TECHNICAL FIELD

The present invention relates to a method of accessing a well, particularly, but not exclusively, a wellhead thereof; and associated apparatus.

BACKGROUND

Wellheads, such as for subsea oil/gas wellbores, have a number of valves for controlling flow or pressure in/from wellbores. In particular, producing wells have Xmas trees mounted at the wellhead, whereby production can be controlled and well fluids contained as desired or required.

Particularly where equipment can be safety-sensitive, caution is employed when inspecting, installing or maintaining equipment. Accordingly, wellhead workover or access systems, such as with wireline (or coiled tubing) are used in combination after pressure control equipment is fitted to the wellhead to ensure safety. Sequential lifts and valve closures are used in closely defined sequences to place equipment in the wellbore at the wellhead.

It may be an object of one or more aspects, examples, embodiments, or claims of the present disclosure to at least mitigate or ameliorate one or more problems associated with the prior art, such as described herein or elsewhere.

SUMMARY

According to a first aspect, there is provided a method of accessing a well. The method may comprise accessing a wellbore. The method may comprise a method of accessing a wellhead. In at least some examples, the method may comprise plugging the wellbore. The method may comprise accessing the well using a longitudinal member. The method may comprise supporting the longitudinal member on or with a well access apparatus. The method may comprise supporting a weight of the longitudinal member with the wellhead apparatus. The wellhead apparatus may comprise the well access apparatus. The well access apparatus may be locatable at or on the wellhead. The method may comprise mounting the entirety of the longitudinal member on the wellhead apparatus such that the wellhead apparatus supports the weight of the entirety of the longitudinal member. The method may comprise supporting the weight of the entirety of the longitudinal member off the deck. In contrast to conventional operations with wireline, slickline, coiled tubing or the like, the method/s of the present disclosure may not require supporting the longitudinal member (including stored/unused/spooled line) on the deck, such as on a deck-mounted drum, reel, skid or the like. The method may comprise supporting the weight of an entirety of the longitudinal member with or on the well access apparatus in use when accessing the well. The method may comprise supporting the weight of the longitudinal member including an unextended length or portion of the longitudinal member with or on the well access apparatus.

The method may comprise connecting the well access apparatus to a wellhead. The method may comprise supporting a weight of the well access apparatus on the wellhead. The method may comprise connecting the well access apparatus to a Xmas tree. The method may comprise supporting the weight of the well access apparatus on the Xmas tree. The weight of the well access apparatus may include a weight, such as an entire weight, of the longitudinal member, optionally including an unextended or undeployed length or portion of the longitudinal member.

The method may comprise lifting the apparatus onto the wellhead in a single lift operation. The method may comprise lifting the longitudinal member, optionally the entire longitudinal member, onto the wellhead in a single lift. The single lift may comprise lifting the longitudinal member together with at least one of: a lubricator; seal; stuffing box; Pressure Control Equipment (PCE); BOP. The apparatus may comprise one or more of: a lubricator; seal; stuffing box; Pressure Control Equipment (PCE). In at least some examples, the method may comprise connecting the apparatus to a lifting apparatus, such as a winch, derrick, crane or the like. The method may comprise a single-lift operation. The lifting apparatus may be a light lifting apparatus, such as relatively lighter than for lifting or supporting a CT injector, CT drum, wireline reel or the like. The operation may comprise an intervention. The method may comprise lifting the well access apparatus together with the longitudinal member in a single lift operation. For example, where the entire longitudinal member is mounted to and/or in the well access apparatus, the entire longitudinal member may be lifted together with the well access apparatus. The method may comprise lifting the entire longitudinal member onto the wellhead prior to commencement of accessing the well. Accordingly, it may not be necessary to transfer a length or portion of longitudinal member, or any additional longitudinal member/s, to the well access apparatus after the well apparatus is connected, such as after lifting onto, the wellhead. In contrast to conventional CT or wireline operations, the method may comprise accessing the well without supplying (e.g. spooling) lengths or portions of longitudinal member from a deck, skid, reel, drum, spool or the like that is spaced from the well access apparatus.

The method may comprise near-surface access to the wellbore. The method may consist of near-surface operations. Limiting the method to near-surface operations may enable use of a shorter length of longitudinal member, such as a shorter total length of extended longitudinal member. Near-surface access may comprise access at or above/uphole of a sub-surface safety valve. Near-surface access may comprise access to only the wellbore at or above/uphole from the sub-surface safety valve. Near-surface may comprise up to and including a maximum depth of a SSV.

The method may comprise accessing the well up to a maximum depth of around 1 ,000ft; optionally around 2,000ft; optionally around 3,000ft; optionally around 5,000ft; optionally around 12,000ft; or more. The method may comprise accessing the well to a depth of around 1 ,000ft; optionally around 2,000ft; optionally around 3,000ft; optionally around 5,000ft; optionally around 12,000ft; or more. The method may comprise accessing the wellbore proximal the wellhead. Proximal to the wellhead may comprise within 100metres, respectively 50metres, respectively 20metres, 10metres, 5metres or less. The apparatus may comprise a longitudinal member with a maximum extendable length corresponding to around the maximum access depth. For example, the longitudinal member may comprise a maximal extendable length of around 100m for accessing to a maximum depth of 100m. In at least some examples, the longitudinal member may comprise an extendable or extended length of at least around 1 ,000ft; optionally around 2,000ft; optionally around 3,000ft; optionally around 5,000ft; optionally around 12,000ft; or more. In all examples, the entirety of the longitudinal member may be supported on or by the apparatus, including unextended portion/s of the longitudinal member. For example, unextended portion/s of the longitudinal member may be wound or coiled on a reel or drum or the like, the reel or drum mounted to or on the apparatus. In at least some examples, the reel or drum may be configured, such as sized and dimensioned, to accommodate the length of longitudinal member for deployment. For example a larger reel or drum may be mounted to or on the apparatus to accommodate a longer length of longitudinal member. Alternatively, a same reel or drum (e.g. suitable for lengths of around at least 12,00ft) may be used for multiple types of operation, such as with differing maximum depths For example, a same drum as for a 12,000ft depth operation may be utilised for supporting a shorter longitudinal member (e.g. of around 3,000ft or less), such as for only near-surface operations.

The method may comprise providing a longitudinal member with a maximum extended length. The method may comprise accessing the wellbore up to a maximum depth dependent on the maximum extended length of the longitudinal member. The method may comprise accessing the wellbore up to a maximum depth corresponding to a subsurface safety valve. The method may comprise accessing the sub-surface safety valve. The method may comprise accessing the wellbore only above the sub-surface safety valve, or a above a depth corresponding thereto. Additionally, or alternatively, the method may comprise accessing the wellbore at or below the SSV.

The method may comprise providing pressure control equipment. The method may comprise pressure control at least equivalent to that for conventional intervention operations, such as with wireline or coiled tubing or the like. The method may comprise providing an apparatus with integral pressure control equipment. The method may comprise connecting an apparatus to the wellhead.

The method may comprise performing operations without one or more of: wireline, slickline, coiled tubing or the like. The method may comprise performing operations without a discrete drum, such as a coiled tubing or wireline drum discrete from the well access apparatus. The method may comprise performing operations without coiled tubing. The method may comprise accessing the well without using or requiring any longitudinal member (such as CT or wireline) suspended or supported separately, such as on a deck-mounted skid or drum or reel, or otherwise supported separately from the well access apparatus.

The method may comprise plugging. The method may comprise plugging the wellbore proximal to the wellhead. The method may comprise plugging the wellbore below, particularly immediately below the wellhead. The method may comprise doubleplugging. The method may comprise providing at least two plugs in the wellbore.

The method may comprise accessing the well with a tool. The tool may comprise one or more of: an intervention tool; an inspection tool; a run-in tool. The method may comprise transporting the apparatus with the tool stored, optionally mounted, in or with the apparatus. The method may comprise transporting the apparatus with the apparatus horizontal, such as in a storage/transportation unit (e.g. cargo basket). The method may comprise transporting the apparatus without the tool. The method may comprise transporting the apparatus without the plug/s.

The method may comprise transporting the longitudinal member with the apparatus (e.g. entire longitudinal member, such as in a stored/spooled configuration) in the storage/transportation unit. The method may comprise transporting the apparatus together with the stored longitudinal member in a single basket.

The method may comprise an intervention operation without suspending or suspensively supporting equipment, such as a toolstring, in or above the wellbore during the well access operation. In at least some examples, the only lifting operation is a lift, such as single lift, of the well access apparatus into position prior to commencement of the well access operation. In some examples, a single lift may be utilised for PCE; a further lift for the apparatus with longitudinal member together.

The method may comprise mounting the tool to the longitudinal member. The method may comprise inserting the tool into the well access apparatus. The method may comprise inserting the tool into the sleeve housing of the well access apparatus via an end of the well access apparatus housing. The insertion end may comprise an open end, such as an open axial end face, when the well access apparatus is not connected to the wellhead. The insertion end may comprise the lower or downhole end of the apparatus. The method may comprise inserting the tool into the well access apparatus when the well access apparatus is in a non-vertical position (e.g. horizontal), prior to mounting the apparatus to the wellhead.

The method may comprise selecting a plug. The method may comprise making up the selected plug to the apparatus. The method may comprise connecting the plug to the tool. The tool may comprise a setting tool. In at least some examples the tool may comprise a fishing tool. The tool may comprise a combined setting/fishing tool.

The tool may be removable from the apparatus. In at least some examples, a plurality of tools may be interchangeable with the apparatus. The method may comprise transferring the apparatus between wells/wellheads without being fully rigged down. The method may comprise lifting the apparatus from a wellhead in a single lift. The method may comprise lifting the apparatus from a first wellhead to another wellhead in a single lift. The method may comprise lifting the apparatus from the wellhead in the single lift with the longitudinal member in its entirety mounted to, on or in the apparatus. The method may comprise lifting the apparatus directly from a first wellhead to a second wellhead. The method may comprise lifting the apparatus from the wellhead without disconnecting the longitudinal member and/or the toolstring.

According to an aspect there is provided an apparatus for accessing a well. The apparatus may comprise a well access apparatus. The well access apparatus may comprise a wellbore access apparatus. The well access apparatus may comprise a wellhead access apparatus. The apparatus may comprise a wellhead intervention apparatus. The apparatus may be configured for near-surface operations. The apparatus may be configured for only near-surface operations. The apparatus may be configured for intervention operations in, at or proximal to the wellhead. The apparatus may be configured for intervention operations only in, at or proximal to the wellhead.

The apparatus may be configured for inspection and/or testing operations, such as integrity testing. The apparatus may be configured for operations to repair and/or replace well equipment, such as to repair or replace one or more wellhead or Xmas tree devices (e.g. valves).

The apparatus may comprise pressure control equipment (PCE). The apparatus may be configured to contain wellbore pressure within at least a portion of the apparatus. The apparatus may be configured to be sealingly connected to the wellhead. The apparatus may be rated to contain wellbore pressure.

In at least some examples, the apparatus may comprise a safety valve/s.

The apparatus may be configured to replace a wireline or coiled tubing operation, such as conventional wireline or CT intervention operation. In at least some examples the apparatus enables a performance of an operation, such as intervention, without any conventional wireline, slickline, coiled tubing operations or the like. The apparatus may be configured to replace a suspension of a toolstring from above the wellhead. The apparatus may comprise a fitting, such as a flange, for connection to the wellhead. The apparatus may be configured to be connected to the wellhead and/or Xmas tree. In at least some examples, the apparatus may comprise a flange on the lower/downhole end for bolting to a corresponding flange on an upper/uphole side of a Xmas tree.

The apparatus may be configured to be sealingly connected to the wellhead. The apparatus may comprise a first chamber housing the longitudinal member in use. The first chamber may be configured to sealingly connect to the wellhead. The apparatus may comprise a seal for sealingly connecting the first chamber above or to the wellhead. The first chamber may be configured to contain wellbore pressure. The first chamber may be configured to be in fluid communication with the wellbore. At least a portion of the longitudinal member may be housed in the first chamber prior to and/or during deployment of the well access apparatus. The apparatus may comprise at least a portion of the seal, or at least an interface or connection therefor. The apparatus may be configured to accommodate a wellbore pressure in the first chamber. The apparatus may be rated to accommodate a wellbore pressure in the first chamber.

The longitudinal member may comprise an extendable member. The extendable member may be selectively extendable for selective extension into the wellbore. The unextended or undeployed length or portion of the longitudinal member may comprise a stored length of the longitudinal member. The longitudinal member may be configured to extend into the wellbore for a distance greater than a length of the well access apparatus. For example, the longitudinal member may be telescopic or spooled in a stored configuration in or on the well access apparatus prior to extension.

Accordingly, a total length of the apparatus may be shorter (e.g. relative to the access depth), such as for ease of transport, storage and/or deployment/installation.

The longitudinal member may comprise a tensile member, such as a cable, wire, or the like. The longitudinal member may comprise one or more of: wireline, e-line, slickline, braided line; digital wireline or the like. The longitudinal member may comprise a spoolable longitudinal member. The method may comprise extension of the longitudinal member by selective spooling. For example, the method may comprise accessing the well by extending the longitudinal member by spooling or paying out a length of the tensile member from a storage device, such as a spool, reel, drum, winch or the like. The spool, reel, drum, winch or the like may be mounted in on or with the well access apparatus. The spool, reel, drum, winch or the like may be integral with or fixed to the well access apparatus. The spool, reel, drum, winch or the like may comprise a maximum diameter of less than 2 meter; optionally less than 1 meter; further optionally less than 50cm; further optionally 30cm or less. The maximum diameter may comprise the diameter when spooled with a maximum length of longitudinal member prior to deployment. For example, the maximum diameter may comprise a flange height of the spool, reel, drum, winch or the like. The spool, reel, drum, winch or the like may comprise a maximum width of less than 2 meters; optionally less than 1 meter; further optionally less than 50cm; further optionally 30cm or less. The spool, reel, drum, winch or the like may comprise a maximum weight configured to be supported by the cylindrical housing of the well access apparatus when mounted on the wellhead. Accordingly, the spool, reel, drum, winch or the like may comprise a maximum weight (e.g. when fully laden with a maximum length of longitudinal member prior to deployment) that is supportable directly on the wellhead. The maximum weight may comprise a maximum of 500kg or less; 200kg or less; 150kg or less; 100kg or less. In contrast to conventional wireline operations, the longitudinal member here can be stored as spooled on the well access apparatus itself mounted directly on the wellhead. Accordingly, there is no requirement for discrete lifting or spooling devices to transfer lengths of the longitudinal member from a separately mounted storage device. In at least some examples, the longitudinal member, and storage thereof, does not require any additional footprint relative to the well access apparatus as such. When the well access apparatus is mounted to the wellhead, no additional footprint is required for the apparatus: all of the apparatus and the entire longitudinal member, including stored/unspooled, is mounted on the wellhead.

The longitudinal member may be configured to carry a signal/s. The signal/s may be carried uphole and/or downhole. The signal/s may comprise one or more of: a power signal/s; a communication signal/s; a control signal/s; a measurement signal/s. In at least some examples, the longitudinal member may comprise an electrical and/or fiber optic cable. The longitudinal member may carry the signal/s into and/or out of the wellbore. For example, the longitudinal member may carry electrical power and optionally a control signal to a too, sensor or device located (or to be located) at in the wellbore (e.g. downhole). Additionally, or alternatively, the longitudinal member may carry a signal uphole, such as out of the wellbore. For example, the longitudinal member may carry a control, status, measurement or sensor signal/s from a device, sensor, tool or the like. The apparatus may be configured to perform or facilitate testing, such as wellbore testing. The signal may comprise a realtime signal.

It will be appreciated that the apparatus or system may additionally or alternatively comprise other signal transmission. For example, a device, tool, sensor or the like may communicate wirelessly.

At least a portion of the longitudinal member may be mounted coaxially with the wellbore. At least a portion of the longitudinal member may be stored in or on the well access apparatus prior to deployment into the well. In at least some examples, the entire longitudinal member may be stored in or on the well access apparatus prior to deployment into the well.

In at least some examples, the well access apparatus may comprise a housing. The housing may comprise a cylindrical housing, such as an external sleeve. The sleeve may comprise a closed sleeve. The housing may comprise an inner bore and/or chamber for receiving the longitudinal member. The longitudinal member may be mounted to an exterior of the housing. For example, the spool, reel, drum, winch or the like may be mounted on an external wall or surface of the housing. The spool, reel, drum, winch or the like may be mounted to a lateral portion of the well access apparatus. The spool, reel, drum or the like may form part of, or be associated with, the winch.

The method may comprise feeding the longitudinal member into the housing for accessing the well. The method may comprise feeding the longitudinal member into an end portion, such as a terminal axial end portion, of the housing. The method may comprise feeding the longitudinal member into the housing for extending the longitudinal member in and/or into the well. The method may comprise withdrawing the longitudinal member from the housing to retract the longitudinal member in and/or from the well.

The well access apparatus may comprise a sealing arrangement for sealing around the longitudinal member. The sealing arrangement may comprise an axial sealing arrangement for sealing against the longitudinal member as the longitudinal member moves axially into and/or out of the well access apparatus’s inner chamber. The sealing arrangement may comprise one or more of: a gland seal, stuffing box, mechanical seal, resilient seal, wedge, V-ring, O-ring, or the like.

The apparatus may comprise a guide member for guiding passage of the longitudinal member into and/or out of the housing. The guide member may be mounted axially spaced or distal from an aperture for the passage of the longitudinal member. The aperture may comprise an axial end aperture. The guide member may be mounted to provide an intermediate portion of the longitudinal member between the guide member and the housing (aperture), the intermediate portion being an axial extension of the longitudinal member within the housing. The guide member may be configured to position the longitudinal member on a longitudinal axis of the well access apparatus, such as a central longitudinal axis of the well access apparatus. The guide member may be configured to provide for a change in angle of the longitudinal member. The change in angle of the longitudinal member may be between the intermediate portion of the longitudinal member extending from the guide member to the housing (aperture) and a portion of the longitudinal member extending from the guide member to a storage device for the longitudinal member. The change in angle may comprise around 180 degrees, such that the guide member may allow for an effective reversal in direction of the longitudinal member. The guide member may comprise a sheave, pulley, guide-wheel or the like. The guide member may be mounted to the well access apparatus housing.

The storage device for the longitudinal member may be mounted on the well access apparatus housing such that an external portion of the longitudinal member extends externally along the housing in an opposite direction from the wellhead. The storage device may comprise a drum, reel, spool, winch, or the like. The storage device may comprise a line puller. The storage device may be configured to maintain and/or control tension in the longitudinal member. The storage device may be configured to control payout of the longitudinal member. The storage device may be configured to actively payout and/or reel in the longitudinal member, such as via an electrically, mechanically and/or hydraulically powered drive.

The longitudinal member may comprise a rigid member, such as a shaft, rod or the like.

The longitudinal member may comprise a shaft for moving longitudinally along a longitudinal axis of the wellbore and/or the of the apparatus. The central longitudinal axis of the apparatus may be a coaxial extension of the central longitudinal axis of the wellbore. The longitudinal member may comprise a telescopic member/s.

The apparatus may comprise a hydraulic actuator. The hydraulic actuator may comprise a piston. The piston may comprise an upper portion for pressure actuation of the piston and a lower portion for moving the shaft. The piston may be configured to provide a longer stroke than a height of the apparatus, the height of the apparatus being defined when the apparatus is in an inactive configuration. The upper portion of the piston may comprise a greater cross-sectional surface area perpendicular to the central axis than the lower portion of the piston, such that a greater force is exerted on the piston by the upper portion than the lower portion for a same pressure in the first and second chambers. For example, the upper portion may have a greater diameter such that less hydraulic pressure is needed to overcome bore pressure to extend the piston downwards.

The apparatus may comprise a cylinder housing the piston. The cylinder may be fixably mounted to the wellhead. The cylinder may form an exterior housing of the well access apparatus. The cylinder may comprise a hydraulic cylinder, the hydraulic cylinder defining the first chamber and a second chamber, the second chamber housing the upper portion of the piston, the piston dividing the cylinder into the first and second chambers. The first chamber may comprise a lower chamber. The second chamber may be configured to connect to a pressure source, such as a hydraulic line connected to an upper end or portion of the apparatus. The lower portion of the piston may be connected to the tool, such as for extending the tool into the wellbore when the piston is extended.

The piston may be arranged to extend the shaft towards the well. When connected to the wellhead, the piston may be positioned on the central axis for moving the piston longitudinally along the central axis of the wellbore.

The method may comprise extending in or into and/or retracting in or from the well. The method may comprise extending and/or retracting via operation of a piston/s. For example, the method may comprise extending a telescopic longitudinal member into the well by hydraulically driving a piston connected to the rigid longitudinal member. The method may comprise retracting the longitudinal member by operating the piston in a retraction direction (e.g. reverse direction or cycle). In at least some examples, the piston may comprise a telescopic piston. The telescopic piston may comprise a multi- stage telescopic piston. The apparatus may be configured to provide a staged or phased longitudinal extension.

The apparatus may be configured to prevent or at least control rotation of the piston/s. In at least some examples, the piston/s may be keyed to prevent rotation about the longitudinal axis. The apparatus may be configured to control a longitudinal position of the piston/s. The apparatus may be configured to detect and/or measure a longitudinal position of a portion of the apparatus, such as pf the piston/s.

The well access apparatus may comprise a sensor for sensing a position of the longitudinal member and/or the tool/s. The position may comprise a longitudinal position of the longitudinal member and/or tool in the well access apparatus (e.g. within the housing) and/or within the well, such as at or below the wellhead. The sensor may be configured to measure or sense a length of a portion of the longitudinal member, such as a length of paid out longitudinal member. The sensor may be configured to measure data relating to a length of longitudinal member in the well. The sensor may be configured to sense or measure tension in/on the longitudinal member. The sensor may comprise a geo-log sensor head. In at least some examples, the sensor may be mounted on an exterior of the housing of the well access apparatus. Additionally, or alternatively, the sensor/s may be mounted internally, within the housing. The sensor/s may be configured to detect an operation of the apparatus, such as a correct operation. The sensor/s may be configured to provide an indication of a position of the apparatus, such as a position of a portion of the apparatus. The position may comprise a longitudinal position, such as a longitudinal position relative to another portion of the apparatus. The sensor/s may comprise an axial sensor. The sensor/s may be configured to measure a separation between or to a piston face, such as an end face. The sensor/s may comprise a contactless sensor/s, such as a laser or optical sensor, and/or an electromagnetic sensor. The sensor/s may comprise an electronic sensor/s. The sensor/s may comprise a mechanical sensor.

The apparatus may comprise a BOP. The BOP may comprise a dual BOP. The apparatus may comprise a valve, such as an auxiliary valve. The valve may be mounted below/downhole of the BOP. The valve may comprise a gate valve. The apparatus may comprise a shear and seal, such as a compact shear and seal. The shear and seal may be mounted below/downhole of the valve and/or BOP. The apparatus sleeve housing may be mounted above/uphole of the BOP. In at least some examples, the well access apparatus comprises one or more components selected from: the housing sleeve with sealing arrangement; BOP; valve; and/or shear and seal. The apparatus may comprise providing the aforementioned components as a single assembly. The method may comprise one or more of: storing, transporting and/or deploying as a single unit the aforementioned components. Accordingly, the apparatus may comprise the components for simultaneous transport and/or deployment. In at least some examples, the unitary apparatus with all its components may be mounted onto and/or removed from the wellhead. The longitudinal member may be mounted to or on any portion of the apparatus. In at least some examples, the reel, spool, drum, winch or the like is mounted to, on or with the BOP. The reel, spool, drum, winch or the like may be laterally mounted to the apparatus. For example, the reel, spool, drum, winch or the like may be relatively compact and/or lightweight, such as compared to conventional wirelines reels, spools, drums or winches. Accordingly, the reel, spool, drum, winch or the like may be laterally mounted (e.g. to the housing/wellhead equipment); and supported on and by the wellhead without impediment, such as without adversely loading the wellhead or affecting access to the wellhead or associated apparatus (e.g. mounted to the wellhead or proximal thereto, such as on the adjacent deck area). In at least some examples, the reel, spool, drum, winch or the like may be mounted laterally on the BOP. In other examples, the reel, spool, drum, winch or the like may be mounted below or above the BOP. In at least some examples, the reel, spool, drum, winch or the like may be mounted to, on or with the housing, such as the lubricator housing (e.g. laterally-mounted, such as affixed to an external wall). The reel, spool, drum, winch or the like may be mounted to, on or with a valve, such as a shear/seal valve/s.

The apparatus may comprise the housing with sealing arrangement and longitudinal member; the apparatus for being mounted to one or more of: the BOP; valve; and/or shear and seal.

The apparatus may comprise a support, such as a support frame. The support frame may be for supporting the housing and/or a tool, toolstring and/or at least a portion of a tool or toolstring. The support may be provided with the apparatus, such as part of or at least connected or mounted to the housing of the apparatus. In at least some examples, the apparatus comprises a support frame for supporting at least a portion of the toolstring/s during a tool change or changeover. In at least some examples, the apparatus may comprise a lifting device, such as a hoist, for supporting at least a portion of the toolstring. The lifting device may be associated with the support (frame). The lifting device may be configured to lift the at least a portion of toolstring, such as for lifting into and/or out of the BOP or well. The lifting device may be configured to support the at least a portion of the toolstring when the lubricator is disconnected. Accordingly, the apparatus may be configured to perform a tool changeout without requiring any external lifting device for the toolstring (or portion thereof). The lifting device may be configured to lift the at least a portion of the toolstring such that the toolstring can be lifted out of the BOP; and optionally lay down the at least a portion of toolstring; and further optionally lift up another or next toolstring (or portion thereof), such as from deck or a basket or similar (e.g. for spading with the BOP). The support may be mounted relative to the housing of the apparatus such that the support is positioned over the BOP when the lubricator is disconnected and moved laterally off the BOP. For example, the support may be mounted at a distance from the central bore of the apparatus corresponding to a similar distance to a (minimum) displacement corresponding to the movement off the BOP for tool changeover. The support’s lifting device may be positioned within 100cm, optionally within 70cm, optionally within about 50cm or less of the central throughbore (e.g. of central wellbore axis). The lifting device may comprise a powered lifting device (e.g. hydraulically/electrically-powered).

The apparatus may comprise an apparatus lifting mechanism. The apparatus lifting mechanism may be configured to lift the apparatus. Accordingly, in at least some examples, the apparatus may comprise a self-lifting apparatus. The self-lifting functionality may enable the apparatus to be lifted off and/or on to a wellhead. The apparatus may be configured for lifting off and/or onto a wellhead without an overhead lifting machine, such as a crane, derrick or the like. The apparatus lifting mechanism may comprise a jacking frame, such as for jacking up the apparatus from the deck. The apparatus lifting mechanism may be configured to lift the apparatus vertically (e.g. up and/or down). The apparatus lifting mechanism may be configured to lift the apparatus with a toolstring supported therein. The apparatus lifting mechanism may be configured to allow lifted translation of the apparatus, or at least the housing thereof, such as lateral translation of the apparatus (or portion thereof) to/from above the well (e.g. onto and/or off the wellhead). The lifting mechanism may comprise a powered lifting mechanism (e.g. electrically- and/or hydraulically- powered). The apparatus lifting mechanism may enable tool changeover/s without an overhead lifting machine, such as a crane, derrick or the like. In at least some examples, the jacking frame is configured to lift the lubricator. The jacking frame may be configured to lift the lubricator by approximately 50cm vertically above the BOP (when disconnected). Once raised by the jacking frame, the lubricator may be translated horizontally laterally, such as by around 30cm-50cm - sufficient to allow access to the top of the BOP/s. The lubricator may be powerably translated, such as using a hydraulic lateral drive. The BOP/s may then be accessed, such as using the apparatus’s integral lifting device to lift tools out of and/or into the BOP. The apparatus’s integral lifting device may then be used to change over the toolstring. The lifting process may effectively be reversed to position the new toolstring in the wellbore. The jacking frame may be powered to laterally translate the lubricator/toolstring horizontally and/or vertically (e.g. to push the new toolstring/lubricator back over the BOP/s and then lower down to allow connection make up).

The apparatus may be configured for operation/control remotely from the apparatus. The apparatus may be operable from a control unit spaced from the apparatus, such as a deck-based control unit spaced from the wellhead. The control unit may comprise a power supply or pack for powering the apparatus. The control unit may be configured to operate the apparatus (e.g. wireline winch/mini-winch) and/or to convey/record information (e.g. depth and/or tension from the measuring head/winch, which may be connected/attached to the side of the lubricator). The control unit may be hard-wired to the apparatus. Additionally or alternatively, the control unit may be wirelessly connected to the apparatus.

The apparatus may be configured to be transferred between wells/wellheads without being fully rigged down. The apparatus may be configured to be lifted from a wellhead in a single lift. The apparatus may be configured to be lifted from a first wellhead to another wellhead in a single lift. The apparatus may be configured to be lifted from the wellhead in the single lift with the longitudinal member in its entirety mounted to, on or in the apparatus. The apparatus may be configured to be lifted directly from a first wellhead to a second wellhead. The apparatus may be configured to be lifted from the wellhead without disconnecting the longitudinal member and/or the toolstring.

According to an aspect, there is provided an assembly comprising apparatus according to any other aspect, example, embodiment or claim and one or more of: a BOP; valve; and/or shear and seal. The assembly may be assembled prior to mounting to a wellhead. For example, the apparatus comprising the housing with sealing arrangement and longitudinal member may be mounted or made up to the BOP; valve; and/or shear and seal prior to connection of the apparatus, BOP; valve; and/or shear and seal to the wellhead. Alternatively, the assembly may be at least partially assembled subsequent to connection of at least one element of the assembly to the wellhead. For example, the apparatus comprising the housing with sealing arrangement and longitudinal member may be mounted to the BOP after the BOP has been mounted on the wellhead.

According to an aspect there is provided a transportation and/or storage unit for transporting and/or storing the apparatus of any other aspect, example, embodiment or claim. The transportation and/or storage unit may comprise a basket, such as a cargo basket. The basket may comprise conventional or standard outer dimensions for the oil/gas industry, such as similar outer dimensions to existing cargo baskets. The basket may comprise the well access apparatus including all of the longitudinal member; and the storage and supply unit (e.g. a reel, spool, drum, winch or the like) where appropriate. The basket may comprise one or more of: the BOP; and/or shear&seal valve/s; and/or lubricator; and/or riser/s; and/or pump/s; and/or control unit/s; and/or hydraulic supply and/or control.

According to an aspect, there is provided a system comprising a controller according to an aspect, claim, embodiment or example of this disclosure, or a system arranged to perform a method according to an aspect, claim, embodiment or example of this disclosure.

According to an aspect, there is provided computer software which, when executed by a processing means, is arranged to perform a method according to aspect, claim, embodiment or example of this disclosure. The computer software may be stored on a computer readable medium. The computer software may be tangibly stored on a computer readable medium. The computer readable medium may be non-transitory.

Any controller or controllers described herein may suitably comprise a control unit or computational device having one or more electronic processors. Thus, the system may comprise a single control unit or electronic controller or alternatively different functions of the controller may be embodied in, or hosted in, different control units or controllers. As used herein the term “controller” or “control unit” will be understood to include both a single control unit or controller and a plurality of control units or controllers collectively operating to provide any stated control functionality. To configure a controller, a suitable set of instructions may be provided which, when executed, cause said control unit or computational device to implement the control techniques specified herein. The set of instructions may suitably be embedded in said one or more electronic processors. Alternatively, the set of instructions may be provided as software saved on one or more memory associated with said controller to be executed on said computational device. A first controller may be implemented in software run on one or more processors. One or more other controllers may be implemented in software run on one or more processors, optionally the same one or more processors as the first controller. Other suitable arrangements may also be used.

Within the scope of this application it is expressly intended that the various aspects, embodiments, examples and alternatives set out in the preceding paragraphs, in the claims and/or in the following description and drawings, and in particular the individual features thereof, may be taken independently or in any combination. That is, all embodiments and/or features of any embodiment can be combined in any way and/or combination, unless such features are incompatible. The applicant reserves the right to change any originally filed claim or file any new claim accordingly, including the right to amend any originally filed claim to depend from and/or incorporate any feature of any other claim although not originally claimed in that manner.

The invention includes one or more corresponding aspects, embodiments or features in isolation or in various combinations whether or not specifically stated (including claimed) in that combination or in isolation. For example, it will readily be appreciated that features recited as optional with respect to the first aspect may be additionally applicable with respect to the other aspects without the need to explicitly and unnecessarily list those various combinations and permutations here (e.g. the apparatus or device of one aspect may comprise features of any other aspect). Optional features as recited in respect of a method may be additionally applicable to an apparatus or device; and vice versa.

In addition, corresponding means for performing one or more of the discussed functions are also within the present disclosure.

The above summary is intended to be merely exemplary and non-limiting. Various respective aspects and features of the present disclosure are defined in the appended claims.

It may be an aim of certain embodiments of the present disclosure to solve, mitigate or obviate, at least partly, at least one of the problems and/or disadvantages associated with the prior art. Certain embodiments may aim to provide at least one of the advantages described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

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

Figure 1 shows a first apparatus according to an example of the present disclosure;

Figure 2 shows the apparatus of Figure 1 with a longitudinal member extended;

Figure 3 shows the apparatus of Figure 1 after deployment of a device and retraction of the longitudinal member from the position of Figure 2;

Figure 4 shows an example method of using the apparatus of Figure 1;

Figure 5 shows a Pressure Control Equipment (PCE) for use with example apparatus;

Figure 6 shows an example tool for use with example apparatus;

Figure 7 shows an example apparatus for use with the PCE of Figure 5 for deploying the tool of Figure 6;

Figure 8 shows a cross-section of the apparatus of Figure 7 made up with the PCE of

Figure 5 and the tool of Figure 6;

Figure 9 shows a detail of the apparatus of Figure 8;

Figure 10 shows an apparatus according to a further example;

Figure 11 shows a cross-section of the apparatus of Figure 10;

Figure 12 shows a detail view of Figure 11 ;

Figure 13 shows a further detail view of Figure 11;

Figure 14 shows a further detail view of Figure 11;

Figure 15 shows the apparatus of Figure 10 in a storage configuration;

Figure 16 shows an apparatus according to a further example;

Figure 17 shows the apparatus of Figure 16 at a wellhead;

Figure 18 shows the apparatus of Figure 16 in use;

Figure 19 shows the apparatus of Figure 16 being lifted between two wellheads in a single lift operation;

Figure 20 shows a control unit for use with the apparatus of Figure 16; Figure 21 shows the apparatus of Figure 16 in a storage/transportation configuration; and

Figure 22 shows the apparatus of Figure 16 adapted to be self-lifting.

DETAILED DESCRIPTION

Figures 1 - 3 show a series of sequential views representing steps of a method of accessing a well using an apparatus 10 according to an example of the present disclosure. Referring first to Figure 1 , there is shown an apparatus 10 positioned above a wellhead 50 that is fitted with a Christmas tree 51 and a bore safety valve 52. Here, the apparatus 10 comprises a longitudinal member in the form of a piston rod 15. The apparatus 10 comprises a telescopic hydraulic cylinder 11 with a first end 12 and a second end 13, the said ends being closed when mounted to the wellhead; and defining an inner chamber 14 of the cylinder 11 . The cylinder 11 houses the piston rod 15, with the cylinder 15 separating the different pressure zones within the chamber 14, thereby defining a hydraulic supply chamber 14a proximate the first end 12 and an extension chamber 14b proximate the second end 13. In at least some examples, the extension chamber 14b comprises a lubricator. Here, the piston 15 is connected to a setting/fishing tool 16. The first end 12, being the upper end here, comprises an attachment 18 through which the apparatus 10 may be attached to other pieces of equipment (not shown), especially for facilitating the positioning of the apparatus 10 over the wellhead 50, for example a winch or a lifting device such as a derrick. It will be appreciated that the lifting device may be a light lifting device, such as relative to a lifting device for lifting a CT drum/injector or the like. The second end 13, being the lower end here, comprises a flange 19 (a threaded bore) which provides means for securing the apparatus 10 onto the bore safety valve 52. A suitable plug 20 is inserted into the extension chamber 14b, mounted beneath the piston rod 15.

An example method according to this disclosure is illustrated in Figure 4; where it is shown that the apparatus 10 can be connected to at or to a wellhead in a first step 114; an operation performed in a second step 118; and then the apparatus disconnected in a third step 122.

In use, the apparatus 10 is connected to a hydraulic supply control 30 via a hydraulic supply line 31 , as shown in Figure 2. Following a shut-off of the well, the apparatus 10 is connected to the bore safety valve 52 via the threaded bore 19. Once determined that it safe to do so, via pressure tests and following pressure equalisation if necessary, the well is reopened. Then, liquid 32 is supplied via the hydraulic supply line 31. The liquid 32 exerts a force on the piston rod 15 due to the build-up of pressure in the sealed hydraulic supply chamber 14a. Thus, the piston 15 is hydraulically moved through the cylinder 11 , thereby moving the setting tool 16 and the plug 20 toward and through the second end 13 thereof, and further through the bore safety valve 52, the Christmas tree 51 and the wellhead 50, into a setting/fishing position 40, such as below a tubing hanger. The plug 20 is then set by the setting/fishing tool 16. Subsequently, the piston 15 along with the setting/fishing tool 16 are retracted back into the cylinder 11 upon release of liquid 32 or pressure out of the hydraulic supply chamber 31 , such as by reversing, reducing or limiting a pump in hydraulic supply control, as shown in Figure 3.

The plug is then inflow-tested and, once its integrity is verified, repairs and/or maintenance activities can be carried out on the bore safety valve 52, Christmas tree 51, and/or the wellhead 50.

Once the repairs and/or maintenance activities are finalised, the plug 20 is retrieved using apparatus 10, by following what are essentially the outlined method steps in reverse. The setting/fishing tool 16 is hydraulically moved to the setting/fishing position 40 by the piston 15, as shown in Figure 3. The plug 20 is latched onto the setting/fishing tool 16 using a corresponding profile and retrieved back into the extension chamber 14b of the cylinder 11 as shown in Figure 2. The apparatus 10 may then be rigged down. In at least some examples, a double-acting hydraulic cylinder is used.

It will be appreciated that, although shown here with a particular setting/fishing tool, other tools may be deployed with the apparatus 10. For example, where another tool, such as another apparatus, is or becomes stuck adjacent or in the wellhead, the apparatus 10 may be used in a fishing operation to retrieve the stuck tool. It will also be appreciated that the wellbore/liner/hanger has been omitted from the figures for clarity.

Figure 5 shows a Pressure Control Equipment (PCE) 253 for use with an example apparatus, such as that 10 of Figure 1 or that 210 of Figure 7. The PCE 253 comprises a lubricator 249, combi blow out preventer 252, mini riser 254, auxiliary gate valve 255 and a compact shear and seal valve 256. Figure 6 shows an example tool 221 for use with the example apparatus 10, 210. Here the tool 221 comprises an electronic setting tool with a bridge plug 220. Figure 7 shows the apparatus 210 for use with the PCE 253 of Figure 5 for deploying the tool 221 of Figure 6.

Figure 8 shows a cross-section of the apparatus 210 of Figure 7 made up with the PCE 253 of Figure 5 and the tool 221 of Figure 6, noting that in some examples the PCE 253 is installed on the wellhead in a first lift; the tool 221 is lifted onto/into the PCE 253 in a second lift; and the apparatus 210 is lifted onto the wellhead, connecting to the PCE 253, in a third lift.

The apparatus 210 of Figures 6 and 8, shown in detail in cross-section in Figure 9, is generally similar to that 10 of Figure 1 , with similar features denoted with similar reference numerals, incremented by 200, noting that descriptions of each similar feature are not repeated here, for brevity and clarity. Accordingly, the apparatus 210 comprises a longitudinal member in the form of a piston rod 215 housed in a cylinder 211. Here, the piston 215 has been designed to be two stage, telescopic and double acting (able to extend and retract using separate ports). If hydraulic capabilities on the retract side are lost for whatever reason, a third emergency piston 205 can be utilised to retract stage 1.

During a normal extend operation, stage 1 will extend first followed by stage 2 due to the larger piston effect on the larger bore stage and during retract operation, stage 1 will retract first followed by stage 2 due to the larger piston effect on the larger bore stage. Both piston stages can overcome 10ksi well pressure due to the piston area differentials.

At the back of the piston housing 211 , a draw wire sensor 207 allows for accurate depth tracking when extending into the well. This provides the operator with sufficient information about what PCE 253 needs to be actioned during the event of equipment malfunction or in any other emergency as well as providing crucial information regarding where the plug 220 should be positioned prior to setting.

The outer housing 211 is made up of a main tubular body, end cap and an API 6A design spec and rated front flange 203 for making up onto the PCE 253 stack up below it. The end cap has a DNV offshore design spec pad eye 209 for lifting out of a cargo basket (such as shown in Figure 15) and onto the stack up in one lift. The cargo shipping basket is designed to house the apparatus 210, the PCE equipment 253 and the bridge plug and relevant jewellery 220, 221 to minimise deck space I footprint on whichever oil rig it is sent to. A counterbalance valve (not shown) is installed onto the retract port to prevent the cylinders extending when in the vertical position under their own weight.

The system is controlled by a hydraulic control panel, where pressures can be set with regulators to overcome the piston effect of the well. Spool valves can allow for smooth operation of the pistons 215 and a monitor for depth control is fed from the draw wire sensor 207. The control panel is fed from a custom-built hydraulic power unit which can provide sufficient flow and pressures up to 10ksi.

All components have been designed for compliance with API 6A where necessary and are made from materials which satisfy NACE I H2S requirements. The safe working temperature of the system is 0-120° and the design is 3rd party verified as well as satisfying ATEX and Zone 1 approval requirements. The maximum working pressure of the system is 10ksi.

In at least some example methods, the apparatus 210 is lifted out of the cargo basket and the bridge plug 220 is made up to the piston end connection. The apparatus 210 is then flanged onto the PCE stack up 253. At this point, the piston stages are both fully retracted and held in place by a counterbalance valve to prevent them extending under the weight of the bridge plug 220. The auxiliary gate valve 255 and the combi BOP 252 are open and pressure testing can be carried out on the stack by testing above the tree valves. Once satisfactory testing is complete, the pressure above the tree will be balanced to the pressure in the well prior to opening the tree valves ready for running in hole (RIH). Pressure is applied to the extend port of the piston 215. Once the counterbalance valves pilot pressure is reached, the first stage will start to extend in a controlled manner until it has reached the end of its stroke. At this point, the bridge plug 220 and accompanying tooling 221 will be clear of all PCE 253.

Once the first stage has reached the end of its stroke, stage two will start to move in a controlled manner until the telescope is full stroked or the desired setting depth has been reached as determined by the operator by using the control panel and draw wire sensor 207 feedback accordingly. After a pre-determined time, the electronic setting tool 221 on the bridge plug 220 will set the plug 220 an auto release once set. The pistons 215 can now be retracted by applying pressure to the retract port. In an unlikely event where the setting tool 221 does not release or the tool string is stuck for any other reason, a shear joint has been implemented at the connection between the piston end and the setting tool 221. This joint can be sheared by applying a pre-determined amount of pressure to the retract port. In the rare event where the plug 220 or tool string 221 is stuck in hole and hydraulics are lost at the same time, the emergency piston 205 can be used to retract the cylinders. If the emergency piston 205 has failed, the pistons 215 can be sheared using the shear and seal I Combi BOP 256/252.

With several Xmas trees on any given platform, there can be high potential for numerous valve failures. As such, gaining access to the platform to repair failed valves can be a major challenge facing operators. When a slot in the platform schedule does become available, there is then further justification required as value-adding well-work is always a strong contender for these available slots. However, the system as shown here 210 is a three lift PCE system that allows for the setting of shallow plugs 220, either below or in the tubing hanger profile. The operation of this system 210 can be executed whilst ensuring the same level of PCE and Well Control as would be found in a standard coil tubing rig up. This system 210 may provide the industry with an alternative, simplified, cheaper, quicker, lower risk solution for plugging wells compared with current wireline or CT methods.

Referring now to Figures 10 through 15, there is shown another example apparatus 310 according to this disclosure. The apparatus 310 is generally similar to that 210 of Figures 6 and 8, (and shown in detail in cross-section in Figure 9), with similar features denoted with similar reference numerals, incremented by 100, noting that descriptions of each similar feature are not repeated here, for brevity and clarity. Accordingly, the apparatus 310 comprises a longitudinal member 315 housed in a cylinder 311. Here, the longitudinal member 315 is in the form of a wireline.

The apparatus 310 here comprises a guide member 360 in the form of an end sheave; a measurement sensor 307 in the form of a geo-log head; and a wireline storage and supply unit 362 in the form of a spring-loaded wireline drum winch mounted directly on an outside surface of the apparatus housing 311. The wireline 315 is fed via an end axial opening 364, through a stuffing box 366 to connect with a tool 321 within an inner chamber 314 of the apparatus 310. As shown here, in cross-section in Figure 11 , the tool 321 has a bridge plug 320 mounted thereto. In use, the wireline 315 payout length is controlled (assisted by the geo-log head 307) to move the tool 321 with plug 320 along the central axis, down through a dual BOP 352 when ready, past an auxiliary gate valve 355 and a compact shear and seal 356, through the wellhead (not shown) into the wellbore therebelow. Similar tools, plugs and/or other equipment can be deployed that could otherwise be deployed with conventional wireline technology, such as with conventionally long wireline for up to much greater depths downhole than here with the compact wireline drum 362 mounted directly on the apparatus 310. The tool and devices 320, 321 mounted thereto can be operated in the wellbore as desired. Having the wireline drum 362 mounted directly on the apparatus 310, avoids using up footprint at or near the wellhead for a disparate deck-supported drum. Furthermore, the provision of only a limited length of wireline 315, such as here up to only 1km long in this example reduces the weight of the laden (and unladen) wireline drum 362, with the weight being borne, in use, directly on the wellhead. It will be appreciated that the drum 362 here is comprised in a winch controlling payout and retrieval of the wireline 315.

In contrast to conventional wireline operations, the longitudinal member 315 here can be stored as spooled on the well access apparatus 310 itself mounted directly on the wellhead. Accordingly, there is no requirement for discrete lifting or spooling devices to transfer lengths of the longitudinal member 315 from a separately mounted storage device. Here, the longitudinal member 315, and storage thereof, does not require any additional footprint relative to the well access apparatus 310 as such. When the well access apparatus 310 is mounted to the wellhead, no additional footprint is required for the apparatus 310: all of the apparatus 310 and the entire longitudinal member 315, including stored/unspooled, is mounted on the wellhead.

Accordingly, at least some example methods comprise accessing a wellbore using a longitudinal member 15, 215, 315, whereby the weight of an entirety of the longitudinal member 15, 215, 315 is supported on the wellhead - with or via the well access apparatus 10, 210, 310 - in use when accessing the well. The method includes supporting the weight of the longitudinal member 15, 215, 315 including an unextended length or portion of the longitudinal member 15, 215, 315 on the wellhead, with or on the well access apparatus 10, 210, 310.

Referring now to Figure 15, there is shown the apparatus 310 of Figure 10 stored in a cargo basket 390 for transportation. As shown here, a single cargo basket 390 is used to store the entirety of the system required for the operation, such as the intervention (e.g. plugging, valve repair or the like). The assembly is shown partially disassembled, with the BOP 352 detached from the housing 311 with lubricator 349. The auxiliary gate valve 355 and the compact shear and seal valve 356 are shown here mounted together with the BOP 352, but separate from the housing 311 with lubricator 349. Similarly, the toolstring is shown partially disassembled, separate from the wireline 315, with the electronic setting tool 321 and bridge plug 320 mounted together in the basket 390. The wireline 315 is spooled on the winch drum 362, which is stored in the basket 390 attached to the housing 311 , along with the measurement sensor 307.

Here, since the drum winch 362 is so compact, the entirety of the wireline 315 is spooled on the drum 362 and both the wireline 315 and the drum 362 can be stored together on the single basket 390 together with the apparatus 310. As shown in Figure 15, the drum 362 can even be stored and transported together with the wireline 315 still or already mounted to the apparatus housing 311 with the lubricator 349.

Here there is also provided a space out spool 354 in the basket 390 for positioning in use below the BOP 352, locating the BOP spaced above the compact shear & seal 356.

It can also be seen that the basket 390 comprises additional storage, such as for a pump 392 (e.g. a double-head, double-action pump); a hydraulic pressure unit & winch control 394; and/or a well control panel 396.

Referring now to Figures 16-22, there is shown another example apparatus 410 according to this disclosure. The apparatus 410 is generally similar to that 310 of Figure 10, with similar features denoted with similar reference numerals, incremented by 100, noting that descriptions of each similar feature are not repeated here, for brevity and clarity. Accordingly, the apparatus 410 comprises a longitudinal member 415 housed in a cylinder 411. Here, the longitudinal member 415 is in the form of a wireline. Figure 17 shows the apparatus 410 at a wellhead 496; and Figure 18 shows the apparatus 410 in use.

The apparatus 410 comprises a support in the form here of a support frame 484, 492 for supporting the housing 411 and/or a tool, toolstring and/or at least a portion of a tool or toolstring. The support frame 484, 492 is provided with the apparatus 410, here as part of or at least connected or mounted to the housing 411 of the apparatus 410. The support frame 484, 492 supports at least a portion of the toolstring/s during a tool change or changeover. Here, the apparatus comprises a lifting device 491 , shown here as a hoist, for supporting at least a portion of the toolstring/apparatus 410. The lifting device 491 is associated with the support frame 484, 492; and is configured for assisting with lifting into and/or out of the BOP or well. The lifting device 491 is configured to support the at least a portion of the toolstring when the lubricator is disconnected. Accordingly, the apparatus 410 is configured to perform a tool changeout without requiring any external lifting device for the toolstring (or portion thereof). The lifting device 491 is configured to lift the at least a portion of the toolstring such that the toolstring can be lifted out of the BOP 452; and additionally lay down the at least a portion of toolstring; and then lift up another or next toolstring (or portion thereof), such as from the deck or a basket or similar (e.g. for spading with the BOP 452). The support 484, 492 is mounted relative to the housing 411 of the apparatus 410 such that the support 484, 492 is positioned over the BOP when the lubricator is disconnected and moved laterally off the BOP 452. Here, the support 484, 492 is mounted at a distance from the central bore of the apparatus 410 corresponding to a similar distance to a (minimum) displacement corresponding to the movement off the BOP 452 for tool changeover, about 50cm or less of the central throughbore (e.g. of central wellbore axis). The lifting device 491 here is a powered lifting device (e.g. hydraulically/electrically-powered).

Figure 19 shows the apparatus 410 of Figure 16 being lifted between two wellheads 496, 498 in a single lift operation. The methods of use here can represent significant time and cost saving compared to conventional wireline operations. For example, the method of use here comprises transferring the apparatus 410 between wells/wellheads 496, 498 without being fully rigged down - unlike conventional wireline that needs fully rigged down between wells. The method of use here comprises transferring the apparatus 410 from a wellhead 496, 498 in a single lift. The method of use here comprises lifting the apparatus 410 from a first wellhead 496 to another wellhead 498 in a single lift. The method of use here comprises lifting the apparatus 410 directly from the wellhead 496, 498 in the single lift with the longitudinal member 415 in its entirety mounted to, on or in the apparatus 410; and without disconnecting the longitudinal member 415 and/or the toolstring. Figure 20 shows a control unit 480 for use with the apparatus of Figure 16. The apparatus 410 is configured for operation/control remotely from the apparatus 410, with the apparatus 410 being operable by an operator 482 from the deck-based control unit 480 spaced from the apparatus 410. The control unit 410 comprises a power pack for powering the apparatus 410 and is configured to operate the apparatus 410 (e.g. wireline winch/mini-winch 470) and/or to convey/record information (e.g. depth and/or tension from the measuring head/winch 407, which is connected/attached to the side of the lubricator). The control unit 480 here is hard-wired to the apparatus 410.

Figure 21 shows the apparatus 410 of Figure 16 in a storage/transportation configuration in a basket 490, generally similar to that shown in Figure 15. Here, it can be seen that the housing support frame 484, 492 and the base support frame 486 are stored and transported together with their respective portions 411 , 452. It will be appreciated that the control unit 480 of Figure 20 can be transported together with the basket 490 of Figure 21.

Figure 22 shows the apparatus 410 of Figure 16 adapted to be self-lifting. The apparatus 410 comprises an apparatus lifting mechanism 499 configured to lift the apparatus 410. The self-lifting functionality enables the apparatus 410 to be lifted off and/or on to the wellhead 496, 498. The apparatus 410 is configured for lifting off and/or onto the wellhead 496, 498 without an overhead lifting machine, such as a crane, derrick or the like. Here, the apparatus lifting mechanism 499 comprises a jacking frame, for jacking up the apparatus 410 from the deck. The apparatus lifting mechanism 499 is configured to lift the apparatus 410 vertically (e.g. up and/or down); and in at least some cases to lift the apparatus 410 with the toolstring supported therein. The apparatus lifting mechanism 499 is configured to allow lifted translation of the apparatus 410, such as lateral translation of the apparatus 410 to/from above the well (e.g. onto and/or off the wellhead 496, 498). The lifting mechanism 499 here comprises a powered hydraulic lifting mechanism, which enables tool changeover/s without an overhead lifting machine, such as a crane, derrick or the like. Here, the jacking frame 499 is configured to lift the lubricator by approximately 50cm vertically above the BOP 452 (when disconnected). Once raised by the jacking frame 499, the lubricator can be translated horizontally with a hydraulic lateral drive by around 30cm- 50cm - sufficient to allow access to the top of the BOP 452, such as using the apparatus’s integral lifting device 491 to lift tools out of and/or into the BOP 452. The apparatus’s integral lifting device 491 can then be used to change over the toolstring. The lifting process is effectively reversed to position the new toolstring in the wellbore. Here, the jacking frame 499 is hydraulically powered, controlled by the operator 482 from the control unit 480. to laterally translate the lubricator/toolstring horizontally and/or vertically (e.g. to push the new toolstring/lubricator back over the BOP 452 and then lower down to allow connection make up).

It will be appreciated that embodiments of the present invention can be realised in the form of hardware, software or a combination of hardware and software. Any such software may be stored in the form of volatile or non-volatile storage such as, for example, a storage device like a ROM, whether erasable or rewritable or not, or in the form of memory such as, for example, RAM, memory chips, device or integrated circuits or on an optically or magnetically readable medium such as, for example, a CD, DVD, magnetic disk or magnetic tape. It will be appreciated that the storage devices and storage media are embodiments of machine-readable storage that are suitable for storing a program or programs that, when executed, implement embodiments of the present invention. Accordingly, embodiments provide a program comprising code for implementing a system or method as disclosed in any aspect, example, claim or embodiment of this disclosure, and a machine-readable storage storing such a program. Still further, embodiments of the present disclosure may be conveyed electronically via any medium such as a communication signal carried over a wired or wireless connection and embodiments suitably encompass the same.

All of the features disclosed in this specification (including any accompanying claims, abstract and drawings), and/or all of the steps of any method or process so disclosed, may be combined in any combination, except combinations where at least some of such features and/or steps are mutually exclusive. The applicant indicates that aspects of the present disclosure may consist of any such individual feature or combination of features. 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 disclosure. For example, it will be appreciated that although shown here with a piston cylinder with a round cross-section, other piston cross-sections are also possible, such as where the piston cylinder has a cross-section that is not rotationally symmetrical, such as to prevent rotation of the piston about its longitudinal axis (e.g. keyed, guided or the like). Similarly, where the drum winch is shown here mounted to a lubricator/housing, the drum winch may be mounted elsewhere, such as on or to an exterior of the BOP, shear/seal valve, mini-riser or space out spool. Each feature disclosed in this specification (including any accompanying claims, abstract and drawings), may be replaced by alternative features serving the same, equivalent or similar purpose, unless expressly stated otherwise. Thus, unless expressly stated otherwise, each feature disclosed is one example only of a generic series of equivalent or similar features.

The invention is not restricted to the details of any foregoing embodiments. The invention extends to any novel one, or any novel combination, of the features disclosed in this specification (including any accompanying claims, abstract and drawings), or to any novel one, or any novel combination, of the steps of any method or process so disclosed. The claims should not be construed to cover merely the foregoing embodiments, but also any embodiments which fall within the scope of the claims.