GB2584841A

GB2584841A - Downhole tools and associated methods

Info

Publication number: GB2584841A
Application number: GB1908599.2A
Authority: GB
Inventors: Henry Walter Macfarlane Alastair; Mccrae Tulloch Rory; S Ivie Bradley
Original assignee: NOV Downhole Eurasia Ltd
Current assignee: NOV Downhole Eurasia Ltd
Priority date: 2019-06-14
Filing date: 2019-06-14
Publication date: 2020-12-23
Also published as: WO2020249730A1; GB201908599D0

Abstract

A downhole tool 300 comprising a housing, a tool component at least part of which is rotatable relative to the housing, a blocking assembly configured to selectively restrict flow through a fluid flow path in response to a change in fluid flow and to thereby cause the tool component to move from a first position to a second position. The tool component may be a roller cutter, or another cutting element that can be pivoted relative to the housing. The blocking assembly may comprise an occluding member 333, movable axially within the housing to block at least one flow path 344. A shear screw 307 may keep the occluding member in a first position until a sufficient fluid pressure is applied to the tool.

Description

Downhole tools and associated methods

FIELD

The present disclosure relates to downhole tools and associated apparatuses and methods. In some examples, those devices comprise downhole tools, actuation devices, etc.

BACKGROUND

When conducting operations downhole, for example drilling, it is often desirable to be able to activate, or reconfigure, a downhole tool. For example it may be desirable to reconfigure a tool component of the downhole tool from a retracted position to a deployed position. Accordingly, it may be necessary to actuate, activate or reconfigure a tool while it is in a bore in order to change its mode of operation or initiate a set procedure.

Given the environments in which such devices operate, actuation mechanisms are required that are effective and unlikely to be prone to failure. If a downhole tool does not correctly actuate in a timely/desired manner, the downhole tool/string may have to be removed from the wellbore, which can be time consuming and thus costly.

During drilling operations, typically a drill string having a downhole tool is deployed in a wellbore from the surface and lowered to a drilling location. The downhole tool will typically comprise a primary cutting structure at an end of the downhole tool for drilling through formation, casings or other materials encountered during downhole drilling operations. The downhole tool is normally connected to surface by the drill string.

During such operations, in some cases the downhole tool may need to be removed from the wellbore to be replaced. A downhole tool may need to be replaced due to wear or the need for an alternative, specialised, cutting structure to be deployed for the drilling operation to continue in an efficient manner. Typically, to replace the downhole tool the entire drill string must be pulled out from the wellbore such that the downhole tool can be replaced by operators at surface. The drill string is then deployed back into the wellbore so that drilling can continue.

During downhole operations, and particularly drilling operations, it is desirable to provide a more time and cost effective solution that is convenient and reliable. There is a continued desire to minimise the costs and improve the effectiveness of such drilling operations.

This background serves only to set a scene to allow a skilled reader to better appreciate the following description. Therefore, none of the above discussion should necessarily be taken as an acknowledgement that that discussion is part of the state of the art or is common general knowledge. One or more aspects/embodiments of the invention may or may not address one or more of the background issues.

SUMMARY

There are described downhole tools and associated apparatus and methods, particularly, in some examples, new and improved drill bits (for example constant-bore drill bits, expandable drill bits and hybrid drill bits) reamers (e.g. near-bit reamers), and/or activation mechanisms. The disclosed devices and method may provide better time and cost effective solutions that are convenient and reliable, and may improve the effectiveness of such downhole operations (e.g. drilling operations).

In one example, there is provided a downhole tool that may require replacing less frequently than existing downhole tools. The downhole tool of the present disclosure may allow a downhole operation -e.g. a drilling operation -to be completed with fewer deployments and pull out operations and thus reduce the time required for the operation.

The downhole tool may have an increased service life such that it needs replacing due to high wear less frequently. The downhole tool may be suitable for use with multiple different materials or formations, such that it needs replacing less frequently.

The present disclosure also provides actuation mechanisms that may be more robust, reliable and/or easier to activate than existing solutions. The actuation mechanisms described herein may be operable from the surface and may have a reduced rate of failure compared to existing designs. The actuation mechanisms may therefore reduce the incidence of actuation failure and thus reduce the risk of having to stop operations to withdraw a downhole tool or reduce the likelihood of well viability being affected by the failure of a downhole tool to actuate.

There is described a downhole tool for use in downhole drilling operations.

The downhole tool may be a drill bit.

The downhole tool may be an expandable drill bit.

The downhole tool may be a reamer for enlarging the diameter of a bore (e.g. an existing bore).

The downhole tool may have a tool component. The tool component may be an assembly of parts. The tool component may comprise a cutting structure. The cutting structure may be provided by or comprise a cutter or blade. The tool component may comprise any tool for use downhole -other examples of such tools may include sensors or probes.

The tool component may be configured to move from the first position to a second position.

The tool component, or a part thereof, may be configured to be rotatable relative to the outer housing. The tool component (or a part thereof) may be configured to rotate about an axis substantially parallel to the longitudinal axis of the downhole tool. Alternatively, the tool component (or a part thereof) may be configured to rotate about an axis substantially perpendicular to the longitudinal axis of the downhole tool.

The tool component, or a part thereof, may be configured to rotate while in the first position and/or the second position. For example, the tool component (or a part thereof) may be configured to rotate while operating in the first and/or second position. Alternatively, the tool component (or a part thereof) may be configured to rotate when moving from the first position to the second position. For example, the tool component(or a part thereof) may rotate from the first position to the second position.

The tool component, or a part thereof, may be configured to rotate from the first position, in which the tool component, or a part thereof, is in a retracted position, to a second position, in which the tool component, or a part thereof, is in a deployed position.

The tool component may comprise a cutter. A cutter may be any structure provided to engage with a rock face. Examples of cutters may include blades (for example with cutter inserts) and cutter blocks.

The tool component may comprise a cutter configured to be rotatable with respect to the outer housing. The cutter may be configured to rotate about an axis substantially parallel to the longitudinal axis of the downhole tool. Alternatively, the cutter may be configured to rotate about an axis substantially perpendicular to the longitudinal axis of the downhole tool.

The cutter may be configured to rotate while in the first position and/or the second position. For example, the cutter may be configured to rotate while operating in the first and/or second position. Alternatively, the cutter may be configured to rotate when moving from the first position to the second position. The cutter may be configured to rotate from the first position in which the cutter is in a retracted position, to a second position in which the cutter is in a deployed position.

The downhole tool may be a drill bit and the tool component may comprise a rotatable roller cutter. The tool component may comprise a plurality of rotatable roller cutters. The rotatable roller cutter may be employed in a cutting structure of the tool component. The rotatable roller cutter may be configured to engage a rock face when the tool component is in the second position. The rotatable cutter may be configured to rotate when engaging a rock face during drilling.

The rotatable roller cutter may be a roller cone bit. The rotatable roller cutter may comprise a conical section. The rotatable roller cutter may comprise a plurality of tungsten carbide inserts. The rotatable roller cutter may be configured to be rotatable relative to the outer housing. The rotatable roller cutter may be configured to be rotatable about its axis.

The tool component may be configured to move from a first position to a second position, in response to a flow control operation by a user.

The downhole tool may have a primary cutting or drilling structure and a deployable cutting or drilling structure. The deployable cutting or drilling structure may be selectively deployed during use. The deployable cutting or drilling structure may define a cutting diameter greater than, equal to, or less than the cutting diameter of the primary drilling structure.

The downhole tool may define a longitudinal axis which runs longitudinally through the centre of the downhole tool. The longitudinal axis may correspond to that of the bore in which the downhole tool operates.

The downhole tool may be an expandable drill bit and the expandable drill bit may define a first cutting diameter when the tool component is in a first position and a second cutting diameter when the tool component is in the second position. The second diameter may be larger than the first diameter.

The downhole tool may have an outer housing. The outer housing may comprise the primary cutting structure. The primary cutting structure may be fixed with respect to the outer housing. The primary cutting structure may define a first cutting plane and a first cutting diameter. Alternatively, the outer housing may not define a cutting structure.

The primary cutting structure may comprise a plurality of cutting inserts, arranged to cut into a material. The primary cutting structure may comprise a plurality of cutting inserts arranged to cut in an axial direction. The primary cutting structure may comprise a plurality of cutting inserts arranged to cut in a radial direction. The primary cutting structure may comprise a plurality of polycrystalline-diamond (PDC) cutter inserts. The primary cutting structure may comprise a plurality of blades.

The cutting inserts of the primary cutting structure may define a substantially flat cutting plane; the cutting plane may be parallel to the end face of the downhole tool (and hence primary cutting structure). The cutting plane may be an envelope of space to be cut by the primary cutting structure; accordingly, the cutting plane may indicate the material immediately in front of the downhole tool which is to be cut. The cutting plane has a diameter determined by the maximum radial cutting reach of the primary cutting structure (e.g. the cutting inserts thereof). Material outside of the cutting plane will not be cut by the downhole tool.

In other tools, the primary cutting structure may define a circumferential cutting plane. The primary cutting structure may be arranged to cut radially. The primary cutting structure may be configured to enlarge the gauge or an existing bore.

The cutting inserts may be arranged so as to ensure that a cut is provided across the entire cutting plane, including the centre of the cutting plane.

The downhole tool may also comprise a flow path arranged to let fluid flow through the downhole tool. The fluid may flow from an upstream end of the downhole tool, towards a downstream end of the downhole tool. The primary cutting structure may be on the downstream axial end of the downhole tool.

The fluid may be drilling fluid (e.g. drilling mud) and these terms may be used interchangeably herein.

The flow path may have an inlet for allowing fluid to enter the flow path. The inlet may be a single downhole tool inlet. The flow path may have an outlet, for allowing fluid to leave the flow path (and the downhole tool). The outlet of the flow path may be in an end face of the downhole tool. The outlet may be in an outer circumferential surface of the downhole tool or the housing thereof. The outlet may be in the primary cutting structure of the downhole tool, or in a curved side wall of the downhole tool. The flow path may connect an inlet of the downhole tool to an outlet of the downhole tool. The flow path may pass through the various components of the downhole tool -e.g. the tool component, or a deployable tool assembly. The flow path may pass around or through the activation mechanism.

The outlet may be configured to provide a restriction to flow. The outlet may create a pressure differential across the fluid flowing through the outlet.

The outlet may comprise a nozzle or valve.

The flow path may be arranged such fluid can flow substantially axially through the downhole tool.

The downhole tool may comprise a tool component. The tool component may be at least partially located within the outer housing. The tool component may be a deployable tool component. Any disclosure made herein relating to the tool component applies, mutatis mutandis, to a deployable tool component and vice versa.

The tool component may comprise a cutter. The cutter may be configured to be rotatable with respect to the outer housing. The cutter may be configured to rotate with respect to the outer housing.

The tool component may comprise a cutter configured to rotate from the first position in which the cutter is in a retracted position, to a second position in which the cutter is in a deployed position.

The cutter may comprise a blade. The cutter may be configured to rotate radially outwards from the outer housing. The cutter may be configured to rotate from the first position to the second position to increase the cutting diameter of the downhole tool. For example, the cutter may be configured such that the downhole tool functions as an expandable drill bit. Alternatively, the cutter may be configured such that the downhole tool functions as a reamer.

The cutter may comprise a roller cone bit. The cutter may be configured to about an axis parallel to the axis of the downhole tool. The cutter may be configured to rotate within the cutting structure during interaction with formation.

The tool component may comprise a plurality of ovoid inserts. The tool component may be configured to reduce the aggressiveness, e.g. the depth of cut, of the downhole tool (e.g. drill bit). Accordingly, in some examples, the deployable tool component may not be for actively cutting material, but rather for interacting with material during a cutting operation.

The tool component may be configured to reduce the depth of cut of the downhole tool. The downhole tool may have a primary cutting structure defining a cutting plane. The tool component may be configured to move from the first position to the second position towards the primary cutting structure. The second position of the tool component may be recessed with respect to the primary cutting structure. The tool component may comprise non-cutting inserts such that the tool component reduces the depth of cut of the downhole tool when the tool component is in the second position.

The tool component may be arranged to be axially movable. The (whole of the) deployable tool component may (only) move axially and parallel to the longitudinal axis of the downhole tool. The tool component may be axially movable from a first position to a second position. In the first position, the deployable cutting structure may be (axially) recessed with respect to the primary cutting structure.

The tool component may be arranged to move towards the primary cutting structure or cutting plane, to the second position.

The tool component may be or comprise a blade assembly or deployable blade assembly. A deployable blade assembly may be an example of a tool component. The deployable blade assembly may define a cutting structure, which may be referred to as the deployable cutting structure. The cutting structure may be defined by the cutter.

The first position of the tool component may be a retracted position and the second position of the tool component may be an extended, or deployed, position, in which the tool component is extended with respect to the retracted position. The tool component may be deployed to the second position.

The first position of the tool component may be an inactive position and the second position of the tool component may be an active position.

According to the disclosure is a downhole tool. The downhole tool may comprise an outer housing. The downhole tool may further comprise a flow path, which may be arranged to permit fluid flow through the downhole tool. The downhole tool may further comprise a tool component, which may be at least partially located within the outer housing. The tool component may be arranged to be movable from a first position to a second position. The downhole tool may further comprise an actuation mechanism, which may be configured to cause the tool component to move from the first position to the second position. The actuation mechanism may be a blocking assembly, which may be configured to move from a first arrangement to a second arrangement in response to a change in the flow of fluid through the downhole tool. In the first arrangement the flow path may be open and fluid may be able to flow through the flow path. In the second arrangement the blocking assembly may be arranged to restrict fluid flow through the flow path. The tool component may be configured to move from the first position to the second position under the action of fluid pressure in response to the blocking assembly moving to the second arrangement.

The tool component or a part thereof may be configured to be rotatable relative to the outer housing.

Further according to the disclosure is a downhole tool comprising: an outer housing; a flow path arranged to permit fluid flow through the downhole tool; a tool component at least partially located within the outer housing, the tool component being arranged to be movable from a first position to a second position; wherein the tool component or a part thereof is configured to be rotatable relative to the outer housing; an occluding member configured to move from a non-occluding position to an occluding position in which flow through the flow path is restricted; a first deformable or frangible member (e.g. a restraint) configured to hold the occluding member in the first arrangement and release the occluding member in response to a change in the flow of fluid through the downhole tool; a second deformable or frangible member (e.g. a release) configured to restrain the tool component in the first position and release the tool component in response to the occluding member moving to the occluding position.

A drill bit for drilling a bore according to the disclosure may comprise: an outer housing; a primary cutting structure defining a cutting plane of a first diameter; a flow path arranged to let drilling fluid flow through the drill bit; and a deployable blade assembly at least partially located within the outer housing, the deployable blade assembly may comprise a cutting structure and may be arranged to be axially movable from a first position, in which the deployable cutting structure is recessed with respect to the primary cutting structure, towards the cutting plane, to a second position; when the deployable blade assembly is in the second position, the deployable cutting structure may define a cutting diameter which is less thanor equal to the first diameter. When the deployable blade assembly is in the second position, the deployable cutting structure may alternatively define a cutting diameter which is more than or equal to the first diameter.

There is also described herein an actuation mechanism. The actuation mechanism may be for use in a downhole tool (e.g. a downhole tool) in a wellbore. The actuation mechanism may be a fluid-activated actuation mechanism. The fluid-activated actuation mechanism may be activated by a change in the flow of fluid through the downhole tool.

The actuation mechanism for use in a downhole tool may be configured to cause a first structure (which, for example may be part of the actuation mechanism or the downhole tool) to move from a first position to a second position. The first structure may be a tool component. The actuation mechanism may comprise a blocking assembly. The blocking assembly may be for blocking, or restricting flow through, a flow path. The blocking assembly may be configured to move from a first arrangement to a second arrangement. In the first arrangement, a flow path through the downhole tool may be open such that fluid can flow through the flow path. In the second arrangement, the blocking assembly may be arranged to restrict fluid flow through the flow path. The blocking assembly may be configured to move from the first to the second arrangement in response to a change in the flow of fluid through the downhole tool. The first structure may move from the first position to the second position under the action of fluid pressure in response to the blocking assembly moving to the second arrangement.

The downhole tool may comprise the actuation mechanism. The actuation mechanism may be configured to cause the deployable tool component to move from the first position to the second position.

There is described a downhole tool. The downhole tool may comprise an outer housing. The downhole tool may comprise a tool component configured to move from a first position to a second position. The downhole tool may comprise an actuation mechanism (which may comprise a blocking assembly). The actuation mechanism may be as described anywhere herein. The actuation mechanism may be configured to cause the first structure to move from the first to the second position.

The downhole tool may be a drill bit. The tool component may comprise a blade assembly and/or a cutting structure (which may be provided by a cutter). The tool component may comprise a rotatable roller cutter.

The downhole tool may be an expandable drill bit. The expandable drill bit may define a first cutting diameter when the tool component is in the first position. The expandable drill bit may define a second cutting diameter when the tool component is in the second position. The second diameter may be larger than the first diameter. The second diameter may be smaller than the first diameter.

The tool component of the expandable drill bit may comprise at least one cutter. The cutters of the expandable drill bit may define the first and the second cutting diameters.

The cutters of the expandable drill bit may be configured to provide a cutting action in both the first and second positions.

The downhole tool may be a reamer. The reamer may be for enlarging the diameter of an existing bore. The reamer may be a near-bit reamer. The reamer may be configured to form part of a drill string. The reamer may be configured to be connected to a further drill string component at each of its axial ends. The reamer may be configured to be adjacent a drill bit in a drill string.

The tool component of the reamer may comprise a cutter, e.g. a cutter blade or cutter block. The tool component may be at least partially located within an outer housing. The tool component may be arranged to be movable from a first position to a second position. In the first position, the first structure may be recessed or flush with an outer surface of the housing. In the second position, the first structure may protrude from an outer surface of the housing -for example radially.

The downhole tool may be a drill bit. The first structure may be the deployable blade assembly. The fluid may be drilling fluid. Any disclosure herein relating to a drill bit applies, mutatis mutandis, to a downhole tool as disclosed herein, and vice versa.

The actuation mechanism may be configured to move the tool component from the first position to the second position. The actuation mechanism may be configured to alter the flow of fluid through the downhole tool which, in turn, may move the tool component from the first position to the second position. The actuation mechanism may be configured to increase the drilling fluid pressure differential across the tool component.

The actuation mechanism may comprise a blocking assembly. The actuation mechanism may be a blocking assembly.

The blocking assembly may be a flow passage, or flow path, blocking assembly.

The blocking assembly may be configured to move from a first arrangement, in which the flow path is open and fluid can flow through the flow path, to a second arrangement, in which the blocking assembly is arranged to restrict fluid from flowing through the flow path. The blocking assembly may be configured to move from the first arrangement to the second arrangement in response to a change in the flow of drilling fluid through the downhole tool.

The blocking assembly may use the flow of the drilling fluid to move the blocking assembly from the first arrangement to the second arrangement.

When the blocking assembly is in the first arrangement, the flow path may be open such that a fluid could flow through the flow path. In the second arrangement, the blocking assembly may be arranged to at least partially close (or entirely close) the flow path, such that fluid flow through the flow path would be restricted. A blocking assembly may be operable to modify the flow of drilling fluid through the downhole tool, for example by blocking a port or a flow path. The blocking assembly may be configured to selectively block a flow path.

The blocking assembly may allow a reduced amount of fluid flow through the flow path and thus restrict fluid flow through the flow path. The blocking assembly may be configured to block the flow path to entirely prevent fluid flow through the flow path when in the second arrangement. Blocking the flow path entirely is included within the use of the term "restrict when referring to fluid flow through the flow path.

The blocking assembly may move from the first arrangement to the second arrangement when a pressure differential across the blocking assembly reaches a threshold value. The blocking assembly may move from the first arrangement to the second arrangement when a resultant force acting on the blocking assembly, or a part thereof, reaches a threshold value. The resultant force may be in an axial direction, the direction may be from the upstream end of the downhole tool to the downstream end of the downhole tool.

The blocking assembly may define a reduction in the area through which fluid can flow in the downhole tool, thus creating a pressure drop and resultant force acting across the blocking assembly.

A pressure differential is created when a fluid flows through a restriction. The outlet of the downhole tool (i.e. the outlet of the flow path) may define a restriction to flow.

Accordingly, the pressure of fluid flowing through the downhole tool may be high compared to the pressure of fluid in the annulus.

A first side of the blocking assembly may be exposed to the pressure of fluid flowing through the drill bit. A second side of the blocking assembly may be exposed to annulus pressure. The annulus pressure may be lower than the flow path pressure and, as such, a pressure gradient may be present across the blocking assembly. The pressure gradient may urge the blocking assembly towards the second arrangement.

The downhole tool may be configured such that the flow path is unrestricted during steady state operation with the tool component in the first and second positions. The blocking assembly may be configured such that flow through the flow path is only restricted as the tool component moves from the first to the second positions.

The change in the flow of fluid through the downhole tool may increase a pressure differential (and thus resultant force) across the blocking assembly to a threshold value.

The change in the flow of drilling fluid through the downhole tool may increase the pressure of the drilling fluid at the entry to the downhole tool, or at an upstream end of the blocking assembly. The change in the flow of drilling fluid through the downhole tool may reduce the pressure of the drilling fluid at an outlet of the downhole tool or at a downstream end of the blocking assembly and/or the deployable tool component.

The change in the flow of drilling fluid through the downhole tool may be an increase in the drilling fluid flow rate.

The change in the flow of drilling fluid through the downhole tool may be increasing the volumetric flow rate of drilling fluid input into the drill string, and hence downhole tool. Increasing the flow rate of the drilling fluid into the drill string and hence the downhole tool may increase the pressure drop across flow restrictions in the downhole tool. The blocking assembly may comprise a flow restriction for drilling fluid and, as such, the pressure differential across the blocking assembly may increase when the flow rate of drilling fluid into the downhole tool increases.

The increase in flow rate suitable for moving the blocking assembly from a first arrangement to a second arrangement may be 20%. This will increase the pressure differential across the blocking assembly by about 44%.

The blocking assembly may be configured to move from the first arrangement to the second arrangement in response to an increase in the pressure differential across the blocking assembly. The percentage pressure differential increase to move the blocking assembly may be of substantially any value which would be achievable in a downhole scenario using known pumps and operating limits. As such, the following ranges are examples. The blocking assembly may be configured to move from the first arrangement to the second arrangement in response to an increase in the pressure differential across the blocking assembly of between 30% and 60%; 35% and 55%; 40% and 50%; or 42% and 46%. A 30% increase in the flow rate will increase the pressure by 69%, a 40% increase in the flow rate will increase the pressure by 96% and a 50% increase in the flow rate will increase the pressure by 125%. The required increase in flow rate for providing these increases in pressure differentials can be obtained by finding the square root of the corresponding pressure differential increase.

As an example for illustration, a flow rate for maintaining the blocking assembly in the first arrangement may be about 60 litres/s (950 US gpm) in a 12-1/4" downhole tool. The change in the flow of drilling fluid through the downhole tool may be to increase the flow rate of drilling fluid through the downhole tool to 72 litres/s (1141 US gpm).

Increasing the flow of drilling fluid through the downhole tool may be implemented at the surface by a user.

The change in the flow of drilling fluid through the downhole tool may be to increase or reduce the volumetric flow rate of used drilling fluid taken out of the well bore -i.e. increase or reduce the flow of drilling fluid out of the downhole tool.

The blocking assembly may be configured to move from the first arrangement to the second arrangement when a pressure differential across the blocking assembly reaches a threshold value. The threshold value may be selected as substantially any practical pressure value achievable in downhole operations. When selecting the value for the threshold pressure, the desired pressure drop across downstream components of the downhole tool must be considered. The following ranges are provided as examples of possible threshold values. The threshold value may be within the range of 0 to 3450 kPa (0 to 500 psi) -although naturally higher values are still possible. The threshold value may be within the range of 0 to 1500 psi. The threshold value may be within any of the following ranges: 600 to 1800 kPa, 900 to 1800 kPa, 1200 to 1500 kPa, or 1300 to 1450 kPa. The threshold value may be greater than any one of the following: 500, 600, 700, 800, 900, 1000, 1200 and 1400 kPa.

The blocking assembly may be configured to move from the first arrangement to the second arrangement when the pressure differential across the blocking assembly (i.e. from an upstream side to a downstream side) is within any of the above-listed ranges.

As an example, the blocking assembly may be configured to move from the first arrangement to the second arrangement when the pressure drop across the blocking assembly is about 1724 to 8274 kPa (about 250 to 1200 psi).

The tool component may move from the first position to the second position in response to a change in the flow of drilling fluid through the downhole tool. The tool component may be configured to move from the first position to the second position under the action of fluid pressure. The tool component may be configured to move from the first position to the second position in response to the blocking assembly moving to the second arrangement. The tool component may be configured to move from the first position to the second position in response to the blocking assembly moving to the second arrangement and causing a pressure differential across the tool component to increase to a deployment value.

The pressure differential across the tool component may be provided by the flow of drilling fluid through the downhole tool. As noted above, the flow of fluid through the downhole tool and out of the outlet may cause the pressure of fluid flowing through the downhole tool to be higher than the pressure of fluid in the annulus. One side of the tool component may be exposed to fluid flowing through the downhole tool. A second side of the tool component may be exposed to annulus pressure.

When the blocking assembly moves to the second arrangement and restricts the flow of fluid through the downhole tool, the pressure differential between fluid flowing through the downhole tool and the annulus (and thus the pressure differential across the tool component) increases.

The tool component may be configured to move from the first to the second position when the pressure differential, or pressure drop, across the tool component (or a part thereof) reaches a threshold value known as the deployment value. The pressure drop may be from an upstream end of the deployable tool component to a downstream end.

The pressure differential across the tool component may create a resultant axial force acting on the tool component and this axial force may move the tool component from the first to the second position.

The change in flow of drilling fluid through the downhole tool may be, or may cause, the pressure differential across the tool component to reach a deployment value (discussed below). A user may increase the flow rate of drilling fluid which may, in turn, increase the pressure gradient across the tool component to the deployment value. For example, an example may not include a blocking assembly and may instead increase the flow rate of drilling fluid through the downhole tool until the pressure gradient reaches a deployment value, as which point the tool component is moved from the first to the second position. As described in relation to examples below, the tool component may be restrained in the first position by a shear ring or frangible screw or bolt, for example, which may be configured to break at a specific value which defines the deployment value.

The tool component may be configured to move from the first position to the second position under the action of fluid pressure in response to the change in the flow of drilling fluid through the downhole tool. Such an arrangement may remove the necessity for having a blocking assembly which blocks a flow path through the device, thus reducing the pressure rise associated with such an embodiment.

The blocking assembly moving to the second arrangement may create an increase in the pressure differential across the tool component (or a part thereof). The blocking assembly moving to the second arrangement may therefore cause the resultant force acting on the tool component to increase to a threshold value for the tool component -the deployment value, moving the tool component from the first to the second position. It should be noted that the threshold value for the tool component is referred to herein as the deployment value in order to avoid confusion with the threshold value for moving the blocking assembly from the first to the second position (which is referred to herein as the threshold value).

The blocking assembly may comprise a first deformable or breakable member, which may be configured to restrain the blocking assembly in the first arrangement and deform or break to release the blocking assembly to move to the second arrangement. The first deformable or breakable member may be referred to herein as a restraint.

The downhole tool may comprise a second deformable or breakable member, which may be configured to restrain the tool component in the first position and deform or break to release the tool component to move to the second position. The second deformable or breakable member may be configured to deform or break in response to the movement of the blocking assembly from the first to the second arrangement. The second deformable or breakable member may be referred to herein as a deformable release.

The tool component may be configured to move from the first position to the second position when a pressure differential across the tool component reaches a deployment value. The deployment value may be selected as substantially any practical pressure value achievable in downhole operations. When selecting the value for the deployment pressure differential, the desired pressure drop across upstream and downstream components of the downhole tool must be considered. The following ranges, relating to the deployment value and the increase in pressure gradient caused by the movement of the blocking assembly to the second arrangement are provided as examples of possible deployment values.

The deployment value may be in the range of 3450 to 10350 kPa (500-1500 psi) although naturally higher values are still possible.

The increase in the pressure differential across the tool component caused by the blocking assembly moving to the second arrangement may be within the range of 1400 to 8300 kPa (200 to 1200 psi) or within any of the above-mentioned ranges. The increase in the pressure differential across the deployable tool component caused by the blocking assembly moving to the second arrangement may be within 3000 to 4600 kPa.

The tool component may be configured to move from the first position to the second position when the pressure differential across the deployable tool component is within any one of the above-stated ranges.

The deployment value may refer to a pressure differential across the piston (see below) of the deployable tool component. Accordingly, the tool component may be configured to move from the first position to the second position when a pressure differential across the piston reaches a deployment value. The above comments relating to exemplar values for the deployment value may apply equally when the pressure drop is measured across the piston, rather than the entire tool component.

The blocking assembly and/or tool component may be configured such that once the tool component starts moving from the first position to the second position, the pressure differential across the deployable tool component starts to decrease. That is, the blocking assembly and/or tool component may be configured such that fluid flow through the flow path is only restricted for a short period of time. In an example, the blocking assembly may only restrict fluid flow through a flow path when the tool component is in the first position. When the tool component moves from the first position, fluid flow through the flow path may no longer be restricted.

The downhole tool, or flow path thereof, may comprise a drilling fluid inlet at an upstream end of the downhole tool.

The inlet may comprise an internal bore of the downhole tool and may be connected to a further downhole assembly component. The downhole tool may comprise a plurality of fluid inlets.

The downhole tool, or flow path thereof, may comprise a plurality of drilling fluid outlets located downstream of the inlet.

The downhole tool may be configured such that fluid can flow through the flow path during steady-state operation with the tool component in the first and second positions. Flow through the flow path may only be restricted during the transition of the tool component from the first to the second positions. All of the fluid outlets may be in use during steady-state operation of the downhole tool before and after movement of the tool component from the first to the second position.

Fluid outlets may be located on the end face of the downhole tool (e.g. on the end face of the outer housing), on a curved side wall of the downhole tool (e.g. the outer housing), or both. Fluid outlets may be located in, on, or as part of, the primary cutting structure (which may be located on an end face of the downhole tool). Fluid outlet(s) may be arranged in the primary or deployable cutting structure.

An (or each) outlet may comprise a valve or nozzle, for controlling flow of drilling fluid through the outlet. An outlet may comprise a fixed size nozzle. A nozzle/valve may throttle fluid flow through the outlet. Nozzles/Valves may be fixed relative to the outer housing or the tool component, depending on where the outlet is located. Including a nozzle/valve in an outlet may allow the pressure on the inlet-side of the nozzle/valve to be controlled and may thus allow an increased pressure to be maintained on the inlet-side of a specific outlet.

Throughout the present disclosure, a nozzle may be used in place of a valve and vice versa. Discussion relating to a valve applies equally to a nozzle.

The flow path may connect the inlet to an outlet.

The downhole tool may comprise a plurality of flow paths, each connecting the (or an) inlet to an outlet. The blocking assembly may be configured to restrict flow through only one, or a plurality of, the flow paths.

The downhole tool may comprise a ratchet. The ratchet may be a ratchet sub-assembly.

The ratchet may be a ratchet ring sub-assembly. The ratchet may be a body lock ring. The ratchet may be located between the outer housing and the tool component. The ratchet may be configured to allow movement of the tool component towards the second position. The ratchet may be configured to resist movement of the tool component away from the second position towards the first position.

The ratchet may be configured to only allow movement of the tool component in one direction. That direction may be towards the second position, e.g. towards the primary cutting structure or cutting plane.

The ratchet may be integral or connected to the outer housing. The ratchet may be integral or connected to the tool component.

The ratchet may assist in holding the tool component in the second position, or in a position that is towards the second position. The ratchet may act as a back-up, or supporting, locking mechanism, in order to assist a lock in holding the tool component in the second position. If the tool component is not able to fully deploy to the second position, due to a blockage for example, the ratchet may be used to hold the tool component in a partially deployed state. Alternatively, the ratchet may be used to control vibrations of the tool component in an axial direction.

The ratchet may comprise a first sleeve fixed relative to the outer housing and comprising a serrated internal surface. The ratchet may further comprise a second sleeve fixed relative to the tool component comprising a serrated external surface. The second sleeve may be arranged to engage with the internal surface of the first sleeve.

The ratchet may comprise two engaging serrated sleeves. The serrations may be shaped so as to allow respective movement in one direction, but not the other. That is, the two serrated surfaces may be able to slide over one another in one direction, but not the other.

The serrations may have a saw-tooth profile with a straight face and an angled face. The straight edge may be perpendicular to the axis of the downhole tool. The angled edge may be arranged at an oblique angle to the axis of the downhole tool. The following geometries are provided as examples for the saw-tooth profile. The angle between the downhole tool and the angled edge may be between 0 and 45 degrees; 15 and 75 degrees; 25 and 65 degrees; 20 to 55 degrees; or 40 and 50 degrees. The angled edge may be arranged at about 30 or 45 degrees to the axis of the downhole tool.

The serrations may have a flat top -that is, the straight edge and angled edge may not meet at a point.

The serrations may be formed by a series of circular grooves formed in the respective surfaces of the sleeves. The serrations may alternatively be formed by a single helical groove formed in the respective surfaces of the sleeves.

One of the first and second sleeves may comprise an axial split permitting deformation of the sleeve. The axial split may facilitate easier relative movement of the two sleeves in the permitted direction, as one of the sleeves can deform in order to "move over/under" the other sleeve.

The first and second sleeves may comprise between 1 and 10, 20, 30, 40 or 50 serrations. The first and second sleeves may comprise between 10 and 50, 20 and 40 or 20 to 30 serrations along their length.

The downhole tool may comprise a release. The release may be configured to hold the tool component in the first position. The release may be configured to release the tool component in response to the blocking assembly moving to a second arrangement, such that the tool component can move towards the second position.

The release may be a deformable release. The downhole tool may comprise a deformable release arranged between the outer housing and the tool component. The deformable release may be configured to restrain the tool component in the first position when in an undeformed state and release the tool component such that it can move with respect to the outer housing when the deformable release is in a deformed state The deformable release may form part of the actuation mechanism and/or the tool component. A first part of the deformable release may be fixed with respect to the outer housing and a second part of the deformable release may be fixed with respect to the tool component. The deformable release may engage both the outer housing and the tool component. The deformable release may restrain the tool component in the first position. The deformable release may be configured to deform (e.g. break between the first and second parts) such that the tool component can move with respect to the outer housing when a pressure differential across the tool component reaches the deployment value. The deformable release may be configured to deform and release the tool component with respect to the outer housing when a pressure differential across the deployable tool component reaches a deployment value. The deformable release may be configured to release the tool component in response to the blocking assembly moving to the second arrangement.

In order to facilitate movement of the tool component at a certain time (e.g. when the pressure gradient/resultant force reaches the deployment value) but not before, the deformable release may hold the tool component in the first position and then release the tool component when the necessary condition is met.

In the present disclosure the term deform is used to describe bending, shrinking, expanding, tearing, shearing or any other form of breaking.

The deformable release may retain its structural integrity up until the point that the pressure differential across the tool component (or piston thereof, for example) reaches the deployment value, at which point the resultant stresses in the deformable release cause the deformable release to break, shear or bend, releasing the tool component.

The deformable release may be a shearable or breakable member, for example a shear pin, shear ring, or a frangible screen or member. The deformable release may determine the deployment value -that is, the pressure drop at which the tool component leaves the first position.

The deformable release may be a shearable screw (e.g. a bolt configured to break when exposed to a specified tensile load). The deformable release may be a threaded connector configured to break at a predetermined tensile load. The shearable screw may be arranged axially within the downhole tool (or actuation mechanism of which it forms a part). The shearable screw may be arranged offset from the centre axis of the downhole tool or actuation mechanism.

A first part of the shearable screw (e.g. the head) may be fixed relative to the outer housing, for example by being inserted through a hole which is fixed relative to the outer housing. A second part of the shearable screw (e.g. the tip) may be fixed relative to the tool component (e.g. the piston), for example by being screwed into a threaded hole formed therein.

The downhole tool may comprise a support cylinder fixed with respect to the outer housing. The deformable release may be inserted (e.g. axially) through a hole in the support cylinder and screwed into a threaded hole in the piston of the deployable tool component. The shearable screw may be arranged to hold the tool component in the first position (against the action of fluid flowing through the tool), until the pressure gradient (and thus resultant force) across the tool component reaches a threshold value, at which the screw breaks and the tool component is free to move to the second position.

The deformable release may be made from any material which deforms at a suitable load for use with the downhole tool. Example materials may include metals, alloys or polymers such as plastics.

The deformable release may be a shear ring. The shear ring may comprise a first ring fixed with respect to the outer housing. The first ring may be connected by a breakable region to a second ring, which may be fixed with respect to the tool component. The shear ring may be arranged such that, as the pressure differential across the deployable tool component increases, axial stresses in the breakable region increase.

The shear ring may be configured such that the breakable region breaks, separating the first and second rings, when the pressure differential across the tool component reaches a deployment value. At this point, the axial stresses in the axial stresses in the breakable region may have reaches the fracture strength of the material.

The pressure differential across the tool component reaching a deployment value may therefore cause the force across the breakable region to reach a breaking force. The material, size and shape of the shear ring (e.g. the diameter and thickness of the breakable region) may be selected such that the axial stresses in the breakable region reach the level required for the material to deform -e.g. break -as the pressure differential reaches the deployment value.

The breakable region may be a band of material connecting the first and second rings with a thickness smaller than that of the rings. The shear ring may be arranged such that the breakable region comprises a tube of material extending in an axial direction, located between the outer housing and the tool component, such that a pressure drop across the tool component results in axial forces in the tubular breakable region.

The downhole tool may comprise a lock arranged to hold the deployable tool component in the second position. A downhole tool or actuation mechanism according to the disclosure may comprise a lock arranged to hold the first structure in the second position.

Once the tool component is in the second position, the tool component or a cutter or cutting structure thereof may be engaging a material to be cut. Cutting a material, for example a formation, results in a lot of axial and torsional dynamic forces being applied to the cutting structure. Accordingly, the downhole tool may comprise a lock to hold the tool component in the second position and prevent it from being forced away from the second position, towards the first position, by interaction with a formation.

The lock may comprise an engagement member in one of the outer housing and the tool component. The engagement member may be biased towards the other of the outer housing and the tool component. The lock may further comprise a recess arranged on the other of the outer housing and the tool component. The recess may be arranged to receive the engagement member (e.g. a part thereof) when the tool component is in the second position.

The lock may comprise a member arranged to engage both the outer housing and tool component when the tool component is in the second position. The member may engage a recess or a detent in each of the outer housing and the tool component.

Biasing the engagement member towards an engaged position will allow the lock to automatically engage once the tool component reaches the second position.

The lock may comprise a pin. The pin may be housed in the outer housing and biased towards the tool component. The tool component may comprise a recess, arranged to receive the end of the pin when the deployable tool component is in the second position, such that the pin spans the interface between the outer housing and the deployable tool component and extends into both, preventing relative axial movement thereof.

The tool component may comprise a piston. The piston may be located within the outer housing.

The piston may be arranged to move axially within the outer housing. A seal, or a plurality of seals, may be located between the piston and the outer housing to prevent fluid from passing between the piston and the outer housing.

A first side of the piston may be exposed to fluid flowing through the downhole tool. A second side of the piston may be exposed to the annulus pressure.

The piston may comprise a plurality of fluid outlets. These fluid outlets may be connected to, or constitute the outlets of the downhole tool flow path. A, or a plurality of, fluid outlets may be located in an axial end face of the piston or a curved side face of the piston. The piston may comprise a plurality of passageways or flow paths therethrough. One, or a plurality, of these flow paths may be the flow path that is blocked by the blocking assembly.

The tool component may comprise valves or nozzles for outputting drilling fluid from the downhole tool. These fluid outlets may be connected to, or constitute the outlets of the downhole tool flow path. A nozzle/valve may be located in an, or each, outlet. The nozzle/valves may be arranged in flow paths. The nozzle/valves may be arranged to output drilling fluid of an axially-facing end face of the downhole tool, or from a radially-facing side face of the downhole tool. The nozzle/valves may be arranged to output drilling fluid axially or radially from the downhole tool.

The piston may comprise a central region for receiving drilling fluid from the downhole tool inlet. The central region may be a cavity. The central region may comprise a plurality of openings leading to flow paths through the piston.

The tool component, or the piston thereof, may comprise, or define, an occluding member seat for receiving an occluding member (see below). The seat may be located in the flow path, the flow through which is restricted by the blocking assembly. The seat may be located in the cavity. The occluding member seat may be arranged in the flow path for supporting the occluding member in the second arrangement. The tool component may comprise a flow path opening and the seat may be located in the flow path opening. The seat may be arranged downstream of other passageways or flow paths leading to outlets, such that drilling fluid may flow through these outlets, regardless of whether the occluding member is located in the seat and restricting flow through the respective flow path.

The seat may be arranged such that, when the occluding member is located in the seat, the flow through only one of the flow paths from the inlet to an outlet is restricted or blocked.

The tool component may comprise a blade. The blade may be connected to the piston. The tool component may comprise a plurality of blades. The blade or blades may comprise the cutter or cutters of the tool component.

It should be noted that where singular language is used to refer to a feature of which there may be a plurality in the downhole tool, it is to be understood that the comments apply equally to one, the, some of, or each, of the feature. For example, when a feature is described in relation to "the blade", the feature also applies equally to "one of the blades, "some of the blades and "each of the blades.

The blade may be substantially cuboidal, with a thin depth and a much larger width and length (which is arranged parallel to the axis of the downhole tool). The blades may comprise, or be made out of, AISI 4330V steel at 1030000 kPa (150,000 psi) Yield Strength, for example.

The blade may be substantially 'L'-shaped when viewed along the longitudinal axis of the downhole tool.

The blade may be connected to the piston by means of a retention pin. The retention pin may be arranged to prevent the blade moving axially, or radially, with respect to the rest of the tool component. The blade and blade retention pins may be configured to withstand all of the drilling forces arising from use of the deployable cutting structure to drill. The pins may be made of metal or a metal alloy, for example steel or a steel alloy.

The blade retention pins may comprise or be made from AISI 4330V with about 1030000 kPa (150 000 psi) Yield Strength in order to withstand all of the forces experienced during drilling. The retention pins may be configured to have clearance between the pins and the blades and/or rest of the tool component such that no axial forces are applied to the pins from the blades under weight-on-bit or axial compression. The pins may however stop the blades being pulled out of the body under tensile drag, for example.

All of the above disclosure in relation to the blade applies, mutatis mutandis, to a cutter of the downhole tool.

The blade and piston may be arranged to move axially with respect to the outer housing.

The tool component may be arranged to move parallel to a longitudinal axis of the downhole tool.

The piston and blade of the tool component may be arranged to move parallel to a longitudinal axis of the downhole tool from the first position to the second position. The piston and blade of the deployable tool component may be arranged to only move parallel to the axis of the downhole tool.

The (longitudinal) axis may extend along the centreline of the downhole tool. The longitudinal axis may be substantially perpendicular to the cutting plane.

In other tools, the tool component (or a part thereof, e.g. a cutter) may rotate relative to the housing, or move by a combination or translation and rotation. The tool component (or a part thereof, e.g. a cutter) may move radially with respect to the housing.

The blade may be arranged substantially radially when viewed along the longitudinal axis of the downhole tool.

The tool component may normally comprise any number of blades or cutters, e.g. from 1 to 12 (for example 3, 4, 5 or 6 blades). The tool component may comprise 4 blades which may be arranged rotationally symmetrically about the axis of the downhole tool, for example such that they extend substantially radially when viewed along the longitudinal axis of the downhole tool.

The blade or cutter may comprise a key, protruding from a surface of the blade. The key may be arranged to restrict the blade to axial movements with respect to the outer housing, parallel to the longitudinal axis of the downhole tool.

The key may comprise an elongated bump or ridge along an axially-extending surface of the key. Alternatively, the key may comprise a groove or slot. The key may be arranged to engage a complementary groove or ridge in the outer housing or other component of the downhole tool.

The blade or cutter may be located within an axially-extending slot which is fixed with respect to the outer housing. The blade or cutter may be arranged to move axially within the slot from a first position to a second position.

The slot and blade/cutter (or, for example, a key on a blade/cutter) may be arranged to prevent radial movement of the blade.

The blade and/or cutter may be level with, or extend out from, the primary cutting structure in an axial direction when the deployable tool component is in the second position.

The primary and deployable cutting structures (i.e. blade/cutter) may comprise a plurality of cutting inserts. The cutting inserts may be for cutting rock, steel casing or other downhole materials. A blade may comprise a plurality of cutting inserts. Examples of such cutting inserts include PDC cutters and roller cutters/roller cone cutters.

The cutting inserts on both the primary and deployable cutting structures may be arranged so as to cut across the entire diameter of the cutting structures. That is, cutting inserts may be located on the cutting structures extending from the centre of the cutting surface to the outer radius of the cutting structure.

Alternatively, cutting inserts on the deployable cutting structure may be located only towards the outside of the axial face of the cutting structure -for example on the outer half, third or quarter of the cutting structure, towards the outer circumference of the cutting structure (the axial face is a face substantially perpendicular to the axis of the downhole tool). The deployable cutting structure may comprise a ring of cutting inserts located spaced from the axis of the downhole tool. The deployable cutting structure may comprise a centre circle located around the axis of the downhole tool in which in which no cutting inserts are located.

During use, as the downhole tool is rotating, the cutting inserts located at larger radiuses from the axis of the downhole tool move faster than those towards the centre (located at smaller radiuses). Accordingly, they may wear down faster. A deployable cutting structure may therefore be for replacing worn cutting inserts and may therefore only be needed towards the outside of the cutting structure, as the cutting inserts towards the centre may not be worn to the same degree.

When the deployable tool component is in the second position, the deployable cutting inserts and/or the deployable cutting structure may be level with, or protrude/extend from, the primary cutting inserts and/or the primary cutting structure, respectively, in an axial direction of the downhole tool.

The tool component, deployable cutting structure and/or the plurality of cutting inserts forming the deployable cutting structure may define a deployable cutting plane. When the tool component is in the second position, the deployable cutting plane may be coplanar with, or extend out from (i.e. further from the centre of mass of the downhole tool than) the cutting plane of the primary cutting structure.

The term extending out from refers to a location which is axially displaced in a direction away from the centre of mass of the downhole tool.

The blades may be arranged to radiate or extend out from the centre of the downhole tool -i.e. the centre of the deployable cutting structure. The deployable cutting inserts may be arranged in rows to radiate out from the centre of the downhole tool -i.e. the centre of the deployable cutting structure. The cutting inserts may be arranged to have a positive or negative rake angle.

The tool component may be a cut-depth reduction surface. The tool component (e.g. the deployable cutting structure) may be recessed with respect to the primary cutting structure in an axial direction when the tool component is in the second position.

The tool component, or a deployable cutting structure thereof, may comprise non-cutting inserts, e.g. a plurality of ovoid inserts. The ovoid inserts may be smooth protrusions configured to abut rock or downhole material, rather than cut it. Ovoid inserts may be used in place of cutting inserts when the deployable cutting structure is used as a cut-depth reduction surface. The ovoid inserts may be domed inserts. The domed inserts which may be non-cutting and deployment could result in reducing the depth of cut of the primary cutting structure when the tips of the domes are located in an axial direction between the tips of the primary cutters and the base material in which they are located when the moveable structure is deployed.

The tool component may be configured to move closer to the primary cutting structure when moving from the first to the second position, such that the cut depth of the primary cutting structure is reduced when the tool component is in the second position compared to when the tool component is in the first position.

The primary cutting structure may comprise a first profile. The tool component, or the deployable cutting structure thereof, may comprise a second profile. The primary cutting structure may define a first profile when viewed in a cross-section parallel or perpendicular to the axis of the downhole tool. The deployable cutting structure may comprise a second shape when viewed in a cross-section parallel or perpendicular to the axis of the downhole tool. The two different shapes of the cutting structures may provide different cutting characteristics and may be optimised for cutting different materials, or at different speeds, or with different torques.

The blocking assembly may comprise an occluding member. The blocking assembly may comprise a restraint. The restraint may be configured to hold the occluding member in the first arrangement. The restraint may be configured to release the occluding member in response to the change in the flow of drilling fluid through the downhole tool. The restraint may be configured to release the occluding member in response to the change in the flow of drilling fluid through the downhole tool such that the occluding member can move from a non-occluding position in the first arrangement to an occluding position in the second arrangement. In the occluding position, the occluding member may restrict flow through the flow path (e.g. prevent fluid from flowing through the flow path).

The occluding member may be configured to move from a non-occluding to an occluding position. In the occluding position, the occluding member may be arranged to restrict (e.g. prevent) flow of drilling fluid through the, or a, flow path. The occluding member may be configured to be moved by the flow of drilling fluid through the downhole tool, from the first to the second arrangement.

The restraint may be fixed with respect to the outer housing and may be configured to hold the occluding member in a non-occluding position (i.e. the first arrangement).

The blocking assembly (e.g. the occluding member thereof) may be located across a flow path or passageway through the downhole tool when in the first arrangement. There may be a plurality of flow paths or passageways through the downhole tool and the blocking assembly (e.g. the occluding member thereof) may be located across one of these flow paths or passageways such that a pressure drop is created across the blocking assembly. Although the blocking assembly or occluding member thereof may be located across a flow path when in the first arrangement, it is to be understood that this does not correspond to an occluding position, as flow through the flow path which is later blocked is not restricted to the same degree. The pressure differential across the blocking assembly may apply a force to the restraint and/or occluding member. The force may be in a direction from the first arrangement to the second arrangement.

The restraint may be configured to resist the force applied to the occluding member/restraint/blocking assembly and hold the occluding member in the non-occluding position until the flow of drilling fluid through the downhole tool is changed (e.g. until the pressure differential across the blocking assembly reaches the threshold value), at which time the restraint may be configured to release the occluding member such that it can move to the occluding position (e.g. the second arrangement) under the action of fluid flow.

At least one of the restraint and the occluding member may be configured to deform in response to the change in the flow of drilling fluid through the downhole tool, such that the occluding member is released. The restraint or the occluding member may be configured to deform in order for the restraint to release the occluding member.

The restraint (or a part thereof) may be configured to deform either by bending, expanding or breaking, such that the occluding member is no longer held in the first position.

When the restraint deforms, it may move from a position in which the occluding member is held in the first arrangement to a position in which the occluding member is no longer held in the first arrangement. The restraint may therefore deform from a restraining arrangement to a non-restraining arrangement.

The restraint may comprise, for example, a deformable fastener. The restraint may comprise a breakable fastener. Examples of such fasteners may include shear pins, shear bolts and shear rings. The deformable fastener may be configured to deform (e.g. break) in response to the change in the flow of drilling fluid through the downhole tool, releasing the occluding member. Once deformed, the fastener may no longer hold the occluding member in the first arrangement. The restraint may be a threaded connector configured to break at a predetermined tensile load.

A first part of the restraint may be fixed with respect to the outer housing. A second part of the restraint may be fixed with respect to the occluding member. The restraint may be configured to break in response to a change in the flow of drilling fluid through the downhole tool. The restraint may be arranged axially within the actuation mechanism or downhole tool.

A first part of the shearable screw (e.g. the head) may be fixed relative to the occluding member by being inserted through a hole in the occluding member. A second part of the shearable screw (e.g. the tip) may be fixed relative to the outer housing by being screwed into a threaded hole in the outer housing or a support cylinder which is fixed relative to the outer housing.

The occluding member may be arranged to move axially within the downhole tool from the first arrangement to the second arrangement. Axial movements refer to movements which are parallel to the axis of the downhole tool. The occluding member may be restricted to axial movement within the outer housing.

The downhole tool may comprise a guide. The guide may be arranged parallel to the axis of the downhole tool. The blocking assembly (or restraint) may comprise a guide. The guide may comprise a track. The guide may be in the form of an elongate member, for example a pin, screw, bar and tube.

The occluding member may be arranged to be movable (e.g. to translate, or slide) within the outer housing, along the guide. The occluding member may be arranged to move axially from the first arrangement to the second arrangement, along the guide.

The occluding member may slidingly engage one of the outer housing or deployable tool component such that the occluding member is arranged to move axially (e.g. along the axis of the downhole tool) from the first arrangement to the second arrangement. The occluding member may slidingly engage a guide of one of the outer housing or deployable tool component.

The occluding member may be an occluding rod. The rod may be arranged to extend along the axis of the downhole tool within the outer housing. The rod may comprise a shoulder which defines a transition from a first to a second diameter. The shoulder may be defined by a radially extended circumferential protrusion or disc, for example a piston head. The occluding member may define a plurality of shoulders. The shoulder(s) may be configured to restrict the flow of fluid through a flow path when the blocking assembly moves to the second arrangement.

The flow path may be arranged to pass through the deployable tool component and may comprise a tapered section or section of reduced diameter. The tapered section may define the occluding member seat. The rod may be configured to move from a first arrangement to a second arrangement, in which the shoulder of the rod abuts the tapered section to restrict flow through the flow path.

The flow path may comprise a cylindrical section arranged parallel to the axis of the downhole tool. The tapered section may lead to the cylindrical section. The occluding rod may comprise a support arm which is arranged in sliding engagement with the cylindrical section such that the occluding rod is movable along the axis of the cylindrical section, parallel to the axis of the downhole tool, from the first to the second arrangement. The occluding rod may comprise a first and second support arm, each of which may be arranged in a sliding engagement with a cylindrical section of the flow path, tool component or outer housing, such that the occluding rod is movable along the axis of the cylindrical section, parallel to the axis of the downhole tool, from the first to the second arrangement.

An opening in the cylindrical section may allow fluid to pass from the cylindrical section towards the outlet. The occluding rod may comprise a neck section of smaller outer diameter than the cylindrical section, such that fluid can flow past the occluding rod and out of the opening when the occluding rod is in the first arrangement.

The deformable fastener may pass through the occluding rod, or be attached thereto.

The deformable faster may also be fixed with respect to the outer housing. The deformable fastener may pass through a tab of the occluding rod and extend into a hole which is fixed with respect to the outer housing.

When the flow of fluid through the downhole tool changes, the deformable fastener may break, releasing the occluding rod. The occluding rod, under the action of fluid flow through the downhole tool and restricted to axial movement by the engagement of the support arm and cylindrical section may move axially within the outer housing from the first arrangement to the second arrangement. In the second arrangement, the occluding rod may be arranged within the cylindrical section such that the shoulder of the rod abuts the tapered section and restricts fluid flow through the tapered section and the cylindrical section.

When in the second arrangement (the occluding position) the occluding member may move with the tool component when the tool component moves from the first to the second position. The occluding member may be in an occluding position (and thus restrict flow through, or prevent flow through the flow path) while it moves with the tool component, and may stay in an occluding position once the tool component is in the second position.

Alternatively, the occluding member may not move with the tool component. As such, the occluding member (and blocking assembly in general) may stay in a second arrangement while the tool component moves to the second position. This may allow a flow path through which fluid was restricted by the blocking assembly to again open up, such that fluid flow therethrough is again unrestricted when the tool component is in the second position.

The downhole tool (or the blocking assembly or tool component thereof) may comprise an abutment. The abutment may be arranged as a detent, and may be arranged to abut or engage the occluding member as it moves with the tool component from the first position of the tool component to the second position of the tool component. The abutment may stop the occluding member. The abutment may engage and restrain the occluding member when the tool component moves from the first to the second position. The abutment may be arranged to contact a shoulder of the occluding member.

The abutment may be arranged to prevent the occluding member from moving with the tool component as the deployable tool component moves from the first to the second position. The abutment may be arranged to prevent the occluding member from being in an occluding position when the tool component is in the second position.

The abutment may be arranged to abut the occluding member shortly after the tool component and occluding member begin moving.

The abutment may be arranged such that the flow of drilling fluid through the downhole tool holds the occluding member against the abutment during subsequent operation of the downhole tool.

The downhole tool or actuation mechanism may comprise a guide cylinder. The guide cylinder may be arranged concentrically within and fixed with respect to a support cylinder or the outer housing. The guide cylinder may be arranged concentrically around the occluding member. The guide cylinder may guide the axial movement of the occluding member. The guide cylinder may define the abutment, which may be arranged to restrict the axial movement of the occluding member. The abutment may comprise a radially inward projecting flange. The abutment may be arranged to abut a shoulder of the occluding member when, or shortly after, the blocking assembly moves to the second arrangement.

The occluding member may comprise a ridge, protrusion or shoulder. The abutment may comprise a ridge, protrusion or shoulder which is arranged to abut the ridge, protrusion or shoulder of the occluding member during movement of the occluding member, as discussed above. The abutment may be a pin.

The occluding member may be a ball. The occluding member may comprise metal, a metal alloy, or a polymer such as a plastic. The occluding member may comprise steel or a polymer such as PEEK.

The restraint may comprise a gate arranged to hold the occluding member in the non-occluding position when in the first arrangement. The restraint may further comprise a fastener configured to hold the gate in the first arrangement. The fastener may be configured to deform in response to a change in the flow of drilling fluid through the downhole tool, releasing the gate and occluding member to move to the second arrangement.

The gate may be a hinged gate, fixed with respect to the outer housing by means of a hinge. The gate may be arranged to be rotatable about the hinge.

The gate may be arranged to move longitudinally within the downhole tool. The gate may slidingly engage one of the outer housing or deployable tool component such that the gate is arranged to move axially (e.g. along the axis of the downhole tool) from the first arrangement to the second arrangement.

The gate may be arranged to be movable (e.g. to translate, or slide) within the outer housing, along the guide. The guide may be arranged parallel to the axis of the downhole tool. The fastener may be a breakable fastener configured to break in response to the change in the flow of drilling fluid through the downhole tool. The gate may be arranged to move from the first arrangement to the second arrangement, along the guide, to release the occluding member, when the fastener breaks.

The gate may be arranged to close off a passageway/flow path through a part of the downhole tool. The ball may be located on the upstream side of the passageway/flow path and be unable to move downstream. The fastener may be arranged to hold the gate in a closed arrangement. The fastener may be fixed with respect to both the gate and the outer housing.

The gate may be arranged to move from the first arrangement to the second arrangement under the action of fluid flowing through the downhole tool.

The gate may be in the form of a door, panel or a plug, arranged to restrict fluid flowing through a passageway or a portion thereof of the downhole tool.

The fastener may be configured to break in response to a change in the flow of drilling fluid through the downhole tool. The fastener may comprise a breakable member, such as a shear pin, a shear bolt, a shear screw or a shear ring. The fastener may be configured to snap, bend or shear when the pressure differential across the occluding position reaches the threshold value, releasing the gate, which is then free to move or rotate, which in turn may release the occluding member to move to the occluding position under the action of the flow.

The fastener may comprise a metal or a polymer.

The fastener may be fixed with respect to both the outer housing and the gate. The fastener may be fixed by means of a mechanical attachment and/or a chemical adhesive, such as a thread and a chemical adhesive to stop the thread backing out with vibration.

The blocking assembly may be configured to move from the first arrangement to the second arrangement when the pressure differential across the blocking assembly is within a range of about 690 to 2760 kPa (100 to 400 psi), or larger.

As an example arrangement, for a passageway bore of about 70 mm (2.75inches) which is blocked by a gate which is rotatable about a hinge: the area is 3832.25 mm2 (5.94 sq. ins). For a pressure differential of about 1380 kPa (200 psi) when the blocking assembly moves from the first to the second arrangement, the force on the gate is about 539 kg (1188 Ibs). If the hinge of the gate is about 73 mm (2.875 inches) from the centre and the fastener is about 54 mm (2.125 inches) from the centre, the fastener failure load is about 310.7 kg (0.577x1188= 685 Ibs). For a fastener with an ultimate tensile strength of about 345000 kPa (50,000 psi), the diameter of the fastener should be about 3.35 mm (0.132 inches).

The downhole tool may further comprise a latch to hold the gate in the second arrangement.

The latch may be configured to receive and maintain the gate in the second arrangement -that is when the gate is open and the occluding member has been released. The latch may be fixed with respect to the outer housing. The latch may comprise a first part on the gate and a second part on an inside surface of the outer housing.

The latch may comprise a magnet, or a magnetic material, fixed with respect to the outer housing, arranged to abut a further magnet or magnetic material located on the gate when the blocking assembly (including the gate) is in the second arrangement.

The latch may comprise a mechanical latch, for example comprising a collet and collet receiver -one fixed with respect to each of the gate and the housing.

The restraint may comprise a deformable screen arranged to hold the occluding member in the non-occluding position when in the first arrangement and to rupture in response to the change in the flow of drilling fluid through the downhole tool, releasing the occluding member to move to the second arrangement. The deformable screen may be a frangible screen.

The restraint may comprise a deformable screen arranged to prevent the occluding member from passing through a passageway when in the first arrangement. The deformable screen may span a passageway or a part thereof and may be arranged to prevent the occluding member from moving downstream with the flow of the drilling fluid.

When the flow of drilling fluid through the downhole tool changes -for example increasing the flow rate to increase a pressure differential across the blocking assembly -the force exerted by the drilling fluid and/or the occluding member on the screen may cause the frangible screen to deform, for example by bending, dissolving or breaking.

Once deformed, the screen may release the occluding member to move to a second arrangement in which it blocks the flow path.

The frangible screen may be made of a polymer, such as PEEK.

The restraint may comprise a support defining an open internal diameter less than an external dimension of the occluding member. The support may be arranged to restrict the maximum diameter of a flow path or passageway in order to capture an occluding member. In a first arrangement, the support may be arranged to prevent the occluding member from passing through the support. The support and/or occluding member may be configured to deform in response to the change in the flow of drilling fluid through the downhole tool such that the occluding member can pass through the support.

The support may be arranged to reduce or constrict a diameter of a passageway for drilling fluid. The support may restrict the diameter of the passageway such that an occluding member is unable to pass through the restriction and is held in a first arrangement by the support. A pressure differential across the blocking assembly may act on the occluding member and provide a force on the occluding member to move through the support to the second arrangement. The interference between the support and the occluding member may prevent the occluding member from moving the reth ro ug h. At least one of the support and the occluding member may be configured to deform when a pressure differential across the blocking assembly reaches a threshold value. A pressure differential across the blocking assembly may cause a resultant force acting on the occluding member in the direction of flow of drilling fluid through the downhole tool.

This force may act to try to move the occluding member through the support, to the second arrangement. When the pressure differential reaches a threshold value, the force may be such that at least one of the occluding member and the support deforms sufficiently to let the occluding member pass through the support to the second arrangement.

The support may be an annular ring.

The support may be a plurality of protrusions protruding from an inside of the outer housing, arranged to restrict the maximum diameter of a flow path or passageway in order to capture an occluding member.

The support may be made from a metal, metal alloy or a polymer, e.g. plastic. Example materials suitable for use as the support may include steel, PTFE, Torlon and PEEK.

The restraint and occluding member may comprise the same material.

The restraint and occluding member may be made of the same material in order to reduce increased/reduced interference caused by temperature changes. Using the same material for both the restraint and occluding member may eliminate any changes in the amount of interference between the parts due to temperature fluctuations and so may make the release of the occluding member from the support more reliable in a range of environments.

The occluding member may be a ball.

The occluding member may be a solid or hollow ball. The ball may be spherical.

Further according to the disclosure is a downhole string comprising a downhole tool as described herein. The downhole string may be a drill string.

Further according to the disclosure is a method of operating a downhole tool as described anywhere herein. The method may comprise operating the downhole tool with the tool component in the first position; changing the flow of fluid through the downhole tool to move the tool component to the second position; and operating the downhole tool with the tool component in the second position.

Further according to the disclosure is a method of drilling, or reaming, using a downhole tool as described anywhere herein.

Further according to the disclosure is a method of operating a downhole tool (e.g. a downhole tool). The method may be for operating a downhole tool as described anywhere herein. The method may comprise steps as described anywhere herein. The method may comprise operating the downhole tool with the deployable tool component in the first position. When the downhole tool is operated with the deployable tool component in the first position, the primary cutting structure may define a cutting plane with a first diameter. Operating the downhole tool with the deployable tool component in the first position may drill a bore with a first diameter. The method may further comprise moving the deployable tool component to a second position. The deployable tool component may be moved to a second position as described anywhere herein. Moving the deployable tool component to a second position may comprise deploying the deployable tool component, the blades, the deployable cutting structure. The method may further comprise operating the downhole tool with the deployable tool component in the second position. When the downhole tool is operated with the deployable tool component in the second position, the deployable cutting structure may define a cutting plane with a diameter equal to or less (or more) than the first diameter. Operating the downhole tool with the deployable tool component in the second position may drill a bore with a diameter equal to or less (or more) than the first diameter. If the deployable cutting structure defines a cutting diameter which is less than the first diameter, the hole which is drilled may be of the first diameter and the central section of the bore may be drilled by the deployable cutting structure and the outer radial area of the bore may be drilled by the first cutting structure.

The method may further comprise changing the flow of drilling fluid through the downhole tool to move the blocking assembly from a first position (e.g. arrangement) to the second position (e.g. arrangement). Operating the downhole tool with the deployable tool component in the first position may comprise using the primary cutting structure to drill.

Changing the flow of drilling fluid through the downhole tool may comprise increasing the flow rate of drilling fluid through the downhole tool. Operating the downhole tool with the deployable tool component in the second position may comprise using the deployable cutting structure to drill.

Further according to the disclosure is a whipstock milling system. The whipstock milling system may comprise a whipstock. The whipstock may be for diverting the downhole tool from the original trajectory of the well bore. The whipstock milling system may comprise an anchor-packer. The anchor-packer may be for radially and axially locating the whipstock milling system in a well bore by expanding parts of the anchor-packer (e.g. dies) to grip the walls of the well bore or casing therein. The whipstock milling system may comprise a downhole tool as described herein. A primary cutting structure of the downhole tool may be used to drill through steel casing in the well bore. A deployable cutting structure may be used to subsequently drill through formation outside of the steel casing.

The whipstock milling system may further comprise a hose connecting a drilling fluid outlet of the downhole tool to the anchor-packer. The downhole tool and hose may be used to activate the anchor-packer by injecting drilling fluid, released from the outlet and guided through the hose, into the anchor-packer, which subsequently expands in order to grip a portion of the well bore.

According to the disclosure is a downhole tool comprising: an outer housing; a primary cutting structure defining a cutting plane of a first diameter; a flow path arranged to let drilling fluid flow through the downhole tool; and a deployable tool component at least partially located within the outer housing, the deployable tool component comprising a cutting structure and being arranged to be axially movable from a first position, in which the deployable cutting structure is recessed with respect to the primary cutting structure, towards the cutting plane, to a second position; wherein when the deployable tool component is in the second position, the deployable cutting structure defines a cutting diameter which is less than or equal to the first diameter.

The downhole tool may further comprise: an actuation mechanism configured to cause the deployable tool component to move from the first position to the second position; wherein the actuation mechanism is a blocking assembly configured to move from a first arrangement, in which the flow path is open and fluid can flow through the flow path, to a second arrangement, in which the blocking assembly is arranged to restrict fluid flow through the flow path, in response to a change in the flow of drilling fluid through the downhole tool; wherein the deployable tool component is configured to move from the first position to the second position under the action of fluid pressure in response to the blocking assembly moving to the second arrangement.

The change in the flow of drilling fluid through the downhole tool may increase a pressure differential across the blocking assembly to a threshold value.

The downhole tool may further comprise a deformable release arranged between the outer housing and the deployable tool component; wherein a first part of the deformable release is fixed with respect to the outer housing and a second part of the deformable release is fixed with respect to the deployable tool component, restraining the deployable tool component in the first position; wherein the deformable release is configured to deform such that the deployable tool component can move with respect to the outer housing when a pressure differential across the deployable tool component reaches a deployment value.

The deformable release may be a threaded connector configured to break at a predetermined tensile load.

The downhole tool may further comprise a lock arranged to hold the deployable tool component in the second position.

The lock may comprise: an engagement member in one of the outer housing and the deployable tool component, biased towards the other of the outer housing and the deployable tool component; and a recess arranged on the other of the outer housing and the deployable tool component, arranged to receive the engagement member when the deployable tool component is in the second position.

The deployable tool component may comprise: a piston located within the outer housing; and a blade connected to the piston.

The piston and blade of the deployable tool component may be arranged to move parallel to a longitudinal axis of the downhole tool from the first position to the second position.

The deployable cutting structure may be level with, or extend out from, the primary cutting structure in an axial direction when the deployable tool component is in the second position.

The blocking assembly may comprise an occluding member and a restraint, wherein the restraint is configured to hold the occluding member in the first arrangement and release the occluding member in response to the change in the flow of drilling fluid through the downhole tool, such that the occluding member can move from a non-occluding position in the first arrangement to an occluding position in the second arrangement in which the occluding member prevents fluid from flowing through the flow path.

The occluding member may be arranged to move parallel to the axis of the downhole tool from the first arrangement to the second arrangement.

The restraint may comprise a breakable fastener.

The restraint may be a (threaded) connector configured to break at a predetermined tensile load The occluding member may be a rod.

A method according to the disclosure may comprise:

operating the downhole tool with the deployable tool component in the first position to drill a bore with a first diameter; moving the deployable tool component to a second position; operating the downhole tool with the deployable tool component in the second position to drill a bore with a diameter equal to or less than the first diameter.

A whipstock milling system according to the disclosure may comprise: a whipstock; an anchor-packer; and a downhole tool as described anywhere herein.

SPECIFIC DESCRIPTION

Examples of the present disclosure will now be described, purely by way of example, in the below figures, in which: Figure 1 is a perspective view of a drill bit according to the disclosure in a first arrangement; Figure 2 is a perspective view of the drill bit of figure 1 in a second arrangement; Figure 3 is a cross-section of a drill bit according to the disclosure in a first arrangement; Figure 4 is a cross-section of the drill bit of figure 3 in a second arrangement; Figure 5 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 6A is a cross-section of the drill bit of figure 5 in a second arrangement; Figure 6B is a perspective view of the drill bit of figure 5 in a second arrangement; Figure 7 is a further cross-section of the drill bit of figure 5 in a first arrangement; Figure 8 is a further cross-section of the drill bit of figure 5 in a second arrangement; Figure 9 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 10 is a cross-section of the drill bit of figure 9 in a second arrangement; Figure 11 is a further cross-section of the drill bit of figure 5 in a first arrangement; Figure 12 is a further cross-section of the drill bit of figure 5 in a second arrangement; Figure 13 is a cross-section of a lock pin in an unlocked arrangement; Figure 14 is a cross-section of a lock pin in a locking arrangement; Figure 15 is an end view of a drill bit according to the disclosure; Figures 16 and 17 are opposing end views of a component of a drill-bit according to the disclosure; Figures 18 and 19 are end views of drill bits according to the disclosure; Figure 20 is a perspective view of a deployable blade assembly; Figure 21 is a cross-section of a drill bit according to the disclosure; Figure 22 is a perspective view of blades and nozzles; Figure 23 is a cross-section of a drill bit according to the disclosure; Figures 24 and 25 are perspective views of blades; Figure 26 is a perspective view of a piston; Figure 27 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 28 is a cross-section of the drill bit of figure 27 in a second arrangement; Figure 29 is a further cross-section of the drill bit of figure 27 in a first arrangement; Figure 30 is a further cross-section of the drill bit of figure 27 in a second arrangement; Figure 31 is a further cross-section of the drill bit of figure 27 in a first arrangement; Figure 32 is a further cross-section of the drill bit of figure 27 in a second arrangement; Figure 33 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figures 34 and 35 are cross-sections of the drill bit of figure 33 in a second arrangement; Figure 36 is a further cross-section of the drill bit of figure 33 in a first arrangement; Figure 37 is a further cross-section of the drill bit of figure 33 in a second arrangement; Figure 38 is a further cross-section of the drill bit of figure 33 in a first arrangement; Figure 39 is a further cross-section of the drill bit of figure 33 in a second arrangement; Figures 40 and 41 are sleeves for use as a ratchet in a drill bit according to the disclosure; Figure 42 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 43 is a cross-section of the drill bit of figure 42 in a second arrangement; Figures 44 to 46 show a conventional whipstock milling system; Figures 47 to 49 are views of a whipstock milling system comprising a drill bit according

to the disclosure;

Figures 50 and 51 are end views of a drill bit according to the disclosure for use in a whipstock milling system; Figure 52 is a perspective view of a drill bit according to the disclosure for use in a whipstock milling system in a second arrangement; Figure 53 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 54 is a cross-section of the drill bit of figure 53 in a second arrangement; Figure 55 is a further cross-section of the drill bit of figure 53 in a first arrangement; Figure 56 is a further cross-section of the drill bit of figure 53 in a second arrangement; Figure 57 is a further cross-section of the drill bit of figure 53 in a first arrangement; Figure 58 is a further cross-section of the drill bit of figure 53 in a second arrangement; Figure 59 is a further cross-section of the drill bit of figure 53 in a first arrangement; Figure 60 is a further cross-section of the drill bit of figure 53 in a second arrangement; Figure 61 is a perspective view of a deployable blade assembly for use with the drill bit of figure 53; Figure 62 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 63 is a cross-section of the drill bit of figure 62 in a second arrangement; Figure 64 is a cross-section of a further drill bit according to the disclosure in a first arrangement.

Figure 65 is a cross-section of the drill bit of figure 64 in a second arrangement; Figure 66 is a further cross-section of the drill bit of figure 64 in a first arrangement; Figure 67 is a further cross-section of the drill bit of figure 64 in a second arrangement; Figure 68 is a cross-section of part of a blocking assembly; Figure 69 is a cross-section of part of a further blocking assembly; Figure 70 is a perspective view of a further drill bit according to the disclosure in a first arrangement; Figure 71 is a perspective cross-section of the drill bit of figure 64 in a second arrangement; Figure 72 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 73 is a further cross-section of the drill bit of figure 72 in a first arrangement; Figure 74 is a further cross-section of the drill bit of figure 72; Figure 75 is a further cross-section of the drill bit of figure 72; Figure 76 is a perspective view of a cross-section of the drill bit of figure 72; Figure 77 is a further cross-section of the drill bit of figure 72 in a second arrangement; Figure 78 is a further cross-section of the drill bit of figure 72 in a second arrangement; Figure 79 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 80 is a further cross-section of the drill bit of figure 78 in a second arrangement; Figure 81 is a cross-section viewed along the axis of the drill bit of figure 78; Figure 82 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 83 is a further cross-section of the drill bit of figure 82 in a first arrangement; Figure 84 is a further cross-section of the drill bit of figure 82; Figure 85 is a further cross-section of the drill bit of figure 82; Figure 86 is a further cross-section of the drill bit of figure 82 in a second arrangement; Figure 87 is a further cross-section of the drill bit of figure 82 in a second arrangement; Figure 88 is a perspective view of a part of the outer housing and blocking assembly in a first arrangement; Figure 89 is a further perspective view of a part of the outer housing and blocking assembly in a second arrangement; Figure 90 is a cross-section of a further drill bit according to the disclosure in a first arrangement; Figure 91 is a further cross-section of the drill bit of Figure 90; Figure 92 is a further cross-section of the drill bit of Figure 90 in a second arrangement; Figures 93A to 93C are rotationally-separated cross-sections through the drill bit of Figure 90; Figures 94A to 94C are a first end view, perspective and second end view respectively of part of a blocking assembly for use in a drill bit; Figures 95A to 95C are a first end view, perspective and second end view of a deployable blade assembly for use in a drill bit; Figures 96A to 96B are cross-section views of a hybrid drill bit according to the disclosure; Figure 97 is an end view of the hybrid drill bit of Figure 96A; Figures 98A and 98B are perspective views of the hybrid drill bit of Figure 96A; Figures 99A to 99C are cross-section views of a near-bit reamer according to the

disclosure;

Figures 100A and 100B are end views of the near-bit reamer of Figure 99A; Figures 101A and 101 B are side views of the near-bit reamer of Figure 99A; Figures 102A to 102C are cross-section views of an expandable drill bit; Figures 103A and 1038 are end views of the expandable drill bit of Figure 102A; Figures 104A and 1048 are side views of the expandable drill bit of Figure 102A; Figures 105A and 105B are cross-section views of cutter blades of an expandable drill bit according to the disclosure; and Figure 106 is an end view of the cutter blades of Figure 105A.

DETAILED DESCRIPTION OF THE DRAWINGS

In the following description, the same reference numerals will be used to refer to corresponding features in different embodiments according to the disclosure. The corresponding features need not be identical. Furthermore, it is to be understood that, unless it is explicitly stated to the contrary, features from a first embodiment of the disclosure can be combined with features of a second embodiment of the disclosure.

This applies for drill bits of different diameters and different lengths -the features described as part of the present disclosure are applicable to drill bits of all sizes.

Typically, the downhole tools described in Figures 1 to 95C are either 215.9mm (8.5 inch) drill bits or 311.15mm (12.25 inch) drill bits. However, drill bits with diameters other than those above may be made according to this disclosure. Furthermore, downhole tools other than drill bits are equally according to the disclosure.

The length of the 215.9mm (8.5 inch) and 311.15mm (12.25 inch) drill bits described with reference to figures 1 to 43 are typically about 914.4 mm (36 inches). Using a drill bit of this length provides a reasonably steerable drill bit and thus drill string, as the short length of the drill bit allows tighter turning to be achieved.

The a 311.15mm (12.25 inch) drill bit for use as part of a whipstock milling system as described with reference to figures 48 to 61, the length may be about 1676.4 mm (66 inches).

Figure 1 illustrates a downhole tool according to the disclosure. The specific example of a downhole tool illustrated in Figure 1 is a drill bit 10. The drill bit 10 is suitable for attaching to the end of a drill string and being used to drill or mill through media located in a well bore. The drill bit 10 is substantially cylindrical and has a longitudinal axis 16 running along its central axis.

In order to facilitate drilling, the drill bit 10 is configured to allow drilling fluid to flow through at least part of the drill bit 10 and to exit through ports located on the end face and/or the outer curved surface of the drill bit. The drill bit 10 therefore can be considered to have an upstream end 12 (top left in figure 1) and a downstream end 14 (bottom right in figure 1) and drilling fluid flows from the upstream end 12 towards the downstream end 14 along at least a portion of the length of the drill bit 10.

A primary cutting structure 18 is located on the downstream axial end 14 of the drill bit and is used to drill or mill through material at the beginning of a drilling operation. The primary cutting structure 18 comprises a plurality of rows of cutting inserts 20 for cutting into material as the drill bit 10 is rotated. In the present drill bit, the cutting inserts 20A extend from the end surface of the drill bit 10 as well as from the curved side wall of the drill bit 10 in the vicinity of the downstream end 14. The primary cutting structure 18 therefore cuts a front face and the side walls of a bore.

The drill bit 10 also has a plurality of deployable blades 22, each comprising a row of cutting inserts 20B. In figure 1, the deployable blades 22 are in a retracted position (i.e. a first arrangement) and the cutting inserts 20B on the deployable blades 22 do not extend from the primary cutting structure 18 and do not interfere with the material being cut by the drill bit 10. The deployable blades form part of a tool component of the drill bit 10.

Figure 2 shows the drill bit 10 of figure 1 in a second arrangement, in which the deployable blades 22 have moved towards the downstream end 14 of the drill bit 10 and are protruding from the primary cutting structure 18, forming a new, deployable, cutting structure. With the deployable blades 22 in the second arrangement, the cutting inserts 20B on the deployable blades 22 contact any material to be cut first and provide the main cutting function of the drill bit 10. Accordingly, the drill bit 10 is configured to provide two cutting structures, a first, primary cutting structure 18, and a second, deployable cutting structure, which can be selectively presented at the option of a user.

The ability to effectively have a drill bit 10 with two cutting structures enables a drill bit 10 having different cutting characteristics with the deployable blades 22 in the second arrangement compared to the first arrangement and thus being geared towards cutting different materials, or cutting the same material with a different cut depth or bore profile.

Alternatively, the cutting characteristics of the two cutting structures can be substantially the same and the deployable cutting structure can be engaged when the cutting inserts 20A of the primary cutting structure 18 are worn, in order to extend the service life of the drill bit 10.

In order to provide different cutting characteristics, the cutting inserts 20A 20B on the primary cutting structure 18 and deployable blades 22, respectively, can be specifically selected to provide two different cutting functions. Thus the size, shape and material of the cutting inserts 20A 20B can be selected to be geared towards a specific use.

Alternatively, the cutting inserts 20A 20B on the primary cutting structure 18 and deployable blades 22 can be the same type of cutting insert and the deployable blades 22 can be engaged and moved to the second arrangement when the cutting inserts 20A on the primary cutting structure 18 are worn, in order to extend the service life of the drill bit 10.

Turning now to figure 3, a cross-section of a drill bit 10 in a first arrangement is shown. The drill bit 10 has an outer housing 24 substantially tubular in shape. The drill bit is a 215.9mm (8.5 inch) drill bit. At the upstream end 12 of the drill bit 10, a drilling fluid inlet 26 can be seen. Drilling fluid-which flows down the drill string from the surface -enters the drill bit 10 through the drilling fluid inlet 26, flows through the outer housing 24 of the drill bit 10 and flows out through outlets 28 located downstream of the fluid inlet 26. In the drill bit 10 of figure 3, the outlets 28 are located on the end face of the downstream end 14 of the drill bit 10 -that is, the outlets 28 are located in the primary cutting structure 18.

After entering the drill bit 10 through the fluid inlet 26, the drilling fluid flows through a chamber 30 defined by the housing 25. At the end of the chamber 30 is a ball 32 located in a restraint. The restraint and ball 32 collectively form a blocking assembly, which is part of the actuation mechanism of the drill bit (discussed in more detail below).

In the drill bit 10 of figure 3, the restraint is a support in the form of an annular ring 34 for supporting the ball 32. The inner diameter of the annular ring 34 is slightly smaller than the outer diameter of the ball 32. As such, the ball 32 is unable to pass through the annular ring 34 when the blocking assembly is in a first arrangement.

The restraint and ball 32 are located in, and block off, a passage in the outer housing 24 through which drilling fluid could otherwise flow. Instead, the drilling fluid flows around the blocking assembly, through circumferentially-located nozzles 36. The restriction in the flow of the fluid around the ball 32 and annular ring 34 causes a pressure differential across the ball 32, which urges the ball 32 towards the annular ring 34 (i.e. in a downstream direction).

After passing through the nozzles 36, the drilling fluid enters a deployable blade assembly 38 comprising a piston 40 and blades 22. The deployable blade assembly 38 is an example of a tool component. The piston 40 is housed within the outer housing 24.

The blades 22 are connected to the piston 40.

A number of flow paths 42 44 are defined through the piston 40 which allow the drilling fluid to exit the drill bit 10 at the primary cutting structure 18 or through the outer housing 24, via nozzles 46 located in or adjacent the outlets 28.

At a certain point during the drilling operation, a user may decide that they wish to use the deployable cutting structure -i.e. to move the blades 22 to a second position such that the second set of cutting inserts 20B are engaged.

Figure 4 shows the drill bit 10 of figure 3 in the second arrangement, with the deployable blade assembly 38 extended -having moved towards the downstream end of the drill bit 10 such that the end of the blades 22 and the cutting inserts 20B protrude out from the primary cutting structure 18 to form a deployable cutting structure.

To move the drill bit 10 from the first arrangement to the second arrangement, a user increases the flow rate of drilling fluid through the drill bit 10. This increase in flow rate increases the pressure differential across the ball 32 to a threshold value. At the threshold value, the ball 32, the annular ring 34, or both deform sufficiently to let the ball 32 pass through the annular ring 34. At this point the blocking assembly moves from a first arrangement towards a second arrangement. This method of activation is very easy for a user to control. It is also robust and reliable, as fluid is constantly flowing through the drill string and it does not rely on a mechanical device deployed into the drill string (which can often get blocked on the way down) or an electrical connection (which can often be damaged due to the harsh environment in which such a device may be operating).

In order to move the blocking assembly from the first to the second arrangement, for a 215.9mm (8.5 inch) drill bit, the pressure drop across the blocking assembly may increase from about 689.5 kPa (100 psi) at a flow rate of 30.3 litres per second (400 gpm) to about 1550 kPa (225 psi) at a flow rate of 45.4 litres per second (600 gpm).

Once the ball 32 has passed through the annular ring, the flow of drilling fluid through the drill bit 10 carries the ball 32 towards the downstream end 14 of the drill bit. The piston 40 comprises a tapered section comprising a seat 48 for holding the ball 32. Fluid flow through the piston 40 locates and holds the ball 32 in the seat 48. The seat 48 is arranged to be a constriction in, and thus form part of, one of the flow paths 44. It will typically take less than a second for the ball 32 to move from the first arrangement (supported by the annular ring 34) to the second arrangement (supported in the seat 48).

When the ball 32 is located in the seat 48, one of the flow paths 44 through the piston is blocked off by the ball 32, preventing drilling fluid from flowing therethrough; accordingly, the pressure differential across the piston 40 (and deployable blade assembly 38 as a whole) increases. The pressure differential across the piston 40 reaches a deployment value. When the pressure differential across the deployable blade assembly 38 reaches the deployment value, the deployable blade assembly 38 moves from a first position in which the cutting inserts 20B on the blades 22 are recessed with respect to the primary cutting structure 18, to a second position in which the cutting inserts 20B on the blades 22 protrude from the primary cutting structure 18, forming a deployable cutting structure. Figure 4 shows the drill bit 10 in a second arrangement, with the deployable blade assembly 38 in a second position.

In the 215.9mm (8.5 inch) drill bit described, the deployable blade assembly 38 moves about 35 mm (1.375 inches) when moving from the first to the second position. However, other drill bits may move more or less than this amount.

The cavity at the downstream end of the drill bit -located between the piston and the primary cutting structure -is allowed to fill with low pressure drilling fluid at all times. However, as the gaps around the blades are very small when the deployable blade assembly 38 is in the first position a lot of cuttings debris should not be able to get into these large cavities under the piston. When the deployable blade assembly 38 travels to the second position, a large gap will be created on the upstream ends of the blades (behind the piston) will allow the of ingress large debris, but this will not affect operation of the drill bit.

The primary cutting structure 18 defines a bore with a first diameter. The deployable cutting structure defines a bore with the same diameter as the primary cutting structure 18. This is achieved by the deployable cutting assembly 38 (i.e. the deployable blades 22 and the cutting inserts 20B themselves) having a profile of the same diameter as the primary cutting structure 18 when viewed along the axis 16, and the deployable cutting assembly 38 (i.e. deployable blades 22) being arranged to only move parallel to the longitudinal axis 16 of the drill bit 10 when moving from the first to the second position.

Providing two different cutting structures with the same bore diameter provides a number of benefits. Importantly, it provides continuity along the length of the hole. This simplifies later usage, as a change in bore diameter does not need to be considered when determining downhole components. Use of a constant bore diameter ensures that the drill bit itself can be easily extracted from the bore once drilling is complete. If a drill bit has a larger diameter in the second arrangement -i.e. the cutting inserts 20B on the blades 22 define a bore diameter which is larger than that of the primary cutting structure 18 when in the second position -it may be difficult to extract the drill bit from the completed bore as its final diameter will be larger than the diameter of the first section of the hole.

In order to prevent leakages reducing the efficacy of the drill bit, a number of seals 50 are located between the outer housing 24 and internal components (e.g. the piston 40 and blocking assembly) to prevent drilling fluid from passing between components and thus reducing pressure differentials. Only one seal is used if all the flow nozzles are on the face of the primary cutting structure. Three seals are needed (as shown) if one or more nozzles are located on the outside diameter of the drill bit (as in this variant) which may have to be used if there is not enough space to locate enough flow ports on the face of a bit.

Figures 5 and 6A illustrate a drill bit similar to that of figures 3 and 4, except with the nozzles 46 of the deployable blade assembly 38 being located at a more downstream location -that is, the nozzles 46 are located much closer to the primary cutting structure 18 than in the drill bit of figures 3 and 4. As with the drill bit of figure 3, the primary cutting structure 18 and deployable cutting structure define a bore with the same diameter.

Figure 6B is a perspective of the downstream end 14 of the drill bit in the second arrangement and the nozzles 46 can be seen, located between rows of cutting inserts 20A 20B, for ejecting drilling fluid straight into the drilling zone for facilitating cutting, in a known manner. A nozzle 46 can also be seen on the curved surface of the outer housing 24, which will be discussed further with reference to figures 7 and 8.

Figures 7 and 8 show the drill bit of figures 5 and 6 rotated by approximately 45 degrees with respect to the view in figures 5 and 6. Figures 7 and 8 show further details of the flow path 44 blocked by the ball 32 when the drill bit is in the second arrangement. This flow path 44 splits at a location downstream of the seat 48, but still within the piston 40, into two paths separated by 180 degrees. The two paths are located radially and nozzles 46 in the side wall of the outer housing 24 connect the paths to the outside and thus facilitate the radial ejection of drilling fluid. The nozzles 46 are fixed with respect to the outer housing 24.

The number and location of outlets provided in a drill bit 10 can be selected to determine optimal use parameters. Reducing the number of available outlets may increase the pressure differential across the drill bit. Locating outlets upstream of the deployable blade assembly 38 may allow a higher drilling fluid input flow rate to be utilised while maintaining within certain pressure gradient parameters across the deployable blade assembly 38. Likewise, arranging a larger number of the available outlets to form part of the flow path 44 blocked by the ball 32 will maximise the increase in pressure differential across the deployable blade assembly 38 when the ball 32 moves into the second arrangement.

Referring back to figures 7 and 8, blades 22 can be seen located in slots of the outer housing, the slots being arranged axially to ensure the blades 22 extend axially, parallel to the longitudinal axis of the drill bit.

Figures 7 and 8 also depict a guide pin 52 fixed with respect to the outer housing 24. The guide pin 52 extends from an internal face of the outer housing 24, into an elongated recess 54 located in the outer surface of the piston 40. The recess 54 is axially elongated, that is in a direction parallel to the longitudinal axis 16 of the drill bit. The guide pin 52 and recess 54 are arranged to help guide the piston 40 and hence the deployable blade assembly 38 as it moves from the first position to the second position. Accordingly, the elongated recess 54 has a length substantially equal to the distance between the first and second positions of the piston 40 and the guide pin 52 travels along the recess 54 from a downstream end elongated recess 54 to an upstream end of the elongated recess 54 as the piston moves from the first to the second position.

Figures 7 and 8 also depict a shear pin 56, arranged to hold the piston 40 (and hence deployable blade assembly 38) in the first position. When the drill bit is in the first arrangement, the shear pin 56 is located in the outer housing 24 of the drill bit and extends into a receiving hole in the piston 40. Accordingly, the shear pin 56 spans the interface between the outer housing 24 and the deployable blade assembly 38 and holds the piston 40 and hence the deployable blade assembly 38 in the first position. As the flow rate of drilling fluid through the drill bit increases and the ball 32 moves through the annular ring 34 and into the seat 48 of the piston 40, the pressure differential across the piston 40 (and hence deployable blade assembly 38) increases which in turn increases the force exerted on the deployable blade assembly 38 by the drilling fluid, towards the downstream end of the drill bit. Initially, the shear pin 56 resists this movement and hence holds the piston 40 in the first position. However, when the pressure differential across the deployable blade assembly 38 reaches a deployment value, the shear pin 56 can no longer withstand the force exerted on it by the piston 40 and the shear pin 56 shears at the interface between the outer housing 24 and the piston 40. As the deployable blade assembly 38 is no longer held in the first position by the shear pin 56, the deployable blade assembly 38 moves to the second position. Accordingly, the breakage strength of the shear pin 56 determines the deployment value at which the deployable blade assembly 38 moves from the first to the second position. Figure 8 illustrates the deployable blade assembly 38 in the second position, with the shear pin 56 broken in two parts -half in the outer housing 24 and half in the piston 40.

Figures 9 and 10 illustrate a drill bit with an alternative arrangement for the flow path 44 which is blocked by the ball 32 when in the drill bit is in the second arrangement. The majority of the drill bit of figures 9 and 10 is similar to that of figure 5; however, the flow path 44 which is blocked by the ball 32 when the drill bit is in the second arrangement is arranged to have an outlet in the downstream end of the drill bit -that is in the primary cutting structure 18. Such an arrangement may provide more flow out of the primary cutting structure 18 when the drill bit is in the first arrangement, as none of the flow is being directed out of the sides of the outer housing 24. The choice of where to output the drilling fluid flow may be made based on the desired cutting characteristics and environment of the specific drill bit and on the space available to locate nozzles within the passageways/flow paths of the bit face of the primary cutting structure.

Figures 11 and 12 show the drill bit of figures 5 and 6 rotated by approximately 90 degrees with respect to the view shown in figures 7 and 8. Lock pins 58 are visible in figures 11 and 12, for securing the piston 40 and hence holding the deployable blade assembly 38 in the second position. The lock pins 58 are located in the outer housing 24 of the drill bit and are biased inwardly -towards the centre of the drill bit. A spring 60 is located radially outwardly with respect to the lock pin and is held in place by a cap.

Thus the spring 60 pushes the lock pin 58 towards the piston.

Locking recesses 62 are located on the outer surface of the piston 40, arranged to receive the lock pins 58 when the deployable blade assembly 38 is in the second position.

When the deployable blade assembly 38 is in the first position, the lock pins 58 abut the outer surface of the piston 40 and so are held in an outward location -entirely located within the outer housing 24. As the deployable blade assembly 38 moves from the first position to the second position, lock pins 58 slide along the outer surface of the piston and, when the deployable blade assembly 38 reaches the second position and the locking recesses 62 are aligned with the lock pins 58, the lock pins 58 pop out of the inner surface of the outer housing to locate in the locking recesses 62 of the piston 40. Thus the lock pins 58 span the interface between the outer housing 24 and the piston 40 and therefore lock the piston 40 (and hence the deployable blade assembly 38) in position with respect to the outer housing 24. The lock pins 58 therefore act to hold the blades 22 and the cutting inserts 22B on the blades in position and to counter any drilling forces acting on the blades 22 which would otherwise force the deployable blade assembly 38 to move out of the second position towards the first position.

Figures 13 and 14 show an alternative example of lock pin systems for use with any drill bit according to the disclosure in a locked and unlocked arrangement, respectively. The example of figures 13 and 14 are located in holes through the outer housing 24 and comprise lock pins 58, biased by springs 60 out from the outer housing 24 towards the piston 40. The springs 60 are held in place by plugs 64 which are in turn held in place by circlips 66. A seal 68 surrounds the plug 64 and in combination with the circlip 66 prevents fluid and wellbore debris from entering or leaving the drill bit via these holes.

Figures 15 and 16 show the downstream end 14 of a drill bit. Figure 17 shows the internal bore of the body from the upstream end without other parts fitted.

Figure 15 shows an example arrangement of cutting inserts 20A of the primary cutting structure 18 and an example arrangement of blades 22 and cutting inserts 20B which form a deployable cutting structure. The cutting inserts 20A of the primary cutting structure can be seen to be arranged in 8 substantially radial rows with between 3 and 7 cutting inserts 20A being visible in each row. Nozzles 46 are arranged amongst the cutting inserts such that drilling fluid can be output onto the cutting structure during drilling. Blades 22 are arranged in between rows of fixed cutting inserts 20A. Each blade 22 comprises between 6 and 10 cutting inserts 20B visible from the view in figure 16.

Three of the blades 22 comprises only a single row of cutting inserts 20B when viewed axially from the downstream end of the drill bit. One of the blades 22 is substantially [shaped and comprises two rows of cutting inserts 20B when viewed axially from the downstream end of the drill bit. The two rows of cutting inserts are arranged substantially at 90 degrees to each other. The purpose of having such a blade 22 is to ensure that the deployable cutting structure has cutting inserts 20B provided across the entire diameter of the surface -i.e. to ensure that cutting inserts 20B are present to cut rock located substantially at the centre of the bore. The cutting inserts along one side of the L-shaped blade may be smaller than the cutting inserts along the other side of the L-shaped blade.

In other embodiments (not illustrated) the deployable cutting structure may only have cutting inserts 20B located towards the outside of the drill bit face. That is, the deployable drilling structure may not provide cutting inserts 20B towards the centre of the drill bit face as shown in figure 15. This is because the cutting inserts 20A of the primary cutting structure located towards the outside of the drilling face (that is a larger distance from the axis 16) move much faster than those at the centre and thus wear down much quicker. Accordingly, the deployable cutting structure may be employed to replace the worn cutting inserts 20A located at large radiuses from the axis 16, rather than to provide an entirely new cutting surface.

Each blade 22 comprises a key 70 in the form of an axial, semi-circular protrusion running along the length of one side of the blade 22. Each key 70 is located in a keyway formed in the housing. Each key 70 slides along its respective keyway, which ensures that each blade 22 can only move axially (i.e. parallel to the longitudinal axis of the drill bit) and not radially.

In figure 15 the cutters 20B of the blades 22 are located behind the cutters 20A of the primary cutting structure with respect to a rotation/cutting direction. The drill bit will be rotating anti-clockwise as shown in figure 15 i.e. looking uphole, but clockwise looking downhole, as is normal. The cutters 20B of the deployable cutting structure are thus generally located behind corresponding cutters 20A of the primary cutting structure when viewed in terms of oncoming material to be cut. In other examples, the cutters 20B of the deployable cutting structure may be generally located behind corresponding cutters 20A of the primary cutting structure when viewed in terms of oncoming material to be cut. All blade cutter rows radiate to the centre of the bit and are designed as such if enough space is available. In the embodiment of figure 15, however, with 4 blades there is not enough room for the moveable blades to radiate to the centre axis (in this specific embodiment). The cutters 20B of the deployable cutting structure are generally radially-staggered compared to adjacent cutters 20A of the primary cutting structure. Furthermore, the cutters 20B of the deployable cutting structure may have an equal angular spacing.

The external surface of the drill bit is hard faced in order to toughen exterior surfaces of the drill bit which may contact the formation or casing.

Figure 16 is an axial view in an upstream direction of part of the drill bit housing with the deployable blade assembly 38 removed. The profile of the slots for the blades 22 and the holes for the nozzles 46 are illustrated. Figure 17 is a view of the component of figure 16 in the opposite direction (a downstream direction).

Figures 18 and 19 depict alternative cutting structure arrangements, for example being suitable for different diameter drill bits. Similarly to with figure 15, figures 18 and 19 depict the cutting insert 20A arrangement for the primary cutting structure 18 and the cutting inserts 20B on the blades 22 which form the deployable cutting structure. Figures 18 and 19 depict the cutting structures for drill bits with different diameters to that of figure 15. However, corresponding features are visible and corresponding comments apply.

Figure 20 shows a deployable blade assembly 38 for use with a drill bit. The deployable blade assembly 38 is located generally within the outer housing 24 of the drill bit and is arranged to move axially with respect to the outer housing, and hence drill bit.

As described above, the deployable blade assembly 38 has a piston 40 to which four blades 22 are attached. Each blade 22 has a plurality of cutting inserts 20B located on its outer edge(s) and which form the cutting structure, or cutting structure, of the drill when the deployable blade assembly 38 is in the second position. The outer profile of the blades 22 and cutting inserts 20B determine the profile of the deployable cutting structure. As such, the shape of the blades 22 may vary depending on the material to be cut and the use for which the drill bit is designed.

In between the blades 22 are four piston tubes 72 which connect the nozzles 46 for outputting drilling fluid to the respective flow paths 42. Also visible is the elongated recess 54 for receiving a guide pin 52 and a lock-pin receiving recess 62. Seals 50 are located in circumferential grooves on the piston in order to provide a seal between the piston 40 and the outer housing 24 to prevent drilling fluid leak. Also visible in figure 20 as part of the deployable blade assembly 38 is a serrated sleeve 74, for use in a ratchet locking system described in more detail below.

Figure 21 is a cross-section perpendicular to the longitudinal axis of the drill bit through the deployable blade assembly 38 and illustrates a pin 76 threaded through a hole near the base of each blade 22 to attach the blade to the piston 40. The hole projects to an outer surface of the housing 24 to provide access to the pins 76. Figure 22 shows the arrangement of the blades 22, the pins 76 used to attach the blades and the tubes 72 which house the nozzles 46.

Figure 23 is a cross-section perpendicular to the longitudinal axis of the drill bit through the outer housing 24 and deployable blade assembly at the level of the outlets from the flow path 44 which is blocked by the ball 32, when in the deployable blade assembly 38 is in the second position. The flow path 44 and outlets blockable by the ball 32 can be seen to extend between the flow paths 42 which run axially within the drill bit 10 and have outlets on the cutting structure of the drill bit 10.

Figures 24 and 25 are perspective views of a blade 22 for use with a drill bit.

Figure 26 is a perspective view of a piston 40 for use with a drill bit. The grooves, slots and holes for receiving the seals 50, blades 22 and tubes 72 are visible.

Figures 27 to 32 show a further downhole tool in the form of a drill bit according to the present disclosure. The drill bit of figures 27 to 32 is a 311.15mm (12.25 inch) drill bit. The majority of the features of the drill bit of figures 27 to 30 correspond to those of figure 5, albeit with slightly different dimensions and arrangements. As such, it should be assumed that features not explicitly described as being different to those of figure 5 operate in a corresponding manner to those of figure 5.

With regard to the drill bit of figure 27, the blocking assembly and tool component in the form of a deployable blade assembly 38 operate in largely similar manners to those of figure 5. Drilling fluid enters the drill bit by means of drilling fluid inlet 26 and, when in the first arrangement, flows around the outside of the blocking assembly comprising a ball 32 and annular ring 34 using nozzles 36. The drilling fluid then flows through the piston 40 and out of the drill bit by means of the flow paths 42 44.

When the flow rate increases a pressure gradient across the ball 32 reaches a threshold value and the ball 32 moves through the annular ring 34 and locates on the seat 48 in the piston 40, thus blocking off a flow path 44. This then causes an increase in pressure gradient across the deployable blade assembly 38 and, once the pressure differential reaches a deployment value, a shear pin 56 is broken (see figures 29 and 30) and the deployable blade assembly 38 moves from the first to the second position causing the cutting inserts 20B on the edges of blades 22 to protrude from the primary cutting structure 18 and thus providing a second, deployable cutting structure. As with the drill bit of figure 5, a guide pin 52 assists in guiding the movement of the piston 40 and a pair of locking pins 58 engage locking recesses 62 in the piston 40 when the piston 40 is in the second position (see figures 31 and 32).

In order to move the blocking assembly from the first to the second arrangement, for a 311.15mm (12.25 inch) drill bit, the pressure drop across the blocking assembly may increase from about 689.5 kPa (100 psi) at a flow rate of 54.6 litres per second (720 gpm) to about 1550 kPa (225 psi) at a flow rate of 81.8 litres per second (1080 gpm).

In the 311.15mm (12.25 inch) drill bit described, the deployable blade assembly 38 moves about 44.5 mm (1.75 inches). However, other drill bits may move more or less than this amount.

The drill bit of figure 27 also comprises a split ratchet ring. The split ratchet ring is located between the outer housing and the deployable blade assembly 38, namely the piston 40. The split ratchet ring is configured to allow movement of the deployable blade assembly 38 towards the second position and prevent movement of the deployable blade assembly 38 away from the second position -that is the split ratchet ring is configured to only allow movement of the piston 40 towards the right in figures 27 to 32.

In the drill bit of figure 27, the ratchet ring sub-assembly comprises an inner 74 and outer serrated sleeve 78. The inner serrated sleeve 74 is fixed relative to the piston 40 with the serrations facing outwards. The outer serrated sleeve 78 is fixed relative to the outer housing 24 with the serrations facing inwards. The inner and outer serrated sleeves 74 78 are arranged such that the serrations engage when the piston 40 is located inside the outer housing 24. The inner ring has no split while the outer ring has to be split to allow it to expand when the inner ring moves downwards.

In the drill bit of figure 27, the serrations have a first face at an oblique angle (e.g. about degrees) to the longitudinal axis of the drill bit and a second face substantially perpendicular to the longitudinal axis of the drill bit. When the deployable blade assembly 38 is moving from the first position to the second position (that is, to the right in figures 27 to 32), the angled surfaces of the two sleeves 74 78 engage and the inner sleeve 74 is able to slide relative to the outer sleeve 78. When the deployable blade assembly 38 is trying to move towards the first position from the second position (that is, to the left in figures 27 to 32), the perpendicular faces ("straight faces") of the two sleeves 74 78 abut and prevent movement of inner sleeve 74 relative to the outer sleeve 78 and hence prevent movement of the movably blade assembly 38 towards the first position.

Figures 33 to 39 depict a downhole tool in the form of a drill bit similar to that of figure 27. A difference between the drill bit of figures 33 to 39 and the drill bit of figure 27 is that the blocking assembly and the surrounding passageway arrangement is slightly modified -it can be seen that in the embodiment of figure 33, the ball 32 and annular ring 34 are housed in a defined central passageway, separated from the surrounding passageway(s) leading to the nozzles 36. Given that drilling fluid cannot pass through the annular ring 34 while the ball 32 is in the position shown in figure 33, there will be no flow of fluid in the length of passage 82 leading to the ball 32 and, as such, the ball 32 will feel a static fluid pressure. Only once the ball 32 has been released from the annular ring 34 will drilling fluid flow through the central passageway.

Figures 40 and 41 illustrate the internal serrated sleeve 74 and external serrated sleeve 78, respectively. It can be seen that the external-facing serrations of the internal serrated sleeve 74 are arranged to engage the internal-facing serrations of the external serrated sleeve 78. On both the internal 74 and external 78 serrated sleeve the serrations are in the form of a row of equi-spaced grooves of a helix. The profile of the serrations can be seen in figure 40. The profile is a saw tooth with a flattened top section. The profile of the serrations may be the same in both the internal 74 and external serrated sleeve 78 (although reversed in order to engage). The external serrated sleeve 78 has an axial split in order to allow the external serrated sleeve 78 to radially expand and contract as required for installation purposes and to more easily allow it to ride over the serrations of the internal sleeve 74 when the deployable blade assembly 38 is moving from the first to the second position.

Figures 42 and 43 illustrate a downhole tool in the form of a drill bit largely similar to that of figure 33. A difference between the drill bit of figure 42 and that of figure 33 is that the deployable blade assembly 38 is held in the first position by a shear ring 82 rather than a shear pin 56. The shear ring 82 is located between the outer housing 24 and the piston 40 of the deployable blade assembly 38. One part of the shear ring 82 is fixed with respect to the outer housing 24 and another part is attached to the piston 40 such that, as the pressure differential across the deployable blade assembly 38 increases and the deployable blade assembly 38 is urged to the right of figure 42, the force exerted on the shear ring 82 increases. When the force in the shear ring 82 reaches a certain value, the shear ring 82 breaks, releasing the piston 40 with respect to the outer housing 24.

The shear ring 82 therefore defines a threshold pressure differential at which the deployable blade assembly 38 moves from the first to the second position, referred to herein as the deployment value.

As a numerical example relating to the failure of the shear ring -when the ball 32 moves to the second arrangement and closes off one of the four flow paths through the piston, the pressure may jump up by 78% from about 4960 kPa to 8800 kPa (720 to 1280 psi). The failure pressure of the shear ring could be anywhere between 4960 kPa to 8800 kPa (720 to 1280 psi) but to give a good safety factor on the shear ring, about 6900 kPa (1000 psi) is chosen in this specific example. If the piston seal diameter is about 206 mm (8.125 inches), the piston area is about 0.033 m2 (51.85 sq. inches). The load to the shear ring will be about 23500 kg (1000psi x 51.85 = 51849 Ibs). If the ultimate tensile strength of the shear ring is about 827400 kPa (120000 psi), the area of the breakable region needed is about 279 mm2 (0.432 sq inches). As the shear ring neck outer diameter is about 174 mm (6.85 inches), the inner diameter needed is about 173 mm (6.810 inches), to provide about a 0.5 mm (0.020 inch) wall section.

Figures 44 to 46 depict a known whipstock milling system comprising a drill bit 90 connected to a whipstock 92 by means of a shear bolt 94. All but one of the drilling fluid outlets in the drill bit 90 are sealed by knock-off plugs 96. The one outlet that is not sealed by a knock-off plug 96 is connected to a hose 102, the far end of which is threaded through a hole in the whipstock 98 and connected to a top of anchor-packer 100 such that the flow of drilling fluid can be used to activate the anchor-packer 100 using drilling fluid at a pressure of up to about 20684 kPa (3000 psi). When the whipstock milling system reaches the desired depth in the well bore, drilling fluid is pumped through the drill string. The drilling fluid flows through the one fluid outlet which is not sealed by a knock-off plug, through the hose 102 and into the anchor packer 100. The high-pressure drilling fluid activates the anchor-packer 100 which anchors the whipstock milling system within the wellbore.

Once the anchor-packer 100 sets the whipstock 92, upwards movement of the drill-string and so drill bit 90 causes the shear bolt 94 and the shearable connection between the hose 102 and the drill bit 90 to shear. The knock-off plugs 94 are knocked off once the drill bit 90 starts drilling operations.

Figures 47 to 49 show a whipstock milling system according to the disclosure. The whipstock drilling system operates in a similar manner to the one described above. The whipstock milling system comprises a drill bit 110 connected to a whipstock 112 by a shearable bolt 120. A hose 114 extends from an outlet of the drill bit 110, through a hole in the whipstock 112 and connects to an anchor-packer 116 at the end of the whipstock 112. Knock-off plugs 118 seal the other outlets. Once drilling operations between, the knock-off plugs are knocked off from the outlets through interaction with the casing or rock face and drilling fluid flows therethrough.

Figures 50 and 51 show an end face of the drill bit of a whipstock milling system before and after drilling operation has started. In figure 50 the knock-off plugs 118 are present.

In figure 51, after drilling operations have begun, the knock-off plugs 118 have been knocked off and the outlets are open for drilling fluid flow.

The drill bit for use with a whipstock milling system is largely similar to the other drill bits described above. As can be seen from figures 50 to 60 (and subsequent figures), the drill bit comprises corresponding features to the drill bits described above and operates in an analogous manner. The dimensions and profile of the drill bit for use with a whipstock milling system may be different to that of the drill bits described above, for example the length of the drill bit for use with a whipstock milling system may be longer than that of the previously-described drill bits. The operation and functions carried out by equivalent parts in the drill bit for the whipstock milling system and the above-described drill bits are equivalent. Accordingly, only a brief description of the drill bit will be provided below. It is to be understood that any description made above in relation to features corresponding to those shown in the following figures, applies to the features shown in the following figures, where appropriate and adapted as appropriate.

As can be seen in figures 50 to 52, the drill bit comprises a primary cutting structure 18 comprising a plurality of rows of cutting inserts 20A. The drill bit also comprises blades 22 as part of a deployable blade assembly 38, each of which comprises a row of cutting inserts 20B which can form a deployable cutting structure. Figure 52 illustrates the blades 22 protruding from the primary cutting structure to provide a deployable cutting structure.

In a drill bit for use with a whipstock milling system, the cutting inserts 20A of the primary cutting structure 18 are made of a material which is suitable for drilling through steel casing located in a wellbore. The cutting inserts 20A in the primary cutting structure may therefore be tungsten carbide milling cutting inserts, for example. The cutting inserts 20B of the deployable cutting structure, attached to the blades 22, may be suitable for drilling formation. The cutting inserts 20B attached to the blades 22 may, therefore, be PDC cutting inserts, for example. This arrangement provides an advantageous system in which cutting inserts suited to the operation at hand are used at all times. Tungsten carbide cutting inserts -well suited to cutting through steel casing -can be used to mill a hole through the steel casing. Once a hole has been drilled through the steel casing, the drill bit can be activated such that the deployable blade assembly 38 moves to the second position and the deployable cutting structure is exposed. The deployable cutting structure utilises PDC cutting inserts and the drill bit is therefore now well suited to cutting through formation. The drill bit therefore has an element of adaptability. Once operations are complete, the drill string and drill bit can be drawn through the hole in the formation and steel casing, since the bores of the primary cutting structure 18 and deployable cutting structure are equal.

As with the drill bits described above, the primary cutting structure 18 and the deployable cutting structure define a bore with the same diameter. Accordingly, the bore of the hole through the steel casing is the same as that through the formation behind it and the drill bit can easily be withdrawn through the formation and casing, back to the surface.

Figures 53 to 60 are cross-sections of the drill bit. As with the drill bits described above, drilling fluid enters the drill bit by means of drilling fluid inlet 26 and, when the deployable blade assembly 38 is in the first position, the fluid flows around the outside of the blocking assembly comprising ball 32 and annular ring 34 using nozzles 36. The drilling fluid then flows through the piston 40 and out of the drill bit by means of the flow paths 42 44.

When the flow rate increases a pressure gradient across the ball 32 reaches a threshold value and the ball 32 moves through the annular ring 34 and locates on the seat 48 in the piston 40, thus blocking off a flow path 44. This then causes an increase in pressure gradient across the deployable blade assembly 38 and, once the pressure differential reaches the deployment value, a shear pin 56 is broken (see figures 57 and 58) and the deployable blade assembly 38 moves from the first to the second position causing the cutting inserts 20B on the edges of blades 22 to protrude from the primary cutting structure 18 and thus providing a second, deployable cutting structure. As with the drill bit of figure 5, a guide pin 52 assists in guiding the movement of the piston 40 and a pair of locking pins 58 engage locking recesses 62 in the piston 40 when the piston 40 is in the second position (see figures 59 and 60).

In a 311.15 mm (12.25 inch) drill bit for use with a whipstock milling system, the deployable blocking assembly moves about 187.3 mm (7.375 inches) from the first position to the second position.

The drill bit of figures 53 to 60 also comprises a ratchet ring sub-assembly. The ratchet ring sub-assembly is located between the outer housing and the deployable blade assembly 38, namely the piston 40. The ratchet ring sub-assembly is configured to allow movement of the deployable blade assembly 38 towards the second position and prevent movement of the deployable blade assembly 38 away from the second position -that is the ratchet is configured to only allow movement of the piston 40 towards the right in figures 53 to 60.

The ratchet ring sub-assembly comprises an inner 74 and outer serrated sleeve 78. The inner serrated sleeve 74 is fixed relative to the piston 40 with the serrations facing outwards. The outer serrated sleeve 78 is fixed relative to the outer housing 24 with the serrations facing inwards. The inner and outer serrated sleeves 74 78 are arranged such that the serrations engage when the piston 40 is located inside the outer housing 24.

The serrations have a first face at an oblique angle (e.g. about 45 degrees) to the longitudinal axis of the drill bit and a second face substantially perpendicular to the longitudinal axis of the drill bit. When the deployable blade assembly 38 is moving from the first position to the second position (that is, to the right in figures 53 to 60), the angled surfaces of the two sleeves 74 78 engage and the inner sleeve 74 is able to slide relative to the outer sleeve 78. When the deployable blade assembly 38 is trying to move in the direction of the first position from the second (that is, to the left in figures 53 to 60), the perpendicular faces of the two sleeves 74 78 abut and prevent movement of inner sleeve 74 relative to the outer sleeve 78 and hence prevent movement of the movably blade assembly 38 towards the first position.

Figure 61 shows a deployable blade assembly 38 of the drill bit, showing the piston 40 and blades 22.

Downhole tools according to the disclosure may comprise blocking assemblies which vary from that described above. Figures 62 and 63 depict a drill bit with an outer housing 24, deployable blade assembly 39, ratchet ring sub-assembly and lock pin 58 -among other features -as described above. However, the restraint of the blocking assembly comprises a hinged gate 122 and a shearable screw 124. When the blocking assembly is in a first arrangement, as shown in figure 62, the hinged gate 122 is in a closed position -preventing the ball 32 from passing through the central passageway 80. The hinged gate 122 is held in the closed position by a fastener, specifically a shearable screw 124, which is fixed with respect to both the hinged gate 122 and the outer housing 24.

Shearable screw 124 is configured to shear when a certain force is applied to it. As such, as the flow rate through the drill bit increases, the pressure differential across the ball 32 and hinged gate 122 increases, creating a resultant force on the hinged gate 122 which is supported by the shearable screw 124. When the pressure gradient across the ball 32 and gate 122 reaches a threshold value, the shearable screw 124 fails, the hinged gate 122 opens, the ball 32 moves towards the piston and the blocking assembly moves to the second arrangement.

Once the ball 32 is released, the drill bit operates in an analogous manner to the drill bits described above. The ball 32 locates in the seat 48 in the piston 40 and blocks off a flow path 44. This causes an increase in the pressure differential across the deployable blade assembly 38 and, when the pressure differential reaches a certain value -the deployment value -a shearable member (e.g. a shear pin) breaks and the deployable blade assembly moves to the second position, exposing the deployable cutting structure, as shown in figure 63.

Example data for a 215.9mm (8.5 inch) drill bit as described above is as follows.

* Ultimate load to break the shear pin holding the deployable blade assembly in the first position: diameter: about 20.5 mm (0.808 INS); area: about 329 mm2 (0.51 square inches); material: brass; ultimate shear strength: about 251320 kPa (35,000 psi); LOAD: about 8100 kg (17,850 LBS). ;* Required pressure differential across the movable blade assembly to shear the shear pin holding the deployable blade assembly in the first position: bore diameter: about 142.9 mm (5.625 inches); piston area: about 0.016 m2 (24.9 SQ INS); pressure: about 4940 kPa (717 PSI).

Figures 64 to 67 illustrate a further example of a blocking assembly. As before, features not forming part of the blocking assembly are as described above and comments made above relating to these features apply, where appropriate and adapted as appropriate.

Similarly to the drill bit of figure 62, the blocking assembly of the drill bit of figure 64 includes a ball 32 and a gate 122 held in the first arrangement by shearable screw 124. The operation of the ball 32, gate 122 and shearable screw 124 is as previously described. Additionally, the blocking assembly of the drill bit of figure 64 also includes a latch 126 to hold the gate in the second arrangement once it has been released by the shearable screw 124. The latch 126 comprises an outer-housing mounted component 126A and a gate-mounted component 126B. When the gate is fully opened, the gate mounted component 126B is received by the outer housing mounted component 126A and retained, thus holding the gate 122 in the second position (i.e. open), as shown in figures 65 and 67.

Figures 68 and 69 illustrate different types of latch.

In figure 68, the latch comprises a collet-catcher. The outer housing mounted component 128A comprises a catcher with a radially-inwardly protruding flange, arranged to receive and capture a radially-outwardly protruding flange on the gate mounted component 128B when the gate opens.

In figure 69, the latch comprises a magnet. At least one of the outer housing mounted component 130A and the gate mounted component 130B comprises a magnet and the other of the outer housing mounted component 130A and the gate mounted component 130B comprises either a magnet or magnetic material. Accordingly, the magnetic attraction holds the gate mounted component in contact with the outer housing mounted component when the gate is open.

Figures 70 and 71 illustrate a further example of a blocking assembly. As before, features not forming part of the blocking assembly are as described above and comments made above relating to these features apply, where appropriate and adapted as appropriate. In the drill bit of figures 70 and 71, the blocking assembly comprises a ball 32 and a frangible screen 132. Frangible screen 132 is located in a central passageway through the drill bit, analogous to the location of the annular ring 34 in previous examples. The frangible ring 132 holds the ball 32 in the passageway 80 and prevents flow of drilling fluid therethrough. When the flow rate is increased and the pressure differential across the ball 32 and the frangible screen 132 increases to a threshold value, the axial force on the frangible screen 132 will cause it to break apart, releasing the ball 32 to move to the second position as in previous examples. The frangible screen 132 may be made from any material suitable for breaking apart when the pressure differential across the ball and frangible screen 132 reaches the threshold value. Suitable materials may include rubbers or plastic, for example PEEK. The frangible screen includes scores in order to encourage breakage.

Figures 72 to 77 illustrate a further example of a downhole tool in the form of a drill bit. As before, the majority of features present in the drill bit of figures 72 to 77 are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply, where appropriate and adapted as appropriate.

In the drill bit of figures 72 to 77, the blocking assembly comprises an occluding rod 133 and a deformable fastening -in this case a shearable screw 140. The occluding rod comprises a cylindrical body section 134 connected to a first support arm 136 and second support arm 137. The occluding rod extends substantially axially within the outer housing 24. The second support arm 137 is located on an upstream end of the cylindrical body 134 and is located in a drilling fluid passageway of the outer housing. The second support arm 137 provides a sliding engagement with a cylindrical section of the outer housing 24. A seal 142 is located between the occluding rod 133 and the cylindrical section defined by the outer housing 24 in order to prevent drilling fluid from passing between these components and reducing a pressure gradient.

The first support arm 136 is located on the downstream end of the body section 134 and extends into the deployable blade assembly 38. The first support arm 136 provides a sliding engagement with a cylindrical section of the flow path (defined by the piston 40).

As such, the occluding member is restricted to axial movement within the outer housing 24.

A shoulder 138 is defined by a reduction in diameter of the occluding rod 133, between the cylindrical body section 134 and the first support arm 136 The first support arm 136 is shaped such that, when the blocking assembly is in the first arrangement, fluid can flow around the occluding rod 133 and through all of the flow paths 42 44.

Turning now to figure 73, a tab protrudes from the side of the cylindrical body section 134 of the occluding rod 133. When the occluding rod 133 is in the first arrangement (i.e. a non-occluding position), a shearable screw 140 extends through the tab and into a part of the outer housing 24, holding the occluding rod 133 in position. When the flow rate through the drill bit is increased and the pressure drop across the occluding rod 134 increases to a threshold value, the axial force exerted on the sharable screw 140 will cause it to fail and break, releasing the occluding rod 133 to move to the second arrangement -that is an occluding position. As the occluding rod 133 is restricted to axial movement within the outer housing 24 and the shearable screw 140 connects directly to the occluding rod 133 and the outer housing, all of the force exerted on the occluding rod 133 is transferred through the shearable screw 140. As such, the increase in tensile force exerted on the screw for a given increase in drilling fluid flow rate is larger in the drill bit of figures 72 than for an equivalent increase in flow rate in a drill bit as described with reference to figure 62.

Once the shearable screw 140 breaks, as illustrated in figures 74 and 75, the occluding rod 133 moves axially within the outer housing 24 towards the deployable blade assembly 38, as in previous examples, until the occluding rod 133 abuts the piston 40. In the present embodiment, the shoulder 138 of the occluding rod abuts a seat defined by a tapered section of the flow path 44 (defined by the piston 40) and seals off that flow path 44. Once the flow path 44 is closed off, the pressure gradient across the deployable blade assembly 38 increases until a deployment value is reached, at which point the shear ring 82 fails and breaks, releasing the deployable blade assembly 38, which moves under the action of the drilling fluid into the second position, as shown in figures 77 and 78.

Figure 76 illustrates the upstream end of the occluding rod 133, with the second support arm 137 slidably engaged with a drilling fluid passageway of the outer housing. In figure 76, the occluding rod 133 has moved from the first arrangement to engage the deployable blade assembly 38, but the deployable blade assembly 38 has not yet moved from the first to the second position. As such, figure 76 corresponds to the drill bit arrangement of figures 74 and 75. The drilling fluid passageway in which the second support arm 137 is located comprises a cylindrical section along the axis of the drill bit with a plug member 148 supporting a nozzle 146. The nozzle 146 helps control the pressure felt by the upstream end of the occluding rod 133. A ring-shaped section around the circumference of the cylindrical section comprises a series of further nozzles which allow fluid to bypass the blocking assembly. These further nozzles ensure that drilling fluid can flow from the inlet to the outlet(s) of the drill bit when the drill bit is operating in a first arrangement.

Figures 79 to 81 illustrate a further example of a drill bit. As before, the majority of features present in the drill bit of figures 78 to 80 are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply, where appropriate and adapted as appropriate.

In the drill bit of figures 79 to 81, the occluding rod 133 has a different shape, with the cylindrical body section 134 having a smaller diameter and the shoulder 138 being formed by a radial flange protruding from the occluding rod 133 between the body section 133 and the first support arm 136.

Additionally, the flow path(s) 44 through which flow is restricted by the occluding rod 133 are arranged to extend radially out from the axis of the drill bit, through the curved side wall of the outer housing 24 via nozzles 144. Flow paths 42 which are not blocked by the occluding rod 133 extend axially and have outlets in the primary cutting structure -that is an axial end face of the drill bit. The inclusion of flow paths which with outlets in the curved side wall of the drill bit -i.e. outlets which are arranged remote from the primary and/or deployable cutting structure -allows a higher total number of flow paths to be implemented in the design. Higher drilling fluid flow rates can be used when flow paths with outlets remote from a drilling structure are present.

Figures 79 and 80 illustrate the drill bit in a first and second arrangement, respectively.

Figure 81 is a view of a cross-section in a plane perpendicular to the axis of the drill bit through the flow paths 44 through which flow may be restricted by the occluding rod 133 ("blockable flow paths"). The flow paths 42 through which flow cannot be restricted by the occluding rod 133 ("open flow paths") can be seen extending axially within the drill bit (out of the plane of the page). Three "blockable flow paths" 44 are arranged at evenly spaced intervals of 120 degrees around the circumference of the drill bit. The flow paths 44 extend from a central flow path region radially out to the curved side wall of the piston 40. Nozzles 144 are located in the flow paths 44 within the side walls of the housing 24.

The nozzles 144 allow a pressure drop between the flow paths 44 and the wellbore to be controlled.

Figures 82 to 89 illustrate a further example of a drill bit. As before, the majority of features present in the drill bit of figures 72 to 77 are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply, where appropriate and adapted as appropriate.

The blocking assembly of the downhole tool of figures 82 to 89 comprises a ball 32, a gate 150, a fastener in the form of a shearable screw 154 and a guide 152.

As in embodiments described above, when in a first arrangement, the gate 150 is located in a fluid passageway in the outer housing and is arranged to prevent fluid flow through this passageway. The gate 150 comprises a seal 156 in this regard in order to prevent fluid from passing between the gate 150 and the passageway wall. The ball 32 is located on the upstream side of the gate 150 and is prevented from moving downstream, towards the deployable blade assembly by the gate 150.

The gate 150 is in sliding engagement with the guide 152, which comprises two axially-aligned rods protruding from the outer housing (only one of which is shown in figures 82 to 87). A head on the end of each rod prevents the gate 150 disengaging the guide 152.

When in the first arrangement, as illustrated in figures 82 and 83, the gate 150 is held in the passageway (i.e. in a first position) by the shearable screw, which extends through a part of the gate 150 and into the surrounding housing/passageway.

As the flow through the drill bit increases, the pressure differential across the ball 32 and gate 150 increases and the ball 32 and gate 150 exert a force on the shearable screw 154 in the direction of the deployable blade assembly 38.

When the pressure gradient across the ball 32 and gate 150 reaches a threshold value, the shearable screw breaks such that the gate 150 is no longer held in the first arrangement. The gate 150 moves in a downstream direction under the action of drilling fluid flowing through the drill bit. The guide 152 guides the gate 150 such that the gate moves axially within the drill bit and is held once the gate 150 engages the heads on the end of each guide 152.

The upstream side of the gate 150 (the one which is in contact with the ball 32 when in the first arrangement) has a convex surface. As such, once the gate 150 moves out of the passageway, the drilling fluid carries the ball 32 around the gate 150 and moves the ball into an occluding arrangement in the seat of the deployable blade assembly 38 as described in previous embodiments. Figures 84 and 85 illustrate the drill bit once the gate 150 and ball 32 have moved from the first arrangement; the ball 32 is in an occluding position, but the deployable blade assembly 38 has not yet moved from the first position.

As with previous embodiments, once the ball 32 is located in an occluding arrangement -restricting flow through a flow path 44 through the deployable blade assembly -the pressure differential across the deployable blade assembly 38 increases until a deployment value is reached, at which point the shear ring 82 fails and the deployable blade assembly 38 moves towards the second position. Figures 86 and 87 show the drill bit in the second arrangement with the blades 22 in a deployed position.

Figures 88 and 89 show the blocking assembly in a first and second arrangement respectively. In the first arrangement, in figure 88, the gate 150 is located snugly in the passageway such that the ball 32 is prevented from passing. The shearable screw 154 is intact and is holding the gate 150 in the passageway against the force created by the pressure gradient. Other passageways through the housing can be seen circumferentially surrounding the gate 150, through which the drilling fluid may flow when the drill bit is operating in a first arrangement. The guide 152 comprising two cantilevered rods can be seen on either side of the gate 150.

Figure 89 shows the blocking assembly in a second arrangement. In figure 89, the threshold pressure gradient has been reached and the shearable screw has failed and thus has sheared at a location between when it is attached to the gate 150 and fixed relative to the outer housing 24. The gate 150 is therefore free to move under the action of the drilling fluid, although its movement is restricted by the guide 152, which only permits axial movement. The gate 150 therefore travels along the guide from the first to a second position, at which point it abuts the heads on the guide rods. The gate 150 is held in this position by the flow of the drilling fluid. Once the gate 150 has left the central passageway, the ball 32 moves out and around the gate 150 and eventually locates in the piston 40 of the deployable blade assembly 38, as described above.

Figures 90 to 93C illustrate a further example of a downhole tool in the form of a drill bit.

As before, the majority of features present in the drill bit of figures 90 to 93C are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply where appropriate and adapted as appropriate.

Figure 90 shows the drill bit with the deployable blade assembly in a first position, the drill blades 222 in a retracted position and the blocking assembly in a first arrangement (i.e. a non-blocking arrangement). Figure 91 shows the drill bit once the blocking assembly has moved into a second arrangement (a blocking arrangement) with the deployable blade assembly still in the first position. Figure 92 shows the drill bit once the deployable blade assembly has moved to a second position and the drill blades 222 are deployed.

Figures 95A to 95C illustrate a tool component in the form of a deployable blade assembly suitable for use in the drill bit of Figures 90 to 93C. The deployable blade assembly comprises a piston 240, which can be located within the outer housing 224 of the drill bit. The piston 240 defines a plurality of flow paths therethrough. A plurality of nozzles 201 extend from the respective flow paths. The nozzles 201 are arranged to control the flow of drilling fluid out the face of the drill bit. The deployable blade assembly further comprises a plurality of blades 222 connected to the piston 240 and arranged to be extendable from the drill bit.

Turning now to Figures 90 and 91, it can be seen that the tool component -i.e. the deployable blade assembly (and in particular the piston 240) is held in a first position by a deformable release which, in the drill bit of figures 90 to 93C, is a shearable screw 203 -i.e. a screw configured to break when a predetermined tension load is experienced.

As seen in Figure 92, one part of the blocking assembly shearable screw 203a (e.g. the head) is fixed with respect to the outer housing 224 -for example by being threaded through a support cylinder 205 which is fixed with respect to the outer housing 224. The other part 203b (e.g. the end) is fixed with respect to the piston 240 -for example by screwingly engaging the piston 240.

The support cylinder 205 (as shown in Figures 90 to 93C and in more detail in Figures 94A to 94C) is arranged to be fixed with respect to the outer housing 224. A plurality of axial ports 211 are arranged to allow fluid to pass from an upstream side of the support cylinder 205 and occluding member 233, to a downstream side, adjacent the deployable blade assembly piston 240, such that the fluid can pass through the flow paths arranged therein.

The blocking assembly of this drill bit comprises an occluding member 233 in the form of a rod and a restraint -in this case a shearable screw 207. The occluding member 233 extends substantially axially within the outer housing 224. Part of the occluding member 233 is arranged within the support cylinder 205. A further part of the occluding member 233 is arranged within the piston 240 of the deployable blade assembly. The occluding member 233 is arranged to move axially with respect to both the support cylinder 233 and the piston 240 of the deployable blade assembly.

As can be seen in Figure 90, the blocking assembly shearable screw 207 (which may alternatively be replaced with any deformable or breakable fastening) is arranged to hold the occluding member 233 in a first arrangement. Once the blocking assembly shearable screw 207 has broken, the occluding member 233 is free to move axially under the action of fluid pressure and flow.

In the drill bit of Figures 90 to 93C, the occluding member 233 comprises a shoulder 238 in the form of a radial protrusion. As is illustrated in Figure 91, the shoulder 238 is configured such that it can block at least one of the plurality of flow paths 244 through the piston 240 when the blocking assembly moves to the second arrangement.

In this example, a guide cylinder 209 is arranged concentrically within and fixed with respect to the support cylinder 205. The guide cylinder 209 is fixed relative to the outer housing 224. The guide cylinder 209 comprises an abutment 213 which is arranged to restrict the axial movement of the occluding member 233. As can be seen in Figure 92, when the deployable blade assembly has moved to the second position, the abutment 213 is arranged to engage the occluding member 233 and prevent it from moving with the deployable blade assembly.

In use, the drill bit will typically initially operate in a first arrangement as shown in Figure 90. In this arrangement the deployable blade assembly is in a first position and the drill blades 222 are retracted within the outer housing 224. Drilling fluid may flow from the surface, through the ports 211 in the support cylinder 205, through the flow paths defined by the deployable blade assembly piston 240 and out of the face of the drill bit. Initially, the occluding member 233 is held in the first arrangement by the shearable screw 207.

When it is desired to deploy the drill blades 222, the operator may increase the flow rate of drilling fluid through the drill bit. As the support cylinder 205 defines a restriction to the flow of drilling fluid, the increase in flow rate will increase the pressure gradient across the support cylinder 205. The pressure differential across the occluding member 233, which is arranged in parallel with the support cylinder 205, will also increase. The pressure gradient across the occluding member 233 imparts an axial force on the occluding member 233 in a downstream direction (i.e. to the right of Figures 90 to 93C). Once the pressure differential across the occluding member reaches a threshold value, the shearable screw 207 breaks, releasing the occluding member 233.

Once the shearable screw 207 has broken the occluding member 233 is axially moved under the action of fluid pressure from a first arrangement towards a second arrangement. The occluding member 233 moves towards the deployable blade assembly (to the right in Figures 90 to 93C). The occluding member 233 moves to the second arrangement and, when in the second arrangement, the occluding member shoulder 238 abuts a seat defined by the piston 240 around the entry to at least one of the flow paths 244 through the piston 240. This is shown in Figure 91.

When the occluding member 233 is in the second arrangement it restricts fluid flow through the piston 240 of the deployable blade assembly (by blocking entry to at least one of the flow paths 244). This causes a sudden increase in the pressure gradient across the piston 240 and the deployable blade assembly as a whole.

The increase in the pressure gradient across the piston 240 urges the deployable blade assembly from the first to the second position, against the action of the deployable blade assembly shearable screw 203. When the pressure differential across the deployable blade assembly reaches a threshold value referred to herein as the deployment value, the deployable blade assembly shearable screw 203 breaks, releasing the deployable blade assembly. The deployable blade assembly moves from the first position to the second position, deploying the drill blades 222 out of the front of the drill bit, as shown in Figure 92.

Figure 92 shows the drill bit after the shearable screw 203 has broken and the deployable blade assembly has moved to the second position, deploying the drill blades. It can be seen that the abutment 213 of the guide cylinder 209 prevents the occluding member 233 from following the piston 240 and, as such, the flow paths 244 which were momentarily closed by the occluding member 233 are again open for drilling fluid to flow therethrough once the piston 240 has moved to the second position.

Figures 93A to 93C are cross-sections through the axis of the drill bit at three different angular rotations, thus showing different features of the support cylinder 205 and piston 240.

As in previous drill bits described herein, a plurality of lock pins 258 may be provided in the housing 224 around the circumference of the piston 240 and biased radially inwards towards the piston 240. These lock pins 258 are arranged to lock the piston 240 -and hence deployable blade assembly -in the second (deployed) position by extending into recesses in the piston 240 when the deployable blade assembly enters the second position.

Figures 96A to 98B illustrate a further example of a downhole tool in the form of a hybrid drill bit 300. As before, the majority of features present in the hybrid drill bit of figures 96A to 98B are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply where appropriate and adapted as appropriate.

Furthermore, the omission of explicit description regarding a feature in relation to this downhole tool is not to be construed as an indication that this downhole tool cannot be combined with said feature.

The activation mechanism, blocking assembly, release, restraint and other internal components of the hybrid drill bit 300 are largely similar to those of the drill bit of Figure 90.

Figure 96A shows the drill bit 300 with the tool component in the form of a deployable blade assembly 322 in a first position, the drill blades 322 in a retracted position and the blocking assembly in a first arrangement (i.e. a non-blocking arrangement). Figure 96B shows the drill bit once the blocking assembly has moved into a second arrangement (a blocking arrangement) with the deployable blade assembly still in the first position. Figure 96C shows the drill bit once the deployable blade assembly has moved to a second position and the drill blades 322 are deployed.

As in previously described drill bits, the tool component is in the form of a deployable blade assembly. The deployable blade assembly comprises a piston 340, which can be located within the outer housing 324 of the drill bit. The piston 340 defines a plurality of flow paths therethrough. A plurality of nozzles 301 extend from the respective flow paths. The nozzles 301 are arranged to control the flow of drilling fluid out the face of the drill bit 300. The deployable blade assembly further comprises a plurality of blades 322 connected to the piston 340 and arranged to be extendable from the drill bit.

In the example of Figures 96A to 98B, the tool component comprises a plurality of rotatable roller cutters 323.

The rotatable roller cutter 323 is located on the end of the blade 322. The roller cutter 323 of this drill bit 300 comprises a cylindrical section and a cone-shaped tip. Tungsten carbide inserts are located over the outer surface of the cylindrical section and the tip. The rotatable roller cutter 323 is arranged to engage the formation during use.

Each rotatable roller cutter 323 is configured to rotate relative to the blade 322 and thus the tool component. The rotatable roller cutter 323 is therefore configured to rotate relative to the outer housing 324 during use. Each roller cutter 323 comprises internal bearings which allow the roller cutter 323 to rotate relative to its respective blade 322.

The roller cutter 323 or "roller cone" -and thus the hybrid drill bit -is typically for use when drilling through rock.

Turning to Figure 96A, it can be seen that the tool component -i.e. the deployable blade assembly (and in particular the piston 340) is held in a first position by a deformable release which, in the hybrid drill bit of figures 96A to 98B, is a shearable screw 303 -i.e. a screw configured to break when a predetermined tension load is experienced. As seen in Figure 96B, one part of the blocking assembly shearable screw 303a (e.g. the head) is fixed with respect to the outer housing 324 -for example by being threaded through a support cylinder 305 which is fixed with respect to the outer housing 324. The other part 303b (e.g. the end) is fixed with respect to the piston 340 -for example by screwingly engaging the tool component (or the piston 340 thereof).

The support cylinder 305 (as shown in Figures 96A to 96C) is arranged to be fixed with respect to the outer housing 324. A plurality of axial ports (not shown) are arranged to allow fluid to pass from an upstream side of the support cylinder 305 and occluding member 333, to a downstream side, adjacent the deployable blade assembly piston 340, such that the fluid can pass through the flow paths arranged therein.

The blocking assembly of this downhole tool comprises an occluding member 333 in the form of a shortened rod; and a restraint in the form of a shearable screw 307. The occluding member 333 extends substantially axially within the outer housing 324. Part of the occluding member 333 is arranged within the support cylinder 305. A further part of the occluding member 333 is arranged adjacent the piston 340 of the tool component.

The occluding member 333 is arranged to move axially with respect to both the support cylinder 333 and the piston 340 of the deployable blade assembly.

As can be seen in Figure 96A, the blocking assembly shearable screw 307 (which may alternatively be replaced with any deformable or breakable fastening) is arranged to hold the occluding member 333 in a first arrangement. Once the blocking assembly shearable screw 307 has broken, the occluding member 333 is free to move axially under the action of fluid pressure and flow.

In the drill bit of Figures 96A to 98B, the occluding member 333 comprises a shoulder 338. As is illustrated in Figure 96B, the shoulder 338 is configured such that it can block at least one of the plurality of flow paths 344 through the piston 340 when the blocking assembly moves to the second arrangement. This is achieved by the shoulder 338 of the occluding member 333 abutting a seat arranged around a flow path.

In this downhole tool, a guide cylinder 309 is arranged coaxially with and fixed with respect to the support cylinder 305. The guide cylinder 309 is fixed relative to the outer housing 324. The downhole tool (and in this specific example the guide cylinder 309) comprises an abutment 313 which is arranged to restrict the axial movement of the occluding member 333. As can be seen in Figure 96C, when the tool component has moved to the second position, the abutment 313 is arranged to engage the occluding member 333 and prevent it from continuing to move with the tool component (deployable blade assembly).

In use, the hybrid drill bit 300 will typically initially operate in a first arrangement as shown in Figure 96A. In this arrangement the deployable blade assembly is in a first position and the drill blades 322 are retracted within the outer housing 324. In this arrangement the roller cutters/cones 323 are retracted with respect to the primary cutting structure that is, the roller cutters 323 are positioned such that they do not routinely contact the formation. Drilling fluid may flow from the surface, through the ports in the support cylinder 305, through the flow paths defined by the deployable blade assembly piston 340 and out of the face of the hybrid drill bit. Initially, the occluding member 333 is held in the first arrangement by the shearable screw 307.

When it is desired to deploy the drill blades 322, the operator may increase the flow rate of drilling fluid through the hybrid drill bit. As the support cylinder 305, as well as the plurality of nozzles 301 define a restriction to the flow of drilling fluid, the increase in flow rate will increase the pressure gradient across the support cylinder 305. The pressure differential across the occluding member 333, which is arranged in parallel with the support cylinder 305, will also increase. The pressure gradient across the occluding member 333 imparts an axial force on the occluding member 333 in a downstream direction (i.e. to the right of Figures 96A to 96C). Once the pressure differential across the occluding member reaches a threshold value, the shearable screw 307 breaks, releasing the occluding member 333.

Turning now to Figure 96B, once the shearable screw 307 has broken the occluding member 333 is axially moved under the action of fluid pressure from a first arrangement towards a second arrangement. The occluding member 333 moves towards the deployable blade assembly (to the right in Figures 96A to 96C). The occluding member 333 moves to the second arrangement and, when in the second arrangement, the occluding member shoulder 338 abuts a seat defined by the piston 340 around the entry to at least one of the flow paths 344 through the piston 340. This is shown in Figure 96B.

When the occluding member 333 is in the second arrangement it restricts fluid flow through the piston 340 of the deployable blade assembly (by blocking entry to at least one of the flow paths 344). This causes an increase in the pressure gradient across the piston 340 and the tool component as a whole.

The increase in the pressure gradient across the piston 340 urges the deployable blade assembly from the first to the second position, against the action of the deployable blade assembly shearable screw 303. When the pressure differential across the deployable blade assembly (tool component) reaches a threshold value referred to herein as the deployment value, the deployable blade assembly shearable screw 303 breaks, releasing the deployable blade assembly (tool component) . The deployable blade assembly and thus the blades 322 carrying the roller cutters/cones 323 moves from the first position to the second position, deploying the roller cutters 323 out of the front of the drill bit, as shown in Figure 96C.

Figure 96C shows the drill bit after the shearable screw 303 has broken and the deployable blade assembly has moved to the second position, deploying the drill blades. It can be seen that the abutment 313 of the guide cylinder 309 prevents the occluding member 333 from following the piston 340 and, as such, the flow paths 344 which were momentarily closed by the occluding member 333 are again open for drilling fluid to flow therethrough once the piston 340 has moved to the second position.

This means that the pressure in the drilling fluid flowing through the hybrid drill bit 300 spikes as the occluding member 333 abuts the tool component, but drops again once the tool component moves away from the occluding member 333. This pressure spike signals to an operator that the operating mode of the downhole tool has changed.

As in previous drill bits described herein, a plurality of lock pins (not shown) may be provided in the housing 324 around the circumference of the piston 340 and biased radially inwards towards the piston 340. These lock pins 358 are arranged to lock the piston 340 -and hence tool component -in the second (deployed) position by extending into recesses in the piston 340 when the deployable blade assembly enters the second position.

Figure 97 shows the end face of the hybrid drill bit 300. As can be seen, the hybrid drill bit 300 comprises three blades, each comprising a roller cutter/cone 323 on its end, arranged to move between a retracted and a deployed position.

Figures 98A and 98B are perspective views of the hybrid drill bit 300 with the tool component in a first (retracted) and second (deployed) position, respectively.

Figures 99A to 101B illustrate a further example of a downhole tool. In this example, the downhole tool is a reamer; in particular a near-bit reamer 400. As before, the majority of features present in the reamer 400 of figures 99A to 101B are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply where appropriate and adapted as appropriate. Furthermore, the omission of explicit description regarding a feature in relation to this downhole tool is not to be construed as an indication that this downhole tool cannot be combined with said feature.

The activation mechanism, blocking assembly, release, restraint and other internal components of the reamer 400 are largely similar to those of the drill bits of Figure 90 and 96A.

Figure 99A shows the reamer 400 with the tool component in a first position, the blades 522 in a retracted position and the blocking assembly in a first arrangement (i.e. a non-blocking arrangement). Figure 99B shows the reamer 400 once the blocking assembly has moved into a second arrangement (a blocking arrangement) with the tool component still in the first position. Figure 99C shows the reamer 400 once the tool component has moved to a second position and the cutter blades 522 are deployed.

The reamer 400 may be used to enlarge a bore. For example, the reamer 400 may be located behind a drill bit in a drill string and may be configured to enlarge the diameter of the bore drilled by the drill bit. The reamer 400 may be inserted downhole in an inactive configuration -e.g. with the tool component in the first position. Once in position, the reamer 400 may be activated -e.g. by moving the tool component to the second position, in order to enlarge a diameter of a bore.

The tool component comprises a piston 540 comprising arms 541. The piston 540 is located within the outer housing 524 of the reamer 400. The arms 541 extend axially along the downhole tool. The piston 540 defines a flow path 544 therethrough. The flow path 544 leads to a plurality of nozzles 501 arranged at the end face of the reamer 400. The nozzles 501 control the flow of drilling fluid out the face of the reamer 400.

The tool component further comprises a plurality of cutter blades in the form of cutter blocks 522. The cutter blocks 522 are connected to the piston 540 (or rather the arms 541 thereof) and arranged to be extendable from the reamer 400.

In this example of a downhole tool, the cutter blocks 522 are rotationally attached to the outer housing by means of a pin 523. Each cutter block 522 is configured to rotate about pin 523. The cutter blocks 522 are configured to be rotatable with respect to the rest of the tool component, the outer housing 524 and downhole tool.

Each cutter block 522 is configured to rotate from the first position to the second position.

Each cutter block 522 is configured to rotate from a retraction position to a deployed position.

The tool component further comprises a linkage 525. The linkage 525 connects an arm 541 to a cutter block 522. Each linkage 525 is pivotally connected to both the arm 541 and cutter block 522.

Longitudinal movement of the piston 540 and arms 541 is converted to rotational movement of the cutter blocks 522, to rotate the cutter blocks 522 from the first (retracted) position to the second (deployed) position.

The cutter blocks 522 comprise a cutting edge, configured to engage and cut an inside surface of a bore.

Turning to Figure 99A, it can be seen that the tool component (and in particular the piston 540) is held in a first position by a deformable release which, in the reamer of figures 99A to 101B, is a shearable screw 503 -i.e. a screw configured to break when a predetermined tension load is experienced. As seen in Figure 99B, one part of the blocking assembly shearable screw 503a (e.g. the head) is fixed with respect to the outer housing 524 -for example by being threaded through a support cylinder 505 which is fixed with respect to the outer housing 524. The other part 503b (e.g. the end) is fixed with respect to the piston 540 -for example by screwingly engaging the tool component (or the piston 540 thereof).

The support cylinder 505 (as shown in Figures 99A to 99C) is arranged to be fixed with respect to the outer housing 524. A plurality of axial ports (not shown) are arranged to allow fluid to pass from an upstream side of the support cylinder 505 and occluding member 533, to a downstream side, adjacent the tool component piston 540, such that the fluid can pass through the flow paths arranged therein.

The blocking assembly of this downhole tool comprises an occluding member 533 in the form of a shortened rod; and a restraint in the form of a shearable screw 507. The occluding member 533 extends substantially axially within the outer housing 524. Part of the occluding member 533 is arranged within the support cylinder 505. A further part of the occluding member 533 is arranged adjacent the piston 540 of the tool component.

The occluding member 533 is arranged to move axially with respect to both the support cylinder 505 and the piston 540 of the tool component.

As can be seen in Figure 99A, the blocking assembly shearable screw 507 (which may alternatively be replaced with any deformable or breakable fastening) is arranged to hold the occluding member 533 in a first arrangement. Once the blocking assembly shearable screw 507 has broken, the occluding member 533 is free to move axially under the action of fluid pressure and flow.

In the reamer of Figures 99A to 101B, the occluding member 533 comprises a shoulder 538. As is illustrated in Figure 99B, the shoulder 538 is configured such that it can at least partially block the flow path 544 through the piston 540 when the blocking assembly moves to the second arrangement. This is achieved by the shoulder 538 of the occluding member 533 abutting a seat arranged around a flow path.

In this downhole tool, a guide cylinder 509 is arranged coaxially with and fixed with respect to the support cylinder 505. The guide cylinder 509 is fixed relative to the outer housing 524. The reamer 400 (and in this specific example the guide cylinder 509) comprises an abutment 513 which is arranged to restrict the axial movement of the occluding member 533. As can be seen in Figure 99C, when the tool component has moved to the second position, the abutment 513 is arranged to engage the occluding member 533 and prevent it from continuing to move with the tool component.

In use, the reamer 400 will typically initially operate in a first arrangement as shown in Figure 99A. In this arrangement the tool component is in a first position and the cutter blocks 522 are retracted within the outer housing 524. In this arrangement the cutter blocks 522 are retracted with respect to the outer surface of the outer housing 524 -that is, the cutter blocks 522 are positioned such that they do not routinely contact the formation. Drilling fluid may flow from the surface, through the ports in the support cylinder 505, through the flow path 544 defined by the tool component piston 540 and out of the face of the reamer 400. Initially, the occluding member 533 is held in the first arrangement by the shearable screw 507.

When it is desired to deploy the cutter blocks 522 such that reaming operations can begin. The operator may increase the flow rate of drilling fluid through the reamer 400. As the support cylinder 505, as well as the plurality of nozzles 501 define a restriction to the flow of drilling fluid, the increase in flow rate will increase the pressure gradient across the support cylinder 505. The pressure differential across the occluding member 533, which is arranged in parallel with the support cylinder 505, will also increase. The pressure gradient across the occluding member 533 imparts an axial force on the occluding member 533 in a downstream direction (i.e. to the right of Figures 99A to 99C).

Once the pressure differential across the occluding member 533 reaches a threshold value, the shearable screw 507 breaks, releasing the occluding member 533.

Turning now to Figure 99B, once the shearable screw 507 has broken the occluding member 533 is axially moved under the action of fluid pressure from a first arrangement towards a second arrangement. The occluding member 533 moves towards the tool component (to the right in Figures 96A to 96C). The occluding member 533 moves to the second arrangement and, when in the second arrangement, the occluding member shoulder 538 abuts a seat defined by the piston 540 around the entry to at least one of the flow paths 544 through the piston 540. This is shown in Figure 99B.

The occluding member comprises seal arranged to abut an internal surface of the guide 309. The occluding member seal may be arranged anywhere along the occluding member 533. Locating the occluding member seal towards the upper end of the occluding member 533 (i.e. towards the left in Figure 99B) causes the occluding member to stay in the flow path of the support cylinder 505 for longer. This results in a pressure difference across the occluding member acting to drive it downwards any time the flow is on. This ensures a good seal when the shoulder 538 of the occluding member lands on the tool component (e.g. the blade piston 540). This ensures that any fluid rushing into the flow path does not stop the occluding member sealing on the blade piston seat.

This also increases the pressure spike when the tool component is moved from the first position towards the second position -making it easier to detect on the surface.

When the occluding member 533 is in the second arrangement it restricts fluid flow through the piston 540 of the tool component (by blocking entry to at least one of the flow paths 544). This causes an increase in the pressure gradient across the piston 540 and the tool component as a whole.

The increase in the pressure gradient across the piston 540 urges the tool component from the first to the second position, against the action of the tool component shearable screw 503. When the pressure differential across the tool component reaches a threshold value referred to herein as the deployment value, the tool component shearable screw 503 breaks, releasing the tool component. The piston 540 and arms 541 move axially towards the downhole end of the reamer 400 under the action of fluid flow through the reamer 400. The axial movement of the arms 541 induces rotational movement of the cutter blocks, which rotate from the first position towards the second position, deploying the cutter blocks out the outer circumferential wall of the reamer 400, as shown in Figure 99C.

Figure 99C shows the reamer 400 after the shearable screw 503 has broken and the tool component has moved to the second position, deploying the cutter blocks 522. It can be seen that the abutment 513 of the guide cylinder 509 prevents the occluding member 533 from following the piston 540 and, as such, the flow path 544 which was momentarily closed by the occluding member 533 is again open for drilling fluid to flow therethrough once the piston 540 has moved to the second position.

This means that the pressure in the drilling fluid flowing through the reamer 400 spikes as the occluding member 533 abuts the tool component, but drops again once the tool component moves away from the occluding member 533. This pressure spike can be registered on the surface and acts to signal to an operator that the operating mode of the downhole tool has changed.

As in previous downhole tools described herein, a plurality of lock pins (not shown) may be provided in the housing 524 around the circumference of the piston 540 and biased radially inwards towards the piston 540. These lock pins 558 are arranged to lock the piston 540 -and hence tool component-in the second (deployed) position by extending into recesses in the piston 540 when the tool component enters the second position.

Figure 100A shows the end face of the reamer 400 with the tool component and hence cutter blocks 522 in a first (retracted) position. The reamer 400 has two cutter blocks 522 -one located on each side of the reamer 400. Figure 100B shows the end face of the reamer 400 with the tool component and hence cutter blocks in the second (deployed) position.

Figures 101A and 101 B are side views of the reamer 400 with the tool component in a first (retracted) and second (deployed) position, respectively.

Figures 102A to 104B illustrate a further example of a downhole tool. In this example, the downhole tool is an expandable drill bit 500. As before, the majority of features present in the expandable drill bit 500 of figures 102A to 104B are equivalent to those in earlier-described embodiments and where a feature is not explicitly described below, it is to be assumed that the comments made above in relation to that feature apply where appropriate and adapted as appropriate. Furthermore, the omission of explicit description regarding a feature in relation to this downhole tool is not to be construed as an indication that this downhole tool cannot be combined with said feature.

The activation mechanism, blocking assembly, release, restraint and other internal components of the expandable drill bit 500 are largely similar to those of the drill bits of Figure 90 and 96A and reamer of Figure 99A.

Figure 102A shows the expandable drill bit 500 with the tool component in a first position, the cutter blades 522 in a retracted position and the blocking assembly in a first arrangement (i.e. a non-blocking arrangement). Figure 102B shows the expandable drill bit 500 once the blocking assembly has moved into a second arrangement (a blocking arrangement) with the tool component still in the first position. Figure 102C shows the expandable drill bit 500 once the tool component has moved to a second position and the cutter blades 522 are deployed.

The expandable drill bit 500 may be configured to drill a hole with a first gauge and drill a hole with a second gauge, where the first and second gauges are different. As such, the expandable drill bit 500 may be used to drill a first section of a bore with a first gauge. The expandable drill bit 500 may define a first gauge (i.e. hole diameter) when the tool component is in the first position. The tool component may then be moved from the first to the second position. The expandable drill bit 500 may define a second gauge when the tool component is in the second position. The expandable drill bit 500 can then be used to drill a second section of a bore with a second gauge.

The tool component comprises a piston 540 comprising arms 541. The piston 540 is located within the outer housing 524 of the expandable drill bit 500. The arms 541 extend axially along the downhole tool. The piston 540 defines a flow path 544 therethrough. The flow path 544 leads to a plurality of nozzles 501 arranged at the end face of the expandable drill bit 500. The nozzles 501 control the flow of drilling fluid out the face of the expandable drill bit 500 and define a pressure gradient, thus causing the fluid pressure inside the expandable drill bit 500 to be higher than the annulus pressure. The same principle may be true for all of the downhole tools described herein.

The tool component further comprises a plurality of cutter blades 522. In the present example there are two cutter blades 522. The cutter blades 522 are connected to the piston 540 (or rather the arms 541 thereof) and arranged to be extendable from the expandable drill bit 500.

In this example of a downhole tool, the cutter blades 522 are rotationally attached to the outer housing by means of a pin 523. Each cutter blade 522 is configured to rotate about pin 523. The cutter blades 522 are configured to be rotatable with respect to the rest of the tool component, the outer housing 524 and downhole tool.

Each cutter blade 522 is configured to rotate from the first position to the second position. Each cutter blade 522 is configured to rotate from a retraction position to a deployed position.

The tool component further comprises a linkage 525. The linkage 525 connects an arm 541 to a cutter blade 522. Each linkage 525 is pivotally connected to both the arm 541 and corresponding cutter blade 522.

Longitudinal movement of the piston 540 and arms 541 is converted to rotational movement of the cutter blades 522, to rotate the cutter blades 522 from the first (retracted) position to the second (deployed) position.

The cutter blocks 522 comprise a cutting edge, or plurality of cutter edges, configured to provide a drilling function. The cutter blocks 522 may comprise cutter inserts, e.g. PDC cutter inserts.

Turning to Figure 102A, it can be seen that the tool component (and in particular the piston 540) is held in a first position by a deformable release which, in the expandable drill bit of figures 102 to 104B, is a shearable screw 503 -i.e. a screw configured to break when a predetermined tension load is experienced. As seen in Figure 102B, one part of the blocking assembly shearable screw 503a (e.g. the head) is fixed with respect to the outer housing 524 -for example by being threaded through a support cylinder 505 which is fixed with respect to the outer housing 524. The other part 503b (e.g. the end) is fixed with respect to the piston 540 -for example by screwingly engaging the tool component (or the piston 540 thereof).

The support cylinder 505 (as shown in Figures 102A to 102C) is arranged to be fixed with respect to the outer housing 524. A plurality of axial ports (not shown) are arranged to allow fluid to pass from an upstream side of the support cylinder 505 and occluding member 533, to a downstream side, adjacent the tool component piston 540, such that the fluid can pass through the flow paths arranged therein.

As can be seen in Figure 102A, the blocking assembly shearable screw 507 (which may alternatively be replaced with any deformable or breakable fastening) is arranged to hold the occluding member 533 in a first arrangement. Once the blocking assembly shearable screw 507 has broken, the occluding member 533 is free to move axially under the action of fluid pressure and flow.

In the expandable drill bit of Figures 102A to 104B, the occluding member 533 comprises a shoulder 538. As is illustrated in Figure 99B, the shoulder 538 is configured such that it can at least partially block the flow path 544 through the piston 540 when the blocking assembly moves to the second arrangement. This is achieved by the shoulder 538 of the occluding member 533 abutting a seat arranged around a flow path.

In this downhole tool, a guide cylinder 509 is arranged coaxially with and fixed with respect to the support cylinder 505. The guide cylinder 509 is fixed relative to the outer housing 524. The expandable drill bit 500 (and in this specific example the guide cylinder 509) comprises an abutment 513 which is arranged to restrict the axial movement of the occluding member 533. As can be seen in Figure 102C, when the tool component has moved to the second position, the abutment 513 is arranged to engage the occluding member 533 and prevent it from continuing to move with the tool component.

In use, the expandable drill bit 500 will typically initially operate in a first arrangement as shown in Figure 102A. In this arrangement the tool component is in a first position and the cutter blocks 522 are retracted within the outer housing 524. In this arrangement the cutter blocks 522 are retracted with respect to the outer surface of the outer housing 524 -that is, the cutter blocks 522 are positioned such that they do not routinely contact the formation. Drilling fluid may flow from the surface, through the ports in the support cylinder 505, through the flow path 544 defined by the tool component piston 540 and out of the face of the expandable drill bit 500. Initially, the occluding member 533 is held in the first arrangement by the shearable screw 507.

When it is desired to deploy the cutter blocks 522 such that reaming operations can begin. The operator may increase the flow rate of drilling fluid through the expandable drill bit 500. As the support cylinder 505, as well as the plurality of nozzles 501 define a restriction to the flow of drilling fluid, the increase in flow rate will increase the pressure gradient across the support cylinder 505. The pressure differential across the occluding member 533, which is arranged in parallel with the support cylinder 505, will also increase. The pressure gradient across the occluding member 533 imparts an axial force on the occluding member 533 in a downstream direction (i.e. to the right of Figures 102A to 102C). Once the pressure differential across the occluding member 533 reaches a threshold value, the shearable screw 507 breaks, releasing the occluding member 533.

Turning now to Figure 102B, once the shearable screw 507 has broken the occluding member 533 is axially moved under the action of fluid pressure from a first arrangement towards a second arrangement. The occluding member 533 moves towards the tool component (to the right in Figures 102A to 102C). The occluding member 533 moves to the second arrangement and, when in the second arrangement, the occluding member shoulder 538 abuts a seat defined by the piston 540 around the entry to at least one of the flow paths 544 through the piston 540. This is shown in Figure 102B.

The increase in the pressure gradient across the piston 540 urges the tool component from the first to the second position, against the action of the tool component shearable screw 503. When the pressure differential across the tool component reaches a threshold value referred to herein as the deployment value, the tool component shearable screw 503 breaks, releasing the tool component. The piston 540 and arms 541 move axially towards the downhole end of the expandable drill bit 500 under the action of fluid flow through the expandable drill bit 500. The axial movement of the arms 541 induces rotational movement of the cutter blades 522, which rotate from the first position towards the second position, splaying the cutter blades 522 radially outwardly, as shown in Figure 102C.

Figure 102C shows the expandable drill bit 500 after the shearable screw 503 has broken and the tool component has moved to the second position, deploying the cutter blocks 522. It can be seen that the abutment 513 of the guide cylinder 509 prevents the occluding member 533 from following the piston 540 and, as such, the flow path 544 which was momentarily closed by the occluding member 533 is again open for drilling fluid to flow therethrough once the piston 540 has moved to the second position.

This means that the pressure in the drilling fluid flowing through the expandable drill bit 500 spikes as the occluding member 533 abuts the tool component, but drops again once the tool component moves away from the occluding member 533. This pressure spike can be registered on the surface and acts to signal to an operator that the operating mode of the downhole tool has changed.

Figure 103A shows the end face of the expandable drill bit 500 with the tool component and hence cutter blocks 522 in a first (retracted) position. The expandable drill bit 500 has two cutter blocks 522 -one located on each side of the expandable drill bit 500. Figure 103B shows the end face of the expandable drill bit 500 with the tool component and hence cutter blocks in the second (deployed) position.

As can be seen, the cutter blocks 522 define a first outer diameter -and hence bore gauge -when in the first (retracted) position. The cutter blocks 522 define a second outer diameter -and hence bore gauge -when in the second (expanded) position.

Figures 104A and 104B are side views of the expandable drill bit 500 with the tool component in a first (retracted) and second (expanded) position, respectively.

Figures 105A, 105B and 106 show an alternative arrangement of cutter blocks 622 for use in an expandable drill bit. As before, the cutter blocks 622 are arranged at an end of the outer housing 624 and are connected to piston arms 641. Here, the cutter blocks 622 are directly connected to the piston arms 641 by means of a pin 627.

The two cutter blocks 622 are arranged in a scissor arrangement. That is, they overlap in a radial direction, as can be seen more clearly in the end face view of Figure 106, which shows the expandable drill bit with the cutter blocks 622 in the second (expanded) position.

As will be understood by the reader, a plurality of seals are employed throughout all of the downhole tools described as part of this disclosure, in order to prevent fluid leakage and to ensure proper operation of the moving components.

The present invention has been described above purely by way of example. Modifications in detail may be made to the present invention within the scope of the claims as appended hereto. Furthermore, it will be understood that the invention is in no way to be limited to the combination of features shown in the examples described herein.

Features disclosed in relation to one example can be combined with features disclosed in relation to a further example.

Claims

CLAIMS: 1. A downhole tool comprising: an outer housing; a flow path arranged to permit fluid flow through the downhole tool; a tool component at least partially located within the outer housing, the tool component being arranged to be movable from a first position to a second position; wherein the tool component or a part thereof is configured to be rotatable relative to the outer housing; an actuation mechanism configured to cause the tool component to move from the first position to the second position; wherein the actuation mechanism is a blocking assembly configured to move from a first arrangement to a second arrangement in response to a change in the flow of fluid through the downhole tool, wherein in the first arrangement the flow path is open and fluid can flow through the flow path and in the second arrangement the blocking assembly is arranged to restrict fluid flow through the flow path; wherein the tool component is configured to move from the first position to the second position under the action of fluid pressure in response to the blocking assembly moving to the second arrangement.
2. The downhole tool of claim 1, wherein the tool component comprises a cutter configured to be rotatable with respect to the outer housing.
3. The downhole tool of claim 1 or 2, wherein the tool component or a part thereof is configured to rotate from the first position in which the tool component or a part thereof is in a retracted position, to a second position in which the tool component or a part thereof is in a deployed position.
4. The downhole tool of claim 1 or 2, wherein the downhole tool is a drill bit and the tool component comprises a rotatable roller cutter.
5. The downhole tool of any of claims 1 to 3, wherein the downhole tool is an expandable drill bit and the expandable drill bit defines a first cutting diameter when the tool component is in the first position and a second cutting diameter when the tool component is in the second position; wherein the second diameter is larger than the first diameter.
6. The downhole tool of any of claims 1 to 3, wherein the downhole tool is a reamer for enlarging the diameter of a bore.
7. The downhole tool of any of the preceding claims, wherein the change in the flow of fluid through the downhole tool increases a pressure differential across the blocking assembly to a threshold value.
8. The downhole tool of any of the preceding claims, wherein the change in the flow of fluid through the downhole tool is an increase in the fluid flow rate.
9. The downhole tool of any of the preceding claims, further comprising a deformable release arranged between the outer housing and the tool component, the release being configured to restrain the tool component in the first position when in an undeformed state and release the tool component such that it can move with respect to the outer housing when the deformable release is in a deformed state.
10. The downhole tool of claim 9, wherein the deformable release is a threaded connector configured to break at a predetermined tensile load.
11. The downhole tool of any of the preceding claims, further comprising a lock arranged to hold the tool component in the second position. 25
12. The downhole tool of any of the preceding claims, wherein the blocking assembly comprises an occluding member and a restraint, wherein the restraint is configured to hold the occluding member in the first arrangement and release the occluding member in response to the change in the flow of fluid through the downhole tool, such that the occluding member can move from a non-occluding position in the first arrangement to an occluding position in the second arrangement in which the occluding member restricts fluid from flowing through the flow path.
13. The downhole tool according to claim 12, wherein the occluding member is arranged to move parallel to the axis of the downhole tool from the first arrangement to the second arrangement.
14. The downhole tool according to claim 12 or claim 13, wherein the restraint is a connector configured to break at a predetermined tensile load.
15. A downhole string comprising a downhole tool according to any of the preceding claims.
16. A method of operating a downhole tool, the downhole tool comprising: a tool component at least partially located within the outer housing, the tool component being arranged to be movable from a first position to a second position; wherein the tool component or a part thereof is configured to be rotatable relative to the outer housing; an actuation mechanism configured to cause the tool component to move from the first position to the second position; wherein the actuation mechanism is a blocking assembly configured to move from a first arrangement to a second arrangement in response to a change in the flow of fluid through the downhole tool, wherein in the first arrangement the flow path is open and fluid can flow through the flow path and in the second arrangement the blocking assembly is arranged to restrict fluid flow through the flow path; wherein the method comprises: operating the downhole tool with the tool component in the first position; changing the flow of fluid through the downhole tool; the blocking assembly moving from the first arrangement to the second arrangement in response to a change in the flow of fluid through the downhole tool; the tool component moving from the first position to the second position under the action of fluid pressure in response to the blocking assembly moving to the second arrangement; operating the downhole tool with the tool component in the second position.