Patent Description:
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 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 the 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. <CIT> discloses a system and method of establishing an offshore exploration and production system in which a well casing is disposed in communication with an adjustable buoyancy chamber and a well hole bored into the floor of a body of water. A lower connecting member joins the well casing and the chamber, and an upper connecting member joins the adjustable buoyancy chamber and a well terminal member. "<NPL>), discloses a mooring-assisted BOP for improving subsea wellhead fatigue life.

The present invention relates to a system for drilling, completing or producing a subsea well, as defined in the appended claims.

Reference will now be made to the accompanying drawings in which:.

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

As best shown in <FIG>, vessel <NUM> is equipped with a derrick <NUM> that supports a hoist (not shown). Vessel <NUM> is a semi-submersible offshore platform, however, in general, the vessel (e.g., vessel <NUM>) 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 <NUM> (not shown in <FIG>) extends subsea from vessel <NUM> to LMRP <NUM>. During drilling operations, riser <NUM> takes mud returns to vessel <NUM>. 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 <NUM> and extends from vessel <NUM> through riser <NUM>, LMRP <NUM>, and BOP <NUM>, and tree <NUM> into wellbore <NUM>. BOP <NUM> includes an outer rectangular prismatic frame <NUM>.

BOP <NUM> and LMRP <NUM> are configured to controllably seal wellbore <NUM> and contain hydrocarbon fluids therein. Specifically, BOP <NUM> includes a plurality of axially stacked sets of opposed rams disposed within frame <NUM>. In general, BOP <NUM> 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 <NUM> from riser <NUM>, opposed blind rams for sealing off wellbore <NUM> when no string/tubular extends through BOP <NUM>, opposed pipe rams for engaging the string/tubular and sealing the annulus around string/tubular, or combinations thereof. LMRP <NUM> 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 <NUM> or seal off wellbore when no string/tubular extends through LMRP <NUM>. The upper end of LMRP <NUM> includes a riser flex joint <NUM> that allows riser <NUM> to deflect and pivot angularly relative to tree <NUM>, BOP <NUM>, and LMRP <NUM> 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 <NUM>, wellhead <NUM>, and primary conductor <NUM> extending from wellhead <NUM> into the sea floor <NUM>. Such cyclical loads can induce fatigue. This may be of particular concern with subsea horizontal production tree architectures (e.g., system <NUM>) 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, the hardware mounted to wellhead <NUM> proximal the sea floor <NUM>, production tree <NUM> and BOP <NUM> 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 <NUM>, wellhead <NUM>, and primary conductor <NUM>. If the wellhead <NUM> and primary conductor <NUM> do not have sufficient fatigue resistance, the integrity of the subsea well may be compromised. Still further, an uncontrolled lateral movement of vessel <NUM> (e.g., an uncontrolled drive off or drift off of vessel <NUM>) from the desired operating location generally over wellhead <NUM> can pull LMRP <NUM> laterally with riser <NUM>, thereby inducing bending moments and associated stresses in BOP <NUM>, wellhead <NUM>, and conductor <NUM>. Such induced bending moments and stresses can be increased further when the relatively tall and heavy combination of tree <NUM> and BOP <NUM> is in a slight angle relative to vertical. Accordingly, a tethering system <NUM> is provided to reinforce BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> by resisting lateral loads and bending moments applied thereto. As a result, system <NUM> offers the potential to enhance the strength and fatigue resistance of BOP <NUM>, wellhead <NUM>, and conductor <NUM>.

Referring again to <FIG> and <FIG>, tethering system <NUM> includes a plurality of anchors <NUM>, a plurality of pile top assemblies <NUM>, and a plurality of flexible tension members <NUM>. One pile top assembly <NUM> is mounted to the upper end of each anchor <NUM>, and one tension member <NUM> extends from each pile top assembly <NUM> to frame <NUM> of BOP <NUM>. As will be described in more detail below, each pile top assembly <NUM> includes a tensioning system <NUM> that can apply tensile loads to the corresponding tension member <NUM>. Each tensioning system <NUM> is a winch, and thus, may also be referred to as winch <NUM>. Each winch <NUM> can pay in and pay out the corresponding tensioning member <NUM>.

Each tension member <NUM> includes a first or distal end 160a coupled to frame <NUM> of BOP <NUM>, and a tensioned span or portion <NUM> extending from the corresponding winch <NUM> to end 160a. As best shown in <FIG> , each distal end 160a is coupled to frame <NUM> of BOP <NUM> at a height H measured vertically from the sea floor <NUM> and at a lateral distance D measured radially and horizontally from central axis <NUM>. Four uniformly circumferentially-spaced anchors <NUM> and associated tension members <NUM> are provided. In addition, height H of each end 160a is the same, lateral distances D to each end 160a is the same. For most subsea applications, lateral distance D is preferably between <NUM> and <NUM> ft, and more preferably about <NUM> ft. However, it should be appreciated that lateral distance D may depend, at least in part, on the available connection points to the frame <NUM> of BOP <NUM>. As will be described in more detail below, each height H is preferably as high as possible but below LMRP <NUM>, and may depend on the available connection points along frame <NUM> of BOP <NUM>.

As best shown in <FIG>, a tensile preload L is applied to each tensioned span <NUM>. With no external loads or moments applied to BOP <NUM>, the actual tension in each span <NUM> is the same or substantially the same as the corresponding tensile preload L. However, it should be appreciated that when external loads and/or bending moments are applied to BOP <NUM>, the actual tension in each span <NUM> can be greater than or less than the corresponding tensile preload L.

Winches <NUM> are positioned proximal to the sea floor <NUM>, and ends 160a are coupled to frame <NUM> of BOP <NUM> above winches <NUM>. Thus, each span <NUM> is oriented at an acute angle α measured upward from horizontal. Since portions <NUM> are in tension and oriented at acute angles α, the tensile preload L applied to frame <NUM> of BOP <NUM> by each span <NUM> includes an outwardly oriented horizontal or lateral preload L<NUM> and a downwardly oriented vertical preload Lv. Without being limited by this or any particular theory, the lateral preload L<NUM> and the vertical preload Lv applied to BOP <NUM> by each tension member <NUM> are a function of the corresponding tensile load L and the angle α. For a given angle α, the lateral preload L<NUM> and the vertical preload Lv increase as the tensile load L increases, and decrease as the tensile load L decreases. For a given tensile load L, the lateral preload L<NUM> decreases and the vertical preload Lv increases as angle α increases, and the lateral preload L<NUM> increases and the vertical preload Lv decreases as angle α decreases. For example, at an angle α of <NUM>°, the lateral preload L<NUM> and the vertical preload Lv are substantially the same; at an angle α above <NUM>°, the lateral preload L<NUM> is less than the vertical preload Lv; and at an angle α below <NUM>°, the lateral preload L<NUM> is greater than the vertical preload Lv. Angle α of each span <NUM> is preferably between <NUM>° and <NUM>°, and more preferably between <NUM>° and <NUM>°.

The lateral preloads L<NUM> applied to frame <NUM> of BOP <NUM> resist external lateral loads and bending moments applied to BOP <NUM> (e.g., from subsea currents, riser <NUM>, etc.). To reinforce and stabilize BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> without interfering with an emergency disconnection of LMRP <NUM>, each height H is preferably as high as possible but below LMRP <NUM>, and may depend on the available connection points along frame <NUM> of BOP <NUM>. Ends 160a are coupled to frame <NUM> proximal the upper end of BOP <NUM> and just below LMRP <NUM>. By tethering frame <NUM> of BOP <NUM> at this location, system <NUM> restricts and/or prevents BOP <NUM>, tree <NUM>, wellhead <NUM>, and primary conductor <NUM> from moving and bending laterally, thereby stabilizing such components, while simultaneously allowing LMRP <NUM> to be disconnected from BOP <NUM> (e.g., via emergency disconnect package) without any interference from system <NUM>.

Referring again to <FIG> and <FIG>, the tensile preload L in each span <NUM> is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding span <NUM>. In other words, the tensile preload in L in each span <NUM> is preferably the lowest tension that results in that span <NUM> extending linearly from the corresponding winch <NUM> to its end 160a. It should be appreciated that such tensile loads L in tension members <NUM> restrict and/or prevent the initial movement and flexing of BOP <NUM> at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each span <NUM> before and after the application of the external loads and/or bending moments. The latter consequence minimizes the potential risk of inadvertent damage to BOP <NUM>, tree <NUM>, and LMRP <NUM> in the event one or more tension members <NUM> uncontrollably break.

In general, each tension member <NUM> can include any elongate flexible member suitable for subsea use and capable of withstanding the anticipated tensile loads (i.e., the tensile preload L as well as the tensile loads induced in spans <NUM> via the application of external loads to BOP <NUM>) without deforming or elongating. Examples of suitable devices for tensile members <NUM> can include, without limitation, chain(s), wire rope, and Dyneema® rope available from DSM Dyneema LLC of Stanley, North Carolina USA. In this embodiment, each tension member <NUM> comprises Dyneema® rope, which is suitable for subsea use, requires the lowest tensile preload L to pull out any slack, curve, and catenary (~ <NUM> ton of tension), and is sufficiently strong to withstand the anticipated tensions.

Referring now to <FIG>, end 160a of each tension member <NUM> is pivotally coupled to one side corner of frame <NUM> with a fairlead assembly <NUM>. In general, each fairlead assembly <NUM> couples the corresponding tension member <NUM> to BOP <NUM> and transfers the tensile loads in the tension member <NUM> to BOP <NUM> (i.e., in the form of lateral load L<NUM> and vertical loads Lv), while simultaneously allowing the tension member <NUM> to pivot up and down about its end 160a (i.e., within a vertical plane) and pivot laterally (i.e., left and right) about its end 160a. Fairlead assemblies <NUM> are welded to the upper end of frame <NUM> along available space that minimizes and/or avoids interference with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover and intervention operations); (c) wellhead <NUM>, primary conductor <NUM>, tree <NUM>, BOP <NUM>, and LMRP <NUM>; (d) subsea remotely operated vehicle (ROV) operations and access to tree <NUM>, BOP <NUM>, and LMRP <NUM>; and (e) neighboring wells.

Referring now to <FIG>, each fairlead assembly <NUM> is the same and includes a base <NUM> attached to frame <NUM>, a receiver block <NUM> pivotally coupled to base <NUM>, and a load pin <NUM> removably seated in the receiver block <NUM>. Base <NUM> includes a horizontal first or upper plate 171a extending laterally from frame <NUM> and a second or lower plate 171b extending laterally from frame <NUM>. Receiver block <NUM> is slidably disposed between plates 171a, 171b and pivotally coupled to plates 171a, 171b with a vertical pin <NUM>. As a result, receiver block <NUM> is free to pivot relative to base <NUM> and frame <NUM> about the vertically oriented central axis <NUM> of pin <NUM>. As best shown in <FIG>, receiver block <NUM> includes a pair of horizontally spaced arms <NUM>. The opposed inner surfaces of each arm <NUM> include receptacles or pockets <NUM> extending downward from the top of the corresponding arm <NUM> to a concave shoulder <NUM>.

Referring now to <FIG> and <FIG>, a thimble <NUM> is disposed in end 160a of tension member <NUM>. Load pin <NUM> is passed through thimble <NUM> and seated in pockets <NUM>. In particular, the ends of load pin <NUM> are slidably seated against concave shoulders <NUM>. Each load pin <NUM> continuously measures the tension in the corresponding tension member <NUM>. 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). By way of example, the tensions measured by load pins <NUM> are communicated acoustically to the surface (e.g., by a preexisting acoustic communication system housed on BOP <NUM>). Communication of the measured tension in each tension member <NUM> 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 <NUM>, and identify any broken tension member(s) <NUM>. An ROV handle 179a is coupled to each load pin <NUM> to facilitate the subsea positioning of each load pin <NUM> in the corresponding receiver block <NUM>. In general, each load pin <NUM> can comprise any suitable tensile load measuring pin known in the art.

As previously described, fairlead assemblies <NUM> are attached to frame <NUM> by welding bases <NUM> thereto. However, the fairlead assemblies (e.g., fairlead assemblies <NUM>) can be bolted to a suitable location of frame <NUM>. Further, although system <NUM> includes one fairlead assembly <NUM> disposed at or proximal each of the four side corners of frame <NUM>, the fairlead assemblies (e.g., fairlead assemblies <NUM>) can be coupled to other suitable locations along frame <NUM>. As previously described, regardless of the means for coupling the fairlead assemblies <NUM> to frame <NUM>, the fairlead assemblies <NUM> are preferably positioned along frame <NUM> to minimize and/or avoid interference with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover and intervention operations); (c) wellhead <NUM>, primary conductor <NUM>, tree <NUM>, BOP <NUM>, and LMRP <NUM>; (d) subsea remotely operated vehicle (ROV) operations and access to tree <NUM>, BOP <NUM>, and LMRP <NUM>; and (e) neighboring wells.

In <FIG> and <FIG>, ends 160a of tension members <NUM> are pivotally coupled to frame <NUM> of BOP <NUM> with fairlead assemblies <NUM>. However, in general, the tension members (e.g., tension members <NUM>) can be coupled to the BOP by other suitable means. For example, the fairlead assemblies <NUM> are eliminated and the distal ends of the tension members (e.g., ends 160a) are directly coupled to the frame <NUM> (e.g., coupled to pad eyes attached to the BOP with shackle assemblies). Regardless of the means for coupling the tension members to the BOP, a load pin or load cell (e.g., load pin <NUM>) is preferably provided for each tension member to measure the tension in the corresponding tension member, which is communicated to the surface.

Referring now to <FIG>, anchors <NUM> are circumferentially-spaced about wellhead <NUM> and secured to the sea floor <NUM>. Four anchors <NUM> are uniformly circumferentially-spaced about wellhead <NUM>. However, in general, three or more uniformly circumferentially-spaced anchors <NUM> are preferably provided. The circumferential positions of anchors <NUM> are 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 <NUM>, primary conductor <NUM>, tree <NUM>, BOP <NUM>, and LMRP <NUM>; (d) subsea remotely operated vehicle (ROV) operations and access to tree <NUM>, BOP <NUM>, and LMRP <NUM>; and (e) neighboring wells. In addition, as best shown in <FIG> and <FIG>, each anchor <NUM> is disposed at a distance R<NUM> measured radially and horizontally (center-to-center) from wellhead <NUM>. Angles α are a function of distances R<NUM> and heights H. Thus, by varying distances R<NUM> and heights H, angles α can be adjusted as desired. However, if each height H is predetermined (e.g., ends 160a are coupled to frame <NUM> of BOP <NUM> at the same predetermined location such as the upper end of frame <NUM> of BOP <NUM> below LMRP <NUM>), angles α are effectively a function of distances R<NUM>. Thus, where each height H is predetermined or known, distances R<NUM> are generally selected to achieve the preferred angles α. Each height H may be the same, however, as best shown in <FIG>, three of the distances R<NUM> are the same and the fourth distance R<NUM> is greater than the other three distances R<NUM>. Consequently, three angles α are the same, but the fourth angle α is different. The lateral preloads L<NUM> applied to BOP <NUM> are preferably balanced and uniformly distributed. Thus, if heights H, angles α, or distances R<NUM> vary among the different tension members <NUM>, the tensile preloads L applied to tension members <NUM> may need to be adjusted and varied to achieve balanced and uniformly distributed lateral preloads L<NUM>.

Referring now to <FIG>, <FIG>, <FIG>, and <FIG>, each anchor <NUM> is an elongate rigid member fixably disposed in the seabed. In particular, each anchor <NUM> has a vertically oriented central or longitudinal axis <NUM>, an upper end 110a disposed above the sea floor <NUM>, a lower end 110b disposed in the seabed below the sea floor <NUM>, a cylindrical outer surface <NUM> extending axially between ends 110a, 110b, and an annular lip or flange <NUM> (<FIG>) extending radially outward from outer surface <NUM> proximal upper end <NUM>10a. Each anchor <NUM> is a subsea pile, and thus, anchors <NUM> may also be referred to as piles <NUM>. Each pile <NUM> 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 <NUM> are sized to penetrate the seabed to a depth to sufficiently resist the anticipated tensile loads applied to tension members <NUM> (i.e., the anticipated tensile preloads L plus any additional tensile loads resulting from the loads and bending moments applied to BOP <NUM>) without moving laterally or vertically relative to the sea floor <NUM>.

Referring now to <FIG> and <FIG>, one pile top assembly <NUM> is releasably mounted to the upper end 110a of one anchor <NUM>. Each pile top assembly <NUM> is the same, and thus, one pile top assembly <NUM> will be described it being understood that the other pile top assemblies <NUM> are the same. Pile top assembly <NUM> includes an adapter <NUM> removably mounted to the upper end 110a of pile <NUM>, a plurality of uniformly circumferentially-spaced locking rams <NUM> attached to adapter <NUM>, and winch <NUM> fixably secured to adapter <NUM>.

Adapter <NUM> is a generally cylindrical sleeve having a first or upper end 121a, a second or lower end 121b, a radially inner annular shoulder <NUM>, and a receptacle <NUM> extending axially from lower end 121b to flange <NUM>. Receptacle <NUM> is sized and configured to receive upper end 110a of anchor <NUM>. To facilitate the receipt of anchor <NUM> and coaxial alignment of anchor <NUM> and adapter <NUM>, an annular funnel <NUM> is disposed at lower end 121b. Adapter <NUM> is generally coaxially aligned with anchor <NUM>, and then lowered onto upper end 110a of anchor <NUM>. Upper end 110a is advanced through lower end 121b and receptacle <NUM> until end 110a axially abuts shoulder <NUM>. With end 110a of anchor <NUM> sufficiently seated in receptacle <NUM>, it is releasably locked therein with locking rams <NUM> described in more detail below. A guide <NUM> for tension member <NUM> is secured to upper end 121a. Tensioning member <NUM> extends from winch <NUM> through guide <NUM> to end 160a. Thus, guide <NUM> generally directs tension member <NUM> as it is paid in and paid out from winch <NUM>.

As best shown in <FIG>, locking rams <NUM> are actuated to engage and disengage upper end 110a of pile <NUM>, which is coaxially disposed in receptacle <NUM>, and releasably lock pile top assembly <NUM> to pile <NUM>. Each ram <NUM> includes a double-acting linear actuator <NUM> mounted to adapter <NUM> between ends 121a, 121b and a gripping member or ram block <NUM> coupled to the actuator <NUM>. Each gripping member <NUM> is mounted to the radially inner end of the corresponding actuator <NUM> and extends into receptacle <NUM>. Actuators <NUM> are actuated to move gripping members <NUM> radially inward into engagement with outer surface <NUM> of pile <NUM> and radially outward out of engagement with pile <NUM>. Locking rams <NUM> are axially positioned along adapter <NUM> such that when actuators <NUM> are operated to move gripping members <NUM> into engagement with outer surface <NUM>, each gripping member <NUM> is axially disposed immediately below annular lip <NUM>. Thus, when gripping members <NUM> are moved into engagement with outer surface <NUM> of pile <NUM>, friction between gripping members <NUM> and outer surface <NUM> and axial engagement of gripping members <NUM> with lip <NUM> prevent adapter <NUM> from being removed from pile <NUM>. Each actuator <NUM> is an ROV operated hydraulic piston-cylinder assembly.

Referring now to <FIG>, <FIG> and <FIG>, winch <NUM> is fixably mounted to upper end 121a of adapter <NUM>. Winch <NUM> includes a spool <NUM> rotatably coupled to adapter <NUM> and a locking mechanism or brake <NUM> coupled to spool <NUM> and adapter <NUM>. Spool <NUM> is selectively rotated relative to adapter <NUM> to pay in and pay out tension member <NUM>. As will be described in more detail below, locking mechanism <NUM> releasably locks spool <NUM> relative to adapter <NUM>.

Spool <NUM> has a horizontal axis of rotation <NUM> and includes a drum <NUM> around which tension member <NUM> is wound, a driveshaft <NUM> extending from one side of drum <NUM>, and a support shaft <NUM> extending from the opposite side of drum <NUM>. Drum <NUM> and shafts <NUM>, <NUM> are coaxially aligned with axis <NUM>. Driveshaft <NUM> extends through a connection block <NUM> fixably mounted to upper end 121a of adapter <NUM> and support shaft <NUM> extends into a connection block <NUM> fixably mounted to upper end 121a of adapter <NUM>. Each shaft <NUM>, <NUM> is rotatably supported within block <NUM>, <NUM>, respectively, with an annular bearing. The distal end of driveshaft <NUM> comprises a torque tool interface <NUM> designed to mate with a subsea ROV torque tool.

As best shown in <FIG>, locking mechanism <NUM> includes an annular spool ring <NUM> disposed about shaft <NUM> and coupled to drum <NUM>, a hub <NUM> extending from block <NUM> and disposed about shaft <NUM>, an annular lock ring <NUM> slidably mounted to hub <NUM>, and an actuation system <NUM> that moves lock ring <NUM> axially along hub <NUM> into and out of spool ring <NUM>. Spool ring <NUM>, hub <NUM>, and lock ring <NUM> are coaxially aligned with axis <NUM>. Spool ring <NUM> is fixably mounted to drum <NUM>, and hub <NUM> is integral with connection block <NUM>. Spool ring <NUM> includes a plurality of internal splines 151a, hub <NUM> includes a plurality of external splines 152a, and lock ring <NUM> 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 <NUM>.

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

Referring now to <FIG>, 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 <NUM> into spool ring <NUM>, via rotation of spool ring <NUM> relative to lock ring <NUM> through a relatively small angle. This enables relatively fine adjustment of the tensile preload L applied to tension member <NUM>.

Referring now to <FIG> and <FIG>, actuation system <NUM> transitions lock ring <NUM> and locking mechanism <NUM> between the locked and unlocked positions. Actuation system <NUM> includes a plurality of double-acting linear actuators <NUM> coupled to lock ring <NUM>. Actuators <NUM> are uniformly circumferentially-spaced about axis <NUM>. In addition, each actuator <NUM> is the same, and thus, one actuator <NUM> will be described it being understood the other actuators <NUM> are the same. As best shown in <FIG>, each actuator <NUM> is an ROV operated hydraulic piston-cylinder assembly including a cylinder <NUM> disposed in block <NUM>, a piston <NUM> slidably disposed in cylinder <NUM>, an extension rod <NUM> coupling piston <NUM> to lock ring <NUM>, and a biasing member <NUM> disposed in cylinder <NUM>.

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

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

Although winches <NUM> are coupled to anchors <NUM>, the tensioning systems (e.g., winches <NUM>) may be coupled to the frame of BOP (e.g., frame <NUM> of BOP <NUM>) and an end of each tension member (e.g., end 160a of each tension member <NUM>) is coupled to the anchor (e.g., anchor <NUM>). The arrangement with winches <NUM> coupled to anchors <NUM> is generally preferred as it generally requires less interaction with BOP <NUM> and a lower likelihood of interference with the BOP <NUM> (including frame <NUM>), other subsea equipment, and subsea operations.

Referring now to <FIG>, a method <NUM> for deploying and installing tethering system <NUM> is shown. For subsea deployment and installation of tethering system <NUM>, one or more remote operated vehicles (ROVs) are preferably employed to aid in monitoring and positioning piles <NUM>, coupling pile top assemblies <NUM> to upper ends 110a of piles <NUM>, coupling tension members <NUM> to winches <NUM> and frame <NUM> of BOP <NUM>, and operating subsea hardware (e.g., winches <NUM>, locking mechanisms <NUM>, locking rams <NUM>, actuation system <NUM>, 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>, in block <NUM>, piles <NUM> are deployed subsea and installed subsea. In particular, piles <NUM> are lowered subsea from a surface vessel such as vessel <NUM> or a separate construction vessel. In general, piles <NUM> can be lowered subsea by any suitable means such as wireline. Next, piles <NUM> are installed (i.e., secured to the sea floor <NUM>). To install piles <NUM>, each pile <NUM> is vertically oriented and positioned immediately above the desired installation location in the sea floor <NUM> (i.e., at the desired circumferential position about wellhead <NUM> and at the desired radial distance R<NUM>). Then, each pile <NUM> is advanced into the sea floor <NUM> (driven or via suction depending on the type of pile <NUM>) until upper end 110a is disposed at the desired height above the sea floor <NUM>. In general, piles <NUM> can be installed one at a time, or two or more at the same time.

Moving now to block <NUM>, pile top assemblies <NUM> are deployed subsea and coupled to upper ends 110a of piles <NUM>. In particular, assemblies <NUM> are lowered subsea from a surface vessel such as vessel <NUM> or a separate construction vessel. In general, assemblies <NUM> can be lowered subsea by any suitable means such as wireline. Next, assemblies <NUM> are lowered onto to ends 110a of piles <NUM> and locked thereon as previously described. Assemblies <NUM> are preferably mounted to piles <NUM> with each guide <NUM> aligned with the corresponding fairlead assembly <NUM>. In general, assemblies <NUM> can be installed one at a time, or two or more at the same time.

Next, in block <NUM>, locking mechanisms <NUM> are transitioned to the unlocked positions and tension members <NUM> are paid out from winches <NUM>. In addition, ends 160a are coupled to frame <NUM> of BOP <NUM> via fairlead assemblies <NUM>. In general, fairlead assemblies <NUM> can be deployed and installed at any time prior to block <NUM>.

Moving now to block <NUM>, tensile preloads L are applied to tension members <NUM> as previously described. Namely, the tensile preload L is applied to each tension member <NUM> by unlocking mechanism <NUM>, and then rotating spool <NUM> with an ROV operated torque tool engaging interface <NUM> to pay in tension member <NUM>. The tension member <NUM> and/or tension measured with the corresponding load pin <NUM> is monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tensioned span <NUM> of tension member <NUM> is removed). Once the desired tensile preload L is achieved, locking mechanism <NUM> is transitioned to and maintained in the locked position.

It should be appreciated that tethering system <NUM> can be deployed and installed on an existing frame <NUM> of BOP <NUM>. Thus, system <NUM> provides an option for reinforcing existing stacks (e.g., BOP <NUM>) before, during, or after drilling operations, completion operations, production operations, or workover operations. Moreover, because pile top assemblies <NUM> are releasably coupled to piles <NUM>, assemblies <NUM> and winches <NUM> mounted thereto can be retrived and reused at different locations.

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

Referring now to <FIG>, system <NUM>, and in particular, primary conductor <NUM>, wellhead <NUM>, BOP <NUM>, and LMRP <NUM> were modeled and simulations were run with and without tethering system <NUM> to assess the impact of tethering system <NUM>. <FIG> graphically illustrate the results of those simulations with and without tethering system <NUM>. In <FIG>, the bending moments induced along LMRP <NUM>, BOP <NUM>, wellhead <NUM>, and conductor <NUM> due to a static offset of surface vessel <NUM> are shown as a function of the elevation relative to the sea floor <NUM> (i.e., mudline); in <FIG>, the bending moments induced along LMRP <NUM>, BOP <NUM>, wellhead <NUM>, and conductor <NUM> due to a wave are shown as a function of the elevation relative to the sea floor <NUM> (i.e., mudline); and in <FIG> , the fatigue life along LMRP <NUM>, BOP <NUM>, wellhead <NUM>, and conductor <NUM> is shown as a function of the elevation relative to the sea floor <NUM> (i.e., mudline).

Referring now to <FIG> and <FIG>, another tethering system <NUM> for reinforcing BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> of system <NUM> is shown. Similar to tethering system <NUM> previously described, tethering system <NUM> reinforces BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> by resisting lateral loads and bending moments applied thereto. As a result, system <NUM> offers the potential to enhance the strength and fatigue resistance of BOP <NUM>, wellhead <NUM>, and conductor <NUM>. In <FIG>, system <NUM> is shown configured for completion operations, and thus, includes tree <NUM>, however, in <FIG>, system <NUM> is shown configured for drilling operations, and thus, tree <NUM> is not included.

Referring still to <FIG> and <FIG>, tethering system <NUM> includes a plurality of anchors <NUM>, a plurality of pile top assemblies <NUM> mounted to anchors <NUM>, a plurality of tensioning systems <NUM> releasably coupled to pile top assemblies <NUM>, and a plurality of flexible tension members <NUM>. Anchors <NUM> and tension members <NUM> are each as previously described. Tensioning systems <NUM> are winches, and thus, may also be referred to as winches <NUM>. However, different devices for applying and maintaining tension on the flexible tension members (e.g., tension members <NUM>) can be employed. One winch <NUM> is coupled to each anchor <NUM>, and one tension member <NUM> is wound to each winch <NUM> such that each flexible tension member <NUM> can be paid in and paid out from the corresponding winch <NUM>.

Distal end 160a of each tension member <NUM> is coupled to frame <NUM> of BOP <NUM>, and tensioned span <NUM> of each tension member <NUM> extends from the corresponding winch <NUM> to end 160a. In addition, each distal end 160a is coupled to frame <NUM> of BOP <NUM> at a height H measured vertically from the sea floor <NUM> and at a lateral distance D measured radially and perpendicularly from central axis <NUM>. Each height H is the same and each lateral distance D is the same. As previously described, for most subsea applications, lateral distance D is preferably between <NUM> and <NUM> ft, and more preferably about <NUM> ft. However, it should be appreciated that lateral distance D may depend, at least in part, on the available connection points to the frame <NUM> of BOP <NUM>.

Tensile preload L is provided on each tensioned span <NUM> of tension members <NUM> with the corresponding winch <NUM>. With no external loads or moments applied to BOP <NUM>, the actual tension in each span <NUM> is the same or substantially the same as the corresponding tensile preload L. However, as previously described, when external loads and/or bending moments are applied to BOP <NUM>, the actual tension in each span <NUM> can be greater than or less than the corresponding tensile preload L.

Winches <NUM> are positioned proximal to the sea floor <NUM>, and ends 160a are coupled to frame <NUM> of BOP <NUM> above winches <NUM>. Thus, each span <NUM> is oriented at an acute angle α measured upward from horizontal. Since portions <NUM> are in tension and oriented at acute angles α, the tensile preload L applied by each tension member <NUM> frame <NUM> of BOP <NUM> includes an outwardly oriented horizontal or lateral preload L<NUM> and a downwardly oriented vertical preload Lv. Without being limited by this or any particular theory, the lateral preload L<NUM> and the vertical preload Lv applied to BOP <NUM> by each tension member <NUM> are a function of the corresponding tensile load L and angle α. For a given angle α, the lateral preload L<NUM> and the vertical preload Lv increase as the tensile load L increases, and decrease as the tensile load L decreases. For a given tensile load L, the lateral preload L<NUM> decreases and the vertical preload Lv increases as angle α increases, and the lateral preload L<NUM> increases and the vertical preload Lv decreases as angle α decreases. For example, at an angle α of <NUM>°, the lateral preload L<NUM> and the vertical preload Lv are substantially the same; at an angle α above <NUM>°, the lateral preload L<NUM> is less than the vertical preload Lv; and at an angle α below <NUM>°, the lateral preload L<NUM> is greater than the vertical preload Lv. Angle α of each span <NUM> is preferably between <NUM>° and <NUM>°, and more preferably between <NUM>° and <NUM>°.

The lateral preloads L<NUM> applied to frame <NUM> of BOP <NUM> resist external lateral loads and bending moments applied to BOP <NUM> (e.g., from subsea currents, riser <NUM>, etc.). To reinforce and/or stabilize BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> without interfering with an emergency disconnection of LMRP <NUM>, each height H is preferably as high as possible but below LMRP <NUM>, and may depend on the available connection points along frame <NUM> of BOP <NUM>. Ends 160a are coupled to frame <NUM> at the upper end of BOP <NUM>, just below LMRP <NUM>. By tethering frame <NUM> of BOP <NUM> at this location, system <NUM> restricts and/or prevents BOP <NUM>, tree <NUM>, wellhead <NUM>, and primary conductor <NUM> from moving and bending laterally, thereby stabilizing such components, while simultaneously allowing LMRP <NUM> to be disconnected from BOP <NUM> (e.g., via emergency disconnect package) without any interference by system <NUM>.

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

As best shown in <FIG> and <FIG>, each end 160a is pivotally coupled to frame <NUM> of BOP <NUM> with an adapter plate <NUM>. Each adapter plate <NUM> has a first or BOP end 250a pivotally coupled to frame <NUM> of BOP <NUM> at height H (from the sea floor <NUM>) and lateral distance D (measured radially and perpendicular to axis <NUM>), and a second or tension member end 250b coupled to end 160a. In particular, each end 250a is pivotally coupled to two pad eyes 47a disposed on the same side of frame <NUM> at height H and lateral distance D, and each end 250b is pivotally coupled to the corresponding end 160a with a shackle assembly <NUM>. This arrangement allows each plate <NUM> and corresponding tension member <NUM> to pivot relative to frame <NUM> of BOP <NUM> about a horizontal axis <NUM>, and allows each tension member <NUM> to pivot relative to the corresponding plate <NUM> about an axis <NUM> oriented perpendicular to (e.g., through the planar surface of) plate <NUM>.

Each shackle assembly <NUM> includes a load cell <NUM> that continuously measures the tension in the corresponding tension member <NUM>. 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). By way of example, the tensions measured by load cells <NUM> are communicated acoustically to the surface by a preexisting acoustic communication system housed on BOP <NUM>. Communication of the measured tension in each tension member <NUM> 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 <NUM>, and identify any broken tension member(s) <NUM>.

As shown in <FIG> and <FIG>, ends 160a of tension members <NUM> are pivotally coupled to frame <NUM> of BOP <NUM> with adapter plates <NUM>. However, in general, the tension members (e.g., tension members <NUM>) can be coupled to the stack by other suitable means. For example, plates <NUM> are eliminated and the distal ends of the tension members (e.g., ends 160a) are directly coupled to the frame <NUM> (e.g., coupled to pad eyes 127a with shackle assemblies <NUM>). Regardless of the means for coupling the tension members to the frame, a load cell (e.g., load cell <NUM>) is preferably provided for each tension member to measure the tension in the corresponding tension member, which is communicated to the surface.

Referring again to <FIG> and <FIG>, four anchors <NUM> are uniformly circumferentially-spaced about wellhead <NUM>. However, in general, three or more uniformly circumferentially-spaced anchors <NUM> are preferably provided. The circumferential positions of anchors <NUM> are selected to avoid unduly interfering with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover and intervention operations); (c) wellhead <NUM>, primary conductor <NUM>, tree <NUM>, BOP <NUM>, and LMRP <NUM>; (d) subsea remotely operated vehicle (ROV) operations and access to tree <NUM>, BOP <NUM>, and LMRP <NUM>; and (e) neighboring wells. In addition, each anchor <NUM> is disposed at a distance R<NUM> measured radially (center-to-center) from wellhead <NUM>. Angles α are a function of distances R<NUM> and heights H. Thus, by varying distances R<NUM> and heights H, angles α can be adjusted as desired. However, if each height H is predetermined (e.g., ends 160a are coupled to frame <NUM> of BOP <NUM> at the same predetermined location such as the upper end of frame <NUM> of BOP <NUM> below LMRP <NUM>), angles α are effectively a function of distances R<NUM>. Thus, where each height H is predetermined or known, radial distances R<NUM> are generally selected to achieve the preferred angles α without unduly interfering with (a) existing or planned subsea architecture; (b) subsea operations (e.g., drilling, completion, production, workover and intervention operations); (c) wellhead <NUM>, primary conductor <NUM>, tree <NUM>, BOP <NUM>, and LMRP <NUM>; (d) subsea remotely operated vehicle (ROV) operations and access to tree <NUM>, BOP <NUM>, and LMRP <NUM>; and (e) neighboring wells. To balance and uniformly distribute lateral preloads L<NUM>, while maintaining preferred angles α with ends 160a coupled to frame <NUM> of BOP <NUM> at the preferred height H, each radial distance R<NUM> is the same. Thus, each tension preload L is the same, each height H is the same, each angle α is the same, and each distance R110 is the same. However, one or more preload L can be different and/or varied, one or more height H can be different and/or varied, one or more angle α can be different and/or varied, one or more radial distance R<NUM> can be different and/or varied, or combinations thereof.

Referring now to <FIG>, <FIG>, and <FIG>, axis <NUM> of each anchor <NUM> is vertically oriented, upper end 110a disposed above the sea floor <NUM>, and lower end 110b disposed in the seabed below the sea floor <NUM>. Piles <NUM> are sized to penetrate the sea floor <NUM> to a depth to sufficiently resist the anticipated tensile preloads L, as well as the loads and bending moments applied to BOP <NUM> without moving laterally or vertically relative to the sea floor <NUM>.

One pile top assembly <NUM> is mounted to upper end 110a of each pile <NUM>. As best shown in <FIG>, each pile top assembly <NUM> includes a cap <NUM> fixably secured to the upper end 110a of pile <NUM> and an anchor adapter <NUM> releasably coupled to cap <NUM>. Cap <NUM> and adapter <NUM> are coaxially aligned with axis <NUM>. Cap <NUM> 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 <NUM> is seated in receptacle 214b and fixably secured to cap <NUM>.

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

Connection body <NUM> 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. Each receptacle 218b is sized and configured to receive a mating pin or stabbing member <NUM> provided on each winch <NUM>. By including multiple receptacles 218b in body <NUM>, the position of one or more winches <NUM> coupled thereto can be varied as desired. With pin <NUM> of the winch <NUM> 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 <NUM> of the winch <NUM> in a given receptacle 218b. The locking mechanism prevents the winch <NUM> from moving axially relative to body <NUM>, but allows the winch <NUM> to rotate about the central axis of the winch pin relative to body <NUM>.

Since each winch <NUM> is releasably coupled to the corresponding adapter <NUM> via receptacle 218b, and each adapter <NUM> is releasably coupled to the corresponding cap <NUM> and pile <NUM> via receptacle 214a, winches <NUM> and adapters <NUM> can be retrieved to the surface, moved between different subsea piles <NUM>, and reused. Although winches <NUM> are configured to stab into adapters <NUM>, and adapters <NUM> are configured to stab into caps <NUM>, the adapters (e.g., adapters <NUM>) can stab into the winches (e.g., winches <NUM>) and/or the cap (e.g., cap <NUM>) can stab into the adapter.

As previously described, tensioning systems <NUM> are releasably coupled to anchors <NUM>. However, the tensioning mechanisms (e.g., winches <NUM>) are coupled to the frame of BOP (e.g., frame <NUM> of BOP <NUM>) and an end of each tension member (e.g., end 160a of each tension member <NUM>) is coupled to the anchor (e.g., anchor <NUM>). The arrangement with tensioning systems <NUM> coupled to anchors <NUM> is generally preferred as it generally requires less interaction with BOP <NUM> and a lower likelihood of interference with the BOP <NUM> (including frame <NUM>), other subsea equipment, and subsea operations.

Referring now to <FIG>, one tensioning system <NUM> is shown, it being understood that each tensioning system <NUM> is the same. As previously described, each tensioning system <NUM> is a winch. In particular, each tensioning system <NUM> includes a base <NUM>, a spool <NUM> rotatably coupled to base <NUM>, a torque tool interface <NUM> coupled to spool <NUM>, and a locking mechanism or brake <NUM> coupled to spool <NUM> and base <NUM>. A pin or stabbing member <NUM> of winch <NUM> removably received in receptacle 218b of adapter <NUM> is not shown in <FIG>, but generally extends downward from base <NUM>. Spool <NUM> is rotated relative to base <NUM> to pay in and payout tension member <NUM>. Locking mechanism <NUM> releasably locks spool <NUM> relative to base <NUM>. In particular, locking mechanism <NUM> has a "locked" position preventing spool <NUM> from rotating relative to base <NUM> and pile <NUM>, and an "unlocked" position allowing spool <NUM> to rotate relative to base <NUM> and pile <NUM>. In general, locking mechanism <NUM> can be any suitable locking mechanism known in the art or any locking mechanism described here (e.g., locking mechanism <NUM> previously described).

The tensile preload L is applied to tension member <NUM> by unlocking mechanism <NUM>, and then rotating spool <NUM> with an ROV operated torque tool engaging interface <NUM> to pay in tension member <NUM>. The tension member <NUM> and/or tension measured with the corresponding load cell <NUM> can be monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tension member <NUM> is removed). Once the desired tensile preload L is achieved, locking mechanism <NUM> is transitioned to and maintained in the locked position. Winch <NUM>, and more specifically locking mechanism <NUM>, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member <NUM> when locking mechanism <NUM> is locked and external loads are applied to BOP <NUM>.

Referring now to <FIG>, a method <NUM> for deploying and installing tethering system <NUM> is shown. For subsea deployment and installation of tethering system <NUM>, one or more remote operated vehicles (ROVs) are preferably employed to aid in monitoring and positioning piles <NUM>, coupling adapters <NUM> to caps <NUM> disposed at the upper ends of piles <NUM>, coupling winches <NUM> to adapters <NUM>, coupling tension members <NUM> to winches <NUM> and frame <NUM> of BOP <NUM>, and operating winches <NUM>. 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. In addition, each ROV is preferably configured to operate a subsea torque tool to apply the tensile preload L to tension members <NUM>.

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

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

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

Next, in block <NUM>, tension members <NUM> are paid out from winches <NUM> with locking mechanisms <NUM> in the unlocked positions, and ends 160a are coupled to frame <NUM> of BOP <NUM>. Ends 160a are coupled to frame <NUM> of BOP <NUM>, and in particular the upper end of BOP frame <NUM>, via shackle assemblies <NUM> and plates <NUM> as previously described. In general, shackle assemblies <NUM> and plates <NUM> can be deployed and installed at any time prior to block <NUM>.

Moving now to block <NUM>, tensile preloads L are applied to tension members <NUM> as previously described. Namely, the tensile preload L is applied to tension member <NUM> by unlocking mechanism <NUM>, and then rotating spool <NUM> with an ROV operated torque tool engaging interface <NUM> to pay in tension member <NUM>. The tension member <NUM> and/or tension measured with the corresponding load cell <NUM> is monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tensioned span <NUM> of tension member <NUM> is removed). Once the desired tensile preload L is achieved, locking mechanism <NUM> is transitioned to and maintained in the locked position.

It should be appreciated that tethering system <NUM> can be deployed and installed on an existing frame <NUM> of BOP <NUM>. Thus, system <NUM> provides an option for reinforcing existing stacks (e.g., BOP <NUM>) before, during, or after drilling operations, completion operations, production operations, or workover operations. Moreover, because adapters <NUM> are releasably coupled to piles <NUM>, and winches <NUM> are releasably coupled to adapters <NUM>, adapters <NUM> and/or winches <NUM> can be reused at different locations.

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

Tethering systems <NUM>, <NUM> previously described, tension members <NUM> can comprise Dyneema® rope, and winches <NUM>, <NUM> include an ROV torque tool interface <NUM>, <NUM>, respectively, and locking mechanism <NUM>, <NUM>. However, the tension members (e.g., tension members <NUM>) can include different materials and/or different types of tensioning mechanisms (e.g., winches) can be utilized. For example, referring now to <FIG> , an alternative tension member <NUM> and tensioning system <NUM> that can be used in system <NUM> in place of tension members <NUM> and tensioning systems <NUM>, respectively, is shown. Tension member <NUM> comprises a chain, and tensioning system <NUM> is a winch configured to pay in and pay out the chain, as well as lock the chain. In particular, winch <NUM> includes a base <NUM>, a chain wheel <NUM> rotatably coupled to base <NUM>, an ROV torque tool interface <NUM> coupled to chain wheel <NUM>, and a locking mechanism or brake <NUM> coupled to base <NUM>. A pin or stabbing member extends downward from base <NUM> and is locked within mating receptacle 218b of adapter <NUM> as previously described. Chain wheel <NUM> is rotated relative to base <NUM> to pay in and pay out chain <NUM>.

Locking mechanism <NUM> controls the pay out of chain <NUM>. Locking mechanism <NUM> includes a locking member or chock <NUM> pivotally coupled to base <NUM>. Chock <NUM> pivots about a horizontal axis <NUM> and includes a pair of parallel arms <NUM> that are spaced apart a horizontal distance that is substantially the same or slightly greater than the minimum width of a link of chain <NUM>. Thus, a first plurality of links of chain <NUM> generally lying in a plane parallel to arms <NUM> and perpendicular to axis <NUM> can pass between arms <NUM>, however, a second plurality of links of chain <NUM> generally oriented perpendicular to the first plurality of links (i.e., lying in a plane oriented parallel to axis <NUM>) cannot pass between arms <NUM>. The first plurality of links and the second plurality of links of chain <NUM> are arranged in an alternating fashion. Therefore, every other link of chain <NUM> can pass between arms <NUM>, whereas the links therebetween cannot pass between arms <NUM>. Accordingly, when chock <NUM> is pivoted away from chain <NUM>, chain <NUM> can be paid in or paid out from chain wheel <NUM>, however, when chock <NUM> is pivoted into engagement with chain <NUM>, one link of chain <NUM> (i.e., a link generally lying in a plane parallel to arms <NUM> and perpendicular to pivot axis <NUM>) is slidingly disposed between arms <NUM>, the adjacent link of chain <NUM> positioned above arms <NUM> is prevented from passing between arms <NUM>, thereby preventing chain <NUM> from being paid out. Therefore, locking mechanism <NUM> and locking member <NUM> may be described as having a "locked" position with locking member <NUM> pivoted into engagement with chain <NUM> with one link of chain <NUM> disposed between arms <NUM>, thereby preventing chain <NUM> from being paid out from chain wheel <NUM>; and an "unlocked" position with locking member <NUM> pivoted away from chain <NUM>, thereby allowing chain <NUM> to be paid in and paid out from spool <NUM>. Locking mechanism <NUM> and locking member <NUM> are biased to the locked position via gravity. However, a biasing member such as a spring can be employed to bias locking mechanism <NUM> and locking member <NUM> to the locked position.

The tensile preload L is applied to tension member <NUM> by transitioning mechanism <NUM> and locking member <NUM> to the unlocked position, and then rotating chain wheel <NUM> with an ROV operated torque tool engaging interface <NUM> to pay in tension member <NUM>. The tension member <NUM> and/or the tension in tension member <NUM> (as measured with the corresponding load cell <NUM>) can be monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in the tensioned span of tension member <NUM> is removed). Once the desired tensile preload L is achieved, locking mechanism <NUM> is transitioned to and maintained in the locked position. Winch <NUM>, and more specifically locking mechanism <NUM>, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member <NUM> when locking mechanism <NUM> is locked and external loads are applied to BOP <NUM>.

In general, the tensile preload L in each chain <NUM> is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding chain <NUM>. In other words, the tensile preload in L in each chain <NUM> is preferably the lowest tension that results in that chain <NUM> extending linearly from the corresponding chain wheel <NUM> to its distal end coupled to BOP <NUM>. It should be appreciated that such tensile loads L in chains <NUM> restrict and/or prevent the initial movement and flexing of BOP <NUM> at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each chain <NUM> before and after the application of the external loads and/or bending moments. The latter consequence minimizes the potential risk of inadvertent damage to BOP <NUM>, tree <NUM>, and LMRP <NUM> in the event one or more chain <NUM> uncontrollably break.

In tethering systems <NUM>, <NUM> previously described, the tensile preload L is applied to tension members <NUM> by rotating spool <NUM> and chain wheel <NUM>, respectively, with an ROV torque tool. However, alternative means may be employed for inducing the tensile preload L in the tension members (e.g., tension members <NUM>, <NUM>). For example, referring now to <FIG>, a tethering system <NUM> for tethering and reinforcing BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> is shown. Tethering system <NUM> is substantially the same as tethering system <NUM> previously described except that tension members <NUM> are replaced with tension members <NUM> comprising chains <NUM>, plates <NUM> are eliminated, tension members <NUM> are directly coupled to frame <NUM> with shackle assemblies <NUM>, tensioning systems <NUM> are replaced with tensioning systems <NUM>, and the tensile preload L is applied to each tension member <NUM> with a net buoyant subsea buoy <NUM>. As best shown in <FIG>, tensioning systems <NUM> are chain sheaves. Each chain sheave <NUM> includes a base <NUM>, a pulley or chain wheel <NUM> rotatably coupled to base <NUM>, and a locking mechanism (not visible in <FIG>) coupled to base <NUM>. A pin or stabbing member <NUM> extends downward from base <NUM> and is releasably locked within a mating receptacle 218b of adapter <NUM>. Although tension members <NUM> include chains <NUM>, in general, tension members <NUM> can include chains, wire rope, Dyneema® rope, or combinations thereof.

The locking mechanism of chain sheave <NUM> controls the pay out of tension member <NUM>. In particular, the locking mechanism has a "locked" position preventing tension member <NUM> from being paid out from chain wheel <NUM>, and an "unlocked" position allowing tension member <NUM> to be paid in and paid out from chain wheel <NUM>. In general, the locking mechanism of each chain sheave <NUM> can be any suitable locking mechanism known in the art or any locking mechanism described here (e.g., locking mechanism <NUM>, <NUM> previously described).

Referring again to <FIG> and <FIG>, each tension member <NUM> has a first or BOP end 460a coupled to frame <NUM> with a shackle assembly <NUM> and a second or buoy end 460b coupled to a subsea buoy <NUM>. A portion of each tension member <NUM> between ends 460a, 460b includes chain <NUM> extending around the corresponding chain wheel <NUM>. The tensile preload L is applied to each tension member <NUM> by unlocking the corresponding locking mechanism and allowing the buoy <NUM> to pull upward on the tension member <NUM>. In generally, buoys <NUM> can be configured to have the buoyancy necessary to induce the desired tensile preloads L. The tension member <NUM> and/or the tension in tension member <NUM> (as measured with the corresponding load cell <NUM>) can be monitored until the desired tensile preload L is applied (i.e., the slack, curve, and catenary in tension member <NUM> is removed). Once the desired tensile preload L is achieved, the corresponding locking mechanism is transitioned to and maintained in the locked position. Chain sheave <NUM>, and more specifically the locking mechanism, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member <NUM> when the locking mechanism is locked and external loads are applied to BOP <NUM>.

Tethering system <NUM> is generally deployed and installed in the same manner as tethering system <NUM> previously described. Once tethering system <NUM> is installed and tensile preloads L are applied to tension members <NUM>, system <NUM> stabilizes BOP <NUM>, wellhead <NUM> and conductor <NUM> to restrict the lateral/radial movement of BOP <NUM>. As a result, tethering system <NUM> described herein offers the potential to reduce the stresses induced in BOP <NUM>, tree <NUM>, wellhead <NUM> and primary conductor <NUM>, improve the strength and fatigue resistance of BOP <NUM>, tree <NUM>, wellhead <NUM> and primary conductor <NUM>, and improve the bending moment response along primary conductor <NUM> below the sea floor <NUM>.

In general, the tensile preload L in each tension member <NUM> is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding member <NUM>. In other words, the tensile preload in L in each member <NUM> is preferably the lowest tension that results in that member <NUM> extending linearly from the corresponding chain wheel <NUM> to its distal end coupled to BOP <NUM>. It should be appreciated that such tensile loads L in chains <NUM> restrict and/or prevent the initial movement and flexing of BOP <NUM> at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each member <NUM> before and after the application of the external loads and/or bending moments. The latter consequence minimizes the potential risk of inadvertent damage to BOP <NUM>, tree <NUM>, and LMRP <NUM> in the event one or more member <NUM> uncontrollably break.

In tethering systems <NUM>, <NUM>, <NUM> previously described, the distal ends of tensioning members <NUM>, <NUM>, <NUM> are coupled to frame <NUM> of BOP <NUM>. However, in some drilling and completion systems, the BOP does not include a frame. In such cases, alternative means are preferably provided for coupling to the subsea architecture at the highest elevation below the LMRP for the reasons previously described. For example, referring now to <FIG>, a tethering system <NUM> for tethering and reinforcing a subsea BOP <NUM>, wellhead <NUM>, and primary conductor <NUM> (disposed below the sea floor <NUM>) is shown. Wellhead <NUM> and primary conductor <NUM> are each as previously described, and BOP <NUM> is the same as BOP <NUM> previously described except that BOP <NUM> does not include frame <NUM>.

Tethering system <NUM> includes anchors <NUM> (not visible in <FIG>), pile top assemblies <NUM> mounted to anchors <NUM>, tensioning systems <NUM>, and tensioning members <NUM>, each as previously described. However, since BOP <NUM> does not include a frame, tethering system <NUM> also includes an adapter <NUM> to couple tension members <NUM> to BOP <NUM>. In particular, adapter <NUM> is mounted to BOP <NUM>, and distal ends 360a of tension members <NUM> are coupled to adapter <NUM>. As best shown in <FIG>, adapter <NUM> is a spider frame including a central annular hub <NUM> and a plurality of uniformly circumferentially-spaced rigid arms <NUM> extending radially outward from hub <NUM>. Thus, each arm <NUM> has a first or radially inner end 562a attached to hub <NUM> and a second or radially outer end 562b distal hub <NUM>. Each end 562b comprises a pad eye <NUM> for coupling to end 360a of a corresponding tension member <NUM> with a shackle assembly <NUM> as previously described.

Referring again to <FIG>, adapter <NUM> is mounted to BOP <NUM> by stabbing a mandrel <NUM> extending from the upper end of BOP <NUM> into hub <NUM>. Subsequently, an LMRP (e.g., LMRP <NUM>) is releasably connected to mandrel <NUM>. Thus, adapter <NUM> is positioned between BOP <NUM> and the LMRP. With adapter <NUM> secured to BOP <NUM>, ends 360a of tension members <NUM> are coupled to pad eyes <NUM> and the tensile preload L is applied to each tension member <NUM>. Thus, the location of pad eyes <NUM> define the height H (from the sea floor <NUM>) and the lateral distance D (measured radially and perpendicular from central axis <NUM>). By varying the length of arms <NUM>, the lateral distance D can be adjusted as desired. As previously described, for most subsea applications, lateral distance D is preferably between <NUM> and <NUM> ft. , and more preferably about <NUM> ft.

Once tethering system <NUM> is installed and tensile preloads L are applied with tensioning systems <NUM>. Accordingly, system <NUM> reinforces BOP <NUM>, wellhead <NUM> and conductor <NUM> by restricting the lateral/radial movement of BOP <NUM>. As a result, tethering system <NUM> described herein offers the potential to reduce the stresses induced in BOP <NUM>, tree <NUM>, wellhead <NUM> and primary conductor <NUM>, improve the strength and fatigue resistance of BOP <NUM>, tree <NUM>, wellhead <NUM> and primary conductor <NUM>, and improve the bending moment response along primary conductor <NUM> below the sea floor <NUM>.

In general, the tensile preload L in each member <NUM> is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding member <NUM>. In other words, the tensile preload in L in each member <NUM> is preferably the lowest tension that results in that member <NUM> extending linearly from the corresponding chain wheel <NUM> to its distal end coupled to adapter <NUM>. It should be appreciated that such tensile loads L in members <NUM> restrict and/or prevent the initial movement and flexing of BOP <NUM> at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each member <NUM> before and after the application of the external loads and/or bending moments. The latter consequence minimizes the potential risk of inadvertent damage to BOP <NUM>, tree <NUM>, and LMRP <NUM> in the event one or more member <NUM> uncontrollably break.

Claim 1:
A system (<NUM>) for drilling, completing or producing a subsea well, said system (<NUM>) comprising:
a subsea wellhead (<NUM>) extending from the well proximal the sea floor (<NUM>);
a subsea blowout preventer (BOP) (<NUM>) coupled to the wellhead (<NUM>);
a lower marine riser package (LMRP) (<NUM>) coupled to the BOP (<NUM>);
a system (<NUM>, <NUM>) for tethering the BOP (<NUM>), the system (<NUM>, <NUM>) for tethering comprising:
a plurality of circumferentially-spaced anchors (<NUM>, <NUM>) disposed about the wellhead (<NUM>) and secured to the sea floor (<NUM>); wherein each anchor (<NUM>, <NUM>) has an upper end (110a) disposed proximal the sea floor (<NUM>);
a plurality of tensioning systems (<NUM>, <NUM>, <NUM>), wherein each tensioning system (<NUM>, <NUM>, <NUM>) is coupled to a frame (<NUM>) of the BOP (<NUM>);
a plurality of flexible tension members (<NUM>), wherein each tension member (<NUM>) is coupled to one of the tensioning systems (<NUM>, <NUM>, <NUM>) and has a first end coupled to one of the anchors (<NUM>, <NUM>); wherein each tension member (<NUM>) is in tension between the corresponding tensioning system (<NUM>, <NUM>, <NUM>) and the first end.