GB2638791A

GB2638791A - Downhole apparatus for use in a borehole

Info

Publication number: GB2638791A
Application number: GB2405172.4A
Authority: GB
Inventors: Anthony Lines Liam; David Murray William; Richard Glover Anthony
Original assignee: GA Drilling AS
Current assignee: GA Drilling AS
Priority date: 2024-03-01
Filing date: 2024-04-11
Publication date: 2025-09-03
Also published as: GB202405172D0

Abstract

A first aspect relates to a downhole apparatus comprising an anchor 113 having a gripping element for engaging a borehole 104 to restrict relative axial and/or rotational movement between the anchor and borehole. The anchor is communicatively connectable with a processor programmed to execute a control strategy. The control strategy is dependent on inputs received from downhole sensors sensing the state of the apparatus and/or a distal tool 108. The control strategy controls the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and borehole. A second aspect is the downhole apparatus wherein upon detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to a drill string, the control strategy adjusts the longitudinal force applied by means of the anchor to the distal tool. A third aspect is the downhole apparatus wherein the control strategy controls the apparatus to apply longitudinal force to the distal tool to achieve a predetermined rate of penetration of the distal tool. A fourth aspect is a method, comprising operating the anchor to move through the wellbore in a surface-bound direction so as to retract the downhole tool from the wellbore.

Description

DOWNHOLE APPARATUS FOR USE IN A BOREHOLE

FIELD OF THE INVENTION

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

BACKGROUND

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

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

The drilling of deep geothermal wells can in some cases be seen as prohibitively expensive and technically challenging due to the high temperatures, hard rock and extreme depths. Deep geothermal wells are also likely to be some of the most complex wells drilled due to geologic complexity (such as faults, fractures and high friction), directional complexity (for example, intersections, geosteering, long laterals and low well spacing) and well control (for example, losses and high pressure zones).

A drillstring anchor can be used to axially stabilize the drillstring and to reduce torsional vibrations, which can help to mitigate these issues and reduce the likelihood of significant and potentially damaging oscillations along the drillstring.

SUMMARY

According to one aspect, there is provided a downhole apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy, in dependence on inputs received from one or more downhole sensors for sensing the state of the downhole apparatus and/or the distal tool, for controlling the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole.

The processor may be configured to: determine one or more downhole parameter measurements from the inputs received from the one or more downhole sensors; and control the anchor to apply longitudinal force to the distal tool in dependence on the one or more downhole parameter measurements.

The one or more downhole parameter measurements may comprise one or more of pressure, displacement, downhole weight on the distal tool and downhole torque on the distal tool. For example, the processor may determine from a measurement of pressure at the distal tool whether the distal tool is engaged with the borehole (for example, the bottom of the borehole for a straight wellbore) and may adjust the longitudinal force applied to the distal tool to allow the distal tool to remain in constant engagement with the wellbore.

In some implementations, the drillstring may comprise a rotational drive proximal of the distal tool for driving the distal tool to rotate. The processor may be configured to execute the control strategy to control the longitudinal force applied to the distal tool to maintain the rotational drive within one or more predetermined operational ranges. The one or more predetermined operational ranges may be predetermined ranges of one or more of rotational speed, torque and power of the rotational drive.

The rotational drive may comprise a downhole motor. The rotational drive may comprise a mud motor. The one or more downhole parameter measurements may comprise a differential pressure between drilling fluid passing through the motor and drilling fluid in the annulus of the borehole.

The downhole apparatus may comprise the processor. The anchor may comprise the processor. The anchor and the processor may be integral. The processor may be local to the anchor. In other implementations, the processor may be remote from the downhole apparatus. For example, the processor may be located at the surface of the wellbore.

The processor may be programmed to execute the control strategy, in dependence on inputs received from the one or more downhole sensors, for controlling the apparatus to apply longitudinal force to the distal tool by means of the anchor.

The one or more downhole sensors may be local to the downhole apparatus. At least one of the one or more downhole sensors may be local to the anchor. The anchor may comprise one or more of the downhole sensors.

The control strategy may be a closed-loop control strategy. The control strategy may be an adaptive control strategy.

The anchor may comprise an internal channel for conveying the flow of drilling fluid to the distal tool. The processor may be configured to execute the control strategy to maintain a differential pressure between the channel and the annulus of the borehole within a predetermined range.

The longitudinal force may provide weight on the distal tool. For example, where the distal tool is a drill bit, the longitudinal force may provide weight on bit to the bit.

The processor may be configured to execute the control strategy to apply longitudinal force to the distal tool to control a depth-of-cut or a rate of penetration of the distal tool.

According to another aspect, there is provided a downhole apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy for controlling the apparatus to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, adjust longitudinal force applied by means of the anchor to the distal tool.

The processor may be programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring and/or the borehole, increase the longitudinal force applied by means of the anchor to the distal tool.

The drillstring may comprise a rotational drive proximal of the distal tool for applying rotational drive to the distal tool. The processor may be programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring and/or the wellbore, adjust the longitudinal force applied by means of the anchor to the distal tool to stabilize or optimize torque requirements of the rotational drive and/or stabilize rotational output from the rotational drive.

The processor may be programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring and/or the wellbore, increase the longitudinal force applied by means of the anchor to the distal tool to maintain engagement between the distal tool and the borehole.

The processor may be programmed to execute the control strategy to maintain the rotational drive within one or more predetermined operational ranges.

The one or more predetermined operational ranges may be predetermined ranges of one or more of rotational speed, torque and power of the rotational drive.

The downhole apparatus may comprise the processor. The anchor may comprise the processor. The processor may be local to the anchor. In other implementations, the processor may be remote from the downhole apparatus. For example, the processor may be located at the surface of the wellbore, The processor may be configured to detect a condition associated with a reduction in drilling efficiency in dependence on inputs from one or more downhole sensors local to the downhole apparatus.

The one or more downhole sensors may comprise one or more sensors configured to measure or infer pressure, downhole weight on the distal tool and downhole torque on the distal tool.

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

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

The gripping element may be for engaging the borehole to restrict relative axial and/or rotational movement between the gripping element and the borehole.

In some implementations, the flow of drilling fluid through the anchor may be used to provide the longitudinal force applied to the distal tool. In this implementation the pressure difference between the drilling fluid being pumped down the inside the anchor and the drilling fluid returning to surface in the annular space around the outside of 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 connected to the grippers of the anchor, will result in movement of the gripper relative to the anchor. If the grippers are engaged with the borehole then this process can also result in longitudinal force being applied to the distal tool.

According to a further aspect, there is provided a method of retracting a downhole tool from a wellbore, the method comprising: performing a downhole operation using a drillstring comprising a downhole tool and an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole; operating the anchor to move through the wellbore in a surface-bound direction so as to retract the downhole tool from the wellbore.

According to a further aspect, there is provided a downhole apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy, in dependence on inputs received from one or more downhole sensors for sensing the state of the downhole apparatus and/or the distal tool, for controlling the apparatus to apply longitudinal force to the distal tool to achieve a predetermined rate of penetration of the distal tool.

The distal tool may be, for example, a conventional drill bit, a plasma drilling head or other drilling mechanism.

In some implementations, a rotational drive may not be used. For example, where the distal tool is a plasma drilling head, rotation of the head may not be needed to progress the borehole.

In some implementations where the drillstring comprises a rotational drive, the processor may be configured to determine the rotational speed of the rotational drive. The processor may be configured to receive data from one or more downhole sensors. The one or more downhole sensors may comprise a vibration sensor configured to detect vibration transverse to the longitudinal axis of the drillstring. The processor may be configured to determine the rotational speed of the rotation drive in dependence on input received from the vibration sensor and a known configuration of the rotational drive. The known configuration of the rotational drive may be a number of rotor lobes of the rotational drive. The vibration sensor may comprise a lateral accelerometer. The downhole apparatus may comprise the processor. The anchor may comprise the processor.

The apparatus may be communicatively connectable with a downhole control unit. In other implementations, the control unit may be at the surface and may be connected to the downhole apparatus using a wired connection, such as electrified wireline. The control unit may comprise the processor. The control unit may be configured to adjust the configuration of the anchor and/or one or more other elements coupled to the anchor (for example, coupled directly or indirectly at the distal end of the anchor) in response to one or more signals. The one or more other elements may be communicatively connectable to the anchor. This may allow signals to be passed through the anchor and/or for signals to be transferred between the anchor and components of a bottom hole assembly than the anchor. The apparatus may comprise the control unit. The control may comprise 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 may comprise adjusting the configuration of the gripper and/or adjusting the configuration of one or more other parts of the anchor, such as one or more pistons for applying an axial force to the drillstring or one or more of the other elements coupled with the anchor, such as a drill bit.

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

The gripping element may be configured to grip the borehole to restrict relative axial movement between the anchor (for example, the gripping element of the anchor) and the borehole. The gripping element may be configured to grip the borehole to restrict relative rotation between the anchor (for example, the gripping element of the anchor) and the borehole.

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

The anchor may be configured to apply longitudinal force to one or more distal downhole components coupled to the anchor.

The anchor may be part of a bottom hole assembly, wherein the anchor is configured to urge the bottom hole assembly into the borehole.

The anchor may be coupled with a tool for performing a downhole operation at the distal end of the bottom hole assembly. The anchor may be configured to apply weight to the tool to urge the tool into the borehole or against the bottom of the borehole.

The anchor may comprise multiple gripping elements each configured to move axially relative to a body of the anchor. The multiple gripping elements may be disposed on the same body, or across multiple body parts that are axially separated along the longitudinal axis of the apparatus. The multiple body parts may each act as separate anchor tools that are independently controlled.

The anchor may comprise a drive mechanism for advancing one gripping element downhole and/or uphole relative to at least one other gripping element. Where the anchor comprises multiple body parts, each body part having multiple gripping elements each configured to move axially relatively to its respective body part, each body part may have a respective drive mechanism for advancing one gripping element downhole and/or uphole relative to at least one other gripping element.

The 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.

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

The apparatus may 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.

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

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.

BRIEF DESCRIPTION OF THE FIGURES

The present invention will now be described by way of example with reference to the accompanying drawings. In the drawings: FIG. 1 schematically illustrates an example of a drilling system, illustrated at a subterranean location in a borehole during a downhole operation; FIG. 2 schematically illustrates an example of an anchor comprising multiple gripping segments; FIG.s 3(a)-3(c) schematically illustrate an example of a gripper made from a hard material; FIG. 4 schematically illustrates an example of a control unit; FIG. 5 schematically illustrates coupling between the anchor and a portion of the drillstring above the anchor; FIG. 6 shows the steps of an exemplary method for retracting a downhole tool from a borehole.

DETAILED DESCRIPTION

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

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

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

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

The component 110 is a downhole motor, such as a mud motor, for providing rotational drive to the tool 108. The motor may be a positive-displacement mud (PDM) motor. Alternatively, an electric motor or other type of motor may be used. The motor may be a steerable motor.

The motor may be a bent motor, which may allow for improved directional control when performing directional drilling.

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

The MWD tool 111 may comprise a means of transmitting information to the surface. This may be performed by, for example, mud pulses, whereby the operation of a valve in the fluid 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.

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

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 may not be used in a BHA that comprises a rotary steerable system (RSS). In this case, the RSS may be used to steer the motor to direct the borehole.

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

The component shown at 113 is an anchor tool, which will be described in more detail below. 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.

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.

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.

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

In the system described above with reference to FIG. 1, the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit below the anchor. However, the anchor described herein may be utilized in non-rotary drilling situations such as jetting or plasma drilling (a contactless drilling technique that uses high-voltage pulses to fracture the rock) or any other compatible operation or situation in a borehole, such as a milling, completion or plug and abandonment operation. Other additional components of the BHA may be drill collars, stabilizers, reamers, hole-openers and bit subs.

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.

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.

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

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

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

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.

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 / conventional drilling applications and communication with other BHA tools.

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).

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.

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.

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 the housing of the anchor, or after a predetermined time since the segment currently gripping was actuated. Alternatively, the segment currently gripping the borehole may release automatically when the other segment is actuated to grip the borehole, or once the other segment is determined to be gripping the borehole, for example when a target gripping force of pressure of a hydraulic actuator is reached. For example, the gripper of a free (i.e. not currently gripping) segment may be triggered to grip the borehole when the currently gripping segment is 20mm from the end of its longitudinal range of travel relative to the housing of the anchor. The currently gripping segment could then be released after another 10mm of drilling (measured by the relative longitudinal movement of the shaft and the channel 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.

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

In some implementations, the 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.

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.

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.

The anchor advantageously allows the ability to rotate the drillstring during axial anchoring and for the drillsring to move axially relative to the anchor during torsional anchoring.

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.

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 may not be urged outwardly relative to the central axis. In the activated state the gripper may be in a location radially outwardly of its location in the deactivated state. The gripper may be biased to one of the states, e.g. by a spring.

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.

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.

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

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.

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

In one implementation, the anchor comprises pistons which are capable of being urged outwardly for gripping the borehole from a passive state to an activated state. The pistons 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.

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.

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.

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

In one example, shown in FIG.s 3(a)-3(c), 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 3(a)-3(c), the piston has an insert at the end of the piston for gripping the borehole. However, in other implementations, the tip of the piston may be compositionally undifferentiated from the body of the piston and may not have any particular surface formations or surface roughness.

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

In the example shown in FIG.s 3(a)-3(c), the gripper 203 is a cylindrical piston with a circular-cross 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. 3(c), 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. The piston and/or the insert of the gripper may optionally be coated. This may allow the gripper to achieve a greater gripping effect than an uncoated gripper. For example, the gripper may be coated with a layer of diamond or superhard grit to increase the effective friction further.

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

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

Generally, the following sequence of steps is performed: -a first gripping element (or set of elements) is activated to grip the borehole; -the drillstring and a second gripping element (or set of elements) are driven to progress them downhole. In the preferred embodiment, the second element (or set of elements) progress at a different (faster) speed than the drillstring, for example at twice the ROP of the drill bit; -a second element (or set of elements) is activated to grip the borehole; -the first element (or set of elements) is deactivated and driven to progress down the borehole with the drillstring.

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

There may be multiple 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.

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.

As mentioned above, the anchor 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.

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).

In some examples, the control unit 400 comprises one or more sensors 404. The sensor(s) 404 may comprise, or the control unit 400 may be communicatively connected with, a vibration sensor configured to detect vibration transverse to the longitudinal axis of the drillstring, as will be described in more detail below.

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.

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.

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.

In some implementations, the drillstring terminates in a distal tool, such as a drill bit. As mentioned above, the anchor is communicatively connectable with a processor that may be programmed to execute a predetermined control strategy. In dependence on inputs received from one or more downhole sensors for sensing the state of the downhole apparatus and/or the distal tool, execution of the control strategy by the processor can control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole.

Keeping a drill bit engaged with the borehole by controlling WOB may allow for faster and further drilling. Drilling dysfunction, such as stick slip, may be mitigated. Even with such dysfunction active, ROP may be significantly improved. Use of the anchor may thus reduce severity of stick slip and/or allow drill bits to drill further and faster through improved engagement of the bit with the rock.

In some implementations, the processor may receive one or more downhole parameter measurements, such as downhole pressure, WOB and/or torque, from the one or more downhole sensors and control the anchor to apply longitudinal force to the distal tool in dependence on the one or more downhole parameter measurements.

In some implementations, the processor is configured to determine one or more downhole parameter measurements from the inputs received from the one or more downhole sensors and control the anchor to apply longitudinal force to the distal tool in dependence on the one or more downhole parameter measurements.

Operation under this scheme may be described as WOB mode. WOB mode can utilize feedback from a WOB sensor (or from other sensors from which WOB can be determined or inferred) to control axial thrust to stabilize WOB, or longitudinal force on another downhole tool at the distal end of the drillstring for a more consistent downhole process. The ability to modulate WOB may address a major source of drilling dysfunction.

In some implementations, the drillstring comprises a rotational drive, such as a motor 110, proximal of the distal tool 108 for driving the distal tool to rotate. The processor may be configured to execute the control strategy to control the longitudinal force applied to the distal tool 108 to maintain the rotational drive within one or more predetermined operational ranges. The one or more predetermined operational ranges may be predetermined ranges of one or more of rotational speed, torque and power of the rotational drive.

In some implementations, the drillstring terminates in a distal tool, such as a drill bit. The downhole apparatus comprises an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the gripping element and the borehole. The anchor is communicatively connectable with a processor programmed to execute a control strategy for controlling the apparatus to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, adjust longitudinal force applied by means of the anchor to the distal tool.

Examples of conditions associated with a reduction in drilling efficiency and/or damage to the drillstring may include stick slip or the presence of other longitudinal or torsional vibrations, which may be detected using downhole sensors, such as vibration sensors or torque sensors on the drillstring or distal tool. For example, the processor may detect a condition associated with a reduction in drilling efficiency and/or damage to the drillstring when the vibration of the drillstring or distal tool exceeds a predetermined threshold.

Adjusting the longitudinal force applied by means of the anchor to the distal tool may comprise increasing the longitudinal force applied by means of the anchor to the distal tool. This may help to achieve consistent engagement between the distal tool and the borehole. Where the distal tool is a drill bit, this may result in faster drilling.

In some implementations, the drillstring comprises a rotational drive proximal of the distal tool for applying rotational drive to the distal tool. The processor can be programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency or a condition associated with damage to the drillstring, adjust the longitudinal force applied by means of the anchor to the distal tool to stabilize or optimize torque requirements of the rotational drive and/or stabilize rotational output from the rotational drive. For example, the anchor can adjust the longitudinal force applied to the drillbit to stabilize or modulate the depth of cut. The torque required to rotate the drill bit is proportional (although may not be linear) to the depth of cut of the drill bit and depth of cut is proportional to the WOB applied to the drill bit. Adjusting the longitudinal force applied to the drill bit can adjust the torque required or rotational speed of the rotational drive and this WOB, depth of cut, torque and/or speed relationship can also be used to damp / cancel out torsional oscillations of the drillstring.

In some implementations, the processor may control the downhole apparatus to increase the longitudinal force applied by means of the anchor to the distal tool to maintain engagement between the distal tool and the borehole. This may result in faster drilling speeds.

In another implementation where the drillstring comprises a rotational drive, the processor is programmed to execute a control strategy for controlling the apparatus. In response to the detection of an increased resistance being encountered by the distal tool, the processor can be configured to control the apparatus to (i) reduce the longitudinal force applied to the distal tool and/or (ii) increase the torque applied by the rotational drive so as to maintain rotation of the distal tool.

The processor may be configured to detect an increased resistance being encountered by the distal tool in dependence on inputs from one or more downhole sensors local to the downhole apparatus, as described above. The sensor(s) may be located at the control unit (i.e. sensors 404) or may be other downhole sensors local to the apparatus and/or communicatively connected to the control unit 400.

In some implementations, the processor is configured to execute control strategy to maintain the rotational drive within one or more predetermined operational ranges. The one or more predetermined operational ranges may be predetermined ranges of one or more of rotational speed, torque and power of the rotational drive. Operation within these ranges may prevent stalling of the rotational drive.

Motor stalls can occur when too much WOB is applied to the distal tool or drill bit. This can result in over engagement of the drill bit cutters and torque requirements that exceed the capacity of the rotational drive. In this situation the differential pressure across the rotational drive, in this example a positive displacement drilling motor, may significantly increase and in some cases result in a stall. A stall occurs because the differential pressure causes expansion of the elastomeric element within the drill motor and allows fluid to bypass the rotational drive element without translating into rotation of the drive. In this situation the available power to turn the distal tool / drill bit reduces and the bit can stall. This can also damage the elastomers and mechanical components within the mud motor and the drilling assembly. Additionally the circulation pressure in the run up to the stall event or during may be too high for the drilling fluid pumps at surface to continue to pump fluid at a sufficient rate to maintain the rotational speed of the mud motor. In this situation the application of stable longitudinal force can prevent the initial over engagement of the drill cutters and prevent the torque increase/spike that results in motor stalling. Additionally, the ability to control longitudinal force in response to differential pressure (differential pressure across a mud motor is proportional to drive torque) can keep the drilling motor in its optimum power band and in such situations where an event occurs to over-engage the cutters with the formation, can reduce the longitudinal force rapidly to prevent stall and/or differential pressures that might damage elements within the drilling motor or drilling assembly. Such operational ranges may be known by the processor.

As described above, the anchor comprises an internal channel for conveying the flow of drilling fluid to the distal tool. The processor may be configured to maintain a differential pressure between the channel and the annulus of the borehole within a predetermined range. Controlling delta pressure (the difference in the pressure of drilling fluid within the anchor tool and in the annulus of the borehole) at the anchor, for example using control flow valves to restrict the flow of drilling fluid through the anchor to reduce or increase the pressure differential, may be used to optimize motor operation. Pressure feedback can be used to stabilize motor differential pressure, torque and/or DOC of the drill bit, which may help to significantly improve motor and drill bit life, whilst also resulting in higher ROP by allowing motors to be run closer to their maximum power.

In some implementations, the processor is configured to determine the rotational speed of the rotational drive. One way in which this may be done will now be described.

The one or more downhole sensors may comprise a vibration sensor configured to detect vibration transverse to the longitudinal axis of the drillstring. The vibration sensor may be, for example, a lateral accelerometer. The processor may receive measurements of vibration transverse to the longitudinal axis of the drillstring (i.e. lateral vibration) from the sensor. The rotational speed of the rotation drive can be determined in dependence on input received from the vibration sensor and a known configuration of the rotational drive. The known configuration of the rotational drive may be a number of rotor lobes of the rotational drive. The detected lateral vibration is approximately equal to the rotational speed of the rotational drive multiplied by the number of rotor lobes of the rotational drive. Thus, the rotational speed of the rotational drive may be determined at the control unit by dividing the detected vibration by the number of rotor lobes of the rotational drive.

This may allow the rotational speed of the rotational drive to be determined downhole and used in control schemes to adjust the rotational speed or other downhole operational parameters. This also provides the ability to optimize the performance of the rotational drive. Motor stall can greatly impact drilling efficiency and drilling dysfunction. Where the rotational drive is a mud motor, by keeping differential pressure within a predetermined range, instances of motor stall may be minimized. The ability of the anchor to measure the rotational speed of a motor may also result in an improvement in motor performance by measuring motor RPM and controlling the motor downhole, which does not require MWD or other telemetry of RPM to the surface.

This approach is independent of MWD and motor provider (as an input is the motor configuration). Standard drilling practice typically operates the motor past its output power peak, resulting in less power to the bit than possible and more hydraulic power being used to destroy the rubber stator in the motor instead. By monitoring the rotational speed of the rotational drive and controlling it between a predetermined range, the performance and lifetime of the motor may be optimized.

This provides the ability to optimize bit performance by controlling longitudinal force applied to the distal tool (for example, WOB) and motor speed in real-time downhole. This can assist in avoiding a loss of control and delay resulting from the length/elasticity of the drillstring to the surface of the borehole.

The downhole apparatus may operate according to multiple control modes.

In one implementation, the processor may control the downhole apparatus in response to downhole sensor measurement of differential pressure and/or torque. In another implementation, the processor may control the downhole apparatus in response to downhole sensor measurement of WOB or pressure at the distal tool. In a further implementation, the processor may control the downhole apparatus in response to downhole sensor measurement of longitudinal displacement of one or more of the grippers relative to the body of the anchor. This may be used to estimate the ROP of the distal tool. In this mode, the processor may control the application of longitudinal force on the distal tool in response to data received from the displacement sensor(s) to achieve a predetermined ROP of the distal tool.

In some examples, the downhole apparatus may first operate according to a primary control mode (for example, ROP mode) but may implement a different control mode (for example, using motor differential pressure/torque control) if the detected differential pressure of drilling fluid flowing through the tool exceeds a threshold.

In some implementations, the drilling fluid may provide the longitudinal force applied to the drilling. In one implementation the pressure difference between the drilling fluid being pumped down the inside the anchor and the drilling fluid returning to surface in the annular space around the outside of 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 connected to the grippers of the anchor, will result in movement of the gripper relative to the anchor. If the grippers are engaged with the borehole then this process can also result in longitudinal force being applied to the distal tool.

The processor may also execute the predetermined control strategy to control the depth of cut (DOC) made by the distal tool. The control strategy may, knowing the relationship between WOB and DOC, control the WOB applied to the drill bit to achieve a desired DOC. The processor may also execute the predetermined control strategy to control the rate of penetration (ROP) of the distal tool. The control strategy may, knowing the relationship between WOB and ROP, control the WOB applied to the drill bit to achieve a desired ROP. This may allow multiple downhole control options to be implemented. The proximity of the processor to the drill bit or other distal tool may result in improved control performance.

The ROP mode may also utilize anchor traverse speed to control ROP, allowing for much more consistent drilling.

WOB and motor/bit interaction are likely a majority creator of slip stick and controlling that interaction with WOB may help to eliminate its creation, and not just insulate the drillstring exaggeration or compounding of stick slip. Controlling and/or providing prime drilling forces, such as WOB and/or torque on bit, downhole instead of from surface may help to control or eliminate axial slip stick deriving from drillstring. This may be improved further by the addition of a shock sub (which may be a common shock sub or custom shock sub) proximal of the anchor in the drillstring.

The apparatus can conveniently be used with coiled tubing (including with torsional and/or axial anchoring). The application of longitudinal force can replace the loads/forces typically coming from segment pipe in instances where drilling with coiled tubing is advantageous. The system can also make control/decisions downhole without involving surface people/systems if desired.

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

In this example, the coupling 114 is a swivel. The swivel may be a continuous swivel. Other suitable couplings may be used. The coupling is configured to at least partially isolate the connector from torsional forces generated distally of the anchor, for example from components to which the anchor is coupled in the BHA, such as the drill bit. The coupling may be configured to fully isolate the connector (and thus the continuous work string attached to the connector in use) from torsional forces generated distally of the anchor. The coupling is configured to allow relative rotation of the coiled tubing connector and the anchor about one or more axes. The coupling may be immediately proximal of the proximal end of the anchor (i.e. immediately above / upbore of the anchor in the drillstring).

In this example, the coupling 114 comprises upper 114a and lower 114b parts. The upper and lower parts of the coupling are configured to rotate relative to each other. Relative rotation may be allowed in both directions or in one direction only (for example, for a unidirectional swivel). The lower part 114b is rotationally fast with the body of the anchor and the upper part 114a is rotationally fast with the connector. The connector may be rotationally fast with the continuous work string when the work string is connected to the connector. The rotatable coupling may be selectively rotatable. For example, it may be lockable so that the parts cannot rotate relative to each other when desired. The direction of rotation may also be controlled.

Alternatively or additionally, the coupling may also be axially compliant. The axially compliant coupling may be configured to compress and/or extend in the axial direction, along the longitudinal axis of the borehole. This may allow the tool at the distal end of the drillstring to be able to progress in the wellbore in the event that the continuous work string becomes temporarily stuck or is not able to keep up with the rate of penetration of the drill bit.

In some examples, the anchor may comprise the rotatable and/or axially compliant coupling at its proximal end (with respect to the surface when in use). The coupling may be integrated with the anchor. That is, the body of the anchor and the coupling may be integrally formed. In other examples, the anchor and the coupling may be separate components with separate bodies. The coupling may be proximal of the proximal end of the anchor and in some cases may be immediately proximal.

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

The connector and the coupling may be configured to allow fluid to pass from the continuous work string to the anchor. For example, the upper 114a and lower 114b parts of the coupling may comprise respective flanges that are sealed together to prevent leakage of fluid whilst allowing relative rotation between the parts 114a, 114b.

The connector may be capable of applying or transferring axial force to the drillstring to pull the drill string down the borehole and/or push the drillstring up the borehole. The anchor may be capable of applying or transferring axial force to the drillstring to pull the drillstring down the borehole and/or push the drillstring up the borehole. The axial force may be generated by the anchor as described above. This can advantageously allow the anchor to act as a tractor for pulling the drillstring into and out of the borehole.

In some implementations, the connector may comprise one or more electrical connectors for connecting to one or more electrical cables within the drillstring for supplying electrical power to the apparatus from the surface of the borehole. The connector may also comprise one or more data connectors for connecting to one or more data cables within the drillstring for transmitting bi-directional communications between the surface of the borehole and the anchor.

In some implementations, the application of longitudinal force by the anchor to the borehole can be used to withdraw one or more downhole tools from the borehole.

FIG. 6 shows a flow chart illustrating the steps of an exemplary method of performing a downhole operation in a borehole. The downhole operation may be, for example, a drilling, milling or completions operation.

At step 601, the method comprises performing a downhole operation using a drillstring comprising a downhole tool and an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the gripping element and the borehole. At step 602, the method comprises operating the anchor to move through the wellbore in a surface-bound direction so as to retract the downhole tool from the borehole.

The apparatus may be connected to further components suitable for performing the operation in the borehole, such as the components of the BHA described above.

The system described herein can operate as an autonomous system for drilling, milling, completions or other operations.

In traditional implementations, torsional stick slip and general drilling dysfunction can result from erratic weight transfer and movement of the drillstring into the borehole. This erratic movement and transfer of force to the drill bit may result in irregular changes in depth of cut and therefore irregular drilling torque that can initiate and/or reinforce torsional dynamics including but not limited to stick slip. There may be multiple causes of this erratic drillstring movement, including contact and friction of the drillstring against the borehole wall, but could also include poor heave compensation from offshore drill rigs or poorly calibrated drill rig draw works control. Phenomena such as drillstring buckling, whereby the axial stiffness of the drillstring is insufficient to carry the axial loads, can force the drillstring to displace laterally and contact the wellbore. This may cause significant torque and drag and reduce the ability to drill extended depth boreholes. The movement of the drillstring may then become erratic as these contact points slip and change location in response to dynamic conditions. The ability of the downhole anchor described herein to apply consistent thrust and, in some cases, pull the drillstring along, can significantly reduce torsional oscillation resulting from erratic movement and drag of the drillstring with the borehole. In some implementations, the drillstring may comprise an axially compliant member above the anchor. The addition of an axially compliant member in the drillstring above the anchor can also help to damp movement and/or longitudinal force requirements of the anchoring system.

The application of longitudinal force to the drill bit by the anchor and movement may help to overcome erratic drillstring drag forces and stabilize and/or optimize the engagement of the distal tool with the borehole. The inclusion of axial compliance above the anchor may damp drillstring movement and allow the anchor and the longitudinal force applied by it to the distal tool to stabilize WOB. The application of longitudinal force may also assist in mitigating or minimizing buckling of the drillstring and optimizing and/or maximizing weight on the distal tool (for example, WOB).

The use of a downhole processor in some implementations can allow for full kinematics control of processes downhole, for example to eliminate drilling dysfunctions (such as stick slip) and can also minimize the need for heavy drilling BHAs that typically limit the use of continuous work strings such as coiled tubing.

The anchor can advantageously isolate the drilling assembly and react torque to the formation, as well as applying axial (push/pull) forces to the work string, BHA and drill bit.

High fidelity and reliable real-time formation evaluation and drilling mechanics data can minimize drilling risk and allow for real-time closed loop control of parameters and drilling kinematics downhole. Improved well control and reduced chance of stuck pipe may result due to more reliable bottom hole pressure control.

The application of axial forces at the anchor, as described above, may also allow the anchor to be used as a tractor for completions and intervention operations. In particular, this may allow a continuous work string, such as coiled tubing, to remain in tension, which may significantly increase the drillable footage. This may also help to avoid buckling, which may occur in typical coiled tubing applications.

By including measurement devices such as sensors local to the anchor, for example at the anchor itself, to measure parameters such as torque and axial force, increased measurement density can allow more precise well placement and formation characterization.

This can also allow for full control of drilling kinematics to minimize drilling dysfunction and improve ROP, as well as reducing damage to downhole tools. Axial stick slip mitigation and/or control of drilling ROP can improve drill motor life due to more stable control of motor differential pressure and torque.

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 apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy, in dependence on inputs received from one or more downhole sensors for sensing the state of the downhole apparatus and/or the distal tool, for controlling the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole.
2. The apparatus as claimed in claim 1, wherein the processor is configured to: determine one or more downhole parameter measurements from the inputs received from the one or more downhole sensors; and control the anchor to apply longitudinal force to the distal tool in dependence on the one or more downhole parameter measurements.
3. The apparatus as claimed in claim 2, wherein the one or more downhole parameter measurements comprise one or more of pressure, displacement, downhole weight on the distal tool and downhole torque on the distal tool.
4. The apparatus as claimed in any preceding claim, wherein the drillstring comprises a rotational drive proximal of the distal tool for driving the distal tool to rotate.
5. The apparatus as claimed in claim 4, wherein the processor is programmed to execute the control strategy to control the longitudinal force applied to the distal tool to maintain the rotational drive within one or more predetermined operational ranges.
6. The apparatus as claimed in claim 5, wherein the one or more predetermined operational ranges are predetermined ranges of one or more of rotational speed, torque and power of the rotational drive.
7. The apparatus as claimed in any of claims 4 to 6, wherein the rotational drive comprises a mud motor and wherein the one or more downhole parameter measurements comprise a differential pressure between drilling fluid passing through the motor and drilling fluid in the annulus of the borehole.
8. The apparatus as claimed in any preceding claim, wherein the downhole apparatus comprises the processor.
9. The apparatus as claimed in any preceding claim, wherein the processor is programmed to execute the control strategy, in dependence on inputs received from the one or more downhole sensors, for controlling the apparatus to apply longitudinal force to the distal tool by means of the anchor.
10. The apparatus as claimed in any preceding claim, wherein the one or more downhole sensors are local to the downhole apparatus.
11. The apparatus as claimed in any preceding claim, wherein the control strategy is a closed-loop control strategy.
12. The apparatus as claimed in any preceding claim, wherein the anchor comprises an internal channel for conveying the flow of drilling fluid to the distal tool, wherein the processor is configured to execute the control strategy to maintain a differential pressure between the channel and the annulus of the borehole within a predetermined range.
13. The apparatus as claimed in any preceding claim, wherein the longitudinal force provides weight on the distal tool.
14. The apparatus as claimed in any preceding claim, wherein the processor is configured to execute the control strategy to apply longitudinal force to the distal tool to control a depth-of-cut or a rate of penetration of the distal tool.
15. A downhole apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy for controlling the apparatus to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, adjust longitudinal force applied by means of the anchor to the distal tool.
16. The apparatus as claimed in claim 15, wherein the processor is programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, increase the longitudinal force applied by means of the anchor to the distal tool.
17. The apparatus as claimed in claim 15 or claim 16, wherein the drillstring comprises a rotational drive proximal of the distal tool for applying rotational drive to the distal tool, wherein the processor is programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, adjust the longitudinal force applied by means of the anchor to the distal tool to stabilize or optimize torque requirements of the rotational drive and/or stabilize rotational output from the rotational drive.
18. The apparatus as claimed in claim 17, wherein the processor is programmed to execute the control strategy to, in response to the detection of a condition associated with a reduction in drilling efficiency and/or a condition associated with damage to the drillstring, increase the longitudinal force applied by means of the anchor to the distal tool to maintain engagement between the distal tool and the borehole.
19. The apparatus as claimed in claim 17 or claim 18, wherein the processor is programmed to execute the control strategy to maintain the rotational drive within one or more predetermined operational ranges.
20. The apparatus as claimed in any of claims 15 to 19, wherein the downhole apparatus comprises the processor.
21. The apparatus as claimed in any of claims 15 to 20, wherein the processor is configured to detect a condition associated with a reduction in drilling efficiency in dependence on inputs from one or more downhole sensors local to the downhole apparatus.
22. The apparatus as claimed in claim 21, wherein the one or more downhole sensors comprise one or more sensors configured to measure or infer pressure, displacement, downhole weight on the distal tool and downhole torque on the distal tool
23. The apparatus as claimed in any of claims 15 to 22, wherein the anchor comprises 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.
24. A downhole apparatus for use in a drillstring in a borehole, the drillstring terminating in a distal tool, the downhole apparatus comprising an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole, the anchor being communicatively connectable with a processor programmed to execute a control strategy, in dependence on inputs received from one or more downhole sensors for sensing the state of the downhole apparatus and/or the distal tool, for controlling the apparatus to apply longitudinal force to the distal tool to achieve a predetermined rate of penetration of the distal tool.
25. A method of retracting a downhole tool from a wellbore, the method comprising: performing a downhole operation using a drillstring comprising a downhole tool and an anchor having a gripping element for engaging the borehole to restrict relative axial and/or rotational movement between the anchor and the borehole; operating the anchor to move through the wellbore in a surface-bound direction so as to retract the downhole tool from the wellbore.