WO2010144187A1

WO2010144187A1 - Subsea hydrocarbon recovery systems and methods

Info

Publication number: WO2010144187A1
Application number: PCT/US2010/033406
Authority: WO
Inventors: Chad A. Broussard; George F. Davenport; Tracy A. Fowler; Ann T. Leger; Stanley O. Uptigrove; Steven Wheeler; Mark Danaczko; Nolan A. O'neal
Original assignee: Exxonmobil Upstream Research Company
Priority date: 2009-06-11
Filing date: 2010-05-03
Publication date: 2010-12-16

Abstract

The present invention discloses systems, apparatuses, and associated methods for producing, separating, storing, and offloading hydrocarbons from a hydrocarbon producing well in a subsea environment, which may be a remote, arctic subsea environment. In particular, the systems include a large gravity-separation tank or tanks constructed at least partially from structural concrete to separate oil, water, gas, and/or particulates. The gravity- separation tank or tanks may be connected to one or more buoyancy cells in a large gravity- based structure (GBS), which may be built in a graving dock, towed to a remote location (e.g. arctic), ballasted to the seafloor and integrated into a subsea hydrocarbon production system. The system may further include an offloading system and a local power supply.

Description

SUBSEA HYDROCARBON RECOVERY SYSTEMS AND METHODS CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U. S. Provisional Application No.

61/186,285 filed June 11, 2009, which is incorporated herein in its entirety.

FIELD OF THE INVENTION

[0002] This invention relates generally to methods and systems for operating a subsea hydrocarbon recovery operation. More particularly, this invention relates to systems, apparatuses, and associated methods of producing, separating, storing, and offloading hydrocarbons from a hydrocarbon producing well in a subsea environment, which may be a remote, arctic subsea environment.

BACKGROUND

[0003] This section is intended to introduce various aspects of the art, which may be associated with the presently disclosed technology. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the disclosed technology. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0004] The geographic portion of the world known as the "high arctic" may contain substantial hydrocarbon resources. However, developing these hydrocarbon resources in the offshore arctic will require a substantial and long term commitment of planning, engineering, and technology development. In addition, the logistical and safety complexities of a permanent manned production facility in the high-arctic ice will be exceedingly difficult. As such, production and development of potentially huge hydrocarbon resources in the arctic is one of the world's toughest energy challenges.

[0005] Some proposals for offshore arctic development of hydrocarbon resources include the use of bottom- founded structures (e.g. ice-resistant jack-up type systems) having separation, storage, other production equipment and personnel on the surface. It is not clear that such structures can resist the overturning moments of ice loads caused by pack-ice and icebergs found in the high arctic. As such, floating production systems would be required, which would result in significant down time, even after the expensive and difficult arctic installation.

[0006] Another approach includes utilizing on-shore facilities and connecting to a subsea production system via tie-backs. However, due to issues such as flow assurance and installation, the challenges are extreme for subsea oil tiebacks (flow lines) and power supply greater than about 100 km. Significant downtime would be required to manage deposition of wax, hydrates, and other plugging materials in addition to conducting other maintenance activities.

[0007] Subsea production and processing systems have been proposed for deepwater and other environments. One example of such a system is disclosed in U.S. Pat. No. 6,197,095 (the '095 reference). The '095 reference discloses a subsea fluid separation system and methods and utilizes mechanical (e.g. cyclonic) separation machinery and a gravity- separation tank in combination. In particular, the system is specifically designed to be more compact in size than surface operating systems, which, according to the '095 reference, is "desirable for subsea operation." Like most previously disclosed subsea separation systems, the '095 reference discloses a scheme to utilize significant mechanical separation to avoid using a large steel gravity separation tank subsea, which may buckle at significant depths and require significant amounts of steel and reinforcement members.

[0008] Rather than adapting deep water and other offshore hydrocarbon production platforms to arctic environments, what is needed is an entirely different operational approach to arctic hydrocarbon resource development which mitigates the challenges of long distance flow lines, power lines, and manned surface production facilities in the arctic.

SUMMARY

[0009] One embodiment of the present invention discloses a fluid separation system.

The fluid separation system includes a first gravity-separation tank at least partially constructed from structural concrete and configured to operate in a subsea environment. In some embodiments, the first gravity-separation tank may be configured to separate at least oil, water, and gas; separate the at least two fluids at a pressure of less than about 200 pounds per square inch (psi); separate the at least two fluids over a retention time from about twelve (12) hours to about 36 hours at full production rates; have a total processing throughput from about 100,000 barrels per day (bblpd) to about 500,000 bblpd; and configured to produce oil having less than about one volume percent water.

[0010] More particular embodiments of the fluid separation system may further include at least one additional gravity-separation tank configured to operate in a subsea environment, wherein the at least one additional gravity-separation tank is operably connected to the first gravity-separation tank; and at least one buoyancy cell operatively connected to a tank selected from the group consisting of the first gravity-separation tank; the at least one additional gravity-separation tank; and any combination thereof, wherein the first gravity-separation tank, the at least one additional gravity-separation tank and the at least one buoyancy cell are operably connected and configured to operate as a self-floating, gravity based structure (GBS), and configured to resist hydrostatic pressure forces in the subsea environment at depths of over at least about 200 feet and prevent hydrocarbon fluid exchange with the subsea environment. Additionally, the fluid separation system may include at least one gas-handling compressor operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity- separation tank; at least one oil-handling pump operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity- separation tank; at least one sand slurry handling pump operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity-separation tank; and any combination thereof.

[0011] Another embodiment of the present invention discloses a method of constructing and installing a fluid separation system. The method includes attaching at least one buoyancy cell to at least one gravity-separation tank to form the fluid separation system, wherein the at least one buoyancy cell and the at least one gravity-separation tank are at least partially constructed from structural concrete and configured to operate in a subsea environment. The method may also include connecting at least one gas-handling compressor to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank; connecting at least one oil-handling pump to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank; and connecting at least one solids-capable water-handling pump to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank. In additional particular embodiments, the method may include floating the fluid separation system out of a graving dock; releasing an air cushion from beneath the fluid separation system; connecting the fluid separation system to at least one marine vessel; towing the fluid separation system to a remote location with the at least one marine vessel; ballasting the fluid separation system to the seafloor at the remote location; and optionally managing ice with at least one ice-breaking vessel.

[0012] A third embodiment of the present invention discloses a subsea production system. The system includes at least one hydrocarbon production well configured to produce a production fluid; and at least one gravity-separation tank at least partially constructed from structural concrete and configured to separate at least two fluids over a retention time of at least one hour and operate in a subsea environment, receive the production fluid, and separate the production fluid into at least a volume of oil, a volume of water, and a volume of gas. In some embodiments, the system includes at least one subsea oil storage tank at least partially constructed from structural concrete and configured to receive and store at least a portion of the volume of oil from the at least one gravity-separation tank; an offloading system configured to offload at least a portion of the volume of oil from the subsea oil storage tank; at least one subsea water re -injection system configured to pump and re-inject at least a portion of the volume of water into a location selected from the group consisting of: a production reservoir, a storage reservoir, a subsea storage tank, and any combination thereof; and at least one subsea compression system configured to compress and re-inject the volume of gas into a location selected from the group consisting of: the production reservoir, the storage reservoir, and any combination thereof.

[0013] In additional particular embodiments, the subsea production system may include a power plant configured to provide power to the subsea production system, wherein the power plant is at a location selected from the group consisting of: a locally docked submarine, a locally stationed floating vessel, a locally installed power system structure on the seabed, and any combination thereof; and wherein the power is generated from an energy production process selected from the group consisting of: nuclear, combustion, fuel cell, battery, geothermal, wave energy, current energy, produced fluid energy from reservoirs in the earth, solar, wind, and any combination thereof; and a monitor and control system operably connected to the subsea production system, comprising: at least one pressure sensor operatively connected to the at least one gravity separation tank; and at least one flow controller operatively connected to the at least one well head water re-injection system to control the flow rate of the water re-injection system.

[0014] In one particular alternative embodiment of the subsea separation system, there may be included a primary separation unit configured to receive the production fluid from the subsea well system and remove at least some produced water and at least some produced gas from the production fluid before the production fluid is sent to the at least one gravity-separation tank; a first expander configured to receive the production fluid at a first pressure and capture energy by reducing the pressure of the production fluid from the first pressure to a second pressure; a second expander configured to receive the production fluid from the primary separation unit at a first separated pressure and capture energy by reducing the pressure of the production fluid from the first separated pressure to a second separated pressure and provide the production fluid at the second separated pressure to the at least one gravity-separation tank; at least one subsea water re-injection system configured to pump and re-inject at least a portion of the at least some produced water into a location selected from the group consisting of: a production reservoir, a storage reservoir, a subsea storage tank, and any combination thereof; at least one subsea compression system configured to compress and re-inject the at least some produced gas into a location selected from the group consisting of: the production reservoir, the storage reservoir, and any combination thereof; and a local power supply configured to provide power to at least the primary separation unit. [0015] A fourth embodiment of the present invention discloses a method of producing hydrocarbons. The method includes producing a production fluid from at least one subsea hydrocarbon well; separating the production fluid in at least one gravity-separation tank configured to operate in a subsea environment into at least a volume of oil, a volume of water, and a volume of gas; storing at least a portion of the volume of oil from the at least one gravity-separation tank in at least one subsea oil storage tank; and offloading at least a portion of the volume of oil from the at least one subsea oil storage tank to an oil-transport vessel via an offloading system.

[0016] Some embodiments of the method may further include monitoring and controlling the operation of the at least one subsea hydrocarbon well, the at least one gravity- separation tank, the at least one subsea oil storage tank, and the offloading system from a location selected from the group consisting of: the oil-transport vessel, another locally stationed surface vessel, a locally docked submarine, a remote location via satellite, cable, or wireless connection through air, water, ice, earth, and any combination thereof, and any combination thereof; and providing power to the at least one gravity-separation tank, the at least one subsea hydrocarbon well, the at least one subsea oil storage tank, and the offloading system from a local power supply, wherein the at least one subsea hydrocarbon well is located in an arctic environment; and the oil-transport vessel is an ice-capable oil shuttle tanker.

[0017] Beneficially, the presently disclosed methods and systems solve many of the problems associated with offshore arctic hydrocarbon development, including eliminating or significantly reducing the need for long distance flow lines and power lines, and eliminating or significantly reducing the need for manned surface production facilities in remote areas. Other benefits include the ability to perform significant construction operations at well- established facilities as opposed to constructing a production system or platform at a remote location.

[0018] In certain embodiments, the disclosed technology is expected to allow extremely remote production of oil fields in the high arctic by combining subsea processing technology, large scale long residence-time gravity based separation, submerged concrete oil storage tanks, and a locally generated power supply. Additionally, some embodiments may utilize ice capable crude carriers to enable oil transportation in large quantities out of the high arctic. The disclosed technology is expected to reduced project risk and cost through simplified construction logistics and an economic solution for resource development in the high arctic deepwater where no other known concepts are technically or commercially viable.

BRIEF DESCRIPTION OF THE DRAWINGS

[0019] The foregoing and other advantages of the present techniques may become apparent upon reviewing the following detailed description and drawings in which: [0020] FIG. 1 is an exemplary illustration of a gravity-separation tank in accordance with certain elements of the disclosed technology;

[0021] FIGs. 2A-2F are exemplary illustrations of a fluid separation system incorporating certain aspects of FIG. 1;

[0022] FIGs. 3A-3B show an example of the separation system of FIGs. 2A-2B operably connected to a storage system as contemplated in certain embodiments of the presently disclosed technology;

[0023] FIG. 4 is an illustrative flow chart of an exemplary method of constructing and installing a fluid separation system like the one disclosed in connection with FIGs. 2A-2B; [0024] FIGs. 5A-5B illustrate an exemplary approach to installing the system of

FIGs. 1 and 2A-2B on a seafloor;

[0025] FIGs. 6A-6B are exemplary schematics of various embodiments of a subsea field development incorporating the systems of FIGs. 1, 2A-2B, and 3A-3B; [0026] FIG. 7 is a flowchart of a method of producing hydrocarbons from a subsea development;

[0027] FIGs. 8A-8B illustrate two exemplary power supply arrangements that may be incorporated into the developments of FIGs. 6A-6B and methods of FIG. 7.

DETAILED DESCRIPTION

[0028] In the following detailed description section, the specific embodiments of the present inventions are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present inventions, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the inventions are not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. DEFINITIONS

[0029] The terms "a" and "an," as used herein, mean one or more when applied to any feature in embodiments of the present inventions described in the specification and claims.

The use of "a" and "an" does not limit the meaning to a single feature unless such a limit is specifically stated.

[0030] The term "about" is intended to allow some leeway in mathematical exactness to account for tolerances that are acceptable in the trade. Accordingly, any deviations upward or downward from the value modified by the term "about" in the range of 1% to 10% or less should be considered to be explicitly within the scope of the stated value.

[0031] The term "arctic," as used herein, means any offshore environment wherein the surface of the water is at least partially covered in ice or includes ice bergs for at least a portion of the year.

[0032] The term "buoyancy cell," as used herein, means any container configured to contain a liquid capable of providing positive, neutral, or negative buoyancy, depending on a liquid fill level in the container.

[0033] In the claims, as well as in the specification above, all transitional phrases such as "comprising," "including," "carrying," "having," "containing," "involving," "holding,"

"composed of," and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases "consisting of and "consisting essentially of shall be closed or semi-closed transitional phrases, respectively, as set forth in the United

States Patent Office Manual of Patent Examining Procedures, Section 2111.03.

[0034] The term "exemplary" is used exclusively herein to mean "serving as an example, instance, or illustration." Any embodiment described herein as "exemplary" is not necessarily to be construed as preferred or advantageous over other embodiments.

[0035] The term "gravity-based structure (GBS)," as used herein, means a structure designed to remain on location primarily or only because the weight of the structure imposes sufficient loading on the seabed to render the structure safe from sliding or overturning. In some embodiments, the GBS may include caissons or other additional devices configured to provide additional means of securing the GBS to the seabed, but will generally exclude the use of piles.

[0036] The term "gravity-separation tank," as used herein, means a vessel wherein a multi-component fluid (e.g. a production fluid) undergoes a separation of the components by a substantially gravity-based process rather than a machine-based process (e.g. a cyclone or auger type separator). Gravity-based separation may also be referred to herein and in other materials as "aging." Gravity-based separation may be measured by "residence time," which is the amount of time a fluid remains in a substantially quiescent or still state (as opposed to an agitative or mixed state).

[0037] The term "oil storage tank," as used herein, means a vessel configured to store or hold the remaining liquid portion of a production fluid after at least one separation process has been applied to the fluid.

[0038] The terms "preferred" and "preferably" refer to embodiments of the inventions that afford certain benefits under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the inventions. [0039] The term "production fluid," as used herein, means any hydrocarbon containing fluid produced from a subterranean reservoir. In particular, the production fluid may include a liquid, a gas, particulates, or any combination of these. For example, the fluid may include crude oil, water (e.g. brine), natural gas (including, for example, CO₂, H₂S, N₂, higher hydrocarbons, etc.), condensates, solid particulates (e.g. sand, salt, etc.), and any combination of these.

[0040] The term "structural concrete," as used herein, means a composite material comprising at least a first material comprising concrete having a high compressive capacity and a second material having a high tensile capacity (e.g. reinforcing steel bars, glass cables, carbon fiber cables, or post-tensioning steel cables), wherein the first and second materials behave in a composite manner.

[0041] The terms "substantial" or "substantially," as used herein, mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable may in some cases depend on the specific context. [0042] The definite article "the" preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used.

EMBODIMENTS

[0043] One embodiment of the disclosed invention includes a gravity-separation tank at least partially constructed from structural concrete and configured to operate in a subsea environment. In some exemplary embodiments, the gravity-separation tank is a large tank capable of separating oil, gas, and aqueous fluids as well as sand and other particulate matter. It is preferably capable of high throughput for large fields, have a high retention time, and operate at low pressures to produce "tanker quality" crude (e.g. crude oil having a low enough content of gas, water, and particulates to safely and economically transport the crude to market). Although in some cases a heating or surface flashing process may be utilized. [0044] In some embodiments, the system includes several gravity-separation tanks connected to buoyancy cells in a gravity-based structure (GBS), which may be constructed in a graving dock, floated, and towed out to a remote location for installation by a controlled ballast to the seabed. Pumps and compressors may be mounted on and connected to the buoyancy cells and/or the gravity-separation tanks and connected to inlets and/or outlets of the tanks and cells.

[0045] After installation on the seabed in a subsea hydrocarbon production and processing system, the separation system (e.g. the GBS having gravity-separation tanks and buoyancy cells) may be connected via flow lines and power lines to hydrocarbon production wells, injection wells, large submerged oil storage tanks, and an offloading system to an oil- transport vessel. Some exemplary systems and methods may further include equipment and methods to provide power to the subsea system and control production operations and power supply thereto. One optional exemplary embodiment may include some preliminary energy capture and separation equipment.

[0046] Beneficially, the described field development technology, which may be referred to as a Submerged Production Storage and Offloading System (SPSO) is believed to enable a technically viable solution for subsea oil production in arctic waters, particularly in deeper waters (e.g. greater than about 200 feet) of the high arctic, which feature sea ice, pack ice, ice bergs, and other hazards to surface-based operations that are also too remote to be served by subsea tie-backs (flow lines) to on-shore facilities.

[0047] Referring now to the figures, FIG. 1 is an exemplary illustration of a gravity- separation tank in accordance with certain elements of the disclosed technology. The gravity- separation tank 100 is a vessel 102 having a fluid inlet line 104 with fluid flow controlled by a valve 106, an oil pump 108 to pump oil through oil flow line 110, a water pump 111 to pump water through water flow line 112, which may be at least partially recycled through recycle line 114, a gas compressor 116 to compress gas to flow through gas line 118. In particular, the vessel 102 may have multiple internal sections, including an upper section 120 for separating gas, a lower section 122 to contain and separate oil, a remaining water portion 124, and a lower solids separation portion 126.

[0048] In one embodiment, the vessel 102 is at least partially constructed from structural concrete and configured to operate in a subsea environment. As such, the vessel 102 should be configured to withstand hydrostatic forces at depths of at least about 100 meters (m) to about 1,000 m or more, depending on the depth of the subsea operation. The vessel 102 is preferably a gravity-separation tank configured to separate a fluid comprising oil, gas, and water, but optionally also separate particulates with a sand trap or other separation device configured to handle particulate solids. The vessel 102 is also preferably large enough to separate the fluid for about a 12 to about a 36 hour retention time at a rate of about 100,000 barrels of oil per day (100 kbopd) to about 500 kbopd. Note that for lower production rates, the retention time could be significantly longer than 36 hours. [0049] The vessel 102 may also include multiple sections with an internal corrosion- resistant material (e.g. steel or certain polymers) lining an upper gas section 120 configured to operate at low to intermediate pressures of about 50 pounds per square inch absolute (psia) to about 200 psia. Gas that separates or evolves in section 120 can be compressed in a liquids-tolerant compressor 116 up to a first stage suction pressure for eventual subterranean injection via gas line 118. Another section located below the upper gas section 120 may operate at a slightly higher pressure and be configured to separate oil 122 from water 124 utilizing primarily gravity-separation over a long retention time (e.g. about 12-36 hours). The long retention time along with optional emulsion breaking enhancers such as electrostatic devices, chemicals, etc. (as required) should enable high quality oil/water separation. Such additional separation or emulsion breaking enhancers are generally known and a person of ordinary skill in the art would understand how to incorporate such additional optional technologies to the disclosed vessel 102.

[0050] In one exemplary embodiment, the separation in the vessel 102 is sufficient to produce a "tanker quality" crude that requires little or no further processing before loading onto an oil-transport vessel for delivery to an import terminal or storage location. The oil 122 may be pumped up to the suction pressure of the upper gas section 120 by an oil pump 108 for delivery to another separation device, a storage location, or an offloading location via oil flow line 110. The water 124 may then be pumped up to the suction pressure of the upper gas section 120 by a water pump 111 for eventual subterranean injection via water line 112. Alternatively, there may also be particulates pumped through water line 112, which may then require a recycle line 114 to facilitate the further separation of particulates out of the water line 112 prior to injection.

[0051] FIGs. 2A-2F are exemplary illustrations of a fluid separation system incorporating certain aspects of FIG. 1. As such, FIGs. 2A-2F may be best understood with reference to FIG. 1. FIG. 2A shows an exemplary illustration 200 of a fluid separation system 202 incorporating multiple gravity-separation tanks 100 including multiple vessels 102a-102d and multiple buoyancy cells 204a-204c attached or connected to the vessels 102a- 102d. In this exemplary embodiment, four vessels 102a-102d and three buoyancy cells 204a-204c are shown, but it should be noted that the system 202 may incorporate any practical number of vessels 102 and cells 204, depending on the volumes desired, construction cost and capacity, pump and compressor configurations, and other factors. For similar reasons, a person of ordinary skill in the art may desire to construct the vessels 102 and cells 204 having a hexagonal, octagonal, or other angular cross-section rather than a circular cross-section, although a circular cross-section may provide better resistance to hydrostatic forces than other cross-sectional shapes. It should also be noted that the vessels 102a-102d may be operated in parallel or series with each other, although this will be highly dependent on the compositions and pressure of the produced fluids being separated. [0052] In some exemplary embodiments, the system 202 may involve a self-floating, concrete, gravity-based structure (GBS) having a large platform base (e.g. from about 2000 m² to about 5000 m², or about 3700 m²) that rests directly on the seafloor. The exemplary system 202 has four dedicated separation cells (vessels) 102a-102d and three buoyancy cells 204a-204c, the latter of which facilitate construction, tow, and installation, and provide real estate for mounting all subsea processing equipment and temporary mechanical systems required for construction and installation. The subsea separation tank can be used with pipeline export to a host facility or market, or with a subsea storage tank and export shuttle tankers. For example, the system 202 may support a fluid inlet line 104, an oil pump 108 to pump oil through oil flow line 110, a water pump 111 to pump water through water flow line 112, a gas compressor 116 to compress gas to flow through gas line 118. Additional pumps and flow lines (not shown) between the vessels 102a-102d may be contemplated depending on the particular configuration selected.

[0053] In certain embodiments of the system 202, the pumps 111 and 108 may include multiple pumps configured in parallel or in series, multistage pumps, centrifugal pumps, displacement pumps, sleeve bearing pumps, or other types of pumps configured to pump a liquid from a relatively low pressure to a relatively high pressure. Additionally, the pumps 111 and 108 should be configured to operate in a subsea environment (e.g. hydrostatic pressures up to about 1,300 psi or greater), which may require a leak-proof seal, for long periods of continuous operation (e.g. up to about 5 years) with high reliability. The pumps 111 and 108 should benefit from pumping a substantially single-phase liquid (oil or water, respectively), rather than requiring multiphase operation. This will depend, to some degree, on the quality of the liquid separation in the vessels 102a-102d.

[0054] The water pump(s) 111 may be configured to operate to increase the fluid pressure from about 50-200 psi to about 800-1,000 psi, depending on the pressure in the vessel 102a-102d and the injection pressure desired. However, the oil pump(s) 108 may be configured to operate in a much smaller range as they simply need to move fluid from the vessels 102a-102d to a storage location (not shown), although there may be some desire to change the pressure of the oil.

[0055] Similarly, the compressors 116 may be multiple compressors configured in parallel or series and may be liquids tolerant and robust such as an axial compressor, a centrifugal compressor, or a "multi-phase" compressor which can boost both liquids and gas, or another similar type of compressor. Like the pumps 111, the compressors 116 may operate in a subsea environment for long periods of continuous operation. The compressors 116 may operate to increase the fluid pressure from about 50-200 psi to up to 3,000 - 5,000 psi depending on the pressure in the vessel 102a-102d and the injection pressure desired. [0056] In one alternative, exemplary embodiment, the system 202 may include an over-pressure protection system with high integrity to protect the subsea processing (e.g. pumps 108 and 111, compressors 116) and storage equipment (not shown). One configuration may include redundant shutdown instrumentation with emergency pressure relief to the ballast separation tanks (e.g. buoyancy cells 204a-204c). A full High Integrity Pressure Protection System (HIPPS) is another option to be considered during design of the processing system.

[0057] FIG. 2B illustrates an elevation view of the system 202. All like components are labeled with the same reference numbers as in FIG. 2A. FIG. 2B shows an exemplary configuration where vessel 102d is taller than the other vessels 102a-102c. This is to beneficially allow a single gathering point for the gas outlet at the highest elevation. However, the system 202 may have many other configurations. Also shown in this exemplary embodiment is the curved top on the vessels 102a-102d, which may be preferred to resist hydrostatic forces, while the top of the buoyancy cells 204a-204c may be flat to more easily accommodate the mounting of pumps 108 and 111, compressors 116, and other equipment.

[0058] FIGs. 2C-2F illustrate exemplary alternative configurations of the fluid separation system 202. FIGs. 2C and 2E show a smaller system 202' with different sizes for the vessels 102a- 102b and the buoyancy cells 204a-204b. Such a configuration may be incorporated as an additional fluid separation system 202' in a field or production operation that already includes another separation system 202 or it may be found to have some advantages over the fluid separation system 202. As shown in FIG. 2E, the vessels 102a and 102b are of the same height. FIGs. 2D and 2F show a system 202" having a different cross- sectional shape than the system 202. In most cases, the circular cross-sectional shape will be preferred, but other shapes are possible and well within the scope of the disclosure. These alternative configurations are just a few examples of the numerous sizes, shapes, and configurations that may be employed in the fluid separation system 202. The disclosure is not limited by the particular sizes, shapes, and configurations disclosed herein, but includes all sizes, shapes, and configurations falling within the spirit and scope of the appended claims.

[0059] Note that the fluid separation system 202 may be configured to have the following notional dimensions, based on conventional design practice, for a separator configured to handle from about 100,000 bopd to about 300,000 bopd + with at least a 24- hour retention time. In this example, the total processing volume is from about 50,000 m³ (about 400,000 bbl) to about 70,000 m³. Total concrete volume for such a capacity is from about 15,000 m³ to about 25,000 m³.

[0060] FIGs. 3A-3B show an example of the separation system of FIGs. 2A-2B operably connected to a storage system as contemplated in certain embodiments of the presently disclosed technology. The system 300 includes a vessel 102 and a storage tank 302 connected via oil flow line 110 and gas flow line 308. The system 300 may further include an oil pump 304 connected to an offloading line 306 going to an offloading location 324. The storage tank 302 may include an upper gas separation section 320 and a lower oil storage section 322. The system 300 may also include a pump 310 for pumping gas through line 308, a valve 312 to control flow of the oil through line 110 and an optional alternate flow line 314, which may include valve 316. FIG. 3B shows an exemplary elevation view of the storage tanks 342a-342g.

[0061] The storage tank 302 may be maintained at a very absolute low pressure, from about 1 psia to about 10 psia in the upper gas separation section 320 and have a slightly higher pressure of about 20 psia to about 100 psia in the lower oil storage section 322, at least partially due to the weight of the oil therein. This low pressure storage system may be utilized with the separation vessel 102 as an accumulation tank of sorts, or may hold and store oil for periods of time of several days to several weeks, depending on the rate of fluids production and the ability to offload the oil to an offloading location 324, which may be an oil-transport vessel. In one embodiment, the storage tank 302 may be a group of multiple tanks 342a-342g, for example, three tanks, five tanks, seven tanks, or nine tanks or more configured to store oil. In one exemplary embodiment, the storage tanks 302 may be constructed in a manner similar to the separation vessels 102 using structural concrete and having a corrosion-resistant liner in the upper gas separation section 320. [0062] In one exemplary embodiment of the storage tank 302, the oil may then be pumped through infield piping 110 to the storage containment system 302 consisting of very large concrete tanks. The tanks 342a-342g should be large enough to accommodate from about 5 to about 18 days of oil production at peak rate, which could be about 2 million barrels (MMbbls) for a 250 kbopd field. The tanks 302 can be configured to operate at ambient seafloor pressure, similar to other gravity based structure (GBS) tanks, with a system to equalize with the seawater as tank levels rise and fall, as known by persons of ordinary skill in the art. Specific tank dimensions will depend on processed and stored volume, water depth, structural strength, construction, tow, and installation requirements. However, in one specific exemplary embodiment, an assembly of seven storage tanks 342a-342g could be expected to measure up to about 80 m tall and up to about 80 m in diameter (for 2 MMbbl capacity). Any gas flashed from the storage tanks 302 would be pumped (multiphase pump 308 with recycled liquid stream 314) or compressed back into the separator vessel 102. The water depth is expected to be several hundred meters, depending on the required storage volume.

[0063] FIG. 4 is an illustrative flow chart of an exemplary method of constructing and installing a fluid separation system like the one disclosed in connection with FIGs. 2A-2B. As such, FIG. 4 may be best understood with reference to FIGs. 2A-2B. The method 400 includes an initial step of attaching 402 at least one buoyancy cell 204 to at least one gravity- separation tank 102 to form the fluid separation system 204, wherein the at least one buoyancy cell 204 and the at least one gravity-separation tank 102 are at least partially constructed from structural concrete and configured to operate in a subsea environment. Next, the method may include any one or all of the steps of connecting 404a at least one gas- handling compressor 116, connecting 404b at least one oil-handling pump 108, and connecting 404c at least one sand and water handling pump 111 to a buoyancy cell 204a- 204c or a gravity-separation tank 102a-102d.

[0064] The method 400 may then include floating 406 the fluid separation system 202 out of a graving dock; releasing 408 an air cushion from beneath the fluid separation system 202; connecting 410 the fluid separation system 202 to at least one marine vessel; towing 412 the fluid separation system 202 to a remote location with the at least one marine vessel; and ballasting 414 the fluid separation system 202 to the seafloor at the remote location. Note that steps 404a-404c may be accomplished in any order or all at once and may even be performed after the system 202 is floated out of the graving dock, but is preferably connected prior to floating the system 202.

[0065] It should also be noted that a modified version of the method 400 may be substantially applied to the storage tanks 302. In one embodiment, the storage tanks 302 will only have two pumps or sets of pumps to handle the offloading of oil from the bottom portion of the tank 322 and rejection of gas from the top portion of the tank 320. However, the storage tanks 302 may be built in a graving dock, floated, towed, and ballasted to the seafloor, much like the separation tanks. One notable difference may be that the storage tanks 342a-342g may be used as buoyancy cells rather than having purpose-built cells separate from the tanks.

[0066] Although the systems 202 and 340 are large, they should be able to be constructed by the method 400 using existing construction facilities (e.g. graving docks, cranes, etc.), construction techniques (e.g. welding, assembling, etc.), and existing construction materials (e.g. structural concrete, corrosion-resistant linings, pumps, compressors, etc.). In fact, one of the benefits of the presently disclosed methods 400 is that well-established graving docks may be used to build the disclosed systems 202 and 340 rather than attempting significant construction work in the open sea or at a remote location. It is also within the scope of the presently disclosed methods and systems to make modifications and advancements to existing construction facilities, methods, and materials to provide more efficient and effective implementation of the presently disclosed technologies. [0067] FIGs. 5A-5B illustrate an exemplary approach to installing the system of

FIGs. 1 and 2A-2B on a seafloor. As such, FIGs. 5A-5B may be best understood with reference to FIGs. 1 and 2A-2B. FIG. 5A shows the subsea separation system 202 marine tow 500 and installation spreads 520. The marine tow 500, includes the subsea separation system 202, multiple seagoing vessels 504a-504c with tow cables 502a-502c connected to and towing the system 202, and another vessel 508 towing a buoyancy tether 506. The installation spreads 520, includes seagoing vessels 504a-504d with cables 502a-502d connected to the system 202 in a spread formation, and the vessel 508 connected to the system 202 via an umbilical 510 and the buoyancy tether 506 connected to the system 202. [0068] FIG. 5B shows the subsea separation system 202 installation sequence using a buoyancy tether 506. The installation starts with 540 where the tow lines 502a-502c begin to slack. The installation continues with 560 where the vessels 504a-504d move to a spread formation and continue to let up on the tow lines 502a-502d while the umbilical 510a controls the levels in the buoyancy cells 204a-204c to lower the system 202. The installation finishes as the system 202 is slowly lowered to the seafloor 582 with the buoyancy tether 506, which may also be controlled by an umbilical 510b.

[0069] FIGs. 6A-6B are exemplary schematics of various embodiments of a subsea field development incorporating the systems of FIGs. 1, 2A-2B, and 3A-3B. As such, FIG. 6 may be best understood with reference to FIGs. 1, 2A-2B, and 3A-3B. The development 600 includes a subsea production well 602 connected to a local power supply 604 and producing a production fluid through line 110 to subsea separation system 202, which produces a gaseous stream 606 that is compressed in compressor 608 to an injection pressure for injection in reservoir 610. Subsea separation system 202 also produces a substantially water stream 612, which is pumped to injection pressure by pump 614 and injected into well 616 or alternatively to a submerged holding tank or series of tanks for injection water. A substantially oil stream 110 is produced and sent to subsea storage tank 340, then offloaded to an oil transport vessel 324 via an offloading system having oil pump 304 and offload line 306.

[0070] The development 600 may be referred to as a Submerged Production Storage and Offloading System (SPSO). In one embodiment of the disclosed development 600, the subsea production well 602 is configured to produce full wellstream fluids using conventional subsea wellheads, trees, jumpers, and manifold hardware, as are known to persons of ordinary skill in the art. The oil, gas, and water will then be gathered with interconnected flowlines and routed to the subsea separation system 202 (or alternatively, to a pre-processing stage as disclosed below). The anticipated wellcount for anticipated arctic fields ranges from about 15 to about 40 or more, including producers and water/gas injectors. Standard control umbilicals may be used to route communications and chemicals to their destination, as in a typical subsea field, although an underwater chemical storage and pumping system may also be utilized to avoid the need for such equipment on the surface, which may include treacherous conditions. All-electric subsea trees and valves may be utilized to avoid the need for hydraulic supply. In some embodiments, the control system includes a link (possibly wireless) to a manned control station, which may include a local or remote located surface vessel, a locally located submarine, a remotely located onshore facility, an airborne location, or some combination of these. [0071] FIG. 6B illustrates an exemplary alternative embodiment of the development

600. The alternative development 650 may include an optional first expander 618 for power capture, a pre-separation unit 620, which produces a water stream 622 to be combined with stream 612 and pumped to pressure in pump 623 for injection in well 616 or alternatively into a holding tank or series of tanks, a gas stream 630 to be combined with stream 606 and compressed to pressure in compressor 632 for injection in well 610, and a pre-separated oil stream 624, which may be produced through an optional expander 626 for power capture to form stream 628, which is introduced to the subsea separation system 202. The alternative development 650 may also include a recycle gas loop 634 from the subsea storage tanks 340 to a multiphase pump 636 (joined with a recycled liquid stream from stream 110) for combination with the gas stream 606. and may also include support vessels 638, which may be ice-breaker vessels in the case where the oil-transport vessel 324 is a surface vessel. [0072] In one exemplary embodiment, the alternative development 650 is configured to include multiple stages of separation and re-injection on the seabed to eliminate the need to store large volumes of produced gas and water. The pre-separation unit 620 is likely to be at high pressure (about 1,000 psi) to minimize the differential pressure required by the re- injection pumps 623 and compressors 632. A conventional gravity based separator or compact mechanical separator (e.g. cyclonic, auger type) could be used as the pre-separation unit 620. It is anticipated that the majority of the water and gas will be removed at this stage. Following pre-separation, the gas 630 is compressed using a liquids tolerant and robust gas compressor 632. If required, scrubbed liquids can be routed back into the process, however scrubbers will be eliminated if possible to simplify the process. The water 622 should be cleaned to sufficient quality and injected into a reservoir 616. The expanders 618 and 626 are optional, but may provide some additional power to decrease the load on the power supply 604 or directly provide power to all the pumps and compressors throughout the development 600.

[0073] FIG. 7 is a flow chart of a method of producing hydrocarbons from a subsea development. The method 700 includes producing a production fluid 702 from at least one subsea hydrocarbon well; separating the production fluid 704 in at least one gravity- separation tank configured to operate in a subsea environment into at least a volume of oil, a volume of water, and a volume of gas; storing at least a portion of the volume of oil from the at least one gravity-separation tank 706 in at least one subsea oil storage tank; and offloading at least a portion of the volume of oil 708 from the at least one subsea oil storage tank to an oil-transport vessel via an offloading system. The method 700 may further include providing power 710 to machinery (e.g. pumps and compressors) associated with the at least one gravity-separation tank, the at least one subsea hydrocarbon well, the at least one subsea oil storage tank, and the offloading system via a local power supply; and monitoring and controlling 712 the operation of the at least one subsea hydrocarbon well, the at least one gravity-separation tank, the at least one subsea oil storage tank, and the offloading system. [0074] In one exemplary embodiment of the method 700, the method 700 may be applied to the subsea hydrocarbon development 600 or 650. For example, the subsea hydrocarbon well may be well 602, the gravity-separation tank may be subsea separation system 202, the subsea oil storage tank may be tank 340, the oil-transport vessel may be oil- transport vessel 324, and the oil offloading system may include pump 304 and line 306. The compressors may be compressors 116, the pumps may be water pumps 111 or oil pumps 108. [0075] One exemplary embodiment of offloading equipment for the oil offloading step 708 includes the conduit 306 connecting the storage tanks 342a-342g to the tanker transport vessel 324, which arrives periodically to offload the crude from the submerged tanks 340. Loading system options include disconnectable turret designs and bonded or unbonded flexible pipe. The loading rate may be very high, up to several million barrels per day, to minimize the time on-station, and may require several large transfer lines (only one shown for clarity purposes) 306.

[0076] The transport tanker 324 will be built to a sufficient ice-class depending on the field location. It may require ice breaker support, particularly during loading operations in heavy ice. Since the crude stored subsea may not be at vapor pressure sales specification, final gas removal may be required. The tanker 324 may have equipment to perform the final stage of gas flash from the crude. The flashed gas may be either recompressed for storage onboard as fuel for the tanker, recompressed for injection subsea, or flared. Also, if required, one of the hull tanks could be designed to accommodate slightly positive pressures to allow the complete gas flash prior to dead crude storage during transit. To minimize the Arctic tanker fleet size, the tankers could shuttle to a notionally ice-free area, where a lightering operation could transfer the crude to conventional tankers.

[0077] One exemplary embodiment of the control scheme for monitoring and controlling 712 may include subsea control from a host facility using lines for communications and power on copper wires. However, due to the complex scope of the subsea processing, additional sensors, actuators, and status information may be required for reliable operations, therefore high bandwidth and low latency data and information networks may be required. If a manned vessel or submarine is available in the field, then a fiber optic cable can be routed to the control station. Without a permanently manned facility, then through-water, ice, and satellite data transmission will be utilized. Alternatively, long distance fiber optic cable to an alternative location either onshore or offshore may be used. [0078] FIGs. 8A-8B illustrate two exemplary power supply arrangements that may be incorporated into the developments of FIGs. 6A-6B and methods of FIG. 7. As such, FIGs. 8A-8B may be best understood with reference to FIGs. 1, 2A-2B, 3A-3B, 6A-6B, and 7. The system 800 includes a subsea hydrocarbon development 801, a local power generation unit 802, which may include a submarine 804 and submarine docking stations 806a and 806b, a conditioning and distribution unit 810, the production well 602, gas compressors 812, pumps 814, and other power users 816.

[0079] In one particular embodiment of the system 800, the subsea hydrocarbon development 801 is the development 600 or alternative development 650, and the local power generation unit 802 is a locally docked submarine or in a locally installed structure on the seabed. In the submarine embodiment, the submarine 802 would likely be manned and capable of docking with docking stations 806a and 806b for a period of several weeks or several months and include a monitor, control, and command center as well as personnel trained and equipped to perform maintenance operations and possibly operate a subsea ROV (remote operated vehicle) to perform maintenance or otherwise enhance operations. In the locally installed structure, the structure 802 would not require separate docking stations 806a and 806b, except possibly for an occasional hook-up to an ROV or submarine and would likely be unmanned, but monitored and controlled from a remote location via wired or wireless signals.

[0080] The subsea processing machinery 812, 814, 816 (which may include pumps

614, 623, 636, and 304, compressors 608 and 632, and separators 620 and 202) may, in some embodiments, require a substantial amount of power (e.g. from 1 to 100 mega-watts (MW)) to operate. The actual power will depend on parameters such as reservoir injection pressure, throughput, system pressures, and other variables. Some efficiencies and power capture concepts could reduce the power demand, such as maximizing pre-separation unit 620 efficiency, and using turbo-expanders (618 and 626) to capture the energy from the well pressure.

[0081] In one particular embodiment of the submarine power supply, the power source may be nuclear. The submarine 802 may be also be used for a control station to operate all the subsea facilities including the wells, trees, manifolds, pumps, compressors, separators, or any other equipment on the sea floor. Electrical connections are made through the hull of the submarine 802 to enable transmission of the electrical power generated from the submarine's power plant to the subsea production system 801 end users (typically variable speed drives and motors on pumps, compressors, and other auxiliary equipment). Electrical connections will also be used for the control system communications and low power consumers (subsea control modules).

[0082] One potential mode of operation is that the submarine 802 will transit to the subsea field location 801, dock to a subsea landing pad 806a and 806b, and make the necessary connections for power and control to the nearby subsea facilities 812, 814, and 816. The submarine's power module could be integrated or separate from the control portion of the submarine 802. The shape of the submerged power supply unit may be cylindrical or be inside some other housing arrangement for protection from the environment. External, manned transport submarines could serve as both escape capsules and crew change transporters.

[0083] For both the submarine and locally installed submerged structure cases, the power generation source could be a variety of energy production methods including, but not limited to: nuclear, combustion, fuel cell, battery, geothermal, wave energy, current energy, produced fluid energy from reservoirs in the earth. The concept includes that any combination of components of the system 800 that may be either floating or submerged including, but not limited to: the location of the actual generation of the electrical power, transforming, frequency/voltage control, distribution, switchgear, conditioning, connecting, etc. The ship or submarine 802 can be changed out without shutting down the subsea equipment through the use of subsea power storage devices, which may also serve as back-up or redundancy in the submarine case or the permanent structure case. The power generated and supplied to the subsea field could be alternating current or direct current. The power generation station and/or the control station 802 may contain components that are either manned or unmanned. The entire system could operate unmanned. For example, the submarine 802 may include an adjacent unmanned power generation module, with only periodic interventions.

[0084] FIG. 8B discloses an alternative subsea power supply system 820, wherein the power supply and control 822 is located at the water surface 826 and connected via cable 824 to the subsea development 801. In one exemplary embodiment of this case, a vessel 822 could be 'stationed' above the field site 801 to supply continuous power. A power cable 824 will be tethered from the vessel 822 to the subsea distribution equipment 810, with a swivel device. The vessel 822 will have mobility within a given radius and have disconnect capabilities. One unique aspect of this arrangement is that the vessel 822 has a long, tethered power cable 824 to connect the vessel power supply to the subsea electrical distribution equipment 810. The vessel 822 can move within a range and continue to supply power and control to the subsea field 801. Electrical distribution equipment such as connectors will be required to route the power to the appropriate users. The control station could be on board the vessel 822, which would be in service year round and may include additional ice-breaker vessels (not shown) and other support vessels.

[0085] The range of operation of such a vessel could be from a few hundred meters to a few kilometers. The vessel 822 may or may not contain a cable spooling reel onboard which would limit the amount of cable on the seabed by continuously releasing or retrieving the power cable 824. A nuclear powered ice breaker with excess electric power to supply power to subsea equipment is one example where the power on board the ship could be used through a flexible and movable power cable connection, while the ship maintains approximate location through the use of its ice breaking capability. The vessel power system may contain a disconnectable device which would accommodate periodic changing of the vessel 822. This could be a moored turret system, a floating buoyant section, or any other mechanism allowing for disconnection/re-connection including a means to locate the cable. [0086] Several alternative arrangements may also be deployed. In one example, a floating ice-breaker power station 822 may be located in the Arctic in an area less prone to severe ice or icebergs than the producing field several hundred kilometers away, and feed power through a seabed cable 824 to the field site 801. Another alternative floating power solution could be that the oil-transport vessel 324 supplies power while onsite to a subsea power storage system (not shown), such as a battery or fuel cell system. The submerged battery or fuel cell system could be recharged to operate continuously. Alternatively, the SPSO system could be designed to only require large amounts of power while the vessel 822 is on station. In one alternative arrangement, it may be possible to transmit the power using long distance direct current (DC) from a land based or fixed offshore platform, but this approach may not be preferable.

[0087] It should also be understood that, unless clearly indicated to the contrary, in the claimed and disclosed methods herein, the order of the steps or acts of the methods are not necessarily limited to the order in which the steps or acts of the methods are recited. [0088] While the present inventions may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the inventions are not intended to be limited to the particular embodiments disclosed herein. Indeed, the present inventions include all alternatives, modifications, and equivalents falling within the true spirit and scope of the inventions as defined by the following appended claims. Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including equivalents to the various elements or limitations specified in the claims.

Claims

CLAIMSWhat is claimed is:

1. A fluid separation system, comprising a first gravity-separation tank at least partially constructed from structural concrete and configured to operate in a subsea environment.

2. The system of claim 1, wherein the first gravity-separation tank is configured to separate at least oil, water, and gas.

3. The system of claim 2, wherein the first gravity-separation tank is configured to separate the at least two fluids at a pressure of less than about 200 pounds per square inch (psi).

4. The system of claim 3, wherein the first gravity-separation tank is configured to separate the at least two fluids over a retention time from about twelve (12) hours to about 36 hours at full production rates.

5. The system of claim 4, wherein the first gravity-separation tank is configured to have a total processing throughput from about 100,000 barrels per day (bblpd) to about 500,000 bblpd.

6. The system of claim 2, wherein the first gravity-separation tank is configured to produce oil having less than about one volume percent water.

7. The system of claim 5, further comprising: at least one additional gravity-separation tank configured to operate in a subsea environment, wherein the at least one additional gravity-separation tank is operably connected to the first gravity-separation tank; and at least one buoyancy cell operatively connected to a tank selected from the group consisting of the first gravity-separation tank; the at least one additional gravity-separation tank; and any combination thereof.

8. The system of claim 6, wherein the first gravity-separation tank, the at least one additional gravity-separation tank and the at least one buoyancy cell are operably connected and configured to operate as a self-floating, gravity based structure (GBS).

9. The system of claim 8, wherein the system is configured to resist hydrostatic pressure forces in the subsea environment at depths of over at least about 200 feet and prevent hydrocarbon fluid exchange with the subsea environment.

10. The system of claim 9, further comprising: at least one gas-handling compressor operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity- separation tank.

11. The system of claim 10, further comprising a device selected from the group consisting of: at least one oil-handling pump operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity- separation tank; at least one sand slurry handling pump operably connected to a device selected from the group consisting of the first gravity-separation tank and the at least one additional gravity- separation tank; and any combination thereof.

12. A method of constructing and installing a fluid separation system, comprising: attaching at least one buoyancy cell to at least one gravity-separation tank to form the fluid separation system, wherein the at least one buoyancy cell and the at least one gravity- separation tank are at least partially constructed from structural concrete and configured to operate in a subsea environment.

13. The method of claim 12, further comprising: connecting at least one gas-handling compressor to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank; connecting at least one oil-handling pump to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank; and connecting at least one solids-capable water-handling pump to a device selected from the group consisting of the at least one buoyancy cell and the at least one gravity-separation tank.

14. The method of claim 13, further comprising: floating the fluid separation system out of a graving dock; releasing an air cushion from beneath the fluid separation system; connecting the fluid separation system to at least one marine vessel; towing the fluid separation system to a remote location with the at least one marine vessel; and ballasting the fluid separation system to the seafloor at the remote location.

15. The method of claim 14, further comprising managing ice with at least one ice-breaking vessel.

16. A subsea production system, comprising: at least one hydrocarbon production well configured to produce a production fluid; and at least one gravity-separation tank at least partially constructed from structural concrete and configured to separate at least two fluids over a retention time of at least one hour and operate in a subsea environment, receive the production fluid, and separate the production fluid into at least a volume of oil, a volume of water, and a volume of gas.

17. The system of claim 16, further comprising: at least one subsea oil storage tank at least partially constructed from structural concrete and configured to receive and store at least a portion of the volume of oil from the at least one gravity-separation tank; and an offloading system configured to offload at least a portion of the volume of oil from the subsea oil storage tank.

18. The system of claim 17, further comprising: at least one subsea water re-injection system configured to pump and re-inject at least a portion of the volume of water into a location selected from the group consisting of: a production reservoir, a storage reservoir, a subsea storage tank, and any combination thereof; and at least one subsea compression system configured to compress and re -inject the volume of gas into a location selected from the group consisting of: the production reservoir, the storage reservoir, and any combination thereof.

19. The system of claim 18, further comprising: a power plant configured to provide power to the subsea production system, wherein the power plant is at a location selected from the group consisting of: a locally docked submarine, a locally stationed floating vessel, a locally installed power system structure on the seabed, and any combination thereof; and wherein the power is generated from an energy production process selected from the group consisting of: nuclear, combustion, fuel cell, battery, geothermal, wave energy, current energy, produced fluid energy from reservoirs in the earth, solar, wind, and any combination thereof.

20. The system of claim 19, further comprising: a monitor and control system operably connected to the subsea production system, comprising: at least one pressure sensor operatively connected to the at least one gravity separation tank; and at least one flow controller operatively connected to the at least one well head water re-injection system to control the flow rate of the water re-injection system.

21. The system of claim 16, further comprising: a primary separation unit configured to receive the production fluid from the subsea well system and remove at least some produced water and at least some produced gas from the production fluid before the production fluid is sent to the at least one gravity-separation tank.

22. The system of claim 21 , further comprising: a first expander configured to receive the production fluid at a first pressure and capture energy by reducing the pressure of the production fluid from the first pressure to a second pressure; a second expander configured to receive the production fluid from the primary separation unit at a first separated pressure and capture energy by reducing the pressure of the production fluid from the first separated pressure to a second separated pressure and provide the production fluid at the second separated pressure to the at least one gravity-separation tank; at least one subsea water re-injection system configured to pump and re-inject at least a portion of the at least some produced water into a location selected from the group consisting of: a production reservoir, a storage reservoir, a subsea storage tank, and any combination thereof; at least one subsea compression system configured to compress and re-inject the at least some produced gas into a location selected from the group consisting of: the production reservoir, the storage reservoir, and any combination thereof; and a local power supply configured to provide power to at least the primary separation unit.

23. A method of producing hydrocarbons, comprising: producing a production fluid from at least one subsea hydrocarbon well; separating the production fluid in at least one gravity-separation tank configured to operate in a subsea environment into at least a volume of oil, a volume of water, and a volume of gas; storing at least a portion of the volume of oil from the at least one gravity-separation tank in at least one subsea oil storage tank; and offloading at least a portion of the volume of oil from the at least one subsea oil storage tank to an oil-transport vessel via an offloading system.

24. The method of claim 23, wherein the at least one subsea hydrocarbon well is located in an arctic environment.

25. The method of claim 24, wherein the oil-transport vessel is an ice-capable oil shuttle tanker.

26. The method of claim 23, further comprising monitoring and controlling the operation of the at least one subsea hydrocarbon well, the at least one gravity-separation tank, the at least one subsea oil storage tank, and the offloading system from a location selected from the group consisting of: the oil-transport vessel, another locally stationed surface vessel, a locally docked submarine, a remote location via satellite, cable, or wireless connection through air, water, ice, earth, and any combination thereof, and any combination thereof.

27. The method of claim 23, further comprising providing power to the at least one gravity-separation tank, the at least one subsea hydrocarbon well, the at least one subsea oil storage tank, and the offloading system from a local power supply.