Title:
Infrastructure-independent deepwater oil field development concept
Kind Code:
A1


Abstract:
A method for developing a sub-sea hydrocarbons field includes sub-sea wells, sub-sea oil/gas separation, storing the degassed oil in a storage tank located or the seabed, liquefying natural gas aboard a vessel using liquid nitrogen aboard the vessel to obtain liquefied natural gas, transporting the liquefied natural gas to an onshore terminal, re-gasifying the liquefied natural gas, and obtaining a new batch of liquid nitrogen using energy recovered from the re-gasifying the liquefied natural gas.



Inventors:
Choi, Michael S. (Houston, TX, US)
Application Number:
10/679545
Publication Date:
01/05/2006
Filing Date:
10/06/2003
Primary Class:
International Classes:
E21B29/12; B63B27/24; B63B27/34; B63B35/44; B65D88/78; E21B43/01; F25J1/02
View Patent Images:
Related US Applications:



Primary Examiner:
BUCHANAN, CHRISTOPHER R
Attorney, Agent or Firm:
Patricia A.Meier (ConocoPhillips Company IP Legal P.O.Box 2443, Bartlesville, OK, 74005, US)
Claims:
What is claimed is:

1. A method for developing a sub-sea hydrocarbons field, comprising: liquefying natural gas aboard a vessel using a liquid coolant aboard the vessel to obtain liquefied natural gas; transporting the liquefied natural gas to an onshore terminal, re-gasifying the liquefied natural gas; and obtaining a new batch of liquid coolant using energy recovered from the re-gasifying the liquefied natural gas.

2. The method of claim 1, wherein the liquid coolant comprises liquid nitrogen and further comprising: transporting the new batch of liquid nitrogen offshore aboard the vessel using a plurality of storage tanks.

3. The method of claim 1, further comprising: de-gasifying hydrocarbons obtained from the sub-sea hydrocarbons field to produce oil and gas; and conveying the produced gas to the vessel and the produced oil to the storage tank on the seabed.

4. The method of claim 3, wherein the produced gas is conveyed to the vessel via a riser.

5. The method of claim 3, further comprising. pre-treating the produced gas before liquefying.

6. The method of claim 3, further comprising: storing the oil in a storage tank attached to a seabed.

7. The method of claim 1, further comprising: liquefying a new batch of natural gas using the new batch of liquid nitrogen aboard the vessel.

8. The method of claim 1, wherein one of a plurality of storage tanks aboard the vessel storage tanks is empty to receive an initial portion of the liquefied natural gas.

9. The method of claim 1, wherein the re-gasifying the liquid natural gas is performed at the onshore terminal.

10. The method of claim 1, wherein re-gasifying the liquefied natural gas produces high pressure gas.

11. The method of claim 10, further comprising: sending the high pressure gas to a pipeline.

12. The method of claim 1, wherein transporting the liquefied natural gas to the onshore terminal is performed using the vessel.

13. A system for developing an oil and gas field, comprising: a vessel configured to liquefy natural gas to obtain liquefied natural gas using liquid nitrogen aboard the vessel; and an onshore terminal configured to obtain a new batch of liquid nitrogen using refrigeration recovered from re-gasifying the liquefied natural gas.

14. The system of claim 13, further comprising: a sub-sea separation system configured to de-gasify hydrocarbons to produce oil and gas; and a natural gas conveyance system configured to use a riser to convey the gas produced from the sub-sea separation system to the vessel; and convey the oil produced from the sub-sea separation system to a sub0-sea storage tank.

15. The system of claim 14, further comprising: a natural gas pre-treating facility configured to treat the produced gas.

16. The system of claim 14, further comprising: a power and control buoy configured to provide electric power and control functions for the sub-sea separation system.

17. An apparatus for developing a sub-sea hydrocarbons field, comprising: means for liquefying natural gas aboard a vessel using liquid nitrogen aboard the vessel to obtain liquefied natural gas; means for transporting the liquefied natural gas to an onshore terminal; means for re-gasifying the liquefied natural gas; and means for obtaining a new batch of liquid nitrogen using energy recovered from the re-gasifying the liquefied natural gas.

Description:

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation-in-part of application Ser. No. 09/818,117 filed on Mar. 27, 2001, and assigned to the assignee of the present invention. That application is hereby incorporated by reference in its entirety.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates generally to offshore oil and gas production and transportation.

2. Background Art

A major factor in determining whether to exploit an offshore oil and gas field is the feasibility of handling and transporting the hydrocarbons to market once they are produced. Generally, hydrocarbons produced offshore must be transported to land-based facilities for subsequent processing and distribution. Temporary storage may be provided at the offshore production site for holding limited quantities of hydrocarbons produced and awaiting transport to shore. In some cases, equipment is also provided at the offshore production site for separating and/or treating the produced hydrocarbons prior to storing and transporting them to shore.

In the case of an offshore production facility located relatively close to shore, hydrocarbons (i.e., oil and/or natural gas) produced may be feasibly transported to shore through a pipeline system extending from the offshore site (e.g., offshore platform or sub-sea wells) to the shore along the ocean floor or seabed. This type of pipeline system is typically preferred, when feasible, because it permits the constant flow of hydrocarbons to shore regardless of the weather or other adverse conditions. However, in some parts of the world, the use of a seabed pipeline system for transporting hydrocarbons to shore may not be economically feasible.

For offshore facilities located a great distance from shore, construction of a pipeline to shore is typically not practicable. In these cases, floating vessels, known as tankers, are used to transport hydrocarbons to shore. Tankers are specially designed vessels, which have liquid hydrocarbon storage (or holding) facilities, typically, in the hull of the vessel. In the case of crude oil production, natural gas, water, and other impurities are typically removed from the oil prior to offloading the oil onto tankers for transport.

Because tankers float on the water surface, their operations are largely dependent upon surface conditions, such as wind, wave, and current conditions. Thus, tankers are typically not operated during severe or unfavorable conditions. Additionally, operation of a particular tanker may be interrupted periodically for maintenance and repairs. Due to the large expense associated with maintaining tankers, tankers may also be shared among several offshore sites. As a result, long delay periods may occur between tanker availability for a particular site. Therefore, it is desirable to have storage facilities available at the offshore site to avoid the need to “shut-in” (or halt) production due to tanker unavailability. Additionally, offshore storage may be desired to allow for continuous production operations, independent of tanker hook-up and disconnect operations, as discussed below.

Examples of existing offshore production and storage systems used for deepwater applications are illustrated in FIG. 1 and in FIGS. 2A-2D. FIG. 1 shows one example of a production platform 2 used in a deepwater application. This production platform 2 includes processing and storage equipment 4 for separating and treating crude oil collected from platform wells 5 and sub-sea wells 6 and storing a limited quantity of the processed oil when transport is not available. Because the surface area and weight carrying capacity of the production platform 2 is extremely limited, storage facilities provided on a platform 2 are limited in size and, thus, inadequate for handling large quantities of hydrocarbons which may be produced during periods of shuttle tanker or other hydrocarbon transport unavailability.

FIG. 2A shows a floating production, storage, and offloading (FPSO) system 10, which comprises an FPSO tanker 11 specially equipped to function as an offshore production facility. The FPSO tanker 11 is permanently moored at the offshore site and connects to the sub-sea wells or sub-sea production gathering system 14 through one or more flowlines 18 connected to the production inlet 16 of the FPSO tanker 11. During production operations, produced hydrocarbons are received, directly or indirectly, from the sub-sea wells 14. Once on the FPSO tanker 11, hydrocarbons are processed and temporarily stored. Hydrocarbons stored on the FPSO tanker 11 are periodically transferred onto a shuttle tanker 12 temporarily positioned in the vicinity of the FPSO tanker 11 during the transfer.

FIG. 2B shows one example of a floating storage and offloading (FSO) system 20, which is a pure form of ship-based storage without production facilities on board. Using this type of storage system, produced hydrocarbons from a production platform 22 are transferred to an FSO vessel 26 via a flowline (not shown) extending from the production platform 22 to the FSO system 20. Hydrocarbons transferred to the FSO vessel 26 are stored, typically in the hull of the FSO vessel 26. From the FSO vessel 26, produced hydrocarbons are periodically offloaded onto a shuttle tanker 24 for transport to shore. Also, during periods when a shuttle tanker 24 is not available for offloading the storage facility on the FSO vessel 26, it may become full requiring interruption of production until a shuttle tanker 24 is available.

FIG. 2C is an illustration of a Direct Shuttle Loading (DSL) system 30. In a DSL system 30 hydrocarbons produced from sub-sea wells 33 are collected at an offshore production gathering system, in this case a production platform 32, and directly offloaded onto a shuttle tanker 34, 38 when available, through a flowline 36. For the DSL system shown in FIG. 2C, hydrocarbons are loaded onto one shuttle tanker 34 for transport to shore while another shuttle tanker 38 waits nearby for subsequent offloading after the first tanker 34 is full and en route to shore. Like other tanker-based storage systems described above, production operations which use DSL systems 30 are susceptible to interruptions in production due to severe weather conditions and periods of shuttle tanker unavailability. Additionally, the use of a DSL system 30 may require operation of a larger shuttle tanker fleet because the presence of at least one shuttle tanker 34, 38 is required at substantially all times in order for production operations to continue. Further, in cases where no temporary storage is provided at the production site, hydrocarbon production will be interrupted every time a shuttle tanker 34, 38 is connected or disconnected for offloading and transport.

Production platforms have also been developed to integrate oil storage into the hull 44 of a platform, such as a SPAR platform 40 as shown in FIG. 2D. Thus, frequent tanker hook-ups to the platform 40 are required. In such cases, even a system comprising a platform 40 with integral storage is still too dependent upon the presence of a shuttle tanker 42.

Other offshore storage systems for deepwater applications may also include smaller thick-walled tanks designed to be sunk to the seabed and internally controlled from the surface. Because the interiors of these tanks are completely isolated from the surrounding seawater environment, these tanks require very thick walls to withstand the hydrostatic pressure difference between the sub-sea environment and the platform environment. As a result, these systems are expensive and limited in capacity. These systems also require additional equipment such as pumps, controls, and other instrumentation, for monitoring and controlling the internal tank environment and moving fluids in and out of the tanks. Other offshore storage systems exist for use in shallow water applications; however, for the most part, these systems are not applicable for use in deepwater applications.

Natural gas produced from offshore gas and oil fields may be handled using a variety of mechanisms. For example, the natural gas may be re-injected into a subsurface formation, flared onsite, or exported by pipeline. Such mechanisms for handling natural gas is used in the industry in such locations as offshore of Nigeria, and in the North Sea. Alternatively, the natural gas obtained from a sub-sea well may be pressurized, to obtain high-pressure gas, and then transferred to a tanker in compressed form.

FIG. 3 shows a system for offshore production of Liquefied Natural Gas (LNG). Natural gas supplied from an underground natural gas source 60 to a field installation 62 located on or adjacent to the sea bed 64. The natural gas is treated by the field installation 62 and transferred in compressed form via a pipeline 66 to an LNG tanker 68. The pipeline 66 through which the compressed natural gas flows is surrounded by sea water and supported by a submerged buoy 70 and a hawser 72. The submerged buoy 70 is arranged for introduction and releaseable securement in a submerged, downwardly open receiving space in the LNG tanker 68. Aboard the LNG tanker 68, the compressed natural gas is converted, at least partially, to LNG by liquefaction by a conversion plant 74. The LNG is stored in storage tanks 76. When the storage tanks 76 are full, the pipeline 66 is disconnected, and connected to another, similar, tanker.

An FPSO may also be used to obtain natural gas and liquefy the natural gas to produce LNG. The FPSO includes buffer storage tanks for temporary storage of continuously produced LNG during absence of an LNG tanker. Once the LNG tanker has returned, the LNG is offloaded from the FPSO to storage tanks on the LNG tanker using a mooring device and a cryogenic transfer device.

SUMMARY OF THE INVENTION

In general, in one aspect, the invention relates to a method for developing a sub-sea hydrocarbons field. The method comprises liquefying natural gas aboard a vessel using liquid nitrogen aboard the vessel to obtain liquefied natural gas, transporting the liquefied natural gas to an onshore terminal, re-gasifying the liquefied natural gas, and obtaining a new batch of liquid nitrogen using energy recovered from re-gasifying the liquefied natural gas.

In general, in one aspect, the invention relates to a system for developing an oil and gas field. The system comprises a vessel configured to liquefy natural gas to obtain liquefied natural gas using liquid nitrogen aboard the vessel, and an onshore terminal configured to obtain a new batch of liquid nitrogen using refrigeration recovered from re-gasifying the liquefied natural gas.

In general, in one aspect, the invention relates to an apparatus for developing a sub-sea hydrocarbons field. The method includes means for liquefying natural gas aboard a vessel using liquid nitrogen aboard the vessel to obtain liquefied natural gas, means for transporting the liquefied natural gas to an onshore terminal, re-gasifying the liquefied natural gas, and means for obtaining a new batch of liquid nitrogen using energy recovered from the re-gasifying the liquefied natural gas.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a prior art offshore production platform with processing and storage equipment on the platform.

FIG. 2A is an illustration of a prior art Floating Production, Storage, and Offloading systems.

FIG. 2B is an illustration of a prior art Floating Storage and Offloading system.

FIG. 2C is an illustration of a prior art Direct Shuttle Loading system.

FIG. 2D shows a prior art SPAR platform with an integral storage facility.

FIG. 3 shows a system for offshore production of Liquefied Natural Gas (LNG).

FIG. 4 shows an embodiment of a seabed oil storage and offtake system in accordance with the present invention.

FIG. 5 shows an embodiment of a seabed oil storage and offtake system configured to supply production to a shuttle tanker.

FIG. 6 is an illustration of an embodiment of a seabed oil storage and offtake system in oil fill mode.

FIG. 7 is an illustration of an embodiment of a seabed oil storage and offtake system in oil offtake mode.

FIG. 8 shows an embodiment of a seabed oil storage and offtake system used in connection with a sub-sea processing system.

FIG. 9 shows an embodiment of a seabed oil storage and offtake system used in connection with a sub-sea processing system.

FIG. 10 shows an embodiment of a system for developing an offshore oil and gas field.

FIG. 11 shows an embodiment of a Floating Production Storage Shuttle Vessel (FPSSV) LNG Production Facility using LIN to provide the necessary refrigeration.

FIG. 12 shows an embodiment of an onshore LNG re-gasification and Liquid Nitrogen (LIN) production facility using LIN to provide the necessary refrigeration.

FIG. 13 shows an embodiment of a flowchart for developing a sub-sea oil and gas field.

DETAILED DESCRIPTION

Referring to the drawings wherein like reference characters are used for like parts throughout the several views, FIG. 4 shows one embodiment of a seabed pertains subsea storage hydrocarbon storage and offtake system in accordance with the present invention. The storage and offtake system comprises a storage tank 100 adapted for placement on and, possibly, attachment to, the seabed 114. The tank 100 comprises a top 100a, a bottom 100b, and one or more side walls 100c. At the base of the tank 100, there is an amount of fixed ballast, such as sand, concrete or other dense material, to provide submerged weight to overcome the buoyancy force of the hydrocarbon when the tank 100 is filled to its maximum storage capacity. In the embodiment shown, the tank 100 rests on the sea floor at a depth of approximately 6000 feet.

The tank may comprise any configuration as determined by one skilled in the art, including cylindrical-shaped, box-shaped, or the like. Those skilled in the art will appreciate that the configuration of the tank is a matter of convenience for the system designer. For example, in a particular embodiment, the tank may comprise a box-shaped configuration and a web-framed steel structure so that it may be constructed using standard ship building techniques, launched from conventional shipways, and have stable floatation for open-water tow.

The storage and offtake system further includes at least one fluid channel 127, such as a standpipe more distinctly illustrated in FIGS. 5 and 6. As shown in the embodiment in FIGS. 5 and 6, the fluid channel 127 has a first end 124a positioned inside of the tank 100 proximal the bottom 100b of the tank 100 and a second end 124b in fluid communication with the environment 125 outside of the tank 100. In one or more embodiments, the second end 124b is positioned away from the seabed (114 in FIG. 4).

Referring once again to FIG. 4, the storage and offtake system further includes at least one offload comprised of a rigid riser 104 and a flexible hose 103. The rigid riser 104 has a first end coupled to the tank 100 and in fluid communication with the interior of the tank 100 proximal the top 100a of the tank 100. A second end of the rigid riser 104 is connected to the flexible hose 103, which adapted to couple in fluid communication to a transport vessel (illustrated in FIG. 5) and to be accessible, in a manner, which will be further explained, from the water surface 116.

The storage and offtake system further includes a vessel mooring system, which has at least one hawser 110. As shown in FIG. 4, the hawser 110 includes a first end operatively coupled to the surface buoy 106 and a second end adapted to be accessible from the water surface 116 through the surface buoy 112. The second end is also adapted to attach to the transport vessel to anchor the transport vessel during offloading operations, as illustrated in FIG. 5.

Referring once again to FIG. 4, suction or conventional piles 102 may be used to attach the tank 100 to the seabed 114 to provide lateral resistance for the tank 100 to sliding due to the slope of the seabed or other lateral forces that may be applied to the storage tank 100 during operation. Additionally, the piles 102 may also act as a restraint for the storage tank 100, which provides mooring for the tanker during offloading operations (illustrated in FIG. 5).

It should be understood that the storage tank 100 may include any material suitable for use as a tank, e.g., steel, concrete, or a composite material such as glass or carbon fiber reinforced plastic. The inside and outside of the tank 100 may also be coated with cement or any other coating material known in the art for protecting structures formed from a metal such as steel against deterioration due to operation in a saltwater environment. In one or more embodiments, the storage tank 100 is a gravity based, pressure balanced structure, as will be described in more detail below.

The lower portion of the offload line 103 in the embodiment shown includes a substantially rigid member, such as a marine riser 104. As shown in FIGS. 3 and 4, the riser 104 in this embodiment is a self-standing, top-tensioned riser; wherein one end of the riser 104 connects to the top of the storage tank 100 and the other end of the riser 104 connects to a subsurface buoyant device (for example, subsurface buoy 106) to maintain the riser 104 in tension in a substantially upright position when the system is submerged in water. To facilitate the interface between the lower end of the riser 104 and the top of the tank 100a, a Lower Marine Riser Package (LMRP) may be used, such as one available from ABB Vetco-Gray, Houston, Tex., or a similar device.

In one or more embodiments, the riser 104 also functions as part of the transport vessel mooring system (further described below). In such case, the riser 104 should be designed to withstand the additional forces expected to be imposed on it by mooring a tanker (illustrated in FIG. 5) to the tank 100 via the riser 104. Those skilled in the art will appreciate that the riser 104, or the like, may be made of any material suitable for the particular application, e.g., steel, or a composite material. Additionally, the external surface of the riser 104 exposed to the seawater environment may be coated with a suitable protective material.

As previously described and shown in FIG. 4, a subsurface buoy 106, or other buoyant device, may be attached to the upper end of the riser 104 to maintain the riser 104 in an upright position and in tension. For example, the subsurface buoy 106 illustrated in FIG. 4 may include one or more chambers filled with fluid substantially lighter than seawater, such as air or oil, and a center passage therethrough for the top of the riser 104 to interface with an end of the upper portion of the offload line 103.

Also as shown in FIG. 4, the subsurface buoy 106 and the upper end of the riser 104 are located a selected distance below the water surface 116. This distance may be selected such that the effects of surface environmental loads, such as the wind, waves, and current, on the subsurface buoy 106 and riser 104 will be feasibly minimized. A desirable depth for a particular embodiment is site specific and may be determined by one skilled in the art based on factors such as the structural integrity of a selected riser 104 (e.g., rigidity, length, and tension) and worst case environmental operating conditions, such as a 1-year, 10-year, or 100-year worst storm criteria for the particular sea state. For example, based on the structural integrity of a particular riser and particular storm criteria, a subsurface buoyant device may be located at a depth below the water surface such that the effects of waves and surface currents on the buoyant device is less than 10%, or more preferably less than 2%, of the effect if the buoyant device was located at the water surface 116. In some cases this depth may be at least 50 feet below the water surface 116. In other cases this depth may be at least 200 feet below the water surface 116. However, as will be appreciated by those skilled in the art, criteria used to determine the desired depth of the subsurface buoyant device and the selected depth are matters of convenience for a system designer. Further, those skilled in the art will appreciate that in the case of the riser 104 used as part of the mooring system (further described below), the tension needed on the riser can be determined based on factors such as the size of the shuttle tanker to be moored, the water depth in which the system is installed, environmental conditions (such as wind, waves, and current) at the particular site, and the worst storm conditions for which the system is designed to function.

The upper portion of the offload line 103 may include a flexible member, such as a hose or series of rigid segments (e.g., subpipe sections) coupled by flex joints. In the embodiment shown in FIGS. 3 and 4, the flexible member includes a hose 108. The hose 108 provides a flexible fluid channel, which extends from the top of the riser 104 to the water surface 116. The hose 108 is in fluid communication with the riser 104 through the subsurface buoy 106 to transfer hydrocarbons (oil) from the tank 100 to a transport vessel such as a shuttle tanker (shown as 113 in FIG. 5) or the like.

In the embodiment shown, the lower end of the hose 108 is attached to the top of the riser 104 at the subsurface buoy 106, and the upper end of the hose 108 is attached to a surface buoy 112 so that the hose 108 can be easily accessed from the water surface 116 for offloading (or offtake) operations. Those skilled in the art will appreciate that the flexible upper portion of the offload line 103 may be made of any material suitable for a particular application, such as rubber, metal, composite material, or a combination thereof.

As shown in FIGS. 3 and 4, in one embodiment, the hawser 110 operatively couples to the tank 100 through the riser 104. One end of the hawser 110 is connected to the subsurface buoy 106 at the upper end of the riser 104. The other end of the hawser 110 is connected to the surface buoy 112. As a result, the hawser 110 can be used to anchor a transport vessel, such as a shuttle tanker (113 in FIG. 5) or the like, to the tank 100 during offloading operations, or during servicing of the system. In this embodiment, the hawser 110 is shorter in length than the hose 108, which ensures that the hawser 110, and not the hose 108, provides the anchoring connection between the riser 104 and any vessel connected to the hawser 110 at the water surface 116. Those skilled in the art will appreciate that in other embodiments, the hawser 110 may be operatively coupled directly or indirectly to the tank 100 in a manner different than the manner shown in FIGS. 3 and 4, without departing from the spirit of the invention. Those skilled in the art will also appreciate that hawsers for mooring transport vessels and the like are well known in the art and that any type of hawser considered suitable for a particular application by a system designer may be used for the system without departing from the spirit of the invention.

As previously explained with respect to FIG. 4, one or more buoyant devices, such as surface buoy 112, may be attached to the upper end of the hose 108 and the upper end of the hawser 110 to maintain the surface ends thereof so that they are easily accessible at the water surface 116. In some embodiments, the storage and offtake system may also include a coupling, such as a flex joint 118 and/or swivel joint 120, disposed between the riser 104 and the hose 108 and/or the riser 104 and the hawser 110 to enable the hose 108 and the hawser 110 to rotate freely with respect to the riser 104. In the embodiment shown in FIG. 4, the flex joint 118 is positioned between the riser 104 and the subsurface buoy 106, and a swivel joint 120 is positioned between the top of the riser 104 and the ends of the hose 108 and hawser 110 proximal the subsurface buoy 106. Additionally, the system may include any connection device known in the art at the accessible end of each of the hose 108 and the hawser 110 for releasably connecting the hose 108 and the hawser 110 to a tanker 113 or other transport vessel during offloading operations.

Now referring to FIGS. 6 and 7, as previously discussed, the storage tank 100 of the system is substantially pressure balanced. This pressure balance can be achieved by providing that the inside of the tank 100 is in fluid communication with the seawater environment outside of the tank 100 at substantially the same depth. Those skilled in the art will appreciate that in the case of a pressure balanced tank 100, the transportation and installation loads, rather than differential pressure across the tank 100 during operation will primarily affect the structural design of the tank 100. This allows for pressure balanced tanks to have substantially reduced wall thickness in comparison to enclosed storage systems on the seabed, which are subject to hydrostatic pressure differences across the walls of the tank. This also allows for feasible tanks with larger storage capacities, such as up to 2 million barrels of oil, for deepwater service, such as in depths up to 10,000 feet of water, or more. In one embodiment, for example, the tank may have dimensions of about 200 feet long, about 200 feet wide, and about 150 feet tall and may have a capacity around 750,000 barrels. Thus, embodiments of the invention may provide a lower cost option and/or increased storage capacity than other storage systems.

Examples of a pressure balanced tank during normal operations in accordance with the above description are shown in FIGS. 6 and 7. FIG. 7 is an illustration of a storage tank 100 during a “filling” operation. FIG. 7 is an illustration of a storage tank 100 during an “offtake” operation. In the examples shown, the pressure balance is achieved through the use of a fluid channel 127, which extends from a lower location inside of the storage tank 100 through an upper section of the tank 100 and into the surrounding seawater environment 125. The fluid channel 127 allows the interior of the storage tank 100 to be in fluid communication with the seawater environment 125. Hydrocarbons 121 entering the tank 100 will float to the top 100a of the tank 100 and become trapped in the riser 104 and the upper portion of the tank 100, thereby displacing water 123 in the tank to the bottom 100b of the tank 100.

Those skilled in the art will appreciate that the tank 100 may additionally include instrumentation to ensure that the maximum and minimum oil 121 and water 123 levels for a selected tank design are not exceeded. Those skilled in the art will also appreciate that the fluid channel 127 may be constructed in any configuration and may communicate with the seawater environment outside of the tank 100 at any location, such as through a side wall of the tank 100, as determined by the system designer without departing from the spirit of the invention. In one embodiment, the fluid channel 127 is in fluid communication with the surrounding seawater environment 125 at a location away from the seabed (114 in FIGS. 4 and 5) as further discussed below.

As shown in FIG. 6 (and FIG. 7), the fluid channel 127 may extend through the top of the tank 100 to elevate the point of water discharge (and intake) at the external end 124b of the fluid channel 127, away from the seabed (at 114 in FIGS. 4 and 5). Locating the external end 124b of the fluid channel 127 away from the seabed (114 in FIGS. 4 and 5) improves the dispersion of seawater exiting the tank and prevents scouring around the base of the storage tank 100. A storage tank 100 with a fluid channel 127 as shown in FIGS. 6 and 7 is functionally the same as an opened bottom tank with respect to pressure-balancing the tank. However, a storage tank 100 with a fluid channel 127 for seawater intake and discharge is more effective because it eliminates problems associated with water dispersion and scouring around the base of the tank 100. Additionally, a storage tank 100 having a fluid channel 127 arrangement as shown may also allow for improved monitoring and control of seawater flow in and out of the storage tank 100 in comparison to open bottom tanks. For example, the system may additionally include instrumentation in or proximal to an end of the fluid channel 127 for monitoring and controlling fluid flow through the fluid channel 127 as determined by the system designer. For instance, a device measuring the resistivity of fluids or residue oil content in the water leaving the fluid channel 127 may be included in the system.

Referring to FIG. 6, during production operations, as hydrocarbons enter the storage tank 100 through the inlet 122, the hydrocarbon/water interface 129 is pushed downward displacing seawater 123 out of the fluid channel 127 and into the surrounding seawater environment 125. It should be understood that in one embodiment, this hydrocarbon/water interface 129 is naturally formed by pumping hydrocarbons (oil) 121 directly on water 123 in the tank and allowing the hydrocarbons 121 to naturally rise to the top of the tank 100 displacing water 123 to the lower section of the tank 100. However, in other embodiments this interface 129 may be mechanically maintained using a flexible or permeable membrane member in the tank, which is displaced in the tank as hydrocarbons 121 flow in or out of the tank 100.

Referring now to FIG. 7, during offtake operations, hydrocarbons 121 in the tank 100 may be offloaded onto a transport vessel, such as a shuttle tanker (113 in FIG. 5) or the like for transport to shore. For example, once the transport vessel is moored using the hawser 110 (in FIG. 5), and the hose 108 (in FIG. 5) is connected to the vessel, a surface valve or other remotely located valve, such as valve 128, is opened and the hydrostatic pressure imbalance due to the gravity difference between the hydrocarbon and seawater columns provides the motive force required to force the hydrocarbons 121 up the riser 104 and hose 108 (in FIG. 5) to the transport vessel at the surface 116. Thus, no pump is required to lift the hydrocarbons 121 from the storage tank 100 to the shuttle tanker (113 in FIG. 5) during the offtake operation. The energy available to transport hydrocarbons 121 up the offload line 103 (in FIG. 5) is substantially equal to the hydrostatic pressure difference between the hydrocarbons 121 and seawater 123 columns. For example, for a 30° API oil stored in a tank at a 6,000-foot water depth, the differential pressure between the fluid columns will be about 325 psi, which is more than sufficient to move the hydrocarbons 121 up the offload line 103 (in FIG. 5) and into a tanker 113.

Now referring again to FIG. 4, one skilled in the art will appreciate that to install a storage tank 100 at a location offshore, the tank 100 may be filled with a fluid lighter than seawater, such as light oil, in protective water and towed to a desired location. Seawater may then be pumped into the tank 100 while displacing the light oil to sink the tank 100 to the seabed 114. The displaced light oil may be recovered and stored in an accompanying tank or tanker. For example, once at the desired surface location, seawater may be pumped into the inlet 122 of the tank 100 until the weight of the seawater plus the weight of the tank 100 is sufficient to overcome the buoyancy force on the tank 100, which initially is full of light oil. Once the buoyancy of the tank 100 is properly adjusted with light oil and seawater, tank 100 is lowered to the seabed. Then, when the tank 100 is in place on the seabed 114, the piles 102 around the tank 100 are installed and the offload line 103, the inlet lines (at 122), and the remaining system components are connected to the tank 100.

Embodiments of a storage and offtake system may be used in conjunction with a sub-sea processing and/or gathering system as illustrated in FIGS. 8 and 9. For example, referring to FIG. 9, the sub-sea processing system may comprise a sub-sea oil and gas separator 136 for degassing liquid hydrocarbons produced from the sub-sea wells 132 (in FIG. 8). An example of a sub-sea processing system is described in U.S. Pat. No. 6,537,349, issued on Mar. 25, 2003, entitled “Passive Low Pressure Flash Gas Compression System,” and incorporated herein by reference. As shown in FIG. 9, when an embodiment of the invention is used with a sub-sea processing system, gas 134 separated from the liquid hydrocarbons may be routed to a gas handling system and the liquid hydrocarbons (oil) 121, exiting the separator 136 at a lower pressure can then be pumped via oil transfer pumps 135 into the inlet 122 of the tank 100.

A system for developing an offshore oil and gas field is shown in FIG. 10. A sub-sea separator 136 obtains hydrocarbons from one or more sub-sea wells 132. In accordance with one embodiment of the invention, the sub-sea separator 136 includes a two-phase separator (gas and liquid). In accordance with another embodiment of the invention, the sub-sea separator 136 includes a three-phase separator (gas, oil, and water). The sub-sea separator 136 de-gasifies the hydrocarbons, thus generating natural gas and oil. In accordance with one embodiment of the invention, the oil is partially stabilized. The oil is output to the storage tank 100 (in FIG. 4). Those having ordinary skill in the art will recognize that the description of a two or three phase separation is not intended to limit the scope of the present invention and that different types of phase separators may be used.

Sub-sea flow lines 180 convey the natural gas output from the sub-sea separator 136 to a vessel, such as a Floating Production Storage Shuttle Vessel (FPSSV) 182 using a natural gas conveyance system, which includes a riser 184, a hose 188, a hawser 190, a subsurface buoyant device 192, a flex joint 194, a swivel joint 196, and a sub-sea flow line-to-riser adapter 197. The riser 184, the offload line 186, the hose 188, the hawser 190, the subsurface buoyant device 192, the flex joint 194, and the swivel joint 196 function similarly, and have properties similar to, the riser 104, the hose 108, the hawser 110, the subsurface buoyant device 106, the flex joint 118, and the swivel joint 120 shown in FIGS. 3-4 and 7-10.

In accordance with one embodiment of the invention, the riser 184 is a top-tensioned riser used in conjunction with a flexible hose (i.e., a “hybrid riser”). In accordance with one embodiment of the invention, the riser 184 is a steel catenary riser. In accordance with one embodiment of the invention, the riser 184 is a flexible pipe. In accordance with another embodiment of the invention, natural gas conveyed to the FPSSV 182 is not compressed, i.e., is low-pressure gas.

A power and control buoy 198 provides electric power and control functions to the sub-sea separator 136 and sub-sea oil wells 132. Examples of the power and control buoy 198, in accordance with embodiments of the invention, may include the Sea Commander Buoy developed and marketed by Resource Technology Development Ltd. Functionality of the power and control buoy 198 may be similar to the buoy used in Western Australia for the East Spar Alliance, except with greater electrical capacity.

In accordance with one embodiment of the invention, the FPSSV 182 may provide electric power and control functions to the sub-sea separator 136 and sub-sea oil wells 132. Other types of buoy backup systems may be used to provide electric power and control functions to the sub-sea separator 136 and sub-sea oil wells 132, in accordance with embodiments of the invention.

Natural gas conveyed from the sub-sea separator 136 to the FPSSV 182 is liquefied aboard the FPSSV 182 to obtain Liquefied Natural Gas (LNG). An FPSSV LNG Production Facility 200 is used to liquefy the LNG. The FPSSV 182 transports the LNG to an onshore terminal 202. In accordance with one embodiment of the invention, the onshore terminal 202 may not necessarily be on dry land, but may be in close proximity to dry land, e.g., on a platform located in the proximity of shore. The use of more than one FPSSV 182 may be facilitated by use of a second riser 204, a second hose 208, a second hawser 210, a second subsurface buoyant device 212, a second flex joint 214, a second swivel joint 216, a second sub-sea flow line-to-riser adapter 218, and a surface buoy 219. The surface buoy 219 has functionality and properties similar to the surface buoy 112 in FIG. 4.

FIG. 11 shows the FPSSV LNG Production Facility 200, which is located aboard the FPSSV 182 (in FIG. 10). A natural gas liquefaction plant 222 takes a pre-treated natural gas input 224 from a natural gas pre-treating facility 226, which takes in natural gas 228 from the flexible hose 188 (in FIG. 10). The natural gas pre-treating facility 226 removes contaminants, such as water vapor, carbon dioxide, hydrogen sulfide, mercury, etc.

In accordance with one embodiment of the invention, the natural gas liquefaction plant 222 uses an open-cycle, open loop process, and takes Liquid Nitrogen (LIN) as an input from one or more FPSSV storage tanks 230 via one or more pumps 232. LIN vaporized during liquefaction is vented as nitrogen gas (N2) via a nitrogen vent 234. LNG created during the natural gas liquefaction process is stored in FPSSV storage tanks 230 aboard the FPSSV.

The LNG stored in the FPSSV storage tanks 230 is transported aboard the FPSSV to the onshore terminal. In accordance with one embodiment of the invention, the onshore terminal 202 (in FIG. 10) may not necessarily be located on dry land, but may be in close proximity to dry land, e.g., on a platform located in the proximity of shore. The LNG is transferred to the Onshore Terminal Storage tanks.

FIG. 12 shows an onshore LNG re-gasification and LIN production facility 260. LNG input 262 from the Onshore Terminal storage tanks 230 is input to a pump 264, which outputs High Pressure (HP) LNG 266. The HP LNG 266 is input to an LNG vaporizer 268. In accordance with one embodiment of the invention, the LNG vaporizer 268 may operate in a manner consistent with conventional LNG vaporizers, as known to those skilled in the art. The LNG vaporizer 268 outputs High Pressure (HP) natural gas 274. In a conventional operation, the LNG vaporizer 268 may take warm seawater from input 270 and discharge cold seawater output from 272. The LNG vaporizer 268 may also include a heat input 273. However, according to embodiments of the invention, the LNG vaporizer 268 is used in conjunction with an integrated LNG re-gasification air separation plant 276 so that the refrigeration from re-gasification of HP LNG 266 may be used to generate LIN.

In order to recover energy from re-gasification of the HP LNG 266, all or a portion of the HP LNG input 266 is input to the integrated LNG re-gasification air separation plant 276. The integrated LNG re-gasification air separation plant 276 takes as input air 278 compressed by a compressor 280. An output of the integrated LNG re-gasification air separation plant 276 is LIN 282, which is transferred to the FPPSV 182 (in FIG. 10), and stored in FPSSV storage tanks 230. In accordance with one embodiment of the invention, one FPSSV storage tank 230 of the FPSSV may be empty when the FPSSV transports the LIN 282 offshore, and additional FPSSV storage tanks 230 will become available when LIG is revaporized.

A flowchart for developing a sub-sea oil and gas field is shown in FIG. 13. A first operation of the flowchart is obtaining natural gas and partially stabilized oil by de-gasifying the hydrocarbons obtained from the sub-sea wells Step 300. Then, once natural gas has been obtained from the hydrocarbons, the natural gas is conveyed to a vessel, such as the FPSSV (Step 302), and the oil is stored in the storage tank (Step 304). The oil is partially stabilized after natural gas has been separated. The natural gas is conveyed to the FPSSV via the sub-sea flow lines and riser, as shown in FIG. 10.

Once the natural gas is aboard the FPSSV, the natural gas is liquefied using LIN stored aboard the FPSSV to obtain LNG (Step 306). The LNG is stored in the FPSSV storage tanks and transported to the onshore terminal (Step 308). At the onshore terminal, the LNG is re-gasified to obtain HP gas and recovered refrigeration, which is used to produce LIN (Step 310). The LIN is then loaded into the FPSSV storage tanks and transported to the offshore oil field (Step 312). In accordance with one embodiment of the invention, one of the FPSSV storage tanks is left empty, and the LIN is transported in the remaining FPSSV storage tanks. In accordance with one embodiment of the invention, some of the FPSSV storage tanks may hold LIN that is not produced using recovered energy, but has been obtained from another source other than the LNG re-gasification LIN production facility (shown as 260 in FIG. 12).

Once the FPSSV is at the location of the offshore oil field, more natural gas is conveyed aboard the FPSSV (Step 314), and the natural gas is liquefied aboard the FPSSV using the onboard LIN to obtain more LNG (Step 316). An initial quantity of LNG obtained using the LIN is stored in the empty FPSSV storage tank. Subsequent quantities of LNG obtained using the LIN are stored in the FPSSV storage tanks that are emptied as the LIN is used in the liquefaction process. Oil (e.g., partially stabilized oil) is offloaded from the oil tank on the seabed onto a tanker periodically (Step 318). Steps 308-316 are repeated to the gas/LNG while the sub-sea oil and gas field is in operation; as is step 318 for the oil.

Embodiments of the invention may also be used to eliminate the need for costly deepwater pipelines to shore, and in some cases may be used to avoid expensive pipeline tariffs. Embodiments of the invention may be operated independent of infrastructure, such as pipelines. Embodiments of the invention may also provide larger storage capacity for offshore production sites in deepwater that is less costly to operate and maintain than prior art storage systems primarily dependent upon shuttle tankers or submerged thick walled storage vessels. Embodiments of the invention may also be used to reduce the number of shuttle tankers required in a hydrocarbon transport fleet. Embodiments of the invention may also provide cost reductions for development of sub-sea oil and gas fields.

The above advantages are merely exemplary of advantages that may be associated with one or more embodiments of the invention. Those skilled in the art will appreciate other advantages. Further, while the invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed. Accordingly, the scope of the invention should be limited only by the attached claims.