Subsea Connector with a Split Clamp Latch Assembly
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 connection comprises a connector body including a sealing portion. The connector body comprises a throughbore running therethrough. The subsea connector also comprises a latch clamp assembly coupled to the sealing portion. The latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection. The connector body and latch clamp assembly together form a sealed connection to the existing subsea connection.
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This application claims benefit of U.S. provisional patent application Ser. No. 61/499,040 filed Jun. 20, 2011, and entitled “Subsea Connector with a Split Clamp Latch Assembly,” which is hereby incorporated herein by reference in its entirety for all purposes.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot applicable
BACKGROUND1. Field of the Invention
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.
2. Background of the Invention
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.
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 high-pressure gas or liquids from the well. Thus, the BOP and LMRP are used as safety 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 high 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 is delivered into the well bore to kill the well.
In the event that the BOP and LMRP fail to actuate or insufficiently actuate in response to a surge of formation fluid pressure in the annulus, a blowout may occur. The blowout may damage subsea well equipment and hardware such as the BOP, LMRP, or drilling riser. This can be problematic if it results in the discharge of hydrocarbons into the surrounding sea water. In addition, it may be challenging to rectify as the damage may be far below the sea surface. In particular, damage to subsea well equipment may result in damage to subsea connections such as a subsea flange connection. 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 SUMMARYThese and other needs in the art are addressed in one embodiment by a subsea connector for forming a sealed connection to an existing subsea connection which comprises a connector body including a sealing portion. The connector body comprises a throughbore running therethrough. The subsea connector also comprises a latch clamp assembly coupled to the sealing portion. The latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection. The connector body and latch clamp assembly together form a sealed connection to the existing subsea connection.
In another embodiment, a method of forming a subsea connection comprises positioning a subsea connector adjacent an existing subsea connection. The subsea connector comprises an connector body comprising a sealing portion. The connector body comprises a throughbore running therethrough. The subsea connector also comprises a latch clamp assembly coupled to the sealing portion. The latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection. The connector body and latch clamp assembly together capable of forming a sealed connection to the existing subsea connection. The method also comprises guiding the subsea connector into engagement with the existing subsea connection. Additionally, the method comprises actuating the subsea connector so as to form a sealed connection with the existing subsea connection.
In another embodiment, a method of forming a subsea connection comprises positioning a subsea connector adjacent an existing subsea connection. The subsea connector comprises an connector body comprising a sealing portion. The connector body comprises a throughbore running therethrough and a subsea connection coupled to the connector body. The subsea connector also comprises a latch clamp assembly coupled to the sealing portion. The latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection. The connector body and latch clamp assembly together form a sealed connection to the existing subsea connection. The method further comprises moving the subsea connector laterally over subsea wellbore. In addition, the method comprises lowering the subsea connector into engagement with the existing subsea connection. The method also 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.
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.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.
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.
As used herein, the term “ROV” refers to remotely operate 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 EMBODIMENTSReferring now to
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.
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 123a, 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, Tex. or the DWHC profile subsea connector available from Cameron International Corporation of Houston, Tex. Typically, such wellhead-type mechanical connectors (e.g., connectors 150) comprise a male component or coupling, labeled with reference numeral 150a herein, that is inserted into and releasably engages a mating female component or coupling, labeled with reference numeral 150b herein. 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, opposed blind rams 128 for sealing off wellbore 101 when no string (e.g., string 116) or tubular extends through main bore 124, and opposed pipe rams 129 for engaging string 116 and sealing the annulus around tubular string 116. 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.
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, 128) or the annulus around tubular string 116 (e.g., rams 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.
Referring still to
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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 may be actuated to seal in wellbore 101. However, in some cases, rams 127, 128, 129 may not seal off wellbore 101, resulting in a blowout.
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As will be described in more detail below, connecting members 525 can move or slide within holes 521a as clamp portions 524a, 524b are moved from an open position to a closed position. Connecting members 525 may be rotatably disposed in holes 527 of clamp portions 524a, 524b. In embodiments, connecting members 525 are threadingly engaged within holes 527 of clamp portions 524a, 524b. As such, when connecting members 525 are rotated, depending on which way connecting members 525 are rotated, clamp portions 524a, 524b are correspondingly moved in a longitudinal direction either up or down. As connecting members 525 are rotated, the threaded portions of connecting members 525 may engage with the corresponding threads within holes 527 and pulls clamp portions 524a, 524b against latch plate 521, thereby ensuring sealing surface 505 is securely seated on riser portion 115a to form a fluid tight seal. Top portions 525a protrude from holes 521a may have a shape suitable for engagement or coupling with an ROV tool. More specifically, top portions may have geometry similar to a nut fastener such as, without limitation, hexagonal, octagonal, rectangular, triangular, and the like. Any suitable geometry may be used.
Still referring to
In an embodiment, clamp portions 524a, 524b are configured to enclose and engage a subsea flange connection 147. More particularly, each clamp portion 524a, 524b may be in the shape of a semi-circle. However, clamp portions 524a, 524b may be of any suitable shape depending on the type of existing subsea connection 147. Clamp portions 524a, 524b may each have inner lips or rims 524c which disposed along the inner top edge 524d and inner bottom edge 524e of clamp portions 524a, 524b as shown clearly in
Latch clamp assembly 520 can also include a plurality of guide rails 522, which help with the deepwater installation of subsea connector 500 over the existing subsea connection 147. Although guide rails 522 are shown to be planar or rectangular in geometry, guide rails 522 may have any geometry suitable for guiding subsea connector 500 into engagement with an existing subsea connection 147. Guide rails 522 have an angled portion 522a and a straight portion 522b. In an embodiment, angled portion 522a of guide rails 522 are outwardly angled or angled away from central axis, a. Angled portion 522a may be disposed at any suitable angle. Furthermore, angled portion 522a may have a straight or curved inner edge 522d. Generally, guide rails 522 are coupled to clamp portions 524a, 524b and/or latch plate 521. In an embodiment, straight portion 522b of guide rails 522 may each have a guidance profile 522c or may be keyed as shown in
Latch assembly 520 has an open position and a closed position as seen in
In a further embodiment, an ROV interface panel (not shown) may be disposed on connector body 510. ROV interface panel may include any ROV interfaces known to those of skill in the art such as dials, handles, hot stabs, and the like. In certain embodiments, ROV interface panel may be used to control actuators or the like on subsea connector 500. However, ROV interface panel may be configured to control any part of 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 and engaging connecting members 525 and connecting rods 523 to move clamp portions 524a, 524b into different positions.
Referring to
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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 surface 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 surface 505 may have a, notched, stepped or completely flat profile.
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 or other subsea connection are unable to be separated. The installation of subsea connector 500 would be similar as described above without the complications of having to deal with the discharge of hydrocarbons. Any subsea devices known to those of skill in the art could be connected to subsea connector 500 either via subsea connection 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.
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.
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
1. A subsea connector for forming a sealed connection to an existing subsea connection comprising:
- a connector body comprising a sealing portion and a throughbore running therethrough; and
- a latch clamp assembly coupled to the sealing portion, wherein the latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection, and wherein the connector body and the latch clamp assembly together form a sealed connection to the existing subsea connection.
2. The subsea connector of claim 1 wherein the sealing portion comprises a sealing surface.
3. The subsea connector of claim 2 wherein the sealing surface has a beveled inner surface to mate with a tapered riser section.
4. The subsea connector of claim 1 wherein the latch clamp assembly further comprises a latch plate, the clamp portions being movably coupled to the latch plate, wherein the clamp portions are movable in at least two different directions, and wherein each clamp portion has one or more rims to engage the existing subsea connection.
5. The subsea connector of claim 1 wherein the clamp portions are movable in a radial direction and a longitudinal direction.
6. The subsea connector of claim 1 wherein each clamp portion is movably coupled to the latch plate by one or more connecting members.
7. The subsea connector of claim 6 wherein the clamp portions are threadingly connected to the one or more connecting members.
8. The subsea connector of claim 1 wherein the clamp portions are movably coupled to each other by one or more connecting rods.
9. The subsea connector of claim 8 wherein the clamp portions are movable from an open position to a closed position by the connecting rods, wherein in the closed position, the clamp portions engage and enclose the existing subsea connection.
10. The subsea connector of claim 9 wherein the clamp portions are spaced apart in the open position.
11. The subsea connector of claim 1, further comprising an ROV interface panel, the ROV interface panel comprising one or more ROV interfaces.
12. The subsea connector of claim 1, further comprising a subsea connection coupled to the connector body.
13. The subsea connector of claim 12 wherein the subsea connection coupled to the connector body is a flange connection.
14. The subsea connector of claim 1, further comprising a sealing cap coupled to the connector body.
15. The subsea connector of claim 1 wherein the existing subsea connection is a flange connection.
16. A method of forming a subsea connection comprising:
- a) positioning a subsea connector adjacent an existing subsea connection, the subsea connector comprising:
- a connector body comprising a sealing portion and a throughbore running therethrough; and
- a latch clamp assembly coupled to the sealing portion, wherein the latch clamp assembly comprises at least a first clamp portion and a second clamp portion which are movable to couple to an existing subsea connection, and wherein the connector body and the latch clamp assembly together form a sealed connection to the existing subsea connection;
- b) guiding the subsea connector into engagement with the existing subsea connection; and
- c) actuating the subsea connector so as to form a sealed connection with the existing subsea connection.
17. The method of claim 16 wherein (c) comprises actuating the clamp portions into a closed position so as to enclose the existing subsea connection within the clamp portions;
18. The method of claim 17 wherein actuating the subsea connector in (c) further comprises rotating one or more connecting rods coupled between the clamp portions to move the clamp portions into the closed position.
19. The method of claim 18 wherein actuating the subsea connector in (c) further comprises tightening one or more connecting members to secure the sealing portion of the connector body to the existing subsea connection.
20. The method of claim 16 wherein (a) through (c) utilizes one or more ROVs.
21. The method of claim 16 wherein the existing subsea connection is a subsea flange connection.
22. The method of claim 16, wherein the subsea connector further comprises a subsea connection coupled to the connector body.
23. The method of claim 22, further comprising coupling a subsea device to the subsea connector via the subsea connection after (c).
24. The method of claim 23, 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.
25. 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 and a throughbore running therethrough, and a subsea connection coupled to the connector body; and
- a latch clamp assembly coupled to the sealing portion, wherein the latch clamp assembly comprises at least a first clamp portion and a second clamp portion movable to couple to an existing subsea connection, and wherein the connector body and latch clamp assembly together form a sealed connection to the existing subsea connection;
- 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.
26. The method of claim 25 wherein the capping device is a BOP, a valve, or combinations thereof
27. The method of claim 26, wherein (e) comprises coupling the capping device to the subsea connection of the subsea connector.
Type: Application
Filed: Jun 19, 2012
Publication Date: Jan 17, 2013
Applicant: BP CORPORATION NORTH AMERICA INC. (HOUSTON, TX)
Inventor: JOSEPH KILLEEN (THE WOODLANDS, TX)
Application Number: 13/527,144
International Classification: E21B 17/04 (20060101); E21B 41/04 (20060101);