GB2615592A

GB2615592A - Drillstring anchor

Info

Publication number: GB2615592A
Application number: GB2201938.4A
Authority: GB
Inventors: Watson Graham; Harrall Martin; Richard Glover Anthony; Webb Mark; Gajdos Matus
Original assignee: GA Drilling AS
Current assignee: GA Drilling AS
Priority date: 2022-02-14
Filing date: 2022-02-14
Publication date: 2023-08-16
Anticipated expiration: 2042-02-14
Also published as: GB2615620A; GB202201938D0; GB202215151D0; GB2615620B; GB2615592B

Abstract

A drillstring anchor 200 for reacting torque from a drillstring to a wellbore includes a channel 201 for receiving a downhole portion of a drillstring 202 so as to be rotationally engaged therewith: a gripper; an energy store; and an actuator capable of being driven from the energy store to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the wellbore and a second, retracted state. Also claimed is a drillstring anchor where there are multiple segments (703, 704, 705, 706, fig7a) disposed along the drillstring anchor which can be driven outwardly independently of each other.

Description

DRILLSTRING ANCHOR

FIELD OF THE INVENTION

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

BACKGROUND

In drilling operations, for example in oil, gas or geothermal drilling, a borehole is drilled through a formation in the earth to form a 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. A downhole motor can be used to rotate the drill bit, allowing the bit to advance through the formation to form the wellbore.

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 rotating, while the drillstring above continues to rotate. This can cause the drillstring to wind up, after which the stuck element slips and rotates again. The drillstring can act like a long torsional spring and is able to store significant amounts of torsional energy. Torsional oscillations in the drillstring can cause damage to the drillstring, bottom hole assembly and the wellbore, and result in poor drilling performance.

Several solutions have been previously proposed to reduce the occurrence of stick slip.

The solution described in W02016/122329 Al is a downhole regulator with capabilities similar to traction control systems used in cars. The axial force or weight on bit (WOB) is continuously controlled. In this way it can prevent the cutters from sticking and also provides a balance between cut and losses to friction.

The solution described in US2014/0311801 Al uses a drill bit with adaptive cartridges, installed inside the fixed blades, which extend and prevent vibrations while preventing the bit from taking too large a bite.

The above solutions are focused on keeping the tool in a stable operation region by reducing WOB to avoid the occurrence of stick slip. However, reducing WOB generally reduces the depth of cut (DOC) and compromises the Rate of Penetration (ROP).

It is desirable to develop a system for reducing torsional vibrations in a drillstring that can mitigate these issues and reduce the likelihood of significant and potentially damaging torsional oscillations along the drillstring.

SUMMARY

According to one aspect there is provided a drillstring anchor for reacting torque from a drillstring to a wellbore, the drillstring anchor comprising: a channel for receiving a downhole portion of a drillstring so as to be rotationally engaged therewith: a gripper; an energy store; and an actuator capable of being driven from the energy store to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the wellbore and a second, retracted state.

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 second 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 energy store may be a reservoir of pressurised fluid.

The energy store may be a source of electricity.

The drillstring anchor 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.

According to a second aspect there is provided a drillstring anchor for reacting torque from a drillstring to a wellbore, the drillstring anchor comprising: 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 one of a first state in which it is urged outwardly for gripping the wellbore and a second, retracted 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.

The drillstring anchor 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 by a force exerted through the drillstring.

The drillstring anchor may comprise a collar linking the first segment with the second segment, wherein the collar is constrained to move axially with the downhole portion of the drillstring.

The collar may be constrained to rotate about the longitudinal axis of the channel.

The collar may comprise multiple protrusions each configured to engage a helical groove in each of the first and second segments.

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 drillstring anchor 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 drillstring anchor may be configured to restrict relative rotation between the drillstring and the wellbore.

The or each gripper may be configured to exert an outward 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 drillstring anchor.

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 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.

The drillstring anchor 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 drillstring anchor reaches the limit of travel along the downhole portion of the drillstring.

The drillstring anchor 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.

The swivel may be a unidirectional swivel.

BRIEF DESCRIPTION OF THE FIGURES

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

In the drawings: FIG. 1 schematically illustrates an example of a drilling system, illustrated at a subterranean location in a wellbore during a downhole operation.

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

FIG.s 3a) and 3b) shows a cross-sectional view of an example of a gripper comprising three pads.

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

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

FIG. 6 schematically illustrates an anchor comprising three independently actuatable gripping segments.

FIG.s 7a)-7d) schematically illustrate the operation of an embodiment of a drillstring anchor comprising multiple segments.

FIG. 8 schematically illustrates a further embodiment of a drillstring anchor comprising multiple segments.

FIG. 9 shows two adjacent segments of the drillstring anchor of FIG. 8.

FIG. 10 shows a collar having multiple protrusions.

FIG. 11 schematically illustrates the collar of FIG. 10 on the downhole portion of the drillstring.

FIG. 12 shows two adjacent segments of the drillstring anchor of FIG. 8.

FIG. 13 shows a cross-sectional view of a gripper in a wellbore.

FIG. 14 shows an example of hydraulic pathways in the downhole portion of the drillstring.

FIG. 15 shows an example of a rotary valve for actuating a gripper.

FIG.s 16a)-16c) show rotary valves of two adjacent segments at various positions.

FIG.s 17a)-b) schematically illustrate a further example of a gripper comprising an axially operated arm.

DETAILED DESCRIPTION

FIG. 1 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-onbit (WOB) is provided from the surface through the drillstring 102.

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 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.

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.

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.

In the system shown in FIG. 1, 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.

In the system described above with reference to FIG. 1, the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit 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.

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.

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.

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.

In the 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.

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 or pneumatic motors.

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, retracted 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.

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.

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.

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).

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.

As noted above, the gripper is configured to be actuated to move between a retracted (i.e. deactivated) state and an outwardly-urged (i.e. 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.

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.

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.

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.

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).

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.

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.

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.

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.

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 self-tightening 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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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 (RIN) 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.

Stage 1: Movement -anchor at end of stroke (i.e. the anchor has reached the upper limit on the downhole portion of the drillstring); Stage 2: Control -activate the anchor to grip the wellbore; Stage 3: Movement -once anchor has reached lower limit, lift drillstring, re-set anchor position on Kelly (whilst anchor is activated); Stage 4: Control -1. Deactivate anchor, 2. Set grip mechanism; Stage 5: Movement -lower drillstring and tag bottom of wellbore; Stage 6: Control -release grip mechanism.

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

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.

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.

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.

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.

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.

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.

FIG.s 7a)-7d) shows an alternative embodiment of an anchor 700 which can allow the drillstring anchor to engage the wellbore continuously as the drillstring is advanced in the wellbore. In these schematic figures, the drillstring is shown advancing horizontally for ease of presentation. The drillstring may also advance vertically, or along some other straight or curved trajectory. Thus the term 'advance downhole' here can be taken to mean in the direction of the drill bit.

As in the previous embodiments, the anchor 700 comprises a channel configured to rotationally engage a downhole portion of the drillstring.

In FIG. 7a), the drillstring is shown at 701. At the end of the drillstring is a downhole motor 702 that provides rotational drive to the drill bit (drill bit not shown in FIG. 7a)). The rotational drive provided by the motor causes the drill bit to advance in the formation 750 to extend the wellbore at a rate of penetration, ROP.

In this embodiment, the drillstring anchor comprises multiple segments. The multiple segments are disposed along the drillstring anchor. Each segment comprises a respective gripper. The grippers of some of the segments are actuable independently of the grippers of the other segments. The multiple segments comprise two sets of segments. A first set of segments comprises segments 703, 704, 705 and 706 A second set of segments comprises segments 707, 708, 709 and 710.

The anchor comprises a drive mechanism for advancing at least one of the segments downhole relative to at least one of the other segments. In this example, the drive mechanism is configured to advance the first set of segments downhole relative to the second set of segments, and vice-versa.

In this example, the first set of segments are each fast with a rail 711. The second set of segments are each fast with a rail 712. In this example, the rails 711, 712 are each attached to a push-pull unit 713 which can advance the first set of segments downhole relative to the second set of segments, or vice-versa. Other embodiments may use alternative means of driving the rails and/or the segments downhole. The rails can be driven to advance at a different rate in the wellbore to the drill bit, for example at twice the ROP. The rails may also contain hydraulic lines to the respective actuators for the respective grippers of the segments.

In FIG. 7a), the first set of segments 703, 704, 705, 706 is activated such that the respective grippers 714, 715, 716, 717 of those segments are driven by their respective actuators to grip the wellbore. Each gripper is configured to exert an outward force on the wellbore relative to the longitudinal axis of the channel of the anchor. The respective grippers may each comprise at least one pad that is configured to exert an outward force on the wellbore relative to the longitudinal axis of the channel. As a result, relative rotation between the drillstring and the wellbore is restricted.

In FIG. 7a), the grippers of the second set of segments 707, 708, 709 and 710 are deactivated and do not grip the wellbore. While the first set of segments grip the wellbore, the second set of segments are free to move, driven by their respective rail 712, in the axial direction (downhole). In this example, the rail 712 and the second set of segments are advanced at twice the ROP of the drill bit. The second set of segments has a range of travel parallel to the axis of the channel. Each set of segments has an upper limit of the range of travel (furthest from the bit) and a lower limit of the range of travel (closest to the bit).

In FIG. 7b), the second set of segments have reached their lower limit of their travel downhole in the axial direction.

In FIG. 7c), the second set of segments 707, 708, 709, 710 is activated such that the respective grippers 718, 719, 720, 721 of those segments are driven by their respective actuators to grip the wellbore. Each gripper is configured to exert an outward force on the wellbore relative to the longitudinal axis of the channel of the anchor. Therefore, in this state, the grippers of both sets of segments are gripping the wellbore.

During this time, the downhole portion of the drillstring can continue to move longitudinally relative to the segments (while they are all activated) during the transition between the activation of one set of segments and the deactivation of another. The transition includes the coordinated gripping and release of sets of segments and may use an activation mechanism that is different to when only one set of segments is activated.

The grippers of the first set of segments are then deactivated. As shown in FIG. 7d), while the second set of segments grip the wellbore, the first set of segments are free to move, driven by their respective rail 711, in the axial direction downhole. In this example, the rail 711 and the first set of segments are advanced at twice the ROE' of the drill bit. The first set of segments has a range of travel parallel to the axis of the channel. The first set of segments continue to advance down the wellbore until they reach the lower limit of their travel in the axial direction.

In FIG. 7d), the second set of segments have reached the lower limit of their travel in the axial direction.

The drillstring anchor shown in FIG. 8 may also allow for continuous anchoring to the wellbore. In this example, multiple segments 801, 802, 803, 804 of the anchor 800 are grouped into two sets "A" and "B". In this example, each set of segments comprises two segments. Set "A" comprises segments 801 and 803. Set "B" comprises segments 802 and 804. In other examples, each set of segments may comprise one or more segments. Each set of segments may move along the longitudinal axis of (e.g. slide up or down) the downhole portion of the drillstring 850 (for example, the Kelly) relative to the other set(s) of segments.

Each segment comprises a respective gripper and a respective actuator capable of being driven to cause the respective gripper to grip the wellbore. The gripper of at least one segment is actuable independently of the gripper of at least one other segment. In this example, the grippers of each set of segments are configured to be actuated simultaneously.

In this example, three pads are equally spaced around the periphery of each segment such that they may act on the surface of a wellbore when a force is applied from hydraulic pistons located under each pad. Other numbers of pads may be used.

FIG. 9 shows the adjacent segments 801 and 802. One of the pads of segment 801 is indicated at 805. One of the pads of segment 802 is indicated at 806.

The set of segments "A" can be activated to grip the well bore, via their respective grippers, whilst the drill bit and the set of segments "B" are allowed to progress down the wellbore. As the lower limit of travel for set of segments "B" is reached, hydraulic pressure is allowed to activate the grippers of set of segments "B". Further free travel of the drill bit can vent pressure from set of segments "A", deactivating them and allowing them to progress down the wellbore ready to be re-activated to take over gripping the wellbore from set "B". Then, set "A" can grip the wellbore whilst the drill bit and a set "B" are allowed to progress down the wellbore, and so on.

The anchor comprises a drive mechanism for advancing at least one of the segments downhole relative to at least one of the other segments. The drive mechanism allows at least one of the segments to be advanced downhole by a force exerted through the drillstring. In this example, set of segments "A" can be advanced downhole relative to set of segments "B", and vice versa, as described above.

The pads of segment sets "A" and "B" are constrained to slide in opposite directions relative to each other along the longitudinal axis of the channel.

In this implementation, the drive mechanism comprises an annular bearing carrier assembly 807 disposed between adjacent segments. The annular bearing carrier 807 is shown in more detail in FIG. 10. The annuar bearing carrier 807 is in the form of a collar having multiple protrusions 808. In this example, the protrusions are bearings. However, the protrusions could have a different form that enables them to engage with each of the adjacent segments.

As shown in FIG. 11, the collar 807 is constrained to move axially with the downhole portion of the drillstring 850. The longitudinal axis of the channel of the anchor, which in this example is also the longitudinal axis of the downhole portion of the drillstring, is indicated at 851. The collar 807 is constrained to rotate about the longitudinal axis 851 of the channel. In some embodiments, a compliant element, such as one or more wave springs 820, can be used to permit axial movement of the collar, for example when both segments 801 and 802 are activated and the downhole portion of the drillstring 851 continues to move axially.

As shown in more detail in FIG. 12, in this example the multiple protrusions of the collar are each configured to engage a helical groove or slot in each of the adjacent segments 801 and 802. One such slot of segment 801 is indicated at 809 and one such slot of segment 802 is indicated at 810. The collar 807 therefore links adjacent segment 801, 802 of the anchor. The diameters of the ends of the segments may be sized so that one can be received inside the other. In this example, the end of segment 802 has a smaller diameter than the end of segment 801, such that the ends of the segments can overlap and both engage with the protrusions of the collar.

The protrusions 808 engage with and run in the helical slots 809, 810 of each segment. The pitches of the helical slots in adjacent segments are opposed. In this example, the pitch of the helical slot in one segment is right-handed, the other left-handed. The annular bearing carrier assemblies 807 are fitted around the Kelly and are constrained to move in the longitudinal direction but are allowed to rotate about the longitudinal axis 851.

The grippers of the segments may be activated in any manner described herein. For example, by an actuator driven from an energy store (e.g. using a hydraulic reservoir) or using the pressure of the drilling mud.

In this example, as shown in FIG.s 13 and 14 for segment 801, hydraulic pressure is applied to pistons acting on three equally spaced levers for pads 805, 830, 831 with a 2:1 mechanical advantage. When the gripper is activated, the pads grip the wellbore, resisting rotational and linear sliding movement of the anchor. The piston of pad 805 is indicated at 826. Pad 805 is attached to the body of the segment at a pivot 825. The rock of the wellbore is shown at 860 in FIG. 13.

As shown in FIG. 14, in this example, slots milled in the outer surface of an inner Kelly sleeve form internal hydraulic pathways 854. Seals at the ends of the inner Kelly sleeve trap the hydraulic fluid within an inner gallery. Alternatively, hydraulic pathways may be machined into the undersides of longitudinal plate elements affixed within slots in the Kelly. The operation of the rotary valve 900 will be described in more detail with reference to FIG. 15.

Hydraulic pressure from the inner gallery can be applied to pad pistons of the pads of set of segments "A" and the set of segments "B" alternately. Whilst switching from set "A" to set "B" and vice-versa, there is a period where both set "A" and "B" are activated such that the respective grippers of each set grip the wellbore.

During this time, the downhole portion of the drillstring can continue to move longitudinally relative to the segments during the transition between the activation of one set of segments and the deactivation of another. The transition includes the coordinated gripping and release of sets of segments and may use a drive mechanism that is different to when only one set of segments is activated.

In the preferred implementation, the control of hydraulic pressure to the pistons is controlled by one or more rotary valves 900, as shown in FIG. 15. In this example, the rotary valve 900 is actuated by a rhombus-shaped guide slot 901 in the Kelly 850. The rotary valve is driven by a pin 902 engaged with the guide slot 901. At one end of the guide slot 901 there is a ramp 903 which closes the valve. At the opposite end of the guide slot 901 there is a ramp 904 which opens the valve. As the Kelly 850 slides within a segment, the movement of the guide slot 901 relative to the rotary valve guide pin 902 forces the valve 900 open (so that the port shown at 905 is aligned with the fluid feed out to the actuator, shown at 909) or closed (so that the port shown at 906 is aligned with the fluid feed out to the actuator, shown at 909). The high-pressure fluid feed into the segment is shown at 907. 908 indicates an 0-ring seal.

In some embodiments, the motion of the collar (e.g. the annular bearing carrier 807) may activate the rotary valve.

FIG. 16a)-c) show adjacent segments 801 and 802 which each comprise a rotary valve of the type shown in FIG. 15, 900a and 900b respectively.

In FIG. 16a), the valve 900a is open and the valve 900b is closed. The pads of segment 801 are therefore activated to grip the wellbore. The pads of segment 802 are deactivated. Segment 802 is free to move with the downhole portion of the drillstring.

In FIG. 16b), both valves 900a and 900b are open. The pads of both segments 801 and 802 are therefore activated to grip the wellbore.

In FIG. 16c), the valve 900a is closed and the valve 900b is open. The pads of segment 802 are therefore activated to grip the wellbore. The pads of segment 801 are deactivated. Segment 801 is free to move with the downhole portion of the drillstring.

In some embodiments, there may be one or more wave springs (820 in FIG. 11) located above the collar (on the opposite side of the collar to the drill bit). Further drilling action and movement of the Kelly may be permitted by allowing the wave spring (or wave spring stack) to compress against the collar. This additional Kelly movement allows the valve guide slot to move relative to the rotary valve, moving it into the closed position, releasing the pads and allowing the segment to move. As soon as one of the sets of pads has been released and can move, the action of the wave spring or stack can move the deactivated segment along part of its travel until the spring has returned to its original state. Instead of one or more wave springs, other forms of compliant element may be used.

In another example, a linear valve may be used rather than a circular value to actuate the gripper(s).

The anchors 700 and 800 described above 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.

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, such as in dependence on the state of compliant element 820 in FIG. 11.

Generally, the following sequence of steps is performed: -a first segment (or set of segments) is activated to grip the wellbore; -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; -a second segment (or set of segments) is activated to grip the wellbore; -the first segment (or set of segments) is deactivated and driven to progress down the wellbore with the downhole portion of the drillstring.

The anchor may comprise a means of 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).

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.

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. Drillstring rotation may be used as an independent drive signal to activate the anchor (or one or more segments of the anchor).

In some embodiments, the control signal for the anchor to be activated or de-activated may be provided from the surface. The use of an electronic system is possible at drilling depths in conventional wells. However, in very deep wells such as geothermal wells (which may be several kilometres deep) the rocks temperature is increasingly hot. The maximum working temperature of electronics is approximately 175°C. Therefore, it may also be desirable to actuate and control the anchor using nonelectronic 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).

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.

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 one-way valves are not used.

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.

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.

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.

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.

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.

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.

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.

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 stuck 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.

In some embodiments, the gripper of the anchor may comprise one or more axially operated arms, as shown in the example of FIG.s 17a) and b). The arm may be actuated using a spring (or any other suitable means, for example, hydraulic) back force. The anchor 900 is shown on the downhole portion of the drillstring 901 in its deactivated and activated configurations in FIG.s 17a) and 17b) respectively. The gripper comprises an arm 902 with a pad 903 that can exert a force from spring 904 on the wellbore. This form of axially operated gripper may allow the gripper(s) to be more easily separated from the rest of the anchor, if desired.

Alternatively, for pads attached to the rest of the anchor via a pivoting hinge, the hinges may be disposed on a separate hydraulic pad. In the event of the anchor becoming stuck in the hole, the hydraulic line to the hinges can be deactivated, so that the hinges then collapse inwards. Then, irrespective of whether the pistons for the pads are actuated or not, the pad will not be forced to engage with the wellbore. If the pad has dug in, then moving the hinge might help to free it.

These gripper types may be applied to any of the embodiments described herein.

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 drillstring anchor for reacting torque from a drillstring to a wellbore, the drillstring anchor comprising: a channel for receiving a downhole portion of a drillstring so as to be rotationally engaged therewith: a gripper; an energy store; and an actuator capable of being driven from the energy store to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the wellbore and a second, retracted state.
2. The drillstring anchor as claimed in claim 1, wherein the energy store is a reservoir of pressurised fluid.
3. The drillstring anchor as claimed in claim 1, wherein the energy store is a source of electricity.
4. The drillstring anchor as claimed in any preceding claim, wherein the drillstring anchor comprises 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.
5. A drillstring anchor for reacting torque from a drillstring to a wellbore, the drillstring anchor comprising: 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 one of a first state in which it is urged outwardly for gripping the wellbore and a second, retracted 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.
6. The drillstring anchor as claimed in claim 4 or claim 5, wherein the drillstring anchor comprises a drive mechanism for advancing the first segment downhole relative to at least the second segment.
7. The drillstring anchor as claimed in claim 6, wherein the drive mechanism allows the first segment to be advanced downhole by a force exerted through the drillstring.
8. The drillstring anchor as claimed in claim 6 or claim 7, wherein the drillstring anchor comprises a collar linking the first segment with the second segment, wherein the collar is constrained to move axially with the downhole portion of the drillstring.
9. The drillstring anchor as claimed in claim 8, wherein the collar is constrained to rotate about the longitudinal axis of the channel.
10. The drillstring anchor as claimed in claim 8 or claim 9, wherein the collar comprises multiple protrusions each configured to engage a helical groove in each of the first and second segments.
11. The drillstring anchor as claimed in any of claims 5 to 10, wherein the first and second segments each have a range of travel in a direction parallel to the longitudinal axis of the channel.
12. The drillstring anchor as claimed in any of claims 4 to 11, wherein the multiple segments comprise at least two sets of segments, wherein the grippers of each set of segments are configured to be actuated simultaneously.
13. The drillstring anchor as claimed in claim 5 or any of claims 6 to 12 as dependent on claim 5, wherein the drillstring anchor comprises at least one energy store and wherein each actuator is capable of being driven from one or more of the at least one energy store to cause the gripper to grip the wellbore.
14. The drillstring anchor as claimed in any preceding claim, wherein, when the or each actuator is driven to cause its respective gripper to grip the wellbore, the drillstring anchor is configured to restrict relative rotation between the drillstring and the wellbore.
15. The drillstring anchor as claimed in any preceding claim, wherein the or each gripper is configured to exert an outward force on the wellbore relative to the longitudinal axis of the channel.
16. The drillstring anchor as claimed in any preceding claim, wherein the or each gripper is capable of gripping the wellbore independently of whether drilling fluid is flowing through the drillstring.
17. The drillstring anchor as claimed in any preceding claim, wherein the channel is configured to allow relative axial movement of the downhole portion of the drillstring and the drillstring anchor.
18. The drillstring anchor as claimed in any preceding claim, wherein the channel has a non-circular cross-section.
19. The drillstring anchor as claimed in any preceding claim, wherein the channel is configured to engage with features on the exterior surface of the downhole portion of the drillstring.
20. The drillstring anchor as claimed in any preceding claim, wherein the or each gripper comprises 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.
21. The drillstring anchor as claimed in claim 20, wherein the or each gripper comprises a lever mechanism for exerting mechanical advantage to move each pad outwardly from the channel.
22. The drillstring anchor as claimed in any preceding claim, wherein the drillstring anchor has a limit of travel along the downhole portion of the drillstring and wherein the or each actuator is configured to be driven to cause the gripper to not grip the wellbore when the drillstring anchor reaches the limit of travel along the downhole portion of the drillstring.
23. The drillstring anchor as claimed in any preceding claim, wherein the drillstring anchor further comprises 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.
24. The drillstring anchor as claimed in claim 23, wherein the swivel is a unidirectional swivel.