HYDROCARBON PRODUCTION AND STORAGE FACILITY

Abstract

A subsea fluids storage facility comprises a tank for holding and separating fluids which is equipped with ballast capacity and a separable base to be deployed upon the seabed in shallow or deep water, and the storage facility is connectable to a surface production facility, especially a buoy for processing fluids. In deep water the tank is held at a depth above the base for temperature controlled stabilization of produced oil in the tank.

Claims

1. A system for the treatment of production fluids from a subsea well, the system comprising: a production buoy having processing equipment adapted to treat production fluids received by the buoy via a first conduit from the subsea well; and a subsea storage facility comprising: a single subsea storage tank for holding and separating fluids, the subsea storage tank having a ballast capacity; a separable base; a second fluid conduit between the buoy and the subsea storage tank to transfer the treated production fluids to the subsea storage tank; wherein the base is deployed upon the seabed and the subsea storage tank is tethered to the base and submerged at a depth within the operational oil processing depth for temperature controlled stabilization of produced oil in the subsea storage tank.

2. A system for the treatment of production fluids from a subsea well according to claim 1, wherein an outer surface of the subsea storage tank has protruding parts to mitigate vortex effects upon the subsea storage facility.

3. A system for the treatment of production fluids from a subsea well according to claim 2, wherein the protruding parts comprise continuous or discontinuous ribs, fins, strakes or ridges extending over the surface, optionally in a curved path.

4. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the subsea storage tank has surface portions selected from the group consisting of torispherical, semi-ellipsoidal, hemispherical, dished and conical parts.

5. A system for the treatment of production fluids from a subsea well according to claim 4, wherein the subsea storage tank has a base wall and a head wall of like shape but oppositely oriented so that the base wall is the inverse orientation of the head wall.

6. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the separable base is a gravity base.

7. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the separable base is settled by use of suction.

8. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the storage facility comprises ballast subsea storage tanks associated with the storage subsea storage tank and wherein the ballast subsea storage tanks are separable from the storage subsea storage tank.

9. A system for the treatment of production fluids from a subsea well according to claim 8, wherein the ballast tanks are selected from a range of different sized and shaped subsea storage tanks including tall narrow cross- section designs and squat large cross-section ballast subsea storage tanks.

10. A system for the treatment of production fluids from a subsea well according to claim 9, wherein the ballast subsea storage tanks comprise detachable feet.

11. A system for the treatment of production fluids from a subsea well according claim 1, wherein the subsea storage tank comprises a single oil/water storage volume with internal compartmentalization using sufficient partitions, baffles or the like space dividers to limit or control internal fluid flow and to provide a degree of segregation to facilitate oil/water separation.

12. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the subsea storage tank is compartmentalized such that there is provided a central subsea storage tank with optionally removable upper and lower parts, oil storage and water separation internal divisions, with delivery and recovery systems, and contingency measures for use with the BOP.

13. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the subsea storage tank is sealed with respect to the environment, such that access and egress of fluids, heat and power is via the point of connection to a fluid conduit.

14. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the fluid conduits are risers.

15. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the subsea storage tank is submerged at a depth to provide heat to facilitate temperature-based separation of water and volatiles from the oil within the storage subsea storage tank.

16. A system for the treatment of production fluids from a subsea well according to claim 1, wherein heat is supplied from the buoy to the subsea storage tank wherein the produced gas is consumed on the buoy to provide power to heat the fluids within the storage subsea storage tank.

17. A system for the treatment of production fluids from a subsea well according to claim 1, including a heat transfer conduit adapted to supply heat to the fluids stored in the subsea storage tank to maintain a stabilization temperature of up to 80° C. within the subsea storage tank.

18. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the processing equipment in the buoy incorporates at least one of de-gassing and de-sanding equipment and at least some of either gas or sand is removed from the fluids before supplying the fluids to the storage subsea storage tank through the second fluid conduit.

19. A system for the treatment of production fluids from a subsea well according to claim 1, wherein the subsea storage tank comprises a central separator zone defined by a column wall, wherein the lower part of the wall comprises a sludge collection zone, and wherein the wall above the sludge collection zone is fluid permeable.

20. A process for separation of water and volatiles, especially n-isobutane, from oil produced from a reservoir which comprises collecting oil in a single submerged tank which is at a depth allowing temperature-based separation of water and volatiles from the oil over a period from about 8 to 60 days or more.

Description

DESCRIPTION OF THE DRAWINGS

[0047] FIG. 1 illustrates a side view of an embodiment of the tank and separable base with associated ballast pods and detachable feet at section A-A of FIG. 2;

[0048] FIG. 2 shows a plan view of a heated section of the tank with associated ballast pods at section B-B of FIG. 1;

[0049] FIG. 3 shows a plan view of the base at section C-C of FIG. 1;

[0050] FIG. 4 illustrates the towing of a storage facility together with a production buoy for deployment either as a single or separate operation;

[0051] FIG. 4a illustrates the towing of a storage facility with detachable base together with a production buoy for deployment either as a single or separated operation;

[0052] FIG. 5 illustrates an initial flooding stage for deploying the tank;

[0053] FIG. 6 illustrates a later stage during submerging of the flooded tank;

[0054] FIG. 7 illustrates a later stage for deploying the flooded tank under ballast control;

[0055] FIG. 8 illustrates positioning the production buoy on station above the tank whilst controlling tank descent to approx. 15 m above seabed by tension of the tethers connected to the buoy;

[0056] FIG. 9 illustrates the buoy ballasted to operational depth and tank settled to sea bed;

[0057] FIG. 10 illustrates connection of a central riser from the tank to the buoy using an ROV controlled from the support vessel;

[0058] FIG. 11 illustrates connection of wellhead production risers to buoy, commission and start up;

[0059] FIG. 12 illustrates an operational system with a wellhead connected by riser to a production buoy which in turn is connected to the separation and storage facility by an umbilical tubular for transferring produced oil to the tank of the facility;

[0060] FIG. 13 illustrates the separate installation of the tank and base by separating the tank from the base and flooding base ballast tanks;

[0061] FIG. 14 illustrates the separation of gravity base from the tank and initial lowering of the base;

[0062] FIG. 15 illustrates the gravity base settled on the seabed and located in place;

[0063] FIG. 16 illustrates the tank being guided and lowered on to the gravity base;

[0064] FIG. 17 illustrates the tank located and locked on to the gravity base on the seabed;

[0065] FIG. 18 illustrates the buoy being located above the tank/base and ballasted to below tether tension depth;

[0066] FIG. 19 illustrates the buoy tethered to the tank/base and ballasted to operational depth;

[0067] FIG. 20 illustrates connection of central riser from the tank to the buoy using an ROV controlled from the support vessel.

[0068] FIG. 21 illustrates connection of wellhead production risers to buoy, commission and start-up.

[0069] FIG. 22 illustrates a deep water operational system with gravity base on the seabed tethering the tank which is not lowered onto the gravity base;

[0070] FIG. 23 illustrates an ROV from the supply vessel uncoupling and removing flexible production and central riser;

[0071] FIG. 24 illustrates buoy ballasted to remove tension from tethers, tethers decoupled from buoy using davit on buoy or ROV, and marker/ballast buoys attached to base;

[0072] FIG. 25 illustrates the detachment and ballasting of tank from the gravity base feet;

[0073] FIG. 26 illustrates the raising of tank and gravity base to the surface;

[0074] FIG. 27 illustrates the tank and gravity base recovered at surface, ballasted for tow out, with ROV from vessel deployed to recover feet;

[0075] FIG. 28 illustrates a multiple unit recovery with the separation of the tank from the gravity base after uncoupling risers etc. as illustrated in FIGS. 23 & 24;

[0076] FIG. 29 illustrates inflating of the ballast pods and raising the tank to the surface;

[0077] FIG. 30 illustrates the tank ballasted at surface and detaching the gravity base from the detachable feet, ballasting the gravity base to the surface;

[0078] FIG. 31 illustrates an ROV from vessel recovering detachable feet;

[0079] FIG. 32 illustrates a variant where the buoy moored to the seabed adjacent to a well with the tank tethered to the gravity base;

[0080] FIG. 33 illustrates tank tethered to the gravity base with tank moored adjacent to the buoy;

[0081] FIG. 34 illustrates schematically a side view of an embodiment of a sub-sea storage facility comprising a tank and associated ballast tanks; and

[0082] FIG. 35 illustrates schematically an internal cross-section of the tank embodiment illustrated in FIG. 34.

DESCRIPTION OF EMBODIMENTS

[0083] Referring to FIG. 1, a deployable and recoverable storage facility comprises a storage tank 11 associated with a separable gravity base 12, and ballast tanks 14, 16, respectively for each of the storage tank 11 and the gravity base 12. Multiple ballast tanks 14, 16, (only one shown) are provided around the storage facility. Releasable feet 18 which may be configured for height adjustment to compensate for variable seabed conditions are attached to each of the base ballast tanks.

[0084] The storage tank 11 includes a central separator zone 13 configured to receive produced oil for stabilization by separation of water and volatiles under a temperature controlled stabilization process.

[0085] Referring to FIG. 2, the storage tank 11 is compartmentalized by radially extending internal walls 21 around the central column separator zone 13 which is defined by an upright tubular column 22. Each sector shaped compartment may include a heater element 23 for maintaining a desired temperature profile therein.

[0086] The heater elements 23 may be formed of a tubular element the length of which is accommodated in the space by e.g. successive returns to form a serpentine flow path, or spiral, or coil, or other convoluted shapes.

[0087] The tubular elements contain either a glycol or oil based fluid heat transfer fluid. In some embodiments of the invention, heat is provided by electrical heaters.

[0088] The central separator zone 13 also is provided with a heater element 26 to heat produced oil received therein.

[0089] Referring to FIG. 3, a separable gravity base 12 comprises a base for releasably receiving the storage tank 11, and base associated ballast pods 16 which are supported upon releasable feet 18.

[0090] Referring to FIGS. 1 and 2, the storage tank 11 is sealed with respect to the environment in use, and is provided with industry standard ports and associated couplings for connection of riser, communications, fluids and service umbilicals, and anchor and tether lines etc. (not shown).

[0091] In use, fluids flow from the subsea well via either natural pressure, or by water injection using a raw sea water pump, powered from a local facility such as a surface vessel, FPSO, platform or preferably a dedicated production buoy 24 with appropriate facilities including heaters, degassing and export functionality. Artificial lift using an ESP or for heavy oil ESPCP may be used to deliver fluids into the buoy 24. The fluids arrive at the subsea tree where they are choked back to regulate the pressure at the seabed.

[0092] Flexible risers then transport fluids from the production tree into the buoy 24 where if there are several wells they pass through a multiphase meter. Production fluids from the well(s) enter the buoy and are comingled in the production header before routing to the degasser/de-sander vessel. Well fluids then pass into the de-gasser/de-sander where the gas is flashed off under near atmospheric pressure and heating. Sand can be removed if required and disposed to sea using turbine oil re-claiming equipment (TORE clean up system).

[0093] Gas which is removed is then sent to selected zones to: [0094] a) Provide fuel for power for the 10 MW engines (utilizing up to 2 million standard cubic feet per day, 1 MMSDFD approximates to 28316.847 m.sup.3 per day @60° F./20° C.) [0095] b) Provide fuel to boilers to heat the subsea storage tank via two boilers (utilizing a combined 6 mmscfd) [0096] c) Flaring for emergency response and peak conditions (up to 30 mmscfd)

[0097] Oil and water are then pumped from the buoy 24 down in to the concrete storage tank 11 via the service riser. There the long residence time of fluids within the storage tank 11 combined with the potential to heat the ˜200,000 barrel contents means that any remaining vapours can be circulated back to the degasser via a balance line.

[0098] The produced water which typically separates to 30 ppm or less is then pumped back or displaced under pressure in to the buoy 24 where it is polished to less than 20 ppm and discharged to sea.

[0099] There are multiple methods to deploy the separation and storage facility and a selection will be made by consideration of the location of the well e.g. shallow water or deep water site, the nature of the seabed surface at the wellhead, the potential yield of remaining assets in the formation containing the reservoir, etc. (see FIGS. 4 and 5)

[0100] Deployment typically requires the following resources, several service vessels or tugs, a production buoy, and at least one ROV. It is not normally required to provide divers since the deployment operation can be remotely controlled.

[0101] Broadly the available methods comprise the steps of: [0102] a) tow out, [0103] b) positioning on site [0104] c) ballast control to submerge storage facility (FIG. 5) and/or gravity base either as separate or combined operation [0105] d) establish base at wellhead [0106] e) submerge storage tank 11 to working depth (FIGS. 6, 7, 8 and 9) [0107] f) connect storage tank 11 to production buoy 24 by central riser 45 (FIG. 10) [0108] g) connect production risers 47, from wellhead 46 to buoy 24 (FIG. 11) [0109] h) commission and start up (FIG. 12).

[0110] Variants may include additional steps or combinations of the steps (FIGS. 13 to 21).

[0111] Installation equipment for the installation in a single trip includes air couplings, suction piling systems, temporary ballasting, descent control systems, location systems and involves the lowering of the storage tank 11 with the buoy 24 attached in such a manner as to ensure a single installation can be achieved with the buoy, tank and tethers or mooring attached and in situ.

[0112] In a possible deployment and use of the separation and storage facility, a tow “package” assembly consisting of a suitable oil production buoy and storage tank with gravity base are towed together, typically in tandem to the work location above the wellhead(s). Multiple vessels, typically 3 boats such as tugs or service vessels 34, would be used to position the buoy 24 and storage tank 11 but a lesser number may be used for towing if further vessels may be called upon at the work location.

[0113] As a first step, the storage tank 11 connected to the buoy 24 by tethers 25 is partially flooded to submerge it (FIG. 5) and after it is fully flooded (FIG. 6) the storage tank 11 descends under control by ballasts (FIG. 7) to an operational oil processing depth determined by length and tension in the buoy tethers 25. The storage tank 11 may be allowed to descend to about 15 metres above the seabed 80 before deploying the buoy 24 (FIG. 8).

[0114] In a further step, the buoy 24 is ballasted to its operational depth and the storage tank 11 allowed to settle on the sea bed where the wellhead is located in shallow waters (FIG. 9).

[0115] In an alternative shallow water situation, the separable gravity base is deployed to the sea floor before the storage tank 11 is submerged to be guided to settle on the base and locked to the base using an ROV 35 (FIGS. 13 to 16).

[0116] In a deep water situation, the storage tank 11 is not allowed to descend beyond the operational oil processing depth for temperature controlled stabilization of produced oil in the storage tank 11. A gravity base is deployed on the seabed, and the equipment required to make up an operational system are tethered to the gravity base. (FIG. 22). A wellhead is connected by a riser to a production buoy 24 which is in turn connected to a submerged but suspended separation and storage tank 11 by an umbilical for transferring produced oil to the storage tank 11.

[0117] A riser 45 between the storage tank 11 and the buoy 24 (FIG. 10) is connected by use of an ROV 35 operated from one of the service vessels/tugs 34, and then the production risers 47 are connected between the wellhead(s) 46 and the buoy 24 (FIG. 11).

[0118] When the time comes for recovery of the storage tank 11 for re-deployment elsewhere, the recovery procedure is generally the reverse of deployment (FIGS. 23 to 31).

[0119] The flexible and central risers 45, 47 would be uncoupled and removed in the initial stages of recovery (FIG. 23). Then the buoy 24 would be ballasted down to release tension in the tethers 25 to the storage tank 11, the tethers 25 would be decoupled e.g. by use of a davit crane (not shown) on the buoy 24 or by use of an ROV 35, to separate the buoy 24 and storage tank 11 (FIG. 24).

[0120] Then after de-ballasting the buoy 24 to tow depth, the storage tank 11 recovery operation can be undertaken. The storage tank 11 and base 12 can either be recovered together (FIGS. 25 and 26) or in separate operations (FIGS. 28, 29 and 30), and in either case it may be suitable to separate the base from the detachable feet 18 and recover these separately using an ROV (FIGS. 27 and 31). If the storage tank 11 is to be recovered first, then it is unlatched from the gravity base 12 (FIG. 28), and de-ballasted to encourage recovery to surface (FIG. 29). Additional buoyancy device use and or crane lifting may be appropriate to facilitate recovery. The storage tank 11 is ballasted for tow away (FIG. 30), and the recovery of the base 12 is undertaken in a similar fashion (FIGS. 30 and 31). The package of buoy, tank and base can then be towed away using the service vessels or tugs in attendance.

[0121] The production buoy, oil stabilization and storage tank, gravity base and separable feet are all capable of being re-used at another location.

[0122] In alternative configurations for operations either: [0123] a) The buoy is moored and the tank floats on the surface tethered to the seabed (FIG. 39), or [0124] b) The buoy is tethered to the seabed and the tank floating on the surface is spread moored (FIG. 33).

[0125] In an emergency situation during flaring, the storage facility with associated production facility can manage up to 30 million standard cubic feet of well gases per day.

[0126] In another embodiment of the tank, as illustrated in FIG. 34, the tank 31 has a dished head 36 and oppositely oriented dished base 39. The side wall of the tank 31 is provided with curved strakes 37 to serve as vortex shedders. The associated ballast tanks 32 are removable pods, and these also have curved strakes 38 on the side walls for the same purpose of mitigating vortex effects.

[0127] A cross-sectional side view of the embodiment of FIG. 34, shown in FIG. 35 shows the tank 31 is constructed with a twin wall 40. The twin wall may accommodate thermal insulation material. The interior of the tank 31 has a central separator zone 33 defined within a column wall, the zone being configured to receive produced oil for stabilization by separation of water and volatiles under a temperature controlled stabilization process. The upper part 43 of the column wall may be permeable to gas, for example slotted or otherwise foraminated. In embodiments, the lower part of the column wall 44 may define a sludge collection zone above which the column wall is fluid permeable.

[0128] The dished head 36, and the dished base 39 of the tank 31 may have a centrally positioned external connection for a collection conduit such as gas offtake, or sediment/sludge/solids removal may be usefully employed with convex shaped inner tank surfaces since gas will tend to collect at the highest point internally of the tank, and gravity will draw heavy fluids and solids to the lowest point internally of the tank. The lowest point may be provided with a weir or internal sludge confinement wall.

[0129] In embodiments with the rounded dished head 36 and rounded dished base 39 the tank may be operated with a design pressure of 8 bar. Temperature distribution in a tank of this shape is improved. The dished configuration facilitates both gas collection at the head of the tank, and also sludge collection at the base of the tank.

[0130] Construction with a double skin wall permits installation of thermal insulation material which allows an operational design temperature of 140° C.

[0131] Embodiments may be used in a variety of processes including: [0132] 1. A process for separation of water and volatiles, especially n-isobutane, from oil produced from a reservoir which comprises collecting oil in a submerged tank which is at a depth allowing temperature-based separation of water and volatiles from the oil over a period of from about 8 to 60 days or more. [0133] 2. A process for separation of water and volatiles from oil produced from a reservoir wherein the submerged tank is at a depth below sea level of up to 120 metres. [0134] 3. A process for separation of water and volatiles from oil produced from a reservoir wherein produced gas is throttled to limit produced gas to a quantity sufficient to satisfy fuel requirements for use in providing heat for the separation [0135] 4. A process for separation of water and volatiles from oil produced from a reservoir wherein production flow is controlled by one or more operations selected from the group consisting of choking production at the wellhead, controlling pump speed (e.g. ESP) and lift rate. [0136] 5. A process for separation of water and volatiles from oil produced from a reservoir wherein heat is supplied to the produced oil when necessary to achieve a stabilization temperature of up to 80° C. in the tank. [0137] 6. A process for separation of water and volatiles from oil produced from a reservoir wherein prior to collecting oil in the submerged tank the oil produced from the reservoir is subjected to at least one of de-gassing and de-sanding under controlled temperature conditions. [0138] 7. A process for separation of water and volatiles from oil produced from a reservoir wherein flow is maintained by use of at least one of an electrical submerged pump (ESP), an electrical submerged progressive cavity pump (ESPCP) and seawater injection pump. [0139] 8. A process for separation of water and volatiles from oil produced from a reservoir useful for water depths exceeding 120 m, wherein the tank is separated from the gravity base and the configuration can be used in deep water (exceeding 2,000 m water depth). [0140] 9. A process for separation of water and volatiles from oil produced from a reservoir wherein the tank depth is set according to volatiles, partial vapour pressures and the ability to remove n-isobutane via heating up to 80° C. [0141] 10. A process for handling reservoir fluids by deploying a tank with an optionally separable base, wherein the base can be opened as part of an emergency response function and located in position by a guide located over a BOP and/or well. [0142] 11. A process for handling reservoir fluids by deploying a tank with an optionally separable base, where in emergency response mode, heating of the tank fluids as part of lowering the tank in situ, inhibits formation of hydrates. [0143] 12. A process for handling reservoir fluids by deploying a tank with an optionally separable base, where under emergency flaring up to 30 million standard cubic feet per day of well gasses is managed.