Downhole tool and controller for use in a borehole

Abstract

Described is a downhole tool (fig. 2a, fig. 5) comprising a linear position sensing arrangement (fig. 5), the downhole tool comprising a first part (501) and a second part (502), the first (501) and second parts (502) being configured to move axially relative to each other, the linear position sensing arrangement comprising: a detector attached to the first part (501); a source (503) attached to the second part (502); and a processor configured to: receive a signal from the detector in response to the detector detecting the source (503); and in dependence on the received signal, determine the linear displacement of the first part relative to the second part.

Description

[0001] GAD01 -134393PC

[0002] DOWNHOLE TOOL AND CONTROLLER FOR USE IN A BOREHOLE

[0003] FIELD OF THE INVENTION

[0004] This invention relates to a downhole tool for use in a drillstring in a borehole. For example, in a subterranean drilling, milling or completions operation.

[0005] BACKGROUND

[0006] In drilling operations, for example in oil, gas or geothermal drilling, a borehole is drilled through a formation in the earth. A drillstring extends from an upbore location, typically on the surface, to the foot of the borehole and typically comprises components known as the bottom hole assembly which may terminate in a drill bit. The drill bit located at the distal end of a drillstring can be rotated by a downhole motor, allowing the bit to advance through the formation to form the borehole. The distal end is the end remote from the surface.

[0007] A common occurrence during drilling is that changes in the reactive torque at the drill bit or friction between the drillstring and borehole can initiate torsional oscillations, including stick slip. Stick slip occurs when the lower section of the drillstring stops rotating, while the drillstring above continues to rotate. This can cause the drillstring to wind up, after which the stuck element slips and rotates again. The drillstring can act like a long torsional spring and is able to store significant amounts of torsional energy. Torsional oscillations in the drillstring can cause damage to the drillstring, bottom hole assembly and the borehole, and result in poor drilling performance.

[0008] The drilling of deep geothermal wells can in some cases be seen as prohibitively expensive and technically challenging due to the high temperatures, hard rock and extreme depths. Deep geothermal wells are also likely to be some of the most complex wells drilled due to geologic complexity (such as faults, fractures and high friction), directional complexity (for example, intersections, geosteering, long laterals and low well spacing) and well control (for example, losses and high pressure zones). A drillstring anchor can be used to axially stabilize the drillstring and to reduce torsional vibrations, which can help to mitigate these issues and reduce the likelihood of significant and potentially damaging oscillations along the drillstring.

[0009] In drillstring anchors, or other downhole tools, it may be desirable to detect the relative displacement of parts of the tool downhole. Making such measurements can be particularly complex in downhole tools, because in addition to operating in extreme environments, parts may also be rotating relative to each other as well as undergoing linear displacement.

[0010] In some cases, it may also be advantageous to automatically enable and / or disable features of such tools at particular stages of the downhole operation.

[0011] It is desirable to develop approaches for addressing at least some of the above issues.

[0012] SUMMARY

[0013] According to a first aspect, there is provided a downhole tool comprising a linear position sensing arrangement, the downhole tool comprising a first part and a second part, the first and second parts being configured to move axially relative to each other, the linear position sensing arrangement comprising: a detector attached to the first part; a source attached to the second part; and a processor configured to: receive a signal from the detector in response to the detector detecting the source; and in dependence on the received signal, determine the linear displacement of the first part relative to the second part.

[0014] The first part may be received in the second part. The first part may be located inside or within the second part. The second part may surround the first part.

[0015] The first part may be a central shaft of the downhole tool. The second part may comprise a gripper unit of an anchor tool. The central shaft may be configured to move axially relative to the gripper unit and rotate relative to the gripper unit.

[0016] The source may be disposed on an interior surface of the second part. The interior surface may face the exterior surface of the first part. The source may be disposed about the circumference of the interior surface of the first second part.

[0017] The source may be a ring magnet.

[0018] The detector may comprise an array of sensors disposed longitudinally along an exterior surface of the first part.

[0019] Each sensor may comprise a magnetic sensor.

[0020] The first part may be configured to rotate relative to the second part.

[0021] The first part may be driveable to rotate relative to the second part.

[0022] The detector may be configured to detect the source while the first part is rotating relative to the second part.

[0023] The downhole tool may further comprise a rotation sensing arrangement configured to detect relative rotation between the first part and the second part, the rotation sensing arrangement comprising the detector and a second source attached to the second part.

[0024] The second source may be a magnet.

[0025] The received signal from the detector may indicate a measured amplitude of a signal emitted by the source.

[0026] The determined linear displacement may be a relative displacement within a displacement range.

[0027] The detector may comprise multiple sensors in an array. The sensors in the array may be equally spaced. The processor may receive voltage outputs from each of the multiple sensors of the array in response to each sensor detecting the source. The voltage outputs may be voltages measured by each of the sensors in the array in response to each sensor detecting the source. The processor can sum the voltage measurements for the multiple sensors of the array to determine a peak voltage. The peak voltage can be divided by the distance between two adjacent sensors in the array (for example, between the centers of the sensors in mm) to give a value of V / unit position (for example, V / mm).The processor may be configured to determine the linear displacement of the first part relative to the second part in dependence on the sum of the voltage output by each of the sensors in the array and the distance between adjacent sensors of the array.

[0028] The downhole tool may be communicatively connected to a control unit configured to control operation of the downhole tool in dependence on the determined linear displacement of the first part relative to the second part.

[0029] The downhole tool may be an anchor tool comprising one or more grippers operable to grip a wellbore, wherein the control unit is configured to control the actuation of the one or more grippers in dependence on the determined linear displacement of the first part relative to the second part.

[0030] The following aspects of the present invention relate to a controller comprising a control arrangement. The control arrangement is configured to control the downhole tool (for example, anchor). The control arrangement may be a control unit. The control arrangement may be or comprise a processor (generally, one or more processors). The control arrangement may alternatively be implemented by an analogue electrical circuit or mechanical and / or hydraulic arrangement. The control arrangement, for example the one or more processors, may be programmed to execute a control strategy for controlling the apparatus to apply longitudinal force to the distal tool. The downhole apparatus may comprise the control arrangement. The anchor may comprise the control arrangement. The control arrangement may be local to the anchor. The control arrangement may be integral with the anchor. In other implementations, the control arrangement may be remote from the downhole apparatus. For example, the control arrangement may be located at the surface of the wellbore. The control arrangement may be arranged for automatically controlling the downhole tool in the ways described herein.

[0031] According to another aspect, there is provided a controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the controller comprising a control arrangement configured to: monitor a pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole; and when the pressure difference is detected to have increased by at least a predetermined amount, output a control signal to the downhole tool.

[0032] The downhole tool may be a downhole anchor tool. The downhole anchor tool may be configured to grip the borehole during a downhole operation. The control signal output to the downhole anchor tool may cause one or more grippers of the downhole anchor tool to grip the borehole.

[0033] The control signal may cause the downhole anchor tool to initiate a gripping cycle of the downhole anchor tool.

[0034] The downhole anchor tool may comprise one or more sets of grippers. Where the downhole anchor tool comprises two or more sets of grippers, each set of grippers may be spaced longitudinally from the other set(s) of grippers. The controller may be configured to control the operation of the sets of grippers according to a predetermined operation sequence in dependence on the pressure difference.

[0035] The downhole tool may be capable of applying axial thrust to one or more components distal of the downhole tool in the bottom hole assembly, wherein the controller is configured to control the applied axial thrust in dependence on the pressure difference.

[0036] The controller may be configured to monitor the pressure difference in dependence on measurements received from one or more pressure sensors, the one or more pressure sensors being located at the bore of the downhole tool and / or the annulus of the borehole.

[0037] The tool configured to provide rotational drive in a bottom hole assembly may be a drilling motor (which may also be referred to as a mud motor) or a turbine.

[0038] According to another aspect, there is provided a method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the method comprising: monitoring a pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole; and when the pressure difference is detected to have increased by at least a predetermined amount, outputting a control signal to the downhole tool.

[0039] According to a further aspect, there is provided a controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive to a distal tool in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the controller comprising a control arrangement configured to: monitor a rate of rotation of the distal tool; and when the rate of rotation is detected to have increased by at least a predetermined amount, or a predetermined pattern of rotation is detected, output a control signal to the downhole tool.

[0040] According to a further aspect, there is provided a method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive to a distal tool in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the method comprising: monitoring a rate of rotation of the distal tool; and when the rate of rotation is detected to have increased by at least a predetermined amount, or a predetermined pattern of rotation is detected, outputting a control signal to the downhole tool.

[0041] The predetermined pattern may be a sequence of rotational speeds, each speed of the sequence optionally being performed for a respective predetermined time period.

[0042] According to a further aspect, there is provided a controller communicatively connectable to a downhole anchor tool, the anchor tool comprising one or more grippers operable to grip a borehole during a downhole operation and the anchor tool being configured to apply axial thrust to one or more components located distally of the anchor tool in a bottom hole assembly, the controller comprising a control arrangement configured to: periodically receive measurements of a parameter of the anchor tool; and when the measurements of the parameter indicate a change in the parameter of greater than a threshold, a pattern in the measurements of the parameter or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, output a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool. The measurements of the parameter may indicate a change in the parameter of greater than a threshold. The change may be over a predetermined time period.

[0043] The measurements of the parameter may indicate one or more changes in the parameter of greater than one or more respective thresholds. The one or more changes may be over respective one or more predetermined time periods. For example, when the measurements indicate a pattern in the measurements of the parameter, the measurements may indicate changes in the parameter that exceed a sequence of thresholds in a corresponding sequence of time periods.

[0044] The parameter may be a difference between an axial thrust applied to the one or more components located distally of the anchor tool in the bottom hole assembly and a measured axial force experienced by the one or more components located distally of the anchor tool in the bottom hole assembly.

[0045] The parameter may be a difference between a measured linear position of one or more grippers relative to a body of the anchor tool and an expected linear position of the one or more grippers relative to the body of the anchor tool.

[0046] The downhole tool may comprise a chamber configured to contain pressurised fluid for providing axial thrust to the one or more components located distally of the anchor tool, and wherein the controller is configured to: periodically receive measurements of pressure in the chamber; and output the control signal when the pressure measurements indicate an increase in pressure of greater than a threshold.

[0047] The downhole tool may comprise a chamber configured to contain pressurised fluid for providing axial thrust to the one or more components located distally of the anchor tool. The parameter may be a difference between an actual pressure and an expected pressure in the chamber.

[0048] The chamber may be connected to a drillstring proximal of the downhole anchor tool, the size of the chamber being variable in response to axial movement of the drillstring.

[0049] According to a further aspect, there is provided a method of controlling a downhole anchor tool, the anchor tool comprising one or more grippers operable to grip a borehole during a downhole operation and the anchor tool being configured to apply axial thrust to one or more components located distally of the anchor tool in a bottom hole assembly, the method comprising: periodically receiving measurements of a parameter of the anchor tool; and when the measurements of the parameter indicate a change in the parameter of greater than a threshold, a pattern in the measurements of the parameter or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, outputting a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool.

[0050] According to a further aspect, there is provided a controller for an anchor tool, the anchor tool comprising two chambers for controlling the amount of axial thrust applied by the anchor tool to one or more components distal of the anchor tool in a drillstring, the controller being configured to maintain the pressure in the two chambers to create a desired axial thrust.

[0051] According to a further aspect, there is provided a controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool optionally being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the controller comprising a control arrangement arranged to control the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly by controlling a pressure difference within the downhole tool.

[0052] The controller may be configured to control the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly by controlling a pressure difference within the downhole tool in dependence on a measured feedback parameter.

[0053] The controller may be configured to control the downhole tool to apply an approximately constant axial thrust to the one or more components by holding the pressure difference within the downhole tool to be approximately constant.

[0054] The controller may be configured to control the downhole tool to apply axial thrust such that an approximately constant weight is applied to the one or more components by controlling the pressure difference within the downhole tool in dependence on feedback from one or more weight sensors located at the one or more components. The controller may be configured to control the downhole tool to apply axial thrust to cause an approximately constant rate of penetration of the bottom hole assembly by adjusting the axial thrust in further dependence on feedback from a linear position sensor of the downhole tool.

[0055] The controller may be configured to control the downhole tool to apply axial thrust such that an approximately constant torque is maintained by the rotational drive.

[0056] The controller may be configured to control the downhole tool to apply axial thrust such that a second pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole is maintained to be approximately constant.

[0057] The controller may be configured to control the downhole tool to apply axial thrust in dependence on measurements received from one or more pressure sensors. The one or more pressure sensors may be located within the downhole tool. The one or more pressure sensors may be located at the bore of the downhole tool and / or the annulus of the borehole.

[0058] The controller may be configured to control the downhole tool to apply axial thrust to cause an approximately constant rate of rotation of a tool distal of the rotational drive.

[0059] The controller according to this aspect may be implemented in combination with the is the controller described in any of the other aspects described herein.

[0060] According to a further aspect, there is provided a method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the method comprising controlling the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly in dependence on a pressure difference within the downhole tool.

[0061] According to another aspect, there is provided a downhole system comprising multiple anchor tools, each anchor tool comprising one or more grippers and a central shaft rotationally fast with a dri Istring, each anchor tool being configurable between a first state in which the central shaft can rotate relative to the gripper(s) and a second state in which the central shaft cannot rotate relative to the gripper(s), wherein in the second state, the respective anchor tool can react torque from the drillstring to the borehole via the gripper(s). A respective anchor tool may transition from the first state to the second state in response to a control signal received from a controller.

[0062] According to another aspect, there is provided a downhole tool comprising the controller described above.

[0063] According to another aspect, there is provided a controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool comprising one or more axial thrusting mechanisms configured to provide axial thrust to one or more components distal of the downhole tool in a drillstring, wherein the controller comprises a control arrangement configured to: vary the axial thrust applied to the one or more components distal of the downhole tool in the drillstring; monitor one or more parameters of the downhole operation; and in dependence on the one or more parameters of the downhole operation, select the axial thrust to be subsequently applied to the one or more components distal of the downhole tool in the drillstring.

[0064] According to another aspect, there is provided a method for performing a downhole operation using a downhole tool in a borehole, the downhole tool comprising one or more axial thrusting mechanisms configured to provide axial thrust to one or more components distal of the downhole tool in a drillstring, the method comprising: varying the axial thrust applied to the one or more components distal of the downhole tool in the drillstring; monitoring one or more parameters of the downhole operation; and in dependence on the one or more parameters of the downhole operation, selecting the axial thrust to be subsequently applied to the one or more components distal of the downhole tool in the drillstring.

[0065] The one or more components distal of the downhole tool may comprise a drill bit. The one or more axial thrusting mechanisms may be configured to provide weight on bit to the drill bit. The one or more parameters may comprise one or more of rate of penetration of the drill bit, rotational speed of the drill bit (RPM), specific mechanical energy and vibration of the drill bit. The selected axial thrust may be the axial thrust to achieve the most desirable drilling conditions, for example the optimal rate of penetration, minimum rotational speed variation (stick / slip) or minimum vibration. The varying of the axial thrust and / or the monitoring of the one or more parameters may be performed periodically, for example at predetermined intervals.

[0066] The downhole tool and / or the bottom hole assembly may comprise one or more downhole sensors configured to measure or infer one or more of pressure, downhole weight on the distal tool and downhole torque on the distal tool.

[0067] The anchor may be configured to apply longitudinal force to the distal tool via the drillstring (e.g. via one or more components of the drillstring distal of the anchor and / or proximal of the distal tool).

[0068] The anchor may comprise an internal channel for conveying the flow of drilling fluid to the distal tool, wherein the processor is configured to maintain a differential pressure between the channel and the annulus of the borehole within a predetermined range.

[0069] The gripper(s) may be for engaging the borehole to restrict relative axial and / or rotational movement between the gripping element and the borehole.

[0070] The anchor may be coupled with a tool for performing a downhole operation at the distal end of the bottom hole assembly. The anchor may be configured to apply weight to the tool to urge the tool into the borehole or against the bottom of the borehole. The drillstring or the bottom hole assembly may terminate in a distal tool such as, for example, a conventional drill bit, a plasma drilling head or other drilling mechanism.

[0071] The apparatus may be communicatively connectable with a downhole control unit. In other implementations, the control unit may be at the surface and may be connected to the downhole apparatus using a wired connection, such as electrified wireline (E-line). The control unit may comprise the processor. The control unit may be configured to adjust the configuration of the anchor and / or one or more other elements coupled to the anchor (for example, coupled directly or indirectly at the distal end of the anchor) in response to one or more signals. The one or more other elements may be communicatively connectable to the anchor. This may allow signals to be passed through the anchor and / or for signals to be transferred between the anchor and components of a bottom hole assembly than the anchor. The apparatus may comprise the control unit. The control may comprise a processor and one or more memories. The memory may store in a non-transient way code that is executable by the processor to implement the methods described herein. Adjusting the configuration of the anchor may comprise adjusting the configuration of the gripper and / or adjusting the configuration of one or more other parts of the anchor, such as one or more pistons for applying an axial force to the drillstring or one or more of the other elements coupled with the anchor, such as a drill bit.

[0072] The apparatus may further comprise or be communicatively connectable with one or more measurement devices for determining one or more downhole parameters. For example, torque, axial force, bending force, pressure and temperature.

[0073] The anchor may be configured to react axial loads to the borehole when the gripping element is gripping the borehole. The anchor may be configured to react torsional loads to the borehole when the gripping element is gripping the borehole. The gripping element may be configured to grip the borehole to restrict both relative rotation and relative axial movement between the anchor and the borehole. The anchor may be configured to react both axial loads and torsional loads to the borehole when the gripping element is gripping the borehole.

[0074] The anchor may be configured to apply longitudinal force to one or more distal downhole components coupled to the anchor. The anchor may be part of a bottom hole assembly, wherein the anchor is configured to urge the bottom hole assembly into the borehole.

[0075] The anchor may comprise multiple gripping elements each configured to move axially relative to a body of the anchor. The multiple gripping elements may be disposed on the same body, or across multiple body parts that are axially separated along the longitudinal axis of the apparatus. The multiple body parts may each act as separate anchor tools that are independently controlled. The anchor may comprise a drive mechanism for advancing one gripping element downhole and / or uphole relative to at least one other gripping element. Where the anchor comprises multiple body parts, each body part having multiple gripping elements each configured to move axially relatively to its respective body part, each body part may have a respective drive mechanism for advancing one gripping element downhole and / or uphole relative to at least one other gripping element.

[0076] The or each gripping element may have an associated actuator. The actuator may be capable of being driven to cause the respective gripping element to adopt at least one of (a) a first state in which it is urged outwardly for gripping the borehole and (b) a second, passive state. In some cases, one actuator may be used to drive multiple grippers, or each gripper may have its own actuator.

[0077] The operation of the or each gripping element may be powered by one or more of the following: the flow of drilling fluid through the anchor; an energy store (such as a battery or other energy source or a reservoir of hydraulic fluid), a thermal gradient between the interior of the anchor and the annulus of the borehole; via an electric conduit connectable with the connector (where electrical power is supplied from the surface); by differential rotation between the anchor and the drillstring or the output of a mud motor.

[0078] The apparatus may be part of a downhole assembly comprising one or more additional downhole tools. The one or more additional downhole tools may comprise one or more of the following: a measurement-while-drilling tool, a logging-while-drilling tool, a fluid conditioning module to regulate hydraulic fluid and / or filter drilling fluid, an orienter tool, a fixed or variable bent sub, a rotary steerable system, a downhole motor (such as a steerable mud motor) for providing rotational drive and / or torque to a drilling or milling tool at a distal end of the drillstring. The drillstring may comprise one or more drilling tools. The drilling tool at the distal end of the drillstring may comprise a conventional rock bit, a PDC bit, a hybrid bit or a plasma bit.

[0079] The apparatus may comprise one or more channels for receiving drilling fluid from the drillstring and conveying the drilling fluid towards the distal end of the drillstring.

[0080] The borehole may be a wellbore. The wellbore may be formed to aid the exploration and / or recovery of natural resources such as oil, gas or water. The borehole may be another type of borehole. The borehole may comprise one or more non-vertical sections.

[0081] The apparatus, e.g. the downhole tool, anchor, orienter and / or controller, may constitute one or more subsystems.

[0082] BRIEF DESCRIPTION OF THE FIGURES

[0083] The present invention will now be described by way of example with reference to the accompanying drawings. In the drawings: FIG. 1 schematically illustrates an example of a drilling system, illustrated at a subterranean location in a borehole during a downhole operation;

[0084] FIG. 2a schematically illustrates an example of an anchor comprising multiple gripping segments;

[0085] FIG. 2b schematically illustrates an example of an anchor tool having chambers for the application of a longitudinal force by the anchor to a distal tool;

[0086] FIG. 2c schematically illustrates an example of the application of a longitudinal force by the anchor to a distal tool;

[0087] FIG. 3a schematically illustrates an example of a gripper made from a hard material;

[0088] FIG. 3b schematically illustrates an example of a gripper made from a hard material;

[0089] FIG. 3c schematically illustrates an example of a gripper made from a hard material;

[0090] FIG. 4 schematically illustrates an example of a control unit;

[0091] FIG. 5 schematically illustrates a downhole tool comprising a linear and rotational position sensing arrangement;

[0092] FIG. 6a shows an exemplary plot of voltage vs. position for multiple sensors in an array;

[0093] FIG. 6b shows an exemplary plot of voltage vs. position for multiple sensors in an array for an alternative implementation;

[0094] FIG. 7 shows the steps of an exemplary method for controlling a downhole tool for use in a downhole operation in a borehole.

[0095] FIG. 8 shows the steps of an exemplary method for controlling a downhole anchor tool;

[0096] FIG. 9 shows the steps of an exemplary control flow for a downhole anchor tool.

[0097] DETAILED DESCRIPTION

[0098] FIG. 1 schematically illustrates an example of a drilling system illustrated at a subterranean location in a borehole (not to scale). In FIG. 1 , although for illustrative purposes the borehole illustrated is vertical, the borehole may have a more complicated two or three dimensional path and may also include multiple branches.

[0099] In operation, a rig 101 provides support and / or power to a drillstring. The drillstring may comprise, for example, conventional drill pipe or coiled tubing. The drillstring comprises multiple components and terminates in a distal tool 108. The borehole is shown at 104. The borehole may be at least partially lined with casing 105 and cement 106. The portion of the drillstring shown at 102 may provide torque and / or power (for example, rotary, thermal, and / or electrical power) to the bottom hole assembly (BHA), shown generally at 107. The BHA is part of the drillstring and may comprise a tool or other component 108. The tool 108 may be a drilling tool. The tool 108 may be, for example, a drill bit. For example, tool 108 in FIG. 1 may be a conventional drill bit such as a polycrystalline diamond compact (PDC) drill bit, a roller cone drill bit or a hybrid bit (a combination of PDC and roller cone). Drilling fluid can be pumped to the component through the drillstring and released into the annulus of the borehole, as shown at 109. The drilling fluid 109 acts to convey cuttings to the surface. The drilling fluid may be referred to as drilling mud.

[0100] The BHA 107 can also comprise one or more additional components. The components described below are exemplary and the BHA may alternatively or additionally comprise other components. The described components need not be immediately adjacent to one another and may be separated by further components.

[0101] The component 110 is a downhole motor, such as a mud motor, for providing rotational drive to the tool 108. The motor may be a positive-displacement mud (PDM) motor. Alternatively, an electric motor or other type of motor may be used. The motor may be a steerable motor. The motor may be a bent motor, which may allow for improved directional control when performing directional drilling.

[0102] The component shown at 111 is a measurement-while-drilling (MWD) tool. The MWD tool provides borehole direction and formation evaluation data. The MWD tool may utilize conventional telemetry techniques (such as mud pulse telemetry) with standalone battery powered tools. The MWD tool may be integrated with the cable(s) in the coiled tubing for higher density data and more reliable decoding in deep applications with challenging mud properties. The data collected by the MWD tool may include shock, vibration, pressure, weight and torque data. The data may be used for closed loop control and optimization of the drilling process.

[0103] The MWD tool 111 may comprise a means of transmitting information to the surface. This may be performed by, for example, mud pulses, whereby the operation of a valve in the fluid flow-path in the drillstring, or by allowing fluid to egress the interior of the drillstring to the annulus, induces pressure variations which may be detected using pressure and / or flow measurements at the surface. Alternatively, this may be performed by electro-magnetic means, where a voltage across an insulated section of drillstring is varied, and these variations detected using a potential difference detector at surface using surface electrodes (not shown), or by employing electrical signals through wired pipe (if present). Both electromagnetic and wired coiled tubing telemetry allow for bi-directional communication, and hence may receive signals transmitted from the surface. As well as communication means, the MWD system may comprise magnetometers and accelerometers, used to measure the earth’s magnetic and gravitational fields, and from which are derived the position of the instrument in the subsurface and hence the trajectory of the borehole. Additionally, there may be other measurement instruments, such as strain-gauges, accelerometers, pressure sensors and gyroscopes to measure the mechanical stresses imposed on, and the motion of, the MWD module.

[0104] In some implementations, a logging while drilling (LWD) tool may alternatively or additionally be used.

[0105] The component shown at 112 is a steering device. The steering device may be an orienter tool. The orienter may be a high torque orienter. The orienter can electrically or hydraulically orient the motor to direct the borehole. This can help to minimize tortuosity by allowing steerable motor to be rotated to drill straight ahead. This can also allow for closed loop trajectory control due to high-speed well directional data and control of the orienter via the E-line. The orienter might not be used in a BHA that comprises a rotary steerable system (RSS). In this case, the RSS may be used to steer the motor to direct the borehole.

[0106] In general, the steering device 112 can utilize some combination of force applied to the borehole, or curvature of the drillstring in order to control the direction of the drill bit. The steering device may be communicatively coupled to the surface. This may allow the steering device to receive commands transmitted from the surface, for example via the E-line, which may allow the drill bit to be urged to follow a desired trajectory.

[0107] The component shown at 113 is an anchor tool, which will be described in more detail below. In some implementations, the anchor 113 may be connected to the part of the drillstring 102 via a coupling 114, such as a swivel. The coupling 114 may couple the anchor 113 to a connector 115 which allows the portion of the drillstring 102 above the anchor to be connected to the proximal (i.e. upbore) end of the connector 114. The coupling may be a flexible coupling. The flexible coupling may allow relative movement of the connector for connection to the drillstring and the anchor about and / or along one or more axes. For example, the coupling may be rotatable and / or axially compliant, as will be described in more detail later.

[0108] The anchor may comprise a channel for receiving a shaft. The anchor may comprise the shaft. The shaft may pass through the channel in the interior of the anchor. The shaft can move longitudinally within the anchor. The shaft can rotate relative to the channel. The shaft may move independently of the gripper(s). The shaft may be axially fast with components of the drillstring or BHA below the anchor. That is, the shaft may move with the components of the drillstring below the anchor. When the gripper(s) is / are gripping the wellbore, the shaft may be configured to move relative to the gripper(s). For example, when the gripper(s) is / are gripping the wellbore, the shaft may be rotatable relative to the channel of the anchor through which the shaft passes. This can allow the BHA / bit to be rotated while the grippers are axially and rotatable locked to the borehole. Torsional anchoring may be achieved using keys or protrusions on the exterior of the shaft and keyways in a surface of the anchor facing the shaft (e.g. in the channel) that engage the keys and prevent relative rotation between the shaft and the wellbore when the one or more grippers are activated to grip the wellbore. The gripper(s) may grip the wellbore fully or partially. When the gripper(s) grip the wellbore, relative axial and / or rotational movement between the gripping element and the borehole may be partially or fully restricted.

[0109] The drilling fluid may be supplied to the tool (and more distal components such as the drill bit) from a tank 120 at the surface of the borehole which is fed to the BHA via pipes 121. The tank may be coupled to a chiller 125. The chiller may cool the drilling fluid. The chiller may keep the drilling fluid at a temperature that is below a predetermined threshold. This may allow for a reduction in bottom hole temperature, making deeper and hotter drilling possible.

[0110] The anchor 113 can transfer axial forces and / or reactive torque from the BHA to the borehole. This may help to prevent the initiation of torsional oscillations in the drillstring, including stick slip. The anchor is designed to remove at least some, and preferably all, of the torque from the drillstring when reactive torque is transferred to the borehole. In the system described above with reference to FIG. 1 , the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit below the anchor. However, the anchor described herein may be utilized in non-rotary drilling situations such as jetting or plasma drilling (a contactless drilling technique that uses high- voltage pulses to fracture the rock) or any other compatible operation or situation in a borehole, such as a milling, completion or plug and abandonment operation. Other additional components of the BHA may be drill collars, stabilizers, reamers, hole-openers and bit subs.

[0111] The rig 101 , provides support for the drillstring. Drilling fluid is circulated through the drillstring via pipes and hoses 121 , from mud tanks 120 by fluid pumps (not shown). The fluid returns to the mud tanks via a further flow channel and shale shakers (not shown). One or more surface computational platforms 123 may perform functions such as controlling the operation of the auto-driller, top-drive and mud-pumps, or they may contain embedded controllers. The surface computational platform 123 can communicate with off-site computers or individuals, using an antenna or cable 124, which may enable effective control to be conducted remotely from the well site. One or more of the components located at the surface of the borehole are part of a surface system of the drilling system.

[0112] In some implementations, the drilling rig may be instrumented, so that parameters related to the drilling operation may be determined at the surface. For example, one or more of the tension applied by the portion of the drillstring 102 to the drilling line (hook-load), the vertical motion of the top of the string (the surface rate-of-penetration), the torque applied to and the rotation speed of the string, and the flow rate and pressure of the drilling fluid at surface. This list is not exhaustive, and other parameters may be monitored.

[0113] The exemplary BHA shown in FIG. 1 comprises a source of electrical power, which may for example be a fluid-driven turbine, the rotation of which generates an electrical current (or any other suitable source for converting mechanical motion into electrical current). Alternative sources of electrical power include batteries or capacitors, or an interface to the E-line, allowing power to be transmitted from the surface. As the turbine rotation speed depends on the flow rate of drilling fluid flowing through the BHA, by measuring the rotation speed, the turbine may also have a subsidiary role in detecting flow rate changes made at surface using the mud-pump controller and mud-pump through which information may be transmitted from the surface to the BHA. In this implementation, the drill bit is driven to rotate by a downhole mud motor to form the borehole in the formation. Where the BHA comprises a motor for rotating the bit, the anchor is configured to be mounted above the motor. The motor may be a mud motor. Alternatively, the drill bit may be driven by other downhole rotary drive devices such as electric motors, pneumatic motors or a drilling turbine. For some types of drill bits, such as bits for plasma drilling, a motor for rotating the bit may not be required.

[0114] The BHA may also comprise a fluid conditioning module to regulate hydraulic pressure and / or to filter the drilling fluid.

[0115] FIG. 2 shows an example of an anchor 113. In this example, the anchor 113 comprises multiple segments 201 , 202 each comprising one or more grippers 203. For example, each segment 201 , 202 may comprise multiple grippers. The segments 201 , 202 can be moved longitudinally relative to each other using a walking mechanism.

[0116] The use of multiple electrically coordinated (for example via a control unit 400 of the anchor) gripping segments, optionally utilizing MWD / LWD and RSS technology, may allow for a coordinated downhole operation. The control unit 400 may also allow for downlinking in non-wired I conventional drilling applications and communication with other BHA tools.

[0117] As shown in FIG. 2, the anchor 113 comprises a first gripping segment 201 and a second gripping segment 202. In this example, the gripping segment 201 comprises an upper gripper set and the gripping segment 202 comprises a lower gripper set (‘upper’ and ‘lower’ being relative to the end of the borehole).

[0118] Connector 204 is an upper connector for connection to drill pipe or an upper part of the BHA. Connector 205 is a lower connector for connection to a downhole mud motor or a lower part of the BHA. The connectors may both comprise adapters to industry standard connectors used to connect the anchor to the adjacent sections of the drillstring.

[0119] In this example, the anchor comprises a wired flex portion 206 between the two gripping segments 201 , 202. This may allow the lower gripping segment 202 to electrically communicate with the control unit 400 and / or the upper gripping segment 201. This can allow control signals and / or power to be supplied to the lower gripping segment from the control unit 400.

[0120] Each gripping segment 201 , 202 comprises a gripper housing 207, 208. The gripper housings house the grippers 203. The gripper housings 207, 208 can move longitudinally relative to the main body of the tool along sections 209, 210 respectively. The range of longitudinal movement along the sections 209, 210 may be referred to as the ‘tool stroke’ (as indicated in FIG. 2). This can allow the gripper housing of one gripping segment to move longitudinally relative to the housing of the other segment when the other segment is gripping the wellbore. This can allow drilling to progress whilst anchoring is active.

[0121] The handover from one gripping segment to the other may be determined based on the position of the other gripping segment relative to one or more other parts of the tool, or after a predetermined time since the segment currently gripping was actuated. Alternatively, the segment currently gripping the borehole may release automatically when the other segment is actuated to grip the borehole, or once the other segment is determined to be gripping the borehole, for example when a target gripping force of pressure of a hydraulic actuator is reached. For example, the gripper of a free (i.e. not currently gripping) segment may be triggered to grip the borehole when the currently gripping segment is 20mm from the end of its longitudinal range of travel relative to the housing of the anchor. The currently gripping segment could then be released after another 10mm of drilling (measured by the relative longitudinal movement of the shaft and the channel in which the shaft moves inside the anchor). An alternative implementation is to release the gripper of the currently gripping segment a fixed time after the free segment gripper activation is started.

[0122] In another implementation, the gripper of the free segment may be actuated to grip the borehole when the currently gripping segment is at a predetermined distance from the end of its longitudinal range of travel relative to the housing. The gripper of the currently gripping segment may then be released from the borehole when the gripper of the other segment has reached a target force against the borehole or a target pressure in the case of a hydraulically actuated gripper such as a piston.

[0123] In some implementations, the anchor may be actively controlled from a power source to push the drillstring, or push a shaft extending through the anchor and coupled to the drillstring, in a downhole direction and apply weight-on-bit to a drill bit, or apply weight to another downhole tool, at the distal end of the drillstring. The anchor may also be configured to apply axial force to the BHA below the anchor to urge the BHA into the borehole (i.e. in the downhole direction). Axial forces may also be applied to the drillstring in a similar way by controlling the anchor to pull the shaft in an uphole direction.

[0124] In one implementation, one or more of the gripping segments may comprise an axial piston moveable within a cylinder. The piston may be connected to the gripper housing and the cylinder may be connected to the shaft running through the anchor (or vice versa). The anchor comprises the shaft. The shaft is axially / longitudinally fast with the distal tool (that is, longitudinal movement of the shaft results in longitudinal movement of the distal tool). Longitudinal force may be applied to the distal tool by applying longitudinal force to the shaft of the anchor. The enclosed volume between the piston and the cylinder may be connected to an actuator or valve controlling the flow of pressurized fluid (such as oil or drilling fluid) into the volume to cause axial movement of the gripper in response to movement of the shaft and to provide longitudinal force transfer to the drillstring / BHA. This piston may be single acting with a mechanical return (such as a spring) or double acting to allow axial force to be applied to the drillstring in both the uphole and downhole directions. The pressurization of the fluid may be controlled based on the internal pressure of drilling fluid flowing through the anchor, may be regulated to remain substantially constant, or may be modulated based on other factors. This may allow longitudinal force to be applied to the drillstring at the anchor, which may be used to provide weight-on-bit (WOB) to a drill bit, or weight on another distal tool, at the distal end of the drillstring.

[0125] In other implementations, the anchor 113 may comprise a single gripping segment that is activated to grip and release the borehole without the walking mechanism or alternatively may comprise individual gripping and push / pull modules that can be connected (for example electrically, mechanically or hydraulically) such that they work in coordination to allow movement and force to be transferred to the drillstring.

[0126] The anchor can advantageously allow the ability to rotate the drillstring during axial anchoring and for the drillsring to move axially relative to the anchor during torsional anchoring.

[0127] The apparatus can comprise one or more channels for receiving fluid from the surface via the drillstring and conveying the fluid towards the distal end of the drillstring. As mentioned above, fluid, such as drilling fluid / mud, may be supplied to the bottom of the borehole from tanks at the surface.

[0128] In some implementations, the flow of drilling fluid through the anchor may be used to provide the longitudinal force applied to the distal tool. This may also be used to apply a longitudinal force in the uphole direction. The pressure difference between the drilling fluid being pumped down the inside the anchor (for example, through a central channel in the anchor) and the drilling fluid returning to surface in the annular space around the outside of the anchor can be used to perform work. This pressure difference can typically be many 100s of psi. In a simple implementation, the higher-pressure drilling fluid from the inside of the tool can be directed (via valves or other means) to one side of an axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the other side of an axial piston. The resulting imbalance in fluid force either side of the piston will result in movement of the piston. This axial piston, if acting between the gripping segment and the shaft running through the anchor, will result in movement of the gripping segment relative to the shaft running through the anchor. If the gripping segment is engaged with the borehole then this process can also result in longitudinal force being applied to the distal tool.

[0129] The anchor may comprise an axial piston, or multiple axial pistons. The or each axial piston may be connected to the gripping segment(s) and / or the drillstring via the shaft of the anchor.

[0130] This is schematically illustrated in FIG.s 2b and 2c for an anchor 250. FIG. 2b shows the configuration of the anchor when a longitudinal force is not applied to urge the drill bit 108 against the bottom (i.e. the distal end) of the borehole and FIG. 2c shows the configuration of the anchor when a longitudinal force is applied to urge the drill bit 108 against the bottom of the borehole.

[0131] As described above, the anchor comprises one or more gripping segments, each comprising one or more grippers. One gripper is indicated at 251 . An axial piston is shown at 252. There is a chamber 253, 254 on either side of the axial piston 252. The chambers 253, 254 can be in fluid communication with the fluid passing through the anchor (for example, through the shaft 255, which can move with the drillstring) or the fluid in the annulus of the borehole. The supply of fluid to the chambers 253, 254 can be controlled by valves or some other means. In FIG.s 2b and 2c, the gripper 251 is engaged with the borehole wall. In FIG. 2b, the higher-pressure drilling fluid from the channel inside of the anchor is directed (via valves or other means) to the chamber 254 on the lower side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber 253 on the upper side (with respect to the bottom of the borehole) of the axial piston.

[0132] In FIG. 2c, the higher-pressure drilling fluid from the inside of the anchor is directed (via valves or other means) to the chamber 253 on the upper side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber 254 on the lower side (with respect to the bottom of the borehole) of the axial piston. The resulting imbalance in fluid force either side of the piston will result in movement of the piston in the downhole direction. This can be used to apply a longitudinal force to the downhole tool via the drillstring, for example through the shaft 255 passing through the anchor.

[0133] This approach may be used for any of the embodiments described herein.

[0134] As mentioned above, the anchor comprises one or more gripping elements (referred to herein as grippers 203) that can be activated by one or more actuators. The actuator can be driven to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the walls of the borehole and a second, passive state. When activated, the gripper can grip the borehole. The gripper is configured to exert an outward force on the borehole relative to the longitudinal axis of the anchor. When the gripper is activated, relative rotation between the gripper of the anchor and the borehole can be resisted and this can allow torque to be reacted to the borehole.

[0135] Throughout this description, the term ‘activated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is urged outwardly relative to the central axis of the drillstring. In this state the gripper can grip the borehole. The term ‘deactivated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is exerting a reduced gripping force relative to the activated state. For example, it may be in a state where it is not gripping the borehole. In this state it might not be urged outwardly relative to the central axis. In the activated state the gripper may be in a location radially outwardly of its location in the deactivated state. The gripper may be biased to one of the states, e.g. by a spring.

[0136] An energy store can provide the energy supply to one or more actuators for actuating one or more of the grippers. The energy store may be a source of energy generated locally at the anchor. The energy store may be charged or refilled at the surface before running in hole. The energy store may be replenished (e.g. recharged) during or after a trip to the surface. The energy store may be self-contained in the anchor. The energy store is preferably a source of energy stored locally at the anchor. The energy store is preferably suitable for permitting the anchor to operate over an extended period of time without requiring replenishment from the surface of the borehole whilst the anchor is in hole. The energy store may be a source of electricity such as a battery or fuel cell. In other implementations, the anchor may be powered by an alternative energy source, such as a direct supply of power from the surface (for example, via the electrical conduit), via a mud- driven turbine or other mechanisms utilizing the flow of drilling fluid.

[0137] When the anchor is activated (i.e. when the actuator is driven to cause the gripper to grip the borehole), the drillstring may be translatable along its longitudinal axis with respect to the anchor. The anchor is configured to allow relative axial movement of the anchor and the drillstring. This may also be the case when the anchor is deactivated (i.e. when the actuator is driven or released to cause the gripper to not grip the borehole). When the anchor is activated, relative rotation between the gripper and the borehole can be resisted or restricted. This may be due to physical engagement between the gripper of the anchor and the interior face of the borehole.

[0138] Additional gripping modules or separate anchor tools may be used to increase torque and axial capacity. The ability to use multiple gripping modules can allow for a less stiff system, which may be advantageous for higher curvature wellbores.

[0139] As noted above, the gripper is configured to be actuated to move between a passive (i.e. deactivated) state and an outwardly-urged (i.e. activated) state. In the passive state, the gripper may be radially retracted relative to the activated state. However, in some implementations there may not be a significant difference in the radial displacement of the gripper in the passive (deactivated state) and the activated state. In the activated state the gripper is configured to restrict relative rotation between the anchor (e.g. the gripper(s) of the anchor) and the borehole. In both the activated and deactivated states the device is configured to allow axial movement of the drillstring relative to the device. In the deactivated state, the anchor can rotate relative to the borehole. In both the activated and deactivated states, relative rotation between the anchor and the downhole section of the drillstring is preferably restricted. In both the activated and deactivated states, the downhole section of the drillstring can move axially relative to the anchor in the downhole direction (i.e. in the direction of the bottom of the borehole, or the furthest reach of the borehole, in the case of a horizontal well) and / or the opposite direction (in the direction of the surface). The gripper can be in the deactivated state when drilling fluid is pumped through the drillstring. Alternatively, the gripper may be activated using mud pressure.

[0140] The anchor may grip the borehole by actuating one or more elements such as pistons or pads to exert an outward radial force on the borehole. A pad or piston may comprise teeth that provide resistance and allow the pad to grip the borehole. Various tooth designs may be used. The gripper may have a non-flat portion. For example, the surface of the gripper may have undulations and / or protuberances. The surface of the gripper may comprise ribs, ridges and / or studs.

[0141] The gripper of the anchor may comprise at least one pad or piston configured to extend in a circumferential or radial direction to engage the borehole. The at least one pad or piston may be configured to move outwardly from the anchor to engage the borehole when the actuator of the respective gripper is driven to cause the gripper to grip the borehole (i.e. when the anchor is activated).

[0142] In one implementation, the anchor comprises pistons which are capable of being urged outwardly for gripping the borehole from a passive state to an activated state. The pistons can move relative to the body of the anchor in a direction perpendicular to the longitudinal axis of the anchor between the passive state and the gripping state in which the piston is urged outwardly to cause a gripper area at the end of the piston to grip the borehole. In other words, the grippers can move in a radial direction relative to the longitudinal axis of the anchor.

[0143] The gripper assembly may comprise a housing that sits in the recess in the body of the gripping segment. The piston is accommodated in the housing and can move outward relative to the housing. The piston can move in the radial direction with respect to the longitudinal axis of the anchor. The piston may have a limit of travel within the housing.

[0144] In one example, the movement of the piston may be supported in the recess in the housing by bearings distributed around the circumference of the recess or channel. There may be multiple sets of bearings distributed along the length of the piston. There may be a grease or oil feed to the bearing area to allow for lubrication of the bearing and / or the contact surface between the housing and the piston. There may alternatively or additionally be one or more seals disposed around at least part of the piston.

[0145] For return to the passive state, the gripper assembly may comprise a return spring. Alternatively, the piston may be double acting, or the absence of hydraulic power applied to achieve the outwardly-urged state may be sufficient to achieve the passive state.

[0146] In one example, shown in FIG.s 3a-3c, the piston is a cylindrical piston. In other implementations, the piston may have other forms. For example, the piston may be a spherical piston or a blade piston. In this example, the end of the piston has an insert which engages the borehole to grip the rock. In other examples, the end of the piston may engage the borehole directly with no additional insert. The gripper can therefore be a removeable and / or replaceable component or can be integral with the piston. Herein, the "gripper" is the part of the gripper assembly that grips the borehole. In FIG.s 3a-3c, the piston has an insert at the end of the piston for gripping the borehole. However, in other implementations, the tip of the piston may be compositionally undifferentiated from the body of the piston and might not have any particular surface formations or surface roughness.

[0147] The pistons may be controllable to move out from the body of the anchor in the radial direction by different amounts depending on the rock condition and mechanical properties. The pistons may advantageously dig through the filter cake (the solids in the drilling mud that line the borehole) to reach the wall of the borehole. The pistons may be capable of deforming elastically when they are urged outwardly to contact the borehole. Forces resulting from elastic deformation of the pistons may be used in addition to friction with the rock to generate a greater gripping force on the borehole.

[0148] In the example shown in FIG.s 3a-3c, the gripper 203 is a cylindrical piston with a circularcross section. The base of the piston has a flange 305 for limiting the travel of the piston within the housing, as described above. The opposite end 312 of the piston to the base has a chamfered profile. In this example, the end of the piston has an insert 311 which engages the borehole to grip the formation. As shown in FIG. 3c, the piston may be hollow to optionally accommodate a spring and defines a chamber for hydraulic fluid. In this example, the gripper comprises a hardened insert (made from, for example, Tungsten Carbide or Diamond) at the end of the piston. The insert is located at the contact face (i.e. the face of the piston that contacts the borehole when the piston is in the extended position). As mentioned above, the insert may have protrusions or teeth which are able to repeatedly cut through lubricant, rock dust and / or residue and engage with the rock surface of the borehole. In this example, the teeth have a pyramidal profile. However, other profiles may be used.

[0149] The anchor may allow for a continuous gripping action as the drillstring advances downhole in the borehole. Generally, a first segment (or first set of segments) or a part thereof can move longitudinally relative to a second segment (or second set of segments) or a part thereof. The first and second segments (or sets of segments) are coupled to each other such that the first segment (or set of segments) or part thereof is free to move along the longitudinal axis of the anchor relative to the second segment (or set of segments) or part thereof. The anchor comprises a drive mechanism for advancing the first segment (or set of segments) or part thereof downhole relative to at least the second segment (or set of segments) or part thereof. In some examples, there may be multiple anchors in the string having synchronized or asynchronous gripping assemblies.

[0150] In order for the anchor to have a continuous gripping action, there is a time when both segments (or set of segments) are activated to grip the borehole and the drillstring can continue to move longitudinally relative to the segments during the transition between the activation of one segment (or set of segments) and the deactivation of another. The transition includes the coordinated gripping and release of segments and may use a drive mechanism that is different to when only one segment (or set of segments) is activated. The transition may be initiated in dependence on the position of the drillstring, for example relative to the activated segment (or set of segments), in dependence on elapsed time since a segment (or set of segments) was activated, or by some other means.

[0151] Generally, the following sequence of steps is performed:

[0152] -a first gripping element (or set of elements) is activated to grip the borehole; -the drillstring and a second gripping element (or set of elements) are driven to progress them downhole. In the preferred embodiment, the second element (or set of elements) progress at a different (faster) speed than the drillstring, for example at twice the ROP of the drill bit;

[0153] -a second element (or set of elements) is activated to grip the borehole;

[0154] -the first element (or set of elements) is deactivated and driven to progress down the borehole with the drillstring.

[0155] This may be referred to as a ‘walking’ sequence.

[0156] The anchor may comprise a means of or mechanism for advancing deactivated segments downhole at a higher rate than the advancement of the drillstring in the borehole (for example, at twice the ROP of the drill bit).

[0157] There may be multiple grippers along the length of the anchor. There may be multiple grippers distributed around the circumference of the anchor. For example, there may be three or four rows of twenty gripping assemblies.

[0158] The anchor and / or other components in the BHA may comprise one or more devices for measuring one or more of torque, radial force, axial force and pressure, or for measuring one or more parameters that can be used to derive such quantities. The measurement devices may comprise sensors, such as torque sensors, pressure sensors and axial force sensors, such as strain gauges. The devices may also measure other parameters which may be used to infer the value of torque, radial force, axial force and / or pressure. The devices may comprise mechanical or hydromechanical mechanisms that are configured to change state or move in response to variations in parameters such as torque, weight and pressure. That change or state or movement may be used to control or provide feedback to control the operation of the anchor. This may also allow these parameters to be measured downhole and then used to control the operation of the anchor or other components of the BHA, such as the steering device 112. The data may also be used to control the operation of the anchor, for example to control the operation of the gripper(s) or to control the axial force applied to the BHA, the drill bit or the drillstring.

[0159] As mentioned above, the anchor tool may comprise a control unit 400. An example of the control unit 400 and some of its associated components is shown in more detail in FIG. 4. In this example, the control unit comprises a processor 401 and a memory 402. The processor may execute computer code stored at the memory 402 to perform the functions described herein. The control unit 400 may control the anchor (for example, the configuration of one or more grippers of the anchor to control the axial and / or torsional force exerted against the borehole or to the drillstring below the anchor by the one or more grippers) based on control signals from a downhole processor. This can allow for autonomous control and / or kinematics control of the anchor and other components in the BHA. The control unit may also comprise a transceiver 403 for sending and receiving signals to and / or from other entities, such as sensors communicatively connected to the anchor.

[0160] In other examples, the control unit may be replaced by a different control arrangement. The control arrangement may alternatively be implemented by an analogue electrical circuit or mechanical and / or hydraulic arrangement. The control arrangement may be arranged for controlling the apparatus in the ways described herein.

[0161] The control unit 400 can control the multiple anchoring modules 201 , 202 and can allow for standalone operation (i.e. with no connection of the control unit to surface). In some implementations, the anchor control unit may also interface with an MWD module in the drillstring (for example to allow real-time feedback to an operator at the surface), and / or with E-line and / or wired drill pipe (for real-time two-way communications with the surface).

[0162] In some examples, the control unit 400 comprises one or more sensors 404 or may be communicatively connected with one or more other sensors of the anchor.

[0163] The control unit 400 may also be connectable to other components of the BHA. As mentioned above, the BHA may comprise a steering device 112, such as an orienter or an RSS. The use of a downhole control unit 400 can also allow high-speed well directional data to be transmitted to the steering device by sending control signals from downhole control unit 400.

[0164] The processor 401 of the control unit 400 of the anchor may be configured to execute a control strategy to vary the axial push / pull force applied to components proximal or distal of the anchor (for example, to the drillstring to push or pull it down the borehole or to the BHA or bit, for example to apply WOB) to optimize the drilling process and reduce drilling dysfunction by reducing stick slip by reacting torsional loads to the borehole. The controller may vary the force based on axial or torsional loads measured at the anchor. The controller may control the anchor and / or other components in the BHA based on closed loop feedback from downhole sensors to optimize the drilling process.

[0165] The incorporation of the downhole control unit 400 comprising a processor 401 and memory 402 into the apparatus may also enable event and diagnostic analysis, as well as closed- loop control of the anchor downhole.

[0166] It may be desirable to determine the relative linear displacement between components of the anchor, such as the central shaft and the housing of the gripping segments of the anchor in which the shaft is received. For example, as mentioned above, the actuation of a gripping segment of the tool may be performed in dependence on the linear position of another gripping segment.

[0167] A linear position sensing arrangement for measuring the linear displacement between two parts of the anchor will now be described. Although an anchor tool is described herein as an example, this approach is also applicable to other downhole tools having two or more parts that can move axially relative to each other.

[0168] Generally, the downhole tool comprises a first part and a second part. The first and second parts are configured to move axially relative to each other. In some implementations, the second part may be driven to move axially relative to the first part. The first part may be received in the second part.

[0169] FIG. 5 shows an example of a drillstring anchor 113 comprising a linear position sensing arrangement.

[0170] In the example of FIG. 5, there is a connection between the portion of the drillstring 102 and the anchor 113. In this example, the portion of the drillstring shown at 102 comprises a continuous work string in the form of coiled tubing. However, the drillstring may be any other pipe, hose or transfer line for deploying drilling equipment and the features described below may also apply to drillstrings having other forms. In this example, the coiled tubing extends from the surface of the borehole. In this example, the coiled tubing is attached to a coiled tubing connector coupled to the anchor by a rotatable coupling. In other implementations, the rotatable coupling may not be present and the connector may be immediately proximal of the proximal end of the anchor, or may be separated from the anchor by other components, such as a sub or drill pipe. The connector is proximal of the anchor in the drillstring. The coupling may be immediately proximal of the proximal end of the anchor (i.e. immediately above I upbore of the anchor in the drillstring).

[0171] In this example, the coupling 114 comprises upper 114a and lower 114b parts. The upper and lower parts of the coupling are configured to rotate relative to each other. Relative rotation may be allowed in both directions or in one direction only (for example, for a unidirectional swivel). The lower part 114b is rotationally fast with the body of the anchor and the upper part 114a is rotationally fast with the connector.

[0172] The connector 115 may be axially coupled with the drillstring below the anchor. Therefore the anchor may be configured so that the portion of the drillstring above the anchor and the components of the BHA below the anchor can move axially relative to the body of the anchor when one or more of the grippers of the anchor is gripping the wellbore. This can allow the drilling, or other operation, to progress when the anchor is activated to grip the borehole.

[0173] In the example shown in FIG. 5, the first part 501 is a central shaft of a drillstring anchor. The central shaft may be coupled to a downhole portion of the drillstring. The second part 502 comprises a gripper unit of the anchor tool. The central shaft 501 is configured to move axially relative to the gripper unit 502 and rotate relative to the gripper unit.

[0174] The anchor 113 comprises a linear position sensing arrangement. The arrangement comprises a detector attached to the first part (in this example, the central shaft) and a source attached to the second part (in this example, the inside of the gripper housing).

[0175] The linear position sensing arrangement also comprises a processor 506 configured to receive a signal from the detector in response to the detector detecting the source. In dependence on the received signal, the processor can determine the linear displacement of the first part relative to the second part.

[0176] The source may be disposed on an interior surface of the second part, the interior surface facing the exterior surface of the first part. The source may be disposed about the circumference of the interior surface of the first part. In the example shown in FIG. 5, the source 503 is a ring magnet and the detector comprises an array of sensors 504a-e disposed longitudinally along the exterior surface of the central shaft 501. In this example, each sensor 504a-e comprises a magnetic sensor. The magnetic sensor may be, for example, a magnetometer or a Hall sensor. Other types of source and detectors may be used.

[0177] The received signal from the detector may indicate a measured amplitude of a signal emitted by the source. The determined linear displacement may be a relative displacement within a displacement range. For example, a signal detected by the source may have an amplitude that corresponds to a particular position in a displacement range. The displacement range may correspond to the distance between the sensors in the sensor array (for example, from the centre of one sensor to the centre of an adjacent sensor). They sensors may be equally spaced along the longitudinal axis of the first part.

[0178] The amplitude of the signal detected by a sensor corresponds to a particular linear position.

[0179] FIG. 6a shows an exemplary schematic plot of the detected voltage signal vs. position for three exemplary sensors 601 , 602, 603. To decide which sensor output is used to determine the position at any point, the processor may monitor the output of each sensor and select the sensor with the detected signal having the greatest absolute magnitude. If the value from this step is negative, the signal from the sensor to the right is used. If the output is positive, the signal from the sensor to the left is used. If the sensor is the first in the array and positive, the signal of that sensor can be used. Similarly, the signal from the last sensor can be used when it is negative.

[0180] For example, consider the position at 0 mm displacement shown in FIG. 6a, which is directly centered over the first sensor which trace 601 . Here the output from the trace 602 for the second sensor has the greatest magnitude and is positive. The trace 601 for the first sensor (to the left) is used to determine position. Now considering the position shown at x1 mm; the maximum negative output value for the trace 602 for the second sensor is observed. Calculations should therefore be made using the value from the trace 603 for the third sensor (to the right). The position is then calculated based on this selection. This may require obtaining calibration points from each sensor to achieve the highest accuracy. Knowing the start position for each sensor and the slope of the output voltage vs. position for each trace can allow the system to stitch the outputs together to produce a final position measurement. In another implementation, the polarization of the ring magnet 503 may be changed to create a pulse in only one direction for each sensor. Adjacent sensors may detect pulses of opposite orientation. This may allow for automatic determination of the maximum amplitude of the signal for each sensor. This may be done by adding the signal for one sensor with the signals from the two adjacent sensors (or all of the sensors, as the other sensors may detect zero voltage if they are not close to the source) to determine the voltage at the peak position in real-time. Whereas the approach shown in FIG. 6a requires knowledge of the peak voltage, this solution can allow the voltage peak to be computed on-the-fly, which may allow for more accurate position measurement, rather than relying on a pre-computed peak value. This is particularly advantageous in a downhole tool where the distance between the source and the detector may vary overtime due to bending and heating of the parts and can allow for more precise position measurement.

[0181] This implementation is schematically illustrated in FIG. 6b, where in this example there are four sensors having respective traces of voltage vs. position shown at 651 , 652, 653 and 654.

[0182] The processor may receive voltage measurements from each of the multiple sensors 504a- 504e of the detector. The processor can sum the voltage measurements for the multiple sensors to determine a peak voltage. The peak voltage can be divided by the distance between two adjacent sensors (for example, between the centers of the sensors in mm) to give a value of V / unit position (for example, V / mm).The processor may be configured to determine a linear position of the first part relative to the second part in dependence on the sum of the voltage output by each of the sensors in the detector array and the distance between adjacent sensors of the detector array.

[0183] The center of the sensor corresponding to trace 652 is at position c shown in FIG. 6b.

[0184] Considering the position at x2 displacement shown in FIG. 6b, here the output from the trace 653 for the third sensor has the greatest magnitude and has a negative output. Calculations should therefore be made using the value from the trace 654 for the fourth sensor (to the right). The position is then calculated based on this selection. Using the peak voltage calculated by adding the voltage values for each sensor together at the same point, and dividing it by the distance between sensor centers, the voltage reading for the fourth sensor can be used to calculate the position. In some implementations, the first part of the downhole tool may be configured to rotate relative to the second part, as well as being configured to move axially relative to each other. The first part may be driveable to rotate relative to the second part. The detector of the linear position sensing arrangement may be configured to detect the source while the first part is rotating relative to the second part.

[0185] The position sensing arrangement described herein may also be used to determine relative rotation between the first part and the second part while the parts are undergoing relative axial movement and relative rotation. The rotation sensing arrangement may use the same detector as the linear position sensing arrangement (i.e. in the example of Figure 5, the array of magnetic sensors 504a-e on the central shaft 501 ) to detect a second source 505. The second source is separate to the first source. In the example shown in FIG. 5, the second source 505 is a magnet. The processor can receive a signal from the detector in response to the detector detecting the second source, and in dependence on the received signal, determine the angular displacement of the first part relative to the second part.

[0186] Some exemplary ways in which the detector may distinguish between the first source 503 and the second source 505 are as follows. If there are two sets of sensors of the type 504a- 504e placed 180 degrees apart on opposite sides of the outside of the first part, both would see the first source which extends around the circumference of the interior of the second part, but only one set would detect the second source at any given moment in time. That can allow the signals from each source to be distinguished. If there is only one set of sensors in a linear arrangement, as shown in FIG. 5, the sensors would not detect the second source all of the time, and so the processor may determine that the source that is intermittently detected is the second source and use that detected signal for the rotation determination.

[0187] The downhole tool may be communicatively connected to a control arrangement, such as control unit 400, configured to control operation of the downhole tool in dependence on the determined linear and / or angular displacement of the first part relative to the second part. For example, where the downhole tool is an anchor tool comprising one or more grippers operable to grip a wellbore, as described above, the control unit may control the actuation of the one or more grippers in dependence on the determined linear displacement of the first part relative to the second part. For example, when it is determined from the linear position measurements that the first part has moved a predetermined distance relative to the second part, the control unit may cause one or more of the grippers to be activated to grip the wellbore, or may cause one or more other grippers to be retracted so that they do not grip the wellbore.

[0188] The control arrangement may be configured to control the downhole tool to apply axial thrust to cause an approximately constant rate of penetration of the bottom hole assembly by adjusting the axial thrust in further dependence on feedback from the linear position sensing arrangement.

[0189] In another aspect, it may be desirable to determine when a downhole tool has contacted the bottom of the wellbore, for example when a drill bit has contacted the bottom of the wellbore and has started drilling using a mud motor or other downhole tool regulated and / or controlled by differential pressure. Herein, this approach is exemplified in the case where the tool is a downhole anchor tool. However, the approach may also be used for other downhole tools where it is desirable to activate a feature of the tool once drilling has started.

[0190] The drillstring may comprise a downhole tool regulated and / or controlled by differential pressure, such as a mud motor or turbine. Such a tool can provide rotational drive to a drill bit, or other tool such as a mill, at the distal end of the drillstring. The downhole tool is proximal of the tool configured to provide rotational drive being regulated and / or controlled using differential pressure. The drillstring may comprise a rotational drive, such as a motor 110, proximal of the distal tool 108 for driving the distal tool to rotate.

[0191] As described above, the anchor tool comprises an internal channel for conveying the flow of drilling fluid to the distal tool from the surface. There may be a differential pressure between fluid in the channel and fluid in the annulus of the borehole. This differential pressure may drive the mud motor or turbine to rotate to supply rotational drive to a drill bit at the distal end of the drillstring.

[0192] When drilling starts, there is an increased toque at the motor, which results in a pressure drop from the bore (inside) of the anchor tool to the annulus of the wellbore (outside of the anchor tool). This pressure drop is created by the motor, the bit and optionally one or more other tools below the anchor tool. The detected pressure drop may be used as a proxy for increased torque at the motor, and therefore may be used to indicate the start of drilling. The differential pressure between the pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole can be measured using with two pressure sensors: one at the bore and one at the annulus. The sensors may comprise pressure transducers. Alternatively, this pressure differential could also be measured using a single sensor that measures the difference between the pressure in the bore and the annulus. The pressure sensor(s) can be used to determine when the flow of drilling fluid has started and / or when drilling has started.

[0193] The sensors can be used to measure the increased pressure drop created by the increased torque on the motor, or other downhole tool regulated and / or controlled by differential pressure, that occurs when the drill bit contacts the bottom of the well and starts drilling. In other words, the pressure measurement can be used to indicate when drilling starts and stops.

[0194] The controller for the downhole tool, such as control unit 400, comprises one or more processors configured to monitor the pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole. When the pressure difference is detected to have increased by at least a predetermined amount, the one or more processors can output a control signal to the downhole tool.

[0195] Where the downhole tool is a downhole anchor tool, the control signal may, for example, cause one or more grippers of the anchor tool to grip the borehole. The control signal may cause the anchor tool to initiate a gripping cycle (for example, the ‘walking’ cycle described above) of the downhole anchor tool. The control signal may cause operation of the sets of grippers of the anchor tool according to a predetermined operation sequence.

[0196] The downhole tool may be capable of applying axial thrust to one or more components distal of the downhole tool in the bottom hole assembly. The controller may control the applied axial thrust in dependence on the measured pressure difference. For example, when it is detected that the bit is on the bottom of the borehole and drilling has started, as a result of the detection of an increase in the pressure difference between the bore of the downhole tool and the annulus of at least a predetermined amount, the output control signal may cause the anchor tool to apply axial thrust to the drillstring so that axial force is applied to the drill bit to urge it against the bottom of the wellbore and / or maintain contact with the bottom of the wellbore.

[0197] FIG. 7 shows a flow chart illustrating the steps of an exemplary method of controlling a downhole tool for use in a downhole operation in a borehole. The downhole operation may be, for example, a drilling, milling or completions operation. At step 701 , the method comprises monitoring a pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole. At step 702, the method comprises, when the pressure difference is detected to have increased by at least a predetermined amount, outputting a control signal to the downhole tool.

[0198] This may allow the start of drilling, or other downhole process that results in an increase in the pressure drop between the bore of the tool and the annulus, to be detected and a downhole tool to be controlled in dependence on the detection.

[0199] In another aspect, it may be desirable to automatically determine when to disable the gripper(s) of the anchor tool. It may be desirable to automatically disable the grippers of the tool when a driller controls equipment at the surface (for example, a rig) to pull on the drillstring, for example when they wish to remove the drillstring from the borehole. When this occurs, a force is applied to the drillstring in an opposing direction to the direction of application of axial thrust to the drillstring by the anchor tool.

[0200] The application of a force in an uphole direction, which may result in movement of the drillstring in the uphole direction, may be inferred from a change in a measured or inferred parameter of greater than a threshold, and / or from a difference between a measured value or inferred value of the parameter and an expected value of the parameter of greater than a threshold.

[0201] Described generally, the controller may periodically receive measurements of a parameter of the anchor tool. It may monitor the received measurements, and when it detects that the measurements of the parameter indicate a change in the parameter of greater than a threshold, and / or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, the controller may output a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool. Some examples of how this may be implemented will now be described.

[0202] In one implementation, the bottom hole assembly comprises an axial force measurement sensor. The sensor may measure the amount of force applied to the drillstring or the drill bit. From data acquired using the axial force sensor, it can be determined whether the force being applied to the bit (i.e. the weight-on-bit) is lower than the axial force that the anchor tool is applying to the drillstring. This would indicate the application of an additional force to the drillstring in an opposing direction (i.e. in an uphole drirection). In this example, the parameter is a difference between an axial thrust applied to the one or more components located distally of the anchor tool in the bottom hole assembly and a measured axial force experienced by the one or more components located distally of the anchor tool in the bottom hole assembly.

[0203] As described above, the anchor tool may comprise two chambers for controlling the amount of axial thrust applied to one or more components of the drillstring distal of the anchor tool in downhole direction. The pressure difference between these two chambers may create the axial thrust.

[0204] The controller for the anchor tool may be configured to maintain these two chambers at specific pressures to create the desired axial thrust. If the required pressure in the chambers to achieve a certain axial force is reached, but the drillstring or drill bit do not move (which may, for example, be measured using the linear position sensing arrangement described herein), it can be inferred that an additional force is being applied to the drillstring in the uphole direction and is stopping the drillstring from moving forward.

[0205] Similarly, if the controller is controlling the application of axial thrust based on a measured linear position, and even at maximum pressure in one of the chambers the drillstring is not moving forward as expected, it can be inferred that a force is being applied to the drillstring in the uphole direction and is stopping it from moving forward. In this example, the parameter is a difference between a measured linear position of one or more grippers relative to a body of the anchor tool and an expected linear position of the one or more grippers relative to the body of the anchor tool.

[0206] In another example, if the controller is controlling the anchor tool to a set pressure, the pressure changes will ordinarily be responsive to the position of the valves, which the controller controls (meaning that if the position of valves are changed, the pressure should change accordingly). If there are sudden spikes in the pressure unrelated to movement of the valves (for example, changes in pressure that exceed a threshold), it can be inferred that an additional force is being applied to the drillstring in an opposing direction and creating the sudden spikes in pressure. Since the controller controls the chamber pressure, the detection of an increase in the pressure that does not match the pressure that should be achieve as a result of the controller controlling the operation of the valves is indication that a force is being applied to the drillstring in an uphole direction. Therefore, the parameter may be a difference between an actual pressure and an expected pressure in a chamber of the anchor tool configured to contain pressurised fluid for providing axial thrust to one or more components located distally of the anchor tool.

[0207] Alternatively, the parameter may be the actual pressure in a chamber of the anchor tool (for example, the chamber on an upper side of the piston with respect to the borehole that is used to apply axial thrust to the drillstring). The size of the chamber is variable in response to axial movement of the drillstring. When the driller pulls up on the drillstring, this chamber will decrease in size. As a result the pressure of fluid in the chamber increases. Therefore, when the measurements of the pressure of fluid in that chamber indicate an increase in pressure of greater than a threshold, which may be a change over a predetermined time period, this can be used to determine that an additional force is being applied to the drillstring in the uphole direction.

[0208] FIG. 8 shows a flow chart illustrating the steps of an exemplary method of controlling a downhole anchor tool. The anchor tool comprises one or more grippers operable to grip a borehole during a downhole operation and is configured to apply axial thrust to one or more components located distally of the anchor tool in a bottom hole assembly. The downhole operation may be, for example, a drilling, milling or completions operation.

[0209] At step 801 , the method comprises periodically receiving measurements of a parameter of the anchor tool. At step 802, the method comprises, when the measurements of the parameter indicate a change in the parameter of greater than a threshold, a pattern in the measurements of the parameter or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, outputting a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool. Alternatively, or in addition to, controlling the anchor tool from the surface by an operator pulling on the drillstring, the anchor may be controlled by sending control signals to the control unit of the anchor using E-line, or using downlinks.

[0210] FIG. 9 shows an exemplary control scheme for controlling an anchor tool. The following parameters may be measured during a downhole operation: gripper pressure, thrust forward pressure (shown as Fwd in FIG. 9), thrust back pressure (shown as Back in FIG. 9), tool bore and annual (or differential) pressure (shown as Diff in FIG. 9), linear position of one or more grippers, drillstring RPM (which may be measured using a gyroscope), acceleration from an accelerometer (for example to derive vibration and / or RPM).

[0211] Optionally, WOB may be measured if using WOB control mode. Additionally, torque-on-bit and gripper RPM may optionally be measured.

[0212] The following parameters are shown in FIG. 9. These parameters may be part of a parameter list that is pre-set at the surface:

[0213] - t1 = the time delay from the drill fluid pumps being turned on to the stable flow of drilling fluid

[0214] - t2 = width of pressure spike required to detect “driller pull up” on the drillstring, which can indicate that the anchor is to be disabled

[0215] - t3 = maximum time for “no flow” of drilling fluid before resetting to “not walking” state

[0216] - t4 = maximum time for “no rotate” before resetting to “not walking” state

[0217] - p1 = set point for “flowing off bottom” (which indicates that the pumps are turned on)

[0218] - p2 = set point for “bit on bottom” (this pressure is across the motor only, which indicates on bottom drilling)

[0219] - p3 = set point for “not flowing” (should be noticeably less than p1 , indicates pumps turned off)

[0220] - p4 = set point for “thrust force too high” (proxy for WOB, indicates attempt to POOH)

[0221] - r1 = maximum RPM considered as “not drilling”

[0222] - control mode = Differential pressure, axial force or ROP

[0223] - ROP max / min

[0224] - Differential pressure max / min

[0225] - Axial force max / min The following parameters may be calculated from the parameters measured during the downhole operation:

[0226] - PO = measured drilling differential when drilling fluid is flowing but when drilling has not started

[0227] - ROP = linear position over time

[0228] At 901 -904 are actions that an operator at the surface may command the anchor tool to perform. In this example, these actions are “Anchor off” 901 , where the anchor is disabled, “Next Parameter list” 902, where the controller uses a different set of preset parameters (of time and pressure setpoints etc) to the set being currently used, “Walk in” 903, where the anchor is controlled to perform a walking sequence to move into the borehole, and “Walk out” 904, where the anchor is controlled to perform a walking sequence to move out of the borehole.

[0229] The controller may monitor a pressure difference between a pressure of fluid in a bore of the anchor and a pressure of fluid in the annulus of the borehole; and when the pressure difference is detected to have increased by at least a predetermined amount, output a control signal to the downhole tool.

[0230] Alternatively or additionally, the controller may monitor a rate of rotation of the distal tool (for example, drill bit); and when the rate of rotation is detected to have increased by at least a predetermined amount, or a predetermined pattern of rotation is detected, output a control signal to the downhole tool.

[0231] For example, the sequences of RPM or differential pressure in a given time period at 905- 908 are different sequences that can be used to initiate the actions shown at 901-904 (“Anchor off’, “Next Param list”, “Walk in” and “Walk Out” respectively). Such a sequence may be, for example, when rotation is detected at 32-40 RPM for 5 seconds, then at 0 RPM for 10 seconds, then at 32-40 RPM for 5 seconds.

[0232] At 909, the BHA is reset on the surface. At 910, the controller monitors the RPM of the drillstring (above the motor) as a function of time to detect a particular sequence of RPM in time. This indicates to the controller that drilling will start soon. If the sequence of RPM in time is detected at 910, the process moves to 911 , where the controller determines whether the differential pressure, Diff, > p1 or the RPM > r1 . If so, the process moves to 912 where there is a delay of a predetermined time t1 to allow the flow of drilling fluid to stabilise.

[0233] Once time t1 has elapsed, at 913, the differential pressure, Diff, pO is measured and recorded when the drilling fluid is flowing but drilling has not started,

[0234] At 914, the controller determines whether the differential pressure, Diff, < p3. If Yes, the process continues to 916. If No, then at 915 it is determined whether the differential pressure, Diff, > p0+p2. If yes, the process continues to 916. If No, steps 914 and optionally 915 are repeated until it is detected that Diff < p3 or Diff > pO + p2.

[0235] At 916, the anchor is controlled to perform its walking sequence, as disclosed above, using pressure and / or linear position control. The anchor can also be controlled to apply axial thrust.

[0236] The steps shown at 917-920 represent conditions that, when detected, cause the walking sequence to be halted and the gripper(s) of the anchor to be deactivated,

[0237] At 917, the controller determines whether the difference in the pressure of the forward and back thrust chambers of the anchor are > p4 for a time period t2. At 918, the controller determines whether the differential pressure Diff < p3 for a time period > t3. At 919, the controller determines whether the RPM > r1 for a time > t4. At 920, the controller determines whether there has been a control failure (such as an electronics or software failure). In each of these cases, the anchor is deactivated.

[0238] The sequence from 921-925 in this example is the same as that shown from 916 to 920 for the actions “Walk in” 903 and “Walk out” 904, where there is no drilling (and so the start of drilling does not need to be detected in steps 910-915) and the process comprises detecting at each stage whether the anchor should be deactivated, as described above.

[0239] This may allow the anchor tool to be controlled based on the differential pressure and / or RPM downhole. In some implementations where the drillstring comprises a drilling motor for providing rotational drive to a drill bit at the distal end of the drillstring, the controller may be configured to control the axial thrust applied by the anchor to the drillstring to achieve a target motor torque. The target motor torque may depend on parameters such as the type of formation and the wear state of the drill bit. For example, with increase wear, the drill bit may require a higher motor torque to achieve a given ROP. The target motor torque may predetermined. The motor torque is generally proportional to weight-on-bit. Therefore the motor torque may be varied by adjusting the axial trust applied to the drillstring, and therefore the weight-on- bit at the drillstring. This may allow a target motor torque to be achieved by controlling the amount of axial thrust applied by the anchor. The controller may be programmed to execute a control strategy for controlling the anchor. The control strategy may be predetermined and may be one of multiple predetermined control strategies, with a particular control strategy being selected based on one or more of the type of drilling motor, the type of formation and the wear state of the drill bit.

[0240] In another aspect, the bottom hole assembly may comprise multiple anchor tools. Each tool may be configurable so that it can selectively perform torsional anchoring of the anchor to the borehole and / or supply axial force to the drillstring. In some circumstances, it may be desirable for only one or some of the multiple anchor tools in the bottom hole assembly to perform torsional anchoring.

[0241] One or more of the anchor tools may be controlled to prevent rotation between the central shaft and the gripper unit(s) (i.e. to torsionally lock), and then allow relative rotation to start again on command.

[0242] In one example, the tool may be configured for performing torsional anchoring when the central shaft of the tool is rotationally fast with the one or more gripper units. This may be achieved by keying the central shaft to the gripper unit(s) of the anchor tool. A control signal sent to the control unit of the tool which causes one or more keys or protrusions to extend and engage with the gripper unit(s) to allow the anchor tool to perform torsional anchoring. Anchor tools in the bottom hole assembly that are configured for performing torsional anchoring may prevent relative rotation between the central shaft and the wellbore when one or more grippers of the anchor tool are activated to grip the wellbore. This may advantageously allow for the prioritization of torsional anchoring or the application of axial force to the drillstring, as desired. If the drilling system comprises drill pipe with rotational drive from the surface, the torsional locking of one or more of the anchor tools may be used to stabilize the toolface of the distal tool at the bottom of the drillstring.

[0243] If the torsional anchors are able to be selectively enabled and disabled, one or more of the anchors could be controlled to torsionally lock once it has been detected (for example, using sensor measurements) that the distal tool (for example, drill bit) has hit a predetermined angle (toolface). This toolface could be adjusted as needed.

[0244] If the drillstring comprises coiled tubing, one or more of the anchors can be controlled to prevent rotation between the central shaft and the gripper unit(s) to react the torque from a drilling motor into the formation, instead of reacting it into the coiled tubing and possibly damaging the coiled tubing or injector system.

[0245] The downhole tools (e.g. anchors) described herein may be or may be part of a downhole subsystem of the system for performing the downhole operation. The downhole operations described herein may be performed by the downhole subsystem. The controller according to any of the aspects described herein may be for controlling a downhole tool that is or is part of a downhole subsystem. The methods described herein may be performed by the downhole subsystem. The controller may be a subsystem different from a downhole subsystem, or the two may constitute a common subsystem.

[0246] The applicant hereby discloses in isolation each individual feature described herein and any combination of two or more such features, to the extent that such features or combinations are capable of being carried out based on the present specification as a whole in the light of the common general knowledge of a person skilled in the art, irrespective of whether such features or combinations of features solve any problems disclosed herein, and without limitation to the scope of the claims. The applicant indicates that aspects of the present invention may consist of any such individual feature or combination of features. In view of the foregoing description it will be evident to a person skilled in the art that various modifications may be made within the scope of the invention.

Claims

CLAIMS1. A downhole tool comprising a linear position sensing arrangement, the downhole tool comprising a first part and a second part, the first and second parts being configured to move axially relative to each other, the linear position sensing arrangement comprising: a detector attached to the first part; a source attached to the second part; and a processor configured to: receive a signal from the detector in response to the detector detecting the source; and in dependence on the received signal, determine the linear displacement of the first part relative to the second part.

2. The downhole tool as claimed in claim 1 , wherein the first part is received in the second part.

3. The downhole tool as claimed in any preceding claim, wherein the first part is a central shaft and the second part comprises a gripper unit of an anchor tool, the central shaft being configured to move axially relative to the gripper unit and rotate relative to the gripper unit.

4. The downhole tool as claimed in any preceding claim, wherein the source is disposed on an interior surface of the second part, the interior surface facing the exterior surface of the first part.

5. The downhole tool as claimed in claim 4, wherein the source is disposed about the circumference of the interior surface of the second part.

6. The downhole tool as claimed in claim 5, wherein the source is a ring magnet.

7. The downhole tool as claimed in any preceding claim, wherein the detector comprises an array of sensors disposed longitudinally along an exterior surface of the first part.

8. The downhole tool as claimed in claim 7, wherein each sensor comprises a magnetic sensor.

9. The downhole tool as claimed in claim 7 or claim 8, wherein the processor is configured to receive voltage outputs from each of the sensors of the array in response to each sensor of the array detecting the source.

10. The downhole tool as claimed in claim 9, wherein the processor is configured to sum the voltage outputs received from each of the sensors of the array to determine a peak voltage.

11. The downhole tool as claimed in claim 9 or claim 10, wherein processor is configured to determine the linear displacement of the first part relative to the second part in dependence on the sum of the voltage outputs from each of the sensors of the array and the distance between adjacent sensors of the array.

12. The downhole tool as claimed in any preceding claim, wherein the first part is configured to rotate relative to the second part.

13. The downhole tool as claimed in claim 12, wherein the first part is driveable to rotate relative to the second part.

14. The downhole tool as claimed in claim 12 or claim 13, wherein the detector is configured to detect the source while the first part is rotating relative to the second part.

15. The downhole tool as claimed in any of claims 12 to 14, further comprising a rotation sensing arrangement configured to detect relative rotation between the first part and the second part, the rotation sensing arrangement comprising the detector and a second source attached to the second part.

16. The downhole tool as claimed in claim 15, wherein the second source is a magnet.4617. The downhole tool as claimed in any preceding claim, wherein the received signal from the detector indicates a measured amplitude of a signal emitted by the source.

18. The downhole tool as claimed in any preceding claim, wherein the determined linear displacement is a relative displacement within a displacement range.

19. The downhole tool as claimed in any preceding claim, wherein the downhole tool is communicatively connected to a control unit configured to control operation of the downhole tool in dependence on the determined linear displacement of the first part relative to the second part.

20. The downhole tool as claimed in claim 19 wherein the downhole tool is an anchor tool comprising one or more grippers operable to grip a wellbore, wherein the control unit is configured to control the actuation of the one or more grippers in dependence on the determined linear displacement of the first part relative to the second part.21 . A controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the controller comprising a control arrangement for controlling the downhole tool configured to: monitor a pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole; and when the pressure difference is detected to have increased by at least a predetermined amount, output a control signal to the downhole tool.

22. The controller as claimed in claim 21 , wherein the downhole tool is a downhole anchor tool configured to grip the borehole during a downhole operation and wherein the control signal output to the downhole anchor tool causes one or more grippers of the downhole anchor tool to grip the borehole.4723. The controller as claimed in claim 22, wherein the control signal causes the downhole anchor tool to initiate a gripping cycle of the downhole anchor tool.

24. The controller as claimed in any of claims 22 to 23, wherein the downhole anchor tool comprises two or more sets of grippers, each set of grippers being spaced longitudinally from the other set(s) of grippers, wherein the controller is configured to control the operation of the sets of grippers according to a predetermined operation sequence in dependence on the pressure difference.

25. The controller as claimed in any of claims 21 to 24, wherein the downhole tool is capable of applying axial thrust to one or more components distal of the downhole tool in the bottom hole assembly, wherein the controller is configured to control the applied axial thrust in dependence on the pressure difference.

26. The controller as claimed in any of claims 21 to 25, wherein the controller is configured to monitor the pressure difference in dependence on measurements received from one or more pressure sensors, the one or more pressure sensors being located at the bore of the downhole tool and / or the annulus of the borehole.

27. A downhole tool comprising the controller of any of claims 21 to 26.

28. A method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the method comprising: monitoring a pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole; and when the pressure difference is detected to have increased by at least a predetermined amount, outputting a control signal to the downhole tool.

29. A controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive to a distal tool in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure,the controller comprising a control arrangement for controlling the downhole tool configured to: monitor a rate of rotation of the distal tool; and when the rate of rotation is detected to have increased by at least a predetermined amount, or a predetermined pattern of rotation is detected, output a control signal to the downhole tool.

30. A downhole tool comprising the controller of claim 29.31 . A method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being proximal of a tool configured to provide rotational drive to a distal tool in a bottom hole assembly, the tool configured to provide rotational drive being regulated and / or controlled using differential pressure, the method comprising: monitoring a rate of rotation of the distal tool; and when the rate of rotation is detected to have increased by at least a predetermined amount, or a predetermined pattern of rotation is detected, outputting a control signal to the downhole tool.

32. A controller communicatively connectable to a downhole anchor tool, the anchor tool comprising one or more grippers operable to grip a borehole during a downhole operation and the anchor tool being configured to apply axial thrust to one or more components located distally of the anchor tool in a bottom hole assembly, the controller comprising a control arrangement for controlling the downhole tool configured to: periodically receive measurements of a parameter of the anchor tool; and when the measurements of the parameter indicate a change in the parameter of greater than a threshold, a pattern in the measurements of the parameter or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, output a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool.

33. The controller as claimed in claim 32, wherein the measurements of the parameter indicate one or more changes in the parameter of greater than one or more thresholds and wherein the change is over one or more predetermined time periods.

34. The controller as claimed in claim 32 or claim 33, wherein the parameter is a difference between an axial thrust applied to the one or more components located distally of the anchor tool in the bottom hole assembly and a measured axial force experienced by the one or more components located distally of the anchor tool in the bottom hole assembly.

35. The controller as claimed in claim 32 or claim 33, wherein the parameter is a difference between a measured linear position of one or more grippers relative to a body of the anchor tool and an expected linear position of the one or more grippers relative to the body of the anchor tool.

36. The controller as claimed in claim 32 or claim 33, wherein the downhole tool comprises a chamber configured to contain pressurised fluid for providing axial thrust to the one or more components located distally of the anchor tool, and wherein the controller is configured to: periodically receive measurements of pressure in the chamber; and output the control signal when the pressure measurements indicate an increase in pressure of greater than a threshold.

37. The controller as claimed in claim 32 or claim 33, wherein the downhole tool comprises a chamber configured to contain pressurised fluid for providing axial thrust to the one or more components located distally of the anchor tool, and wherein the parameter is a difference between an actual pressure and an expected pressure in the chamber.

38. The controller as claimed in claim 36 or claim 37, wherein the chamber is connected to a drillstring proximal of the downhole anchor tool, the size of the chamber being variable in response to axial movement of the drillstring.

39. A downhole tool comprising the controller of any of claims 32 to 38.

40. A method of controlling a downhole anchor tool, the anchor tool comprising one or more grippers operable to grip a borehole during a downhole operation and the anchor tool being configured to apply axial thrust to one or more components located distally of the anchor tool in a bottom hole assembly, the method comprising: periodically receiving measurements of a parameter of the anchor tool; and when the measurements of the parameter indicate a change in the parameter of greater than a threshold, a pattern in the measurements of the parameter or a difference between a measured value of the parameter and an expected value of the parameter of greater than a threshold, outputting a control signal to the anchor tool to disable the grippers(s) of the downhole anchor tool.

41. A controller for an anchor tool, the anchor tool comprising two chambers for controlling the amount of axial thrust applied by the anchor tool to one or more components distal of the anchor tool in a drillstring, the controller being configured to maintain the pressure in the two chambers to create a desired axial thrust.

42. A controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the controller comprising a control arrangement arranged to control the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly by controlling a pressure difference within the downhole tool, wherein the controller is configured to control the downhole tool to apply an approximately constant axial thrust to the one or more components by holding the pressure difference within the downhole tool to be approximately constant.

43. A controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the controller comprising a control arrangement arranged to control the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly by controlling a pressure difference within the downhole tool, wherein the controller is configured to control the downhole tool to apply axial thrust to cause an approximately constant rate of penetration of the bottom hole assembly by adjusting the axial thrust in further dependence on feedback from a linear position sensor of the downhole tool.5144. A controller communicatively connectable to a downhole tool for use in a downhole operation in a borehole, the controller comprising a control arrangement arranged to control the downhole tool to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly by controlling a pressure difference within the downhole tool, wherein the controller is configured to control the downhole tool to apply axial thrust such that a second pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole is maintained to be approximately constant.

45. The controller as claimed in any of claims 41 to 44, wherein the controller is configured to control the downhole tool to apply axial thrust in dependence on measurements received from one or more pressure sensors.

46. The controller as claimed in any of claims 41 to 45, wherein the controller is the controller as claimed in any of claims 21 to 26, 29 or claims 32 to 38.

47. A downhole tool comprising the controller of any of claims 41 to 46.

48. A method of controlling an anchor tool, the anchor tool comprising two chambers for controlling the amount of axial thrust applied by the anchor tool to one or more components distal of the anchor tool in a drillstring, the method comprising maintaining the pressure in the two chambers to create a desired axial thrust.

49. A method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being configured to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly in dependence on a pressure difference within the downhole tool, wherein the method comprises controlling the downhole tool to apply an approximately constant axial thrust to the one or more components by holding the pressure difference within the downhole tool to be approximately constant.

50. A method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being configured to apply axial thrust to one or more52components located distally of the downhole tool in the bottom hole assembly in dependence on a pressure difference within the downhole tool, wherein the method comprises controlling the downhole tool to apply axial thrust to cause an approximately constant rate of penetration of the bottom hole assembly by adjusting the axial thrust in further dependence on feedback from a linear position sensor of the downhole tool.51 . A method of controlling a downhole tool for use in a downhole operation in a borehole, the downhole tool being configured to apply axial thrust to one or more components located distally of the downhole tool in the bottom hole assembly in dependence on a pressure difference within the downhole tool, wherein the method comprises controlling the downhole tool to apply axial thrust such that a second pressure difference between a pressure of fluid in a bore of the downhole tool and a pressure of fluid in the annulus of the borehole is maintained to be approximately constant.

52. A downhole system comprising multiple anchor tools, each anchor tool comprising one or more grippers and a central shaft rotationally fast with a drilstring, each anchor tool being configurable between a first state in which the central shaft can rotate relative to the gripper(s) and a second state in which the central shaft cannot rotate relative to the gripper(s), wherein in the second state, the respective anchor tool can react torque from the drillstring to the borehole via the gripper(s).53

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