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CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims benefit of U.S. provisional patent application Ser. No. 61/514,626 filed Aug. 3, 2011 and entitled “Releasable Connections for Subsea Flexible Joints and Service Lines,” which is hereby incorporated herein by reference in its entirety for all purposes. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not applicable. 
       BACKGROUND 
       [0003]    1. Field of the Invention 
         [0004]    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. 
         [0005]    2. Background of the Technology 
         [0006]    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. 
         [0007]    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. 
         [0008]    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. 
         [0009]    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. 
         [0010]    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. 
         [0011]    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 
       [0012]    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. 
         [0013]    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. 
         [0014]    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. 
         [0015]    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 
         [0016]    For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
           [0017]      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; 
           [0018]      FIG. 2  is an enlarged schematic view of the BOP stack of  FIG. 1 ; 
           [0019]      FIG. 3  is an enlarged schematic view of the offshore drilling system of  FIG. 1  damaged by a subsea blowout; 
           [0020]      FIG. 4  is an enlarged schematic view of the BOP stack of  FIG. 1  with the flexible joint and riser service lines removed; and 
           [0021]      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 
       [0022]    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. 
         [0023]    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. 
         [0024]    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. 
         [0025]    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 . 
         [0026]    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 . 
         [0027]    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  123   a  releasably secured to LMRP  140 , a lower end  123   b  releasably secured to wellhead  130 , and a main bore  124  extending axially between 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 stack  120  is releasably coupled to LMRP  140  and wellhead  130  with hydraulically actuated, mechanical wellhead connections  150 . 
         [0028]    Typically, connections  150  comprise a downward-facing mating female connector, labeled  150   a  herein, with a receptacle that receives an upward-facing male connector or “hub,” labeled  150   b  herein. Each connector  150   a  is hydraulically actuated between a “locked” positively engaging its corresponding hub  150   b  and an “unlocked” position disengaged from its corresponding hub  150   b.  With connector  150   a  in the “unlocked” position, hub  150   b  can be axially inserted into or axially pulled from connector  150   a.  However, with connector  150   a  in the “locked” position, hub  150   b  cannot be axially inserted into or removed from connector  150   a.  Thus, each connector  150   a  is lowered axially onto its corresponding hub  150   b  in the unlocked position to seat hub  150   b  therein, and then hydraulically actuated to the locked position positively engaging the hub  150   b  to form a secure and rigid connection therebetween. To disconnect a connector  150   a  from its corresponding hub  150   b,  connector  150   a  is hydraulically actuated to the unlocked position, and then, axially lifted off hub  150   b . In general, each connector  150   a  and each hub  150   b  may comprise any suitable combination of mating connector and hub. Examples of suitable hubs for use as one or more hubs  150   b  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  150   a  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. 
         [0029]    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. 
         [0030]    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. 
         [0031]    Referring still to  FIGS. 1 and 2 , LMRP  140  has a body  141  with an upper end  141   a  releasably secured to flexible joint  160  with a connection  150 , a lower end  141   b  releasably secured to upper end  123   a  with a connection  150 , and a throughbore  142  extending between upper and lower ends  141   a, 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  142   a  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  142   a  has the ability to seal on a variety of pipe sizes and seal off bore  142  when no tubular is extending therethrough. 
         [0032]    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  142   a , 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. 
         [0033]    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  160   a,  a lower end  160   b,  and a fluid passage  162  extending axially between ends  160   a, b . Upper end  160   a  comprises an annular flange  161  bolted to a mating flange at the lower end of riser  113 , and lower end  160   b  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. 
         [0034]    In this embodiment, flexible joint  160  includes a cylindrical base  163  extending from lower end  1160   b  and a riser extension or adapter  164  pivotally coupled to and extending upward from base  163  to upper end  160   a.  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 . 
         [0035]    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 . 
         [0036]    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 . 
         [0037]    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  190   a  herein, that receives and releasably locks onto an upward-facing male flow-line connector or “hub,” labeled  190   b  herein. Each connector  190   a  is hydraulically actuated between a “locked” positively engaging its corresponding hub  190   b  and an “unlocked” position disengaged from its corresponding hub  190   b.  With connector  190   a  in the “unlocked” position, hub  190   b  can be axially inserted into or axially pulled from connector  150   a.  However, with connector  190   a  in the “locked” position, hub  190   b  cannot be axially inserted into or removed from connector  190   a.  Thus, each connector  190   a  is lowered axially onto its corresponding hub  190   b  in the unlocked position to seat hub  190   b  therein, and then hydraulically actuated to the locked position positively engaging the hub  190   b  to form a secure and rigid connection therebetween. To disconnect a connector  190   a  from its corresponding hub  190   b,  connector  190   a  is hydraulically actuated to the unlocked position, and then, axially lifted off hub  190   b.  In general, each connector  190   a  and each hub  190   h  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  190   b  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  190   a  include, without limitation, 3 1/16 inch Mini-connectors available from Cameron International Corporation of Houston, Tex., and the like. 
         [0038]    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  142   a  of LMRP  140  are normally actuated to seal in wellbore  101 . However, in some cases, rams  127  and annular BOP  142   a  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  142   a.  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. 
         [0039]    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 . 
         [0040]    Referring now to  FIGS. 3 and 4 , to prepare for the landing and mounting of a capping stack to LMRP  140 , connector  150   a  is hydraulically actuated to the unlocked position and each connector  190   a  is hydraulically actuated to the unlocked position. With connector  150   a  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  190   a  unlocked, service lines  170  are removed from choke and kill lines  180 . By unlocking connector  150   a  at the lower end of flexible joint  160  from hub  150   b  at the upper end of LMRP  140 , flexible joint  160  may be removed from LMRP  140  with relative ease; and by unlocking connectors  170   a  at the lower ends of service lines  170  from hubs  170   b  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  150   b  at the upper end of LMRP  140 . 
         [0041]    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. 
         [0042]    In this embodiment, containment cap  200  is a BOP stack  210  including a body  212  with a first or upper end  212   a,  a second or lower end  212   b,  and a main bore  213  extending axially between ends  212   a, b . In this embodiment, upper end  212   a  comprises an upward-facing hub  150   b  as previously described and lower end  212   b  comprises a downward-facing connector  150   a  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  216   a  comprising an upward-facing flow-line hub  190   b  as previously described. 
         [0043]    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. 
         [0044]    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  150   a,    190   a,  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 . 
         [0045]    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  150   b  at upper end  212   a.  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. 
         [0046]    Moving now to  FIG. 6 , cap  200  is lowered laterally offset from LMRP  140  until lower end  212   b  is slightly above hub  150   b  at the upper end  141   a  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  150   a  at lower end  212   b  generally coaxially aligned with upward-facing hub  150   a  at upper end  141   a  of LMRP  140 . One or more ROVs  300  may utilize their claws  302  to guide and position cap  200  relative to LMRP  140 . 
         [0047]    With containment cap  200  positioned immediately above LMRP  140 , and connector  150   a  substantially coaxially aligned with hub  150   b,  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  150   b  at upper end  141   a  into the female connector  150   a  at lower end  212   b.  Once hub  150   b  is sufficiently seated in connector  150   a,  connector  150   a  is hydraulically actuated and transitioned to the locked position to securely connect cap  200  to LMRP  140  as shown in  FIG. 8 . 
         [0048]    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 . 
         [0049]    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 . 
         [0050]    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  190   a  that is releasably locked onto a mating flow-line hub  190   b  at the upper end of one choke and kill line  216 ,  180 ; the flow-line hub  190   b  at the upper end of each choke and kill line  216 ,  280  is seated in one mating flow-line connector  190   a  at the lower end of one service line  240 , and then the connector  190   a  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. 
         [0051]    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.

Summary:
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.