A riser sensor unit is used to sense engagement of a subsea riser tool with a riser coupling. The riser sensor unit includes a power supply configured to convert alternating current to direct current, an intrinsic safety barrier connected to the power supply, and a first sensor powered by the intrinsic safety barrier. The first sensor is attached to a sub of the subsea riser tool and is configured to generate a first signal upon detecting contact of a bottom surface of the sub with the riser coupling. The intrinsic safety barrier is configured to receive the first signal from the first sensor and transmit the first signal to a control system located remotely from the intrinsic safety barrier.
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
G01D 5/20 - Mechanical means for transferring the output of a sensing memberMeans for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for convertingTransducers not specially adapted for a specific variable using electric or magnetic means influencing the magnitude of a current or voltage by varying inductance, e.g. by a movable armature
E21B 33/038 - Connectors used on well heads, e.g. for connecting blow-out preventer and riser
A blowout preventer system including a lower blowout preventer stack comprising a number of hydraulic components, and a lower marine riser package comprising a first control pod and a second control pod adapted to provide, during use, redundant control of hydraulic components of the lower blowout preventer stack where the first and the second control pods are adapted to being connected, during use, to a surface control system and to be controlled, during use, by the surface control system. The blowout preventer system further including at least one additional control pod connected to at least one additional surface control system and to be controlled, during use, by the additional surface control system.
Embodiments include a system for setting a seal in a wellbore including a sabot arranged proximate the seal, the sabot being supported by the seal and having a first diameter larger than a second diameter of the seal. The system also includes a bridge coupled to the sabot and in contact with the seal, the bridge extending axially away from the sabot and positioned within a slot formed by an extension of the seal. The system also includes an energizing ring that drives legs of the seal radially outward, the energizing ring applying a radial force a leg proximate the sabot to at least partially deform the sabot
Embodiments include an energizing ring for setting a downhole seal includes a body having a varied cross-section along at least a portion of an axial length. The energizing ring also includes a plurality of peaks forming at least a portion of the varied cross-section having a first diameter. The energizing ring also includes a plurality of valleys forming at least a portion of the varied cross-section having a second diameter, the first diameter being larger than the second diameter, and respective valleys of the plurality of valleys being arranged proximate respective peaks of the plurality of peaks.
A system for setting a seal (200, 300, 400) in a wellbore includes a sabot (230, 330, 412) being supported by the seal (200, 300, 400) and having a first diameter (232, 332, 414) larger than a second diameter (222, 322, 420) of the seal (200, 300, 400). The system also includes a bridge (240, 340, 424) coupled to the sabot (230, 330, 412), the bridge (240, 340, 424) extending axially away from the sabot (230, 330, 412) and positioned within a slot (228, 328) formed by an extension (212, 312, 418). The system also includes an energizing ring (308, 402) that applies a radial force to a leg (206, 306, 404) proximate the sabot (230, 330, 412) to at least partially deform the sabot (230, 330, 412).
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
F16L 21/02 - Joints with sleeve or socket with elastic sealing rings between pipe and sleeve or between pipe and socket, e.g. with rolling or other prefabricated profiled rings
An energizing ring (200, 400, 600) for setting a downhole seal (300, 500) includes a body having a varied cross-section along at least a portion of an axial length (204, 418, 604). The energizing ring also includes a plurality of peaks (216, 410, 612) forming at least a portion of the varied cross-section having a first diameter (218 A, 414) and a plurality of valleys (222, 412, 616) forming at least a portion of the varied cross-section having a second diameter (416), the first diameter (218 A, 414) being larger than the second diameter (416), and respective valleys (222, 412, 616) of the plurality of valleys (222, 412, 616) being arranged proximate respective peaks (216, 410, 612) of the plurality of peaks (216, 410, 612).
Provided is a life cycle tracking system including a memory and a processor. The memory includes instructions that, when executed by the processor, cause the processor to perform certain operations. For example, the operations can include effecting a change in a first database including data related to a set of components installed on a blowout preventer stack, in response to a drag and drop operation having been performed on a human machine interface. The change can include associating information from a second database to the first database. The second database includes data related to a set of spare components.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
G06F 3/0484 - Interaction techniques based on graphical user interfaces [GUI] for the control of specific functions or operations, e.g. selecting or manipulating an object, an image or a displayed text element, setting a parameter value or selecting a range
A wellhead (34) includes a wellhead body and a locking end (44) coupled to the wellhead body. The locking end (44) includes an exterior surface with an exterior locking profile (38). The exterior locking profile (38) includes an exterior groove (48) formed between exterior stab and load flanks (64, 62) on the exterior surface. The locking end (44) also includes an interior surface having an interior locking profile (40). The interior locking profile (40) includes an interior groove formed between interior stab and load flanks on the interior surface. At least one of the exterior groove (48) or the interior groove is a relief groove (48) that undercuts at least one of the respective stab or load flank (64, 62). The relief groove (48) corresponds to a portion of the contour of an ellipse (54) intersecting at least a portion of the respective stab or load flank (64, 62), and an axis of the ellipse (54) is at a tilted angle with respect to an axis of the wellhead (34).
E21B 17/04 - CouplingsJoints between rod and bit, or between rod and rod
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
A wellhead includes a wellhead body and a locking end coupled to the wellhead body. The locking end includes an exterior surface with an exterior locking profile. The exterior locking profile includes an exterior groove formed between exterior stab and load flanks on the exterior surface. The locking end also includes an interior surface having an interior locking profile. The interior locking profile includes an interior groove formed between interior stab and load flanks on the interior surface. At least one of the exterior groove or the interior groove is a relief groove that undercuts at least one of the respective stab or load flank. The relief groove corresponds to a portion of the contour of an ellipse intersecting at least a portion of the respective stab or load flank, and an axis of the ellipse is at a tilted angle with respect to an axis of the wellhead.
A system is disclosed as including a seal for sealing an area between a hanger and a housing of a wellhead. The seal is provided with at least a notch that defines at least a movable portion such as a wing or a lip. An e-ring is provided for a first energizing of the seal. The movable portion enables pressurized fluid from beneath the seal to cause the movable portion to protrude further against a mating side in the wellhead and the hanger for a second energizing of the seal. This type of seal maintains or improves the sealing of the wellhead in high pressure applications. Methods applied to the above seal are also disclosed.
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
B23H 1/00 - Electrical discharge machining, i.e. removing metal with a series of rapidly recurring electrical discharges between an electrode and a workpiece in the presence of a fluid dielectric
B23B 1/00 - Methods for turning or working essentially requiring the use of turning-machinesUse of auxiliary equipment in connection with such methods
F16J 15/28 - Sealings between relatively-moving surfaces with stuffing-boxes for rigid sealing rings with sealing rings made of metal
B33Y 80/00 - Products made by additive manufacturing
An apparatus is disclosed as including a first material volume with at least a hardened portion and a second material volume that includes at least two layers. The first material volume is composed of at least a hardenable alloy of steel. The at least two layers is located adjacent to a first surface comprising the hardened portion of the first material volume. The at least two layers includes a first layer composed of at least a ductile low-carbon alloy of steel and a second layer composed of at least a cobalt-based hardfacing over the first layer. The apparatus is applicable in preparing shear ram blocks and shear ram blades to provide a hardened blade edge with an adjacent hardfacing surface.
C22C 19/07 - Alloys based on nickel or cobalt based on cobalt
C22F 1/10 - Changing the physical structure of non-ferrous metals or alloys by heat treatment or by hot or cold working of nickel or cobalt or alloys based thereon
A system is disclosed as including a seal for sealing an area between a hanger and a housing of a wellhead. The seal is provided with at least a notch that defines at least a movable portion such as a wing or a lip. An e-ring is provided for a first energizing of the seal. The movable portion enables pressurized fluid from beneath the seal to cause the movable portion to protrude further against a mating side in the wellhead and the hanger for a second energizing of the seal. This type of seal maintains or improves the sealing of the wellhead in high pressure applications. Methods applied to the above seal are also disclosed.
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
F16L 15/00 - Screw-threaded jointsForms of screw-threads for such joints
F16L 15/08 - Screw-threaded jointsForms of screw-threads for such joints with supplementary elements
E21B 33/043 - Casing headsSuspending casings or tubings in well heads specially adapted for underwater well heads
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 43/10 - Setting of casings, screens or liners in wells
Embodiments of the present disclosure describe a piston cylinder arrangement including an inner barrel (18) positioned within an outer barrel (12), being linearly moveable along an axis (56). A primary sealing assembly (28) at an upper end (40) of the outer barrel includes a plurality of seals (74) positioned to block debris from entering an interior chamber (24). Additionally, an end cap (40) is coupled to the inner barrel (18) and an end cap diameter is greater than an inner barrel outer diameter. Moreover a secondary sealing assembly (90) is arranged between the end cap (40) and the primary sealing assembly (28) and includes a plurality of secondary seals (74) positioned to block debris from entering the interior chamber (24) of the riser tensioner (10), wherein the secondary sealing assembly (90) reduces a stroke length of the inner barrel (18) when installed above the primary sealing assembly (28).
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
Embodiments of the present disclosure include systems and methods with a piston cylinder arrangement comprising an inner barrel positioned within an outer barrel, the inner barrel being linearly moveable along an axis. A primary sealing assembly at an upper end of the outer barrel includes a plurality of seals positioned to block debris from entering an interior chamber. Additionally, an end cap is coupled to the inner barrel and an end cap diameter is greater than an inner barrel outer diameter. Moreover a secondary sealing assembly is arranged between the end cap and the primary sealing assembly and includes a plurality of secondary seals positioned to block debris from entering the interior chamber of the riser tensioner, wherein the secondary sealing assembly reduces a stroke length of the inner barrel when installed above the primary sealing assembly.
A system is disclosed as including an enclosed space within a seal for sealing an area between a hanger and a housing of a wellhead. The enclosed space traverses a first section of the seal, a middle section of the seal, and an opening at a second section of the seal. A port is provided as accessible from the housing. A tool positions the seal within the hanger and the housing so that the port is able to access the enclosed space from the housing to the hanger. A pressure applicator applies fluid into the port at a pressure, which is monitored to determine integrity of the seal. In a monitoring mode, a pressure is monitored at the port. A change in the pressure from an ambient pressure at the port may indicate an on-going issue with the seal. Methods applied to the system are also disclosed.
A subsea wellhead assembly provides a positive indication of landing of a wellhead member and locking of a wellhead member to a wellhead. The subsea wellhead assembly includes at least one positive indicator assembly disposed within a wellhead member, and a communication line extending down a running string from a platform to a running tool disposed in a subsea wellhead. The at least one positive indicator assembly provides confirmation of setting of the wellhead member, and the communication line is in communication with the positive indicator assembly to communicate the confirmation of setting with the platform following setting of the wellhead member.
A system includes a wellhead monitoring system. The wellhead monitoring system includes a processor configured to receive from a sensor a detection of one or more operating parameters associated with a wellhead disposed within a subsea environment. The sensor is coupled to the wellhead, and is configured to detect the one or more operating parameters within the subsea environment. The processor is configured to store the detection of the one or more operating parameters, and to generate an output based at least in part on the detection of the one or more operating parameters. The output includes an indication of an operational fatigue or an operational health of the wellhead.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
A system includes a housing section positioned within a wellhead area, the housing section also includes a removable wellhead bushing arranged over at least one engagement feature of the housing. The system also includes a Christmas tree including a treehead area, the treehead area includes a removable treehead bushing arranged over at least one engagement feature of the treehead area. The system further includes a tubular extending through both the wellhead bushing and the treehead bushing, wherein the tubular includes an installation and removal tool adapted to remove at least one of the wellhead bushing and the treehead bushing during wellbore operations.
An annular seal for sealing an interface between a wellhead housing and a casing hanger. The annular seal includes a central body portion and a first pair of seal legs extending in a first direction from the central body portion. Each of the first pair of seal legs sealingly engages one of the wellhead housing or the casing hanger, and are further energized by bore pressure. The annular seal also includes a second pair of seal legs extending in a second direction from the central body portion. Each of the second pair of seal legs sealingly engages one of the wellhead housing or the casing hanger, and is further energized by annulus pressure.
A wellhead assembly includes a wellhead housing having a bore with a wellhead housing sidewall and a longitudinal axis. A hanger lands in the bore, the hanger having a hanger sidewall. Parallel circumferentially extending hanger sidewall ridges are located on the hanger sidewall. Each of the hanger sidewall ridges have upper and lower flanks that converge to a crest. Hanger sidewall bands are located between adjacent ones of the hanger sidewall ridges. A metal seal ring has an outer seal surface in metal-to-metal sealing engagement with the wellhead housing sidewall and an inner seal surface in metal-to-metal sealing engagement with the hanger sidewall bands. Crests of the hanger sidewall ridges embed into the inner seal surface to restrict relative movement between the hanger and the seal ring. A recess extends through each of the hanger sidewall ridges from the upper flank to the lower flank to allow any fluid trapped between the hanger sidewall ridges to flow out.
A tubular member connection system includes a box having an inner diameter surface and internal box threads. A pin has an outer diameter surface and external pin threads, the pin threads shaped to mate with the box threads to releasably secure the pin to the box so that the pin and the box are aligned along a common central axis. A slot is located in one of the inner diameter surface and the outer diameter surface, the slot having a pair of sidewalls. An anti-rotation profile is located in the other of the inner diameter surface and the outer diameter surface. A key is sized to fit within the slot and have a key profile shaped to engage the anti-rotation profile and prevent relative rotational movement between the box and the pin.
A hydraulic cylinder enclosing a cavity, the cylinder containing a thru hole, an inner cylinder surface, and a longitudinal axis, and a piston within the cavity and movable relative to the cylinder in parallel to the longitudinal axis between a first and second positions. The piston includes a rod extending through the thru hole, the piston attached to the rod and in sealed engagement with the inner cylinder surface, and dividing the cavity into low and high pressure cavities, and each of the low and high pressure cavities containing a hydraulic fluid. The hydraulic cylinder further including a flexible bladder within the high pressure cavity containing a gas and preventing the gas from mixing with hydraulic fluid in the high pressure cavity. The flexible bladder is attached to an end of the cylinder, and is expandable within the high pressure cavity so that when the piston is in the first position, the flexible bladder and the gas are compressed, and as the piston moves toward the second position, the flexible bladder and the gas fill at least a portion of the high pressure cavity.
F15B 15/02 - Mechanical layout characterised by the means for converting the movement of the fluid-actuated element into movement of the finally-operated member
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
F15B 15/14 - Fluid-actuated devices for displacing a member from one position to anotherGearing associated therewith characterised by the construction of the motor unit of the straight-cylinder type
23.
Wellhead metal seal with energizing ring having trapped fluid reliefs
A wellhead housing has a bore with an inner seal surface. A hanger with an outer seal surface lands in the bore. Wickers are formed on at least one of the seal surfaces. A metal seal ring lands between the seal surfaces, the seal ring having annular inner and outer legs separated by an annular slot. An energizing ring has inner and outer diameter surfaces that slide against the inner and outer legs of the seal ring when the energizing ring is moved downward in the slot to radially deform the inner and outer legs into sealing engagement with the wellhead housing and hanger. The energizing ring has an inner diameter relief and an outer diameter relief, each being a partially circumferential groove extending upward from a lower rim. The reliefs define a bridge of narrower radial thickness in the lower rim.
Embodiments of the present disclosure include a riser tensioner includes a cylinder barrel, a rod reciprocally carried within the cylinder barrel and having an external end sealingly extending out of a proximal end of the cylinder barrel, and a piston on an interior end of the rod that slides and seals against an inner surface of the cylinder barrel. The tensioner further includes a selectively sealed low pressure chamber in the cylinder barrel between the piston and a distal end of the cylinder barrel and fillable with a low pressure fluid, and a selectively sealed annulus between the rod and the cylinder barrel, the annulus extending between the piston and the proximal end of the cylinder barrel and fillable with an annulus fluid at a pressure higher than the low pressure fluid, thereby urging the piston and rod towards retraction.
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
F15B 15/14 - Fluid-actuated devices for displacing a member from one position to anotherGearing associated therewith characterised by the construction of the motor unit of the straight-cylinder type
F15B 15/16 - Fluid-actuated devices for displacing a member from one position to anotherGearing associated therewith characterised by the construction of the motor unit of the straight-cylinder type of the telescopic type
An external tieback connector secures to a lower end of a driller riser. The tieback connector has a locking element that engages an external profile on the wellhead housing and an actuating piston within a piston chamber. A hydraulic fluid accumulator is in communication with the piston chamber through a hydraulic circuit having valves. An umbilical extends from a floating platform to the accumulator. Sending a signal through the umbilical opens the valves to supply hydraulic fluid pressure from the accumulator to the piston chamber. An acoustic signal receiver also connects to the hydraulic circuit. An acoustic transducer deployed subsea on a transducer cable will emit an acoustic signal that is received by the receiver. The receiver opens the valves to apply hydraulic fluid pressure to the piston chamber.
E21B 43/013 - Connecting a production flow line to an underwater well head
E21B 36/00 - Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
E21B 29/12 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground specially adapted for underwater installations
E21B 41/04 - Manipulators for underwater operations, e.g. temporarily connected to well heads
A wellhead assembly includes an outer wellhead member having a bore and an inner wellhead member located in the bore, defining an annular pocket between the outer and inner wellhead members. A sealing assembly is located within the annular pocket, the sealing assembly having an annular seal and an energizing ring. The energizing ring engages inner and outer legs of the annular seal to push the inner and outer legs into sealing engagement with the inner and outer wellhead members. A retainer nut is threadingly attached to the free end of the outer leg of the sealing assembly. Mating grooves are located on one of an inner diameter of the retainer nut and an outer diameter of the energizing ring and mating protrusions located on the other. The mating protrusions mate with the mating grooves to prevent relative axial movement between the energizing ring and the annular seal.
A wellhead assembly has a casing hanger for supporting a string of casing, the casing hanger having an external upward-facing shoulder. A radially movable annular lockdown member is carried on the shoulder for movement between a retracted position while the casing hanger is being run and an expanded position. In the expanded position, the lockdown member is in engagement with a lockdown profile shoulder in a wellhead housing. A casing hanger seal is carried by the casing hanger above the lockdown member. The casing hanger seal has a lower extension that includes a connection leg and a nose ring. The nose ring has a cam surface that engages and moves the lockdown member to the expanded position while the casing hanger seal is being lowered into a set position. Slots are formed in the extension to reduce the axial stiffness.
A tubular member connection system includes a pin having a central axis, external pin threads, and an annular pin lip at a shoulder surface. A box has internal box threads and an annular box lip at an end surface of the box. The box threads are shaped to mate with the pin threads to releasably secure the pin to the box. A recess is formed in an outer diameter surface of the pin and extends in an axial direction from the pin lip. An anti-rotation key is located within the recess and has a row of teeth along an outer edge. A fastener retains the anti-rotation key in the recess. A circumferentially extending series of grooves on the box lip are sized to engage the teeth and resist a rotation of the pin relative to the box in an unscrewing direction when the pin is releasably secured to the box.
A wellhead housing has a bore with a landing shoulder aid an annular retaining groove spaced above the landing shoulder. A casing hanger connects to a string of easing and lands on the landing shoulder. A seal assembly between the hanger and an interior side wall of the wellhead housing below the retaining groove has an energizing ring that moves axially downward relative to the seal member to a set position that causes the seal member to sealingly engage the hanger and the interior side wall. A lockdown member has an outer lower end portion that bears against an upper end of the energizing ring and an inner lower end portion that hears against an upper end of the hanger. A lockdown ring mounted to the lockdown member engages the retaining groove to prevent upward movement of the lockdown member.
E21B 33/04 - Casing headsSuspending casings or tubings in well heads
E21B 23/02 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing
A tubular member connection system includes a pin having a central axis, external pin threads, and an annular pin lip at a shoulder surface of the pin. A box has internal box threads and an annular box lip at an end surface of the box. The box threads are shaped to mate with the pin threads to releasably secure the pin to the box. A pin recess is formed in an outer diameter surface of the pin, the pin recess extending in an axial direction from the pin lip. A pin key is selectively fastenable within the pin recess, the pin key having pin teeth on an outer edge of the pin key. The box teeth are located in the box. The box teeth selectively mate with the pin teeth and resist rotation of the pin relative to the box.
A system for monitoring the orientation and position of components in an oil well. The system includes a first well component, a second well component, and a transducer attached to the first well component, for generating a pulse. The system also includes a transceiver attached to the second well component for measuring the parameters of the pulse generated by the transducer, and a processor in communication with the transceiver that receives information about the parameters of the pulse as measured by the transceiver, and that calculates the position of the transceiver relative to the transducer.
A method for tying back a subsea well assembly to a surface platform and a tieback connector used to perform this operation. The tieback connector includes a mandrel having an axis, external threads, an upward facing lip on an external lower end portion of the mandrel, a backup ring having internal threads engaged with the external threads of the mandrel, a sleeve carried on an outside diameter of the backup ring. When the mandrel is rotated relative to the backup ring, the mandrel moves axially upward relative to the sleeve, deforming an annular seal assembly between the upward facing lip of the mandrel and the load bearing surface of the sleeve, thereby creating a seal between the apparatus and the wellhead housing.
E21B 29/12 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground specially adapted for underwater installations
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
E21B 43/10 - Setting of casings, screens or liners in wells
E21B 33/038 - Connectors used on well heads, e.g. for connecting blow-out preventer and riser
A subsea well connector for connecting a tubular member to a subsea wellhead assembly includes a tieback connector having an annular stationary connector body that circumscribes a portion of an annular moveable connector body. A tie rod with a tie rod profile extends axially from the stationary connector body. A dog ring circumscribes the tie rod and is moveable between a lockdown open position where the dog ring is spaced from the tie rod, and a lockdown engaged position where a dog ring inner diameter profile engages the tie rod profile, to axially couple the stationary connector body and the moveable connector body. An annular piston circumscribes the dog ring and has a region with a reduced inner diameter that engages an outer diameter of the dog ring to retain the dog ring in the lockdown engaged position. A cylinder circumscribes the annular piston, defining a lockdown piston cavity.
F16L 35/00 - Special arrangements used in connection with end fittings of hoses, e.g. safety or protecting devices
E21B 33/035 - Well headsSetting-up thereof specially adapted for underwater installations
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
E21B 29/12 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground specially adapted for underwater installations
E21B 43/013 - Connecting a production flow line to an underwater well head
E21B 33/038 - Connectors used on well heads, e.g. for connecting blow-out preventer and riser
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
A wellhead assembly includes an outer tubular wellhead member and an inner tubular wellhead member with a seal pocket between them. A seal ring is located in the seal pocket. An annular energizing ring urges the seal ring into sealing engagement with the outer tubular wellhead member and the inner tubular wellhead member. A recess is located on an outer diameter of the annular energizing ring or a radially inner diameter of the seal ring, and a ratcheted retainer is on the other. A ratchet clip with a clip profile is located within the recess. The recess and the ratchet clip extend less than a full circumferential distance around the outer diameter of the annular energizing ring or the radially inner diameter of the seal ring. A retainer profile on the ratcheted retainer selectively engages with the clip profile of the ratchet clip.
A wellhead assembly having an insert that is disposed between a wellhead housing and casing hanger. Axial slots through the insert define a flow path between the wellhead housing and casing hanger. The insert is made from a higher strength material and supports a load exerted between the casing hanger and wellhead housing. The insert is a ring like member, and the slots can more easily be machined in the insert than in the wellhead housing.
A wear bushing assembly protects and locks down a hanger in a wellhead housing; and which includes a wear bushing body that inserts into a wear bushing sleeve. A lock ring extends into registered recesses on the body and sleeve to couple together the body and sleeve. The wellhead housing has a profiled recess circumscribing its inner surface. A lockdown ring selectively mates with the profiled recess; and when mated is in interfering contact with an upper surface of the wear bushing sleeve, thereby coupling the sleeve to the wellhead housing. The sleeve outer surface is profiled to interfere with upward movement of the hanger, so that force is transferred from the hanger to the housing through the sleeve which locks down the housing.
A valve stem packing assembly can seal a valve stem to a valve body having a body cavity. The packing assembly includes a packing ring circumscribing the valve stem within a stem opening extending axially through the valve body. A primary dynamic seal is positioned to seal a dynamic leak path between the packing ring and the valve stem. A secondary dynamic seal is spaced axially apart and functionally independent from the primary dynamic seal and positioned to redundantly seal the dynamic leak path. A primary static seal is positioned to seal a static leak path between the packing ring and the valve body. A secondary static seal is spaced axially apart and functionally independent from the primary static seal and positioned to redundantly seal the static leak path.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16K 39/04 - Devices for relieving the pressure on the sealing faces for sliding valves
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
F16J 15/3212 - Sealings between relatively-moving surfaces with elastic sealings, e.g. O-rings with at least one lip provided with tension elements, e.g. elastic rings with metal springs
F16J 15/3236 - Sealings between relatively-moving surfaces with elastic sealings, e.g. O-rings with at least one lip having two or more lips with at least one lip for each surface, e.g. U-cup packings
38.
Alignment guide feature for metal to metal seal protection on mechanical connections and couplings
A connection is established between a pin connector and a box connector defined on a pair of tubular members such as casing segments in the field of oil and gas recovery. The pin connector and box connector include features for the protection of metallic-sealing surfaces during assembly, disassembly, transport and handling of the tubular members. The pin connector includes a stabbing flank with an inwardly tapered annular flank surface thereon, and an alignment protrusion extending outward with respect to the pin-side metallic sealing surface in a direction normal to a cone angle defined by the inwardly tapered annular flank surface. The alignment protrusion engages internal surfaces of the box connector to concentrically align the pin connector with the box connector, and thereby protects the metallic sealing surfaces from damage that might otherwise result from collisions between the pin connector and the box connector.
A computer-implemented method is disclosed for characterizing a threaded coupling such as between two tubular members, e.g., casing segments employed in the field of oil and gas recovery. In one embodiment, a virtual model of the coupling is generated, and the virtual model is re-arranged to simulate plastic deformation of at least part of the coupling. The re-arranged model is analyzed to derive a stress/strain distribution of the coupling subject to subsequent loading, and an SAF (stress amplification factor) is determined from the analysis that reflects the effect of cyclic loading of the coupling. The method facilitates a thorough assessment of the performance of the coupling in fatigue.
A wellhead assembly includes a wellhead housing having a bore and a locking profile including a gallery slot, and an annular notch. An inner wellhead assembly is selectively landed in the bore of the wellhead housing, the inner wellhead assembly having a lock ring with a lock ring profile that engages the locking profile. The engaging surface is a sloped downward facing surface at an axially upper end of the gallery slot. The annular notch has a notch engaging profile with a downward facing notch upper shoulder and an upward facing notch lower shoulder. The locking profile includes an inlay, the inlay being located on the notch upper shoulder and the engaging surface.
A wellhead assembly including a tubing hanger adapted to be connected to a tubing string and landed in a wellhead, and defining a tubing annulus between the tubing string and casing in a well. The wellhead assembly also includes a tubing annulus upper access bore extending downward from an upper end of the tubing hanger, and a tubing annulus lower access bore extending upward from a lower end of the tubing hanger and misaligned with the upper access bore, the lower access bore adapted to communicated with the tubing annulus. A communication cavity connects the upper and lower access bores within the tubing hanger. A remotely actuated valve is in the communication cavity for selectively opening and closing communication between the lower access bore and the upper access bore.
A wellhead assembly includes a tubular wellhead housing having a bore and an annular gallery slot. The annular gallery slot is defined by an enlarged inner diameter of the bore. A tubular hanger is selectively landed in the bore of the wellhead housing, defining an annular cavity between the bore and an outer diameter of the tubular hanger. The tubular hanger is supported by the wellhead housing with a hanger support located in the annular cavity. A flow-by passage is in fluid communication with the annular cavity at locations above and below the hanger support. The flow-by passage intersects with the gallery slot and intersects an outer radial surface of the tubular hanger.
A retention system for limiting axial and radial movement of a wellbore lock ring. The retention system includes pins for resisting axial movement of the lock ring and assemblies for limiting radial outward movement of the lock ring. The lock ring circumscribes and couples to a wellbore hanger. The pins project radially from the hanger into the lock ring and into slots, where the slots extend a distance along the inner surface of the lock ring. The assemblies also project radially into the hanger and each have a portion that registers with a channel on a lower end of the lock ring. Lock ring outer radial movement is limited by contact between the portions of the assemblies and inner surfaces of the channels.
A wellhead assembly having a tubular magnetized in at least one selected location, and a sensor proximate the magnetized location that monitors a magnetic field from the magnetized location. The magnetic field changes in response to changes in mechanical stress of the magnetized location, so that signals from the sensor represent loads applied to the tubular. Analyzing the signals over time provides fatigue loading data useful for estimating structural integrity of the tubular and its fatigue life. Example tubulars include a low pressure housing, a high pressure housing, conductor pipes respectively coupled with the housings, a string of tubing, a string of casing, housing and tubing connections, housing and tubing seals, tubing hangers, tubing risers, and other underwater structural components that require fatigue monitoring, or can be monitored for fatigue.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
A device for thermally insulating at least one element of a subsea installation from ambient cold sea water, the device comprising an external casing which encloses an internal fluid chamber. The fluid chamber accommodates a fluid having heat-storing capacity, the element being received in the fluid chamber with the fluid surrounding the element so as to allow the fluid to delay cooling of the element by means of heat stored in the fluid. A heat storing member is mounted in the fluid chamber so as to be surrounded by the fluid. The heat storing member contains a medium having heat-storing capacity so as to allow transfer of heat from the fluid to the medium in the heat storing and vice versa to thereby allow the heat storing member to delay cooling of the fluid by means of heat stored in the medium in the heat storing member.
E21B 36/00 - Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
A gate valve for use in oil field applications and including a seat seal assembly. The seat seal assembly includes primary, secondary, and tertiary seals for sealing the space between the seat rings and the valve body. The provision of multiple seals in the seat seal assembly provides redundancy that allows for maintenance of the seal between the components even if one or two of the individual seals fail.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16K 3/30 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing Details
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
E21B 33/00 - Sealing or packing boreholes or wells
47.
Gate valve real time health monitoring system, apparatus, program code and related methods
Systems, apparatus, and program code, and methods for monitoring the health and other conditions of the valve, are provided. An exemplary system for monitoring the condition of the gate valve includes a logic module configured to perform the operations of receiving sensor data providing an acoustic emission, vibration, and/or stream level signature and determining the level of lubricity, level of friction, level of surface degradation, and leakage rate at a gate-valve seat interface. An exemplary method for monitoring the condition of the gate valve includes receiving sensor data providing an acoustic emission, vibration, and/or stream level signature and determining the level of lubricity, level of friction, level of surface degradation, and leakage rate at a gate-valve seat interface.
G01N 29/14 - Investigating or analysing materials by the use of ultrasonic, sonic or infrasonic wavesVisualisation of the interior of objects by transmitting ultrasonic or sonic waves through the object using acoustic emission techniques
G01M 3/00 - Investigating fluid tightness of structures
F16K 37/00 - Special means in or on valves or other cut-off apparatus for indicating or recording operation thereof, or for enabling an alarm to be given
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
G01N 29/12 - Analysing solids by measuring frequency or resonance of acoustic waves
A gate valve for use in oil field applications and including a stem seal assembly and a seat seal assembly. Each of the stem and seat seal assemblies accommodate independent primary, secondary, and tertiary seals for sealing the space between the stem and the bonnet, or the seat ring and the valve body, respectively. The provision of multiple seals in each assembly provides redundancy that allows for maintenance of the seal between the components even if one or two of the individual seals fail.
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16K 3/30 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing Details
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
E21B 33/00 - Sealing or packing boreholes or wells
49.
Annulus seal utilizing energized discrete soft interfacial sealing elements
A seal assembly for sealing an annulus between inner and outer wellhead members includes an energizer ring formed of a high strength elastic material having inner and outer legs. An annular inner recess with grooves on its base is formed on an inward facing surface of the inner leg. An inner diameter seal ring formed of an inelastic material engages the grooves of the inner recess. An annular outer recess with grooves on its base is formed on an outward facing surface of the outer leg. An outer diameter seal ring formed of an inelastic material engages the grooves of the outer recess. When the energizer ring is coaxially inserted in the annulus, the inner diameter seal ring is compressively and permanently deformed into sealing contact with the inner wellhead member, and the outer diameter seal ring is compressively and permanently deformed into sealing contact with the outer wellhead member.
A tensioner assembly for applying tension to a tubular member, such as a riser, can include an upper latch connected to the tubular member, a platform with a bore, and a lower latch ring. After applying tension to the tubular member, the lower latch ring can be closed around the tubular member so that when the tension is released, the upper latch lands on and engages the lower latch. The assembly can include a locking mechanism that prevents axial movement of the upper latch, relative to the lower latch, after engagement. The upper latch can self-center on the lower latch as it is moved into the latching position.
A tensioner assembly for applying tension to a tubular member, such as a riser, can include an upper latch connected to the tubular member, a platform with a bore, and a plurality of lower latch segments, each having a base that is pivotally connected to the platform. After applying tension to the tubular member, the segments pivot inward to form an annular lower latch ring having an inner diameter less than an outer diameter of the upper latch. The assembly can include a locking mechanism that prevents axial movement of the upper latch, relative to the lower latch ring, after engagement. The upper latch can self-center on the lower latch as it is moved into the latching position.
An assembly for clamping a flanged tubular components, the assembly including a segmented clamp having a recess configured to accept the flanges of the tubular components, and a hole oriented substantially perpendicular to the longitudinal axes of the tubular components. The assembly also includes a housing surrounding an outer portion of the segmented clamp and configured for attachment to at least one of the tubular components, and a drive screw that passes through the housing and is threadedly engaged with the hole of the segmented clamp. As the drive screw rotates, it drives the segmented clamp perpendicularly relative to the tubular components between a locked position, in which the circumferential recess engages the flanges of the tubular components, and an unlocked position, in which the circumferential recess is positioned laterally out of engagement with the flanges of the tubular components.
Apparatus and methods for managing cementing operations are provided. An example method includes connecting a cementing adapter atop a casing head itself positioned atop a surface casing landed within a conductor pipe, connecting a drilling adapter atop the cementing adapter, connecting a blowout preventer to the drilling adapter, and drilling for and running production casing. The method also includes positioning a casing hanger at least partially within a bore of the cementing adapter to be immobilized therein to retain back pressure of cement within an annulus located between the production casing and the surface casing, cementing the production casing within the surface casing, and removing the drilling adapter and blowout preventer after running the cement, but typically prior to cement bonding.
An anti-rotation system for use in retaining a threaded connection between a pin and a box. The anti-rotation system includes a key that sets in a recess formed in one of the box or pin. The key is selectively in contact with one of the other of the box or pin, and is activated when the threaded connection begins to decouple. The key is profiled and operates in a cam like fashion to wedge itself between the box and pin when these members begin to decouple and prevents further relative rotation.
F16L 15/08 - Screw-threaded jointsForms of screw-threads for such joints with supplementary elements
E21B 17/043 - CouplingsJoints between rod and bit, or between rod and rod threaded with locking means
F16B 1/02 - Means for securing elements of mechanisms after operation
F16B 21/20 - Means without screw-thread for preventing relative axial movement of a pin, spigot, shaft, or the like and a member surrounding itStud-and-socket releasable fastenings without screw-thread by separate parts for bolts or shafts without holes, grooves, or notches for locking members
F16B 39/282 - Locking by means of special shape of work-engaging surfaces, e.g. notched or toothed nuts
55.
Radially-inserted anti-rotation key for threaded connectors
A pipe connection includes a box that mates with a pin. A box slot extends through a side wall of the box at a point adjacent the rim for alignment with a pin slot formed on the pin. Each of the slots has a circumferential dimension and an axial dimension that is less than the circumferential dimension. The pin slot has a greater circumferential dimension than the box slot. A locking key has a pin section and a box section located within the pin slot and the box slot, respectively, when the key is installed. The pin section has teeth that bite into the pin slot. The key has a width substantially the same as the circumferential dimension of the box slot.
A pipe connection includes a tubular box having an internal threaded section extending from a rim, and a nose receptacle area joining the threaded section. A box seal surface is formed on the nose receptacle area. A tubular pin has a nose area extending from a pin end, and an external threaded section joining the nose area, the external threaded section mating with the internal threaded section. An annular groove is formed on the nose area between the pin end and the external threaded section. A pin seal surface is located at least partially in the groove for engaging the box seal surface to form a metal to metal sealing engagement.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A seal member has inner and outer walls separated by a slot, where the slot has an upper portion that is wider than a lower portion of the slot. An energizing ring having an upper end portion and a nose is moved into the slot, where the upper end portion has a greater cross-sectional thickness than the nose. As the energizing ring is moved into the slot, the nose of the energizing ring engages the lower portion of the slot to form a lock against the walls of the inner and outer wellhead members, and the upper end portion of the energizing ring engages the upper portion of the slot to form a seal against the walls of the inner and outer wellhead members.
A downhole control system can include a pair of drive lines passing through a wellbore member such as a tubing hanger, and a plurality of hydraulic switches, each in communication with the drive lines. Each hydraulic switch can have a unique pressure band, wherein the switch only responds when the pressure in the drive lines is within the unique pressure band. Once the pressure in the drive lines is within the pressure band, the switch can open or close in response to a pressure differential in the drive lines.
A tubular connector secures two coaxial tubulars using a box and pin connection. A pin end tubular member having an axis and a pin end inserts into a box end tubular member having a box end. A pin end flange formed on an outer diameter of the pin end tubular member receives an end of the box end of the box end tubular member. An inwardly depending flange is disposed on the inner diameter of the box end portion. The inwardly depending flange is spaced apart from the box end planar surface and has a box end shoulder formed at an angle to the axis facing a same direction as the box end planar surface of the box end tubular member. An end of the pin end of the pin end tubular member engages with the inwardly depending flange for compressive load transfer.
A tubular connector connects two tubulars of a string of tubular members. The tubular connector has a pin end tubular member having an axis and a pin end. A pin end flange is positioned on an outer diameter of the pin end and has an undercut adjacent the union of the pin end flange with the pin end. The tubular connector also has a box end tubular member having a box end. A box end shoulder is adjacent the union of the box end with the box end tubular member. The box end shoulder has an undercut thereon. The pin end is secured to the box end so that the pin end tubular member and the box end tubular member are joined, stresses applied to the pin end tubular member and the box end tubular member are distributed through the undercuts.
A ball valve assembly is provided. The ball valve assembly comprises a pipe section having an axial bore for enabling fluid flow therethrough in use; a valve ball having an internal conduit, the valve ball being mounted within the pipe section and being for rotation with respect to the pipe section between an open position in which fluid within the axial bore may flow through the internal conduit and a closed position in which the internal conduit is inaccessible to fluid within the axial bore; a device configured to rotate the valve ball, the device being located radially outside the axial bore; and an encapsulation positioned to receive the valve ball and having portions located radially between the pipe bore and the device configured to rotate the valve ball, such that the encapsulation prevents fluid within the axial bore from accessing the device configured to rotate the valve ball.
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
F16K 31/163 - Operating meansReleasing devices actuated by fluid with a mechanism, other than pulling- or pushing-rod, between fluid motor and closure member the fluid acting on a piston
E21B 34/00 - Valve arrangements for boreholes or wells
A rotating gate valve can be used to shear cables or tubing as it closes to obstruct flow. In embodiments, a valve body can have a flow passage and a lateral bore that is transverse to the flow passage. The gate can have a generally cylindrical shape and can rotate about the axis of the gate as it moves laterally to close a flow passage. The lateral and rotational movement can shear articles such as, for example, cables and tubing that extend through the flow passage.
A tree cap has a wedge type annular metal seal for capping and sealing a subsea tree and associated methods to energize the same. The tree cap includes a cam element having a lower end with a conical profile adapted to be disposed within a respective bore of the subsea tree. The cam element moves along an axis of the bore. The annular metal seal is disposed on an outer diameter of the cam element so that the cam element may compress the annular metal seal against an actuation member to seal the bore of the subsea tree. The tree cap includes a housing adapted to be disposed on and secure to the subsea tree. The housing carries the cam element and exerts an axial force on the cam element to deform the annular metal seal into sealing engagement between the tree cap and the subsea tree.
A riser assembly and method of forming where the riser assembly is made up of tubular members joined together. A metal spray process applies a layer of cladding onto ends of the tubular members and the ends are threaded to form respective box and pin configurations. Grooves are provided onto the surface of the tubular members beneath where the metal spray is applied for enhancing adhesion of the cladding and tubular members. The layer of cladding provides sufficient material so that threads may be selectively formed on the outer or the inner surface of the tubular members.
A wellbore assembly includes a housing member, an outer wellbore member, and a second wellbore member, with an outer sensor located in the annulus between the outer wellbore member and the second wellbore member. The outer sensor can sense a condition of the annulus, such as pressure or temperature, and transmit data through a solid portion of the sidewall of the outer wellbore member to a signal receiver located on the housing member. In one embodiment, the signal receiver can transmit an electromagnetic field to inductively charge a power supply on the outer sensor.
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
A method and apparatus for forming an elongate tubular from a composite material. The composite material includes fibers and epoxy resin that are disposed around an elongated mandrel. The fibers are wound around the outer circumference of the mandrel and the epoxy resin may be applied to the fibers, before, during, or after, being wound onto the mandrel. A trough is provided that supports the mandrel between ends of the mandrel. An example trough includes a flexible membrane supported on its lateral ends to resemble a catenary.
A ball valve assembly includes an enclosure for supporting the ball valve during actuation. In one embodiment, the enclosure can be a split enclosure, and can have trunnion support apertures for engaging trunnions on the ball valve. In one embodiment, a pair of link arms are used to transfer force from a pair of actuation members to the ball valve. The link arms can be located in a recess on the actuation members, such the actuation members and the face of the trunnions define a cavity to enclose and protect the link arms.
F16K 5/06 - Taps or cocks comprising only cut-off apparatus having at least one of the sealing faces shaped as a more or less complete surface of a solid of revolution, the opening and closing movement being predominantly rotary with plugs having spherical surfacesPackings therefor
68.
Metal-to-metal sealing arrangement for control line and method of using same
A well completion system includes a wellhead, a control line assembly for use in completions that is mounted to the wellhead, and a tubing hanger. The control line assembly includes a cylinder, a main housing assembly, a passage and a metal-to-metal seal. A split lockout ring provides a positive lock to the passage. Control lines enter the tubing hanger and exit via the wellhead. This arrangement on the wellhead provides sufficient height and clearance to allow for the installation of a plurality of control lines.
A valve includes a stem seal assembly that prevent fluid flow in a first direction and vents in a second direction opposite the first direction. The assembly includes a packing assembly positioned within a valve stem opening of a valve body of the valve to seal a valve stem to the valve body. The packing assembly includes a first seal and a second seal preventing passage of fluid from a body cavity of the valve body to an exterior of the valve body along the valve stem while venting fluid from an exterior of the valve body to the body cavity along the valve stem. The packing assembly isolates the first seal and the second seal so that a load applied to the first seal ring is not transferred to the second seal ring.
F16K 41/04 - Spindle sealings with stuffing-box with at least one ring of rubber or like material between spindle and housing
F16J 15/18 - Sealings between relatively-moving surfaces with stuffing-boxes for elastic or plastic packings
F16J 15/32 - Sealings between relatively-moving surfaces with elastic sealings, e.g. O-rings
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
F16K 39/04 - Devices for relieving the pressure on the sealing faces for sliding valves
F16K 41/08 - Spindle sealings with stuffing-box with at least one ring provided with axially-protruding peripheral closing-lip
70.
Seal with bellows style nose ring and radially drivable lock rings
A seal assembly between a wellhead housing having a bore and a casing hanger, has an inner seal leg for sealing against a hanger and an outer seal leg for sealing against the housing. A bellows style portion is formed on a nose ring carried by the seal assembly to increase lockdown capacity. The bellows style portion has an inner surface that faces an outer profile of the hanger, and an outer surface that faces the bore of the housing. Inner and outer lock rings are disposed on the bellows style portion. When the bellows style portion is axially collapsed, it radially expands into the bore of the housing and the outer profile of the hanger, and urges the inner and outer lock rings into engagement with the outer profile of the hanger and the bore of the housing.
A method and system for producing fluid from a subsea wellbore. An amount of fluid is sampled from fluid being produced and retained for a period of time until constituents in the fluid stratify. A fluid characteristic is sensed at spaced apart vertical locations in the sampled fluid. A water fraction as well as gas content can be ascertained from sensing the sampled fluid. The fluid characteristic is used for calibrating a multi-phase flowmeter that measures flow of the fluid being produced from the wellbore.
A coupler having two degrees of axial freedom couples a hydro-pneumatic cylinder to a tensioner ring of a riser tensioner mounted to a platform. A post extends along an axis of the cylinder and an intermediate sleeve is disposed around the post to form a post annulus. An outer sleeve is secured to the tensioner ring and defines a cavity into which the post and intermediate sleeve are inserted so that an annulus is formed between the sleeve and the outer sleeve. The Outer sleeve is coupled to the intermediate sleeve so that the outer sleeve may pivot on the coupling between the outer sleeve and the intermediate sleeve relative to the intermediate sleeve. The intermediate sleeve is coupled to the post so that the intermediate sleeve may pivot on the coupling between the intermediate sleeve and the post relative to the post.
E21B 19/09 - Apparatus for feeding the rods or cablesApparatus for increasing or decreasing the pressure on the drilling toolApparatus for counterbalancing the weight of the rods specially adapted for drilling underwater formations from a floating support using heave compensators supporting the drill string
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
A receptacle sub that increases the venting flowrate during retrieval of a running tool. The sub includes a sleeve with a bypass port in a central bore defined by a tubular body. The sleeve is selectively moveable from an upper position to a lower position. A seal on the sleeve seals the sleeve to the bore while a retainer holds the sleeve in the upper position. A bypass passage in the body is in fluid communication with the bypass port. A drop member lands on the sleeve, blocking downward flow through the sleeve and actuating a hydraulic function. The drop member receives a fluid pressure greater than the hydraulic function fluid pressure, releasing the retainer to move the sleeve to the lower position. This allows fluid communication from above the central bore through the bypass passage and through the bypass ports of the sleeve below the drop member.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
E21B 34/00 - Valve arrangements for boreholes or wells
A subsea test tree control system provides operational control and power to subsea test tree equipment located within a subsea riser without an in riser umbilical to supply additional power to the subsea test tree control system. The subsea test tree control system includes a subsea horizontal subsea tree landed on a subsea wellhead, and a subsea control module communicatively coupled to the horizontal subsea tree. A subsea test tree stack is landed through the riser in the horizontal subsea tree. A subsea control module communication line extends through the horizontal subsea tree to terminate at a bore of the horizontal subsea tree proximate to the tubing hanger, and a riser string communication line communicatively couples to the subsea control module communication line to provide operational power and control the subsea test tree stack. Intervention workover control system umbilicals may bypass the subsea control module and directly connect to the subsea control module communication line.
E21B 29/12 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground specially adapted for underwater installations
75.
Bi-directional pressure energized axial seal and a swivel connection application
A tubular connection has first and second tubular members having aligned bores with a common axis and having first and second seal surfaces, respectively. A metal seal has a first end portion that sealingly engages the first seal surface and a second end portion that sealingly engages the second seal surface. The metal seal has a sidewall with at least two folds. One of the folds defines an axial interior gap. The other of the folds defines an axial exterior gap. An exterior spacer member is positioned in the exterior gap to limit closer of the exterior gap in response to a greater pressure on the interior of the seal than on the exterior. An interior spacer member is positioned in the interior gap to limit closure of the interior gap in response to a greater pressure on the exterior of the seal than on the interior.
F16L 19/08 - Joints in which sealing surfaces are pressed together by means of a member, e.g. a swivel nut, screwed on, or into, one of the joint parts with metal rings which bite into the wall of the pipe
E21B 33/00 - Sealing or packing boreholes or wells
A subsea wellhead assembly includes a housing with a bore. A hanger is lowered into the housing, the hanger having at least one downward facing load shoulder. An expandable load ring is carried on the hanger. When casing weight is applied to the hanger, the weight energizes the load ring, causing it to expand and thereby increase the contact area between a load shoulder on the load ring and a load shoulder on the housing. The shoulders create a path for the load to be transferred to the housing. The increase in contact area increases the load carrying capacity of the hanger. The load ring expansion is limited to elastic expansion to allow it to return to a retracted position when the casing weight is removed.
A subsea wellhead assembly provides a positive indication of landing of a wellhead member and locking of a wellhead member to a wellhead. The subsea wellhead assembly includes at least one positive indicator assembly disposed within a wellhead member, and a communication line extending down a running string from a platform to a running tool disposed in a subsea wellhead. The at least one positive indicator assembly provides confirmation of setting of the wellhead member, and the communication line is in communication with the positive indicator assembly to communicate the confirmation of setting with the platform following setting of the wellhead member.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 33/035 - Well headsSetting-up thereof specially adapted for underwater installations
E21B 33/043 - Casing headsSuspending casings or tubings in well heads specially adapted for underwater well heads
E21B 47/09 - Locating or determining the position of objects in boreholes or wellsIdentifying the free or blocked portions of pipes
A wear bushing having a lead impression block is landed axially above a casing hanger and actuated to test an elevation of lock ring grooves formed in a wellhead. Then, drilling operations are performed through the wear bushing. The wear bushing includes a first tubular member having an axis and a second tubular member coaxial with the first tubular member. The second tubular member moves down to actuate a lead impression assembly to measure an elevation within the wellhead with the lead impression block. After the drilling operations are completed, the deformed lead impression block is retrieved along with the wear bushing.
A wellhead seal assembly forms a metal-to-metal seal between inner and outer wellhead members. A metal seal ring has inner and outer walls separated by a slot. An energizing ring has a C-ring captured on its outer surface. When the energizing ring is moved further into the slot, the C-ring is forced from its pocket and engages a profile on the seal ring, locking the energizing ring to the seal assembly.
A gate valve assembly having metallic valve seats that are axially resilient and maintain a static sealing interface between the valve seat and a body pocket and a sliding dynamic sealing interface between the valve seat and a gate in the valve assembly. The valve seats are annular members having slots formed radially through the valve seats from the inner and outer circumferences. Sleeves may be provided that are coaxial to the valve seats; the sleeves may be on the inner surface of the valve seats, outer surface of the valve seats, or both. Shims may optionally be set in the slots.
F16K 3/00 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing
F16K 1/16 - Lift valves, i.e. cut-off apparatus with closure members having at least a component of their opening and closing motion perpendicular to the closing faces with pivoted closure members
F16K 25/00 - Details relating to contact between valve members and seats
F16K 3/02 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with flat sealing facesPackings therefor
A push-up tensioner for maintaining a tensile force in a riser having an axis couples to a floating platform and maintains the tensile force while the riser tilts variably from the vertical. The tensioner includes a plurality of cylinders having a lower end pivotally coupled to the deck. The cylinders are substantially perpendicular to the deck in the running position and at an angle to the deck in the tensioning position. After running of the riser, a placement assembly moves the cylinders from the running position to the tensioning position. A tensioner ring is run on the riser proximate to an upper end of the cylinders, and the cylinders are then automatically coupled to the tensioner ring.
A connector for use with a subsea riser installation is provided. The connector comprises a body, wherein the body comprises a first connecting face comprising a through-passageway and adapted for connection to a first external conduit element and a ball joint within the body, wherein the ball joint comprises a through-passageway which is substantially aligned with the through-passageway in the first face, and a second connecting face on an opposite side of the connector to the first connecting face and adapted for connection to a second external conduit element. The connector further comprises at least one detent mechanism adapted to engage a corresponding locating feature on the ball joint, wherein the through-passageway are maintained in alignment and wherein the ball joint is prevented from moving relative to the body until a predetermined bending moment is applied to the ball joint across the axis of the through-passageway in the ball joint.
F16L 27/04 - Universal joints, i.e. with mechanical connection allowing angular movement or adjustment of the axes of the parts in any direction with partly-spherical engaging surfaces
An electrical and hydraulic configuration on a subsea tree that facilitates the use of an ROV control system to operate the tree during well installations, interventions, and workovers. An SCM at the tree is in communication with a fixed junction plate that receives a production umbilical during normal operation. The ROV can be deployed to disconnect and park the production umbilical during well installations, interventions, and workovers to prevent accidental operation of the SCM or tree. The junction plate is configured to connect with the ROV and thereby establish communication with the hydraulic lines of the SCM. The ROV may carry an umbilical from a vessel to provide electrical and hydraulic service to the SCM during well operations. In addition, the ROV has facilities to repressurize spent control fluid to thereby allow reuse of the control fluid by the SCM.
A wellhead assembly made up of a wellhead housing, a production tree mounted on the wellhead housing, tubing suspended into a wellbore from within the wellhead housing, and an annulus between the tubing and the wellhead housing. A shuttle valve is provided within a tubing hanger that supports the tubing from within the wellhead housing. An accumulator is disposed in the annulus that is in fluid communication with a closed position port on the shuttle valve. Pressure is maintained in the accumulator for closing the shuttle valve when a force for opening the valve is removed.
Disclosed herein is a subsea well assembly; wherein in an example embodiment the subsea well assembly includes an umbilical attached to a power source. The power source can be on a platform. Also included is a connector for connecting the umbilical to a receptacle included with the subsea well assembly and a subsea control module delivering power and control signals to the subsea well assembly. An impressed current protection module is integrated in the subsea control module that receives power from the umbilical.
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
C23F 13/00 - Inhibiting corrosion of metals by anodic or cathodic protection
86.
Method and apparatus for positioning a wellhead member including an overpull indicator
An outer wellhead member has a bore with a first profile portion and an annular recess. A tubular inner wellhead member with a centralizer/overpull ring is lowered into the outer wellhead member. The centralizer/overpull ring is biased to expand outward to engage the bore of the outer wellhead member to center the inner wellhead member within the bore as the inner wellhead member is lowered through the bore. The recess of the outer wellhead member is adapted to receive the centralizer/overpull ring and oppose axial movement of the centralizer/overpull ring to enable an upward test pull of the inner wellhead member.
A riser for use in subsea operations that is parked subsea deployed as needed onto wellheads disposed proximate where the riser is parked. A base anchored into the seafloor provides a pedestal for parking the riser. The riser emits a beacon signal so it can be located when needed. When parked, the riser can be kept in a vertical orientation by a buoyancy module mounted on an upper portion of the riser. A workboat, or other vessel, attaches to the parked riser and positions it onto a designated wellhead. An extension connects the riser to platform or other vessel above the sea surface.
A subsea wellhead assembly having a completion landing string inside a drilling riser is described herein and comprises a power source for generating an alternating electrical current; a connector for connecting the power source to a receptacle in the subsea well assembly; a first inductor electrically connected to the power source through the connector; a subsea control module delivering power and control signals to the subsea well assembly; and a second inductor spaced from the first inductor, and located in the subsea control module, the second inductor positioned so that an EMF is produced on the second inductor when the alternating electrical current is passed through the first inductor to thereby generate an alternating current signal on the second inductor.
Riser management systems, apparatus, and methods to maintain a selected range of tension on a plurality of risers extending between subsea well equipment and a floating vessel, are provided. A riser management system can include a mono-buoyancy can platform operably coupled to a plurality of risers extending between subsea well equipment and a moored floating vessel, and a plurality of tensioner units each connected to a top portion of a separate one of the risers to provide tension to each of the risers. The mono-buoyancy can platform can provide tension to each of the risers sufficient to compensate for a relative vertical offset between the risers and the vessel due to vessel movement, which generally affects each of the risers equally, within tolerances, while the tensioner units can simultaneously provide tension to compensate for one or more additional factors which can affect each riser differently.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A metal seal ring has inner and outer walls separated by a slot. An elastomeric seal is located below the seal ring and has a bottom portion that contacts an upward facing shoulder of a hanger. An energizing ring with a tapered nose is moved into the slot. The tapered nose has a compound angle that determines how much the nose travels into the slot when a force is applied to the energizing ring. Once the elastomeric seal is compressed to a desired level, the load on the energizing ring has increased to the point that the tapered nose of the energizing ring will further enters the slot and force the outer and inner walls of the metal seal into sealing engagement with the inner and outer wellhead members.
A method and apparatus for forming a tubular from a composite material. The composite material includes fibers and epoxy resin that are formed into plies that are wound around an axis to form an annular member. The fibers in each ply are arranged axially and hoopwise. The axially oriented fibers are angled from about 10° up to about 20° with respect to an axis of the tubular. The hoopwise fibers are wound in the plies ranging from about 60° at the innermost ply up to about 90° in the outermost ply. The hoop fibers in the intermediate plies are arranged at increasing angles with distance away from the innermost layer. Transitioning the hoop fiber alignment in the successive plies better distributes hoop stress through the wall of the tubular thereby reducing stress concentrations on the innermost ply.
B29C 70/08 - Fibrous reinforcements only comprising combinations of different forms of fibrous reinforcements incorporated in matrix material, forming one or more layers, with or without non-reinforced layers
A seal assembly between a wellhead housing having a bore and a casing hanger, has an inner seal leg for sealing against hanger and an outer seal leg for sealing against housing. An extension extends downward from outer seal leg and is connected to a nose ring having a downward facing shoulder that rests on the hanger shoulder to provide a reaction point for setting operations. A lock ring is retained within interior portion of the nose ring. An upward facing shoulder formed on an upper portion of nose ring contacts the lower surface of the inner seal leg. The shoulder prevents the downward deflection of the inner leg and eliminates buckling due to Poisson effect from the resulting axial force due to growth of the seal legs during setting operations. The shoulder thus prevents crooked or twisted setting of the seal to prevent plastic strain in the seal.
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 43/10 - Setting of casings, screens or liners in wells
An emergency riser disconnection system for disconnecting a riser from a subsea installation having disconnect actuators and a signal and power circuit for controlling the actuators. The signal and power circuit is made up of an umbilical with signal lines and hydraulic lines. At an umbilical termination, the signal and hydraulic lines exit the umbilical and can be routed separately to the disconnect actuators. The umbilical termination is disposed above the uppermost break away point on the riser and can be recovered after the riser is disconnected.
A packoff is located within a wellhead housing and a casing hanger. The packoff has an internal ratchet ring that engages a threaded profile on the exterior of the casing hanger thereby allowing installation of the packoff to be achieved by simply stabbing the packoff over the protruding neck of the casing hanger. This ratchet ring significantly reduces the rotation required during installation, decreasing potential for damage to seals. The casing hanger has an external lock ring that is inwardly biased. During installation of the packoff, the packoff acts to activate the lock ring to thereby force it outward. The lock ring is forced outward and into a recess formed in the interior of the wellhead housing. The lock ring and the ratchet ring locks the packoff and casing hanger into place with the wellhead housing without the need of external lockdown screws, thereby minimizing leak paths.
A method and apparatus for forming an elongate tubular from a composite material. The composite material includes fibers and epoxy resin that are disposed around an elongated mandrel. The fibers are wound around the outer circumference of the mandrel and the epoxy resin may be applied to the fibers, before, during, or after, being wound onto the mandrel. A trough is provided that supports the mandrel between ends of the mandrel. An example trough includes a flexible membrane supported on its lateral ends to resemble a catenary.
B23P 23/00 - Machines or arrangements of machines for performing specified combinations of different metal-working operations not covered by a single other subclass
B05C 11/11 - Vats or other containers for liquids or other fluent materials
96.
Casing hanger profile for multiple seal landing positions
A wellhead assembly having a wellhead housing, a casing hanger set within the wellhead housing, and sealing areas provided on opposing surfaces of the wellhead housing and casing hanger. The sealing areas circumscribe an axis of the wellhead assembly along respective axial distances on the wellhead housing and casing hanger. A seal is included with the wellhead assembly that has inner and outer legs that respectively engage the sealing areas and form sealing surfaces against the sealing areas. The axial distances of the sealing areas exceeds the length of the inner and outer legs, so that an original seal can be removed and replaced by a secondary seal, wherein the secondary seal engages sealing areas different from the sealing areas engaged by the original seal.
A riser tensioner for an offshore floating platform has a frame stationarily mounted to the upper portion of the riser. Pistons and cylinders are spaced circumferentially around the riser and connected between the frame and the floating platform. A tubular guide member is mounted to the floating platform for movement in unison in response to waves and currents. The riser extends through the guide member. A guide roller support is mounted to and extends downward from the frame around the guide member. At least one set of guide rollers is mounted to the guide roller support in rolling engagement with the guide member as the guide member moves in unison with the platform.
A wellhead seal assembly that forms a metal-to-metal seal between inner and outer wellhead members. A bi-metallic U-shaped seal with legs having a low yield metal on the outer portions. During installation of the seal assembly, the legs of the seal are forced outward against the surfaces of the wellhead members, by pressurization of a interim non-metallic seal which forces a wedge into the U-shaped seal, causing localized yielding of the low yield metal to fill defects on wellhead member surfaces.
A tieback connector connects a tieback conduit from an offshore platform to a subsea wellhead assembly. The tieback connector has a mandrel that is connected to a string of tieback conduit and a sleeve and load ring that are carried by the mandrel. The load ring is radially expansible and has a conical portion with internal threads. The load ring has an external grooved profile that engages an internal grooved profile in the subsea assembly. The mandrel is rotatable relative to the sleeve while in its lower position, causing the load ring to further expand outward into engagement with the internal profile. A locking member is carried below the load ring on an exterior cam surface of the mandrel. The cam surface moves the locking member outward when the mandrel moves downward into engagement with an internal profile in the subsea assembly.
A system, apparatus, and method to apply tension to completion tubing in a wellbore. The system, apparatus, and method comprises an inner and outer tubing hanger, with the string of tubing attached to the inner tubing hanger. A running tool lands the outer tubing hanger on a landing shoulder and continues to lower the inner tubing hanger into the wellbore until the lower end of the inner tubing hanger latches into a retaining device. The running tool then sets a seal which holds the outer tubing hanger in position and causes a ratcheting mechanism to move to an engaged position. The running tool then withdraws the inner tubing hanger a predetermined distance until the inner tubing hanger engages the ratcheting mechanism.
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
