Downhole apparatus for use with a continuous work string

Abstract

Apparatus including a bottom hole assembly (BHA) with a drill bit 108, and a downhole anchor 113 having a gripping element for engaging the borehole to control relative movement and load transfer bet

Description

FIELD OF THE INVENTION This invention relates to downhole apparatus for use with a continuous work string in a borehole. For example, in a subterranean drilling, milling or completions operation. BACKGROUND In drilling operations, for example in oil, gas or geothermal drilling, a borehole is drilled through a formation in the earth to form a borehole. 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 drillsting can be rotated by a downhole motor, allowing the bit to advance through the formation to form the borehole. 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. 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. It is desirable to use a continuous work string in the drillstring to reduce tripping time and nonproductive time and to allow for continuous circulation of drilling fluid and improved control of downhole operations. SUMMARY According to one aspect, there is provided an apparatus for use in a borehole, the apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole and a connector for connecting the apparatus to a continuous work string terminating proximally of the anchor, wherein the connector is configured to facilitate transfer of signals between the anchor and the surface of the wellbore. The signals may be received and / or transmitted via the continuous work string. The signals may be received and / or transmitted via the formation in which the borehole is formed. The signals may be, for example, electrical or electro-magnetic signals. The signals may be one or more of power signals, control signals and data signals. The signals may be received by and / or transmitted from the connector. The signals may be received by and / or transmitted from the connector from and / or to the surface via the continuous work string. The apparatus may be communicatively connectable with a surface or downhole control unit. 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 surface to more distal components of a bottom hole assembly than the anchor. The signals may be received at the connector. The apparatus may comprise the control unit. Alternatively, the control unit may be remote from the apparatus. 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 continuous work string or one or more of the other elements coupled with the anchor, such as a drill bit. The continuous work string may extend from the surface of the borehole (i.e. from ground level). The connector may be configured to receive power and / or control signals via the continuous work string from the surface. The connector may be an electrical connector. The connector may alternatively be electrically insulating, which may enable electro-magnetic signals to be transmitted between the anchor and the surface via the formation. The apparatus may further comprise one or more measurement devices for determining one or more of torque, axial force, bending force, pressure and temperature. The gripping element may be configured to grip the borehole to restrict relative axial movement between the anchor and the borehole. The gripping element may be configured to grip the borehole to restrict relative rotation between the anchor and the borehole. 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. The anchor may be capable of transferring axial force to the continuous work string to pull the continuous work string down the borehole and / or push the continuous work string up the borehole. The connector may be capable of transferring axial force to the continuous work string to pull the continuous work string down the borehole and / or push the continuous work string up the borehole. The anchor may be configured to apply axial 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. The anchor may be coupled with a tool for performing a downhole operation at the distal end of the bottom hole assembly and wherein the anchor is configured to apply weight to the tool to urge the tool into the borehole or against the bottom of the borehole. 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. The continuous work string may comprise coiled tubing. The continuous work string may comprise any other suitable continuous pipe, hose or transfer line. Multiple such continuous strings may be connected together in some cases, for example when drilling very deep wells where extended reach is required. The or each gripping element may have an associated actuator and wherein the actuator is 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. The connector may be proximal of the anchor. The connector may be coupled to the anchor by a rotatable and / or axially compliant coupling. The coupling may be configured to allow relative rotation of the connector and the anchor about one or more axes. The coupling may comprise a swivel. The swivel may be a unidirectional swivel or a bidirectional swivel. The swivel may be a continuous swivel. The coupling may be configured to at least partially isolate the connector from torsional forces generated distally of the anchor. The coupling may be configured to fully isolate the connector from torsional forces generated distally of the anchor. The coupling may be proximal of the proximal end of the anchor. The coupling may be immediately proximal of the proximal end of the anchor. Alternatively, there may be other components between the coupling and the proximal end of the anchor. 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. The apparatus may comprise one or more of the following: one or more data connectors for connecting to one or more data cables within the continuous work string for transmitting bidirectional communications between the surface of the borehole and the anchor; and / or one or more hydraulic connectors for connecting to one or more conduits within the continuous work string for transmitting hydraulic fluid between the surface of the borehole and the anchor. The connector may be configured to connect the apparatus to multiple continuous work strings. 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 drilling tool at the distal end of the drillstring may comprise a conventional rock bit, a PDC bit, a hybrid bit and a plasma bit. The continuous work string may terminate at the connector. The apparatus may comprise one or more channels for receiving drilling fluid from the continuous work string and conveying the drilling fluid towards the distal end of the drillstring. 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. According to another aspect, there is provided an apparatus for use in a borehole, the apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole and a connector for connecting the apparatus to a continuous work string terminating proximally of the anchor, wherein the connector is coupled to the anchor by a flexible coupling. The flexible coupling may be a rotatable and / or axially compliant coupling. According to a further aspect, there is provided a system for use in a borehole, the system comprising: a continuous work string extending from the surface of the borehole; and the apparatus defined above; wherein the continuous work string is connected to the apparatus at the connector. According to a further aspect, there is provided a method of performing a downhole operation in a borehole, the method comprising: deploying a continuous work string into the borehole, the continuous workstring being connected via a connector to an apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole, the continuous work string terminating proximally of the anchor; sending signals from the surface of the borehole to the apparatus; and controlling the configuration of the anchor based on the received signals. The method may further comprise applying an axial force to the continuous work string using the anchor to pull the contunuous work string down the borehole or push the continuous work string up the borehole. The method may further comprise, using the anchor, applying an axial force to one or more components coupled distally of the anchor to urge the one or more components downhole or uphole in the borehole. The method may further comprise applying weight on bit to a drill bit at the distal end of a bottom hole assembly comprising the apparatus. In the above apparatus and method above, the continuous work string may comprise a conduit for convenying the signals via the continuous work string, for example between the surface of the borehole (from which the continuous work string may be deployed into the borehole) and the connector. The conduit may be an electrical conduit (which may be referred to as an E-line) for convenying electrcial signals or a conduit for conveying electro-magnetic signals. BRIEF DESCRIPTION OF THE FIGURES 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. FIG.s 2(a) and 2(b) schematically illustrate an example of a gripper comprising a hydraulically actuated piston assembly. FIG.s 3(a)-3(c) schematically illustrate an example of a piston. FIG. 4 schematically illustrates an example of an anchor comprising multiple gripping segments. FIG. 5 schematically illustrates an example of a hydraulic cylinder assembly of the anchor of FIG. 4. FIG. 6 schematically illustrates the connection of a continuous work string proximally of the anchor. FIG. 7 shows the steps of an exemplary method for performing a downhole operation in a borehole using a continuous work string. DETAILED DESCRIPTION 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. In operation, a rig 101 provides support and / or power to a drillstring. The drillstring comprises a continuous work string 102. In this example, the continuous work string is a string of coiled tubing. Coiled tubing is typically a continuous length of tubing, which may comprise multiple sections of tubing that are welded together to form a continuous string capable of being deploying into the borehole as a single unit. The coiled tubing may be made from a low-alloy carbon steel tubing. In this example, the coiled tubing is spooled on a reel 103 from which it is deployed into the borehole. The use of coiled tubing may allow for continuous drilling and circulation of drilling fluid and can additionally minimize drilling and well control risk, reduce bottom hole temperatures and improve tripping times compared to conventional jointed drill pipe. The coiled tubing may be insulated for additional reduction in bottom hole temperatures. The coiled tubing may be maintained in tension for increased longevity and to maximize drilling distance. In other examples, the continuous work string may be other types of continuous pipe, hose or transfer line. Conversely to conventional drill pipe, which generally comprises multiple joints of drill pipe approximately 30 ft (9m) in length that are mechanically joined together at deployment to form the drillstring, the continuous work string may be a continuous length of greater than 5,000 ft without mechanical joints. In some cases, multiple continuous strings may be joined together for very deep wells where, for example, a single reel of coiled tubing is not long enough. The use of a continuous work string may allow the BHA to be more quickly deployed in the borehole, which can reduce trip time and non-productive time. The continuous work string 102 may comprise one or more electrical conduits such as cables for supplying power and / or communications to and / or from one or more downhole components. Such an electrical conduit in the continuous work string may be known as an E-line. This can allow for robust communications and the provision of power independently of other power sources, such as from the flow of drilling fluid. The borehole is shown at 104. The borehole may be at least partially lined with casing 105 and cement 106. The work string 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 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. 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. 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. 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. 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 flowpath 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 variation detected using a potential difference detector at surface using surface electrodes (not shown), or by employing electrical signals through wired pipe (if present). Both electro-magnetic 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. The component shown at 112 is a steering device. The steering device may be an orientertool. 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 may 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. 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. The component shown at 113 is an anchor tool, which will be described in more detail below. The anchor 113 is connected to the coiled tubing 102 via a coupling 114, such as a swivel. The coupling 114 couples the anchor 113 to a coiled tubing connector 115 which allows the coiled tubing 102 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 work string 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 below. The drilling fluid may be supplied to the tool 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. The anchor 113 can transfer axial forces and / or reactive torque from the BHA to the borehole, as will be described in more detail below. This may help to prevent the initiation of torsional oscillations in the work string, including stick slip. The anchor is designed to remove at least some, and preferably all, of the torque from the work string. 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. The rig 101, provides support for the work string 102. Drilling fluid is circulated through the work string 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. 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 work string 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. 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. 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. The BHA may also comprise a fluid conditioning module to regulate hydraulic pressure and / or to filter the drilling fluid. As will be described in more detail below, the anchor comprises one or more gripping elements (referred to herein as grippers) that can be activated by one or more actuators. The actuators may be driven from an energy store at the anchor or other energy source. 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. As a result, when the gripper is activated, relative rotation between the anchor and the borehole is resisted and this can allow torque to be reacted to the borehole. 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 may 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. The energy store provides the energy supply to one or more actuators for actuating one or more 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 reservoir of pressurised hydraulic fluid such as an accumulator. 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) or via a mud-driven turbine. In one implementation, the anchor is hydraulically actuated and has its own self-contained or sealed hydraulic system. The hydraulic fluid can be pressurised to higher pressures than the mud pressure inside the drillstring (during drilling), and so has a higher pressure differential with the annular pressure. Therefore, the anchor may not directly use the drilling mud to actuate its gripper(s). Instead, the anchor can use stored energy to activate and deactivate the anchor. The anchor can be in the deactivated configuration when the mud pumps are running. The anchor may generate its own reservoir of stored hydraulic energy. The reservoir enables the anchor to be activated when needed, independently of the drilling mud pumps. This may be a high pressure, low volume reservoir using clean fluid (not drilling mud). The system may use and re-charge a hydraulic accumulator. The anchor can thus in some cases be activated and deactivated without using the use of mud flow, mud pressure, or mud pulses and / or without using electronics. When the anchor is activated (i.e. when the actuator is driven to cause the gripper to grip the borehole), the drillstring is 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 is also 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 anchor and the borehole can be resisted or restricted. This may be due to physical engagement between the anchor and the interior face of the borehole. 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 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. 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. In one example, symmetrical teeth that are all the same length may be used. In other examples, teeth may be shaped such that they are not symmetrical and are more aggressive on the leading edge to resist motion. Each tooth may have a different angle on the back of the tooth different according to the local applied loading. Each tooth may have a different length to form a desired contact profile with the borehole. The direction of teeth on the outside of the pads may be chosen according to the direction of loading. This may lead to a stronger tooth and require less force to provide a given torque capacity. 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. 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). 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 are preferably hydraulically actuated. 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. One example of a gripping assembly comprising a hydraulic piston is shown in FIG.s 2a) and 2b). In FIG. 2a) the piston is in its passive position (which in this example is a retracted position) and in FIG. 2b) the piston is in an extended position in which it is urged outwardly from the body of the anchor to cause the end of the piston to grip the borehole. The body of the anchor is indicated at 200. The gripper assembly 201 sits in a recess in the body 200 of the anchor so that when the gripper is it its passive state the distal end of the piston does not stand proud of the surface of the body 200 of the anchor. The gripper assembly 201 comprises a housing 202 that sits in the recess in the body 200. The piston 203 is accommodated in the housing and can move outward relative to the housing. The piston 203 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. In this example, the travel of the piston relative to the housing is limited by a circular groove 204 in the housing in which a flange 205 at the base of the piston 203 can run. The groove has an end stop 206 which limits the travel of the piston 203 in the housing 202, as illustrated in FIG. 2(b). In this example, the movement of the piston 203 is supported in the recess in the housing 202 by bearings 208, 210 distributed around the circumference of the recess or channel. In this example, there are 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 203. There may alternatively or additionally be one or more seals disposed around at least part of the piston. For example, in FIG. 2(a) and 2(b) seals 207 and 209 are circumferential seals around the piston housing. 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. In the example of FIG.s 2(a) and 2(b), the gripper assembly 201 comprises a return spring 212, which can allow the piston 203 to be returned to its passive state when the anchor is at the surface of the borehole and there is no acting pressure differential between the body of the anchor and the annulus of the borehole. In this example, the end of the piston 203 has an insert 211 which engages the borehole to grip the rock. In other examples, the end of the piston 203 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 the following examples, 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 may not have any particular surface formations or surface roughness. 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. One example of a piston with an insert is shown in FIG.s 3(a)-3(c). The piston is cylindrical with a circular-cross section. The base of the piston has a flange 205 for limiting the travel of the piston within the housing, as described above. The opposite end 212 of the piston to the base has a chamfered profile. As shown in FIG. 3(c), the piston is hollow to optionally accommodate a spring and defines a chamber for hydraulic fluid. In this example, the gripper comprises a hardened insert 211 (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. The piston and / or the insert of the gripper may optionally be coated. This may allow the gripper to achieve a greater gripping affect than an uncoated gripper. For example, the gripper may be coated with a layer of diamond or superhard grit to increase the effective friction further. As mentioned above, the grippers may in some cases be activated from an energy store, such as a reservoir of hydraulic fluid at the anchor using a pump driven by the motor. Alternatively, a hydraulic accumulator may be used with enough stored energy for a drilling trip. The anchor may alternatively be powered by using energy generated as a result of the operation of the drillstring. The anchor may also be activated by drilling mud pressure, mud flow (either directly or via a mud powered device such as a turbine), by turning the drillstring, or by axial movement of the drillstring. In one example, the anchor (or one or more segments of the anchor) may be activated when mud is pumped to turn the mud motor, or when drilling with WOB is initiated or detected. Drillstring rotation may be used as an independent drive signal to activate the anchor (or one or more segments of the anchor). In some embodiments, the control signal for the anchor to be activated or de-activated may be provided from the surface. The use of an electronic system is possible at drilling depths in conventional wells. However, in very deep wells such as geothermal wells (which may be several kilometres deep) the rocks temperature is increasingly hot. The maximum working temperature of electronics is approximately 175°C. Therefore, it may also be desirable to actuate and control the anchor using non-electronic means. For example, the anchor may be activated as a result of changes to the tension / compression of the drill string as weight is applied to the bit, or as results of a detected combination of axial force and torsion. The anchor may be deactivated when the tool is lifted up in the hole or rotated from the surface. This can help to ensure the tool can be pulled out of the well. Alternatively the activation may be controlled via mud pumps, mud pulse or electrically via the E-line. 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. 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 (comprising the continuous work string and the BHA) 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. Generally, the following sequence of steps is performed: -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; -a second element (or set of elements) is activated to grip the borehole; -the first element (or set of elements) is deactivated and driven to progress down the borehole with the drillstring. 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). There may be multiple gripping assemblies each comprising a piston along the length of the anchor. There may be multiple gripping assemblies each comprising a piston distributed around the circumference of the anchor. For example, there may be four rows of twenty gripping assemblies. FIG. 4 shows an example of an anchor. In this example, the anchor 113 comprises multiple segments 401, 402 each comprising one or more grippers. For example, each segment may comprise multiple grippers of the type described above. The segments 401,402 can be moved relative to one another using a walking mechanism. In this embodiment, the anchor uses a hydraulic walking mechanism to move the segments and their associated gripper(s) down the borehole as drilling progresses. As shown in FIG. 4, the anchor 113 comprises a first gripping segment 401 and a second gripping segment 402. In this example, the gripping segment 401 comprises an upper gripper set and the gripping segment 402 comprises a lower gripper set (‘upper’ and ‘lower’ being relative to the bottom of the borehole). The segments 401 and 402 are each connected to hydraulic cylinder assemblies 405 and 409, for example via galleries. The respective gripping segments are fast with their respective cylinder assemblies such that movement of a cylinder assembly relative to the drillstring causes corresponding movement of the respective gripping segment. Connector 403 is an upper connector for connection to drill pipe or an upper part of the BHA. Connector 410 is a lower connector for connection to a downhole mud motor or a lower part of the BHA. The upper connector 2003 and lower connector 2003 may both be adapters to industry standard connectors used to connect the anchor to the adjacent sections of the drillstring. Unit 404 is a hydraulic unit configured to provide hydraulic power for actuating the grippers of gripper segments 401 and 402. In this example, the hydraulic unit 404 does not provide hydraulic power to the drive mechanisms of the gripping segments (hydraulic cylinder assemblies 405 and 409) and the hydraulic power supplied to the units 405, 409 is passive and on a separate circuit. Connections between the hydraulic unit 404 and the grippers may be provided by galleries within the units 401,402, 405, 406 and 408. In this example, the drive mechanism for moving each segment longitudinally relative to the other segment(s) comprises a hydraulic circuit with hydraulic cylinder assemblies. A first cylinder assembly is shown at 405. The cylinder assembly 405 controls the movement of the first gripping segment 401 relative to the body or housing of the anchor. The cylinder assembly 405 drives the first gripping segment 401 to move relative to the second gripping segment 402. A second cylinder assembly is shown at 409. The cylinder assembly 409 controls the movement of the second gripping segment 402 relative to the housing of the anchor. The cylinder assembly 409 drives the second gripping segment 402 to move relative to the first gripping segment 401. Unit 406 is an upper key housing which contains galleries connecting the cylinder assemblies 405 and 409. Unit 408 is a lower key housing which contains galleries connecting cylinder assemblies 405 and 409. The key housings 406, 408 are configured to engage with the main shaft of the anchor, which may have corresponding keyed protrusions which engage with the key housings. Hoses 407 connect the hydraulic cylinder assemblies 405, 409 of the upper and low gripping segments 401, 402 and provide the actuation and return hydraulic feeds to these units 405, 409. In other implementations, there may be further gripping segments and cylinder pairs in the anchor. The units 401,402, 404, 405, 406, 408 and 409 comprising the anchor may be arranged in any order. FIG. 5 shows an example of a cylinder assembly 405, 409 and its associated components. In this example, the cylinder assemblies 405, 409 each comprise two cylinder assemblies 501, 502. In other examples of the anchor, there may be only one cylinder assembly 501 or more than two cylinder assemblies per gripping segment. In the example shown in FIG. 5, one pair of cylinder assemblies 501,502 is attached to the housing of a gripping segment. In otherwords, each pair of cylinder assemblies is fast with a gripping segment of the anchor. The cylinder assemblies are arranged around the circumference of the channel which engages a shaft 508. For example, the cylinder assemblies may be arranged on opposing sides of the channel and shaft 508. The cylinder assemblies of each gripping segment are connected to each other, for example by piping, to allow the flow of hydraulic fluid therebetween. The shaft 508 may be axially coupled with components on either side of the anchor. The shaft may be axially coupled with the continuous work string above the anchor and other components of the BHA below the anchor. This can allow drilling to progress while one or more of the grippers of the anchor are activated to grip the borehole. The main components of a cylinder assembly are indicated in FIG. 5 for cylinder assembly 501. Cylinder assembly 502 comprises corresponding features. Cylinder assembly 501 comprises a piston 505 which separates two chambers 503, 506 within the cylinder. One chamber 503 is above the piston and the other 506 below (with respect to the downhole direction). There is a connection 507 between the linkage 509 and the shaft 508. The linkage 509, which in this example is a rod passing through the upper and lower chambers and the piston 505, is slidably attached to the piston 505. The rod is attached at its lower end (in the downhole direction) to the shaft 508 via connection 507. The linkage 509 is configured to transfer a force to the piston 505 when the shaft 508 moves downhole. Movement of the linkage 509 in the downhole direction when the shaft 508 progresses downhole therefore causes movement of the piston 505 within the chamber in the downhole direction. This reduces the size of the chamber 506 below the piston. Movement of the shaft 508 relative to the channel of the anchor in the downhole direction therefore displaces the piston 505. In this example, linkage 509 comprises a seat, shown at 510, which bears against one or more compliant members between the seat 510 and the piston 505. In this particular implementation, the one or more compliant members are springs 504 located adjacent to the piston 505 in the uphole direction, between the piston 505 and seat 510 of linkage 509. The compliant member(s) provides for compliance between the piston 505 and the linkage 509 that allows drilling to progress, and thus allows the shaft 508 to continue moving axially in the downhole direction, when both gripping segments are gripping the borehole (for example, during the handover phase between the gripping segments, as described below). In this example, the linkage 509 comprises a stop 511. Stop 511 can be inserted during assembly of the anchor device to preload the compliant spring member 504. During walking motion, the spring preload is sufficient to resist the hydraulic pressures generated in the chamber 506 and so there is no relative movement between piston 505 and linkage 509. However, during handover from one gripping segment to the other gripping segment, when both segments are gripping the borehole, continued motion of linkage 509 generates hydraulic pressure in the lower chamber 506 large enough to overcome the preload and the piston 505 and stop 511 can separate and in this case there is relative motion between piston 505 and linkage 509. The stop 511 also allows the weight of the gripper housing to be carried without applying a force to the compliant member 504. In a cylinder assembly that is fixedly connected to the gripping segment that is activated and gripping the borehole wall at a given time (referred to now as SEGMENT A), this piston movement that occurs when the shaft moves downhole causes a change in volume in the chambers 503, 506 on either side of the piston 505. Fluid is discharged from the chamber 506 below the piston 505 because its volume is reduced and the chamber 503 above the piston increases in volume. This fluid displaced from the lower chamber 506 described above is fed via a connection (for example, hoses or piping 407) to the lower chamber(s) of the cylinder(s) attached to the other gripper segment (referred to now as SEGMENT B). When the gripper(s) of this segment are not activated and not gripping borehole, this fluid can be accepted into the lower chamber of this other cylinder assembly by moving the gripper segment attached to the other cylinder (SEGMENT B) down the borehole, increasing the volume of the lower chamber. The piston(s) within the SEGMENT B cylinder(s) have also been moved down relative to the borehole by motion of the shaft 508. As a result of this and the incoming fluid from the SEGMENT A cylinder(s), the SEGMENT B gripper housing is seen to move at twice the speed of the main shaft 508 in the downhole direction. The volume changes in the upper chambers 503 are dealt with by fluid flowing from the cylinder(s) of SEGMENT B to SEGMENT A. When SEGMENT B is the set of grippers that are activated and fixed to the borehole wall, the system works in reverse and the SEGMENT A gripper housing is seen to move down hole at twice the speed of the shaft 508. When passing the gripping effort from one gripping segment to the other (i.e. from 401 to 402 or vice versa), it is advantageous for there to be continuous resistance to the turning torque and thus continuous gripping of the borehole. As a result, a short period where the grippers of both segments are actuated to grip the borehole wall is advantageous. During this period, the shaft 508 can continue to move downhole relative to the channel of the anchor as drilling progresses. During this handover phase between the segments, the piston 505 does not move within the cylinder assembly 501. A change in volume of the lower chamber 506 of the cylinder assemblies cannot be relieved by moving fluid between the chambers of the cylinder assembly(s) of the gripping segments. Therefore, there is resistance to motion of the piston 505 in the downhole direction. This is counteracted by seat 510 compressing the one or more compliant members 504 above the piston 505 to allow the linkage 509 to move with the shaft 508, thus allowing the drillstring to continue moving downhole. The handover from one gripping segment to the other may be determined based on the position of the other gripping segment relative to the housing of the anchor, 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). An alternative implementation is to release the gripper of the currently gripping segment a fixed time after the free segment gripper activation is started. 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. In some implementations, the hydraulic cylinders may be actively controlled from a hydraulic power source to push the shaft (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 BHA. 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 continuous work string in a similar way by controlling the hydraulic cylinders to pull the shaft in an uphole direction. 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 508 running through the anchor (or vice versa). 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 force transfer to the 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 shaft 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. In other implementations, the anchor 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 (electrically, mechanically or hydraulically) such that they work in coordination to allow movement and force to be transferred to the BHA The connection between the continuous work string 102 and the anchor 113 is shown in more detail in FIG. 6. In this example, the continuous work string 102 is a string of coiled tubing. However, the continuous work string may be any other continuous pipe, hose or transfer line for deploying drilling equipment and the features described below may also apply to a continuous work string of other forms. The coiled tubing extends from the surface of the borehole. For example, the coiled tubing may be deployed from reel 103 at the surface. 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 coiled tubing may extend continuously from the surface to the coiled tubing connector. The coiled tubing connector is proximal of the anchor in the drillstring. The coiled tubing terminates at the coupling. The coiled tubing terminates proximally of the anchor. In this example, the coupling 114 is a swivel. The swivel may be a continuous swivel. Other suitable couplings may be used. The coupling is configured to at least partially isolate the connector from torsional forces generated distally of the anchor, for example from components to which the anchor is coupled in the BHA, such as the drill bit. The coupling may be configured to fully isolate the connector (and thus the continuous work string attached to the connector in use) from torsional forces generated distally of the anchor. The coupling is configured to allow relative rotation of the coiled tubing connector and the anchor about one or more axes. 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). 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. The connector may be rotationally fast with the continuous work string when the work string is connected to the connector. The rotatable coupling may be selectively rotatable. For example, it may be lockable so that the parts cannot rotate relative to each other when desired. The direction of rotation may also be controlled. Alternatively or additionally, the coupling between the anchor and the work string connector may also be axially compliant. The axially compliant coupling may be configured to compress and / or extend in the axial direction, along the longitudinal axis of the borehole. This may allow the tool at the distal end of the drillstring to be able to progress in the wellbore in the event that the continuous work string becomes temporarily stuck or is not able to keep up with the rate of penetration of the drill bit. Alternatively, there may be a separate axially compliant member proximal of the coupling (for example the swivel) to allow relative axial movement between the connector and the anchor and / or the tool at the distal end of the BHA. In some examples, the anchor may comprise the rotatable and / or axially compliant coupling at its proximal end (with respect to the surface when in use). The coupling may be integrated with the anchor. That is, the body of the anchor and the coupling may be integrally formed. In other examples, the anchor and the coupling may be separate components with separate bodies. The coupling may be proximal of the proximal end of the anchor and in some cases may be immediately proximal. The connector 115 may be axially coupled with the shaft 508 of the anchor. Therefore the anchor may be configured so that the continuous work string 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. The connector and the coupling may be configured to allow fluid to pass from the continuous work string to the anchor. For example, the upper 114a and lower 114b parts of the coupling may comprise respective flanges that are sealed together to prevent leakage of fluid whilst allowing relative rotation between the parts 114a, 114b. The connector may be capable of applying or transferring axial force to the continuous work string to pull the continuous work string down the borehole and / or push the continuous work string up the borehole. The anchor may be capable of applying or transferring axial force to the continuous work string to pull the continuous work string down the borehole and / or push the continuous work string up the borehole. The axial force may be generated by the anchor as described above. This can advantageously allow the anchor to act as a tractor for pulling the work string into and out of the borehole. The connector may comprise one or more electrical connectors for connecting to one or more electrical cables within the continuous work string for supplying electrical power to the apparatus from the surface of the borehole. The connector may alternatively be electrically insulating, which may allow electro-magnetic signals to be sent via the formation rather than sending electrical signals via the work string. The connector may also comprise one or more data connectors for connecting to one or more data cables within the continuous work string for transmitting bi-directional communications between the surface of the borehole and the anchor. The connector may also comprise one or more hydraulic connectors for connecting to one or more conduits within the continuous work string for transmitting hydraulic fluid between the surface of the borehole and the anchor. The apparatus can comprise one or more channels for receiving fluid from the continuous work string connected to the connector and conveying the fluid towards the distal end of the drillstring. The apparatus can comprise one or more connectors for connecting the apparatus to a drilling fluid supply conduit. The drilling fluid supply conduit may be within the continuous work string, receiving fluid from the continuous work string connected to the connector. The fluid channels may convey the fluid towards the distal end of the drillstring. As mentioned above, fluid such as drilling fluid may be supplied to the bottom of the borehole from tanks at the surface. 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. 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 continuous work string. As mentioned above, the connector for connecting the anchor to the continuous work string can comprise an electrical connector. The electrical connector may be configured to receive power and / or control signals from the continuous work string. The power and / or the control signals may be received from the surface. The electrical connector may also allow electrical signals to be sent from the anchor, or one or more other components of the BHA such as the MWD tool, to the surface. The electrical connector may allow bi-directional communications to be sent to and received from the surface, for example from surface computational platform 123 in FIG. 1. Control signals received from the surface via the continuous work string (for example via E-line in a coiled tubing string) may be used to control the anchor or other components in the BHA such as steering device 112. The connector may receive signals to be conveyed to components of the BHA located distally of the anchor, to which the anchor is connected directly or indirectly. The anchor may comprise a control unit. The control unit may comprise a processor and a memory. The processor may execute computer code stored at the memory to perform the functions described herein. The control unit may control the anchor (for example, the configuration of one or more grippers of the anchor to control the force exerted against the borehole or on the BHA by the one or more grippers) based on control signals received from the surface via the continuous work string (for example, via E-line within the string) and the electrical connector, or via RFID tags or via modulation of flow / pressure of the drilling fluid In some implementations, the control unit may be at surface and connected to analogue circuitry within the anchor, for example via E-line. This can allow for autonomous control and / or kinematics control of the anchor and other components in the BHA attached to the continuous work string. As mentioned above, the BHA may comprise a steering device 112 such as an orienter or an RSS. The use of a continuous work string electrically connected to the surface can allow highspeed well directional data to be transmitted to a surface controller and used to control of the steering device by sending control signals from the surface controller to the steering device via the electrical connection to the surface. The control unit of the anchor may be configured to vary the axial push / pull force applied to components proximal or distal of the anchor (for example, to the continuous work string 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 applied axial force based on control signals received from the surface at the electrical connector via the continuous work string or other means (for example, RFID or drilling fluid flow / pressure). 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 or surface metrics to optimize the drilling process. In one implementation, the connector is configured to connect the apparatus to multiple continuous work strings. For example, there may be two, three or more than three strings (for example, coiled tubing strings) extending from the surface of the borehole to the connector. The connector may connect the strings to the coupling. The use of multiple continuous work strings such as multiple coiled tubing strings may allow for improved flow rates downhole, which may improve the drilling speed by assisting with cutter transport and / or hole cleaning. The use of the anchor with multiple strings may prevent damaging torsional vibrations from being transmitted to the strings, which may prevent the strings from becoming twisted and compressed, affecting the flow rates of media being transported downhole within them. The anchor may also be used to assist with the deployment of the multiple strings into the borehole, which may be more difficult than the deployment of a single string, by applying axial force to the connector to pull the strings down the borehole. Figure 7 shows a flow chart illustrating the steps of an exemplary method of performing 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 deploying a continuous work string into the borehole, the continuous workstring being connected to an apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole, the continuous work string terminating proximally of the anchor. At step 702, the method comprises sending signals from the surface of the borehole to the apparatus (for example, to the connector and / or to the anchor). The signals may, for example, be sent via the continuous work string or alternatively via the formation. At step 703, the method comprises controlling the configuration of the anchor based on the received signals. The apparatus may be connected to further components suitable for performing the operation in the borehole, such as the components of the BHA described above. The system described herein can operate as an autonomous reeled system for drilling, milling, completions or other operations. By connecting the anchor with a continuous work string, this may allow a BHA to be deployed in the borehole quickly and with improved control and supply of downhole power. An connection (for example, an electrical connection) via the work string to the connector proximal of the anchor can allow for full kinematics control of processes downhole, for example to eliminate drilling dysfunctions (such as stick slip) and minimizes the need for heavy drilling BHAs that typically limit the use of continuous work strings such as coiled tubing. The anchor can advantageously isolate the drilling assembly and react torque to the formation, as well as applying axial (push / pull) forces to the work string, BHA and drill bit. This may allow off-the-rack technologies to be used deeper and hotter due to continuous circulation. High tripping speeds can mitigate cost of failure or premature wear of current off-the-rack technologies. High fidelity and reliable real-time formation evaluation and drilling mechanics data can minimize drilling risk and allow for real-time closed loop control of parameters and drilling kinematics downhole. Improved well control and reduced chance of stuck pipe may result due to more reliable bottom hole pressure control and continuous circulation even while tripping. It may also allow significant simplification of the anchor power and control systems. Faster tripping speeds can reduce operational costs and allow deep drilling to be commercially viable. Drilling speeds may also be further improved due to not needing to stop to make drill pipe connections and this can reduce the personnel required on the rig floor and at the location in general. The application of axial forces at the anchor, as described above, may also allow the anchor to be used as a tractor for completions and intervention operations. Allowing a continuous work string, such as coiled tubing, to remain in tension may significantly increase the drillable footage. This may also help to avoid buckling, which may occur in typical coiled tubing applications. The system can also allow for the application of additional WOB that ordinarily may not be able to be transferred to the bit using a continuous work string such as coiled tubing due to buckling of the tubing. In some implementations, the continuous work string may be insulated. Insulation of the continuous work string (such as by using insulating coiled tubing) may allow for an even larger temperature differential at the bottom of the borehole. The described approach may also be performed to utilize hybrid rigs which can allow the top hole section to be drilled conventionally and then coiled tubing (or another continuous work string) to be used for the deeper / production sections of the borehole. The distance that can be drilled may be extended further by splicing multiple continuous strings together. The continuous work string may be used as one conduit for the supply of power to downhole tools to minimize the size of the E-line. By including measurement devices such as sensors in the BHA, for example at the anchor or in an MWD tool, to measure parameters such as torque, position and axial force, increased measurement density can allow more precise well placement and formation characterization. It can also allow for full control of drilling kinematics to minimize drilling dysfunction and improve ROP, as well as reducing damage to downhole tools. Axial stick slip mitigation and / or control of drilling ROP can improve drill motor life due to more stable control of motor differential pressure and torque. It can further allow for simplified control and power to the anchor via E-line independent of drilling fluid flow. Alternatively, the flow of drilling fluid may be utilized to control the anchor to minimize the E-line requirements, as desired. The system may also allow for improved well control, as the continuous work string may be equipped with surface pressure controls that mean it can be used as a primary barrier and bottom hole pressure can be maintained more reliably than using weighted drilling fluid. 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

1. An apparatus for use in a borehole, the apparatus comprising:a bottom hole assembly comprising a drill bit and a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole; anda connector for connecting the apparatus to a continuous work string terminating proximally of the anchor, the connector being at least partially isolated from torsional forces from the drill bit by a rotatable coupling, wherein the anchor is configured to apply axial force to one or more distal downhole components coupled to the anchor.

2. The apparatus as claimed in claim 1, wherein the anchor is configured to react torsional loads to the borehole when the gripping element is gripping the borehole.

3. The apparatus as claimed in claim 1 or claim 2, wherein the apparatus is communicatively connectable with a surface or downhole control unit, wherein the control unit is configured to adjust the configuration of the anchor and / or one or more other elements coupled to the anchor in response to one or more signals.

4. The apparatus as claimed in any preceding claim, wherein the apparatus further comprises one or more measurement devices for determining one or more of torque, axial force, bending force, pressure and temperature.

5. The apparatus as claimed in any preceding claim, wherein the gripping element is configured to grip the borehole to restrict relative axial movement between the anchor and the borehole.

6. The apparatus as claimed in any preceding claim, wherein the gripping element is configured to grip the borehole to restrict relative rotation between the anchor and the borehole.

7. The apparatus as claimed in any preceding claim, wherein the anchor is configured to react axial loads to the borehole when the gripping element is gripping the borehole.

8. The apparatus as claimed in any preceding claim, wherein the anchor is capable of transferring axial force to the continuous work string to pull the continuous work string down the borehole and / or push the continuous work string up the borehole.

9. The apparatus as claimed in any preceding claim, wherein the anchor is configured to apply weight on bit to the drill bit.

10. The apparatus as claimed in any preceding claim, wherein the anchor is configured to urge the bottom hole assembly into the borehole.

11. The apparatus as claimed in any preceding claim, wherein the anchor comprises multiple gripping elements each configured to move axially relative to a body of the anchor.

12. The apparatus as claimed in any preceding claim, wherein the continuous work string comprises coiled tubing.

13. The apparatus as claimed in any preceding claim, wherein the or each gripping element has an associated actuator and wherein the actuator is capable of causing 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.

14. The apparatus as claimed in any preceding claim, wherein the connector is proximal of the anchor.

15. The apparatus as claimed in any preceding claim, wherein the coupling is axially compliant.

16. The apparatus as claimed in any preceding claim, wherein the coupling is configured to allow relative rotation of the connector and the anchor about one or more axes.

17. The apparatus as claimed in any preceding claim, wherein the coupling comprises a swivel.

18. The apparatus as claimed in any preceding claim, wherein the operation of the or each gripping element is powered by one or more of the following: the flow of drilling fluidthrough the anchor; an energy store; a thermal gradient between the interior of the anchor and the annulus of the borehole; power signals received at the connector via an electrical conduit of the continuous work string; and relative rotation between components in the bottom hole assembly.

19. The apparatus as claimed in any preceding claim, wherein the apparatus comprises one or more of the following:one or more data connectors for connecting to one or more data cables within the continuous work string for transmitting bi-directional communications between the surface of the borehole and the anchor; and / orone or more hydraulic connectors for connecting to one or more conduits within the continuous work string for transmitting hydraulic fluid between the surface of the borehole and the anchor.

20. The apparatus as claimed in any preceding claim, wherein the coupling is proximal of the proximal end of the anchor.

21. The apparatus as claimed in any preceding claim, wherein the apparatus is part of a downhole assembly comprising one or more additional downhole tools, the one or more additional downhole tools comprising 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 conventional rock bit, a PDC bit, a hybrid bit and a plasma bit.

22. The apparatus as claimed in any preceding claim, wherein the bottom hole assembly further comprises a motor for providing rotational drive to the drill bit.

23. A system for use in a borehole, the system comprising:a continuous work string extending from the surface of the borehole; and the apparatus as claimed in any preceding claim;wherein the continuous work string is connected to the apparatus at the connector.

24. A method of performing a downhole operation in a borehole, the method comprising deploying a continuous work string into the borehole, the continuous workstring being connected via a connector to an apparatus comprising a bottom hole assembly comprisinga drill bit and a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole, the continuous work string terminating proximally of the anchor, wherein the connector is at least partially isolated from torsional forces from the drill bit by a rotatable coupling, wherein the anchor is configured to apply axial force to one or more distal downhole components coupled to the anchor.

25. The method as claimed in claim 24, wherein the method further comprises applying an axial force to the continuous work string using the anchor to pull the continuous work string down the borehole or push the continuous work string up the borehole.A

Images