U.S. patent application number 13/457074 was filed with the patent office on 2013-02-28 for apparatus and methods for establishing and/or maintaining controlled flow of hydrocarbons during subsea operations.
This patent application is currently assigned to BP CORPORATION NORTH AMERICA INC.. The applicant listed for this patent is Pierre Albert Beynet, Douglas Paul Blalock, Kevin James Devers, Trent James Fleece, Kinton Lowell Lawler, Jason Edward Waligura. Invention is credited to Pierre Albert Beynet, Douglas Paul Blalock, Kevin James Devers, Trent James Fleece, Kinton Lowell Lawler, Jason Edward Waligura.
Application Number | 20130048295 13/457074 |
Document ID | / |
Family ID | 46085692 |
Filed Date | 2013-02-28 |
United States Patent
Application |
20130048295 |
Kind Code |
A1 |
Beynet; Pierre Albert ; et
al. |
February 28, 2013 |
APPARATUS AND METHODS FOR ESTABLISHING AND/OR MAINTAINING
CONTROLLED FLOW OF HYDROCARBONS DURING SUBSEA OPERATIONS
Abstract
A device for capturing hydrocarbons discharged from a subsea
flow passage comprises an elongate tubular structure having a
central axis, a first end, and a second end opposite the first end.
The second end is open and in fluid communication with the first
end. The tubular structure includes a rigid stabbing member
extending axially from the second end and configured to he inserted
into the flow passage. In addition, the device comprises an annular
flexible skirt disposed about the stabbing member. The skirt is
secured to the stabbing member and extends radially outward from
the stabbing member. The skirt is configured to flex from an
unflexed position to a flexed position upon insertion of the
stabbing member into the flow passage. The skirt is biased to the
unflexed position and has an outer diameter in the unflexed
position that is greater than the inner diameter of the flow
passage.
Inventors: |
Beynet; Pierre Albert;
(Houston, TX) ; Blalock; Douglas Paul; (Katy,
TX) ; Devers; Kevin James; (Katy, TX) ;
Fleece; Trent James; (Houston, TX) ; Lawler; Kinton
Lowell; (Fulshear, TX) ; Waligura; Jason Edward;
(Bellaire, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Beynet; Pierre Albert
Blalock; Douglas Paul
Devers; Kevin James
Fleece; Trent James
Lawler; Kinton Lowell
Waligura; Jason Edward |
Houston
Katy
Katy
Houston
Fulshear
Bellaire |
TX
TX
TX
TX
TX
TX |
US
US
US
US
US
US |
|
|
Assignee: |
BP CORPORATION NORTH AMERICA
INC.
Houston
TX
|
Family ID: |
46085692 |
Appl. No.: |
13/457074 |
Filed: |
April 26, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61479704 |
Apr 27, 2011 |
|
|
|
Current U.S.
Class: |
166/341 ;
166/344 |
Current CPC
Class: |
E21B 33/064 20130101;
E21B 43/0122 20130101 |
Class at
Publication: |
166/341 ;
166/344 |
International
Class: |
E21B 43/01 20060101
E21B043/01 |
Claims
1. A device for capturing hydrocarbons discharged from a subsea
flow passage having an inner diameter, the device comprising: an
elongate tubular structure having a central axis, a first end, and
a second end opposite the first end, wherein the second end is open
and in fluid communication with the first end; wherein the tubular
structure includes a rigid stabbing member extending axially from
the second end and configured to be inserted into the flow passage;
and an annular flexible skirt disposed about the stabbing member,
wherein the skirt is secured to the stabbing member and extends
radially outward from the stabbing member; wherein the skirt is
configured to flex from an unflexed position to a flexed position
upon insertion of the stabbing member into the flow passage,
wherein the skirt is biased to the unflexed position and has an
outer diameter in the unflexed position that is greater than the
inner diameter of the flow passage.
2. The device of claim 1, wherein the skirt is configured to
slidingly engage an inner surface defining the flow passage upon
insertion of the stabbing member into the flow passage and at least
partially block the flow of hydrocarbons from the flow passage.
3. The device of claim 2, wherein the tubular structure further
comprises a crossover member coupled to the stabbing member
configured to rotate about the central axis relative to the
stabbing member.
4. The device of claim 3, wherein the tubular structure further
comprises an adapter member extending from the first end to the
crossover member, wherein the adapter member includes a J-slot
connector configured to releasably engage the tie-back conduit.
5. The device of claim 2, wherein the second end comprises a
tapered mule-shoe.
6. The device of claim 2, further comprising a plurality of axially
spaced annular skirts disposed about the stabbing member, wherein
each skirt is secured to the stabbing member and extends radially
outward from the stabbing member; wherein each skirt is configured
to flex from an unflexed position to a flexed position upon
insertion of the stabbing member into the flow passage, wherein
each skirt is biased to the unflexed position and has an outer
diameter in the unflexed position that is greater than the inner
diameter of the flow passage.
7. The device of claim 6, wherein at least one skirt includes a
pair of axially adjacent annular discs secured to the stabbing
member, wherein each disc comprises a plurality of
circumferentially adjacent flaps defined by a plurality of
circumferentially spaced radial slits.
8. The device of claim 7, wherein the radial slits in each disc are
circumferentially misaligned.
9. The device of claim 2, and wherein the first end is configured
to be coupled to a lower end of a tie-back conduit extending
subsea.
10. The device of claim 9, wherein the tie-back conduit is a riser
or pipe string extending from the surface.
11. The device of claim 2, further comprising an ROV control panel
coupled to the tubular structure, and a plurality of flow lines
extending from the ROV control panel to the stabbing member;
wherein the flow lines are configured to inject a fluid into the
tubular structure.
12. The device of claim 2, wherein the tubular structure further
comprises: a connector member coupled to the stabbing member with a
first elbow; and a recovery member coupled to the connector member
with a second elbow; wherein the connector member is oriented at a
first angle .alpha. relative to the stabbing member and the
recovery member is oriented at a second angle .beta. relative to
the connector member, wherein angle .alpha. is between 30.degree.
and 90.degree. and angle .beta. is between 45.degree. and
180.degree..
13. The device of claim 12, wherein the recovery member is oriented
perpendicular to the stabbing member.
14. The device of claim 12, further comprising a stop plate
extending between the stabbing member and the connector member,
wherein the stop plate is configured to prevent impingement of the
tubular structure upon insertion of the stabbing member into the
flow passage.
15. The device of claim 12, further comprising a support arm
coupled to the connector, member, wherein the support arm is
oriented parallel to the recovery member and is configured to
support vertical loads upon insertion of the stabbing member into
the flow passage.
16. The device of claim 15, wherein the support arm is pivotally
coupled to the connector member.
17. The device of claim 12, further comprising a clamp coupled to
the connector member and disposed about the stabbing member.
18. The device of claim 2, further comprising a landing plate
disposed about the stabbing member, wherein the landing plate is
secured to the stabbing member and extends radially outward from
the stabbing member; wherein the skirt is axially positioned
between the landing plate and the second end, and wherein the
landing plate has an outer diameter greater than the outer diameter
of the skirt in the flexed position.
19. A method for capturing hydrocarbons discharged from a subsea
flow passage, the method comprising (a) lowering a hydrocarbon
collection tool subsea, the collection tool comprising a tubular
structure having a central axis, a first end, a second end, and a
stabbing member extending axially from the second end, wherein the
second end is open and in fluid communication with the first end;
(b) coupling a tie-back conduit to the first end of the collection
tool; (c) inserting the stabbing member into the subsea flow
passage; (d) flowing the hydrocarbons into the collection tool at
the second end; and (e) flowing the hydrocarbons through the
collection tool and the tie-back conduit to the surface.
20. The method of claim 19, further comprising: at least partially
blocking the flow of the hydrocarbons through the flow passage
during (d).
21. The method of claim 20, wherein the collection tool includes a
plurality of annular flexible skirts disposed about the stabbing
member, wherein each skirt is secured to the stabbing member and
extends radially outward from the stabbing member; wherein (c)
further comprises slidingly engaging an inner surface defining the
flow passage with the skirts.
22. The method of claim 21, wherein the skirts at least partially
block the flow of hydrocarbons through the flow passage during
(d),
23. The method of claim 19, further comprising: injecting a fluid
into the hydrocarbons flowing through the collection tool.
24. The method of claim 23, wherein the injected fluid is a hydrate
inhibitor, a wax inhibitor, an asphaltene inhibitor, a scale
inhibitors, a corrosion inhibitors, or an antideposition agent.
25. The method of claim 20, wherein (a) comprises lowering the
collection tool subsea from a surface vessel with the tie-back
conduit.
26. The method of claim 20, further comprising: lowering the
collection tool subsea outside of a plume formed by the discharged
hydrocarbons; aligning the collection tool with the flow passage;
moving the collection tool in a first direction beyond an outlet of
the flow passage; and moving the collection tool in a second
direction opposite the first direction to insert the stabbing
member into the flow passage.
27. The method of claim 20, wherein the flow of the hydrocarbons
through the flow passage during (d) is at least partially blocked
by an annular packer disposed about the stabbing member.
28. The method of claim 27, further comprising: radially expanding
the annular packer into engagement with an inner surface defining
the flow passage after (c).
29. A device for capturing hydrocarbons discharged from a subsea
flow passage having an inner diameter, the device comprising: an
elongate tubular structure having a central axis, a first end, and
a second end opposite the first end, wherein the second end is open
and in fluid communication with the first end; wherein the tubular
structure includes a rigid stabbing member extending axially from
the second end and configured to be inserted into the flow passage;
and an annular packer disposed about the stabbing member, wherein
the packer is secured to the stabbing member and extends radially
outward from the stabbing member; wherein the packer is configured
to radially expand from a retracted position to an expanded
position upon insertion of the stabbing member into the flow
passage, wherein the packer has an outer diameter in the retracted
position that is less than the inner diameter of the flow
passage.
30. The device of claim 29, wherein the packer is configured to
sealingly engage an inner surface defining the flow passage and at
least partially block the flow of hydrocarbons from the flow
passage.
31. The device of claim 30, wherein the tubular structure further
comprises a crossover member coupled to the stabbing member and
configured to rotate about the central axis relative to the
stabbing member.
32. The device of claim 31, wherein the tubular structure further
comprises an adapter member extending from the first end to the
crossover member, wherein the adapter member includes a J-slot
connector configured to releasably engage the tie-back conduit.
33. The device of claim 30, wherein the second end comprises a
tapered mule-shoe.
34. The device of claim 30, and wherein the first end is configured
to be coupled to a lower end of a tie-back conduit extending
subsea.
35. The device of claim 30, wherein the tie-back conduit is a riser
or pipe string extending from the surface.
36. The device of claim 30, further comprising an ROV control panel
coupled to the tubular structure, and a plurality of flow lines
extending from the ROV control panel to the stabbing member;
wherein the flow lines are configured to inject a fluid into the
tubular structure.
37. The device of claim 30, further comprising a plurality of
circumferentially spaced ribs coupled to the stabbing member,
wherein the ribs are axially positioned between the second end and
the packer, and wherein the ribs extend radially outward from the
stabbing member to an outer diameter that is greater than the outer
diameter of the packer in the retracted position and less than the
inner diameter of the flow passage.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. provisional patent
application Ser. No. 61/479,704 filed Apr. 27, 2011, and entitled
"Apparatus for Use In Establishing and/or Maintaining Controlled
Flow of Hydrocarbons During Subsea Operations," 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 apparatus and methods for
flowing hydrocarbons from a subsea conduit to the surface. More
particularly, the invention relates to apparatus and methods for
intervening in subsea conduits such as risers to flow hydrocarbons
to the surface while minimizing the formation of hydrocarbon gas
hydrates.
[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 (also referred to
as "mud") is delivered through the drill string, and returned up an
annulus between the drill string and tubular casing that lines the
well bore. In the event of a rapid influx of formation fluid into
the annulus, commonly known as a "kick," the BOP and/or LMRP may
actuate to seal the annulus and control the well. In particular,
BOPs and LMRPs comprise closure members capable of sealing and
closing the well in order to prevent the release of high-pressure
gas or liquids from the well. Thus, the BOP and LMRP are used as
safety devices that close, isolate, and seal the wellbore. Heavier
drilling mud may be delivered through the drill string, forcing
fluid from the annulus through the choke line or kill line to
protect the well equipment disposed above the BOP and LMRP from the
high pressures associated with the formation fluid. Assuming the
structural integrity of the well has not been compromised, drilling
operations may resume. However, if drilling operations cannot be
resumed, cement or heavier drilling mud is delivered into the well
bore to kill the well.
[0008] In the event that the BOP and LMRP fail to actuate or
insufficiently actuate in response to a surge of formation fluid
pressure in the annulus, a blowout may occur. The blowout may
damage subsea well equipment and hardware such as the BOP, LMRP, or
drilling riser. 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 remedy the situation remotely,
as the damage may be hundreds or thousands of feet below the sea
surface.
[0009] In the event that a subsea blowout results in the discharge
of hydrocarbons into the surrounding sea, it is important to
capture the emitted hydrocarbons at the subsea source as quickly as
possible in order to minimize the volume of hydrocarbons discharged
in the sea water. One approach is to cap and shut-in the subsea
well by lowering a containment cap and connecting it to the upper
end of the equipment stack that is connected to the well bore
(e.g., LMRP or BOP). However, this procedure may take time to
complete, especially if it requires the removal of a damaged subsea
riser before landing the cap. During such time, hydrocarbons may be
discharged into the surrounding sea from the damaged subsea
riser.
[0010] Accordingly, there is a need in the art for apparatus and
methods to capture hydrocarbons from a damaged subsea riser or
conduit. Such apparatus and methods would be particularly
well-received if they offered the potential to capture hydrocarbons
discharged from a subsea riser or conduit, and flow the captured
hydrocarbons to the surface while minimizing the formation of
hydrates.
BRIEF SUMMARY OF THE DISCLOSURE
[0011] These and other needs in the art are addressed in one
embodiment by a device for capturing hydrocarbons discharged from a
subsea flow passage. In an embodiment, the device comprises an
elongate tubular structure having a central axis, a first end, and
a second end opposite the first end. The second end is open and in
fluid communication with the first end. The tubular structure
includes a rigid stabbing member extending axially from the second
end and configured to be inserted into the flow passage. In
addition, the device comprises an annular flexible skirt disposed
about the stabbing member. The skirt is secured to the stabbing
member and extends radially outward from the stabbing member. The
skirt is configured to flex from an unflexed position to a flexed
position upon insertion of the stabbing member into the flow
passage. The skirt is biased to the unflexed position and has an
outer diameter in the unflexed position that is greater than the
inner diameter of the flow passage.
[0012] These and other needs in the art are addressed in another
embodiment by a method for capturing hydrocarbons discharged from a
subsea flow passage. In an embodiment, the method comprises (a)
lowering a hydrocarbon collection tool subsea, the collection tool
comprising a tubular structure having a central axis, a first end,
a second end, and a stabbing member extending axially from the
second end. The second end is open and in fluid communication with
the first end. In addition, the method comprises (b) coupling a
tie-back conduit to the first end of the collection tool. Further,
the method comprises (c) inserting the stabbing member into the
subsea flow passage. Still further, the method comprises (d)
flowing the hydrocarbons into the collection tool at the second
end. Moreover, the method comprises (e) flowing the hydrocarbons
through the collection tool and the tie-back conduit to the
surface.
[0013] These and other needs in the art are addressed in another
embodiment by a device for capturing hydrocarbons discharged from a
subsea flow passage. In an embodiment, the device comprises an
elongate tubular structure having a central axis, a first end, and
a second end opposite the first end. The second end is open and in
fluid communication with the first end. The tubular structure
includes a rigid stabbing member extending axially from the second
end and configured to be inserted into the flow passage. In
addition, the device comprises an annular packer disposed about the
stabbing member. The packer is secured to the stabbing member and
extends radially outward from the stabbing member. The packer is
configured to radially expand from a retracted position to an
expanded position upon insertion of the stabbing member into the
flow passage. The packer has an outer diameter in the retracted
position that is less than the inner diameter of the flow
passage.
[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 a schematic view of the offshore drilling system
of FIG. 1 damaged by a subsea blowout;
[0018] FIG. 3 is a side view of an embodiment of a tool for
capturing hydrocarbons from a subsea conduit;
[0019] FIG. 4 is an enlarged partial side perspective view of the
tool of FIG. 3;
[0020] FIG. 5 is an enlarged cross-sectional view of the cross-over
member of FIG. 3;
[0021] FIG. 6 is a front view of the ROV access panel of the tool
of FIG. 3;
[0022] FIG. 7 is a cross-sectional view of the first elbow of FIG.
3 illustrating the position of two flow lines along the inside the
tool of FIG. 3;
[0023] FIGS. 8A and 8B are partial perspective views of the tool of
FIG. 3 mounted in an embodiment of a support frame;
[0024] FIG. 9 is a side view of an embodiment of a tool for
capturing hydrocarbons from a subsea conduit;
[0025] FIGS. 10A-10E are partial perspective views of the tool of
FIG. 9 mounted in an embodiment of a support frame;
[0026] FIG. 11 is a side view of an embodiment of a tool for
capturing hydrocarbons from a subsea conduit;
[0027] FIG. 12 is a rear view of the tool of FIG. 11;
[0028] FIGS. 13A-13H are sequential schematic illustrations of an
embodiment of a method for deploying the tool of FIG. 3, FIG. 9, or
FIG. 11;
[0029] FIGS. 14A-14F are schematic illustrations of alternative
applications of embodiments disclosed herein;
[0030] FIG. 15 is a side view of an embodiment of a tool for
capturing hydrocarbons from a subsea conduit;
[0031] FIGS. 16A-16D are sequential schematic illustrations of an
embodiment of a method for deploying the tool of FIG. 15; and
[0032] FIG. 17 is a side view of an embodiment of a tool for
capturing hydrocarbons from a subsea conduit.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0033] The following discussion is directed to various exemplary
embodiments. However, one skilled in the art will understand that
the examples disclosed herein have broad application, and that the
discussion of any embodiment is meant only to be exemplary of that
embodiment, and not intended to suggest that the scope of the
disclosure, including the claims, is limited to that
embodiment.
[0034] 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.
[0035] In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ." Also, the term "couple" or "couples" is intended to mean
either an indirect or direct connection. Thus, if a first device
couples to a second device, that connection may be through a direct
connection, or through an indirect connection via other devices,
components, and connections. In addition, as used herein, the terms
"axial" and "axially" generally mean along or parallel to a central
axis (e.g., central axis of a body or a port), while the terms
"radial" and "radially" generally mean perpendicular to the central
axis. For instance, an axial distance refers to a distance measured
along or parallel to the central axis, and a radial distance means
a distance measured perpendicular to the central axis, Still
further, as used herein the terms "hydrocarbon gas hydrates,"
"hydrates," and "hydrocarbon hydrates" refer to hydrates formed
from hydrocarbon gases selected from the group consisting of
methane, ethane, propane, butane, isobutane, isobutene and mixtures
thereof.
[0036] 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. Platform 110 is equipped with a derrick 111 that
supports a hoist (not shown), A drilling riser 115 extends from
platform 110 to LMRP 140. In general, riser 115 is a large-diameter
pipe that connects LMRP 140 to the floating platform 110. During
drilling operations, riser 115 takes mud returns to the platform
110. Casing 131 extends from wellhead 130 into subterranean
wellbore 101.
[0037] 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.
[0038] 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 Cameron International
Corporation 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--opposed blind shear rams or blades 127 for severing
tubular string 116 and sealing off wellbore 101 from riser 115 and
opposed pipe rams 129 for engaging string 116 and sealing the
annulus around tubular string 116, and may include opposed blind
rams 128 for sealing off wellbore 101 when no string (e.g., string
116) or tubular extends through 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.
[0039] 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.
[0040] 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. 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.
[0041] Referring now to FIG. 2, during a "kick" or surge of
formation fluid pressure in wellbore 101, one or more rams 127,
128, 129 of BOP 120 and/or LMRP 140 are normally actuated to seal
in wellbore 101. If wellbore 101 is not sealed, a blowout may
result. Such a blowout may result in the discharge of such
hydrocarbon fluids subsea. In FIG. 2, system 100 is shown after a
subsea blowout. In the exemplary blowout scenario shown in FIG. 2,
riser 115 and drillstring 116 have been severed subsea 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 through the end
of riser 115 disposed along the sea floor 103. The emitted
hydrocarbon fluids form a subsea hydrocarbon plume 160. Embodiments
of hydrocarbon capture apparatus and methods described in more
detail below are designed to capture the hydrocarbons flowing
through riser 115, thereby reducing the subsea discharge of
hydrocarbon fluids.
[0042] Referring now to FIG. 3, an embodiment of a device or tool
200 for capturing hydrocarbons from a subsea conduit is shown. Tool
200 is an elongate tubular structure or assembly having a central
or longitudinal axis 205, an open upper end 200a, and a lower open
end 200b in fluid communication with end 200a. Starting at end 200b
and moving axially towards end 200a, in this embodiment, tool 200
includes a stabbing member 210 extending from end 200b, a connector
member 220 coupled to stabbing member 210 with a first elbow 270, a
recovery member 230 coupled to connector member 220 with a second
elbow 275, and an adapter member 250 extending from end 200a and
coupled to recovery member 230 with a crossover member 240. Each
member 210, 220, 230, 240, 250 and each elbow 270, 275 is a rigid
tubular conduit coaxially aligned with tool axis 205, and thus,
each may also be referred to as a conduit. Accordingly, a
continuous flow passage extends through tool 200 from end 200a to
end 200b. In this embodiment, each member 210, 220, 230 has the
same inner and outer diameters, however, crossover member 240
provides a transition from recovery member 230 to a larger inner
and outer diameter adapter member 250. In other embodiments, the
stabbing member. (e.g., member 210) has a smaller inner and outer
diameter than the remaining conduits of the tool (e.g., connector
member 220 and recovery member 230) to facilitate insertion of the
stabbing member into a subsea conduit.
[0043] Each tubular member 210, 220, 230 is linear (i.e., straight)
between its respective ends, however, members 210, 220, 230 are not
collinear (i.e., members 210, 220, 230 do not extend along the same
straight line). Consequently, central axis 205 is linear along each
respective member 210, 220, 230, but includes bends between members
210, 220, 220. In particular, first elbow 270 orients connector
member 220 at an angle .alpha. relative, to stabbing member 210,
and second elbow 275 orients recovery member 230 at an angle
.alpha. relative to connector member 220. Angle .alpha. and angle
.beta. are preferably selected so that stabbing member is coaxially
aligned with the end of the conduit discharging hydrocarbons when
recovery member 230 is vertically oriented. For most applications,
angle .alpha. is preferably between 30.degree. and 90.degree. and
angle .beta. is preferably between 45.degree. and 180.degree.. In
this embodiment, angle .alpha. is 45.degree. and angle .beta. is
130.degree.. Thus, recovery member 230 is generally oriented
perpendicular to stabbing member 210.
[0044] To enhance visibility subsea, any one or more of members
210, 220, 230, 240, 250 and elbows 270, 275 may be painted a color
that contrasts with the color of the surrounding water, which is
usually very dark (black) at subsea depths. For example, these
components may be painted white or yellow. Reflective tape or other
light-reflective element(s) may also be provided on one or more of
these components.
[0045] Referring now to FIGS. 3 and 4, stabbing member 210 extends
axially from end 200b to elbow 270. A plurality of axially spaced
annular diaphragms or skirts 211 are disposed about stabbing member
210 between end 200b and elbow 270. Skirts 211 are fixed to
stabbing member 210 such that skirts 211 do not move axially along
stabbing member 210 or rotate about stabbing member 210. Each skirt
211 extends radially outward from stabbing member 210 and comprises
a flexible, resilient material. Examples of suitable materials far
skirts 211 include natural or synthetic rubber (e.g., thermoplastic
elastomers), which may be filled with fillers (e.g., carbon black)
and/or other additives to improve flexibility, elastic properties,
resistance to erosion or saltwater attack, and the like. As will he
described in more detail below, stabbing member 210 is inserted
into a conduit or flow passage discharging hydrocarbons subsea to
capture the hydrocarbons before they roach the surrounding sea.
Upon insertion of stabbing member 210 into the subsea conduit or
passage, skirts 211 slidingly engage and conform to the inner
surface of the conduit as well as the outer surfaces of any other
components disposed within the conduit (e.g., a drillpipe disposed
within a riser), thereby forming a barrier that restricts and/or
prevents the discharge of the hydrocarbons into the surrounding sea
and directing the hydrocarbons into stabbing member 210 and tool
200 at end 200b. Thus, each skirt 211 has an unflexed position
prior to insertion into the subsea conduit or passage and a flexed
position after insertion into the subsea conduit or passage. The
resilient material(s) from which skirts 211 are made causes skirts
211 to be biased to the unflexed position shown in FIGS. 3 and 4.
In the unflexed position, each skirt 211 has an outer diameter
greater than the inner diameter of the subsea conduit or passage,
and in the flex position, each skirt 211 has an outer diameter
equal to the inner diameter of the subsea conduit or passage as the
skirt slidingly engages the inner surface of the conduit or passage
upon insertion therein.
[0046] In the embodiment shown in FIGS. 3 and 4, each skirt 211
comprises a pair of axially adjacent, annular discs 212 secured to
stabbing member 210. Each disc 212 comprises a plurality of
circumferentially adjacent strips or flaps 213 defined by radial
slits or cuts 214. Inclusion of slits 214 enhances the flexibility
of discs 212 and skirts 211. Discs 212 of each skirt 211 are
preferably oriented such that slits 214 are circumferentially
mis-aligned (i.e., out of alignment) to minimize the flow of fluids
through slits 214. Although each skirt 211 includes two discs 212
in this embodiment, in general, each skirt (e.g., skirt 211) may
comprise any suitable number of discs (e.g., discs 212) such as
one, two, three, or more discs.
[0047] Stabbing member 210 has a stabbing tip 217 at end 200b. In
this embodiment, tip 217 is generally perpendicular to axis 205.
However, in other embodiments, the tip of the stabbing member
(e.g., tip 217 of stabbing member 210) may be tapered or comprise a
muleshoe to facilitate its insertion into a subsea conduit.
[0048] Referring still to FIGS. 3 and 4, a stop plate 215 extends
between stabbing member 210 and connector member 220 along the
inside of elbow 270 and a mud cutting plate 271 extends along the
outside of elbow 271 generally away from stabbing member 210. Each
plate 215, 271 lies in a plane containing axis 205.
[0049] Stop plate 215 functions as webbing that adds rigidity and
structural support to members 210, 220 by restricting and/or
preventing tool 200 from flexing at elbow member 270 under load. In
addition, when stabbing member 210 is inserted into an end of a
conduit discharging hydrocarbons subsea, stop plate 215 provides a
rigid buffer between any sharp edges on the end of the conduit
being serviced and elbow 270, thereby reducing and/or eliminating
the potential for the end of the conduit to impact and puncture or
damage elbow 270. In this embodiment, stop plate 215 includes a
notch or recess 216 configured to receive the end of the conduit
being serviced with tool 200. Seating of the end of the conduit in
notch 216 offers the potential to stabilize the position of
stabbing member 210 within the conduit by limiting relative
movement of stabbing member 210 and tool 200 relative to the
conduit.
[0050] Mud plate 271 enhances the ability of tool 200 and elbow 270
to penetrate the sea floor as necessary during subsea hydrocarbon
capture operations. In addition, once penetrated into the seafloor,
mud plate 271 provides lateral stability to tool 200 by resisting
lateral movement of tool 200 relative to the sea floor.
[0051] Referring still to FIGS. 3 and 4, connector member 220
extends axially between elbows 270, 275. A support or stabilizer
arm 221 is pivotally coupled to connector member 220 between elbows
270, 275. In particular, arm 221 has a first or pivot end 221a
rotatably coupled to connector member 220 and a second or free end
221b opposite end 221a. End 221a is coupled to connector member 220
with a mounting bracket 222 Welded to connector member 220 and a
pin 223 extending through end 221a and bracket 222. Pin 223 is
oriented perpendicular to the plane containing tool axis 205. Thus,
arm 221 pivots about pin 223 within a plane that contains or is
parallel to tool axis 205. In this embodiment, a conduit engagement
plate or member 224 is pivotally coupled to end 221b and is
configured to engage and grip the outer surface of the subsea
conduit being serviced when stabbing member 210 is inserted
therein, thereby providing additional support and stability to tool
200 during subsea hydrocarbon capture operations. For example,
engagement of plate 224 with the subsea conduit offers the
potential to resist forces seeking to push tool 200 out of the
conduit.
[0052] As best shown in FIG. 4, a stopper or bumper 225 is secured
to connector member 220 between bracket 222 and elbow 270 to
prevent arm 221 and conduit engagement member 224 from
unintentionally impinging and damaging connector member 220. In
addition, a lifting eye 226 is welded to connector member 220
proximal elbow 270 to facilitate transport and deployment of tool
200.
[0053] Referring now to FIGS. 3 and 5, crossover member 240
rotatably connects recovery member 230 and adapter member 250. In
other words, crossover member 240 allows adapter member 250 to
rotate relative to recovery member 230 about axis 205. In addition,
crossover member 240 provides a transition from recovery member 230
and adapter member 250, which has a larger inner and outer diameter
than recovery member 230. For example, crossover member 240 may
provide a connection between a 4-inch (10 cm) diameter recovery
member 230 and a 6 5/8-inch (17 cm) adapter member 250.
[0054] As best shown in FIG. 5, in this embodiment, crossover
member 240 includes an annular adapter sleeve 241 secured to the
upper end of recovery member 230 and a coupling member 242
rotatably coupled to sleeve 241. In particular, sleeve 241 is
threaded onto the upper end of recovery member 230 and has a
radially outer cylindrical surface 243 including an annular recess
or groove 244. Coupling member 242 has a first or upper end 242a
and a second or lower end 242b. In addition, coupling member 242
includes a counterbore 245 extending axially from lower end 242b
and an internally threaded box end connector 246 at upper end 242a.
Counterbore 245 defines a radially inner surface 247 that glidingly
engages surface 243 of sleeve 241. In addition, a plurality of
circumferentially spaced head caps 248 extend radially through
coupling member 232 and into sliding engagement with recess 244. In
this embodiment, head caps 248 are threaded through radial bores in
coupling member 242. Connector 246 threadably receives a mating pin
end connector at the lower end of adapter member 250, thereby
rotatably coupling adapter member 230 to recover member 250.
[0055] A pair of axially spaced annular seal assemblies 248 are
provided between sleeve 241 and coupling member 242 to restrict
and/or prevent fluid flow between sleeve 241 and coupling member
242. In this embodiment, each seal assembly 248 includes au annular
recess or seal gland 249a in outer surface 243 and an annular seal
member 249b (e.g., O-ring) disposed therein. Thus, seal member 249b
forms an annular static seal with sleeve 241 and an annular dynamic
seal with coupling member 242.
[0056] Referring again to FIG. 3, adapter member 250 functions to
connect tool 200 to a deployment tool, a retrieval tool, a tie back
system of fluid conduit (e.g., pipestring extending from the
surface), or combinations thereof. In this embodiment, adapter
member 250 comprises a J-slot connector for releasably coupling
tool 200 to a lower end of such tools or conduits. As is known in
the art, a J-slot connector is a releasable connection that allows
the transfer of rotational torque. In general, the J-slot connector
in adapter member 250 may be a right-hand or left hand J-slot
connector. In addition, the J-slot connector in adapter member 250
may include a shear pin for disconnecting in an emergency
situation, such as a surface vessel drive-off. Although member 250
comprises a J-slot connector in this embodiment, in general, the
adapter member (e.g., member 250) may comprise any suitable
releasable subsea connector for connecting the hydrocarbon capture
tool (e.g., tool 200) to the lower end of another tool or conduit
such as a connector that attaches and releases through only
relative vertical movement. Another example of a suitable subsea
connector that may be employed for the adapter member is an OPTIMA
connector available from Vector Subsea, Inc. of Houston, Tex.
[0057] Referring now to FIGS. 3 and 6, hydrocarbon capture tool 200
also includes an ROV access panel 280 mounted to recovery member
230 between crossover member 240 and elbow 275. The face of panel
280 is oriented at an angle between 30.degree. and 90.degree.
relative to horizontal to enhance visualization of and access to
panel 280 with a subsea ROV. In this embodiment, panel 280 includes
U-shaped handles 281, a plurality of control handles 282a, b, c and
a plurality of receptacles 283a, b, c (e.g., hot stabs) associated
with handles 282a, b, c, respectively. Handles 281 facilitate the
positioning of tool 200 by personnel at the surface and by ROVs
subsea. Each paddle 282a, b, c operates a corresponding valve
(disposed behind panel 280) to control the flow of fluids through
flow lines 284a, b, c, respectively. As shown in FIGS. 4 and 6,
flow lines 284a, b extend from panel 280 along the outside of
recovery member 230 and connector member 220 to elbow 270, and flow
line 284c extends from panel 280 along the outside of recovery
member 230, connector member 220, elbow 270, and stabbing member
210 to end 200b. As best shown in FIG. 4, along stabbing member
210, flow line 284c may extend under skirts 211 in route to end
200b. Flow lines 284a, b, c can be secured to recovery member 230,
connector member 220, elbow 275, elbow 270, stabbing member 210, or
combinations thereof with retainers 285.
[0058] The end of each flow line 284a, b distal panel 280 extends
through the sidewall of elbow 270 into the interior of tool 200 as
shown in FIG. 7, and the end of flow line 284c distal panel 280
extends through the sidewall of stabbing member 210 into the
interior of tool 200 proximal end 200b. During subsea hydrocarbon
capture operations, flow lines 284a, b, c may be used to inject a
functional fluid (e.g., hydrate inhibitors) into tool 200 and the
captured hydrocarbons flowing therethrough.
[0059] In this embodiment, panel 280 includes a receptacle 283a, b,
c for each paddle 282a, b, c, respectively, and flow line 284a, b,
c, respectively. Receptacles 283a, b, c may comprise any suitable
connection for coupling a fluid line to panel 280 including,
without limitation, API 17H hot stab connectors. The valves in
panel 280 controlled by paddles 281a, b, c control the flow of
fluids between receptacles 283a, b, c, respectively, and lines
284a, b, c. Thus, fluids can he supplied to lines 284a, b, c
through receptacles 283a, b, c, respectively, and the corresponding
valves.
[0060] Referring now to FIGS. 8A and 8B, a support structure or
frame 290 for supporting tool 200 during transport of tool 200 is
shown. For purposes of clarity, one skirt 211 is not shown in FIG.
8A. Support frame 290 includes a horizontal foundation or base
platform 291 and an elongate pipe stand 292 extending vertically
therefrom. Platform 291 includes a plurality of lifting handles 293
and a plurality of support stanchions or brackets 294. Stabbing
member 210 is seated in a semi-circular notch in each bracket 294,
recovery member 230 is seated in a clamp 295 mounted to stand 292,
and adapter member 250 is seated in a clamp 295 mounted to stand
292. Brackets 294 and clamps 295 help support and maintain, the
position of tool 200 within frame 290.
[0061] Referring now to FIGS. 9 and 10A-10E, another embodiment of
a device or tool 300 for capturing hydrocarbons from a subsea
conduit is shown. In FIGS. 10A-10E, tool 300 is shown supported by
support structure 290 previously described during transport of tool
300.
[0062] Tool 300 is substantially the same as tool 200 previously
described. Namely, tool 300 includes members 210, 220, 230, 240,
250 and elbows 270, 275, each as previously described. However, in
this embodiment, the inner and outer diameters of members 220, 230
and elbows 270, 275 are increased relative to stabbing member 210.
For example, in tool 200 previously described, the nominal pipe
size of each member 210, 220, 230, and elbows 270, 275 is 4.0''
(.about.10 cm). However, in tool 300, member 210 has a nominal pipe
size of 4.0'' 10 cm), but members 220, 230 and elbows 270, 275 have
a nominal pipe size of 6.0'' (.about.15 cm). In general, increasing
the diameters of members 220, 230 and elbows 270, 275 increases
strength and rigidity of tool 300 in that tool 300 can resist large
vertical forces up or down. However, in this embodiment, tip 217 is
tapered or mule-shoe shaped, a support plate 327 is provided
between connector member 220 and recovery member 230, and a
vertical support assembly 331 is provided.
[0063] Support plate 327 lies in a plane containing axis 205 and
functions as webbing that adds rigidity and structural support to
members 220, 230 by restricting and/or preventing tool 300 from
flexing at elbow member 275 under load. In addition, support plate
327 provides a surface for assisting in routing flow lines 284a, b,
c. Tapered tip 217 facilitates the insertion of stabbing member 210
into a subsea conduit.
[0064] Support assembly 331 includes a base frame 332 mounted to
elbow 275 and connector member 220 and a support leg 333 removably
coupled to frame 332 with a pin 334. Frame 332 and leg 333 extend
vertically downward from elbow 275 and member 220 and are generally
vertically aligned with recovery member 240. The lower end of leg
333 comprises a saddle 335, which is sized and shaped to engage and
rest on the outside of the subsea conduit being serviced, thereby
providing a direct support path for vertical loads on tool 300. By
removing pin 334, different sized legs 333 may be provided in
assembly 331 to accommodate differently sized subsea conduits.
[0065] Referring now to FIGS. 11 and 12, another embodiment of a
device or tool 400 for capturing hydrocarbons from a subsea conduit
is shown. Tool 400 is substantially the same as tool 300 previously
described. Namely, tool 400 includes members 210, 220, 230, 240,
250 and elbows 270, 275, each as previously described. However, in
this embodiment, stabilizer arm 221 is eliminated and support
assembly 331 has been replaced with a different vertical support
assembly 431.
[0066] Support assembly 431 includes a frame 432 mounted to elbow
275 and connector member 220 and a hoop clamp 435 mounted to frame
432. Frame 432 comprises a vertical member 433a extending downward
from elbow 275 and vertically aligned with recovery member 240 and
a horizontal member 433b extending from member 433a to connector
member 220. The lower end of member 433a comprises a saddle 335 as
previously described. Hoop clamp 435 is coupled to member 433b and
hangs downward therefrom. Clamp 435 is hydraulically actuated to
engage and. grip the subsea conduit being serviced following
insertion of stabbing member 210. More specifically, clamp 435 is
open to receive the conduit as stabbing member 210 is inserted and
advanced into the conduit. After insertion of stabbing member 210,
clamp 435 is hydraulically actuated (e.g., with a subsea ROV) to
close around and engage the outside of the conduit, thereby
securing tool 400 to the conduit. Clamp 435 is preferably
positioned a few feet from the end of the subsea conduit. With
stabbing member 210 disposed within the conduit, saddle 335 resting
atop the conduit, and clamp 435 secured about the conduit, tool 400
may be left alone for an extended period of time. In general, clamp
435 may be any clamp known in the art for grasping the outside of
tubulars such as are used in pipeline applications to grip and
align pipe segments for splicing and/or repairs.
[0067] Referring now to FIGS. 13A-13I, the deployment of a tool
200' to capture hydrocarbons discharged from a subsea riser 115
previously described is schematically shown. Tool 200' is the same
as tool 200 previously described except that tool 200' includes a
tapered muleshoe at tip 217 and only two axially spaced skirts 211.
The open end of severed riser 115 is disposed along the sea floor
103 with severed drillstring 116 extending therethrough.
[0068] For subsea deployment and implementation of tool 200', one
or more remote operated vehicles (ROVs) are preferably employed to
aid in positioning the tool (e.g., tool 200'), monitoring the tool
and the conduit, and actuating subsea hardware (e.g., handles 282a,
b, c, clamp 435, etc.). In this embodiment, ROVs 170 are employed
to perform these functions. Each ROV 170 includes an arm 171 having
a claw 172, a subsea camera 173 for viewing the subsea operations.
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.
[0069] Referring first to FIGS. 13A and 13B, tool 200' is
controllably lowered subsea. In general, tool 200' may be lowered
on the end of a pipe string (e.g., drillstring or riser) or with
wireline. One or more buoyancy devices (e.g., buoyancy tanks) may
be coupled to tool 200' during deployment to counteract the weight
of tool 200', thereby decreasing the loads applied to the wireline
or pipe string and facilitating easier manipulation of tool 200'
with ROVs 170. During deployment, tool 200' is preferably
maintained outside of plume 160 of hydrocarbon fluids emitted from
wellbore 101 to enhance visibility and reduce the potential for the
formation of hydrates within tool 200'. As tool 200' approaches
riser 115, it is oriented such that stabbing member 210 is
positioned above and aligned parallel to riser 115 as shown in FIG.
13B.
[0070] Moving now to FIGS. 13C and 13D, with stabbing member 210
just above and aligned with riser 115, tool 200' is moved parallel
to riser 115 until tip 217 is about 3 ft. (.about.90 cm) beyond the
end of riser 115, and then lowered such that stabbing member 210 is
generally coaxially aligned with riser 115 but radially spaced from
string 116. Next, as shown in FIGS. 13E and 13F, tool 200' is moved
towards the end of riser 115 to insert tip 217 into the severed end
of riser 115 and axially advance stabbing member 210 therein. As
best shown in FIGS. 13E and 13H, as stabbing member 210 is advanced
into riser 115, flexible skirts 211 conform to inside surface of
riser 115 and the outside surface of string 116, thereby
restricting and/or preventing the flow of hydrocarbons from riser
115 into the surrounding sea. Thus, skirts 211 block the flow of
hydrocarbons out of the end of riser 115, and direct the
hydrocarbons to flow into end 200b and through tool 200 to end
200a. With stabbing member 210 sufficiently seated within riser
115, locking arm 221 may be pivoted to bring engagement plate 224
into engagement with the outside of riser 115 to help secure tool.
200' thereto.
[0071] Moving now to FIG. 13G, to maintain the position of tool
200' and reduce the potential for seawater external riser 115 to
mix with hydrocarbons flowing through riser 115 into tool 200', one
or more barriers 190 may be placed over and around the end of riser
115 and tool 200. For example, sandbags, rocks, chert, berms,
tarps, or combinations thereof may be placed around tool 200' and
the end of riser 115. As best shown in the cross-sectional end view
of tool 200 disposed within riser 11.5 of FIG. 13H any one or more
of fluid lines 284a, b, c may be used to inject various fluids and
chemicals (e.g., hydrate inhibitors, wax inhibitors, asphaltene
inhibitors, scale inhibitors, corrosion inhibitors, antideposition
agents, and combinations thereof) into the hydrocarbons flowing
through tool 200',
[0072] Referring now to FIG. 13I, the hydrocarbons flowing through
tool 200' are produced to the surface via a tic-back conduit 180
that extends from tool 200' to a surface vessel 181, which may be a
drill ship such as an MODU or other vessel such as a drilling rig.
The hydrocarbons may he temporarily stored before being offloaded
and shipped to a designated oil terminal onshore. In general,
tie-back conduit 180 may be the pipe string used to deploy tool
200', a pipe string coupled to tool 200' (via adapter member 250)
after deployment, or other conduit (e.g., flexible hose) coupled to
tool 200' (via adapter member 250) before or after deployment.
[0073] As previously described, tool 200' may be lowered subsea
with wireline or with a pipe string (e.g., drillstring, riser,
etc.). During deployment with a pipe string, a low-density fluid
(e.g., nitrogen) is preferably pumped down the pipe string and
through tool 200' to limit the formation of hydrates within tool
200' and the pipe string. Following insertion of stabbing member
210 into the subsea conduit (e.g., riser 115), the flow of
hydrocarbons up tool 200' and the pipe string are established by
gradually reducing the flow of the low-density fluid through tool
200'.
[0074] If tool 200' is deployed with wireline, the tic-back conduit
is coupled to tool 200' subsea. In such a scenario, tool 200' may
be deployed before, after, or at substantially the same time as the
tie-back conduit. Further, once tool 200' and the tie-back conduit
are coupled subsea, the tie-back conduit can be used to pick up and
manipulate the position of tool 200. Seawater in the tie-back
conduit and tool 200' is preferably flushed with a low-density
fluid such as nitrogen, and once the low-density flushing fluid is
observed bubbling of tip 217, the installation of tool 200 may
continue as previously described.
[0075] Although the deployment of an exemplary tool 200' is shown
in FIGS. 13A-13I and described above, the embodiments of
hydrocarbon capture tools described herein (e.g., tools 200, 300,
400) are deployed in the same manner. Further, the methods
described above for deploying tool 200' with a pipe string or
wireline and utilizing a low-density fluid to reduce the potential
for the hydrate formations may be used with any of the embodiments
disclosed herein (e.g., tools 200, 300, 400).
[0076] Referring still to FIG. 13I, in one exemplary deployment of
tool 200', stabbing member 210 of tool 200' has a 4.0 in.
(.about.10 cm) diameter and a 5 ft. length (.about.150 cm). Riser
115 has a 21.0 in. diameter (.about.53 cm) and is disposed on the
sea floor 103 at a depth of 5,000 ft. (.about.1500 m). The severed
end of riser 115 is about 600 ft. (.about.180 m) from wellhead 130
and BOP 120. Tie-back conduit 180 is a new riser connected to tool
200', and flows hydrocarbons from tool 200' to surface vessel 181
for processing. Thus, tie-back conduit 180 has a length of about
5,000 ft. (.about.1500 m). The system is designed to minimize the
formation of gas hydrates at the 5,000 ft. (.about.1500 m) depth.
In particular, flow lines 284a, b inject methanol into tool 200' to
limit the formation of gas hydrates in the ultra-deep water.
Tie-hack conduit 180 conveys hydrocarbons to surface vessel 181,
which is configured to process 15,000 barrels of oil per day
(.about.2400 m.sup.3/day) and store 139,000 barrels (.about.22,000
m.sup.3). A support barge may be deployed with a capacity to store
137,000 barrels of oil (.about.22,000 m.sup.3).
[0077] In the manner previously described, embodiments of tools
described herein (e.g., tools 200, 200', 300, 400) may be employed
to capture hydrocarbons discharged from a damaged subsea riser 115
containing a severed drillstring 116. However, embodiments
described herein may also he used to capture hydrocarbons flowing
through/from other subsea conduits, pipes, and flow lines. FIGS.
14A-14F schematically illustrate other exemplary applications of
tools described herein. The tools shown in FIGS. 14A-14F are
deployed in substantially the same manner previously described, but
are used to capture hydrocarbons discharged from subsea components
other than severed risers. In particular, FIG. 14A schematically
illustrates an embodiment of a tool 500 in accordance with the
principles described herein inserted into a subsea pipeline 500 to
collect and capture hydrocarbons flowing therethrough.
[0078] In FIG. 14B, an embodiment of a tool 500' in accordance with
the principles described herein is shown capturing hydrocarbons
flowing through a flexible gooseneck 501 coupled to a subsea
wellhead 130'. Gooseneck 501 supplies hydrocarbons from wellhead
130' to a subsea manifold (not shown), but in this case, has a
leaking area 502 that is discharging hydrocarbons into the
surrounding sea water. To capture hydrocarbons from gooseneck 501
and reduce and/or eliminate the discharge of hydrocarbons into the
sea water, stabbing member 210 of tool 500' is stabbed into area
502 until skirt 211 engages the outside of gooseneck 501, thereby
forming a partial seal that restricts the discharge of hydrocarbons
from leaking area 502.
[0079] In FIG. 14C, an embodiment of a tool 500'' in accordance
with the principles described herein is shown capturing
hydrocarbons flowing through a surface vessel 505 from a damaged
area 506 disposed below the sea surface 102. To capture
hydrocarbons from area 506 and reduce and/or eliminate the
discharge of hydrocarbons into the sea water, stabbing member 210
of tool 500'' is stabbed into area 506 until skirt 211 engages the
outside of vessel 505, thereby forming a partial seal that
restricts the discharge of hydrocarbons from area 506. Tool 500''
is fluidly connected to processing equipment 507 on vessel 505.
[0080] In FIG. 14D, an embodiment of a tool 500''' in accordance
with the principles described herein is inserted into a subsea
riser access conduit 510 extending from a riser 511, which has been
obstructed by a hydrate plug 512. With tool 500''' sufficiently
seated in conduit 510, a valve 513 in conduit is opened to allow
tool 500''' to collect and capture hydrocarbons flowing through
conduit 510. In FIG. 14E, an embodiment of a tool 500'''' in
accordance with the principles described herein is inserted into a
riser 515 through an access port 516, which may be cut into riser
515 or result from damage to riser 515. Again, in this embodiment,
skirt 211 forms at least a partial seal against the external
surface of riser 515.
[0081] In FIG. 14F, an embodiment of a tool 500''''' in accordance
with the principles described herein is shown capturing
hydrocarbons flowing through a subsea manifold 520 that has
suffered a leak in an area 521 of a conduit 522. Leaking area 521
may be the result of damage or corrosion. If there is no valve in
header 523 to isolate the leaking conduit 522, tool 500''''' may be
employed in a similar manner as was previously described with
respect to FIG. 14E. Namely, stabbing member 210 is inserted
through the leaking area 521 into conduit 522 until skirt 211
engages the outside of conduit 522 and forms at least a partial
seal against the external surface of conduit 522.
[0082] In the alternative applications shown in FIGS. 14A-14F and
described above, the portion of stabbing member 210 inserted into
the hydrocarbon discharge site may be varied as appropriate (e.g.,
only a short length of stabbing member 210 may be inserted). In
addition, the diameter of stabbing member 210 and skirts 211 may be
varied depending on size of the discharge site (e.g., leaking area
or damage).
[0083] As previously described, one or more small diameter flow
lines (e.g., flow lines 284a, b, c) may be used to deliver one or
more functional fluids into the interior of the tool (e.g., tool
200, 200', 300, 400, etc.) or exterior of the tool. Such functional
fluids may include, without limitation, hydrate inhibitors, wax
inhibitors, asphaltene inhibitors, scale inhibitors, corrosion
inhibitors, antideposition agents, combinations of two or more
thereof, and the like. Suitable hydrate inhibitors include, without
limitation, alcohols (such as methanol, ethanol, and the like) and
glycols (such as ethylene glycol, propylene glycol, and the like,
and mixtures of glycols). An important property of propylene glycol
is its ability to lower the freezing point of water. Solutions of
inhibited propylene glycol (propylene glycol containing a corrosion
inhibitor) may also be employed. Suitable corrosion inhibitors
include, without limitation, amides, quaternary ammonium salts,
rosin derivatives, amines, pyridine compounds, trithione compounds,
heterocyclic sulfur compounds, alkyl mercaptans, quinoline
compounds, polymers of any of these, and mixtures thereof Suitable
scale inhibitors include, without limitation, phosphate esters,
polyacrylates, phosphonates, polyacrylamides, polysulfonated
polycarboxylates, copolymers thereof, and mixtures thereof.
Examples of scale and corrosion inhibitors are described in U.S.
Pat. No. 7,772,160, which is hereby incorporated herein by
reference in its entirety. Suitable asphaltene inhibitors include,
without limitation, ester and ether reaction products, such esters
formed from the reaction of polyhydric alcohols with carboxylic
acids; ethers formed from the reaction of glycidyl ethers or
epoxides with polyhydric alcohols; and esters formed from the
reaction of glycidyl ethers or epoxides with carboxylic acids, as
described in U.S. Pat. No. 6,313,367, which is hereby incorporated
herein by reference in its entirety. In certain embodiments, a
chemical may contribute more than one of the functions of wax,
corrosion, and scale inhibition, and dispersant action. For
example, U.S. Pat. No. 6,313,367 discloses compositions that may
function as asphaltene deposition inhibitors and dispersants.
[0084] The flow rate of the injected chemical(s) depends on the
specific situations. In general, the flow rate of an injected
hydrate inhibitor is preferably in the range of 0.5 to about 1.0
volumetric units of inhibitor chemical to volumetric units of water
that is expected to mix with the hydrocarbons. For example, the
flow rate of hydrate inhibitor such as methanol may range from
about 2.0 to about 15.0 gallons per minute, or from about 6.0 to
about 8.0 gallons per minute.
[0085] Another approach to reduce the potential for hydrate
formation is to reduce and/or eliminate contact between the
hydrocarbons and the sea water. Skirts 211 provide a barrier
between the hydrocarbons and the seawater, but may not form a
perfect annular seal (i.e., some hydrocarbons and/or water may flow
past skirts 211). Accordingly, in some embodiments, one or more
radially expanding bladder (e.g., packer) may be included on the
stabbing member (e.g., stabbing member 210) to form an annular seal
between the stabbing member and conduit into which the stabbing
member is inserted. Use of an expanding bladder is particularly
suited to subsea conduits that do not include other objects or
structures (e.g., pipes) that may obstruct or impact the ability of
the expanding bladder to form an annular seal with the inside of
the conduit. In addition, such packers offer the potential for a
high pressure seal and can function as anchors that maintain the
position of the stabbing member within the subsea conduit. A
hydraulic supply line extending from the ROV panel along the device
can provide hydraulic pressure to actaute the packer. In other
embodiments, an annular seal between the stabbing member and
conduit may be formed with a plug (e.g., mud or cement) inserted
into the annulus between the stabbing member and conduit rearward
of the stabbing tip (e.g., tip 217) and at least one skirt (e.g.,
skirt 211).
[0086] Following insertion of the stabbing member (e.g., stabbing
member 210) into the conduit discharging hydrocarbons, a chemical
dispersant may be introduced in the vicinity of any escaping
(non-captured) hydrocarbons mixing with seawater. Dispersants, if
used, are preferably mixed only with oil that is not captured,
since adding dispersant to oil that is captured may be
counter-productive, making oil/water separation very difficult.
Examples of suitable chemical dispersants are listed in Table 1
below and are available from Nalco Company, Naperville, Ill.,
USA.
TABLE-US-00001 TABLE 1 Ingredients in COREXIT .RTM. 9500 and 9527
brand dispersants CAS Registry Number Chemical Name 57-55-6
1,2-Propanediol 111-76-2 Ethanol, 2-butoxy-* 577-11-7 Butanedioic
acid, 2-sulfo-, 1,4-bis(2-ethylhexyl) ester, sodium salt (1:1)
1338-43-8 Sorbitan, mono-(9Z)-9-octadecenoate 9005-65-6 Sorbitan,
mono-(9Z)-9-octadecenoate, poly(oxy-1,2-thanediyl) derivs.
9005-70-3 Sorbitan, tri-(9Z)-9-octadecenoate,
poly(oxy-1,2-ethanediyl) derivs 29911-28-2 2-Propanol,
1-(2-butoxy-1-methylethoxy)- 64742-47-8 Distillates (petroleum),
hydrotreated light *Note: This chemical component is not included
in the composition of COREXIT 9500.
[0087] Embodiments of tools previously described (e.g., tools 200,
200', 300, 400, etc.) are generally designed for insertion into a
horizontal or substantially horizontal subsea conduit (i.e.,
oriented at an angle between 0.degree. and about 45.degree. from
horizontal). However, embodiments described herein may be
configured for insertion into a subsea conduit that is vertical or
substantially vertical (i.e., oriented at an angle between about
45.degree. and 90.degree. from horizontal). Referring now to FIG.
15, an embodiment of a device or tool 600 for capturing
hydrocarbons from a vertical or substantially vertical subsea
conduit is shown. Tool 600 is an elongate tubular structure or
assembly having a central or longitudinal axis 605, an open upper
end 600a, and an open lower end 600b in fluid communication with
end 600a. Starting at end 600b and moving axially towards end 600a,
in this embodiment, tool 600 includes a stabbing member 610
extending from end 600b, and an adapter member 250 coupled to the
upper end of stabbing member 610 with a crossover member 240.
Adapter member 250 and crossover member 240 are each as previously
described. In this embodiment, axis 605 is generally vertical and
linear between ends 600a, b.
[0088] Each member 610, 240, 250 is a tubular conduit coaxially
aligned with tool axis 605. Thus, a continuous flow passage extends
through tool 600 from end 600a to end 600b. Crossover member 240
provides a transition from member 610 to a larger inner and outer
diameter adapter member 250. To enhance visibility subsea, any one
or more of members 610, 240, 250 may be painted a color that
contrasts with the color of the surrounding water, which is usually
very dark (black) at subsea depths. For example, these components
may be painted white or yellow. Reflective tape or other
light-reflective element(s) may also be provided on one or more of
these components.
[0089] Referring still to FIG. 15, stabbing member 610 extends
axially from end 600b to crossover member 240 and is rotatably
coupled to crossover member 240 as previously described. A rigid
annular landing plate 611 is mounted to stabbing member 610 and a
plurality of axially spaced annular diaphragms or skirts 211 as
previously described are disposed about stabbing member 610 between
end 600b and plate 611. Skirts 211 and plate 611 are fixed to
stabbing member 610 such that skirts 211 and plate 611 do not move
axially along stabbing member 610 or rotate about stabbing member
610. Skirts 211 are designed to slidingly engage and conform to the
inner surface of the conduit being serviced as previously
described. However, plate 611 is landed upon and engages the upper
end of the conduit being serviced to prevent tool 600 from falling
therethrough and providing an additional barrier to the discharge
of hydrocarbons from the conduit and influx of sea water into the
conduit. Stabbing member 610 has a stabbing tip 617 at end 600b. In
this embodiment, tip 617 is a tapered muleshoe to facilitate
insertion into a subsea conduit.
[0090] Hydrocarbon capture tool 600 also includes an ROV access
panel 280 as previously described coupled to stabbing member 610
between plate 611 and crossover member 240. However, in this
embodiment, panel 280 is radially spaced away from stabbing member
610 and axis 605 to position panel 280 outside the hydrocarbon
plume during insertion of stabbing member 610 into a vertical or
substantially vertical conduit. Flow lines 284a, b, c (not shown in
FIG. 15) extend from panel 280 to stabbing member 610, downward
along the outside of stabbing member 610, and through the sidewall
of member 610 into the interior of tool 600 between plate 611 and
tip 617. During subsea hydrocarbon capture operations, flow lines
284a, b, c may be used to inject a functional fluid (e.g., hydrate
inhibitors) into tool 600 and the captured hydrocarbons flowing
therethrough.
[0091] Referring now to FIGS. 16A-16D, the deployment of tool 600
to capture hydrocarbons discharged from a vertical subsea conduit
650 is schematically shown. For subsea deployment and
implementation of tool 600, one or more ROVs 170 as previously
described are preferably employed to aid in positioning tool 600,
monitoring tool 600 and conduit 650, and actuating subsea hardware
(e.g., handles 282a, b, c, etc.).
[0092] Referring first to FIGS. 16A and 16B, tool 600 is
controllably lowered subsea. In general, tool 600 may be lowed on
the end of a pipe string (e.g., drillstring or riser) or with
wireline. During deployment, tool 600 is preferably maintained
outside of plume 160 of hydrocarbon fluids emitted from conduit 650
to enhance visibility and reduce the potential for the formation of
hydrates within tool 600. Tool 600 is lowered laterally offset from
conduit 650 until tip 617 is immediately above the upper end of
conduit 650.
[0093] Moving now to FIG. 16C, tool 600 is moved laterally over
conduit 650 with stabbing member 610 substantially coaxially
aligned with conduit 650. Next, as shown in FIG. 16D, tool 600 is
lowered to insert tip 617 into the end of conduit 650 and axially
advance stabbing member 610 therein. Tool 600 is lowered under its
own weight until plate 611 axially abuts and engages the upper end
of conduit 650, thereby preventing further advancement of stabbing
member into conduit 650. As stabbing member 610 is advanced into
conduit 650, flexible skirts 211 conform to inside surface of
conduit 650 and any structures therein (e.g., a drillpipe, etc.),
thereby restricting and/or preventing the flow of hydrocarbons from
conduit 650 into the surrounding sea. In addition, plate 611 forms
an additional barrier at the upper end of conduit 650. Thus, skirts
211 and plate 611 at least partially block the flow of hydrocarbons
out of the end of conduit 650, and direct the hydrocarbons to flow
into end 600b and through tool 600 to end 600a.
[0094] The hydrocarbons flowing through tool 600 are produced to
the surface via a tie-back conduit in the manner previously
described. In addition, a low-density fluid such as nitrogen may be
pumped through tool 600 in the manner previously described to
reduce the potential for hydrate formations during deployment of
tool 600.
[0095] Referring now to FIG. 17, another embodiment of a device or
tool 700 for capturing hydrocarbons from a vertical or
substantially vertical subsea conduit is shown. Tool 700 is the
same as tool 600 previously described except that tool 700 does not
include plate 611 or skirts 211 disposed about stabbing member 610.
Rather, in this embodiment, an annular packer 710 is mounted to
stabbing member 610 and a plurality of circumferentially-spaced
ribs 730 are disposed about stabbing member 610 between packer 720
and tip 617.
[0096] In general, packer 710 may be any annular packer known in
the art that is hydraulically actuated to expand radially outward
into sealing engagement with a tubular within which it is disposed
(e.g., BOP throughbore, riser, pipeline, etc.). In FIG. 17, packer
710 is shown in the radially retracted "run in" position (solid
line) and the radially expanded "sealing" position (dashed line).
Packer 710 may he actuated via a hydraulic line extending from
control panel 280 or other subsea hydraulic power source.
[0097] Ribs 730 function to protect packer 710 during insertion and
advancement of stabbing member 610 and packer 710 into a subsea
conduit. In this embodiment, four uniformly circumferentially
spaced ribs 730 are disposed about stabbing member 610. Each rib
730 extends to an outer radius that is greater than the outer
radius of packer 710 in the retracted position, but less than the
outer radius of packer 710 in the expanded position.
[0098] Tool 700 is deployed in the same manner as tool 600
previously described except that tool 700 relies on packer 710 to
anchor it to the subsea conduit and seal between stabbing member
610 and the conduit. In particular, tool 700 is lowered subsea and
inserted into the subsea conduit with packer 710 in the retracted
position. Ribs 720 precede and shield packer 710 during insertion
of stabbing member 610 into the conduit being serviced. With packer
710 sufficiently disposed within the conduit, it is actuated to
expand radially outward into sealing engagement with the conduit,
thereby directing hydrocarbons flowing through the conduit into
tool 700 at tip 617.
[0099] In the manner described, embodiments described herein
provide means for capturing hydrocarbons discharged subsea. In
general, embodiments of tools described herein may be used fix
insertion into and collection of hydrocarbons emanating subsea from
any of a variety of subsea components or devices, such as risers,
drill pipes, a BOP, wellheads or connections thereto, manifolds,
transfer pipelines, lower marine riser packages (LMRP), lower riser
assemblies (URA), upper riser assemblies (URA), goosenecks or wing
valve assemblies, underwater portions of surface vessels,
underwater vessels, underwater containers (such tanks), and the
like. Such tools include features (e.g., skirts, diaphragms,
packers, etc.) that provide a barrier to the undesirable subsea
contact of hydrocarbons and sea water. Since water is a necessary
ingredient in formation of hydrates, this offers the potential to
mitigate hydrate formation. In addition, the releasable connection
of a tie-back conduit to embodiments described herein enables the
captured hydrocarbons to be flowed to a surface vessel.
[0100] 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.
* * * * *