GB2586204A

GB2586204A - Controlling the temperature of injection water for reservoir pressure support

Info

Publication number: GB2586204A
Application number: GB1908178.5A
Authority: GB
Inventors: Gotaas Johnsen Cecilie; Sveberg Knut
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2019-06-07
Filing date: 2019-06-07
Publication date: 2021-02-17
Also published as: WO2020246899A1; GB201908178D0

Abstract

A system for supporting the pressure of a subsea hydrocarbon reservoir uses production fluid heat to raise the temperature of seawater which is to be reinjected into the reservoir. The system comprises a production wellhead as an inlet 2 for receiving produced fluid from a subsea hydrocarbon reservoir. Production fluid will pass through separators 21, 28 which lead on to a heat exchanger 14. A seawater inlet and seawater treatment unit 12 is connected to the heat exchanger 14 for heating the seawater by using heat from the produced fluid. The heat exchanger 14 may be subsea on the seabed. Injectors 3a inject the heated seawater into the subsea hydrocarbon reservoir. Production facilities can be topside on an unmanned production platform. Produced hydrocarbons will pass to surface facility through a production riser 17 and may return to subsea storage 11. Warming the injection water reduces risk of thermal fracturing of the hydrocarbon reservoir. Set point temperature for the heated seawater can be determined and the seawater is heated to the set point temperature prior to injection.

Description

Controlling the temperature of injection water for reservoir pressure support The present invention concerns the injection of water into a sub-sea hydrocarbon reservoir in order to support the reservoir pressure. It is particularly useful in (but not limited to) the exploitation of sub-sea oil reservoirs with low overburden. Reservoirs with low overburden are often prone to thermal fracking when water injection methods are applied.

It is well known to use water injection to support reservoir pressure in order to enhance oil recovery from subterranean reservoirs. Doing so allows more oil to be recovered from a reservoir, thereby increasing the recovery efficiency and making marginal wells more economical and attractive for exploitation. Typically, water is injected directly into the reservoir to maintain pressure as fluids are produced from the well.

The processing of the produced fluid recovered from a well usually involves the separation of water from hydrocarbons. This separated 'produced water' must then be disposed of in some manner. It is known to inject the produced water back into the well, or into another well; see WO 2003/086976 for example.

However, during the earlier stages of production in the lifetime of a reservoir, the water content of the produced fluid can be very low. The water content increases with the on-going injection of water into the well for pressure support over time. As a result, very little water is removed in the separation process and there is not enough of this separated produced water to meet the required volume for pressure support via re-injection. Alternative water sources must then be considered. In the case of sub-sea reservoirs, it is common practice to instead inject treated or untreated seawater into the reservoir in order to meet the requirements for pressure support as seawater is freely available at such locations The seawater is typically cold, approximately 0-5 degrees Celsius dependent on location and water depth. If the seawater is treated, its temperature will normally increase only very slightly through any processing, and so it remains relatively cold The injection of seawater into a reservoir can result in an increased danger of thermal tracking, particularly in a reservoir with low overburden. Thermal fracking is a separate phenomenon to high pressure fracking (which is sometimes used to extract oil and gas from a well) and occurs as a result of the temperature of injected fluid, and the thermal gradient that it between the two in the well. Thermal tracking may therefore occur when the injected seawater is much colder than the -2 produced fluid from a well (and the well interior) because when this odder fluid is injected into a reservoir it results in a steep thermal gradient. For example, the rock surrounding part of the reservoir can shrink slightly due to a reduction in temperature relative to another part and this can result in fracturing.

Thermal tracking poses a greater danger in reservoirs with a shallow overburden (i.e. the overlying material), particularly in reservoirs where the reservoir temperature is very different to that of injected water, resulting in a steep temperature gradient. Overburden pressure is equal to the total pressure from the weight of the sediment above the reservoir (rocks, sand etc.) and the weight of the fluids above the reservoir (for example, the water column). With low overburden pressure reservoirs (typically those located relatively close to the sea bed), there is less pressure to "contain" the reservoirs, and cold fluid is more likely to result in thermal fracking. Thermal fracking is undesirable, as it results in lost fluid from the reservoir which is both inefficient and can be damaging to the environment.

Reservoirs with shallow overburden are additionally susceptible to thermal tracking from the injection of cold seawater because the borehole through which the seawater is passed into the subsea reservoir is much shorter than that of a typical reservoir (as there is less overlying material). When typical reservoirs are injected with seawater, the passage of the seawater down the longer boreholes can heat the seawater naturally, and therefore reduces the temperature gradient and the associated danger of thermal fracking; the shallow boreholes of subsea reservoirs with low overburden cannot heat the seawater to the same extent.

A further problems associated with the injection of cold seawater is hydrate or wax precipitation in the reservoir. Hydrates are ice-like crystalline solids composed of water and gas, and hydrate deposition in pipelines is a severe problem in oil and gas production infrastructure. When warm hydrocarbon fluid in the reservoir mixes vvith cold seawater, hydrates and waxes will precipitate and these can reduce the output of the reservoir and adhere to the inner walls of pipelines and other production infrastructure. This reduces the pipeline cross-sectional area, which, without proper counter measures, will lead to a loss OT pressure and ultimately to a complete blockage of the pipeline or other process equipment.

According to a first aspect of the present invention, there is provided a method for supporting the pressure of a subsea hydrocarbon reservoir, the method comprising: providing a produced fluid from a subsea hydrocarbon reservoir; providing seawater; heating the seawater using heat from the produced fluid by means of a heat exchanger; and injecting the heated seawater into the subsea hydrocarbon reservoir.

By heating the seawater prior to injection into the well, the danger of thermal tracking in the well can be reduced. Furthermore, by heating the seawater using heat from the produced fluid, energy which would have otherwise been allowed to dissipate from the produced fluid is utilised, thus preventing the need for another source of heat and avoiding the waste of heat energy already present. This also reduces any possible damage caused by dissipated heat to the environment local to the reservoir.

The method may further comprise separating a hydrocarbon liquid from the produced fluid and heating the seawater using heat from the separated hydrocarbon liquid. Separating of a hydrocarbon liquid from the produced fluid typically comprises additional heating. This additional heat would also otherwise be allowed to dissipate and so the method makes use more, otherwise wasted, energy. The hydrocarbon liquid may typically be an oil product.

The method may further comprise separating produced water from the produced fluid and heating the seawater using the produced water. Similar to above, the separation of water typically comprises additional heating and the additional heat added would otherwise be allowed to dissipate.

The method may alternatively or further comprise a step of separating the produced fluid, wherein the produced fluid flows through the heat exchanger and heats the seawater prior to the separating step. In this way, the produced fluid can be cooled in the heat exchanger prior to separation.

Preferably the seawater is heated to a temperature approaching the temperature of the formation into which it will be injected. However, any significant reduction in the temperature differential will reduce the risk of thermal tracking, Thus, the seawater may be heated to a temperature that reduces or minimises the risk of thermal fracking in the subsea hydrocarbon reservoir. By heating to an optimum temperature to reduce thermal fracking, greater amounts of seawater can be injected into the well without thermal fracking occurring, thus increasing the output of the well.

The optimum temperature depends on the particular formation, but will typically be in the range of 5 to 12'C. As such, dependent on the temperature of the subsea reservoir and other factors, the temperature of the seawater may be raised from approximately 0°C to approximately 5 °C, up to 8°C, or even up to 12° The heat exchanger may be subsea. By having the heat exchanger subsea, the produced fluid and seawater do not need to be brought topside for the heating to be carried out. Furthermore, the produced fluid has to travel a shorter distance to the heat exchanger and so less heat is dissipated from the produced fluid to the surrounding seawater prior to the heating, thereby increasing the effectiveness of the method.

The method may further comprise controlling the flew rate of seawater, hydrocarbon liquid and/or produced fluid through the heat exchanger in order to control the temperature of the heated seawater.

The method may further comprise determining a set point temperature for the heated seawater This may include a target/optimum temperature, a minimum temperature and/or a maximum temperature. By determining set points, the risk of thermal Tracking can be reduced whilst balancing other requirements such as the desired flow rate of seawater injected into the well to support reservoir pressure. The separating of the hydrocarbon liquid from the produced fluid may comprise heating the produced fluid and the heating of the produced fluid may occur topside.

The seawater may be collected from the sea local to the reservoir through an inlet, wherein the inlet may be located on the sea bed. The seawater may be drawn through the inlet by means of a pressure differential created by the subsea injector. Thus, a dedicated pump is not required to collect the seawater.

The method may further comprise storing the separated hydrocarbon liquid in subsea storage after using it to heat the seawater. The present invention is particularly useful in cases where separated hydrocarbon liquid is stored in subsea storage because, over time, the heat energy of the stored fluid dissipates into the surrounding seawater and is therefore wasted. It is therefore advantageous to make use of this heat energy before the hydrocarbon liquid is stored.

The seawater may be treated to meet a predetermined standard for injection into the reservoir.

The method may further comprise mixing separated water with the seawater prior to injection into the subsea reservoir. in this way, a greater flow rate of injected water can be achieved to support reservoir pressure, whilst also disposing of -5..

otherwise waste separated water and (depending on the temperature of the separated water) possibly raising the temperature of the injected seawater further.

At least some separation of the produced fluid may be carried out subsea, and the produced fluid may be separated into a hydrocarbon liquid, a gas fluid product and produced water. This may avoid the need for a separator topside.

However, at least some separation and/or treatment of the hydrocarbon liquid, gas product and/or produced water may carried out topside on a production platform.

According to another aspect of the present invention, there is provided a system for supporting the pressure of a subsea hydrocarbon reservoir, the system comprising: an inlet for receiving produced fluid from a subsea hydrocarbon reservoir; a seawater inlet; a heat exchanger for heating the seawater using heat from the produced fluid; and injectors for injecting the heated seawater Into the subsea hydrocarbon reservoir.

As discussed, by heating the seawater prior to injection into the well, the danger of thermal tracking in the well can be reduced. Furthermore, by heating the seawater using heat from the produced fluid, energy which would have otherwise been allowed to dissipate from the produced fluid is utilised, thus preventing the need for another source of heat and avoiding the waste of heat energy already present. This also reduces any possible damage caused by dissipated heat to the environment local to the reservoir.

The system may further comprise a first flow line cor:figured to receive produced fluid from the inlet, wherein the inlet is a production wellhead for connection to a subsea hydrocarbon reservoir; a production platform configured to receive produced fluid from the first flow line and configured to separate hydrocarbon liquid from the produced fluid; a second flow line that carries the separated hydrocarbon liquid away from the production platform; a third flow line that receives seawater from the seawater inlet, wherein the heat exchanger is arranged to transfer heat from the produced fluid in the first flow line and/or the separated hydrocarbon liquid in the second flow line to the seawater In the third flow line; and an injection wellhead in communication with the third flow line on the seabed, configured to inject the heated seawater into the hydrocarbon reservoir.

The system may further comprise subsea storage configured to receive separated hydrocarbon liquid from the second flow line after the separated hydrocarbon liquid has been used to heat the seawater ir: the third flow line. As -6 -mentioned, the present invention is particularly useful in cases where separated hydrocarbon liquid is stored in subsea storage because, over time; the heat energy of the stored fluid dissipates into the surrounding seawater and is therefore wasted The heat exchanger may be a subsea heat exchanger, in this way the produced fluid and seawater do not need to be brought topside for the heating to be carried out and the produced fluid has to travel a shorter distance to the heat exchanger and so less heat is dissipated from the produced fluid to the surrounding seawater prior to the heating.

The system may further comprise a subsea separator connected to the first flow line and configured to at least partially separate the produced fluid.

The system may further comprise a controller (e.g. a microprocessor-based controller) and the controller and system may be configured to carry out any of the methods described above in relation to the first aspect, preferably under the control of such a controller.

Certain embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Figure 1 is a schematic overview of a subsea hydrocarbon production system according to a first embodiment of the invention; Figure 2 is an enlarged perspective view corresponding to a portion of Figure 1 showing the seawater pumps and treatment systems thereof in more detail; Figure 3 is a schematic fluid flow diagram showing production features, processing and injection features of a second embodiment; and Figure 4 is schematic diagram of a controller and related components used in the embodiments.

The illustrated embodiment of Figure 1 is a subsea hydrocarbon production system 100 in which a subsea separator 101 is provided to separate hydrocarbon-containing fluid produced from local wellheads 102 into an oil product, a gas product and produced water at the sea bed. The system employs enhanced oil recovery, whereby seawater and/or gas are injected into the formation to support its pressure, which may employ separated water and/or seawater. By means of the invention, the injected fluids may be heated in a controlled manner prior to injection using heat from produced fluids. This may be necessary or desirable in order to prevent thermal fracturing ("frocking") of the overburden above the reservoir being caused by the reinjection process.

For this purpose, seawater pumps (not shown) and treatment units 103 are provided at the sea bed to take in seawater local to the units and treat it to a predetermined standard suitable for injection into the subsea reservoir in the known manner. The system further comprises a heat exchanger 104 configured to heat the treated seawater (discussed further below) and injection wellheads 105 for injecting the heated seawater into the subsea reservoir.

The system also comprises subsea storage 106 for storing a hydrocarbon liquid separated from the produced fluid received from the reservoir by separator 101.

In operation, produced fluid is passed from production wellheads 102 along flow lines 107 via pump 108 to the subsea separator 101 The subsea separator is a three phase separator configured to separate the produced fluid into a hydrocarbon liquid, a gas product and produced water. During the early stages of the production lifetime of a subsea reservoir, very little produced water may be separated. The produced fluid from the subsea reservoir is typically much warmer than the seawater local to the reservoir, for example around 25°C.

The hydrocarbon liquid, gas product and produced water are passed from the separator 101 to flow lines 110 111 and 112 respectively. Each of these three flow lines passes up a riser (not shown) to Unmanned Production Platform (UPPTM) 109.

At the UPP 109, the hydrocarbon liquid, gas and oil are further processed, (as will be described further below) and the processed hydrocarbon liquid, gas product and produced water are passed down the riser in flow lines 113, 114 and respectively, back to the sea bed. The processing of the hydrocarbon liquid and produced water raises their temperature to above that of the produced fluid, and thus further above that of the seawater local to the subsea reservoir, to approximately 35 °C for example.

The processed gas product flow line 114 leads to gas injectors (not shown) that inject the gas back into the subsea reservoir in order to support the reservoir pressure. Alternatively, the processed gas product flow line may lead to storage for the gas product or may carry the gas onshore.

Seawater is collected by subsea pump and treatment units 103 which treat the seawater to a predetermined standard in order to be injected into the subsea reservoir. The temperature of the seawater is typically much lower (e.g. approximately 0 degrees Celsius) than that of the produced fluid from the well and -8 -the processed hydrocarbon liquid The treated seawater is passed to heat exchanger 104 through which it flows in a first conduit. The processed hydrocarbon liquid flow line 113 also leads to heat exchanger 104, through which it flows in a second conduit in thermal contact with the first conduit. As such, heat exchanger 104 (which is itself conventional) transfers heat from the processed hydrocarbon liquid to the treated seawater, thus raising the temperature of the treated seawater, for example to between 5 and 12°C. Dependent on the temperature of the subsea reservoir, the temperature of the seawater may be raised from approximately Otto approximately 5 'C. up to 8°C, or even up to 12°C. The temperature to which the seawater is heated is controlled by controlling the flow rate of treated seawater and processed hydrocarbon liquid through the heat exchanger, as will be described further below.

After the processed hydrocarbon liquid has been used to raise the temperature of the treated seawater in heat exchanger 104, it is passed to subsea storage 106, where it is stored and remaining heat slowly dissipates over time. The hydrocarbon liquid is later collected from the storage 106 by a vessel.

When sufficient processed produced water is available for use in reinjection, it may be passed along flow line 115 to be treated at the LIPP 109 to a predetermined standard so that it can also be injected in to the subsea reservoir. It is comingled with the heated seawater at pump 116 prior to injection. The temperature of the comingled water can be controlled by controlling the ratios of the mixed heated seawater and processed produced water.

The water for injection (which may include produced water) is then passed from pump 116 through flow line 117 leading to water injectors 105 that inject the water into the subsea reservoir.

The amount of produced water comingled with the seawater will typically vary over the lifetime of production of the reservoir. During the early stages, the water content of produced fluid will be low, so very little produced water will be separated from the produced fluid. In this case, the temperature of the injected water will be entirely or largely determined by the temperature to which the treated seawater is heated to in heat exchanger 104. However, as time passes, the water content of the produced fluid will generally increase, with the result that more (higher temperature) produced water is available for reinjection. As such, produced water may provide most, if not all, of the heat required and so the heat exchanger 104 may cease to be useful Figure 2 shows the seawater collection and treatment systems in more detail. Here, the subsea seawater pump and treatment units 103 and processed hydrocarbon liquid flow line 113 can be seen connected to the heat exchanger 104.

The processed produced water flow line can be see connected to pump 116 which also received the heated seawater from the heat exchanger 104 and subsequently comingles the heated seawater and processed produced water and passes the comingled water to water injectors via flow lines 117.

A separation, treatment and reinjection process according to a second embodiment will now be described in more detail with reference to Figure 3. This shows components located topside on a UPP above the central horizontal line, with risers and subsea components below the line.

Produced fluid from a number of production wellheads 2 at the sea bed is boosted through multi-phase pump 6 and then passes through flow lines 5a, riser base 7 and production riser conduit 17 to the UPPTm The production riser conduit 17 leads to a first stage, three phase, separator 21 having outlet c;onduits 23 for gas, 24 for oil and 26 for water, (In this embodiment this separator is located topside.) The first outlet is connected to the output from a downstream flash gas compressor 35; which will be discussed below.

The second leads via valve 27 to the input of second stage separator 28. The separators may be gravity separators, cyclone separators or any other separator known in the art. The third outlet conduit leads, via water treatment unit 29 and produced water pump 31, to produced water riser 18, This is connected to a water injection system that will be described further below.

The second stage separator 28 is two-phase, having outlet conduits 44 for gas and 45 for oil. The former is connected to flash gas compressor 35 which has an outlet conduit 43 which connects to gas outlet conduit 23 from the first stage separator and leads to first interstage gas cooler 36 and then to first stage suction scrubber 37. The latter 45 leads via oil product pump 30 and semi-stable crude oil riser 19 to a first conduit within heat exchanger 14 at the sea bed to subsea storage 11, which may be located remotely. (Although for clarity the entire hydrocarbon liquid flow is shown passing through the heat exchanger, in practice a portion of it may flow through a bypass passage.) First stage suction scrubber 37 has an outlet conduit 46 for gas leading to first stage gas injection compressor 38.The outlet conduit from this leads via a second interstage gas cooler 39 to a second stage suction scrubber 40 and a -10 -second stage gas injection compressor 41 which feeds gas inlet riser conduit 20, which leads to the gas injectors 3b at the sea bed.

The suction scrubbers 37, 40 each have outlet conduits 47, 48 for oil that has been scrubbed from the gas. The liquid outlet from the second stage suction scrubber 48 leads back via valve 49 to the first stage scrubber and the outlet from the first stage scrubber 47 leads back via valve 50 to second stage separator 28. Also shown at the sea bed is a water injection system which is fed by both produced water from produced water riser 18 and/or seawater. The seawater is provided by seawater treatment unit 12, which is connected to a mixing valve 16, to which the produced water riser is also connected, via a second conduit of heat exchanger 14. This is connected in turn to water injection pumps 13 and water injectors 3a. In practice, several such treatment units, pumps, etc. may be provided.

Within the heat exchanger 14, the first and second conduits are in thermal contact so that heat may be transferred from the produced hydrocarbon liquid to the seawater.

It should be noted that the production riser conduit 17, produced water riser conduit 18, semi-stable crude oil riser conduit 19 and gas injection riser conduit 20 are all included in the structure of one riser. They are shown separated in Figure 3 merely for clarity.

In operation, after the produced fluid has been lifted through the production riser 17 to the UPPTM 9, it enters first stage separator 21. This holds the hydrocarbon-containing fluid at a pressure of approximately 15 bar and partially separates the fluid into three components primarily consisting of oil, gas, and water respectively in the known manner.

The separated oil is then passed via conduit 24 and valve 27 to second stage separator 28. The separated water is passed through water conduit 25 to water treatment unit 29 and the separated gas is passed through gas conduit 23.

The second stage separator 28 reduces the oil fluid to a pressure of approximately 4 bar, a lower pressure than the first stage separator in order to flash down the oil fluid, thereby releasing gas from within the fluid. This flash gas is separated from the oil fluid such that the oil is conditioned to a level at which it can be transported.

Following this, the oil product is boosted through oil product pump 30, and passed down oil product riser 19 to a first conduit through heat exchanger 14 where it is used to heat seawater (described in more detail below), after which it is exported to subsea storage 11.

In this embodiment, the flash gas produced in second stage separator 2 (at a pressure of 4 bar) is removed from the second stage separator 28 and recompressed to a pressure of 15 bar (the same pressure as the gas removed from the first stage separator 21) in flash gas compressor 35. The flash gas is then recombined with the gas removed via the first stage separator 21 and passed through a first interstage gas cooler 36 in order to cool the gas and remove the resultant heat from the prior compression. In this embodiment, the cooling in each cooler is carried out via a heat exchanging relationship with seawater and/or air.

The combined gas ('the gas") is then passed through first stage suction scrubber 37 in order to remove particulates and condensates from the gas and protect later gas compressors. This improves the performance of later stage gas compressors and other components.

The gas is ten passed through first stage gas injection compressor 38 in order to raise its pressure to 38 bar. The gas is subsequently cooled in second interstage gas cooler 39.

The gas then enters second stage suction scrubber 40 in order to remove any further particulates or condensate before entering a second stage gas Injection compressor 41 that raises the pressure of the gas to 100 bar. The gas is then passed down through gas injection riser 20 via flow lines 5b to gas injectors 3b, where it is re-injected into the reservoir to Support the reservoir pressure.

The water that remains following the separation of the hydrocarbon liquid and gas as described above flows from the base of first stage separator 21 to water treatment unit 29, which ensures that it is suitable for reinjection. Pump 31then pumps the water via produced water riser to the water injection system. There is may be mixed at mixing valve 16 with treated seawater. Where there is a sufficient volume of produced water, the mixing valve may be controlled to ensure that the two streams of water are mixed such that the injected water is at the desired temperature. When there is insufficient produced water for this purpose, the injected water is primarily or entirely sea water which is heated as required by heat exchanger 16. A controller (described below with reference to Figure 4) controls the mixing valve 16 and operation of the heat exchanger 15 based on temperature measurements.

-12 -The operation of the water injection system will now be described in greater detail.

In the early stages of the lifetime of a reservoir, the produced fluid will typically comprise mostly hydrocarbons and so very little water will be separated from the produced fluid. In order to satisfy the demand of water required for injection into the subsea reservoir to support its pressure, seawater is taken in from the surroundings of subsea seawater pumps and treatment units 12 that are located on the seabed. This seawater is treated at subsea seawater treatment unit 12 in order to meet the conditions required for re-injection into the subsea oil reservoir.

Normally; oil and particles are removed from the water to below a predetermined level to meet requirements dictated by the reservoir conditions. Typically, sulphate is removed to below 20 ppb, along with sonic salts if necessary.

The treated seawater is then passed to heat exchanger 14, where it is heated using the processed hydrocarbon liquid from the UPPTM 9. The temperature that the seawater is heated to is controlled by altering the flow rate of the heated seawater and/or the processed hydrocarbon liquid through the heat exchanger 14. For example, for a set flow rate of produced oil (i.e. the maximum flow rate in order to maximise the production from the system) a lower flow rate of seawater will result in a higher temperature than a higher flow rate as a given amount of heat from the processed hydrocarbon liquid is applied to a smaller volume of water.

Separated water from first stage separator 21 is conditioned at water treatment unit 29 in order to meet the conditions required for re-injection into the subsea oil reserve, as discussed above This produced water is then pumped through produced water pump 31, and passed down produced water riser conduit 18. The produced water is then comingled with the heated seawater at location 16 and the comingled water is pumped via pump 13 to water injectors 3a for injection into the subsea reservoir in order to support reservoir pressure.

The controlling of the temperature of the mixed water is carried out using a controller such as that shown in Figure 4, which will now be described in more detail.

Controller 51 receives temperature readings from temperature sensors Ti and T2. Ti provides a reading of the temperature of the seawater after it has been treated to meet predetermined injection standards and T2 provides a temperature reading of the processed hydrocarbon liquid after it has been processed at the tiPPTM. 13 -

Controller 51 also receives input(s) that include a set point (target) temperature for the heated seawater, and may also include a minimum temperature and/or a maximum temperature for the heated seawater (i.e. the minimum or maximum possible temperature when taking into account the danger of thermal tracking); a desired flow rate for the heated seawater in order to support reservoir pressure; and/or a minimum and maximum flow rate. These variables for the input could be entered by an operator, or may be calculated by the controller based on parameters of the reservoir and/or fluids. The controller may also receive additional variables such as a feedback temperature of heated seawater; a flow rate of treated seawater; and/or a temperature of the subsea hydrocarbon reservoir.

Processed hydrocarbon liquid passes through valve 52, located in its flow path to the heat exchanger, to meter M1 Treated seawater passes through valve 53, located in its flow path to the heat exchanger, to meter M2.

Based on the temperature readings, input(s), and any other additional variables the controller receives, the controller determines what the set POint temperature of the seawater for injection. Based on this set point, the controller then determined the flow rates of the treated seawater and processed hydrocarbon liquid required to pass through the heat exchanger 14 in order to heat the seawater to the optimum temperature. (Hydrocarbon liquid that is not required for heating purposes may be directed around the heat exchanger via the bypass passage mentioned above.) Based on the determined flow rates, the controller then operates metering units IVI, and M2 to alter the flow rate of the processed hydrocarbon liquid and seawater respectively. The processed hydrocarbon liquid and seawater then both pass into heat exchanger 14 where they are in a heat exchanging relationship with one another and heat is transferred from the warmer processed hydrocarbon liquid to the colder treated seawater. The heated seawater the leaves heat exchanger 14 and is pumped via pump 13 to water injectors to be injected into the subsea hydrocarbon reservoir. The processed hydrocarbon liquid leaves the heat exchanger 14 and is pumped into subsea storage 11.

If produced water is separated from the hydrocarbon and comingled with the heated seawater, other inputs to the controller that are used for determining the flow rates and/or optimum temperature of the heated seawater may include the temperature of the produced water and/or the flow rate of the produced water. The -14 -controller may then adjust the temperature by controlling mixing valve 13 in a manner analogous to that described in relation to its control of the heat exchanger.

If the seawater is further, or alternatively, heated with the produced fluid from the wellhead additional inputs to the controller may include a temperature of the produced fluid from the subsea reservoir and/or a flow rate of the produced

Claims

-15 -CLAIMS1. A method for supporting the pressure of a subsea hydrocarbon reservoir, the method comprising: providing a produced fluid from a subsea hydrocarbon reservoir; providing seawater; heating the seawater using heat from the produced fluid by means of a heat exchanger; and injecting the heated seawater into the subsea hydrocarbon reservoir.
2. The method of claim 1, comprising separating a hydrocarbon liquid from the produced fluid and heating the seawater using heat from the separated hydrocarbon liquid.
3. The method of claim 2, wherein the separating of the hydrocarbon liquid from the produced fluid comprises heating the produced fluid, wherein the heating of the produced fluid preferably occurs topside.
4. The method of claim 2, wherein the hydrocarbon liquid is an oil product
5. The method of claim 1, comprising separating produced water from the produced fluid and heating the seawater using the produced water.
6. The method of claim 1, further comprising a step of separating the produced fluid, wherein the produced fluid flows through the heat exchanger and heats the seawater prior to the separating step
7. The method of any preceding claim, wherein the seawater is heated to a temperature that reduces or minimises the risk of thermal tracking in the subsea hydrocarbon reservoir.
8. The method of any preceding claim, wherein the heat exchanger is subsea,.
9, The method of any preceding claim, wherein the method further comprises controlling the flow rate of seawater, hydrocarbon liquid and/or produced fluid through the heat exchanger in order to control the temperature of the heated seawater.
10. The method of any preceding claim, wherein the method further comprises determining a set point temperature for the heated seawater and wherein the seawater is heated to approximately the set point temperature prior to injection
11. The method of any preceding claim, wherein the seawater is collected from the sea local to the reservoir through an inlet and wherein the inlet is preferably located on the sea bed.
12. The method of any preceding claim, further comprising storing separated hydrocarbon liquid in subsea storage after using it to heat the seawater.
13. The method of any preceding claim, wherein the seawater is treated to meet a predetermined standard for injection into the reservoir
14. The method of any preceding claim, wherein the method further comprises mixing separated water with the seawater prior to injection into the subsea reservoir.
15. The method of any preceding claim, wherein at least some separation of the produced fluid is carried out subsea, and wherein the produced fluid is separated into a hydrocarbon liquid, a gas product and produced water.
16. The method of any preceding claim, wherein at least some separation and/or treatment of the hydrocarbon liquid, gas product and/or produced water is carried out topside on a production platform.
17. A system for supporting the pressure of a subsea hydrocarbon reservoir, the system comprising: an inlet for receiving produced fluid from a subsea hydrocarbon reservoir; a seawater inlet for receiving seawater from the sea; --17 -a heat exchanger for heating the seawater using heat from the produced fluid' and injectors for injecting the heated seawater into the subsea hydrocarbon rvoir.
18. A system as claimed in claim 17, further comprising: a first flow line configured to receive produced fluid from the inlet, wherein the inlet is a production wellhead for connection to a subsea hydrocarbon reservoir; a production platform configured to receive produced fluid from the first flow line and configured to separate hydrocarbon liquid from the produced fluid; a second flow line that carries the separated hydrocarbon liquid away from the production platform; a third flow line that receives seawater from the seawater inlet,, wherein the heat exchanger is arranged to transfer heat from the produced fluid in the first flow line and/or the separated hydrocarbon liquid in the second flow line to the seawater in the third flow line; and an injection wellhead in communication with the third flow line on the seabed, configured to inject the heated seawater into the hydrocarbon reservoir.
19. The system of claim 18, wherein the system funher comprises subsea storage configured to receive separated hydrocarbon liquid from the second flow line after the separated hydrocarbon liquid has been used to heat the seawater in the third flow line,
20. The system of claim 18 or 19, wherein the heat exchanger is a subsea heat exchanger.
21. The system of any of claims 18 to 20, wherein the system further comprises a subsea separator connected to the first flow line and configured to at least partially separate the produced fluid
22. The system of any of claims claim 18 to 21, wherein the system further comprises a controller and the controller and system are configured to carry out the method of any of claims Ito 17.