Drillstring anchor

Abstract

A drilling method for forming a wellbore in a rock formation using a drilling mechanism comprising a drill bit, a drillstring, a rotational drive coupled between the drillstring and the drill bit for driving the drill bit to rotate relative to the drillstring, and an anchor operable to rigidly grip the interior of the wellbore, the drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor so as to provide a reaction path for reacting torque from the rotational drive to the wellbore, the drillstring being moveable longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore, the method comprising: advancing the anchor longitudinally along the wellbore to an anchoring location; and simultaneously: (i) operating the rotational drive so as to drive the drill bit to rotate; (ii) applying a longitudinal force on the bit to force the bit into contact with a distal end of the wellbore; and (iii) operating the anchor to rigidly grip the wellbore at the anchoring location; the anchoring location being such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur.

Description

[0001] DRILLSTRING ANCHOR

[0002] FIELD OF THE INVENTION

[0003] This invention relates to a drillstring anchor for use in a wellbore. For example, in a subterranean drilling operation.

[0004] BACKGROUND

[0005] In drilling operations, for example in oil, gas or geothermal drilling, a borehole is drilled through a formation in the earth to form a wellbore. A drillstring extends from an upbore location, typically on the surface, to the foot of the wellbore and typically comprises long sections of drill pipe and other components, known as the bottom hole assembly, connected to a drill bit. The drill bit located at the distal end of a drillsting is rotated from the surface with a topdrive or a kelly or from a downhole motor, or both, allowing the bit to advance through the formation to form the wellbore.

[0006] A common occurrence during drilling is that changes in the reactive torque at the drill bit or friction between the drillstring and wellbore can initiate torsional oscillations, including stick slip. Stick slip occurs when the lower section of the drillstring stops or almost stops rotating, while the drillstring above continues to rotate faster, e.g. at the driven speed. 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 wellbore, and result in poor drilling performance.

[0007] A drillstring anchor can be used to reduce torsional vibrations in a drillstring that can mitigate these issues and reduce the likelihood of significant and potentially damaging torsional oscillations along the drillstring.

[0008] The axial force pushing the bit forward (weight on bit) is generally provided by the weight of the vertical section of the drillsting. For a given drill bit and lithology, the rate of penetration (ROP) is primarily a function of downhole weight on bit (DWOB) and downhole torque on bit (DTOB) and bit rotation speed (RPM). It is well-known that ROP can be increased if an optimum combination of DWOB, DTOB, and RPM is selected. A precise and accurate knowledge of ROP, DWOB, DTOB and RPM is therefore desirable in order to practice ROP maximization to lower overall drilling costs.

[0009] The control of the DWOB is generally carried out at surface by releasing the brake holding the drill string back. The torque DTOB is a result of the weight and RPM, and the RPM is the sum of the drillstring RPM controlled at the surface and the motor RPM which is a direct function of the mud flow rate, which is set and measured at the surface.

[0010] DWOB and DTOB are currently inferred from surface measurements. The primary measurement of DWOB is the hookload, and a correction can be applied using a drill string friction model depending on the wellbore trajectory, as well as buoyancy. The resulting accuracy of the inferred DWOB is therefore very poor because it depends on assumptions for the friction model and fidelity of the modeling code used. Similarly, DTOB can be estimated from the surface torque measured at the topdrive or at the kelly minus the modeled drillstring friction torque. When a motor is used, then the motor torque is added. The motor torque is estimated from motor manufacturer data sheets using the difference in surface standpipe pressure between on and off bottom (the motor delta p) and mud flow rate. RPM can be estimated from the surface measured RPM plus motor RPM estimated from the surface measured mud flow rate and motor manufacturer data sheets. The resulting accuracy of the estimated DTOB is therefore poor compared with a direct measurement performed downhole.

[0011] Attempts have been made to provide downhole measurements of DWOB and DTOB with instrumented drill collars used as a sensing element. Strain gauges have been used to provide an at-bit measurement. Experience showed however that the measured collar strain was primarily a function of pressure and temperature, and only weakly depending on weight and torque, rendering this measurement useless.

[0012] In addition, the measurement of ROP (and therefore total well depth via integration) is also subject to uncertainties as it is measured as the surface ROP, i.e. the rate at which pipe is lowered in the ground, which can be different from the distance traveled by the bit, due to pipe buckling and / or stretch.

[0013] The ROP maximization process via the optimum setting of DWOB, DTOB and RPM has therefore historically posed a problem, because of the poor quality of the measurement of these input parameters. It is desirable to obtain more accurate measurements of ROP, DWOB, and DTOB. SUMMARY

[0014] According to a first aspect, there is provided a drilling method for forming a wellbore in a rock formation using a drilling mechanism comprising a drill bit, a drillstring, a rotational drive coupled between the drillstring and the drill bit for driving the drill bit to rotate relative to the drillstring, and an anchor operable to rigidly grip the interior of the wellbore, the drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor so as to provide a reaction path for reacting torque from the rotational drive to the wellbore, the drillstring being moveable longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore, the method comprising: advancing the anchor longitudinally along the wellbore to an anchoring location; and simultaneously: (i) operating the rotational drive so as to drive the drill bit to rotate; (ii) applying a longitudinal force on the bit to force the bit into contact with a distal end of the wellbore; and (iii) operating the anchor to rigidly grip the wellbore at the anchoring location; the anchoring location being such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur.

[0015] The rotational drive may be a drilling motor. The anchoring location may be above (or proximal of) the rotational drive. The longitudinal force may be applied on the bit from the anchor. The longitudinal force may be weight on bit. The method may comprise reacting torque from the anchor to the wellbore.

[0016] The method may comprise selecting the anchoring location to which to advance the anchor. The method may comprise selecting the anchoring location in dependence on the torsional stiffness of the reaction path. The method may comprise selecting the anchoring location in dependence on the torsional stiffness of the reaction path such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur. The method may comprise repeatedly selecting the anchoring location as the drill bit advances in the wellbore. The method may comprise repeatedly advancing the anchor to the presently determined anchoring location as the bit advances in the wellbore. The method may comprise, as the drill bit advances in the wellbore, advancing the anchor to successive anchoring locations selected such that at each anchoring location the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur with the drill bit in its position for the time being. According to one aspect there is provided a drilling method for forming a wellbore in a rock formation using a drilling mechanism comprising a drill bit, a rotational drive coupled to the drill bit for driving the drill bit to rotate, an anchor being operable to rigidly grip the wellbore, and a drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor and can move longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore, the method comprising: operating the anchor to rigidly grip the wellbore; operating the rotational drive to drive the drill bit to drill the rock formation under operational conditions such that torsional vibrations occur in the portion of the drillstring downbore of the anchor; allowing the drillstring to move axially relative to the anchor while the anchor is gripping the wellbore such that the drill bit proceeds to drill the rock formation to progress the wellbore; whereby when the anchor is rigidly gripping the wellbore, the anchor isolates the portion of the drillstring upbore of the anchor from the torsional vibrations.

[0017] The method may comprise operating the rotational drive to drive the drill bit to drill the rock formation under operational conditions such that stick slip occurs. The stick slip may occur in the portion of the drillstring downbore of the anchor. The torsional vibrations may be due to the stick slip. When the anchor is rigidly gripping the wellbore, the anchor may isolate the portion of the drillstring upbore of the anchor from torsional vibrations due to the stick slip. The torsional vibrations may be bit-generated torsional vibrations. The bit-generated torsional vibrations may be generated in the drillstring by the behaviour of the drill bit.

[0018] The anchor may fully or partially isolate the portion of the drillstring upbore of the anchor from the torsional vibrations. The method may comprise reacting all of the torque from the portion of the drillstring downbore of the anchor to the wellbore through the anchor. The method may comprise reacting differential torque from the portion of the drillstring downbore of the anchor to the wellbore. For example, in some cases there may be some torque in the portion of the drillstring above the anchor. In this case, rather than reacting all of the torque from the portion of the drillstring downbore of the anchor to the wellbore through the anchor, Only the differential torque (the difference between the torque in the portion of the drillstring downbore of the anchor and above the anchor) may be reacted to the wellbore by the anchor.

[0019] The methods above may have any of the following further features:

[0020] The method may comprise operating the rotational drive to drive the drill bit to rotate at a rate of at least 30 revolutions per minute. The method may comprise operating the rotational drive to drive the drill bit to rotate at a rate of at least 40, 50, 60, 70 or 80 revolutions per minute. The method may comprise applying a weight on bit to the drill bit of between 2,000 to 120,000 Ibf. The method may comprise applying a weight on bit to the drill bit of between 5,000 to 80,000 Ibf. Other operational ranges may include 15,000 to 70,000 Ibf, 20,000 to 60,000 Ibf, 25,000 to 50,000 Ibf and 30,000 to 40,000 Ibf.

[0021] The method may comprise applying a torque on bit to the drill bit of between 1 ,000 to 80,000 ft- Ibf. The method may comprise applying a torque on bit to the drill bit of between 5,000 to 70,000 ft-lbf. Other operational ranges may include 10,000 to 60,000 ft-lbf, 20,000 to 50,000 ft-lbf, 30,000 to 45,000 ft-lbf and 35,000 to 40,000 ft-lbf.

[0022] The method may further comprise applying weight on bit at the anchor.

[0023] The rotational drive may be a motor positioned distally of the anchor in the drillstring.

[0024] The anchor may comprise multiple independently actuatable grippers. The method may further comprise operating the grippers to grip the wellbore sequentially while allowing the drillstring to move axially relative to the anchor.

[0025] The drill bit may comprise one or more conical polycrystalline diamond compact cutters. All of the cutters of the drill bit may be conical polycrystalline diamond compact cutters. In the absence of the anchor tool, such bits may generate unsustainable torsional vibrations.

[0026] According to a further aspect, there is provided use for the purpose of mitigating stick slip in a drilling procedure for forming a wellbore in a rock formation of a drilling mechanism comprising: a drill bit; a rotational drive coupled to the drill bit for driving the drill bit to rotate; an anchor; and a drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor and can move longitudinally relative to the anchor when the rotational drive is operated to drive the drill bit to drill the rock formation under operational conditions such that torsional vibrations occur in the portion of the drillstring downbore of the anchor; wherein the anchor is operated to rigidly grip the wellbore to react the torsional vibrations during drilling so as to isolate the portion of the drillstring upbore of the anchor from the torsional vibrations.

[0027] According to a further aspect, there is provided use for the purpose of mitigating torsional vibration and / or stick slip in a drilling procedure for forming a wellbore in a rock formation of a drilling mechanism comprising: a drill bit; a drillstring; a rotational drive coupled between the drillstring and the drill bit for driving the drill bit to rotate relative to the drillstring; and an anchor operable to rigidly grip the interior of the wellbore, the drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor so as to provide a reaction path for reacting torque from the rotational drive to the wellbore, the drillstring being moveable longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore; wherein the anchor is advanced longitudinally along the wellbore to an anchoring location; and wherein the following are performed simultaneously: (i) the rotational drive is operated so as to drive the drill bit to rotate; (ii) a longitudinal force is applied on the bit to force the bit into contact with a distal end of the wellbore; and (iii) the anchor is operated to rigidly grip the wellbore at the anchoring location; the anchoring location being such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur.

[0028] According to a further aspect, there is provided a downhole anchor tool for use with a drillstring for forming a wellbore, the tool comprising a channel having a configuration for rotational engagement with a downhole portion of the drillstring passing through the channel and comprising two grippers, each gripper being linearly displaceable relative to a body of the tool and the other gripper and being actuatable to grip the wellbore, wherein the tool comprises one or more sensors for determining the longitudinal position of one or more of the grippers relative to a reference point.

[0029] The downhole portion of the drillstring may comprise a shaft attachable to a lower part of the drillstring, the lower part of the drillstring comprising a drill bit for progressing the wellbore.

[0030] The reference point may be on the body of the tool. The reference point may be on the downhole portion of the drillstring.

[0031] The channel may be configured to allow relative axial movement of the downhole portion of the drillstring and the tool when one or more of the grippers is gripping the wellbore. The one or more sensors may be configured to detect the relative displacement of a respective gripper relative to the reference point when that gripper is gripping the wellbore.

[0032] The tool may be communicatively connectable with a first processor arranged to sum relative longitudinal movements of each gripper in the downhole direction. Each gripper may have a range of travel relative to the body of the tool, wherein the one or more sensors are configured to determine the longitudinal position of one or more of the grippers within its range of travel.

[0033] The tool may comprise a hydraulic chamber configured to house a piston for driving a respective gripper to move relative to the body of the tool and wherein the one or more sensors are configured to acquire data indicative of the longitudinal position of the piston within the chamber.

[0034] The one or more sensors may comprise one or more of a linear variable displacement transducer, a magneto strictive linear displacement transducer, a linear variable inductance transducer, a potentiometric device and a capacitive device.

[0035] The tool may be operable according to a cycle whereby the following steps are performed: a first one of the grippers is actuated to grip the wellbore; a second one of the grippers is actuated to grip the wellbore; the first one of the grippers is released from the wellbore; the first one of the grippers is actuated to grip the wellbore; and the second one of the grippers is released from the wellbore. The tool may comprise a first sensor for determining the longitudinal position of the first gripper relative to the reference point and / or a second sensor for determining the longitudinal position of the second gripper relative to the reference point.

[0036] The tool may be communicatively connectable with a second processor configured to determine a time period between the actuation of the first gripper and the actuation of the second gripper. The tool may be communicatively connectable with a third processor configured to determine a time period between the actuation of one of the grippers and a subsequent activation of that gripper.

[0037] The two grippers may be spaced longitudinally relative to one another.

[0038] The one or more sensors may be configured to measure the relative displacement of one gripper relative to the other gripper.

[0039] According to another aspect, there is provided a method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool for use with a drillstring for forming the wellbore, the tool comprising one or more grippers being actuatable to grip the wellbore, the method comprising: applying rotational drive to the drill bit; actuating a gripper of the one or more grippers to grip the wellbore; allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress in the wellbore; measuring the relative displacement between the gripper and a reference point on the downhole portion of the drillstring during a time period; and determining the rate of penetration of the drill bit as the ratio of the measured relative displacement and the time period.

[0040] According to another aspect, there is provided a method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool for use with a drillstring for forming the wellbore, the tool comprising two independently actuable grippers spaced longitudinally relative to each other, each gripper being linearly displaceable relative to a body of the tool and being actuatable to grip the wellbore, the method comprising: applying rotational drive to the drill bit; actuating a first one of the grippers to grip the wellbore, wherein at the time of actuation of the first one of the grippers, the first one of the grippers is at a first longitudinal position relative to the body of the tool; allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress in the wellbore; actuating a second one of the grippers to grip the wellbore, wherein at the time of actuation of the second one of the grippers, the first one of the grippers is at a second longitudinal position relative to the body of the tool; determining a time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers; determining the rate of penetration of the drill bit as the ratio of the distance between the first longitudinal position and the second longitudinal position and the time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers.

[0041] Each gripper may have a range of longitudinal travel relative to the body of the tool, wherein the first longitudinal position of the first one of the grippers corresponds to an upper limit of the range of travel with respect to the downhole direction.

[0042] The method may further comprise determining the distance between the first longitudinal position and the second longitudinal position.

[0043] The method may comprise determining the distance between the first longitudinal position and the second longitudinal position based on data acquired by one or more position sensors.

[0044] The distance between the first longitudinal position and the second longitudinal position may be known.

[0045] The method may further comprise determining the time difference between the actuation of the first gripper and the second gripper in dependence on measurements made by one or more further sensors of a bottom hole assembly, wherein the one or more further sensors comprise a vibration sensor, an accelerometer, a displacement sensor or a velocity sensor.

[0046] According to another aspect, there is provided a downhole anchor tool for use with a drillstring for forming a wellbore, the tool comprising a channel and a shaft passing through the channel, the channel having a configuration for rotational engagement with the shaft, and one or more grippers configured to be actuated to grip the wellbore to transfer torque from the drillstring to the wellbore, wherein the tool comprises one or more torque sensors for measuring the torque between the shaft and the channel.

[0047] The shaft may be connectable to the drillstring so as to be fast therewith. The channel may be configured such that the shaft (and thus the drillstring) can move axially relative to the channel (and / or the anchor tool) when one or more of the grippers are gripping the wellbore. The shaft may comprise one or more protrusions which engage with corresponding features of the channel to transmit torque from the drillstring to the anchor tool. The one or more torque sensors may be disposed at an interface between the protrusions and a main body of the shaft. The one or more protrusions may engage with the corresponding features of the channel when the channel is rotationally engaged with the shaft. The features may be concave features.

[0048] The shaft may comprise multiple protrusions symmetrically disposed about its radius. The main body of the shaft may comprise channels which engage a protrusion. The protrusions may be keys and the channels may be keyways. The tool may comprise a respective torque sensor for determining the torque between each protrusion and its corresponding feature of the channel.

[0049] Each torque sensor may be disposed at a respective radial planar portion of the shaft. Each respective radial planar portion may define part of a respective channel. For example, each respective radial planar portion way define a side wall of a respective channel.

[0050] One or more of the torque sensors may comprise a piezo electric force sensing foil. One or more of the torque sensors may comprise a strain gauge. One or more of the torque sensors may be a contactless torque sensor, for example that uses magnoelasticity to measure torque.

[0051] The tool may be configured to convey data from the one or more torque sensors to a processor for determining one or more drilling parameters comprising rate of penetration, downhole weight on bit, downhole torque on bit and mechanical specific energy. The processor may be configured to determine the downhole torque on bit as the sum of the moments of the forces about a central longitudinal axis of the tool. The tool may comprise a communications module configured to transmit data acquired by the torque sensors to the surface of the wellbore.

[0052] The tool may be configured to react torque from the drillstring to the wellbore when one or more of the grippers are actuated to grip the wellbore.

[0053] Each gripper may be capable of being driven to cause the gripper to adopt at least one of (a) a first state in which it is urged outwardly for gripping the wellbore and (b) a second, passive state.

[0054] According to another aspect, there is provided a downhole anchor tool for use with a drillstring for forming a wellbore, the tool comprising a channel having a configuration for rotational engagement with a downhole portion of the drillstring passing through the channel and comprising two grippers spaced longitudinally relative to each other, each gripper being linearly displaceable relative to a body of the tool and being actuatable to grip the wellbore, wherein the tool comprises a hydraulic drive mechanism for advancing the first gripper downhole relative to the second gripper, the mechanism comprising a hydraulic chamber and a piston moveable within the chamber that separates the chamber into upper and lower portions, wherein the tool comprises one or more pressure gauges for determining the differential pressure between the upper and lower portions of the chamber.

[0055] The chamber may house a portion of a linkage fixedly connectable to the downhole portion of the drillstring and slidably connectable to the piston.

[0056] The tool may comprise multiple hydraulic chambers and respective pistons.

[0057] The channel may be configured such that the downhole portion of the drillstring can move longitudinally relative to the channel when one or more of the grippers are gripping the wellbore.

[0058] The tool may be configured to convey data acquired by the one or more pressure gauges to a processor configured to determine one or more drilling parameters from the determined differential pressure.

[0059] The one or more drilling parameters may comprise one or more of downhole weight on bit and drillstring friction. The one or more pressure gauges may be configured to determine the pressure acting on the cross-sectional area of the piston.

[0060] According to a further aspect, there is provided a downhole anchor tool for use with a drillstring for forming a wellbore, the tool comprising a channel having a configuration for rotational engagement with a downhole portion of the drillstring passing through the channel and comprising two grippers spaced longitudinally relative to each other, each gripper being linearly displaceable relative to a body of the tool and being actuatable to grip the wellbore, wherein each gripper comprises one or more sensors for determining a property of a rock formation defining the wellbore.

[0061] The one or more sensors may be configured to measure a property of the rock formation, a property of the Earth’s magnetic or gravitational field, the rotation speed of the Earth, or seismic waves transmitted from or proximate to the Earth’s surface.

[0062] The anchor tool according to any of the above aspects may have any of the following exemplary features.

[0063] The tool may be for reacting torque from a drillstring to a wellbore. The tool may comprise: a channel for receiving a downhole portion of a drillstring so as to be rotationally engaged therewith: a gripper; and an actuator capable of being driven to cause the gripper to adopt at least one of (a) a first state in which it is urged outwardly for gripping the wellbore and (b) a second, passive state.

[0064] The tool may comprise an energy store. The actuator may be capable of being driven from the energy store to cause the gripper to adopt at least one of the first state and the second state. The energy store may be a reservoir of 11 pressurized fluid. The energy store may be a source of electricity.

[0065] The tool may comprise multiple segments disposed along the drillstring anchor, each segment comprising a respective gripper, the gripper of at least one segment being actuable independently of the gripper of at least one other segment.

[0066] The tool may comprise: a channel for receiving a downhole portion of a drillstring so as to be rotationally engaged therewith; multiple segments disposed along the drillstring anchor, each segment comprising a respective gripper and a respective actuator capable of being driven to cause the respective gripper to adopt at least one of (a) a first state in which it is urged outwardly for gripping the wellbore and (b) a second, passive state, the gripper of at least one segment being actuable independently of the gripper of at least one other segment; the multiple segments comprising a first segment and a second segment coupled to each other so as to permit relative longitudinal motion therebetween.

[0067] The tool may comprise: a channel for receiving a downhole portion of a drillstring so as to be rotationally engaged therewith; multiple segments disposed along the drillstring anchor, each segment comprising a respective gripper and a respective actuator capable of being driven to cause the respective gripper to adopt at least one of (a) a first state in which it is urged outwardly for gripping the wellbore and (b) a second, passive state, the gripper of at least one segment being actuable independently of the gripper of at least one other segment; the multiple segments comprising a first segment and a second segment, wherein the first segment can move longitudinally relative to the second segment.

[0068] The tool may comprise a drive mechanism for advancing the first segment downhole relative to at least the second segment. The drive mechanism may allow the first segment to be advanced downhole. For example, the drive mechanism may allow the first segment to be advanced downhole by a force exerted through the drillstring. The drive mechanism may be a hydraulic drive mechanism. However, in other examples, the drive mechanism may not be hydraulic. The drive mechanism may have other means of actuation in some embodiments. The drive mechanism may comprise multiple hydraulic cylinders, each cylinder comprising a chamber and a piston moveable within the chamber, each cylinder acting between the channel and a respective one of the first and second segments. A respective one of the hydraulic chambers or its respective piston may be fast with a respective one of the first and second segments. The drive mechanism may comprise multiple hydraulic cylinders, each cylinder comprising a chamber and a piston moveable within the chamber, each cylinder configured for acting between the downhole portion of the drillstring and a respective one of the first and second segments. A respective one of the hydraulic chambers or its respective piston may be fast with a respective one of the first and second segments. Each hydraulic chamber may house a portion of a linkage. The linkage may be a compliant linkage. The linkage may be fixedly connectable to the downhole portion of the drillstring. The linkage may be slidably connectable to one or more pistons. A respective piston may be movable relative to its respective segment.

[0069] The tool and the downhole portion of the drillstring may be compliantly couplable in the longitudinal direction so as to permit relative longitudinal motion of the downhole portion of the drillsting relative to the channel when the grippers of the first and second segments are gripping the wellbore. This connection may be via the linkage.

[0070] The tool may comprise a compliant member. Each hydraulic chamber may house a compliant member. The compliant member may allow axial movement of the downhole portion of the drillstring relative to the channel when the respective actuators of the first and second segments are driven to cause their respective grippers to grip the wellbore.

[0071] The first and second segments may be interlinked by a drive connector such that motion of one of the first and second segments in a direction relative to the channel causes motion of the other of the first and second segments in an opposing direction. The first and second segments may be interlinked by a drive connector such that motion of one of the first and second segments in a direction along the downhole portion of the drillstring causes motion of the other of the first and second segments in an opposing direction. The drive connector may be a hydraulic conduit. The drive mechanism may comprise a hydraulic circuit. The hydraulic circuit may be contained within the tool. The hydraulic circuit may not be fed from outside the drillstring anchor.

[0072] When the respective actuator of one or more segments of the multiple segments is driven to cause its respective gripper to grip the wellbore, the tool may be configured to restrict relative rotation between the drillstring and the wellbore.

[0073] The tool may be configured to allow relative axial movement of the downhole portion of the drillstring and the drillstring anchor when the respective gripper of one or more of the multiple segments is gripping the wellbore. The channel may be configured to engage with features on the exterior surface of the downhole portion of the drillstring. The channel may comprise multiple concave features configured to engage with protrusions on the exterior of the downhole portion of the drillstring. The first and second segments may each have a range of travel in a direction parallel to the longitudinal axis of the channel. The multiple segments may comprise at least two sets of segments. The grippers of each set of segments may be configured to be actuated simultaneously. The tool may comprise at least one energy store and each actuator may be capable of being driven from one or more of the at least one energy store to cause the gripper to grip the wellbore. When the or each actuator is driven to cause its respective gripper to grip the wellbore, the tool may be configured to restrict relative rotation between the tool and the wellbore. The or each gripper may be configured to exert an outward (radial) force on the wellbore relative to the longitudinal axis of the channel. The or each gripper may be capable of gripping the wellbore independently of whether drilling fluid is flowing through the drillstring. The channel may be configured to allow relative axial movement of the downhole portion of the drillstring and the tool. The channel may have a non-circular cross-section. The channel may be configured to engage with features on the exterior surface of the downhole portion of the drillstring. The channel may extend along the longitudinal axis of the drillstring. The housing of the drillstring anchor may comprise the channel.

[0074] The or each gripper may comprise at least one pad configured to move outwardly from the channel to engage the wellbore when the actuator of the respective gripper is driven to cause the gripper to grip the wellbore. The or each gripper may comprise a lever mechanism for exerting mechanical advantage to move each pad outwardly from the channel.

[0075] The tool may have a limit of travel along the downhole portion of the drillstring. The or each actuator may be configured to be driven to cause the gripper to not grip the wellbore when the tool reaches the limit of travel along the downhole portion of the drillstring.

[0076] The tool may further comprise a swivel located proximally of the or each gripper for allowing relative rotation between the channel and a section of the drillstring above the channel. Where there are multiple grippers in the drillstring anchor, the swivel may be located above the most proximal gripper (with respect to the surface of the wellbore). The swivel may be a unidirectional swivel.

[0077] The tool may comprise a gearbox. The gearbox may be a reduction gearbox so that the rotational speed of the drillstring is higher than the required drilling speed (and the torque is lower). The tool may apply weight-on-bit or depth-of-cut to a drill bit at the distal end of the drillstring. The motion of one segment relative to at least one of the other segments may be driven by means other than hydraulics. The tool may have a housing. The multiple segments may be mounted so as to be movable longitudinally relative to the housing of the tool. The tool may be configured so as to be activated and / or deactivated in response to a command from the surface of the wellbore. For example, in response to a command from the surface, an activation or deactivation signal may be received by the tool wirelessly or via a wired connection. When the tool is deactivated, all grippers of the drillstring anchor may be in their passive state. When the tool is deactivated, the tool may be configured so as to not restrict relative rotation between the drillstring and the wellbore.

[0078] One or more of the grippers and / or actuators may comprise a hydraulic piston. There may be a hydraulic feed to the hydraulic piston(s) within the housing of the tool between the channel and a respective segment. The tool may comprise a hydraulic unit for supplying hydraulic fluid to actuate to the hydraulic piston(s).

[0079] The tool may be configured such that when the actuator of one of the first and second segments is driven to cause its respective gripper to grip the wellbore, the other of the first and second segments is drivable to move longitudinally relative to the one of the first and second segments.

[0080] The tool may be configured to advance in the wellbore by performing the following steps in order:

[0081] (i) driving the actuator of one of the first and second segments to cause its respective gripper to grip the wellbore;

[0082] (ii) while that gripper continues to grip the wellbore, advancing the other of the first and second segments along the wellbore;

[0083] (iii) while that gripper continues to grip the wellbore, driving the actuator of the other of the first and second segments to cause its respective gripper to grip the wellbore; and

[0084] (iv) causing the actuator of the said one of the first and second segments to cause its respective gripper to release from gripping the wellbore.

[0085] The first and second segments may each have a respective range of longitudinal travel relative to a housing of the drillstring anchor. The first and second segments may each have a coupling for attachment to the downhole portion of the drillstring and a respective range of longitudinal travel relative to the coupling. The tool may be configured to trigger the actuator of one of the first and second segments to cause its respective gripper to grip the wellbore in response to the location of the other of the first and second segments in its range of travel. For example, the tool may be configured to trigger the actuator of one of the first and second segments to cause its respective gripper to grip the wellbore when the other of the first and second segments reached a predetermined distance before the end of its range of travel in the downhole direction.

[0086] The first and second segments may each have a respective range of longitudinal travel relative to a housing of the tool and the tool may be configured to advance in the wellbore by: when the actuators of both the first and second segments are being driven to cause their respective grippers to grip the wellbore and the downhole portion of the drillstring is advancing in the wellbore relative to the channel, releasing the gripper of the said one of the first and second segments before that segment reaches a limit of its range of travel whilst the gripper of the other of the first and second segments continues to grip the wellbore.

[0087] The first and second segments may each have a coupling for attachment to the downhole portion of the drillstring and a respective range of longitudinal travel relative to that coupling. The tool may be configured to advance in the wellbore by: when the actuators of both the first and second segments are being driven to cause their respective grippers to grip the wellbore and the downhole portion of the drillstring is advancing in the wellbore relative to the channel, releasing the gripper of the said one of the first and second segments before that segment reaches a limit of its range of travel whilst the gripper of the other of the first and second segments continues to grip the wellbore.

[0088] The actuators of both the first and second segments may be driven to cause their respective grippers to grip the wellbore and the downhole portion of the drillstring is advancing in the wellbore relative to the channel, the tool is configured to cause the gripper of the said one of the first and second segments to release the wellbore (in which it may adopt its passive state) in response to one or more of the following states:

[0089] (i) a position of the downhole portion of the drillstring relative to the channel (for example, when the downhole portion of the drillstring has moved longitudinally relative to the channel by a predetermined distance);

[0090] (ii) a time since the actuator of the other segment was driven to cause its respective gripper to grip the wellbore;

[0091] (iii) a gripper of the other segment being determined to be gripping the wellbore.

[0092] A gripper of the other segment may be determined to be gripping the wellbore when a target force of the gripper against the wellbore has been reached. When the gripper of the other segment is a hydraulically actuated gripper, the gripper may be determined to be gripping the wellbore when a target pressure level has been reached.

[0093] In the first state the gripper may be urged outwardly relative to a central axis of the drillstring locally to the gripper. In the second state the gripper may be located relatively inwardly of its position in the first state. The passive state may be a retracted state. In other implementations, there may not be a significant difference in the radial displacement of the gripper in the second state and the first state. The actuator may cause or permit the gripper to adopt the first state. The actuator may cause or permit the gripper to adopt the second state. The gripper may be biased to one of the states, e.g. by a resilient element such as a spring. The actuator may be capable of driving the gripper to the other of the states. The actuator may in some implementations be capable of driving the gripper to both of the states. For transitioning from the first state to the second state, the gripper may comprise a return spring. Alternatively, where the gripper is a piston, the piston may be double acting, or the absence of hydraulic power applied to achieve the first, outwardly-urged state may be sufficient to achieve the second, passive state. The tool may be for reacting torque from a drillstring to a wellbore during a drilling operation. The anchor tool may be for reacting torque from one or more of a drillstring, a drill bit and a drilling motor in a wellbore or borehole. The anchor tool may comprising at least two gripping bodies interlinked so as to be moveable longitudinally relative to each other, each gripping body having a gripper actuable to exert an outward force to grip an interior surface of the wellbore, the tool anchor having a splined hole (or channel) therethrough for rotational engagement with a drillstring, and the anchor tool being configured to advance along the wellbore by causing alternate ones of the gripping bodies to grip the interior surface of the wellbore whilst another of the gripping bodies advances along the wellbore. The gripping bodies may be interlinked by a hydraulic drive for driving relative longitudinal motion of the gripping bodies. Each gripping body may have an actuator for exerting an outward force on the gripper. The anchor tool may have a controller for operating the hydraulic drive and the actuators to advance the anchor tool along the wellbore. The controller may be configured so as to cause the anchor tool to advance both gripping bodies whilst maintaining at least one of the gripping bodies gripping the wellbore. In some embodiments, the gripping bodies may be interlinked by an intermediate member, each gripping body being coupled to the intermediate member by a mechanism that permits relative longitudinal motion of the respective gripping body and the intermediate member. The intermediate member may have the splined hole or channel therethrough. The splined channel may resist relative rotation of the anchor and the drillstring. The drillstring may be shaped so that a downhole part of the drillstring cannot pass through the drillstring channel. The drillstring channel may abut that downhole part of the drillstring when the anchor has advanced sufficiently in a downhole direction relative to the drillstring. Then, further downhole motion of the anchor tool can apply force in a downhole direction to the drillstring. This may apply weight-on-bit to a bit at the distal end of the drillstring.

[0094] According to a further aspect there is provided a system for drilling a borehole comprising a surface system, a drillstring, a bottom-hole-assembly (BHA), a drillstring anchor tool (which may have any of the features described herein), a drilling motor, and a drill bit. During operations the drillstring may be suspended from a drilling rig of the surface system. The surface system may be configured to rotate the drillstring, or hold it in a fixed rotational position. The surface system may be configured to deliver drilling fluid to the interior of the drillstring and / or to receive the drilling fluid from its return path through the annulus of the borehole. The surface system may also be configured to communicate, for example mono-directionally or bi-directionally, with one or more instruments and / or apparatus at the distal end of the drillstring (for example with the bottom-hole-assembly or with the anchor). The surface system may be configured to analyse and / or store information received from those instruments and / or apparatus, and optionally to further communicate with a remote control system.

[0095] The bottom-hole-assembly may, for example, comprise one or more drill collars, which may be sections of drill pipe with a larger outer diameter and metal thickness to deliver downward force to the bit and support compressive loads. The bottom-hole-assembly may comprise one or more modules known generically as logging-while-drilling (LWD) and measurement-while- drilling (MWD) apparatus. LWD modules can measure properties of the earth such as, but not restricted to, electrical, acoustic, magnetic resonance and nuclear properties. They may include capabilities for processing and storing the measurements, as well as communicating the measurements to the MWD module for further transmission to the surface equipment. The MWD module may comprise instruments to measure the earth’s gravitational and magnetic field from which, in combination with the longitudinal position of the measurement in the wellbore, the position of the instrument may be determined (known as direction and inclination (D&l) measurements) Additionally it may comprise instruments for measuring the pressure and temperature environment, stress state and dynamic motion of drillstring, such as but not restricted to thermocouples, strain gauges, pressure sensors, dynamic magnetomoters, accelerometers, and gyroscopes. The MWD system may be communicatively coupled to the surface system to communicate MWD and LWD measurements to the surface system, for example through a telemetry unit which can communicate through a number of possible methods, such as acoustic pressure (often referred to as mud-pulse), electromagnetic, or through drill pipe containing electrical conductors (wired-pipe). The MWD apparatus may be powered by stored electrical power, or through the use of a turbine in the flow path off drillingfluid. The MWD apparatus may also be configured to receive information transmitted from the surface, such as measurement of downhole flow rate (for which the turbine can be used in addition to its role in electrical power generation), or through electrical means using the electromagnetic MWD apparatus in a receiving role. The MWD apparatus may also comprise a computational processor whose primary purpose is to perform calculations on the data received from the measurement apparatus with the MWD and LWD apparatus, and calculations for the telemetry system, but which may also perform calculations on data derived from instrumentation of the anchor, and provide commands to the steerable system based on that data. Different components of the BHA may be above the anchor tool, between the anchor tool and the motor, or between the motor and the bit. The BHA may also comprise a steerable system. This may enable the drill bit to follow a trajectory determined at the surface, for example at the rig site, or transmitted from a remote control system. The steerable system may be rotating, and thus located below the drilling motor, or non-rotating, located either above the drilling motor or integrated within it. The steerable system may be communicatively coupled to the surface system (i.e. it may be configured to receive communications from the surface). The steerable system may be in communication with the MWD apparatus, or may possess independent means for receiving communications from the surface system. For the steerable system to be more effectively operated with an anchor rigidly attached to the borehole, the BHA may also contain one or more components with increased lateral compliance, known as flexjoints.

[0096] At the top of the BHA, or above the anchor if that is above the BHA, there may be a ball or dartcatcher, which can receive a ball or other object dropped from the surface, whose arrival triggers a downhole action, such as enabling or disabling the operation of the anchor. The anchor tool may be configured to apply weight to the downhole tool. The anchor tool may be configured to apply weight to the downhole tool to urge it against the bottom of the wellbore. The drillstring anchor may have any of the features described above. The downhole tool may be a drill bit and the anchor may be configured to apply weight-on-bit to the drill bit. The weight-on-bit may be applied from the anchor tool via the drillstring. The drillstring anchor tool may comprise: a coupling for coupling to a downhole portion of a drillstring; one or more grippers actuable to engage a wellbore; and a drive mechanism operable to act between the gripper(s) and the coupling for applying force in a downhole direction to the drillstring. The drillstring may comprise a linkage extending between the coupling and the gripper(s) through which axial rotation of the drillstring can be reacted against the grippers.

[0097] The drillstring anchor tool may have any of the features described above.

[0098] BRIEF DESCRIPTION OF THE FIGURES

[0099] The present invention will now be described by way of example with reference to the accompanying drawings.

[0100] In the drawings:

[0101] FIG. 1 (a) schematically illustrates an example of a drilling system, illustrated at a subterranean location in a wellbore during a downhole operation.

[0102] FIG. 1 (b) schematically illustrates a further example of a drilling system, illustrated at a subterranean location in a wellbore during a downhole operation.

[0103] FIG.s 2a)-2c) schematically illustrate an overview of the operation of an embodiment of a drillstring anchor tool.

[0104] FIG. 2d)-2e) schematically illustrates further examples of a downhole portion of a drillstring. FIG.s 3a) and 3b) shows a cross-sectional view of an example of a gripper comprising three pads.

[0105] FIG 4 schematically illustrates an example of a hydraulic system for driving an actuator of a gripper.

[0106] FIG. 5 shows an example of a sequence of events to re-set an anchor tool after reaching its limit of travel along the downhole portion of the drillstring.

[0107] FIG. 6 schematically illustrates an anchor tool comprising three independently actuatable gripping segments.

[0108] FIG.s 7a)-b) schematically illustrate a further example of a gripper comprising a hydraulically actuated piston assembly.

[0109] FIG.s 8a)-c) schematically illustrate further details of the hydraulically actuated piston of FIG.s 7a)-7b).

[0110] FIG. 9 schematically illustrates a further example of a drillstring anchor tool comprising multiple gripping segments.

[0111] FIG. 10 schematically illustrates an example of a hydraulic cylinder assembly of the drillstring anchor tool of FIG. 9.

[0112] FIG. 11 shows the steps of an exemplary drilling method for forming a wellbore in a rock formation using a drilling mechanism.

[0113] FIG. 12 shows the steps of an exemplary method for determining the rate of penetration of a drill bit in a wellbore.

[0114] FIG. 13 shows the steps of another exemplary method for determining the rate of penetration of a drill bit in a wellbore.

[0115] FIG. 14(a) and 14(b) schematically illustrate examples of a downhole tool comprising torque sensors.

[0116] DETAILED DESCRIPTION

[0117] FIG. 1 (a) shows an example of a drilling system illustrated at a subterranean location in a wellbore. In operation, a rig 101 provides support and / or power to a drillstring 102, which may comprise, for example, coiled tubing or conventional drill pipe. Weight-on-bit (WOB) is provided from the surface through the drillstring 102.

[0118] The wellbore is shown at 103. The wellbore may be at least partially lined with casing 104 and cement 105. The drillstring may provide torque and / or power (for example, rotary, thermal, and / or electrical power) to the bottom hole assembly (BHA), shown generally at 106. The BHA may comprise a tool or other component 107. The tool 107 may be a drilling tool. The tool 107 may be, for example, a drill bit. For example, tool 107 in FIG. 1 (a) may be a polycrystalline diamond compact (PDC) drill bit or a roller cone drill bit. Drilling fluid can be pumped to the component through the drillstring and released into the annulus of the wellbore, as shown at 109. The drilling fluid 109 acts to extract cuttings to the surface.

[0119] The BHA 106 can also comprise one or more additional components, shown at 108. The component 108 may be a downhole motor, such as a mud motor, for providing rotational drive to the tool. Alternatively, an electric motor or other type of motor may be used. Other additional components may be drill collars, stabilizers, reamers, hole-openers and bit subs.

[0120] The drilling fluid may be supplied to the tool from a tank 110 at the surface of the wellbore which is fed to the drillstring and the tool via pipes 111.

[0121] In the system shown in FIG. 1 (a), a drillstring anchor is illustrated at 112. The drillstring anchor 112 can transfer reactive torque from the BHA to the wellbore, as will be described in more detail below. This may help to prevent the initiation of torsional oscillations in the drillstring, including stick slip. The drillstring anchor is designed to remove at least some, and preferably all, of the torque from the drill string.

[0122] In the system described above with reference to FIG. 1 (a), the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit 107 below the anchor 112. However, the drillstring anchor described herein may be utilized in any other compatible operation or situation where it is desirable to transfer reactive torque in a wellbore.

[0123] FIG. 1 (b) shows a further example of drilling system illustrated during the process of drilling a borehole in a subterranean location, with exemplary components of the system shown in more detail. In Figures 1 (a) and 1 (b), 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. The rig 101 , provides support for the drillstring 102, which may comprise conventional drill pipe, or drill pipe that can transmit data and / or electrical power (for example, wired pipe). In this example, the drillstring is suspended from a travelling block 126, which is raised and lowered using the drilling line 125, which emanates from the cable drum 122. During drilling the release of cable, and hence the lowering of the drillstring, is controlled by a brake, which may either be operated by a human driller, or an automated controller (autodriller). Azimuthal positioning and rotation of the drillstring at surface may be performed by the top-drive 121 , positioned between the travelling block and the drillstring, although other means, such as a Kelly and rotary table are also possible. Drilling fluid is circulated through the drillstring via pipes and hoses 111 , from mud tanks 110 by fluid pumps 120. 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 autodriller, 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.

[0124] 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 drillstring to the drilling line (hook-load), the vertical motion of the top of the drillstring (the surface rate-of-penetration), the torque applied to and the rotation speed of the drillstring, and the flow rate and pressure of the drilling fluid at surface. This list is not exhaustive, and other parameters may be monitored.

[0125] The wellbore is shown at 103. The wellbore may be at least partially lined with casing 104 , which may be bonded to the formation 140 by cement 105. The drillstring may provide torque, rotation and / or electrical power to the BHA, shown generally at 106. The BHA may comprise a number of components, not all of which may be present in every BHA. The relative position and location of these components in the figure is purely illustrative and may differ in other examples. The exemplary BHA shown in FIG. 1 (b) comprises a source of electrical power, 131 , which in this example is shown as a fluid-driving turbine, the rotation of which generates an electrical current. Alternative sources of electrical power include batteries or capacitors, or an interface to wired pipe, 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 pump 120 through which information may be transmitted from the surface to the BHA. Above the turbine 131 in this example are drill collars, some of which may contain logging-while-drilling (LWD) tools 130 which can measure properties of the surrounding rocks such as resistivity, natural radioactivity, density, porosity, acoustic sound speed using a combination of measurement instruments and active emission of energy into the formation. Such LWD tools may be powered by the electrical power source 131 . The collars that do not contain LWD tools may provide downward force (weight) on the drill bit 107 at the distal end of the drillstring. Other components of this section of drillstring may include jars, to disturb the BHA should it become stuck, and / or a ball or dart catcher, the operation of which may enable or disable the operation of other BHA components, such as the anchor 112. Below the electrical power source 131 is located in this example measurement while drilling (MWD) apparatus 132, which contains 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 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 pipe 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 wellbore. 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.

[0126] Below the anchor 112 is shown a mechanical component 133, part of which has a more lateral flexibility than drill-collars, for instance by including a section with a reduced diameter, known as a flex-joint, in order to allow the components below the anchor 112 to generate or maintain a slightly different inclination or azimuth to the anchor 112. It may not be necessary for the flexjoint to be present.

[0127] In the exemplary drilling system shown in FIG. 1 (b), a steering device 134 is shown both above and below the drilling motor 108. The steering device can utilise some combination of force applied to the wellbore, or curvature of the drillstring in order to control the direction of the drill bit 107. If the steering device is below the motor 108, where rotation is continuously present, the device may be configured to maintain the orientation of the directional control despite this rotation (rotational steerable system). Two steering devices are shown only for exemplary purposes. In some practical examples, either one or neither may be present. The steering device(s) may be communicatively coupled to the surface. This may allow the steering device(s) to receive commands transmitted from the surface, which may allow the drill bit to be urged to follow a desired trajectory.

[0128] Below the anchor 112 there may be a drilling motor, for example a positive-displacement-motor.

[0129] Other drilling motors may also be used, such as a drilling turbine, or an electrical motor, through which rotation is applied to the drill bit 107 and any other components below the motor. In this example further drill collars 135 are shown below the motor, which may be a combination of collars to provide weight, LWD collars, MWD apparatus and telemetry and power generating means. The system 135 may communicate directly with the surface, or to the other MWD system 132 using short range communication.

[0130] The section of drill collars 135 may also comprise an under-reamer. In the absence of the drill collars 135, the steerable system 134 may be integrated into the non-rotating housing of the drilling motor 108.

[0131] In addition to the elements shown, the BHA may contain other elements, such as stabilisers, which aid in the maintenance of rotation stability and directional control.

[0132] FIG.s 2a), 2b) and 2c) show an overview of the operation of an embodiment of a drillstring anchor 200. The drillstring anchor 200 comprises a channel 201 for receiving a downhole portion of a drillstring 202. The longitudinal axis of the channel is indicated at 203. The downhole portion of the drillstring 202 is rotationally engaged with the channel 201 of the drillstring anchor 200 so that in at least one direction one cannot rotate relative to the other.

[0133] In the preferred implementation, the channel has a non-circular cross-section. The channel may be configured to engage with features on the exterior surface of the downhole portion of the drillstring. For example, the section of the drillstring which is engaged by the channel may be a part of the drillstring having a non-circular cross-section. That part of the drillstring may be termed a downhole Kelly. The cross-section of the downhole Kelly perpendicular to the longitudinal axis of the drillstring may, for example, be hexagonal. The anchor therefore has a continuation of the drillstring (which runs from an upbore location, such as from the surface, to the BHA) running through it.

[0134] In this description the terms downhole Kelly or Kelly are used to mean the downhole portion of the drillstring that is associated with the drillstring anchor. These terms may be used interchangeably. This includes the section along which the anchor slides plus features either side of this section that are used by the anchor, for purposes such as to activate or deactivate the anchor or to pressurise the hydraulic system, where present.

[0135] In some exemplary embodiments described herein, the cross-section of the downhole portion of the drillstring is a regular hexagon. However, a downhole Kelly with another non-regular shape in longitudinal cross-section, such as a non-equal hexagon, a polygon of another degree such as a square, or a circle into or from which one or more splined channels or ribs extend, may alternatively be used. This may allow for a larger radial gap in which to house the gripper and actuator components. Other shapes are also possible. For example, the downhole portion of the drillstring (and / or the channel) may have a helical form. In some circumstances, the downhole portion of the drillstring may comprise conventional drill pipe.

[0136] In one particular embodiment, as schematically illustrated in FIG. 2d), the downhole portion of the drillstring comprises a tubular shaft having a circular cross section. The shaft may have a single piece constructions ora multi-piece construction. In this example, the shaft 206 comprises an inner shaft 207 and an outer shaft 208. Both the inner shaft 207 and the outer shaft 208 are tubular and the inner shaft sits concentrically inside the outer shaft with sealing contact between the inner shaft and the outer shaft. The inner diameter of the shaft 206 defines a passageway 209 for drilling fluid to travel from the surface of the wellbore to the drill bit at the bottom of the drillstring. The downhole portion of the drillstring may also comprise one or more fluid passageways through which hydraulic fluid for actuating the grippers of the drillstring anchor can flow. The fluid passageways may be located between the inner diameter and the outer diameter of tubular shaft 206. This may be achieved by one or both of the inner shaft 207 and the outer shaft 208 having grooves which can act as fluid passageways when the inner shaft and the outer shaft are sealed together. This may avoid excessive machining of the downhole portion of the drillstring to accommodate the fluid passageways.

[0137] In this example, the downhole portion of the drillstring comprises protrusions 210 which engage with corresponding features of the channel of the drillstring anchor to transmit torque from the drillstring to the anchor. In the example of Figure 2(d), the protrusions are keyed protrusions or keys 210 which are engaged with channels (or keyways) 211 in the shaft 206 of the downhole portion of the drillstring.

[0138] A further example where the downhole portion of the drillstring comprises protrusions 210 for transmitting torque to the drillstring anchor is shown in FIG. 2e).

[0139] The downhole portion of the drillstring having a circular shaft 206 may make it easier to implement sealing solutions, thus allowing greater control of sliding friction between the downhole portion of the drillstring and the drillstring anchor.

[0140] The downhole portion of the drillstring may also comprise one or more linear bearings for preventing rotation between the channel of the drillstring anchor and the downhole portion of the drillstring. The one or more bearings may comprise rolling elements such as recirculating or caged rollers or balls, or may comprise rollers on posts.

[0141] In the preferred implementation, the drill bit 204 is driven to rotate by a downhole mud motor (not shown in FIG.s 2a)-2c)) to form the wellbore in the formation 205. Therefore, the downhole section of the drillstring that is engaged by the channel is not driven to rotate and is rotationally engaged with the channel of the anchor. Where the drillstring comprises a motor for rotating the bit, the anchor is configured to be mounted on a section of the drillstring 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.

[0142] As will be described in more detail below, the drillstring anchor comprises a gripper that can be activated by an actuator driven from an energy store. 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 wellbore and a second, passive state. When activated, the gripper can grip the wellbore. The gripper is configured to exert an outward force on the wellbore relative to the longitudinal axis of the channel. As a result, when the gripper is activated, relative rotation between the drillstring and the wellbore is resisted and this can allow torque to be reacted to the wellbore.

[0143] Throughout this description, the term ‘activated’ is used to mean that an actuator 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 it can cause its respective gripper(s) to grip the wellbore. The term ‘deactivated’ is used to mean that an actuator of the anchor (or a segment of the anchor) is in a state where it is not suitable for causing its respective gripper(s) to grip the wellbore. In this state it may not be urged outwardly relative to the central axis. In the activated state the actuator may be in a location radially outwardly of its location in the deactivated state. The actuator may be biased to one of the states, e.g. by a spring.

[0144] The energy store provides the energy supply to one or more actuators. 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 drillstring 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 wellbore 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 one preferred 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 be activated and deactivated without using the use of mud flow, mud pressure, or mud pulses and / or without using electronics.

[0145] When the anchor is activated (i.e. when the actuator is driven to cause the gripper to grip the wellbore), the drillstring is free to move along its longitudinal axis with respect to the anchor. The channel is configured to allow relative axial movement of the downhole portion of the drillstring and the anchor. 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 wellbore).

[0146] When the anchor is activated, relative rotation between the anchor and the wellbore can be resisted or restricted. This may be due to physical engagement between the anchor and the interior face of the wellbore. Optionally the anchor may be controlled to permit limited rotation between the Kelly and the anchor, whilst the anchor is activated. This may, for example, assist with steering the drillstring.

[0147] 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 wellbore. 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 wellbore. 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 wellbore, or the furthest reach of the wellbore, 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.

[0148] In FIG 2a), the gripper of the anchor has been activated to grip the wellbore. The section of the drillstring with which the anchor is rotationally engaged, which in this example is a downhole Kelly, can move axially relative to the anchor. This allows the drillstring to advance downhole whilst the anchor is in its activated state.

[0149] The anchor interacts with a specific section of the drillstring (for example, the downhole Kelly in the example show in FIG.s 2a)-2c)). The anchor can move along this downhole portion of the drill string. The anchor may be free to slide relative to the downhole Kelly along the longitudinal axis of the Kelly, conveniently within certain positional limits. In this example, the anchor has a positional upper limit (furthest from the bit) and lower limit (closest to the bit) along the downhole portion of the drillstring. In FIG. 2a), the anchor is positioned at its lower limit on the downhole portion of the drillstring. In FIG. 2b), the anchor has reached the upper limit of its travel along the downhole portion of the drillstring, as the drillstring has moved downhole relative to the anchor. At this point, the anchor can be deactivated and then reset.

[0150] In FIG. 2c), the anchor has been positioned at its lower limit and is re-activated and the drillstring can then continue to advance downhole while the gripper of the anchor grips the wellbore so as to restrict relative rotation between the anchor and the wellbore.

[0151] The gripper of the anchor may comprise at least one pad configured to extend in a circumferential direction to engage the wellbore. The at least one pad may be configured to move outwardly from the channel of the anchor to engage the wellbore when the actuator of the respective gripper is driven to cause the gripper to grip the wellbore (i.e. when the anchor is activated).

[0152] FIG.s 3a) and 3b) show one example of a gripper of the anchor and its respective actuator. In this example, the gripper comprises three pads 301 , 302, 303 which are hydraulically actuated. The channel of the anchor is indicated at 304. The channel receives the downhole portion of the drillstring. In this example, the channel and the downhole portion of the drillstring have hexagonal cross sections. In FIG. 3a) the pads are in a deactivated configuration. Each pad 301 , 302, 303 has a lever that can exert a mechanical advantage on its respective pad. In this example, the mechanical advantage is greater than 1 . This reduces the pressure / force needed to activate the pads and may ensure that they have sufficient torque capacity. This can also reduce the size and number of actuating pistons and the size of the actuating system and re-charging system.

[0153] The pads are preferably actuated using stored energy (hydraulic or electrical). For example, hydraulic pressure can be applied to pistons acting on three equally spaced pad levers with a 2:1 mechanical advantage. The pads grip the wellbore, resisting rotational and linear sliding movement of the anchor.

[0154] FIG. 3b) shows pad 301 and its actuator in the activated configuration. Each pad has a pivot, shown at 305 for pad 301 . An actuating piston or cylinder 306 pushes the pad outwardly from the channel 304 onto the wellbore. In this example, the piston is not directly connected to the anchor but has a dome, shown at 307, that has a hard-wearing sliding contact with the underside of the pad 301. Alternatively, a direct / non sliding connection may be used between the two with a two-part hinged connecting rod. Pressure-relief valves can be used to set the working pressure and / or prevent over-pressurisation. The pads may also be articulated to increase the contact force between the pad and the wellbore.

[0155] The cross-sectional shape of the pads may be chosen in dependence on the direction of loading. The shape of the pads may also be chosen in dependence on the properties of the rock or wellbore, including well anticipated curvature.

[0156] With the drill bit usually rotating in a clockwise direction, the orientation of the pads can be trailing or leading the direction of applied torque. The “leading” direction (as shown in FIG 3a) is selftightening and may require less force to provide a given torque capacity. In the “trailing” direction (i.e. in the opposite orientation to that shown in FIG. 3a)), there is a lower load on the pivots, but having the pads in this orientation requires a higher activation force.

[0157] A pad may comprise teeth that provide resistance and allow the pad to grip the wellbore. 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 wellbore. 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.

[0158] 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.

[0159] FIG. 4 schematically illustrates an example of a hydraulic system for driving the actuator of a gripper. The anchor paddle or lever 401 actuates the pad 402. The actuating piston is shown at 403. The inlet and outlet of the control valve are shown at 404 and 405 respectively. An accumulator is shown at 406 and the pressurising system at 407. The reservoir of hydraulic fluid is shown at 408. The Kelly is shown at 409.

[0160] The hydraulic system may therefore comprise a hydraulic reservoir (at ambient pressure), a pressuring system and a high-pressure reservoir (such as an accumulator). The pads may be controlled via one or more hydraulic valves, for example using push rods linking switching features.

[0161] In some embodiments, the reservoir of hydraulic fluid may be re-charged during its operation via interaction between the anchor and the moving drillstring. The charging system may use one of the resources that is readily available downhole, such as the weight of the BHA. More specifically, as drilling continues and while the anchor is still gripping the wellbore, it may use features on the downhole portion of the drillstring to push or press on at least one piston that forces high pressure fluid into the accumulator (such as a taper in the Kelly, as shown in FIG. 4).

[0162] The hydraulic fluid may, for example, be a conventional hydraulic fluid, water or drilling mud. In the case of water or drilling mud, the system may be open, venting into the wellbore. Typically, hydraulic cylinders are cylindrical. However, in downhole tools there is often extremely limited radial space in which to package the tool. For example, for a 150mm diameter tool, the downhole portion of the drillstring may be over 95mm in diameter, leaving a small radial gap. Cylinders that are toroidal in cross section may be convenient for packaging the hydraulics. The hydraulic system therefore preferably comprises toroidal chambers (for the pressurising cylinder, accumulator and low-pressure reservoir), which is a good use of space in the anchor. As discussed above, the channel of the anchor is preferably configured to engage with features on the exterior of the downhole section of the drillstring. This may allow the downhole portion of the drillstring to be rotationally engaged with the channel.

[0163] In some embodiments, the channel of the anchor may also be configured to axially lock or hold the anchor to the downhole portion of the drillstring when desired. In the absence of excessive friction, the anchor should slide down to the bottom of the downhole portion of the drillstring when the anchor is in its deactivated state. However, friction between the anchor and the wellbore and / or the downhole portion of the drillstring may prevent the anchor from sliding down the downhole portion of the drillstring. The anchor may have an actuator that can lock it longitudinally to the drillstring. The anchor may then be used to apply drillhead pressure.

[0164] There may be high lateral forces at the contact points / lines / areas between the channel and the downhole portion of the drillstring. For a portion of the drillstring with a hexagonal cross-section, the contacts are line contacts. In some embodiments, the downhole portion of the drillstring may be machined so that there are rectangular contact areas, or rollers may be incorporated to aid sliding between the channel and the downhole portion of the drillstring.

[0165] In order to aid the transfer of axial force along the drillstring in the absence of overall rotation, the drillstring at surface may be alternately rotated slowly in forward and backward (i.e. clockwise and anti-clockwise) directions, in a method known as ‘pipe-rocking’. Alternatively, or additionally, a device may be located along the drillstring, at some distance, for example 500m, from the bit, which generates cyclical axial motion from the flow of drilling fluid.

[0166] In some embodiments, the downward motion of the anchor can be powered. In some embodiments, there may be a locking or gripping mechanism between the anchor and the downhole portion of the drillstring. By providing a mechanism for enabling interaction or grip between the anchor and the downhole portion of the drillstring, this can allow the anchor to be moved to its new anchoring position by lowering the downhole portion of the drillstring relative to the anchor.

[0167] One way of controlling the position of the anchor relative to the downhole portion of the drillstring is to use a grip mechanism that can lock or hold the anchor at the “Start Position” (for example, at the lower positional limit, nearest the drill bit) of the downhole portion of the drillstring. This may be used to reliably re-set the anchor during a normal drilling operation and / or after running into hole (RIH) from the surface. One sequence of events to re-set the anchor 200 is given below, as shown in FIG. 5. In this example, the downhole portion of the drillstring 202 is a downhole Kelly. The longitudinal axis of the channel of the anchor is indicated at 203. FIG. 5 shows the Kelly as having a tapered shape. However, the Kelly need not be tapered.

[0168] Stage 1 : Movement - anchor at end of stroke (i.e. the anchor has reached the upper limit on the downhole portion of the drillstring);

[0169] Stage 2: Control - activate the anchor to grip the wellbore;

[0170] Stage 3: Movement - once anchor has reached lower limit, lift drillstring, re-set anchor position on Kelly (whilst anchor is activated);

[0171] Stage 4: Control - 1. Deactivate anchor, 2. Set grip mechanism;

[0172] Stage 5: Movement - lower drillstring and tag bottom of wellbore;

[0173] Stage 6: Control - release grip mechanism.

[0174] Only a low-pressure activation of the anchor is needed during Stage 3 movement, though full pressure activation may alternatively be used.

[0175] The process of RIH is performed as quickly as possible, therefore run-in-hole speeds of over 1 m / s are common. At surface, the anchor may be positioned at the lower end of the Kelly. However, high run-in speeds may generate high frictional loads between the anchor and the wellbore, which may push the anchor up the Kelly.

[0176] The anchor may naturally scrape “filter cake” or small debris from the wellbore. Therefore, after RIH the anchor may be at the upper end of the Kelly with a build-up of debris immediately below it, preventing it from sliding under its own weight. Therefore, it may be desirable that the position of the anchor is not controlled or fixed while RIH, but a grip mechanism be used for re-setting the anchor.

[0177] One option for the grip mechanism may use a spring-loaded ball that engages with the groove. This is a simple self-locking mechanism to overcome friction between the anchor and the wellbore while the system is lowered to the bottom of the stroke. The ball may be disengaged from the groove by applying a sufficient axial load.

[0178] The grip mechanism is preferably located at the lower end of the downhole portion of the drillstring (the end closest to the bit), but it could be located anywhere along the anchor and Kelly. For a multi-sided Kelly (e.g. hexagonal), there may be one mechanism per side of the Kelly (i.e. 6 in total for a hexagonal Kelly). Alternatively, a pressurising cylinder may be used. This is a similar arrangement to the solution above, but uses the piston / cylinders of the anchor’s pressurising system (if one is included). A shut off valve may be used to lock the piston in the “engaged” position. Alternatively, a rachet system may be used to grip the Kelly.

[0179] FIG. 6 illustrates one implementation where multiple drillstring anchors 200 are used along the downhole portion of the drillstring 202. Each anchor can be selectively activated and deactivated, as described above. The operation of the multiple anchors may be synchronised. The use of multiple anchors may allow a greater force to be exerted on the wall of the wellbore and may allow for a greater amount of torque transfer. The multiple anchors may be selectively activated and deactivated such that one or more of the anchors is in its activated state at one time. This may allow for a serial or parallel gripping action on the wellbore.

[0180] In the following examples, the gripper(s) of the anchor may be activated from an energy store, as described above, or by using energy generated as a result of the operation of the drillstring. For example, the anchor may be activated by drilling mud pressure, mud flow (either directly or via a mud powered device), by turning the drillstring, or by axial movement of the drillstring.

[0181] The anchors described herein can allow for a continuous gripping action as the drillstring advances downhole in the wellbore. 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 channel 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.

[0182] 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 wellbore and the downhole portion of 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 downhole portion 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.

[0183] Generally, the following sequence of steps is performed:

[0184] -a first segment (or set of segments) is activated to grip the wellbore;

[0185] -the downhole portion of the drillstring and a second segment (or set of segments) are driven to progress them downhole. In the preferred embodiment, the second segment (or set of segments) progress at a different (faster) speed than the downhole portion of the drillstring, for example at twice the ROP of the drill bit;

[0186] -a second segment (or set of segments) is activated to grip the wellbore;

[0187] -the first segment (or set of segments) is deactivated and driven to progress down the wellbore with the downhole portion of the drillstring.

[0188] The anchor may comprise a means of or mechanism for advancing deactivated segments downhole at a higher rate than the advancement of the downhole portion of the drill string (for example, at twice the ROP of the drill bit).

[0189] All embodiments of the anchor described herein may be powered by an energy store, as discussed above, or by some other means. For example, the anchor may be powered by hydraulic fluid from a pump driven by the mud motor. Alternatively, a hydraulic accumulator may be used with enough stored energy for a drilling trip. Alternatively, a pump may be driven by rotation of the drill string, or by axial movement of the anchor relative to the downhole portion of the drillstring. Alternatively, a pump may be driven by a secondary small mud motor. Alternatively, the anchor may be activated by mud pressure differential, rather than having its own hydraulic system.

[0190] 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).

[0191] 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. The anchor may be deactivated when it reaches that end of the “working section” of the downhole Kelly. The anchor may be de-activated when the tool is lifted up in the hole. This can help to ensure the tool can be pulled out of the well. The activation or deactivation of the segments(s) may be triggered by using the relative position between Kelly and tool and / or, changes in axial loading of the Kelly (i.e. as a result of applying WOB). These relate directly to the drilling process. Alternatively the activation may be controlled via mud pumps, mud pulse or electrically (e.g. using “wired” pipe).

[0192] The anchor may comprise a mechanism for enabling the deactivation of the gripper(s) when lifting the drillstring (for example, when pulling out of hole). For example, the anchor may comprise a mechanism that depressurises the pad actuators to deactivate them when the anchor is pulled up by the drillstring. When the anchor is powered using a hydraulic or electric energy store, gripper activation may be disabled when pulling out of hole, even when the drilling mud pumps are running, for example to assist in cleaning the wellbore of cuttings.

[0193] When using mud pressure as the source of power, there may be a dump valve in a top sub to vent the driving pressure into the wellbore. This can deactivate the anchor during tripping, if oneway valves are not used.

[0194] In some circumstances, there may be a washout in the wellbore directly in the zone where the anchor is to be deployed. The gripper may be configured to measure the force acting on it when it is activated to grip the wellbore. If a washout is identified by measurement of these forces (for example, if the diameter of the wellbore has been increased as a result of the washout and the grippers cannot extend sufficiently radially to achieve an adequate gripping force), the anchor may be re-positioned some distance away from the original zone to try to obtain a higher gripping force in another section of the wellbore.

[0195] Using the drillstring anchor, the direct result (for example, when using a means such as a downhole motor for driving bit rotation) would be that the drillstring above the anchor does not rotate during drilling. This may not be desirable in certain situations, where the low-speed axial movement of the drill string down the hole may result in an erratic motion and transfer of weight to the drill bit. The lack of rotation of the drillstring above the anchor may also, in some cases, make a situation known as “differential sticking” more likely. This is a condition where a section of the drill pipe becomes pushed against the wellbore in such a way that it gets stuck fast, and retrieval of the drill string from the wellbore may be extremely difficult. Therefore, in some implementations there may be a swivel located at the proximal end of anchor, allowing the drillstring to be rotated from the surface. The rotational speed of the drillstring may then be independent of (or at least different to) the speed of the drill bit.

[0196] The swivel may be a lockable feature. This would allow the use of a steerable motor above the bit. Such a device may require the drill string to be rotated in order to point or orientate the bend of the motor and thus drilling in a specific direction according to the required trajectory of the well.

[0197] One illustrative way of doing this may be to have a short sliding section, the bottom of which is splined. When there is compression in the unit, the splines are dis-engaged and the swivel can rotate. When the drillstring is pulled up, the splines engage and so lock the swivel. Thus, rotation of the drillstring from the surface will turn the motor body, which may enable the driller to orientate the bend and control the direction of the well.

[0198] Therefore, in some embodiments, there may be a swivel located at the proximal end of the drillstring anchor (i.e. proximally of the or each gripper) configured to allow relative rotation between the channel and a section of the drillstring above the channel. This can allow rotation of the drill string above the anchor to reduce friction between drill string and wellbore. This may improve the transfer of WOB and reduce the likelihood of getting stuck in hole. The swivel may be configurable so as to allow relative rotation between the channel and the section of the drillstring above the channel in a predetermined rotation direction. The swivel may allow relative rotation between then channel and the section of the drillstring above the channel in one rotation direction only (i.e. it may be a unidirectional swivel). One consequence of using a swivel, in some circumstances, is that it can break the relationship between the drillstring and the bit. It can create two separate sections of the drillstring, with the rotation of each section being used for a different function. A drillstring anchor as described herein may be utilized in one or more sections. In one embodiment, the lower section may have an anchor with a straight channel and the upper section may have an anchor with a helical channel. This would be equivalent to feed rate on a lathe and drillstring rotation would advance the drill bit through the anchor. Therefore, the DOC of the drill bit could be controlled using a coordination of the rotation and axial movements of the upper section of the drillstring.

[0199] In some embodiments, the anchor may house a reduction gearbox so that the drillstring speed is higher than the required drilling speed and the torque is lower. This may also reduce drill string wind up and mitigate stick slip. This may also allow the anchor to be used for energy generation downhole, for example for hammering. The drillstring anchor described above may be implemented in oil and gas drilling operations, geothermal drilling operations, plug and abandonment operations, or any other suitable operation. The operation need not be subterranean. The anchor described herein may be part of a drill string comprising one or more of a mechanical drill bit, a thermal-based drill bit, a plasma drill bit, a rotary steerable system, a measurement-while-drilling tool, a logging-whilst-drilling tool, a milling tool, a perforation gun, a drill collar, a stabilizer, a reamer, a hole-opener and a bit sub.

[0200] In some implementations, WOB may be imposed at the anchor rather than at the surface. As an alternative to WOB, depth of cut (DOC) could be imposed at the anchor.

[0201] In some embodiments, the anchor may comprise a mechanism to release the grippers from the rest of the anchor, for example in the case that the anchor becomes stuck in the hole. Radial forces may cause worsening of the borehole stability and cause the anchor to become stuck in some rare occasions. Therefore, there may be a mechanism for separating the gripper(s) from the rest of the anchor.

[0202] In an alternative implementation, the drillstring anchor comprises pistons which are capable of being urged outwardly for gripping the wellbore from a passive state to an activated state. The pistons are preferably hydraulically actuated. The pistons can move relative to the body of the drillstring anchor in a direction perpendicular to the longitudinal axis of the drillstring 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 wellbore. In other words, the grippers can move in a radial direction relative to the longitudinal axis of the drillstring anchor.

[0203] There may be multiple gripping assemblies each comprising a piston along the length of the drillstring anchor. There may be multiple gripping assemblies each comprising a piston distributed around the circumference of the drillstring anchor. For example, there may be four rows of twenty gripping assemblies.

[0204] One example of a gripping assembly comprising a hydraulic piston is shown in FIG.s 7a) and 7b). In FIG. 7a) the piston is in its passive position (which in this example is a retracted position) and in FIG. 18b) the piston is in an extended position in which it is urged outwardly from the body of the drillstring anchor to cause the end of the piston to grip the wellbore. The body of the drillstring anchor is indicated at 1800. The gripper assembly 1801 sits in a recess in the body 1800 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 1800 of the anchor.

[0205] The gripper assembly 1801 comprises a housing 1802 that sits in the recess in the body 1800. The piston 1803 is accommodated in the housing and can move outward relative to the housing. The piston 1803 can move in the radial direction with respect to the longitudinal axis of the drillstring 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 1804 in the housing in which a flange 1805 at the base of the piston 1803 can run. The groove has an end stop 1806 which limits the travel of the piston 1803 in the housing 1802, as illustrated in FIG. 7b).

[0206] In this example, there are movement of the piston 1803 is supported in the recess in the housing 1802 by bearings 1808, 1810 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 1802 and the piston 1803. There may alternatively or additionally be one or more seals disposed around at least part of the piston. For example, in FIG. 7(a) and 7(b) seals 1807 and 1809 are circumferential seals around the piston housing.

[0207] 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.

[0208] In the example of FIG.s 7(a) and 7(b), the gripper assembly 1801 comprises a return spring 1812, which can allow the piston 1803 to be returned to its passive state when the drillstring anchor is at the surface of the wellbore and there is no acting pressure differential between the body of the anchor and the annulus of the wellbore.

[0209] In this example, the end of the piston 1803 has an insert 1811 which engages the wellbore to grip the rock. In other examples, the end of the piston 1803 may engage the wellbore 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 wellbore. In the following examples, the piston has an insert at the end of the piston for gripping the wellbore. 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 drillstring 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 wellbore) to reach the wall of the wellbore. The pistons may be capable of deforming elastically when they are urged outwardly to contact the wellbore. 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 wellbore.

[0210] In this implementation, hydraulic fluid bears on the piston directly. In one example, hydraulic fluid (for example, oil) enters the piston from an annulus around the shaft of the downhole portion of the drillstring. The hydraulic fluid may be supplied to the pistons via fluid passageways in the downhole portion of the drillstring, as described above with reference to FIG. 2d).

[0211] The gripper assembly 1801 may also be removable from the body 1800 of the drillstring anchor in one piece for easier serviceability and replacement of individual grippers as and when required. The gripper assembly 1801 may be a removable cartridge comprising a piston and a housing. The gripper assembly 1801 may screw into the recess in the body 1800 of the drillstring anchor for fast replacement of the gripper assembly 1801 at service.

[0212] As mentioned above, each gripper may have an insert 1811 at the contact face for engagement with the wellbore. The insert may be separate to the body of the piston 1803 on which the hydraulic fluid acts. Preferably, the surface of the insert is not flat and / or not smooth. The material of the insert is preferably harder than the rock on which the drillstring anchor acts. Such inserts may conveniently elevate the level of friction achieved during contact between the grippers and the wellbore by a factor of more than 3 or 4 (for example, from simple friction to include a “scratch” type friction).

[0213] Preferably, there are multiple points of contact between the gripper and the wellbore. The contact stress between a point of contact between the gripper and the wellbore is preferably above the compressive strength of the rock forming the wellbore wall. This may also allow lubricant and rock dust from previous gripping events to have a passageway through the contact face so that it can be pushed aside and not prevent contact between the gripper and the wellbore.

[0214] One example of a piston with an insert is shown in FIG.s 8a)-8c). Diameters shown in FIG. 8(c) are exemplary. The piston is cylindrical with a circular-cross section. The base of the piston has a flange 1805 for limiting the travel of the piston within the housing, as described above. The opposite end 1812 of the piston to the base has a chamfered profile. As shown in Figure 8c), the piston is hollow to optionally accommodate spring 1812 and defines a chamber for hydraulic fluid. In this example, the gripper comprises a hardened insert 1811 (made from, for example, T ungsten 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 wellbore when the piston is in the extended position). 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 wellbore. 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.

[0215] In the example shown in FIG.s 8a)-8c), the piston has a circular cross-section for ease of manufacturability. However, the pistons may alternatively have a differently shaped crosssection, such as square or hexagonal.

[0216] The direct-acting piston can allow for greater stroke allows operation in larger oversized holes than a paddle design can achieve. Furthermore, individual pistons actuated from a common hydraulic source can better conform to deviations in the well bore wall than grippers having paddles, potentially increasing the area of the gripper in contact with the wellbore. The removable gripper assembly and reduced number of parts additionally allows for easier serviceability.

[0217] On one drillstring anchor tool having multiple grippers, there may be different designs of gripper on one tool. This may allow the drillstring anchor to effectively act on different types and strengths of rock that may be encountered in the formation during the drilling operation.

[0218] FIG. 9 shows a further example of a drillstring anchor. In this example, the drillstring anchor 2000 comprises multiple segments 2001 , 2002 each comprising one or more grippers. For example, each segment may comprise multiple grippers of the type described above with reference to FIG.s78(a), 7(b) and / or 8. The segments 2001 , 2002 can be moved relative to one another using a walking mechanism. In this embodiment, the drillstring anchor uses a hydraulic walking mechanism to move the segments and their associated gripper(s) down the wellbore as drilling progresses.

[0219] As shown in FIG. 9, the drillstring anchor 2000 comprises a first gripping segment 2001 and a second gripping segment 2002. In this example, the gripping segment 2001 comprises an upper gripper set and the gripping segment 2002 comprises a lower gripper set (‘upper’ and ‘lower’ being relative to the bottom of the wellbore). The segments 2001 and 2002 are each connected to hydraulic cylinder assemblies 2005 and 2009, 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 downhole portion of the drillstring causes corresponding movement of the respective gripping segment.

[0220] An optional sensor 2116 is shown on one of the grippers, which will be described in more detail below.

[0221] Connector 2003 is an upper connector for connection to drill pipe or an upper part of the BHA. Connector 2010 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 drillstring anchor to the adjacent sections of the drillstring.

[0222] Unit 2004 is a hydraulic unit configured to provide hydraulic power for actuating the grippers of gripper segments 2001 and 2002. In this example, the hydraulic unit 2004 does not provide hydraulic power to the drive mechanisms of the gripping segments (hydraulic cylinder assemblies 2005 and 2009) and the hydraulic power supplied to the units 2005, 2009 is passive and on a separate circuit. Connections between the hydraulic unit 2004 and the grippers may be provided by galleries within the units 2001 , 2002, 2005, 2006 and 2008.

[0223] 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 2005. The cylinder assembly 2005 controls the movement of the first gripping segment 2001 relative to the housing of the anchor. The cylinder assembly 2005 drives the first gripping segment 2001 to move relative to the second gripping segment 2002. A second cylinder assembly is shown at 2009. The cylinder assembly 2009 controls the movement of the second gripping segment 2002 relative to the housing of the anchor. The cylinder assembly 2009 drives the second gripping segment 2002 to move relative to the first gripping segment 2001 .

[0224] Unit 2006 is an upper key housing which contains galleries connecting the cylinder assemblies 2005 and 2009. Unit 2008 is a lower key housing which contains galleries connecting cylinder assemblies 2005 and 2009. The key housings 2006, 2008 are configured to engage with the downhole portion of the drillstring, which may have corresponding keyed protrusions as shown in FIG.s 2d) and 2e) which engage with the key housings. Hoses 2007 connect the hydraulic cylinder assemblies 2005, 2009 of the upper and low gripping segments 2001 , 2002 and provide the actuation and return hydraulic feeds to these units 2005, 2009.

[0225] In other implementations, there may be further gripping segments and cylinder pairs in the drillstring anchor. The units 2001 , 2002, 2004, 2005, 2006, 2008 and 2009 comprising the drillstring anchor may be arranged in any order.

[0226] FIG. 10 shows an example of a cylinder assembly 2005, 2009 and its associated components. In this example, the cylinder assemblies 2005, 2009 each comprise two cylinder assemblies 2101 , 2102. In other examples of the drillstring anchor, there may be only one cylinder assembly 2101 or more than two cylinder assemblies per gripping segment.

[0227] In the example shown in FIG. 10, one pair of cylinder assemblies 2101 , 2102 is attached to the housing of a gripping segment. In other words, each pair of cylinder assemblies is fast with a gripping segment of the drillstring anchor. The cylinder assemblies are arranged around the circumference of the channel which engages with the downhole portion of this drillstring, which in the example is shown as a shaft 2108. For example, the cylinder assemblies may be arranged on opposing sides of the channel and shaft 2108. The cylinder assemblies of each gripping segment are connected to each other, for example by piping, to allow the flow of hydraulic fluid therebetween.

[0228] The main components of a cylinder assembly are indicated in FIG. 10 for cylinder assembly 2101. Cylinder assembly 2102 comprises corresponding features. Cylinder assembly 2101 comprises a piston 2105 which separates two chambers 2103, 2106 within the cylinder. One chamber 2103 is above the piston and the other 2106 below (with respect to the downhole direction). There is a connection 2107 between the linkage 2109 and the shaft 2108 (the downhole portion of the drillstring).

[0229] The linkage 2109, which in this example is a rod passing through the upper and lower chambers and the piston 2105, is slidably attached to the piston 2105. The rod is attached at its lower end (in the downhole direction) to the downhole portion of the drillstring 2108 via connection 2107. The linkage 2109 is configured to transfer a force to the piston 2105 when the downhole portion of the drillstring 2108 moves downhole. Movement of the linkage 2109 in the downhole direction when the downhole portion of the drillstring 2108 progresses downhole therefore causes movement of the piston 2105 within the chamber in the downhole direction. This reduces the size of the chamber 2106 below the piston. Movement of the downhole portion of the drillstring relative to the channel of the drillstring anchor in the downhole direction therefore displaces the piston 2105. In this example, linkage 2109 comprises a seat, shown at 2110, which bears against one or more compliant members between the seat 2110 and the piston 2105. In this particular implementation, the one or more compliant members are springs 2104 located adjacent to the piston 2105 in the uphole direction, between the piston 2105 and seat 2010 of linkage 2109. The compliant member(s) provides for compliance between the piston 2105 and the linkage 2109 that allows drilling to progress, and thus allows the downhole portion of the drillstring 2108 to continue moving axially in the downhole direction, when both gripping segments are gripping the wellbore (for example, during the handover phase between the gripping segments, as described below). In this example, the linkage 2109 comprises a stop 2111. Stop 2111 can be inserted during assembly of the anchor device to preload the compliant spring member 2104. During walking motion, the spring preload is sufficient to resist the hydraulic pressures generated in the chamber 2106 and so there is no relative movement between piston 2105 and linkage 2109. However, during handover from one gripping segment to the other gripping segment, when both segments are gripping the wellbore, continued motion of linkage 2109 generates hydraulic pressure in the lower chamber 2106 large enough to overcome the preload and the piston 2105 and stop 2111 can separate and in this case there is relative motion between piston 2105 and linkage 2109. The stop 2111 also allows the weight of the gripper housing to be carried without applying a force to the compliant member 2104. In a cylinder assembly that is fixedly connected to the gripping segment that is activated and gripping the wellbore wall at a given time (referred to now as SEGMENT A), this piston movement that occurs when the downhole portion of the drillstring moves downhole causes a change in volume in the chambers 2103, 2106 on either side of the piston 2105. Fluid is discharged from the chamber 2106 below the piston 2105 because its volume is reduced and the chamber 2103 above the piston increases in volume. This fluid displaced from the lower chamber 2106 described above is fed via a connection (for example, hoses or piping 2007) 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 wellbore, 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 wellbore, increasing the volume of the lower chamber. The piston(s) within the SEGMENT B cylinder(s) have also been moved down relative to the wellbore by motion of the shaft 2108. 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 2108 in the downhole direction. The volume changes in the upper chambers 2103 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 wellbore 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 2108. When passing the gripping effort from one gripping segment to the other (i.e. from 2001 to 2002 or vice versa), it is advantageous for there to be continuous resistance to the turning torque and thus continuous gripping of the wellbore. As a result, a short period where the grippers of both segments are actuated to grip the wellbore wall is advantageous. During this period, the downhole portion of the drillstring 2108 can continue to move downhole relative to the channel of the drillstring anchor as drilling progresses. During this handover phase between the segments, the piston 2105 does not move within the cylinder assembly 2101. A change in volume of the lower chamber 2106 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 2105 in the downhole direction. This is counteracted by seat 2110 compressing the one or more compliant members 2104 above the piston 2105 to allow the linkage 2109 to move with the downhole portion of the drillstring 2108, 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 drillstring anchor, or after a predetermined time since the segment currently gripping was actuated. Alternatively, the segment currently gripping the wellbore may release automatically when the other segment is actuated to grip the wellbore, or once the other segment is determined to be gripping the wellbore, 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 wellbore 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 downhole portion of the drillstring 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.

[0230] In another implementation, the gripper of the free segment may be actuated to grip the wellbore 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 wellbore when the gripper of the other segment has reached a target force against the wellbore or a target pressure in the case of a hydraulically actuated gripper such as a piston.

[0231] In some implementations, the hydraulic cylinders may be actively controlled from a hydraulic power source to push the drill pipe (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. In addition to the items shown in FIG. 10, there may additionally be compensated accumulators in the system, whose role is to allow for expansion of the hydraulic fluid with increasing temperature and to provide a means of maintaining the internal system pressure of the walking mechanism at a fixed relationship above wellbore ambient pressure. Therefore, in some implementations the drive mechanism may comprise an accumulator. The accumulator may be used to deal with pressure transients.

[0232] The gripping segments need not be mechanically linked. Each gripping segment may be independently controllable in order to achieve the above-described behaviour. The motion of multiple independently controllable gripping segments may be synchronised to achieve the above-described behaviour. Each gripping segment may be configured to move at a different speed relative to the downhole portion of the drillstring as it moves downhole. Each gripping segment may be configured to move at any desired speed relative to the downhole portion of the drillstring as it moves downhole.

[0233] In some implementations, the drillstring anchor may be activated to grip the wellbore (by one or more of the gripping segments) in dependence on the pressure differential between fluid flowing inside the downhole portion of the drillstring and fluid in the wellbore annulus outside of the drillstring anchor. For example, there may be a threshold pressure differential for activating the drillstring anchor to grip the wellbore. The threshold may be a predetermined threshold. The threshold may be set by an operator of the drillstring anchor. When the pressure differential reaches the threshold, the drillstring anchor may be activated to grip the wellbore. When the pressure differential is below the threshold, the drillstring anchor may be deactivated such that it is not gripping the wellbore. When the drillstring anchor is deactivated, all grippers of the drillstring anchor may be in their passive state. When the drillstring anchor is deactivated, the drillstring anchor may be configured so as to not restrict relative rotation between the drillstring and the wellbore.

[0234] In some embodiments, the gripper(s) of the anchor may be activated using energy from a mechanism that can recover energy from the flow of drilling fluid passing through and / or around the drillstring. For example, such a mechanism may comprise a turbine. The turbine may generate power from the flow of drilling fluid through the drillstring and / or the BHA. The turbine may provide energy to the actuators of the grippers. The turbine may also be used to power other elements such as MWD and LWD apparatus, or steerable systems, or may be a turbine that only provides power to the drilling anchor. Each actuator may be capable of being driven using energy from one or more turbines to cause its respective gripper to grip the wellbore. An advantage of this system is that it does not require an external power source. The system pressure is created by the weight of the gripping segments and motion by the movement of the downhole portion of the drillstring. It is also more robust than other mechanical solutions and is capable of advancing the segment that is not currently gripping the wellbore at twice the rate of drill bit advance. It also allows for a handover period where both segments are gripping the wellbore so that drilling can be continuous and is compensated for borehole pressure.

[0235] In all of the embodiments described herein, the drillstring anchor may be activated and / or disabled as required in response to a command from the surface of the wellbore. For example, in response to a command, a signal may be communicated to the drillstring anchor wirelessly or via a wired connection. This can allow drilling to be performed without the anchor in operation when desired. When deactivated, the grippers of each segment are in the passive state. When deactivated, the segments of the drillstring anchor may not move longitudinally relative to one another.

[0236] In some implementations, control of the direction of drilling may be desirable. This may allow the borehole to be placed in a desired location. Particular features of drilling with the anchor described above may provide advantages compared to conventional rotational drilling. Conventionally, surveying measurements made by the magnetometers and accelerometers in an MWD system are only made when the drillstring is stationary, for instance during connections, which may be, for example, 20m, 30m, or 40m apart. Reducing the distance between survey locations can increase the accuracy with which the borehole location may be determined. The absence of rotation above the anchor can allow these measurements to be made much more frequently, and both stored locally and transmitted to surface at possibly a reduced rate.

[0237] When transitioning between two well inclinations (for instance, vertical and horizontal), it is generally desirable to maintain a steady curvature. If the rate-of-penetration varies, then it may be problematic for downhole steerable systems to maintain a steady curvature. For instance, with the same average side-force exerted by a steerable system, if the rate-of-penetration doubles, the curvature achieved will halve. However, in the absence of downhole measurement of rate-of-penetration, any adjustment to steerable system settings may be transmitted to the steerable system by a surface controller, and the lags and errors in this process can lead to significant variations in curvature. By measuring the time between the actuation of two sets of grippers, the average rate-of-penetration may be determined by taking the ratio of the difference between the distance between the grippers at maximum and minimum longitudinal position, and the time between actuations. If a desired curvature has been transmitted to a downhole computational processor, for instance located within the MWD, then based on the measured rate-of-penetration, corrected settings for the steerable system may calculated, and sent to the steerable system to enable reduced variation in curvature.

[0238] Figure 11 shows an example of a method 2200 for forming a wellbore in a rock formation using a drilling mechanism as described herein. The drilling mechanism comprises a drill bit, a rotational drive coupled to the drill bit for driving the drill bit to rotate (such as a mud motor), an anchor (which may have a form corresponding to any of the non-limiting examples described herein being operable to rigidly grip the wellbore, and a drill string extending through the anchor to the drill bit. The method comprises, at step 2201 , operating the anchor to rigidly grip the wellbore. At step 2202, the method comprises operating the rotational drive to drive the drill bit to drill the rock formation under operational conditions such that torsional vibrations occur in the portion of the drillstring downbore of the anchor. At step 2203, the method comprises allowing the drillstring to move axially relative to the anchor while the anchor is gripping the wellbore such that the drill bit proceeds to drill the rock formation to progress the wellbore; whereby when the anchor is rigidly gripping the wellbore, the anchor isolates (fully or partially) the portion of the drillstring upbore of the anchor from the torsional vibrations.

[0239] Such a drilling mechanism may therefore be used for the purpose of mitigating stick slip, and / or other torsional vibrations, in a drilling procedure for forming a wellbore in a rock formation. The anchor can be operated to rigidly grip the wellbore to react the torsional vibrations (for example due to stick-slip) during drilling so as to isolate the portion of the drillstring upbore of the anchor, partially or fully, from the torsional vibrations. In the absence of the anchor gripping the wellbore, bit-generated torsional vibrations may cause stick slip in the portion of the drillstring upbore of the anchor.

[0240] All of the torque from the portion of the drillstring downbore of the anchor may be reacted to the wellbore through the anchor. Alternatively, only the differential torque may be reacted. For example, in some cases there may be some torque in the portion of the drillstring above the anchor. Rather than reacting all of the torque from the portion of the drillstring downbore of the anchor to the wellbore through the anchor, only the differential torque may be reacted to the wellbore by the anchor.

[0241] In other implementations, the drillstring being rotationally fast with the anchor provides a reaction path for reacting torque from the rotational drive to the wellbore. The anchor can be advanced longitudinally along the wellbore to an anchoring location. The following can then be performed simultaneously:

[0242] (i) the rotational drive can be operated so as to drive the drill bit to rotate;

[0243] (ii) a longitudinal force can be applied on the bit to force the bit into contact with a distal end of the wellbore; and

[0244] (iii) the anchor can be operated to rigidly grip the wellbore at the anchoring location;

[0245] The anchor gripping the wellbore at the anchoring location may result in the torsional stiffness of the reaction path being sufficiently high such that torsional vibration and / or stick slip of the drill bit is mitigated (for example, is of reduced severity compared to when the anchor is not operated to rigidly grip the wellbore) or does not occur.

[0246] The presence of the anchor at the anchoring location above the rotational drive (e.g. a drilling motor) means that the reaction path for the torque that’s driving the drill bit to rotate is stiffer than normal. Instead of reacting torque all the way to the surface, it is reacted to the wellbore by the anchor. That means that if the bit encounters resistance, after only a small amount of torsion in the reaction path the torsional force at the drill bit is high enough to cause it to break through the resistance. This may result in smoother and / or faster and / or deeper drilling. This may be achieved by reducing the severity of torsional vibrations or stick slip.

[0247] In operation, longitudinal force may be applied to the drill bit to urge it against the distal end of the wellbore. This weight on bit can help to improve drilling performance. However, it can increase the resistance to rotation of the drill bit, making stick-slip more likely. In one arrangement the drillstring passes through the anchor, the stationary part of a motor is attached to the drillstring distally of the anchor, and the rotary part of the motor is attached to the drill bit. In this arrangement, with the anchor gripping the wellbore and the drillstring rotationally fast with the anchor as a result of cooperating splines, keyways etc. on the two, as described herein, a reaction path is provided for torque from the motor. That reaction path extends from the stationary (non-rotating) part of the motor, up the drillstring to the anchor and through the anchor to the wellbore. In another arrangement the motor may be integrated with the anchor, in which case the drillstring does not form part of the reaction path. In each case the reaction path for torque from the bit also includes the bit, the rotary part of the motor and a shaft or other member extending from the rotary part of the drill to the bit. In each case, it will be noted that the torque from the motor can be reacted somewhat locally to the bit, as a result of the anchor being located downhole. This can allow the torsional stiffness of the reaction paths to be higher than when the torque is reacted elsewhere, e.g. at the surface.

[0248] As drilling advances, the anchor can be advanced downhole. Conveniently, as the bit advances a new location for the anchor is determined periodically. That location may be determined by a recalculation of drilling performance data, or of data regarding the stiffness of the reaction path(s). Alternatively, those calculations may be performed in advance and the system may operate to advance the anchor at a predetermined rate to maintain a suitable anchor location. Alternatively, the system may operate to maintain the anchor within a predetermined window of distance from the bit. That window may be determined, for instance, by prior drilling in the same or similar rock. As the drill bit advances, the anchor moves to successive anchoring locations to keep the reaction path from the bit sufficiently stiff to prevent or at least mitigate sticking of the bit. Those locations may also depend on the weight being applied to the bit. A processor may determine successive anchoring locations dependent on the factors set out herein.

[0249] Thus, in one approach, a suitable range of distances from the bit to the anchor may be predetermined. The range may be determined prior to drilling of the wellbore. It may be adjusted as drilling of the wellbore progresses, in dependence on the conditions encountered and the system’s drilling performance. As the bit advances, new locations for the anchor are repeatedly determined in order to maintain its distance from the bit in the currently determined range. The determination of a location may involve determining that the anchor is to move a certain distance from its current location at a certain time.

[0250] The anchor may be particularly effective under certain operational conditions. For example, stick-slip and other torsional vibrations may be particularly unsustainable when the drill bit is rotated at an RPM of at least 30 revolutions per minute. This effect may be exacerbated further at RPMs of at least 40, 50, 60, 70 or 80 revolutions per minute. Similarly, a weight on bit in the range 2,000 to 120,000 Ibf (8900 to 530,000 N) and or a torque on bit of between 1 ,000 to 80,000 ft-lbf (1400 to 110,000 Nm) may cause unsustainable torsional vibrations in the drillstring. These parameters may be dependent on one or more of the rock type, the drillstring length, the drillstring diameter and the hole size. Certain bit types may also be particularly susceptible to torsional vibrations which may cause stick slip to occur. Such drill bits may comprise one or more conical polycrystalline diamond compact cutters. Such cutters may have a conical diamond element and a standard tungsten carbide base. All of the cutters of the drill bit may be conical polycrystalline diamond compact cutters. In the absence of the anchor tool, such bits may generate unsustainable torsional vibrations. Therefore, the use of the anchor may allow such bits to be used to achieve good drilling results.

[0251] As mentioned above, the average ROP can be determined by measuring the time period between the actuation of two sets of grippers 2101 , 2102 of the anchor tool shown in FIG. 10, and the distance travelled by one gripper (the gripper currently gripping the wellbore) relative to a fixed point. For the average rate-of-penetration over the distance drilled during each cycle of the anchor (i.e. between the actuation of the first gripper, actuation of the second gripper, etc), the time between cycles, or pairs of cycles, can be measured, and ROP inferred from the known or measured distance.

[0252] To allow such calculations to be performed, the tool may comprise one or more sensors for determining the longitudinal position of one or more of the grippers relative to a reference point. In some examples, the reference point may be on the body of the tool and may be used to determine the longitudinal position of one or more of the grippers (or the housing from which the are actuated to move radially relative to the housing to engage the wellbore) relative to the tool body.

[0253] The time between the actuation of the first gripper 2001 and the second gripper 2002 may be measured using signals from the anchor tool that indicate that the grippers are being actuated to grip the wellbore, or may be inferred from indirect measurements made by other sensors in the drillstring. For instance, accelerometers in the drillstring, for example in an MWD tool, may pick up vibrations characteristic of particular events in the anchor cycle, for instance the deployment of grippers. In other examples, the time between the actuation of the first gripper and the second gripper may be fixed and / or known.

[0254] The measurement of ROP may therefore be performed by measuring the time between activations of the two sets of grippers. This gives an average ROP estimation, as the distance that the drill bit has moved forward by can be determined from the longitudinal distance moved by the gripper housing for the gripper that is gripping the wellbore relative to the body of the anchor tool.

[0255] If the sensors are close to the upper gripper assembly, for instance in an MWD tool located above the anchor in the BHA, then they may only be sensitive to signals generated by one gripper assembly, and thus the timing that would be measured would be for the movement of both upper 2001 and lower 2002 gripping assemblies.

[0256] Alternatively, the downhole ROP may be measured by determining the relative movement between a gripper that is gripping the wellbore and a reference point on the downhole portion of the drillstring (such as on shaft 2108 in FIG. 10) with respect to time. In FIG. 10, a position sensor is shown on the gripper housing at 2114 and a reference point on the downhole portion of the drillstring is shown at 2115. By measuring the relative displacement between the gripper and a reference point on the downhole portion of the drillstring during a time period, this can be used to indicate how much the drillstring has moved relative to the gripper, which is at a fixed position, and thus can be used to give an indication of downhole ROP.

[0257] Referring to FIG. 10, the shaft 2108 (downhole portion of the drill string) moves relative to the gripper housing 2112 as the drill bit is driven to progress the wellbore. The gripper housing 2112 is held geostationary when the gripper pistons are activated to cause the corresponding grippers to grip the wellbore. A measurement of the relative displacement rate between a reference point on the downhole portion of the drillstring 2108 (or any other member mechanically connected to the downhole portion of the drillstring) and a reference point on the gripper housing 2112 (or any other member mechanically connected to part 2112) is therefore a direct measurement of the instantaneous ROP. It is an in-situ direct measurement and does not rely on any modeling-based corrections.

[0258] In a further example, the ROP may be inferred from the position of the piston 2105 that drives the hydraulic fluid within the chamber during the tool’s forward motion. This may be determined using position sensors within the hydraulic chamber. This measurement can be performed using commercial position sensors typically used for hydraulic cylinders. Such position sensors include linear variable displacement transducers (LVDT), magneto strictive linear displacement transducers (MLDT), or linear variable inductance transducers (LVIT). Potentiometric or capacitive devices may also be used.

[0259] One advantageous use of the determined downhole ROP is in combination with a steering tool in order to follow a prescribed path, or a path with a prescribed curvature. Another use is in combination with measurement of torque, and of the motor rotation speed, to allow the calculation of the energy required to removed a unit volume of rock (known as mechanical specific energy, or MSE).

[0260] The anchor tool may comprise or be communicatively connected to a processor for processing data acquired by the sensors of the tool and / or a communication unit for sending raw measurements and / or data processed by the processor to the surface of the wellbore. In some implementations, the measurements and / or processed data may be telemetered to the surface via an MWD module of the BHA. The ROP data can be used to feed drilling optimization algorithms, determine the bit depth of cut, and calculate the total depth of the well by integration in time.

[0261] FIG. 12 shows an example of a method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool. The tool comprises one or more grippers being actuatable to grip the wellbore and may have any of the exemplary forms described herein. The method comprises, at step 2301 , applying rotational drive to the drill bit. At step 2302, the method comprises actuating a gripper of the one or more grippers to grip the wellbore. At step 2303, the method comprises allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress in the wellbore. At step 2304, the method comprises measuring the relative displacement between the gripper and a reference point on the downhole portion of the drillstring during a time period. At step 2305, the method comprises determining the rate of penetration of the drill bit as the ratio of the measured relative displacement and the time period.

[0262] FIG. 13 shows another example of another method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool for use with a drillstring for forming the wellbore. In this example, the tool comprises two independently actuable grippers spaced longitudinally relative to each other, each gripper being linearly displaceable relative to a body of the tool and being actuatable to grip the wellbore. At step 2401 , the method comprises applying rotational drive to the drill bit. At step 2402, the method comprises actuating a first one of the grippers to grip the wellbore, wherein at the time of actuation of the first one of the grippers, the first one of the grippers is at a first longitudinal position relative to the body of the tool. At step 2403, the method comprises allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress the wellbore. At step 2404, the method comprises actuating a second one of the grippers to grip the wellbore, wherein at the time of actuation of the second one of the grippers, the first one of the grippers is at a second longitudinal position relative to the body of the tool. At step 2405, the method comprises determining a time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers. At step 2406, the method comprises determining the rate of penetration of the drill bit as the ratio of the distance between the first longitudinal position and the second longitudinal position and the time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers.

[0263] Therefore, the anchor tool can conveniently be used to determine the downhole ROP, which can be used in steering calculations and / or to determine other properties of the wellbore.

[0264] The anchor tool may comprise or be communicatively connected to a processor for processing data acquired by the sensors of the tool and / or a communication unit for sending raw measurements and / or data processed by the processor to the surface of the wellbore. In some implementations, the measurements and / or processed data may be telemetered to the surface via an MWD module of the BHA. The anchor tool can also provide means to a direct measurement of the downhole weight on bit (DWOB). Referring to FIG. 10, when the tool is anchored with the gripper pistons deployed, piston 2105 connected to linkage 2109, the axial force on the shaft 2108 (the DWOB) is equal to the pressure in upper chamber 2103 minus the pressure in lower chamber 2106 acting on the cross section of piston 2105. This measurement can be performed with, for example, a differential pressure gauge. It may be assumed that the annular zone 2113 between the shaft 2108 and the gripper housing 2112 is filled with drilling mud at the downhole wellbore pressure. If there is more than one cylinder assembly, the measurement can be multiplied by the total number of cylinder assemblies (each comprising a hydraulic chamber and a respective piston house within the chamber) to obtain the DWOB, since the cylinder assemblies of each gripping segments are connected hydraulically to each other. The tool may therefore comprise one or more pressure gauges for determining the differential pressure between the upper 2103 and lower 2106 portions of the chamber. The tool is configured to convey data acquired by the one or more pressure gauges to a processor configured to determine one or more drilling parameters from the determined differential pressure. The one or more drilling parameters comprise one or more of downhole weight on bit and drillstring friction.

[0265] As in the case of the downhole ROP measurement described above, this DWOB is a direct measurement which is not dependent on modeling-based corrections and other assumptions, and thus presents a much better accuracy. The measurements may be sent to the surface by the communication unit of the tool. The measurements may be used in various drilling optimization algorithms. One particularly useful application of DWOB is the estimation of the drillstring friction in the wellbore. The friction is the difference between surface and downhole WOB. Drillstring friction is a key parameter in determining weight transfer and the onset of stuck pipe events.

[0266] The construction of the drillstring anchor can also allow for the performing a direct measurement of the drilling reaction torque, which by definition is equal to the torque at the bit. As shown in FIG 14(a) (where the same parts shown in FIG. 2(b) use the same numbering), the shaft of the downhole portion of the drillstring comprises protrusions 210 which engage with corresponding features of the channel of the drillstring anchor to transmit torque from the drillstring to the anchor. The protrusions can be instrumented to include torque sensors, for instance by means of piezo electric force sensing foils 212 inserted in the radial plane between the keys 210 and the main body of the shaft 208, as shown in FIG.s 14 (a) and 14(b). In these examples, the torque sensors are disposed at the interface between the protrusions (keys) on the downhole portion of the drillstring and the channels (keyways) in the main shaft body with which the keys are engaged. The torque can be determined as the sum of the moments of the forces about the tool centre line. In this example, the downhole portion of the drillstring comprises four protrusions 210 symmetrically disposed about its radius and the tool comprises a torque sensor at each interface between the protrusions and the side walls of the channels. Each torque sensor is disposed at a respective radial planar portion of the channel. Each torque sensor may comprise, for example, a piezo electric force sensing foil or a strain gauge. In some examples, one or more of the torque sensors may comprise a contactless torque sensor. Such torque sensors may be based on magnetoelasticity and use magnetic fields to detect torque.

[0267] The tool may be configured to convey data from the one or more torque sensors to a processor for determining one or more drilling parameters, such as rate of penetration, downhole weight on bit, downhole torque on bit and mechanical specific energy. The processor may be configured to determine the downhole torque on bit as the sum of the moments of the forces about a central longitudinal axis of the tool. As described above for the data acquired to determine the downhole ROP, the tool may comprise a communications module configured to transmit data acquired by the torque sensors to the surface of the wellbore.

[0268] The grippers may also be instrumented to make other measurements relevant to the subterranean drilling operation. As the gripper units remain stationary with respect to the wellbore for prolonged periods (when they are actuated to grip the wellbore), they can provide a useful platform for measurements with benefit from a long measurement period, such as surveying measurements. For example, the grippers may comprise one or more sensors for measuring the Earth’s magnetic field (for example, magnetometers), the Earth’s gravitational field (for example, accelerometers) and the Earth’s rotation speed (for example, using a gyroscope). Other measurements that benefit from a rigid coupling to the wellbore wall are those employed for seismic surveys made during the drilling of well, such as accelerometers or geophones, which detect seismic waves transmitted typically from the Earth’s surface. Such a sensor is indicated on a gripper at 2116 in FIG. 9.

[0269] In some examples, each gripper may comprise one or more sensors for determining a property of a rock formation defining the wellbore. For example, each gripper may comprise an indenter for measuring the strength and / or hardness of the rock formation defining the walls of the wellbore. In one example, an indenter longer in one axis than the other (perpendicular to the direction of indentation) may be used to identify anisotropy in the hardness, and hence compressive strength, of an indented rock. Knoop hardness tests involve a pyramidal diamond indenter that is 7 times as long in one axis perpendicular to the indentation direction as the other. Knoop indentation testing may be used to determine rock strength anisotropy, at either ambient or downhole conditions. Measurements of hardness at different indentation depths can also indicate the presence of a modified surface layer and allow the quantification of the underlying material’s hardness. The pressure of the gripper-actuating fluid can be measured and can indicate the force acting on the indenter. The contact area of the indentation may be inferred from the distance that the gripper(s) move after making contact with the borehole wall and knowledge of the shape of the indenting surface of the gripper. Therefore, a measurement of rock hardness may be obtained from indentation of the borehole wall by the grippers. The indenter may be made from a material that is hard and tough in comparison with any rock likely to be encountered, such as diamond. Measurement of the gripper displacement relative to the borehole wall can also be made. Rock compressive strength in the downhole environment may be inferred from the measurement of indentation hardness combined with a knowledge of the rock porosity. The rock’s unconfined compressive strength may be estimated from that and knowledge of the borehole pressure and, in permeable rocks, the pore pressure. As described above, the use of an indenter significantly longer in one axis perpendicular to the indentation direction than the other may be used to detect rock hardness and rock strength anisotropy.

[0270] The pistons of the grippers themselves may also be used to measure the elastic properties of the borehole walls. The pistons may be instrumented with a force sensor and a sensor that measures the displacement of the piston in the radial direction with respect to the longitudinal axis of the tool. As the pistons are extended to grip the wellbore, force-displacement data may be used to determine the strength and / or stiffness of the rock formation. One or more of the grippers may alternatively or additionally comprise one or more sensors or equipment configured to measure a property of the Earth’s magnetic or gravitational field, the rotation speed of the Earth, or seismic waves transmitted from or proximate to the Earth’s surface (such as an airgun).

[0271] The above-described sensors may be applied to any of the drillstring anchor examples described herein, with single or multiple gripping segments.

[0272] 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 drilling method for forming a wellbore in a rock formation using a drilling mechanism comprising a drill bit, a drillstring, a rotational drive coupled between the drillstring and the drill bit for driving the drill bit to rotate relative to the drillstring, and an anchor operable to rigidly grip the interior of the wellbore, the drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor so as to provide a reaction path for reacting torque from the rotational drive to the wellbore, the drillstring being moveable longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore, the method comprising: advancing the anchor longitudinally along the wellbore to an anchoring location; and simultaneously:(i) operating the rotational drive so as to drive the drill bit to rotate;(ii) applying a longitudinal force on the bit to force the bit into contact with a distal end of the wellbore; and(iii) operating the anchor to rigidly grip the wellbore at the anchoring location; the anchoring location being such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur.

2. The drilling method as claimed in claim 1 , wherein the rotational drive is a drilling motor.

3. The drilling method as claimed in claim 1 or claim 2, wherein the longitudinal force is applied on the bit from the anchor.

4. The drilling method as claimed in claim 3, wherein the longitudinal force is weight on bit.

5. The method as claimed in any preceding claim, wherein the method comprises reacting torque from the anchor to the wellbore.

6. The method as claimed in any preceding claim, wherein the method comprises operating the rotational drive to drive the drill bit to rotate at a rate of at least 30 revolutions per minute.

7. The method as claimed in any preceding claim, wherein the method comprises applying a weight on bit to the drill bit of between 2,000 to 120,000 Ibf (8900 to 530,000 N).

8. The method as claimed in any preceding claim, wherein the method comprises applying a torque on bit to the drill bit of between 1,000 to 80,000 ft-lbf (1400 to 110,000Nm).

9. The method as claimed in any preceding claim, wherein the anchor comprises multiple independently actuatable grippers and the method further comprises operating the grippers to grip the wellbore sequentially while allowing the drillstring to move axially relative to the anchor.

10. The method as claimed in any preceding claim, wherein the drill bit comprises one or more conical polycrystalline diamond compact cutters.11 . Use for the purpose of mitigating torsional vibration and / or stick slip in a drilling procedure for forming a wellbore in a rock formation of a drilling mechanism comprising: a drill bit; a drillstring; a rotational drive coupled between the drillstring and the drill bit for driving the drill bit to rotate relative to the drillstring; and an anchor operable to rigidly grip the interior of the wellbore, the drillstring extending through the anchor to the drill bit, the anchor and the drillstring being cooperatively shaped so that the drillstring is rotationally fast with the anchor so as to provide a reaction path for reacting torque from the rotational drive to the wellbore, the drillstring being moveable longitudinally relative to the anchor when the anchor is operated to rigidly grip the wellbore; wherein the anchor is advanced longitudinally along the wellbore to an anchoring location; and wherein the following are performed simultaneously:(i) the rotational drive is operated so as to drive the drill bit to rotate;(ii) a longitudinal force is applied on the bit to force the bit into contact with a distal end of the wellbore; and(iii) the anchor is operated to rigidly grip the wellbore at the anchoring location; the anchoring location being such that the torsional stiffness of the reaction path is sufficiently high that torsional vibration and / or stick slip of the drill bit is mitigated or does not occur.

12. A downhole anchor tool for use with a drillstring for forming a wellbore, the tool comprising a channel having a configuration for rotational engagement with a downhole portion of the drillstring passing through the channel and comprising two grippers, each gripper being linearly displaceable relative to a body of the tool and the other gripper and being actuatable to grip the wellbore, wherein the tool comprises one or more sensors for determining the longitudinal position of one or more of the grippers relative to a reference point.

13. The tool as claimed in claim 12, wherein the downhole portion of the drillstring comprises a shaft attachable to a lower part of the drillstring, the lower part of the drillstring comprising a drill bit for progressing the wellbore.

14. The tool as claimed in claim 12 or claim 13, wherein the reference point is on the body of the tool.

15. The tool as claimed in any of claims 12 to 14, wherein the reference point is on the downhole portion of the drillstring.

16. The tool as claimed in claim 15, wherein the channel is configured to allow relative axial movement of the downhole portion of the drillstring and the tool when one or more of the grippers is gripping the wellbore, wherein the one or more sensors are configured to detect the relative displacement of a respective gripper relative to the reference point when that gripper is gripping the wellbore.

17. The tool as claimed in any of claims 12 to 16, wherein the tool is communicatively connectable with a first processor arranged to sum relative longitudinal movements of each gripper in the downhole direction.

18. The tool as claimed in any of claims 12 to 17, wherein each gripper has a range of travel relative to the body of the tool, wherein the one or more sensors are configured to determine the longitudinal position of one or more of the grippers within its range of travel.

19. The tool as claimed in any of claims 12 to 18, wherein the tool comprises a hydraulic chamber configured to house a piston for driving a respective gripper to move relative to the body of the tool and wherein the one or more sensors are configured to acquire data indicative of the longitudinal position of the piston within the chamber.

20. The tool as claimed in any of claims 12 to 19, wherein the one or more sensors comprise one or more of a linear variable displacement transducer, a magneto strictive linear displacement transducer, a linear variable inductance transducer, a potentiometric device and a capacitive device.

21. The tool as claimed in any of claims 12 to 20, wherein the tool is operable according to a cycle whereby the following steps are performed: a first one of the grippers is actuated to grip the wellbore;a second one of the grippers is actuated to grip the wellbore; the first one of the grippers is released from the wellbore; the first one of the grippers is actuated to grip the wellbore; and the second one of the grippers is released from the wellbore. wherein the tool comprises a first sensor for determining the longitudinal position of the first gripper relative to the reference point and / or a second sensor for determining the longitudinal position of the second gripper relative to the reference point.

22. The tool as claimed in claim 21 , wherein the tool is communicatively connectable with a second processor configured to determine a time period between the actuation of the first gripper and the actuation of the second gripper.

23. The tool as claimed in claim 21 , wherein the tool is communicatively connectable with a third processor configured to determine a time period between the actuation of one of the grippers and a subsequent activation of that gripper.

24. A method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool for use with a drillstring for forming the wellbore, the tool comprising one or more grippers being actuatable to grip the wellbore, the method comprising: applying rotational drive to the drill bit; actuating a gripper of the one or more grippers to grip the wellbore; allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress in the wellbore; measuring the relative displacement between the gripper and a reference point on the downhole portion of the drillstring during a time period; and determining the rate of penetration of the drill bit as the ratio of the measured relative displacement and the time period.

25. A method of determining the rate of penetration of a drill bit in a wellbore using a downhole anchor tool for use with a drillstring for forming the wellbore, the tool comprising two independently actuable grippers spaced longitudinally relative to each other, each gripper being linearly displaceable relative to a body of the tool and being actuatable to grip the wellbore, the method comprising: applying rotational drive to the drill bit; actuating a first one of the grippers to grip the wellbore, wherein at the time of actuation of the first one of the grippers, the first one of the grippers is at a first longitudinal position relative to the body of the tool;allowing the drillstring to move longitudinally relative to the tool to allow the drill bit to progress in the wellbore; actuating a second one of the grippers to grip the wellbore, wherein at the time of actuation of the second one of the grippers, the first one of the grippers is at a second longitudinal position relative to the body of the tool; determining a time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers; determining the rate of penetration of the drill bit as the ratio of the distance between the first longitudinal position and the second longitudinal position and the time difference between the time of actuation of the first one of the grippers and the time of actuation of the second one of the grippers.

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