Patent Application
20180195362
The present invention relates to production apparatus and to related well production methods and systems. More particularly, but not exclusively, the invention relates to production methods and systems for use on subsea wells.
Offshore production assemblies typically comprise a number of components including, but not limited to:
a well extending below the seabed to a hydrocarbons reservoir; and
a wellhead typically located at an upper portion of the well and/or near the seabed and providing structural and/or sealing functionality with respect to one or more production components such as casing, liners, tubing, etc.
The control of fluids, in particular in production wells where produced hydrocarbons flow from the well, and in injection wells where a fluid or a gas is injected into the well, is generally achieved by the provision of a production tree or so-called “Christmas tree”. The production tree is typically located on the seabed on top of a subsea well extending into the seabed, and in such instance is termed a subsea production tree. The production tree is typically connected to and/or placed on the wellhead or on a tubing head spool supporting a tubing hanger.
The production tree also constitutes a barrier between the well and the downstream environment. The production tree may comprise a single bore or a dual bore and is typically equipped with well control barriers to maintain adequate sealing integrity and reliability. A typical configuration of such a subsea tree entails dual valves vertically stacked between a horizontal tubular that transmits the flow of fluids or gases from or into the subsea well and an isolation valve mounted below the subsea tree connector for well intervention operations.
However, such typical valves assemblies used in subsea production trees for well fluid and pressure containment and isolation have limited capability to provide the shearing/cutting and sealing functionality to provide sufficient safety to personnel, oil installations and environment during production and intervention operations required in case of emergency.
Under current practice, well control during intervention operations is performed by a Completion Work-Over Riser (CWOR) system.
A CWOR system provides a conduit from a surface vessel to a subsea well for communication of fluids and well intervention tools and services that can be conveyed on slickline, eline, coil tubing or jointed tubulars. CWOR systems typically contain a Lower Riser Package (LRP) that includes the safety devices that seal the well bore and permit disconnection of the CWOR system from the subsea production tree in event of an emergency situation, essentially replicating the functions of a blowout preventer (BOP) stack as used during well drilling and completion operations.
The Lower Riser Package (LRP) of the CWOR system, in either single or dual bore configurations, comprises:
The current practice for subsea systems is to ensure that all of the pressure retaining elements of the subsea system are capable of operating with the maximum expected full shut-in wellhead conditions generated by the reservoir pressure and temperature. As reservoir pressures and temperatures increase and the full shut-in pressure at the wellhead rises beyond the capability of conventional well control and pressure retaining equipment, costs to develop and manufacture new equipment increase significantly the system costs for both the production and workover intervention systems.
In particular, there is a desire in the industry to design downhole systems and assembly capable of operating at very high pressure, for example in excess of 15 kpsi, e.g., up to 20 kpsi. As a consequence, all equipment exposed to high pressure must be rated to the maximum expected pressure. As subsea well pressures increase beyond 15 kpsi, the cost of pressure rating subsea equipment to full shut in wellhead pressure renders some oil and gas reserves un-economic to develop.
It is an object of the present invention to eliminate or mitigate one or more of the disadvantages associated with the prior art.
According to a first aspect of the present invention there is provided a production apparatus configured to be connected to an emergency disconnect package (EDP), the production apparatus comprising:
a housing defining a wellbore;
a first wellbore valve member for closing the wellbore, the first wellbore valve member provided within the housing, the first wellbore valve member being capable, in use, of shearing an object located in the wellbore; and
a second wellbore valve member for closing the wellbore, the second wellbore valve member provided within the housing, the second wellbore valve member being capable, in use, of shearing an object located in the wellbore.
The production apparatus may be and/or may be termed a “Christmas tree”.
The production apparatus may be located subsea, e.g., at or near and upper end of a subsea well.
The provision of a production apparatus, e.g. subsea tree, with wellbore valve members having shearing and sealing functionality, and being directly connectable to the EDP, obviates the need for a lower riser package (LRP) which would normally provide the required emergency shearing/cutting and sealing functionalities. This permits reduction in weight, cost and complexity of the overall assembly, e.g. CWOR. As such, the apparatus may define and/or may function as a combined or integrated production and intervention apparatus.
In one embodiment, the production apparatus may be connectable to and/or may be placed on top of a wellhead. The production apparatus may comprise a wellhead connector for connecting to the wellhead.
In another embodiment, the production apparatus may be connectable to and/or may be placed on top of a tubing head spool. The production apparatus may comprise a tubing head spool connector for connecting to the tubing head spool.
In an open configuration, the first wellbore valve member and the second wellbore valve member allow flow of fluid, e.g., hydrocarbons, through the wellbore.
In a closed configuration, the first wellbore valve member and the second wellbore valve member prevent flow of fluid, e.g. hydrocarbons, through the wellbore.
Preferably, the first wellbore valve member and the second wellbore valve member may be rated to the maximum expected full shut-in wellbore conditions, e.g. maximum expected wellbore pressure. By such provision, closure of one or both of the first wellbore valve member and the second wellbore valve member protects the equipment above and/or downstream of the first wellbore valve member and/or second wellbore valve member. The first wellbore valve member and the second wellbore valve member may be rated up to about 15 kpsi, preferably up to about 20 kpsi.
In one embodiment, the first wellbore valve member may be provided within and/or may define a first wellbore valve. The second wellbore valve member may be provided within and/or may define a second wellbore valve.
In another embodiment, the production apparatus may comprise a wellbore valve comprising the first wellbore valve member and the second wellbore valve member. In such instance, the first wellbore valve member and the second wellbore valve may form part of and/or may be provided within the wellbore valve. The first wellbore valve member may be or may comprise a first gate. The second wellbore valve member may be or may comprise a second gate.
The first wellbore valve member, e.g. first gate, and the second wellbore valve member, e.g. second gate, may be located within a wellbore valve housing.
The first gate and/or the second gate may be moveable in a direction transverse to the wellbore between a wellbore open position and a wellbore closed position. Advantageously, the first gate and the second gate may be moveable in different directions transverse, e.g. substantially perpendicular, to the wellbore between a wellbore open position and a wellbore closed position.
The wellbore valve may further comprise a first seal seat for forming a seal with the first gate in the wellbore closed position to seal the wellbore.
The wellbore valve may further comprise a second seal seat for forming a seal with the second gate in the wellbore closed position to seal the wellbore.
In one embodiment, the first gate and the second gate may be capable, in use, of shearing an object, e.g. a tubular, located between the first and second gates, e.g. located within the wellbore.
The first wellbore valve member and/or the second wellbore valve member may be capable, in use, of shearing an object, e.g., a tubular, located in the wellbore.
The first wellbore valve member, second wellbore valve member, first gate, and/or second gate may comprise a shearing end or shearing face capable of shearing an object, e.g., a tubular, located in the wellbore. It will be understood that shearing an object, e.g. a tubular, located in the wellbore, may be required in workover mode, e.g., during intervention operations, when an object such as a tubular is or has been inserted in the wellbore to perform a given intervention task. However, during normal production operations, a tubular would typically not be present in the wellbore, and closure of the first wellbore valve member, second wellbore valve member, first gate, and/or second gate would therefore not cause shearing of such a tubular.
In one embodiment, the wellbore valve may be a valve as described in International Patent Application Publication No. WO 2008/035091 (Edwards), which is incorporated herein by reference in its entirety, for example as valve as marketed by Enovate Systems Ltd under the trade name En-Tegrity. In such instance, the first wellbore valve member may comprise a first gate having a shearing face and a sealing portion or surface, and the second wellbore valve member may comprise a second gate having a shearing face and a sealing portion or surface. The wellbore valve may comprise a first seal seat for forming a seal with the first gate in the wellbore closed position to seal the wellbore. The gates may be axially moveable with respect to the wellbore, permitting the gates to move into a sealing engagement with one of the seal seats under the action of an external force, such as an applied pressure.
Advantageously, the first wellbore valve member and the second wellbore valve member are actuatable and/or operable independently of each other.
The first wellbore valve member may be coupled to and/or associated with a first actuator.
The second wellbore valve member may be coupled to and/or associated with a second actuator.
The first actuator and the second actuator may be operable independently of each other.
In normal operating conditions, the first actuator and/or the second actuator may be activated and/or may be operable by a user. The first actuator and/or the second actuator may be operable hydraulically, electrically, or the like.
In an emergency situation, for example following detection of pressure over a predetermined threshold, the first actuator and/or the second actuator may be activated automatically.
The first actuator and/or the second actuator may be automatically activated by reception of a command signal, e.g., of an electrical signal. The first actuator and/or the second actuator may be automatically activated through loss of a command signal, e.g., of an electrical signal.
Automatic activation and/or operation of the first actuator and/or of the second actuator may automatically cause a respective first valve member or second valve member to move to a closed position.
Preferably, the first actuator and the second actuator may be operable automatically and independently of each other. By such provision, two or more independent failsafe barriers may be provided within the production apparatus, e.g., Christmas tree. This ensures compliance with the provision of two independent failsafe barriers, as required by API Standards. This obviates the need for equipment located downstream of the production apparatus to be rated to the maximum expected pressure. This also obviates the need for a separate LRP to be provided between the EDP and the production apparatus to ensure well isolation in case of an emergency during intervention operations.
In use, while the present production apparatus meets the API Standards requirement for two independent failsafe barriers, closure of either of the first wellbore valve member or the second wellbore valve member may prevent flow of fluid, e.g., hydrocarbons, through the wellbore.
In an embodiment, automatic activation of the first actuator and/or second actuator may mechanically operate the first actuator and/or second actuator, for example by releasing a torsion spring.
The first actuator may comprise two separate actuation mechanisms, e.g., a first actuation mechanism and a second actuation mechanism.
The second actuator may comprise two separate actuation mechanisms, e.g., a first actuation mechanism and a second actuation mechanism.
Advantageously, each of the first actuator and the second actuator may comprise two separate actuation mechanisms.
The first actuation mechanism of the first actuator and the first actuation mechanism of the second actuator may be the same or different.
The second actuation mechanism of the first actuator and the second actuation mechanism of the second actuator may be the same or different.
In an embodiment, the first actuation mechanism may comprise an electric actuation mechanism. In another embodiment, the first actuation mechanism may comprise a hydraulic actuation mechanism.
The second actuation mechanism may comprise a mechanical actuation mechanism, e.g. a spring. In an embodiment, the second actuation mechanism may be activated upon loss of an activating means to the first actuation mechanism, e.g. upon loss of electrical supply to electric actuation mechanism, or upon loss of hydraulic supply to the hydraulic actuation mechanism.
By such provision, the first and/or second actuator, advantageously each of the first and second actuators, may be provided with two separate actuation mechanisms which may help ensure actuation of the first and/or second actuator in an emergency, even in the event of a loss of power and/or hydraulic supply to the first actuation mechanism.
In an embodiment, the first actuator and/or the second actuator may comprise an actuator as described in US Patent Application Publication No. US 2012/0234117 A (Oswald), which is incorporated herein by reference in its entirety. In such instance, the actuator may comprise an electric drive containing both an electric drive mechanism and control electronics used to open and close an associated valve gate under electric power as well as compressing a spring in a spring chamber. During initialisation of the actuator the spring may be compressed and mechanically latched in position by latch. Following initialisation the electric drive may be used to open and close valves in normal operation using non-fail safe control methods while the spring may remain compressed. A latch release mechanism consisting of a hammer held by a continuously powered solenoid may be released on loss of power to the solenoid, e.g., in an emergency situation. The latch release may dis-engage the mechanical latch and may release the spring to operate the actuator and close the valve gate.
In another embodiment, automatic activation of the first actuator and/or second actuator may hydraulically operate the first actuator and/or second actuator.
Hydraulic actuation may be accomplished by the release of a fluid at high pressure to a pressure chamber of the first actuator and/or second actuator, e.g., to move a piston of the first actuator and/or of the second actuator thereby forcing a respective first valve member and/or second valve member to its closed position.
Hydraulic actuation may be accomplished by the influx of a fluid at high pressure generated by a subsea pump to a pressure chamber of the first actuator and/or second actuator, e.g., to move a piston of the first actuator and/or of the second actuator thereby forcing a respective first valve member and/or second valve member to its closed position.
The production apparatus may further comprise a gripping mechanism configured for gripping and/or catching an object, e.g., a tubular, within the wellbore. It will be understood that gripping and/or catching an object, e.g., a tubular, located in the wellbore, may be required in workover mode, e.g. during intervention operations, when an object such as a tubular is or has been inserted in the wellbore to perform a given intervention task, and closure of the first wellbore valve member and/or the second wellbore valve member causes shearing of the tubular. However, during normal production operations, a tubular would typically not be present in the wellbore, and actuation of a/the gripping mechanism would therefore not be necessary.
The gripping mechanism may be moveable between a retracted, non-engaged configuration and a deployed, engaged configuration. When in said engaged configuration, the gripping mechanism may apply a gripping force to the object, e.g., tubular.
The gripping mechanism may be located below the first wellbore valve member and the second wellbore valve member. By such provision, upon actuation of the first wellbore valve member and/or the second wellbore valve member, causing the object, e.g., the tubular to be severed, the gripping mechanism may prevent the severed object from falling down the wellbore.
In the engaged configuration, the gripping mechanism may be adapted to center the object, e.g., tubular within the wellbore.
The gripping mechanism may comprise a plurality of gripping elements.
The gripping elements may be spaced apart from one another. Conveniently, the gripping elements may be circumferentially disposed relative to the wellbore.
In one embodiment, one or more gripping elements, e.g. each gripping element, may be adapted to rotate or pivot around its own rotation axis from the retracted configuration to the deployed configuration. In use, upon deployment, one or more gripping elements, e.g., each gripping element, e.g., a gripping portion thereof, may pivot or rotate towards a central portion of the wellbore and/or towards the object.
In another embodiment, one or more gripping elements, e.g., each gripping element, may be adapted to move radially transverse to the wellbore axis from the retracted configuration to the deployed configuration. In use, upon deployment, one or more gripping elements, e.g., each gripping element, e.g., a gripping portion thereof, may move radially transverse to the wellbore axis towards a central portion of the wellbore and/or towards the object.
In one embodiment, one or more gripping elements are locked in the deployed configuration by the weight of the object.
In another embodiment, one or more gripping elements are locked in the deployed configuration, e.g., by a locking mechanism such as a mechanical locking mechanism.
In one embodiment, the gripping mechanism may comprise a gripping mechanism as described in International Patent Application Publication No. WO 2011/039512 (Edwards et al.), which is incorporated herein by reference in its entirety.
The gripping mechanism may be actuated by an emergency event, e.g., by detection of pressure over a predetermined threshold. The gripping mechanism, e.g., deployment thereof from a retracted configuration to a deployed configuration, may be actuated via a command signal, e.g. an electrical signal.
The gripping mechanism may comprise at least one gripping mechanism actuator capable of causing deployment of one or more gripping elements. The at least one gripping mechanism actuator may be coupled to and/or associated with one or more gripping elements.
The gripping mechanism actuator may be automatically operable and/or activated. Automatic activation of the gripping mechanism actuator may be similar to the automatic activation described above in respect of the first actuator and/or second actuator, and is therefore not repeated here for reasons of brevity.
The production apparatus is connectable to an emergency disconnect package (EDP). The production apparatus may comprise an EDP connector for connecting to the EDP. Advantageously, connecting the EDP to the production apparatus, e.g. subsea tree, obviates the need for a lower riser package (LRP) which would normally provide the required emergency shearing/cutting and sealing functionalities. This permits reduction in weight, cost and complexity of the overall assembly, e.g. CWOR.
The production apparatus may be connectable to the EDP at or near an upper portion thereof. The EDP connector may be provided at or near an upper portion of the production apparatus.
In one embodiment, the CWOR assembly, e.g., EDP and/or riser, may comprise a single bore. The assembly may comprise a bore selector, e.g. provided within the EDP, for selective access to the wellbore or to an annulus bore in the production apparatus, e.g. for intervention operations in the subsea well.
In another embodiment, the CWOR assembly, e.g., EDP and/or riser, may comprise a single bore for access to a single wellbore in the production apparatus, e.g. for intervention operations in the subsea well.
In another embodiment, the CWOR assembly, e.g., EDP and/or riser, may comprise a two or more bores, e.g., a dual bore system, one bore being configured for access to an annulus bore, and one bore being configured for access to the wellbore in the production apparatus, e.g. for intervention operations in the subsea well.
In one embodiment, actuation of the first wellbore valve member and/or of the second wellbore valve member may cause the EDP to disconnect from the production apparatus.
In another embodiment, disconnection of the EDP from the production apparatus may be actuated by an emergency event, e.g. by detection of pressure over a predetermined threshold. Disconnection of the EDP from the production apparatus may be actuated by a command signal, e.g., an electrical signal.
The CWOR assembly, e.g. the EDP and/or the production apparatus, may comprise a disconnect actuator capable of causing disconnection between the EDP and the production apparatus, e.g. capable of causing disconnection of the EDP connector.
The disconnect actuator may be automatically operable and/or activated. Automatic activation of the disconnect actuator may be similar to the automatic activation described above in respect of the first actuator and/or second actuator, and is therefore not repeated here for reasons of brevity.
The production apparatus may further comprise an intervention isolation device.
The intervention isolation device may comprise a valve, e.g., a gate valve, flapper valve, ball valve, or the like.
The intervention isolation device may be axially spaced from the first wellbore valve member, second wellbore valve member, and/or wellbore valve, relative to the wellbore.
The intervention isolation device may be located above the first wellbore valve member, second wellbore valve member, and/or wellbore valve. The terms “above” and “up” will not be understood to refer to any geometric arrangement, but will be understood to refer to a location distal or away from the wellhead and/or reservoir, whereas terms “below” and “down” will be understood to refer to a location proximal to or nearer the wellhead and/or reservoir.
The intervention isolation device may be provided at or near an upper portion of the production apparatus.
Preferably, the intervention isolation device may be rated to the maximum expected full shut-in wellbore conditions, e.g., maximum expected wellbore pressure. By such provision, closure of the intervention isolation device may ensure protection of the equipment above the intervention isolation device.
Typically, the intervention isolation device may be closed during normal production operations, e.g., to produce hydrocarbons from the reservoir, e.g., via a production line which may be in fluid communication with the wellbore. The production line may be connected to the wellbore within the production apparatus, e.g., below the intervention isolation device.
Typically, the intervention isolation device may provide access to the well during intervention operations, e.g. to allow deployment of a wireline, coiled tubing, etc.
The intervention isolation device may be associated with a third actuator.
In normal operating conditions, the third actuator may be operable by a user.
The intervention isolation device and/or third actuator may be operated by a standard Remote Operating Vehicle (ROV).
The third actuator may be operable hydraulically, electrically, or the like.
In an emergency situation, for example following detection of pressure over a predetermined threshold, the third actuator may be activated automatically. Automatic activation of the third actuator may be similar to the automatic activation described above in respect of the first actuator and/or second actuator.
Preferably, the first actuator, second actuator, and third actuator may be operable automatically and independently of each other.
The intervention isolation device may comprise a mechanical plug having a locking profile in the wellbore. The mechanical plug may be retrieved prior to intervention operations and/or may be installed on completion of such operations by conventional well interventions methods such as slickline, wireline or coiled tubing.
The production apparatus may comprise and/or may be associated with a pressure control device capable of controlling and/or regulating pressure within a portion of the production apparatus and/or downstream of the production apparatus.
The pressure control device may comprise a choke, e.g. a subsea Christmas tree choke.
The pressure control device may comprise a production line configured for allowing flow of fluid to and/or from the wellbore, e.g., during production.
The production line may be in fluid communication with the wellbore. The production line may be connected to the wellbore within the production apparatus.
The production line may be connected to the wellbore at a location below the intervention isolation device. By such provision, when the intervention isolation device is closed, e.g., during normal production operations, the pressure control device may be capable of controlling and/or regulating pressure and/or flow of fluids flowing to and/or from the wellbore.
The production line may be connected to the wellbore at a location above the first wellbore valve member, second wellbore valve member, and/or wellbore valve. Because the first wellbore valve member and second wellbore valve member are actuatable independently of each other, e.g. automatically and independently of each other, connecting the production line to the wellbore at a location above the first wellbore valve member, second wellbore valve member, and/or wellbore valve, obviates the need for equipment located downstream of the pressure control device to be rated to the maximum expected pressure which may in turn reduce complexity of the production assembly and costs.
The production line may be connected to the wellbore at a location between the intervention isolation device and the first wellbore valve member, second wellbore valve member, and/or wellbore valve.
The pressure control device may comprise at least one pressure control valve rated to the maximum expected full shut-in wellbore conditions, e.g. maximum expected wellbore pressure. By such provision, closure of the pressure control valve may ensure protection of the down-rated equipment downstream of the pressure control device.
The production apparatus may comprise and/or may be associated with a control system for automatically controlling actuation and/or operation of the first wellbore valve member and/or of the second wellbore valve member.
The control system may be configured for automatically controlling actuation of the first wellbore valve member and the second wellbore valve member.
The control system may be configured for automatically operating the first actuator and/or the second actuator, preferably both the first actuator and the second actuator.
The control system may be further configured for automatically controlling actuation of the gripping mechanism. In use, actuation of the gripping mechanism may be required only during work-over mode, e.g., to catch any object entering the wellbore. In such instance, the control system may comprise and/or may be provided with a selective input allowing selective enablement and/or disablement of the activation of the gripping mechanism actuator.
In one embodiment, the control system may comprise and/or may be provided with a work-over mode. When in work-over mode, the gripping mechanism actuator may be activated and/or operated by the control system. When not in work-over mode, the gripping mechanism actuator may be not activated and/or operated. This may prevent unnecessary actuation of the gripping mechanism during production operation in event of an emergency.
In another embodiment, the control system may comprise and/or may be provided with a production mode. When in production mode, the gripping mechanism actuator may not be activated and/or operated by the control system. When not in production mode, the gripping mechanism actuator may be activated and/or operated. This may prevent unnecessary actuation of the gripping mechanism during production operation in event of an emergency.
The control system may comprise one or more sensors configured to monitor and/or measure one or more predetermined parameters, e.g. pressure, temperature, etc.
The one or more sensors may be located in the wellbore and/or one or more conduits associated with and/or in fluid communication with the wellbore.
Preferably, the control system may comprise a plurality of sensors.
In one embodiment, the control system may comprise three or more sensors.
Preferably, one or more sensors may be configured to monitor and/or measure pressure.
In one embodiment, the control system may comprise one or more control modules in communication with one or more sensors.
In another embodiment, the control system may comprise a control module in communication with the plurality of sensors.
In an embodiment, the control system may comprise a plurality of control modules, each control module being associated and/or being in communication with a respective actuator. Each of the first actuator, second actuator, third actuator, and/or gripping mechanism actuator may be associated and/or may be in communication with a respective control module. By such provision, each actuator may be independently activated, thereby improving safety and/or reliability.
In another embodiment, the control system may comprise a control module associated and/or being in communication with a plurality of actuators. The first actuator, second actuator, third actuator, and/or gripping mechanism actuator may be associated and/or may be in communication with the control module. By such provision, simplicity of the control system may be improved. Such an arrangement may also reduce the likelihood of an erroneous shut-in occurring as a result of a control module failure.
The one or more sensors may be located downstream of the pressure control device, first wellbore valve member and/or second wellbore valve member. By such provision, detection of pressure above a predetermined threshold by one or more sensors may cause the control module to actuate the first wellbore valve member and the second valve member.
In another embodiment, the one or more sensors may be located upstream of the pressure control device. In such instance, the one or more sensors may be located upstream of the first wellbore valve member and/or second wellbore valve member, e.g. below the production apparatus. Alternatively, the one or more sensors may be located above of the first wellbore valve member and/or second wellbore valve member, e.g. within or above the production apparatus.
The control module(s) may be capable of receiving signals from the sensors and of taking action upon analysis of the received signals. The/each control module(s) may comprise a logic solver.
In one embodiment, the control module(s), e.g. logic solver(s), may initiate an action, e.g. actuation of one of more actuators, when pressure above a predetermined threshold has been detected by a predetermined number and/or ratio of the sensors. The control module(s), e.g. logic solver(s), may initiate action, e.g. actuation of one or more actuators, when pressure above a predetermined threshold has been detected by a majority of sensors associated with the control module, e.g. logic solver.
By way of example, when there are three pressure sensors, the control module(s), e.g. logic solver(s), may initiate action, e.g. actuation of one or more actuators, when pressure above a predetermined threshold has been detected by at least two sensors. Similarly, when there are five pressure sensors, the control module(s), e.g. logic solver(s), may initiate action, e.g. actuation of one or more actuators, when pressure above a predetermined threshold has been detected by at least three sensors. By such provision, in the event that one (three sensor configuration) or two (five sensor configuration) of the sensors is faulty, accidental activation may be avoided and/or required activation may not be prevented.
A plurality of actuators, e.g. first actuator, second actuator, and/or gripping mechanism actuator, may be in communication with each other. By such provision, each actuator may notify one or more other actuators upon activation. This may ensure synchronisation of closure/activation and/or increased safety by ensuring all synchronised actuators are activated should the control module instruct activation of one of the synchronised actuators.
The control module may comprise and/or may define a so-called High Integrity Pressure Protection System (HIPPS).
According to a second aspect of the present invention there is provided a production apparatus, the production apparatus comprising:
a housing defining a wellbore;
a first wellbore valve member for closing the wellbore, the first wellbore valve member provided within the housing, the first wellbore valve member being coupled to a first actuator;
a second wellbore valve member for closing the wellbore, the second wellbore valve member provided within the housing, the second wellbore valve member being coupled to a second actuator,
wherein the first wellbore actuator and the second wellbore actuator each have at least two separate actuation mechanisms.
The first wellbore actuator and the second wellbore actuator may each have two separate actuation mechanisms.
The first wellbore actuator may comprise a first actuation mechanism and a second actuation mechanism.
The second wellbore actuator may comprise a first actuation mechanism and a second actuation mechanism.
The first actuation mechanism of the first wellbore actuator and the first actuation mechanism of the second wellbore actuator may be the same or different.
The second actuation mechanism of the first wellbore actuator and the second actuation mechanism of the second wellbore actuator may be the same or different.
In an embodiment, the first actuation mechanism may comprise an electric actuation mechanism. In another embodiment, the first actuation mechanism may comprise a hydraulic actuation mechanism.
The second actuation mechanism may comprise a mechanical actuation mechanism, e.g. a spring. In an embodiment, the second actuation mechanism may be activated upon loss of an activating means to the first actuation mechanism, e.g. upon loss of electrical power to the electric actuation mechanism, or upon loss of hydraulic supply to the hydraulic actuation mechanism.
By such provision, the first and/or second actuator, advantageously each of the first and second actuators, may be provided with two separate actuation mechanisms which may help ensure actuation of the first and/or second actuator in an emergency, even in the event of a loss of electrical power and/or hydraulic supply to the first actuation mechanism.
The production apparatus may comprise a control system for automatically controlling actuation and/or operation of the first wellbore valve member and/or of the second wellbore valve member.
The control system may automatically control actuation of the first wellbore valve member and the second wellbore valve member.
The control system may control actuation of the first wellbore valve member and the second wellbore valve member independently of each other.
The control system may comprise one or more control module in communication with one or more sensors. The control module may comprise and/or may define a High Integrity Pressure Protection System (HIPPS).
The features described in connection with the production apparatus according the first aspect of the invention may apply to the production apparatus according to the second aspect of the invention, and are therefore not repeated here for brevity.
According to a third aspect of the present invention there is provided a production apparatus, the production apparatus comprising:
a housing defining a wellbore;
a first wellbore valve member for closing the wellbore, the first wellbore valve member provided within the housing, the first wellbore valve member being capable, in use, of shearing an object located in the wellbore; and
a second wellbore valve member for closing the wellbore, the second wellbore valve member provided within the housing, the second wellbore valve member being capable, in use, of shearing an object located in the wellbore; and
a gripping mechanism disposed within the housing and configured for gripping and/or catching the object within the wellbore.
The gripping mechanism may be located below the first wellbore valve member and the second wellbore valve member. By such provision, upon actuation of the first wellbore valve member and/or the second wellbore valve member, causing the object, e.g. a tubular, to be severed, the gripping mechanism may prevent the severed object from falling down the wellbore.
It will be understood that gripping and/or catching an object, e.g., a tubular, located in the wellbore, may be required in workover mode, e.g. during intervention operations, when an object such as a tubular is or has been inserted in the wellbore to perform a given intervention task, and closure of the first wellbore valve member and/or the second wellbore valve member causes shearing of the tubular. However, during normal production operations, a tubular would typically not be present in the wellbore, and actuation of a/the gripping mechanism would therefore not be necessary.
The gripping mechanism may comprise a plurality of gripping elements, and at least one gripping mechanism actuator coupled to and/or associated with one or more gripping elements.
The features described in connection with the production apparatus according to the first aspect or the second aspect of the invention may apply to the production apparatus according to the third aspect of the invention, and are therefore not repeated for brevity.
According to a fourth aspect of the present invention there is provided a subsea assembly comprising a production apparatus according to any of the first, second, or third aspect of the invention.
The subsea assembly may define a Completion Work-Over Riser (CWOR) assembly.
The assembly may comprise an emergency disconnect package (EDP).
The assembly may comprise an EDP connector for connecting the EDP to the production apparatus. Advantageously, connecting the EDP directly to the production apparatus, e.g. subsea tree, obviates the need for a lower riser package (LRP) which would normally provide the required emergency shearing/cutting and sealing functionalities. This permits reduction in weight, cost and complexity of the overall assembly, e.g. CWOR.
The EDP connector may be provided on or may form part of the EDP.
The EDP connector may be provided on or may form part of the production apparatus.
The EDP connector may comprise two connector portions, a first connector portion being provided on or forming part of the production apparatus, and a second connector portion being provided on or forming part of the EDP.
The assembly may comprise a/the control system for automatically controlling actuation and/or operation of the first wellbore valve member and/or of the second wellbore valve member.
According to a fifth aspect of the present invention there is provided a method for closing a wellbore in a production apparatus, the method comprising:
providing a production apparatus configured to be connected to an emergency disconnect package (EDP), the production apparatus comprising a housing defining a wellbore; a first wellbore valve member for closing the wellbore, the first wellbore valve member provided within the housing, the first wellbore valve member being capable, in use, of shearing an object located in the wellbore; and a second wellbore valve member for closing the wellbore, the second wellbore valve member provided within the housing, the second wellbore valve member being capable, in use, of shearing an object located in the wellbore; and
actuating and/or operating the first wellbore valve member and the second wellbore valve member.
The method may comprise actuating and/or operating the first wellbore valve member and the second wellbore valve member independently of each other.
The method may comprise actuating and/or operating the first wellbore valve member and the second wellbore valve member automatically.
The method may comprise shearing an object, e.g. a tubular, located in the wellbore. It will be understood that shearing an object, e.g. a tubular, located in the wellbore, may be required in workover mode, e.g. during intervention operations, when an object such as a tubular is or has been inserted in the wellbore to perform a given intervention task. However, during normal production operations, a tubular would typically not be present in the wellbore, and the method would therefore not involve shearing such a tubular.
The method may comprise shearing the object during actuation and/or operation of the first wellbore valve member and/or of the second wellbore valve member.
The method may comprise catching the object, e.g., the tubular. The method may comprise catching the object within or inside the production apparatus.
The method may comprise catching the object, e.g. the tubular, below the first wellbore valve member and the second wellbore valve member. By such provision, upon actuation of the first wellbore valve member and/or the second wellbore valve member, causing the object, e.g. a tubular, to be severed, the gripping mechanism may prevent the severed object from falling down the wellbore.
The method may comprise automatically catching the object, e.g. the tubular. The method may comprise automatically controlling actuation of a/the gripping mechanism.
The method may comprise disconnecting the production apparatus from an emergency disconnect package (EDP) which may be directly connected to the production apparatus.
The method may comprise automatically controlling actuation and/or operation of the first wellbore valve member and/or of the second wellbore valve member, e.g. by using a control system.
The method may comprise monitoring and/or measuring one or more predetermined parameters, e.g. pressure, temperature, etc. The method may comprise monitoring and/or measuring one or more predetermined parameters in the wellbore and/or in one or more conduits associated with and/or in fluid communication with the wellbore.
Preferably, the method may comprise monitoring and/or measuring pressure in the wellbore and/or in one or more conduits associated with and/or in fluid communication with the wellbore.
The method may comprise monitoring and/or measuring pressure using a plurality of sensors.
The method may comprise monitoring and/or measuring pressure downstream of the first wellbore valve member and/or second wellbore valve member. By such provision, detection of pressure above a predetermined threshold by one or more sensors may cause the control module to actuate and/or operate the first wellbore valve member and the second valve member.
The method may comprise monitoring and/or measuring pressure upstream of the first wellbore valve member and/or second wellbore valve member, e.g. below or within the production apparatus.
The method may comprise processing signals and/or information received from one or more sensors using one or more control module in communication with one or more sensors.
The method may comprise actuating the first wellbore valve member, the second wellbore valve member, and/or the gripping mechanism, for example by activating or operating a/the first wellbore valve member actuator, a/the second wellbore valve member actuator, and/or the gripping mechanism actuator, when pressure above a predetermined threshold has been detected by one or more sensors, e.g. by a predetermined number and/or ratio of sensors.
Following closure of the wellbore, the method may comprise resuming production. The method for resuming production may be carried out when pressure measured and/or monitored by one or more sensors is within a predetermined limit.
The method for resuming production may comprise closing the/a pressure control device.
The method may comprise opening the first wellbore valve member, and/or second wellbore valve member actuator, preferably both the first wellbore valve member and the second wellbore valve member actuator.
In the event that the production apparatus comprises a gripping mechanism, and that the gripping mechanism has been activated, for example in workover mode, the method may comprise opening the gripping mechanism.
The method may comprise opening the pressure control device, for example until a new set-point is reached in a portion of the downstream equipment, e.g. within the predetermined limit.
Advantageously, following a safety event, e.g. emergency closure of the wellbore, the systems and methods of the present invention may allow the system to be rendered operational again for production quickly after such a safety event.
The features described in connection with the production apparatus according the first, second or third aspect of the invention or the assembly according to the fourth aspect of the invention may apply to the method according to the fifth aspect of the invention, and are therefore not repeated for brevity.
According to a sixth aspect of the present invention there is provided a method for resuming production following a safety event, the method comprising, in sequence:
closing the/a pressure control device;
opening a first wellbore valve member and a second wellbore valve member, the first wellbore valve member and the second wellbore valve member being configured for closing a wellbore and being capable, in use, of shearing an object located in the wellbore, the first wellbore valve member and the second wellbore being provided within a housing of a production apparatus connectable to an emergency disconnect package (EDP).
In the event that the production apparatus comprises a gripping mechanism, and that the gripping mechanism has been activated, for example in workover mode, the method may comprise deployment of a retrieval tool to secure the sheared object, opening the gripping mechanism and retrieving the sheared object.
The method may comprise opening the pressure control device, for example until a new set-point is reached in a portion of the downstream equipment, e.g. within the predetermined limit.
The features described in connection with the production apparatus according to the first, second or third aspect of the invention, with the assembly according to the fourth aspect of the invention, or with the method according to a fifth aspect of the invention may apply to the method according to the sixth aspect of the invention, and are therefore not repeated for brevity.
Embodiments of the invention will now be given by way of example only, and with reference to the accompanying drawings, which are:
Referring to
The assembly 5 comprises a wellhead 10, a production apparatus 20 in the form of a Christmas tree and connected on top of the wellhead 10 located on the seabed, a Lower Riser Package (LRP) 40, an emergency disconnect package (EDP) 35, and a riser 30.
The riser 30 has a pressure-containing tubular 31 that provides a pressure containment system from subsea to surface.
The emergency disconnect package (EDP) 35 is attached to the riser 30 and is connectable to a Lower Riser Package (LRP) 40. The emergency disconnect package (EDP) 35 is capable of disconnecting from the LRP 40 in the event of an emergency. The EDP 35 has a riser valve 32 to prevent discharge of fluids, e.g. hydrocarbons, from the riser 30 as a result of disconnection of the EDP 35.
The LRP 40 has two safety valves 41,42 capable of shearing and sealing the wellbore, essentially replicating the functions of a blowout preventer (BOP) stack as used during well drilling and completion operations. The LRP 40 also has a connecting portion 43 for connecting to the Christmas tree 20.
The Christmas tree 20 includes a lower master valve 21 and an upper master 22 to control the flow of fluids through the wellbore. The Christmas tree 20 also includes a wing valve 23 and a choke valve 24 to control, during production, pressure within the wellbore and flow of fluids from the wellbore to surface via a flow line 25.
Referring now to
The assembly 5′ has a main bore 51′ and an annulus bore 52′ in communication with the subsea well.
The assembly 5′ also includes a wellhead 10′, and a tubing hanger 11′. A subsea production apparatus 20′ in the form of a Christmas tree is connected to the wellhead 10′ via wellhead connector 26′.
The assembly 5′ includes an emergency disconnect package (EDP) 35′ attached to a lower end of a riser (not shown) and connected to a Lower Riser Package (LRP) 40′ and capable of disconnecting from the LRP 40′ in the event of an emergency. The EDP 35′ has a main riser valve 32′ to prevent discharge of fluids, e.g. hydrocarbons, from the main bore 51′ of the riser as a result of disconnection of the EDP 35′. The EDP 35′ includes an annulus riser valve 32a′ to prevent discharge of fluids, e.g. hydrocarbons, from the annulus bore 52′ of the riser as a result of disconnection of the EDP 35′.
The LRP 40′ includes safety valves 41′,42′ capable of shearing through and sealing the main bore 51′. The LRP 40′ also has safety valves 41a′,42a′ capable of shearing through and sealing the annulus bore 52′. Valves 41′,41a′ may be the same or different. Valves 42′,42a′ may be the same or different.
The LRP 40′ is connected to the Christmas tree 20′ via tree connector 43′.
The Christmas tree 20′ includes a lower master valve 21′ and an upper master 22′ to control the flow of fluids through the main bore 51′. The Christmas tree 20′ also has an annulus master valve 21a′ to control the flow of fluids through the annulus bore 52′.
The Christmas tree 20′ has an intervention isolation valve or swab valve 27′. The swab valve 27′ is provided near an upper end of the Christmas tree 20′. Typically, the swab valve 27′ is closed during normal production operations, and can be opened to provide access to the main bore 51′ during intervention operations, e.g. to allow deployment of a wireline, coiled tubing, etc.
The Christmas tree 20′ also includes an annulus intervention isolation valve 27a′ or annulus swab valve. The annulus swab valve 27a′ is provided near an upper end of the Christmas tree 20′. The annulus swab valve 27a′ is configured to provide access to the annulus bore 52′ during intervention operations.
The Christmas tree 20′ also has a wing valve 23′ and a choke valve 24′ to control, during production, pressure within the main bore 51′ and flow of fluid from the main bore 51′ to surface via a main flow line 25′.
The Christmas tree 20′ also has an annulus isolation valve 23a′ to control pressure within the annulus bore 52′ and flow of fluid between the annulus bore 51′ and surface via an annulus flow line 25a′.
Referring now to
In the embodiment of
The assembly 105 comprises a subsea production apparatus 120 in the form of a Christmas tree connected to a wellhead 110 via wellhead connector 126.
The assembly 105 includes an emergency disconnect package (EDP) 135 attached to a lower end of a riser (not shown).
The assembly EDP 135 is connected directly to the Christmas tree 120. The EDP 135 is capable of disconnecting from the Christmas tree 120 via disconnector 136 in the event of an emergency. The EDP 135 has a main riser valve 132 to prevent discharge of fluids, e.g. hydrocarbons, from the main bore 151 of the riser as a result of disconnection of the EDP 135. The EDP 135 also has an annulus riser valve 132a to prevent discharge of fluids, e.g. hydrocarbons, from the annulus bore 152 of the riser as a result of disconnection of the EDP 135.
The Christmas tree 120 has an annulus master valve 121a to control the flow of fluids through the annulus bore 152.
The Christmas tree 120 has a wellbore valve 160 having a first wellbore valve member 161 or first gate, and a second wellbore valve member 162 or second gate (as best shown in
In use, each of the first gate 161 and the second gate 162 has a shearing face and is capable of shearing an object, e.g. a tubular, located between the first 161 and second 162 gates within the main bore 151. For example, the wellbore valve 160 has a valve as marketed by Enovate Systems Ltd under the trade name En-Tegrity.
The first gate 161 and the second gate 162 are rated to the maximum expected full shut-in wellbore conditions, e.g. maximum expected wellbore pressure. By such provision, closure of one or both of the first gate 161 and the second gate 162 protects the equipment above and/or downstream of the wellbore valve 160.
In this embodiment, the first gate 161 and the second gate 162 are operable automatically and independently of each other. This ensures compliance with the provision of two independent failsafe barriers, as required by API Standards. This also obviates the need for a separate LRP to be provided between the EDP 135 and the Christmas tree 120 to ensure well isolation in case of an emergency. This also obviates the need for equipment located downstream of the production apparatus to be rated to the maximum expected pressure. This allows reduction in the size and weight of the subsea assembly, thus reducing manufacturing costs, whilst reducing the complexity of the CWOR assembly 105 and being more easily deployable from a wider range of vessels.
The Christmas tree 120 includes an intervention isolation valve 127. The intervention isolation valve 127 is provided near an upper end of the Christmas tree 120′. Typically, the intervention isolation valve 127 is closed during normal production operations, and is opened to provide access to the main bore 151 during intervention operations, e.g. to allow deployment of a wireline, coiled tubing, etc.
The Christmas tree 120 also has an annulus intervention isolation valve 127a. The annulus intervention isolation valve 127a is provided near an upper end of the Christmas tree 120. The annulus intervention isolation valve 127a provides access to the annulus bore 152 during intervention operations.
The Christmas tree 120 also has a wing valve 123 and a choke valve 124 to control, during production, pressure within the main bore 151 and flow of fluid from the main bore 151 to surface via a main flow line 125.
The Christmas tree 120 also has an annulus isolation valve 123a to control pressure within the annulus bore 152 and flow of fluid between the annulus bore 152 and surface via an annulus flow line 125a.
In the embodiment of
The EDP 235 also has a crossover line 238 equipped with a crossover valve 239. The crossover line is in fluid communication with main bore 251. The crossover line 238 is also in fluid communication with the annulus bore 252. The purpose of the crossover line is to allow communication between main bore 251 and annulus bore 252 to equalise pressure if and when required.
In the embodiment of
In the embodiment of
The gripping mechanism 465 is moveable between a retracted, non-engaged configuration (as shown in
The gripping mechanism 465 is located below the wellbore valve 460. By such provision, upon actuation of the wellbore valve 460, e.g. of the first gate 461 and/or of the second gate 462 (as best shown in
In the embodiment of
This ensures compliance with the provision of two independent failsafe barriers which will close the wellbore 551 automatically in the event of an emergency, as required by API Standards. This also obviates the need for a separate LRP to be provided between the EDP 535 and the Christmas tree 520 to ensure well isolation in such an event.
The control system 570 is configured for automatically operating a first actuator (not shown) connected to the first gate 561 and a second actuator (not shown) connected to the second gate 562. The actuators are described in more detail in connection with the embodiment of
In other embodiments, the control system 570 may be further configured to automatically control actuation of the gripping mechanism 565.
The control system has a control module 574 coupled to a plurality of pressure sensors 571,572,573 configured to monitor and/or measure pressure at a portion of the main flow line 525. In this embodiment, the sensors 571,572,573 are conveniently located downstream of the wellbore valve 560 and downstream of the choke valve 524, which may help ease of installation and/or maintenance.
In operation, detection of pressure above a predetermined threshold by one or more of the sensors 571,572,573 is fed to the module 574 which will then cause the control module 574 to actuate the first gate 561 and the second gate 562.
The control module 574 receives signals from the sensors 571,572,573 and takes action, e.g., initiates closure of the first gate 561 and the second gate 562, upon analysis of the received signals.
Typically, the control module 574 comprises one or more logic solvers. In this embodiment, the logic solver(s) of the control module 574 initiate closure of first gate 561 and second gate 562, e.g. activation of a first actuator and second actuator associated therewith, when pressure above a predetermined threshold has been measured by at least two out of the three sensors 571,572,573. By such provision, in the event that one of the sensors 571,572,573 is faulty, accidental activation is avoided in the event that one of the sensors 571,572,573 incorrectly detects high pressure under otherwise normal pressure conditions, and/or necessary activation is not prevented in the event that one of the sensors 571,572,573 does not detect an abnormally high pressure above the predetermined threshold.
The choke valve 524 is rated to the maximum expected full shut-in wellbore conditions, e.g. maximum expected wellbore pressure. By such provision, closure of the choke valve 524 ensures protection of the down-rated equipment downstream of the choke valve 524.
The intervention isolation valve 527 is also rated to the maximum expected full shut-in wellbore conditions, e.g., maximum expected wellbore pressure. By such provision, closure of the intervention isolation valve 527 ensures protection of the equipment above the intervention isolation valve 127.
By the arrangement depicted in
In the embodiment of
In this embodiment, each of the first, second, and third actuators 681,682,686 is associated with a respective control module including a logic solver 683,684,687 respectively. Each logic solver 683,684,687 receives signals 688 from sensors 671,672,673 and is capable of taking action, e.g. initiate actuation of closure of the first, second, and third actuators 681,682,686, upon analysis of the received signals 688.
In this embodiment, there is provided a workover mode input 689. If workover mode is activated, actuation of the gripping mechanism 665 is enabled. The logic solver 686 is enabled to activate third actuator 687 when pressure sensors 671,672,673 detect pressure above a predetermined threshold. However, if workover mode is not activated, actuation of the gripping mechanism 665 is disabled, i.e., logic solver 686 is not enabled to activate third actuator 687 when pressure is above a predetermined threshold. This ensures that, when not in workover mode, i.e. when no object such as a tubular is present in the wellbore 651, the gripping mechanism 665 is not unnecessarily actuated.
The assembly 605 also includes an isolation valve 691 and a production wing valve 623 to permit testing of the control system 670. When testing is desired, the first isolation valves 691 and the wing valve 623 are closed, thereby isolating a portion 693 of flow line 625 containing pressure sensors 671,672,673 between wing valve 623 and isolation valve. A service line valve 692 is also provided to control flow from service line 694 into portion 693. In order to create an over-pressure event, service line valve 692 is opened to inject a fluid and increase pressure within the section 693. Pressure is increased to a desired level, until pressure sensors 671,672,673 reach the predetermined threshold at which the logic solvers 683,684,687 activate actuators 681,682,686. By such provision, the efficacy of the failsafe system may be efficiently and quickly tested.
Following a safety event, production may be resumed quickly and efficiently using the assembly 605.
Once pressure measured by sensors 671,672,673 is below a predetermined threshold, production may be resumed by performing the following steps, in sequence:
The control system 770 has a control module 774 for automatically operating a first actuator 781 connected to a first gate 761 and a second actuator 782 connected to a second gate 762. The control module 774 receives signals 788 from pressure sensors 771,772,773.
In operation, detection of pressure above a predetermined threshold by one or more of the sensors 771,772,773 is fed to the module 774 which will then cause the control module 774 to actuate the first gate 761 and the second gate 762.
The control module 774 receives signals from the sensors 771,772,773 and takes action, e.g., initiates closure of the first gate 761 and the second gate 762, upon analysis of the received signals.
Typically, the control module 774 comprises one or more logic solvers. In this embodiment, the logic solver(s) of the control module 774 initiate closure of first gate 761 and second gate 762, i.e. activation of the first actuator 781 and second actuator 782 associated therewith, when pressure above a predetermined threshold has been measured by at least two out of the three sensors 771,772,773. By such provision, in the event that one of the sensors 771,772,773 is faulty, accidental activation is avoided in the event that one of the sensors 771,772,773 incorrectly detects high pressure under otherwise normal pressure conditions, and/or necessary activation is not prevented in the event that one of the sensors 771,772,773 does not detect an abnormally high pressure above the predetermined threshold.
The actuator 1001 comprises an electric drive 1003 containing both an electric drive mechanism and control electronics used to operate an actuator member 1002. The electric drive 1003 is configured to compress a spring 1005 in a spring chamber 1004. During initialisation of the actuator 1001, the spring 1005 is compressed and mechanically latched in position by latch 1006. Following initialisation the electric drive 1003 may be used to open and close valve gates (not shown) in normal using non-fail safe control methods while the spring 1005 may remain compressed. A latch release mechanism 1007 consisting of a hammer held by a continuously powered solenoid is released on loss of electrical power to the solenoid, e.g., in an emergency situation such as main electrical power failure. The latch release 1007 disengages the mechanical latch 1006 and releases the spring 1005 to operate the actuator 1001 and close the valve gate.
However, in this embodiment, the CWOR assembly 805 includes an upper tree 806 and a lower tree 807. Thus, in this embodiment, the Christmas tree includes two complementary and connected parts consisting of the upper tree 806 and the lower tree 807.
The upper tree 806 includes the pressure regulating means and control system 870 as described in connection with
In this embodiment the lower tree 806 is in the form of a tubing head spool.
By such an arrangement the first gate 861, second gate 862, and gripping mechanism 865 can be confined to the tubing head spool 806, with the upper tree 807 being disposed on top of the tubing head spool 806.
The upper tree 806 has two intervention isolation valves 828,829 at an upper portion thereof. The intervention isolation valves 828,829 are configured to provide access to the wellbore 851 during intervention operations.
In the embodiments shown in
| Number | Date | Country | Kind |
|---|---|---|---|
| 1510673.5 | Jun 2015 | GB | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/GB2016/051804 | 6/16/2016 | WO | 00 |
