Method and system for CO2 enhanced oil recovery

Abstract

Methods of Enhanced Oil Recovery (EOR) from an oil reservoir by CO.sub.2 flooding are disclosed. One method comprises producing a well stream from the reservoir; separating the well stream into a liquid phase and a gas phase with a first gas/liquid separator, wherein the gas phase comprises both CO.sub.2 gas and hydrocarbon gas; cooling the gas phase with a first cooler; compressing the gas phase using a first compressor into a compressed stream; mixing the compressed stream with an external source of CO.sub.2 to form an injection stream; and injecting the injection stream into the reservoir. Systems for EOR from an oil reservoir by CO.sub.2 flooding are also disclosed.

Claims

1. A method of Enhanced Oil Recovery (EOR) from an oil reservoir by CO.sub.2 flooding, comprising: producing a well stream from the oil reservoir; separating the well stream into a liquid phase and a first gas phase with a first gas/liquid separator, wherein the first gas phase comprises both CO.sub.2 and hydrocarbon gas; reducing a pressure of the liquid phase to release a second gas phase comprising both CO.sub.2 and hydrocarbon gas from the liquid phase, thereby lowering a content of CO.sub.2 in the liquid phase; separating the second gas phase from the liquid phase with a second gas/liquid separator; combining the first gas phase and the second gas phase into a combined gas phase; cooling the combined gas phase with a first cooler; compressing the combined gas phase into an injection stream with a first compressor; and injecting the injection stream into the oil reservoir.

2. The method as claimed in claim 1, wherein the first gas phase and the second gas phase comprise water vapour.

3. The method as claimed in claim 1, where the first cooler is an active cooler; or wherein the first compressor is a liquid tolerant compressor.

4. The method as claimed in claim 2, further comprising mixing an external source of CO.sub.2 into the injection stream prior to the injecting the injection stream into the oil reservoir.

5. The method as claimed in claim 4, wherein the external source of CO.sub.2 comprises liquid CO.sub.2.

6. The method as claimed in claim 5, wherein the injection stream into which the external source of CO.sub.2 is mixed comprises a gas phase, and wherein the mixing the external source of CO.sub.2 into the injection stream causes the gas phase of the injection stream to at least partially condense or dissolve in the liquid CO.sub.2.

7. The method as claimed in claim 4, wherein the method further comprises cooling the injection stream with a second cooler, by active cooling, either before or after the external source of CO.sub.2 is mixed into the injection stream; wherein this cooling step condenses at least part of a gas phase in the injection stream.

8. The method as claimed in claim 1, wherein the well stream is choked to a pre-defined pressure prior to the separating the well stream into the liquid phase and the first gas phase.

9. The method as claimed in claim 1, wherein prior to the separating the well stream into the liquid phase and the first gas phase, the well stream is heated, via a heat exchanger.

10. The method as claimed in claim 1, wherein the oil reservoir is an offshore reservoir.

11. The method as claimed in claim 10, wherein the method is carried out subsea; or wherein the separating the well stream into the liquid phase and the first gas phase are carried out subsea, and subsequent steps are carried out above the sea, on a platform or a floater; or wherein at least the following steps are carried out above the sea, on the platform or the floater: the separating the well stream into the liquid phase and the first gas phase with the first gas/liquid separator; the reducing the pressure of the liquid phase to release the second gas phase; the separating the second gas phase from the liquid phase with the second gas/liquid separator; the combining the first gas phase and the second gas phase into the combined gas phase; the cooling the combined gas phase with the first cooler; and the compressing the combined gas phase into the injection stream with the first compressor.

12. The method as claimed in claim 1, wherein the liquid phase is transported to an oil processing facility through carbon steel piping; wherein a film forming corrosion inhibitor is injected into the liquid phase.

13. The method as claimed in claim 1, wherein the second gas phase is cooled by a third cooler and then compressed prior to being combined with the first gas phase; optionally wherein the second gas phase is compressed by one compressor or two compressors arranged in series.

14. The method as claimed in claim 13, wherein after compressing the second gas phase, part of the compressed second gas phase forms an anti-surge flow which is directed into the second gas phase downstream of the second gas/liquid separator and upstream of the third cooler.

15. The method as claimed in claim 1, wherein a pressure of the second gas phase is increased by an ejector prior to being combined with the first gas phase separated by the first gas/liquid separator; wherein the ejector is powered by motive gas flow from downstream of the first compressor.

16. An enhanced oil recovery system, comprising: a producer arranged to produce a well stream from a reservoir; a first gas/liquid separator arranged to separate the well stream into a liquid phase and a first gas phase comprising CO.sub.2 and hydrocarbon gas; a choke arranged to reduce a pressure of the liquid phase so as to release a second gas phase comprising CO.sub.2 and hydrocarbon gas from the liquid phase, thereby lowering a content of CO.sub.2 in the liquid phase; a second gas/liquid separator arranged to separate the second gas phase from the liquid phase; piping or a mixer arranged to combine or mix the first gas phase and the second gas phase into a combined gas phase; a first cooler arranged to cool the combined gas phase; a first compressor arranged to compress the combined gas phase into an injection stream; and injection piping arranged to inject the injection stream into the reservoir.

17. The enhanced oil recovery system as claimed in claim 16, wherein the first cooler is an active cooler or wherein the first compressor is a liquid tolerant compressor.

18. The enhanced oil recovery system as claimed in claim 16, further comprising an external source of CO.sub.2 and a mixer arranged to mix CO.sub.2 from the external source of CO.sub.2 with the injection stream, wherein the external source of CO.sub.2 comprises liquid CO.sub.2.

19. The enhanced oil recovery system as claimed in claim 18, further comprising a second cooler arranged upstream of the mixer to cool the injection stream prior to mixing with the CO.sub.2, or downstream of the mixer to cool the injection stream after mixing with the CO.sub.2; wherein the second cooler is an active cooler.

20. The enhanced oil recovery system as claimed in claim 16, further comprising a second choke arranged to choke the well stream upstream of the first gas/liquid separator.

21. The enhanced oil recovery system as claimed in claim 16, further comprising carbon steel piping arranged to transport the liquid phase to an oil processing facility.

22. The enhanced oil recovery system as claimed in claim 16, further comprising a third cooler arranged downstream of the second gas/liquid separator to cool the second gas phase, and a compressor arranged downstream of the third cooler to compress the second gas phase.

23. The enhanced oil recovery system as claimed in claim 16, further comprising an ejector arranged to increase a pressure of the second gas phase, wherein the ejector is powered by motive gas flow from downstream of the first compressor.

Description

(1) Preferred embodiments of the present invention will now be described by way of example only and with reference to the accompanying drawings, in which:

(2) FIGS. 1a and 1b are generalised diagrams each illustrating an EOR system and method according to an embodiment of the invention wherein the entire process is carried out subsea;

(3) FIGS. 2a and 2b are generalised diagrams each illustrating an EOR system and method according to an embodiment of the invention wherein part of the process is carried out topside;

(4) FIG. 3 is a process diagram illustrating an EOR system and method according to an embodiment of the invention in which corrosion-resistant piping is required;

(5) FIG. 4 is a process diagram illustrating an EOR system and method according to an embodiment of the invention in which a secondary separation process is carried out; and

(6) FIG. 5 is a process diagram of an alternative embodiment of an EOR system and method in which a secondary separation process is carried out.

(7) It will be noted that the described embodiments relate to offshore CO.sub.2 EOR processes, however the skilled person will appreciate that the embodiments may equally be employed in onshore fields.

(8) FIG. 1a illustrates an EOR system 1 of an embodiment of the invention wherein the entire process is carried out subsea. A well stream 4 is produced from an oil reservoir 2 by the production tubing 3 and passed out via well head 5. At point 6 it is determined whether CO.sub.2 breakthrough has occurred yet. If it has not, then the well stream, numbered 4a, is directed to an existing top-side oil processing facility 7. Reference numeral 10 indicates sea level and numeral 22 indicates the sea floor. In this case, since there is no back-produced CO.sub.2, imported CO.sub.2 12 from an external source (preferably liquid CO.sub.2) forms stream 13 which is injected into the reservoir 2 via injection piping 15, to provide EOR. This may be considered as a first phase of operation.

(9) If CO.sub.2 breakthrough has occurred, i.e. CO.sub.2 gas is now being back-produced, then the well stream, numbered 4b, is directed to subsea process unit 8. This may be considered as a second phase of operation. Embodiments of this process unit will be described later with reference to FIGS. 3 to 5. In this process unit 8 a gas phase 11 comprising CO.sub.2, and hydrocarbon gas and small amounts of dissolved water is separated from a liquid phase 9 comprising oil and water. The oil/water stream 9 is provided to the oil processing facility 7. The gas phase 11 exits the process unit 8 and is mixed with imported CO.sub.2 12 (preferably liquid CO.sub.2) from an external source, to form an injection stream 13. Further process steps are carried out on this stream (not shown) and then it is provided via injection well-head 14 to injection piping/injector 15, which injects the injection stream 13 into the reservoir 2. Whilst the mixing of the gas phase 11 with the imported CO.sub.2 12 into injection stream 13 is shown outside subsea process unit 8, this may in fact typically be part of subsea process unit 8. FIG. 1b illustrates the system of FIG. 1a, but wherein these steps are incorporated into a complete subsea process unit 8′, incorporating also those processes of unit 8.

(10) FIG. 2a illustrates an EOR system 20 of an embodiment in which part of the main process is carried out topside on a separate installation (platform or floater). Essentially, in this embodiment, the entire subsea process unit 8 of FIG. 1 is instead located above sea level 10, i.e. topside, and forms topside process unit 19. The other parts and processes of the system 20 are the same as those of FIG. 1, and so will not be described again here. As with FIG. 1a, whilst the mixing of the gas phase 11 with the imported CO.sub.2 12 into injection stream 13 is shown subsea, outside topside process unit 19, it may in fact be part of process unit 19. Thus, this part of the process may also be carried out topside.

(11) FIG. 2b is a modified version of the embodiment of FIG. 2a, wherein some processing steps are carried out subsea, and some carried out topside. As with FIGS. 1 and 2a, in this EOR system 30, a well stream 4 is produced from an oil reservoir 2 by the production piping 3 and passed out via well head 5. At point 6 it is determined whether CO.sub.2 breakthrough has occurred yet. If it has not, then the well stream, numbered 4a, is directed to a top-side oil processing facility. In this case, since there is no back-produced CO.sub.2, imported CO.sub.2 12 only from an external source forms stream 13 which is injected into the reservoir 2 via injection piping 15, to provide EOR.

(12) If CO.sub.2 breakthrough has occurred, i.e. CO.sub.2 gas is now being back-produced, then the well stream, numbered 4b, is directed to gas/liquid separator 16, which separates the well stream 4b into a liquid phase 9 comprising oil and water and a gas phase 18 comprising CO.sub.2 and hydrocarbon gas and dissolved water.

(13) The liquid phase 9 is directed to the oil processing facility 17. The gas phase 18 is supplied to a topside process unit 19 above the surface, for example on a platform or a floater. This topside process unit 19 carries out various further process steps, resulting in a gas phase 11 comprising CO.sub.2 and hydrocarbon gas which is mixed with imported CO.sub.2 12 from an external source, to form injection stream 13. Further process steps are carried out on this stream 13 (not shown) and it is then provided via injection well-head 14 to injection piping/injector 15, which injects the stream 13 into the reservoir 2.

(14) As with FIG. 1a, whilst the mixing of the gas phase 11 with the imported CO.sub.2 12 into injection stream 13 is shown subsea, outside topside process unit 19, it may in fact be part of process unit 19. Thus, this part of the process may also be carried out topside.

(15) Optionally, in the embodiment of FIG. 2b, the topside process unit 19 may carry out a further gas/liquid separation step on the gas phase 18 that it receives. In this case, the separated liquid phase 21 exits the topside process unit 19, mixes with the liquid phase 9 from the gas/liquid separator 16, and is input to the oil processing facility 7.

(16) FIG. 3 illustrates an EOR system 40 of an embodiment in which corrosion-resistant piping and equipment is required for the liquid phase downstream the separator 16. This embodiment is based on the general system configuration of FIG. 1b, wherein the entire process is carried out subsea. Parts common to both Figures are given the same reference numbers. The components within the dotted line box numbered 8′ in FIG. 3 form the subsea process unit 8′ of FIG. 1b. The entire system may be known as an “EOR process facility”.

(17) In the system of FIG. 3, a well stream 4 is produced from an oil reservoir 2 by production piping 3. It will be determined from an analysis of the well stream 4 whether CO.sub.2 breakthrough has occurred yet, as described in relation to FIG. 1, though this is not illustrated in FIG. 3 for simplicity. If it has not, then the well stream, is directed to a top-side oil processing facility (again, not shown in this Figure), which may be considered as a first phase of operation. In this case, since there is no back-produced CO.sub.2, imported CO.sub.2 12 from an external source forms stream 13′ which is injected into the reservoir 2 via injector 15, to provide EOR. This may be considered as a second phase of operation.

(18) If, as is likely, the pressure of the external CO.sub.2 source is not sufficient for direct injection into the reservoir, a booster pump 36 is provided to increase the pressure prior to injection. The booster pump 36 delivers sufficient pressure to inject the CO.sub.2 into the reservoir. The pressure required will depend on the pressure in the reservoir at the injection point, the necessary excess pressure to drive the CO.sub.2 into the reservoir, the static pressure increase from the injection template to the injection point, and the frictional pressure drop in the injection pipe.

(19) FIG. 3 also illustrates a subsea cooler 34 through which the stream 13 passes; however it is not necessary to cool the stream 13 if it comprises only external CO.sub.2 12, so in this situation the cooler 34 will be inactive. Since the cooler 34 is not required for external CO.sub.2 12 only, in an alternative configuration the external CO.sub.2 12 could be supplied downstream the cooler 34.

(20) Once CO.sub.2 breakthrough has occurred, i.e. CO.sub.2 gas is now being back-produced, then the well stream 4 is directed to various process equipment which together form a “subsea process unit” 8. The point at which the well stream 4 should be directed to the subsea process unit 8 may be determined based on the composition of the well stream. For example, a certain gas composition, particularly a certain CO.sub.2/methane ratio may be expected once CO.sub.2 breakthrough has occurred. In this initial phase after CO.sub.2 breakthrough, the methane content in the gas will be high and the CO.sub.2 content low. Also, the total gas flow will be low, compared with later life.

(21) First, the well stream 4 is choked by choke 25 to a pre-defined pressure, and is then directed to gas/liquid separator 16. The selection of the pressure level provided by the choke 25 will decide the partial pressure/content of CO.sub.2 in the gas-phase and the CO.sub.2 content in the liquid phase produced by the gas/liquid separator 16. A lower pressure will reduce the CO.sub.2 content in the liquid. The separation pressure will also influence the compressor requirements (compressor 30, discussed later) and the power required for the gas to be injected, and will decide if the liquid phase 9 sent to the oil processing facility needs to be pressure boosted or not. If pressure boosting is required, a pump will be provided for liquid phase 9 (not shown in FIG. 3).

(22) Moreover, the separation pressure will determine whether carbon steel can be used in the piping downstream the separator 16 (i.e. the piping connecting with the oil processing facility) or whether corrosion resistant materials are required. The higher the pressure, the more CO.sub.2 there will be in the liquid phase 9. Due to the corrosive effect of CO.sub.2, if the CO.sub.2 in the liquid phase 9 is too high, some pipeline materials such as carbon steel will suffer from corrosion to an unacceptable extent. Thus, at higher pressures, the larger amounts of CO.sub.2 in the liquid phase 9 requires the downstream piping to be manufactured from corrosion resistant material, such as stainless steel. In the embodiment of FIG. 3, the CO.sub.2 content in the liquid phase 9 is high enough that the downstream piping must be made of corrosion resistant materials. Whilst this may be disadvantageous, the higher pressure means that no additional pumping is required for the liquid phase 9 (though in other embodiments a pressure boost may be required as discussed above).

(23) However, in another embodiment, the separation pressure could be lowered to a level where corrosion resistant materials are not necessary, and thus the downstream piping could be made of carbon steel. A pump would then be required to increase the pressure of the liquid phase 9 after leaving the separator. Such embodiments are described later with reference to FIGS. 4 and 5.

(24) Corrosion-resistant materials will always be required in the EOR process facility (i.e. the whole system of FIGS. 3, 4 and 5 except for the piping for liquid phase 9 in FIGS. 4 and 5) due to the separated gas phase comprising dissolved water, unless the gas phase is dehydrated.

(25) Continuing the discussion of FIG. 3, the gas phase 26 separated by the separator 16 comprises both CO.sub.2 and hydrocarbon gas and dissolved water. This is, if necessary, cooled in a subsea cooler 27. Preferably, this is an active cooler, here shown with pump circulation by a sea-water pump 18, so that the temperature can be adequately controlled to avoid hydrate formation and optimise the gas temperature prior to later mixing with external CO.sub.2. The cooled gas 29 is input to compressor 30 which increases the pressure thereof, forming cooled, compressed gas 11. Preferably, the compressor 30 is a liquid tolerant compressor since liquid may form after the cooler 27. If the compressor is not liquid tolerant, an additional gas/liquid separator may be required upstream the compressor to separate any liquid that has formed during cooling (not shown in the Figure). An additional liquid pump may also then be needed to bring the liquid phase back to the main gas/liquid separator 16 or directly to the liquid phase 9 being directed to the oil processing facility.

(26) In FIG. 3, one-stage compression is shown utilising a single compressor 30. However compression in more than one stage (i.e. by more than one compressor in series) is also possible and may be used if the required pressure is higher than can be achieved by one compressor. However, for simplicity, a design such as that illustrated requiring only one compressor 30 is preferable (this is also less expensive).

(27) The well stream gas flow rate after CO.sub.2 breakthrough will be highly dynamic (mainly increasing) especially in the first period of operation, before a more stable situation is reached. To give an example, if the operational time for the CO.sub.2 EOR facility is 10 years after CO2 breakthrough, the largest dynamics would happen in the first 1 to 2 years. To handle this dynamic situation, a compressor recycle is provided. As can be seen, a recycle flow 32 from downstream the compressor 30 is directed into the well stream 4 upstream the gas liquid separator 16. This provides more stable conditions for the separator operation, as it allows the separator to operate within narrower gas and liquid load ranges during the lifetime of the oil reservoir 2, which simplifies the operation and control of the separator. Alternatively, the compressor recycle flow 32 can be mixed into the gas 26 downstream the gas/liquid separator 16.

(28) To protect the compressor against surge, an anti-surge line 31 is also provided. Gas from downstream the compressor 30 is directed into the separated gas 26 upstream from the cooler 27. Alternatively, gas from downstream the compressor 30 may be mixed with the well stream 4 upstream the gas/liquid separator 16. It will be appreciated that in one embodiment, a combined compressor recycle and anti-surge line may be provided.

(29) Downstream the compressor 30, the gas phase 11 is mixed at mixer 33 with CO.sub.2 12 from an external supply. The pressure of the external CO.sub.2 and the compressed gas phase 11 needs to be balanced. In a first phase after CO.sub.2 breakthrough, the gas flow 11 from the compressor will be low and contain high concentrations of methane. This gas needs to be condensed prior to injection into the reservoir 2. However, a very high pressure from the compressor would be required for condensation by sea-water alone, and there would be a high risk of hydrate formation. However, by mixing the gas 11 with the external CO.sub.2 12, the gas 11 will condense/dissolve in the external CO.sub.2 during the mixing process or in subsequent cooling by cooler 34. Thus, the compression requirement is lower.

(30) The process temperatures are controlled by both sea-water coolers 34, 27 to avoid hydrate formation. It is desirable to reach a lower temperature after the mixing and cooling, to increase the density of the fluid, preferably liquid, leaving the cooler 34, but at the same time stay above the hydrate formation temperature. Therefore, the cooler 34 is preferably an active cooler, with sea water circulation by a sea water pump 35. In an alternative embodiment, the gas 11 is cooled prior to (rather than after) being mixed with the external CO.sub.2 12.

(31) The pressure of the fluid leaving the cooler 34 is increased by booster pump 36, then the resulting fluid 13′ comprising a high proportion of CO.sub.2 is injected into the reservoir 2 via injection well head 14 and injection piping 15, yielding enhanced oil recovery. Typically, the proportion of CO2 in the injection fluid 13′ will be between 85-95 mole % of the total fluid (though this will be case specific). The CO.sub.2 is ultimately back-produced via production tubing 3 and recycled through the process again.

(32) After some time, the gas flow rate from the reservoir 2 will stabilise and contain more and more CO.sub.2, up to 80-90 mole % or more. When the gas flow rate increases, the required amount of external CO.sub.2 12 reduces.

(33) Whilst in the embodiment of FIG. 3 the entire process is carried out subsea (as in the general configuration of FIG. 1b), the mixing of external CO.sub.2 and the processes downstream of this could be carried out subsea whilst the remainder of the method is carried out topside on a platform or floater, e.g. as in FIG. 2a. Or, the external CO.sub.2 could also be taken topside for mixing, cooling and pumping. Or, the gas/liquid separation could be carried out subsea, the mixing with external CO.sub.2 and the downstream processes carried out subsea, and the remainder of the method carried out topside (as in FIG. 2b).

(34) Example process data for an implementation of the embodiment of FIG. 3 will now be given: Temperature of well stream 4 prior to being choked: 90° C. Pressure of well stream 4 prior to being choked: 60 bara (600 kPa) Pressure of well stream after being choked: 30 bara (300 kPa) Temperature of gas phase 29 exiting the first cooler 27: 20-40° C. Pressure of gas phase 11 exiting the compressor 30: 85 bara (8500 kPa) Temperature of external CO.sub.2 12: 9° C. Pressure of external CO.sub.2 12: 85 bara (8500 kPa) Temperature of injection stream 13′ exiting cooler 34: 15-30° C. Temperature of injection stream 13′ entering injection piping 15: 15-35° C. Pressure of injection stream 13′ entering injection piping 15: 120-160 bara (12000-16000 kPa) Pressure in reservoir 2 at injection point: 320-360 bara (32000-36000 kPa) Depth of oil reservoir 2: 2600 m

(35) It will be appreciated that these values are approximate, and are for one particular example only.

(36) FIG. 4 illustrates an embodiment of an EOR system 50 in which a secondary separation process is carried out. Much of this system 50 is the same as that of FIG. 3, and will not be described again here. Parts common to both Figures are given the same reference numbers. The difference between the embodiments of FIGS. 3 and 4 is that in FIG. 4, there is a secondary gas/liquid separation process. In other words, the gas/liquid separation is carried out in multiple stages, in this embodiment two stages, but in other embodiments the system may be extended to more than two stages.

(37) Gas/liquid separator 16, as in FIG. 3, separates the well stream 4 into gas phase 26 comprising both CO.sub.2 and hydrocarbon gas, and a liquid phase. However, the liquid phase is not then directed directly to an oil processing facility as stream 9. Instead, the liquid phase 41 from the gas/liquid separator 16 is choked down to a lower pressure by choke 42 which results in the formation of more gas. The reduced pressure gas/liquid flow 43 is input to a further gas/liquid separator 44, which separates the gas phase 47. The partial pressure of CO.sub.2 in the gas phase results in CO.sub.2 content in the liquid phase 45 being low enough to allow for a carbon steel pipeline to the oil processing facility and in the oil processing facility itself. In other words, since there is less CO.sub.2 in the liquid 45, the liquid is less corrosive, so corrosion-resistant piping is not required and carbon steel can instead be used. Due to the reduced pressure of the liquid 45, an export pump 46 is provided to pump the liquid, as liquid 9, to the oil processing facility.

(38) The liquid phase 45 will still be corrosive to some extent though, as some CO.sub.2 will still be dissolved in it, so a corrosion control method such as the injection of a film forming corrosion inhibitor may be used to limit the corrosion rate of the pipeline and process equipment.

(39) The gas stream 47 is, if required, cooled by cooler 48, here shown as an active cooler with sea-water circulation by sea water pump 49. However in other embodiments a passive cooler may be used. The pressure is likely to be low enough that hydrates are not an issue, so active cooling may be less essential.

(40) The flow rate of the gas stream 47 from the gas/liquid separator 44 is substantially lower than that of the gas stream 26 from the gas/liquid separator 16. To bring the latter up to the same or similar flow rate/pressure as the former, more than one compressor is required if the required pressure ratio for the compression is too high for one compressor. Thus, the cooled gas stream 51 from the cooler 48 is compressed by compressor 52 to form compressed stream 53, followed by compressor 54 to form further compressed stream 55. If the total pressure ratio is low enough, intermediate cooling between the compressors is not needed, but may be required for higher pressure ratios. The compressors are preferably both liquid tolerant compressors, or at least the compressor 52 should be a liquid tolerant compressor. Optionally, dry gas compressors may be used, and if so then upstream separators/scrubbers will be needed.

(41) The compressors 52 and 53 are smaller than compressor 30, and the power requirement is typically less than 10% of that of the compressor 30. The operational conditions of compressors 52 and 53 will likely be constant enough to avoid the need for compressor recycle, but if not a compressor recycle system similar to shown in FIG. 3 could be introduced

(42) To protect the compressors 52 and 53 against surge, and anti-surge line 56 is provided. Gas from downstream compressor 53 is directed into the separated gas 47 upstream from the cooler 48. Alternatively, gas from downstream the compressor 53 may be mixed with the liquid phase 43 upstream the gas/liquid separator 44.

(43) In other embodiments, more than two compressors may be necessary.

(44) The compressed gas 55 is mixed into separated gas stream 26, to form combined gas stream 56. This is then processed in the same way as in gas stream 26 in FIG. 3, and ultimately injected into the reservoir 2.

(45) FIG. 5 illustrates an alternative embodiment of an EOR system in which a secondary separating process is carried out. Much of this system is the same as that of FIG. 4, and will not be described again here. Parts common to both Figures are given the same reference numbers. The difference between the embodiments of FIGS. 4 and 5 is that in FIG. 5, the compressors 52 and 53 are replaced with an ejector 48.

(46) In this embodiment, the gas stream 47 is directed to ejector 48. Ejector 48 is powered by motive gas flow 49 from downstream the compressor 30. The ejector utilises this high pressure gas flow 49 to increase the pressure of stream 47. This significantly simplifies the system, and may also remove the need for any intermediate cooler. Since the ejector motive gas flow 49 is taken from downstream the compressor 30, this will be ultimately be recycled through the compressor 30, in addition to the compressor recycle flow 32. Thus, more gas might be recycled through the compressor 30 in the embodiment of FIG. 5 than in the embodiment of FIG. 4. This could potentially increase the compressor power requirement.

(47) In some embodiments, more than one ejector may be used.

(48) Whilst in the embodiments of FIGS. 4 and 5 the entire process is carried out subsea (as in the general configuration of FIG. 1), the subsea process unit 8 could instead be located topside on a platform or a floater (as in FIG. 2a) or onshore, instead of subsea. Or, either or both of the gas/liquid separations could be carried out subsea but the other process steps carried out topside (as in FIG. 2b). Moreover, whilst in the embodiments shown the reservoir 2 is an offshore reservoir, the process is equally applicable to onshore reservoirs.