Patent Publication Number: US-2006000615-A1

Title: Infrastructure-independent deepwater oil field development concept

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  100   a , a bottom  100   b , and one or more side walls  100   c . 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  124   a  positioned inside of the tank  100  proximal the bottom  100   b  of the tank  100  and a second end  124   b  in fluid communication with the environment  125  outside of the tank  100 . In one or more embodiments, the second end  124   b  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  100   a  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  100   a , 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  100   a  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  100   b  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  124   b  of the fluid channel  127 , away from the seabed (at  114  in  FIGS. 4 and 5 ). Locating the external end  124   b  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.