WO2015185905A1

WO2015185905A1 - Downhole tool & method

Info

Publication number: WO2015185905A1
Application number: PCT/GB2015/051590
Authority: WO
Inventors: Neil Andrew Abercrombie Simpson; Wojciech Buczak
Original assignee: PARADIGM DRILLING SERVICES Ltd
Current assignee: PARADIGM DRILLING SERVICES Ltd
Priority date: 2014-06-01
Filing date: 2015-06-01
Publication date: 2015-12-10
Anticipated expiration: 2016-12-01
Also published as: GB201409816D0

Abstract

A downhole tool (10) for drilling, reaming or cutting a borehole (B) comprises a body (12)and a numberof bore-engaging members (14) which are moveable between a first, retracted, position relative to the body (12) and a second, extended, position relative to the body (12). A first piston member (56) is disposed in the body (12) and is operable to move the bore-engaging members (14) in a first direction relative to the body (12).A second piston member (58) which is coupled to the mandrel (22) is operable to move in a second direction relative to the body (12). In use, engagement between the bore-engaging members (14) and the mandrel (22)as a result of either or both of the movement of the first and second piston members urges the bore-engaging members (14)to the second, extended, position.

Description

DOWNHOLE TOOL & METHOD

FIELD

This invention relates to a downhole tool and method. More particularly, but not exclusively, embodiments of the present invention relate to an expandable downhole drilling or reaming tool and to a method for reaming or drilling a borehole.

BACKGROUND

Within the oil and gas industry, in order to access subsurface hydrocarbons a well borehole is typically drilled from surface, the borehole then being lined with sections of bore-lining tubing.

In order to extend the life of existing pre-drilled well boreholes and to increase the amount and recovery rate of hydrocarbons within the reservoir formation in the most cost effective manner, "through tubing" drilling may be employed to extend the borehole beyond the existing lined section and into previously untapped regions of the reservoir formation. In some instances, the extended borehole may be lined ("cased hole") while in other instances the extended borehole may not be lined ("open hole").

Through tubing drilling may be carried out by running a drilling tool through the existing borehole, the drilling tool then being operated to extend the borehole to the required depth/distance. In some instances, the drilling tool may be conveyed on coiled tubing. In other instances, the drilling tool may be conveyed on small diameter jointed drill pipe which may or may not be operated in rotary mode.

Conventional techniques and equipment for through tubing drilling, however, suffer from a number of drawbacks. For example, in order to extend a borehole it is often necessary to enlarge the borehole beyond the diameter of the tubing or liner higher up the borehole. In larger diameter boreholes, this may be achieved using a bi- centre drill bit, expandable drilling reamer or under reaming tool used elsewhere in the industry. However, conventional bi-centre drill bit and reaming tools do not readily scale down for use in small diameter boreholes without compromises in the physical strength, functionality, reliability and fail safe characteristics required for use in this specialized area of drilling. SUMMARY

According to a first aspect, there is provided a downhole tool comprising:

a body;

a bore-engaging member for drilling, reaming or cutting a borehole, the bore- engaging member moveable between a first, retracted, position relative to the body and a second, extended, position relative to the body; and

an activation arrangement for moving the bore-engaging member between the first, retracted, position and the second, extended, position, the activation arrangement comprising a mandrel, a first piston member operable to move in a first direction relative to the body and a second piston member operable to move in a second direction relative to the body, movement of at least one of the first piston member in said first direction and the second piston member in said second direction urging the bore-engaging member from the first, retracted, position to the second, extended, position.

In use, a downhole tool according to embodiments of the present invention may be run downhole in a first configuration in which the bore-engaging member defines the first, retracted, position relative to the body and, on reaching a desired location, reconfigured to a second configuration in which the bore-engaging member defines the second, extended, position in order to engage the borehole and perform a downhole operation.

Beneficially, a downhole tool according to embodiments of the present invention is capable of deployment into and through existing bore lining tubing and permits a borehole operation, such as a borehole reaming operation, borehole enlargement operation, or borehole extension operation, to be carried out. Embodiments of the invention thus provide, amongst other things, a simple and robust expandable reaming tool which will fit into the restricted design envelope for small diameter or "slim bore" applications whilst still maintaining the physical strength, functionality, reliability and fail safe characteristics required to provide a downhole expandable reaming tool for use in this specialized area of drilling, and which will fail safe and be recoverable from the well bore through the restrictions which it must pass.

In particular embodiments, the activation arrangement comprises a fluid activated activation arrangement.

The first piston member may be axially moveable relative to the body.

In use, axial movement of the first piston member may urge the bore-engaging member from the first, retracted, position to the second, extended, position. The first piston member may be moveable in response to a fluid pressure acting on the first piston member.

The first piston member may be moveable in response to a fluid pressure differential acting across the first piston member.

The first piston member may be moveable in response to a fluid pressure or fluid pressure differential exceeding a threshold fluid pressure or flow rate.

In particular embodiments, the fluid pressure acting on or fluid pressure differential acting across the first piston member may be generated by fluid directed through the downhole tool.

In use, an increase in fluid flow through the downhole tool may generate the fluid pressure which moves the first piston member and thereby urges the bore- engaging member towards the second, extended, position.

A first side of the first piston member may communicate with the fluid directed through the downhole tool.

A second side of the first piston member may communicate with fluid in an annulus between the downhole tool and the borehole.

The first piston member may be annular.

The first piston member may comprise a fluid flow passage for directing flow towards the bore-engaging member. In use, fluid may be directed through the fluid flow passage of the first piston member to direct flow over the bore-engaging member, and thereby clean the bore-engaging member.

The downhole tool may comprise a nozzle arrangement communicating with the fluid flow passage of the first piston member.

The second piston member may be axially moveable relative to the body.

In use, axial movement of the second piston member may urge the bore- engaging member from the first, retracted, position to the second, extended, position.

The second piston member may be moveable in response to a fluid pressure acting on the second piston member.

The second piston member may be moveable in response to a fluid pressure differential acting across the second piston member.

The second piston member may be moveable in response to a fluid pressure or fluid pressure differential exceeding a threshold fluid pressure or flow rate.

In particular embodiments, the fluid pressure acting on or fluid pressure differential acting across the second piston member may be generated by fluid directed through the downhole tool. In use, an increase in fluid flow through the downhole tool may generate the fluid pressure which moves the second piston member and thereby urges the bore- engaging member towards the second, extended, position.

A first side of the second piston member may communicate with fluid directed through the downhole tool. A second side of the second piston member may communicate with fluid in an annulus between the downhole tool and the borehole.

The second piston member may be annular.

The downhole tool may define a fluid chamber between the first piston member and the second piston member.

The fluid chamber communicates with the fluid directed through the downhole tool.

In use, part of the fluid flow through the downhole tool may be communicated to the fluid chamber in order to apply the fluid pressure to move the first and second piston members.

The downhole tool may comprise at least one lateral port.

The at least one lateral port may permit fluid communication with the first piston member and the second piston member.

The at least one lateral port may permit fluid communication with the fluid chamber.

The mandrel may be tubular.

The mandrel may comprise an axial throughbore.

The at least one lateral port may be provided in the mandrel.

The mandrel may be profiled.

The mandrel may comprise a first profile portion. The first profile portion may be configured to urge the bore-engaging member to the second, extended, position on relative movement between the mandrel and the bore-engaging member.

The first profile portion may comprise a ramp profile.

The mandrel may comprise a single first profile portion or a plurality of first profile portions.

The mandrel may comprise a second profile portion. The second profile portion may be configured to lock the bore-engaging member in the second, extended, position. The second profile portion may define a raised or upset portion relative to a longitudinal axis of the mandrel. The second profile portion may define a landing surface which prevents movement of the bore-engaging member towards the first, retracted, position. The mandrel may be disposed through the first piston member.

In particular embodiments the mandrel may comprise a separate component and may be coupled to the second piston member. A coupling may be provided between the mandrel and the second piston member. The coupling may be of any suitable form. In particular embodiments, the coupling may comprise a threaded coupling.

In use, movement of the second piston member may move the mandrel and thereby urge the bore-engaging member towards the second, extended, position.

Thus, in particular embodiments the first piston member may directly engage or move into direct engagement with the bore-engaging member whereas the second piston member may indirectly engage the bore-engaging member via the mandrel.

In other embodiments, the mandrel may be integrally formed with the second piston member. In such embodiments, the features of the mandrel may be considered as forming part of the second piston member.

The downhole tool may be lockable in the first configuration.

At least one of the body and the bore-engaging member may be configured to lock the downhole tool in the first configuration. For example, the body may retain the bore-engaging member in the first configuration.

The downhole tool may be lockable in the second configuration.

In particular embodiments, the downhole tool is lockable in both the first configuration and the second configuration.

Beneficially, the ability to lock the downhole tool in the first configuration ensures the downhole tool does not activate prematurely. The ability to lock the downhole tool in the second configuration permits the downhole tool to maintain the bore-engaging member in the second, extended, position while supporting the torsional drilling loads, compressive loads and/or compressive end loads experienced by the downhole tool during operation.

The downhole tool may comprise a lock arrangement.

The mandrel may form part of a lock arrangement.

In particular embodiments, the downhole tool comprises a lock arrangement.

The bore-engaging member may be lockable in the second, extended, position.

The body may be of any suitable form and construction.

The body may be tubular.

The body may comprise an axial throughbore. In use, the longitudinal bore may facilitate the flow of fluid through the tool. The tubular body may be configured for coupling to a tubular string, for example but not exclusively a drill string, a running string, a bore-lining tubular string, a completion string, or the like. In particular embodiments, the tubular body may be configured for coupling to the string at an intermediate position in the string. Alternatively, the tubular body may be configured for coupling to the string at an end of the string, such as a distal end of the string.

The body may comprise or define a radially upset portion.

The body may comprise a window. In use, the bore-engaging member may extend through the window. The window may comprise a slot. One window may be provided for each bore-engaging member. In embodiments, comprising a plurality of windows, the windows may be circumferentially arranged. The body may retain the bore-engaging member in the first configuration until the bore-engaging member is aligned with the window.

The downhole tool may be biased towards the first configuration. Beneficially, biasing the downhole tool towards the first configuration provides for fail-safe operation, facilitating removal of the downhole tool from the borehole in the event of failure of the activation arrangement. Alternatively, or additionally, biasing the downhole tool towards the first configuration permits the downhole tool to negotiate obstructions in the borehole which may otherwise prevent or at least hinder withdrawal of the downhole tool from the borehole.

The downhole tool may be configured to be adopt or return to the first configuration in response to the fluid pressure or fluid flow below a selected threshold.

The downhole tool may comprise a biasing arrangement for biasing the downhole tool towards the first configuration.

The biasing arrangement may comprise a biasing member, such as a spring.

In use, the spring may urge the bore-engaging member towards the first, retracted, position relative to the body.

The biasing arrangement may comprise a plunger member, pusher rod or the like. The plunger member, pusher rod or the like may be interposed between the biasing member and the bore-engaging member. The plunger member, pusher rod or the like may comprise a tapered end face for engaging a corresponding tapered end face of the bore-engaging member. In use, engagement between the tapered end face of the plunger member, pusher rod or the like and the tapered end face of the bore- engaging member urges the bore-engaging member towards the first, retracted, position. The biasing arrangement may be disposed in or on the body. The biasing arrangement may lock or act towards locking or retaining the downhole tool in the first configuration.

The downhole tool may comprise a retainer for securing the first piston member relative to the body. The retainer may comprise one or more shear pin or the like. The retainer may lock or act towards locking or retaining the downhole tool in the first configuration.

The bore-engaging member may be of any suitable form and construction.

In the first, retracted, position the bore-engaging member may be disposed within the body, that is the bore-engaging member may not extend to a greater radial extent than the body. In this first position, the bore-engaging member may facilitate run in of the downhole tool through the bore-lining tubing, through bore restrictions or otherwise through the borehole.

In the second, extended, position the bore-engaging member may extend beyond the body, that is the bore-engaging member may extend to a greater radial extent than the body. In this second position, the bore-engaging member may engage the borehole to ream, drill or otherwise cut the borehole.

The bore-engaging member may comprise a reaming member.

The downhole tool may comprise a single radially extendable member.

The downhole tool may comprise a plurality of radially extendable members. In particular embodiments, the downhole tool may comprise three bore- engaging members.

The bore-engaging member may comprise a cutter arrangement.

The cutter arrangement may comprise a fixed cutter arrangement.

The cutter arrangement may comprise a plurality of cutter elements, such as PDC cutter elements or the like.

The downhole tool may comprise a top sub.

In particular embodiments, the top sub may be configured for coupling to the mandrel.

In other embodiments, the top sub may be integrally formed with the top sub. The downhole tool may comprise a bottom sub.

In other embodiments, the top sub may be integrally formed with the top sub. The bottom sub may comprise or form a cap of the downhole tool. In use, the bottom sub may be coupled to the body, and ensure that the bore-engaging member is retained within the body.

The downhole tool may comprise a connector for coupling the body to a tubular string. The connector may be of any suitable form. The connector may, for example, comprise at least one of a mechanical connector, fastener, adhesive bond, or the like. In some embodiments, the connector may comprise a threaded connector at one or both ends of the body. In particular embodiments, the connector may comprise a threaded box connector at a first end of the body and a threaded box connector at a second end of the body, although it will be understood that either or both of the box connectors may alternatively comprise threaded pin connectors or other suitable connector.

The downhole tool may comprise or may be provided in combination with a drilling tool, such as a drill bit or the like.

According to a second aspect there is provided a method of drilling or reaming a wellbore, the method comprising:

providing a downhole tool according to the first aspect in a borehole;

reconfiguring the downhole tool from a first, run in, configuration to a second, deployed, configuration using an activation arrangement comprising a first piston member operable to move in a first direction relative to the body and a second piston member operable to move in a second direction relative to the body, movement of at least one of the first piston member in said first direction and the second piston member in said second direction urging a bore-engaging member of the downhole tool from a first, retracted, position relative to the body to a second, extended, position relative body to engage the borehole.

The method may comprise running the downhole tool into the borehole. In some embodiments, the downhole tool may be run into the borehole on coiled tubing. In other embodiments, the downhole tool may be run into the borehole on drill pipe.

The method may comprise directing fluid through the downhole tool to activate the activation arrangement of the downhole tool.

The method may comprise drilling the borehole.

The method may comprise reaming the borehole. The method may comprise under-reaming the borehole.

The method may comprise translating the downhole tool to at least one of extend the borehole and enlarge or ream the borehole. The method may comprise translating the downhole tool in a downhole direction to extend the borehole.

The method may comprise translating the downhole tool in an uphole direction to enlarge or ream the borehole.

It should be understood that the features defined above in accordance with any aspect of the present invention or below in relation to any specific embodiment of the invention may be utilised, either alone or in combination, with any other defined feature, in any other aspect of the invention. BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 shows a side view of a downhole tool according to an embodiment of the present invention, in a first configuration;

Figure 2 shows a side view of the downhole tool shown in Figure 1 , in a second configuration;

Figure 3 shows a longitudinal section view A-A of the downhole tool shown in

Figure 1 , in the first configuration;

Figure 4 shows an enlarged view of part of the downhole tool shown in Figure

3;

Figure 5 shows a longitudinal section view B-B of the downhole tool shown in Figures 1 to 4, in the second configuration;

Figure 6 shows an enlarged view of part of the downhole tool shown in Figure

5;

Figure 7 shows a cross sectional view C-C of the downhole tool shown in Figures 1 to 6, in the second configuration;

Figure 8 shows an alternative longitudinal section view D-D of the downhole tool shown in Figures 1 to 7, in the second configuration;

Figure 9 shows a cross sectional view E-E of the downhole tool shown in Figure

7;

Figure 10 shows an enlarged view of part of the downhole tool shown in Figures 1 to 9;

Figure 11 shows an enlarged view of another part of the downhole tool shown in Figures 1 to 10, in the first configuration; and

Figure 12 shows an enlarged view of the part of the downhole tool shown in Figure 1 1 , in the second configuration. DETAILED DESCRIPTION OF THE DRAWINGS

Referring first to Figures 1 and 2 of the accompanying drawings, there are shown side views of a downhole tool 10 according to an embodiment of the present invention. Figure 1 shows the downhole tool 10 in a first, run-in, configuration. Figure 2 shows the downhole tool 10 in a second, deployed, configuration.

In use, the downhole tool 10 is run into a borehole (shown diagrammatically by B) in the first configuration and reconfigured to the second configuration in order to perform a downhole operation. In the illustrated embodiment, the downhole tool 10 takes the form of an expandable drilling reamer and the downhole operation comprises at least one of drilling, reaming and/or under-reaming operations in order to extend or expand the borehole B.

As shown in Figures 1 and 2, the downhole tool 10 comprises a body 12, a plurality of bore-engaging members which in the illustrated embodiment take the form of cutter arms 14 having a number of fixed cutter PDC inserts 16 mounted thereon, a top sub 18 for coupling the downhole tool 10 to an adjacent component or tool T1 , a bottom sub 20 for coupling the downhole tool 10 to an adjacent component or tool T2 and a mandrel 22.

In the illustrated embodiment, the downhole tool 10 comprises three circumferentially arranged and spaced cutter arms 14. However, it will be recognised that the downhole tool 10 may comprise any suitable number of cutter arms 14.

Each of the cutter arms 14 is both axially moveable relative to the body 12 and radially moveable between a first, retracted, position as shown in Figure 1 and a second, extended, position as shown in Figure 2 and as will be described further below, the downhole tool 10 further comprises an activation arrangement - represented generally by 24 - for urging the cutter arms 14 from the first position to the second position.

In use, the downhole tool 10 is run into the borehole B with the cutter arms 14 in the first position. On reaching the desired location, the activation arrangement 24 then reconfigures the downhole tool 10 from the first configuration to the second configuration by moving the cutter arms 14 from the first position to the second, extended, position whereby the cutter arms 14 are positioned to engage the borehole B and perform the borehole operation or operations. In the illustrated embodiment, the downhole tool 10 comprises three circumferentially arranged and spaced cutter arms 14. However, it will be recognised that the downhole tool 10 may comprise any suitable number of cutter arms 14.

Referring now also to Figures 3 to 8 of the accompanying drawings, there are shown section views of the downhole tool 10. Figure 4 shows an enlarged view of part of the downhole tool shown in Figure 3. Figure 5 shows a longitudinal section view B-B of the downhole tool shown in Figures 1 to 4, in the second configuration. Figure 6 shows an enlarged view of part of the downhole tool shown in Figure 5. Figure 7 shows a cross sectional view C-C of the downhole tool shown in Figures 1 to 6, in the second configuration. Figure 8 shows an alternative longitudinal section view D-D of the downhole tool shown in Figures 1 to 7, in the second configuration.

As shown for example in Figure 3, the body 12 has a throughbore 26 extending therethrough. A plurality of circumferentially arranged and spaced bays or slots 28 are provided through the body 12 and, in use, the slots 28 permit the movement of the cutter arms 14 from the first position to the second position. One slot 28 is provided for each of the cutter arms 14 and so in the illustrated embodiment the body 12 comprises three circumferentially arranged and spaced slots 28. The body 12 further comprises a radially upset portion 30 which in the illustrated embodiment is disposed adjacent to the slots 28. In use, the radially upset portion 30 ensures that the cutter arms 14 are spaced/offset from the borehole B when the downhole tool 10 is run into the borehole B and a leading end (to the right as shown in the figures) of the upset portion 30 is tapered to facilitate passage of the downhole tool 10 into the borehole B. A downhole end portion 32 of the body 12 is directly coupled to the bottom sub 20 by a thread connection 34, a distal end face 36 of the body 12 abutting a corresponding shoulder 38 on the bottom sub 20.

The bottom sub 20 has a first portion 40 for coupling to the body 12 and which extends into the end portion of the body 12 and a second portion 42 defining a coupling 44 for connecting the downhole tool 10 to the component or tool T2. In the illustrated embodiment, the coupling 44 takes the form of a threaded box connection. However, it will be recognised that the coupling 44 may be of any suitable form and construction. The bottom sub 20 also functions as a cap, the cutter arms 14 being installed in the body 12 such that they can only be assembled if the bottom sub 20 is detached from the body 12 prior to assembly. The cutter arms are thus unable to be replaced or become detached from the body 12 without the removal or loss of the bottom sub 20, ensuring that the structural integrity of the downhole tool 10 is maintained during downhole operations.

The top sub 18 has a first portion 46 for coupling to the mandrel 22 via a threaded connection 48 and which extends over an uphole end portion 50 of the mandrel 22 and a second portion 52 defining a coupling 54 for connecting the downhole tool 10 to the adjacent component or tool T1. In the illustrated embodiment, the coupling 54 takes the form of a threaded box connection. However, it will be recognised that the coupling 54 may be of any suitable form and construction.

As described above, the downhole tool 10 is run into the borehole B with the cutter arms 14 in the first position and, on reaching the desired location, reconfigured by the activation arrangement 24 from the first configuration to the second configuration in which the cutter arms 14 are positioned to engage the borehole B and perform the borehole operation or operations.

As shown most clearly in Figures 4 and 6, the activation arrangement 24 comprises a first piston member 56 and a second piston member 58.

The first piston member 56 is disposed within the body 12. The first piston member 56 is radially interposed between the body 12 and the mandrel 22 and axially interposed between the cutter arms 14 and the second piston member 58.

The second piston member 58 is disposed within the body 12. The second piston member 58 is radially interposed between the body 12 and the mandrel 22 axially interposed between the first piston member 56 and the bottom sub 20. A first portion 60 of the second piston member 58 is disposed around and coupled to an end portion 62 of the mandrel 22 via a threaded connection 64. A second portion 66 of the second piston member 58 extends into the bottom sub 20, a shoulder 68 on the second piston member 58 engaging a no-go 70 (see Figure 3) on the bottom sub 20 to provide an end stop for movement of the second piston member 58.

The mandrel 22 is disposed within the body 12 and has a throughbore 72 which, in use, defines an axial throughbore or axial flow passage of the downhole tool 10, permitting fluid to be directed into and through the downhole tool 10. As described above, the mandrel 22 is coupled to the top sub 18 (at its end portion 50) via threaded connection 48 and to the second piston member 58 (at its end portion 62) via threaded connection 64.

Referring now also in particular to Figures 9 and 10 of the accompanying drawings, it can see that the mandrel 22 is profiled, the mandrel 22 having a first profile portion 74 and a second profile portion 76. In use, the profile portions 74, 76 of the mandrel 22 are used to urge the cutter arms 14 towards the second, extended, position and also permit the downhole tool 10 to be locked in both the first configuration and the second configuration.

The first profile portion 74 of the mandrel 22 comprises a first side surface 78, a top surface or crest 80 and a second side surface 82. The first side surface 78 defines a ramp profile for engaging corresponding ramp profiles 84 in the cutter arms 14 to urge the cutter arms 14 radially outwards on relative axial movement therebetween. The top surface 80 defines a landing profile which prevents movement of the cutter arms 14 radially inwards when the cutter arms 14 are in the second, extended, position and supports the cutter arms 14 against radial loading experienced during operation. The second side surface 82 is perpendicular or substantially perpendicular to the central longitudinal axis X of the downhole tool 10 and engages corresponding profiles 86 in the cutter arms 14. Engagement between the second side surface 82 and the corresponding profiles 86 in the cutter arms 14 facilitates locking the downhole tool 10 in the first configuration during run-in.

The second profile portion 76 of the mandrel 22 comprises a first side surface 88, a top surface or crest 90 and a second side surface 92. The first side surface 88 defines a ramp profile for engaging corresponding ramp profiles 94 in the cutter arms 14 to urge the cutter arms 14 radially outwards on relative axial movement therebetween. The top surface 90 defines a landing profile which prevents movement of the cutter arms 14 radially inwards when the cutter arms 14 are in the second, extended, position and supports the cutter arms 14 against radial loading experienced during operation. The second side surface 92 is perpendicular or substantially perpendicular to the central longitudinal axis X of the downhole tool 10 and defines an end stop for axial movement of the cutter arms 14. Engagement between the second side surface 92 and the corresponding profiles 96 in the cutter arms 14 facilitates locking the downhole tool 10 in the first configuration during run-in.

The mandrel 22 is rotationally and axially coupled to the body 12 via a spline connection 98. The spline connection 98 rotationally locks the mandrel 22 to the body 12 while permitting axial movement of the mandrel 22 relative to body 12.

The mandrel 22 further comprises an upset portion 100. In use, the upset portion 100 engages an end 102 of the spline connection 98 to limit stroke/travel of the mandrel 22.

One or more lateral port 104 is formed or provided through the mandrel 22, the lateral port or ports 104 communicating with a fluid chamber 106 between the first piston member 56 and the second piston member 58, the fluid chamber 106 being isolated by seals 108.

In use, fluid is directed from surface or from other fluid source through the downhole tool 10 via the axial throughbore 72, a portion of the fluid being directed through the lateral port or ports 104 into the fluid chamber 106 and generating a fluid pressure P on the first and second piston members 56, 58. This fluid pressure P urges the first piston member 56 in a first direction relative to the body 12 and the mandrel 22 to urge the cutter arms 14 towards the second position and urges the second piston member 58 and the mandrel 22 in a second direction relative to the body 12, opposite to the first direction, which also urges the cutter arms 14 towards the second, extended, position.

Referring now also in particular to Figures 11 and 12 of the accompanying drawings, the downhole tool 10 further comprises a biasing arrangement 110 for biasing the downhole tool 10 towards the first, run in, configuration. The biasing arrangement 1 10 comprises a plunger or pusher rod 112 which is spring loaded in the body 12 via a spring 1 14, which in the illustrated embodiment comprises a coil spring. A distal end face 1 16 of the pusher rod 1 12 is tapered and engages a corresponding tapered end face 1 18 of the cutter arms 14. In the illustrated embodiment, one pusher rod 1 12 and spring 114 are provided for each of the cutter arms 14. However, it will be understood that one pusher rod 112 and spring 114 may be operatively associated with a plurality of the cutter arms 14. In use, the biasing arrangement 110 acts to urge the cutter arms 14 towards the first, retracted, position and so maintain the downhole tool 10 in the first, run-in, configuration unless acted upon by the activation arrangement 24 or until the pressure P exceeds a selected threshold which overcomes the spring force of the spring 114. The biasing arrangement 110 acts to lock the downhole tool 10 in the first configuration. Moreover, the biasing arrangement 110 also provides for fail safe operation by urging the downhole tool 10 towards the first configuration in the event of failure of the activation arrangement 24, permitting the downhole tool 10 to be safely removed from the borehole B.

In the illustrated embodiment, the downhole tool 10 further comprises a retainer

120 disposed between the body 12 and the first piston member 56. The illustrated retainer 120 comprises a shear pin extending through the body 12 and into the first piston member 56. However, it will be recognised that any suitable retainer, such a ball retent arrangement or the like, may be used. In use, the retainer 120 acting on the first piston member 56 to temporarily lock the operation of the downhole tool 10 and, for example, permit limited circulation of fluid through the downhole tool 10 without activating the tool 10.

Referring now also in particular to Figure 8 of the accompanying drawings, which shows an alternative longitudinal section view of the downhole tool 10 to that shown in Figure 5, it can be seen that the first piston member 56 comprises a fluid flow passage or gallery 122 for directing flow towards the cutter arms 14, a nozzle arrangement 124 being provided at an end of the fluid flow passage or gallery 122 and communicating with the fluid flow passage or gallery 122 of the first piston member 56. In use, fluid may be directed from the fluid chamber 106 through the fluid flow passage 122 and nozzle arrangement 124 to direct flow over the cutter arms 14 so as to clean material from the cutter arms 14 and/or for cooling purposes.

Operation of the downhole tool 10 will now be described with reference to all of the accompanying drawings.

The downhole tool 10 is initially configured in the first, run in, configuration and is run into the borehole B on a suitable conveyance, such as coiled tubing, drill pipe string, or other running string. In this first configuration, the cutter arms 14 are in the first, retracted, position within the body 12 of the downhole tool 10 and so the downhole tool 10 is capable of running through the bore-lining tubing T and traversing obstructions in the borehole B. As described above, the retainer temporarily locks the downhole tool 10, permitting a degree of circulation of fluid through the downhole tool 10 without activation.

Once located at the desired depth in the borehole B, the downhole tool 10 is activated by increasing drilling fluid flow from surface through the throughbore 72. A portion of the fluid flow is directed through the lateral ports 104 and into the chamber 106 which, due to the pressure differential between the fluid in the chamber 106 and fluid in the annulus A, acts to urge the first piston member 56 in the first direction relative to the body 12 (to the left as shown in the figures). The first piston member 56 pushes the cutter arms 14 axially upwards (to the left as shown in the figures) against the conical ramp surface 76 of the first profile portion 74 and the ramp surface 86 of the second profile portion 76 of the mandrel 22, the inter-engaging faces 76,86,84,94 of the mandrel 22 and the cutter arms 14 urging the cutter arms 14 to move upwards within the slots/bays 28 in the body 12 and radially outwards relative to the central longitudinal axis X of the body 12. Movement of the cutter arms 14 pushes the respective pusher rods 1 12 to compress the springs 114 to the point where they bottom out on the upper side portions of the slots 28, preventing any further upward longitudinal travel of the cutter arms 14.

As described above, a portion of the fluid flow is directed through the lateral ports 104 and into the chamber 106 which, due to the pressure differential between the fluid in the chamber 106 and fluid in the annulus A, acts to urge the first piston member 56 in the first direction relative to the body 12 (to the left as shown in the figures). At the same time, the pressure differential also acts on the second piston member 58 which is attached to the mandrel 22 but free to move longitudinally within the bore of the body 12. This has the effect of urging the mandrel 22 to move inboard against the cutter arms 14 now locked between the first piston member 56 and the pusher rods, further locking the cutter arms 14 in the outboard position such that side loading on the arms 14 - no matter how high - is not capable of forcing them radially inwards from their locked outboard position. Compressive weight on the top sub 18 applied in order to carry out the reaming process further locks the mandrel 22 in this inboard position.

During operation, rotational drive loads required for reaming are transmitted between the top sub and the body 12 by means of a splined section. Tensile loads pulling loads between the top sub and the body 12 are supported by the upset section on the central mandrel 22 abutting against the lower end of the splined section. In the illustrated embodiment, and as described above, fluid pumped through the downhole tool 10 may be partially diverted through the flow passages in the first piston member 56 and channelled through the nozzles to direct fluid flow onto the PDC cutting structure of the cutter arms 14 for cooling and cleaning purposes.

Following the downhole operation, or otherwise where it is desired to deactivate the downhole tool 10, the downhole tool 10 may be de-activated by release of pressure entering the ports by reducing or stopping the fluid flow through the throughbore. This releases the hydraulic force acting on the first piston member 56, allowing the spring loaded pusher rods to push the cutter arms 14 towards the first, retracted, position within the body 12. Alternatively or additionally the action of pulling back when retrieving the downhole tool 10 from the borehole B has the effect of pulling on the top sub which - by virtue of the threaded connection with the mandrel 22 - de- supports the cutter arms 14, allowing the downhole tool 10 to return to the first configuration. This provides an additional fail safe closure mechanism of the cutter arms 14 should for any reason the pusher rods not be able to return to their inboard locked position. Beneficially, embodiments of the present invention thus provide a downhole tool (10) for drilling, reaming or cutting a borehole (B) comprising a body (12) and a number of bore-engaging members (14) which are moveable between a first, retracted, position relative to the body (12) and a second, extended, position relative to the body (12). A first piston member (56) is disposed in the body (12) and is operable to move the bore- engaging members (14) in a first direction relative to the body (12). A second piston member (58) which is coupled to the mandrel (22) is operable to move in a second direction relative to the body (12). In use, engagement between the bore-engaging members (14) and the mandrel (22) as a result of either or both of the movement of the first and second piston members urges the bore-engaging members (14) to the second, extended, position.

It will be recognised that embodiments of the present invention provide a downhole tool 10 suitable for through tubing drilling and/or reaming operations in small diameter tubing applications and which permits cutter arms 14 of the downhole to be locked inboard in their closed position and locked outboard in their open position in a way that they can support the torsional drilling loads, compressive side loads, and the compressive end loads required for the reaming operation in a slim hole expandable reaming tool for use in oil and gas wells. Moreover, the activation arrangement of the downhole tool 10 beneficially provides a double lock and release mechanism which prevents the cutter arms 14 from closure while deployed in the open position in high angle and horizontal drilling environments and at the same time provides a failsafe closure mechanism when the tool 10 is pulled out of the borehole B, ensuring that the downhole tool 10 can be withdrawn through the restrictions it negotiated while running into the section of borehole B that required enlarging in diameter.

It should be understood that the embodiment described herein is merely exemplary and that various modifications may be made thereto without departing from the scope of the invention.

Claims

1. A downhole tool comprising:

a body;

2. The downhole tool of claim 1 , wherein the first piston member is axially moveable in said first direction relative to the body.

3. The downhole tool of claim 1 or 2, wherein the first piston member is moveable in response to a fluid pressure acting on, or fluid pressure differential acting across, the first piston member.

4. The downhole tool of claim 3, wherein the fluid pressure acting on, or fluid pressure differential acting across, the first piston member is generated by fluid directed through the downhole tool.

5. The downhole tool of any preceding claim, wherein the second piston member is axially moveable in said second direction relative to the body.

6. The downhole tool of any preceding claim, wherein the second piston member is moveable in response to a fluid pressure acting on, or fluid pressure differential acting across, the second piston member.

7. The downhole tool of claim 6, wherein the fluid pressure acting on, or fluid pressure differential acting across, the second piston member is generated by fluid directed through the downhole tool.

8. The downhole tool of any preceding claim, comprising a fluid chamber between the first piston member and the second piston member for receiving fluid directed through the downhole tool.

9. The downhole tool of any preceding claim, wherein the mandrel is profiled.

10. The downhole tool of claim 9, wherein the mandrel comprises a first profile portion, engagement between the first profile portion and the bore-engaging member on relative movement between the mandrel and the bore-engaging member urging the bore-engaging member from the first position to the second, extended, position.

1 1. The downhole tool of claim 10, wherein the first profile portion comprises a ramp profile.

12. The downhole tool of any preceding claim, wherein the bore-engaging member is lockable in the first, retracted, position.

13. The downhole tool of any preceding claim, wherein the bore-engaging member is lockable in the second, extended, position.

14. The downhole tool of claim 13, wherein the mandrel comprises a second profile portion, engagement between the second profile portion and the bore-engaging member locking the bore-engaging member in the second, extended, position.

15. The downhole tool of claim 14, wherein the second profile portion defines a raised or upset landing surface relative to a longitudinal axis of the downhole tool.

16. The downhole tool of any preceding claim, wherein the mandrel is coupled to the second piston member, movement of the second piston member in the second direction moving the mandrel in the second direction.

17. The downhole tool of any preceding claim, wherein the mandrel comprises at least one lateral port.

18. The downhole tool of claim 17, when dependent on claim 8, wherein the at least one lateral port communicates with the fluid chamber.

19. The downhole tool of any preceding claim, comprising a biasing arrangement for biasing the bore-engaging member towards the first position.

20. The downhole tool of claim 19, wherein the biasing arrangement comprises a biasing member, such as a spring.

21. The downhole tool of claim 19 or 20, wherein the biasing arrangement comprises a pusher rod.

22. The downhole tool of any preceding claim, comprising a retainer for securing the first piston member relative to the body.

23. The downhole tool of claim 22, wherein the retainer comprises at least one of: a shear pin; and a ball retent device.

24. The downhole tool of any preceding claim, wherein in the first, retracted, position the bore-engaging member is radially disposed within the body and wherein in the second, extended, position the bore-engaging member extends to a greater radial extent than the body.

25. The downhole tool of any preceding claim, wherein the downhole tool comprises a reaming member.

26. The downhole tool of any preceding claim, wherein the downhole tool comprises a plurality of bore-engaging members.

27. The downhole tool of any preceding claim, wherein the bore-engaging member comprises a cutter arrangement.

28. The downhole tool of claim 27, wherein the cutter arrangement comprises a fixed cutter arrangement.

29. The downhole tool of claim 27 or 28, wherein the cutter arrangement comprises a plurality of cutter elements, such as PDC cutter elements.

30. The downhole tool of any preceding claim, wherein the first piston member comprises a fluid flow passage for directing flow towards the bore-engaging member.

31. The downhole tool of claim 30, comprising a nozzle arrangement communicating with the fluid flow passage of the first piston member.

32. A method of drilling or reaming a wellbore, the method comprising:

providing a downhole tool according to the first aspect in a borehole;

33. The method of claim 32, comprising running the downhole tool into the borehole.

34. The method of claim 32 or 33, comprising directing fluid through the downhole tool to activate the activation arrangement of the downhole tool.

35. The method of claim 32, 33 or 34, comprising at least one of drilling and reaming the borehole.

36. The method of any one of claims 32 to 35, comprising translating the downhole tool to at least one of extend the borehole and enlarge or ream the borehole.