WO2021225448A1

WO2021225448A1 - Capturing and storing co2 generated by offshore hydrocarbon production facilities

Info

Publication number: WO2021225448A1
Application number: PCT/NO2021/050109
Authority: WO
Inventors: Bengt Olav Neeraas; Jostein Pettersen; Gelein MAINZA DE KOEIJER; Efstathios SKOURAS-ILIOPOULOS
Original assignee: Equinor Energy As
Priority date: 2020-05-04
Filing date: 2021-04-30
Publication date: 2021-11-11
Also published as: GB202006527D0; GB2595635A

Abstract

A method of capturing C0₂ produced by an offshore hydrocarbon production facility (1) comprises generating electrical power and/or heat for use by the hydrocarbon production facility (1) at an offshore location, producing an exhaust gas containing C0₂. At the offshore location, CO₂ is separated from at least a portion of the exhaust gas to form a CO₂ stream, and the pressure of the CO₂ stream is increased to form a pressurised stream. The pressurised stream is mixed with an injection water stream to form a carbonated water stream, and the carbonated water stream is injected into a reservoir. This method makes it possible to utilise existing water injection systems present at a production facility (1) to inject CO₂ into a reservoir concurrently with injected water, in the form of carbonated water.

Description

CAPTURING AND STORING C0₂ GENERATED BY OFFSHORE HYDROCARBON PRODUCTION FACILITIES

The present invention relates to a method and system for reducing C0₂ emissions from offshore hydrocarbon production. In particular, it relates to capturing and storing CO₂ emitted during power production on offshore hydrocarbon production facilities, i.e. offshore oil and gas production facilities.

Natural gas (for example, associated gas) is often utilised as a readily available fuel source for producing power and heat on offshore production facilities. However, combustion of the natural gas produces CO₂, which is a major source of CO₂ emissions from offshore oil and gas production facilities.

In order to reduce these emissions, it has been proposed to electrify processes or to utilise fuels that do not emit CO₂ when burnt; however, this can often be technically and economically challenging.

Another proposed solution is to capture the CO₂ emitted from the power production and to store or sequester the CO₂ in subsurface formations. However, there are difficulties in practically implementing such a method. For example, in order to store the CO₂ in subsurface formations it is often necessary to provide a dedicated CO₂ injection system and well, which can be complex and expensive.

In a first aspect, the present invention provides a method of capturing CO₂ produced by an offshore hydrocarbon production facility, the method comprising: generating electrical power and/or heat for use by the hydrocarbon production facility at an offshore location, wherein generating the power and/or heat produces an exhaust gas containing C0₂; and at the offshore location: separating CO₂ from at least a portion of the exhaust gas to form a CO₂ stream; increasing the pressure of the CO₂ stream to form a pressurised stream; mixing the pressurised stream with an injection water stream to form a carbonated water stream; and injecting the carbonated water stream into a reservoir.

This method makes it possible to use existing production facility infrastructure to sequester CO₂ emissions in a reservoir. Rather than requiring dedicated CO₂ injection system and well, the method utilises the water injection system already present in the production facility to inject the CO₂ into the reservoir concurrently with the injected water, in the form of carbonated water. Accordingly, this technique provides a technically simple and economically viable method of sequestering CO2 emissions from hydrocarbon production facilities, thereby reducing their CO2 emissions.

The reservoir may be a hydrocarbon reservoir. Injecting the carbonated stream into a hydrocarbon reservoir may advantageously support reservoir pressure and stimulate hydrocarbon production, i.e. to support formation pressure. However, the invention may be used when produced water is injected to avoid disposal to sea, which may require additional treatment.

Natural gas may be used as a fuel source for generating the electrical power and/or heat. The produced fluids from hydrocarbon reservoirs typically contain natural gas (e.g. in the form of associated gas), and this natural gas is commonly separated from the heavier hydrocarbons in hydrocarbon processing facilities. Hence, natural gas can be a readily available source of fuel in and around hydrocarbon processing facilities. Accordingly, the natural gas may be produced natural gas, i.e. natural gas produced from a reservoir. The reservoir from which the natural gas is produced is preferably the same reservoir into which the carbonated water is being, or is to be, injected.

Whilst using natural gas is preferable, other fuels may be used for generating the electrical power and/or heat. For instance, petrol or diesel may be used.

The injection water stream may be provided at an injection pressure. Used herein, the injection pressure is defined as the pressure that is necessary to inject the carbonated water stream into the reservoir. The injection pressure will depend on, for example, the pressure in the reservoir at the injection point, the necessary excess pressure to drive the water into the reservoir, any hydrostatic pressure difference caused by a difference in height between the point at which the water is pressurised (e.g. at a topside facility) to the injection point (e.g. on the sea bed), and the frictional pressure drop in the injection pipe used to inject the water into the reservoir. The injection pressure may be 100 to 400 bar (10 to 40 MPa), for instance 100 to 200 bar (10 to 20 MPa), or 300 to 400 bar (30 to 40 MPa).

Alternatively, the injection water stream may be provided at an intermediate pressure lower than the injection pressure. The intermediate pressure may be 20 to 50 bar (0.2 to 0.5 MPa), preferably 30 to 50 bar (0.3 to 0.5 MPa).

Increasing the pressure of the CO2 stream may comprise increasing the pressure of the CO2 stream to the injection pressure. That is to say, the pressurised CO2 stream may have a pressure of 100 to 400 bar (10 to 40 MPa) for instance 100 to 200 bar (10 to 20 MPa), or 300 to 400 bar (30 to 40 MPa). The pressurised stream may be mixed with the injection water stream at the injection pressure, thereby forming a carbonated water stream at the injection pressure.

Alternatively, the pressure of the CO2 stream may be increased to the intermediate pressure. That is to say, the pressurised stream may have a pressure of 20 to 50 bar (0.2 to 0.5 MPa), preferably 30 to 50 bar (0.3 to 0.5 MPa). The pressurised stream may be mixed with the injection water stream at the intermediate pressure to form a carbonated water stream at the intermediate pressure. Increasing the pressure of the CO2 stream to the intermediate pressure may require less energy compared to increasing the pressure of the CO2 stream to the injection pressure.

The intermediate pressure may not be sufficient to inject the carbonated water stream into the reservoir. Hence, the method may further comprise increasing the pressure of the carbonated water to the injection pressure. This may be done, for instance, using one or more pumps.

The method may comprise removing O2 from the CO2 stream and/or the pressurised stream. The presence of O2 in the CO2 stream and/or pressurised stream can have a corrosive effect on the materials used to pressurise, mix and inject the fluid into the reservoir. The presence of O2 may also lead to bacterial growth, which can produce hydrogen sulphide that, if injected into a hydrocarbon reservoir, can lead to undesirable souring of the hydrocarbons present in the reservoir. Hence, it is preferable to reduce or remove any O2 contained in the CO2 stream and/or pressurised stream to limit or prevent O2 from being injected into the reservoir with the carbonated water. Any suitable O2 removal technology may be used, such as catalytic oxidation.

An amine scrubber or a membrane separator may be used to separate the CO2 from the exhaust gas.

The step of increasing the pressure of the CO2 stream may use one or more compressors to increase the pressure of the CO2 stream. Preferably, the compressor is a liquid tolerant compressor. In addition, or alternatively, the pressurisation step may use one or more pumps to increase the pressure of the CO2 stream.

The step of increasing the pressure of the CO2 stream may comprise multiple, i.e. more than one, pressurisation stages. For example, the step of increasing the pressure of the CO2 stream may include two, three, four or more pressurisation stages. Each pressurisation stage may have a pressure ratio (i.e. outlet pressure divided by inlet pressure) of 2 to 4.

One or more of the pressurisation stage(s) may comprise a compressor to increase the pressure of the CO2 stream. The compressor may preferably be a liquid tolerant compressor. CO2 behaves as a “dense fluid” or a “supercritical fluid” at pressures above its critical pressure (73.8 bar, 7.38 MPa) and temperatures above its critical temperature (31.0 °C), and becomes a highly compressible fluid that demonstrates properties of both liquid and gas phases. Accordingly, one or more of the pressurisation stages may include a pump to increase the pressure of the CO2 stream by pumping. It may be desirable to use a pump to pump the supercritical CO2 since pumping requires less power than compression. It is, however, preferable to use only compressor(s), if possible, in order to minimise complexity.

It may be desirable to increase the pressure of the CO2 stream in more than one stage if the total required pressure ratio is higher than can be achieved by one pressurisation stage, e.g. by one compressor. However, it is possible to increase the pressure of the CO2 stream using only one pressurisation stage. It is preferable to use only one pressurisation stage, if possible, in order to minimise cost and complexity.

The method may comprise removing impurities, such as sulphur or water, from the pressurised CO2 stream.

The method may comprise cooling the pressurised CO2 stream prior to mixing with the injection water stream. Where the pressure of the CO2 stream is increased in multiple pressurisation stages, the partially pressurised CO2 stream may be cooled after one or more stage. Cooling the CO2 stream may cause impurities in the CO2 stream, such as water and/or sulphur, to condense out of the CO2 stream.

The method may comprise removing the condensed impurities from the CO2 stream. The impurities may be removed using a scrubber or separator.

The step of removing O2 from the CO2 stream may cause the pressure of the CO2 stream to decrease. This pressure drop may be proportional to the pressure of the CO2 stream. It may be desirable to minimise this decrease in pressure in order to improve efficiency of the pressurisation step. The pressure of the CO2 stream will be different after each pressurisation stage, thereby providing a range of pressures at which the O2 may be removed. Hence, the O2 removal step may be carried out after one or more of the pressurisation stages, as desired, to minimise any decrease in pressure resulting from the O₂ removal step.

The optimal pressure for removing O₂ from the CO₂ stream may depend on the pressure of the CO₂ stream. For instance, it may be possible to extract a higher fraction of the O₂ from the CO₂ stream at a one pressure compared to another pressure. Hence, it may be beneficial to choose the pressure at which the O₂ removal step occurs in order to optimise the O₂ removal capacity.

Moreover, the equipment used to remove the O₂ from the CO₂ stream may have to be tailored to withstand the high operational pressures. For instance, walls of the equipment may need to be made thicker or from stronger and/or heavier materials in order to withstand higher pressures. This may lead to large and cumbersome equipment. Accordingly it may be desirable to perform the O₂ removal step after one of the earlier pressurisation stages, where the pressure of the CO₂ is lower.

The method may comprise forming the injection water stream by pumping water to the injection pressure or the intermediate pressure. One or more pumps may be used to pump the water. Where multiple pumps are used, they may be arranged in parallel. This provides redundancy in case one or more of the pumps fail.

The injection water stream may comprise sea water and/or produced water. Using produced water in the injection stream makes it possible to efficiently dispose of the produced water in an environmentally friendly manner. Produced water may otherwise be disposed into the sea, which may require additional treatment of the produced water. Preferably the produced water is water produced from the reservoir, i.e. a portion of water produced from the reservoir is reinjected into the reservoir as part of the carbonated water. The produced water and/or the sea water may be cleaned to remove any impurities, such as oxygen and undissolved particulate matter.

The solubility of CO₂ in water increases as the salt content in the water decreases. The salinity of the injection water may ultimately be determined by the salinity and/or quantities of sea water and/or produced water that are available for use in the method. However, it may be possible to minimise the salt content of the injection water stream in order to maximise the quantity of CO₂ that can be dissolved in the injection water stream and subsequently be sequestered in the reservoir as carbonated water. This may be achieved by controlling the composition of the injection water, for example by controlling the relative quantities of sea water and produced water present in the injection water stream.

Hence, the method may comprise varying the quantities of sea water and produced water in the injection water stream to provide an injection water stream having a desired salinity. This may be achieved by varying the quantities of sea water and produced water passed to the pump(s) during formation of the injection water stream.

The rate at which exhaust gas is generated by the hydrocarbon production plant may vary over time. Rather than providing capacity to cope with peak exhaust gas generation rate, a system may be provided that is optimised to receive and treat the exhaust gas at an average exhaust gas generation rate. The term “average exhaust gas generation rate” is used herein to mean the rate at which exhaust gas is produced, averaged over a specified time period (e.g. a week, a month or a year). This value may differ between hydrocarbon production facilities. The method may be made more efficient by optimising the CO₂ removal step to the average exhaust gas generation rate.

The rate at which the exhaust gas is generated may, in some cases, be too great for all of the CO₂ to be removed during the CO₂ removal step. For instance, if the rate is too high, it could overwhelm the CO₂ removal process, which may lead to inefficiencies. This may be because (as noted above) the CO₂ removal process has been optimised for an average exhaust gas removal rate, whereas the actual rate of exhaust gas generation exceeds the average rate. Accordingly, a portion of the exhaust gas may be vented before CO₂ separation has occurred. That is to say, only a portion (though typically a major portion) of the generated exhaust gas may be passed to the CO₂ removal process, and surplus or excess exhaust gas may be removed prior to the separation step.

Alternatively, all of the generated exhaust gas may be passed to the CO₂ removal process.

The electrical power and/or heat may be generated by a heat engine, such as a gas turbine or an internal combustion engine.

The mixing step may comprise passing the pressurised CO₂ stream and the injection water stream through a mixing unit. Any suitable mixing unit may be used, such as a static mixer, or an ejector. The ejector may be a multistage ejector.

Mixing the streams using an ejector may also cause the pressure of the pressurised CO₂ stream to increase. Therefore, the pressurised CO₂ stream may be provided to the ejector at the intermediate pressure. The ejector may be used as an alternative to one or more stages of CO₂ pressurisation. The ejector may advantageously be powered by the injection water stream.

The method may comprise injecting one or more additional streams of water into the reservoir. The additional stream(s) of water may be derived, i.e. extracted, from the injection water stream before the injection water stream is mixed with the pressurised CO₂ stream. That is to say, only a portion of the injection water stream may be mixed with the pressurised CO₂ to form the carbonated water stream. In this way, both carbonated water and non-carbonated water can be injected into the reservoir. Injecting too high a quantity of carbonated water into the reservoir, or into unfavourable formations or areas in the reservoir, may lead to carbonated water being back-produced from the reservoir. Injecting a quantity of non-carbonated water into the reservoir can reduce the likelihood of this occurring.

The non-carbonated water may be injected into a different area of the reservoir compared to the carbonated water, for example using a different injection well.

It is possible that the carbonated water stream may include some undissolved gasses, such as nitrogen and undissolved CO₂. The presence of gaseous CO₂ in the carbonated water can be undesirable since it can be difficult to trap gaseous CO₂ in the reservoir. Hence, the method may comprise separating any undissolved gas, such as CO₂, from the carbonated water, prior to injection. This separation step may use a separator to separate gases (e.g. gas phase CO₂) from the carbonated water stream.

The power and/or heat generation step, separation step, step of increasing the pressure of the CO₂ stream, O₂ removal step, mixing step, the step of separating any undissolved gas from the carbonated water and/or pumping step(s) may all be performed on a topside installation, for example a platform or a floater. Preferably, the installation is associated with the oil and gas production facility.

That is to say, the installation may have a primary purpose of housing components of the oil and gas production facility.

The invention also extends to a CO₂ capture system for capturing CO₂ from an exhaust gas. Therefore, in a second aspect, the invention provides a CO₂ capture system for capturing CO₂ from an exhaust gas, the system comprising: a CO₂ capture unit configured to receive exhaust gas and to separate CO₂ from the exhaust gas to form a CO₂ stream; a pressurisation unit arranged to increase the pressure of the C02 stream to form a pressurised CO2 stream; and a mixing unit arranged to mix the pressurised stream with an injection water stream to form a carbonated water stream.

The CO2 capture system may be suitable for use and/or used in the method of the first aspect, and may include any one or more or all of the optional features discussed above.

This system makes it possible to extract CO2 from an exhaust gas produced by a hydrocarbon production facility. The system can also be used to treat the extracted CO2 so that it can be mixed with a water stream for injection into a reservoir.

The CO2 capture unit may comprise an amine scrubber or a membrane separator.

The CO2 capture unit may comprise multiple CO2 capture units arranged in parallel. This provides the system with a level of redundancy and flexibility should one or more of the CO2 capture units fail. This also allows for the number of operational CO2 capture units to be tailored to demand, i.e. depending on the quantity of exhaust gas being passed to the CO2 sequestering system. This can lead to greater energy efficiency.

The pressurisation unit may comprise a compressor, preferably a liquid tolerant compressor. In addition, or as an alternative, the pressurisation unit may comprise a pump.

The pressurisation unit may comprise multiple, i.e. more than one, pressurisation stages. For example, the pressurisation unit may include two, three, four or more pressurisation stages. Each pressurisation stage may be configured to receive CO2 at an inlet pressure and output CO2 at an outlet pressure. Each pressurisation stage may have a pressure ratio (i.e. outlet pressure divided by inlet pressure) of 2 to 4. That is to say, each pressurisation stage may be arranged to increase the pressure of the CO2 stream to a pressure 2 to 4 times the received pressure.

One or more of the pressurisation stage(s) may each comprise a compressor to increase the pressure of the CO2 stream. The compressor may preferably be a liquid tolerant compressor. Increasing the pressure of the CO2 above its critical pressure (73.8 bar, 7.38 MPa) may cause the CO2 to become a “dense fluid” or a “supercritical fluid”. In this state, the CO2 to exhibits properties of both the liquid and gas phases. Therefore, one or more of the pressurisation stages may include a pump to increase the pressure of the CO2 stream (e.g. a supercritical CO2 stream) by pumping. This can reduce energy consumption since pumping requires less power than compression. It is however preferable to use only compressor(s), if possible, in order to minimise complexity.

Whilst multiple pressurisation stages may be needed if the total required pressure ratio is higher than can be achieved by one pressurisation stage, e.g. by one compressor, the pressurisation unit may comprise only one pressurisation stage. It is preferable to use only one pressurisation stage, if possible, in order to minimise cost and complexity

The pressurisation unit may be arranged to increase the pressure of a stream of CO2 to an injection pressure. This may be a pressure suitable for injecting a water stream into a subsea reservoir, and will depend on, for example, the pressure in the reservoir at the injection point, the necessary excess pressure to drive the water into the reservoir, any hydrostatic pressure difference caused by a difference in height between the point at which the water is pressurised (e.g. at a topside facility) to the injection point (e.g. on the sea bed), and the frictional pressure drop in the injection pipe used to inject the water into the reservoir. The injection pressure may be 100 to 400 bar (10 to 40 MPa), for instance 100 to 200 bar (10 to 20 MPa) or 300 to 400 bar (30 to 40 MPa). Alternatively, the pressurisation unit may be arranged to increase the pressure of a stream of CO2 to an intermediate pressure, lower than the injection pressure. The intermediate pressure may be too low to inject a stream of water in a subsea reservoir. The intermediate pressure may be 20 to 50 bar (0.2 to 0.5 MPa), preferably 30 to 50 bar (0.3 to 0.5 MPa).

The system may comprise an O2 removal unit for removing O2 from a CO2 stream. The O2 removal unit may be arranged downstream of the pressurisation unit so as to receive a pressurised stream of CO2 output from the pressurisation unit.

The O2 removal unit may comprise a catalytic oxidiser.

The O2 removal unit may be arranged between successive pressurisation stages of the pressurisation unit. In this way, the O2 removal unit may be arranged to receive a CO2 stream at a desired pressure, which may be below the output pressure of the pressurisation unit.

Using the O2 removal unit to remove C>2from a CO2 stream may lead to a drop in pressure of the CO2 stream. This pressure drop may be proportional to the pressure of the CO₂ stream. It may be desirable to minimise this drop in pressure in order to improve efficiency of the CO₂ capture system. The pressure of the CO₂ stream will be different after each pressurisation stage, thereby providing a range of pressures at which the O₂ may be removed. Hence, the O₂ removal unit may be arranged after one or more of the pressurisation stages, as desired, to minimise any drop in pressure caused by the O₂ removal unit.

Moreover, the O₂ removal unit may have to be tailored to withstand high operational pressures. For instance, walls of the O₂ removal unit may need to be made thicker or from stronger and/or heavier materials in order to withstand higher pressures. This may lead to large and cumbersome equipment. Accordingly it may be desirable to arrange the O₂ removal unit such that it receives CO₂ at a low pressure.

The O₂ removal unit may be arranged in a branch line extending from a main flow path in the CO₂ capture system. The branch line may include a controllable valve arranged to control flow of gas through the branch line and the O₂ removal unit. The branch line may be arranged to pass gas back to the main flow path once it has passed through the O₂ removal unit.

One or more of the pressurisation stages may comprise a cooler arranged downstream of the compressor and/or pump. The cooler may be arranged to receive and cool the CO₂ output from the compressor and/or pump.

One or more of the pressurisation stages may comprise a separator arranged downstream of the cooler. The separator may be arranged to receive a cooled CO₂ stream from the cooler and separate the stream into a gas phase and a liquid phase. The separator may have a gas outlet and a liquid outlet. The mixing unit is preferably arranged in fluid communication with the gas outlet to receive the gas phase from the separator.

The provision of the cooler(s) allows the CO₂ stream to be cooled which may cause impurities, such as water, in the CO₂ stream to condense. The condensed impurities can be separated from the CO₂ using the separator.

The mixing unit may comprise a static mixer or an ejector, such as a multistage ejector.

The invention further extends to an offshore hydrocarbon production facility comprising the CO₂ capture unit of the second aspect. Hence, in a third aspect, the invention provides an offshore hydrocarbon production facility, comprising: a heat engine arranged to generate electrical power and/or heat for use by the hydrocarbon production facility and produce an exhaust gas containing CO₂; a pump unit arranged to receive a water stream and pump the water stream to an injection water stream; the CO₂ capture system of the second aspect arranged to receive the exhaust gas from the heat engine, wherein the mixing unit is arranged to receive the injection water stream from the pump unit and mix the injection water stream with the pressurised CO₂ stream to form a carbonated water stream; and a conduit (e.g. injection piping) for injecting the carbonated water stream into a reservoir.

The offshore hydrocarbon production facility may be suitable for use and/or used in the method of the first aspect, and may include any one or more or all of the optional features discussed above.

The hydrocarbon production facility is preferably located on a topside installation, i.e. a production installation, such as a platform or a floater. One or more or all of the heat engine, the CO₂ capture system, and/or the pump unit may be located on the production installation.

The reservoir may be a hydrocarbon reservoir. Injecting the carbonated stream into a hydrocarbon reservoir may advantageously support reservoir pressure and stimulate hydrocarbon production, i.e. to support formation pressure.

The hydrocarbon production facility may comprise a producer arranged to receive and produce a well stream from a reservoir. A separation system may be arranged to separate a natural gas stream from the well stream.

The heat engine may be arranged to receive the natural gas stream from the separation system and use the natural gas a fuel. Hence, produced natural gas may be used as the fuel source for the heat engine.

The injection piping may be arranged to inject the carbonated water into the reservoir. Preferably, the reservoir is the same reservoir from which the well stream is produced.

The pump unit may comprise a pump, preferably multiple pumps arranged in parallel. By arranging the pumps in parallel, the pump unit is provided with a degree of redundancy.

An exhaust vent line may be provided downstream of the heat engine and upstream of the CO₂ capture unit. The exhaust vent line may be arranged to vent a portion of the exhaust gas to the environment. A controllable valve may be provided in the exhaust vent line configured to control flow of exhaust gas through the exhaust vent line. The heat engine may in fact comprise multiple heat engines. The heat engines may be arranged in parallel. In facilities including more than one heat engine, the CO₂ capture plant may be arranged to receive exhaust gas from each of the heat engines. The facility may comprise a manifold arranged to receive the exhaust gas from the heat engines and pass the exhaust gas to the CO₂ capture plant. That is to say, the exhaust gas from multiple heat engines may be directed to a common CO₂ capture plant. The exhaust vent line, where present, may be arranged downstream of the manifold and upstream of the CO₂ capture plant. The pump unit may comprise the manifold.

The pump unit may have a first inlet for receiving sea water, and a second inlet for receiving produced water. A controllable valve may be coupled to each of the first inlet and the second inlet configured to control flow of sea water and produced water into the pump unit.

Alternatively, the facility may include a water-mixing system configured to receive sea water and/or produced water and mix the water sources together before passing the mixed water to the pump unit.

The facility may comprise a separation unit configured to separate and clean a stream of produced water from the well stream. The pump unit may be arranged to receive the stream of produced water from the separation unit at its second inlet. Where present, the water-mixing system may be arranged to receive the stream of produced water from the separation unit and mix the stream of produced water with a stream of sea water.

Using produced water to at least partially form the injection water stream makes it possible to efficiently dispose of the produced water in an environmentally friendly manner. Produced water may otherwise be disposed into the sea, which may require additional treatment of the produced water.

A branch line may be provided downstream of the pump unit and upstream of the mixing unit. The branch line may be configured as injection piping to inject a portion of the water stream received from the pump unit into the reservoir. A controllable valve may be provided in the branch line configured to control flow of water through the branch line.

A separator may be configured to receive the carbonated water stream from the mixing unit and separate the carbonated water stream into a liquid phase comprising carbonated water and a gas phase. The gas phase may comprise undissolved gas, such as CC>2and nitrogen. The injection piping may be configured to receive the liquid phase from the separator.

The facility may comprise a second pump unit configured to receive the carbonated water stream from the mixing unit and pump the carbonated water stream to an injection pressure. The second pump unit may be similar to the pump unit described above. It may comprise multiple pumps arranged in parallel.

In facilities having a second pump unit to pump the carbonated water, the second pump unit may be configured to receive the liquid phase from the separator.

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

Figure 1 is a generalised diagram illustrating a system and method for capturing and sequestering CO2 generated on an offshore hydrocarbon production facility;

Figure 2 is a generalised diagram illustrating another system and method for capturing and sequestering CO2 generated on an offshore hydrocarbon production facility;

Figure 3 is a generalised diagram of a CO2 sequestering system having a vent line arranged upstream of the CO2 capture unit;

Figure 4 is a generalised diagram of a CO2 pressurisation and treatment unit;

Figure 5 is a generalised diagram of another CO2 pressurisation and treatment unit;

Figure 6 is a generalised diagram illustrating yet another system and method for capturing and sequestering CO2 generated on an offshore hydrocarbon production facility;

Figure 7 is a more detailed illustration of the CO2 sequestering system of Figure 6;

Figure 8 is a diagram of a CO2 pressurisation and treatment unit for use in a C02 sequestering system; and

Figure 9 illustrates yet another CO2 sequestering system.

Figure 1 illustrates a CO2 sequestering system 2 in situ in an offshore hydrocarbon production facility 1. The offshore hydrocarbon production facility 1 includes a gas turbine 3 for generating electrical power and/or heat for the production facility 1 , a water injection apparatus 4 for injecting water into an oil and gas reservoir, and a CO2 capture system 5 for extracting CO2 from exhaust gas. The CO2 sequestering system 2 comprises the CO2 capture system 5 and the water injection apparatus 4.

The gas turbine 3, the CO2 capture system 5 and the water injection apparatus 4 are arranged on an offshore installation, such as a platform or a floater. The offshore installation also houses other hydrocarbon production apparatus of the production facility 1.

The gas turbine 3 is arranged to receive a natural gas stream 6 which it uses to generate electrical power and heat to be utilised by the production facility 1. For example, the electrical power generated by the gas turbine 3 may be used to at least partially power components of the production facility 1. The gas turbine 3 acts to combust the natural gas in order to generate the electrical power and heat. As a result of this combustion process, an exhaust gas 7 is generated and emitted from the gas turbine 3 via a conduit, such as an exhaust pipe 8. The exhaust gas 7 contains, amongst other things, nitrogen, oxygen, CO2 and water vapour.

The hydrocarbon production facility 1 may comprise multiple, i.e. more than one, gas turbine 3. For example, in the arrangement shown in Figure 2, the production facility 1 includes three gas turbines 3. It will however be appreciated that the production facility 1 may include any suitable number of gas turbines 3 to satisfy the electrical power and/or heating needs of the production facility 1.

Also, whilst the production facility 1 shown in Figure 1 includes a gas turbine 3 for generating electrical power from the natural gas stream 6, it will be appreciated that any suitable heat engine may be used for this purpose. For example, the production facility 1 may include a natural gas combustion engine in place of the gas turbine 3.

The production facility 1 additionally includes the water injection apparatus 4 for injecting water into the reservoir. Water is often injected into reservoirs to support the reservoir pressure and stimulate the recovery of hydrocarbons from the reservoir. This technique may utilise sea water, water that has been produced from the reservoir (i.e. produced water), or a mixture of sea water and produced water.

The water injection apparatus 4 includes a pump unit 9 to increase the pressure of water to an injection pressure. As shown in Figure 1 , the pump unit 9 includes two inlets 10, 11 so that it can receive sea water (e.g. via inlet 10) and produced water (e.g. via inlet 11) in varying quantities. Prior to being passed to the pump unit 9, the sea water and produced water may be treated and cleaned to remove impurities, such as oxygen, sulphur and/or sulphates. The presence of oxygen in the water can have a corrosive effect on the materials of the production facility 1 (e.g. the piping) and can lead to bacterial growth which can produce hydrogen sulphide. The presence of sulphur in the water injected into the reservoir can lead to undesirable souring of the hydrocarbons present in the reservoir.

The pump unit 9 acts to increase the pressure of the water so that it can be injected into the reservoir, forming an injection water stream 12. In cases where sea water and produced water are supplied separately to the pump unit 9, the pump unit 9 may also act to mix the two sources of water together. Alternatively, a separate water-mixing system (not shown) may be provided upstream of the pump unit 9 to mix the water sources and then pass the mixed water to the pump unit 9.

The pump unit 9 acts to increase the pressure of the water to an injection pressure that is sufficiently high to inject the water into the reservoir. This may be a pressure in the range of 100-400 bar (10-40 MPa), for instance 100-200 bar (10-20 MPa). The injection pressure will depend on, for example, the pressure in the reservoir at the injection point, the necessary excess pressure to drive the water into the reservoir, any hydrostatic pressure difference caused by a difference in height between the point at which the water is pressurised (e.g. at a topside facility) to the injection point (e.g. on the sea bed), and the frictional pressure drop in the injection pipe used to inject the water into the reservoir.

In some hydrocarbon production facilities, the pump unit 9 may act to increase the pressure of the water to an intermediate pressure that is below the injection pressure. Such a facility may be provided with additional pumping equipment to increase the pressure of the water from the intermediate pressure to the injection pressure. An example of such a system is described later with reference to Figures 6 and 7.

In order to reduce CO2 emissions from the gas turbine 3, the exhaust pipe 8 is fluidly connected to the CO2 capture system 5. Together with the water injection apparatus 4, the CO2 capture system 5 forms part of the CO2 sequestering system 2. The CO2 capture system 5 is arranged to capture CO2 from the exhaust gas 7 and mix the CO2 with the injection water stream 12. In this way, the CO2 can be injected into the reservoir along with the injection water and sequestered in the reservoir.

The CO2 capture system 5 includes a CO2 capture unit 13, a CO2 pressurisation and treatment unit 14, and a mixing unit 15. The CO2 capture unit 13 is fluidly connected to the exhaust pipe 8, thereby allowing the exhaust gas 7 from the gas turbine 3 to be passed to the CO2 capture unit 13 via the exhaust pipe 8. The CO2 capture unit 13 acts to separate CO2 from the other components making up the exhaust gas 7, producing a CO2 stream 16. The CO2 capture unit 13 thus acts to remove CO2 from the exhaust gas 7. Downstream of the CO2 capture unit 13, the treated exhaust gas 7’ (i.e. exhaust gas 7 minus the CO2) may be released into the atmosphere or optionally sent for further treatment.

The CO2 capture unit 13 may utilise any suitable separation technology to remove the CO2 from the exhaust gas 7. Example technologies may include amine scrubbing or gas membrane separation.

The CO2 pressurisation and treatment unit 14 is provided downstream of the CO2 capture unit 13. The CO2 pressurisation and treatment unit 14 receives the CO2 stream 16 from the CO2 capture unit 13 and acts to increase the pressure of the CO2 stream 16, forming a pressurised CO2 stream 17. The solubility of CO2 in water increases with the pressure of the CO2. Hence, by increasing the pressure of the CO2 it is possible to dissolve an increased amount of CO2 in the injection water stream 12.

The CO2 pressurisation and treatment unit 14 acts to increase the pressure of the CO2 stream 16 to the injection pressure of the injection water stream 12. As discussed above, this may be a pressure in the range of 100-200 bar (10-20 MPa).

At pressures above the critical pressure of CO2 (73.8 bar, 7.38 MPa), the CO2 may behave as a supercritical fluid, exhibiting properties of both the liquid and gas phases. This will occur if the temperature of the CO2 exceeds its critical temperature (31.0 °C). It will be appreciated that at pressures at or near to the injection pressure (e.g. 100-200 bar, 10-20 MPa) the pressurised CO2 stream 17 may become a supercritical fluid stream, if its temperature exceeds the critical temperature.

Whilst in the CO2 sequestering system 2 discussed above the CO2 is mixed with the injection water stream 12 at the injection pressure, these fluids may be mixed at an intermediate pressure that is lower than the injection pressure. Such a system may be provided with additional pumping equipment to increase the pressure of the carbonated water from the intermediate pressure to the injection pressure. An example of such a system is described later with reference to Figures 6 and 7. The CO2 pressurisation and treatment unit 14 may also act to remove impurities, such as O2, from the CO2 stream 16. As discussed above, the presence of O2 in the water injected into the reservoir can lead to souring of the hydrocarbons present in the reservoir and can have a corrosive effect on the materials of the production facility 1. Hence, it may be necessary to remove oxygen from the CO2 stream 16 to meet a required O2 specification of the injection water and/or to minimise the corrosion of facility equipment.

The pressurised CO2 stream 17 from the CO2 pressurisation and treatment plant is mixed with the injection water stream 12 in the mixing unit 15 that is provided downstream of the water pump unit 9. In this way, the CO2 becomes dissolved in the injection water stream 12, creating a carbonated water stream 18. The carbonated water stream 18 is passed to an injection system for injection into the reservoir.

Whilst the composition of the injection water stream may ultimately be determined by the quantities and compositions of the sea water and/or produced water available at the facility 1 , it may be possible to control the composition of the injection water stream 12 by varying the quantities of produced water and sea water that are passed to the pump unit 9. This may be achieved by providing controllable valves coupled to the inputs 10, 11 or varying the quantities of sea water and produced water passed to the water-mixing unit, where present. In this way, the salinity of the injection water stream 12 may be controlled. The solubility of CO2 in water decreases as the salinity of the water increases. Hence, by controlling the salinity of the injection water stream 12 it is possible to control the quantity of CO2 that can be dissolved in the injection water stream 12 and subsequently sequestered in the reservoir.

The quantity of water produced from the reservoir typically increases over the lifetime of the reservoir, meaning that the quantity of produced water that is available for injection may increase over time. Accordingly, early in the reservoir’s lifetime, the injection water stream 12 may comprise predominantly sea water, with little or no produced water content. It is desirable to inject produced water into the reservoir (or another reservoir) to avoid disposing of the produced water into the sea, which may require additional treatment of the produced water. Hence, the produced water content of the injection water stream 12 may increase over time, when more produced water becomes available. In some cases, the quantity of pressurised CO2 generated by the CO2 capture system 5 may exceed the solubility capacity of the injection water. In such a case, a CO2 rich phase may be created when the pressurised CO2 is mixed with the injection water stream 12. At the high pressures required for injection into the reservoir, this CO2 rich phase will be in the dense phase and have a density close to that of the injection water stream 12, or indeed a carbonated water stream 18.

The CO2 rich phase will therefore have similar properties to the injection water stream 12, making it possible to inject the CO2 rich phase into the reservoir in a similar fashion as the carbonated water.

The above described system makes it possible to inject CO2 generated by an offshore hydrocarbon production facility 1 into a reservoir concurrently with water that is being injected into the reservoir to stimulate hydrocarbon production. Unlike with conventional CO2 injection, there is no need for a dedicated CO2 injection system, such as a dedicated CO2 injection flowline and well. Rather, this technique utilises the water injection apparatus 4 already present in the production facility 1 to sequester the CO2. Accordingly, this technique provides a technically simple and economically viable method of reducing CO2 emissions from the hydrocarbon production facility 1.

At the pressures necessary for injecting the water stream into the reservoir, it may be possible to dissolve around 2-6 wt% of CO2 in the injection water stream 12. For a typical water injection rate of 20000-40000 m³/day using carbonated water having a CO2 concentration of 4 wt%, this means that it may be possible to sequester about 440000 tons of CO2 annually. In comparison, a typical offshore hydrocarbon production facility 1 may require around 30-70 MW to power various components. If all of this power is generated by one or more gas turbines 3 (or other heat engines) at the facility 1, this may correspond to an annual CO2 production of around 150000-350000 tons. Hence, in many cases, this technique has the capacity to sequester all or a majority of the CO2 from the power production on the hydrocarbon production facility 1.

Certain optional features of the CO2 sequestering system 2 will now be described in detail with reference to Figures 2 to 9.

In the system shown in Figure 1, the CO2 sequestering system 2 includes a single CO2 capture unit 13. However, the CO2 sequestering system 2 may include multiple CO2 capture units 13. Such a system is shown in Figure 2. In arrangements comprising multiple CO2 capture units 13, the CO2 capture units 13 may each have a smaller CO2 capture capacity than a CO2 capture unit 13 arranged in a system having only a single CO2 capture unit 13. The total CO2 capture capacity of a CO2 sequestering system 2 having multiple CO2 capture plants may be the same as the CO2 capture capacity of a CO2 sequestering system 2 having a single CO2 capture plant.

Figure 2 illustrates a hydrocarbon production facility 1 having three gas turbines 3 and a C02 sequestering system 2 having two CO2 capture units 13. Exhaust gas 7 from each of the gas turbines 3 is combined, for example in a manifold 19, and passed to the CO2 capture units 13. In this way, the exhaust gas 7 from each of the gas turbines 3 is distributed to the CO2 capture units 13.

The provision of multiple CO2 capture units 13 may provide the system with more flexibility. For instance, the system may be configured such that one or more of the CO2 capture units 13 can be shut off, allowing the number of online C02 capture units 13 to be varied. When a CO2 capture unit 13 is shut off, exhaust gas 7 may be prohibited from flowing through the CO2 capture unit 13. In this way, it is possible to vary the CO2 capture capacity of the system. A CO2 capture unit 13 may be shut off by closing a controllable valve 20 coupled to its inlet, for instance. This may be of benefit in systems where the quantity of exhaust gas 7 produced by the gas turbine(s) 3 varies over time.

The provision of multiple (in this case three) gas turbines 3 may provide the facility 1 with the ability to vary the amount of electrical power and/or heat that it produces. For instance, in normal operation one or more of the gas turbines 3 may be in a standby mode, i.e. not producing electrical power and/or heat, whilst the other gas turbines 3 are operational. The one or more gas turbines may remain in standby until additional power and/or heat is required, for example if there is an increase in demand. In order to fulfil this increased power and/or heat demand, one or more of the gas turbines 3 in standby may be switched to an operational mode.

Figure 3 shows a CO2 sequestering system 2 having a vent line 21 arranged upstream of the CO2 capture unit 13.

The vent line 21 is provided upstream of the CO2 capture unit 13 in order to make it possible to discharge a portion of the exhaust gas 7 from the CO2 sequestering system 2 in order to reduce the quantity of exhaust gas 7 that is passed to the CO2 capture unit 13. This may be necessary if the rate at which exhaust gas 7 produced by the gas turbine(s) 3 exceeds the capacity of the CO2 capture unit 13. The vent line 21 allows a portion of the exhaust gas 7 to bypass the CO2 capture unit 13 so as not to overwhelm the CO2 capture unit 13.

The vent line 21 may include a controllable valve 22 which may be opened, when required, to allow exhaust gas 7 to be discharged from the CO2 sequestering system 2 through the vent line 21. The discharged exhaust gas 7 may be released to the atmosphere via the vent line 21. The vent line may also serve to protect the gas turbines 3 in the event that the CO2 capture unit 13 becomes inoperative and cannot receive the exhaust gas 7.

Figure 4 provides a detailed illustration of an example CO2 pressurisation and treatment unit 14. In the CO2 pressurisation and treatment unit 14 shown in Figure 4, the pressure of the CO2 stream 16 is increased in multiple stages, in this example four stages 23a, 23b, 23c, 23d. The pressure of the CO2 stream 16 may be increased in any number of suitable stages and the CO2 pressurisation and treatment unit 14 may be include fewer or more than four stages.

The CO2 pressurisation and treatment unit 14 as shown in Figure 4 includes a first compressor 24a. The first compressor 24a receives the CO2 stream 16 from the CO2 capture unit 13 and acts to increase the pressure of the CO2 stream 16 to a first pressure. This pressure may be 3-6 bar (0.3-0.6 MPa)

A first cooler 25a is provided downstream of the first compressor 24a to cool the CO2 output from the first compressor 24a. This may cause some impurities, such as water, to condense out of the pressurised CO2, forming a multiphase fluid 27. This fluid 27 is then supplied to a first separator 26a arranged downstream of the first cooler 25a. The first separator 26a receives the fluid 27 and acts to separate any liquid from the CO2, forming a CO2 gas stream 28 and a liquid stream 29.

The first compressor 24a, the first cooler 25a and the first separator 26a form a first pressurisation stage 23a.

The CO2 compression and treatment unit 14 includes three further pressurisation stages 23b, 23c, 23d arranged in series downstream of the first pressurisation stage. Each of these pressurisation stages 23b, 23c, 23d includes a compressor 24b, 24c, 24d and a cooler 25b, 25c, 25d arranged as discussed above in relation to the first pressurisation stage. The second and third pressurisation stages 23b, 23c each also include a separator 26b, 26c arranged as discussed above in relation to the first pressurisation stage. At the pressures present in the final stage of pressurisation, the CO2 may become a supercritical fluid. Hence, the entire stream of fluid exiting the cooler 25d may be a supercritical fluid. Therefore, the fourth pressurisation stage 23d does not include a gas liquid separator.

After passing through the first pressurisation stage 23a, the CO2 stream 16 may have a pressure of 3-6 bar (0.3-0.6 MPa). The CO2 stream 16 exiting the second pressurisation stage 23b may have a pressure of 10-20 bar (1-2 MPa). The CO2 stream 16 exiting the third pressurisation stage 23c may have a pressure of 30-80 bar (3-8 MPa). The fourth pressurisation stage 23d may increase the pressure of the CO2 stream 16 to the injection pressure, i.e. 100-200 bar (10-20 MPa). At such pressures, the CO2 stream 16 may become a supercritical fluid. Hence, the fourth pressurisation stage 23d does not comprise a separator.

The CO2 is passed through the four pressurisation stages 23a, 23b, 23c,

23d and is increased in pressure to the injection pressure of the injection stream.

As discussed above, this may be a pressure in the range of 100-200 bar (10-20 MPa).

The mixing unit 15 comprises a static mixer 30. The pressurisation CO2 stream 17 is mixed with the injection water stream 12 in the static mixer 30 arranged downstream of the cooler of the fourth pressurisation stage 23d.

The water injection apparatus 4 shown in Figure 4 includes multiple, i.e. more than one, water pumps 31, 32. In this case, the water injection apparatus 4 includes two water pumps 31, 32 arranged in parallel, although any suitable number of water pumps may be utilised and they may be arranged in series if appropriate.

A manifold 33 is provided upstream of the water pumps 31, 32. The manifold 33 is arranged to receive sea water 34 and produced water 35, in varying quantities. The manifold 33 acts to combine the water sources 34, 35 and distribute the combined water to the pumps. The pumps 31, 32 act to increase the pressure of the water to the injection pressure, forming the injection stream. The injection stream is passed to the static mixer 30 downstream of the pumps 31, 32.

The static mixer 30 acts to mix the pressurised CO2 with the injection stream. This causes the CO2 to become dissolved in the injection stream, forming the carbonated water stream 18.

Whilst the above system uses a static mixer 30 to mix the pressurised CO2 with the injection stream, any suitable mixing device may be used. A system utilising an ejector for this purpose will be described later with reference to Figure 9.

As discussed above, it may be necessary to remove O2 from the CO2 stream 16 since the presence of O2 in the injection water stream 12 can have a corrosive effect on the materials of the production facility 1 and can lead to souring of the hydrocarbons present in the reservoir.

With continued reference to Figure 4, the CO2 capture system 5 includes an O2 removal unit 36. The O2 removal unit 36 shown in Figure 4 is arranged in a bypass branch 37 downstream of the compressor in the third pressurisation stage 23c. The bypass branch 37 may include a controllable valve 38 to allow, when opened, fluid to flow from the main flow path and to the O2 removal unit 36 via the bypass branch 37.

The O2 removal unit 36 acts to remove O2 from the CO2 stream 16, forming a treated CO2 stream 39. The treated CO2 stream 39 is passed back to the main CO2 flow path upstream of the cooler in the third pressurisation stage 23c, where it continues to pass through the remaining pressurisation stage 23d. The O2 removal unit 36 may comprise a catalytic oxidiser.

Passing the CO2 stream 16 through the O2 removal unit 36 may result in decrease in the pressure of the CO2 stream 16. This decrease in pressure may proportional to the pressure of the CO2 stream 16 that is passed to the O2 removal unit 36. Hence, the O2 removal unit 36 (and the bypass branch 37) may be arranged at any suitable stage of pressurisation i.e. at any suitable pressure level, in order to minimise this drop in pressure. For instance, instead of being arranged to receive pressurised CO2 from the third compressor 24c (as shown in Figure 4), the O2 removal unit 36 may be arranged to receive CO2 from the first compressor 24a, the second compressor 24b or the fourth compressor 24d.

The CO2 pressurisation and treatment unit 14 may include multiple O2 removal units 36 arranged to receive CO2 of different pressures.

Another CO2 pressurisation and treatment unit 14 is shown in Figure 5. Much of this arrangement is the same as that of Figure 4, and the parts common to both Figures will not be described again here. The difference between the arrangements of Figures 4 and 5 is that the CO2 pressurisation and treatment unit 14 of Figure 5 includes five pressurisation stages 23a, 23b, 23c, 23d, 23e, with the fifth and final pressurisation stage 23e including a pump 40. That is to say, the fifth pressurisation stage 23e includes the pump 40 in place of a compressor.

The pressurisation stages 23a, 23b, 23c, 23d upstream of the pump 40 act to increase the pressure of the CO2 and cool the CO2. The result of this pressure increase is that the CO2 may become a supercritical fluid, exhibiting properties of both the liquid and gas phases. This may occur at pressures below the injection pressure of the injection stream. For instance, a pressure of 75 bar (7.5 MPa) may be sufficient to cause the CO2 to become supercritical at a temperature of 31 °C, whereas the injection pressure may be between 100-200 bar (10-20 MPa). Hence, it is possible to use the pump 40 to pump the (supercritical fluid) CO2 to the injection pressure before the CO2 is mixed with the injection water stream 12. Pumping requires less power than compression, so this arrangement may be used to improve the energy efficiency of the CO2 capture system 5.

Since the solubility of CO2 in water increases with pressure, it is often desirable to mix the CO2 with the water at the highest possible pressure, i.e. the injection pressure. This is the approach shown in Figures 1-5 where the CO2 is mixed with the injection water stream 12 at the injection pressure. However, it is also possible to mix the CO2 with the water stream at an intermediate pressure below the injection pressure. Figures 6 and 7 show an arrangement configured for this purpose.

In Figure 6, the CO2 pressurisation and treatment unit 14 acts to increase the pressure of the CO2 to an intermediate pressure that is lower than the injection pressure. This intermediate pressure may be, for example, 20-50 bar (2-5 MPa). This makes it possible to reduce the amount of power consumed by the CO2 pressurisation and treatment unit 14 to increase the pressure of the CO2. For example, this may mean that fewer pressurisation stages are required in the CO2 pressurisation and treatment unit 14, leading to lower power consumption.

The pump unit 9 acts to increase the pressure of the water to the intermediate pressure, forming an intermediate pressure stream 41.

The pressurised CO2 stream 17 from the CO2 pressurisation and treatment unit 14 is mixed with the intermediate pressure stream 41 in the mixing unit 15, forming the carbonated water stream 18. A second stage pump unit 42 is provided downstream of the mixing unit 15 and acts to pump the carbonated water to the injection pressure.

Figure 7 shows an example arrangement that is configured to increase the pressure of the CO2 to an intermediate pressure. Much of what is shown in Figure 7 is the same as that shown in Figure 4, and parts that are common to both Figures will not be described in detail again here. Figure 7 shows a CO2 pressurisation and treatment unit 14 having three pressurisation stages 23a, 23b, 23c.

The static mixer 30 receives the pressurised CO2 from the cooler and the intermediate pressure stream 41 and acts to mix the CO2 with the intermediate pressure stream 41 , forming the carbonated water stream 18. The second stage pump unit 42 comprises two pumps 43, 44 arranged in parallel. These pumps 43, 44 receive the carbonated water and act to pump the carbonated water to the injection pressure.

Whilst the arrangement shown in Figure 7 shows two pumps 43, 44 arranged in parallel, it will be appreciated that the facility may comprise any suitable number of pumps, such as one or more pumps. The pumps may also be arranged in series, if appropriate.

Another CO2 sequestering system 2 is shown in Figure 8. Much of what is shown in Figure 8 is the same as that shown in Figure 4, and parts that are common to both Figures will not be described in detail again here. The CO2 sequestering system 2 of Figure 8 differs from that of Figure 4 in that the water injection apparatus 4 incudes a branch line 45 downstream of the water pumps 31, 32 and upstream of the static mixer 30. The branch line 45 may include a controllable valve 46 which, when opened, allows at least a portion of the injection water stream 12 to pass through the branch line 45.

The branch line 45 acts to pass a portion of the injection water stream 12 to a water injection pipe. This water injection pipe is used to inject the water into the reservoir.

For some applications, it may not be desirous to inject carbonated water into every part of the reservoir. Instead, engineers may wish to inject carbonated water into only a particular part of the reservoir whist injecting non-carbonated water into other areas of the reservoir. The inclusion of the branch line 45 makes it possible to selectively split the injection stream into a non-carbonated stream (that is not mixed with the CO2) and a stream that will go on to be mixed with the CO2 to form the carbonated stream. These separate streams may be directed to different wells for injecting into different areas of the reservoir, as desired. It is also possible to select a desired fraction of the water that is utilised for producing carbonated water, for example by varying the controllable valve 46 in the branch line 45.

Figure 9 illustrates a CO2 sequestering system 2 that utilises a liquid driven ejector 47 at the point at which the CO2 is mixed with the water. The ejector 47 is provided downstream of the CO2 pressurisation and treatment unit 14 and receives CO2 from the CO2 pressurisation and treatment unit 14. The ejector 47 is also arranged downstream of the water pumps 31 , 32 and receives the injection water stream 12 output by the water pumps 31, 32. The ejector 47 acts to increase the pressure of the CO2 and also facilitates mixing of the CO2 with the water.

The ejector 47 is powered by the injection water stream 12 and acts to further increase the pressure of the pressurised CO2 stream 17 output from the CO2 pressurisation and treatment unit 14. Therefore, the pressurised CO2 stream 17 may be provided at a lower pressure compared to systems that do not include the ejector 47. This makes it possible to reduce the amount of power consumed by the CO2 pressurisation and treatment unit to increase the pressure of the CO2. For example, this may mean that fewer pressurisation stages are required in the CO2 pressurisation and treatment unit 14, leading to lower power consumption.

The carbonated water stream 18 may contain undissolved gas, such as gaseous CO2 and nitrogen. In order to remove these gasses, the system of Figure 9 also includes a separator 48 arranged downstream of the ejector 47. The separator 48 receives the carbonated water stream 18 from the ejector 47 and acts to separate the gasses from the carbonated water stream 18. The separator 48 outputs a gas stream 49 and a liquid stream 50. The liquid stream 50 comprises the carbonated water stream 18, and is passed to the injection pipe for injection into the reservoir. The gas stream 49, containing separated gaseous CO2, may be recycled back to the CO2 pressurisation and treatment unit 14 or the CO2 capture unit 13 so as to be mixed with the CO2 stream 16. In this way, another attempt can be made to dissolve the separated CO2 in the injection water stream 12. Alternatively the gas stream 49 may be mixed with the exhaust gas 7 or vented to the environment.

Any one or more of the features of the offshore hydrocarbon production facility 1 and/or the CO2 sequestering systems 2 described above with reference to Figures 1 to 9 may be combined in a single system.

Claims

1. A method of capturing CO2 produced by an offshore hydrocarbon production facility, the method comprising: generating electrical power and/or heat for use by the hydrocarbon production facility at an offshore location, wherein generating the power and/or heat produces an exhaust gas containing CO2; and at the offshore location: separating CO2 from at least a portion of the exhaust gas to form a CO2 stream; increasing the pressure of the CO2 stream to form a pressurised stream; mixing the pressurised stream with an injection water stream to form a carbonated water stream; and injecting the carbonated water stream into a reservoir.

2. A method according to claim 1 , wherein the reservoir is a hydrocarbon reservoir.

3. A method according to claim 1 or 2, wherein increasing the pressure of the

CO2 stream comprises increasing the pressure of the CO2 stream to an injection pressure suitable for injecting a carbonated water stream into the reservoir.

4. A method according to claim 3, wherein the injection pressure is 100 to 200 bar (10 to 20 MPa).

5. A method according to claim 3 or 4, wherein the pressurised stream is mixed with the injection water stream at the injection pressure thereby forming a carbonated water stream at the injection pressure.

6. A method according to claim 1 or 2, wherein increasing the pressure of the CO2 stream comprises increasing the pressure of the CO2 stream to an intermediate pressure not suitable for injecting a carbonated water stream into the reservoir.

7. A method according to claim 6, wherein the intermediate pressure is 20 to 50 bar (0.2 to 0.5 MPa).

8. A method according to claim 6 or 7, wherein the pressurised stream is mixed with the injection water stream at the intermediate pressure to form a carbonated water stream at the intermediate pressure.

9. A method according to claim 8, wherein the method further comprises increasing the pressure of the carbonated water to an injection pressure suitable for injecting a carbonated water stream into the reservoir.

10. A method according to any preceding claim, comprising removing O2 from the CO2 stream and/or the pressurised stream.

11. A method according to any preceding claim, comprising removing impurities from the CO2 stream.

12. A method according to any preceding claim, wherein the injection water stream comprises sea water and/or produced water.

13. A method according to claim 12, wherein the method comprises varying quantities of sea water and produced water in the injection water stream to provide an injection water stream having a desired salinity.

14. A method according to any preceding claim, wherein the step of increasing the pressure of the CO2 stream uses a compressor and/or a pump to increase the pressure of the CO2 stream.

15. A method according to any preceding claim, wherein the step of increasing the pressure of the CO2 stream comprises multiple pressurisation stages.

16. A method according to claim 15, wherein the O2 removal step is carried out after one or more of the pressurisation stages.

17. A method according to any preceding claim, comprising venting a portion of the exhaust gas before the CO2 separation step such that only a portion of the exhaust gas is passed to the CO2 separation step.

18. A method according to any preceding claim, wherein the mixing step comprises passing the pressurised CO2 stream and the injection water stream through an ejector.

19. A method according to any preceding claim, comprising injecting one or more additional streams of water into the reservoir, the additional stream(s) of water being divided from the injection water stream before the injection water stream has been mixed with the pressurised CO2 stream.

20. A method according to any preceding claim, comprising separating any undissolved gases from the carbonated water prior to injection.

21. A method according to any preceding claim, wherein the power and/or heat generation step, separation step, the step of increasing the pressure of the CO2 stream, O2 removal step, mixing step, the step of separating any undissolved gases from the carbonated water and/or the pumping step(s) are performed on a topside installation.

22. A CO2 capture system for capturing CO2 from an exhaust gas, the system comprising: a CO2 capture unit configured to receive exhaust gas and to separate CO2 from the exhaust gas to form a CO2 stream; a pressurisation unit arranged to increase the pressure of the CO2 stream to form a pressurised CO2 stream; and a mixing unit arranged to mix the pressurised CO2 stream with an injection water stream to form a carbonated water stream.

23. A CO2 capture system according to claim 22, wherein the pressurisation unit is arranged to increase the pressure of a stream of CO2 to an injection pressure suitable for injecting a water stream into a subsea reservoir.

24. A CO2 capture system according to claim 23, wherein the injection pressure is 100 to 200 bar (10 to 20 MPa).

25. A CO2 capture system according to claim 24, wherein the pressurisation unit is arranged to increase the pressure of a stream of CO2 to an intermediate pressure not suitable for injecting a water stream into a subsea reservoir.

26. A CO2 capture system according to claim 25, wherein the intermediate pressure is 20 to 50 bar (0.2 to 0.5 MPa).

27. A CO2 capture system according to any of claims 22 to 26, wherein the pressurisation unit comprises multiple pressurisation stages.

28. A CO2 capture system according to any of claims 22 to 27, comprising an O2 removal unit arranged to remove O2 from the CO2 stream.

29. A CO2 capture system according to claim 28, wherein the CO2 removal unit is arranged between successive pressurisation stages of the pressurisation unit.

30. A CO2 capture system according to any of claims 22 to 29, wherein the CO2 capture unit comprises an amine scrubber or a membrane separator.

31. A CO2 capture system according to any of claims 22 to 30, wherein the pressurisation unit comprises a compressor.

32. A CO2 capture system according to claim 31 , wherein the compressor is a liquid tolerant compressor.

33. A CO2 capture system according to any of claims 22 to 32, wherein the pressurisation unit comprises a pump.

34. A CO2 capture system according to claim 31 , 32 or 33, comprising a cooler arranged to receive and cool CO2 output from the compressor or pump.

35. A CO2 capture system according to claim 34, comprising a separator arranged to receive a cooled CO2 stream from the cooler and separate the stream into a gas phase and a liquid phase.

36. A CO2 capture system according to any of claims 22 to 35, wherein the mixing unit comprises an ejector.

37. An offshore hydrocarbon production facility, comprising: a heat engine arranged to generate electrical power and/or heat for use by the hydrocarbon production facility and produce an exhaust gas containing CO2; a pump unit arranged to receive a water stream and pump the water stream to an injection water stream; the CO2 capture system according to any of claims 22 to 36 arranged to receive the exhaust gas from the heat engine, wherein the mixing unit is arranged to receive the injection water stream from the pump unit and mix the injection water stream with the pressurised CO2 stream to form a carbonated water stream; and injection piping for injecting the carbonated water stream into a reservoir.

38. An offshore hydrocarbon production facility according to claim 37, comprising a vent line provided downstream of the heat engine and upstream of the CO2 capture unit arranged to vent a portion of the exhaust gas.

39. An offshore hydrocarbon production facility according to claim 37 or 38, wherein the pump unit has a first inlet for receiving sea water, and a second inlet for receiving produced water.

40. An offshore hydrocarbon production facility according to claim 37, 38 or 39, comprising a second pump unit configured to receive the carbonated water stream from the mixing unit and pump the carbonated water stream to an injection pressure suitable for injecting a water stream into a subsea reservoir.

41. An offshore hydrocarbon production facility according to claim 40, wherein the injection pressure is 100 to 200 bar (10 to 20 MPa).

42. An offshore hydrocarbon production facility according to any of claims 37 to 41, comprising a branch line provided downstream of the pump unit and upstream of the mixing unit and arranged to direct a portion of the injection water stream away from the mixing unit

43. An offshore hydrocarbon production facility according to claim 42, wherein the branch line is configured as injection piping to inject a portion of the water stream received from the pump unit into the reservoir.

44. An offshore hydrocarbon production facility according to any of claims 37 to

43, comprising a separator configured to receive a carbonated water stream from the mixing unit and separate the carbonated water stream into a liquid phase comprising carbonated water and a gas phase comprising undissolved gas.

45. An offshore hydrocarbon production facility according to any of claims 37 to

44, wherein the heat engine, C02 capture system, and/or pump unit are located on a topside installation.