WO2020032920A1 - Pile de coiffage de robinet à bille - Google Patents

Pile de coiffage de robinet à bille Download PDF

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Publication number
WO2020032920A1
WO2020032920A1 PCT/US2018/045387 US2018045387W WO2020032920A1 WO 2020032920 A1 WO2020032920 A1 WO 2020032920A1 US 2018045387 W US2018045387 W US 2018045387W WO 2020032920 A1 WO2020032920 A1 WO 2020032920A1
Authority
WO
WIPO (PCT)
Prior art keywords
flowline
ball valve
along
capping stack
flowbore
Prior art date
Application number
PCT/US2018/045387
Other languages
English (en)
Inventor
Guy R. FOX
Douglas N. DERR
Carl J. CRAMM
Andrew J. Cuthbert
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to BR112020024213-6A priority Critical patent/BR112020024213A2/pt
Priority to EP18929831.8A priority patent/EP3797208A4/fr
Priority to AU2018436246A priority patent/AU2018436246A1/en
Priority to US16/476,399 priority patent/US20210148192A1/en
Priority to PCT/US2018/045387 priority patent/WO2020032920A1/fr
Publication of WO2020032920A1 publication Critical patent/WO2020032920A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/02—Valve arrangements for boreholes or wells in well heads
    • E21B34/04—Valve arrangements for boreholes or wells in well heads in underwater well heads
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
    • E21B33/064—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers specially adapted for underwater well heads
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • E21B33/076—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/04—Ball valves

Definitions

  • 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.
  • 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.
  • rams pipe rams, blind rams or shear rams
  • 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.
  • 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 perspecti ve 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.
  • 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.
  • Di scl osed 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.
  • 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.
  • the capping stack includes a non-flange connector, such as a stab-in connector.
  • the ball valves deployed along the central flowline are larger in cross-sectional area than the ball valves utilized along the side flowlines.
  • the central flowline ball valves are used in certain well containment operations to sever tubulars extending through the central flowline.
  • 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.
  • 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 wel lhead 110.
  • a stream 1 12 of fluids may escape into the surrounding environment from the wellbore 100.
  • 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.
  • ROV remotely operated vehicle
  • capping stack assembly 120 may be transported from platform 106 utilizing ROV 124.
  • 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 l28a and a second connector end 128b, with an outlet 130a disposed at the first connector end l28a and an outlet l30b disposed at the second connector end 128b.
  • Second connector end 128b is disposed for attachment to a wellhead 1 10 (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 1 10.
  • BOP blowout preventer
  • second connector end 128b may be a stab connector assembly.
  • capping stack assembly 120 includes three upwardly extending flowlines 132, namely a central flowine l32a, and two side flowlines l32b, l32c.
  • 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 132a, 132b and l32c 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 138a and side flowbores 138b, 138c.
  • Main flowbore 136 terminates at an inlet 140, while each of flowbores 138a, 138b and 138c, terminate at three respective outlets l42a, l42b, and 142c which in turn are in fluid communication with flowlines 132a, l32b and 132c, respectively.
  • Manifold body 134 is attached to connector 128 so that inlet 140 of manifold body 134 is adj acent outlet l30a of connector 128, thereby permitting main flowbore 136 to be axially aligned and in fluid communication with bore 130 of connector 128.
  • central flowbore 138a is axially aligned with central flowline l32a and main flowbore 136 along primary' axis 137.
  • a tubing string (see in dashed line of FIG. 3) may be passed through central flowine 132a, central flowbore 138a 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.
  • the sum of the cross-sectional areas of the smaller flowbores 138a, 138b, l38c is substantially equivalent to cross-sectional area of the main flowbore 136.
  • central flowline l32a has a cross-sectional area Al that is larger than the cross sectional area A2 of the each of flowlines l32b, l32c, and central flowbore 138a has a cross-sectional area that is larger than flowbores 138b, 138c, the larger size of the central flowline l32a and central flowbore l38a being disposed to accommodate insertion of intervention equipment therethrough.
  • flowline l32a is approximately 7-1/16 in diameter and flowlines l32b, l32c are approximately 5-1/8 in diameter.
  • a ball valve 144 is disposed along at least one flowline 132.
  • a ball valve 144a is disposed along at least central flowline l32a in order to shut off flow from the well and to cut or sever a tubing string (see FIG. 3) extending through central flowline l32a, such as a tubing string carrying intervention equipment as described below.
  • a ball valve may also be disposed along one or more of flowlines 132b and l32c.
  • each main flowline l32a and at least one side flowline 132b or l32c includes a ball valve 144
  • ball valve l44a is correspondingly larger than ball valves l44b and l44c allowing ball valve 144a 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 !46a, l46b and l46c.
  • Second ball valve 146 may be spaced apart from ball valve 144 along their respective flowlines.
  • 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 l48a, l48b, 148c of each flowlines 132a, l32b, l32c, respectively.
  • frame 151 encloses ball valves l44a, l44b, l44c so as to provide additional protection thereto.
  • Frame 151 may include a deck 152 from which each of the second or upper portions l50a, l50b, l50c of flowlines l32a, l32b, l32c vertically extend.
  • the upper portions l50a, l50b, l50c 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.
  • lifting mechanism 158 positioned at the distal end of flowline l32a may be disengaged or otherwise removed once capping stack 120 is in place, permitting access to flowline l32a.
  • a choke mechanism 160 may be positioned along each of side flowlines l32b, 132c upstream of ball valves 146b, 146c. Specifically, a choke mechanism 160b is positioned at the distal end 162b of side flowline 132b so as to be in fluid communication with first ball valve 146b and a choke mechanism 160c is positioned at the distal end l62c of side flowline l32c so as to be in fluid communication with first ball valve l46c.
  • 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.
  • sensors 163 are positioned along flowlines 132b, l32c and utilized to control choke mechanism l60b, 160c.
  • choke mechanism 160 is adjustable in response to measurement of a condition of fluid flow along flowlines 132 utilizing sensor 163.
  • a support assembly 164 may be disposed along the upper portion 150 of each flowline 132, as illustrated by support assembly l64a, l64b, l64c.
  • 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 l32a includes an upper ball valve l46a and a lower ball valve !44a.
  • Flowline !32b includes an upper ball valve l46b, a lower ball valve l44b and a choke mechanism l60b.
  • Flowline !32c includes an upper ball valve l46c, a lower ball valve l44c and a choke mechanism l60c.
  • a tubing string 168 is illustrated in dashed lines as extending through capping stack 120.
  • upper ball valve !46a and lower ball valve !44a are deployed in a one hundred eighty degree relationship to one another so that the spindle 170’ of upper ball valve 146a extends in the opposite direction from the spindle 170” of lower ball valve l44a, thereby providing additional balance to capping stack 120, which is particularly desirable during manipulation and deployment.
  • ball valves l44a, 146a are larger than the ball valves along flowlines l32b, l32c, ball valves l44a, l46a, 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 l44a, l46a in order to more easily maneuver and manipulate capping stack 120.
  • FIG. 4 is a side view of the capping stack assembly 120.
  • 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 128a of connector 128.
  • a frame 151 encloses a portion of manifold body 134, and a flowline l32c extends from manifold body 134.
  • Flowline l32c includes an upper ball valve l46c, a lower ball valve 144c and a choke mechanism l60c.
  • a support assembly 164c is mounted on deck 152 of frame 151, thereby supporting the upper vertical portion l50c of flowline !32c.
  • Support assembly l64c may include a release mechanism 165 to the upper portion l50c of flowline l32c including upper ball valve l46c, to be detached from capping stack 120.
  • At least one, and in some embodiments both, upper ball valve 146a and lower ball valve 144a 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 I46a and lower ball valve l44a is to allow tubing strings to pass therethrough and to have the ability of sever tubing strings as described herein.
  • upper ball valve l46a and lower ball valve l44a are deployed in a one hundred eighty degree relationship to one another so that the spindle 170’ of upper ball valve 146a extends in the opposite direction from the spindle 170” of lower ball valve l44a, thereby providing additional balance to capping stack 120, due to the weight of upper ball valve l46a and lower ball valve l44a in certain embodiments.
  • 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.
  • support assembly 164 is shown having a support base 178 secured to deck 152.
  • a support base 178a, 178b, l78c is shown corresponding to a vertical portion l50a, 150b, l50c of each flowline l32a, l32b, l32c, respectively.
  • Each support base 178 is disposed to engage with a barrel or bucket guide 180.
  • barrel guide 180 fits over support base 178 and is secured thereto by locking and release mechanism 165.
  • barrel guide 180 may include a window 181 for visual confirmation of orientation.
  • barrel guide 180 can readily be detached from support base 178.
  • 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.
  • 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 132a, l32b, l32c each includes an upper ball valve l46a, 146b, l46c, a lower ball valve 144a, l44b, l44c.
  • Flowlines 132b, 132 each include and a choke mechanism l60b, l60c.
  • 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 l32b and l32c.
  • flowline l32a includes an upper ball valve 146a as previously described, in place of the ball valve 132b and choke 140b described above, flowline l32b is shown as having flowback assembly 181. Likewise, in place of the ball valve 132c and choke 140c described above, flowline 132c 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 180b of support assembly 184b.
  • Barrel guide 180b attaches to support base l78b so that fitting 184 is in fluid communication with the lower portion 148b (see FIG. 2) of flowline 132b via support assembly 164b.
  • 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.
  • release mechanism 165 is manipulated to release bucket guide 180b from support base l78b and remove the upper portion 150b of flowline 132b having a ball valve l46b and choke l60b (shown in FIG. 5) and secure an upper portion l50b configured with the flowback assembly 180.
  • flowback assembly 181 includes an upper ball valve l46b, such that fitting 184 simply replaces choke mechanism 140b in the overall configuration.
  • burst disk assembly 182 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 l80c of support assembly l84c.
  • Barrel guide l80c attaches to support base 178c so that fitting 1 burst disk valve 190 is in fluid communication with the lower portion l48c (see FIG. 2) of flowline l32c via support assembly 164c.
  • 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 132c to release wellbore fluids 112 and reduce pressure buildup within wellbore 100.
  • release mechanism l65c is manipulated to release bucket guide l80c from support base l78c and remove the upper portion !50c of flowline l32c having a ball valve l46c and choke l60c (shown in FIG. 5) and secure an upper portion l50c configured with the burst disk assembly 182.
  • burst disk assembly 182 includes an upper ball valve l46c, such that burst disk valve 190 simply replaces choke mechanism 140c in the overall configuration.
  • 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.
  • 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.
  • 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.
  • a stab-type connector is utilized in certain embodiments of step 202.
  • the various valves 146, 144 are in the“open” position as capping stack 120 is lowered and attached to wellhead 110.
  • 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.
  • the equipment and the tubing string are lowered through capping stack assembly 120 along flowline l32a into wellbore 100. Because flowline l 32a is axially aligned with connector 128, the tubing string can readily pass through capping stack assembly 120.
  • open ball valves 146a, l44a disposed along flowline l32a allow passage of the tubing string, and any equipment attached to the tubing string, through capping stack assembly 120.
  • 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 inj ecting a working fluid into the wellbore to balance or overbalance the wellbore, or fishing operations to retrieve other equipment lost in the wellbore.
  • 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.
  • 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.
  • the capping stack 120 is utilized to sever the tubing string passing therethrough.
  • one of the ball valves l46a, l44a along flowline l32a 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.
  • the lower ball valve !44a is actuated to sever the tubing string adjacent diverter body 134.
  • 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 l32a is actuated and closed.
  • step 210 the other ball valve along flowline l32a is actuated and closed.
  • hydrocarbon fluids are no longer flowing along flowline !32a. However they may continue to flow along flowlines 132b, 132c as described herein.
  • ball valves l44b, !44c, l46b, !46c 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.
  • 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.
  • 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 adj acent the manifold body and a distal end; a second flowline in fluid communication with the second flowbore, the second flowline having a proximal end adj acent 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 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 adj acent 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;
  • 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 adj acent 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.
  • 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 adj acent 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.
  • 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.
  • 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.
  • Actuating the ball valve comprises driving the ball valve from an open position to a closed position.

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Valve Housings (AREA)

Abstract

Une pile de coiffage destinée à être utilisée avec un puits sous-marin comprend un robinet à bille disposée le long d'une première conduite d'écoulement qui est alignée axialement avec un alésage d'écoulement principal d'un corps de collecteur de telle sorte qu'une colonne de production peut passer par la robinet à bille jusque dans le puits et moyennant quoi le robinet à bille peut être activé à la fois pour fermer la conduite d'écoulement et sectionner la colonne de production selon les besoins. L'alésage d'écoulement principal du corps de collecteur est défini le long d'un axe principal et la pile de coiffage comprend des deuxième et troisième conduites d'écoulement qui croisent chacune l'axe primaire selon un angle supérieur à zéro et qui comprennent chacune un mécanisme d'étranglement et une paire de robinets à bille espacés disposés le long de la conduite d'écoulement.
PCT/US2018/045387 2018-08-06 2018-08-06 Pile de coiffage de robinet à bille WO2020032920A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
BR112020024213-6A BR112020024213A2 (pt) 2018-08-06 2018-08-06 pilha de cobertura para uso com um poço submarino, e, método para intervenção de poço
EP18929831.8A EP3797208A4 (fr) 2018-08-06 2018-08-06 Pile de coiffage de robinet à bille
AU2018436246A AU2018436246A1 (en) 2018-08-06 2018-08-06 Ball valve capping stack
US16/476,399 US20210148192A1 (en) 2018-08-06 2018-08-06 Ball valve capping stack
PCT/US2018/045387 WO2020032920A1 (fr) 2018-08-06 2018-08-06 Pile de coiffage de robinet à bille

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2018/045387 WO2020032920A1 (fr) 2018-08-06 2018-08-06 Pile de coiffage de robinet à bille

Publications (1)

Publication Number Publication Date
WO2020032920A1 true WO2020032920A1 (fr) 2020-02-13

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PCT/US2018/045387 WO2020032920A1 (fr) 2018-08-06 2018-08-06 Pile de coiffage de robinet à bille

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Country Link
US (1) US20210148192A1 (fr)
EP (1) EP3797208A4 (fr)
AU (1) AU2018436246A1 (fr)
BR (1) BR112020024213A2 (fr)
WO (1) WO2020032920A1 (fr)

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CN111859750A (zh) * 2020-07-16 2020-10-30 中国石油大学(北京) 一种水下应急封井装置应用于日井喷流量气田的分析方法

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US11867022B2 (en) * 2019-01-24 2024-01-09 Halliburton Energy Services, Inc. Electric ball valve mechanism

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WO2012142274A2 (fr) * 2011-04-13 2012-10-18 Bp Corporation North America Inc. Systèmes et procédés de coiffage d'un puits sous-marin
US20140034337A1 (en) * 2011-04-14 2014-02-06 Johannes Van Wijk Capping stack and method for controlling a wellbore
US20150060081A1 (en) 2013-09-04 2015-03-05 Trendsetter Engineering, Inc. Capping stack for use with a subsea well
US20160245041A1 (en) * 2013-10-08 2016-08-25 Expro North Sea Limited Intervention system and apparatus
US20170350210A1 (en) * 2016-06-01 2017-12-07 Trendsetter Engineering, Inc. Rapid mobilization air-freightable capping stack system

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WO2012142274A2 (fr) * 2011-04-13 2012-10-18 Bp Corporation North America Inc. Systèmes et procédés de coiffage d'un puits sous-marin
US20140034337A1 (en) * 2011-04-14 2014-02-06 Johannes Van Wijk Capping stack and method for controlling a wellbore
US20150060081A1 (en) 2013-09-04 2015-03-05 Trendsetter Engineering, Inc. Capping stack for use with a subsea well
US20160245041A1 (en) * 2013-10-08 2016-08-25 Expro North Sea Limited Intervention system and apparatus
US20170350210A1 (en) * 2016-06-01 2017-12-07 Trendsetter Engineering, Inc. Rapid mobilization air-freightable capping stack system

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN111859750A (zh) * 2020-07-16 2020-10-30 中国石油大学(北京) 一种水下应急封井装置应用于日井喷流量气田的分析方法
CN111859750B (zh) * 2020-07-16 2021-03-16 中国石油大学(北京) 一种水下应急封井装置应用于日井喷流量气田的分析方法

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EP3797208A1 (fr) 2021-03-31
AU2018436246A1 (en) 2020-12-17
US20210148192A1 (en) 2021-05-20
EP3797208A4 (fr) 2022-01-12
BR112020024213A2 (pt) 2021-02-17

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