Downhole system for use in a borehole

Abstract

Described is a downhole system for use in a borehole comprising: one or more anchoring units operable to grip the borehole; one or more axial thrusting mechanisms operable to apply axial thrust; a directional drilling tool having a proximal end and a distal end, the directional drilling tool being coupled to a drill bit at its distal end, the directional drilling tool being capable of adopting multiple angular orientations; and a controller configured to transmit one or more control signals to cause the axial thrusting mechanism(s) to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to a target steering direction.

Description

[0001] GAD01 -134392PC

[0002] DOWNHOLE SYSTEM FOR USE IN A BOREHOLE

[0003] FIELD OF THE INVENTION

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

[0005] BACKGROUND

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

[0007] In the drilling of directional wells, where the borehole deviates from a vertically straight line, it can be difficult to maintain a high rate of penetration in the target steering direction. It can be challenging to keep the drill bit pointing in the direction of desired drilling, because when drilling with a motor or other rotational drive, the motor is near the distal end of a very long drillstring which is torsionally flexible. The drillstring can be twisted multiple times in its free state from the top to the bottom of the drillstring. The orientation of the bottom of the drillstring can in some cases differ by more than 720° to that of the top of the drillstring which is manipulatable by the driller on the rig. The motor’s torque applied to the bit is reacted against or into the drillstring above the motor. As the torque of the motor varies due to uneven and / or sporadic drilling conditions, the reactive torque varies sporadically. This varying reactive torque can vary the twist in the considerable length of drillstring above the motor, which can make it difficult for the driller on the surface to keep the motor oriented in the target direction of drilling. Furthermore, typical apparatuses for directional drilling such as rotary steerable systems are generally positioned directly above the drill bit. For disruptive drilling technologies, such as plasma-assisted drilling, this can occupy space in the bottom hole assembly needed for components such as spark generators and controllers.

[0008] It is desirable to develop approaches for addressing at least some of the above issues.

[0009] SUMMARY

[0010] According to a first aspect, there is provided a downhole system for use in a borehole comprising: one or more axial thrusting mechanisms operable to apply axial thrust; a directional drilling tool having a proximal end and a distal end, the directional drilling tool being coupled to a drill bit at its distal end, the directional drilling tool being capable of adopting multiple angular orientations; and a controller configured to transmit one or more control signals to cause the axial thrusting mechanism(s) to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to a target steering direction.

[0011] The directional drilling tool may be a bent sub or a kick pad.

[0012] The system may further comprise a central shaft. The directional drilling tool may be coupled to the central shaft at its proximal end. The directional drilling tool may be capable of adopting multiple angular orientations relative to the longitudinal axis of the central shaft. The one or more control signals may cause the axial thrusting mechanism(s) to apply axial thrust to the central shaft in dependence on the angular orientation of the directional drilling tool relative to the target steering direction.

[0013] Where the directional drilling tool is a bent sub, the bent sub may be coupled to the central shaft at its proximal end. The bent sub may be capable of adopting multiple angular orientations relative to the longitudinal axis of the central shaft. The one or more control signals may cause the axial thrusting mechanism(s) to apply axial thrust to the central shaft in dependence on the angular orientation of the bent sub relative to the target steering direction. The directional drilling tool (for example, bent sub) may be directly or indirectly connected to the central shaft.

[0014] The one or more axial thrust mechanisms may comprise one or more axial thrust chambers. The one or more axial thrust chambers may be configured to receive pressurised drilling fluid. The pressurized drilling fluid may be received from or via the drillstring. The axial thrust applied by the one or more axial thrust mechanisms may be dependent on the pressure in the one or more axial thrust chambers. The pressure in the chambers may depend on the pressure of drilling fluid in the chambers.

[0015] The system may further comprise one or more anchoring units operable to grip the borehole.

[0016] The one or more axial thrust mechanisms may be configured to apply axial thrust when the one or more anchoring units are gripping the borehole. The one or more anchoring units may grip the side wall(s) of the borehole. The axial thrust may be generated when the one or more anchoring units are operated to grip the borehole. The axial thrust may be generated via the one or more anchoring units gripping the borehole. The one or more axial thrust mechanisms may be configured to generate axial thrust by transferring or reacting axial forces to the borehole via the one or more anchoring units.

[0017] The central shaft may be configured to extend through the one or more anchoring units. Each anchoring unit may comprise a central shaft.

[0018] Alternatively, the shaft may be rigidly connected to a part of the anchoring unit. The bent sub or other directional drilling tool may be rotated from a motor below the anchoring unit. The gripper(s) of the anchoring mechanism(s) may be wheels or blades that move via a mechanism.

[0019] The central shaft may be rigidly connected to or integral with the one or more anchoring units.

[0020] The central shaft may be configured to rotate relative to the one or more anchoring units.

[0021] The one or more axial thrusting mechanisms may be part of one or more of the anchoring unit(s). The system may further comprise a motor proximal of the one or more anchoring units. The directional drilling tool (for example, bent sub) may be configured to be rotationally driven from the motor.

[0022] The directional drilling tool (for example, bent sub) may be configurated to be rotationally driven from a drilling rig at the surface of the borehole.

[0023] The assembly might not contain a separate rotary drive system and may wholly be rotated from the surface.

[0024] The directional drilling tool (for example, bent sub) may be coupled to a drilling motor. The drilling motor may be configured to provide rotational drive to the drill bit. The directional drilling tool may be coupled to a tool configured to provide rotational drive that is regulated and / or controlled using differential pressure.

[0025] The controller may be configured to transmit one or more further control signals to the drilling motor to vary the rotational speed of the drill bit in dependence on the orientation of the directional drilling tool relative to the target steering direction.

[0026] The controller may be configured to modulate the axial thrust applied by the one or more axial thrusting mechanisms in dependence on a measured instantaneous angular orientation of the directional drilling tool (for example, bent sub) relative to the target steering direction.

[0027] The controller may be configured to cause the axial thrusting mechanism(s) to increase the axial thrust applied to the directional drilling tool when the orientation of the directional drilling tool is within a predetermined range of the target steering direction.

[0028] The controller may be configured to cause the axial thrusting mechanism(s) to reduce the axial thrust applied to the directional drilling tool when the orientation of the directional drilling tool is not within a predetermined range of the target steering direction. The controller may be configured to cause an increase in the rotational speed of the drill bit when the orientation of the directional drilling tool is within a predetermined range of the target steering direction.

[0029] The system may further comprise one or more sensors configured to measure the angular orientation of the directional drilling tool (for example, bent sub). The controller may be configured to: receive data from the sensor(s); determine the angular orientation of the directional drilling tool relative to the target steering direction in dependence on the data received from the sensor(s); and transmit the or more control signals to cause the axial thrusting mechanism to apply axial thrust to the directional drilling tool in dependence on the determined angular orientation of the directional drilling tool relative to a target steering direction.

[0030] The controller may be configured to implement closed loop feedback in dependence on a measured rate of penetration of the drill bit and / or modulate the rate of penetration in dependence on the angular orientation of the directional drilling tool relative to the target steering direction while the drill bit and the directional drilling tool rotate.

[0031] The system may further comprise a measurement while drilling tool. The controller may be configured to receive positional and steering data from the measurement while drilling tool and transmit control signals to cause the axial thrusting mechanism to apply thrust to the directional drilling tool and / or vary the rotational speed of the drill bit in dependence on the positional and steering data received from the measurement while drilling tool.

[0032] The system may further comprise a rotary steerable system.

[0033] The one or more axial thrust mechanisms may apply axial thrust via anchoring against the borehole. For example, the one or more axial thrust mechanisms may comprise one or more grippers for gripping the borehole. The one or more grippers may allow axial thrust to be applied to the directional drilling tool when the one or more grippers are gripping the borehole.

[0034] According to another aspect, there is provided a method for drilling in a borehole using a system comprising one or more axial thrusting mechanisms operable to apply axial thrust and a directional drilling tool having a proximal end and a distal end, the directional drilling tool being coupled to a drill bit at its distal end, the directional drilling tool being capable of adopting multiple angular orientations, the method comprising: determining an angular orientation of the directional drilling tool relative to a target steering direction; and sending one or more control signals to the one or more axial thrusting mechanisms to cause the one or more axial thrusting mechanisms to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to the target steering direction.

[0035] According to a further aspect, there is provided an orienter for use with a downhole tool in a drillstring, the orienter being configured to angularly orient the downhole tool relative to a longitudinal axis of the orienter, the orienter comprising: a housing; one or more axial thrust chambers within the housing; and a mandrel axially and rotationally moveable within the housing, the mandrel configured to move axially within the housing in dependence on the pressure in the axial thrust chamber(s) and the mandrel comprising one or more features configured to move in a helical groove of the housing; wherein the mandrel is configured for engagement with the downhole tool such that axial movement of the mandrel within the housing causes angular rotation of the downhole tool about the longitudinal axis of the orienter.

[0036] The mandrel may optionally be a helically splined mandrel. The mandrel may have other forms.

[0037] The one or more axial thrust chambers may be configured to receive pressurised drilling fluid. This may provide the pressure in the axial thrust chambers. This may cause the mandrel to move axially within the housing in dependence on the pressure. The pressurized drilling fluid may be received from or via the drillstring. The movement of the mandrel may be dependent on the pressure in the chambers. The pressure in the chambers may depend on the pressure of drilling fluid in the chambers.

[0038] The orienter may comprise a valving system configured to receive drilling fluid via the drillstring. The axial movement of the mandrel within the housing may be hydraulically driven using the valving system. The valve(s) of the valving system may in some examples be electrically actuated rotary valves. The orienter may be configured to hold an incremental angular position when the flow of drilling fluid to the valving system is halted.

[0039] The axial movement of the mandrel within the housing may be driven by an electrical power source.

[0040] The orienter may be configured to cause angular rotation of the downhole tool relative to the longitudinal axis of one or more uphole components in the drillstring.

[0041] The one or more axial thrust chambers may be configured to receive pressurised fluid from one or more of the uphole components in the drillstring.

[0042] The pressurised fluid may be drilling fluid or clean hydraulic fluid.

[0043] The one or more uphole components may comprise an anchor tool.

[0044] The mandrel may be axially splined to the downhole tool so as to allow relative axial movement between the mandrel and the downhole tool.

[0045] The downhole tool may be a bent sub. The spline angle and / or length of the mandrel may allow more than one complete rotation of the downhole tool (for example, bent sub).

[0046] At least one axial thrust chamber may house one or more members configured to bias the axial movement of the mandrel within the housing in the downhole direction.

[0047] The orienter may be configured to continuously adjust the angular orientation of the downhole tool based on the real-time orientation of the downhole tool and / or wellplan information.

[0048] The orienter may be proximally coupled to a downhole anchor tool and wherein the drillstring proximal of the anchor comprises coiled tubing.

[0049] According to a further aspect, there is provided a method for performing a downhole operation in a borehole, the method comprising: providing a drillstring comprising coiled tubing proximally coupled to a downhole anchor tool; providing an orienter coupled to a downhole tool and configured to angularly orient the downhole tool, the orienter being distal of the downhole anchor tool; and applying axial thrust to the orienter using the downhole anchor tool.

[0050] The orienter used in the method may be the orienter having any of the features described above.

[0051] The downhole tool and / or the bottom hole assembly may comprise one or more downhole sensors configured to measure or infer one or more of pressure, downhole weight on the distal tool and downhole torque on the distal tool.

[0052] The anchor tool or anchoring unit may be configured to apply longitudinal force to the distal tool via the drillstring (e.g. via one or more components of the drillstring distal of the anchor and / or proximal of the distal tool).

[0053] The anchor tool or anchoring unit may comprise an internal channel for conveying the flow of drilling fluid to the distal tool, wherein the processor is configured to maintain a differential pressure between the channel and the annulus of the borehole within a predetermined range.

[0054] The anchor tool or anchoring unit may comprise one or more grippers for engaging the borehole to restrict relative axial and / or rotational movement between the gripping element and the borehole.

[0055] The anchor tool or anchoring unit may be coupled with a tool for performing a downhole operation at the distal end of the bottom hole assembly. The anchor tool or anchoring unit may be configured to apply weight to the tool to urge the tool into the borehole or against the bottom of the borehole. The drillstring or the bottom hole assembly may terminate in a distal tool such as, for example, a conventional drill bit, a plasma drilling head or other drilling mechanism.

[0056] The anchor tool or anchoring unit may be communicatively connectable with a downhole control unit. In other implementations, the control unit may be at the surface and may be connected to the downhole apparatus using a wired connection, such as electrified wireline (E-line). The control unit may comprise the processor. The control unit may be configured to adjust the configuration of the anchor and / or one or more other elements coupled to the anchor (for example, coupled directly or indirectly at the distal end of the anchor) in response to one or more signals. The one or more other elements may be communicatively connectable to the anchor. This may allow signals to be passed through the anchor and / or for signals to be transferred between the anchor and components of a bottom hole assembly than the anchor. The anchor tool or anchoring unit may comprise the control unit. The control may comprise the processor and one or more memories. The memory may store in a non-transient way code that is executable by the processor to implement the methods described herein. Adjusting the configuration of the anchor tool or anchoring unit may comprise adjusting the configuration of the gripper and / or adjusting the configuration of one or more other parts of the anchor, such as one or more pistons for applying an axial force to the drillstring or one or more of the other elements coupled with the anchor tool or anchoring unit, such as a drill bit.

[0057] The anchor tool or anchoring unit may further comprise or be communicatively connectable with one or more measurement devices for determining one or more downhole parameters. For example, torque, axial force, bending force, pressure and temperature.

[0058] The anchor tool or anchoring unit may be configured to react axial loads to the borehole when the gripping element is gripping the borehole. The anchor tool or anchoring unit may be configured to react torsional loads to the borehole when the gripping element is gripping the borehole. The gripping element may be configured to grip the borehole to restrict both relative rotation and relative axial movement between the anchor and the borehole. The anchor may be configured to react both axial loads and torsional loads to the borehole when the gripping element is gripping the borehole.

[0059] The anchor tool or anchoring unit may be configured to apply longitudinal force to one or more distal downhole components coupled to the anchor tool or anchoring unit. The anchor may be part of a bottom hole assembly, wherein the anchor is configured to urge the bottom hole assembly into the borehole.

[0060] The anchor tool or anchoring unit may comprise multiple gripping elements each configured to move axially relative to a body of the anchor. The multiple gripping elements may be disposed on the same body, or across multiple body parts that are axially separated along the longitudinal axis of the apparatus. The multiple body parts may each act as separate anchor tools that are independently controlled. The anchor tool or anchoring unit may comprise a drive mechanism for advancing one gripping element downhole and / or uphole relative to at least one other gripping element. Where the anchor tool or anchoring unit comprises multiple body parts, each body part having multiple gripping elements each configured to move axially relatively to its respective body part, each body part may have a respective drive mechanism for advancing one gripping element downhole and / or uphole relative to at least one other gripping element.

[0061] The or each gripping element may have an associated actuator. The actuator may be capable of being driven to cause the respective gripping element to adopt at least one of (a) a first state in which it is urged outwardly for gripping the borehole and (b) a second, passive state. In some cases, one actuator may be used to drive multiple grippers, or each gripper may have its own actuator.

[0062] The operation of the or each gripping element may be powered by one or more of the following: the flow of drilling fluid through the anchor; an energy store (such as a battery or other energy source or a reservoir of hydraulic fluid), a thermal gradient between the interior of the anchor and the annulus of the borehole; via an electric conduit connectable with the connector (where electrical power is supplied from the surface); by differential rotation between the anchor and the drillstring or the output of a mud motor.

[0063] The anchor tool or anchoring unit may be part of a downhole assembly comprising one or more additional downhole tools. The one or more additional downhole tools may comprise one or more of the following: a measurement-while-drilling tool, a logging-while-drilling tool, a fluid conditioning module to regulate hydraulic fluid and / or filter drilling fluid, an orienter tool, a fixed or variable bent sub, a rotary steerable system, a downhole motor (such as a steerable mud motor) for providing rotational drive and / or torque to a drilling or milling tool at a distal end of the drillstring. The drillstring may comprise one or more drilling tools. The drilling tool at the distal end of the drillstring may comprise a conventional rock bit, a PDC bit, a hybrid bit or a plasma bit.

[0064] The anchor tool or anchoring unit may comprise one or more channels for receiving drilling fluid from the drillstring and conveying the drilling fluid towards the distal end of the drillstring. According to a further aspect, there is provided a downhole tool for applying axial vibration to a drillstring, the downhole tool being communicatively connected with a controller configured to: determine the resonant frequency of the drillstring; and control the downhole tool to apply axial vibration at a frequency within a predetermined range of the resonant frequency of the drillstring.

[0065] The controller may be configured to dynamically deteremine the resonant frequency of the drillstring from data received from one or more sensors located on the drillstring.

[0066] The resonant frequency of the drillstring may be provided as an input to the controller.

[0067] The downhole tool may comprise the controller.

[0068] The controller may be configured to control the downhole tool to apply axial vibration at the resonant frequency of the drillstring.

[0069] The controller may be configured to control the downhole tool to apply axial vibration at an amplitude at or below a vibration amplitude threshold.

[0070] The vibration amplitude threshold may be a known threshold at which damage or degraded performance would be caused to one or more elements of the drillstring.

[0071] According to a further aspect, there is provided a downhole subsystem comprising: the downhole tool described above; and a further downhole tool comprising one or more axial thrusting mechanisms, the further downhole tool being configured to create axial thrust to damp oscillation in the drillstring and / or control one or more of depth or cut and torque of a distal tool.

[0072] According to a further aspect, there is provided a method of controlling a downhole tool for applying axial vibration to a drillstring, the method comprising: determining the resonant frequency of the drillstring; and controlling the downhole tool to apply axial vibration at a frequency within a predetermined range of the resonant frequency of the drillstring.

[0073] According to a further aspect, there is provided a downhole tool for applying axial vibration, the downhole tool being communicatively connected with a controller configured to control the downhole tool to apply axial vibration at a frequency and / or amplitude. The frequency of the axial vibration may be applied in dependence on one or more of: a local vibration amplitide at the downhole tool, a remote measured vibration amplitude, and based on attaining a target vibration amplitude at the downhole tool or a remote location in a bottom hole assembly or drillstring.

[0074] The downhole tool may comprise the controller.

[0075] The downhole tool may be used without the anchor tool or the anchor tool may have the features of the downhole tool.,

[0076] The borehole may be a wellbore. The wellbore may be formed to aid the exploration and / or recovery of natural resources such as oil, gas or water. The borehole may be another type of borehole. The borehole may comprise one or more non-vertical sections.

[0077] The apparatus, e.g. the downhole tool, anchor, orienter and / or controller, may constitute one or more subsystems.

[0078] BRIEF DESCRIPTION OF THE FIGURES

[0079] The present invention will now be described by way of example with reference to the accompanying drawings. In the drawings:

[0080] FIG. 1 schematically illustrates an example of a drilling system, illustrated at a subterranean location in a borehole during a downhole operation;

[0081] FIG. 2 schematically illustrates an example of an anchor comprising multiple gripping segments;

[0082] FIG. 3a schematically illustrates an example of a gripper made from a hard material;

[0083] FIG. 3b schematically illustrates an example of a gripper made from a hard material;

[0084] FIG. 3c schematically illustrates an example of a gripper made from a hard material;

[0085] FIG. 4 schematically illustrates an example of a control unit;

[0086] FIG. 5a schematically illustrates a system comprising a bent sub, an anchor and a drill bit driven by a drilling motor;

[0087] FIG. 5b schematically illustrates an example of an anchor tool having chambers for the application of a longitudinal force by the anchor to a distal tool; FIG. 5c schematically illustrates an example of the application of a longitudinal force by the anchor to a distal tool;

[0088] FIG. 6 shows a view along the drillstring in the downhole direction of the arrangement of FIG. 5;

[0089] FIG. 7 shows the steps of an exemplary method for drilling in a borehole;

[0090] FIG. 8 shows an example of an orienter tool;

[0091] FIG. 9 illustrates a region of splined engagement between the housing and mandrel of the orienter tool of FIG. 8;

[0092] FIG. 10 shows the steps of an exemplary method for performing a downhole operation in a borehole;

[0093] FIG. 11 schematically illustrates a system comprising a downhole tool for applying axial vibration.

[0094] FIG. 12 shows the steps of an exemplary method for controlling a downhole tool.

[0095] DETAILED DESCRIPTION

[0096] FIG. 1 schematically illustrates an example of a drilling system illustrated at a subterranean location in a borehole (not to scale). In FIG. 1 , although for illustrative purposes the borehole illustrated is vertical, the borehole may have a more complicated two or three dimensional path and may also include multiple branches.

[0097] In operation, a rig 101 provides support and / or power to a drillstring. The drillstring may comprise, for example, conventional drill pipe or coiled tubing. The drillstring comprises multiple components and terminates in a distal tool 108.

[0098] The borehole is shown at 104. The borehole may be at least partially lined with casing 105 and cement 106. The portion of the drillstring shown at 102 may provide torque and / or power (for example, rotary, thermal, and / or electrical power) to the bottom hole assembly (BHA), shown generally at 107. The BHA is part of the drillstring and may comprise a tool or other component 108. The tool 108 may be a drilling tool. The tool 108 may be, for example, a drill bit. For example, tool 108 in FIG. 1 may be a conventional drill bit such as a polycrystalline diamond compact (PDC) drill bit, a roller cone drill bit or a hybrid bit (a combination of PDC and roller cone). Drilling fluid can be pumped to the component through the drillstring and released into the annulus of the borehole, as shown at 109. The drilling fluid 109 acts to convey cuttings to the surface. The drilling fluid may be referred to as drilling mud.

[0099] The BHA 107 can also comprise one or more additional components. The components described below are exemplary and the BHA may alternatively or additionally comprise other components. The described components need not be immediately adjacent to one another and may be separated by further components.

[0100] The component 110 is a downhole motor, such as a mud motor, for providing rotational drive to the tool 108. The motor may be a positive-displacement mud (PDM) motor. Alternatively, an electric motor or other type of motor may be used. The motor may be a steerable motor. The motor may be a bent motor, which may allow for improved directional control when performing directional drilling.

[0101] The component shown at 111 is a measurement-while-drilling (MWD) tool. The MWD tool provides borehole direction and formation evaluation data. The MWD tool may utilize conventional telemetry techniques (such as mud pulse telemetry) with standalone battery powered tools. The MWD tool may be integrated with the cable(s) in the coiled tubing for higher density data and more reliable decoding in deep applications with challenging mud properties. The data collected by the MWD tool may include shock, vibration, pressure, weight and torque data. The data may be used for closed loop control and optimization of the drilling process.

[0102] The MWD tool 111 may comprise a means of transmitting information to the surface. This may be performed by, for example, mud pulses, whereby the operation of a valve in the fluid flow-path in the drillstring, or by allowing fluid to egress the interior of the drillstring to the annulus, induces pressure variations which may be detected using pressure and / or flow measurements at the surface. Alternatively, this may be performed by electro-magnetic means, where a voltage across an insulated section of drillstring is varied, and these 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 electromagnetic and wired coiled tubing telemetry allow for bi-directional communication, and hence may receive signals transmitted from the surface. As well as communication means, the MWD system may comprise magnetometers and accelerometers, used to measure the earth’s magnetic and gravitational fields, and from which are derived the position of the instrument in the subsurface and hence the trajectory of the borehole. Additionally, there may be other measurement instruments, such as strain-gauges, accelerometers, pressure sensors and gyroscopes to measure the mechanical stresses imposed on, and the motion of, the MWD module.

[0103] In some implementations, a logging while drilling (LWD) tool may alternatively or additionally be used.

[0104] The component shown at 112 is a steering device. The steering device may be an orienter tool. The orienter may be a high torque orienter. The orienter can electrically or hydraulically orient the motor to direct the borehole. This can help to minimize tortuosity by allowing steerable motor to be rotated to drill straight ahead. This can also allow for closed loop trajectory control due to high-speed well directional data and control of the orienter via the E-line. The orienter might not be used in a BHA that comprises a rotary steerable system (RSS). In this case, the RSS may be used to steer the motor to direct the borehole.

[0105] In general, the steering device 112 can utilize some combination of force applied to the borehole, or curvature of the drillstring in order to control the direction of the drill bit. The steering device may be communicatively coupled to the surface. This may allow the steering device to receive commands transmitted from the surface, for example via the E-line, which may allow the drill bit to be urged to follow a desired trajectory.

[0106] The component shown at 113 is an anchor tool, which will be described in more detail below. In some implementations, the anchor 113 may be connected to the part of the drillstring 102 via a coupling 114, such as a swivel. The coupling 114 may couple the anchor 113 to a connector 115 which allows the portion of the drillstring 102 above the anchor to be connected to the proximal (i.e. upbore) end of the connector 114. The coupling may be a flexible coupling. The flexible coupling may allow relative movement of the connector for connection to the drillstring and the anchor about and / or along one or more axes. For example, the coupling may be rotatable and / or axially compliant, as will be described in more detail later.

[0107] The anchor may comprise a channel for receiving a shaft. The anchor may comprise the shaft. The shaft may pass through the channel in the interior of the anchor. The shaft can move longitudinally within the anchor. The shaft can rotate relative to the channel. The shaft may move independently of the gripper(s). The shaft may be axially fast with components of the drillstring or BHA below the anchor. That is, the shaft may move with the components of the drillstring below the anchor. When the gripper(s) is / are gripping the wellbore, the shaft may be configured to move relative to the gripper(s). For example, when the gripper(s) is / are gripping the wellbore, the shaft may be rotatable relative to the channel of the anchor through which the shaft passes. This can allow the BHA / bit to be rotated while the grippers are axially and rotatable locked to the borehole. Torsional anchoring may be achieved using keys or protrusions on the exterior of the shaft and keyways in a surface of the anchor facing the shaft (e.g. in the channel) that engage the keys and prevent relative rotation between the shaft and the wellbore when the one or more grippers are activated to grip the wellbore. The gripper(s) may grip the wellbore fully or partially. When the gripper(s) grip the wellbore, relative axial and / or rotational movement between the gripping element and the borehole may be partially or fully restricted.

[0108] The drilling fluid may be supplied to the tool (and more distal components such as the drill bit) from a tank 120 at the surface of the borehole which is fed to the BHA via pipes 121. The tank may be coupled to a chiller 125. The chiller may cool the drilling fluid. The chiller may keep the drilling fluid at a temperature that is below a predetermined threshold. This may allow for a reduction in bottom hole temperature, making deeper and hotter drilling possible.

[0109] The anchor 113 can transfer axial forces and / or reactive torque from the BHA to the borehole. This may help to prevent the initiation of torsional oscillations in the drillstring, including stick slip. The anchor is designed to remove at least some, and preferably all, of the torque from the drillstring when reactive torque is transferred to the borehole.

[0110] In the system described above with reference to FIG. 1 , the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit below the anchor. However, the anchor described herein may be utilized in non-rotary drilling situations such as jetting or plasma drilling (a contactless drilling technique that uses high- voltage pulses to fracture the rock) or any other compatible operation or situation in a borehole, such as a milling, completion or plug and abandonment operation. Other additional components of the BHA may be drill collars, stabilizers, reamers, hole-openers and bit subs. The rig 101 , provides support for the drillstring. Drilling fluid is circulated through the drillstring via pipes and hoses 121 , from mud tanks 120 by fluid pumps (not shown). The fluid returns to the mud tanks via a further flow channel and shale shakers (not shown). One or more surface computational platforms 123 may perform functions such as controlling the operation of the auto-driller, top-drive and mud-pumps, or they may contain embedded controllers. The surface computational platform 123 can communicate with off-site computers or individuals, using an antenna or cable 124, which may enable effective control to be conducted remotely from the well site. One or more of the components located at the surface of the borehole are part of a surface system of the drilling system.

[0111] In some implementations, the drilling rig may be instrumented, so that parameters related to the drilling operation may be determined at the surface. For example, one or more of the tension applied by the portion of the drillstring 102 to the drilling line (hook-load), the vertical motion of the top of the string (the surface rate-of-penetration), the torque applied to and the rotation speed of the string, and the flow rate and pressure of the drilling fluid at surface. This list is not exhaustive, and other parameters may be monitored.

[0112] The exemplary BHA shown in FIG. 1 comprises a source of electrical power, which may for example be a fluid-driven turbine, the rotation of which generates an electrical current. Alternative sources of electrical power include batteries or capacitors, or an interface to the E-line, allowing power to be transmitted from the surface. As the turbine rotation speed depends on the flow rate of drilling fluid flowing through the BHA, by measuring the rotation speed, the turbine may also have a subsidiary role in detecting flow rate changes made at surface using the mud-pump controller and mud-pump through which information may be transmitted from the surface to the BHA.

[0113] In this implementation, the drill bit is driven to rotate by a downhole mud motor to form the borehole in the formation. Where the BHA comprises a motor for rotating the bit, the anchor is configured to be mounted above the motor. The motor may be a mud motor. Alternatively, the drill bit may be driven by other downhole rotary drive devices such as electric motors, pneumatic motors or a drilling turbine. For some types of drill bits, such as bits for plasma drilling, a motor for rotating the bit may not be required.

[0114] The BHA may also comprise a fluid conditioning module to regulate hydraulic pressure and / or to filter the drilling fluid. FIG. 2 shows an example of an anchor 113. In this example, the anchor 113 comprises multiple segments 201 , 202 each comprising one or more grippers 203. For example, each segment 201 , 202 may comprise multiple grippers. The segments 201 , 202 can be moved longitudinally relative to each other using a walking mechanism.

[0115] The use of multiple electrically coordinated (for example via a control unit 400 of the anchor) gripping segments, optionally utilizing MWD / LWD and RSS technology, may allow for a coordinated downhole operation. The control unit 400 may also allow for downlinking in non-wired I conventional drilling applications and communication with other BHA tools.

[0116] As shown in FIG. 2, the anchor 113 comprises a first gripping segment 201 and a second gripping segment 202. In this example, the gripping segment 201 comprises an upper gripper set and the gripping segment 202 comprises a lower gripper set (‘upper’ and ‘lower’ being relative to the end of the borehole).

[0117] Connector 204 is an upper connector for connection to drill pipe or an upper part of the BHA. Connector 205 is a lower connector for connection to a downhole mud motor or a lower part of the BHA. The connectors may both comprise adapters to industry standard connectors used to connect the anchor to the adjacent sections of the drillstring.

[0118] In this example, the anchor comprises a wired flex portion 206 between the two gripping segments 201 , 202. This may allow the lower gripping segment 202 to electrically communicate with the control unit 400 and / or the upper gripping segment 201. This can allow control signals and / or power to be supplied to the lower gripping segment from the control unit 400.

[0119] Each gripping segment 201 , 202 comprises a gripper housing 207, 208. The gripper housings house the grippers 203. The gripper housings 207, 208 can move longitudinally relative to the main body of the tool along sections 209, 210 respectively. The range of longitudinal movement along the sections 209, 210 may be referred to as the ‘tool stroke’ (as indicated in FIG. 2). This can allow the gripper housing of one gripping segment to move longitudinally relative to the housing of the other segment when the other segment is gripping the wellbore. This can allow drilling to progress whilst anchoring is active. The handover from one gripping segment to the other may be determined based on the position of the other gripping segment relative to one or more other parts of the tool, or after a predetermined time since the segment currently gripping was actuated. Alternatively, the segment currently gripping the borehole may release automatically when the other segment is actuated to grip the borehole, or once the other segment is determined to be gripping the borehole, for example when a target gripping force of pressure of a hydraulic actuator is reached. For example, the gripper of a free (i.e. not currently gripping) segment may be triggered to grip the borehole when the currently gripping segment is 20mm from the end of its longitudinal range of travel relative to the housing of the anchor. The currently gripping segment could then be released after another 10mm of drilling (measured by the relative longitudinal movement of the shaft and the channel in which the shaft moves inside the anchor). An alternative implementation is to release the gripper of the currently gripping segment a fixed time after the free segment gripper activation is started.

[0120] In another implementation, the gripper of the free segment may be actuated to grip the borehole when the currently gripping segment is at a predetermined distance from the end of its longitudinal range of travel relative to the housing. The gripper of the currently gripping segment may then be released from the borehole when the gripper of the other segment has reached a target force against the borehole or a target pressure in the case of a hydraulically actuated gripper such as a piston.

[0121] In some implementations, the anchor may be actively controlled from a power source to push the drillstring, or push a shaft extending through the anchor and coupled to the drillstring, in a downhole direction and apply weight-on-bit to a drill bit, or apply weight to another downhole tool, at the distal end of the drillstring. The anchor may also be configured to apply axial force to the BHA below the anchor to urge the BHA into the borehole (i.e. in the downhole direction). Axial forces may also be applied to the drillstring in a similar way by controlling the anchor to pull the shaft in an uphole direction.

[0122] In one implementation, one or more of the gripping segments may comprise an axial piston moveable within a cylinder. The piston may be connected to the gripper housing and the cylinder may be connected to the shaft running through the anchor (or vice versa). The anchor comprises the shaft. The shaft is axially / longitudinally fast with the distal tool (that is, longitudinal movement of the shaft results in longitudinal movement of the distal tool). Longitudinal force may be applied to the distal tool by applying longitudinal force to the shaft of the anchor. The enclosed volume between the piston and the cylinder may be connected to an actuator or valve controlling the flow of pressurized fluid (such as oil or drilling fluid) into the volume to cause axial movement of the gripper in response to movement of the shaft and to provide longitudinal force transfer to the drillstring / BHA. This piston may be single acting with a mechanical return (such as a spring) or double acting to allow axial force to be applied to the drillstring in both the uphole and downhole directions. The pressurization of the fluid may be controlled based on the internal pressure of drilling fluid flowing through the anchor, may be regulated to remain substantially constant, or may be modulated based on other factors. This may allow longitudinal force to be applied to the drillstring at the anchor, which may be used to provide weight-on-bit (WOB) to a drill bit, or weight on another distal tool, at the distal end of the drillstring.

[0123] In other implementations, the anchor 113 may comprise a single gripping segment that is activated to grip and release the borehole without the walking mechanism or alternatively may comprise individual gripping and push / pull modules that can be connected (for example electrically, mechanically or hydraulically) such that they work in coordination to allow movement and force to be transferred to the drillstring.

[0124] The anchor advantageously allows the ability to rotate the drillstring during axial anchoring and for the dril Isring to move axially relative to the anchor during torsional anchoring.

[0125] The apparatus can comprise one or more channels for receiving fluid from the surface via the drillstring and conveying the fluid towards the distal end of the drillstring. As mentioned above, fluid, such as drilling fluid / mud, may be supplied to the bottom of the borehole from tanks at the surface.

[0126] As mentioned above, the anchor comprises one or more gripping elements (referred to herein as grippers 203) that can be activated by one or more actuators. The actuator can be driven to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the walls of the borehole and a second, passive state. When activated, the gripper can grip the borehole. The gripper is configured to exert an outward force on the borehole relative to the longitudinal axis of the anchor. When the gripper is activated, relative rotation between the gripper of the anchor and the borehole can be resisted and this can allow torque to be reacted to the borehole. Throughout this description, the term ‘activated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is urged outwardly relative to the central axis of the drillstring. In this state the gripper can grip the borehole. The term ‘deactivated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is exerting a reduced gripping force relative to the activated state. For example, it may be in a state where it is not gripping the borehole. In this state it might not be urged outwardly relative to the central axis. In the activated state the gripper may be in a location radially outwardly of its location in the deactivated state. The gripper may be biased to one of the states, e.g. by a spring.

[0127] An energy store can provide the energy supply to one or more actuators for actuating one or more of the grippers. The energy store may be a source of energy generated locally at the anchor. The energy store may be charged or refilled at the surface before running in hole. The energy store may be replenished (e.g. recharged) during or after a trip to the surface. The energy store may be self-contained in the anchor. The energy store is preferably a source of energy stored locally at the anchor. The energy store is preferably suitable for permitting the anchor to operate over an extended period of time without requiring replenishment from the surface of the borehole whilst the anchor is in hole. The energy store may be a source of electricity such as a battery or fuel cell. In other implementations, the anchor may be powered by an alternative energy source, such as a direct supply of power from the surface (for example, via the electrical conduit), via a mud- driven turbine or other mechanisms utilizing the flow of drilling fluid.

[0128] When the anchor is activated (i.e. when the actuator is driven to cause the gripper to grip the borehole), the drillstring may be translatable along its longitudinal axis with respect to the anchor. The anchor is configured to allow relative axial movement of the anchor and the drillstring. This may also be the case when the anchor is deactivated (i.e. when the actuator is driven or released to cause the gripper to not grip the borehole). When the anchor is activated, relative rotation between the gripper and the borehole can be resisted or restricted. This may be due to physical engagement between the gripper of the anchor and the interior face of the borehole.

[0129] Additional gripping modules or separate anchor tools may be used to increase torque and axial capacity. The ability to use multiple gripping modules can allow for a less stiff system, which may be advantageous for higher curvature wellbores. 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 might not be a significant difference in the radial displacement of the gripper in the passive (deactivated state) and the activated state. In the activated state the gripper is configured to restrict relative rotation between the anchor (e.g. the gripper(s) of the anchor) and the borehole. In both the activated and deactivated states the device is configured to allow axial movement of the drillstring relative to the device. In the deactivated state, the anchor can rotate relative to the borehole. In both the activated and deactivated states, relative rotation between the anchor and the downhole section of the drillstring is preferably restricted. In both the activated and deactivated states, the downhole section of the drillstring can move axially relative to the anchor in the downhole direction (i.e. in the direction of the bottom of the borehole, or the furthest reach of the borehole, in the case of a horizontal well) and / or the opposite direction (in the direction of the surface). The gripper can be in the deactivated state when drilling fluid is pumped through the drillstring. Alternatively, the gripper may be activated using mud pressure.

[0130] The anchor may grip the borehole by actuating one or more elements such as pistons or pads to exert an outward radial force on the borehole. A pad or piston may comprise teeth that provide resistance and allow the pad to grip the borehole. Various tooth designs may be used. The gripper may have a non-flat portion. For example, the surface of the gripper may have undulations and / or protuberances. The surface of the gripper may comprise ribs, ridges and / or studs.

[0131] The gripper of the anchor may comprise at least one pad or piston configured to extend in a circumferential or radial direction to engage the borehole. The at least one pad or piston may be configured to move outwardly from the anchor to engage the borehole when the actuator of the respective gripper is driven to cause the gripper to grip the borehole (i.e. when the anchor is activated).

[0132] In one implementation, the anchor comprises pistons which are capable of being urged outwardly for gripping the borehole from a passive state to an activated state. The pistons can move relative to the body of the anchor in a direction perpendicular to the longitudinal axis of the anchor between the passive state and the gripping state in which the piston is urged outwardly to cause a gripper area at the end of the piston to grip the borehole. In other words, the grippers can move in a radial direction relative to the longitudinal axis of the anchor.

[0133] The gripper assembly may comprise a housing that sits in the recess in the body of the gripping segment. The piston is accommodated in the housing and can move outward relative to the housing. The piston can move in the radial direction with respect to the longitudinal axis of the anchor. The piston may have a limit of travel within the housing.

[0134] In one example, the movement of the piston may be supported in the recess in the housing by bearings distributed around the circumference of the recess or channel. There may be multiple sets of bearings distributed along the length of the piston. There may be a grease or oil feed to the bearing area to allow for lubrication of the bearing and / or the contact surface between the housing and the piston. There may alternatively or additionally be one or more seals disposed around at least part of the piston.

[0135] 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.

[0136] In one example, shown in FIG.s 3a-3c, the piston is a cylindrical piston. In other implementations, the piston may have other forms. For example, the piston may be a spherical piston or a blade piston. In this example, the end of the piston has an insert which engages the borehole to grip the rock. In other examples, the end of the piston may engage the borehole directly with no additional insert. The gripper can therefore be a removeable and / or replaceable component or can be integral with the piston. Herein, the "gripper" is the part of the gripper assembly that grips the borehole. In FIG.s 3a-3c, the piston has an insert at the end of the piston for gripping the borehole. However, in other implementations, the tip of the piston may be compositionally undifferentiated from the body of the piston and might not have any particular surface formations or surface roughness.

[0137] The pistons may be controllable to move out from the body of the anchor in the radial direction by different amounts depending on the rock condition and mechanical properties. The pistons may advantageously dig through the filter cake (the solids in the drilling mud that line the borehole) to reach the wall of the borehole. The pistons may be capable of deforming elastically when they are urged outwardly to contact the borehole. Forces resulting from elastic deformation of the pistons may be used in addition to friction with the rock to generate a greater gripping force on the borehole.

[0138] In the example shown in FIG.s 3a-3c, the gripper 203 is a cylindrical piston with a circularcross section. The base of the piston has a flange 305 for limiting the travel of the piston within the housing, as described above. The opposite end 312 of the piston to the base has a chamfered profile. In this example, the end of the piston has an insert 311 which engages the borehole to grip the formation. As shown in FIG. 3c, the piston may be hollow to optionally accommodate a spring and defines a chamber for hydraulic fluid. In this example, the gripper comprises a hardened insert (made from, for example, Tungsten Carbide or Diamond) at the end of the piston. The insert is located at the contact face (i.e. the face of the piston that contacts the borehole when the piston is in the extended position). As mentioned above, the insert may have protrusions or teeth which are able to repeatedly cut through lubricant, rock dust and / or residue and engage with the rock surface of the borehole. In this example, the teeth have a pyramidal profile. However, other profiles may be used.

[0139] The grippers may have other forms. For example, the gripper may comprise a blade configured to extend to contact the borehole to provide torsional anchoring.

[0140] The anchor may allow for a continuous gripping action as the drillstring advances downhole in the borehole. Generally, a first segment (or first set of segments) or a part thereof can move longitudinally relative to a second segment (or second set of segments) or a part thereof. The first and second segments (or sets of segments) are coupled to each other such that the first segment (or set of segments) or part thereof is free to move along the longitudinal axis of the anchor relative to the second segment (or set of segments) or part thereof. The anchor comprises a drive mechanism for advancing the first segment (or set of segments) or part thereof downhole relative to at least the second segment (or set of segments) or part thereof. In some examples, there may be multiple anchors in the string having synchronized or asynchronous gripping assemblies.

[0141] In order for the anchor to have a continuous gripping action, there is a time when both segments (or set of segments) are activated to grip the borehole and the drillstring can continue to move longitudinally relative to the segments during the transition between the activation of one segment (or set of segments) and the deactivation of another. The transition includes the coordinated gripping and release of segments and may use a drive mechanism that is different to when only one segment (or set of segments) is activated. The transition may be initiated in dependence on the position of the drillstring, for example relative to the activated segment (or set of segments), in dependence on elapsed time since a segment (or set of segments) was activated, or by some other means.

[0142] Generally, the following sequence of steps is performed:

[0143] -a first gripping element (or set of elements) is activated to grip the borehole;

[0144] -the drillstring and a second gripping element (or set of elements) are driven to progress them downhole. In the preferred embodiment, the second element (or set of elements) progress at a different (faster) speed than the drillstring, for example at twice the ROP of the drill bit;

[0145] -a second element (or set of elements) is activated to grip the borehole;

[0146] -the first element (or set of elements) is deactivated and driven to progress down the borehole with the drillstring.

[0147] This may be referred to as a ‘walking’ sequence.

[0148] The anchor may comprise a means of or mechanism for advancing deactivated segments downhole at a higher rate than the advancement of the drillstring in the borehole (for example, at twice the ROP of the drill bit).

[0149] There may be multiple grippers along the length of the anchor. There may be multiple grippers distributed around the circumference of the anchor. For example, there may be three or four rows of twenty gripping assemblies.

[0150] The anchor and / or other components in the BHA may comprise one or more devices for measuring one or more of torque, radial force, axial force and pressure, or for measuring one or more parameters that can be used to derive such quantities. The measurement devices may comprise sensors, such as torque sensors, pressure sensors and axial force sensors, such as strain gauges. The devices may also measure other parameters which may be used to infer the value of torque, radial force, axial force and / or pressure. The devices may comprise mechanical or hydromechanical mechanisms that are configured to change state or move in response to variations in parameters such as torque, weight and pressure. That change or state or movement may be used to control or provide feedback to control the operation of the anchor. This may also allow these parameters to be measured downhole and then used to control the operation of the anchor or other components of the BHA, such as the steering device 112. The data may also be used to control the operation of the anchor, for example to control the operation of the gripper(s) or to control the axial force applied to the BHA, the drill bit or the drillstring.

[0151] As mentioned above, the anchor tool may comprise a control unit 400. An example of the control unit 400 and some of its associated components is shown in more detail in FIG. 4. The control unit comprises a processor 401 and a memory 402. The processor may execute computer code stored at the memory 402 to perform the functions described herein. The control unit 400 may control the anchor (for example, the configuration of one or more grippers of the anchor to control the axial and / or torsional force exerted against the borehole or to the drillstring below the anchor by the one or more grippers) based on control signals from a downhole processor. This can allow for autonomous control and / or kinematics control of the anchor and other components in the BHA. The control unit may also comprise a transceiver 403 for sending and receiving signals to and / or from other entities, such as sensors communicatively connected to the anchor.

[0152] The control unit 400 can control the multiple anchoring modules 201 , 202 and can allow for standalone operation (i.e. with no connection of the control unit to surface). In some implementations, the anchor control unit may also interface with an MWD module in the drillstring (for example to allow real-time feedback to an operator at the surface), and / or with E-line and / or wired drill pipe (for real-time two-way communications with the surface).

[0153] In some examples, the control unit 400 comprises one or more sensors 404 or may be communicatively connected with one or more other sensors of the anchor.

[0154] The control unit 400 may also be connectable to other components of the BHA. As mentioned above, the BHA may comprise a steering device 112, such as an orienter or an RSS. The use of a downhole control unit 400 can also allow high-speed well directional data to be transmitted to the steering device by sending control signals from downhole control unit 400.

[0155] The processor 401 of the control unit 400 of the anchor may be configured to execute a control strategy to vary the axial push / pull force applied to components proximal or distal of the anchor (for example, to the drillstring to push or pull it down the borehole or to the BHA or bit, for example to apply WOB) to optimize the drilling process and reduce drilling dysfunction by reducing stick slip by reacting torsional loads to the borehole. The controller may vary the force based on axial or torsional loads measured at the anchor. The controller may control the anchor and / or other components in the BHA based on closed loop feedback from downhole sensors to optimize the drilling process.

[0156] The incorporation of the downhole control unit 400 comprising a processor 401 and memory 402 into the apparatus may also enable event and diagnostic analysis, as well as closed- loop control of the anchor downhole.

[0157] It may be desirable to drill a directional or deviated well; that is, a borehole that deviates from a vertically straight line. This may be done, for example, in order to access several target areas of the formation using the same well. In such cases, the anchor may be utilised to apply axial thrust to the drillstring to enhance directional steering of the drill bit.

[0158] FIG. 5 shows an example of a system 500 for drilling a directional well. Reference numbers common with FIG. 1 illustrate the same components. Components at the surface have been omitted for simplicity, but the arrangement may comprise any of the components described with reference to FIG. 1. The drillstring may comprise, for example, coiled tubing or drill pipe.

[0159] The system comprises an anchor tool 113. The anchor tool comprises one or more axial thrusting mechanisms operable to apply axial thrust to one or more component distal of the anchor in the drillstring. The axial thrust may be applied via the drillstring. For example, the anchor tool may comprise a central shaft that is axially coupled with the drillstring distal of the anchor. The axial thrust may be applied to the central shaft. The axial thrust may be transferred from the central shaft to the one or more components distal of the anchor in the drillstring.

[0160] In some implementations, the flow of drilling fluid through the anchor may be used to provide the axial thrust. This may also be used to apply a longitudinal force in the uphole direction. The pressure difference between the drilling fluid being pumped down the inside the anchor (for example, through a central channel in the anchor) and the drilling fluid returning to surface in the annular space around the outside of the anchor can be used to perform work. This pressure difference can typically be many 100s of psi. In a simple implementation, the higher-pressure drilling fluid from the inside of the tool can be directed (via valves or other means) to one side of an axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the other side of an axial piston. The resulting imbalance in fluid force either side of the piston will result in movement of the piston. This axial piston, if acting between the gripping segment and the central shaft running through the anchor, will result in movement of the gripping segment relative to the shaft running through the anchor. If the gripping segment is engaged with the borehole then this process can also result in longitudinal force being applied to the distal tool.

[0161] The anchor may comprise an axial piston, or multiple axial pistons. The or each axial piston may be connected to the gripping segment(s) and / or the drillstring via the shaft of the anchor.

[0162] This is schematically illustrated in FIG.s 5b and 5c for an anchor 250. Anchor 250 is an anchoring unit. The anchoring unit can transfer rotational and axial forces to the borehole. FIG. 5b shows the configuration of the anchor when a longitudinal force is not applied to urge the drill bit 108 against the bottom (i.e. the distal end) of the borehole and FIG. 5c shows the configuration of the anchor when a longitudinal force is applied to urge the drill bit 108 against the bottom of the borehole.

[0163] As described above, the anchor comprises one or more gripping segments, each comprising one or more grippers. One gripper is indicated at 251 . An axial piston is shown at 252. There is a chamber 253, 254 on either side of the axial piston 252. The chambers 253, 254 can be in fluid communication with the fluid passing through the anchor (for example, through the shaft 255, which can move with the drillstring) or the fluid in the annulus of the borehole. The supply of fluid to the chambers 253, 254 can be controlled by valves or some other means. In FIG.s 5b and 5c, the gripper 251 is engaged with the borehole wall.

[0164] In FIG. 5b, the higher-pressure drilling fluid from the channel inside of the anchor is directed (via valves or other means) to the chamber 254 on the lower side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber 253 on the upper side (with respect to the bottom of the borehole) of the axial piston. In FIG. 5c, the higher-pressure drilling fluid from the inside of the anchor is directed (via valves or other means) to the chamber 253 on the upper side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber 254 on the lower side (with respect to the bottom of the borehole) of the axial piston. The resulting imbalance in fluid force either side of the piston will result in movement of the piston in the downhole direction. This can be used to apply a longitudinal force to the downhole tool via the drillstring, for example through the shaft 255 passing through the anchor.

[0165] This approach may be used for any of the downhole tools described herein.

[0166] Shown at 130 is a bent sub. A bent sub is a section of tool or pipe that is formed at an angle to assist in drilling deviated wells. The bent sub is capable of adopting multiple angular orientations. The bent sub angle is illustrated at 131 . This is the angle of the angled part of the bent sub relative to the longitudinal axis of the drillstring. The bent sub may be rotationally fast with the drillstring. The drillstring may be rotated from the surface of the borehole. Therefore, the bent sub may rotate with the drillstring.

[0167] Alternatively, the bent sub may be coupled to and / or located distally of a tool configured to provide rotational drive that is regulated and / or controlled using differential pressure, which in this case is the pressure difference between the pressure of fluid in the drillstring and fluid in the anulus of the borehole. The tool may provide rotational drive that causes the bent sub to rotate about the longitudinal axis of the drillstring. The bent sub may be coupled to a drilling motor. The drilling motor may be configured to provide rotational drive to the bent sub and the drill bit. The bent sub may be a bent mud motor.

[0168] There may be a motor, or other tool configured to provide rotational drive that is regulated and / or controlled using differential pressure, proximal of the one or more anchoring units and the bent sub may be configured to be rotationally driven from the motor.

[0169] The bent sub has a proximal end and a distal end. The bent sub is coupled to a drill bit at its distal end. The bent sub may be directly coupled to the drill bit or there may be one or more components between the bent sub and the drill bit (i.e. the bent sub may be indirectly coupled to the drill bit). The bent sub is capable of adopting multiple angular orientations. The multiple angular orientations may be relative to the longitudinal axis of the drillstring proximal of the bent sub, shown at 132 in FIG. 5.

[0170] Where the anchor comprises a central shaft, the bent sub may be coupled to the central shaft at the proximal end of the bent sub. The bent sub may be capable of adopting multiple angular orientations relative to the longitudinal axis of the central shaft.

[0171] The bent sub may be directly or indirectly connected to the central shaft at the proximal end of the bent sub.

[0172] The central shaft may be configured to extend through the one or more anchoring units. Alternatively, the shaft may be rigidly connected to a part of the anchoring unit. The bent sub may be rotated from a motor below the anchoring unit. The gripper(s) of the anchoring mechanism(s) may be wheels or blades that move via a mechanism.

[0173] The central shaft may be rigidly connected to or integral with the one or more anchoring units. Alternatively, the central shaft may be configured to rotate relative to the one or more anchoring units.

[0174] The one or more axial thrusting mechanisms may be part of one or more of the anchoring unit(s).

[0175] The system comprises a controller, for example controller 400 shown in FIG. 4, configured to transmit one or more control signals to cause the axial thrusting mechanism(s) of the anchor tool 113 to apply axial thrust to the bent sub in dependence on the angular orientation of the bent sub relative to a target steering direction, shown at 133.

[0176] The target steering direction may be predetermined, or in some cases may be calculated using current measurements of the orientation of the drillstring or bottom hole assembly.

[0177] The target steering direction may be an angular direction relative to vertical (the vertical direction being relative to the horizontal surface of the Earth). Toolface measurements, for example using downhole sensors, may be used to determine which way the bend is pointing with respect to gravity (and therefore relative to the horizontal surface of the Earth).

[0178] The anchor tool may be allowed to rotate freely with the drillstring, controlled from the surface (without torsionally anchoring the anchor to the borehole), and the controller may transmit one or more control signals to cause the axial thrusting mechanism(s) to only apply axial thrust to the bent sub (or other directional drilling tool) when it is measured to be in the desired orientation. This can assist the tool in building a curve at the maximum rate supported by the bend angle and the formation.

[0179] In another, implementation the controller might not transmit control signals to cause the axial thrusting mechanism(s) every time that the bent sub is in the desired orientation, but may only transmit control signals for some percentage (less than 100%) of the time that the bent sub (or other directional drilling tool) is measured to be in the desired orientation. This may allow a curve to be built at less than the maximum rate supported by the bend angle and the formation. This may be advantageous when switching between rotating and sliding during drilling.

[0180] FIG. 6 illustrates a top-down view, looking down the drillstring 102. The orientation of the bent sub may be defined as the angle of the axis 601 of the bent part of the bent sub (i.e. the part of the bent sub that is at the bent sub angle) relative to a reference orientation 602.

[0181] The bent sub angle 131 of the bent sub may be known and the orientation of the bent sub relative to the target steering direction may also be determined in dependence on this angle.

[0182] The controller can transmit one or more control signals to cause the axial thrusting mechanism(s) of the anchor 113 to apply or increase the axial thrust applied to the bent sub 130 when the angular orientation of the bent sub matches or is within a predetermined angular range of the target steering direction 133.

[0183] For example, where the anchor 113 comprises a central shaft, the one or more control signals may cause the axial thrusting mechanism(s) to apply axial thrust to the central shaft in dependence on the angular orientation of the bent sub relative to the target steering direction (for example, to apply or increase the axial thrust supplied to the bent sub 130 when the angular orientation of the bent sub matches or is within a predetermined angular range of the target steering direction 133).

[0184] The controller may be configured to modulate the axial thrust applied by the one or more axial thrusting mechanisms in dependence on a measured instantaneous angular orientation of the bent sub relative to the target steering direction. If the instantaneous angular orientation of the bent sub indicates that the angled part of the bent sub is aligned with the target steering direction, increase axial thrust may be applied.

[0185] The controller may be configured to cause the axial thrusting mechanism(s) to reduce the axial thrust applied to the bent sub when the orientation of the bent sub is not within a predetermined range of the target steering direction. This may reduce the ROP when the bit is not oriented in the target steering direction.

[0186] The controller may be configured to transmit one or more further control signals to the drilling motor to vary the rotational speed of the drill bit in dependence on the orientation of the bent sub relative to the target steering direction. The controller may be configured to cause an increase in the rotational speed of the drill bit when the orientation of the bent sub is within a predetermined range of the target steering direction. This may further assist the drilling of directional wells by allowing a greater ROP when the drill bit is pointing in the desired direction.

[0187] The system may further comprise one or more sensors configured to measure the angular orientation of the bent sub and wherein the controller is configured to: receive data from the sensor(s); determine the angular orientation of the bent sub relative to the target steering direction in dependence on the data received from the sensor(s); and transmit the or more control signals to cause the axial thrusting mechanism to apply axial thrust to the bent sub in dependence on the determined angular orientation of the bent sub relative to a target steering direction.

[0188] The controller may be configured to implement closed loop feedback in dependence on a measured rate of penetration of the drill bit and / or modulate the rate of penetration in dependence on the angular orientation of the bent sub relative to the target steering direction while the drill bit and the bent sub rotate. Although the above-described implantations use a bent sub and control the axial thrust applied to the bent sub in dependence on the on the angular orientation of the bent sub relative to the target steering direction, other directional drilling tool may be used. The directional drilling tool can bias the drill bit in a particular direction or deviation from the axis of the existing wellbore. For example, a tool with a feature such as a kickpad may be used to orient the drill bit in the target steering direction. The controller may control the axial thrust applied to the directional drilling tool, which is coupled to the drill bit and can transfer the axial thrust to the drill bit, in dependence on the on the angular orientation of the directional drilling tool relative to the target steering direction.

[0189] Where the directional drilling tool is a downhole sub such as a kickpad, the controller may apply or increase the axial thrust applied to the kickpad when it detects that the kickpad is oriented 0 or 180 degrees from the target steering direction. This may be dependent on where the kickpad is located relative to the drill bit. For example, where the kickpad is close to the drill bit in the drillstring, the controller may apply or increase the axial thrust applied to the kickpad when it detects that the kickpad is oriented 180 degrees from the target steering direction.

[0190] Component 111 in FIG. 5 is an MWD tool. The controller may be configured to receive positional and / or steering data from the MWD tool. The controller may use this information to determine the angular orientation of the bent sub relative, or other directional drilling tool, to the target steering direction. The controller may transmit control signals to cause the axial thrusting mechanism to apply thrust to the drill bit (for example via a bent sub) and / or vary the rotational speed of the drill bit in dependence on the positional and steering data received from the MWD tool.

[0191] The system may optionally be used with a rotary steerable system to provide additional directional forces on the wellbore to steer the bit if desired.

[0192] The controller can track the orientation of the bend of the bent sub when the bit is rotating and when the bit is pointing in the target steering direction the system can apply or increase the amount of applied axial thrust and optionally also the rotational speed up the drill to preferentially drill in that direction. This may result in a higher ROP when the bend sub is pointing in the target steering direction. The controller modulates thrust and anchoring to allow the drill bit to drill ahead. This type of steering can generate 20-50% of the directional output of the motor when sliding.

[0193] The controller may implement sensor feedback to track the orientation of the bent sub while it rotates. The controller may implement closed loop feedback of ROP and modulate between high and low ROP depending on the alignment of drill bit with the target steering direction while the drill bit, bent sub and optionally the central shaft rotate through the anchoring unit(s).

[0194] In the above implementations, the axial thrust mechanism(s) of the anchor can selectively push the drill bit forward by applying axial thrust (or increasing the amount of axial thrust applied) when the bent sub or other directional drilling apparatus is orienting the drill bit in the desired direction of drilling. Likewise, the axial force applied can be reduced or ceased when the drill bit is pointing in the “wrong” direction, for example where the drill bit is at an orientation that is more than a predetermined orientation from the target steering direction. This can allow the toolface of the motor to be more easily kept in the desired direction (toolface), which may improve ROP when drilling directional wells.

[0195] FIG. 7 shows an example of a method 700 for drilling in a borehole using a system comprising one or more axial thrusting mechanisms operable to apply axial thrust and a directional drilling tool having a proximal end and a distal end. The directional drilling tool is coupled to a drill bit at its distal end and is capable of adopting multiple angular orientations. At step 701 , the method comprises determining an angular orientation of the directional drilling tool relative to a target steering direction. At 702, the method comprises sending one or more control signals to the one or more axial thrusting mechanisms to cause the one or more axial thrusting mechanisms to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to the target steering direction.

[0196] According to another aspect, the drillstring may comprise an orienter. The orienter is configured to angularly orient a downhole tool at the distal end of the orienter relative to a longitudinal axis of the orienter. The orienter may particularly be used for applications where the drillstring comprises coiled tubing or reeled pipe. It may be used without or with the anchor tool described above. FIG. 8 shows an exemplary orienter tool 800. FIG. 8 is a cross-section through the tool taken along its longitudinal axis. The orienter 800 has a channel 801 running along its longitudinal axis 809 through which drilling fluid can flow from the surface to a distal tool, such as a drill bit, at the distal end of the drillstring. The drillstring may comprise coiled tubing.

[0197] The orienter 800 comprises a housing 802. A mandrel 803 is located within the housing. The mandrel 803 is axially and rotationally moveable within the housing.

[0198] The tool 800 comprises one or more axial thrust chambers. In the example shown in FIG. 8, the orienter tool 800 comprises an axial thrust chamber 804 for applying forward axial thrust to the mandrel to allow it to move axially within the housing in a downhole direction and an axial thrust chamber 805 for applying backwards axial thrust to the mandrel to allow it to move axially within the housing in an uphole direction. The mandrel is configured to move axially within the housing in dependence on the pressure in the axial thrust chambers 804, 805. If the pressure in chamber 804 is greater than the pressure in chamber 805, the mandrel is forced to move in a downhole direction within the housing.

[0199] The axial thrust chambers may be configured to receive pressurised fluid from one or more of the uphole components in the drillstring, such as the anchor tool 113 described herein. The pressurised fluid may be drilling fluid or ‘clean’ hydraulic fluid (not used for other purposes). The flow of pressurised fluid into the chambers may be controlled, for example using a valving system. The position of the valves may be adjusted to control the flow of pressurized drilling fluid into the chamber(s). This can be used to orient the tool.

[0200] The region shown at 806 illustrates a region where the mandrel is splined to the housing. In this example, the mandrel is splined to the housing is so as to allow the mandrel to move axially within the housing and rotate relative to the housing. For example, the mandrel may comprise one or more features such as protrusions configured to move in a helical groove of the housing. When the mandrel is driven to move axially within the housing, the mandrel will also rotate due to the protrusion(s) of the mandrel being constrained to follow the helical groove in the housing. The mandrel is preferably a helically splined mandrel.

[0201] The orienter may comprise a valving system configured to receive drilling fluid via the drillstring. The valving system may control the flow of drilling fluid, or other hydraulic fluid, into the one or more axial thrust chambers. The one or more axial thrust chambers may receive drilling fluid from the channel 801 in the tool or from the annulus of the wellbore. The axial movement of the mandrel within the housing may be hydraulically driven using the valving system.

[0202] The valving system may comprise one or more inlet and outlet valves. In one example, for each axial thrust chamber, a respective inlet valve may control the flow of fluid into the chamber and a respective outlet valve may control the flow of fluid out of the chamber. Opening the inlet valve causes fluid to flow into the chamber from the channel 801 of the tool or from the annulus of the borehole, between the orienter tool and the borehole wall, as will be described in more detail below. The valving system may be responsive to one or more control signals from the controller to actuate the valves of the valving system to achieve a predetermined pressure in the axial thrust chamber(s). This can cause the mandrel to move axially within the housing and rotate to achieve a desired angular orientation of the downhole tool.

[0203] Alternatively, instead of using drilling fluid in the axial thrust chambers, a different hydraulic fluid may be used, such as hydraulic oil.

[0204] In the example shown in FIG. 8, the orienter comprises two chambers 804, 805 for controlling the amount of axial thrust applied to the mandrel. The pressure difference between these two chambers may create the axial thrust. As described above, there may be a pressure difference between drilling fluid being pumped through the inside the bore of the tools in the drillstring and the drilling fluid returning to the surface in the annular space around the outside of the drillstring. This pressure difference can typically be many 100s of psi.

[0205] The chambers 804 and 805 may be in fluid communication with the channel 801 of the orienter tool and the annulus of the wellbore, outside of the orienter tool.

[0206] In a simple implementation, the higher-pressure drilling fluid from the inside bore of the tool (in chamber 801 ) can be directed (via valves or other means) to a first chamber 804 on one side of the mandrel 803 and the lower-pressure annular drilling fluid can be directed (via valves or other means) to a second chamber 805 on the other side of the mandrel 803. The resulting imbalance in fluid force in the chambers on either side of the mandrel will result in axial movement of the mandrel within the housing in the downhole direction and rotational movement of the mandrel within the housing in a first rotational direction. To allow the mandrel to move axially in the opposite direction (i.e. uphole), the lower-pressure drilling fluid from the annulus of the borehole can be directed (via valves or other means) to the first chamber 804 and the higher-pressure annular drilling fluid can be directed (via valves or other means) to the second chamber 805. The resulting imbalance in fluid force in the chambers on either side of the mandrel will result in axial movement of the mandrel within the housing in the uphole direction and rotational movement of the mandrel within the housing in a second rotational direction.

[0207] FIG. 9 shows an axial cross-section of the orienter tool 800 showing the region 806 in more detail. Some other components have been omitted for simplicity. In this example, the mandrel comprises a protrusion 810 configured to move in a helical track 811 of the housing. When the mandrel 803 is driven to move axially within the housing 803, the mandrel will also rotate due to the protrusion 810 of the mandrel being constrained to follow the helical track 811 in the housing.

[0208] The pitch of the helix of the helical track can be chosen to give a desired number of complete rotations of the mandrel within the housing as the mandrel moves along its axial range of travel within the housing in response to an increase in pressure in chamber 804. The mandrel may be configured to complete one or multiple complete rotations (i.e. 360-degree rotations), or a fraction thereof, about its longitudinal axis as it moves along its axial range of travel within the housing.

[0209] The spline angle (the angle of the helical track relative to the longitudinal axis of the orienter) in the region 806 and / or the length of the mandrel may allow more than one complete rotation of the downhole tool relative to the orienter when the mandrel moves axially within the housing along its range of travel.

[0210] At least one of the axial thrust chambers 804, 805 may house one or more members configured to bias the axial movement of the mandrel within the housing in the downhole direction. For example, the mandrel may be biased using compliant members such as springs within the chamber 804. This may help to balance some of the drilling reaction torque and maximize the available orienting torque. As an alternative to being driven in response to the pressure in chambers 804 and 805, the axial movement of the mandrel within the housing may be driven by an electrical power source, such as a battery.

[0211] Due to the helical splining of the mandrel to the housing, axial movement of the mandrel within the housing can also cause it to rotate within the housing. The rotation may be about the longitudinal axis of the mandrel.

[0212] The mandrel 803 is configured for engagement with a downhole tool 850 such that axial movement of the mandrel within the housing causes angular rotation of the downhole tool about the longitudinal axis 809 of the orienter.

[0213] The region shown at 807 illustrates a region where the mandrel 803 is axially splined to a downhole tool 850. The mandrel is axially splined to the downhole tool so as to allow relative axial movement between the mandrel and the downhole tool. The axial splines can prevent any change in overall length of the orienter. The mandrel is rotationally fast with the downhole tool, so that rotation of the mandrel results in rotation of the downhole tool.

[0214] A seal 808 between the downhole tool 850 and the housing 802 may prevent the exfiltration of drilling fluid from the tool where the downhole tool 850 is coupled to the orienter. The rotation of the downhole tool 850 may be supported by bearings. There may also be bearings to support the rotation of the mandrel within the housing of the orienter.

[0215] In one example, the downhole tool 850 may be a bent sub, which may be part of a bent motor. The orienter may rotate the bent sub to orient the bend in the desired direction of drilling, such as a target steering direction. This may be advantageous in the drilling of directional wells.

[0216] The orienter may be configured to hold an incremental angular position when the flow of drilling fluid to the valving system is halted. This may be achieved by closing the inlet and outlet valves of the axial thrust chamber(s) to retain the fluid in the chambers to hold the position. In the event of fluid leakage from the chamber(s) and / or varying drilling torque, the controller may adjust the pressure in the chamber(s), for example by actuating the valves, in order to hold the axial position of the mandrel constant with respect to the surface of the Earth. The orienter may be configured to continuously adjust the angular orientation of the downhole tool based on the real-time orientation of the downhole tool and / or wellplan information. For example, if the downhole tool, such as a bent sub, is detected in real-time to be oriented at a particular angle, the valves of the orienter may be controlled to achieve a target orientation of the bent sub, which may correspond to a target steering direction.

[0217] The orienter 800 is coupled to one or more components of the drillstring at its proximal end. In some implementations, the drillstring proximal of the anchor may comprise coiled tubing. The orienter may conveniently be used with the anchor in a drillstring comprising coiled tubing to allow continuous drilling without needing to stop to make connections in drill pipe.

[0218] The orienter may optionally work in coordination with the anchor described herein such that the anchor slips to allow the orienter to reset without needing to remove the drill bit from the bottom of the borehole and stop drilling.

[0219] The orienter tool may also be used hold the toolface for the drill bit to be constant, for example by orienting a bent sub coupled above the drill bit to have a desired orientation. The anchor may be controlled to apply axial thrust to the bent sub when it is held at an orientation corresponding to the target steering direction.

[0220] The orienter may be controllable by a downhole control unit (for example, where the control unit is of the type shown in Figure 4). The orienter may be controlled without requiring a connection to the surface of the borehole. The control unit may implement a closed-loop control strategy. The closed-loop control strategy may be such as to generate control signals for controlling the tool in dependence on a comparison between a desired state of the tool and a sensed state of the tool. This may enable closed-loop steering using the orienter tool. The control signals may control the position(s) of the valve(s) of the valving system for controlling the flow of pressurized drilling fluid into the chamber(s) to control the pressure in the chamber(s). The control of the orienter may be initiated or programmed via a downlink command (for example via a hydraulic downlink from the surface). Continuous communication with the surface may not be required.

[0221] FIG. 9 shows an example of a method 900 for performing a downhole operation in a borehole. At step 901 , the method comprises providing a drillstring comprising coiled tubing proximally coupled to a downhole anchor tool. At step 902, the method comprises providing an orienter coupled to a downhole tool and configured to angularly orient the downhole tool, the orienter being distal of the downhole anchor tool. At step 903, the method comprises applying axial thrust to the orienter using the downhole anchor tool.

[0222] The orienter used in the method may be the orienter having any of the features described above.

[0223] The approaches described herein can allow to implement steering functionality complimentary to operations with downhole anchoring technology and facilitate the addition of disruptive drilling technologies such as plasma-assisted drilling in the bottom hole assembly.

[0224] A typical rotary steerable system is positioned directly above the drill bit. Particular benefits of the orienter and / or modulated axial thrust concepts described herein are that the orienter and / or system for applying axial thrust to the directional drilling tool can be placed further uphole in the drilling than a rotary steerable system and free up the valuable space adjacent to the drill bit for elements needed to power disruptive drilling technologies (such as a spark generator and controller).

[0225] One further benefit of the orienter tool described here is that it does not require clean hydraulic piping or electrical cables to be run from surface and it may output significantly more holding torque as compared to conventional coiled tubing orienters.

[0226] In another implementation, a downhole tool may be used to apply axial vibration (i.e. vibration parallel to the longitudinal axis) to one or more components in the drillstring, for example to one or more components above and / or below the downhole tool in the BHA. In this way, the downhole tool may be configured to act as an agitator tool or a hammer tool. In some implementations, the downhole tool may be positioned above the BHA in the drillstring, for example a few thousand feet above the BHA. This may be done where it is desirable to use the downhole tool to agitate the drillstring. Where it is desirable to use the downhole tool to apply vibration as a hammer tool, the downhole tool may be positioned closer to the drill bit. This tool may be used independently of the anchor tool described above. The anchor tool may alternatively incorporate the features of the downhole tool for applying axial vibration described herein.

[0227] FIG. 11 shows an example of a system 1100 for drilling a borehole. Reference numbers common with FIG. 1 illustrate the same components. Components at the surface and some possible components in the BHA have been omitted for simplicity, but the arrangement may comprise any of the components described with reference to FIG. 1 . The drillstring 102 may comprise, for example, coiled tubing or drill pipe. The downhole tool is illustrated at 1101. Steering device 112 is optionally present. Motor 110 for providing rotational drive to the drill bit 108 is optionally present. When using a drilling motor, the lack of drillstring rotation while sliding can increase drag. Vibration of the drillstring can reduce drag by reducing the static friction factor and making it closer to the dynamic friction factor. Rotation of a drill bit may alternatively be applied from the surface.

[0228] The axial vibration may be applied, for example, using one or more axial thrusting mechanisms. This may be achieved similarly to as described above with reference to FIG.s 5b and 5c, with or without the grippers.

[0229] The flow of drilling fluid through the downhole tool may be used to generate the axial vibration. The downhole tool may be configured to generate axial vibration using an axial piston. For example, there may be a chamber on either side of the axial piston. The chambers can be in fluid communication with the fluid passing through the downhole tool or the fluid in the annulus of the borehole. The supply of fluid to the chambers can be controlled by valves or some other means. The valves may in some examples be electrically actuated rotary valves.

[0230] Higher-pressure drilling fluid from the channel inside of the downhole tool can be directed (via valves or other means) to the chamber on the lower side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber on the upper side (with respect to the bottom of the borehole) of the axial piston.

[0231] Higher-pressure drilling fluid from the inside of the anchor can be directed (via valves or other means) to the chamber on the upper side (with respect to the bottom of the borehole) of the axial piston and the lower pressure annular drilling fluid can be directed (via valves or other means) to the chamber on the lower side (with respect to the bottom of the borehole) of the axial piston. The resulting imbalance in fluid force either side of the piston will result in movement of the piston in the downhole direction. This can be used to create movement that can be applied to the one or more components. The piston may be repeatedly moved back and forth to provide the axial vibration at the desired frequency and / or amplitude.

[0232] In one implementation, the downhole tool 1101 may comprise telescoping splined elements and an axial piston (for example, a hydraulic piston). A change in length between the telescoping splined elements and / or a variation in thrust force applied by the piston can create the axial vibration. In another implementation, the chambers of the tool may be used to move a mass back and forth inside the tool to generate the axial vibration.

[0233] The downhole tool may be connected with or comprise a control unit of the type 400 shown in FIG. 4. The controller may alternatively comprise another form of electronic control, such as a programmable logic controller (PLC), or an analogue controller. The controller may use sensor feedback to dynamically adjust the frequency and / or amplitude of applied axial vibration. The controller may implement a control strategy. The control strategy implemented by the control unit may be a closed-loop control strategy. The closed-loop control strategy may be such as to generate control signals for the downhole tool in dependence on a comparison between a desired state of the equipment and a sensed state of the equipment. The sensed state may be determined from measurement(s) acquired by one or more sensors, for example one or more sensors on the drillstring from which the current resonant frequency of the drillstring may be determined. The control strategy may be an adaptive control strategy.

[0234] In one example, the controller may be configured to dynamically adjust the vibration frequency in dependence on the resonant frequency of the drillstring. For example, the controller may be configured to dynamically adjust (or tune) the vibration frequency to be within a predetermined range (for example, within 5, 10, 20 or 50%) of the resonant frequency of the drillstring. The controller may be configured to dynamically adjust the vibration frequency to match the resonant frequency of the drillstring.

[0235] The resonant frequency of the drillstring is the natural frequency at which the drillstring vibrates with maximum amplitude (i.e. achieves resonance) when subjected to an external force or vibration. Resonance occurs when the driving frequency of an external force matches the drillstring’s natural frequency. The resonant frequency of the drillstring may be dictated by the physical properties of the drillstring, such as length, mass and stiffness. The resonant frequency of the drillstring may be known and provided to the controller (for example, the controller may determine the resonant frequency from a received value or determine the resonant frequency by referring to a stored value), calculated or may be determined using one or more sensors on the drillstring.

[0236] There may be multiple resonant frequencies and mode shapes. If, for instance, there was an event which resulted in a situation where a component in the drillstring became stuck, the tool could excite the resonant frequency of the mode that resulted in maximum movement at the stuck component.

[0237] Exciting the drillstring to vibrate at or around its resonant frequency can maximize vibration and minimize drag between components of the drillstring and the wellbore. This may be desirable to assist rock removal.

[0238] The controller may be configured to determine the resonant frequency of the drillstring, for example using measurements from one or more sensors 1102, 1103. The sensors may be located on the drillstring 102 or on particular components of the drillstring. The controller may then be configured to control the downhole tool to apply axial vibration at or around the resonant frequency. For example, axial vibration may be applied within a predetermined range of the resonant frequency of the drillstring.

[0239] The downhole tool may be configured to apply axial vibration at frequencies of up to 10 Hz. A typical drillstring axial resonant frequency may be, for example, less than 3 Hz. The downhole tool may be configured to apply axial vibration at frequencies of up to 3 Hz to be within a predetermined range of the resonant frequency. The downhole tool may be capable of applying axial vibration at a higher frequency, for example to overcome an obstacle or blockage or where the drillstring has become stuck against the wellbore.

[0240] Where it is desired to use the downhole tool as a hammer tool, for example in the drilling of hard rock, the downhole tool may be configured to apply higher frequencies of axial vibration. For example, from 15-50 Hz, 15-60 Hz, or 15-100 Hz. The amplitude of vibration applied by the downhole tool may be maintained at or below a vibration amplitude threshold. The vibration amplitude threshold may be a known threshold which would damage elements of the drillstring or cause degraded performance. The vibration amplitude threshold may be, for example, 5g root mean square (RMS) or 50g Peak Shock. The amplitude of the vibration to be generated may optionally be determined in dependence on sensor data.

[0241] The controller may adjust the frequency of vibration and / or amplitude of vibration as the length of the drillstring changes (i.e. in dependence on the length of the drillstring). The control unit may continuously monitor the resonant frequency of the drillstring as the drillstring increases in length (for example, as more stands of drill pipe are added or a greater length of coiled tubing is deployed as the wellbore becomes deeper). The controller may be configured to determine the current resonant frequency of the drillstring. The controller may then be configured to control the downhole tool to apply axial vibration at the current resonant frequency. For example, within a predetermined range of the current resonant frequency of the drillstring.

[0242] The application of axial vibration as described above may be used to reduce wellbore torque and drag and enable the drilling of longer lateral wells and improved directional control.

[0243] FIG. 12 shows an example of a method of controlling a downhole tool. At step 1201 , the method comprises determining the resonant frequency of the drillstring. At step 1202, the method comprises controlling the downhole tool to apply axial vibration at a frequency within a predetermined range of the resonant frequency of the drillstring

[0244] In a further implementation, the drillstring may incorporate multiple downhole tools. For example, one or more downhole tools may be used to generate axial vibration within a predetermined range of the resonant frequency of the drillstring, as described above, and one or more downhole tools may be used to create axial thrust to damp oscillation and / or to control one or more of depth or cut and torque of a distal tool such as a drill bit. The use of such multiple tools in combination in a downhole subsystem may advantageously reduce wellbore torque and drag and enable the drilling of longer laterals and improved directional control and optimize the drilling process in terms of depth of cut and / or torque. Alternatively, the frequency of vibration of the downhole tool may be controlled based on other factors, such as a local vibration amplitude at the downhole tool or a local vibration amplitude at a remote sensing point, such as in an MWD or RSS tool. The controller may be configured to self-adjust the vibration frequency based on attaining a target local or remote vibration amplitude setpoint.

[0245] Generally, the downhole tool may be communicatively connected with a controller configured to control the downhole tool to apply axial vibration at a frequency in dependence on a local vibration amplitide at the downhole tool (which may be measured), a remote measured vibration amplitude (for example, at another downhole tool), or based on attaining a target vibration amplitude at the downhole tool or remote location in the bottom hole assembly or the drillstring. The downhole tool may comprise the controller.

[0246] Various targets could be set. For example, the controller may control the tool to adjust the vibration frequency and / or amplitude to minimize mechanical specific energy (MSE), to achieve a particular vibration level at the downhole tool or at another remote tool, such as a MWD or RSS tool, or various other parameters. For example, the controller may control the tool to adjust the applied vibration frequency and / or amplitude to maximize a downhole sensed weight on bit to surface-determined weight on bit ratio (which may optionally utilize a wireline connection to the surface and a downhole weight and / or torque on bit sensor).

[0247] The downhole tool may be programmable via hydraulic downlinks from surface, via wireline or without intervention from the surface.

[0248] The downhole system and tools (e.g. downhole tool or orienter) described herein may be or may be part of a downhole subsystem of a complete system for performing the downhole operation. The downhole operations described herein may be performed by the downhole subsystem. The controller according to any of the aspects described herein may be for controlling a downhole tool that is or is part of a downhole subsystem. The methods described herein may be performed by the downhole subsystem. The controller may be a subsystem different from a downhole subsystem, or the two may constitute a common subsystem.

[0249] The applicant hereby discloses in isolation each individual feature described herein and any combination of two or more such features, to the extent that such features or combinations are capable of being carried out based on the present specification as a whole in the light of the common general knowledge of a person skilled in the art, irrespective of whether such features or combinations of features solve any problems disclosed herein, and without limitation to the scope of the claims. The applicant indicates that aspects of the present invention may consist of any such individual feature or combination of features. In view of the foregoing description it will be evident to a person skilled in the art that various modifications may be made within the scope of the invention.

Claims

CLAIMS1 . A downhole system for use in a borehole comprising: one or more anchoring units operable to grip the borehole; one or more axial thrusting mechanisms operable to apply axial thrust; a directional drilling tool having a proximal end and a distal end, the directional drilling tool being coupled to a drill bit at its distal end, the directional drilling tool being capable of adopting multiple angular orientations; and a controller configured to transmit one or more control signals to cause the axial thrusting mechanism(s) to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to a target steering direction.

2. The system as claimed in claim 1 , wherein the system further comprises a central shaft, the directional drilling tool being coupled to the central shaft at its proximal end, the directional drilling tool being capable of adopting multiple angular orientations relative to the longitudinal axis of the central shaft, wherein the one or more control signals cause the axial thrusting mechanism(s) to apply axial thrust to the central shaft in dependence on the angular orientation of the directional drilling tool relative to the target steering direction.

3. The system as claimed in claim 2, wherein the directional drilling tool is directly or indirectly connected to the central shaft.

4. The system as claimed in claim 2 or claim 3, wherein the central shaft is configured to extend through the one or more anchoring units.

5. The system as claimed in any preceding claim, wherein the one or more axial thrust mechanisms comprise one or more axial thrust chambers, wherein the one or more axial thrust chambers are configured to receive pressurised drilling fluid.

6. The system as claimed in claim 5, wherein the axial thrust applied by the one or more axial thrust mechanisms is dependent on the pressure in the one or more axial thrust chambers.

7. The system as claimed in any preceding claim, wherein the one or more axial thrust mechanisms are configured to apply axial thrust when the one or more anchoring units are gripping the borehole.

8. The system as claimed in any preceding claim, wherein the one or more axial thrusting mechanisms are part of one or more of the anchoring unit(s).

9. The system as claimed in any preceding claim, wherein the system further comprises a motor or a turbine proximal of the one or more anchoring units and wherein the directional drilling tool is configured to be rotationally driven from the motor or the turbine.

10. The system as claimed in any preceding claim, wherein the directional drilling tool is configurated to be rotationally driven from a drilling rig at the surface of the borehole and / or a downhole drilling motor or turbine.11 . The system as claimed in any preceding claim, wherein: the directional drilling tool is coupled to a drilling motor or a turbine, the drilling motor or turbine being configured to provide rotational drive to the drill bit; or the directional drilling tool comprises a drilling motor or turbine.

12. The system as claimed in claim 11 , wherein the controller is configured to transmit one or more further control signals to the drilling motor to vary the rotational speed of the drill bit in dependence on the orientation of the directional drilling tool relative to the target steering direction.

13. The system as claimed in any preceding claim, wherein the controller is configured to modulate the axial thrust applied by the one or more axial thrusting mechanisms in dependence on a measured instantaneous angular orientation of the directional drilling tool relative to the target steering direction.

14. The system as claimed in any preceding claim, wherein the controller is configured to cause the axial thrusting mechanism(s) to increase the axial thrust applied to thedirectional drilling tool when the orientation of the directional drilling tool is within a predetermined range of the target steering direction.

15. The system as claimed in any preceding claim, wherein the controller is configured to cause the axial thrusting mechanism(s) to reduce the axial thrust applied to the directional drilling tool when the orientation of the directional drilling tool is not within a predetermined range of the target steering direction.

16. The system as claimed in any preceding claim, wherein the controller is configured to cause an increase or decrease in the rotational speed of the drill bit when the orientation of the directional drilling tool is within or outside a predetermined range of the target steering direction respectively.

17. The system as claimed in any preceding claim, wherein the system further comprises one or more sensors configured to measure the angular orientation of the directional drilling tool and wherein the controller is configured to: receive data from the sensor(s); determine the angular orientation of the directional drilling tool relative to the target steering direction in dependence on the data received from the sensor(s); and transmit the or more control signals to cause the axial thrusting mechanism to apply axial thrust to the directional drilling tool in dependence on the determined angular orientation of the directional drilling tool relative to a target steering direction.

18. The system as claimed in any preceding claim, wherein the controller is configured to implement closed loop feedback in dependence on a measured rate of penetration of the drill bit and / or modulate the rate of penetration in dependence on the angular orientation of the directional drilling tool relative to the target steering direction while the drill bit and the directional drilling tool rotate.

19. The system as claimed in any preceding claim, wherein the system further comprises a measurement while drilling tool and wherein the controller is configured to receive positional and steering data from the measurement while drilling tool andtransmit control signals to cause the axial thrusting mechanism to apply thrust to the directional drilling tool and / or vary the rotational speed of the drill bit in dependence on the positional and steering data received from the measurement while drilling tool.

20. The system as claimed in any preceding claim, wherein the one or more axial thrust mechanisms are configured to generate axial thrust by reacting axial force to the borehole via the one or more anchoring units.

21. A method for drilling in a borehole using a system comprising one or more anchoring units operable to grip the borehole, one or more axial thrusting mechanisms operable to apply axial thrust and a directional drilling tool having a proximal end and a distal end, the directional drilling tool being coupled to a drill bit at its distal end, the directional drilling tool being capable of adopting multiple angular orientations, the method comprising: determining an angular orientation of the directional drilling tool relative to a target steering direction; and sending one or more control signals to the one or more axial thrusting mechanisms to cause the one or more axial thrusting mechanisms to apply axial thrust to the directional drilling tool in dependence on the angular orientation of the directional drilling tool relative to the target steering direction.

22. An orienter for use with a downhole tool in a drillstring, the orienter being configured to angularly orient the downhole tool relative to a longitudinal axis of the orienter, the orienter comprising: a housing; one or more axial thrust chambers within the housing, wherein the one or more axial thrust chambers are configured to receive pressurised drilling fluid; and a helically splined mandrel axially and rotationally moveable within the housing, the mandrel configured to move axially within the housing in dependence on the pressure in the axial thrust chamber(s) and the mandrel comprising one or more features configured to move in a corresponding helical groove of the housing; wherein the mandrel is configured for engagement with the downhole tool such that axial movement of the mandrel within the housing causes angular rotation of the downhole tool about the longitudinal axis of the orienter.

23. The orienter as claimed in claim 22, wherein the orienter comprises a valving system configured to receive drilling fluid via the drillstring, wherein the axial movement of the mandrel within the housing is hydraulically driven using the valving system.

24. The orienter as claimed in claim 23, wherein the orienter is configured to hold an incremental angular position when the flow of drilling fluid to the valving system is halted.

25. The orienter as claimed in claim 22, wherein the axial movement of the mandrel within the housing is driven by an electrical power source.

26. The orienter as claimed in any of claims 22 to 25, wherein the orienter is configured to cause angular rotation of the downhole tool relative to the longitudinal axis of one or more uphole components in the drillstring.

27. The orienter as claimed in claim 26, wherein the one or more axial thrust chambers are configured to receive pressurised drilling fluid from one or more of the uphole components in the drillstring.

28. The orienter as claimed in claim 27, wherein the one or more uphole components comprise an anchor tool.

29. The orienter as claimed in any of claims 22 to 28, wherein the mandrel is axially splined to the downhole tool so as to allow relative axial movement between the mandrel and the downhole tool.

30. The orienter as claimed in claim 29, wherein the spline angle and / or the length of the mandrel allows more than one complete rotation of the bent sub.31 . The orienter as claimed in any of claims 22 to 30, wherein at least one axial thrust chamber houses one or more members configured to bias the axial movement of the mandrel within the housing in the downhole direction.

32. The orienter as claimed in any of claims 22 to 31 , wherein the orienter is configured to continuously adjust the angular orientation of the downhole tool based on the realtime orientation of the downhole tool and / or wellplan information.

33. The orienter as claimed in any of claims 22 to 32, wherein: the orienter is proximally coupled to a downhole anchor tool; and / or wherein the drillstring proximal of the anchor comprises coiled tubing or reeled drill pipe.

34. A method for performing a downhole operation in a borehole, the method comprising: providing a drillstring comprising coiled tubing proximally coupled to a downhole anchor tool; providing an orienter coupled to a downhole tool and configured to angularly orient the downhole tool, the orienter being distal of the downhole anchor tool; and applying axial thrust to the orienter using the downhole anchor tool.

35. A method as claimed in claim 35, wherein the orienter is the orienter as claimed in any of claims 22 to 33.

36. A downhole tool for applying axial vibration to a drillstring, the downhole tool being communicatively connected with a controller configured to: determine the resonant frequency of the drillstring; and control the downhole tool to apply axial vibration at a frequency within a predetermined range of the resonant frequency of the drillstring.

37. The downhole tool as claimed in claim 36, wherein the controller is configured to dynamically determine the resonant frequency of the drillstring from data received from one or more sensors located on the drillstring.

38. The downhole tool as claimed in claim 36, wherein the resonant frequency of the drillstring is provided as an input to the controller.

39. The downhole tool as claimed in any of claims 36 to 38, wherein the downhole tool comprises the controller.

40. The downhole tool as claimed in any of claims 36 to 39, wherein the controller is configured to control the downhole tool to apply axial vibration at the resonant frequency of the drillstring.41 . The downhole tool as claimed in any of claims 36 to 40, wherein the controller is configured to control the downhole tool to apply axial vibration at an amplitude at or below a vibration amplitude threshold.

42. The downhole tool as claimed in claim 41 , wherein the vibration amplitude threshold is a known threshold at which damage or degraded performance would be caused to one or more elements of the drillstring.

43. A downhole subsystem comprising: the downhole tool as claimed in any of claims 36 to 42; and a further downhole tool comprising one or more axial thrusting mechanisms, the further downhole tool being configured to create axial thrust to damp oscillation in the drillstring and / or control one or more of depth or cut and torque of a distal tool.

44. A method of controlling a downhole tool for applying axial vibration to a drillstring, the method comprising: determining the resonant frequency of the drillstring; and controlling the downhole tool to apply axial vibration at a frequency within a predetermined range of the resonant frequency of the drillstring.

45. A downhole tool for applying axial vibration, the downhole tool being communicatively connected with a controller configured to control the downhole tool to apply axial vibration at a frequency in dependence on one or more of: a local vibration amplitide at the downhole tool, a remote measured vibration amplitude, and based on attaining a target vibration amplitude at the downhole tool or a remote location in a bottom hole assembly or drillstring.

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