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WO2025088194A1 - Appareil de fond de trou destiné à être utilisé avec une colonne de travail continue - Google Patents

Appareil de fond de trou destiné à être utilisé avec une colonne de travail continue Download PDF

Info

Publication number
WO2025088194A1
WO2025088194A1 PCT/EP2024/080340 EP2024080340W WO2025088194A1 WO 2025088194 A1 WO2025088194 A1 WO 2025088194A1 EP 2024080340 W EP2024080340 W EP 2024080340W WO 2025088194 A1 WO2025088194 A1 WO 2025088194A1
Authority
WO
WIPO (PCT)
Prior art keywords
anchor
borehole
downhole
tool
work string
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
PCT/EP2024/080340
Other languages
English (en)
Inventor
Liam Anthony LINES
William David Murray
Anthony Richard Glover
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
GA Drilling AS
Original Assignee
GA Drilling AS
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from GB2316351.2A external-priority patent/GB2636344A/en
Priority claimed from GB2405172.4A external-priority patent/GB2638791A/en
Application filed by GA Drilling AS filed Critical GA Drilling AS
Priority to PCT/EP2025/055722 priority Critical patent/WO2025181402A1/fr
Publication of WO2025088194A1 publication Critical patent/WO2025088194A1/fr
Pending legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/04—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
    • E21B23/0411—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion specially adapted for anchoring tools or the like to the borehole wall or to well tube
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/01—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/18—Anchoring or feeding in the borehole
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E21B44/02—Automatic control of the tool feed

Definitions

  • This invention relates to downhole apparatus for use with a continuous work string in a borehole. For example, in a subterranean drilling, milling or completions operation.
  • a borehole is drilled through a formation in the earth to form a borehole.
  • a drillstring extends from an upbore location, typically on the surface, to the foot of the borehole and typically comprises components known as the bottom hole assembly which may terminate in a drill bit.
  • the drill bit located at the distal end of a drillsting can be rotated by a downhole motor, allowing the bit to advance through the formation to form the borehole.
  • 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).
  • geologic complexity such as faults, fractures and high friction
  • directional complexity for example, intersections, geosteering, long laterals and low well spacing
  • well control for example, losses and high pressure zones.
  • a drillstring anchor can be used to axially stabilize the drillstring and to reduce torsional vibrations which can help to mitigate these issues and reduce the likelihood of significant and potentially damaging oscillations along the drillstring. It is desirable to use a continuous work string in the drillstring to reduce tripping time and nonproductive time and to allow for continuous circulation of drilling fluid and improved control of downhole operations.
  • an apparatus for use in a borehole comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole and a connector for connecting the apparatus to a continuous work string terminating proximally of the anchor, wherein the connector is configured to facilitate transfer of signals between the anchor and the surface of the wellbore.
  • the signals may be received and/or transmitted via the continuous work string.
  • the signals may be received and/or transmitted via the formation in which the borehole is formed.
  • the signals may be, for example, electrical or electro-magnetic signals.
  • the signals may be one or more of power signals, control signals and data signals.
  • the signals may be, for example, communications signals and/or signals indicating measurements, for example of one or more of force, torque, bending and flowrate of drilling fluid.
  • the signals are power signals
  • the power signals may provide power to drive components at the anchor and/or below the anchor in the drillstring.
  • the signals may be received by and/or transmitted from the connector.
  • the signals may be received by and/or transmitted from the connector from and/or to the surface via the continuous work string.
  • the apparatus may be communicatively connectable with a surface or downhole control unit.
  • the control unit may be configured to adjust the configuration of the anchor and/or one or more other elements coupled to the anchor (for example, coupled directly or indirectly at the distal end of the anchor) in response to one or more signals.
  • the one or more other elements may be communicatively connectable to the anchor. This may allow signals to be passed through the anchor and/or for signals to be transferred between the surface to more distal components of a bottom hole assembly than the anchor.
  • the signals may be received at the connector.
  • the apparatus may comprise the control unit. Alternatively, the control unit may be remote from the apparatus.
  • Adjusting the configuration of the anchor may comprise adjusting the configuration of the gripper and/or adjusting the configuration of one or more other parts of the anchor, such as one or more pistons for applying an axial force to the continuous work string or one or more of the other elements coupled with the anchor, such as a drill bit.
  • the continuous work string may extend from the surface of the borehole (i.e. from ground level).
  • the connector may be configured to receive power and/or control signals via the continuous work string from the surface.
  • the connector may be an electrical connector.
  • the connector may alternatively be electrically insulating, which may enable electro-magnetic signals to be transmitted between the anchor and the surface via the formation.
  • the apparatus may further comprise one or more measurement devices for determining one or more of torque, axial force, bending force, pressure and temperature.
  • the gripping element may be configured to grip the borehole to restrict relative axial movement between the anchor and the borehole.
  • the gripping element may be configured to grip the borehole to restrict relative rotation between the anchor and the borehole.
  • the anchor may be configured to react axial loads to the borehole when the gripping element is gripping the borehole.
  • the anchor may be configured to react torsional loads to the borehole when the gripping element is gripping the borehole.
  • the gripping element may be configured to grip the borehole to restrict both relative rotation and relative axial movement between the anchor and the borehole.
  • the anchor may be configured to react both axial loads and torsional loads to the borehole when the gripping element is gripping the borehole.
  • the anchor may be capable of transferring axial force to the continuous work string to pull the continuous work string down the borehole and/or push the continuous work string up the borehole.
  • the connector may be capable of transferring axial force to the continuous work string to pull the continuous work string down the borehole and/or push the continuous work string up the borehole.
  • the anchor may be configured to apply axial force to one or more distal downhole components coupled to the anchor.
  • the anchor may be part of a bottom hole assembly, wherein the anchor is configured to urge the bottom hole assembly into the borehole.
  • the anchor may be coupled with a tool for performing a downhole operation at the distal end of the bottom hole assembly and wherein the anchor is configured to apply weight to the tool to urge the tool into the borehole or against the bottom of the borehole.
  • the anchor may comprise multiple gripping elements each configured to move axially relative to a body of the anchor.
  • the multiple gripping elements may be disposed on the same body, or across multiple body parts that are axially separated along the longitudinal axis of the apparatus.
  • the multiple body parts may each act as separate anchor tools that are independently controlled.
  • the anchor may comprise a drive mechanism for advancing one gripping element downhole and/or uphole relative to at least one other gripping element.
  • each body part having multiple gripping elements each configured to move axially relatively to its respective body part
  • each body part may have a respective drive mechanism for advancing one gripping element downhole and/or uphole relative to at least one other gripping element.
  • the continuous work string may comprise coiled tubing.
  • the continuous work string may comprise any other suitable continuous pipe, hose or transfer line. Multiple such continuous strings may be connected together in some cases, for example when drilling very deep wells where extended reach is required.
  • the or each gripping element may have an associated actuator.
  • 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.
  • one actuator may be used to drive multiple grippers, or each gripper may have its own actuator.
  • the connector may be proximal of the anchor.
  • the connector may be coupled to the anchor by a rotatable and/or axially compliant coupling.
  • the coupling may be configured to allow relative rotation of the connector and the anchor about one or more axes.
  • the coupling may comprise a swivel.
  • the swivel may be a unidirectional swivel or a bidirectional swivel.
  • the swivel may be a continuous swivel.
  • the connector may comprise a fluid conduit.
  • the coupling may comprise the fluid conduit (or a part thereof).
  • the fluid conduit of the coupling may be configured to receive fluid from the continuous workstring.
  • the fluid conduit may be configured to receive drilling fluid from a drilling fluid supply conduit of the continuous workstring.
  • the coupling may be configured to at least partially isolate the connector from torsional forces generated distally of the anchor.
  • the coupling may be configured to fully isolate the connector from torsional forces generated distally of the anchor.
  • the coupling may be proximal of the proximal end of the anchor.
  • the coupling may be immediately proximal of the proximal end of the anchor.
  • 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.
  • an energy store such as a battery or other energy source or a reservoir of hydraulic fluid
  • a thermal gradient between the interior of the anchor and the annulus of the borehole via an electric conduit connectable with the connector (where electrical power is supplied from the surface); by differential rotation between the anchor and the drillstring or the output of a mud motor.
  • the apparatus may comprise one or more of the following: one or more data connectors for connecting to one or more data cables within the continuous work string for transmitting bidirectional communications between the surface of the borehole and the anchor; and/or one or more hydraulic connectors for connecting to one or more conduits within the continuous work string for transmitting hydraulic fluid between the surface of the borehole and the anchor.
  • the one or more data connectors may be configured to transmit bi-directional communications between the surface and the downhole tool via the anchor.
  • the one or more data connectors may be configured to transmit bi-directional communications between the anchor and one or more tools above and/or below the anchor.
  • MWD/LWD and/or steering tools for example, am RSS tool
  • the connector may be configured to connect the apparatus to multiple continuous work strings.
  • the apparatus may be part of a downhole assembly comprising one or more additional downhole tools.
  • the one or more additional downhole tools may comprise one or more of the following: a measurement-while-drilling tool, a logging-while-drilling tool, a fluid conditioning module to regulate hydraulic fluid and/or filter drilling fluid, an orienter tool, a fixed or variable bent sub, a rotary steerable system, a downhole motor (such as a steerable mud motor) for providing rotational drive and/or torque to a drilling or milling tool at a distal end of the drillstring.
  • the drilling tool at the distal end of the drillstring may comprise a conventional rock bit, a PDC bit, a hybrid bit and a plasma bit.
  • the continuous work string may terminate at the connector.
  • the connector may comprise an electrical disconnect component configured to electrically disconnect the continuous workstring from the anchor. This may allow the continuous workstring to be electrically disconnected from the anchor, for example in the case of a stuck pipe event.
  • the apparatus may comprise one or more channels for receiving drilling fluid from the continuous work string and conveying the drilling fluid towards the distal end of the drillstring.
  • the borehole may be a wellbore.
  • the wellbore may be formed to aid the exploration and/or recovery of natural resources such as oil, gas or water.
  • the borehole may be another type of borehole.
  • an apparatus for use in a borehole comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole and a connector for connecting the apparatus to a continuous work string terminating proximally of the anchor, wherein the connector is coupled to the anchor by a flexible coupling.
  • the flexible coupling may be a rotatable and/or axially compliant coupling.
  • a system for use in a borehole comprising: a continuous work string extending from the surface of the borehole; and the apparatus defined above; wherein the continuous work string is connected to the apparatus at the connector.
  • a method of performing a downhole operation in a borehole comprising: deploying a continuous work string into the borehole, the continuous workstring being connected via a connector to an apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole, the continuous work string terminating proximally of the anchor; sending signals from the surface of the borehole to the apparatus; and controlling the configuration of the anchor based on the received signals.
  • the method may further comprise applying an axial force to the continuous work string using the anchor to pull the continuous work string down the borehole or push the continuous work string up the borehole.
  • the method may further comprise, using the anchor, applying an axial force to one or more components coupled distally of the anchor to urge the one or more components downhole or uphole in the borehole.
  • the method may further comprise applying weight on bit to a drill bit at the distal end of a bottom hole assembly comprising the apparatus.
  • the continuous work string may comprise a conduit for convenying the signals via the continuous work string, for example between the surface of the borehole (from which the continuous work string may be deployed into the borehole) and the connector.
  • the conduit may be an electrical conduit (which may be referred to as an E-line) for convenying electrcial signals or a conduit for conveying electro-magnetic signals.
  • the anchor may control (and in some cases restrict) relative axial movement between the anchor and the drillstring.
  • the continuous workstring may be connected via the connector to an apparatus comprising one or more downhole anchors having any of the features described above (for example, multiple downhole anchors).
  • the continuous work string may be an insulated continuous workstring.
  • the continuous workstring may be configured to receive drilling fluid from a chilled drilling fluid supply at the surface of the borehole. This may be particularly suitable where the apparatus is for geothermal drilling applications.
  • 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 control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool (for example, a distal face of the distal tool) and the distal end of the borehole (for example, the bottom of the borehole).
  • the control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole as the distal tool is being operated (for example, driven to rotate) to advance the borehole.
  • the control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole for more than a predetermined time period.
  • the distal tool may be a drill bit.
  • the control strategy may control the apparatus to apply longitudinal force to optimize the engagement of the distal tool and the borehole to minimize drilling dysfunction and/or enhance the drilling process (for example, as the drill bit is being operated to advance 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.
  • 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.
  • 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.
  • the processor may be remote from the downhole apparatus.
  • 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.
  • 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.
  • the apparatus may be communicatively connectable with a downhole control unit.
  • 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 unit may comprise the processor and one or more memories.
  • 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.
  • 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.
  • 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.
  • an energy store such as a battery or other energy source or a reservoir of hydraulic fluid
  • a thermal gradient between the interior of the anchor and the annulus of the borehole via an electric conduit connectable with the connector (where electrical power is supplied from the surface); by differential rotation between the anchor and the drillstring or the output of a mud motor.
  • the apparatus may comprise one or more 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.
  • FIG. 1 schematically illustrates an example of a drilling system, illustrated at a subterranean location in a borehole during a downhole operation.
  • FIG.s 2(a) and 2(b) schematically illustrate an example of a gripper comprising a hydraulically actuated piston assembly.
  • FIG.s 3(a)-3(c) schematically illustrate an example of a piston.
  • FIG. 4 schematically illustrates an example of an anchor comprising multiple gripping segments.
  • FIG. 5 schematically illustrates an example of a hydraulic cylinder assembly of the anchor of FIG. 4.
  • FIG. 6 schematically illustrates the connection of a continuous work string proximally of the anchor.
  • FIG. 7 schematically illustrates an example of a control unit.
  • FIG. 8 shows the steps of an exemplary method for performing a downhole operation in a borehole using a continuous work string.
  • FIG. 1 schematically illustrates an example of a drilling system illustrated at a subterranean location in a borehole (not to scale).
  • the borehole illustrated is vertical, the borehole may have a more complicated two or three dimensional path and may also include multiple branches.
  • a rig 101 provides support and/or power to a drillstring.
  • the drillstring comprises a continuous work string 102.
  • the continuous work string is a string of coiled tubing.
  • Coiled tubing is typically a continuous length of tubing, which may comprise multiple sections of tubing that are welded together to form a continuous string capable of being deploying into the borehole as a single unit.
  • the coiled tubing may be made from a low-alloy carbon steel tubing.
  • the coiled tubing is spooled on a reel 103 from which it is deployed into the borehole.
  • coiled tubing may allow for continuous drilling and circulation of drilling fluid and can additionally minimize drilling and well control risk, reduce bottom hole temperatures and improve tripping times compared to conventional jointed drill pipe.
  • the coiled tubing may be insulated for additional reduction in bottom hole temperatures.
  • the coiled tubing may be maintained in tension for increased longevity and to maximize drilling distance.
  • the continuous work string may be other types of continuous pipe, hose or transfer line.
  • the continuous work string may be a continuous length of greater than 5,000 ft without mechanical joints.
  • multiple continuous strings may be joined together for very deep wells where, for example, a single reel of coiled tubing is not long enough. The use of a continuous work string may allow the BHA to be more quickly deployed in the borehole, which can reduce trip time and non-productive time.
  • the continuous work string 102 may comprise one or more electrical conduits such as cables for supplying power and/or communications to and/or from one or more downhole components.
  • electrical conduits in the continuous work string may be known as an E-line. This can allow for robust communications and the provision of power independently of other power sources, such as from the flow of drilling fluid.
  • the borehole is shown at 104.
  • the borehole may be at least partially lined with casing 105 and cement 106.
  • the work string 102 may provide torque and/or power (for example, rotary, thermal, and/or electrical power) to the bottom hole assembly (BHA), shown generally at 107.
  • the BHA may comprise a tool or other component 108.
  • the tool 108 may be a drilling tool.
  • the tool 108 may be, for example, a drill bit.
  • 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 component shown at 111 is a measurement-while-drilling (MWD) tool.
  • the MWD tool provides borehole direction and formation evaluation data.
  • the MWD tool may utilize conventional telemetry techniques (such as mud pulse telemetry) with standalone battery powered tools.
  • the MWD tool may be integrated with the cable(s) in the coiled tubing for higher density data and more reliable decoding in deep applications with challenging mud properties.
  • the data collected by the MWD tool may include shock, vibration, pressure, weight and torque data. The data may be used for closed loop control and optimization of the drilling process.
  • the MWD tool 111 may comprise a means of transmitting information to the surface. This may be performed by, for example, mud pulses, whereby the operation of a valve in the fluid flowpath in the drillstring, or by allowing fluid to egress the interior of the drillstring to the annulus, induces pressure variations which may be detected using pressure and/or flow measurements at the surface. Alternatively, this may be performed by electro-magnetic means, where a voltage across an insulated section of drillstring is varied, and these variation detected using a potential difference detector at surface using surface electrodes (not shown), or by employing electrical signals through wired pipe (if present). Both electro-magnetic and wired coiled tubing telemetry allow for bi-directional communication, and hence may receive signals transmitted from the surface.
  • mud pulses whereby the operation of a valve in the fluid flowpath in the drillstring, or by allowing fluid to egress the interior of the drillstring to the annulus, induces pressure variations which may be detected using pressure and/or flow measurements at the surface.
  • 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 straingauges, accelerometers, pressure sensors and gyroscopes to measure the mechanical stresses imposed on, and the motion of, the MWD module.
  • a logging while drilling (LWD) tool may alternatively or additionally be used.
  • LWD logging while drilling
  • 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.
  • RSS rotary steerable system
  • the steering device 112 can utilize some combination of force applied to the borehole, or curvature of the drillstring in order to control the direction of the drill bit.
  • the steering device may be communicatively coupled to the surface. This may allow the steering device to receive commands transmitted from the surface, for example via the E-line, which may allow the drill bit to be urged to follow a desired trajectory.
  • the component shown at 113 is an anchor tool, which will be described in more detail below.
  • the anchor 113 is connected to the coiled tubing 102 via a coupling 114, such as a swivel.
  • the coupling 114 couples the anchor 113 to a coiled tubing connector 115 which allows the coiled tubing 102 to be connected to the proximal (i.e. upbore) end of the connector 114.
  • the coupling may be a flexible coupling.
  • the flexible coupling may allow relative movement of the connector for connection to the work string and the anchor about and/or along one or more axes.
  • the coupling may be rotatable and/or axially compliant, as will be described in more detail below.
  • 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.
  • the shaft may be configured to move relative to the gripper(s).
  • the shaft may be rotatable relative to the channel of the anchor through which the shaft passes.
  • 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 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 (for example, work string), including stick slip.
  • the anchor is designed to remove at least some, and preferably all, of the torque from the drillstring (for example, work string).
  • the operation is a rotary drilling operation which uses a downhole motor to provide rotational drive to a drill bit below the anchor.
  • the anchor described herein may be utilized in non-rotary drilling situations such as jetting or plasma drilling (a contactless drilling technique that uses high-voltage pulses to fracture the rock) or any other compatible operation or situation in a borehole, such as a milling, completion or plug and abandonment operation.
  • Other additional components of the BHA may be drill collars, stabilizers, reamers, hole-openers and bit subs.
  • the rig 101 provides support for the work string 102. Drilling fluid is circulated through the work string via pipes and hoses 121 , from mud tanks 120 by fluid pumps (not shown). The fluid returns to the mud tanks via a further flow channel and shale shakers (not shown).
  • One or more surface computational platforms 123 may perform functions such as controlling the operation of the auto-driller, top-drive and mud-pumps, or they may contain embedded controllers.
  • the surface computational platform 123 can communicate with off-site computers or individuals, using an antenna or cable 124, which may enable effective control to be conducted remotely from the well site.
  • One or more of the components located at the surface of the borehole are part of a surface system of the drilling system.
  • the drilling rig may be instrumented, so that parameters related to the drilling operation may be determined at the surface. For example, one or more of the tension applied by the work string 102 to the drilling line (hook-load), the vertical motion of the top of the string (the surface rate-of-penetration), the torque applied to and the rotation speed of the string, and the flow rate and pressure of the drilling fluid at surface. This list is not exhaustive, and other parameters may be monitored.
  • the exemplary BHA shown in FIG. 1 comprises a source of electrical power, which may for example be a fluid-driven turbine, the rotation of which generates an electrical current.
  • Alternative sources of electrical power include batteries or capacitors, or an interface to the E- line, allowing power to be transmitted from the surface.
  • 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.
  • the drill bit is driven to rotate by a downhole mud motor to form the borehole in the formation.
  • the anchor is configured to be mounted above the motor.
  • the motor may be a mud motor.
  • the drill bit may be driven by other downhole rotary drive devices such as electric motors, pneumatic motors or a drilling turbine.
  • 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.
  • the anchor comprises one or more gripping elements (referred to herein as grippers) that can be activated by one or more actuators.
  • the actuators may be driven from an energy store at the anchor or other energy source.
  • the actuator can be driven to cause the gripper to adopt one of a first state in which it is urged outwardly for gripping the walls of the borehole and a second, passive state.
  • 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.
  • the term ‘activated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is urged outwardly relative to the central axis of the drillstring. In this state the gripper can grip the borehole.
  • the term ‘deactivated’ is used to mean that a gripper of the anchor (or a segment of the anchor) is in a state where it is exerting a reduced gripping force relative to the activated state. For example, it may be in a state where it is not gripping the borehole. In this state it may not be urged outwardly relative to the central axis. In the activated state the gripper may be in a location radially outwardly of its location in the deactivated state.
  • the gripper may be biased to one of the states, e.g. by a spring.
  • the energy store provides the energy supply to one or more actuators for actuating one or more grippers.
  • the energy store may be a source of energy generated locally at the anchor.
  • the energy store may be charged or refilled at the surface before running in hole.
  • the energy store may be replenished (e.g. recharged) during or after a trip to the surface.
  • the energy store may be self-contained in the anchor.
  • the energy store is preferably a source of energy stored locally at the anchor.
  • the energy store is preferably suitable for permitting the anchor to operate over an extended period of time without requiring replenishment from the surface of the borehole whilst the anchor is in hole.
  • the energy store may be a reservoir of pressurised hydraulic fluid such as an accumulator.
  • the energy store may be a source of electricity such as a battery or fuel cell.
  • the anchor may be powered by an alternative energy source, such as a direct supply of power from the surface (for example, via the electrical conduit) or via a mud-driven turbine.
  • the anchor is hydraulically actuated and has its own self-contained or sealed hydraulic system.
  • the hydraulic fluid can be pressurised to higher pressures than the mud pressure inside the drillstring (during drilling), and so has a higher pressure differential with the annular pressure. Therefore, the anchor may not directly use the drilling mud to actuate its gripper(s). Instead, the anchor can use stored energy to activate and deactivate the anchor.
  • the anchor can be in the deactivated configuration when the mud pumps are running.
  • the anchor may generate its own reservoir of stored hydraulic energy.
  • the reservoir enables the anchor to be activated when needed, independently of the drilling mud pumps. This may be a high pressure, low volume reservoir using clean fluid (not drilling mud).
  • the system may use and re-charge a hydraulic accumulator.
  • the anchor can thus in some cases be activated and deactivated without using the use of mud flow, mud pressure, or mud pulses and/or without using electronics.
  • the drillstring When the anchor is activated (i.e. when the actuator is driven to cause the gripper to grip the borehole), the drillstring is translatable along its longitudinal axis with respect to the anchor.
  • the anchor may be 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).
  • the anchor When the anchor is activated, relative rotation between the anchor and the borehole can be resisted or restricted. This may be due to physical engagement between the anchor and the interior face of the borehole.
  • the gripper is configured to be actuated to move between a passive (i.e. deactivated) state and an outwardly-urged (i.e. activated) state.
  • the gripper In the passive state, the gripper may be radially retracted relative to the activated state.
  • the gripper In the activated state the gripper is configured to restrict relative rotation between the anchor and the borehole.
  • the device In both the activated and deactivated states the device is configured to allow axial movement of the drillstring relative to the device.
  • the anchor In the deactivated state, the anchor can rotate relative to the borehole.
  • relative rotation between the anchor and the downhole section of the drillstring is preferably restricted.
  • the downhole section of the drillstring can move axially relative to the anchor in the downhole direction (i.e. in the direction of the bottom of the borehole, or the furthest reach of the borehole, in the case of a horizontal well) and/or the opposite direction (in the direction of the surface).
  • the gripper can be in the deactivated state when drilling fluid is pumped through the drillstring. Alternatively, the gripper may be activated using mud pressure.
  • the anchor may grip the borehole by actuating one or more elements such as pistons or pads to exert an outward radial force on the borehole.
  • a pad or piston may comprise teeth that provide resistance and allow the pad to grip the borehole.
  • Various tooth designs may be used. In one example, symmetrical teeth that are all the same length may be used. In other examples, teeth may be shaped such that they are not symmetrical and are more aggressive on the leading edge to resist motion. Each tooth may have a different angle on the back of the tooth different according to the local applied loading. Each tooth may have a different length to form a desired contact profile with the borehole.
  • the direction of teeth on the outside of the pads may be chosen according to the direction of loading. This may lead to a stronger tooth and require less force to provide a given torque capacity.
  • the gripper may have a non-flat portion. For example, the surface of the gripper may have undulations and/or protuberances. The surface of the gripper may comprise ribs, ridges and/or stud
  • 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).
  • the anchor comprises pistons which are capable of being urged outwardly for gripping the borehole from a passive state to an activated state.
  • the pistons are preferably hydraulically actuated.
  • the pistons can move relative to the body of the anchor in a direction perpendicular to the longitudinal axis of the anchor between the passive state and the gripping state in which the piston is urged outwardly to cause a gripper area at the end of the piston to grip the borehole.
  • the grippers can move in a radial direction relative to the longitudinal axis of the anchor.
  • FIG.s 2a) and 2b One example of a gripping assembly comprising a hydraulic piston is shown in FIG.s 2a) and 2b).
  • the piston In FIG. 2a) the piston is in its passive position (which in this example is a retracted position) and in FIG. 2b) the piston is in an extended position in which it is urged outwardly from the body of the anchor to cause the end of the piston to grip the borehole.
  • the body of the anchor is indicated at 200.
  • the gripper assembly 201 sits in a recess in the body 200 of the anchor so that when the gripper is it its passive state the distal end of the piston does not stand proud of the surface of the body 200 of the anchor.
  • the gripper assembly 201 comprises a housing 202 that sits in the recess in the body 200.
  • the piston 203 is accommodated in the housing and can move outward relative to the housing.
  • the piston 203 can move in the radial direction with respect to the longitudinal axis of the anchor.
  • the piston may have a limit of travel within the housing. In this example, the travel of the piston relative to the housing is limited by a circular groove 204 in the housing in which a flange 205 at the base of the piston 203 can run.
  • the groove has an end stop 206 which limits the travel of the piston 203 in the housing 202, as illustrated in FIG. 2(b).
  • the movement of the piston 203 is supported in the recess in the housing 202 by bearings 208, 210 distributed around the circumference of the recess or channel.
  • bearings 208, 210 distributed around the circumference of the recess or channel.
  • seals 207 and 209 are circumferential seals around the piston housing.
  • the gripper assembly may comprise a return spring.
  • 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.
  • the gripper assembly 201 comprises a return spring 212, which can allow the piston 203 to be returned to its passive state when the anchor is at the surface of the borehole and there is no acting pressure differential between the body of the anchor and the annulus of the borehole.
  • the end of the piston 203 has an insert 211 which engages the borehole to grip the rock.
  • the end of the piston 203 may engage the borehole directly with no additional insert.
  • the gripper can therefore be a removeable and/or replaceable component or can be integral with the piston.
  • the "gripper" is the part of the gripper assembly that grips the borehole.
  • the piston has an insert at the end of the piston for gripping the borehole.
  • 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.
  • FIG.s 3(a)-3(c) One example of a piston with an insert is shown in FIG.s 3(a)-3(c).
  • the piston is cylindrical with a circular-cross section.
  • the base of the piston has a flange 205 for limiting the travel of the piston within the housing, as described above.
  • the opposite end 212 of the piston to the base has a chamfered profile.
  • the piston is hollow to optionally accommodate a spring and defines a chamber for hydraulic fluid.
  • the gripper comprises a hardened insert 211 (made from, for example, T ungsten Carbide or Diamond) at the end of the piston.
  • the insert is located at the contact face (i.e. the face of the piston that contacts the borehole when the piston is in the extended position).
  • the insert may have protrusions or teeth which are able to repeatedly cut through lubricant, rock dust and/or residue and engage with the rock surface of the borehole.
  • the teeth have a pyramidal profile.
  • other profiles may be used.
  • the piston and/or the insert of the gripper may optionally be coated. This may allow the gripper to achieve a greater gripping affect than an uncoated gripper.
  • the gripper may be coated with a layer of diamond or superhard grit to increase the effective friction further.
  • the grippers may in some cases be activated from an energy store, such as a reservoir of hydraulic fluid at the anchor using a pump driven by the motor.
  • a hydraulic accumulator may be used with enough stored energy for a drilling trip.
  • the anchor may alternatively be powered by using energy generated as a result of the operation of the drillstring.
  • the anchor may also be activated by drilling mud pressure, mud flow (either directly or via a mud powered device such as a turbine), by turning the drillstring, or by axial movement of the drillstring.
  • the anchor (or one or more segments of the anchor) may be activated when mud is pumped to turn the mud motor, or when drilling with WOB is initiated or detected. Drillstring rotation may be used as an independent drive signal to activate the anchor (or one or more segments of the anchor).
  • the control signal for the anchor to be activated or de-activated may be provided from the surface.
  • the use of an electronic system is possible at drilling depths in conventional wells. However, in very deep wells such as geothermal wells (which may be several kilometres deep) the rocks temperature is increasingly hot. The maximum working temperature of electronics is approximately 175°C. Therefore, it may also be desirable to actuate and control the anchor using non-electronic means.
  • the anchor may be activated as a result of changes to the tension/compression of the drill string as weight is applied to the bit, or as results of a detected combination of axial force and torsion.
  • the anchor may be deactivated when the tool is lifted up in the hole or rotated from the surface. This can help to ensure the tool can be pulled out of the well.
  • the activation may be controlled via mud pumps, mud pulse or electrically via the E-line.
  • the anchor may allow for a continuous gripping action as the drillstring advances downhole in the borehole.
  • 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.
  • the anchor In order for the anchor to have a continuous gripping action, there is a time when both segments (or set of segments) are activated to grip the borehole and the drillstring (comprising the continuous work string and the BHA) can continue to move longitudinally relative to the segments during the transition between the activation of one segment (or set of segments) and the deactivation of another.
  • the transition includes the coordinated gripping and release of segments and may use a drive mechanism that is different to when only one segment (or set of segments) is activated.
  • the transition may be initiated in dependence on the position of the drillstring, for example relative to the activated segment (or set of segments), in dependence on elapsed time since a segment (or set of segments) was activated, or by some other means.
  • the drillstring and a second gripping element are driven to progress them downhole.
  • 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;
  • the first element (or set of elements) is deactivated and driven to progress down the borehole with the drillstring.
  • gripping assemblies each comprising a piston along the length of the anchor.
  • gripping assemblies each comprising a piston distributed around the circumference of the anchor. For example, there may be four rows of twenty gripping assemblies.
  • FIG. 4 shows an example of an anchor.
  • the anchor 113 comprises multiple segments 401 , 402 each comprising one or more grippers.
  • each segment may comprise multiple grippers of the type described above.
  • the segments 401 , 402 can be moved relative to one another using a walking mechanism.
  • the anchor uses a hydraulic walking mechanism to move the segments and their associated gripper(s) down the borehole as drilling progresses.
  • control unit 700 of the anchor may allow for a coordinated downhole operation.
  • the control unit (such as control unit 700) may also allow for downlinking in non-wired I conventional drilling applications and communication with other BHA tools.
  • the anchor 113 comprises a first gripping segment 401 and a second gripping segment 402.
  • the gripping segment 401 comprises an upper gripper set and the gripping segment 402 comprises a lower gripper set (‘upper’ and ‘lower’ being relative to the bottom of the borehole).
  • the segments 401 and 402 are each connected to hydraulic cylinder assemblies 405 and 409, for example via galleries.
  • the respective gripping segments are fast with their respective cylinder assemblies such that movement of a cylinder assembly relative to the drillstring causes corresponding movement of the respective gripping segment.
  • the anchor may comprise a wired flex portion between the two gripping segments. This may allow the lower gripping segment to electrically communicate with a control unit of the anchor and/or the upper gripping segment. This can allow control signals and/or power to be supplied to the lower gripping segment from the control unit.
  • Each gripping segment comprises a gripper housing.
  • the gripper housings house the grippers.
  • the gripper housings can move longitudinally relative to the main body of the tool. The range of longitudinal movement may be referred to as the ‘tool stroke’. 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 anchor advantageously allows the ability to rotate the drillstring during axial anchoring and for the dril Isring to move axially relative to the anchor during torsional anchoring.
  • Connector 403 is an upper connector for connection to drill pipe or an upper part of the BHA.
  • Connector 410 is a lower connector for connection to a downhole mud motor or a lower part of the BHA.
  • the upper connector 2003 and lower connector 2003 may both be adapters to industry standard connectors used to connect the anchor to the adjacent sections of the drillstring.
  • Unit 404 is a hydraulic unit configured to provide hydraulic power for actuating the grippers of gripper segments 401 and 402.
  • the hydraulic unit 404 does not provide hydraulic power to the drive mechanisms of the gripping segments (hydraulic cylinder assemblies 405 and 409) and the hydraulic power supplied to the units 405, 409 is passive and on a separate circuit. Connections between the hydraulic unit 404 and the grippers may be provided by galleries within the units 401 , 402, 405, 406 and 408.
  • the drive mechanism for moving each segment longitudinally relative to the other segment(s) comprises a hydraulic circuit with hydraulic cylinder assemblies.
  • a first cylinder assembly is shown at 405.
  • the cylinder assembly 405 controls the movement of the first gripping segment 401 relative to the body or housing of the anchor.
  • the cylinder assembly 405 drives the first gripping segment 401 to move relative to the second gripping segment 402.
  • a second cylinder assembly is shown at 409.
  • the cylinder assembly 409 controls the movement of the second gripping segment 402 relative to the housing of the anchor.
  • the cylinder assembly 409 drives the second gripping segment 402 to move relative to the first gripping segment 401 .
  • Unit 406 is an upper key housing which contains galleries connecting the cylinder assemblies 405 and 409.
  • Unit 408 is a lower key housing which contains galleries connecting cylinder assemblies 405 and 409.
  • the key housings 406, 408 are configured to engage with the main shaft of the anchor, which may have corresponding keyed protrusions which engage with the key housings.
  • Hoses 407 connect the hydraulic cylinder assemblies 405, 409 of the upper and low gripping segments 401 , 402 and provide the actuation and return hydraulic feeds to these units 405, 409.
  • the units 401 , 402, 404, 405, 406, 408 and 409 comprising the anchor may be arranged in any order.
  • FIG. 5 shows an example of a cylinder assembly 405, 409 and its associated components.
  • the cylinder assemblies 405, 409 each comprise two cylinder assemblies 501 , 502.
  • one pair of cylinder assemblies 501 , 502 is attached to the housing of a gripping segment.
  • each pair of cylinder assemblies is fast with a gripping segment of the anchor.
  • the cylinder assemblies are arranged around the circumference of the channel which engages a shaft 508.
  • the cylinder assemblies may be arranged on opposing sides of the channel and shaft 508.
  • the cylinder assemblies of each gripping segment are connected to each other, for example by piping, to allow the flow of hydraulic fluid therebetween.
  • the shaft 508 may be axially coupled with components on either side of the anchor.
  • the shaft may be axially coupled with the continuous work string above the anchor and other components of the BHA below the anchor. This can allow drilling to progress while one or more of the grippers of the anchor are activated to grip the borehole.
  • Cylinder assembly 502 comprises corresponding features.
  • Cylinder assembly 501 comprises a piston 505 which separates two chambers 503, 506 within the cylinder.
  • One chamber 503 is above the piston and the other 506 below (with respect to the downhole direction).
  • the linkage 509 which in this example is a rod passing through the upper and lower chambers and the piston 505, is slidably attached to the piston 505.
  • the rod is attached at its lower end (in the downhole direction) to the shaft 508 via connection 507.
  • the linkage 509 is configured to transfer a force to the piston 505 when the shaft 508 moves downhole.
  • linkage 509 comprises a seat, shown at 510, which bears against one or more compliant members between the seat 510 and the piston 505.
  • the one or more compliant members are springs 504 located adjacent to the piston 505 in the uphole direction, between the piston 505 and seat 510 of linkage 509.
  • the compliant member(s) provides for compliance between the piston 505 and the linkage 509 that allows drilling to progress, and thus allows the shaft 508 to continue moving axially in the downhole direction, when both gripping segments are gripping the borehole (for example, during the handover phase between the gripping segments, as described below).
  • the linkage 509 comprises a stop 511. Stop 511 can be inserted during assembly of the anchor device to preload the compliant spring member 504. During walking motion, the spring preload is sufficient to resist the hydraulic pressures generated in the chamber 506 and so there is no relative movement between piston 505 and linkage 509.
  • this fluid can be accepted into the lower chamber of this other cylinder assembly by moving the gripper segment attached to the other cylinder (SEGMENT B) down the borehole, increasing the volume of the lower chamber.
  • the piston(s) within the SEGMENT B cylinder(s) have also been moved down relative to the borehole by motion of the shaft 508.
  • the SEGMENT B gripper housing is seen to move at twice the speed of the main shaft 508 in the downhole direction.
  • the volume changes in the upper chambers 503 are dealt with by fluid flowing from the cylinder(s) of SEGMENT B to SEGMENT A.
  • SEGMENT B is the set of grippers that are activated and fixed to the borehole wall
  • the system works in reverse and the SEGMENT A gripper housing is seen to move down hole at twice the speed of the shaft 508.
  • a short period where the grippers of both segments are actuated to grip the borehole wall is advantageous.
  • the shaft 508 can continue to move downhole relative to the channel of the anchor as drilling progresses.
  • the piston 505 does not move within the cylinder assembly 501 .
  • a change in volume of the lower chamber 506 of the cylinder assemblies cannot be relieved by moving fluid between the chambers of the cylinder assembly(s) of the gripping segments. Therefore, there is resistance to motion of the piston 505 in the downhole direction. This is counteracted by seat 510 compressing the one or more compliant members 504 above the piston 505 to allow the linkage 509 to move with the shaft 508, thus allowing the drillstring to continue moving downhole.
  • the handover from one gripping segment to the other may be determined based on the position of the other gripping segment relative to the housing of the anchor, or after a predetermined time since the segment currently gripping was actuated.
  • 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.
  • the gripper of a free (i.e. not currently gripping) segment may be triggered to grip the borehole when the currently gripping segment is 20mm from the end of its longitudinal range of travel relative to the housing of the anchor.
  • the currently gripping segment could then be released after another 10mm of drilling (measured by the relative longitudinal movement of the shaft and the channel).
  • An alternative implementation is to release the gripper of the currently gripping segment a fixed time after the free segment gripper activation is started.
  • 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.
  • 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.
  • the hydraulic cylinders may be actively controlled from a hydraulic power source to push the shaft (in a downhole direction) and apply weight-on-bit to a drill bit, or apply weight to another downhole tool, at the distal end of the BHA.
  • the anchor may also be configured to apply axial force to the BHA below the anchor to urge the BHA into the borehole (i.e. in the downhole direction). Axial forces may also be applied to the continuous work string in a similar way by controlling the hydraulic cylinders to pull the shaft in an uphole direction.
  • one or more of the gripping segments may comprise an axial piston moveable within a cylinder.
  • the piston may be connected to the gripper housing and the cylinder may be connected to the shaft 508 running through the anchor (or vice versa).
  • the anchor comprises the shaft.
  • the shaft is axi al ly/l ongitud i nal ly 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 force transfer to the BHA.
  • This piston may be single acting with a mechanical return (such as a spring) or double acting to allow axial force to be applied to the shaft in both the uphole and downhole directions.
  • the pressurization of the fluid may be controlled based on the internal pressure of drilling fluid flowing through the anchor, may be regulated to remain substantially constant, or may be modulated based on other factors. 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.
  • WOB weight-on-bit
  • the anchor may comprise a single gripping segment that is activated to grip and release the borehole without the walking mechanism or alternatively may comprise individual gripping and push/pull modules that can be connected (electrically, mechanically or hydraulically) such that they work in coordination to allow movement and force to be transferred to the drillstring and/or BHA.
  • the continuous work string 102 is a string of coiled tubing.
  • the continuous work string may be any other continuous pipe, hose or transfer line for deploying drilling equipment and the features described below may also apply to a continuous work string of other forms.
  • the coiled tubing extends from the surface of the borehole.
  • the coiled tubing may be deployed from reel 103 at the surface.
  • the coiled tubing is attached to a coiled tubing connector coupled to the anchor by a rotatable coupling.
  • the rotatable coupling may not be present and the connector may be immediately proximal of the proximal end of the anchor, or may be separated from the anchor by other components, such as a sub or drill pipe.
  • the coiled tubing may extend continuously from the surface to the coiled tubing connector.
  • the coiled tubing connector is proximal of the anchor in the drillstring.
  • the coiled tubing terminates at the coupling.
  • the coiled tubing terminates proximally of the anchor.
  • 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.
  • 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.
  • the coupling between the anchor and the work string connector may also be axially compliant.
  • the axially compliant coupling may be configured to compress and/or extend in the axial direction, along the longitudinal axis of the borehole. This may allow the tool at the distal end of the drillstring to be able to progress in the wellbore in the event that the continuous work string becomes temporarily stuck or is not able to keep up with the rate of penetration of the drill bit.
  • the connector 115 may be axially coupled with the shaft 508 of the anchor. Therefore the anchor may be configured so that the continuous work string above the anchor and the components of the BHA below the anchor can move axially relative to the body of the anchor when one or more of the grippers of the anchor is gripping the wellbore. This can allow the drilling, or other operation, to progress when the anchor is activated to grip the borehole.
  • the connector and the coupling may be configured to allow fluid to pass from the continuous work string to the anchor.
  • the upper 114a and lower 114b parts of the coupling may comprise respective flanges that are sealed together to prevent leakage of fluid whilst allowing relative rotation between the parts 114a, 114b.
  • the connector may be capable of applying or transferring axial force to the continuous work string (or other drillstring type) to pull the continuous work string down the borehole and/or push the continuous work string up the borehole.
  • the anchor may be capable of applying or transferring axial force to the continuous work string (or other drillstring type) to pull the continuous work string down the borehole and/or push the continuous work string up the borehole.
  • the axial force may be generated by the anchor as described above. This can advantageously allow the anchor to act as a tractor for pulling the drillstring into and out of the borehole.
  • the connector may comprise one or more electrical connectors for connecting to one or more electrical cables within the continuous work string for supplying electrical power to the apparatus from the surface of the borehole.
  • the connector may alternatively be electrically insulating, which may allow electro-magnetic signals to be sent via the formation rather than sending electrical signals via the work string.
  • the connector may also comprise one or more data connectors for connecting to one or more data cables within the continuous work string for transmitting bi-directional communications between the surface of the borehole and the anchor.
  • the connector may also comprise one or more hydraulic connectors for connecting to one or more conduits within the continuous work string for transmitting hydraulic fluid between the surface of the borehole and the anchor.
  • the one or more data connectors may be configured to transmit bi-directional communications between the surface and the downhole tool via the anchor.
  • the one or more data connectors may be configured to transmit bi-directional communications between the anchor and one or more tools above and/or below the anchor.
  • MWD/LWD and/or steering tools for example, am RSS tool
  • the connector may comprise an electrical disconnect component configured to electrically disconnect the continuous workstring from the anchor. This may allow the continuous workstring to be electrically disconnected from the anchor, for example in the case of a stuck pipe event.
  • the apparatus can comprise one or more channels for receiving fluid from the continuous work string connected to the connector and conveying the fluid towards the distal end of the drillstring.
  • the apparatus can comprise one or more connectors for connecting the apparatus to a drilling fluid supply conduit.
  • the drilling fluid supply conduit may be within the continuous work string, receiving fluid from the continuous work string connected to the connector.
  • the fluid channels may convey the fluid towards the distal end of the drillstring.
  • fluid such as drilling fluid may be supplied to the bottom of the borehole from tanks at the surface.
  • the anchor and/or other components in the BHA may comprise one or more devices for measuring one or more of torque, radial force, axial force and pressure.
  • the measurement devices may comprise sensors, such as torque sensors, pressure sensors and axial force sensors, such as strain gauges.
  • the devices may also measure other parameters which may be used to infer the value of torque, radial force, axial force and/or pressure.
  • the devices may comprise mechanical or hydromechanical mechanisms that are configured to change state or move in response to variations in parameters such as torque, weight and pressure. That change or state or movement may be used to control or provide feedback to control the operation of the anchor. This may also allow these parameters to be measured downhole and then used to control the operation of the anchor or other components of the BHA, such as the steering device 112.
  • the data may also be used to control the operation of the anchor, for example to control the operation of the gripper(s) or to control the axial force applied to the BHA, the drill bit or the continuous work string.
  • the anchor may comprise a control unit.
  • An example of a control unit 700 and some of its associated components are shown in more detail in FIG. 7.
  • the control unit may comprise a processor 701 and a memory 702.
  • the processor may execute computer code stored at the memory to perform the functions described herein.
  • the processor is shown as a single component. In other examples, the operations of the processor may be performed by multiple processing elements, which may be at different locations.
  • the control unit may control the anchor (for example, the configuration of one or more grippers of the anchor to control the force exerted against the borehole or on the BHA by the one or more grippers) based on control signals received from the surface via the continuous work string (for example, via E-line within the string) and the electrical connector, or via RFID tags or via modulation of flow/pressure of the drilling fluid
  • the control unit may be at surface and connected to analogue circuitry within the anchor, for example via E-line.
  • the control unit may also 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.
  • 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
  • the control unit may also comprise a transceiver 703 for sending and receiving signals to and/or from other entities, such as sensors communicatively connected to the anchor.
  • the control unit can control multiple anchoring modules and can allow for standalone operation (i.e. with no connection of the control unit to surface).
  • the anchor control unit may also interface with an MWD module in the drillstring (for example to allow realtime feedback to an operator at the surface), and/or with E-line and/or wired drill pipe (for realtime two-way communications with the surface).
  • control unit 700 comprises one or more sensors 704.
  • the sensor(s) 704 may comprise, or the control unit 700 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 700 may also be connectable to other components of the BHA.
  • the BHA may comprise a steering device 112, such as an orienter or an RSS.
  • the use of a downhole control unit 700 can also allow high-speed well directional data to be transmitted to the steering device by sending control signals from downhole control unit 700.
  • the processor 701 of the control unit 700 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 700 comprising a processor 701 and memory 702 into the apparatus may also enable event and diagnostic analysis, as well as closed-loop control of the anchor downhole.
  • the control unit may be located at the surface, or elsewhere on the BHA.
  • the BHA may comprise a steering device 112 such as an orienter or an RSS.
  • a steering device 112 such as an orienter or an RSS.
  • the use of a continuous work string electrically connected to the surface can allow highspeed well directional data to be transmitted to a surface controller and used to control of the steering device by sending control signals from the surface controller to the steering device via the electrical connection to the surface.
  • the control unit of the anchor may be configured to vary the axial push/pull force applied to components proximal or distal of the anchor (for example, to the continuous work string to push or pull it down the borehole or to the BHA or bit, for example to apply WOB) to optimize the drilling process and reduce drilling dysfunction by reducing stick slip by reacting torsional loads to the borehole.
  • the controller may vary the applied axial force based on control signals received from the surface at the electrical connector via the continuous work string or other means (for example, RFID or drilling fluid flow/pressure).
  • the controller may vary the force based on axial or torsional loads measured at the anchor.
  • the controller may control the anchor and/or other components in the BHA based on closed loop feedback from downhole sensors or surface metrics to optimize the drilling process.
  • the connector is configured to connect the apparatus to multiple continuous work strings.
  • there may be two, three or more than three strings for example, coiled tubing strings
  • the connector may connect the strings to the coupling.
  • multiple continuous work strings such as multiple coiled tubing strings may allow for improved flow rates downhole, which may improve the drilling speed by assisting with cutter transport and/or hole cleaning.
  • the use of the anchor with multiple strings may prevent damaging torsional vibrations from being transmitted to the strings, which may prevent the strings from becoming twisted and compressed, affecting the flow rates of media being transported downhole within them.
  • the anchor may also be used to assist with the deployment of the multiple strings into the borehole, which may be more difficult than the deployment of a single string, by applying axial force to the connector to pull the strings down the borehole.
  • Figure 8 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.
  • the method comprises deploying a continuous work string into the borehole, the continuous workstring being connected to an apparatus comprising a downhole anchor having a gripping element for engaging the borehole to control relative movement and load transfer between the anchor and the borehole, the continuous work string terminating proximally of the anchor.
  • the method comprises sending signals from the surface of the borehole to the apparatus (for example, to the connector and/or to the anchor). The signals may, for example, be sent via the continuous work string or alternatively via the formation.
  • the method comprises controlling the configuration of the anchor based on the received signals.
  • the drillstring terminates in a distal tool, such as a drill bit.
  • the anchor is communicatively connectable with a processor that may be programmed to execute a predetermined control strategy.
  • 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.
  • the drillstring may comprise, for example, conventional drill pipe or coiled tubing.
  • the control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool (for example, a distal end face of the distal tool, for example where the distal end face accommodates one or more cutting elements) and the bottom of the borehole.
  • the control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole as the distal tool is being operated to advance the borehole.
  • the control strategy may control the apparatus to apply longitudinal force to the distal tool to maintain engagement between the distal tool and the borehole for more than a predetermined time period (for example, more than 30 seconds, more than 1 minute, more than 10 minutes, or more than 30 minutes).
  • 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 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.
  • downhole parameter measurements such as downhole pressure, WOB and/or torque
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the processor is programmed to execute a control strategy for controlling the apparatus.
  • 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 704) or may be other downhole sensors local to the apparatus and/or communicatively connected to the control unit 700.
  • 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 I 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.
  • 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.
  • 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.
  • the ability to control longitudinal force in response to differential pressure 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.
  • the anchor may comprise 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.
  • the downhole apparatus may operate according to multiple control modes.
  • 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.
  • the drilling fluid may provide the longitudinal force applied to the drillstring.
  • 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.
  • 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.
  • the drillstring may comprise a continuous workstring, such as coiled tubing, an umbilical or composite pipe.
  • the coiled tubing may be connected to the anchor by a connector, as shown in FIG. 6.
  • the drillstring may also be any other pipe, hose or transfer line for deploying drilling equipment and the features described herein may also apply to drillstrings having other forms.
  • the coiled tubing extends from the surface of the borehole.
  • the coiled tubing is attached to a coiled tubing connector coupled to the anchor by a rotatable coupling.
  • 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.
  • the rotatable coupling of the connector described above 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.
  • 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.
  • 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 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.
  • 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.
  • Phenomena such as drillstring buckling
  • 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).
  • 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.
  • 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.
  • 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.
  • Implementations of the system described herein can operate as an autonomous reeled system for drilling, milling, completions or other operations. By connecting the anchor with a continuous work string, this may allow a BHA to be deployed in the borehole quickly and with improved control and supply of downhole power.
  • a connection via the work string to the connector proximal of the anchor can allow for full kinematics control of processes downhole, for example to eliminate drilling dysfunctions (such as stick slip) and minimizes the need for heavy drilling BHAs that typically limit the use of continuous work strings such as coiled tubing.
  • the anchor can advantageously isolate the drilling assembly and react torque to the formation, as well as applying axial (push/pul I) forces to the work string, BHA and drill bit.
  • High tripping speeds can mitigate cost of failure or premature wear of current off- the-rack technologies.
  • High fidelity and reliable real-time formation evaluation and drilling mechanics data can minimize drilling risk and allow for real-time closed loop control of parameters and drilling kinematics downhole. Improved well control and reduced chance of stuck pipe may result due to more reliable bottom hole pressure control and continuous circulation even while tripping. It may also allow significant simplification of the anchor power and control systems.
  • Drilling speeds can reduce operational costs and allow deep drilling to be commercially viable. Drilling speeds may also be further improved due to not needing to stop to make drill pipe connections and this can reduce the personnel required on the rig floor and at the location in general.
  • the application of axial forces at the anchor may also allow the anchor to be used as a tractor for completions and intervention operations. Allowing a continuous work string, such as coiled tubing, to remain in tension may significantly increase the drillable footage. This may also help to avoid buckling, which may occur in typical coiled tubing applications.
  • the system can also allow for the application of additional WOB that ordinarily may not be able to be transferred to the bit using a continuous work string such as coiled tubing due to buckling of the tubing.
  • the continuous work string may be insulated. Insulation of the continuous work string (such as by using insulating coiled tubing) may allow for an even larger temperature differential at the bottom of the borehole.
  • the described approach may also be performed to utilize hybrid rigs which can allow the top hole section to be drilled conventionally and then coiled tubing (or another continuous work string) to be used for the deeper/production sections of the borehole.
  • the distance that can be drilled may be extended further by splicing multiple continuous strings together.
  • the continuous work string may be used as one conduit for the supply of power to downhole tools to minimize the size of the E-line.
  • measurement devices such as sensors in the BHA, for example at the anchor or in an MWD tool, to measure parameters such as torque, position and axial force
  • increased measurement density can allow more precise well placement and formation characterization.
  • 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 system may also allow for improved well control, as the continuous work string may be equipped with surface pressure controls that mean it can be used as a primary barrier and bottom hole pressure can be maintained more reliably than using weighted drilling fluid.

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Abstract

L'invention concerne un appareil destiné à être utilisé dans un trou de forage (107), l'appareil comprenant un ancrage de fond de trou (113) ayant un élément de préhension (211) pour venir en prise avec le trou de forage pour commander un mouvement relatif et un transfert de charge entre l'ancrage (113) et le trou de forage et un connecteur (115) pour connecter l'appareil (107) à une chaîne de travail continue (102) se terminant de manière proximale par rapport à l'ancrage (113), le connecteur étant (115) configuré pour faciliter le transfert de signaux entre l'ancrage (113) et la surface du puits de forage.
PCT/EP2024/080340 2023-10-25 2024-10-25 Appareil de fond de trou destiné à être utilisé avec une colonne de travail continue Pending WO2025088194A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
PCT/EP2025/055722 WO2025181402A1 (fr) 2024-03-01 2025-03-03 Appareil de fond de trou destiné à être utilisé dans un trou de forage

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
GB2316351.2A GB2636344A (en) 2023-10-25 2023-10-25 Downhole apparatus for use with a continuous work string
GB2316351.2 2023-10-25
US202463560158P 2024-03-01 2024-03-01
US63/560,158 2024-03-01
GB2405172.4A GB2638791A (en) 2024-03-01 2024-04-11 Downhole apparatus for use in a borehole
GB2405172.4 2024-04-11

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WO2025088194A1 true WO2025088194A1 (fr) 2025-05-01

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WO (1) WO2025088194A1 (fr)

Citations (4)

* Cited by examiner, † Cited by third party
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US20040055788A1 (en) * 2001-01-10 2004-03-25 Bruno Best Device for anchoring a drill string in a borehole
US6857486B2 (en) * 2001-08-19 2005-02-22 Smart Drilling And Completion, Inc. High power umbilicals for subterranean electric drilling machines and remotely operated vehicles
US11713665B2 (en) * 2019-05-08 2023-08-01 General Downhole Tools, Ltd. Systems, methods, and devices for directionally drilling an oil well while rotating including remotely controlling drilling equipment
WO2023152404A1 (fr) * 2022-02-14 2023-08-17 Ga Drilling, A.S. Ancrage d'une garniture de forage

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20040055788A1 (en) * 2001-01-10 2004-03-25 Bruno Best Device for anchoring a drill string in a borehole
US6857486B2 (en) * 2001-08-19 2005-02-22 Smart Drilling And Completion, Inc. High power umbilicals for subterranean electric drilling machines and remotely operated vehicles
US11713665B2 (en) * 2019-05-08 2023-08-01 General Downhole Tools, Ltd. Systems, methods, and devices for directionally drilling an oil well while rotating including remotely controlling drilling equipment
WO2023152404A1 (fr) * 2022-02-14 2023-08-17 Ga Drilling, A.S. Ancrage d'une garniture de forage

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