Extender jumper system and method

Extender jumper systems and methods including an extender jumper system having an extender jumper assembly with a flowline and first and second connectors positioned at first and second ends of the flowline, and a support assembly configured to couple the extender jumper assembly to a support structure within a subsea field and to support the second connector to facilitate attachment between the second connector and a corresponding connector of another extender jumper or a jumper.

BACKGROUND

Drilling and production systems are typically employed to access, extract, and otherwise harvest desired natural resources, such as oil and gas, that are located below the surface of the earth. These systems may be located onshore or offshore depending on the location of the desired natural resource. When a natural resource is located offshore (e.g., below a body of water), a subsea production system may be used to extract the natural resource. Such subsea production systems may include components located on a surface vessel (e.g., a rig or platform), components located remotely from the surface vessel at a subsea location, typically on or near the seabed or seafloor at or near an access conduit to a subterranean formation (e.g., a well) in which the resource is located, and/or components between subsea and surface. Subsea production systems may include jumpers to convey fluids to or between various components of the subsea production systems.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” “mate,” “mount,” or any other term describing an interaction between elements is intended to mean either an indirect or a direct interaction between the elements described. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” or “lateral” or “laterally” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” “upper,” “lower,” “up,” “down,” “vertical,” “horizontal,” and variations of these terms is made for convenience, but does not require any particular orientation of the components.

As noted above, certain subsea production systems may utilize jumpers to convey fluids to or between various components of a subsea production system. The length of some typical jumpers or the distance spanned by some typical jumpers may be limited to achieve acceptable stability of the jumper and/or fluid flow through the jumper, for example. With the foregoing in mind, embodiments of the present disclosure relate generally to extender jumper systems configured to fluidly connect two or more components of a subsea production system to one another. In certain embodiments, an extender jumper system includes an extender jumper having a first connector (e.g., collet connector or female connector) at a first end to couple the extender jumper to a first component within a subsea field and a second connector (e.g., hub or male connector) at a second end to couple the extender jumper to another jumper (e.g., another extender jumper or other type of jumper or flowline). The extender jumper may include a support assembly at the second end to couple the extender jumper to a support structure positioned within a subsea field and/or to support the second connector to facilitate coupling the extender jumper to another jumper. Thus, the extender jumper may enable multiple jumpers to be coupled to one another to span a distance between two components of the subsea field. As discussed in more detail below, the support assembly of the extender jumper may be supported by and/or coupled to various support structures within the subsea field, including a wellhead (e.g., abandoned wellhead) or other existing structure installed at and/or fixed to the sea floor, for example. While it is envisioned that an extender jumper system of the present disclosure may be connected to a specially installed support structure, use of an existing structure may provide a rigid attachment point for the extender jumper system without additional costs and/or time delays associated with constructing or installing a new platform or support structure.

FIG. 1is a schematic diagram of an extender jumper system10within a subsea field12, in accordance with embodiments of the present disclosure. As shown, the extender jumper system10includes an extender jumper14(e.g., extender jumper assembly, extender tubular assembly, extender flowline assembly, or extender flexible pipe assembly) that extends between a first structure16(e.g., first host structure or first component) and a support structure18. As shown, a jumper20(e.g., jumper assembly, tubular assembly, flowline assembly, or flexible pipe assembly) may extend from the extender jumper14at the support structure18to a second structure22(e.g., second host structure or second component). Thus, the extender jumper system10may enable fluid connection between the first structure16and the second structure22that are separated from one another by a distance44, which may exceed an acceptable distance for a single jumper20or other typical jumpers, pipelines, or connectors, for example.

The first structure16and the second structure22may be any of a variety of subsea structures, including, but not limited to, a manifold, a Christmas tree, a pipeline end termination (PLET), a pipeline end manifold (PLEM), a pump (e.g., multiphase pump), or a high integrity pressure protection system (HIPPS). Similarly, the support structure18may be any of a variety of subsea structures, including, but not limited to, a manifold, a Christmas tree, a PLET, a PLEM, a pump, a HIPPS, a wellhead, a mud mat, a pile, a skid, or any other subsea equipment, component, or platform capable of support, any of which may be existing (e.g., previously installed at or near and/or fixed to the sea floor for use in drilling or production or injection or intervention operations, for example), currently operative, previously operative, currently inoperative, and/or abandoned (e.g., indefinitely inoperative, plugged, and/or incapable of operating for its original intended purpose in its current state). For example, the support structure18may include an inoperative wellhead, such as an abandoned wellhead. Furthermore, the first structure16, the second structure22, and the support structure18may be the same type of subsea structure or different types of subsea structures.

In the illustrated embodiment, the extender jumper14and the first structure16are coupled to one another at an interface24, which may include a connector26(e.g., first connector) configured to couple to a connector28(e.g., second connector). In some embodiments, the connector26is a female connector (e.g., collet connector) positioned at one end of the extender jumper14, and the connector28is a male connector extending from the first structure16. In the illustrated embodiment, the jumper20and the second structure22are coupled to one another at an interface30, which may include a connector32(e.g., third connector) configured to couple to a connector34(e.g., fourth connector). In some embodiments, the connector32is a female connector (e.g., collet connector) positioned at one end of the jumper20, and the connector34is a male connector extending from the second structure22. In the illustrated embodiment, the extender jumper14and the jumper20may be coupled to one another at an interface36, which may include a connector38(e.g., fifth connector) and a connector40(e.g., sixth connector) configured to couple to one another. In some embodiments, the connector38is a male connector positioned at one end of the extender jumper14, and the connector40is a female connector (e.g., collet connector) positioned at one end of the jumper20. As discussed in more detail below, the extender jumper14may include a support assembly42(e.g., annular support assembly) that facilitates connection between the extender jumper14and the jumper20(e.g., by supporting the connector38) and/or that couples the extender jumper14to the support structure18. It should be understood that any of the connectors26,28,32,34,38, and40may be male or female connectors, and may be coupled to a corresponding male or female connector. The connectors26,28,32,34,38,40may be any of a variety of types of connectors, including clamp connectors, collet connectors, split ring connectors, flanges (including bolted flanges), threaded connectors, or the like. The connectors26,28,32,34,38,40also may include locking dogs, lock rings, toothed interfaces, tongue-in-groove interfaces, threaded interfaces, or any combination thereof.

As noted above, some typical jumpers may be limited in length, and a single jumper may not be able to span the distance44between two components (e.g., the first structure16and the second structure22) positioned at a sea floor46within the subsea field12. The extender jumper14enables multiple jumpers (e.g., one or more extender jumpers14and the jumper20) to be coupled to one another in series to span the distance44between the two components. For example, the extender jumper14may include various features, such as the support assembly42and the connector38, which support the extender jumper14above the sea floor46and enable the extender jumper14to couple to another jumper (e.g., another extender jumper14or the jumper20), respectively, thereby enabling the extender jumper system10to span the distance44between the two components. In some embodiments, the support assembly42may stabilize the extender jumper system10, thereby facilitating fluid flow between the two components and/or reducing wear (e.g., at the connectors26,28,38,40,32,34), for example.

As noted above, the support structure18may be any of a variety of subsea structures. However, in some embodiments, an abandoned subsea structure (e.g., abandoned wellhead) may be used as the support structure18, and the support assembly42of the extender jumper14may be coupled to the abandoned subsea structure (e.g., to an accessible or exposed structure, such as a housing of the abandoned wellhead). Such abandoned subsea structures may be fixed and/or cemented in place at the sea floor46and may provide a stable support structure18for the extender jumper14without additional time and/or costs associated with manufacturing and/or installing for the specific purpose other types of support structures, such as mud mats, piles, or the like.

The extender jumper system10disclosed herein may be utilized in a variety of circumstances. For example, in some cases, such as when an existing well at a first location within the subsea field12is no longer producing, it may be desirable to drill a new well at another location (e.g. re-spud location) within the subsea field12. In some such cases, a distance between the re-spud location and existing structures (e.g., the first structure16, a manifold, a pump, a PLET, a PLEM, and/or a HIPPS) within the subsea field12may exceed preferred or acceptable distances for typical jumpers or other typical pipelines or connectors. However, the extender jumper system10may be utilized to fluidly connect such existing structures to a new production tree (e.g., the second structure22) positioned at the new well at the re-spud location. In some such embodiments, a wellhead (e.g., an abandoned wellhead) at the existing well (e.g., a plugged well) at the first location within the subsea field12may be utilized as the support structure18to enable the extender jumper system10to span the distance between the production tree at the new well at the re-spud location and the existing manifold or other existing structures, for example. To facilitate discussion, the extender jumper system10and its components may be described with reference to an axial axis or direction47, a radial or a lateral axis or direction48, and a circumferential axis or direction49.

FIG. 2is a side view of an embodiment of the extender jumper14that may be used in the extender jumper system10ofFIG. 1. As shown, the extender jumper14includes a pipe50(e.g., tube or flowline) to support fluid flow, the connector26positioned at a first end52of the extender jumper14, and the connector38positioned at a second end54of the extender jumper14. In the illustrated embodiment, the connector26is a female collet connector that is configured to couple to a corresponding male connector, such as the connector28of the first structure16or the connector38of another extender jumper14shown inFIG. 1. However, in other embodiments, the connector26may be a male connector that is configured to couple to a corresponding female connector, such as the connector28of the first structure16or the connector38of another extender jumper14shown inFIG. 1In the illustrated embodiment, the connector38is a male connector that is configured to couple to a corresponding female connector, such as the connector40of the jumper20or the connector26of another extender jumper14shown inFIG. 1. However, in other embodiments, the connector38may be a female connector that is configured to couple to a corresponding male connector, such as the connector40of the jumper20or the connector26of another extender jumper14shown inFIG. 1. As noted above, the connectors26,38, as well as other connectors28,32,34,40described herein, may include locking dogs, lock rings, toothed interfaces, tongue-in-groove interfaces, threaded interfaces, or any combination thereof. As shown, the connector38is supported by the support assembly42, which is configured to mount to the support structure18(e.g., abandoned wellhead).

The pipe50may have any of a variety of configurations to support fluid flow. The pipe50generally extends between the connector26and the connector38to enable fluid flow between the first end52and the second end54of the extender jumper14. In some embodiments, the pipe50includes sections that extend in different directions, which may enable the connector26and/or the connector38to face or be oriented axially upward or axially downward, which may in turn facilitate connection with corresponding connectors of other extender jumpers14, the jumper20, and/or structures16,22. For example, in the illustrated embodiment, the pipe50includes a first axially extending portion56that is aligned with (e.g., coaxial) and extends axially from the connector26. As shown inFIG. 3and discussed in more detail below with respect toFIG. 3, the pipe50may also include a second axially extending portion94that is aligned with (e.g., coaxial) and extends axially from the connector38within the support assembly42, and a bending portion58(e.g., having segments extending in different directions, such as in directions47and48) that connects the first axially extending portion56and the second axially extending portion94. As shown, the extender jumper14may include clamps60to facilitate moving the extender jumper14between the sea surface and the subsea field12, for example.

FIG. 3is a cross-sectional side view of an embodiment of the support assembly42of the extender jumper14ofFIG. 2. The support assembly42is configured to support the connector38and to couple to the support structure18, such as a manifold, a Christmas tree, a PLET, a PLEM, a pump, a HIPPS, a wellhead, a mud mat, a pile, a skid, or any other subsea equipment, component, or platform capable of support, any of which may be existing, currently operative, previously operative, currently inoperative, active, inactive, and/or abandoned. For example, the support structure18may include an inoperative wellhead, such as an abandoned wellhead. In the illustrated embodiment, the support assembly42includes a hollow housing or cap70(e.g., annular cap, sleeve, or cup) configured to receive and to circumferentially surround at least a portion of the support structure18. In some embodiments, a capture funnel72(e.g., tapered annular funnel or frustroconical funnel) may extend axially from the cap70to guide the cap70into position about the support structure18. In some embodiments, the cap70may have a circular cross-sectional shape (e.g., taken in a plane perpendicular to the axis47) to facilitate coupling the support assembly42to a housing (e.g., high pressure housing) of an abandoned wellhead, for example; however, it should be understood that the cap70may have any of a variety of suitable geometries and cross-sectional shapes, including a rectangular cross-sectional shape, to facilitate coupling the support assembly42to various support structures18. The cap70is configured to block lateral movement (e.g., horizontal movement) of the extender jumper14along the sea floor via the rigid, fixed position of the support structure18.

In the illustrated embodiment, the support assembly42includes a lock74(e.g., one or more locking dogs, locking rings, fasteners, locking screws, clamps, collet segments, or the like) that is configured to couple the support assembly42to the support structure18. The lock74(e.g.,1,2,3,4,5,6,7,8,9,10, or more locks74) is configured to move between an unlocked position (e.g., radially expanded position), which enables the support assembly42and the lock74to move into place about the support structure18, and a locked position (e.g., radially contracted position), which blocks movement of the support assembly42relative to the support structure18. In some embodiments, at least a portion of the lock74may contact and/or exert a radially-inward force on a side wall78(e.g., outer wall, annular wall, or radially-outer wall) of the support structure18when the lock74is in the locked position.

In some embodiments, the lock74may be actuated or driven from the unlocked position to the locked positioned via one or more actuators76(e.g., handle, pin, tool interface, mechanical actuator, hydraulic actuator, pneumatic actuator, electrical actuator, or the like). For example, in some embodiments, the one or more actuators76may be pushed radially-inwardly or rotated to move radially-inwardly along a threaded interface to drive the lock74into the locked position. In the illustrated embodiment, multiple actuators76(e.g.,1,2,3,4,5,6,7,8,9,10, or more actuators) are positioned circumferentially about the support assembly42. In some embodiments, the one or more actuators76may be operated by a remotely operated vehicle (ROV) and/or an autonomously operated vehicle (AOV). In some embodiments, the support assembly42may be supported by and positioned (e.g., lowered) about the support structure18via the ROV or AOV, and then locked into place via operation of the actuator76by the ROV or AOV. In some embodiments, the support assembly42may have a weight (e.g., be self-weighted) that maintains its position about the support structure18, in addition to or in lieu of the lock74.

In the illustrated embodiment, the support assembly42includes a frame80(e.g., upper housing or annular housing) that extends axially from the cap70. In the illustrated embodiment, the frame80is coupled to the cap70via fasteners82(e.g., threaded fasteners, such as bolts) spaced circumferentially about the frame80. However, in some embodiments, the frame80and the cap70may be a one-piece structure and may be integrally formed with one another. As shown, the frame80is generally annular and includes a bore84defined by a side wall86(e.g., outer wall, annular wall, or radially-outer wall). As shown, the side wall86of the frame80extends between the cap70and an axially-facing wall88(e.g., top wall or upper wall) of the support assembly42, and the side wall86of the frame80includes an opening90(e.g., hole) to enable the pipe50to extend into the bore84.

In the illustrated embodiment, the pipe50includes the bending portion58having a segment92that extends in a first direction (e.g., along the lateral axis48) through the opening90and a second axially-extending portion94that extends axially from the connector38and/or is coaxial with the connector38(e.g., with a central axis96of the connector38). In the illustrated embodiment, the segment92and the second axially-extending portion94of the pipe50are joined by a turn 98 (e.g., bending or turning portion) positioned within the bore84of the support assembly42. In some embodiments, the turn 98 may be formed by a continuous pipe section (e.g., bending pipe section), as shown inFIG. 4. In some embodiments, the turn 98 may be formed by a block elbow that joins two discrete segments of the pipe50to one another.

The connector38is supported by and coupled to the support assembly42. As shown, the connector38extends through an opening100(e.g., hole) formed in the axially-facing wall88of the support assembly42. In the illustrated embodiment, a ring102(e.g., split ring or annular ring) engages a recess104(e.g., annular recess) formed in a side wall106(e.g., outer wall, annular wall, or radially-outer wall) of the connector38, and the ring102is coupled to the axially-facing wall88of the support assembly42via one or more fasteners108(e.g., threaded fasteners, such as bolts). As shown, the support assembly42may support the connector38such that the central axis96of the connector38is generally vertical, extends in the axial direction47, is perpendicular to the axially-facing wall88, and/or is perpendicular to the sea floor46when the support assembly42is coupled to the support structure18. The connector38may be supported such that the connector38extends vertically above the support assembly42(e.g., along the axial axis47and relative to the sea floor46). As discussed above, the connector38may be coupled to a corresponding connector, such as the connector40of the jumper20or the connector26of another extender jumper14, as shown inFIG. 1. Thus, the support assembly42enables the extender jumper14to be coupled to and supported by the support structure18, and also supports the connector38to facilitate coupling the extender jumper14to another component, such as another extender jumper14, the jumper20, or other subsea component.

FIG. 4is a perspective view of the support assembly42of the extender jumper14ofFIG. 3, in accordance with an embodiment of the present disclosure. In the illustrated embodiment, the support assembly42includes the cap70and the capture funnel72, and multiple actuators76extend radially outward from the cap70. The frame80is coupled to the cap70via fasteners82, which are spaced circumferentially about the frame80. The opening90is formed in the side wall86of the frame80to enable the pipe50to extend into the support assembly42. The connector38extends through the opening100formed in the axially-facing surface88of the support assembly42, and the connector38is coupled to the axially-facing surface88of the support assembly42via the ring102and the fasteners108. As shown, the connector38is configured to mate with a corresponding connector (e.g., female collet connector), such as the illustrated connector40of the jumper20. As noted above, the connector38may be configured to mate with any of a variety of connectors and/or components, such as the connector26of another extender jumper14, shown inFIG. 1, or other flowline or subsea structure.

FIG. 5is a flow diagram of a method150of installing the extender jumper system10ofFIG. 1within the subsea field12, in accordance with an embodiment of the present disclosure. The method150includes various steps represented by blocks. Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate. As shown, in step152, the first end52of the extender jumper14may be coupled to the first structure16within the subsea field12. For example, in certain embodiments, the connector26of the extender jumper14may be coupled to the connector28of the first structure16.

In step154, the support assembly42of the extender jumper14may be coupled to the support structure18within the subsea field12. In some embodiments, the support assembly42is coupled to the support structure18by positioning the cap70about the support structure18and driving the lock74into the locked position via the one or more actuators76(e.g., using the ROV or the AUV). As discussed above, the support structure18may be any of a variety of subsea structures, including, but not limited to, a manifold, a Christmas tree, a PLET, a PLEM, a pump, a HIPPS, a wellhead, a mud mat, a pile, a skid, or any other subsea equipment, component, or platform capable of support, any of which may be existing, currently operative, previously operative, currently inoperative, and/or abandoned. For example, the support structure18may include a temporarily or permanently inoperative wellhead, such as for example an abandoned wellhead. In some embodiments, the support assembly42may stabilize the extender jumper14and may also support the connector38at the second end54of the extender jumper14to facilitate coupling the extender jumper14to another jumper, such as another extender jumper14or the jumper20.

In step156, a first end of the jumper20is coupled to the second end54of the extender jumper14. As discussed above, the connector38is positioned at the second end54of the extender jumper14and is supported by the support assembly42. In certain embodiments, the connector38of the extender jumper14may be coupled to the connector40of the jumper20. It should be understood that in certain embodiments, multiple extender jumpers14may be coupled to one another in series, and that the jumper20may be coupled to the last extender jumper14of the series of extender jumpers14.

In step158, a second end of the jumper20may be coupled to the second structure22within the subsea field12. For example, in certain embodiments, the connector32of the jumper20may be coupled to the connector34of the second structure22. In step160, fluid may flow between the first structure16and the second structure22via the extender jumper14and the jumper20of the extender jumper system10.

FIG. 6is a schematic diagram of the extender jumper system10in a subsea field180having multiple wells182, in accordance with an embodiment of the present disclosure. As shown, one or more wells182,184(e.g., production wells having respective Christmas trees positioned at the one or more wells182,184) may be coupled to the first structure16(e.g., a manifold) via respective jumpers20,186. In some embodiments, the one or more wells182,184may be existing or previously drilled wells that are located a distance from the first structure16that can be traversed by respective jumpers20,186, for example.

In the illustrated embodiment, one well182,188(e.g., the second structure22,189, such as a Christmas tree, positioned at the one well182,188) is coupled to the first structure16via a first extender jumper14,190and a first jumper20,192, and the first extender jumper14,190includes a first support assembly42,194that is supported by a first support structure18,196. In the illustrated embodiment, one well182,198(e.g., the second structure22,200, such as a Christmas tree, positioned at the one well182,198) is coupled to the first structure16via multiple extender jumpers14in series (e.g., the first extender jumper14,190, and a second extender jumper14,204) and a second jumper20,206. As shown, the second extender jumpers14,204also include a second support assembly42,208that is supported by a second support structure18,210. In the illustrated embodiment, a splitter212(e.g., t-coupling, y-coupling, manifold with multiple outlets) is provided proximate to the first support assembly42,194of the first extender jumper14,190. For example, the splitter212may be provided along the pipe50of the second extender jumper14,204, proximate to first support assembly42,194to enable multiple wells182to be coupled to the first structure16via the first extender jumper14,190.

By way of example, in some embodiments, the wells182,188,198may be relatively new wells at re-spud locations that are located a distance from the first structure16that may exceed an acceptable distance for a single jumper20or other typical jumpers, pipelines, or connectors, for example. In such cases, the extender jumper system10may enable the wells182,188,198to be coupled to the existing first structure16. As noted above, the support structure18may include a manifold, a Christmas tree, a PLET, a PLEM, a pump, a HIPPS, a wellhead, a mud mat, a pile, a skid, or any other subsea equipment, component, or platform capable of support, any of which may be existing, currently operative, previously operative, currently inoperative, and/or abandoned. For example, the support structure18may include an inoperative wellhead, such as an abandoned wellhead. Thus, in some such cases, the extender jumper10may enable the wells182,188,198to be coupled to the existing first structure16using an existing support structure18as a rigid attachment point for the extender jumper system10without additional costs and/or time delays associated with constructing or installing a new platform or support structure.

Reference throughout this specification to “one embodiment,” “an embodiment,” “embodiments,” “some embodiments,” “certain embodiments,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, these phrases or similar language throughout this specification may, but do not necessarily, all refer to the same embodiment.