WO2012177713A2

WO2012177713A2 - Subsea connector with an actuated latch cap assembly

Info

Publication number: WO2012177713A2
Application number: PCT/US2012/043274
Authority: WO
Inventors: Thomas Patrick MATAWAY; Stanley Leroy BOND; Pierre Albert BEYNET
Original assignee: Bp Corporation North America Inc.
Priority date: 2011-06-20
Filing date: 2012-06-20
Publication date: 2012-12-27
Also published as: WO2012177713A3

Abstract

Methods and devices for forming a subsea connection over an existing subsea connection are described herein. In one embodiment, a subsea connector for forming a sealed connection to a subsea flange connection comprises a connector body having a sealing portion. The connector body has a throughbore running therethrough, and a subsea connection coupled to the connector body. The subsea connector also comprises a latch cap assembly movably disposed around the sealing portion. The latch cap assembly comprises a flange cavity which is configured to completely enclose and couple to an existing subsea connection. The connector body and latch cap assembly together are configurable to form a sealed connection to the subsea connection. In addition, the subsea connector comprises a plurality of bidirectional actuators for moving the latch cap assembly over the connector body. The bidirectional actuators are coupled to the subsea connection and the latch cap assembly.

Description

Subsea Connector with an Actuated Latch Cap Assembly

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No. 61/499,037 filed June 20, 2011, and entitled "Subsea Connector with an Actuated Latch Cap Assembly," which is hereby incorporated herein by reference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable

BACKGROUND

Field of the Invention

[0003] This invention relates generally to systems and methods of subsea operations in the exploration and production of hydrocarbons. More specifically, the invention relates to a method of forming a subsea connection over an existing subsea connection.

Background of the Invention

[0004] In offshore drilling operations, a blowout preventer (BOP) is installed on a wellhead at the sea floor and a lower marine riser package (LMRP) mounted to the BOP. In addition, a drilling riser extends from a flex joint at the upper end of LMRP to a drilling vessel or rig at the sea surface. A drill string is then suspended from the rig through the drilling riser, LMRP, and the BOP into the well bore. A choke line and a kill line are also suspended from the rig and coupled to the BOP, usually as part of the drilling riser assembly.

[0005] 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. In the event of a rapid influx of formation fluid into the annulus, commonly known as a "kick," the BOP and/or LMRP may actuate to seal the annulus and control the well. In particular, BOPs and LMRPs comprise closure members capable of sealing and closing the well in order to prevent the release of gas or liquids from the well. Thus, the BOP and LMRP are used as devices that close, isolate, and seal the wellbore. Heavier drilling mud may be delivered through the drill string, forcing fluid from the annulus through the choke line or kill line to protect the well equipment disposed above the BOP and LMRP from the pressures associated with the formation fluid. Assuming the structural integrity of the well has not been compromised, drilling operations may resume. However, if drilling operations cannot be resumed, cement or heavier drilling mud may be delivered into the well bore to kill the well.

[0006] In the event that the wellbore is not secured in response to a surge of formation fluids in the annulus, a blowout may occur. The blowout may also result in damage to subsea connections of subsea well equipment, such as a subsea flange connection. In addition, it may be challenging to rectify as the damage may be far below the sea surface. A new connection may be needed in order to couple a subsea device such as a capping device to the damaged subsea connection. In cases where the subsea connection uses a flange connection, circumstances may not allow for the separation of the existing connection. Consequently, there is a need for methods and apparatuses for forming a subsea connection over an existing subsea connection.

BRIEF SUMMARY

[0007] These and other needs in the art are addressed in one embodiment by a subsea connector for forming a sealed connection to a subsea flange connection comprising a connector body having a sealing portion. The connector body has a throughbore running therethrough, and a subsea connection coupled to the connector body. The subsea connector also comprises a latch cap assembly movably disposed around the sealing portion. The latch cap assembly comprises a cavity which is configured to completely enclose and couple to an existing subsea connection. The connector body and latch cap assembly together are configurable to form a sealed connection to the subsea connection. In addition, the subsea connector comprises a plurality of bidirectional actuators for moving the latch cap assembly over the connector body. The bidirectional actuators are coupled to the subsea connection and the latch cap assembly.

[0008] In another embodiment, a method of forming a subsea connection comprises positioning a subsea connector adjacent an existing subsea connection. The subsea connector comprises a connector body having a sealing portion. The connector body has a throughbore running therethrough and a subsea connection coupled to the connector body. The latch cap assembly is movably disposed around the sealing portion. The latch cap assembly comprises a cavity configured to completely enclose and couple to an existing subsea connection. The connector body and latch cap assembly together are configurable to form a sealed connection to the subsea connection. The subsea connector also comprises a plurality of bidirectional actuators for moving the latch cap assembly over the connector body. The bidirectional actuators are coupled to the subsea connection and the latch cap assembly. In addition, the method comprises guiding the latch cap assembly so as to enclose the existing subsea connection within the cavity of the latch cap assembly. The method further comprises actuating the subsea connector so as to form a sealed connection with the existing subsea connection.

[0009] In yet another embodiment, capping a subsea well producing hydrocarbons into the surrounding sea comprises positioning a subsea connector adjacent an existing subsea connection. The subsea connector comprises a connector body having a sealing portion. The connector body has a throughbore running therethrough, and a subsea connection coupled to the connector body. The latch cap assembly is movably disposed around the sealing portion. The latch cap assembly comprises a cavity configured to completely enclose and couple to an existing subsea connection. The connector body and latch cap assembly together are configurable to form a sealed connection to the subsea connection. The subsea connector also comprises a plurality of bidirectional actuators for moving the latch cap assembly over the connector body. The bidirectional actuators are coupled to the flange and the latch cap assembly. The method comprises moving the subsea connector laterally over subsea wellbore. In addition, the method comprises guiding the subsea connector into engagement with the existing subsea connection. The method additionally comprises actuating the subsea connector so as to form a sealed connection with the existing subsea connection and coupling a capping device on to the subsea connector to cap the subsea well.

[0010] The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0011] For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: [0012] Figure 1 is a schematic view of an embodiment of an offshore drilling system;

[0013] Figure 2 is an enlarged view of the riser flex joint of the lower marine riser package of

Figure 1;

[0014] Figure 3 is a schematic view of the BOP and the flex joint after substantial removal of the riser;

[0015] Figure 4 A is a cross-sectional side view of an embodiment a subsea connector. In this view, the subsea connector is shown with the latch cap assembly in latched mode;

[0016] Figure 4B is a cross-sectional side view of an embodiment a subsea connector. In this view, the subsea connector is show with the latch cap assembly in deploy mode;

[0017] Figure 4C is a perspective view of an embodiment of a subsea connector;

[0018] Figure 4D is a cross-sectional view of a locking assembly as part of an embodiment of a subsea connector;

[0019] Figure 4E is a cross-sectional view of a retaining assembly as part of an embodiment of a subsea connector;

[0020] Figure 5A is a schematic view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0021] Figure 5B is a schematic view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0022] Figure 5C is a schematic view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0023] Figure 5D is a schematic view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0024] Figure 5E is a cross-sectional view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0025] Figure 5F is a cross-sectional view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0026] Figure 5G is a cross-sectional view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0027] Figure 5H is a cross-sectional view of an embodiment of a subsea connector being installed on to a flex joint flange.

[0028] Figure 6A illustrates a schematic view of an embodiment of a subsea connector installed on the flex joint. [0029] Figure 6B illustrates a schematic view of an embodiment of a subsea connector installed on the flex joint. An embodiment of the subsea connector is shown coupled to a capping device.

NOTATION AND NOMENCLATURE

[0030] Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.

[0031] 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 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.

[0032] As used herein, the term "ROV" refers to remotely operated vehicle. Each ROV may include arms having a claw, a subsea camera for viewing the subsea operations (e.g., the relative positions of subsea tools or devices such as subsea connector 500), and an umbilical. Streaming video and/or images from cameras are communicated to the surface or other remote location via umbilical for viewing on a live or periodic basis. Arms and claws may be controlled via commands sent from the surface or other remote location to ROV through umbilical.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0033] Referring now to Figure 1, an embodiment of an offshore system 100 for drilling and/or producing a wellbore 101 is shown. In this embodiment, system 100 includes an offshore platform 110 at the sea surface 102, a subsea blowout preventer (BOP) 120 mounted to a wellhead 130 at the sea floor 103, and a lower marine riser package (LMRP) 140. Platform 110 is equipped with a derrick 111 that supports a hoist (not shown). A drilling riser 115 extends from platform 110 to LMRP 140. In general, riser 115 is a large-diameter pipe that connects LMRP 140 to the floating platform 110. During drilling operations, riser 115 takes mud returns to the platform 110. Casing 131 extends from wellhead 130 into subterranean wellbore 101.

[0034] Downhole operations are carried out by a tubular string 116 (e.g., drillstring, production tubing string, coiled tubing, etc.) that is supported by derrick 111 and extends from platform 110 through riser 115, LMRP 140, BOP 120, and into cased wellbore 101. A downhole tool 117 is connected to the lower end of tubular string 116. In general, downhole tool 117 may comprise any suitable downhole tool(s) for drilling, completing, evaluating and/or producing wellbore 101 including, without limitation, drill bits, packers, testing equipment, perforating guns, and the like. During downhole operations, string 116, and hence tool 117 coupled thereto, may move axially, radially, and/or rotationally relative to riser 115, LMRP 140, BOP 120, and casing 131.

[0035] BOP 120 and LMRP 140 are configured to controllably seal wellbore 101 and contain hydrocarbon fluids therein. Specifically, BOP 120 has a central or longitudinal axis 125 and includes a body 123 with an upper end 123a releasably secured to LMRP 140, a lower end 123b releasably secured to wellhead 130, and a main bore 124 extending axially between upper and lower ends 123 a, b. Main bore 124 is coaxially aligned with wellbore 101, thereby allowing fluid communication between wellbore 101 and main bore 124. In this embodiment, BOP 120 is releasably coupled to LMRP 140 and wellhead 130 with hydraulically actuated, mechanical wellhead-type connectors 150. In general, connectors 150 may comprise any suitable releasable wellhead-type mechanical connector such as the H-4® profile subsea connector available from VetcoGray Inc. of Houston, Texas or the DWHC profile subsea connector available from Cameron International Corporation of Houston, Texas. Typically, such wellhead-type mechanical connectors (e.g., connectors 150) comprise a male component or coupling that is inserted into and releasably engages a mating female component or coupling. In addition, BOP 120 includes a plurality of axially stacked sets of opposed rams - opposed blind shear rams or blades 127 for severing tubular string 116 and sealing off wellbore 101 from riser 115, and opposed pipe rams 128, 129 for engaging string 116 and sealing the annulus around tubular string 116, and may include opposed blind rams for sealing off wellbore 101 when no string (e.g., string 116) or tubular extends through main bore 124. Each set of rams 127, 128, 129 is equipped with sealing members that engage to prohibit flow through the annulus around string 116 and/or main bore 124 when rams 127, 128, 129 is closed. [0036] Opposed rams 127, 128, 129 are disposed in cavities that intersect main bore 124 and support rams 127, 128, 129 as they move into and out of main bore 124. Each set of rams 127, 128, 129 is actuated and transitioned between an open position and a closed position. In the open positions, rams 127, 128, 129 are radially withdrawn from main bore 124 and do not interfere with tubular string 116 or other hardware that may extend through main bore 124. However, in the closed positions, rams 127, 128, 129 are radially advanced into main bore 124 to close off and seal main bore 124 (e.g., rams 127) or the annulus around tubular string 116 (e.g., rams 128, 129). Each set of rams 127, 128, 129 is actuated and transitioned between the open and closed positions by a pair of actuators 126. In particular, each actuator 126 hydraulically moves a piston within a cylinder to move a drive rod coupled to one ram 127, 128, 129.

[0037] Referring still to Figure 1, LMRP 140 has a body 141 with an upper end 141a connected to the lower end of riser 115, a lower end 141b releasably secured to upper end 123a with connector 150, and a throughbore 142 extending between upper and lower ends 141a, b. Throughbore 142 is coaxially aligned with main bore 124 of BOP 120, thereby allowing fluid communication between throughbore 142 and main bore 124. LMRP 140 also includes an annular blowout preventer 142a comprising an annular elastomeric sealing element that is mechanically squeezed radially inward to seal on a tubular extending through bore 142 (e.g., string 116, casing, drillpipe, drill collar, etc.) or seal off bore 142. Thus, annular BOP 142a has the ability to seal on a variety of pipe sizes and seal off bore 142 when no tubular is extending therethrough.

[0038] Referring now to Figures 1 and 2, in this embodiment, upper end 141a of LMRP 140 comprises a riser flex joint 143 that allows riser 115 to deflect angularly relative to BOP 120 and LMRP 140 while hydrocarbon fluids flow from wellbore 101, BOP 120 and LMRP 140 into riser 115. In this embodiment, flex joint 143 includes a cylindrical base 144 rigidly secured to the remainder of LMRP 140 and a riser extension or adapter 145 extending upward from base 144. A fluid flow passage extending through base 144 and adapter 145 defines the upper portion of throughbore 142. A flex element (not shown) disposed within base 144 extends between base 144 and riser adapter 145, and sealingly engages both base 144 and riser adapter 145. The flex element allows riser adapter 145 to pivot and angularly deflect relative to base 144, LMRP 140, and BOP 120. The upper end of adapter 145 distal base 144 comprises an annular flange 145 a for coupling riser adapter 145 to a mating lower riser flange 118 at the lower end of riser 115 or to alternative devices. As best shown in Figure 2, upper flex joint flange 145a typically includes a plurality of circumferentially-spaced holes that receive bolts for securing upper flex joint fiange 145a to a mating annular flange 118 at the lower end of riser 115. In addition, upper flex joint flange 145a includes a pair of circumferentially spaced guide holes, each guide hole having a diameter greater than the diameter of holes. In this embodiment, flex joint 143 also includes a mud boost line 149 having an inlet (not shown) in fluid communication with flow passages 142, 146, an outlet in flange 145a, and a valve 149c configured to control the flow of fluids through line 149. Although LMRP 140 has been shown and described as including a particular flex joint 143, in general, any suitable riser flex joint may be employed in LMRP 140.

[0039] During a "kick" or surge of formation fluid pressure in wellbore 101, one or more rams 127, 128, 129 of BOP 120 and/or LMRP 140 are normally actuated to seal in wellbore 101. In the event the wellbore 101 is not sealed, a blowout may result.

[0040] Referring to Figure 3, a substantial portion of riser 115 may be severed and removed after a blowout leaving a lower portion 115a remaining. Lower end portion 115a of riser 115 may have an uneven surface. In some instances, lower end portion 115a may have a tapered side profile 115b. In addition, lower end portion 115a remains attached to lower riser flange 118. The combination of lower riser flange 118 and upper flex joint flange 145a may be referred to as the flex joint flange connection 147. As such, in order to cap the well, a connector can be installed which sealingly connects over lower end portion 115a, annular fiange 118 of riser 115, and upper flex joint flange 145a, and additionally provides a generic connection or adapter for coupling a capping device such as a capping stack or a single valve manifold, as described in US Provisional Application Serial No. 61/475,032, filed April 13, 2011, incorporated herein by reference in its entirety for all purposes. Such a connector may preclude the removal of annular fiange 118 and facilitate connection of a capping device or other subsea device.

[0041] Referring now to Figures 5A-5C, an embodiment of a subsea connector 500 is shown. As mentioned above, embodiments of the subsea connector 500 sealingly "latch" or couple to a standard subsea fiange connection and form a sealed connection with a capping device or other subsea device. In general, subsea connector 500 may include a connector body 501 with a standard subsea connection (e.g. flange connection) 503, and a latch cap assembly 520 movably coupled to a connector body 501. Preferably, connector body 501 has a cylindrical geometry. Upper portion 520a of latch cap assembly 520 is disposed circumferentially around sealing portion 501a of connector body 501. In an embodiment, in which subsea connection or coupling 503 comprises a fiange, the flange may have a plurality of circumferentially spaced holes 503a for receiving bolts that secure a capping device or other member to subsea connector 500. In other embodiments, subsea connection or coupling 503 may any subsea connection known to those of skill in the art such as without a limitation, a universal subsea hub connection.

[0042] Latch cap assembly 505 may be moved axially (i.e. up or down) along cylindrical body 501 by means of a plurality of actuators 502. In this embodiment, actuators 502 are hydraulic cylinders. However, it is envisioned that actuators 502 may be any device known to those of skill in the art capable of introducing motion to objects. Examples include without limitation, hydraulic actuators, electro-mechanical actuators, pneumatic actuators, and the like. Actuators 502 are coupled to flange 503 and upper portion 520a of latch assembly 520a. More particularly, actuators 502 may be coupled via a movable connection such as without limitation, a hinged connection. As shown in Figure 5, in this embodiment, actuators 502 are coupled by clevises 502a to flange 503 and upper portion 520a. However, actuators 502 may be coupled by any fasteners or connections known to those of skill in the art. Additionally, any number of actuators 502 may be utilized with embodiments of the subsea connector 500.

[0043] Connector body 501 has a throughbore 504 through which fluids such as hydrocarbons may flow. Connector body 501 includes a sealing portion 501a which has a rim or flanged surface 501b. Rim 501b of sealing portion 501a provides a contacting surface for locking elements 522a and also for upper portion 520a of latch cap assembly 520, as will be described in more detail below. Furthermore, sealing portion 501a of connector body 501 has a sealing member 505 disposed at proximal end 504b of sealing portion 501a. Sealing member 505 forms the sealed connection between subsea connector 500 and flex joint flange connection 147. More particularly, sealing member 505 contacts the outer surface of lower riser portion 115a and is configured to mate with outer surface of lower riser portion 115a. In some instances, lower riser portion 115a has a tapered or angled section. Accordingly, sealing member 505 may have a corresponding angled or beveled inner surface 505a configured to mate with lower riser portion 115a. Preferably, sealing member 505 is made of metal to withstand the pressure exerted on it by actuators 502. However, sealing member 505 may be made of any suitable material such as without limitation, polymers, rubbers, composites, or the like.

[0044] Latch cap assembly 520 has a flange cavity 527 which is configured or adapted to securely enclose a standard subsea flange connection. As shown, flange cavity 527 is configured to enclose and attach or latch to lower riser flange 118 and upper flex joint flange 145 a. However, flange cavity 527 may be configured to engage or couple to any subsea connections known to those of skill in the art. In an embodiment, latch cap assembly 520 includes a plurality of locking assemblies 522 and retaining assemblies 523. Locking assemblies 522 and retaining assemblies 523 are disposed circumferentially around latch cap assembly body 520b. Locking assemblies 522 and retaining assemblies 523 may be arranged such that they are equidistant to each other. In this embodiment, latch cap assembly 520 has eight locking assemblies 522 and six retaining assemblies 523. However, any number of locking assemblies 522 and retaining assemblies 523 may be disposed around latch cap assembly body 520b. Each locking assembly 522 has a locking member 522b which contacts and exerts force on to riser flange 118. Similarly, each retaining assembly 523 has a retaining member 523b which contacts and exert upward force on the flex joint flange 145a. Latch cap assembly 520 further has a plurality of locking assembly holes 522a and retaining assembly holes 523a disposed circumferentially around inner surface 527a of flange cavity 527. Movably disposed within each locking element hole 522a and each retaining member hole 523a are locking members 522b and retaining members 523b, respectively.

[0045] As shown in Figure 5 A, subsea connector 500 is depicted in latched mode or position. Specifically, latched mode means locking members 522a and retaining members 523a are fully extended into flange cavity 527 so as to contact and secure fiex joint assembly 147. In addition, in latched mode or position latch cap assembly 520 has been lowered in full contact with sealing portion 501a of connector body 501. Figure 5B shows the subsea connector 500 in deploy mode in which locking members 522a and retaining members 523a are fully retracted within holes 522b, 532b, respectively. Furthermore, latch cap assembly 520 is shown raised such that there is a space or distance d between upper portion 520a of latch cap assembly 520 and sealing portion 501a of connector body 501.

[0046] Referring now to Figure 5C, a perspective view of an embodiment of subsea connector 500 is shown. In an embodiment, a first guide pin 511 and a second guide pin 512 are coupled to sealing portion 501a of connector body 501. Guide pins 511, 512 extend downwardly from sealing portion 501a through flange cavity 527. Although first and second guide pins 511, 512 may be configured with any geometry and shape, first and second guide pins 511, 512 are preferably configured or adapted to be inserted through existing holes in fiex joint flange connection 147. In one embodiment, first guide pin 511 may be longer than second guide pin 512. In addition, a stop pin 513 is coupled to latch cap assembly body 520b. Stop pin 513 extends downwardly from latch cap assembly body 520b and serves to prevent over- rotation of subsea connector 500 during alignment and installation.

[0047] In a further embodiment, an ROV 516 frame may be disposed circumferentially around latch cap assembly 520. In an embodiment, ROV frame 516 may be constructed of a circular tubular member coupled to latch cap assembly body 520b via frame members 516a. ROV frame 516 may prevent entanglement of ROV cords and hoses during operations as well as providing an additional handle for manipulation by ROVs. Furthermore, an ROV interface panel 518 may be disposed on connector body 510. ROV interface panel 518 may include any ROV interfaces known to those of skill in the art such as dials, handles, hot stabs, and the like. In the embodiment shown in Figure 5 A, ROV interface panel 518 is used to control actuators 502 and move latch cap assembly 520 axially (i.e. up or down) into different positions. However, ROV interface panel 518 may be configured to control any part of subsea connector 500.

[0048] Referring to Figures 5D and 5E, a detailed view of an embodiment of locking assembly 522 and retaining assembly 523 are shown. Locking assembly 522 may include locking member 522a, linear actuator 522d, receptacle 522e, and stop pin 522f. In an embodiment, locking member 522a can have an angled surface 522a- 1 which contacts sealing portion 501a of connector body 501. Locking member 522a is actuated by linear actuator 522d. When subsea connector 500 is initially deployed, locking member 522a is retracted within hole or space 522b. Linear actuator 522d is activated or rotated by an ROV through receptacle 522e. Using linear actuator 522d, locking member 522a may be extended until contacting stop pin 522f. Linear actuators 523d, 522d may be any known linear actuators to those of skill in the art. In the embodiment shown in Figures 5D and 5E, linear actuators 523d, 522d are screw actuators.

[0049] Referring now to Figure 5E, retaining assembly 523 may include retaining member 523 a, linear actuator 523 d, and receptacle 523e. Instead of the angled surface of locking member 522a, retaining member 523a may have a stepped profile 523a-l so as to contact and secure upper flex joint flange 145a. However retaining member 523a may have any suitable profile depending on the type of subsea connection for which the subsea connector 500 is configured. Linear actuators 523d, 522d may extend radially from latch cap assembly body 520b. Receptacles 522e, 523e disposed at the distal end of linear actuators 522d, 523d provide an interface for ROV to actuate retaining members 523a and locking members 522a. More specifically, receptacles 522e, 523e may be configured to receive an ROV tool, where the ROV tool is configured to actuate linear actuators 522e, 523e and extend or retract retaining members 523a and locking members 522a.

[0050] Figures 6A through 6H illustrate the deployment and installation of an embodiment of a subsea connector 500. In operation, subsea connector 500 may be lowered adjacent to the plume through any methods known to those of skill in the art. For subsea deployment and installation of subsea connector 500, one or more ROVs 190 are preferably employed to aid in positioning subsea connector 500, engaging actuators 502 to move latch cap assembly 520 into different positions, and engaging linear actuators 522d, 523d to extend locking members 522a and retaining members 523a into position.

[0051] Referring to Figure 6A, in this embodiment, subsea connector 500 is shown being controllably lowered subsea with a plurality of cables 180 secured to subsea connector 500 and extending to a surface vessel (not shown). Due to the weight of subsea connector 500, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel may be employed to support and lower subsea connector 500 on cables 180. Although cables 180 are employed to subsea connector 500 in this embodiment, in other embodiments, subsea connector 500 may be deployed subsea on a pipe or drill string. In an embodiment, as shown in Figure 6A, subsea connector 500 may be lowered adjacent or laterally offset to the flex joint flange connection 147 in order to avoid formation of hydrates. More particularly, using cables 180, subsea connector 500 is lowered subsea under its own weight from a location generally above and laterally offset from flex joint flange connection 147. More specifically, during deployment, subsea connector 500 is preferably maintained outside of any discharge of hydrocarbon fluids emitted from wellbore 101. One or more ROVs 190 are used to assist in deploying and/or maneuvering subsea connector 500 around flex joint 143.

[0052] Referring now to Figure 6B, once subsea connector 500 has been lowered adjacent to the flex joint 143, subsea connector 500 may be moved laterally into closer proximity to plume so as to align first guide pin 511 over first guide hole 147a. Perfect coaxial alignment of subsea connector 500 and flex joint connection 147, as well as perfect coaxial alignment of pins 511, 512 and mating holes 147a, 147b, may be difficult. With subsea connector 500 appropriately positioned, and guide pins 511, 512 aligned with corresponding holes in flex joint connection 147, cables 180 lower subsea connector 500 axially downward, thereby inserting and axially advancing first guide pin 511 into corresponding hole 147a and inserting and axially advancing guide pin 511 until guide pin 511 is partially inserted as shown in Figure 6B. The frustoconical surface on the lower end of each pin 511, 512 functions to guide each pin 511, 512 into its corresponding hole 147a, 147b even if pins 511, 512 are initially slightly misaligned with holes 147a. 147b.

[0053] First guide pin 511 may be inserted into a first guide hole 147a where latch cap assembly 520 may be oriented such that latch cap assembly body 520b is tangential to outer diameter of flex joint flange connection 147 but such that any hydrocarbons being discharged are not flowing through latch cap assembly 520. That is, the majority of latch cap assembly body 520b is not over existing subsea connection 147. Moving to Figure 6C, subsea connector 500 may then be rotated until second guide pin 512 is aligned over second guide hole 147b and/or stop guide pin 513 contacts outer edge of flex joint flange connection 147. Stop guide pin 513 prevents over-rotation during alignment of subsea connector 500. As shown in Figure 6D, subsea connector 500 may then be lowered over flex joint flange connection 147 so that second guide pin 512 is inserted into second guide hole 147b and until seal member 505 is in contact with lower riser portion 115a.

[0054] In deploy mode, as shown in Figure 6E, locking members 522a and retaining members 523a of subsea connector 500 are retracted within holes 522b, 523b, allowing latch cap assembly 520 to fit over flex joint flange connection 147. In addition, upper portion 520a of latch cap assembly 520 and rim 501b of sealing portion 501a are separated by a space or distance d. By way of ROV manipulation (e.g. hot stabs), actuators 502 are activated and latch cap assembly 520 may be lowered a predetermined distance. Generally, as shown in Figure 6F, latch assembly 520 is lowered to a position where there is a space or distance d2 between retaining members 523a and flex joint flange 145a. Distance d2 may be any suitable distance. In addition, still referring to Figure 6F, further pressure may be applied via actuators 502 to ensure that sealing member 505 is securely seated on to riser portion 118 via receptacles 523e. Upper portion 520a of latch assembly 520 contacts rim 501b of sealing portion 501a and thereby applying pressure to sealing member 505. ROVs may then actuate each retaining assembly 523 such that retaining member 523a are fully extended into flange cavity 527. Now referring to Figure 6G, latch assembly 520 may then be raised with actuators 502 until retaining members 523a contact bottom surface of flex joint flange 145a. Retaining members 523a act as lower clamp members to secure latch assembly 520 to flex joint connection 147.

[0055] Now referring to Figure 6G-H, like the retaining assemblies 523, locking assemblies 522 are actuated by ROVs through receptacles 522e. Locking members 522a are wedged or extended into the space d3 between lower riser flange 118 and latch cap assembly 520 until tightly secured or a predetermined amount of resistance has been met (i.e. torque). The combination of retaining members 523a and locking members 522a securely couple subsea connector 500 to flex joint connection 147, where sealing member 505 forms a fluid tight seal with lower riser portion 115a. Once subsea connector 500 has been secured in place, flange 503 may now serve as a universal connector for a capping device (e.g. capping stacks, BOPs, valves, etc) or other suitable subsea device for capping the well. Figure 7A shows subsea connector 500 installed on flex joint 147. As shown in Figure 7B, for illustrative purposes, subsea connector 500 is shown with a capping device 700. Much like the installation of subsea connector 500, a capping device 700 may be lowered by cables adjacent or laterally offset to flex joint 143. Once in position next to subsea connector 500, capping device 700 is lowered on to flange 503 of subsea connector 500 and then coupled securely to flange 503 to form a fluid tight connection. Although installation of subsea connector 500 and capping device 700 is shown sequentially, it is contemplated that subsea connector 500 and capping device 700 may be deployed or installed simultaneously. In other words, capping device 700 could be coupled to subsea connector 500 and the entire combination may be lowered subsea and installed. Any subsea devices known to those of skill in the art could be connected to subsea connector 500 either via subsea connection (e.g. flange) 503 or welded to the subsea device. Examples of other subsea devices may include without limitation, flex joints, risers, lower marine riser packages, BOPs, valves, chokes, production trees, tubulars, subsea trees, combinations thereof, etc.

[0056] Although embodiments of subsea connector 500 have been discussed with respect to a flex joint flange connection 147 with flanges 118, 145a connected, it is envisioned that subsea connector 500 may be used in situations where lower riser flange 118 has been removed. In such an embodiment, sealing member 505 may have a surface configured or adapted to mate on the surface of upper flex joint flange 145a as opposed to lower riser portion 115a. For example, instead of an angled or tapered profile, sealing member 505 may have a, notched, stepped or completely flat profile.

[0057] Subsea connector 500 may also be used for other purposes besides the capping of a subsea blowout. In an exemplary embodiment, subsea connector 500 may be used to provide a subsea connection in cases where the upper and lower portions of a flange connection are unable to be separated. The installation of subsea connector 500 would be similar as described above with out the complications of having to deal with the discharge of hydrocarbons.

[0058] While the embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described and the examples provided herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. [0059] Any discussion of a reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated herein by reference in their entirety, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.

Claims

CLAIMS What is claimed is:

1. A subsea connector for forming a sealed connection over an existing subsea connection comprising:

a connector body comprising a sealing portion, the connector body comprising a throughbore running therethrough, and a subsea connection coupled to the connector body;

a latch cap assembly movably disposed around the sealing portion, wherein the latch cap assembly comprises a cavity configured to completely enclose and couple to an existing subsea connection, and wherein the connector body and latch cap assembly together are configurable to form a sealed connection to the existing subsea connection; and

a plurality of bidirectional actuators for moving the latch cap assembly over the connector body, the bidirectional actuators coupled to the subsea connection and the latch cap assembly.

2. The subsea connector of claim 1 wherein the sealing portion comprises a sealing member.

3. The subsea connector of claim 2 wherein the sealing member has a beveled inner surface to mate with a tapered riser section.

4. The subsea connector of claim 1, further comprising one or more guide pins extending axially from the latch cap assembly.

5. The subsea connector of claim 1 wherein the plurality of bidirectional actuators are hydraulic cylinders.

6. The subsea connector of claim 1 wherein the cavity of the latch cap assembly is configured to enclose and couple to an existing subsea flange connection.

7. The subsea connector of claim 1, further comprising an ROV interface panel, the ROV interface panel comprising one or more ROV interfaces.

8. The subsea connector of claim 1 wherein the latch cap assembly comprises a plurality of locking assemblies and a plurality of retaining assemblies.

9. The subsea connector of claim 8 wherein the plurality of locking assemblies and the plurality of retaining assemblies extend radially from the latch cap assembly.

10. The subsea connector of claim 8 wherein each locking assembly comprises a locking element coupled to a linear actuator, the locking element actuated by the linear actuator to extend into the cavity of the latch cap assembly.

11. The subsea connector of claim 10 wherein the locking element has at least one angled surface.

12. The method of claim 8 wherein each retaining assembly comprises a retaining element coupled to a linear actuator, the retaining element actuated by the linear actuator to extend into the cavity of the latch cap assembly.

13. The subsea connector of claim 12 wherein the retaining element has a stepped edge.

14. The subsea connector of claim 1 , wherein the subsea connection is a flange connection.

15. A method of forming a subsea connection over an existing subsea connection comprising: a) positioning a subsea connector adjacent an existing subsea connection, the subsea connector comprising: a connector body comprising a sealing portion, the connector body comprising a throughbore running therethrough, and a subsea connection coupled to the connector body; a latch cap assembly movably disposed around the sealing portion, wherein the latch cap assembly comprises a cavity configured to completely enclose and couple to an existing subsea connection, and wherein the connector body and latch cap assembly together are configurable to form a sealed connection to the existing subsea connection; and

a plurality of bidirectional actuators for moving the latch cap assembly over the connector body, the bidirectional actuators coupled to the subsea connection and the latch cap assembly; b) guiding the latch cap assembly so as to enclose the existing subsea connection within the cavity of the latch cap assembly; and c) actuating the subsea connector so as to form a sealed connection with the existing subsea connection.

16. The method of claim 15 wherein the subsea connector comprises a first guide pin and a second guide pin, wherein guiding the latch cap assembly in (b) comprises: bl) positioning the subsea connector until the first guide pin is partially inserted into a first hole in the subsea connection; b2) rotating the subsea connector until latch cap assembly is coaxially aligned with the subsea connection; and b3) positioning the subsea connector until the second guide pin is inserted into a second hole in the subsea connection and the sealing portion abuts the subsea connection.

17. The method of claim 15 wherein the subsea connector further comprises a plurality of locking assemblies and a plurality of retaining assemblies extending radially from the latch cap assembly.

18. The method of claim 16 wherein actuating the subsea connector in (c) further comprises: cl) operating the plurality of bidirectional actuators to lower the latch cap assembly a first distance; c2) actuating the retaining assemblies to extend a plurality of retaining members; c3) operating the plurality of bidirectional actuators to raise the latch cap assembly such that the retaining members contact the existing subsea connection; and c4) actuating the locking assemblies to extend a plurality of locking members to secure the subsea connector to the existing subsea connection.

19. The method of claim 17 wherein (cl) comprises applying pressure via the bidirectional actuators to ensure the sealing portion is sealed against the subsea connection.

20. The method of claim 15 wherein (a) through (c) utilizes one or more ROVs.

21. The method of claim 15 wherein the existing subsea connection is a subsea flange connection.

22. The method of claim 15, further comprising coupling a subsea device to the subsea connector via the subsea connection after (c).

23. The method of claim 22, wherein the subsea device comprises a flex joint, a riser, a lower marine riser package, a BOP, a valve, a chokes, a subsea tree, or combinations thereof.

24. A method of capping a subsea well producing hydrocarbons into the surrounding sea comprising: a) positioning a subsea connector adjacent an existing subsea connection, the subsea connector comprising: a connector body comprising a sealing portion, the connector body comprising a throughbore running therethrough, and a subsea connection coupled to the connector body; a latch cap assembly movably disposed around the sealing portion, wherein the latch cap assembly comprises a cavity configured to completely enclose and couple to an existing subsea connection, and wherein the connector body and latch cap assembly together are configurable to form a sealed connection to the existing subsea connection; and

a plurality of bidirectional actuators for moving the latch cap assembly over the connector body, the bidirectional actuators coupled to the flange and the latch cap assembly; b) moving the subsea connector laterally over subsea wellbore; c) guiding the subsea connector into engagement with the existing subsea connection; d) actuating the subsea connector so as to form a sealed connection with the existing subsea connection; and e) coupling a capping device on to the subsea connector to cap the subsea well.

25. The method of claim 24 wherein the capping device is a BOP, a valve, or combinations thereof.

26. The method of claim 25, wherein (e) comprises coupling the capping device subsea connection of the subsea connector.