TECHNICAL FIELD

The present disclosure relates to a system for use in carbon storage, such as a system for use in subsea carbon storage.

BACKGROUND

In the field of carbon capture and storage, captured carbon dioxide (CO2) may be injected into a subsea reservoir, primarily for storage thereof.

Typical systems for injecting CO2 into subsea reservoirs may use components designed and used in the oil and gas industry, including a Christmas tree to sit over and seal a wellhead or entrance to a subsea reservoir and a manifold or other piping arrangement for delivering the CO2to be injected to the reservoir via the Christmas tree.

There is a need to provide new and improved systems which are more cost effective for use in carbon storage applications.

The present disclosure provides a simplified and improved system for use in carbon storage, for example suitable for use in subsea CO2 injection systems.

SUMMARY

From a first aspect, the disclosure provides a system for use in carbon storage, the system comprising: a valve arrangement including a first fluid flow bore and a manually operable valve arranged in the first fluid flow bore, wherein the manually operable valve is moveable between an open position which allows for fluid flow there through and a closed position in which fluid is blocked from flowing there through, wherein the valve arrangement is free from any remotely operable valve; a piping arrangement including a second fluid flow bore; and a module comprising a connecting bore for connecting the first fluid flow bore to the second fluid flow bore to form a fluid flow path extending from the second fluid flow bore via the connecting bore to the first fluid flow bore, wherein the module further comprises a remotely operable barrier valve arranged in the connecting bore, wherein the barrier valve is moveable between an open position which allows for fluid flow there through and a closed position in which fluid is blocked from flowing there through.

It will be understood that the provision of a remotely operable barrier valve arranged in the connecting bore of the module allows the system to include a simpler valve arrangement in which no remotely operable valve need be provided.

At least in some examples of the disclosure, the module may be removable from the valve arrangement such that the module may be removed for maintenance, leaving the valve arrangement in situ subsea.

This may provide the advantage at least in some examples of the disclosure of allowing the remotely operable valve to be maintained repaired or replaced without the need to remove the valve arrangement or carry out maintenance or replacement of the remotely operable valve in a subsea environment.

At least in some examples of the disclosure, the first fluid flow bore may be configured to supply fluid to a subsea storage site.

At least in some examples of the disclosure, the second fluid flow bore may be configured to be connected to a fluid supply via a flowline.

At least in some examples of the disclosure, the remotely operable barrier valve may be a fail-safe valve.

At least in some examples of the disclosure, the remotely operable barrier valve may comprise a hydraulically actuated valve or an electrically actuated valve.

At least in some examples of the disclosure, the remotely operable barrier valve may be configured to be caused to close by a loss of power or hydraulics. At least in some examples of the disclosure, the system may further comprise a subsurface safety valve configured to be located in a wellbore extending from the valve arrangement to the subsea storage site.

At least in some examples of the disclosure, the subsurface safety valve may be a surface controlled subsurface safety valve, for example a manually controlled subsurface safety valve.

At least in some examples of the disclosure, the subsurface safety valve may further comprise a downhole non-return valve configured to be located in a wellbore extending from the valve arrangement to the subsea storage site.

At least in some examples of the disclosure, the downhole non-return valve may be a mechanically operated flapper valve.

At least in some examples of the disclosure, the system may be free from any hydraulically operated subsurface safety valve in the wellbore.

From a further aspect, the disclosure provides an arrangement for subsea carbon storage, the arrangement comprising: a subsea storage site; and a system as described in any of the above examples, wherein the first fluid flow bore is fluidly connected to the subsea storage site.

At least in some examples of the disclosure, the arrangement may further comprise a carbon supply and a flowline fluidly connecting the carbon supply to the second fluid flow bore.

At least in some examples of the disclosure, the system may be located on or near the seabed, adjacent the subsea storage site.

From a still further aspect of the disclosure, a method of removing a module from a system for use in carbon storage as described any of the above examples is provided, the method comprising: closing the manually operable valve in the valve arrangement; and removing the module from the system.

At least in some examples of the disclosure, the method may further comprise replacing or repairing the module after it has been removed.

At least in some examples of the disclosure, repairing the module may comprise replacing or maintaining the remotely operable barrier valve in the module, and the method may further comprise replacing the module in the or another system after it has been repaired.

From a still further aspect of the disclosure, a method of operating a system for use in carbon storage as described in any of the above examples is provided, the method comprising: connecting a carbon supply to the second fluid flow bore; and opening the remotely operable barrier valve in the module to allow carbon to flow into a subsea storage site from the system.

At least in some examples of the disclosure, the method may further comprise: closing the remotely operable barrier valve in the module to stop carbon flow into the subsea storage site from the system.

At least in some examples of the disclosure, the method may further comprise disconnecting the carbon supply from the second fluid flow bore.

At least in some examples of the disclosure, the method may further comprise closing the remotely operable barrier valve due to an emergency event.

At least in some examples of the disclosure, the method may further comprise closing a subsea safety valve.

Although certain advantages are discussed below in relation to the features detailed above, other advantages of these features may become apparent to the skilled person following the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS One or more non-limiting examples will now be described, by way of example only, and with reference to the accompanying figures in which:

Figure 1 is a schematic representation of an arrangement for subsea carbon storage including a system according to a first example of the present disclosure;

Figure 2 is a schematic representation of an arrangement for subsea carbon storage including a system according to a second example of the present disclosure;

Figure 3 is a schematic representation of an arrangement for subsea carbon storage including a system according to a third example of the present disclosure;

Figure 4 is a schematic diagram showing a method of using a system according to the disclosure;

Figure 5 is a schematic diagram showing a method of removing a module from a system according to the disclosure; and

Figure 6 is a schematic diagram showing a method of operating a system according to the disclosure in an emergency situation.

DETAILED DESCRIPTION

According to various examples of the disclosure, a system for use in a subsea CO2 injection system for carbon capture and storage applications is provided. The system comprises a valve arrangement, a piping arrangement for connecting two or more flow streams together (for example, a flowbase or a manifold) and a module. In some examples, the valve arrangement may be a Christmas tree (XT). The valve arrangement may be positioned on or near the seabed above a subsea storage site. The subsea storage site may for example include one or more of various types of subsurface formations including a subsea reservoir, a saline aquifer or a coal seam. The valve arrangement may be connected to the subsea storage site to form a barrier between the subsea storage site and the environment (e.g. the surrounding sea water). The valve arrangement includes a first fluid flow bore and a manually operable valve arranged in the first fluid flow bore, wherein the first fluid flow bore may be adapted to be coupled to tubing for supplying a fluid to the subsea subsea storage site, and wherein the manually operable valve is moveable between an open position which allows for flow there through and a closed position in which fluid is blocked from flowing there through, and wherein the valve arrangement is free from any remotely operable barrier valve. The piping arrangement includes a second fluid flow bore which may be adapted to be coupled to a flowline for supplying the fluid to be injected into the subsea storage site to the piping arrangement. The module comprises a connecting bore for connecting the first fluid flow bore to the second fluid flow bore to form a fluid flow path extending from the second fluid flow bore via the connecting bore to the first fluid flow bore. The module further comprises a remotely operable barrier valve arranged in the connecting bore. The remotely operable barrier valve is moveable between an open position which allows for flow there through and a closed position in which fluid is blocked from flowing there through. At least in some examples of the disclosure, the remotely operable barrier valve may be fail safe closed (meaning that, in the event of loss of power or hydraulics, this barrier valve on the module would automatically close to shut-in the subsea storage site. In other words, the remotely operable barrier valve may be caused to close by a loss of power or hydraulics). Thus, the remotely operable barrier valve may function to replace a primary or remotely operable valve on a valve arrangement. Because of this, the valve arrangement may be free from any remotely operable barrier valve as described above.

In any example of the disclosure, a manually operable valve may be operated by a remotely operated vehicle (ROV). In any example of the disclosure, a remotely operable valve may be operated without the need for any manual intervention (for example from an ROV). A remotely operable valve can for example be controlled to open and close as required by a hydraulic control or by an electronic control. A remotely operable valve (including but not limited to a hydraulically actuated or electrically actuated valve) can be controlled from a location which is remote (at a distance or removed from) the location of the remotely operable valve. In some examples of the disclosure, a remotely operable valve may be controlled by a control system which is located on shore or on a vessel or other structure located above the surface of the sea.

Referring now to Figure 1 , and in any example of the disclosure, a subsea carbon dioxide (CO2) injection arrangement for carbon capture and storage (CCS) applications may be configured to inject CO2 into storage in a subsea environment after it has been captured. The arrangement 2 may include a temporary storage structure for storing CO2 which has been captured from the environment. This may provide a carbon supply for injection. In some examples, such as that shown in Figure 1, the temporary storage structure may be provided by one or more storage tanks (not shown) which may for example be provided on a vessel 4. In some examples, use of the vessel 4 may allow for transportation of the CO2 in the storage tanks from a first location to a location above a subsea injection site. The first location may for example be a carbon capture location such as a carbon capture system found in a power station or a factory.

The arrangement 2 may be configured to allow for CC to be injected into a subsea storage site such as an aquifer 6 for storage therein. In some examples of the disclosure, the vessel 4 may be adapted to be moored to a buoy (not shown) so as to be located above or near to the aquifer 6.

A system according to an example of the disclosure is provided and includes a valve arrangement 10, in this example a Christmas tree (XT), such as a tree for CO2 injection, a piping arrangement, in this example a flowbase 12, and a module 14 of the types described above.

As seen in Figure 1, the aquifer 6 may be connected to the seabed surface via a wellbore (not shown) extending downwardly from the seabed surface. Wellbore tubing 16 may extend through the wellbore to provide fluid to the aquifer 6. A safety valve 20 may be provided in the wellbore, in some examples in the wellbore tubing 16, such that the aquifer 6 can be fluidly isolated from the seabed and /or other elements of the external environment if required in the event of any system malfunction. In any example of the disclosure, the safety valve 20 may be a surface controlled subsurface safety valve (SCSSV). The SCSSV may be a manually controlled SCSSV which may for example be closed by a hot stab controlled by an ROV.

As an additional safety feature to the SCSSV, in at least some examples of the disclosure, a downhole non-return valve (not shown) may also be provided in the wellbore, for example in the wellbore tubing 16. This non-return valve may be a mechanically operated flapper valve which is adapted to open when a pressure of fluid above the valve, i.e. flowing into the wellbore towards the aquifer, is above a desired limit or threshold. Thus, the downhole non-return valve will act to close against fluid trying to escape from the aquifer via the wellbore. In still further examples of the disclosure, the SCSSV may be replaced by a downhole non-return valve of the type described above such that the safety valve 20 is a downhole non-return valve which is provided as an alternative to an SCSSV.

It will be understood that in any example of the disclosure, the safety valve 20 may take any desired form including either or both of an SCSSV and a downhole nonreturn valve.

As described above, the valve arrangement 10 is connected to the aquifer 6 by a first fluid flow bore 22 which is connected to the wellbore tubing 16. The valve arrangement 10 may further comprise a further fluid flow bore 24 as seen. At least in some examples of the disclosure, the first fluid flow bore 22 is an injection bore and the further fluid flow bore 24 is an annulus bore, that is a bore for accessing an annulus in the wellbore. It will be understood by a person skilled in the art that the annulus is an annular space typically formed between the wellbore tubing and a metal casing that provides structural stability to the wellbore. The annulus usually contains some sort of pressurised fluid which is monitored to ensure that any increase or decrease in annulus pressure does not cause any integrity issues for the wellbore tubing. The annulus bore may provide a means to access the annulus for monitoring, pressure management and intervention activities as needed.

First and second valves 26, 28 are provided in the first fluid flow bore 22 and are spaced from each other along the length of the first fluid flow bore 22. The first and second valves 26, 28 are manually operable valves which are moveable between an open position which allows for fluid flow there through and a closed position in which fluid is blocked from flowing there through. It will be understood that in other examples of the disclosure which are not shown, only one manually operable valve is provided in the first fluid flow bore 22. It will further be understood that the valve arrangement in the system according to the disclosure is free from any remotely operable valve. In other words, no remotely operable valve such as hydraulically or electrically actuated barrier valves is provided in the valve arrangement.

In addition to the valves described above, third and fourth valves 30, 32 are provided in the further fluid flow bore 24 and are spaced from each other along the length of the further fluid flow bore 24. The third and fourth valves 30, 32 are again manually operable valves which are moveable between an open position which allows for fluid flow there through and a closed position in which fluid is blocked from flowing there through. It will be understood that in other examples of the disclosure which are not shown, only one manually operable valve is provided in the further fluid flow bore 24. Further, if required, more than two such valves could be provided in one or both of the first and further fluid flow bores 22, 24.

It will be understood that access to the wellbore may be provided via either of the first and further fluid flow bores 22, 24 if needed for well intervention operations. Further, although the valve arrangement 10 shown in Figure 1 shows the first and further fluid flow bores 22, 24 extending vertically away from the aquifer 6 and the valves provided in the flow bores, in other examples the valve arrangement could correspond to that of a horizontal XT. For example, crown plugs could be provided in each fluid flow bore and valves could be provided below the crown plugs to allow fluid to flow through the valves, for example in a horizontal direction, when the valves were open.

The flowbase 12 includes a second fluid flow bore 34 which, when the flowbase is in situ and the system is assembled, is coupled to a flowline or flexible riser 36 for supplying the fluid to be injected into the aquifer 6 to the flowbase 12. As seen in Figure 1, CO2 from the storage tanks on vessel 6 may be pressurised as required for injection and supplied to the flowbase 12 via the flowline 36 which connects the storage tanks to second fluid flow bore 34. A manually activated flowbase valve 38 is provided in the second fluid flow bore 34 and can be closed if required to isolate flow into or out of the flowbase via the flowline 36.

A further manually activated flowbase valve 39 is provided, at least in some but not all examples, in the second fluid flow bore 34. The further flowbase valve 39 can be closed if required to isolate flow into or out of the flowbase. This further flowbase valve 39 provides a similar function as the flowbase valve 38. It is provided to allow for possible expansion of the system to include additional wells that may be a distance away from the initial wellbore, connecting the additional wells to the system via the flowbase. This could be achieved by connecting such a new well into the flowbase via a new flowline (not shown) which could be connected to the second fluid flow bore 34 such that fluid could flow from the second fluid flow bore

34, through the further flowbase valve 39 when opened and onward to one or more additional wells via the new flowline.

The module 14 includes a connecting bore 40 for connecting the second fluid flow bore 34 of the flowbase 12 to the first fluid flow bore 22 to form a fluid flow path extending from the second fluid flow bore 34 via the connecting bore 40 to the first fluid flow bore 22. The module 14 also includes a remotely operable barrier valve 42 arranged in the connecting bore 40. The remotely operable barrier valve 42 is moveable between an open position which allows for flow there through and a closed position in which fluid is blocked from flowing there through such that fluid cannot flow past the remotely operable barrier valve 42 and through the connecting bore 40 from the second fluid flow bore 34 to the first fluid flow bore 22 or from the first fluid flow bore 22 to the second fluid flow bore 34 when the remotely operable barrier valve 42 is closed. The remotely operable barrier valve 42 may be actuated quickly if required, in the event of a system failure for example, to stop or limit fluid from the aquifer flowing from the module into the flowbase or escaping into the environment. At least in some examples, the remotely operable barrier valve 42 is configured to close automatically due to a loss of power or hydraulic pressure. Thus, the remotely operable barrier valve 42 may provide a primary barrier valve that closes in an emergency to shut-in the subsea storage site and so avoid CO2 leakage.

In some examples, the remotely operable barrier valve 42 may be a wing valve.

At least in some examples of the disclosure, the module 14 may also include a choke valve 44 arranged in the connecting bore 40 for controlling the flowrate of fluid through the choke valve 44 and through the wellbore tubing 16 into the subsea reservoir. In some examples, the choke valve 44 may be remotely actuatable but it could also be manually actuatable, for example by an ROV. The choke valve may be configured to be adjustable to provide a desired resistance to fluid flow therethrough depending on the position of the valve. It will be understood that although the example of Figure 1 includes a choke valve 44 within the connecting bore 40 of the module 14, in other examples no choke valve need be provided in the module. If desired, a choke valve could additionally or alternatively be provided in another part of the system, for example within the first fluid flow bore 22 of the valve arrangements 10.

Although it could take many different forms as discussed above, the remotely operable barrier valve 42 in the example of Figure 1 is an electrically actuated valve which is controlled via a direct current (DC) signal which, in some examples, may be provided from an onshore control centre 46. The signal may travel from the control centre 46 to the remotely operable barrier valve 42 via a wired connection 48 between the control centre 44 and the module 14 as seen in Figure 1. By using electrically actuated valves in the module, it is possible to remove the need for any hydraulics in the system, thus reducing the cost and complexity of the system.

It will be understood that the remotely operable barrier valve 42 has fail-safe closed functionality. In other words, the valve may close automatically, for example, on the loss of power or signal communication or if other emergency situations should arise. The remotely operable barrier valve 42 can be used to shut off flow into or out of a well as needed. In some examples such as when being used for CO2 injection, the remotely operable barrier valve 42 may be closed to shut CO2 into the subsea storage site in between CO2 injection cycles. Thus, the remotely operable barrier valve 42 may be opened and closed relatively frequently such that a high number of valve operation cycles may be experienced over the life of the subsea storage site. At least in some examples, the module including the remotely operable barrier valve 42 may be removeable to allow for the remotely operable barrier valve 42 to be repaired or replaced without a need to remove the whole system.

In any example of the disclosure therefore, the module (for example module 14) including the remotely operable valve (for example, barrier valve 42) may be a removable or retrievable module. Thus, the module 14 may be disconnected from the valve arrangement 10 and the manifold 12 and removed from the subsea environment while leaving either the valve arrangement 10 or both the valve arrangement 10 and the flowbase 12 in situ and connected to the subsea reservoir. This enables the remotely operable valve 42 to be removed (for example to an onshore location) for replacement or for maintenance without the need to remove the valve arrangement 10, thus significantly reducing the time and expense involved in replacing or maintaining the remotely operable valve 42. This is advantageous at least in some examples in the context of carbon storage as the remotely operable valve 42 may be actuated on a daily basis or more frequently. Therefore, the remotely operable valve 42 is likely to have a shorter lifetime or to wear out more quickly than a typical barrier valve used in an oil and gas recovery system. Thus, making the barrier valve of a system according to the disclosure less expensive and time consuming to replace is desirable. It will further be understood that the manually operable valve(s) provided in the valve arrangement 10(for example valves 26, 28, 30 and 32), or provided in the flowbase 12 (for example valve 38) need only be closed in the event that it is not possible to close the remotely operable valve 42 of the module 14 or when it is intended to remove the module 14 from the system. Thus, using an ROV to manually close one or more valves in the valve arrangement and I or the manifold will only be necessary on a relatively infrequent basis such that this will not cause any significant inconvenience or expense.

Figure 2 shows a second example of a system according to the disclosure in which all the components of the system except the module correspond to and are as described for the example of Figure 1. Because of this, the same reference numbers are used for these components in Figures 1 and 2 and the components are not described further here.

As seen in Figure 2, the module 214 of this example has all the features of the module 14 of Figure 1. Thus, the module 214 includes a connecting bore 240 for connecting the second fluid flow bore 34 of the manifold 12 to the first fluid flow bore 22. The module 214 also includes a remotely operable barrier valve 242 and a choke valve 244 arranged in the connecting bore 240 as for the Figure 1 example. In addition, the module 214 of this example includes a further remotely operable barrier valve 260 which may be located at any desired location along the extent of the connecting bore 240. In the example shown, the remotely operable barrier valve 242 is provided downstream of the choke valve 244 and the further remotely operable barrier valve 260 is provided on the other side of the choke valve 244, upstream thereof.

It will be understood that a further or secondary remotely operable barrier valve 260 may have all the same characteristics as those of the remotely operable barrier valve 42 described above in relation to Figure 1. Further, such a further or secondary remotely operable barrier valve may be provided in any example of the disclosure if it is desired to provide a secondary barrier. In some examples, this may be because the provision of only a single mechanical barrier between a storage site and the external environment is not considered to meet safety requirements, for example as set out in local industry standards.

In various examples of the disclosure such as the example shown in Figure 3, CO2 may be injected into the subsea storage site via more than one valve arrangements and wellbores. Although any suitable number of wellbores and corresponding valve arrangements may be provided, in the example of Figure 3, the arrangement shown includes two separate wellbores and valve arrangements. In the arrangement shown, first and second systems 370, 372 according to an example of the disclosure are provided. Each system 370, 372 includes a valve arrangement 310 connected to a respective module 314, wherein each valve arrangement 310 and the module 314 is as described above in relation to Figure 1.

The valve arrangements and the modules of this example are connected to a single piping arrangement, in this example, a manifold 312. A CO2 supply vessel 304 supplies the manifold 312 via a supply line 336 as for the arrangement of Figure 1. Thus, the supply line 336 can be connected to a second fluid flow bore 334 of the manifold 312. The second fluid flow bore 334 of the manifold 312 is connected to both the first and second systems 370, 372.

Wellbore tubing 316 is provided through which CO2 may be injected in to the subsea storage site 306 from each respective system 370, 372. A safety valve 320 of one of the types described above is provided in each wellbore tubing 316. As shown in Figure 3, a single control centre 346 may communicate via a single wired connection 348 with both of the systems 370, 372. If desired however, for example for improved safety, separate wired connections could be provided for each system.

As for the flowbase of the examples of Figures 1 and 2, a manually activated manifold valve 338 is provided in the second fluid flow bore 334 and can be closed if required to isolate flow into or out of the manifold 312 via the supply line 336. A further manually activated manifold valve 339 is provided, at least in some but not all examples, in the second fluid flow bore 334. The further manifold valve 339 can be closed if required to isolate flow into or out of the manifold. This further manifold valve 339 provides a similar function as the manifold valve 338. It is provided to allow for possible expansion of the system to include additional wells that may be a distance away from the initial wellbore, connecting the additional wells to the system via the flowbase. This could be achieved by connecting such a new well into the flowbase via a new flowline (not shown) which could be connected to the second fluid flow bore 34 such that fluid could flow from the second fluid flow bore 34, through the further flowbase valve 39 when opened and onward to one or more additional wells via the new flowline.

Various methods of using a system for use in carbon storage according to the disclosure will now be described. It will be understood that the method described herein may be used with a system according to any example of the disclosure, including but not limited to the example systems and arrangements described above. For ease of reference, the method steps below are described with reference to the system shown in Figure 1.

Figure 4 is a schematic diagram showing how a system according to the disclosure may be used when injecting CO2 into a subsea storage site during normal operation. It will be understood that the system 2 may be installed subsea and connected to a subsea storage site such that it is ready for use. Further, under normal operating conditions, the manually operable valves of the valve arrangement and the piping arrangement will remain open whereas the remotely operable barrier valves in the module will be closed when the system is not connected or in use.

To inject captured CO2 into a subsea storage site, a vessel 4 may be used to transport the stored CO2 offshore. The vessel may then be connected to a flexible riser 36 such that injection of CO2into the flexible riser may be commenced (step 401). Next, the one or more remotely operable barrier valves in the module are opened (for example via an electrical or hydraulic signal from the control centre) to allow the CO2 to flow into the subsea storage site (step 402).

When injection of the CO2 from the vessel has been completed or if it is desired to stop the injection for any reason, the one or more remotely operable barrier valves in the module are closed to shut-in the subsea storage site (step 403).

Once the one or more remotely operable barrier valves in the module are closed, the vessel may be disconnected from the flexible riser and the vessel may then depart the storage site, for example to return to shore to be re-stocked with CO2 for injection (step 404).

Figure 5 is a schematic diagram showing a method of retrieving a module from a system according to the disclosure. It will be understood that once retrieved, the module may be repaired or replaced as necessary. In order to retrieve the module, a diver or ROV is first deployed to shut at least one manually operable valve in the valve arrangement so as to shut-in the subsea storage site (step 501).

At step 502, the module is then removed from the system subsea. In some examples, the module may be retrieved by an ROV or diver and taken to shore to be repaired. For example, the remotely operable barrier valve may be replaced so as to renew the module.

The module is then replaced by either a new module or the original module after it has been repaired or renewed (step 503). Again, this step can be carried out by an ROV or a diver.

After the module has been replaced and reconnected to the system as necessary, a diver or ROV re-opens the at least one manually operable valve in the valve arrangement (step 504). After this step has been completed, the system may again be used for normal operation of CO2 injection as required.

Figure 6 is a schematic diagram showing the steps in an emergency shut down of a system according to the disclosure. At step 601 , an emergency event occurs. This could for example be due to a storm or due to failure of one or more components of the system. When such an emergency occurs, power supply or communication with the control centre may be lost (step 602), causing an automatic closure of the remotely operable barrier valve in the module (604). In other examples, the emergency event may cause a signal to be directly or indirectly generated (step 603) and the signal may be sent to the module from the control centre thus causing the closure of the remotely operable barrier valve in the module (604). At least in some examples, a subsea safety valve provided in the wellbore and of any type described above may also be closed by the signal generated at step 603 (step 605). In other examples, the subsea safety valve may be configured to close automatically or to be closed manually as discussed further above.

While the disclosure has been described in detail in connection with only a limited number of examples, it should be readily understood that the disclosure is not limited to such disclosed examples. Rather, the disclosure can be modified to incorporate any number of variations, alterations, substitutions or equivalent arrangements not heretofore described, but which are commensurate with the scope of disclosure. Additionally, while various examples of the disclosure have been described, it is to be understood that aspects of the disclosure may include only some of the described examples. Accordingly, the disclosure is not to be seen as limited by the foregoing description, but is only limited by the scope of the appended claims.