US20210148192A1

US20210148192A1 - Ball valve capping stack

Info

Publication number: US20210148192A1
Application number: US16/476,399
Authority: US
Inventors: Guy R. Fox; Douglas N. DERR; Carl J. Cramm; Andrew J. CUTHBERT
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2018-08-06
Filing date: 2018-08-06
Publication date: 2021-05-20
Also published as: WO2020032920A1; BR112020024213A2; EP3797208A1; AU2018436246A1; EP3797208A4

Abstract

A capping stack for use with a subsea well includes a ball valve disposed along a first flowline that is axially aligned with a main flowbore of a manifold body so that a tubing string can be passed through the ball valve into the well and whereby the ball valve can be activated to both close the flowline and sever the tubing string as desired. The main flowbore of the manifold body is defined along a primary axis and the capping stack includes second and third flowlines that each intersect the primary axis at an angle greater than zero and that each include a choke mechanism and a pair of spaced apart ball valves disposed along the flowline.

Description

BACKGROUND

Technical Field

The present disclosure generally relates to oilfield equipment and, in particular, to capping stacks. More particularly still, the present disclosure relates to a capping stack utilizing ball valves to control flow through the capping stack and to sever tubing string extending through the capping stack.
Hydrocarbons are commonly produced from wells that penetrate a subterranean formation, beneath a body of water. Within such subterranean formations, fluids and gases, including hydrocarbons, may be present at very high pressures. Therefore, throughout the processes of drilling and completing the well, producing hydrocarbons from the subterranean formation, stimulating the subterranean formation to improve hydrocarbon production therefrom, and/or, ultimately, closing-in and abandoning the well, a variety of pressure management measures are employed to maintain control of the well.
Despite such pressure management efforts, unforeseen circumstances, equipment failures, or other factors may lead to the loss of control of a well. Loss of well control may result in formation fluids being emitted from the well at uncontrolled flow rates and pressures. When control over a well is lost, it is necessary to, as expediently as possible, regain control thereof. To achieve this, following loss of control, a capping stack must be transported to a location, deployed from the surface vessel, maneuvered through hundreds of feet of water and installed on the wellhead. A capping stack is generally utilized to manage fluid flow by closing in the flow or diverting the uncontrolled fluid flow from the well along multiple flow paths to a surface separation/collection system. Current technology uses either rams (pipe rams, blind rams or shear rams) or gate valves to close off the flow paths of a capping stack. Applicable guidelines require that rams close in a time limit of 45 seconds in order to mitigate excessive elastomer erosion, since they are designed to close against pressure not flow. One drawback to the use of rams is that the rams significantly increase the weight and footprint of the capping stack assembly. This can make it very difficult to transport and also manipulate and install. Gate valves have also been used in the industry because they are designed to close against hydrocarbon flow. On the other hand, gave valves are preferable because they have better sealing performance than rams by employing a metal-to-metal seal. Gate valves, due to the different nature of closure and seal face, take up to two minutes to close since the gate valve spindle must be rotated by an ROV from an open to close position. The slower closure time allows a “soft” shut-in. Gate valves, also reduce the capping stack footprint, making the capping stacks easier to transport and manipulate for installation.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:

FIG. 1 is a view of a capping stack being deployed on a wellhead.

FIG. 2 is cross-sectional view of a capping stack having a central ball valve for severing a tubular passing down a central flowline.

FIG. 3 is a perspective view of the capping stack of FIG. 2.

FIG. 4 is an orthogonal side view of the capping stack of FIG. 2.

FIG. 5 is a partially exploded perspective view of a capping stack.

FIG. 6 is a perspective view of a capping stack with flowback and burst disk assemblies.

FIG. 7 is a method for controlling flow of wellbore fluids from a wellbore.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is not intended to limit the invention to the embodiments illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.
Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “up-hole,” “upstream,” or other like terms shall be construed as generally from the formation toward the surface or toward the surface of a body of water; likewise, use of “down,” “lower,” “downward,” “down-hole,” “downstream,” or other like terms shall be construed as generally into the formation away from the surface or away from the surface of a body of water, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis.
Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
Disclosed herein are embodiments of a capping stack of a well containment assembly, wherein a ball valve is deployed along one or more flowlines of the capping stack. In one or more embodiments, two ball valves are deployed along a flowline. Embodiments of a capping stack include a capping manifold having an inlet, a central flowline and two side flowlines, each flowline leading to an outlet, with at least two spaced apart ball valves deployed along each flowline. The capping stack further includes a choke valve deployed along each of the side flowlines between a ball valve and the outlet, and a pressure sensor associated with the main inlet. Finally, the capping stack includes a non-flange connector, such as a stab-in connector. In some embodiments, the ball valves deployed along the central flowline are larger in cross-sectional area than the ball valves utilized along the side flowlines. In one or more embodiments, the central flowline ball valves are used in certain well containment operations to sever tubulars extending through the central flowline.
Referring to FIG. 1, illustrated is a wellbore 100 penetrating a subterranean formation 102 for the purpose of recovering hydrocarbons, storing hydrocarbons, disposing of carbon dioxide, or the like. The wellbore 100 may extend substantially vertically over a vertical portion of the wellbore 100 or may deviate at any angle from the earth's surface over a deviated or horizontal portion of the wellbore 100. All or portions of the wellbore 100 may be vertical, deviated, horizontal, and/or curved. It will be appreciated that the wellbore 100 and its depiction are intended for illustration purposes only and the orientations described herein are not intended to be limiting. The wellbore 100 may be drilled into the subterranean formation 102 using any suitable drilling technique. For example, a drilling, servicing, and/or production rig 104 may be located on a Mobile Offshore Drilling Unit (MODU) 106 or other platform at the surface of a body of water 108 which platform 106 may be employed to drill and/or service the wellbore 100 and/or produce hydrocarbons therefrom. A wellhead 110 provides a connection to the wellbore 100. Various subsea equipment, for example, pipelines, manifolds, blowout preventers, risers, and the like may be located at the seafloor proximate to the wellhead 110, associated with the wellhead 110 and/or in fluid communication with the wellhead 110. Where the wellhead 110 and/or any of the equipment associated therewith has become damaged or has failed, a stream 112 of fluids may escape into the surrounding environment from the wellbore 100. Prior to and/or following removal of the damaged components, as disclosed herein, the fluid stream 112 may continue to escape into the surrounding environment, for example, in the embodiment of FIG. 1, into the surrounding body of water 108. The stream 112 may comprise fluid or gaseous hydrocarbons, water, paraffins, salts, and the like escaping the wellhead 110 and/or the associated equipment in a relatively high rate and/or pressure.
A capping stack assembly 120 is shown in relation to the wellhead 110 during installation on the wellhead 110. Capping stack assembly 120 is suspended from a cable 126, or other means of conveyance, which may be utilized to lower the capping stack assembly 120 into position from platform 106. An underwater vehicle (UV) 124, such as for example remotely operated vehicle (ROV) 124, may be used to assist in the attachment of capping stack assembly 120 to wellhead 110. In alternative embodiments, capping stack assembly 120 may be transported from platform 106 utilizing ROV 124.
Referring to FIG. 2, capping stack assembly 120 is illustrated in cross-section. Capping stack assembly 120 includes a capping manifold 126 attached to a connector 128. Connector 128 has a main bore 130 defined along a connector axis 131 and extending between a first connector end 128 a and a second connector end 128 b, with an outlet 130 a disposed at the first connector end 128 a and an outlet 130 b disposed at the second connector end 128 b. Second connector end 128 b is disposed for attachment to a wellhead 110 (see FIG. 1) or other equipment attached thereto, such as a blowout preventer (BOP), preferably by stabbing, thus avoiding the need for flanged makeup between connector 128 and wellhead 110. It will be appreciated that the environment conditions in which capping stack assembly 120 is deployed render it very difficult to make up flange connected equipment due to the high pressures and flowrates of fluid stream 112 from wellbore 100 and the lack of visibility at the wellhead 110, all of which would inhibit an ROV 124 in such an operation. For this reason, second connector end 128 b may be a stab connector assembly.
In any event, capping stack assembly 120 includes three upwardly extending flowlines 132, namely a central flowline 132 a, and two side flowlines 132 b, 132 c. As used herein, “flowline” refers to any conduit or assembly of conduits, connectors, elbows or other structure or equipment forming a passage through which fluid may flow. Flowlines 132 a, 132 b and 132 c all extend from a manifold body 134. Manifold body 134 has a main flowbore 136 defined along a primary axis 137 and three smaller flowbores 138 branching off from main flowbore 136, namely center flowbore 138 a and side flowbores 138 b, 138 c. Side flowbores 138 b, 138 c are each in fluid communication with the main flowbore 136 and intersect the primary axis 137 at an angle θ1, θ2 greater than zero degrees. In one or more embodiments, the angle θ of the intersection is greater than zero and less than 60 degrees. Main flowbore 136 terminates at an inlet 140, while each of flowbores 138 a, 138 b and 138 c, terminate at three respective outlets 142 a, 142 b, and 142 c which in turn are in fluid communication with flowlines 132 a, 132 b and 132 c, respectively. Manifold body 134 is attached to connector 128 so that inlet 140 of manifold body 134 is adjacent outlet 130 a of connector 128, thereby permitting main flowbore 136 to be axially aligned and in fluid communication with bore 130 of connector 128. Likewise, central flowbore 138 a is axially aligned with central flowline 132 a and main flowbore 136 along primary axis 137. As such, when capping stack assembly 120 is installed on a wellhead 110, a tubing string (see in dashed line of FIG. 3) may be passed through central flowline 132 a, central flowbore 138 a and main flowbore 136 into well 100. This is particularly desirable when the tubing string is carrying intervention equipment for use in intervention operations as described below.
In one or more embodiments, the sum of the cross-sectional areas of the smaller flowbores 138 a, 138 b, 138 c is substantially equivalent to cross-sectional area of the main flowbore 136. In one or more embodiments, central flowline 132 a has a cross-sectional area A1 that is larger than the cross sectional area A2 of the each of flowlines 132 b, 132 c, and central flowbore 138 a has a cross-sectional area that is larger than flowbores 138 b, 138 c, the larger size of the central flowline 132 a and central flowbore 138 a being disposed to accommodate insertion of intervention equipment therethrough. In one or more embodiments, flowline 132 a is approximately 7 1/16 in diameter and flowlines 132 b, 132 c are approximately 5⅛ in diameter.
A ball valve 144 is disposed along at least one flowline 132. In one or more embodiments, a ball valve 144 a is disposed along at least central flowline 132 a in order to shut off flow from the well and to cut or sever a tubing string (see FIG. 3) extending through central flowline 132 a, such as a tubing string carrying intervention equipment as described below. In one or more embodiments, a ball valve may also be disposed along one or more of flowlines 132 b and 132 c. To the extent each main flowline 132 a and at least one side flowline 132 b or 132 c includes a ball valve 144, it will be appreciated that because flowline 132 a is larger than flowlines 132 b and 132 c, then ball valve 144 a is correspondingly larger than ball valves 144 b and 144 c allowing ball valve 144 a to perform the unique function as described below.
Each flowline 132 may further include a second ball valve 146, such as shown as ball valves 146 a, 146 b and 146 c. Second ball valve 146 may be spaced apart from ball valve 144 along their respective flowlines. In this regard, as shown, first ball valve 144 may be disposed along a first portion 148 of flowline 132 while second ball valve 146 may be disposed along a second portion 150 of flowline 132. A frame 151 at least partially encloses manifold body 134 and the first or lower portion 148 a, 148 b, 148 c of each flowlines 132 a, 132 b, 132 c, respectively. Likewise, frame 151 encloses ball valves 144 a, 144 b, 144 c so as to provide additional protection thereto. Frame 151 may include a deck 152 from which each of the second or upper portions 150 a, 150 b, 150 c of flowlines 132 a, 132 b, 132 c vertically extend. In this regard, the upper portions 150 a, 150 b, 150 c of the respective flowlines 132 may be generally parallel with one another.
One or more lifting mechanisms 158 is positioned on capping stack 120 so as to allow suitable cranes or hoists to lift and lower the capping stack 120, as desired. In the illustrated embodiment, lifting mechanism 158 positioned at the distal end of flowline 132 a may be disengaged or otherwise removed once capping stack 120 is in place, permitting access to flowline 132 a.
A choke mechanism 160 may be positioned along each of side flowlines 132 b, 132 c upstream of ball valves 146 b, 146 c. Specifically, a choke mechanism 160 b is positioned at the distal end 162 b of side flowline 132 b so as to be in fluid communication with first ball valve 146 b and a choke mechanism 160 c is positioned at the distal end 162 c of side flowline 132 c so as to be in fluid communication with first ball valve 146 c. One or more sensors 163 may be positioned along flowlines 132. Sensors 163 are not limited to a particular type of sensor. In some embodiments, sensor 163 is a temperature sensor and/or a pressure sensor. In some embodiments, sensors 163 are positioned along flowlines 132 b, 132 c and utilized to control choke mechanism 160 b, 160 c. Thus, choke mechanism 160 is adjustable in response to measurement of a condition of fluid flow along flowlines 132 utilizing sensor 163.
Finally, a support assembly 164 may be disposed along the upper portion 150 of each flowline 132, as illustrated by support assembly 164 a, 164 b, 164 c. In particular, support assembly 164 is mounted on deck 152 of frame 151, thereby supporting the vertical portion 150 of flowline 132. Each support assembly 164 may include a release mechanism 165 to permit upper ball valve 146 to be detached from capping stack 120. This can permit valves 146 to be retrievable or replaceable as desired. Additionally, this can permit the attachment of other equipment, as described more specifically with reference to FIG. 5.
FIG. 3 is perspective view of capping stack assembly 120. As shown, connector 128 is attached to manifold body 134. A frame 151 encloses a portion of manifold body 134. Flowline 132 a includes an upper ball valve 146 a and a lower ball valve 144 a. Flowline 132 b includes an upper ball valve 146 b, a lower ball valve 144 b and a choke mechanism 160 b. Flowline 132 c includes an upper ball valve 146 c, a lower ball valve 144 c and a choke mechanism 160 c. A tubing string 168 is illustrated in dashed lines as extending through capping stack 120.
In the illustrated embodiment, upper ball valve 146 a and lower ball valve 144 a are deployed in a one hundred eighty degree relationship to one another so that the spindle 170′ of upper ball valve 146 a extends in the opposite direction from the spindle 170″ of lower ball valve 144 a, thereby providing additional balance to capping stack 120, which is particularly desirable during manipulation and deployment. In this regard, it will be appreciated that because ball valves 144 a, 146 a are larger than the ball valves along flowlines 132 b, 132 c, ball valves 144 a, 146 a, including their respective spindles 170′, 170″, tend to be heavier than the spindles of the other ball valves and it becomes more imperative to equally distribute the weight of ball valves 144 a, 146 a in order to more easily maneuver and manipulate capping stack 120.
FIG. 4 is a side view of the capping stack assembly 120. In the illustrated embodiment, connector 128 is attached to manifold body 134. This may be accomplished by fastening a flange 172 adjacent the inlet 140 of manifold body 134 to a flange 174 at the first connector end 128 a of connector 128. A frame 151 encloses a portion of manifold body 134, and a flowline 132 c extends from manifold body 134. Flowline 132 c includes an upper ball valve 146 c, a lower ball valve 144 c and a choke mechanism 160 c. A support assembly 164 c is mounted on deck 152 of frame 151, thereby supporting the upper vertical portion 150 c of flowline 132 c. Support assembly 164 c may include a release mechanism 165 to the upper portion 150 c of flowline 132 c including upper ball valve 146 c, to be detached from capping stack 120.
In one or more embodiments, at least one, and in some embodiments both, upper ball valve 146 a and lower ball valve 144 a are larger in size than the other valves of capping stack assembly 120. This is because of the intended functionality of one or both of upper ball valve 146 a and lower ball valve 144 a is to allow tubing strings to pass therethrough and to have the ability of sever tubing strings as described herein. For this reason, upper ball valve 146 a and lower ball valve 144 a are deployed in a one hundred eighty degree relationship to one another so that the spindle 170′ of upper ball valve 146 a extends in the opposite direction from the spindle 170″ of lower ball valve 144 a, thereby providing additional balance to capping stack 120, due to the weight of upper ball valve 146 a and lower ball valve 144 a in certain embodiments.
Also shown in FIG. 4 is an ROV connection panel 176 for attachment of one or more lines from an ROV (such as ROV 124 if FIG. 1) for certain operations, such as chemical injections into flow lines 132.
FIG. 5 is a partially exploded, orthogonal view of capping stack assembly 120, illustrating the functionality of support assembly 164 mounted on deck 152 of frame 151. In particular, for each flowline 132, support assembly 164 is shown having a support base 178 secured to deck 152. Thus, a support base 178 a, 178 b, 178 c is shown corresponding to a vertical portion 150 a, 150 b, 150 c of each flowline 132 a, 132 b, 132 c, respectively. Each support base 178 is disposed to engage with a barrel or bucket guide 180. In one or more embodiments, barrel guide 180 fits over support base 178 and is secured thereto by locking and release mechanism 165. To ensure barrel guide 180 is properly aligned and seated on support base 178, barrel guide 180 may include a window 181 for visual confirmation of orientation. In instances where it is desirable to replace the upper vertical portion 150 of one or more flowlines 132, barrel guide 180 can readily be detached from support base 178. It will be appreciated that release mechanism 165 can be actuated by an ROV, such as ROV 124 of FIG. 1, to facilitate detachment and attachment of upper lowliness 132 as desired. In this regard, upper flowlines 132 can be replaced in situ while capping stack assembly 120 is positioned at wellhead 110.
Frame 151 is shown enclosing a portion of manifold body 134. Flowlines 132 a, 132 b, 132 c each includes an upper ball valve 146 a, 146 b, 146 c, a lower ball valve 144 a, 144 b, 144 c. Flowlines 132 b, 132 each include and a choke mechanism 160 b, 160 c. Also shown is ROV connection panel 176 for attachment of one or more lines from an ROV (such as ROV 124 if FIG. 1) for certain operations, such as chemical injections into flow lines 132.
FIG. 6 illustrates capping stack assembly 120 with support assembly 164 attaching different configurations for flowlines 132 b and 132 c. While flowline 132 a includes an upper ball valve 146 a as previously described, in place of the ball valve 132 b and choke 140 b described above, flowline 132 b is shown as having flowback assembly 181. Likewise, in place of the ball valve 132 c and choke 140 c described above, flowline 132 c is shown as having burst disk assembly 182. Although it is primarily contemplated to utilize capping stack assembly 120 to shut-in a well by closing valves 144, 146, in instances where shut-in of a well could result in wellbore pressures capable of damaging the reservoir, flowback operations may be conducted, wherein capping stack assembly 120 is utilized to control flow and direct flow to the surface.
Flowback assembly 181 generally includes a fitting 184, such as a right angle forge block, in fluid communication with a conduit 186 and generally supported by a barrel guide 180 b of support assembly 184 b. Barrel guide 180 b attaches to support base 178 b so that fitting 184 is in fluid communication with the lower portion 148 b (see FIG. 2) of flowline 132 b via support assembly 164 b. Conduit 186 extends to the surface for delivery of wellbore fluids from wellbore 100 to the surface. Fitting 184 may include a fixed or adjustable valve, such as valve 188. In operation, release mechanism 165 is manipulated to release bucket guide 180 b from support base 178 b and remove the upper portion 150 b of flowline 132 b having a ball valve 146 b and choke 160 b (shown in FIG. 5) and secure an upper portion 150 b configured with the flowback assembly 180. In some embodiments, flowback assembly 181 includes an upper ball valve 146 b, such that fitting 184 simply replaces choke mechanism 140 b in the overall configuration.
In one or more embodiments, deployed on capping stack assembly 120 in conjunction with flowback assembly 181 is burst disk assembly 182. Burst disk assembly 182 generally includes a burst disk vale 190 generally supported by a barrel guide 180 c of support assembly 184 c. Barrel guide 180 c attaches to support base 178 c so that fitting burst disk valve 190 is in fluid communication with the lower portion 148 c (see FIG. 2) of flowline 132 c via support assembly 164 c. Burst disk valve 190 is not limited to a particular mechanism, but can be any valve that is designed to open upon experiencing a threshold pressure, thereby forming an open flow path from wellhead 110 along flowline 132 c to release wellbore fluids 112 and reduce pressure buildup within wellbore 100. In operation, release mechanism 165 c is manipulated to release bucket guide 180 c from support base 178 c and remove the upper portion 150 c of flowline 132 c having a ball valve 146 c and choke 160 c (shown in FIG. 5) and secure an upper portion 150 c configured with the burst disk assembly 182. In some embodiments, burst disk assembly 182 includes an upper ball valve 146 c, such that burst disk valve 190 simply replaces choke mechanism 140 c in the overall configuration.
It will be appreciated that during flowback operations utilizing flowback assembly 181, back pressure within conduit 186 may arise. Under normal flowback conditions, burst disk valve 190 remains closed. To avoid back pressure damage to the formation 102 around wellbore 100, when the pressure within conduit 186 rises above a select threshold, burst disk valve 190 will open, releasing the pressure within conduit 186 and protecting the formation from damage.
Turning to FIG. 7, a method of operation 200 of capping stack assembly 120 is described. Generally, upon the occurrence of a wellbore release incident, such as release of wellbore fluids 110 into the surrounding water 108, in operation 200, a capping stack assembly 120 is lowered from the surface and attached to a subsea wellhead or mandrel or BOP in a first step 202. The capping stack assembly 120 may be lowered on a cable or tubing string, and/or may be assisted by an ROV. It will be appreciated that connector 128 is of the type that can be stabbed into engagement with the equipment 110 to which it is attached, such as a wellhead, without the need for flanged make-up. Typically, in the case of an uncontrolled release of wellbore fluids 112 from wellhead 110, environmental conditions around the wellhead 110 render it difficult to attach equipment components to one another. For this reason, a stab-type connector is utilized in certain embodiments of step 202. In any event, typically, the various valves 146, 144 are in the “open” position as capping stack 120 is lowered and attached to wellhead 110.
In step 204, various wellbore operations may be carried out by lowering a tubing string into the wellbore. The tubing string may include various equipment attached thereto, such as intervention equipment, which is lowered into the wellbore 100 on the tubing string. In particular, the equipment and the tubing string are lowered through capping stack assembly 120 along flowline 132 a into wellbore 100. Because flowline 132 a is axially aligned with connector 128, the tubing string can readily pass through capping stack assembly 120. Moreover, open ball valves 146 a, 144 a disposed along flowline 132 a allow passage of the tubing string, and any equipment attached to the tubing string, through capping stack assembly 120. In any event, the tubing string and any wellbore equipment attached thereto are positioned in the wellbore 100 and various operations, such as well intervention are conducted. Such operations may include injecting a working fluid into the wellbore to balance or overbalance the wellbore, or fishing operations to retrieve other equipment lost in the wellbore. For example, the working fluid may be a weighted mud utilized to stabilize formation fluid flow within the wellbore by achieving a neutral or overbalanced condition within the wellbore.
In step 206, a determination is made that the capping stack 120 needs to be closed off with a portion of the tubing string still in the wellbore. This may be due to the fact that the equipment carried by the tubing string has become stuck or engaged in the wellbore. Upon such a determination, the capping stack 120 is utilized to sever the tubing string passing therethrough. Thus, one of the ball valves 146 a, 144 a along flowline 132 a is actuated by rotating it from an “open” position to a “closed” position so that the leading edged of the ball valve severs the tubing string. In one or more embodiments, the lower ball valve 144 a is actuated to sever the tubing string adjacent diverter body 134.
In step 208, the tubing string above the actuated ball valve is then withdrawn from the capping stack assembly 120, and finally, in step 210, the other ball valve along flowline 132 a is actuated and closed. It will be appreciated that the order of ball valve actuation has been described wherein the lower ball valve 144 a is closed first to sever the tubing string and then the upper ball valve 146 a is closed as an additional barrier to fluid flow. Although the reverse sequence is also encompassed by the disclosure, whereby the upper ball valve 146 a is closed first in order to sever the tubing string, this will leave a greater portion of the tubing sting in the capping stack assembly 120. Moreover, upon closure of the lower ball valve 144 a, the tubing string will again be severed, thus stranding a portion of the tubing string in the capping stack assembly 120 along flowline 132 a between the two ball valves 144 a, 146 a.
In any event, at this point, hydrocarbon fluids are no longer flowing along flowline 132 a. However they may continue to flow along flowlines 132 b, 132 c as described herein. In such case, ball valves 144 b, 144 c, 146 b, 146 c may be selectively actuated to partially or fully close the ball valves as desired. It will be appreciated that in such case, the ball valves will experience much less damage to their leading edge compared to other types of valves. More significantly, it will be appreciated that the closure of any of the ball valves described herein can occur much more quickly than traditional gate since a ball valve can be actuated to translate from “opened” to “closed” with no more than a 90 degree rotation of the ball valve stem. In contrast, gate valves require multiple complete rotations of the valve stem in order to translate from “opened” to “closed”, thus requiring significantly more time to accomplish a closure. Ball valves as described herein are much less resistant to such erosion and can be utilized to choke flow therethrough by driving them to a partially open configuration.
Thus, a capping stack for use with a subsea well has been described. The capping stack may include a manifold body having a main flowbore defined along a primary axis, a first flowbore in fluid communication with the main flowbore and axially aligned with the main flowbore, and a second flowbore in fluid communication with the main flowbore and intersecting the primary axis at an angle greater than zero; a first flowline in fluid communication with the first flowbore and affixed to the manifold body so as to be axially aligned with the primary axis, the first flowline having a proximal end adjacent the manifold body and a distal end; a second flowline in fluid communication with the second flowbore, the second flowline having a proximal end adjacent the manifold body and a distal end; a ball valve disposed along the first flowline between the proximal and distal ends of the first flowline; a valve disposed along the second flowline between the proximal and distal ends of the second flowline; and a choke mechanism disposed along the second flowline between the valve and the distal end of the second flowline, wherein the ball valve is movable between a first position and a second position, said first position allows tubing to be passed through the flowline and manifold body along the primary axis and said second position blocks passage of tubing through said ball valve. In other embodiments, the capping stack may include a manifold body having a main flowbore defined along a primary axis, a first flowbore in fluid communication with the main flowbore and axially aligned with the main flowbore, and a second and third flowbores in fluid communication with the main flowbore, each of the second and third flowbores intersecting the primary axis at an angle greater than zero; a first flowline in fluid communication with the first flowbore and affixed to the manifold body so as to be axially aligned with the primary axis, the first flowline having a proximal end adjacent the manifold body and a distal end; a second flowline in fluid communication with the second flowbore, the second flowline having a proximal end adjacent the manifold body and a distal end; a third flowline in fluid communication with the third flowbore, the third flowline having a proximal end adjacent the manifold body and a distal end; a ball valve disposed along the first flowline between the proximal and distal ends of the first flowline and movable between a first position and a second position; a ball valve disposed along the second flowline between the proximal and distal ends of the second flowline and movable between a first position and a second position; a ball valve disposed along the third flowline between the proximal and distal ends of the second flowline and movable between a first position and a second position; a choke mechanism disposed along the second flowline between the valve and the distal end of the second flowline; a choke mechanism disposed along the third flowline between the valve and the distal end of the third flowline, wherein the first position of the ball valve along the first flowline allows tubing to be passed through the first flowline and manifold body along the primary axis.
For any one of the above-described capping stack embodiments, the following elements may be combined alone or in combination with any other elements:

- An additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline, wherein each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline, wherein the second portions of the first, second and third flowlines are substantially parallel, and wherein one ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.
- A frame at least partially enclosing the manifold body and the ball valve along the first portion of each flowline.
- The valve disposed along the second flowline is a ball valve.
- The valve disposed along the third flowline is a ball valve.
- The manifold body has a third flowbore in fluid communication with the main flowbore and intersecting the primary axis at an angle greater than zero, and wherein the valve disposed along the second flowline is a ball valve, said capping stack further comprising a third flowline in fluid communication with the third flowbore, the third flowline having a proximal end adjacent the manifold body and a distal end; a ball valve disposed along the third flowline between the proximal and distal ends of the third flowline; and a choke mechanism disposed along the third flowline between the ball valve and the distal end of the third flowline.
- A connector having a bore defined therein along a connector axis, said connector affixed to the manifold body so that the connector bore and main flowbore are axially aligned to permit tubing to be passed therethrough.
- The connector comprises a stab connector assembly.
- A frame at least partially enclosing the manifold body and the ball valve along the first flowline.
- The first flowbore and the second flowbore each have a cross-sectional area, and the cross-sectional area of the first flowbore is greater than the cross-sectional area of the second flowbore.
- The main flowbore, the first flowbore and the second flowbore each have a cross-sectional area, and the sum of the cross-sectional areas of the first and second flowbore is substantially equivalent to the cross-sectional area of the main flowbore.
- The frame comprises a deck from which an upper portion of each flowline extents, and a support structure mounted on said deck and supporting the upper portion of the second flowline.
- An additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline.
- Each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline, wherein the second portions of the first, second and third flowlines are substantially parallel.
- One ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.
- The support structure further comprises a release mechanism to releasably attach the valve along second flowline to the capping stack assembly.
- An additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline.
- Each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline.
- The second portions of the first, second and third flowlines are substantially parallel.
- One ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.
- A frame at least partially enclosing the manifold body and the ball valve along the first portion of each flowline.
- The manifold body has a third flowbore in fluid communication with the main flowbore and intersecting the primary axis at an angle greater than zero, and wherein the valve disposed along the second flowline is a ball valve, said capping stack further comprising a third flowline in fluid communication with the third flowbore, the third flowline having a proximal end adjacent the manifold body and a distal end; a ball valve disposed along the third flowline between the proximal and distal ends of the third flowline; and a choke mechanism disposed along the third flowline between the ball valve and the distal end of the third flowline.
- A connector having a bore defined therein along a connector axis, said connector affixed to the manifold body so that the connector bore and main flowbore are axially aligned to permit tubing to be passed therethrough.
- The connector comprises a stab connector assembly.
- A frame at least partially enclosing the manifold body and the ball valve along the first flowline.
- The frame comprises a deck from which an upper portion of each flowline extents, and a support structure mounted on said deck and supporting the upper portion of the second flowline.
- An additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline.
- Each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline, wherein the second portions of the first, second and third flowlines are substantially parallel.
- One ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.

Thus, a method for controlling flow of wellbore fluids from a wellbore has been described. The method may be wellbore intervention operations including attaching a capping stack to a subsea wellhead, BOP or other subsea mandrel; passing well intervention equipment through the capping stack along a flowline of the capping stack; utilizing the well intervention equipment to perform intervention procedures within the wellbore, BOP or other subsea mandrel; and actuating a first ball valve disposed along the flowline in order to sever a tubing string on which the well intervention equipment is supported. In other embodiments, the method for controlling flow of wellbore fluids from a wellbore may include attaching a capping stack to a subsea wellhead of a wellbore; passing a tubing string through the capping stack along a flowline of the capping stack and into a wellbore; utilizing the tubing string to perform operations in the wellbore; and actuating a first ball valve disposed along the flowline in order to sever the tubing string.
For any one of the above-described embodiments, the following steps may be combined alone or in combination with any other steps:

- Withdrawing the tubing remaining in the flowline upstream of the first ball valve; and actuating a second ball valve disposed along the flowline upstream of the first ball valve.
- Actuating the ball valve comprises driving the ball valve from an open position to a closed position.
- Releasing flow from the capping stack through multiple flowlines.
- Aligning a central flowline of the capping stack with the central flow passage of a wellhead and passing the well intervention equipment through the central flowline and central flow passage into a wellbore.
- Performing well intervention operations within the wellbore.
- Attaching well intervention equipment to a tubing string and utilizing the tubing string to deploy the well intervention equipment into the wellbore by passing the tubing string along a flowline of the capping stack.
- Injecting a working fluid into the wellbore to balance the wellbore.
- Injecting a working fluid into the wellbore to overbalance the wellbore.
- Performing fishing operations in the wellbore to retrieve equipment from the wellbore.
- Injecting a working fluid into the wellbore.

While various embodiments have been illustrated in detail, the disclosure is not limited to the embodiments shown. Modifications and adaptations of the above embodiments may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the disclosure.

Claims

What is claimed is:

1. A capping stack for use with a subsea well, the capping stack comprising:

a manifold body having a main flowbore defined along a primary axis, a first flowbore in fluid communication with the main flowbore and axially aligned with the main flowbore, and a second flowbore in fluid communication with the main flowbore and intersecting the primary axis at an angle greater than zero;

a first flowline in fluid communication with the first flowbore and affixed to the manifold body so as to be axially aligned with the primary axis, the first flowline having a proximal end adjacent the manifold body and a distal end;

a second flowline in fluid communication with the second flowbore, the second flowline having a proximal end adjacent the manifold body and a distal end;

a ball valve disposed along the first flowline between the proximal and distal ends of the first flowline;

a valve disposed along the second flowline between the proximal and distal ends of the second flowline; and

a choke mechanism disposed along the second flowline between the valve and the distal end of the second flowline,

wherein the ball valve is movable between a first position and a second position, said first position allows tubing to be passed through the flowline and manifold body along the primary axis and said second position blocks passage of tubing through said ball valve.

2. The capping stack of claim 1, wherein the valve disposed along the second flowline is a ball valve.

3. The capping stack of claim 1, wherein said manifold body has a third flowbore in fluid communication with the main flowbore and intersecting the primary axis at an angle greater than zero, and wherein the valve disposed along the second flowline is a ball valve, said capping stack further comprising a third flowline in fluid communication with the third flowbore, the third flowline having a proximal end adjacent the manifold body and a distal end; a ball valve disposed along the third flowline between the proximal and distal ends of the third flowline; and a choke mechanism disposed along the third flowline between the ball valve and the distal end of the third flowline.

4. The capping stack of claim 3, further a connector having a bore defined therein along a connector axis, said connector affixed to the manifold body so that the connector bore and main flowbore are axially aligned to permit tubing to be passed therethrough.

5. The capping stack of claim 4, wherein said connector comprises a stab connector assembly.

6. The capping stack of claim 1, further comprising: a frame at least partially enclosing the manifold body and the ball valve along the first flowline.

7. The capping stack of claim 6, wherein said frame comprises a deck from which an upper portion of each flowline extents, and a support structure mounted on said deck and supporting the upper portion of the second flowline.

8. The capping stack of claim 3, further comprising an additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline.

9. The capping stack of claim 10, wherein each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline, wherein the second portions of the first, second and third flowlines are substantially parallel.

10. The capping stack of claim 11, wherein one ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.

11. A method for well intervention comprising:

attaching a capping stack to a subsea wellhead, BOP or other subsea mandrel;

passing well intervention equipment through the capping stack along a flowline of the capping stack; and

actuating a first ball valve disposed along the flowline in order to sever a tubing string on which the well intervention equipment is supported.

12. The method of claim 9, further comprising: withdrawing the tubing remaining in the flowline upstream of the first ball valve; and actuating a second ball valve disposed along the flowline upstream of the first ball valve.

13. The method of claim 11, wherein actuating the ball valve comprises driving the ball valve from an open position to a closed position.

14. The method of claim 13, further comprising, releasing flow from the capping stack through multiple flowlines.

15. The method of claim 11, further comprising aligning a central flowline of the capping stack with the central flow passage of a wellhead and passing the well intervention equipment through the central flowline and central flow passage into a wellbore.

16. The method of claim 15, further comprising, performing well intervention operations within the wellbore.

17. The method of claim 11, further comprising, attaching well intervention equipment to a tubing string and utilizing the tubing string to deploy the well intervention equipment into the wellbore by passing the tubing string along a flowline of the capping stack.

18. A capping stack for use with a subsea well, the capping stack comprising:

a manifold body having a main flowbore defined along a primary axis, a first flowbore in fluid communication with the main flowbore and axially aligned with the main flowbore, and a second and third flowbores in fluid communication with the main flowbore, each of the second and third flowbores intersecting the primary axis at an angle greater than zero;

a third flowline in fluid communication with the third flowbore, the third flowline having a proximal end adjacent the manifold body and a distal end;

a ball valve disposed along the first flowline between the proximal and distal ends of the first flowline and movable between a first position and a second position;

a ball valve disposed along the second flowline between the proximal and distal ends of the second flowline and movable between a first position and a second position;

a ball valve disposed along the third flowline between the proximal and distal ends of the second flowline and movable between a first position and a second position;

a choke mechanism disposed along the second flowline between the valve and the distal end of the second flowline;

a choke mechanism disposed along the third flowline between the valve and the distal end of the third flowline,

wherein the first position of the ball valve along the first flowline allows tubing to be passed through the first flowline and manifold body along the primary axis.

19. The capping stack of claim 18, further comprising an additional ball valve disposed along each flowline and spaced apart from the other ball valve along the flowline, wherein each flowline comprises a first portion at the proximal end of the flowline and a second portion at the distal end of the flowline, wherein the second portions of the first, second and third flowlines are substantially parallel, and wherein one ball valve along a flowline is located along the first portion of the flowline and one ball valve along the flowing is located along the second portion of the flowline.

20. The capping stack of claim 19, further comprising: a frame at least partially enclosing the manifold body and the ball valve along the first portion of each flowline.