Section 7 Marine Drilling Riser Systems
Diverter Telescopic Joint
Riser Joints
LMRP BOP
Wellhead
A marine drilling riser system provides a tubular conduit from the rig to the subsea BOP and the wellbore below it. The riser assembly guides downhole tools and equipment from the surface to the wellbore, permits drilling fluids to circulate back to the rig, and carries the BOP stack as it is run or retrieved. The drilling riser is composed of a series of specially designed joints which are connected together by couplings. Choke and kill lines for the BOP are run integrally down the outside of the riser tube along with other auxiliary lines. Marine drilling riser joints are made from seamless X-52, X-65, or X-80 line pipe material and normally come in 50, 75, or 90 foot joint lengths. Deep water marine risers are made of FG 47 T or RFG 57 T material. Each integral drilling riser joint will have a connector box and pin welded at each end. A set of pup joints is usually supplied with a riser string so that the riser can be spaced out for any water depth. Pup joints of 5’, 10’, 20’, and 25’are normally supplied.
Drilling Riser Joints
Support flanges and guide gussets are incorporated into each joint to facilitate handling of the heavy riser joints. The flanges support the riser as it is run, provide recesses for the choke and kill lines and have deflector plates to prevent hanging of the riser as it passes through the rotary. The choke and kill lines are clamped to the body of the riser joint. Usually three clamps are used on a 50 foot length. This eliminates the welding of support brackets to the riser body. This feature avoids any possibility of stress concentrations in the riser body that short surface welds might produce. The support flanges generally have extra preparations for shackles and handling slings. Sometimes mud booster lines are integrally attached to the marine riser. These are used to increase the velocity of the mud returns in the large diameter riser systems when drilling inside smaller casing strings. On some of the deep water systems, where electrohydraulic or multiplex control systems are used with the blowout preventer equipment, one or two fluid supply lines are also incorporated into the riser joints in a manner Drilling Riser Joints on the rig pipe rack
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similar to the choke and kill lines. Gussets fabricated as part of the support flange help to guide the riser joint through the rotary table after each connection is made. Riser diameters are based on the size of the BOP over which they are run. The most common sizes are 21”for 18-3/4”BOP, and 18-5/8”for 16-3/4”BOP. Riser system design and selection is based on complex analysis of the loads which the riser will develop during use. This is based on combined tension and bending loads produced by the length of the riser string. Other loads which should be considered are loads induced by the differential pressure between the seawater outside the riser and the drilling fluid inside the riser, loads induced by the choke and kill lines, loads induced by buoyancy, and loads induced during handling. Riser coupling design capacities must be within the stress levels induced by the indicated loads. API RP 2R establishes riser coupling classes based on the tensile capacity of the coupling. These are; API Riser Coupling Class
Tensile capacity in millions of pounds
Class A
.5
Class B
1
Class C
1.25
Class D
1.5
Class E
2
Class F
2.5
Drilling Riser Connectors ABB Vetco Gray has produced three types of drilling riser connector, one using a split circumferential lock ring, various connector designs using dogs for the locking mechanism, and a flange style deep water riser connector. The first drilling riser connector manufactured by ABB Vetco Gray was the BT connector, which was modified to become the BTM and then the BTL. The BTL box section has a series of bosses welded to the body, which house actuating screws. After the box section is stabbed over the tapered pin section, the actuating screws are tightened t force the split lock ring into the mating groove of the pin. This external boss and actuating screw make-up method is still in use today with newer connector designs. The tensile load capacity of the BTL connector is rated at 750,000 pounds.
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The need for a stronger more durable connector led to the development of the MR-4 connector, then the MR-4B, MR-6B, MR-6C, and MR-6D. The progression reflects the continuing need to increase the connector tensile capacity for deeper water and longer drilling riser strings. Other marine riser connectors supplied by ABB Vetco Gray in the past include the FC and FD style couplings the most recent of which were designated FC-8 and FD-8. These were also locking dog style couplings for shallow and intermediate water depths. MR Type Riser Connector The “MR”type riser connector is characterized by a box and pin arrangement which mate to make the connection. The box member has bolt on bosses which contain hex headed actuating screws. At the inboard side of the connector, dogs are attached to the actuating screws. A double groove profile on the pin member provides the mating profile for the dogs to impinge, and lock the connector together when the
MR-6 Pin Riser Connector
actuating screws are tightened driving the dogs inward. The mating grooves on the pin have a 10o taper which forces the connection together as they are made up, creating a preloaded connection with the load distributed evenly over the pin. An o-ring carried in the connector box is the primary pressure seal. An additional o-ring on the pin below the mating profile keeps trash and corrosion out of the connector’s moving parts. MR-6 Box Riser Connector The actuating screws on the MR series of connector require about 1000 ft/lbs of torque to achieve the proper preload. An air impact wrench of known output is typically used to make up the connection. The actuating screws should be kept lightly greased with a nonmetallic grease compound for best operation and life of the connector.
The drilling riser column is subjected to a great deal of vibration which could potentially loosen the actuating screws on the connector. A spring loaded lock
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ring which captures the hex head of the actuating screw as the wrench is removed, locks the actuating screw in the fully engaged position. The support plates and boss mounts on the MR type connectors are an integral part of the forging. The only welding required is the coupling to joint weld. The support plates have holes specifically designed for easy handling using shackles and slings. Choke and kill stabs mate easily and utilize dual polypak seals. The MR type connector has been manufactured with either four or six locking dogs. These include the MR4B, MR-4C, MR-6C, MR-6D, and MR-6E. In the designation the MR stands for “Marine Riser”the number stands for the number of locking dogs, and the B, C, D, or E stands for the API riser coupling class. The MR riser design has only recently been developed for use as a Class E riser coupling. Class D risers are typically good for water depths to
HMF Box Riser Connector
6,000 feet. Class E riser should be good to 8,000 feet. Type HMF Riser Connector The need for a marine riser connector to be used for drilling applications in water depths exceeding 6,000 feet has led to the development of the ABB Vetco Gray HMF connector. This high strength flanged marine riser connector, designed with the aid of CAD/CAM and finite element analysis, is HMF Pin Riser Connector especially suited for deep water drilling where high tensile and bending loads are encountered. The connector has high preload and fatigue strength, yet is designed for easy field maintenance. Significant features of the HMF connector are: • Flange sections are compact and light weight in comparison to other flange connectors. There is no direct threading into the connector body. • Tapered nose pin containing resilient seals allows for easy, even connector stabbing and make-up, even under conditions of severe vessel motion.
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• Nose pin insert locks positively into the connector with set screws. If damaged during drilling or production operations, pin inserts are easily removed and replaced in the field. All other components are also replaceable for simplified maintenance. • High preload provides for longer service life and increased fatigue strength and ensures that no separation of the flanges takes place under maximum loading conditions. • Same type of integral choke and kill line stabs that are already in use on other ABB Vetco Gray marine riser systems. • Polypak lip type seals assure pressure integrity. An optional high-pressure metal to metal seal is also available. • Locking bolt assemblies are self-contained with no loose parts. They are easily removed for inspection. There are either 6 or 8 bolts on an HMF connector, depending on riser diameter and customer preference. The bolts require approximately 10,000 ft./lbs of torque to achieve the desired preload condition. Specially designed hydraulic wrenches are available for these connectors. • The HMF, being a deep water riser, will often be outfitted with air can or syntactic foam buoyancy. Riser joints are set up for bouyancy module installation. • Fast, sure make-up and disconnect. • Female choke and kill line element free to float, reducing stress in the connector and choke and kill lines when the riser flexes. Drilling Riser Handling Tools Running drilling riser systems requires two marine riser handling tools and a marine riser handling spider which sits in the rotary table. The riser handling tool has a drill pipe stem with a tool joint box looking up. At the lower end of the stem is a marine riser connector box looking down. The box member of the handling tool makes up to the pin member of the riser joint being handled. Two handling tools are normally used so that one can be used to lower the riser joint through the rotary table, while the other is installed on the next riser joint. Riser Handling Tool made up to riser joint as it is lifted by pipe elevators
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Drilling Riser Handling Spider The Marine Riser Handling Spider can be a split, gimballed, hinged or hydraulic unit that is used to support the marine riser and BOP stack as the riser joints are lowered and landed at the rotary table similar to a set of rotary slips. The marine riser support flange on the riser connector pin rests on the dogs of the handling spider. It is important to note that the correct Hydraulic Riser Handling Spider size spider dog be used for the size of the riser being run. The dog segments must extend in close to the connector body when supporting a joint from the rotary table, otherwise, the weight on the riser will be transferred to the flange alone rather than to the pin connector body. A shock absorbing/gimballed spider is a popular device used to minimize the peak stresses on the support flanges. These units are particularly effective when long riser strings are run. A single riser system requires adjustable spider dogs. One setting is for the individual riser joints and another is for the large diameter of the outer barrel of the telescopic joint. The handling spider used with a 37-1/2”rotary table has hinged end pieces on each dog, allowing for two adjustments. The spider used with a 49-1/2”rotary table has sliding dog segments adjustable to five different positions. When running the BOP stack, periodic pressure testing of the choke and kill lines is advisable to ascertain the integrity of the stab sub seals. Separate test caps, or test caps integral to the handling sub, are used to do this. Usually, choke and kill lines are tested every fourth or fifth joint.
Spider with shock absorbing gimble 7-6
Telescopic Joints The telescopic joint (slip joint) is the top joint in the drilling riser system. It compensates for the effect of heave and tidal motion on the drilling vessel. It also provides a means of connecting the diverter to the drilling riser system. The outer barrel supports the terminal fittings for the choke and kill lines and also provides the attachment for the riser tensioning system. ABB Vetco Gray’s Telescopic Joints have a stroke capability of 55 or 75 feet, and a tensile load capacity of greater than 1,000,000 pounds in the extended or locked position. Taking tidal conditions into consideration, the riser joints are spaced such that the slip joint is at midstroke once the hydraulic latch, or BOP is landed. The telescopic joint is comprised of an inner barrel and an outer barrel. The inner barrel is attached to the diverter which in turn is secured to the underside of the rotary table beams. The outer barrel is attached to the last riser joint by means of a drilling riser connector. The telescopic joint packing elements, located in a packing box attached to the outer barrel, provides the annular seal between the inner barrel and the outer barrel. The elements are of a dual Telescopic Joint and Riser Support Ring design. The outer element is either pneumatically or hydraulically expanded into contact with the inner element. Further expansion extrudes the rubber of the inner element around the slip joint inner barrel to effect a seal. In telescopic joints with two packing elements, the upper inner seal is a split rubber element which is pneumatically activated by the outer element, normally 10 to 15 p.s.i. is adequate. Being of a split design, the element, if worn or damaged, can be replaced without removing the upper end connection from the inner barrel.
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In operation, it is suggested that just enough pressure be applied so that there is a slight weeping between the packing element and the inner barrel. This small amount of leakage has a lubricating effect and avoids excessive wear to the packing element. In most cases, a constant flow of water directed at the inner barrel just above the packing box will provide better lubricity. The lower dual solid elements are intended for use when higher than expected pressure Telescopic Joint lifted occurs in the marine riser. The assembly off of the pipe rack acts as a back-up seal when the upper seal malfunctions or wears out. The operating pressure required on this lower solid seal element, which is hydraulically actuated, ranges from 15 to 300 p.s.i. depending upon the marine riser internal pressure. The upper end of the inner barrel is threaded so that the marine riser connector pin or crossover adapter can be removed for replacement of the solid seal elements. The telescopic joint can be locked in the closed position by inserting pins through four clevis style lugs on the outer barrel to engage the four lugs on the inner barrel end connection. These are special high tensile pins which should never be substituted. An optional hydraulic release of the inner and outer barrels is available. This feature is popular with contractors who prefer to land the BOP stack with the telescopic joint in the pinned position. Riser Tensioner Support Rings The riser tensioning cables are connected to a riser tensioner support ring which is attached to the outer barrel of the telescopic joint. These support rings come in many different configurations depending on customer requirements. The support ring, with integral pad eyes for attachment of the riser tensioner cables, can be a permanently fixed solid ring or a removable hinged rotating ring. The advantage of this type of support system is the initial investment, however, since these are normally pre-attached to the outer barrel of the telescopic joint, the individual tensioner Riser Support Ring cables must be attached to the pad eyes while the unit is suspended in the moon pool. This can be a difficult and time consuming task.
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An alternative is the use of a solid circumferential support ring that has all the tensioner cables pre-attached. This unit, called the SDL support ring is stored underneath the diverter housing when not in use. The riser pipe is run through the SDL ring until a support plate on the outer barrel of the telescopic joint is adjacent to the SDL support ring dogs. The dogs are then hydraulically pivoted out underneath the support plate. After unlatching the SDL ring from the diverter housing, it is carried down with the telescopic joint as it is lowered. The riser tensioners can now be pressured up to support the complete riser string. This type of a riser support system is much safer and less time consuming to install. After the proper amount of tension has been applied to the riser string, the choke and kill terminations on the outer barrel of the telescopic joint are attached to the rig floor manifold piping with high pressure flexible lines (drape hoses) and terminal fittings. To increase personnel safety and save rig time, a combination riser support ring and terminal fitting assembly is available. This assembly is known as the KT style support ring. The choke and kill lines terminate into a mandrel carried on the telescopic joint outer barrel. The KT support ring, like the SDL support ring, has all the tensioner cables pre-attached. But, unlike the SDL ring, the choke and kill line drape hoses are also pre-attached. Once the KT ring is mated with the telescopic joint outer barrel, sleeves are hydraulically extended into pockets on the mandrel to seal the terminal fitting drape hose interface. On most vessels, the terminal fittings with drape hoses attached will now be swung out from their stored position and made up to the male stab terminations on the outer barrel of the telescopic joint. To contain them while under pressure, the two terminal fittings for the choke and kill lines are trapped under a thrust plate on the outer barrel. The choke and kill female stab subs on the terminal fitting are identical to those on the integral marine riser joints and provide a crossover connection from the choke and kill lines on the marine riser to the flexible lines extending from the choke and kill manifold on the drilling vessel’s rig floor. An automatic pull-in and attachment of the terminal fittings is an option available on all telescopic joints. The BOP, flex joint and riser string are then lowered and soft landed onto the High Pressure Wellhead Housing using either the motion compensator or riser tensioners. The last operation is to hook up the flow diverter.
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Diverter Systems KFDS The KFDS flow diverter is connected to the inner barrel of the telescopic joint and solidly secured under the rotary table inside a diverter housing. This housing is a permanently attached ring, fabricated to the beams under the rotary table during the building of the vessel, or it can be retrofitted to existing vessels. It has one to four 12” or larger outlets (depending on contractor preference) for mud returns and diverting flow during shallow gas kicks. This housing also provides a profile for storing the SDL or KT riser support rings when these units are not in use. After landing the diverter in its housing, pins are hydraulically extended to lock them together. The KFDS diverter features pressure energized KFDS Diverter System flowline seals above and below the flow outlet cavity. A quick connect manifold supplies hydraulic pressure for the flowline seals, and for locking down and activating the packer insert. The packer insert is a 10”inside diameter rubber bag, backed up by metal rings. In the event of formation pressure coming up the riser, the bag is hydraulically expanded around the drill string, diverting this pressure to the appropriate outlet. The standard units are rated to 500 p.s.i. with 1,000 p.s.i. rated units available. CSO Diverter System Another type of diverter is called the CSO (Complete Shut Off). This diverter is similar to the KFDS except the packer insert has been replaced with an annular preventer type bag. The bag opens t a full 20”when relaxed and will close and seal around any size or shape of pipe, as well as an open hole. These diverter features save time by eliminating the need for a packer insert and improve safety by being able to close around anything or nothing at all.
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Once the diverter has been landed and locked into its support housing, the rig crew can commence with drilling below the conductor. When the surface hole has been drilled the Hydraulic Latch is released and the marine riser system is pulled and laid down. Careful observation of the hydrostatic condition of the well is recommended before pulling the riser, as a flow at this point would be uncontrolled. Flex Joints A floating drilling rig whether moored or CSO Diverter dynamically positioned cannot stay centered perfectly over the wellbore. Current, wind, tides, and waves act to push the rig off center. To prevent excessive bending loads in the riser, flex joints are used at the bottom and top of the riser assembly. The flex joint provides for 10o of deflection from vertical of the riser as the rig moves laterally above the well. Historically ABB Vetco Gray has manufactured various ball/flex joints that precede the Singleflex joint being manufactured today. Ball joints are similar in structure to a person’s shoulder joint. A ball on the lower section is housed in a socket above, that allows relative motion in any direction around the ball. The breech lock flex joint was the first flex joint made by ABB Vetco Gray. It involved a series of interlocking, sealed segments, each with a flex capacity of approximately 1-1/2o. The problem with this joint was its low tensile capacity. The multi-ball flex joint replaced the breech lock flex joint. Three interlocking ball sections, each with approximately 3-1/3o flex capability, were the basis for the mechanical operation of this flex joint. Although this proved to be a much stronger joint than the breech lock flex joint, it still did not meet the tensile requirements necessary for running a BOP stack on marine risers in deep water. The Type 1 single ball flex joint was the predecessor to the Type 2 flex joint which is a single ball joint which utilizes a hydraulic fluid cushion to minimize wear at the ball joint. Single Ball Joint 7-11
The sea water hydrostatic head creates an unbalanced force on the socket section of the ball joint, tending to force it down onto the ball section. This downward force is balanced by use of a pressured film of lubricating oil which is trapped between o-ring seals in the ball joint interface. The lubricating oil is forced into the ball joint cavity by a fluid/oil separator which transmits sea pressure to the lubricating oil thereby balancing the pressure of the lubricating oil with the hydrostatic head of the sea water. The hydrostatic head of the drilling fluid and the upward force applied by the riser tensioners create an imbalance in the ball joint socket section in the upward direction as well. A film of lubricating oil is used to counterbalance this upward force. The pressure of this film of oil is regulated manually as the amount of tension is variable based on the water depth and riser tension. Hydraulic fluid from the BOP stack control system, at a calculated pressure, is applied to the base of the floating piston in another fluid-oil separator. This transfers the pressure into the lubricating oil, which maintains the required balancing force to compensate for the overpull and mud weight. An indicator rod attached to the piston of each fluid-oil separator verifies the piston’s position. A fully extended rod indicates that the lubricating oil has been used up, signifying a leak past the ball joint seals. The inside surfaces of the separator cylinders has a slightly enlarged inside diameter at the top. This allows the piston to permit a bypass of sea water in one case and hydraulic fluid in the other t lubricate the ball surfaces. This is only a temporary situation until the ball joint is retrieved to the surface for repair. Another type of pressurized, single ball flex joint manufactured by ABB Vetco Gray is known as the Type CR-1. It is essentially the same as the Type 2, however it is inverted in comparison to the Type 2 and thus only requires one hydraulically pressurized chamber (upper ball/socket interface). In either case, the required hydraulic pressure applied to the ball joint is dependent upon the tension load on the drilling riser, water depth, and mud weight. Pressure charts are used to calculate the required pressure to balance the pressurized ball joints for the forces induced by the mud weight and overpull of the riser tensioners. These pressure charts are individually prepared for each ball joint size and are included in service manuals supplied to the user. Each single ball flex joint has an anti-rotation pin which prevents the socket from rotating relative to the ball section. This is necessary in order to avoid twisting problems with the flexible choke and kill lines around the flex joint. Extensive wear on the inner bore of the ball joint can occur as the result of drilling while the vessel is off location. A replaceable wear bushing insert is installed in the ball section to provide an expendable component, and avoid irreparable damage. The single ball flex joints have a tensile load capacity of up to two million pounds which has proven to be ample for running the larger BOP stacks and for the tensioning loads of the drilling riser.
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Non-pressured Flex Joints The development of the deep water guidelineless subsea systems required equipment which could be used in 3,000 to 10,000 feet of water. Because of the pressure requirements anticipated for a ball joint at these depths, it necessitated the development of a nonpressurized flex joint with the high tensile capacity to handle the deep water subsea equipment. ABB Vetco Gray designed the UniFlex Joint to meet these standards. It has since been replaced by the more economical and compact Singleflex joint. Although the nonpressurized flex joint was originally developed for the guidelineless system, it is gaining Single Flex Joint wide acceptance for use with guideline systems being discussed, and has some distinct advantages over the single ball type flex joint. The Singleflex Joint requires no hydraulic balance pressure and therefore its operation is simplified and the service and maintenance requirements are substantially reduced. The primary flexing takes place at the elastomeric bearing ring in the upper section of the flex joint. The bearing ring flexes to a maximum of 10o from center line, providing an angle of 10o from vertical flexing capability. The control flex seal is composed of the same flexing material and mainly functions as a seal between the internal mud pressure and the external ambient pressure. This seal assembly will resist differential pressures of up to 3,000 p.s.i. The flex material is laminated layers of stainless steel and rubber. The durability of this material has been exemplified in its extensive use as a shock absorbing element for helicopter rotors and also for universal joints in
Flex Joint in LMRP
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heavy-duty trucks. This type of construction is more likened to a sliding, compressive loading rather than the pivotal loading on a spherical surface experienced by the single ball flex joint. In the Singleflex Joint, all resilient material is preloaded. This preload assures positive compression in the flex seal with the unit under maximum tension. The maximum static tensile load for the unit is rated up to 2,000,000 pounds, and the maximum operating tensile load is 1,500,000 pounds. Test results indicate that it requires approximately 20,000 lbs/ft bending moment to flex the 18-3/4”unit one degree. Due to the approximate linearity of the data, this tends to hold true for any degree change within the 10o range. The Singleflex Joint is rated for H2S service as a standard and can be used with oil-based drilling muds. Since the elastomeric bearing ring is not exposed t the mud column, harmful chemicals will not damage the rubber, so its service live and reliability are extended. A drilling riser connector attached to the flex joint provides the crossover to the riser pipe which is the means for lowering the BOP assembly. The ABB Vetco Gray subsea system requires a drilling riser pin connector above the flex joint since the riser system incorporates a pin up, box down connection. Emergency Riser Disconnect The Emergency Riser Disconnect offers a secondary means for quick release of the riser should the rig offset exceed recommended operating parameters. The Emergency Riser Disconnect is incorporated into a riser joint which can be installed anywhere in the riser string above the lower flex joint. The disconnect operates hydraulically. A locking sleeve on the upper section of the joint is held in the lock position by hydraulic pressure applied through the supply line. The hydraulic fluid on the latch side of the locking sleeve is trapped in place by a pilot operated check valve. The pilot side is connected to the unlatch side of the locking sleeve. The only way to release the hydraulic locking fluid is to pressure the unlatch line. The locking dogs engage a recess in the lower mandrel of the joint. As hydraulic pressure is applied to the unlock side of the locking sleeve (1500 p.s.i.) the pilot port opens releasing the hydraulic pressure on the lock side of the sleeve permitting the sleeve to slide upward from behind the locking dogs. The locking dogs are then free to disengage from the lower joint mandrel permitting the joint to separate releasing the riser string above the connection. The taper behind the locking dogs is self locking so that in the event of hydraulic failure the connector will not release regardless 7-14
Emergency Riser Disconnect
of the tension on the riser string. The pull to separate the joint is always axial to the centerline of the riser. Therefore, there are no forces binding the coupling to keep it from separating, regardless of how far the vessel is off the hole. Instrumented Riser Joint The Instrumented Riser Joint provides the means of monitoring a number of parameters associated with the use of deep water riser systems. These parameters are measured by sensors incorporated into a riser pup joint and are multi-plexed by a subsurface electronics assembly and transmitted to the surface using a small diameter armored logging cable. Data is converted at the surface to an output signal for readout and or storage. Parameters typically monitored include, temperature, pressure, inclination in two directions, axial stress, and bending stress in two directions. Other readouts can be provided.
Instrumented Riser Joint
Automatic Riser Fill Valve The Automatic Riser Fill Valve prevents the riser from collapsing under external pressure in the event of a sudden mud loss. It is designed with an outer sliding sleeve that opens automatically, allowing sea water to fill the riser, when the internal pressure at the valve falls below the external pressure. The Automatic Riser Fill Valve also has hydraulic overrides which permit it to be opened or closed as desired. In the automatic mode a pre-charged accumulator mounted on the valve joint provides actuating pressure. As pressure in the riser falls below the external pressure, the pressure in the accumulator operates the sliding sleeve which moves upward exposing the ports in the valve to the sea water, which will then flood the riser. The override system is operated by hydraulic control lines to the Automatic Riser Fill Valve. The override cylinders move freely through the flanges on the sliding sleeve, either lifting it or lowering it when on of the end caps comes into contact with one of the flanges. They are guided by piston rods attached to
Automatic Riser Fill Valve 7-15
the riser coupling and the choke and kill line support flange, and are centered on the piston rods by pressure from the pre-charged accumulator. Pressure applied to the top or bottom chamber of the override cylinder opens or closes the valve and the cylinder is again centered by accumulator pressure when control pressure is vented. Hydraulic Latch In years past it was considered prudent to install a riser into the Low Pressure Wellhead Housing while drilling the surface hole to provide a means for well control (diverter system) if shallow gas was encountered in this hole section. A second riser would then be run with the BOP once the surface hole was cased, and the High Pressure 30” Hydraulic Latch Wellhead Housing landed. Current practice typically provides for drilling the surface hole section without a riser so drilling fluids used to drill the hole section (seawater) are allowed to disperse at the sea bottom rather than being circulated back to the rig. Incidents which have occurred over time have shown that taking a gas kick back through the rig diverter system is more dangerous than allowing the gas to disperse at the sea floor. In deep water, the expense and difficulty of handling two complete riser assemblies is also undesirable. Drilling the surface hole with returns requires the use of four major component assemblies which make up the riser system, and provide the necessary circulating conduit, motion compensation, and well control. These assemblies are the hydraulic latch, flex joint, marine riser string including the telescopic joint, and a flow diverter. The Hydraulic Latch is run at the bottom of the riser assembly. It stabs, seals, and locks into the Low Pressure Wellhead Housing. It is typically rated to 500 p.s.i. working pressure. Four hydraulic cylinders attached to the main body are used to drive the dog ring downward which forces eight dogs into the running profile in the Low Pressure Wellhead Housing. Normally, only 800 p.s.i. is required to lock the unit onto the Low Pressure Wellhead Housing, and this pressure should be maintained until the latch is released. The latching profiles of the dogs and grooves are tapered
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at 45o to ensure easy release when the dog ring is moved upward to the release position and the latch is pulled from the Low Pressure Wellhead Housing. Prior to running the Hydraulic Latch, the dog ring should be functioned and left in the unlock position with all dogs manually pushed back into the lower body, assuring adequate clearance when entering the Low Pressure Wellhead Housing. Once landed, hydraulic pressure is applied through a control hose bundle run with the riser, to lock the latch. The Hydraulic Latch fits inside the Low Pressure Wellhead Housing reducing the inside diameter to 21-1/4”. This means that underreaming is required to make the 26”hole, or a pilot hole, usually 15”or 12-1/4”, is drilled. The Hydraulic Latch is normally directly connected to a flex joint by means of a flange or hub connector, and is stored in the moon pool area as a package. Alternatively, the H-4 connector of the Lower Marine Riser Package (LMRP) can be connected to the Hydraulic Latch if the Latch has an H-4 profile at the top. In this case the LMRP is run above the Hydraulic Latch. This is not a preferred method however as it adds to the wear and tear on the LMRP. Guidance is provided by a framework bolted to the upper body of the Hydraulic Latch, which has two or four slotted guide funnels attached. The guide lines are inserted into these guide funnels when the Hydraulic Latch is staged to run on the rigs moon pool beams. When the guide funnels stab over the guide posts on the Permanent Guide Structure, they centralize the latch and provide final guidance.
30” Hydraulic Latch with Ball Joint and Riser Connector at spider deck
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