Hydrocarbon production and storage facility

Abstract

A subsea fluids storage facility comprises a tank (11) for holding and separating fluids which is equipped with ballast capacity (14) and a separable base (12) 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 (24) for processing fluids. In deep water the tank (11) is held at a depth above the base (12) for temperature controlled stabilization of produced oil in the tank (11).

Claims

1. A method of treating and recovering production fluids from a subsea well, the method comprising connecting a first riser between a surface buoy and the well and supplying production fluids from the well through the first riser to the buoy, connecting a second riser between the buoy and a subsea storage tank for holding and separating fluids, the subsea storage tank including a single water/oil storage volume, the method including processing the fluids supplied to the buoy from the first riser to remove gas from the production fluids, supplying the de-gassed production fluids through the second riser to the subsea storage tank, separating water from oil within the subsea storage tank by maintaining a temperature profile of the fluids stored in the subsea storage tank, and exporting separated oil from the subsea storage tank following the separation of the water and the oil within the tank, wherein the method includes compartmentalising the single water/oil storage volume of the tank with at least one separator in the form of a baffle wherein the step of separation of the water and the oil within the tank comprises flowing gasses through a foraminated upper portion of the baffle, containing sludge within sludge containment zones between lower parts of the baffle, and flowing liquids through the baffle above the sludge containment zones and below the foraminated upper portion of the baffle, wherein said steps of flowing gasses, containing sludge and flowing liquids are performed within the subsea storage tank before export of the separated oil from the subsea storage tank.

2. The method according to claim 1, including removing gas from the oil contained within the subsea storage tank before exporting the oil from the subsea storage tank, wherein the step of removing gas is performed within the subsea storage tank.

3. The method according to claim 1, including heating the fluids within the subsea storage tank prior to exporting the fluids from the subsea storage tank.

4. The method according to claim 1, including submerging the subsea storage tank at an intermediate depth between a sea bed and a sea surface while treating the fluids within the subsea storage tank.

5. The method according to claim 1, including insulating the subsea storage tank against heat loss during the treatment of the fluids.

6. The method according to claim 1, including removing n-isobutane from the fluids stored in the subsea storage tank before exporting the fluids from the subsea storage tank.

7. The method according to claim 1, including removing sand from the fluids in the buoy before supplying the fluids to the subsea storage tank through the second riser.

8. The method according to claim 1, including maintaining the subsea storage tank at an intermediate depth between the sea bed and the buoy during the separation of water from oil within the subsea storage tank.

9. A method as claimed in claim 1, the method including minimising impact of inward and outward fluid flow disturbance upon the separating fluids in the storage tank.

10. A method as claimed in claim 1, including supplying heat to the fluids in the subsea storage tank and including generating the heat on the buoy and transferring the heat generated on the buoy to the subsea storage tank.

11. A method as claimed in claim 1, including consuming gas on the buoy to provide power to heat the fluids in the subsea storage tank.

12. A method as claimed in claim 1, including separating gas from liquids in the subsea storage tank, and returning gas to the buoy through a balance line for treatment of the gas in the buoy.

13. A method as claimed in claim 1, including returning water separated from the oil within the subsea storage tank to the buoy.

14. A method as claimed in claim 13, including discharging water that has returned from the subsea storage tank to the buoy into the sea.

15. A method as claimed in claim 1, including flowing water from the buoy to the subsea storage tank and displacing oil separated from water in the subsea storage tank into an oil export line.

16. A method as claimed in claim 1, including connecting a first end of the second riser to the buoy, and a second end of the second riser to the subsea storage tank.

17. A method of treating and recovering production fluids from a subsea well, the method comprising connecting a first riser between a surface buoy and the well and supplying production fluids from the well through the first riser to the buoy, connecting a first end of a second riser to the buoy and connecting a second end of the second riser to a subsea storage tank for holding and separating fluids, processing the fluids supplied to the buoy from the first riser to remove gas from the production fluids, supplying the de-gassed production fluids through the second riser to the subsea storage tank, separating water from oil within the subsea storage tank by maintaining a temperature profile of the fluids stored in the subsea storage tank, exporting oil from the subsea storage tank following the separation of the water and the oil within the tank, and returning at least some of the water separated from oil in the subsea storage tank back to the buoy.

18. A method as claimed in claim 17, including discharging at least some of the water returned to the buoy into the sea.

19. A method as claimed in claim 17, wherein the subsea storage tank comprises a single water/oil storage volume, wherein the method includes compartmentalising the single water/oil storage volume of the tank with at least one separator in the form of a baffle wherein the step of separation of the water and the oil within the tank comprises flowing gasses through a foraminated upper portion of the baffle, containing sludge within sludge containment zones between lower parts of the baffle, and flowing liquids through the baffle above the sludge containment zones and below the foraminated upper portion of the baffles, wherein said steps of flowing gasses, containing sludge and flowing liquids are performed within the subsea storage tank before export of the separated oil from the subsea storage tank.

20. A method of treating and recovering production fluids from a subsea well, the method comprising connecting a first riser between a surface buoy and the well and supplying production fluids from the well through the first riser to the buoy, connecting a second riser between the buoy and a subsea storage tank for holding and separating fluids, processing the fluids supplied to the buoy from the first riser to remove gas from the production fluids, supplying the de-gassed production fluids through the second riser to the subsea storage tank, separating water from oil within the subsea storage tank by maintaining a temperature profile of the fluids stored in the subsea storage tank, flowing water from the buoy to the subsea storage tank and displacing oil separated from water in the subsea storage tank and exporting separated oil from the subsea storage tank following the separation of the water and the oil within the tank.

Description

DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 illustrates a side view of an embodiment of the tank and separable base with associated ballast tanks and detachable feet at section A-A of FIG. 2;

(2) FIG. 2 shows a plan view of a heated section of the tank with associated ballast tanks at section B-B of FIG. 1;

(3) FIG. 3 shows a plan view of the base at section C-C of FIG. 1;

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

(5) 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;

(6) FIG. 5 illustrates an initial flooding stage for deploying the tank;

(7) FIG. 6 illustrates a later stage during submerging of the flooded tank;

(8) FIG. 7 illustrates a later stage for deploying the flooded tank under ballast control;

(9) 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;

(10) FIG. 9 illustrates the buoy ballasted to operational depth and tank settled to sea bed;

(11) FIG. 10 illustrates connection of a central riser from the tank to the buoy using an ROV controlled from the support vessel;

(12) FIG. 11 illustrates connection of wellhead production risers to buoy, commission and start up;

(13) 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;

(14) FIG. 13 illustrates the separate installation of the tank and base by separating the tank from the base and flooding base ballast tanks;

(15) FIG. 14 illustrates the separation of gravity base from the tank and initial lowering of the base;

(16) FIG. 15 illustrates the gravity base settled on the seabed and located in place;

(17) FIG. 16 illustrates the tank being guided and lowered on to the gravity base;

(18) FIG. 17 illustrates the tank located and locked on to the gravity base on the seabed;

(19) FIG. 18 illustrates the buoy being located above the tank/base and ballasted to below tether tension depth;

(20) FIG. 19 illustrates the buoy tethered to the tank/base and ballasted to operational depth;

(21) FIG. 20 illustrates connection of central riser from the tank to the buoy using an ROV controlled from the support vessel.

(22) FIG. 21 illustrates connection of wellhead production risers to buoy, commission and start-up.

(23) 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;

(24) FIG. 23 illustrates an ROV from the supply vessel uncoupling and removing flexible production and central riser;

(25) 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;

(26) FIG. 25 illustrates the detachment and ballasting of tank from the gravity base feet;

(27) FIG. 26 illustrates the raising of tank and gravity base to the surface;

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

(29) 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;

(30) FIG. 29 illustrates inflating of the ballast tanks and raising the tank to the surface;

(31) FIG. 30 illustrates the tank ballasted at surface and detaching the gravity base from the detachable feet, ballasting the gravity base to the surface;

(32) FIG. 31 illustrates an ROV from vessel recovering detachable feet;

(33) FIG. 32 illustrates a variant where the buoy moored to the seabed adjacent to a well with the tank tethered to the gravity base;

(34) FIG. 33 illustrates tank tethered to the gravity base with tank moored adjacent to the buoy;

(35) FIG. 34 illustrates schematically a side view of an embodiment of a sub-sea storage facility comprising a tank and associated ballast tanks; and

(36) FIG. 35 illustrates schematically an internal cross-section of the tank embodiment illustrated in FIG. 34.

DESCRIPTION OF EMBODIMENTS

(37) 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.

(38) The storage tank 11 includes a central separator zone 13 configured to receive produced oil for stabilisation by separation of water and volatiles under a temperature controlled stabilisation process.

(39) Referring to FIG. 2, the storage tank 11 is compartmentalised 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.

(40) 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.

(41) 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.

(42) The central separator zone 13 also is provided with a heater element 26 to heat produced oil received therein.

(43) Referring to FIG. 3, a separable gravity base 12 comprises a base for releasably receiving the storage tank 11, and base associated ballast tanks 16 which are supported upon releasable feet 18.

(44) 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).

(45) 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.

(46) 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).

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

(48) 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.

(49) 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.

(50) 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 deepwater 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)

(51) 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.

(52) Broadly the available methods comprise the steps of: (i) tow out, (ii) positioning on site (iii) ballast control to submerge storage facility (FIG. 5) and/or gravity base either as separate or combined operation (iv) establish base at wellhead (v) submerge storage tank 11 to working depth (FIGS. 6, 7, 8 and 9) (vi) connect storage tank 11 to production buoy 24 by central riser 45 (FIG. 10) (vii) connect production risers 47, from wellhead 46 to buoy 24 (FIG. 11) (viii) commission and start up (FIG. 12).

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

(54) 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.

(55) 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.

(56) 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 meters above the seabed 80 before deploying the buoy 24 (FIG. 8).

(57) 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).

(58) 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).

(59) In a deepwater situation, the storage tank 11 is not allowed to descend beyond the operational oil processing depth for temperature controlled stabilisation 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.

(60) 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).

(61) 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).

(62) 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).

(63) 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.

(64) The production buoy, oil stabilisation and storage tank, gravity base and separable feet are all capable of being re-used at another location.

(65) In alternative configurations for operations either: A. The buoy is moored and the tank floats on the surface tethered to the seabed (FIG. 39), or B. The buoy is tethered to the seabed and the tank floating on the surface is spread moored (FIG. 33).

(66) 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.

(67) 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. 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 stabilisation by separation of water and volatiles under a temperature controlled stabilisation 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.

(68) 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.

(69) 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.

(70) Construction with a double skin wall permits installation of thermal insulation material which allows an operational design temperature of 140° C.

(71) Embodiments may be used in a variety of processes including: 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. 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 meters. 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 process. 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. 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 stabilisation temperature of up to 80° C. in the tank. 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. 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. 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). 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. 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. 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. 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.