Datalog Wellsite Procedures Manual 1999

Datalog Wellsite Procedures Manual 1999

SECTION 1

RIGS AND THEIR EQUIPMENT

ROTARY DRILLING RIGS Land rigs Offshore drilling vessels Barges Jack-Up Rigs Semi-Submersible Rigs Drillships Platforms

3 3 3 3 3 4 4 4

COMPONENTS OF THE ROTARY DRILLING RIG

7

THE HOISTING SYSTEM Providing Rotation to the Drillstring and Bit • Kelly and Swivel • Top Drive Units Lifting Equipment • Bails and Elevators • Slips • Tongs • Power Tongs and Pipe Spinners • Chain Wrench

8 9 9 10 11 11 11 12 12 12

THE CIRCULATING SYSTEM Solids Control Equipment

13 14

DRILL BIT AND DRILLSTRING Drag Bits Roller Bits Bit Terminology IADC Bit Classification Cone Action Bearing Types Teeth Diamond and Polycrystalline Diamond Compact (PDC) bits Grading Of Bits The IADC bit grading system Drillpipe Drill Collars The Bottom Hole Assembly (BHA) • Stabilizers • Reamers • Hole Opener • Cross Over Sub • Jars • Shock Sub

17 17 17 18 18 19 19 19 20 21 22 23 24 25 25 25 25 25 26 27

BLOW OUT PREVENTION SYSTEM Closing the well • Annular Preventor

28 29 29

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Datalog Wellsite Procedures Manual 1999

• Ram Type Preventors Closing the preventors • Accumulators • Control Panel • Positioning of the rams • Kill Lines • The Diverter Inside Blowout Preventers • Surface Shut Off Valves • Downhole Check Valves Rotating BOPs

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29 30 30 31 31 31 32 32 33 33 33

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Datalog Wellsite Procedures Manual 1999

SECTION 1

RIGS AND THEIR EQUIPMENT

ROTARY DRILLING RIGS In the early days of petroleum exploration and production, wells were drilled with cable tool rigs. The technique used was percussive drilling where a hardened bit, suspended on a cable, was repeatedly dropped onto the bottom of the hole. The constant pounding would break up the formation, deepening the hole in the process. The drawbacks to the cable tool rig were limited depth capabilities, very slow drilling rates and no way to control subsurface formation pressures. Modern drilling uses a rotary drilling method providing faster drilling rates, much greater depth capabilities, offshore drilling, and the safe control of subsurface pressures. Land rigs Land rigs are typically designed around a cantilever mast principle, providing easy transportation and quick assembly. The mast, or derrick, is transported to the drill site in sections, assembled on the ground, then raised to a vertical position by using the rigs hoisting system (drawworks). Blow out preventors are positioned directly beneath the rig floor, connecting the floor to the well head. This allows drilling fluid to be circulated and pipe to be lifted in and out of the well. Offshore drilling vessels Drilling offshore obviously requires a completely self-contained vessel, not only in terms of drilling requirements but also in terms of accommodation for personnel. Situated in remote, hostile locations, they are much more costly to operate and require more sophisticated safety measures since water separates the wellhead from the actual rig. There are different types of offshore rigs and their use principally depends on the depth of water that they are required to operate in. Temporary installations (that can move from location to location), used for exploratory drilling, can either be supported by the seabed or they can be floating and anchored in positioned. Permanent installations, or platforms, are required for production wells. Barges These are small, flat-bottomed vessels that can only be used in very shallow waters such as deltas, swamps, lagoons and shallow lakes. Jack-Up Rigs These are mobile vessel suitable for drilling in shallow sea water depths. They consist of a fixed hull or platform which is supported on by a number of legs, typically 3, that stand on the seafloor. To move a jack-up rig, the legs can be raised so that the rig floats on its hull enabling it to be towed into position by barges. This makes the vessel very top heavy and unstable during towing, so that calm waters and slow towing speeds are essential to avoid capsize. Once in the required position, the legs can be lowered to the seabed creating a very stable structure unaffected by wave motion. The blow out preventors are mounted underneath the rig floor, so that a large conductor pipe, driven into the seafloor, is required to connect the well to the rig and allow drilling fluid to be circulated.

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Datalog Wellsite Procedures Manual 1999

Semi-Submersible Rigs “Semi-subs” are floating rigs that are suitable for drilling in deeper waters than jack-ups. The deck is supported by a number of legs or columns. Subsea, these columns are supported by pontoons which can be solitary or connected. Both pontoons and columns are utilized to ballast and stabilize the rig. This substructure sits below the sea surface, avoiding the worst, surface turbulence of the water. This makes them more stable than drillships and therefore more suited to drilling in rough seas. The pontoons are fitted with thrusters for position adjustment or self- propulsion, but they are generally moved into position by sea going tugs, with the thrusters being used to assist in the final positioning of the rig. Once correctly positioned, the semi-submersible is anchored in place, although in deeper waters the thrusters may be used to maintain position by way of an automated location monitor. Unlike the jack-up, blowout preventors are located on the seabed, mounted on conductor pipe that has been set into the seafloor. Positioning of the BOP’s is very tricky and achieved with the assistance of underwater cameras or remotely operated vehicles (ROV’s). This allows the well to be left secure should the rig be forced to abandon the location. A large flexible, telescopic steel pipe, called the marine riser, connects the BOP’s to the rig, enabling drilling fluid to be circulated and the drillstring to be guided into the well. Drillships Drillships are capable of drilling in deeper water. They are generally self propelled and therefore easily transported to the drilling location. They are extremely mobile, but generally less stable than semi-submersibles and therefore not able to drill in rougher seas. A drillship can be anchored, or position maintained by automated thruster systems. The drillship has exactly the same subsea equipment as a semi-submersible, with the BOP’s mounted on the seabed. To compensate for movement of the drillship (also semi-submersibles), the marine riser includes a telescopic joint to allow for vertical movement. A ball joint at the seafloor allows for horizontal motion. The length of the riser is often the limiting factor in deep water drilling, before it becomes subjected to too much bending and stress. Platforms Platforms are permanently fixed structures installed where mobility is not required. This is typically when multiple wells are going to be drilled to develop and produce a field. Platforms can be of two designs, piled or gravity structures. A piled platform consists of a steel jacket which is pinned to the seabed and supports the deck structure. This type of platform is stable in very bad weather conditions, but is not very mobile. They are usually constructed in separate sections that can be individually towed to position and constructed in place. Gravity type platforms are constructed from concrete, steel or a combination of both. They have a cellular base, providing both ballast and storage, with vertical columns supporting the deck structure. They are normally constructed in their entirety, then towed to the location and ballasted into position.

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Datalog Wellsite Procedures Manual 1999

LAND RIGS

…..before the mast has been raised into position

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Datalog Wellsite Procedures Manual 1999

JACK UP 3 legs are most typical. Note here that drilling has not been started since there is no conductor pipe in place.

SEMI-SUBMERSIBLE

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Datalog Wellsite Procedures Manual 1999

COMPONENTS OF THE ROTARY DRILLING RIG The modern rotary drilling rig, whatever the type, consists of 5 principle components:(1) Drill Bit and Drillstring (2) Fluid Circulating System (3) Hoisting System (4) Power System (5) Blowout Prevention System The term rotary comes from the physical movement of the drillstring and bit, applying a rotary cutting action to the rock at the bottom of the hole. Rotation can be provided at surface or by motors positioned in the drillstring downhole. The drillstring (1) consists of hollow steel pipe allowing drilling fluid to be transported into the hole. The pipe will typically be a combination of ‘standard’ drillpipe, thicker, heavier drillpipe and larger diameter, heavy drill collars immediately above the bit. This is all supported from the derrick with vertical movement (in and out of the hole) provided by the drawworks, crown block and travelling block (3). Rotation of the drillstring, at surface, is applied in one of two ways, either by a rotary table, bushings and kelly or by a top drive unit. The drilling fluid, commonly referred to as drilling mud, is stored in mud tanks or pits. From here, the mud can be pumped, via the standpipe, to the kelly swivel where it can enter the kelly and subsequently the drillpipe. The mud can then pass all the way to the bit, before returning to surface through the annulus (the space between the wall of the borehole and the drillstring). On return to surface, the mud is passed through several pieces of equipment to remove the drilled rock chips or cuttings, before completing the cycle and returning to the mud tanks (2). Formations in the shallower part of the wellbore are usually protected by large diameter steel tubing, or casing, which is cemented into place. The annulus that the mud now passes through on it’s way back to surface is now the space between the inside of the casing and the outside of the drillstring. Attached to the top of the casing is the blowout preventor stack (5), a series of valves and seals that can be used to close off the annulus or wellbore in order to control large subsurface pressures. All of the equipment described above is operated by a central power system (4), which will also supply the general power required for electrical lighting, service company equipment etc. Typically, this power source is by way of a central diesel-electric power plant.

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Datalog Wellsite Procedures Manual 1999

THE HOISTING SYSTEM The complete hoisting system has several basic functions: Fast shiv Crown block

Drill line or Fast line

Dead line

Travelling block

Hook

Drawworks drum

Dead line anchor

The hoisting system supported by the derrick

•

Supporting the weight of the drillstring, possibly up to several hundred tonnes.

•

Lifting the drillstring in and out of the hole.

•

Maintaining the force, or weight, applied to the bit during drilling.

The derrick supports the weight of the drillstring at all times, whether the drillstring is suspended from the crown block or supported temporarily in the rotary table. The size and strength of the derrick is the limiting factor to the weight of drillpipe that can be supported and therefore the depth that the rig is capable of drilling to. The height of the derrick will determine the length of the pipe sections that can housed when the drillstring has to be pulled from the hole. During this operation, the pipe will normally be broken down into double or triple stands (2 or 3 individual lengths, or joints, of pipe). During the drilling operation, the kelly and

drillstring are supported from the travelling block by way of the travelling hook. This is connected to the drawworks by way of a simple pulley system. A steel cable, the drilling line, is spooled on a large reel at the drawworks where it can be drawn in, or let out, depending on whether an upward or downward motion of the travelling block is required. From the drawworks, the drilling line passes up to a stationary set of pulleys, called the crown block, situated at the top of the derrick. Here, the cable is repeatedly passed between a series of wheels, or shivs, and the travelling block suspended in the derrick, so that the travelling block will be suspended by a number of lines, typically 8 to 12. The drilling line is then passed from the crown block to an anchor where the cable is securely clamped. This length of drilling line is referred to as the dead line, and the deadline Fast line up anchor is typically located to one to crown side of rig floor. From the deadline anchor, the drilling line passes to a storage reel, to one side of the rig, where extra drilling line is stored. The drilling line is commonly referred to as the fast line for the length running from the drawworks to the crown block. This is because the Drawworks first shiv that it is spooled around is Drum generally larger than the others and known as the fast shiv.

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The usage of the drilling line, or wear, is recorded in terms of the load moved over a given distance. For example, 1 ton-mile means that the line has moved a 1 ton weight a distance of 1 mile. Similarly, a measurement of 1kN-km means that the line has moved 1000 newtons a distance of 1 kilometre. This record allows the drilling crew to determine when the drilling line needs to be replaced by a new length of cable. The ‘slip and cut’ procedure requires the travelling block to be lowered to the drill floor so that there is no load on the drilling line. The line is released at the dead line anchor so that new line can be fed, or slipped, through. The line is tensioned by feeding the it through the pulley system and feeding the old line Drill line ‘pulley’ out from the drawworks. This old line can be removed, or cut, and the new Travelling block length of cable tensioned and anchored once more at the dead line anchor. This procedure allows for even wear on the Hook drilling line as it is used.

Kelly hose

Elevators Bushings Kelly

The drawworks have a heavy duty braking system allowing for the speed to be controlled, or resisted, when moving the pipe into the hole. During the drilling operation, the drawworks also allows for control, or adjustment, of the proportion of the string weight that is supported by the derrick and that which is supported by the bottom of the hole. This equates to the weight, or force, that is applied to the bit and thus can be adjusted according to the hardness of the formation and the weight required in order to produce failure of the formation and allow penetration, or deepening of the hole to proceed.

Providing Rotation to the Drillstring and Bit Kelly and Swivel The kelly is a hollow length of steel, normally around 12 or 13m in length, either square or hexagonal, through which drilling fluid can enter the drillpipe. The top of the drillstring is connected to the kelly by a kelly sub (or saver sub). This sub, being cheaper to replace than the kelly, saves wear on the connecting threads of the kelly, which passes through a ‘rotary kelly bushing’ mounted and locked into master bushings that are set into the rotary table. Free vertical movement of the kelly is possible through the bushing, allowing upward and downward movement of the drillstring. Rollers within the bushing facilitate this movement and, again, minimize the wear on the kelly. The shape of the kelly (commonly 4 or 6 sided) fits exactly into the bushing so that, if the bushing rotates, the kelly rotates. Since the bushing is locked into the rotary table, rotation of the table (either electrically or mechanically) will rotate the bushing and therefore the kelly and drillpipe. Vertical movement is still possible even if the kelly is rotating. When the kelly is lifted Datalog Wellsite Procedures Manual 1999

kelly

kelly bushings

rotary table drillpipe joint in mousehole

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from the ‘hole’ to expose the drillpipe, the kelly bushings are lifted along with the kelly. Between the kelly and the hook is an assembly known as the swivel. This supports the kelly but does not rotate as the kelly rotates. This prevents the hook and travelling block from rotating and twisting the drilling line as the string is rotated. The swivel is also the point at which the drilling fluid enters the drillstring, through an attachment known as a gooseneck connected to the kelly hose carrying the drilling fluid. A safety valve is located at the top of the kelly. This ‘kelly cock’ can be manually closed in the event of the well flowing due to high, subsurface, formation pressure. This prevents back pressure from entering, and perhaps damaging, the kelly swivel. Top Drive Units On more recent rigs, the rotary drive and swivel are combined into a single top drive unit, which may be electrically or hydraulically operated. The drillstring now connects directly into the top drive unit where rotation is applied and where drilling fluid enters the string through a similar swivel and gooseneck assembly. Since rotation is now applied directly to the top of the drillstring, there is no requirement for a kelly and rotary bushing. The advantage of a top drive unit over the conventional kelly system is primarily one of time and cost. With the kelly, as drilling progresses, only single lengths, or joints, can be added to the drillstring. This ‘connection’ process requires the kelly being ‘broken off’ from the drillstring, picking up and attaching the new joint of pipe to the kelly, then reattaching the new pipe and kelly back to the drillstring. With a top drive unit, this operation is not only made much simpler by the fact that pipe is connected directly to the unit, but it also enables a stand of drillpipe (equivalent to 3 single joints of pipe) to be picked up and added to the drillstring at any one time. A complete stand of drillpipe can therefore be drilled continuously, so that only one connection is required for every three that would be required with a kelly.

Travelling Block

Top Drive

Overall time required to make ‘connections’ is therefore much less for rigs possessing top drive units. This means a big saving in cost, especially for large land rigs or offshore rigs where the daily cost of hiring the rig is much more expensive.

Elevators Drillpipe ‘ingress”

Datalog Wellsite Procedures Manual 1999

Another important advantage of the top drive unit is during tripping operations, when the drillstring is being lifted in or out of the hole. The conventional kelly is not used when tripping pipe. It is set aside on the rig floor in what is called the ‘rat-hole’. Bails and elevators are then used to lift the drillstring. If the pipe was to become stuck during the trip, circulation of drilling fluid may be

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required to free the pipe. In order to achieve this, the kelly would have to be picked up from the rat-hole and attached to the drillstring, a process that may take as long as 5 or 10 minutes during which time, the ‘sticking’ of the pipe may become worse. With a top drive unit, elevators are again used to lift the pipe, but these are suspended beneath the top drive unit. It is therefore a very quick procedure to ‘attach’ the top drive unit to the drillstring so that circulation of drilling fluid and rotation of the pipe is possible almost immediately. In most circumstances, this minimizes the potential problem and reduces the time that may be required to resolve it. Lifting Equipment The procedures of tripping, lifting the pipe in and out of the hole, and making connections, adding new lengths of drillpipe to the drillstring in order to drill deeper, have already been introduced. Handling of the pipe during these operations requires the use of specialized pieces of equipment.

bails

elevators

slips

To pull a stand of drillpipe from the hole, the elevators are clamped around the pipe. When the blocks are raised, the elevators rest beneath the larger diameter tool joint so that the pipe can be lifted. When the stand is completely above the rotary table, slips will be held around the pipe as it is slowly lowered. The slips will wedge firmly in the rotary table, clasping the pipe. The total weight of the string is now supported by the rotary table. The stand above the table can now be removed from the string and set aside. Firstly, the tool joint connection is broken with two sets of tongs, one positioned beneath the tool joint holding the pipe steady, the second positioned above the tool joint. This is connected by a chain which is pulled in at the cathead, breaking the connection. The stand is quickly unscrewed by using a pipe spinner, so that it is free and hanging from the elevators. The stand is racked to one side of the derrick and held in position by placing the top of the stand in a rack known as ‘fingers’. This operation is performed by the derrickman who works up in the derrick on a platform known as the monkey board. monkey board and fingers Bails

and Elevators

racked drillpipe

These are used to lift the pipe into position or remove it when the connection has been broken. The elevators are simply clamps that are placed and closed around the ‘stem’ of the pipe. As the elevators are lifted, they will move up the pipe until they come against the wider tool joint so that the pipe can be lifted. The elevators are suspended from the travelling block by links or bails, so that vertical movement is applied from the drawworks. Elevators are of specific sizes and designs to accommodate pipe of different diameter, casing joints and drill collars. Slips While connections are being made or broken, the drillstring has to be suspended and supported in the rotary Datalog Wellsite Procedures Manual 1999

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table to prevent it from fallen down the hole. This is achieved by using slips, tapered or wedged shaped dies held together in a frame with handles. These are placed around the ‘stem’ of the pipe and lowered, along with the pipe, into the master bushings where they become ‘set’, fully supporting the weight of the drillstring in the rotary table.

Slips

Tongs These are used to tighten or loosen the connections between sections of pipe. These ‘wrenches’ are suspended on cables from the derrick and attached to the cathead, on the drawworks, by a chain through which tension can be applied. Two tongs are used, being placed on either side of the connection or joint. The lower tong will hold the drillstring in place below the joint and the upper tong, by pulling on the chain, will loosen or break the connection or in the opposite direction, tighten or make the connection. When making the connection, a gauge on the chain allows the correct amount of torque to be applied. Power Tongs and Pipe Spinners These are pneumatically powered ‘wrenches’ enabling rapid spinning of the pipe during the making or breaking of connections. Tongs will be used to apply final torque when making the connection and to initially loosen the joint when pipe spinner breaking the connection.

tongs

chain to cathead

Breaking tool joint to make a connection used to pull the pipe up so that is resting vertically against the “v-door”, a ramp that joins the pipe deck to the rig floor. The blocks can then be lowered and the joint of pipe picked up in the elevators (different elevators are used to pick up collars or casing tubular). Once picked up, the joint of pipe is lowered into the mousehole (a hole drilled into the surface sediments and lined with tubular) where it is ready for use when the next connection is to be made.

Datalog Wellsite Procedures Manual 1999

Chain Wrench If pneumatic wrenches are not available, spinning of the pipe has to be done manually by way of a chain wrench. Chain is wrapped around the pipe, clasped and gripped by the wrench. Spinning of the pipe is done by physically walking around the pipe while it is gripped and held by the wrench. When pipe has to be added in order to drill further, it is picked up from the pipe deck to one side of the rig. A winch is

rig floor “v-doors” pipe deck

casing joints

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Datalog Wellsite Procedures Manual 1999

THE CIRCULATING SYSTEM We have already seen how the drilling fluid, commonly called mud, enters the drillstring through the kelly or top drive unit. There are many ways in which the mud aids the drilling process and, in fact, is a vital component to the successful drilling of a well. The most important functions are: •

To cool and lubricate the drill bit and drillstring in order to minimize wear, prolong their life and reduce costs.

•

To remove the drilled rock fragments, or cuttings from the hole. This not only keeps the annulus clear but also allows examination at surface for formation evaluation.

•

To balance high fluid pressures that may be present in some formations and minimizing the potential of kicks or blowouts. The safety of the rigs personnel and of the rig itself is of paramount importance in any drilling operation.

•

To stabilize the wellbore and formations that have already been drilled.

Types of drilling mud and it’s function will be discussed in more detail in section 4.

Creating a drilling mud is almost like cooking, with many ingredients or additives going into the system, each having a particular function to perform. The mud is ‘built’ and stored in mud tanks or pits. Different names are given to individual pits depending on their specific function. Typically, they may be called: Premix Pit

Where additional chemicals are added and mixed into the mud system.

Suction Pit

The pit where mud is taken by the rig pumps to begin it’s journey to the drillstring. This is the ‘live’ or ‘active’ pit, lined up to the actual wellbore.

Reserve/Settling Additional mud volume, generally not part of the ‘active’ system. Datalog Wellsite Procedures Manual 1999

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Shaker Pit

This is the tank situated directly beneath the shale shakers. A sand trap is normally an integral part of the shaker pit. It’s purpose is to allow as much fine material, sand and silt, to settle out from the mud system and be removed.

Trip Tank

A smaller tank, used to monitor small mud displacements. Situations that require this include tripping the drillstring out of the hole and monitoring a well kick.

Slug Pit

A tank used to make up small volumes of ‘special’ mud that may be required for specific operations during the drilling of a well.

The number of the pits required will depend on the size and the depth of the well being drilled, and thus on the volume of mud required to fill that hole. Typically, 4 to 6 tanks may be used, but for larger wells and platforms, this number may increase to 16 or more.

Mud agitator

Pit level sensor

Grating covering pits

From it’s storage in the mud tanks, the mud is pumped through an upright standpipe fixed to the side of the derrick, through a gooseneck into the connected kelly hose. From the kelly hose, the mud passes through another gooseneck, through the swivel into the kelly from where it is forced down the inside of the drillstring. Exiting the drillstring through the bit, the mud then returns to surface by way of the annulus (the space between the wellbore wall/casing and the outside of the drillstring). In the case of offshore wells, a further conduit has to be positioned to allow mud to be circulated from the seabed to the rig. This is done by way of a large conductor pipe or marine riser.

Conductor

A pipe driven into the seafloor, providing a conduit to the BOP stack situated beneath the rig floor on jackups and platforms.

Marine Riser

A pipe connected to the top of the BOP stack which is located on the seabed on semi-submersibles and drillships, providing a conduit to the rig. The riser incorporates a telescopic or ‘slip’ joint that allows for rig heave adjusting the vertical position of the rig.

Solids Control Equipment Solids control is vital in maintaining efficient drilling operations. High mud solids increase the mud density and viscosity, leading to higher chemical-treating costs, poor hydraulics and increased pumping pressures. With increased solids, the mud becomes increasingly abrasive and increases wear on the drill string, wellbore and surface equipment. It becomes more difficult to remove solids from the mud as the solids content increases. Drilling mud surfacing from the wellbore contains cuttings, sand and other solids, and probably gas, all of which must be removed before the mud is suitable for recirculating in the well. Mud treatment clays and chemicals must also be added from time to time to maintain the required properties. All of these functions require special equipment.

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Once exiting the wellbore at surface, the mud is ‘drawn off’ at the bell nipple and directed along a flowline to a shaker box (also called a header box or possum belly). This is where the mud logger will position a gas trap and mud monitoring sensors to analyze the mud returning from the hole. Gates in the shaker box regulate the flow of mud onto the shale shaker. Here, sloped, vibrating mesh screens (normally two) separate the drilled cuttings from the drilling mud, which is allowed to pass through the screens into the sand trap or shaker pit. The mud can then be returned to the main pit system where the circulating cycle can start over again. The screens can be changed so that the size of the mesh is appropriate to the size of the cuttings needing to be removed. Normally, a coarser screen is positioned above a finer screen. The vibration motion of the screens improves the separation of the mud from the cuttings. Samples for geological analysis will be collected at this point. mixing hopper centrifuge premix pit desilter

desander

degasser

suction line to rig pump suction or active pit

return flowline shaker box

reserve & settling pits

shale shaker sand trap

shaker pit

With environmental concerns an important consideration, the cuttings separated at the shale shaker are collected in tanks so that they can be easily transported to sites where they can be thoroughly cleaned of any residual mud or chemicals and deposited. Additional equipment is often put into the circulating system before the mud reaches the mud tanks. If the mud is particularly gaseous, it may be passed through a degasser, a large tank with an agitator to force the release of gas from the mud. After passing through the shale shakers, there may still be very fine solid material such as silt or sand grains that have to be removed from the mud. The mud first drops into a sand trap after passing through the shakers. This is a conical or tapered chamber incorporated within the shaker pit, where the muds flowrate is reduced allowing solids to separate and settle. The bottom of the trap is sloped so that the settling particles fall to the base where they collect Datalog Wellsite Procedures Manual 1999

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and can discarded. If these particles do not settle out when the mud passes through the sand trap, it will be necessary, before returning it to the mud tanks, to pass the mud through additional solids control equipment. A desander, when used in addition to the shale shaker, removes most of the abrasive solids, thereby reducing wear on the mud pumps, surface equipment, drill string and bit. Also used in conjunction with the shale shaker and desander is a desilter, which removes even finer material from the mud. Desanders and desilters separate solids in a hydroclone, a cone-shaped separator in which the fluid rotates and causes the solids to separate by centrifugal force. The drilling fluid flows upward, in a helical motion, through conical chambers, where solid particles are thrown outward from the drilling fluid. At the same time, water passes downward through the chamber, carrying away the solid particles removed from the mud. Additional centrifuges may also be used in order to remove large amounts of clay solids suspended in the mud. Once SHALE SHAKER clean mud A hydroclone the mud is cleaned, it can be returned to the mud tanks for re-circulating. A centrifuge consists of a high-speed rotating, cone-shaped drum, and a screw conveyor that moves the coarse particles in the drum to the discharge port and back to the mud system. It is often used when the mud weight has to be significantly reduced, rather than adding liquid and increasing the volume. The centrifuge may also be used to remove glass or plastic beads that have been Shaker box with used to improve lubrication or to reduce density in underbalanced applications. This ‘solids gas trap andcontrol’ mud performed by the surface equipment is a very important aspect of maintaining the mud. Fineparameter grains would obviously be very sensors abrasive and damaging to equipment such as pumps, drillstring and bit etc. It is also important in controlling the density of the mud. If solids were allowed to remain and build up in the mud, it’s density would increase as a result. Mud return mud inlet One further step that may flowline be required to prepare the drilling mud for recirculation is performed by a degasser, which separates and vents large volumes of entrained gas to a flare line. Recirculating gas-cut mud can be hazardous and will reduce pumping efficiency and lower the hydrostatic pressure required to balance the formation pressure. A mudgas separator safely handles high-pressure gas and flow from a well when a kick occurs. A vacuum degasser is more appropriate for separating entrained gas, which may resemble foaming on the surface of the mud (gas cut mud). DESILTER water and solid discharge

Most rigs have two rig pumps to circulate the mud under pressure around the entire system. Smaller rigs drilling shallower holes may only require one. Rig pumps can be of

two types: Duplex Pumps

These possess 2 cylinders, or chambers, each of which discharges drilling fluid on both forward and backward motion of the pump stroke. As the mud is being discharged on one side of the piston, the cylinder is being filled up from the other side of the piston. As the piston returns, this mud will now be discharged, with the previously discharged side now being refilled behind the piston.

TRIPLEX PUMP Triplex Pumps These possess 3 cylinders. Only the duplex pump, mud is only discharged on the forward stroke. In each cylinder, mud is discharged by the pushing motion of the piston on the forward part of the stroke, leaving the cylinder behind the piston empty. As the piston returns on the backward part of CHAMBER & PISTON the stroke, mud re-fills the chamber. This mud will again be discharged on the forward part of the pump stroke.

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Datalog Wellsite Procedures Manual 1999

DRILL BIT AND DRILLSTRING Drill Bit Types Drag Bits These have hard faced blades, rather than distributed cutters, that are an integral part of the bit and rotate as one with the drillstring. They have a tendency to produce high drilling torque and are also prone to drilling crooked holes. Penetration is achieved with a scraping action using low force (weight on bit or WOB) and high rotation speed (RPM). They are only really suitable for drilling soft, unconsolidated formations, lacking the hardness and wear resistance required for consolidated formations. Roller Bits Early bits possessed 2 cones that had no interaction, or meshing, and were therefore prone to balling (where drilled cuttings collect and consolidate, or ball, around the bit) in soft formations. These were superceded by the Tri-Cone bit, the most common bit type used in modern drilling. These possess 3 cones, which are intermeshing and therefore selfcleaning, with rows of cutters on each cone. The cutters are of two principle types, either milled teeth or tungsten carbide inserts (TCI), and can be of varying size and hardness according to the lithologies expected. A lot of heat is generated by friction during drilling and this heat has to be dissipated. Cooling, together with lubrication, is an important function of the drilling fluid. This exits the drillstring through “ports” in the bit that are called jets or nozzles. One jet is positioned above each cone. They are replaceable and can be of varying size, the smaller the jet the greater the velocity and force of the mud exiting the bit. Jet sizes are either expressed in millimetres or in 32nds of an inch. If no jet is set into the “port”, it is known as an open jet (the size is one inch, i.e. thirty two 32nds).

Tri-cone tooth bit

Roller bits are classified by a system developed by the International Association of Drilling Contractors (IADC): Most roller bits would therefore have a 3 digit IADC Code.

For example: Hughes ATM22

IADC code 517

Soft chisel type TCI bit, softest in the range, with friction sealed journal bearings and gauge protected.

Reed MHP13G

IADC code 137

Soft milled tooth bit, moderately hard in the range, friction sealed journal bearings and gauge protected.

Certain bits may also have a 4th category to describe additional features about the bit. Examples include air application (A) bits, centre jets (C), deviation control (D), extra gauge (E), horizontal steering (H), standard steel tooth bit (S), chisel shaped inserts (X), conical shaped inserts (Y).

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Datalog Wellsite Procedures Manual 1999

Bit Terminology sculptured inserts middle row inner heel row

cone nose

heel row cone Shirt tail bit leg

nozzle boss jet or nozzle shoulder shank

Tri-cone button bit (tungsten carbide inserts) IADC Bit Classification Series Type of cutting structure

Type Degree of hardness of cutting structure Design Option Bearing design and gauge protection

1 2 3

Soft Medium Hard

4 5 6 7 8

Very soft Soft Medium Hard Very hard

1-4

1 – softest 4 – hardest

1 2 3 4 5 6 7 8 9

Datalog Wellsite Procedures Manual 1999

Milled Tooth

Chisel

Tungsten Carbide Insert

Conical

Standard product Air drilling Gauge protected Sealed bearing Gauge protected and sealed bearing Friction, sealed journal bearing Friction, sealed journal bearing, gauge protected Directional Other

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Datalog Wellsite Procedures Manual 1999

Cone Action As cones roll on the bottom of the hole, a sliding action is produced that gouges and scrapes the formation. Cones have more than one rolling centre due to number and alignment of cutter rows, but this is restrained by the weight of the drill collars acting on the bit. Rotation will therefore be around the bit centre-line so that the teeth must slide and scrape as they roll. This action is minimized in the design of hard bits (by having no cone offset) to reduce wear, but action is still not pure rolling. heel row nose row

inner heel row

middle row

The sliding action produces a controlled tearing, gouging and scraping action on the formation leading to fast and efficient chip removal. For soft formations, the scraping action is enhanced by offsetting the cones. This leads to faster drilling and the amount of scraping action depends on the degree of offset. Soft formation bits may have an offset of 1/4”, 1/8” in medium bits, none for hard bits.

jet or nozzle Bearing Types Unsealed

These are grease filled and exposed. Their life is therefore short since they are exposed to both metal fatigue and to abrasion from solids.

Sealed and self lubricating

Metal fatigue still exists, but abrasion from solids is eliminated as long as there is a seal.

Sealed journal bearings

These have a much longer life, but wear may come from seizure of the sliding metal to metal surfaces on the bottom side of bearings. If the seal fails, drilling mud will leak into the bearing, displacing the grease. Overheating will cause rapid failure of the bearing. The bearing has a pressure compensation system that minimizes the pressure differential between the bearing and the mud column pressure.

Teeth The size, shape and separation of the teeth affect the efficiency, or performance, of the bit in formations of varying hardness. The tooth design will also determine the size and form of the drilled cuttings produced and subsequently used for formation evaluation. For soft formations, the teeth are typically long, slender and widely spaced. The longer teeth allow for deeper penetration into the soft formation. This deeper penetration is maintained as the teeth become worn, by making the teeth as slender as possible. The wide spacing prevents the soft formation from balling, or packing, between the teeth. The cutting action is one of gouging and scraping and the cuttings typically produced will be large and freshly broken.

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Datalog Wellsite Procedures Manual 1999

Bearing size and strength is necessarily restricted in soft formation bits owing to the size of the teeth. This normally does not produce a problem since only low weights or force need to be applied to the bit to achieve formation failure and penetration. For formations of medium hardness, shorter, broader teeth are used. Deep penetration is limited by the formation hardness so that longer teeth are unnecessary. The length is such that as much penetration as possible is achieved while, at the same time, wear caused by the firmer formation is kept to a minimum. Wide spacing allows for efficient cleaning even though balling is not such an important consideration as in the soft formation. For drilling in hard formations, short, broad teeth produce a crushing and chipping action rather than scraping and gouging. The drilled cuttings will be smaller, more rounded, crushed and ground. Tooth spacing is not required for cleaning since cuttings are smaller, with a lower concentration, or volume, resulting from lower penetration rates. Increased life in hard, abrasive formations can be produced by hard facing the milled steel teeth or by using tungsten carbide inserts (TCI). For harder formations, fewer and smaller teeth facilitate larger, stronger bearings that can withstand the higher forces that may cause failure. Operating requirements Hard, abrasive formations require a higher force (weight on bit or WOB) being applied to the bit. The greater weight would obviously impact on the bearings, so that a corresponding lower RPM is applied, in order to minimize bearing wear. The WOB required is slightly lower for an equivalent TCI bit to prevent impact failure or cracking of the insert cutters. Softer formations require lower weight on bit in order to achieve penetration, therefore higher RPM can be applied. Similar parameters are required for both tooth and TCI bits. Too much weight being applied could actually break the longer teeth or inserts. Generally, penetration rate (ROP) is faster with more weight applied to the bit and /or higher RPM, but too much weight can have detrimental affects such as bit balling in softer formations, failure of roller bearings, seizure of journal bearings, and breakage of teeth or inserts. Diamond and Polycrystalline Diamond Compact (PDC) bits These bits have a long life since the cutters are obviously very hard and there are no bearings or moveable parts. Natural industrial diamonds are hand set into geometric designs that cover the bottom of the bit, allowing for breakage and redundancy. They also channel the mud flow from the bit, allowing for cooling and cuttings removal. With PDC bits, polycrystalline diamonds are mounted into tungsten carbide. The diamond actually does the drilling, or cutting, with the tungsten carbide providing strength and rigidity. Diamond Bit Datalog Wellsite Procedures Manual 1999

PDC Bit 20

Datalog Wellsite Procedures Manual 1999

Diamond cutters start out sharp and they wear sharp, whereas most cutters become dull with wear. This and their longer life makes them extremely cost effective for deep drilling in hard, abrasive formations. Since they have no moving parts, they are economic when high rotary speeds (perhaps above the limits of roller bearings) are produced when drilling with mud motors or turbines. They do have a long life, although ROP’s are generally slower. The overall footage, or meters achieved by the bit has to justify the much higher cost of diamond bits. The cutting action of diamond bits is more of a shearing or grinding type action. This produces cuttings that are much finer than those produced by tri-cone bits, often appearing as a very fine rock flour, and sometimes, even being thermally changed (metamorphosed) by the high frictional heat generated. This does not make the bit conducive to formation evaluation, since the structure and form of the lithology has been destroyed to a large degree. At the same time, they are unresponsive to lithological changes (changes in ROP is normally the first indication of a lithology change) therefore, again, they are not so well suited to geological interpretation. Diamond bits have different operational requirements to tri-cone bits. They typically have a slightly smaller gauge (diameter) than the hole size in order to reduce wear on trips in and out of the hole. Optimum performance is achieved with lower WOB’s and the highest RPM possible, together with high mud velocities across the face of the bit. Before drilling ahead with a new bit, it should be ‘patterned’. In other words, the profile of the bottom of the hole must match that of the bit. This is done by very slowly increasing the WOB before the start of drilling, so that the profile of the bit is cut into the bottom of the hole. Grading Of Bits Roller bits can be simply graded by the condition of the teeth (or inserts) and bearings, and also by the gauge or diameter of the bit. This is known as the TBG grading, with teeth and bearings graded on a scale of 1 to 8.

(T)eeth

1 - virtually as new 8 - completely worn

(B)earings

1 - as new 8 - complete failure

(G)auge

IG - in gauge or the measurement of the degree of undergauge i.e. 1/8 inch or 2mm

This is a very basic grading system that gives little additional or qualifying information about the bits condition. For example, the inner and outer rows of cutters may have different degrees of wear, but this system can only facilitate one recording. A more sophisticated and informative grading is provided by the IADC system.

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Datalog Wellsite Procedures Manual 1999

The IADC bit grading system

Cutting Structure Inner rows

Outer rows

0 – 8 linear scale 0 2 4 6 8

– -

no wear 25% 50% 75% 100%

Major dulling characteristics BC – broken cone BT – broken teeth CC – cracked cone CR – cored CT – chipped teeth ER – erosion JD – junk damage LC – lost cone LT – lost teeth PB – pinched bit PN – plugged nozzle RG – rounded gauge RO – ring out SD – shirttail damage WO – washed out WT – worn teeth

Bearing condition

Gauge

Location of major dulling Rollers: N – nose M – middle row H – heel row A – all rows Cone 1, 2, 3

Other dulling characteristics No – Sealed Bearings: 0–8 0 – as new 8 – life gone Sealed Bearings:

Fixed Cutters: C – cone N – nose T – taper S – shoulder G – gauge A – all areas

Datalog Wellsite Procedures Manual 1999

Remarks

E – effective F – failed

I – in gauge Undergaug e measured to the nearest 1/16 inch

Same codes as major dulling characteristics

Reason pulled

BHA – change BHA DMF – downhole motor failure DSF – drill string failure DST – drill stem test LOG – run logs CD – condition mud CP – core point DP – drill plug FM – formation change HP – hole problems HR – hours on bit PP – pump pressure PR – penetration rate TD – total depth (or casing point) TQ – torque TW – twist off WC – weather conditions

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Datalog Wellsite Procedures Manual 1999

The Drillstring Very simply, the drillstring is made up of drill pipe and drill collars, with a number of smaller, additional components, connecting the surface systems to the drill bit. The main purposes of the drillstring are: • • • •

Provide a conduit from the surface to the bit so that drilling fluid can be conducted under pressure. Transmit rotation, that is applied at surface, to the bit. Transmit force, or weight, to the bit so that failure of the formation is more easily achieved. Provide the means to lower and raise the drill bit in the wellbore.

All connections from the swivel to the upper kelly are made with left-hand threads whereas all connections from the lower kelly to the drill bit are made with a right hand thread. With rotation of the drillstring to the right during drilling, connections will tend to tighten rather than loosen or back off. All tubular sizes, whether drillpipe, drill collars or casing, are standardized by the American Petroleum Institute (API) by way of the outside diameter (OD) of the tube. Drillpipe This comprises the main component, in terms of length, of the drillstring. Each length (referred to as a single or a joint) of drillpipe, constructed of steel, is commonly either 10 or 15m in length. Each end of the pipe has a tapered tool joint, either male or female, that is welded or shrunk on so that lengths of pipe can be easily screwed together. The ‘shoulder’ around the tool joint is enlarged or upset to provide extra strength to the connections. The drillpipe is available in various diameters (OD) although the most commonly used is 5 inches or 127mm. The inside diameter (ID) of the drillpipe will vary depending on the weight per unit length of the pipe. The larger the weight, the smaller the ID. Commonly, the drillpipe (for OD 127mm) used is 19.5 lb/ft or 29.1 kg/m: This gives

OD 5” or 127mm ID 4.28” or 108.7mm

Drillpipe is also available in different grades of steel giving different degrees of strength, where ‘D’ is the weakest and ‘S’ the strongest. Heavy or thicker walled drillpipe is normally called ‘heavy-weight’ drillpipe. This heavier pipe is situated above the drill collars in the drillstring to provide extra weight and stability. As with ‘standard’ drillpipe, heavy-weight is available in different OD’s and varying ID’s depending on the weight of the steel. Heavy-weight drillpipe will differ in appearance from standard drillpipe in that they have longer tool joints.

Commonly, the weight (for OD 127mm) used is 49.3 lb/ft or 73.5 kg/m This gives

OD 5” or 127mm ID 3” or 76.2mm

Notice that the heavy-weight drillpipe has the same OD as the standard drillpipe, and as we shall see, the same ID as the drill collars.

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Datalog Wellsite Procedures Manual 1999

Drill Collars Drill collars are rigid, thick walled, heavy lengths of pipe that go to make up the main part of the Bottom Hole Assembly, positioned between the drillpipe and the bit. Collars have several important functions: • • • • •

Provide weight for the bit. Provide the strength required so that the collars are always in compression. Provide weight to ensure that the drillpipe is always held in tension to avoid buckling. Provide rigidity or stiffness so that hole direction is maintained. Produce a pendulum effect, allowing near vertical holes to be drilled.

As with drillpipe, drill collars are available in several diameters (OD) with the ID diameter variable due to varying weights of steel. Typically, the ID is similar to that of the heavy-weight drillpipe, close to 3” or 76mm.

Square drill collar

Spiral drill collar

Smooth drill collar

The weight applied to the bit must come from the drill collars only. If the weight applied to the bit was to exceed the total weight of the drill collars, the extra weight would be coming from the drillpipe which would be subject to buckling and twist-off (breaking) at the tool joints. The weight of the collars acting directly on the bit has two main consequences: •

The tendency for the string to hang vertically due to the weight and gravity. The heavier the drill collars, the more likely it is that the bit will not deviate from a vertical position.

•

The weight acting upon the bit will stabilize it, making it more likely that the hole being drilled will follow the path of the section just drilled i.e. maintaining hole direction. This bit stabilization also allows for even distribution of the load across the cutting structure of the bit. This prevents the bit from wandering or migrating from a central position, ensuring a straight, properly sized or gauged hole, even bit wear and faster penetration rates.

The maintaining of the hole direction is assisted not only by the weight and stiffness of the drill collars at the base of the drillstring, but will also be greatly assisted if the OD of the collars is only slightly smaller than the bit diameter or actual hole size. This is known as a ‘packed-hole assembly’. A problem with this type of arrangement is that the collar part of the drillstring will be very prone to differential sticking, where the pipe becomes stuck in the filter cake covering the borehole wall. The risk of this is minimized by utilizing a number of different designs in the sectioning, or grooving, of the collars to reduce the surface area of the drill collar that is in contact with the wellbore. Thus, collars may be round, square or eliptically sectioned, spirally grooved etc.

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Datalog Wellsite Procedures Manual 1999

The Bottom Hole Assembly (BHA) This is the name applied to the drill collars and any other tools incorporated with them, including the bit. The drillstring is therefore made up of the drillpipe (heavy-weight drillpipe is normally distinguished as well) and the BHA. Stabilizers These are a short length of pipe, or sub, positioned between the drill collars in order to centralize them and maintain a straight hole and, by way of a scraping action, they maintain a full sized, or gauged, hole. The full gauge is provided by ‘ribs’ or blades mounted on a mandrel. These may be made from solid rubber or aluminium, or more typically, they are made from steel with tungsten carbide inserts on the facing edges. Stabilizers can be categorized into rotating or non-rotating blades, with the ribs or blades being generally spiral or straight. Reamers Roller Reamers will ream the hole just behind the bit and perform a similar function to the stabilizers in that they stabilize the assembly and help maintain a full gauge hole. They are more typically used when problems are being experienced in maintaining a full gauged hole, particularly in abrasive formations, when the bit is worn undergauge. Similarly, they may be used if key seats or ledges are known to exist in the borehole. The number and position of reaming ‘blades’ will categorize the type of reamer. For example, with three blades, it is termed a 3-point reamer. If they are positioned towards the base of the sub (as shown), it will be termed a 3-point near-bit reamer. A stabilizer reamer will have the blades positioned centrally in the sub.

3-point near-bit reamer Under Reamers are also placed directly behind the bit to ream the hole and maintain full gauge or enlarge the hole. The reaming or cutting action is by way of rotating cones located on collapsible arms. These are opened and held out during drilling by the pressure of the mud passing through the tool. This enables the tool to pass through a narrow diameter hole section, then open up and drill a wider hole. Hole Opener This is a similar tool to the under reamer, in that a cutting action is provided by rotating cones in order to enlarge a hole. Unlike the under reamer however, the cones are in a fixed position so that the hole opener has to be able to pass through the ‘previous’ hole diameter. They are therefore generally used on surface hole sections to widen the hole where large hole diameters are required. Cross Over Sub A small length of pipe enabling drillpipe and/or collars of different diameters and threads to be connected together.

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Datalog Wellsite Procedures Manual 1999

Jars A mechanically or hydraulically operated device to provide a high impact ‘hammer’ blow to the drillstring downhole, in the event that it becomes stuck. Jars are designed specifically for drilling or fishing (retrieval of part of the drillstring left downhole) operations. Should the drill string become stuck and incapable of being freed with normal working (i.e., upward and downward movement) of the pipe or by pulling on the pipe without exceeding drill string and surface equipment limitations, then rotary drilling jars will be used. Rotary drilling jars are tools designed to strike heavy-impact hammer blows, in an upward or downward direction, to the drill string. The direction in which the jar is activated depends upon the pipe movement when it became stuck. A downward blow is struck if the pipe was stationary or moving upwards. An upward blow will be struck if the drill string was moving downwards. The majority of stuck pipe situations result from an upward moving, or stationary, pipe so that, typically, downward jarring is required. To free the pipe, the jar needs to be situated above the stuck point so, typically, jars will be situated in the upper apart of the bottomhole assembly, certainly above stabilizers and other tools most prone to sticking. Jars can be hydraulically or mechanically triggered, but both work on the same principle. That is, the jar consists of an outer barrel which is attached to the drill string below (the stuck pipe) and an inner mandrel which, attached to the free string above, can slide, delivering rapid upward or downward acceleration and force. •

Hydraulic jars operate on a time delay produced by the release of hydraulic fluid. As the mandrel is extended, the hydraulic fluid is released slowly through a small opening. Over several minutes, opening continues but is restricted by the hydraulic metering. The fluid channel then increases in diameter allowing rapid flow and unrestricted, rapid opening of the jar, known as its stroke. At the end of the stroke, typically 8 inches, a tremendous blow is delivered by the rapid deceleration of the drill string above the jars which were accelerating through the stroke. Drill String is Slacked Off

Drill String is Raised

Gravity Accelerates BHA Mass

8” Drop

Jar Cocks

Jar Latch Trips

Stuck Pipe

Impact is Delivered Step 1

•

Step 2

Step 3

Mechanical jars deliver the hammer blow by the same acceleration/deceleration of the jars, but the triggering mechanism is by a pre-set tension with no time delay once the jar has been cocked.

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Datalog Wellsite Procedures Manual 1999

•

A jar accelerator may be set above the rotary jars, typically within the heavy-weight drill pipe, to intensify the blow delivered by the jars. Upward strain compresses a charge of fluid or gas (commonly nitrogen) and, when the rotary jar trips, the expansion of fluid or gas in the accelerator amplifies the jarring effect. A jar accelerator offers the advantages of confining movement to the drill collar—or close to the stuck point—and minimizing shock on the drill string and surface equipment by cushioning rebounds through the compression of fluid or gas.

If jarring is unable to free the stuck pipe, the only recourse is to back off the pipe that is still free. This may be achieved by simply twisting off, or unscrewing, the free pipe; or by determining the free point with a wireline tool, then running an explosive charge, on wireline, to blow the string apart. The remaining stuck pipe now has to be either retrieved, removed or avoided before drilling can continue.

Shock Sub This will be positioned close behind the bit where hard formations cause the bit to bounce on the bottom of the hole. They are designed to absorb the impact from this bouncing in order to prevent damaging the remaining part of the drillstring. This may be done by way of springs or rubber packing.

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Datalog Wellsite Procedures Manual 1999

BLOW OUT PREVENTION SYSTEM During normal drilling operations, the hydrostatic pressure, at any depth, exerted by the column of drilling fluid inside the well exceeds the pressure exerted by the formation fluids. Thus, the flow of formation fluids (influx or kick) into the wellbore is prevented. Should, however, the pressure due to the formation fluid exceed the hydrostatic pressure of the mud column, the formation fluid, be it water, gas or oil, will be able to feed into the wellbore. This is known as a kick. A kick is defined as an influx of formation fluid into the wellbore that can be controlled at surface. When this flow of formation fluid becomes uncontrollable at surface, the kick becomes a blowout. To prevent the occurrence of a blowout, there needs to be a way of ‘closing’ or shutting off the wellbore so that the flow of formation fluids remain under control. This is possible with a blowout prevention system (BOP), an arrangement of preventors, valves and spools that sit atop the wellhead. This arrangement is commonly referred to as the stack.

The BOP stack must be able to: • • • •

Close the top of the wellbore to prevent fluid from escaping to surface and risking an explosion. Release fluids from the wellbore under safely controlled conditions. Enable drilling fluid to be pumped into the well, under controlled conditions, to balance wellbore pressures and prevent further influx (kill the well). Allow movement of the drillstring.

The size and arrangement of the BOP stack will be determined by the hazards expected and the protection required, together with the size and type of pipe being used. The basic requirements of the BOP stack means: • • • • •

There must be sufficient casing in the hole to provide a firm anchor for the stack. It must be possible to close off the well completely, whether there is pipe in the hole or not. Closing the well must be a simple and rapid procedure easily understood and performed by the drilling personnel. There must be controllable lines through which pressure can be bled off safely. There must be a means to circulate fluid through the drillstring or annulus so that formation fluid can be removed from the wellbore, and so that higher density mud can be circulated to balance the formation pressure and control the well.

There are additional requirements in the case of floating rigs, where the BOP stack will be situated on the seabed. Should the rig have to temporarily abandon the well, there must be means to shut the well in completely, by hanging off or shearing any pipe in the hole. The marine riser can then be detached from the wellhead, allowing the rig to move away to a safe location but able to return and re-enter the well at a later time. During normal operations, the marine riser will be subjected to lateral movement due to the water current. The attachment of the riser to the stack must therefore be by way of a ‘ball joint’ to prevent movement of the stack. BOPs have various pressure ratings established by the American Petroleum Institute (API). This will be based upon the lowest pressure rating of a particular item in the stack such as a preventor, casing head or other fitting. A suitably rated BOP can therefore be installed depending on the rating of the casing and expected formation pressures below the casing seat. BOPs commonly used have ratings of 5, 10 or 20000 psi.

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Datalog Wellsite Procedures Manual 1999

Closing the well This is achieved with preventors or rams, enabling the annulus to be closed off or the complete wellbore to be closed off, with or without pipe in the hole. Annular Preventor This is a reinforced rubber seal, or packer, that surrounds the wellbore. When pressure is applied it will close around the pipe, sealing off the annulus. The annular preventor has the advantage that with pressure progressively applied, it will close in on any size of pipe or any shape. The wellbore can therefore be closed in regardless of whether the kelly, drillpipe or drill collars are passing through the stack. This adaptability does not, however, extend to spiral drill collars or tools such as stabilizers where the shape is irregular. The annular preventor also allows for slow rotation or vertical movement of the drillstring while the annulus remains closed off. This allows for pipe to be tripped in (“snubbing) or out (stripping) of the hole while the well is still under a controlled condition. Most annular preventors are also able to seal across an open wellbore, but this will shorten the life of the packer and should be avoided. Ram Type Preventors These differ from the annular preventor in that the rubber sealing element is comparitively rigid and will seal around pre-designated shapes. They are made to seal around specific objects (pipe and casing rams) or over an open hole (blind rams). They can be equipped with shearing blades that can cut through drillpipe or casing and still have the ability to seal an open hole (shear/blind rams). Pipe or Casing Rams Annular preventor Here, the rubber faces of the ram are moulded to match the outside diameter of specifically sized pipe. The rams can therefore close around that specific drillpipe exactly, closing off the annulus. If more than one size of drillpipe is being used, the BOP stack must include pipe rams for each size of pipe in the hole. Blind or Shear Rams

Ram preventors

Datalog Wellsite Procedures Manual 1999

These rams, closing from opposite sides, will close off the complete borehole when there is no drillpipe in the hole. If there is pipe in the hole, the rams will crush it or cut through it if equipped with shear blades (shear rams). Shear rams are more typically used in subsea stacks so that, if pipe is in the hole, the well can be completely closed off should the well have to be temporarily abandoned. Blind rams are more typically used in stacks situated under the drillfloor.

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Datalog Wellsite Procedures Manual 1999

Closing the preventors The preventors are closed hydraulically with hydraulic fluid supplied under pressure. If the stacks are accessible, i.e. on land rigs and jack-ups, the rams can also be closed manually. The basic components to a preventor closing system are: • • • • • •

Pumps providing a source of pressure. A source of power to drive the pumps. Suitable hydraulic fluid to open and close the preventors. A control system to direct and control the fluid. A source of pressure when normal sources fail. Backup sources of power.

There has to be means to store the hydraulic fluid under pressure and a means of the delivering it to the preventors. To be taken into account is the fact that different preventors require different operating pressures and preventors of different sizes will require varying amounts of fluid for opening and closing.

A

B

C

Accumulator bottles

Accumulators Accumulator bottles provide the means to store, under pressure, the full amount of hydraulic fluid required to operate all of the BOP components and effect rapid preventor closure. Several accumulator bottles can be linked together to provide the necessary volume. The accumulator bottles are precharged with compressed nitrogen (typically 750 to 1000 psi). When hydraulic fluid is forced into the bottle, by way of air or electrically powered pumps, the nitrogen is compressed thereby increasing the pressure. Typically, to ensure BOP operation, a closing unit will have more than one pressure source in case of failure. Similarly, if air or electrical pumps are being used in the closing unit, there will be more than one source of air, more than one source of electricity etc. There should always be a

backup. The operating pressure of the accumulator is typically 1500 to 3000 psi. A minimum operating pressure of 1200 psi is normally assumed. These pressures will determine the amount of hydraulic fluid that can be supplied from each bottle and from this, the number of bottles needed to supply the full amount of fluid to operate the BOP can be determined.

e.g.

A. Precharge

volume of bottle = 40 litres,

B. Max Fluid Charge

pressure = 3000 psi

C. Minimum Operating Pressure

= 1200 psi

precharge pressure = 1000 psi volume of N2 = 1000 x 40 / 3000 =13.33 litres volume of N2 = 1000 x 40 / 1200 =33.33 litres

Therefore, the amount of usable hydraulic fluid in each accumulator bottle = 33.33 - 13.33 = 20 litres

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Datalog Wellsite Procedures Manual 1999

A hydraulic control manifold, consisting of regulators and valves, controls the direction of flow of the high pressure hydraulic fluid. The fluid will be directed to the correct ram or preventor and the regulators will reduce the pressure of the hydraulic fluid from the accumulator operating pressure to the operating pressure of the preventor (typically in the region of 500 to 1500 psi). All components to the closing system; pressure source, accumulators, control manifold, master control panel, should be located a safe distance from the wellbore. Control Panel Typically, there will be more than one control panel. The master panel will be located on the drill floor convenient to the driller (typically in the doghouse). An auxiliary panel will be placed in a safe area so that, should the driller’s panel fail and the accumulator panel not be reachable, the well can still be safely controlled. The control panel is air operated and will typically provide gauges to show air pressure to the control panel and pressures throughout the system such as accumulator, air supply manifold and annular preventor. The panel will also typically include preventor control valves to open or close preventors, valves to open or close the choke and kill lines and a pressure control valve to adjust the pressure of the annular pressure. Positioning of the rams Typically, one annular preventor will be placed at the top of the stack. The best arrangement for the remaining rams depend on the operations that may need to be carried out. The possibilities are that blind rams are sited above all pipe rams, below all pipe rams or between pipe rams. The operations possible are then governed by the fact that blind rams cannot shut off the well if pipe is in the hole. With blind rams in the lower position, the well can be closed if no pipe is in the hole and all other rams can be repaired or replaced if required. In case of blowout with pipe out of the hole, the well can be closed and pressure reduction achieved by lubricating mud into the well below the rams. With an annular preventor above, drillpipe can be stripped into the well by holding pressure when the blind ram is opened. A disadvantage is that drillpipe cannot be hung off on pipe rams and the well killed by circulation through the drillstring. With blind rams in the upper position, lower pipe rams can be closed with pipe in the hole, allowing the blind rams to be replaced with pipe rams. This will minimize wear on the lower pipe rams with the upper rams taking the additional wear as a result of working the drillstring with rams closed. Drillpipe can also be hung from the any of the pipe rams, backed off and the well completely closed by the blind rams. The main disadvantage is that the blind rams cannot be used as a ‘master’ valve allowing for changing or repair of rams above. Kill Lines The placement or configuration of the rams will affect the positioning of the kill lines. These will be located directly beneath one or more of the rams, so that when the rams are closed, fluid and pressure can be bled off under control (choke line). The choke line is routed to the choke manifold where pressures can be monitored. An adjustable choke allows for the ‘back pressure’ being applied to the well to be adjusted in order to maintain control.

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Datalog Wellsite Procedures Manual 1999

FLOWLINE

ANNULAR PREVENTOR

CHOKE + KILL LINES BLIND/SHEAR RAMS

PIPE RAMS

PIPE RAMS

PIPE RAMS

CASING HEAD

They also allow for an alternative way of pumping drilling mud or cement into the wellbore should it not be possible to circulate through the kelly and drillstring (kill line). The kill line will normally be lined up to the rig pumps, but a ‘remote’ kill line may often be employed in order to use an auxiliary high pressure pump. Although preventors may have side outlets for the attachment of choke and kill lines, separate drilling spools are often used. This is a drill-through fitting that fits between the preventors creating extra space (which may be required in order to hang off pipe and have enough room for tool joints between the rams) and allowing for the attachment of the kill lines. On floating rigs, when the BOP stack is on the seabed, the choke and kill lines are attached to opposite sides of the marine riser. The lines have to flexible at the top and the bottom of the riser to allow for movement and heave. The Diverter A diverter is typically employed before the installation of a BOP stack. The diverter, installed directly beneath the normal bell nipple and flowline assembly, is a low pressure system. It’s purpose is to direct any well flow or kick away from the rig and personnel, providing a degree of protection prior to setting the casing string that the BOP stack will be mounted on.

The diverter system is only designed to handle low pressures. It is designed to pack off or close around the kelly or drillpipe and direct the flow away. If it were attempted to control high pressures, or completely shut Simple BOP stack schematic in the well, the likely result would be uncontrolled flow and breakdown of formations around the shallow casing or conductor pipe. The use of a diverter is essential in offshore drilling. Inside Blowout Preventers Complete blowout prevention is only achieved when both the annulus and the inside of the drillpipe are closed off. The preventors and rams so far described primarily close off the annulus. Blind rams only close off open holes without drillpipe and shear rams cut the drillpipe rather than closing off. Inside BOPs are pieces of equipment that can close off the inside of the drillpipe. There are two main types: 1.

Manual shut off valves employed at the surface.

2.

Automatic check valves situated in the drillstring downhole

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Datalog Wellsite Procedures Manual 1999

Choke Manifold

Surface Shut Off Valves Kelly Safety Valve

This is installed on the lower end of the kelly, with different sizes available for all sizes of pipe.

Kelly Cock

This is installed between the swivel and the kelly

Drillpipe Safety Valve

This is manually screwed, or stabbed, into open drillpipe held in slips. This allows for quick shut off should backflow occur during tripping when the kelly is racked.

Downhole Check Valves Drop-in Check Valve

This can be sited at any position in the drillstring, requiring a landing sub. If there is danger of a blowout, the valve is pumped down the string, lands in the sub and provides continuous protection. This should be employed before shearing drillpipe so that the drillpipe is protected against flow up the pipe.

Drillpipe Float Valve

This can be positioned directly above the bit to prevent backflow into the drillstring, providing instantaneous shut off against pressures and fluid flow. Some floats have vented flappers allowing shut-in pressures to be accurately monitored.

Rotating BOPs Otherwise known as a rotating control head, the function of the rotating BOP is specifically as a rotating flow diverter, which is mounted on the top of a normal BOP stack. Simply, the RBOP allows vertical movement and rotation of the drillstring while a rubber ‘stripper’ seals around and rotates with the string, allowing flow to be contained and diverted. This type of unit has obvious advantages for underbalanced drilling, when drilling with high pressures or, increasingly, for enhanced safety, RBOPs are being used in normal drilling applications. While well pressures are contained by the rubber seal around the drillstring or kelly, flow is diverted by way of a steel bowl and bearing assembly. The bearing assembly enables the inner part to rotate with the drillstring while the outer part is stationary with the bowl. Seals are typically of two types: Datalog Wellsite Procedures Manual 1999

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Datalog Wellsite Procedures Manual 1999

1.

A cone shaped rubber that seals around the drillstring. The ID of the seal is slightly smaller than the OD of the pipe so that the seal stretches to provide an exact seal around the pipe. No hydraulic pressure is required to complete the seal since the pressure is provided by wellbore pressures acting on the cone rubber. The rubber is therefore self-sealing, the higher the wellbore pressure the greater the seal.

2.

A packer type seal requiring an external hydraulic pressure source to inflate the rubber and provide a seal. A seal will be given as long as the hydraulic pressure is greater than the wellbore pressure.

The huge advantage of the rotating BOP is that, since rotation and vertical movement are possible while an annular seal is present, drilling can commence while a flowing well is being safely controlled. The assembly is easily installed, and the rubbers easily inspected and replaced with minimum loss of time. If the wellbore pressure approaches the maximum capability of the RBOP (typically 1500 to 2500psi), the well should be controlled conventionally using the BOP preventors.

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