U.S. patent application number 13/468872 was filed with the patent office on 2012-12-20 for air-freightable containment cap for containing a subsea well.
This patent application is currently assigned to BP Corporation North America Inc.. Invention is credited to Robert Winfield Franklin, Richard Harland, Stuart Douglas Rettie, Roy Bryant Shilling, III.
Application Number | 20120318522 13/468872 |
Document ID | / |
Family ID | 47352765 |
Filed Date | 2012-12-20 |
United States Patent
Application |
20120318522 |
Kind Code |
A1 |
Franklin; Robert Winfield ;
et al. |
December 20, 2012 |
AIR-FREIGHTABLE CONTAINMENT CAP FOR CONTAINING A SUBSEA WELL
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.
Inventors: |
Franklin; Robert Winfield;
(Katy, TX) ; Harland; Richard; (Houston, TX)
; Rettie; Stuart Douglas; (Houston, TX) ;
Shilling, III; Roy Bryant; (Houston, TX) |
Assignee: |
BP Corporation North America
Inc.
Houston
TX
|
Family ID: |
47352765 |
Appl. No.: |
13/468872 |
Filed: |
May 10, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61498269 |
Jun 17, 2011 |
|
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|
61500679 |
Jun 24, 2011 |
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Current U.S.
Class: |
166/363 ;
166/368 |
Current CPC
Class: |
E21B 43/0122
20130101 |
Class at
Publication: |
166/363 ;
166/368 |
International
Class: |
E21B 33/035 20060101
E21B033/035 |
Claims
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.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] 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.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 1. Field of the Invention
[0004] 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.
[0005] 2. Background of the Technology
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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.
BRIEF SUMMARY OF THE DISCLOSURE
[0011] 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.
[0012] 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).
[0013] 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.
[0014] Embodiments described herein comprise a combination of
features and advantages intended to address various shortcomings
associated with certain prior devices, systems, and methods. The
various characteristics described above, as well as other features,
will be readily apparent to those skilled in the art upon reading
the following detailed description, and by referring to the
accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For a detailed description of the preferred embodiments of
the invention, reference will now be made to the accompanying
drawings in which:
[0016] FIG. 1 is a schematic view of an embodiment of an offshore
drilling system;
[0017] FIG. 2 is an enlarged view of the riser flex joint of the
lower marine riser package of FIG. 1;
[0018] FIG. 3 is a top view of the flange of the riser adapter of
FIG. 2;
[0019] FIG. 4 is a schematic view of the offshore drilling system
of FIG. 1 damaged by a subsea blowout;
[0020] FIG. 5 is a perspective view of an embodiment of a modular,
air-freightable containment cap for containing the wellbore of FIG.
4;
[0021] FIG. 6 is a cross-sectional side view of the containment cap
of FIG. 5;
[0022] FIG. 7 is a perspective view of the lower assembly of FIG.
5;
[0023] FIG. 8 is a side view of the lower assembly of FIG. 5;
[0024] FIG. 9 is a top view of the lower assembly of FIG. 5;
[0025] FIG. 10 is a schematic view of the lower assembly of FIG.
5;
[0026] FIG. 11 is a perspective view of the upper assembly of FIG.
5;
[0027] FIG. 12 is a side view of the upper assembly of FIG. 5;
[0028] FIG. 13 is a cross-sectional side view of the upper assembly
of FIG. 5;
[0029] FIG. 14 is a schematic view of the upper assembly of FIG.
5;
[0030] FIG. 15 is a perspective view of the kill-flowback assembly
of FIG. 5;
[0031] FIG. 16 is a side view of the kill-flowback assembly of FIG.
5;
[0032] FIG. 17 is a perspective view of the lower assembly of FIG.
5 configured for subsea deployment;
[0033] FIG. 18 is an assembly view illustrating the lower assembly
of FIG. 5, the running tool of FIG. 17, and a pair of adapters for
deploying the lower assembly subsea;
[0034] FIG. 19 is a perspective view of the upper assembly of FIG.
5 configured for subsea deployment;
[0035] FIGS. 20A-20L are sequential schematic views of the subsea
deployment and installation of the containment cap of FIG. 5
directly onto the BOP of FIG. 4;
[0036] FIG. 21 is a schematic view of the containment cap of FIG. 5
directly connected to the wellhead of FIG. 4;
[0037] FIG. 22 is a side view of an embodiment of a transition
spool for coupling the containment cap of FIG. 5 to the flex joint
of FIG. 4;
[0038] FIG. 23 is a perspective view of an embodiment of a system
for adjusting the angular orientation of the riser adapter of FIG.
2;
[0039] FIG. 24 is a top view of the system of FIG. 23;
[0040] FIG. 25 is a perspective view of the base members of FIG. 23
mounted to the flex joint base of FIG. 2;
[0041] FIG. 26 is a perspective view of an embodiment of a system
for adjusting the angular orientation of the riser adapter of FIG.
2;
[0042] FIG. 27 is a perspective view of the hydraulic cylinder
assembly of FIG. 26;
[0043] FIG. 28 is a perspective view of an embodiment of a set of
wedge members for locking the angular orientation of the riser
adapter of FIG. 2;
[0044] FIG. 29 is a top view of the set of wedge members of FIG.
28;
[0045] FIGS. 30A-30P are sequential schematic views of the subsea
deployment and installation of the containment cap of FIG. 5 onto
the flex joint of Figure of FIG. 4;
[0046] FIG. 31 is a side cross-sectional view of an embodiment of a
modular, air-freightable containment cap for containing the
wellbore of FIG. 4;
[0047] FIG. 32 is a schematic view of an embodiment of a method for
deploying the containment cap of FIG. 5;
[0048] FIG. 33 is a schematic view illustrating various transition
spools used to couple the containment cap of FIG. 5 or FIG. 31 to a
plurality of riser flex joints having differing connector
profiles;
[0049] FIG. 34 is a front view of an embodiment of a transition
spool in accordance with the principles described herein;
[0050] FIG. 35 is a perspective, exploded view of the transition
spool of FIG. 34;
[0051] 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;
[0052] 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
[0053] 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.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0054] 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.
[0055] 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.
[0056] 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.
[0057] Referring now to FIG. 1, an embodiment of an offshore system
100 for drilling and/or producing a wellbore 101 is shown. In this
embodiment, system 100 includes an offshore platform 110 at the sea
surface 102, a subsea blowout preventer (BOP) 120 mounted to a
wellhead 130 at the sea floor 103, and a lower marine riser package
(LMRP) 140 mounted to BOP 120. Platform 110 is equipped with a
derrick 111 that supports a hoist (not shown). A drilling riser 115
extends subsea from platform 110 to LMRP 140. In general, riser 115
is a large-diameter pipe that connects LMRP 140 to the floating
platform 110. During drilling operations, riser 115 takes mud
returns to platform 110. Casing 131 extends from wellhead 130 into
subterranean wellbore 101.
[0058] Downhole operations are carried out by a tubular string 116
(e.g., drillstring, production tubing string, coiled tubing, etc.)
that is supported by derrick 111 and extends from platform 110
through riser 115, LMRP 140, BOP 120, and into cased wellbore 101.
A downhole tool 117 is connected to the lower end of tubular string
116. In general, downhole tool 117 may comprise any suitable
downhole tool(s) for drilling, completing, evaluating and/or
producing wellbore 101 including, without limitation, drill bits,
packers, testing equipment, perforating guns, and the like. During
downhole operations, string 116, and hence tool 117 coupled
thereto, may move axially, radially, and/or rotationally relative
to riser 115, LMRP 140, BOP 120, and casing 131.
[0059] BOP 120 and LMRP 140 are configured to controllably seal
wellbore 101 and contain hydrocarbon fluids therein. Specifically,
BOP 120 has a central or longitudinal axis 125 and includes a body
123 with an upper end 123a releasably secured to LMRP 140, a lower
end 123b releasably secured to wellhead 130, and a main bore 124
extending axially between upper and lower ends 123a, b. Main bore
124 is coaxially aligned with wellbore 101, thereby allowing fluid
communication between wellbore 101 and main bore 124. In this
embodiment, BOP 120 is releasably coupled to LMRP 140 and wellhead
130 with hydraulically actuated, mechanical wellhead-type
connections 150. In general, connections 150 may comprise any
suitable releasable wellhead-type mechanical connection such as the
H-4.RTM. 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 150a herein, that is received by and
releasably engages a complementary, downward-facing mating female
connector or receptacle, labeled with reference numeral 150b
herein. In addition, BOP 120 includes a plurality of axially
stacked sets of opposed rams--one set of opposed blind shear rams
or blades 127 for severing tubular string 116 and sealing off
wellbore 101 from riser 115 and two sets of opposed pipe rams 128,
129 for engaging string 116 and sealing the annulus around tubular
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 of
rams 127, 128, 129 is equipped with sealing members that engage to
prohibit flow through the annulus around string 116 and/or main
bore 124 when rams 127, 128, 129 is closed.
[0060] Opposed rams 127, 128, 129 are disposed in cavities that
intersect main bore 124 and support rams 127, 128, 129 as they move
into and out of main bore 124. Each set of rams 127, 128, 129 is
actuated and transitioned between an open position and a closed
position. In the open positions, rams 127, 128, 129 are radially
withdrawn from main bore 124 and do not interfere with tubular
string 116 or other hardware that may extend through main bore 124.
However, in the closed positions, rams 127, 128, 129 are radially
advanced into main bore 124 to close off and seal main bore 124
(e.g., rams 127) or the annulus around tubular string 116 (e.g.,
rams 128, 129). Each set of rams 127, 128, 129 is actuated and
transitioned between the open and closed positions by a pair of
actuators 126. In particular, each actuator 126 hydraulically moves
a piston within a cylinder to move a drive rod coupled to one ram
127, 128, 129.
[0061] Referring still to FIG. 1, LMRP 140 has a body 141 with an
upper end 141a connected to the lower end of riser 115, a lower end
141b releasably secured to upper end 123a with connector 150, and a
throughbore 142 extending between upper and lower ends 141a, b.
Throughbore 142 is coaxially aligned with main bore 124 of BOP 110,
thereby allowing fluid communication between throughbore 142 and
main bore 124. LMRP 140 also includes an annular blowout preventer
142a comprising an annular elastomeric sealing element that is
mechanically squeezed radially inward to seal on a tubular
extending through bore 142 (e.g., string 116, casing, drillpipe,
drill collar, etc.) or seal off bore 142. Thus, annular BOP 142a
has the ability to seal on a variety of pipe sizes and seal off
bore 142 when no tubular is extending therethrough.
[0062] Referring now to FIGS. 1 and 2, in this embodiment, upper
end 141a of LMRP 140 comprises a riser flex joint 143 that allows
riser 115 to deflect angularly relative to BOP 120 and LMRP 140
while hydrocarbon fluids flow from wellbore 101, BOP 120 and LMRP
140 into riser 115. In this embodiment, flex joint 143 includes a
cylindrical base 144 rigidly secured to a mating hub or mandrel 151
extending from the upper end of LMRP 140, and a riser extension or
adapter 145 extending upward from base 144. A fluid flow passage
146 extending through base 144 and adapter 145 defines the upper
portion of throughbore 142. A flex element (not shown) disposed
within base 144 extends between base 144 and riser adapter 145, and
sealingly engages both base 144 and riser adapter 145. The flex
element allows riser adapter 145 to pivot and angularly deflect
relative to base 144, LMRP 140, and BOP 120. The upper end of
adapter 145 distal base 144 comprises an annular flange 145a for
coupling riser adapter 145 to a mating annular flange 118 at the
lower end of riser 115 or to alternative devices. As best shown in
FIG. 3, flange 145a includes a plurality of
circumferentially-spaced holes 147 that receive bolts for securing
flange 145a to a mating annular flange 118 at the lower end of
riser 115. In addition, flange 145a includes a pair of
circumferentially spaced guide holes 148, each guide hole 148
having a diameter greater than the diameter of holes 147. In this
embodiment, flex joint 143 also includes a mud boost line 149
having an inlet (not shown) in fluid communication with flow
passages 142, 146, an outlet 149b in flange 145a, and a valve 149c
configured to control the flow of fluids through line 149. Although
LMRP 140 has been shown and described as including a particular
flex joint 143, in general, any suitable riser flex joint may be
employed in LMRP 140.
[0063] As previously described, in this embodiment, BOP 120
includes three sets of rams (one set of shear rams 127 and two sets
of pipe rams 128, 129), however, in other embodiments, the BOP
(e.g., BOP 120) may include a different number of rams (e.g., four
sets of rams), different types of rams (e.g., two sets of shear
rams and two sets of pipe rams, one or more sets of opposed blind
rams), an annular BOP (e.g., annular BOP 142a), or combinations
thereof. It should be appreciated that BOP 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, although LMRP 140 is shown and
described as including one annular BOP 142a, in other embodiments,
the LMRP (e.g., LMRP 140) may include a different number of annular
BOPs (e.g., two sets of annular BOPs), different types of rams
(e.g., shear rams), or combinations thereof.
[0064] Referring now to FIG. 4, during a "kick" or surge of
formation fluid pressure in wellbore 101, one or more rams 127,
128, 129 of BOP 120 and/or annular BOP 142a of LMRP 140 are
normally actuated to seal in wellbore 101. In the event wellbore
101 is not sealed, it may potentially result in the discharge of
such hydrocarbon fluids subsea. In FIG. 4, system 100 is shown
after a subsea blowout. In the exemplary blowout scenario shown in
FIG. 4, riser 115 has been severed and bent over proximal flex
joint 143. As a result, hydrocarbon fluids flowing upward in
wellbore 101 pass through BOP 120 and LMRP 140, and are discharged
into the surrounding sea water proximal the sea floor 103 through
punctures and breaks in riser 115. The emitted hydrocarbon fluids
form a subsea hydrocarbon plume 160 that extends to the sea surface
102. Embodiments of containment caps and methods for deploying same
described in more detail below are designed to contain and shut-in
wellbore 101, and control the subsea emission of hydrocarbon fluids
to reduce and/or eliminate the subsea discharge of hydrocarbon
fluids.
[0065] Referring now to FIGS. 5 and 6, an embodiment of a
containment stack or cap 200 for capping wellbore 101 previously
described (FIG. 4), and containing the hydrocarbon fluids therein
is shown. In this embodiment, containment cap 200 is modular,
meaning cap 200 comprises distinct and separate sections or
assemblies that are deployed subsea independently and then coupled
together subsea to form cap 200. Specifically, containment cap 200
comprises three assemblies--a first or lower assembly 210, a second
or upper assembly 250 releasably coupled to lower assembly 210 with
a wellhead-type connection 150, and a kill-flowback assembly 290
releasably coupled to upper assembly 250 with a wellhead-type
connection 150. As will be described in more detail below,
assemblies 210, 250 function together to contain and shut-in
wellbore 101, whereas assembly 290 functions to deliver kill weight
fluids to wellbore 101 and/or produce wellbore 101 once it is
contained and controlled.
[0066] In this embodiment, each assembly 210, 250, 290 is sized and
configured to be air-freightable on its own or in conjunction with
another assembly 210, 250, 290. In other words, each assembly 210,
250, 290 has a weight and dimensions suitable for air transport.
Conventional cargo aircraft such as the Antonov AN124 and Boeing
747 have a maximum payload capacity of about 120 tons
(240.times.103 lbs.), and cargo bays sized to accommodate cargo
having a maximum width of up to about 21 ft. and a maximum height
of up to about 14 ft. In embodiments described herein, lower
assembly 210 has a weight of about 70 tons (140.times.103 lbs.),
upper assembly 250 has a weight of about 40 tons (80.times.103
lbs.), and kill-flowback assembly 290 has a weight of about 7.5
tons (15.times.103 lbs.). In addition, each assembly 210, 250, 290
is sized such that it can be oriented to have a width less than 21
ft. and a height less than 14 ft. For example, although 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 three
assemblies 210, 250, 290 may be transported together by air in a
single cargo aircraft. The assembly 210, 250, 290 not transported
with another assembly 210, 250, 290 may be transported in a
separate cargo aircraft. As previously described, conventional
capping stacks are not sized and configured to be transported by
air because their weight exceeds the payload capacity of
conventional cargo aircraft and/or their dimensions cannot be
accommodated by conventional cargo aircraft cargo bays.
Consequently, transport of such conventional capping stacks must be
accomplished by land and/or sea vessel, which, depending on the
relative locations of the offshore blowout and the capping stack,
may be time consuming. For example, if there is a subsea blowout in
the Gulf of Mexico, and the most suitable capping stack for
containing that blowout is located in the Middle East, it may take
days or even weeks to transport the capping stack by land and sea
to the offshore location in the Gulf of Mexico. However,
embodiments of containment caps described herein (e.g., cap 200)
are air-freightable, and thus, may be transported around the globe
in a matter of hours or short number of days (e.g., one to two days
maximum). As a result, embodiments described herein offer the
potential to more efficiently and timely contain a subsea blowout,
thereby reducing the total volume of subsea hydrocarbon
emissions.
[0067] Referring now to FIGS. 5-10, lower assembly 210 includes a
frame 211 and a spool tree or body 221 disposed within frame 211.
Frame 211 supports spool body 221 and the other components of lower
assembly 210. In addition, frame 211 protects spool body 221 and
the other components of lower assembly 210 from impacts during
transport and deployment.
[0068] Spool body 221 includes a first pipe spool or spool piece
222 and a second pipe spool or spool piece 230 attached to and
extending perpendicularly from spool piece 222. Spool piece 222 has
a central or longitudinal axis 223, a first or upper end 222a, a
second or lower end 222b opposite end 222a, a vertical flow bore or
throughbore 224 extending axially between ends 222a, b, and a
horizontal flow bore 225 extending perpendicularly from bore 224.
Upper end 222a of first spool piece 222 defines the upper end of
spool body 221, and lower end 222b of first spool piece 222 defines
the lower end of spool body 221. Throughbore 224 is coaxially
disposed within spool piece 222. In other words, throughbore 224
has a central axis coincident with axis 223. Throughbore 224 has a
minimum inner diameter equal to or greater than the inner diameter
of wellbore 101, through bore 142, and main bore 124, and thus,
throughbore 224 may be described as having a "full bore diameter"
and providing "full bore access."
[0069] Upper end 222a of spool piece 222 comprises an upward-facing
hub 150a and lower end 222b comprises a downward-facing receptacle
150b. Hub 150a at upper end 222a extends axially upward from frame
211 and is configured to mate, engage, and interlock with a
downward-facing complementary connector 150b on upper assembly 250,
thereby forming a releasable wellhead-type, hydraulically actuated
mechanical connection 150 between assemblies 210, 250. As will be
described in more detail below, receptacle 150b at lower end 222b
is configured to mate, engage, and interlock with an upward-facing
complementary hub 150a on a transition spool 330, BOP 120, or
wellhead 130, thereby forming a releasable wellhead-type,
hydraulically actuated mechanical connection 150 between lower
assembly 210 and flex joint adapter 145, BOP 120, or wellhead 130,
respectively.
[0070] Referring still to FIGS. 6-10, second spool piece 230
extends perpendicularly from first spool piece 222 and has a
central or longitudinal axis 231, a first or radially inner end
230a (relative to axis 223) secured to spool piece 222, a second or
radially outer end 230b (relative to axis 223) opposite end 230a
and distal spool piece 222, and a horizontal flow bore or
throughbore 232 extending axially (relative to axis 231) between
ends 230a, b. Throughbore 232 is coaxially disposed within spool
piece 230, and thus, throughbore 232 has a central axis coincident
with axis 231.
[0071] Throughbore 232 is coaxially aligned with and contiguous
with horizontal bore 225. Thus, throughbore 232 is in fluid
communication with bore 225. Together, bores 225, 232 define a
horizontal branch or flow path in spool body 221 that extends
perpendicularly from vertical main bore 224. As best shown in FIG.
10, first spool piece 222 includes a valve 233 positioned along
bore 225 and second spool piece 230 includes a valve 233 positioned
along throughbore 232. Valves 233 control the flow of fluids
through bores 225, 232. Namely, each 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
through bores 225, 232 is restricted and/or prevented if one or
both valves 233 are closed, and fluid flow through bores 225, 232
is permitted if both valves 233 are opened. In general, each valve
233 may comprise any type of valve suitable for the anticipated
fluid pressures and fluids in bore 232 including, without
limitation, ball valves, gate valves, and butterfly valves.
Further, each valve 233 may be manually actuated, hydraulically
actuated, mechanically actuated, or electrically actuated valves.
In this embodiment, each valve 233 is a hydraulically actuated gate
valve rated for a 15 k psi pressure differential. Each valve 233
may be controlled and hydraulically actuated subsea with an ROV.
Alternatively, each valve 233 may be controlled from the surface
with hydraulic flow lines or flying leads extending from the
surface and coupled to valves 233 via a panel located on lower
assembly 210.
[0072] Lower assembly 210 also includes a choke valve 234
positioned between a fluid conduit 235 and spool piece 230. Fluid
conduit 235 has a first end 235a coupled to choke valve 234, a
second end 235b distal choke valve 234, and a flow bore 236
extending between ends 235a, b. Ends 230b, 235a are coupled to
choke valve 234, and bores 232, 236 are in fluid communication with
choke valve 234. Thus, choke valve 234 controls the flow rate of
fluids between bores 232, 236. In general, choke valve 234 may
comprise any suitable choke or choke valve for regulating the rate
of fluid flow between bores 232, 236. In this embodiment, choke
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. The choke valve 234 has
a retrievable insert that can be removed and replaced subsea.
[0073] Second end 235b of fluid conduit 235 comprises an
upward-facing hub 239a 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 each valve
233 open, fluid in throughbore 224 is free to flow through bores
225, 232, choke valve 234, and bore 236 to hub 239a at end 235b,
where the fluid may be discharged into the surrounding sea or
flowed into another device connected to hub 239a at end 235b. For
example, as will be described in more detail below, when lower
assembly 210 is coupled to wellbore 101 and each valve 233 is open,
hydrocarbons discharged from wellbore 101 may be flowed from bore
224 through bores 225, 232, choke valve 234, and bore 236 to hub
239a at end 235b, where the hydrocarbons may be discharged into the
surrounding sea or produced to another device connected to hub 239a
at end 235b. Alternatively, with each valve 233 open, fluid may be
supplied and/or pumped from a device connected to hub 239a through
bore 236, choke valve 234, and bores 232, 225 into bore 224. For
example, as will be described in more detail below, when lower
assembly 210 is coupled to wellbore 101, chemicals or kill weight
fluids may be supplied and/or pumped from a device connected to hub
239a through bore 236, choke valve 234, and bores 232, 225 into
hydrocarbons in bore 224.
[0074] As best shown in FIG. 10, a first annulus line 237 and a
second annulus line 238 provide access to throughbore 224 axially
above and below bore 225, respectively. In particular, first
annulus line 237 has a first or radially inner end 237a in fluid
communication with throughbore 224 and a second or radially outer
end 237b extending to the outer surface of spool piece 222; and
second annulus line 238 has a first or radially inner end 238a in
fluid communication with throughbore 224 and a second or radially
outer end 238b extending to the outer surface of spool piece 222.
End 237a is positioned axially above bore 225, and end 238a is
positioned axially below bore 225. Ends 237b, 238b may be accessed
by an ROV or other device as desired. In this embodiment, one valve
233 as previously described is positioned along each flow line 237,
238 between ends 237a, b and 238a, b, respectively. Lines 237, 238
may be employed to produce wellbore 101 once it has been contained
and controlled.
[0075] Referring still to FIG. 10, in this embodiment, lower
assembly 210 also includes a chemical injection system 240 and a
fluid monitoring or sensor system 226. For purposes of clarity,
chemical injection system 240 and fluid monitoring system 226 are
not shown in FIGS. 6-9. Chemical injection system 240 includes a
first flow line 241 for injecting chemicals into bore 232, a second
flow line 242 for injecting chemicals into bore 224 above bore 225,
and a third flow line 243 for injecting chemicals into bore 224
above second flow line 242. The upstream ends of flow lines 241,
242, 243 converge at a common inlet port of a dual port ROV hot
stab receptacle 248. Chemicals such as methanol and glycol may be
supplied and/or pumped through flow lines 241, 242, 243 via inlet
receptacle 248.
[0076] Each flow line 241, 242, 243 includes a primary valve 245
for controlling the flow of chemicals through that particular flow
line 241, 242, 243. Namely, each 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 a particular flow line 241, 242, 243 is restricted and/or
prevented if its corresponding valve 245 is closed, and fluid flow
through a particular flow line 241, 242, 243 is permitted if its
corresponding valve 245 is opened. In general, each valve 245 may
comprise any type of valve suitable for the anticipated fluid
pressures and fluids in flow lines 241, 242, 243 including, without
limitation, ball valves, gate valves, and butterfly valves.
Further, each valve 245 may be manually actuated, hydraulically
actuated, mechanically actuated, or electrically actuated valves.
In this embodiment, each valve 245 is a hydraulically actuated gate
valve rated for a 15 k psi pressure differential. Each valve 245
may be controlled and hydraulically actuated subsea with an ROV. In
addition, in this embodiment, valve 245 on each flow line 242, 243
includes a check valve that allows one-way fluid communication from
inlet receptacle 248 to bore 224. Valve 245 on flow line 241 does
not include a check valve so that pressure testing and sampling of
bore 232 may be performed. Each flow line 242, 243 also includes a
pressure gauge 246 positioned between valve 245 and its inlet
receptacle 248. Gauges 246 measure the fluid pressure within flow
lines 242, 243. Secondary valves 247 are positioned along flow
lines 242, 243 between gauges 246 and inlet receptacle 248, and an
additional secondary valve 247 is positioned at inlet receptacle
248. Secondary valves 247 provide a secondary means to valves 245
for controlling fluid flow through flow lines 241, 242, 243. In
general, each valve 247 may comprise any type of valve suitable for
the anticipated fluid pressures and fluids in flow lines 241, 242,
243 including, without limitation, ball valves, gate valves, and
butterfly valves. Further, each valve 247 may be manually actuated,
hydraulically actuated, mechanically actuated, or electrically
actuated valves. In this embodiment, each valve 247 is a manually
operated needle valve rated for a 15 k psi pressure differential.
Each valve 247 may be manually operated subsea with an ROV.
Alternatively, each valve 247 may be hydraulically controlled from
the surface with hydraulic flow lines or flying leads extending
from the surface and coupled to valves 247 via a panel located on
lower assembly 210.
[0077] Referring still to FIG. 10, fluid monitoring system 226
includes an electronic pressure transducer 227 positioned along
throughbore 224 and an electronic temperature transducer 228
positioned along throughbore 224. Transducers 227, 228 measure and
monitor the pressure and temperature, respectively, of fluids in
bore 224. Each transducers 227, 228 is electronically coupled to an
electrical coupling 229 configured to transmit the measured
temperature and pressure data, respectively, from transducers 227,
228, respectively, to a subsea ROV or other device connected to
coupling 229.
[0078] Referring now to FIGS. 5, 6, and 11-14, upper assembly 250
includes a frame 251 and a pipe spool or spool piece 260 disposed
within frame 251. Frame 251 supports spool piece 260 as well as the
remaining components of upper assembly 250. In addition, frame 251
protects spool piece 260 and the remaining components of upper
assembly 250 from impacts during transport and deployment. The top
of frame 251 comprises a planar pad 252 for landing kill-flowback
assembly 290.
[0079] Spool piece 260 has a central or longitudinal axis 261, a
first or upper end 260a, a second or lower end 260b opposite end
260a, and a flow bore or throughbore 262 extending axially between
ends 260a, b. Flow bore 262 is coaxially disposed within spool
piece 260. In other words, flow bore 262 has a central axis
coincident with axis 261. In this embodiment, spool piece 260 is
oriented such that axis 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 of
throughbore 224 and wellbore 101.
[0080] Upper end 260a of spool piece 260 comprises an upward-facing
hub 150a and lower end 260b comprises a downward-facing receptacle
150b. Hub 150a at upper end 260a extends axially upward from pad
252 and is configured to mate, engage, and interlock with a
complementary downward-facing connector 150b on assembly 290,
thereby forming a releasable wellhead-type, hydraulically actuated
mechanical connection 150 between assemblies 250, 290. Further,
receptacle 150b at lower end 260b is configured to mate, engage,
and interlock with a complementary upward-facing hub 150a at upper
end 222a of spool piece 221, thereby forming a releasable
wellhead-type, hydraulically actuated mechanical connection 150
between assemblies 210, 250.
[0081] As best shown in FIGS. 12-14, spool piece 260 also includes
a first or lower valve 263, a second or upper valve 263, and a flow
bore access member 265, each positioned along flow bore 262 between
ends 260a, b. More specifically, second valve 263 is axially spaced
above first valve 263, and access member 265 is axially positioned
between valves 263. Valves 263 control the flow of fluids in bore
262. Namely, each valve 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 through bore
262 is restricted and/or prevented if one or both valves 263 are
closed, and fluid flow through bore 262 is permitted if both valves
263 are opened. In general, each valve 263 may comprise any type of
valve suitable for the anticipated fluid pressures and fluids in
bore 262 including, without limitation, ball valves, gate valves,
and butterfly valves. Further, each valve 263 may be manually
actuated, hydraulically actuated, mechanically actuated, or
electrically actuated valves. In this embodiment, each valve 263 is
a hydraulically actuated gate valve rated for a 15 k psi pressure
differential. Each valve 263 may be controlled and hydraulically
actuated subsea with an ROV. As will be described in more detail
below, flow bore access member 265 enables access to flow bore
262.
[0082] Referring now to FIG. 14, in this embodiment, upper assembly
250 also includes a chemical injection system 270 and a fluid
monitoring or sensor system 280. For purposes of clarity, chemical
injection system 270 and fluid monitoring system 280 are not shown
in FIGS. 5, 6, and 11-13. Chemical injection system 270 includes a
supply line 271 that may be used to inject chemicals into bore 262
and a return line 272 for receiving fluids from bore 262. Supply
line 271 has an inlet end 271a and a second or outlet end 271b in
fluid communication with bore 262 via access member 265. Return
line 272 has a first or inlet end 272a in fluid communication with
bore 262 via access member 265 and a second or outlet end 272b.
Inlet end 271a and outlet end 272b are connected to separate ports
on a dual port ROV hot stab receptacle 248. Chemicals such as
methanol and glycol may be supplied and/or pumped through supply
line 271 into bore 262, and fluids in bore 262 may be acquired via
return line 272. As will be described in more detail below, supply
and return lines 271, 272 may also be used to acquire wellbore
fluid samples for pressure and/or temperature measurement and
monitoring.
[0083] Each flow line 271, 272 includes a pair of valves 273,
arranged series, for controlling the flow of chemicals through that
particular flow line 271, 272. Namely, each 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 a particular flow line 271, 272 is
restricted and/or prevented if one or both of its valves 273 is
closed, and fluid flow through a particular flow line 271, 272 is
permitted if both of its corresponding valves 273 are opened. In
general, each valve 273 may comprise any type of valve suitable for
the anticipated fluid pressures and fluids in flow lines 271, 272
including, without limitation, ball valves, gate valves, and
butterfly valves. Further, each valve 273 may be manually actuated,
hydraulically actuated, mechanically actuated, or electrically
actuated valves. In this embodiment, each valve 273 is a manually
operated needle valve rated for a 15 k psi differential. Each valve
273 may be manually operated subsea with an ROV. In this
embodiment, return line 272 includes a pressure gauge 246
positioned between valves 273 and access member 265. Gauge 246
measure the fluid pressure within return line 272.
[0084] Referring still to FIG. 14, fluid monitoring system 280
includes a bore fluid supply line 281, a bore fluid return line
282, and a sensor package or assembly 285. Flow line 281 has an
inlet end 281a in fluid communication with flow bore 262 via access
member 265 and an outlet end 281b comprising a coupling 283. Flow
line 282 has an inlet end 282a comprising a coupling 283 and an
outlet end 282b in fluid communication with flow bore 262 via
access member 265. Each flow line 281, 282 includes a valve 247 as
previously described for controlling the flow of fluids through
that particular flow line 281, 282. Sensor package 285 includes a
fluid flow line 286, a pressure sensor 287 disposed along line 286,
a temperature sensor 288 disposed along line 286, and a data
transmitter 289 coupled to sensors 287, 288. Flow line 286 has an
inlet end 286a comprising a coupling 284 releasably coupled to
coupling 283 of line 281 and an outlet end 286b comprising a
coupling 284 releasably coupled to coupling 283 of line 282. Thus,
flow lines 281, 282, 286 create a bore fluid flow loop--fluids in
flow bore 262 flow through line 281, 286, and 282 back into flow
bore 262. Sensors 287, 288 measure the pressure and temperature,
respectively, of the bore fluids flowing through flow line 286. The
measured pressure and temperature data is communicated to
transmitter 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 to lines
281, 282 via couplings 283, 284. Thus, sensor package 285 may be
removed or coupled to access member 265 as desired. One or more
ROVs may be used to connect sensor package 285 to lines 281, 282
and to disconnect sensor package 285 from lines 281, 282.
[0085] In this embodiment, systems 270, 280 utilize separate supply
and return lines. Namely, system 270 includes supply line 271 and
return line 272, and system 280 includes supply line 281 and return
line 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 into hot stab
receptacle 248, receive wellbore fluids via supply line 271 and
return wellbore fluids via return line 272. In other words, ends
286a, b of flow line 286 may be configured as ports in a hot stab
connector that is coupled to receptacle 248 with inlet end 286a in
fluid communication with supply line 271 and outlet end 286b in
fluid communication with return line 272.
[0086] Referring now to FIGS. 5, 6, 15 and 16, kill-flowback
assembly 290 includes a frame 291 and a pipe spool or spool piece
292 extending through frame 291. Frame 291 supports spool piece 292
as well as the remaining components of assembly 290. In addition,
frame 291 protects spool piece 292 and the remaining components of
assembly 290 from impacts. The lower end of frame 291 comprises an
annular funnel or guide 293 to facilitate the landing of assembly
290 onto upper assembly 250.
[0087] Spool piece 292 has a central or longitudinal axis 294, a
first or upper end 292a, a second or lower end 292b opposite end
292a, and a flow bore or throughbore 295 extending axially between
ends 292a, b. Flow bore 295 is coaxially disposed within spool
piece 292. In other words, flow bore 295 has a central axis
coincident with axis 294. In this embodiment, spool piece 292 is
oriented such that axis 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.
[0088] Upper end 292a of spool piece 292 extends axially upward
from frame 291 and comprises an upward-facing flange 296, and lower
end 292b comprises a downward-facing receptacle 150b. 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 from wellbore 101. In this
embodiment, two exemplary conduits 298, 299 are shown in FIGS. 15
and 16. Receptacle 150b at lower end 292b is configured to mate,
engage, and interlock with upward-facing hub 150a at upper end 260a
of spool piece 260, thereby forming a releasable wellhead-type,
hydraulically actuated mechanical connection 150 between assemblies
250, 290.
[0089] Referring again to FIG. 6, upper assembly 250 is releasably
coupled to lower 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. When cap 200 is
assembled as shown in FIG. 6, flow bores 224, 262, 295 are
coaxially aligned, flow bore 224 is in fluid communication with
flow bore 262, and flow bore 295 is in fluid communication with
flow bores 224, 262 as long as both valves 263 in flow bore 262 are
opened. Thus, with valves 263 opened, fluids are free to flow
through bores 224, 262, 295 between ends 222b, 292a. Thus, when cap
200 is coupled to subsea wellhead 130, BOP 120, or LMRP 140, valves
263 are opened, and full access bore 224 is in fluid communication
with wellbore 101, kill weight fluids may be pumped into wellbore
101 via conduit 298 or 299 during kill operations, or
alternatively, hydrocarbons flowing from wellbore 101 may be
produced via conduit 298 or 299.
[0090] In this embodiment, containment cap 200 is designed to be
deployed subsea and landed on riser flex joint 143 of LMRP 140, on
mandrel 151 of LMRP 140, on BOP 120, or on wellhead 130, depending
on which is the most suitable landing site. For example, in FIG.
20L, cap 200 is shown installed on subsea BOP 120 previously
described; in FIG. 21, cap 200 is shown installed on subsea
wellhead 130 previously described; and in FIG. 30P, cap 200 is
shown installed on flex joint 143 of LMRP 140 previously described.
Regardless of the landing/installation site, in this embodiment,
the modular 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), then upper assembly 250 is
deployed subsea and installed onto lower assembly 210, and then
kill-flowback assembly 290 is deployed subsea and installed onto
upper assembly 250.
[0091] Referring briefly to FIGS. 17 and 18, in this embodiment,
lower assembly 210 is lowered and manipulated subsea with a running
tool 215 releasably coupled to hub 150a at upper end 222a of spool
piece 222. As best shown in FIG. 18, running tool 215 has a first
or upper end 215a and a second or lower end 215b opposite end 215a.
Lower end 215b comprises a downward-facing receptacle 150b that
releasably engages hub 150a at upper end 222a. Upper end 215a of
running tool 215 may be releasably coupled to a first adapter 216
that enables deployment of lower assembly 210 with a pipestring or
drillstring, or to a second adapter 217 that enables deployment of
lower assembly 210 on wireline. Thus, running tool 215 may be
deployed subsea from a surface vessel with a pipe string using
first adapter 216 and running tool 215, or with a wireline using
second adapter 217 and running tool 215. As shown in FIG. 19, upper
assembly 250 is lowered and manipulated subsea with wireline
coupled to frame 251 with a plurality of lead lines 253 disposed
about pad 252. Kill-flowback assembly 290 is lower and manipulated
subsea with wireline in the same manner as upper 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.
[0092] Referring now to FIGS. 20A-20L, containment cap 200 is shown
being deployed and installed subsea on BOP 120 to shut-in and/or
produce wellbore 101. More specifically, in FIGS. 20A-20D, lower
assembly 210 is shown being lowered subsea and coupled to BOP 120;
in FIGS. 20E-20H, upper assembly 250 is shown being lowered subsea
and coupled to lower assembly 210; and in FIGS. 20I-20L,
kill-flowback assembly 290 is shown being lowered subsea and
coupled to upper assembly 250.
[0093] For subsea deployment and installation of containment cap
200, one or more remote operated vehicles (ROVs) are preferably
employed to aid in positioning assemblies 210, 250, 290, monitoring
assemblies 210, 250, 290 and BOP 120, and operating assemblies 210,
250, 290 (e.g., actuating valves 233, 263, operating chemical
injection systems, etc.). In this embodiment, three ROVs 170 are
employed to position assemblies 210, 250, 290, monitor assemblies
210, 250, 290 and BOP 120, and operate assemblies 210, 250, 290.
Each ROV 170 includes an arm 171 having a claw 172, a subsea camera
173 for viewing the subsea operations (e.g., the relative positions
of assemblies 210, 250, 290, BOP 120, plume 160, the positions and
movement of arms 170 and claws 172, etc.), and an umbilical 174.
Streaming video and/or images from cameras 173 are communicated to
the surface or other remote location via umbilical 174 for viewing
on a live or periodic basis. Arms 171 and claws 172 are controlled
via commands sent from the surface or other remote location to ROV
170 through umbilical 174.
[0094] Before connecting cap 200 to BOP 120, LMRP 140 is removed
from BOP 120 by decoupling connection 150 between BOP 120 and LMRP
140, and then lifting LMRP 140 from BOP 120 with wireline, a
pipestring, one or more ROVs 170, or combinations thereof. In
addition, any tubulars or debris extending from upper end 123a of
BOP 120 are cut off substantially flush with upper end 123a with
one or more ROVs 170.
[0095] Referring first to FIG. 20A, in this embodiment, lower
assembly 210 is shown being controllably lowered subsea with a
pipestring 180 secured to the upper end of adapter 216 and
extending to a surface vessel. A derrick or other suitable device
mounted to the surface vessel is preferably employed to support and
lower assembly 210 on string 180. Although string 180 is employed
to deploy lower assembly 210 in this embodiment, in other
embodiments, lower assembly 210 may be deployed subsea on wireline.
Using string 180, lower assembly 210 is lowered subsea under its
own weight from a location generally above and laterally offset
from wellbore 101 and BOP 120. More specifically, during
deployment, lower assembly 210 is preferably maintained outside of
plume 160 of hydrocarbon fluids emitted from wellbore 101. Lowering
lower assembly 210 subsea in plume 160 may trigger the undesirable
formation of hydrates within lower assembly 210, particularly at
elevations substantially above sea floor 103 where the temperature
of hydrocarbons in plume 160 is relatively low.
[0096] Moving now to FIG. 20B, lower assembly 210 is lowered
laterally offset from BOP 120 and outside of plume 160 until lower
end 222b is slightly above BOP 120. As assembly 210 descends and
approaches BOP 120, ROVs 170 monitor the position of assembly 210
relative to BOP 120. Next, as shown in FIG. 20C, assembly 210 is
moved laterally into position immediately above and substantially
coaxially aligned with BOP 120. One or more ROVs 170 may utilize
their claws 172 and frame 211 to guide and manipulate the position
of assembly 210 relative to BOP 120. Due to its own weight,
assembly 210 is substantially vertical, whereas BOP 120 may be
oriented at a slight angle relative to vertical. Thus, it is to be
understood that perfect coaxial alignment of BOP 120 and assembly
210 may be difficult. However, the mating profiles of hub 150a at
upper end 123a of BOP 120 and receptacle 150b at lower end 222b of
assembly 210 facilitate the coaxial alignment and coupling of
assembly 210 and BOP 120 as assembly 210 is lowered from a position
immediately above BOP 120, even if assembly 210 is initially
slightly misaligned with BOP 120.
[0097] Moving now to FIG. 20D, with receptacle 150b at lower end
222b of assembly 210 positioned immediately above and substantially
coaxially aligned with hub 150a at upper end 123a of BOP 120,
string 180 lowers assembly 210 axially downward. Due to the weight
of assembly 210, compressive loads between assembly 210 and BOP 120
urge the male hub 150a at upper end 123a into the female receptacle
150b at lower end 222b. Once the hub 150a is sufficiently seated in
the receptacle 150b to form wellhead-type connection 150,
connection 150 is hydraulically actuated to securely connect
assembly 210 to BOP 120 as shown in FIG. 20D.
[0098] As assembly 210 is positioned immediately above BOP 120,
hydrocarbons emitted from BOP 120 are free to flow unrestricted
through bore 224. In addition, prior to moving assembly 210
laterally over BOP 120, valves 233 in lines 237, 238 are closed,
and valves 233 in bores 225, 232 are opened to allow hydrocarbon
fluids emitted by BOP 120 to flow through bore 232, choke 234, and
bore 236. Valves 233 in bores 225, 232 may be transitioned to the
open position and valves 233 in lines 237, 238 may be transitioned
to the closed position at the surface 102 prior to deployment, or
subsea via one or more ROVs 170. Thus, as assembly 210 is moved
laterally over BOP 120 and lowered into engagement with BOP 120,
emitted hydrocarbon fluids flow freely through bores 224, 225, 232,
236. As a result, open valves 233 offer the potential to reduce the
resistance to the axial insertion of hub 150a into receptacle 150b
and coupling of lower assembly 210 to BOP 120. In other words, open
valves 233 in bores 225, 232 allow the relief of well pressure
during installation of lower assembly 210. With a sealed, secure
connection between lower assembly 210 and BOP 120, ROVs 170
decouple running tool 215 from lower assembly 210. Running tool 215
and adapter 216 may then be removed to the surface with pipestring
180.
[0099] Referring now to FIG. 20E, with lower assembly 210 securely
coupled to BOP 120, upper assembly 250 is deployed and coupled to
lower assembly 210. In this embodiment, upper assembly 250 is shown
being controllably lowered subsea with wireline 181 extending from
a surface vessel and having a lower end secured to leads 253. Due
to the weight of assembly 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 and
lower assembly 250 on wireline 181. Although wireline 181 and leads
253 are employed to lower assembly 250 in this embodiment, in other
embodiments, assembly 250 may be deployed subsea on a pipe string.
Using wireline 181, assembly 250 is lowered subsea under its own
weight from a location generally above and laterally offset from
wellbore 101, BOP 120, lower assembly 210, and outside of plume 160
to reduce the potential for hydrate formation within assembly
250.
[0100] Moving now to FIG. 20F, upper assembly 250 is lowered
laterally offset from lower assembly 210 and outside of plume 160
until lower end 260b is slightly above lower assembly 210. As upper
assembly 250 descends and approaches lower assembly 210, ROVs 170
monitor the position of upper assembly 250 relative to lower
assembly 210. Next, as shown in FIG. 20G, assembly 250 is moved
laterally into position immediately above and substantially
coaxially aligned with lower assembly 210. One or more ROVs 170 may
utilize their claws 172 and frame 251 to guide and manipulate the
position of upper assembly 250 relative to lower assembly 210. Due
to its own weight, assembly 250 is substantially vertical, whereas
lower assembly 210 may be oriented at a slight angle relative to
vertical if BOP 120 was slightly angled. Thus, it is to be
understood that perfect coaxial alignment of assemblies 210, 250
may be difficult. However, the mating profiles of hub 150a at upper
end 222a of spool piece 222 and receptacle 150b at lower end 260b
of assembly 250 facilitate the coaxial alignment and coupling of
assemblies 210, 250 as upper assembly 250 is lowered from a
position immediately above lower assembly 210, even if upper
assembly 250 is initially slightly misaligned with lower assembly
210.
[0101] Moving now to FIG. 20H, with receptacle 150b at lower end
260b positioned immediately above and substantially coaxially
aligned with hub 150a at upper end 222a, wireline 181 lowers
assembly 250 axially downward. Due to the weight of assembly 250,
compressive loads between upper assembly 250 and lower assembly 210
urge the male hub 150a at upper end 222a into the female receptacle
150b at lower end 260b. Once the hub 150a is sufficiently seated in
the receptacle 150b to form wellhead-type connection 150,
connection 150 is hydraulically actuated to securely connect upper
assembly 250 to lower assembly 210 as shown in FIG. 20H. With a
sealed, secure connection between lower assembly 210 and upper
assembly 250, ROVs 170 decouple leads 253 from upper assembly 250.
Leads 253 may then be removed to the surface with wireline 181.
[0102] Prior to moving upper assembly 250 laterally over lower
assembly 210 and BOP 120, valves 263 are transitioned to the open
position also allowing hydrocarbon fluids emitted by BOP 120 and
lower assembly 210 to flow through bore 262. Valves 263 may be
transitioned to the open position at the surface 102 prior to
deployment, or subsea via one or more ROVs 170. Thus, as upper
assembly 250 is moved laterally over lower assembly 210 and lowered
into engagement with lower assembly 210, emitted hydrocarbon fluids
flow freely through bore 262. As a result, open valves 263 offer
the potential to reduce the resistance to the axial insertion of
hub 150a into receptacle 150b and coupling of upper assembly 250 to
lower assembly 210. In other words, open valves 263 allow the
relief of well pressure during installation of upper assembly 250.
It should also be appreciated that aligned bores 224, 262 enable
re-entry of BOP 120 and wellbore 101.
[0103] Referring now to FIG. 20I, with upper assembly 250 securely
coupled to lower assembly 210, kill-flowback assembly 290 is
deployed and coupled to upper assembly 250. Assembly 290 is
deployed in substantially the same manner as upper assembly 250.
Specifically, in this embodiment, kill-flowback assembly 290 is
shown being controllably lowered subsea with wireline 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 of assembly 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 and lower assembly 290 on wireline
181. Although wireline 181 and leads 253 are employed to lower
assembly 290 in this embodiment, in other embodiments, assembly 290
may be deployed subsea on a pipe string. Using wireline 181,
assembly 290 is lowered subsea under its own weight from a location
generally above and laterally offset from wellbore 101, BOP 120,
lower assembly 210, upper assembly 250, and outside of plume 160 to
reduce the potential for hydrate formation within assembly 290.
[0104] Moving now to FIG. 20J, assembly 290 is lowered laterally
offset from upper assembly 250 and outside of plume 160 until lower
end 292b is slightly above upper assembly 250. As assembly 290
descends and approaches upper assembly 250, ROVs 170 monitor the
position of assembly 290 relative to upper assembly 250. Next, as
shown in FIG. 20K, assembly 290 is moved laterally into position
immediately above and substantially coaxially aligned with upper
assembly 250. One or more ROVs 170 may utilize their claws 172 and
frame 291 to guide and manipulate the position of assembly 290
relative to upper assembly 250. Due to its own weight, assembly 290
is substantially vertical, whereas upper assembly 250 may be
oriented at a slight angle relative to vertical if BOP 120 was
slightly angled. Thus, it is to be understood that perfect coaxial
alignment of assemblies 250, 290 may be difficult. However, the
mating profiles of hub 150a at upper end 260a of spool piece 260
and receptacle 150b at lower end 292b of spool piece 292 facilitate
the coaxial alignment and coupling of assemblies 250, 290 as
assembly 290 is lowered from a position immediately above upper
assembly 250, even if assembly 290 is initially slightly misaligned
with upper assembly 250.
[0105] Moving now to FIG. 20L, with receptacle 150b at lower end
292b positioned immediately above and substantially coaxially
aligned with hub 150a at upper end 260a, wireline 181 lowers
assembly 290 axially downward. Due to the weight of assembly 290,
compressive loads between assembly 290 and upper assembly 260 urge
the male hub 150a at upper end 260a into the female receptacle 150b
at lower end 292b. Once the hub 150a is sufficiently seated in the
receptacle 150b to form wellhead-type connection 150, connection
150 is hydraulically actuated to securely connect kill-flowback
assembly 290 to upper assembly 250 as shown in FIG. 20L. With a
sealed, secure connection between upper assembly 250 and
kill-flowback assembly 290 ROVs 170 decouple leads 253 from
assembly 290. Leads 253 may then be removed to the surface with
wireline 181.
[0106] Prior to moving assembly 290 laterally over upper assembly
250 and BOP 120, flow bore 295 is maintained opened to allow
hydrocarbon fluids emitted by BOP 120 and assemblies 210, 250 to
flow through bore 295. Thus, as kill-flowback assembly 290 is moved
laterally over upper assembly 250 and lowered into engagement with
upper assembly 250, emitted hydrocarbon fluids flow freely through
bore 295, thereby offering the potential to reduce the resistance
to the axial insertion of hub 150a into receptacle 150b and
coupling of assembly 290 to upper assembly 250. In other words,
open flow bore 295 allows the relief of well pressure during
installation of kill-flowback assembly 290. A conduit 298, 299 may
be coupled to upper end 292a of spool piece 292 (to supply kill
weight fluids or produce wellbore 101) once assembly 290 is
securely connected to upper assembly 250.
[0107] In the manner described, cap 200 is deployed and installed
on BOP 120. However, as best shown in FIG. 21, cap 200 may also be
installed directly onto wellhead 130. Assemblies 210, 250, 290 are
deployed subsea and connected together in the exact same manner as
previously described with the exception that lower assembly 210 is
securely connected to wellhead 130. In particular, downward-facing
receptacle 150b at lower end 222b is coupled to upward-facing
receptacle 150a of wellhead 130, thereby forming connection 150
between lower assembly 210 and wellhead 130. Before connecting
lower assembly 210 to wellhead 130, LMRP 140 and BOP 120 are
removed from wellhead 130 by decoupling connection 150 between BOP
120 and LMRP 140, lifting LMRP 140 from BOP 120 and then decoupling
connection 150 between BOP 120 and wellhead 130 and lifting BOP 120
from wellhead 130. In addition, any tubulars or debris extending
from wellhead 130 are cut off substantially flush with the upper
end of wellhead hub 150a with one or more ROVs 170.
[0108] Referring now to FIGS. 6 and 20L, upon installation of
containment cap 200, hydrocarbons are free to flow through cap 200.
To contain and shut-in wellbore 101, valves 233 in bores 225, 232
and valves 263 in bore 262 are manipulated by subsea ROVs 170. If
kill fluids are utilized to aid in shutting in wellbore 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 in
wellbore 101, the shut-in procedures may be initiated prior to
installation of kill-flowback assembly 290.
[0109] To shut-in wellbore 101, valves 233 in flow lines 237, 238
are both closed, and valves 233 in bores 225, 232 are both
maintained opened while upper valve 263 is transitioned closed. As
upper valve 263 is transitioned closed, the pressure of wellbore
fluids within lower assembly 210 are monitored with pressure
transducer 227 and the pressure of wellbore fluids within upper
assembly 250 are monitored with pressure sensor 287. As long as the
formation fluid pressures within assemblies 210, 250 are within
acceptable limits, upper valve 263 continues to be closed until it
is fully closed. Once upper valve 263 is closed, lower valve 263
may also be fully closed to provide redundancy. With both valves
263 closed, fluid flow through bore 262 is restricted and/or
prevented, however, since valves 233 in bores 225, 232 are opened,
formation fluids are free to flow through bores 224, 225, 232, 236
and choke valve 234. Next, valve 233 in bore 232 is transitioned
closed. As that valve 233 is transitioned closed, the pressure of
wellbore fluids within lower assembly 210 are monitored with
pressure transducer 227. As long as the formation fluid pressures
within assembly 210 is within acceptable limits, valve 233 in bore
232 continues to be closed until it is fully closed. Once valve 233
in bore 232 is closed, valve 233 in bore 225 may also be fully
closed to provide redundancy. With each valve 233, 263 closed,
wellbore 101 is contained and shut-in. It should be appreciated
that inclusion of choke valve 234 and the staged shut-in of
wellbore 101 via sequential closure of valves 233, 263 enables a
"soft" shut-in, thereby offering the potential to reduce the
likelihood of an abrupt formation pressure surge, which may damage
subsea components (e.g., BOP 120, assembly 210, assembly 250,
assembly 290) and lead to another subsea blowout.
[0110] Once wellbore 101 is shut-in and generally under control,
and the necessary infrastructure for producing wellbore 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/or conduit 235. For example,
depending on the particular circumstances, wellbore 101 may be
produced through flowback assembly 290 with valves 233 closed and
valves 263 opened, produced through conduit 235 with valves 233
opened and valves 263 closed, or produced through both assembly 290
and conduit 235 with all valves 233, 263 opened.
[0111] As previously described, lower assembly 210 includes
chemical injection system 240, and upper assembly 250 includes a
chemical injection system 270. Injection systems 240, 270 may be
used prior to, during, or after shutting-in wellbore 101 to inject
chemicals into bores 224, 262, respectively, and wellbore 101. For
example, chemicals such as glycol and/or methanol may be injected
to reduce hydrate formations within assemblies 210, 250 which might
otherwise hamper or prevent the ability to install assemblies 210,
250. As another example, chemical dispersants may be injected into
hydrocarbons flowing through assemblies 210, 250 after installation
to mitigate volume of oil and volatile organic compounds generated
at the sea surface.
[0112] Containment cap 200 previously described may also be
installed onto mandrel 151 or flex joint 143 of LMRP 140.
Installation of cap 200 onto flex joint 143 of LMRP 140 will now be
described. As shown in FIGS. 1 and 2, riser adapter 145 is coupled
to flex joint 143; the upper end of riser adapter 145 comprises
flange 145a for coupling adapter 145 to mating flange 118 at the
lower end of riser 115. However, in the embodiment shown, lower end
222b of spool piece 222 (FIG. 8) comprises receptacle 150b for
connecting to a complementary mating hub 150a to form a
wellhead-type connection 150. Thus, receptacle 150b is not
configured or designed to mate and engage with flange 145a.
Accordingly, referring now to FIG. 22, in this embodiment, an
adapter or transition spool 330 is employed to couple lower
assembly 210 of cap 200 to riser adapter 145.
[0113] Referring to FIG. 22, in this embodiment, transition spool
330 has a central or longitudinal axis 335, a first or upper end
330a, a second or lower end 330b opposite end 330a, and a flow bore
331 extending axially between ends 330a, b. Upper end 330a
comprises an upward-facing hub 150a configured to releasably engage
complementary receptacle 150b at lower end 222b of containment cap
200 to form a wellhead-type connection 150, lower end 330b
comprises a mule shoe 340 configured to be coaxially inserted into
riser adapter 145 following removal of riser 115 from flex joint
143. An annular flange 334 is axially disposed between ends 330a,
b, and is sized and configured to mate and engage with flange 145a
of flex joint 143. Flange 334 includes a plurality of
circumferentially spaced holes 334a. Bolts 334b are pre-disposed in
holes 334a, and a resilient annular band 336 is disposed about the
upper ends of bolts 334b. Band 336 urges the upper ends of bolts
334b radially inward relative to their lower ends and holes 334a,
thereby skewing and angling bolts 334b relative to holes 334a
(i.e., bolts 334b are not coaxially aligned with holes 334a). In
this manner, band 336 maintains the position of bolts 334b
extending into holes 334a during deployment of transition spool
330, thereby reducing the likelihood of one or more bolts 334b
disengaging their corresponding holes 334a and being dropped to the
sea floor 103 during deployment and installation of containment cap
200.
[0114] Referring still to FIG. 22, a pair of circumferentially
spaced alignment guides or pins 338 extend axially downward from
flange 334. Pins 338 are sized and positioned to coaxially and
rotationally align flange 334 of transition spool 330 relative to
flange 145a of flex joint 143 such that holes 334a are coaxially
aligned with corresponding holes in flange 145a. Transition spool
330 also includes a plug 337 extending axially through flange 334.
Plug 337 is positioned and oriented for axial insertion into outlet
149b of mud boost line 149 in flange 145a when flanges 145a, 334
are coupled together. Plug 337 functions to close off and seal
outlet 149b, thereby preventing the leakage of hydrocarbon fluids
therethrough in the event mud boost valve 149c fails or otherwise
leaks. In this embodiment, plug 337 is pre-installed in transition
spool 330 prior to deployment such that it engages mating outlet
149b as flanges 145a, 334 axially abut. Alternatively, plug 337 may
be installed by an ROV 170 after flanges 145a, 334 are secured
together. Plug 337 may be fitted with an adapter for coupling a
chemical supply line to plug 337 to inject a chemical into outlet
149b in the event it is necessary to flush hydrates from outlet
149b.
[0115] Mule shoe 340 is a tubular extending axially downward from
flange 334. In this embodiment, shoe 340 also includes a plurality
of circumferentially spaced elongate through slots 343 extending
radially from the outer cylindrical surface of shoe 340 to bore
331. In the embodiment, slots 343 are oriented parallel to axis
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 of transition spool 330 includes mule 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)
[0116] 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 until flanges 145a, 334 axially abut. During insertion of
mule shoe 340 into flex joint 143, through slots 343 provide a flow
path for hydrocarbon fluids discharged from wellbore 101 through
BOP 120 and LMRP 140, thereby offering the potential to relieve
wellbore pressure during installation.
[0117] To facilitate the alignment and insertion of mule shoe 340
into flex joint 143, lower end 330b is angled or tapered in side
view (i.e., when viewed perpendicular to axis 335). Specifically,
lower end 330b is oriented at an angle .beta. relative to axis 335.
Angle .beta. is preferably between 30.degree. and 60.degree.. In
this embodiment, angle .beta. is 45.degree.. Tapered lower end 330b
also facilitates the axial advancement of mule 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. As shoe 340 is advanced,
tapered end 330b slidingly engages the component, thereby guiding
shoe 340 into the component. In addition, tapered end 330b
slidingly engages and guides tubulars within the component into
bore 331. In other words, tapered end 330b enables mule shoe 340 to
wedge itself radially between the component and the tubulars
disposed therein. This may be particularly advantageous in
instances where mule shoe 340 is coupled to a component that
contains damage tubulars or pipes that cannot be removed.
[0118] To prepare flange 145a for sealing engagement with flange
334, riser 115 is removed from flex joint 143, and any tubulars or
debris extending upward from flange 145a are preferably cut off
substantially flush with flange 145a. In addition, riser adapter
145 is preferably oriented vertically and locked in the vertical
position prior to coupling transition spool 330, lower assembly
210, upper assembly 250, kill-flowback assembly 290, or
combinations thereof to riser adapter 145. This offers the
potential to simplify installation of these components as well as
reduce moments experienced by adapter 145 following installation of
these components. More specifically, since riser adapter 145 is
designed to angularly deflect and pivot relative to base 144, the
moments exerted on riser adapter 145 following attachment of such
components may cause riser adapter 145 to undesirably pivot and/or
break. However, by straightening flex joint 143 (i.e., orienting
riser adapter 145 vertically) and locking riser adapter 145 in
place, such moments can be reduced and resisted without adapter 145
pivoting or breaking. In general, riser adapter 145 may be oriented
vertically and locked in the vertical orientation by any suitable
systems and/or methods. Examples of suitable systems and methods
for orienting riser adapter 145 vertically and locking riser
adapter 145 in the vertical orientation are disclosed in U.S.
patent application 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.
[0119] Referring briefly to FIGS. 23-25, an embodiment of a system
300 for adjusting and restraining the angular orientation of riser
adapter 145 relative to base 144, BOP 120, and wellhead 130 is
shown. In this exemplary embodiment, the system 300 includes a
plurality of base members 301 circumferentially spaced about and
mounted to the upper end of base 144 and a plurality of hydraulic
cylinder assemblies 310, one cylinder assembly 310 is radially
positioned between each base member 301 and riser adapter 145. Each
base member 301 includes an upper pocket or cavity 302 within which
one cylinder assembly 310 is seated and a lower pocket or cavity
303 that receive the upper ends of studs and nuts 304 extending
upward from base 144.
[0120] Each hydraulic cylinder assembly 310 includes a cylinder
member 311 that rests in the upper pocket 302 and a piston member
312 extending from cylinder member 311. Piston member 312 is
hydraulically actuated to extend or retract relative to cylinder
member 311. Piston member 312 includes a contact member 313 for
engaging the outer surface of riser adapter 145. Upon actuation,
piston member 312 can be extended axially from cylinder member 311
to exert a radial force on riser adapter 145 to pivot riser 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.RTM. RC-502 hydraulic cylinders
and/or Enerpac.RTM. 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.
[0121] Base members 301 and cylinder assemblies 310 are positioned
about riser adapter 145 with one or more subsea ROVs (e.g., ROVs
170). In particular, base members 301 and cylinder assemblies 310
are circumferentially positioned and spaced to exert the
appropriate radial forces on riser adapter 145 to vertically orient
riser adapter 145.
[0122] Referring now to FIG. 26, an embodiment of another system
340 for adjusting and restraining the angular orientation of riser
adapter 145 relative to base 144, BOP 120, and wellhead 130 is
shown. In this exemplary embodiment, the system 340 includes a
plurality of stud caps 341 mounted to the upper ends the studs
extending upward from base 144 and a plurality of hydraulic
cylinder assemblies 345 (only one cylinder assembly 345 is shown in
FIG. 26) radially positioned between caps 341 and riser adapter
145. Each cap 341 is a rigid cylinder including a counterbore or
cavity in its lower end that receives the upper end of one stud
extending upward from base 144.
[0123] Referring now to FIGS. 26 and 27, each hydraulic cylinder
assembly 345 includes a body 346 and a piston-cylinder assembly 347
coupled to body 346. Body 346 includes a piston-cylinder housing
346a and a flange 346b extending downward from housing 346a.
Piston-cylinder assembly 347 is disposed within housing 346a and
includes a piston member 348 hydraulically actuated to extend or
retract relative to housing 346a. Piston member 348 includes a
contact face 348a for engaging the outer surface of riser adapter
145. An ROV handle 349 is coupled to body 346 to facilitate
positioning of assembly 345 by a subsea ROV.
[0124] To adjust the angle between riser adapter 145 and base 144,
caps 341 are mounted on the studs extending upward from base 144,
and one or more assemblies 345 are circumferentially disposed about
riser adapter 145. In particular, assemblies 345 are radially
positioned between caps 341 and riser adapter 145 with housing 346a
engaging caps 341, piston member 348 extending radially inward from
housing 346a towards riser adapter 145, and flange 346b engaging
the inner surface of base 144. Next, assemblies 347 are actuated to
extend piston members 348 radially inward into engagement riser
adapter 145. Continued actuation of assemblies 347 causes piston
members 348 to exert a radial force on riser adapter 145 to pivot
riser 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.RTM. RC-502
hydraulic cylinders and/or Enerpac.RTM. 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.
[0125] Caps 341 and cylinder assemblies 345 are positioned about
riser adapter 145 with one or more subsea ROVs (e.g., ROVs 170). In
particular, caps 341 and cylinder assemblies 345 are
circumferentially positioned and spaced to exert the appropriate
radial forces on riser adapter 145 to vertically orient riser
adapter 145.
[0126] 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 300, 340 can be uniformly circumferentially disposed about
riser adapter 145 to exert balanced radial forces that maintain
riser adapter 145 in the vertical orientation. Alternatively, rigid
wedges may be disposed in the annulus radially positioned between
riser adapter 145 and base 144, and uniformly circumferentially
spaced about riser adapter 145 once adapter 145 is vertically
oriented to maintain adapter 145 in the vertical orientation.
[0127] Referring now to FIGS. 28 and 29, an embodiment of a set 350
of wedge members 360 for locking riser adapter 145 in a vertical
orientation is shown. Wedge members 360 are sized and configured to
be positioned in the annulus between riser adapter 145 and
cylindrical base 144. In particular, wedge members 360 are
numerically labeled (e.g., "1", "2", "3", "4" . . . ) to designate
the circumferential order in which wedge members 360 are arranged
within set 350. For example, wedge member 360 labeled "1" is
circumferentially adjacent wedge member 360 labeled "2", which is
circumferentially adjacent wedge member 360 labeled "3", and so on.
With wedge members 360 arranged in the proper circumferential
order, set 350 defines an inner annular cylindrical surface 351
disposed at an inner diameter Di and an outer annular cylindrical
surface 352 disposed at an outer diameter Do. Inner diameter Di is
substantially the same or slightly greater than the outer diameter
of riser adapter 145, and outer diameter Do is substantially the
same or slightly less than the inner diameter of base 144. Thus,
when wedge members 360 are arranged in the proper circumferential
order and disposed about riser adapter 145, inner surface 351
engages riser adapter 145 and outer surface 352 engages the inner
surface of base 144, thereby locking the position and angle of
riser adapter 145 relative to base 144. In this embodiment, an ROV
handle 361 is coupled to each wedge member 360 to facilitate the
independent positioning wedge members 360 by a subsea ROV.
[0128] As best shown in FIG. 29, inner surface 351 is centered
about a first centrum 351a and outer surface 352 is centered about
a second centrum 352a that is radially offset from centrum 351a.
The degree of radial offset of centrums 351a, 352a can be varied to
orient and lock riser adapter 145 at a particular angle relative to
base 144.
[0129] Referring now to FIGS. 30A-30P, containment cap 200
previously described is shown being deployed and installed subsea
on flex joint 143 of LMRP 140, after riser adapter 145 has been
prepared for engagement with transition spool 330 as previously
described, to contain and shut-in wellbore 101. Since receptacle
150b at lower end 222b of spool piece 222 is not configured or
designed to mate and engage with flange 145a, transition spool 330
previously described is first deployed and coupled to LMRP 140,
followed by deployment and installation of assemblies 210, 250,
290. In FIGS. 30A-30D, transition spool 330 is shown being
controllably lowered subsea and secured to flex joint 143; in FIGS.
30E-30H, lower assembly 210 is shown being controllably lowered
subsea and secured to transition spool 330; in FIGS. 30I-30L, upper
assembly 250 is shown being controllably lowered subsea and secured
to lower assembly 210; and in FIGS. 30M-30P, kill-flowback assembly
290 is shown being controllably lowered subsea and secured to upper
assembly 250.
[0130] Referring first to FIG. 30A, transition spool 330 is shown
being controllably lowered subsea with wireline 181 and leads 253
secured to spool 330 and extending to a surface vessel. Due to the
weight of spool 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 and
lower spool 330 on wireline 181. Although wireline 181 is employed
to lower 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. Using wireline 181, spool 330 is lowered
subsea under its own weight from a location generally above and
laterally offset from wellbore 101, BOP 120, and LMRP 140 and
outside of plume 160 to reduce the potential for hydrate formation
within spool 330.
[0131] Moving now to FIG. 30B, spool 330 is lowered laterally
offset from riser adapter 145 (outside of plume 160) until mule
shoe 340 is slightly above flange 145a. As spool 330 descends and
approaches riser adapter 145, ROVs 170 monitor the position of
spool 330 relative to flex joint 143. Next, as shown in FIG. 30C,
transition spool 330 is moved laterally into position immediately
above riser adapter 145 with mule shoe 340 substantially coaxially
aligned with riser adapter 145. In addition, spool 330 is rotated
about axis 335 to substantially align guide pins 338 with
corresponding holes 148 in flange 145a. One or more ROVs 170 may
utilize their claws 172 to guide and rotate spool 330 into the
proper alignment relative to flange 145a.
[0132] Due to its own weight, spool 330 is substantially vertical,
whereas riser adapter 145 may be oriented at an angle relative to
vertical. Thus, it is to be understood that perfect coaxial
alignment of mule shoe 340 and flex joint 143, as well as perfect
alignment of pins 338 and mating holes in flange 145a, may be
difficult.
[0133] With mule shoe 340 positioned immediately above and
generally coaxially aligned with riser adapter 145, and guide pins
338 aligned with corresponding holes in flange 145a, wireline 181
lower spool 330 axially downward, thereby inserting and axially
advancing pins 338 into corresponding holes 148 and inserting and
axially advancing mule shoe lower end 330b into riser adapter 145
until flange 334 axially abuts and engages flange 145a as shown in
FIG. 30D. The frustoconical surface on the lower end of each pin
338 functions to guide each pin 338 into its corresponding hole
148, even if pins 338 are initially slightly misaligned with holes
148. Likewise, taper on lower end 330b functions to guide the
insertion and coaxial alignment of spool 330 and riser adapter 145
as spool 330 is lowered from a position immediately above riser
adapter 145, even if mule shoe 340 is initially slightly misaligned
with riser adapter 145. During installation of spool 330, emitted
hydrocarbons flow freely through spool 330 and slots 343 in mule
shoe 340, thereby relieving well pressure and offering the
potential to reduce the resistance to the axial insertion of mule
shoe 340 into riser adapter 145 and coupling of transition spool
330 thereto.
[0134] With mule shoe 340 sufficiently seated in riser adapter 145
and flange 334 abutting mating flange 145a, holes 334a are
coaxially aligned with corresponding holes 147 in flange 145a and
plug 337 is disposed in mud boost outlet 149b. Next, one ROV 170
cuts band 336, thereby allowing bolts 334b to drop into holes 147.
One or more ROVs 170 may also help facilitate the lowering of bolts
334b into holes 147 if necessary. Bolts 334b may then be tightened
with ROVs 170 to rigidly secure spool 330 to riser adapter 145.
With a sealed, secure connection between spool 330 and riser
adapter 145, ROVs 170 decouple leads 253 from transition spool 330.
Leads 253 may then be removed to the surface with wireline 181.
[0135] Once transition spool 330 is securely coupled to riser
adapter 145, assemblies 210, 250, 290 are deployed in the same
manner as previously described with respect to FIGS. 20A-20L with
the exception that lower assembly 210 is connected to transition
spool 330. Specifically, as shown in FIGS. 30E-30H, lower assembly
210 is lowered subsea as previously described and coupled to
transition spool 330 via engagement of upward-facing hub 150a of
transition spool 330 and downward-facing receptacle 150b of lower
assembly 210 to form a wellhead-type connection 150 therebetween.
Next, as shown in FIGS. 30I-30L, upper assembly 250 is lowered
subsea and connected to lower assembly 210 as previously described,
and then, as shown in FIGS. 30M-30P, kill-flowback assembly 290 is
lowered subsea and connected to upper assembly 250 as previously
described. Wellbore 101 may be contained and shut-in with
assemblies 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 of LMRP 140, BOP 120, and
wellbore 101.
[0136] Once wellbore 101 is shut-in and generally under control,
and the necessary infrastructure for producing wellbore 101 are in
place (e.g., hydrocarbon storage vessels, risers, manifolds, flow
lines, etc. are installed), wellbore 101 may be produced via
flowback assembly 290 and/or conduit 235. In addition, injection
systems 240, 270 may be used prior to, during, or after shutting-in
wellbore 101 to inject chemicals into bores 224, 262, respectively,
and wellbore 101. Although FIGS. 30A-30P illustrate containment cap
200 being deployed and installed subsea on riser adapter 145,
installation of cap 200 on LMRP 140, wellhead 130, or BOP 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).
[0137] Referring now to FIG. 31, another embodiment of a
containment cap 400 for capping wellbore 101 previously described
(FIG. 4), and containing the hydrocarbon fluids therein is shown.
Containment cap 400 is similar to containment cap 200 previously
described. Namely, containment cap 400 is modular, and includes a
first or lower assembly 210 as previously described. For purposes
of clarity, frame 211, second pipe spool 230, chemical injection
system 240, and sensor system 226 of lower assembly 210 are not
shown in FIG. 31. Unlike cap 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 in main bore 224 of lower
assembly 210, and kill-flowback assembly 290 has been replaced with
a cap 470. Valve assembly 450 is releasably maintained within lower
assembly 210 by cap 470. Cap 470 is securely attached to lower
assembly 210 with an annular coupling member 480 that forms
wellhead-type connections 150 with cap 470 and lower assembly 210.
Assemblies 210, 450 function together to contain and shut-in
wellbore 101, whereas cap 470 facilitates the deliver of
kill-weight fluids to wellbore 101 as well as the production of
wellbore 101 once it is contained and controlled.
[0138] As previously described, lower assembly 210 is
air-freightable. In this embodiment, valve assembly 450, cap 470,
and coupling 480 are also air-freightable. Thus, lower assembly
210, valve assembly 450, cap 470, and coupling 480 are each sized
and configured to be transported by air on its own or with one or
more of assembly 210, assembly 450, cap 470, and coupling 480. In
other words, lower assembly 210, valve assembly 450, cap 470, and
coupling 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 with lower
assembly 210.
[0139] Referring still to FIG. 31, valve assembly 450 comprises a
tubular body 451 having a central or longitudinal axis 452, a first
or upper end 451a, a second or lower end 451b, and a throughbore
453 extending axially between ends 451a, b. Assembly 450 also
includes a pair of axially-spaced valves 454 disposed along
throughbore 453. Valves 454 control the flow of fluids through bore
453. Namely, each valve 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 along throughbore 453. Consequently, fluid flow through bore
453 is restricted and/or prevented if one or both valves 454 are
closed, and fluid flow through bore 453 is permitted if both valves
454 are opened. In general, each valve 454 may comprise any type of
valve suitable for the anticipated fluid pressures and fluids in
bore 453 including, without limitation, ball valves, gate valves,
and butterfly valves. Further, each valve 454 may be manually
actuated, hydraulically actuated, mechanically actuated, or
electrically actuated valves. In this embodiment, each valve 454 is
a hydraulically actuated ball valve rated for a 15 k psi pressure
differential. Each valve 454 may be controlled and actuated subsea
with an ROV. Alternatively, each valve 454 may be controlled from
the surface with hydraulic flow lines or flying leads extending
from the surface and coupled to valves 454 via a panel located on
lower assembly 210.
[0140] Valve assembly 450 is partially disposed within main bore
224--upper end 451a extends axially from bore 224, and lower end
451b is disposed in bore 224. An annular insert 460 is coaxially
disposed within bore 224 axially between assembly 450 and an
annular shoulder 224a within bore 224. Insert 460 has a first or
upper end 460a, a second or lower end 460b opposite end 460a, and a
flow passage 461 extending axially between ends 460a, b. Upper end
460a comprises a cylindrical recess or counterbore 462 that
receives lower end 451b, and lower end 460b comprises a reduced
outer diameter portion that extends into bore 224 below shoulder
224a. Thus, insert 460 is seated in bore 224 against shoulder 224a,
and tubular body 451 is seated in recess 462. A plurality of
annular seal assemblies 470 are radially disposed between tubular
body 451 and spool piece 222. Seal assemblies 470 restrict and/or
prevent fluids from flowing axially between body 451 and spool
piece 222.
[0141] Referring still to FIG. 31, cap 470 maintains valve assembly
450 in bore 224 with lower end 451b seated in insert 460. Cap 470
is coaxially aligned with bores 224, 453 and has a first or upper
end 470a, a second or lower end 470b, and a flow passage 471
extending axially between ends 470a, b. In this embodiment, upper
end 470a comprises an upward-facing flow line connection hub 239a
and lower end 470b comprises a downward-facing hub 150a. A
cylindrical recess or counterbore 472 extends axially from lower
end 470b and defines an annular shoulder 473 in passage 471.
Tubular member 451 extends into recess 472 and is seated against
shoulder 473. Ends 470b, 222a axially abut and are held together
with an annular coupling member 480. Specifically, coupling member
480 is disposed about ends 470b, 222a and includes an upward-facing
receptacle 150b releasably secured to hub 150a at end 470b to form
a wellhead-type connection 150 therebetween, and a downward-facing
receptacle 150b releasably secured to hub 150a at end 222a to form
a wellhead-type connection 150 therebetween. Upward-facing hub 239a
at upper end 470a releasably engages and interlocks a mating
receptacle at the lower end of a flow line for injecting kill
weight fluids into cap 400 and wellbore 101 or producing wellbore
101.
[0142] Containment cap 400 is deployed subsea and installed on
wellhead 130, BOP 120, or LMRP 140 to contain and shut-in wellbore
101, and/or produce wellbore 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 in lower assembly 210,
and cap 470 coupled to lower assembly 210 with coupling 480 at the
surface 102, and then the entire pre-assembled cap 400 lowered
subsea. To install cap 400 onto BOP 120, riser 115 is removed from
LMRP 140, and LMRP 140 is removed from BOP 120. Then, cap 400 is
lowered subsea on a pipestring 180 or wireline 181 coupled to hub
239a, and securely attached to BOP 120 with wellhead-type
connection 150. To install cap 400 onto wellhead 130, riser 115 is
removed from LMRP 140, LMRP 140 is removed from BOP 120, and BOP
120 is removed from wellhead 130. Then, cap 400 is lowered subsea
on a pipestring 180 or wireline 181 coupled to hub 239a, and
securely attached to wellhead 130 with wellhead-type connection
150. To install cap 400 onto LMRP 140, riser 115 is removed from
LMRP 140, then transition spool 330 is lower subsea and securely
attached to riser adapter 145 as previously described. Next, cap
400 is lowered subsea and securely attached to transition spool 330
with wellhead-type connection 150. In each case, cap 400 is
preferably lowered subsea laterally offset from wellbore 101 and
outside of plume 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 or more
ROVs 170 may be employed to facilitate the installment of cap
400.
[0143] Although cap 400 is preferably assembled at the surface 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 into cap 400 subsea. For instance,
lower assembly 210 may be lowered subsea and installed on wellhead
130, BOP 120, or transition spool 330 as previously described, and
then valve assembly 450 may be lowered subsea with wireline 181 or
pipestring 180, installed in bore 224, and secured to assembly 210
with cap 470 and annular coupling 480.
[0144] Referring still to FIG. 31, upon installation of containment
cap 400, hydrocarbons are free to flow through cap 400. To contain
and shut-in wellbore 101, valves 233 in bores 225, 232 and valves
454 in bore 453 are manipulated by subsea ROVs 170. To utilize kill
weight fluids in shutting in wellbore 101, a kill fluids supply
line is connected to hub 239a at upper end 470a of cap 470 prior to
initiating the shut-in procedures. However, if kill fluids are not
utilized to aid in shutting in wellbore 101, the shut-in procedures
may be initiated prior to installation of a flow line onto hub
239a.
[0145] To shut-in wellbore 101, valves 233 in flow lines 237, 238
are both closed, and valves 233 in bores 225, 232 are both
maintained opened while upper valve 454 is transitioned closed. As
upper valve 454 is transitioned closed, the pressure of wellbore
fluids within lower assembly 210 are monitored with pressure
transducer 226 and the pressure of wellbore fluids within upper
assembly 250 are monitored with pressure sensor 287. As long as the
formation fluid pressures within assemblies 210, 450 are within
acceptable limits, upper valve 454 continues to be closed until it
is fully closed. Once upper valve 454 is closed, lower valve 454
may also be fully closed to provide redundancy. With both valves
454 closed, fluid flow through bore 453 is restricted and/or
prevented, however, since valves 233 in bores 225, 232 are opened,
formation fluids are free to flow through bores 224, 225, 232, 236
and choke valve 234. Next, valve 233 in bore 232 is transitioned
closed. As that valve 233 is transitioned closed, the pressure of
wellbore fluids within lower assembly 210 are monitored with
pressure transducer 226. As long as the formation fluid pressures
within assembly 210 is within acceptable limits, valve 233 in bore
232 continues to be closed until it is fully closed. Once valve 233
in bore 232 is closed, valve 233 in bore 225 may also be fully
closed to provide redundancy. With each valve 233, 454 closed,
wellbore 101 is contained and shut-in. Accordingly, in this
embodiment, valves 454 of assembly 450 perform the same function(s)
as valves 263 of upper assembly 250 previously described. It should
be appreciated that inclusion of choke valve 234 and the staged
shut-in of wellbore 101 via sequential closure of valves 233, 454
enables a "soft" shut-in, thereby offering the potential to reduce
the likelihood of an abrupt formation pressure surge, which may
damage subsea components (e.g., BOP 120, assembly 210, assembly
450, assembly 290) and lead to another subsea blowout.
[0146] Once wellbore 101 is shut-in and generally under control,
and the necessary infrastructure for producing wellbore 101 are in
place (e.g., hydrocarbon storage vessels, risers, manifolds, flow
lines, etc. are installed), wellbore 101 may be produced via hub
239a at upper end 470a of cap 470 and/or conduit 235. For example,
depending on the particular circumstances, wellbore 101 may be
produced through cap 470 with valves 233 closed and valves 454
opened, produced through conduit 235 with valves 233 opened and
valves 454 closed, or produced through both cap 470 and conduit 235
with all valves 233, 454 opened.
[0147] As previously described, lower assembly 210 includes
chemical injection system 240. Injection systems 240 may be used
prior to, during, or after shutting-in wellbore 101 to inject
chemicals into bores 224, 453, respectively, and wellbore 101. For
example, chemicals such as glycol may be injected to reduce hydrate
formations within assemblies 210, 450.
[0148] 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.
[0149] Referring now to FIG. 32, an overview of a method 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 in block 501, a
suitable subsea landing site is identified. In the embodiment of
offshore system 100 previously described, subsea BOP 120 is mounted
to wellhead 130 at the sea floor 103 with a wellhead-type
connection 150, LMRP 140 is mounted to BOP 120 with wellhead-type
connection 150, flex joint 143 is mounted to LMRP 140 via mandrel
151, and riser 115 is coupled to riser adapter 145 with a flanged
connection. Thus, potential landing sites include riser adapter 145
of LMRP 140 following removal of riser 115, LMRP mandrel 151
following removal of flex joint 143, BOP 120 following removal of
LMRP 140, and wellhead 130 following removal of BOP 120. These
represent particularly suitable landing sites as the various
connections between these components may be decoupled subsea with
the aid of ROVs 170. The ultimate selection of the most desirable
landing site may vary from well-to-well and depends on a variety of
factors including, without limitation, the ease with which a
particular connection may be broken and re-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.
[0150] If the selected landing site is mandrel 151 of LMRP 140 or
riser adapter 145, the connection between riser 115 and riser
adapter 145 is broken, and riser 115 is removed from riser adapter
145 according to block 506. If the selected landing site is riser
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 is LMRP
mandrel 151, then flex joint 143 (including riser adapter 145) is
removed at block 535. Thereafter, appropriate transition spool
(e.g., transition spool 330), as needed, is deployed and installed
subsea on mandrel 151 at block 536. On the other hand, if the
selected landing site is BOP 120, riser 115 is removed from riser
adapter 145, connection 150 between LMRP 140 and BOP 120 is broken,
and LMRP 140 is removed from BOP 120 according to block 507. Still
further, if the selected landing site is wellhead 130, riser 115 is
removed from riser adapter 145, connection 150 between LMRP 140 and
BOP 120 is broken, LMRP 140 is removed from BOP 120, connection 150
between BOP 120 and wellhead 130 is broken, and BOP 120 is removed
from wellhead 130 according to block 508.
[0151] 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 150a) configured to mate and engage receptacle 150b at
lower end 222b, 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 engage receptacle 150b at lower end
222b, then a transition spool is necessary to transition from
receptacle 150b at lower end 222b to the particular type of
connector or hub at the landing site.
[0152] Moving now to block 515, before, during, or after
preparation of the landing site according to blocks 506, 507, 508,
the transition spool (e.g., transition spool 330) and the
containment cap components (e.g., assemblies 210, 250, 290 of
containment cap 200, or assemblies 210, 450, cap 470, and coupling
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.
[0153] Once the transition spool (if necessary) and the assemblies
of the containment cap 200, 400 have been transported to the
offshore site, they may be deployed and installed subsea to form
cap 200, 400 as previously described in block 520. Next, in block
525, wellbore 101 is contained and shut-in with containment cap
200, 400 as previously described. With wellbore 101 under control,
flowback assembly 290 and/or conduit 235 may be used to produce
wellbore 101 according to block 530.
[0154] Previously described was an embodiment in which a particular
transition spool 330 was employed in order to couple containment
cap 200 to riser 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 with receptacle 150b disposed at lower end 222b. However, in
other cases, the landing site may have a connector or hub with a
profile that is not compatible with receptacle 150b at lower end
222b. In such embodiments, a transition spool is employed to
transition between the connector profile at the landing site and
receptacle 150b at lower end 222b. Consequently, a variety of
differently configured transition spools are required to transition
between receptacle 150b at end 222b to the numerous connector
profiles at the landing site. This may be best explained with
reference to FIG. 33. As shown, lower marine riser package 140 is
releasably coupled to BOP 120 which, in turn, is releasably coupled
to wellhead 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-extending riser adapter 145A-145E,
respectively, that, in the normal course of drilling and
production, couples to a riser (not shown in FIG. 33). In the
situation where it is desirable to couple a containment cap 200,
400 to one of riser adapters 145A-145E, a differently-configured
transition spool is required in each instance.
[0155] More particularly, FIG. 33 shows five differently-configured
riser 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 that riser adapter 145A has a different configuration
than riser 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 the corresponding riser adapter 145A-145E.
Although the lower end of each transition spool 330A-330E is
different to accommodate a differently configured riser adapters
145A-145E, the upper end of each transition spool 330A-330E is
configured the same for engagement, in each instance, with a
containment cap of a uniform design. In this instance, each
transition spool 330A-330E includes a wellhead-type connection hub
150a at its upper end configured to mate and engage the
complementary female receptacle 150b at the lower end 222b of cap
200, 400 to form a standard wellhead-type connection 150.
[0156] Referring now to FIGS. 34 and 35, an embodiment of a
containment cap adapter or transition 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 150b at end 222b) to the
connection and associated connector profile at the landing site
(e.g., riser adapter 145, LMRP mandrel 151, hub 150a of BOP 120, or
hub 150a of wellhead 130). In this embodiment, transition spool 600
includes an upper portion or spool 610 and a lower portion or spool
620 coupled to upper spool 610. Upper spool 610 has a central axis
615, a first or upper end 610a, and a second or lower end 610b. In
addition, upper portion 610 includes a connector 611 at upper end
610a, an annular flange 613 at lower end 610b, and a tubular body
612 extending axially from connector 611 to flange 613. A through
bore 614 extends axially through spool 610 from upper end 610a to
lower end 610b. Flange 613 includes an annular planar facing
surface 616 having an annular groove 617 and a plurality of
circumferentially-spaced holes 618 extend axially therethrough.
Connector 611 at upper end 610a is configured to mate and sealingly
engage with the containment cap. Thus, for connection to
containment cap 200, 400 previously described, connector 611 is a
hub 150a configured to mate and sealingly engage complementary
receptacle 150b at lower end 222b of containment cap 200, 400.
[0157] Lower spool 620 has a central axis 625, a first or upper end
620a, and a second or lower end 620b. In addition, lower portion
620 includes an annular flange 621 at upper end 620a, a connector
624 at lower end 620b, a frustoconical body 622 extending axially
from flange 621, and a tubular body 623 extending from body 622 to
connector 624. A through bore 626 extends axially through spool 620
from upper end 620a to lower end 620b. Flange 621 is configured the
same as flange 613 previously described. In particular, flange 621
includes an annular planar facing surface 627 having an annular
groove (not shown) and a plurality of circumferentially-spaced
holes 629 extend axially therethrough. Connector 624 at lower end
620b 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.
[0158] To connect upper spool 610 to lower spool 620, an annular
seal 630 formed of inconel or other suitable material is positioned
in the annular grooves in facing surfaces 616, 627, spools 610, 620
are coaxially aligned, and flanges 613, 621 are pushed into
engagement with each other. With holes 618, 629 aligned, threaded
studs 631 and hex nuts 632 fasten together upper and lower spools
610, 620.
[0159] Referring now to FIGS. 36A-36N, different embodiments of
adapters 600A-600N are shown. Each adapter 600A-600N includes an
upper portion 610 as previously described and a lower portion
620A-620N, respectively. Thus, the same upper portion 610 is used
in each adapter 600A-600N, upper portion 610 including connector
611 configured to mate and sealingly engage the complementary
connector on the containment cap (e.g., receptacle 150b at lower
end 222b of containment 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 complementary female receptacle 150b at
lower end 222b of containment cap 200, 400, which is a female H4
connector, as available from GE Oil & Gas of Houston, Tex.
Flange 613 is an 183/4 in. API flange. Each lower portion 620A-620L
is the same as lower spool 620 previously described with the
exception that the connector 624A-624L, respectively, at each lower
end 620b is different to accommodate a different mating connector
650A-650L, respectively, at the landing site 651A-651L,
respectively. Lower portion 620M, 620N simply comprises a connector
624M, 624N, respectively, that is directly connected to flange 613
of upper portion 610 with bolts. In other words, connectors 624M,
624N do not include a frustoconical body 622 or tubular body 623 as
previously described. Connector 624M, 624N is different to
accommodate a different mating connector 650M, 650N, respectively,
at the landing site 651M, 651N, respectively. In general,
connectors 650A-650L and corresponding landing sites 651A-651L
described in more detail below are employed on riser adapters
(e.g., riser adapter 145), whereas connectors 650M, 650N and
corresponding landing sites 651M, 651N are employed on LMRPs (e.g.,
LMRP 130), BOPs (e.g., BOP 120), and wellheads (e.g., wellhead
130). Flange 621 of each lower spool 620A-620L is configured to
mate and engage flange 613, and the upper end of each connector
624M, 624N is configured to mate and engage flange 613.
Accordingly, since flange 613 is an 183/4 in. API flange, flange
621 of each lower spool 620A-620L is a mating 18 3/4 in. API
flange, and the upper end of each connector 624M, 624N is
configured to mate with an 183/4 in. API flange.
[0160] In FIG. 36A, connector 624A of lower portion 620A is a
female CLIP.TM. connector, as available from Aker-Kvaerner, having
a connector profile configured to mate and sealingly engage with
complementary connector 650A, which is a male CLIP.TM. connector,
as available from Aker-Kvaerner. In FIG. 36B, connector 624B of
lower portion 620B is a female Load King.TM. connector, as
available from Cameron International Corp., having a connector
profile configured to mate and sealingly engage with complementary
connector 650B, which is a male Load King.TM. connector, as
available from Cameron International Corp. In FIG. 36C, connector
624C of lower 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. In
FIG. 36D, connector 624D of lower portion 620D is a male MR-6H
connector, as available from Vetco Gray, Inc., having a connector
profile configured to mate and sealingly engage with complementary
connector 650D, which is a female MR-6H connector, as available
from Vetco Gray, Inc. In FIG. 36E, connector 624E of lower portion
620E is a female MR-6C connector, as available from Vetco Gray,
Inc., having a connector profile configured to mate and sealingly
engage with complementary connector 650E, which is a male MR-6C
connector, as available from Vetco Gray, Inc. In FIG. 36F,
connector 624F of lower portion 620F is a female MR-6D connector,
as available from Vetco Gray, Inc., having a connector profile
configured to mate and sealingly engage with complementary
connector 650F, which is a male MR-6D connector, as available from
Vetco Gray, Inc. In FIG. 36G, connector 624G of lower portion 620G
is a male HMF-G connector, as available from Vetco Gray, Inc.,
having a connector profile configured to mate and sealingly engage
with complementary connector 650G, which is a female HMF-G
connector, as available from Vetco Gray, Inc. In FIG. 36H,
connector 624H of lower portion 620H is a male HMF-D connector, as
available from Vetco Gray, Inc., having a connector profile
configured to mate and sealingly engage with complementary
connector 650H, which is a female HMF-D connector, as available
from Vetco Gray, Inc. In FIG. 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. In FIG. 36J,
connector 624J of lower 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
with complementary connector 650J, which is a male FT-GB connector,
as available from National Oilwell Varco, Inc. of Houston, Tex. In
FIG. 36K, connector 624K of lower portion 620K is a male RD
connector, as available from Cameron International Corp., having a
connector profile configured to mate and sealingly engage with
complementary connector 650K, which is a female RD connector, as
available from Cameron International Corp. In FIG. 36L, connector
624L of lower portion 620L is a female DT-2 connector, as available
from Shafer, having a connector profile configured to mate and
sealingly engage with complementary connector 650L, which is a male
DT-2 connector, as available from Shafer. In FIG. 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 with complementary connector 650M, which is a
male SHD H4 connector, as available from Cameron International
Corp. In FIG. 36N, connector 624N of lower 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.
[0161] 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 the well
head 130, on the BOP 120, on the mandrel 151 of LMRP 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 identical upper portions 610 and differing lower
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 or drilling 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 of transition 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 one containment 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.
[0162] Referring to FIG. 37, a storage facility 700 is
schematically represented and houses lower assembly 210, upper
assembly 250, and kill-flow back assembly 290, each as previously
described, in a condition to be readily shipped and assembled into
containment cap 200. Also maintained in inventory within storage
facility 700 is at least one of each of a plurality of adapters 600
(e.g., one or more of adapters 600A-600N) as might be needed to
connect containment cap 200 to any well head, BOP, LMRP mandrel, or
riser adapter in the geographic region for which the storage
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 attach cap 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 of adapters 600A-600N
(or other transition spools including different connectors) can be
included in facility 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 in storage 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 the containment cap 200 to a specific well component or
components) is selected, and deployed for transportation to the
well site along with containment cap assemblies 210, 250, 290 in
order to cap and contain the well. Having the modular containment
cap assemblies (e.g., assemblies 210, 250, 290) and all possible
adapters (e.g., 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. Although storage facility 700
shown in FIG. 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 of
containment cap 400 previously described (e.g., lower assembly 210,
valve assembly 450, and cap 470).
[0163] Referring now to FIG. 38, another storage facility 800 is
schematically represented and houses lower assembly 210, upper
assembly 250, and kill-flow back assembly 290 of containment cap
200, each as previously described. Further, an inventory is
maintained in facility 800 including at least one upper portion 610
(two being shown in this example) and each lower portion 620A-620F,
620M, and 620N of adapters 600A-600F, 600M, and 600N needed to
service the wells in the designated region. Again, it is to be
understood that lower portions 620A-620F, 600M, and 600N of adapter
600A-600F, 600M, and 600N, respectively, are merely examples of
possible transition spool lower portions. In general, any
combination of lower portions 620A-620N (or other lower portions
including different connectors) can be included in facility 800
depending on the structures of the wellheads, BOPs, LMRP mandrels,
and riser adapters in the geographic region of interest. Because
upper portion 610 of each adapter 600A-600F, 600M, and 600N is
identical in these embodiments, it is not necessary to inventory an
upper portion 610 for each of the adapter 600A-600F, 600M, and
600N. Instead, upon the need arising, the appropriate lower portion
620A-620F, 620M, 620N can be selected and attached to the upper
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 multiple upper portions 610 for each adapter 600A-600F,
600M, and 600N. Although storage facility 800 shown in FIG. 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 of containment cap 400
previously described (e.g., lower assembly 210, valve assembly 450,
and cap 470).
[0164] 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.
* * * * *