Systems And Methods For Collecting Hydrocarbons Vented From A Subsea Discharge Site

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Invention

The invention relates generally to systems and methods for collecting hydrocarbons vented from a subsea discharge site. More particularly, the invention relates to systems and methods for collecting the bulk hydrocarbon flow from a pre-determined, controlled subsea pressure exhaust vent point.

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) is 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 and/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 some scenarios, it may be necessary to vent hydrocarbon fluids into the surrounding sea to manage wellbore pressures and/or protect equipment from damage. This situation would typically arise where a fluid conduit (e.g., choke line) for flowing the exhausted hydrocarbon fluids from the subsea vent point to the surface is not already in place or has been damaged. For example, a subsea blowout may damage the subsea BOP, LMRP, or riser, potentially resulting in the discharge of hydrocarbons into the surrounding sea. One approach to capping and shutting-in the subsea well is to lower a capping stack subsea, couple the capping stack to the upper end of the subsea BOP or LMRP that is discharging hydrocarbons, and then utilize the capping stack to shut-in the well. Examples of capping stacks, methods of deploying and installing capping stacks, and methods of containing a subsea well with capping stacks are described in U.S. Patent Application Ser. No. 61/475,032 filed Apr. 13, 2011 and entitled “Systems and Methods for Capping a Subsea Well,” which is hereby incorporated herein by reference in its entirety for all purposes. However, due to pressure limitations of the wellbore, ay not be desirable or safe to completely shut-in the well with the capping stack. Accordingly, hydrocarbon fluids may be controllably vented from the well through the capping stack into the surrounding sea.

As another example, a sudden and potentially prolonged release of hydrocarbon fluids at a subsea discharge site may result from the shut-in of a surface flow containment vessel during a cap and flow response operation. In particular, a normally closed discharge site protected by a pressure safety valve or burst disc assembly may open in response to a shut-in and associated wellbore pressure increase. As still yet another example, a choke outlet on a capping stack mounted to a subsea BOP may be allowed to vent hydrocarbons subsea during a relief well bottom-kill operation.

Traditionally, hydrocarbon fluids discharged into the sea are allowed to rise to the surface, where they are treated with chemical dispersing agents, which are specially formulated chemical products containing surface-active agents and a solvent. Dispersants aid in breaking up hydrocarbon solids and liquids by reducing the interfacial tension between the oil and water, thereby promoting the migration of finely dispersed water-soluble micelles that are rapidly diluted. As a result, the hydrocarbons are effectively spread throughout a larger volume of water, and the environmental impact may be reduced. Typically, dispersants are sprayed onto the oil at the surface of the water. However, since oil released from a subsea well diffuses and spreads out at it rises to the surface, oil at the surface is often spread out over a relatively large area (e.g., hundreds or thousands of square miles). To sufficiently cover all or substantially all of the oil that reaches the surface, relatively large quantities of dispersant must be distributed over the relatively large area encompassed by the oil slick. To minimize “overspray” and limit the application of dispersants to the oil slick itself, distribution at the surface typically involves the visualization of the oil slick at the surface. Accordingly, around the clock surface distribution may not be possible (e.g., at night the location and boundaries of the oil slick at the surface may not be visible). It should also be appreciated that some turbulence at the surface (e.g., wave action) is preferred during surface application of dispersants to sufficiently mix the dispersant into the oil and the treated oil into the water. Depending on the weather and sea conditions, surface turbulence may be less than adequate.

Accordingly, there remains a need in the art for systems and methods to contain and capture hydrocarbon fluids discharged subsea. Such systems and methods would be particularly well-received if they offered the potential to capture the hydrocarbon fluids at the subsea discharge site to reduce and/or eliminate the need to apply chemical dispersants at the surface.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a method for capturing at least a portion of hydrocarbon fluids vented into the surrounding sea from a subsea discharge site. In an embodiment, the method comprises (a) mounting a pressure control device to the subsea discharge site. Further, the method comprises (b) flowing the vented hydrocarbon fluids from the subsea discharge site through the pressure control device. Still further, the method comprises (c) positioning a collection system subsea on a lower end of a tubular string. Moreover, the method comprises (d) flowing the vented hydrocarbons fluids from the pressure control device into the collection system and through the tubular string after (b). The method also comprises (e) minimizing lateral loads applied to the subsea discharge site by the collection system.

These and other needs in the art are addressed in another embodiment by an assembly for capturing at least a portion of hydrocarbon fluids vented into the surrounding sea from a subsea discharge site. In an embodiment, the assembly comprises a collection system including a connection member, an overshot tool, and a flexible conduit extending from the overshot tool to the connection member. The connection member has a central axis, an upper end, a lower end, and a flow passage extending axially from the upper end to the lower end, the upper end configured to releasably connect to a lower end of a tubular string and the lower end coupled to the flexible conduit. The overshot tool has a central axis, an upper end coupled to the flexible conduit, a lower end, and a flow passage extending from the lower end of the overshot tool to the upper end of the overshot tool. The overshot tool includes an elongate slot extending axially from the lower end and extending radially through the overshot tool to the flow passage of the overshot tool. The flexible conduit is in fluid communication with the flow passage of the overshot tool and the flow passage of the connection member.

These and other needs in the art are addressed in another embodiment by an assembly for capturing at least a portion of hydrocarbon fluids vented into the surrounding sea from a subsea discharge site. In an embodiment, the assembly comprises a collection system including a connection member and an overshot tool. The connection member has a central axis, an upper end, a lower end, and a flow passage extending axially from the upper end to the lower end, the upper end configured to releasably connect to a lower end of a tubular string and the lower end comprising a funnel guide. The overshot tool has a central axis, an upper end, a lower end, a flow passage extending from the lower end of the overshot tool to the upper end of the overshot tool. The overshot tool includes a coupling member at the lower end of the overshot tool and an elongate stabbing member extending axially from the coupling member to the upper end of the overshot tool. The stabbing member is slidingly disposed in the flow passage of the connection member.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. 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. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 3 is a schematic front view of an embodiment of a capping stack mounted to the BOP of FIG. 2;

FIG. 4 is an enlarged schematic front view of the capping stack of FIG. 3;

FIG. 5 is an enlarged schematic side view of the capping stack of FIG. 3;

FIG. 6 is a partial cut-away side view of an embodiment of a subsea pressure control device for connecting to one of the side outlets of the capping stack of FIG. 3;

FIG. 7 is a front view of the pressure control device of FIG. 6;

FIGS. 8-11 are sequential schematic views of the deployment and installation of the pressure control device of FIG. 6 onto the capping stack of FIG. 3;

FIG. 12 is a side view of an embodiment of a collection apparatus for capturing hydrocarbon fluids exhausted from a subsea discharge site;

FIG. 13 is an enlarged view of the connection member of FIG. 12;

FIG. 14 is an enlarged view of the overshot tool of FIG. 12;

FIGS. 15-17 are sequential schematic views illustrating the collection apparatus of FIG. 12 being deployed subsea and positioned to collect hydrocarbons discharged from the pressure control device of FIG. 11;

FIG. 18 is a side view of an embodiment of a collection assembly for capturing hydrocarbon fluids exhausted from a subsea discharge site;

FIG. 19 is an enlarged view of the connection member of FIG. 18;

FIG. 20 is an enlarged view of the overshot tool of FIG. 18;

FIGS. 21-26 are sequential views illustrating the collection assembly of FIG. 17 being deployed subsea and positioned to collect hydrocarbons discharged from the pressure control device of FIG. 11;

FIG. 27 is a front view of an embodiment of a collection apparatus for capturing hydrocarbon fluids exhausted from a subsea discharge site; and

FIGS. 28-30 are sequential views illustrating the collection apparatus of FIG. 27 being deployed subsea and positioned to collect hydrocarbons discharged from the pressure control device of FIG. 11.

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 or mobile offshore drilling unit (MODU) 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 attached to BOP 120. 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 MODU 110. During drilling operations, riser 115 takes mud returns to the MODU 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 MODU 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 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 releasably secured to LMRP 140, a lower end releasably secured to wellhead 130, and a main bore 124 extending axially between the upper and lower ends. Main bore 124 is coaxially aligned with wellbore 101, thereby allowing fluid communication between wellbore 101 and main bore 124. In this embodiment, BOP 120 is releasably coupled to LMRP 140 and wellhead 130 with hydraulically actuated, mechanical wellhead-type connectors 150. In general, connectors 150 may comprise any suitable releasable wellhead-type mechanical connector such as the H-4® profile subsea connector available from VetcoGray Inc. of Houston, Tex. or the DWHC profile subsea connector available from Cameron International Corporation of Houston, Tex. Typically, such wellhead-type mechanical connectors (e.g., connectors 150) comprise a male component or coupling that is inserted into and releasably locked within a mating female component or coupling. In addition, BOP 120 includes a plurality of axially stacked sets of opposed rams—opposed blind shear rams or blades 127 for severing tubular string 116 and sealing off wellbore 101 from riser 115, opposed blind rams 128 for sealing off wellbore 101 when no string (e.g., string 116) or tubular extends through main bore 124, and opposed pipe rams 129 for engaging string 116 and sealing the annulus around tubular string 116. Each set of rams 127, 128, 129 is equipped with sealing members that engage to prohibit flow through the annulus around string 116 and/or main bore 124 when rams 127, 128, 129 is closed.

Opposed rams 127, 128, 129 are disposed in cavities that intersect main bore 124 and support rams 127, 128, 129 as they move into and out of main bore 124. Each set of rams 127, 128, 129 is actuated and transitioned between an open position and a closed position. In the open positions, rams 127, 128, 129 are radially withdrawn from main bore 124 and do not interfere with tubular string 116 or other hardware that may extend through main bore 124. However, in the closed positions, rams 127, 128, 129 are radially advanced into main bore 124 to close off and seal main bore 124 (e.g., rams 127, 128) or the annulus around tubular string 116 (e.g., rams 129). Each set of rams 127, 128, 129 is actuated and transitioned between the open and closed positions by a pair of actuators 126. In particular, each actuator 126 hydraulically moves a piston within a cylinder to move a drive rod coupled to one ram 127, 128, 129.

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

In this embodiment, the upper end 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. Flex joint 143 includes a riser adapter 145 with an annular flange 145a at its upper end for coupling to a mating annular flange 118 at the lower end of riser 115 or to alternative devices. 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 this embodiment, BOP 120 includes three sets of rams (one set of shear rams 127, one set of pipe rams 129, and one blind rams 128), 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 and one set of pipe rams), 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.

Referring now to FIG. 2, during a “kick” or surge of formation fluid pressure in wellbore 101, resulting in a blowout, potentially resulting in the discharge of such hydrocarbon fluids subsea in the form of a plume 160 that extends to the sea surface 102. In FIG. 2, system 100 is shown after a subsea blowout. To contain and control the subsea well and the emission of hydrocarbon fluids, a capping stack may be deployed subsea and installed onto BOP 120 as described in U.S. Patent Application Ser. No. 61/475,032 filed Apr. 13, 2011 and entitled “Systems and Methods for Capping a Subsea Well,” which is hereby incorporated herein by reference in its entirety for all purposes.

Referring now to FIGS. 3-5, an exemplary capping stack 200 for capping and controlling wellbore 101 previously described (FIG. 2) is shown. In this embodiment, capping stack 200 comprises a drilling BOP 210 similar to BOP 120 previously described. In particular, BOP 210 has a central or longitudinal axis 215, and includes a body 212 with a first or upper end 212a, a second or lower end 212b, and a main bore 213 extending axially between ends 212a, b. Upper end 212a comprises a male coupling of a wellhead-type connector 150 and lower end 212b comprises the female coupling of a wellhead-type connector 150. In addition, BOP 210 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 213 and support rams 127, 128, 129 as they move into and out of main bore 213. 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 213, and in the closed positions, rams 127, 128, 129 are radially advanced into main bore 213 to close off and seal main bore 213. 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. 4, a plurality of T-handles 219 extend radially outward from body 212, and enable ROVs to manipulate, rotate, and position stack 200 during subsea deployment.

Referring still to FIGS. 3-5, in this embodiment, stack 200 also includes a plurality of side outlets 214 extending from main bore 213 through body 212. Each side outlet 214 has a first end 214a in fluid communication with main bore 213, a second end 214b distal main bore 213 and extending from body 212, and an isolation valve 214c that controls the flow of fluids through the side outlet 214. Side outlets 214 provide a means for relieving the pressure of fluids in main bore 213. For example, 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 210) 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, as shown in FIG. 3, main bore 213, one or more side outlets 214, or combinations thereof may be opened to vent wellbore fluids and relieve pressure within wellbore 101. Second end 214b of each side outlet 214 comprises an upward facing male component or coupling 216 that is received by and releasably locked within a mating female component or coupling.

Referring now to FIGS. 6 and 7, an embodiment of a wellbore pressure control device 300 that can be releasably coupled to a side outlet 214 of capping stack 200 to control the discharge of hydrocarbon fluids and manage wellbore fluid pressures is shown. In this embodiment, pressure control device 300 is a choke assembly having a central axis 305, a first or upper end 300a, and a second or lower end 300b opposite end 300a. In addition, choke assembly 300 includes an annular receiving guide 310 at lower end 300b, a downward facing female component or coupling 320 axially adjacent guide 310, a choke valve 330 at upper end 300a, and a tubular fluid conduit 340 extending axially between coupling 320 and choke valve 330.

Receiving guide 310 includes an inner passage 311 extending axially from lower end 300b to coupling 320. At lower end 300b, passage 311 comprises an inverted frustoconical guide surface 312 configured to receive and guide second end 214b of side outlet 214 into coupling 320. A pair of handles 313 extend radially outward from guide 310 and enable ROVs to manipulate, rotate, and position device 300 during subsea deployment.

Female coupling 320 is configured to matingly receive and releasably lock onto coupling 216 of side outlet 214, thereby securing choke assembly 300 to side outlet 214. In this embodiment, coupling 320 is a hydraulically actuated, mechanical connector that releasably locks onto and sealingly engages coupling 216. More specifically, when coupling 216 at end 214b of side outlet 214 is sufficiently seated within connector 320, connector 320 is hydraulically actuated to releasably lock onto end 214b. In general, couplings 216, 320 may comprises any suitable types of connectors known in the art for forming a secure, releasably connection between side outlet 214 and choke assembly 300. Examples of suitable types of couplings include, without limitation, three inch Choke and Kill Connector available from Cameron international Corporation of Houston, Tex.; the Optima Subsea Connector available from Vector Group, Inc. of Houston, Tex.; and the RIC and RAC connectors available from Oil States international, Inc. of Arlington, Tex.

Referring still to FIGS. 6 and 7, choke valve 330 has an inlet 331, an outlet 332, and is configured to choke the flow of fluids through pressure control device 300. A tubular exhaust conduit 335 attached to choke valve 330 has a lower inlet end 335a in fluid communication with outlet 332 and an open, upper outlet end 336b opposite end 335a. Conduit 340 extends from coupling 320 to choke valve 330 and provides fluid communication between coupling 320 and inlet 331. Thus, when device 300 is mounted to side outlet 214, hydrocarbon fluids flowing through side outlet 214 exit end 214b within coupling 320 and flow through conduit 340 and inlet 331 into choke valve 330, where the hydrocarbon fluid flow is restricted. The choked or restricted fluid flow exits choke valve 330 through outlet 332, and flows through conduit 335 into the surrounding environment at open end 335b. In this embodiment, conduit 335 includes a 90° bend between ends 335a, b that allows inlet end 335a to be oriented perpendicular to axis 305 and outlet end 335b to be oriented parallel to axis 305.

In this embodiment, pressure control device 300 also includes an ROV control panel 350 that enables a subsea ROV to operate choke valve 330, as well as operate the other functions of device 300. In particular, device 300 includes a hydraulic fluid control valve 351a, a test fluid control valve 352a, a chemical injection control valve 353a, and a chemical dispersant control valve 354a. Each valve 351a, 352a, 353a, 354a is mounted to control panel 350 and is accessed and controlled subsea with an ROV via an associated valve actuation member 351b, 352b, 353b, 354b, respectively, disposed on control panel 350. Each valve 351a, 352a, 353a, 354a has an inlet coupled to a fluid inlet supply line and an outlet coupled to a fluid outlet supply line. For purposes of clarity the inlet supply lines and the outlet supply lines are not shown in FIGS. 6 and 7. In particular, the inlet of valve 351a is connected to a pressurized hydraulic fluid supply line, inlet of valve 352a is connected to a test fluid supply line, the inlet of valve 353a is connected to a chemical injection supply line, and an inlet of valve 354a is connected to a chemical dispersant supply line. The outlet of valve 351a selectively supplies pressurized hydraulic fluid to connector 320 to actuate connector 320 between the locked and unlocked positions; the outlet of valve 352a selectively supplies testing fluids (e.g., glycol, methanol, etc.) to device 300 proximal choke valve inlet 331; the outlet of valve 353a selectively supplies chemicals (e.g., methanol) to inlet end 335a of exhaust conduit 335; and the outlet of valve 354a selectively supplies dispersant (e.g., Corexit® EC9500A available from Nalco Company of Naperville, Ill.) to conduit 335 between ends 335a, b. A choke valve actuator member 355 is positioned axially above control panel 350 and allows a subsea ROV to actuate choke valve 330.

Referring now to FIGS. 8-11, pressure control device 300 is shown being deployed and installed subsea on end 214b of one side outlet 214 to choke and control the flow of hydrocarbons exhausted from capping stack 200. More specifically, in FIG. 8, device 300 is shown being lowered subsea; in FIG. 9, device 300 is shown being moved laterally over end 214b of one side outlet 214; in FIG. 10, device 300 is shown being generally coaxially aligned with end 214b and lowered into engagement with side outlet 214; and in FIG. 11, device 300 is shown being secured to end 214b of side outlet 214. For purposes of clarity and further explanation, the side outlet 214 to which device 300 is mounted (the side outlet 214 shown on the right in FIGS. 8-11) is designated with reference numeral 214′ to distinguish it from the other side outlet 214 (the side outlet 214 shown on the left in FIGS. 8-11), which is designated with reference numeral 214″.

To simplify installation operations and enable device 300 to be installed easier, valve 214c associated with the side outlet 214′ is preferably closed prior to and during installation of device 300. However, to ensure relief of pressure within main bore 213 and wellbore 101, valve 214c associated with the other side outlet 214″ is preferably open prior to and during installation of device 300. In the exemplary installation sequence shown in FIGS. 8-11, valve 214c of the side outlet 214′ is closed prior to and during installation of device 300, valve 214c of side outlet 214″ is open prior to and during installation of device 300, and main bore 213 is closed downstream of ends 214a (e.g., one or more rams 127, 128, 129 are closed) prior to, during, and after installation of device 300. Following installation of device 300, valve 214c of side outlet 214′ is opened, valve 214c of side outlet 214″ is closed, main bore 213 remains closed, and device 300 is employed. to choke the flow through side outlet 214′.

For subsea deployment and installation of device 300, one or more remote operated vehicles (ROVs) are preferably employed to aid in positioning device 300, monitoring device 300, BOP 120, and capping stack 200, and selectively actuating valves 330, 351a, 352a, 353a, 354a. In this embodiment, two ROVs 170 are provided to facilitate the installation and operation of device 300 as well as monitor device 300 and BOPs 120, 210. 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 and device 300, 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. 8, in this embodiment, device 300 is shown being controllably lowered subsea with a plurality of wireline cables 180 secured to device 300 and extending to a surface vessel. A winch or crane mounted to a surface vessel is preferably employed to support and lower device 300 on cables 180.

Using cables 180, device 300 is lowered subsea under its own weight from a location generally above and laterally offset from wellbore 101 and capping stack 200. More specifically, during deployment, device 300 is preferably maintained outside of plume 160 of hydrocarbon fluids emitted from cap 200. Lowering device 300 subsea in plume 160 may trigger the undesirable formation of hydrates within device 300, particularly at elevations substantially above sea floor 103 where the temperature of hydrocarbons in plume 160 is relatively low.

Moving now to FIG. 9, device 300 is lowered laterally offset from stack 200 and outside of plume 160 until guide 310 is slightly above end 214b of closed side outlet 214′. As device 300 descends and approaches capping stack 200, ROVs 170 monitor the position of device 300 relative to capping stack 200. Next, as shown in FIG. 10, device 300 is moved laterally into position immediately above end 214b of side outlet 214′ with guide 310 substantially coaxially aligned with end 214b. One or more ROVs 170 may utilize their claws 172 and handles 313 to guide and rotate device 300 into proper alignment relative to end 214b.

With guide 310 positioned immediately above and generally coaxially aligned with end 214b of side outlet 214′, cables 180 lower device 300 axially downward, thereby inserting and axially advancing end 214b of side outlet 214′ into guide 310 and coupling 320 until end 214b is sufficiently seated in coupling 320. The frustoconical guide surface 312 at lower end 300b functions to guide end 214b into coupling 320, even if end 214b is initially slightly misaligned with guide 310. Prior to moving device 300 laterally over side outlet 214′, choke valve 330 is preferably transitioned to the open position. Choke valve 330 may be transitioned to the open position at the surface 102 prior to deployment, or subsea via one or more ROVs 170. Since outlet 214′ was previously closed, there is little to no resistance to the axial insertion of end 214b into guide 310 and coupling 320.

With end 214b sufficiently seated in coupling 320, an ROV 170 actuates coupling 320 to lock onto mating coupling 216 at end 214b, thereby securing device 300 onto side outlet 214′. Once device 300 is securely coupled to side outlet 214′, cables 180 may be decoupled from stack 200 with ROVs 170 and removed to the surface. With a sealed, secure connection between device 300 and side outlet 214′, valve 214c of side outlet 214′ is opened, thereby allowing emitted hydrocarbon fluid to flow freely through outlets 214′, 214″ and device 300. Next, valve 214c of outlet 214″ is closed, and choke valve 330 may be adjusted (e.g., transitioned to a partially closed position) with an ROV 170 to achieve the desired pressure and flow through side outlet 214′. In some cases, it may be necessary to continue to vent hydrocarbon fluids through side outlet 214′ and device 300 to manage wellbore pressures. Any such vented hydrocarbon fluids from device 300 or other subsea structure (e.g., subsea manifold) are preferably captured and contained to minimize environmental impacts. Embodiments of system and methods for capturing and collecting hydrocarbons vented from device 300 following connection of device 300 to side outlet 214′ are described in more detail below.

Referring now to FIGS. 4, an embodiment of collection system 400 for capturing hydrocarbon fluids exhausted from a subsea discharge site (e.g., hydrocarbons discharged from exhaust conduit 335) is shown. System 400 has a central or longitudinal axis 405, a first or upper end 400a, and a second or lower end 400b opposite end 400a. In this embodiment, system 400 includes a connection member 410 at upper end 400a, an overshot tool 420 at lower end 400b, and a flexible conduit 430 extending from connection member 410 to overshot tool 420. Connection member 410, tool 420, and flexible conduit 430 are connected end-to-end with connectors 440.

As best shown in FIG. 13, connection member 410 has a central axis 415 coincident with axis 405, a first or upper end 410a defining upper end 400a of system 400, a second or lower end 410b coupled to conduit 430 with connector 440, and a central through bore 411 extending axially between ends 410a, b. In this embodiment, connection member 410 includes a J-latch coupling 412 extending axially from upper end 410a, an elongate pipe 413 extending axially from lower end 410b to J-latch coupling 412, and an ROV control panel 414 attached to pipe 413. ROV control panel 414 is disposed along pipe 413 axially below latch coupling 412 and includes a stabbing port for injecting a hydrate inhibitor (e.g., methanol) into pipe 413 to reduce and/or prevent the formation of hydrates downstream of pipe 413.

J-latch coupling 412 comprises a rigid tubular body 416 having an annular funnel guide 417 at upper end 410a and a pair of circumferentially spaced J-slots 418 positioned axially adjacent guide 417. In this embodiment, J-slots 418 are angularly spaced 180° apart relative to axis 415. As is known in the art, a J-slot defines a track on a first device that releasably receives a mating pin on a second device to releasably couple the first and second devices. Once made-up, a J-slot connection is capable of transferring tensile and compression axial loads, as well as rotational torque. In this embodiment, each J-slot 418 extends radially through body 416 to bore 411 and is configured to slidingly receive a pin on the lower end of a tubular string (e.g., drillstring) to releasably couple connection member 410 and system 400 to the tubular string for subsea deployment and manipulation.

Referring now to FIG. 14, overshot tool 420 has a central axis 425 coincident with axis 405, a first or upper end 420a coupled to conduit 430 with one connector 440, a second or lower end 420b defining end 400b of system 400, and a central through bore 421 extending axially between ends 420a, b. In this embodiment, overshot tool 420 comprises a rigid tubular body 422 having an elongate slot 423 extending axially from lower end 420b and extending radially through body 422 to bore 421. Slot 423 defines opposed lateral edges 424. In this embodiment, a resilient rubber bumper 426 is mounted to each edge 424 proximal the upper end of slot 423. As will be described in more detail below, bumpers 426 provide a resilient, flexible surface configured to slidingly engage conduit 335 of pressure control device 300 when system 400 is mounted thereto. Overshot tool 420 also includes a pair of handles 427 that extend radially outward from body 422 and enable ROVs to manipulate, rotate, and position system 400 during subsea deployment.

Referring now to FIGS. 15-17, hydrocarbon collection system 400 is shown being deployed subsea and positioned to capture hydrocarbons discharged from exhaust conduit 335. More specifically, in FIG. 15, system 400 is shown being lowered subsea; in FIG. 16, system 400 is shown being moved laterally over outlet end 335b of exhaust conduit 335; and in FIG. 17, system 400 is shown being advanced over outlet end 335b of exhaust conduit 335 to capture hydrocarbons emitted therefrom. For subsea deployment and installation of collection system 400, one or more ROVs 170 are preferably employed to aid in positioning collection system 400 and monitoring collection system 400, pressure control device 300, BOPs 120, and capping stack 200.

Referring first to FIG. 15, system 400 is coupled to the lower end of a tubular string 700 at the surface 102 with J-latch coupling 412, and is then controllably lowered subsea with string 700. A derrick or other suitable device mounted to a surface vessel is preferably employed to support and lower system 400 on string 700.

Using string 700, system 400 is lowered subsea from a location generally above and laterally offset from exhaust conduit 335. More specifically, during deployment, system 400 is preferably maintained outside of plume 160 of hydrocarbon fluids emitted from exhaust conduit 335. Lowering system 400 subsea in plume 160 may trigger the undesirable formation of hydrates within system 400 and/or string 700, particularly at elevations substantially above sea floor 103 where the temperature of hydrocarbons in plume 160 is relatively low. As system 400 is lowered subsea, a hydrate inhibitor (e.g., methanol) may be injected into pipe 413 via a subsea ROV 170 and control panel 414. Any injected inhibitor is free to flow upward within the remainder of system 400 and string 700. In addition to injection of a hydrate inhibitor, or as an alternative thereto, string 700 can be filled with an inert gas such as nitrogen to help prevent the formation of hydrates therein during installation of system 400.

Referring now to FIGS. 15 and 16, system 400 is lowered laterally offset from exhaust conduit 335 and outside of plume 160 until overshot tool 420 is slightly above outlet end 335b. As system 400 descends and approaches device 300, ROVs 170 monitor the position of system 400 relative to capping stack 200 and device 300. Next, system 400 is rotated and oriented to circumferentially align conduit 335 with slot 423.

Moving now to FIGS. 16 and 17, system 400 is moved laterally into position immediately above end 335b with tool 420 substantially coaxially aligned with end 335b. One or more ROVs 170 may utilize their claws 172 and handles 427 to guide and rotate system 400 into proper alignment relative to exhaust conduit 335.

As best shown in FIG. 17, with overshot tool 420 positioned immediately above outlet end 335b, generally coaxially aligned with end 335b, and with slot 423 circumferentially aligned with conduit 335, string 700 lowers system 400 axially downward, thereby inserting and axially advancing end 335b of exhaust conduit 335 into overshot tool 420. As vertically oriented end 335b axially advances into through bore 421, the horizontal portion of conduit 335 extends radially through and slidingly engages slot 423. Conduit 335 is preferably advanced through overshot tool 420 until resilient bumpers 426 engage conduit 335 proximal upper end 422a.

With end 335b sufficiently seated in overshot tool 420, hydrocarbon fluids discharged from exhaust conduit 335 flow upward through system 400 and string 700 to the surface where they may be captured and contained. A hydrate inhibitor (e.g., methanol) may be injected into pipe 413 via control panel 414 while system 400 is being lowered over the exhaust and/or during collection of discharged hydrocarbons to prevent and/or reduce the formation of hydrates within J-latch coupling 412 and string 700.

During collection operations, the weight of system 400 is supported by string 700 to minimize the transfer of any loads to exhaust conduit 335 and pressure control device 300. Minimizing loads on exhaust conduit 335 as well as the flexibility of conduit 430 of collection system 400 offers the potential to reduce the chances of inadvertently damaging conduit 335 and/or control device 300, particularly if the deployment vessel at the surface 102 experiences a sudden lateral or vertical movement.

Referring now to FIGS. 18-20, an embodiment of a collection system 500 for capturing hydrocarbon fluids exhausted from a subsea discharge site (e.g., hydrocarbons discharged from exhaust conduit 335) is shown. In this embodiment, system 500 includes a connection member 510 and an overshot tool 520. Connection member 510 is hung from the lower end of a tubular string (e.g., string 700), and overshot tool 520 is coupled to the discharge site and is slidingly received by the connection member 510 subsea.

As best shown in FIG. 19, connection member 510 has a central axis 515, a first or upper end 510a, a second or lower end 510b opposite end 510a, and a central through passage 511 extending axially between ends 510a, b. In this embodiment, connection member 510 includes a J-latch coupling 412 as previously described extending axially from upper end 510a and an elongate pipe 513 extending axially from lower end 510b to J-latch coupling 412.

Referring still to FIG. 19, J-latch coupling 412 comprises a rigid tubular body 416 having an annular funnel guide 417 at upper end 410a and a pair of circumferentially spaced J-slots 418 positioned axially adjacent guide 417. Each J-slot 418 extends radially through body 416 to passage 511 and is configured to slidingly receive a pin on the lower end of a tubular string (e.g., drillstring) to releasably couple connection member 510 to the tubular string for subsea deployment and manipulation

Pipe 513 comprises a rigid tubular body 514 having a generally rectangular funnel guide 516 at lower end 510b and a pair of handles 517 axially adjacent guide 516. Handles 517 extend radially outward from body 514 and enable ROVs to manipulate, rotate, and position connection member 510 during subsea deployment. The upper end of pipe 513 is coupled to the lower end of J-latch coupling 412 with a flex joint 518 that allows pipe 513 to pivot relative to J-latch coupling 412. An ROV control panel (e.g., ROV control panel 414) may be disposed along pipe 513 axially below J-latch coupling 512 for injecting a hydrate inhibitors (e.g., methanol) into pipe 513 to reduce and/or prevent the formation of hydrates downstream of pipe 513.

Referring now to FIG. 20, overshot tool 520 has a central axis 525, a first or upper end 520a, a second or lower end 520b opposite end 520a, and a central through bore 521 extending axially between ends 520a, b. In this embodiment, overshot tool 520 includes a coupling member 522 at lower end 520b and an elongate stabbing member 523 extending from coupling member 522 to upper end 520a. A flex joint (e.g., flex joint 518) can be provided between stabbing member 523 and coupling member 522 if additional flexibility along tool 520 is desired. Coupling member 522 comprises a rigid tubular body 523, a handle 524, and a plurality of circumferentially spaced locking members 526. Handle 524 extends radially outward from body 523 and enables ROVs to manipulate, rotate, and position overshot tool 520 during subsea deployment. Locking members 526 releasably secure overshot tool 520 to the hydrocarbon discharge site (e.g., end 335b of exhaust conduit 335). In this embodiment, three locking members 526 uniformly spaced 90° apart are provided. Further, in this embodiment, each locking member 526 is a T-bolt that threadingly engages a mating bore extending radially through body 523. In particular, each locking member 526 has a first or radially outer end 526a disposed outside body 523 and a second or radially inner end (not shown) extending into bore 521. End 526a of each locking member 526 is a T-handle that enables an ROV to rotate the corresponding locking member 526 to thread it radially inward and outward through body 523.

Stabbing member 523 extends axially from coupling member 522 and comprises a rigid tubular pipe 527 having an angle mule shoe tip 528 at upper end 520a. Tip 528 facilities the axially insertion of stabbing member 523 into funnel guide 516 of pipe 513 and passage 511 at lower end 510b.

Referring now to FIGS. 21-25, hydrocarbon collection system 500 is shown being deployed subsea and positioned to capture hydrocarbons discharged from exhaust conduit 335. More specifically, in FIG. 21, overshot tool 520 is shown being lowered subsea; in FIG. 22, overshot tool 520 is shown being positioned over outlet end 335b of conduit 335; in FIG. 23, overshot tool 520 is shown being mounted to exhaust conduit 335; in FIG. 24, connection member 510 is shown being lowered subsea; in FIG. 25, connection member 510 is shown being moved laterally end 520a of overshot tool 520; and in FIG. 26, connection member 510 is shown being lowered and mounted to overshot tool 520. For subsea deployment and installation of collection system 500, one or more ROVs 170 are preferably employed to aid in positioning of overshot tool 520 and connection member 510, as well as to monitor overshot tool 520, connection member 510, pressure control device 300, BOP 120, and capping stack 200.

Referring first to FIG. 21, overshot tool 520 is shown being controllably lowered subsea with a wireline cable 180 releasably coupled to tool 520 and extending to a surface vessel. A winch or crane mounted to a surface vessel is preferably employed to support and lower tool 520 on cables 180.

Using cable 180, overshot tool 520 is lowered subsea front a location generally above and laterally offset from exhaust conduit 335 to maintain overshot tool 520 outside of plume 160, thereby reducing the potential for the formation of hydrates therein. Overshot tool 520 is lowered laterally offset front exhaust conduit 335 and outside of plume 160 until lower end 520b is slightly above outlet end 335b. As tool 520 descends and approaches device 300, ROVs 170 monitor the position of tool 520 relative to capping slack 200 and device 300. Moving now to FIG. 22, tool 520 is moved laterally into position immediately above end 335b with tool 520 substantially coaxially aligned with end 335b. One or more ROVs 170 may utilize their claws 172 and handles 427 to guide tool 520 into proper alignment relative to exhaust conduit 335.

Referring now to FIGS. 22 and 23, with overshot tool 520 positioned immediately above and coaxially aligned with outlet end 335b, cable 180 lowers tool 520 axially downward, thereby inserting and axially advancing end 335b of exhaust conduit 335 into coupling member 522. With end 335b sufficiently seated within member 522, one or more ROVs 170 rotate locking members 526 to threadingly advance the radially inner ends of locking members into engagement with exhaust conduit 335, thereby locking overshot tool 520 onto conduit 335. With tool 520 mounted to conduit 335, the hydrocarbon fluids emitted at end 335b flow upward through bore 521 and out end 520a.

Referring now to FIG. 24, connection member 510 is coupled to the lower end of a tubular string 700 at the surface 102 with J-latch coupling 412, and is then controllably lowered subsea with string 700. A derrick or other suitable device mounted to a surface vessel is preferably employed to support and lower device 300 on string 700. Using string 700, connection member 510 is lowered subsea from a location generally above and laterally offset from overshot tool 520 to maintain connection member 510 outside of plume 160, thereby reducing the potential for the formation of hydrates therein.

Connection member 510 is lowered laterally offset from overshot tool 520 and outside of plume 160 until lower end 510b is slightly above tip 528 at upper end 520a. As connection member 510 descends and approaches overshot tool 520, ROVs 170 monitor the position of connection member 510 relative to tool 520, capping stack 200, and device 300. Moving now to FIG. 25, connection member 510 is moved laterally into position immediately above end 520a and substantially coaxially aligned with stabbing member 523. One or more ROVs 170 may utilize their claws 172 and handles 517 to guide connection member 510 into proper alignment relative to stabbing member 523.

Referring now to FIGS. 25 and 26, with connection member 510 positioned immediately above and generally coaxially aligned with stabbing member 523, string 700 lowers connection member 510 axially downward, thereby inserting and axially advancing end 520a of overshot tool 520 into passage 511 of connection member 510. Funnel guide 516 at end 510b and mule shoe tip 528 at upper end 520a facilitate the insertion and axial advancement of stabbing member 523 into pipe 513 in the event connection member 510 is slightly out of alignment with stabbing member 523. Stabbing member 523 is axially advanced through pipe 513 until tip 528 is axially proximal and below flex joint 518, thereby allowing J-latch coupling 412 to pivot about flex joint 518 relative to pipe 513 and stabbing member 523 disposed therein.

With stabbing member 523 disposed in pipe 513, hydrocarbon fluids discharged from exhaust conduit 335 flow upward through overshot tool 520, connection member 510, and string 700 to the surface where they may be captured and contained.

During collection operations, the weight of connection member 510 is supported by string 700 to minimize the transfer of any loads to overshot tool 520, exhaust conduit 335, and pressure control device 300. Minimizing loads on exhaust conduit 335 as well as the flexibility of connection member 510 due to flex joint 518 offers the potential to reduce the chances of inadvertently damaging conduit 335 and/or control device 300, particularly if the deployment vessel at the surface 102 experiences a sudden lateral or vertical movement.

Referring now to FIGS. 27, an embodiment of a collection system 600 for capturing hydrocarbon fluids exhausted from a subsea discharge site (e.g., hydrocarbons discharged from exhaust conduit 335) is shown. System 600 has a central or longitudinal axis 605, a first or upper end 600a, and a second or lower end 600b opposite end 600a. In this embodiment, system 600 includes a connection member 610 extending axially from upper end 600a, a top hat 620 coupled to connection member 610, and an annular flexible skirt 630 extending from top hat 620 to lower end 600b.

Connection member 610 has a central axis 615 coincident with axis 605, a first or upper end 610a defining upper end 600a of system 600, a second or lower end 610b coupled to top hat 620, and a central through bore 611 extending axially between ends 610a, b. In this embodiment, connection member 610 includes a J-latch coupling 412 as previously described extending axially from upper end 610a.

Referring still to FIG. 27, top hat 620 has a central axis 625 coaxially aligned with axis 615, a first or upper end 620a coupled to lower end 610b, and a second or lower end 620b. Top hat 620 is an annular inverted funnel defining an inner flow passage extending between ends 620a, b. The flow passage has an inlet at lower end 620b and an outlet at upper end 620a in fluid communication with bore 611 of connection member 610. In this embodiment, top hat 620 also includes a plurality of circumferentially spaced auxiliary outlets 621 proximal upper end 620a and an ROV control panel 622. Each outlet 621 includes an ROV operated valve 623 that controls the flow of fluids through the corresponding outlet 621. Control panel 622 includes a plurality of receptacles for injecting a hydrate inhibitor (e.g., methanol) into top hat 620 to reduce and/or prevent the formation of hydrates within top hat 620 and downstream of top hat 620. A pair of handles 624 that extend radially from top hat 620 and enable ROVs to manipulate, rotate, and position top hat 620 during subsea deployment. Additional details and examples of top hats that may be used as top hat 620 are disclosed in U.S. Patent Application Ser. No. 61/384,358 filed Sep. 20, 2010 and entitled “Containment Cap for Controlling a Subsea Blowout,” which is hereby incorporated herein by reference in its entirety.

Annular skirt 630 hangs from lower end 620b of top hat 620. in this embodiment, skirt 630 comprises a plurality of flexible generally rectangular panels 631 positioned circumferentially adjacent each other. More specifically, in this embodiment, each panel 631 is a rubber sheet having an axial length of four feet.

Referring now to FIGS. 28-30, hydrocarbon collection system 600 is shown being deployed subsea and positioned to capture hydrocarbons discharged from exhaust conduit 335. More specifically, in FIG. 28, system 600 is shown being lowered subsea; in FIG. 29, system 600 is shown being moved laterally over conduit 335; and in FIG. 30, system 600 is shown positioned about end 335b of exhaust conduit 335. For subsea deployment and installation of collection system 600, one or more ROVs 170 are preferably employed to aid in positioning collection system 600 and monitoring collection system 600, pressure control device 300, BOP 120, and capping stack 200.

Referring first to FIG. 28, system 600 is coupled to the lower end of a tubular string 700 at the surface 102 with J-latch coupling 412, and is then controllably lowered subsea with string 700. A derrick or other suitable device mounted to a surface vessel is preferably employed to support and lower system 600 on string 700.

Using string 700, system 600 is lowered subsea from a location generally above and laterally offset from exhaust conduit 335 to maintain system 600 outside of plume 160, thereby reducing the potential for the formation of hydrates therein. As system 600 is lowered subsea, a hydrate inhibitor (e.g., methanol) may be injected into top hat 620 via a subsea. ROV 170 and control panel 622. Any injected inhibitor is free to flow upward within the remainder of system 600 and string 700.

Referring now to FIGS. 28-30, system 600 is lowered laterally offset from exhaust conduit 335 and outside of plume 160 until outlet end 335b is axially positioned between ends 600b, 620b. As system 600 descends and approaches device 300, ROVs 170 monitor the position of system 600 relative to capping stack 200 and device 300. Next, system 600 is moved laterally to position end 335b inside skirt 630. As system 600 moves laterally across end 335b, circumferentially adjacent flexible panels 631 are urged apart to allow end 335b to pass therebetween and into skirt 630. One or more ROVs 170 may utilize their claws 172 and handles 624 to guide system 600 as it is moved laterally across end 335b.

With end 335b disposed within skirt 630 and positioned axially between ends 600b, 620b, hydrocarbon fluids discharged from exhaust conduit 335 flow upward through skirt 630, top hat 620, connection member 610, and string 700 to the surface where they may be captured and contained. A hydrate inhibitor (e.g., methanol) may be injected into top hat 620 via control panel 622 during collection of discharged hydrocarbons to prevent and/or reduce the formation of hydrates within top hat 620, connection member 610, and string 700.

During collection operations, the weight of system 600 is supported by string 700 to minimize the transfer of any loads to exhaust conduit 335 and pressure control device 300. Minimizing loads on exhaust conduit 335 as well as the flexibility of conduit 430 of collection system 400 offers the potential to reduce the chances of inadvertently damaging conduit 335 and/or control device 300, particularly if the deployment vessel at the surface 102 experiences a sudden lateral or vertical movement.

In the manner described, embodiments of systems and methods described herein may be employed to contain and collect at least a portion of the hydrocarbon fluids exhausted from a subsea discharge site. Although embodiments of system 400, system 500, and system 600 have been described as containing and collecting hydrocarbon fluids emitted from pressure control device 300 coupled to side outlet 214 of capping stack 200, in general, embodiments described herein may be used to contain and collect hydrocarbons vented from any subsea discharge site including, without limitation, a subsea BOP or capping stack side outlet, a subsea manifold outlet, a subsea production tree outlet or leak, an outlet with an isolation valve operated locally by an ROV or operated remotely by a subsea control system, a normally closed outlet fitted with a pressure safety valve (e.g. relief valve), or a burst disc designed to open automatically if a pre-determined pressure differential is exceeded

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 Collecting Hydrocarbons Vented From A Subsea Discharge Site

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CPC

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CROSS-REFERENCE TO RELATED APPLICATIONS

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