WO2021045631A1

WO2021045631A1 - Re-injection of a produced hydrocarbon gas into a hydrocarbon reservoir without gas drying

Info

Publication number: WO2021045631A1
Application number: PCT/NO2020/050227
Authority: WO
Inventors: Bjørgulf Haukelidsæter EIDESEN; Cecilie Gotaas Johnsen; Arild SAMUELSBERG
Original assignee: Equinor Energy As
Priority date: 2019-09-05
Filing date: 2020-09-07
Publication date: 2021-03-11
Also published as: GB2592454A; GB202014025D0; GB2592454B; GB201912808D0

Abstract

A system and corresponding method for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir are provided. The system includes a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase. The separation apparatus is fluidly connected to an injection apparatus by one or more conduits such that the gas phase can be passed to the injection apparatus. The separation apparatus is configured to process the produced fluid such that the gas phase is outside the gas hydrate forming envelope for conditions within the system, thereby avoiding significant formation of gas hydrates in the system.

Description

RE-INJECTION OF A PRODUCED HYDROCARBON GAS INTO A HYDROCARBON

RESERVOIR WITHOUT GAS DRYING

The present invention relates to systems for the re-injection of a hydrocarbon gas into a hydrocarbon reservoir without the need for gas drying. The disclosure also extends to corresponding methods. The disclosed systems and methods are particularly useful in, but not limited to, supporting the pressure of a hydrocarbon reservoir.

It is well known to use produced hydrocarbon gas to support reservoir pressure in order to enhance oil and gas recovery from subterranean reservoirs. Doing so allows more hydrocarbon fluid to be extracted from the reservoir and as a result increases the recovery efficiency. Typically, hydrocarbon gas recovered from the reservoir is re-injected into the reservoir to maintain the pressure of the reservoir as fluids are extracted.

In addition to hydrocarbons, the fluid produced from the reservoir will often contain liquid water and gaseous water. Before the gas can be re-injected into the reservoir, it must first be processed to separate it from the other fluids produced from the reservoir. This usually involves separating the produced fluid into a liquid phase product and a gas phase product, which typically comprises gaseous water and gaseous hydrocarbons. If the gas phase product is allowed to cool, the water in the gas phase will condense and, below the hydrate forming temperature, gas hydrates will form.

Gas hydrates are ice-like crystalline solids composed of water and gas, and hydrate deposition on the inside wall of gas and/or oil pipelines is a severe problem in oil and gas production infrastructure. The pressure and temperature conditions under which gas hydrates can form from a particular fluid composition is known as the “hydrate envelope”. Hydrates can be formed where liquid water is present alongside gaseous hydrocarbons. Therefore, for a given hydrocarbon gas containing water, hydrates form at lower pressures and temperatures where liquid water is able to condense from the gas phase. For example, when a hydrocarbon gas containing water flows through a conduit with cold walls, the water vapour may condense from the gas and cause hydrates to precipitate and adhere to the inner walls of the conduit. This reduces the conduit cross-sectional area, which, without proper counter measures, will lead to a loss of pressure and ultimately to a complete blockage of the conduit or other process equipment. Therefore, measures are normally taken to control the presence of water vapour in the hydrocarbon gas passing through a processing system. Such processes are known as “gas drying” processes since they remove water from the hydrocarbon gas.

Known “gas drying” processes to remove water from a hydrocarbon gas, such as that disclosed in US 2015/0291901, typically include the addition of a hydrate inhibitor or desiccant, such as triethylene glycol (TEG), diethylene glycol (DEG), monoethylene glycol (MEG), to the hydrocarbon gas to absorb and remove the water from the hydrocarbon gas. Where the water content in the hydrocarbon gas is high, proportionally larger amounts of desiccants are needed, which require a desiccant regeneration process unit with sufficient capacity to recover and recycle the desiccant. This adds to the power consumption of the hydrocarbon processing facility. Moreover, in offshore hydrocarbon production, such gas drying facilities are usually arranged topside, for instance on a platform or floater. This limits the location of subsea wells to locations where topside facilities can be installed.

According to a first aspect of the present invention, there is provided a system for re injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and one or more conduits fluidly connecting the separation apparatus to the injection apparatus for passing the gas phase from the separation apparatus to the injection apparatus; wherein the separation apparatus is configured to process the produced fluid such that the gas phase is outside the gas hydrate forming envelope for conditions within the system, whereby significant formation of gas hydrates in the system is avoided.

As discussed above, the “hydrate forming envelope” defines the pressure and temperature conditions under which gas hydrates can form from a particular fluid composition, in this case the gas phase separated from the produced fluid.

Since the separation apparatus is configured so the separated gas phase is maintained outside of the gas hydrate forming envelope for conditions within the system, e.g. as it flows to the injection apparatus via the conduits, the formation of gas hydrates within the system can be avoided without having to subject the gas phase to a gas drying process. Such gas drying processes require additional energy in order to dry the gas. Therefore, by avoiding the need for additional gas drying processes the system of the present invention can be made more energy efficient.

The process of transporting the gas to equipment for gas drying also requires energy, for example to compress the gas to account for pressure losses as the gas is passed to the gas drying equipment. Thus, by removing the need to send the gas to gas drying equipment, the power consumption of the system can be reduced, leading to improved efficiency. Removal of the gas-drying process also reduces the distance that must be travelled by the gas phase along its flow path before re-injection, thereby reducing the amount of cooling experienced by the gas phase as it passes through the system where heat can be dissipated to the surrounding environment. By reducing cooling of the gas phase in the system, the formation of gas-hydrates can be further avoided. Moreover, where a hydrocarbon reservoir is situated subsea, the system allows for the re-injection of gas into the hydrocarbon reservoir without the need for an associated top side facility to house the gas-drying equipment. It will therefore be appreciated that the invention is particularly useful in the re-injection of hydrocarbon gas into a subsea hydrocarbon reservoir; however the invention is not so limited.

Whilst it is possible that hydrates can form from gases that contain any quantity of hydrocarbon molecules, even in small concentrations, hydrates are more readily formed in conditions with a high concentration of gaseous hydrocarbons. It will therefore be appreciated that the invention is particularly useful when the majority (i.e. greater than 50 vol%) of the composition of the gas phase is hydrocarbon molecules; although the invention is not so limited. Preferably, the gas phase contains substantially hydrocarbon gas. For instance, the gas phase may have a hydrocarbon content of greater than 70 vol%, greater than 80 vol% or greater than 90 vol%. In some cases, the gas phase may have a hydrocarbon content of at least 99 vol%.

The injection apparatus may comprise a compressor for increasing the pressure of the gas phase. The compressor allows the gas phase to be compressed to a pressure sufficient to aid in hydrocarbon recovery from the hydrocarbon well by supporting reservoir pressure. The compressor may be configured to increase the pressure of the gas phase to at least 20 MPa, preferably to between 20 MPa and 45 MPa.

The injection apparatus may comprise an injection wellhead for injecting the gas phase into the hydrocarbon reservoir. The injection wellhead may be fluidly connected to the compressor for injecting the pressurised gas phase into the hydrocarbon reservoir.

The separation apparatus may comprise a separator for separating the produced fluid into a gas phase and a liquid phase. The separator may have an inlet for receiving the produced fluid, a gas phase outlet and a liquid phase outlet.

The separation apparatus may comprise a cooler for reducing the temperature of the produced fluid. The cooler may be arranged upstream of the separator, such that the separator is arranged to receive fluid that has been cooled by the cooler. The cooler allows the system to be able cool the produced fluid and thereby regulate the hydrocarbon dew point of the produced fluid. Hence, the cooler allows for control over which components of the produced fluid will be present in the gas phase and which components of the produced fluid will be present in the liquid phase, i.e. the cooler allows for control over the composition of the gas phase and the liquid phase.

The separation apparatus may comprise a pressure reduction valve for reducing the pressure of the produced fluid. The pressure reduction valve may be arranged upstream of the separator such that the separator is arranged to receive fluid that has had its pressure reduced by the pressure reduction valve. Likewise, the pressure reduction valve may be arranged upstream of the cooler, such that the cooler is arranged to receive fluid that has had its pressure reduced by the pressure reduction valve. The pressure reduction valve can be used to control the pressure of the produced fluid, and hence can be used to control the hydrocarbon dew point of the produced fluid. Like the cooler, the pressure reduction valve allows for control over which components of the produced fluid will be present in the gas phase and which components of the produced fluid will be present in the liquid phase. That is to say, the pressure reduction valve allows for control over the composition of the gas phase and the liquid phase.

The system preferably further comprises a gas recovery unit for extracting a flash gas from the liquid phase. In this way, additional gas can be extracted from the liquid phase thereby increasing the quantity of gas available for re-injection.

A liquid phase supply line may fluidly connect the separation apparatus and the gas recovery unit for supplying the liquid phase to the gas recovery unit. The liquid phase supply line may include a pressure reduction device, such as a control valve, for reducing the pressure of the liquid phase as it is passed to the gas recovery unit. The pressure reduction device allows for control over the hydrocarbon dew point of the liquid phase, thereby enabling control over the composition of the flash gas that can be extracted from the liquid phase by the gas recovery unit.

The system may comprise a flash gas return line fluidly connecting the gas recovery unit and the separation apparatus for directing the flash gas from the gas recovery unit to the separation apparatus. The flash gas return line may be fluidly connected to the gas inlet of the separator of the separation apparatus, if present.

The gas recovery unit may comprise a separator for separating a flash gas from the liquid phase.

The gas recovery unit may comprise a pressurising device, such as an ejector, for increasing the pressure of the flash gas. In this way, the pressurising device allows the flash gas to be pressurised to the pressure of the fluid at an inlet of the separation apparatus, for example the inlet of the separator of the separation apparatus, if present.

The gas recovery unit may comprise a pump for boosting the pressure of the liquid phase after the flash gas has been separated from the liquid phase. Where the gas recovery unit includes a separator, the pump may be configured to receive the liquid phase from the separator of the gas recovery unit. The pump may be configured to boost the pressure of the liquid phase to hydrostatic pressure. Where the gas recovery unit comprises an ejector for increasing the pressure of the flash gas, the gas recovery unit may also comprise an ejector boost supply line configured to feed a slipstream from the boosted liquid phase to the ejector such that energy within the boosted liquid phase is used to compress the flash gas. In this way, energy within the boosted liquid phase can be used to compress the flash gas and power requirements of the system can be reduced. The ejector boost supply line may comprise a flow control device, such as a flow control valve, for controlling the slipstream fed to the ejector.

The system may further comprise a storage facility configured to receive and store the liquid phase from the separation apparatus and/or the gas recovery unit. The storage facility may comprise a storage tank. The storage facility may be located subsea, optionally on the sea bed, for subsea storage of the liquid phase.

Preferably, the system may be configured to process the produced fluid such that the liquid phase is a semi-stable liquid product. The semi-stable liquid product may have a true vapour pressure (TVP) of greater than 100 kPa (1 bar). The term “semi-stable liquid product”, as used herein, refers to a liquid that has been stabilised to a certain extent, but has not been fully stabilised. That is to say, the liquid is only in a stable state (i.e. components of the liquid cannot evaporate) at ambient temperature if it is stored at a pressure above atmospheric pressure. Hence, by definition, gaseous components cannot evaporate from a semi-stable liquid. Therefore, by forming a liquid phase that is a semi stable liquid product, the liquid phase can be used to flush the system, for example to remove any gas hydrates that have formed the system, and will not lead to hydrate formation within the system.

The system may comprise a collection sump for collecting liquid that condenses from the gas phase within the system. The collection sump may be arranged at the lowest point of the system such that liquid that condenses from the gas phase can drain to the collection sump under the action of gravity. The collection sump may be the separator of the separation apparatus, if present. By collecting condensed liquid at a predefined point in the system, it is possible to control where both gas hydrocarbons and liquid water will be present together, and thereby control where gas hydrates will form within the system. Moreover, collecting the condensed liquid at a predefined point also acts to drain the liquid away from other parts of the system. Thus, this prevents gas hydrates from forming in parts of the system where liquid water may otherwise be present.

Since the collection sump is arranged to collect liquid, in particular liquid water, that has condensed out of the gas phase within the system there is a possibility that gas hydrates may form within the collection sump. The collection sump may therefore be fluidly connected to a supply of hydrate inhibitor to prevent gas hydrate formation within the collection sump. The system may comprise a container, such as a tank, for storing a supply of hydrate inhibitor. The container is preferably fluidly connected to the collection sump. For example, a hydrate inhibitor supply line may fluidly connect the container and the collection sump. The hydrate inhibitor supply line may comprise a control valve for controlling the supply of hydrate inhibitor to the collection sump. The injection apparatus may comprise a header arranged to collect the gas phase received from the separation apparatus. Preferably, the header comprises an inlet at the top of the header for receiving the gas phase. The header may comprise an outlet at the top of the header for outputting the gas phase, for example to an injection wellhead for re-injection. In this way, any liquid present within the header cannot exit the header through the inlet and/or outlet arranged in the top of the header. This prevents liquid from being re-injected into the reservoir and ensures that the liquid is collected in the header. The header is preferably fluidly connected to the injection wellhead via a conduit having an inverted U-bend shape. This configuration ensures that any liquid that collects in the header is not passed to the injection wellhead and also means that condensation forming in the upward portions of the conduits is drained back into the header.

Where the injection apparatus comprises a compressor, the header is preferably arranged such that liquid may drain from the compressor to the header under the action of gravity. In this way, the header acts as a sump, similar to the collection sump discussed above, and ensures that any liquid water is collected at a predefined location. This limits the locations within the system where liquid water is present and thereby limits the locations at which gas hydrates can be formed in the system.

Where the system comprises a collection sump, the header is preferably arranged higher in the system than the collection sump. That is to say, the collection sump is preferably arranged at a lower point in the system than the header. This allows any liquid collected in the header to be passed to the collection sump under the action of gravity. In this way, any liquid that has condensed out of the gas phase within the system can be passed easily to the collection sump where any necessary hydrate prevention strategy can be implemented. Accordingly, a hydrate prevention strategy, such as the provision of hydrate inhibitor, is only required in the collection sump, and gas hydrates can be removed from the header by passing the liquid to the collection sump.

The provision of a collection sump is seen as an invention in its own right. Accordingly, viewed from another aspect, the invention provides a system for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; and a collection sump for collecting liquid that condenses from the gas phase within the system, wherein the collection sump is arranged such that the condensed liquid drains to the collection sump under the action of gravity.

This aspect of the invention is preferably performed in combination with any of the previously described features of the invention. In particular, the collection sump is preferably arranged at the lowest point of the system such that liquid that condenses from the gas phase can drain to the collection sump under the action of gravity. The collection sump is preferably the separator of the separation apparatus, if present. The system may also include an injection apparatus for injecting the gas phase into the hydrocarbon reservoir, the injection apparatus preferably including one or more of the features described above in relation to the first aspect.

It will be appreciated that in either of the above described aspects of the invention, the system comprises a flow path or one or more conduits arranged to pass fluid, such as the liquid phase and/or the gas phase, between the constituent components of the system. For instance, the system may comprise one or more conduits fluidly connecting the separation apparatus to the injection apparatus, and/or one or more conduits for passing flash gas from the gas recovery unit to the separation apparatus. A gas product, e.g. the gas phase from the separation apparatus or the flash gas from the gas recovery unit, is passed through these conduits during operation of the system. Preferably, these conduits are arranged such that the gas passing through each conduit is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided. By avoiding gas hydrate forming conditions within the conduits, the formation and build-up of gas hydrates within the system can be prevented.

The conduits may have a length of less than 10m, preferably less than 5m, more preferably less than 3m, and even more preferably less than 2m. The system may be arranged on a single unit or skid, thereby constraining the possible length of the conduits between the components of the system. For example, the unit or skid may have an area of less than 200m², an area of less than 100m², or an area of less than 25m². As discussed above, as gas passes through the system, some of its heat can be dissipated to the surrounding environment. This cooling is prevalent in conduits, where the gas is exposed to ambient conditions via the walls of the conduit. This cooling can cause the gas to cool sufficiently such that water condenses out of the gas, allowing gas hydrate formation. Therefore, by minimising the length of the conduits the distance travelled by the gas through the conduits can be reduced and the cooling effect can be limited. Accordingly, the formation of gas hydrates in the conduits can be prevented.

The system may be arranged such that a residence time of the gas within a conduit is less than 30 seconds, preferably less than 10 seconds. This reduces the time the gas is resident in the relatively cooler conditions of the conduit, thereby limiting the cooling of the gas as it passes through the conduit. Therefore, reducing residence time in the conduit acts to maintain the gas outside of the hydrate forming envelope as it passes through the conduit and prevents gas hydrate formation within the conduit.

Preferably, the conduits are insulated conduits. By providing insulation from the ambient conditions as the gas flows through a conduit, cooling of the gas can be reduced and the conditions can be maintained outside the gas hydrate forming envelope within the conduit.

The conduits may be heated conduits. For example, walls of the conduits may be heated. By heating the conduits, the cooling effect of the ambient conditions can be reduced. This acts to reduce or even prevent condensation of liquid water out of the hydrocarbon gas, thereby avoiding hydrate forming conditions within the conduits.

The arrangement of the conduits within the system described above for ensuring that the gas phase is maintained outside of the gas hydrate forming envelope is also seen as an invention in its own right. Accordingly, viewed from yet another aspect, the invention provides a system for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and one or more conduits fluidly connecting the separation apparatus to the injection apparatus; wherein each of the one or more conduits is configured such that the gas phase is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided.

This aspect of the invention is preferably performed in combination with any of the previously described features of the invention. In particular, the conduits may have a length of less than 10m, preferably less than 5m, more preferably less than 3m, and even more preferably less than 2m. The system may be arranged such that a residence time of the gas within a conduit is less than 30 seconds, preferably less than 10 seconds. Preferably, the conduits are insulated conduits and/or heated conduits.

This invention also extends to a corresponding method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir. Accordingly, viewed from yet another aspect, the invention provides a method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; and injecting the gas phase into the hydrocarbon reservoir; wherein separation of the produced fluid is such that the gas phase is outside the gas hydrate forming envelope.

The majority of the gas phase may be hydrocarbon gas. That is, the gas phase may have a hydrocarbon content of greater than 50 vol%. Preferably, the gas phase contains substantially hydrocarbon gas. For instance, the gas phase may have a hydrocarbon content of greater than 70 vol%, greater than 80 vol% or greater than 90 vol%. In some cases, the gas phase may have a hydrocarbon content of at least 99 vol%. The method is preferably performed using the system discussed above and has corresponding features. For instance, the method may further comprise draining liquid that condenses from the gas phase to a collection sump under the action of gravity.

Draining of the condensed liquid to a collection sump is seen as an invention in its own right. Accordingly, viewed from a further aspect, the invention provides a method of re injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; passing the gas phase to an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and draining liquid that condenses from the gas phase as the gas phase is passed to the injection apparatus to a collection sump under the action of gravity.

This aspect of the invention is preferably performed in combination with any of the previously described features of the invention. In particular, this method is preferably performed using the system discussed above and has corresponding features.

In either of the above described methods, the gas phase may be passed through one or more conduits to an injection apparatus for injecting the gas phase into the hydrocarbon reservoir. Each of these one or more conduits may be configured such that the gas phase is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided.

Passing the gas phase through such an arrangement of conduits that ensures that the gas phase is maintained outside of the gas hydrate forming envelope is also seen as an invention in its own right. Hence, viewed from yet another aspect, the invention provides a method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; and passing the gas phase through one or more conduits to an injection apparatus for injecting the gas phase into the hydrocarbon reservoir, wherein each of the one or more conduits is configured such that the gas phase is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided.

An embodiment of the present invention will now be described, by way of example only, with reference to the following figures, in which:

Figure 1 is an elevation view of a subsea gas injection system according to an embodiment of the invention; Figure 2 is a process diagram illustrating the gas processing components of the subsea gas injection system;

Figure 3 is a process diagram illustrating the liquid processing components of the subsea gas injection system; and

Figure 4 is a process diagram of an embodiment of a flash-gas recovery unit.

With reference to Figure 1 , there is shown a subsea gas injection system on the sea bed 2. Fluid produced from a subsea hydrocarbon well is transported to the subsea gas injection system by a pipeline 1. Two plugs 3 separate the pipeline 1 into three sections; inlet piping 1a, header 1b, and outlet piping 1c, and prevent fluid from passing between the three sections 1a, 1b, 1c. The inlet piping 1a is connected to a wellhead (not shown) of a subsea hydrocarbon well and the produced fluid passes through the inlet piping 1a towards the subsea gas injection system. The produced fluid may comprise water, natural gas and liquid hydrocarbons.

The produced fluid is passed from the inlet piping 1a to a cooler 6 through conduit 5. A control valve 4 is provided in the conduit 5 to reduce the pressure of the produced fluid that is passed to the cooler 6. The produced fluid is cooled by the cooler before being passed to a gas-liquid separator 8 via conduit 7 where gaseous components of the produced fluid (i.e. the gas phase) are separated from liquid components (i.e. the liquid phase).

The control valve 4, cooler 6 and gas-liquid separator 8 regulate the hydrocarbon dew point of the hydrocarbon gas present in the produced fluid. By reducing the pressure and temperature of the produced fluid, some of the gas present in the produced fluid is able to condense to a liquid and is separated from the remaining gaseous components in the gas- liquid separator 8. In the gas-liquid separator 8 a proportion of lighter hydrocarbons remain in the gas phase and are separated from heavier hydrocarbons that condense into the liquid phase. Accordingly, the liquid phase will contain the less volatile heavier hydrocarbons and liquid water, whilst the gas phase will contain the more volatile lighter hydrocarbons together with some water vapour. The gas phase may contain substantially (i.e. greater than 70 vol%) hydrocarbons, and can often have a hydrocarbon content of greater than 90 vol%.

The composition of the gas and liquid phases can be controlled by adjusting the temperature and pressure of the produced fluid using the control valve 4 and the cooler 6. Thus, the control valve 4 and the cooler 6 provide control over how the constituents of the produced fluid are separated in the gas-liquid separator 8.

The gas phase is supplied to a compressor 10 via a conduit 9. As shown in Figure 2, the compressor 10 is positioned higher than the gas-liquid separator 8 and the conduit 9 is arranged such that liquid condensing from the gas phase within the compressor 10 and/or the conduit 9 may drain back to the gas-liquid separator 8 under the action of gravity. In other words, the gas-liquid compressor 8 is the local low point of the separator-compressor system. That is to say, the gas-liquid separator 8 acts as a sump to collect liquid that condenses within the conduit 9 and/or the compressor 10.

The gas phase is compressed in the compressor 10 before being passed to the top of the header 1 b via a conduit 11. In one embodiment, the gas is compressed by the compressor to the required gas injection pressure so that the gas can be re-injected into the hydrocarbon well to aid in hydrocarbon recovery. For example, the gas may be compressed to between 200 bar and 450 bar (between 20 MPa and 45 MPa). Alternatively, it is possible that the gas phase could be used to provide lift gas to aid in the extraction of produced fluid from the hydrocarbon well. In this case, the gas phase is compressed to a pressure sufficient to provide gas lift to the subsea hydrocarbon well, for example between 100 and 250 bar (between 10 MPa and 25 MPa).

As can be seen from Figure 2, the compressor 10 is positioned higher than the header 1b, i.e. the header 1b is the local low point of the compressor-header system. The conduit 11 is arranged so that liquid may flow from the compressor 10 to the header 1 b under the action of gravity, thus preventing any liquid in the header 1b from flowing back to the compressor 10. This ensures that any liquid that condenses from the gas phase in the header 1b or the conduit 11 collects in the header 1b. That is to say, the header 1b acts as a sump to collect liquid that condenses in the conduit 11, or indeed in the header 1b itself.

In this example, conduits 12 connect the header 1b to valve trees (not shown) of subsea gas injection wells 13 for re-injection of the gas into the hydrocarbon well. The conduits 12 are initially directed upward from the top of the header 1b before bending downwards towards the subsea gas injection wells 13. For example, the conduits 12 may form an inverted U-bend shape. This configuration ensures that any liquid that collects in the header 1b is not passed to the subsea gas injection wells 13 and also means that condensation forming in the upward portions of the conduits 12 is drained into the header 1b.

Processing of the liquid phase from the gas-liquid separator 8 will now be described with reference to Figures 1 , 3 and 4.

The separated liquid phase is passed from the gas-liquid separator 8 to a flash-gas recovery unit 18 via a conduit 14. A control valve 15 is provided in the conduit 14 to reduce the pressure of the liquid phase that is passed to the flash-gas recovery unit 18. In the flash- gas recovery unit 18, gas is flashed from the liquid phase before being passed back to the gas-liquid separator 8 via conduit 19. This increases the quantity of gas available for reinjection into the hydrocarbon well.

In the example shown in Figure 4, the flash-gas recovery unit 18 comprises a gas- liquid separator 22, a pump 24 and an ejector 26. The pressure of liquid phase from the gas-liquid separator 8 is reduced as it is passed through the control valve 15, causing a reduction in the vapour pressure of the liquid phase and allowing gas to flash from the liquid phase in the gas-liquid separator 22. The remaining liquid phase is then passed from the gas-liquid separator 22 to the pump 24 through conduit 23 to boost the pressure of the liquid phase up to hydrostatic pressure. As shown in Figure 4, the pump 24 is located higher than the inlet of the gas-liquid separator 22.

The liquid phase is then passed to the outlet piping 1c via conduit 20, through which it is transported to one or more sub-sea storage tanks 21. It is preferred that the liquid product is stored under pressure as a semi-stable liquid product, and maintained at a pressure at which hydrates cannot form. For example, the liquid may have a vapour pressure of 1.5-10 bar (150-1000 kPa). As discussed above, the term “semi-stable” is used herein to describe a liquid that has been stabilised to a certain extent, but has not been fully stabilised. For example, in the described subsea gas injection system, the liquid may be stabilised only to a certain extent because the pressure of the liquid state is reduced to a pressure that is greater than atmospheric pressure as it passes through the subsea gas injection system. Thus, the semi-stable liquid product is only in a stable state at ambient temperatures if it is stored at a pressure over a certain pressure level, i.e. greater than atmospheric pressure. Thus, a semi-stable liquid product may be a liquid product that is only in a stable state due to it being under elevated pressure, at ambient temperature or above. The semi-stable liquid comprises some, but not all, of the gas components of the produced fluid. That is to say, the semi-stable liquid comprises some of the components of the produced fluid that would otherwise be gaseous at ambient temperatures, if not for the fact that the liquid is stored at an elevated pressure.

An ejector 26 is used to increase the pressure of the flash gas removed from the gas- liquid separator 22 to the inlet pressure of the gas-liquid separator 8. It is necessary to increase the pressure of the flashed gas since it is at a lower pressure than the gas input into to gas-liquid separator 8 because the pressure of the liquid phase has been further reduced by control valve 15. As an alternative to ejector 26, or in addition, a compressor may be used to increase the pressure of the flash gas. By increasing the pressure of the flash gas, it can be recirculated to the gas-liquid separator 8 and recovered, thereby increasing the quantity of gas available for reinjection.

The ejector 26 uses the energy within the boosted liquid stream to entrain and compress the flash gas to an intermediate pressure. The flash gas is fed to the suction side of the ejector 26 via conduit 25 and a slipstream is taken from the boosted liquid phase in conduit 20 and fed to the ejector 26 via conduit 27. Control of the slipstream is provided by a flow control valve 28 in the conduit 27. By utilising the energy within the boosted liquid stream to compress the flash gas, power requirements of the subsea gas reinjection system are reduced.

All of the components of the flash-gas recovery unit 18 are located higher than the gas-liquid separator 8. In other words, the gas-liquid separator 8 is the local low point of the separator-gas recovery system. As shown in Figure 3, the conduits 14 and 19 are arranged such that any liquid in the conduits 14, 19 drains back to the gas-liquid separator 8 under the action of gravity.

As the gas passes through the system, it can be cooled due to cool ambient seawater temperatures and its pressure can reduce with distance travelled (due to friction).

It is therefore also necessary to consider conditions as the gas phase passes through the system. Liquid may condense from the gas phase due to cooling as the gas phase passes through the subsea gas reinjection system. Cooling can occur, for example, as the gas phase passes through the conduits where the temperature can vary depending on the temperature conditions of the local environment. For example, ambient subsea temperatures in the North Sea are typically in the region of 0-8°C and can drop as low as - 1°C or -2°C at greater depths. Such low ambient temperatures can cause the gas phase to cool as it flows through the conduits. This cooling can cause the water vapour present in the gas phase to condense into liquid water. As the gas phase passes through the system, frictional forces also cause a reduction in the pressure of the gas phase. This can also cause water vapour to condense out of the gas phase into liquid water. Where liquid water is present alongside gaseous hydrocarbons there is the risk that hydrates may form, which could lead to blockages in the subsea gas injection system.

In order to limit the formation of hydrates in the subsea gas injection system, the length of the conduits between the various components is made as short as possible. Typically, the longer the conduit is the colder the gas phase will become as its temperature approaches that of the seawater surrounding the conduit, thereby increasing the risk of hydrate formation. Therefore, in this example, the gas injection system, including the conduits and its various components, is arranged on a skid assembly (i.e. a support frame or platform) having a platform area of 5x5m. In this way, the distances between the components of the gas injection system are relatively small, e.g. on the sale of several meters and at most around 7m, and the conduits fluidly connecting the components can be made short. For example, the conduits may have a length of less than 5m, preferably less than 3m, more preferably less than 2m.

To further reduce the risk of hydrate formation within the conduits, the conduits of the present example are insulated from the surrounding sea water. Similarly, the pipeline 1 may also be insulated to limit formation of hydrates in the pipeline 1. As discussed above, the geometry of the subsea gas injection system is controlled to ensure that any liquid that condenses from the gas phase is drained to an appropriate location, for example the gas-liquid separator 8 or the header 1b. Accordingly, liquid drains towards, and gathers in, the local low points of the subsea gas injection system. In this way, the system may be considered to be self-draining in the sense that no external intervention is required for ensuring the condensed liquid drains to the desired location(s) within the system.

The gas-liquid separator 8 is also arranged so that the bottom of the gas-liquid separator 8 is the low point of the entire subsea gas injection system, i.e. the bottom of the gas-liquid separator 8 is located lower than the compressor 10, the flash-gas recovery unit 18 and the header 1b. This means that any liquid that condenses from the gas phase can be drained to the gas-liquid separator 8 under the action of gravity.

The liquid collecting in the header 1b cannot drain under the action of gravity to the gas-liquid separator 8 via conduits 11 and 9. This is because the compressor 10 is positioned higher than the header 1b and the conduit 11 is arranged so that liquid drains towards the header 1b under gravity. Therefore, a conduit 16 is provided to connect the bottom of the header 1b to the gas-liquid separator 8 and arranged to allow liquid collected in the header 1b to be drained to the gas-liquid separator 8 under the action of gravity. This is can be seen in Figure 2. The flow of liquid from the header 1b to the gas-liquid separator can be controlled by a valve 17 provided in the conduit 16. Accordingly, liquid can be allowed to build up in the header 1b until it is necessary to drain it to the gas-liquid separator. The header 1b may be drained periodically, for example, during shutdown of the subsea gas injection system.

Semi-stable liquid from the outlet of the flash-gas recovery unit 18, i.e. conduit 20, may also be directed to the header 1b and/or the gas-liquid separator 8 to flush the header 1b and/or the gas-liquid separator 8. By definition, gas cannot evaporate from the semi stable liquid at ambient temperatures, therefore by using the semi-stable liquid to flush the system the presence of gaseous hydrocarbons is avoided and thus hydrate formation can be prevented.

It will be appreciated that the geometry of the subsea gas injection system is designed to control the locations within the subsea gas injection system where the liquid condensed from the gas phase collects. This ensures that any liquid water that condenses from the gas phase collects at specific controlled locations. Since gas hydrate formation requires the presence of liquid water, the geometry of the subsea gas injection system means that the risk of hydrate formation is limited to the specific locations where the liquid water collects under the action of gravity. Local hydrate strategies can be implemented at the local low points, i.e. in the gas- liquid separator 8, header 1b and/or the gas-liquid separator 22, to avoid formation of gas hydrates at these locations. For example, a hydrate inhibitor can be controllably injected into the subsea gas injection system in the gas-liquid separator 8, header 1b and/or the gas- liquid separator 22. Such hydrate inhibitors may include methanol, monoethylene glycol (MEG), diethylene glycol (DEG) and triethylene glycol (TEG).

As an alternative to injecting hydrate inhibitor into the header 1b, the liquid collected in the header 1b can be periodically flushed to the gas-liquid separator 8 via conduit 16 to remove liquid water from the header 1b. By removing liquid water from the header 1b, the risk of gas hydrate formation in the header 1b is reduced. Therefore, a specific hydrate strategy, such as injection of hydrate inhibitors, is not required for the header 1b. Instead, it is only necessary to have a local hydrate strategy in the gas-liquid separator 8 to prevent gas hydrate formation in the subsea gas injection system. In other words, because all of the condensed liquid water is sent to the gas-liquid separator 8 there is a reduced risk of hydrates forming in other parts of the subsea gas injection system. This avoids the need to inject hydrate inhibitor into numerous different parts of the subsea gas injection system.

Therefore, the present subsea gas injection system enables the prevention of gas hydrate formation without the need to control of the water dew point of the gas phase. Instead, liquid water that condenses from the gas phase is drained to specific locations within the subsea gas injection system under the action of gravity. Hydrate strategies can be implemented at these specific locations to avoid gas hydrate formation. Consequently, drying of the gas to remove water from the gas phase is not required. This avoids the need to transport the gas phase to and from a separate facility to dry the gas before re-injection of the gas into the hydrocarbon well. Thus, this avoids the need to construct such a gas drying facility and reduces the power consumption of the system. Accordingly, the infrastructure and power requirements for the subsea gas injection system are reduced, leading to lower costs. This also means that the subsea gas injection system can be implemented in more remote or hostile environments where it would be difficult, costly or impossible to construct such a gas drying facility.

Transportation of the gas phase between the injection system and a gas drying facility also requires the gas to be compressed in order to account for pressure loss caused by frictional forces as the fluid passes through the pipeline or conduits. This leads to increased power consumption. Thus, by removing the gas drying step this compression of the gas phase can be avoided and the power consumption of the system can be reduced, leading to improved efficiency.

Claims

CLAIMS:

1. A system for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and one or more conduits fluidly connecting the separation apparatus to the injection apparatus for passing the gas phase from the separation apparatus to the injection apparatus; wherein the separation apparatus is configured to process the produced fluid such that the gas phase is outside the gas hydrate forming envelope for conditions within the system, whereby significant formation of gas hydrates in the system is avoided.

2. The system of claim 1, wherein the separation apparatus comprises a separator for separating the produced fluid into a gas phase and a liquid phase.

3. The system of claim 1 or 2, wherein the separation apparatus comprises a cooler for reducing the temperature of the produced fluid.

4. The system of claim 1, 2 or 3, wherein the separation apparatus comprises a pressure reduction valve for reducing the pressure of the produced fluid.

5. The system of any preceding claim, further comprising a collection sump for collecting liquid that condenses from the gas phase within the system, the collection sump being arranged to collect the condensed liquid under the action of gravity.

6. The system of claim 5, wherein the collection sump comprises the separator of the separation apparatus.

7. The system of claim 5 or 6, wherein the collection sump is fluidly connected to a supply of hydrate inhibitor via a hydrate inhibitor supply line, preferably wherein the hydrate inhibitor supply line comprises a control valve for controlling the supply of hydrate inhibitor to the collection sump.

8. The system of any preceding claim, wherein the injection apparatus comprises a header arranged to collect the gas phase received from the separation apparatus.

9. The system of claim 8, wherein the header is arranged higher in the system than the collection sump, the header being fluidly connected to the collection sump such that liquid may drain from the header to the collection sump under the action of gravity.

10. The system of any preceding claim, wherein the injection apparatus comprises an injection wellhead.

11. The system of claim 10, wherein the header is fluidly connected to the injection wellhead via a conduit having an inverted U-bend shape.

12. The system of any preceding claim, wherein the conduits are arranged such that the gas passing through each conduit is maintained outside the gas hydrate forming envelope for conditions within the conduit.

13. The system of claim 12, wherein a the conduits have a length of less than 10m, preferably less than 5m, and more preferably less than 2m.

14. The system of claim 12 or 13, wherein the system is arranged such that a residence time of the gas within each conduit is less than 30 seconds, preferably less than 10 seconds.

15. The system of claim 12, 13, or 14, wherein the conduits are insulated conduits.

16. The system of any of claims 12 to 15, wherein the conduits are heated conduits.

17. The system of any preceding claim, further comprising a gas recovery unit for extracting a flash gas from the liquid phase.

18. The system of any preceding claim, further comprising a storage facility configured to receive and store the liquid phase.

19. The system of claim 18, wherein the storage facility is located subsea for subsea storage of the liquid phase.

20. The system of any preceding claim, the system being configured to process the produced fluid such that the liquid phase is a semi-stable liquid product.

21. The system of claim 20, wherein the semi-stable liquid product has a true vapour pressure (TVP) of greater than 100 kPa (1 bar).

22. The system of any preceding claim, wherein a majority of the gas phase is hydrocarbon gas.

23. A system for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; and a collection sump for collecting liquid that condenses from the gas phase within the system, wherein the collection sump is arranged such that the condensed liquid drains to the collection sump under the action of gravity.

24. A system for re-injecting produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the system comprising: a separation apparatus for receiving a produced fluid from a hydrocarbon reservoir and separating the produced fluid into a gas phase and a liquid phase; an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and one or more conduits fluidly connecting the separation apparatus to the injection apparatus; wherein each of the one or more conduits is configured such that the gas phase is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided.

25. A method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; and injecting the gas phase into the hydrocarbon reservoir; wherein separation of the produced fluid is such that the gas phase is outside the gas hydrate forming envelope.

26. The method of claim 25, wherein a majority of the gas phase is hydrocarbon gas.

27. A method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; passing the gas phase to an injection apparatus for injecting the gas phase into the hydrocarbon reservoir; and draining liquid that condenses from the gas phase as the gas phase is passed to the injection apparatus to a collection sump under the action of gravity.

28. A method of re-injecting a produced hydrocarbon gas into a hydrocarbon reservoir for supporting the pressure of the hydrocarbon reservoir, the method comprising: separating a produced fluid from a hydrocarbon reservoir into a gas phase and a liquid phase; and passing the gas phase through one or more conduits to an injection apparatus for injecting the gas phase into the hydrocarbon reservoir, wherein each of the one or more conduits is configured such that the gas phase is maintained outside the gas hydrate forming envelope for conditions within the conduit, whereby significant formation of gas hydrates in the conduit is avoided.