US20120260839A1

US20120260839A1 - Systems and methods for subsea gas storage installation and removal

Info

Publication number: US20120260839A1
Application number: US13/144,461
Authority: US
Inventors: James V. Maher; Edward E. Horton, III; Lyle D. Finn
Original assignee: Horton Wison Deepwater Inc
Current assignee: Wison Offshore Technology Inc
Priority date: 2010-01-05
Filing date: 2010-01-20
Publication date: 2012-10-18
Also published as: WO2011084164A1; BRPI1008151B1; BRPI1008151A2

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.

Description

This application is the U.S. National Stage under 35 U.S.C. §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

Not applicable

BACKGROUND OF THE INVENTION

1. Field of the Invention
The invention relates generally to subsea gas storage systems. More particularly, the invention relates to the deployment and removal of subsea gas storage systems.
2. Background of the Technology
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.
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.
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.
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.
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

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).
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.
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.
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

For a detailed description of exemplary embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic cross-sectional view of an embodiment of a subsea gas storage vessel;

FIG. 2 is a schematic cross-sectional view of the subsea gas storage vessel of FIG. 1 during deployment subsea;

FIG. 3 is a schematic cross-sectional view of the subsea gas storage vessel of FIG. 1 during anchoring to the sea floor;

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;

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;

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;

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;

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;

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;

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;

FIG. 11 is an embodiment of a combine water/air pumping system for deploying the subsea gas storage vessel of FIG. 1;

FIG. 12 is a front view of an embodiment of a compartmentalized subsea gas storage vessel;

FIG. 13 is a top schematic view of the subsea gas storage vessel of FIG. 11;

FIG. 14 is a schematic cross-sectional view of the subsea gas storage vessel of FIG. 11; and

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

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.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first 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.
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.
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.
Vessel 10 has a central or longitudinal axis 15 and extends between an upper end 10 a and a lower end 10 b. In addition, vessel 10 includes a rigid, thin-walled storage tank 20, a mud skirt 30 at lower end 10 b, and a ballast chamber 40 containing ballast 41 proximal lower end 10 b 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 10 a positioned above lower end 10 b. 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.
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.
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 21 a inside chamber 21 and bag 50, and a second region 21 b 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 21 b is close to zero.
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 21 b. In this embodiment, buoyancy control gas outlet 23 is at upper end 10 a, and buoyancy control gas inlet 24 is positioned distal upper end 10 a and proximal ballast chamber 40. The flow of a air 6 out of and into second region 21 b through outlet 23 and inlet 24, respectively, is controlled by an outlet valve 23 a and inlet valve 24 a, 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 24 a into second region 21 b 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 21 b is exhausted through outlet 23 and associated valve 23 a into sea water 3 outside tank 20 to decrease the buoyant forces acting on vessel 10.
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 10 a, 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 25 a. In this embodiment, one conduit 25, port 51 and valve 25 a 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.
Storage tank 20 further includes a through port 26 distal upper end 10 a 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 21 b. 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 21 b, 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 21 b (if any), and the pressure of buoyancy control gas in storage second region 21 b (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 21 b; during anchoring operations (FIG. 3), sea water 3 flows through port 26 into tank 20 and second region 21 b; 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 21 b; and during lifting operations (FIG. 6), air 6 flow out of tank and second region 21 b.
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 L₁₀measured between ends 10 a, b, and tank 20 has a total axial length L₂₀measured between upper end 10 a and ballast chamber 40. Furthermore, vessel 10 has a maximum outer diameter D₁₀and tank 20 has a maximum outer diameter D₂₀. In this embodiment, diameter D₁₀and diameter D₂₀are the same. In general, vessel 10 and tank 20 may have any suitable lengths L₁₀, L₂₀and diameters D₁₀, D₂₀. For most subsea gas storage applications, length L₁₀is preferably at least 50 ft, length L₂₀is preferably at least 40 ft., and diameters D₁₀, D₂₀are preferably each at least 20 ft. In one exemplary embodiment, lengths L₁₀is about 50 ft, L₂₀is about 40 ft, and diameters D₁₀, D₂₀are each about 26 ft. The primary design considerations in determining lengths L₁₀, L₂₀and diameter D₁₀, D₂₀are total gas storage volume and dry weight of vessel 10. To maintain a given gas storage volume, as the tank diameter (e.g., diameter D₂₀) increase, the tank length (e.g., length L₂₀) 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.
Flexible gas storage bag 50 is designed to expand when the pressure in first region 21 a is greater than the pressure in second region 21 b, and contract when the pressure in first region 21 a is less than the pressure in second region 21 b. Further, when first region 21 a 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 21 a is substantially empty and bag 50 is collapsed. However, as shown in FIG. 4, during subsea gas storage operations, first region 21 a 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 21 b comprises sea water 3 and a air 6; and as shown in FIG. 4, during subsea gas storage operations, second region 21 b comprises sea water 3.
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., CO₂). 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 21 a and sea water 3 in second region 21 b, thereby reducing and/or eliminating the potential for the undesirable formation of hydrates and undesirable methane releases.
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.
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 21 b 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 21 a 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.
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 21 b 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 10 a.
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 21 b. The maximum pressure differential experienced by bag 50 during radial expansion is the pressure differential proximal upper end 10 a. Bag 50 is preferably designed to withstand the maximum anticipated pressure differential proximal upper end 10 a 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 10 a 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 10 a.
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 10 b. 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.
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.
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.
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.
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.
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.
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.
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 10 a 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 21 b is completely filled with air 6 from upper end 10 a 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.
The deployment apparatus connected to upper end 10 a applies an upward, vertical lifting force to upper end 10 a 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 10 a 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 21 b within tank 20. With valve 23 a closed, as vessel 10 is lowered, sea water 3 continues to flow into second region 21 b and the air 6 in second region 21 b 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 21 b 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 21 b 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 21 b is much slower.
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 24 a is opened and air 6 is pumped through valve 24 a and inlet 24 into second region 21 b 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).
Pumping air 6 into second region 21 b 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 21 b continues to be compressed, the pumping requirements increase, and thus, larger and/or more specialized marine compressors may be required.
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 24 a is closed and pumping of air 6 through inlet 24 into second region 21 b is ceased, and valve 23 a is opened to allow any air 6 in second region 21 b to exit inner region 21 b. 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 21 b, 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 23 a may be closed, the deployment apparatus may be decoupled from vessel 10, a gas supply may be coupled to conduit 25, and valve 25 a may be opened to allow for the flow of gas 5 into gas storage bag 50.
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.
Referring now to FIG. 6, during gas storage operations, valve 25 a is opened and valves 23 a, 24 a 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.
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 25 a is closed, and valve 23 a is closed (if not already closed). In addition, the deployment apparatus is coupled to upper end 10 a of vessel 10 and applies an upward lifting force to vessel 10, valve 24 a is opened, and air 6 is pumped through valve 24 a and inlet 24 into second region 21 b 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 21 b, 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.
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 23 a and 25 a 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 24 a and inlet 24 into second region 21 b. As the depth of tank 20 decreases, the hydrostatic pressure of sea water 3 decreases and the air 6 in second region 21 b expands. The expansion of air 6 in second region 21 b and the continued pumping of air 6 into second region 21 b 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 21 b is completely filled with air 6 from upper end 10 a to port 26. Any additional volume of air 6 will simply exit tank 20 and second region 21 b 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 10 a, the lower the maximum possible buoyant force due to air 6, and the closer the port 26 to lower end 10 b, 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.
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.
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 25 a is closed, and valve 23 a is closed (if not already closed). In addition, the deployment apparatus is coupled to upper end 10 a of vessel 10 and applies an upward lifting force to vessel 10, valve 24 a is opened, and air 6 is pumped through valve 24 a and inlet 24 into second region 21 b 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 24 a and inlet 24 into second region 21 b. 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 25 a is closed, and valve 23 a is closed (if not already closed). In addition, the deployment apparatus is coupled to upper end 10 a of vessel 10 and applies an upward lifting force to vessel 10. Next, valve 24 a is opened and air 6 is pumped through valve 24 a and inlet 24 into second region 21 b of tank 20. As air 6 is pumped into tank 20, it naturally rises to the top of second region 21 b and displaces water 3 within second region 21 b. 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 24 a and inlet 24 into second region 21 b. Thus, in this embodiment, the buoyancy of air 6 and stored gas 5 within tank 20 are leveraged during the disengagement and removal processes.
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 25 a 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.
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.
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 25 a 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.
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.
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 21 b. 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 24 a 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.
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.
Referring still to FIG. 11, once the combined air-water solution reaches tank 20, the air 6 rises within second region 21 b 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.
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 21 a, 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.
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 200 a and a lower end 200 b. 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 200 a positioned above lower end 200 b.
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 221 a inside chamber 221 and bag 250, and a second region 221 b 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 223 b, and each buoyancy control gas inlet 224 is in fluid communication with a header pipe or conduit 224 b. Outlet valve 223 a controls the flow of buoyancy control gas or air 6 through outlets 223 and header pipe 223 b, and inlet valve 224 a controls the flow of buoyancy control gas or air 6 through header pipe 224 b and gas inlets 224. Thus, in this embodiment, one outlet valve 223 a controls the exhaust of air 6 from every tank 220, and one inlet valve 224 a 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.
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 225 b. The flow of a stored gas 5 into and out of each gas storage bag 250 through header pipe 225 b, each conduit 225, and each gas port 251 is controlled by a gas valve 225 a. Thus, in this embodiment, one gas valve 225 a 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.
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.
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 200 b. 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.
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.
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).
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.
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 200 a 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 221 b of each tank 220 is completely filled with air 6 from upper end 200 a 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.
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 223 a closed, sea water 3 continues to flow into second region 221 b, the air 6 in second region 221 b is compressed, and the buoyancy provided by tanks 220 decreases. However, during deployment of vessel 200, valve 224 a is opened and air 6 is pumped through valve 224 a, header pipe 224 b, and inlets 224 into second region 221 b 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).
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 224 a is closed and pumping of air 6 through header pipe 224 b and inlets 224 is ceased, and valve 223 a is opened to allow any air 6 in second region 221 b 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 221 b 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 223 a 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 225 b, and valve 225 a may be opened to allow for the flow of gas 5 through header pipe 225 b and valve 225 a into gas storage bags 250.
During gas storage operations, valve 225 a is opened and valves 223 a, 224 a 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.
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 225 a is closed, and valve 223 a 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 224 a is opened, and air 6 is pumped through valve 224 a, header pipe 224 b, and inlets 224 into second region 21 b 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.
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 223 a and 225 a 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 224 a, header pipe 224 b, 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 221 b is completely filled with air 6 from upper end 200 a to port 226. Any additional volume of air 6 will simply exit the tank 220 and second region 221 b through port 226.
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.
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.
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.
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 224 a and header pipe 224 b, 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.
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.
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.
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.
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.

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.