EP4577725A1

EP4577725A1 - Carbon dioxide injection

Info

Publication number: EP4577725A1
Application number: EP23857809.0A
Authority: EP
Inventors: Per Lothe; Arild SAMUELSBERG
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2022-08-25
Filing date: 2023-08-25
Publication date: 2025-07-02
Also published as: GB2621871A; KR20250085726A; EP4577725A4; WO2024043790A1; GB202212382D0; CN120153164A; JP2025529089A; AU2023329696A1

Abstract

A method of injecting carbon dioxide into an offshore injection well (4), the method comprising: storing carbon dioxide within a plurality of storage pipes (103) at an offshore storage facility (1); and injecting the stored carbon dioxide into an injection well (4).

Description

CARBON DIOXIDE INJECTION

The present invention relates to a method of injecting carbon dioxide into an offshore, subsea injection well and to an offshore storage facility configured to store and subsequently inject carbon dioxide into an offshore, subsea injection well.

Injection is a process that may be used to maintain or increase pressure within a hydrocarbon producing reservoir to thereby permit or improve the production of hydrocarbons therefrom. One known form of injection relies on the injection of carbon dioxide (CO2) into the reservoir via one or more injection wells. Carbon dioxide is a particularly advantageous injectant because it is readily available and thus cheap, and because it has the added effect of reducing oil viscosity which permits for easier hydrocarbon production.

Injection of carbon dioxde can also be leveraged as a useful climate solution since the carbon dioxide, which may have otherwise been emitted to the environment, can be stored long-term in a reservoir or other subsea geological formation into which it has been injected. Thus, the notoriously well-known and detrimental impacts that emission of the carbon dioxide to the environment might have had can be avoided.

One known method of injecting carbon dioxide to an offshore injection well comprises a vessel (i.e. a tanker), loaded with carbon dioxide, travelling to a site of the injection well. The carbon dioxide is then offloaded from the vessel and injected to the well. Once depleted of carbon dioxide, the vessel then travels away from the injection site for further retrieval of carbon dioxide.

An issue with this known method is that the injection is discontinuous (i.e. only occurs whilst the vessel is at the site of the offshore injection well). Large flow rates of carbon dioxide are also involved since the offloading of carbon dioxide from the vessel occurs over a relatively short timeframe, which in turn means that the process involves high pressures and thus requires high design pressures, which is not desirable.

An alternative method for injection at an offshore injection well is known, for example, from the applicant’s own “Northern Lights” project (https://www.equinor.com/energy/northern-lights). Instead of a vessel travelling to the offshore site of the injection well, an onshore (i.e. land-based) storage facility Is connected to the offshore injection well by a subsea pipeline. The pipeline enables the carbon dioxide to flow from the storage facility to the offshore injection well for injection thereat. The storage facility stores the carbon dioxide in large vessels (tanks) at ambient pressure conditions and temperature conditions significantly below ambient temperature. This method provides advantages over those based on transportation vessels in that the injection need not be discontinuous given the pipeline can continuously transport carbon dioxide to the injection well whilst the storage facility provides a continuous feed of carbon dioxide. Moreover, given the continuous presence of the pipeline, the high flow rates and pressures associated with the method reliant on a transportation vessel can be avoided.

Still further alternative methods and apparatus for injection of carbon dioxide at offshore injection wells are desired.

In accordance with a first aspect of the invention, there is provided a method of injecting carbon dioxide into an offshore injection well, the method comprising: storing carbon dioxide within a plurality of storage pipes at an offshore storage facility; and injecting the stored carbon dioxide into an injection well.

The method of the first aspect provides advantages over the known prior art methods that are reliant on a transportation vessel for transporting the carbon dioxide and offloading the carbon dioxide directly to the injection well. Notably, this is because issues surrounding discontinuous injection and associated high flow rates/pressures with such prior art methods can be avoided using the method of the first aspect. Since the offshore storage facility is connected, effectively permanently, to the injection well it can enable a continuous supply of carbon dioxide to the injection well, and hence the high pressures associated with discontinuous supply are avoided.

Additionally, the method of the first aspect provides advantages in terms of reduced operational and infrastructural demands as compared to these known prior art methods reliant on a transportation vessel, which in turn results in reduced operational and infrastructural costs. Significantly, the method of the first aspect does not require a transportation vessel to frequently travel to the site of the injection well (or at the very least significantly reduces the frequency that a transportation vessel has to travel to a site of the injection well/offshore storage facility) thereby avoiding or reducing the large operational costs associated therewith. Equally, the method of the first aspect avoids the need for high design pressures as discussed above and thereby avoids the significant infrastructural demands associated with such high design pressures. The method of the first aspect also provides advantages over the injection solution known from the applicant’s own ‘Northern Lights’ project, in particular in scenarios where the injection well is situated remotely, in a ‘hard-to-reach’ location or at a large distance from an established carbon dioxide onshore storage facility. In such a scenario, it may not be feasible, technically and/or commercially, to provide a pipeline in communication with said injection well given how ‘remote’ it is, but an offshore storage facility of the type defined in the first aspect of the invention could feasibly be used to permit for injection at said well.

The carbon dioxide that is stored and subsequently injected may have previously been captured from a carbon dioxide production source (e.g. a chemical plant or other industrial plant, a gas-fired powerplant or power source, coal-fired powerplant or power source, etc) prior to its emission to the environment/atmosphere. Alternatively, the carbon dioxide may have been directly captured from the atmosphere. The method of the first aspect may thus comprise capturing carbon dioxide, optionally from a carbon dioxide production source or from the environment, prior to the step of storing the carbon dioxide. This step of capturing carbon dioxide may take place at a carbon capture facility, which may be onshore (land-based) or offshore. There is an evident environmental benefit to these optional features of the invention.

As will be implicit from the above discussion, the offshore storage facility may be provided at the site of the of the injection well. That is, the offshore storage facility may be provided in the vicinity (i.e. in close proximity) to the injection well. The offshore storage facility may thus be considered to be in combination with and/or paired with the injection well. The offshore storage facility may, with reference to a lateral direction (i.e. a direction aligned with the sea level and/or the sea bed), be situated within 2 km of the injection well. Optionally, the offshore storage facility may, with reference to a lateral direction (i.e. a direction aligned with the sea level and/or or sea bed), be situated within 1 km, 500 m, 400 m, 300 m, 200 m or 100 m of the injection well. The offshore storage facility may be situated effectively above the injection well.

As noted above, the offshore storage facility can provide an effectively continuous provision of carbon dioxide to the offshore injection well. As such, the total volume of storage at the offshore storage facility (i.e. the total volume of storage provided by the storage pipes) may be capable of meeting the demands of injection at the offshore injection well for a significant period of time, for example for at least 1 week, 1 month, 6 months, 1 year, 5 years or optionally even longer. The total volume of storage at the offshore storage facility (i.e. the total volume of storage provided by the storage pipes) may be for example 10,000 m³, 30,000 m³, 100,000 m³, or optionally even larger.

The offshore injection well may also be termed a subsea injection well or an offshore/subsea injection well.

As also alluded to above, the offshore injection well may be situated remotely and/or at a large distance from land and/or from any already established infrastructure enabling carbon dioxide storage (e.g. an onshore carbon dioxide storage facility) other than the offshore storage facility of the invention. A large distance may be a distance at which it would not be feasible, technically and/or commercially, to provide a pipeline from land/ the established infrastructure to the offshore injection well. The skilled person, given a particular context, would readily understand what would constitute such a distance. For example, the injection well may be situated more than 60 km from land and/or established infrastructure, optionally more than 100 km, further optionally more than 200 km away.

The injection well may be in communication with a hydrocarbon reservoir. The hydrocarbon reservoir may be a producing hydrocarbon reservoir, i.e. one from which hydrocarbons are being, or soon will be, produced. Injection into the well may maintain or increase pressure within the hydrocarbon reservoir. This may permit or improve the production of hydrocarbons from the hydrocarbon reservoir via, for example, a hydrocarbon production system

This combination of features is seen to be particularly advantageous and therefore, in accordance with a second aspect of the invention, there is provided a method of operating a hydrocarbon production system, the method comprising: injecting carbon dioxide into an offshore injection well in accordance with the first aspect of the invention, wherein the offshore injection well is connected to a hydrocarbon reservoir; and producing hydrocarbons from the hydrocarbon reservoir with the hydrocarbon production system.

The use of the carbon dioxide as an injectant in this second aspect of the invention has the synergistic effect of supporting hydrocarbon production and avoiding emission of carbon dioxide to the environment.

Producing hydrocarbons from the hydrocarbon reservoir may be carried out in a conventional manner and using conventional production equipment and/or apparatus. The optional hydrocarbon production system may comprise a hydrocarbon production facility. The hydrocarbon production facility may comprise a hydrocarbon production platform, e.g. an unmanned hydrocarbon production platform, or a floating production, storage and offloading unit (FPSO).

The injection well may form part of the hydrocarbon production system or the hydrocarbon production facility. As such, the hydrocarbon production system or the hydrocarbon production facility may comprise the injection well. The hydrocarbon production system or the hydrocarbon production facility may comprise one or more additional injection wells, for example the additional injection wells described below.

The hydrocarbon production system is a system that is specifically configured for the production and/or processing of hydrocarbons (e.g. oil, natural gas, etc.). As such, the hydrocarbon production system (e.g. the hydrocarbon production facility) may comprise a degree of production equipment and/or a degree of processing equipment configured for processing or part-processing the produced hydrocarbons.

The hydrocarbon production system and/or the hydrocarbon production facility may be provided at the site of the of the injection well and/or the offshore storage facility. That is, the hydrocarbon production system and/or the hydrocarbon production facility may be provided in the vicinity (i.e. in close proximity) to the injection well and/or the offshore storage facility. The hydrocarbon production system and/or the hydrocarbon production facility may thus be considered to be in combination with and/or paired with the injection well and/or the offshore storage facility. The hydrocarbon production system and/or the hydrocarbon production facility may, with reference to a lateral direction (i.e. a direction aligned with the sea level and/or sea bed), be situated within 2 km of the injection well and/or the offshore storage facility. Optionally, the hydrocarbon production system and/or the hydrocarbon production facility may, with reference to a lateral direction (i.e. a direction aligned with the sea level or sea bed), be situated within 1 km, 500 m, 400 m, 300 m, 200 m or 100 m of the injection well and/or the offshore storage facility. The hydrocarbon production system and/or the hydrocarbon production facility may be situated effectively above the injection well.

It is not however required for the injection well to be connected to a hydrocarbon reservoir. Instead of the hydrocarbon reservoir, the injection well may be in communication with an alternative geological formation (i.e. not a hydrocarbon reservoir or at least not a producing hydrocarbon reservoir, for example a hydrocarbon reservoir that has previously been depleted of its hydrocarbons). As such, the injection of the carbon dioxide may not be used to support production of hydrocarbons, but instead is used simply as a means to store the carbon dioxide underground.

The method of the first aspect may comprise injecting carbon dioxide into a plurality of offshore injection wells. As such, the method may comprise storing carbon dioxide within the plurality of storage pipes at the offshore storage facility; and injecting the stored carbon dioxide into the plurality of injection wells. Each of the plurality of injection wells may be in accordance with the injection well described above.

The step of storing carbon dioxide within a plurality of storage pipes at an offshore storage facility may comprise storing the carbon dioxide as a liquid (i.e. liquefied carbon dioxide). The method may thus comprise the step of liquefying the carbon dioxide prior to storing the carbon dioxide within the plurality of storage pipes at the offshore storage facility. This liquefying step may occur at the offshore storage facility, before (i.e. as a precursor to) the step of storing the carbon dioxide within the plurality of storage pipes at the offshore storage facility. Alternatively, the carbon dioxide may be liquefied prior to its arrival at the offshore storage facility. That is to say, the carbon dioxide may have been transported to the offshore storage facility, for example via a transportation vessel (more on this optional feature below), as a liquid.

The step of injecting the stored carbon dioxide may comprise injecting the carbon dioxide as a liquid, optionally using a pump. Injection of liquid carbon dioxide using a pump has advantages in terms of efficiency since the use of pump is more efficient than using a compressor, which would be commonly used to inject gaseous carbon dioxide.

Optionally, the method may comprise storing the carbon dioxide within the plurality of storage pipes at the offshore storage facility as a liquid at ambient temperature conditions. Consequently, the method may also comprise liquefying the carbon dioxide at ambient temperature conditions prior to storage. The skilled person will appreciate that storing liquefied carbon dioxide at ambient temperature conditions requires the carbon dioxide to be pressurised at pressures far above ambient pressure conditions with the exact pressure conditions being determined by the specific ambient temperature at which the carbon dioxide is stored. Conventionally, liquefaction and storage of carbon dioxide as a liquid is carried out at ambient pressure conditions and hence, as will be understood by the skilled person, at very cold temperature conditions that are significantly below ambient temperature conditions. In the context of the invention however, whilst possible, it is less advantageous to store carbon dioxide at temperature conditions significantly below ambient temperature conditions. This is because there is significant complexity and expenditure, both operational and capital, associated with the equipment, personnel and processes required to produce and maintain carbon dioxide as a liquid at such temperature conditions and at ambient pressure conditions. In an offshore scenario, limited space also means that it may not be viable to provide the necessary infrastructure to store liquefied carbon dioxide at ambient pressure conditions.

Thus, it is thought to be particularly advantageous (though optional) in the context of the invention of the above aspects to store liquid carbon dioxide at ambient temperature conditions. As noted above, this requires the carbon dioxide to be pressurised at pressure conditions well above ambient conditions; however, the pressurisation required is associated with significantly reduced complexity and expenditure, both operational and capital, in terms of the equipment, personnel and processes involved and hence is particularly suited to offshore scenarios.

Ambient temperature conditions may be a temperature between 0 - 25 °C. As such, the pressure required in order to store the liquefied carbon dioxide may be between 34 barg - 45 barg, with the exact pressure required being determined by the ambient temperature.

The term ‘storage pipe’ refers to a storage container formed from a length of pipe, which has been closed at each end, optionally by a hemispherical cap or dome that has, for example, been welded to the end of the pipe. Accordingly, the storage pipes are highly elongate, typically having a length-to-diameter ratio of at least 20.

The use of storage pipes as compared to, e.g., conventional tank storage (i.e. vessel storage) as the basis for storage at offshore storage facility is advantageous since it is associated with a significantly lower capital and operational expenditure, particularly in the optional context of storing liquid carbon dioxide at elevated pressures and ambient temperature conditions.

Typical ‘tank’ type storage solutions require thick steel walled tanks. These tanks are expensive to provide (given the large amount of material typically required), and are also expensive to transport to their location of use given their weight (again, given the large amount of material required). The requisite wall thickness (and hence weight of the tank) also limits the size of the tank that can be used, meaning that the volume of carbon dioxide stored therein is limited.

In contrast, pipe storage is relatively inexpensive to provide because standard, ‘off-the-shelf’ pipes may be used to manufacture them. Moreover, for a given volume of storage, pipe storage can have a comparatively smaller wall thickness. Thus, a given volume of carbon dioxide can be stored using a comparatively lower total weight of storage tank material using pipe storage and this can consequently be achieved at a lower capital expenditure. Thus, pipe storage is a more viable solution.

Each of the storage pipes may have a nominal diameter of between 40-60 inches (1.0m - 1.5m). Preferably, each pipe may have a nominal size of 42 inches (1.1m) or 56 inches (1 ,4m), or may have any nominal size in the range of 42 inches (1.1m) to 56 inches (1.4m).

A vessel having a nominal diameter greater than about 56-60 inches (1.4 m -1.5m) would typically be considered by the skilled person as a conventional tank (or pressure vessel) that is distinct from a pipe. This consideration is also true in the context of the current application, whereby any vessel having a nominal diameter of greater than about 56-60 inches (1.4m -1.5m) would not be considered as a pipe.

The storage pipe may be or have an X52, X56, X60, X65, X70 or X80 pipe in accordance with the API SPEC 5L specification.

As noted above, the storage pipes are highly elongate. Accordingly, each storage pipe may have a length of between 10 m to 30 m, for example 12 m, 24 m or 26 m.

The storage pipes may be formed from rolled pipes with, optionally, a single longitudinal seam. Such pipes are commonly available as ‘off-the-shelf’ type components and are typically inexpensive.

The storage pipes may be configured for storing carbon dioxide at an elevated pressure, for example liquefied carbon dioxide at ambient temperature conditions. The storage pipes may be configured to store the carbon dioxide at between 34 barg - 45 barg. The exact pressurised conditions that the storage pipes are configured to store the carbon dioxide at may be selected dependent on the ambient temperature of the carbon dioxide (optionally as a liquid) to be stored therein, the tolerances of the storage pipe and/or the tolerance of the equipment used for loading and unloading the carbon dioxide into the storage pipes.

Each of the storage pipes may be arranged vertically (i.e. the primary axis of the storage pipes may be arranged vertically or substantially vertically) or horizontally (i.e. the primary axis of the storage pipes may be arranged horizontally or substantially horizontally). The storage pipes may comprise a combination of horizontally and vertically arranged storage pipes. Each or some of the storage pipes may be arranged in any other orientation between horizontal and vertical.

A particularly advantageous, but optional, combination of features resides in the use of storage pipes for storing liquefied carbon dioxide at ambient temperature conditions at the offshore storage facility. This combination of features offers a cheap, simple and technically non-challenging means for storing liquid carbon dioxide at ambient temperature conditions that is superior to other storage solutions.

The method may comprise transporting the carbon dioxide to the site of the offshore storage facility. The method may subsequently comprise the step of transferring the carbon dioxide to the offshore storage facility.

The step of transporting the carbon dioxide to the site of the offshore storage facility may comprise transporting the carbon dioxide from a (the) carbon capture facility. The carbon capture facility may be situated onshore (i.e. land- based) or offshore.

The step of transporting the carbon dioxide to the site of the offshore storage facility may comprise transporting the carbon dioxide as a liquid (i.e. liquefied carbon dioxide), optionally as a liquid at ambient temperature conditions. The step of transferring the carbon dioxide to the offshore storage facility may comprise transferring the carbon dioxide as a liquid (i.e. liquefied carbon dioxide), optionally as a liquid at ambient temperature conditions. The (optional) step of liquefying the carbon dioxide, optionally at ambient temperature conditions, may hence occur prior to the step of transporting the carbon dioxide to the site of the offshore storage facility.

The step of transporting may be achieved using a transportation vessel (e.g. tanker) comprising storage thereon for the carbon dioxide.

The storage of the transportation vessel may be, for example, a second plurality of storage pipes. The second plurality of storage pipes may correspond to the storage pipes provided at the offshore storage facility as described above, and optionally may be in accordance with any compatible optional feature thereof as also discussed above.

The step of transferring the carbon dioxide to the offshore storage facility may comprise transferring the carbon dioxide from the transportation vessel to the offshore storage facility. This may comprise use of offloading equipment (e.g. comprising conduits, pumps, compressors and the like), which may be configured to maintain the carbon dioxide as a liquid at ambient temperature conditions by maintaining the carbon dioxide at the necessary pressure.

The offshore storage facility may be considered as an intermediate storage facility and/or a buffer storage facility. That is, the offshore storage facility may act as a temporary store/ a buffer for a supply of carbon dioxide to the injection well, optionally after having been transferred to the offshore storage facility from a (the) transportation vessel.

The offshore storage facility may be a single, self-contained unit, e.g. a single, modular unit. The offshore storage facility may be self-contained, separate and separable from, e.g., the injection well, the optional hydrocarbon production system, the optional hydrocarbon facility, the optional transportation vessel etc.

The offshore storage facility may be an offshore floating storage facility. For example, the offshore storage facility may take the form of a floating platform, such as a spar platform, a tension leg platform, a semi-submersible platform, etc. The offshore storage facility may alternatively take the form of a spar buoy or a vessel (e.g. a tanker or a barge). The offshore storage facility may comprise a ship shaped hull, e.g. a modified ship hull.

Alternatively, the offshore storage facility may be a fixed offshore storage facility (i.e. not floating). For example, the offshore storage facility may take the form of a fixed platform, a jack-up platform, a jacketed platform, a gravity platform, etc. The storage pipes of the fixed offshore storage facility may be at, above, below, or partly above and partly below sea level.

The offshore storage facility may comprise a pump. The pump may be configured to pump the carbon dioxide out of the storage pipes and into the injection well. As such, the step of injecting the stored carbon dioxide into an injection well of the hydrocarbon production system may comprise pumping the carbon dioxide out of the storage pipes and into the injection well using the pump. The pump may additionally or alternatively be configured to pump carbon dioxide into the storage pipes. As such, prior to the step of storing carbon dioxide within the plurality of storage pipes at the offshore storage facility, the method may comprise pumping the carbon dioxide into the plurality of storage pipes.

The offshore storage facility may comprise a receiver. The receiver may be arranged to receive carbon dioxide transferred to the offshore storage facility, for example carbon dioxide transferred to the offshore storage facility from a (the) transportation vessel. Accordingly, the method may comprise receiving carbon dioxide transferred to the offshore storage facility at the receiver. The receiver may be arranged to supply carbon dioxide to the storage pipes for subsequent storage therein, optionally with the assistance of a (the) pump. Accordingly, the method may comprise supplying carbon dioxide to the storage pipes from the receiver. In embodiments where the carbon dioxide is in liquid form, the receiver may be arranged to ensure that only liquid carbon dioxide is supplied to the storage pipes.

The offshore storage facility may be unmanned, for example an unmanned platform or an unmanned vessel. That is to say, the offshore storage facility may have no permanent personnel and may only be occupied for particular operations such as maintenance and/or installation of equipment. The unmanned offshore storage facility may require no personnel for the offshore storage facility to carry out its normal function, for example day-to-day functions relating to the steps of storing carbon dioxide and injecting carbon dioxide.

An unmanned offshore storage facility may comprise no provision of facilities for personnel to stay, for example there may be no shelters for personnel, no toilet facilities, no drinking water and/or no personnel operated communications equipment. The unmanned offshore storage facility may also include no heli-deck and/or no lifeboat.

An unmanned offshore storage facility may alternatively or additionally be defined based on the relative amount of time that personnel are needed to be present during operation. This relative amount of time may be defined as maintenance hours needed per annum, for example, an unmanned offshore storage facility may require fewer than 10,000 maintenance hours per year, optionally fewer than 5000 maintenance hours per year, perhaps fewer than 3000 maintenance hours per year.

In accordance with a third aspect of the invention, there is provided an offshore storage facility comprising a plurality of storage pipes configured to store carbon dioxide therein, wherein the offshore storage facility is configured to inject stored carbon dioxide into an injection well. The offshore storage facility of the third aspect may be in accordance with the offshore storage facility discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof.

In accordance with a fourth aspect of the invention, there is provided a combination comprising a subsea injection well and an offshore storage facility according to the third aspect of the invention, optionally in accordance with any optional form thereof. The offshore storage facility is connected to the injection well via a conduit, wherein the conduit permits injection of carbon dioxide from the offshore storage facility to the injection well.

The injection well of the fourth aspect of the invention may be in accordance with the injection well discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof. Similarly, the offshore storage facility of the fourth aspect may be in accordance with the offshore storage facility discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof.

In accordance with a fifth aspect of the invention, there is provided a combination comprising a hydrocarbon production system for producing hydrocarbons from a hydrocarbon reservoir and an offshore storage facility in accordance with the third aspect of the invention, optionally in accordance with any optional form thereof. The hydrocarbon production system comprises a subsea injection well in communication with the hydrocarbon reservoir, wherein the subsea injection well is connected to the offshore storage facility via a conduit that permits injection of carbon dioxide from the offshore storage facility to the injection well.

The hydrocarbon production system of the fifth aspect of the invention may be in accordance with the hydrocarbon production system discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof. Similarly, the injection well of the fifth aspect of the invention may be in accordance with the injection well discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof. The offshore storage facility of the fifth aspect may also be in accordance with the offshore storage facility discussed in connection with the above aspects of the invention, and may be in accordance with any optional form thereof. The hydrocarbon reservoir of the fifth aspect may be in accordance with the hydrocarbon reservoir described in connection with the above aspects of the invention. Certain embodiments of the invention will now be described, by way of example only, and with reference to the accompanying drawings, in which:

Figure 1 schematically depicts an offshore storage facility connected to a subsea injection well of a hydrocarbon production system;

Figure 2 is a perspective view of the offshore storage facility of Figure 1;

Figure 3 is a cross-sectional view of the offshore storage facility of Figures 1 and 2; and

Figure 4 is a part-cutaway side view and cutaway plan view of the tanker of Figure 1.

Figure 1 shows an offshore storage facility 1 , and more specifically an offshore floating storage facility 1 at the site of and connected to a subsea injection well 4 via a conduit 4a. The subsea injection well 4 is in communication with a producing hydrocarbon reservoir 6 and forms part of a hydrocarbon production system 3. The hydrocarbon production system additionally comprises hydrocarbon production platform 5, which itself comprises production and processing equipment that enables production of hydrocarbons from the hydrocarbon reservoir 6 and processing thereof.

Also connected to the offshore floating storage facility 1 is a tanker 2. The tanker 2 is connected to the offshore floating facility 1 via two separate conduits 2a, 2b that are each arranged to carry a fluid, specifically liquid carbon dioxide, between the tanker 2 and the offshore floating storage facility 1 as will be described in greater detail below. The conduits 2a and 2b are reversibly connected to the tanker 2 as is also described in further detail below.

As can be seen in greater detail with reference to Figures 2 and 3, the offshore floating storage facility 1 has a predominantly ship shaped hull 101 and, situated at a top of the hull 101 , a landing pad 102 for helicopters to permit personnel access to the facility 1 for maintenance or otherwise. Housed within the hull 101 are a plurality of vertically oriented storage pipes 103. The storage pipes 103 are arranged to store liquid carbon dioxide therein at ambient temperature conditions and, consequently, at pressures of between 34 barg - 45 barg (the exact pressure of storage being dependent on the ambient temperature conditions). Each storage pipe 103 is formed from a section of pipe having an X45 specification and that is sealed at either end via a suitable hemispherical cap. As shown, several hundred storage pipes 103 are housed within the hull 101 of the offshore floating facility 1. The hull 101 also comprises a plurality of pumps 105 that are configured to pump liquid carbon dioxide into the storage pipes 103 at a time when the carbon dioxide is received at the offshore floating storage facility 1 from the tanker 2 (more on this below). The pumps 105 are additionally configured to pump liquid carbon dioxide out of the storage pipes and to the injection well 4 for injection purposes.

Figure 4 shows further details of the tanker 2. The tanker 2 comprises a plurality of storage pipes 23 (again, several hundred storage pipes 23) divided between several cargo holds 25 on the tanker 2. The storage pipes 23 are comparable to storage pipes 103 situated on the offshore floating facility 1 in that they are vertically oriented on-board the tanker 2 and are arranged to store liquid carbon dioxide therein at ambient temperature conditions and, consequently, at pressures of between 34 barg - 45 barg (the exact pressure of storage being dependent on the ambient temperature conditions). Each storage pipe 23 is formed from a section of pipe having an X45 specification and that is sealed at either end via a suitable hemispherical cap.

In use, the storage pipes 23 on-board the tanker 2 are loaded with ambient temperature liquid carbon dioxide at a carbon capture facility that is remote from the offshore floating storage facility 1 and the hydrocarbon production system 3. The tanker 2 then travels to the site the offshore floating storage facility 1 and the hydrocarbon production system 3 (e.g. as shown in Figure 1) whilst the liquid, ambient temperature carbon dioxide is maintained as such within the storage pipes 23. This is achieved by ensuring that the storage pipes 23 remain suitably pressurised during transit of the tanker 2. Once at the site of the offshore floating facility 1, the conduits 2a, 2b are connected to the tanker 2. Liquid carbon dioxide is then offloaded from the storage pipes 23 on the tanker 2 to the offshore floating facility 1 via the conduit 2a and via support provided by the pumps 105.

The transfer between the storage pipes 23 and the storage pipes 103, and the subsequent storage therein, is carried out whilst maintaining, as far as possible, the carbon dioxide as a liquid at ambient temperature conditions. This requires the transfer and subsequent storage in the pipes 103 to be carried out at suitably pressurised conditions, and the maintenance of these pressurised conditions is supported by the pumps 105. It typically will not be possible to maintain all carbon dioxide in a liquid state during this transfer however, even with the support of the pumps 105. For example, prior to introduction of liquid carbon dioxide in to the storage pipes 103, the interior of the storage pipes 103 may be under ambient pressure conditions and be filled with air and/or gaseous carbon dioxide left over as a remnant from a previous store of carbon dioxide. As such, initial introduction of the pressurised liquid carbon dioxide at ambient temperature conditions into the storage pipes 103 will result in an initial depressurisation of some liquid carbon dioxide such that it is vaporised into a gaseous form. Soon after however, the storage pipes 103 will pressurise sufficiently such that further introduced carbon dioxide will remain in a liquid state at ambient temperature conditions.

In the event of vaporisation of any portion of the carbon dioxide during its transfer between the tanker 2 and the offshore floating facility 1 (e.g. after initial introduction into the storage pipes 103 as discussed above), then the vaporised portion of the carbon dioxide is separated off from the liquid carbon dioxide at the offshore floating facility 1 and is transferred back to the tanker 2 via the conduit 1b. This gaseous carbon dioxide can then be re-condensed on-board the tanker 2 at ambient temperature conditions and subsequently transferred back to the offshore facility 1 via the conduit 2a for storage thereon. Alternatively, the gaseous carbon dioxide can be stored aboard the tanker 2 for transit back to, e.g., the carbon capture facility.

Once all of the liquid carbon dioxide has been offloaded from the tanker 2, the conduits 2a, 2b are disconnected. The tanker 2 then travels away from the offshore floating facility 1, optionally back to the carbon capture for further loading and transport of carbon dioxide.

The liquid carbon dioxide stored within the storage pipes 103 aboard the offshore floating facility 1 is used as an injectant into the subsea injection well 4. This is achieved by pumping the liquid carbon dioxide out of the storage pipes 103 using the pumps 105 and transferring the carbon dioxide to the subsea injection well 4 via conduit 4a under the impetus provided by the pumps 105.

The carbon dioxide injected into the subsea injection well 4 is, in turn, introduced to the hydrocarbon reservoir 6. This maintains (i.e. remedies any drop in pressure resulting from hydrocarbon production) or increases the pressure within the hydrocarbon producing reservoir 6 to thereby maintain, permit or improve the production of hydrocarbons from the hydrocarbon production reservoir by the hydrocarbon production platform 5.

The offshore storage facility 1 thus provides a buffer store for injectant, namely carbon dioxide, for the subsea injection well 4. With this buffer storage, an effective continuous supply of carbon dioxide can be supplied to the injection well 4 for injection. The offshore storage facility 1 will have a total volume of storage of carbon dioxide capable to meet the demands of injection at the subsea injection well 4 over a significant period of time and when the volume of carbon dioxide at the offshore storage facility 1 is running low then a tanker 2 can transport additional carbon dioxide to the offshore storage facility 1 to ensure that injection of carbon dioxide at the subsea injection well 4 can be maintained at the desired and optimal rate.

Claims

1. A method of injecting carbon dioxide into an offshore injection well, the method comprising: storing carbon dioxide within a plurality of storage pipes at an offshore storage facility; and injecting the stored carbon dioxide into an injection well.

2. A method as claimed in claim 1, wherein the carbon dioxide is stored as a liquid at ambient temperature conditions within the storage pipes.

3. A method as claimed in claim 2, wherein the ambient temperature conditions are between 0°C - 25 °C.

4. A method as claimed in any preceding claim, wherein the offshore storage facility is provided at the site of the of the injection well.

5. A method as claimed in any preceding claim, wherein the offshore storage facility is an offshore floating storage facility.

6. A method as claimed in any preceding claim, wherein the injection well is in communication with a geological formation capable of storing the carbon dioxide.

7. A method as claimed in any preceding claim, wherein each of the plurality of storage pipes is formed from a length of pipe that has been closed at each end.

8. A method as claimed in any preceding claim, wherein each of the storage pipes has a nominal diameter of between 40-60 inches (1.0m - 1.5m), optionally a nominal diameter in the range of 42 inches (1.1m) to 56 inches (1.4m).

9. A method as claimed in any preceding claim, where each of the plurality of storage pipes is a X52, X56, X60, X65, X70 or X80 pipe in accordance with the API SPEC 5L specification. A method as claimed in any preceding claim, wherein each of the storages pipes has a length of between 10 m to 30 m. A method as claimed in any preceding claim, comprising transporting the carbon dioxide to the offshore storage facility A method as claimed in claim 11 , wherein the step of transporting comprises use of a transportation vessel, the transportation vessel comprising a second plurality of storage pipes for storing the carbon dioxide therein during transportation. A method as claimed in claim 12, wherein the carbon dioxide is stored as a liquid at ambient temperature conditions within the second plurality of storage pipes. A method of operating a hydrocarbon production system, the method comprising: injecting carbon dioxide into an offshore injection well in accordance with any preceding claim, wherein the offshore injection well is connected to a hydrocarbon reservoir; and producing hydrocarbons from the hydrocarbon reservoir with the hydrocarbon production system. An offshore storage facility comprising a plurality of storage pipes configured to store carbon dioxide therein, wherein the offshore storage facility is configured to inject stored carbon dioxide into an injection well. A combination comprising a subsea injection well and an offshore storage facility according to claim 15, wherein the offshore storage facility is connected to the injection well via a conduit, and wherein the conduit permits injection of carbon dioxide from the offshore storage facility to the injection well. A combination comprising a hydrocarbon production system for producing hydrocarbons and an offshore storage facility according to claim 15, wherein the hydrocarbon production system comprises a offshore injection well in communication with the hydrocarbon reservoir, and wherein the offshore injection well is connected to the offshore storage facility via a conduit that permits injection of carbon dioxide from the offshore storage facility to the injection well.