Drilling Manual Drill Quip

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 Accumulate Introduction ................................................................................ 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

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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).

Figure 1.3. Stratigraphic Trap

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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

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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 weren’t 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 it’s 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.

Figure 1.4. Salt Dome Trap

Pressure Gradients Fresh water has a pressure gradient of 0.433 psi/ft. and sea®

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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 Drilling Introduction ................................................................................. 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.

Figure 2.1. Illustration of a land drilling operation

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,


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Configuration of a Rotary Drilling Rig

CROWN BLOCK

WATER TABLE

DRILLING LINE MAST OR DERRICK STRUCTURE TRAVELING BLOCK GOOSENECK

HOOK

ROTARY HOSE

SWIVEL

STAND PIPE

KELLY COCK KELLY

MUD PUMP OR SLUSH PUMP

STAND PIPE VALVE

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

GROUND RETURN FLOWLINE

SUCTION PIT

CELLAR

BELL NIPPLE SETTLING PIT BLOWOUT PREVENTER STACK

CEMENTED CONDUCTOR

CASING HEAD

SHALE SHAKER

CEMENTED CASING CASING SHOE DRILL PIPE ANNULUS RETURNS WELLBORE

LEGEND DRILLING FLUID

DRILL COLLARS DRILL COLLAR SUB DRILLING BIT

CIRCULATION PATH

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.

Figure 2.3. Photo of a typical drilling bit

STABILIZER

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.

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.

Figure 2.5. Photo of a typical kelly and kelly bushing

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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.

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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.

Figure 2.8. Photo of a typical derrick

Figure 2.9. Photo of a typical mud pump.

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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

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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.

Figure 2.11. Photo of a typical rotary hose

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

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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.

CROWN BLOCK

DEADLINE

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.

FAST LINE 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

Rotating System Figure 2.14. Photo of a typical rotary

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

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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".

Figure 2.15. Photo of a typical substructure.

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.

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

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.

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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 Top Drive

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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 Land Introduction ............................................................................... 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

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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.

CONDUCTOR

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

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


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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

CELLAR STARTING HEAD

DRILLING BIT

Figure 3.2. Preparing to drill out for surface casing

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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 ®

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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.

ROTARY TABLE

RIG FLOOR

RISER

SURFACE CASING

CELLAR STARTING HEAD

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 ®

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A

B

CEMENTING HEAD TOP WIPER PLUG BOTTOM WIPER PLUG

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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.

CASING SLIPS

BELL NIPPLE

STARTING HEAD

DRILLING FLUID

FLOAT COLLAR

FLOAT SHOE

Figure 3.4. Setup for Cementing casing into place

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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 ®

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A

B

CEMENTING HEAD TOP WIPER PLUG

CEMENT

BOTTOM WIPER PLUG

DRILLING FLUID

FLOAT COLLAR

FLOAT SHOE

Figure 3.5. Cementing operation in progress

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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 3.6. 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).

DRILLING FLUID

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).

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

Figure 3.7. Cement in place around the casing

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. 26

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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.

Casing Hanger

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

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

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water. A good cement job will also enhance the burst strength capacity of the 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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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

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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

GAS OR OIL

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

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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.

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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

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Completing the Well for Production Pressure 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

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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.

TUBING STRING

PRODUCTION CASING SET ABOVE THE PRODUCTION ZONE

OPEN HOLE

Figure 4.1. Top Set or Open Hole Completion

TUBING STRING

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.

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PRODUCTION ZONE

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

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.

CASING HEAD

DRILLING FLUID

CEMENT PLUG

PRODUCING ZONE

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.

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. Figure 4.4. Drilling out cement plug

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.

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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

DRILLING FLUID

CIRCULATING JOINT OR SLIDING SLEEVE

SEALING OVERSHOT OR BLAST JOINT BLAST JOINT

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.

PACKER

PRODUCING FORAMTION BLAST JOINT TUBING PLUG NIPPLE PRODUCTION CASING

Figure 4.6. Installing Tubing String

40

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 ®

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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.

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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

41


TREE CAP SWAB VALVE WING VALVE

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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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 ®

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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 ZONE BLAST JOINT FLOW COUPLING

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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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 LOWER single tubing string. In this FOR PRODUCING ZONE PRODUCING ZONE 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.

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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, BOP’s 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 Drilling Function ..................................................................................... 47 Grades of Steel ........................................................................... 49 Thread Forms ............................................................................ 49 Special Large Diameter Thread Forms .................................. 52 Special Large Diameter Connectors ........................................ 52 Offshore Casing Programs ....................................................... 55

5

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 improved resistance to burst pressure, but this extra burst capacity is usually discounted as the quality of the cement behind the casing is not quantifiable. The purpose of cement in the casing/hole annulus is generally to stop the migration of fluids or gases from a zone to the surface. It also aids in improving the pile or load-bearing (compressive strength) capacity of surface conductors and casing strings. Casing provides a smooth internal bore for the passage of drilling tools and downhole assemblies while, at the same time, giving a maximum guaranteed bore dimension (drift diameter). This is particularly important in order to avoid the possibility of jamming downhole equipment into the casing.

Casing and Casing Connectors Used in Offshore Drilling

5

Minimum Yield PSI *

Minimum Tensile PSI **

Grade

API Specs

A

5L & 5LS

Line Pipe Conductor, Structural

30,000

48,000

B

5L & 5LS

Line Pipe, Conductor, Structural

35,000

60,000

H-40

5A

Casing, Tubing

40,000

60,000

X-52

5LS & 5LX

Line Pipe, Conductor, Marine Riser

52,000

66,000

X-56

5LS & 5LX

Line Pipe, Conductor, Marine Riser

56,000

75,000

J-55

5A

Casing, Tubing

55,000

75,000

K-55

5A

Casing, Tubing (Corrosion Resistant)

55,000

95,000

X-65

5LS & 5LX

Line Pipe, Marine Riser

65,000

80,000

E-75

5A

Drill Pipe

75,000

100,000

C-75

5AC

Casing, Tubing (Corrosion Resistant)

75,000

95,000

N-80

5A

Casing, Tubing

80,000

100,000

X-95

5AX

Drill Pipe

95,000

105,000

P-105

5AX

Tubing

105,000

120,000

G-105

5AX

Drill Pipe

105,000

115,000

P-110

5AX

Casing

110,000

125,000

Q-125

5AQ

Casing

125,000

135,000

S-135

5AX

Drill Pipe

135,000

145,000

V-150

5AX

Casing

150,000

160,000

Application

* Minimum value of stress or elongation, before permanent deformation occurs * *Maximum value of stress or elongation, before permanent deformation occurs Figure 5.1

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Grades of Steel Casing is made from various grades of steel with different wall thicknesses to accommodate the physical requirements of burst, collapse, tensile strength and drift diameter (mentioned earlier). Also, the chemical composition of the steel is important if the casing is to resist corrosive gases or fluids, or if it is to be easily welded to other steel components. Welding to casing is not generally very easy because of the high carbon content in the steel alloys used for the casing. The American Petroleum Institute (API) has set the accepted industry standards for the dimensional, physical and chemical properties of casing, tubing, drill pipe and line pipe. Figure 5.1 is a brief summary of the grades of pipe most commonly used in the oil industry. Thread Forms The thread forms used in casing couplings and connections are required to provide a strong, pressure tight means of screwing lengths of casing together. The simplest thread form used in the oil industry is a rounded thread machined directly on to the pipe ends. Usually, there are 8 threads per inch and the thread form is machined on a taper of 3/4" per foot. The threaded end of the casing is called a male thread, or pin. The casing coupling is a short length of large diameter pipe, threaded internally with a matching thread form. The coupling is usually installed on one threaded end (at the mill site). The exposed half of the coupling thread form is called a female thread, or box. The casing is normally run in the hole in a box up/pin down manner. The eight-round thread form is a metal-to-metal sealing thread when made up to the recommended torque value. As deeper wells were drilled, the demands for increased tensile load capacity and pressure ratings increased and new thread forms were developed. Longer couplings were used to extend thread forms and rugged square thread forms (with 5 threads

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Typical Standard Casing Thread Forms

API Non-Upset Threaded and Coupled joint with 8 Round threads per inch

Mill Buttress Threaded and Coupled joint with 5 threads per inch

Threaded and Coupled Joint with Square Thread Form and Trapped Pin Ends

API Modified Threaded and Coupled Joint with Teflon Seal Ring

Integral Threaded Joint with Resilient Seal Ring

Integral 2 Step Threaded Joint with Metal-to-Metal Seals

Figure 5.2

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per inch) were machined on the pipe ends giving rise to the commonly used mill buttress casing. Couplings, with internal shoulders, were introduced to prevent thread galling problems caused by over-torque. The internal shoulders were prepared with a reverse angle to trap the nose of the pin end of the thread and to also generate a metal-to-metal seal. Sometimes, the casing was prepared with an upset or thicker walled section at each end so that a stronger thread form could be machined directly on to the upset section. Teflon seals were introduced and two step thread forms were used in special cases. The following cross sections give a brief look at some of

HORIZONTAL CAM KEY

E-60

S-60

C-60

FB-60

H-60

H-90

S-60D

FB-60D

H-60D

H-90D

D-60

D-90

VERTICAL SLOT KEY

Figure 5.3. Illustration of the AntiRotation Keys of the threaded Specialty Connectors

Cross Section of DRIL-QUIP QUIK-THREAD and Multi-Threaded Specialty Connectors Figure 5.4

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the more popular casing connections (Figure 5.2). Special Large Diameter Thread Forms The thread forms previously illustrated could be used on nearly all casing sizes up to 20" OD. The main problem with fine thread forms on large diameter pins and boxes is cross threading. This results in a lot of expensive lost time when running the casing. The answer to this problem has been solved on large diameter casing and conductors, up to 30" OD, by using very coarse 2-pitch or 3-pitch rounded thread forms on generous tapers (Figure 5.3). These new thread forms allow good stabbing characteristics and fast thread make-up,

SL-60

SF-60

NS-60

HD-90

NF-60

HF-90

FOD-90

Cross Section of DRIL-QUIP QUIK-STAB Weight Set Specialty Connectors Figure 5.5

MULTIPLE LOAD SHOULDER

ANTIROTATION PIN

DUAL TAPER

LOCK RING INSTALLATION GROOVE

while virtually eliminating cross threading. These proprietary thread forms are machined on pin and box forgings and the finished pins and boxes are then welded on to line pipe. Resilient seals are usually used to provide the pressure integrity of the joint. The reverse back angles on thread forms and shoulders are used to provide additional burst capacity and bending load capacity. Special Large Diameter Connectors There are some instances where the use of threaded connectors is not the best practical means of connecting large diameter tubulars together. Sometimes, with poor surface hole

Figure 5.6. Cross section of the Quik-Stab Connector

52

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conditions, the speed of running the conductor or casing becomes the most important criteria. For these occasions, automatic connectors that use lock rings provide the fastest means of make-up (Figure 5.5). These automatic connectors are machined from pin and box forgings and welded to lengths of line pipe. The pin member usually carries a lock ring which is depressed as the box member stabs over the pin. When the box is correctly seated, the lock ring snaps in to a matching groove in the box and the two connector halves are locked together. Large resilient seals are carried on the pin member and seal against prepared surfaces inside the box member. These special large diameter connectors also incorporate an anti-rotation feature, usually a key, or pin, that is located in a matching slot or groove on the box member (Figure 5.6). These large diameter connectors are automatic and particularly useful when tubulars need to be lowered down into the hole without the risk of any rotation induced by the make-up of connectors. The connection at the bottom of the subsea Hole/Bit Size

Casing Size

Grades of Steel

Setting Depths Below Sea Floor

36"

30" OD x 1.000" Wall 310 lb-ft

A or B Line Pipe

100' - 500'

26"

20" OD x 0.625" Wall 133 lb-ft

X-52 / X-56

400' - 1600'

17-1/2"

13-3/8" OD 68 lb-ft

J-55 - N-80

1400' - 5000'

12-1/4'

9-5/8" OD 47 lb-ft

C75 - P110

4000' - 13000'

8-1/2"

7" OD 23-35 lb-ft

C75 - V150

6000' - 22000'

Figure 5.7

wellhead housing joint is a case in point. The object here is to avoid any rotation from being imported to the cam actuated

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Typical Offshore Casing Program 30" x 20" x 13-3/8" x 9-5/8" x 7" Mudline Suspension Equipment

18-3/4" Subsea Wellhead System

150' - 500'

36" HOLE 30" CASING

500' - 1600'

26" HOLE 20" CASING

17-1/2" HOLE 2000' - 4500'

13-3/8" CASING

12-1/4" HOLE 5000' - 12000'

6000' - 20000"

9-5/8" CASING

8-1/2" HOLE 7" CASING

Figure 5.8

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running tool used to lower the wellhead housing into position. Automatic connectors also find widespread use in hammer driven conductors and piles, where no threaded make-up capability exists. The following cross sections of DRILQUIP's automatic connectors amply illustrate the features discussed in this section. Offshore Casing Programs The most commonly used casing program used in offshore exploration drilling,, from bottom supported or floating drilling vessels, is tabulated below. The illustration in Figure 5.8 gives a diagrammatic crosssection through a mudline suspension system and a subsea wellhead system showing the relationship of hole size to casing. The classic casing program illustrated will be modified if an additional casing string is required, or one is left out. An extra casing string may be required to shut off a lost circulation zone or a section of hole with caving or swelling shale problems. Some examples of other casing programs follow: Examples: 36" x 24" x 18-5/8" x 13-3/8" x 9-5/8" x 7" Casing Program 30" x 20" x 16" x 13-3/8" x 9-5/8" x 7" Casing Program 30" x 16" x 10-3/4" x 7-5/8" Casing Program The last example is more likely to be used for a development well as the drilling conditions are known and the protective casing strings, anticipated in the exploration well, can be left out. Also in development drilling, the production string of casing will be designed to accommodate the largest downhole tubing completion compatible with the expected production of oil and/or gas.

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The casing program design becomes very important in development drilling. It ensures that optimum sizes of casing are used, still maintaining accepted safety or design factors, relative to the economics of drilling the well and it's productive life. Design factors used in casing string analyses are justifiably conservative. Using a factor of 1.00 to represent the material strength of the casing in question, commonly used design factors are tension 1.75, burst 1.5 and collapse 1.1.

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Offshore Drilling from a Jackup Drilling Vessel Introduction ............................................................................... 57 Jack-up Drilling Vessels ........................................................... 60 Drilling a Well From a Jack-Up Drilling Vessel Using Mudline Suspension Equipment and a Conventional Surface Wellhead System ................................................... 61 Introduction ............................................................................... 61 Mudline Suspension Equipment .............................................. 61 Primary Conductor Installation .............................................. 63 Flow Diverters ........................................................................... 66 Drilling Ahead For the 20" Casing String .............................. 67 Running and Cementing the 20" Casing ................................ 67 Running and Cementing 13-3/8" Casing ................................ 71 Running and Cementing 9-5/8" Casing .................................. 74 7" Mudline Casing String......................................................... 76 Well Abandonment ................................................................... 76 Installing Temporary Abandonment Corrosion Caps .......... 78 Alternative Stab-in TA Caps .................................................... 80

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Table of Contents

6

Offshore Drilling from a Jackup Drilling Vessel

Introduction The previous chapters of this manual have been focused on the review of common practices and procedures for drilling a development well on land, and completing the well for production. The next chapters will be devoted to a similar treatment of drilling and completing wells offshore. The natural evolution of offshore drilling occurred when the known geological formations of existing oil or gas fields could easily be extrapolated beneath coastlines, waterways or lakes in producing areas. The means to tap into these additional reserves was achieved by extending jetties and causeways out into the open water. These jetties and causeways provided a solid base for the land drilling rigs to be established, and development or exploration wells were drilled and completed using the land drilling techniques previously described in this manual. This form of offshore drilling was established around the year 1900 and was the primary method of developing offshore reserves of oil and gas for many years (Figure 6.1). The concept of using a customized barge with the drilling rig and required support equipment was put into practice in Louisiana in the early 1930's. The original intention was that the barge would provide a stable floating base to drill from. Figure 6.1. Jetty drilling and Jack-up


6

Figure 6.2. Time Chart; Evolution of Offshore Drilling

However, the load of equipment and material on board caused it to rest on the bottom of the shallow bayou where it was located. Drilling proceeded from the partially submerged barge and the first "submersible" drilling vessel was in business. Meanwhile, the improvements in seismic surveys and geological extrapolations indicated the existence of many large geological structures under the shallow waters of the Gulf of Mexico. To reach these locations many miles offshore, the cost of establishing jetties and causeways was prohibitive and therefore more mobile or independent drilling bases were designed and built (Figure 6.2). These designs evolved from 58

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CROWN BLOCK WATER TABLE DRILLING LINE MAST OR DERRICK STRUCTURE JACK-UP LEG TRAVELING BLOCK GOOSENECK ROTARY HOSE STAND PIPE

HOOK SWIVEL KELLY COCK KELLY


STAND PIPE VALVE

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

SUCTION PIT SETTLING PIT SHALE SHAKER

RETURN FLOWLINE BELL NIPPLE BLOWOUT PREVENTER STACK CASING HEAD

30" RISER

JACK-UP HULL

WATER LINE 20" CASING

RELEASABLE CONNECTOR MUDLINE SUSPENSION SYSTEM

MUDLINE

DRIVEN 30" CONDUCTOR DRILL PIPE CEMENTED 20" CASING

Figure 6.3

CASING SHOE ANNULUS RETURNS DRILL COLLARS DRILL COLLAR SUB

WELLBORE

DRILLING BIT

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6

the "jetty" and "submersible" technology already established, as shown in the time chart. These new offshore drilling and productions systems; platforms, jack-ups, semi-submersibles, drillships, and tension leg platforms are described in the following chapters. Jack-up Drilling Vessels Jack-ups are the most commonly used mobile drilling vessels used in offshore exploration and/or development drilling. The basic design of a jack-up drilling vessel is a custom built floating hull section equipped with a complete drilling rig and living quarters for operating personnel. The jack-up is also equipped with three or more large legs that can be raised or lowered using powerful jacking assemblies. The jack-up is generally towed to location by tugs with the legs in the raised position. When at the selected drilling site, the legs are jacked down to the sea floor or lake bed. Quite often, a prior survey of bottom soil conditions will have given an idea of the penetration that can be expected from the legs. It is common practice for the feet of the legs of the jack-up to be equipped with water jets to assist in getting the legs down through mud etc. to solid, load-bearing strata. When each leg is determined to be on solid footing, it will be separately load-tested to ensure that the legs will not move down unexpectedly when the hull section, with its full operating load, is jacked up to its operating height above the water. This height, or air gap, is generally in the range of 60-80 ft. above the mean-water level depending on sea or weather conditions expected. In this mode, the jackup provides a stable platform for wells to be drilled using conventional land drilling techniques. Jack-ups can drill in water depths of 50 ft. to 500 ft. depending on their size, specifications and bottom conditions. Some jackups are equipped with a reinforced steel sea-floor, “mat”, which is attached to the legs of the jack-up and rests on the seafloor when the legs are jacked down. The purpose of the “mat” is to distribute the downward load from the legs more evenly, as a means of avoiding the point loading that occurs when 60

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individual legs penetrate the sea-floor. The drilling mast, or derrick, on jack-ups is generally designed to move laterally within the hull section of the jack-up so that a number of wells can be drilled from the jack-up on a known well center spacing. This feature is particularly useful if the jack-up is drilling wells through a sea floor drilling template, or if it is being used in a cantilever mode over an established steel platform jacket with multiple well conductors. As noted previously, jack-ups come in various sizes and configurations. The smaller jack-ups may not have enough space or capacity to house all of the pipe racks, pumps or drilling fluid storage that a conventional land rig set-up would include. The use of a “tender”, or customized barge, with all of the necessary support equipment on it and adjacent to the jack-up provides the extra space and capacity.

CONVENTIONAL WELLHEAD SYSTEM

MUDLINE SYSTEM

Drilling a Well From a Jack-Up Drilling Vessel Using Mudline Suspension Equipment and a Conventional Surface Wellhead System Introduction This section of the manual describes the equipment and general practices used in drilling a single offshore exploratory well from a jack-up. The assumption is made that the reader is already familiar with land drilling and completion practices. Mudline Suspension Equipment The use of mudline suspension equipment in drilling wells from jack-ups has become a common practice. In the early days of jack-up drilling, the primary conductor would have been made up from welded sections of large diameter steel pipe. The subsequent casing strings would be suspended from the casing heads and spools installed at the cellar-deck level. There are seldom any disconnect points in the conductor or the casing strings at the mudline. They would be removed by cutting through all of the strings at or below the mudline ®

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System Features • Standard service system rated for 15,000 psi • H2S service system rated for 10,000 psi • High load carrying capacity • Stack down system Running Tool Features • Right hand rotation releases running tool. • Wash out ports are located in the running tool and not the hanger. • Two resilient seals and a metal-to-metal seal are located above the wash out ports in order to assure re-seal after wash out. • The seal below the wash out ports is located sufficiently (3 turns) from the ports so that no cement can be washed into the threads. • A one-way seal located at the bottom of the running tool protects the tie-back seal areas during wash out. • All running tools are fully aligned prior to thread contact to prevent cross-threading in case the tool must be remotely stabbed. • Available without wash ports. Hanger Features • Large flow-by area designed to allow full 360o bearing area between load shoulder and landing shoulder for greater hanging capacity. • All hangers stack down, fully exposing the tie-back thread and seal areas. • Running and setting of hangers is accomplished in a single trip. • All hangers are simple weight set designs. No rotation or lifting is required to set the hangers. • Each mudline hanger is equipped with a left hand running thread and right hand tie-back thread. • Two separate metal-to-metal seal preparations are included in each hanger. One running tool seal area and one for tie-back tools.

MS-15 Mudline Suspension System Figure 6.4

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using a mechanical cutter run on drill pipe, or alternatively blasted apart using one large explosive charge run inside the last casing string. Mudline suspension equipment provides a means of mechanically disconnecting all conductor and casing strings at or below the sea level. The following summary of the major features of a modern mudline suspension system also highlights additional advantages: •

Casing loads are suspended at or below the sea-bed (mudline) which means the loads supported at the cellar-deck level are greatly reduced.

•

Each mudline suspension casing hanger is equipped with a mechanical disconnect point, usually in the form of a coarse right hand release thread form. This means that cutting tools and explosives are not required when abandoning the well either temporarily or permanently.

•

Usually a re-connection point is also provided in the mudline casing hanger design so that a well can be reentered with tie-back strings and seals. These reconnection points are usually in the form of right hand make-up thread forms.

•

Mudline casing hangers are usually designed with circulation ports that can be opened and closed mechanically. These circulation ports are used to circulate out any excess cement that has got into the annulus above the casing hanger during the casing cementing operation.

•

The pressure and load capacity ratings of mudline casing hangers are normally greater than the attached casing strings.

Primary Conductor Installation After the jack-up has been elevated to its drilling position and ®

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RELEASING SCREWS

6

the support equipment is all in place and hooked up, the next operation is to establish the primary drilling conductor which is generally driven into place with a diesel or steam hammer.

RESILIENT SEAL

The primary conductor is usually made up of 40 ft. sections (sometimes 50 ft.) of thick walled large diameter steel pipe. 30" ANTI-ROTATION O.D. x 1" wall pipe is commonly used, but larger sizes and PIN different wall thicknesses are used in special applications. The 40 ft. lengths of conductor can either be welded together or be Figure 6.5. 30" Quik-Stab Connector equipped with specialty connectors that fit together very quickly. These specialty connectors can be the automatic variety using a lock ring that snaps into a lock ring groove as the two halves come together, or they can use large modified square thread forms that require rotation and torque to make up the joints (Figure 6.5). These large diameter connectors usually have generous bearing shoulders to withstand heavy driving loads and are equipped with large resilient seals. LOCK-RING

LOCKING SEGMENTS

RESILIENT SEALS

HF-60/90 QUIK-STAB CONNECTOR BOX PROFILE

Figure 6.6. 30" Quik-Jay Connector

Some primary conductor strings will also include a remotely releasable connector above the mudline (Figure 6.6). This connector must also provide the ability to be reconnected in the event the well will be tied back for subsequent drilling or completion. The 30" conductor string may also be equipped with an internal landing shoulder that will be positioned at, or near, the sea-bed after the conductor is driven into place. The landing shoulder will provide the seat for the mudline casing hanger on the next casing string. For handling purposes, the 40 ft. lengths of conductor may be equipped with two steel pad-eyes with a flat landing base. These pad eyes are usually welded to the outside of the conductor about 3 ft. from the upper end and are used to

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45 DEGREE LANDING SHOULDER

MINIMUM ID

Figure 6.7. 30" Buttweld Sub

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land the joint at the rotary table, or on a false rotary, so that the next joint can be connected. When the next joint has been connected, the conductor string is picked up and the pad eyes are cut off. The conductor string is then lowered until the next set of pad eyes lands at the rotary table. This procedure continues until the conductor string starts to take weight on the sea-floor. At this point, the conductor string will be driven by a diesel or steam hammer. Conductor lengths are added as the conductor string is driven downwards into its refusal position. The point of refusal will be stated as a number of blows-per-foot for a two or three foot interval. The size and energy output of the hammer will be used to determine the required blows-per-foot at refusal. An alternative to using pad eyes for running the conductor is to use two sets of conductor elevators, one set used as a landing shoulder and the other set to pick up and lower the next joint into position. Figure 6.8 illustrates the components in a driven conductor string. The shoe joint of a driven conductor is open-ended with the shoe being reinforced with additional metal and prepared with a vee shaped or wedge shaped cross-section. The required penetration of the primary conductor into the sea-floor will have been established before the conductor string is assembled and lowered to the sea-floor. The required minimum penetration is usually determined by the local regulating authorities with a stated number of blows per foot as the conductor reaches refusal conditions.

HAMMER JOINT

CONDUCTOR PIPE

QUIK-STAB CONNECTOR

QUIK-JAY CONNECTOR

BUTTWELD SUB

QUIK-STAB CONNECTOR

If the driving conditions are difficult, the conductor may not be close to minimum penetration depth even though refusal DRIVING SHOE conditions have been met. In this case, the drilling rig is set up to drill out of the shoe and into formation below to a specified depth. The drilling assembly is pulled out of the hole and Figure 6.8. 30" primary conductor driving operations are re-started. casing string There are two other means of getting the primary conductor into place. These consist of drilling a hole and cementing the ®

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PACKER ELEMENT DIVERTER ASSEMBLY

ROTARY TABLE AND SUB STRUCTURE

6

conductor in place, or jetting the conductor into position. These methods are generally not used as they tend to disturb the bottom sediments more than the driving method, and therefore reduce the pressure containing capability of the installed conductor. Assuming the primary conductor has been driven into place, it is most likely that the last conductor section added to the drive string will be cut off at the cellar-deck level. A large flanged starting head, or casing head, will then be welded to the conductor. This starting head may have an internal landing shoulder to land the casing hanger from the next casing string.

DIVERTER HOUSING

OVERSHOT RISER SPOOL

OVERSHOT PACKER ASSEMBLY

CONDUCTOR SUB

Figure 6.9. Flow Diverter

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The section of the primary conductor above the sea bed is called a “riser”, so named because it has raised the circulation level of the drilling fluid from ground zero. In this case, the circulation level is raised from the sea floor to the cellar-deck level of the jack-up directly below the rotary table. This riser section of the conductor will normally be in compression and may need lateral support. If the riser section is particularly long and the conductor cannot be used in a free-standing condition, then a tensioning system comprising pad-eyes and turnbuckles will be used to support the riser. Flow Diverters The use of flow diverter systems on jack-up drilling vessels has become a common practice, particularly in exploratory drilling (Figure 6.9). The flow diverter will be installed on the primary conductor and it may consist of a large annular preventer, or a customized flow diverter. The purpose of the flow diverter system is to provide a means of closing the annular space between the drill pipe and the primary conductor above large bore side outlets. The flow diverter system is activated in the event of drilling into an unexpected pocket of shallow formation gas at a pressure which overcomes the hydrostatic head of the drilling fluid in the hole creating a potential blowout condition. The rubber packing element in the annular preventer, or flow diverter, is closed on the drill ®


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pipe. If there is no drill pipe in the hole, the packing element is designed to close off the open hole. At the same time a large side outlet below the diverter is opened to a large bore flare line extending outboard of the jack-up. There is usually more than one flare line, and the choice will depend on prevailing wind direction. The fluid and/or gas coming out of the well is allowed to blow out of the flare line, clear of the rig, with no effort to control the well bore pressure. Most shallow pockets of gas are small in volume and will blow down quite fast, sometimes in a matter of minutes but usually in a few hours. Any effort to put back pressure on the formation by a choke mechanism may cause the formation to break down at the conductor shoe, leading to the potential hazards mentioned earlier, namely gas breakthrough at the sea floor and possible cratering. When the blow of gas from the shallow packet is exhausted, the drilling fluid column will be re-established and the drilling operations can proceed again. Because of the dangerous conditions that can exist during the operation, all of the control functions of the flow diverter system can be controlled from a remote or alternative location on the jack-up. Drilling Ahead For the 20" Casing String When the diverter system has been installed at the top of the primary conductor, the bell nipple and mud return flowline will be hooked up and drilling for the next casing string can commence. Sea water will almost certainly be used as the drilling fluid and the hole will be drilled to casing depth. The hole will be circulated clear of cuttings and the drilling assembly will be pulled out of the hole.

ALIGNING PROFILES

ALIGNING PROFILE

RESILIENT SEAL

Figure 6.10. Quik Thread Connector

Running and Cementing the 20" Casing The next casing string used inside the primary conductor will be large diameter, usually in the size range 16"-24" OD. The most common size is 20" OD and is usually supplied in 40 ft. lengths and equipped with right hand threaded connections. Because the daily operating costs for jack-up drilling are high, a lot of attention is given to time saving equipment and practices. Fast make-up connections specially designed for ®

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large diameter conductors and casing is one area where considerable time savings are achieved over traditional thread forms.

CASING THREADS METAL SEAL BACK-UP RESILIENT SEALS WASH OUT PORTS RESILIENT SEALS RUNNING THREADS ONE WAY SEALS

Figure 6.11. 20" Mudline Hanger Running Tool

TIE-BACK THREADS RUNNING THREADS

20" OD casing can be supplied from most pipe mills with 8 round threads per inch or a mill buttress thread form with 5 threads per inch. In practice, these threads can be difficult to make-up offshore, particularly if high winds are prevailing and cross-threading is not uncommon. Modern thread forms for 20" casing are usually 2 or 3 threads per inch, which means the threads are coarser, therefore more rugged and less prone to damage (Figure 6.10). Also, the threads are a rounded design and machined on a generous stabbing taper sometimes incorporating a reverse angle on the back flank of the thread form to create very positive engagement and greater burst capacity. Most of these modern threaded connections come equipped with a resilient seal and many are designed with metal-to-metal sealing capabilities. These proprietary threaded pin and box couplings are usually machined from high quality steel forgings and are equipped with a 20" weld preparation to match the plain end 20" OD pipe. Some manufacturers provide the completed 40' long joints or weld the pin and box connectors to the 20" pipe provided by their customers.

LANDING RING FLOW-BY HOLES RETAINER RING

LANDING SHOULDER FOR 13-3/8" MUDLINE HANGER

CASING THREADS

Figure 6.12. 20" Shoulder Hanger

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Sometimes in special circumstances, automatic connectors with incorporated lock-rings are used. These pin and box connectors simply stab together using the weight of the casing joint and lock ring, usually carried on the pin member and snaps into position in a lock ring groove on the box member. The casing string is made up using the threaded connections in a box up/pin down mode. Each length of casing used would be recorded and the mudline suspension casing hanger and running tool would be spaced out precisely in the casing string. The running string of casing above the running tool is usually identical to the casing string suspended from the mudline suspension hanger (Figures 6.10 and 6.11). The running string is also spaced out so that no coupling or ®


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connection interferes with the subsequent wrap-around casing hanger installation in the surface casing head. When the casing string has been run and landed correctly on the mudline shoulder in the primary conductor, the running string will extend above the rotary table and the cementing head will be attached to the top of the casing. The cementing of the casing string then takes place in the same manner as described in the land drilling section of this manual. The only difference in the cementing operation using a mudline suspension system is that any excess cement in the annulus above the mudline casing hanger has to be washed out. If not, the running tool will get cemented in place making recovery of the running string at the end of the well rather more difficult. The removal of any excess cement is usually achieved by opening washout ports in the mudline hanger or the running tool by rotating the running string 6 turns to the right. The coarse right-hand release threads on the running tool cause the tool to back off from its running position to expose the washout ports. The excess cement is circulated out of the annulus by pumping water or drilling fluid down the running string and taking returns from the annulus. When all of the cement has been cleaned out, the washout ports are closed by rotating the running string 6 turns to the left so that the running tool re-seats in its running position and the ports are sealed off. It has become accepted practice to spot several barrels of cement retarder around the running tool prior to closing the ports. There are certain occasions when operational requirements mean that the cement slurry in the annulus (above the hanger) has to be washed out using small diameter tubing lowered down into the casing/conductor annulus. At this point, the cement head will be removed and the flow diverter etc. will be disconnected from the starting casing Figure 6.13. 20" Mudline Running head. The flow diverter assembly will be lifted up to expose Tool made up to the Shoulder Hanger and ready to run

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STARTING HEAD

20" CASING

30" CASING

Surface Wellhead after the 20" Casing has been Installed

20" Shoulder Hanger and Running Tool Landed Figure 6.14

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the running string of 20" casing. Then the 20" casing is cut at a specified distance above the top of the 30" conductor flange and a 20" socket weld casing hanger is welded to the 20" casing stub. Usually the socket weld casing head will sit directly on the 30" conductor and it will have short stabilizer ribs that centralize the casing head with respect to the 30" conductor. The 20" casing head will have two side outlets and an internal landing profile for the 13-3/8" surface casing hanger. The next step in drilling the well is to install a BOP stack on the 20" casing head. Some rigs will have two BOP stacks e.g. a 203/4" 2,000 psi BOP stack and a 13-5/8" 10,000 psi BOP stack. In this case, the 20-3/4" BOP stack would be installed on the 20" casing head, and the 13-5/8" BOP stack would be installed on the next (13-3/8)" casing spool. If the rig is equipped with a single BOP stack it will most likely be an 18-3/4" 10,000 psi (or 15,000 psi) BOP stack. Some vessels may have a 16-3/4" BOP stack but this size is not very common these days. For our theoretical well, the assumption is that a single 18-3/4" BOP stack is available and is therefore installed on the 20" casing head. The rig is then set up to drill a 17-1/2" hole for the 133/8" casing string. The next section of the 17-1/2" hole is then drilled to casing depth with the BOP stack in place. The drilling procedures used are the same as described in the land drilling chapter of this manual. There are various adaptations and alternative equipment selections that can change the basic procedures just described. Running and Cementing 13-3/8" Casing The 13-3/8" casing string will include a mudline hanger running tool (Figure 6.15) and a mudline suspension hanger (Figure 6.16). Care will be taken when spacing out the 13-3/ 8" casing string to ensure that no casing coupling interferes with the subsequent installation of the wrap-around hanger in the surface casing head.

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The 13-3/8" casing string is run into the hole and the landing ring on the mudline hanger seats on the internal landing shoulder of the 20" mudline hanger. The last joint of 13-3/8" casing will extend above the rotary table and a cementing head will be installed. Cementing of the 133/8" casing then takes place. If any cement slurry finishes up in the 20" x 13-3/8" annulus above the mudline hanger, it can washed out by rotating the running string 6 turns to the right to expose the washout ports in the running tool, and circulating out the excess cement. At this point, it is considered good practice to spot up to 10 barrels of cement retarder at the mudline hanger. The running string is then rotated 6 turns to the left to close the washout ports.

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CASING THREADS

METAL-TO-METAL SEAL

RESILIENT SEALS WASH PORTS RESILIENT SEALS

RUNNING THREADS

ONE WAY SEAL

Figure 6.15. 13-3/8" Running Tool

METAL-TO-METAL SEAL TIE-BACK THREAD RUNNING THREAD

LANDING RING FLOW-BY HOLES

RETAINER RING

After the cement has set, or the well is considered safe, the BOP stack is disconnected MULTIPLE LOAD SHOULDER from the casing spool and raised about 2 feet to expose the 13-3/8" casing. A wraparound casing hanger and seal assembly will be installed CASING THREADS Figure 6.17. 13-3/8" Running Tool around the casing and then made up to the 13-3/8" Shoulder sealed in to the prepared pro Figure 6.16. 13-3/8" Shoulder Hanger Hanger ready to run file in the casing spool. Usually this type of hanger will 72

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CASING SPOOL

13-3/8" CASING STARTING HEAD

20" CASING 30" CASING

Surface Wellhead after the 13-3/8" Casing has been Installed

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢

13-3/8" Shoulder Hanger and Running Tool Landed Figure 6.18

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CASING THREADS

METAL-TO-METAL SEAL RESILIENT SEALS WASH PORTS RESILIENT SEALS

RUNNING THREADS

ONE WAY SEAL

Figure 6.19. 9-5/8" Running Tool

METAL-TO-METAL SEAL

TIE-BACK THREAD RUNNING THREAD

FLOW-BY HOLES LOAD RING

SPLIT RING DETENT RING RETAINER RING MULTIPLE LOAD SHOULDER

CASING THREADS

Figure 6.20. 9-5/8" Shoulder Hanger

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have slips, but will also have a packoff seal that is mechani cally set by axial bolts made up from the top of the casing hanger. In some cases, there will be sufficient stretch in the 133/8" casing to weight- set the slips and packoff seal. The casing string is then cut carefully at a set distance above the casing hanger, according to the surface wellhead manufacturers advice. The cut off casing is then pulled up through the rotary table and laid down. The BOP stack is set aside and the casing stub is dressed to receive a secondary seal unit that slips over the casing stub and against the prepared internal seal surface of the next casing spool. The next step in drilling the well is to install the BOP stack on the casing spool and prepare to drill 12-1/4" hole for the 9-5/ 8" casing string. The hole is then drilled to casing depth, the cuttings are circulated out, the mud is conditioned, the hole is logged and the rig is set up to run the 9-5/8" casing string. Running and Cementing 9-5/8" 4-1/2" API IF Casing BOX The 9-5/8" casing string run will include a mudline suspension split ring hanger (Figure 6.19) SHEAR PINS and a running tool (Figure 6.20). TORQUE Instead of a landing ring seating PROFILE KEY SPLIT RING on a shoulder in the previous casing string, the next mudline casing hanger usually uses a split ring with a specific external profile that will expand and seat in WASH PORT the matching internal profile of the last mudline casing hanger. These profiles are designed so that the split ring cannot set prematurely in any other position 4-1/2 API IF PIN in the previous casing string. Prior to running mudline casing hangers, it is good practice to Figure 6.21. Profile Clean Out run a circulating tool that will Tool ®

WASH PORT


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CASING SPOOL OR TUBING HEAD

9-5/8" CASING CASING SPOOL

13-3/8" CASING STARTING HEAD

20" CASING 30" CASING

Surface Wellhead after the 9-5/8" Casing has been Installed

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@¢Q,À@ ÀÀ ,, QQ ¢¢ @@¢Q,À@ ÀÀ ,, QQ ¢¢ @@¢Q,À@ ÀÀ ,, QQ ¢¢ @@¢Q,À@ ÀÀ ,, QQ ¢¢

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢ @@ ÀÀ ,, QQ ¢¢

9-5/8" Shoulder Hanger and Running Tool Landed Figure 6.22

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wash, or clean, the internal seating profiles of the previous mudline hanger (Figure 6.21). This is particularly true where swelling shales have been encountered in the drilling of the hole as well as sticky lumps of clay that may have become trapped in the setting profiles. When a casing string is being run with a split ring type of landing ring it is good practice to lower the string slowly into its landing profile. This allows the natural spring force of the split ring to fully engage the ring in its matching profile.

The cementing procedures for this casing string follow the procedures previously outlined, and any excess cement in the annulus above the casing hanger is washed out by circulating through the opened washout ports in the mudline suspension system. (Six turns to the right to open, six turns to the left to close). The surface wellhead connections and installation of the wraparound casing hanger and seal assemblies follows similar steps for each casing string. 7" Mudline Casing String The next step in the drilling program may call for an 8-3/4" or 8-1/2" hole to be drilled to casing depth. This will most likely be the section of the hole that will penetrate any productive formation. The decision will be made at this time to either run a 7" casing liner that covers the open hole section and hangs from a liner hanger positioned inside the 9-5/8" casing or run a full 7" casing string that will extend all the way back to the surface wellhead. If a full 7" casing string is required, the 7" mudline suspension equipment will include a 7" split ring mudline hanger and a 7" mudline hanger running tool (Figure 6.23). Figure 6.23. 7" Shoulder Hanger and 7" Running Tool

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These pieces of equipment are used in the identical fashion as the 9-5/8" mudline suspension equipment described previ ®


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Temporary Abandonment Caps • All Temporary Abandonment Caps make up into the running tool threads while protecting the tie-back threads. • Temporary Abandonment Caps are available in vented style or with a back pressure valve. • A simple "J" tool runs and retrieves all Temporary Abandonment Caps. • Temporary Abandonment Caps are available in both the threaded style and stab-in.

Temporary Abandonment Cap Stack-Up Figure 6.24

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ously. A mudline hanger profile cleanout tool can also be used to clean the internal seating profiles of the 9-5/8" mudline hanger prior to running the 7" casing string. The cementing of the 7" casing, the washing out of excess cement in the annulus and installing of the surface casing hangers and seals all follow the same procedures outlined for the 9-5/8" casing string. Well Abandonment 4-1/2" API IF BOX

CENTRALIZER

RUNNING/ RETRIEVING JAY SLOTS BACK PRESSURE VALVE STINGER

TA CAP MAKE-UP THREADS

RESILIENT SEALS BACK PRESSURE VALVE

Figure 6.25. 7" TA Cap and 7" TA Cap Running Tool

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If the well is temporarily or permanently abandoned at the end of the well, it is common practice to set one or more cement bridges in the well to prevent any possible escape of well bore fluids. After the bridge plugs are installed, the surface wellhead equipment and BOP stack will be “nippled down” or dismantled for use on the next well. The individual running strings will be released from their respective mudline casing hangers with right-hand rotation, and recovered for re-use. In temporary abandonment, sealing corrosion caps are run and made up to the left-hand running threads in the mudline casing hangers. These corrosion caps protect the right-hand tie-back threads and sealing surfaces that will be used when the well is re-entered. Installing Temporary Abandonment Corrosion Caps One of the design features of a modern mudline suspension system includes stack-down mudline hangers. This means that the suspension point for each mudline hanger is below the previous mudline hanger, with enough distance to ensure that the running tool of the previous hanger is not overlapped by the next mudline hanger (Figure 6.4). This design feature also means that the installed TA cap of a particular mudline hanger is below the running tool/threads of the previous mudline hanger. As can be seen, each TA cap is covered by the next TA cap. When the well is temporarily abandoned, the 7" running string of casing will be released by rotating it 10 turns to the right.

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This will tfully disengage the mudline hanger running tool from the left-hand threads of the mudline casing hanger. The running string is then picked up and pulled out of the well. Prior to running the 7" TA cap, it is generally good practice to run a jetting tool to wash debris out of the 7" mudline hanger internal thread profiles. The TA cap running and retrieval tool is made up to a stand of drill pipe. The 7" TA cap can be a vented design (non-pressure sealing) or can be equipped with a back pressure valve (pressure sealing) (Figure 6.25). The vented cap does not require the stinger in the TA running tool and should be removed. The pressure sealing cap requires the stinger in the running tool in order to hold the back-pressure valve open so that there is no hydraulic lock formed when the TA cap is lowered into the 7" mudline hanger. A hydraulic lock will prevent the correct make-up of the TA cap to the mudline hanger.

4-1/2" API IF BOX

CENTRALIZER

With the 7" TA cap running tool made up to the 7" TA cap, the BACK PRESSURE VALVE STINGER assembly is lowered into the well on drill pipe. The last 5 to 10 feet before the 7" TA cap tags the top of the 7" mudline hanger RESILIENT SEALS is done very slowly to avoid thread damage to either piece of RUNNING/RETRIEVING JAY SLOTS equipment. The TA caps are self-aligning with the mudline Figure 6.26. Temporary Abandonhangers and the full weight of the drill pipe running string can ment Cap Running and Retrieving Tool be set down on the TA cap after the initial tag. The drill string for 9-5/8" TA Caps and larger is then picked up until only 5000 lbs of the hook load is acting downwards on the mudline hanger running threads. The drill string is then rotated to the left using rig tongs. After 3 turns, additional torque build-up should be noted. The torque should be increased to 500 ft-lb more than the initial rotation torque value. The 7" TA cap is now installed and the TA cap running tool can be retrieved with a straight upward pull. If the TA cap was a pressure sealing cap the stinger in the running tool would be pulled out at the same time and the back pressure valve would seat in its sealing position providing a containing seal against any subsequent well pressure that might occur. The resilient seal seals on the outside of the 7" TA cap protecting the tie-back threads and seal surfaces of the 7" mudline hanger.

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RUNNING/ RETRIEVING MANDREL

RUNNING/RETRIEVING JAY LUGS TA CAP MAKE-UP THREADS RESILIENT SEALS

Figure 6.27. Illustration of a "vented" Temporary Abandonment Cap

RUNNING/RETRIEVING MANDREL

RUNNING/RETRIEVING JAY LUGS TA CAP MAKE-UP THREADS

RESILIENT SEALS

Figure 6.28. 20" Stab-in "vented" TA Cap

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With the 7" TA Cap installed, the 9-5/8" running string of casing and 9-5/8" mudline running tool can be released from the 9-5/8" mudline hanger running threads. As with the 7" running string, 10 turns to the right disengages the running tool from the mudline hanger and the 9-5/8" casing can be pulled out of the well. The TA Cap Running Tool, which runs the 9-5/8" and larger sized TA Caps, is configured with an overshot type connection between the tool and the TA Cap. This is different then the 7" TA Cap Running Tool (Figure 6.26). The procedures for running the 9-5/8" TA Cap are identical to the procedures used to run the 7" TA Cap. It is unlikely that a pressure containing 9-5/8" TA Cap would be used if the 7" TA Cap was equipped with a back pressure valve. A TA Cap without a back pressure valve is called a vented TA Cap. The 13-3/8" (Figure 6.27) and 20" TA Caps (Figure 6.28) can be run as required after their respective running strings have been retrieved. As previously mentioned, the same TA Cap Running Tool is used for all TA caps 9-5/8" and larger with the only difference being the centralizing stabilizer that is used above the tool to provide good alignment as the TA Cap enters its respective mudline hanger.

Alternative Stab-in TA Caps Another design of TA Caps available include a split threaded lock ring that engages the mudline hanger running threads (Figure 6.28). This TA Cap style is run using the TA Cap Running Tool on drill pipe, and the applied weight of the RUNNING/RETRIEVING MANDREL running string causes the split ring to collapse inward as the BACK PRESSURE VALVE STINGER TA Cap moves the last 2 inches to its seated position in the RUNNING/RETRIEVING mudline hanger. Again, the running string is turned to the left JAY LUGS using rig tongs until the torque builds up to 500 ft-lb over the TA CAP MAKE-UP THREADS initial rotational torque value. The threads on the split lock RESILIENT SEALS ring will engage the left hand threads of the mudline hanger, which should take no more the 1/2 to 2 turns. A pick up test Figure 6.29. Illustration of a Temporary Abandonment Cap with Back Pres- of 5,000 to 10,000 pounds can be performed to verify that the stab-in TA Cap is latched in. sure Valve

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The stab-in TA Caps are provided in the vented style or with the back pressure valve features. This type of stab-in cap is used when any thread damage on the mudline hanger is suspected in preventing a full thread TA Cap from being installed. After all the TA Caps are in place, the 30" conductor will be disconnected at or above the mudline and recovered. The disconnection may involve the use of divers to run in releasing bolts if a specialty connector has been used. The jack-up drilling vessel will be jacked down to sea-level and the supporting legs will be raised from the sea-bed. Sometimes the feet of the legs become embedded in re-consolidated sand and mud. Sea water jets built into the feet are used to break up the compacted sediments and free the legs. The jack-up will then be towed to another location. The well may be left with a marker buoy or a subsea transponder or beeper working off a long life battery pack. If these markers fail, the coordinates of longitude and latitude would serve to re-locate the well and, in these days of inertial navigation, the well can be pin-pointed within 10 square meters.

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Jacket and Platform Drilling and Production Equipment Platform Drilling and Production ........................................... 83 Jack-ups Used for Jacket Drilling ........................................... 84 Re-entering a Well Drilled with Mudline Suspension Equipment............................................................................................ 85 Retrieving Temporary Abandonment Caps ........................... 85 Installing the 20" Tie-Back Casing String ............................. 87 Alternative Stab-in Tie-Back Tools......................................... 87 Completing the Well ................................................................. 88 Jack-ups Used for Subsea Template Drilling ......................... 90 Platform Drilling and Production ........................................... 91 Drilling a Well From a Jack-up or Platform Using Mudline Suspension Equipment and a Unitized Surface Wellhead System ......................................................... 99 Running the 20" Casing ......................................................... 101 Installing the 18-3/4" Unitized Wellhead on 20" Casing ............................................................................... 101 Cementing the 20" Casing ..................................................... 102 Installing the 18-3/4" BOP Stack with Quik-Clamp Connector ................................................................................ 103 Testing the 18-3/4" BOP Stack and 18-3/4" Unitized Wellhead Without Casing Hangers Installed ....................... 104 Running the 13-3/8" Casing with 13-3/8" Mudline Shoulder Hanger and 13-3/8" Surface Mandrel Casing Hanger ......................................................................... 105 Adjustment Sub ...................................................................... 106 Setting of the Adjustment Sub ............................................... 106 Running 13-3/8" Casing ......................................................... 107 Installing 18-3/4" Seal Assembly on 18-3/4" x 13-3/8" Mandrel Casing Hanger ......................................................... 110 Installing the 18-3/4" x 13-3/8" Wear Bushing .................... 111 Run 9-5/8" Casing String with 9-5/8" Split Ring Mudline Hanger and 9-5/8" Surface Mandrel Hanger ....... 112 Installing 18-3/4" Seal Assembly on 18-3/4" x 9-5/8" Mandrel Casing Hanger ............................ 113 Installing the 18-3/4" x 9-5/8" Wear Bushing ...................... 113 Abandonment .......................................................................... 113

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Jacket and Platform Drilling and Production Equipment

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Platform Drilling and Production Once the mudline suspended well has been drilled and temporarily abandoned, the well data is analyzed. When exploration wells drilled by a Jack-up drilling vessel are determined to be viably produceable, they are tied back to a fixed platform for surface completion. This process involves reconnecting casing to the well by way of mudline suspension tie-back tools. During the tie back process, typically a conventional surface wellhead system is incorporated and the well is completed in the same way a land well is completed. The platform generally consists of two major parts. These parts are the jacket section constructed from large steel tubular members and the top-side section, or sections, that will include the drilling rig and its support equipment, production and processing equipment and accommodations for the operating personnel. In the case where a large field is to be drilled and developed, the jacket and platform can become large structures that require considerable engineering and planning. Additional information on large multiple well platforms will be discussed later in this chapter. In the case of individual wells that are to be completed, only the jacket structure is installed over the mudline system with the intent of establishing a flow connection to a platform with the needed process equipment close by. ®

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Jack-ups Used for Jacket Drilling Many jack-up drilling rigs are designed with the capability of drilling wells with the drilling mast or derrick in a cantilever, or over-the-side, drilling mode. This capability is used when drilling development wells through small jackets, or tieing wells, previously drilled back to the jacket for surface completion. Jackets are usually constructed from large diameter steel tubular members and are installed by barges and pinned to the sea floor with piles driven through each leg of the jacket. The top side of the jacket will be exposed above the water line by 20 ft. or more, depending on the sea states expected at the location. The jacket will have well conductor guides for one or more wells built into the open framework structure of the jacket. If more than one well is planned, the center lines of the proposal wells will be spaced to accommodate any surface completion wellheads and production trees. After the jacket is installed, the jack-up drilling rig is moved in next to the jacket, and the drilling mast and rotary drilling equipment are moved out in a cantilever mode over the jacket drilling slots. If the jacket has been designed to support all casing loads from the surface wellhead, the jack-up can proceed with drilling the well as previously described without the use of a mudline suspension system. In some cases, the well may have already been drilled. One of the advantages of the mudline suspension system is the ability to disconnect the riser casing string for jacket installation. In Figure 7.1. Illustration of cantilever this event, the casing loads will be supported by the suspenJack-up drilling vessel positioned over a sion system at the mudline which will allow a cheaper and jacket more economical jacket design. Tieing what was once an exploratory well drilled with a mudline suspension system back to a jacket for surface completion is a widely used technique for drilling and completing wells in Jack-up drilling depths.

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Re-entering a Well Drilled with Mudline Suspension Equipment If a single well is being re-entered, it isgenerally being done to complete the well as a producer of oil or gas. This means that the well will be completed with either a steel jacket to support a mudline tie-back system (Figure 7.1), surface wellhead equipment and production tree, or it will be completed as a subsea producer with subsea wellhead adapters and subsea production tree. The following text will deal with the tie-back of the mudline hangers and surface completion using a steel jacket. The subsea completion of a mudline well will be covered in subsequent chapters reviewing subsea completions. For this section, we are assuming that a steel jacket with piled foundations of gas has been correctly positioned over the temporarily abandoned mudline suspension well (Figure 7.1). The next step is to move a jack-up drilling vessel, with a cantilever drilling capability, in next to the steel jacket. The drill floor and rig will be centered over the temporarily abandoned well. The first operation will be to re-connect the 30" primary conductor riser to the 30" conductor at the mudline. If the well was left in good order at abandonment, the reconnection will be achieved by stabbing one half of a specialty connector over, or into, the mating half left on the seafloor conductor. This is a difficult operation, particularly if strong Figure 7.2. Illustration of a mudline tidal currents are present. Underwater television, diver assis- suspended well temporarily abandoned tant, guidance systems and foul language etc. may all be used to re-establish the primary conductor. Retrieving Temporary Abandonment Caps Once the primary conductor is in place, a surface starting head will be installed on the conductor at the cellar deck level of the steel jacket. The 30" conductor will form the main structural element in support of the surface wellhead equipment and the surface production tree as well as the primary conduit for the 20" Temporary Abandonment (TA) cap retrieving tool.

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Prior to running the TA Cap Running/Retrieving Tool, it may be advisable to run a TA Cap Clean Out Tool to wash any debris away from the TA cap mandrel (Figure 7.3). The retrieving tool is run on drill pipe with a centralizer above the tool, to centralize it in the 30" conductor.

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4-1/2" API IF

Wash Fluid

PORTS

Figure 7.4. 20" Stab-in "vented" TA Cap

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The TA Cap Running/Retrieving Tool (Figure 7.5) is run on drill Figure 7.3. Temporary Abanpipe with a centralizer above the donment Cap Clean Out Tool tool to centralize it in the 30" conductor. When the retrieving tool has tagged the retrieving mandrel of the TA Cap, it can be slowly be rotated to the right or left and lowered until the jay slots on the retrieving tool drop over the lugs on the TA cap mandrel. The retrieving string is then rotated slowly to the right and the number of turns should be carefully noted. The rotational torque should drop as the TA Cap releases from the running threads in the 20" mudline hanger. Vented TA Caps (Figure 7.4) require 3 to 4 turns of 4-1/2" API IF BOX right- hand rotation while the pressure containing caps need 6 to 7 turns of right-hand rotation. The TA Cap should be totally CENTRALIZER disengaged from the mudline hanger threads. This can be veriBACK PRESSURE fied with a pick up test. Once VALVE STINGER free, the assembly can be pulled RUNNING/RETRIEVING JAY SLOTS from the well taking care not to rotate the drill pipe on the way Figure 7.5. Temporary Abanout. This is a precaution against donment Cap Running and Rethe TA Cap becoming un-jayed trieving Tool for 9-5/8" TA Caps from the retrieving tool and drop- and larger ping back down the well.

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Installing the 20" Tie-Back Casing String After the TA Cap has been recovered, it is considered good practice to run a washout tool designed to clean the right hand tie-back threads in the mudline casing hanger. Sea water is used for this operation as the tool is rotated slowly to the right. Pressures up to 1000 psi are used and the flushing action should be done for 10-20 minutes, before pulling out.

CASING THREADS

RESILIENT SEALS

RIGHT-HAND The 20" Tie-Back Tool (Figure 7.6) is then run with a centralizer TIE-BACK THREADS on the 20" tie-back casing. The tie-back should be lowered RESILIENT slowly into the mudline hanger body. The weight acting on SEALS the threads should be kept at a minimum as the tie-back string is rotated 4-5 turns to the right. This makes up the tie-back tool Figure 7.6. 20" Threaded Tie-Back to the mudline casing hanger. A minimum of 5000 ft-lb of Tool (centralizer not installed) torque is required to energize the metal-to-metal seal on the nose of the tie-back tool. The maximum amount of torque should not exceed 15,000 ft-lb above the initial rotational torque to engage the threads.

At this point, a pressure test can be conducted to verify the sealing integrity of the tie-back connection. The amount of pressure applied will be limited by the pressure ratings of the various system components. The 20" casing is cut off and a 20" slip-on weld casing head will be welded to the 20" casing. Alternatively, an 18-3/5" unitized wellhead could be connected to the 20" casing (a procedure described in the next section of this manual). The 20" casing head, or the 18-3/4" unitized wellhead will provide the landing and sealing profile for the 13-3/8" casing hanger.

CASING THREADS

RESILIENT SEALS RIGHT-HAND TIE-BACK THREADS

The recovery of the 13-3/8", 9-5/8" and 7" TA caps proceed sequentially in the same fashion just described after each outer tie-back casing string has been installed.

RESILIENT SEALS

Figure 7.7. 20" Stab-In Tie-Back Tool (centralizer not installed)

Alternative Stab-in Tie-Back Tools As with the TA Caps, an alternative stab-in as opposed to the full thread form tie-back tools is available (Figure 7.7). All of the precautionary cleaning out procedures are used with this style of tie-back tool and is run in identical fashion to the ®

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threaded tie-back tool except that weight will be used to push the split threaded lock ring into the tie-back threads. The downward travel to reach this position is 2 inches after the stab-in tie-back tool has landed inside the body of the mudline casing hanger. The casing string is then rotated 1/2 to 2 turns to the right. A minimum of 5,000 ft-lb up to maximum of 15,000 ft-lb over the initial rotational torque is required to energize the metal-to-metal seal. If it is necessary to apply torque in excess of that achieved with the casing, a torque tool can be run (Figure 7.9). This torque tool engages the torque slots found in the ID of the Stab-In Tieback Tool. This tool assists in assuring that the Stab-In Tieback Tool is tight and can achieve the metal-to-metal seal. This seal can be pressure tested and the tie-back casing is then landed and sealed off in the surface wellhead as previ4-1/2" API IF BOX ously indicated with the standard tie-back system. This type of stab-in tie-back tool is only used when thread damage is suspected in the mudline suspension hanger.

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢

Completing the Well SPRING LOADED The surface wellhead equip- TORQUE KEYS Figure 7.8. 13-3/8" Stab-In Tie-Back ment is built up after each tieTool being torqued with the Stab-In Ti- back string until the tubing Back Torque Tool spool is installed. The BOP stack will then be installed on the tubing spool and the op- Figure 7.9. Tie-Back Torque Tool eration of drilling out bridge plugs, cement bridges and perforating the production zone, or zones, will take place.

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5000 10000

COMPLETION TREE

TUBING BONNET

TUBING SPOOL

INTERMEDIATE SPOOL

STARTING HEAD

Typical Conventional Wellhead System with completion tree after the well has been tied back

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢

¢¢ @@ ÀÀ ,, QQ @@ ÀÀ ,, QQ ¢¢

Mudline Tie-Back System Stack-Up

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Figure 7.10

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The well will be completed with a downhole tubing assembly and the tubing landed and sealed off in the tubing spool. These procedures are fully described in earlier chapters that describe the completion of a land based well, including the installation of the production tree. The flowlines from the well will then be connected to any processing equipment on the jacket before the oil and gas production goes into a subsea flowline that goes to another production platform or onshore gathering station. Jack-ups Used for Subsea Template Drilling The use of subsea drilling templates has increased in recent years driven, in part, by the need to achieve early production from an offshore discovery. The wells are drilled while the jacket and platform facilities are built. Early production means early cash flow from a field development, which is extremely important because of current high development costs and lower crude oil prices.

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The type of subsea template used in conjunction with a jack-up drilling rig is usually a lightweight 2 to 8 well spacer template, constructed of steel tubular or I-beam members (Figure 7.11). The individual well slots normally have shallow funnel guides on top and the spacer template may only be 10' to 15' high, depending on the bottom conditions anticipated. In areas where soft bottom conditions are expected, the bottom of the spacer template will be filled in with steel plate to create a “mud mat” with better bearing capacity.

1

1

1

Figure 7.11. Typical bottom supported Template used in mudline suspension completion work

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These spacer templates are usually small enough and light enough to be lowered into position on the sea floor, from the jack-up drilling rig

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once it is established on loca tion. The drilling of the deviated wells is done using mudline suspension equipment so that the tie-back feature with metal-to-metal sealing capabilities can be used when the jacket and platform facilities are moved in over the temporarily abandoned wells. When the tie-back casing strings have been re-connected to the subsea mudline suspension equipment, the platform- based drilling or work-over rig, will complete the wells with surface wellhead equipment. The cement bridges or bridge plugs left in the production casing string will then be drilled out, the selected producFigure 7.13. Side view of a conductor supported tion zones will Template System. Note the location of the gripper dog segments be perforated, the downhole completion assembly will be run, the tubing landed in the surface tubing hanger spool, and the production tree will be installed. Platform Drilling and Production Fixed drilling and production platforms are used to develop discovered oil and gas fields in offshore and major inland lake locations. The extent of the discovery will have been determined from exploration wells drilled by bottom-supported, or floating drilling vessels, and by interpretation of seismic and geological information. Other important factors when estimating the size of the discovered reserves involve careful analysis of the production tests on the discovery of wells, including the very important bottom-hole pressure recordings before, during and after each of the production tests. Figure 7.12. Top view of a conductor From this information, the size of the platform, number of supported Template System

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wells required and the best location for the platform will be decided. The use of deviated wells to reach and drain the reservoir from its boundaries is a planned feature of every multiple-well platform. Sometimes the lateral extent of the discovered field is too great for the wells from one platform to effectively drain the producing formations. In giant offshore fields, two, three or four major platforms with multiple wells may be required to effectively produce the field. The conventional platforms generally consist of two major parts, the jacket section constructed from large steel tubular members, and the top-side section or sections that will include the drilling rig and its support equipment, production and processing equipment, and accommodations for operating personnel. Using state-of-the-art technology, these steel-jacketed platforms were designed for use in all ranges of water depths. The vast majority of offshore platforms are installed in water depths less than 500 ft. deep, but there are an increasing number that are used in water depths over 800 ft. with the current water depth record being +1100 ft. The steel jacketed section of the platform is the first part of the platform required and usually constructed at a shore side facility in the horizontal position. The major tubular legs of the jacket will be equipped with guides for subsequent piles to be driven through each of the legs into the sea-floor to anchor the jacket section securely in place. The size of the platform and/ or the bottom conditions may also dictate if additional piling is required to secure the platform. In this case, the additional piles are driven through external pile guides on the legs of the steel jacket. These piles are called “skirt” piles. The steel jacket will almost certainly include in its construction the guides for the primary drilling conductors for each well. When the jacket is complete, it is usually loaded onto a large flat-topped barge and towed out to location. The steel jacket

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is then slid off the barge into the water and supported by the buoyancy of sealed tubular members and usually additional attached buoyancy modules. By controlled flooding and positioning tethers attached to the tubs, the jacket is lowered slowly to the sea bed. Once in place, the task of pinning it to the sea bed with the previously mentioned piles and/or skirt piles takes place.

MIGHTY SERVANT 2

MIGHTY SERVANT 2

MIGHTY SERVANT 2

Figure 7.14. Sequence illustrating the off-loading and positioning of the jacket over the template system

This piling operation will be done by a specialist contractor with a large floating vessel with a crane and pile hammer installed. The long sections of tubular piles are usually welded together or they are connected with specialty connectors that fit together very quickly. These specialty connectors have to be strong enough to withstand high bending loads, particularly if the piles are being battered into position at an angle. These connectors have to also be releaseable, especially if they are used in the recoverable pile follower sections. Pile connectors have been used in all sizes of from 20" OD to 84" OD. ®

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After the piles to secure the jacket have been driven into place, it is generally the practice to drive the primary well conductors into place. Again, the use of specialty connectors has become a common alternative to welding the conductor sections together. Depending on the bottom conditions, the primary conductors will penetrate the sea bed in excess of 100 ft. before the point of refusal is reached. The point of refusal will be stated as a number of blows-per-foot for a two or three foot interval. The size and energy output of the diesel or steam-hammer will be used to determine the required blows-per-foot at refusal. Sometimes, the local regulatory bodies require a minimum penetration to be reached. If the minimum penetration depth has not been reached when the point of refusal is reached, then it is quite common for a Figure 7.15. Photo of a pile driving small drilling unit to be used operation to drill out the center of the conductor pile and make additional hole below the pile shoe. The pile hammer is then re-installed and the conductor pile is again battered into place. After all of the primary conductors are driven into place, the drilling modules of the platform top-side sections will be installed so that the drilling program can be started. On smaller jackets, a bottom supported drilling rig will be moved in adjacent to the steel jacket. A cantilevered drilling rig will then commence to drill the wells in each well slot on the jacket.

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Figure 7.16. Illustration of the conductors installed in the template system

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The wells will be drilled using the conventional drilling equipment and systems used in land drilling. However, there are some areas where the drilling equipment used may differ from the conventional land-based systems. One requirement for modified equipment may be to move the suspension point for the suspended casing strings, used in the drilling of the well, from the jacket structure to the sea floor. This requirement would be obvious from the outset when the jacket structure is designed, built and the strength of the structure decided. The drilling system required to provide the sea bed support is generally referred to as a casing support system (Figure 7.17). The casing support system depicted in the illustration will be used in conjunction with a typical surface wellhead or unitized wellhead system. Another area where the offshore drilling equipment may differ is the use of a flowdiverter system, which is installed on top of the primary conductor while the hole is drilled for the surface casing string. The flow diverter system may consist of a large annular preventer or a customized flow diverter. The purpose of the flow diverter system is to provide a means of closing the annular space between the drill pipe and the primary conductor above the large bore side outlets. In the event of drilling into an unexpected pocket of shallow formation gas Figure 7.17. Illustration of the casing support system used at a pressure which overcomes the hydro- in a jacket and platform completion operation static head of the drilling fluid and thus precipitates a potential blowout condition, the flow diverter system is put into operation. The fluid and gas coming out of the well is directed through large bore flare lines which terminate outboard of the drilling operational area. This means that potentially hazardous gas is not blowing in an unrestricted fashion through the rotary table into the rig floor ®

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DIVERTER ASSEMBLY

DIVERTER HOUSING AND FLOWLINE OUTLETS

OVERSHOT SPOOL

OVERSHOT RISER AND PACKER

CONDUCTOR PIPE STARTING HEAD

Conductor Set

Figure 7.18

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Surface Casing Set ®

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area where it could possibly ignite causing major damage. Once the blow of gas from the shallow pocket is exhausted, the drilling fluid column will be re-established and the drilling operations can proceed again. Because of the dangerous conditions that can exist during this operation, all of the functions of the flow diverter system are equipped with alternative and remotely operated controls. One question commonly asked is, “Why isn’t the annular preventer or flow diverter used to shut in the gas blow and set about controlling the well through a choke and kill manifold?” The answer to this is that closing in a shallow pocket of gas will cause the build up of pressure in the wellbore which may break down the formation at the shoe of the primary conductor. If this occurs, the gas then starts to find its way to the sea bed through multiple cracks or fissures in relatively unconsolidated sediments. Now the gas is spread over a large area as it comes bubbling up through the water around the drilling platform, and the dangers of ignition are increased as well as the possible formation of craters in the sea bed that could undermine the whole drilling structure.

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DIVERTER ASSEMBLY

DIVERTER HOUSING AND FLOWLINE OUTLETS

OVERSHOT RISER AND PACKER

BLOW OUT PREVENTER

BOP Installed Figure 7.19

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Drilling a Well From a Jack-up or Platform Using Mudline Suspension Equipment and a Unitized Surface Wellhead System The previous section of this chapter described mudline suspension equipment used in conjunction with a conventional surface wellhead system assembled from casing spools stacked up from the initial casing head. A unitized wellhead is simply one piece of equipment that replaces the 2 or 3 casing spools used to build a conventional wellhead system. A unitized surface wellhead (Figure 7.20) is generally manufactured from a single high grade steel forging, and can have internal from a single high grade steel forging and can have internal landing seats or profiles for 2 or 3 casing hangers. The advantages of a unitized wellhead over a conventional wellhead are summarized below. • Minimizes the number of connections and re-connections of the BOP stack equipment, flanges, clamps etc. as the well is drilled. The BOP stack can remain connected to the top of the unitized wellhead as the well is drilled and each casing string is landed. • The number of potential leak paths is reduced with the elimination of connections and accompanying steel ring gaskets or seal rings. • More compact, as the stacked height of casing hangers inside the unitized wellhead results in an overall reduction in height. This height reduction is particularly advantageous where headroom beneath drilling substructures or drilling vessel rotary floors is restricted. • Saves rig time by reducing the number of connections and re-connections of BOP stack equipment etc. The unitized wellhead is primarily used in the drilling of development wells, but the daily costs of offshore operations have caused a number of operators to review time saving ®

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Exploratory Unitized Wellhead System Feature • Simple reliable and trouble free operation • Available for most casing programs, Standard or H2S Service • Compact space savings design • Fewer Flanges Reduce possible leak paths • Mandrel Type Casing Hangers run through the BOP Stack eliminating nipple up/nipple down time • Large passages for flow-by and cement returns • True Metal-to-Metal Seals on Seal Assembly • Seal Assembly can be tested without installing the BOP Stack • All casing Hangers use the same Seal Assembly within a particular wellhead size • BOP Stack can be tested without pulling the Wear Bushing

Unitized Wellhead System Figure 7.20

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equipment as unitized wellheads are being used more often in exploratory drilling. The following text assumes that the drilling of the well from the jack-up has reached the point where the 30" primary conductor is installed and the 26" hole has been drilled for the 20" casing. Running the 20" Casing The 20" casing string will include the 20" mudline shoulder hanger, 20" mudline running tool and the 18-3/4" wellhead that are all run on the full bore wellhead running tool (Figure 7.21). The 20" casing shoe is the first joint run. Intermediate casing joints are made up and run until the casing that will be below the mudline is run. The pre-assembled joint including the 20" mudline hanger and the 20" mudline hanger running tool is then made up to the 20" casing. After the pre-assembled mudline hanger joint passes through the rotary table, the casing string must not be rotated as the 20" casing is lowered into the hole. This is to prevent the possibility of the mudline running tool from backing off and releasing from the mudline hanger as the casing is being lowered into the hole. All of the 20" casing connections above the running tool should be made up to manufacturers maximum allowable torque. If the connections are equipped with anti-rotation keys, these should also be installed. These precautions are necessary as the running string will subsequently be rotated to the right to open the mudline washports and then back to the left to close the washports. Aaccurate spacing of the 20" running string is also required to be able to place the top of the modified square thread (located on the outside of the 18-3/4" unitized wellhead) to within six inches of the top of the 30" conductor.

18-3/4" CLUTCH-TYPE RUNNING TOOL

18-3/4" UNITIZED WELLHEAD

20" RISER CASING

20" MUDLINE HANGER RUNNING TOOL

20" MUDLINE SHOULDER HANGER

20" CASING

Installing the 18-3/4" Unitized Wellhead on 20" Casing The 18-3/4" wellhead running tool (Figure 7.22) is a full bore 7.21. Unitized Wellhead, 20" threaded running tool which is made up to the wellhead with Figure casing, and mudline hanger running left hand rotation at the surface. This full bore feature allows tool and hanger the operator to launch cement wiper plugs from the surface.

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CASING THREADS

RIGHT-HAND RUNNING THREADS RESILIENT SEALS

Figure 7.22. Unitized wellhead running tool

QUIK-CLAMP CONNECTOR PROFILE 9-5/8" CASING HANGER POSITION

SIDE OUTLETS 13-3/8" CASING HANGER POSITION LANDING RING 20" CASING THREADS

Figure 7.23. 18-3/4" Unitized Wellhead

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The unitized wellhead (Figure 7.23) has two casing hanger positions to set 13-3/8" and 9-5/8" inside the wellhead. The internal surface will have metal-to-metal seal preparations for the casing hanger seal assemblies when they are run. The wellhead has a Quik-Clamp connector profile, but flanged or clamp hub connections can also be used. A landing ring is located on the outside so that the wellhead will rest on the 30" conductor stub. This landing ring can either be fixed or threaded to allow for adjustment. The wellhead has a threaded bottom to accept a 20" casing pup joint. The wellhead running tool and unitized wellhead is picked up as a complete assembly and the 20" casing connector at the bottom of the housing pup joint is made up to the last joint of 20" casing. The 20" casing landing joint made up to the running tool is then used to lower the entire 20" casing string slowly down until the 20" mudline shoulder hanger lands on the 30" mudline landing ring. The entire casing string is weight-set down. Cementing the 20" Casing The 20" cement head is installed on the 20" landing joint and the cementing of the 20" casing proceeds exactly as outlined in previous text. The inclusion of the 18-3/4" unitized wellhead and running tool in the 20" casing string have no affect on the cementing operation as they have full bore openings. The only operational requirement is to pick up the weight of the casing string above the mudline hanger so that the upper spline mechanism of the 18-3/4" wellhead running tool is fully engaged. After the cement has been displaced, the washports on the mudline running tool are opened with six turns of righthand rotation so that the excess cement in the annulus can be washed out. After the cement job is completed, the washports have been reclosed and seals have been successfully pressure tested, the 20" landing string is tensioned to the desired amount. The two halves of the threaded split support ring are then fitted onto the modified square thread on the outside of the 18-3/4" ®

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unitized wellhead. The cap screws in each end of the split support ring are then made up so that the ring acts as one piece. This ring is then rotated down the threads until it sits firmly on top of the 30" conductor pipe or flange. The upward pull on the running string is then completely slacked off. This allows the stem of the housing running tool to disengage from the upper splines and engage in the lower splines of the running tool. The 18-3/4" unitized wellhead running tool is then turned approximately six turns to the left which releases it from the internal housing running threads and it can then be retrieved and laid down. Installing the 18-3/4" BOP Stack with Quik-Clamp Connector Another time-saving piece of equipment that is also gaining acceptance is a rapid make-up connector at the bottom of the surface BOP stack. This connector makes up quickly to an external profile on the unitized wellhead or last casing spool and avoids the time consuming operation of making up flanges or clamps (Figure 7.23). The Quik-Clamp connector at the bottom of the 18-3/4" BOP stack is unlocked from the BOP test stump. The two halves of the Quik-Clamp connector will separate when the BOP stack is picked up off of the test stump. The metal DX seal ring can now be removed. The seal areas in each half of the connector should be carefully cleaned and lightly oiled. A new DX seal ring should be placed carefully into the bottom half of the connector.

CLAMP HUB TOP

RING GASKET

REACTION RING LOCKING RING CAM RING WELLHEAD

Figure 7.24. Quik-Clamp Connector and BOP Adapter

The 18-3/4" BOP stack with the Quik-Clamp connector in the released position is now lowered on to the 18-3/4" unitized wellhead and seated with the entire weight of the BOP stack. The Quik-Clamp connector is now locked to the outside profile of the wellhead housing by making up the eight cap screws (according to the instructions in the service manual). ®

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The final torque value on each cap screw should be 2700 ft-lb. The BOP stack installation is then completed and the BOP stack and Quik-Clamp connector can be tested. Testing the 18-3/4" BOP Stack and 18-3/4" Unitized Wellhead Without Casing Hangers Installed The BOP stack and wellhead pressure test is conducted using the multi-purpose Combination Tool (Figure 7.25). Prior to any pressure tests, the Combination Tool is configured to retrieve the Nominal Bore Protector and lowered down through the BOP stack on drill pipe until it lands on the 18-3/ 4" bore protector installed in the wellhead housing. The Combination Tool is then rotated to the left no more than a quarter turn. This allows the lugs on the tool to drop into the jay-slots. An additional 1/8 of a turn to the left moves the lugs to the retrieving position in the jay-slots. A straight upward pull retrieves the Combination Tool and bore protector. The Combination Tool is then reconfigured as a test tool and is run on drill pipe to land on the internal load shoulder of the 18-3/ 4" unitized wellhead. The resilient seal on the Combination Tool seals on the reduced bore just below the load shoulder. 4-1/2" API IF BOX

The BOP stack can then be tested to 5000 psi by applying hydrostatic pressure below a pipe ram closed on the drill pipe running string. This pressure test will also test the DX seal of the Quik-Clamp connector. After all pressure tests have been successfully concluded, the pipe ram is opened and the Combination Tool is retrieved with straight upward pull. If the wellhead housing and 104

RUNNING AND RETRIEVING JAY-LUGS (REMOVED) RESILIENT TEST SEAL (INSTALLED)

4-1/2" API IF PIN

Figure 7.25. Combination Tool configured to test the BOP stack

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BOP stack are rated above 5000 psi, it is advisable to use a heavy-walled drill pipe of high grade steel so that the drill pipe does not collapse at higher pressures.

4-1/2" API IF BOX

RUNNING AND RETRIEVING JAY-LUGS

TEST SEAL The Combination Tool is used RESILIENT (REMOVED) to run the 18-3/4" Nominal Bore Protector (Figure 7.27) back into the wellhead. Release of the tool from the bore protector is performed by turning the Combination Tool 4-1/2" API IF PIN 1/8 of a turn to the right and Figure 7.26. Combination Tool picking straight up.

configured to run the nominal bore protector and wear bushings

The 17-1/2" hole for the 13-3/ 8" casing is then drilled. The hole will then be conditioned, and the rig is set up to run the 13-3/8" casing string. Before running the casing, the 18-3/4" Nominal Bore Protector will be removed from the wellhead housing using the Combination Tool run on drill pipe. Running the 13-3/8" Casing with 13-3/8" Mudline Shoulder Hanger and 13-3/8" Surface Mandrel Casing Hanger Historically it has been difficult to realize the benefits of a unitized wellhead system and mandrel-type hangers when mudline suspension is used in the well. The inheritant JAY-SLOT difficulty is spacing out the casing string to land the RESILIENT SEALS mudline hanger at the sea bed and the mandrel-type hanger at the surface simultaneously. Recently, the introduction of an oilfield casing tool, by DRIL- Figure 7.27. Nominal Bore Protector ®

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CASING THREADS

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QUIP, has provided the means to overcome the problems of space-out and tensioning requirements. The casing Adjustment Sub is a unique casing tool that facilitates adjustment of the casing string between two fixed points. The function of this tool is described in the following paragraphs and it will be incorporated in the 13-3/8" and 9-5/8" casing strings.

INNER BODY

RETAINER NUT SEAL ASSEMBLY

OUTER BODY

ADJUSTMENT SLEEVE

OVERPULL SLOT CASING THREADS

Figure 7.28 Adjustment Sub

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Adjustment Sub The Adjustment Sub is a full bore tool that is included in casing strings, generally just below the mandrel-type casing hangers used in surface and subsea wellhead systems (Figure 7.28). It is, as the name implies, a tool which provides up to 18" of vertical adjustment to accommodate any space out discrepancy in casing strings, and also enables the operator to apply full tension to the casing below the casing hanger. The Adjustment Sub can be used with surface mandrel-type casing hangers in conjunction with mudline suspension equipment where the requirement for casing space out and tension are also very desirable. Setting of the Adjustment Sub With the casing run and the mandrel hanger within 18" inches of its correct landing seat, the mandrel casing hanger running tool is released and retrieved. The Adjustment Sub Setting Tool is run on drill pipe and spaced out so that the kelly can be used in the rotary table to transmit torque to the running string. The Setting Tool is lowered 5 feet below the bottom of the Adjustment Sub. Approximately 1000 psi is then applied to the setting tool through drill pipe. This pressure forces a set of pistons against the inside of the load ring which pushes it out against the inside of the casing. With the pressure maintained, the Setting Tool is pulled slowly up until the load ring snaps into the matching profile on the Adjustment Sub (Figure 7.29). An increase in load will be noted and this should be

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increased and then maintained at 10,000 lbs overpull. The internal pressure can now be removed. The casing string can be tensioned to the desired amount. With the 10,000 lbs overpull still applied to the setting tool, the drill pipe is rotated to the right using the kelly. The center sleeve of the Adjustment Sub will begin to rotate and as it does the mandrel casing hanger will begin to move down. The center sleeve of the Adjustment Sub has a compound thread and with three rotations, moves the casing hanger down 2 inches. The number of right-hand rotations to seat the casing hanger will depend on how far the casing hanger was above the landing position. When the torque increases sharply, it is a positive indication of the casing hanger landing on its seat in the wellhead. The seals in the Adjustment Sub can be pressure tested with a straddle cup tester or during the casing pressure test. This is done by applying the required pressure, usually not greater than 80% of the burst rating of the casing, down the drill pipe. Running 13-3/8" Casing The 13-3/8" casing string (Figure 7.30) is run with the 13-3/8" mudline shoulder hanger, mudline running tool and the 13-3/ 8" Mandrel Hanger with Adjustment Sub on the full bore clutch-type casing hanger running tool. This 13-3/8" casing string is spaced out very carefully to ensure that the mudline shoulder hanger seats correctly on the 20" mudline landing ring. At this time, the mandrel casing hanger is within 18 inches of its correct landing position at the surface.

4-1/2" API IF

SETTING TOOL MAIN BODY

SPRING LOADED TORQUE KEYS

LOCK RING

The 13-3/8" full bore clutch-type casing hanger running tool (Figure7.31) is a threaded full bore running tool which is made up to the 13-3/8" mandrel casing Hanger with right-hand rotation at the surface. This full bore feature allows the 4-1/2" API IF PIN operator to launch cement wiper plugs from the surface. The running tool incorporates splines which allows the tool to rotate the mudline running tool down the hole without un- Figure 7.29 Setting Tool threading from the mandrel casing hanger. This is done with an overpull on the running tool. Any right-hand rotation

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13-3/8" DOUBLE CLUTCH RUNNING TOOL 13-3/8" MANDREL CASING HANGER

13-3/8" ADJUSTMENT SUB

13-3/8"RISER

13-3/8" MUDLINE HANGER RUNNING TOOL

13-3/8" MUDLINE SHOULDER HANGER

13-3/8" CASING

Figure 7.30. Upper section of the 13-3/8" casing string

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applied at the rig floor will rotate the mudline running tool to the right exposing the washports. After the annulus is washed out, the running tool is rotated to the left to close the mudline hanger running tool. After the mudline hanger has been pressure tested, the overpull on the clutch-type running tool is relaxed. The clutch-type running tool can then be rotated to the right and be released from the mandrel casing hanger. The 13-3/8" mandrel casing hanger (Figure 7.32) has righthand running threads. The outside surface has a metal-tometal seal preparation for the casing hanger seal assembly when it is run. The mandrel casing hanger has a threaded box down to accept a 13-3/8" casing pup, or (when mudline hangers are in use) to accept the 13-3/8" adjustment sub. The 13-3/8" casing shoe is the first joint run. Intermediate casing joints are made up and run until the casing that will be below the mudline is run. The pre-assembled mudline hanger and running tool joint is then picked up and made up to the 133/8" casing string. After the pre-assembled joint passes through the rotary table, the casing string must not be rotated as the 13-3/8" casing is lowered into the hole. As was the case with the 20" casing, this is to prevent the possibility of the CASING THREADS mudline running tool from backing off and releasing from the mudline hanger as the casing is being lowered into the hole. All of the 13-3/8" casing connections above the running tool should be made up CENTRALIZER to the maximum torque of the casing connection. These precautions are necessary as the running string will subseANTI-ROTATION quently be rotated to the right PINS to open the mudline RUNNING THREADS washports and then back to Figure 7.31. Clutch-Type Casing the left to close the washports. Hanger Running Tool ®

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Accurate spacing of the 13-3/8" running string is also required to place the 13-3/8" mandrel casing hanger within 18" of the landing seat inside the wellhead. The mandrel casing hanger running tool and casing hanger is picked up as a complete assembly and the 13-3/8" adjustment RUNNING sub made up to the bottom of THREADS the 13-3/8" mandrel casing SEALING SURFACE hanger is made up to the last joint of 13-3/8" casing. The 13- FLOW-BY PORTS 3/8" casing landing joint made up to the running tool is then used to lower the entire 13-3/8" CASING THREADS casing string slowly down until the 13-3/8" mudline shoul- Figure 7.32. 13-3/8" Mandrel Casing Hanger der hanger lands inside the 20" mudline hanger. The entire casing string is weight-set down. The 13-3/8" cement head is then installed on the 13-3/8" casing landing joint and a full bore cement job can be done as per program. At the conclusion of the cement job, the 13-3/8" mandrel casing hanger running tool is kept in tension so that the upper spline section of the tool is engaged and torque can be transmitted to the mudline hanger running tool if washout of excess cement is required. If the annulus cement level is below the mudline hanger, then the mandrel casing hanger running tool is allowed to stroke downwards to the lower spline section. The mandrel hanger running tool is then released from the right-hand running threads of the mandrel hanger with seven turns of left-hand rotation and recovered with straight upward pull. This leaves the 13-3/8" mandrel hanger unseated. The Setting Tool is then run down to the Adjustment Sub below the mandrel hanger. The Setting Tool is actuated with drill pipe pressure. This locks the Setting Tool into the Adjustment Sub ®

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Figure 7.33. Running the Setting Tool and setting the mandrel hanger

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Figure 7.34. Retrieving the Adjustment Sub Setting Tool

and the casing string is tensioned to the desired amount. The Setting Tool is then turned to the right to move the mandrel casing hanger down to its correct position in the 18-3/4" Unitized Wellhead. Pressure tests are then conducted on the Adjustment Sub seals and the setting tool is recovered. Installing 18-3/4" Seal Assembly on 18-3/4" x 13-3/8" Mandrel Casing Hanger The 18-3/4" Seal Assembly Running Tool (Figure 7.35) is made up to drill pipe. The 18-3/4" Seal Assembly (Figure 7.36) is lifted up and slipped on to the suspended running tool. The seal assembly is turned to the left (counterclockwise, looking down) to engage the four jay-lugs on the running tool. This assembly is then lowered through the 18-3/4" BOP stack 110

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4-1/2" API I.F. BOX

until the seal assembly lands on the 18-3/4" x 13-3/8" mandrel casing hanger. Seven turns of right-hand rotation make up the seal assembly to the external threads on the casing hanger. 10,000 ft-lb of final torque is required to energize the metal seals of the seal assembly. The drill pipe torque and the jaylugs on the running tool will be positioned in the automatic release position from the seal assembly jay-slots. The 18-3/4" seal assembly can now be pressure tested with the running tool in position by closing a pipe ram on the BOP stack and applying test pressure to the annular space below the pipe ram. RUNNING TOOL JAY-SLOT LOCKING RING

METAL SEALS

WEAR BUSHING JAY-SLOT

At the conclusion of the pressure tests, the rams are opened and the running tool is retrieved with straight upward pull.

JAY-LUGS (4)

RESILIENT SEALS

4-1/2" API I.F. PIN

7.35. Seal Assembly RunInstalling the 18-3/4" x 13-3/ Figure ning Tool 8" Wear Bushing Figure 7.36. 18-3/4" Seal Assembly The 18-3/4" x 13-3/8" wear bushing (Figure 7.37) is set on the rotary table and the 18-3/4" Combination Tool is made up to the jay-slot preparation in the wear bushing with 1/8 turn to the right. The wear bushing is then lowered through the BOP stack until it lands on the 18-3/4" x 13-3/8" mandrel casing hanger. No more than 1/4 turn of left-hand rotation should be needed for the jay-lugs on the skirt of the wear bushing to drop into the jay-slot preparation of the seal assemRUNNING/ bly. A quarter turn to the right locks the wear bushing into the RETRIEVING JAY SLOTS seal assembly and moves the Combination Tool to its autoBARRIER SEAL matic release position. The Combination Tool can now be retrieved with straight upward pull. JAY SLOTS

The well is now ready for the next drilling phase, namely drilling 12-1/4" hole for the 9-5/8" casing string. After the hole has been drilled to casing depth, the hole will be conditioned Figure 7.37. 18-3/4" x 13-3/8" Wear Bushing and the rig will be set up to run the 9-5/8" casing string.

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CASING THREADS

CENTRALIZER

ANTI-ROTATION PINS RUNNING THREADS

Figure 7.38 Illustration of the 9-5/8" Clutch-Type Casing Hanger Running Tool

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Run 9-5/8" Casing String with 9-5/8" Split Ring Mudline Hanger and 9-5/8" Surface Mandrel Hanger The 9-5/8" casing string is run with the 9-5/8" mudline split ring hanger and mudline running tool, and the 9-5/8" Mandrel Hanger with Adjustment Sub on the full bore double spline casing hanger running tool. Again, the 9-5/8" casing string is spaced out very carefully to ensure that the mudline shoulder hanger seats correctly in the multiple load shoulder profile of the 13-3/8" mudline hanger and that the mandrel casing hanger is within 18 inches of its correct landing position at the surface. The 9-5/8" full bore clutch-type casing hanger running tool (Figure 7.38) is identical in operation to the 13-3/8" full bore running tool . The 9-5/8" mandrel casing hanger (Figure 7.39) has righthand running threads. The outside profile has a metal-tometal seal preparation for the casing hanger seal assembly when it is run. The inside of the 9-5/8" mandrel casing hanger has right-hand tie-back threads for the possibility of well testing, if necessary. The mandrel casing hanger has a threaded box down to accept a 9-5/8" casing pup or when mudline hangers are used with a 9-5/8" adjustment sub.

RUNNING THREADS SEALING SURFACE

FLOW-BY SLOTS

CASING THREADS

The 9-5/8" casing shoe, casing, mudline hanger joint, riser and mandrel casing hanger and adjustment sub are run similar to the 13-3/8" casing (Figure 7.40). As was the case with 13-3/8" casing, accurate spacing of the 9-5/8" running string is required to place the 9-5/8" mandrel casing hanger within 18" of its landing seat in the wellhead. The 9-5/8" casing can be cemented in accordance with the well program. At the conclusion of the cement job, the 9-5/8" mandrel casing hanger is adjusted to its landing seat in the same manner as the 13-3/8" mandrel casing hanger.

Figure 7.39. 18-3/4" x 13-3/8" mandrel casing hanger

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Installing 18-3/4" Seal Assembly on 18-3/4" x 9-5/8" Mandrel Casing Hanger The 18-3/4" Seal Assembly for the 9-5/8" casing hanger is identical to the seal assembly used on the 18-3/4" x 13-3/8" mandrel casing hanger. It is run with the same tool and in the same manner as the seal assembly for the 13-3/8" mandrel casing hanger. Installing the 18-3/4" x 9-5/8" Wear Bushing The 18-3/4" x 9-5/8" wear bushing is equipped with the same running preparation as the 18-3/4" x 13-3/8" wear bushing and is therefore run in the same manner as the 18-3/4" x 13-3/8" wear bushing. The well is now ready for the next drilling or testing phase. Abandonment The same procedures for abandoning, re-entering and completing the well, as described in the earlier part of the chapter, can be applied to a well drilled with an 18-3/4" unitized wellhead.

9-5/8" DOUBLE CLUTCH RUNNING TOOL

9-5/8" MANDREL CASING HANGER

9-5/8" ADJUSTMENT SUB

9-5/8"RISER

9-5/8" MUDLINE HANGER RUNNING TOOL

9-5/8" MUDLINE SPLIT RING HANGER

9-5/8" CASING

Figure 7.40. Upper section of the 9-5/8" casing string

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Offshore Exploration From a Floating Drilling Vessel Introduction ............................................................................. 115 Floating Drilling Vessel Developments .................................. 115 Reusable Drilling Equipment Used in Guideline Drilling Systems....................................................................... 118 Motion Compensator .............................................................. 118 Guideline Tensioners ............................................................... 121 Marine Riser Tensioners ......................................................... 124 Subsea BOP Stacks.................................................................. 126 Wellhead Connector ................................................................ 127 DX Wellhead Connector ......................................................... 127 Lower BOP Stack Frame ........................................................ 128 Blowout Preventer Rams ........................................................ 129 Choke and Kill Lines .............................................................. 129 Choke and Kill Line Valves .................................................... 130 Annular Preventer .................................................................. 130 BOP Stack Mandrel ................................................................ 131 Upper BOP Stack Frame ........................................................ 131 BOP Stack Guide Posts ........................................................... 132 Lower Marine Riser Package Components .......................... 132 BOP Stack Connector ............................................................. 132 Lower Marine Riser Package Framework ........................... 133 Optional Annular Preventer................................................... 133 Ball Joints and Flex Joints...................................................... 134 Flex Joint Extension ................................................................ 135 Choke and Kill Flexible Hoses, or Loops .............................. 135 Marine Riser System ............................................................... 136 Marine Riser Joints ................................................................. 136 Telescopic Joint ........................................................................ 139 BOP Stack Control System ..................................................... 140

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Offshore Exploration From a Floating Drilling Vessel

Introduction Exploration drilling from floating drilling vessels had its beginnings in the mid 1950’s when flat-bottomed barges were modified to incorporate a central opening, or “moon-pool”, in the vessel. The drilling derrick and rotary drilling equipment were built into the deck structure over the moon-pool. The rest of the barge was used for storage of equipment, mud chemicals, drill pipe, etc. as well as living quarters for the operating personnel. These barges were towed to location by oceangoing tugs and anchored to the sea floor with up to 8 anchor lines radially deployed from the barge. These lateral anchoring restraints limited the sideways movement of the vessel, but had little effect on the up and down movement caused by tidal or wave action. The drilling operations from these floating vessels could not proceed in the same fashion as land drilling without some changes to the traditional equipment and procedures. The equipment changes and developments are discussed later in this chapter.

Figure 8.1. Illustration of a semi submersible floating drilling vessel

Floating Drilling Vessel Developments As the offshore drilling industry expanded, the requirement increased for more mobile floating drilling vessels with increased water depth capability. Self-propelled shipshape vessels were custom designed and built. Large self-propelled semi-submersibles became more popular, particularly in


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areas where sea conditions were known to be severe, i.e. the North Sea. Conventional anchoring systems are used to anchor drillships and semi-submersibles in position. The semi-submersible tends to offer a more stable base to drill from than a drillship. This results from the fact that the buoyancy for the semiSemisubmersible is provided by large Submersible (Anchored) pontoons that are submerged 70'100' below the water line Floating which puts them mostly Production Systems out of the main zone of (Anchored) Drillships (Anchored) Dynamically Positioned Drilling Vessels

Submersibles

Figure 8.3. Example of a typical Drillship

Jackups Land Frist Commercial Oil Production

Jetties

Platform

Tension Leg Platform

1850 1860 1870 1880 1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000

Figure 8.2 Illustration depicting the development of offshore and subsea drilling and completion vessels.

wave action. The supporting columns extending up from the pontoons are subject to wave movement, but the volumetric displacement is small when compared with the mass of the semi-submersible. Therefore, the semi-submersible tends to move up and down less and roll slower than a drillship in similar operating conditions. Figure 8.4. Example of a typical Semi-Submersible

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As offshore drilling locations moved into deeper waters, the use of conventional anchoring systems became prohibitively more expensive and time consuming. Any water depths in excess of 3000' have usually been drilled by dynamically positioned drillships and semi-submersibles. These drilling

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CROWN BLOCK

WATER TABLE

DRILLING LINE

MAST OR DERRICK STRUCTURE

TRAVELLING BLOCK GOOSENECK

ROTARY HOSE STAND PIPE

HEAVE COMPENSATOR HOOK KELLY COCK KELLY KELLY BUSHING


STAND PIPE VALVE GUIDELINE (4 TYPE) TENSIONER

ROTARY TABLE RETURN FLOWLINE

SUCTION PIT SETTLING PIT

TENSIONING CABLE (4-6 TYPE)

RISER TENSIONER (4 -6 TYPE)

SHALE SHAKER

TELESCOPIC JOINT ANCHOR CHAIN (8 TYPICAL)

MOONPOOL

MARINE RISER MARINE RISER CONNECTOR

GUIDELINE (4 TYPE)

BALL JOINT LOWER MARINE RISER PACKAGE GUIDE FRAME BOP STACK POST (4 TYPE) B.O.P. STACK WELLHEAD CONNECTOR

PERMANENT GUIDE BASE

SUBSEA WELLHEAD

TEMPORARY GUIDE BASE CEMENTED 30" CONDUCTOR CEMENTED 20" CASING

DRILL PIPE CASING SHOE

DRILL COLLARS

ANNULUS RETURNS

DRILL COLLAR SUB WELLBORE (17-1/2" HOLE) DRILLING BIT

Figure 8.5 Illustration of the main components of the Ship-Shape Floating Drilling Vessel

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units are held on location by powerful thrusters that are keyed into the satellite navigational system now available. The theory is that the vessel can be held on a centerline location in normal conditions within a 10 meter circle. The success of these dynamically positioned vessels appears to verify the theory. Wells have been drilled in water depths exceeding 7000' using these specialized units and guidelineless drilling systems. However, the next part of this chapter is devoted to the modified and specially developed equipment used by anchored floating drilling vessels using a guideline drilling system.

ACCUMULATOR AIR

AIR

PISTON

HYDRAULICS HYDRAULICS HOOK

HOOK

Figure 8.6. Illustration of drillstring compensator principle of operation

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Reusable Drilling Equipment Used in Guideline Drilling Systems Motion Compensator Anchored floating drilling vessels supplied a unique set of challenges to the oil industry. At the time, drilling technology was not prepared to accommodate the constant motion of the floating drilling vessel. A system of specialty equipment had to be designed to eliminate any wave-induced motion. One of the most important pieces of equipment created to handle this challenge is the motion or drillstring compensator. The function of a drill string motion compensator is to suspend the drilling assembly so that a constant weight is applied to the drill bit as the floating drilling vessel moves up and down. The principle of operation is depicted in Figure 8.6. The motion compensator is shown as a single cylinder and piston assembly supplied by hydraulic fluid from a large

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pressurized accumulator. The hook is attached to the piston and the drill pipe while the drill collars and bit are suspended from the hook. As can be seen from the diagram, the drilling assembly is shown resting on the bottom of the hole. Any pressure applied under the piston will provide an upward force. This force can be expressed by the equation: Force (lbs) = Pressure (psi) x Piston Area (Sq ins) Consider the following example where the total hook load is 100,000 lbs., and a pressure of 1000 PSI is applied to the compensator piston with an effective area of 80 sq. in. Using the above equation Force (lbs) = 1000 x 80 = 80,000 (lbs).

Figure 8.7. Early derricks and traveling blocks were retrofitted with two cylinder motion compensators

This means that the compensator is exerting 80,000 lbs. of upward pull which is not enough to lift the drill bit off of the bottom of the hole because the total hook load is 100,000 lbs. This means that 20,000 lbs is not supported by the compensator and is acting on the bit. This AIR SUPPLY BOTTLES example describes a static condition. If the MOTION COMPENSATOR drilling vessel moves down, and the compensator with it, then this action would tend to ACCUMULATOR increase the weight on the bit. However, the COMPRESSOR storage accumulator is providing fluid at a AND DRYER constant 1,000 psi to the underside of the piston. This moves the piston upward to support 80,000 lbs. leaving 20,000 lbs. on the bit once CONTROL PANEL again. As the vessel moves up, so does the FLUID compensator and effect is to lift the drilling SUPPLY assembly out of the hole. However, the piston can only support 80,000 lbs. as the fluid under Figure 8.8. Schematic of a single cylinder drillstring the piston moves back into the storage accu- Motion Compensator mulator at 1000 psi. In this manner, the float

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Figure 8.9. Photo of a typical air compressor and dryer unit

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ing drilling vessel moves up and down, but the compensator moves in and out ensuring that the weight on the bit is maintained at 20,000 lbs. If more or less weight is required on the bit, this is achieved by bleeding off the air pressure or increasing the air pressure from the air compressor/dryer assembly. In effect, the sensing device for the compensator is the drill string resting on the bottom of the hole. In drilling operations, the “neutral point” between the tensioned drill string and the portion resting in compression on the bottom of the hole is always maintained within the drill collar section of the drilling assembly. This is done because the drill collar sections and tool joints are very much more rugged than the drill pipe. The design of the drill string motion compensators usually employs two hydraulic cylinders and pistons. These cylinders and pistons are integrated into a unit that is inserted between the travelling block and hook (Figure 8.7). The designs have evolved using pistons in compression, or tension. Travelling block compensators are by far the most common in use on floating drilling vessels. Recently with the increasing use of “top-drive” drilling systems, crown block motion compensators are being used to eliminate the number of long flexible hoses in the derrick associated with travelling block compensators. The supply of operating fluid for the compensator at nearly constant pressure relies on a bank of high pressure air storage bottles. These air storage bottles are kept at operating pressure by an air compressor/dryer, or alternatively for additional compressed air bottles.

Figure 8.10. Photo of a typical drillstring compensator accumulator

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An integrated system of guideline tensioners, riser tensioners and drill string motion compensator can all be fed high pressure air from a large bank of air bottles supplied by one air compressor. The control panel for the drill string compensator is mounted adjacent to the driller's console and weight indicator. The control panel is provided with system pressure gages,

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compensator extension indicator, and control valves to raise or lower the operating pressure. Most compensators have a locking mechanism that locks the compensator together in its closed position and the control panel will have the control lever to actuate the lock mechanism. Most drill string compensators have 20'-25' of stroke capacity with a dynamic load carrying capability ranging between 400,000 lbs. to 600,000 lbs. Maximum system operating pressures range from 2000 psi to 3500 psi. Motion compensators are often used when lowering equipment to the sea floor, to provide a “soft” landing. For instance, if a BOP stack or a subsea production tree is being lowered on to a subsea wellhead, the compensator can be set to support all but 5000 to 10,000 lbs of the total hanging load. This means that even in fairly heavy swells, the BOP stack or tree is not subjected to a fierce impact when it lands on the subsea wellhead. Motion compensators are also used when landing casing hangers and the suspended casing strings in subsea wellheads. The motion compensator is probably the single most important innovation that simplified floating drilling operations. Guideline Tensioners The requirement for guiding drilling equipment from the floating drilling vessel to the sea floor resulted in the use of a guideline system. Some early systems used 3 guidelines, but these were quickly displaced by systems using 4 guidelines attached to a weighted guide base on the sea floor. The wire cables used for guidelines are equally spaced on a 6' radius from the central point of the guide base. This is the accepted industry standard today. Each guideline has to be tensioned so that it remains taut as the floating drilling vessel moves up and down. One early method used to tension guidelines was simply to string each guideline over 4 suitably positioned idler sheaves and connect the 4 guidelines to 4 hanging weights.

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TO AIR SUPPLY

ACCUMULATOR AIR

This simple guideline tensioning system had operational deficiencies, such as accommodating large swells and tidal movement, the guideline was cut to a specific length for the particular water depth at the drilling location and the weight needed some guidance restraints to prevent them from swinging around in a dangerous fashion. If the guideline broke for any reason, the hanging weight would drop and cause varying degrees of damage as it found its way to the sea floor. A better system was required and special guideline tensioners were designed and built.

FLUID

PISTON

WEIGHT TO AIR SUPPLY

ACCUMULATOR AIR

FLUID

PISTON

WEIGHT Figure 8.12. Illustration demonstrating the guideline tensioner principle of operation

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Most guideline tensioners in use today use a hydraulic cylinder and piston assembly in conjunction with wireline sheaves. Figure 8.5 shows the guideline tensioners and their position on the floating drilling vessel. Figure 8.11 shows the main components of the guideline tensioning system. High pressure air from the air compressor/dryer is supplied to the air storage bottle or bottles. The control panel has air control valves and air pressure gauges for each guideline tensioner. When the air control valve is opened, the air pressure then acts on the fluid in the AIR STORAGE ACCUMULATOR accumulator. The BOTTLES TENSIONER fluid under pressure then acts on the piston providCONTROL ing an upward PANEL force. The piston rod has two AIR wireline sheaves COMPRESSOR mounted at its AND DRYER upper end. The hydraulic cylinder has two Figure 8.11. Illustration guideline tensioners wireline sheaves main components

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mounted at its lower end. The steel guideline cable is strung, or reeved, over the four sheaves of the guideline tensioner. The end of the guideline from the sea floor guide base is passed over the idler sheave which is hung from underneath the rig floor. The other end of the guideline is spooled from a drum of cable and clamped with a wire line anchor to the fixed framework of the guideline tensioner. The guideline tensioner is mounted to the floating drilling vessel structure using mounting plates. In operation, as the floating drilling vessel moves up and down, the piston with the two upper sheaves will move in and out. This means that guideline cable is let out as the vessel moves up, and guideline cable is pulled in as the vessel moves down. As can be seen from the diagram, if the floating drilling vessel moves up, the piston will move down. Specifically, as the guideline tensioner moves up 4 feet, the guideline tensioner piston will move down 1 foot, because of the 4:1 mechanical advantage of the guideline tensioner. If the required tension in a guideline is 5000 lbs., the tensioner piston has to exert an upward force of 20,000 lbs., again because of the 4:1 mechanical advantage of the tensioner. If the piston area is 20 sq. inches, then the air pressure required in the system is 1000 psi. This is based on the equation: Force (lbs) = Pressure (psi) x Area (sq in). The tension in the guideline can be altered by adjusting the systems operating pressure. This is done by bleeding off air pressure or adding pressure by means of the air compressor, or an adjacent high pressure air vessel. The guideline will remain taut at a practically constant tension while the floating vessel moves up and down, and the piston assembly moves in and out supported by the “air spring”

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PISTON

ACCUMULATOR

AIR STORAGE

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which contracts and expands as the hydraulic fluid moves in and out of the air/oil accumulator. Obviously, as the air volume contracts, the pressure in the system will increase and reduce when the air volume expands. This in turn translates into increased or decreased tension in the guideline. If the air volume, or “air spring”, is large, then the tension variations are minimized. This can be achieved by having a bank of interconnected air storage bottles and the load, or tension variations, are reduced. Normally, guideline tensioners are designed with a 40' or 50' line travel capability and a 16,000 lbs. tension limit. Maximum operating pressures vary between 2,000 psi and 3,500 psi depending on the make of tensioner used. The guideline tensioner shown in Figure 8.13 is called a compression type because the piston rod is always in compression when it is operating. Other styles of tensioners use a configuration that puts the piston rod in tension during operation. The previous illustration shows the guideline tensioner components as independent pieces, but designs integrate the air/ oil accumulator and the air storage vessel into the structure of the guideline tensioner resulting in a compact unit.

TO AIR SUPPLY

Figure 8.13. Illustration of a typical guideline tensioner

Guideline tensioners also see duty if additional guidelines are required by guiding TV cameras on frames down to the sea floor. When a well is completed, each guideline will be cut, or pulled, from the sea floor guide structure and spooled back through the tensioner on to the spare drum of cable. As with all cable used in hoisting and tensioning devices, a log of tonmiles will be recorded for each tensioner. When the recommended service life of the cable is approached, it is cut and slipped so that new cable is put into service. Marine Riser Tensioners The function of marine riser tensioners is to apply a constant upward tension on the marine riser so that no part of the system is in compression during the up and down motion of

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the floating drilling vessel. Usually, the “neutral” point is calculated to be within the BOP stack. The tension required in the marine riser is a function of marine riser weight and density of the drilling fluid within the marine riser. The most common form of riser tensioners uses a hydropneumatic system to provide a constant force to a hydraulic cylinder and piston assembly. The cylinder and piston assembly are configured with wireline sheaves that accept the reeving of the riser tension cable. Figure 8.14 is a diagrammatic cross-section of a riser tensioner showing the relationship of the major components. As can be seen AIR STORAGE from this diagram, riser tensioners are just larger versions of guideline tensioners. The principle of operations is identical (refer to the earlier section on AIR SUPPLY guideline tensioners to understand the basic mode of operation). One end of the riser tensioner cable is attached to the outer barrel of the telescopic joint by means of fixed pad eyes, or a tensioning ring with pad eyes. Sometimes the tensioning ring is designed to accommodate 4, 6 or 8 riser tensioner cables depending on the size of riser and the water depths encountered. The tensioning ring can also be designed to rotate and a fluid bearing may be incorporated to assist the rotation. This is particularly true of operations conducted from a guidelineless floating drilling vessel where the vessel will be moved by its thruster to head into the weather. Single riser tensioners are usually designed with a 50' stroke capability and tension capacities from 60,000 lbs. to 100,000 lbs. Some dual designs will have a capacity of up to 160,000 lbs. Operating pressures of the system range from 2,000 psi to 3,500 psi depending on the type and manufacturer. Ton-mile records are kept on the tensioner cables, and they are cut and shipped when service life recommendations are approached.

PISTON

ACCUMULATOR

CONTROL PANEL

Figure 8.14. Illustration of a typical riser tensioner

The riser tensioners are usually mounted on either side of the

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rig structure in a row and the idler sheaves are suspended below the rig floor.

Figure 8.15. Photo of a typical BOP stack outfitted for guideline drilling operations

Subsea BOP Stacks The first BOP stacks used in floating offshore drilling operations incorporated the ram preventers and annular preventers in the bore sizes and pressure ratings that were available in the land drilling business. A popular combination used was a 203/4" x 2000 psi BOP stack and a 13-5/8" x 5000 psi BOP stack. This combination of BOP stack is known as a two stack system and is in occasional use in today's floating drilling operations. By definition, each size of BOP stack was connected to a matching size of subsea wellhead housing, and this type of subsea wellhead system become known as a two stack wellhead system. The value of this two stack system was that each hole size could be drilled with a full bore drilling assembly without the use of an under-reamer. Its disadvantage was that the 13-3/8" casing string and attached 13-5/8" wellhead housing had to be run into open hole as the 20-3/4" BOP stack had to be pulled prior to running the 13-3/8" casing. Also the cost, in terms of time, required to run and pull two BOP stacks in the course of drilling a subsea well became a major consideration. The introduction of single 16-3/4" x 5000 psi subsea BOP stacks to drill a subsea well overcame the inherent problems of a two stack system. However, under-reaming was still a requirement to open the pilot hole drilled through the 16-3/4" subsea wellhead up to 17-1/2" to accommodate the 13-3/8" casing string. The use of 18-3/4" BOP stack components, specially created for offshore drilling, to be used in conjunction with an 18-3/4" subsea wellhead housing, has now become the offshore industry standard. In parallel with the move to the 18-3/4" bore systems, the pressure rating requirements for offshore BOP stacks also increased. Abnormally over-pressured formations and zones were encountered with bottom hole pressures in excess of 12,000 psi. The requirement for a 15,000 psi BOP

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stack became a necessity and the BOP stack components got heavier and bulkier. It is not uncommon for a fully equipped 18-3/4" x 15000 psi BOP stack to weigh 180 tons. The primary function of the subsea BOP stack is basically the same as a land BOP stack, namely to provide a pressure tight means of controlling potential blowout conditions. The following narrative will describe the components and functions of a fully equipped 18-3/4" subsea BOP stack. Wellhead Connector The wellhead connector, attached to the bottom of the BOP stack, is a hydraulically operated unit that can be locked to, and unlocked from, a matching profile at the top of the subsea wellhead housing. Subsea wellhead profiles are categorized as hub profiles or mandrel profiles. The wellhead connector carries a metal seal gasket which provides a seal between the wellhead housing and the wellhead connector. This metal seal gasket is fully energized by the locking force of the wellhead connector. The various manufacturer designs for wellhead connectors are too numerous to cover in this brief review, but this component receives a lot of attention as its reliability of operation is of the utmost importance in the running and recovery of subsea BOP stacks. The upper body of the wellhead connector usually has a key slot in its bore. This key slot is used when setting oriented tubing hangers when, and if, the well is completed. DX Wellhead Connector The Dril-Quip DX Wellhead Connector is a mandrel profile connector designed for deepwater, high wellhead pressures and longer drilling times. This wellhead connector incorporates three hydraulic circuits: •

Primary Lock

•

Secondary Unlock

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Primary Unlock

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The primary locking circuit provides the power to LOCKING SEGMENTS lock the wellhead connecANNULAR tor to the well- PISTON/ head. The pri- CAM RING mary unlock- SPREADER ing circuit un- SEGMENTS locks the Connector from SECONDARY UNLOCK PISTON the wellhead, providing 25% greater unlocking force than locking Figure 8.16. Illustration of the 18-3/4" force. The secondary DX Wellhead Connector unlock circuit is an independent unlocking circuit used as a backup to the primary unlock circuit. The secondary unlocking circuit provides 88% greater unlocking force than locking force. The DX Wellhead Connector (Figure 8.16) incorporates a unique locking segment retracting feature which ensures the locking segments are fully retracted from the wellhead profile when the connector is unlocked. This is accomplished with four spreader cam segments that are attached to the annular piston/cam ring. Figure 8.17. Illustration showing the positive unlock feature of the DX Wellhead Connector

The Ring gasket retainer system is ROV compatible for easy ring gasket replacement without retrieving the BOP Stack to the surface. Lower BOP Stack Frame As mentioned earlier, the size and weight of the BOP stack components means that the supporting framework for the integrated stack needs to be carefully designed. The lower

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BOP stack frame has a central steel structural ring that is bolted to the body of the wellhead connector. The frame will normally have four arms terminating in structural flanges that will match up with the four posts of the BOP stack. Blowout Preventer Rams Modern subsea BOP stacks will have 4 ram preventers in them. The illustration shows two dual ram preventers stacked up and bolted to the upper adapter of the wellhead connector. One of the four rams will be a blind/shear ram capable of cutting through drill pipe and sealing the bore of the BOP stack. These rams, in common with the main BOP stack components, require hydraulic power to close and open the rams. The position of the blind/shear ram in subsea BOP stacks appear to be a matter of personal preference as they have been placed in each of the four positions available. The most common position appears to be the second ram position from the top.

UPPER BOP STACK FRAME

POSTS

Choke and Kill Lines LOWER As can be seen from the BOP stack cross section, choke and kill BOP STACK outlets are provided under each ram position. In the example FRAME shown in Figure 8.20, each outlet has been connected to a choke or kill line. Dual hydraulically operated gate valves are Figure 8.18. Illustration of the BOP shown on each outlet. This doubling up of the valves provide stack frame. extra safety for this important well control function. If the BOP stack is used to control a blowout, the rate of fluid or gas flow through these choke and kill valves and lines can be very high and if abrasive particles are carried in the fluid or gas, the gates and seats in the valve can be damaged extensively. The choke and kill lines are manufactured from ex Figure 8.19. Photo of typical 18-3/4" 15,000 psi ram preventers

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tra heavy wall line pipe with pressure ratings in excess of the pressure rating of the BOP stack. This measure is taken in order to provide a greater than normal safety factor to components that may see very severe operational conditions in their service life. The choke and kill lines terminate in male stab subs above the upper BOP stack frame. KILL LINE

MANDREL RAMS

GATE VALVES GATE VALVES

WELLHEAD CONNECTOR

Figure 8.20. Illustration of the wellhead connector, rams and mandrel stack-up

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Choke and Kill Line Valves These specialized mud service gate valves are hydraulically operated and are usually furnished with gates and seats that are hard-faced with tungsten carbide, or equally wear resistant metal. They are usually mounted in pairs to provide a CHOKE safety back-up. The hydraulic operators will have a spring LINE cartridge that will close the valve in the event of hydraulic control failure. Annular Preventer The next component in the BOP stack is the annular preventer that is bolted or clamped to the top of the upper ram preventer. The annular preventer has a full opening rubber element reinforced with metal ribs that can close on any shape of tubular positioned within the BOP stack bore. The rubber element can close on open hole, but this capability is only used in an emergency as the resulting wear and tear shortens the service life of the element. In BOP stack testing, the annular preventer will be pressure tested on a large diameter tubular section positioned in the BOP stack. The unit is hydraulically closed and usually retracts to its full open position when the closing pressure is bled down. The natural spring force of the rubber element is usually sufficient to get full retraction. However, if it does not retract properly, it becomes a constriction to the passage of full bore down hole tools. A number of down hole equipment failures have been attributed to the gouging of exposed seals and seal surfaces as they have passed through constrictive annular elements. As mentioned in the earlier chapter on land drilling, a number of drilling operators cut the elements in half to assist the element in retracting to a

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fully open position. The pressure ratings of annular preventers mounted on subsea BOP stacks are usually lower than the pressure ratings of the ram preventers. BOP Stack Mandrel The BOP stack mandrel is bolted or clamped to the top of the annular preventer. It has the same bore dimension as the BOP stack. The upper end of the mandrel has an external profile in the form of a hub or a grooved locking dog preparation. The BOP stack mandrel is the connection point for he connector in the lower marine riser package. Upper BOP Stack Frame Figure 8.21. Illustration of a typical The upper BOP stack frame is the most structurally significant annular preventer frame in the BOP stack. It is mounted around the annular preventer and is connected to each of the four BOP stack guide posts. The upper frame provides the baseplate for two female control pod receptacles. These receptacles are mounted 180o apart and provide the locking and sealing interface for the two retrievable control pods that are run with the BOP stack. Only one control pod is required to operate the BOP stack. The other control pod provides a Figure 8.22. NL Shaffer and Hydril Annular backup in the Preventers event of a failure in the first control pod. The receptacles have outlets that are connected to each of the hydraulic control functions on the BOP stack.

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CONTROL POD RECEPTACLES UPPER BOP STACK FRAME

Figure 8.24. Illustration of the main BOP Stack assembled

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BOP Stack Guide Posts These 4 guide posts, mounted at the 4 corners of the BOP stack, are large tubular members with longitudinal slots to accommodate the 4 guidelines. Each post has a line trap, top and bottom, to capture the guideline. The lower part of the post is a downward facing cone to give the stack primary guidance as its posts move down over the four posts of the sea floor guide structure. The BOP stack posts and framework are designed to protect the integrated BOP stack components from any bending loads or stresses anticipated during the drilling of a well. Sometimes, because the drilling conditions induced by underwater currents and surface weather are expected to be particularly severe, the BOP stack framework is beefed up. The drilling contractor may also want the stack equipped for emergency recovery in a worst case scenario. This could mean that the BOP stack has been dropped and is resting on the sea floor on one side in water depths too deep for diver assistance. For this case, the framework may be designed so that a recovery grapple can engage one leg or post and recover the BOP stack without any buckling or damage. There are other emergency recovery systems for BOP stacks that have lost their conventional control system because of a control pod failure or a plumbing failure on the BOP stack. This means the BOP stack cannot be unlocked from the subsea wellhead and hydraulic power has to be supplied to the wellhead connector by another method. In these days of remotely operated vehicles (ROV’s), an acceptable solution would be to deploy the ROV with the ability to connect a hydraulic adapter to an outboard mating assembly on the BOP stack. Hydraulic power would come from a pre-charged accumulator carried by the ROV and the wellhead connector could be unlocked and the BOP stack recovered. Lower Marine Riser Package Components BOP Stack Connector This piece of equipment can be identical to the wellhead connector on the bottom of the BOP stack, and quite often that

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is the case (Refer to Figure 8.25). It is hydraulically locked and unlocked from the BOP stack mandrel. This connector is rarely separated when the BOP stack and lower marine riser package are in position locked to the subsea wellhead. However, in an emergency or if weather conditions are severe and the floating drilling vessel is forced off location, the BOP stack will be left on bottom in a shut-down mode and the lower marine riser package and the marine riser system will be recovered. Sometimes, the emergency occurs very rapidly and the vessel moves off location which applies a high bending moment at the BOP stack as the marine riser system tries to pull the BOP stack over on its side. The requirement for a guide positive release from the BOP stack becomes extremely important and the designs of these BOP stack connectors have seen some changes. One such change has been to reduce the swallow of the connector so that the connector body does not bind with the BOP stack mandrel even though the locking mechanism in the connector has been released. The reduced swallow allows the BOP stack connector to release more easily giving rise to high angle release connectors. The term high angle is misleading as the specifications usually call out a maximum release angle of 10o from the vertical. Normal connectors probably have a release angle of 3o or less.

FLEX JOINT EXTENSION

FLEX JOINT

FLEX LOOPS

CONTROL PODS

ANNULAR

BOP STACK

Lower Marine Riser Package Framework CONNECTOR Usually, a four armed frame is built around the BOP stack connector with guide cones and line runners to engage the CONTROL PODS four guidelines. This framework usually carries two mating control pod receptacles that interface with the two control pod receptacles on the BOP stack upper frame. Also, two female Figure 8.25. Illustration of the lower choke and kill line stab subs are integrated into this framework marine riser package that engage the male choke and kill stab subs on top of the BOP stack. Optional Annular Preventer Sometimes a second annular preventer is called for in the BOP stack design, again reflecting the commonly occurring theme

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of equipment redundancy in subsea equipment design. The second annular preventer can be included in the main BOP stack and occasionally has been done. However, weight and height limitations on floating drilling vessels have generally dictated that the second annular is put in the lower marine riser package. It is bolted or clamped to the BOP stack connector. Ball Joints and Flex Joints The lateral migration of the floating drilling vessel as it moves within its anchoring restraints because of surface currents or wind action means that the marine riser is flexing backwards and forwards, even if somewhat slowly. Subsea currents can impart a considerable side loading as the currents act on the effective “sail” area of the marine riser system. To control the effects of these movements being transferred into the BOP stack and lower marine riser package, a full bore ball joint, or flex joint, is included at the base of the marine riser. These units are bolted or clamped to the top of the BOP stack connector or the second annular preventer if one is included in the lower marine riser package. Single ball joints allow up to 10o flex from the vertical and rely on resilient seals to keep the drilling fluid inside the marine riser. Some of the inherent problems with ball joints are that the seals have to move backwards and forwards over a seal surface that is lubricated by drilling fluid on the inside and seawater on the outside. As marine risers are tensioned, this tension is also applied to the ball joint which means the ball and socket sections of the ball joint are forced together. These factors create an abrasive wear environment for the seals and seal surfaces. Various means of pressurized lubrication have been used on ball joints and have extended the service life of these units. The development of flex joints that have no moving seal surfaces was a technical advance in this critical area of marine

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riser systems. The modern flex joints use a shaped multilayered laminate of synthetic rubber and steel that is bonded together. The flex element permits up to 10o angular movement from the vertical and has its own spring force to bring it back to a vertical position when no side loading is applied. The flex joints are a lot stiffer in their movement than a ball joint. Flex joints have largely replaced ball joints in floating drilling operations as they are virtually maintenance free (Figure 8.26). Flex Joint Extension This piece of equipment is constructed from a short length of marine riser pipe. The lower end usually has a flanged connection that forms part of the top adapter of the flex joint, or may be bolted to the top of the flex joint. The upper end of the flex joint extension is normally equipped with a marine riser connector pin looking up. The length of the flex joint extension is dictated by the need to accommodate flexible choke and kill hoses, or steel flex loops. Choke and Kill Flexible Hoses, or Loops The choke and kill lines from the BOP stack have to pass around the flex joint, or ball joint, and flexible lines are required to accommodate the angular deflection as the flex units move (Figure 8.25). The lower ends of the choke and kill lines in the lower marine riser package are female stab subs that are integrated into the guide frame. The upper ends of the choke and kill lines terminate as male stab subs, secured in a support flange that is usually an integral part of the marine riser connector pin mentioned earlier. The connecting lines between these stab connections are flexible hoses, or flex loops. The flexible hose can be compared with a short section of rotary hose. Some of these hoses are more heavily built than others depending on the pressure rating of the choke and kill line system. The flexible steel loops are also made of thicker walled material based on pressure requirements. Usually 15,000 psi systems use steel loops, but high pressure armored

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Figure 8.26. Illustration of a flex joint currently in use

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flexible hose is available when specified. Marine Riser System

TELESCOPIC JOINT

TENSIONING RING

INTEGRAL CHOKE AND KILL LINES

RISER JOINT

Figure 8.27. Illustration of the upper section of the marine riser system

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Marine Riser Joints The function of the marine riser is to provide a steel conductor that (a) raises the drilling fluid circulation level from the sea floor to the floating drilling vessel and (b) provides a conduit for the drilling assemblies and casing strings as they are lowered into the BOP stack and well bore. Early marine riser systems used large diameter steel pipe with flanged end connections. Each section of marine riser was 50' long with a selection of shorter sections or pup joints, for spacing out the marine riser in order to accommodate the water depth at a drilling location. The choke and kill lines were usually run separately through the use of guide frames or stabbed through guide funnels attached to the marine riser body. The lower end of the choke or kill line would be a stab sub that latched into a matching receptacle on the BOP stack. Modern marine riser systems have the choke and kill lines integrated into each marine riser joint, and the marine riser connectors are pin and box assemblies that are locked rigidly together (Figure 8.27). The joints are usually run in the pin up/ box down mode as are the integral choke and kill lines. The choke and kill lines stab together when the marine riser joints are stabbed and locked together. The support flanges at each end of the marine riser joint are recessed to provide the attachment points for each end of the choke and kill lines. Additional clamps are used around the body of the marine riser to hold the choke and kill lines in position. Marine riser connectors usually have locking dogs, carried in the box half of the connector, that are driven inwards to engage a matching groove profile on the pin half of the connector. Some marine riser box connectors use a heavy section locking

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ring that is driven into a matching lock ring groove on the pin section of the connector. Whatever means is used, it is imperative that the locking dog, or ring, is held firmly into position while the marine riser is in service. The natural movement and flexing of the marine riser, coupled with vibrations from the drill string, can loosen the connection if an anti-backout means is not provided for each make-up mechanism. The resilient seals for each choke and kill stab connections are carried in the female half of the stab sub. The resilient seals for the marine riser connections can be carried on either the box or pin section. As offshore wells were drilled in deeper and deeper water, the various lengths of marine riser have increased as well as the overall weight of the mariner riser. In order to reduce the marine riser load, buoyancy systems have been used very effectively. These buoyancy systems have varied in form from buoyancy modules of syntactic foam attached to the riser to integral buoyancy cans that use compressed air systems to displace the sea water from the cans. The diameter of the marine riser pipe and the wall thickness are carefully selected to match the bore of the associated subsea BOP stack. Some common match-ups are listed in the chart below. Riser Size (OD) 16" 18-5/8" 21" 24"

BOP Stack Size 13-5/8" 16-3/4" 18-3/4" 21-1/4"

The pressure rating of the BOP stack will determine the pressure rating of the choke and kill line system. The diameter, wall thickness and the grade of steel pipe used in the manufacture of the choke and kill lines is a function of the

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pressure rating and flow capacity required in the choke and kill lines. A limiting factor on the overall OD of the integral marine riser is the maximum opening through the rotary table. 49-1/2" rotary tables have become quite common in offshore floating drilling systems and appears to accommodate most requirements. The BOP stack and lower marine riser package are lowered to the sea floor wellhead or marine riser. Each joint is picked up using a marine riser handling tool which consists of a marine riser box down with a short drill pipe stem and box up. The first joint is lowered through the rotary table and connected to the marine riser pin on top of the flex joint extension. The BOP stack and connected lower marine riser package is then picked up off of the support beams, or spider beams, which are then retracted out of the way. The assembly is then lowered until the upper support flange on the marine riser joint can be landed on the four support dogs of the marine riser handling spider sitting on the rotary table. The marine riser handling tool may have choke and kill pressure test caps on it that seal on the marine riser choke and kill lines. A pressure test can be made against the closed choke and kill line valves on the BOP stack. After a successful pressure test, the marine riser handling tool is removed and the next joint of marine riser is stabbed over and made up to the marine riser pin sitting in the marine riser handling spider. The marine riser and suspended BOP stack are then picked up, the four spider dogs are retracted, and the assembly is lowered until the four spider dogs can once again be positioned under the support flange of the added joint of marine riser. More marine riser joints are added in this manner, including any required pup joints for spacing purposes. The choke and kill lines will be pressure tested at regular intervals, usually every 2 or 3 joints, as the riser is run. The uppermost component of the marine riser system, the telescopic joint, is added next.

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Telescopic Joint The function of the telescopic joint is to provide sufficient vertical stroke which compensates for the effect of heave and tidal motion on the floating drilling vessel. The telescopic joint is made up of two main components, the outer barrel and the inner barrel (Figure 8.28). The outer barrel has a marine riser connector box at its lower end which connects to the last joint of marine riser. The outer barrel carries the rubber sealing elements that permit the inner barrel to stroke in and out containing the drilling fluid in the marine riser. The sealing elements are contained in a packing box mounted on top of the outer barrel. The inner barrel has the same bore as the marine riser and an upper connection that mates with a bell nipple, or flow diverter system. The lower end of the inner barrel is equipped with a shoe that provides a funnel shaped profile for drilling tools coming out of the hole and a stop shoulder that comes up against the packing box when the telescopic joint is fully extended. Typically, telescopic joints have a 50' plus or minus stroke capability and can support in excess of 1,000,000 lbs load in the locked shut mode or the fully extended mode. In operation, the outer barrel of the telescopic joint is a fixed part of the marine riser connected to the sea floor by way of the BOP stack. It carries the attachment points for the riser tensioning system to maintain the marine riser in tension as the floating vessel moves up and down. The inner barrel is attached to the underside of the rig floor by way of the attached bell nipple or flow diverter.

INNER BARREL

PACKING OR STUFFING BOX

CHOKE & KILL STAB SUB

OUTER BARREL

The choke and kill lines are attached to the outside of the outer Figure 8.28. Illustration of a typical barrel. The lower ends of the choke and kill lines are female telescopic joint stab subs that mate and seal with the male stab subs on the last joint of marine riser when the telescopic joint is connected. The upper end of the choke and kill lines are equipped with a stab sub profile, a clamp or flange connection. Flexible high pressure hoses are connected to these choke and kill end fittings as well as the high pressure steel lines leading to the

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choke and kill manifold. These high pressure choke and kill hoses have to be long enough to accommodate the full stroke of the telescopic joint in operation. BOP Stack Control System All of the functions on the BOP stack and lower marine riser package require hydraulic fluid under pressure to lock and unlock the wellhead connector, to open and close the choke and kill valves and to open and close the ram preventers and the annular preventers. Therefore, the function of the control system is to direct sufficient volumes of hydraulic fluid under pressure to the required BOP stack components. The most common type of EMERGENCY BATTERY PACK BOP stack control system is a hydraulic pilot operated system. This CONTROL MINI PANEL HYDRAULIC PANEL system is used POWER UNIT because it ofHOSE REEL MANIFOLD fers a fast reHOSE REEL sponse time from the conHOSE BUNDLES trol panel initiation to operation of the BOP stack function. The control line CONTROL umbilical is an POD ACCUMULATOR integrated asRACK sembly of multiple small diameter control Figure 8.29. Schematic diagram of the BOP stack hoses and one control system or two larger 140

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diameter hydraulic fluid supply hoses. The umbilical is usually sheathed in a smooth, hard wearing plastic. As mentioned earlier in the BOP stack components summary, two control pod receptacles are integrated into the lower marine riser package framework which, in turn, engage and seal on two more receptacles on the main BOP stack framework. The dual control pod system gives 100% redundancy of operation with either control pod and connected umbilical capable of operating the BOP stack functions completely. The control pod contains pilot operated valves that, when actuated, direct the hydraulic fluid to the required functions by way of the steel control lines connecting the outlets on the control pod receptacle to the BOP stack functions. One of the primary operating requirements is that the valves and rams operate very quickly in order to avoid excessive drilling fluid wear if these components are closing on a potential blowout condition. If all of the hydraulic fluid had to pass through the fluid supply hose in the control line umbilical, then slow closure rates would result. In order to improve the closure time, a bank of hydraulic fluid accumulators are mounted on the BOP stack. The capacity of this high pressure storage bank is usually 1-1/2 times or more than the total volume required to operate every single function on the BOP stack at least once. This source of high pressure fluid provides the required surge of hydraulic power when a pilot valve in the control pod is opened and maintained by constant supply from the fluid supply units on the floating drilling vessel.

Figure 8.30. Photo of a typical BOP stack control panel

Figure 8.31. Photo of a typical hydraulic supply Koomey unit

When the BOP stack is lowered to position on the sea floor, the control pods are locked to their respective receptacles on the BOP stack and the two control line umbilicals are spooled out with two steel cables attached to the control pods. Once the BOP stack is landed, the auxiliary control panel on each umbilical spool can be used to lock the BOP stack to the Figure 8.32. Photo of the moonpool subsea wellhead housing. Because the BOP stack can be area and the umbilical reels

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operated from either of the two control systems, shuttle valves are used to direct the fluid flow to the required function. Sometimes, these shuttle valves are mounted directly on the inlet ports of the BOP stack component or they are integrated into a bank of shuttle valves mounted on the BOP stack. If one of the control pods malfunctions, it can be unlocked and pulled to the surface independently of the BOP stack by the pod cable and control line umbilical. Usually, drilling operations will be suspended while the control pod is repaired and re-run down to the BOP stack.

Figure 8.33. Photo of a control pod being tested (unlocked and pulled)

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The main control panel is mounted on the rig floor close to the driller's console. A number of the controls will require two hand operations so that inadvertent operation of a BOP stack function cannot take place. A duplicate remote control panel will be situated in the rig superintendents office on board the floating drilling vessel. The operating pressure for the hydraulic control system is usually in the range of 1500-3000 psi.

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Introduction to Subsea Wellhead Equipment Introduction ............................................................................. 145 Temporary Guide Base ........................................................... 146 Drilling 36" Hole ..................................................................... 148 30" Conductor, 30" Housing, And Permanent Guide Base ............................................................................... 148 Jetting the 30" Conductor In To Place .................................. 152 Installing the 30" Conductor with a Mud Mat ..................... 153 Dril 26" Hole ............................................................................ 153 Drilling Without Returns ....................................................... 153 Drilling With Returns ............................................................. 154 Drilling with Returns And A Flow Diverter.......................... 155 20" Casing, 18-3/4" Wellhead Housing ................................. 156 18-3/4" BOP Stack, 21" Marine Riser .................................. 160 18-3/4" BOP Stack Testing ..................................................... 161 18-3/4" Nominal Bore Protector ............................................ 162 Features of Subsea Casing Hanger System ........................... 166 Casing Hanger, Seal Assembly Running Tool ....................... 166 18-3/4" Seal Assembly ............................................................. 168 13-3/8" Casing, 18-3/4" x 13-3/8" Casing Hanger ............... 169 18-3/4" x 13-3/8" Wear Bushing ............................................ 179 9-5/8" Casing, 18-3/4" x 9-5/8" Casing Hanger ................... 181 18-3/4" x 7" Casing Hanger and 18-3/4" Wear Bushing ..... 183 Testing the BOP Stack ............................................................ 184 Mill and Flush Tools ................................................................ 185 18-3/4" Seal Assembly Running Tool .................................... 188 The Emergency Seal Assembly .............................................. 189 Emergency Drill Pipe Hangoff Tool ...................................... 190 Abandonment .......................................................................... 190 Optional Subsea Wellhead Equipment ................................. 191 Full Bore Cementing and Full Bore Running Tools ............. 191 16" Supplemental Casing Hanger System ............................ 193 Deepwater Drilling Considerations ....................................... 195 Annulus Packoffs .................................................................... 197 Secondary Conductor String ................................................. 197 Riserless Supplemental Casing Systems ............................... 198 Table of Contents

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Introduction to Subsea Wellhead Equipment

Drilling A Typical Subsea Well With An 18-3/4" 15,000 PSI Three Hanger Wellhead Housing Introduction This chapter of the manual assumes that the floating drilling vessel, shipshape or semi-submersible, is anchored over the selected drilling site and that the reader is familiar with the practices and procedures used to drill a well on land. Floating drilling has seen the evolution of specialized equipment in order to deal with underwater conditions and sea motion. These pieces of specialized equipment; Tensioners; Heave Compensators; Subsea BOP Stacks; and Marine Riser Systems should be referenced as the drilling of our typical subsea well is described. Subsea wellhead systems have gone through an evolution over the years. Each different subsea wellhead system has made its own contribution to the overall development of subsea wellhead technology. The subsea wellhead system that will be used in this discussion will be a DRIL-QUIP SS-15 Subsea Wellhead System. Figure 9.1. Stack-up of the 18-3/4" SS-15 subsea wellhead system

The design objective of the SS-15 Subsea Wellhead System is


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two-fold. First, to provide the operator with the latest in technology, as well as maximum strength and capacities. Secondly, to provide a wellhead system that is easy to install and requires a minimum amount of handling. This is accomplished by incorporating a weight-set seal assembly design and minimizing the total number of tools to install the wellhead components. All subsea wellhead components can be placed into three major categories: 1. 2. 3.

Figure 9.2. Illustration of the temporary guide base

Guidance Equipment Wellheads, Casing Hangers, Seal Assemblies, and Wear Bushings Running Tools

Temporary Guide Base The function of the temporary guide base is to provide a weighted primary guide base on the seal floor with four guide lines attached to it for the guidance of tools and equipment as the well is drilled. Before it is run to the sea floor, the open compartments of the temporary guide base (Figure 9.2) are first filled with weighting material, usually sacks of barites or cement, until it weighs about 25,000 lbs.

Figure 9.3. Temporary guide base waiting transport

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This is usually done while it sits on the spider beams located directly below the rotary table. The four wire guidelines (3/4" or 7/8") are connected to the four pad eyes on the temporary guide base. The four guidelines are 90o apart on a 6' radius which is an industry standard. The temporary guide base running tool is made up to drill pipe and then inserted into the short guidance funnel on the temporary guide base made up to the 4 jay slots with

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Figure 9.4. Landing the temporary guide base on the sea floor with the Temporary Guide Base Running Tool

1/8th of a turn to the left. The temporary guide base is then picked up, the spider beams are retracted and the temporary guide base is lowered on drill pipe to the sea floor letting out the four guidelines as it goes down. When the base has landed on the sea floor, the weight is set down on the running tool and the drill string is rotated 1/ 8th of a turn to the right to disengage the running tool from the jay slots in the base. The temporary guide base running tool is then retrieved with a straight upward pull. The guideline tensioners mounted on the drilling vessel are activated (see Tensioner Section of Chapter 2 for more detail). The tension in each guideline will be up to 5,000 lbs. pull, but not enough to lift the temporary guide base off the sea floor.

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Drilling 36" Hole The next operation is to drill the 36" hole for the 30" conductor. The 36" drilling assembly is made up and lowered on drill pipe down through the rotary table to the moonpool or spider deck area. Here a retrievable guide frame, with two arms equipped with line runners or guide cones, is installed around the drill pipe above the drilling assembly. Two opposite guidelines are installed in the line runners or guide cones and the drilling assembly can now be guided as it is lowered to the sea floor and enters the central hole in the temporary guide base. The first section of 36" hole can now be drilled. After the first additional joint of drill pipe has been added to the drill string, the retrievable guide frame can be recovered to the surface. The 36" hole is then drilled to depth using sea water as the drilling fluid with returns and cuttings being dumped at the sea floor.

ALIGNMENT LUGS

CEMENT RETURN HOLES

An alternative method in guiding the 36" drilling assembly is to centralize the bottom hole assembly inside the guide lines with four soft line ropes and shackles which act like runners along the guide lines. When the drilling assembly enters the center receptacle of the temporary guide base, the ropes simply break off allowing the rig to proceed with drilling the 36" hole.

GUIDE TOP RETAINER RING LEVEL INDICATOR

30" LANDING SHOULDER

GUIDE POST

Figure 9.5. Illustration of the drilling or expendable permanent guide base

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This section of open hole is usually about 150' - 200' deep, but can often be difficult to keep open if the sea floor sediments are loose and unconsolidated. To stabilize the hole, it is sometimes the practice to spot a pre-mixed gel of clay and water in the hole prior to running the primary conductor. 30" Conductor, 30" Housing, and Permanent Guide Base Before the 30" primary conductor is run, the ®


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permanent guide base is set on spider beams below the rotary table. The permanent guide base is a four post structure with slotted posts to receive the four guidelines which are inserted and secured in place with the guideline traps. The four guide posts are 90° apart on a 6' radius from the center of the base. Permanent guide base post tops are available in a number of styles.

CEMENT RETURN HOLES

GUIDE TOP

ALIGNMENT LUGS

30" LANDING SHOULDER

RETAINING COLLAR RETRIEVAL LUG

RETAINER RING

GUIDE POST

GIMBAL LOCKING PIN

LEVEL INDICATOR

T HANDLE LOCKDOWN SCREWS

GIMBAL

RECOVERY CHAIN

Figure 9.6. Illustration of the remote retrievable permanent guide base

Since the permanent guide base interfaces the wellhead equipment with the BOP stack (no two BOP stacks are alike), permanent guide bases are available in a number of configurations. First, there is a simple drilling guide base which incorporates all the features necessary for drilling a subsea well. This guide base, however, is not retrievable (Figure 9.5) without plugging the well and retrieving the wellhead equipment too. This drilling guide base also has bolts on posts that are not retrievable or re-installable during the drilling operation. Drilling or expendable guide bases are typical of early subsea drilling guide base configurations.

The remote retrievable permanent guide base is retrievable with a drill pipe running and retrieving tool and does so while leaving the 30" wellhead, 18-3/4" wellhead and all the wellhead components in place on the sea floor (Figure 9.6). This guide base also has the capability for ROV assisted guide post removal and reinstallation in the event a post is damaged during the drilling operation. Permanent guide bases are manufactured according to the specifications of the operator and may combine one or more of the features described. For purposes of this discussion, the

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remote retrievable permanent guide base will be featured.

30" WELLHEAD RUNNING TOOL

30" WELLHEAD

30" WELLHEAD EXTENSION

DRILL PIPE CEMENT STINGER

The 30" conductor is made up from 40' or 50' lengths of conductor pipe with large diameter automatic weight-set connectors that lock together as the box member stabs over the pin member (refer to Chapter 1). Automatic weight-set connectors are the connector of choice because of the difficulty in handling and rotating the large bore diameter conductor on the Floating Drilling Vessel. The 30" shoe joint is passed through the center opening of the permanent guide base. In order to ensure that the 30" shoe will be centered when it is lowered to the sea floor, four soft line guide ropes are attached to small pad eyes welded to the outside of the shoe joint. The guide ropes are then secured to the guidelines with small shackles that also act as line runners. The 30" conductor sections are connected and run and the last joint with the 30" wellhead housing (Figure 9.7) welded on top is added and the 30" wellhead housing is landed in the rotary table. A cement stinger of drill pipe can be made up at this time using a false table on top of the 30" wellhead housing. The 30" wellhead housing

Figure 9.7. Illustration of the permanent guide base, 30" wellhead and the 30" Wellhead Running Tool

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Figure 9.8. 30" wellhead landed at the rotary table

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running tool is then made up to the cement stinger and lowered into the 30" wellhead housing. The four pins on the running tool should be aligned with the four anti-rotation slots in the top of the 30" wellhead housing. The running tool is made up to the wellhead housing by rotating the tool 5 turns to the left. This rotation forces a lock ring on the running tool out into the matching internal profile of the 30" wellhead housing. Verify that the running tool is fully made up by observing the indicator rod. At this time, the ball valves for the fill up and vent lines installed on top of the running tool can be opened. The conductor, complete with housing, running tool and cement stinger, is then picked up and lowered through the rotary table until the 30" housing alignment slots can be aligned with the four lugs in the center section of the perma- Figure 9.9. Lowering the 30" wellhead and permanent guide base nent guide base. The 30" housing is secured to the permanent into the splash zone guide base with a retainer that snaps closed over the top of the 30" housing. A cable is attached to the ball valve handles on the running tool which is spooled out when the complete assembly of conductor, 30" housing and permanent guide base is lowered to the splash zone. As the assembly is lowered on drill pipe, the 30" conductor is allowed to fill with sea water through the fill-up ports in the running tool. When the conductor is full, the cable attached to the ball valve handles is pulled up to close the vents. Continued upward pull shears the cable from the handles and the cable is retrieved. As the assembly is lowered to the sea floor, the 30" guide shoe will enter the drilled hole and the four soft rope guides will break. The permanent guide base gimbal will land on the temporary guide base funnel Figure 9.10. Illustration of the 30" wellhead, (Figure 9.10). At this time, the 30" conductor is running tool and permanent guide base landed on cemented in place, usually with at least 100% excess the temporary guide base ®

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cement slurry over the calculated volume of the annulus between the 30" conductor and the 36" hole. The additional cement is expected to fill the sections of oversize hole that usually occur in drilled hole. The complete cementing of the annulus is extremely important as the pile section formed by the 30" conductor and the hardened cement is the foundation building block of the whole well. In instances where the cement job is an obvious failure, a top cement job will be performed. This entails running a cement stinger of pipe into the annulus and pumping in additional cement slurry with the expectation that the 30" conductor will be stabilized. Assuming a good cement job, the 30" housing running tool is released with five turns of right-hand rotation and retrieved with straight upward pull. Figure 9.11. Retrieving the 30" Wellhead Running Tool after the permanent guide base and 30" wellhead have been installed

Jetting the 30" Conductor In To Place Sometimes. the sea floor conditions are very soft and not suitable for drilling because of the risk of caving and collapsed hole. Jetting the 30" conductor into place can be an excellent alternative. The 30" conductor used in jetting operations has an open ended shoe. The drill pipe stinger extending below the 30" housing running tool is equipped with a jetting assembly positioned just inside the 30" shoe.

The assembly of 30" conductor, 30" housing, running tool and permanent guide structure is made up as described in the previous text. This time, however, no temporary guide base is used and the four guidelines attached directly to the top of the four posts on the permanent guide structure. The four flow-by plugs in the running tool are removed as the jetting returns will come out of these ports. The whole assembly is then lowered to the sea floor and the jetting with sea water Figure 9.12. Illustration of the 30" proceeds as the 30" conductor moves down through the sediwellhead, running tool and permanent ments. Jetting will continue until the permanent guide strucguide base jetted into position on the sea ture is a few feet off of the sea floor (Figure 9.12). The running floor 152

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tool is released with 5 turns of right-hand rotation and retrieved with straight upward pull. The four guidelines are tensioned as required. Installing the 30" Conductor with a Mud Mat In recent years, the trend has been towards jetting the 30" into place. This method for installing the conductor does not require the use of a temporary guide base. When sea floor conditions are not consolidated and the method for installing the 30" is through jetting, typically the use of a mud mat is incorporated into the 30" PGB assembly. The mud mat supplies the assembly with a foundation for support. The mud mat is set down in the moonpool area first, then the permanent guide base is set on it. The 30" conductor is made Figure 9.13. Permanent guide base and mud mat in the moonpool up in the same way previously described in the jetting section. The whole assembly is lowered into the sea and jetting operations commence. The jetting operation is finished when the mud mat touches down on the ocean floor and it has been determined that the necessary support has been provided (Figure 9.14). The running tool is released with 5 turns of right-hand rotation and retrieved with straight upward pull. The four guidelines are tensioned as required. Drill 26" Hole Drilling Without Returns The 26" hole for the 20" casing can be drilled without the annulus returns and cuttings coming back to the drilling vessel. This is done by simply guiding the 26" drilling assembly into the open 30" conductor and drilling ahead again using sea water as the drilling fluid. The Figure 9.14. Illustration of the permanent guide base, 30" annulus returns between the drill pipe and Wellhead Running Tool, 30" wellhead, and mud mat jetted into position on the sea floor ®

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SECONDARY UNLATCH 1/4" NPT

LATCH 1/4" NPT UNLATCH 1/4" NPT

Figure 9.16. Illustration of a hydraulic latch with a flange connection up. The flex joint will be attached to the top flange connection

the 30" conductor come out of the 30" housing and spill onto the sea floor. The 26" hole is drilled to depth and a premixed gel of clay and water will probably be spotted in the hole prior to pulling out the 26" drilling assembly. This method of drilling the 26" hole gives absolutely no means of controlling any flow of formation fluids or gases into the hole if the hydrostatic pressure of the sea water column is overcome by unexpected formation pressure. An uncontrolled blowout will then result.

9 MARINE RISER BALL OR FLEX JOINT

HYDRAULIC LATCH PERMANENT GUIDE BASE

Drilling With Returns 30" WELLHEAD HOUSING If returns are required at the drilling vessel, then a riser has to be established from the 30" Figure 9.15. Illustration of the wellhead housing back up to marine riser system used when drilling with returns to surface the drilling vessel. This is achieved by using the marine riser system that is used with the subsea BOP stack (Figure 9.15). (Refer to Marine Riser Systems section of Chapter 2. ) However, the subsea BOP stack and wellhead connector is not used. A hydraulic latch is used at the bottom of the mariner riser. The hydraulic latch (Figure 9.16) locks and seals to the internal profile of the 30" wellhead housing and provides a 261/4" bore. A flex joint or ball joint will be used directly above the hydraulic latch and marine riser joints will complete the riser section up to the telescopic joint at the top. The marine riser system will be tensioned (Refer to Tensioner

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section of Chapter 8) and the drilling assembly for the 20" hole will be run down to the cement inside the 30" conductor.

DIVERTER SYSTEM

The bore of the riser system used will determine if a 26" bit can be used or if a pilot 17-1/2" bit and a 26" under-reamer is required. As 30" marine riser systems are fairly uncommon, it is almost certain that a pilot bit and under-reamer will be used in conjunction with a 21" or similar size riser. As a circulation system has now been established, the 30" shoe and a few feet of new hole will be drilled out with sea water as the drilling fluid. A light water clay gel drilling fluid will then be used to displace the sea water from the hole and drilling will continue until the 20" casing depth is reached. This method of drilling with returns gives a little more protection against formation fluids or gases entering the wellbore as the increased hydrostatic head of a light gel drilling fluid is definitely an advantage over a column of sea water. However, the latch and marine riser system have to be disconnected and retrieved before the 20" casing and 18-3/4" subsea wellhead housing can be run. This means that the hydrostatic pressure in the wellbore will be reduced as sea water takes the place of the drilling fluid column in the marine riser. This can be a moment of truth, but usually the precautions of drilling with returns will have given indications in the cuttings and drilling fluid if problem zones were present. Drilling With Returns And A Flow Diverter The drilling setup here is virtually identical to the one just described except that a flow diverter system is installed on the inner barrel of the telescopic joint. The purpose of the flow diverter is to enable the escaping gas, from a shallow pocket encountered in this section of hole, to blow itself down through large diameter flare lines and outboard of the drilling vessel. Assuming the 26" hole section has been drilled to casing depth, the rig is then set up to run 20" casing.

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TELESCOPIC JOINT

MARINE RISER JOINT

Figure 9.17. Illustration of the riser system, telescopic joint, and Diverter System when drilling the 26" hole with returns to surface

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20" Casing, 18-3/4" Wellhead Housing The 18-3/4" 15,000 psi Subsea Wellhead Housing is a unitized wellhead which provides an interface between the subsea BOP stack and the subsea well (Figure 9.18). The Wellhead itself is a pressure vessel and the male member to a large bore diameter conMETAL RING GASKET SEAL nection (the feAREA male counterpart is the well- WELLHEAD head connector CONNECTOR on the bottom LOCKING PROFILE of the BOP RUNNING TOOL / HANGER stack). The 18- TUBING LOCKING PROFILE 3/4" wellhead will house, and thus support, each additional 7" CASING casing string HANGER POSITION when they are run and 9-5/8" CASING landed. The ID HANGER POSITION of the 18-3/4" wellhead pro- LOCK RING vides a metalto-metal sealing surface for 13-3/8" CASING the seal assem- HANGER POSITION bly when it is PRIMARY LANDING e n e r g i z e d SHOULDER around the casing hanger. 16" WEAR BUSHING The wellhead LOCKING PROFILE provides a primary landing Figure 9.18. Illustration of the shoulder in the 18-3/ 4" high pressure wellhead bottom ID area.

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This landing shoulder is the landing seat for the 13-3/8" (or smaller) casing hanger and casing when it is installed in the wellhead. This landing shoulder interface provides a total of 7 million lbs. end-load support capacity. The multiple load shoulder/load ring interface is necessary to support the combined casing loads (13-3/8" plus 9-5/8" plus 7") and the end load generated when 15,000 psi is applied to a BOP test tool to test the BOP stack. The wellhead will have a 20" casing extension welded to the bottom of it so that the 20" casing can be made up and hung off the bottom of the wellhead.

Figure 9.19. Inspecting the 18-3/4" wellhead housing

On floating drilling vessels, the 20" casing string can be very difficult to make up and run in the hole. This is particularly true if the drilling vessel is moving around in rough weather conditions of high seas and high winds. The stabbing and make up of 40' joints of 20" casing in these conditions can cause cross threading and thread damage. In recent years, the development of coarse threaded connectors, that are welded to line pipe, has provided the industry with connections that make up rapidly, eliminate cross threading and are damage tolerant. (Refer to Chapter 1 "Casing and Casing Connectors Used in Offshore Drilling"). The 20" casing shoe joint is lowered through the rotary table and four soft rope guides are attached in similar fashion to the 30" shoe joint previously described. These guide ropes will ensure that the 20" shoe joint stabs centrally into the 30" housing as the 20" casing is run. When the last joint of 20" casing is landed in the rotary table, a drill pipe cement stinger, if required, can be run down inside the 20" casing. This is usually done through a split support plate sitting on top of the 20" casing using two sets of drill pipe elevators.

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Figure 9.20. Testing the 20" shoe for flow

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DRILL PIPE RUNNING STRING


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18-3/4" WELLHEAD RUNNING TOOL

18-3/4" WELLHEAD

20" CASING (WELLHEAD EXTENSION)

AUTOMATIC WEIGHT SET CONNECTOR

DRILL PIPE CEMENT STINGER

Figure 9.21. Illustration of the 18-3/4" Wellhead Running Tool and 18-3/4" wellhead made up ready to run

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Prior to running the 20" casing, the 18-3/4" wellhead housing running tool (Figure 9.21) and the 18-3/4" subsea wellhead housing will have been assembled. A drill pipe pup joint will have been added to the bottom of the running tool if a cement stinger or a cement plug retainer is to be used on the cement job. The 18-3/4" subsea wellhead housing may have a nominal bore protector installed to protect the internal profile and sealing surfaces during subsequent cementing and drilling operations. However, modern practice is to leave the nominal bore protector out and run it after the BOP stack is tested. The 18-3/4" Running Tool is made up to the 18-3/4" subsea wellhead housing by rotating the tool stem to the left 5 turns. This drives a cam down behind push rods which, in turn, drive a split lock ring outwards into the matching profile in the wellhead housing. Correct make up is verified by checking that the indicator rod has moved down the correct distance. The whole assembly is then picked up in the derrick and made up to the cement stinger drill pipe box sitting on the split support plate. The stinger is then picked up and the split support plate is removed. The 18-3/4" housing joint is then lowered and made up to the threaded box looking up, or on to an automatic stab-in connector pin looking up. A number of operators prefer the automatic connector as it avoids any rota- Figure 9.22. Picking up the 18-3/4" wellhead with tion that might 18-3/4" Wellhead Running Tool be imported into the running tool.

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The 20" casing and 18-3/4" subsea wellhead housing are run down to the 30" housing using a drill pipe running string. During the running of the 20" casing, it will not fill automatically with sea water as the float valve in the shoe or float collar will prevent fluids from entering the casing. This means that every three or four joints, the casing will be filled as it is run. Complete filling of the casing can be achieved by using the air vent valves on the 18-3/4" housing running tool as it is lowered below the water level. When full of sea water, the air vents are closed and the 18-3/4" housing and attached casing are lowered and landed in the 30" wellhead housing. This landing operation is usually done using a heave compensator, (Refer to Heave Compensator section of Chapter 2) which allows the operator to land the 18-3/4" housing “softly” and smoothly. This is particularly useful when the drilling vessel is experiencing a fair amount of heave. If the 18-3/4" housing has seated correctly in the 30" housing, a split lock ring on the 18-3/4" housing will snap into a matching Figure 9.23. Running the 20" groove in the 30" housing. A pickup test of 25,000 lbs will casing, and 18-3/4" wellhead with the confirm that the 18-3/4" housing is locked in place. 18-3/4" Wellhead Running Tool The 20" casing is then cemented, as required. If a cement plug retainer has been used below the 18-3/4" housing running tool, then balls or darts will be dropped through the drill pipe running string to release the cement plug, or plugs, at the appropriate stage of the cement job. The annulus returns displaced from the hole during the cement job will pass through the aligned parts in the 30" housing and permanent guide base on to the sea floor. If excess cement has been planned to ensure a good cement job all the way up the 30" x 20" casing annulus, then the excess cement will also fall on to the sea floor. At the conclusion of the cement job, the 18-3/4" Wellhead Running Tool is released from the 18-3/4" subsea wellhead

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Figure 9.24. Illustration of the 18-3/4" wellhead landed in the 30" wellhead with the 18-3/4" Wellhead Running Tool

housing with five turns of right-hand rotation and retrieved with straight upward pull. 18-3/4" BOP Stack, 21" Marine Riser The next operation is to run the 18-3/4" BOP stack on the 21" marine riser with integral choke and kill lines and lock the wellhead connector on the bottom of the BOP stack to the 183/4" subsea wellhead housing. (This topic is covered in more detail under the Subsea BOP Stacks and Marine Riser Systems

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sections in Chapter 2). The riser will be tensioned, as required, to ensure that no part of the marine riser system is in compression. This is done in order to minimize the po- Figure 9.25. Running the BOP stack on marine riser tential for equipment failure that can occur quite rapidly in components that are in compression and subjected to the constant flexing and motion experienced by marine risers. Choke and kill stabs are made up on the telescopic joint and the BOP stack is prepared for the next phase of the drilling operation. RESILIENT TEST SEAL

18-3/4" BOP Stack Testing The BOP Isolation Test Tool (Figure 9.26) used to test the BOP stack is a plug type test tool that functions by weight-set. The tool provides sufficient flow-by during running and retrieving and incorporates an activator ring that assures the tool does not set prematurely. The illustration shows the tool in a configuration used to test the BOP stack when casing hangers and/or wear bushings are installed in the wellhead. When the wellhead is void of any casing hangers or wear bushings (such is the case at this stage of the operation), then a wellhead

ACTIVATOR RING

WELLHEAD HOUSING ADAPTER

housing adapter is required to make up the landing shoulder of the BOP test tool compatible with the landing shoulder in the bottom of the wellhead. The wellhead housing adapter is slipped onto the test tool and captured with a retainer ring. Figure 9.26. Illustration of the BOP The tool is run on drill pipe and landed in the 18-3/4" wellhead Isolation Test Tool and wellhead housing adapter

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Figure 9.27. BOP Test Tool with wellhead housing adapter ready to run

Figure 9.28. Testing the BOP stack with the BOP Isolation Test Tool

housing (Figure 9.28). The BOP stack is pressure tested through each of the two control pods on the BOP stack. The choke and kill lines and BOP choke and kill valves will also be pressure tested and functionally tested. After successful tests, the test tool is retrieved with straight upward pull. 18-3/4" Nominal Bore Protector The nominal bore protector is a machined steel sleeve, that is installed in the subsea wellhead housing to protect the internal

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profiles and sealing surfaces from damage during drilling operations (Figure 9.29). It is equipped with a running jay slot type profile and an internal lip type retrieving profile. The nominal bore protector has resilient seals on it's outer profile that act as trash seals, preventing debris from getting behind the nominal bore protector. The Multi-Purpose Tool is used to run and retrieve the nominal bore protector and the wear bushings. This is done through the use of adapters (Figure 9.30). There are four adapters - a running and a retrieving adapter for the nominal bore protector and a running and a retrieving adapter for all of the wear bushings. The seal assembly is also retrieved with the wear bushing retrieving adapter. The wear bushing adapters will be discussed later in this chapter. Prior to running the nominal bore protector, the Multi-Purpose Tool is equipped with the Nominal Bore Protector Running Adapter. The MultiPurpose Tool is lowered into the nominal bore protector and rotated to the left so that

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MULTI-PURPOSE TOOL

NOMINAL BORE PROTECTOR RUNNING ADAPTER

NOMINAL BORE PROTECTOR

NOMINAL BORE PROTECTOR RUNNING ADAPTER

Figure 9.30. Multi-Purpose Tool with the nominal bore protector running adapter highlighted for use

Figure 9.29. Illustration of the nominal bore protector made up to the Multi-Purpose Tool

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Figure 9.31. Illustration of the Multi-Purpose Tool installing the nominal bore protector in the wellhead

the four jay lugs engage the jay slots in the ID of the bore protector. The Multi-Purpose Tool and nominal bore protector assembly is lowered on drill pipe, inside marine riser and the BOP stack, taking care not to rotate the running string during the operation. The nominal bore protector is set on its landing seat in the subsea wellhead housing. With 5000 lbs. weight acting on the Multi-Purpose Tool, it is turned 1/4 turn to the right to unjay it from the nominal bore protector and retrieved with straight upward pull. A 17-1/2" 164

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JET SUB EXTENSION

LATCH RETRIEVAL RING

Figure 9.33. Illustration of the Multi-Purpose Tool landed in the nominal bore protector for retrieval and washing out the multiple load shoulder profile in the bottom of the wellhead in preparation for running the 13-3/8" casinghanger NOMINAL BORE PROTECTOR RETRIEVING ADAPTER

hole is then drilled to the 13-3/8" casing depth, the hole is circulated and the drilling fluid is conditioned prior to running the 13-3/8" casing. Before running the 13-3/8" casing, the nominal bore protector has to be removed from the 18-3/4" subsea wellhead housing. The Multi-Purpose Tool is used for this operation and is set up

JET SUB

with a jet sub (Figure 9.32) and extension made up to the

Figure 9.32. Multi-Purpose Tool with its nominal bore protector retrieving adapter, jet sub, and jet sub extension highlighted for use

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bottom of the tool. Also installed to the Multi-Purpose Tool is the Nominal Bore Protector Retrieving Adapter and latch ring. The Multi-Purpose Tool is then run on drill pipe down to the nominal bore protector, cleaning the last 5 to 10 feet by circulating through the jet sub extension and jet sub. When the Multi-Purpose Tool lands on the nominal bore protector, the latch retrieval ring engages a matching groove inside the top of the bore protector. The bore protector can be recovered with straight upward pull. It is good practice, at this point, to circulate through the jet sub extension and jet sub so that the jetting action cleans the 13-3/8" casing hanger load profile at the bottom of the 18-3/4" wellhead housing. Features of Subsea Casing Hanger System The operational features offered in a modern subsea casing hanger system have given the drilling operator a number of important selections that require decisions before running the casing hanger. An evolution of these features are discussed in the following text.

Figure 9.34. Multi-Purpose Tool and nominal bore protector retrieved to the rig floor

Casing Hanger, Seal Assembly Running Tool The Casing Hanger, Seal Assembly Running Tool has experienced a number of evolutionary advancements. Early seal assemblies were installed in the wellhead with rotational torque and each casing hanger size required its own dedicated running tool. Furthermore, the running tool ran the casing hanger only and the seal assembly was run in a separate trip. Testing the seal assembly occurred with a tool run in a third trip and if the seal assembly did not test, the test tool had to be recovered and the seal assembly retrieved in yet another trip. The early systems required a family of casing hanger running tools and multiple trips to install a tested casing hanger and seal assembly. Clearly there was room for improvement. First, the casing hanger running tool was modified to carry the seal assembly along with the hanger when casing was run.

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This allowed the operator to install the hanger and set the seal assembly in the same trip - eliminating one trip. Subsequent modifications gave the running tool the capability of testing the seal assembly after it was energized. Finally, all size casing hangers were modified to accommodate one casing hanger running tool - eliminating the requirement for obtaining a running tool for each size hanger. These improvements allowed floating drilling and exploration to move into new frontiers. As deeper and deeper water depths became common, the need for two additional improvements became obvious. First, the seal assembly was now further away from the rig and the process of applying rotational torque to set and install the seal assembly was inefficient. Second, if the seal assembly did not test successfully after installation, the additional trip required to retrieve it consumed time and represented costs that could be eliminated. "Weight-Set" systems were introduced as an alternative to torque-set systems. The concept is to take advantage of the force from weight and pressure to energize the seal assembly. Rotation will be required to simply unlock the tool from the casing hanger. This will greatly simplify the installation of a seal assembly in deep water without applying massive amounts of torque at the surface.

LOCK SLEEVE ACTIVATOR RELEASE SEGMENTS SEAL ASSEMBLY RECOVERY SHEAR PINS CAM ACTUATED LOCK RING

SEALS FOR TESTING THE SEAL ASSEMBLY AND THE BOP STACK

The system used in this discussion is a weight set system. The Casing Hanger Seal Assembly Running Tool is a weight-set tool which carries the casing hanger and seal assembly to the wellhead when the casing is run. Running threads (commonly Figure 9.35. Illustration of the used in previous systems) have been eliminated to reduce the Casing Hanger Seal Assembly Running Tool possibility that the operator will encounter high torque when rotating the drill pipe to release the tool from the casing hanger. This tool has the capability to test the seal assembly

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and the BOP stack after the seal assembly is energized and locked down. Additionally, if the seal assembly pressure test fails, the running tool used in this discussion has the ability to bring the seal assembly to the surface when the running tool is retrieved - eliminating an additional trip to recover the seal assembly. 18-3/4" Seal LOCKING SLEEVE Assembly CASING The 18-3/4" Seal HANGER Assembly incorLOCK DOWN RING porates a metal(OPTIONAL) to-metal sealing system that is LOCKING RING weight-set (Fig- METAL-TOure 9.36). Once METAL SEALING the Seal Assem- SYSTEM bly is energized (after the casing Figure 9.36. Illustration of the Seal Assembly is cemented), test pressure functions an actuator sleeve on the running tool which locks the seal assembly to the hanger. An optional lock ring on the OD of the seal assembly will lock the seal to the wellhead, if desired. The choice to lock the casing hanger to the wellhead can be made at the very last moment before the casing is run. The external lock ring can be removed if casing hanger lockdown is not required. Usually, the reason that casing hangers are locked down is because they are being used in a development well where the heat from the producing fluids or gases may cause the casing to expand, overcoming the residual tension and move the casing hanger and seal off its seat. This move ment can potentially cause seal failure with the unwelcome prospect of oil and gas getting into unwanted places. On exploration wells the casing hangers are generally not locked

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down, which can make recovery of the subsea hangers a little bit easier during plug and abandonment operations.

SEAL ASSEMBLY LOCKING GROOVE

LANDING SEAT FOR THE NEXT CASING HANGER

SEAL ASSEMBLY SEALING AREA

13-3/8" Casing, 18-3/4" x 13-3/8" Casing Hanger RUNNING The 13-3/8" casing hanger has a 4 degree taper on the TOOL LOCKING OD of the top of the hanger. This is the metal-to-metal GROOVE sealing area of the hanger which is used by the seal FLOW-BY assembly to seal against. The top of the 13-3/8" casing hanger is configured to provide a landing shoulder LANDING SHOULDER for the next casing hanger. Inside the top of the 13-3/ 8" casing hanger, a threaded profile is provided for CASING THREADS tieback purposes. This tieback profile allows the operator to tie the hanger back to the surface for surface completion. A two grooved locking profile Figure 9.37. Illustration of the 13-3/8" casing hanger for the cam actuated lock ring on the Casing Hanger Seal Assembly Running Tool is located below the tieback threads. The 13-3/8" casing hanger incorporates a landing shoulder found on the bottom OD section. This landing shoulder lands on the landing shoulder in the bottom of the wellhead when the hanger lands on its seat. These landing shoulders supply the support necessary to accommodate the combined casing loads of 13-3/8", 9-5/8" and 7" plus the end load generated from 15,000 psi BOP stack test against a BOP test tool. The ability of the wellhead to support the combined loads of the casing weight and the end load from a 15,000 psi BOP test are what makes this a 15,000 psi wellhead system. In most cases, the casing hanger will be run on drill pipe, the single trip method will be used and the hanger will not be locked down. There are cases where the casing hanger will be run on casing (as opposed to drill pipe) and this situation will be covered in optional equipment under full bore running tools found later in this chapter. Before the 13-3/8" casing is run, the 18-3/4" casing hanger

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running tool is made up to the 18-3/4" seal assembly and the 18-3/4" x 13-3/8" casing hanger (Figure 9.38).

CASING HANGER SEAL ASSEMBLY RUNNING TOOL

SEAL ASSEMBLY

CASING HANGER

Figure 9.38. Casing Hanger Seal Assembly Running Tool, seal assembly and 13-3/8" casing hanger made up and ready to run

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First, the casing hanger running tool is prepared with 8 new spring-loaded shear pins. The seal assembly, without the outer lock ring, is installed over the 8 shear pins and retained. If a cement plug retainer is required, it is installed on the bottom threaded connection of the running tool. The first joint of pipe above the running tool will have a specified OD as it will subsequently have rams closed on it during the pressure testing of the seal assembly and BOP stack. The running tool and seal assembly is then set into the 183/4" x 13-3/8" casing hanger which is normally set in the rotary table for this operation. The stem of the running tool is then rotated 3 turns to the left and lifted out of the casing hanger. The seal assembly is installed on the eight spring load shear pins and the wiper plugs are installed on the plug retainer. The tool is then carefully stabbed back into the hanger. Three to four more right-hand turns are made until torque builds up and the running tool is fully made up. Figure 9.39. Casing Hanger Seal Assembly Running Tool, seal The running tool stem is then assembly and 13-3/8" casing hanger rotated to the right 1/8 turn so being made up that the cam-actuated drive mechanism in the running tool is not in an initial bind later when the running tool has to be released from the hanger. The whole assembly of running tool with special BOP test joint, seal assembly, casing hanger and cement plug retainer is stood

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Figure 9.42. Sequence showing Hanger and Seal Assembly Running Tool, Hanger Landed (TP Drawing 31500-06) ®

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Hanger and Seal Assembly Running Tool, Hanger Landed TP 31500-06

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Figure 9.42. Sequence showing Hanger and Seal Assembly Running Tool, Seal Assembly Landed on Hanger (TP Drawing 31500-07) ®

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Hanger and Seal Assembly Running Tool, Seal Assembly Landed on Hanger TP 31500-07

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Figure 9.42. Sequence showing Hanger and Seal Assembly Running Tool, Seal Assembly Tested and Locked Down (TP Drawing 31500-08) ®

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Hanger and Seal Assembly Running Tool, Seal Assembly Tested and Locked Down TP 31500-08

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back in the derrick. Protective covering is often placed on the metal-to-metal sealing surfaces to help ensure these critical seal surfaces will not be damaged during handling. The 13-3/8" casing string is then assembled and run into the hole. The threaded couplings used on this casing string will normally be an API mill buttress thread unless unusual downhole conditions are anticipated or the casing string is very long. Depending on the downhole conditions, other thread forms will be selected based on their resistance to high bending loads seen in deviated wells, their gas sealing properties and their load carrying capacity. The use of spring cage type centralizers is not recommended on casing strings run in subsea wells. Obviously, the intention of centralizers is to center the casing in the hole to help the cement to form a uniform sheath around the casing, but this perceived advantage is far out-weighed by the potential damage that a loose leaf spring can cause in a subsea wellhead. With the last joint of 13-3/8" casing supported in the casing slips at the rotary table, the running tool assembly is picked up and the casing hanger is made up to the 13-3/8" casing. The makeup of the threaded connection is done very carefully to avoid any rotation of the running tool relative to the casing hanger body. Any protective covering that had been placed on Figure 9.40. Casing Hanger Seal Assembly Running Tool, seal the metal-to-metal sealing surfaces are removed. The whole casing string is now picked up, the casing slips are removed and the casing string and hanger are run on drill pipe down to the subsea wellhead housing. As the seal assembly requires a minimum of 15,000 lbs. weight to set the seal, the running string may include drill collars to set the seal. The last few feet of travel down to the seat in the wellhead housing are made a lot easier with the motion compensator set to provide a “safe” landing. Once the casing hanger has landed, it can be said that it is in the correct seating position. The casing is then cemented according to the well program. During the opera ®

assembly and 13-3/8" casing hanger being lowered through the rotary table

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tion, the casing must not be picked up or rotated. Using the motion compensator, leave 15,000 lb. of the running string weight acting down on the running tool. Rotate the drill string 5 or 6 turns to the right which releases the running tool from the casing hanger body and the running tool will drop 10 inches at which point the seal assembly has landed over the outside of the casing hanger body. The full weight of the running string is then set down on the

Figure 9.43. Illustration of the Casing Hanger Seal Assembly Running Tool after the seal has been tested and locked, testing the BOP stack

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seal assembly which energizes the resilient seals on the seal assembly and pushes the metal seals into position. The BOP stack drill pipe rams are then closed on the special drill pipe stem above the running tool. Pressure is then applied below the closed ram building up quickly to 2,500 psi. If this pressure holds satisfactorily for 30 seconds, then the pressure is increased to 3,500 psi minimum. This pressure provides the required downward force to establish a metal-to-metal seal and lock the seal assembly to the casing hanger. At this time, other BOP stack functions can be operated and pressure tested. After successful conclusion of the pressure tests, the pipe ram is opened and the casing hanger running tool is retrieved with straight upward pull. Approximately 60,000 lb. overpull is required to shear the 8 spring loaded shear pins that hold the seal assembly to the casing hanger running tool.

18-3/4" x 13-3/8" Wear Bushing The 18-3/4" x 13-3/8" wear bushing is a rugged steel sleeve that lands into the 13-3/8" casing hanger body. It provides protection for the internal profiles and sealing surfaces of the subsea wellhead housing and the casing hanger from damage during drilling operations. It is run into the well on the MultiPurpose Tool with the Wear Bushing Running Adapter installed. Prior to running the 13-3/8" wear bushing, the Wear Bushing Running Adapter is installed on the Multi-Purpose Tool. Four spring loaded shear pins are the locking mechanism used to attach the Multi-Purpose Tool to the wear bushings. The Multi-Purpose Tool and wear bushing running adapter is installed into the top of the wear bushing (Figure 9.44), and its own weight depresses the spring loaded shear pins until they snap into the mating groove in the wear bushing. The assembly is then run on drill pipe and the 18-3/4" x 13-3/8" wear bushing is landed on the 18-3/4" x 13-3/8" casing hanger. The

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WEAR BUSHING RUNNING ADAPTER

Figure 9.44. Illustration of the Multi-Purpose Tool and the wear bushing running adapter highlighted for use

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MULTI-PURPOSE TOOL

WEAR BUSHING RUNNING ADAPTER

13-3/8" WEAR BUSHING

Figure 9.46. Illustration of the Multi-Purpose Tool installing the 13-3/8" wear bushing in the wellhead 8 spring loaded shear pins on the bottom of the wear bushing automatically lock into the matching groove in the seal assembly body. The Multi-Purpose Tool is released from the wear bushing with approximately 30,000 lbs upward pull which shears the four shear pins on the tool, and it can be pulled straight out of the hole.

Figure 9.45. Illustration of the Multi-Purpose Tool made up to the 13-3/8" wear bushing and ready to run

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The rig is then set up to drill 12-1/4" hole to the 9-5/8" casing depth. If BOP stack pressure tests are required during this section of hole, these can be done with the 18-3/4" x 13-3/8"

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wear bushing in place using the 18-3/4" BOP Isolation Test Tool. After the 12-1/4" hole is drilled, the 18-3/4" x 13-3/8" wear bushing is retrieved prior to running the 9-5/8" casing. The Multi-Purpose Tool equipped with latch ring, wear bushing, retrieving adapter and jet sub is run on drill pipe. Prior to entering the wellhead, mud pumps are started and fluid is pumped through the drill string to wash out any debris that may have accumulated while drilling the 12-1/4" hole. As the Multi-Purpose Tool is lowered into the wear bushing, the fluid being pumped will clean the retrieving profile in the top of the wear bushing. When the Multi-Purpose Tool lands in the 133/8" wear bushing, the latch ring snaps into the matching groove in the top of the wear bushing. An overpull of 60,000 lbs. shears the 8 spring loaded shear pins at the bottom of the wear bushing. This releases the wear bushing from the casing hanger and it can be recovered to the surface with straight upward pull. The jet LATCH RETRIEVAL sub can be used in this operaRING tion to clean the retrieving profile on the wear bushing WEAR if thick clays or gumbo from BUSHING RETRIEVING the drilling operation are susADAPTER pected of interfering with retrieval. 9-5/8" Casing, 18-3/4" x 9-5/ 8" Casing Hanger The 9-5/8" casing hanger is similar to the 13-3/8" casing hanger, with the exception of the smaller bore with a 95/8" casing thread (Figure 9.49). The 9-5/8" casing hanger is equipped with a

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JET SUB

Figure 9.47. Illustration of the Multi-Purpose Tool with the wear bushing retrieving adapter and jet sub highlighted for use

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Figure 9.48. Illustration of the Multi-Purpose Tool and jet sub landed in the 13-3/8" wear bushing for retrieval

landing seat which mates with the top of the 13-3/8" casing hanger. The 9-5/8" casing hanger is run in the same manner as the 13-3/8" casing hanger - with the casing hanger, seal assembly running tool and 18-3/4" seal assembly. Operational procedures; five to six right-hand rotations of the drill pipe and running tool, a 10" drop in the drill pipe and initial setting pressure of 2,500 psi are the same as described with the 13-3/8" casing hanger and seal assembly. Subsequent BOP stack pressure tests are then performed. The 9-5/8" (Figure 9.51) wear bushing is similar to the 13-3/8" wear bushing. It has the same running and retrieving profile 182

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in the top to accommodate the Multi-Purpose Tool running and retrieving adapters. The only difference is that it is shorter because it now has to protect a shorter length of housing and has a reduced bore compatible with the hanger bore. Assuming that the 9-5/8" casing hanger, seal assembly and wear bushing are all correctly installed, the next step is to then drill 8-1/2" hole, or larger, for the 7" casing. The 18-3/4" x 9-5/8" wear bushing is retrieved with the 18-3/4" Multi-Purpose Tool prior to running the 7" casing.


SEAL ASSEMBLY SEALING AREA

RUNNING TOOL LOCKING GROOVE

FLOW-BY

LANDING SHOULDER

Figure 9.49. 9-5/8" Casing Hanger

18-3/4" x 7" Casing Hanger and 18-3/4" x 7" Wear Bushing The previous paragraphs also apply to the 7" casing hanger (Figure 9.52). The landing shoulder referenced supports the 7" wear bushing and is a possible landing shoulder for a subsea tubing hanger in the event this well is completed subsea. The previous paragraphs discussing wear bushings also apply to the 18-3/4" x 7" wear bushing (Figure 9.53). The 7" casing hanger and wear bushing are run in an identical manner as the previous casing hangers and wear bushings. Assuming that this equipment has all been correctly installed the next step is to then drill a 6" hole to total depth, discovering Figure 9.50. Illustration of the Casing Hanger Seal Assembly two or three highly permeable Running Tool installing the 9-5/8" casing hanger ®

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LATCH RETRIEVAL RING PROFILE SHEAR PIN RUNNING PROFILE

LOCKING SHEAR PINS

Figure 9.51. Illustration of the 9-5/ 8" wear bushing

LATCH RETRIEVAL RING PROFILE SHEAR PIN RUNNING PROFILE LOCKING SHEAR PINS

Figure 9.53. Illustration of the 7" wear Bushing

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pay zones that exhibit no pressure drawdown on extended drill stem tests.


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Testing the BOP Stack The Casing Hanger Seal As- SEAL ASSEMBLY sembly Running Tool has the SEALING AREA capability to test the BOP stack RUNNING when the casing hanger and TOOL LOCKING seal are run. There is, how- GROOVE ever, a need to test the BOP LANDING stack at intervals when the rig RING is drilling each hole. There are two additional methods for Figure 9.52. Illustration of the 7" testing the BOP stack in these casing hanger situations. As previously described in this chapter, the BOP Isolation Test Tool is used to test the BOP stack after it is initially run using the wellhead housing adapter. Once casing hangers have been installed in the wellhead, the wellhead housing adapter is taken off of the BOP Isolation Test Tool to configure the test tool so it can land in either the wear bushings or casing hangers. This test tool will seal in the wellhead bore above the previously installed seal assembly and isolate the seal assembly from any test pressure. A second method for testing the BOP stack is with the MultiPurpose Tool and its cup tester accessories. Each cup tester accessory is sized to fit each casing hanger. This allows the operator to run or retrieve a wear bushing and test the BOP stack in the same trip. An important feature for deepwater drilling operations in that costly trip time is eliminated. Additionally, each test cup will sit in the throat of its corresponding casing hanger as opposed to the casing to allow the operator to perform a pressure test to the full BOP stack rating without being limited by the casing pressure rating. When the

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TEST SEAL ACTIVATOR RING

Figure 9.54. Illustration of the BOP Isolation Test Tool configured to test the BOP stack when casing hangers and wear bushings have been installed in the wellhead

Figure 9.55. Illustration of the BOP Isolation Test Tool landed in the 7" wear bushing for testing the BOP stack

Multi-Purpose tool and cup tester is used to test the BOP stack, the seal assembly is also pressure tested. Mill and Flush Tools Casing hanger seals in any wellhead system, land or offshore, are of critical importance for the safety of the well if abnormal pressure conditions are encountered. These seals prevent high pressure fluid or gas that may be in the well bore from entering the casing annulus below the casing hanger with the

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7" CUP

9-5/8" CUP 13-3/8" CUP

Figure 9.56. Illustration of the Multi-Purpose Tool and cup tester accessories

Figure 9.57. Illustration of the Multi-Purpose Tool and 9-5/8" cup tester landed on top of the 9-5/8" wear bushing

Figure 9.58 Illustration of the Multi-Purpose Tool and 9-5/8" cup tester accessories

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potential to rupture the outer casing string and cause sever damage to the well. Therefore, great care is taken to ensure that the seal areas where the casing hanger seal is set are free from any debris that could cause a malfunction. However, the best laid plans do not always succeed, and such is the case with downhole casing hanger seals. The debris can take a number of forms from very hard, tough pieces of formation to manmade items such as pieces of metal from drilling tools and accessories. If debris is carried into position with the casing hanger and ®


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seal assembly, it may prevent the seal from being driven down to its correct sealing position, in which case a poor pressure test may result. As previously indicated, a feature of the Casing Hanger Seal Assembly Running Tool is that it will automatically retrieve the seal assembly in these situations. There it will be inspected very closely in order to determine the cause of the problem. If interference from debris is suspected, then mill and flush tools are used to clean out the seal area between the casing hanger body and the wellhead housing. The Multi-Purpose Tool, jet sub and mill and flush adapter

MULTI-PURPOSE TOOL

WEAR BUSHING RETRIEVING ADAPTER MILL AND FLUSH ADAPTER

JET SUB

Figure 9.59. Illustration of the Multi-Purpose Tool, jet sub and mill and flush adapter

Figure 9.60. Illustration of the Multi-Purpose Tool, jet sub and mill and flush adapter cleaning out the annulus area

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(Figure 9.59) assembly is run down to the casing hanger on drill pipe. The jetting action is directed down inside the mill and flush adapter and up the outside. The assembly is slowly rotated as jetting continues, and the assembly is slowly lowered until the mill reaches the end of its travel over the body of the casing hanger. This operation is conducted with as much care as possible as the mill teeth will break up any debris present into small pieces that may get washed into the annular space between the mill body and the wellhead housing. If the pieces are hard metal, they can score the seal surface on the inside of the wellhead housing which can cause further sealing problems. When the mill and flush adapter is retrieved, a visual inspection of the nylon indicator pins will indicate if the mill reached the end of its specified travel. If not, a decision will need to be made whether to rerun the mill and flush adapter or run an emergency seal assembly (the emergency seal assembly will be discussed later in this section). Mill and flush tools are also available for use with the standard jet sub to clean out the seal area between a 16" supplemental casing hanger and the 20" adapter mentioned earlier. 18-3/4" Seal Assembly Running Tool If all goes well during the milling operation, another standard 18-3/4" seal assembly can be run on the 18-3/4" Seal Assembly Running Tool. The Seal Assembly Running Tool runs and installs the seal assembly in a similar fashion as the Casing Hanger Seal Assembly Running Tool (Figure 9.61). The only difference is the Seal Assembly Running Tool does not carry casing and therefore does not require any rotation to function a locking ring. The seal assembly is carried to the casing hanger on spring loaded shear pins and locked down by a lock sleeve activator in the same manner the Casing Hanger Seal

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Assembly Running Tool does. The seal assembly is installed on the spring loaded shear pins of the Seal Assembly Running Tool and run to the casing hanger. Once it has been determined that the seal has landed on the hanger, a minimum 15,000 lbs. is applied to the running tool. Pipe rams are closed and 2,500 psi is pumped down a choke or kill line to energize the seal assembly and cause the running tool to lock the seal assembly to the casing hanger (Figure 9.62 and Figure 9.63). The Emergency Seal Assembly The emergency seal assembly is a weight set design and is also run using the 18-3/4" Seal Assembly Running Tool. Its design is such that it will seal in a slightly higher position in the wellhead. This requires a larger sealing system since more annular space will be spanned by the seal. The emergency sealing system is elastomer; a logical approach since the emergency seal is used only when the standard seal is unable to set and test, it is assumed that a scratch in the wellhead or casing hanger is preventing a metal-to-metal seal. The

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CENTRALIZING SLEEVE

LOCK SLEEVE ACTIVATOR

SEAL ASSEMBLY RECOVERY SHEAR PINS

SEAL ASSEMBLY TEST SEALS

Figure 9.61. Illustraion of the Seal Assembly Running Tool

Figure 9.62. Seal assembly landed but not tested

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Figure 9.63. Seal assembly tested and locked down

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emergency seal does not change the stack up dimensions and is not retrieved prior to running the next casing hanger. Emergency Drill Pipe Hangoff Tool Weather conditions are an important factor in the successful operation of a floating drilling vessel. Storm conditions can cause temporary suspension of drilling operations and in sever conditions, warrant the drillLOCKING ing vessel actually disRING connect from the wellhead. RESILIENT SEALING SYSTEM

When a disconnect is imminent, the rig must stop drilling operations and Figure 9.65. Illustration of the emergency trip drill pipe out of the seal assembly ole to raise the drill bit into the last casing string installed. If time is a factor, the emergency drill pipe hangoff tool is then made up to the drilling string and lowered to the wellhead to hangoff the drilling assembly in the well. Pipe rams in the main BOP are closed around the emergency drill pipe hangoff tool and the drill pipe above the tool is then rotated to disconnect this upper section of drill pipe from the drilling string that has been hungoff in the wellhead. The rig can then disconnect the lower marine riser package (refer to Chapter 2) from the main BOP leaving the well secure. After the storm conditions have passed, the lower marine riser package is reconnected to the main BOP, the emergency drill pipe hangoff tool is reconnected and the drilling vessel can return to drilling operations. Abandonment If the well is a “duster”, or even if it had some promising

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“shows” but is considered expendable, then the well will be permanently abandoned. Bridge plugs and cement bridges will be set in the open hole section and inside the casing to prevent any future migration of wellbore fluids from one zone to another or up the wellbore itself. Any uncemented casing below the casing hangers will be cut and recovered along with the associated subsea casing hanger. The 18-3/4" subsea wellhead and 30" conductor housing and the four post permanent guide base will be recovered for reconditioning and reuse. Sometimes the equipment is recovered in too poor a condition to be repaired and is declared scrap. The sea bed is therefore left clear of debris, a requirement that is being imposed in many offshore drilling areas. If the well is a “keeper”, then the well is temporarily abandoned so that it may be completed at a later date with a subsea production tree or become one well of a subsea template development that is eventually tied back to a platform installed over the subsea wells. In this case, temporary bridge plugs and/or cement bridges will be set in the well to prevent fluid or gas migration and a sealing corrosion cap may be installed on the 18-3/4" subsea wellhead housing. Usually, a passive fluid with corrosion inhibitor is spotted in the subsea wellhead when the corrosion cap is installed. The floating drilling vessel will then recover anchors and move off to another location. A marker buoy or pinger will be left to mark the well site and if they disappear or fail, the measurements of latitude and longitude are used to relocate the well.

DUAL CAM ACTUATOR SUB

TEST SUB BOWL

BLIND RAMS TEST DART

Optional Subsea Wellhead Equipment Figure 9.66. Illustration of the drill

Full Bore Cementing and Full Bore Running Tools pipe release and test sub used for The majority of subsea casing hangers are run on drill pipe emergency drill pipe hangoff running tools because the running operation is speeded up and the shouldered drill pipe tool joints give very positive control of turns and torque transmitted to the running tool.

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Figure 9.67. Illustration of a Temporary Abandonment Cap installed on the wellhead

The main drawback to drill pipe as a running string is that stage cementing jobs are a little more difficult to perform than a full bore cement job from the surface. Also, on some occasions when very long strings of 13-3/8" or 9-5/8" casing are run below a subsea casing hanger, the drill pipe joint strength becomes a limiting factor. A full bore cement job does, however, require the seal assembly be run in a second trip after the casing hanger and casing has been run and cemented in place. Figure 9.68. Getting ready to run a 13-3/8" casing hanger with the full bore running tool

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The two-trip approach does offer the operator the opportunity to clean out the sealing area between casing hanger body and

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wellhead housing before running the seal assembly. Also, the circulation path for annulus returns is less obstructed which could help the cement job. The main culprit in seal assembly failures is nearly always trapped debris in the seal area that either gouges the sealing surfaces or prevents the seal assembly from getting down to its correct position. Some recovered subsea wellhead housings and casing hangers have shown that various items, such as tong dies, detached centralizer springs, a small lever from power tongs and even a drill pipe wiper have finished up in critical sealing areas or ex-centralized the casing hanger.

CASING THREADS

RUNNING THREADS

SEAL

The 13-3/8" full bore casing hanger running tool is a threaded RINGS tool which makes up into the threaded profile located in the Figure 9.69. Illustration of the top of the 13-3/8" hanger (Figure 9.69). The 9-5/8" (Figure 13-3/8" full bore casing hanger 9.70) and 7" full bore running tools are cam actuated tools. As running tool already noted, cam actuated running tools are more desirable then threaded tools to minimize the potential for high torque when the tool is being rotated for release. The reason the 133/8" casing hanger full bore running tool is threaded is because of the restricted area available between the bore CASING and the ID of the casing hanger in the locking profile area. THREADS Supplemental Casing Hanger Systems The most common casing program used in offshore exploration drilling is 30" x 20" x 13-3/8" x 9-5/8" x 7" and the subsea ACTIVATING SLEEVE wellhead system most commonly used has a 30" housing with the 30" conductor attached and a three hanger 18-3/4" high pressure housing with the 20" casing attached. However, LOCK RING there are offshore drilling locations where an additional cas- SEAL ing string is required to shut off a known problem formation RINGS or is included as an insurance string in anticipation of drilling Figure 9.70. Illustration of the problems. 9-5/8" cam actuated full bore casing hanger running tool

One way to handle the extra casing string is to use a four hanger 18-3/4" housing with the 20" casing attached. This approach has been used quite often, but the extra long housing

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does not come cheaply and operators now have to carry 3 and 4 hanger housings in their inventory. A convenient solution to this optional hanger position is to hang the 16" casing inside the 20" casing much like a liner (Figure 9.71). This approach requires the use of a special forged adapter strategically placed in the 20" casing string to optimize coverage of a known problem formation and minimize 16" casing costs. The 20" adapter is welded into a joint of 20" casing and reserved as a special joint. This 20" joint is placed in the 20" casing string when casing is run allowing final adjustments of final placement to occur at the last minute. Figure 9.72 illustrates the 20" adapter which has a positive casing hanger landing shoulder and a prepared internal seal surface for the casing hanger seal assembly. Figure 9.73 illustrates the 16" casing hanger which is run on a 16" Casing Hanger Seal Assembly Running Figure 9.71. Illustration of the 16" Tool similar to the 18-3/ supplemental casing hanger system and 4" Casing Hanger Seal Asits placement in the 20" casing string sembly Running Tool. SEALING The 16" supplemental AREA FOR 16" SEAL casing hanger system can be ASSEMBLY used as a single trip system, where the 16" casing hanger and attached 16" seal assem- LOAD RING PROFILE bly (Figure 9.74) are run with the 16" Casing Hanger Seal LANDING SHOULDER Assembly Running Tool. As was the case with the 18-3/ 4" seal assembly, the 16" seal assembly is weight-set and pressure lock. The 16" Casing Hanger Seal Assembly Run 194

FOR 16" CASING HANGER

Figure 9.72. Illustration of the 20" adapter for the 16" supplemental casing hanger

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ning Tool can also test the seal and retrieve it if it does LOCKING SLEEVE not test. A 10" drop indicates the seal assembly has LOCKING RING been delivered to the casRESILIENT ing hanger and an initial SEAL pressure test of 2,000 psi, then raised to 80% of casFigure 9.74. Illustration of the ing yield sets and locks 16" seal assembly the seal to the hanger. A 60,000 lb. overpull indicates that the seal is locked in place.

SEALING AREA LOCK DOWN GROOVE SEALING AREA RUNNING TOOL LOCKING PROFILE

LOAD RING ACTUATING SLEEVE

After successful tests, the running tool is retrieved and a special 18-3/4" x 16" wear bushing is run and landed in the 183/4" wellhead housing. This wear bushing absorbs the main Figure 9.73. Illustration of the 16" positive stop supplemental casing wear and tear generated by the drilling operations for the next hanger casing string. The 16" wear bushing is also designed to withstand any downward test loads induced when the 18-3/ 4" BOP Isolation Test Tool is landed on top of the wear bushing. Deepwater Drilling Considerations Deepwater drilling experience has identified a phenomenon of shallow water flow from sands buried at relatively shallow depths below the mudline. The concern is that during spudin procedures and drilling out for surface pipe (typically done without riser), this shallow water zone will be encountered. The water flow can range from a temporary zone pressuring and discharging to a serious flow from a geologically overpressured zone which will flow around the conductor and/or surface pipe resulting in a loss of the well or related seafloor equipment such as a template. Many solutions to the problem have been explored and im- Figure 9.76. Making up the 16" pacted technology from cement slurries to wellhead equip- Casing Hanger Seal Assembly Running Tool, seal assembly and 16" ment. Following is a discussion of the various solutions, Casing Hanger

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18-3/4" RIGID LOCKDOWN WELLHEAD

30" RIGID LOCKDOWN WELLHEAD 18-3/4" SEAL ASSEMBLY


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ANNULUS PACK OFF

Actuated when the 18-3/4" wellhead is preloaded into the conductor wellhead, the annulus shutoff system seals off the annulus between the 20" casing and the primary conductor string(s).

MUD MAT

16" SEAL ASSEMBLY 16" POSITIVE STOP SUPPLEMENTAL CASING HANGER

20" SUPPLEMENTAL ADAPTER 26" STAB HANGER 26" SUPPLEMENTAL ADAPTER

16" SUPPLEMENTAL CASING HANGER SYSTEM The field proven 16" supplemental casing hanger is run hung off and sealed in the 20" adapter above the 20" stab sub. It is rated to 5,000 psi and one million pound tensile capacity combined loading. SECONDARY CONDUCTOR STRING The secondary conductor string is hung off in the primary conductor and supplies foundation strength and rigidity to the primary conductor in unstable pressurized sands. The secondary conductor string is set above the hazard and can carry a landing adapter for the 20: riserless supplemental casing hanger system.

20" STAB SUB 20" SEAL ASSEMBLY 20" RISERLESS SUPPLEMENTAL CASING HANGER 16" CASING 36" CASING 26" CASING 20" CASING

20" RISERLESS SUPPLEMENTAL CASING HANGER SYSTEM The 20" riserless supplemental casing hanger incorporates a separate testable, replaceable packoff that is set in the 20: X 26" annulus. DRIL-QUIP's riserless supplemental casing hanger system is designed to be installed in open water on drill pipe. Expensive large bore diameter riser and a subsea diverter for testing is not required.

Figure 9.76. Illustration of the Wellhead System with options for controlling pressureized sands

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partial and/or otherwise, with respect to the wellhead equipment. Annulus Packoffs Methods to address the shallow water flow problem initially started with a need to supply a secondary mechanically actuated seal between the conductor (30") and surface (20") strings. This seal is carried on the 18-3/4" high pressure housing and is actuated after the cementing operation with a tool which drives "locking tabs" down which, in turn, drive a ring with resilient seals into the annulur area between the conductor wellhead and the 18-3/4" wellhead. If the cement job had been contaminated by a shallow water zone, then any flow around the surface pipe would be inhibited by the annulus packoff. Concern arouse, however, about the possibility that the annulus packoff would cause overburdened pressure to force a shallow water flow into the formation and around the conductor string eroding the entire foundation of the well. This concern supplied the logic towards reinforcing the conductor string with a second conductor string. Secondary Conductor String Several options are available and have been considered to strengthen the foundation pile and/or seal of the annulus between the two conductor strings. Alternative conductor programs utilizing 36", 26" and 24" have become common. One technique is to "piggy-back" the conductor wellheads with either 36" and 30" or 30" and 24" hanging from them. Conductor wellheads can also be nested as discussed in the Tension Leg Platform (TLP) section found in chapter 10. Nested conductor wellheads are not standard and are usually found on development wells as was the case with the TLP application discussed.

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Another technique for designing subsea wells with two conductor strings utilizes the "scab hanger" concept. This involves the placement of a buttweld sub below the first wellhead which supplies a landing shoulder for a second conductor string to be hung off from that point. Scab hangers can be designed with various features such as simple landing shoulders, with or without flow-by and with a lock ring, or with shear pins. These hangers are designed to supplement the foundation characteristics of the conductor string. Riserless Supplemental Casing Systems When drilling a well with a shallow water hazard in the horizon, the ultimate protection becomes a large bore diamater hanger system that offers a testable, retrievable, replaceable packoff or seal assembly, such as the features found in the 16" Supplemental Casing Hanger System (Refer to the 16" Supplemental Casing Hanger section found previously in the chapter). The 20" Supplemental Casing Hanger System offers a solution, but presents the neccesity to run the 18-3/4" wellhead, 20" extension with an adapter for the 16" casing hanger system and a special stab sub that slides into the throat of the 20" casing hanger. This special stab sub will have multiple sealing systems on its OD to assure a seal between the 18-3/4" wellhead and the rest of the 20" casing string.

The 18-3/4" SS-15 Wellhead System was developed around the classic 30" x 20" x 13-3/8" x 9-5/8" x 7" casing program. As various drilling parameters and needs are considered, wellhead systems are modified to accomodate the specifications. To date, subsea wellhead systems have been offered to the industry that are 13-5/8", 16-3/4", 18-3/4" and 21-1/4". Because of the evolutionary changes in wellhead systems requirements, Subsea Wellhead System changes will forever continue.

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TLP and Tie-Back to Subsea Wellhead Systems

Introduction ............................................................................. 199 Tie-Back to Subsea Wellhead Systems .................................. 200 Tieing Back the 18-3/4" Wellhead ......................................... 201 20" Internal Tie-Back Connector .......................................... 201 20" External Tie-Back Connector ......................................... 203 TLP Subsea Wellhead Systems .............................................. 208 Guide Bases vs Templates ...................................................... 208 Nested Conductor Wellhead Housings .................................. 209 Drilling With Returns to Surface .......................................... 210 18-3/4" Rigid Lockdown Wellhead and 20" Stab Sub ........ 211 Standard Wellhead Components ........................................... 212 Lockdown Sleeve .................................................................. 213

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Introduction The previous chapter described the process of drilling an exploratory well with a subsea wellhead system. When completion wells are drilled using subsea wellhead equipment, consideration for the completion method must be made. The first completion method may involve a tie-back to surface with a surface production tree. The second is a subsea tree. A decision for the method used is based on many factors, with one of the most important factors being the water depth the well has been drilled in. Subsea production trees are specialty surface trees that are modified to accommodate the remote location on the sea floor. These trees have been installed in a range of relatively shallow water up to water depths of several thousand feet. A discussion of subsea production trees and components can be found in Chapter 11 "Introduction to Subsea Completion Systems." Figure 10.1. Illustration of a Tension Leg Platform

When the water depth is within the 1200' range, typically a platform is utilized and a tie-back system is installed to establish communications from the surface to the downhole equipment. A second conventional or unitized specialty wellhead is made up at the surface and a typical tree is installed. A surface tree operated and maintained by a man


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has been the completion method preferred by a majority of the operators. This is an important issue because water depths beyond 1200' are outside the technological envelope of a platform that stands on the sea floor. For this reason, a structure that will allow surface completions has to be created that will make deep water subsea wells viably produceable with surface trees. The Tension Leg Platform (TLP) is a floating structure that is tethered to the sea floor. Each tether is tensioned to pull the platform down into the water, which tempers the behavior of the structure in any wave action. Movement, both horizontal and vertical, is severely restrained but not eliminated. The TLP behaves like a platform standing on the sea floor so subsea wells can be tied back to the surface for completion.

Figure 10.2. Illustration of a Tension Leg Platform over a template

When a subsea wellhead is tied back to a TLP, the tie-back string must be tensioned to inhibit metal fatigue and riser failure. This tension combined with the slight, but constant, movement effects the subsea wellhead system. The wellhead, wellhead components, and upper section of each casing string is "cold worked" and realize more stress then a subsea wellhead that is tied back to a standard platform. For this reason, the subsea wellhead is modified to accommodate the stress imparted to the wellhead system when used in conjunction with a tension leg platform. There can be many variations to a TLP subsea wellhead design depending on the sea floor geology, casing program and operator preference. The following discussion centers around a TLP subsea wellhead system used in the Gulf of Mexico as an example.

Tie-Back to Subsea Wellhead Systems The previous section of this chapter discussed the installation of a TLP subsea wellhead system. Subsea wellhead systems and TLP subsea wellhead systems should be designed for tieback to the surface for surface completion. There are a number 200

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of ways to tie-back a subsea wellhead system. Regardless of the design and whether it is a platform tie-back or TLP tieback, the wellhead body will, in most cases, be tied back to establish a barrier string between the sea and the production casing annulus. There will always be a tie-back for the production casing string and there may or may not be a secondary tie-back between the production annulus and the barrier string. The following section discusses the number of different variations for tieing back a subsea wellhead system and will assume that the maximum amount of casing strings will, in deed, be tied back. In the end, the operator will make a choice as to whether he will follow the scheme presented here or select some modification and/or some combinations of the standard tie-back system presented. Tieing Back the 18-3/4" Wellhead Tieing back the 18-3/4" wellhead consists of a wellhead connector that will conform to the strength and pressure specifications for the particular well. There have been a number of wellhead connectors used over the years which are summarized in the following list: 1. Standard drilling hub type wellhead connector (used in the TLP subsea wellhead discussed earlier in this chapter) 2. Standard drilling mandrel type wellhead connector (discussed in Chapter 8) 3. Standard internal type tie-back connector 4. External type tie-back connector 20" Internal Tie-Back Connector The 20" Tie-Back Connector is an internal tie-back connector used to connect the 20" barrier riser string to the 18-3/4" subsea wellhead. The 20" Tie-Back Connector is run on casing and locks to the running profile located in the wellhead ID with a cam actuated split lock ring (Figure 10.4). The lock ring is

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Figure 10.3. SS-15 Standard Subsea Wellhead stackup system

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actuated with a threaded wedge ring which is driven down when the threaded actuator ring is rotated. Resilient type seals mate with the ring gasket profile in the top of the wellhead. Since angular mis-alignment and wellhead off-set mis-alignment are of critical concern, the connector body is designed to accept a stab nose to assist in high angle stabbing conditions.

20" TIE-BACK CONNECTOR

20" STAB NOSE

18-3/4" SUBSEA WELLEAD

DRILL PIPE STINGER

Figure 10.4. Illustration of the 20" connector and high angle stab nose being lowered into the wellhead

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The High Angle Stab Nose guides the 20" Tie-Back Connector into the 18-3/4" wellhead. It is equipped with a non-abrasive nylon nose to protect the ring gasket seal area when it is entering the wellhead. The nylon nose can also be replaced with an attachment which provides a drill pipe connection to allow entry into the wellhead with a drill pipe entry stinger. A retrieving profile in the top of the stab nose allows the 20" Torque Tool to lock to the stab nose when the tool is run and landed in the 20" Tie-Back Connector. The High Angle Stab Nose is retrieved when the Torque Tool is retrieved. First, the 20" Tie-back Connector and High Angle Stab Nose are run on 20" casing which will become the barrier riser string. The drill pipe stinger or nylon nose guides the connector into position over the wellhead. The 20" Tie-Back Connector is lowered into the 18-3/4" wellhead until the 20" Tie-Back Connector has landed in the wellhead. A confirmation that the 20" TieBack Connector is firmly seated out in the 18-3/4" wellhead is made by filling the 20" riser with water.

Figure 10.5. Internal tie-back connector ready to run

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The 20" Torque Tool locks and preloads the 20" Tie-Back Conector to the 18-3/4" wellhead (Figure 10.6). Run on drill pipe inside the barrier riser string, the Torque Tool lands on a ring inside the 20" connector. The drill pipe is then rotated to the right until the three torque keys on the Torque Tool locate their corresponding slots in the actuator ring of the 20" Tie-Back Connector. The Torque Tool is Figure 10.7. Retrieving the then rotated to the right approxihigh angle stab nose with the mately eight turns to lock and 20" Torque Tool preload the tie-back connector to the wellhead. With casing elevators latched to the 20" casing, a confirmation that the 20" Tie-Back Connector is locked to the wellhead is made by taking a 10,000 lbs. overpull. The 20" Torque Tool is retrieved with a straight upward pull bringing the High Angle Stab Nose with it. Wellhead and BOP equipment are made up at the surface as dictated by the operator. 20" External Tie-Back Connector The 20" External Tie-Back Connector is also used to connect the 20" barrier riser casing string to the 183/4" subsea wellhead in situations where the running profile in the wellhead ID is not accessible. The External Tie-Back Connector has an overshot type bottom which swallows the wellhead. Resilient type seals mate with the ring gasket profile in the top of the wellhead. This

Figure 10.6. Illustration of the Torque Tool locking the tie-back connector to the 18-3/4" wellhead

Figure 10.8. Photo of the external tie-back connector

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connector can be designed to lock to a hub type as well as several variations of mandrel type profiles. The External Tie-Back Connector is compatible with the High Angle Stab Nose and is run in a similar manner as the Internal Tie-Back Connector. All SS-15 subsea casing hangers are equipped with a modified acme right-hand thread that RIGHT HAND is designed to accept a TIE-BACK THREADS threaded split lock ring (Figure 10.9). The 13-3/8" Stab-In Tie-back Adapter is equipped with a threaded split lock ring and will provide a means to connect the last casing hanger run to any riser casing size or connection. The 13-3/8" Stab-In Tie-Back Adapter incorporates a split threaded lock ring which pro-

Figure 10.11. Illustration of the 13-3/4"Stab-In Tie-Back Adapter landed in the casing hanger

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Figure 10.10. Photo of the 13-3/8" Stab-In Tie-Back Adapter. Note the thread split lock ring

Figure 10.9 Illustration of a standard subsea casing hanger

vides a simple weight-set lock and rotation torque interface between the tool and the casing hanger (Figure 10.10). The seal between the Tie-Back Adapter and the casing hanger ID is a metal-to-metal seal with resilient type seals as back up. The jetting tool is used to flush and clean out any debris that may exist in the tie-back threads of the subsea casing hanger prior to running the tie-back adapter.

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A 13-3/8" Torque and Test Tool can be used to impart final torque to preload the 13-3/8" Stab-In Tie-Back Adapter to the subsea casing. The Torque and Test Tool is equipped with test seals to isolate the tie-back connection (Figure 10.12). Pressure down the drill pipe confirms a tight seal exists between the TieBack Adapter and the casing hanger. After pressure tests are successful, the Torque and Test Tool is lifted with straight upward pull and retrieved to the surface. Surface wellhead equipment is installed. The standard subsea wellhead discussed in this manual offers the above described tie-back capability. If it is desirable to monitor the annulus between the secondary string and the production casing hanger, a special annulus monitoring casing hanger must be installed during the drilling phase. This annulus monitoring casing hanger is equipped with the necessary thread profiles and porting to maintain continuity between the annulus below the wellhead and the annulus in the riser allowing uninterrupted monitoring. Figure 10.13 illustrates an annulus monitoring casing hanger. The annulus monitoring ports are isolated from the well bore with a protective sleeve which threads into the throat of the hanger. This protective sleeve also protects the right-hand production casing tie-back threads from any damage from drilling bits as they are raised and lowered during the drilling process. The annulus monitoring features are essentially ignored during the drilling phase and the hanger is run as if it were a standard casing hanger.

Figure 10.12. Illustration of the 13-3/8" Torque & Test Tool making up and testing the 13-3/8" Stab-In Tie-Back Adapter

RIGHT HAND TIE-BACK THREADS ANNULUS MONITORING PORTS RIGHT HAND TIE-BACK THREADS

The 10-3/4" (or 9-5/8", 7-5/8" and 7") Stab-In Tieback Tool also PROTECTIVE SLEEVE incorporates a threaded split lock ring to facilitate stab-in and make up (Figure 10.14). Metal-to-metal primary seals are backed up with resilient backup seals on the nose of the tool. The split lock ring locks the tool to the right-hand modified acme thread located behind the protective sleeve in the annuFigure 10.13. Illustration of the lus monitoring casing hanger. annulus monitoring casing hanger

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Prior to running the Tie-Back Tool, the protective sleeve is removed from the annulus monitoring casing hanger to expose the tie-back threads. The 10-3/4" Stab-In Tie-Back Tool is run in the same manner the 13-3/8" Tie-Back Adapter (Figure 10.16).

Figure 10.14. Photo of the 10-3/4" Stab-In Tie-Back Tool. Not the metalto-metal sealing nose

A torque and test tool is also provided to ensure the tieback connection is locked and pressure tight (Figure 10.17).

Figure 10.16. Illustration of the 10-3/4" Tie-Back Tool landed in the annulus monitoring casing hanger

As each casing string is tied back, the surface wellhead is built up in stages. When the tie-back system has been successfully installed, the surface wellhead is ready to be completed. Down hole work is performed and tubing with tubing hanger is run. The tree is nippled up and the well is placed on line. Figure 10.15. Illustration of the annulus monitoring casing hanger with protective sleeve removed

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Figure 10.17. Illustration of the 10-3/4" Test Tool making up the 10-3/4" Stab-In Tie-Back Tool

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Figure 10.18 Illustration of the Tie-Back to Subsea Wellhead System installed

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TLP Subsea Wellhead Systems

Figure 10.19. Illustration of a guidelineless guide base used with dynamically positioned drilling vessels. This guide base is designed for completion wells (non retrievable)

Figure 10.21. Illustration of the mud mat and guidelineless guide base in the moonpool area, ready to run conductor

Guide Bases vs Templates A TLP project will undoubtedly be costly. For this reason, the field the operator is completing must be capable of supporting a large quantity of wells. Template systems provide exact well spacing and are the most common initial structures placed on the sea floor. The conductor wellhead design will match each receptacle in the template. The conductor casing size may need to be larger than the 30", the wall thickness will most certainly be greater and the material may be stronger then previously discussed. Again, all of the final specifications will be a function of the sea floor geology, water depth and operator preference. The TLP wellhead system used in this example will not utilize guidelined drilling technology. Each well will be drilled with a dynamically positioned drilling vessel and guidelineless drilling technology. A dynamically positioned Figure 10.20. Map of the wellhead drilling vessel is a specially location on the sea floor. A template equipped drilling vessel system was not used designed to drill in water depths considered too deep for the use of anchors and guidelines to be practical. Instead, computers control the drilling vessel and incorporate thrusters to maintain the drilling vessel over the well site. When using a dynamically positioned drilling vessel, a substitution is also made by replacing the permanent guide base with a guidelineless guide base. A unique approach is to pass on the use of a template system and install the conductor casing, guidelineless guide bases

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and a mud mat in a precise pattern mapped out on the sea floor (Figure 10.19). Since dynamically positioned drilling vessels have historically proven to be quite precise, the expense of a template was saved. The sea floor conditions were quite soft and, in fact, unconsolidated for the first 100'. The first conductor starts with 38" and two nested conductor wellheads were necessary. The mud mat is positioned in the moonpool area with the guidelineless guide base positioned on top of it. A 36" conductor jet shoe is lowered through the rotary table through the center receptacle of the guidelineless guide base and mud mat. Intermediate 36" conductor joints were made up and run using a 1/2 turn make up Quik-Thread connector similar to the ones described in Chapter 1 of this manual. The 38" conductor swages into 36" below the first 100'. Finally, the 38" special conductor wellhead is run to the conductor string and, with a 38" Wellhead Running Tool similar to the 30" Wellhead Running Tool described in Chapter 9, is used to lower the Figure 10.22. Illustration of the 38" wellhead into the guidelineless guide base and mud mat. The entire assembly is picked up and lowered to the sea floor. Jetting operations were used to install the 38"/36" conductor string, guidelineless guide base and mud mat (Figure 10.22). Once the mud mat touches down on the sea floor, the 38" WellheadRunning Tool is rotated with five right- hand rotations and retrieved to the surface. Nested Conductor Wellhead Housings As previously noted, the example TLP wellhead system incorporates a nested conductor configuration. A second 26" conductor string will crossover to a section of 28" conductor topped out with a 28" conductor wellhead that will fit inside the 28" conductor. The 28" conductor wellhead will provide a special profile for a preloaded connection between the high pressure wellhead and conductor casing strings (Figure 10.24). The 26" conductor will also incorporate a special adapter which supplies a landing shoulder and resilient sealing area for a 20" Supplemental Casing Hanger System similar to the ®

conductor, guidlelineless guide base and mud mat jetted into position on the sea floor

Figure 10.23. 38" Wellheads, 28" wellheads and 18-3/4" wellheads in final assembly

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16" Supplemental Casing Hanger System described in Chapter 9.

Figure 10.25. Running the 28" special Rigid Lockdown WellheadHousing

The 28"/26" second conductor casing string is run and landed in the 38" wellhead with a 28" Wellhead Running Tool (Figure 10.26). Again, the 28" Wellhead Running Tool is similar to the 30" Wellhead Running Tool previously described. After the 28" conductor is cemented into place, the wellhead running tool is released LOCK with five right-hand rota- DOWN GROOVES tions and retrieved. Drilling With Returns to Surface Before drilling the next section of hole, a hydraulic 5 TAPER latch, special subsea diverter system and large diameter riser system are run and connected to the Figure 10.24. Ilustration of the 28" wellhead to protect special 28" Rigid Lockdown Wellhead Housing against possible shallow gas pockets. The subsea diverter is essentially a bag type preventer hydraulically controled from the surface. In the event gas migrates into the well bore, the diverter will be closed and large hydraulically actuated valves below the diverter serve to vent the gas safely to the sea. O

Figure 10.26. 28" wellhead installed in the 38" wellhead

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The 20" casing hanger and 20" seal assembly is run on a 20" Casing Hanger Seal Assembly Running Tool and the hanger is landed inside the 28" Supplemental Adapter (Figure 10.27). After the casing is cemented, the running tool is rotated and the 20" seal is set with 15,000 lbs. of weight, similar to the procedure previously described. A plugging dart is dropped in the drill pipe and lands out in a sliding sleeve in the neck of the 20" Casing Hanger Seal Assembly Running Tool. Since

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there are no choke or kill lines available to test the 20" seal, pressure is introduced through the drill pipe which reacts against the dart to shift the sleeve in the running tool creating a pressured path into the wellbore. Pressure applied to the seal and diverter will determine if the seal is set. When testing is complete, the 20" Casing Hanger Seal Assembly Running Tool is retrieved. Figure 10.27. 20" Supplemental 18-3/4 Rigid Lockdown Casing Hanger and Seal installed Wellhead and 20" Stab Sub The 18-3/4" Rigid Lockdown Wellhead locking mechanism is found in the center section of the wellhead body and the reaction ring found at the bottom OD section of the wellhead (Figure 10.28). These components are designed to establish a preloaded connection between the 18-3/4" wellhead and the conductor wellhead it is sitting in. By driving the locking tabs down, the split lock ring is forced into the 2 grooved running profile inside the top section of the 28" (or 30" on standard rigid lockdown systems) wellhead. This action compressively loads the wellhead down into the reaction ring and the 5o taper profile in the ID of the 28" wellhead. This locking mechanism will create between 500,000 psi to 2,000,000 psi of preload depending on the amount of force used to drive the locking tabs down.

STANDARD 18-3/4" BODY

LOCKING TABS LOCKING RING

The 18-3/4" wellhead will have a 20" Supplemental Casing REACTION Hanger Adapter , several joints of exactly dimensioned 20" casing RING and a special 20" stab sub directly below it. The 20" stab sub will slide into the ID of the 20" Supplemental Casing Hanger. The 20" stab sub has multiple resilient seals on the OD to ensure a Figure 10.28. Illustration of the pressure tight seal is established between the wellhead and the 18-3/4" Rigid Lockdown Wellhead

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20" casing hanging in the 28" conductor. The 16" casing string will hang inside the 20" above the special stab sub and be cemented into place. This will cover up the seals on the 20" stab sub and seal off any potential leak paths. Since the 18-3/4" Rigid Lockdown Wellhead has an OD larger than the ID of the 30" riser system, the subsea diverter system and riser must be retrieved prior to running the wellhead.

Figure 10.29. Illustration of the 18-3/4" Mechanical Rigid Lockdown Wellhead

Figure 10.30. Running the 20" Stab Sub and 18-3/4" Rigid Lockdown Wellhead

Figure 10.31. Top view of the Mechanical Rigid Lockdown Tool

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The 18-3/4" Rigid Lockdown Wellhead is run with the Mechanical Rigid Lockdown Tool (Figure 10.32). This tool is connected to the wellhead with the standard 18-3/4" Wellhead Running Tool. After the 18-3/4" wellhead is landed in the 28" wellhead, the Mechanical Rigid Lockdown Tool is functioned with a1/8 left-hand turn and pulled straight up. This action drives the tool’s actuating sleeve down which, in turn, drives the locking tabs on the wellhead down rigidly locking the 183/4" wellhead to the 28" wellhead. An ROV camera confirms the wellhead is locked down. Five right-hand turns release the 18-3/4" Wellhead MASTER LINKS Running Tool and Mechanical Rigid Lockdown Tool from INDICATOR the 18-3/4" wellhead. The tool PLATE is retrieved with 5 right-hand rotations and a straight up18-3/4" ward pull. WELLHEAD Standard Wellhead Components The BOP stack is run and tested with the BOP Isolation Test Tool as described in the previous chapter. A nominal bore protector is installed with the Multi-Purpose Tool and the Nominal Bore Protec

RUNNING TOOL

LOCKING TABS ACTUATOR SLEEVE

Figure 10.32. Illustration of the 18-3/4" Mechanical Rigid Lockdown Tool and Wellhead Running Tool

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tor Running Adapter. A 22" hole is drilled in preparation for the 16" casing. The 16" Supplemental Casing Hanger and the 16" seal assembly is run with the 16" Casing Hanger Seal Assembly Running Tool. The seal assembly is tested, locked down and the running tool retrieved. The 16" wear bushing is installed with the Multi-Purpose Tool and the Wear Bushing Running Adapter. The next hole section is drilled in preparation for the first casing hanger to be installed into the wellhead. The casing hanger is installed in the same as previously described in Chapter 9. Lockdown Sleeve The Lockdown Sleeve is unique to the TLP wellhead system. By landing on the last casing hanger and locking into the 183/4" wellhead running profile, the Lockdown Sleeve preloads all of the wellhead components into the bottom of the wellhead (Figure 10.34). This is to minimize the stress induced from bending loads on the wellhead system throughout the life of the TLP and increase the fatigue life. The Lockdown Sleeve incorporates a tie-back profile and load supporting shoulders designed to offer a contingency hanging point for the production casing string. The seal mounted to the OD is inverted and reacts against a 4o back tapper shoulder on the Lockdown Sleeve. This seal isolates the production casing bore from the rest of the wellhead components.

Figure 10.33. Illustration of the 18-3/4" Rigid Lockdown Wellhead and 20" stab sub installed

Once the Lockdown Sleeve is installed, a specialized corrosion cap is run with an ROV assist running tool. The corrosion cap contains a compartment of corrosive inhibitor which is injected into the wellhead and water is displaced from the wellhead when the cap is landed. Subsequent wells are batch drilled with the dynamically positioned drilling vessel while the TLP structure is being built at a fabrication facility. When completed, the TLP will be moved to the drilling location and installed. All corrosion caps will be retrieved and the wells tied back to the surface for completion.

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ACTUATING SLEEVE LOCKDOWN SLEEVE

Figure 10.36. Running the corrosion cap with Corrosion Cap Running Tool

SEAL ASSEMBLY

LANDING SEAT

TUBING HANGER HANGOFF PROFILE

Figure 10.34. Illustration of the 18-3/4"Lockdown Sleeve

Figure 10.35. Illustration of the 18-3/4"Lockdown Sleeve

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Figure 10.37 Illustration of the TLP Wellhead System installed. The corrosion cap has been left out for clearity

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Introduction to Subsea Completions Introduction and Scope The subsea production tree offers the means by which a single subsea well can be completed, controlled and produced. The early underwater production trees were very simple, and were nothing more than a stacked assembly of standard flanged valves installed by divers on an underwater flanged wellhead. Lake Erie was the site for over 300 of these early underwater trees that were first installed in the 1930’s. Production from the wells was done through lakebed flow lines; and control of production was done manually by sending a diver down to open or shut valves on the production trees as required.

Figure 11.1 Photo of a typical Subsea Tree, LRP and EDP

Since the 1930's subsea tree technology has developed and advancements have made deep water subsea completions a reality. Many different varieties and tree configurations have evolved. This chapter introduces the concepts, the terms, the equipment and the installation steps of subsea tree components. Most examples used represent actual equipment supplied, however, there are many common variations which are represented with graphics. Keep in mind that general categories have been identified in an attempt to simplify different concepts and tree types. There

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Introduction to Subsea Completions

are, in some cases, overlap, and in all cases exceptions to each generalization.

Open Hole Completion PRODUCTION CASING DOWN HOLE SAFETY VALVE TUBING SLIDING SLEEVE TUBING RECEPTACLE PACKER/ HANGER

OPEN HOLE PRODUCING ZONE

Figure 11.2 Typical top-set or open hole completion method.

Subsea Completion Tree Considerations Any serious attempt to understand current day subsea completion trees will cover a bewildering array of specialized equipment and technologies. For purposes of simplifying the subject these technologies are divided into five major categories; • • • • • •

Downhole Configuration Subsea Wellhead System to be Completed Tubing Hanger Equipment Tree and Tree Components Flow line Connections Control Equipment

Downhole Configuration Any consideration of subsea tree designs starts with a consideration for the following: • The Completion Method • Downhole Completion Equipment The completion method specifies the process of selecting zones that will be exposed to the well bore. The most common completion methods used in subsea production systems are a top-set or open hole completion, and a setthrough completion method. In a top-set or open-hole completion (Figure 11.2), the casing is set in place and cemented above the producing formation. Additional hole is drilled beyond the casing and through the productive formation. The additional hole is not cased. Since all zones are exposed to the well bore, this method is often used when known reservoirs are being developed. In such cases, the zones of interest have been previously defined and it is desirable to expose all zones.

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In a set-through completion method (Figure 11.3), the final hole is drilled through the formation and the hole is cased and cemented. This method requires that perforations be made through the casing to reach the productive zone. This method makes it possible to accurately control the effects of stimulation and production operations. Zone isolation is much easier with set-through completions because packers and other downhole equipment are able to form more effective seals inside the casing. There are other completion methods that represent some variation of the already mentioned methods. Dual completions are also a consideration, but historical performance has indicated that it is not practical in a subsea completion application. Downhole completion equipment used to produce hydrocarbons has been broken down into the following categories: 1. Packers 2. The tubing string, coupling size, type and grade 3. Surface controlled sub-surface safety valve (SCSSV), plug nipples, tubing-seal receptacles, sliding sleeves, flow couplings, surface controlled subsurface safety valves 4. Sensing units, such as temperature, pressure, etc.

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Set-Through Completion PRODUCTION CASING DOWN HOLE SAFETY VALVE TUBING SLIDE SLEEVE TUBING RECEPTACLE

PACKER/HANGER

PRODUCING ZONE

PRODUCTION CASING

Figure 11.3 Illustration of a typical set-through completion method.

The specific tubing design and configuration, and the number of above components designed into the tubing string, is strictly the operators choice. The tubing design and/or downhole equipment incorporated in the tubing design will be a function of the following; • number of zones to be completed • type of completion method

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• workover scenario anticipated (i.e., direct overhead access is to be required or can workover be accomplished remotely from a production platform?) • downhole equipment type (pressure balanced downhole safety valve or standard) Following is a list of specific items that the tubing hanger system must interface with: 1. Downhole Safety Valve (SCSSV). The downhole safety valve is a fail-safe close valve located in the tubing string above the packer. This valve requires constant pressure, supplied through one control line from the remote production station, through the tubing hanger to the valve downhole to keep the tree producing. In the event a catastrophe occurs, (example: fishing net pulling the completion tree over, or an iceberg scours the ocean floor and breaks the production flow-line), the SCSSV control line will be disrupted, resulting in a pressure loss and automatic shut-in of the tree. Sophisticated downhole valves are designed to react to a pressure surge in the flow line and will automatically shut-in, alerting the operator to a possible problem with the producing zone. These downhole safety valves are “pressure balanced” and will require two control lines through the tubing hanger. 2. Downhole Sensing and Position Indicator Devices. Downhole sensing devices, such as temperature or pressure sensors, transmit the sensed information to the remote production station through electrical lines which pass through the tubing hanger. These electrical lines will also terminate in a seal pocket in much the same manner as the SCSSV control line, but will house an electrical connection to the electrical line to the sensor. 218

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DOWNHOLE SAFETY VALVE REQUIRES POCKET IN TUBING HANGER

GAS LIFT MANDRELS REQUIRE LARGE VOLUME ANNULUS ACCESS

PRESSURE GAUGE TRANSMITTER REQUIRES ELECTRICAL CONNECTION AT TUBING HANGER

Figure 11.4 Illustration of a sophisticated down hole completion equipment. ®

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3. Annulus Access Specifications. Downhole access such as gas lift will effect the tubing hanger and control whether any additional access lines need be designed into the tubing hanger. Also it is good practice to have an annulus access port through the tubing hanger body for purposes of fluid circulation during completion of the well and subsequently for pressure monitoring of the annulus when the well is in production. This annulus access bore through the tubing hanger body will also have a seal pocket at the top and a threaded box down for any suspended annulus tubing. 4. Workover Specifications. In the most sophisticated designs, presumably for trees in the deepest water, most in accessible locations, some downhole workover capabilities do exist without using a vessel overhead. Through Flow Line, which calls for annulus access downhole and the addition of a third line called the service line. The service line will also have a seal pocket at the top and a threaded box down for any suspended tubing. This tubing string crosses back over to the annulus access line and is used to back out any tools that have been pumped down the annulus line.

Figure 11.5 Illustration of the SS-15 Subsea Wellhead System with 7" production casing installed.

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The type of tubing hanger used, is a function of the downhole completion equipment specified. Finally the ®


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tree is designed around the tubing hanger, once it has been specified and the workover scenario has been clarified. Subsea Wellhead and Configuration Before subsea completion trees and associated equipment can be discussed, the subsea wellhead system and the wellhead components installed during the drilling process must be reviewed (Figure 11.5). The reason is to clarify the following items: 1. Water depth 2. Casing program and production casing size 3. Wellhead size, type (manufacturer, connector profile, etc.), pressure rating and guidance equipment foundation 4. Space availability for a subsea tubing hanger 5. Profile configuration for: •Tubing Hanger Seal Assembly •Tubing Hanger Lockdown Profile There are many types, sizes, and pressure ratings of subsea wellhead systems. Additionally, the casing program installed during the drilling phase affects the completion tree specifications. These are all issues that must be considered to make a determination of the location of the tubing hanger relative to the wellhead and wellhead components. Depending on the production casing string installed, wellhead type and manufacturer, tubing hanger manufacturer, and annulus requirements, the following choices for tubing hanger location are available: 1. Landed on the production casing string. If there is space available in the wellhead, and the same manufacturer for the wellhead and tubing hanger are ®

TUBING HANGER LOCKDOWN PROFILE

TUBING HANGER POSITION

TUBING HANGER LANDING SEAT TUBING HANGER METAL-TO- METAL SEALING AREA

Figure 11.6 Illustration showing SS-15 Wellhead System drilling equipment and detail of tubing hanger landing seat, sealing area, and lockdown profile.

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TUBING HANGER LANDING SEAT

TUBING HANGER ADAPTER METAL-TO-METAL SEAL

selected, the tubing hanger will likely sit on top of the production casing hanger and lock into the hanger, seal assembly or the wellhead (Figure 11.6). 2. Landed in a tubing hanger adapter bowl. The tubing hanger adapter allows the operator to safely mix subsea wellhead and subsea completion tree vendors. Run and installed prior to running the tubing hanger, the tubing hanger adapter bowl seals in the casing hanger ID with metal-to-metal seals and provides a convenient lock down profile for the tubing hanger (Figure 11.7). 3. Landed in a tubing head. When completing a well that has been drilled by a jackup, and the well incorporates a mudline suspension system, the tubing hanger is landed in a tubing head. The tubing head ID profile allows for a landing seat, metal-to-metal sealing profile, and a tubing hanger lockdown profile (refer to Figure 11.8).

Figure 11.7 Illustration of a Tubing Hanger Adapter.

TUBING HANGER LOCK DOWN PROFILE

TUBING HANGER LANDING SEAT

Figure 11.8 Illustration of a tubing head used for completing a mudline suspended well subsea.

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When the well has been drilled with a subsea wellhead, a tubing head can also be used when mixing manufacturers. This configuration, known as a "split tree" consists of a tubing head mounted to the top of a wellhead connector. This lower section of the tree will also include a guide frame, flowline stab components, and any control system components that may be required. The tubing head profile will mimic the wellhead profile. The rest of the tree will start with another wellhead connector, a guide frame, the tree body and control system. While the additional expense of 2 wellhead connectors exist, there are added benefits of the split tree. First, the tubing hanger system can be simplified because the annulus can be monitored from a side outlet on the tubing head. Secondly, the lower portion of the tree can carry flowline pull-in components, control system hardware, etc. ®


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Standard 10,000 psi wellhead systems (including DRIL-QUIP'S 10,000 psi wellhead) are shorter than the 15,000 psi wellhead system illustrated. A shorter wellhead places the subsea tubing hanger above the top of the wellhead if a 7" casing hanger has been installed. While this does not necessarily eliminate the possibility of landing a tubing hanger in the 7" casing hanger, the tubing hanger is unprotected and subject to damage during tree installation. Furthermore, it requires the tubing hanger lock inside the casing hanger instead of using the wellhead for lock down. An alternative is to consider the split tree previously described. For 10,000 psi systems, hopefully the last casing hanger position has not been used, and the tubing hanger can occupy this space. As previously noted, an alternative is to utilize a tubing hanger adapter and lock the tubing hanger inside it. Tubing Hanger Systems and Running Tools In a subsea well, production tubing is supported and sealed off inside the subsea wellhead housing. The tubing hanger and the running tool necessary to install it defines a tubing hanger system. On wells with subsea wellheads, the subsea tubing hangers are run and landed through the marine riser and the subsea BOP stack with a full drilling fluid/completion fluid column in place. On wells that have been mudline suspended, the subsea tubing hangers are landed in a tubing head through casing riser and a surface BOP stack. Before a discussion of the Tubing Hanger System can proceed, the following information must be identified: 1. Nominal wellhead size and pressure rating 2. Production casing size and pressure capacity 3. Number and size of tubing strings supported 4. Number and size of control ports for downhole functions and/or sensing devices The great majority of subsea tubing hangers are mandrel type hangers as opposed to slick joint type hangers. The reason for this is that space out and sealing difficulties of a

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Figure 11.9 Photo of a split tree used for completing a subsea wellhead system. Note the tubing head spool between the two wellhead connectors.

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slick joint type hanger are not easily over come in a wellhead out of manual adjustment range. In addition to the production bore, any communication with any equipment down hole, such as downhole safety valves (SCSSV), temperature sensors, gas lift mandrels, etc., must pass through the tubing hanger. In order to accommodate these requirements, all tubing hanger systems can be summarized into two categories. PRODUCTION BORE

• •

ANNULUS ACCESS PORTS (IF REQUIRED)

Figure 11.10 Top view of a concentric bore tubing hanger system.

Concentric bore or non-orienting tubing hanger. Multi bore or orienting type of tubing hanger system.

Concentric Bore Tubing Hanger System The most basic subsea tubing hangers have a single central bore threaded box down to make up to a single tubing string (Figure 11.11). The upper part of the tubing hanger body will have a central seal pocket to receive the mating male stab sub from the subsea production tree. The tubing hanger is lowered into position with a running tool that is connected mechanically or hydraulically to the tubing hanger body ID. The running string may be drill pipe, tubing or a custom designed completion string with integral tubing strings and control lines. Generally the tubing hanger will incorporate a metal-tometal seal and a positive lockdown feature. The metal-tometal seal will either be torque or weight set energized and isolates the annulus from the tree. The lockdown feature is maintained by a lockdown ring and an actuating sleeve which is actuated by weight and locked in position with a ratchet lock down threads. The purpose of locking the tubing hanger in place, is to provide a restraint against upward thermal expansion of the tubing string during production. The residual tension in the tubing string may be sufficient to counteract the thermal expansion of the tubing, but if the production temperatures are too high, the lock down feature is essential. This restraint ensures that the annulus seal on the tubing hanger see very little move-

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ment due to thermal expansion. Figure 11.10 and Figure 11.11 show concentric tubing hanger designes to land in a tubing head . The hanger incorporates a weight set metal-to-metal seal. Control over a maximum of two downhole safety valves is accommodated with special porting in the male stab sub that maintains communication from the running tool (and tree) through to the tubing hanger. The tubing hanger illustrated is run with a threaded running tool. Because the hanger lands in a tubing head, annulus access is through a side outlet on the tubing head. The concentric bore tubing hanger designed for a subsea wellhead incorporates all the features just described, but also includes a metal-to-metal sealing annulus valve (Figure 11.15). This valve provides access to the production annulus bore through the tubing hanger. Access through the tubing hanger is necessary when no side outlet exits such as the case with a LOCK RING subsea wellhead. ACTUATOR Control over the annulus valve (open and close funcMALE STAB tions) are accommodated RECEPTACLE with additional porting in the male stab sub (refer to LOCKING RING Figure 11.13) similar to the porting which controls the SEAL ASSEMBLY down hole safety valves. (METAL-TOMETAL SEALING The subsea wellhead conSYSTEM) centric bore tubing hanger is run on a hydraulically RUNNING THREADS actuated tubing hanger running tool. Figure 11.11 Illustration of a concentric bore tubing hanger. This tubing hanger is designed to land in a tubing head.

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Figure 11.12 Photo of a concentric bore tubing hanger.

If there is only one producing zone to be completed; a maximum of one downhole 225

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CHEMICAL INJECTION

safety valve in the tubing string; and annulus access is for monitoring only, a concentric bore tubing hanger system is the most efficient choice because:

ANNULUS VALVE OPEN

ANNULUS VALVE CLOSED

First - All down hole access occurs through the stab sub, eliminating any need for specific orientation. SCSSV PORT

SEALS TREE SIDE FLUID PATH SEALS

TUBING HANGER FLUID PATH SEALS

Figure 11.13 Illustration of a male stab sub.

Second - The concentric bore tubing hanger is a simple tubing hanger system, making it cost effective and easy to install. Third - The concentric bore tubing hanger system supports the simplest tree configuration. The tree has only one bore (production) and does not have to be oriented to the tubing hanger prior to landing on the wellhead. Multi Bore Tubing Hanger Systems The multi bore or orienting tubing hangers incorporate the same metal-to-metal annulus seal found in the concentric bore tubing hanger system. It also incorporates two or more pockets in the tubing hanger body for communiLOCK RING cations to multiple tubing ACTUATING SLEEVE strings and multiple stab LOCKDOWN receptacles, to maintain RING control over downhole ANNULUS equipment (Figure 11.16). VALVE

Figure 11.14 Photo of the male stab sub.

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Tubing hanger orientation on multi bore tubing hanger systems is accomplished with a keyed Tubing Hanger Running Tool and a slot in the wellhead connector on the BOP stack. An alternative method for orientation is with a cammed groove on the Tubing Hanger Running Tool OD, which interfaces

WEIGHT SET METAL-TOMETAL SEAL ASSEMBLY

Figure 11.15 Illustration of a concentric bore tubing hanger for subsea wellhead completions. ®


TUBING HANGER RUNNING TOOL LOCKING PROFILE

with a pin in a BOP stack outlet. If the following conditions exist, the ability for the concentric bore tubing hanger to accommodate the design parameters are exceeded. 1. Several downhole safety valves are required and/or a pressure balanced valve exists. 2. Large volume requirements are necessary for annulus access. The multi bore tubing hanger allows the operator to enter the annulus from directly overhead through an annulus bore in the tree to the tubing hanger and tubing/equipment downhole. This capability makes the tubing hanger orientation specific with respect to the tree. This also means that the completion tree will require a specific design orientation and a specific orientation to the tubing hanger during installation. 1. The multi bore tubing hanger can accommodate several communication lines downhole with stab subs between the tree and the tubing hanger. Special downhole sensors, etc., are accommodated in the same way.

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LOCK RING ACTUATING SLEEVE LOCKDOWN RING ADJUSTING RING ANNULUS BORE PRODUCTION BORE

WEIGHT SET METAL-TOMETAL SEAL

Figure 11.16 Illustration of a multibore tubing hanger.

TEMPERATURE SENSING CONNECTION

PRESSURE BALANCED SCSSV

ANNULUS ACCESS BORE

PRODUCTION ANNULUS

2. The multi bore tubing hanger is a more complex system because of the downhole specifications and the workover scenario demanding direct overhead annulus access. 3. The multi bore tubing hanger system supports a completion tree which provides the operator with full annulus access from directly overhead. The tubing hanger and tree become orientation specific and provisions must be made for this in the design phase and operational phase.

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Figure 11.17 Top view of a Concentric Bore Tubing Hanger.

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TUBING THREADS

LOCK SLEEVE ACTUATOR

DOWNSHOLE ACCESS PORTS (SCSSV's) CHEMICAL INJECTION, ETC.

LEFT HAND RUNNING THREADS

Figure 11.18 Illustration of a mechanical (threaded) concentric bore Tubing Hanger Running Tool.

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The Tubing Hanger Running Tool The hydraulically actuated Tubing Hanger Running Tool is designed to provide full-tubing-bore access and control of downhole functions while running and retrieving the tubing hanger. The tubing hanger running tool will be tubing hanger specific and must be designed to mimic the completion tree. It will be required to perform the following functions: • Engage and release from the tubing hanger body (either mechanically threaded or hydraulically) • Set annulus seal assembly and lock tubing hanger down • Pressure test annulus seal and stab sub seals • Provide full bore access for any suspended tubing strings • Provide the hydraulic conduit for operation of SCSSV's during the setting of the tubing hanger in place. The tubing hanger running tool can lock mechanically (Figure 11.18) or hydraulically (Figure 11.22) to the tubing hanger. If the tubing hanger is multi-bore, an index slot in the activating sleeve of the tubing hanger orients the running tool prior to engagement of the stab subs into the tubing hanger body. In operation, hydraulic pressure forces the outer sleeve of the running tool down against the top of the activating sleeve of the tubing hanger. This downward movement of the activating sleeve forces lock dogs in the tubing hanger outward into a locking groove in the casing hanger. When these dogs are in position, ratchet-type latches engage the activating sleeve. This retains the tubing hanger in a locked position. To unlock the tubing hanger, these locking latches must be released. Release occurs when pins holding the latches in place are sheared as the running tool raises the activating sleeve. This action releases the entire tubing

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PRESSURE IS MAINTAINED ON THE OPEN FUNCTION OF THE DOWNHOLE SAFETY PRIOR TO LANDING THE TUBING HANGER

LOCK RING LOCKS RUNNING TOOL TO TUBING HANGER

MALE STAB SUB SUPPLIES PATH FOR HYDRAULIC CONTROL FOR DOWN HOLE EQUIPMENT AND FUNCTIONS IN THE TUBING HANGER

ANNULUS SEALING SYSTEM IS WEIGHT SET METAL-TO-METAL SEAL

R£¥£TR ¥£TR£R¥T ¥T£R¥£TR ¥£TR


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Figure 11.19 Tubing Hanger Landed in Wellhead ®

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R£¥£TR¢Q,¤¢SQ, £R¥T¥£TR£R¥T¤¢SQ,¤S ¥T£R¥£TR ¥£TR


PRESSURE IS MAINTAINED ON SCSSV

PRESSURE IS APPLIED TO TUBING HANGER LOCK DOWN FUNCTION OF RUNNING TOOL

RUNNING TOOL LOCK RING ACTUATOR DRIVES TUBING HANGER LOCK RING ACTUATOR DOWN

TUBING HANGER LOCKDOWN RING MOVES OUT, LOCKING TUBING HANGER TO WELLHEAD

Figure 11.20 Lock Tubing Hanger To Wellhead

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R£¥£TR¢Q,¤¢SQ, ¥£TR¥£TR,Q¢¤¢SQ,¤¢SQ,


APPLY PRESSURE TO UNLOCK RUNNING TOOL FROM TUBING HANGER

LOCKING SLEEVE MOVES UP UNLOCKING RUNNING TOOL FROM TUBING HANGER

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RELEASE PRESSURE TO SCSSV PRIOR TO RUNNING TOOL RETRIEVAL

CLOSE ANNULUS VALVE THROUGH ANNULUS VALVE, CLOSE HYDRAULIC FUNCTION IN TOOL

Figure 11.21 Unlock Running Tool From Tubing Hanger ®

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TUBING RUNNING STRING

COMPLETION RISER

CONTROL HOSES

hanger/running tool assembly from the wellhead for retrieval (see Figure 11.19 to 11.21). If the tubing hanger is concentric bore, the running tool will cross over to tubing to the surface. Hydraulic control lines and umbilical attach to the top of the tubing hanger running tool to maintain control over the locking function of the running tool and any downhole equipment in the tubing string. This hose bundle will be strapped to the tubing running string. If the tubing hanger is multi bore, the running string of choice will be completion riser. Completion riser is discussed in detail later in this chapter. If the completion tree application is a stand-alone, (i.e. not part of a large scale completion installation of three or more trees) it is possible to run the multi bore tubing hanger on tubing with the control bundle being strapped to the tubing running strings.

TUBING HANGER LOCK RING ACTUATOR

RUNNING TOOL LOCK RING

MALE STAB SUB

Figure 11.22 Illustration of hydraulic Tubing Hanger Running Tool.

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Because of the number of tasks the tubing hanger running tool must accomplish, a number of hydraulic control lines are required for the operation and pressure test functions of the tubing hanger running tool. These hydraulic control lines will be run in a bundle attached to the drill pipe or tubing running string as the tubing hanger is run. Sometimes a custom built completion riser will be used, which has integral tubing strings and control lines inside a steel tubular housing. Completion riser usually comes in 40' or 50' lengths with special pin and box couplings that are mechanically locked together. The tubing strings and control lines have male and female stab subs that are aligned and made up as each completion joint is added to the running string. The completion riser approach to running tubing hangers is probably the most efficient and operationally easy method, but is expensive, and the internal dimensions of the drilling riser and BOP stack may limit the size of completion riser connector, which in turn limits the number of through bores it can accommodate. ®


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Completion riser is also used to lower the subsea tree into position, so it can be a very versatile product if all the pressure, control and through bore requirements can be achieved within an imposed design envelope. Running Tubing and Tubing Hanger As previously stated the tubing string and attached tubing hanger will be run within the protection of the drilling marine riser and subsea BOP stack. The production zone will have been perforated and a full completion fluid column established. A conditioning trip will have been made with a downhole assembly, including a bit, and possibly a casing roller if a downhole completion packer has to pass through a perforated section of casing. The tubing string(s) will almost certainly include an array of tubing plug profiles, a sliding sleeve for circulation, a mechanical or hydraulic set packer, plus the SCSSV. Additional complexity would arise if electric downhole pressure and/or temperature sensors were included in the completion. The space out of these components has to be performed carefully as they will all be suspended from a mandrel type tubing hanger with no means of vertical adjustment (Figure 11.23). Completion Tree Configurations Once the tubing hanger system has been specified, the tree design can be finalized. The main design parameter will be to build the tree around the tubing hanger system. The largest portion of the tree that this affects, is the tree valving and tree top. The overall function of a subsea completion tree is to provide a pressure tight termination to the completed subsea well with manual or remotely operated valves that open and shut on the production and annulus bores through the tree. The basic configuration and function of a subsea tree is very similar to a tree installed on a surface wellhead with ®

Figure 11.23 Preparing the tubing hanger and Tubing Hanger Running Tool for installation.

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a similar downhole tubing configuration and similar production or injection requirements. The major differences between subsea and surface trees generally relate to the underwater installation; the remote control of the subsea tree; and the demand for remote read out information, concerning bore pressures, bore temperatures and valve position indicators. The main purpose of the completion or production tree is to provide an ability to shut in the well at the subsea wellhead. The tree is therefore a series of valves equipped to be locked to the wellhead OD, interfacing with the tubing hanger bores below and connecting outboard to subsea flow lines at the sea bed. A tree manifold at the top provides a junction point for all control functions and an interface for the tree running tool during installation and reentry for workover. Tree types range from a simple diver-assisted tree to the more complex TFL completion tree. To understand the various tree configurations, the following general categories have been summarized and their features highlighted: Category 1. 11.24).

Simple diver-assist completion tree (Figure

• Used in shallow waters only • Wellhead/tree connector may be simple API connection or equivalent, manual make-up or hydraulically actuated • Tubing hanger system is simple concentric bore • Low volume annulus access • Valves are stacked • Tree cap/manifold is API connection and manifold is diver-assist • Control system is direct hydraulic (depending on location of tree relative to production station) 234

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• Flow line connection is simple flanged or misalignment union and flange connection Category 1 generally incorporates trees that will be installed on wells that have been drilled with a jack-up. Category 2.

Simple diver-assist completion tree.

• Used in shallow waters only • Wellhead/tree connector will be subsea wellhead profile, manual make-up or hydraulically actuated • Tubing hanger system is concentric bore • Low volume annulus access • Valves are stacked • Tree cap/manifold is API connection and manifold is diver-assist

Figure 11.25 Photo of a simple subsea tree for mudline suspended wells.

• Control system is direct hydraulic (depending on location of tree relative to production station) • Flow line connection is simple flanged or misalignment union and flange connection Category 2 includes trees that will be installed on wells that have been drilled with a floater in shallow water.

SWAB VALVE

INJECTION WING VALVE UPPER MASTER VALVE

Category 3. Diver-assist/non-diver completion tree.

LOWER MASTER VALVE

• Used in shallow to deeper waters • Wellhead/tree connector will be hydraulically actuated with either a drilling wellhead connector (such as the DX wellhead connector), or some variation which meets bending criteria • Tubing hanger system is either concentric bore or multi

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PRODUCTION WING VALVE

TUBING HANGER ADAPTER

WELLHEAD OR TUBING HEAD CONNECTOR

Figure 11.24 Diagram of a simple diver assist subsea tree for shallow water

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SWAB VALVE TREE CAP INJECTION WING VALVE

INJECTION LINE LOWER MANUAL MASTER GUIDE FRAME

PRODUCTION WING UPPER FSC MASTER VALVE ANNULUS WING VALVES PRODUCTION FLOWLINE

WELLHEAD CONNECTOR TUBING HANGER ADAPTER

Figure 11.26 Diagram of a simple subsea tree using stack valve configuration

bore with annulus valve • Annulus access is for monitoring and/or pump down • Valve Block • Tree cap/manifold is API connection and manifold is more complex diver-assist or an integral part of the tree cap • Control system can be direct hydraulic (depending on location of tree relative to production station), but will more than likely be sequenced hydraulic or electro/ hydraulic • Flow line connection is misalignment union and flange connection, Remote pull-in, or lay-away Category 3 incorporates wells drilled with a floater in shallow to moderate water depths Category 4.

Through-Flow Line (TFL)

• Used in deeper waters • Wellhead/tree connector will be hydraulically actuated wellhead connector (such as the DX wellhead connector) • Tubing hanger system is multi bore (multi bore is requirement for TFL workover) • Valve Block • Wye Spool • Tree cap/manifold is complex diver-less unitized and automatic

Figure 11.27 Photo of simple subsea tree for shallow to moderate water depths

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• Control system will more than likely be sequenced hydraulic, electro/hydraulic, or multi-plexed • Flow line connection is remote pull-in, or lay-away ®


FSC SWAB VALVE

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TREE CAP AND MANIFOLD

Category 4 incorporates wells that have been drilled with a FSC ANNULUS floater, and incorporate the SWAB VALVES capability for workover from FSC FSC ANNULUS the production station. TFL LOWER MASTER MASTER VALVES refers to the ability to pass tools through the production or annulus flow line, through the tree and tubing hanger to Figure 11.28 Diagram of a subsea a pre-determined point tree designed for moderate water depths downhole. While this capability is unique, there is a large economic sacrifice from the tree design standpoint. Additionally, through-flow line workover has historically met with varying results suggest this tree type is not a possible alternative for this application. FSC WING VALVE FSC UPPER MASTER

In order to better understand the completion tree and its components, the following modules are presented: • Tree/Wellhead Connector • Tree Guide Frame • Gate Valves and Valve Blocks • Tree Cap/Manifold • Tree Running Tools • Flow line Connections • Control System Tree/Wellhead Connectors The subsea tree connector is the bottom component of the tree and locks and seals to the completed tubing head or subsea wellhead housing. The connector will support a male stab sub which estab®

SWAB VALVE BLOCK W/ FSC PRODUCTION SWAB AND ANNULUS SWAB VALVES

MASTER VALVE BLOCK W/ FSC PRODUCTION UPPER MASTER AND LOWER MASTER VALVES

Figure 11.29 Photo of a moderate water depth subsea tree.

FSO CROSSOVER GATE VALVE

PRODUCTION AND SERVICE LINE FLOW LOOPS

FSC ANNULUS MASTER

WELLHEAD CONNECTOR

Figure 11.30 Diagram of a through-flow line (TFL) tree.

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lishes communications between the tree and tubing hanger. The connector size depends on the tubing head or subsea wellhead size and valve block size. There are a number of tree connectors that can be used to attach a subsea tree to the well. An API connection or equivalent is used to make up a simple subsea tree to a tubing head. The QUIK-CLAMP Connector™ is a manually operated, diver assisted make-up connector. Six make-up bolts pull a locking cam ring up which drive a split lock ring in around the tubing head profile. The connector carries a metal ring gasket which serves to achieve a metal-to-metal seal between the tree and tubing head.

Figure 11.31 Photo of a throughflow line (TFL) tree.

API CONNECTOR FOR VALVES

MAKE-UP BOLT (8) CAM RING LOCKING RING RING GASKET MALE STAB SUB

Figure 11.32 Illustration of the manual QUIK CLAMP tree connector.

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The QUIK-CLAMP Connector (Figure 11.32) is also available with hydraulic actuation. The locking ring is driven into the locking profile with an annular piston/cam ring. This design can also be used as the connector for the tree cap and connector for the Tree Running Tool. The DRIL-QUIP DX Subsea Wellhead Connector (Figure 11.33) hydraulically locks to and energizes a metal to metal seal (DX) between tree and wellhead (in the same manner as the BOP stack). Variations include manually actuated connectors for diver operation and other mechanical units actuated by hydraulic running tools. More information about the DX Connector is found in Chapter 2 of this manual. The connector body houses mechanical and hydraulic operating components and the top adapter will terminate with an API interface between itself and the valve section. As an alternative, the upper body of the wellhead connector can be a unitized component of the valve block. In this case the gasket is retained in the top adapter flange/master valve block assembly, and seals between the wellhead housing and a preparation in the master valve block (Refer to Figure 11.45 later in this chapter). This is unlike a con®


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ventional DX connector where the gasket seals in the top adapter. The unitized tree connector/valve block design eliminates one high-pressure seal and reduces the overall height of the tree. An important feature of the DX Wellhead Connector is the two step metal-to-metal sealing profile. The emergency second step is comforting when installing a subsea tree on a subsea well that has experienced a washout on the primary sealing area. This possibility is all to common on a subsea well that is being prepared for completion. Two separate distinct hydraulic systems are used to actuate the lock/release mechanism of the connector. The primary system locks and release, while the secondary system is used exclusively to release the connector. Tree Guide Frame The tree guide frame is attached to the outer body of the tree connector in a predetermined orientation, so that the guide arms and cones integrated into the tree frame structure will provide the required subsea tree orientation as it is lowered over the four post guide LOCKING SEGMENTS structure. By this means the stab ANNULAR subs carried in the PISTON/CAM tree connector RING will be correctly aligned with the SPREADER SEGMENTS seal pockets in the tubing hanger, SECONDARY which was oriUNLOCK ented when it was PISTON landed during the well completion. The tree guide Figure 11.33 Illustration of the DX frame may also tree connector. This connector is also used for drilling the subsea well. ®

Figure 11.34 Making up the QUIKCLAMP Connector.

Figure 11.35 Testing the tree connector.

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SEAL AREA (Metal-to-metal) SEAL AREA (Metal-to-metal)

STANDARD GASKET

BACKUP GASKET SEAL AREA (Metal-to-metal)

SEAL AREA (Metal-to-metal)

Figure 11.36 Illustration of the two step metal-to-metal DX ring gasket profile.

Figure 11.37 Photo of a subsea tree with a guide frame that incorporates a walk way for a special diver.

provide the support for the control pod base plate, the flow line connections, and a work platform. Gate Valves and Valve Blocks In shallow waters, such as mudline suspended wells drilled with a jack-up, the valving arrangement consists of stack valves of either manual (diver-assisted), hydraulic or a combination of both. The stacked-valve arrangement can only be used when the tubing hanger system is concentric bore. In modern subsea trees the valve cavities for the production and annulus bores are machined directly into a forged metal block. The use of an integral valve block, instead of stacked valves, provides a stronger assembly and also cuts down on the number of potential leak paths in the tree. Also, it gives the tree designer the benefit of moving the center lines of the tree bores closer together so that the largest production tubing can be squeezed into the confining envelope of the production casing bore used below the tubing hanger. The various valve operators may be installed in pockets machined in an integral valve block. The valve block will incorporate either manual actuators, hydraulic actuators or a combination of both. It may also incorporate one bore (production) in cases where concentric bore tubing hangers were selected, or several bores if the multi bore tubing hanger is used. The gate valves used in these underwater valve blocks have become extremely reliable with extended service lives. Features of these modern production valves are metal-tometal sealing of the gate to seat; metal-to-metal sealing of the stem with the stem packing; and full pressure sealing of the stem in its back seated position.

Figure 11.38 Installing gate valve seat seals, inner gate and gate guides in a valve block.

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The subsea gate valve used on subsea trees is generally a hydraulically operated valve, with a spring-loaded fail-safe close (FSC) capability. The valve is opened and held open ®


by hydraulic control pressure acting on the hydraulic piston within the valve operator attached to the valve. If control pressure is removed, or fails, the spring force of the spring cartridge within the valve operator will move the stem and attached gate to the closed position. Other features of subsea gate valves and operators include manual override capability to open or close the valve with diver assistance or remotely-operated vehicle (ROV) interface and valve position indication that can be visually observed or electronically sensed. The minimum valve requirement for subsea trees will include a lower master, a wing, and a swab valve for a single bore tree. Completion trees with an annulus bore for direct overhead access to the annulus will also include a lower master, wing and swab valve. UPPER

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HANDWHEEL BEARING AND RACE ASSEMBLY NON-RISING STEM SEAT SEAL ASSEMBLY

GATE GATE GUIDES

Figure 11.39 Illustration of a manually operated metal-to-metal sealing gate valve.

STEM BEARING AND RACE ASSEMBLY FAIL-SAFE RETURN SPRING

ACTUATOR PISTON SEAT SEAL ASSEMBLY

GATE GATE GUIDES

Figure 11.40 Illustration of an hydraulically actuated Series DH failsafe close gate valve.

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Corrosive service trim for subsea gate valves is also becoming standard practice, particularly if carbon dioxide or hydrogen sulfide gases are anticipated sooner or later in the service life of the tree. The special trims usually consist of particular metal alloy overlays on the parent metal, such as stainless steel, inconel, tungsten carbide, stellite, etc. The performance of the gate valves on the subsea tree is of utmost importance to the pressure control of the well, particularly if a catastrophic accident severs the sea floor flow lines or control hose bundle. The doubling up of the valves in the production

Figure 11.41 Installing an hydraulically actuated gate valve in a valve block.

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FSC HYDRAULIC SWAB W/MANUAL OVERRIDE FSC HYDRAULIC UPPER MASTER W/ MANUAL OVERRIDE WING OUTLET MANUAL LOWER MASTER

HYDRAULIC QUIK-CLAMP TREE CONNECTOR

MALE STAB SUB

bores of the subsea trees adds another level of safety in the control of the well. Modern subsea tree valve blocks not only have the production and annulus master valves in them but also the swab valves and sometimes the wing valves are integrated into the block. This style of tree block requires very long and heavy forgings and the machining of bores and valve pockets has to be done with great accuracy.

Wing Valves The wing valves are generFigure 11.42 Illustration of a simple diver assist single bore tree with valve bloc. ally hydraulically and/or manually operated gate valves that are connected to the studded tee portion of the tree and flowline spool. They can also be manufactured as a spool that is connected to the master valve block with flanged or clamped connections. Dual production wing PRODUCTION BORE gate valves are included on most modern subsea trees. ANNULUS BORE

Figure 11.43 Illustration of a wyespool found on TFL trees.

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On subsea trees designed with through-flow line (TFL) capability, this section of the tree will become a wye-spool with smooth angled entry providing the interconnecting link between the tree production bores and the TFL production and service flow loops. The pump down tools and locomotives pass through the flow loops and into the production bore. They are recovered by reversing the hydraulic flow and pumping the TFL train out of the production bore. In order that the returned TFL tools do not try to exit vertically through the swab valve, a deflector or flow diverter is installed in the wye-spool. This flow diverter can ®


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be an automatic device, or remotely and/or manually operated. The number of TFL subsea trees installed is very small, and the number of these trees actually used in a TFL mode is even smaller. In other words it has not become a popular design and has proven very costly and difficult to maintain and operate. Swab Valves Re-entries to subsea trees through the top of the tree are done through the swab valve. This means that downhole work in the production tubing, such as replacing inserts in sub-surface safety valves and installing tubing plugs in selected downhole profiles, is being accomplished with conventional wireline tools. The conduit for the downhole wireline tools can be provided by tubing, drill pipe, or completion riser that is connected to the top of the tree by a floating production service vessel or drilling vessel. There have been a few successful vertical re-entries to subsea trees using an underwater wireline lubricator. Figure 11.45 shows the next part of the tree including the swab valves, tree running mandrel, and the hydraulic line manifold for the tree functions. The swab valves are hydraulically and/or manually operated gate valves that can only be opened and closed when the tree is connected vertically through a running or re-entry mode. In other words these swab valves are never controlled remotely through the platform based or shore based control system, as an obvious safety precaution against accidental opening when the well is on production. Quite often a tubing plug profile is included in each tree bore section directly above the swab valve or valves. Flow Loops and Crossover Valve The steel flow line loops on subsea trees generally have smooth curves so that the production flow from the well causes as little erosive or abrasive wear as possible. Also, the loops which may be TFL are generally designed with ®

Function testing the ROV interface

ROV interface panel on a complex dual bore tree

ANNULUS FLOW LOOP LINE

PRODUCTION FLOW LOOP LINE

Figure 11.44 Illustration of a TFL tree and the flow loops that are unique to TFL trees

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some flex capability which may be utilized during subsea flow line connections to the subsea tree. The flow loops will also be interconnected with a crossover pipe and gate valve. This crossover gate valve is a hydraulically and/or manually controlled valve usually designed with a fail-safe open (FSO) operator. The crossover valve is used when the subsea flow lines have been installed, so that the flow lines can be pigged and flushed in either direction from the platform or shore based production facility. It can also be used when the well is on production, in the open mode, to allow the production to use TREE CAP MANDREL an alternative flow path if damage or maintenance requirements have closed TREE CAP the main production flow line. TREE MANIFOLD FSC ANNULUS SWAB FSC PRODUCTION SWAP

FSC ANNULUS WING FSC ANNULUS LOWER MASTER TREE CONNECTOR

FSC PRODUCTION WING

FSC PRODUCTION LOWER MASTER GUIDE FLANGE

FLOW LINE

PRODUCTION AND ANNULUS FLOWLINE CONNECTORS

Figure 11.45 Illustration of a typical multi-bore subsea tree.

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Wing outlets are often interconnected by a crossover valve either inboard or outboard of the wing valves. The crossover valve is usually fail safe open (FSO) if located outboard of the wing valves as on TFL trees. This permits circulation through the flow lines to the tree without operating a control function on the tree. However, when inboard, the wing valves are fail safe closed. This permits diverting production through the alternate annulus or service flow line if the normal production flow lines are damaged. This alternate ®


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ALIGNMENT PIN

flow path also allows flow testing of an individual well when the normal production flow line is tied to a manifold system which combines flow from several wells into a common production header. Number and sizes depend on the tubing program, number of strings, whether annulus access is provided or not, and special features required like chemical injection, etc., Material used depends on produced fluid. For example service in high concentrations of H2S/CO2 requires stainless steel valve bodies. Tree Manifold The tree manifold provides the control line stab receptacles and outlets that are connected to each hydraulic function on the subsea tree. The tree running tool has stab subs that mate with the stab receptacles or seal faces on the tree manifold which allows direct hydraulic control of the subsea tree through the control line umbilical run with the tree running string.

TREE CAP RUNNING MANDREL

STAB RECEPTACLES

Figure 11.46 Illustration of the tree cap and tree manifold of a typical subsea tree.

The hydraulic connections, or tree plumbing, are usually done with stainless steel tubing. Each open or close port on a valve operator or each lock or release function on the tree connector will be connected to a specified port on the tree manifold. Also, other hydraulic lines will come from the tree manifold to the control pod base plate. These other lines will permit remote control of selected tree functions from the remote control station. The tree cap also mates with the tree manifold so that the tree functions can be operated remotely from the production or shore based production facility through the sea floor control line bundle. This subject will be covered in more detail in the section on remote control of the subsea tree.

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Figure 11.47 Photo of the lower stab receptacles, a component of the tree manifold.

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Tree Cap The basic function of the tree cap is to provide a sealing cap that blocks to the tree running profile. It is usually run down to position with the tree running tool. The tree cap also protects the seal surfaces at the top of the tree and also protects the exposed surfaces of the tree manifold. The tree cap may also have internal hydraulic lines or conduits that provide an interconnection between control ports of the tree manifold. These interconnections are required so that the hydraulic control fluid from the remote platform or shore based facility is directed to the required tree function. The tree cap has the same upper profile as the tree. Some tree functions can be controlled through the tree cap when it is locked and mated to the tree and tree manifold. This ability to control the tree through a vertical connection as well as through the subsea control line umbilical requires the use of shuttle valves which are mounted on the tree cap. The size of the tree cap can obviously vary considerably depending on the number of accessories and auxiliary functions it INDICATOR ROD

METAL-TO-METAL SEALING RING GASKET ALIGNMENT PIN

HYDRAULIC CAM RING

CONTROL STAB RECEPTACLES LOCK RING

Figure 11.48 Illustration of a typical tree cap which uses the hydraulic Quik-Clamp locking system.

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is expected to carry. For guidance and balance purposes, the use of a four armed guide frame with guide cones is sometimes required.

Tree Running Tool The tree running tool will be designed and built to perform the following functions: • Lock onto and release from the tree running mandrel • Provide an upper connection or connections for the tree running string, be it tubing, drill pipe or completion riser • Provide direct vertical access into the production and annulus bores in the tree • Carry the control line stab subs that interface with the matching seal receptacles or seal faces on the tree manifold • Run the Tree Cap The tree running tool is a multiple use tool, used in running and retrieving the tree, tree cap, or the electro-hydraulic control pod. The tool is run either on a tubing string, on drill pipe with a control hose bundle, or a completion riser. The top of the tool is a modified pin connector which mates to tubing or the completion riser. The tool has an internal mechanism which locks onto the tree manifold or the tree cap. The body of the tool can contain multiple hydraulic stabs which mate to the tree manifold ports to supply hydraulic power for all lock/unlock and open/close functions on the tree. The running tool locks and unlocks the tree cap through the integral control lines of the completion riser or the control

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Figure 11.49 Photo sequence of fit and function of the tree running tool.

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hose bundle. When locked to the tree manifold, the running tool can provide direct surface control of up to nine tree functions through the control lines in the completion riser. In addition, direct vertical access is provided to the tubing bores and the annulus. If individual control of the tree functions is desired, in addition to those functions controlled through the completion riser, a separate hose bundle is required. Flow line and Control Line Connections The installation of sea floor flow lines and control lines to subsea trees is a complex subject. The following notes are intended to give a brief understanding of the subject, and to describe the main components and their operation.

Platform control umbilical connection at the tree

The function of the sea floor flow line or flow lines is to provide transportation for the subsea oil or gas from the subsea tree to a remote platform or shore based production facility. Sometimes the flow lines connect the subsea tree to a subsea gathering manifold or to the base of an anchored floating production vessel or loading buoy. CROSSOVER SUB/STRESS JOINT

The function of the control lines, usually encased in an armored multi-core umbilical, is to provide hydraulic and/or TWO ARMED GUIDE electric power and pilot signals STRUCTURE to the control pod on the tree, which in turn directs the hydraulic fluid to the required tree functions. CAM RING SPLIT LOCK RING The control line umbilical is Figure 11.50 Illustration of a typical tree and tree cap usually run in running tool.

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conjunction with the sea floor flow lines. Flow line Connections The underwater make-up of fluid connections or electrical connections is associated with a certain risk. Subsea electrical connectors in particular have been prone to immediate failure and limited reliability. Needless to say a great deal of effort has been directed at this problem area, and improvements have been achieved in the direct contact connectors using special wiper mechanisms, fluids, and greases. The most effective underwater electrical power or electric signal connections appear to be those that use inductive couplers which avoid the requirement for direct electrical contact. With these problems in mind, the tree and the flow line bundle require a specially designed end connection to mate with, and lock to, the matching connection on the tree. This end connection can be a seal plate with seal pockets or stab subs that are pulled into position using a pull-in cable and/ or hydraulic power from a special pull-in tool. The sophistication of these end connections will also depend on the amount of diver assistance required, or desired, to establish the flow line control line connection. Sometimes the water depth precludes the use of diver assistance. In all cases underwater television cameras would monitor the event, and in the installations using remotely-operated vehicles (ROV’s) their presence is essential. Various options in the sequence of tree installation and flow line connections are usually available. The flow line and control umbilicals can be connected to a flow line receptacle structure that is incorporated into the four post guide structure before the tree is run. If flexible flow lines are being used rather than the more rigid steel flow lines, then it is possible to make the first end connections of the flow lines and control lines to the tree before it is lowered to the sea

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floor. This procedure has been used offshore in Brazil and as the subsea tree is lowered to the subsea wellhead, a special pipe laying vessel controls the spooling out of the flow line bundle. The benefit of this approach is that all connections are done under optimum conditions and the use of divers and flow line pull-in equipment is avoided. The pipe laying vessel will continue to spool out the underwater flow line bundle until it reaches the location of the second end connection.

PRODUCTION BORE ELECTRICAL CONNECTIONS ANNULUS BORE SERVICE BORE

Figure 11.51 Illustration of a complex flow line connector.

When the flow lines are connected to the tree, a series of pressure tests and control line umbilical tests will be conducted. Also, the flow line or flow lines will be pigged and circulated to ensure that no damage, kinks, or restrictions have occurred during the flow line laying and connection operations. Assuming that all pressure tests are satisfactory, and the remote control of the tree functions is successful, the interface equipment from the surface installation vessel will be recovered, and the well is ready to go on production. Flow line connections on subsea trees generally fall into four categories: 1. Simple diver-assist flange or diver-assist misalignment union 2. Hydraulic diverless flow line connector 3. Remote flow line pull-in 4. Flow line lay-away Diver-assist Flange or Misalignment Union A diver assist flow line connection has misalignment flanges with +/-10 degrees angular adjustment to ease flow line make up. These flowline connections will generally be found on subsea trees on mudline suspended wells and shallow water trees on subsea wellheads.

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Hydraulic Diverless Flow Line Connector The diverless flow line flange requires a flowline alignment structure (FAS) to be installed on the subsea wellhead guidebase before installation of the tree. Vertical stab flow line connections have been used on satellite and template trees. Two advantages result. Most important is that the flow line connection is automatically made as the tree is landed. Another is that the angle of approach of a single flow line in the horizontal plane can vary more because its termination has a vertical axis allowing rotation without consequence. The main drawback is that the flow line must be connected to the wellhead before the tree is run. Remote Flow line Pull-in Used with subsea trees beyond diver depths, the remote flow line pull-in system involves a special hydraulically actuated flow line and production umbilical pull-in tool. One end of a tag line is attached to the tool on the surface, while the other end is attached to the flow line on the sea bed. Using two guidelines, the tool is run on drill pipe to the completion tree. Special hydraulic actuators pull the flow line up to a connection plate. The tool performs final alignment and connects the flow line to the tree. Piping between the wing valves and the flow line connection may need spring and flexibility. Large loops with minimum 5 foot radius bend are necessary for TFL trees to permit passage of knuckle jointed tool trains. The Completion Riser The 5" x 2" - 10,000 psi Riser Joints are part of the dual bore workover/completion riser system. They are used to run the EDP/LRP and tubing hanger running/orientation joint and have a maximum rated tensile capacity of 500,000 lbs.

Figure 11.52 Illustration of a misalignment union.

Figure 11.53 Photo of a typical flow line.

The riser joints have a dual bore design. One bore is the 5" production line which is the main load carrying member. The second bore is the 2" annulus line. It provides commu-

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nication to the annulus bore but does not support any of the riser loads. Each riser joint has a connection that is compatible with all other riser connections in the system. The joints are fitted with clamps which can accommodate both the tubing hanger and workover umbilicals. The joints land out securely in both the manual and hydraulic riser spiders. Sealing throughout the riser systems is achieved with elastomeric polypak type seals. Sealing areas are hard faced. Other areas are coated for corrosion protection. In addition to standard 45 ft. riser joints, there are 20 ft., 10 ft., and 5 ft. pup joints. These pup joints allow for optimal space-out. Figure 11.54 Hydraulic flow line connector

Figure 11.55 Photograph of a subsea tree with a diverless flowline connector.

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Running the Subsea Tree Prior to running the subsea tree, the tree will be locked to a test stump and each function will be operated and pressure tested the same way as a subsea BOP stack is tested before it enters the water. The running tool will be connected to the tree running profile during this testing operation. After the production tests, the master production and swab valves will be closed and the tree running tool will be released from the tree running profile and be suspended before flow lines were connected to the tree,

Figure 11.56 Illustration of a remote flow line pull-in system

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then tubing plugs will be set in the tubing hanger bores and possibly in the plug profiles in the bores above each swab valve.

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ALIGNMENT KEY SLOT RISER BOX RISER PIN CONNECTION F/ CONNECTION ANNULUS BORE F/PRODUCTION BORE

Subsea Dual Bore Completion System RETAINER RETAINER RING As previously discussed in this chapter, a dual bore comple- RING tion system uses a multibore type tubing hanger that is used RISER when vertical access to the annulus and production bores CLAMP are required. Orientation is necessary to align the producANULUS BORE PRODUCTION tion and annulus bores in the tubing hanger with those in BORE the tree to be installed as well as various stab/seals subs for ALIGNMENT downhole hydraulic valves and electrical sensors. In addiRING tion, the direction and location of the flow line exit from the RETAINER RING well in relation to the orientation of the production bore RISER PIN RISER BOX must be considered. The installation of the tubing hanger CONNECTION F/ CONNECTION and subsea tree will involve the use of several groups of ANNULUS BORE F/PRODUCTION BORE running tools and control equipment to facilitate compleFigure 11.57 Illustration of a typical tion. Installing the Tubing Hanger The tubing hanger (Figure 11.59, page 256) will be oriented and landed in a subsea wellhead provided there is a landing shoulder, sealing area, and provision to lock the tubing hanger to the wellhead. If no such provision exists in the wellhead, a tubing head with these features will need to be installed. The top of the wellhead/tubing head will provide a locking profile for attaching a blowout preventer stack for pressure control during completion operations. Generally, during the drilling phase of the well, a drilling guide base is used and then removed after landing and cementing the surface casing strings. The first step in preparing the well for completion will be installing a completion guide base which will provide guidance for installing the tree along with provisions for connecting a flow line and hydraulic control umbilical from the production platform. In general, the two types of flow line connection methods are diver/ ROV assist and diverless remote hydraulic.

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completion riser joint for a multi-bore subsea tree.

Hydraulic flowline connector integral to the tree frame

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The flowline connector can be part of the completion guide base and the tree guide frame. As illustrated in the photo, and in (Figure 11.73), the male mandrel of the flowline connector is on the completion guide base while the female portion is attached to the tree guide frame. Figure 11.58 Making up a completion riser connector.

Completion riser joints in shipping frame

When the rig is over location and a guidance system has been established, preparations for running the tubing hanger and completing the well can be made. In order to set the tubing hanger and complete the well, it will be necessary to establish some control dimensions to assure the hanger is set at the correct elevation and aligned properly. The first of these control dimensions is from the landing shoulder for the tubing hanger in the wellhead to the locking profile in the top of the wellhead. If the landing shoulder for the tubing hanger was set high, adjustments to the tubing hanger will be necessary. This dimension is generally established using a lead impression tool (Figure 11.64) that is run on drill pipe and lands on the tubing hanger landing shoulder. The top of the tool has retractable lead blocks that are activated by pumping pressure down the drill pipe forcing them out into the profile in the wellhead enabling retrieval of an exact dimension from the landing seat to the lock down profile in the wellhead. It will also establish orientation and elevation control data to enable checking the tubing hanger's elevation and orientation after it has landed to ensure alignment and proper make up with the tree. The tubing hanger systems consist of the tubing hanger and the equipment required to run and orient the hanger. These components are as follows: A hydraulic tubing hanger running tool that will lock the work string to the hanger, lock the hanger to the wellhead and provide vertical access to the annulus and production bores as well as maintain hydraulic

Dual Bore Tree, EDP, and LRP

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control of the downhole safety valve or valves. An orientation adapter joint (Figure 11.62) to connect the tubing hanger and tubing hanger running tool to the riser running string and provide a means of orienting the tubing hanger by interfacing with an orientation pin (Figure 11.63) located directly above the wellhead in the BOP stack. A control system to operate the hydraulic functions of the tubing hanger running tool and the hydraulic downhole equipment through a control umbilical. A completion riser system made up to lower the tubing hanger to the wellhead and provide access to the annulus and production bores and a structure to support attachment points for the control umbilical down to the tubing hanger running tool. This system will consist of a lower riser joint (Figure 11.60) connected to the top of the orientation adapter joint and subsequent riser joints to make up the required distance to TD.

Completion guide base

A surface joint (Figure 11.70) to protect the riser through the rotary, topped off with a circulation handling and test tool which has an integral elevator shoulder to facilitate lowering the tubing hanger orientation assembly into place as well as quick connections for the annulus and production bores so that circulation can be achieved by attaching lines. A hydraulic riser spider (Figure 11.74, page 268) will be used at the rotary to suspend the tubing hanger and riser running assembly as each joint of riser is made up while the tubing hanger and completion string is being run. A tubing hanger elevation check tool (Figure 11.66,

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Running the completion guide base

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LOCK DOWN RING ACTUATOR IN “SET POSITION”

DOWNHOLE PRESSURE AND TEMPERATURE LINE

ANNULUS BORE

DOWNHOLE SAFETY VALVE LINE

DOWNHOLE PRESSURE AND TEMPERATURE LINE

TUBING HANGER SEAL ASSEMBLY IN “SET” POSITION

LOCK DOWN RING ACTUATOR IN “RUNNING” POSITION

PRODUCTION BORE DOWNHOLE SAFETY VALVE LINE

LOCK DOWN RING

ADJUSTABLE LOCATOR RING

ANNULUS BORE PLUG PROFILE

ANNULUS BORE

PRODUCTION BORE PLUG PROFILE INDICATOR PIN GROOVED SHEAR PIN PRODUCTION BORE RETAINER RING

TUBING HANGER SEAL ASSEMBLY IN “RUNNING” POSITION

METAL-TO-METAL SEALS

Figure 11.59 Dual Bore Tubing Hanger Assembly 256

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page 260) to enable verification that the tubing hanger is all the way down on its landing shoulder and oriented properly. Prior to running the tubing hanger and production/ completion string, it is a common practice to run the spaceout of the completion string on a dummy tubing hanger. This hanger is simply a mimic of the tubing hanger body that is run on drill pipe with the completion string attached to insure proper space-out. The dummy hanger sets on the landing shoulder for the tubing hanger. The only hydraulic function for this operation is the downhole safety valve. The line passes through a slot in the side of the dummy hanger and is strapped to the drill pipe back to the surface. When the space-out of the completion string is correct, the dummy hanger is pulled back to the surface and removed. The completion string is then made up to the tubing hanger and suspended in the rotary on a tubing hanger rotary bushing (Figure 11.65) which allows for make up of all of the necessary downhole line connections to the tubing hanger. The tubing hanger is then run on its completion riser running assembly down through the drilling riser and BOP stack which is landed and locked to the wellhead. The tubing hanger is then tagged out on its landing shoulder with partial string weight. Prior to setting the weight-set seal assembly, the orientation pin on the BOP is extended so that it comes in contact with de OD of the orientation adapter joint. The tubing hanger running assembly is then picked up a short distance so that the orientation pin engages the helix on the orientation adapter joint and allows the tubing hanger and running assembly to orient to the vertical slot in the adapter joint which is preset to achieve the desired orientation of the production and annulus bore. With the orientation pin still extended, the ®

Measuring the lock ring elevation on the tubing hanger

Hydraulic orientation pin

ALIGNMENT KEY SLOT RISER BOX RISER PIN CONNECTION F/ CONNECTION ANNULUS BORE F/PRODUCTION BORE RETAINER RING

RETAINER RING

RISER CLAMP ANULUS BORE

PRODUCTION BORE ALIGNMENT RING RETAINER RING

RISER PIN CONNECTION F/ ANNULUS BORE

RISER BOX CONNECTION F/PRODUCTION BORE

Figure 11.60 Riser Joint

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ORIENTATION/ ELEVATION CHECK TOOL

FIGURE 11.62 ORIENTATION ADAPTER JOINT

FIGURE 11.63 BOP ORIENTATION PIN

FIGURE 11.61 TREE TEST BASE

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TUBING HANGER WASHOUT TOOL

TUBING HANGER

TUBING HANGER RUNNING TOOL

TUBING HANGER SEAL ASSEMBLY FIGURE 11.64 MULTI-PURPOSE TOOL WITH LEAD IMPRESSION BLOCKS

FIGURE 11.65 ROTARY TABLE BUSHING

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4-1/2" IF BOX CONNECTION

IMPRESSION BLOCK RETAINER SLEEVE

RETAINER NUT LEAD IMPRESSION BLOCK

SOCKET SET SCREW

IMPRESSION BLOCK ASSEMBLY

ORIENTATION LINE

LANDING JOINT LANDING HEAD INDICATOR PIN

ALIGNMENT KEY

Figure 11.66 Orientation/elevation check tool

tubing hanger is set back down on the landing shoulder with total string weight which will activate the tubing hanger seal assembly. After the seal has been tested, the tubing hanger is then hydraulically locked to the wellhead through the control function in the tubing hanger running tool. An overpull test will establish that the tubing hanger is locked to the wellhead. All downhole equipment is then tested and the wireline tubing hanger plugs for the annulus and production bores are run and set. The tubing hanger running tool is hydraulically unlocked from the tubing hanger and the tubing hanger running assembly is then pulled back through the rotary using the riser spider to suspend the balance of the string while each joint is disassembled and laid down. It is necessary, at this point, to find out if the tubing hanger and completion string were landed in the wellhead at the proper elevation and orientation to ensure that the production and annulus bore stab subs/seals in addition to the other downhole connection subs will properly make up with the bottom of the tee. This is accomplished by running the orientation/ elevation check tool on drill pipe and landing it on the top of the tubing hanger. When the tool has landed, it is rotated so that it sits down inside the top of the tubing hanger using spring loaded alignment keys matching those in the upper end of the hanger. In this respect, it is now an extension of the current orientation of the tubing hanger. Lead indicator pins on the lower landing shoulder of the elevation tool will indicate whether the tool has landed in the proper location.

Dual bore dummy tubing hanger

260

On the top of the elevation tool, there is another lead impression block which is clocked to the proper orientation position of the annulus and production bores. The elevation and orientation control data used to establish correct orientation were made earlier with the BOP stack sitting atop the tree test stand (Figure 11.61). When the tool is landed out, the orientation pin in the BOP stack is extended ®


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to make an impression in the lead block on the upper portion of the elevation check tool. The tool is then retrieved and the indicator pins on the bottom of the tool are examined to see that the tool landed in the right spot and the impression in the lead block at the top of the tool checked against the control impressions made previously to ensure proper alignment and elevation prior to running the tree. If all indications are that the tubing hanger is oriented and at the proper elevation and the annulus and production Hydraulic riser spider completion bore wireline plugs are set in the hanger, then the BOP stack and drilling riser are pulled in preparation for running the tree. Tubing Hanger Washout Tool A tubing hanger washout tool (Figure 11.67) is used to provide a means of cleaning out the upper portion of the wellhead prior to landing the tree so that the stab/seals subs in the wellhead around the top of the tubing hanger are clean, allowing complete make up and sealing to the seal/stab subs in the bottom of the tree. This tool is run on drill pipe and simply lands on the top of the wellhead. Fluid is then pumped down through the drill pipe to the tool where it exists through jet ports into the upper portion of the wellhead cleaning the top of the tubing hanger and exiting through the flowby ports in the top of the tool. After the washout process is complete, preparation for running the tree begins. The tree will be run down to the wellhead on completion riser utilizing a riser spider at the rotary to suspend the lower riser package and tree as each joint of riser is added to the running string. This riser stack up from the bottom up will consist of a tapered stress joint (Figure 11.68) that provides a means of connection to the lower riser package, completion riser joints making up the required length to TD, a tensioning joint (Figure 11.69) to keep the riser string in tension throughout the operation, a surface joint (Figure 11.70) to protect the riser through the rotary area and a surface tree ®

Tubing hanger washout tool

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Tubing Hanger Tagged with Orientation Pin Retracted

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Orientation Pin Extended, Tubing Hanger picked up while Orientation Joint Rotates

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Orientation Pin Stroked Out, Tubing Hanger Fully Orientated

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@,ÀÀ@,À@,À@,À@, À@,

Lock Tubing Hanger to Wellhead

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Tubing Hanger Running Tool Unlocked from Tubing Hanger

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Elevation Check Tool Landed With Orientation Pin Extended

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Introduction to Subsea Completions ANNULUS BOX CONNECTION PRODUCTION RISER PIN CONNECTION

ALIGNMENT RING STANDARD PRODUCTION RISER CONNECTION

ALIGNMENT RING

ANNULUS BORE

RISER CLAMP

PRODUCTION BORE

RADIAL BOLT PIN CONNECTION

HYDRAULIC ACTIVATING CYLINDER

LOCKING DOG ENGAGED

HINGE PIN

LOCKING DOG RETRACTED COVER PLATE

ROTARY ADAPTER ASSEMBLY

WEAR PLATE

BASE PLATE

Figure 11.74 Hydraulic spider

(Figure 11.71) to provide pressure control and controlled access to the production and annulus bores at the surface. This surface tree may also be equipped with wing valves on the production and annulus side to facilitate circulation down to the subsea tree. These valves can be manually or hydraulically actuated. Lower Riser Package/Emergency Disconnect Package A lower riser package (Figure 11.72), or LRP, will be attached to the bottom of the tapered stress joint for running the tree. There are three primary functions for this package, the first being redundant pressure control provided by hydraulically controlled valves in the production and annulus bores above the tree since a BOP stack is not used. The LRP consists of two components; the lower riser package containing the redundant valves for the tree and the upper portion being referred to as the EDP section, emergency disconnect package (Figure 11.73). The EDP provides the second primary function which is a means to disconnect from the tree/LRP should the rig need to be moved off location or excessive wave action dictates that the riser system be disconnected from the well. The EDP and the LRP are locked together and to the top of the tree with remotely operated hydraulic connectors. A

Figure 11.68 Tapered stress joint.

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4-1/2" IF BOX GUIDE POST FUNNEL ASSEMBLY LIFTING EYE

RELEASE BOLT

FLOW BY PARTS

DEBRIS SHIELD WASHING JETS RELEASE BOLT

SNAP RING

Figure 11.67 Tubing hanger washout tool

hydraulic control line umbilical is connected to the top of the EDP back to the surface and provides control for the connectors and valves in the LRP/EDP. Additional control lines pass through the EDP/LRP to operate the valves and bottom connector on the tree. The third function of the LRP is applicable if the valves in the LRP are designed to provide the ability to shear wireline or coil tubing that may be in use during the completion or workover operations.

Dual bore tree, LRP and EDP assembled for a function test

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Subsea Trees A typical subsea tree (Figure 11.75) provides features including a hydraulic connector at the bottom to lock the tree to the wellhead, seal pockets or stab sub receptacles in the bottom to interface with the tubing hanger annulus, production and downhole tool connections, a flow line connection system and hydraulic controls and accessories. Generally, all of the valves in the tree with the exception of the lower production master valve are hydraulically controlled with manual overrides which are adapted for actuation by an ROV. The lower production master valve will be manually operated and also equipped with the ROV actuation feature. During the "running the tree" operation, the valves are hydraulically controlled from the control umbilical connected to the EDP/LRP which passes the control fluid pressure down to the tree. Later in the operation when the tree cap is installed, the functions will 269

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TAPERED STRESS JOINT

FIGURE 11.73 EMERGENCY DISCONNECT PACKAGE (EDP)

FIGURE 11.72 LOWER RISER PACKAGE (LRP)

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FIGURE 11.70 SURFACE JOINT

FIGURE 11.71 SURFACE TREE

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RISER HANDLING, TEST AND CIRCULATION TOOL

SURFACE TREE ADAPTER JOINT

FIGURE 11.69 TENSION JOINT

HYDRAULIC RISER SPIDER

RISER JOINT

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Introduction to Subsea Completions STAB PLATE

TREE MANDERL

ALIGNMENT PIN TREE GUIDE FRAME

METHANOL INJECTION LINE ACCUMULATOR

PRODUCTION SWAB VALVE CROSSOVER VALVE UPPER PRODUCTION MASTER VALVE

PRODUCTION WING VALVE

ANNULUS WING VALVE

SSSV CONTROL LINE CONNECTION

VX GASKET TEST CONNECTION FLOWLINE ANODE

FLOWLINE DEBRIS COVER

DX CONNECTOR FLOWLINE CONNECTOR

Figure 11.73 Subsea tree

be bridged over to the control umbilical attached to the completion guide base so that the tree can be controlled from the production platform location. For guideline-based operations, the tree is encased in a guide frame with four guide posts that mate up with those on the completion guidebase and LRP package. In the case of guidelineless operations, some type of funnel down configuration is incorporated in the bottom end of the tree guide frame to guide it onto the wellhead. Running the Tree In preparation for running the tree, the EDP/LRP package will be locked to the top of the tree at the surface in the moon pool. The hydraulic control umbilical is connected to the top of the EDP. All hydraulics will be tested, ie. the EDP, LRP, tree hydraulic connectors and valves. At this point, the tapered stress joint from the completion riser system will be locked into its connection on top of the EDP. The riser spider is then installed in the rotary and the EDP, 272

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LRP and tree will be picked up with the riser handling tool and hung off in the riser spider. The tree is then lowered down to its required depth by adding riser joints. As the riser Joints are added, the hydraulic control umbilical is fed down off storage spools and clamped to the riser to provide protection and stability. At the upper end of the completion riser joints, a tensioning joint is installed to keep the completion riser in tension during the landing and completion operations. Tensioning lines in the moon pool area are attached to the rotating tension ring on the riser tension joint. The tree is now landed on the wellhead and locked to the wellhead by activating the hydraulic lock function through the control umbilical to the tree connector. An overpull is made to verify the connection and usually visual verification by TV camera or ROV observing the indicator rod on the connector. The flow line connector is made up as required by design. Pressure testing of all applicable connections and valve functional testing are performed at this time. The surface joint is now installed bringing the riser system through the rotary. The bottom of the surface tree is fitted with a completion riser connection to make up to the top of the surface joint. The surface tree is lowered onto the top of the surface joint by attaching casing elevators at the elevator shoulder on the upper end of the surface tree body. A functional test of the surface tree can now be performed, if applicable. The wireline plugs can now be pulled from the tubing hanger by hooking up the wire line unit to the quick union connections on top of the surface tree. Once the plugs have been retrieved, the well can be completed and flow tested. The tree is now shut in preparation for pulling the EDP/LRP/completion riser system. The surface tree is disconnected and laid aside. The LRP connector is hydraulically unlocked from the tree and with the riser spider installed at the rotary, the EDP/LRP/completion riser system can be retrieved.

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The tree on the EDP, LRP, and completion riser

Dual bore tree cap

Tree cap mounted to tree cap running tool

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CONTROL JUMPER TERMINAL ASSEMBLY (CJTA)

SUBSEA TREE W/GUIDE FRAME

FIGURE 11.79 COMPLETION GUIDE BASE ASSEMBLY

FIGURE 11.78 TREE TEST STAND

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DEBRIS COVER RUNNING TOOL ASSEMBLY

LATCH UNLATCH

FIGURE 11.77 TREE/TREE CAP RUNNING TOOL FIGURE 11.80 DEBRIS COVER

FIGURE 11.76 TREE CAP

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GUIDELINE LATCH RUNNING TOOL

DRILL PIPE UTILITY GUIDE FRAME

DEBRIS COVER FRAME TREE CAP MANDREL OVERSHOT

GL-4 POST TOP PROFILE ADAPTER

LATCH UNLATCH

ROV OPERATING HANDLE DEBRIS COVER RUNNING TOOL RUNNING AND RETRIEVING MANDREL

Figure 11.81 Debris cover and debris cover running tool

Installing a Tree Cap A tree cap will now be installed on the tree. The tree cap (Figure 11.76) will lock to the top of the tree using a hydraulically actuated connector that engages the same profile on top of the tree that was used to connect the LRP. The top of the tree cap has the same mandrel as the top of the tree so that a hydraulic connector type tree cap running tool (Figure 11.77) can be used to run the tree cap. The running tool has a stab plate to attach a hydraulic control umbilical to function the connector lock and unlock functions for the tree cap and tree cap running tool. The tree cap will seal off the annulus and production bores at the top of the tree and re-route the hydraulic control umbilical junction on the completion guide base that directs the control of the subsea tree back to the production platform. Once the tree cap has been landed on top of the tree, it is hydraulically locked to the tree. Using and over pull and visual observation by an ROV, confirmation that the tree cap has been locked down is made and the tree cap running tool is hydraulically unlocked from the tree cap and retrieved. The tree can now be operated from the platform and brought back on line. In some locations, it may be required to install a debris cover (Figure 11.80) on the tree to protect it from falling objects or from being snagged by fishing nets. These simple steel structures are designed to cover the tree and divert fishing nets up and over the tree and falling objects away from the tree. Installation of the tree is now complete and after guide lines are released, if applicable, the rig can be moved off location.

Control System Hydraulic energy is used in all cases to operate subsea production trees. Subsea tree control functions are operated from either of Debris cover

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two points. These are: 1. Workover or Utility Control System (operated from the installation vessel or workover vessel) 2. Production Control System (operated by the production platform) Utility Control System The Utility Control System is a direct hydraulic control system used during tree installation and workover operations. It consists of the following modules:

1. 2. 3.

Control panel Hose bundle and reel Power Skid

The utility control panel located on the installing or workover vessel is the control center for direct hydraulic control of the subsea completion equipment. It operates the tubing hanger running tool, tree running tool, and tree functions required during installation and workover. During tubing hanger and tree installation, a direct hydraulic control system umbilical connects the control panel to the tree through a hose bundle and reel. The umbilical is generally strapped to the tubing or drill pipe when being deployed. Control Systems for Subsea Trees Hydraulic power is required to remotely operate the open and close functions and the lock and unlock functions on the subsea tree. All of the control systems discussed in this section of the manual have that objective, namely to direct the hydraulic power to the required tree function. The production control system will consist of a control panel, power supply unit and the production umbilical. Each module will vary in degree of complexity based on the type of control system and the method of control used. Four methods of hydraulic control are available for remote ®

Master 36 function hydraulic control panel POWER SKID

CONTROL PANEL

HOSE REEL AND BUNDLE

Figure 11.82 Diagram of Utility Control System

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Land Tree on Wellhead - Overview 278

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Lock Tree to Wellhead Overview

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Unlatch and Retrieve LRP/EDP Assembly

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Run Tree Cap with Tree Cap Running Tool

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11 POWER SKID


production control of the ocean floor completion equipment. These methods are:

HOSE REEL FOR HYDRAULICS

CONTROL STATIONS

COMPUTER PROCESSORS HOSE REEL FOR ELECTRIC

Figure 11.83 Diagram of a complex production control system.

DIRECT HYDRAULIC CONTROL PANEL

Sea Level Seal Level

Direct hydraulic Sequence hydraulic Electro-hydraulic (E/H) Multiplexed electro-hydraulic Direct Hydraulic or Discrete Hydraulic Control System The simplest remote control system is one where there is a dedicated (discrete) control line to each valve operator or hydraulic mechanism on the subsea tree. The simplest control line bundle is one where individual flexible control lines are made into a bundle and wrapped securely together. This bundle of hoses is then laid on the sea floor, probably in conjunction with the sea floor flow line. One end is connected to the remote platform or shore based control station, and the other terminal is at the tree. Divers will be used to connect the individual control lines to a manifold on the tree which has previously been plumbed with stainless steel control lines to each tree function. The remote control station can now pump hydraulic control fluid into a single control line and open or close the function on the tree at the other end of the control line. This simple hydraulic control system has advantages and disadvantages. Advantages are that it is simple, has no moving parts, and is generally a cheap, ready made solution. Disadvantages, the response time from command to operation of the tree function is slow, as the expansion of the line under fluid pressure plus the volume of fluid required to operate the tree function must all pass into the line from the remote station.

TREE VALVES Seal Sea Bed

Hydraulic Line

Figure 11.84

282

The slow closure or opening of a tree valve may not be in the best interest of the valve, particularly if the oil or gas flow through the valve is erosive or abrasive. The gates and seats of valves can be cut by the flow of oil or gas, which ®


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can prevent the valve from sealing correctly. The discrete or direct hydraulic control systems have been used on many occasions, but discoveries in deeper waters have made diver assistance less attractive, and discoveries in waters far from established platforms or land have required control systems with faster responses and operating times. Piloted Hydraulic Control System This system requires a sea floor control umbilical that has multiple small diameter control lines for the pilot pressure and one or two larger diameter hydraulic lines for higher volume transmission of hydraulic fluid. Usually this flexible umbilical is encased in a hard smooth protective sheath, and is run with the sea floor flow line bundle. This control system will also employ a control pod that locks to a base plate mounted on the tree framework. This control pod will contain pilot operated valves that direct the hydraulic control fluid to the tree function. The control pod is usually a retrievable piece of equipment, independent of the tree. In order that the supply of hydraulic fluid is delivered in sufficient volume and correct pressure to quickly operate the tree functions, a pressurized accumulator is installed on the fluid power line at the tree. This accumulator is usually sized with enough fluid capacity to operate all tree functions at least once before it has to be recharged from the platform or shore based control station. The tree plumbing is much more complicated than the direct hydraulic system previously described. Small bore stainless steel tubing will connect each tree function to the tree manifold and the tree manifold outlets will be connected to the control pod base plate. The tree cap provides the linking conduits for the operating fluid as it comes from the control pod base plate to the tree manifold, through the tree cap, back through the tree manifold to the required operating function on the tree. This control scenario for the tree is used when the tree is controlled from a remote control station. ®

Main control umbilical reeler and tubing hanger/tree cap control umbilical reeler

Main control umbilical hookup to master control panel

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PILOTED HYDRAULIC CONTROL SYSTEM CONTROL PANEL


TREE SUPPLY

PILOT VALVES

TREE VALVES Seal Bed

Hydraulic Line Electrical Line Accumulator

Figure 11.85

Sea Bed

If the tree cap running tool is connected to the tree cap then vertical control line access is gained through a control line umbilical run with the tree cap running tool string, which is in turn connected to the shuttle valves mounted on the tree cap. Control line fluid from the floating vessel positioned over the tree will shift the shuttle valve on the connected line so that the fluid can pass through the tree cap and the tree manifold to the selected operating function on the tree. The control panel at the remote station will have each tree function clearly illustrated on the panel face. Pressure gauges will indicate the operating pressure in the fluid power lines to the subsea tree. This pressure is usually in the 1000-1500 psi range, but higher pressures, up to 3000 psi, have been used. When a control button or lever is operated on the panel, hydraulic fluid pressure will be applied to the selected hydraulic pilot line going to the tree. The pressure in this line will build up until it is sufficient to open the pilot operated valve in the control pod. There will be a time delay varying in a few seconds to a few minutes for the pilot control pressure to open the valve in the control pod, depending on the distance from the remote control station to the subsea tree. However, once the valve opens, the hydraulic fluid under pressure from the tree mounted accumulator will be directed to the tree operating function very rapidly. As mentioned earlier the control fluid is routed through the tree manifold, by way of the tree cap, to the selected operating function on the tree. In this method of a hydraulic pilot operated control system the main assemblies of moving parts and seals are housed in the retrievable control pod on the tree cap. This means that repairs or maintenance can be done to the control system, by a dedicated service vessel rather than a floating

Main control panel

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drilling or production vessel, without pulling the subsea tree. Sequenced Hydraulic Control System The purpose of the sequenced hydraulic control system is to provide a means of controlling the subsea tree based purely on the operating pressure in the operating fluid line and independent of pilot control lines. The main component in this system is the sequence valve usually mounted on the tree cap. The sequence valve is designed to shift to three or four positions when the incoming operating pressure is changed within specified ranges. When the valve changes position the hydraulic fluid is directed to another exit port in the valve body. If the pressure is raised to the next range, the valve shifts again and the hydraulic fluid comes out of another pod. Stated in simple terms the sequence valves will have one incoming port and three or four exit ports representing each step up in pressure.

1

0

CONTROL PANEL

Sea SealLevel Level

TREE SUPPLY

Pressure Position Range PSI

SEQUENCED HYDRAULIC CONTROL SYSTEM

SEQUENCE SUPPLY

This means that each exit port can be manifolded to included one tree function, or a number of tree functions. The following simplified table gives some idea of how the tree functions could be coupled with a four position sequence valve used in an override capacity to the normal pilot operated system.

Control panel at umbilical reeler.

SEQUENCE VALVE

Tree Functions Controlled All valves on tree move to failsafe close position. Crossover valve moves to fail-safe-open position.

MULTI-WELL TEMPLATE

Hydraulic Line

Seal Bed Sea Bed

Electrical Line

2

1000-1500

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Normal operating mode, where hydraulic fluid is directed through control pod for normal

Accumulator

Figure 11.86

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ELECTROHYDRAULIC CONTROL SYSTEM

pilot operated control of tree. 3

1500-2000

4

2000-2500

CONTROL PANEL

Keeps tree valves in production mode, bypassing the control pod, which could be malfunctioning.


TREE SUPPLY

SEQUENCE SUPPLY

Shuts in well and could release recall buoy from tree if so designed. The sequence valve listed above has been plumbed into the hydraulic control system of the subsea tree to provide an override, or back-up system in the event of pilot control system failure. The sequenced hydraulic control system is not generally used as the primary control system for a subsea tree.

SEQUENCE & SOLENOID VALVES

TREE VALVES


Figure 11.87

Seal Bed Sea Bed

Electrohydraulic Control System The purpose of the electrohydraulic control system for subsea trees is to send electric signals to the tree control pod so that the hydraulic port can be directed to the selected tree function. The means to do this is provided by a sheathed sea floor control line umbilical that contains the hydraulic power line and multiple electrical conductors. This sea floor umbilical is usually run in conjunction with the flow lines. The subsea electrical connections at the flow line tree interface will be a socket type or an inductive coupler type. The pilot electric signal from the remote stations control panel will operate a solenoid operated valve in the control pod. When the solenoid valve opens, hydraulic power fluid under pressure will be directed to operate the selected tree function by way of the tree manifold and tree cap. As can be seen in Figure 11.87, the electrohydraulic control system is very similar to the hydraulic pilot operated control system. The differences being that electric signals have replaced the hydraulic pilot signals and that the solenoid

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Multiplex Control Systems The purpose of a multiplex control system is the same as an electrohydraulic control system, namely to initiate the hydraulic function on the subsea tree with an electric signal. Instead of a multicore electrical sea floor umbilical, only 3 or 4 conductors are required which reduces the size and complexity of the sea floor control line umbilical. However, a decoder of the electric signals sent through the sea floor umbilical is required, usually housed in the retrievable control pod. The decoder receives the signal, and then switches electric signal power to the solenoid valve in the control pod. The solenoid valve operates and directs the hydraulic fluid to the selected tree function. The system has a response time equal to the electrohydraulic control system. The umbilical is cheaper, but the control pod hardware is more expensive.

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MULTIPLEXED CONTROL SYSTEM

CONTROL PANEL


TREE SUPPLY

operated valves have replaced the hydraulic pilot valves in the control pod. The operating difference between the two control systems is that the response time from initiating a function electrically at the remote control panel to the time the function operates at the tree is immediate. From an economic standpoint the sea floor control umbilical is cheaper in an electrohydraulic system, but the electrical connectors and control pod solenoid valves are more expensive than their equivalent hydraulic parts. The main advantage is response time weighed against the traditional difficulty of getting electrical connectors to work consistently underwater. However electro-hydraulic control systems are in common use, and are integrated with the increasing number of electrical readout signals from downhole pressure sensors, tree bore pressure, temperature sensors, and valve position indicators.

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MULTIPLEX

MULTI-WELL TEMPLATE Seal Bed Sea Bed


Figure 11.88

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Drilling Manual Drill Quip

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