Fluid flow conditioning

Abstract

A flow conditioning unit, FCU 1, for conditioning a multiphase fluid. The FCU may be used in conditioning multiphase fluid from a wellhead containing an oil and water liquid phase and a hydrocarbon ga

Description

TECHNICAL FIELD The present invention relates to the conditioning of multiphase flows in subsea processing systems. In particular, embodiments of the present invention relate to fluid conditioning units for conditioning a multiphase fluid, fluid processing systems for transporting a multiphase fluid, fluid processing systems for producing a single metered multiphase fluid flow from a plurality of multiphase fluid flows, methods for conditioning multiphase fluids, methods for producing a single multiphase fluid from a plurality of multiphase fluid flows, and methods for transporting a multiphase fluid in a subsea processing system. BACKGROUND Multiphase fluids are fluids comprising fluids in both a liquid phase and a gaseous phase. The transport of multiphase fluids along a pipeline can pose a number of challenges, particularly when the ratio of the liquid phase to the gaseous phase in the fluid may be variable (e.g. due to extraction or production of the multiphase fluid). Sudden increases in the liquid phase of the multiphase fluid cause “slugs” or “surge waves”. A slug is a liquid plug completely bridging the cross-section of the flowline, whilst a surge wave is a liquid wave that only partially bridges the cross-section of the flowline. Such fluctuations in the liquid content of a multiphase fluid are especially challenging when a multiphase fluid is to be compressed by a subsea compressor for transport. Liquids are essentially incompressible and much denser than gases. Conventional compressors are designed to handle single-phase gas. This introduces a need for the gas being completely separated from the liquid before being compressed. Traditionally, this is achieved by using a scrubber upstream of the compressor to remove liquids from the well stream. The liquid phase is reintroduced into the main pipeline downstream of the compressor, such that it mixes back into the compressed gas phase. In order to achieve this functionality, a liquid pump is used to pump the liquids from the scrubber liquid outlet towards the gasliquid mixing point downstream the compressor. These systems can be large and expensive due to the various components they require. More recently, there has been a focus on using multiphase compressors in combination with pipe-based flow conditioning units in place of conventional scrubbers and conventional single-phase compressors. Multi-phase compressors compress a multiphase fluid wherein the liquid content of the mixture is within a certain range. However, if the compressor ingests a “slug” of liquid (so that the liquid content is well above that range), the load imposed on the compressor, i.e. the torque required to drive the compressor, can increase dramatically (i.e. abruptly, or rapidly in a short period of time) and lead to damage of the compressor. Accordingly, whilst it is no longer necessary to remove all liquid from gas provided to the compressor, it remains necessary to control the liquid content of the fluid being compressed. The transport of multiphase fluids is pertinent to the subsea processing of hydrocarbon streams. Hydrocarbon streams are typically multiphase fluids comprising an intermixed flow of a liquid phase including oil and water and a hydrocarbon gaseous phase. Hydrocarbon streams can be pressurised by subsea compression plants to permit long-distance pipeline transport of the hydrocarbon stream from a subsea location in a subsea processing system. These subsea locations are generally linked to hydrocarbon production host platforms that receive hydrocarbons from a well(s). It is desired to provide a number of improvements and optimisations to the transportation of multiphase fluids. SUMMARY Viewed from a first aspect, there is provided a flow conditioning unit, FCU, for conditioning a multiphase fluid. The FCU comprises: a main pipeline having an inlet portion arranged to receive a multiphase fluid flow; a gas extraction portion arranged to remove gas content from the main pipeline; a liquid reservoir arranged to receive liquid content from the main pipeline; and a gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow; wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer; and wherein the liquid reservoir comprises at least one bend portion. By accommodating for surges of liquid present in an incoming multiphase fluid flow using a liquid reservoir, a conditioned flow rate of liquid can be provided to a gas-liquid mixer such that a conditioned multiphase fluid flow is produced. As such, the conditioned multiphase fluid flow can be stabilised. This may be of benefit when transporting the multiphase fluid in a processing system, and may also benefit any downstream processing subsystems which receive the multiphase fluid flow such as, but not limited to, multiphase compressors. By having the liquid reservoir comprise at least one bend portion, the footprint of the liquid reservoir, and hence also the overall footprint of the FCU, can be made more compact. As such, an increased buffer volume for liquid content stored in the liquid reservoir can be provided by fitting a greater volume of pipe into the same space. (For a liquid reservoir of a specific volume, it will be appreciated that the size / footprint of the liquid reservoir in at least one dimension can be reduced as compared to a liquid reservoir of the same specific volume not comprising at least one bend portion.) A conditioned multiphase fluid flow may be understood to be a multiphase fluid flow in which the liquid content of the multiphase fluid flow remains relatively invariant, i.e. remains steady, and / or such that its liquid content changes slowly over time, and / or such that its liquid content varies in a controlled manner. The liquid reservoir can be formed of pipeline, and can preferably be defined by pipeline along substantially all its length. The pipeline can comprise the bend portion. The use of pipeline in the place of a vat or other storage vessel can ease manufacture and be a cheaper component for the FCU, whilst additionally providing its own flow metering or buffering properties not otherwise realised by using a vat or other storage vessel. For example, the provision of pipeline, and particularly pipeline comprising a bend portion, for the liquid reservoir may increase the length of the flow path the liquid content must take before reaching the gas-liquid mixer. This can further increase the buffering time taken for any liquid transients, such as slugs and surge waves, to reach the gas-liquid mixer. This may assist in smoothing out the flow rate of liquid content provided by the liquid reservoir to the gas-liquid mixer. The liquid reservoir may comprise at least one bend portion such that the liquid reservoir can double back on itself. The liquid reservoir may be arranged to double back on itself. The liquid reservoir can comprise a plurality of bend portions. Each bend portion can comprise a section of pipeline defining a change in a direction of the flow path of: greater than or equal to 30 degrees; of greater than or equal to 45 degrees; greater than or equal to 60 degrees; greater than or equal to 90 degrees; of greater than or equal to 120 degrees; greater than or equal to 150 degrees; or greater than or equal to 180 degrees. One bend portion, or a plurality of bend portions distributed along the flow path defined by the liquid reservoir, may enable the liquid reservoir to double back on itself. A bend portion may be defined by a smooth curve (i.e. it may be a curved portion), an angular / discrete change in direction or angle of the flow path defined by the liquid reservoir; or a plurality of angular / discrete cumulative changes in direction or angle of the flow path defined by the liquid reservoir. The bend portion may define a change in a direction of the flow path of about 90 degrees, and may be an elbow joint. The bend portion may define a change in a direction of the flow path of about 180 degrees, and may be a U-bend. In some embodiments, the bend portion may define a constant angle of curvature for the liquid reservoir, e.g. to produce a spiral-shaped portion of pipeline, or a substantially circular, elliptical, parabolic or hyperbolic portion of pipeline. The liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a flow rate that is relatively invariant over time compared to the volume of liquid content received by the inlet portion. That is, the liquid reservoir may be arranged to provide liquid content to the gas-liquid mixer at a substantially steady flow rate, even if liquid content is received by the inlet portion at a substantially non-steady (or, variable) flow rate. In other words, the liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a substantially steady flow rate, preferably independently of the possibly variable flow rate at which liquid content is received by the inlet portion. The liquid reservoir can be arranged to accommodate surges of liquid such that the flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may be relatively invariant over time compared to the volume of liquid content received by the inlet portion. The volume of liquid content received by have a rate of change of between 0 to 50%, or 0 to 40%, or 0 to 30%, in a period of less than 20 seconds, or less than 15 seconds, or less than 10 seconds. The total flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may have a rate of change of between 0 to 50%, or 0 to 40%, or 0 to 30%, in a period of at least 90 seconds, or of at least 120 seconds, or of at least 150 seconds, or of at least 180 seconds. The liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a flow rate that does not exceed a predetermined threshold. The predetermined threshold may be less than or equal to 0.5; less than or equal to 0.4; less than or equal to 0.3; less than or equal to 0.2; or less than or equal to 0.1, wherein the predetermined threshold is a liquid-mass-fraction, LMF, of the liquid mass flow to the total mass flow in the conditioned multiphase fluid flow. A rate of change of flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may not exceed another predetermined threshold. For example, the predetermined threshold may be a rate of change of: less than 1% per second; less than 0.5% per second; less than 0.4% per second; less than 0.3% per second; less than 0.2% per second; or less than 0.1% per second. The FCU may comprise a liquid extraction portion arranged to remove liquid content from the main pipeline; wherein the liquid reservoir is arranged to receive the liquid content removed from the pipeline. The liquid reservoir may be distinct from the main pipeline. That is, whilst the liquid reservoir may be in flow communication with the main pipeline, it may define a separate flow path to the main pipeline. The liquid reservoir may be provided in parallel, or in series with, the main pipeline. The liquid reservoir may comprise a continuous loop of pipeline. The liquid reservoir may comprise a racetrack-shaped portion of pipeline. Alternatively, the liquid reservoir may comprise a discontinuous flow path. The liquid reservoir may comprise a serpentine-shaped portion of pipeline. The serpentine-shaped portion may be serpentine insofar as the pipeline is winding, and may wind back and forth a plurality of times, and preferably greater than 3, 4 or 5 times. The main pipeline may comprise a central portion extending between the inlet portion and the outlet portion; wherein the inlet portion comprises an uphill portion leading to the central portion; and wherein the outlet portion comprises a downhill portion leading from the central portion. Providing an uphill portion and a downhill portion in the main pipeline may facilitate the main pipeline, the gas extraction portion and the liquid reservoir being provided in respective and different vertical planes. As such, any incoming liquid content and gaseous content from the multiphase fluid flow(s) to be conditioned can be gravitationally separated from the main pipeline. Further, providing the features of the FCU across a range of different vertical planes can help achieve a more compact footprint for the FCU, e.g. by enabling the features of the FCU to be stacked above one another. Any terminology recited herein and defining a relative directionality or positionality will be understood to refer to, or be defined with reference to, a corresponding direction or position during a typical use / operation. The liquid reservoir may be located below the central portion and above the outlet portion. The liquid extraction portion may comprise a plurality of pipes extending substantially downwardly from the main pipeline in a harp extraction configuration. The liquid extraction portion, including the plurality of pipes in a harp extraction configuration, may be located below the main pipeline. The liquid reservoir may be a length of the main pipeline downstream from the inlet portion, such that the main pipeline itself is used to form the liquid reservoir. In other words, the liquid reservoir can be integrated into, or provided as an integral part of, the main pipeline. Accordingly, the liquid reservoir can be provided as a continuation of the main pipeline, and is defined by the main pipeline. By providing a liquid reservoir which is a length of the main pipeline, there is no need to provide a liquid reservoir that is a separate entity and / or defined by additional hardware. This may also assist with simplifying manufacture of the FCU and reducing the cost of the FCU, by utilising the main pipeline as the liquid reservoir. Further, providing a liquid reservoir that is integrated into the main pipeline can help provide a more compact footprint for the FCU by avoiding the need to provide a liquid reservoir that is a separate entity and / or defined by additional hardware. The liquid reservoir may comprise a serpentine-shaped portion of pipeline. The serpentine-shaped portion may be serpentine insofar as the pipeline is winding, and may wind back and forth a plurality of times, and preferably greater than 3, 4 or 5 times. The liquid reservoir may comprise a spiral-shaped portion of pipeline. The liquid reservoir may be arranged to descend, i.e. decline or slope downwards, along its length. By having the liquid reservoir descend along its length, liquid content in the liquid reservoir can be motivated towards the gas-liquid mixer under the influence of gravity. Further, the rate of descent can be chosen to achieve a suitable flow rate for the liquid content through the liquid reservoir, to achieve buffering or smoothing of the flow rate of liquid content from the liquid reservoir as desired. The descent will be in the direction of flow of the liquid content, i.e. in a direction of flow from the inlet portion to the gas-liquid mixer. The liquid reservoir may be arranged to descend at gradient of between 0 and 10 degrees; between 0 and 5 degrees; between 0 and 3 degrees; between 0 and 2 degrees; or between 0 and 1 degree. A gradient, i.e. rate, of descent of the liquid reservoir may be constant, or may vary along its length. The inlet portion may comprise an uphill portion leading to the liquid reservoir. Providing an uphill portion leading to the liquid reservoir may facilitate the liquid reservoir being arranged to descend along its length. The liquid reservoir may comprise a tapered, narrowing, or constricting portion located toward the gas-liquid mixer. The restriction in a diameter of the flowline may help to control a flow rate of liquid content from the liquid reservoir to the gas-liquid mixer. The liquid reservoir may be arranged to provide the flow of liquid content to the outlet portion under action of a pressure head of the liquid content stored in the liquid reservoir. As such, no additional pumps may be required to motivate liquid content to the gas-liquid mixer. The FCU may comprise a controllable valve operable to control the flow of liquid content provided to the outlet portion. The gas extraction portion may comprise a plurality of pipes extending substantially upwardly from the main pipeline in a harp extraction configuration. The gas extraction portion, including the plurality of pipes in the harp extraction configuration, may be located above the main pipeline. The FCU may be arranged to produce a plurality of conditioned multiphase fluid flows. As such, the FCU may be arranged to produce a plurality of conditioned, i.e. stable, multiphase fluid flows from at least one, e.g. one ora plurality, of incoming, potentially unstable, incoming multiphase fluid flows. An outlet portion of the FCU, or the gas-liquid mixer itself, may be arranged to produce two respective conditioned multiphase fluid flows. For example, the FCU may comprise a plurality of gas-liquid mixers each producing a respective conditioned multiphase fluid flow. Additionally, or alternatively, an outlet portion of the FCU may be arranged to split a conditioned multiphase fluid flow into a plurality of multiphase fluid flows. In other embodiments, the FCU may be arranged to produce only a single conditioned multiphase fluid flow. For example, the FCU may be arranged to condition a single incoming multiphase fluid flow to produce the single conditioned multiphase fluid flow. Alternatively, FCU may be arranged to receive a plurality of incoming multiphase fluid flows and produce a single conditioned multiphase fluid flow. Viewed from a second aspect, there is provided a fluid processing system for transporting a multiphase fluid. The system comprises: a supply pipe arranged to convey a multiphase fluid flow; and a flow conditioning unit, FCU, as described according to the first aspect; wherein the inlet portion of the FCU is in fluid communication with the supply pipe and is arranged to receive the multiphase fluid flow. The fluid processing system of the second aspect comprises the FCU as described according to the first aspect. Accordingly, the fluid processing system of the second aspect may have one or more or all of the features (including optional features) of the FCU of the first aspect. Thus, the above description of the FCU according to the first aspect may be equally applicable to the fluid processing system of the second aspect. The fluid processing system may comprise one or more multiphase compressors. Each multiphase compressor may be arranged to compress a respective conditioned multiphase fluid flow, produced by the FCU. The FCU may be located anywhere upstream of the one or more multiphase compressors, i.e. the FCU need not be located immediately, or directly, upstream of the one or more multiphase compressors. For example, one or more subsea processing subsystems may be located between the FCU and the one or more multiphase compressors. Alternatively, the fluid processing system may not comprise a multiphase compressor. As such, the FCU may be implemented in the fluid processing system for the purpose of simply stabilising an incoming multiphase fluid flow(s). The fluid processing system may be a subsea processing system for multiphase hydrocarbon fluids. The multiphase fluid(s) may be a multiphase hydrocarbon fluid. Viewed from a third aspect, there is provided a method for conditioning a multiphase fluid using a flow conditioning unit, FCU, according to the first aspect. The method comprises: receiving, at the FCU, a multiphase fluid flow; separating a gaseous phase from the multiphase fluid flow to produce a gas content flow; providing liquid content from the multiphase fluid flow to a liquid reservoir; and recombining the liquid content from the liquid reservoir with the gas content flow to produce a conditioned multiphase fluid flow by providing a conditioned flow rate of liquid content to the gas content flow. The method of the third aspect comprises using the FCU as described according to the first aspect. Accordingly, the method of the third aspect may comprise the use of one or more or all of the features (including optional features), and method steps relating to the use of one or more or all of the features (including optional features), of the FCU of the first aspect. Thus, the above description of the FCU according to the first aspect may be equally applicable to the method of the third aspect. Providing liquid content from the multiphase fluid flow to the liquid reservoir may comprise providing any, or substantially all, liquid content from the multiphase fluid flow to the liquid reservoir. The method may comprise splitting the conditioned multiphase fluid flow into a plurality of metered multiphase fluid flows. The method may comprise controlling the flow rate of liquid content provided to the gas content flow using a controllable valve. The method may be performed by a subsea processing system for multiphase hydrocarbon fluids. The multiphase fluid(s) may be a multiphase hydrocarbon fluid. Viewed from a fourth aspect, there is provided a method for transporting a multiphase fluid in a subsea processing system. The method comprises: providing a metered multiphase fluid according to the method of the third aspect; compressing the metered multiphase fluid using a multiphase compressor; and conveying the compressed metered multiphase fluid in a pipeline. The method of the fourth aspect may have one or more or all features (including optional features) of the method of the third aspect. Thus, the above description of the method according to the third aspect may be equally applicable to the method of the fourth aspect. Viewed from a fifth aspect, there is provided a fluid processing system for producing a single metered multiphase fluid flow from a plurality of multiphase fluid flows. The system comprises: a plurality of supply pipes, wherein each supply pipe is arranged to convey a multiphase fluid flow; and a flow conditioning unit, FCU, in fluid communication with each of the plurality of supply pipes and arranged to receive a plurality of multiphase fluid flows; wherein the FCU is arranged to accommodate surges of liquid and to produce a single conditioned multiphase fluid flow. By accommodating for surges of liquid present in an incoming multiphase fluid flow, a conditioned flow rate of liquid can be produced. As such, the conditioned multiphase fluid flow can be stabilised. This may be of benefit when transporting the multiphase fluid in a processing system, and may also benefit any downstream processing subsystems which receive the multiphase fluid flow such as, but not limited to, multiphase compressors. When combining or merging a plurality of multiphase fluid flows, instabilities may be introduced. For example, where plural multiphase fluid flows are being merged, a combined sum of liquid content from the plurality of multiphase fluid flows could exceed a tolerable level within a fluid processing system, and particularly for any downstream fluid processing subsystems including, but not limited to, multiphase compressors. Thus, by using the FCU to receive a plurality of multiphase fluid flows and to produce a single conditioned multiphase fluid flow, instabilities and other surges of liquid content when merging multiphase fluid flows can be smoothed out. Accordingly, the FCU can meter the flow rate of liquid content removed from the plurality of multiphase fluid flows such that it remains below a tolerable level. A conditioned multiphase fluid flow may be understood to be a multiphase fluid flow in which the liquid content of the multiphase fluid flow remains relatively invariant, i.e. remains steady, and / or such that its liquid content changes slowly over time, and / or such that its liquid content varies in a controlled manner. The FCU may comprise: a main pipeline having an inlet portion arranged to receive a multiphase fluid flow; a gas extraction portion arranged to remove gas content from the main pipeline; a liquid reservoir arranged to receive liquid content from the main pipeline; and a gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow; wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer. The liquid reservoir can be formed of pipeline, and can preferably be defined by pipeline along substantially all its length. The use of pipeline in the place of a vat or other storage vessel can ease manufacture and be a cheaper component for the FCU, whilst additionally providing its own flow metering or buffering properties not otherwise realised by using a vat or other storage vessel. For example, the provision of pipeline for the liquid reservoir may increase the length of the flow path the liquid content must take before reaching the gasliquid mixer. This can further increase the buffering time taken for any liquid transients, such as slugs and surge waves, to reach the gas-liquid mixer. This may assist in smoothing out the flow rate of liquid content provided by the liquid reservoir to the gas-liquid mixer. The liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a flow rate that is relatively invariant over time compared to the volume of liquid content received by the inlet portion. That is, the liquid reservoir may be arranged to provide liquid content to the gas-liquid mixer at a substantially steady flow rate, even if liquid content is received by the inlet portion at a substantially non-steady (or, variable) flow rate. In other words, the liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a substantially steady flow rate, preferably independently of the possibly variable flow rate at which liquid content is received by the inlet portion. The liquid reservoir can be arranged to accommodate surges of liquid such that the flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may be relatively invariant over time compared to the volume of liquid content received by the inlet portion. The volume of liquid content received by have a rate of change of between 0 to 50%, or 0 to 40%, or 0 to 30%, in a period of less than 20 seconds, or less than 15 seconds, or less than 10 seconds. The total flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may have a rate of change of between 0 to 50%, or 0 to 40%, or 0 to 30%, in a period of at least 90 seconds, or of at least 120 seconds, or of at least 150 seconds, or of at least 180 seconds. The liquid reservoir may be arranged to provide liquid content to the gasliquid mixer at a flow rate that does not exceed a predetermined threshold. The predetermined threshold may be less than or equal to 0.5; less than or equal to 0.4; less than or equal to 0.3; less than or equal to 0.2; or less than or equal to 0.1, wherein the predetermined threshold is a liquid-mass-fraction, LMF, of the liquid mass flow to the total mass flow in the conditioned multiphase fluid flow. A rate of change of flow rate of liquid content provided to the gas-liquid mixer by the liquid reservoir may not exceed another predetermined threshold. For example, the predetermined threshold may be a rate of change of: less than 1% per second; less than 0.5% per second; less than 0.4% per second; less than 0.3% per second; less than 0.2% per second; or less than 0.1% per second. The FCU may comprise a liquid extraction portion arranged to remove liquid content from the main pipeline; wherein the liquid reservoir is arranged to receive the liquid content removed from the pipeline. The liquid reservoir may be distinct from the main pipeline. That is, whilst the liquid reservoir may be in flow communication with the main pipeline, it may define a separate flow path to the main pipeline. The liquid reservoir may be provided in parallel, or in series with, the main pipeline. The main pipeline may comprise a central portion extending between the inlet portion and the outlet portion; wherein the inlet portion comprises an uphill portion leading to the central portion; and wherein the outlet portion comprises a downhill portion leading from the central portion. Providing an uphill portion and a downhill portion in the main pipeline may facilitate the main pipeline, the gas extraction portion and the liquid reservoir being provided in respective and different vertical planes. As such, any incoming liquid content and gaseous content from the multiphase fluid flow(s) to be conditioned can be gravitationally separated from the main pipeline. Further, providing the features of the FCU across a range of different vertical planes can help achieve a more compact footprint for the FCU, e.g. by enabling the features of the FCU to be stacked above one another. The liquid reservoir may be located below the central portion and above the outlet portion. The liquid extraction portion may comprise a plurality of pipes extending substantially downwardly from the main pipeline in a harp extraction configuration. The liquid extraction portion, including the plurality of pipes in a harp extraction configuration, may be located below the main pipeline. The liquid reservoir may be a length of the main pipeline downstream from the inlet portion, such that the main pipeline itself is used to form the liquid reservoir. In other words, the liquid reservoir can be integrated into, or provided as an integral part of, the main pipeline. Accordingly, the liquid reservoir can be provided as a continuation of the main pipeline, and is defined by the main pipeline. By providing a liquid reservoir which is a length of the main pipeline, there is no need to provide a liquid reservoir that is a separate entity and / or defined by additional hardware. This may also assist with simplifying manufacture of the FCU and reducing the cost of the FCU, by utilising the main pipeline as the liquid reservoir. Further, providing a liquid reservoir that is integrated into the main pipeline can help provide a more compact footprint for the FCU by avoiding the need to provide a liquid reservoir that is a separate entity and / or defined by additional hardware. The liquid reservoir may be arranged to descend, i.e. decline or slope downwards, along its length. By having the liquid reservoir descend along its length, liquid content in the liquid reservoir can be motivated towards the gas-liquid mixer under the influence of gravity. Further, the rate of descent can be chosen to achieve a suitable flow rate for the liquid content through the liquid reservoir, to achieve buffering or smoothing of the flow rate of liquid content from the liquid reservoir as desired. The descent will be in the direction of flow of the liquid content, i.e. in a direction of flow from the inlet portion to the gas-liquid mixer. The liquid reservoir may be arranged to descend at gradient of between 0 and 10 degrees; between 0 and 5 degrees; between 0 and 3 degrees; between 0 and 2 degrees; or between 0 and 1 degree. A gradient, i.e. rate, of descent of the liquid reservoir may be constant, or may vary along its length. The inlet portion may comprise an uphill portion leading to the liquid reservoir. Providing an uphill portion leading to the liquid reservoir may facilitate the liquid reservoir being arranged to descend along its length. The liquid reservoir may comprise a tapered, narrowing, or constricting portion located toward the gas-liquid mixer. The restriction in a diameter of the flowline may help to control a flow rate of liquid content from the liquid reservoir to the gas-liquid mixer. The liquid reservoir may be arranged to provide the flow of liquid content to the outlet portion under action of a pressure head of the liquid content stored in the liquid reservoir. As such, no additional pumps may be required to motivate liquid content to the gas-liquid mixer. The FCU may comprise a controllable valve operable to control the flow of liquid content provided to the outlet portion. The gas extraction portion may comprise a plurality of pipes extending substantially upwardly from the main pipeline in a harp extraction configuration. The gas extraction portion, including the plurality of pipes in the harp extraction configuration, may be located above the main pipeline. The FCU may be an FCU according to the first aspect. The fluid processing system of the fifth aspect may have one or more or all of the features (including optional features) of the FCU of the first aspect. Thus, the above description of the FCU according to the first aspect may be equally applicable to the fluid processing system of the fifth aspect. The fluid processing system may comprise one or more multiphase compressors. Each multiphase compressor may be arranged to compress a respective conditioned multiphase fluid flow, produced by the FCU. The FCU may be located anywhere upstream of the one or more multiphase compressors, i.e. the FCU need not be located immediately, or directly, upstream of the one or more multiphase compressors. For example, one or more subsea processing subsystems may be located between the FCU and the one or more multiphase compressors. Alternatively, the fluid processing system may not comprise a multiphase compressor. As such, the FCU may be implemented in the fluid processing system for the purpose of simply stabilising an incoming multiphase fluid flow(s). The fluid processing system may be a subsea processing system for multiphase hydrocarbon fluids. The multiphase fluid(s) may be a multiphase hydrocarbon fluid. Viewed from a sixth aspect, there is provided a method for producing a single metered multiphase fluid flow from a plurality of multiphase fluid flows. The method comprises: receiving, at a flow conditioning unit, FCU, the plurality of multiphase fluid flows; and producing, using the FCU, a single conditioned multiphase fluid flow from the plurality of multiphase fluid flows; wherein the FCU is arranged to accommodate for surges of liquid when producing the single conditioned multiphase fluid flow. By accommodating for surges of liquid present in an incoming multiphase fluid flow, a conditioned flow rate of liquid can be produced. As such, the conditioned multiphase fluid flow can be stabilised. This may be of benefit when transporting the multiphase fluid in a processing system, and may also benefit any downstream processing subsystems which receive the multiphase fluid flow such as, but not limited to, multiphase compressors. A conditioned multiphase fluid flow may be understood to be a multiphase fluid flow in which the liquid content of the multiphase fluid flow remains relatively invariant, i.e. remains steady, and / or such that its liquid content changes slowly over time, and / or such that its liquid content varies in a controlled manner. When combining or merging a plurality of multiphase fluid flows, instabilities may be introduced. For example, where plural multiphase fluid flows are being merged, a combined sum of liquid content from the plurality of multiphase fluid flows could exceed a tolerable level within a fluid processing system, and particularly for any downstream fluid processing subsystems including, but not limited to, multiphase compressors. Thus, by using the FCU to receive a plurality of multiphase fluid flows and to produce a single conditioned multiphase fluid flow, instabilities and other surges of liquid content when merging multiphase fluid flows can be smoothed out. Accordingly, the FCU can meter the flow rate of liquid content removed from the plurality of multiphase fluid flows such that it remains below a tolerable level. The step of producing, using the FCU, a single conditioned multiphase fluid flow from the plurality of multiphase fluid flows, may comprise: separating a gaseous phase from each of the multiphase fluid flows to produce a gas content flow; providing liquid content from each of the multiphase fluid flows to a liquid reservoir; and recombining the liquid content from the liquid reservoir with the gas content flow to produce the single multiphase fluid flow by providing a conditioned flow rate of liquid content to the gas content flow. Providing liquid content from each of the multiphase fluid flows to the liquid reservoir may comprise providing any, or substantially all, liquid content from each of the multiphase fluid flows to the liquid reservoir. The FCU may comprise: a main pipeline having an inlet portion arranged to receive a multiphase fluid flow; a gas extraction portion arranged to remove gas content from the main pipeline; a liquid reservoir arranged to receive liquid content from the main pipeline; and a gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow; wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer. The method may comprise controlling the flow rate of liquid content provided to the gas content flow using a controllable valve. The method may be performed by a subsea processing system for multiphase hydrocarbon fluids. The multiphase fluid(s) may be a multiphase hydrocarbon fluid. The method may be performed using a fluid processing system according to the fifth aspect. The method of the sixth aspect may comprise the use of one or more or all of the features (including optional features), and method steps relating to the use of one or more or all of the features (including optional features), of the fluid processing system of the fifth aspect. Thus, the above description of the fluid processing system according to the fifth aspect may be equally applicable to the method of the sixth aspect. Viewed from a seventh aspect, there is provided a method for transporting a multiphase fluid in a subsea processing system. The method comprises: providing a metered multiphase fluid according to the method of the sixth aspect; compressing the metered multiphase fluid using a multiphase compressor; and conveying the compressed metered multiphase fluid in a pipeline. The method of the sixth aspect may have one or more or all features (including optional features) of the method of the fifth aspect. Thus, the above description of the method according to the fifth aspect may be equally applicable to the method of the sixth aspect. BRIEF DESCRIPTION OF THE DRAWINGS Certain preferred embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Figure 1 shows a schematic representation of a subsea processing system; Figure 2 illustrates a flow conditioning unit; Figures 3A and 3B illustrate another flow conditioning unit from respective perspective views; Figure 4 illustrates a flow diagram for the flow conditioning unit of figures 2 and 3A, 3B; Figure 5 shows a schematic representation of a subsea processing system; Figure 6 illustrates a flow conditioning unit; Figures 7A and 7B illustrate another flow conditioning unit from respective perspective views; and Figure 8 illustrates a flow diagram for the flow conditioning unit of figures 6 and 7A, 7B. DETAILED DESCRIPTION Figure 1 shows a subsea processing system 100 comprising a flow conditioning unit (FCU) 1 and a compressor 2, according to an embodiment. The FCU 1 receives a multiphase fluid flow 101 (e.g. from a wellhead), and produces a conditioned multiphase fluid flow 102 to the compressor(s) 2. In the embodiment illustrated, the conditioned multiphase fluid flow 102 is split into two respective conditioned multiphase fluid flows 102a, 102b (although in other embodiments, only a single conditioned multiphase flow 102 may be produced). The compressor(s) 2 receives the conditioned multiphase fluid flow 102. In the embodiment illustrated, two compressors 2a, 2b receive respective conditioned multiphase fluid flows 102a, 102b. The compressors 2a, 2b are multiphase compressors, and are each configured to compress a multiphase fluid. The multiphase fluid is a multiphase hydrocarbon fluid. The FCU 1 is configured to condition the multiphase fluid flow 101 to smooth out such transient changes in the liquid content, such that the liquid content of the conditioned multiphase fluid flow 102 remains at a tolerable level for the multiphase compressor 2 downstream of the FCU 1. The conditioned multiphase fluid flow 102 is conditioned insofar as the liquid content of the multiphase fluid flow remains relatively invariant, and / or such that its liquid content changes slowly over time. Having the flow rate of liquid content in the conditioned multiphase fluid flow 102 be conditioned can avoid sudden increases in load acting on the multiphase compressor 2 due to liquid slugs or surge wave transients present in the liquid content of the flow provided to the compressor 2. Thus, the conditioned multiphase fluid flow 102 can be considered to be relatively invariant compared to that of the multiphase fluid flow 101 received by the FCU 1. Generally, the conditioned multiphase fluid flow(s) 102 is conditioned such that the liquid-mass-fraction, i.e. the ratio between liquid mass flow and total mass flow (LMF), does not exceed 0.4. The multiphase flow 101 may experience transient changes of between 0-40% of the LMF over a period of as little as 10 seconds. Generally, the conditioned multiphase fluid flow(s) 102 can be conditioned such that the LMF of the conditioned multiphase fluid flow(s) 102 changes within a range of 0 to 0.4 over a period of roughly 120 seconds. Figure 2 illustrates the structure of FCU 1 in closer detail, whilst figure 4 illustrates the flow diagram for the FCU 1. The FCU 1 comprises a main pipeline having an inlet portion 10 and a gasliquid mixer. In the present embodiment, the gas-liquid mixer is an outlet portion 50 of the main pipeline. The inlet portion 10 is arranged to receive the multiphase fluid flow 101, and the outlet portion 50 is arranged to produce the conditioned multiphase fluid flow 102. A central portion 25 extends between the inlet portion 10 and the outlet portion 50. The main pipeline comprises a gas extraction portion 20 downstream of the inlet portion 50, and a liquid extraction portion 30 downstream of the gas extraction portion 20 and upstream of the outlet portion 50. The inlet portion 10 further comprises an uphill portion 11 extending between the inlet portion 10 and the central portion 25, the outlet portion 50 comprises a downhill portion 51 extending between central portion 25 and the outlet portion 50. In use during flow conditioning, the main pipeline is shut at a controllable valve 52. However, the main pipeline is capable of being pigged when the controllable valve 52 is open. This is due to the main pipeline having only gradual curves along its length, and the diameter of the main pipeline not varying along its length. The gas extraction portion 20 comprises a plurality of gas pipes 21 extending upwardly from the main pipeline, in a harp extraction configuration. That is, each of the plurality of gas pipes 21 are arranged to be in fluid communication with the main pipeline, and each of the plurality of pipes 21 extend from the main pipeline in parallel with one another. The plurality of gas pipes 21 are located above the main pipeline, such that gas content is separated from the main pipeline under the effects of gravity. The design and number of gas pipes 21 can be selected based on the desired liquid entrainment criteria, e.g. to limit the maximum ascending velocity of any liquid droplets, or inclining the gas harp to aid separation of the gas content from the liquid content. The FCU 1 also comprises a gas extraction pipe 22, which is arranged to be in fluid communication with the plurality of gas pipes 21 and the outlet portion 50. The gas extraction pipe 22 is thus arranged to provide a gas content flow from the plurality of gas pipes 21 to the outlet portion 50. The liquid extraction portion 30 comprises a plurality of liquid pipes 31 extending downwardly from the main pipeline, in a harp extraction configuration. Liquid content is separated from the main pipeline under the effects of gravity. The FCU 1 comprises a liquid reservoir 40 located below the main pipeline. The liquid reservoir 40 is arranged to receive liquid content from the plurality of liquid pipes 31, and to provide liquid content to the outlet portion 50. The liquid reservoir 40 is a continuous loop of pipeline, which in the present embodiment is an elongate racetrack-shaped pipeline. In other embodiments, the pipeline could be a discontinuous length of pipeline. The liquid reservoir 40 is arranged to accommodate surges of liquid content by holding back any surge waves, liquid slugs or other liquid content transients in the reservoir 40, such that a relatively invariant flow of liquid content can be provided to the outlet portion 50. The liquid reservoir 40 comprises a liquid extraction pipe 41, which is arranged to convey liquid content from the liquid reservoir 40 to the outlet portion 50. The liquid extraction pipe 41 comprises a liquid control valve 42, which is arranged to control a flow of liquid content conveyed by the liquid extraction pipe 41. In some embodiments, liquid content from the liquid extraction pipe 41 can be an oil / water mix. The liquid content may be routed through an oil / water separator (not shown) for removal of water content, before any oil content is provided to the gas-liquid mixer. The liquid reservoir 40 also comprises a gas bleed pipe 43, which is arranged to provide gas content present in the liquid reservoir 40 to the gas extraction pipe 22, and to prevent pressure build-up in the liquid reservoir 40 in the event an increase in liquid content, i.e. a liquid slug / surge wave transient, is introduced into the liquid reservoir 40. In the embodiment illustrated in figures 2 and 4, the outlet portion 50 is arranged to split the conditioned multiphase fluid flow 102 into two respective conditioned multiphase fluid flows 102a, 102b. A pipe (which in the present embodiment is a crossline pipe, but in other embodiments could be a branching pipe) connects the main pipeline to a second pipeline 60 such that gas content can flow between the two pipelines. The outlet portion 50 and the second pipeline could have identical or different respective diameters. The second pipeline 60 can comprise a closed end accessible for pigging the second pipeline 60. The liquid extraction pipe 41 comprises a T-portion which is arranged to split the flow of liquid content conveyed by the liquid extraction pipe 41. Two liquid control valves 42a, 42b are provided and are arranged to control the flow of liquid content conveyed to each respective pipeline. In other embodiments, the outlet portion 50 can alternatively be arranged to produce a single conditioned multiphase fluid flow 102 and can comprise a single liquid control valve 42. In other embodiments, the outlet portion 50 can also comprise a distribution header (not shown) downstream of the outlet portion 50, to split the conditioned multiphase fluid flow 102 into a plurality of conditioned multiphase fluid flows 102a, 102b. As mentioned above, in the present embodiment the liquid reservoir 40 is a continuous loop of pipeline. In other embodiments, it could also be a discontinuous length of pipeline. In either case, the liquid reservoir 40 will comprise at least one bend portion. The bend portion may enable the liquid reservoir 40 to double back on itself. As such, the liquid reservoir 40 can achieve a more compact footprint for the FCU 1. In other words, an increased buffer volume for liquid content stored in the liquid reservoir 40 can be provided by fitting a greater volume of pipe into the same space. As mentioned above, the outlet portion 50 functions as a gas-liquid mixer, receiving gas content flow from the gas extraction portion 20 and liquid content flow from the liquid reservoir 40, to produce the conditioned multiphase fluid flow 102. Having the gas-liquid mixer be incorporated into the same main pipeline as the inlet portion 10, the gas extraction portion 20 and the liquid extraction portion 30 can also provide a compact arrangement for the FCU 1. The main pipeline, the gas extraction portion 20, the liquid extraction portion 30 and the liquid reservoir 40 are provided in different vertical planes relative to each other to aid gravitational separation of the liquid content and the gas content from the incoming multiphase flow 101. Additionally, the main pipeline, the gas extraction portion 20, the liquid extraction portion 30 and the liquid reservoir 40 are located directly above and below each other in the manner as described above and as illustrated in figure 2, which can achieve a more compact footprint for the FCU 1. The central portion 25 also comprises a bend or curve such that it is also doubled back on itself, which assists in reducing the overall length of the footprint of the FCU 1. To this end, the multiphase fluid 101 received by the inlet portion 10 can be considered to flow counter-currently to the conditioned multiphase fluid 102 provided by the outlet portion 50. Figure 3A illustrates the structure of another FCU T in closer detail from a first perspective view, and figure 3B illustrates the structure of the FCU 1’ from a second perspective view. The FCU T can be used in place of the FCU 1 in the subsea processing system 100, discussed above and as illustrated in figure 1. Figure 4 also illustrates the flow diagram for the FCU T. The FCU T comprises a main pipeline having an inlet portion 10’ and a gasliquid mixer. In the present embodiment, the gas-liquid mixer is a T-pipe 54’ located at an outlet portion 50’ of the main pipeline. The inlet portion 10’ is arranged to receive the multiphase fluid flow 101, and the outlet portion 50’ is arranged to produce the conditioned multiphase fluid flow 102. The main pipeline comprises a gas extraction portion 20’ downstream of the inlet portion 10’. The inlet portion 10’ further comprises an uphill portion 11’ extending between the inlet portion 10’ and the gas extraction portion 20’, leading to a liquid reservoir 40’. The gas extraction portion 20’ comprises a plurality of gas pipes 21’ extending upwardly from the main pipeline, in a harp extraction configuration. The plurality of gas pipes 21’ are located above the main pipeline, such that gas content is separated from the main pipeline under the effects of gravity. The design and number of gas pipes 21’ can be selected based on the desired liquid entrainment criteria, e.g. to limit the maximum ascending velocity of any liquid droplets, or inclining the gas harp to aid separation of the gas content from the liquid content. The FCU 1’ also comprises a gas extraction pipe 22’, which is in fluid communication with the plurality of gas pipes 21’ and the outlet portion 50’. The gas extraction pipe 22’ is thus arranged to provide a gas content flow from the plurality of gas pipes 21’ to the outlet portion 50’. The FCU T comprises a liquid reservoir 40’ downstream of the gas extraction portion 20’. The liquid reservoir 40’ is arranged to receive liquid content from the main pipeline, and to provide liquid content to the outlet portion 50’. The liquid reservoir 40’ provides a buffer volume for any slugs / surge waves of liquid content received by the main pipeline. The liquid reservoir 40’ is arranged to accommodate surges of liquid content by holding back any surge waves, liquid slugs or other liquid content transients in the reservoir 40’, such that a relatively invariant flow of liquid content can be provided to the outlet portion 50’. In the present embodiment, the main pipeline functions as the liquid reservoir 40’. That is, a length of the main pipeline is, itself, the liquid reservoir 40’. The liquid reservoir 40’ is thus provided as a continuation of the main pipeline. Thus, unlike the FCU 1 illustrated in figure 1, the FCU T does not comprise a liquid extraction portion perse, and a liquid reservoir that is distinct from the main pipeline. Instead, the FCU T of the present embodiment utilises a continuation of the main pipeline itself as the liquid reservoir 40’. The liquid reservoir 40’ extends to a liquid extraction portion 4T, which is arranged to convey liquid content from the liquid reservoir 40’ to the outlet portion 50’, via the T-pipe functioning as the gas-liquid mixer 54’. The liquid extraction portion 41’ is narrower than the liquid reservoir 40’. This restriction in the flowline diameter may help to control a flow rate of liquid content from the liquid reservoir 40’ to the outlet portion 50’. The liquid extraction portion 41’ also comprises a liquid control valve 42’, which is arranged to control a flow of liquid conveyed by the liquid extraction portion 41’ to the outlet portion 50’. In some embodiments, liquid content from the liquid extraction pipe 41’ can be an oil / water mix. The liquid content may be routed through an oil / water separator (not shown) for removal of water content, before any oil content is provided to the gas-liquid mixer 54’. The liquid reservoir 40’ comprises a plurality of gas bleeds feeding into a gas bleed pipe 43’. The gas bleeds are arranged to provide gas content present in the liquid reservoir 40’ to the gas extraction pipe 22’, and to prevent pressure build up in the liquid reservoir 40’ in the event an increase in liquid content, i.e. a liquid slug / surge wave transient, is introduced into the liquid reservoir 40’. As illustrated in figures 3A and 3B, the outlet portion can be arranged to produce a single conditioned multiphase fluid flow 102, using a single gas-liquid mixer. In other embodiments however, the outlet portion 50’ can be arranged to split the conditioned multiphase fluid flow 102 into two respective conditioned multiphase fluid flows 102a, 102b as shown in figures 1 and 4. This may be achieved using a distribution header downstream of the outlet portion 50’, or by using a plurality of gas-liquid mixers leading to separate pipelines, to split the conditioned multiphase fluid flow 102 into a plurality of conditioned multiphase fluid flows 102a, 102b. As mentioned above, in the present embodiment the liquid reservoir 40’ is a length of the main pipeline. Further, as illustrated in figures 3A and 3B, the liquid reservoir 40’ comprises a plurality of bends and / or curves which can enable the liquid reservoir 40’ to double back on itself. As a result, the liquid reservoir 40’ takes on a serpentine configuration; i.e. it comprises a pipeline that is winding. As such, the liquid reservoir 40’ can achieve a more compact footprint for the FCU T. In other words, an increased buffer volume for liquid content stored in the liquid reservoir 40’ can be provided by fitting a greater volume of pipe into the same space. In other embodiments, the liquid reservoir 40’ could take on a spiralling shape, or any other suitable shape comprising at least one bend or curve and having a discontinuous length. The liquid reservoir 40’ is also arranged to descend along its length. This is preferably at a constant rate of descent, although it may be varied, e.g. to gradually increase. Having the liquid reservoir 40’ descend along its length can motivate liquid content, under the influence of gravity, to flow to the outlet portion 50’. The rate of descent can be chosen to achieve a suitable flow rate for the liquid content through the liquid reservoir 40’ to achieve buffering of the liquid content. As described above, liquid reservoir 40’, and hence the main pipeline itself, is a discontinuous length of pipeline. As such, the gas-liquid mixer, and the outlet portion 50’ are formed in a separate pipeline parallel to, and in fluid communication with, the main pipeline in a manner as described above. The main pipeline thus ends at the liquid control valve 42’, with the outlet portion 50’ receiving a conditioned liquid content and the gas content from the main pipeline to produce the conditioned multiphase fluid flow 102. In the embodiment illustrated in figures 3A and 3B, the main pipeline is not piggable due to the sharp bends / curves formed in the liquid reservoir 40’, and due to the liquid reservoir 40’ narrowing as it transitions to the liquid extraction portion 41’. Whilst the FCUs 1, 1’ of the above-discussed embodiments provide the conditioned multiphase fluid flows 102a, 102b to respective multiphase compressors 2a, 2b, it will be appreciated that the conditioned multiphase fluid flow 102 does not need to be exclusively provided to a multiphase compressor 2. In other embodiments, the FCUs 1,1’ are used to simply condition the multiphase fluid flow 101, e.g. to produce a single conditioned multiphase fluid flow 102 from the multiphase fluid flow 101, or to aid in splitting the flow into respective conditioned multiphase fluid flows 102a, 102b, prior to the conditioned multiphase fluid flow(s) 102 being provided to any downstream subsea fluid processing subsystems. Thus, embodiments are also disclosed herein in which an FCU 1, 1’ are provided anywhere upstream of a multiphase compressor, i.e. not immediately or directly upstream of the multiphase compressor; and in which the FCU 1, 1’ is provided simply to condition the multiphase fluid flow 101 in a flowline where there is no multiphase compressor at all. Figure 5 shows a subsea processing system 200 according to another embodiment. The subsea processing system 200 comprises an FCU 201, which is arranged to receive a plurality of multiphase fluid flows 101a, 101b and to produce a single conditioned multiphase fluid flow 102. The single conditioned multiphase fluid flow 102 is provided to a multiphase compressor 2 or other downstream processing equipment. The multiphase fluid is a multiphase hydrocarbon fluid. The FCU 201 is configured to condition the multiphase fluid flow 101 to smooth out such transient changes in the liquid content, such that the liquid content of the conditioned multiphase fluid flow 102 remains at a tolerable level for the multiphase compressor 2 downstream of the FCU 201. The conditioned multiphase fluid flow 102 is thus conditioned insofar as the liquid content of the multiphase fluid flow remains relatively invariant, and / or such that its liquid content changes slowly over time. Having the flow rate of liquid content in the conditioned multiphase fluid flow 102 be conditioned can avoid sudden increases in load acting on the multiphase compressor 2 due to liquid slugs or surge wave transients present in the liquid content of the flow provided to the compressor 2. Thus, the conditioned multiphase fluid flow 102 can be considered to be relatively invariant compared to that of the multiphase fluid flow 101 received by the FCU 201. Generally, the conditioned multiphase fluid flow 102 is conditioned such that the liquid-mass-fraction, i.e. the ratio between liquid mass flow and total mass flow (LMF), does not exceed 0.4. The plurality of multiphase flows 101a, 101b may each experience transient changes of between 0-40% of the LMF over a period of as little as 10 seconds. Generally, the conditioned multiphase fluid flow 102 can be conditioned such that the LMF of the conditioned multiphase fluid flow 102 changes within a range of 0 to 0.4 over a period of roughly 120 seconds. Figure 6 illustrates one particular structure of an FCU 201 that could be used in the subsea processing system 200 in closer detail, whilst figure 8 illustrates the flow diagram for the FCU 201. The FCU 201 comprises a main pipeline having an inlet portion 210 and a gas-liquid mixer which, in the present embodiment, is an outlet portion 250 of the main pipeline. The inlet portion 210 is arranged to receive the multiphase fluid flow 101, and the outlet portion 250 is arranged to produce the conditioned multiphase fluid flow 102. A central portion 225 extends between the inlet portion 210 and the outlet portion 250. The main pipeline comprises a gas extraction portion 220 downstream of the inlet portion 250, and a liquid extraction portion 230 downstream of the gas extraction portion 220 and upstream of the outlet portion 250. The inlet portion 210 further comprises an uphill portion 211 extending between the inlet portion 210 and the central portion 225, the outlet portion 250 comprises a downhill portion 251 extending between central portion 225 and the outlet portion 250. In use during flow conditioning, the main pipeline is shut at a controllable valve 252. However, the main pipeline is capable of being pigged when the controllable valve 252 is open. This is due to the main pipeline having only gradual curves along its length, and the diameter of the main pipeline not varying along its length. The gas extraction portion 220 comprises a plurality of gas pipes 221 extending upwardly from the main pipeline, in a harp extraction configuration. That is, each of the plurality of gas pipes 221 are arranged to be in fluid communication with the main pipeline, and each of the plurality of pipes 221 extend from the main pipeline in parallel with one another. The plurality of gas pipes 221 are located above the main pipeline, such that gas content is separated from the main pipeline under the effects of gravity. The design and number of gas pipes 221 can be selected based on the desired liquid entrainment criteria, e.g. to limit the maximum ascending velocity of any liquid droplets, or inclining the gas harp to aid separation of the gas content from the liquid content. The FCU 201 also comprises a gas extraction pipe 222, which is arranged to be in fluid communication with the plurality of gas pipes 221 and the outlet portion 250. The gas extraction pipe 222 is thus arranged to provide a gas content flow from the plurality of gas pipes 221 to the outlet portion 250. The liquid extraction portion 230 comprises a plurality of liquid pipes 231 extending downwardly from the main pipeline, in a harp extraction configuration. Liquid content is separated from the main pipeline under the effects of gravity. The FCU 201 comprises a liquid reservoir 240 located below the main pipeline. The liquid reservoir 240 is arranged to receive liquid content from the plurality of liquid pipes 231, and to provide liquid content to the outlet portion 250. The liquid reservoir 240 is a continuous loop of pipeline, which in the present embodiment is an elongate racetrack-shaped pipeline. In other embodiments, the pipeline could be a discontinuous length of pipeline. The liquid reservoir 240 is arranged to accommodate surges of liquid content by holding back any surge waves, liquid slugs or other liquid content transients in the reservoir 240, such that a relatively invariant flow of liquid content can be provided to the outlet portion 250. The liquid reservoir 240 comprises a liquid extraction pipe 241, which is arranged to convey liquid content from the liquid reservoir 240 to the outlet portion 250. The liquid extraction pipe 241 comprises a liquid control valve 242, which is arranged to control a flow of liquid content conveyed by the liquid extraction pipe 241. In some embodiments, liquid content from the liquid extraction pipe 241 can be an oil / water mix. The liquid content may be routed through an oil / water separator (not shown) for removal of water content, before any oil content is provided to the gas-liquid mixer. The liquid reservoir 240 also comprises a gas bleed pipe 243, which is arranged to provide gas content present in the liquid reservoir 240 to the gas extraction pipe 222, and to prevent pressure build-up in the liquid reservoir 40 in the event an increase in liquid content, i.e. a liquid slug / surge wave transient, is introduced into the liquid reservoir 40. The inlet portion 210 can be arranged to receive the plurality of multiphase fluid flows 101a, 101b in a number of ways, for example by using a Y-connector; a plurality of branch fittings, each branch fitting carrying a respective multiphase fluid flow 102a, 102b and joining the main pipeline; or a suitable outlet header. The outlet portion 250 is arranged to produce the single conditioned multiphase fluid flow 102. The liquid extraction pipe 241 provides a single flow path to the outlet portion 250. A liquid control valve 242 is provided along the liquid extraction pipe 241, to control the flow of liquid content conveyed by the liquid extraction pipe 241. As mentioned above, in the present embodiment the liquid reservoir 240 is a continuous loop of pipeline. In other embodiments, it could also be a discontinuous length of pipeline. In either case, the liquid reservoir 40 will comprise at least one bend portion. The bend portion can enable the liquid reservoir 40 to double back on itself. As such, the liquid reservoir 40 can achieve a more compact footprint for the FCU 201. In other words, an increased buffer volume for liquid content stored in the liquid reservoir 40 can be provided by fitting a greater volume of pipe into the same space. As mentioned above, the outlet portion 250 functions as a gas-liquid mixer, receiving gas content flow from the gas extraction portion 220 and liquid content flow from the liquid reservoir 240, to produce the conditioned multiphase fluid flow 102. Having the gas-liquid mixer be incorporated into the same main pipeline as the inlet portion 210, the gas extraction portion 220 and the liquid extraction portion 230 can also provide a compact arrangement for the FCU 201. The main pipeline, the gas extraction portion 220, the liquid extraction portion 230 and the liquid reservoir 240 are provided in different vertical planes relative to each other to aid gravitational separation of the liquid content and the gas content from the incoming multiphase flow 101. Additionally, the main pipeline, the gas extraction portion 220, the liquid extraction portion 230 and the liquid reservoir 240, and are located directly above and below each other in the manner as described above and as illustrated in figure 5, which can achieve a more compact footprint for the FCU 201. The central portion 225 also comprises a bend or curve such that it is also doubled back on itself, which assists in reducing the overall length of the footprint of the FCU 201. To this end, the multiphase fluid 101 received by the inlet portion 210 can be considered to flow counter-currently to the conditioned multiphase fluid 102 provided by the outlet portion 250. Figure 7A illustrates the structure of another FCU 201’ in closer detail from a first perspective view, and figure 7B illustrates the structure of the FCU 201’ from a second perspective view. The FCU 201’ can be used in place of the FCU 201 in the subsea processing system 200, discussed above and as illustrated in figure 5. Figure 8 also illustrates the flow diagram for the FCU 20T. The FCU 201’ comprises a main pipeline having an inlet portion 210’ and a gas-liquid mixer. In the present embodiment, the gas-liquid mixer is a T-pipe 254’ located at an outlet portion 250’ of the main pipeline. The inlet portion 210’ is arranged to receive the multiphase fluid flow 101, and the outlet portion 250’ is arranged to produce the conditioned multiphase fluid flow 102. The main pipeline comprises a gas extraction portion 220’ downstream of the inlet portion 210’. The inlet portion 210’ further comprises an uphill portion 211’ extending between the inlet portion 210’ and the gas extraction portion 220’, leading to a liquid reservoir 240’. The gas extraction portion 220’ comprises a plurality of gas pipes 221’ extending upwardly from the main pipeline, in a harp extraction configuration. The plurality of gas pipes 221’ are located above the main pipeline, such that gas content is separated from the main pipeline under the effects of gravity. The design and number of gas pipes 221’ can be selected based on the desired liquid entrainment criteria, e.g. to limit the maximum ascending velocity of any liquid droplets, or inclining the gas harp to aid separation of the gas content from the liquid content. The FCU 201’ also comprises a gas extraction pipe 222’, which is in fluid communication with the plurality of gas pipes 221’ and the outlet portion 250’. The gas extraction pipe 222’ is thus arranged to provide a gas content flow from the plurality of gas pipes 221 ’ to the outlet portion 250’. The FCU 201’ comprises a liquid reservoir 240’ downstream of the gas extraction portion 220’. The liquid reservoir 240’ is arranged to receive liquid content from the main pipeline, and to provide liquid content to the outlet portion 250’. The liquid reservoir 240’ provides a buffer volume for any slugs / surge waves of liquid content received by the main pipeline. The liquid reservoir 240’ is arranged to accommodate surges of liquid content by holding back any surge waves, liquid slugs or other liquid content transients in the reservoir 240’, such that a relatively invariant flow of liquid content can be provided to the outlet portion 250’. In the present embodiment, the main pipeline functions as the liquid reservoir 240’. That is, a length of the main pipeline is, itself, the liquid reservoir 240’. The liquid reservoir 240’ is thus provided as a continuation of the main pipeline. Thus, unlike the FCU 201 illustrated in figures, the FCU 201’ does not comprise a liquid extraction portion perse, and a liquid reservoir that is distinct from the main pipeline. Instead, the FCU 201’ of the present embodiment utilises a continuation of the main pipeline itself as the liquid reservoir 240’. The liquid reservoir 240’ extends to a liquid extraction portion 24T, which is arranged to convey liquid content from the liquid reservoir 240’ to the outlet portion 250’, via the T-pipe functioning as the gas-liquid mixer 254’. The liquid extraction portion 241’ is narrower than the liquid reservoir 240’. This restriction in the flowline diameter may help to control a flow of liquid content from the liquid reservoir 240’ to the outlet portion 250’. The liquid extraction portion 241’ also comprises a liquid control valve 242’, which is arranged to control a flow of liquid conveyed by the liquid extraction portion 241’ to the outlet portion 250’. In some embodiments, liquid content from the liquid extraction pipe 241’ can be an oil / water mix. The liquid content may be routed through an oil / water separator (not shown) for removal of water content, before any oil content is provided to the gas-liquid mixer 254’. The liquid reservoir 240’ comprises a plurality of gas bleeds feeding into a gas bleed pipe 243’. The gas bleeds are arranged to provide gas content present in the liquid reservoir 240’ to the gas extraction pipe 222’, and to prevent pressure build-up in the liquid reservoir 240’ in the event an increase in liquid content, i.e. a liquid slug / surge wave transient, is introduced into the liquid reservoir 240’. The inlet portion 210’ can be arranged to receive the plurality of multiphase fluid flows 101a, 101b in a number of ways, for example by using a Y-connector; a plurality of branch fittings, each branch fitting carrying a respective multiphase fluid flow 102a, 102b and joining the main pipeline; or a suitable outlet header. The outlet portion 250’ is arranged to produce the single conditioned multiphase fluid flow 102. The liquid extraction pipe 241’ provides a single flow path to the outlet portion 250’. A liquid control valve 242’ is provided along the liquid extraction pipe 24T, to control the flow of liquid content conveyed by the liquid extraction pipe 241’. As mentioned above, in the present embodiment the liquid reservoir 240’ is a length of the main pipeline. Further, as illustrated in figures 3A and 3B, the liquid reservoir 240’ comprises a plurality of bends and / or curves which can enable the liquid reservoir 240’ to double back on itself. As a result, the liquid reservoir 240’ takes on a serpentine configuration; i.e. it comprises a serpentine-shaped pipeline. As such, the liquid reservoir 240’ can achieve a more compact footprint for the FCU 201’. In other words, an increased buffer volume for liquid content stored in the liquid reservoir 240’ can be provided by fitting a greater volume of pipe into the same space. In other embodiments, the liquid reservoir 240’ could take on a spiralling shape, or any other suitable shape comprising at least one bend or curve and having a discontinuous length. The liquid reservoir 240’ is also arranged to descend along its length. This is preferably at a constant rate of descent, although it may be varied, e.g. to gradually increase. Having the liquid reservoir 240’ descend along its length can motivate liquid content, under the influence of gravity, to flow to the outlet portion 250’. The rate of descent can be chosen to achieve a suitable flow rate for the liquid content through the liquid reservoir 240’ to achieve buffering of the liquid content. As described above, liquid reservoir 240’, and hence the main pipeline itself, is a discontinuous length of pipeline. As such, the gas-liquid mixer, and the outlet portion 250’ are formed in a separate pipeline parallel to, and in fluid communication with, the main pipeline in a manner as described above. The main pipeline thus ends at the liquid control valve 242’, with the outlet portion 250’ receiving a conditioned liquid content and the gas content from the main pipeline to produce the conditioned multiphase fluid flow 102. In the embodiment illustrated in figures 3A and 3B, the main pipeline is not piggable due to the sharp bends / curves formed in the liquid reservoir 240’, and due to the liquid reservoir 240’ narrowing as it transitions to the liquid extraction portion 241’. As mentioned above, the FCUs 201, 201’ are arranged to receive a plurality of multiphase fluid flows 101a, 101b and to produce a single conditioned multiphase fluid flow 102. The FCUs 201, 20T, and particularly in certain embodiments where the liquid reservoir 240, 240’ is arranged to accommodate surges of liquid, can smooth out instabilities introduced by the merging of a plurality of multiphase fluid flows 101a, 101b. Further, where two multiphase fluid flows 102a, 102b merge, the combined sum of liquid content could exceed the tolerable level for the multiphase compressor 2 downstream of the FCUs 201, 20T. Accordingly, the FCUs 201, 201’ can meter the flow rate of liquid content removed from the plurality of multiphase fluid flows 101a, 101b such that it remains below a tolerable level for multiphase compression by the multiphase compressor 2. Whilst the FCUs 201,201’ of the above-discussed embodiments provide the single conditioned multiphase fluid flow 102 to a multiphase compressor 2, it will be appreciated that the single conditioned multiphase fluid flow 102 does not need to be exclusively provided to a multiphase compressor 2. Accordingly, in other embodiments, the FCUs 201, 201’ are used to simply condition the plurality of multiphase fluid flows 101a, 101b, e.g. to produce a single conditioned multiphase fluid flow 102 from the plurality of multiphase fluid flows 101a, 101b, prior to the single conditioned multiphase fluid flow 102 being provided to any downstream subsea fluid processing subsystem. Thus, embodiments are also disclosed herein in which an FCU 201,201’ is provided anywhere upstream of a multiphase compressor, i.e. not immediately or directly upstream of the multiphase compressor; and in which the FCU 1, 1’ is provided simply to condition the plurality of multiphase fluid flows 101a, 101b in a flowline where there is no multiphase compressor at all.

Claims

1. A flow conditioning unit, FCU, for conditioning a multiphase fluid, the FCU comprising:a main pipeline having an inlet portion arranged to receive a multiphase fluid flow;a gas extraction portion arranged to remove gas content from the main pipeline;a liquid reservoir arranged to receive liquid content from the main pipeline; anda gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow;wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer; andwherein the liquid reservoir comprises at least one bend portion.

2. An FCU as claimed in claim 1, wherein the liquid reservoir is arranged to provide liquid content to the gas-liquid mixer at a flow rate that is relatively invariant over time compared to the volume of liquid content received by the inlet portion.

3. An FCU as claimed in claim 1 or 2, wherein the liquid reservoir is arranged to provide liquid content to the gas-liquid mixer at a flow rate that does not exceed a predetermined threshold.

4. An FCU as claimed in any preceding claim, comprising a liquid extraction portion arranged to remove liquid content from the main pipeline;wherein the liquid reservoir is arranged to receive the liquid content removed from the pipeline.

5. An FCU as claimed in claim 4, wherein the liquid reservoir comprises a continuous loop of pipeline.

6. An FCU as claimed in claim 4 or 5, wherein the liquid reservoir is a racetrack-shaped portion of pipeline.

7. An FCU as claimed in claim 4, wherein the liquid reservoir comprises a serpentine-shaped portion of pipeline.

8. An FCU as claimed in any of claims 4 to 7, wherein the main pipeline comprises a central portion extending between the inlet portion and an outlet portion of the main pipeline;wherein the inlet portion comprises an uphill portion leading to the central portion; andwherein the outlet portion comprises a downhill portion leading from the central portion.

9. An FCU as claimed in claim 8, wherein the liquid reservoir is located below the central portion and above the outlet portion.

10. An FCU as claimed in any of claims 4 to 9, wherein the liquid extraction portion comprises a plurality of pipes extending substantially downwardly from the main pipeline in a harp extraction configuration.

11. An FCU as claimed in claim 1,2 or 3, wherein the liquid reservoir is a length of the main pipeline downstream from the inlet portion, such that the main pipeline itself is used to form the liquid reservoir.

12. An FCU as claimed in claim 11, wherein the liquid reservoir comprises a serpentine-shaped portion of pipeline.

13. An FCU as claimed in claim 11 or 12, wherein the inlet portion comprises an uphill portion leading to the liquid reservoir; andwherein the liquid reservoir is arranged to descend along its length.

14. An FCU as claimed in any preceding claim, wherein the liquid reservoir is arranged to provide the flow of liquid content to the gas-liquid mixer under action of a pressure head of the liquid content stored in the liquid reservoir.

15. An FCU as claimed in any preceding claim, comprising a controllable valve operable to control the flow of liquid content provided to the gas-liquid mixer.

16. An FCU as claimed in any preceding claim, wherein the gas extraction portion comprises a plurality of pipes extending substantially upwardly from the main pipeline in a harp extraction configuration.

17. An FCU as claimed in any preceding claim, wherein the FCU is arranged to split the metered multiphase fluid flow into a plurality of conditioned multiphase fluid flows.

18. A fluid processing system for transporting a multiphase fluid, the system comprising:a supply pipe arranged to convey a multiphase fluid flow; anda flow conditioning unit, FCU, according to any preceding claim;wherein the inlet portion of the FCU is in fluid communication with the supply pipe and is arranged to receive the multiphase fluid flow.

19. A fluid processing system for producing a single metered multiphase fluid flow from a plurality of multiphase fluid flows, the system comprising:a plurality of supply pipes, wherein each supply pipe is arranged to convey a multiphase fluid flow; anda flow conditioning unit, FCU, in fluid communication with each of the plurality of supply pipes and arranged to receive a plurality of multiphase fluid flows;wherein the FCU is arranged to accommodate surges of liquid and to produce a single conditioned multiphase fluid flow.

20. A fluid processing system as claimed in claim 19, wherein the FCU comprises:a main pipeline having an inlet portion arranged to receive a multiphase fluid flow;a gas extraction portion arranged to remove gas content from the main pipeline;a liquid reservoir arranged to receive liquid content from the main pipeline;anda gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow;wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer.

21. A fluid processing system as claimed in claim 19, wherein the FCU is an FCU according to any of claims 1 to 1622. A fluid processing system as claimed in any of claims 18 to 21, comprising: a multiphase compressor arranged to compress the conditioned multiphase fluid flow.

23. A fluid processing system as claimed in any of claims 18 to 22, wherein the fluid processing system is a subsea processing system for multiphase hydrocarbon fluids.

24. An FCU as claimed in any of claims 1 to 17, or a fluid processing system as claimed in any of claims 18 to 23, wherein the multiphase fluid(s) is a multiphase hydrocarbon fluid.

25. A method for conditioning a multiphase fluid using a flow conditioning unit, FCU, as claimed in any of claims 1 to 17 the method comprising:receiving, at the FCU, a multiphase fluid flow;separating a gaseous phase from the multiphase fluid flow to produce a gas content flow;providing liquid content from the multiphase fluid flow to a liquid reservoir; andrecombining the liquid content from the liquid reservoir with the gas content flow to produce a conditioned multiphase fluid flow by providing a conditioned flow rate of liquid content to the gas content flow.

26. A method as claimed in claim 25, comprising:splitting the conditioned multiphase fluid flow into a plurality of metered multiphase fluid flows.

27. A method for producing a single metered multiphase fluid flow from a plurality of multiphase fluid flows, the method comprising:receiving, at a flow conditioning unit, FCU, the plurality of multiphase fluid flows; andproducing, using the FCU, a single conditioned multiphase fluid flow from the plurality of multiphase fluid flows;wherein the FCU is arranged to accommodate for surges of liquid when producing the single conditioned multiphase fluid flow.

28. A method as claimed in claim 27, wherein the step of producing, using the FCU, a single conditioned multiphase fluid flow from the plurality of multiphase fluid flows, comprises:separating a gaseous phase from each of the multiphase fluid flows to produce a gas content flow;providing liquid content from each of the multiphase fluid flows to a liquid reservoir; andrecombining the liquid content from the liquid reservoir with the gas content flow to produce the single multiphase fluid flow by providing a conditioned flow rate of liquid content to the gas content flow.

29. A method as claimed in claim 27 or 28, wherein the FCU comprises:a main pipeline having an inlet portion arranged to receive a multiphase fluid flow;a gas extraction portion arranged to remove gas content from the main pipeline;a liquid reservoir arranged to receive liquid content from the main pipeline; anda gas-liquid mixer arranged to receive a gas content flow from the gas extraction portion and a liquid content flow from the liquid reservoir to produce a conditioned multiphase fluid flow;wherein the liquid reservoir is arranged to accommodate surges of liquid and to provide a conditioned flow rate of liquid content to the gas-liquid mixer.

30. A method as claimed in claim 27 or 28, wherein the FCU is a flow conditioning unit according to any of claims 1 to 1631. A method as claimed in any of claims 25 to 30, comprising: controlling the flow rate of liquid content provided to the gas content flow using a controllable valve.

32. A method as claimed in any of claims 25 to 31, wherein the method is performed by a subsea processing system for multiphase hydrocarbon fluids.

33. A method as claimed in any of claims 25 to 32, wherein the multiphase fluid(s) is a multiphase hydrocarbon fluid.

34. A method for transporting a multiphase fluid in a subsea processing system, the method comprising:providing a metered multiphase fluid according to a method as claimed in any of claims 25 to 33;compressing the metered multiphase fluid using a multiphase compressor;andconveying the compressed metered multiphase fluid in a pipeline.Application No: GB2407435.3 Examiner: George TalbotClaims searched: 1-18, 25-26 and 24, 31-34 (in Date of search: 21 November 2024part)Patents Act 1977: Search Report under Section 17Documents considered to be relevant:Category Relevant to claims Identity of document and passage or figure of particular relevance v A 1-18, 24-26 and 31-34 "Subsea Compression Plant", EQUINOR ENERGY AS- DUPUY et al., Questel Research Disclosure, Database number 717031, 30 / 11 / 2023 See especially Figure 1 and pages 2-3Categories:X Document indicating lack of novelty or inventive step A Document indicating technological background and / or state of the art. Y Document indicating lack of inventive step if combined with one or more other documents of same category. P Document published on or after the declared priority date but before the filing date of this invention. & Member of the same patent family E Patent document published on or after, but with priority date earlier than, the filing date of this application.Field of Search:International Classification:Subclass Subgroup Valid From E21B 0043 / 34 01 / 01 / 2006 BOID 0019 / 00 01 / 01 / 2006 B01F 0025 / 432 01 / 01 / 2022Application No: GB2407435.3 Examiner: George TalbotClaims searched: 19-23, 27-30 and 24, 31-34 in Date of search: 28 April 2025partPatents Act 1977Further Search Report under Section 17Documents considered to be relevant:Category Relevant to claims Identity of document and passage or figure of particular relevance X 19-24, 27-34 "Subsea Compression Plant", EQUINOR ENERGY AS - DUPUY et al., Questel Research Disclosure, Database number 717031, 30 / 11 / 2023 See especially Figure 1 and pages 2-3 X 19-24, 27-34 GB 2569244 A (EQUINOR ENERGY AS) Page 8 lines 3-14 X 19-24, 27-34 WO 2014 / 006371 A2 (CALTEC LTD) Page 4 lines 20-28 X 19-24, 27-34 US 5232475 A (JEPSON) Figure 1 X 19-24, 27- 34 WO 2009 / 131462 A2 (STATOILHYDRO ASA) Page 9 line 11 to page 10 line 21, Figure 2Categories:X Document indicating lack of novelty or inventive step A Document indicating technological background and / or state of the art. Y Document indicating lack of inventive step if P Document published on or after the declared priority date but combined with one or more other documents of same category. before the filing date of this invention. & Member of the same patent family E Patent document published on or after, but with priority date earlier than, the filing date of this application.Field of Search:International Classification:________________________________________________Subclass Subgroup Valid FromSubclass Subgroup Valid From E21B 0043 / 34 01 / 01 / 2006 BOID 0019 / 00 01 / 01 / 2006 B01F 0025 / 432 01 / 01 / 2022

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