U.S. patent application number 13/144461 was filed with the patent office on 2012-10-18 for systems and methods for subsea gas storage installation and removal.
This patent application is currently assigned to HORTON WISON DEEPWATER, INC.. Invention is credited to Lyle D. Finn, Edward E. Horton, III, James V. Maher.
Application Number | 20120260839 13/144461 |
Document ID | / |
Family ID | 44305673 |
Filed Date | 2012-10-18 |
United States Patent
Application |
20120260839 |
Kind Code |
A1 |
Maher; James V. ; et
al. |
October 18, 2012 |
SYSTEMS AND METHODS FOR SUBSEA GAS STORAGE INSTALLATION AND
REMOVAL
Abstract
A method for deploying a gas storage vessel below the surface of
the water comprises coupling an upper end of the gas storage vessel
to a deployment apparatus positioned at the surface of the water.
The gas storage vessel has a total dry weight and a lower end
opposite the upper end. The gas storage vessel also includes a
storage tank defining an inner region inside the tank and an
exterior region outside the tank. In addition, the method comprises
lowering the gas storage vessel below the surface of the water with
the deployment apparatus. Further, the method comprises pumping a
buoyancy control gas into the inner region of the tank. The
buoyancy control gas in the inner region of the tank generates a
buoyancy force acting on the gas storage vessel.
Inventors: |
Maher; James V.; (Houston,
TX) ; Horton, III; Edward E.; (Houston, TX) ;
Finn; Lyle D.; (Sugar Land, TX) |
Assignee: |
HORTON WISON DEEPWATER,
INC.
Houston
TX
|
Family ID: |
44305673 |
Appl. No.: |
13/144461 |
Filed: |
January 20, 2010 |
PCT Filed: |
January 20, 2010 |
PCT NO: |
PCT/US10/21445 |
371 Date: |
August 17, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61292274 |
Jan 5, 2010 |
|
|
|
Current U.S.
Class: |
114/257 ;
405/210 |
Current CPC
Class: |
F17C 2201/0119 20130101;
F17C 2205/0184 20130101; F17C 2221/033 20130101; F17C 2201/0166
20130101; F17C 2250/032 20130101; F17C 2201/018 20130101; F17C
2260/042 20130101; F17C 2201/032 20130101; B65D 90/046 20130101;
B65D 88/08 20130101; F17C 2203/0663 20130101; F17C 2223/0123
20130101; B65D 2590/046 20130101; B65D 88/78 20130101; F17C
2203/013 20130101; F17C 2205/0142 20130101; F17C 2201/0109
20130101; F17C 2201/0185 20130101; F17C 2203/0639 20130101; F17C
2223/0161 20130101; F17C 2270/0128 20130101; F17C 2201/054
20130101; F17C 2227/0192 20130101; F17C 3/005 20130101; F17C
2203/012 20130101 |
Class at
Publication: |
114/257 ;
405/210 |
International
Class: |
B65D 88/78 20060101
B65D088/78; B63B 9/08 20060101 B63B009/08 |
Claims
1. A method for deploying a gas storage vessel below the surface of
the water, comprising: (a) coupling an upper end of the gas storage
vessel to a deployment apparatus positioned at the surface of the
water, wherein the gas storage vessel has a total dry weight and a
lower end opposite the upper end, and wherein the gas storage
vessel includes a storage tank defining an inner region inside the
tank and an exterior region outside the tank; (b) lowering the gas
storage vessel below the surface of the water with the deployment
apparatus; and (c) pumping a buoyancy control gas into the inner
region of the tank during (b), wherein the buoyancy control gas in
the inner region of the tank generates a buoyancy force acting on
the gas storage vessel during (b).
2. The method of claim 1, further comprising: (d) ensuring the dry
weight of the gas storage vessel minus the buoyancy force is
greater than zero and less than a maximum load capacity of the
deployment apparatus during (b).
3. The method of claim 2, wherein the deployment apparatus has a
maximum load capacity, and wherein (d) further comprises ensuring
the dry weight of the gas storage vessel minus the buoyancy force
is less than the maximum load capacity of the deployment
apparatus.
4. The method of claim 2, wherein the subsea gas storage vessel
further comprises: a first inlet adapted to flow a stored gas into
the inner region; a second inlet adapted to flow the buoyancy
control gas into the inner region; a port in fluid extending
through the tank and in communication with the inner region and the
outer region; a first valve adapted to control the flow of the
stored gas through the first inlet; and a second valve adapted to
control the flow of the buoyancy control gas through the second
inlet.
5. The method of claim 4, wherein the second valve is open during
(c), and (c) further comprises pumping the buoyancy control gas
from the surface of the water through the second valve and the
second inlet into the inner region of the tank.
6. The method of claim 5, wherein the subsea gas storage vessel
further comprises a first outlet adapted to exhaust the buoyancy
control gas from the inner region to the outer region and a third
valve adapter to control the flow of the buoyancy control gas
through the first outlet; wherein the third valve is closed during
(c).
7. The method of claim 6, wherein the first outlet is disposed at
the upper end.
8. The method of claim 4, wherein (c) further comprises allowing
water to flow freely through the port between the inner region and
the outer region during (b).
9. The method of claim 1, wherein (a) further comprises coupling a
pipestring to the upper end of the gas storage vessel, wherein the
pipestring has a longitudinal axis and extends from the gas storage
vessel to the deployment apparatus; and wherein (b) further
comprises lowering the gas storage vessel with the pipestring.
10. The method of claim 9, wherein the pipestring includes an
in-line damping device.
11. The method of claim 9, wherein (a) further comprises coupling a
supply line to the second inlet, wherein the supply line extends
from the deployment apparatus to the gas storage vessel, and
wherein (c) further comprises pumping the buoyancy control gas from
the surface down the supply line, through the second valve and the
second inlet into the inner region of the tank.
12. The method of claim 11, wherein (c) further comprises pumping
water along with the buoyancy control gas down the supply line,
through the second valve and the second inlet into the inner region
during (b).
13. The method of claim 11, further comprising resisting the
rotation of the pipestring and the gas storage vessel about the
longitudinal axis during (b).
14. The method of claim 9, wherein the deployment apparatus
includes a derrick that supports the pipestring and the gas storage
vessel, and lowers the gas storage vessel subsea.
15. The method of claim 1, wherein the deployment apparatus
includes a crane that supports the gas storage vessel and lowers
the gas storage vessel below the surface of the water.
16. The method of claim 6, further comprising: (e) anchoring the
gas storage vessel to the sea floor after (b).
17. The method of claim 16, wherein (e) relying on gravity to
anchor the gas storage vessel to the sea floor or utilizing piles
to anchor the gas storage vessel to the sea floor.
18. The method of claim 16, wherein (e) comprises: (e1) engaging
the sea floor with the lower end of the gas storage vessel; (e2)
closing the second valve; (e3) opening the third valve; and (e4)
exhausting the buoyancy control gas from the inner region of the
tank to the outer region through the third valve and the first
outlet.
19. The method of claim 18, wherein (e) further comprises: (e5)
allowing water to flow through the port into the inner region
during (e4).
20. The method of claim 19, wherein the gas storage vessel includes
a mud skirt at the lower end, and a ballast chamber containing
ballast between the tank and the mud skirt, and wherein (e) further
comprises (e6) penetrating the sea floor with the mud skirt.
21. The method of claim 20, wherein (e) further comprises (e7)
increasing suction between the lower end of the gas storage vessel
and the sea floor.
22. The method of claim 19, further comprising (f) storing the gas
in the gas storage tank.
23. The method of claim 22, wherein (f) comprises: (f1) opening the
first valve; (f2) flowing the gas through the first valve and the
first inlet into the gas storage tank.
24. The method of claim 23, wherein the gas storage vessel further
comprises a flexible gas storage bag disposed in the gas storage
tank, wherein the gas storage bag has a gas inlet in fluid
communication with the first inlet.
25. The method of claim 24, wherein (f) further comprises: (f3)
flowing the gas through the first valve, the first inlet, and the
gas inlet into the flexible gas storage bag.
26. The method of claim 25, wherein (f) further comprises: (f4)
displacing water in the tank with the gas flowing into the flexible
gas storage bag; (f5) flowing water through the port from the inner
region to the outer region.
27. A method, comprising: (a) disposing a gas storage vessel on the
sea floor, wherein the gas storage vessel has an upper end distal
the sea floor and a lower end engaging the sea floor and includes a
gas storage tank defining an inner region inside the tank and an
exterior region outside the tank, and wherein the gas storage tank
includes a first inlet in fluid communication with the inner
region, a first valve that controls the flow of fluid through the
first inlet, and a port in fluid communication with the inner
region and the exterior region; (b) pumping a buoyancy control gas
through the first valve and first inlet into the inner region to
generate a buoyancy force acting on the gas storage vessel; (c)
displacing water in the inner region with the buoyancy control gas;
(d) flowing water through the port from the inner region to the
outer region; and (e) moving the gas storage vessel from the sea
floor toward the surface.
28. The method of claim 27 further comprising: (f) flowing the
buoyancy control gas through the port from the inner region to the
outer region during (e).
29. The method of claim 28, wherein (e) further comprises: coupling
the upper end of the gas storage vessel to a deployment apparatus
positioned at the surface of the water; and applying a vertical
lifting force to the gas storage vessel with the deployment
apparatus.
30. The method of claim 29, further comprising: (f) ensuring the
dry weight of the gas storage vessel minus the buoyancy force is
greater than zero and less than a maximum load capacity of the
deployment apparatus during (e).
31. The method of claim 28, wherein the subsea gas storage vessel
further comprises: a second inlet adapted to flow a stored gas into
the inner region; and a second valve adapted to control the flow of
the stored gas through the first inlet; a first outlet adapted to
flow the buoyancy control gas from the inner region to the outer
region, the first outlet being positioned at the upper end; a third
valve adapted to control the flow of the buoyancy control gas
through the first outlet.
32. The method of claim 31, further comprising: closing the second
valve and the third valve before (b).
33. The method of claim 28, further comprising: decreasing suction
forces between the gas storage vessel and the sea floor.
34. The method of claim 33, wherein decreasing suction forces
comprises pumping water from the exterior region to the interface
between the gas storage vessel and the sea floor.
35. The method of claim 28, further comprising: (g) maintaining a
volume of a stored gas in the inner region of the tank during (e),
wherein the stored gas in the inner region generates a buoyancy
force acting on the gas storage vessel.
36. The method of claim 35, wherein (e) further comprises: coupling
the upper end of the gas storage vessel to a deployment apparatus
positioned at the surface of the water; applying a vertical lifting
force to the gas storage vessel with the deployment apparatus;
ensuring the dry weight of the gas storage vessel minus the
buoyancy force generated by the buoyancy control gas and the
buoyancy force generated by the stored gas is greater than zero and
less than a maximum load capacity of the deployment apparatus
during (e).
37. A system for storing a gas subsea, comprising: a subsea gas
storage vessel including: a gas storage tank defining an inner
region inside the tank and an exterior region outside the tank,
wherein the tank has an upper end and a lower end opposite the
upper end; wherein the gas storage tank includes a gas inlet
adapted to flow the gas into the inner region, an air inlet adapted
to flow air into the inner region, a port in fluid communication
with the inner region and the outer region; a valve adapted to
control the flow of gas through the gas inlet; and a valve adapted
to control the flow of air through the air inlet.
38. The system of claim 37, wherein the subsea gas storage vessel
further comprises: an air outlet adapted to exhaust air from the
inner region to the outer region, wherein the air outlet is
positioned at the upper end of the tank; and a valve adapted to
control the flow of air through the air outlet.
39. The system of claim 37, wherein the subsea gas storage vessel
further comprises: a ballast chamber coupled to the lower end and
ballast disposed in the ballast chamber; and a mud skirt extending
from the ballast chamber.
40. The system of claim 39, wherein the subsea gas storage vessel
further comprises: a suction control apparatus coupled to the tank
and adapted to control suction forces in the within the mud
skirt.
41. The system of claim 40, wherein the subsea gas storage vessel
further comprises: a flexible gas storage bag disposed in the inner
region of the tank, wherein the flexible gas storage bag is adapted
to store the gas and includes a gas port in fluid communication
with the gas inlet; and wherein the flexible gas storage bag has a
collapsed position when the bag is empty and an expanded position
when the bag contains the gas.
42. The system of claim 41, wherein the flexible storage bag has a
first end proximal the upper end of the tank and a second end
opposite the first end, wherein the gas port is disposed at the
first end, and wherein the first end of the bag is oversized
relative to the second end of the bag.
43. The system claim 41, wherein the bag is positioned between the
port and the upper end.
44. The system of claim 37, further comprising: a deployment
apparatus at the surface of the water and adapted for deploying the
gas storage vessel subsea; a pipestring extending from the
deployment apparatus to the gas storage vessel, wherein the pipe
string has an upper end positioned at the deployment apparatus and
a lower end coupled to the subsea gas storage vessel.
45. The system of claim 44, wherein the pipestring includes an
inline damping device.
46. The system of claim 44, wherein the deployment apparatus
includes a derrick that supports the pipestring and the gas storage
vessel.
47. The system of claim 37, wherein the gas storage vessel has a
central axis and a total dry weight; wherein the inner region
comprises a first section extending axially from the upper end to
the port, the first section having a total volume; wherein the
total volume times the density of water is less than the dry
weight.
Description
[0001] This application is the U.S. National Stage under 35 U.S.C.
.sctn.371 of International Patent Application No. PCT/US2010/021445
filed Jan. 20, 2010, entitled "Systems and Methods For Subsea Gas
Storage Installation and Removal."
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH DEVELOPMENT
[0002] Not applicable
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The invention relates generally to subsea gas storage
systems. More particularly, the invention relates to the deployment
and removal of subsea gas storage systems.
[0005] 2. Background of the Technology
[0006] Oil at standard temperature and pressure conditions (stp) is
a relatively dense liquid, and thus, is suitable for transportation
in tankers and storage in tanks, thereby enabling a global market
for oil. However, since natural gas is a gas at stp, it is less
suited to transportation in tankers and storage in tanks.
Consequently, most natural gas is transported through pipelines,
which rely on a local source or supply, thereby limiting natural
gas to a generally local market.
[0007] A primary challenge in the development of a global natural
gas industry is that natural gas, at stp, is extremely diffuse, and
thus, has relatively little economic value for a given volume as
compared to oil (a difference of three orders of magnitude at
$7/MCF for natural gas and $50/BBL for oil). Due to this difference
in economic value for a given volume of natural gas vs. oil and the
gaseous state of natural gas at stp, transport of natural gas at
stp over long distances is not economically feasible. Various
methods for achieving more favorable ratios of gas value for a
given volume, such as compressing or liquefying the natural gas,
are commonly used to make the transmission and storage of natural
gas more economically attractive. Compression is the most commonly
used method employed for the transportation of natural gas in
pipeline systems. For marine transportation, liquefaction is used
to create Liquified Natural Gas (LNG) and compression is used to
create Compressed Natural Gas (CNG). However, once the natural gas
has reached its desired destination, the LNG and CNG undergo some
processing to conform the natural gas to conditions (e.g.,
pressure, temperature, etc.) suitable for standard pipeline
systems.
[0008] Like transportation, storage of natural gas has also
presented challenges. Natural gas at stp is commonly stored in
relatively large underground natural caverns. In such cases, the
storage of the natural gas is dependent on the location and
availability of such underground storage caverns (e.g., underground
natural salt caverns). Further, there have been many accidents
related to these caverns, including fires and explosions. LNG and
CNG also present storage complications. Typically, LNG is stored
onshore in pressurized or cryogenic containment tanks, both of
which are relatively expensive and dangerous. Due to the risks and
dangers of onshore LNG storage, it has become increasingly
difficult too locate LNG regassification units despite large market
demands. CNG has not been used for natural gas storage to date,
possibly due to the lack of availability of efficient storage
means.
[0009] Subsea oil storage systems have been deployed on the
seafloor, namely the Harding platform in the North Sea and the
Dubai Oil Storage tanks in the Middle East. However, subsea storage
of natural gas has not yet been achieved, although it offers some
important technical advantages over conventional onshore gas
storage systems and methods. U.S. Patent Application Publication
Nos. 2008/0041291 and 2009/0010717, each of which is hereby
incorporated herein by reference in its entirety for all purposes,
disclose apparatus and methods for storing natural gas, either LNG
or CNG, on the seafloor. Although the apparatus and methods
disclosed in these publications offer some advantages, most
conceivable mechanisms for the deployment, removal, and relocation
of the disclosed systems involve apparatus that are relatively
complicated and complex.
[0010] Accordingly, there remains a need in the art for natural gas
storage systems. Such systems and methods would be particularly
well received if they offered the potential for reduced dangers and
risks to life and property, and could be deployed and relocated
with conventional equipment.
BRIEF SUMMARY OF THE DISCLOSURE
[0011] These and other needs in the art are addressed in one
embodiment by a method for deploying a gas storage vessel below the
surface of the water. In an embodiment, the method comprises (a)
coupling an upper end of the gas storage vessel to a deployment
apparatus positioned at the surface of the water. The gas storage
vessel has a total dry weight and a lower end opposite the upper
end. The gas storage vessel also includes a storage tank defining
an inner region inside the tank and an exterior region outside the
tank. In addition, the method comprises (b) lowering the gas
storage vessel below the surface of the water with the deployment
apparatus. Further, the method comprise (c) pumping a buoyancy
control gas into the inner region of the tank during (b). The
buoyancy control gas in the inner region of the tank generates a
buoyancy force acting on the gas storage vessel during (b).
[0012] These and other needs in the art are addressed in another
embodiment by a method. In an embodiment, the method comprises (a)
disposing a gas storage vessel on the sea floor. The gas storage
vessel has an upper end distal the sea floor and a lower end
engaging the sea floor and includes a gas storage tank defining an
inner region inside the tank and an exterior region outside the
tank. The gas storage tank also includes a first inlet in fluid
communication with the inner region, a first valve that controls
the flow of fluid through the first inlet, and a port in fluid
communication with the inner region and the exterior region. In
addition, the method comprises (b) pumping a buoyancy control gas
through the first valve and first inlet into the inner region to
generate a buoyancy force acting on the gas storage vessel.
Further, the method comprises displacing water in the inner region
with the buoyancy control gas. Still further, the method comprises
(d) flowing water through the port from the inner region to the
outer region. Moreover, the method comprises moving the gas storage
vessel from the sea floor toward the surface.
[0013] These and other needs in the art are addressed in another
embodiment by a system for storing a gas subsea. In an embodiment,
the system comprises a subsea gas storage vessel. The storage
vessel includes a gas storage tank defining an inner region inside
the tank and an exterior region outside the tank. The tank has an
upper end and a lower end opposite the upper end. The gas storage
tank also includes a gas inlet adapted to flow the gas into the
inner region, an air inlet adapted to flow air into the inner
region, a port in fluid communication with the inner region and the
outer region. In addition, the gas storage tank includes a valve
adapted to control the flow of gas through the gas inlet. Further,
the gas storage tank includes a valve adapted to control the flow
of air through the air inlet.
[0014] Thus, 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 exemplary embodiments of the
invention, reference will now be made to the accompanying drawings
in which:
[0016] FIG. 1 is a schematic cross-sectional view of an embodiment
of a subsea gas storage vessel;
[0017] FIG. 2 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 1 during deployment subsea;
[0018] FIG. 3 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 1 during anchoring to the sea floor;
[0019] FIG. 4 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 1 anchored to the sea floor for subsea gas
storage operations;
[0020] FIG. 5 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 1 during the sea floor disengagement phase
of removal and/or relocation operations;
[0021] FIG. 6 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 1 during the lifting phase of removal and/or
relocation operations;
[0022] FIG. 7 is a schematic cross-sectional view of the subsea gas
storage vessel of FIG. 4 illustrating the hydrostatic pressure of
the sea water and the pressure of the stored gas;
[0023] FIG. 8 is a schematic view of a system for supplying gas to
and pulling gas from the subsea gas storage vessel of FIG. 4;
[0024] FIG. 9 is a schematic cross-sectional view of an embodiment
of a subsea gas storage vessel anchored to the sea floor for subsea
gas storage operations;
[0025] FIG. 10 is a schematic cross-sectional view of an embodiment
of a subsea gas storage vessel anchored to the sea floor for subsea
gas storage operations;
[0026] FIG. 11 is an embodiment of a combine water/air pumping
system for deploying the subsea gas storage vessel of FIG. 1;
[0027] FIG. 12 is a front view of an embodiment of a
compartmentalized subsea gas storage vessel;
[0028] FIG. 13 is a top schematic view of the subsea gas storage
vessel of FIG. 11;
[0029] FIG. 14 is a schematic cross-sectional view of the subsea
gas storage vessel of FIG. 11; and
[0030] FIGS. 15 and 16 are schematic views of deployment system for
deploying, removing, lifting, and relocating a subsea gas storage
vessel.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0031] 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 intimate that the scope of the
disclosure, including the claims, is limited to that
embodiment.
[0032] 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.
[0033] 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.
[0034] Embodiments described herein comprise a combination of
features and advantages intended to address various shortcomings
associated with certain prior apparatus, systems, and methods. For
example, embodiments described herein provide subsea gas storage
installation and removal apparatus, systems, and methods that offer
the potential for improved deployment, relocation, and hydrate
prevention/overtopping control as compared to conventional
apparatus, 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
description, and by referring to the accompanying drawings.
[0035] Referring now to FIG. 1-6, an embodiment of a subsea gas
storage apparatus or vessel 10 is schematically shown. In FIG. 1,
vessel 10 is shown at the sea surface before being submerged
subsea; in FIG. 2, vessel 10 is shown being lowered in sea water 3
for subsea deployment; in FIG. 3, vessel 10 is shown being anchored
to the sea floor 4; in FIG. 4, vessel 10 is shown anchored to sea
floor 4 during subsea gas storage operations; in FIG. 5, vessel 10
is shown disengaging sea floor 4 during removal and/or relocation
operations; and in FIG. 6, vessel 10 is shown being lifted from sea
floor 4 after disengagement from sea floor 4 for during removal
and/or relocation operations.
[0036] Vessel 10 has a central or longitudinal axis 15 and extends
between an upper end 10a and a lower end 10b. In addition, vessel
10 includes a rigid, thin-walled storage tank 20, a mud skirt 30 at
lower end 10b, and a ballast chamber 40 containing ballast 41
proximal lower end 10b between tank 20 and skirt 30. Vessel 10 is
designed to be deployed and positioned subsea in a vertical
orientation with axis 15 generally perpendicular to the sea floor
and upper end 10a positioned above lower end 10b. As will be
described in more detail below, during deployment operations, the
design of vessel 10 including ballast chamber 40 and associated
ballast 41 below tank 20 enhances the stability of vessel 10 since
the center of gravity of vessel 10 is positioned below the center
of buoyancy of vessel 10.
[0037] Referring still to FIGS. 1-6, the relatively thin-walled
tank 20 functions as a gas storage tank. Tank 20 comprises rigid
walls preferably made of steel or composite material. For a typical
steel design, the wall thickness would depend primarily on the
anticipated pressure differentials experienced by tank 20. For most
subsea applications, the wall thickness will range from about 0.5
in. to about 1.5 in. The walls may include reinforcing ribs (not
shown) to assist in strengthening the walls. The reinforcing ribs
can be either inside the tank or outside, with a preference for
outside due to its ease of construction and inspection. Further,
placement of reinforcing ribs on the outside of the tank (e.g.,
tank 20) prevents the ribs from interfering with gas storage
hardware disposed within the tank such as gas storage bag 50
described in more detail below. The top of tank 20 can be formed of
either a hemispherical or elliptical head typical of pressure
vessel fabrication. It can alternately be stiffened panel
construction with a flat top surface.
[0038] Storage tank 20 defines an inner region or chamber 21 within
tank 20 and an exterior region 22 outside tank 20. In this
embodiment, a flexible gas storage bag 50 is disposed within inner
chamber 21, thereby dividing chamber 21 into a first region 21a
inside chamber 21 and bag 50, and a second region 21b inside
chamber 21 but outside bag 50. In addition, gas storage bag 50
includes a stored gas port 51. It should be appreciated that when
bag 50 is collapsed (i.e., empty), the volume of second region 21b
is close to zero.
[0039] Storage tank 20 also includes a buoyancy control gas outlet
23 and a buoyancy control gas inlet 24, each in fluid communication
with second region 21b. In this embodiment, buoyancy control gas
outlet 23 is at upper end 10a, and buoyancy control gas inlet 24 is
positioned distal upper end 10a and proximal ballast chamber 40.
The flow of a air 6 out of and into second region 21b through
outlet 23 and inlet 24, respectively, is controlled by an outlet
valve 23a and inlet valve 24a, respectively. Although buoyancy
control gas 6 may comprise any suitable gas, in embodiments
described herein, buoyancy control gas 6 is air, and thus, buoyancy
control gas 6 may also be referred to as air 6. As shown in FIGS. 2
and 5, during deployment of vessel 10 and disengagement of vessel
10 from sea floor 4, air 6 is pumped through inlet 24 and
associated valve 24a into second region 21b to maintain or increase
the buoyant forces acting on vessel 10; and as shown in FIG. 3,
during anchoring of vessel 10 to sea floor 4, air 6 within second
region 21b is exhausted through outlet 23 and associated valve 23a
into sea water 3 outside tank 20 to decrease the buoyant forces
acting on vessel 10.
[0040] Referring still to FIGS. 1-6, storage tank 20 also includes
a stored gas conduit 25 in fluid communication stored gas port 51
in gas storage bag 50. In this embodiment, stored gas conduit 25
and gas port 51 are positioned at upper end 10a, however, in other
embodiments, the stored gas conduit (e.g., stored gas conduit 25)
and the gas port (e.g., gas port 51) may be disposed at other
suitable locations. The flow of a stored gas 5 into and out of gas
storage bag 50 through conduit 25 and gas port 51 is controlled by
a valve 25a. In this embodiment, one conduit 25, port 51 and valve
25a are used to flow the stored gas 5 into and out of storage tank
20. In other embodiment, more than one conduit (e.g., conduit 25),
gas port (e.g., gas port 51), and valve (e.g., valve 25) may be
used for the flow of storage gas into the tank (e.g., tank 20). A
control system (not shown) may be used to control each valve 23,
24, 25 from the surface.
[0041] Storage tank 20 further includes a through port 26 distal
upper end 10a and generally proximal ballast chamber 40. Port 26 is
essentially a through hole or opening in the lower portion of
storage tank 20 that allows fluid communication between outer
region 22 and second region 21b. It should be appreciated that flow
through port 26 is not controlled by a valve or other flow control
device. Thus, port 26 permits the free flow of fluid between
regions 21b, 22. Without being limited by this or any particular
theory, the flow of fluid through port 26 will depend on the depth
of vessel 10 and associated hydrostatic pressure of water 5, the
pressure of stored gas 5 in first region 21b (if any), and the
pressure of buoyancy control gas in storage second region 21b (if
any). During deployment and subsea gas storage operations (FIGS. 2
and 4), sea water 3 may flow through port 26 into or out of tank 20
and second region 21b; during anchoring operations (FIG. 3), sea
water 3 flows through port 26 into tank 20 and second region 21b;
during disengagement of vessel 10 from sea floor 4 (FIG. 5), sea
water 3 flows through port 26 out of tank 20 and second region 21b;
and during lifting operations (FIG. 6), air 6 flow out of tank and
second region 21b.
[0042] Referring specifically to FIG. 1, in general, tank 20 and
vessel 10 may have any suitable geometry including, without
limitation, rectangular, cylindrical, spherical, etc., and any
suitable size. In general, the size of tank 20 and vessel 10 will
depend, at least in part, on the desired volume within tank 20 for
gas storage. In this embodiment, vessel 10 and tank 20 are
cylindrical. Further, tank 20 and vessel 10 may have any suitable
size. In general, the size of tank 20 and vessel 10 will depend, at
least in part, on the desired volume within tank 20 for gas
storage. Vessel 10 has a total axial length L.sub.10 measured
between ends 10a, b, and tank 20 has a total axial length L.sub.20
measured between upper end 10a and ballast chamber 40. Furthermore,
vessel 10 has a maximum outer diameter D.sub.10 and tank 20 has a
maximum outer diameter D.sub.20. In this embodiment, diameter
D.sub.10 and diameter D.sub.20 are the same. In general, vessel 10
and tank 20 may have any suitable lengths L.sub.10, L.sub.20 and
diameters D.sub.10, D.sub.20. For most subsea gas storage
applications, length L.sub.10 is preferably at least 50 ft, length
L.sub.20 is preferably at least 40 ft., and diameters D.sub.10,
D.sub.20 are preferably each at least 20 ft. In one exemplary
embodiment, lengths L.sub.10 is about 50 ft, L.sub.20 is about 40
ft, and diameters D.sub.10, D.sub.20 are each about 26 ft. The
primary design considerations in determining lengths L.sub.10,
L.sub.20 and diameter D.sub.10, D.sub.20 are total gas storage
volume and dry weight of vessel 10. To maintain a given gas storage
volume, as the tank diameter (e.g., diameter D.sub.20) increase,
the tank length (e.g., length L.sub.20) decreases, and vice versa.
Further, as will be described in more detail below, as the tank
length decreases, the tank design pressure requirements decrease
(i.e., the maximum pressure differential the tank must be designed
to withstand decreases). Thus, to reduce the tank design pressure
requirements for a particular gas storage volume, the tank diameter
or width may be increased and the tank length or height may be
decreased. A larger tank diameter may also enhance anchoring
capabilities for a given tank gas storage volume. On the other
hand, it should be appreciated that dynamic loading experienced by
the vessel (e.g., vessel 10) during deployment and removal subsea
increases with tank diameter or width. Consequently, the ultimate
geometry of the vessel and associated tank may also be influenced
by the tank design pressure requirements, the anchoring
requirements, and consideration of dynamic loads experienced by the
tank during subsea deployment and removal.
[0043] Flexible gas storage bag 50 is designed to expand when the
pressure in first region 21a is greater than the pressure in second
region 21b, and contract when the pressure in first region 21a is
less than the pressure in second region 21b. Further, when first
region 21a is substantially empty, flexible storage bag 50 assumes
a generally collapsed configuration. For example, as best shown in
FIGS. 2, 3, 5, and 6, during deployment, anchoring, removal and
lifting operations, first region 21a is substantially empty and bag
50 is collapsed. However, as shown in FIG. 4, during subsea gas
storage operations, first region 21a is at least partially filled
with a stored gas 5 and bag 50 is at least partially expanded.
Further, as shown in FIGS. 2, 3, 5, and 6, during deployment,
anchoring, removal and lifting operations, second region 21b
comprises sea water 3 and a air 6; and as shown in FIG. 4, during
subsea gas storage operations, second region 21b comprises sea
water 3.
[0044] Referring briefly to FIG. 4, embodiments described herein
are generally directed to the subsea storage of natural gas, in
which case stored gas 5 is natural gas. However, in general, the
stored gas (e.g., stored gas 5) may be any gas for which subsea
storage is desired (e.g., CO.sub.2). For subsea natural gas storage
(i.e., stored gas 5 is natural gas), bag 50 provides physical
separation of stored gas 5 in first region 21a and sea water 3 in
second region 21b, thereby reducing and/or eliminating the
potential for the undesirable formation of hydrates and undesirable
methane releases.
[0045] In general, bag 50 may comprise any flexible, pliable, and
expandable bag suitable for gas storage. A variety of gas storage
bags currently on the market may be used for bag 50. One example of
a bag that may be employed for bag 50 is Large Fuel Bladder
manufactured and sold by Interstate Products of Sarasota, Fla. Most
conventional bags for gas storage are made from a flexible,
pliable, and expandable vinyl, polyester, or polymeric material.
For relatively large tanks that provide a relatively large gas
storage volume, conventional gas storage bags may be unsuitable
(e.g., not capable of handling the desired gas storage volume
and/or pressures) and/or cost prohibitive to design and build.
Consequently, for relatively large gas storage tanks, it may be
desirable to provide multiple gas storage bags or a
compartmentalized tank, each compartment having its own dedicated
gas storage bag. In either case, each bag must be placed in fluid
communication with the stored gas conduit so that stored gas may be
flowed into or out of each bag or compartment. Such designs may
enable the use of conventional of gas storage bags or cost
effective design of new bags. Further, such designs may provide
some advantages in terms of minimizing the environmental impacts
should one relatively small bag or compartment rupture as compared
to the rupture of a single large bag.
[0046] Referring briefly to FIG. 7, the hydrostatic pressure 61 and
associated forces of sea water 3 in outer region 22, the pressure
62 and associated forces of sea water 3 in second region 21b within
tank 20, and the pressure 63 and associated forces of stored gas 5
in bag 50 are schematically shown during subsea gas storage
operations. Without being limited by this or any particular theory,
the hydrostatic pressure 61 of sea water 3 outside tank 20
increases with depth, and since port 26 allows the free movement of
sea water 3 into and out of tank 20, the pressure 62 of sea water 3
within tank 20 also varies with depth and corresponds to the
hydrostatic pressure 61 of sea water 3 in outer region 22 at the
equivalent depth. Further, without being limited by this or any
particular theory, although the pressure 63 of stored gas 5 within
bag 5 may vary over time (e.g., as gas 5 is pumped into or removed
from bag 50), the pressure 63 of stored gas 5 within bag 50 and
first region 21a is substantially uniform at all locations within
bag 50. In particular, the gas pressure gradient is relatively
small compared to the water pressure gradient, and therefore the
gas pressure differential over the height of the bag (e.g., bag 50)
is negligible.
[0047] During subsea gas storage operations, if the pressure 63 of
stored gas 5 in bag 50 is less than the pressure 62 of sea water 3
in second region 21b at a region along the interface 27 between bag
50 and sea water 3 in tank 20, then bag 50 will be compressed at
that region and sea water 3 will flow into tank 20 through port 26.
However, if the pressure 63 of stored gas 5 in bag 50 is greater
than the pressure 62 of sea water at a region along interface 27,
then bag 50 will expand at that region and sea water 3 will flow
out of tank 20 through port 26. Thus, bag 50 and stored gas 5
within bag 50 will compress and expand based on any pressure
differential across bag 50 along interface 27. Since the pressure
62 of any sea water 3 within tank 20 decreases as depth decreases,
any pressure differential between gas pressure 63 and water
pressure 62 within tank 20 will tend to be greatest proximal upper
end 10a.
[0048] Flexible bags for gas storage may rupture or burst if the
pressure inside the bag is sufficiently greater than the pressure
outside the bag. In other words, flexible bags for gas storage are
typically designed and rated to withstand a maximum pressure
differential, which may be referred to as the "burst" or "rupture"
pressure differential. During radial expansion of bag 50 (i.e.,
before bag 50 engages the wall of tank 20), bag 50 is subject to
the pressure differential between stored gas 5 in bag 50 and sea
water 3 radially positioned between bag 50 and tank 20 in second
region 21b. The maximum pressure differential experienced by bag 50
during radial expansion is the pressure differential proximal upper
end 10a. Bag 50 is preferably designed to withstand the maximum
anticipated pressure differential proximal upper end 10a during
radial expansion, and designed and sized to expand radially outward
into engagement with the walls of tank 20 before the maximum
pressure differential proximal upper end 10a reaches the "burst"
pressure differential of bag 50. For example, as schematically
shown in FIG. 1, the upper portion of the bag (e.g., bag 50) may be
oversized (i.e., larger than the lower portion of the bag) to
ensure that the upper portion of the bag subject to the maximum
pressure differential during radial expansion engages the rigid
tank walls before the burst pressure differential is reached. Once
bag 50 expands into engagement with tank 20, the rigid walls of
tank 20 (as opposed to bag 50) support the maximum pressure
differential. Thus, tank 20 is preferably designed to withstand, at
a minimum, the maximum anticipated pressure differential between
hydrostatic pressure 61 and pressure 63 proximal upper end 10a.
[0049] Referring again to FIGS. 1-6, skirt 30 functions to
positively engage the sea floor 4 and restrict and/or prevent the
lateral movement of vessel 10 once positioned at the sea floor 4
for gas storage operations. Skirt 30 extends axially downward from
ballast chamber 40 and circumferentially around the entire
periphery of vessel 10, thereby defining a recess 31 at lower end
10b. As shown in FIG. 3, during anchoring of vessel 10, vessel 10
is urged downward and skirt 30 is pushed into sea floor 4. As skirt
30 penetrates the sea floor 4 and recess 31 is filled with mud. The
lateral movement of vessel 10 is restricted by the mud engaging
both the inside and outside of skirt 30 as well as suction that may
arise within recess 31 between vessel 10 and the sea floor 4.
[0050] During anchoring of vessel 10 to the sea floor 4 (FIG. 3)
and subsea gas storage operations (FIG. 4), suction forces within
recess 31 between vessel 10 and sea floor 4 is generally desirable
since it tends to pull vessel 10 into engagement with sea floor 4
and resist movement of vessel 10 once seated on the sea floor 4.
However, during operations to remove and/or relocate vessel 10,
such suction forces are undesirable because they increase the
vertical lifting force that must be exerted on vessel 10 to lift
vessel 10 from the sea floor 4. Consequently, in this embodiment,
vessel 10 includes a suction control apparatus 34 that can increase
or decrease the suction forces in recess 31. Suction control
apparatus 34 comprises a fluid conduit 35 extending to recess 31
and a valve 36. Fluid conduit 35 is in fluid communication with
recess 31 and valve 36 controls fluid flow into and out of recess
31--when valve 36 is in a closed position, flow through conduit 34
is restricted and/or prevented, and when valve 36 is in an opened
position, flow through conduit 34 is permitted.
[0051] Suction control apparatus 34 is controllably operated to
increase or decrease the suction forces within recess 31 as
desired. As shown in FIG. 3, during anchoring of vessel 10 to the
sea floor 4, suction control apparatus 34 may be used to generate
and/or increase suction forces in recess 31 to pull vessel 10 into
engagement with sea floor 4 and urge skirt 30 into sea floor 4.
Suction forces in recess 31 may also be generated and/or increased
by suction control apparatus 34 during subsea gas storage
operations (FIG. 4) to ensure vessel 10 is properly seated on sea
floor 4 in the desired orientation. Suction forces within recess 31
are generated and/or increased with suction control apparatus 34 by
opening valve 36 (if not already opened) and pumping a mixture of
mud and sea water (designated by reference numeral 7) out of recess
31 through conduit 35 and valve 36. Conversely, as shown in FIG. 5,
to initiate the disengagement of vessel 10 from sea floor 4, such
control apparatus 34 may be used to reduce suction forces in recess
31. In particular, suction forces within recess 31 are decreased
with suction control apparatus 34 by opening valve 36 (if not
already opened) and pumping sea water 3 through conduit 35 and
valve 36 into recess 31.
[0052] Referring again to FIGS. 1-6, as previously described,
ballast 41 is contained within ballast chamber 40. In general,
ballast 41 may comprise any type of ballast. For example, ballast
41 may comprise permanent solid ballast (e.g., concrete ballast),
removable solid ballast (e.g., hematite, magnetite, etc.), sea
water 5, or combinations thereof. However, to minimize the volume
and size of ballast chamber 40 while providing sufficient weight,
ballast 41 is preferably a relatively dense solid ballast such as
hematite or magnetite.
[0053] Ballast 41 may be installed in ballast chamber 40 at the
surface or at depth. Installing ballast 41 at the surface is
usually easier since it is more easily monitored and controlled.
However, installation of ballast 41 at the surface may increase the
demands on the crane (or other device at the surface) that
controllably deploys vessel 10 from the surface.
[0054] In general, ballast 41 counteracts the upward vertical
buoyancy forces resulting from the stored gas 5 and/or air 6 in
tank 20. The quantity and weight of ballast 41 is chosen to achieve
the desired total dry weight of vessel 10. For embodiments
described herein, the dry weight of vessel 10 is preferably greater
than the total buoyant forces acting on vessel during all
operational phases of vessel 10 (e.g., deployment, anchoring, gas
storage, disengaging, removal, and relocation of vessel 10). During
deployment and anchoring of vessel 10 (FIGS. 2 and 3), the
difference between the dry weight of vessel 10 and the buoyancy
forces acting on vessel 10 enables the submersion and lowering of
vessel 10 subsea; during gas storage operations (FIG. 4), the
difference between the dry weight of vessel 10 and the buoyancy
forces acting on vessel 10 restrict movement of vessel 10 and
maintains the position of vessel 10 at the sea floor 4; during
disengagement of vessel 10 from the sea floor (FIG. 5) and lifting
of vessel 10 (FIG. 6) for removal and/or relocation, the difference
between the dry weight of vessel 10 and the buoyancy forces acting
on vessel 10 allows for a controlled, managed lift as will be
described in more detail below.
[0055] Deployment of a large gas storage vessel or system to the
sea floor from a floating vessel involves some challenges that are
not typical of most marine operations and subsea installations due
to the relatively large size and weight of the gas storage vessel
compared to standard subsea hardware (e.g., cranes) and associated
lifting capacities. Due to the relatively large size and weight of
a subsea gas storage vessel, the static deployment loads can be
quite substantial, and further, there may also be large dynamic
loads associated with relative motion between the gas storage
vessel and the floating installation vessel during the installation
itself. In particular, the static load alone of a reasonably and
practically sized subsea gas storage vessel deployed with gravity
anchoring will significantly reduce and limit the total number of
potential installation vessels available in the world. Few, if any,
of the installation vessels capable of handling the anticipated
static loads are designed to provide heave compensation, and thus,
are unlikely qualified to handle the anticipated dynamic loads of
deployment. Consequently, the methods of deployment described
herein utilize buoyant forces to decrease the required lifting
capacity and hook load of the surface equipment used to deploy the
gas storage vessel.
[0056] Referring now to FIG. 2, during subsea deployment of vessel
10, buoyancy control gas or air 6 is used to reduce the static load
of vessel 10. Specifically, vessel 10 is connected at upper end 10a
to a deployment apparatus at the surface such as a crane. As
previously described, the dry weight of vessel 10 is preferably
greater than the maximum buoyancy forces acting on vessel 10 during
deployment, and thus, vessel 10 naturally wants to begin sinking.
It should be appreciated that the maximum possible buoyant forces
resulting from air 6 in tank 20 during deployment occurs when
second region 21b is completely filled with air 6 from upper end
10a to port 26. No greater buoyant force can be achieved during
deployment since any additional air volume will simply exit tank 20
through port 26.
[0057] The deployment apparatus connected to upper end 10a applies
an upward, vertical lifting force to upper end 10a and vessel 10 to
manage and control the rate at which vessel 10 submerges subsea.
The vertical lifting force exerted by the deployment apparatus may
also be referred to as the hook load. The lifting force applied at
upper end 10a and the design of vessel 10 having its center of
buoyancy above its center of gravity maintain the substantially
vertical orientation of vessel 10 during deployment. As vessel 10
is lowered subsea, sea water 3 in outer region 22 flows through
port 26 into second region 21b within tank 20. With valve 23a
closed, as vessel 10 is lowered, sea water 3 continues to flow into
second region 21b and the air 6 in second region 21b is compressed
according to the ideal gas law. As a result, the buoyancy forces
acting on vessel 10 decrease. This effect tends to be greatest
proximal the sea surface because the initial pressure of the air 6
in second region 21b is relatively low and a small increase in
water depth can drastically reduce buoyancy of vessel 10. However,
at greater depths, the change in the pressure of the air 6 in
second region 21b for a given depth change is constant (linear with
density of water), however, the initial pressure of air 6 is
relatively high, and thus, the volume of the air 6 in second region
21b is much slower.
[0058] Without some action to counteract the decrease in buoyant
forces acting on vessel 10 as it is lowered subsea, the maximum
hook load capacity of the deployment apparatus at the surface may
be exceeded, potentially resulting in damage to the deployment
apparatus and/or loss of control over the deployment of vessel 10.
However, during deployment of embodiments described herein, valve
24a is opened and air 6 is pumped through valve 24a and inlet 24
into second region 21b of tank 20 during the deployment process to
maintain a sufficient buoyant force. In particular, during
deployment, disengagement, removal and relocation of vessel 10
(i.e., anytime the surface deployment apparatus applies a lifting
force to vessel 10), the total weight of vessel 10 minus the
buoyant force is preferably greater than zero (to prevent an
uncontrolled ascent of vessel 10) and less than the maximum hook
load capacity of the deployment apparatus (to ensure the maximum
hook load capacity is not exceeded).
[0059] Pumping air 6 into second region 21b during deployment can
be achieved at the surface very efficiently with standard marine
compressors, which are generally suitable for the high volume, low
pressure specifications. However, as the depth of vessel 10
increases and the air 6 within second region 21b continues to be
compressed, the pumping requirements increase, and thus, larger
and/or more specialized marine compressors may be required.
[0060] Referring now to FIG. 3, once vessel 10 reaches the sea
floor 4, skirt 30 begins to engage and penetrate the sea floor 4.
To anchor vessel 10 to the sea floor 4, valve 24a is closed and
pumping of air 6 through inlet 24 into second region 21b is ceased,
and valve 23a is opened to allow any air 6 in second region 21b to
exit inner region 21b. As air 6 exits tank 20 and rises to the
surface, sea water 3 flows through port 26 and fills the remainder
of second region 21b, thereby reducing and/or eliminating buoyant
forces acting on vessel 10. As the buoyant forces decrease, skirt
30 penetrates further into sea floor 4 under the weight of vessel
10. To enhance seating of vessel 10, suction control apparatus 34
may be employed as previously described to increase suction forces
in recess 31 and pull vessel 10 further into sea floor 4. Once
anchoring is complete, valve 23a may be closed, the deployment
apparatus may be decoupled from vessel 10, a gas supply may be
coupled to conduit 25, and valve 25a may be opened to allow for the
flow of gas 5 into gas storage bag 50.
[0061] As described above, a gravity based anchoring technique is
employed to anchor vessel 10 to the sea floor 4. Specifically,
ballast 41 is fixed ballast that provides a sufficient load to
anchor vessel 10 to the sea floor 4. However, in other embodiments,
alternative means of anchoring may be used to secure the subsea gas
storage vessel (e.g., vessel 10) to the sea floor. For example,
piles may be used to anchor the vessel to the sea floor. The piles
may be driven, suction, jetted, or combinations thereof. Although
alternative anchoring techniques may be employed, gravity anchoring
is generally more suited to relocation operations in which vessel
10 is lifted from location on the sea floor 4 and move to a
different location on the sea floor 4. In such cases, the use of
gravity anchoring eliminates the need to deploy additional piles
subsea and drive the new piles into he sea floor 4 to anchor vessel
10 at its new location.
[0062] Referring now to FIG. 6, during gas storage operations,
valve 25a is opened and valves 23a, 24a are closed. As the volume
of gas 5 in bag 50 increases, the buoyancy forces resulting
therefore also increase. However, as previously described, the
amount and weight of ballast 41 is set such that the total weight
of vessel 10 is greater than the maximum possible buoyancy forces
resulting from stored gas 5. Consequently, vessel 10 remains
anchored to the sea floor 4 as the volume of gas 5 in tank 20
increases during storage operations.
[0063] Referring now to FIGS. 5 and 6, to remove and/or relocate
vessel 10, vessel 10 is first be disengaged from the sea floor 4
(FIG. 5), and then lifted and moved to the desired location (FIG.
6). As shown in FIG. 5, in this embodiment, to initiate
disengagement of vessel 10 from the sea floor 4, stored gas 5 is
emptied from bag 50, valve 25a is closed, and valve 23a is closed
(if not already closed). In addition, the deployment apparatus is
coupled to upper end 10a of vessel 10 and applies an upward lifting
force to vessel 10, valve 24a is opened, and air 6 is pumped
through valve 24a and inlet 24 into second region 21b of tank 20.
As air 6 is pumped into tank 20, it naturally rises to the top of
tank 20 and begins to displace sea water 3 in second region 21b,
thereby increasing the buoyant forces acting on vessel 10. The
displaced sea water 3 is free to exit tank 20 through port 26. In
addition to the lifting and buoyant forces acting on vessel 10,
suction control apparatus 34 may be employed as previously
described to decrease suction in recess 31 and aid in the initial
lifting of vessel 10 from sea floor 4.
[0064] As best shown in FIG. 6, once vessel 10 is disengaged from
sea floor 4, it may be lifted to the surface or lifted and
relocated to a different subsea location. To continue lifting
vessel 10, valves 23a and 25a are maintained in the closed
positions, and valve 36 is closed. Further, the deployment
apparatus continues to apply a vertical lifting force to vessel 10
and air 6 continues to be pumped through valve 24a and inlet 24
into second region 21b. As the depth of tank 20 decreases, the
hydrostatic pressure of sea water 3 decreases and the air 6 in
second region 21b expands. The expansion of air 6 in second region
21b and the continued pumping of air 6 into second region 21b
continues to increase the buoyant forces acting on vessel 10.
However, regardless of the depth of vessel 10, the expansion of air
6 in tank 20, and the volume of air 6 pumped into tank 20, the
buoyant forces acting on vessel 10 cannot exceed a predetermined
maximum buoyant force defined by the location of port 26. In
particular, the maximum buoyant force acting on vessel 10 due to
air 6 in tank 20 occurs when second region 21b is completely filled
with air 6 from upper end 10a to port 26. Any additional volume of
air 6 will simply exit tank 20 and second region 21b through port
26. Thus, the location of port 26 defines the maximum possible
buoyant force acting on vessel 10--the closer port 26 is to upper
end 10a, the lower the maximum possible buoyant force due to air 6,
and the closer the port 26 to lower end 10b, the greater the
maximum possible buoyant force due to air 6. The axial position of
port 26 along tank 20 is preferably set such that the maximum
possible buoyancy force from air 6 is less than or equal to the
total weight of vessel 10, and such that the total weight of vessel
10 minus the maximum possible buoyancy force from air 6 is greater
than zero and less than the maximum hook load capacity of the
deployment apparatus. As a result, vessel 10 may be controllably
lifted by the deployment apparatus without exceeding the maximum
hook load capacity, and without uncontrollably accelerating to the
surface under a continuously increasing buoyancy force as the air
continues to expand as depth decreases.
[0065] Once anchored for subsea gas storage operations, gas 5 may
be supplied to or pulled from gas storage vessel 10. Referring
briefly to FIG. 8, gas conduit 25 of subsea gas storage vessel 10
is placed in fluid communication with a buoy 80 moored in place by
mooring lines 81, 82 connected to anchors 83, 84 at sea floor 4.
Buoy 80 may be connected to a CNG tanker 90 and/or placed in fluid
communication with a seafloor gas pipeline 91. Gas 5 may be
provided to vessel 10 from pipeline 91, buoy 80, and/or tanker 90,
or offloaded from vessel 10 to pipeline 91, buoy 80, and/or tanker
92 as desired. It should be appreciated that FIG. 8 illustrates one
exemplary subsea configuration, however, a variety of other subsea
configurations employing embodiments of subsea gas storage vessel
described herein are possible.
[0066] As described above with reference to FIGS. 5 and 6, in one
embodiment, to initiate disengagement of vessel 10 from the sea
floor 4, stored gas 5 is emptied from bag 50, valve 25a is closed,
and valve 23a is closed (if not already closed). In addition, the
deployment apparatus is coupled to upper end 10a of vessel 10 and
applies an upward lifting force to vessel 10, valve 24a is opened,
and air 6 is pumped through valve 24a and inlet 24 into second
region 21b of tank 20. Once vessel 10 is disengaged from sea floor
4, to continue lifting vessel 10, the deployment apparatus
continues to apply a vertical lifting force to vessel 10 and air 6
continues to be pumped through valve 24a and inlet 24 into second
region 21b. Thus, in the embodiment described above with reference
to FIGS. 5 and 6, only air 6 is relied on to provide buoyancy
(i.e., stored gas 5 is not relied on to provide buoyancy). However,
in other embodiments, the buoyancy provided by the stored gas 5
stored in the gas storage tank 20 may be leveraged during
disengagement, removal, relocation, or combinations thereof. For
example, to initiate disengagement of the gas storage vessel 10
from the sea floor 4, all of the stored gas 5 in tank 20 may not be
unloaded from the tank 20, but rather, some stored gas 5 may be
left within tank 20 or additional stored gas 5 may be added to tank
20. Once the desired amount of stored gas 5 is in tank 20, valve
25a is closed, and valve 23a is closed (if not already closed). In
addition, the deployment apparatus is coupled to upper end 10a of
vessel 10 and applies an upward lifting force to vessel 10. Next,
valve 24a is opened and air 6 is pumped through valve 24a and inlet
24 into second region 21b of tank 20. As air 6 is pumped into tank
20, it naturally rises to the top of second region 21b and
displaces water 3 within second region 21b. Water 3 within tank 20
is free to flow through port 26 to outer region 22 as the volume of
air 6 within tank 20 increases. When the lifting force applied to
vessel 10 plus the buoyancy provided by air 6 and stored gas 5
within tank 20 exceed the dry weight of vessel 10 and any suction
forces between vessel 10 and the sea floor 4, vessel 10 will
disengage the sea floor. Once vessel 10 is disengaged from sea
floor 4, the removal and relocation process is similar to that
previously described with reference to FIGS. 5 and 6. Namely, to
continue lifting vessel 10, the deployment apparatus continues to
apply a vertical lifting force to vessel 10 and air 6 continues to
be pumped through valve 24a and inlet 24 into second region 21b.
Thus, in this embodiment, the buoyancy of air 6 and stored gas 5
within tank 20 are leveraged during the disengagement and removal
processes.
[0067] In the embodiments of vessel 10 previously described, a
flexible gas storage bag 50 is employed to store gas 5 and to
maintain physical separation of stored gas 5 and sea water 3 within
tank 20 to prevent hydrate formation. However, in other
embodiments, alternative means may be employed to separate gas 5
and sea water 3 within the tank (e.g., tank 20). For example,
referring now to FIG. 9, an embodiment of a subsea gas storage
vessel 100 is schematically shown disposed at sea floor 4 for
subsea gas storage operations. Vessel 100 is substantially the same
as vessel 10 previously described, except that vessel 100 employs a
floating diaphragm system 110 to physically separate stored gas 5
from sea water 3 within tank 20 as opposed to a flexible gas
storage bag (e.g., bag 50). Specifically, floating diaphragm system
110 comprises a rigid plate or diaphragm 111 that is supported by
air bubble 112, which may be added during the deployment process
and prior to storage of gas 5 in tank 20. The air bubble 112 allows
diaphragm 111 to float on top of sea water 3 within tank 20
although diaphragm 111 may have a density greater than sea water 3.
However, the density of diaphragm 111 is greater than the density
of gas 5 within tank 20, and thus, diaphragm 111 remains positioned
below gas 5. A dynamic sliding seal 113 is formed between diaphragm
111 and tank 20. Seal 113 extends annularly around the entire
circumference of diaphragm 111 and restricts and/or prevents the
axial flow of sea water 3 and gas 5 across diaphragm 111, and thus,
restricts and/or prevents gas 5 from contacting sea water 3. Seal
113 may be formed by any suitable means including, without
limitation, a lubricated bag assembly that extends radially from
diaphragm 111 to tank 20. In this embodiment, a liquid hydrate
inhibitor 115 that inhibits the formation of hydrates is disposed
in tank 20 between gas 5 and diaphragm 111. Hydrate inhibitor 115
may be injected into tank 20 through gas conduit 25 and valve 25a
or other inlet positioned above diaphragm 111 (e.g., a dedicated
chemical injection inlet). Hydrate inhibitor 115 has a density
greater than gas 5, and thus, hydrate inhibitor 115 naturally flows
downward in tank 20 until it is positioned atop diaphragm 111. In
general, hydrate inhibitor 115 may be any suitable known hydrate
inhibitor.
[0068] As yet another example, a barrier fluid may be employed to
separate to separate gas 5 and sea water 3 within the tank (e.g.,
tank 20). Referring now to FIG. 10, an embodiment of a subsea gas
storage vessel 150 is schematically shown disposed at sea floor 4
for subsea gas storage operations. Vessel 150 is substantially the
same as vessel 10 previously described, except that vessel 150
employs a barrier fluid system 160 to physically separate stored
gas 5 from sea water 3 within tank 20 as opposed to a flexible gas
storage bag (e.g., bag 50). Specifically, barrier fluid system 160
comprises a barrier fluid 161 axially disposed between gas 5 and
sea water 3. Barrier fluid 161 has a density less than sea water 3
and greater than gas 5. Barrier fluid 161 is preferably immiscible
to both sea water 3 and gas 5. An example of a barrier fluid is
described in U.S. Patent Application Publication Nos. 2008/0041291
and 2009/0010717, each of which is hereby incorporated herein by
reference in its entirety for all purposes. Those systems describe
a perfectly immiscible fluid to both water and gas. In practice,
fluids of this type are difficult to find. The method that is
disclosed here offers the potential to utilize a much broader range
of available and environmentally acceptable fluids.
[0069] In addition, in this embodiment, a liquid hydrate inhibitor
162 that inhibits the formation of hydrates is disposed in tank 20
between gas 5 and barrier fluid 161. Hydrate inhibitor 162 and/or
barrier fluid 161 may be injected into tank 20 through gas conduit
25 and valve 25a or other inlet. Hydrate inhibitor 162 has a
density greater than gas 5 and less than barrier fluid 161. In
general, hydrate inhibitor 115 may be any suitable known hydrate
inhibitor. Various sensors may be employed in vessel 150 to provide
warn of potential overtopping, release of gas, release of barrier
fluid 161, or combinations thereof to the surrounding
environment.
[0070] In one embodiment, a dead oil fluid, which is somewhat
miscible to both sea water 3 and gas 5 may be used as the barrier
fluid (e.g., barrier fluid 161). Hydrates may form as gas 5 or sea
water 3 moves through the dead oil barrier and contacts the other.
Consequently, the hydrate formation is relatively slow. Further, by
injecting sufficient hydrate inhibitors (e.g., methanol) prior to
unloading or discharging gas 5, the hydrate effects can be
minimized while still allowing standard, environmentally friendly
materials to be used.
[0071] As previously described, during deployment of vessel 10
(FIG. 2), the air pumping requirements increase as the depth of
vessel 10 increases due to compression of the air 6 within second
region 21b. For deep applications, the air pressure requirements
may be substantial. Referring now to FIG. 11, for such deep
applications a combined air/water pumping system 180 may be
employed to pump air 6 into tank 20 during deployment. System 180
comprises a fluid conduit 181 extending to valve 24a and inlet 24,
an air inlet line 182 coupled to conduit 181, a water inlet line
183 coupled to conduit 181 above air inlet line 181. Water 3 is
pumped through water inlet line 183 and into conduit 181, and air 6
is pumped through air inlet line 182 into conduit 181. The water 3
is preferably pumped at a sufficient volumetric flow rate to push
and convey air 6 down conduit 181 to inlet 24 and tank 20.
Accordingly, the drag load imposed on air 6 within conduit 181 by
water 3 in conduit 181 must always be greater than the buoyancy of
the bubbles of air 6 in conduit 181. As the bubbles of air 6 move
down, they decrease in size according to the ideal gas law. Thus,
system 180 must be designed such that the flow rate of water 3 down
conduit 181 is sufficiently high to achieve conveyance of air 6 to
the installation depth.
[0072] Combined air-water pumping system 180 offers the potential
to eliminate high compression requirements at the surface as the
hydrostatic water head accomplishes that function. Consequently,
standard equipment may be used to perform the pumping operations,
which are inherently safe because high pressures are achieved at
depth without necessitating high pressure components at the surface
near the workers.
[0073] Referring still to FIG. 11, once the combined air-water
solution reaches tank 20, the air 6 rises within second region 21b
to add buoyancy and the water 3 is free to exit tank 20 through
port 26. In this way, the air 6 achieves its desired effect and the
amount of water 3 that is added is not critical since it simply
exits tank 20 through port 26.
[0074] Embodiments of subsea gas storage vessels 10, 100, 150
described above included a single tank (e.g., tank 20) and a single
chamber or volume for gas storage (e.g., first region 21a, inner
region 21) for gas storage. However, in other embodiments, the
subsea gas storage vessel or system may include multiple gas
storage tanks. Such embodiments may be referred as
compartmentalized subsea gas storage vessels or systems since the
total gas stored is divided among multiple subsea gas storage
tanks. Compartmentalized subsea gas storage vessels offer the
potential to reduce quantities of gas leaks subsea by spreading the
volume of stored gas across multiple tanks. Further,
compartmentalization offers the potential to reduce manufacturing
costs as smaller flexible bags are typically easier to design and
build.
[0075] Referring now to FIGS. 12-14, an embodiment of a
compartmentalized subsea gas storage vessel 200 is shown. Vessel
200 has a central axis 250 and extends between an upper end 200a
and a lower end 200b. In addition, vessel 200 includes a plurality
of rigid, thin-walled storage tanks 220 and a base 260 positioned
below tanks 220. Vessel 200 is designed to be deployed and
positioned subsea with tanks 220 in a vertical orientation with
upper end 200a positioned above lower end 200b.
[0076] Each tank 220 is substantially the same as tank 20
previously described. Namely, each tank 220 comprises rigid walls
preferably made of steel or composite material. In addition, each
storage tank 220 defines an inner region or chamber 221 and an
exterior region 222. A flexible gas storage bag 250 as previously
described is disposed within inner chamber 221 of each tank 220,
thereby dividing chamber 221 into a first region 221a inside
chamber 221 and bag 250, and a second region 221b inside chamber
221 but outside bag 250. Each gas storage bag 250 includes a stored
gas port 251. As best shown in FIG. 12, the walls of each tank 220
include external reinforcing ribs to assist in strengthening the
walls. Moreover, a buoyancy control gas outlet 223 and a buoyancy
control gas inlet 224 is provided on each storage tank 220. In this
embodiment, each buoyancy control gas outlet 223 is in fluid
communication with a header pipe or conduit 223b, and each buoyancy
control gas inlet 224 is in fluid communication with a header pipe
or conduit 224b. Outlet valve 223a controls the flow of buoyancy
control gas or air 6 through outlets 223 and header pipe 223b, and
inlet valve 224a controls the flow of buoyancy control gas or air 6
through header pipe 224b and gas inlets 224. Thus, in this
embodiment, one outlet valve 223a controls the exhaust of air 6
from every tank 220, and one inlet valve 224a controls the flow of
air 6 into every tank 220. However, in other embodiments, each tank
(e.g., each tank 220) may have its own independently controlled
buoyancy control gas inlet valve and/or buoyancy control gas outlet
valve. In such embodiment, the flow of buoyancy control gas into
and out of each tank may be independently controlled to vary the
buoyancy forces acting on different tanks.
[0077] Referring still to FIGS. 12-14, each storage tank 220 also
includes a stored gas conduit 225 in fluid communication with gas
port 251 of its associated gas storage bag 250. In this embodiment,
each stored gas conduit 225 is in fluid communication with a gas
header pipe or conduit 225b. The flow of a stored gas 5 into and
out of each gas storage bag 250 through header pipe 225b, each
conduit 225, and each gas port 251 is controlled by a gas valve
225a. Thus, in this embodiment, one gas valve 225a controls the
flow of stored gas 5 into and out of every bag 250. However, in
other embodiments, each tank (e.g., each tank 220) may have its own
independently controlled gas valve such that the flow of gas into
or out of each bag (e.g., each bag 250) can varied. Further, as
previously described, each storage tank 220 includes a through port
226 positioned proximal the lower end of its associated tank
220.
[0078] In general, each tank 220 may have any suitable size and
geometry. In this embodiment, each tank 220 has the same size and
cylindrical geometry. In general, the size of each tank 220, and
hence the overall size of vessel 200, will depend, at least in
part, on the desired volume for subsea gas storage. A given volume
of gas may be stored in a single relatively large tank or stored in
multiple smaller gas tanks of a compartmentalized subsea gas
storage vessel. However, in general, smaller gas storage tanks are
simpler and less expensive to construct as compared to large gas
storage tanks. Consequently, a compartmentalized subsea gas storage
vessel, such as vessel 200, may be more cost effective to
manufacture than a subsea gas storage vessel that employs one
relatively large tank to store the same total gas volume. In
addition, compartmentalized subsea gas storage vessels are better
suited to deployment methods previously described that employ
temporary buoyancy. For example, it may be desirable to use only
some of the buoyancy when lowering the system and
compartmentalization makes this process simpler and more
robust.
[0079] Referring still to FIGS. 12-14, base 260 of vessel 200
includes a ballast chamber 240 containing ballast 241 and a
plurality of mud skirts 230 at lower end 200b. Ballast chamber 240
is positioned axially between tanks 220 and skirts 230. In this
embodiment, one mud skirt 230 is provided for each tank 220.
However, in general, one or more mud skirts may be provided.
[0080] Mud skirts 230 functions to positively engage the sea floor
4 and restrict and/or prevent the lateral movement of vessel 200
once positioned at the sea floor 4 for gas storage operations. Each
skirt 230 is substantially the same as skirt 30 previously
described. During anchoring of vessel 200, vessel 200 is urged
downward and each skirt 230 is pushed into sea floor 4. A suction
control apparatus similar to suction control apparatus 34
previously described maybe provided for one or more of skirts 230
to control suction forces within skirts 230 during anchoring and
removal operations. For example, a suction control apparatus (e.g.,
suction control apparatus 34) may be provided for each skirt 230 to
aid in leveling out vessel 200 once positioned. In particular,
differential suctioning may be provided among skirts 230 to vary
the suction forces acting on different portions of vessel 200.
[0081] Referring still to FIGS. 12-14, ballast 241 is contained
within ballast chamber 240. In this embodiment, a single ballast
chamber 240 extends beneath each tank 220. However, in other
embodiments, each tank (e.g., each tank 220) may have its own
distinct ballast chamber. In general, ballast 241 counteracts the
upward vertical buoyancy forces resulting from the stored gas 5
and/or air 6 in tanks 220. The quantity and weight of ballast 241
is chosen to achieve the desired total dry weight of vessel 200. As
with vessel 10 previously described, the dry weight of vessel 200
is preferably greater than the total buoyant forces acting on
vessel 200 during all operational phases of vessel 200 (e.g.,
deployment, anchoring, gas storage, disengaging, removal, and
relocation of vessel 200). Further, during deployment, removal and
relocation of vessel 200 (i.e., anytime the surface deployment
apparatus applies a lifting force to vessel 10), the total weight
of vessel 200 minus the buoyant forces acting on vessel 200 is
preferably greater than zero (to prevent the uncontrolled ascent of
vessel 200) and less than the maximum hook load capacity of the
deployment apparatus (to ensure the maximum hook load capacity is
not exceeded).
[0082] In this embodiment, each tank 220 includes a gas storage bag
250 and is adapted to store gas 5 in order to maximize the gas
storage volume or capacity of vessel 200. However, in other
embodiments, one or more of the tanks of a compartmentalized subsea
gas storage vessel (e.g., tanks 220 of vessel 200) may serve as a
dedicated ballasting cell that may be used to provide buoyancy
during installation and then flooded during anchoring.
[0083] Vessel 200 is operated in a similar fashion as vessel 10
previously described. Specifically, during deployment subsea,
vessel 200 is connected by a releasable coupling 270 at upper end
200a to a deployment apparatus at the surface (e.g., a crane on a
surface vessel). The dry weight of vessel 200 is preferably greater
than the maximum buoyancy forces acting on vessel 200 during
deployment, and thus, vessel 200 naturally wants to sink. The
maximum possible buoyant forces resulting from air 6 in tanks 220
during deployment occurs when second region 221b of each tank 220
is completely filled with air 6 from upper end 200a to its
respective port 226. No greater buoyant force can be achieved while
vessel 200 is subsea since any additional air volume in any tank
220 will simply exit through port 226. Accordingly, the maximum
possible buoyant force of each tank 220 can be adjusted by varying
the axial position or height of port 226.
[0084] The deployment apparatus connected to coupling 270 applies
an upward, vertical lifting force to vessel 200 to manage and
control the rate at which vessel 200 submerges subsea. As vessel
200 is lowered subsea, sea water 3 in outer region 222 flows
through ports 226 of tanks 220. With valve 223a closed, sea water 3
continues to flow into second region 221b, the air 6 in second
region 221b is compressed, and the buoyancy provided by tanks 220
decreases. However, during deployment of vessel 200, valve 224a is
opened and air 6 is pumped through valve 224a, header pipe 224b,
and inlets 224 into second region 221b of each tank 220 to maintain
a sufficient buoyant force. In particular, during deployment,
disengagement, removal and relocation of vessel 10 (i.e., anytime
the surface deployment apparatus applies a lifting force to vessel
10), the total weight of vessel 10 minus the buoyant force is
preferably greater than zero (to prevent an uncontrolled ascent of
vessel 10) and less than the maximum hook load capacity of the
deployment apparatus (to ensure the maximum hook load capacity is
not exceeded).
[0085] Once vessel 200 reaches the sea floor 4, skirts 230 begin to
engage and penetrate the sea floor 4. To anchor vessel 200 to the
sea floor 4, valve 224a is closed and pumping of air 6 through
header pipe 224b and inlets 224 is ceased, and valve 223a is opened
to allow any air 6 in second region 221b of each tank 220 to exit.
As air 6 exits tanks 220, sea water 3 flows through ports 226 and
fills the remainder of second region 221b of each tank 220, thereby
reducing and/or eliminating the buoyancy of tanks 220. As the
buoyancy of vessel 200 is reduced, skirts 230 penetrate further
into sea floor 4 under the weight of vessel 200. To enhance
seating, a suction control apparatus may be employed as previously
described. Once anchoring is complete, valve 223a may be closed,
coupling 270 may be released to disconnect the deployment apparatus
from vessel 200, a gas supply may be coupled to header pipe 225b,
and valve 225a may be opened to allow for the flow of gas 5 through
header pipe 225b and valve 225a into gas storage bags 250.
[0086] During gas storage operations, valve 225a is opened and
valves 223a, 224a are closed. As the volume of gas 5 in each bag
250 increases, the buoyancy of each tank 220 also increases.
However, as previously described, the amount and weight of ballast
241 is set such that the total weight of vessel 200 is greater than
the maximum possible buoyancy forces resulting from stored gas 5.
Consequently, vessel 200 remains anchored to the sea floor 4 as the
volume of gas 5 in each tank 220 increases.
[0087] To remove and/or relocate vessel 200, vessel 200 must first
be disengaged from the sea floor 4, and then lifted and moved to
the desired location. To initiate disengagement of vessel 200 from
the sea floor 4, stored gas 5 is emptied from each bag 250, valve
225a is closed, and valve 223a is closed (if not already closed).
In addition, the surface deployment apparatus is coupled to vessel
200 via coupling 270, an upward lifting force is applied to vessel
200 by the deployment apparatus, valve 224a is opened, and air 6 is
pumped through valve 224a, header pipe 224b, and inlets 224 into
second region 21b of each tank 220. As air 6 is pumped into each
tank 220, the air 6 rises to the top of each tank 220 and begins to
displace sea water 3 in the tank 220, thereby increasing the
buoyancy of each tank 220 and vessel 200. The displaced sea water 3
is free to exit each tank 220 through its port 226. In addition to
the lifting and buoyant forces acting on vessel 200, a suction
control apparatus may be employed as previously described to
decrease suction forces between vessel 200 and the sea floor.
[0088] Once vessel 200 is disengaged from sea floor 4, it may be
lifted to the surface or lifted and relocated to a different subsea
location. To continue lifting vessel 200, valves 223a and 225a are
maintained in the closed positions. Further, the deployment
apparatus continues to apply a vertical lifting force to vessel 200
and air 6 continues to be pumped through valve 224a, header pipe
224b, and inlets 24 into each tank 220. As the depth of tank 20
decreases, the hydrostatic pressure of sea water 3 decreases and
the air 6 in each tank 220 expands. The expansion of air 6 in each
tank 220 and the continued pumping of air 6 into each tank 220
continues to increase the buoyancy of each tank 220 and vessel 200.
However, regardless of the depth of vessel 200, the expansion of
air 6 in tank 20, and the volume of air 6 pumped into each tank
220, the buoyancy of each tank 220 and vessel 200 cannot exceed a
predetermined maximum buoyancy defined by the location of ports
226. As previously described, the maximum buoyancy of each tank 220
due to air 6 occurs when second region 221b is completely filled
with air 6 from upper end 200a to port 226. Any additional volume
of air 6 will simply exit the tank 220 and second region 221b
through port 226.
[0089] As previously described, vessel 200 is deployed subsea as a
single structure or unit. However, in some applications, it may be
desirable to deploy vessel 200 in separate parts, and then assembly
vessel 200 subsea. For example, base 260 may be deployed and
anchored to the sea floor, and then tanks 220 may be deployed and
coupled to the top of the previously anchored base 260. Upon
removal and relocation, the base 260 may be left in place or
removed along with tanks 220. In this way, the overall weight and
complexity of the lift may be minimized, although there may be some
additional complication involved in coupling the tanks 220 and base
260 at depth.
[0090] As previously described, during deployment of embodiments of
gas storage vessels described herein (e.g., vessel 10, vessel 200,
etc.), the total weight of the gas storage vessel minus the
buoyancy of the vessel is preferably greater than zero and less
than the maximum hook load capacity of the deployment apparatus at
the surface. As a result, the static load of the gas storage vessel
is sufficiently small to enable controlled deployment with
conventional surface deployment equipment such as cranes mounted to
surface vessels. However, dynamic loads must also be taken into
account because the total entrapped mass and added mass above and
below the vessel are substantial. The total system mass combined
with the fact that the floating deployment apparatus may be moving
dynamically with wave excitations can create significant dynamic
loads.
[0091] Due to the load capacity and heave compensation
requirements, deployment with conventional winch wire may be
difficult. Further, since winch wires generally do not resist
rotational torques, the winch wire and any supply or control lines
extending from the floating deployment vessel to the subsea gas
storage vessel (e.g., buoyancy control air supply line) may become
twisted and/or damaged. As a result, embodiments of subsea gas
storage vessels described herein are preferably deployed subsea
with a pipestring.
[0092] Referring now to FIGS. 15 and 16, an embodiment of a subsea
gas storage vessel deployment system 300 is shown. In this
embodiment, system 300 is shown deploying subsea gas storage vessel
200 previously described. System 300 includes a floating surface
vessel 310 and a pipestring 320. Surface vessel 310 includes a
derrick 311 that supports pipestring 320 and vessel 200 coupled to
the lower end of pipestring 320 with releasable coupling 270. Thus,
pipestring 310 extends from floating surface vessel 310 to gas
storage vessel 200. In this embodiment, surface vessel 310 also
includes a crane 312. A buoyancy control gas supply line 330 also
extends from floating surface vessel 310 to gas storage vessel 200.
Supply line 330 is in fluid communication with valve 224a and
header pipe 224b, and supplies buoyancy control gas or air 6 during
deployment, removal and relocation of vessel 200. In embodiments
using a combined air/water pumping system (e.g., combined air/water
pumping system 180 shown in FIG. 11) to provide air 6 to the subsea
tanks, the combined air/water solution may be delivered to the
subsea tanks with supply line 330. In this embodiment, pipestring
320 includes an in-line damping device 325 that absorbs and
dissipates dynamic loads.
[0093] Embodiments of system 300 provide several potential
advantages over conventional winch wire deployment systems. As
compared to winch wires, drilling pipes and pipestrings offer the
potential for improved load capacities. In addition, since the
pipestring (e.g., pipestring 320) is rigid, its rotation can be
controlled at the surface with conventional equipment associated
with the derrick (e.g., derrick 311) such as a top drive or rotary
table. As a result, twisting of any supply lines (e.g., supply line
330) around the pipestring can be reduced and/or completely
eliminated. Further, the load capacities of most drilling derricks
(e.g., derrick 311) is substantially greater than the load
capacities of most cranes, and thus, deployment with a pipestring
and drilling derrick offers the potential to improve safety and
enhance control over the subsea gas storage vessel. Still further,
most conventional drilling derricks offer the potential for
improved heave compensation. Specifically, the traveling block
provides some heave compensation when it supports the pipestring
(e.g., pipestring 320). When the pipestring is set down off the
traveling block in slips, heave compensation may be provided by the
damping device (e.g., damping device 325) in-line with the
pipestring.
[0094] Although embodiments described herein include a single gas
storage tank (e.g., vessel 10) or multiple gas storage tanks that
are coupled together to form a single structure (e.g., vessel 200),
it should be appreciated that a plurality of separate gas storage
vessels can be grouped together subsea to form a larger subsea gas
storage assembly or farm. In joining the storage vessels together,
standard subsea architectures can be used.
[0095] Embodiments disclosed herein may serve in a variety of
applications. For example, embodiments described herein may be used
to store natural gas produced during a offshore well testing
operation where the operator does not want to commit to building a
pipeline for gas export before the reservoir has been producing for
long enough to evaluate its characteristics and condition. As
another example, embodiments described herein may be used to store
natural gas at locations close to a pipeline network independent of
the prior existence of naturally occurring caverns. Accordingly,
embodiments described herein offer the potential to reduce
dependency on the availability of natural caverns for gas storage.
In addition, embodiments described herein may be used to store gas
in locations remote from human life and property, thereby offering
the potential to reduce risks associated with gas storage.
[0096] 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.
* * * * *