GB2578148A - Optimized water quality injection strategy for reservoir pressure support - Google Patents

Abstract

A method for supporting the pressure of a subsea hydrocarbon reservoir comprising: recovering produced fluid from the reservoir; separating produced water from the produced fluid; providing seawater; mixing the produced water and the seawater at a determined ratio in order to provide mixed water having a desired temperature; and injecting the mixed water into the subsea hydrocarbon reservoir. Provides a wide range of target temperatures between that of seawater and the produced water. A system for supporting reservoir pressure comprises production 2 wellheads and water 3a and gas injectors connected to an unmanned production platform 9 having processing equipment and a seawater treatment unit 12. A controller controls mixing and reinjection which may account for factors such as the temperature of the reservoir and anticipated produced water flow rate. The ratio and flow rate of mixed waters may change during the process. Provides a way to dispose of produced water and minimise risk of thermal fracking especially in low, temperature, low overburden reservoirs given that produced water is typically heated during separation and processing where heat exchangers are not practicable.

Description

Optimized water quality injection strategy for reservoir pressure upport The present invention concerns a system for the injection of water into as 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.

In the art, 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 of 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 force oil from the formation arid out of a production well. In the case of sub-sea reservoirs, it is common practice to inject seawater directly into the reservoir to achieve this effect as seawater is freely availabie at such locations.

The processing of the produced fluid recovered from a well usually involves the separation of water and oil. 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 20031086976 for example. This provides a useful means for disposing of the produced water whilst also supporting reservoir pressure. This is particularly common at offshore locations, as otherwise the produced water must often be treated to meet strict environmental standards in order to be released into the sea The inventors of the present invention have recognised that the injection of produced water into a reservoir can result in an increased danger of thermal fracking. particularly in a reservoir with low overburden. During conventional separation and processing methods, the produced fluid from the well is typically heated. This heat is retained by the produced water that is re-injected into the reservoir, and when this warmer fluid is injected into a reservoir it can result in thermal fracking. Thermal tracking is fracturing of the formation that occurs as a result of the temperature of injected fluid.

This is a greater danger of thermal fracking in reservoir with low overburden, particularly in reservoirs where the reservoir temperature is low. Overburden is related to the pressure or stress imposed on a reservoir by the weight of overlying material, 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 (typically shallow) reservoirs; there is less pressure to "contain" the reservoirs, and warm fluid more likely to result in thermal fracking. Thermal fracking is undesirable, as it results in lost fluid from the well which is both inefficient and can be damagina to the environment.

The use of heat exchangers to lower the temperature of produced water, for example via a heat exchange relationship with seawater, is often not practicable (particularly at remote and marginal wells) due to the large size of heat exchangers required to achieve a substantial temperature drop and the associated supporting structures.

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 recovering produced fluid from a subsea hydrocarbon reservoir; separating produced water from the produced fluid, providing seawater; mixing the produced water and the seawater at a determined ratio in order to provide mixed water having a desired temperature; and injecting the mixed water into the subsea hydrocarbon reservoir The present invention is based upon the inventors' realisation that a combination of produced water with seawater is a practical and effective way to lower the temperature of the injected (mixed) fluid, as seawater is typically of 'a much lower temperature than the produced fluid and therefore reduce the risk of thermal fracking. In many cases, it is useful to inject fluid that is of as low a temperature as possible, The inventors have also realised that it is advantageous to be able to control the temperature of the fluid injected, as well as the exact amount and ratio of produced water and seawater that is mixed prior to injection Thus, a desired temperature may be determined and the produced water and seawater may be mixed accordingly This means that one can optimise the water injection process for any given well, thereby minimising risks such as thermal fracking, whilst still disposing of produced water efficiently and maximising well output.

In another aspect of the present invention, there is provided a syste supporting the pressure of a subsea hydrocarbon reservoir, the system comprisin a production wellhead for connection to a subsea hydrocarbon reservoir; a production platform configured to receive produced fluid from the wellhead and configured to separate produced water from the produced fluid; a flowline configured to carry the produced water away from the production platform; a subsea pump configured to take in seawater and pass it into the flowline such that the seawater and produced water mix; a controller configured to control the ratio of seawater to mixed water; and an injection wellhead in communication with the flowline and on the seabed, configured to inject the mixed seawater and produced water into the hydrocarbon reservoirs.

As discussed in relation to the first aspect, the ratio of produced water to seawater may be determined ratio in order to provide mixed water having a desired temperature.

Accordingly, the present invention is able to alter the mixing ratio of treated seawater and produced water in a controlled way in order to achieve a target temperature. The controlling of the mixing ratio of produced water to seawater can be used to achieve a wide range of target temperatures, ranging from the temperature of the seawater up to the temperature of the treated produced water. For example the temperature of the injected water could be selected to match the temperature of the reservoir.

In any of the above aspects of the present invention, the ratio of the produced water to seawater may be determined in order to minimise the risk of thermal tracking in the subsea hydrocarbon reservoir and a controller may be used to determine the ratio. The controller may comprise data processing apparatus and may have means for inputting the desired (target) temperature (or for calculating it) and means for outputting control commands such as signals for controlling valve actuators. It may also have input means for receiving flow rate information and/or sensed temperature data from the produced water, seawater and/or mixed water streams.

In determining the ratio, the controller may take into account a target temperature of the mixed water. This target temperature may be based upon the associated risk of thermal fracking in the subsea hydrocarbon reservoir.

The controller may also take into account a temperature of the produced water, and a temperature of the seawater provided. These temperatures could be measured with sensors such as thermocouples in the respective flow lines providing these fluid streams. -4 -

The controller may also determine or take into account a range of possible temperatures the mixed water could take. For example, it could determine a minimum possible temperature achievable with the mixture of water, and a maximum allowable temperature to be injected into the well before a risk of thermal 5:racking occurs.

The controller may also take into account the flow rate of the produced water recovered from the produced fluid; for example, by anticipating chancres in the water content of the well output during its lifetime.

The controller may also determine a target flow rate. This target flow rate may be the flow rate required to maximise well output. in addition to this, the controller may determine a maximum or minimum flow rate allowable. The minimum flow rate could be the flow rate required to maintain pressure in the reservoir and the maximum may be the limit at which hydraulic tracking begins to pose a risk.

The controller may also take into account the pressure or the temperature of the subsea hydrocarbon reservoir.

In the second aspect of the present invention, the system may be provided with means for measuring any of the above variables. Alternatively, any of the above factors could also be determined and/or input to the controller by an operator.

In any of the above embodiments, the seawater may be collected from the sea local to the reservoir by a subsea pump. This subsea pump may be in any convenient location, e.g. at the platform, but is preferably located on the sea bed, thereby reducing the amount of equipment that must be provided on a platform local to the reservoir. With less equipment required on a platform, smaller (preferably unmanned) platforms may be utilised which are more cost-effective and easier to install, particularly in remote locations.

The ratio at which the produced water and seawater is mixed may change during the injection process. For example, the mixing ratio may change in response to a change in any of the above-mentioned variables. The flow rate of the injected mixed water could also be altered during the injection process.

The produced water, the seawater and/or the mixed water may be treated to meet predetermined standards prior to injection into the subsea hydrocarbon reservoir. These predetermined standards may vary depending on the reservoir, but typically the shallower overburden a reservoir has, the stricter the requirements -5 -for injection. These requirements could include the removal of oil in the water, the filtering of particle size and concentration, and the temperature.

This treatment may be carried out at a subsea treatment system, which may be located on the seabed; again, thereby reducing the amount of equipment that must be prowled on a platform local to the reservoir Alternatively, this treatment may be carried out on a platform, preferably an unmanned production platform (UPPTNI). The separating of produced water may be also carried out on an UPPTM local to the subsea hydrocarbon reservoir.

The separation of the produced water and oil from the hydrocarbon containing fluid may be carried out by any known means. This could include a two phase and/or a three-phase separator.

Although the invention may be carried out using a conventional manned production platform, since only limited processing of the produced fluid is required, an unmanned production platform (UPPTM) is both suitable and preferred. The use of an UPPTM greatly improves the commercial viability of producing a marginal reserve.

The produced fluid may be processed to produce an oil and/or a gas product that is exported to a host (e.g. a remote platform or vessel). This processing may also take place on an UPPIrm.

Multiple streams of mixed water may be produced for injection, each of which may have a different ratio of produced water to seawater. In this way, the injection process can be tailored for a number of different wells. This is advantageous as at a subsea reservoir there are typically a number of different wells and wellheads, each of which may have different characteristics (including depths and overburden). Normally, one centralised system is used for preparing the fluid to be injected into these wells and so It is important to be able to tailor the injected fluid to reduce the risk of thermal tracking in each of the wells, particular the well with the weakest overburden strength.

Part of a gas product may also be re-injected into the subsea reservoir in order to further support the pressure of the reservoir and/or used as a gas-lift to support the flow of hydrocarbons from the well bore up the riser to the platform/topside facility.

Part of a gas product may also be combusted at a platform or UPPTM local to the well in order to meet power requirements. For example, in order to power the water treatment or water injections systems. -6 -

The invention also extends to software contigured to cause a data processing device (controller) to control an apparatus as described above in order to perform the method(s) described above.

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 an overview of one embodiment of the present invention local to a sub-sea oil reservoir; Figure 2 is a schematic fluid flow diagram showing the production features. processing features (on a local Unmanned Production Platform), and injection features of an embodiment of the present invention; and Figure 3 is a schematic diagram of a controller that may be used with an embodiment of the present invention.

The illustrated embodiment of Figure 1 is a subsea hydrocarbon production system in which a sub-sea hydrocarbon reservoir has a local Unmanned Production Platform 9 (UPP-Fm). This provides systems that separate hydrocarbon-containing fluid produced from local wellheads 1 into an oil product, a gas product and produced water. The illustrated embodiment also has subsea seawater treatment unit 12 and other subsea components, such as pumps and flow lines, as will be discussed below.

Wellheads 1 are shown on the seabed in communication with a subsea hydrocarbon reservoir (not shown). The wellheads comprise (hydrocarbon) producers 2, water injectors 3a and gas injectors 3b. Producers 2 are connected via flow lines 5a, subsea multiphase pumps 6 and riser base 7 to a riser 8, which provides multiple fluid flow conduits to and from UPPTM 9.

Extending away from the riser base 7 along the seabed is long distance pipeline 10, which extends to a remote host 11. in the form of a tanker vessel 11.

The UPPTM 9 is a floating platform anchored to the seabed. It provides various facilities for treating hydrocarbon-containing fluids (hereinafter also referred to as the produced fluid). These include a separation system 16, which is illustrated in Figure 2 The produced fluid recovered from the reservoir is a mixture including oil, water, and natural gas. It is produced from the reservoir in the conventional manner at the producers 2. It then passes through flow lines 5a and is boosted through the subsea multiphase pumps 6 to riser base 7. The hydrocarbon-containing fluid is then lifted through a conduit in riser 8 to UPP'm g -7 -At the UPP"" the hydrocarbon-containing fluid is separated into constituent parts -oil, gas, water, sediments, etc. by separator 16 -as will be described in more detail below with reference to Figure 2. The oil is then transported via riser '8 and riser base 7 to a long distance pipeline 10 on the seabed.

The aas separated from the hydrocarbon-containing fluid is conditioned at the UPPIM 9 so that it may be used for gas injection back into a subsea oil reservoir, either the same reservoir from wnich the hydrocarbon containing fluid is recovered or a different reservoir. After conditioning, the gas passes through a conduit in riser 8, via riser base 7 and flow lines 5b to injectors 3b, where it is injected into a reservoir, or a number of different reservoirs with different overburdens.

In the illustrated embodiment, some of the gas is used as fuel for power generation at the UP'PTM 9. This is carried out by gas turbine or gas engine (or dual fuel engine) power, production unit 15 in which the gas (containing shoil-chain hydrocarbons, i.e. natural gas) is combusted to generate power. Such electrical power production may be used to meet some, or all, of the power demand at the reservoir.

In a variant of this embodiment, instead of using the gas for injection into a reservoir. it is also conditioned at the UPPTM 9 (separately from the oil). such that it car be transported in an additional long-distance pipeline (not shown) extending to host 11. This further improves the economic sustainability of the reservoir.

The water separated from the hydrocarbon: containing fluid is treated and conditioned at the UPPT" 9 by produced water treatment system 14 to the required standard determined by reservoir conditions, such that it can be re-injected into the reservoirto support its pressure. This treated water passes from the UPP1m, down through a conduit in riser 8 via riser base 7, into flow lines 5c. It is then mixed with seawater from seawater treatment unit 12 and then flows to water injection pumps 13 and then water injectors 3a.

The separation and produced water treatment process is tailored to have specific injection qualities depending on reservoir requirements. The water could be tailored depending on tracking requirements in the reservoir, for pressure support, or treated to an ultrapure quality to meet environmental standards, for example. However, the main requirement is that the treatment allows the produced water to be re-injected into the, reservoir via water injection pumps 13. -8 -

Some of the water recovered from the hydrocarbon-containing fluid may be treated at the UPPTM 9 to a level that allows a to be released into the sea, if the quantity of produced water was in excess of that which is required for injection for example.

The processing temperature of the liquids (oil/water separation and produced water treatment at the UPPTM 9) is mainly governed by the reservoir temperature, typically ranging from about 20°C upwards but heat may typically be added to the liquids for optimal processing temperature.

Seawater is taken in by subsea seawater treatment unit 12, where it is also treated to a standard such that it can be injected into the reservoir to support its pressure. This treated water passes from the subsea seawater treatment unit 12, is mixed with the produced water, (As noted above, the mixed water then flows via flow lines Sc to water injection pumps 13 and water injectors 3a where it is injected into the subsea reservoir) The flow diagram of Figure 2 schematically shows the separation and processing features of the local UPPTM 9 in greater detail along with the water treatment and subsea components of the embodiment, some of which have been described already with reference to Figure 1. Thus, produced fluid from a number of producers 2 is boosted through multi-phase pump 6 and then passes through flow lines 5a, and riser base 7 and production riser conduit 17 to the UPPTm (which houses the components shown above the central horizontal dividing line). Also shown are certain water injection components, including water injection pumps 13, which are fed with a mixture of produced water by produced water riser 18 and seawater from seawater treatment 32, and water injectors 3a In addition, gas injectors 3b are shown connected to gas injection riser conduit 20.

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 riser 8 (see Figure 1). They are shown separated in Figure 2 merely for clarity.

The production riser conduit 17 leads to a first stage, three phase, separ or 21 having outlet conduits 23 for gas, 24 for oil and 26 for water. The first 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 eatment unit 29 and, produced water pump 31, to produced water riser 18.

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 30 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 the long distance pipeline 10 leading to host/storage 11 (see Figure 1).

First stage suction scrubber 37 has an outlet conduit 48 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 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 of 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.

After the produced fiuid has been lifted through the production riser 17 to the UPPDA 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, after which it is exported to the host along subsea long-distance export lines 10.

In this embodiment, the flash gas produced in second stage separator 28 (at a pressure of 4 bar) is removed from the second stage separator 28 and -10 -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 resuitant 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 then passed through first stage gas injection compressor 38 in order to raise its pressure to 35 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 final pressure before re-injection into the subsea reservoir.

The gas at 100 bar 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 injection process of the embodiment of the present invention will now be described in greater detail.

The 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. Normally, oil and particles are removed from the water to below a predetermined level to meet requirements dictated by the reservoir conditions or environmental requirements if disposal to sea occurs. Typically, sulphate is removed to below 20 ppb, along with some salts if necessary. This produced water is then pumped through produced water pump 31, and passed down produced water riser conduit 18.

Seawater is taken in from the surroundings of the subsea seawater treatment 12 that is 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. The treated seawater is then mixed with the produced water from produced water riser conduit 18 in a conduit that leads to water injection pumps 13.

The treated seawater and produced water are selectively mixed to control the temperature of the combined water that then passes through water injection pumps 13 to water injectors 3a where it is injected into the subsea oil reservoir in order to support reservoir pressure.

The ratio of the mixed water, and therefore its temperature, is carefully controlled and selected to minimise the danger of thermal franking in the reservoir when the water is injected. The temperature of the seawater is typically much colder than that of the produced water (which may have been heated as part of the processing of the hydrocarbon containing fluid, or treatment of the water prior to injection) and so by mixing it with the produced water, the overall temperature of the injected water is lowered.

The above embodiment alters the mixing ratio of treated seawater and produced water in a controlled way in order to achieve a target temperature. It is typically advantageous to lower the temperature of this injected water as much as possible to avoid the danger of thermal Stacking. However, the controlling of the mixing ratio could be used to achieve a wide range of target temperatures., ranging from the temperature of the seawater up to the temperature of the treated produced water.

The controlling of the temperature of the mixed water may be carried out using a controller such as that shown in Figure 3, which is described in more detail below.

Controller 51 receives temperature readings from temperature sensors Ti arid 12; T1 provides a reading of the temperature of the produced water after it has been treated to meet predetermined injection standards and T2 provides a temperature reading of the seawater after it has been treated to meet predetermined injection standards.

Controller 51 also receives an input. This input includes a target temperature for the mixed water, and may also include a minimum temperature and/or a maximum temperature for the mixed water, a desired flow rate for the mixed water, and/or a minimum and maximum flow rate. These variables for the input could be entered by an operator. The controller may also receive additional variables such as a feedback temperature of mixed water; a flow rate of produced water; and/or a temperature of the subsea hydrocarbon reservoir.

-12 -Treated produced water passes through valve 52 to meter M, Treated seawater passes through valve 53 to meter M2.

Based on the temperature readings, input, and any other additional variables the controller receives, the controller determines what the optimum ratio at which the seawater and produced water should be mixed in order to produce mixed water with the required temperature (and other relevant properties).

Based on the determined ratio, the controller then operates metering units M1 and M2 to alter the flow rate of the produced water and seawater respectively. The produced water and seawater then pass into conduit 54 where they are mixed at the determined ratio prior to reaching water injection pumps 13. The mixed water is then injected into the subsea hydrocarbon reservoir via water injectors 34 in order to support reservoir pressure.

Claims (4)

1. CLAIMSA method for supporting the pressure of a subsea hydrocarbon resensoir, the method comprising: recovering produced fluid from a subsea hydrocarbon reservoir; separating produced water from the produced fluid; providing seawater; mixing the produced water and the seawater at a determined ratio in order provide mixed water having a desired temperature; and injecting the mixed water into the subsea hydrocarbon reservoir.
2. 2. A method according to claim 1, wherein the ratio of the produced water to seawater is determined in order to minimise the risk of thermal fracking in the subsea hydrocarbon reservoir.
3. A method according to claim 1 or 2, wherein a controller determines the ratio at which the produced water and seawater are mixed.
4. 4. A method "according to any preceding claim, wherein the controller takes into account any one or a combination of the following: a target temperature of the mixed water, a temperature of the seawater prior to mixing; a temperature of the produced water prior to mixing; a maximum and/or minimum temperature of the mixed water; a target flow rate of mixed water; a maximum and/or minimum flow rate of mixed water; a feedback temperature of mixed water; an amount of produced water recovered from the produced fluid; a temperature of the subsea hydrocarbon reservoir; a pressure of water mixed water to be injected.

   A method according to any preceding claim wherein the seawater is collected from the sea local to the reservoir by a subsea pump, wherein the pump is preferably on the sea bed.

   -14 -10 12. 14.

   A metnod according to any preceding claim, wherein the ratio of produced water to seawater is changed durino the injecting.

   A method according to any preceding claim, wherein any one or a combination of: the produced water; the seawater; and the mixed 'water is treated to meet a predetermined standard for injection into the reservoir and/or wherein some of the produced water is treated to meet a standard for releasing into the sea and some of the treated produced water is released into the sea A method according to claim 7, wherein the treatment of the produced water and/or seawater occurs at a subsea treatment system, preferably at a subsea treatment system on the sea floor.

   A method according to any preceding claim, wherein the separating of the produced water is carried out on an unmanned production platform (UPP) or at a subsea treatment system, preferably on the sea floor.

   A method according to any preceding claim, wherein the produced fluid is further processed to produce an oil product and/or a gas product that is exported to a host.

   A method according to any preceding claim, wherein multiple streams of mixed water are produced for injection, each of which may have a different ratio of produced water to seawater.

   A method according to any claim 10, wherein at least part of the gas product is re-injected into the subsea hydrocarbon reservoir.

   A method according to claim 10 or claim 12, wherein, electrical power is generated for use local to the well by combusting at least part of the gas product.

   A system for supporting the pressure of subsea hydrocarbon reservoir, the system comprising: a production wellhead for connection to a subsea hydrocarbon reservoir; a production platform configured to receive produced fluid fr m the wellhead and configured to separate produced water from the produced fluid; a flowline configured to carry the produced water away from the production platform; a subsea pump configured to take in seawater and pass he flow ine such that the seawater and produced water mix; a controller configured to control the ratio of seawater tomixed; water,and an injection wellhead in communication with the flowline and on the seabed, configured to inject the mixed seawater and produced water 1,5 into the hydrocarbon reservoir.

   15, The system of claim 14, wherein the ratio of produced water to seawater is determined ratio in order to provide mixed water having a desired temperature.

   16, The system of claim 14 or 15, confconfigured to carry out the method of any of claims', to 13.