GB2549558A

GB2549558A - System and method for converting heat in a wellstream fluid to work

Info

Publication number: GB2549558A
Application number: GB1615737.2A
Authority: GB
Inventors: Brenne Lars; Tarald Kibsgaard Svend; Bjørge Tor; Odin Gaustad Tom; Helland Tingstveit Astrd
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2016-04-12
Filing date: 2016-09-15
Publication date: 2017-10-25
Also published as: GB201615737D0

Abstract

A heat exchanger for extracting heat from a well-stream comprising a production pipe and a casing, working fluid passes through a channel between the production pipe and the casing allowing heat transfer from the production fluid to the working fluid. A system 1 for converting heat in a well-stream fluid to work in order to drive at least one component 30, 60, the system comprising: an energy converter 70 being arranged to convert at least some of the heat energy in the well-stream to work; and the at least one component 30, 60 being arranged to be driven by at least some of the work output from the energy converter 70. The energy converter may be a heat exchanger 20, 40 arranged to transfer heat from the production fluid or oil to a working fluid in a fluid path 50, the working fluid being used to generate electricity to drive the component. The energy converter may be a turbine 70 powered by the working fluid which transfers the work produced to the component which may be a compressor 30.

Description

System and method for converting heat in a wellstream fluid to work

The present invention provides a system and method for utilising heat energy present in a wellstream for useful work, and a heat exchanger inside a well.

Such wellstream fluid is produced from a reservoir via a well. The wellstream typically contains a substantial amount of heat energy, such as up to 100 MW. The precise amount of heat energy will depend on factors such as the temperature of the well and wellstream, and the composition of the wellstream. For instance, a wellstream may contain a mixture of fluid components such as hydrocarbon gas, hydrocarbon liquid, carbon dioxide, nitrogen, water, glycol or other fluids added to the reservoir fluid to change its behaviour or properties. The proportion of each component in the wellstream fluid may vary between different reservoirs, and may vary over the lifetime of a reservoir. For instance, as a reservoir becomes older, water injected into the reservoir to maintain the reservoir’s pressure may become present in a greater proportion in the wellstream. The wellstream fluid properties will also vary with the composition of the wellstream fluid. For example, the heat energy in the wellstream fluid will be much higher if there is a majority of water present, or indeed if substantially only water is present, or if the liquid hydrocarbon fraction is high, due to a significantly higher heat capacity of liquids compared to gases.

For subsea wells, the heat from the well and wellstream is typically wasted by dissipating it into the sea water surrounding the well and the downstream pipeline. This dissipation is done so as to improve the transport efficiency of the wellstream away from the well. WO 2014/014358 describes a system where, instead of dissipating the heat to surrounding seawater, some of the heat in the wellstream is removed using a heat exchanger. The heat removed using the heat exchanger is then transported to a downstream location distant from the well where the removed heat is transferred back into the wellstream to maintain the temperature of the wellstream at the downstream location sufficiently high to prevent hydrate and wax formation. WO 2014/177188 describes a system where water is injected into a reservoir that has been made hot by a thermal hydrocarbon-recovery method. The reservoir is allowed to heat the water, and the water is then produced from the reservoir as a well stream. The heat is removed from the water at the Earth’s surface and the heat is used to produce steam.

The cooled water is then again injected into the reservoir. The steam is used in a thermal hydrocarbon-recovery method in a different reservoir.

In a first aspect the invention provides a system for converting heat in a wellstream fluid to work in order to drive at least one component, the system comprising: an energy converter being arranged to convert at least some of the heat energy in the wellstream to work; and the at least one component being arranged to be driven by at least some of the work output from the energy converter.

The present invention allows the system to harness heat energy in the wellstream and use this heat energy for useful work. This in turn allows for the energy consumption of the system from external sources to be reduced, or even eliminated, and so makes the system more efficient and environmentally friendly. In the vicinity of the wellhead, in typical systems there are usually several components that require power, such as compressor(s) and pump(s).

There may be a very large amount of heat energy in a wellstream fluid exiting the top of the well (which can be up to 100MW). As is mentioned above, this is usually wasted by dissipating it into surrounding sea water, or is used merely to heat other components (such as heating hydrocarbons in a transport pipeline as in WO 2014/014358, or creating steam for a thermal hydrocarbon-recovery method as in WO 2014/177188). However, the inventors have realised that if instead this heat energy were harnessed and converted into work, then the component(s) requiring power can be powered without the need for (or at least with reduced reliance on) an external power source, such as electricity supplied to the system. This makes the present system more environmentally friendly than prior systems.

When used subsea, the present system is advantageous as it does not require many topside modifications, whilst avoiding the need for conventional electrical power distribution apparatus (transformers, long-distance cables, power umbilicals, etc.) to deliver power to the location of the system. Thus, the system can be thought of as being self-sufficient, or at least more self-sufficient than prior systems. This is particularly beneficial when working on remote fields, such as satellite fields/wells, where to have inputs into the system, such as power and working fluid, from sources external to the system (which would mean that the system is not self-sufficient) is particularly costly/difficult.

Indeed, the system may even produce excess energy, which can then be exported to other systems (such as neighbouring wellheads), e.g. as electricity, or even exported to an electrical power transmission system, such as a grid.

Unlike the present invention, whilst the system of WO 2014/014358 does not merely dissipate heat in the wellstream to the surrounding environment, it does not generate any work in the vicinity of the well. The system of WO 2014/014358 therefore requires just as many external inputs into the system as a typical system (such as power for pumps/compressors). The system of WO 2014/014358 is therefore not self-sufficient.

Indeed, since WO 2014/014358 uses fresh water as the coolant, this must also be supplied from an external source, so the system of WO 2014/014358 is even less self-sufficient (i.e. requires more external inputs) than a typical system.

Also unlike the present invention, whilst the system of WO 2014/177188 does not merely dissipate heat in the wellstream to the surrounding environment, it does not generate any work using the heat from the wellstream. The system of WO 2014/177188 therefore still requires external inputs into the system (such as power for the compressor). The system of WO 2014/177188 is therefore not self-sufficient.

Further, there is no possibility of either of these systems being used to export energy from the system (e.g. in the form of electricity), as there is with the present system.

Cooling the wellstream fluid by extracting heat from it is also advantageous. When it is desired to move the wellstream away from the well (e.g. moving hydrocarbons in the wellstream away from the well), cooling the wellstream allows the wellstream to be more efficiently moved away from the well/system, e.g. through a pipeline to a platform. Cooling the wellstream fluid leads to an increased fluid density, this in turn leads to a decreased fluid velocity, which in turn leads to a lower resistance to flow.

Additionally/alternatively, when it is desired to inject, or re-inject, the wellstream into the reservoir (e.g. injecting water in the wellstream into the reservoir), cooling the wellstream allows the injected fluid to be cooler when it enters the reservoir and hence allows the reservoir to more efficiently heat the injected fluid before the injected fluid is again produced from the reservoir through the wellstream.

The wellstream is preferably a wellstream from a hydrocarbon reservoir, such as an oil and/or gas reservoir. The hydrocarbon reservoir may comprise fluid, such as water, oil and/or gas. The hydrocarbon reservoir may be one from which hydrocarbons are produced, or may be a partially depleted, or a substantially depleted reservoir. Over time the hydrocarbon reservoir may turn into a partially depleted or substantially depleted reservoir. The wellstream may be produced from a well in said reservoir. The reservoir, or the Earth’s formation in the vicinity of the reservoir, may act as the heat source for the wellstream.

Preferably, the system may comprise a wellstream fluid path being arranged to allow the wellstream fluid to pass therethrough. The system may comprise a working fluid path being arranged to allow a working fluid to pass therethrough. The working fluid path and the wellstream fluid path may be arranged so as not to generally allow fluids to pass between the two paths (except possibly via the working fluid supplier, when one is present (see below)). The system may comprise a heat exchanger being arranged to remove said heat energy from the wellstream fluid. The heat exchanger may be arranged to allow heat to be exchanged between the wellstream fluid in the wellstream fluid path and the working fluid in the working fluid path, but may not allow fluid to be exchanged between the working fluid path and the wellstream fluid path. The heat exchanger in this disclosure may be any means by which heat can be exchanged from one fluid (the wellstream fluid) to another fluid (the working fluid). The energy converter and the working fluid path may be configured such that the energy converter converts at least some of the energy in the working fluid in the working fluid path exiting the heat exchanger to work. The working fluid path may be a closed loop.

Thus, the energy converter may be in communication with the heat exchanger such that at least some of the removed energy can be communicated from the heat exchanger to the energy converter.

Alternatively, the energy converter can directly extract heat from the wellstream and convert it into work, such as by applying heat from the wellstream directly to a heat engine, such as a Stirling engine (i.e. there may be no need for the working fluid). Although a heat engine can also use the heated working fluid exiting the heat exchanger as its heat source.

The at least one component may be in communication with the energy converter such that at least some of the work generated by the energy converter can be communicated to the at least one component.

Thus, the energy converter converts heat in the wellstream to work. The heat in the wellstream may be heat present due to the temperature of the reservoir. However, heat may also be present in the wellstream due to the wellstream being treated in a way that increases its temperature, for example by compressing it. Thus, if there is a compressor present (that may be powered by an external power source), then this may pressurise and add heat to the wellstream. This heat can be converted by the energy converter to work, which can then be used to power other component(s) (or partially power the powered compressor).

The location at which heat is removed from the wellstream (e.g. the heat exchanger or heat engine), or indeed the entire system, may be located in the vicinity of a well, such that the wellstream fluid is preferably hot when it reaches the heat exchanger. For instance, this location may be located at or near the wellhead. Preferably, this location is in the vicinity of the wellhead such that the wellstream fluid at the location (e.g. entering the heat exchanger or heat engine) is at least 50°C, 100°C, 150°C or 200°C, preferably between 70-200°C, preferably between 100-200°C.

The location may be at the Earth’s surface (e.g. the sea bed), for example downstream of the well, such as in the vicinity of or adjacent to a wellhead. Alternatively/additionally, the location at which heat is removed from the wellstream may be within the well itself. This may be achieved for example using the heat exchanger of the third aspect, whose details are provided below. The features of the third aspect can be combined with those of the first and/or second aspects. However, it may also be achieved by for example using a heat engine, such as a Stirling engine, within the well itself. This heat engine may be powered from the heat in the working fluid of the heat exchanger of the third aspect (see below), or may be powered directly from the heat in the wellstream directly (e.g. with no need for the heat exchanger).

Heat may be removed from the wellstream at a plurality of locations.

The at least one component may comprise a component that requires power that is typically present in the vicinity of a wellhead, such as compressor(s) or pump(s) or control systems or instrumentation.

Preferably, the at least one component may be driven directly by the energy converter. By “directly” it is intended to mean that energy absorbed by and output from the energy converter is transmitted to the at least one component to cause similar/corresponding energy of the at least one component without being converted into another form of energy, such as electricity. The transmission may be via some physical mechanical transmission -such as a shaft and/or gearing and/or fluid - that transmits the work output from the energy converter to the at least one component, or by some other transmission - such as a magnetic couple or clutch - that transmits the work. This may maximise the efficiency of the system. The at least one component may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source, such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the at least one component may be configured to be switched to be driven directly by the energy converter.

The at least one component may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and another (external) electricity source (when electricity from the energy converter is not available such as prior to well production and during well production start-up). The at least one component may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) source, preferably electrical, such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the at least one component may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

The system may comprise a motor configured to be driven by the (additional or external) power source, such as a power umbilical or battery. The motor may drive the at least one component, preferably via the same transmission between the energy converter and the at least one component (such as the drive shaft, see below).

Preferably, the at least one component may comprise a compressor arranged to pressurise a/the wellstream fluid entering the compressor. The compressor may be located in the wellstream fluid path. Preferably, the compressor may be configured to pressurise the same wellstream as the heat energy was removed from. However, it may alternatively/ additionally be configured to pressurise a different wellstream. A/the compressor may be used to move the wellstream (e.g. hydrocarbons) away from the vicinity of the well (e.g. topside). Additionally/alternatively, a/the compressor may be used as an injector to inject the wellstream (e.g. substantially all water) into a reservoir (which may be the same as or different to the reservoir from which the wellstream is produced).

Preferably, the compressor may be driven directly by the energy converter (e.g. via some mechanical or magnetic transmission that transmits the work output from the energy converter to the compressor directly). This may maximise the efficiency of the system. The compressor may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source, such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the compressor may be configured to be switched to be driven directly by the energy converter.

The compressor may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and an external electricity source (when generated electricity is not available such as prior to well production and during well production start-up). The compressor may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the compressor may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

It is known for typical subsea systems to use a compressor in the vicinity of the wellhead to compress the wellstream fluid. In the prior art, such a compressor requires power from an external source (such as electricity supplied to it from a topside generator). The present system reduces or removes the reliance on such an external source.

The compressor may be located downstream of the location at which the heat is removed from the wellstream (e.g. the heat exchanger or heat pump) with respect to the flow of the wellstream. The compressor may be located in the wellstream fluid path downstream of this location. This means that the wellstream fluid that the compressor acts upon is relatively cool, which is preferable. Compression tends to increase not only the pressure of the wellstream fluid but also the temperature. It is therefore preferable to compress the wellstream fluid after it has been cooled by having had heat removed.

Additionally or alternatively, the at least one component may comprise a pump arranged to pump the wellstream fluid entering the pump. The pump may be located in the wellstream fluid path. Preferably, the pump may be configured to pump the same wellstream as the heat energy was removed from. However, it may alternatively/additionally be configured to pump a different wellstream. A/the pump may be used to move the wellstream (e.g. hydrocarbons) away from the vicinity of the well (e.g. topside). Additionally/alternatively, a/the pump may be used as an injector to inject the wellstream (e.g. substantially all water) into a reservoir (which may be the same as or different to the reservoir from which the wellstream is produced). Additionally/alternatively, a/the pump may be located within the well, preferably at the base of the well, to boost production of the wellstream within the well.

Preferably, the pump may be driven directly by the energy converter (e.g. via some mechanical or magnetic transmission that transmits the work output from the energy converter to the pump directly). This may maximise the efficiency of the system. The pump may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the pump may be configured to be switched to be driven directly by the energy converter.

The pump may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and an external electricity source (when generated electricity is not available such as prior to well production and during well production start-up). The pump may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the pump may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

It is known for typical subsea systems to use a pump in the vicinity of the wellhead to pump the wellstream fluid. In the prior art, such a pump requires power from an external source (such as electricity supplied to it from a topside generator). The present system reduces or removes the reliance on such an external source.

The pump may be located downstream of the location at which the heat is removed from the wellstream (e.g. the heat exchanger or heat pump) with respect to the flow of the wellstream. The pump may be located in the wellstream fluid path downstream of this location. This means that the wellstream fluid that the pump acts upon is relatively cool, which is preferable. Pumping tends to increase the temperature of the wellstream fluid. It is therefore preferable to pump the wellstream fluid after it has been cooled.

Additionally or alternatively, the at least one component may comprise an injector arranged to inject fluid into a reservoir. The injector may be arranged to inject the wellstream fluid entering the injector into a reservoir. Alternatively, the injector may be arranged to inject working fluid (such as water or CO2) into a reservoir (see third aspect for more details).

Preferably the reservoir is the same reservoir as the wellstream is produced from, but it may also be a different wellstream.

When the injector injects the wellstream, the injector may be located in the wellstream fluid path. Preferably, the injector may be configured to inject the same wellstream as the heat energy was removed from. However, it may alternatively/additionally be configured to inject a different wellstream. The injected wellstream fluid may be substantially all water.

When the injector injects the working fluid, the injector may be located in the working fluid path.

The injector may comprise a pump and/or a compressor (e.g. the pump and/or compressor discussed above and herein).

Preferably, the injector may be driven directly by the energy converter (e.g. via some mechanical or magnetic transmission that transmits the work output from the energy converter to the injector directly). This may maximise the efficiency of the system. The injector may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the injector may be configured to be switched to be driven directly by the energy converter.

The injector may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and an external electricity source (when generated electricity is not available such as prior to well production and during well production start-up). The injector may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the injector may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

The injector may be located downstream of the location at which the heat is removed from the wellstream (e.g. the heat exchanger or heat pump) with respect to the flow of the wellstream. The injector may be located in the wellstream fluid path downstream of this location. This means that the wellstream fluid that the injector acts upon is relatively cool, which is preferable since it is optimal to inject a cool fluid into the reservoir.

Additionally or alternatively, the at least one component may comprise a separator arranged to separate the wellstream fluid entering the separator into at least two separate fluid streams, said fluid streams comprising different components. A first separated fluid stream may comprise substantially all water and a second separated fluid stream may comprise hydrocarbons, and possibly also C02 and impurities. The separator may be used if the wellstream comprises water and hydrocarbons. There may be no need for a separator if the wellstream comprises substantially only water or hydrocarbons.

The separator may be located in the wellstream fluid path.

The separator may be upstream of the pump(s) and/or compressor(s) and/or injector(s) and/or the location(s) at which heat is removed. However, the separator may be downstream of the (first, at least) location at which heat is removed.

The separated water fluid stream may go on to the injector, possibly via a heat-removing location (e.g. a heat exchanger in communication with the energy converter, or a heat engine).

The separated hydrocarbon-containing fluid stream may go on to the pump and/or compressor, possibly via a heat-removing location (e.g. a heat exchanger in communication with the energy converter, or a heat engine).

Preferably, the separator may be driven directly by the energy converter (e.g. via some mechanical or magnetic transmission that transmits the work output from the energy converter to the separator directly). This may maximise the efficiency of the system. The separator may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the separator may be configured to be switched to be driven directly by the energy converter.

The separator may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and an external electricity source (when generated electricity is not available such as prior to well production and during well production start-up). The separator may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the separator may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

The location at which the heat is removed may be a first location at which the heat is removed from the wellstream (e.g. a first heat exchanger or a first heat engine). The system may further comprise a second location at which heat is removed from the wellstream (e.g. a second heat exchanger or second heat engine). Preferably, the second location is downstream of the at least one component, such as the compressor, pump, separator and/or injector, with respect to the flow of the wellstream. The second heat exchanger may allow heat to be exchanged between the wellstream fluid in the wellstream fluid path downstream of the at least one component and the working fluid in the working fluid path.

Cooling the wellstream fluid at the second location is also advantageous as it allows the wellstream to be more efficiently moved away from the well/system, e.g. through a pipeline to a platform. Cooling the wellstream fluid leads to an increased fluid density, this in turn leads to a decreased fluid velocity, which in turn leads to a lower resistance to flow. Further, when the cooled wellstream is to be re-injected into the reservoir it increases the efficiency of the heat transfer from the reservoir to the injected fluid if the fluid is cool.

As mentioned above, when the compressor, pump, and/or injector acts on the wellstream fluid, the temperature of the wellstream fluid tends to increase. In order to further increase the efficiency of the system, the inventors have realised that heat energy in the wellstream fluid exiting the compressor, pump, and/or injector can be harnessed and converted into work, in a similar fashion to the heat energy in the produced wellstream fluid exiting the wellhead.

Whether a pump, compressor and/or injector is used may depend on the composition and/or state of the fluid (e.g. the liquid and/or gas proportions of the wellstream fluid).

Preferably, an energy converter may be arranged to convert at least some of the heat energy removed from the wellstream at the first and second locations (e.g. by the first and second heat exchangers or heat engines) to work, which may be used to drive at least one component of the system. This energy converter may preferably be the same energy converter that is used to convert energy from the wellstream fluid at the first location. The energy converter and the working fluid path may be arranged to convert at least some of the energy in the working fluid in the working fluid path exiting both the first and second heat exchangers to work.

The first and second heat exchangers may be arranged in parallel with each other, with respect to the working fluid. The first and second heat exchangers may be arranged in series with each other, with respect to the wellstream fluid.

When heat engine(s) are used, these may drive the same or different component(s). A heat engine can be used at one of the first and/or second location and a heat exchanger can be used at the other.

Additionally or alternatively, the at least one component may comprise a pump being arranged to move the working fluid around the working fluid path. The pump may be located in the working fluid path. In order to transport the energy from the location at which energy is removed from the wellstream to the energy converter, it may be necessary to have a pump. The inventors have realised that this pump may advantageously be powered by the energy converter. This pump may be used to pump working fluid through the well (for example when the heat exchanger is in the well, see the third aspect for details). The pump may be located within the well or may be located downstream of the well (e.g. proximate the Earth’s surface or wellhead) with respect to the wellstream flow.

Preferably, the pump may be driven directly by the energy converter (e.g. via some mechanical or magnetic transmission that transmits the work output from the energy converter to the pump directly). This maximises the efficiency of the system. The pump may be configured to be driven during start-up of the system (i.e. start-up of well production) using an (external) power source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the pump may be configured to be switched to be driven directly by the energy converter.

The pump may alternatively be driven by electricity generated using the work output from the energy converter. This would ease switching between using generated electricity from the energy converter (when available) and an external electricity source (when generated electricity is not available, e.g. prior to well production and during well production start-up). The pump may be configured to be driven during start-up of the system (i.e. startup of well production) using an (external) power source, preferably an electrical source such as a power umbilical or preferably a battery (as discussed below). Once the system has started, the pump may be configured to be switched to be driven electrically by electricity generated using the work output from the energy converter.

With regard to the working fluid path, preferably the output of the pump is connected (directly) to the input of heat exchanger(s). The input of the pump may be connected (directly) to the output of the energy converter, or there may be one or more components intermediate the energy converter and the pump such as a working fluid-cooling heat exchanger (see below). The working fluid and the working fluid path may be arranged such that the pump pumps liquid working fluid. Liquid working fluid may enter the heat exchanger(s) where it is evaporated. Gaseous working fluid may pass from the heat exchanger(s) to the energy converter. The energy converter may cool and/or condense the working fluid (e.g. gaseous working fluid may condense in the turbine). The working fluid output from the energy converter may be liquid and/or gas. The working fluid output from the third heat exchanger may have been cooled to a liquid. This will increase the efficiency of the energy converter system.

Additionally or alternatively, the at least one component may comprise an electrical generator. The at least one component may also comprise an electrical component, and the electrical generator may be arranged to power the electrical component. The system may comprise a plurality of electrical components, and the electrical generator may be arranged to power the plurality of electrical components. The electrical generator may be arranged to power every electrical component in the system. There may be additional electrical component(s) in the vicinity of the system, e.g. in other systems in the vicinity of the wellhead, and the electrical generator may be arranged to power said electrical component(s). The electrical generator may also be configured to charge a battery (see below) if/when it produces excess electrical power (i.e. more power than required by the electrical component(s)).

The electrical generator may be configured to produce electrical energy for exporting outside of the system (e.g. it may be connected to power transmission lines or a grid). This may be in addition to or as an alternative to generating electricity for use in the system, in a neighbouring system, or in charging a battery.

The electrical generator may be run as a generator and may be reversed to run as a motor when supplied with energy (e.g. from the battery or from an external source).

The electrical component(s) may comprise the pump(s) and/or the compressor(s) and/or the injector(s) and/or separator(s).

The at least one electrical component may be arranged to be driven, not only by the work output from the energy converter, but also by another (external) power source (e.g. via the motor powered by an electrical source such as a power umbilical or preferably a battery (as discussed below)). Prior to well production and during well start-up, for example, there may be insufficient heat energy to generate sufficient work to drive the at least one component.

The energy converter and the motor may be able to drive the at least one component simultaneously. In present systems, for example, a motor’s size is typically limited, for example to around 12 MW, and it can be difficult to upgrade and/or replace the motor with a more powerful motor. Thus, the work doable by the at least one component may be limited in such existing systems. However, with the present system, the work done by the component can be increased, in some cases at least doubled, by supplementing the work done by a motor with work from the energy converter.

When there is insufficient heat energy, an additional/external power source, such as a power umbilical or preferably a battery (as discussed below), may be used. When there is sufficient heat energy, the work output from the energy converter may be used. The system, or (each of) the at least one component, may comprise a switching means for switching between using the work output from the energy converter to using the additional/external power source, and vice versa. The additional/external power source may comprise an electrical power source (e.g. including a power umbilical or battery, when the system is subsea) or may comprise a mechanical power source (e.g. an engine). The system may comprise the additional/external power source.

Thus, the additional/external power source may be used in order to start production. However, it may not be necessary for the present system to require an additional/external power source, and a mechanical method of start-up is discussed below with regard to the method.

As an alternative to, or in addition to, the energy converter being powered by the working fluid and heat exchanger(s), the energy converter may comprise a heat engine, such as a Stirling engine, as noted above. The heat engine may be driven by the heat directly from the wellstream (e.g. from the wellstream path upstream of the heat exchanger, the at least one component, downstream of the at least one component (but upstream of the second heat exchanger)), the heat extracted from the wellstream by the heat exchanger (e.g. from the working fluid path downstream of the heat exchanger and/or the second heat) and/or by any other heat source present in the system or in the vicinity of the system. The heat engine may drive the at least one component (e.g. the compressor, the pump, the working fluid pump, the motor, the generator, etc.) as discussed above.

The energy converter may be a first energy converter, and the system may comprise at least one second energy converter. The second energy converter may be arranged to drive the at least one component (e.g. the compressor, the pump, the working fluid pump, the motor, the generator, etc.) in combination with the first energy converter.

The second energy converter may comprise one or more heat engines, such as a Stirling engine. The heat engine(s) may be driven by the heat in a fluid stream in the system or in the vicinity of the system. Such a fluid stream may be the wellstream (e.g. from the wellstream path upstream of the heat exchanger or downstream of the at least one component (but upstream of the second heat exchanger)), the heat extracted from the wellstream by the heat exchanger (e.g. from the working fluid path downstream of the heat exchanger) and/or by any other heat source present in the system or in the vicinity of the system. Thus, there may be a heat engine in the working fluid path downstream of the heat exchanger, a heat engine in the working fluid path downstream of the second heat exchanger, a heat engine in the wellstream fluid path upstream of the heat exchanger and/or a heat engine in the wellstream fluid path downstream of the at least one component (but upstream of the second heat exchanger).

The first and/or second heat engine(s) (such as a Stirling engine) may also be used during start-up where heat supplied to the heat engine (e.g. from an energy storage system, such as a battery, see below) may be used to drive the energy converter to output work to produce fluid flow in the system during start-up.

Additionally/alternatively, the second energy converter may comprise one or more energy converters for converting a pressure differential in a fluid path into work, such as a turbine. There may be a source of such a pressure differential in the wellstream, or in another fluid stream in the system.

For instance, one such pressure differential may be present at a location in the wellstream. At certain locations in the wellstream, the fluid pressure may be relatively high. At other locations, the fluid pressure may be required to be relatively low. In order to drop the pressure, a throttle or choke valve is typically used. However, the inventors have realised that a turbine could instead be used to lower the pressure whilst also converting energy to work.

The wellstream fluid may undergo a pressure drop as it exits the well, i.e. between the well (or Xmas tree at the well) and the location at which heat is removed from the wellstream (e.g. the heat exchanger or heat engine). Thus, one such energy converter may be located at this location. This energy converter could be used instead of a throttle or choke valve that is typically used here.

The wellstream fluid may undergo a pressure drop before it reaches a topside processing plant, i.e. downstream of the at least one component and/or second location at which heat is removed from the wellstream (e.g. the second heat exchanger or second heat engine). Thus, there may be an additional/alternative energy converter here. This energy converter could be used instead of a throttle or choke valve that may typically be used here.

Another possible source for a pressure differential is an additive fluid source in the system. Such an additive may be an additive for avoiding hydrate formation, such as glycol (MEG). Typical subsea systems have such a glycol source that is connected to the wellstream downstream of the well. This is particularly the case where the wellstream comprises hydrocarbons.

The glycol is introduced into the wellstream by ensuring that the glycol source pressure is greater than the wellstream pressure. Again, a throttle is typically used to reduce the pressure of the glycol prior to it entering the wellstream. However, the inventors have realised that the excess pressure can be converted into work and hence used for a useful purpose, rather than being simply dissipated.

Thus, the present system may comprise a wellstream additive source, such as a source of glycol. The wellstream additive source may be configured to introduce additive into the wellstream, preferably downstream of the well, and possibly upstream or downstream of the location at which heat is removed from the wellstream (e.g. the heat exchanger or heat engine). The wellstream additive source may comprise an additive fluid that is at higher pressure than the wellstream fluid at the location of the wellstream fluid path into which the additive fluid is to be added. The system may comprise an energy converter that reduces the pressure of the additive fluid prior to it entering the wellstream fluid path and converts the pressure change into work. This energy converter may be a turbine in the glycol fluid path.

The work generated by the at least one additional energy converter may be used to directly drive the at least one component, or may be converted to electricity by a generator (which may be the generator driven by the energy converter or may be a different generator). The work generated by the additional energy converter may drive the same or different component(s) as the energy converter.

In addition to driving the at least one component, the energy converter and/or the additional energy converter(s) may be used to charge an energy storage system, such as a battery. Thus, the system may comprise an energy storage system (such as a battery) that is arranged to be charged by the energy converter and/or the additional energy converter(s). Each respective energy converter may have its own energy storage system, or may charge the same energy storage system. The energy storage system may be charged only when there is excess energy converted by the energy converter(s), i.e. when there is more than enough energy generated by the energy converter(s) to power any and all necessary components.

The energy stored in the energy storage system(s) may be used during start-up to run the at least one component, and/or to run the energy converter(s) in a reverse-mode so as to output heat and/or work from input energy. This may be necessary as during start-up there may not be sufficient heat present to drive the at least one component. This may be augmented by the use of pressure build up below the wellhead during shut down (see method discussion below).

Such an energy storage system may reduce or remove the need for a power umbilical, and hence may make the present system more self-sufficient.

The energy storage system may also be used to power other components in the system such as instrumentation and control systems.

The battery may be arranged to supply energy to component(s) of the system (such as the heat engine(s) and/or the pump(s) and/or the compressor(s) and/or injector(s) and/or separator(s)). This may be used to start said component(s) before wellstream fluid begins flowing during start-up (and hence before a source of heat energy is present). This may be referred to as kick-starting the component(s). For example, when an energy converter (such as a Stirling engine) drives an electrical generator which in turn is connected to charge the battery, the battery may be arranged to supply power to the generator such that the generator acts as a motor to drive the energy converter.

The at least one component (such as the compressor or pump) may be configured to act upon the same wellstream as the heat energy was removed from, or may be configured to act upon a different wellstream. There may be a plurality of such components driven by the energy converter, each component acting upon different wellstreams.

Preferably the working fluid is a hydrocarbon (such as one or more condensate components, such as C4, C5 and/or C6 hydrocarbons, like butane, pentane and/or hexane), preferably extracted from the wellstream (when the wellstream comprises hydrocarbons). Using a hydrocarbon working fluid is particularly advantageous as there is a ready supply of the working fluid obtainable from the wellstream. Further, should any of the working fluid leak into the wellstream (which may occur for example between a transmission link, such as a drive shaft, between the energy converter, such as the turbine (see below), and the compressor/pump in the wellstream, and because the pressure of the working fluid may be greater than the pressure of the wellstream fluid at the at least one component) the working fluid will not contaminate the wellstream with any foreign (e.g. non-hydrocarbon) fluid.

However, the system is not limited to the use of a hydrocarbon working fluid. Any suitable working fluid could be used, supplied and managed in a conventional/known manner.

For instance C02 could be used as working fluid. C02 may be particularly advantageous because it is a clean, commonly used working fluid with good properties for use as a working fluid.

Using a C02 working fluid is particularly advantageous as there may be a ready supply of the working fluid obtainable from the vicinity of the present system. For example, the wellstream typically includes a portion of C02 (typically around 1-5%), e.g. when the wellstream comprises hydrocarbons. Also, in the vicinity of some wells/reservoirs there may be some C02 injection systems, where C02 has been captured from a power station and is piped from the power station toward a reservoir where it is injected into the reservoir. Such a C02 injection system, if in the vicinity of the present system, may also give an adequate source for C02 working fluid. Indeed the C02 injection system could be at least partly driven by (any of) the energy converter(s) discussed above, i.e. the at least one component could comprise the C02 injection system.

Further, should any of the working fluid leak into the wellstream (which may occur for example between a transmission link, such as a drive shaft, between the energy converter, such as the turbine (see below), and the compressor/pump in the wellstream, and because the pressure of the working fluid may be greater than the pressure of the wellstream fluid at the at least one component) the working fluid may not contaminate the wellstream with any foreign fluid (e.g. because C02 may be a typical component of the wellstream anyway).

In order to prevent contamination of the wellstream with the working fluid, the energy converter side may have a higher pressure compared to the wellstream fluid path at the at least one component. This would mean that if there is any leak between the working fluid path and the wellstream fluid path, working fluid would leak into the wellstream fluid and not the other way around.

However, the energy converter may also comprise a barrier, such as a barrier fluid. The barrier may prevent working fluid entering the wellstream in the vicinity of the at least one component. The barrier fluid pressure may be higher than the working fluid and wellstream fluid pressure. This will allow the barrier fluid to prevent contamination of the wellstream fluid by the working fluid. In the case of a transmission device, such a magnetic coupling, being used there may be a physical barrier between the working fluid path and the wellstream fluid path, which may avoid working fluid contamination.

Preferably, the system may comprise a working fluid supplier. The working fluid supplier may be configured to extract an appropriate working fluid from a/the wellstream and supply at least some of the extracted working fluid to the heat exchanger(s). The wellstream may be the same wellstream from which heat has been, or is, removed or may be a different wellstream. Alternatively, the working fluid supplier may be configured to extract an appropriate working fluid (such as CO2) from a source in the vicinity of the system (such as pipeline of C02 for a C02 injection well).

The inventors have realised that, since the wellstream fluid may comprise some components that are suitable for use as a working fluid in a heat-exchanger system (such as one or more condensate components, such as C4, C5 and/or C6 hydrocarbons, like butane, pentane and/or hexane, C02 or water), the system may use such components as the working fluid. This helps the system to be self-contained/sufficient, which is particularly advantageous when the system is subsea. Over time, it may be necessary to top-up or change the working fluid. Without the working fluid supplier, the operator would need to intervene in the system to supply new working fluid. With the present working fluid supplier, such intervention is not necessary.

The working fluid supplier may be in communication with the wellstream path and the working fluid path. The working fluid supplier may supply at least some of the extracted working fluid to the working fluid path, preferably upstream of the pump, preferably downstream of the energy converter, preferably downstream of the working-fluid cooling heat exchanger (see below).

Preferably, the working fluid supplier is in communication with the wellstream path upstream of the at least one component, and preferably downstream of the location at which heat is removed from the wellstream. This allows the pressure of the working fluid to be substantially equal to the pressure of the wellstream path upstream of the at least one component. The pressure of the wellstream path upstream of the at least one component (and hence the pressure in the working fluid path) is typically greater than at downstream locations, such as the at least one component itself. Thus, it should be appreciated that due to the location of the working fluid supplier, the working fluid pressure at the energy converter is greater than the wellstream pressure at the at least one component. This is advantageous as there may be a path for working fluid to contact the wellstream fluid (and vice versa) at the energy converter and the at least one component (e.g. the common shaft). Since the pressure of the working fluid here is greater than the pressure of the wellstream here fluid, this prevents wellstream fluid from entering the working fluid path, which would be disadvantageous as the wellstream fluid would reduce the effectiveness of the working fluid. On the other hand it is not particularly disadvantageous for the working fluid to leak back into the wellstream fluid, as it would simply be replaced by more working fluid from the working fluid supplier.

The working fluid supplier may be configured to controllably extract the appropriate working fluid from the wellstream. The working fluid supplier may be configured to controllably supply the extracted working fluid to the heat exchanger(s). This control may be an active control, i.e. the amount of fluid extracted from the wellstream fluid is controlled depending on the need, and the amount of fluid supplied to the heat exchanger(s) is controlled depending on the need. The working fluid supplier may be controllable by the operator, and/or may be controllable by a processor. There may be one or more sensors sensing working fluid quality and/or level, which may be used in the controlling of the working fluid supplier. The working fluid supplier may also be able to allow working fluid in the working fluid path to be exhausted back into the wellstream fluid path, e.g. if there is too much working fluid in the working fluid path, or if the working fluid in the working fluid path becomes old or starts to have a reduced performance.

The working fluid supplier may comprise a membrane for extracting the working fluid (such as C02) from the wellstream.

Preferably, the working fluid supplier comprises a store, such as a tank, for storing at least some of the extracted working fluid. The tank may be used to store the extracted working fluid prior to supplying the working fluid.

Preferably, the working fluid supplier comprises a separator for selecting the appropriate (e.g. appropriate hydrocarbon) working fluid components from the wellstream fluid.

The system may comprise a third heat exchanger, also described as a working fluid heat exchanger. The third heat exchanger may be arranged to allow heat to be exchanged between the working fluid output from the energy converter and a cooling fluid. The third heat exchanger may be located in the working fluid path. The third heat exchanger may be the working fluid-cooling heat exchanger mentioned above. The third heat exchanger may be (immediately) downstream of the energy converter. The third heat exchanger may be (immediately) upstream of the pump. The third heat exchanger is preferably between the output of the energy converter and the input of the (first) heat exchanger. The third heat exchanger is preferably between the output of the energy converter and the input of the working fluid pump. The cooling fluid may preferably be sea water.

The inventors have found that cooling the working fluid prior to it entering the (first) heat exchanger allows for increased heat energy transfer from the wellstream fluid to the working fluid, and hence increased energy transfer from the wellstream fluid to the energy converter.

It should be noted that “third” here is merely a label to distinguish this heat exchanger from any other heat exchanger in the system. It does not necessarily mean there are two other heat exchangers present.

The working fluid and/or the working fluid path may also be arranged so as to cool and/or heat component(s) in the system, to improve or optimise the performance of the component(s). For instance, it may be arranged to cool the (electric) motors and/or may be arranged to heat the energy storage system (e.g. the battery) to improve the performance of the component(s).

The working fluid may be used as a barrier fluid for component(s) that are required to be (or preferably) protected from wellstream fluid(s).

Preferably, the energy converter comprises a turbine. In this disclosure, the term “turbine” is intended to mean any rotating device that may mechanically and directly convert the energy in a fluid flow (such as the working fluid exiting the heat exchanger(s)) to rotational kinetic energy and hence to useful work. The output of the energy converter may be a rotating member, such as a shaft. The rotating member is advantageous as it can be used to directly drive the compressor, the pump and/or the electrical generator. For instance, a compressor typically requires a rotating drive member to drive the compressor-the rotating member can be used for this. Further, a pump typically requires a rotating drive member to drive the pump - the rotating member can be used for this. For instance, the pump may comprise an impeller attached to the rotating member. Further, an electrical generator typically requires a rotating drive member to drive the generator - the rotating member can be used for this. For instance, the rotor of the generator can be attached to the rotating member. Of course, suitable transmission/gearing may be present between the rotating member and (each of) the at least one components, e.g. if it is desired to alter the speed of rotation between the rotating member and the compressor, pump and/or electrical generator.

When the additional/external power source is present (such as the power umbilical or battery) to power a motor, the motor may preferably act on the rotating member, causing the rotating member to rotate, and thus drive the at least one component. However, the external power source may also act through a drive train separate to the rotating member.

The system may be a subsea system. The system offers some particularly strong advantages when it is used in the subsea environment. For instance, in subsea environments, it can be difficult to maintain systems and to provide power to systems. The present system is a more self-contained, self-sufficient solution than the prior art systems (indeed it can be completely self-contained/sufficient). This reduces the need for external power to be supplied to the system and for the operator to intervene (such as when replacing/managing the working fluid), which can be difficult in subsea systems. The system may be located proximate or on the seabed, such as proximate to or on a wellhead template or Xmas tree mounted to the seabed

The system may be a module that can be mounted to a template and/or wellhead and/or Xmas tree. This is particularly advantageous as it eases installation of the system.

By module, it is intended to mean a unit that can be handled, moved and installed as a single unit. It is preferably completely self-contained or self-sufficient, at least for energy (and working fluid) consumption. However, the power output from the energy converter could be used to power components outside of the module also.

The system may also be located at least partially within the well itself. For instance, the working fluid, the (first) heat exchanger, the energy converter, the working fluid path, the at least one component and/or any of the other components discussed herein may at least partially (but possible totally) be located within the well. This may be achieved for example using the heat exchanger of the third aspect, whose details are provided below. The features of the third aspect can be combined with those of the first and/or second aspects. However, it may also be achieved by for example using a heat engine, such as a Stirling engine, within the well itself. This heat engine may be powered from the heat in the working fluid of the heat exchanger of the third aspect (see below), or may be powered directly from the heat in the wellstream directly (e.g. with no need for the heat exchanger).

The well/wellstream is preferably a hydrocarbon well/wellstream. The hydrocarbon wellstream may comprise liquid hydrocarbons and/or gaseous hydrocarbons and/or water and/or C02 and/or other impurities. It can be more advantageous to use the present system on hydrocarbon wellstreams that have significant (e.g. at least 10, 20, 30, 40, 50% by volume) liquid hydrocarbons levels, as liquid hydrocarbons have a greater heat capacity and thermal conductivity in comparison to gaseous hydrocarbons.

Alternatively, the well/wellstream can be a hydrocarbon well/wellstream where the water content is high. Indeed the well/wellstream may comprise at least a majority or substantially entirely a water well/wellstream. The water may be liquid water. Liquid water has a very high heat capacity and so may be advantageous.

When water and hydrocarbons are present in the same wellstream, the system may comprise the separator discussed above.

In a particular case, the wellstream may be at least a majority water, preferably at least 70%, 80%, 90%, 95% or 99% by volume water.

This may be the case where the reservoir is used as a heat source for producing energy.

The inventors have devised a system where fluid (e.g. water) is injected into a reservoir, the injected fluid is allowed to gain heat from the reservoir, and the injected fluid is then removed from the reservoir as the wellstream. The wellstream fluid can then act as a heat source, which the present system can turn into useful work using any of the features discussed herein.

The reservoir in question may be a depleted or partially depleted hydrocarbon reservoir. It is preferably not a reservoir that has had a thermal recovery method performed on it; rather it may use the naturally-present heat of the reservoir. The inventors have realised that the temperature in a reservoir may be sufficient to heat injected fluid by (significantly) more than the energy required to inject fluid into the reservoir. Thus, preferably, the injected fluid is heated by an amount sufficient such that the work energy converted from the heat energy extracted from the fluid is equal to or more than the energy required to inject the fluid (e.g. per unit mass/volume). For instance, for a certain reservoir at a temperature of around 140°C, the work produced from the heat energy gained by the injected fluid may be around 5-10 times greater than the work required to inject the fluid into the reservoir.

The reservoir may be around 50-250°C, preferably 60-150°C. The reservoir may be around 0.5-3km deep, preferably 1-2km deep.

The injected fluid may be injected into the reservoir from the surface, e.g. the sea bed. The injected fluid may be injected into the reservoir through a well/bore. The well/bore may be an existing well/bore previously used in the extraction of hydrocarbons from the reservoir, e.g. such as an injection well or a production well.

The injected fluid may be injected at a distance from the well through which the wellstream is produced. This distance may be such that the injected fluid takes enough time and absorbs enough heat from the reservoir before it is produced in the wellstream. This will be dependent on the heat of the reservoir, the depth of the reservoir and the permeability of the reservoir, amongst other factors. The distance may be a substantially horizontal distance. The distance may preferably be around 0.5-5km, preferably 1-3km. The injected fluid may be in the reservoir for an average of at least 1 day, 10 days, 1 month, 6 months, 1 year or 2 years before it is produced in the wellstream.

The injection of the injected fluid may act to maintain the pressure of the reservoir, and hence maintain the production of the wellstream. Without the injection, the production of the wellstream would eventually slow and/or cease. The system may be thought of as a closed loop system, where the fluid (e.g. water) is cycled around a closed loop where it is injected into the reservoir, heated in the reservoir, produced to the surface, cooled at the surface (e.g.by extracting at least some of its heat energy for converting into work) and then re-injecting the water.

There may be two or more wellstreams used in the present system. At least one may have at least a majority of hydrocarbons (preferably substantially all hydrocarbons) and at least one may have at least a majority of water (preferably substantially all water).

When a mixture of hydrocarbons and water is present in a wellstream, the system may comprise the separator for separating the water and the hydrocarbons. As mentioned above, the system may also comprise an injector for injecting the (separated) water back into the reservoir. The at least one component mentioned above may comprise the separator and/or the injector. Thus, the separator and/or injector may be powered using the work output from any of the energy converter(s) mentioned above.

Thus, the separator and/or the injector may be driven by energy converted by the energy converter(s) from the heat of the wellstream. This heat may be heat in the unseparated wellstream, the separated hydrocarbon wellstream and/or the separated water wellstream. As can be appreciated, the more water is in the wellstream, the greater the amount of energy that is required to separate and inject it. However, the more water that is in the wellstream, the more heat will be present in the wellstream (due to water’s large heat capacity), so the more energy can be extracted from the wellstream to drive the separator and/or injector. This water re-injection system may be therefore at least self-compensating (e.g. when the water is injected to boost efficiency of the hydrocarbon production) or may provide a source of energy for use in the system (or for export from the system).

The system may not comprise any external power source such as a power umbilical coming from the topside. The system may not comprise any external working fluid input.

The system may therefore be thought of as self-sufficient.

In a second aspect, the invention provides a method of converting heat in a wellstream fluid to work to drive at least one component, the method comprising removing heat energy from a wellstream; converting at least some of the removed heat energy to work using an energy converter; and driving the at least one component using the work output from the energy converter.

The energy may be removed and transported from the wellstream to the energy converter via a working fluid. The working fluid may flow through a working fluid path. This path may be a closed loop.

Additionally/alternatively, the energy may be removed from the wellstream directly by the energy converter (e.g. a heat engine).

The method may preferably be performed during production of the wellstream from a well.

Preferably, the at least one component may be a compressor. The method may comprise pressurising the wellstream fluid entering the compressor using the compressor.

Additionally/alternatively, the at least one component may be a pump. The method may comprise moving the wellstream fluid entering the pump using the pump.

The compressor and/or pump may be located downstream of the location at which heat is removed from the wellstream with respect to the direction of flow of the wellstream fluid.

The method may comprise removing heat from the wellstream fluid downstream of the compressor and/or pump, and preferably also converting said removed energy to work using the energy converter.

Additionally/alternatively, the at least one component may be a pump. The method may comprise moving the working fluid using the pump.

Additionally/alternatively, the at least one component may be an electrical generator. The method may comprise powering an electrical component using electricity generated by the electrical generator.

Additionally/alternatively, the at least one component may be a separator for separating water and hydrocarbons from a wellstream. The method may comprise separating the water and hydrocarbons using the separator.

Additionally/alternatively, the at least one component may be an injector. The injector may be for injecting an injection fluid into a/the reservoir. The injection fluid may be or comprise (the separated) water. The injection fluid may be or comprise C02. The injection fluid may be a working fluid when the heat exchanger is located in the well (see third aspect for more details). The method may comprise injecting the injection fluid into a/the reservoir using the injector. This may at least partially maintain the pressure in the reservoir, may allow for heat to be removed from the wellstream in the well and/or may allow for C02 to be stored in the reservoir.

Additionally, the method may comprise injecting fluid into a reservoir, allowing the injected fluid to gain heat from the reservoir, removing the injected fluid from the reservoir as the wellstream, removing heat energy from the wellstream, converting at least some of the removed heat energy to work using the energy converter, and driving the at least one component using the work output from the energy converter. This method may be performed cyclically, such that the method comprises re-injecting the wellstream after heat is removed from it.

The method may comprise extracting an appropriate working fluid from the wellstream and supplying at least some of the extracted working fluid to the working fluid path. The method may comprise (actively) controlling the extraction of the working fluid from the wellstream fluid. The method may comprise (actively) controlling the supply of the working fluid to the working fluid path. The method may comprise storing at least some of the extracted working fluid.

The method may comprise cooling the working fluid output from the energy converter by using a cooling fluid to remove heat from the working fluid output from the energy converter.

The method may comprise switching between driving the at least one component using work generated in the energy converter and driving the at least one component using the external power source (e.g. via a motor powered by the external power source). The method may comprise switching between driving the at least one component using the external power source and driving the at least one component using work generated in the energy converter.

The method may be performed subsea, preferably proximate to or on the sea bed, such as proximate to or on a wellhead template or Xmas tree mounted to the seabed.

At least some of the method (e.g. the heat-removing step) may be performed within the well through which the wellstream is produced.

The method may be performed using a system as described above. The system may be mounted to a wellhead and/or Xmas tree and/or at least partially within the well.

The method may comprise a method for starting-up production from the well. In a typical field, the reservoir has a higher pressure compared to the well location where the pressure is somewhat lower towards the producing system. Further, there will be losses due to hydrostatic effects and friction effects as the wellstream is flowing from the reservoir or bottom hole upwards towards the Xmas tree located at the sea floor. A typical vertical distance of the well tubing between the reservoir bottom hole and the Xmas tree is between 1000 - 3000 meters. For a conventional well production system without the use of artificial lift (e.g. via a compressor or a pump) the bottom hole pressure will be determined based on the downstream system resistance to produce (pressure drop) the fluid and the permeability inside the reservoir to let the fluid move towards the depletion area. Applying a pump or compressor will reduce the resistance to produce, hence the bottom hole pressure in the depletion area of the reservoir is lowered significantly, increasing the pressure difference between the outer reservoir area and the depletion area, causing a higher production rate from the well.

In the present method and system, the compressor/pump may only be powered by the heat energy of the wellstream once the wellstream is being produced. Further, in the case of fluid injection to maintain pressure in the reservoir, the injector may only be powered by the heat energy of the wellstream once the wellstream is being produced. Of course, it may not be possible to power the compressor and/or pump and/or injector in this way when there is no wellstream being produced (as there will be no or insufficient heat energy available). Thus, the inventors faced a problem of how to start-up production.

One solution to this problem is to use the additional/external power source (such as the power umbilical or battery) discussed above to drive the compressor/pump prior to and during start-up. This lowers the pressure sufficiently at the wellhead to allow the wellstream to be produced. Once production has started, the system and method of using heat in the produced wellstream can take over.

However, the inventors have also devised a way of starting-up production without the use of the external power source. This is preferable in many situations as the selfcontainment, self-sufficiency and energy efficiency of the present solution is one of its major advantages.

In order to stop production from the well, normal practise is to close a valve on the Xmas tree, such as a safety valve or a choke valve. As the fluid flow in the well tubing is stopped (infinity flow resistance) there are no friction losses between the bottom hole in the reservoir and the Xmas tree. In such a situation, the depletion area pressure is equal to the overall reservoir pressure. Similarly, the reservoir side of the safety valve on the Xmas tree faces a high pressure (equal to the reservoir pressure minus the hydrostatic weight of the fluid in the well tubing). On the downstream side of the closed safety valve, the pressure will be reduced somewhat compared to the normal production pressure at that location. This is due to the fact that the pressure in this area during normal production must be higher compared to the receiving facility (e.g. a topside receiving facility) to be able to transport the wellstream fluid to the receiving facility and, as the production is stopped, the pressure will equalize in this system, lowering the pressure close to the well and increasing the pressure close to the receiving facility.

Thus, when the valve is closed, the pressure on the upstream side (the reservoir side) of the valve increases, and the pressure on the downstream side of the valve decreases. This means that a differential pressure is present at the Xmas tree across the valve, and the magnitude could be in the range for 50 -150 bar.

The inventors have realised that, due to this pressure difference, when the wellstream fluid path is opened, the wellstream fluid is produced from the wellhead. Its heat can then be used to power the compressor and/or pump(s) and/or electrical generator and/or separator and/or injector, which can then reduce the pressure at the wellhead in order to maintain wellstream production. The compressor and/or pump and/or injector may be required to maintain wellstream production because the pressure difference (caused by closing the wellstream path and allowing pressure below to build up) will reduce quite quickly as wellstream fluid is produced.

In a third aspect, the invention provides a heat exchanger for extracting heat energy from a wellstream within a well, wherein the well comprises a production pipe and a well casing, wherein the wellstream may pass through the production pipe. The heat exchanger comprises a working fluid path, which may contain a moving working fluid, which passes between the production pipe and the well casing. The production pipe and the working fluid path are arranged such that heat may be transferred between the wellstream and the working fluid. A typical well comprises a casing. A casing may be a generally hollow tubular protective layer that defines a boundary between the well and the Earth’s rock formations through which the well has been bored. The casing may typically be cemented in place.

The casing may have circular cross-section.

The production pipe is typically placed in the inside of the casing. The production pipe may be referred to as a production tube or a production casing. It is a pipe through which a wellstream is transported upwards from the reservoir toward the Earth’s surface.

Between the production pipe and the casing there is typically a space. This space may be annular in shape, and is often referred to as the well annulus.

Inside certain wells, there may be one or pumps or other components requiring power, at a certain depth within the well. Such pumps are used to boost the wellstream production by pumping it through the well. In the prior art these pumps are electrical, such as electrical splurge pumps. Further, they operate in harsh conditions where temperatures and pressures are high. It is therefore difficult to insulate and protect the components of the pump, such as the motor or the wires/cables.

The inventors have realised that, since there is some significant heat energy present in the wellstream (as discussed above), that this could be used as a source of energy for powering components within the well itself. For instance, the temperature of the well typically increases with depth and may be between 100-200°C. In order to harness the energy of the wellstream, the inventors have devised a system where a working fluid is passed through the space between the casing and the production pipe.

The heat exchanger may also be arranged such that the working fluid may be heated by heat through the casing. The rock formation through which the well is bored may also be hot. This heat can transfer through the casing into the working fluid.

This heat exchanger may be the heat exchanger (preferably the first heat exchanger) discussed above in relation to the first and second aspects. The heat exchanger of the third aspect can be combined with any of the features discussed herein in relation to the system or method of converting heat energy into work.

Thus, the invention may provide a system for converting heat in a wellstream fluid to work in order to drive at least one component as set out in the first aspect, comprising the heat exchanger of the third aspect. The invention may also provide a method of converting heat in a wellstream fluid to work to drive at least one component as set out in the second aspect, the method comprising extracting heat from the wellstream using the heat exchanger of the third aspect.

For example, the heat exchanger of the third aspect can be used to supply heat to an energy converter which can then power at least one component. Further, the working fluid may pass through a working fluid path as described in the first and second aspects, and the working fluid may be supplied using a working fluid supplier as described in the first and second aspects, and there may be one or more other energy converters located in the system for converting heat to work to drive at least one component.

The at least one component may comprise a pump, such as a splurge pump. The pump may preferably be located in the well, such as in the base of the well, and may be for boosting the wellstream. Additionally or alternatively, the at least one component may comprise one or more injector. The injector(s) may be located inside and/or outside of the well. The injector(s) may be for injecting fluid into a reservoir, preferably for injecting the working fluid into the reservoir into which the well extends.

The energy converter may convert heat energy in the working fluid into work. The at least one component may be powered mechanically or electrically using the energy converter.

The energy converter may also be located in the well, preferably in the vicinity of or adjacent to the at least one component. Just like the energy converter of the first and aspects, the energy converter may comprise a turbine or may comprise a heat engine, which may be powered by the heat energy of the working fluid. In addition to or as an alternative to this heat exchanger, it may also be possible run such a heat engine directly from the heat in the wellstream.

The energy converter may be arranged to mechanically drive the at least one component (e.g. via a shaft or a fluid). This may remove or reduce the need for electrical components in the well, which addresses the issues associated with running electrical components in the harsh environments in the well.

The at least one component may be located in the well.

The working fluid may pass through one or more working fluid tubes located between the production pipe and the casing. For instance, the working fluid tube(s) may be physically attached to the production pipe on an outside surface of the production pipe so that there is a physical connection between the working fluid tube(s) and the production pipe so as to provide a heat path between the wellstream and the working fluid. The working fluid tube(s) may be substantially in continuous contact with the production pipe along their length. The tube(s) may protect or separate the working fluid from other objects and/or fluids that may be present in the annulus.

The working fluid tube(s) may be made from a material that is sufficiently tough material for the environment of the annulus and that has a sufficiently high thermal conductivity to allow heat to transfer from the wellstream to the working fluid.

The wellstream fluid moves generally upwards. The working fluid may move generally downward. This allows the working fluid to gain heat as it moves downward, which may be toward the energy converter and/or at least one component in the well.

Additionally/alternatively, the working fluid may move generally upwardly. After having moved generally downwardly and having reached the energy converter, the working fluid may be somewhat cooled since some of its heat energy may be converted to work by the energy converter. This cooled working fluid can then be circulated upwards and can absorb more heat from the wellstream as it does so. This heated upward-moving working fluid can then be used to produce work using an energy converter, which may be the same energy converter used to produce work from the downward-moving working fluid or may be a different energy converter.

For instance, the downward-moving working fluid may be used to produce work using a lower energy converter. The working fluid can then be circulated upwards, being heated as it moves upwards. The working fluid can then be used to produce work using an upper energy converter. The lower energy converter may be located proximate the at least one component (e.g. the pump for boosting the wellstream), for example proximate the base of the well. The upper energy converter may be located on the Earth’s surface, for example proximate the wellhead.

In this case, the working fluid path may be a closed path. In the case of a closed path, the working fluid may be water, C02 and/or appropriate hydrocarbons.

The working fluid may move downward through the space between the casing and the production pipe.

The working fluid may move upward through the space between the casing and the production pipe.

Additionally or alternatively, the working fluid may move upward through production pipe. In this case, the working fluid exiting the energy converter can enter the production pipe and can be passed upwards to a system on the wellhead where the working fluid may be separated from the wellstream fluid, and can then be re-used as a working fluid by reintroducing it downward into the well. The working fluid that is introduced into the production pipe can be used to lower the average density of the wellstream fluid in the production pipe, which can lead to boosted fluid production. When the working fluid heats up as it passes downward through the space, its density may decrease, e.g. it may turn from liquid to gas and/or its gaseous volume may increase. Provided, the working fluid exiting the energy converter is of a sufficiently high pressure, it can enter the production pipe through a fluid path that may be provided between the exit of the energy converter and the production pipe. This pressure may be such that working fluid exiting the energy converter is of a higher pressure than the fluid in the production pipe (e.g. the fluid exiting the pump in the well). This may allow the working fluid to enter the production pipe, and may prevent wellstream fluid leaking out of the production pipe. When working fluid is included in the wellstream, the system may comprise a separator for separating the fluid from the reservoir (e.g. hydrocarbons, water, etc.) from the working fluid in the produced fluid. The separated working fluid may then be cooled (e.g. using ambient water or using a heat exchanger such that the extracted heat can be used for useful work) and then re-used in the heat exchanger.

However, it is also possible for the working fluid path to be an open path.

For instance, working fluid can be moved downward, for example from the Earth’s surface. Working fluid may not be moved generally upward, e.g. cycled upwards through the well after it has been moved downward through the. Instead, after heat in the working fluid has been converted into work by the energy converter in the well (preferably at the base of the well), the working fluid can be stored in the reservoir. The working fluid may therefore have more than one purpose: not only may it remove heat from the wellstream which can be converted into work by an energy converter to power at least one component, but the working fluid may also be injected into the reservoir so as to help maintain reservoir pressure. This may particularly be the case where the working fluid comprises, or substantially consists of, water. Additionally/alternatively, when the working fluid is, or comprises, C02 the working fluid can be injected into the reservoir so as to store the C02.

Since water injection and/or C02 injection are already desired results for other purposes, the inventors have devised a way of increasing the efficiency of the present injection, production and/or C02 storage systems. This is effectively achieved by injecting the injection fluid down the production well (e.g. through the annulus) and using the injection fluid as a working fluid by allowing heat to flow between injection fluid (e.g. injected working fluid, such as water and/or C02) and the wellstream fluid. The injection fluid can then be used to help power component(s), preferably component(s) in the well, before it is injected into the reservoir.

By “injected fluid” it is intended to mean fluid injected into a reservoir on a substantially permanent (or at least semi-permanent) basis. The injected fluid may come from the Earth’s surface.

The working fluid may be circulated by one or more working fluid pumps. The pump(s) may be powered by the energy converter(s). The working fluid may be injected by one or more injectors. The injector(s) may be powered by the energy converter(s).

The working fluid may be or may comprise water, C02 and/or appropriate hydrocarbons. The working fluid may be obtained in a similar way to the working fluid of the first and second aspects of the invention, i.e. using a working fluid supplier in communication with the wellstream.

Certain preferred embodiments will now be described by way of example only and with reference to the accompanying drawings, in which

Figure 1 shows a schematic view of a system according to an embodiment of the invention;

Figure 2 shows a schematic view of a system according to another embodiment of the invention;

Figure 3 shows a schematic view of a system according to another embodiment of the invention;

Figure 4 shows a schematic view of a system according to another embodiment of the invention; and

Figure 5 shows a schematic view of a system according to another embodiment of the invention.

Regarding Figure 1, shown is an exemplary system 1 for converting heat in a wellstream fluid to work in order to drive at least one component 30. The system 1 comprises a wellstream fluid path 10 through which a wellstream fluid passes. In the Figure 1 embodiment, the wellstream comprises substantially all produced hydrocarbons from a hydrocarbon reservoir. The wellstream fluid path 10 comprises a first wellstream fluid path line 11 that connects a wellhead 130 to an input of a first heat exchanger 20, a second wellstream fluid path line 12 that connects an output of the first heat exchanger 20 with an input of the compressor 30, a third wellstream fluid path line 13 that connects an output of the compressor 30 with an input of a second heat exchanger 40, and a fourth wellstream fluid path line 14 that connects an output of the second heat exchanger 40 with an infrastructure (such as a topside platform, not shown). During production, the wellstream fluid in the wellstream fluid path 10 flows in the direction of the arrows shown in Figure 1: from the wellhead through the first heat exchanger 20 through the compressor 30 through the second heat exchanger 40 toward the infrastructure.

The wellhead 130 is fed fluid from a well 131. The fluid comprises substantially entirely hydrocarbons, but may also comprise some water. In this case a separator may be located at or proximate the wellhead 130 (see Figure 2 for more details on this). At or downstream of the wellhead 130 in the wellstream path is a valve 132 is present. This valve 132 is configured to close the well in order to shut-down production. Production may commence when the valve 132 is opened.

The system 1 comprises a working fluid path 50 through which a working fluid circulates. The working fluid path 50 is a closed loop circuit, such that working fluid circulates around the loop. The working fluid path 50 comprises a first working fluid path line 51 that connects an output of a pump 60 to an input of the first heat exchanger 20, a second working fluid path line 52 that connects an output of a pump 60 to an input of the second heat exchanger 40, a third working fluid path line 53 that connects an output of the first heat exchanger 20 with an input of an energy converter 70, a fourth working fluid path line 54 that connects an output of the second heat exchanger 40 with the input of the energy converter 70, a fifth working fluid path line 55 that connects an output of the energy converter 70 with an input of a third heat exchanger 80 and sixth working fluid path line 56 that connects an output of the third heat exchanger 80 with an input of the pump 60. During operation, the pump 60 acts to circulate the working fluid around the working fluid path 50 in the direction of the arrows in Figure 1: from the pump 60 through the first and second heat exchangers 20, 40 through the energy converter 70 through the third heat exchanger 80 and back to the pump 60.

The first line 51 and the second line 52 are both in communication with the output of the pump 60. The third line 53 and fourth line 54 are both in communication with the input of the energy converter 70. In this way, the first and second heat exchangers 20, 40 are connected in parallel with respect to the working fluid path 50.

The first line 51 may be attached to the output of the pump 60 and the second line 52 may branch off from it. This may also be the other way around. The third line 53 may be attached to the input of the energy converter 70 and the fourth line 54 may join the third line upstream of the energy converter 70. This may also be the other way around.

At the first and second heat exchangers 20, 40, the wellstream fluid in the wellstream fluid path 10 is in thermal communication with the working fluid in the working fluid path 50 such that heat may transfer between the wellstream fluid and the working fluid. Heat exchangers 20, 40 may take any conventional form.

In this embodiment, the energy converter 70 comprises a turbine that converts energy in the working fluid output from the first and second heat exchangers 20, 40 to rotating kinetic energy. The energy converter 70 comprises a driving shaft 71 driven by the turbine. The driving shaft 71 is connected to the compressor 30 and drives the compressor 30 when the turbine turns. Alternatively/additionally, a heat engine, such as a Stirling engine, could be driven by the energy in the working fluid path at 70, and drive shaft 71.

The third heat exchanger 80 allows the working fluid exiting the energy converter 70 to be cooled by a cooling fluid (not shown) such as sea water. The third heat exchanger 80 is connected between the output of the energy converter 70 and the input of the pump 60. A working fluid supplier 90 is provided to supply working fluid to the working fluid path 50 from the wellstream fluid path 10. The working fluid supplier 90 comprises a first working fluid supplier line 91 leading from the wellstream output of the first heat exchanger 20 (e.g. second wellstream fluid path line 12) to an input of a separator 94, a second working fluid supplier line 92 leading from a first output of the separator 94 towards the input of the compressor 30 (e.g. second line 12), a working fluid supplier line 93 leading from a second output of the separator 94 towards the working fluid path 50 (preferably towards the input of the pump 60, e.g. line 56). In the third working fluid supplier line 93, there is a valve 95 for controlling the supply of the working fluid from the separator 94 to the working fluid path 50.

The heat exchange 20, 40, working fluid path 50, energy converter 70 system described here is just one example of how energy can be converted from heat in the wellstream to work. For example, instead or in addition to any of the above discussed components, a heat engine could be used.

In use, wellstream fluid leaves the well and enters the first heat exchanger 20 via first wellstream fluid path line 11 at a high temperature (such as 70-200°C, preferably 100-200°C) and at a high pressure (such as 100-300 bar). The working fluid is pumped from the pump 60 to the first heat exchanger 20 via first working fluid line 51 at a lower temperature (e.g. 0-7°C, approximately the sea temperature). In line 51, the working fluid is a liquid. At the first heat exchanger 20, heat is transferred from the wellstream fluid to the working fluid such that the wellstream fluid exiting the first heat exchanger 20 in second wellstream fluid line 12 has a reduced temperature (such as 10-30°C), but still has substantially the same high pressure as the wellstream fluid entering the first heat exchanger 20 (such as 100-300 bar), though this may be reduced slightly (such as by 1-2 bar). The working fluid exiting the first heat exchanger 20 in third working fluid line 53 has a raised temperature (such as around 100°C).

The raised temperature working fluid in the third working fluid line 53 is moved toward the energy converter 70 by means of the pump 60 and due to its increased temperature. Due to its increased temperature, the working fluid in line 53 is a vapour (i.e. it has evaporated in the heat exchanger 20). At the energy converter 70, the turbine converts some of the energy in the working fluid in line 54 to work. The turbine drives the shaft 71, which in turn drives the compressor 30. Working fluid of reduced energy exits the energy 70 via fifth working fluid line 55. There may be excess energy produced by the energy converter 70 which can be exported 72 from the system, for example in the form of electricity.

The compressor 30 thus driven sucks in wellstream fluid from the second wellstream fluid line 12 compresses the wellstream fluid. The wellstream fluid output from the compressor has an increased pressure and an increased temperature (such as 80-100°C).

The pressure ratio of the compressor (i.e. pressure of wellstream fluid in divided by pressure of wellstream fluid out) is 1.5 -4. The pressure of wellstream fluid in third wellstream fluid line is 150 -1200 bar.

The wellstream fluid thus leaves the compressor 30 and enters the second heat exchanger 40 via third wellstream fluid path line 13 at this raised temperature. The working fluid is pumped from the pump 60 to the second heat exchanger 40 via second working fluid line 52 at a lower temperature (e.g. 0-7°C, approximately the sea temperature). At the second heat exchanger 40, heat is transferred from the wellstream fluid to the working fluid such that the wellstream fluid exiting the second heat exchanger 40 in the fourth wellstream fluid line 14 has a reduced temperature (such as 10-30°C), but still has the same high pressure as the wellstream fluid entering the second heat exchanger 40 (such as 150-1200 bar), though this may be reduced slightly (such as by 1-2 bar). The working fluid exiting the second heat exchanger 40 in the fourth working fluid line 54 has a raised temperature (such as around 80-100°C).

The wellstream fluid exiting the second heat exchanger 40 then is passed through a pipeline (not shown) to a platform (not shown). The raised temperature working fluid in the fourth working line 54 is moved toward the energy converter 70 by means of the pump 60 and due to its increased temperature. Due to its increased temperature, the working fluid in line 54 is a vapour (i.e. it has evaporated in the heat exchanger 20). In essentially the same process as for working fluid in line 53, at the energy converter 70 the turbine converts some of the energy in the working fluid in line 54 to work to power the compressor 30. Working fluid of reduced energy exits the energy converter 70 via fifth working fluid line 55. The working fluid in line 55 is cooler than the working fluid input into the energy converter 70.

The working fluid output from the energy converter 70 may be (partially) condensed.

The working fluid exiting the energy converter 70 may still be quite hot, and should be cooled, and completely condensed, prior to its use as a coolant in first and second heat exchangers 20, 40. In order to achieve this, working fluid exiting the energy converter 70 is passed to a third heat exchanger 80 via line 55, where it is cooled by sea water. Cooled liquid working fluid (back to around 0-7°C, approximately the sea temperature) can then be passed from the third heating exchanger 80 back to the pump 60 where it can be recirculated.

Preferably the pump 60, and any other components requiring power that may be present, are also powered by the work output from the energy converter 70.

When it is desired to change or top-up the working fluid in the working fluid path 50, the working fluid supplier 90 can be used. When the valve 95 is open, some of the wellstream fluid output from the first heat exchanger 20 can pass through first working fluid supplier line 91 to the separator 94. At the separator 94, an appropriate working fluid (such as C4, C5 and/or Ce hydrocarbons or C02) is separated from the wellstream. The appropriate working fluid thus separated is passed through third working fluid supplier line 93 to the working fluid path 50. The remaining wellstream fluid is exhausted from the separator 94 towards the input of the compressor 30 via second working fluid supplier line 92. When the valve 95 is closed, working fluid supplier 90 is disconnected from the working fluid path 50. Thus, the separated working fluid in the third working fluid supplier line 93 is prevented from entering the working fluid path 50, which in turn prevents any more wellstream fluid entering the separator 94. In normal operation, the valve 95 is closed. The operation of the valve 95 may be controlled by the user and/or by a processor. The system may be monitored using sensors (not shown) to give the user/processor information on the state of the working fluid path. Between the separator 94 and the third working fluid supplier line 93 may be a tank (not shown) for storing separated working fluid. Prior to being replaced by new working fluid, old/worn working fluid in the working fluid path 50 may be exhausted into the wellstream via the working fluid supplier 90.

Because the working fluid supplier 90 extracts working fluid from the wellstream at a location upstream of the compressor 30, the working fluid in the working fluid path 50 has substantially the same pressure as the pressure of the wellstream upstream of the compressor 30.

In addition to the energy converter 70, the system 1 also comprises a plurality of additional energy converters 101, 102, 120, 121, 122. These are configured to generate work from energy sources in or near the system 1 and are configured to generate electricity to be stored in a battery 110 (although they may also be used to drive the at least one component 30). The battery 110 is thus arranged to be charged by the energy converters 101, 102, 120, 121, 122, and may even be configured to be charged by energy converter 70, although this is not shown. The battery 110 is charged, and the energy converters 101, 102, 120, 121, 122 may operate, only when there is more than enough energy generated by the energy converter 70 to power any and all necessary components 30. A first additional energy converter 101 is located at or proximate the third working fluid line 53 or the output of the heat exchanger 20. This energy converter 101 is a Stirling engine that converts some of the heat present at this location into work. The Stirling engine may drive a generator (not shown) to charge the battery 110, or to supply electrical energy to other components. The battery 110 can be used to power the Stirling engine 101, e.g. in order to start Stirling engine 101 during start-up of the system 1, by driving the Stirling engine using the generator as a motor. A second additional energy converter 102 is located at or proximate the first wellstream fluid line 11 or the output of the wellhead 130. This energy converter 102 is a Stirling engine that converts some of the heat present at this location into work. The Stirling engine may drive a generator (not shown) to charge the battery 110, or to supply electrical energy to other components. The battery 110 can be used to power the Stirling engine 102, e.g. in order to start Stirling engine 102 during start-up of the system 1, by driving the Stirling engine using the generator as a motor.

Similar heat engines can be provided at other locations in the system 1 where sufficient heat is present. A third additional energy converter 121 is located at or proximate the first wellstream fluid line 11 or at the output of the wellhead 130. This energy converter 121 is turbine that reduces the pressure of the wellstream fluid and converts the pressure reduction into work. The turbine 121 may drive a generator (not shown) to charge the battery 110, or to supply electrical energy to other components. A fourth additional energy converter 122 is located between a glycol source 123 and the wellstream fluid path 11. This energy converter 122 is turbine that reduces the pressure of the wellstream fluid and converts the pressure reduction into work. The turbine 122 may drive a generator (not shown) to charge the battery 110, or to supply electrical energy to other components. A fifth additional energy converter 120 is located at or proximate the fourth wellstream fluid line 11 or proximate an input of a topside platform (not shown). This energy converter 120 is turbine that reduces the pressure of the wellstream fluid and converts the pressure reduction into work. The turbine 120 may drive a generator (not shown) to charge the battery 110, or to supply electrical energy to other components.

Additionally, the second energy converter may comprise one or more energy converters for converting a pressure differential in a fluid path into work, such as a turbine. There may be a source of such a pressure differential in the wellstream, or in another fluid stream in the system.

Similar turbines can be provided at other locations in the system 1 where a suitable pressure drop is possible or desired or necessary.

The battery 110 is connected to electrically-powered component(s) 125. The component(s) 125 comprises a control unit 125 and may also serve as a variable speed drive, VSD, and/or a control.

Figure 2 shows another embodiment of a system 201 for converting heat energy in a wellstream fluid into work. This system 201 is largely identical to system 1 described above, except where discussed below.

In system 201, the wellstream from the well 131 comprises water and hydrocarbons. However, the system 201 may also work when the wellstream comprises substantially only water or hydrocarbons. In such a case, the separator 250 becomes redundant.

System 201 comprises a separator 250. The separator 250 is configured to separate hydrocarbons from water in the wellstream. A first output 251 of the separator 250 comprises substantially all water. A second output 252 of the separator 250 comprises substantially all hydrocarbons.

The first output 251 is connected to a first heat exchanger 20 for extracting heat from the separated water wellstream. The remainder of the components downstream of the separator 250 act on the water wellstream in the same way as the components discussed above in relation to Figure 1 act on the wellstream in Figure 1.

The second output 250 is connected to a first heat exchanger 20’ for extracting heat from the separated hydrocarbon wellstream. Downstream of the first heat exchanger 20’ may be components corresponding to those shown in Figure 1 for making use of the heat in the separated hydrocarbon wellstream. However, the components downstream of the first heat exchanger 20 (e.g. the water path) and the components downstream of the first heat exchanger 20’ (e.g. the hydrocarbon path) may both be used to charge the same battery 110, or different batteries. The skilled person would recognise that the first heat exchangers 20, 20’ may be combined in the same physical heat exchanger and/or may communicate with the same working fluid path 50.

In Figure 2, the separator 250 is located downstream of the wellhead 130, the valve 132, the turbine 121 and the heat engine 102. However, the separator 250 may be located upstream of the heat engine 102, the turbine 121 and/or the valve 132. If the separator 250 is located upstream of any of the valve 132, the turbine 121 and/or the heat engine 102, then both the separated water wellstream path and the separated hydrocarbon wellstream path may comprise respective valves, heat engines and turbines between the separator 250 and the heat exchangers 20, 20’.

In Figure 2, the separator 250 is located upstream of the first heat exchanger 20 (and the first heat exchanger 20’ for the separated hydrocarbon wellstream). However, the separator 250 may be located downstream of the first heat exchanger 20. In this case, there would be no first heat exchanger 20’, rather both water and hydrocarbons would pass through the first heat exchanger 20 before being separated. The separator could also be located upstream or downstream of the working fluid supplier 90, upstream or downstream of the at least one component 230, and upstream or downstream of the second heat exchanger 40.

In Figure 2, water exiting from the first heat exchanger 20 through line 20 passes to the at least one component 230. The system 201 may comprise a working fluid supplier 90 for extracting a portion of water or for extracting C02 or for extracting hydrocarbon impurities from the water wellstream for use as the working fluid. However, the working fluid may alternatively be supplied by a working fluid supplier in communication with the hydrocarbon wellstream output from the separator 250, or indeed from any other source (such as a local source of C02).

The at least one component 230 is an injector 230. The injector 230 may be in the form of a pump or a compressor. The injector 230 injects water into a well 231, preferably via a wellhead 130’. The well 231 is in communication with a reservoir, which is preferably the same reservoir with which well 131 is in communication. This injection can be used to increase or at least partially maintain the pressure in the reservoir during production, so as to boost the wellstream production through well 131. Further, over time the fluid injected into well 231 can be heated by the reservoir and then produced through well 131. In this case, a closed-loop, or at least a semi-closed-loop, heat transfer system can be made.

Between the injector 230 and the well 231, there may be the second heat exchanger 40 and the turbine 120 as discussed above in relation to Figure 1. However, in some embodiments the turbine 120 may not be present, as it may be desired to lower the pressure of the water prior to or during injection.

The injector 230 is powered using the energy converter 70. There may be excess energy produced by the energy converter 70 which can be exported 72 from the system, for example as electricity.

With regard to Figure 3, this shows another embodiment of the present invention. In this embodiment, the produced wellstream comprises substantially all water. However, it may also be the case that the wellstream comprises some significant proportions of hydrocarbons. In this case, hydrocarbons can be re-injected along with the water (as is discussed below), or the system of Figure 3 can comprise the separator 250 of Figure 2 to separate the hydrocarbons from the water, so that hydrocarbons can be moved away from the system as in Figure 1 and water can be injected as in Figure 2.

Returning to Figure 3, as can be seen there is a system 301 comprising a production well 131, terminating at a wellhead 130, and an injection well 231, terminating at a wellhead 130’, placing a reservoir 240 in communication with a system, preferably on or in the vicinity of the sea bed 241. The reservoir 240 is a depleted, or partially depleted, hydrocarbon reservoir.

Water is produced from the reservoir through the well 131 to the wellhead 130. Heat is then extracted from the water wellstream at first heat exchanger 20. The water wellstream is then passed to an injector 230, which re-injects the water wellstream back into the reservoir 240 via an injection well 231.

The heat extracted from the water wellstream using the heat exchanger 20 is transported to the energy converter 350, which may comprise a turbine or generator 70, via a working fluid 50’. The working fluid returns from the energy converter to the heat exchanger 5T. The heat extracted from the water wellstream using the heat exchanger 20 is converted into work by the energy converter 350. This work is used to drive the injector 230. The work is transmitted from the energy converter 350 to the injector 230 via transmission 71, such as a fluid, electricity, a shaft or a magnetic coupling, or any other type of energy transmission. Excess energy produced by the energy converter 70 is exported 72 from the system 301, typically in the form of electricity.

The system 301 may comprise any or all of the components of system 1 or 201 discussed above.

Water is injected into the reservoir 240 to help to maintain the reservoir’s pressure, which in turn helps to boost production of the wellstream through the well 131.

When the water is injected into the reservoir 240, it generally travels 232 between the injection well 231 and the production well 131. This takes time, possibly months or years. During this time, the water is heated by heat in the reservoir present due to the internal heat of the Earth. Thus, the water produced from the well 131 contains heat energy which can be used to power not only the re-injection of the water but also to produce energy to export energy 72 from the system 301.

With regard to Figure 4, this shows a heat exchanger 420 for extracting heat energy from a wellstream within a well 131. The well 131 comprises a production pipe 481 and a well casing 480. The wellstream 451 passes through the production pipe. A working fluid 450 passes between the production pipe 481 and the well casing 480. The production pipe 481 and the working fluid 450 are arranged such that heat may be transferred between the wellstream 451 and the working fluid 450.

This heat exchanger 420 is used in combination with the other components discussed below in a system for system for converting heat in the wellstream 451 to work.

The casing 480 is a generally hollow tubular protective layer that defines a boundary between the well 131 and the Earth’s rock formations through which the well 131 has been bored. The casing 480 may be cemented in place. The casing 480 may have circular cross-section.

In the inside of the casing 480, the production pipe 481 is located. The production pipe 481 is a pipe through which a wellstream 451 is transported upwards from the reservoir 340 toward the Earth’s surface 241.

Between the production pipe 481 and the casing 480 there is a space 482. This space 482 is generally annular in shape, and is referred to as the well annulus 482.

Inside the well 131, at a certain depth there is a pump 430 requiring power. This pump 430 is used to boost the wellstream 451 production by pumping it through the well 131. The pump 430 is located toward the base of the well 131.

An energy converter 470 is also located in the well 131 proximate to the pump 430. The energy converter 470 converts heat energy in the working fluid 450 into work. The pump 430 is powered mechanically using the energy converter 470, e.g. via transmission 471 (such as via fluid or a shaft). The energy converter 470 comprises a turbine that is rotated by the working fluid 450. The transmission 471 may pass from the space 482 into the production pipe 481. Where it does so, a seal 460 may be provided to ensure the production pipe 481 does not leak.

The working fluid 450 passes through a plurality of working fluid tubes (not shown) located between the production pipe 481 and the casing 480. The working fluid tubes are physically attached to the production pipe 481 on an outside surface of the production pipe 481 so that there is a physical connection between the working fluid tubes and the production pipe 481 so as to provide a heat path between the wellstream 451 and the working fluid 450. The working fluid tubes may be substantially in continuous contact with the production pipe 481 along their length.

Due to pressure differentials in the reservoir caused by the well 131, fluid 452 in the reservoir 340 moves toward the well 131. This fluid 452 once it enters the well 131 becomes the wellstream fluid 451. The wellstream fluid 451 moves generally upwards between the reservoir 340 and the Earth’s surface 241. Some of the working fluid 450 moves generally downward. Other parts of the working fluid 450 move generally upwardly. After having moved generally downwardly the working fluid 450 gains heat energy. Some of this energy is given up to the energy converter when the working fluid 450 reaches and passes through the energy converter 470. Thus, the working fluid 450 exiting the energy converter 470 is somewhat cooler since some of its heat energy has been converted to work by the energy converter 470. This cooled working fluid 450 is then circulated upwards and can absorb more heat from the wellstream 451 as it does so. This heated upward-moving working fluid 450 can then be used to produce work using an energy converter in system 401. The system 401 may be substantially similar to, or may comprise features of, system 1, 201 or 301. The wellstream 402 may be output from the system 401 to be moved away from the wellhead (e.g. sent topside) or to be injected into a/the reservoir. The system 401 circulates the working fluid 450.

The working fluid 450 is circulated by one or more working fluid pumps, such as working fluid pump 60 discussed in Figure 1. These pumps may be located in system 401 and/or proximate energy converter 470. The pump(s) are powered by the energy converter(s).

In Figure 4, the working fluid path 450 is a generally closed path. The working fluid may be supplied via a working fluid supplier as part of system 401.

Regarding Figure 5, this shows an embodiment of a heat exchanger 520 and a system for converting heat in a wellstream 551 to work via a working fluid 550 that is similar to that of Figure 4 except that the working fluid path 550 is not a closed path, i.e. it is an open path.

In Figure 5, the working fluid 550 is generally moved downward only through annulus 582, i.e. it is not circulated upward also like in Figure 4. Instead, after heat in the working fluid 550 has been converted into work by the energy converter 570 in the well 131, the working fluid 550 exits the energy converter 553 and is stored in the reservoir 340. Additionally or alternatively, the working fluid 553’ exiting the energy converter 570 can enter the production pipe 581 and can be passed back up to the system 501, where it is separated from the produced fluid 551, and can then be re-used as a working fluid 550.

In this embodiment, the working fluid 550 has more than one purpose: not only may it remove heat from the wellstream 551 which can be converted into work by an energy converter 570 to power the pump 530 via the shaft 571, but the working fluid 553 also may be injected into the reservoir 340. When the working fluid 550 comprises water this helps to maintain reservoir pressure. When the working fluid 550 comprises C02this helps to store the C02.

The working fluid 550 is injected by one or more injectors, such as the injector 230 discussed in Figure 2. These injectors may be located in the system 501 and/or proximate energy converter 571. The injector(s) are powered by the energy converter(s).

Additionally or alternatively, the working fluid 553’ that is introduced into the production pipe 581 can be used to lower the average density of the wellstream fluid 551 in the production pipe 581, which can lead to boosted fluid production. When the working fluid 550 heats up as it passes downward through the space 582, its density may decrease, e.g. it may turn from liquid to gas and/or its gaseous volume may increase. Provided, the working fluid 550 exiting the energy converter 570 is of a sufficiently high pressure, it can enter the production pipe 581 through a fluid path that may be provided between the exit of the energy converter and the production pipe. This pressure may be such that working fluid 533’ exiting the energy converter is of a higher pressure than the fluid in the production pipe 581 (e.g. the fluid exiting the pump 530). This allows the working fluid 553’ to enter the production pipe 581, and prevents wellstream fluid 551 leaking out of the production pipe 581.

When working fluid 533’ is included in the wellstream 551, the system 501 may comprise a separator for separating the fluid from the reservoir (e.g. hydrocarbons, water, etc.) from the working fluid 550. The working fluid 550, preferably after is has been separated from the wellstream, may be cooled (e.g. using ambient water proximate system 501 and/or using heat exchanger which can extract heat from the working fluid 550 for conversion to useful work) and then re-used in the heat exchanger 520.

The skilled person would appreciate that features of the certain features of the embodiments of Figures 1 to 4 could readily be combined with each other in accordance with the teaching of the discussion of the first, second and third aspects of the invention provided above, and the claims below, which define the scope of protection.

Claims

Claims:

1. A heat exchanger for extracting heat energy from a wellstream within a well, wherein the well comprises a production pipe and a well casing, wherein the wellstream may pass through the production pipe, the heat exchanger comprising the production pipe and a working fluid path that passes between the production pipe and the well casing, wherein the production pipe and the working fluid path are arranged such that heat may be transferred between the wellstream and working fluid within the working fluid path.

2. A heat exchanger as claimed in claim 1, wherein the working fluid path and the casing is arranged such that the working fluid may be heated by heat through the casing.

3. A heat exchanger as claimed in claim 1 or 2, wherein the working fluid path is open, closed or partially-closed.

4. A system for converting heat in a wellstream fluid to work in order to drive at least one component, the system comprising: an energy converter being arranged to convert some of the heat energy in the wellstream to work; and the at least one component being arranged to be driven by at least some of the work output from the energy converter.

5. A system as claimed in claim 4, wherein the at least one component is arranged to be driven directly by the energy converter.

6. A system as claimed in claim 4 or 5, wherein the at least one component is arranged to be driven by electricity generated using at least some of the work output from the energy converter.

7. A system as claimed in claim 4, 5 or 6, wherein the at least one component comprises: a compressor arranged to pressurise the wellstream fluid, or another wellstream fluid, entering the compressor; and/or a pump arranged to pump the wellstream fluid, or another wellstream fluid, entering the pump.

8. A system as claimed in any of claims 4 to 7, wherein the at least one component comprises an injector arranged to inject an injection fluid into a reservoir via a well.

9. A system as claimed in claim 8, wherein the well is an injection well that is different to the well through which the wellstream is produced.

10. A system as claimed in claim 8, wherein the injection fluid is a working fluid for removing heat from the wellstream inside the well and the well is the same well from which the wellstream is produced.

11. A system as claimed in any of claims 4 to 10, wherein the at least one component comprises a separator for separating the wellstream into a first portion comprising substantially all water and a second portion comprising substantially all hydrocarbons.

12. A system as claimed in any of claims 4 to 11, wherein the at least one component is located downstream, with respect to the wellstream, of a location at which at least some of the heat energy in the wellstream is extracted from the wellstream.

13. A system as claimed in any of claims 4 to 12, wherein the at least one component is located upstream, with respect to the wellstream, of a location at which at least some of the heat energy in the wellstream is extracted from the wellstream.

14. A system as claimed in claim 12 and 13, wherein the energy converter is arranged to convert at least some of the heat energy removed from the wellstream at both said locations to work.

15. A system as claimed in claim 12 and 13, wherein a first energy converter is arranged to convert at least some of the heat energy removed from the wellstream at a first of the locations to work and a second energy converter is arranged to convert at least some of the heat energy removed from the wellstream at a second of the locations to work.

16. A system as claimed in any of claims 4 to 15, wherein the at least one component comprises an electrical generator arranged to generate electricity when driven by at least some of the work output from the energy converter.

17. A system as claimed in any of claims 4 to 16, wherein heat is extracted from the wellstream at a location within the well from which the wellstream is produced.

18. A system as claimed in any of claims 4 to 17, wherein heat is extracted from the wellstream at a location downstream, with respect to the wellstream, of the well from which the wellstream is produced.

19. A system as claimed in any of claims 4 to 18, wherein the heat is extracted from the wellstream by way of at least one heat exchanger that is arranged to remove heat from the wellstream fluid by transferring heat from the wellstream fluid to a working fluid.

20. A system as claimed in claim 49, wherein the at least one component comprises a pump being arranged to move the working fluid.

21. A system as claimed in claim 19 or 20, wherein the system further comprises a working fluid supplier configured to extract an appropriate working fluid from the wellstream, or another wellstream, and supply at least some of the extracted working fluid to the at least one heat exchanger.

22. A system as claimed in claim 19, 20 or 21, wherein the system further comprises a working fluid supplier configured to extract an appropriate working fluid from a fluid stream in the vicinity of the system and supply at least some of the extracted working fluid to the heat exchanger(s), wherein the fluid stream is preferably a C02 pipeline for C02 injection.

23. A system as claimed in claim 19, 20, 21 or 22, wherein the system further comprises a working fluid heat exchanger arranged to remove heat from the working fluid output from the energy converter.

24. A system as claimed in any of claims 4 to 23, wherein the energy converter comprises a turbine.

25. A system as claimed in any of claims 4 to 24, wherein the energy converter comprises a heat engine, preferably a Stirling engine.

26. A system as claimed in any of claims 4 to 25, comprising at least one second energy converter configured to convert heat in a fluid stream into work and/or electricity, and/or convert pressure differentials in a fluid stream into work and/or electricity.

27. A system as claimed in any of claims 4 to 26, comprising an energy storage system configured to store energy generated by the energy converter(s), and preferably configured to power the at least one component.

28. A system as claimed in any of claims 4 to 27, wherein the wellstream fluid comprises liquid hydrocarbon(s) and/or water.

29. A system as claimed in any of claims 4 to 28, wherein the system is a subsea system.

30. A system as claimed in any of claims 4 to 29, wherein the system is a module that can be mounted to a wellhead and/or Xmas tree.

31. A system as claimed in any of claims 4 to 30, wherein the system is configured to export excess energy produced by the energy converter.

32. A method of converting heat in a wellstream fluid to work to drive at least one component, the method comprising: removing heat energy from the wellstream fluid; converting at least some of the removed heat energy to work using an energy converter; and driving the at least one component using at least some of the work output from the energy converter.

33. A method as claimed in claim 32, comprising directly driving the at least one component using at least some of the work output from the energy converter.

34. A method as claimed in claim 32 or 33, comprising driving the at least one component using electricity generated using at least some of the work output from the energy converter.

35. A method as claimed in claim 32, 33 or 34, wherein the at least one component comprises a compressor arranged to compress the wellstream fluid, or another wellstream fluid, and the method comprises pressurising the wellstream fluid entering the compressor using the compressor; and/or wherein the at least one component comprises a pump arranged to pump the wellstream fluid, or another wellstream fluid and the method comprises pumping the wellstream fluid entering the pump using the pump.

36. A method as claimed in any of claims 32 to 35, wherein the at least one component comprises an injector arranged to inject an injection fluid into a reservoir via a well, and the method comprises injecting the injection fluid into the reservoir using the injector.

37. A method as claimed in claim 36, wherein the well is an injection well different to the well through which the wellstream is produced, wherein the injection well extends into the same reservoir as the well from which the wellstream is produced extends into, wherein the method comprises allowing the injection fluid to be heated in the reservoir before being produced from the reservoir in the wellstream.

38. A method as claimed in claim 37, comprising re-injecting at least a portion of the wellstream after heat is removed from it.

39. A method as claimed in claim 36, wherein the injection fluid is a working fluid for removing heat from the wellstream inside the well and the well is the same well from which the wellstream is produced, wherein the method comprises removing heat from the wellstream within the well using the working fluid and using said removed heat in the working fluid to generate work using said energy converter prior to the working fluid being injected into the reservoir.

40. A method as claimed in any of claims 32 to 39, wherein the at least one component comprises a separator, the method comprising separating the wellstream into a first portion comprising substantially all water and a second portion comprising substantially all hydrocarbons using the separator.

41. A method as claimed in claim 40, comprising injecting the first portion into a reservoir and moving the second portion away from the well.

42. A method as claimed in any of claims 32 to 41, wherein the at least one component is located downstream of a location at which at least some of the heat is removed from the wellstream, with respect to the direction of flow of the wellstream fluid.

43. A method as claimed in any of claims 32 to 42, wherein the at least one component is located upstream of a location at which at least some of the heat is removed from the wellstream, with respect to the direction of flow of the wellstream fluid.

44. A method as claimed in claim 42 and 43, comprising converting at least some of the heat energy removed from the wellstream at both of the locations to work using the energy converter.

45. A method as claimed in claim 42 and 43, wherein a first energy converter converts at least some of the heat energy removed from the wellstream at a first of the locations to work, and a second energy converter converts at least some of the heat energy removed from the wellstream at a second of the locations to work.

46. A method as claimed in any of claim 32 to 45, wherein removing heat energy from a wellstream fluid comprises transferring heat from the wellstream fluid to a working fluid, wherein the at least one component comprises a pump arranged to move the working fluid, and wherein the method comprises moving the working fluid using the pump.

47. A method as claimed in any of claims 32 to 46, wherein the at least one component comprises an electrical generator, and wherein the method comprises driving the electrical generator using at least some of the work output from the energy converter to generate electricity.

48. A method as claimed in any of claims 32 to 47, comprising extracting heat from the wellstream at a location within the well from which the wellstream is produced.

49. A method as claimed in any of claim 32 to 48, comprising extracting heat from the wellstream at a location downstream, with respect to the wellstream, of the well from which the wellstream is produced.

50. A method as claimed in any of claims 32 to 49, comprising removing heat from the wellstream fluid using a working fluid, extracting an appropriate working fluid from the wellstream, or another wellstream, and supplying at least some of the extracted working fluid for use in removing heat from the wellstream fluid.

51. A method as claimed in any of claims 32 to 50, comprising removing heat from the wellstream fluid using a working fluid, extracting an appropriate working fluid from a fluid stream in the vicinity of the energy converter and supplying at least some of the extracted working fluid for use in removing heat from the wellstream fluid.

52. A method as claimed in any of claims 32 to 51, comprising transferring the removed heat energy to the energy converter using a working fluid and cooling the working fluid output from the energy converter.

53. A method as claimed in any of claims 32 to 52, wherein the method is performed subsea.

54. A method as claimed in any of claims 32 to 53, comprising using the system of any of claims 4 to 31 to perform the method.

55. A method as claimed in claim 54, wherein the system is a module mounted to a wellhead and/or Xmas tree.

56. A method as claimed in claim 54 or 55, wherein the energy converter generates work in excess of the requirements of the at least one component and the method comprises exporting energy from the system.

57. A system as claimed in any of claims 4 to 31, comprising the heat exchanger of claims 1,2 or 3, which is configured to extract the heat energy from the wellstream that is converted to work by the energy converter.

58. A system as claimed in claim 57, wherein the energy converter and/or the at least one component are located within the well.

59. A method as claimed in any of claims 32 to 56, comprising the heat exchanger of claims 1,2 or 3, the method comprising using the heat exchanger of claims 1, 2 or 3 to extract the heat energy from the wellstream that is converted to work by the energy converter.