SYSTEMS AND METHODS FOR CAPPING A SUBSEA WELL

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Invention

The invention relates generally to systems and methods for containing fluids being discharged subsea. More particularly, the invention relates to systems and methods for capping a subsea blowout preventer or lower marine riser package and controlling the discharge of hydrocarbons into the surrounding sea.

2. Background of the Technology

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. Containing and capping the blowout may present challenges as the wellhead may be hundreds or thousands of feet below the sea surface.

Accordingly, there remains a need in the art for systems and methods to cap a subsea well. Such systems and methods would be particularly well-received if they offered the potential to cap a subsea well discharging hydrocarbon fluids.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a method for capping a subsea wellbore, wherein a wellhead of the subsea wellbore is disposed at the sea floor, a subsea blowout preventer (BOP) is mounted to the wellhead, a lower marine riser package (LMRP) is coupled to the BOP, and a riser extends from the LMRP. In an embodiment, the method comprises (a) identifying a subsea landing site on the BOP or LMRP for connection of a capping stack. In addition, the method comprises (b) preparing the subsea landing site for connection of the capping stack. Further, the method comprises (c) installing a capping stack on to the subsea landing site. Still further, the method comprises (d) shutting in the wellbore with the capping stack after (c).

These and other needs in the art are addressed in another embodiment by a capping stack for containing a subsea wellbore. In an embodiment, the capping stack comprises a body containing a sealing mechanism. The body has a central axis, a first end, a second end opposite the first end, and a main bore extending axially from the lower end to the upper end. The sealing mechanism is configured to seal the main bore. In addition, the capping stack comprises a transition spool having a central axis, a first end releasably connected to the second end of the body, a second end opposite the first end, and a flow bore extending axially between the first end and the second end. The flow bore is in fluid communication with the main bore of the body. The transition spool includes an annular flange axially disposed between the first end and the second end of the transition spool and a mule shoe extending axially from the second end of the transition spool.

These and other needs in the art are addressed in another embodiment by a method for shutting in a subsea wellbore, wherein a wellhead of the wellbore is disposed on the sea floor, a subsea BOP is mounted to the wellhead, an LMRP is mounted to the BOP, and a riser extends from the LMRP. In an embodiment, the method comprises (a) removing the LMRP from the BOP subsea. In addition, the method comprises (b) lowering a second BOP subsea from a surface vessel to a position laterally adjacent the subsea BOP. The second BOP includes a body having a central axis, an upper end, a lower end, and a main bore extending axially from the lower end to the upper end. Further, the method comprises (c) maintaining the second BOP outside of a plume of hydrocarbons formed by the produced hydrocarbons during (b). Still further, the method comprises (d) moving the second BOP laterally over the subsea BOP after (b). Moreover, the method comprises (e) lowering the second BOP axially downward into engagement with the subsea BOP after (d). The method also comprises (f) securing the second BOP to the subsea BOP.

These and other needs in the art are addressed in another embodiment by a capping stack for containing a subsea wellbore. In an embodiment, the capping stack comprises a valve spool containing a valve. The valve spool has a central axis, a first end, a second end opposite the first end, and a main bore extending axially from the lower end to the upper end. The valve is configured to seal the main bore. In embodiments, the capping stack comprises a transition spool having a central axis, a first end releasably connected to the second end of the body, a second end opposite the first end, and a flow bore extending axially between the first end and the second end. The flow bore is in fluid communication with the main bore of the body, and the transition spool includes an annular flange axially disposed between the first end and the second end of the transition spool and a mule shoe extending axially from the second end of the transition spool. In embodiments, the first end of the transition spool comprises a wellhead-type connector. In embodiments, the capping stack further comprises a plurality of side outlets, each side outlet having a first end in fluid communication with the main bore, a second end distal the valve spool, and a side outlet valve disposed between the first end and the second end. Each side outlet valve is configured to control the flow of fluid through the corresponding side outlet. In embodiments, the plurality of side outlets are disposed between the valve spool and the transition spool. In embodiments, the second end of each side outlet comprises a connector hub. A pressure control device is coupled to at least one of the connector hubs. In embodiments, the capping stack comprises a BOP coupled to the valve spool. The BOP comprises one or more sets of opposed rams. In embodiments, the mule shoe has a tapered end in side view and is configured to be inserted into a flex joint. In embodiments, the annular flange of the transition spool includes a plurality of circumferentially spaced holes. A bolt is positioned in each of the plurality of holes in the annular flange, each bolt having a lower end disposed in one hole and an upper end axially above the hole. An annular band is disposed about the upper end of each bolt, wherein the band is configured to bias the upper end of each bolt radially inward.

These and other needs in the art are addressed in another embodiment by a method for capping a subsea wellbore, wherein a wellhead of the subsea wellbore is disposed at the sea floor, a subsea blowout preventer (BOP) is mounted to the wellhead, a lower marine riser package (LMRP) is coupled to the BOP, and a riser extends from the LMRP. In an embodiment, the method comprises (a) identifying a subsea landing site on the BOP or LMRP for connection of a capping stack. In addition, the method comprises (b) preparing the subsea landing site for connection of the capping stack. Further, the method comprises (c) installing a capping stack on to the subsea landing site. The capping stack comprises a valve spool having a central axis, a first end, a second end opposite the first end, a main bore extending axially from the first end to the second end, and a valve configured to seal the main bore. Still further, the method comprises (d) closing the valve after (c). In embodiments, the capping stack further comprises a plurality of side outlets, each side outlet having a first end in fluid communication with the main bore, a second end distal the spool body, and a side outlet valve disposed between the first end and the second end. Each side outlet valve is configured to control the flow of fluid through the corresponding side outlet. In embodiments, (d) comprises allowing each side outlet valve to remain in an open position during the actuating of the valve of the valve spool to alleviate pressure on the wellbore. In embodiments, (d) comprises sequentially closing each of the side outlet valves to shut in the wellbore. In embodiments, the LMRP has an upper end including a riser flex joint connected to the riser, and wherein the subsea landing site is a riser adapter of the riser flex joint. In embodiments, (b) comprises removing the riser from the riser flex joint before (c). In embodiments, the capping stack includes a mule shoe coupled to the second end of the valve spool, and an annular flange axially disposed between the mule shoe and the valve spool, wherein (c) comprises (c1) inserting the mule shoe into the riser adapter; (c2) axially advancing the mule shoe into the riser adapter until the annular flange of the capping stack engages a mating annular flange on the riser adapter; and (c3) securing the annular flange of the capping stack to the annular flange of the riser adapter. In embodiments, (c) further comprises (c1) connecting a transition spool to the riser adapter, wherein the transition spool comprises a longitudinal axis, a first end configured to be coupled to the body of the capping stack, a second end comprising a mule shoe, and an annular flange positioned axially adjacent the mule shoe; and (c2) connecting the capping stack to the transition spool after (c1). In embodiments, (c1) comprises positioning the transition spool laterally offset from the subsea landing site; moving the transition spool into alignment with the riser adapter; and urging the transition spool into engagement with the riser adapter, wherein (c2) comprises positioning the capping stack laterally offset from the subsea landing site, moving the capping stack into alignment with the transition spool, and urging the capping stack into engagement with the transition spool. In embodiments, the subsea landing site is a wellhead-type coupling at a first end of the BOP. In embodiments, the capping stack comprises a BOP coupled to the valve spool.

Thus, 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 embodiment of an offshore drilling system;

FIG. 2 is an enlarged view of the riser flex joint of the lower marine riser package of FIG. 1;

FIG. 3 is a top view of the flange of the riser adapter of FIG. 2;

FIG. 4 is a schematic view of the offshore drilling system of FIG. 1 damaged by a subsea blowout and after removal of the riser;

FIG. 5 is a side view of an embodiment of a capping stack for containing the wellbore of FIG. 4;

FIG. 6 is a schematic cross-sectional view of the capping stack of FIG. 5;

FIG. 7A-7E are sequential schematic views of the deployment and installation of the capping stack of FIG. 5 onto the flex joint of FIG. 4;

FIG. 8 is schematic view of an embodiment of a capping stack for containing a wellbore;

FIG. 9 is cross-sectional view of the blowout preventer of FIG. 8;

FIG. 10 is a perspective view of the transition spool of FIG. 8;

FIG. 11A-11H are sequential schematic views of the deployment and installation of the capping stack of FIG. 8 onto the flex joint of FIG. 4;

FIG. 12 is a schematic front view of an embodiment of a capping stack for containing the wellbore of FIG. 4;

FIG. 13 is a schematic side view of the capping stack of FIG. 12;

FIG. 14A-14D are sequential schematic views of the deployment and installation of the capping stack of FIG. 12 onto the BOP of FIG. 4;

FIG. 15 is a schematic front view of an embodiment of a capping stack for containing the wellbore of FIG. 4;

FIG. 16 is a schematic cross-sectional view of the valve spool of FIG. 15;

FIG. 17A-17H are sequential schematic views of the deployment and installation of the capping stack of FIG. 15 onto the BOP of FIG. 4;

FIG. 18 is a schematic front view of an embodiment of a capping stack for containing the wellbore of FIG. 4;

FIG. 19 is a schematic side view of the BOP of FIG. 18;

FIG. 20 is a front view of the BOP of FIG. 18;

FIG. 21 is a side view of the BOP of FIG. 18;

FIG. 22 is a front view of the BOP of FIG. 18 configured for deployment subsea;

FIG. 23 is a side view of the BOP of FIG. 18 configured for deployment subsea;

FIGS. 24A-D are sequential schematic views of the deployment and installation of the capping stack of FIG. 18 onto the BOP of FIG. 4;

FIG. 25 is a schematic front view of an embodiment of a capping stack for containing the wellbore of FIG. 4;

FIG. 26 is a schematic cross-sectional view of the valve manifold of FIG. 25;

FIGS. 27A-D are sequential schematic views of the deployment and installation of the capping stack of FIG. 28 onto the BOP of FIG. 4; and

FIG. 28 is a flowchart illustrating an embodiment of a method for deploying and installing a capping stack.

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

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, without limitation, 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. Thus, each set of rams 127, 128, 129 functions as a sealing mechanism.

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 FIG. 1, LMRP 140 has a body 141 with an upper end 141a connected to the lower end of riser 115, a lower end 141b releasably secured to upper end 123a with connector 150, and a throughbore 142 extending between upper and lower ends 141a, b. Throughbore 142 is coaxially aligned with main bore 124 of BOP 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 116, casing, drillpipe, drill collar, etc.) or seal off bore 142. Thus, annular BOP 142a has the ability to seal on a variety of pipe sizes and seal off bore 142 when no tubular is extending therethrough.

Referring now to FIGS. 1 and 2, in this embodiment, upper end 141a of LMRP 140 comprises a riser flex joint 143 that allows riser 115 to deflect angularly relative to BOP 120 and LMRP 140 while hydrocarbon fluids flow from wellbore 101, BOP 120 and LMRP 140 into riser 115. In this embodiment, flex joint 143 includes a cylindrical base 144 rigidly secured to the remainder of LMRP 140 and a riser extension or adapter 145 extending upward from base 144. A fluid flow passage 146 extending through base 144 and adapter 145 defines the upper portion of throughbore 142. A flex element (not shown) disposed within base 144 extends between base 144 and riser adapter 145, and sealingly engages both base 144 and riser adapter 145. The flex element allows riser adapter 145 to pivot and angularly deflect relative to base 144, LMRP 140, and BOP 120. The upper end of adapter 145 distal base 144 comprises an annular flange 145a for coupling riser adapter 145 to a mating annular flange 118 at the lower end of riser 115 or to alternative devices. As best shown in FIG. 3, flange 145a includes a plurality of circumferentially-spaced holes 147 that receive bolts for securing flange 145a to a mating annular flange 118 at the lower end of riser 115. In addition, flange 145a includes a pair of circumferentially spaced guide holes 148, each guide hole 148 having a diameter greater than the diameter of holes 147. In this embodiment, flex joint 143 also includes a mud boost line 149 having an inlet (not shown) in fluid communication with flow passages 142, 146, an outlet 149b in flange 145a, and a valve 149c configured to control the flow of fluids through line 149. Although LMRP 140 has been shown and described as including a particular flex joint 143, in general, any suitable riser flex joint may be employed in LMRP 140.

As previously described, in an embodiment, BOP 120 includes three sets of rams (one set of shear rams 127, and two sets of pipe rams 128, 129), however, in other embodiments, the BOP (e.g., BOP 120) may include a different number of rams (e.g., four sets of rams), different types of rams (e.g., two sets of shear rams or a blind ram), an annular BOP (e.g., annular BOP 142a), 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 (e.g., two sets of annular BOPs), different types of rams (e.g., shear rams), or combinations thereof.

During a “kick” or surge of formation fluid pressure in wellbore 101, one or more rams 127, 128, 129 of BOP 120 and/or LMRP 140 are normally actuated to seal in wellbore 101. However, in some cases, rams 127, 128, 129 may not seal off wellbore 101, resulting in a blowout. If the preventers of BOP 120 and LMRP 140 do not seal the wellbore, this may result in the uncontrolled discharge of such hydrocarbon fluids. Referring to FIGS. 1 and 4, riser 115 may be severed and removed after a blowout leaving flange 145a of flex joint 143 remaining. Embodiments of capping stacks and methods for deploying same described in more detail below are designed to cap wellbore 101 and stop the subsea emission of hydrocarbon fluid.

Referring now to FIGS. 5 and 6, an embodiment of a capping stack 200 for capping wellbore 101 previously described and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 200 comprises a valve spool 210 and a guidance device 230. Valve spool 210 has a central axis 215, and includes a spool body 211 with a first or upper end 211a, a second or lower end 211b opposite upper end 211a, and a main bore 211c extending axially between ends 211a, b.

Valve spool 210 also includes a sealing mechanism 220 that controls the flow of fluids through main bore 211c. In this embodiment, sealing mechanism 220 is an isolation valve—when valve 220 is in an “open” position, valve 220 allows fluid flow through main bore 211c between ends 211a, b, however, when valve 220 is in a “closed” position, valve 220 restricts and/or prevents fluid flow through main bore 211c between ends 211a, b. Accordingly, valve 220 may also be referred to as a “sealing mechanism.” Valve 220 is transitioned between the open and closed positions with subsea ROVs. Depending on the type of actuator (e.g. mechanical or hydraulic) on valve 220, transitioning between the open and closed positions subsea is accomplished either by (a) direct use of an ROV manipulator arm, (b) an ROV-powered torque tool, or (c) means of a “flying lead” hydraulic line coupled to the valve hydraulic actuator. In this embodiment, valve 220 is a ball valve. However, in general, valve 220 may comprise any valve suitable for subsea conditions and containing the anticipated pressure of fluids from wellbore 101 including, without limitation, a gate valve or a ball valve. Further, in other embodiments, the valve spool (e.g., valve spool 210) may include more than one valve (e.g., valve 220).

In this embodiment, spool 210 is a double-flanged spool, and thus, upper end 211a comprises an annular flange 212 and lower end 211b comprises an annular flange 213. Each flange 212, 213 includes a plurality of circumferentially spaced holes 212a, 213a, respectively, for receiving bolts that secure capping stack 200 to a mating flange of another component. As will be described in more detail below, capping stack 200 is configured to be secured to flex joint 143 following removal of riser 115 from flex joint 143. Thus, lower flange 213 is sized and configured to mate and engage with flange 145a of flex joint 143. Bolts 214 are pre-disposed in holes 213a, and a resilient annular band 216 is disposed about the upper ends of bolts 214. Band 216 biases the upper ends of bolts 214 radially inward relative to their lower ends and holes 213a, thereby skewing and angling bolts 214 relative to holes 213a (i.e., bolts 214 are not coaxially aligned with holes 213a). In this manner, band 216 maintains the position of bolts 214 extending into holes 213a during deployment of stack 200, thereby reducing the likelihood of one or more bolts 214 disengaging their corresponding holes 213a and being dropped to the sea floor 103 during deployment and installation of capping stack 200. In general, band 216 may comprise any suitable resilient device for urging and biasing the upper ends of bolts 214 radially inward. In this embodiment, band 216 comprises a tensioned annular band.

Referring now to FIGS. 3, 5, and 6, a pair of circumferentially spaced alignment guides or pins 217 extend axially downward from lower flange 213. Pins 217 are sized and positioned to coaxially and rotationally align flange 213 of capping stack 200 relative to flange 145a of flex joint 143 such that holes 213a are coaxially aligned with corresponding holes 147 in flange 145a. In particular, pins 217 slidingly engage mating guide holes 148 in flange 145a. The lower ends of pins 217 comprise a frustoconical outer surface for facilitating the alignment and insertion of pins 217 into holes 148. Each pin 217 includes a handle 218 extending axially upward from flange 213. Handles 218, as well as T-handles 219 extending radially from spool body 210, enable subsea manipulation of stack 200 with one or more subsea remotely operated vehicles (ROVs) during deployment and installation of stack 200. Band 216 is disposed about bolts 214 but positioned on the inside or radially inward of handles 218 such that the ROVs can access handles 218 without interference.

Referring still to FIGS. 5 and 6, in this embodiment, guidance device 230 is a tubular mule shoe extending axially downward from lower end 211b and flange 213 of spool body 210. Mule shoe 230 has a central axis 235 coaxially aligned with axis 215, a first or upper end 230a connected to lower flange 213, a second or lower end 230b distal flange 213, and a cylindrical through bore 232 extending axially between ends 231a, b. Bore 232 is coaxially aligned with and in fluid communication with main bore 211c of spool body 210. Shoe 230 also includes a plurality of circumferentially spaced elongate through slots 233 extending radially from the outer cylindrical surface of shoe 230 to bore 232. In the embodiment, slots 233 are oriented parallel to axis 215. In other embodiments, the slots in the mule shoe (e.g., slots 233 in mule shoe 230) may be omitted.

As will be described in more detail below, during installation of capping stack 200 onto flex joint 143, mule shoe 230 is coaxially aligned with joint 143 and axially advanced into joint 143 until flanges 145a, 213 axially abut. During insertion of mule shoe 230 into flex joint 143, through slots 233 provide a flow path for hydrocarbon fluids discharged from wellbore 101 through BOP 120 and LMRP 140.

To facilitate the alignment and insertion of mule shoe 230 into flex joint 143, lower end 230b is angled or tapered in side view (i.e., when viewed perpendicular to axis 235). Specifically, lower end 230b is oriented at an angle β relative to axis 235. Angle β is preferably between 30° and 60°. In this embodiment, angle β is 45°. Tapered lower end 230b also facilitates the axial advancement of mule shoe 230 into another component (e.g., flex joint 143) that is bent or angled relative to vertical and/or that contain pipes or tubulars disposed therein. For example, mule shoe 230 may be inserted into another component and slowly axially advanced. As shoe 230 is advanced, tapered end 230b slidingly engages the component, thereby guiding shoe 230 into the component. In addition, tapered end 230b slidingly engages and guides tubulars within the component into bore 232. In other words, tapered end 230b enables shoe 230 to wedge itself radially between the component and the tubulars disposed therein. This may be particularly advantageous in instances where mule shoe 230 is coupled to a component that contains damage tubulars or pipes that cannot be removed.

Referring now to FIGS. 7A-7E, capping stack 200 is shown being deployed and installed subsea on LMRP 140 to cap and contain wellbore 101. More specifically, in FIG. 7A, capping stack 200 is shown being lowered subsea; in FIG. 7B, capping stack 200 is shown being moved laterally over flex joint 143; in FIG. 7C, capping stack 200 is shown being generally coaxially aligned with flex joint 143 and lowered into engagement with flex joint 143; and in FIGS. 7D and 7E, capping stack 200 is shown being secured to flex joint 143.

To prepare flange 145a engagement with capping stack 200 (or any other device), riser 115 is removed from flex joint 143, and any tubulars or debris extending upward from flange 145a are preferably cut off substantially flush with flange 145a. In addition, riser adapter 145 is preferably oriented vertically and locked in the vertical position. This offers the potential to reduce moments experienced by adapter 145 following installation of these components. More specifically, since riser adapter 145 is designed to pivot relative to base 144, the moments exerted on riser adapter 145 following attachment of such components may cause riser adapter 145 to undesirably pivot and/or break. However, by straightening flex joint 143 (i.e., orienting riser adapter 145 vertically) and locking riser adapter 145 in place, such moments can be reduced and resisted without adapter 145 pivoting or breaking. In general, riser adapter 145 may be oriented vertically and locked in the vertical orientation by any suitable systems and/or methods. Examples of suitable systems and methods for orienting riser adapter 145 vertically and locking riser adapter 145 in the vertical orientation are disclosed in U.S. patent application Ser. No. 61/482,132 filed May 3, 2011, and entitled “Adjustment and Restraint System for a Subsea Flex Joint,” which is hereby incorporated herein by reference in its entirety for all purposes.

For subsea deployment and installation of capping stack 200, one or more remote operated vehicles (ROVs) are preferably employed to aid in positioning stack 200, monitoring stack 200, BOP 120, and LMRP 140, and actuating valve 220 between the open and closed position. In this embodiment, ROVs 170 are employed to position stack 200, monitor stack 200, BOP 120, and LMRP 140, and actuate valve 220. Each ROV 170 includes an arm 171 having a claw 172, a subsea camera 173 for viewing the subsea operations (e.g., the relative positions of stack 200, plume 160, the positions and movement of arms 170 and claws 172, etc.), and an umbilical 174. Streaming video and/or images from cameras 173 are communicated to the surface or other remote location via umbilical 174 for viewing on a live or periodic basis. Arms 171 and claws 172 are controlled via commands sent from the surface or other remote location to ROV 170 through umbilical 174.

Referring first to FIG. 7A, in this embodiment, stack 200 is shown being controllably lowered subsea with a plurality of cables 180 secured to stack 200 and extending to a surface vessel. Due to the weight of stack 200, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower stack 200 on cables 180. Although cables 180 are employed to lower stack 200 in this embodiment, in other embodiments, capping stack 200 may be deployed subsea on a pipe string.

Using cables 180, capping stack 200 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101, BOP 120, and LMRP 140. More specifically, during deployment, capping stack 200 is preferably maintained outside of plume 160 of hydrocarbon fluids emitted from wellbore 101. Lowering stack 200 subsea in plume 160 may trigger the undesirable formation of hydrates within stack 200, particularly at elevations substantially above sea floor 103 where the temperature of hydrocarbons in plume 160 is relatively low.

As shown in FIG. 7A, to ensure the flush, sealing engagement between flanges 145a, 213 described in more detail below, riser 115 is preferably removed from flex joint 143. In general, flange 118 may be disconnected from flange 145a subsea by any suitable means (e.g., with subsea ROVs 170). Moreover, although tapered lower end 230b of mule shoe 230 enables mule shoe 230 to be advanced over tubulars and other debris disposed in throughbore 142, to simplify the coupling of flanges 145a, 213, any tubulars or debris extending upward from flange 145a are preferably cut off slightly above flange 145a so as to provide initial coarse guidance for engaging lower end 230b of mule shoe 230. For example, one or more ROVs 170 may be equipped with a saw capable of cutting through any tubulars or debris extending from flange 145a.

Moving now to FIG. 7B, stack 200 is lowered laterally offset from riser adapter 145 and outside of plume 160 until mule shoe 230 is slightly above flange 145a. As stack 200 descends and approaches riser adapter 145, ROVs 170 monitor the position of stack 200 relative to flex joint 143. Next, as shown in FIG. 7C, stack 200 is moved laterally into position immediately above riser adapter 145 with mule shoe 230 substantially coaxially aligned with riser adapter 145. In addition, stack 200 is rotated about axes 215, 235 to substantially align guide pins 217 with corresponding holes 148 in flange 145a. Guide pins 217 may each have sockets or holes by which additional guide wires or cables (not shown) may be attached. Guide wires may be attached to guide pins 217 and then threaded through pin holes in flange 145a. The guide wires may be used to guide ROVS due to low visibility due to the presence of hydrocarbons. One or more ROVs 170 may utilize their claws 172 and handles 218, 219 to guide and rotate stack 200 into proper alignment relative to flange 145a. ROVs 170 may tighten or straighten guide wires which have been threaded through pin holes of flange 145a, and guide transition spool and/or stack 200 into engagement with flange 145a.

Due to its own weight, stack 200 is substantially vertical, whereas riser adapter 145 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of mule shoe 230 and flex joint 143, as well as perfect coaxial alignment of pins 217 and mating holes in flange 145a, may be difficult. With mule shoe 230 positioned immediately above and generally coaxially aligned with riser adapter 145, and guide pins 217 aligned with corresponding holes in flange 145a, cables 180 lower stack 200 axially downward, thereby inserting and axially advancing pins 217 into corresponding holes 148 and inserting and axially advancing mule shoe lower end 230b into riser adapter 145 until flange 213 axially abuts and engages flange 145a as shown in FIG. 7D. The frustoconical surface on the lower end of each pin 217 functions to guide each pin 217 into its corresponding hole 148, even if pins 217 are initially slightly misaligned with holes 148. Likewise, taper on lower end 230b functions to guide the insertion and coaxial alignment of capping stack 200 and riser adapter 145 as stack 200 is lowered from a position immediately above riser adapter 145, even if mule shoe 230 is initially slightly misaligned with riser adapter 145.

Prior to moving stack 200 laterally over riser adapter 145, valve 220 is transitioned to the open position allowing hydrocarbon fluids emitted by flex joint 143 to flow unrestricted through stack 200. Valve 220 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Thus, as stack 200 is moved laterally over riser adapter 145 and lowered into engagement with flange 145a, emitted hydrocarbon fluids flow freely through stack 200 as well as slots 233 in mule shoe 230. Slots 233 also allow emitted hydrocarbons to flow freely through mule shoe 230 as it is moved over and inserted into riser adapter 145. As a result, open valve 220 and slots 233 offer the potential to reduce the resistance to the axial insertion of mule shoe 230 into riser adapter 145 and coupling of stack 200 thereto. In other words, open valve 220 and slots 233 allow the relief of well pressure during installation of stack 200.

With mule shoe 230 sufficiently seated in riser adapter 145 and flange 213 abutting mating flange 145a, holes 213a are coaxially aligned with corresponding holes 147 in flange 145a. Next, one ROV 170 cuts band 216, thereby allowing bolts 214 to drop into holes 147. One or more ROVs 170 may also help facilitate the lowering of bolts 214 into holes 147 if necessary. Bolts 214 may then be tightened with ROVs 170 to rigidly secure stack 200 to riser adapter 145 as shown in FIG. 7E. With a sealed, secure connection between stack 200 and riser adapter 145, valve 220 is transitioned to the closed position with an ROV 170, thereby shutting off the flow of hydrocarbons emitted from wellbore 101, BOP 120, and LMRP 140. Cables 180 may be decoupled from stack 200 with ROVs 170 and removed to the surface once stack 200 is securely bolted to flex joint 143.

Referring now to FIG. 8, an embodiment of a capping stack 300 for capping wellbore 101 previously described (FIG. 4) and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 300 comprises a BOP 310 and a transition spool 330 coupled to BOP 310. In this embodiment, BOP 310 is releasably coupled to transition spool 330 with a mechanical wellhead-type connector 150 as previously described.

Referring now to FIGS. 8 and 9, BOP 310 is similar to BOP 120 previously described. Specifically, BOP 310 has a central or longitudinal axis 315 and includes a body 312 with a first or upper end 312a, a second or lower end 312b releasably secured to transition spool 330, and a main bore 313 extending axially between ends 312a, b. In this embodiment, upper end 312a comprises a male coupling 150a of a wellhead-type connector 150 and lower end 312b comprises a female coupling 150b of wellhead-type connector 150. In addition, BOP 310 also includes a plurality of axially stacked sets of opposed rams. However, in this embodiment, BOP 310 includes two sets of axially stacked sets of opposed rams—two sets of opposed blind shear rams or blades 127 as previously described, for sealing off wellbore main bore 313. Thus, as compared to relatively larger three ram BOPs (e.g., BOP 110), two ram BOP 310 may generally be considered a light weight BOP. Although this embodiment of BOP 310 includes two sets of blind shear rams 127, in other embodiments, the BOP (e.g., BOP 310) may comprise other types of opposed rams such as opposed blind rams (e.g., rams 128), pipe rams (e.g., rams 129), or combinations thereof.

Opposed rams 127 are disposed in cavities that intersect main bore 313 and support rams 127 as they move into and out of main bore 313. Each set of rams 127 is actuated and transitioned between an open position and a closed position. In the open positions, rams 127 are radially withdrawn from main bore 313 and do not interfere with any hardware that may extend through main bore 313. However, in the closed positions, rams 127 are radially advanced into main bore 313 to close off and seal main bore 313. Each set of rams 127 is actuated and transitioned between the open and closed positions by a pair of actuators 126 as previously described.

Referring now to FIGS. 8 and 10, transition spool 330 has a central or longitudinal axis 335 (coaxially aligned with axis 315 when coupled to BOP 310), a first or upper end 330a releasably coupled to BOP 310, a second or lower end 330b, and a flow bore 331 extending axially between ends 330a, b. Flow bore 331 is coaxially aligned with main bore 313, thereby forming a continuous flow passage extending axially through capping stack 300. In this embodiment, upper end 330a comprises the male coupling 150a of wellhead-type connector 150. As best shown in FIG. 10, transition spool 330 includes an annular flange 334 axially between ends 330a, b and a mule shoe 230 as previously described extending axially from flange 334 to lower end 330b. Flange 334 is similar to flange 213 previously described with reference to capping stack 200. Specifically, flange 334 includes a plurality of circumferentially spaced holes 334a for receiving bolts 214 that secure transition spool 330 and capping stack 300 to a mating flange of another component. As will be described in more detail below, capping stack 300 is configured to be secured to flex joint 143 following removal of riser 115 from flex joint 143. Thus, flange 334 is sized and configured to mate and engage with flange 145a of flex joint 143. Bolts 214 are pre-disposed in holes 334a, and a resilient annular band 216 as previously described is disposed about the upper ends of bolts 214. Band 216 urges the upper ends of bolts 214 radially inward relative to their lower ends and holes 334a, thereby skewing and angling bolts 214 relative to holes 334a (i.e., bolts 214 are not coaxially aligned with holes 334a). In this manner, band 216 maintains the position of bolts 214 extending into holes 334a during deployment of stack 300, thereby reducing the likelihood of one or more bolts 214 disengaging their corresponding holes 334a and being dropped to the sea floor 103 during deployment and installation of capping stack 300.

Referring still to FIGS. 8 and 10, a pair of circumferentially spaced alignment guides or pins 217 as previously described extend axially downward from flange 334. Pins 217 are sized and positioned to coaxially and rotationally align flange 334 of transition spool 330 relative to flange 145a of flex joint 143 such that holes 334a are coaxially aligned with corresponding holes in flange 145a (FIGS. 2 and 3). Relatively long guide arms with T-handles 219 extend radially from BOP 310 and enable subsea manipulation of stack 300 with one or more subsea ROVs 170 during deployment and installation of stack 300, while simultaneously allowing ROVs 170 to stay outside hydrocarbon plume 160. Band 216 is disposed about bolts 214 but positioned on the inside or radially inward of handles 218 such that ROVs 170 can access handles 218 without interference. Transition spool 330 also includes a plug 337 extending axially through flange 334. Plug 337 is positioned and oriented for axial insertion into outlet 149b of mud boost line 149 in flange 145a when flanges 145a, 334 are coupled together. Plug 337 functions to close off and seal outlet 149b, thereby preventing the leakage of hydrocarbon fluids therethrough in the event mud boost valve 149c fails or otherwise leaks. In this embodiment, plug 337 is pre-installed in transition spool 330 prior to deployment such that it engages mating outlet 149b as flanges 145a, 334 axially abut. Alternatively, plug 337 may be installed by an ROV 170 after flanges 145a, 334 are secured together. Plug 337 may be fitted with an adapter for coupling a chemical supply line to plug 337 to inject a chemical into outlet 149b in the event it is necessary to flush hydrates from outlet 149b.

As described above, mule shoe 230 extends axially from flange 334 to lower end 330b. Central axis 235 of mule shoe 230 is coaxially aligned with axes 315, 335, first or upper end 230a of mule shoe 230 is connected to flange 334, second or lower end 230b of mule shoe 230 defines lower end 330b of transition spool 330, and through bore 232 of mule shoe 230 defines the lower portion of flow bore 331 of transition spool 330. As will be described in more detail below, during installation of capping stack 300 onto flex joint 143, mule shoe 230 is coaxially aligned with joint 143 and axially advanced into joint 143 until flanges 145a, 334 axially abut. During insertion of mule shoe 230 into flex joint 143, through slots 233 provide a flow path for hydrocarbon fluids discharged from wellbore 101 through BOP 120 and LMRP 140.

Referring now to FIGS. 11A-11H, capping stack 300 is shown being deployed and installed subsea on LMRP 140 to cap and contain wellbore 101. Unlike capping stack 200 previously described, in this embodiment, capping stack 300 is installed in stages—transition spool 330 is first deployed and installed subsea onto flex joint 143, and then, BOP 310 is deployed and installed subsea onto transition spool 330. The two stage installation approach is preferred since it allows the relatively light weight, stand alone transition spool 330 suspended on wires 180 to be more precisely and easily manipulated subsea with ROVs 170 to achieve sufficient engagement with riser adapter 145. In addition, due to the relatively light weight of transition spool 330, ROVs 170 are more adept at maintaining the position of spool 330 and engagement of flanges 145a, 334 while bolting flanges 145a, 334 together. However, once transition spool 330 is secured to riser adapter 145, the upward facing wellhead connector coupling 150a is available for landing and connecting BOP 310, which is typically a more straight forward procedure similar to conventional subsea BOP installation operations. In FIGS. 11A-D, transition spool 330 is shown being controllably lowered subsea and secured to flex joint 143; and in FIGS. 11E-H, BOP 310 is shown being controllably lowered subsea and secured to transition spool 330.

To prepare flange 145a for sealing with flange 334, riser 115 is removed from flex joint 143, and any tubulars or debris extending upward from flange 145a are preferably cut off substantially flush with flange 145a. In addition, riser adapter 145 is preferably oriented vertically and locked in the vertical position. Examples of suitable systems and methods for orienting riser adapter 145 vertically and locking riser adapter 145 in the vertical orientation are disclosed in U.S. patent application No. 61/482,132 filed May 3, 2011, and entitled “Adjustment and Restraint System for a Subsea Flex Joint,” which is hereby incorporated herein by reference in its entirety for all purposes.

Referring first to FIG. 11A, transition spool 330 is shown being controllably lowered subsea with a plurality of cables 180 secured to spool 330 and extending to a surface vessel. Due to the weight of spool 330, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower spool 330 on cables 180. Although cables 180 are employed to lower spool 330 in this embodiment, in other embodiments, spool 330 may be deployed subsea on a pipe string. Using cables 180, spool 330 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101, BOP 120, and LMRP 140 and outside of plume 160 to reduce the potential for hydrate formation within spool 330.

Moving now to FIG. 11B, spool 330 is lowered laterally offset from riser adapter 145 (outside of plume 160) until mule shoe 230 is slightly above flange 145a. As spool 330 descends and approaches riser adapter 145, ROVs 170 monitor the position of spool 330 relative to flex joint 143. Next, as shown in FIG. 11C, spool 330 is moved laterally into position immediately above riser adapter 145 with mule shoe 230 substantially coaxially aligned with riser adapter 145. In addition, spool 330 is rotated about axis 335 to substantially align guide pins 217 with corresponding holes 148 in flange 145a (FIG. 3). One or more ROVs 170 may utilize their claws 172 and handles 218 to guide and rotate spool 330 into the proper alignment relative to flange 145a.

Due to its own weight, spool 330 is substantially vertical, whereas riser adapter 145 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of mule shoe 230 and flex joint 143, as well as perfect alignment of pins 217 and mating holes in flange 145a, may be difficult. To facilitate the alignment of the pins (e.g., pins 217) and mating holes in the flange (e.g., flange 145a) and the alignment of the mule shoe (e.g., mule shoe 230) and the flex joint (e.g., flex joint 143), in other embodiments, guide wires are secured to the lower tips of the pins. The free ends of such guide wires are threaded through the mating holes in the flange, and are pulled to urge the pins into alignment with the mating holes and the mule shoe into alignment with the flex joint.

With mule shoe 230 positioned immediately above and generally coaxially aligned with riser adapter 145, and guide pins 217 aligned with corresponding holes in flange 145a, cables 180 lower spool 330 axially downward, thereby inserting and axially advancing pins 217 into corresponding holes 148 and inserting and axially advancing mule shoe lower end 230b into riser adapter 145 until flange 334 axially abuts and engages flange 145a as shown in FIG. 11D. The frustoconical surface on the lower end of each pin 217 functions to guide each pin 217 into its corresponding hole 148, even if pins 217 are initially slightly misaligned with holes 148. Likewise, taper on lower end 230b functions to guide the insertion and coaxial alignment of spool 330 and riser adapter 145 as stack 200 is lowered from a position immediately above riser adapter 145, even if mule shoe 230 is initially slightly misaligned with riser adapter 145. During installation of spool 330, emitted hydrocarbons flow freely through spool 330 and slots 233 in mule shoe 230, thereby relieving well pressure and offering the potential to reduce the resistance to the axial insertion of mule shoe 230 into riser adapter 145 and coupling of transition spool 330 thereto.

With mule shoe 230 sufficiently seated in riser adapter 145 and flange 334 abutting mating flange 145a, holes 334a are coaxially aligned with corresponding holes 147 in flange 145a and plug 337 is disposed in mud boost outlet 149b. Next, one ROV 170 cuts band 216, thereby allowing bolts 214 to drop into holes 147. One or more ROVs 170 may also help facilitate the lowering of bolts 214 into holes 147 if necessary. Bolts 214 may then be tightened with ROVs 170 to rigidly secure spool 330 to riser adapter 145. With a sealed, secure connection between spool 330 and riser adapter 145, ROVs 170 decouple cables 180 from spool 330, and BOP 310 is controllably lowered subsea and coupled to upper end 330a of transition spool 330 with connector 150.

Moving now to FIG. 11E, BOP 310 is shown being lowered subsea with cables 180 secured thereto and extending to a winch or crane mounted to a surface vessel. Due to the weight of BOP 310, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. Although cables 180 are employed to lower BOP 310 in this embodiment, in other embodiments, BOP 310 may be deployed subsea on a pipe string. Using cables 180, BOP 310 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101, BOP 120, LMRP 140, and spool 330, and outside of plume 160 to reduce the potential for hydrate formation within BOP 310.

Moving now to FIG. 11F, BOP 310 is lowered laterally offset from transition spool 330 and outside of plume 160 until lower end 312b is slightly above spool 330. As BOP 310 descends and approaches spool 330, ROVs 170 monitor the position of BOP 310 relative to spool 330. Next, as shown in FIGS. 11F and 11G, BOP 310 is moved laterally into position immediately above spool 330 with female coupling 150b at lower end 312b generally coaxially aligned with male coupling 150a at upper end 330a of spool 330. One or more ROVs 170 may utilize their claws 172 and handles 219 to guide and position BOP 310 relative to spool 330.

Due to its own weight, BOP 310 is substantially vertical, whereas spool 330 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of BOP 310 and spool 330 may be difficult. With BOP 310 positioned immediately above and couplings 150a, b generally coaxially aligned, cables 180 lower BOP 310 axially downward. Due to the weight of BOP 310, compressive loads between BOP 310 and spool 330 urge the male coupling 150a at upper end 310a into the female coupling 150b at lower end 330b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect BOP 310 to spool 330 and form stack 300 as shown in FIG. 11H.

Prior to moving BOP 310 laterally over riser adapter 145 and spool 330, rams 127 are transitioned to the open position allowing hydrocarbon fluids emitted by flex joint 143 and spool 330 to flow unrestricted through BOP 310, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of BOP 310 to spool 330. Rams 127 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Thus, as BOP 310 is moved laterally over spool 330 and lowered into engagement with spool 330, emitted hydrocarbon fluids flow freely through BOP 310.

With a sealed, secure connection between BOP 310 and spool 330, one or both rams 127 are transitioned to the closed position with an ROV 170, thereby shutting off the flow of hydrocarbons emitted from wellbore 101. Cables 180 may be decoupled from BOP 310 with ROVs 170 and removed to the surface once BOP 310 is secured to spool 330.

Referring now to FIGS. 12 and 13, an embodiment of a capping stack 400 for capping wellbore 101 previously described (FIG. 4) and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 400 comprises a drilling BOP 410 similar to BOP 110 previously described. In particular, BOP 410 has a central or longitudinal axis 415, and includes a body 412 with a first or upper end 412a, a second or lower end 412b, and a main bore 413 extending axially between ends 412a, b. Upper end 412a comprises a male coupling 150a of a wellhead-type connector 150 and lower end 412b comprises the female coupling 150b of a wellhead-type connector 150. In addition, BOP 410 includes a plurality of axially stacked sets of opposed rams—one set of opposed blind shear rams or blades 127, one set of opposed blind rams 128, and one set of opposed pipe rams 129, each as previously described. Opposed rams 127, 128, 129 are disposed in cavities that intersect main bore 413 and support rams 127, 128, 129 as they move into and out of main bore 413. 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 413, and in the closed positions, rams 127, 128, 129 are radially advanced into main bore 413 to close off and seal main bore 413. Each set of rams 127, 128, 129 is actuated and transitioned between the open and closed positions by a pair of actuators 126 as previously described. As best shown in FIG. 12, a plurality of T-handles 219 extend radially from body 412. As will be described in more detail below, handles 219 are used by ROVs 170 to manipulate, rotate, and position stack 400.

During and after a well shut in, there may be a risk of the fluid pressure in the wellbore (e.g., wellbore 101) exceeding the pressure limits of the containment hardware coupled to the wellhead (e.g., BOP 120, BOP 410) and/or the casing (e.g., 131). Exceeding the pressure containment limits of the containment hardware or the casing may result in a blowout. Accordingly, embodiments of capping stacks described herein (e.g., capping stack 400), preferably include temperature and pressure transducers to measure the temperature and pressure of the hydrocarbon fluids within the capping stack, and a means for relieving wellbore pressure to avoid a potential blowout. As best shown in FIG. 13, in this embodiment, capping stack 400 includes a temperature transducer 421 and a pressure transducer 422 positioned along main bore 413 to measure the temperature and pressure, respectively, of the fluids within main bore 413. Transducers 421, 422 are positioned axially below the lowermost set of rams 127 such that transducers 421, 422 can continue to measure the temperature and pressure, respectively, of the wellbore fluids even if rams 127 are closed. Transducers 421, 422 communicate the temperature and pressure measurements to a transmitter 423, which then communicates the temperature and pressure measurements to the surface where they may be continuously or periodically monitored. In general, transmitter 423 may comprise any suitable device for communicating a signal subsea. In this embodiment, transmitter 423 is an acoustic telemetry transmitter.

Referring still to FIG. 13, in this embodiment, stack 400 also includes a plurality of side outlets 414 extending from main bore 413 through body 412. Each side outlet 414 has a first end 414a in fluid communication with main bore 413, a second end 414b distal main bore 413 and extending from body 412, and a sealing mechanism 414c that controls the flow of fluids through the side outlet 414. In this embodiment, each sealing mechanism 414c is an isolation valve. As will be described in more detail below, side outlets 414 provide a means for relieving the pressure of fluids in main bore 413. Each second end 414b preferably comprises a connector hub for connecting other devices to end 414a to aid in managing the fluid pressure within main bore 413. Such other devices may include, without limitation, chokes, pressure relief assemblies (e.g., burst disk assembly), pressure caps, flexible jumpers, etc. In other embodiments, one or more side outlets 414 may be coupled to a containment and/or disposal system such that outlets 414 produce to the containment and/or disposal system once stack 400 is coupled to BOP 120. Although side outlets 414 are shown and described as outlets, they may also be used as inlets to inject fluids into main bore 413.

Referring now to FIGS. 14A-14D, capping stack 400 is shown being deployed and installed subsea on BOP 120 to cap and contain wellbore 101. More specifically, in FIG. 14A, capping stack 400 is shown being controllably lowered subsea; in FIG. 14B, capping stack 400 is shown being move laterally over BOP 120; in FIG. 14C, capping stack 400 is shown being generally coaxially aligned with BOP 120 and lowered into engagement with BOP 120; and in FIG. 14D, capping stack 400 is shown being secured to BOP 120. As previously described, capping stack 400 is configured to be secured to BOP 120. Before connecting stack 400 to BOP 120, LMRP 140 is removed from BOP 120 by decoupling connector 150 between BOP 120 and LMRP 140, and then lifting LMRP 140 from BOP 120 with one or more ROVs 170. In addition, any tubulars or debris extending from upper end 123a of BOP 120 are cut off substantially flush with upper end 123b with one or more ROVs 170.

Referring first to FIG. 14A, stack 400 is shown being controllably lowered subsea with a plurality of cables 180 secured to stack 400 and extending to a surface vessel. Due to the weight of stack 400, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower stack 400 on cables 180. Although cables 180 are employed to lower stack 400 in this embodiment, in other embodiments, stack 400 may be deployed subsea on a pipe string. Using cables 180, stack 400 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101 and BOP 120, and outside of plume 160 to reduce the potential for hydrate formation within stack 400.

Moving now to FIG. 14B, stack 400 is lowered laterally offset from BOP 120 and outside of plume 160 until lower end 412b is slightly above upper end 123a. As stack 400 descends and approaches BOP 120, ROVs 170 monitor the position of stack 400 relative to BOP 120. Next, as shown in FIG. 14C, stack 400 is moved laterally into position immediately above BOP 120 with female coupling 150b at lower end 412b of BOP 410 generally coaxially aligned with male coupling 150a at upper end 123a of BOP 120. One or more ROVs 170 may utilize their claws 172 and handles 219 to guide and rotate stack 400 into the proper alignment relative to BOP 120.

Due to its own weight, stack 400 is substantially vertical, whereas BOP 120 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of couplings 150a, b may be difficult. With lower end 412b of BOP 410 positioned immediately above upper end 123a of BOP 120 and couplings 150a, b generally coaxially aligned, cables 180 lower stack 400 axially downward. Due to the weight of BOP 410, compressive loads between BOP 410 and BOP 120 urge the male coupling 150a at upper end 123a into the female coupling 150b at lower end 412b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect BOP 410 to BOP 120 as shown in FIG. 14D.

Prior to moving BOP 410 laterally over riser adapter 145, valves 414c and rams 127, 128, 129 are transitioned to the open position allowing hydrocarbon fluids emitted by BOP 120 to flow unrestricted through main bore 413 and flow passages 414. Valves 414c and rams 127, 128, 129 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Thus, as BOP 410 is moved laterally over BOP 120 and lowered into engagement with BOP 120, emitted hydrocarbon fluids flow freely through BOP 410, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of BOP 410 to BOP 120.

With a sealed, secure connection between BOP 410 and BOP 120, wellbore 101 is shut in by closing one or more rams 127, 128, 129, valves 414c, or combinations thereof with ROVs 170. It should be appreciated that closure of one or both rams 129, 128 shuts off the flow of hydrocarbons through main bore 413 to upper end 412a, but does not impede the flow of emitted hydrocarbons through passages 414. Thus, if rams 127 and valves 414c are open, hydrocarbons emitted from wellbore 101 may pass through a portion of main bore 413 and passages 414 into the surrounding sea water, regardless of whether one or both rams 129, 128 are closed. Specifically, closure of rams 129, 128 (positioned axially above passage ends 414a) does not impede the flow of emitted hydrocarbons through the lower portion of main bore 413 into passages 414. However, closure of rams 127 (positioned axially below passage ends 414a) does impede the flow of emitted hydrocarbons through main bore 413 into passages 414. Therefore, to completely shut in wellbore 101, rams 127 must be closed or valves 414c and at least one of rams 129, 128 must be closed.

Transducers 421, 422 and side outlets 414 offer the potential to reduce the likelihood of an undesirable blowout during and after shutting in wellbore 101. In particular, pressure transducer 422 continuously measures the pressure of wellbore fluids in main bore 413. The measured pressure is communicated to the surface with transmitter 423. If the measured pressure approaches an undesirable level during or after shutting in wellbore 101, rams 127, 128, 129, valves 414c, or combinations thereof can be opened to relieve wellbore pressure. Chokes or pressure relief assemblies may also be coupled to second ends 414b to help manage wellbore pressure during and after installation of stack 400. For example, ends 414b of side outlets 414 may be closed with a burst disk assembly that prevents fluid flow through ends 414b below a predetermined pressure and allows fluid flow through ends 414b above the predetermined pressure that causes one or more bust disks to rupture. The assembly is preferably designed such that the predetermined pressure is below the pressure at which a blowout may occur such that wellbore pressure is relieved prior to reaching an undesirable level. With a sealed, secure connection between BOP 410 and BOP 120, cables 180 may be decoupled from BOP 410 with ROVs 170 and removed to the surface.

Referring now to FIG. 15, an embodiment of a capping stack 500 for capping wellbore 101 previously described (FIG. 4) and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 500 comprises BOP 310 as previously described coupled to a valve spool 510 including sealing mechanism 220 (i.e., isolation valve 220) as previously described. In this embodiment, BOP 310 is releasably coupled to spool 510 with a mechanical wellhead-type connector 150 as previously described.

Referring now to FIGS. 15 and 16, spool 510 includes a spool body 511 having a central axis 515 (coaxially aligned with axis 315 when coupled to BOP 310), a first or upper end 510a releasably coupled to BOP 310, and a second or lower end 510b opposite upper end 510a, and a main bore 512 extending axially between ends 510a, b. Valve 220 controls the flow of fluids through main bore 512—when valve 220 is in an “open” position, valve 220 allows fluid flow through main bore 512 between ends 510a, b, however, when valve 220 is in a “closed” position, valve 220 restricts and/or prevents fluid flow through main bore 512 between ends 510a, b. In this embodiment, valve 220 is a ball valve. However, in general, valve 220 may comprise any valve suitable for subsea conditions and containing the anticipated pressure of fluids from wellbore 101 including, without limitation, a butterfly valve, a gate valve, or a ball valve. In this embodiment, spool 510 is not a flanged spool. Rather, upper end 510a comprises a male coupling 150a of a wellhead-type connector 150 and lower end 510b comprises a female coupling 150b of a wellhead-type connector 150. As will be described in more detail below, capping stack 500 is configured to be secured to BOP 120 following removal of LMRP 140. T-handles 219 extending radially from spool body 511, enable subsea manipulation of body 511 with one or more subsea ROVs 170 during deployment and installation of body 511.

Referring now to FIGS. 17A-17H, capping stack 500 is shown being deployed and installed subsea on BOP 120 to cap and contain wellbore 101. Similar to capping stack 300 previously described, in this embodiment, capping stack 500 is installed in stages—valve spool 510 is first deployed and installed subsea onto BOP 120, and then, BOP 310 is deployed and installed subsea onto valve spool 510. In FIGS. 17A-D, valve spool 510 is shown being controllably lowered subsea and secured to BOP 120; and in FIGS. 17E-H, BOP 310 is shown being controllably lowered subsea and secured to valve spool 510. Since capping stack 500 is configured to be secured directly to BOP 120, LMRP 140 is removed from BOP 120 before connecting valve spool 510 to BOP 120. LMRP 140 is removed from BOP 120 by decoupling connector 150 between BOP 120 and LMRP 140, and then lifting LMRP 140 from BOP 120 with one or more ROVs 170. In addition, any tubulars or debris extending from upper end 123a of BOP 120 are cut off substantially flush with upper end 123b with one or more ROVs 170.

Referring first to FIG. 17A, valve spool 510 is shown being controllably lowered subsea with a plurality of cables 180 secured to spool 510 and extending to a surface vessel. Due to the weight of spool 510, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower spool 510 on cables 180. Although cables 180 are employed to lower spool 510 in this embodiment, in other embodiments, spool 510 may be deployed subsea on a pipe string. Using cables 180, spool 510 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101 and BOP 120, and outside of plume 160 to reduce the potential for hydrate formation within spool 510.

Moving now to FIG. 17B, spool 510 is lowered laterally offset from BOP 120 and outside of plume 160 until lower end 510b is slightly above BOP 120. As spool 510 descends and approaches BOP 120, ROVs 170 monitor the position of spool 510 relative to BOP 120. Next, as shown in FIG. 17C, spool 510 is moved laterally into position immediately above BOP 120 with female coupling 150b substantially coaxially aligned with male coupling 150a. Due to its own weight, spool 510 is substantially vertical, whereas BOP 120 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of couplings 150a, b may be difficult. With lower end 510b positioned immediately above upper end 123a of BOP 120 and couplings 150a, b generally coaxially aligned, cables 180 lower spool 510 axially downward. Due to the weight of spool 510, compressive loads between spool 510 and BOP 120 urge male coupling 150a at upper end 123a into the female coupling 150b at lower end 412b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect spool 510 to BOP 120 as shown in FIG. 17D. With a sealed, secure connection between BOP 120 and spool 510, cables 180 may be decoupled from spool 510 with ROVs 170 and removed to the surface.

Prior to moving spool 510 laterally over BOP 120, valve 220 is transitioned to the open position allowing hydrocarbon fluids emitted by BOP 120 to flow unrestricted through spool 510, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of spool 510 to BOP 120. Valve 220 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170.

Moving now to FIG. 17E, BOP 310 is shown being controllably lowered subsea with cables 180 secured thereto and extending to a winch or crane mounted to a surface vessel. Due to the weight of BOP 310, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. Although cables 180 are employed to lower BOP 310 in this embodiment, in other embodiments, BOP 310 may be deployed subsea on a pipe string. Using cables 180, BOP 310 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101, BOP 120, and spool 510, and outside of plume 160 to reduce the potential for hydrate formation within BOP 310.

Moving now to FIG. 17F, BOP 310 is lowered laterally offset from spool 510 and outside of plume 160 until lower end 312b is slightly above spool 510. As BOP 310 descends and approaches spool 510, ROVs 170 monitor the position of BOP 310 relative to spool 510. Next, as shown in FIGS. 17F and 17G, BOP 310 is moved laterally into position immediately above spool 510 with couplings 150a, b substantially coaxially aligned with spool 510. One or more ROVs 170 may utilize their claws 172 and handles 219 to guide and position BOP 310 relative to spool 510. Due to its own weight, BOP 310 is substantially vertical, whereas spool 510 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of couplings 150a, b may be difficult. With BOP 310 positioned immediately above and couplings 150a, b generally coaxially aligned, cables 180 lower BOP 310 axially downward. Due to the weight of BOP 310, compressive loads between BOP 310 and spool 510 urge the male coupling 150a at upper end 510a into the female coupling 150b at lower end 312b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect BOP 310 to spool 510 and form stack 500 as shown in FIG. 17H.

Prior to moving BOP 310 laterally over spool 510, rams 127 are transitioned to the open position allowing hydrocarbon fluids emitted by BOP 120 and spool 330 to flow unrestricted therethrough. Rams 127 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Thus, as BOP 310 is moved laterally over spool 510 and lowered into engagement with spool 510, emitted hydrocarbon fluids flow freely through BOP 120, spool 510, and BOP 310.

With a sealed, secure connection between BOP 310 and spool 510, one or both rams 127 and/or valve 220 are transitioned to the closed position with an ROV 170, thereby shutting off the flow of hydrocarbons emitted from wellbore 101. Cables 180 may be decoupled from BOP 310 with ROVs 170 and removed to the surface once BOP 310 is secured to spool 510.

Referring now to FIG. 18, an embodiment of a capping stack 600 for capping wellbore 101 previously described (FIG. 4) and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 600 comprises a BOP 610 and transition spool 330 as previously described coupled to BOP 310. In this embodiment, BOP 610 is releasably coupled to transition spool 330 with a mechanical wellhead-type connector 150 as previously described.

Referring now to FIGS. 19-21, BOP 610 is similar to BOP 410 previously described. In particular, BOP 610 has a central or longitudinal axis 615, and includes a body 612 with a first or upper end 612a, a second or lower end 612b, and a main bore 613 extending axially between ends 612a, b. Upper end 612a comprises a wellhead-type connector male coupling 150a and lower end 612b comprises a wellhead-type connector female coupling 150b. In addition, BOP 610 includes a plurality of axially stacked sets of opposed rams—two sets of opposed upper blind shear rams or blades 127, and one set of opposed blind rams 128, each as previously described. Opposed rams 127, 128 are disposed in cavities that intersect main bore 613 and support rams 127, 128 as they move into and out of main bore 613. Each set of rams 127, 128 is actuated and transitioned between an open position and a closed position. In the open positions, rams 127, 128 are radially withdrawn from main bore 613, and in the closed positions, rams 127, 128 are radially advanced into main bore 613 to close off and seal main bore 613. Each set of rams 127, 128 is actuated and transitioned between the open and closed positions by a pair of actuators 126 as previously described. As best shown in FIG. 20, a frame 616 is connected to body 612 and extends around rams 127. As will be described in more detail below, frame 616 may be used by ROVs 170 to manipulate, rotate, and position BOP 610.

As best shown in FIG. 19, BOP 610 includes a temperature transducer 421 and a pressure transducer 422, each as previously described, positioned along main bore 613 to measure the temperature and pressure, respectively, of the fluids within main bore 613. Transducers 421, 422 are positioned axially below the lowermost set of rams 128 such that transducers 421, 422 can continue to measure the temperature and pressure, respectively, of the wellbore fluids even if rams 127, 128 are closed. Transducers 421, 422 communicate the temperature and pressure measurements to a transmitter 423 as previously described, which then communicates the temperature and pressure measurements to the surface where they may be continuously or periodically monitored.

Referring again to FIGS. 19-21, in this embodiment, BOP 610 also includes a plurality of side outlets 614 extending from main bore 613 through body 612. Each side outlet 614 has a first end 614a in fluid communication with main bore 613, a second end 614b distal main bore 613 and extending from body 612, and a pair of gate valves 614c that controls the flow of fluids through the side outlet 614. As will be described in more detail below, side outlets 614 provide a means for injecting fluids into main bore 613 as well as relieving the pressure of fluids in main bore 613. In other words, side outlets 614 provide passages for introducing fluids into main bore 613 and removing fluids from main bore 613. In this embodiment, each second end 614b comprises a connector hub 617 for connecting other devices thereto. Such other devices may include, without limitation, chokes, pressure relief assemblies (e.g., burst disk assembly), pressure caps, flexible jumpers, etc. In some embodiments, one or more side outlets 614 may be coupled to a containment and/or disposal system such that outlets 614 produce to the containment and/or disposal system once stack 600 is coupled to BOP 120.

In this embodiment, capping stack 600 is installed in stages—transition spool 330 is first deployed and installed subsea onto flex joint 143 as previously described and shown in FIGS. 11A-D, and then, BOP 610 is deployed and installed subsea onto transition spool 330 as described below. To prepare flange 145a of riser adapter 145 for sealing with flange 334 of transition spool 330, riser 115 is removed from flex joint 143, and any tubulars or debris extending upward from flange 145a are preferably cut off substantially flush with flange 145a as previously described.

Referring now to FIGS. 22 and 23, BOP 610 is shown configured for subsea deployment using a deployment assembly 601. In this embodiment, deployment assembly 601 includes a hydrate inhibitor injection system 630 and a running tool 640 which are coupled to BOP 610 for subsea deployment. System 630 includes a perforated riser joint 631 and an injection line 635. Riser joint 631 is a tubular having a first or upper end 631a, a second or lower end 631b, and a plurality of holes 632 along its length. Upper end 631a comprises an annular mounting flange 633 connecting riser joint 631 to running tool 650. Lower end 631b comprises an annular flange 634 connected to a wellhead-type connector female coupling 150b that engages male coupling 150a at upper end 612a, thereby releasably coupling riser joint 631 to BOP 610. Injection line 635 comprises an elongate fluid flow line having a first or inlet end 635a coupled to running tool 640 and a second or outlet end 635b coupled to connector hub 617 of one side outlet 614.

Running tool 640 has a first or upper end 640a removably coupled to a tubular pipe string 650 and a second or lower end 640b comprising an annular flange 641 coupled to flange 633 of riser joint 631. Upper end 640a includes a fluid passage 642 having a first or inlet end 642a in fluid communication with tubing string 650 and a second or outlet end 642b in fluid communication with inlet 635a. As will be described in more detail below, with gate valves 614c opened, a hydrate inhibiting fluid such as glycol may be pumped down string 650, through passage 642, line 635, and side outlet 614 into main bore 613 to reduce the potential for hydrate formation within BOP 610. Lower end 640b of running tool 640 occludes and completely closes off riser joint 631. Thus, any fluids flowing axially upward through main bore 613 (e.g., hydrocarbon fluids, hydrate inhibitors, etc.) and riser joint 631 are blocked by running tool 640 and are forced radially outward through holes 632.

Although running tool 640, perforated riser joint 631, and hydrate inhibitor injection system 630 are shown in conjunction with BOP 610 of capping stack 600, running tool 640, perforated riser joint 631, injection system 630, or combinations thereof may be employed during deployment of other embodiments of BOPs, capping stacks, valve spools, and valve manifolds described herein. In such embodiments, the BOP, capping stack, valve spool, or valve manifold is preferably deployed with a pipe string (e.g., string 650) to enable communication of hydrate inhibiting chemicals to system 630.

In FIGS. 24A-D, BOP 610 is shown being lowered subsea and secured to transition spool 330, which has already been deployed and installed subsea onto flex joint 143 as previously described and shown in FIGS. 11A-D. Referring first to FIG. 24A, BOP 610 is controllably lowered subsea with tubular string 650, which extends from running tool 640 to a surface vessel. A derrick or other suitable device mounted to the surface vessel is preferably employed to support and lower BOP 610 on string 650. Although string 650 is employed to lower BOP 610 in this embodiment, in other embodiments, BOP 610 may be deployed subsea on cables (e.g., cables 180). Using string 650, BOP 610 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101, BOP 120, and transition spool 330 and outside of plume 160 to reduce the potential for hydrate formation within BOP 610. In addition, during deployment and installation of BOP 610, a hydrate inhibitor such as glycol is pumped down tubing string 650, through passage 642, line 635, and side outlet 614 into main bore 613. As BOP 610 is lowered, the injected inhibitor is free to flow upward within main bore 613 into riser joint 631 and out holes 632. In this manner, hydrate inhibitor injection system 630 offers the potential to reduce and/or eliminate hydrate formation during deployment of BOP 610.

Moving now to FIG. 24B, BOP 610 is lowered laterally offset from transition spool 330 and outside of plume 160 until lower end 612b is slightly above spool 330. As BOP 610 descends and approaches spool 330, ROVs 170 monitor the position of BOP 610 relative to spool 330. Next, as shown in FIGS. 24C and 24D, BOP 610 is moved laterally into position immediately above spool 330 with female coupling 150b at lower end 612b substantially coaxially aligned with male coupling 150a at upper end 330a of spool 330. One or more ROVs 170 may utilize their claws 172 and frame 616 to guide and position BOP 610 relative to spool 330.

Due to its own weight, BOP 610 is substantially vertical, whereas spool 330 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of couplings 150a, b may be difficult. With BOP 610 positioned immediately above spool 330 with couplings 150a, b generally coaxially aligned, string 650 lowers BOP 610 axially downward. Due to the weight of BOP 610, compressive loads between BOP 610 and spool 330 urge the male coupling 150a at upper end 330a into the female coupling 150b at lower end 612b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect BOP 610 to spool 330 and form stack 600 as shown in FIG. 24D. Injection of hydrate inhibiting fluids into main bore 613 may continue, as desired, after BOP 610 securely connected to spool 330.

Prior to moving BOP 610 laterally over spool 330, rams 127, 128 and valves 614c are transitioned to the open position allowing hydrocarbon fluids emitted by spool 330 to flow unrestricted through BOP 610 and passages 614 that are not being used for hydrate inhibitor injection, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of BOP 610 to spool 330. Rams 127, 128 and valves 614c may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Thus, as BOP 610 is moved laterally over spool 330 and lowered into engagement with spool 330, emitted hydrocarbon fluids flow freely through main bore 613, riser joint 631 and associated holes 632, and passages 614 that are not being used for hydrate inhibitor injection.

With a sealed, secure connection between BOP 610 and spool 330, wellbore 101 is shut in by closing one or more rams 127, 128, valves 614c, or combinations thereof with ROVs 170. Hydrate inhibitor fluid injection is preferably ceased before shutting in wellbore 101. It should be appreciated that closure of one or both sets of rams 127 shuts off the flow of hydrocarbons through main bore 613 to upper end 612a, but does not impede the flow of emitted hydrocarbons through passages 614. Thus, if lower rams 128 and valves 614c are open, hydrocarbons emitted from wellbore 101 may pass through a portion of main bore 613 and passages 614 into the surrounding sea water, regardless of whether one or both sets of upper rams 127 are closed. Therefore, to completely shut in wellbore 101, lower rams 128 must be closed or valves 414c and at least one set of upper rams 127 must be closed.

Transducers 421, 422 and side outlets 614 offer the potential to reduce the likelihood of an undesirable blowout during and after shutting in wellbore 101. In particular, pressure transducer 422 continuously measures the pressure of wellbore fluids in main bore 413. The measured pressure is communicated to the surface with transmitter 423. If the measured pressure approaches an undesirable level during or after shutting in wellbore 101, rams 127128, valves 614c, or combinations thereof can be opened to relieve wellbore pressure. Chokes or pressure relief assemblies may also be coupled to connector hubs 617 (with corresponding valves 614c open) to help manage wellbore pressure during and after installation of stack 600. For example, ends 614b of side outlets 614 may be closed with a burst disk assembly that prevents fluid flow through ends 614b below a predetermined pressure and allows fluid flow through ends 614b above the predetermined pressure that causes one or more bust disks to rupture. The assembly is preferably designed such that the predetermined pressure is below the pressure at which a blowout may occur such that wellbore pressure is relieved prior to reaching an undesirable level.

As desired, tubular string 650, running tool 650, and riser joint 631 may be disconnected from BOP 610 and removed to the surface by disconnecting wellhead-type connector 150 between riser joint 631 and BOP 610. In addition, injection line 635 is disconnected from connector hub 617 so that it can be removed to the surface along with running tool 650. ROVs 170 may be employed to perform these procedures.

Although capping stack 600 has been shown and described as including BOP 610 and transition spool 330, it should be appreciated that BOP 610 itself may function as a capping stack that is directly connected to BOP 120 in a similar manner as capping stack 400 previously described. In such embodiments, BOP 610 would be configured as shown in FIGS. 22 and 23, and deployed as shown in FIGS. 24A-E, with the exception that female coupling 150b at lower end 612b is directly coupled to male coupling 150a at upper end 123a of BOP 120 following removal of LMRP 140 from BOP 120.

Referring now to FIG. 25, an embodiment of a capping stack 700 for capping wellbore 101 previously described (FIG. 4) and containing the hydrocarbon fluids therein is shown. In this embodiment, capping stack 700 comprises a valve spool 710 and transition spool 330 as previously described coupled to spool 710. In this embodiment, spool 710 is releasably coupled to transition spool 330 with a mechanical wellhead-type connector 150 as previously described.

Referring now to FIGS. 25 and 26, valve spool 710 has a central or longitudinal axis 715, and includes a body 712 with a first or upper end 712a, a second or lower end 712b, and a main bore 713 extending axially between ends 712a, b. In addition, valve spool 710 includes sealing mechanism 220 (i.e., isolation valve 220) as previously described, which controls the flow of fluids through main bore 713—when valve 220 is in an “open” position, valve 220 allows fluid flow through main bore 713 between ends 712a, b, however, when valve 220 is in a “closed” position, valve 220 restricts and/or prevents fluid flow through main bore 713 between ends 712a, b. Valve 220 is transitioned between the open and closed positions with subsea ROVs 170. Depending on the type of actuator (e.g. mechanical or hydraulic) on valve 220, transitioning between the open and closed positions subsea is accomplished either by (a) direct use of an ROV manipulator arm, (b) an ROV-powered torque tool, or (c) means of a “flying lead” hydraulic line coupled to the valve hydraulic actuator. In this embodiment, valve 220 is a ball valve. However, in general, valve 220 may comprise any valve suitable for subsea conditions and containing the anticipated pressure of fluids from wellbore 101 including, without limitation, a gate valve or a ball valve. Further, in other embodiments, the valve spool (e.g., valve spool 710) may include more than one valve (e.g., valve 220) that controls the flow of fluid through the main bore (e.g., bore 713).

In this embodiment, spool 710 is not a flanged spool. Rather, upper end 712a of spool body 712 comprises a wellhead-type connector male coupling 150a, and lower end 612b comprises a wellhead-type connector female coupling 150b. As will be described in more detail below, capping stack 700 is configured to be secured to flex joint 143. T-handles 219 extending radially from spool body 712, enable subsea manipulation of spool 710 with one or more subsea ROVs 170 during deployment and installation of spool 710.

As best shown in FIG. 26, spool 710 includes a temperature transducer 421 and a pressure transducer 422, each as previously described, positioned along main bore 713 to measure the temperature and pressure, respectively, of the fluids within main bore 713. Transducers 421, 422 are positioned axially below isolation valve 220 such that transducers 421, 422 can continue to measure the temperature and pressure, respectively, of the wellbore fluids even if valve 220 is closed. Transducers 421, 422 communicate the temperature and pressure measurements to a transmitter 423 as previously described, which then communicates the temperature and pressure measurements to the surface where they may be continuously or periodically monitored.

Referring again to FIGS. 25 and 26, in this embodiment, valve spool 710 also includes a plurality of side outlets 714 extending from main bore 713 through body 712. Each side outlet 714 has a first end 714a in fluid communication with main bore 713, a second end 714b distal main bore 713 and extending from body 712, and a sealing mechanism 714c that controls the flow of fluids through the side outlet 714. In this embodiment, each sealing mechanism 714c is a valve. Accordingly, valve spool 710 may also be described as a “valve manifold.” As will be described in more detail below, side outlets 714 provide a means for injecting fluids into main bore 713 as well as relieving the pressure of fluids in main bore 713. In other words, side outlets 714 provide passages for introducing fluids into main bore 713 and removing fluids from main bore 713. In this embodiment, each second end 714b comprises a connector hub 617 as previously described for connecting other devices thereto. Such other devices may include, without limitation, chokes, pressure relief assemblies (e.g., burst disk assembly), pressure caps, flexible jumpers, etc. In other embodiments, one or more side outlets 714 may be coupled to a containment and/or disposal system such that outlets 714 produce to the containment and/or disposal system once stack 700 is coupled to BOP 120.

In this embodiment, capping stack 700 is installed in stages—transition spool 330 is first deployed and installed subsea onto flex joint 143 as previously described and shown in FIGS. 11A-D, and then, valve manifold 710 is deployed and installed subsea onto transition spool 330 as described below. To prepare flange 145a of riser adapter 145 for sealing with flange 334 of transition spool 330, riser 115 is removed from flex joint 143, and any tubulars or debris extending upward from flange 145a are preferably cut off substantially flush with flange 145a as previously described.

Referring now to FIGS. 27A-D, valve manifold 710 is shown being lowered subsea and secured to transition spool 330, which has already been deployed and installed subsea onto flex joint 143 as previously described and shown in FIGS. 11A-D. Referring first to FIG. 27A, in this embodiment, valve manifold 710 is shown being controllably lowered subsea with a plurality of cables 180 secured to stack 700 and extending to a surface vessel. Due to the weight of valve manifold 710, cables 180 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower valve manifold 710 on cables 180. Although cables 180 are employed to lower stack 200 in this embodiment, in other embodiments, valve manifold 710 may be deployed subsea on a pipe string.

Moving now to FIG. 27B, valve manifold 710 is lowered laterally offset from transition spool 330 and outside of plume 160 until lower end 712b is slightly above spool 330. As valve manifold 710 descends and approaches spool 330, ROVs 170 monitor the position of valve manifold 710 relative to spool 330. Next, as shown in FIG. 27C, valve manifold 710 is moved laterally into position immediately above spool 330 with female coupling 150b at lower end 712b substantially coaxially aligned with male coupling 150a at upper end 330a of spool 330. One or more ROVs 170 may utilize their claws 172 and handles 219 to guide and position valve manifold 710 relative to spool 330.

Due to its own weight, valve manifold 710 is substantially vertical, whereas spool 330 may be oriented at an angle relative to vertical (e.g., angle α). Thus, it is to be understood that perfect coaxial alignment of couplings 150a, b may be difficult. With valve manifold 710 positioned immediately above spool 330 with couplings 150a, b generally coaxially aligned, cables 180 lower valve manifold 710 axially downward. Due to the weight of valve manifold 710, compressive loads between valve manifold 710 and spool 330 urge the male coupling 150a at upper end 330a into the female coupling 150b at lower end 712b. Once the male coupling 150a is sufficiently seated in the female coupling 150b to form wellhead-type connector 150, connector 150 is hydraulically actuated to securely connect valve manifold 710 to spool 330 and form stack 700 as shown in FIG. 27D. During deployment and installation of valve manifold 710, a hydrate inhibitor injection system similar to system 630 previously described may be used to inject hydrate inhibiting fluids into main bore 713 via one or more side outlets 714.

Prior to moving valve manifold 710 laterally over spool 330, valve 220 and valves 714c are transitioned to the open position allowing hydrocarbon fluids emitted by spool 330 to flow unrestricted through main bore 713 and passages 714, thereby relieving well pressure and offering the potential to reduce the resistance to the coupling of manifold 710 to spool 330. Valves 220, 714c may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170.

With a sealed, secure connection between valve manifold 710 and spool 330, wellbore 101 is shut in by closing valve 220 and valves 714c with ROVs 170. Transducers 421, 422 and side outlets 714 offer the potential to reduce the likelihood of an undesirable blowout during and after shutting in wellbore 101. In particular, pressure transducer 422 continuously measures the pressure of wellbore fluids in main bore 413. The measured pressure is communicated to the surface with transmitter 423. If the measured pressure approaches an undesirable level during or after shutting in wellbore 101, one or more valves 220, 714c can be opened to relieve wellbore pressure. For example, if closure of a particular valve 714c results in a wellbore pressure increase, that valve 714c may be immediately reopened to relieve that increased pressure, thereby potentially avoiding a blowout. Chokes or pressure relief assemblies may also be coupled to connector hubs 617 (with corresponding valves 714c open) to help manage wellbore pressure during and after installation of stack 700. For example, ends 714b of side outlets 714 may be closed with a burst disk assembly that prevents fluid flow through ends 714b below a predetermined pressure and allows fluid flow through ends 714b above the predetermined pressure that causes one or more bust disks to rupture. The assembly is preferably designed such that the predetermined pressure is below the pressure at which a blowout may occur such that wellbore pressure is relieved prior to reaching an undesirable level.

With a sealed, secure connection between valve manifold 710 and spool 330, cables 180 may be decoupled from valve manifold 710 with ROVs 170 and removed to the surface. However, it may be desirable to keep cables 180 connected to valve manifold 710 until after shutting off the flow of hydrocarbons in case valve manifold 710 needs to be lifted back to the surface for any reason (e.g., there is a blowout or failure while shutting in wellbore 101).

Although capping stack 700 has been shown and described as including valve manifold 710 and transition spool 330, it should be appreciated that valve manifold 710 itself may function as a capping stack that is directly connected to BOP 120 in a similar manner as capping stack 400 previously described. In such embodiments, valve manifold 710 would be deployed as shown in FIGS. 27A-E, with the exception that female coupling 150b at lower end 712b is directly coupled to male coupling 150a at upper end 123a of BOP 120 following removal of LMRP 140 from BOP 120.

In the manner described, embodiments of capping stacks described herein (e.g., capping stacks 200, 300, 400, 500, 600, 700) may be deployed subsea from a surface vessel and installed on a subsea BOP (e.g., BOP 120) or LMRP (e.g., LMRP 140) that is emitting hydrocarbon fluids into the surrounding sea. Once securely installed subsea, valves, rams, or combinations thereof are actuated and closed to shut in the wellbore. In some embodiments, pressure and temperature sensors are included to measure the pressure and temperature of the wellbore fluids, thereby enabling an operator to manage the opening and closing of valves and rams in a manner that reduces the likelihood of a blowout while shutting in the wellbore. For example, while shutting in the wellbore, the valves and rams are preferably closed in a sequential order while the wellbore pressure is continuously monitored. In the event closure of a particular valve or ram triggers an undesirable increase in wellbore pressure, that valve or ram (or another valve or ram) may be immediately opened to relieve the increased wellbore pressure, thereby offering the potential to avert a blowout while shutting in the well. Likewise, after the well is shut in, the wellbore pressure may be monitored so that a valve or ram may be opened in the event of an unexpected spike in wellbore pressure to relieve such wellbore pressure increase.

Referring now to FIG. 28, an overview of a method 800 for deploying and installing an embodiment of a subsea capping stack (e.g., capping stack 200, 300, 400, 500, 600, 700) on a failed or damaged subsea BOP or LMRP that is emitting hydrocarbon fluids is shown. Starting in block 801, a suitable subsea landing site is identified. In the embodiment of offshore system 100 previously described, subsea BOP 120 is mounted to wellhead 130 at the sea floor 103, LMRP 140 is mounted to BOP 120 with wellhead connector 150, and riser 115 is coupled to LMRP 140 with a flanged connection. Thus, potential landing sites include riser adapter 145 of LMRP 140 following removal of riser 115 and male coupling 150a at upper end 123a of BOP 120 following removal of LMRP 140 from BOP 120. These represent particularly suitable landing sites as the flanged connection between riser 115 and riser adapter 145 may be broken subsea with the aid of ROVs 170, and connector 150 between BOP 120 and LMRP 140 may be decoupled with the aid of ROVs 170. The ultimate selection of the most desirable landing site may vary from well to well and depends on a variety of factors including, without limitation, the ease with which a particular connection may be broken and re-connected, the type of damage, the component(s) that are damaged (e.g., BOP 120, LMRP 140, riser 115, etc.), the potential for adverse effects when preparing the selected landing site (e.g., exposure of internal debris, trapped pipes, etc.), the potential for increased well flow/hydrocarbon emissions, the ability of the landing site and associated hardware (e.g., BOP 120, LMRP 140, etc.) to take the load of the capping stack, or combinations thereof. Although the description to follow explains the procedures for deploying a “capping stack,” it should be appreciated that embodiments of capping stacks that are deployed in multiple stages (e.g., capping stack 300 in which transition spool 330 is deployed and installed to LMRP 140 followed by deployment and installation of BOP 310 onto transition spool 330), each component is preferably deployed in substantially the same manner as described in method 800, albeit the landing site of the second component deployed will be the upper end of the first component deployed.

Moving now to block 805, if the selected landing site is LMRP 140, the flanged connection between riser 115 and riser adapter 145 is broken, and riser 115 is removed from riser adapter 115 according to block 806. On the other hand, if the selected landing site it BOP 120, connector 150 between LMRP 140 and BOP 120 is broken, and LMRP 140 is removed from BOP 120 according to block 807. Identification of the landing site also defines the connection that will be needed at the lower end of the capping stack. For example, if male coupling 150a on upper end 123a of BOP 120 is the landing site, the lower end of the capping stack preferably comprise a mating female coupling 150b configured to mate and engage male coupling 150a of BOP 120. Alternatively, if the landing site is riser adapter 145, the lower end of the capping stack preferably comprises a flange configured to mate and engage with flange 145a of riser adapter 145.

After preparation of the landing site via block 806 or 807, the capping stack is deployed from a surface vessel in and lowered subsea in block 810. The valves and rams in the capping stack are preferably opened during deployment and installation to allow the discharged hydrocarbon stream to pass therethrough unrestricted. To minimize the potential for hydrate formation during deployment, the capping stack is lowered laterally offset from the landing site and out of the plume of hydrocarbons emitted from the subsea landing site according to block 811. Moving now to block 812, while laterally offset from the landing site and outside the hydrocarbon plume, the capping stack is lowered until is immediately axially above the landing site. Next, the capping stack is moved laterally over the landing site, and properly alignment with the landing site (e.g., coaxially align mating couplings 150a, b, align pins 217 with mating holes guide holes 148 in flange 145a, etc.) in block 814. ROVs 170 are preferably employed to properly position and orient the capping stack relative to the landing site. Moving now to blocks 815 and 816, the capping stack is lowered into engagement with the landing site and secured thereto. In embodiments described herein, the capping stack is secured to the landing site with a flanged connection or wellhead-type connector 150.

With the capping stack securely connected to the landing site, flow of hydrocarbons through the capping stack is reduced by closing one or more valves and/or rams according to block 820. While shutting in wellbore 101, the wellbore pressure is continuously monitored in block 821. If the wellbore pressure increases to an undesirable level in block 822, wellbore pressure is relieved by opening one or more valves or rams, thereby allowing wellbore hydrocarbons to vent into the sea according to block 823. If, however, the wellbore pressure remains within acceptable limits in block 822, wellbore 101 may continue to be shut in according to block 824. When wellbore 101 is completely shut in, the flow of hydrocarbons into the surrounding sea ceases.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

SYSTEMS AND METHODS FOR CAPPING A SUBSEA WELL

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