PHASE DEW-POINTED GAS

Field

5

The present invention relates to a system and method for subsea cooling a wellhead gas, in particular a system and method for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase, dehydrated and dew-pointed gas for pipeline transport.

10

Background

In the upstream oil and gas industry, there has recently been a move to undertake various processing operations subsea, rather than perform them on the platform as per

15 convention. This change is necessitated by development of reservoirs in deeper and more remote waters and to undertake operations in a safe, environmentally friendly and cost effective way. Initial subsea processing developments have concentrated on subsea pumping, separation and even compression. However, to date, little attention has been directed to the possibility of undertaking fundamental 'process engineering'

20 functions subsea which would allow the multi-phase hydrocarbon fluids that emerge from wellheads to be successfully and economically processed and transported from remote locations.

Multi-phase pipelines proved successful for transporting multi-phase hydrocarbons 25 fluids in the oil & gas industry in the 1980s and 1990s. However the pipelines were generally deployed for exporting water dry multi-phase hydrocarbon fluids from platforms or shallow waters, over relatively short distances. More recently, the industry has tackled much deeper waters, over longer distances, with full well stream subsea flow of non-processed water wet fluids.

30

A water dry pipeline has two very significant benefits over a water wet pipeline. These are:- i. Corrosion is prevented

ii. Water- Hydrocarbon hydrates are prevented

35 The benefit of a single phase pipeline, in addition to the above, is the lack of slugging issues and the need for a slug-catcher. The separation and export of the hydrocarbon liquids at the source may also be preferred, as compared to the end destination of the gas pipeline. Hence, the option for transport of either a water dry pipeline and/or a 5 single phase hydrocarbon fluids becomes desirable in certain circumstances.

The present invention seeks to overcome at least some of the aforementioned disadvantages and enable production of a water dry, non-corrosive single phase hydrocarbon gas suitable for long distance transfer.

10

Summary

In its broadest aspect, the invention provides a system and method for subsea cooling a wellhead gas containing components separable by dewpoint condensation to i s produce a single phase, dehydrated and dew-pointed gas for pipeline transport.

According to one aspect there is provided a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport, said system comprising:

20 a first cooling apparatus configured in use to cool the wellhead gas in direct or indirect heat exchange relation with ambient seawater to a first temperature marginally above ambient seawater temperature to condense liquids comprising one or more hydrocarbons other than methane and at least partially condense water in the wellhead gas;

25 a first separator to separate the condensed liquids and water from the cooled gas;

a means to add a hydrate inhibitor into the separated cooled gas;

a second cooling apparatus configured to further cool the separated cooled gas to a second temperature below the first temperature to condense the remaining

30 condensable liquids and produce a single phase dew-pointed gas; and,

a second separator to separate the condensed liquids from the single phase dew-pointed gas.

In another embodiment, the first temperature is above the hydrate formation 35 temperature and the second temperature is below the hydrate formation temperature. In one embodiment the second temperature is below ambient seawater temperature.

In one embodiment, the first cooling apparatus may comprise a conduit for passage of the wellhead gas therethrough, the conduit being arranged in direct heat exchange relation with ambient seawater. Alternatively, the first cooling apparatus may comprise a plurality of conduits configured in a parallel network, said network of conduits being arranged in direct heat exchange relation with ambient seawater. In another embodiment, the first cooling apparatus may comprise a first subsea heat exchanger in heat exchange relation with a cooling medium fluid from one or more subsea cooling modules. The subsea cooling modules may comprise a plurality of conduits configured in a parallel network, said network of conduits being arranged in direct heat exchange relation with ambient seawater. In an alternative embodiment, the first cooling apparatus may comprise a first subsea heat exchange in heat exchange relation with a cooling medium fluid comprising seawater directly pumped from surrounding ambient seawater.

In one embodiment, the second cooling apparatus comprises a gas-gas heat exchanger in serial combination with the expander, whereby the separated gas is used as a cooling medium in the gas-gas heat exchanger.

The gas-gas heat exchanger in serial combination with the expander may be configured to cool the separated cooled gas. It will be appreciated that the specific temperature to which the separated cooled gas will be cooled by the gas-gas heat exchanger and the expander will depend on the hydrocarbon composition of said gas and the nature of the phase diagram, and the specific temperature to which said gas will be cooled will be selected to produce a single phase dry gas. For example, at pressures of 50-100 bar, the gas may be cooled to -2 °C to -15 °C for water and hydrocarbon dewpointing. Alternatively, at pressures of 100-200 bar, the gas may be cooled to a temperature from 0 to 5 °C below the ambient seawater temperature for predominantly water dewpointing only. Typically, the separated cooled gas may be cooled to below ambient sea water temperature. The desired temperature also depends on the ambient temperature at which the export pipeline passes. This temperature may change as, typically, the pipeline moves from colder deeper waters to warmer shallow waters. Equally there could be other specific circumstances where the ambient temperature along the length of the export pipeline 5 varies.

In one embodiment, a second subsea heat exchanger may be configured upstream of the gas-gas heat exchanger. The second subsea heat exchange may be in heat exchange relation with the cooling medium fluid from one or more subsea cooling l o modules.

The cooling medium fluid used in the first and second subsea heat exchangers may be cooled in the one or more subsea cooling modules by heat exchange with ambient surrounding seawater.

15

To reduce the distances between the gas-gas heat exchanger, the expander and the second separator, the gas-gas heat exchanger, the expander and the second separator may be closely positioned with respect to one another or directly coupled to one another in serial combination.

20

In one embodiment the means to add a hydrate inhibitor into the separated cooled gas comprises an injector adapted to inject a fluid comprising the hydrate inhibitor into a flowpath of the separated cooled gas.

25 In one embodiment, the system may further comprise a gas-liquid heat exchanger disposed either upstream or downstream of the gas-gas heat exchanger in an arrangement whereby the condensed liquids separated by the second separator are used as a heat exchange fluid in the gas-liquid heat exchanger.

30 In another embodiment, the second separator may be a dual phase separator vessel.

In one form, the dual phase separator vessel may be in fluid communications with a dehydration column. In an alternative form, the second separator may have an upper section thereof configured as a dehydration column.

35 In another aspect of the invention there is provided a method of subsea cooling a

wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport, said method comprising:

a) cooling the wellhead gas to a first temperature below a hydrocarbon dewpoint and marginally above ambient seawater temperature to condense liquids comprising one or more hydrocarbons other than methane and at least partially

5 condense water in the wellhead gas;

b) separating the condensed liquids and water from the cooled gas;

c) adding a hydrate inhibitor to the gas separated in step b);

d) cooling the gas from step c) to a second temperature less than the first

temperature to condense the remaining condensable liquids and produce a l o single phase dew-pointed gas; and,

e) separating the condensed liquids from the single phase dew-pointed gas.,

In one embodiment, the first temperature is above the hydrate formation temperature and the second temperature is below the hydrate formation temperature.

15

In one embodiment the second temperature is below ambient seawater temperature,

In one embodiment, cooling the wellhead gas to the first temperature may comprise passing the wellhead gas through a conduit arranged in direct heat exchange relation 20 with ambient seawater. Alternatively, cooling the wellhead gas may comprise passing the wellhead gas through a plurality of conduits configured in a parallel network, said network of conduits being arranged in direct heat exchange relation with ambient seawater.

25 In an alternative embodiment, cooling the wellhead gas to the first temperature may comprise passing the wellhead gas through a first subsea heat exchanger in heat exchange communication with a cooling medium fluid from one or more subsea cooling modules.

30 In one embodiment the first temperature may be marginally greater than the hydrate formation temperature. The generally observed hydrate formation temperature may be within a range of 20 ^e C - 25 ^e C, Therefore the first temperature may be about 30 ^e C - 35 ^e C.

35 In another embodiment the first temperature may be marginally greater than both the hydrate formation temperature and a wax formation temperature. Common wax formation temperatures typically occur between the hydrate formation temperature and 40-50 °C. In practice, the first temperature may be about 5 °C marginally above the wax formation temperature.

5

In one embodiment the hydrate inhibitor may comprise methanol, monoethylene glycol (MEG), similar hydrate inhibitors, or a combination thereof. The hydrate inhibitor may be added in an amount sufficient to depress the hydrate formation temperature to about 5 ^e C below the hydrate formation temperature at a final pressure and l o temperature.

In one embodiment, cooling the gas from step c) comprises passing said gas through a gas-gas heat exchanger and expanding said gas exiting the gas-gas heat exchanger, wherein the separated gas from step e) is used as a cooling medium in step d) in heat 15 exchange relation with the hydrate inhibitor-gas mixture.

In a further embodiment, prior to cooling the gas from step c), the process comprises passing said gas through a gas-liquid heat exchanger, wherein the condensed liquids separated in step e) are used as a heat exchange fluid in the gas-liquid heat 20 exchanger.

In an alternative embodiment, prior to expanding the gas from step c) through the expander, the process comprises passing said gas through a gas-liquid heat exchanger disposed downstream of the gas-gas heat exchanger, wherein the

25 condensed liquids separated in step e) are used as a heat exchange fluid in the gas- liquid heat exchanger.

Prior to performing step c), the hydrate inhibitor-gas mixture may be passed through a second subsea heat exchanger in heat exchange relation with a cooling medium fluid

30 from one or more subsea cooling modules. The hydrate inhibitor-gas mixture may be cooled in the second subsea heat exchanger to a temperature lower than the first temperature.

In another embodiment, cooling the gas from step c) comprises passing the hydrate 35 inhibitor-gas mixture through a second subsea heat exchanger in heat exchange relation with a cooling medium fluid from one or more subsea cooling modules. The hydrate inhibitor-gas mixture may be cooled in the second subsea heat exchanger to a temperature lower than the first temperature.

The cooling medium fluid used in the first and second subsea heat exchangers may be cooled in the one or more subsea cooling modules by heat exchange with ambient surround seawater.

Description of the Figures

Figure 1 is a schematic representation of one embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport;

Figure 2 is a schematic representation of an alternative embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport;

Figure 3 is a schematic representation of a further alternative embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport;

Figure 4 is a schematic representation of another alternative embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport;

Figure 5 is a schematic representation of yet another alternative embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport; and,

Figure 6 is a schematic representation of another further alternative embodiment of a system for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport.

Detailed Description Referring to the Figures there are shown five embodiments of a system 10 for subsea cooling a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport.

The term 'subsea cooling' as used herein refers to a cooling process performed under the surface of a body of water with respect to a raw natural gas obtained from a wellhead. It will be appreciated that the body of water may be sea-based, but could equally apply to any body of water including inland or lake-based water bodies. It will be appreciated that a reference to a sea floor, sea bed, or seawater herein may equally apply to a lake floor, lake bed, or lakewater and/or freshwater and/or saltwater and/or brine, respectively, depending on the location of the wellhead and the character of the body of water in which it is located.

The term 'wellhead gas', as used herein, refers to a raw natural gas extracted from a producing well. Raw natural gas is gas directly extracted from a subsea wellhead with 100% of fluid compositional flow. The composition of the wellhead gas depends on the type, depth, and location of the underground deposit and the geology of the area. Raw natural gas typically consists primarily of methane (CH ₄ ) and varying amounts of heavier gaseous hydrocarbons such as ethane (C ₂ H ₆ ), propane (C ₃ H ₈ ), n-butane (n- C ₄ H ₁₀ ), isobutane (i-C ₄ H ₁₀ ), pentanes and even higher molecular weight hydrocarbons; acid gases such as carbon dioxide (C0 ₂ ), hydrogen sulphide (H ₂ S) and mercaptans such as methanethiol (CH ₃ SH) and ethanethiol (C ₂ H ₅ SH); inert gases such as nitrogen and helium; water vapour and liquid water, including dissolved salts and dissolved gases; liquid hydrocarbons including natural gas condensate and/or crude oil, mercury, and naturally occurring radioactive material.

The wellhead gas may contain components separable therefrom by dewpoint condensation. Primarily these separable components may be any one or more of the heavier gaseous hydrocarbons referred to above and water. The term 'dewpoint condensation', as used herein, refers to a process of cooling the gas to a temperature at or below a hydrocarbon dewpoint and/or a water dewpoint to condense the respective component.

The hydrocarbon dewpoint is the temperature (at a given pressure) at which 5 hydrocarbon components of a hydrocarbon component-containing gas mixture will start to condense out of the gaseous phase. The hydrocarbon dew point is a function of the gas composition as well as the pressure.

The water dewpoint is the temperature (at a given pressure) at which water vapour of a l o wet gas mixture will start to condense out of the gaseous phase. The water dew point is also a function of the gas composition as well as the pressure.

Many components of raw natural gas (e.g. methane, ethane, propane, isobutane, carbon dioxide, nitrogen and hydrogen sulphide) may form gas hydrates, which are

15 solid crystalline compounds that resemble compressed snow and exist above 0 ^e C at high pressures. Structurally, gas hydrates are inclusion compounds (clathrates) formed by trapping of gas molecules in the voids of crystalline structures consisting of water molecules. The term 'hydrate formation temperature' as used herein refers to the temperature (at a given pressure) at which a hydrocarbon hydrate begins to form.

20 Hydrate formation conditions may be predicted using commercial phase equilibria

computer programs such as HYSYS, PVTsim, UNISIM and so forth.

The term 'ambient seawater temperature' as used herein refers to the bulk temperature of the surrounding seawater. It will appreciated that the ambient seawater temperature

25 may vary depending on the location of the wellhead and the location of the system.

For example, the ambient deepwater seawater temperature is commonly understood to be about 4 ^e C. However, in deepwater operations off the north-west shelf of Western Australia, the ambient seawater temperature may be 8 ^e C, while in Arctic waters the ambient seawater temperature may be close to 0 ^e C. The term 'below ambient

30 seawater temperature' refers to a temperature below the bulk temperature of the

surrounding seawater.

The term 'dehydrated' as used herein refers to a gas having a reduced water vapour content, optionally to a specified maximum limit for residual water content. The 35 specified maximum limit may vary according to several factors including operational, regulatory or sales specification guidelines. For example, operational guidelines may specify that the maximum limit for residual water content should not result in the formation of liquid water on the pipeline wall. A pipeline may be exposed to a range of ambient temperatures along its route, and the pipeline gas will have a variation in both temperature and pressure both from ambient temperatures, the degree of heat transfer and insulation in the pipeline and any Joule Thomson thermodynamic effects as the pressure changes along the pipeline. Referring now to the Figures, where like reference numerals refer to like parts throughout, several of the embodiments will now be described.

The particular embodiment of the subsea cooling system 10 described with reference to Figures 1 , 3 to 6 includes a first cooling apparatus comprising a first subsea heat exchanger 12 arranged in heat exchange communication with the wellhead gas. The first subsea heat exchanger 12 may be of various types, such as shell & tube, or various others well understood by those skilled in the art, and may be arranged in various configurations (series/parallel) with other heat exchangers. It will be appreciated that the first subsea heat exchanger 12 may comprise conventional shell & tube heat exchanger which has been modified for subsea use.

In a preferred embodiment, the first subsea heat exchanger 12 may take the form of a hydrocarbon process fluid heat exchanger disposed subsea as described in

International Application Publication No. WO2012/151635, which is incorporated in its entirety herein. In summary, in this form the first subsea heat exchanger 12 is arranged to provide heat exchange communication between the wellhead gas and a cooling medium fluid. The cooling medium fluid is circulated through a subsea cooling unit comprising one or more subsea cooling modules for cooling the cooling medium fluid. The one or more subsea cooling modules comprises a plurality of cooling pipes configured in heat exchange relationship with ambient surrounding seawater.

In use, the first subsea heat exchanger 12 is configured to cool the wellhead gas to a first temperature below a hydrocarbon dewpoint and marginally above ambient seawater temperature to condense liquids comprising one or more hydrocarbons other than methane and at least partially condense water in the wellhead gas. In an alternative embodiment shown in Figure 2, the system 10 omits the first subsea heat exchanger 12. Instead, the system 10 relies on passive cooling to cool the wellhead gas to a first temperature below the hydrocarbon dewpoint. In the

embodiment shown in Figure 2, the wellhead gas is cooled by passing the wellhead gas through conduit 5 which is in direct heat exchange relation with ambient seawater. The degree of cooling of the wellhead gas will be dependent on many factors including, but not limited to, the ambient seawater temperature, the length of the conduit, residence time of wellhead gas in conduit 5, flow rate through conduit 5, and so forth. It is generally assumed that, in this particular embodiment, the length of the conduit 5 would be sufficient to ensure that the wellhead gas was cooled to a temperature marginally above ambient seawater temperature.

Alternatively, the wellhead gas may be cooled by passing the wellhead gas through a simple pipe network in direct heat exchange relation with ambient seawater.

It will be appreciated that with respect to the embodiment described with reference to Figure 2, the wellhead gas will be cooled to a temperature approaching the ambient temperature of the seawater surrounding the conduit or pipe network. The ambient temperature of seawater, particularly in deepwater operations, may be below the hydrate formation temperature. In embodiments where the wellhead gas is likely to be cooled to a temperature below the hydrate formation temperature, a hydrate inhibitor (as will be described later) may be added into the wellhead gas, prior to cooling in direct heat exchange relation with ambient seawater, to avoid formation of hydrates and associated blockages or disruption to wellhead gas flow.

The system 10 also includes a first separator 14 to separate the condensed liquids and water from the cooled wellhead gas. The first separator 14 is arranged in fluid communication with the first subsea heat exchanger 12 in a manner to receive the cooled wellhead gas.

The first separator 14 may take the form of any separator suitable for separating multiphase fluids, as will be well known to those skilled in the art. Exemplary separators include, but are not limited to, a pipe type or vessel type separator. The system 10 shown in Figures also includes a second subsea heat exchanger 16 configured downstream of the first separator 14 in an arrangement to receive the separated gas from the first separator 14. The second subsea heat exchanger 16 may be of various types, such as shell & tube, or various others well understood by those 5 skilled in the art, and may be arranged in various configurations (series/parallel) with other heat exchangers. It will be appreciated that the second subsea heat exchanger 16 may comprise conventional shell & tube heat exchanger which has been modified for subsea use. l o In a preferred embodiment, the second subsea heat exchanger 16 may also take the form of a hydrocarbon process fluid heat exchanger disposed subsea as described in International Application Publication No. WO2012/151635, which is incorporated in its entirety herein. In summary, in this form the second subsea heat exchanger 16 is arranged to provide heat exchange communication between the wellhead gas and a

15 cooling medium fluid. The cooling medium fluid is circulated through a subsea cooling unit comprising one or more subsea cooling modules for cooling the cooling medium fluid. The one or more subsea cooling modules comprises a plurality of cooling pipes configured in heat exchange relationship with ambient surrounding seawater.

20 The cooling medium fluid used in the first and second subsea heat exchangers 12, 16 may be any suitable fluid which is capable of flowing through a respective heat exchange circuit associated therewith and transferring heat from a fluid, such as a hydrocarbon fluid, via the first and second subsea heat exchangers 12, 16. Preferably, the cooling medium fluid has a high thermal capacity, low viscosity, is low cost, non- 25 toxic, and chemically inert, neither causing nor promoting corrosion of the heat

exchange circuit.

In general, the cooling medium fluid of the present invention may be a liquid, although in some alternative embodiments of the invention the cooling medium fluid may be a 30 gas.

Suitable examples of cooling medium fluids include, but are not limited to, aqueous media containing additives to inhibit corrosion within the heat exchange circuit, depress the melting point and/or raise the boiling point. In a preferred embodiment the cooling 35 medium fluid comprises water mixed with a suitable organic chemical, such as ethylene glycol, diethylene glycol, or propylene glycol.

In use, the second subsea heat exchanger 16 is configured to further cool the separated gas to below the hydrate formation temperature. In practice, the

temperature of the cooled gas will approach the temperature of ambient seawater.

In view of the risk of forming solid hydrates when the separated gas is cooled to below the hydrate formation temperature, the system 10 also includes a means 18 to add a hydrate inhibitor into the separated cooled gas upstream of the second subsea heat exchanger 16. The means 18 to add the hydrate inhibitor into the separated cooled gas may comprise an injector configured to introduce the hydrate inhibitor into a conduit 7 for the separated cooled gas between the separator 14 and the second subsea heat exchanger 16. The hydrate inhibitor may be introduced into conduit 7 in an amount sufficient to ensure no hydrates form under any temperature and pressure conditions within the hydrate formation envelope present in the flowpath of the single phase dew-pointed gas and its upstream precursor gas.

The means 18 to add the hydrate inhibitor may be adapted to ensure even distribution of the hydrate inhibitor throughout the separated cooled gas (and any other stream) to which it is introduced. Said means may take the form of conventional pipework, flow constriction devices or valves. In a preferred form, the means 18 to add the hydrate inhibitor may comprise a 'static mixer' component to ensure substantially homogenous distribution of the hydrate inhibitor. A gas-gas heat exchanger 20 in serial combination with an expander 22 is disposed downstream of the injector 18. The gas-gas heat exchanger 20 and the expander 22 are configured to receive and further cool the gas-hydrate inhibitor mixture to condense the remaining condensable liquids and produce a single phase dew-pointed gas.

Disposed downstream of the expander 22 is a separator 24 to separate the condensed liquids from the single phase dew-pointed gas. Preferably the separator 24 is a high performance separator configured to remove a high percentage of condensed liquids from the gas stream.

The gas-gas heat exchanger 20 may be in the form of a shell & tube heat exchanger. The gas cooling medium of the gas-gas heat exchanger 20 may be the single phase dew-pointed gas separated in separator 24.

The expander 22 may be any suitable device to reduce the pressure of the gas, thereby cooling the gas. Exemplary expanders may include, but are not limited to, Joule-Thomson valves, turboexpanders, venturi tubes, nozzles and so forth, as will be well known to those skilled in the art. The expander 22 may also be referred to as a pressure let-down device. In a preferred embodiment, the expander 22 may be a Joule-Thomson valve. Expanding the gas through a Joule-Thomson valve will achieve a sufficient temperature reduction while at the same time controlling and minimising a corresponding reduction in pressure. Expander 22 is configured to reduce the pressure of the gas to produce a temperature and gas composition corresponding to a single phase dew-pointed gas stream. The degree of pressure reduction will be controlled by the expander 22. Preferably, the pressure reduction will be in a range of 5-15 bar.

Pressures may be higher under subsea conditions than conventional topsides gas processing. The pressure may need to be at a point where the separation in the final separator successfully produces a gas of the required composition. This may mean that the entire system will need to operate at a lower pressure than otherwise, with a requirement for export compression following the separation stage. In turn, this may create a requirement for a greater pressure reduction through the expander 22.

It will be appreciated that the temperature of the cooled gas is lowered to below ambient seawater temperatures when it is passed through the gas-gas heat exchanger 20 and the expander 22. Consequently, a high degree of insulation material will be required until the vapour-liquid equilibria separation is completed in the separator 24, and the cooled gas is used in gas-gas heat exchanger 20. High performance insulation will be required when the cooled gas exits the gas-gas heat exchanger 20, the expander 22, the separator 24, and re-enters gas-gas heat exchanger 20, and all connecting pipework, thereby preventing heat leakage into the hydrocarbon fluids from the ambient seawater. The insulation material could take one of several forms including 'pipe-in-pipe' systems.

Additionally, the physical distances between the gas-gas heat exchanger 20, the expander 22 and the separator 24 need to be minimised to reduce the risk of heat leakage. In some embodiments, the gas-gas heat exchanger 20, the expander 22 and the separator 24 may be directly coupled to one another in serial combination.

It will also be appreciated that separator 24 will be of sufficient size and dimensions to perform its duty. The separator 24 may be any one or a combination of types of separators including in-line pipe separators and vessel-type separators.

Referring now to the embodiments described with reference to Figures 4 to 6, these embodiments omit the gas-gas heat exchanger 20 in serial combination with an expander 22 disposed downstream of the injector 18 shown in Figure 1 . Rather, gas cooled in the second subsea heat exchanger 16 is passed directly to separator 24 to separate the condensed liquids from the dry single phase gas. In the embodiments shown in Figures 4 and 5, the separator 24 is adapted to also remove water from the cooled gas.

In Figure 4, the separator 24 is directly coupled to, and is in fluid communication with, a dehydration column section 26. The dehydration column section 26 is configured to receive a volume of hydrate inhibitor via inlet 28. The water and hydrate inhibitor mixture, and any residual hydrocarbon liquids are removed from a common outlet 30 in the dehydration column 26.

In Figure 5, the separator 24 is provided with a dehydration column section 26 in an upper section thereof. The dehydration column section 26 is configured to receive a volume of hydrate inhibitor via inlet 28. The water and hydrate inhibitor mixture, and any residual hydrocarbon liquids are removed from a common outlet 30 in the separator 24.

The effect of using a dehydration column section 26 in combination with the separator 24 is to achieve an increased degree of dryness (water removal from the gas) than by cooling alone. The column height of the dehydration column section 26 is relatively small. Without any pre-cooling, however, the dehydration column section 26 would need to be a significant height which would detract from its cost and practicality in the subsea environment. In Figure 6, it will be appreciated that the second subsea heat exchanger 16 would be of sufficient size and duty such that the closest possible approach to the ambient seawater temperature is achieved (e.g. between 1 oC to 3oC with ambient seawater temperature). This particular embodiment would be suitably employed where export pipelines cross to more benign environmental conditions (e.g. shallow water and warmer temperatures). This reduces the risk of water formation. It also corresponds to those conditions that suit a leaner, less rigorous approach to water removal, such as cases with compositions containing low corrosive components and operating cases where some hydrate risk is acceptable. Optionally, a small amount of hydrate and/or corrosion inhibitor could also be injected into the pipeline.

Referring now to the embodiment described with reference to Figure 3, the system 10 may further include a gas-liquid heat exchanger 26 disposed upstream of the gas-gas heat exchanger 20. The condensed liquids separated in separator 24 may be used as a heat exchange fluid in the gas-liquid heat exchanger 26 via conduit 19. In this way, cooling capacity produced in the system 10 may be conserved and used in the system 10. In an alternative embodiment (not shown), the gas-liquid heat exchanger may be disposed downstream of the gas-gas heat exchanger and upstream of the expander. In use, the system 10 is used subsea to cool a wellhead gas containing components separable by dewpoint condensation to produce a single phase dew-pointed gas for pipeline transport.

The wellhead gas 1 is cooled to a first temperature below a hydrocarbon dewpoint and marginally above ambient seawater temperature to condense liquid comprising one or more hydrocarbons other than methane and at least partially condense water in the wellhead gas 1 . Cooling the wellhead gas 1 to the first temperature comprises passing the wellhead gas 1 through the first subsea heat exchanger 12 in heat exchange communication with a cooling medium fluid 3 from one or more subsea cooling modules (not shown).

In one embodiment, the first temperature may be marginally greater than the hydrate formation temperature. In particular, the first temperature may be about 25 ^e C - 30 ^e C. . For most typical gas compositions and reservoir conditions, cooling the wellhead gas to 30 ^e C or below will result in condensation of a significant fraction of hydrocarbons (other than methane, ethane and propane) and a substantial proportion of water in the wellhead gas 1 . The resulting cooled gas comprises a two-phase fluid which may then be passed to separator 14 via conduit 5 to separate the condensed liquids and water from the cooled gas. Some minor carry-over of liquids may be acceptable. With respect to the separated liquids, the produced and condensate water including any salts and solids can either be reinjected into the reservoir or disposed of at sea after removal of hydrocarbon liquids to the required environmental standards, or taken to the surface or transported by pipe to another remote facility.

It will be appreciated that separation of the condensed liquids from the wellhead gas prior to later expanding said gas improves the efficiency of the expander and the amount of cooling obtained from pressure let down. If liquids were present, their heat capacity would otherwise absorb some of the cold produced by the non-ideal gas expansion.

A hydrate inhibitor is added to, and evenly distributed in, the separated cooled gas prior to passing said gas through the gas-gas heat exchanger 20 and the expander 22 or any heat exchangers 16, 26 upstream of the gas-gas heat exchanger 20. The hydrate inhibitor may be added to and evenly distributed in the separated cooled gas via any suitable means 18 including, but not limited to, an injector device, static mixer or alternative suitable device. The hydrate inhibitor may be any suitable compound or agent that depresses the hydrate formation temperature to about 5 ^e C below the hydrate formation temperature at a final pressure. The final pressure may be the pressure of the cooled expanded gas, as will be described later. Exemplary hydrate inhibitors include, but are not limited to, methanol, monoethylene glycol (MEG or a combination thereof.

The hydrate inhibitor may be added in an amount sufficient to depress the hydrate formation temperature to about 5 ^e C below the hydrate formation temperature at the final pressure. The gas containing the hydrate inhibitor is then passed to the second subsea heat exchanger 16 via conduit 7. Said gas is cooled to a temperature lower than the first temperature. Cooling said gas to temperature lower than the first temperature comprises passing said gas through the second subsea heat exchanger 16 in heat exchange communication with a cooling medium fluid 9 from one or more subsea 5 cooling modules (not shown) as described earlier. Typically, said gas is cooled to about the same temperature as ambient seawater which is used to cool the cooling medium fluid of the second subsea heat exchanger 16. The temperature of the ambient seawater may be below the hydrate formation temperature at which the remaining water and the hydrate inhibitor may condense. Alternatively, the l o temperature of the ambient seawater may be above the hydrate formation

temperature. It will be appreciated that some condensation of remaining water and hydrocarbons other than methane may still occur above the hydrate formation temperature.

15 The gas exiting the second subsea heat exchanger 16 via conduit 1 1 may be further cooled to below the hydrate formation temperature by passing the cooled separated gas through the gas-gas heat exchanger 20 and expanding the cooled separated gas through the expander 22 to the final pressure, thereby condensing the hydrate inhibitor, any remaining condensable liquids including hydrocarbons and water.

20

The resulting multi-phase fluid is then passed to the separator 24 via conduit 13 to separate the condensed liquids and hydrate inhibitor from the resulting single phase dew-pointed gas. The single phase dew-pointed gas is used as the cooling stream 15 in the gas-gas heat exchanger 20 to cool the hydrate inhibitor-gas mixture therein.

25 Employing the single phase dew-pointed gas as the cooling stream 15 in gas-gas heat exchanger 20 captures cooling capacity in the system 10 and improves efficiency.

It will be appreciated that the degree of cooling achieved by the gas-gas heat exchanger 20 in combination with the expander 22 will vary depending on several

30 factors including the hydrocarbon composition of the gas, ambient seawater

temperature, insulation around the apparatus, pressure ranges, hydrate risk level acceptance and corrosion risk level acceptance. For example, a water dewpoint would typically be obtained by cooling the gas between 0°C to 5 °C below ambient seawater temperature. This would typically apply for pressures of between 100 bara to 240 bar. 35 At pressures within this range, the resulting cooled hydrocarbon fluid would typically be in the dense phase region with no dropout of hydrocarbon liquids. However, the cooled hydrocarbon fluid would be 'water dry' and hence have a high certainty of avoiding hydrate formation and corrosion in the subsea pipeline through which it is exported. The exported hydrocarbon fluid would commence its journey in the dense phase region but may end in the multiphase region if the pipeline pressure drop is sufficient.

A temperature of -2 to -15 °C, in pressure range of 50 bar to 100 bar, would likely produce a hydrocarbon condensation and dewpoint and hence the potential to export both a water dry and hydrocarbon dry, single phase gas is also possible in the present system.

Different circumstances are likely to drive different levels of water dryness. A minimum temperature of 0 - 2 °C below ambient seawater temperature may be regarded as sufficient to prevent hydrate formation. However if the hydrocarbon fluid is corrosive, a lower temperature and hence a lower water content may be desired.

Those experienced in the industry will know that different operating companies implement different standards and this may drive different levels of water content and dryness.

A temperature slightly above ambient seawater temperature may be selected if a low level of hydrate risk is acceptable.

The ambient temperature and pressure differential that the pipeline passes through would also influence the desired outcome. If the pipeline passes through shallower and warmer water at lower pressure, the risk of water condensation may be less. Hence various factors affecting the desired downstream temperature and pressure include:- i. Hydrocarbon composition

ii. Export pipeline environment including ambient sea temperatures,

insulation (burial) and pressure range

iii. Hydrate risk level acceptance

iv. Corrosion risk level acceptance In the embodiment shown in Figure 3, prior to passing said mixture through the gas- gas heat exchanger 20 and expanding the cooled mixture through the expander 22, the mixture may be passed through the gas-liquid heat exchanger 26, wherein the condensed liquids separated in separator 24 is used as the heat exchange fluid in the gas-liquid heat exchanger 26 via conduit 19. Similarly, employing the condensed 5 liquids as the heat exchange medium 19 in liquid-gas heat exchanger 26 also captures cooling capacity in the system 10 and improves efficiency. It will be appreciated that this particular embodiment is likely to be deployed if the volume of condensed liquids would warrant the additional liquid-gas heat exchanger 26 and slight additional complexity.

10

The single phase dew-pointed gas exiting the gas-gas heat exchanger 20 is transported via conduit 17 to an export pipeline or a compressor.

It is desirable to minimise the reduction in pressure through the expander 22 so that i s the final pressure of the single phase dew-pointed gas is sufficient to transport the single phase dew-pointed gas and extract the maximum reserves from the

hydrocarbon reservoirs. In deep water, the drop in pressure may be countered by the removal of condensable liquids from the export pipeline and hence a reduction in pressure loss due to the fluid head as compared to any alternate multiphase pipeline 20 system. Generally, a pressure drop of from 5 - 15 bar is desirable, although it will be appreciated that the pressure drop may be greater in some particular embodiments.

The hydrate inhibitor may be recovered from the separated condensed liquids for reuse by well understood recovery techniques, such as a glycol reboiler. In

25 embodiments where significant salts from produced water from the reservoir are

present, other techniques such as vacuum distillation may need to be employed to separate the hydrate inhibitor from the condensed water, and remove the salts.

Referring now to the embodiments described with reference to Figures 4 and 5, the

30 second cooling apparatus omits the gas-gas heat exchanger 20 in serial combination with an expander 22 disposed downstream of the injector 18 shown in Figures 1 and 2. Rather, gas cooled in heat exchanger 16 is passed directly to second separator 24 to separate the condensed liquids from the dry single phase gas. In these particular embodiments, the second separator 24 is adapted to also remove water from the 35 cooled gas. In Figure 4, the second separator 24 is directly coupled to, and is in fluid

communication with, a dehydration column 26. The dehydration column 26 is configured to receive a volume of hydrate inhibitor via inlet 28. The water and hydrate inhibitor mixture, and any residual hydrocarbon liquids are removed from a common outlet 30 in the dehydration column 26.

In Figure 5, the separator 24 is provided with a dehydration column 26 in an upper section thereof. The dehydration column 26 is configured to receive a volume of hydrate inhibitor via inlet 28. The water and hydrate inhibitor mixture, and any residual hydrocarbon liquids are removed from a common outlet 30 in the second separator 24. The effect of using a dehydration column 26 in combination with the second separator 24 is to achieve an increased degree of dryness (water removal from the gas) than by cooling alone. The column height of the dehydration column 26 is relatively small. Without any pre-cooling, however, the dehydration column 26 would need to be a significant height which would detract from its cost and practicality in the subsea environment.

In view of the preceding discussion, it will become apparent to the skilled person that the process and system described herein involves two stages of cooling. The first cooling stage is undertaken to cool the wellhead gas to a temperature above the hydrate formation temperature while at the same time condensing (and subsequently separating) produced liquids including salts. In this way, the process and system reduces the potential for contaminating the hydrate inhibitor when it is added to the cooled wellhead gas prior to the second cooling stage.

Several advantages will become apparent to the skilled addressee including:

· production of a dehydrated dewpointed hydrocarbon gas that can be transported long distances in subsea pipelines as a single phase gaseous fluid;

• problems associated with multiphase subsea pipelines, such as multiphase

slugging issues, pressure drops, as well as holdup of glycol (or other hydrate inhibitors), are removed;

· hydrocarbon liquids can be removed separately, prior to export. This may be significant advantage if downstream facilities are less able to handle these export liquids; • practicality of the process and system is significantly improved by employing subsea cooling processes as described in the inventor's earlier International Application Publication No. WO2012/151635.

5 Numerous variations and modifications will suggest themselves to persons skilled in the relevant art, in addition to those already described, without departing from the basic inventive concepts. All such variations and modifications are to be considered within the scope of the present invention, the nature of which is to be determined from the foregoing description.

10 For example, the system 10 may further comprise one or more subsea compressors to compress the single phase dew-pointed gas. It is expected that the design of the associated subsea compressors would in many cases be substantially simpler and more efficient for the resulting single phase dew-pointed gas in comparison to prior art subsea compressors which were required to compress a multiphase fluid. i s In another example of a variation to the embodiments described herein, the expander 22 may take the form of a subsea turbo-expander re-compressor unit. The subsea turbo-expander re-compressor unit may be advantageously employed to achieve isentropic pressure reduction, and hence lower separator temperature, but more importantly recover pressure.

20 Various alternatives may be considered for treating the separated liquid streams. One efficient option is for a surface hub facility which provides pump, chemicals and liquids treatment while the gas is processed substantially subsea. The large risers, piping and valving, and associated safety systems with bringing the gas to surface would not be required if the system 10 as described herein was used, therefore avoiding the large

25 and very expensive costs associated with additional facility requirements.

Additionally, it will be appreciated that, for a very lean, dry wellhead gas, it may not be necessary to actively or passively cool said wellhead gas and subsequently separate the condensed components from said wellhead gas, prior to further cooling the

30 wellhead gas in the gas-gas heat exchanger in serial combination with the expander.

It is to be understood that, although prior art use and publications may be referred to herein, such reference does not constitute an admission that any of these form a part of the common general knowledge in the art, in Australia or any other country.

For the purposes of this specification it will be clearly understood that the word "comprising" means "including but not limited to", and that the word "comprises" has a corresponding meaning.