The present invention relates to a tubing severing tool. In particular, but not exclusively, the present invention relates to a tubing severing tool for use in severing a wellbore tubular. The present invention also relates to a well shut-off device, and to a wellhead, comprising such a tubing severing tool.

In the oil and gas exploration and production industry, well fluids have conventionally been recovered from subterranean rock formations by drilling a wellbore from surface, and then lining the drilled wellbore with wellbore-lining tubing in the form of a metal casing. The casing serves numerous purposes, including: supporting the drilled rock formations; preventing undesired ingress/egress of fluid; and providing a pathway through which further tubing and downhole tools can pass. The casing is cemented in place, the wellbore extended, and a further section of smaller diameter casing located in the well. This process is repeated as necessary until the wellbore has been extended to the region of a producing formation. The well is then 'completed' by installing production tubing, extending to surface, and the casing perforated to permit well fluids to enter the wellbore, where they flow up to surface through the production tubing. During drilling, it is necessary to prevent the influx of formation fluids. This is achieved using a well shut-off device known as a blow-out preventer or 'BOP'. The BOP includes hydraulic seal rams which can seal around a string of tubing extending into the wellbore, to provide annulus pressure control, and shear rams which can sever the tubing in an emergency situation. Where deployed from a floating surface facility such as a floating drilling rig, the BOP is positioned on a wellhead on the seabed, and is connected to the surface facility via a marine riser.

Severing the tubing using the shear rams, in conjunction with closure of the seal rams, provides pressure control for the well in the event of an emergency situation arising.

However, once pressure control has been achieved, it is necessary to re-enter the well to stabilise it and enable subsequent recovery of well fluids. The section of tubing remaining in the well must be recovered to surface or remediated to enable re-entry. However, closure of the shear rams leaves a section of tubing with a crimped end in the well. This is illustrated in the attached schematic illustration of Fig. A, in which shear rams 2a and 2b are shown in closed positions, following actuation to sever a tubing 3, with a portion 4 recovered to surface and a portion 5 remaining in the well. The crimped ends of the tubing portions 4 and 5 are indicated at 6 in the drawing, and typically have a length of approximately 1.5 times the original diameter of the tubing 3. Recovery or remediation of the tubing section 5 is hampered by the crimped end 6; it is necessary to mill off the crimped end 6 to allow re-entry into the well. This creates a significant volume of cuttings, which must be circulated out of the well. Also, in particularly large bore BOPs (or other cutting devices) with a narrow annulus, the crimped ends 6 of the tubing portions can interfere with the BOP bore, which reduces the effectiveness of the shear rams 2a, 2b.

Other methods of severing wellbore tubulars are known. These include, in appropriate circumstances, lowering an internal cutting tool from surface down the inside of the tubular which is to be severed. Lowering an internal cutting tool takes time, and so is not generally suitable for severing a tubular in an emergency situation. The tools also typically employ either a milling style process, if the end of the tubular member can be accessed nearby, or a scraping style cutting process, if the tubular member is continuous to surface. These cutting processes generate significant volumes of cuttings. Some of the internally deployed tools have extendable arms, and differ in the ways in which the arms are deployed, and various features which complement the cutting process, such as:

grappling/fishing tools, hangers for securing the tool and mud motors for rotating only the tool at the target depth while a deployment line remains stationary. Problems exist in terms of ensuring the cut is performed at the correct location, and the removal of cuttings.

A further option for severing wellbore tubulars is to lower an explosive element on a wireline into the bore of the tubular, and to disconnect by means of an explosion. This involves an additional trip, and can prove difficult and time consuming. It can also have a damaging effect on surrounding components.

Other methods of drilling and completing wells have been developed, including 'casing drilling' techniques, which employ the casing itself to drill and extend the wellbore. One such alternative method is disclosed in International Patent Publication No. WO- 2006/010906. In the disclosed method, a subsea shut off device including a gripping mechanism is latched to a template at surface. A casing is suspended from the device using the gripping mechanism, and the device run to the sea floor on the casing string. The casing string is then drilled in and converted into a riser. The casing string is captured and sealed within a subsea shut-off device after installing and spacing out a surface BOP. Following drilling-in of the casing, the casing is severed using a cutting device in the subsea shut-off device, and the cut portion of casing recovered to surface. When emergency disconnection is required, shear rams in the device cut the casing and seal in the well.

Whilst the method disclosed in WO-2006/010906 offers significant advantages over other more conventional drilling methods, severing of the casing following drilling-in can be problematic. In particular, the cutting device comprises a body which is rotatably mounted within a main housing of the shut-off device. A plurality of hydraulic pistons are mounted in the body, and carry rotary cutters which are urged against a tubular extending through the housing, to sever the tubular as the body rotates. The tension in the tubular (which is suspended from a surface facility) exerts an axially directed force on the cutters, which can cause them to break.

It is an object of the present invention to provide an improved tubing severing tool.

According to a first aspect of the present invention, there is provided a tubing severing tool for use in severing a wellbore tubular, the tool comprising:

a main housing;

a body mounted for rotation relative to the housing;

a plurality of tubing severing devices which are arranged to sever the wellbore tubular when the body is rotated relative to the housing, in which the tubing severing devices each comprise:

· a tubing severing element; and • a mounting member for the tubing severing element, the mounting member being mounted for movement relative to the body to urge the tubing severing element into contact with the wellbore tubular;

in which the tubing severing elements are each mounted on their respective mounting member in such a way that movement of the tubing severing elements in an axial direction relative to the body is permitted.

Mounting the tubing severing elements on their respective mounting members in this way provides a degree of axial play, to account for axial loads imparted on the severing elements during use. In particular, the wellbore tubular to be severed may be suspended and so under tension, with the result that an axially directed force is imparted on the tubing severing elements as they are driven into a wall of the tubular to sever it. Providing a degree of axial play means that such loads can be accounted for, and reduces the likelihood of breakage of the severing elements.

Reference is made to movement of the tubing severing elements in an axial direction relative to the body. It will be understood that the axial direction which is referred to may be a direction which is parallel to a main longitudinal axis of the body.

The tubing severing elements may each be mounted on their respective mounting member in such a way that movement of the tubing severing elements in an axial direction relative to the mounting members is permitted. This may facilitate the required movement of the tubing severing elements in the axial direction, relative to the body. The mounting members may each be mounted for movement relative to the body in said axial direction, to thereby facilitate the required movement of the tubing severing elements. The tubing severing elements may then be restrained against movement in said axial direction relative to the mounting members. In other words, the axial movement is permitted by movement of the mounting member, carrying the tubing severing element, relative to the body. The tubing severing devices may each comprise a mounting arrangement for mounting the tubing severing elements to their respective mounting member in such a way that said movement in the axial direction is permitted. The mounting arrangement may comprise at least one load resisting element, which is arranged so that it can be deflected or deformed to accommodate axial loading on the tubing severing element. The load resisting element may be elastically deflectable or deformable.

The load resisting element may be arranged so that axial movement of the tubing severing element compresses the load resisting element between the tubing severing element and the mounting member. The load resisting element may be a compressible element. The load resisting element may be mounted between a surface of the tubing severing element and a surface of the mounting member, so that it is compressed when the tubing severing element moves in said axial direction. The load resisting element may be a substantially solid or one-piece element. A material of the load resisting element may be selected to allow a desired degree of deformation, and so a desired degree of axial movement of the tubing severing element relative to the body. Plastics materials may be most suitable, including but not limited to polyurethane. The load resisting element may be shaped so as to allow a desired degree of deformation, and may be a spring or sprung element. The load resisting element may be a Belleville washer or the like. Metal or metal alloy materials may then be most suitable.

The load resisting element may be arranged so that axial movement of the tubing severing element imparts a tensile load on the load resisting element. The load resisting element may therefore be a tensionable element. The load resisting element may be coupled to both the tubing severing element and the mounting member, so that the tensile load can be imparted on the load resisting element. The load resisting element may be a spring or sprung element.

The tubing severing elements may be mounted so that axial movement relative to the body in a first axial direction is permitted. The tubing severing elements may be mounted so that axial movement relative to the body in both a first and a second (opposite) axial direction is permitted. The tubing severing elements may be mounted to their respective mounting members in such a way that, in an initial position of the tubing severing elements, the elements abut a surface of the mounting member so that movement of the tubing severing element in only a first axial direction, away from the initial position, is permitted. Movement of the tubing severing element in the second axial direction is prevented through contact between the element and the surface of the mounting member. It will be understood that, following movement of the tubing severing elements away from their initial positions, return movement towards the initial position (in the second axial direction) may be possible. The tubing severing elements may be mounted for rotation relative to the respective mounting members. In this way, the tubing severing elements may rotate around a surface of the wellbore tubular, to indent and sever the tubular. The elements may be mounted on a pin or rod oriented parallel to an axis of the body, for rotation relative to the mounting member. The elements may be blades, may be circular in shape in plan view, and may taper in directions towards radially outer edges of the elements. Providing tubing severing elements having such a tapered shape may facilitate severing of the wellbore tubular with little or no cuttings being generated. Thus severing is achieved by a separation process rather than by material removal. The axial play between the tubing severing elements and the body may be particularly advantageous in the case of such tapered blades. This is because the tapered shape may result in an axially directed reaction load being imparted on the severing element during use, irrespective of the tension in the tubular. The axial play which is provided may help to reduce the resultant likelihood of breakage of the severing elements. The mounting members may each be mounted for movement within apertures extending at least part way through a wall of the body. The mounting members may be mounted for radial movement, and may be arrayed equidistantly around the body. The mounting members may each be moveable between: a retracted position, in which the tubing severing element does not contact the tubular; and an extended position, in which the element can contact and indent the tubular. The tubing severing elements may be mounted to the mounting members at a first end thereof, and the mounting members may define an abutment surface at a second, opposite end which can abut the main housing. The tubing severing devices may comprise abutment components defining the abutments surfaces, and which may form sacrificial wear strips. The abutment components may be of a material having a relatively low coefficient of friction. Suitable materials for the abutment components may comprise plastics materials, in particular PTFE or PEEK.

The mounting members may be mounted to the body in such a way that rotation of the mounting members (about axes of the mounting members) is restricted. This may maintain the associated tubing severing elements in desired orientations, and may resist twisting of the elements during use. This may be advantageous in that it may help to ensure that the plurality of tubing severing elements all follow the same path around the surface of the tubular when the body is rotated. The mounting members may each be mounted for movement on at least one mounting rod or pin, which may extend at least part way along the aperture. The pin may be shaped to resist said rotation of the mounting member.

Typically there will be a plurality of mounting rods or pins which together act to resist such rotation. The mounting members may be retained within the apertures by mounting plates which resist retraction of the mounting members from the apertures, typically in a direction away from the tubular to be severed. The mounting plates may carry or may be coupled to the at least one mounting pin or rod. The abutment surface may protrude beyond a surface of the mounting plate for abutting the housing. The mounting plates may comprise an aperture, and the abutment component may extend through the aperture for abutting the main housing. The abutment component may be dimensioned so that, when the abutment surface contacts the main housing, a gap exists between an associated end of the mounting member and the mounting plate. In this way, the mounting member does not exert a direct load on the mounting plate, the load instead being transferred to the main housing. The tubing severing devices may be hydraulically actuated, and the mounting members may be pistons mounted in cylinders defined by apertures in the body. The pistons may be actuated to urge the tubing severing elements into contact with the tubular to be severed by applied fluid pressure. The body may be sealed relative to the housing, and a pressure chamber defined between the body and the housing. The pistons may be actuated by controlling the pressure of the fluid in the chamber. The body may be sealed relative to the housing by at least one seal which is arranged so that it provides a static pressure barrier to prevent fluid flow past the seal when the body is stationary. Typically there will be at least two seals, spaced axially along the body and straddling the mounting members. The at least one seal may be arranged so that a degree of leakage past the seal is allowed when the body is rotated relative to the housing, to lubricate the seal, which may facilitate rotation of the body. It will be understood that the pressure of the fluid in the chamber will be greater than that outside the chamber during use, creating a pressure differential across the seal which will result in fluid egress from the chamber, but which will prevent ingress of fluids into the chamber. The static seal will also prevent fluid ingress in the event that external pressure is greater when the tool is deactivated and so when the body is stationary. The at least one seal may communicate with a fluid storage chamber which stores fluid which has leaked past the seal. The fluid storage chamber may be pressure compensated. The tool may comprise a pressure compensating arrangement for communicating the pressure of fluid external to the pressure chamber to the fluid in the storage chamber. This may prevent hydraulic lock; and may reduce the pressure differential across the at least one seal. The pressure compensating arrangement may comprise a plunger or piston mounted for movement relative to the fluid storage chamber, the plunger having a first face exposed to fluid in the fluid storage chamber, and a second face exposed to the fluid external to the fluid storage chamber. In this way, the pressure differential between the first and second plunger faces causes movement of the plunger so that the external pressure can be communicated to the fluid in the fluid storage chamber.

The tool may comprise a shock absorbing arrangement associated with the tubing severing devices. The shock absorbing arrangement may compensate for hydraulic shock loads imparted on the mounting pistons due to sudden movement of the tubing severing elements. For example, as the body rotates and indents the severing elements into the tubular, there comes a point where one or more of the severing elements will break through a wall of the tubular in a relatively sudden, free movement. As the body is rotating, the tubing severing element will then encounter a portion of the wall which has not yet been breached, and will be urged sharply back in the opposite direction. This could result in a hydraulic shock load on the mounting piston, which is absorbed by the shock absorbing arrangement. The shock absorbing arrangement may comprise a shock absorbing chamber which communicates with the pressure chamber, and a plunger or piston mounted for movement relative to the shock absorbing chamber. The plunger may have a first face exposed to fluid in the pressure chamber, and a second face exposed to: fluid external to the shock absorbing chamber; or to a volume pre-charged with fluid (typically a compressible fluid such as a gas) at a desired pressure. In this way, the hydraulic shock load can be accommodated by movement of the plunger within the shock absorbing chamber.

The tool may comprise a drive arrangement for driving and rotating the body relative to the main housing. The drive arrangement may comprise a geared drive and an actuator, which may be a motor, particularly a hydraulic motor. The drive arrangement may extend through a wall of the main housing, and a double seal barrier may be provided between the drive arrangement and the main housing. A first seal may be provided on a part of the drive arrangement extending through the housing wall; and a second seal may be provided between a cap which surrounds a part of the drive arrangement which protrudes from the housing, and the housing.

The tool may comprise an actuator for controlling the operation of the tubing severing devices. Where the tubing severing devices are hydraulically actuated, the actuator may be a fluid actuator for supplying hydraulic fluid to the severing devices to actuate the devices. The actuator may be arranged to move the tubing severing elements towards the wellbore tubular. The actuator may be arranged to control the return movement of the tubing severing elements away from the wellbore tubular.

The actuator may be arranged to supply hydraulic fluid to the tubing severing devices to actuate the devices, which fluid may be contained within the tool, or which may be separate and coupled to the tool when required. The fluid may be provided by a remotely operated vehicle (ROV) which can be coupled to the tool via a stab-plate associated with the tool, or in a 'hot stab' scenario via a direct coupling with the tool.

The actuator may comprise a control arrangement for selectively supplying fluid to the tubing severing devices. The control arrangement may comprise a main control piston which communicates with the pressure chamber; a biasing element acting on the main control piston, for exerting a force on the piston to cause the piston to impart a fluid pressure force on the fluid in the pressure chamber; and a release mechanism acting on the main control piston, which can be operated to release the piston so that the biasing element acts on the piston to pressurise the fluid in the pressure chamber and so act on the tubing severing devices.

The main housing may define an axial bore for receiving the wellbore tubular, and the body may be mounted within the housing. The body may be hollow. The tool may therefore be an external tubing severing tool, for severing a wellbore tubular extending through the housing and the body. The tubing severing elements may be movable radially inwardly to sever the tubular.

The tool may be adapted to be located within a wellbore tubular to be severed, and the body may be hollow and mounted on or around an external surface of the housing. The tool may therefore be an internal tubing severing tool, for severing a wellbore tubular within which the tool is located. The tubing severing elements may be movable radially outwardly to sever the tubular. It will be understood that the tool may have a utility in severing a wide range of types of wellbore tubular, including but not limited to: wellbore-lining tubing such as casing and liner; production tubing; coiled tubing; and tool strings.

Reference is made to the severing of wellbore tubular, and to tubing severing devices having tubing severing elements. It will be understood that the severing of the wellbore tubular which is referred to may be achieved without material removal, such as occurs in tools employing milling and/or scraping elements. The severing elements are indented into a surface of the wellbore tubular to be severed, and separate the tubular by imparting a high radial force over a small surface area of the tubular. This is advantageous in terms of avoiding (or at least significantly reducing) the generation of cuttings, compared to prior tools.

According to a second aspect of the present invention, there is provided a well shut-off device comprising a tubing severing tool according to a first aspect of the invention.

The shut-off device may be a BOP. The shut-off device may be a device of the type employed in a casing-drilling method, such as that disclosed in WO-2006/010906.

According to a third aspect of the present invention, there is provided a wellhead comprising a tubing severing tool according to the first aspect of the invention. Further features of the tubing severing tool of the second and third aspect of the invention may be derived from the text above relating to the first aspect of the invention.

Whilst the tubing severing tool of the first aspect of the invention has a particular utility in a well shut-off device or a wellhead, it will be understood that the tool may have a utility with many other types of devices and/or in many different scenarios. The tool, in particular the main housing, may be adapted for connection to other devices, and may be coupled to or provided as part of a relatively short length of tubing such as a spool piece, for connection to or provision as part of such other devices. The tool, in particular the main housing, may carry appropriate connectors, such as flanges or threads, for connection to or provision as part of such other devices.

An embodiment of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Fig. 1 is a highly schematic drawing of a well shut-off device in the form of a BOP, incorporating a tubing severing device, in accordance with an embodiment of the present invention; Fig. 2 is an enlarged, detailed longitudinal cross-sectional view of the tubing severing tool of Fig 1; Figs. 3 and 4 are enlarged rear and front perspective views, respectively, of a tubing severing device of the tool shown in Fig. 2;

Figs. 5 and 6 are side and sectional views of a body of the tool shown in Fig. 2; Fig. 7 is a cross-sectional view of the tool shown in Fig. 2, taken about the line B-B, and with certain components not shown, for ease of illustration;

Fig. 8 is a cross-sectional side view of an actuator of the tool shown in Fig. 2, for controlling the operation of tubing severing devices of the tool, and illustrating its relationship to one of the tubing severing devices; and

Fig. 9 is a detail view showing part of a drive arrangement of the tool of Fig. 2, which extends through a wall of a main housing of the tool. Turning firstly to Fig. 1 , there is shown a highly schematic view of a well shut-off device in the form of a BOP, indicated generally by reference numeral 10, incorporating a tubing severing device 12, in accordance with an embodiment of the present invention. As with the exemplary prior device shown in Fig. A, the BOP 10 comprises blind shear rams 2a and 2b, and is shown following an emergency shut-off operation, in which the shear rams have been actuated to close and shear a wellbore tubular 3 into separate parts 4 and 5. As will be understood by persons skilled in the art, the wellbore tubular 3 may be any of a number of different types of tubular, including but not limited to: wellbore-lining tubing such as casing and liner; production tubing; coiled tubing; and tubular forming part of a tool string deployed into a well. In the illustrated example however, the wellbore tubular is a length of casing 3 deployed into a well 7 for lining a wellbore 8. The BOP is shown located on a subsea wellhead 11 , which has been located in the drilled wellbore 8, and from which a first section of casing 9 has been suspended. The wellbore 8 has then been extended, and the drawing shows the smaller diameter casing 3 during running-in to the wellbore, suspended from a floating surface facility such as a drilling rig (not shown), in a conventional fashion.

When pressure control has been achieved, the severed portion 4 of the casing 3 is retrieved to surface, and the shear rams 2a and 2b can then be opened. The tubing severing tool 12 is provided below the shear rams 2a and 2b, and can be provided integrally with the BOP 10, or as a modular unit which can be mounted on or in the BOP. The tubing severing tool 12 is operated to remove the crimped end 6 of the casing portion 5 remaining in the well 7, enabling re-entry into the well. The crimped end 6 of the casing portion 5 can later be fished out, for example using a wire-line tool. This would allow for simple re-entry into the well 7 at a later date, when the associated well pressure-control incident has been resolved.

The tubing severing tool 12 is shown in more detail in the enlarged longitudinal cross- sectional view of Fig. 2, and generally comprises a main pressure housing 14, provided integrally with the BOP 10, or separately and coupled to the BOP. The tool 12 also comprises a body 16 mounted for rotation relative to the housing 14, and a plurality of tubing severing devices, indicated generally by reference numeral 18. The tubing severing devices 18 are arranged to sever the casing 3 when the body 16 is rotated relative to the housing 14, and each comprise a tubing severing element 20 and a mounting member 22 for the tubing severing element. The mounting members 22 are mounted for movement relative to the body 16, to urge the tubing severing elements 20 into contact with the casing 3 which is to be severed. The tubing severing elements 20 are each mounted on their respective mounting members 22 in such a way that movement of the tubing severing elements in an axial direction relative to the body, as indicated by the arrow 24 (Fig. 2), is permitted. Mounting the tubing severing elements 20 on their respective mounting members 22 in this way provides a degree of axial play, to account for axial loads imparted on the severing elements during use. In particular, the casing 3 to be severed is suspended from the surface facility and so is under tension, with the result that an axially directed force is imparted on the tubing severing elements 20 as they are driven into a wall of the casing 3 to sever it. Providing a degree of axial play means that such loads can be accounted for, and reduces the likelihood of breakage of the severing elements 20. In the illustrated embodiment, the tubing severing tool 12 is an external, annular severing or cutting tool intended to sever a wellbore tubular, that is the casing 3, extending through the tool. To this end, the main housing 14 defines an axial bore 26 which receives the casing 3, and the body 16 is hollow and mounted coaxially within the housing for rotation relative to the housing 14. The tubing severing elements 20 are movable radially inwardly to sever the casing 3 located in the axial bore 26. It will be understood however that the tubing severing tool of the invention may be adapted to be located within a wellbore tubular to be severed, such as the casing 3, and so that in an embodiment of the invention, the tool may be an internal tubing severing tool. The body would then be hollow and mounted on or around an external surface of the housing, and the tubing severing elements movable radially outwardly to sever the casing 3. The tool would be deployed down inside the tubular to be severed on a suitable tubing string.

The tubing severing tool 12 will now be described in more detail, with reference also to Figs. 3 and 4, which are enlarged rear and front perspective views of one of the tubing severing devices 18; Figs. 5 and 6, which are side and sectional views of the body 16; and Fig. 7, which is a cross-sectional view of the tool 12 taken about the line B-B of Fig. 2 (and with certain components not shown, for ease of illustration).

The tubing severing tool 12 comprises the rotating body 16, which is situated within the bore 26 of a pressure vessel in the form of the main housing 14, for the purpose of severing tubular members such as the casing 3. The body 16 contains a symmetrical arrangement of six tubing severing devices 18, as best shown in Fig. 7, although any suitable number and arrangement of the severing devices 18 may be employed. The mounting members 22 take the form of bespoke cutting pistons carrying the tubing severing elements 20. Torque is transmitted to the tool via a drive arrangement 28 comprising a geared drive, indicated generally by numeral 30, and an actuator in the form of a hydraulic motor 32. The geared drive 30 includes a sealed cartridge-style driveshaft 34, which carries a bevel gear 36 that meshes with a gear ring 38 (Fig. 5) on a lower end of the body 16. The tool 12 severs the casing 3 by separating the material, when the body 16 is rotated within the housing 14, this being achieved by means of the tubing severing or cutting elements 20. The tubing severing elements 20 take the form of generally circular blades, and are relatively hard disk-shaped wheels, which taper towards their radially outer edges 21. In use, the blades 20 roll around a periphery of the casing 3, to reduce friction. The severing elements 20 are rotatable relative to the pistons 22 on hard and polished pins 39, which allow the blades 20 to roll around the surface of the casing 3, thereby reducing the running friction of the tool 12. The blades 22 are able to axially displace during the severing or cutting process, to reduce loading on the severing elements. This is achieved by means of a mounting arrangement, indicated generally by numeral 40. The mounting arrangements 40 each comprise a load resisting element 42, which is arranged so that it can be deflected or deformed to accommodate axial loading on the blade 20. The load resisting element 42 is elastically deflectable or deformable, and takes the form of a substantially solid or one- piece, compressible washer. The washer 42 is arranged so that axial movement of the blade 20 compresses the washer between the severing element and a surface 44 of the piston 20. A material of the washer 42 is selected to allow a desired degree of

deformation, and so a desired degree of axial movement of the blade 20 relative to the body 16. Plastics materials, including but not limited to polyurethane, may be most suitable.

Providing blades 20 having a tapered shape facilitates severing of the wellbore tubular with little or no cuttings being generated. This is because severing is achieved by a separation process rather than by material removal. The axial play between the blades 20 and the body 16 is particularly advantageous where the blades are tapered, because the tapered shape results in an axially directed reaction load being imparted on the blade during use, irrespective of the tension in the casing 3. The axial play helps to reduce the resultant likelihood of breakage of the blade 20 by allowing axial blade deflection.

The blades 20 are mounted so that axial movement relative to the body 16 in a first axial direction, indicated by the arrow 24, is permitted. The blades 20 are mounted to their respective pistons 22 in such a way that, in an initial position of the blades, they abut a lower surface 46 of the piston, so that movement of the blade 20 in only the first axial direction 24, away from the initial position, is permitted. Movement of the blade 20 in a second (opposite) axial direction is prevented, through contact between the blade 20 and the surface 46 of the piston 22. It will be understood that, following movement of the blades 20 away from their initial positions, return movement towards the initial position (in the second axial direction) is possible.

The pistons 22 are each mounted for movement within apertures 48 extending through a wall 50 of the body 16, and which define hydraulic cylinders. The pistons 22 are mounted for radial movement, and arrayed equidistantly around the body 16. The pistons 22 are each moveable between a retracted position (Fig. 2), in which the respective blade 20 does not contact the casing 3, and an extended position, in which the blade can contact and indent the casing. The pistons 22 are mounted to the body 16 in such a way that rotation of the pistons 22 about their axes 52 (Fig. 7) is restricted. This maintains the associated blades 20 in desired orientations, and resists twisting of the blades 20 during use. This is advantageous in that it helps to ensure that the plurality of blades 20 all follow the same path around the surface of the casing 3 when the body 16 is rotated. The pistons 22 are each mounted for movement on at least one mounting rod or pin, which extends at least part way along the aperture, and in the illustrated embodiment, are mounted on a pair of pins 54. The pins 54 are arranged so that they act to resist rotation of the piston 22 about its axis 52.

The pistons 22 are retained within the cylinders 48 by mounting plates 54, which resist retraction of the pistons from the cylinders, in a direction away from the casing 3 to be severed. The mounting plates 48 are secured to the body 16, and carry the mounting pins 54, and thereby serve for mounting the pins 54 to the rotating body 16. The blades 20 are mounted to the pistons 22 at first ends 58 thereof, and the pistons comprise an abutment surface 60 at a second, opposite end 62, which can abut the main housing 14. The abutment surfaces 60 are defined by abutment components 64 mounted on the pistons 22, and which form wear strips. The abutment strips 64 are of a material having a relatively low coefficient of friction, suitable materials including plastics materials, in particular PTFE or PEEK. The abutment surface 60 is curved to match the shape of an inner surface 66 of the main housing 14, and protrudes beyond an outer surface 68 of the mounting plate 56 for abutting the housing 14. The wear strips 64 rub against the housing 14 when the pistons 22 are in their retracted positions and the body 16 rotated. The mounting plates 56 each comprise an aperture 70, and the abutment strip 64 extends through the aperture 70 for abutting the surface 66 of the main housing 14. The abutment strip 64 is dimensioned so that, when the abutment surface 60 contacts the housing surface 66, a small radial gap (not shown) exists between the second end 62 of the piston 22 and the mounting plate 56. In this way, the piston 22 does not exert a direct load on the mounting plate 56 when retracted, the load instead being transferred to the main housing 14.

The pistons 22 are hydraulically actuated to urge the blades 20 into contact with the casing 3 to be severed by applied fluid pressure. The rotating body 16 is sealed relative to the main housing 14, and a pressure chamber 72 is defined between the body 16 and the housing 14. The rotating body 16 is thus partially surrounded by a pressure compensated oil bath, in the form of the pressure chamber 72, which is closed in by an upper sub 73 and a lower sub 75. The pistons 22 are actuated by controlling the pressure of the fluid in the chamber 72. To maintain pressure vessel integrity, rotary seals 74 are provided which allow a small amount of lubricating flow past them while operational. These rotary seals 74 are leak-proof from the other direction while static. This reduces running friction and prevents wear while operational, preserving the seal 74 material for its subsequent static high pressure holding function.

In more detail, the body 16 is sealed relative to the housing 14 by a pair of seals 74 which are axially spaced along the body 16, and which straddle the pistons 22. The seals 74 are arranged to provide a static pressure barrier to prevent fluid flow past the seals when the body 16 is stationary. The seals 74 are also arranged (by suitable shaping and/or selection of materials for the seal) so that a degree of leakage past the seals 74 is allowed when the body 16 is rotated relative to the housing 14. This lubricates the seal 74 and facilitates rotation of the body 16. It will be understood that the pressure of the fluid in the chamber 72 will be greater than that outside the chamber, creating a pressure differential across the seals 74 which will result in fluid egress from the chamber (to lubricate the seals), but which will prevent ingress of fluids into the chamber. The static seal will also prevent fluid ingress in the event that external pressure is greater when the tool 12 is deactivated, and so when the body 16 is stationary. The lubricating flow past the rotary seals 74 is collected within a fluid storage chamber 76, which takes the form of a plunger-style pressure compensated oil bath, to prevent environmental contamination. The seals 74 communicate with the fluid storage chamber 76, which stores fluid which has leaked past the seals. In the illustrated embodiment, the fluid storage chamber 76 is pressure compensated, the tool 12 comprising a pressure compensating arrangement 78 for communicating the pressure of fluid external to the pressure chamber (in the bore of the BOP 10) to the fluid in the storage chamber 76. This reduces the pressure differential across the seals 74. The pressure compensating arrangement 78 comprises a plunger or piston 80 mounted for movement relative to the fluid storage chamber, the plunger having a first face 82 exposed to fluid in the fluid storage chamber 76, and a second face 84 exposed to the fluid external to the fluid storage chamber 76. In this way, the pressure differential between the first and second plunger faces 82, 84 causes movement of the plunger 80 so that the external pressure can be communicated to the fluid in the fluid storage chamber 76. The chamber 76 housing the plunger 80 is pre- filled to allow adequate capacity, to ensure it does not top-out during the tubing the severing operation as fluid flows into the chamber 76.

The tool 12 also comprises a shock absorbing arrangement (not shown) associated with the tubing severing devices 18. The shock absorbing arrangement may take the form of an accumulator, and compensates for hydraulic shock loads imparted on the pistons 22 due to sudden movement of the blades 20. For example, as the body 16 rotates and indents the blades 20 into the casing 3, there comes a point where one or more of the blades 20 will break through a wall of the casing 3 in a relatively sudden, free movement. As the body 16 is rotating, the blade 20 will then encounter a portion of the wall which has not yet been breached, and will be urged sharply back in the opposite direction (radially outwardly). This could result in a hydraulic shock load on the piston 22, which is absorbed by the shock absorbing arrangement. The shock absorbing arrangement is similar to the pressure compensating arrangement 78, and so comprises a shock absorbing chamber which communicates with the pressure chamber 72, typically with the cylinders 48. A plunger or piston is mounted for movement relative to the shock absorbing chamber, and has a first face exposed to fluid in the pressure chamber 72, and a second face exposed to fluid external to the shock absorbing chamber. In the alternative, the second face of the plunger may be exposed to a volume pre-charged with fluid, typically a compressible fluid such as a gas, at a desired pressure. In this way, the hydraulic shock load can be accommodated by movement of the plunger within the shock absorbing chamber. The accumulator (pre- charged to depth or pressure compensated) is used to provide some level of shock absorption, preventing pressure spikes which could otherwise cause excessive loading on the blades 20, and maintaining an even cut when the pistons 22 are characteristically reciprocating during the final stages of the cut process.

Turning now to Fig. 8, there is shown a cross-sectional side view an actuator 86, which forms part of a hydraulic injection syringe system, for controlling the operation of the tubing severing devices 18. As discussed above, the tubing severing devices 18 are hydraulically actuated, and so the actuator 86 is a fluid actuator for supplying hydraulic fluid to the severing devices 18 to actuate them. The pressure used to drive the tubing severing devices 18 onto the casing 3 surface is provided via the syringe system, and this is also used to draw the pistons 22 back. The actuator 86 is thus arranged to translate the pistons 22 within the cylinders 48, to urge the blades 20 towards the casing 3 to sever the casing when the body 16 is rotated within the housing by the drive arrangement 28. The actuator 86 is also arranged to control the return movement of the pistons 22 away from the casing 3 following severing. The actuator 86 supplies hydraulic fluid from a reservoir 88 in the actuator to the tubing severing devices 18, to actuate the devices. The reservoir 88 communicates with the pressure chamber 72 via a fluid line 90 and an injection port 92 in the housing 14, and so acts on all the pistons 22 of the severing devices 18 in unison. The actuator 86 comprises a piston 94 which is advanced and retracted to expel fluid from the reservoir 88, or draw fluid back into the reservoir (and thereby control movement of the pistons 22), by a hydraulic motor 96. The motor 96 is coupled to the piston 94 via a drive shaft 98, which advances and retracts the piston 94. The actuator 86 may be provided as an integral part of the tool 12, or separately and coupled to the tool when required to operate the tool to sever the casing 3. The actuator 86 may thus be carried, for example, by an ROV (not shown) and coupled to the port 92 in the housing 14 when required. In the alternative, the hydraulic actuating fluid may be provided by the ROV, which can be coupled to the tool via a stab-plate associated with the tool 12, or in a 'hot stab' scenario via a direct coupling with the tool 12.

Power delivery to the tool 12 can therefore be achieved by an energy storage device (the actuator 86), which is pre-set to achieve a complete cut within full expenditure of the stored energy. This is achieved by pre-charging the actuator reservoir 88 with the requisite volume of fluid to perform the cut. Other energy storage devices could be employed.

The actuator 86 may comprise a control arrangement for selectively supplying fluid to the tubing severing devices, including a biasing element such as a spring (not shown) acting on the piston 94, for exerting a force on the piston to cause the piston to impart a fluid pressure force on the fluid in reservoir 88, and so on the fluid in the pressure chamber 72. A release mechanism (not shown) restrains movement of the piston 94 under the biasing action of the spring, and can be operated to release the piston so that the biasing element acts on the piston 94, to pressurise the fluid in the pressure chamber 72 and so act on the tubing severing devices 18.

As discussed above, the drive arrangement 28 extends through a wall of the main housing 14, the motor 32 being provided externally of the housing. This is also shown in the detail view of Fig. 9. A double seal barrier is provided between the drive arrangement 28 and the main housing 14, and includes a first seal 98 and a second seal 99. The first seal 98 is provided on a hollow mounting rod 100, which houses the rotating drive shaft 34, and which serves for mounting the drive arrangement 28 to the housing 14 via a mounting 101. A cap 102 surrounds the part of the drive arrangement 28 which protrudes from the housing 14, and the second seal 99 is provided between the cap 102 and the housing 14.

In general terms, a tubing severing device 12 is disclosed for severing tubular members (e.g. the casing 3) within a preinstalled pressure vessel (the housing 14), which may be in a BOP, wellhead or spool piece, located subsea or on a platform surface. The tool 12 cleanly severs tubular members, and the cut profile which is formed has very little deformation leading to simple re-entry, with very few metallic cuttings created during the severing process. The tool 12 provides the ability to cut at the same location every time, and has been designed with the intention of being used in conjunction with casing drilling methods such as that disclosed in WO-2006/010906 discussed above. The tool is suitable for use as part of an emergency disconnect package, or as a modular disconnect tool.

The tool 12 comprises the bearing mounted rotating body 16 located within a pressure vessel, in the form of the housing 14. The tubing severing or cutting devices 18 are driven inwardly onto the tubular member surface via applied hydraulic pressure. The cutting device 18 design is specific for a separation style of cutting, and therefore there are no sliding faces. Instead, the cutting blades or elements 20 are free to roll over the outside of the tubular member (casing 3) while being indented into the wall. To ensure the cutting blades 20 all cut within the same groove, they are guided linearly on the set of rear- mounted pins 54. These prevent the pistons 22 from swivelling around their centres and hold all cutting blades 20 in the same plane during the early stages of the cut operation. When performing a cut with the tubular member (casing 3) in tension, the cutting blades 22 are exposed to stress that could lead to breaking of the cutting elements. The axial mounting of the cutting blades 20 inside the pistons 22, including the compressible element (washer 42), allows the cutting blades 20 to rise vertically during the cut, thereby reducing stress loading.

The tool 12 could be built into the wall of any pressure vessel that is part of any system which requires a casing disconnect, for example BOPs or wellheads. In the latter case, the tool 12 could therefore be built into the wellhead 11 shown in Fig. 1. The tool 12 could also be provided as a modular unit that can be connected to a similar system of

components, allowing for a simple means of severing tubular members during drilling. The modular housing could be adapted to suit most types of connectors. Accordingly, whilst the tubing severing tool 12 has a particular utility in a well shut-off device or a wellhead, it will be understood that the tool 12 may have a utility with many other types of devices and/or in many different scenarios. The tool, in particular the main housing, may be adapted for connection to other devices, and may be coupled to or provided as part of a relatively short length of tubing such as a spool piece, for connection to or provision as part of such other devices. The tool, in particular the main housing, may carry appropriate connectors, such as flanges or threads, for connection to or provision as part of such other devices.

Various modifications may be made to the foregoing without departing from the spirit or scope of the present invention. For example, whilst reference is made to mounting of the tubing severing elements in such a way that movement of the elements relative to the body in an axial direction is permitted, it will be understood that the same effect could be achieved by mounting the body itself for axial movement relative to the housing. The load resisting element may be shaped so as to allow a desired degree of deformation, and may be a spring or sprung element. The load resisting element may be a Belleville washer or the like. Metal or metal alloy materials may then be most suitable. The load resisting element may be arranged so that axial movement of the tubing severing element imparts a tensile load on the load resisting element. The load resisting element may therefore be a tensionable element. The load resisting element may be coupled to both the tubing severing element and the mounting member, so that the tensile load can be imparted on the load resisting element. The load resisting element may be a spring or sprung element.