FIELD

The present disclosure relates to a downhole tool, in particular a downhole drill bit and associated methods and apparatuses.

BACKGROUND

During drilling operations, a drill string having a drill bit is deployed in a wellbore from the surface and lowered to a drilling location. The drill bit will typically comprise a primary cutting structure on an end of the drill bit for abrasively interacting with the rock face and drilling through the rock formation, or for drilling through casing or other materials encountered during downhole drilling operations, such as casing shoes and casing guides.

It may become necessary during drilling operations to replace this drill bit. This may be because the primary cutting structure of the drill bit has been worn down and so is not drilling to a satisfactory rate of penetration, or because the drill bit requires a different cutting structure to penetrate the rock effectively. In order to replace a traditional drill bit the entire drill string would be removed from the bore, the end tool - i.e. the drill bit - would be replaced, and then the entire drill string would be run back down the bore. This can take significant time during which wellbore operations are stopped, reducing the efficiency of drilling operations.

Some tools used in downhole activities, such as multi-cycle circulating subs, may have active and inactive configurations. It is typically undesirable to deploy a tool in an active configuration, as it may make running the tool down the wellbore more difficult or may risk damaging the tool. Similarly, it may be that a tool must be active only after a certain operational phase. It is therefore beneficial if the tool (e.g. drill bit) can be activated on demand. In existing methods, control of the activation of such tools is both limited and unreliable. Some existing methods may require complex, expensive and unreliable electronic equipment, or the use of bodies deployed downhole which irreversibly block a flow path of the equipment. Such devices are often unreliable, fragile, can damage other equipment or irreversibly alter equipment uphole of the tool or limit the maximum flow rate which can be pumped to avoid activation.

SUMMARY

According to the disclosure is a drill bit for drilling a bore. The drill bit may comprise a housing. The drill bit may comprise a primary cutting structure. The drill bit may comprise an activation member, which may be arranged within the housing such that the activation member can move axially - for example under an action of fluid flowing through the drill bit. The drill bit may further comprise an indexer, which may be configured to control axial movement of the activation member between a first, second and third axial position. The indexer may be configured such that the activation member can be selectively moved into the third position. This selective movement may be in accordance with a variation of a flow of fluid through the drill bit.

The drill bit may further comprise a deployable assembly. The deployable assembly may be at least partially located within the housing. The deployable assembly may comprise a structure. The deployable assembly may be arranged to be movable from a retracted position (e.g. in which the deployable structure is recessed with respect to the primary cutting structure), towards the primary cutting structure, to a deployed position.

The deployable structure may be a deployable cutting structure.

The drill bit may be arranged such that the deployable assembly is movable from the retracted position towards the deployed position (or to the deployed position), under an action of fluid pressure, in response to the activation member moving to the third axial position.

Further according to the disclosure is a downhole tool. The downhole tool may comprise a housing. The downhole tool may comprise an activation member, which may be arranged within the housing such that the activation member can move axially - for example under an action of fluid flowing through the downhole tool. The downhole tool may further comprise an indexer, which may be configured to control axial movement of the activation member between a first, second and third axial position. The indexer may be configured such that the activation member can be selectively moved into the third position. This selective movement may be in accordance with a variation of a flow of fluid through the drill bit.

The downhole tool may further comprise a deployable member. The deployable member may be at least partially located within the housing. The deployable member may comprise a tool component. The deployable member may be arranged to be movable from a retracted position (e.g. in which the tool component is recessed in the housing - for example in a storage position) to a deployed position (e.g. in which the tool component is extended - for example in an operable configuration). The tool component may be a cutting component, a sensing component, an actuating component or any other component which may need to move from a retracted to a deployed position.

The downhole tool may be arranged such that the deployable member is movable from the retracted position towards the deployed position, under an action of fluid pressure, in response to the activation member moving to the third axial position.

The retracted position may be a position located entirely within the housing. Alternatively, the retracted position may be a position in which the deployable member is located partially within the housing.

The downhole tool may be drill bit. The downhole tool may be a constant-diameter drill bit. The downhole tool may be a hybrid drill bit. The tool component may comprise a roller or rotatable cutter. The deployable member/assembly may be configured to move axially within the housing. The tool component, tool structure, deployable assembly and/or deployable member may be configured to move parallel to the axis of the downhole tool from the retracted position to a deployed position.

The downhole tool may be a variable-diameter, or expandable, drill bit. The tool component may comprise a cutter blade. The cutter blade(s) may be movable in a radial direction, or rotatable, with respect to the housing from the retracted position to the deployed position. In the retracted position, the tool, or cutter blade(s), may define a bore of a first diameter. In the deployed position, the tool, or cutter blade(s), may define a bore with a second diameter. The downhole tool may be a reamer, for example a string reamer or a near-bit reamer. The tool component may comprise a cutter block. The cutter block(s) may be movable in a radial direction, or rotatable, with respect to the housing from the retracted position to the deployed position. In the retracted position, the tool may define a bore of a first diameter. In the deployed position, the tool may define a bore of a second diameter.

Where the tool is of a larger diameter with the tool component in the deployed position compared to the retracted position - for example where the tool is an expandable drill bit or a reamer - it may be necessary to allow the tool components to move from the deployed position towards the retracted position, in order to be able to withdraw the tool from the bore. In such examples, certain features described herein as being for locking the tool components in the deployed position may be omitted or modified to allow movements of the tool components back towards a retracted position. The omission of such features may allow the tool component to move from the deployed position towards the retracted position. This may reduce the maximum diameter of the tool and allow it to be withdrawn from the bore.

Although the specific embodiments described herein relate to drill bits, it will be understood that the present disclosure is also suitable for use in a more generic downhole tool, in which the deployable assembly is instead a deployable member, for example comprising a tool. As such, any description below relating to a drill bit applies, mutatis mutandis, to a downhole tool.

Certain aspects of EP3259437, GB1720773.9 and GB1809767.5 and may be suitable for use with the present disclosure and, as such, the disclosures of these documents are incorporated herein by reference.

Examples according to the present disclosure may provide a device which can be fed downhole in a first configuration and activated, or deployed, at a time chosen by a user. The device may be activatable, or deployable, by varying a flow of fluid through the device - this provides an efficient, reliable and convenient mechanism by which the device can be activated or deployed. Examples according to the disclosure may also place no restriction on the flow of fluid through the device before the device is activated. For example, an operator may be able to increase and decrease the flow of fluid through the device over the full range of flow rates without activating or deploying the device and may only activate or deploy the device when it is decided to do so.

Products according to the disclosure may also provide a reliable mechanism by which a deployable assembly or member can be held in a deployed or activated arrangement, preventing unnecessary or accidental withdrawal and increasing device reliability.

The specific arrangement of this disclosure may provide a more compact device, thus reducing the overall tool length and providing the device with greater downhole manoeuvrability and control. A shorter tool length may enable sharper turns to be provided downhole.

The terms “uphole” and “downhole” may be used herein. These terms relate to directions in during use of the drill bit, with uphole being closer to the surface and downhole being closer to the bottom of the wellbore. While it is felt that the terms uphole and downhole are suitable clear, these terms can be interchanged throughout the disclosure with a first direction/end and a second direction/end, respectively, if required.

The drill bit may be configured for being connected as part of a drill string or other tool string used downhole. The drill bit may be configured to be rotated while engaging a lower end of the wellbore in order to penetrate the rock face.

The drill bit may comprise an outer housing. The housing may be substantially tubular. The housing may be made of any material suitable for use downhole in an oil and gas well. The housing may be arranged to contain and/or support other components of the drill bit.

The housing may comprise a first end at an uphole end of the drill bit and a second end at the downhole end of the drill bit. The first end may comprise a connection means - e.g. a thread or one part of a pin and box connector, for connection to an adjacent element of the drill string. The drill bit may further comprise a primary cutting structure. The primary cutting structure may be located at a second end of the housing/drill bit. The primary cutting structure may be fixed with respect to the housing. The primary cutting structure may comprise a plurality of cutters or cutting blades. The primary cutting structure may comprise a plurality of cutting elements which are arranged to abut and penetrate a rock face during use. The primary cutting structure may comprise polycrystalline diamond cutters.

The primary cutting structure may define a plurality of primary cutting characteristics. The primary cutting structure may define a primary cutting diameter which dictates the diameter of the well bore. The primary cutting structure may define a primary cutting aggressiveness, which defines how aggressive the rock face is penetrated. The primary cutting characteristics may determine the nature of the primary cutting structure and may determine the optimal type of rock face and environment in which it can operate.

The drill bit may further comprise an activation member. The activation member may be supported within the housing. The activation member may be arranged axially within the housing - for example along the centre axis of the drill bit.

The activation member may comprise a piston. The activation member may also comprise a mandrel. The activation member - for example the mandrel portion thereof - may define a flow path through which drilling fluid can pass during use. The activation member - for example the piston portion thereof - may be arranged to be movable under the action of drilling fluid flowing through the drill bit.

The activation member may define a restriction to fluid flow through the drill bit. During use, there may be a pressure drop of fluid flowing through the drill bit across the activation member. This pressure drop may urge the activation member axially within the drill bit. The activation member may be arranged to move axially within and relative to the housing.

The force urging the activation member due to the fluid flow through the drill bit may urge the activation member in the downhole direction. The force on the activation member may be dependent on fluid flow rate through the drill bit. As such, increasing the fluid flow rate may increase the force exerted on the activation member in the downhole direction.

The drill bit may comprise an indexer. The indexer may be arranged within the housing. The indexer may comprise a tubular sleeve. The indexer may be arranged concentrically with the activation member - for example concentrically around or within the mandrel or piston portion thereof.

The indexer may be configured to cooperate with the activation member to control the movement of the activation member within the housing. Collectively, the indexer and activation member may be configured to define a first, second and third position - e.g. axial position - of the activation member. The first, second and third positions may be defined relative to the housing.

The first position may be an uphole position (e.g. in the first direction). In the first position, the activation member may be located closest to the uphole end (i.e. the first end) of the drill bit. The first position may be closer to the first end than the second and third positions. The first position may correspond to a no-stroke position.

The third position may be a downhole position (e.g. in the second direction). In the third position, the activation member may be located closest to the downhole end (i.e. the second end) of the drill bit. The third position may be closer to the second end than the first and second positions. The third position may correspond to a long-stroke position.

The third position may correspond to an activating position. Movement of the activation member to the third position may cause the deployable assembly to move to a deployed position, or may activate the tool. Movement of the activation member to the third position may cause a change in the flow of fluid through the drill bit which may in turn cause the deployment or activation of the deployable assembly.

The second position may be an intermediate position. In the second position, the position of the activation member may be between that of the first position and the second position. The second position may correspond to a short-stroke position. The activation member may be biased towards the first position by a spring arranged in the first chamber. The drill bit may comprise a biasing means. The activation member may be biased. The activation member may be biased in an uphole direction (e.g. a first direction). The activation member may be biased towards the first position (described in more detail below). The biasing means may be arranged within the first chamber (described in detail below).

The activation member may be moveable between the first, second and third position under the action of at least one of, or a combination of, fluid flowing through the drill bit and a biasing means. The activation member may be configured to be movable under the action of a biasing member in the first direction (i.e. towards the first position). The activation member may be configured to be movable under the action of fluid pressure in the second direction (e.g. towards the second and/or third positions).

The activation member may move in a downhole direction (i.e. away from the first position, towards the second/third positions) when the force exerted on the activation member by fluid flowing through the drill bit exceeds that of the biasing member. This may occur when the flow rate of fluid through the drill bit exceeds a predetermined flow rate. The activation member may move in an uphole direction (i.e. away from the second/third positions, towards the first position) when the force exerted on the activation member by fluid flowing through the drill bit is less than that exerted by the biasing member.

The indexer may be configured (or the activation means and/or indexer may be configured) such that the activation member can be selectively moved into the third position. The drill bit may be configured such that the activation member is selectively moved into the third position in response to a variation of a flow of fluid through the drill bit. The activation member may be moved into the third position in response to the variation of an operating parameter - for example during a transition of the activation member between the second and first positions. The variation of an operating parameter may be a change in the flow of fluid flowing through the drill bit - for example flow rate. The activation member may be selectively movable into the third position in response to an increase in the flow rate of fluid flowing through the drill bit during a transition of the activation member from the second position to the first position.

The drill bit may be configured such that the activation member is selectively moved into the third position (only) in response to a variation of a flow of fluid through the drill bit within a predetermined time period. The drill bit may be configured such that the activation member is selectively moved into the third position (only) in response to a first variation of a flow of fluid through the drill bit and a second variation of a flow of fluid through the drill bit within a predetermined time period. The first variation may be a decrease in flow rate. The second variation may be an increase in flow rate.

The variation of a flow of fluid may be an increase in the flow rate of fluid through the drill bit. The predetermined time period may be within a predetermined time period of the flow rate being decreased. The predetermined time period may be the time it takes for the activation member to move from the second position to the first position (e.g. after the flow rate has been decreased with the activation member in the second position).

In order for the activation member to move to the third position, the flow rate of fluid through the drill bit may need to be increased within 30 minutes, 10 minutes, 5 minutes, 2 minutes, 1 minute or 30 seconds of the flow rate being decreased. That is, the predetermined time period may be 30 minutes, 10 minutes, 5 minutes, 2 minutes, 1 minute or 30 seconds. These specific periods are provided purely as examples.

The predetermined time period may be dependent on any of, or a combination of, the indexer (e.g. the track thereof), the biasing member (e.g. the spring urging the activation member towards the first position), the first and second chambers and the flow restriction between the first and second chambers.

The drill bit (e.g. indexer and/or activation member) may be configured such that in order to move the activation member from the first position to the third position, a predetermined sequence of flow control actions must be undertaken.

A flow control action may comprise any result in a change in the flow of fluid through the drill bit. The drill bit (e.g. the indexer and/or activation member) may be configured such that the predetermined sequence of flow control actions must be undertaken within a set time period.

The predetermined sequence of flow control actions may include a reduction in the flow rate of fluid through the drill bit, followed by an increase in the flow rate of fluid through the drill bit. The increase in flow rate may occur within a predetermined time-period. The predetermined sequence of flow control actions may first include an increase in the flow rate of fluid through the drill bit, followed by the above-described decrease and subsequent increase.

The drill bit (e.g. the indexer and/or activation member) may be configured such that in order for the activation member to move to the third position, the rate of fluid flow through the drill bit must be increased within a predetermined period of the flow rate being decreased.

The drill bit may be configured such that the activation member is in: the first position when no fluid is flowing through the drill bit; the second position when fluid is flowing through the drill bit but the predetermined sequence of flow control actions has not just been completed; and the third position when fluid is flowing through the drill bit and the predetermined sequence of flow control actions has just been completed.

The drill bit may be configured such that the activation member can cycle between the first position and the second position.

The drill bit (e.g. the indexer and/or activation member) may be configured such that in order for the activation member to move to the third position, the rate of fluid flow through the drill bit must be changed during a transition of the activation member from the second position to the first position.

The indexer and activation member may be configured such that the activation member (only) moves to the third position in response to a change of the rate of fluid flow through the drill bit during a transition from the second position to the first position. One of the indexer and activation member may define a track. The other of the indexer and activation member may define a follower. The follower may be arranged to travel the track in response to variation of a flow of fluid through the drill bit.

The track may define a no-stroke position corresponding to the first position of the activation member. The track may define a short-stroke position corresponding to the second position of the activation member. The track may define a pathway from the short-stroke position to the no-stroke position.

The track may define a long-stroke position corresponding to the third position of the activation member. The track may define a pathway leading to the long-stroke position.

The pathway leading to the long-stroke position may branch off from the pathway from the short-stroke position to the no-stroke position. The pathway leading to the long- stroke position may branch off at a location between the no-stroke position and short- stroke position. The pathway leading to the long-stroke position may branch off at a location such that to enter the pathway leading to the long-stroke position, the direction of movement of the follower must reverse after leaving the short-stroke position and before arriving at the no-stroke position.

The pathway leading to the long-stroke position may be arranged such that in order for the follower to access said pathway, the direction of relative axial movement between the indexer and the activation member must reverse during a transition of the activation member between the second position and the first position.

The drill bit may comprise a first chamber. The activation member may be arranged in the first chamber. The activation member may act to define the first chamber. The activation member may be configured to move axially within the first chamber - for example the piston portion of the activation member may move axially within the first chamber. The indexer may be arranged in the first chamber.

The drill bit may comprise a second chamber. The second chamber may be in fluid communication with the first chamber. The first and second chambers may be arranged such that fluid passes between the first and second chambers as the activation member moves between the first, second and third positions.

The drill bit may comprise a first chamber and a second chamber; wherein the first chamber and second chamber are at least partially concentrically arranged with respect to each other. The first chamber may be fluidically connected to the second chamber such that fluid can travel between the first and second chambers as the activation member moves between the first, second and third positions.

The second fluid chamber may be arranged to concentrically surround the first fluid chamber. The first fluid chamber may be arranged to concentrically surround the second fluid chamber. Such an arrangement may provide a compact arrangement which reduces the ultimate drill bit length.

The drill bit further may comprise a flow restriction arranged between the first chamber and second chamber. The flow restriction may be configured to restrict the flow of fluid between the first and second chamber.

The flow restriction may provide a first restriction to fluid flow from the first chamber to the second chamber and a second restriction to fluid flow from the second chamber to the first chamber. The second restriction may be more restrictive than the first restriction such that fluid flow from the second chamber to the first chamber is slower than from the first chamber to the second chamber. The flow restriction may comprise a check valve and/or a bi-directional flow control valve.

The flow restriction may be configured to control the rate of movement of the activation member in the first and/or second directions (i.e. from the first position towards the second/third positions and from the second/third positions towards the first position). The characteristics of the flow restriction may therefore determine the time it takes for the activation member to move between the first, second and third positions.

The flow restriction may thus be configured to prolong the transition of the activation member from the second position towards the first position in order to increase the duration of the window during which the flow may be varied to enter the third position. The drill bit may comprise a diaphragm. The diaphragm may be arranged in the second chamber. The diaphragm may define an expandable fluid cavity.

The diaphragm may be configured to receive fluid from the first chamber as the activation member moves towards the second/third position. The diaphragm may be configured to expel fluid (i.e. back into the first chamber) as the activation member moves towards the first position. The diaphragm may be arranged such that fluid entering the second chamber enters and expands the cavity, and the cavity contracts when fluid leaves the second chamber and enters the first chamber.

In other drill bits the diaphragm may be replaced with a compensating piston arranged to move within the second chamber. In other drill bits the diaphragm may be replaced with a bellows.

The drill bit may further comprise a deployable assembly. The deployable assembly may be a deployable blade assembly.

The deployable assembly may have or define a structure - for example at the downhole end thereof. The structure may be a deployable structure.

The deployable structure may be one of either a deployable cutting structure or a deployable depth of cut control structure.

The deployable assembly may be configured to move between a retracted position and a deployed position. In the retracted position the deployable structure may not be deployed and may not interfere with cutting operations of the drill bit. As such, the cutting characteristics of the drill bit may be determined by those of the primary cutting structure. In the deployed position, the deployable structure may interfere with cutting operations. In the deployed position, the deployable structure may alter the cutting characteristics of the drill bit.

The deployable structure may comprise any component configured to alter the cutting characteristics of the drill bit. The deployable structure may be or comprise a cutting structure. The deployable structure may comprise cutter inserts. The deployable assembly may comprise blades; the blades may comprise cutter inserts.

The deployable structure may be or comprise a non-cutting structure. The deployable structure may be or comprise a depth of cutting control structure. The deployable structure may comprise non-cutting domed inserts.

The deployable assembly (when deployed) may be configured to increase or reduce the depth of cut of the drill bit. The deployable assembly may be configured to alter the material properties, e.g. hardness, of the drill bit.

In the retracted position, the deployable assembly may be entirely located within the housing. In the deployed position, the deployable structure may be located behind (i.e. in an uphole direction), level with, or in front of (i.e. in a downhole direction) the primary cutting structure.

In some drill bits, in the deployed position, a portion of the deployable assembly (e.g. the deployable structure) may protrude from the housing or from the primary cutting structure. In other drill bits, the deployable structure may not protrude from the primary cutting structure or the housing in either of the retracted and deployed positions. Instead, the deployable structure may be moved towards the primary cutting structure but remain recessed therefrom - for example to reduce the overall depth of cut - e.g. aggressiveness - of the drill bit. In cases where the deployable structure is configured to change the depth of cut, the deployable structure may comprise domed inserts.

The drill bit may be configured such that the deployable assembly is movable from the retracted to the deployed position under the action of fluid pressure. The deployable assembly may be movable under the action of fluid flowing through the drill bit. Fluid flowing through the drill bit may exert a differential pressure across the deployable assembly, urging the deployable assembly from the retracted to the deployed position. The deployable assembly may move from the retracted to the deployed position in response to the activation member moving to the third position. Fluid flowing through the drill bit may urge the deployable assembly to the deployed position when the activation member is in the third position. When the activation member is in the first and second positions, fluid flowing through the drill bit may be prevented from moving the deployable assembly to the deployed position.

The drill bit may further comprise an actuation chamber.

The drill bit may be configured such that fluid flowing through the drill bit is restricted (or prevented) from communicating with the actuation chamber when the activation member is in the first position and second position.

The activation member may be configured to allow fluid flowing through the drill bit to communicate with the actuation chamber when the activation member is in the third position, for example such that the deployable assembly is movable from the retracted position towards the deployed position under the action of pressure of fluid in the actuation chamber.

The actuation chamber may be arranged adjacent the deployable assembly. The actuation chamber may be arranged such that fluid within the actuation chamber can exert a pressure on the deployable assembly in a direction of the deployed position.

The drill bit may be configured such the deployable assembly moves from the retracted position towards the deployed position when fluid flowing through the drill bit is in fluidic communication with the actuation chamber. Fluid flowing through the drill bit may be able to communicate with the actuation chamber when the activation member is in the third position.

Fluid flowing through the drill bit may be at a higher pressure than that in the annulus/surrounding the drill bit. As such, the pressure in the actuation chamber may increase when fluid flowing through the drill bit is in communication with the actuation chamber. The pressure in the chamber may drop over time when fluid flowing through the drill bit is restricted or prevented from communicating with the actuation chamber. The drill bit may be configured such that fluid flowing through the drill bit is prevented from communicating with the actuation chamber when the activation member is in the first and/or second position.

The drill bit may further comprise an opening leading to the actuation chamber and the drill bit may be configured to restrict (or prevent) fluid flowing through the opening when the activation member is in the first position and second position; and allow fluid to flow through the opening when the activation member is in the third position.

The drill bit may further comprise a blocking member moveable between a closed position in which fluid flowing through the drill bit is restricted (or prevented) from communicating with the actuation chamber, and an open position in which fluid flowing through the drill bit can communicate with the activation chamber.

The blocking member may be biased towards the closed position. The activation member may be configured to move the blocking member to the open position when the activation member moves to the third position.

The drill bit may be configured to send a signal to a user when the deployable assembly moves from the retracted position towards the deployed position.

The signal may be a change (e.g. a drop, or increase) in the pressure of fluid flowing through the drill bit.

The drill bit may comprise a fluid valve. The fluid valve may be arranged to communicate with the actuation chamber. The fluid valve may be arranged to allow fluid to flow from the actuation chamber to an annulus of the wellbore - for example through the housing. The fluid valve may be configured to be exposed to fluid flow when the activation member moves to the third position. The fluid valve may be configured to provide a change in the pressure of fluid flowing through the drill bit - for example when the activation member moves to the third position.

The drill bit (e.g. fluid valve and/or activation member/actuation chamber) may be configured such that fluid flowing through the drill bit is restricted from communicating with the fluid valve when the activation member is in the first position and second position. The drill bit (e.g. fluid valve and/or activation member) may be configured to allow fluid flowing through the drill bit to communicate with the fluid valve when the activation member is in the third position.

The use of a pressure change event when the deployable assembly moves from the retracted to the deployed position can act as a signal to a user that the deployable assembly has been deployed.

The drill bit may further comprise a release member axially fixed with respect to the housing. The release member may be arranged to move between a first position and a second position. In the first position, the release member may engage the deployable assembly when the deployable assembly is in the retracted position and prevent the deployable assembly from moving towards the deployed position. In the second position the deployable assembly is free to move from the retracted position towards the deployed position. The release member may be biased towards the first position.

The release member may be a pin. The release member may be located in the housing of the drill bit. The release member may be arranged to protrude from an inner surface of the housing when in the first position. The release member may be arranged to be retracted into the housing when in the second position. The release member may be biased by a spring.

The drill bit may comprise a plurality of release members or pins - for example 2, 3, 4, 5, 6 or more than 6. The release members may be arranged around the circumference of the drill bit.

The drill bit (or the release member) may be arranged such that the release member is movable from the first position to the second position under an action of fluid pressure. The release member may be configured to move from the first position to the second position in response to the activation member moving to the third axial position.

The release member may be configured to move from the first position to the second position under the action of fluid pressure of the fluid in the actuation chamber, in response to the activation member moving to the third axial position. When fluid flowing through the drill bit is in communication with the actuation chamber the pressure in the actuation chamber may increase. The release member may be in communication with the actuation chamber, such that the pressure of fluid in the actuation chamber acts upon the release member. The release member may be urged from the first position to the second position under the action of fluid pressure of fluid in the actuation chamber, when the activation member is in the third position.

The release member and deployable assembly may be configured such that the release member is engageable with the deployable assembly by moving into the first position when the deployable assembly is in the deployed position. The release member may be arranged to prevent the deployable assembly from moving from the deployed position towards the retracted position when the deployable assembly is in the deployed position and the release member is in the first position.

The release member may be configured to provide a locking function if the pressure in the actuation chamber drops after deployment of the deployable assembly (for example if the activation member moves out of the third position. To do so, the release member may be configured to move from the second position to the first position if the activation member moves from the third position (i.e. if fluid flowing through the drill bit is restricted or prevented from communicating with the actuation chamber). The deployable assembly may be configured to receive the release member when the deployable assembly is in the deployed position and the release member is in the first position, thus locking the deployable assembly in the deployed position.

In tools such as expandable drill bits or reamers, where the outer diameter of the tool may be increased when the tool component (e.g. cutter) is moved to the deployed position, it may be necessary for the tool component to move back towards the retracted position to allow the tool to be withdrawn from the well. In such tools, the release member may be omitted. Alternatively, the release member may be modified to not provide a locking function.

The drill bit may comprise a locking member. The locking member may be arranged to move between an unlocked position and a locked position. In the unlocked position, the deployable assembly may be free to move between the retracted position and the deployed position. In the locked position the locking member may engage the deployable assembly when the deployable assembly is in the deployed position and prevents the deployable assembly from moving from the deployed position towards the retracted position.

The locking member may be biased towards the locked position.

The locking member may be a pin. The locking member may be located in the housing of the drill bit. The locking member may be arranged to protrude from an inner surface of the housing when in the locked position. The locking member may be arranged to be retracted into the housing when in the unlocked position. The locking member may be biased by a spring.

The locking member may be fluidically isolated from fluid flowing through the drill bit. The locking member may be separated from the actuation chamber by means of a seal. The locking member may be arranged such that pressure of fluid flowing through the drill bit cannot urge the locking member towards a retracted position.

The deployable assembly may comprise a recess or detent or other means suitable for receiving the locking member. The deployable assembly may be configured to receive the locking member when the locking member is in the locked position and the deployable assembly is in the deployed position.

The locking member may be biased from the unlocked position towards the locked position. The locking member and/or deployable assembly may be configured such that the locking member moves from the unlocked position to the locked position when the deployable assembly moves to the deployed position.

In tools such as expandable drill bits or reamers, where the outer diameter of the tool may be increased when the tool component (e.g. cutter) is moved to the deployed position, it may be necessary for the tool component to move back towards the retracted position to allow the tool to be withdrawn from the well. In certain examples of such tools, the locking member may be omitted or modified to allow retrieval of the tool. The deployable assembly may define a flow path or passage. The flow path may be configured such that fluid may flow through the deployable assembly flow via the flow path.

The activation member may be configured to restrict the flow of fluid through the flow path or passage when the deployable assembly is in the retracted position and the activation member is in the third position.

The activation member may comprise a central mandrel through which fluid can flow. The activation member may be configured to block the flow path or passage through the deployable assembly when the activation member moves to the third axial position.

The central mandrel may comprise a closed end. The closed end may be arranged to approach the flow path to restrict fluid flow therethrough as the activation member moves to the third position. The central mandrel may comprise radial flow ports through which fluid can flow.

The activation member may be configured to restrict the flow of fluid through the deployable assembly when the activation member moves to the third position (for example by blocking a flow path).

Restricting the fluid flow through the deployable assembly will result in an increased pressure drop across the deployable assembly. Once the pressure drop across the deployable assembly reaches a predetermined value, the deployable assembly may move from the retracted position towards the deployed position.

The activation member and deployable assembly may be configured such that, as the deployable assembly moves from the retracted to the deployed position, the activation member stops blocking the flow passage through the deployable assembly.

The activation member may stay in the third position as the deployable assembly moves to the deployed position. As the activation member may not move with the deployable assembly, as the deployable assembly moves from the retracted position, flow through the flow path is no longer restricted (as a seat surrounding the flow path may be spaced from the activation member). As such, the deployable assembly may be deployable in response to a momentary restriction in fluid flow through the deployable assembly, with a full flow cross-sectional area being operation once the deployable assembly has been deployed.

The drill bit may further comprise a deformable release. The deformable release may be arranged between the housing and the deployable assembly. The deformable release may be configured to restrain the deployable assembly in the retracted position when the activation member is in the first or second position. The deformable release may further be configured to deform in response to the activation member moving to the third position, such that the deployable assembly is free to move from the retracted position to the deployed position.

The deformable release may be a breakable fastener. The deformable release may be a shear pin or screw or otherwise frangible fixing.

A first part of the deformable release may be fixed with respect to the housing. A second part of the deformable release may be fixed with respect to the deployable assembly. The deformable release may thus restrain the deployable assembly in the first position.

The deformable release may be configured to deform such that the deployable assembly can move with respect to the outer housing when a pressure differential across the deployable assembly reaches a deployment value.

The deformable release may be configured to deform (e.g. break) when the pressure differential across the deployable assembly increases caused by the movement of the activation member to the third position. The restriction to fluid flow through the deployable assembly and resulting increase in pressure differential may be sufficient to deform the deformable release, thus freeing the deployable assembly to move to the deployed position.

Further according to the disclosure is a downhole tubular string comprising a drill bit as describe herein. Further according to the disclosure is a downhole tubular string comprising a tool as described herein.

Further according to the disclosure is a method for deploying a deployable assembly of a drill bit. The drill bit may be as described herein. The drill bit may thus comprise a housing; a primary cutting structure; an activation member arranged within the housing such that the activation member can move axially under an action of fluid flowing through the drill bit; an indexer configured to control axial movement of the activation member between a first, second and third axial position; wherein the indexer is configured such that the activation member can be selectively moved into the third position in accordance with a variation of a flow of fluid through the drill bit; the drill bit further comprising: a deployable assembly at least partially located within the housing, the deployable assembly comprising a deployable structure and being arranged to be movable from a retracted position, in which the deployable structure is recessed with respect to the primary cutting structure, towards the primary cutting structure, to a deployed position; wherein the drill bit is arranged such that the deployable assembly is movable from the retracted position towards the deployed position, under an action of fluid pressure, in response to the activation member moving to the third axial position.

The method may comprise moving the activation member into the third position by varying the flow of fluid through the drill bit, thus moving the deployable assembly from the retracted position towards the deployed position.

Varying the flow of fluid through the drill bit may comprise: increasing the flow rate of fluid through the drill bit; reducing the flow rate of fluid through the drill bit; and increasing the flow rate of fluid through the drill bit within a predetermined period of the flow rate being reduced.

A method according to the disclosure may comprise the operation of any of the features of the drill bit or tool described herein.

BRIEF DESCRIPTION OF DRAWINGS

Figure 1 is a side view of a drill bit; Figure 2A is a cross-section of the drill bit of Figure 1;

Figure 2B is a partial cross-section of the drill bit of Figure 1;

Figure 2C is a further partial cross-section of the drill bit of Figure 1;

Figure 3A is a further cross-section of the drill bit of Figure 1;

Figure 3B is a further partial cross-section of the drill bit of Figure 1;

Figure 4A is a further cross-section of the drill bit of Figure 1;

Figure 4B is a further partial cross-section of the drill bit of Figure 1;

Figure 4C is a further partial cross-section of the drill bit of Figure 1;

Figure 5 is a perspective view of an indexer;

Figure 6 is a schematic view of a track for use with an indexer;

Figures 7 A to 7K are schematic views of a track for use with an indexer;

Figures 8A to 8D are perspective views of an indexer and activation member suitable for use with the drill bit of Figure 1;

Figure 9 is a graph schematically illustrating operational pressures for the drill bit of Figure 1;

Figures 10A to 10D are perspective views of the indexer and activation member of the drill bit of Figure 1;

Figure 11 is a perspective cross-sectional view of the indexer and activation member of the drill bit of Figure 1; Figure 12 is a perspective cross-sectional view of subcomponents of the drill bit of Figure 1;

Figure 13 is a further partial cross-section of the drill bit of Figure 1;

Figure 14 is a partial cross-section of a further drill bit;

Figure 15 is a further partial cross-section of the drill bit of Figure 14;

Figure 16 is a further partial cross-section of the drill bit of Figure 14; and Figure 17 is a further partial cross-section of the drill bit of Figure 14.

DETAILED DESCRIPTION OF DRAWINGS

Figure 1 illustrates a drill bit 10. The drill bit 10 comprises a first end 12 for connection to a drill string (not shown) and a second end 14 comprising a primary cutting structure 16. The primary cutting structure 16 is arranged on the end face of the drill bit 10 for abrasively engaging a rock face during use of the drill bit 10.

In this example the primary cutting structure 16 comprises a plurality of cutters arranged on a drill face of the drill bit.

The drill bit 10 in Figure 1 further comprises a deployable assembly 18. In the drill bit 10 of Figure 1, the deployable assembly is a deployable blade assembly 18. The deployable assembly 18 of the drill bit 10 of Figure 1 comprises a deployable cutting structure. The deployable cutting structure is provided by a plurality of cutter blades 20, one of which is illustrated in Figure 1 in a retracted position, recessed with respect to the primary cutting structure 16.

The deployable assembly 18 is configured to move from a retracted position, in which the deployable assembly 18 does not interact with the rock face, to a deployed position in which the deployable assembly 18 interacts with the rock face, either to alter the cutting characteristics of the drill bit 10, or provide consistent drilling characteristics for a prolonged period of time, i.e. to replace worn crown cutters. The drill bit 10 of Figure 1 is arranged such that the deployable assembly 18 can be moved from a retracted to a deployed position in response to a variation of a flow of fluid through the drill bit 10. This may allow a user to selectively deploy the deployable assembly on demand as required.

Drill bits according to this disclosure have a compact arrangement which results in a drill bit with a short length. This may allow deviations of a tighter radius to be drilled, providing increased manoeuvrability. This in turn provides a more versatile drill bit which can be used in a wider range of applications

Figure 2A is a cross-section of the drill bit 10 of Figure 1. Figure 2B is an enlarged image of part of Figure 2A. Figures 3A and 3B are cross-sections of the drill bit 10 with the activation member 30 in the second position and Figures 4A and 4B are cross- sections of the drill bit 10 with the activation member 30 in the third position.

Figure 2C is a different cross-section of the drill bit 10, viewed along a plane rotated with respect to that of Figures 2A, 2B, 3A, 3B, 4A and 4C. The cross-section of Figure 2C is oriented along the centreline of the release pins 58 and locking pins 108 (described below).

The following description is made with reference to Figures 2A to 4B.

The drill bit 10 has a housing 28 which houses an activation member 30, an indexer 32 and a deployable assembly 18. The activation member 30 and indexer 32 cooperate to selectively allow fluid flowing through the drill bit 10 to communicate with an actuation chamber. When fluid flowing through the drill bit is able to communicate with the actuation chamber, a set of release members are withdrawn and the deployable assembly 18 is free to move under the action of fluid pressure to a deployed position. When the deployable assembly 18 reaches the deployed position a set of locking members are biased into engagement with the deployable assembly 18, locking the deployable assembly in the deployed position.

The housing 28 is substantially cylindrical. The housing 28 defines an outer body of the drill bit 10. The drill bit 10 defines a flow path via which drilling fluid can flow through the drill bit 10. Drilling fluid can flow from a tubular connected uphole of the drill bit 10, through the drill bit 10 to exit the primary cutting structure 16 of the drill bit 10 to interact with a rock face.

In this drill bit 10, the drill bit flow path first passes along the longitudinal axis of the drill bit, entering the drill bit 10 through via the first end. The flow path then passes through the hollow central region of the activation member 30 and sleeve 22 and blocking piston 24 (described in more detail below). The flow path then passes into the deployable assembly (described in more detail below) and through a plurality of passages 26 defined therein before exiting the primary cutting structure 16.

In the drill bit of Figure 1, varying the flow of fluid - for example in conjunction with timing periods - through the drill bit moves the activation member 30 between a first, second and third position.

The activation member 30 comprises a piston 30a with a hollow central mandrel 30b. The piston 30a of the activation member 30 is located in and partially defines a first chamber 34, which in this example is defined between the hollow central mandrel 30b of the activation member and a concentric cylinder 36 fixed with respect to the housing 28. The outer circumference of the piston 30a of the activation member 30 fluidically seals against the inner circumferential surface of the concentric cylinder 36. As the activation member 30 moves axially within the housing 28, the size of the first chamber 34 changes accordingly.

The drill bit 10 of Figure 1 comprises a spring 44 arranged to bias the activation member 30 in an uphole direction (i.e. to the left of Figure 2A). The spring 44 is arranged in the first chamber 34, concentric with the activation member 30.

The activation member 30 defines a restriction to fluid flow through the drill bit 10 and, as such, a pressure differential acts across the activation member 30 when fluid flows through the drill bit 10. When fluid flows through the drill bit 10 in a downhole direction (from left to right in Figure 2A), the pressure differential urges the activation member 30 downhole (i.e. towards the primary cutting structure 16). The spring 44 bias acts against the force caused by the pressure differential across the activation member 30. An indexer 32 is arranged adjacent the activation member 30 and is configured to define and control the movement of the activation member 30.

The indexer 32 is in the form of a sleeve arranged about the mandrel 30b of the activation member 30. The indexer 32 is mounted on a radially and axially extending support 29 which is fixed with respect to the housing 28. The indexer 32 is axially fixed with respect to the housing 28, in this example the indexer 32 is free to rotate relative to the activation member 30. Radial and axial needle roller bearings may be arranged radially inside of and at the end of the indexer 32 respectively to permit rotation of the indexer 32.

The activation member 30 includes a follower which, in this example, comprises a plurality of pins 38. The activation member 30 may comprise one, two, three four, five or more than five pins. The pin 38 protrudes radially inwardly from the activation member piston 30a. The pin 38 engages the indexer 32.

The indexer 32 defines a track in the form of a slotted pathway. The track is on the outer circumferential surface of the indexer 32. The pin 38 of the activation member 30 engages the track and travels along the slotted pathways of the indexer 32 as the activation member 30 moves axially within the housing 28. The form of the track defines the axial movement of the activation member 30 and, as such, the indexer 32 defines the first, second and third axial positions of the activation member 30. This is discussed further below with respect to Figures 5 to 8.

A second chamber 42 is arranged concentrically surrounding the first chamber 34. The second chamber 42 in this example is defined between the cylinder 36 and the housing 28. In the drill bit 10 of Figure 1, a flexible diaphragm 40 is arranged in the second chamber 42. The flexible diaphragm 40 is arranged to receive fluid entering the second chamber 42. The diaphragm 40 and cylinder 36 are arranged to define a cavity within the second chamber 42. The cavity between the diaphragm 40 and the cylinder 36 is configured to receive fluid from the first chamber 34. In the second chamber 42 surrounding the diaphragm 40 is a separate cavity which, during use, will contain drilling fluid. In other examples of the drill bit 10, the diaphragm 40 may be replaced with a corresponding bellows arrangement, or a compensating piston arranged to travel within the second chamber 42 in response to fluid entering or leaving the second chamber 42.

The first chamber 34 and second chamber 42 are fluidically connected such that fluid can travel between the first and second chambers 34 42 as the activation member moves 30 between the first, second and third axial positions. In Figure 2B, it can be seen that the first chamber 34 and second chamber 42 are connected by means of a passage 48. The passage 48 passes through and is defined by the support 29. The support is fixed relative to the housing 28. This passage 48 comprises a flow restriction 46, which in the form of a fluid flow restrictor device (e.g. a valve) in the drill bit 10 of Figure 1.

The flexible diaphragm 40 and flow passage 48 are arranged such that, as the activation member 30 moves downhole (i.e. to the right of Figure 2A), the first chamber 34 and spring 44 are compressed. Fluid is expelled from the first chamber 34, through the flow passage 48 and into the second chamber 42. As fluid enters the second chamber 42, the flexible diaphragm 40 deforms and expands.

When the flow of fluid through the drill bit 10 is varied such that the biasing force of spring 44 surpasses the force derived from the pressure gradient across the activation member piston 30a, the activation member 30 is moved uphole (i.e. to the left in Figure 2A). The spring 44 expands and the first chamber 34 increases in size. As this happens, fluid leaves the second chamber 42 and volume defined by the diaphragm 40 and enters the first chamber 34 via the flow passage 48 and flow restriction 46.

The flow restriction 46 is configured to control the flow rate of fluid from the second chamber 42 to the first chamber 34 in order to control the speed at which the activation member 30 moves in an uphole direction (e.g. from the second position towards the first position - see below).

The drill bit 10 further comprises a support sleeve 22. The support sleeve 22 is arranged adjacent the downhole end of the activation member mandrel 30b. The support sleeve 22 comprises a plurality of openings 50 around its circumference. The plurality of openings 50 lead to an actuation chamber 52 which in the present example surrounds the support sleeve 22.

The support sleeve 22 houses a blocking piston 24 which is arranged to move longitudinally within the support sleeve 22 and defines a flow path therethrough. The blocking piston 24 is moveable between a closed position in which fluid flowing through the drill bit 10 is prevented from communicating with (e.g. entering) the actuation chamber, and an open position in which fluid flowing through the drill bit can communicate with the actuation chamber 52. The blocking piston 24 is configured to move axially within the drill bit between the open and closed positions. In the closed position, the blocking piston 24 closes off the openings 50, thus preventing fluidic communication therethrough. The blocking piston 24 moves axially in a downhole direction to stop restricting access through the openings 50, into the open position.

In this drill bit 10, the blocking piston 24 is biased by a spring 54 in an uphole direction (i.e. to the left of Figure 2A). As such, the blocking piston 24 must be moved against the biasing action of the spring 54 in order to move to an open position.

When the blocking piston 24 is in an open position, fluid flowing through the drill bit 10 is able to communicate with the actuation chamber 52. The actuation chamber 52 is arranged adjacent the deployable assembly 18 and, as such, fluid pressure of the fluid in the actuation chamber imparts a force in a downhole direction (i.e. to the right of Figure 2A) on the deployable assembly.

In the drill bit 10 of Figure 1A, the deployable assembly 18 is a deployable blade assembly 18. The deployable assembly 18 comprises a blade piston 56. The blade piston 56 is arranged inside the housing 28 and, in this example, defines a plurality of flow passages 26 through which fluid flowing through the drill bit 10 can exit the primary cutting surface 16 at the rock face.

The deployable assembly 18 also comprises a plurality of cutter blades 20 which are connected (for example at one end) to the blade piston 56. The cutter blades 20 extend substantially longitudinally within the housing 28. In the drill bit 10 of Figure 1, the deployable assembly 18 comprises three cutter blades 20 arranged at 120 degree intervals. Other examples may include one, two, three, four, five or more than five cutter blades 20.

The cutter blades 20 comprise cutters and are arranged to engage the rock face when the deployable assembly 18 is in the deployed position. Each cutter blade 20 is located in slot in the housing 28 which guides the movement of the cutter blades 20 during deployment.

The deployable assembly 18 is configured to move axially within the housing 28 between the retracted and deployed positions. The deployable assembly 18 sealingly engages an inner surface of the housing 28.

A plurality of release members in the form of release pins 58 are arranged to secure the deployable assembly 18 in the retracted position. In the present drill bit 10, there are three release pins 58; however, in other example there may be one, two, four, five, six or more than six release pins 58. The release pins 58 are configured to release the deployable assembly 18 such that it can move to the deployed position in accordance with a specific variation of the flow of fluid through the drill bit 10.

The release pins 58 are arranged around an outer circumference of the blade piston 56. Each release pin 58 is arranged in a recess 60 in the housing 28. In this example, each release pin 58 is configured to move between a first position and a second position. In the first position the release pin 58 protrudes from the inner surface of the housing 28 and engages the blade piston 56. The blade piston 56 comprises a circumferential groove 102 arranged to receive a portion of the release pin 58 when the deployable assembly 18 is in the retracted position and the release pin 58 is in the first position (as shown in Figure 2B). Naturally, it will be understood that while a circumferential groove 102 is used in the present drill bit 10, in order examples a plurality of holes, slots or recesses may be used.

By engaging the blade piston 56, the release pin 58 prevents axial movement of the blade piston 56 with respect to the housing 28. As such, when the release pin 58 is in the first position and the blade piston 56 is in the retracted position, the release pin 58 may engage the blade piston 56 and act to prevent the blade piston 56 from moving to the deployed position. In the drill bit of Figure 1, a spring 104 is arranged in each housing recess 60. In this drill bit, there are three housing recesses 60 (for each of the three release pins 58). The springs 104 are arranged to bias the release pins 60 towards the first position.

In the second position, the release pin 58 is fully housed within the housing 28 and no longer engages the deployable assembly 18. The deployable assembly 18 may therefore no longer be axially restrained within the housing 28. The deployable assembly 18 may therefore be free to move axially within the housing 28 from the retracted position to the deployed position.

The groove 102 in the blade piston 56 is in fluidic communication with the actuation chamber 52. As such, a radially-inner end of each release pin 58 (e.g. that end which engages the blade piston 56) is exposed to the fluid pressure of the actuation chamber 52. When the blocking piston 24 is in the open position and fluid flowing through the drill bit 10 is in communication with the actuation chamber 52, the end of each release pin 58 is exposed to that fluid pressure. The fluid pressure acting on each release pin 58 will be in a radially-outward direction and thus acts against the bias of the springs 104. The springs 104 may be selected such that the force generated by the fluid pressure exceeds the spring force and the release pins 58 automatically retract when the actuation chamber 52 is in communication with fluid flowing through the drill bit 10. The deployable assembly 18 is therefore automatically released and moved to the deployed position when the activation member 30 moves the blocking piston 24 to the open position.

The deployable assembly 18 further comprises an indent 106 around the circumference of the uphole end of the deployable piston blade 56. The indent 106 is in the form of a 90 degree cut-out around the circumferential edge of the blade piston 56. The indent 106 is arranged to engage the release pins 58 when the deployable assembly 18 is in the deployed position and the release pin 58 is in the first position (as shown in Figure 4C).

The release pins 58 may assist in restraining the deployable assembly 18 in the deployed position. The release pins 58 may engage the deployable assembly 18 when the deployable assembly 18 is in the deployed position and the activation member 30 moves from the third position to the first position, as is shown in Figure 4C.

This may occur when the flow rate through the drill bit is reduced after the deployable assembly 18 has been deployed. Reducing the flow rate through the drill bit 10 causes the activation member 30 to move uphole (e.g. from the third towards the first position). The pressure in the actuation chamber 52 is reduced and the biasing force of each release pin spring 104 overcomes the fluid pressure force. This may cause the release pins 58 to move towards the first position and extend radially inwardly from the housing 28. As the deployable assembly 18 will still be in the deployed position (described in more detail below), the release pins 58 engage the indent 106 and assist in restraining the deployable assembly 18 in the deployed position.

If the fluid flow through the drill bit 10 is reduced after the deployable assembly 18 is deployed, the activation member 30 moves out of the third position and the surface area over which the high pressure of the fluid flowing through the drill bit acts is reduced. However, in this case, with the release pins 58 described above, the release pins 58 will move to engage the deployable assembly 18 thus increasing the locking strength of the deployable assembly 18.

The drill bit 10 of Figure 1 further comprises a plurality of locking members in the form of locking pins 108. Similar to the release pins 58, the locking pins 108 are arranged around an outer circumference of the blade piston 56. The locking pins 108 in the drill bit 10 of Figure 1 are axially displaced with respect to the release pins 58.

Each locking pin 108 is arranged in a recess 110 in the housing 28. In this example, each locking pin 108 is configured to move between an unlocked position and a locked position. In the unlocked position, the deployable assembly 18 is free to move between the retracted position and the deployed position. In the locked position the locking pin 110 engages the deployable assembly 18 when the deployable assembly 18 is in the deployed position and prevents the deployable assembly 18 from moving from the deployed position to the retracted position.

Biasing means 112 are located in each locking pin recess 110, which bias the locking pins 108 towards the blade piston 56 of the deployable assembly 18. The deployable assembly 18 comprises a circumferential locking groove 114 (analogous to the groove 102 for receiving the release pins 58) to receive the locking pins 108. The locking groove 114 of this example may be replaced in alternative examples with a plurality of holes, slots or recesses. The locking groove 114 is positioned such that the radially- inward end of the locking pins 108 are adjacent the groove 114 as the deployable assembly 18 reaches the deployed position. At this point, the biasing means 112 urges the locking pin(s) 108 into the groove 114, thus locking the deployable assembly 18 in the deployed position.

The locking pins 108 are isolated from the actuation chamber 52 by means of a seal 109. The seal is located around the circumference of the deployable blade piston 56 to isolate the locking pins 108 from the pressure of the fluid flowing through the drill bit 10. In particular, the seal 109 is arranged to isolate the locking pins 108 from the actuation chamber 52.

The operation of the drill bit 10 of Figures 1 to 4B will now be described.

As shown in Figures 2A and 2B, the deployable assembly 18 is initially in a retracted position. The activation member 30 is in the first position and so is axially located in an uphole position (i.e. to the left of Figure 2A). The uphole direction (i.e. towards the first end 12 of the drill bit 10 and away from the primary cutting structure 16) may be referred to as a first direction.

As described above, the drill bit 10 defines a primary flow path through which drilling fluid can flow. The flow path passes through the first end of the drill bit 10, through the central mandrel 30b of the activation member 30, through the sleeve 22 and blocking piston 24 and finally through the passages 26 in the blade piston 56.

In Figures 2A and 2B either no fluid flows through the drill bit 10, or a low level of fluid flows through the drill bit 10. If there is fluid flow through the drill bit 10, the force exerted on the activation member 30 by the pressure gradient across the activation member flow restriction acts in a downhole direction (i.e. a second direction - towards the primary cutting structure 16). When the flow is low, or there is no flow, this force is exceeded by the spring force of spring 44, acting in an uphole direction (i.e. away from the primary cutting structure 16 and to the left in Figure 2A). As such, in Figures 2A and 2B the activation member is maintained in a first position.

When the activation member 30 is in the first position (and, in fact, the second position), the blocking piston 24 is in the closed position. In the closed position, the blocking piston 24 prevents fluid flowing through the drill bit 10 from flowing through openings 50 in the sleeve 22 and into the actuation chamber 52. As such, with the activation member 30 in the first and second positions, the actuation chamber 52 is not in fluid communication with fluid flowing through the drill bit 10.

In Figures 3A and 3B the rate of fluid flow through the drill bit 10 has been increased. This in turn increases the downhole force on the activation member 30 caused by the pressure differential. When this pressure force exceeds the biasing force of the spring 44, the activation member 30 moves downhole (i.e. to the right of Figures 3A and 3B). The indexer 32 and activation member 30 cooperate to define a second axial position, which corresponds to a short-stroke position, as shown in Figures 3A and 3B. The indexer 32 (and more specifically the track thereon) prevents the activation member 30 from moving any further downhole at this time.

As can be seen from Figure 3B, in this position the downhole end of the mandrel 30b of the activation member 30 abuts and is adjacent part of the blocking piston 24. However, the blocking piston 24 has not been axially moved downhole by the activation member 30.

As the activation member 30 has moved downhole, the first chamber 34 has become smaller and fluid has been expelled, via the flow passage 48 in the support 29, into the second chamber 42 and, more specifically, the cavity formed by the diaphragm 40.

With the activation member 30 in the second position, the deployable assembly is maintained in the retracted position.

Provided a sufficiently long time is left between decreasing and increasing the flow rate, an operator can cycle the flow rate of fluid flowing through the drill bit 10 and the activation member 30 will cycle between the first and second positions, leaving the deployable assembly in the retracted position throughout. Turning now to Figures 4A and 4B, the drill bit 10 is shown with the activation member 30 in the third position and the deployable assembly 18 in a deployed position.

If an operator decreases the fluid flow rate through the drill bit 10 when the activation member 30 is in the second position (shown in Figures 3A and 3B), the bias force of spring 40 exceeds the pressure force on the activation member 30 and the activation member 30 starts to move from the second position towards the first position. If the flow rate is again increased before the activation member 30 reaches the first position, the activation member 30 may move to the third position (or, in some examples as discussed below, to an intermediate or second short-stroke position).

The third position of the activation member 30 is further downhole than both the first and the second positions. This position may be referred to as a long-stroke position.

As can be seen in Figures 4A and 4B, when the activation member 30 is in the third position, the mandrel 30b of the activation member 30 abuts the blocking piston 24 and urges the blocking piston 24 in a downhole direction against the action of the spring 54. This movement moves the blocking piston 24 from a closed position to an open position. In the open position, the blocking position 24 no longer prevents fluid flowing through the drill bit 10 from flowing through the openings 50 into the actuation chamber 52.

The downhole end of the activation member 30 defines a plurality of ports 31 (in this case, in the form of castellations). When the activation member 30 abuts the blocking piston 24, the castellations allow fluid to flow from the mandrel 30b of the activation member 30, past the blocking piston 24, through the openings 50 and into the actuation chamber 52.

As the actuation chamber 52 now communicates with fluid flowing through the drill bit 10, the pressure in the actuation chamber 52 increases. This fluid pressure exerts a downhole force on the deployable assembly 18 (and, in this case, the blade piston 56 thereof). This force urges the deployable assembly 18 towards the deployed position. The pressure of the fluid in the actuation chamber 52 also exerts a force on the release pins 58, which are urged in a radially-outward direction. This force urges the release pins 58 against the biasing force of the springs 104, causing the release pins to move to the second position. When all of the release pins 58 have entered the second position, the deployable assembly 18 is free to move from the retracted position to the deployed position. The deployable assembly 18 can be seen in the deployed position in Figure 4A, with the cutter blades 20 protruding from the primary cutting structure 18. It should be noted, however, that in some examples the cutter blades 20 may not protrude from the primary cutting structure when in the deployed position.

As the deployable assembly 18 moves to the deployed position, the locking pins 108 are biased into engagement with recesses 112 in the deployable blade piston 56 to lock the deployable assembly 18 in the deployed position.

If the flow rate of fluid through the drill bit 10 is reduced after the deployable assembly 18 has moved to the deployed position, the pressure in the actuation chamber 52 may drop. This drop in pressure may result in the biasing force of the springs 104 on the release pins 58 exceeding the pressure force holding them in the second position. The release pins 58 may therefore move back to the first position and engage the deployable blade piston 56, to hold the deployable assembly 18 in the deployed position along with the locking pins 108 (but in the absence of the pressure force in actuation chamber 52). This configuration is shown in Figure 4C.

This ensures the deployable assembly 18 is always very robustly secured in the deployed position once it has been deployed. When the flow rate through the drill bit 10 is high and the activation member 30 is in the third position, high pressure fluid in the actuation chamber 52 exerts a force on a large surface area of the deployable assembly 18 towards the deployed position and the locking pins 108 lock the deployable assembly 18 in the deployed position, thus providing a very robust retention force maintaining the deployable assembly in the deployed position.

If the flow rate through the drill bit 10 decreases after the deployable assembly 18 has moved to the deployed position, the activation member 30 may move away from the third position (i.e. towards the first position). This may cause fluid flowing through the drill bit 10 to no longer be able to communicate with the actuation chamber 52 (and thus the release pins 58). The release pins 58 will then move back towards the first position (as they are no longer urged radially outward by the fluid pressure) and engage the deployable blade piston 56 (e.g. via indent 106) to hold the deployable assembly 18 in the deployed position in combination with the locking pins 108. In this case, the area of the deployable assembly over which the high-pressure fluid flowing through the drill bit acts is reduced. However, an additional set of pins (the release pins 58) act to mechanically hold the deployable assembly in the deployed position.

As such, the deployable assembly 18 is always robustly held in a deployed position. When the activation member 30 is in the third position, the deployable assembly 18 is held in a deployed position by fluid pressure acting on a large surface area and the locking pins 108. When the activation member 30 is in the first or second positions, the deployable assembly 18 (once deployed) will be held in position by fluid pressure acting on a smaller surface area, the release pins 58 and the locking pins 108.

Figure 5 depicts an indexer 32 according to the disclosure. Figures 6 to 8D relate to the indexer 32 of Figure 5. Although the indexer 32 described with respect to Figures 5 to 9 is different to that depicted in the drill bit of Figures 1 to 4B, they are functionally analogous and the indexer 32 of Figures 5 to 9 is suitable for use in the drill bit 10 of Figures 1 to 4B. Figures 10A to 12 depict the indexer 32 of the drill bit 10 of Figures 1 to 4C. The indexer 32 depicted in Figures 10A to 12 operates in an analogous way to that of Figures 6 to 8D and, as such, the description provided with respect to Figures 6 to 8D applies, mutatis mutandis, in relation to the operation of the indexer 32 of Figures 10A to 12.

The indexer 32 is tubular and is thus an indexer sleeve. The indexer 32 comprises an internal radius configured to be mounted on needle roller bearings surrounding a cylindrical mounting surface of the support 29, which in turn is fixed within the housing. The indexer 32 can rotate relative to the housing. A first end 62 of the indexer 32 comprises a flat surface. This flat surface is arranged to engage a thrust bearing located between the first end 62 of the indexer 32 and the support 29. The indexer 32 is configured to rotate relative to the housing 28 but in the present example is axially restrained such that it cannot move in the first direction with respect to the housing 28. A second end 64 of the indexer 32 comprises a castellated profile. In other examples, the second end 64 of the indexer 32 may comprise an undulating or otherwise shaped profile. The castellated profile may be configured to engage a similarly castellated profile, or a series of protrusions, on the inside of the activation member 30 (discussed in more detail below) to support axial loads when the activation member is in the second and third axial positions.

On the outer curved surface of the indexer 32 a track 74 comprising a plurality of pathways is defined in the form of channels or slots cut into the thickness of the indexer sleeve. The channels are arranged to engage the activation member pin 38.

The plurality of pathways cooperate with the pins 38 of the activation member 30 to define the first position, second position and third position of the activation member 30. Naturally, while in this example the indexer 32 comprises the track 74 and the activation member 32 comprises the pins 38, in other examples the activation member 32 may define the track and the indexer 32 may comprise pins.

The indexer comprises more than one plurality of pathways, which repeat around the outer circumferential surface of the indexer 32. The multiple sets of pathways may be arranged to engage with multiple followers (i.e. pins 38) arranged around the circumference of the activation member 30. The track may define a continuous path around the circumference of the indexer 32. This may permit the activation member 30 and indexer 32 to (endlessly) cycle between first and second, first and third and/or second and third positions.

Although it is understood that this in this example the activation member 30 comprises a plurality of pins 38 and the indexer comprises a plurality of pathways for each respective pin 38, in the following description the arrangement of only a single pin 38 and plurality of pathways will be described. Naturally, where a plurality of pins 38 are provided, each with a corresponding set of pathways, the following description may apply to each pin-pathways pair. Furthermore, the pathways replicated around the indexer 32 may be interconnected such that a pin 38 can travel through a first plurality of pathways before entering a second plurality of pathways, for example after a number of flow control actions. The pathways comprise corresponding locations for the pin 38 when the activation member 30 is in the first position, second position and the third position.

The location for the pin 38 corresponding to the first axial position of the activation member 30 is referred to as the no-stroke position 66. The location for the pin 38 corresponding to the second axial position of the activation member 30 is referred to as the short-stroke position 68, 70. The position corresponding to the third axial position of the activation member 30 is referred to as the long-stroke position 72.

In the example shown, the pathways also comprise a location for the pin 38 which defines a second short-stroke position 70, to be entered between the second position and the third position. When the pin 38 of the activation member 30 is in the second short-stroke position 70, the activation member 30 is in the second position. The provision of a second short-stroke position 70 for the activation member 30 increases the length of the sequence of flow control actions required for the activation member 30 to enter the third axial position and, as such, reduces the likelihood that the activation member 30 will enter the third position by mistake.

The indexer 32 and pin 38 are configured such that the pin 38 can travel along the pathways as the activation member 30 moves axially within the housing 28. The indexer 32 is configured to rotate relative to the activation member 30 as the pin 38 traverses a pathway which extends circumferentially around the indexer 32.

The track 74 comprises a change in depth in the form of a step 75. The step 75 is located at a position to prevent the pin 38, following the pathways defined by the track 74, from entering the pathways in an incorrect sequence. An example of an incorrect sequence may be going straight from the no-stroke position 66 to a second short- stroke position 70 or long-stroke position 72 without first going to the second position. The step is discussed further with reference to Figure 6.

Figure 6 schematically illustrates an example track 77 for use on an indexer 32 according to the disclosure. The track 77 of Figure 6 and Figure 7 is similar, but slightly different, to that shown in Figure 5. The function of both tracks 74, 77 however, are essentially the same - that is, both profiles define a first, second and third axial position of the activation member 30. Both tracks 74, 77 are suitable for use in a drill bit 10 according to the disclosure.

The track 77 includes a position for the pin 38 when the activation member 30 is in the first position (no-stroke position 66), second position (short-stroke position 68), an intermediate position (a second short-stroke position 70) and the third position (long- stroke position 72).

The track 77 comprises a first pathway 76 connecting the no-stroke 66 and short-stroke positions 68. This pathway 76 may be travelled along by the pin 38 when the activation member 30 moves axially towards the primary cutting structure 16 in response to fluid flowing through the drill bit 10 (or an increase in the flow rate), thus producing a pressure differential across the activation member 30. The first pathway 76 guides the activation member 30 from the first position to the second position.

If the pressure across the activation member 30 is reduced, for example because the flow through the drill bit 10 has been reduced, the activation member 30 moves uphole, i.e. away from the primary cutting structure 16 (to the left of Figure 2A) and the pin 38 traverses the second pathway 78, which leads from the short-stroke position 68 to the no-stroke position 66.

If the pressure differential across the activation member 30 remains low, the activation member 30 reaches the first position and the pin 38 reaches the no-stroke position 66.

If, however, during the return stroke - i.e. as the activation member 30 moves from the second position towards the first position and the pin 38 moves from the short-stroke position 68 towards that for the no-stroke position 66 - the pressure differential across the activation member 30 again increases (e.g. due to a corresponding increase in the flow rate through the drill bit 10), the activation member 30 moves back downhole, towards the primary cutting structure (i.e. to the right in Figure 2A). The pin 38 will therefore follow the first intermediate pathway 80, which branches off from the second pathway 78 and leads to the second short-stroke position 70.

In the second short-stroke position 70 the activation member 30 is in the second position and as such, the arrangement of drill bit is as shown in Figures 7 and 9A. When the flow rate through the drill bit 10 is again reduced, the pressure differential across the activation member 30 reduces. This causes the activation member 30 to move in the uphole direction again under the action of the corresponding spring 44. As the activation member 30 moves uphole, the pin 38 follows the second intermediate pathway 82 towards the no-stroke position 66.

If the flow rate through the drill bit 10 remains low, the activation member 30 reaches the first position and the pin 38 reaches the corresponding location for the no-stroke position 66.

If, however, the flow rate through the drill bit is again increased before the activation member 30 reaches the first position (and hence before the pin 38 reaches the no stroke position 66), the activation member 30 again moves downhole towards the primary cutting structure 16 (i.e. to the right in Figure 2A) and the pin 38 follows the third pathway 84. The third pathway 84 leads to the long-stroke position 70. Accordingly, the activation member 30 enters the third position.

The time during which the flow rate can be increased to enter the ‘next’ pathway (e.g. the first intermediate pathway 80 from the second pathway 78, or the third pathway 84 from the second intermediate pathway 82) is determined by the location of the intersections 85. The intersections 85 are configured such that once the pin 38 is located at, or has traversed, the intersection 85, reversal of the movement of the pin 38 results in the pin 38 entering the next pathway rather than the one from which it came. Therefore, the pin 38 must have traversed, or be located at, the intersection 85 before the flow rate is increased in order for the pin 38 to enter the ‘next’ pathway. The time that it takes for the pin 38 to travel from the location corresponding to the short-stroke position 68 (or second short-stroke position 70) to the intersection 85 may be referred to as a “predetermined period”.

Once the pin 38 has traversed the no-stroke intersections 75, located adjacent the no stroke position 66, the activation member 30 will not be able to advance to the ‘next’ position, even if the flow rate is again increased. Instead, the pin 38 will travel to the short-stroke position 68 and the activation member 30 will go to the first axial position. The section in which this is the case extends between the intersections 75 and the no stroke position 66.

Given knowledge of the characteristics of the drill bit 10, the time that it takes for the pin 38 to move from the short-stroke position 68 (or second short-stroke position 70) to the intersection 85 may be calculated. Alternatively, it may be measured.

Likewise, the time it takes for the activation member 30 to travel from the second position to the first position can be calculated or measured.

These two times will allow a user to determine a window of time after reducing the flow through the drill bit during which the flow needs to be increased in order to move the activation member 30 into the ‘next’ position (e.g. third position). This window of time is schematically represented in Figure 6 by reference numeral 86.

Although not visible in Figure 6, the location of the change in depth of the pathways - i.e. steps 75 - are indicated. A first step 75 is located at the intersection between the first pathway 76 and the second pathway 78 at the end closest to that corresponding to the no-stroke position 66. A second step 75 is located at the end of the third pathway 84 and second intermediate pathway 82 at the end closest to the location corresponding to the no-stroke position 66. The steps 75 are defined as a step down when travelling along the second pathway 78 or third pathway 84 towards the no-stroke position 66. The steps 75 are arranged to prevent a pin from inadvertently entering the second pathway 78 or third pathway 84 from the first pathway 76, without first going to the short-stroke position 68. This prevents the drill bit 10 from inadvertently going straight from no-flow to the third axial position of the activation member, deploying the deployable assembly 18 unintentionally.

As can be seen from the schematic track 77, the long-stroke position 72 corresponds to the third axial position of the activation member 30. In the third position, the activation member 30 is located further downhole, that is, closer to the primary cutting structure 16 than the second and intermediate positions.

Turning now to Figures 7 A to 7K a movement sequence of the pin 38 in the track 77 of Figure 6 is shown. In Figure 7 A the pin 38 is at the no-stroke position 66.

In Figure 7B, the pin 38 is shown moving from the no-stroke position 66 to the short- stroke position 68 along the first pathway 76. This movement is caused by an increase in fluid flow rate through the drill bit 10, thus increasing a pressure differential across the activation member 30 and moving the activation member 30 to the second position.

In Figure 7C, the flow of fluid through the drill bit 10 has been reduced causing the activation member 30 to be urged towards the first position by the spring 44. The pin 38 therefore travels towards the no-stroke position 66 along the second pathway 78.

In Figure 7D the pin 38 continues along the second pathway 78, until it reaches the no stroke position 66, in Figure 7E.

In Figure 7F, movement is shown corresponding to a movement of the activation member 30 downhole - i.e. towards the primary cutting structure 16 occurring after the period shown in Figure 7D but before the period shown in Figure 7E. That is, the flow rate through the drill bit 10 is increased during the transition from the second position to the first position (i.e. at some point while the pin 38 is traversing the second pathway 78). Figure 7F shows the pin moving up the second pathway 78, towards the second short-stroke position 70.

In Figure 7G, the flow rate is maintained and so the pin 38 continues to travel to the second short-stroke position 70, via the first intermediate pathway 80.

In Figure 7H, the flow rate through the drill bit 10 is reduced such that the activation member 30 is biased uphole and the pin 38 moves along the second intermediate pathway 82 towards the no-stroke position 66.

In Figures 7I and 7J the flow rate is maintained at a low level (e.g. off) and the activation member 30 continues to move uphole under the action of the spring 44 and the pin 38 therefore travels along the second intermediate pathway 82 to the no-stroke position 66. In Figure 7K, however, the flow rate through the drill bit 10 is increased before the activation member 30 reaches the first position (and hence before the pin 38 reaches the no-stroke position 66). The activation member 30 is therefore urged downhole and moves to the third position; the pin follows the third pathway 84 and moves to the long- stroke position 70. The flow rate is increased at a time after the period shown in Figure 7H but before that shown in Figure 7I and 7J (although it is to be noted that the activation member 30 would still enter the third position if the flow rate was increased after the period shown in 7I but before that of 7J).

Figures 8A to 8D depict an assembly of the piston 30a of the activation member 30 and indexer 32 in configurations corresponding to the activation member 30 being in the first position, second position, an intermediate position corresponding to the second position (i.e. a second short-stroke position) and the third position.

The activation member 30 has six pins 38 equally spaced around the circumference of the sleeve portion of the activation member piston 30a which engage the track of the indexer 32. The track defines ramps 79 which provide a change in depth of the corresponding pathway. Ramps 79 are located in the first pathway, leading from the no-stroke position 66 to the short-stroke position 68, and the pathway leading from the long-stroke position 72 back to the no-stroke position 66. The ramps 79 are provided such that step 75 can be included and the track can still provide a continuous track around the indexer 32.

In Figure 8A, the pins 38 are located in a position corresponding to the activation member 30 being in the first position.

In Figure 8B the activation member 30 has moved to the second position and the pin 38 has advanced to the short-stroke position 68. The activation member 30 has moved axially, the indexer 32 has rotated relative to the housing 28 and activation member 30.

In Figure 8C the pin 38 is in a second short-stroke position 70. Accordingly, the flow through the drill bit 10 has been reduced and then increased before the activation member 30 reached the first position. Again, the activation member 30 has moved axially while the indexer 32 rotates. In Figure 8D the activation member 30 is in the third position and the pin 38 is in the long-stroke position.

Figure 9 is a graph showing an exemplar sequence of flow control actions for use with a drill bit according to the disclosure. In the drill bit according to the graph of Figure 9, the indexer 32 is that according to Figures 5 to 8D. As such, the indexer 32 defines an intermediate position 70 and two cycles of a reduction in pressure shortly followed by an increase in pressure are required in order for the activation member 30 to move to the third position to deploy the deployable assembly.

In this example, the predetermined time period (i.e. the time period during which the flow rate must be increased for the activation member 30 to move to the ‘next’ position) has been calculated or measured at 2 minutes.

The drill bit starts with little or no fluid flowing therethrough. Thus the activation member 30 is in the first position. During the time period t1 the flow rate is increased and thus the pressure increases causing the activation member 30 to move into the second position (and the pin to the short-stroke position 68) . In t2 the flow rate is reduced and the pressure drops. Before the activation member 30 reaches the first position, however, the flow rate is increased at the start of t3 - this moves the activation member 30 back to the second position (and the pin 38 to the second short- stroke position 70). The flow rate is again reduced and the pressure drops during t4. Before the activation member 30 reaches the first position, the flow rate is again increased and the pressure rises during t5. This causes the activation member 30 to move to the third position (t5) (and the pin 38 to the long-stroke position 72), deploying the deployable assembly of the drill bit.

Time periods t6 and t7 illustrate that the flow rate can be reduced and provided it is increased within the predetermined time period (2 minutes in the present example) ensuring that the activation member 30 does not reach the first position, the activation member 30 will go back to the third position. In t6 the flow rate is reduced such that the activation member 30 leaves the third position. However, the flow rate is increased before the activation member 30 reaches the first position and, as such, the activation member 30 moves back to the third position. In time period t8 the flow rate is reduced for longer than the predetermined time period such that the activation member 30 reaches the first position. Accordingly, when the flow rate is again increased in period t9, the activation member 30 moves to the second position.

The graph of Figure 9 also illustrates that there is a drop in the peak pressure of the fluid flowing through the drill bit when the activation member 30 is in the third position. This may be due to the presence of ports in the actuation chamber 52 which allow fluid to flow into the annulus. This allows a user to easily and reliably confirm from the surface whether the drill bit is in an active or inactive position.

Figures 10A to 10D illustrate the indexer 32 of the drill bit 10 of Figures 1 to 4B. The activation member 30 and indexer 32 assembly of Figures 10A to 10D are analogous in terms of structure and function to that of Figures 8A to 8D. As such, the comments made with respect to Figures 8A to 8D apply to Figures 10A to 10D, mutatis mutandis.

The assembly of Figures 10A to 10D includes four pins 38 and four corresponding sets of pathways on the indexer 32 (rather than the 6 of Figures 5 to 8D). In alternative embodiments there may be two pins 38.

A further difference to the activation member 30 and indexer 32 of Figures 5 to 8D is that the track 74 of the indexer 32 illustrated in Figures 10 to 10D (corresponding to that in the drill bit 10 of Figures 1 to 4B) includes a first intermediate position 70a and a second intermediate position 70b (unlike that of Figures 5 to 8D which includes only one intermediate position 70). Both of these positions correspond to an activation member 30 axial position equivalent to the second position.

The assembly starts with the pin 38 in the no-stroke position 66 and the activation member 30 in the first position - see Figure 10A. The fluid flow must be increased to move the pin 38 to the short-stroke position 68 (with the activation member 30 in the second position) - see Figure 10B. A subsequent decrease in flow rate followed by an increase moves the pin 38 to the first intermediate position 70a (with the activation member 30 in the second position) - see Figure 10C. A second decrease and subsequent increase in flow rate will move the pin 38 to the second intermediate position 70b (with the activation member 30 in the second position). A third decrease and subsequent increase in flow rate will move the pin 38 to the long-stroke position 72 (with the activation member 30 in the third position) - see Figure 10D. This will activate the drill bit 10 and the deployable assembly 16 will move towards the deployed position.

Figure 11 illustrates an assembly of the activation member 30 and indexer 32 of Figures 10A to 10D.

The assembly includes a pair of needle roller bearing 88, 90 on the inner circumferential surface of the indexer 32. The bearings 88, 90 allow the indexer 32 to rotate relative to the housing 28 or support 29 on which it is mounted.

The indexer 32 comprises a plurality of sets of identical tracks which repeat around the circumference of the indexer 32. In the present example there are four sets of identical tracks repeated around the outer surface of the indexer 32.

The second end 64 of the indexer 32 comprises a castellated profile, as discussed above. The end profile of the second end 64 is configured to be complementary to, and engage, a corresponding profile on a surface of the activation member 30. The end profile of the indexer 32 comprises a plurality of cut-outs 94. The corresponding end surface of the activation member 30 comprises a plurality of protrusions 96. These profiles are configured such that the axial load is transferred between the activation member 30 and the indexer 32 via the castellated profile rather than the pin 38. Accordingly, a first set of surfaces of the second end 64 of the indexer 32 and of the activation member 30 are arranged to abut when the activation member 30 is in a second position (e.g. an end surface of the protrusion 96 and a flat surface of the indexer 32). A further set of surfaces of the second end 64 of the indexer 32 and of the activation member 30 are arranged to abut when the activation member 30 is in an intermediate position (e.g. an end surface of the protrusion 96 and a recessed inner surface of the cut-out 94 of the indexer 32). A further set of surfaces of the second end 64 of the indexer 32 and of the activation member 30 are arranged to abut when the activation member 30 is in the third position (e.g. an end surface of the protrusion 96 and a recessed inner surface of the same, or a second, cut-out 94 of the indexer 32). The activation member 30 comprises a piston 30a which has a cylindrical sleeve section which is arranged to surround the indexer 32 when the activation member 30 is in the third position. The activation member 30 and indexer 32 are therefore arranged such that the indexer 32 can move into and out of the activation member 30 as the activation member 30 moves between the first, second and third positions.

The activation member 30 comprises four pins 38 arranged around the internal circumference of the sleeve section 94 to engage the channels of the four sets of tracks 74 of the indexer 32. The activation member 30 comprises a wave spring 92 arranged to bias each pin 38 away from the activation member 30, into the pathway/track 74 of the indexer 32.

The wave spring 92 biases the pin 38 towards the bottom of the corresponding pathway. This ensures that, if the pin 38 encounters a step 75 arranged in the track 74, it does not inadvertently traverse the step 75 due to a poor contact between the pathway and the pin 38. The wave spring 92 ensures the pin 38 is always in contact with the bottom of the pathway such that the step 75 efficiently prevents the pin 38 from entering the corresponding pathway.

As discussed previously, the track 74 comprises ramps in order to return the pin 38 to the ‘original’ height after traversing a step 75, these are seen in Figure 8A. This ensures a continuous track 74 can be provided.

A plurality of seals 98 are provided to prevent the ingress of drilling mud or other fluids between components.

Figure 12 shows an assembly of an activation member 30, indexer 32, support 29, support sleeve 22 and blocking piston 24, according to the drill bit 10 of Figure 1.

The activation member 30 and indexer 32 are as described with reference to Figure 11, albeit with the activation member mandrel 30b being shown in Figure 12. The indexer 32 is mounted on the support 29 and is permitted to rotate thereon by means of the needle bearings 88, 90. The mandrel 30b of the activation member extends through the centre of the support 29, towards the support sleeve 22 and the blocking piston 24. In the arrangement of Figure 12, the activation member 30 is in the first position and so is spaced from the blocking piston 24. The blocking piston 24 is located inside the support sleeve 22. The blocking piston 24 sealingly engages the inner surface of the support sleeve 22. In this example a spring 54, biases the blocking piston 24 towards a closed position. In the closed position, the blocking piston 24 is arranged to prevent fluid flowing through the drill bit from communicating with the actuation chamber 52 (not shown in Figure 12) via the openings 50 in the support sleeve 22. The blocking piston 24 is arranged to move axially under the action of the activation member 30 (and, more particularly, the mandrel 30b thereof) to an open position, against the bias of the spring 54.

The support 29 defines a flow passage 48, which connects the first and second chambers 34, 42 (not shown in Figure 12). The flow passage 48 comprises a flow restriction 46 which, in the present example, is a valve. The valve is configured to provide a higher restriction to flow of fluid from the second chamber 42 to the first chamber 34 than from the first chamber 34 to the second chamber 42. As such, the drill bit 10 is configured such that the activation member 30 moves more slowly from the second position towards the first position than from the first position towards the second position.

The restriction to fluid flow 46 determines the predetermined time period. That is, the restriction to fluid flow 46 determines the speed at which the activation member 30 moves between the first, second and third positions. By increasing the restriction to fluid flow when the activation member 30 is moving towards the first position from the second, third or an intermediate position, the transition from the second/intermediate/third position to the first position lasts a longer time and it is easier for an operator to increase the flow rate before the first position is reached, in order to move the activation member 30 on to the ‘next’ position, if required.

Figure 13 is a cross-section of the drill bit 10 of Figures 1 to 4B. The drill bit 10 is shown with the activation member 30 in the third position and the deployable assembly 18 in the deployed position.

As discussed above, the drill bit 10 of the present disclosure allows an operator to increase and decrease the flow rate of drilling fluid through the drill bit without deploying the deployable assembly 18, provided they do not undertake the predetermined flow control actions necessary for deployment.

As an operator increases the flow rate the pressure of the drilling fluid increases. The drill bit 10 of Figure 1 provides a pressure drop when the deployable assembly 18 moves to the deployed position, providing feedback to the operator to inform them of deployment.

In an example according to the disclosure, the pressure of drilling fluid flowing through the drill bit 10 may be at a first level when the flow rate is low and the activation member 30 is in the first position. The pressure of drilling fluid flowing through the drill bit 10 may be at a second level (which is higher than the first level) when the flow rate is high and the activation member 30 is in the second position. The pressure may be at a third level when the flow rate is high and the activation member 30 is in the third position. This third level may be between the first and the second level. This may allow an operator to check the pressure of drilling fluid in order to determine whether the deployable assembly 18 is in the deployed position.

The above functionality is provide by a bypass nozzle 116 located in the actuation chamber 52. Fluid flowing through the drill bit 10 is unable to communicate with the bypass nozzle 116 when the activation member 30 is in the first and second positions. When the activation member 30 is in the third position, fluid flowing through the drill bit 10 is able to communicate with, e.g. pass through, the bypass nozzle 116. This increases the area through which fluid can flow through the drill bit 10 and results in a pressure drop when the flow rate is high and the activation member 30 is in the third position compared to the second position.

Referring now to Figures 14 to 17, a further drill bit 210 according to the disclosure is depicted. The drill bit 210 of Figures 14 to 17 has a number of similar components to that of Figures 1 to 4B. In particular, the housing, support 29, cylinder 36, indexer 32, activation member piston 30a, first chamber 34, spring 44 and locking pins 108 are largely structurally and functionally similar to those described with respect to the drill bit 10 of Figures 1 to 4B. For this reason, further detailed discussion relating to these features will not be provided with respect to Figures 14 to 17. Figure 14 shows the drill bit 210 with the activation member 30 in the first position. Figure 15 shows the drill bit 210 with the activation member 30 in the second position. Figure 16 shows the drill bit 210 with the activation member 30 in the third position with the deployable assembly 18 in the retracted position. Figure 17 shows the drill bit 210 with the activation member 30 in the third position with the deployable assembly 18 in the deployed position.

Referring now to Figure 14, the central mandrel 30b of the activation member 30 comprises a closed end surface 212. Adjacent the closed end surface 212 of the mandrel 30b are a plurality of radial ports 214 through which drilling fluid may flow.

When the activation member 30 is in the first position (as shown in Figure 14), drilling fluid flows from the surface, into the first (uphole) end of the drill bit 210. Fluid then flows through the central mandrel 30b of the activation member 30 and out of radial ports 214 into a space behind the blade piston 56. From here, fluid flows through the blade piston 56 via the flow path 216 (as well as other corresponding flow paths, not shown in Figure 14). The fluid then exits the primary cutting structure 16 via nozzles 218.

In the drill bit 210 of Figure 14, a compensating piston 224 is located in the second chamber 42 in place of the diaphragm 40 of the drill bit 10 of Figures 1 to 4B. The compensating piston 224 acts to balance the fluid pressure of fluid moving from the first chamber 34 to the second chamber 42.

The deployable assembly 18 is held in the retracted position (as shown in Figures 14, 15 and 16) by a shear screw 220. The shear screw 220 is arranged axially within the drill bit 210. A first end of the shear screw 220a is fixed with respect to the housing 28 and a second end of the shear screw 220b is fixed with respect to the deployable assembly 18. As the deployable assembly 18 defines a restriction to fluid flow through the drill bit 210, a pressure force acts on the deployable assembly in a direction downhole (i.e. in the direction of fluid flow). The shear screw 220 counteracts the pressure force acting on the deployable assembly 18. The shear screw 220 is therefore under tension when fluid flow through the drill bit 210. Figure 15 shows the drill bit 210 with the activation member 30 in the second position. The activation member 30 has advanced downhole (e.g. towards the piston blade 56). The closed end surface 212 of the actuating member 30 approaches a seat surrounding the flow path 216. The closed end surface 212 of the actuating member 30 does not abut the seal surrounding the flow path 216 and, as such, a circumferential gap 220 is maintained through which fluid may flow.

The shear screw 220 holds the deployable assembly 18 in the retracted position.

Figure 16 shows the activation member 30 in the third position. The deployable assembly 18 has not yet moved to the deployed position and, as such, is in the retracted position.

The actuating member 30 is located adjacent the blade piston 56 and the closed end surface 212 of the activation member mandrel 30b abuts a seat surrounding the entrance to the flow path 216 through the deployable assembly 18. This abutment provides a sealing contact 222. The contact 222 between the closed end surface 212 and the seat of the blade piston 56 restricts fluid flow through the deployable assembly 18.

Although a sealing contact is provided in the present drill bit 210, it is to be understood that in other examples a sealing contact - or even contact - may not be required. Instead, an increased restriction to flow may be sufficient without providing a contact.

As fluid flow through the deployable assembly 18 is restricted the pressure across the deployable assembly 18 increases. That is, the pressure acting on an uphole end of the deployable assembly 18 (to the left in Figure 17) greatly exceeds that on a downhole end of the deployable assembly 18. The force acting on deployable assembly 18 therefore also increases. In this drill bit 210, movement of the activation member 30 to the third position blocks off the flow path 216 shown in Figures 14 to 17. This flow path 216 is one of six flow paths of the same cross-sectional area. Only this one of the six flow paths is blocked off by the activation member 30. The reduction from six flow paths/nozzles to five increases the pressure acting on the deployable assembly 18 by a factor of 1.44. Naturally, the specific increase in pressure is dependent on the flow path arrangement through the deployable assembly 18. Similarly, ratio of 1.44 can also be altered by changing the relevant size of the flow paths 216 through the deployable assembly.

In the present drill bit 210 the force exerted on the deployable assembly 18 exceeds the maximum strength of the shear screw 220 and the screw 220 breaks. Once the screw 220 has broken, the deployable assembly 18 is no longer held in the retracted position. The deployable assembly 18, including the blade piston 56 and the cutter blades 20 are therefore free to move axially within the housing 28. The deployable assembly 18 therefore moves axially from the retracted position towards the deployed position.

The increase in fluid pressure - and hence the increase in force exerted on the deployable assembly - is substantially instantaneous once the activation member 30 has moved to the third position (thus providing the sealing contact 220). As such, the shear screw 220 breaks very shortly after, and practically simultaneously with, movement of the activation member 30 to the third position. The interruption to fluid flow through the deployable assembly 18 (i.e. via the flow path 216 and valve 218) is thus very short in duration. However, this interruption in fluid flow will cause a change in the pressure of fluid flowing through the drill bit 10 - e.g. a pressure spike. This change in pressure can be used as an indicator to a user to inform them that the deployable assembly has been deployed.

Figure 17 shows the drill bit 210 with the deployable assembly 18 in the deployed position. As can be seen, the shear screw 220 has broken and a first part 220a is fixed with respect to the housing 28 and a second part 220b is fixed with respect to the blade piston 56.

A plurality of locking pins 108 are arranged around the circumference of the blade piston 56 and engage the blade piston 56 in a manner similar to that described with respect to Figures 1 to 4B.

Once the deployable assembly 18 has been deployed, the indexer 32 may be left in the third position or cycled back to the first position (e.g. by reducing the flow rate of fluid through the drill bit 210). In the drill bit 10 of Figures 1 to 4B, a change in pressure occurs as the activation member 30 moves into and out of the third position. This is due to the presence of nozzles 116, which are in fluid communication with fluid flowing through the drill bit 10 and provide an additional path by which fluid can exit the drill bit 10 into the bore. These nozzles 116 are exposed to fluid flow when the activation member 30 is in the third position, but not when the activation member 30 is in the first or second positions.

In the drill bit 210 of Figures 14 to 17, there are no nozzles 116. However, when the activation member 30 moves to the third position and momentarily restricts the flow of fluid through the deployable assembly (i.e. by restricting fluid flow through the flow path 216), the pressure of fluid flowing through the drill bit 210 will increase. This pressure spike can indicate to a user that the deployable assembly has been deployed or is being deployed.

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.