US20120318522A1 - Air-freightable containment cap for containing a subsea well - Google Patents
Air-freightable containment cap for containing a subsea well Download PDFInfo
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- US20120318522A1 US20120318522A1 US13/468,872 US201213468872A US2012318522A1 US 20120318522 A1 US20120318522 A1 US 20120318522A1 US 201213468872 A US201213468872 A US 201213468872A US 2012318522 A1 US2012318522 A1 US 2012318522A1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
- E21B43/0122—Collecting oil or the like from a submerged leakage
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Abstract
A modular containment cap for containing a subsea wellbore discharging hydrocarbons comprises a lower assembly including a spool body having an upper end, a lower end opposite the upper end, and a first throughbore extending from the upper end to the lower end. In addition the containment cap comprises an upper assembly including a spool piece having an upper end, a lower end opposite the upper end, a throughbore extending from the upper end to the lower end, and a first spool piece valve disposed in the throughbore. The first spool piece valve is configured to control the flow of fluids through the throughbore of the spool piece. The upper end of the spool body is releasably connected to the lower end of the spool piece, and the first throughbore of the spool body is coaxially aligned with and in fluid communication with the throughbore of the spool piece.
Description
- This application claims benefit of U.S. provisional patent application Ser. No. 61/498,269 filed Jun. 17, 2011, and entitled “Air-Freightable Containment Cap for Containing a Subsea Well,” which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. provisional patent application Ser. No. 61/500,679 filed Jun. 24, 2011, and entitled “Subsea Containment Cap Adapter,” which is hereby incorporated herein by reference in its entirety.
- Not applicable.
- 1. Field of the Invention
- The invention relates generally to systems and methods for containing a subsea wellbore that is discharging hydrocarbons. More particularly, the invention relates to systems and methods for capping a subsea wellbore at the flex joint of the lower marine riser package, the blowout preventer (BOP), or wellhead, and controlling the discharge of hydrocarbons into the surrounding sea. Still more particularly, the invention relates to a modular, air-freightable system for capping a subsea blowout preventer or lower marine riser package and controlling the discharge of hydrocarbons into the surrounding sea.
- 2. Background of the Technology
- In offshore drilling operations, a blowout preventer (BOP) is installed on a wellhead at the sea floor and a lower marine riser package (LMRP) is mounted to the BOP. In addition, a drilling riser extends from a flex joint at the upper end of LMRP to a drilling vessel or rig at the sea surface. A drill string is then suspended from the rig through the drilling riser, LMRP, and the BOP into the well bore. A choke line and a kill line are also suspended from the rig and coupled to the BOP, usually as part of the drilling riser assembly.
- During drilling operations, drilling fluid, or mud, is delivered through the drill string, and returned up an annulus between the drill string and casing that lines the well bore. In the event of a rapid influx of formation fluid into the annulus, commonly known as a “kick,” the BOP and/or LMRP may actuate to seal the annulus and control the well. In particular, BOPs and LMRPs comprise closure members capable of sealing and closing the well in order to prevent the release of gas or liquids from the well. Thus, the BOP and LMRP are used as devices that close, isolate, and seal the wellbore. Heavier drilling mud may be delivered through the drill string, forcing fluid from the annulus through the choke line or kill line to protect the well equipment disposed above the BOP and LMRP from the pressures associated with the formation fluid. Assuming the structural integrity of the well has not been compromised, drilling operations may resume. However, if drilling operations cannot be resumed, cement or heavier drilling mud may be delivered into the well bore to kill the well.
- In the event that the wellbore is not sealed, a blowout may occur. The blowout may damage subsea equipment and/or connections between subsea equipment. This can be especially problematic if it results in the discharge of hydrocarbons into the surrounding sea water. In addition, it may be challenging to rectify remotely as the discharge may be hundreds or thousands of feet below the sea surface.
- In the event such a subsea blowout results in the discharge of hydrocarbons into the surrounding sea, the amount of time it takes to cap and/or shut-in the well is important (i.e., the more time it takes, the more hydrocarbons are discharged into the surrounding water). One possible approach to capping and shutting-in a subsea well is to obtain a second BOP, lower the second BOP subsea, couple the second BOP to the upper end of the subsea BOP or LMRP that is discharging hydrocarbons, and then utilize the second BOP to shut-in the well. However, due to their sheer size and weight, most conventional BOPs are not transportable by air. Accordingly, identifying, obtaining, and transporting a suitable conventional BOP for use in capping a subsea blowout may be time consuming and inefficient.
- Accordingly, there remains a need in the art for systems and methods to cap a subsea well. Such systems and methods would be particularly well-received if they offered the potential to cap a subsea well discharging hydrocarbon fluids and were air-freightable.
- These and other needs in the art are addressed in one embodiment by a modular containment cap for containing a subsea wellbore discharging hydrocarbons into the surrounding sea. In an embodiment, the containment cap comprises a lower assembly including a spool body having an upper end, a lower end opposite the upper end, and a first throughbore extending from the upper end to the lower end. In addition the containment cap comprises an upper assembly including a spool piece having an upper end, a lower end opposite the upper end, a throughbore extending from the upper end to the lower end, and a first spool piece valve disposed in the throughbore. The first spool piece valve is configured to control the flow of fluids through the throughbore of the spool piece. The upper end of the spool body is releasably connected to the lower end of the spool piece, and the first throughbore of the spool body is coaxially aligned with and in fluid communication with the throughbore of the spool piece.
- These and other needs in the art are addressed in another embodiment by a method for containing and/or producing a subsea wellbore discharging hydrocarbons into the surrounding sea. A wellhead is disposed at the sea floor at the upper end of the wellbore, a subsea BOP is mounted to the wellhead, an LMRP is mounted to the BOP, and a riser extends from the LMRP. In an embodiment, the method comprises (a) selecting a subsea landing site from one of the BOP, the LMRP, or the wellhead. In addition, the method comprises (b) preparing the landing site for connection to a modular containment cap. The containment cap comprises a lower assembly including a spool body and an upper assembly including a spool piece. Further, the method comprises (c) transporting the lower assembly and the upper assembly to an offshore location. Still further, the method comprises (d) lowering the lower assembly subsea and releasably connecting the lower assembly to the landing site. Moreover, the method comprises (e) lowering the upper assembly subsea and releasably connecting the upper assembly to the lower assembly. Moreover, the method comprises (f) shutting in the wellbore with the containment cap after (d) and (e).
- These and other needs in the art are addressed in another embodiment by a containment cap for containing a subsea wellbore discharging hydrocarbons into the surrounding sea. In an embodiment, the containment cap comprises a lower assembly including a spool body having an upper end, a lower end opposite the upper end, and a first throughbore extending from the upper end to the lower end. In addition, the containment cap comprises a valve assembly slidingly disposed in the first throughbore. The valve assembly comprises a tubular body and a first spool body valve. The tubular body has an upper end extending from the first throughbore, a lower end disposed within the first throughbore, and a throughbore extending between the upper end and the lower end of the tubular body. The first spool body valve is disposed along the throughbore of the tubular body and is configured to control the flow of fluids through the throughbore of the tubular body. Further, the containment cap comprises a plurality of annular seal assemblies radially positioned between the spool body and the tubular body. Each seal assembly is configured to restrict the flow of fluids between the tubular body and the spool body.
- Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.
- For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
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FIG. 1 is a schematic view of an embodiment of an offshore drilling system; -
FIG. 2 is an enlarged view of the riser flex joint of the lower marine riser package ofFIG. 1 ; -
FIG. 3 is a top view of the flange of the riser adapter ofFIG. 2 ; -
FIG. 4 is a schematic view of the offshore drilling system ofFIG. 1 damaged by a subsea blowout; -
FIG. 5 is a perspective view of an embodiment of a modular, air-freightable containment cap for containing the wellbore ofFIG. 4 ; -
FIG. 6 is a cross-sectional side view of the containment cap ofFIG. 5 ; -
FIG. 7 is a perspective view of the lower assembly ofFIG. 5 ; -
FIG. 8 is a side view of the lower assembly ofFIG. 5 ; -
FIG. 9 is a top view of the lower assembly ofFIG. 5 ; -
FIG. 10 is a schematic view of the lower assembly ofFIG. 5 ; -
FIG. 11 is a perspective view of the upper assembly ofFIG. 5 ; -
FIG. 12 is a side view of the upper assembly ofFIG. 5 ; -
FIG. 13 is a cross-sectional side view of the upper assembly ofFIG. 5 ; -
FIG. 14 is a schematic view of the upper assembly ofFIG. 5 ; -
FIG. 15 is a perspective view of the kill-flowback assembly ofFIG. 5 ; -
FIG. 16 is a side view of the kill-flowback assembly ofFIG. 5 ; -
FIG. 17 is a perspective view of the lower assembly ofFIG. 5 configured for subsea deployment; -
FIG. 18 is an assembly view illustrating the lower assembly ofFIG. 5 , the running tool ofFIG. 17 , and a pair of adapters for deploying the lower assembly subsea; -
FIG. 19 is a perspective view of the upper assembly ofFIG. 5 configured for subsea deployment; -
FIGS. 20A-20L are sequential schematic views of the subsea deployment and installation of the containment cap ofFIG. 5 directly onto the BOP ofFIG. 4 ; -
FIG. 21 is a schematic view of the containment cap ofFIG. 5 directly connected to the wellhead ofFIG. 4 ; -
FIG. 22 is a side view of an embodiment of a transition spool for coupling the containment cap ofFIG. 5 to the flex joint ofFIG. 4 ; -
FIG. 23 is a perspective view of an embodiment of a system for adjusting the angular orientation of the riser adapter ofFIG. 2 ; -
FIG. 24 is a top view of the system ofFIG. 23 ; -
FIG. 25 is a perspective view of the base members ofFIG. 23 mounted to the flex joint base ofFIG. 2 ; -
FIG. 26 is a perspective view of an embodiment of a system for adjusting the angular orientation of the riser adapter ofFIG. 2 ; -
FIG. 27 is a perspective view of the hydraulic cylinder assembly ofFIG. 26 ; -
FIG. 28 is a perspective view of an embodiment of a set of wedge members for locking the angular orientation of the riser adapter ofFIG. 2 ; -
FIG. 29 is a top view of the set of wedge members ofFIG. 28 ; -
FIGS. 30A-30P are sequential schematic views of the subsea deployment and installation of the containment cap ofFIG. 5 onto the flex joint of Figure ofFIG. 4 ; -
FIG. 31 is a side cross-sectional view of an embodiment of a modular, air-freightable containment cap for containing the wellbore ofFIG. 4 ; -
FIG. 32 is a schematic view of an embodiment of a method for deploying the containment cap ofFIG. 5 ; -
FIG. 33 is a schematic view illustrating various transition spools used to couple the containment cap ofFIG. 5 orFIG. 31 to a plurality of riser flex joints having differing connector profiles; -
FIG. 34 is a front view of an embodiment of a transition spool in accordance with the principles described herein; -
FIG. 35 is a perspective, exploded view of the transition spool ofFIG. 34 ; -
FIGS. 36A-36N are front, exploded views of embodiments of transitions spools including lower portions having different connector profiles to accommodate different landing site connector profiles; -
FIG. 37 is a schematic representation of an inventory, including the modular components of the containment cap and a plurality of transition spools to couple the cap to multiple subsea components; and -
FIG. 38 is a schematic representation of another inventory, including modular components of the containment cap and components of transition spools that are ready to be coupled to form completed transition spools prior to shipping. - The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest in any way that the scope of the disclosure, including the claims, is limited to that embodiment.
- Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
- In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first component couples to a second component, that connection may be through a direct engagement between the two components, or through an indirect connection via other intermediate devices, components, and/or connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the given axis, and a radial distance means a distance measured perpendicular to the given axis.
- Referring now to
FIG. 1 , an embodiment of anoffshore system 100 for drilling and/or producing awellbore 101 is shown. In this embodiment,system 100 includes anoffshore platform 110 at thesea surface 102, a subsea blowout preventer (BOP) 120 mounted to awellhead 130 at thesea floor 103, and a lower marine riser package (LMRP) 140 mounted toBOP 120.Platform 110 is equipped with aderrick 111 that supports a hoist (not shown). Adrilling riser 115 extends subsea fromplatform 110 toLMRP 140. In general,riser 115 is a large-diameter pipe that connectsLMRP 140 to the floatingplatform 110. During drilling operations,riser 115 takes mud returns toplatform 110. Casing 131 extends fromwellhead 130 intosubterranean wellbore 101. - Downhole operations are carried out by a tubular string 116 (e.g., drillstring, production tubing string, coiled tubing, etc.) that is supported by
derrick 111 and extends fromplatform 110 throughriser 115,LMRP 140,BOP 120, and into casedwellbore 101. Adownhole tool 117 is connected to the lower end oftubular string 116. In general,downhole tool 117 may comprise any suitable downhole tool(s) for drilling, completing, evaluating and/or producingwellbore 101 including, without limitation, drill bits, packers, testing equipment, perforating guns, and the like. During downhole operations,string 116, and hencetool 117 coupled thereto, may move axially, radially, and/or rotationally relative toriser 115,LMRP 140,BOP 120, andcasing 131. -
BOP 120 andLMRP 140 are configured to controllably sealwellbore 101 and contain hydrocarbon fluids therein. Specifically,BOP 120 has a central orlongitudinal axis 125 and includes abody 123 with anupper end 123 a releasably secured toLMRP 140, alower end 123 b releasably secured towellhead 130, and amain bore 124 extending axially between upper and lower ends 123 a, b. Main bore 124 is coaxially aligned withwellbore 101, thereby allowing fluid communication betweenwellbore 101 andmain bore 124. In this embodiment,BOP 120 is releasably coupled toLMRP 140 andwellhead 130 with hydraulically actuated, mechanical wellhead-type connections 150. In general,connections 150 may comprise any suitable releasable wellhead-type mechanical connection such as the H-4® profile subsea system available from VetcoGray Inc. of Houston, Tex., the DWHC profile subsea system available from Cameron International Corporation of Houston, Tex., and the HC profile subsea system available from FMC Technologies of Houston, Tex. Typically, such wellhead-type mechanical connections (e.g., connections 150) comprise an upward-facing male connector or “hub,” labeled with reference numeral 150 a herein, that is received by and releasably engages a complementary, downward-facing mating female connector or receptacle, labeled withreference numeral 150 b herein. In addition,BOP 120 includes a plurality of axially stacked sets of opposed rams—one set of opposed blind shear rams orblades 127 for severingtubular string 116 and sealing offwellbore 101 fromriser 115 and two sets of opposed pipe rams 128, 129 for engagingstring 116 and sealing the annulus aroundtubular string 116. In other embodiments, the BOP (e.g., 120) may also include one or more sets of opposed blind rams for sealing off wellbore when no string (e.g., string 116) or tubular extends through the main bore of the BOP (e.g., main bore 124). Each set oframs string 116 and/ormain bore 124 whenrams -
Opposed rams main bore 124 and support rams 127, 128, 129 as they move into and out ofmain bore 124. Each set oframs main bore 124 and do not interfere withtubular string 116 or other hardware that may extend throughmain bore 124. However, in the closed positions, rams 127, 128, 129 are radially advanced intomain bore 124 to close off and seal main bore 124 (e.g., rams 127) or the annulus around tubular string 116 (e.g., rams 128, 129). Each set oframs actuators 126. In particular, each actuator 126 hydraulically moves a piston within a cylinder to move a drive rod coupled to oneram - Referring still to
FIG. 1 ,LMRP 140 has a body 141 with anupper end 141 a connected to the lower end ofriser 115, alower end 141 b releasably secured toupper end 123 a withconnector 150, and athroughbore 142 extending between upper and lower ends 141 a, b.Throughbore 142 is coaxially aligned withmain bore 124 ofBOP 110, thereby allowing fluid communication betweenthroughbore 142 andmain bore 124.LMRP 140 also includes anannular blowout preventer 142 a comprising an annular elastomeric sealing element that is mechanically squeezed radially inward to seal on a tubular extending through bore 142 (e.g.,string 116, casing, drillpipe, drill collar, etc.) or seal offbore 142. Thus,annular BOP 142 a has the ability to seal on a variety of pipe sizes and seal offbore 142 when no tubular is extending therethrough. - Referring now to
FIGS. 1 and 2 , in this embodiment,upper end 141 a ofLMRP 140 comprises a riser flex joint 143 that allowsriser 115 to deflect angularly relative toBOP 120 andLMRP 140 while hydrocarbon fluids flow fromwellbore 101,BOP 120 andLMRP 140 intoriser 115. In this embodiment, flex joint 143 includes acylindrical base 144 rigidly secured to a mating hub ormandrel 151 extending from the upper end ofLMRP 140, and a riser extension oradapter 145 extending upward frombase 144. Afluid flow passage 146 extending throughbase 144 andadapter 145 defines the upper portion ofthroughbore 142. A flex element (not shown) disposed withinbase 144 extends betweenbase 144 andriser adapter 145, and sealingly engages bothbase 144 andriser adapter 145. The flex element allowsriser adapter 145 to pivot and angularly deflect relative tobase 144,LMRP 140, andBOP 120. The upper end ofadapter 145distal base 144 comprises anannular flange 145 a forcoupling riser adapter 145 to a matingannular flange 118 at the lower end ofriser 115 or to alternative devices. As best shown inFIG. 3 ,flange 145 a includes a plurality of circumferentially-spacedholes 147 that receive bolts for securingflange 145 a to a matingannular flange 118 at the lower end ofriser 115. In addition,flange 145 a includes a pair of circumferentially spaced guide holes 148, eachguide hole 148 having a diameter greater than the diameter ofholes 147. In this embodiment, flex joint 143 also includes amud boost line 149 having an inlet (not shown) in fluid communication withflow passages outlet 149 b inflange 145 a, and avalve 149 c configured to control the flow of fluids throughline 149. AlthoughLMRP 140 has been shown and described as including a particular flex joint 143, in general, any suitable riser flex joint may be employed inLMRP 140. - As previously described, in this embodiment,
BOP 120 includes three sets of rams (one set ofshear rams 127 and two sets of pipe rams 128, 129), however, in other embodiments, the BOP (e.g., BOP 120) may include a different number of rams (e.g., four sets of rams), different types of rams (e.g., two sets of shear rams and two sets of pipe rams, one or more sets of opposed blind rams), an annular BOP (e.g.,annular BOP 142 a), or combinations thereof. It should be appreciated thatBOP 120 is exemplary only and that any subsea BOP preferably includes at least three sets of rams including at least two sets of pipe rams and at least one set of blind-shear rams. Likewise, althoughLMRP 140 is shown and described as including oneannular BOP 142 a, in other embodiments, the LMRP (e.g., LMRP 140) may include a different number of annular BOPs (e.g., two sets of annular BOPs), different types of rams (e.g., shear rams), or combinations thereof. - Referring now to
FIG. 4 , during a “kick” or surge of formation fluid pressure inwellbore 101, one ormore rams BOP 120 and/orannular BOP 142 a ofLMRP 140 are normally actuated to seal inwellbore 101. In theevent wellbore 101 is not sealed, it may potentially result in the discharge of such hydrocarbon fluids subsea. InFIG. 4 ,system 100 is shown after a subsea blowout. In the exemplary blowout scenario shown inFIG. 4 ,riser 115 has been severed and bent over proximal flex joint 143. As a result, hydrocarbon fluids flowing upward inwellbore 101 pass throughBOP 120 andLMRP 140, and are discharged into the surrounding sea water proximal thesea floor 103 through punctures and breaks inriser 115. The emitted hydrocarbon fluids form asubsea hydrocarbon plume 160 that extends to thesea surface 102. Embodiments of containment caps and methods for deploying same described in more detail below are designed to contain and shut-inwellbore 101, and control the subsea emission of hydrocarbon fluids to reduce and/or eliminate the subsea discharge of hydrocarbon fluids. - Referring now to
FIGS. 5 and 6 , an embodiment of a containment stack or cap 200 for cappingwellbore 101 previously described (FIG. 4 ), and containing the hydrocarbon fluids therein is shown. In this embodiment,containment cap 200 is modular, meaningcap 200 comprises distinct and separate sections or assemblies that are deployed subsea independently and then coupled together subsea to formcap 200. Specifically,containment cap 200 comprises three assemblies—a first orlower assembly 210, a second orupper assembly 250 releasably coupled tolower assembly 210 with a wellhead-type connection 150, and a kill-flowback assembly 290 releasably coupled toupper assembly 250 with a wellhead-type connection 150. As will be described in more detail below,assemblies wellbore 101, whereasassembly 290 functions to deliver kill weight fluids to wellbore 101 and/or producewellbore 101 once it is contained and controlled. - In this embodiment, each
assembly assembly assembly lower assembly 210 has a weight of about 70 tons (140×103 lbs.),upper assembly 250 has a weight of about 40 tons (80×103 lbs.), and kill-flowback assembly 290 has a weight of about 7.5 tons (15×103 lbs.). In addition, eachassembly upper assembly 250 may have a height greater than 14 ft., it is dimensioned such that it can be laid down and fit within the confines of the cargo bay during shipment and then erected after transport for deployment. Accordingly, any two of the threeassemblies assembly assembly - Referring now to
FIGS. 5-10 ,lower assembly 210 includes aframe 211 and a spool tree orbody 221 disposed withinframe 211.Frame 211 supportsspool body 221 and the other components oflower assembly 210. In addition,frame 211 protectsspool body 221 and the other components oflower assembly 210 from impacts during transport and deployment. -
Spool body 221 includes a first pipe spool orspool piece 222 and a second pipe spool orspool piece 230 attached to and extending perpendicularly fromspool piece 222.Spool piece 222 has a central orlongitudinal axis 223, a first orupper end 222 a, a second orlower end 222 b oppositeend 222 a, a vertical flow bore orthroughbore 224 extending axially between ends 222 a, b, and a horizontal flow bore 225 extending perpendicularly frombore 224.Upper end 222 a offirst spool piece 222 defines the upper end ofspool body 221, andlower end 222 b offirst spool piece 222 defines the lower end ofspool body 221.Throughbore 224 is coaxially disposed withinspool piece 222. In other words, throughbore 224 has a central axis coincident withaxis 223.Throughbore 224 has a minimum inner diameter equal to or greater than the inner diameter ofwellbore 101, throughbore 142, andmain bore 124, and thus, throughbore 224 may be described as having a “full bore diameter” and providing “full bore access.” -
Upper end 222 a ofspool piece 222 comprises an upward-facinghub 150 a andlower end 222 b comprises a downward-facingreceptacle 150 b.Hub 150 a atupper end 222 a extends axially upward fromframe 211 and is configured to mate, engage, and interlock with a downward-facingcomplementary connector 150 b onupper assembly 250, thereby forming a releasable wellhead-type, hydraulically actuatedmechanical connection 150 betweenassemblies receptacle 150 b atlower end 222 b is configured to mate, engage, and interlock with an upward-facingcomplementary hub 150 a on atransition spool 330,BOP 120, orwellhead 130, thereby forming a releasable wellhead-type, hydraulically actuatedmechanical connection 150 betweenlower assembly 210 and flexjoint adapter 145,BOP 120, orwellhead 130, respectively. - Referring still to
FIGS. 6-10 ,second spool piece 230 extends perpendicularly fromfirst spool piece 222 and has a central orlongitudinal axis 231, a first or radiallyinner end 230 a (relative to axis 223) secured tospool piece 222, a second or radiallyouter end 230 b (relative to axis 223) oppositeend 230 a anddistal spool piece 222, and a horizontal flow bore orthroughbore 232 extending axially (relative to axis 231) between ends 230 a, b.Throughbore 232 is coaxially disposed withinspool piece 230, and thus, throughbore 232 has a central axis coincident withaxis 231. -
Throughbore 232 is coaxially aligned with and contiguous withhorizontal bore 225. Thus, throughbore 232 is in fluid communication withbore 225. Together, bores 225, 232 define a horizontal branch or flow path inspool body 221 that extends perpendicularly from verticalmain bore 224. As best shown inFIG. 10 ,first spool piece 222 includes avalve 233 positioned alongbore 225 andsecond spool piece 230 includes avalve 233 positioned alongthroughbore 232.Valves 233 control the flow of fluids throughbores valve 233 has an open position allowing fluid flow therethrough and a closed position restricting and/or preventing fluid flow therethrough.Valves 233 are positioned in series along bores 225, 232. Consequently, fluid flow throughbores valves 233 are closed, and fluid flow throughbores valves 233 are opened. In general, eachvalve 233 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inbore 232 including, without limitation, ball valves, gate valves, and butterfly valves. Further, eachvalve 233 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 233 is a hydraulically actuated gate valve rated for a 15 k psi pressure differential. Eachvalve 233 may be controlled and hydraulically actuated subsea with an ROV. Alternatively, eachvalve 233 may be controlled from the surface with hydraulic flow lines or flying leads extending from the surface and coupled tovalves 233 via a panel located onlower assembly 210. -
Lower assembly 210 also includes achoke valve 234 positioned between afluid conduit 235 andspool piece 230.Fluid conduit 235 has afirst end 235 a coupled to chokevalve 234, asecond end 235 bdistal choke valve 234, and aflow bore 236 extending betweenends 235 a, b.Ends valve 234, and bores 232, 236 are in fluid communication withchoke valve 234. Thus, chokevalve 234 controls the flow rate of fluids betweenbores choke valve 234 may comprise any suitable choke or choke valve for regulating the rate of fluid flow betweenbores valve 234 is a Willis CC40 Control Choke with SLCA Hydraulic Stepping Actuator capability (non-functional) or mechanical stepping capability with torque tool available from Cameron International Corporation of Houston, Tex. Thechoke valve 234 has a retrievable insert that can be removed and replaced subsea. -
Second end 235 b offluid conduit 235 comprises an upward-facinghub 239 a configured to mate, engage, and interlock with a downward-facing connector of a flow line to form a releasable flow line connection therebetween. Thus, with eachvalve 233 open, fluid inthroughbore 224 is free to flow throughbores choke valve 234, and bore 236 tohub 239 a atend 235 b, where the fluid may be discharged into the surrounding sea or flowed into another device connected tohub 239 a atend 235 b. For example, as will be described in more detail below, whenlower assembly 210 is coupled to wellbore 101 and eachvalve 233 is open, hydrocarbons discharged fromwellbore 101 may be flowed frombore 224 throughbores choke valve 234, and bore 236 tohub 239 a atend 235 b, where the hydrocarbons may be discharged into the surrounding sea or produced to another device connected tohub 239 a atend 235 b. Alternatively, with eachvalve 233 open, fluid may be supplied and/or pumped from a device connected tohub 239 a throughbore 236,choke valve 234, and bores 232, 225 intobore 224. For example, as will be described in more detail below, whenlower assembly 210 is coupled towellbore 101, chemicals or kill weight fluids may be supplied and/or pumped from a device connected tohub 239 a throughbore 236,choke valve 234, and bores 232, 225 into hydrocarbons inbore 224. - As best shown in
FIG. 10 , afirst annulus line 237 and asecond annulus line 238 provide access tothroughbore 224 axially above and belowbore 225, respectively. In particular,first annulus line 237 has a first or radiallyinner end 237 a in fluid communication withthroughbore 224 and a second or radiallyouter end 237 b extending to the outer surface ofspool piece 222; andsecond annulus line 238 has a first or radiallyinner end 238 a in fluid communication withthroughbore 224 and a second or radiallyouter end 238 b extending to the outer surface ofspool piece 222. End 237 a is positioned axially abovebore 225, and end 238 a is positioned axially belowbore 225.Ends valve 233 as previously described is positioned along eachflow line ends 237 a, b and 238 a, b, respectively.Lines wellbore 101 once it has been contained and controlled. - Referring still to
FIG. 10 , in this embodiment,lower assembly 210 also includes achemical injection system 240 and a fluid monitoring orsensor system 226. For purposes of clarity,chemical injection system 240 andfluid monitoring system 226 are not shown inFIGS. 6-9 .Chemical injection system 240 includes afirst flow line 241 for injecting chemicals intobore 232, asecond flow line 242 for injecting chemicals intobore 224 abovebore 225, and athird flow line 243 for injecting chemicals intobore 224 abovesecond flow line 242. The upstream ends offlow lines hot stab receptacle 248. Chemicals such as methanol and glycol may be supplied and/or pumped throughflow lines inlet receptacle 248. - Each
flow line primary valve 245 for controlling the flow of chemicals through thatparticular flow line valve 245 has an open position allowing fluid flow therethrough and a closed position restricting and/or preventing fluid flow therethrough. Consequently, fluid flow through aparticular flow line corresponding valve 245 is closed, and fluid flow through aparticular flow line corresponding valve 245 is opened. In general, eachvalve 245 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inflow lines valve 245 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 245 is a hydraulically actuated gate valve rated for a 15 k psi pressure differential. Eachvalve 245 may be controlled and hydraulically actuated subsea with an ROV. In addition, in this embodiment,valve 245 on eachflow line inlet receptacle 248 to bore 224.Valve 245 onflow line 241 does not include a check valve so that pressure testing and sampling ofbore 232 may be performed. Eachflow line pressure gauge 246 positioned betweenvalve 245 and itsinlet receptacle 248.Gauges 246 measure the fluid pressure withinflow lines Secondary valves 247 are positioned alongflow lines gauges 246 andinlet receptacle 248, and an additionalsecondary valve 247 is positioned atinlet receptacle 248.Secondary valves 247 provide a secondary means tovalves 245 for controlling fluid flow throughflow lines valve 247 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inflow lines valve 247 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 247 is a manually operated needle valve rated for a 15 k psi pressure differential. Eachvalve 247 may be manually operated subsea with an ROV. Alternatively, eachvalve 247 may be hydraulically controlled from the surface with hydraulic flow lines or flying leads extending from the surface and coupled tovalves 247 via a panel located onlower assembly 210. - Referring still to
FIG. 10 ,fluid monitoring system 226 includes anelectronic pressure transducer 227 positioned alongthroughbore 224 and anelectronic temperature transducer 228 positioned alongthroughbore 224.Transducers bore 224. Eachtransducers electrical coupling 229 configured to transmit the measured temperature and pressure data, respectively, fromtransducers coupling 229. - Referring now to
FIGS. 5 , 6, and 11-14,upper assembly 250 includes aframe 251 and a pipe spool orspool piece 260 disposed withinframe 251.Frame 251 supportsspool piece 260 as well as the remaining components ofupper assembly 250. In addition,frame 251 protectsspool piece 260 and the remaining components ofupper assembly 250 from impacts during transport and deployment. The top offrame 251 comprises aplanar pad 252 for landing kill-flowback assembly 290. -
Spool piece 260 has a central orlongitudinal axis 261, a first orupper end 260 a, a second orlower end 260 b oppositeend 260 a, and a flow bore orthroughbore 262 extending axially between ends 260 a, b. Flow bore 262 is coaxially disposed withinspool piece 260. In other words, flow bore 262 has a central axis coincident withaxis 261. In this embodiment,spool piece 260 is oriented such thataxis 261 and flow bore 262 extend vertically. In addition, in this embodiment, flow bore 262 has a minimum inner diameter that is less than the minimum inner diameter ofthroughbore 224 andwellbore 101. -
Upper end 260 a ofspool piece 260 comprises an upward-facinghub 150 a andlower end 260 b comprises a downward-facingreceptacle 150 b.Hub 150 a atupper end 260 a extends axially upward frompad 252 and is configured to mate, engage, and interlock with a complementary downward-facingconnector 150 b onassembly 290, thereby forming a releasable wellhead-type, hydraulically actuatedmechanical connection 150 betweenassemblies receptacle 150 b atlower end 260 b is configured to mate, engage, and interlock with a complementary upward-facinghub 150 a atupper end 222 a ofspool piece 221, thereby forming a releasable wellhead-type, hydraulically actuatedmechanical connection 150 betweenassemblies - As best shown in
FIGS. 12-14 ,spool piece 260 also includes a first orlower valve 263, a second orupper valve 263, and a flow boreaccess member 265, each positioned along flow bore 262 betweenends 260 a, b. More specifically,second valve 263 is axially spaced abovefirst valve 263, andaccess member 265 is axially positioned betweenvalves 263.Valves 263 control the flow of fluids inbore 262. Namely, eachvalve 263 has an open position allowing fluid flow therethrough and a closed position restricting and/or preventing fluid flow therethrough.Valves 263 are positioned in series along flow bore 262. Consequently, fluid flow throughbore 262 is restricted and/or prevented if one or bothvalves 263 are closed, and fluid flow throughbore 262 is permitted if bothvalves 263 are opened. In general, eachvalve 263 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inbore 262 including, without limitation, ball valves, gate valves, and butterfly valves. Further, eachvalve 263 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 263 is a hydraulically actuated gate valve rated for a 15 k psi pressure differential. Eachvalve 263 may be controlled and hydraulically actuated subsea with an ROV. As will be described in more detail below, flow boreaccess member 265 enables access to flowbore 262. - Referring now to
FIG. 14 , in this embodiment,upper assembly 250 also includes achemical injection system 270 and a fluid monitoring orsensor system 280. For purposes of clarity,chemical injection system 270 andfluid monitoring system 280 are not shown inFIGS. 5 , 6, and 11-13.Chemical injection system 270 includes asupply line 271 that may be used to inject chemicals intobore 262 and areturn line 272 for receiving fluids frombore 262.Supply line 271 has aninlet end 271 a and a second or outlet end 271 b in fluid communication withbore 262 viaaccess member 265.Return line 272 has a first or inlet end 272 a in fluid communication withbore 262 viaaccess member 265 and a second or outlet end 272 b. Inlet end 271 a and outlet end 272 b are connected to separate ports on a dual port ROVhot stab receptacle 248. Chemicals such as methanol and glycol may be supplied and/or pumped throughsupply line 271 intobore 262, and fluids inbore 262 may be acquired viareturn line 272. As will be described in more detail below, supply and returnlines - Each
flow line valves 273, arranged series, for controlling the flow of chemicals through thatparticular flow line valve 273 has an open position allowing fluid flow therethrough and a closed position restricting and/or preventing fluid flow therethrough. Consequently, fluid flow through aparticular flow line valves 273 is closed, and fluid flow through aparticular flow line corresponding valves 273 are opened. In general, eachvalve 273 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inflow lines valve 273 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 273 is a manually operated needle valve rated for a 15 k psi differential. Eachvalve 273 may be manually operated subsea with an ROV. In this embodiment,return line 272 includes apressure gauge 246 positioned betweenvalves 273 andaccess member 265. Gauge 246 measure the fluid pressure withinreturn line 272. - Referring still to
FIG. 14 ,fluid monitoring system 280 includes a borefluid supply line 281, a borefluid return line 282, and a sensor package orassembly 285.Flow line 281 has aninlet end 281 a in fluid communication with flow bore 262 viaaccess member 265 and anoutlet end 281 b comprising acoupling 283.Flow line 282 has aninlet end 282 a comprising acoupling 283 and anoutlet end 282 b in fluid communication with flow bore 262 viaaccess member 265. Eachflow line valve 247 as previously described for controlling the flow of fluids through thatparticular flow line Sensor package 285 includes afluid flow line 286, apressure sensor 287 disposed alongline 286, atemperature sensor 288 disposed alongline 286, and adata transmitter 289 coupled tosensors Flow line 286 has aninlet end 286 a comprising acoupling 284 releasably coupled tocoupling 283 ofline 281 and anoutlet end 286 b comprising acoupling 284 releasably coupled tocoupling 283 ofline 282. Thus,flow lines line flow bore 262.Sensors flow line 286. The measured pressure and temperature data is communicated totransmitter 289, which then wirelessly retransmits the measured pressure and temperature data to the surface.Transmitter 289 may communicate pressure and temperature data periodically or on a real-time basis. In general,transmitter 289 may be any suitable device for transmitting data from a subsea location to the surface. In this embodiment,transmitter 289 is an acoustic datalogger. As described above,sensor package 285 is releasably coupled tolines couplings sensor package 285 may be removed or coupled to accessmember 265 as desired. One or more ROVs may be used to connectsensor package 285 tolines sensor package 285 fromlines - In this embodiment,
systems system 270 includessupply line 271 and returnline 272, andsystem 280 includessupply line 281 and returnline 282. However, in other embodiments, the fluid monitoring system (e.g., system 280) may utilize the same supply and return lines as the chemical injection system (e.g., system 270). For example,sensor package 285 may be configured to plug intohot stab receptacle 248, receive wellbore fluids viasupply line 271 and return wellbore fluids viareturn line 272. In other words, ends 286 a, b offlow line 286 may be configured as ports in a hot stab connector that is coupled toreceptacle 248 with inlet end 286 a in fluid communication withsupply line 271 and outlet end 286 b in fluid communication withreturn line 272. - Referring now to
FIGS. 5 , 6, 15 and 16, kill-flowback assembly 290 includes aframe 291 and a pipe spool orspool piece 292 extending throughframe 291.Frame 291 supportsspool piece 292 as well as the remaining components ofassembly 290. In addition,frame 291 protectsspool piece 292 and the remaining components ofassembly 290 from impacts. The lower end offrame 291 comprises an annular funnel or guide 293 to facilitate the landing ofassembly 290 ontoupper assembly 250. -
Spool piece 292 has a central orlongitudinal axis 294, a first orupper end 292 a, a second orlower end 292 b oppositeend 292 a, and a flow bore orthroughbore 295 extending axially between ends 292 a, b. Flow bore 295 is coaxially disposed withinspool piece 292. In other words, flow bore 295 has a central axis coincident withaxis 294. In this embodiment,spool piece 292 is oriented such thataxis 294 and flow bore 295 extend vertically. In this embodiment, flow bore 295 has an inner diameter that is the same as the inner diameter of flow bore 262. -
Upper end 292 a ofspool piece 292 extends axially upward fromframe 291 and comprises an upward-facingflange 296, andlower end 292 b comprises a downward-facingreceptacle 150 b.Flange 296 is configured to mate, engage, and connect with a downward-facing flange on a flow conduit that supplies kill weight fluids to cap 200 and/or produces hydrocarbons fromwellbore 101. In this embodiment, twoexemplary conduits FIGS. 15 and 16 .Receptacle 150 b atlower end 292 b is configured to mate, engage, and interlock with upward-facinghub 150 a atupper end 260 a ofspool piece 260, thereby forming a releasable wellhead-type, hydraulically actuatedmechanical connection 150 betweenassemblies - Referring again to
FIG. 6 ,upper assembly 250 is releasably coupled tolower assembly 210 with a wellhead-type connection 150, and kill-flowback assembly 290 is releasably coupled to upper assembly with a wellhead-type connection 150. Whencap 200 is assembled as shown inFIG. 6 , flow bores 224, 262, 295 are coaxially aligned, flow bore 224 is in fluid communication withflow bore 262, and flow bore 295 is in fluid communication with flow bores 224, 262 as long as bothvalves 263 in flow bore 262 are opened. Thus, withvalves 263 opened, fluids are free to flow throughbores ends cap 200 is coupled tosubsea wellhead 130,BOP 120, orLMRP 140,valves 263 are opened, and full access bore 224 is in fluid communication withwellbore 101, kill weight fluids may be pumped intowellbore 101 viaconduit wellbore 101 may be produced viaconduit - In this embodiment,
containment cap 200 is designed to be deployed subsea and landed onriser flex joint 143 ofLMRP 140, onmandrel 151 ofLMRP 140, onBOP 120, or onwellhead 130, depending on which is the most suitable landing site. For example, inFIG. 20L ,cap 200 is shown installed onsubsea BOP 120 previously described; inFIG. 21 ,cap 200 is shown installed onsubsea wellhead 130 previously described; and inFIG. 30P ,cap 200 is shown installed onflex joint 143 ofLMRP 140 previously described. Regardless of the landing/installation site, in this embodiment, themodular cap 200 previously described is installed in stages—lower assembly 210 is first deployed subsea and installed on the selected landing site (e.g.,LMRP 140,mandrel 151, flex joint 143,wellhead 130, BOP 120), thenupper assembly 250 is deployed subsea and installed ontolower assembly 210, and then kill-flowback assembly 290 is deployed subsea and installed ontoupper assembly 250. - Referring briefly to
FIGS. 17 and 18 , in this embodiment,lower assembly 210 is lowered and manipulated subsea with a runningtool 215 releasably coupled tohub 150 a atupper end 222 a ofspool piece 222. As best shown inFIG. 18 , runningtool 215 has a first orupper end 215 a and a second orlower end 215 b oppositeend 215 a.Lower end 215 b comprises a downward-facingreceptacle 150 b that releasably engageshub 150 a atupper end 222 a.Upper end 215 a of runningtool 215 may be releasably coupled to afirst adapter 216 that enables deployment oflower assembly 210 with a pipestring or drillstring, or to asecond adapter 217 that enables deployment oflower assembly 210 on wireline. Thus, runningtool 215 may be deployed subsea from a surface vessel with a pipe string usingfirst adapter 216 and runningtool 215, or with a wireline usingsecond adapter 217 and runningtool 215. As shown inFIG. 19 ,upper assembly 250 is lowered and manipulated subsea with wireline coupled to frame 251 with a plurality oflead lines 253 disposed aboutpad 252. Kill-flowback assembly 290 is lower and manipulated subsea with wireline in the same manner asupper assembly 250. In other embodiments,upper assembly 250 and/or kill-flowback assembly 290 may be lowered via drillpipe, tubing string, flexible tubing, or coiled tubing. - Referring now to
FIGS. 20A-20L ,containment cap 200 is shown being deployed and installed subsea onBOP 120 to shut-in and/or producewellbore 101. More specifically, inFIGS. 20A-20D ,lower assembly 210 is shown being lowered subsea and coupled toBOP 120; inFIGS. 20E-20H ,upper assembly 250 is shown being lowered subsea and coupled tolower assembly 210; and inFIGS. 20I-20L , kill-flowback assembly 290 is shown being lowered subsea and coupled toupper assembly 250. - For subsea deployment and installation of
containment cap 200, one or more remote operated vehicles (ROVs) are preferably employed to aid inpositioning assemblies monitoring assemblies BOP 120, and operatingassemblies valves ROVs 170 are employed to positionassemblies assemblies BOP 120, and operateassemblies ROV 170 includes anarm 171 having aclaw 172, asubsea camera 173 for viewing the subsea operations (e.g., the relative positions ofassemblies BOP 120,plume 160, the positions and movement ofarms 170 andclaws 172, etc.), and an umbilical 174. Streaming video and/or images fromcameras 173 are communicated to the surface or other remote location via umbilical 174 for viewing on a live or periodic basis.Arms 171 andclaws 172 are controlled via commands sent from the surface or other remote location toROV 170 through umbilical 174. - Before connecting
cap 200 toBOP 120,LMRP 140 is removed fromBOP 120 bydecoupling connection 150 betweenBOP 120 andLMRP 140, and then liftingLMRP 140 fromBOP 120 with wireline, a pipestring, one ormore ROVs 170, or combinations thereof. In addition, any tubulars or debris extending fromupper end 123 a ofBOP 120 are cut off substantially flush withupper end 123 a with one ormore ROVs 170. - Referring first to
FIG. 20A , in this embodiment,lower assembly 210 is shown being controllably lowered subsea with apipestring 180 secured to the upper end ofadapter 216 and extending to a surface vessel. A derrick or other suitable device mounted to the surface vessel is preferably employed to support andlower assembly 210 onstring 180. Althoughstring 180 is employed to deploylower assembly 210 in this embodiment, in other embodiments,lower assembly 210 may be deployed subsea on wireline. Usingstring 180,lower assembly 210 is lowered subsea under its own weight from a location generally above and laterally offset fromwellbore 101 andBOP 120. More specifically, during deployment,lower assembly 210 is preferably maintained outside ofplume 160 of hydrocarbon fluids emitted fromwellbore 101. Loweringlower assembly 210 subsea inplume 160 may trigger the undesirable formation of hydrates withinlower assembly 210, particularly at elevations substantially abovesea floor 103 where the temperature of hydrocarbons inplume 160 is relatively low. - Moving now to
FIG. 20B ,lower assembly 210 is lowered laterally offset fromBOP 120 and outside ofplume 160 untillower end 222 b is slightly aboveBOP 120. Asassembly 210 descends and approachesBOP 120,ROVs 170 monitor the position ofassembly 210 relative toBOP 120. Next, as shown inFIG. 20C ,assembly 210 is moved laterally into position immediately above and substantially coaxially aligned withBOP 120. One ormore ROVs 170 may utilize theirclaws 172 andframe 211 to guide and manipulate the position ofassembly 210 relative toBOP 120. Due to its own weight,assembly 210 is substantially vertical, whereasBOP 120 may be oriented at a slight angle relative to vertical. Thus, it is to be understood that perfect coaxial alignment ofBOP 120 andassembly 210 may be difficult. However, the mating profiles ofhub 150 a atupper end 123 a ofBOP 120 andreceptacle 150 b atlower end 222 b ofassembly 210 facilitate the coaxial alignment and coupling ofassembly 210 andBOP 120 asassembly 210 is lowered from a position immediately aboveBOP 120, even ifassembly 210 is initially slightly misaligned withBOP 120. - Moving now to
FIG. 20D , withreceptacle 150 b atlower end 222 b ofassembly 210 positioned immediately above and substantially coaxially aligned withhub 150 a atupper end 123 a ofBOP 120,string 180 lowers assembly 210 axially downward. Due to the weight ofassembly 210, compressive loads betweenassembly 210 andBOP 120 urge themale hub 150 a atupper end 123 a into thefemale receptacle 150 b atlower end 222 b. Once thehub 150 a is sufficiently seated in thereceptacle 150 b to form wellhead-type connection 150,connection 150 is hydraulically actuated to securely connectassembly 210 toBOP 120 as shown inFIG. 20D . - As
assembly 210 is positioned immediately aboveBOP 120, hydrocarbons emitted fromBOP 120 are free to flow unrestricted throughbore 224. In addition, prior to movingassembly 210 laterally overBOP 120,valves 233 inlines valves 233 inbores BOP 120 to flow throughbore 232, choke 234, and bore 236.Valves 233 inbores valves 233 inlines surface 102 prior to deployment, or subsea via one ormore ROVs 170. Thus, asassembly 210 is moved laterally overBOP 120 and lowered into engagement withBOP 120, emitted hydrocarbon fluids flow freely throughbores open valves 233 offer the potential to reduce the resistance to the axial insertion ofhub 150 a intoreceptacle 150 b and coupling oflower assembly 210 toBOP 120. In other words,open valves 233 inbores lower assembly 210. With a sealed, secure connection betweenlower assembly 210 andBOP 120,ROVs 170decouple running tool 215 fromlower assembly 210. Runningtool 215 andadapter 216 may then be removed to the surface withpipestring 180. - Referring now to
FIG. 20E , withlower assembly 210 securely coupled toBOP 120,upper assembly 250 is deployed and coupled tolower assembly 210. In this embodiment,upper assembly 250 is shown being controllably lowered subsea withwireline 181 extending from a surface vessel and having a lower end secured to leads 253. Due to the weight ofassembly 250,wireline 181 and leads 253 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support andlower assembly 250 onwireline 181. Althoughwireline 181 and leads 253 are employed tolower assembly 250 in this embodiment, in other embodiments,assembly 250 may be deployed subsea on a pipe string. Usingwireline 181,assembly 250 is lowered subsea under its own weight from a location generally above and laterally offset fromwellbore 101,BOP 120,lower assembly 210, and outside ofplume 160 to reduce the potential for hydrate formation withinassembly 250. - Moving now to
FIG. 20F ,upper assembly 250 is lowered laterally offset fromlower assembly 210 and outside ofplume 160 untillower end 260 b is slightly abovelower assembly 210. Asupper assembly 250 descends and approacheslower assembly 210,ROVs 170 monitor the position ofupper assembly 250 relative to lowerassembly 210. Next, as shown inFIG. 20G ,assembly 250 is moved laterally into position immediately above and substantially coaxially aligned withlower assembly 210. One ormore ROVs 170 may utilize theirclaws 172 andframe 251 to guide and manipulate the position ofupper assembly 250 relative to lowerassembly 210. Due to its own weight,assembly 250 is substantially vertical, whereaslower assembly 210 may be oriented at a slight angle relative to vertical ifBOP 120 was slightly angled. Thus, it is to be understood that perfect coaxial alignment ofassemblies hub 150 a atupper end 222 a ofspool piece 222 andreceptacle 150 b atlower end 260 b ofassembly 250 facilitate the coaxial alignment and coupling ofassemblies upper assembly 250 is lowered from a position immediately abovelower assembly 210, even ifupper assembly 250 is initially slightly misaligned withlower assembly 210. - Moving now to
FIG. 20H , withreceptacle 150 b atlower end 260 b positioned immediately above and substantially coaxially aligned withhub 150 a atupper end 222 a,wireline 181 lowers assembly 250 axially downward. Due to the weight ofassembly 250, compressive loads betweenupper assembly 250 andlower assembly 210 urge themale hub 150 a atupper end 222 a into thefemale receptacle 150 b atlower end 260 b. Once thehub 150 a is sufficiently seated in thereceptacle 150 b to form wellhead-type connection 150,connection 150 is hydraulically actuated to securely connectupper assembly 250 tolower assembly 210 as shown inFIG. 20H . With a sealed, secure connection betweenlower assembly 210 andupper assembly 250,ROVs 170 decouple leads 253 fromupper assembly 250.Leads 253 may then be removed to the surface withwireline 181. - Prior to moving
upper assembly 250 laterally overlower assembly 210 andBOP 120,valves 263 are transitioned to the open position also allowing hydrocarbon fluids emitted byBOP 120 andlower assembly 210 to flow throughbore 262.Valves 263 may be transitioned to the open position at thesurface 102 prior to deployment, or subsea via one ormore ROVs 170. Thus, asupper assembly 250 is moved laterally overlower assembly 210 and lowered into engagement withlower assembly 210, emitted hydrocarbon fluids flow freely throughbore 262. As a result,open valves 263 offer the potential to reduce the resistance to the axial insertion ofhub 150 a intoreceptacle 150 b and coupling ofupper assembly 250 tolower assembly 210. In other words,open valves 263 allow the relief of well pressure during installation ofupper assembly 250. It should also be appreciated that aligned bores 224, 262 enable re-entry ofBOP 120 andwellbore 101. - Referring now to
FIG. 20I , withupper assembly 250 securely coupled tolower assembly 210, kill-flowback assembly 290 is deployed and coupled toupper assembly 250.Assembly 290 is deployed in substantially the same manner asupper assembly 250. Specifically, in this embodiment, kill-flowback assembly 290 is shown being controllably lowered subsea withwireline 181 extending from a surface vessel and having a lower end coupled to frame 291 with a plurality of leads 253. Due to the weight ofassembly 290,wireline 181 and leads 253 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support andlower assembly 290 onwireline 181. Althoughwireline 181 and leads 253 are employed tolower assembly 290 in this embodiment, in other embodiments,assembly 290 may be deployed subsea on a pipe string. Usingwireline 181,assembly 290 is lowered subsea under its own weight from a location generally above and laterally offset fromwellbore 101,BOP 120,lower assembly 210,upper assembly 250, and outside ofplume 160 to reduce the potential for hydrate formation withinassembly 290. - Moving now to
FIG. 20J ,assembly 290 is lowered laterally offset fromupper assembly 250 and outside ofplume 160 untillower end 292 b is slightly aboveupper assembly 250. Asassembly 290 descends and approachesupper assembly 250,ROVs 170 monitor the position ofassembly 290 relative toupper assembly 250. Next, as shown inFIG. 20K ,assembly 290 is moved laterally into position immediately above and substantially coaxially aligned withupper assembly 250. One ormore ROVs 170 may utilize theirclaws 172 andframe 291 to guide and manipulate the position ofassembly 290 relative toupper assembly 250. Due to its own weight,assembly 290 is substantially vertical, whereasupper assembly 250 may be oriented at a slight angle relative to vertical ifBOP 120 was slightly angled. Thus, it is to be understood that perfect coaxial alignment ofassemblies hub 150 a atupper end 260 a ofspool piece 260 andreceptacle 150 b atlower end 292 b ofspool piece 292 facilitate the coaxial alignment and coupling ofassemblies assembly 290 is lowered from a position immediately aboveupper assembly 250, even ifassembly 290 is initially slightly misaligned withupper assembly 250. - Moving now to
FIG. 20L , withreceptacle 150 b atlower end 292 b positioned immediately above and substantially coaxially aligned withhub 150 a atupper end 260 a,wireline 181 lowers assembly 290 axially downward. Due to the weight ofassembly 290, compressive loads betweenassembly 290 andupper assembly 260 urge themale hub 150 a atupper end 260 a into thefemale receptacle 150 b atlower end 292 b. Once thehub 150 a is sufficiently seated in thereceptacle 150 b to form wellhead-type connection 150,connection 150 is hydraulically actuated to securely connect kill-flowback assembly 290 toupper assembly 250 as shown inFIG. 20L . With a sealed, secure connection betweenupper assembly 250 and kill-flowback assembly 290ROVs 170 decouple leads 253 fromassembly 290.Leads 253 may then be removed to the surface withwireline 181. - Prior to moving
assembly 290 laterally overupper assembly 250 andBOP 120, flow bore 295 is maintained opened to allow hydrocarbon fluids emitted byBOP 120 andassemblies bore 295. Thus, as kill-flowback assembly 290 is moved laterally overupper assembly 250 and lowered into engagement withupper assembly 250, emitted hydrocarbon fluids flow freely throughbore 295, thereby offering the potential to reduce the resistance to the axial insertion ofhub 150 a intoreceptacle 150 b and coupling ofassembly 290 toupper assembly 250. In other words, open flow bore 295 allows the relief of well pressure during installation of kill-flowback assembly 290. Aconduit upper end 292 a of spool piece 292 (to supply kill weight fluids or produce wellbore 101) onceassembly 290 is securely connected toupper assembly 250. - In the manner described,
cap 200 is deployed and installed onBOP 120. However, as best shown inFIG. 21 ,cap 200 may also be installed directly ontowellhead 130.Assemblies lower assembly 210 is securely connected towellhead 130. In particular, downward-facingreceptacle 150 b atlower end 222 b is coupled to upward-facingreceptacle 150 a ofwellhead 130, thereby formingconnection 150 betweenlower assembly 210 andwellhead 130. Before connectinglower assembly 210 towellhead 130,LMRP 140 andBOP 120 are removed fromwellhead 130 bydecoupling connection 150 betweenBOP 120 andLMRP 140, liftingLMRP 140 fromBOP 120 and thendecoupling connection 150 betweenBOP 120 andwellhead 130 and liftingBOP 120 fromwellhead 130. In addition, any tubulars or debris extending fromwellhead 130 are cut off substantially flush with the upper end ofwellhead hub 150 a with one ormore ROVs 170. - Referring now to
FIGS. 6 and 20L , upon installation ofcontainment cap 200, hydrocarbons are free to flow throughcap 200. To contain and shut-inwellbore 101,valves 233 inbores valves 263 inbore 262 are manipulated bysubsea ROVs 170. If kill fluids are utilized to aid in shutting inwellbore 101, kill-flowback assembly 290 is preferably installed prior to initiating the shut-in procedures (i.e., so that kill weight fluids may be supplied to cap 200 and wellbore 101 via conduit 298). However, if kill fluids are not utilized to aid in shutting inwellbore 101, the shut-in procedures may be initiated prior to installation of kill-flowback assembly 290. - To shut-in
wellbore 101,valves 233 inflow lines valves 233 inbores upper valve 263 is transitioned closed. Asupper valve 263 is transitioned closed, the pressure of wellbore fluids withinlower assembly 210 are monitored withpressure transducer 227 and the pressure of wellbore fluids withinupper assembly 250 are monitored withpressure sensor 287. As long as the formation fluid pressures withinassemblies upper valve 263 continues to be closed until it is fully closed. Onceupper valve 263 is closed,lower valve 263 may also be fully closed to provide redundancy. With bothvalves 263 closed, fluid flow throughbore 262 is restricted and/or prevented, however, sincevalves 233 inbores bores valve 234. Next,valve 233 inbore 232 is transitioned closed. As thatvalve 233 is transitioned closed, the pressure of wellbore fluids withinlower assembly 210 are monitored withpressure transducer 227. As long as the formation fluid pressures withinassembly 210 is within acceptable limits,valve 233 inbore 232 continues to be closed until it is fully closed. Oncevalve 233 inbore 232 is closed,valve 233 inbore 225 may also be fully closed to provide redundancy. With eachvalve wellbore 101 is contained and shut-in. It should be appreciated that inclusion ofchoke valve 234 and the staged shut-in ofwellbore 101 via sequential closure ofvalves BOP 120,assembly 210,assembly 250, assembly 290) and lead to another subsea blowout. - Once
wellbore 101 is shut-in and generally under control, and the necessary infrastructure for producingwellbore 101 are in place (e.g., hydrocarbon storage vessels, risers, manifolds, flow lines, etc. are installed),wellbore 101 may be produced via kill-flowback assembly 290 and/orconduit 235. For example, depending on the particular circumstances, wellbore 101 may be produced throughflowback assembly 290 withvalves 233 closed andvalves 263 opened, produced throughconduit 235 withvalves 233 opened andvalves 263 closed, or produced through bothassembly 290 andconduit 235 with allvalves - As previously described,
lower assembly 210 includeschemical injection system 240, andupper assembly 250 includes achemical injection system 270.Injection systems wellbore 101 to inject chemicals intobores assemblies assemblies assemblies -
Containment cap 200 previously described may also be installed ontomandrel 151 or flex joint 143 ofLMRP 140. Installation ofcap 200 onto flex joint 143 ofLMRP 140 will now be described. As shown inFIGS. 1 and 2 ,riser adapter 145 is coupled to flex joint 143; the upper end ofriser adapter 145 comprisesflange 145 a forcoupling adapter 145 tomating flange 118 at the lower end ofriser 115. However, in the embodiment shown,lower end 222 b of spool piece 222 (FIG. 8 ) comprisesreceptacle 150 b for connecting to acomplementary mating hub 150 a to form a wellhead-type connection 150. Thus,receptacle 150 b is not configured or designed to mate and engage withflange 145 a. Accordingly, referring now toFIG. 22 , in this embodiment, an adapter ortransition spool 330 is employed to couplelower assembly 210 ofcap 200 toriser adapter 145. - Referring to
FIG. 22 , in this embodiment,transition spool 330 has a central orlongitudinal axis 335, a first orupper end 330 a, a second orlower end 330 b oppositeend 330 a, and aflow bore 331 extending axially between ends 330 a, b.Upper end 330 a comprises an upward-facinghub 150 a configured to releasably engagecomplementary receptacle 150 b atlower end 222 b ofcontainment cap 200 to form a wellhead-type connection 150,lower end 330 b comprises amule shoe 340 configured to be coaxially inserted intoriser adapter 145 following removal ofriser 115 from flex joint 143. Anannular flange 334 is axially disposed betweenends 330 a, b, and is sized and configured to mate and engage withflange 145 a of flex joint 143.Flange 334 includes a plurality of circumferentially spacedholes 334 a.Bolts 334 b are pre-disposed inholes 334 a, and a resilientannular band 336 is disposed about the upper ends ofbolts 334 b.Band 336 urges the upper ends ofbolts 334 b radially inward relative to their lower ends and holes 334 a, thereby skewing and anglingbolts 334 b relative toholes 334 a (i.e.,bolts 334 b are not coaxially aligned withholes 334 a). In this manner,band 336 maintains the position ofbolts 334 b extending intoholes 334 a during deployment oftransition spool 330, thereby reducing the likelihood of one ormore bolts 334 b disengaging their correspondingholes 334 a and being dropped to thesea floor 103 during deployment and installation ofcontainment cap 200. - Referring still to
FIG. 22 , a pair of circumferentially spaced alignment guides or pins 338 extend axially downward fromflange 334.Pins 338 are sized and positioned to coaxially androtationally align flange 334 oftransition spool 330 relative to flange 145 a of flex joint 143 such that holes 334 a are coaxially aligned with corresponding holes inflange 145 a.Transition spool 330 also includes aplug 337 extending axially throughflange 334.Plug 337 is positioned and oriented for axial insertion intooutlet 149 b ofmud boost line 149 inflange 145 a whenflanges seal outlet 149 b, thereby preventing the leakage of hydrocarbon fluids therethrough in the eventmud boost valve 149 c fails or otherwise leaks. In this embodiment, plug 337 is pre-installed intransition spool 330 prior to deployment such that it engagesmating outlet 149 b asflanges ROV 170 afterflanges outlet 149 b in the event it is necessary to flush hydrates fromoutlet 149 b. -
Mule shoe 340 is a tubular extending axially downward fromflange 334. In this embodiment,shoe 340 also includes a plurality of circumferentially spaced elongate throughslots 343 extending radially from the outer cylindrical surface ofshoe 340 to bore 331. In the embodiment,slots 343 are oriented parallel toaxis 335. In other embodiments, the slots in the mule shoe (e.g.,slots 343 in mule shoe 340) may be omitted. Moreover, although this embodiment oftransition spool 330 includesmule shoe 340, in other embodiments, the mule shoe (e.g., mule shoe 340) is completely eliminated. In such embodiments, a plurality of guide pins (e.g., guide pins 338) facilitate the alignment and coupling of the transition spool (e.g., spool 320) and the flex joint (e.g., flex joint 143) - As will be described in more detail below, during installation of
transition spool 330 onto flex joint 143,mule shoe 340 is coaxially aligned with joint 143 and axially advanced into joint 143 untilflanges mule shoe 340 into flex joint 143, throughslots 343 provide a flow path for hydrocarbon fluids discharged fromwellbore 101 throughBOP 120 andLMRP 140, thereby offering the potential to relieve wellbore pressure during installation. - To facilitate the alignment and insertion of
mule shoe 340 into flex joint 143,lower end 330 b is angled or tapered in side view (i.e., when viewed perpendicular to axis 335). Specifically,lower end 330 b is oriented at an angle β relative toaxis 335. Angle β is preferably between 30° and 60°. In this embodiment, angle β is 45°. Taperedlower end 330 b also facilitates the axial advancement ofmule shoe 340 into another component (e.g., flex joint 143) that is bent or angled relative to vertical and/or that contain pipes or tubulars disposed therein. For example,mule shoe 340 may be inserted into another component and slowly axially advanced. Asshoe 340 is advanced,tapered end 330 b slidingly engages the component, thereby guidingshoe 340 into the component. In addition, taperedend 330 b slidingly engages and guides tubulars within the component intobore 331. In other words,tapered end 330 b enablesmule shoe 340 to wedge itself radially between the component and the tubulars disposed therein. This may be particularly advantageous in instances wheremule shoe 340 is coupled to a component that contains damage tubulars or pipes that cannot be removed. - To prepare
flange 145 a for sealing engagement withflange 334,riser 115 is removed from flex joint 143, and any tubulars or debris extending upward fromflange 145 a are preferably cut off substantially flush withflange 145 a. In addition,riser adapter 145 is preferably oriented vertically and locked in the vertical position prior tocoupling transition spool 330,lower assembly 210,upper assembly 250, kill-flowback assembly 290, or combinations thereof toriser adapter 145. This offers the potential to simplify installation of these components as well as reduce moments experienced byadapter 145 following installation of these components. More specifically, sinceriser adapter 145 is designed to angularly deflect and pivot relative tobase 144, the moments exerted onriser adapter 145 following attachment of such components may causeriser adapter 145 to undesirably pivot and/or break. However, by straightening flex joint 143 (i.e., orientingriser adapter 145 vertically) and lockingriser adapter 145 in place, such moments can be reduced and resisted withoutadapter 145 pivoting or breaking. In general,riser adapter 145 may be oriented vertically and locked in the vertical orientation by any suitable systems and/or methods. Examples of suitable systems and methods fororienting riser adapter 145 vertically and lockingriser adapter 145 in the vertical orientation are disclosed in U.S. patent application No. 61/482,132 filed May 3, 2011, and entitled “Adjustment and Restraint System for a Subsea Flex Joint,” which is hereby incorporated herein by reference in its entirety for all purposes. - Referring briefly to
FIGS. 23-25 , an embodiment of asystem 300 for adjusting and restraining the angular orientation ofriser adapter 145 relative tobase 144,BOP 120, andwellhead 130 is shown. In this exemplary embodiment, thesystem 300 includes a plurality ofbase members 301 circumferentially spaced about and mounted to the upper end ofbase 144 and a plurality ofhydraulic cylinder assemblies 310, onecylinder assembly 310 is radially positioned between eachbase member 301 andriser adapter 145. Eachbase member 301 includes an upper pocket orcavity 302 within which onecylinder assembly 310 is seated and a lower pocket orcavity 303 that receive the upper ends of studs andnuts 304 extending upward frombase 144. - Each
hydraulic cylinder assembly 310 includes acylinder member 311 that rests in theupper pocket 302 and apiston member 312 extending fromcylinder member 311.Piston member 312 is hydraulically actuated to extend or retract relative tocylinder member 311.Piston member 312 includes acontact member 313 for engaging the outer surface ofriser adapter 145. Upon actuation,piston member 312 can be extended axially fromcylinder member 311 to exert a radial force onriser adapter 145 to pivotriser adapter 145 to the vertical position. In general,hydraulic cylinder assembly 310 may be any one of several robustly rated cylinders, including, for example, Enerpac® RC-502 hydraulic cylinders and/or Enerpac® RC-504 hydraulic cylinders which have an approximately 50-ton cylinder capacity. Hydraulic cylinders with various other capacities and characteristics are also contemplated and known to one having ordinary skill. -
Base members 301 andcylinder assemblies 310 are positioned aboutriser adapter 145 with one or more subsea ROVs (e.g., ROVs 170). In particular,base members 301 andcylinder assemblies 310 are circumferentially positioned and spaced to exert the appropriate radial forces onriser adapter 145 to vertically orientriser adapter 145. - Referring now to
FIG. 26 , an embodiment of anothersystem 340 for adjusting and restraining the angular orientation ofriser adapter 145 relative tobase 144,BOP 120, andwellhead 130 is shown. In this exemplary embodiment, thesystem 340 includes a plurality of stud caps 341 mounted to the upper ends the studs extending upward frombase 144 and a plurality of hydraulic cylinder assemblies 345 (only onecylinder assembly 345 is shown inFIG. 26 ) radially positioned betweencaps 341 andriser adapter 145. Eachcap 341 is a rigid cylinder including a counterbore or cavity in its lower end that receives the upper end of one stud extending upward frombase 144. - Referring now to
FIGS. 26 and 27 , eachhydraulic cylinder assembly 345 includes abody 346 and a piston-cylinder assembly 347 coupled tobody 346.Body 346 includes a piston-cylinder housing 346 a and aflange 346 b extending downward fromhousing 346 a. Piston-cylinder assembly 347 is disposed withinhousing 346 a and includes apiston member 348 hydraulically actuated to extend or retract relative tohousing 346 a.Piston member 348 includes acontact face 348 a for engaging the outer surface ofriser adapter 145. An ROV handle 349 is coupled tobody 346 to facilitate positioning ofassembly 345 by a subsea ROV. - To adjust the angle between
riser adapter 145 andbase 144, caps 341 are mounted on the studs extending upward frombase 144, and one ormore assemblies 345 are circumferentially disposed aboutriser adapter 145. In particular,assemblies 345 are radially positioned betweencaps 341 andriser adapter 145 withhousing 346 a engagingcaps 341,piston member 348 extending radially inward fromhousing 346 a towardsriser adapter 145, andflange 346 b engaging the inner surface ofbase 144. Next,assemblies 347 are actuated to extendpiston members 348 radially inward intoengagement riser adapter 145. Continued actuation ofassemblies 347 causespiston members 348 to exert a radial force onriser adapter 145 to pivotriser adapter 145 to the desired vertical position. In general,hydraulic cylinder assembly 345 may be any one of several robustly rated cylinders, including, for example, Enerpac® RC-502 hydraulic cylinders and/or Enerpac® RC-504 hydraulic cylinders which have an approximately 50-ton cylinder capacity. Hydraulic cylinders with various other capacities and characteristics are also contemplated and known to one having ordinary skill. -
Caps 341 andcylinder assemblies 345 are positioned aboutriser adapter 145 with one or more subsea ROVs (e.g., ROVs 170). In particular, caps 341 andcylinder assemblies 345 are circumferentially positioned and spaced to exert the appropriate radial forces onriser adapter 145 to vertically orientriser adapter 145. - Once
adapter 145 is oriented vertically, it is preferably locked in the vertical orientation so that it does not bend or flex during or after installation of a containment cap. For example,systems riser adapter 145 to exert balanced radial forces that maintainriser adapter 145 in the vertical orientation. Alternatively, rigid wedges may be disposed in the annulus radially positioned betweenriser adapter 145 andbase 144, and uniformly circumferentially spaced aboutriser adapter 145 onceadapter 145 is vertically oriented to maintainadapter 145 in the vertical orientation. - Referring now to
FIGS. 28 and 29 , an embodiment of aset 350 ofwedge members 360 for lockingriser adapter 145 in a vertical orientation is shown.Wedge members 360 are sized and configured to be positioned in the annulus betweenriser adapter 145 andcylindrical base 144. In particular,wedge members 360 are numerically labeled (e.g., “1”, “2”, “3”, “4” . . . ) to designate the circumferential order in whichwedge members 360 are arranged withinset 350. For example,wedge member 360 labeled “1” is circumferentiallyadjacent wedge member 360 labeled “2”, which is circumferentiallyadjacent wedge member 360 labeled “3”, and so on. Withwedge members 360 arranged in the proper circumferential order, set 350 defines an inner annularcylindrical surface 351 disposed at an inner diameter Di and an outer annularcylindrical surface 352 disposed at an outer diameter Do. Inner diameter Di is substantially the same or slightly greater than the outer diameter ofriser adapter 145, and outer diameter Do is substantially the same or slightly less than the inner diameter ofbase 144. Thus, whenwedge members 360 are arranged in the proper circumferential order and disposed aboutriser adapter 145,inner surface 351 engagesriser adapter 145 andouter surface 352 engages the inner surface ofbase 144, thereby locking the position and angle ofriser adapter 145 relative tobase 144. In this embodiment, anROV handle 361 is coupled to eachwedge member 360 to facilitate the independentpositioning wedge members 360 by a subsea ROV. - As best shown in
FIG. 29 ,inner surface 351 is centered about afirst centrum 351 a andouter surface 352 is centered about asecond centrum 352 a that is radially offset fromcentrum 351 a. The degree of radial offset ofcentrums lock riser adapter 145 at a particular angle relative tobase 144. - Referring now to
FIGS. 30A-30P ,containment cap 200 previously described is shown being deployed and installed subsea onflex joint 143 ofLMRP 140, afterriser adapter 145 has been prepared for engagement withtransition spool 330 as previously described, to contain and shut-inwellbore 101. Sincereceptacle 150 b atlower end 222 b ofspool piece 222 is not configured or designed to mate and engage withflange 145 a,transition spool 330 previously described is first deployed and coupled toLMRP 140, followed by deployment and installation ofassemblies FIGS. 30A-30D ,transition spool 330 is shown being controllably lowered subsea and secured to flex joint 143; inFIGS. 30E-30H ,lower assembly 210 is shown being controllably lowered subsea and secured to transitionspool 330; inFIGS. 30I-30L ,upper assembly 250 is shown being controllably lowered subsea and secured tolower assembly 210; and inFIGS. 30M-30P , kill-flowback assembly 290 is shown being controllably lowered subsea and secured toupper assembly 250. - Referring first to
FIG. 30A ,transition spool 330 is shown being controllably lowered subsea withwireline 181 and leads 253 secured to spool 330 and extending to a surface vessel. Due to the weight ofspool 330,wireline 181 and leads 253 are preferably relatively strong cables (e.g., steel cables) capable of withstanding the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support andlower spool 330 onwireline 181. Althoughwireline 181 is employed tolower spool 330 in this embodiment, in other embodiments,spool 330 may be deployed subsea with a running tool mounted to the lower end of a pipe string. Usingwireline 181,spool 330 is lowered subsea under its own weight from a location generally above and laterally offset fromwellbore 101,BOP 120, andLMRP 140 and outside ofplume 160 to reduce the potential for hydrate formation withinspool 330. - Moving now to
FIG. 30B ,spool 330 is lowered laterally offset from riser adapter 145 (outside of plume 160) untilmule shoe 340 is slightly aboveflange 145 a. Asspool 330 descends and approachesriser adapter 145,ROVs 170 monitor the position ofspool 330 relative to flex joint 143. Next, as shown inFIG. 30C ,transition spool 330 is moved laterally into position immediately aboveriser adapter 145 withmule shoe 340 substantially coaxially aligned withriser adapter 145. In addition,spool 330 is rotated aboutaxis 335 to substantially alignguide pins 338 withcorresponding holes 148 inflange 145 a. One ormore ROVs 170 may utilize theirclaws 172 to guide and rotatespool 330 into the proper alignment relative to flange 145 a. - Due to its own weight,
spool 330 is substantially vertical, whereasriser adapter 145 may be oriented at an angle relative to vertical. Thus, it is to be understood that perfect coaxial alignment ofmule shoe 340 and flex joint 143, as well as perfect alignment ofpins 338 and mating holes inflange 145 a, may be difficult. - With
mule shoe 340 positioned immediately above and generally coaxially aligned withriser adapter 145, and guidepins 338 aligned with corresponding holes inflange 145 a,wireline 181lower spool 330 axially downward, thereby inserting and axially advancingpins 338 into correspondingholes 148 and inserting and axially advancing mule shoelower end 330 b intoriser adapter 145 untilflange 334 axially abuts and engagesflange 145 a as shown inFIG. 30D . The frustoconical surface on the lower end of eachpin 338 functions to guide eachpin 338 into itscorresponding hole 148, even ifpins 338 are initially slightly misaligned withholes 148. Likewise, taper onlower end 330 b functions to guide the insertion and coaxial alignment ofspool 330 andriser adapter 145 asspool 330 is lowered from a position immediately aboveriser adapter 145, even ifmule shoe 340 is initially slightly misaligned withriser adapter 145. During installation ofspool 330, emitted hydrocarbons flow freely throughspool 330 andslots 343 inmule shoe 340, thereby relieving well pressure and offering the potential to reduce the resistance to the axial insertion ofmule shoe 340 intoriser adapter 145 and coupling oftransition spool 330 thereto. - With
mule shoe 340 sufficiently seated inriser adapter 145 andflange 334 abuttingmating flange 145 a, holes 334 a are coaxially aligned with correspondingholes 147 inflange 145 a and plug 337 is disposed inmud boost outlet 149 b. Next, oneROV 170cuts band 336, thereby allowingbolts 334 b to drop intoholes 147. One ormore ROVs 170 may also help facilitate the lowering ofbolts 334 b intoholes 147 if necessary.Bolts 334 b may then be tightened withROVs 170 to rigidlysecure spool 330 toriser adapter 145. With a sealed, secure connection betweenspool 330 andriser adapter 145,ROVs 170 decouple leads 253 fromtransition spool 330.Leads 253 may then be removed to the surface withwireline 181. - Once
transition spool 330 is securely coupled toriser adapter 145,assemblies FIGS. 20A-20L with the exception thatlower assembly 210 is connected to transitionspool 330. Specifically, as shown inFIGS. 30E-30H ,lower assembly 210 is lowered subsea as previously described and coupled totransition spool 330 via engagement of upward-facinghub 150 a oftransition spool 330 and downward-facingreceptacle 150 b oflower assembly 210 to form a wellhead-type connection 150 therebetween. Next, as shown inFIGS. 30I-30L ,upper assembly 250 is lowered subsea and connected tolower assembly 210 as previously described, and then, as shown inFIGS. 30M-30P , kill-flowback assembly 290 is lowered subsea and connected toupper assembly 250 as previously described.Wellbore 101 may be contained and shut-in withassemblies 210, 250 (with or without the use of kill fluids via assembly 290) in the same manner as previously described. It should also be appreciated that prior to installation of kill-flowback assembly 290, or after removal of kill-flowback assembly 290, aligned bores 224, 262 enable re-entry ofLMRP 140,BOP 120, and wellbore 101. - Once
wellbore 101 is shut-in and generally under control, and the necessary infrastructure for producingwellbore 101 are in place (e.g., hydrocarbon storage vessels, risers, manifolds, flow lines, etc. are installed),wellbore 101 may be produced viaflowback assembly 290 and/orconduit 235. In addition,injection systems wellbore 101 to inject chemicals intobores FIGS. 30A-30P illustratecontainment cap 200 being deployed and installed subsea onriser adapter 145, installation ofcap 200 onLMRP 140,wellhead 130, orBOP 120 is performed in the same fashion with the exception of the preparation of the landing site (e.g.,LMRP 140,wellhead 130, or BOP 120). - Referring now to
FIG. 31 , another embodiment of acontainment cap 400 for cappingwellbore 101 previously described (FIG. 4 ), and containing the hydrocarbon fluids therein is shown.Containment cap 400 is similar tocontainment cap 200 previously described. Namely,containment cap 400 is modular, and includes a first orlower assembly 210 as previously described. For purposes of clarity,frame 211,second pipe spool 230,chemical injection system 240, andsensor system 226 oflower assembly 210 are not shown inFIG. 31 . Unlikecap 200 previously described, in this embodiment,upper assembly 250 and kill-flowback assembly 290 are not included. Rather,upper assembly 250 has been replaced with a valve assembly 450 coaxially disposed inmain bore 224 oflower assembly 210, and kill-flowback assembly 290 has been replaced with acap 470. Valve assembly 450 is releasably maintained withinlower assembly 210 bycap 470.Cap 470 is securely attached tolower assembly 210 with anannular coupling member 480 that forms wellhead-type connections 150 withcap 470 andlower assembly 210.Assemblies 210, 450 function together to contain and shut-inwellbore 101, whereascap 470 facilitates the deliver of kill-weight fluids to wellbore 101 as well as the production ofwellbore 101 once it is contained and controlled. - As previously described,
lower assembly 210 is air-freightable. In this embodiment, valve assembly 450,cap 470, andcoupling 480 are also air-freightable. Thus,lower assembly 210, valve assembly 450,cap 470, andcoupling 480 are each sized and configured to be transported by air on its own or with one or more ofassembly 210, assembly 450,cap 470, andcoupling 480. In other words,lower assembly 210, valve assembly 450,cap 470, andcoupling 480 each has a weight and dimensions suitable for air transport. In this embodiment, valve assembly 450 has a weight under 30 tons, and thus, may be transported along withlower assembly 210. - Referring still to
FIG. 31 , valve assembly 450 comprises a tubular body 451 having a central orlongitudinal axis 452, a first orupper end 451 a, a second orlower end 451 b, and athroughbore 453 extending axially between ends 451 a, b. Assembly 450 also includes a pair of axially-spacedvalves 454 disposed alongthroughbore 453.Valves 454 control the flow of fluids throughbore 453. Namely, eachvalve 454 has an open position allowing fluid flow therethrough and a closed position restricting and/or preventing fluid flow therethrough.Valves 454 are positioned in series alongthroughbore 453. Consequently, fluid flow throughbore 453 is restricted and/or prevented if one or bothvalves 454 are closed, and fluid flow throughbore 453 is permitted if bothvalves 454 are opened. In general, eachvalve 454 may comprise any type of valve suitable for the anticipated fluid pressures and fluids inbore 453 including, without limitation, ball valves, gate valves, and butterfly valves. Further, eachvalve 454 may be manually actuated, hydraulically actuated, mechanically actuated, or electrically actuated valves. In this embodiment, eachvalve 454 is a hydraulically actuated ball valve rated for a 15 k psi pressure differential. Eachvalve 454 may be controlled and actuated subsea with an ROV. Alternatively, eachvalve 454 may be controlled from the surface with hydraulic flow lines or flying leads extending from the surface and coupled tovalves 454 via a panel located onlower assembly 210. - Valve assembly 450 is partially disposed within
main bore 224—upper end 451 a extends axially frombore 224, andlower end 451 b is disposed inbore 224. Anannular insert 460 is coaxially disposed withinbore 224 axially between assembly 450 and anannular shoulder 224 a withinbore 224.Insert 460 has a first orupper end 460 a, a second orlower end 460 b oppositeend 460 a, and aflow passage 461 extending axially between ends 460 a, b.Upper end 460 a comprises a cylindrical recess orcounterbore 462 that receiveslower end 451 b, andlower end 460 b comprises a reduced outer diameter portion that extends intobore 224 belowshoulder 224 a. Thus, insert 460 is seated inbore 224 againstshoulder 224 a, and tubular body 451 is seated inrecess 462. A plurality ofannular seal assemblies 470 are radially disposed between tubular body 451 andspool piece 222.Seal assemblies 470 restrict and/or prevent fluids from flowing axially between body 451 andspool piece 222. - Referring still to
FIG. 31 ,cap 470 maintains valve assembly 450 inbore 224 withlower end 451 b seated ininsert 460.Cap 470 is coaxially aligned withbores upper end 470 a, a second orlower end 470 b, and aflow passage 471 extending axially between ends 470 a, b. In this embodiment,upper end 470 a comprises an upward-facing flowline connection hub 239 a andlower end 470 b comprises a downward-facinghub 150 a. A cylindrical recess orcounterbore 472 extends axially fromlower end 470 b and defines anannular shoulder 473 inpassage 471. Tubular member 451 extends intorecess 472 and is seated againstshoulder 473.Ends annular coupling member 480. Specifically,coupling member 480 is disposed aboutends receptacle 150 b releasably secured tohub 150 a atend 470 b to form a wellhead-type connection 150 therebetween, and a downward-facingreceptacle 150 b releasably secured tohub 150 a atend 222 a to form a wellhead-type connection 150 therebetween. Upward-facinghub 239 a atupper end 470 a releasably engages and interlocks a mating receptacle at the lower end of a flow line for injecting kill weight fluids intocap 400 and wellbore 101 or producingwellbore 101. -
Containment cap 400 is deployed subsea and installed onwellhead 130,BOP 120, orLMRP 140 to contain and shut-inwellbore 101, and/or producewellbore 101. To simplify deployment,containment cap 400 is preferably deployed and installed subsea as a single unit in a single trip. In other words, in this embodiment, valve assembly 450 is preferably installed inlower assembly 210, and cap 470 coupled tolower assembly 210 withcoupling 480 at thesurface 102, and then the entirepre-assembled cap 400 lowered subsea. To installcap 400 ontoBOP 120,riser 115 is removed fromLMRP 140, andLMRP 140 is removed fromBOP 120. Then,cap 400 is lowered subsea on apipestring 180 orwireline 181 coupled tohub 239 a, and securely attached toBOP 120 with wellhead-type connection 150. To installcap 400 ontowellhead 130,riser 115 is removed fromLMRP 140,LMRP 140 is removed fromBOP 120, andBOP 120 is removed fromwellhead 130. Then,cap 400 is lowered subsea on apipestring 180 orwireline 181 coupled tohub 239 a, and securely attached towellhead 130 with wellhead-type connection 150. To installcap 400 ontoLMRP 140,riser 115 is removed fromLMRP 140, then transitionspool 330 is lower subsea and securely attached toriser adapter 145 as previously described. Next,cap 400 is lowered subsea and securely attached to transitionspool 330 with wellhead-type connection 150. In each case,cap 400 is preferably lowered subsea laterally offset fromwellbore 101 and outside ofplume 160, and then moved laterally over the landing site (e.g.,BOP 120,transition spool 330, or wellhead 130) and coupled thereto with a wellhead type-connection 150. One ormore ROVs 170 may be employed to facilitate the installment ofcap 400. - Although
cap 400 is preferably assembled at thesurface 102, and then lowered subsea as a single unit, in other embodiments,lower assembly 210 and valve assembly 450 may be lowered subsea separately, and then assembled intocap 400 subsea. For instance,lower assembly 210 may be lowered subsea and installed onwellhead 130,BOP 120, ortransition spool 330 as previously described, and then valve assembly 450 may be lowered subsea withwireline 181 orpipestring 180, installed inbore 224, and secured toassembly 210 withcap 470 andannular coupling 480. - Referring still to
FIG. 31 , upon installation ofcontainment cap 400, hydrocarbons are free to flow throughcap 400. To contain and shut-inwellbore 101,valves 233 inbores valves 454 inbore 453 are manipulated bysubsea ROVs 170. To utilize kill weight fluids in shutting inwellbore 101, a kill fluids supply line is connected tohub 239 a atupper end 470 a ofcap 470 prior to initiating the shut-in procedures. However, if kill fluids are not utilized to aid in shutting inwellbore 101, the shut-in procedures may be initiated prior to installation of a flow line ontohub 239 a. - To shut-in
wellbore 101,valves 233 inflow lines valves 233 inbores upper valve 454 is transitioned closed. Asupper valve 454 is transitioned closed, the pressure of wellbore fluids withinlower assembly 210 are monitored withpressure transducer 226 and the pressure of wellbore fluids withinupper assembly 250 are monitored withpressure sensor 287. As long as the formation fluid pressures withinassemblies 210, 450 are within acceptable limits,upper valve 454 continues to be closed until it is fully closed. Onceupper valve 454 is closed,lower valve 454 may also be fully closed to provide redundancy. With bothvalves 454 closed, fluid flow throughbore 453 is restricted and/or prevented, however, sincevalves 233 inbores bores valve 234. Next,valve 233 inbore 232 is transitioned closed. As thatvalve 233 is transitioned closed, the pressure of wellbore fluids withinlower assembly 210 are monitored withpressure transducer 226. As long as the formation fluid pressures withinassembly 210 is within acceptable limits,valve 233 inbore 232 continues to be closed until it is fully closed. Oncevalve 233 inbore 232 is closed,valve 233 inbore 225 may also be fully closed to provide redundancy. With eachvalve wellbore 101 is contained and shut-in. Accordingly, in this embodiment,valves 454 of assembly 450 perform the same function(s) asvalves 263 ofupper assembly 250 previously described. It should be appreciated that inclusion ofchoke valve 234 and the staged shut-in ofwellbore 101 via sequential closure ofvalves BOP 120,assembly 210, assembly 450, assembly 290) and lead to another subsea blowout. - Once
wellbore 101 is shut-in and generally under control, and the necessary infrastructure for producingwellbore 101 are in place (e.g., hydrocarbon storage vessels, risers, manifolds, flow lines, etc. are installed),wellbore 101 may be produced viahub 239 a atupper end 470 a ofcap 470 and/orconduit 235. For example, depending on the particular circumstances, wellbore 101 may be produced throughcap 470 withvalves 233 closed andvalves 454 opened, produced throughconduit 235 withvalves 233 opened andvalves 454 closed, or produced through bothcap 470 andconduit 235 with allvalves - As previously described,
lower assembly 210 includeschemical injection system 240.Injection systems 240 may be used prior to, during, or after shutting-inwellbore 101 to inject chemicals intobores assemblies 210, 450. - In the manner described, embodiments of containment caps described herein (e.g., caps 200, 400) may be deployed subsea from a surface vessel and installed on a subsea wellhead (e.g., wellhead 130), BOP (e.g., BOP 120) or LMRP (e.g., LMRP 140) that is emitting hydrocarbon fluids into the surrounding sea. Once securely installed subsea, a series of valves are actuated and closed to achieve a “soft” shut-in of the wellbore. Pressure and temperature sensors are included to measure the pressure and temperature of the wellbore fluids, thereby enabling an operator to manage the opening and closing of valves in a manner that reduces the likelihood of a blowout while attempting to shut-in the wellbore. For example, while shutting in the wellbore, the valves are preferably closed in a sequential order while the wellbore pressure is continuously monitored. In the event closure of a particular valve triggers an undesirable increase in wellbore pressure, that valve (or another valve) may be immediately opened to relieve the increased wellbore pressure, thereby offering the potential to avert a blowout while shutting in the well. Likewise, after the well is shut-in, the wellbore pressure may be monitored so that a valve may be opened in the event of an unexpected spike in wellbore pressure to relieve such wellbore pressure increase.
- Referring now to
FIG. 32 , an overview of amethod 500 for deploying and installing an embodiment of a subsea containment cap (e.g.,containment cap 200, 400) on a subsea wellhead, a BOP, an LMRP (e.g., LMRP mandrel), or a flex joint riser adapter that is emitting hydrocarbon fluids is shown. Starting inblock 501, a suitable subsea landing site is identified. In the embodiment ofoffshore system 100 previously described,subsea BOP 120 is mounted towellhead 130 at thesea floor 103 with a wellhead-type connection 150,LMRP 140 is mounted toBOP 120 with wellhead-type connection 150, flex joint 143 is mounted toLMRP 140 viamandrel 151, andriser 115 is coupled toriser adapter 145 with a flanged connection. Thus, potential landing sites includeriser adapter 145 ofLMRP 140 following removal ofriser 115,LMRP mandrel 151 following removal of flex joint 143,BOP 120 following removal ofLMRP 140, andwellhead 130 following removal ofBOP 120. These represent particularly suitable landing sites as the various connections between these components may be decoupled subsea with the aid ofROVs 170. The ultimate selection of the most desirable landing site may vary from well-to-well and depends on a variety of factors including, without limitation, the ease with which a particular connection may be broken and re-conneted, the type of damage, the component(s) that are damaged (e.g.,BOP 120,LMRP 140,riser 115, etc.), the potential for adverse effects when preparing the selected landing site (e.g., exposure of internal debris, trapped pipes, etc.), the potential for increased well flow/hydrocarbon emissions, the ability of the landing site and associated hardware (e.g.,BOP 120,LMRP 140, etc.) to take the load of the containment cap, or combinations thereof. - If the selected landing site is mandrel 151 of
LMRP 140 orriser adapter 145, the connection betweenriser 115 andriser adapter 145 is broken, andriser 115 is removed fromriser adapter 145 according to block 506. If the selected landing site isriser adapter 145, then the appropriate transition spool (e.g., transition spool 330), as needed, is deployed and installed subsea according to block 510. However, if the landing site isLMRP mandrel 151, then flex joint 143 (including riser adapter 145) is removed atblock 535. Thereafter, appropriate transition spool (e.g., transition spool 330), as needed, is deployed and installed subsea onmandrel 151 atblock 536. On the other hand, if the selected landing site isBOP 120,riser 115 is removed fromriser adapter 145,connection 150 betweenLMRP 140 andBOP 120 is broken, andLMRP 140 is removed fromBOP 120 according to block 507. Still further, if the selected landing site iswellhead 130,riser 115 is removed fromriser adapter 145,connection 150 betweenLMRP 140 andBOP 120 is broken,LMRP 140 is removed fromBOP 120,connection 150 betweenBOP 120 andwellhead 130 is broken, andBOP 120 is removed fromwellhead 130 according to block 508. - It should be appreciated that identification of the landing site also influences whether a transition spool (e.g., transition spool 330) is necessary to couple the containment cap to landing site. For example, if the landing site includes a connector or hub (e.g.,
hub 150 a) configured to mate and engagereceptacle 150 b atlower end 222 b, then a transition spool is not necessary. On the other hand, if the landing site comprises a connector or hub that is not configured to mate and engagereceptacle 150 b atlower end 222 b, then a transition spool is necessary to transition fromreceptacle 150 b atlower end 222 b to the particular type of connector or hub at the landing site. - Moving now to block 515, before, during, or after preparation of the landing site according to
blocks assemblies containment cap 200, orassemblies 210, 450,cap 470, andcoupling 480 of containment cap 400) are transported to the offshore deployment location. In general, the transition spool and containment cap components may be transported by air to a suitable onshore staging site, and then transported offshore by a boat or surface vessel. Air transport of the transition spool and/or any one or more of the components of the containment cap may be particularly desirable for transition spools and/or components stored or housed at a geographic locale that is distant the offshore deployment location since long range air transport is typically much faster than long range sea or land transport. - Once the transition spool (if necessary) and the assemblies of the
containment cap cap block 520. Next, inblock 525, wellbore 101 is contained and shut-in withcontainment cap wellbore 101 under control,flowback assembly 290 and/orconduit 235 may be used to producewellbore 101 according to block 530. - Previously described was an embodiment in which a
particular transition spool 330 was employed in order to couplecontainment cap 200 toriser adapter 145 of a particular flex joint 143. However, manufacturers have developed numerous types of riser flex joints, lower marine riser packages, BOPs, and wellheads. In particular, there are a number of potentially different connector profiles across riser flex joints, lower marine riser packages, BOPs, and wellheads. As previously described, in some cases, the landing site on the riser adapter, LMRP, BOP, or wellhead may have a connector or hub with a profile designed to directly mate and engage withreceptacle 150 b disposed atlower end 222 b. However, in other cases, the landing site may have a connector or hub with a profile that is not compatible withreceptacle 150 b atlower end 222 b. In such embodiments, a transition spool is employed to transition between the connector profile at the landing site andreceptacle 150 b atlower end 222 b. Consequently, a variety of differently configured transition spools are required to transition betweenreceptacle 150 b atend 222 b to the numerous connector profiles at the landing site. This may be best explained with reference toFIG. 33 . As shown, lowermarine riser package 140 is releasably coupled toBOP 120 which, in turn, is releasably coupled towellhead 130, as previously explained. In this example, five different riser flex joints 143A-143E have identically-configured lower connectors that are suitably-configured for connecting to the upper connection of LMRP 140 (i.e., mandrel 151), but each has a differently-configured, upwardly-extendingriser adapter 145A-145E, respectively, that, in the normal course of drilling and production, couples to a riser (not shown inFIG. 33 ). In the situation where it is desirable to couple acontainment cap riser adapters 145A-145E, a differently-configured transition spool is required in each instance. - More particularly,
FIG. 33 shows five differently-configuredriser adapters 145A-145E, each suitable for connection to a differently-configured transition spool, shown as 330A-330E. It should be understood that the schematic representations of the riser adapter profiles 145A-145E do not represent actual shapes or actual profiles of riser adapters, but are used herein merely to illustrate thatriser adapter 145A has a different configuration thanriser adapter 145B, which has a different configuration than riser adapter 145C, and so on. Having such differently-configured connector profiles requires that transition spools 330A-330E have downwardly-extending connectors and associated connector profiles that are different from one another so as to be configured to releasably connect to thecorresponding riser adapter 145A-145E. Although the lower end of eachtransition spool 330A-330E is different to accommodate a differently configuredriser adapters 145A-145E, the upper end of eachtransition spool 330A-330E is configured the same for engagement, in each instance, with a containment cap of a uniform design. In this instance, eachtransition spool 330A-330E includes a wellhead-type connection hub 150 a at its upper end configured to mate and engage the complementaryfemale receptacle 150 b at thelower end 222 b ofcap type connection 150. - Referring now to
FIGS. 34 and 35 , an embodiment of a containment cap adapter ortransition spool 600 is shown. In general,transition spool 600 functions to transition between the connector and associated connector profile at the lower end of the containment cap (e.g.,female receptacle 150 b atend 222 b) to the connection and associated connector profile at the landing site (e.g.,riser adapter 145,LMRP mandrel 151,hub 150 a ofBOP 120, orhub 150 a of wellhead 130). In this embodiment,transition spool 600 includes an upper portion orspool 610 and a lower portion orspool 620 coupled toupper spool 610.Upper spool 610 has acentral axis 615, a first orupper end 610 a, and a second orlower end 610 b. In addition,upper portion 610 includes aconnector 611 atupper end 610 a, anannular flange 613 atlower end 610 b, and atubular body 612 extending axially fromconnector 611 toflange 613. A throughbore 614 extends axially throughspool 610 fromupper end 610 a tolower end 610 b.Flange 613 includes an annularplanar facing surface 616 having anannular groove 617 and a plurality of circumferentially-spacedholes 618 extend axially therethrough.Connector 611 atupper end 610 a is configured to mate and sealingly engage with the containment cap. Thus, for connection tocontainment cap connector 611 is ahub 150 a configured to mate and sealingly engagecomplementary receptacle 150 b atlower end 222 b ofcontainment cap -
Lower spool 620 has acentral axis 625, a first orupper end 620 a, and a second orlower end 620 b. In addition,lower portion 620 includes anannular flange 621 atupper end 620 a, aconnector 624 atlower end 620 b, afrustoconical body 622 extending axially fromflange 621, and atubular body 623 extending frombody 622 toconnector 624. A throughbore 626 extends axially throughspool 620 fromupper end 620 a tolower end 620 b.Flange 621 is configured the same asflange 613 previously described. In particular,flange 621 includes an annularplanar facing surface 627 having an annular groove (not shown) and a plurality of circumferentially-spacedholes 629 extend axially therethrough.Connector 624 atlower end 620 b is configured to mate and sealingly engage with a complementary connector on the landing site (e.g.,riser adapter 145,LMRP mandrel 151,BOP 120, wellhead 130). Due to the number of possible connectors across the various landing sites,connector 624 may comprise any one of a number of possible connectors described in more detail below. For connection to a flange at the landing site,connector 624 may comprise a mating flange including alignment pins to facilitate the alignment of the mating flanges. - To connect
upper spool 610 tolower spool 620, anannular seal 630 formed of inconel or other suitable material is positioned in the annular grooves in facingsurfaces flanges holes studs 631 andhex nuts 632 fasten together upper andlower spools - Referring now to
FIGS. 36A-36N , different embodiments ofadapters 600A-600N are shown. Eachadapter 600A-600N includes anupper portion 610 as previously described and alower portion 620A-620N, respectively. Thus, the sameupper portion 610 is used in eachadapter 600A-600N,upper portion 610 includingconnector 611 configured to mate and sealingly engage the complementary connector on the containment cap (e.g.,receptacle 150 b atlower end 222 b ofcontainment cap 200, 400). In these embodiments,connector 611 is a male H4 connector, as available from Cameron International Corp., having a connector profile configured to mate and sealingly engage with complementaryfemale receptacle 150 b atlower end 222 b ofcontainment cap Flange 613 is an 18¾ in. API flange. Eachlower portion 620A-620L is the same aslower spool 620 previously described with the exception that theconnector 624A-624L, respectively, at eachlower end 620 b is different to accommodate adifferent mating connector 650A-650L, respectively, at thelanding site 651A-651L, respectively.Lower portion connector 624M, 624N, respectively, that is directly connected to flange 613 ofupper portion 610 with bolts. In other words,connectors 624M, 624N do not include afrustoconical body 622 ortubular body 623 as previously described.Connector 624M, 624N is different to accommodate adifferent mating connector 650M, 650N, respectively, at thelanding site connectors 650A-650L andcorresponding landing sites 651A-651L described in more detail below are employed on riser adapters (e.g., riser adapter 145), whereasconnectors 650M, 650N andcorresponding landing sites Flange 621 of eachlower spool 620A-620L is configured to mate and engageflange 613, and the upper end of eachconnector 624M, 624N is configured to mate and engageflange 613. Accordingly, sinceflange 613 is an 18¾ in. API flange,flange 621 of eachlower spool 620A-620L is a mating 18 3/4 in. API flange, and the upper end of eachconnector 624M, 624N is configured to mate with an 18¾ in. API flange. - In
FIG. 36A ,connector 624A oflower portion 620A is a female CLIP™ connector, as available from Aker-Kvaerner, having a connector profile configured to mate and sealingly engage withcomplementary connector 650A, which is a male CLIP™ connector, as available from Aker-Kvaerner. InFIG. 36B ,connector 624B oflower portion 620B is a female Load King™ connector, as available from Cameron International Corp., having a connector profile configured to mate and sealingly engage withcomplementary connector 650B, which is a male Load King™ connector, as available from Cameron International Corp. InFIG. 36C , connector 624C oflower portion 620C is a male HMF-F connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage with complementary connector 650C, which is a female HMF-F connector, as available from Vetco Gray, Inc. InFIG. 36D ,connector 624D oflower portion 620D is a male MR-6H connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage withcomplementary connector 650D, which is a female MR-6H connector, as available from Vetco Gray, Inc. InFIG. 36E ,connector 624E oflower portion 620E is a female MR-6C connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage withcomplementary connector 650E, which is a male MR-6C connector, as available from Vetco Gray, Inc. InFIG. 36F ,connector 624F oflower portion 620F is a female MR-6D connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage withcomplementary connector 650F, which is a male MR-6D connector, as available from Vetco Gray, Inc. InFIG. 36G ,connector 624G oflower portion 620G is a male HMF-G connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage withcomplementary connector 650G, which is a female HMF-G connector, as available from Vetco Gray, Inc. InFIG. 36H ,connector 624H oflower portion 620H is a male HMF-D connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage withcomplementary connector 650H, which is a female HMF-D connector, as available from Vetco Gray, Inc. InFIG. 36I , connector 624I of lower portion 620I is a male HMF-E connector, as available from Vetco Gray, Inc., having a connector profile configured to mate and sealingly engage with complementary connector 650I, which is a female HMF-E connector, as available from Vetco Gray, Inc. InFIG. 36J ,connector 624J oflower portion 620J is a female FT-GB connector, as available from National Oilwell Varco, Inc. of Houston, Tex., having a connector profile configured to mate and sealingly engage withcomplementary connector 650J, which is a male FT-GB connector, as available from National Oilwell Varco, Inc. of Houston, Tex. InFIG. 36K ,connector 624K oflower portion 620K is a male RD connector, as available from Cameron International Corp., having a connector profile configured to mate and sealingly engage withcomplementary connector 650K, which is a female RD connector, as available from Cameron International Corp. InFIG. 36L ,connector 624L oflower portion 620L is a female DT-2 connector, as available from Shafer, having a connector profile configured to mate and sealingly engage withcomplementary connector 650L, which is a male DT-2 connector, as available from Shafer. InFIG. 36M , connector 624M is a female SHD H4 connector, as available from Cameron International Corp., having a connector profile configured to mate and sealingly engage withcomplementary connector 650M, which is a male SHD H4 connector, as available from Cameron International Corp. InFIG. 36N ,connector 624N oflower portion 620N is a female HC connector, as available from Cameron International Corp., having a connector profile configured to mate and sealingly engage with complementary connector 650N, which is a male HC connector, as available from Cameron International Corp. - As will thus be understood, a single containment cap (e.g.,
cap 200, 400) can be employed so as to shut in and contain a well by placement of the cap at any one of four locations (on thewell head 130, on theBOP 120, on themandrel 151 ofLMRP 140, or on the riser adapter 145). This may be accomplished by maintaining an inventory of multiple transition spools 600, with such transition spools 600 having identicalupper portions 610 and differinglower portions 620 to accommodate different landing sites. As used herein, the term “inventory” when used as a noun means a collection of goods held in stock. Similarly, the word “inventory” when used as a verb and the phrase “maintaining an inventory” mean keeping the collection of goods on hand and ready for disposition. For a given well, the connector profiles of wellhead, the BOP, the mandrel of LMRP and of the riser adapter are all known such that the proper transition spool(s) 600 may be maintained at the surface vessel ordrilling rig 110, or at a more distant storage facility. For example, a storage facility can be used for housing and maintaining one of each type oftransition spool 600 that might be necessary for use with all the wells in a given region, such as the Gulf of Mexico. The inventory would include, in addition to the appropriate transition spools 600, at least onecontainment cap 200, 400 (preferably stored in its modular form). Should a well blowout occur, the modular components of the containment cap, as well as the transition spools necessary may be identified, selected from the inventory, and shipped expeditiously to the well site for use in capping the well. - Referring to
FIG. 37 , astorage facility 700 is schematically represented and houseslower assembly 210,upper assembly 250, and kill-flow backassembly 290, each as previously described, in a condition to be readily shipped and assembled intocontainment cap 200. Also maintained in inventory withinstorage facility 700 is at least one of each of a plurality of adapters 600 (e.g., one or more ofadapters 600A-600N) as might be needed to connectcontainment cap 200 to any well head, BOP, LMRP mandrel, or riser adapter in the geographic region for which thestorage facility 700 is dedicated to serve. For each well in that geographic region, it will be known the type and configuration of well head, BOP, LMRP, mandrel and riser adapter. In this example,adapters 600A-600F, 600M, and 600N comprise all the adapters necessary to attachcap 200 to each of the wellhead, BOP, LMRP mandrel, and riser adapter for each well in the region. However, it should be appreciated that any combination ofadapters 600A-600N (or other transition spools including different connectors) can be included infacility 700 depending on the structures of the wellheads, BOPs, LMRP mandrels, and riser adapters in the geographic region of interest. Should a subsea blowout occur, the information about the well and its structures (e.g., wellhead, BOP, LMRP mandrel, and riser adapter) is transmitted to service personnel maintaining the equipment in storage instorage facility 700. Alternatively, the service personnel may have information at hand and be able to “look up” information as to the type and configuration of all equipment at each well. Once that information is known, the appropriate adapter(s) 600 necessary (e.g., necessary to connect thecontainment cap 200 to a specific well component or components) is selected, and deployed for transportation to the well site along withcontainment cap assemblies assemblies adapters 600A-600F, 600M, and 600N) in inventory and ready for shipment may provide a faster and more efficient means for capping a subsea well and may lessen potential environmental impact and damage. Althoughstorage facility 700 shown inFIG. 37 includes the components of containment cap 200 (e.g.,lower assembly 210,upper assembly 250, and kill-flow back assembly 290), in other embodiments, the storage facility (e.g., facility 700) may alternatively include the components ofcontainment cap 400 previously described (e.g.,lower assembly 210, valve assembly 450, and cap 470). - Referring now to
FIG. 38 , anotherstorage facility 800 is schematically represented and houseslower assembly 210,upper assembly 250, and kill-flow back assembly 290 ofcontainment cap 200, each as previously described. Further, an inventory is maintained infacility 800 including at least one upper portion 610 (two being shown in this example) and eachlower portion 620A-620F, 620M, and 620N ofadapters 600A-600F, 600M, and 600N needed to service the wells in the designated region. Again, it is to be understood thatlower portions 620A-620F, 600M, and 600N ofadapter 600A-600F, 600M, and 600N, respectively, are merely examples of possible transition spool lower portions. In general, any combination oflower portions 620A-620N (or other lower portions including different connectors) can be included infacility 800 depending on the structures of the wellheads, BOPs, LMRP mandrels, and riser adapters in the geographic region of interest. Becauseupper portion 610 of eachadapter 600A-600F, 600M, and 600N is identical in these embodiments, it is not necessary to inventory anupper portion 610 for each of theadapter 600A-600F, 600M, and 600N. Instead, upon the need arising, the appropriatelower portion 620A-620F, 620M, 620N can be selected and attached to theupper portion 610 as previously described. Although some additional time is required to make this connection, it is one that is not overly time-consuming and can save the cost of manufacturing, maintaining and storing multipleupper portions 610 for eachadapter 600A-600F, 600M, and 600N. Althoughstorage facility 800 shown inFIG. 38 includes the components of containment cap 200 (e.g.,lower assembly 210,upper assembly 250, and kill-flow back assembly 290), in other embodiments, the storage facility (e.g., facility 800) may alternatively include the components ofcontainment cap 400 previously described (e.g.,lower assembly 210, valve assembly 450, and cap 470). - While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
Claims (40)
1. A modular containment cap for containing a subsea wellbore discharging hydrocarbons into the surrounding sea, comprising:
a lower assembly including a spool body having an upper end, a lower end opposite the upper end, and a first throughbore extending from the upper end to the lower end;
an upper assembly including a spool piece having an upper end, a lower end opposite the upper end, a throughbore extending from the upper end to the lower end, and a first spool piece valve disposed in the throughbore, wherein the first spool piece valve is configured to control the flow of fluids through the throughbore of the spool piece;
wherein the upper end of the spool body is releasably connected to the lower end of the spool piece, and wherein the first throughbore of the spool body is coaxially aligned with and in fluid communication with the throughbore of the spool piece.
2. The containment cap of claim 1 , wherein the spool body of the lower assembly further comprises:
a second throughbore extending from the first throughbore;
a first spool body valve disposed in the second throughbore; and
wherein the first spool body valve in the second throughbore is configured to control the flow of fluids through the second throughbore of the spool body.
3. The containment cap of claim 1 , wherein the upper assembly further comprising a second spool piece valve disposed in the throughbore of the spool piece of the upper assembly, wherein the second spool piece valve is configured to control the flow of fluids through the throughbore of the spool piece of the upper assembly;
wherein the spool body of the lower assembly further comprises a second spool body valve disposed in the second throughbore, wherein the second spool body valve in the second throughbore is configured to control the flow of fluids through the second throughbore of the spool body.
4. The containment cap of claim 2 , wherein the second throughbore has a first end intersecting the first throughbore and a second end distal the first throughbore, wherein the second end of the second throughbore is coupled to a choke valve.
5. The containment cap of claim 4 , wherein the lower assembly further comprises a fluid conduit extending from the choke valve, wherein the fluid conduit has a first end coupled to the choke valve and a second end distal the choke valve, and wherein the second end of the fluid conduit comprises an upward-facing hub configured to releasably engage a mating downward-facing receptacle.
6. The containment cap of claim 2 , wherein the first throughbore of the spool body is configured to provide full bore access to the wellbore.
7. The containment cap of claim 2 , further comprising:
a kill-flowback assembly including a spool piece having an upper end, a lower end opposite the upper end, and a throughbore extending from the upper end to the lower end;
wherein the upper end of the spool piece of the upper assembly is releasably connected to the lower end of the spool piece of the kill-flowback assembly, and wherein the throughbore of the spool piece of the upper assembly is coaxially aligned with and in fluid communication with the throughbore of the spool piece of the kill-flowback assembly.
8. The containment cap of claim 7 , wherein the kill-flowback assembly includes a fluid conduit coupled to the upper end of the spool piece of the kill-flowback assembly, wherein the fluid conduit is configured to produce the wellbore or supply kill fluids to the wellbore.
9. The containment cap of claim 7 , wherein the lower assembly, the upper assembly, and the kill-flowback assembly are each configured to be air freightable.
10. The containment cap of claim 9 , wherein the lower assembly has a first weight, the upper assembly has a second weight, and the kill-flowback assembly has a third weight;
wherein the first weight, the second weight, and the third weight are each less than 120 tons.
11. The containment cap of claim 10 , wherein the sum of any two of the first weight, the second weight, and the third weight is less than 120 tons.
12. The containment cap of claim 10 , wherein the lower assembly, the upper assembly, and the kill-flowback assembly each has a maximum height, a maximum width, and a maximum length; and
wherein at least one of the maximum height, the maximum width, and the maximum length of each of the lower assembly, the upper assembly, and the kill-flowback assembly is less than 21 ft. and at least a different one of the maximum height, the maximum width, and the maximum length of each of the lower assembly, the upper assembly, and the kill-flowback assembly is less than 14 ft.
13. The containment cap of claim 7 , wherein the lower assembly comprises a frame coupled to the spool body, the upper assembly comprises a frame coupled to the spool piece of the upper assembly, and the kill-flowback assembly comprises a frame coupled to the spool piece of the kill-flowback assembly; and
wherein the frame of the lower assembly is configured to support the spool body, the frame of the upper assembly is configured to support the spool piece of the upper assembly, and the frame of the kill-flowback assembly is configured to support the spool piece of the kill-flowback assembly.
14. The containment cap of claim 2 , wherein the lower end of the spool body comprises a downward-facing receptacle configured to engage an upward-facing hub to form a wellhead-type connection;
wherein the upper end of the spool body comprises an upward-facing hub that releasably engages a mating downward-facing receptacle at the lower end of the spool piece to form a wellhead-type connection between the spool body and the spool piece; and
wherein the upper end of the spool piece comprises an upward-facing hub configured to engage a downward-facing receptacle to form a wellhead-type connection.
15. A method for containing and/or producing a subsea wellbore discharging hydrocarbons into the surrounding sea, wherein a wellhead is disposed at the sea floor at the upper end of the wellbore, a subsea BOP is mounted to the wellhead, an LMRP is mounted to the BOP, and a riser extends from the LMRP, the method comprising:
(a) selecting a subsea landing site from one of the BOP, the LMRP, or the wellhead;
(b) preparing the landing site for connection to a modular containment cap, wherein the containment cap comprises a lower assembly including a spool body and an upper assembly including a spool piece;
(c) transporting the lower assembly and the upper assembly to an offshore location;
(d) lowering the lower assembly subsea and releasably connecting the lower assembly to the landing site;
(e) lowering the upper assembly subsea and releasably connecting the upper assembly to the lower assembly;
(f) shutting in the wellbore with the containment cap after (d) and (e).
16. The method of claim 15 , wherein the spool body of the lower assembly has an upper end, a lower end opposite the upper end, a first throughbore extending from the upper end to the lower end, a second throughbore extending from the first throughbore, a first spool body valve disposed in the second throughbore, and a second spool body valve disposed in the second throughbore;
wherein the spool piece of the upper assembly has an upper end, a lower end opposite the upper end, a throughbore extending from the upper end to the lower end, a first spool piece valve disposed in the throughbore, and a second spool piece valve disposed in the throughbore;
wherein the upper end of the spool body is releasably connected to the lower end of the spool piece, and wherein the first throughbore of the spool body is in fluid communication with the throughbore of the spool piece.
17. The method of claim 16 , further comprising:
opening the first spool body valve and the second spool body valve before (d); and
opening the first spool piece valve and the second spool piece valve before (e).
18. The method of claim 17 , wherein (f) comprises:
(f1) closing the first spool piece valve;
(f2) closing the first spool body valve after (f1).
19. The method of claim 18 , wherein (f) further comprises:
closing the second spool piece valve after (f1); and closing the second spool body valve after (f2).
20. The method of claim 18 , further comprising:
flowing at least a portion of the hydrocarbon fluids through the first throughbore and the second throughbore before (f);
flowing at least a portion of the hydrocarbon fluids through the throughbore of the spool piece before (f);
restricting the flow of the hydrocarbon fluids through the throughbore of the spool piece after (f1);
flowing at least a portion of the hydrocarbon fluids through the second throughbore after (f1); and
restricting the flow of the hydrocarbon fluids through the first throughbore and the second throughbore after (f2).
21. The method of claim 15 , wherein the LMRP has an upper end including a riser flex joint connected to the riser, and wherein the subsea landing site is a riser adapter of the flex joint; and
wherein (b) comprises removing the riser from the riser flex joint before (d).
22. The method of claim 21 , further comprising:
lowering a transition spool subsea and connecting it to the riser flex joint; and
wherein (d) comprises lowering the lower assembly subsea and releasably connecting the lower assembly to the transition spool.
23. The method of claim 22 , wherein the transition spool has a longitudinal axis, an upper end, a lower end comprising a mule shoe, and an annular flange axially disposed between the upper end and the mule shoe.
24. The method of claim 15 , wherein the subsea landing site is an upward-facing hub at an upper end of the BOP or an upper end of the wellhead;
wherein (d) comprises releasably connecting a downward-facing receptacle at a lower end of the lower assembly with the upward-facing hub.
25. The method of claim 16 , further comprising:
lowering a kill-flowback assembly subsea and releasably connecting the kill-flowback assembly to the upper assembly after (e).
26. The method of claim 25 , wherein (f) further comprises:
Pumping kill weight fluids through the kill-flowback assembly, the upper assembly, and the lower assembly into the wellbore.
27. The method of claim 25 , further comprising:
(g) producing the hydrocarbons through the kill-flowback assembly.
28. The method of claim 15 , wherein (c) comprises:
(c1) transporting the lower assembly and the upper assembly by air from a first land location to a second land location.
29. The method of claim 27 , wherein (c) further comprises:
(c2) transporting the lower assembly and the upper assembly from the second location to an onshore location; and
(c3) transporting the lower assembly and the upper assembly from the onshore location to the offshore location by surface vessel.
30. A containment cap for containing a subsea wellbore discharging hydrocarbons into the surrounding sea, comprising:
a lower assembly including a spool body having an upper end, a lower end opposite the upper end, and a first throughbore extending from the upper end to the lower end;
a valve assembly slidingly disposed in the first throughbore, wherein the valve assembly comprises a tubular body and a first spool body valve, wherein the tubular body has an upper end extending from the first throughbore, a lower end disposed within the first throughbore, and a throughbore extending between the upper end and the lower end of the tubular body;
wherein the first spool body valve is disposed along the throughbore of the tubular body and is configured to control the flow of fluids through the throughbore of the tubular body;
a plurality of annular seal assemblies radially positioned between the spool body and the tubular body, wherein each seal assembly is configured to restrict the flow of fluids between the tubular body and the spool body.
31. The containment cap of claim 30 , wherein the spool body of the lower assembly further comprises:
a second throughbore extending from the first throughbore;
a first valve disposed in the second throughbore; and
wherein the first valve in the second throughbore is configured to control the flow of fluids through the second throughbore of the spool body.
32. The containment cap of claim 31 , wherein the valve assembly further comprises a second spool body valve disposed along the throughbore of the tubular body and configured to control the flow of fluids through the throughbore of the tubular body;
wherein the spool body of the lower assembly further comprises a second valve disposed in the second throughbore;
wherein the second valve in the second throughbore is configured to control the flow of fluids through the second throughbore of the spool body.
33. The containment cap of claim 31 , further comprising an annular insert disposed in the first throughbore and axially positioned between the tubular body and an annular shoulder in the first throughbore, wherein the lower end of the tubular body is seated in a cylindrical recess in the insert.
34. The containment cap of claim 30 , further comprising a cap disposed about the upper end of the tubular body, wherein the cap has an upper end comprising an upward-facing hub, a lower end comprising a downward-facing hub, and a flow passage extending from the lower end to the upper end;
wherein the flow passage is in fluid communication with the throughbore of the tubular body.
35. The containment cap of claim 34 , further comprising an annular coupling member disposed about the lower end of the cap and the upper end of the spool body, wherein the coupling member has an upper end comprising an upward-facing receptacle and a lower end comprising a downward-facing receptacle;
wherein the downward-facing hub at the lower end of the cap releasably engages the receptacle at the upper end of the coupling member, and an upward-facing hub at the upper end of the spool body releasably engages the receptacle at the lower end of the coupling member.
36. The containment cap of claim 31 , wherein the second throughbore has a first end intersection the first throughbore and a second end distal the first throughbore, wherein the second end of the second throughbore is coupled to a choke valve.
37. The containment cap of claim 36 , wherein the lower assembly further comprises a fluid conduit extending from the choke valve, wherein the fluid conduit has a first end coupled to the choke valve and a second end distal the choke valve, and wherein the second end of the fluid conduit comprises an upward-facing hub configured to releasably engage a mating downward-facing receptacle.
38. The containment cap of 31, wherein the first throughbore of the spool body is configured to provide full bore access to the wellbore.
39. The containment cap of claim 35 , wherein the lower assembly, the valve assembly, the cap, and the coupling member are each configured to be air freightable.
40. The containment cap of claim 39 , wherein the lower assembly has a first weight and the valve assembly has a second weight;
wherein the sum of the first weight and the second weight is less than 120 tons.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/468,872 US20120318522A1 (en) | 2011-06-17 | 2012-05-10 | Air-freightable containment cap for containing a subsea well |
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
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US201161498269P | 2011-06-17 | 2011-06-17 | |
US201161500679P | 2011-06-24 | 2011-06-24 | |
US13/468,872 US20120318522A1 (en) | 2011-06-17 | 2012-05-10 | Air-freightable containment cap for containing a subsea well |
Publications (1)
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US20120318522A1 true US20120318522A1 (en) | 2012-12-20 |
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US13/468,845 Abandoned US20120318521A1 (en) | 2011-06-17 | 2012-05-10 | Subsea containment cap adapters |
US13/468,872 Abandoned US20120318522A1 (en) | 2011-06-17 | 2012-05-10 | Air-freightable containment cap for containing a subsea well |
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US13/468,845 Abandoned US20120318521A1 (en) | 2011-06-17 | 2012-05-10 | Subsea containment cap adapters |
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US (2) | US20120318521A1 (en) |
EP (2) | EP2721250A2 (en) |
CN (2) | CN103582740A (en) |
AU (1) | AU2012273431A1 (en) |
BR (1) | BR112013031327A2 (en) |
CA (2) | CA2837692A1 (en) |
EA (2) | EA201370243A1 (en) |
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Also Published As
Publication number | Publication date |
---|---|
WO2012173716A3 (en) | 2013-05-16 |
EP2721249A1 (en) | 2014-04-23 |
EA201370243A1 (en) | 2014-05-30 |
EA201370242A1 (en) | 2014-06-30 |
MX2013014050A (en) | 2014-02-27 |
US20120318521A1 (en) | 2012-12-20 |
AU2012273431A1 (en) | 2013-11-07 |
BR112013031327A2 (en) | 2017-03-21 |
CN103582740A (en) | 2014-02-12 |
CN103597168A (en) | 2014-02-19 |
EP2721250A2 (en) | 2014-04-23 |
MX2013014052A (en) | 2014-02-27 |
CA2837692A1 (en) | 2012-12-20 |
CA2835132A1 (en) | 2012-12-27 |
WO2012177329A1 (en) | 2012-12-27 |
WO2012173716A2 (en) | 2012-12-20 |
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