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

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The disclosure relates generally to systems and methods for bracing subsea structures. More particular, the disclosure relates to systems and methods for enhancing the fatigue performance of subsea wellheads and primary conductors during subsea drilling, completion, production, and workover 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 is 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 positioned 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 system for tethering a subsea wellhead comprises a plurality of anchors disposed about the subsea BOP and secured to the sea floor. In addition, the system comprises a plurality of tensioning systems. One tensioning system is coupled to an upper end of each anchor. Further, the system comprises a plurality of flexible tension members. Each tension member extends from a first end coupled to the subsea wellhead to a second end coupled to one of the tensioning systems. Each tensioning system is configured to apply a tensile preload to one of the tension members.

In another embodiment disclosed herein, a system for drilling, completing, 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 wellhead and secured to the sea floor. Each anchor has an upper end disposed proximal the sea floor. Further, the system comprises a plurality of tensioning systems. Each tensioning system is coupled to one of the anchors. Further, the system comprises a wellhead adapter mounted to the wellhead. Moreover, the system comprises a plurality of flexible tension members. Each tension member is coupled to one of the tensioning systems and has a first end coupled to the wellhead adapter. Each tension member is in tension between the corresponding tensioning system and the first end.

In another embodiment disclosed herein, a method for tethering a subsea wellhead comprises (a) securing the plurality of anchors to the sea floor about the wellhead. In addition, the method comprises (b) coupling a flexible tension member to each anchor. Further, the method comprises (c) coupling each tension member to the wellhead. Still further, the method comprises (d) applying a tensile preload to each tension member after (a)-(c).

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 system for completing a subsea well including an embodiment of a subsea tethering system in accordance with the principles described herein;

FIG. 2 is a top view of the offshore system of FIG. 1;

FIG. 3 is an enlarged partial view of the tethering system and wellhead of FIG. 1;

FIG. 4 is an enlarged isometric view of one of the pile top assemblies of FIG. 1;

FIG. 5 is a cross-sectional side view of the pile top assembly of FIG. 4;

FIG. 6 is a cross-sectional view of the winch of FIG. 4 illustrating the locking mechanism;

FIG. 7 is a partial exploded view of the winch of FIG. 4 illustrating the locking mechanism;

FIG. 8 is a side view of the winch of FIG. 4 with the locking mechanism and locking ring in the “unlocked” position;

FIG. 9 is a side view of the winch of FIG. 4 with the locking mechanism and locking ring in the “locked” position;

FIG. 10 is a graphical illustration of an embodiment of a method in accordance with the principles described herein for deploying and installing the tethering system of FIG. 1;

FIG. 11 is a schematic partial cross-sectional side view of an offshore system for completing a subsea well including an embodiment of a subsea tethering system in accordance with the principles described herein;

FIG. 12 is a top view of the offshore system of FIG. 11;

FIG. 13 is an enlarged partial isometric view of the tethering system and wellhead of FIG. 11;

FIG. 14 is an enlarged partial isometric view of the tethering system and wellhead of FIG. 11;

FIG. 15 is an enlarged exploded isometric view of one pile top assembly of FIG. 11;

FIG. 16 is an enlarged exploded isometric view of one pile top assembly and tensioning system of FIG. 11;

FIG. 17 is an enlarged isometric view of one tensioning system of FIG. 11;

FIG. 18 is a graphical illustration of an embodiment of a method in accordance with the principles described herein for deploying and installing the tethering system of FIG. 11;

FIG. 19 is a graphical illustration comparing the bending moments induced along the subsea LMRP, BOP, wellhead, and primary conductor of FIG. 11 due to a static offset of the surface vessel with and without the tethering system of FIG. 11;

FIG. 20 is a graphical illustration comparing the bending moments induced along the subsea LMRP, BOP, wellhead, and primary conductor of FIG. 11 due to a wave with and without the tethering system of FIG. 11; and

FIG. 21 is a graphical illustration comparing the fatigue life induced along the subsea LMRP, BOP, wellhead and primary conductor of FIG. 11 with and without the tethering system of FIG. 11.

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 FIG. 1, an embodiment of an offshore system 10 for drilling and completing a wellbore 20, respectively, is shown. In this embodiment, system 10 includes a floating offshore vessel 30 at the sea surface 11, a horizontal production tree 40 releasably connected to a wellhead 50 disposed at an upper end of a primary conductor 51 extending into the wellbore 20, a subsea blowout preventer (BOP) 41 releasably connected to production tree 40, and a lower marine riser package (LMRP) 42 releasably connected to BOP 41. Tree 40, BOP 41, and LMRP 42 are vertically arranged or stacked one-above-the-other, and are generally coaxially aligned with wellhead 50. Wellhead 50 has a central axis 55 and extends vertically upward from wellbore 20 above the sea floor 12. In FIG. 1, system 10 is shown configured for completion operations, and thus, includes tree 40, however, for drilling operations, tree 40 may not be included.

As best shown in FIG. 1, vessel 30 is equipped with a derrick 31 that supports a hoist (not shown). In this embodiment, vessel 30 is a semi-submersible offshore platform, however, in general, the vessel (e.g., vessel 30) 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 43 (not shown in FIG. 2) extends subsea from vessel 30 to LMRP 42. During drilling operations, riser 43 takes mud returns to vessel 30. 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 31 and extends from vessel 30 through riser 43, LMRP 42, and BOP 41, and tree 40 into wellbore 20. In this embodiment, BOP 41 includes an outer rectangular prismatic frame 47.

BOP 41 and LMRP 42 are configured to controllably seal wellbore 20 and contain hydrocarbon fluids therein. Specifically, BOP 41 includes a plurality of axially stacked sets of opposed rams disposed within frame 47. In general, BOP 41 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 20 from riser 43, opposed blind rams for sealing off wellbore 20 when no string/tubular extends through BOP 41, opposed pipe rams for engaging the string/tubular and sealing the annulus around string/tubular, or combinations thereof LMRP 42 includes an annular blowout preventer comprising an annular elastomeric sealing element that is mechanically squeezed radially inward to seal on a string/tubular extending through LMRP 42 or seal off wellbore when no string/tubular extends through LMRP 42. The upper end of LMRP 42 includes a riser flex joint 44 that allows riser 43 to deflect and pivot angularly relative to tree 40, BOP 41, and LMRP 42 while fluids flow therethrough.

During drilling, completion, production, and workover operations, cyclical loads due to riser vibrations (e.g., from surface vessel motions, wave actions, current-induced VIV, or combinations thereof) are applied to BOP 41, wellhead 50, and primary conductor 51 extending from wellhead 50 into the sea floor 12. Such cyclical loads can induce fatigue. This may be of particular concern with subsea horizontal production tree architectures (e.g., system 10) 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 hardware mounted to wellhead 50 proximal the sea floor 12, production tree 40 and BOP 41 in particular, is relatively tall, and thus, presents a relatively large surface area for interacting with environmental loads such as subsea currents. These environmental loads can also contribute to the fatigue of BOP 41, wellhead 50, and primary conductor 51. If the wellhead 50 and primary conductor 51 do not have sufficient fatigue resistance, the integrity of the subsea well may be compromised. Still further, an uncontrolled lateral movement of vessel 30 (e.g., an uncontrolled drive off or drift off of vessel 30) from the desired operating location generally over wellhead 50 can pull LMRP 42 laterally with riser 43, thereby inducing bending moments and associated stresses in BOP 41, wellhead 50, and conductor 51. Such induced bending moments and stresses can be increased further when the relatively tall and heavy combination of tree 40 and BOP 41 is in a slight angle relative to vertical. Accordingly, in this embodiment, a tethering system 100 is provided to brace and reinforce wellhead 50 and primary conductor 51 by resisting lateral loads and bending moments applied thereto. As a result, system 100 offers the potential to enhance the strength and fatigue resistance of wellhead 50 and conductor 51.

Referring now to FIGS. 1 and 2, in this embodiment, tethering system 100 includes a plurality of anchors 110, a plurality of pile top assemblies 120, a plurality of flexible tension members 160, and a wellhead adapter 180 mounted to wellhead 50. One pile top assembly 120 is mounted to the upper end of each anchor 110, and one tension member 160 extends from each pile top assembly 120 to adapter 180. As will be described in more detail below, each pile top assembly 120 includes a tensioning system 140 that can apply tensile loads to the corresponding tension member 160. In this embodiment, each tensioning system 140 is a winch, and thus, may also be referred to as winch 140. Each winch 140 can pay in and pay out the corresponding tension member 160. As will be described in more detail below, each tension member 160 extends from the corresponding winch 140 and is coupled to adapter 180.

Referring still to FIGS. 1 and 2, anchors 110 are circumferentially-spaced about wellhead 50 and secured to the sea floor 12. In addition, each anchor 110 is disposed at a distance R₁₁₀measured radially (horizontally center-to-center) from wellhead 50. The circumferential positions and distances R₁₁₀of anchors 110 are preferably selected to avoid and/or minimize interference with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover and intervention operations); (c) wellhead 50, primary conductor 51, tree 40, BOP 41, and LMRP 42; (d) subsea remotely operated vehicle (ROV) operations and access to tree 40, BOP 41, and LMRP 42; and (e) neighboring wells.

As will be described in more detail below, lateral preloads are applied to wellhead 50 by tension members 160. To balance and uniformly distribute such lateral preloads applied to wellhead 50, anchors 110 are preferably uniformly circumferentially-spaced about wellhead 50 and each distance R₁₁₀is preferably the same. In this embodiment, four anchors 110 are uniformly circumferentially-spaced about wellhead 50, and each anchor 110 is disposed at the same distance R₁₁₀. However, in general, three or more uniformly circumferentially-spaced anchors 110 are preferably provided. For most subsea applications, each radial distances R₁₁₀are between 15 and 60 ft. However, radial distances R₁₁₀outside this range can also be employed.

Referring now to FIGS. 1, 4, and 5, each anchor 110 is an elongate rigid member fixably disposed in the seabed. In particular, each anchor 110 has a vertically oriented central or longitudinal axis 115, an upper end 110a disposed above the sea floor 12, a lower end 110b disposed in the seabed below the sea floor 12, a cylindrical outer surface 111 extending axially between ends 110a, 110b, and an annular lip or flange 112 (FIG. 5) extending radially outward from outer surface 111 proximal upper end 110a. In this embodiment, each anchor 110 is a subsea pile, and thus, anchors 110 may also be referred to as piles 110. Each pile 110 is embedded in the seabed and, in general, can be any suitable type of pile including, without limitation, a driven pile or suction pile. Typically, the type of pile employed will depend on a variety of factors including, without limitation, the soil conditions at the installation site. Piles 110 are sized to penetrate the seabed to a depth to sufficiently resist the anticipated tensile loads applied to tension members 160 (i.e., the anticipated tensile preloads L plus any additional tensile loads resulting from the loads and bending moments applied to BOP 41) without moving laterally or vertically relative to the sea floor 12.

Referring now to FIGS. 4 and 5, each pile top assembly 120 is releasably mounted to the upper end 110a of one anchor 110. In this embodiment, each pile top assembly 120 is the same, and thus, one pile top assembly 120 will be described it being understood that the other pile top assemblies 120 are the same. Pile top assembly 120 includes an adapter 40 removably mounted to the upper end 110a of pile 110, a plurality of uniformly circumferentially-spaced locking rams 130 attached to adapter 40, and winch 140 fixably secured to adapter 40.

Adapter 40 is a generally cylindrical sleeve having a first or upper end 40a, a second or lower end 40b, a radially inner annular shoulder 41, and a receptacle 42 extending axially from lower end 40b to flange 41. Receptacle 42 is sized and configured to receive upper end 110a of anchor 110. To facilitate the receipt of anchor 110 and coaxial alignment of anchor 110 and adapter 40, an annular funnel 124 is disposed at lower end 40b. Adapter 40 is generally coaxially aligned with anchor 110, and then lowered onto upper end 110a of anchor 110. Upper end 110a is advanced through lower end 40b and receptacle 42 until end 110a axially abuts shoulder 41. With end 110a of anchor 110 sufficiently seated in receptacle 42, it is releasably locked therein with locking rams 130 described in more detail below. A guide 125 for tension member 160 is secured to upper end 40a. Tension member 160 extends from winch 140 through guide 124 to end 160a. Thus, guide 125 generally directs tension member 160 as it is paid in and paid out from winch 140.

As best shown in FIG. 5, locking rams 130 are actuated to engage and disengage upper end 110a of pile 110, which is coaxially disposed in receptacle 42, and releasably lock pile top assembly 120 to pile 110. Each ram 130 includes a double-acting linear actuator 131 mounted to adapter 40 between ends 40a, 40b and a gripping member or ram block 132 coupled to the actuator 131. Each gripping member 132 is mounted to the radially inner end of the corresponding actuator 131 and extends into receptacle 42. Actuators 131 are actuated to move gripping members 132 radially inward into engagement with outer surface 111 of pile 110 and radially outward out of engagement with pile 110. Locking rams 130 are axially positioned along adapter 40 such that when actuators 131 are operated to move gripping members 132 into engagement with outer surface 111, each gripping member 132 is axially disposed immediately below annular lip 112. Thus, when gripping members 132 are moved into engagement with outer surface 111 of pile 110, friction between gripping members 132 and outer surface 111 and axial engagement of gripping members 132 with lip 112 prevent adapter 40 from being removed from pile 110. In this embodiment, each actuator 131 is an ROV operated hydraulic piston-cylinder assembly.

Referring now to FIGS. 4, 6, and 7, winch 140 is fixably mounted to upper end 40a of adapter 40. In this embodiment, winch 140 includes a spool 141 rotatably coupled to adapter 40 and a locking mechanism or brake 150 coupled to spool 141 and adapter 40. Spool 141 is selectively rotated relative to adapter 40 to pay in and pay out tension member 160. As will be described in more detail below, locking mechanism 150 releasably locks spool 141 relative to adapter 40.

Spool 141 has a horizontal axis of rotation 145 and includes a drum 142 around which tension member 160 is wound, a driveshaft 143 extending from one side of drum 142, and a support shaft 144 extending from the opposite side of drum 142. Drum 142 and shafts 143, 144 are coaxially aligned with axis 145. Driveshaft 143 extends through a connection block 146 fixably mounted to upper end 40a of adapter 40 and support shaft 144 extends into a connection block 147 fixably mounted to upper end 40a of adapter 40. Each shaft 143, 144 is rotatably supported within block 146, 147, respectively, with an annular bearing. The distal end of driveshaft 143 comprises a torque tool interface 148 designed to mate with a subsea ROV torque tool.

As best shown in FIGS. 6-9, locking mechanism 150 includes an annular spool ring 151 disposed about shaft 144 and coupled to drum 142, a hub 152 extending from block 147 and disposed about shaft 144, an annular lock ring 153 slidably mounted to hub 152, and an actuation system 154 that moves lock ring 153 axially along hub 152 into and out of spool ring 151. Spool ring 141, hub 152, and lock ring 153 are coaxially aligned with axis 145. Spool ring 151 is fixably mounted to drum 142, and hub 152 is integral with connection block 147. Spool ring 151 includes a plurality of internal splines 151a, hub 152 includes a plurality of external splines 152a, and lock ring 153 includes a plurality of external splines 153a and a plurality of internal splines 153b. Splines 151a, 152a, 153a, 153b are all oriented parallel to axis 145.

Internal splines 151a of spool ring 151 and external splines 153a of lock ring 153 are sized and configured to mate, intermesh, and slidingly engage; and external splines 152a of hub 152 and internal splines 153b of lock ring 153 are sized and configured to mate, intermesh, and slidingly engage. Lock ring 153 is slidingly mounted to hub 152 with mating splines 152a, 153b intermeshing, and thus, lock ring 153 can move axially along hub 152 but engagement of splines 152a, 153b prevents lock ring 153 from rotating relative to hub 152. As previously described, actuating system 154 moves lock ring 153 along hub 152 into and out of spool ring 151. More specifically, as best shown in FIG. 12, when lock ring 153 is positioned outside of spool ring 151, splines 151a, 153a are axially spaced apart and drum 142 is free to rotate relative to lock ring 153, hub 152, and adapter 40. However, as best shown in FIG. 13, when lock ring 153 is positioned inside spool ring 151, mating splines 151a, 153a intermesh, thereby preventing drum 142 from rotate relative to lock ring 153. Since engagement of splines 152a, 153b prevents lock ring 153 from rotating relative to hub 152, the engagement of splines 151a, 153a also prevents drum 142 from rotating relative to hub 152 and adapter 40. Accordingly, locking mechanism 150 and lock ring 153 may be described as having an “unlocked” position (FIG. 12) with lock ring 153 positioned outside of spool ring 151, thereby allowing drum 142 to rotate freely relative to lock ring 153, hub 152, and adapter 40; and a “locked” position (FIG. 13) with lock ring 153 positioned inside of spool ring 151, thereby preventing drum 142 from rotating relative to lock ring 153, hub 152, and adapter 40.

Referring now to FIG. 7, mating splines 152a, 153b have greater circumferential widths than mating splines 151a, 153a. Without being limited by this or any particular theory, the greater the circumferential width of a spline, the greater the torque that can be transferred by that spline. Thus, splines 152a, 153b having a relatively large circumferential widths can transfer relatively large torques. Splines 151a, 153b have relatively smaller circumferential widths, but enable enhanced mating resolution. In particular, the relatively smaller splines 151a, 153b enable alignment of splines 151a, 153b, as is necessary for insertion of lock ring 153 into spool ring 151, via rotation of spool ring 151 relative to lock ring 153 through a relatively small angle. This enables relatively fine adjustment of the tensile preload L applied to tension member 160.

Referring now to FIGS. 6 and 7, actuation system 154 transitions lock ring 153 and locking mechanism 150 between the locked and unlocked positions. In this embodiment, actuation system 154 includes a plurality of double-acting linear actuators 155 coupled to lock ring 153. Actuators 155 are uniformly circumferentially-spaced about axis 145. In addition, each actuator 155 is the same, and thus, one actuator 155 will be described it being understood the other actuators 155 are the same. As best shown in FIG. 6, in this embodiment, each actuator 155 is an ROV operated hydraulic piston-cylinder assembly including a cylinder 156 disposed in block 147, a piston 157 slidably disposed in cylinder 156, an extension rod 158 coupling piston 157 to lock ring 153, and a biasing member 159 disposed in cylinder 156.

Piston 157 divides cylinder 156 into two chambers 156a, 156b. Chamber 156a is vented to the external environment. Biasing member 159 biases piston 157 toward spool ring 151 (to the right in FIG. 6), thereby biasing lock ring 153 and locking mechanism 150 to the locked position. However, by applying sufficient hydraulic pressure to chamber 156b, the biasing force of biasing member 159 is overcome and piston 156 is moved away from spool ring 151 (to the left in FIG. 6), thereby transitioning lock ring 153 and locking mechanism 150 to the unlocked position. In this embodiment, biasing member 159 is a coil spring.

Although winches 140 are coupled to anchors 110 in this embodiment, in other embodiments, the tensioning systems (e.g., winches 140) are coupled to the wellhead adapter (e.g., adapter 180) and an end of each tension member (e.g., end 160a of each tension member 160) is coupled to the anchor (e.g., anchor 110). The arrangement with winches 140 coupled to anchors 110 is generally preferred as it generally requires less interaction with wellhead 50 and BOP 41, resulting in a lower likelihood of interference with wellhead 50, BOP 41, and subsea operations.

Referring again to FIGS. 1 and 3, adapter 180 provides a means for coupling tension members 160 to wellhead 50, thereby enabling tension members 160 to apply lateral loads to wellhead 50. As best shown in FIG. 3, in this embodiment, adapter 180 is a spider frame including a central annular hub 181, a plurality of uniformly circumferentially-spaced locking devices 182 coupled to hub 181, and a plurality of uniformly circumferentially-spaced rigid arms 186 extending radially outward from hub 181. Each arm 186 has a first or radially inner end 186a integral with hub 181 and a second or radially outer end 186b distal hub 181. Each end 186b comprises a pad eye 183 for coupling a tension member 160 thereto. In this embodiment, each arm 186 has the same length measured radially from hub 181 to end 186b.

Locking devices 182 are uniformly distributed about hub 181. In this embodiment, one locking device 182 is positioned between each pair of circumferentially adjacent arms 186. Locking devices 182 are configured to releasably engage wellhead 50 to fix the axial position of adapter 180 along wellhead 50. In particular, each locking device 182 has a first or unlocked position allowing adapter 180 to slidingly engage and move along wellhead 50, and a second or locked position axially fixing adapter 180 to wellhead 50. In general, locking devices 182 can include any locking means known in the art suitable for subsea use. In this embodiment, locking devices 182 are substantially the same as locking rams 130 previously described. Namely, each locking device 182 includes a double-acting linear actuator (e.g., actuator 131) mounted to hub 181 and a gripping member or ram block (e.g., ram block 132) coupled to the actuator. In this embodiment, the double-acting linear actuators are ROV operated hydraulic piston-cylinder assemblies.

Referring now to FIGS. 1 and 3, each tension member 160 has a first or distal end 160a coupled to one pad eye 183 with a shackle assembly 184, and a tensioned span or portion 161 extending from the corresponding winch 140 to end 160a. As best shown in FIG. 1, each distal end 160a is coupled to adapter 180 at a height H measured vertically from the sea floor 12. In this embodiment, adapter 180 is level (horizontally oriented), and thus, the vertical height of each pad eye 183 from the sea floor 12 is the same and each height H is the same. The height H depends, at least in part, on the location along the wellhead 50 at which adapter 180 is secured. Adapter 180 is preferably disposed along a relatively smooth cylindrical portion of wellhead 50 such that locking devices 182 can securely engage and grip wellhead 50. The location of such cylindrical portion along wellhead 50 thereby effectively defines the height H.

A tensile preload L is applied to each portion 161 by the corresponding winch 140. The tensile preload L in each tension member 160 results in a lateral or horizontal preload L_lapplied to adapter 180 and wellhead 50 by each tension member 160. Portions 161 are horizontal or substantially horizontal, and thus, there is little to no vertical preload applied to adapter 180 and wellhead 50 by the tension members 160. Thus, the lateral preload L_lis the same or substantially the same as the tensile preload L. In this embodiment, the tensile preload L in each tension member 160 is the same, and thus, the lateral preload L_lapplied to wellhead 50 by each tension member 160 is the same. With no external loads or moments applied to wellhead 50, the actual tension in portion 161 of each tension member 160 is the same or substantially the same as the corresponding tensile preload L and associated lateral preload L_l. However, it should be appreciated that when external loads and/or bending moments are applied to wellhead 50, the actual tension in each portion 161 can be greater than or less than the corresponding tensile preload L and associated lateral preload L_l. The lateral loads applied to wellhead 50 (e.g., lateral preloads L_l) resist external lateral preloads and bending moments applied to wellhead 50 (e.g., from subsea currents, riser 115, etc.). As a result, embodiments of tethering system 100 described herein offer the potential to improve the fatigue resistance of wellhead 50 and primary conductor 51.

Referring still to FIGS. 1 and 2, the tensile preload L in each tension member 160 is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding portion 161. In other words, the tensile preload L in each portion 161 is preferably the lowest tension that results in the corresponding portion 161 extending linearly from the corresponding winch 140 to its end 160a. It should be appreciated that such tensile preloads in portions 161 restrict and/or prevent the initial movement and flexing of wellhead 50 at the onset of the application of external loads and/or bending moments, while minimizing the tension in portions 161 before and after the application of external loads and/or bending moments. The latter consequence minimizes the potential risk of damage to wellhead 50, BOP 41, tree 40, and LMRP 42 in the event one or more tension members 160 uncontrollably break.

As best shown in FIG. 3 and previously described, each end 160a is pivotally coupled to one arm 186 with a shackle assembly 184. In this embodiment, each shackle assembly 184 includes a load cell or pin 185 that continuously measures the tension in the corresponding portion 161. The measured tensions are communicated to the surface in near real time (or on a period basis). In general, the measured tensions can be communicated by any means known in the art including, without limitation, wired communications and wireless communications (e.g., acoustic telemetry). In this embodiment, the tensions measured by load cells 185 are communicated acoustically to the surface by a preexisting acoustic communication system housed on BOP 41. Communication of the measured tension in each portion 161 to the surface enables operators and other personnel at the surface (or other remote location) to monitor the tensions, quantify the external loads on BOP 41, and identify any broken tension member(s) 160.

In general, each tension member 160 can include any elongate flexible member suitable for subsea use and capable of withstanding the anticipated tensile loads (i.e., pretension load L as well as the actual tensile loads resulting from external loads to BOP 41) without deforming or elongating. Examples of suitable devices for tensile members 160 included, without limitation, chain(s), wire rope, and Dyneema® rope available from DSM Dyneema LLC of Stanley, N.C. USA. In this embodiment, each tension member 160 comprises Dyneema® rope, which requires the lowest tension to pull out any slack, curve, and catenary (˜1.0 ton of tension), is sufficiently strong to withstand the anticipated tensions, and is suitable for subsea use.

Referring now to FIGS. 1, 3, 8, and 9, the tensile preload L is applied to tension member 160 by transitioning lock ring 153 and locking mechanism 150 to the unlocked position via operation of actuation system 154 with a subsea ROV, and then rotating spool 141 about axis 145 with an ROV operated torque tool engaging interface 148 to pay in tension member 160. The tension member 160 and/or tension measured with the corresponding load pin 173 can be monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tension member 160 is removed). Once the desired tensile preload L is achieved, locking mechanism 150 and lock ring 153 are allowed to transitioned back to the locked position via biasing members 159. Winch 140, and more specifically locking mechanism 150, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member 160 when locking mechanism 150 is locked and external loads are applied to BOP 41.

Referring now to FIG. 10, an embodiment of a method 190 for deploying and installing tethering system 100 is shown. For subsea deployment and installation of tethering system 100, one or more remote operated vehicles (ROVs) are preferably employed to aid in monitoring and positioning piles 110, coupling pile top assemblies 120 to upper ends 110a of piles 110, coupling tension members 160 to adapter 180, and operating subsea hardware (e.g., winches 140, actuation systems 154, locking devices 182, locking mechanisms 150, locking rams 130, etc.). 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. 10, in block 191, adapter 180 is deployed subsea from a surface vessel such as vessel 110 or a separate construction vessel. In general, adapter 180 can be lowered subsea by any suitable means such as wireline. Adapter 180 is lowered subsea and positioned over wellhead 50. In particular, hub 181 is positioned immediately above wellhead 50 and coaxially aligned with wellhead 50. Next, with locking devices 182 in the unlocked positions, adapter 180 is lowered to allow wellhead 50 to stab into hub 181. Adapter 180 is then positioned at the desired height H (e.g., aligned with the cylindrical outer surface of wellhead 50), leveled, and then locking devices 182 are actuated to lock adapter 180 to wellhead 50 at the height H. Since wellhead 50 is stabbed into hub 181 of adapter 180 in this embodiment, adapter 180 is installed prior to coupling tree 40, BOP 41, or LMRP 42 to wellhead 50.

Moving now to block 192, piles 110 are deployed subsea and installed subsea. In particular, piles 110 are lowered subsea from a surface vessel such as vessel 30 or a separate construction vessel. In general, piles 110 can be lowered subsea by any suitable means such as wireline. Next, piles 110 are installed (i.e., secured to the sea floor 12). To install piles 110, each pile 110 is vertically oriented and positioned immediately above the desired installation location in the sea floor 12 (i.e., at the desired circumferential position about wellhead 50 and at the desired radial distance R₁₁₀). Then, each pile 110 is advanced into the sea floor 12 (driven or via suction depending on the type of pile 110) until upper end 110a is disposed at the desired height above the sea floor 12. In general, piles 110 can be installed one at a time, or two or more at the same time.

Referring still to FIG. 10, in block 193, pile top assemblies 120 are deployed subsea and coupled to upper ends 110a of piles 110. In particular, assemblies 120 are lowered subsea from a surface vessel such as vessel 30 or a separate construction vessel. In general, assemblies 120 can be lowered subsea by any suitable means such as wireline. Next, assemblies 120 are lowered onto to ends 110a of piles 110 and locked thereon as previously described. Assemblies 120 are preferably mounted to piles 110 with each guide 125 aligned with the corresponding arm 186 of adapter 180. In general, assemblies 120 can be installed one at a time, or two or more at the same time.

Next, in block 194, locking mechanisms 150 are transitioned to the unlocked positions and tension members 160 are paid out from winches 140. In addition, ends 160a are coupled to pad eye 183 of the corresponding arm 186 via a shackle assembly 184. In general, shackle assemblies 184 can be deployed and installed at any time prior to block 183. Moving now to block 195, tensile preloads L are applied to tension members 160 as previously described. Namely, the tensile preload L is applied to each tension member 160 by unlocking mechanism 150, and then rotating spool 141 with an ROV operated torque tool engaging interface 148 to pay in tension member 160. The tension member 160 and/or tension measured with the corresponding load cell 185 is monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tensioned span 161 of tension member 160 is removed). Once the desired tensile preload L is achieved, locking mechanism 150 is transitioned to and maintained in the locked position.

In the manner described, tethering system 100 is deployed and installed. Once installed and tensile preloads L are applied, tethering system 100 reinforces and/or stabilizes wellhead 50 and conductor 51 by restricting the lateral/radial movement of wellhead 50. As a result, embodiments of tethering system 100 described herein offer the potential to reduce the stresses induced in wellhead 50 and primary conductor 51, improve the strength and fatigue resistance of wellhead 50 and primary conductor 51, and improve the bending moment response along primary conductor 51 below the sea floor 12.

Referring now to FIGS. 11 and 12, another embodiment of a tethering system 200 for reinforcing wellhead 50 and primary conductor 51 of system 10 is shown. Similar to tethering system 100 previously described, in this embodiment, tethering system 200 reinforces wellhead 50 and primary conductor 51 by resisting lateral loads and bending moments applied thereto. As a result, system 200 offers the potential to enhance the strength and fatigue resistance of wellhead 50 and conductor 51. In FIG. 11, system 10 is shown configured for completion operations, and thus, includes tree 40, however, for drilling operations tree 40 may not be included.

Referring now to FIGS. 11-14, in this embodiment, tethering system 200 includes a plurality of anchors 110, a plurality of pile top assemblies 212 mounted to anchors 110, a plurality of tensioning systems 220 releasably coupled to pile top assemblies 212, an adapter 180 mounted to wellhead 50, and a plurality of flexible tension members 240. Anchors 110 and adapter 180 are each as previously described. In this embodiment, tensioning systems 220 are winches, and thus, may also be referred to as winches 220. One winch 220 is coupled to each anchor 110, and one tension member 240 is wound to each winch 220 such that each flexible tension member 240 can be paid in and paid out from the corresponding winch 220. Tension members 240 extend from winches 220 and are coupled to adapter 180.

Anchors 110 are circumferentially spaced about wellhead 50 and secured to the sea floor 12. In addition, each anchor 210 is disposed at a distance R₁₁₀measured radially (center-to-center) from wellhead 50. As previously described, the circumferential positions of anchors 110 and the radial distances R₁₁₀are generally selected to avoid unduly interfering with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, and workover operations); (c) wellhead 50, primary conductor 131, tree 40, BOP 41, and LMRP 42; (d) subsea remotely operated vehicle (ROV) operations and access to tree 40, BOP 41, and LMRP 42; and (e) neighboring wells. As will be described in more detail below, lateral preloads are applied to wellhead 50 by tension members 240. To balance and uniformly distribute such lateral preloads applied to wellhead 50, anchors 110 are uniformly circumferentially-spaced about wellhead 50 and each radial distance R₁₁₀is the same. In this embodiment, four anchors 110 are uniformly circumferentially-spaced about wellhead 50. However, in general, three or more uniformly circumferentially-spaced anchors 110 are preferably provided. For most subsea applications, each radial distances R₁₁₀are between 15 and 60 ft. However, radial distances R₁₁₀outside this range can also be employed.

Referring now to FIGS. 13 and 15, one pile top assembly 212 is mounted to upper end 110a of each pile 110. As best shown in FIG. 15, each pile top assembly 212 includes a cap 213 fixably secured to the upper end 110a of pile 110 and an anchor adapter 216 releasably coupled to cap 213. Cap 213 and adapter 216 are coaxially aligned with axis 115. Cap 213 has a first or upper end 213a including a receptacle 214a and a second or lower end 213b including a receptacle 214b. The upper end 110a of pile 110 is seated in receptacle 214b and fixably secured to cap 213.

Referring still to FIGS. 13 and 15, adapter 216 has a first or upper end 216a and a second or lower end 216b. In addition, adapter 216 includes a generally annular connection body 218 at upper end 216a and an elongate pin or stabbing member 219 extending axially from body 218 to end 216b. Pin 219 is received by receptacle 214a and releasably locked therein, thereby releasably connecting adapter 216 to cap 213 and pile 211. In general, any locking mechanism known in the art can be employed to releasably lock pin 219 in the mating receptacle 214a.

Connection body 218 has a planar upward facing surface 218a and a plurality of uniformly circumferentially-spaced receptacles 218b disposed proximal the perimeter of surface 218a and extending downward from surface 218a. As best shown in FIG. 16, each receptacle 218b is sized and configured to receive a mating pin or stabbing member 225 provided on each winch 220. By including multiple receptacles 218b in body 218, the position of one or more winches 220 coupled thereto can be varied as desired. With pin 225 of the corresponding winch 220 sufficiently seated in the desired receptacle 218b, it is releasably locked therein. In general, any locking mechanism known in the art can be employed to releasably lock pin 225 in a given receptacle 218b. In this embodiment, the locking mechanism is a set screw or bolt that is threaded into engagement with a mating annular recess on the outer surface of pin 225, thereby preventing winch 220 from moving axially relative to body 218, but allows winch 220 to rotate about the central axis of pin 225 relative to body 218.

Since each winch 220 is releasably coupled to the corresponding adapter 216 via receptacle 218b, and each adapter 216 is releasably coupled to the corresponding cap 213 and pile 211 via receptacle 214a, winches 220 and adapters 216 can be retrieved to the surface, moved between different subsea piles 211, and reused. Although winches 220 are configured to stab into adapters 216, and adapters 216 are configured to stab into caps 213 in this embodiment, in other embodiments, the adapters (e.g., adapters 216) can stab into the winches (e.g., winches 220) and/or the cap (e.g., cap 213) can stab into the adapter.

Referring now to FIGS. 16 and 17, one tensioning system 220 is shown, it being understood that each tensioning system 220 is the same. As previously described, in this embodiment, each tensioning system 220 is a winch. Each winch 220 includes a base or housing 221, a spool 222 disposed within and rotatably coupled to housing 221, and a locking mechanism or brake 224 coupled to spool 222 and housing 221. Pin 225 extends downward from housing 221. Spool 222 is rotated relative to housing 221 to pay in and pay out tension member 240. In this embodiment, the portion of tension member 240 extending through winch 220 is chain, and thus, spool 222 is a chain wheel.

Locking mechanism 224 releasably locks spool 222 relative to housing 221. In this embodiment, locking mechanism 224 is a ratchet including a ratchet wheel or gear 225 fixably attached to the shaft of spool 222 and a pawl 226 pivotally coupled to housing 221 adjacent wheel 225. Pawl 226 pivots about a horizontal axis 227 into and out of engagement with the teeth of gear 225. Accordingly, when pawl 226 is pivoted away from gear 225, spool 222 is free to rotate in either direction, and thus, tension member 240 can be paid in or paid out from winch 220. However, when pawl 226 is pivoted into engagement with the teeth of gear 225, spool 222 can rotate in one direction to pay in tension member 240, but is prevented from rotating in the other direction to pay out tension member 240. Accordingly, locking mechanism 224 and pawl 226 may be described as having a “locked” position with pawl 226 pivoted into engagement with gear 225, thereby preventing tension member 240 from being paid out from winch 220; and an “unlocked” position with pawl 226 pivoted away from gear 225, thereby allowing tension member 240 to be paid in and paid out from winch 220. In this embodiment, locking mechanism 224 and pawl 226 are biased to the locked position via gravity. However, in other embodiments, a biasing member such as a spring can be employed to bias locking mechanism 224 and pawl 226 to the locked position.

Referring again to FIGS. 13 and 14, adapter 180 provides a means for coupling tension members 240 to wellhead 50, thereby enabling tension members 240 to apply lateral loads to wellhead 50. Each tension member 240 has a first or distal end 240a coupled to one pad eye 183 of adapter 180 with a shackle assembly 184, and a portion 241 extending from the corresponding winch 220 to end 240a. As best shown in FIG. 11, each distal end 240a is coupled to adapter 180 at a height H measured vertically from the sea floor 12. In this embodiment, adapter 180 is level (relative to horizontal), and thus, the vertical height of each pad eye 183 from the sea floor 12 is the same and each height H is the same. The height H depends, at least in part, on the location along the wellhead 50 at which adapter 180 is secured. As previously described, adapter 180 is preferably disposed along a relatively smooth cylindrical portion of wellhead 50 such that locking devices 182 can securely engage and grip wellhead 50. The location of such cylindrical portion along wellhead 50 thereby effectively defines the height H.

A tensile preload L is applied to portion 241 of each tension member 240 with the corresponding winch 220. The tensile preload L in each tension member 240 results in a lateral or horizontal preload L_lapplied to adapter 180 and wellhead 50 by each tension member 240. Portions 241 are horizontal or substantially horizontal, and thus, there is little to no vertical preload applied to adapter 180 and wellhead 50 by the tension members 240. In this embodiment, the tensile preload L in each tension member 240 is the same or substantially the same, and thus, the lateral preload L_lapplied to wellhead 50 by each tension member 240 is the same or substantially the same. With no external loads or moments applied to wellhead 50, the actual tension in portion 241 of each tension member 240 is the same or substantially the same as the corresponding tensile preload. However, it should be appreciated that when external loads and/or bending moments are applied to wellhead 50, the actual tension in each portion 241 can be greater than or less than the corresponding tensile preload. The lateral loads applied to wellhead 50 (e.g., lateral preloads L_l) resist external lateral preloads and bending moments applied to wellhead 50 (e.g., from subsea currents, riser 115, etc.). As a result, embodiments of tethering system 200 described herein offer the potential to improve the fatigue resistance of wellhead 50 and primary conductor 131.

Referring still to FIG. 11, the tensile preload in each tension member 240 is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding portion 241. In other words, the tensile preload in each portion 241 is preferably the lowest tension that results in the corresponding portion 241 extending linearly from the corresponding winch 220 to its end 240a. It should be appreciated that such tensile preloads in portions 241 restrict and/or prevent the initial movement and flexing of wellhead 50 at the onset of the application of external loads and/or bending moments, while minimizing the tension in portions 241 before and after the application of external loads and/or bending moments. The latter consequence minimizes the potential risk of damage to wellhead 50, BOP 41, tree 40, and LMRP 42 in the event one or more tension members 240 uncontrollably break.

In general, each tension member 240 can include any elongate flexible member suitable for subsea use and capable of withstanding the anticipated tensile loads (i.e., pretension load L as well as the actual tensile loads resulting from external loads to BOP 41) without deforming or elongating. Examples of suitable devices for tensile members 240 included, without limitation, chain(s), wire rope, and Dyneema® rope available from DSM Dyneema LLC of Stanley, N.C. USA. In this embodiment, each tension member 240 comprises chain (coupled to the corresponding winch 220) and Dyneema® rope extending from the chain to end 240a. Dyneema® rope requires a relatively low tension is to pull out any slack, curve, and catenary (˜1.0 ton of tension), is sufficiently strong to withstand the anticipated tensions, and is suitable for subsea use.

As best shown in FIGS. 13 and 14 and previously described, each end 240a is pivotally coupled to one arm 186 with a shackle assembly 184. In this embodiment, each shackle assembly 184 includes a load cell 185 that continuously measures the tension in the corresponding portion 241. The measured tensions are communicated to the surface in near real time (or on a period basis). In general, the measured tensions can be communicated by any means known in the art including, without limitation, wired communications and wireless communications (e.g., acoustic telemetry). In this embodiment, the tensions measured by load cells 185 are communicated acoustically to the surface by a preexisting acoustic communication system housed on BOP 41. Communication of the measured tension in each portion 241 to the surface enables operators and other personnel at the surface (or other remote location) to monitor the tensions, quantify the external loads on BOP 41, and identify any broken tension member(s) 240.

Referring now to FIGS. 11 and 13, in this embodiment, the tensile preload is applied to each tension member 240 by unlocking the locking mechanism 224, and then rotating spool 222 to pay in tension member 240 and pull portion 241. In this embodiment, spools 222 are rotated with an ROV torque tool that is coupled to spool 222. However, in other embodiments, the spools (e.g., spools 222) can be rotated by any suitable means such as a subsea buoy coupled to the end of tension member 240 opposite end 240a, etc. The tension member 240 and/or tension measured with the corresponding load cell 185 can be monitored until the desired tensile preload is applied (i.e., the slack, curve, and catenary in tension member 240 is removed). Once the desired tensile preload is achieved, locking mechanism 224 is transitioned to and maintained in the locked position. Tensioning system 220, and more specifically locking mechanism 224, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member 240 when locking mechanism 224 is locked and external loads are applied to wellhead 50.

Referring now to FIG. 18, an embodiment of a method 290 for deploying and installing tethering system 200 is shown. For subsea deployment and installation of tethering system 200, one or more remote operated vehicles (ROVs) are preferably employed to aid in monitoring and positioning piles 110, coupling adapters 216 to caps 213 disposed at the upper ends of piles 110, coupling winches 220 to adapters 216, coupling tension members 240 to adapter 180, and operating subsea hardware (e.g., winches 220, locking devices 182, locking mechanisms 224, etc.). 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. 18, in block 291, adapter 180 is deployed subsea from a surface vessel such as vessel 110 or a separate construction vessel. In general, adapter 180 can be lowered subsea by any suitable means such as wireline. Adapter 180 is lowered subsea and positioned over wellhead 50. In particular, hub 181 is positioned immediately above wellhead 50 and coaxially aligned with wellhead 50. Next, with locking devices 182 in the unlocked positions, adapter 180 is lowered to allow wellhead 50 to stab into hub 181. Adapter 180 is then positioned at the desired height H (e.g., aligned with the cylindrical outer surface of wellhead 50), leveled, and then locking devices 182 are actuated to lock adapter 180 to wellhead 50 at the height H. Since wellhead 50 is stabbed into hub 181 of adapter 180 in this embodiment, adapter 180 is installed prior to coupling tree 40, BOP 41, or LMRP 42 to wellhead 50.

Moving now to block 292, piles 110 are deployed subsea with caps 213 mounted thereto. In particular, piles 110 are lowered subsea from a surface vessel such as vessel 30 or a separate construction vessel. In general, piles 110 can be lowered subsea by any suitable means such as wireline. Next, piles 110 are installed (i.e., secured to the sea floor 12). To install piles 110, each pile 110 is vertically oriented and positioned immediately above the desired installation location in the sea floor 12 (i.e., at the desired circumferential position about wellhead 50 and at the desired radial distance R₁₁₀). Then, each pile 110 is advanced into the sea floor 12 (driven or via suction depending on the type of pile 110) until cap 213 is disposed at the desired height above the sea floor 12. In general, piles 110 can be installed one at a time, or two or more at the same time.

Moving now to block 293, adapters 216 are deployed subsea and coupled to caps 213. In particular, adapters 216 are lowered subsea from a surface vessel such as vessel 30 or a separate construction vessel. In general, adapters 216 can be lowered subsea by any suitable means such as wireline. Next, adapters 216 are coupled to caps 213 and piles 110 by aligning each pin 219 with the corresponding receptacle 214a, lowering adapters 216 to seat pins 219 in receptacles 214, and then releasably locking pins 219 within receptacles 214, thereby forming anchors 110. In general, adapters 216 can be installed one at a time, or two or more at the same time.

With anchors 110 secured to the sea floor 12, winches 220 are deployed subsea and coupled to adapters 216 in block 315. In particular, winches 220 are lowered subsea from a surface vessel such as vessel 30 or a separate construction vessel. In general, winches 220 can be lowered subsea by any suitable means such as wireline. Winches 220 are preferably deployed subsea with tension members 240 coupled thereto. Next, winches 220 are coupled to adapters 216 by aligning pin 225 of each winch 220 with the corresponding receptacle 215b, lowering winches 220 to seat pins 225 in receptacles 218b, and then releasably locking pins 225 within receptacles 218b. In general, winches 220 can be installed one at a time, or two or more at the same time.

Next, in block 295, tension members 240 are paid out from winches 220 with locking mechanisms 224 in the unlocked positions, and ends 240a are coupled to adapter 180. In this embodiment, ends 240a are coupled to adapter 180 via shackle assemblies 181 and pad eyes 183 as previously described. Moving now to block 296, tensile preloads L are applied to tension members 240 to induce lateral preloads L_l. Namely, the tensile preload is applied to each tension member 240 by unlocking the locking mechanism 224, and then rotating the spool 222 to pay in the tension member 224. The tension member 240 and/or tension measured with the corresponding load cells 185 are monitored until the desired tensile preload is applied (i.e., the slack, curve, and catenary in tension member 240 is removed). Once the desired tensile preload in each tension member 240 is achieved, its locking mechanism 224 is transitioned to and maintained in the locked position.

In the manner described, tethering system 200 is deployed and installed on wellhead 50. In particular, tethering system 200 reinforces wellhead 50 by restricting the lateral/radial movement of wellhead 50. As a result, embodiments of bracing system 200 described herein offer the potential to reduce the stresses induced in wellhead 50 and primary conductor 131, improve the fatigue resistance of wellhead 50 and primary conductor 131, and improve the bending moment response along primary conductor 131 below the sea floor 12.

Referring now to FIGS. 19-21, system 10, and in particular, primary conductor 51, wellhead 50, BOP 41, and LMRP 42 were modeled and simulations were run with and without tethering system 200 to assess the impact of tethering system 200. FIGS. 19-21 graphically illustrate the results of those simulations with and without tethering system 200. In FIG. 19, the bending moments induced along LMRP 42, BOP 41, wellhead 50, and conductor 51 due to a static offset of surface vessel 30 are shown as a function of the elevation relative to the sea floor 12 (i.e., mudline); in FIG. 20, the bending moments induced along LMRP 42, BOP 41, wellhead 50, and conductor 51 due to a wave are shown as a function of the elevation relative to the sea floor 12 (i.e., mudline); and in FIG. 21, the fatigue life along LMRP 42, BOP 41, wellhead 50, and conductor 51 is shown as a function of the elevation relative to the sea floor 12 (i.e., mudline).

In the manners described, embodiments of tethering systems 100, 200 described herein apply lateral preloads L_lto subsea wellheads (e.g., wellhead 50). The lateral preloads L_lapplied to a given wellhead are preferably substantially the same and uniformly distributed about the wellhead and uniformly applied (i.e., the lateral preloads L_lapplied to a given wellhead are preferably balanced). Accordingly, the lateral preloads L_lgenerally seek to maintain the subsea architecture in a generally vertical orientation, reinforce the wellhead (e.g., wellhead 50) and the conductor (e.g., conductor 51) by restricting the lateral/radial movement of the wellhead. As a result, embodiments of tethering systems 100, 200 described herein offer the potential to reduce the stresses induced in the wellhead and the primary conductor, improve the strength and fatigue resistance of the wellhead, and the primary conductor, and improve the bending moment response along the primary conductor below the sea floor 12.

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.

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

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CROSS-REFERENCE TO RELATED APPLICATIONS

Provisional Applications (1)