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 offshore CO.sub.2-based EOR or for offshore CO.sub.2-based EGR, in which method: CO.sub.2 in a state selected from the liquid and super-critical states is delivered by at least one carrier vessel from at least one CO.sub.2 storage site to an integrated offshore facility provided with at least one on-site storage means, selected from tanks and vessels, adapted to store CO.sub.2 in said state and with equipment for marine transfer of CO.sub.2 in said state; and CO.sub.2 is utilised as required from said at least one on-site storage means 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.

2. A method according to claim 1, wherein said at least one storage means includes a separate floating storage and offloading vessel without oil or natural gas production facilities provided at said integrated offshore facility, the said separate vessel being provided with said at least one storage tank adapted to store CO.sub.2 in said state.

3. A method according to claim 2, wherein the said separate vessel comprises both 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 CO.sub.2 so that it reaches the said state, and with plant and equipment to achieve the requisite CO.sub.2 pressure and temperature for injection into the a sub-sea oil field or a sub-sea natural gas field; whereby the said separate vessel may be supplied for CO.sub.2-based EOR or for CO.sub.2-based EGR at an offshore site not otherwise equipped for CO.sub.2-based EOR or for CO.sub.2-based EGR, and is adapted to be towed away from said site when no longer required thereat for use at a fresh offshore site.

4. A method according to claim 1, wherein the integrated offshore facility further comprises equipment for separating CO.sub.2 from the production stream for direct re-injection or for storage in the at least one on-site storage means.

5. A method according to claim 1, wherein the at least one CO.sub.2 storage site comprises a second integrated offshore facility provided with at least one on-site storage means selected from tanks or vessels adapted to store CO.sub.2 in said state and with equipment for marine transfer of CO.sub.2 in said state; the second integrated offshore facility having an oil/gas production stream including spare entrained CO.sub.2 selected from CO.sub.2 not required for use at the second integrated offshore facility and CO.sub.2 in excess of requirements for use at the second integrated offshore facility.

6. A method according to claim 1, wherein the at least one CO.sub.2 storage site is at least one onshore site to which CO.sub.2 is delivered by at least one of pipeline, road and rail from at least one facility in which CO.sub.2 is produced as a waste product; and wherein the CO.sub.2 is liquefied or rendered supercritical at one of the said facility and the onshore site.

7. Apparatus for offshore CO.sub.2-based EOR or for offshore CO.sub.2-based EGR comprising: an integrated offshore facility provided with: at least one on-site storage means, selected from tanks and vessels, adapted to store CO.sub.2 in a state selected from liquid and super-critical states, and equipment for marine transfer of CO.sub.2 in said state, equipment for injecting CO.sub.2 into a sub-sea oil field for EOR or into a sub-sea natural gas field for EGR; and equipment for recovering 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 integrated offshore facility, preferably an onshore site, to the said integrated offshore facility.

8. Apparatus according to claim 7, wherein the integrated offshore facility comprises one of a concrete gravity-based structure located in fixed position by the ballasted weight of the structure resting on the seabed, and a steel gravity based structure in which the 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; and the said on-site storage tanks adapted to store CO.sub.2 in the liquid or super-critical state are separate from any ballasted tanks and provided in the ballasted structure or mounted on the seabed.

9. Apparatus according to claim 7, wherein the integrated offshore facility comprises a floating structure comprising one of (a) a floating production storage and offloading structure in which a marine vessel has a hull and a deck, the hull being one of a ship-like shape and 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, (b) a floating natural gas 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 natual gas tanker, (c) 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, oil storage tanks being located within the vertical cylindrical section for periodic unloading to an oil tanker, (d) 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 (e) 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 the said storage tanks adapted to store CO.sub.2 in said state are provided in the floating structure.

10. Apparatus according to claim 7, wherein the integrated offshore facility comprises a jack-up structure in which a barge type production platform provided 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 CO.sub.2 in said state are provided in one of the barge and the optional ballasted tank.

11. Apparatus according to claim 7, wherein the integrated offshore facility is provided with a separate floating storage and offloading vessel without oil or natural gas production facilities, the vessel being provided with the said storage tanks adapted to store CO.sub.2 in said state.

12. Apparatus according to claim 11, wherein the separate vessel comprises both with 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 CO.sub.2 so that it reaches said state; and with plant and equipment to achieve the requisite CO.sub.2 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.

13. Apparatus according to claim 7, wherein the integrated offshore facility additionally comprises both 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 CO.sub.2 so that it reaches said state; and with plant and equipment to achieve the requisite CO.sub.2 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.

14. An integrated offshore oil or natural gas facility comprising: at least one on-site storage means, selected from tanks and vessels, adapted to store CO.sub.2 in a state selected from liquid and super-critical states, and equipment for marine transfer of CO.sub.2 in said state, equipment for injecting CO.sub.2 into a sub-sea oil field for EOR or into a sub-sea natural gas field for EGR; and equipment for recovering oil and/or natural gas from a resulting production stream.

15. An integrated offshore oil or natural gas facility according to claim 14, additionally comprising both with 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 CO.sub.2 so that it reaches said state; and with plant and equipment to achieve the requisite CO.sub.2 pressure and temperature for storage in said at least one on-site storage means or for injection into a sub-sea oil field or a sub-sea natural gas field.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0045] Reference will now be made to the description of various embodiments by way of example only with reference to the accompanying drawings, in which:—

[0046] FIG. 1 is a schematic view of a plurality of onshore CO2 producers, a representative integrated offshore facility, and a plurality of carrier vessels;

[0047] FIG. 2 is a schematic flow diagram for a system employing the teachings of the present disclosure; and

[0048] FIG. 3 illustrates how different forms of offshore facility may be classified.

DETAILED DESCRIPTION

[0049] 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. The floating unit illustrated incorporates at least one, and preferably a plurality of, storage tanks 5 for storing CO.sub.2 in the liquid or super-critical state within hull 6 of the floating unit. One 7a out of a fleet of carrier vessels 7 is shown unloading liquid or super-critical CO.sub.2 from that vessel to the storage tanks 5 employing equipment 8 for marine transfer of CO.sub.2 in the liquid or super-critical state located on the floating unit.

[0050] 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.

[0051] 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.

[0052] 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.

[0053] 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.

[0054] 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, steel GBSs (Gravity Based Structures) with steel tanks on the sea-bed, Jack-Ups with steel tanks on the sea-bed, Spars, FLNG (Floating Liquefied Natural Gas) structures, FPSO (Floating Production Storage and Offloading) structures, FSO (Floating Storage and Offloading) structures, and Concrete GBSs may be 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. Similarly, semi-submersibles may be provided with tanks in their base capable of storage of liquid or super-critical CO.sub.2. A separate floating storage vessel is suitably provided at the offshore facility when it is a Conventional Jack-Up, TLP (Tension Leg Platform), or Steel Jacket.

[0055] 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. 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.

[0056] 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.

[0057] 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.

[0058] 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.

[0059] 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.

[0060] 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.

[0061] 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.

[0062] 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.

[0063] 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.

[0064] 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.

[0065] 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.

[0066] 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.

[0067] 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.

[0068] 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: [0069] Plant and equipment for the reception, separation and processing of produced fluids. [0070] Oil, condensate and natural gas storage and or export plant and equipment. [0071] In specific cases, equipment for the liquefaction, storage and unloading of natural gas. [0072] Machinery such as pumps, compressors and power-gen equipment. [0073] Control systems. [0074] Safety systems. [0075] Offloading equipment. [0076] Accommodation.

[0077] 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.

[0078] 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.

[0079] 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.

[0080] 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.

[0081] 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.

[0082] 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.

[0083] 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.

[0084] 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.