Techniques in the upstream oil and gas industry

Abstract

CO.sub.2 in the liquid or super-critical state is delivered by at least one carrier vessel from at least one CO.sub.2 storage site, which may be an onshore site, to an integrated offshore facility. The integrated offshore facility is provided with at least one on-site storage tank or vessel adapted to store CO.sub.2 in the liquid or super-critical state and with equipment for marine transfer of CO.sub.2 in the liquid or super-critical state. CO.sub.2 is utilised as required from said at least one on-site storage tank or vessel for EOR at said offshore site or for EGR at said offshore site by injection into a sub-sea oil or natural gas bearing reservoir and recovery of oil and/or natural gas from a resulting production stream.

Claims

1. A method for enhancing offshore oil recovery at a first offshore hydrocarbon production facility using carbon dioxide (CO.sub.2) or for enhancing offshore natural gas recovery at said first offshore facility using CO.sub.2 comprising the steps of: delivering CO.sub.2 in a liquid state or a super-critical state by at least one carrier vessel from at least one CO.sub.2 storage site to said first offshore facility, said first offshore facility being provided with at least one on-site CO.sub.2 storage unit, selected from subsea tanks or internal tanks within a hull or other floating structure of the offshore facility, and with marine transfer equipment configured to transfer CO.sub.2 in said state from the carrier vessel to the on-site storage unit; storing the CO.sub.2 in said state in the on-site storage unit; and utilizing the CO.sub.2 from said at least one on-site storage unit for enhanced oil recovery at said first offshore site or for enhanced gas recovery at said first offshore site both at times when a said carrier vessel is present at said first offshore facility and at times when no carrier vessel is present at said first offshore facility by injecting the CO.sub.2 into a sub-sea oil or natural gas bearing reservoir and recovering oil and/or natural gas from a resulting production stream; wherein the at least one CO.sub.2 storage site comprises a second offshore hydrocarbon production facility remote from the first offshore facility, said second offshore facility comprising a hydrocarbon production facility having an oil and/or natural gas production stream that includes entrained CO.sub.2 in an amount in excess of requirements for use of CO.sub.2 at said second offshore facility, said second offshore facility being provided with: at least one on-site storage unit selected from internal tanks within the second offshore facility, sub-sea tanks and at least one tank within the hull of a separate hulled vessel, the at least one on-site storage unit of said second offshore facility being adapted to store in said state CO.sub.2 separated from said production stream that includes entrained CO.sub.2; and marine transfer equipment configured to transfer stored CO.sub.2 in said state from said at least one on-site storage unit of said second offshore facility to a said carrier vessel for transport thereby to said first offshore facility.

2. An apparatus for enhanced offshore oil recovery using carbon dioxide (CO.sub.2) or for enhanced offshore natural gas recovery using CO.sub.2, comprising: a first offshore hydrocarbon production facility provided with: at least one on-site storage unit, selected from subsea tanks and internal tanks within a hull or other floating structure of the offshore facility, adapted to store CO.sub.2 in a liquid or a super-critical state at said first offshore facility; marine transfer equipment configured to transfer CO.sub.2 in said state to and from said at least one on-site storage unit; injection equipment configured to inject CO.sub.2 into a sub-sea oil field for enhanced recovery of oil or into a sub-sea natural gas field for enhanced recovery of natural gas; and recovery equipment configured to recover oil and/or natural gas from a resulting production stream; and at least one carrier vessel adapted to deliver CO.sub.2 in said state from at least one CO.sub.2 storage site remote from the first offshore facility to the said first offshore facility or to export CO.sub.2 in said state from the said first offshore facility to a second offshore hydrocarbon production facility remote from the first offshore facility; the first offshore facility being further provided with first plant and equipment which has the capability to process CO.sub.2-laden hydrocarbon production streams, separate CO.sub.2 from production fluids, and process and apply the necessary pressure and temperature regulation to separated CO.sub.2 so that it reaches said state; and with second plant and equipment coupled to said first plant and equipment, to said at least one on-site storage unit, and to said injection equipment to store the separated CO.sub.2 in said at least one on-site storage unit or to transfer CO.sub.2 to the injection equipment for injection into the sub-sea oil field or the sub-sea natural gas field.

3. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a concrete structure located in fixed position by the ballasted weight of the structure resting on the seabed.

4. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a floating production storage and offloading structure in the form of a marine vessel having a hull and a deck, the hull being of a ship-like shape or a generally cylindrical shape, and being provided with oil storage tanks therewithin for periodic offloading of oil to an oil tanker, and the deck being provided with hydrocarbon processing equipment.

5. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a jack-up structure in which a barge type production platform is provided with legs and configured to be towed to a selected position at said offshore facility and to be jacked up on the said legs directly from the seabed or from structure comprising at least one ballasted steel tank located on the seabed, and said on-site storage unit comprises at least one tank provided within at least one of the barge and the structure.

6. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a pre-existing hydrocarbon production facility is provided with an additional separate floating storage and offloading vessel comprising a hull without oil or natural gas production facilities, said on-site storage unit comprising tanks within the hull of said separate vessel.

7. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a pre-existing hydrocarbon production facility provided with an additional separate vessel comprising both the first plant and equipment and the second plant and equipment.

8. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a steel structure comprising topsides, and a combined tank and steel jacket on which the topsides are supported, and the steel structure is located on the seabed by ballasted tanks capable of being emptied to allow the structure to be floated for relocation; and wherein the at least one on-site storage unit adapted to store CO.sub.2 in said state is separate from any ballasted tanks and provided in the ballasted structure or mounted on the seabed.

9. The apparatus of claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a floating structure having a hull and a deck, and comprising a vessel-based natural gas production facility provided with topsides plant comprising natural gas liquefaction plant on its deck and liquefied natural gas storage tanks in its hull for periodic offloading to a liquefied natural gas tanker, and wherein the liquefied natural gas storage tanks are separate from said at least one storage unit.

10. The apparatus of claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a spar tethered to the seabed and comprising a vertically oriented cylindrical section located below the waterline and a floating platform supported by the cylindrical section and comprising topsides including oil production facilities, wherein oil storage tanks are located within the vertical cylindrical section for periodic unloading to an oil tanker, and wherein the on-site storage unit is separate from said oil storage tanks and comprises at least one tank within the cylindrical section.

11. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a semi-submersible structure comprising a buoyant platform provided with ballasted tanks for oil or liquefied natural gas located below the waterline, the semi-submersible structure being tied to the seabed, and wherein said ballasted tanks are separate from said on-site storage unit.

12. The apparatus according to claim 2, wherein at least one of the first offshore facility and the second offshore facility comprises a tension leg platform in which a buoyant platform is located by mooring tethers in tension to ensure its vertical position relative to the seabed; and wherein said on-site storage unit comprises at least one tank within said buoyant platform.

13. An offshore oil or natural gas production facility provided with: at least one on-site storage unit, selected from subsea tanks or internal tanks within a hull or other floating structure of the offshore oil or natural gas facility, adapted to store carbon dioxide (CO.sub.2) in a liquid or a super-critical state; marine transfer equipment configured to transfer CO.sub.2 in said state to and from said at least one on-site storage unit; injection equipment configured to inject CO.sub.2 into a sub-sea oil field for enhanced recovery of oil or into a sub-sea natural gas field for enhanced recovery of natural gas; recovery equipment configured to recover oil and/or natural gas from a resulting production stream; first plant and equipment which has the capability to process CO.sub.2-laden hydrocarbon production streams, separate CO.sub.2 from production fluids, and to process and apply the necessary pressure and temperature regulation to the separated CO.sub.2 so that it reaches said state; and second plant and equipment coupled to the first plant and equipment, to the at least one on-site storage unit, and to the injection equipment to store the separated CO.sub.2 in said state at least one on-site storage unit or to transfer CO.sub.2 to the injection equipment for injection into the sub-sea oil field or the sub-sea natural gas field.

14. A method for producing oil and/or natural gas at an offshore facility, comprising the steps of: separating carbon dioxide (CO.sub.2) at said offshore facility from a production stream at said facility, and storing said CO.sub.2 in a liquid or supercritical state in at least one onsite storage unit selected from subsea tanks and internal tanks within a hull or other floating structure of the offshore facility, utilizing CO.sub.2 from the at least one storage unit for enhanced oil recovery or enhanced gas recovery at said offshore facility by injecting the CO.sub.2 into a sub-sea oil or natural gas bearing reservoir and recovering oil and/or natural gas from a resulting production stream, transferring CO.sub.2 in said state to a carrier vessel using marine transfer equipment provided at the offshore facility, and delivering the transferred CO.sub.2 in said state to a second offshore facility using the carrier vessel for use in enhancing offshore oil recovery using CO.sub.2 at the second offshore facility or for enhancing offshore gas recovery using CO.sub.2 at the second offshore facility.

15. An offshore oil or natural gas production facility provided with: at least one on-site storage unit, selected from subsea tanks and internal tanks within a hull or other floating structure of the offshore oil or natural gas facility, adapted to store CO.sub.2 in a liquid or supercritical state; injection equipment configured to inject carbon dioxide (CO.sub.2) into a sub-sea oil field for enhanced recovery of oil or into a sub-sea natural gas field for enhanced recovery of natural gas; marine transfer equipment configured to transfer CO.sub.2 in said state from said at least one on-site storage unit to a carrier vessel; recovery equipment configured to recover oil and/or natural gas from a hydrocarbon production stream; first plant and equipment which has the capability to process CO.sub.2-laden hydrocarbon production streams, to separate CO.sub.2 from production fluids, and to process and apply the pressure and temperature regulation to separated CO.sub.2 so that it reaches said state; and second plant and equipment coupled to the first plant and equipment and to the at least one on-site storage unit to store separated CO.sub.2 in said state in said at least one on-site storage unit.

16. A method for producing oil and/or natural gas at an offshore facility, comprising the steps of: separating carbon dioxide (CO.sub.2) at said offshore facility from a production stream at said facility, and storing said CO.sub.2 in a liquid or supercritical state in at least one onsite storage unit selected from subsea tanks and internal tanks within a hull or other floating structure of the offshore facility, and utilizing CO.sub.2 from the at least one storage unit for enhanced oil recovery or enhanced gas recovery at said offshore facility by injecting the CO.sub.2 into a sub-sea oil or natural gas bearing reservoir and recovering oil and/or natural gas from a resulting production stream.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Reference will now be made to the description of various embodiments by way of example only with reference to the accompanying drawings, in which:

(2) FIG. 1 is a schematic view of a plurality of onshore CO2 producers, a representative integrated offshore facility, and a plurality of carrier vessels;

(3) FIG. 2 is a schematic flow diagram for a system employing the teachings of the present disclosure;

(4) FIG. 3 illustrates how different forms of offshore facility may be classified; and

(5) FIGS. 4, 5 are schematic views of additional embodiments of offshore facilities and carrier vessels.

DETAILED DESCRIPTION

(6) An integrated offshore facility is schematically illustrated at 1 in FIG. 1. Distances are shown fore-shortened for ease of illustration. In practice, offshore oil and natural gas facilities are commonly located many miles from the shoreline 2, especially in the North Sea. The illustrated offshore facility is of the MOPU (Mobile Offshore Production Unit) type, linked by risers 3 to a plurality of sub-sea wellheads 4, but may take any of the conventional forms for offshore oil or natural gas facilities as explained in more detail below. In the embodiment of FIG. 1, the floating unit illustrated comprises a floating natural gas structure or marine vessel 6 that includes a hull 6H and a deck 6D, where the marine vessel 6 incorporates at least one, and preferably a plurality of, storage tanks 5 for storing CO2 in the liquid or super-critical state within the hull 6H of the floating unit. One 7a out of a fleet of carrier vessels 7 is shown unloading liquid or super-critical CO2 from that vessel to the storage tanks 5 employing equipment 8 for marine transfer of CO2 in the liquid or super-critical state located on the floating unit.

(7) A plurality of onshore CO.sub.2 producers 9, which may, for example, comprise power stations or large industrial complexes, are associated with CO.sub.2 loading jetties 10 along the shoreline. The producers 9 may be so associated by pipelines 11 for gaseous, liquid or super-critical CO.sub.2 and/or by other means of transport such as road or rail tankers operating along rail or road networks between the producers 9 and the jetties 10 to transport CO.sub.2 from the producer sites 9 to the jetties 10.

(8) A fleet of CO.sub.2 carrier vessels 7, enable simultaneous loading (shown by carrier 7b at jetty 10a), transport from jetty to offshore facility (shown by carrier 7c) and off-loading (shown by carrier 7a) at the offshore facility, so that a sufficient supply of CO.sub.2 in liquid or super-critical state is always available at the offshore facility 1. We envisage that, in practice, there would be a large fleet of carrier vessels 7 serving a number of offshore facilities 1. At or adjacent the jetties 10, storage tanks 12 are suitably provided, and these may be associated with a plant for converting gaseous CO.sub.2 delivered to the jetty facility into liquid or super-critical form before it is loaded into the carrier vessels.

(9) The offshore facility 1 is provide with equipment 13 for injecting CO.sub.2 into a sub-sea oil field for EOR, into a sub-sea natural gas field for EGR, or into a condensate field (being a field intermediate between an oil field and a natural gas field, in which an appreciable amount of liquid is effectively present in vapour or fine droplet form within gas) for EOR and/or EGR.

(10) Equipment 8 for marine transfer of CO.sub.2 will be generally similar to equipment for marine transfer of oil or of liquefied natural gas, and no further details should be required for a person with skills in these fields to select, purchase or fabricate suitable such equipment. Similarly, EOR and EGR are known techniques, and persons with skills in these fields will be familiar with the kinds of equipment 13 required for injecting CO.sub.2 into a sub-sea oil field, into a sub-sea natural gas field, or into a sub-sea condensate field. Similarly, equipment for the separation of CO.sub.2 from hydrocarbon production streams, and for subsequent CO.sub.2 treatment are also known per se. Accordingly, no detailed description of plant and equipment to separate and process CO.sub.2, or to raise the pressure and regulate the temperature of the CO.sub.2 to match the required injection conditions, or of the associated technologies such as compressors, pumps, coolers, or control systems, is deemed necessary.

(11) The offshore facility may comprise one of many different structures, as explained above, and as classified in FIG. 3. In accordance with the teachings of this disclosure, the offshore facility may comprise a mobile offshore production unit 102 such as a steel gravity based structure (GBS) with steel tanks on the sea-bed 104, a Jack-Up structure 106 such as a conventional jack-up 108 or a jack-up with steel tanks on the sea-bed 110, a Spar 112, a semi-submersible structure 114 comprising a base and a tank positioned in the base capable of storage of liquid or super-critical CO.sub.2, a tension leg platform (TLP) 116, a floating liquefied natural gas (FLNG) structure 118, a floating production storage and offloading (FPSO) structure 120, and a floating storage and offloading (FSO) structure 122. In some embodiments, the offshore facility comprises a fixed installation 130 such as a concrete GBS 132 provided with equipment capable of marine transfer of CO.sub.2 and with storage tanks suitable for storing liquid or super-critical CO.sub.2, and a steel jacket GBS structure 134. In some embodiments, the concrete GBS 132 is located in a fixed position by the ballasted weight of the concrete GBS 132 resting on the seabed. A separate floating storage vessel is suitably provided at the offshore facility when it is a Conventional Jack-Up, TLP, or Steel Jacket.

(12) In some embodiments, a barge type production platform is provided in jack-up structure 106 with legs and towed to a selected position is jacked up on the said legs directly from the seabed or from an optional ballasted steel tank located on the seabed, and the said storage tanks adapted to store CO2 in said state are provided in one of the barge and the optional ballasted tank. In some embodiments, the spar 112 is tethered to the seabed and comprises a vertically oriented cylindrical section located below the waterline and a floating platform supported by the cylindrical section, and comprises topsides including oil production facilities, oil storage tanks being located within the vertical cylindrical section for periodic unloading to an oil tanker. In certain embodiments, the semi-submersible structure 114 comprises a buoyant platform provided with ballasted tanks for oil or liquefied natural gas located below the waterline, the semi-submersible structure 114 being tied to the seabed. In certain embodiments, a buoyant platform is located in the TLP 116 by mooring tethers in tension to ensure its vertical position relative to the seabed. In certain embodiments, the steel jacket GBS structure 134 comprises a structure 134 in which topsides are supported by a combined tank and steel jacket which is located on the seabed by virtue of ballasted tanks capable of being emptied to allow the structure to be floated for relocation.

(13) Referring briefly to FIG. 4, an embodiment of an offshore facility 140 and a carrier vessel 7 are shown. In the embodiment of FIG. 4, offshore facility 140 comprises a GBS 142, such as a concrete GBS or a steel GBS having a steel jacket. GBS 142 of offshore facility 140 includes a ballasted tank 144 and an on-site subsea storage tank 146 each located at a seabed 150. Subsea storage tanks 146 of offshore facility store CO2 in the liquid or super-critical state at the seabed 150. A carrier vessel 7 may unload liquid or super-critical CO2 to subsea storage tanks 146 via equipment 8 for marine transfer of CO2.

(14) A separate vessel, not unlike that shown at 1 in FIG. 1, but tethered alongside a pre-existing oil or natural gas facility (including previously de-commissioned such facilities) is particularly suitable when that facility is one not originally designed to use CO.sub.2-based EOR or CO.sub.2-based EGR technology, and in particular such a facility with limited reserves and/or low production rates, and/or which is operating near to the end of its field life. For example, referring briefly to FIG. 5, an offshore facility 160 is shown that includes a production vessel or facility 162 and a separate storage and/or offloading vessel 180. In the embodiment of FIG. 5, production vessel 162 comprises a hull 164 and a deck 166 upon which plant and equipment 14 for processing CO.sub.2 and equipment 13 for injecting CO.sub.2 are positioned. In some embodiments, the plant and equipment 14 achieve the requisite CO2 pressure and temperature for storage in said at least one on-site storage means or for injection into the sub-sea oil field or the sub-sea natural gas field. The separate storage vessel 180 comprises a hull 182 and storage tanks 184 positioned within hull 182 for storing liquid or super-critical CO.sub.2. A carrier vessel 7 may unload liquid or super-critical CO.sub.2 to storage tanks 184 via equipment 8 for marine transfer of CO.sub.2. In other embodiments, by providing the separate vessel with equipment 8 for marine transfer of CO.sub.2 as well as storage tanks for liquid or super-critical CO.sub.2, with plant and equipment for processing CO.sub.2-laden production streams, separation and treatment of separated CO.sub.2, conversion of gaseous CO.sub.2 to conditions required in readiness for injection, and with equipment 13 required for injecting CO.sub.2 into a sub-sea oil field for EOR or into a sub-sea natural gas field for EGR, this avoids the need to provide such equipment 8 and/or equipment 13 on the original offshore facility. When such new plant and equipment is provided on a separate vessel, it will have acid gas capability which may not have been included in the specifications of the original offshore facility.

(15) In the case of EOR or EGR in an existing oil or natural gas field, following an initial stage in which the sub-sea oil or natural gas field will be charged with CO.sub.2, CO.sub.2 will emerge entrained in the oil or natural gas produced from the field. Whether provided on the facility itself or on the separate vessel discussed above and tethered alongside the original facility, plant and equipment 14 should also be provided which has the capability to process CO.sub.2-laden production streams, separate CO.sub.2 from the production fluids, and process and apply the necessary pressure and temperature regulation to separated CO.sub.2 so that it reaches the liquid or super-critical state, and can be reinjected into the sub-sea oil or natural gas field together with such quantity of fresh liquid or super-critical CO.sub.2 supplied from the carrier vessels and stored in tanks on the facility itself or on the separate vessel, if present, needed to make up the quantity of CO.sub.2 required at any time. Equally well, CO.sub.2 separated from production streams by appropriate plant and equipment of the kind employed in existing hydrocarbon production facilities utilising CO.sub.2-based EOR or EGR may be employed to separate and process CO.sub.2 from the production stream and pass it to the on-site CO.sub.2 storage tanks for injection at a later time. Such plant and equipment should be familiar to persons skilled in this field. Accordingly, no further detailed description of the separators, compressors, pumps, control systems, etc., employed in such plant and equipment is deemed necessary.

(16) The United Kingdom and Norwegian sectors of the North Sea would particularly benefit from the technologies disclosed herein. These areas have a number of mature fields whose yield of oil and natural gas is declining, but which have relative proximity to European countries with power-intensive economies (many CO.sub.2 sources) and numerous sea ports that can serve as CO.sub.2 loading points. It will readily be appreciated that the methods herein described and the apparatus herein described, have the incidental benefit that, in operation, significant quantities of CO.sub.2 is sequestrated in the sub-sea reservoir.

(17) The storage required at offshore facilities when the teachings of the present disclosure are applied is illustrated by the calculation below, by way of example.

(18) As explained above, it has been estimated by Kemp et al that of the order of 0.4 tonnes of CO.sub.2 per incremental additional barrel of produced oil is required for EOR.

(19) Reference may also be made to “A New Equation of State for Carbon Dioxide Covering the Fluid Region from the Triple-Point Temperature to 1100° K at Pressures up to 800 MPa”, Span et al, J. Phys. Chem. Vol 25, No: 6, 1996, for a discussion of the states of CO.sub.2.

(20) In the light of Kemp's estimate, for an incremental oil rate of 30000 barrels per day, it would be necessary to inject 12000 tonnes/day of CO.sub.2. Liquid CO.sub.2 typically has a temperature of −53° C., a pressure of 7.5 bars absolute, and a density of 1166 kg/m.sup.3. Super-critical CO.sub.2 typically has a temperature of 37° C., a pressure of 80 bars absolute, and a density of 328 kg/m.sup.3. It can readily be seen from this that the daily quantity of CO.sub.2 required would occupy 10292 m.sup.3 in the liquid state and 36585 m.sup.3 in the super-critical state.

(21) Given the significant differences in density and required pressure between CO.sub.2 in the liquid and super-critical states, storage in the liquid rather than the super-critical state has the advantage that the storage vessels or tanks would not need to be so large or to be pressurised to so high an extent. Moreover, compliance with Health & Safety requirements would likely be less challenging. However, optimisation of design of the offshore facility with respect to cost, footprint, operability and availability may make it advantageous to store at least some of the CO.sub.2 in the super-critical state for at least part of the time. Accordingly, the “at least one on-site storage tank or vessel adapted to store CO.sub.2 in the liquid or super-critical state” required by the present disclosure may encompass a variety of different possibilities, including: one or more tanks and/or vessels for storing liquid CO.sub.2; one or more tanks and/or vessels for storing CO.sub.2 in the super-critical state; and one or more tanks and/or vessels for storing liquid CO.sub.2 as well as one or more tanks and/or vessels for storing CO.sub.2 in the super-critical state.

(22) Long-term, a portion of the injected CO.sub.2 will be made up of gas that was previously injected (‘recycled’ CO.sub.2). This ‘recycled’ CO.sub.2 will be entrained with the oil or natural gas produced, and, when separated, will be in the gaseous state. As well as treatment, it will require compression in preparation for pumping and reinjection.

(23) Continuing with the aforesaid example, and considering two scenarios where 50% and 75% of the injected CO.sub.2 is sourced from the production streams: The quantity of CO.sub.2 that would have to be separated, treated and compressed would be 6000 tonnes/day of CO.sub.2 and 9000 tonnes/day of CO.sub.2, respectively. In volumetric terms, in the gaseous state, these equate to 3.21 million standard cubic metres/day and 4.81 million standard cubic metres/day.

(24) The plant capability required to handle the ‘recycled’ CO.sub.2 stream is therefore notable. Unless the oil or natural gas facility was designed originally with a view to employing CO.sub.2-based EOR or EGR, the plant and equipment required for acid gas handling, and the separation, treatment, compression and pumping of such quantities of gaseous CO.sub.2 may best be provided on a separate vessel designed for the purpose.

(25) Reference will now be made to FIG. 2 to explain how the teachings of the present disclosure may be integrated within the functions of the overall oil/gas asset.

(26) CO.sub.2 is produced on-shore in step 15, and converted in step 16 to liquid or super-critical CO.sub.2 either on-shore or on a carrier vessel. Carrier vessels are loaded with CO.sub.2 in step 17. CO.sub.2 is transported by sea in step 18, and the vessel is coupled to an integrated offshore facility in step 19 for unloading of CO.sub.2 in step 20. The empty carrier vessel is de-coupled in step 21, and returns to the same or another port in step 22 to be recharged with CO.sub.2. Liquid or super-critical CO.sub.2 is stored in step 23 in tanks integrated into the facility proper, or in tanks integrated into a separate vessel alongside and forming with the facility proper an integrated facility. Liquid or super-critical CO.sub.2 is pumped from store in step 24, and its temperature and pressure regulated in step 25 before being injected in step 26 into injection wells. Production wells 27 pass fluids to produced fluids reception at 28, and thence to oil/gas/water/CO.sub.2 separation and processing plant 29. Produced/recycled CO.sub.2 passes from plant 29 to a further processing step 30 and thence to production of liquid or super-critical CO.sub.2 in step 31 to pass to store 23 or alternatively direct to the pumping step 24 for reinjection. A produced natural gas stream from plant 29 passes via further processing and/or compression step 32 for direct export or liquefaction and on-site storage in step 33 or to a natural gas-based secondary recovery and/or EOR step 34 from which some or all of the gas is passed back to the production wells 27 to issue again in the produced fluids or is injected into the injection wells 26. A produced oil/condensate stream from the plant 29 passes to a further oil and condensate processing step 35 and thence to direct export or on-site storage in step 36. A produced water stream from plant 29 passes to a further water processing step 37 and thence either to disposal in step 38 or to a water-based secondary recovery and/or EOR/EGR step 39 for injection into the injection wells 26.

(27) It should be understood by persons skilled in this field, without further explanation or detailed description, that in implementing the teachings of the present disclosure in practical offshore facilities, the following may be expected to be present:

(28) Plant and equipment for the reception, separation and processing of produced fluids.

(29) Oil, condensate and natural gas storage and or export plant and equipment.

(30) In specific cases, equipment for the liquefaction, storage and unloading of natural gas.

(31) Machinery such as pumps, compressors and power-gen equipment.

(32) Control systems.

(33) Safety systems.

(34) Offloading equipment.

(35) Accommodation.

(36) One of the most attractive applications of CO.sub.2-based EOR/EGR is to aging assets and those in production decline. Therefore, while the teachings of this disclosure are applicable both to new/planned and existing offshore production facilities, their application to existing ones is worthy of particular consideration.

(37) Persons skilled in this art will readily appreciate that the adoption of methods and apparatus employing the teachings of this disclosure will avoid many of the pre-existing problems preventing widespread use of EOR and EGR techniques offshore.

(38) There is no need to build a pipeline connecting an appropriately located onshore CO.sub.2 source with offshore facilities using such CO.sub.2 in CO.sub.2-based EOR/EGR.

(39) There is no need to match the quantity and variability of CO.sub.2 production of the CO.sub.2 ‘producer’ with the operational needs of the CO.sub.2 ‘user’ (offshore facility). For example, the production of CO.sub.2 by a power station may vary due to grid demand (daily, seasonal), whereas an oil production facility tends to run at a constant rate.

(40) The further complication that the amount of CO.sub.2 which the oil/gas operator may need to inject will likely vary through time—particularly during the formative stages of the application of CO.sub.2-based EOR/EGR is also avoided. This variability arises because, at the beginning of the process, the reservoir will need to be ‘charged’ with CO.sub.2. During this time the CO.sub.2 being injected will be exclusively ‘supplied’ CO.sub.2 from the onshore CO.sub.2 producer. Later, previously injected CO.sub.2 will be entrained in the hydrocarbons produced. At least a proportion of this entrained CO.sub.2 may be separated, treated and re-injected. Consequently, as the proportions of ‘supplied’ and ‘recycled’ CO.sub.2 in the injected CO.sub.2 stream change, the amount of ‘supplied’ CO.sub.2 required will also change. Accurate forecasting of the time when CO.sub.2-laden hydrocarbon streams reach the producing wells (and the extent to which this will reduce the quantity of ‘supplied’ CO.sub.2 required) is not possible. Consequently, heretofore the setting up of future CO.sub.2 purchase contracts would have been difficult.

(41) With such variability in the amount of ‘supplied’ CO.sub.2 required by the oil/gas asset through time in addition to potential daily/seasonal changes in the supplier's rate of CO.sub.2 production, setting up equitable contracts between CO.sub.2 suppliers and oil/gas facility operators would have been difficult. Heretofore, damping out differences between the production rates of specific CO.sub.2 suppliers and the CO.sub.2 quantities required by specific oil/gas facility operators could only have been achieved by creating an expansive CO.sub.2 pipeline grid connecting numerous CO.sub.2 producers with numerous CO.sub.2 consumers. However, to establish an expansive CO.sub.2 pipeline network would require a substantial capital expenditure. This would be both expensive and time-consuming. Furthermore, such high capital expenditure would be unlikely to prove economic in mature hydrocarbon basins like the North Sea where the remaining operating life of the offshore facilities, even with EGR/EOR, is likely to prove relatively limited.

(42) The teachings of the present disclosure transform EGR/EOR, previously considered only a theoretical possibility for mature offshore hydrocarbon basins, into a realistically deployable technology with both economic potential for oil/gas recovery and the ability simultaneously to sequester significant quantities of onshore generated CO.sub.2.

(43) Although the present teachings are particularly useful in utilising onshore generated CO.sub.2, as described above, the same techniques can be employed for utilising excess CO.sub.2 present in the production stream from an offshore oil or natural gas facility, which would otherwise be discharged to atmosphere or have to be piped elsewhere. CO.sub.2 may be present in the production stream either because EOR/EGR was previously employed at that facility or because the related subsea reservoir contains CO.sub.2 as well as useful quantities of oil or natural gas. The offshore facility in question may not be suited to EOR/EGR and so have no use for CO.sub.2 entrained in its production stream. Alternatively, its production stream may have more entrained CO.sub.2 than needed for EOR/EGR at that facility. In either such case, this second offshore facility serves as a CO.sub.2 storage facility storing CO.sub.2 in liquid or super-critical form, which can serve as a CO.sub.2 source in a fashion similar to the previously described onshore sites. This CO.sub.2 stored in the liquid or super-critical state may then be unloaded periodically to one or more carrier vessels for delivery to a separate integrated offshore facility such as that illustrated at 1 in FIG. 1 at which the CO.sub.2 is utilised for EOR or EGR in exactly the same manner as described above.