A system including a subsea module, a tool hanger, and an in-well tool string coupled to and extending from a lower portion of the tool hanger is provided. The subsea module includes a subsea spool with a main bore formed therethrough, and the main bore includes a tool hanger interface. The subsea module also includes a connector for mounting the subsea module on a subsea component, wherein the connector includes a grip configured to engage the subsea component, and a first seal coupled to the connector and configured to seal the connector against the subsea component. The tool hanger is disposed within the main bore and coupled to the tool hanger interface via at least a second seal configured to seal the tool hanger against the main bore of the subsea spool. The in-well tool string is configured to couple the tool hanger to an in-well tool.
A flexible deployment system is used to deploy subsea/downhole well equipment or modules from a multi-purpose vessel without requiring a moon pool and a derrick or tower. The deployment system may include the vessel and a deployment frame disposed on the vessel. The deployment frame includes a protruding section extending as a cantilever beyond an external edge of the vessel, and the protruding section includes an aperture formed therein to facilitate construction of the well equipment or modules through the protruding section. The deployment system also includes an actuation assembly coupled to the protruding section to selectively transition the protruding section to a collapsed, split, or retracted orientation out of a deployment path of the well equipment or modules. The system allows for controlled deployment of well equipment or modules including at least a string of downhole tools or tubulars coupled end to end from the side of the vessel in a single trip.
A flexible deployment system is used to deploy subsea/downhole well equipment or modules from a multi-purpose vessel without requiring a moon pool and a derrick or tower. The deployment system may include the vessel and a deployment frame disposed on the vessel. The deployment frame includes a protruding section extending as a cantilever beyond an external edge of the vessel, and the protruding section includes an aperture formed therein to facilitate construction of the well equipment or modules through the protruding section. The deployment system also includes an actuation assembly coupled to the protruding section to selectively transition the protruding section to a collapsed, split, or retracted orientation out of a deployment path of the well equipment or modules. The system allows for controlled deployment of well equipment or modules including at least a string of downhole tools or tubulars coupled end to end from the side of the vessel in a single trip.
A flexible deployment system is used to deploy subsea/downhole well equipment or modules from a multi-purpose vessel without requiring a moon pool and a derrick or tower. The deployment system may include the vessel and a deployment frame disposed on the vessel. The deployment frame includes a protruding section extending as a cantilever beyond an external edge of the vessel, and the protruding section includes an aperture formed therein to facilitate construction of the well equipment or modules through the protruding section. The deployment system also includes an actuation assembly coupled to the protruding section to selectively transition the protruding section to a collapsed, split, or retracted orientation out of a deployment path of the well equipment or modules. The system allows for controlled deployment of well equipment or modules including at least a string of downhole tools or tubulars coupled end to end from the side of the vessel in a single trip.
A wellhead based well control arrangement including a pressure control head having a gripping element configured to grip an outside surface of a well head and a seal element configured to seal against an inside surface of the same well head, a perforating, packer, and circulation mandrel extending from the pressure control head. A method for controlling a well at a well head for plugging and abandonment operations including running an arrangement as above into engagement with a well head, engaging the gripping element to an outside surface of the wellhead, sealing the seal element to an inside surface of the well head, and setting a packer of the mandrel.
A system including a subsea module, a tool hanger, and an in-well tool string coupled to and extending from a lower portion of the tool hanger is provided. The subsea module includes a subsea spool with a mam bore formed therethrough, and the mam bore includes a tool hanger interface. Ute subsea module also includes a connector for mounting the subsea module on a subsea component, wherein the connector includes a grip configured to engage the subsea component, and a first seal coupled to the connector and configured to seal the connector against the subsea component. The tool hanger is disposed within the main bore and coupled to the tool hanger interface via at least a second seal configured to seal the tool hanger against the main bore of the subsea spool. The in-well tool string is configured to couple the tool hanger to an in-well tool.
A system including a subsea module, a tool hanger, and an in-well tool string coupled to and extending from a lower portion of the tool hanger is provided. The subsea module includes a subsea spool with a main bore formed therethrough, and the main bore includes a tool hanger interface. The subsea module also includes a connector for mounting the subsea module on a subsea component, wherein the connector includes a grip configured to engage the subsea component, and a first seal coupled to the connector and configured to seal the connector against the subsea component. The tool hanger is disposed within the main bore and coupled to the tool hanger interface via at least a second seal configured to seal the tool hanger against the main bore of the subsea spool. The in-well tool string is configured to couple the tool hanger to an in-well tool.
A method for providing well safety control in a remedial electronic submersible pump (ESP) application including a making up an electric submersible pump (ESP) on a conduit with a primary well control capability; running the foregoing through a preexisting SCSSV.
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
F04B 15/02 - Pumps adapted to handle specific fluids, e.g. by selection of specific materials for pumps or pump parts the fluids being viscous or non-homogeneous
F04B 47/06 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
A method for providing well safety control in a remedial electronic submersible pump (ESP) application including a making up an electric submersible pump (ESP) on a conduit with a primary well control capability; running the foregoing through a preexisting SCSSV.
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
F04B 47/06 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
F04B 15/02 - Pumps adapted to handle specific fluids, e.g. by selection of specific materials for pumps or pump parts the fluids being viscous or non-homogeneous
Various subsea production arrangements may utilize a base module (12) and a pump module (14) including one or more subsea pumps, such as ESPs or subsea centrifugal pumps, the base module and pump module being fluidly coupled together. An adjustable foot (18) may be utilized to at least partially support the pump module at a horizontal distance from the base module. A horizontally oriented pump module may be equipped with a truss arrangement (106) designed to reduce bending loads on the pump module. The base module and pump module may be delivered to a subsea location separately or in a single trip. A modular subsea production arrangement may enable low cost installation and/or operation and high adaptability of various combinations of well production equipment. Certain subsea production arrangements may include one or more retrievable FCU/LCU modules (38, 40) for use with subsea apparatus, such as pumps and compressors.
A semi-submersible floating structure for the drilling and production of offshore oil and gas is provided. The semi-submersible floating structure includes a pontoon having a plurality of pontoon sections, an outer edge, and an inner edge, the pontoon sections defining an interior space. The semi-submersible floating structure further includes a plurality of columns extending vertically upward from the pontoon. Each column has an upper section having an upper column width; and a lower section. The lower section has a bottom end coupled to the pontoon and aligned with the outer edge of the pontoon, the bottom end having a lower column width greater than the upper column width, at least part of the bottom end protruding into the interior space. The lower section further has a flared portion between the upper section and the bottom end; the flared portion having a width that varies from the upper column width at the upper section to the lower column width at the bottom end. A pontoon center-to-center distance between central axes of opposing sections of the pontoon is greater than a corresponding column center-to-center distance between central axes of opposing upper sections of the columns coupled to the opposing sections of the pontoon.
B63B 35/44 - Floating buildings, stores, drilling platforms, or workshops, e.g. carrying water-oil separating devices
B63B 43/06 - Improving safety of vessels, e.g. damage control, not otherwise provided for reducing risk of capsizing or sinking by improving stability using ballast tanks
B63B 43/08 - Improving safety of vessels, e.g. damage control, not otherwise provided for reducing risk of capsizing or sinking by improving stability by transfer of solid ballast
A semi-submersible floating structure (10) for the drilling and production of offshore oil and gas is provided. The semi-submersible floating structure includes a pontoon (15) having a plurality of pontoon sections, an outer edge, and an inner edge, the pontoon sections defining an interior space. The semi-submersible floating structure further includes a plurality of columns (11) extending vertically upward from the pontoon. Each column has an upper section (16) having an upper column width (23); and a lower section (12). The lower section has a bottom end coupled to the pontoon and aligned with the outer edge of the pontoon, the bottom end having a lower column width greater than the upper column width, at least part of the bottom end protruding into the interior space. The lower section further has a flared portion between the upper section and the bottom end; the flared portion having a width that varies from the upper column width at the upper section to the lower column width at the bottom end. A pontoon center-to-center distance between central axes of opposing sections of the pontoon is greater than a corresponding column center-to-center distance between central axes of opposing upper sections of the columns coupled to the opposing sections of the pontoon.
The invention provides a subsea pump system, comprising a subsea pump, a fluid conditioner tank, a liquid conservation tank, a line arranged for liquid recirculation from the liquid conservation tank to upstream the subsea pump, and an umbilical for power, monitoring and control, wherein the fluid conditioner tank is arranged upstream to the subsea pump which is arranged upstream to the liquid conservation tank. The subsea pump system is distinctive by that it further comprises: a first buoyancy element suspended in the fluid conditioner tank, a second buoyancy element suspended in the liquid conservation tank, optical fiber sensors, at least arranged to a suspension of the buoyancy element in the fluid conditioner tank and to a suspension of the buoyancy element in the liquid conservation tank, and electronics, wherein all subsea sensors consist of optical fiber sensors and all electronics for monitoring and control consist of electronics arranged topsides. The invention also provides a subsea pressure booster, comprising at least one optical fiber sensor arranged in the motor compartment for monitoring a lubricant flow rate.
F04B 47/06 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
14.
WELL HEAD TUBING HANGER CONVERSION CONFIGURATION AND METHOD FOR COMPLETING A WELL USING THE SAME
A wellhead adapter configuration includes a body configured and dimensioned to attach to a wellhead. An inside dimension sufficient to allow through passage of a casing hanger. A method for preparing a borehole.
Systems and methods providing a tree cap that allows power, signal, and/or hydraulic function connections to be established between an Electrical Submersible Pump and a vertical Christmas tree (VXT) control system are provided. The tree cap includes an Electrical Feed-through System (EFS) having an electro-hydraulic stinger configured to form a connection to an ESP hanger plug of the Electrical Submersible Pump (ESP). The tree cap is configured to lock onto the vertical Christmas tree (VXT) and provide a secondary seal barrier element to the environment.
A subsea umbilical system is provided for connecting a topside structure to subsea equipment. The system includes an umbilical (150) having cables for powering or communicating with subsea equipment, bend stiffener (160) and bend restrictor (200) through which the umbilical passes, and a breakout box (170) between the bend stiffener and the subsea equipment. The breakout box includes breakout openings allowing one or more breakout cables (180) to exit the umbilical and run along the outside of the bend stiffener to the topside structure.
A subsea umbilical system can be provided for connecting a topside structure at a proximal end of the system to subsea equipment at a distal end of the system. The system can include an umbilical configured to allow one or more cables for powering or communicating with subsea equipment to be passed through at least a portion of the umbilical. The system can further include reinforcing elements radially surrounding a portion of the umbilical. The system can further include a breakout box disposed along the umbilical and configured to be positioned between the reinforcing element and the subsea equipment. The breakout box can include a breakout opening configured to allow one or more breakout cables to exit the umbilical and run along the outside of the reinforcing elements to the topside structure. Related methods of making and using such systems are also described.
A power triad of an umbilical may be rotated during multiple transition lengths to position each power cable of the power triad equally at radial orientation over the length of the umbilical. A first portion of the umbilical includes the triad in a first radial orientation, a second portion of the umbilical includes the triad in a second radial orientation, and a third portion of the umbilical includes the triad in a third radial orientation. The triad is rotated a first one hundred twenty degrees from the first radial orientation to the second radial orientation during a first transition length. The triad is rotated a second one hundred twenty degrees from the second radial orientation to the third radial orientation during a second transition length. The use of three radial orientations along the length of the umbilical may reduce imbalances between the power cables of the triad.
H02G 9/02 - Installations of electric cables or lines in or on the ground or water laid directly in or on the ground, river-bed or sea-bottomCoverings therefor, e.g. tile
A power triad of an umbilical may be rotated during multiple transition lengths to position each power cable of the power triad equally at radial orientation over the length of the umbilical. A first portion of the umbilical includes the triad in a first radial orientation, a second portion of the umbilical includes the triad in a second radial orientation, and a third portion of the umbilical includes the triad in a third radial orientation. The triad is rotated a first one hundred twenty degrees from the first radial orientation to the second radial orientation during a first transition length. The triad is rotated a second one hundred twenty degrees from the second radial orientation to the third radial orientation during a second transition length. The use of three radial orientations along the length of the umbilical may reduce imbalances between the power cables of the triad.
E21B 33/035 - Well headsSetting-up thereof specially adapted for underwater installations
H02G 1/10 - Methods or apparatus specially adapted for installing, maintaining, repairing, or dismantling electric cables or lines for laying cables, e.g. laying apparatus on vehicle in or under water
H02G 9/12 - Installations of electric cables or lines in or on the ground or water supported on or from floating structures, e.g. in water
H02G 9/02 - Installations of electric cables or lines in or on the ground or water laid directly in or on the ground, river-bed or sea-bottomCoverings therefor, e.g. tile
Systems and methods providing a tree cap that allows power, signal, and/or hydraulic function connections to be established between an Electrical Submersible Pump and a vertical Christmas tree (VXT) control system are provided. The tree cap includes an Electrical Feed-through System (EFS) having an electro-hydraulic stinger configured to form a connection to an ESP hanger plug of the Electrical Submersible Pump (ESP). The tree cap is configured to lock onto the vertical Christmas tree (VXT) and provide a secondary seal barrier element to the environment.
Systems and methods providing a tree cap that allows power, signal, and/or hydraulic function connections to be established between an Electrical Submersible Pump and a vertical Christmas tree (VXT) control system are provided. The tree cap includes an Electrical Feed-through System (EFS) having an electro-hydraulic stinger configured to form a connection to an ESP hanger plug of the Electrical Submersible Pump (ESP). The tree cap is configured to lock onto the vertical Christmas tree (VXT) and provide a secondary seal barrier element to the environment.
An offshore floating structure (10) for the drilling and production of oil and gas includes a generally circular toroidal, hollow pontoon (11) of substantially the same radial width throughout a perimeter of the pontoon. The offshore floating structure includes a plurality of columns (12) of substantially a same cross-sectional area, each coupled at a coupling point, on a bottom end thereof to the pontoon at an equidistant point along the perimeter of the pontoon, and adapted to be coupled on a top end to a deck structure. The diameter (23) from a center of the radial width of the pontoon is greater than a distance (21) from a center of one column to a center of an adjacent column.
A deep draft semi-submersible production and drilling platform unit with dry trees is described. The platform unit preferably comprises four columns, a ring pontoon, a two-axis symmetrical hull with draft in the range of 100 to 155 feet, top-tensioned risers with push or pull tensioners of preferred combined vertical stiffness of 10% to 30% of the platform water plane stiffness, a wellbay with a well spacing in the range of 12 to 18 feet, a riser guiding system supported by the pontoons or at an elevated level, topside facilities supported by a box type of deck structure, mooring lines, and catenary risers.
A subsea connector that includes a connector capable of selectively connecting to a spool body to form a connector assembly. The subsea connector may include an adapter ring that is capable of connecting the spool body to the connector. The connector assembly may be lowered onto a wellhead member and locked into place by a movable piston and split lock ring. While the connector assembly is in the unlocked state, the adapter ring may be rotated moving the connector up or down with respect to the spool body, which lands on the wellhead member. The movement of the connector may be used to vary the alignment of the connector locking means with respect to the locking profile of the wellhead member. This change in position may be used to modify the preload force applied to the connector when locked onto the wellhead member.
A subsea boosting cap system is disclosed. The system comprises an anchor assembly capable of attaching to the sea floor. The anchor assembly comprises a pump cavity capable of receiving a removable pump assembly. A valve system is attached to the anchor assembly. The valve system comprises an inlet flow path and an outlet flow path. A boosting cap covers the pump cavity. The boosting cap comprises a first flow path configured to provide fluid communication between the inlet flow path and the removable pump assembly. A second flow path provides fluid communication between the removable pump assembly and the outlet. A crossover flow path provides fluid communication between the inlet flow path and the outlet flow path, the crossover flow path bypassing the pump cavity.
An annulus isolation valve comprises a valve actuation bore and a flow passage capable of providing fluid communication between an upper annulus and a lower annulus. The flow passage comprises a first flow path and a portion of the valve actuation bore. Further, the first flow path has a second longitudinal axis that is different from a first longitudinal axis. The annulus isolation valve further includes a plug gate positioned in the valve actuation bore. The plug gate is configured so that in the open position it allows fluid communication between the upper annulus and the lower annulus. The annulus isolation valve further includes a biasing mechanism positioned in the valve actuation bore. The biasing mechanism is capable of forcing the plug gate into the closed position when the actuation force is not applied.
A tubing hanger for use in a wellhead. The wellhead includes a throughbore, a landing seat positioned in the throughbore, a landing groove positioned above the landing seat in the throughbore, and a locking groove in the throughbore. The tubing hanger comprises an expandable landing ring positioned on the tubing hanger for engaging the landing groove and a landing mechanism for expanding the landing ring radially outward from the tubing hanger. A locking ring for engaging the locking groove can be positioned on the tubing hanger. The tubing hanger can further include a locking mechanism for expanding the locking ring radially outward from the tubing hanger body and locking it into the locking groove.
A wellhead assembly including a wellhead housing. The wellhead housing comprises a throughbore having a recessed sealing area and a tubing hanger positioned in the throughbore. A seal is positioned between the wellhead housing and the tubing hanger, the seal being positioned so as to form a gap between the seal and the wellhead housing. The wellhead assembly can further include a seal energizer capable of moving relative to the seal in a manner that forces the seal against the wellhead housing to bridge the gap. A method of installing a tubing hanger into a throughbore of a wellhead housing is also disclosed.
An annulus isolation valve comprises a valve actuation bore and a flow passage capable of providing fluid communication between an upper annulus and a lower annulus. The flow passage comprises a first flow path and a portion of the valve actuation bore. Further, the first flow path has a second longitudinal axis that is different from a first longitudinal axis. The annulus isolation valve further includes a plug gate positioned in the valve actuation bore. The plug gate is configured so that in the open position it allows fluid communication between the upper annulus and the lower annulus. The annulus isolation valve further includes a biasing mechanism positioned in the valve actuation bore. The biasing mechanism is capable of forcing the plug gate into the closed position when the actuation force is not applied.
An umbilical field connect assembly comprising: a first umbilical portion comprising two or more first bundled members chosen from electrical cables, fluid conduits, and optical fibers; a second umbilical portion comprising two or more second bundled members chosen from electrical cables, fluid conduits, and optical fibers; a first housing assembly having a first end coupled to the first umbilical portion and a second end comprising a first coupling plate having a plurality of first couplings chosen from male and female couplings positioned therein, one of the plurality of first couplings being positioned at an end of each of the first bundled members; a second housing assembly having a third end coupled to the second umbilical portion and a fourth end comprising a second coupling plate having a plurality of second couplings chosen from male and female couplings positioned therein, one of the second couplings being positioned at an end of each of the second bundled members. The first housing and the second housing can be positioned so that each of the first couplings join with one of the second couplings to form mated coupling pairs, whereby the first bundled members of the first umbilical portion and the second bundled members of the second umbilical portion can be joined in a manner that effectively provides for a single functioning umbilical assembly.
An internal tree cap having a running configuration and a latched configuration to be selectively secured to a tree spool. The tree cap may include an inner sleeve movable between upper and lower positions. The movement of the inner sleeve to the lower position may simultaneously engage a locking profile within the tree spool and energize a sealing element around the exterior of the tree cap. The tree cap may be a low profile tree cap that is flush with the top of the tree spool when installed. The tree cap may provide a collateral beneficial locking means to secure a tubing hanger within the tree spool. A lower housing may be attached to the tree cap to seal on the exterior of the upper neck of the tubing hanger. The tree cap may include a profile to accept a wireline plug.
A locking tree cap for use on a subsea tree. The tree cap may be installed and retrieved using a remote operated vehicle. The tree cap may include deflectable collet fingers that lock the tree cap to a tree spool. The deflectable collet fingers may be adapted, such as with enlarged heads, to extend into recesses of the tree spool when the tree cap has been landed on the tree spool. The tree cap may be locked onto a tree spool before energizing sealing members within the bores of the subsea tree, thereby protecting the sealing members from damage during the installation of the tree cap onto the tree spool. The tree cap may include soft landing means such as a plastic cap, on the end of stabs to protect the sealing members as the tree cap is landed. The tree cap may include a secondary locking mechanism used to further secure the tree cap to the tree spool.
A retrievable tree cap for use on a subsea tree having a concentric bore. The tree cap may be installed and retrieved using a remotely operated vehicle. Hydraulic pressure may be used to lock the tree cap onto the subsea tree and to set the tree cap seals. The tree cap is locked onto the subsea tree before setting the seals within the concentric bore. The tree cap includes a locking means that may engage a profile within the subsea tree regardless of the radial orientation of the tree cap. The tree cap may be used to hydraulically isolate an annulus bore from the production bore of the subsea tree. The tree cap may provide for the injection of a corrosion inhibitor within a cavity of the tree cap and may also provide for the removal of water trapped between the tree cap and the subsea tree.
A coupling switches control fluid from a tubing hanger to a downhole completion of a subsea well. The coupling, located between a tubing hanging running tool and a downhole completion, includes a coupling body and a tubing hanger. A hydraulic poppet switches control fluid flow from a first and second flow path. The hydraulic poppet includes an isolation sleeve for opening and closing a first and second inlet port. At least two perimeter seals provide fluid isolation for the first flow path. A retainer seal seals the coupling body against the second inlet port. A retaining sleeve holds the coupling body against the tubing hanger. A first and second circumferential seal are located on opposite ends between the coupling body and tubing hanger. The hydraulic poppet is adapted to move perimeter seals and the retainer seal to open and close the first and second inlet ports.
A system to re-inject drill cuttings slurry into a well formation for the storage of the cuttings. The system may include a pressure containing conduit that creates a flow path to an annulus within the well formation. The system may include an injection inlet, a drilling guide base, an injection adapter having a circular gallery, an injection mandrel having at least one injection port, and an annulus created between the injection mandrel and an inner casing. The slurry may be injected into the annulus while still drilling the wellbore. The location of the injection inlet may be positioned relative to the circular gallery of the injection adapter such that a cyclone effect is created within gallery minimizing erosion due to the flow of the slurry. The injection mandrel may be adapted to allow the passage of drilling mud to a downhole drilling location while injecting slurry into the casing annulus.
A system to re-inject drill cuttings slurry into a well formation for the storage of the cuttings. The system may include a pressure containing conduit that creates a flow path to an annulus within the well formation. The system may include an injection inlet, a drilling guide base, an injection adapter having a circular gallery, an injection mandrel having at least one injection port, and an annulus created between the injection mandrel and an inner casing. The slurry may be injected into the annulus while still drilling the wellbore. The location of the injection inlet may be positioned relative to the circular gallery of the injection adapter such that a cyclone effect is created within gallery minimizing erosion due to the flow of the slurry. The injection mandrel may be adapted to allow the passage of drilling mud to a downhole drilling location while injecting slurry into the casing annulus.
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