Patent Publication Number: US-10322912-B2

Title: Connector system

Description:
FIELD 
     The present invention relates to a connector system, for example a subsea connector system. 
     BACKGROUND 
     In the oil and gas exploration and production industry many operations require reliable connections to be provided between components or infrastructure. Such connections may be of a permanent or long-term nature, intended to remain part of service infrastructure, such as connections between downhole completion equipment, between lengths of tubular and the like. Other connections may be of a temporary or short-term nature, for example used during the deployment and retrieval of equipment. For example, temporary connections may be required during the deployment and/or retrieval of subsea equipment, such as wellhead equipment. In such temporary connections it can often be a critical requirement to reliably make and break the connection. 
     Many temporary connectors are known, and many utilise hydraulic power to activate connecting mechanisms. In some instances such hydraulic connectors provide a robust and reliable solution. In some applications, however, for example in deep water subsea applications, hydraulic connector systems may be adversely limited due to the significant ambient pressures involved. 
     SUMMARY 
     An aspect or embodiment relates to a subsea connector system for providing a connection with a subsea well component, the connector system comprising:
         a latch assembly defining a through bore;   a latch member mounted on the latch assembly and being moveable between a latch configuration and an unlatch configuration to facilitate connection and disconnection with a subsea well component;   a mandrel extending through the through bore of the latch assembly, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member and configure the connector system between connected and disconnected configurations;   a conveyance connector for providing a connection between a conveyance member and the mandrel such that a conveyance member may permit an axial movement component of the predefined movement sequence; and   a rotation interface mounted on one of the mandrel and the latch assembly such that a subsea manipulator may permit a rotational movement component of the predefined relative movement sequence.       

     Thus, a connection with a subsea well component may be made and/or broken by establishing a combination of relative rotational and axial movement between the latch assembly and the mandrel in the predefined relative movement sequence, by the combined use of a conveyance member, providing or permitting axial movement, and a subsea manipulator, providing or permitting rotational movement. Such an arrangement may provide a purely mechanically actuated connector system. As such, an aspect or embodiment may relate to a mechanically actuated subsea connector system. This may minimise or eliminate potential problems associated with, for example, hydraulic systems. Accordingly, the connector system may be less vulnerable to water depth limitations which may be associated with hydraulic systems. 
     The connection system is arranged to be operated by relative movement between the latch assembly and the mandrel permitted or provided by separate sources of control, specifically axial control via a conveyance member, and rotational control via a subsea manipulator. Such an arrangement may eliminate any requirement for the conveyance member to impart rotation within the connector assembly. This may permit a wider range of conveyance member to be utilised. For example, conveyance members having relatively low torsional stiffness may be utilised, such as very slender members, wire, rope, chain or the like. 
     The requirement for a conveyance member to provide, for example only provide, relative axial movement within the connector system may permit simplified control of the conveyance member, for example via a surface vessel. In some embodiments this may avoid the necessity to utilise specialised, high cost and infrequently available vessels, and allow more ready use of vessels of opportunity, such as monohull vessels, mobile offshore drilling units and the like. 
     Also, the requirement for a subsea manipulator to provide, for example only provide, relative rotational movement within the connector may minimise the work requirement of the subsea manipulator, for example by avoiding or minimising the requirement for the subsea manipulator to take on any weight of the connector assembly and/or associated equipment. 
     By providing different components or portions of the predefined relative movement sequence by separate sources of control (the conveyance member and the subsea manipulator), an additional degree of safety may be established in that a single control source is not entirely responsible, and a more involved or deliberate connection and/or disconnection procedure is required. This may minimise the risk of accidental disconnection, for example. 
     The conveyance member may comprise an elongate member, such as a slender elongate member. The conveyance member may be spoolable. The conveyance member may comprise a wire, rope, chain, slickline, e-line or the like. The conveyance member may comprise a tubular conveyance member, such as provided by coiled tubing, jointed pipe (e.g., drill pipe) or the like. The conveyance member may be defined by a tubular riser. The conveyance member may be defined by a landing string. 
     The conveyance member may be configured to support a tensile axial force. Such an arrangement may permit use of gravity to provide axial movement within the connector system. Control of axial movement within the connector system may be provided by controlling a pulling force relative to the connector assembly, against the effect or force of gravity, against a reaction point, for example a point of connection between the connector system and a subsea well component, or the like. In some embodiments the conveyance member may be configured to control axial movement within the connector assembly by varying tension within the conveyance member. 
     In some embodiments the conveyance member may not be required to support any or significant compressive axial force. Such an arrangement may permit a wider range of conveyance member to be utilised, such as wire, rope or the like. However, in some embodiments the conveyance member may be configured to support a compressive axial force. 
     The conveyance member and thus axial movement within the connector system may be controlled from a surface vessel. The surface vessel may comprise a heave compensation system. The conveyance member may be controlled by a spool assembly, such as a compensated spool assembly, on a surface vessel. 
     The conveyance member may be used to control movement of the connector system through water, for example to control deployment and/or retrieval from a surface vessel. In some embodiments the conveyance member may be used to control movement of any well component connected to the connector system. 
     The conveyance connector may comprise any suitable connector to facilitate connection with the required conveyance member. For example, the conveyance connector may comprise a rope socket, hook, shackle, eyelet, swivel, threaded connector or the like. 
     The subsea manipulator may comprise a remotely operated vehicle (ROV). 
     The rotation interface may comprise any suitable interface to facilitate mechanical engagement of a subsea manipulator and to transmit torque to one of the latch assembly and the mandrel. In one embodiment the rotation interface may comprise an engagement arm extending generally radially relative to one of the latch assembly and the mandrel. 
     In one embodiment the rotation interface may be provided on the mandrel such that a subsea manipulator may move the mandrel relative to the latch assembly. 
     The latch member may be configurable between an unlatch configuration and a latch configuration to facilitate connection of the connector system with a subsea well component. Relative movement between the mandrel and the latch assembly during the predefined relative movement sequence may operate the latch member to be reconfigured between its latch and unlatch configurations. 
     When in its latch configuration the latch member may be engaged with the well component. In one embodiment the latch member may engage a latch profile provided on the subsea well component. 
     When in its unlatch configuration the latch member may be permitted to disengage the well component. Accordingly, the unlatch configuration may comprise a defined state of the latch member in that it is capable of disengaging the subsea well component. 
     The latch member may engage the well component to prove a preload between the connector system and the subsea well component, for example between the latch assembly and the well component. Such a preload may one or both axially and rotationally secure at least the latch assembly and the well component. Such axial and/or rotational connection or locking between the well component and the latch assembly may permit reaction to axial and/or rotational loadings. This may facilitate axial and/or rotary based procedures or operations to be performed, for example within or through the well component. 
     In one embodiment the latch member may be positively moved during relative movement between the mandrel and latch assembly. For example, the latch member may be positively moved to be reconfigured into its latch configuration. Such an arrangement may provide a controlled connection with a subsea well component. Further, such an arrangement may permit a preload to be established between the connector system and the subsea well component. In some embodiments the latch member may be supported when in its latch configuration. Accordingly, the latch configuration of the latch member may be achieved by securing or supporting the latch member in engagement with the subsea well component. 
     The latch member may be positively moved to be reconfigured into its unlatch configuration. Alternatively, the latch member may not be positively moved to be reconfigured into its unlatch configuration. For example, the latch member may be desupported during relative movement between the mandrel and latch assembly such that the latch member is no longer positively held within its latch configuration. Accordingly, the unlatch configuration of the latch member may be achieved by desupporting the latch member. 
     The mandrel may comprise a drive profile for engaging and operating the latch member and permitting said latch member to be reconfigured between its latch and unlatch configurations during relative movement between the mandrel and the latch assembly. The drive profile may be arranged to move the latch member from its unlatch to latch configurations, and optionally support the latch member in its latch configuration. The drive profile may be arranged to desupport the latch member to permit said latch member to be reconfigured from its latch configuration to its unlatch configuration. 
     The drive profile may define an axial surface arranged to engage the latch member in an axial direction. The drive surface may be provided by a load shoulder on the mandrel. The load shoulder may be defined by an upset portion on the mandrel. The load shoulder may be provided by an interface or connection between different components of the mandrel. 
     In some embodiments the latch member may be reconfigured between its latch and unlatch configurations during both relative axial and rotational movement components of the predefined relative movement sequence. 
     Alternatively, the latch member may be reconfigured between its latch and unlatch configurations during one of the axial or rotational movement components of the predefined relative movement sequence. In some embodiments one of the axial and rotational components of the relative movement sequence may reconfigure the latch member, and the other of the axial and rotational components of the relative movement sequence may provide a secondary function. The secondary function may comprise a securing function to secure the latch member in either its latch or unlatch configuration. 
     Relative axial movement between the latch assembly and the mandrel may be provided along a primary axis. Relative rotation between the latch assembly and the mandrel may be achieved around the primary axis. 
     In one embodiment the rotational component of the predefined relative movement sequence may be limited, for example physically limited, to prevent over-rotation. In one embodiment, the axial component of the predefined relative movement sequence may be limited, for example physically limited. 
     At least one rotational component of the predefined relative movement sequence may provide an enhancement of a connection force applied by the latch member and the subsea well component. For example, at least one rotational component may provide a cam or wedge effect. 
     The connector system may be reconfigurable from its disconnected configuration to its connected configuration during relative movement of the mandrel and latch assembly in a first direction in the predefined relative movement sequence. The connector system may be reconfigurable from its connected configuration to its disconnected configuration during relative movement of the mandrel and latch assembly in a reverse second direction in the predefined relative movement sequence. 
     The mandrel and latch assembly may be moveable relative to each other in the predefined relative movement sequence between first and second relative positions. When in the first relative position the connector system may be arranged in its disconnected configuration. When in the second relative position the connector system may be arranged in is connected configuration. 
     The predefined relative movement sequence may comprise at least one axial component and at least one rotational component. In one embodiment an axial component must be completed before a rotational component can be initiated, and vice versa. 
     In one embodiment the predefined relative movement sequence may comprise at least one axial component and multiple, for example two, rotational movement components. The rotational components may be provided in the same or different rotational directions. 
     In one embodiment the predefined relative movement sequence may comprise a first rotational component followed by an axial component, followed by a second rotational component. The axial component may facilitate reconfiguring of the latch member, for example to selectively support and desupport the latch member. The rotational components may provide a securing function, for example to prevent relative axial movement between the mandrel and the latching assembly which may otherwise reconfigure the latch member. 
     In one embodiment the predefined relative movement sequence may comprise multiple axial components and multiple rotational components. For example, in one embodiment the predefined relative movement sequence may comprise first and second axial components and first and second rotational components. The first and second rotational and axial components may be interspersed. The first and second rotational movement components may be provided in a common rotational direction. The first and second rotational movement components may be provided in opposing rotational directions. The first and second axial movement components may be provided in a common axial direction. The first and second axial movement components may be provided in opposing axial directions. 
     In one embodiment relative movement of the mandrel and latch assembly from the first relative position to the second relative position to reconfigure the connector system in its connected configuration may be achieved by the first axial component, followed by the first rotational component, followed by the second axial component, followed by the second rotational component. The first axial component and subsequent first rotational movement may provide movement from an initial running configuration. The second axial component may facilitate reconfiguring of the latch member to its latch configuration. The second rotational component may effectively provide locking of the connector system in its connected configuration. The second rotational component may provide an enhancement of a connection force applied by the latch member and the subsea well component. For example, the second rotational component may provide a cam or wedge effect. Such an arrangement may provide or enhance preloading in the connector system 
     Relative movement of the mandrel and latch assembly from the second relative position to the first relative position to configure the connector system to its disconnected configuration may be achieved by reverse movement. That is, initially establishing the reverse second rotational component to effectively unlock the connector system (and release at least a portion of any preload), followed by the reverse second axial component to reconfigure the latch member to its unlatch configuration, and then the reverse first rotational component and reverse first axial component. 
     When the mandrel and latch assembly are arranged in their first relative position the latch assembly may be suspended from the mandrel. In such an arrangement during reconfiguring of the connector system from its disconnected configuration to its connected configuration the first axial component of the predefined relative movement sequence may be provided by downward movement of the mandrel relative to the latch assembly. This arrangement may be achieved by supporting the latch assembly on the subsea well component. 
     Thus, in one embodiment the operational sequence to provide a connection with a subsea well component may comprise:
         landing the latch assembly on the well component;   reducing tension in an associated conveyance member to permit the mandrel to move axially downward relative to the latch assembly;   rotating one of the mandrel and the latch assembly using a subsea manipulator;   applying or increasing tension in the conveyance member to move or lift the mandrel axially relative to the latching assembly and reconfigure the latch member to its latch configuration; and   further rotating one of the mandrel and the latch assembly using the subsea manipulator to secure the connector system within its connected configuration.       

     The operational sequence may comprise applying or increasing tension in the conveyance member to move the mandrel axially relative to the latching assembly to initially engage the latch member with the well component, and then increasing (e.g., further increasing) tension in the conveyance member to establish a preload between the connector system and the well component. In this manner the initial engagement of the latch member may provide an adequate axial load reaction point to permit tension in the conveyance member to be further increased without causing separation between the connector system and the well component. 
     In one embodiment the operational sequence to break an existing connection with a subsea well component may comprise:
         rotating one of the mandrel and the latch assembly using the subsea manipulator;   lowering the mandrel relative to the latch assembly using the conveyance member to permit the latch member to be configured in its unlatch configuration;   further rotating one of the mandrel and the latch assembly; and   lifting the mandrel using the conveyance member until the mandrel picks up the latch assembly from the well component.       

     The connector system may comprise an interface assembly provided between the latch assembly and the mandrel. The interface assembly may prescribe the predefined relative movement sequence between the mandrel and the latch assembly. That is, the interface assembly may only permit relative movement between the latch assembly and mandrel in the predefined relative movement sequence. 
     The interface assembly may comprise a track arrangement provided on one of the latch assembly and the mandrel, and a dog arrangement provided in the other of the latch assembly and the mandrel. Interaction of the dog arrangement with the track arrangement may provide or dictate the predefined movement sequence between the mandrel and the latch assembly. 
     In one embodiment the track arrangement may be provided on the latch assembly, for example provided within the through bore of the latch assembly, and the dog arrangement may be provided on the mandrel. 
     Alternatively, the track arrangement may be provided on the mandrel, and the dog arrangement may be provided on the latch assembly, for example within the through bore of the latch assembly. 
     The track arrangement may comprise a track, and the dog arrangement may comprise at a dog configured to be guided or follow along the track. 
     The track arrangement may comprise multiple track portions defining individual components of the predefined relative movement sequence. The track arrangement may define at least one axially extending track portion and at least one rotationally extending track portion, thus providing axial and rotational components of the predefined relative movement sequence. In one embodiment the track arrangement may comprise first and second axially extending track portions and first and second rotationally extending track portions, for example to facilitate the exemplary operational sequence defined above. 
     Each track portion may be defined by at least one track edge, wherein a dog of the dog arrangement is configured to move, for example slide, along or relative to said track edge. At least one track portion may be defined by a single track edge. At least one track portion may be defined between opposing track edges, for example to define a slot therebetween. 
     In some embodiments a track edge may define a load surface, for example to permit a load to be applied between a dog and the at least one track edge. Such an arrangement may be used to provide a preload within the connector system. 
     In one embodiment the track may define a pocket, wherein a dog of the dog arrangement is received within said pocket when the connector system is in its disconnected configuration. The pocket may be defined in a track edge. 
     The pocket may provide an axial and rotational connection between the mandrel and the latch assembly such that the latch assembly may be suspended from the mandrel with relative rotation therebetween prevented or restricted. 
     The pocket may be arranged such that relative axial movement between the mandrel and latch assembly is required to remove the dog from the pocket, followed by relative rotational movement, for example along a track edge, to misalign the dog and the pocket. 
     The track arrangement may comprise a plurality of tracks, and the dog arrangement may comprise a corresponding plurality of dogs. 
     The interface assembly may comprise a movement limit arrangement. The movement limit arrangement may comprise at least one rotational movement stop. The movement limit arrangement may comprise at least one axial movement stop. 
     The connector system may comprise a secondary locking arrangement for providing locking of the latch member in its latch configuration. Thus, the secondary locking arrangement may function to retain the latch member in engagement with the well component. 
     The secondary locking arrangement may be operable by a subsea manipulator, such as an ROV. 
     The secondary locking arrangement may comprise at least one locking pin, moveable to engage the latch member when said latch member is in its latch configuration. The at least one locking pin may provide a locking force between the latch member and the latch assembly. The at least one locking pin may be threadedly mounted on the latch assembly, and operable to selectively lock and unlock the latch member my being rotated, for example by a subsea manipulator. 
     The latch member may be pivotally mounted on the latch assembly and arranged to pivot to selectively engage and disengage a subsea well component. In one embodiment the latch member may be pivotable about a pivot, such as a pivot pin mounted on or supported by the latch assembly. The latch member may be pivotable by rocking about a pin or fulcrum provided on the latch assembly. 
     The latch member may be generally L-shaped. In one embodiment a first portion of the latch member may be arranged to be engaged by the mandrel, for example a drive profile of the mandrel, and a second portion of the latch member may be arranged to engage a well component. 
     The connector system may comprise a plurality of latch members, for example circumferentially arranged around the latch assembly. 
     The connector system may be arranged to provide a connection with a rim structure of a well component. In this arrangement the latch assembly may be arranged to be received over a rim portion of a well component, and the latch member operated to engage a portion of the rim. Engagement of the latch member with the well component in this way may facilitate a preloaded connection or engagement between the latch assembly and the well component to be achieved. 
     In some embodiment that well component may comprise a subsea well head. The well component may comprise a Xmas tree, such as a production tree, for example a horizontal tree, vertical tree or the like. The well component may comprise a well control barrier, such as a blow out preventer (BOP), subsea test tree (SSTT) or the like 
     The connector system may be configured to support and/or at least partially define a tool assembly. The connector system may comprise a tool assembly connector for providing a connection with a tool assembly. The tool assembly connector may comprise a rigid connector. The tool assembly connector may comprise a flexible interface, such as a compliant interface. In one embodiment the mandrel may be arranged to support a tool assembly. The mandrel may comprise a tool assembly connector. 
     The connector system may be arranged to support and/or at least partially define a rotary tool assembly. In this regard, the connector system may be capable of being rotationally fixed to a well component, such that a rotational reaction may be established for operation of the rotary tool assembly. 
     The connector system may be configured to support and/or at least partially define a cutting tool assembly, such as a rotary cutter, mechanical cutter, plasma cutter, abrasive cutter, explosive cutter or the like. In some embodiments the cutter tool assembly may be configured to cut a portion of the well component, for example to permit a portion of the well component connected to the connector system to be retrieved. In one embodiment the well component may comprise a well head, and a cutter tool assembly provided on the connector system may be for cutting one or more tubulars or casings suspended from the wellhead, for example below a mudline. Such an arrangement may permit a well head to be retrieved, for example as part of a well abandonment procedure. 
     The connector system may be configured to support and/or at least partially define a sealing tool assembly. The sealing tool assembly may be arranged to provide or establish a seal within the well component. The sealing tool assembly may comprise a packer or pack-off seal assembly. 
     The sealing tool assembly may provide feed through capabilities, for example to permit fluid communication, for example controlled fluid communication, through the seal assembly. 
     The sealing tool assembly may facilitate one or more operations within the well component. 
     For example, the well component may form part of a well bore or system, such that the sealing tool assembly may extend into the wellbore or system and establish a seal therein. Such a seal may permit well testing operations, such as pressure testing, for example pressure testing plugs, downhole valves, and the like, extracting samples from the wellbore or system or the like. Such a seal may permit well stimulation procedures to be performed. 
     The well component may form part of a well control barrier such as a Xmas tree, such that the sealing assembly may extend into the well control barrier and establish a seal therein. Such a seal may permit various operations to be performed, such as pressure testing of various valves and barriers, removing or setting crown plugs and the like. 
     The sealing tool assembly may be supported by the mandrel. In one embodiment the sealing tool assembly may be at least partially defined by or on the mandrel. 
     The sealing tool assembly may comprise a sealing arrangement. The sealing arrangement may be configured to sealingly engage the well component, for example an inner surface of the well component. The sealing arrangement may be reconfigurable from a non-sealing configuration to a sealing configuration. Such an arrangement may facilitate initial deployment of the sealing tool assembly. The sealing arrangement may comprise one or more sealing rings. 
     The sealing arrangement may be reconfigurable from its sealing configuration to its non-sealing configuration. Such an arrangement may facilitate retrieval and/or repositioning of the sealing tool assembly. 
     The sealing arrangement may be displaceable from its non-sealing configuration to its sealing configuration. In one embodiment the sealing arrangement may be circumferentially expandable to be reconfigured to its sealing configuration. The sealing arrangement may be located on a first support surface defining a first outer diameter or dimension when said sealing arrangement is configured in its non-sealing configuration. The sealing arrangement may be located on a second support surface defining a second, larger outer diameter or dimension when said sealing arrangement is configured in its sealing configuration. In such an arrangement displacement of the sealing arrangement from the first support surface to the second support surface may reconfigure the sealing arrangement from its non-sealing configuration to its sealing configuration. 
     The first and second support surface may be continuous with each other. A tapering (e.g., ramped, conical etc.) surface may be provided between the first and second support surfaces. 
     The sealing tool assembly may comprise an actuator. The actuator may be operable to reconfigure the sealing arrangement between its non-sealing and second configurations. The actuator may comprise a piston arrangement, such as a hydraulic piston arrangement. 
     The connector system may comprise a feed-through arrangement, permitting one or more conduits to extend past the connector system, for example from surface and into the well component, for example to provide operation to the well component, to provide operation to a tool assembly mounted within the well component or the like. The conduit may comprise a hydraulic conduit, pneumatic conduit, electrical conduit, fibre optic conduit or the like. 
     The mandrel may comprise or define an entry orifice, an exit orifice and a cavity extending therebetween to facilitate passage of a conduit. The entry orifice may be positioned on one side of the latch assembly, and the exit orifice may be positioned on an opposite side of the latch assembly. 
     One of the entry and exit orifices may be provided in a side wall of the mandrel. One of the entry and exit orifices may be provided in an end of the mandrel. The cavity of the mandrel may be defined by a bore extending at least partially through the mandrel. 
     The connector system may be operable to provide an initial connection with a subsea well component to permit the well component to be deployed subsea, for example from a vessel. In such an arrangement the connector system may define or form part of a running tool. Once deployed to the required location, the connector system may be operated by a combination of control via the conveyance member and a subsea manipulator to disconnect the connector system from the deployed well component. The deployed well component may comprise any subsea component, and may include a well head, Xmas tree, BOP, SSTT or the like. 
     The connector system may be operable to provide an initial connection to a well component at a subsea location to permit operations to be performed on or via the well component, such as testing operations, work over operations, intervention operations or the like. Following performance of the required operations the connector system may be disconnected from the subsea well component. 
     The connector system may be operable to provide an initial connection to a well component at a subsea location to permit the subsea well component to be moved, for example retrieved to surface, repositioned at a different subsea location or the like. 
     An aspect or embodiment relates to a method for establishing a connection with a subsea well component, comprising:
         positioning a latch assembly relative to the well component;   establishing relative movement in a predefined relative movement sequence between a mandrel and the latch assembly to operate a latch member mounted on the latch member to move to engage the well component,   wherein the predefined relative movement sequence comprises at least one axial component provided by a conveyance member connected to the mandrel, and at least one rotational component provided by a subsea manipulator engaged with one of the mandrel and the latch assembly.       

     The method may comprise activating a secondary locking arrangement to retain the latch member in engagement with the well component. The secondary locking arrangement may be activated or operated by a subsea manipulator. 
     The method may be performed using the connector system of any other aspect. 
     An aspect or embodiment relates to a method for breaking a connection with a subsea well component, comprising:
         establishing relative movement in a predefined relative movement sequence between a mandrel and a latch assembly to operate a latch member mounted on the latch member to move to disengage the well component,   wherein the predefined relative movement sequence comprises at least one axial component provided by a conveyance member connected to the mandrel, and at least one rotational component provided by a subsea manipulator engaged with one of the mandrel and the latch assembly.       

     An aspect or embodiment relates to a subsea tool system, comprising:
         a latch assembly defining a through bore;   a latch member mounted on the latch assembly and being moveable between a latch configuration and an unlatch configuration to facilitate connection and disconnection with a subsea well component;   a mandrel extending through the through bore of the latch assembly, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member and facilitate connection and disconnection with the subsea well component;   a conveyance connector for providing a connection between a conveyance member and the mandrel such that a conveyance member may permit an axial movement portion of the predefined movement sequence;   a rotation interface mounted on one of the mandrel and the latch assembly such that a subsea manipulator may permit a rotational movement portion of the predefined relative movement sequence; and   a tool assembly connected to the mandrel.       

     The tool assembly may be at least partially defined by the mandrel. 
     The tool assembly may comprise at least one of a rotary tool assembly, a cutting tool assembly, and a sealing tool assembly. 
     An aspect or embodiment relates to a wellbore casing cutter, comprising a connector system according to any other aspect and a cutting tool assembly connected to the connector system. 
     An aspect or embodiment relates to a method for cutting casing, for example using a wellbore casing cutter according to any other aspect. 
     An aspect or embodiment relates to a running tool for deploying and/or retrieving a subsea component. The running tool may comprise a connector system according to any other aspect. 
     An aspect or embodiment relates to a method for deploying and/or retrieving a subsea component, comprising using a running tool according to any other aspect. 
     An aspect or embodiment relates to a sealing apparatus, comprising a connector system according to any other aspect and a sealing tool assembly connected to the connector system. 
     An aspect or embodiment relates to a method for sealing with a well component, for example using a sealing apparatus according to any other aspect. 
     An aspect or embodiment relates to a connector system for providing a connection with a component, the connector system comprising:
         a latch assembly;   a latch member mounted on the latch assembly and being moveable to selectively engage and disengage a component;   a mandrel, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member;   a conveyance connector for providing a connection between a conveyance member and the mandrel such that a conveyance member may permit an axial movement component of the predefined movement sequence; and   a rotation interface mounted on one of the mandrel and the latch assembly such that a manipulator may permit a rotational movement component of the predefined relative movement sequence.       

     It should be understood that the features defined in relation to one aspect may be provided in any combination with any other aspect. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other aspects and embodiments will now be described, by way of example only, with reference to the accompanying drawings, in which: 
         FIG. 1  is a side elevation view of a subsea mechanically actuation connector system, illustrated in a connected state with a well component; 
         FIG. 2  is a cross-section view of the connector system taken along line  2 - 2  of  FIG. 1 ; 
         FIG. 3  is a perspective view, from below, of a bonnet member of the connector system of  FIG. 1 ; 
         FIG. 4  is a side elevation view of a mandrel portion of the connector system of  FIG. 1 ; 
         FIG. 5  is a cross-section view of the mandrel portion taken along line  5 - 5  of  FIG. 4 ; 
         FIG. 6  is a side elevation view of a rotation lock ring of the connector system of  FIG. 1 ; 
         FIG. 7  is a cross-section view of the rotation lock ring taken along line  7 - 7  of  FIG. 6 ; 
         FIGS. 8 to 21  provide an illustration of a sequence for providing a connection between the connector system of  FIG. 1  and a well component; and 
         FIGS. 22 to 32  provide exemplary uses of the connection system of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION OF THE DRAWINGS 
       FIG. 1  provides a side elevation view of a subsea connector system, generally identified by reference numeral  10 , shown connected with a subsea well component  12 . The subsea well component  12  may be any subsea component, such as a well head, Xmas tree or the like. The connector system  10  comprises a latch assembly  14  which mounts over a rim  16  of the well component  12  and includes a plurality of latch members  18  (only one visible in  FIG. 1 ) which pivot to engage the rim  16  of the well component  12  to provide a connection therewith. 
     The connector system  10  further includes a mandrel  20  which is coupled to the latch assembly  14  and includes a conveyance connector  22  in the form of a shackle which provides connection to a conveyance member  24 , specifically wire rope in the present embodiment. The conveyance member  24  extends from a surface vessel (not shown) and is used to trip the connector system  10  to/from the vessel. The conveyance member  24  may also be used to control a relative axial movement between the mandrel  20  and the latch assembly  14 . 
     A pair of rotation arms  26  (only one visible in  FIG. 1 ) are secured to the mandrel  20 , and in use permit an ROV (not shown) to engage one or both arms  26  and cause relative rotation between the mandrel  20  and the latch assembly  14 . 
     As will be described in more detail below, a connection with the well component  12  may be made and broken by establishing relative movement between the mandrel  20  and the latch assembly  14  in a predefined relative movement sequence comprising at least one axial component under the control of the conveyance member  24 , and at least one rotational component under the control of an ROV engaging one or both arms  26 . 
       FIG. 2  provides a cross-sectional view of the connector system  10 , taken along line  2 - 2  of  FIG. 1 . The mandrel  20  extends through a through bore  28  of the latch assembly  14 , and includes an upper mandrel section  20   a  and a lower mandrel section  20   b  secured together by a threaded connection  30 , such that the lower mandrel section  20   b  establishes an axial shoulder  32 . 
     The latch members  18  are provided in the form of L-shaped arms and are each pivotally mounted, via fulcrum members  34 , on the latch assembly  14 , such that the latch members  18  may be moveable in a rocking motion. Each latch member  18  includes a profiled engagement portion  36  which is arranged to engage, generally from below, a corresponding engagement profile  38  on the rim  16  of the well component  12 . 
     The latch members  18  also each comprise a drive portion  40  which is engaged by the axial shoulder  32  of the mandrel  20  such that upward movement of the mandrel  20  relative to the latch assembly  14  drives the latch members  18  to pivot and grip the rim  16 . As the engagement portions  36  of the latch members  18  generally grip the rim  16  from below, this may have the effect of pressing the latch assembly  14  and the rim  16  together, for example in region  42 , which may provide a preload within the connection. Such a preload may provide a reaction against relative axial and rotational movement between the latch assembly  14  and the well component  12 . Downward movement of the mandrel  20  relative to the latch assembly  14  may permit the latch members  18  to be desupported, and thus remove their grip on the rim  16 . In this respect a collar  44  is mounted on the mandrel  20  above the latch assembly  14  to limit downward movement of the mandrel  20  relative to the latch assembly  14 . 
     As noted above, relative axial movement of the mandrel  20  in reverse directions relative to the latch assembly  14  may permit operation of the latch members  18 . However, as will be described in more detail below, such axial movement is only a component of a required predefined movement sequence, with rotational movement also required to facilitate a complete connection and disconnection operation. In this respect the connector system  10  further comprises an interface arrangement  46  between the mandrel  20  and latch assembly which prescribes the required movement sequence by only permitting relative movement in the predefined sequence. In the present embodiment the interface arrangement  46  includes a track arrangement  48  provided on the latch assembly  14 , and a dog assembly  50  provided on the mandrel  20 . The form and interaction of the track arrangement  48  and dog assembly  50  will be described in detail below. The interface arrangement  46  also includes a limit ring  52 , which, as will be described in more detail below, permits relative axial and rotational movement between the mandrel  20  and latch assembly  14  to be limited. 
     The mandrel  20  further includes an upper orifice  11  provided in a side wall thereof above the latch assembly  14 , and a lower orifice  13  provided in a lower end thereof below the latch assembly  14 , with an internal bore  15  extending partially through the mandrel to connect the upper and lower orifices  11 ,  13 . As will be described in further detail below, the orifices  11 ,  13  and bore  15  provide a duct arrangement to permit one or more conduits to be directed through the mandrel  20 , past the latch assembly  14 . 
       FIG. 3  provides a perspective view, from below, of a portion of the latch assembly  14 , with the mandrel  20  and latch members  14  removed for clarity. The track arrangement  48  includes three identical tracks  60  arranged circumferentially within the through bore  28  of the latch assembly  14 . Each track  60  includes a first track portion  62  which extends generally circumferentially, a second track portion  64  which extends generally axially, and a third track portion  66  which extends generally circumferentially. The first track portion  62  is defined by a single track edge  62 . The second track portion  64  is defined between a pair of track edges  64   a ,  64   b  and is thus provided in the form of an axial slot. The third track portion  66  is defined between a pair of track edges  66   a ,  66   b  and is thus provided in the form of a circumferential slot. 
     The first track portion  62  of each track  60  includes a recess or pocket  70 . 
     The track arrangement  48  also includes three rotation stop members  72 . 
       FIG. 4  provides a side elevation view of the lower mandrel section  20   b , in isolation, and  FIG. 5  is a sectional view, taken along line  5 - 5  in  FIG. 4 . The lower mandrel section  20   b  includes or defines the dog assembly  50  and comprises an upper cylindrical portion  80  and a lower enlarged portion  82  with an axial shoulder  84  defined therebetween. The upper cylindrical portion  80  includes three evenly distributed dogs  86  which are sized and arranged to engage the various tracks  60  of the track assembly  48  ( FIG. 3 ). The upper cylindrical portion  80  also includes three evenly distributed locator lugs  88  which function to rotatably secure the limit ring  52  ( FIG. 2 ) to the lower mandrel section  20   b.    
     A side elevation view of the limit ring  52 , in isolation, is shown in  FIG. 6 , with a sectional view, taken along line  7 - 7  of  FIG. 6  provided in  FIG. 7 . The limit ring  52  includes a base ring portion  90  and three evenly distributed limit rib members  92  axially extending upwardly from the base ring portion  90 . Three locator slots  94  (only 2 visible in  FIG. 7 ) are provided on the inner surface of the base ring portion  90 . The limit ring  52  may be mounted over the upper cylindrical portion  80  of the lower mandrel section  20   a  (see, e.g.,  FIG. 4 ) with the locator slots  94  of the base ring  90  allowing the limit ring  52  to pass the dogs  86 . The limit ring  52  may then rest on the axial shoulder  84 , with the locator lugs  88  received within the locator slots  94 , thus rotationally securing the limit ring  52  to the lower mandrel section  20   b.    
     An operational sequence will now be described in detail with reference to  FIGS. 8 to 21 . 
     Reference is first made to  FIGS. 8 and 9 , wherein  FIG. 8  is a part cut-away perspective view of the connector system  10  being initially deployed via conveyance member  24 , for example from a surface vessel and through a depth of water towards the seabed.  FIG. 9  is an enlarged view showing the corresponding configuration of the interface arrangement  46 . In this configuration the dogs  86  of the lower mandrel section  20   b  are received within the respective pockets  70  of each track  60 , such that the latch assembly  14  is effectively suspended from the mandrel  20 , with the weight of the latch assembly  14  carried by the mandrel  20  via the dogs  86 . When in this configuration the mandrel  20  and latch assembly  14  are positioned such that the latch members  18  are axially separated from the shoulder  32  on the mandrel  20 , and thus are in an unlatch or free configuration. 
       FIG. 10  illustrates the connector system  10  upon initial engagement with the rim  16  of the well component, with  FIG. 11  providing an enlarged view of the corresponding configuration of the interface arrangement  46 . In this configuration the weight of the latch assembly  14  is transferred to the well component  14 , with the conveyance member  24  slightly lowering the mandrel  20  relative to the latch assembly  14 , thus moving the dogs  86  out of the respective pockets  70  of the tracks  60 . 
     Subsequent to this, as illustrated in  FIGS. 12 and 13 , the mandrel  20  is rotated, in an anti-clockwise direction (for example by around 60 degrees of rotation), relative to the latch assembly  14 , by use of an ROV (not shown) engaging one or both of the arms  26 . Such rotation moves the dogs  86  along the respective first track portion  62  of each track  60  until the dogs  86  become aligned with the second track portion  64 . In this respect over-rotation is prevented by engagement between the dogs  86  and the rotation stop members  72 . 
     Subsequent to this, as illustrated in  FIGS. 14 and 15 , the mandrel  20  is lifted axially by the conveyance member  24 , moving the dogs  86  into the second track portions  64  of the respective tracks  60 , thus engaging the shoulder  32  against the latch members  18  and causing said members  18  to pivot and initially engage the rim  16  of the well component  12 . 
     As illustrated in  FIGS. 16 and 17 , now that initial engagement is made between the latch members  18  and the well component  12 , axial tension within the conveyance member  24  can be increased, causing further axial movement of the mandrel  20 , increasing the pressing force of the latch members  18  against the rim  16  of the well component  12  and moving the dogs  86  further into the respective second track portions  64 , establishing a preload between the latch assembly  14  and the well component  12 . 
     Following this, as illustrated in  FIGS. 18 and 19 , the mandrel  20  may be again rotated by the ROV (not shown) in an anti-clockwise direction (for example by around 60 degrees of rotation), such that the dogs  86  are now moved into and along the third track portions  66  of the respective adjacent tracks  60  (not visible in  FIG. 18 or 20 —see  FIG. 3 ). In this respect, upper track edge  66   a  of each third track portion  66  may provide a slight tapering surface, such that an additional axial force between the mandrel  20  and the latch assembly  14  may be created, to provide an additional preload within the connection. As illustrated in  FIG. 19 , the limit rib members  92  of the limit ring  52  engage the rotation stop members  72  of the track arrangement  48 , thus preventing over-rotation. 
     Once in the connected state, a secondary locking system may be operated, as illustrated in  FIGS. 20 and 21 . In this respect, the latch assembly  14  includes a locking pin  100  associated with each latch member  18 . Each locking pin may be driven downwardly, by an ROV (not shown), to engage a top surface of a respective latch members  18 . 
     Thus, a connection with a subsea well component  12  may be made and/or broken by establishing a combination of relative rotational and axial movement between the latch assembly  14  and the mandrel  20  in the predefined relative movement sequence, by the combined use of a conveyance member  24 , providing or permitting axial movement, and an ROV (not shown), providing or permitting rotational movement. Such an arrangement may provide a purely mechanically actuated connector system. This may minimise or eliminate potential problems associated with, for example, hydraulic systems, allowing the connector system  10  to have utility in both shallow and ultra-deep applications 
     The requirement for a conveyance member  24  to only provide relative axial movement within the connector system  10  may permit simplified control of the conveyance member  24  via a surface vessel. In some embodiments this may avoid the necessity to utilise specialised, high cost and infrequently available vessels, and allow more ready use of vessels of opportunity, such as monohull vessels, mobile offshore drilling units and the like. 
     Also, the requirement for an ROV (not shown) to only provide relative rotational movement within the connector system  10  may minimise the work requirement of the ROV, for example by avoiding or minimising the requirement for the ROV to take on any weight of the connector assembly  10  and/or associated equipment. 
     By providing different components or portions of the predefined relative movement sequence by separate sources of control (the conveyance member  24  and the ROV), an additional degree of safety may be established in that a single control source is not entirely responsible, and a more involved or deliberate connection and/or disconnection procedure is required. This may minimise the risk of accidental disconnection, for example. 
     The connector system  10  may be used in multiple applications, for example for use in deploying a well component from a vessel, for retrieving a well component to a vessel, for supporting an operation on a well component, or the like. Some example applications will now be described, with reference to  FIGS. 22 to 31 . 
     Referring first to  FIG. 22 , the connector  10  is illustrated as forming part of a casing cutter system, generally identified by reference numeral  110 , with the connector system  10  providing a connection to a wellhead  12 . In this embodiment an abrasive cutter tool assembly  112  is suspended from the mandrel  20  via a flexible interface link  114 . An umbilical  116  extends from surface and through the mandrel  20  to deliver power, for example hydraulic power to the abrasive cutter tool assembly  112 . The cutter tool assembly  112  may generate a radially directed abrasive jet, with rotation of the cutter tool assembly  112  (for example via a mud motor  113 ) permitting casing strings  120 ,  122  suspended form the well head  12  to be cut at some location below the mudline  124 . 
     In an alternative embodiment, as shown in  FIG. 23 , the same abrasive cutter tool assembly  112  may be mounted to the mandrel via a rigid interface link  130 . 
     In further alternative embodiments other forms of cutting tool assembly may be provided. For example,  FIG. 24  illustrates a perforation gun assembly  132  mounted to the mandrel  20  via a rigid interface  134 .  FIG. 25  illustrates a mechanical cutting tool assembly  136  mounted on the mandrel  20  via a flexible interface  138  and rotatable by mud motor  113  to permit cutting of the casing strings  120 ,  122 .  FIG. 26  illustrates the same cutting tool  136  mounted on drill pipe  140  which extends to surface and also provides the function of conveyance member  24  and a portion of the mandrel  20 . 
     In each of the embodiments in  FIGS. 22 to 26 , the cutting tool assembly facilitates cutting of casing strings  120 ,  122  below the mudline  124 . This can permit the wellhead  12  and severed sections of casing strings  120 ,  122  to be retrieved, via the conveyance member  24 , as illustrated in  FIG. 27 . This may form part of a well abandonment operation. 
     The connector system  10  may also be utilised in well testing operations. For example, as illustrated in  FIG. 28 , the connector system  10  is connected to a wellhead  12  in the manner described above. In this case a sealing tool assembly  150  in the form of a pack off seal is mounted on and below the mandrel  20 , such that a seal may be generated within the wellhead (or lower within the associated wellbore). An umbilical  152  extends from surface and through the mandrel  20 , and is coupled to the sealing tool assembly  150 . The umbilical  152  may deliver high pressure fluid through the sealing tool assembly  150  and into a wellbore space  154  below the sealing tool assembly  150 . This pressurised fluid may be used to pressure test a lower established seal or plug  156 , for example which may be used as a well abandon barrier. 
     In some examples, following the test operation illustrated in  FIG. 28 , a cutting operation may be performed, such as illustrated in any one of  FIGS. 22 to 26 , to retrieve the wellhead  12 . 
     An example of a sealing tool assembly  150  is illustrated in  FIGS. 29A and 29B . The sealing tool assembly  150 , which is shown in partial cross section, is illustrated in a non-sealing configuration in  FIG. 29A , and in a sealing configuration in  FIG. 29B . 
     In this example, the sealing tool assembly  150  includes a body  200  upon which is mounted a seal support  202  which defines a first support surface  204 , a second support surface  206  of a larger diameter than the first support surface  204 , and a ramp interface  208  therebetween. Although the seal support  202  is illustrated as being separately formed from the body  200 , in an alternative arrangement part or all of the seal support  202  may be integrally formed with the body  200 . A seal member  210 , such as an elastomeric seal member, is mounted on the seal support  202 . A hydraulic piston sleeve  212  is mounted on the body  200 , and is operable to stroke in opposing axial directions by hydraulic pressure delivered via conduits  214 ,  216 . 
     When in the non-sealing configuration, as illustrated in  FIG. 29A , the seal member  210  is positioned on the first support surface  204  of the seal support  202 . When sealing is required, pressure is applied via conduit  214  to cause the piston sleeve  212  to stroke and drive the seal member  210  onto the second support surface  206 , as illustrated in  FIG. 29B . 
     In one example the seal member  210  may be secured to the piston sleeve  212 , to facilitate reconfiguration of the sealing tool assembly back to its non-sealing configuration. 
     The sealing tool assembly  150  in the examples shown is provided separately from the mandrel  20  of the connector system. However, in other examples the sealing tool assembly may be provided as part of the connector system  10 . For example, the sealing tool assembly  150  may form part of the lower mandrel section  20   b  (see, for example,  FIG. 2 ). 
     Other applications or uses of the connector system  10  may include deploying tools or equipment. One example is illustrated in  FIG. 30 , in which the connector system  10  is shown in the deployment of a subsea Xmas tree  160 . In this case the Xmas tree  160  includes a re-entry mandrel  162  to which the connector assembly  10  is connected. A pack off seal assembly  164  is mounted below the mandrel  20  of the connector system  10 , and in use establishes a seal within the re-entry mandrel  162 . An umbilical  166  may extend through the mandrel  20  to provide a high pressure fluid connection to the pack off seal assembly  164 . Such high pressure fluid may be communicated through the pack off seal assembly  164  and used in pressure testing within the Xmas tree  160  (for example pressure testing of various pressure barriers within the Xmas tree  160 ), and/or pressure testing within an associated wellbore. 
     In an alternative embodiment shown in  FIG. 31 , the connection system  10  may include a tubular riser  170  which provides the function as a conveyance member  24  and also forms part of the mandrel  20 . In such an embodiment the tubular riser  170  may deliver pressurised fluid into the Xmas tree  160  for pressure/wellbore testing. 
     In a further alternative embodiment of  FIG. 32 , an alternative form of pack off sealing assembly  180  is provided which permits tripping through the tubular riser  170  and the pack of seal assembly  180  to permit crown plugs (not shown) within the Xmas tree  160  to be set and pulled. Such an embodiment may also permit pressure/wellbore testing. 
     It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of the invention.