WO2008074995A1

WO2008074995A1 - Electrical power storage and pressurised fluid supply system

Info

Publication number: WO2008074995A1
Application number: PCT/GB2007/004792
Authority: WO
Inventors: Anthony Stephen Bamford; Hugh Williams
Original assignee: Geoprober Drilling Limited; Fathom Systems Limited
Priority date: 2006-12-21
Filing date: 2007-12-13
Publication date: 2008-06-26
Also published as: GB0625830D0

Abstract

The invention relates to an electrical power storage and pressurised fluid supply system for use in the oil and gas exploration and production industry. A fluid operated apparatus associated with a well incorporating such a system; a method of carrying out a well function; and a method of storing electrical power and supplying fluid under pressure to a fluid operated apparatus associated with a well is also disclosed. In an embodiment of the invention, there is disclosed an electrical power storage and pressurised fluid supply system (10) for use in a subsea environment in the actuation of fluid operated apparatus such as a BOP (48) associated with a well (59). The system comprises an electrical power storage unit (12); at least one electric motor (18, 18') coupled to and powered by the at least one electrical power storage unit; and at least one pump (20, 20') coupled to and driven by said electric motor, said, pump adapted to supply fluid under pressure to the fluid operated apparatus for carrying out a function subsea.

Description

Electrical power storage and pressurised fluid supply system

The present invention relates to an electrical power storage and pressurised fluid supply system. In particular, but not exclusively, the present invention relates to an electrical power storage and pressurised fluid supply system for use in the oil and gas exploration and production industry; a fluid operated apparatus associated with a well incorporating such a system; a method of carrying out a well function; and a method of storing electrical power and supplying fluid under pressure to a fluid operated apparatus associated with a well.

In the oil and gas exploration and production industry, many oil and gas reserves are found in rock formations which are located in subsea environments. Accordingly, in order to gain access to the oil and gas reserves, it is necessary to drill a well borehole from the seabed down to the hydrocarbon containing rock formations. This involves deploying equipment from a surface facility, which may be a floating facility such as a drillship, floating production storage and offloading vessel (FPSO) or semi-submersible rig; or a fixed facility such as a gravity, jack-up or tension-leg platform. In each case, however, a riser extends from a wellhead of a lined wellbore drilled into the seabed, and through which production tubing passes into the lined wellbore and down to the producing rock formation.

Health and Safety laws in the industry require that adequate pressure control equipment is provided during drilling, completion and production phases of the process involved in recovering oil and gas to surface. Typically, this involves installing a large blowout preventer (BOP) on the wellhead, through which wellbore tubing and tool strings pass into the well. The BOP includes a number of hydraulically actuated shear and seal rams, which serve for carrying out varying functions. These include sealing an annulus around tubing passing through the BOP into the well and, in extreme circumstances, complete shearing of tubing passing through the BOP to shut-in the well. Other types of pressure control equipment, operating in a different fashion but serving a similar purpose, have also been proposed. These include the system disclosed in International Patent Publication No .WO2006/010906 to one of the current inventors.

As the shear and seal rams of such known pressure-control equipment are hydraulically operated, it is necessary to provide a source of pressurised fluid to quickly actuate the rams as and when required. It is often impractical to supply the fluid through pressure lines extending to surface, and such lines can be susceptible to damage, rendering the equipment inoperable, with serious consequences for safety of the operation. Furthermore, demand peaks on a permanent power supply at surface, or use of a power supply which is intermittent, can affect the supply of hydraulic fluid and thus safe operation of the equipment .

Currently therefore, it is common to provide hydraulic power by means of a system including hydraulic accumulators mounted on the BOP (or other pressure control equipment) . Fluid is stored under pressure in accumulators comprising rigid containers mounted on the BOP, and weights, springs or compressed gas provide an energy storage component. However, as the water depth in which the BOP is located increases, so does ambient pressure. Accordingly, accumulators utilising compressed gas or the like to store energy become increasingly inefficient with water depth, and the size and weight of an accumulator installation needed to store a given quantity of energy thereby increases significantly. Furthermore, heavy duty valves are required to control supply of fluid to the BOP, and these valves are large and heavy, adding to the weight of the BOP.

In addition, many types of downhole tools are fluid operated and therefore require a source of pressurised fluid for actuation of the tool. In this case, fluid is typically supplied from surface either via control lines coupled to the tool, or by control of fluid pressure in the wellbore using large pumps. Where the tools are operated through control lines, these may be many thousands of feet in length, leading to difficulties in running, recovering and controlling the tool. Where the tools are operated by control of wellbore pressure, significant energy is expended in raising the wellbore pressure to the required level simply to actuate the tool. Furthermore, the tools can be prematurely actuated should the pressure be accidentally raised above a threshold actuating level. Typical such downhole tools include downhole valves such as sub-surface safety valves (SSSVs) .

It is therefore amongst the objects of embodiments of the present invention to obviate or mitigate at least one of the foregoing disadvantages. It is also amongst the objects of embodiments of the present invention to provide a means of energy storage and hydraulic power delivery that is more efficient, smaller and lighter than traditional systems at the elevated pressures encountered underwater.

According to a first aspect of the present invention, there is provided an electrical power storage and pressurised fluid supply system for use in a εubsea environment in the actuation of fluid operated apparatus associated with a well, the system comprising: an electrical power storage unit; at least one electric motor coupled to and powered by the at least one electrical power storage unit; and at least one pump coupled to and driven by said electric motor, said pump adapted to supply fluid under pressure to the fluid operated apparatus for carrying out a function subsea.

The present invention thereby provides a system for supplying fluid to a fluid operated apparatus to carry out a desired function subsea, the fluid being supplied under pressure from a pump driven by a motor, the motor powered by an electrical power storage unit provided as part of the system, and thus which may be located in the subsea environment. Providing such a system permits many subsea functions to be carried out without requiring large pressure accumulators as is the case with prior systems known in the oil and gas exploration and production industry, and thus the system may be of smaller volume and lower weight than prior systems.

It will be understood that the system may be associated with a well in that the system may be coupled directly to the well, for example on a wellhead or other equipment provided subsea on the wellhead such as a BOP or tree; or may be provided at a remote location and coupled to the well via fluid flow lines or the like, depending upon the function to be performed.

The system may be for use in the actuation of subsea pressure/fluid control equipment, and in particular may be for actuating an at least one fluid operated element of the pressure control equipment. In embodiments of the invention, the system may be for use in the actuation of pressure control equipment such as a blowout preventer (BOP) , or a shutoff assembly of a type disclosed in WO2006/ 010906 to one of the current inventors, the disclosure of which is incorporated herein by way of reference. The system may be for use in actuating an at least one hydraulic ram of the pressure control equipment, which ram may be a shear, seal, blind and/or shear and seal ram. The well function to be carried out may therefore be a flow control function which may involve a sealing or shearing action.

In other embodiments of the invention, the system may be for use in the actuation of pressure control equipment such as a subsea tree. The system may be for use in actuating an at least valve of the tree, to thereby control the flow of fluid from and/or to the tree and thus from and/or to the well. The system may comprise at least one accumulator and said pump may be coupled to said accumulator for supplying pressurised fluid to the accumulator. It will be understood that subsea trees typically include valves which are failsafe closed by mechanical springs or the like, and require to be held open by applied fluid pressure. In the event of a loss of applied pressure, the valves therefore failsafe close. Accumulators used to hold the valve or valves open may therefore be topped up, and thus maintained at an operating pressure sufficient to hold the valve open, by the system.

Alternatively, the system may be for use in the actuation of a fluid operated apparatus at least part of which is locatable downhole, which may be pressure/fluid control equipment. It will therefore be understood that the system may be located subsea, such as at or near seabed level, and may serve for controlling part or parts of a tool fluid operated apparatus located downhole. The system may be for actuating an at least one fluid operated element of pressure control equipment locatable or located downhole. In embodiments of the invention, the system may be for use in the actuation of pressure control equipment comprising a valve such as a subsurface safety valve (SSSV) . The system may be for use in actuating an at least one valve element of the pressure control equipment. The well function to be carried out may therefore be a flow control function which may involve a downhole sealing action. Alternatively, the system may be adapted for use in the actuation of a downhole tool such as a packer, perforation tool, plug, lock or other fluid operated tool. In a similar fashion to subsea trees described above, the downhole tool may be operated through an at least one accumulator of the system, and the accumulator used to hold the valve or valve elements open may therefore be topped up, and thus maintained at an operating pressure sufficient to hold the valve element open, by the system.

The present invention may thereby provide a system for supplying fluid to a downhole fluid operated apparatus, to carry out a desired function downhole. Providing such a system permits many downhole functions to be carried out without requiring supply of fluid along control lines extending to surface or manipulation of wellbore pressure to carry out the downhole function, and thus offers advantages over prior systems.

In a further alternative, the system may be for use in the actuation of subsea production control equipment, for controlling the flow of fluid to and/or from the well and which may take the form of or comprise a subsea production manifold, pump and/or valve assembly. In particular, the system may be for actuating an at least one fluid operated element of the subsea production control equipment, such as a valve. The well function to be carried out may therefore be a flow control function which may involve controlling the flow of fluids from the well. Again, the equipment may operate through one or more accumulator of the system.

The electrical power storage unit may comprise at least one battery, and preferably comprises a plurality of batteries optionally connected in series. Said battery may be rechargeable and the system may comprise a charging interface, which may facilitate charging in-situ in the subsea environment. The electrical power storage unit may comprise a plurality of sub-units or pods, each sub-unit comprising an at least one battery.

The at least one pump may be adapted to be coupled in a closed loop to the fluid operated apparatus. The system may comprise a plurality of pumps, which may be coupled in series but which are typically coupled in parallel. This may provide a degree of redundancy in the system, to provide a back-up in the event of failure of a particular pump .

Preferably, the system comprises at least one control unit for controlling operation of said electric motor and thus operation of the system. The/each control unit may be coupled between the/a respective electrical power storage unit and the at least one motor, to thereby control the supply of electrical power from the respective unit to the/each motor and thus to control motor operation. Where the system comprises a plurality of pumps coupled in parallel, the system may comprise three pumps, and each pump may comprise a respective control unit. The control units may be adapted to be coupled to and controlled from surface via a common controller, and may be configured to compare received activation signals and to activate their corresponding pumps only in the event that at least two of the control units recognise an activation signal. This may assist in preventing a spurious signal from activating the system.

According to a second aspect of the present invention, there is provided fluid operated apparatus for carrying out a function subsea, the apparatus adapted to be located in a subsea environment and to be associated with a well, the apparatus comprising: at least one fluid actuated element; and an electrical power storage and pressurised fluid supply system comprising: an electrical power storage unit; at least one electric motor coupled to and powered by the at least one electrical power storage unit; and at least one pump coupled to and driven by said electric motor, said pump adapted to supply fluid under pressure to said fluid actuated element to actuate the element and thereby carry out a function subsea.

The apparatus may be subsea pressure/fluid control equipment, and may be a BOP, or a shutoff assembly of a type disclosed in WO2006/010906. The at least one fluid actuated element may be a hydraulic ram which ram may be a shear, seal, blind and/or shear and seal ram. Alternatively, the equipment may be a subsea tree and the at least one fluid actuated element may be a valve of the tree.

In a further alternative, the apparatus may be pressure/fluid control equipment at least part of which is locatable downhole. The equipment may take the form of a downhole tool adapted to be located downhole, or may comprise such a downhole tool, with part of the equipment adapted to be located subsea outwith a wellbore of the well. In particular, the system or parts thereof may be adapted to be located at or on a wellhead of the well, and the equipment may comprise a tree carrying the system or part(s) thereof, said part or parts fluidly coupled to a downhole tool. The downhole tool may be a valve such as a subsurface safety valve (SSSV) , and the at least one fluid operated element may be an at least one valve element. Alternatively, the downhole tool may be a packer, a perforation tool, a plug, a lock or other fluid operated tool.

In an alternative, the apparatus may be subsea production control equipment for controlling the flow of fluid to and/or from the well, and which may comprise one or more of a subsea production manifold, a pump and/or a valve assembly. The fluid operated element of the subsea production control equipment may be an at least one valve.

Further features of the fluid operated apparatus of the second aspect of the present invention are defined above in relation to the first aspect of the invention.

According to a third aspect of the present invention, there is provided a method of carrying out a well function subsea, the method comprising the steps of: locating a fluid operated apparatus in a subsea environment, the apparatus having a fluid actuated element and an electrical power storage and pressurised fluid supply system; associating the apparatus with a well; selectively activating the fluid actuated element of the apparatus to carry out a well function subsea by activating an at least one electric motor of the system to drive an at least one pump of the system coupled to said motor and thereby supply fluid under pressure to the fluid actuated element, said electric motor being powered by an electrical power storage unit of the system.

The method may be a method of controlling fluid flow from a well and the step of locating a fluid operated apparatus in the subsea environment may comprise locating pressure control equipment in the subsea environment. The step of selectively activating the fluid actuated element may comprise selectively actuating an at least one hydraulic ram of the pressure control equipment to seal an annulus around an at least one tubing extending through the pressure control equipment into the well and/or to sever the tubing. In embodiments of the invention, the method may comprise locating pressure control equipment in the form of a BOP in the subsea environment, which may be located on a wellhead of the well, or a shutoff assembly of a type disclosed in W02006/010906. In other embodiments of the invention, the method may comprise locating pressure control equipment in the form of a subsea tree in the subsea environment.

Alternatively, the step of locating apparatus in the subsea environment may comprise locating subsea production control equipment in the subsea environment, and may comprise locating a subsea production manifold, pump and/or valve assembly in the subsea environment, optionally in the seabed remote from the well. The step of selectively activating the fluid actuated element may comprise selectively activating an at least one valve of the subsea production equipment to thereby control flow of fluid from the well.

In a further alternative, the step of locating apparatus in the subsea environment may comprise locating a tool downhole, and the step of selectively actuating the fluid actuating element may comprise actuating at least one valve of the downhole tool, or an at least one sealing element of the tool, to control the flow of fluid from the well. Alternatively, the step of selectively actuating the fluid actuated element may comprise actuating a perforating element of the tool, or a locking element of the tool.

According to a fourth aspect of the present invention, there is provided a method of carrying out a well function subsea, the method comprising the steps of: locating a fluid operated apparatus in a subsea environment ; coupling the apparatus to a well; providing the apparatus with a fluid actuated element for carrying out a well function and an electrical power storage and pressurised fluid supply system; coupling an electrical power storage unit of the system to an at least one electric motor of the system; coupling an at least one fluid pump of the system to said electric motor; selectively activating the fluid actuated element of the apparatus to carry out a well function subsea by activating said electric motor to drive said pump and thereby supply fluid under pressure to the fluid actuated element .

In a further aspect of the present invention, there is provided a method of storing electrical power and supplying fluid under pressure to a fluid operated apparatus associated with a well, the method comprising the steps of any one of the methods defined in the third or fourth aspects of the present invention.

Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

Fig. 1 is a perspective, schematic view of an electrical power storage and pressurised fluid supply system in accordance with an embodiment of the present invention;

Fig. 2 is a detailed side view of the system shown in Fig. 1;

Fig. 3 is a schematic, partial longitudinal sectional view of apparatus for carrying out a function subsea in accordance with an embodiment of the present invention;

Fig. 4 is a diagrammatic view of part of an electrical power storage and pressurised fluid supply system of the apparatus shown in Fig. 3 ;

Fig. 5 is a schematic illustration of apparatus for carrying out a function subsea in accordance with an alternative embodiment of the present invention; Fig. 6 is a view of the apparatus of Fig. 5 showing an electrical power storage and pressurised fluid supply system of the Fig. 5 apparatus coupled to a downhole tool in the form of an SSSV; and

Fig. 7 is a schematic perspective view of apparatus for carrying out a function subsea in accordance with a further alternative embodiment of the present invention.

Turning firstly to Fig. 1, there is shown a perspective, schematic view of an electrical power storage and pressurised fluid supply system in accordance with an embodiment of the present invention, the system indicated generally by reference numeral 10 and the Figure illustrating the basic components of the system. The system 10 includes an electrical power storage unit 12 which includes a number of rechargeable batteries 14 connected in series and contained within a waterproof housing 16. The system 10 also includes at least one electric motor 18 coupled to and powered by the electrical power storage unit 12, and at least one pump 20 coupled to and driven by the motor 18. The pump 20 serves for supplying fluid under pressure to a fluid operated apparatus, for carrying out a desired function.

The system 10 has a utility in subsea environments in the actuation of fluid operated apparatus associated with a well, for carrying out a function subsea. In addition however, the system 10 has a utility in the actuation of downhole fluid operated apparatus, for carrying out a function downhole. Typical subsea and downhole functions, and corresponding apparatus and methods, will be described in more detail below. The system 10 and its method of operation will now be described in more detail, with reference also to the detailed side view of Fig. 2. The system 10 further comprises a control unit 22 which is electrically coupled to the power unit 12 via cables 24, 26 and to the motor 18 via cables 28 and 30. The motor 18 is thus selectively activated by the control unit 22 according to control signals supplied to the unit 22. To this end, the control unit 22 may be provided with electrical or hydraulic control lines (not shown) extending to surface. Preferably however, the unit 22 includes a receiver for receiving electromagnetic (for example, radio or acoustic frequency) signals transmitted from surface. In this fashion, the motor can be selectively activated from surface by transmission of an appropriate control signal.

The pump 20 is connected to the fluid operated apparatus to be actuated (not shown in Fig. 1) in a closed loop, via supply and return flow conduits 32 and 34. Fluid is supplied to the apparatus via the supply conduit 32 and returned via return conduit 34, to facilitate actuation of a fluid actuated element of the apparatus. On selective activation of the motor 18, under the control of the control unit 22, the motor rotates an impeller (not shown) of the pump 20 to supply pressurised fluid to the fluid operated apparatus through the supply conduit 32, thereby actuating the apparatus for carrying out the desired function.

The system 10 in fact comprises two D. C. motors 18, 18' each coupled to respective pumps 20, 20' which are connected in parallel to supply pressurised fluid to the apparatus in question. The motors 18, 18' are each powered by the electrical power unit 12, and the unit 12, motors 18, 18' and pumps 20, 20' are all provided within a waterproof housing 35 of a control pod 36. Typically and as will be described in more detail below, the system 10 will comprise a number of such control pods 36, to provide a degree of redundancy in the operation of the system.

The fluid conduits 32 and 34 are coupled to the apparatus for supplying pressurised fluid via hydraulic interface connectors 38, and electrical and fibre-optic interface connectors 40, 42 are also provided for connection to a stab plate (not shown) on the apparatus in question, which facilitate removal of the pod 36 for servicing. To this end, the pod 36 includes a handling pin 44 by which the pod can be retrieved to surface. In addition, the system 10 comprises a compensator cylinder 46 in which a compensator piston (not shown) is mounted, which accounts for differences in supplied and returned fluid volumes.

The system 10 also includes a contactor and switch gear (not shown) which permits selective connection of the motors 18, 18' to the batteries 14 via one of two channels. A first channel, connected through the cables 24 and 26, provides for 'normal' operation of the apparatus coupled to the system. A second channel, connected through the contactor, provides for 'emergency' operation, when a large current is required to be drawn from the batteries 14, such as would be necessary in a tubing shearing operation, where the system 10 is to be used for actuating shear rams of a BOP, which will be shown and described below. The system 10 offers numerous advantages over prior systems known in the oil and gas exploration and production industry. In particular and as will be described below, the system may be provided as part of apparatus taking the form of pressure control equipment such as a BOP or well shutoff assembly of the type disclosed in WO2006/010906 to one of the current inventors, the disclosure of which is incorporated herein by way of reference. In such situations, the system facilitates a flow control function to be carried out by the appropriate supply of fluid to a fluid operated element of the flow control equipment, without requiring large accumulators and/or associated valves.

Turning now to Fig. 3, there is shown a schematic, partial longitudinal sectional view of apparatus for carrying out a function subsea in accordance with an embodiment of the present invention, the apparatus indicated generally by reference numeral 48. In the illustrated embodiment, the apparatus 48 takes the form of a subsea BOP having fluid actuated elements comprising a pair of hydraulic seal rams 50 and a pair of hydraulic shear rams 52. The BOP 48 is located on a tree 54 on a subsea wellhead 56 of an oil/gas well 58, which has been lined with concentric steel casings 60, 62 and 64 that have been cemented in place, in a known fashion. Production tubing 66 is shown extending from surface through a riser 76 and down through the BOP 48 into the casing section 64, which extends deepest into the well to a region adjacent a producing formation. Oil and/or gas is recovered to surface through the production tubing 66. In the event of a loss of control of well fluids, it may be necessary to actuate the seal rams 50, to urge piston heads 68 of the rams into sealing abutment with an outer surface 70 of the production tubing 66. Actuating the seal rams 50 in this way closes an annulus 72 formed between the outer surface 70 of the production tubing 66 and the casing section 64 (and which annulus extends up through a bore 74 of the BOP 48 and a riser 76) . Accordingly, the seal rams 50 then close flow up the annulus 72. In the event of a more serious loss of control of well fluids as may occur, for example, during drilling when an unexpectedly high pressure formation is encountered, it is necessary to also actuate the shear rams 52 , which shear and sever any tubing extending through the BOP 48 into the well 58, thereby shutting-in the well.

The BOP 48 includes an electrical power storage and pressurised fluid supply system in accordance with an alternative embodiment of the present invention, the system indicated generally by reference numeral 10a. Like components of the system 10a with the system 10 of Figs. 1 and 2 share the same reference numerals with the addition of the suffix ^xa'. The system 10a serves for selectively controlling actuation of the seal and shear rams 50, 52 and thus operation of the BOP 48. The system 10a comprises three control pods 36a coupled together in parallel and mounted on a stab plate 78 of the BOP 48, which is illustrated schematically in the Figure. The arrangement of the control pods 36a and their coupling to the seal and shear rams 50, 52 is illustrated in more detail in the diagrammatic view of Fig. 4. In use and when it is desired to actuate the seal rams 50 or shear rams 52, a control signal is sent from surface. in the embodiment of Figs. 3 and 4, an electromagnetic signal is sent via an appropriate transmitter (not shown) , the signal received by acoustic transducers 80 in each pod 36a. The control units 22 of each pod 36a are connected via cables 82, 84 and 86, to ensure correct operation of the pods .

The use of three pods 36a offers increased operability and reliability, as all three pods 36a process the same input data and generate the same outputs. Also, the pods 36a are connected together in such a way as to provide hardware voting logic on their output signals . This voting logic ensures that at least two pods 36a must agree in their output state for that output to be energised. Use of this architecture ensures that state contention is avoided, and provides increased system availability and integrity. In the event of a failure of one pod 36a, the system 10a automatically reconfigures itself to a duty/standby dual architecture. Additionally, a further pod 36a failure would still allow operation of the system 10a with a single pod.

Accordingly, following receipt of a correct activation signal, the control units 22 of the pods 36a activate the respective pod motors 18a, 18 'a which in turn activate the corresponding pumps 20a, 20 'a to supply pressurised fluid to one or both of the seal and shear rams 50, 52. Supply of fluid to the selected rams 50, 52 is governed by appropriate valves 88 and 90 on the supply and return conduits 32a, 34a for the pumps 20a; and corresponding valves 88', 90' on the supply and return conduits 32 'a, 34 'a for the pumps 20 'a. The operation of the valves 88, 90 and 88', 90' is controlled by the pod control units 22a. Following actuation of one or both of the seal and shear rams 50, 52, communication may be reopened by sending an appropriate control signal to the pod transducers 80. It will be appreciated that such reopening would follow appropriate remedial action to stabilise the well 58.

One further situation in which it may be necessary to shear the production tubing 66 is in the event of a requirement to perform an emergency disconnect, such as may occur if a rig from which the riser 76 and tubing 66 is suspended requires to urgently move off-station. The BOP 48 shear and seal rams 50, 52 would be operated as described above to shut-in the well, and a lower riser package (LRP) comprising the riser 76 then released from the BOP 48. The BOP 48 and system 10a remain subsea following disconnection of the riser 76. The rig may then move off-station.

Turning now to Fig. 5, there is shown a schematic illustration of apparatus for carrying out a function subsea in accordance with an alternative embodiment of the present invention, the apparatus indicated generally by reference numeral 48b. Like components of the apparatus 48b with the apparatus 48 of Figs. 3 and 4 share the same reference numeral with the addition of the suffix ^λb' or with the suffix ^λa' replaced by the suffix λb' .

The apparatus 48b takes the form of a subsea tree located on a subsea wellhead 56b. In a known fashion, the tree 48b includes a number of inlets/outlets 92, 94, 96, 98, 100 and 102 each having a respective valve 93, 95, 97, 99, 101 and 103. The valves 93 - 103 are each failsafe closed by springs or the like (not shown) , and are actuated open by applied fluid pressure. The tree 48b also includes an electrical power storage and pressurised fluid supply system indicated generally by reference numeral 10b. The system 10b is coupled to each of the tree valves 93 - 103 via appropriate control lines. However, for ease of illustration, the system 10b is shown coupled only to the outlet 92 valve 93. Typically the system 10b will include a manifold with appropriate valves for coupling the control pods 36b of the system 10b to a selected one or ones of the outlets 92 - 102. In this fashion, pressurised fluid may be selectively supplied to the valves 93 - 103 in the respective outlets to thereby actuate the valves and allow flow of fluid from or to the tree 48b.

In the illustrated embodiment, tubing 66b carrying a SSSV 104 has been located in a well 58b which has been lined with a steel casing 60b that has been cemented in place, in a conventional fashion. The tubing 66b is suspended from the casing 60b by a tubing hanger 106 and extends through the tree 48b to surface. As is known in the art, the tree 48b controls flow of fluid from and to the well. In the illustrated embodiment, the tree is shown with all outlets 92 - 102 failsafe closed. When it is desired to open flow from the well 58b through the tubing 66b, a control signal is sent from surface to actuate the system 10b, in the fashion described above in relation to the system 10a. Pressurised fluid is then supplied to the valve in the outlet 92, actuating the valve 93 to open flow through the outlet into a discharge conduit 108 which either extends to surface or to a subsea manifold (not shown) of subsea production equipment. As with the system 10a, the system 10b can be actuated to close the valve in the outlet 92 by sending an appropriate control signal from surface to reduce or shutoff applied fluid pressure to the valve 93, which then failsafe closes. Accordingly, by appropriate control of the valves in the manifold, fluid flow to/from the tree via one or more of the remaining outlets 94 - 102 can be achieved.

In a variation of the system 10b, which is a preferred version of the system 10b, hydraulic/gas accumulators of a type which will be shown and described below are provided between the pumps 20, 20' of the system 10b and the valves 93 - 103. The pumps 20, 20' act to maintain fluid pressure in the accumulators at or above a pressure required to maintain the valves failsafe open, and thus at a level sufficiently high to overcome the spring force of the failsafe springs.

Turning now to Fig. 6, the subsea tree 48b of Fig. 5 is shown with the system 10b coupled to the SSSV 104, for controlling actuation of the SSSV located downhole in the well 58b. Each control pod 36b is connected to a suitably sized hydraulic/gas accumulator 110 which in turn is manifolded to a hydraulic control line 112 leading to the SSSV 104.

Currently, SSSVs are normally maintained in an open position by application of constant hydraulic pressure through a control line extending to surface. This allows flow through the SSSV from the oil/gas reservoir to surface. However, in the event pressure through the control line is lost, the SSSV will close to secure the well. Accordingly, should hydraulic pressure inadvertently be lost, the SSSV automatically closes.

In contrast, with the system 10b coupled to and controlling the SSSV 104, the SSSV can be re-pressurised from the control pods 36b to reopen the valve. In the event of a serious leak, the control pods 36b are isolated by check valves 114. The accumulators 110 can optionally be built into the pods 36b, thereby facilitating retrieval of the pods and accumulators to surface for servicing. To close the SSSV 104, accumulator 110 pressure is simply vented. Whilst the system 10b has been described as providing an override function to override inadvertent closing of the SSSV 104, it will be understood that full operation of the SSSV 104 can be controlled by the system 10b, dispensing with a need for a control line extending to surface from the SSSV 104.

Furthermore, whilst the system 10b has been shown in Fig. 6 controlling the operation of an SSSV 104, it will be understood that the system may be employed in controlling operation of other fluid operated downhole tools such as packers, plugs, perforation tools and downhole locks. Furthermore, the system may be built into the downhole tool and thus run into the well.

Turning now to Fig. 7, there is shown a schematic perspective view of apparatus for carrying out a function subsea in accordance with an alternative embodiment of the present invention, the apparatus indicated generally by reference numeral 48c. Like components of the apparatus 48c with the apparatus 48 of Figs. 3 and 4 share the same reference numeral with the addition of the suffix ^λc' or with the suffix ^xa' replaced by the suffix *c' .

The apparatus 48c takes the form of a subsea production manifold located on a seabed 115 and coupled to four separate producing wells 116 - 122. The manifold serves for controlling flow to surface from the wells 116 - 122 via a number of flowlines 124, in a fashion known in the art. The manifold 48c includes an electrical power storage and pressurised fluid supply system indicated generally by reference numeral 10c, and which is of like construction and operation to the system 10a of Figs. 3 and 4. The system 10c serves for controlling valves (not shown) in the manifold 48c to in turn control the flow of fluid from one or more of the wells 116 - 122. The valves typically operate in a similar fashion to the valves 93 - 103 on the tree 48b described and shown in Figs. 5 and 6, and are thus typically failsafe closed and opened by fluid supplied from pods 36c of the system 10c. As with the tree 48b, the system 10c may include suitable accumulators (not shown) .

There follows a discussion of preliminary observations and experiments conducted by the inventors, which should not be taken as limiting on the scope of the claimed invention.

Hydraulic accumulators are a well known technology commonly used for the provision of stored energy for subsea systems. The major drawback with accumulators is that they lose efficiency as energy storage devices as ambient pressure increases. Assuming that typical rams with the following dimensions will be used: Piston Diameter = 362 mm; Rod Diameter = 112 mm; Stroke = 225 mm; the hydraulic swept volume to close is 23.3 L. Assuming that ram boosters with the following dimensions will be used: Piston Diameter = 362 mm; Rod Diameter = 112 mm; Stroke = 50 mm; the hydraulic swept volume to close is 4.65 L.

Each function (i.e., blind and shear) has two pairs of rams. Additionally, the shear rams also have one pair of boosters. The regulatory requirement API Spec 16D requires that the hydraulic control system for a subsea Blowout Preventer (BOP) stack shall have a minimum total stored hydraulic fluid volume, with the pumps inoperative, to satisfy several operating conditions. In order to satisfy the requirements, the total hydraulic volume needed is 251 L or 5 bottles (55 L) . Assuming that the rams will require a force to shear equivalent to that generated by a pair of standard 375 mm (14-3/4 in) , then actuators fitted with equal area tandem booster cylinders, operated at 207 Bars (3,000 psi) , at full system depth of 3000 m, the total gas volume required is 1982 L or 36 bottles (55 L) . Therefore, the system requires a total number of 41 bottles with a total weight of 10.5 t.

Please note that gas volumes are based upon using Helium as the fill gas. It should also be noted that gas back up bottles are based upon the standard 55 L size. Weights are based upon accumulator cylinders with a working pressure of 690 bar (255 kg for a 55 L bottle) . Although the maximum working pressure (gauge) of the accumulators will only be 350 bar on the seabed, this will enable full gas pre-charge to be applied at the surface. If lower working pressure bottles are used they will have to be topped up with high pressure gas on the seabed.

Savings in accumulator size and weight could be gained by relaxing the assumptions for required storage volume and/or load pressure characteristics. Different types of accumulator arrangement may be implemented. Assuming the use of a single bank of accumulators connected into the system supply header, the system pressure starts at some value greater than the design pressure and is arranged to finish at the design pressure, and thereby retain the mechanical performance of the actuator throughout its range. In this case additional pressure regulation at the accumulator output is needed to avoid overstressing the actuator. Experiments have shown that it is clear that for the assumptions made for the load characteristics, the load and supply are poorly matched.

Efficiency of this type of arrangement can be improved by splitting the accumulator bank into one or more sections where each section is allowed to depressurise to a point that is more appropriate to the load characteristic. It should be noted though that splitting the accumulator bank introduces an additional level of complexity in the form of an extra control valve for each bank of accumulators, so that the correct pressure can be manifolded into the high pressure header at the right stage of the actuation process. These extra valves have to be operated by the control system in the correct order and in response to measurement of flow, actuator position or system pressure, in order to ensure that sufficient fluid is available.

In contrast and considering the single bank of accumulators discussed above, the total energy used to compress back up gas on the surface is 1080 MJ; the total energy available in the fluid on the surface is 14.1 MJ; the energy available in the fluid at 3000 m is 6.6 MJ; and the energy required for the assumed ram operations with 50% spare capacity is 3.7 MJ. It can be clearly seen that the energy efficiency of this method is approximately one third of one percent .

Storing electrical energy in batteries overcomes many of the inefficiencies associated with accumulators, not least of which are independence of ambient pressure and much better load matching capability. A single 12V, 162 kC (45 A-hr) rated battery, as used in a many cars contains 1.9MJ of electrical energy. For the present application, a DC motor running at a nominal voltage of 72 V with an average shaft output over the actuator closing cycles of 23 kW has been considered. To achieve the required voltage, six standard 12 V batteries would be connected in series, and the average running current would be approximately 375 A. Considering the energy required it would appear that batteries with capacity of only 54 kC (15 A-hr) would be sufficient. There are, however, a number of factors that act to decrease available capacity and suitability such as: Low temperatures reduce the amount of energy that can be drawn from the battery. At 0° C the available capacity can be expected to be reduced by 20%; High current rates reduce the amount of energy that can be drawn from the battery. At the current rates specified and for the type of battery considered available capacity can be expected to be reduced by 80%; Small batteries cannot supply high current without damage to the internals. To cope with starting current for this motor current capacity in excess of IOOOA will be required.

Taking the combination above, the required battery capacity will have to be greater than 338 kC (94 A-hr) . The specification for a typical 360 kC (100 A-hr) battery capable of providing "cold cranking current" over 1000 A is commercially readily available. Each of these batteries weigh 34 kg, and therefore, a bank of six would weigh 204kg. Adding in estimated weights for the pump and motor and an oil filled box to hold them all, the total estimated weight for the energy storage system is approximately 500 kg, which is less than the weight of two high pressure accumulators.

Subsea Control Module (SCM) - after careful analysis of the cost and performance criteria of potential configurations, the use of a Triple Modular Redundancy (TMR) SCM system was recommended for the shutoff system disclosed in International Patent Publication No.WO2006/010906 to one of the current inventors. This is achievable due to the reduced number of functions required to be operated by the emergency release system, and will offer significant improvement in reliability and availability when compared to conventional dual SCM architectures. The use of three SCM allows a number of configurations to be implemented that offer increased operability and reliability when compared to dual and single SCM systems. The most effective of these architectures is known as TMR, and is where all three SCM process the same input data and generate the same outputs, but are connected together in such a way as to provide hardware voting logic on their output signals. This voting logic ensures that at least two SCMs must agree in their output state for that output to be energized.

Use of this architecture ensures that state contention is avoided, and provides increased system availability and integrity. For these reasons, TMR architectures are widely used in industries and technologies where ultimate system reliability and availability is needed. In the event of a failure of one SCM, the system automatically reconfigures itself to a duty/standby dual architecture. A further SCM failure would still allow operation of the system with a single control module.

The three emergency release SCM that are required to provide the TMR functionality are all identical. They are identified as POD A, B and C. Each SCM comprises an oil-filled pressure compensated painted steel enclosure, inside which there is a pressure compensated lead-acid gel type battery system, two electrically driven hydraulic pumps (one for each BOP ram pair) , two high- power oil-filled contactors (one for each HPU) and a single one atmosphere subsea electronics module. On the top of the SCM housing there is a running-tool mandrel to allow the SCM to be retrieved using a crane whip-line with assistance from the ROV. An integral compensation oil bladder provides equalisation of the compensation oil pressure inside the SCM housing.

Acoustic telemetry is provided by an integral acoustic modem system whose transducer is mounted on the top of the SCM. Outrigger arms may be deployed, depending on the water depth to provide a clearer acoustic "view" upwards to the host vessel. On the underside of the base of the SCM there is an array of hydraulic and electrical couplers. These provide connections between the Geo-SOS hydraulic systems and the SCM, and allow the inter- connection of signals between the three SCM, the support ROV and the non-critical "Class 2" utility SCM.

In addition to the three TMR configured emergency release SCM, there is a fourth "simplex" SCM - the utility SCM. This fourth SCM is permanently installed on the Geo-SOS and is local to the ROV landing stage. It performs three main functions: 1) Operation of certain hydraulic functions on the Geo-SOS when the ROV is not docked on but is in the vicinity of the Geo-SOS; 2) Provide instrumentation feedback from all Geo-SOS instruments and sensors, either with the ROV docked on to the system or with the ROV local to the Geo-SOS; 3) Provide a telemetry and power conduit for communication with all the emergency release SCM to allow status monitoring, system testing and battery recharge.

A detailed fluid system analysis for the system disclosed in WO2006/010906 concluded that the hydraulic system should be closed-loop, using a conventional mineral hydraulic fluid system. This will allow the use of "standard" hydraulic components with well-documented reliability data and performance criteria.

A prototype was developed using a hired Scan Tech 800T Hydraulic Shear cutter to simulate the cutting demands of a BOP shear rams. Batteries were used to store the required energy. When energised, contactors connected the battery terminals to a DC motor which was used to drive a hydraulic pump. The output from the pump was directly connected to the 800T cutter actuator which closed as fluid was delivered and cut a pipe sample held within the jaws of the cutter. Energy for the cutting process was provided by three separate banks of military specification batteries, each providing the motive power for one motor-pump set. Each battery bank had a capacity of 346 kC (96 A-hr) and operated at a nominal 72 V, with a maximum cold cranking capacity of more than 2000 A. Each battery bank was isolated from its motor-pump set by means of high current contactors, whose coil side was energised from a separate low voltage (24 V) supply. The contactors were energised by means of relays and switches sited in the operator's control box. The control box enabled the operator to select which of the motors were to be used during a specific test and had a single switch to run or stop whichever of the motors were selected.

The three pumps were constant horsepower controlled, with a maximum set pressure of 200 bar. They outputted into a common header via a non return valve on each pump outlet. The common header contained a system relief valve and high pressure filter. Quick connect hoses attached the circuit to the cutter for pressure supply and return to the tank. The return side of the circuit contained a low pressure filter for pump protection. The motor-pump equipment was positioned in a safe location directly behind the cutter. Output from pressure and other sensors were fed to a data logger and computer located in a safe location.

Results - several tests were carried out and some representative results are presented here.

Shear Test 1 consisted of the attempt to shear 194 mm (7- 5/8 in) 44.2 kg/m (29.7 lbm/ft) L80 casing only, without liner pipe present. At 0 seconds the motor was turned on and the pump delivered a pressure of 40 bar to close the cutting jaws. The jaws were not yet in contact with the pipe. At 22 seconds the cutting jaws contacted the pipe and the current drawn from the batteries increased to supply a higher pressure which overcome the resistance and deformed the pipe. The slower rate of extension of the driving cylinder corresponded to the deformation of the pipe. At 62 seconds the jaws have completely crushed the pipe. A first pressure spike is seen which corresponds to the drop in resistance felt by the cutting jaws as the top half of the pipe is sheared. The pressure built again until the cutting jaws sheared the bottom half of the pipe. Thereafter, the pressure dropped since there was no resistance being felt. The total time to complete test was 62 seconds, the total time needed to shear the pipe after contact was made was 40 seconds and the pressure required to shear the pipe was 143 bar (2,074 psi) .

A further Shear Test 4 consisted of the attempt to shear 194 mm (7-5/8 in) 44.2 kg/m (29.7 lbm/ft) L80 casing with 76 mm (3 in) liner pipe inside to represent coiled tubing. At 0 seconds the motor was turned on and the pump delivered a pressure of 40 bar to close the cutting jaws. The jaws were not yet in contact with the pipe. At 28 seconds the cutting jaws contacted the pipe and the current drawn from the batteries increased to supply a higher pressure which overcome the resistance and deformed the pipe. The slower rate of extension of the driving cylinder corresponded to the deformation of the pipe. At 68 seconds the jaws have completely crushed the pipe. A first large drop in pressure occurred which corresponded to the drop in resistance felt by the jaws as the top half of the pipe is sheared. A second large drop in pressure occurred which corresponded to the coil tubing being sheared. The pressure built again until the jaws shear the bottom half of the pipe, which corresponds to a third large drop in pressure. The total time to complete test was 68 seconds, the total time needed to shear the pipe after contact was made was 40 seconds and the pressure required to shear the pipe was 140 bar (2, 030 psi) .

It should also be noted that one battery set successfully completed six shearing tests without recharging. Three tests with casing pipe only and three tests with casing pipe and liner pipe inside.

Conclusions - it is well known that hydraulic accumulators lose efficiency as water depth increases and for the proposed application at depth of 3000 m such a system would require 41 bottles with a total weight of 10.5 t. The new proposed system consists of three ROV replaceable control pods, organised as TMR SCM, containing control electronics, batteries for energy storage, communications and power links, and a motor/pump unit for supplying hydraulic fluid to each function. The total weight for the new system is approximately 500 kg. Additionally, the energy storage is much increased; the system preserves operability with one pod down; there are no hydraulic control valves in the system; and there are far fewer points in the system that are susceptible to single point or common mode failures. All the tests carried out with the prototype clearly demonstrate the capability of the Electro-Hydraulic system to shear 194 mm (7-5/8 in) casing with 76 mm (3 in) liner pipe.

Various modifications may be made to the foregoing without departing from the spirit and scope of the present invention.

Part or parts of the system may be adapted to be provided downhole. For example, the motor and pump may be adapted to be provided downhole, coupled to the power storage unit (provided, for example, at seabed level) via wires or cables. However, it is preferred that the power storage unit, motor and pump are provided together to facilitate removal of the system for maintenance and/or replacement.

Claims

1. An electrical power storage and pressurised fluid supply system for use in a subsea environment in the actuation of fluid operated apparatus associated with a well, the system comprising: an electrical power storage unit; at least one electric motor coupled to and powered by the at least one electrical power storage unit; and at least one pump coupled to and driven by said electric motor, said pump adapted to supply fluid under pressure to the fluid operated apparatus for carrying out a function subsea.

2. A system as claimed in claim 1, wherein the system is adapted to be coupled directly to the well.

3. A system as claimed in claim 1, wherein the system is adapted to be provided at a remote location and coupled to the well via fluid flow lines.

4. A system as claimed in any preceding claim, wherein the electrical power storage unit comprises at least one battery.

5. A system as claimed in claim 4, wherein the electrical power storage unit comprises a plurality of batteries connected in series.

6. A system as claimed in either of claims 4 or 5, wherein the or each battery is rechargeable and the system comprises a charging interface.

7. A system as claimed in any preceding claim, wherein the electrical power storage unit comprises a plurality of sub-units, each sub-unit comprising an at least one battery.

8. A system as claimed in any preceding claim, wherein the at least one pump is adapted to be coupled in a closed loop to the fluid operated apparatus.

9. A system as claimed in any preceding claim, comprise a plurality of pumps coupled in parallel.

10. A system as claimed in any preceding claim, comprising at least one control unit for controlling operation of said electric motor and thus operation of the system.

11. A system as claimed in claim 10, wherein the at least one control unit is coupled between the electrical power storage unit and the at least one motor, to thereby control the supply of electrical power from the unit to the motor and thus to control motor operation.

12. A system as claimed in either of claims 10 or 11, wherein the system comprises a plurality of pumps coupled in parallel, and a respective control unit for each pump.

13. A system as claimed in claim 12, wherein the system comprises three pumps and a corresponding control unit for each of the pumps, and wherein the control units are adapted to be coupled to and controlled from surface via a common controller, and configured to compare received activation signals and to activate their corresponding pumps only in the event that at least two of the control units recognise an activation signal.

14. Fluid operated apparatus for carrying out a function subsea, the apparatus adapted to be located in a subsea environment and to be associated with a well, the apparatus comprising: at least one fluid actuated element; and an electrical power storage and pressurised fluid supply system comprising: an electrical power storage unit; at least one electric motor coupled to and powered by the at least one electrical power storage unit; and at least one pump coupled to and driven by said electric motor, said pump adapted to supply fluid under pressure to said fluid actuated element to actuate the element and thereby carry out a function subsea.

15. Apparatus as claimed in claim 14, comprising subsea pressure control equipment which equipment comprises the at least one fluid actuated element.

16. Apparatus as claimed in claim 15, wherein the pressure control equipment is a BOP.

17. Apparatus as claimed in claim 15, wherein the pressure control equipment is a shutoff assembly.

18. Apparatus as claimed in either of claims 16 or 17, wherein the fluid actuated element is an at least one hydraulic ram of the pressure control equipment.

19. Apparatus as claimed in any one of claims 14 to 18, wherein the function to be carried is a flow control function which involves a sealing and/or shearing action.

20. Apparatus as claimed in claim 15, wherein the pressure control equipment is a subsea tree.

21. Apparatus as claimed in claim 20, wherein the fluid actuated element is an at least valve of the tree, for controlling the flow of fluid from and/or to the tree and thus from and/or to the well.

22. Apparatus as claimed in any one of claims 14 to 21, wherein the system comprises at least one accumulator and said pump is coupled to said accumulator for supplying pressurised fluid to the accumulator.

23. Apparatus as claimed in claim 22, wherein said accumulator serves for holding an at least one fluid actuated element in the form of a valve open, and wherein the at least one pump is adapted to maintain accumulator pressure above an operating pressure sufficient to hold the valve open.

24 . Apparatus as claimed in claim 14 , wherein at least part the apparatus is locatable downhole .

25. Apparatus as claimed in claim 24, wherein the fluid actuated element is adapted to be located downhole and forms part of pressure control equipment.

26. Apparatus as claimed in either of claims 24 or 25, wherein the system is adapted to be located subsea at seabed level and serves for controlling the part of the apparatus located downhole .

27. Apparatus as claimed in either of claims 25 or 26, comprising an SSSV, and wherein the system is for use in actuating a fluid actuated element of the SSSV in the form of an at least one valve element of the SSSV.

28. Apparatus as claimed in any one of claims 24 to 27, wherein the function to be carried out is a flow control function involving a downhole sealing action.

29. Apparatus as claimed in claim 24, comprising a downhole tool selected from the group comprising a packer, a perforation tool, a plug and a lock.

30. Apparatus as claimed in claim 29, comprising at least one accumulator, said pump being coupled to said accumulator for supplying pressurised fluid to the accumulator, and wherein said accumulator serves for holding an at least one fluid actuated element of the downhole tool in a desired position.

31. Apparatus as claimed in claim 14, comprising subsea production control equipment which equipment comprises the at least one fluid actuated element, for controlling the flow of fluid to and/or from the well .

32. Apparatus as claimed in claim 31, wherein the equipment takes the form of a subsea production manifold.

33. Apparatus as claimed in claim 33, wherein the equipment comprises one or more of a pump and an at least one valve assembly.

34. Apparatus as claimed in either of claims 32 or 33, wherein the well function to be carried out is a flow control function involving controlling the flow of fluids from the well.

35. A method of carrying out a well function subsea, the method comprising the steps of: locating a fluid operated apparatus in a subsea environment, the apparatus having a fluid actuated element and an electrical power storage and pressurised fluid supply system; associating the apparatus with a well; selectively activating the fluid actuated element of the apparatus to carry out a well function subsea by activating an at least one electric motor of the system to drive an at least one pump of the system coupled to said motor and thereby supply fluid under pressure to the fluid actuated element, said electric motor being powered by an electrical power storage unit of the system.

36. A method as claimed in claim 35, wherein the method is a method of controlling fluid flow from a well and wherein the step of locating a fluid operated apparatus in the subsea environment comprises locating pressure control equipment in the subsea environment .

37. A method as claimed in claim 36, wherein the step of selectively activating the fluid actuated element comprises selectively actuating an at least one hydraulic ram of the pressure control equipment to seal an annulus around an at least one tubing extending through the pressure control equipment into the well .

38. A method as claimed in claim 36 or 37, wherein the step of selectively activating the fluid actuated element comprises selectively actuating an at least one hydraulic ram of the pressure control equipment to sever an at least one tubing extending through the pressure control equipment into the well.

39. A method as claimed in any one of claims 35 to 38, wherein the step of locating fluid operated apparatus in the subsea environment comprises locating pressure control equipment in the form of a BOP in the subsea environment.

40. A method as claimed in any one of claims 35 to 38, wherein the step of locating fluid operated apparatus in the subsea environment comprises locating pressure control equipment in the form of a shutoff assembly in the subsea environment.

41. A method as claimed in any one of claims 35 to 38, wherein the step of locating fluid operated apparatus in the subsea environment comprises locating pressure control equipment in the form of a subsea tree in the subsea environment .

42. A method as claimed in any one of claims 39 to 41, comprising locating the pressure control equipment on a wellhead of the well.

43. A method as claimed in any one of claims 35 to 38, wherein the step of locating fluid operated apparatus in the subsea environment comprises locating subsea production control equipment comprising a subsea production manifold subsea.

44. A method as claimed in claim 43, comprising locating the equipment on the seabed remote from the well.

45. A method as claimed in either of claims 43 or 44, wherein the step of selectively activating the fluid actuated element comprises selectively actuating an at least one valve of the subsea production equipment to thereby control flow of fluid from the well.

46. A method as claimed in any one of claims 35 to 45, wherein the step of locating apparatus in the subsea environment comprises locating a tool downhole.

47. A method as claimed in claim 46, wherein the step of selectively actuating the fluid actuated element comprises activating at least one valve of the downhole tool, to control the flow of fluid from the well.

48. A method as claimed in claim 46, wherein the step of selectively activating the fluid actuated element comprises actuating an at least one sealing element of the tool, to control the flow of fluid from the well.

49. A method as claimed in claim 46, wherein the step of selectively activating the fluid actuated element comprises actuating a perforating element or a locking element of the tool.

50. A method of carrying out a well function subsea, the method comprising the steps of: locating a fluid operated apparatus in a subsea environment; coupling the apparatus to a well; providing the apparatus with a fluid actuated element for carrying out a well function and an electrical power storage and pressurised fluid supply system; coupling an electrical power storage unit of the system to an at least one electric motor of the system; coupling an at least one fluid pump of the system to said electric motor; selectively activating the fluid actuated element of the apparatus to carry out a well function subsea by activating said electric motor to drive said pump and thereby supply fluid under pressure to the fluid actuated element.