These seals are mechanically activated by lockdown screws. After the casing hanger is correctly positioned in the starting head, the casing load is picked up by the hook, or drawworks, and the casing slips and the safety clamp (if used) would be removed. The casing load would then be slowly lowered so that the slips in the casing hanger start to take a grip and support the casing load. When this has been successfully achieved and the casing hanger packoff seal has been set (either by the weight of the suspended load or mechanically), the excess casing above the hanger will be carefully cut off. The precise cut off point will be dictated by the manufacturer of the equipment, as the casing stub has to fit into the next casing spool which will be bolted or clamped to the starting head. The casing stub usually has to interface and seal with the intermediate packoff bushings installed with the next casing

BELL NIPPLE

BLOWOUT PREVENTER

DRILLING BIT

FLOAT COLLAR

TOP WIPER PLUG

FLOAT SHOE

Figure 3.9. Preparing to drill out of surface casing with the BOP Stack installed

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spool. With this operation completed, the well now has its primary conductor and surface casing string in place. The next stage in drilling the well is to install the blowout preventer (BOP) stack directly on the casing spool, adapter or drilling spool attached to the casing spool. This next section of hole is drilled with the blowout preventer stack in place as shown in Figure 3.9. Therefore, the following text is devoted to a brief discussion on the main elements of the BOP stack and its functions. Blowout Prevention and Control What is a blowout? It can be described as an uncontrolled flow of fluids and/or gases from the wellbore to the atmosphere. How does a blowout occur? As mentioned in earlier discussions on drilling fluids, the hydrostatic pressure exerted by the column of drilling fluid must always exceed the pressure of the fluids and/or gases contained in the formations being Figure 3.10. Illustration of the BOP penetrated. If this positive pressure differential is not main- Stack tained, the formation fluids and gases can enter the wellbore and displace the drilling fluid which can lead to a blowout condition if corrective action is not taken. The most common reasons for a blowout to occur in open hole sections of the well are: The drilling fluid column density is lowered by gas bubbles escaping from drilled cuttings or the formation. Formation fluids or gases enter the wellbore as the drilling assembly, acting as a plunger or swab, is pulled out of the hole. Loss of drilling fluid due to a lost circulation zone in the Figure 3.11. Dual Ram-type wellbore which reduces the hydrostatic column which, in preventers turn, can allow formation fluids or gases from another zone in the well to enter the wellbore. Failure to fill the hole when pulling out drilling assemblies

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from the hole. This permits the fluid column to drop in the well, thereby reducing the hydrostatic pressure on the formation penetrated. An unusually high pressure zone is encountered and the hydrostatic head of the drilling fluid is simply insufficient to contain the formation fluids or gases. When any of the above conditions occur, the drilling fluid column will be pushed back out of the well slowly at first, but gaining speed rapidly as the column gets lighter and lighter with the entry of more and more formation fluids or gases. The main flow will be out of the annulus, but flow will also come out of the drill pipe if there is no means to shut it off. The blowout preventer is used to close the annular space therefore preventing further loss of fluid from the annulus. There are two main types of blowout preventers. These are described below.Figure 3.12. Annular preventer

Ram Type Preventers The illustration in Figure 3.11 shows two ram type preventers. The ram type preventer contains two pistons that drive two rubber packers, or rams, to meet and seal at the center of the BOP stack bore. The shape of the rams would have been selected to either close and seal on drill pipe (drill-pipe rams), close and seal on casing (casing rams) or close and seal on open hole (blind rams). The rubber elements of the rams are sheathed in shaped steel plates, or fingers, and used for an anti-extrusion device as well as provide additional strength. Some blind rams are designed specifically to cut drill pipe or tubing and seal off the well bore. These rams are known as blind, or shear, rams. The normal operating pressure to hydraulically open and close these rams is 1500 psi. Shear rams need additional force to cut drill pipe or tubing and this is achieved by putting on a larger operating piston and cylinder while still using the normal 1500 psi operating pressure. Ram-type preventer bodies can have pressure ratings that cover up to 15,000 psi. The construction of the rams in the ram-type preventers is 30

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such that a string of drill pipe can be hung from them, if necessary. Annular Preventers The illustration in Figure 3.12 shows the annular preventer, typically installed at the top of the BOP stack on the dual ram type preventer. As shown in the cross-section, the rubber packing element is a complete annular ring that is driven inwards by the upward movement of the annular piston acting on the tapered interface between the two parts. The rubber element can close and seal on any size of tubular as well as on open hole. The rubber packing element is reinforced with radial steel fingers to give the element additional strength and reduce the extrusion of the rubber when activated. The annular preventer is always installed at the top of the BOP stack. The flexibility of the annular preventer's rubber element is such that the drill pipe and it's tool joints can be stripped in to, or out of, the well with pressure contained under the rubber element. This practice is only used in emergencies and, as one would expect, this type of use causes very high wear on the rubber element. Other names used for annular preventers are bag-type preventers and spherical preventers. The normal operating pressure to hydraulically close the annular preventer is 1500 psi, but this may be reduced if the wellbore pressure is assisting the closure of the preventer on a tubular in the wellbore (there is concern about the collapse rating of the tubular, particularly if it is casing). The annular preventer returns to its open position as the annular piston is hydraulically moved downwards. The rubber element returns to it's fully open position with a considerable natural spring force in the element itself. However, in old and worn elements, this natural spring force is sometimes insufficient and this part of the BOP stack can often be a restriction to drilling tools being lowered into, or pulled out of, a well. In order to overcome this problem, the industry has adopted the practice of cutting the rubber packing elements in two so that the two halves can easily move back to their fully open position.

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ANNULAR PREVENTER

RAM PREVENTERS

Controlling a Potential Blowout Condition One of the early signs that formation fluids or gases are entering the wellbore is that the level of drilling fluid in the mud pit is rising quite rapidly as the drilling fluid is being forced out of the hole. A continuous recording pit level indicator will provide this eviCHOKE & KILL MANIFOLD dence to the driller or rig supervisor. Many pit level indicator systems have built-in alarm systems just in case the importance of the event has escaped the vigilant eye of those concerned. If it is quickly determined that the flow is indeed uncontrolled, then the next action would be to close a ram, or rams, on the BOP stack so that they close on the tubular in the wellbore. The closure of any ram or annular preventer must take place very rapidly. The reason for this is that escaping fluids can be extremely abrasive and the rubber elements can be destroyed if they move to the fully closed position too slowly. The fast closure of preventers is accomplished by having a large pre-charged reservoir or accumulator of hydraulic fluid that will instantly provide several gallons of hydraulic fluid at the 1500 psi operating pressure. The next thing that will happen is that pressure will start to increase under the closed preventer and in the drill pipe, or tubular, in the wellbore. Assuming that the drill pipe is in the hole and the kelly is attached, a means to circulate the well still exists. However, circulation will only be re-established when heavier drilling fluid is prepared in sufficient quantities to completely circulate the old drilling fluid out of the drill pipe and annulus.

GAS OR OIL

Figure 3.13. Circulating the well through the choke and kill manifold

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Choke and Kill Lines In this case, the drill pipe becomes the kill line as it is delivering the heavier fluid to kill the flow of fluids and/ or gases from the wellbore. Obviously, the returns from the annulus will be under pressure. These are taken through a choke and kill manifold which will be connected to the side outlet of the casing spool, or drilling spool, directly below the BOP stack. The line from the side outlet to the choke and kill manifold is known as the choke line (Figure 3.13). The back pressure maintained by the adjustable choke in the choke and kill manifold on the annulus returns. It ensures that the effective hydrostatic head in the annulus is sufficiently high to contain the formation fluid and/or gases that have been entering the wellbore. As the heavier drilling fluid is forced down the drill pipe and up the annulus, the pressure gauge reading on the choke and kill manifold will gradually decrease indicating that the annulus pressure is dropping. When the pressure reading has dropped sufficiently, the adjustable choke is opened to it's fully open position or it is bypassed by opening an alternative flow-path in the choke and kill manifold. When full circulation has been re-established with the heavier drilling fluid, the mud pumps will be shut down and the annulus pressure and flow will be observed to see if the well killing operation has been successful. If there is no pressure increase or flow, the closed preventers in the BOP stack will be opened and the normal circulation path, by way of the bell nipple and mud return flowline, will be re-established and drilling operations can proceed.

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This brief and simplified description of blowout preventers and their functions is merely an introduction to a very complex and important area of pressure control in drilling wells. There are many variations in the theories and practices used in controlling potential blowout conditions. The regular functional and pressure tests required for BOP stacks, BOP stack control systems and choke and kill manifolds are among the most important tests in drilling wells. One leak in the fluid path when trying to control a formation flow or kick can lead to total destruction of the drilling rig, loss of the well and extreme danger to human life. Definitely not a subject to be taken lightly.

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Completing the Well for Production

Completing the Well for ProductionPressure Testing the BOP Stack & Casing Hanger Seals ..... 35 Drilling the Hole for the Production Casing String ............... 36 Logging the Hole ....................................................................... 36 Completing the Well for Production ....................................... 38 Running the Downhole Tubing Assembly .............................. 39 The Production Tubing String ................................................. 40 Dual Zone Completions through the Production Annulus .................................................................. 44 Dual Zone Completions with a Second Tubing String .......... 44

Table of Contents

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Pressure Testing the BOP Stack and Casing Hanger Seals After the BOP Stack has been installed, the next step is to pressure test the packoff seals on the casing hanger previously landed and the BOP stack and connectors. This series of pressure tests can be done by lowering a cup tester, or special packer, on the drill pipe so that the test tool seals in the casing below the casing hanger. One of the pipe rams can then be closed onto the drill pipe. Hydraulic pressure applied through the side outlet of the drilling spool will test the BOP ram seal on the drill pipe, the metal ring gasket seal between the BOP stack and the drilling spool, the upper casing hanger packoff seal, and the seal between the test tool and the casing string. The pressure tests will be done to a specified pressure, usually 80% of the collapse rating of the suspended casing, not exceeding the working pressure of the BOP stack for a specified period of time. Any leaks would be noted as significant pressure drops and the leak, or leaks, would be investigated to determine their location. Assuming a successful series of pressure tests, including the upper pipe rams and the annular preventer, has been achieved, the rams would be opened and the test tool would be re


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trieved. A bore protector may then be installed on the next casing hanger seat to protect the sealing surfaces for the next casing hanger packoff and to protect the landing shoulder in the casing spool. Many land wellhead systems are equipped with small test ports in the casing spools to allow a pressure test to be conducted on the casing hanger packoffs without a full BOP stack test. Regular BOP stack tests will be conducted on a regular basis (once a week or more) depending on local regulations and company procedures. Drilling the Hole for the Production Casing String With all of the pressure tests successfully concluded and the bore protector in place, the next drilling assembly is made up and lowered down into the cement plugs in the casing. Using the drilling fluid used to drill the previous section of hole, the cement plugs, float collar, hardened cement and casing shoe will be drilled out and a few feet of new hole may be made. At this point, the old drilling fluid may be displaced from the hole by new drilling fluid specially prepared and weighted for the next section of hole. As this section of hole is projected to penetrate the producing formation, the conditioning of the drilling fluid is of great importance. The drilling fluid properties such as weight, viscosity and fluid loss will be checked regularly. The on-site geologist will be monitoring the cuttings coming over the shale shaker as the producing formations are approached. Once the expected formation or formations have been drilled through, the hole will have reached total depth and no further drilling will take place. The hole will be circulated to clear the last cuttings from the annulus, the drilling fluid will be conditioned and the drilling assembly will be pulled out of the hole. Logging the Hole The next operation will be to run a series of logging tools on 36

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multiple core, armored electric cable, into the hole and continuously record the formation characteristics measured by the logging tools as they are slowly pulled out of the hole at a constant speed. There are a variety of logging tools or sondes used, but essentially the logging tool has a source of energy (electrical, radio-active or sonic) that is transmitted into the formation by means of contact pads on spring loaded arms. As the logging tool is pulled slowly out of the hole, receivers in the logging tool monitor the amount of energy returning to the logging tool and the continuous recording of these return signals makes up what becomes the well log. Interpretation of these well logs can tell the well-site geologist many characteristics of the formations penetrated, such as porosity, permeability, if it is water bearing or oil bearing and if it provides an internal caliper log of the well bore. From these logs and the geologist's analysis and correlation of cuttings from the well, the subsequent decisions on how to complete or abandon the well are made. If the well being drilled was an exploration well, the decision to drill the hole deeper would also hinge on the interpretations made from these logs. For our purposes, this well is a development well being drilled into known formations and therefore our next step is to complete the well. After the logging operation has been completed and the last logging tool is out of the hole, the next step will be to run a wiper trip with the drilling assembly. This wiper trip is merely running the drilling assembly to the bottom of the hole, watching for any tight spots in the open hole section. Once on the bottom, the drilling fluid will be circulated and conditioned prior to running casing. Any tight spots in the open hole section will be reamed by the drilling assembly. In other words, the drilling assembly will be rotated, raised and lowered through the tight spots.

TUBING STRING

PRODUCTION CASING SET ABOVE THE PRODUCTION ZONE

OPEN HOLE

PRODUCTION ZONE

Figure 4.1. Top Set or Open Hole Completion

TUBING STRING

PRODUCTION CASING SET THROUGH THE PRODUCTION ZONE

PRODUCTION ZONE

Figure 4.2. Set Through Completion

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After the hole has been cleaned up, the drilling assembly is pulled from the hole, the bore protector is removed from the casing spool and the rig is prepared to run casing and cement it in place.WORK-OVER BOP STACK

TUBING HEAD PRODUCTION CASING CASING HEAD

There are generally two methods for completing a producing zone: top set, or open hole, completions and set through completions (Figure 4.1 and Figure 4.2). In an open hole completion, the production casing is run and set above the producing zone. A packer is then set inside the production casing on the tubing. A tubing stinger, located below the packer, allows the producing fluid to enter the tubing string and flow to the surface. The cementing procedure will follow the same pattern as shown in the previous chapter. Once the final displacement of cement is completed and the float valve in the casing string is holding, the next step is to install the casing hanger and casing hanger packoffs for the casing string. Again, this has been described in an earlier chapter and is depicted in Figure 4.3. Completing the Well for Production A Set through completion is generally the most common method used for completing a producing zone and will be used as a completion example. When the production casing string has been landed and tested, a cement bond log (CBL) may be run to confirm the quality of the cement job. If no remedial work is required, the BOP stack will be removed and the tubing head will be installed and packed off against the prepared stub of the last casing string. The tubing head looks very similar to a casing head, having side outlets and an internal landing profile for the tubing hanger.

DRILLING FLUID

CEMENT PLUG

PRODUCING ZONE

Figure 4.3. Cased Hole, Preparing Tubing heads are often equipped with test ports to test the to drill out cement plug

packoff seal with the last casing string as well as to test the metal ring gasket seal between the tubing head and the casing head. The tubing head will most likely be equipped with

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radial bolts, positioned in the upper part of the tubing head, that will subsequently be used to lock down the tubing hanger when it is landed in the tubing head. Running the Downhole Tubing Assembly A small bore BOP stack will be installed on the tubing head. The drilling assembly will then be lowered into the casing and run down to tag the top of the cement on the top cementing plug. The cement and top plug would be drilled out leaving several feet of good quality cement above the production casing guide shoe (Figure 4.4). This drilled depth is noted in the well log as the plugged back", or PB, depth. Next, the drilling fluid will be conditioned for perforating the casing and the drilling assembly will be pulled out. The casing and cement is then perforated all the way through to the producing formation (Figure 4.5). These perforations are made with a perforating gun, which carries shaped charges, or bullets. The perforating gun is lowered into the hole on an armored, multi-core electric cable. When the perforating gun is positioned at the correct depth, the shaped charges are electrically detonated and a known interval of casing and cement will be fully penetrated with 4 shots, or holes, per foot. The vertical length of perforations made will depend on the length of perforating gun, or guns, used.Figure 4.4. Drilling out cement plug Figure 4.5. Perforating casing

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When the perforating operation is complete and the last perforating gun is removed, the drilling assembly, complete with casing reamer, is run to bottom. Any tight spots are reamed by rotating the drilling assembly as it moves up and down through the tight spots that may have resulted from distortion of the casing during the perforating operation. After this operation, the drilling assembly is carefully pulled out taking care not to swab the well in as the producing formation is now able to flow into the casing through the perforations. The Production Tubing String The rig is then set up to run the production tubing and downhole production assembly into the casing. The illustration in Figure 4.6 shows completion using a single tubing string. In this case, the bottom of the tubing is equipped with a tubing plug nipple, with internal profile, to receive a tubing plug or tool. These tubing plug profiles are used extensively in down hole completion assemblies, especially as the completion becomes more complex. The plugs and tools set in these internal tubing profiles are run on wireline, usually by a wireline service company. The next item up in the tubing string is a blast joint. Blast joints are used, in lengths, to overlap the perforated interval and resist the potentially erosive wear that might result from a very productive zone, either oil or gas, as it enters the well bore. The next part of the downhole assembly is a hydraulically-set packer. The packer is set by applying pressure to the tubing string when it is in place and a tubing plug has been set in the bottom tubing plug nipple. The increase in pressure drives tapered segments together which, in turn, force the slip segments outwards to the bit into the production casing. At the same time, the synthetic rubber sealing elements are squeezed together to seal off the tubing casing annulus. The energy in the seals and slips are maintained after the hydraulic pressure

DRILLING FLUID

CIRCULATING JOINT OR SLIDING SLEEVE

SEALING OVERSHOT OR BLAST JOINT BLAST JOINT

PACKER

PRODUCING FORAMTIONBLAST JOINT TUBING PLUG NIPPLE PRODUCTION CASING

Figure 4.6. Installing Tubing String

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is released by a ratchet or wicker preparation within the packer body. Mechanically set packers are commonly used in this type of downhole completion. The next item of equipment shown in the illustration is another blast joint, again placed to overlap the upper perforated interval. The next piece of equipment shown is a tubing overshot that enables the lower part of the completion assembly to be left in place so that the tubing can be pulled for inspection or modification. These tubing overshots are equipped with recoverable seals in the overshot section and are usually designed to release with right-hand or left-hand rotation, as required. The mandrel section of the tubing overshot is usually equipped with an internal plug profile. The next item up is a circulating joint, or sliding sleeve. The circulating joint has an internal sleeve that can be moved up or down to open or shut circulating ports. The internal sleeve has a tubing plug profile so that a shifting tool can be set, and locked into the sleeve. This operation is done on wireline. After the shifting operation is complete, the shifting tool will be recovered. The rest of the tubing assembly shown consists of tubing terminating at the tubing plug bushing which is threaded onto the last joint of tubing. The upper end of the tubing plug bushing is equipped with internal tubing threads so that a landing joint of tubing can be installed. The assembly just described constitutes the entire tubing assembly for our example. It by no means describes all of the equipment found in downhole completion assemblies and has been used only to illustrate typical components in our theoretical well. All of the components and tubing are carefully measured prior to running to ensure their correct position inside the production casing.

TUBING


SEALING OVERSHOT BLAST JOINT

BLAST JOINT

PACKER SLIPS PACKER SEALING ELEMENT

BLAST JOINT

TUBING PLUG NIPPLE

Figure 4.7. Illustration of a typical completion tubing string

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TREE CAP SWAB VALVE WING VALVE

After the tubing assembly has been run, a slick joint tubing hanger will be installed on the last joint of tubing. The tubing plug bushing and the tubing landing joint will then be added. Next, the entire assembly is slowly lowered into place until the tubing hanger seats and seals in the internal profile of the tubing head. A tubing plug will then be run on wireline and set in the bottom tubing plug nipple. The tubing hanger seals will be externally pressure tested and, assuming tests were successful, the hydraulic packer will be set by applying sufficient internal hydraulic pressure to the tubing string. These setting pressures can range from 1,000 psi or more. The setting of the packer can usually be noted by a sudden jolt in the tubing string. If a shear out plug has been used in the bottom of the tubing string instead of a tubing plug, then a sudden drop in pressure will be noted after the setting pressure has been reached and the plug shears out of the bottom of the tubing. After the hydraulic packer is set, the landing joint of tubing is removed. The BOP stack is removed and the tubing bonnet is bolted to the tubing head spool (Figure 4.8). This traps and seals the tubing plug bushing. The production tree, or christmas tree, can then be bolted to the tubing bonnet. The next step is to displace the drilling fluid from the tubing and the tubing casing annulus. This is done by first mounting a wireline lubricator on top of the production tree. The wireline service company will then open the swab valve and two production valves on the tree and then lower the shifting tool down to the circulating sleeve. The sleeve will be moved to the open position so that the circulating ports are open. The drilling fluid is displaced by water or crude oil by pumping down the tubing by way of the upper wing valve and taking the annulus returns through the annulus wing outlets. Next, the wireline operator will shift the sleeve in the circulating joint to the closed position and retrieve the shifting tool. A

UPPER MASTER VALVE LOWER MASTER VALVE

TUBING HEAD

STARTING HEAD

TUBING STRING

PRODUCING ZONE

Figure 4.8. Nipple down BOP Stack and install production tree

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FLOW COUPLING

retrieving tool will then be run in to recover the tubing plug in the bottom of the tubing. Now the well is live, but has COMPLETION not yet been unloaded (FigFLUID ure 4.9). This unloading operation describes the initial production from the perforations in the producing formaFLUID FROMTHE tion as it pushes the displaced PRODUCING ZONE water or crude oil out of the tubing or annulus. The unloading usually starts slowly but, as the water or dead oil is pushed out of the well, it gains speed until the live crude oil, with its associated gas, surges out flare lines attached to the side outlets of the production tree into a collection tank or sump. When it is decided that the producing zone, or zones, has cleaned up sufficiently, the well is closed by shutting the production master valves and the annulus wing valves.

SEATING NIPPLE FLOW COUPLING

PRODUCTION TUBING


UPPER PRODUCTION ZONE

PACKER

The flowlines from the well are then connected to any processing equipment required before the crude oil or gas enters the main gathering LOWER PRODUCTION ZONE lines. Simple processing of the produced oil and/or gas Figure 4.9. Illustration showing includes de-watering, or sepathe well being "unloaded", or rating, the bulk of the gas from Figure 4.10. Dual zone completion through the production casing anbrought on stream the crude oil. nulus

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FLOW COUPLING SEATING NIPPLE FLOW COUPLING FLOW COUPLING SLIDING SLEEVE FLOW COUPLING

UPPER PACKER FLOW COUPLING SEATING NIPPLE FLOW COUPLING PERFORATED SPACER TUBE

PINNED COLLAR

SEATING NIPPLE

UPPER PRODUCTION ZONEBLAST JOINT FLOW COUPLING

Dual Zone Completions and Dual Zone Completions through the Production Annulus The rig is then set up to run the production tubing and downhole production assembly into the casing. The illustration in Figure 4.10 shows dual zone completion using a TUBING STRING TUBING STRING FOR UPPER single tubing string. In this FOR LOWER ZONE PRODUCING ZONE PRODUCING case, the bottom of the tubing is equipped with a tubing plug Figure 4.12. Dual string tubing nipple with internal profile to hanger receive a tubing plug or tool. These tubing plug profiles are used extensively in down hole completion assemblies, especially as the completion becomes more complex. The plugs and tools set in these internal tubing profiles are run on wireline, usually by a wireline service company). While this technique has been practiced, it is not common. Dual Zone Completions with a Second Tubing String A Second way of configuring a dual zone completion is with a second packer and tubing string. The illustration in Figure 4.11 shows dual zone completion using two tubing strings. In this case, a second packer is set above the upper producing zone which allows the first tubing string to pass through it and has a recepticle for a second tubing string. The tubing strings will usually be designed with more flow control equipment in it. The plugs and tools used to set plugs and control the tubing tools will again be run on wireline. When a dual zone completion is considered with a second tubing string, the tubing hanger at the surface will be configured to accomodate two tubing strings (Figure 4.12). In this case, the production tree will have two master valves, two swab valves and two wing valves in the each tubing string.

LOWER PACKER

SEATING NIPPLE PERFORATED SPACER TUBE SEATING NIPPLE

LOWER PRODUCTION ZONE

Figure 4.11. Dual zone completion through the a second tubing string

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A completion tree that accomodates a dual zone completion will have two production bores (Figure 4.13). Typically, a master valve block is utilized to reduce leak paths and reduce stack up heights. Conclusion Our theoretical well is now complete and has been used to illustrate a number of the operations and practices used in drilling and completing wells. There are many variations to the size and ratings of wellheads, BOPs and production trees, not to mention the corrosive problems of H2S and CO2. However, it is hoped that these notes have given the reader an insight into the fundamentals of onshore operations.

Figure 4.13. Typical Dual completion tree

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Casing & Casing Connectors Used in Offshore DrillingFunction ..................................................................................... 47 Grades of Steel ........................................................................... 49 Thread Forms ............................................................................ 49 Special Large Diameter Thread Forms .................................. 52 Special Large Diameter Connectors ........................................ 52 Offshore Casing Programs ....................................................... 55

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Casing & Casing Connectors Used in Offshore Drilling

Function The function of steel casing in drilled wells is to provide a strong sheath, or liner, to the hole. The casing selected for a particular size of hole will be expected to withstand external formation pressures acting to collapse the casing as well as resist anticipated internal pressures trying to burst the casing. The tensile strength of the casing will also be carefully reviewed with respect to the length and weight of casing being suspended in the hole. Casing that has been cemented in place has an impro

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