Systems and Methods for Bracing Subsea Wellheads to Enhance the Fatigue Resistance of Subsea Wellheads and Primary Conductors

A device for bracing a subsea wellhead includes a wellhead coupling configured to be mounted to the subsea wellhead. In addition, the device includes a plurality of circumferentially-spaced anchor couplings disposed about the wellhead coupling. Each anchor coupling is radially spaced from the wellhead coupling and is configured to be mounted to a subsea anchor. Further, the device includes a plurality of circumferentially-spaced rigid wellhead support members. Each wellhead support member has a radially inner end coupled to the wellhead coupling and a radially outer end coupled to one of the anchor sleeves. The wellhead support members are configured to transfer lateral loads from the wellhead coupling to the anchor coupling.

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Description
CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/838,701 filed Jun. 24, 2013, and entitled “Systems and Methods for Bracing Subsea Wellheads to Enhance the Fatigue Resistance Thereof,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The disclosure relates generally to systems and methods for bracing subsea structures. More particularly, the disclosure relates to systems and methods for enhancing the fatigue performance of subsea wellheads and primary conductors during subsea drilling, completion, production, workover, and intervention operations.

In offshore drilling operations, a large diameter hole is drilled to a selected depth in the sea bed. Then, a primary conductor extending from the lower end of an outer wellhead housing, also referred to as a low pressure housing, is run into the borehole with the outer wellhead housing positioned just above the sea floor/mud line. To secure the primary conductor and outer wellhead housing in position, cement is pumped down the primary conductor and allowed to flow back up the annulus between the primary conductor and the borehole sidewall.

With the primary conductor cemented in place, a drill bit connected to the lower end of a drillstring suspended from a drilling vessel or rig at the sea surface is lowered through the primary conductor to drill the borehole to a second depth. Next, an inner wellhead housing, also referred to as a high pressure housing, is seated in the upper end of the outer wellhead housing. A string of casing extending downward from the lower end of the inner wellhead housing (or seated in the inner wellhead housing) is position within the primary conductor. Cement then is pumped down the casing string, and allowed to flow back up the annulus between the casing string and the primary conductor to secure the casing string in place.

Prior to continuing drilling operations in greater depths, a blowout preventer (BOP) is mounted to the wellhead and a lower marine riser package (LMRP) is mounted to the BOP. The subsea BOP and LMRP are arranged one-atop-the-other. In addition, a drilling riser extends from a flex joint at the upper end of LMRP to a drilling vessel or rig at the sea surface. The drill string is suspended from the rig through the drilling riser, LMRP, and BOP into the well bore. Drilling generally continues while successively installing concentric casing strings that line the borehole. Each casing string is cemented in place by pumping cement down the casing and allowing it to flow back up the annulus between the casing string and the borehole sidewall. During drilling operations, drilling fluid, or mud, is delivered through the drill string, and returned up an annulus between the drill string and casing that lines the well bore.

Following drilling operations, the cased well is completed (i.e., prepared for production). For subsea architectures that employ a horizontal production tree, the horizontal subsea production tree is installed on the wellhead below the BOP and LMRP during completion operations. Thus, the subsea production tree, BOP, and LMRP are arranged one-atop-the-other. Production tubing is run through the casing and suspended by a tubing hanger seated in a mating profile in the inner wellhead housing or production tree. Next, the BOP and LMRP are removed from the production tree, and the tree is connected to the subsea production architecture (e.g., production manifold, pipelines, etc.). From time to time, intervention and/or workover operations may be necessary to repair and/or stimulate the well to restore, prolong, or enhance production.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment disclosed herein, a device for bracing a subsea wellhead comprises a wellhead coupling configured to be mounted to the subsea wellhead. In addition, the device comprises a plurality of circumferentially-spaced anchor couplings disposed about the wellhead coupling. Each anchor coupling is radially spaced from the wellhead coupling and is configured to be mounted to a subsea anchor. Further, the device comprises a plurality of circumferentially-spaced rigid wellhead support members. Each wellhead support member has a radially inner end coupled to the wellhead coupling and a radially outer end coupled to one of the anchor sleeves. The wellhead support members are configured to transfer lateral loads from the wellhead coupling to the anchor coupling.

In another embodiment disclosed herein, an offshore system for drilling and/or producing a subsea well comprises a subsea wellhead extending from the well proximal the sea floor. In addition, the system comprises a plurality of circumferentially-spaced anchors disposed about the well and secured to the sea floor. Each anchor has an upper end positioned above the sea floor. Still further, the system comprises a support frame mounted to the wellhead and the anchors. The support frame comprises a wellhead sleeve disposed about the wellhead. The wellhead sleeve has a central axis. The support frame also comprises a plurality of circumferentially-spaced anchor sleeves disposed about the wellhead sleeve. Each anchor sleeve is radially spaced from the wellhead sleeve and is disposed about one of the anchors. Moreover, the support frame comprises a plurality of circumferentially-spaced rigid wellhead support members, wherein each wellhead support member extends from the wellhead sleeve to one of the anchor sleeves and is configured to transfer lateral loads therebetween.

In another embodiment disclosed herein, a method for enhancing the fatigue resistance of a subsea wellhead comprises (a) deploying a bracing device subsea. The bracing device comprises a wellhead coupling. The bracing device also comprises a plurality of circumferentially-spaced anchor couplings disposed about the wellhead coupling. Each anchor coupling is radially spaced from the wellhead coupling. The bracing device further comprises a plurality of circumferentially-spaced rigid wellhead support members. Each wellhead support member extends from the wellhead coupling to one of the anchor couplings. In addition, the method comprises (b) mounting the wellhead coupling to the wellhead. Further, the method comprises (c) mounting each anchor coupling to an anchor. Still further, the method comprises (d) securing each anchor to the sea floor. Moreover, the method comprises (e) transferring lateral loads and bending moments applied to the wellhead to the anchors with the bracing device after (b), (c), and (d).

Embodiments described herein include a combination of features and advantages over certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic partial cross-sectional side view of an offshore drilling system including an embodiment of a subsea wellhead bracing system in accordance with the principles described herein;

FIG. 2 is an enlarged view of the subsea wellbore, wellhead, tree, BOP, and bracing system of FIG. 1;

FIG. 3 is a schematic partial cross-sectional side view of the subsea wellhead and bracing system of FIG. 1;

FIG. 4 is a top view of the subsea wellhead and bracing system of FIG. 3;

FIG. 5A is a top partial view of the subsea wellhead and bracing system of FIG. 3 with the locking devices in the open positions;

FIG. 5B is a top partial view of the subsea wellhead and bracing system of FIG. 3 with the locking devices in the closed positions;

FIG. 6 is a graphical illustration of a method in accordance with the principles described herein for deploying and installing the bracing system of FIG. 1;

FIG. 7 is a graphical illustration comparing the bending moments induced along the subsea LMRP, BOP, wellhead and primary conductor of FIG. 1 due to a static offset of the surface vessel with and without the bracing system of FIG. 1;

FIG. 8 is a graphical illustration comparing the bending moments induced along the subsea LMRP, BOP, wellhead and primary conductor of FIG. 1 due to a wave with and without the bracing system of FIG. 1; and

FIG. 9 is a graphical illustration comparing the fatigue life induced along the subsea LMRP, BOP, wellhead and primary conductor of FIG. 1 with and without the bracing system of FIG. 1.

 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. 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” 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.

Referring now to FIGS. 1 and 2, an embodiment of an offshore system 100 for drilling a wellbore 101 is shown. In this embodiment, system 100 includes a floating offshore vessel 110 at the sea surface 102, a horizontal production tree 121 releasably connected to a wellhead 130 disposed at an upper end of a primary conductor 131 extending into the wellbore 101, a subsea blowout preventer (BOP) 122 releasably connected to production tree 121, and a lower marine riser package (LMRP) 123 releasably connected to BOP 122. Wellhead 130 has a central axis 135 and extends vertically upward from wellbore 101 above the sea floor 103. Tree 121, BOP 122, and LMRP 123 are vertically arranged one-above-the-other, and are generally coaxially aligned with wellhead 130.

Vessel 110 is equipped with a derrick 111 that supports a hoist (not shown). In FIG. 1, vessel 110 is a semi-submersible offshore platform, however, in general, vessel 110 can be any type of floating offshore drilling vessel including, without limitation, a moored structure (e.g., a semi-submersible platform), a dynamically positioned vessel (e.g., a drill ship), a tension leg platform, etc. A drilling riser 115 extends subsea from vessel 110 to LMRP 123. During drilling operations, riser 115 takes mud returns to vessel 110. Downhole operations are carried out by a tool connected to the lower end of the tubular string (e.g., drillstring) that is supported by derrick 111 and extends from vessel 110 through riser 115, LMRP 123, and BOP 122, tree 121 into wellbore 101.

BOP 122 and LMRP 123 are configured to controllably seal wellbore 101 and contain hydrocarbon fluids therein. Specifically, BOP 122 includes a plurality of axially stacked sets of opposed rams. In general, BOP 122 can include any number and type of rams including, without limitation, opposed double blind shear rams or blades for severing the tubular string and sealing off wellbore 101 from riser 115, opposed blind rams for sealing off wellbore 101 when no string/tubular extends through BOP 122, opposed pipe rams for engaging the string/tubular and sealing the annulus around string/tubular, or combinations thereof. LMRP 123 includes an annular blowout preventer including an annular elastomeric sealing element that is mechanically squeezed radially inward to seal on a string/tubular extending through LMRP 123 or seal off wellbore when no string/tubular extends through LMRP 123. The upper end of LMRP 123 includes a riser flex joint 124 that allows riser 115 to deflect and pivot angularly relative to tree 121, BOP 122, and LMRP 123 while fluids flow therethrough.

During drilling, completion, production, workover, and intervention operations, cyclical loads (e.g., from riser vibrations, surface vessel motions, wave action, current-induced VIV, or combinations thereof) are applied to wellhead 130 and primary conductor 131 extending from wellhead 130 into the sea floor 103. Such cyclical loads can induce fatigue. This may be of particular concern with subsea horizontal production tree architectures due to the relatively large height and weight of the hardware secured to the wellhead proximal the mud line (i.e., tree, BOP, and LMRP). For example, in this embodiment, the subsea hardware coupled to wellhead 130 proximal the sea floor 103 (i.e., tree 121, BOP 122, and LMRP 123) is relatively tall, and thus, presents a relatively large surface area for interacting with environmental loads such as subsea currents. These environmental loads acting on tree 121, BOP 122, and LMRP 123 can also fatigue wellhead 130 and primary conductor 131. If wellhead 130 and related hardware do not have sufficient fatigue resistance, the integrity of the subsea well may be compromised. Accordingly, in this embodiment, a bracing system 200 is provided to brace and reinforce wellhead 130, and resist lateral loads and bending moments applied to wellhead 130. As a result, system 200 offers the potential to enhance the fatigue resistance of wellhead 130 and the associated conductor 131, as well as ensure the integrity of wellhead 130 and conductor 131.

Referring now to FIGS. 2-4, in this embodiment, bracing system 200 includes a plurality of circumferentially-spaced anchors 210 disposed about wellhead 130 and a rigid template or support frame 250 coupling anchors 210 to wellhead 130. Anchors 210 are secured to the sea floor 103, and frame 250 is rigidly secured to wellhead 130 and anchors 210. Thus, lateral loads and bending moments applied to wellhead 130 are transferred through frame 250 to anchors 210, which resist the lateral loads and bending moments. As a result system 200 restricts and/or prevents the lateral movement of wellhead 130, thereby reinforcing (e.g., stabilizing) wellhead 130 and conductor 131.

In general, the geometry, size, and positioning of anchors 210 and support frame 250 are selected to avoid interference with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover, and intervention operations); (c) wellhead 130, primary conductor 131, tree 121, BOP 122, and LMRP 123; (d) subsea remotely operated vehicle (ROV) operations and access to tree 121, BOP 122, and LMRP 123; and (e) neighboring wells. For example, as best shown in FIGS. 3 and 4, each anchor 210 is disposed at a distance R210 measured radially (center-to-center) from wellhead 130. Radial distances R210 are generally selected to be as close to wellhead 130 as possible without interfering with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover, and intervention operations); (c) wellhead 130, primary conductor 131, tree 121, BOP 122, and LMRP 123; (d) subsea remotely operated vehicle (ROV) operations and access to tree 121, BOP 122, and LMRP 123; and (e) neighboring wells. For most subsea applications, each radial distance R210 is preferably between 3.0 and 10.0 m, and more preferably between 4.0 and 6.0 m. To balance and uniformly distribute loads between wellhead 130 and anchors 210, each radial distance R210 is preferably the same, and preferably at least three uniformly circumferentially-spaced anchors 210 are provided in bracing system 200. In this embodiment, system 200 includes three uniformly circumferentially-spaced anchors 210, which each anchor 210 disposed at a radial distance R210 of 5.0 m.

As best shown in FIG. 3, in this embodiment, each anchor 210 is an elongate pile embedded in the sea floor 103. In particular, each anchor 210 has a vertically oriented central or longitudinal axis 215, an upper end 210a disposed above the sea floor 103, and a lower end 210b disposed below the sea floor 103. In general, anchor 210 can be any suitable type of pile including, without limitation, a driven pile or suction pile. Typically, the type of pile selected for anchor 210 will depend on a variety of factors including, without limitation, the soil conditions at the installation site. Anchors 210 are sized to penetrate the sea floor 103 to a depth to sufficiently resist the anticipated lateral loads and bending moments applied to wellhead 130 without moving laterally within sea floor 103.

Referring again to FIGS. 3 and 4, frame 250 is positioned at a height H250 (FIG. 3) measured vertically from the sea floor 103. Height H250 is preferably between 0.0 and 10.0 ft. In addition, frame 250 is vertically movably secured to wellhead 130 and rigidly secured to anchors 210. In this embodiment, support frame 250 includes a wellhead adapter or coupling 251, a plurality of uniformly circumferentially-spaced anchor adapters or couplings 260 disposed about wellhead coupling 251, a plurality of rigid wellhead support members 270 extending radially from coupling 251 to couplings 260, and a plurality of rigid anchor coupling support members 280 extending between each pair of circumferentially adjacent anchor couplings 260. Wellhead coupling 251 is mounted to wellhead 130, and each anchor coupling 260 is securely mounted to one anchor 210. Thus, the number of anchor couplings 260 is the same as the number of anchors 210. Because three anchors 210 are provided in this embodiment, three anchor couplings 260 are provided.

In this embodiment, wellhead coupling 251 is a sleeve, and thus, may also be referred to herein as wellhead sleeve 251; and anchor couplings 260 are sleeves, and thus, may also be referred to herein as anchor sleeves 260. As best shown in FIG. 4, each anchor sleeve 260 is disposed at a distance R260 measured radially from wellhead sleeve 251 to anchor sleeve 260. Wellhead sleeve 251 is disposed about wellhead 130 and anchor sleeves 260 are disposed about anchors 210. Thus, distance R260 is the same or substantially the same as distance R210.

Referring now to FIGS. 3 and 4, wellhead sleeve 251 has a central axis 255 coaxially aligned with wellhead 130, an upper end 251a, a lower end 251b opposite end 251a, and a throughbore or passage 252 extending axially between ends 251a, 251b. Throughbore 252 is sized and configured to receive wellhead 130. In other words, the inner diameter of wellhead sleeve 251 is greater than the outer diameter of wellhead 130. As a result, an annulus 253 is radially disposed between wellhead 130 and wellhead sleeve 251. In this embodiment, lower end 251b is shaped as a funnel 254 that facilitates the alignment and receipt of wellhead 130 into sleeve 251 during installation of system 200 described in more detail below.

Each anchor sleeve 260 has a central axis 265 coaxially aligned with the corresponding anchor 210, an upper end 260a, a lower end 260b opposite end 260a, and a throughbore or passage 261 extending axially between ends 260a, 260b. Each throughbore 261 is sized and configured to receive one anchor 210. In other words, the inner diameter of each sleeve 260 is greater than the outer diameter of the corresponding anchor 210. As a result, an annulus 262 is radially disposed between each anchor 210 and the corresponding anchor sleeve 260. In this embodiment, each end 260a, 260b includes a funnel 263 that facilitates the alignment and movement of the sleeve 260 relative to the corresponding anchor 210 during installation of system 200 described in more detail below. As best shown in FIG. 2, in this embodiment, lower end 251b of wellhead sleeve 250 is vertically aligned with lower ends 260b of anchor sleeves 260. In other words, lower ends 251b, 260b are disposed at the same vertical position or height (e.g., relative to the sea floor). However, in this embodiment, upper end 251a of wellhead sleeve 250 is axially disposed above upper ends 260a of anchor sleeves 260.

Referring again to FIGS. 3 and 4, one wellhead support member 270 extends radially from wellhead sleeve 251 to each anchor coupling 260, and one anchor coupling support member 280 extends between each pair of circumferentially adjacent anchor sleeves 260. Support members 270 maintain the radial spacing of anchor sleeves 260 relative to wellhead sleeve 251, and support members 280 maintain the circumferential spacing of anchor sleeves 260. Thus, support members 270, 280 maintain the positioning of sleeves 251, 260 relative to each other. In addition, wellhead support members 270 transfer radial/lateral loads from wellhead sleeve 251 to anchor sleeves 260, and anchor coupling support members 280 transfer loads between anchor sleeves 260. In this embodiment, each support member 270, 280 is a rigid tubular steel frame or truss.

Referring now to FIG. 3, as previously described, wellhead sleeve 251 is coupled to wellhead 130. In particular, wellhead sleeve 251 is mounted to wellhead 130 such that wellhead 130 is restricted and/or prevented from moving radially/laterally relative to wellhead sleeve 251. However, wellhead sleeve 251 is not axially fixed to wellhead 130, and thus, wellhead 130 can move axially relative to wellhead sleeve 251. This arrangement allows the effective and efficient transfer of radial/lateral loads and bending moments applied to wellhead 130 to sleeve 251, while accommodating the axial movement of wellhead 130 relative to sleeve 251 due to thermal expansion of primary conductor 131 during production operations.

In this embodiment, wellhead sleeve 251 is radially fixed relative to wellhead 130 with a plurality of uniformly circumferentially-spaced locking rams or assemblies 290 extending radially from sleeve 251 to wellhead 130 (FIGS. 4, 5A, and 5B) and cement 295 disposed in annulus 253 (FIG. 3). In general, cement 295 can include any material suitable for subsea use that is capable of being injected in a flowing, fluid form and then allowed to harden including, without limitation, a grout, an epoxy, or the like.

Referring now to FIGS. 5A and 5B, locking assemblies 290 are attached to sleeve 251 and configured to releasably engage wellhead 130 disposed therein. In this embodiment, each locking assembly 290 includes a housing 291 attached to the outside of wellhead sleeve 251, a linear actuator 292 disposed in housing 291, and a gripping or extension member 293 coupled to actuator 292. Each extension member 293 extends radially from the corresponding actuator 292 into annulus 253. Linear actuators 292 are configured to move extension members 293 radially between a withdrawn or unlocked position radially spaced from wellhead 130 disposed in sleeve 251 (FIG. 5A), and an advanced or locked position engaging wellhead 130 disposed in sleeve 251 (FIG. 5B). In this embodiment, each actuator 292 is an ROV operated hydraulic piston-cylinder assembly.

To ensure wellhead 130 can move axially relative to wellhead sleeve 251, wellhead sleeve 251 is axially positioned along a portion of wellhead 130 that is disposed above the sea floor 103 and has a cylindrical (i.e., uniform diameter) outer surface. The interface between wellhead 130 and extension members 293 allows sliding engagement therebetween, and further, the interface between wellhead 130 and cement 295 allows sliding engagement therebetween. This can be achieved by selecting materials at the interfaces that provide a relatively low coefficients of friction such as UHMW (ultra-high molecular weight) polyethylene.

Referring now to FIG. 3, as previously described, each anchor sleeve 260 is coupled to upper end 210a of the corresponding anchor 210. In particular, each anchor sleeve 260 is radially and axially fixed to the corresponding anchor 210 such that it is restricted and/or prevented from moving radially and axially relative to the corresponding anchor 210. This arrangement allows the effective and efficient transfer of radial/lateral loads and bending moments applied to wellhead 130 to anchors 210 via sleeve 251, wellhead support members 270, and sleeves 260. In this embodiment, each anchor sleeve 260 is radially and axially fixed to the corresponding anchor 210 with cement 296 disposed in annulus 262. In general, cement 296 can comprise any material suitable for subsea use that is capable of being injected in a flowing, fluid form and then allowed to harden including, without limitation, a grout, an epoxy, or the like

Referring now to FIG. 6, an embodiment of a method 300 for deploying and installing bracing system 200 is shown. In this embodiment, sleeve 251 is a unitary, single-piece tubular configured to axially receive wellhead 130, and thus, system 200 is designed to be deployed and installed while vertical access to wellhead 130 is available (i.e., when tree 121, BOP 122, and LMRP 123 are not coupled to wellhead 130). However, in other embodiments, the wellhead coupling (e.g., wellhead sleeve 251) includes a multi-piece structure that is disposed about the wellhead (e.g., wellhead 130) and then made-up. For example, in one embodiment, the wellhead coupling is a clam-shell type design including two-halves that are radially advanced toward each other around the wellhead, and then bolted or welded together with the wellhead captured therebetween. In such alternative embodiments, the bracing system (e.g., bracing system 200) can be deployed and installed with or without vertical access to the wellhead (e.g., wellhead 130).

For subsea deployment and installation of bracing system 200, one or more remote operated vehicles (ROVs) are preferably employed to aid in positioning support frame 250 and anchors 210, monitoring support frame 250 and anchors 210, actuating locking assemblies 290, and filling annuli 253, 262 with cement 295, 296, respectively. Each ROV preferably includes an arm with a claw for manipulating objects and a subsea camera for viewing the subsea operations. Streaming video and/or images from the cameras are communicated to the surface or other remote location for viewing on a live or periodic basis.

Referring still to FIG. 6, in block 301, support frame 250 is deployed subsea from a surface vessel such as vessel 110 or a separate construction vessel. In general, support frame 250 can be lowered subsea by any suitable means such as wireline. Moving now to block 305, support frame 250 is lowered to wellhead 130. Wellhead sleeve 251 is positioned immediately above wellhead 130 and coaxially aligned with wellhead 130. Next, frame 250 is lowered to the sea floor 103 while wellhead 130 is received into wellhead sleeve 251. Mud mats are preferably disposed on the sea floor 103 below frame 250 to distribute the weight of frame 250 and prevent frame 250 from sinking into any soft/loose material at the sea floor 103. Such mud mats can be deployed prior to or in conjunction with support frame 250.

Anchors 210 are deployed subsea in block 310. In general, anchors 210 can be lowered subsea from a surface vessel such as vessel 110 or a separate construction vessel by any suitable means such as wireline, and further, anchors 210 can be lowered before, during, or after frame 250 is deployed in block 305. Next, in block 315, anchors 210 are installed (i.e., secured to the sea floor 103). To install anchors 210, each anchor 210 is vertically oriented, positioned immediately above and coaxially aligned with one anchor sleeve 260. Then, each anchor 210 is vertically lowered and passed through the corresponding sleeve 260, and advanced into the sea floor 103 until upper end 210a disposed at the desired height above the sea floor 103. In general, anchors 210 can be installed one at a time, or two or more at the same time.

Following block 315, support frame 250 is disposed on the sea floor 103 with wellhead 130 disposed in wellhead sleeve 251 and anchors 210 disposed in anchor sleeves 260. In block 320, support frame 250 is raised from the sea floor 103 to the desired height aligned with the cylindrical portion of wellhead 130, and leveled. Frame 250 can be raised and leveled by any suitable means such as one or more jacks, wirelines from a surface vessel, subsea ROVs, or combinations thereof. Next, in blocks 325 and 330, support frame 250 is maintained in the raised and leveled position while anchor sleeves 260 is secured to anchors 210 with cement 296 and wellhead sleeve 251 is secured to wellhead 130 with locking assemblies 290 and cement 295. More specifically, cement 296 is pumped into annulus 262 and then allowed to cure and harden, extension members 293 are transitioned to the locked positions with actuators 292, and cement 295 is pumped into annulus 253 and then allowed to cure and harden.

In the embodiment shown in FIG. 6, anchors 210 are installed after support frame is lowered to the sea floor 103 with wellhead 130 stabbed into wellhead sleeve 251. However, in other embodiments, the anchors (e.g., anchors 210) are installed before the wellhead (e.g., wellhead 130) is stabbed into the wellhead sleeve (e.g., wellhead sleeve 250) of the support frame (e.g., support frame 250), and then upper ends of the installed anchors and the wellhead are simultaneously stabbed into the corresponding sleeves by lowering the support frame to the sea floor.

In the manner described, bracing system 200 is deployed and installed on wellhead 130. In particular, bracing system 200 reinforces (e.g., stabilizes) wellhead 130 by restricting the lateral/radial movement of wellhead 130, thereby stiffening wellhead 130 and changing the natural frequency of wellhead 130. As a result, embodiments of bracing system 200 described herein offer the potential to reduce the stresses induced in wellhead 130 and primary conductor 131, improve the fatigue resistance of wellhead 130 and primary conductor 131, and improve the bending moment response along primary conductor 131 below the sea floor 103.

Referring now to FIGS. 7-9, system 10, and in particular, primary conductor 131, wellhead 130, BOP 122, and LMRP 123 were modeled and simulations were run with and without bracing system 200 to assess the impact of bracing system 200. FIGS. 7, 8, and 9 graphically illustrate the results of those simulations with and without bracing system 200. In FIG. 7, the bending moments induced along LMRP 123, BOP 122, wellhead 130, and conductor 131 due to a static offset of surface vessel 110 are shown as a function of the elevation relative to the sea floor 103 (i.e., mudline); in FIG. 8, the bending moments induced along LMRP 123, BOP 122, wellhead 130, and conductor 131 due to a wave are shown as a function of the elevation relative to the sea floor 103 (i.e., mudline); and in FIG. 9, the fatigue life along LMRP 123, BOP 122, wellhead 130, and conductor 131 is shown as a function of the elevation relative to the sea floor 103 (i.e., mudline).

Although frame 250 is shown and described as being mounted to wellhead 130 in system 200, in other embodiments, a rigid frame (e.g., frame 250) coupled to a plurality of subsea anchors (e.g., anchors 210) is mounted to other locations of the subsea architecture. For example, an anchored frame can be coupled to a subsea production tree (e.g., tree 121), a subsea BOP (e.g., BOP 122), the mandrel extending between the subsea tree and BOP, or the mandrel extending between the BOP and an LMRP (e.g., LMRP 123).

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

1. A device for bracing a subsea wellhead, the device comprising:

a wellhead coupling configured to be mounted to the subsea wellhead;
a plurality of circumferentially-spaced anchor couplings disposed about the wellhead coupling, wherein each anchor coupling is radially spaced from the wellhead coupling and is configured to be mounted to a subsea anchor;
a plurality of circumferentially-spaced rigid wellhead support members, wherein each wellhead support member has a radially inner end coupled to the wellhead coupling and a radially outer end coupled to one of the anchor sleeves, and wherein the wellhead support members are configured to transfer lateral loads from the wellhead coupling to the anchor coupling.

2. The device of claim 1, further comprising a plurality of rigid anchor coupling support members, wherein one anchor coupling support member extends between each pair of circumferentially adjacent anchor coupling and is configured to transfer loads therebetween.

3. The device of claim 1, wherein the anchor couplings are uniformly circumferentially-spaced about the wellhead coupling.

4. The device of claim 1, wherein each anchor coupling is disposed at a radial distance R1 from the wellhead coupling, and wherein each radial distance R1 is the same.

5. The device of claim 4, wherein each radial distance R1 is between 4.0 and 6.0 m.

6. The device of claim 1, wherein a lower end of each anchor coupling is vertically aligned with a lower end of the wellhead coupling.

7. The device of claim 1, wherein the wellhead coupling is a wellhead sleeve configured to be disposed about the wellhead and each anchor coupling is an anchor sleeve configured to be disposed about one subsea anchor.

8. The device of claim 7, wherein the lower end of the wellhead sleeve and the lower end of each anchor sleeve comprises a funnel.

9. The device of claim 1, further comprising a plurality of circumferentially spaced locking devices mounted to the wellhead coupling, wherein each locking device is configured to engage and lock onto the subsea wellhead.

10. The device of claim 1, wherein the plurality of anchor couplings comprises at least three uniformly circumferentially-spaced anchor couplings.

11. An offshore system for drilling or producing a subsea well, the system comprising:

a subsea wellhead extending from the well proximal the sea floor;
a plurality of circumferentially-spaced anchors disposed about the well and secured to the sea floor, wherein each anchor has an upper end positioned above the sea floor;
a support frame mounted to the wellhead and the anchors, wherein the support frame comprises: a wellhead sleeve disposed about the wellhead, wherein the wellhead sleeve has a central axis; a plurality of circumferentially-spaced anchor sleeves disposed about the wellhead sleeve, wherein each anchor sleeve is radially spaced from the wellhead sleeve and is disposed about one of the anchors; a plurality of circumferentially-spaced rigid wellhead support members, wherein each wellhead support member extends from the wellhead sleeve to one of the anchor sleeves and is configured to transfer lateral loads therebetween.

12. The system of claim 11, wherein each anchor is a driven pile or a suction pile having a lower end disposed below the sea floor.

13. The system of claim 11, wherein each anchor sleeve is axially and radially fixed to the upper end of the corresponding anchor.

14. The system of claim 13, wherein the wellhead sleeve is radially fixed to the wellhead.

15. The system of claim 11, wherein an annulus is radially positioned between the wellhead and the wellhead sleeve; and

wherein the annulus is at least partially filled with cement.

16. The system of claim 11, wherein an annulus is radially positioned between the wellhead and the wellhead sleeve;

wherein the support frame further comprises a plurality of circumferentially spaced locking devices mounted to the wellhead sleeve, wherein each locking device extends radially inward from the wellhead sleeve through the annulus and into engagement with the wellhead;
wherein each locking device is configured to prevent the wellhead from moving radially relative to the wellhead sleeve and allow the wellhead to move axially relative to the wellhead sleeve.

17. The system of claim 11, wherein the anchors are uniformly circumferentially-spaced about the wellhead.

18. The system of claim 17, wherein each anchor is disposed at a radial distance R1 from the wellhead, and wherein each radial distance R1 is the same.

19. The system of claim 18, wherein each radial distance R1 is between 4.0 and 6.0 m.

20. The system of claim 11, wherein the wellhead sleeve and each anchor sleeve are positioned above the sea floor.

21. The system of claim 11, wherein the plurality of anchors comprises at least three uniformly circumferentially-spaced anchors; and

wherein the plurality of anchor sleeves comprises at least three uniformly circumferentially-spaced anchor sleeves, each anchor sleeve being secured to one of the anchors.

22. A method for enhancing the fatigue resistance of a subsea wellhead, the method comprising

(a) deploying a bracing device subsea, wherein the bracing device comprises: a wellhead coupling; a plurality of circumferentially-spaced anchor couplings disposed about the wellhead coupling, wherein each anchor coupling is radially spaced from the wellhead coupling; a plurality of circumferentially-spaced rigid wellhead support members, wherein each wellhead support member extends from the wellhead coupling to one of the anchor couplings;
(b) mounting the wellhead coupling to the wellhead;
(c) mounting each anchor coupling to an anchor;
(d) securing each anchor to the sea floor;
(e) transferring lateral loads and bending moments applied to the wellhead to the anchors with the bracing device after (b), (c), and (d).

23. The method of claim 22, wherein the wellhead coupling is a wellhead sleeve; and

wherein (b) comprises aligning the wellhead sleeve with the wellhead and lowering the bracing device to receive the wellhead into the wellhead sleeve.

24. The method of claim 23, wherein each anchor coupling is an anchor sleeve; and

wherein (d) comprises advancing one anchor through each of the anchor sleeves and into the sea floor.

25. The method of claim 22, further comprising:

(f) radially fixing each anchor coupling relative to the corresponding anchor to prevent relative radial movements therebetween;
(g) radially fixing the wellhead coupling relative to the wellhead to prevent relative radial movement therebetween.

26. The method of claim 25, further comprising:

supporting the bracing device with the sea floor during (d); and
raising the bracing device off the sea floor after (c) and (d), and before (f) and (g).

27. The method of claim 25, wherein (g) comprises actuating a locking assembly to extend an extension member radially inward from the wellhead coupling into engagement with the wellhead.

28. The method of claim 22, wherein each anchor coupling is disposed at a radial distance R1 from the wellhead, and wherein each radial distance R1 is the same.

29. The method of claim 28, wherein each radial distance R1 is between 4.0 and 6.0 m.

Patent History
Publication number: 20140374113
Type: Application
Filed: Jun 24, 2014
Publication Date: Dec 25, 2014
Inventor: Elizbar Buba Kebadze (Sutton)
Application Number: 14/313,594
Classifications
Current U.S. Class: Connection Or Disconnection Of Submerged Members Remotely Controlled (166/338)
International Classification: E21B 17/02 (20060101);