RELEASABLE CONNECTIONS FOR SUBSEA FLEXIBLE JOINTS AND SERVICE LINES

Abstract

A method for shutting in a subsea wellbore is described, comprising disconnecting a flexible joint from the lower marine riser package subsea after a subsea blowout. The flexible joint is releasably connected to the lower marine riser package with a first connection comprising a connector with a receptacle and a hub seated in the receptacle. The method further comprises positioning a containment cap subsea proximate to the lower marine riser package. In addition, the method comprises connecting the containment cap to the lower marine riser package. The containment cap is releasably connected to the lower marine riser package with a second connection comprising a connector with a receptacle and a hub seated in the receptacle. Furthermore, the method comprises substantially shutting in the wellbore with the containment cap.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Invention

The invention relates generally to the subsea flexible joints attached to lower marine riser packages or blowout preventer stacks. More particularly, the invention relates to flexible joints and associated service lines that are releasably connected to lower marine riser packages or blowout preventer stacks.

2. Background of the Technology

In offshore drilling operations, a blowout preventer (BOP) stack is installed on a wellhead at the sea floor and a lower marine riser package (LMRP) is mounted to the BOP. In addition, a flexible joint is attached to the upper end of the LMRP and is coupled to drilling riser that extends upward to a drilling vessel or rig at the sea surface. Typically, the flexible joint is connected to the LMRP with a bolted flange joint designed to be made up by personnel at the surface (e.g., drilling rig personnel). Consequently, such connections are not designed to be disconnected subsea. A drill string is then suspended from the rig through the drilling riser, flexible joint, LMRP, and the BOP stack into the well bore.

Service lines such as choke lines and kill lines are also suspended from the rig and run along, but external to, the drilling riser. At the flexible joint, the service lines are connected to flexible pipes or compliant sections of rigid pipe to allow for the movement of the flexible joint without kinking or straining the services lines. The lower end of each flexible pipe or compliant section of rigid pipe is rigidly secured to an upper end a corresponding flow line of the LMRP and/or BOP stack. Together, the services lines and flow lines enable fluids to be supplied to the LMRP and BOP as well as removed from the LMRP and BOP. Typically, the service lines are rigidly secured to the corresponding LMRP-BOP flow lines with clamps designed to be made up by personnel at the surface (e.g., drilling rig personnel). Consequently, such connections are not designed to be disconnected subsea.

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, and drilling riser. In addition, it may be challenging to rectify remotely as the damage may be hundreds or thousands of feet below the sea surface.

One approach to containing and controlling discharged hydrocarbons resulting from a subsea blowout is to deploy and connect a capping stack or containment cap to the subsea wellhead, BOP, or LMRP to contain the wellbore and shut off the flow of hydrocarbons into the surrounding environment. Depending on a variety of factors such as the damage to subsea equipment (e.g., BOP, LMRP, riser, etc.) and accessibility of certain subsea connections, it may not be desirable or practical to remove the BOP from the wellhead to install the capping stack directly on to the wellhead, or to remove the LMRP from the BOP to install the capping stack directly on to the BOP. In such cases, the most practical landing site and connection point for the capping stack may be the LMRP. However, as previously described, the flexible joint is conventionally attached to the LMRP with a bolted connection designed to be manually made-up by hand-tools at the surface, and further, service lines are conventionally attached to mating flow lines of the LMRP and BOP with clamp connections designed to be manually made-up by hand-tools at the surface. Consequently, such conventional, generally rigid and fixed connections may be very difficult to disconnect subsea. Further, disconnecting these connections subsea with ROV operated tools (e.g., saws, grinders, etc.) may damage the flexible joint and/or LMRP and BOP flow lines beyond repair or render subsequent mounting of the capping stack and connection of new services lines difficult. Breaking such connections with subsea ROV operated tools may also be a tedious and time consuming process during which hydrocarbons continue to be discharged subsea.

Accordingly, there remains a need in the art for connections between subsea flexible joints and LMRPs, as well as connections between service lines and BOP-LMRP flow lines, that are more easily broken and made-up subsea. Such connections would be particularly well-received if they offered the potential to simplify the subsea removal of subsea flexible joints and service lines, reduce the time required to do so, and reduce the likelihood of further damage to subsea hardware.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a method for shutting in a subsea wellbore. The subsea wellbore has a wellhead, a subsea blowout preventer stack is mounted to the wellhead, and a lower marine riser package is mounted to the blowout preventer stack. The method comprises (a) disconnecting a flexible joint from the lower marine riser package subsea after a subsea blowout. The flexible joint is releasably connected to the lower marine riser package with a first connection comprising a connector with a receptacle and a hub seated in the receptacle. The method further comprises (b) positioning a containment cap subsea proximate to the lower marine riser package. In addition, the method comprises connecting the containment cap to the lower marine riser package. The containment cap is releasably connected to the lower marine riser package with a second connection comprising a connector with a receptacle and a hub seated in the receptacle. Furthermore, the method comprises (d) substantially shutting in the wellbore with the containment cap.

These and other needs in the art are addressed in another embodiment by a method for shutting in a subsea wellbore. The wellbore includes a wellhead, a subsea BOP is mounted to the wellhead, an LMRP is mounted to the BOP, a flexible joint is connected to the LMRP, and a riser extends from the flexible joint. In an embodiment, the method comprises (a) removing the flexible joint from the subsea lower marine riser package by actuating a connector at a lower end of the flexible joint to unlock from a hub at an upper end of the lower marine riser package. In addition, the method comprises (b) positioning a containment cap subsea from a surface vessel to a position laterally adjacent the subsea lower marine riser package. Further, the method comprises (c) moving the containment cap laterally over the subsea lower marine riser package after (b). Still further, the method comprises (d) lowering the containment cap axially downward into engagement with the subsea lower marine riser package. Moreover, the method comprises (e) securing the containment cap to the subsea lower marine riser package.

In an embodiment, a subsea drilling riser system comprises a BOP stack. The BOP stack includes a plurality of ram BOPs. In addition, the system comprises an LMRP coupled to the BOP stack. Further, the system comprises a flexible joint releasably connected to the LMRP and configured to be coupled to a riser. The releasable connection is configured to allow the flexible joint to be quickly disconnected from the LMRP subsea. The system additionally comprises a choke and kill line coupled to the blowout preventer stack. The service line is releasably connected to the choke and kill line with a flow-line connection configured to allow the service line to be disconnected from the choke and kill line subsea.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic view of an offshore drilling system including an embodiment of a BOP stack in accordance with the principles described herein;

FIG. 2 is an enlarged schematic view of the BOP stack of FIG. 1;

FIG. 3 is an enlarged schematic view of the offshore drilling system of FIG. 1 damaged by a subsea blowout;

FIG. 4 is an enlarged schematic view of the BOP stack of FIG. 1 with the flexible joint and riser service lines removed; and

FIGS. 5-9 are sequential schematic views of the deployment and installation of an exemplary containment cap onto the BOP stack of FIG. 4.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate 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 FIGS. 1 and 2, 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 BOP stack 120 mounted to a wellhead 130 at the sea floor 103, an LMRP 140 connected to BOP stack 120, and a flexible joint 160 coupled to LMRP 140. Platform 110 is equipped with a derrick 111 that supports a hoist (not shown). A drilling riser 113 extends from platform 110 to flexible joint 160. In general, riser 113 is a large-diameter pipe that connects flexible joint 160 to the floating platform 110. During drilling operations, riser 113 takes mud returns to the platform 110. In addition, a plurality of service lines 170 are suspended from platform 110 and extend subsea to choke and kill lines 180 coupled to BOP stack 120 and LMRP 140. As shown in FIGS. 1 and 2, service lines 270 are choke and kill lines. However, the service lines extending from the surface to BOP stack 120 and LMRP 140 (e.g., service lines 170) may also include a mud boost line and a hydraulic fluid supply line. Casing 131 extends from wellhead 130 into subterranean wellbore 101.

Downhole operations are carried out by a tubular string 117 (e.g., drillstring, production tubing string, coiled tubing, etc.) that is supported by derrick 111 and extends from platform 110 through riser 113, flexible joint 160, LMRP 140, BOP stack 120, and into cased wellbore 101. A downhole tool 118 is connected to the lower end of tubular string 117. In general, downhole tool 118 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 117, and hence tool 118 coupled thereto, may move axially, radially, and/or rotationally relative to riser 113, flexible joint 160, LMRP 140, BOP stack 120, and casing 131.

BOP stack 120 and LMRP 140 are configured to controllably seal wellbore 101 and contain hydrocarbon fluids therein. Specifically, BOP stack 120 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 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 stack 120 is releasably coupled to LMRP 140 and wellhead 130 with hydraulically actuated, mechanical wellhead connections 150.

Typically, connections 150 comprise a downward-facing mating female connector, labeled 150a herein, with a receptacle that receives an upward-facing male connector or “hub,” labeled 150b herein. Each connector 150a is hydraulically actuated between a “locked” positively engaging its corresponding hub 150b and an “unlocked” position disengaged from its corresponding hub 150b. With connector 150a in the “unlocked” position, hub 150b can be axially inserted into or axially pulled from connector 150a. However, with connector 150a in the “locked” position, hub 150b cannot be axially inserted into or removed from connector 150a. Thus, each connector 150a is lowered axially onto its corresponding hub 150b in the unlocked position to seat hub 150b therein, and then hydraulically actuated to the locked position positively engaging the hub 150b to form a secure and rigid connection therebetween. To disconnect a connector 150a from its corresponding hub 150b, connector 150a is hydraulically actuated to the unlocked position, and then, axially lifted off hub 150b. In general, each connector 150a and each hub 150b may comprise any suitable combination of mating connector and hub. Examples of suitable hubs for use as one or more hubs 150b include, without limitation, standard wellhead hubs and mandrels such as HC and DWHC profile wellhead hubs available from Cameron International Corporation of Houston, Tex., H4® mandrel-style hubs available from GE Vetco of Houston, Tex., and the like. Examples of suitable connectors for use as one or more connectors 150a include, without limitation, Model 70, HC, HCH4, and DWHC Collet Connectors available from Cameron International Corporation of Houston, Tex.; H-4® connectors available from VetcoGray Inc. of Houston, Tex.; connectors compatible with the HC and H4 hub profiles available from FMC Technologies of Houston, Tex., Dril-Quip of Houston, Tex. and Aker Solutions, Norway, and the like.

BOP stack 120 also includes a plurality of axially stacked ram BOPs 127. Each ram BOP 127 includes a pair of opposed rams for seating off wellbore 101. In general, the opposed rams in each ram BOP 127 may include any suitable types of rams including, without limitation, opposed blind shear rams or blades for severing tubular string 117 and sealing off wellbore 101 from riser 113, opposed blind rams for sealing off wellbore 101 when no string or tubular extends through main bore 124, or opposed pipe rams for engaging string 117 and sealing the annulus around tubular string 117. Each set of opposed rams is equipped with sealing members that engage to prohibit flow through the annulus around string 117 and/or main bore 124 when that particular set of rams is closed.

The opposed rams of each ram BOP 127 are disposed in cavities that intersect main bore 124 and support the rams as they move radially into and out of main bore 124. Each set of rams is actuated and transitioned between an open position and a closed position. In the open positions, the rams are radially withdrawn from main bore 124 and do not interfere with tubular string 117 or other hardware that may extend through main bore 124. However, in the closed positions, the rams are radially advanced into main bore 124 to close off and seal main bore 124 or the annulus around tubular string 117. Each set of rams 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.

Referring still to FIGS. 1 and 2, LMRP 140 has a body 141 with an upper end 141a releasably secured to flexible joint 160 with a connection 150, a lower end 141b releasably secured to upper end 123a with a connection 150, and a throughbore 142 extending between upper and lower ends 141a, b. Throughbore 142 is coaxially aligned with main bore 124 of BOP 110, 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 117, 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.

As previously described, in this embodiment, BOP stack 120 includes three sets of ram BOPs, however, in other embodiments, the BOP stack (e.g., BOP stack 120) may include a different number of rams, different types of rams, an annular BOP, or combinations thereof. Likewise, although LMRP 140 is shown and described as including one annular BOP 142a, in other embodiments, the LMRP (e.g., LMRP 140) may include a different number of annular BOPs, one or more ram BOPs, or combinations thereof.

Referring still to FIGS. 1 and 2, riser flexible joint 160 allows riser 113 to deflect angularly relative to BOP stack 120 and LMRP 140 while hydrocarbon fluids flow from wellbore 101, BOP stack 120 and LMRP 140 into riser 113. Flexible joint 160 has an upper end 160a, a lower end 160b, and a fluid passage 162 extending axially between ends 160a, b. Upper end 160a comprises an annular flange 161 bolted to a mating flange at the lower end of riser 113, and lower end 160b is releasably secured to LMRP 140 with a connection 150. Fluid passage 162 is in fluid communication with bores 142, 124 of LMRP 140 and BOP stack 120, respectively.

In this embodiment, flexible joint 160 includes a cylindrical base 163 extending from lower end 1160b and a riser extension or adapter 164 pivotally coupled to and extending upward from base 163 to upper end 160a. Fluid passage 162 extends through base 163 and adapter 164. A flexible element (not shown) disposed within base 163 is positioned radially between base 163 and riser adapter 164, and sealingly engages both base 163 and riser adapter 164. The flexible element allows riser adapter 164 to pivot and angularly deflect relative to base 163, LMRP 140, and BOP stack 120.

As previously described, a choke service line 170 and a kill service line 170 extend subsea along rise 113 from platform 110 to choke and kill lines 180 of LMRP 140 and BOP stack 120. In general, choke and kill services lines 170 are employed to supply fluids (e.g., kill fluids, chemicals, hydraulic fluid, etc.) BOP stack 120 and/or LMRP 140 via lines 180, as well as receive fluids (e.g., fluid samples, choke fluids, etc.) from BOP stack 120 and/or LMRP 140 via lines 180. Although services lines 170 are external to riser 113, they extend along the outside of riser 113 and may be coupled thereto at periodic intervals along the length of riser 113.

Each services line 170 has a first section or segment 171 extending from platform 110 to flexible joint 160 and second section or segment 172 extending from flexible joint 160 to LMRP 140. First segments 171 are generally rigid and placed in tension between platform 110 and flexible joint 160, whereas second segments 172 are flexible and include some slack between flexible joint 160 and lines 180 to allow riser adapter 164 to pivot relative to base 163, LMRP 140, and BOP stack 120 without kinking, straining, or damaging lines 170. In other words, second segments 172 are not in tension and have axial lengths greater than the minimum distance between flexible joint 160 and lines 180.

Each service line 170 is releasably connected to one choke and kill line 180 with a hydraulically actuated, mechanical flow line connection 190. Typically, connections 190 comprise a downward-facing mating female flow-line connector, labeled 190a herein, that receives and releasably locks onto an upward-facing male flow-line connector or “hub,” labeled 190b herein. Each connector 190a is hydraulically actuated between a “locked” positively engaging its corresponding hub 190b and an “unlocked” position disengaged from its corresponding hub 190b. With connector 190a in the “unlocked” position, hub 190b can be axially inserted into or axially pulled from connector 150a. However, with connector 190a in the “locked” position, hub 190b cannot be axially inserted into or removed from connector 190a. Thus, each connector 190a is lowered axially onto its corresponding hub 190b in the unlocked position to seat hub 190b therein, and then hydraulically actuated to the locked position positively engaging the hub 190b to form a secure and rigid connection therebetween. To disconnect a connector 190a from its corresponding hub 190b, connector 190a is hydraulically actuated to the unlocked position, and then, axially lifted off hub 190b. In general, each connector 190a and each hub 190h may comprise any suitable combination of mating flow-line connector and hub. Examples of suitable small bore hubs for use as one or more hubs 190b include, without limitation, #6 mini-connector hubs available from Cameron International Corporation of Houston, Tex., and the like. Examples of suitable connectors for use as one or more connectors 190a include, without limitation, 3 1/16 inch Mini-connectors available from Cameron International Corporation of Houston, Tex., and the like.

Referring now to FIG. 3, during a “kick” or surge of formation fluid pressure in wellbore 101, one or more rams 127 of BOP stack 120 and/or annular BOP 142a of LMRP 140 are normally actuated to seal in wellbore 101. However, in some cases, rams 127 and annular BOP 142a may not seal off wellbore 101, resulting in a blowout. Such a blowout may damage BOP stack 120, LMRP 140, riser 113, platform 110, or combinations thereof. Damage to subsea BOP stack 120, LMRP 140, or riser 113 may compromise the ability to contain wellbore 101 and the hydrocarbon fluids therein, potentially resulting in the discharge of such hydrocarbon fluids subsea. In FIG. 3, system 100 is shown after a subsea blowout due to failure or malfunction of rams 127 and annular BOP 142a. As shown in FIG. 3, a portion of riser 113 has been removed as well as lines 170, 171. As a result, hydrocarbon fluids flowing upward in wellbore 101 pass through BOP stack 120 and LMRP 140, and may be discharged into the surrounding sea water.

As previously described, one approach to reducing and/or eliminating the subsea discharge of hydrocarbon fluids, is to deploy and connect a capping stack or containment cap to the subsea wellhead, BOP, or LMRP, and utilize the capping stack to shut off the flow of hydrocarbons into the surrounding environment. There are several possible locations at which the capping stack could be mounted. For example, the capping stack could be mounted to BOP stack 120 after removing LMRP 140 from BOP stack 120 or mounted to wellhead 130 after removing BOP stack 120 and LMRP 140 from wellhead 130. In some cases, it may be desirable to remove flexible joint 160 and service lines 170 from LMRP 140 and then mount the capping stack directly onto LMRP 140. With conventional LMRPs, this may be very difficult because the flexible joint is typically manually attached to the LMRP at the surface with a bolted connection and service lines are typically attached to choke and kill lines with clamp connections manually made-up at the surface. The connections between conventional flexible joints and LMRPs and between conventional service lines and choke and kill lines are not designed or adapted to be disconnected in a remote subsea environment. However, in embodiments described herein, hydraulically actuated, mechanical connection 150 between flexible joint 160 and LMRP 140 are designed and configured for remote disconnection of flexible joint 160 from LMRP 140, and hydraulically actuated, mechanical small-bore flow line connections 190 between service lines 170 and lines 180 are designed and configured for remote disconnection of service lines 170 from lines 180.

Referring now to FIGS. 3 and 4, to prepare for the landing and mounting of a capping stack to LMRP 140, connector 150a is hydraulically actuated to the unlocked position and each connector 190a is hydraulically actuated to the unlocked position. With connector 150a unlocked, flexible joint 160 and damaged riser 113 are removed from LMRP 140. For example, riser 113 may be cut from flexible joint 160 with one or more subsea ROVs, and then, flexible joint 160 may be lifted from LMRP 140 with wireline or a pipe string extending from a surface vessel (e.g., platform 110, surface boat, etc.). Further, with connectors 190a unlocked, service lines 170 are removed from choke and kill lines 180. By unlocking connector 150a at the lower end of flexible joint 160 from hub 150b at the upper end of LMRP 140, flexible joint 160 may be removed from LMRP 140 with relative ease; and by unlocking connectors 170a at the lower ends of service lines 170 from hubs 170b at the upper ends of choke and kill lines 180, service lines 170 may be removed from choke and kill lines 180 with relative ease. Once flexible joint 160, riser 113, and service lines 170 are disconnected and cleared, the capping stack may be deployed and mounted to LMRP 140, and in particular, mounted to upward-facing hub 150b at the upper end of LMRP 140.

Referring now to FIGS. 5-9, an exemplary embodiment of a capping stack or containment cap 200 is shown being deployed subsea and installed subsea on to LMRP 140 following removal of flexible joint 160, riser 113, and service lines 170. Once installed, containment cap 200 is used to shut-in wellbore 101 previously described (FIG. 3) and contain the hydrocarbon fluids therein.

In this embodiment, containment cap 200 is a BOP stack 210 including a body 212 with a first or upper end 212a, a second or lower end 212b, and a main bore 213 extending axially between ends 212a, b. In this embodiment, upper end 212a comprises an upward-facing hub 150b as previously described and lower end 212b comprises a downward-facing connector 150a as previously described. In addition, BOP stack 210 includes two sets of axially stacked sets of ram BOPs 127 as previously described. Each ram BOP 127 includes a pair of opposed rams for sealing off main bore 213. BOP stack 210 also includes choke and kill lines 216, which are configured to supply fluids to and receive fluids from BOP stack 210. Each choke and kill line 216 has an upper end 216a comprising an upward-facing flow-line hub 190b as previously described.

As compared to relatively large three and four ram BOP stacks (e.g., BOP stack 110), two ram BOP stack 210 may generally be considered a light weight stack. Although containment cap 200 is shown and described as a BOP stack in this embodiment, in general, the containment cap may comprises other devices for capping, containing, and controlling hydrocarbons in wellbore 101. In some embodiments, the containment cap may be employed to produce wellbore 101 following containment and control of wellbore 101. For instance, such embodiments may be useful for allowing some level of flow from the well to prevent over-pressuring the wellbore. Other examples of containment caps and capping stacks that may be installed onto LMRP 140 to contain and control wellbore 101 are disclosed in U.S. Provisional Patent Application Ser. No. 61/498,269 filed Jun. 17, 2011, and entitled “Air-Freightable Containment Cap for Containing a Subsea Well,” and U.S. Provisional Patent Application Ser. No. 61/475,032 filed Apr. 13, 2011, and entitled “Systems and Methods for Capping a Subsea Well,” each of which is hereby incorporated herein by reference in its entirety.

For subsea deployment and installation of containment cap 200, one or more remote operated vehicles (ROVs) 300 are preferably employed to aid in positioning cap 200, and monitoring cap 200, LMRP 140, BOP stack 120, and wellhead 130. Subsea ROVs 300 may also be used to actuate connectors 150a, 190a, and facilitate the disconnection and removal of flexible joint 160 and services lines 170 previously described. In this embodiment, each ROV 300 includes an arm 301 having a claw 302, a subsea camera 303 for viewing the subsea operations (e.g., the relative positions of cap 200. LMRP 140, BOP stack 120, the positions and movement of arms 301 and claws 302, etc.), and an umbilical 304. Streaming video and/or images from cameras 303 are communicated to the surface or other remote location via umbilical 304 for viewing on a live or periodic basis. Arms 301 and claws 302 are controlled via commands sent from the surface or other remote location to ROV 300 through umbilical 304.

Referring now to FIG. 5, containment cap 200 is shown being controllably lowered subsea with a pipestring 220 extending from a surface vessel and releasably coupled to hub 150b at upper end 212a. A derrick or other suitable device mounted to the surface vessel is (preferably employed to support and lower cap 200 on string 220. Although string 220 is employed to lower cap 200 in this embodiment, in other embodiments, cap 200 may be deployed subsea on wireline. Using string 220, cap 200 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101 and BOP stack 120. Specifically, lowering cap 200 subsea directly over a plume of hydrocarbons may trigger the formation of hydrates within cap 200, particularly at elevations substantially above sea floor 103 where the temperature of hydrocarbons is relatively low.

Moving now to FIG. 6, cap 200 is lowered laterally offset from LMRP 140 until lower end 212b is slightly above hub 150b at the upper end 141a of LMRP 140. As containment cap 200 descends and approaches LMRP 140, ROVs 300 monitor the position of cap 200 relative to LMRP 140. Next, as shown in FIGS. 7 and 8, cap 200 is moved laterally into position immediately above LMRP 140 with downward-facing connector 150a at lower end 212b generally coaxially aligned with upward-facing hub 150a at upper end 141a of LMRP 140. One or more ROVs 300 may utilize their claws 302 to guide and position cap 200 relative to LMRP 140.

With containment cap 200 positioned immediately above LMRP 140, and connector 150a substantially coaxially aligned with hub 150b, pipestring 220 lowers cap 200 axially downward. Due to the weight of cap 200, compressive loads between cap 200 and LMRP 140 urge the male hub 150b at upper end 141a into the female connector 150a at lower end 212b. Once hub 150b is sufficiently seated in connector 150a, connector 150a is hydraulically actuated and transitioned to the locked position to securely connect cap 200 to LMRP 140 as shown in FIG. 8.

Prior to moving cap 200 laterally over LMRP 140, rams 127 are transitioned to the open position allowing hydrocarbon fluids emitted by LMRP 140 to flow unrestricted through cap 200, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of cap 200 to LMRP 140. Rams 127 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 300. Thus, as cap 200 is moved laterally over LMRP 140 and lowered into engagement with LMRP 140, emitted hydrocarbon fluids flow freely through cap 200.

With a secure connection 150 between cap 200 and LMRP 140, one or both rams 127 are transitioned to the closed position with an ROV 300, thereby shutting off the flow of hydrocarbons emitted from wellbore 101. As shown in FIG. 9, string 220 may be decoupled from cap 200 with ROVs 300 and removed to the surface once cap 200 is locked onto LMRP 140.

Referring now to FIG. 9, once connection 150 is secure, choke and kill lines 216 of cap 200 are releasably connected to a first set of service lines 240 and choke and kill lines 180 of BOP stack 120 and LMRP 140 are releasably connected to a second set of service lines 240. In particular, the lower end of each service line 240 comprises a small bore flow-line connector 190a that is releasably locked onto a mating flow-line hub 190b at the upper end of one choke and kill line 216, 180; the flow-line hub 190b at the upper end of each choke and kill line 216, 280 is seated in one mating flow-line connector 190a at the lower end of one service line 240, and then the connector 190a is hydraulically actuated and transitioned to the locked position. Fluids may be supplied to or received from lines 216, 180 via service lines 240. In general, service lines 240 may be any suitable rigid or flexible conduit extending subsea from a surface vessel or from another subsea location.

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.

Claims

1. A method for shutting in a subsea wellbore, the subsea wellbore having a wellhead, a subsea blowout preventer stack is mounted to the wellhead, and a lower marine riser package is mounted to the blowout preventer stack, the method comprising: (a) disconnecting a flexible joint from the lower marine riser package subsea after a subsea blowout, wherein the flexible joint is releasably connected to the lower marine riser package with a first connection comprising a connector with a receptacle and a hub seated in the receptacle;(b) positioning a containment cap subsea proximate to the lower marine riser package;(c) connecting the containment cap to the lower marine riser package, wherein the containment cap is releasably connected to the lower marine riser package with a second connection comprising a connector with a receptacle and a hub seated in the receptacle; and(d) substantially shutting in the wellbore with the containment cap.

2. The method of claim 1, further comprising removing a riser that is coupled to the flexible joint prior to (a).

3. The method of claim 1, wherein (a) further comprises actuating the first connector to unlock and disengage the hub.

4. The method of claim 3, wherein (c) further comprises: seating the hub of the second connection in the connector of the second connection; andactuating the second connector to lock onto the hub.

5. The method of claim 3, wherein the connector of the first connection and the connector of the second connection are each hydraulically actuated.

6. The method of claim 2, wherein a service line extends subsea along a riser coupled to the flexible joint and is releasably connected to a choke and kill line of the blowout preventer stack; and wherein (a) further comprises disconnecting the service line from the choke and kill line sub sea.

7. The method of claim 6, wherein the service is releasably connected to the choke and kill line with a flow-line connection comprising a connector with a receptacle and a hub seated in the receptacle.

8. The method of claim 7, wherein (a) further comprises hydraulically actuating the connector of the flow-line connection to unlock and disengage the hub.

9. A method for shutting in a subsea wellbore after a subsea blowout, wherein the wellbore includes a wellhead, a subsea blowout preventer mounted to the wellhead, a subsea lower marine riser package is mounted to the blowout preventer, a flexible joint is connected to the subsea lower marine riser package, and a riser extends from the flexible joint, the method comprising: (a) removing the flexible joint from the subsea lower marine riser package by actuating a connector at a lower end of the flexible joint to unlock from a hub at an upper end of the lower marine riser package;(b) positioning a containment cap subsea from a surface vessel to a position laterally adjacent the subsea lower marine riser package;(c) moving the containment cap laterally over the subsea lower marine riser package after (b);(d) lowering the containment cap axially downward into engagement with the subsea lower marine riser package; and(e) securing the containment cap to the subsea lower marine riser package.

10. The method of claim 9, further comprising: (f) shutting in the wellbore with the containment cap after (e).

11. The method of claim 9, wherein (a) comprises actuating a connector at a lower end of the flexible joint to unlock from a hub at an upper end of the lower marine riser package.

12. The method of claim 11, wherein (e) comprises actuating a connector at a lower end of the containment cap to lock onto the hub at the upper end of the lower marine riser package.

13. The method of claim 9 further comprising: disconnecting a first service line extending along the outside of the riser from a choke and kill line of the blowout preventer stack.

14. The method of claim 13, wherein disconnecting the first service line comprises actuating a flow-line connector at a lower end of the first service line to unlock from a flow-line hub at an upper end of the choke and kill line.

15. The method of claim 13, further comprising: connecting a second service line to the choke and kill line.

16. The method of claim 11, wherein connecting the second service line comprise actuating a flow-line connector at a lower end of the second service line to lock onto the flow-line hub at the upper end of the choke and kill line.

17. A subsea drilling riser system, comprising: a blowout preventer stack configured to be coupled to a subsea wellhead, wherein the blowout preventer stack includes a plurality of ram blowout preventers;a lower marine riser package coupled to the blowout preventer stack;a flexible joint releasably connected to the lower marine riser package and configured to be coupled to a riser, the flex joint having a releasable connection configured to allow the flexible joint to be quickly disconnected from the lower marine riser package subsea;a choke and kill line coupled to the blowout preventer stack, wherein the choke and kill line comprises a releasable flow-line connection configured to allow a service line to be disconnected from the choke and kill line subsea.

18. The subsea drilling system of claim 17, wherein the releasable connection comprises a connector with a receptacle and a hub seated in the receptacle.

19. The subsea drilling system of claim 18, wherein the connector has a locked position positively engaging the hub and an unlocked position disengaged from the hub.

20. The subsea drilling system of claim 18, wherein the connector is disposed at a lower end of the flexible joint and the hub is disposed at the upper end of the lower marine riser package.

21. The subsea drilling system of claim 18, wherein the connector is configured to be hydraulically actuated between the locked position and the unlocked position.

22. The subsea drilling system of claim 17, wherein the flow-line connection comprises a connector with a receptacle and a hub seated in the receptacle.

23. The subsea drilling system of claim 22, wherein the connector has a locked position positively engaging the hub and an unlocked position disengaged from the hub.

24. The subsea drilling system of claim 22, wherein the connector is disposed at a lower end of the flexible joint and the hub is disposed at the upper end of the lower marine riser package.

25. The subsea drilling system of claim 22, wherein the connector is configured to be hydraulically actuated between the locked position and the unlocked position.