Patent Grant
10577768
Not applicable.
The disclosure relates generally to systems and methods for tethering subsea structures. More particularly, the disclosure relates to systems and methods for enhancing the strength and fatigue performance of subsea blowout preventers, 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 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.
In some aspects, a system for tethering a subsea blowout preventer (BOP) may comprise an anchor disposed about the subsea BOP and secured to the sea floor, and a flexible tension member extending from a first end to a second end coupled to a tensioning system. The flexible tension member may extend horizontally and vertically from the first end to the second end to impart a lateral preload and a vertical preload to the subsea BOP. The tensioning system may include a winch configured to pay in and pay out the flexible tension member. The winch may include a base, a spool rotatably coupled to the base, and a locking mechanism coupled to the spool and the base. The locking mechanism may have a locked position preventing the spool from rotating relative to the base. The winch may be coupled to a frame of the subsea BOP and the first end of the flexible tension member is coupled to the anchor.
In some aspects, a method for tethering a subsea blowout preventer (BOP) coupled to a subsea wellhead to an anchor disposed about the subsea BOP and secured to the sea floor may comprise a step of providing a flexible tension member extending from a first end to a second end coupled to a tensioning system. The tensioning system may include a winch configured to pay in and pay out the flexible tension member. The winch may include a base, a spool rotatably coupled to the base, and a locking mechanism coupled to the spool and the base. The locking mechanism may have a locked position preventing the spool from rotating relative to the base. The method may further comprise the steps of coupling the first end of the flexible tension member to the anchor, coupling the winch to a frame of the subsea BOP, extending the flexible tension member horizontally and vertically from the first end to the second end, imparting a lateral preload and a vertical preload to the subsea BOP, and moving the locking mechanism into the locked position.
In some aspects, a system for tethering a subsea blowout preventer (BOP) may comprise a plurality of anchors disposed about the subsea BOP and secured to the sea floor, a plurality of tensioning systems, which may each be coupled to a frame of the BOP, and a plurality of flexible tension members, which may each be coupled to one of the anchors. Each tension member may extend from a first end coupled to one of the tensioning systems to a second end coupled to an anchor. Each tensioning system may be configured to apply a tensile preload to one of the tension members.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
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
As best shown in
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 there through.
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 reinforce BOP 41, 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 BOP 41, wellhead 50, and conductor 51.
Referring again to
Each tension member 160 includes a first or distal end 160a coupled to frame 47 of BOP 41, and a tensioned span or portion 161 extending from the corresponding winch 140 to end 160a. As best shown in
As best shown in
Winches 140 are positioned proximal to the sea floor 12, and ends 160a are coupled to frame 47 of BOP 41 above winches 140. Thus, each span 161 is oriented at an acute angle α measured upward from horizontal. Since portions 161 are in tension and oriented at acute angles α, the tensile preload L applied to frame 47 of BOP 41 by each span 161 includes an outwardly oriented horizontal or lateral preload Ll and a downwardly oriented vertical preload Lv. Without being limited by this or any particular theory, the lateral preload Ll and the vertical preload Lv applied to BOP 41 by each tension member 160 are a function of the corresponding tensile load L and the angle α. For a given angle α, the lateral preload Ll 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 Ll decreases and the vertical preload Lv increases as angle α increases, and the lateral preload Ll increases and the vertical preload Lv decreases as angle α decreases. For example, at an angle α of 45°, the lateral preload Ll and the vertical preload Lv are substantially the same; at an angle α above 45°, the lateral preload Ll is less than the vertical preload Lv; and at an angle α below 45°, the lateral preload Ll is greater than the vertical preload Lv. In embodiments described herein, angle α of each span 161 is preferably between 10° and 60°, and more preferably between 30° and 45°.
The lateral preloads Ll applied to frame 47 of BOP 41 resist external lateral loads and bending moments applied to BOP 41 (e.g., from subsea currents, riser 43, etc.). To reinforce and stabilize BOP 41, wellhead 50, and primary conductor 51 without interfering with an emergency disconnection of LMRP 42, each height H is preferably as high as possible but below LMRP 42, and may depend on the available connection points along frame 47 of BOP 41. In this embodiment, ends 160a are coupled to frame 47 proximal the upper end of BOP 41 and just below LMRP 42. By tethering frame 47 of BOP 41 at this location, system 100 restricts and/or prevents BOP 41, tree 40, wellhead 50, and primary conductor 51 from moving and bending laterally, thereby stabilizing such components, while simultaneously allowing LMRP 42 to be disconnected from BOP 41 (e.g., via emergency disconnect package) without any interference from system 100.
Referring again to
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., the tensile preload L as well as the tensile loads induced in spans 161 via the application of external loads to BOP 41) without deforming or elongating. Examples of suitable devices for tension members 160 can include, 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 is suitable for subsea use, requires the lowest tensile preload L to pull out any slack, curve, and catenary (˜1.0 ton of tension), and is sufficiently strong to withstand the anticipated tensions.
Referring now to
Referring now to
Referring now to
As previously described, fairlead assemblies 170 are attached to frame 47 by welding bases 171 thereto. However, in other embodiments, the fairlead assemblies (e.g., fairlead assemblies 170) can be bolted to a suitable location of frame 47. Further, although system 100 includes one fairlead assembly 170 disposed at or proximal each of the four side corners of frame 47, in other embodiments, the fairlead assemblies (e.g., fairlead assemblies 170) can be coupled to other suitable locations along frame 47. As previously described, regardless of the means for coupling the fairlead assemblies 170 to frame 47, the fairlead assemblies 170 are preferably positioned along frame 47 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 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.
In the embodiment shown in
Referring now to
Referring now to
Referring now to
Adapter 121 is a generally cylindrical sleeve having a first or upper end 121a, a second or lower end 121b, a radially inner annular shoulder 122, and a receptacle 123 extending axially from lower end 121b to shoulder 122. Receptacle 123 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 121, an annular funnel or guide 125 is disposed at lower end 121b. Adapter 121 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 121b and receptacle 123 until end 110a axially abuts shoulder 122. With end 110a of anchor 110 sufficiently seated in receptacle 123, it is releasable locked therein with locking rams 130 described in more detail below. A guide 125 for tension member 160 is secured to upper end 121a. Tensioning member 160 extends from winch 140 through annular funnel or guide 125 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
Referring now to
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 121a of adapter 121 and support shaft 144 extends into a connection block 147 fixably mounted to upper end 121a of adapter 121. 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
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, actuation system 154 moves lock ring 153 along hub 152 into and out of spool ring 151. More specifically, as best shown in
Referring now to
Referring now to
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
Referring now to
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 frame of BOP (e.g., frame 47 of BOP 41) 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 BOP 41 and a lower likelihood of interference with the BOP 41 (including frame 47), other subsea equipment, and subsea operations.
Referring now to
Referring still to
Moving now to block 182, 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 fairlead assembly 170. In general, assemblies 120 can be installed one at a time, or two or more at the same time.
Next, in block 182, 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 frame 47 of BOP 41 via fairlead assemblies 170. In general, fairlead assemblies 170 can be deployed and installed at any time prior to block 183.
Moving now to block 184, 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 locking 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 pin 173 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 are removed). Once the desired tensile preload L is achieved, locking mechanism 150 is transitioned to and maintained in the locked position.
It should be appreciated that tethering system 100 can be deployed and installed on an existing frame 47 of BOP 41. Thus, system 100 provides an option for reinforcing existing stacks (e.g., BOP 41) before, during, or after drilling operations, completion operations, production operations, or workover operations. Moreover, because pile top assemblies 120 are releasable coupled to piles 110, assemblies 120 and winches 140 mounted thereto can be retrieved and reused at different locations.
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 BOP 41, wellhead 50 and conductor 51 by restricting the lateral/radial movement of BOP 41. As a result, embodiments of tethering system 100 described herein offer the potential to reduce the stresses induced in BOP 41, tree 40, wellhead 50 and primary conductor 51, improve the strength and fatigue resistance of BOP 41, tree 40, wellhead 50 and primary conductor 51, and improve the bending moment response along primary conductor 51 below the sea floor 12.
Referring now to
Referring now to
Referring still to
Distal end 160a of each tension member 160 is coupled to frame 47 of BOP 41, and tensioned span 161 of each tension member 160 extends from the corresponding winch 220 to end 160a. In addition, each distal end 160a is coupled to frame 47 of BOP 41 at a height H measured vertically from the sea floor 12 and at a lateral distance D measured radially and perpendicularly from central axis 55. In this embodiment, 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 5.0 and 15.0 feet, and more preferably about 10.0 feet. However, it should be appreciated that lateral distance D may depend, at least in part, on the available connection points to the frame 47 of BOP 41.
Tensile preload L is provided on each tensioned span 161 of tension members 160 with the corresponding winch 220. With no external loads or moments applied to BOP 41, the actual tension in each span 161 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 41, the actual tension in each span 161 can be greater than or less than the corresponding tensile preload L.
Winches 220 are positioned proximal to the sea floor 12, and ends 160a are coupled to frame 47 of BOP 41 above winches 220. Thus, each span 161 is oriented at an acute angle α measured upward from horizontal. Since portions 161 are in tension and oriented at acute angles α, the tensile preload L applied by each tension member 160 to frame 47 of BOP 41 includes an outwardly oriented horizontal or lateral preload Ll and a downwardly oriented vertical preload Lv. Without being limited by this or any particular theory, the lateral preload Ll and the vertical preload Lv applied to BOP 41 by each tension member 160 are a function of the corresponding tensile load L and angle α. For a given angle α, the lateral preload Ll 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 Ll decreases and the vertical preload Lv increases as angle α increases, and the lateral preload Ll increases and the vertical preload Lv decreases as angle α decreases. For example, at an angle α of 45°, the lateral preload Ll and the vertical preload Lv are substantially the same; at an angle α above 45°, the lateral preload Ll is less than the vertical preload Lv; and at an angle α below 45°, the lateral preload Ll is greater than the vertical preload Lv. In embodiments described herein, angle α of each span 161 is preferably between 10° and 60°, and more preferably between 30° and 45°.
The lateral preloads Ll applied to frame 47 of BOP 41 resist external lateral loads and bending moments applied to BOP 41 (e.g., from subsea currents, riser 43, etc.). To reinforce and/or stabilize BOP 41, wellhead 50, and primary conductor 51 without interfering with an emergency disconnection of LMRP 42, each height H is preferably as high as possible but below LMRP 42, and may depend on the available connection points along frame 47 of BOP 41. In this embodiment, ends 160a are coupled to frame 47 at the upper end of BOP 41, just below LMRP 42. By tethering frame 47 of BOP 41 at this location, system 200 restricts and/or prevents BOP 41, tree 40, wellhead 50, and primary conductor 51 from moving and bending laterally, thereby stabilizing such components, while simultaneously allowing LMRP 42 to be disconnected from BOP 41 (e.g., via emergency disconnect package) without any interference by system 200.
Referring still to
As best shown in
In this embodiment, each shackle assembly 251 includes a load cell 254 that continuously measures the tension in the corresponding tension member 160. 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, in this embodiment, the tensions measured by load cells 254 are communicated acoustically to the surface by a preexisting acoustic communication system housed on BOP 41. Communication of the measured tension in each tension member 160 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.
In the embodiment shown in
Referring again to
Referring now to
One pile top assembly 212 is mounted to upper end 110a of each pile 110. As best shown in
Referring still to
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. 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 winch 220 sufficiently seated in the desired receptacle 218b, it is releasable locked therein. In general, any locking mechanism known in the art can be employed to releasable lock pin 225 of the winch 220 in a given receptacle 218b. In this embodiment, the locking mechanism prevents the winch 220 from moving axially relative to body 218, but allows the winch 220 to rotate about the central axis of the winch pin relative to body 218.
Since each winch 220 is releasable coupled to the corresponding adapter 216 via receptacle 218b, and each adapter 216 is releasable coupled to the corresponding cap 213 and pile 110 via receptacle 214a, winches 220 and adapters 216 can be retrieved to the surface, moved between different subsea piles 110, 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.
As previously described, tensioning systems 220 are releasable coupled to anchors 210 in this embodiment. However, in other embodiments, the tensioning mechanisms (e.g., winches 220) are coupled to the frame of BOP (e.g., frame 47 of BOP 41) 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 tensioning systems 220 coupled to anchors 210 is generally preferred as it generally requires less interaction with BOP 41 and a lower likelihood of interference with the BOP 41 (including frame 47), other subsea equipment, and subsea operations.
Referring now to
In this embodiment, the tensile preload L is applied to tension member 160 by unlocking mechanism 224, and then rotating spool 222 with an ROV operated torque tool engaging interface 223 to pay in tension member 160. The tension member 160 and/or tension measured with the corresponding load cell 254 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 224 is transitioned to and maintained in the locked position. Winch 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 160 when locking mechanism 224 is locked and external loads are applied to BOP 41.
Referring now to
Referring still to
Moving now to block 282, 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 releasable locking pins 219 within receptacles 214, thereby forming anchors 210. In general, adapters 216 can be installed one at a time, or two or more at the same time.
With anchors 210 secured to the sea floor 12, winches 220 are deployed subsea and coupled to adapters 216 in block 283. 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 160 coupled thereto. Next, winches 220 are coupled to adapters 216 by aligning the pin of each winch 220 with the corresponding receptacle 218b, lowering winches 220 to seat the winch pins in receptacles 218b, and then releasable locking the winch pins 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 284, tension members 160 are paid out from winches 220 with locking mechanisms 224 in the unlocked positions, and ends 160a are coupled to frame 47 of BOP 41. In this embodiment, ends 160a are coupled to frame 47 of BOP 41, and in particular the upper end of BOP frame 47, via shackle assemblies 251 and plates 250 as previously described. In general, shackle assemblies 251 and plates 250 can be deployed and installed at any time prior to block 315.
Moving now to block 285, tensile preloads L are applied to tension members 160 as previously described. Namely, the tensile preload L is applied to tension member 160 by unlocking mechanism 224, and then rotating spool 222 with an ROV operated torque tool engaging interface 223 to pay in tension member 224. The tension member 160 and/or tension measured with the corresponding load cell 254 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 224 is transitioned to and maintained in the locked position.
It should be appreciated that tethering system 200 can be deployed and installed on an existing frame 47 of BOP 41. Thus, system 200 provides an option for reinforcing existing stacks (e.g., BOP 41) before, during, or after drilling operations, completion operations, production operations, or workover operations. Moreover, because adapters 216 are releasable coupled to piles 110, and winches 220 are releasable coupled to adapters 216, adapters 216 and/or winches 220 can be reused at different locations.
In the manner described, tethering system 200 is deployed and installed. Once installed and tensile preloads L are applied, tethering system 200 reinforces and/or stabilizes BOP 41, wellhead 50 and conductor 51 by restricting the lateral/radial movement of BOP 41. As a result, embodiments of tethering system 200 described herein offer the potential to reduce the stresses induced in BOP 41, tree 40, wellhead 50 and primary conductor 51, improve the strength and fatigue resistance of BOP 41, tree 40, wellhead 50 and primary conductor 51, and improve the bending moment response along primary conductor 51 below the sea floor 12.
In the embodiments of tethering systems 100, 200 previously described, tension members 160 can comprise Dyneema® rope, and winches 140, 220 include an ROV torque tool interface 148, 223, respectively, and locking mechanism 150, 224. However, in other embodiments, the tension members (e.g., tension members 160) can include different materials and/or different types of tensioning mechanisms (e.g., winches) can be utilized. For example, referring now to
Locking mechanism 324 controls the pay out of chain 360. In this embodiment, locking mechanism 324 includes a locking member or chock 325 pivotally coupled to base 321. Chock 325 pivots about a horizontal axis 326 and includes a pair of parallel arms 327 that are spaced apart a horizontal distance that is substantially the same or slightly greater than the minimum width of a link of chain 360. Thus, a first plurality of links of chain 360 generally lying in a plane parallel to arms 327 and perpendicular to axis 326 can pass between arms 327, however, a second plurality of links of chain 360 generally oriented perpendicular to the first plurality of links (i.e., lying in a plane oriented parallel to axis 326) cannot pass between arms 327. The first plurality of links and the second plurality of links of chain 360 are arranged in an alternating fashion. Therefore, every other link of chain 360 can pass between arms 327, whereas the links therebetween cannot pass between arms 327. Accordingly, when chock 325 is pivoted away from chain 360, chain 360 can be paid in or paid out from chain wheel 322, however, when chock 325 is pivoted into engagement with chain 360, one link of chain 360 (i.e., a link generally lying in a plane parallel to arms 327 and perpendicular to pivot axis 326) is slidingly disposed between arms 327, the adjacent link of chain 360 positioned above arms 327 is prevented from passing between arms 327, thereby preventing chain 360 from being paid out. Therefore, locking mechanism 324 and locking member 325 may be described as having a “locked” position with locking member 325 pivoted into engagement with chain 360 with one link of chain 360 disposed between arms 327, thereby preventing chain 360 from being paid out from chain wheel 322; and an “unlocked” position with locking member 325 pivoted away from chain 360, thereby allowing chain 360 to be paid in and paid out from wheel 322. In this embodiment, locking mechanism 324 and locking member 325 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 324 and locking member 325 to the locked position.
In this embodiment, the tensile preload L is applied to tension member 360 by locking mechanism 324 and locking member 325 to the unlocked position, and then rotating chain wheel 322 with an ROV operated torque tool engaging interface 323 to pay in tension member 360. The tension member 360 and/or the tension in tension member 360 (as measured with the corresponding load cell 254) 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 360 are removed). Once the desired tensile preload L is achieved, locking mechanism 324 is transitioned to and maintained in the locked position. Winch 320, and more specifically locking mechanism 324, has a sufficiently high holding capacity (e.g., on the order of hundreds of tons) to prevent the inadvertent pay out of tension member 360 when locking mechanism 324 is locked and external loads are applied to BOP 41.
In general, the tensile preload L in each chain 360 is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding chain 360. In other words, the tensile preload in L in each chain 360 is preferably the lowest tension that results in that chain 360 extending linearly from the corresponding chain wheel 322 to its distal end coupled to BOP 41. It should be appreciated that such tensile loads L in chains 360 restrict and/or prevent the initial movement and flexing of BOP 41 at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each chain 360 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 41, tree 40, and LMRP 42 in the event one or more chain 360 uncontrollably breaks.
In tethering systems 100, 200 previously described, the tensile preload L is applied to tension members 160 by rotating spool 141 and chain wheel 322, respectively, with an ROV torque tool. However, in other embodiments, alternative means are employed for inducing the tensile preload L in the tension members (e.g., tension members 160, 360). For example, referring now to
The locking mechanism of chain sheave 420 controls the pay out of tension member 460. In particular, the locking mechanism has a “locked” position preventing tension member 460 from being paid out from chain wheel 422, and an “unlocked” position allowing tension member 460 to be paid in and paid out from chain wheel 422. In general, the locking mechanism of each chain sheave 420 can be any suitable locking mechanism known in the art or any locking mechanism described here (e.g., locking mechanism 150, 324 previously described).
Referring again to
Tethering system 400 is generally deployed and installed in the same manner as tethering system 200 previously described. Once tethering system 400 is installed and tensile preloads L are applied to tension members 460, system 400 stabilizes BOP 41, wellhead 50 and conductor 51 to restrict the lateral/radial movement of BOP 41. As a result, embodiments of tethering system 400 described herein offer the potential to reduce the stresses induced in BOP 41, tree 40, wellhead 50 and primary conductor 51, improve the strength and fatigue resistance of BOP 41, tree 40, wellhead 50 and primary conductor 51, and improve the bending moment response along primary conductor 51 below the sea floor 12.
In general, the tensile preload L in each tension member 460 is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding member 460. In other words, the tensile preload in L in each member 460 is preferably the lowest tension that results in that member 460 extending linearly from the corresponding chain wheel 422 to its distal end coupled to BOP 41. It should be appreciated that such tensile loads L in chains 360 restrict and/or prevent the initial movement and flexing of BOP 41 at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each member 460 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 41, tree 40, and LMRP 42 in the event one or more member 460 uncontrollably breaks.
In the embodiments of tethering systems 100, 200, 400 previously described, the distal ends of tensioning members 160, 360, 460 are coupled to frame 47 of BOP 41. 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
In this embodiment, tethering system 500 includes anchors 110 (not visible in
Referring again to
Once tethering system 500 is installed and tensile preloads L are applied with tensioning systems 320. Accordingly, system 500 reinforces BOP 522, wellhead 50 and conductor 51 by restricting the lateral/radial movement of BOP 522. As a result, embodiments of tethering system 500 described herein offer the potential to reduce the stresses induced in BOP 522, tree 40, wellhead 50 and primary conductor 51, improve the strength and fatigue resistance of BOP 522, tree 40, wellhead 50 and primary conductor 51, and improve the bending moment response along primary conductor 51 below the sea floor 12.
In general, the tensile preload L in each member 360 is preferably as low as possible but sufficient to pull out any slack, curve, and catenary in the corresponding member 360. In other words, the tensile preload in L in each member 360 is preferably the lowest tension that results in that member 360 extending linearly from the corresponding chain wheel 322 to its distal end coupled to adapter 560. It should be appreciated that such tensile loads L in members 360 restrict and/or prevent the initial movement and flexing of BOP 41 at the onset of the application of an external loads and/or bending moments, while minimizing the tension in each member 360 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 41, tree 40, and LMRP 42 in the event one or more member 360 uncontrollably breaks.
In the manners described, embodiments of tethering systems 100, 200, 400, 500 described herein apply lateral preloads Ll to subsea BOPs (e.g., BOP 41, 522). The lateral preloads Ll applied to a given BOP are preferably substantially the same and uniformly distributed about the BOP and uniformly applied (i.e., the lateral preloads Ll applied to a given BOP are preferably balanced). Accordingly, the lateral preloads Ll generally seek to maintain the subsea architecture in a generally vertical orientation, reinforce the BOP (e.g., BOP 41, 522), the wellhead (e.g., wellhead 50), the tree (e.g., tree 40) (if provided), and the conductor (e.g., conductor 51) by restricting the lateral/radial movement of the BOP. As a result, embodiments of tethering systems 100, 200, 400, 500 described herein offer the potential to reduce the stresses induced in the BOP, the tree (if provided), the wellhead and the primary conductor, improve the strength and fatigue resistance of the BOP, the tree (if provided), 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.
This application is a continuation of U.S. patent application Ser. No. 15/849,982, which was filed on Dec. 21, 2017, and which is hereby incorporated herein by reference in its entirety. U.S. patent application Ser. No. 15/849,982 is a continuation of U.S. patent application Ser. No. 15/149,825, now U.S. Pat. No. 9,879,396, which was filed on May 9, 2016, and which is hereby incorporated herein by reference in its entirety. U.S. patent application Ser. no. 15/149,825 is a continuation of U.S. patent application Ser. No. 14/313,633, now U.S. Pat. No. 9,359,852, which was filed on Jun. 24, 2014, and which is hereby incorporated herein by reference in its entirety. U.S. patent application Ser. No. 14/313,633 claims priority benefit to U.S. provisional patent application Ser. No. 61/838,709, which was filed on Jun. 24, 2013, and which is hereby incorporated herein by reference in its entirety.
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| Number | Date | Country | |
|---|---|---|---|
| 20190194898 A1 | Jun 2019 | US |
| Number | Date | Country | |
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| 61838709 | Jun 2013 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15849982 | Dec 2017 | US |
| Child | 16266266 | US | |
| Parent | 15149825 | May 2016 | US |
| Child | 15849982 | US | |
| Parent | 14313633 | Jun 2014 | US |
| Child | 15149825 | US |
