Directional drilling apparatus and methods

This application claims priority from U.S. Application No. 61/843,356 filed 6 Jul. 2013. For purposes of the United States, this application claims the benefit under 35 U.S.C. § 119 of U.S. Application No. 61/843,356 filed 6 Jul. 2013 and entitled DIRECTIONAL DRILLING APPARATUS AND METHODS which is hereby incorporated herein by reference for all purposes.

This application relates to subsurface drilling, specifically to directional drilling. Embodiments are applicable to but not limited to drilling wells for recovering hydrocarbons.

Recovering hydrocarbons from subterranean zones typically involves drilling wellbores.

Wellbores are made using surface-located drilling equipment which drives a drill string that eventually extends from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. Drilling fluid, usually in the form of a drilling “mud”, is typically pumped through the drill string. The drilling fluid cools and lubricates the drill bit and also carries cuttings back to the surface. Drilling fluid may also be used to help control bottom hole pressure to inhibit hydrocarbon influx from the formation into the wellbore and potential blow out at surface.

In some circumstances it is desirable to cause a drill bore to follow a trajectory that may include changes in direction. For example, it may be desirable to drill straight down to a desired depth and then cause the drill bore to turn so that the drill bore extends horizontally in a desired direction. Various directional drilling technologies have been developed to allow a rotary drill to be steered so as to cause a wellbore to follow a desired path. Rotary steerable technologies fall into two broad categories which can be described as “push-the-bit” and “point-the-bit”. Push-the-bit systems steer a drill bit by applying a side load that forces the bit laterally in a desired direction. The most common push-the-bit tools use pads on the outside of the tool which press against the well bore thereby causing the bit to drill more toward the opposite side causing a direction change. Point-the-bit systems steer the bit by tilting the bit in the direction of the desired curve. Point-the-bit systems generally include a bent section in the drillstring near the bit and a mud motor to drive the bit so that drilling can proceed without rotating the entire drill string. The bend points the bit in a direction different from the axis of the wellbore. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a desired wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore.

RSS (Rotary steerable system) is another directional drilling technology. RSS tools allow steering while the drill string is rotating. Some RSS tools provide pads that can rotate relative to the drill string and are operable to steer the bit.

Bottom hole assembly (BHA) is the name given to the equipment at the terminal end of a drill string. In addition to a drill bit, a BHA may comprise elements such as: apparatus for steering the direction of the drilling (e.g. a steerable downhole mud motor or rotary steerable system); sensors for measuring properties of the surrounding geological formations (e.g. sensors for use in well logging); sensors for measuring downhole conditions as drilling progresses; one or more systems for telemetry of data to the surface; stabilizers; heavy weight drill collars; pulsers; and the like. The BHA is typically advanced into the wellbore by a string of metallic tubulars (drill pipe).

Electronics in a BHA may provide any of a wide range of functions including, without limitation: data acquisition; measuring properties of the surrounding geological formations (e.g. well logging); measuring downhole conditions as drilling progresses; controlling downhole equipment; monitoring status of downhole equipment; directional drilling applications; measuring while drilling (MWD) applications; logging while drilling (LWD) applications; measuring properties of downhole fluids; and the like. A BHA may include various sensors (e.g. sensors for use in well logging) that may include one or more of vibration sensors, magnetometers, inclinometers, accelerometers, nuclear particle detectors, electromagnetic detectors, acoustic detectors, and others; acquiring images; measuring fluid flow; determining directions; emitting signals, particles or fields for detection by other devices; interfacing to other downhole equipment; sampling downhole fluids; etc.

Downhole sensors may detect the direction and angle of inclination of the drill string near the drill bit. Data from such sensors may be used in directional drilling applications to help guide the borehole to follow a desired trajectory.

A downhole probe may communicate a wide range of information to the surface by telemetry. Telemetry information can be invaluable for efficient drilling operations. For example, telemetry information may be used by a drill rig crew to make decisions about controlling and steering the drill bit to optimize the drilling speed and trajectory based on numerous factors, including legal boundaries, locations of existing wells, formation properties, hydrocarbon size and location, etc. A crew may make intentional deviations from the planned path as necessary based on information gathered from downhole sensors and transmitted to the surface by telemetry during the drilling process. The ability to obtain and transmit reliable data from downhole locations allows for relatively more economical and more efficient drilling operations.

One or more systems may be provided for telemetry of data to the surface. Data telemetry techniques include transmitting information by generating vibrations in fluid in the bore hole (e.g. acoustic telemetry or mud pulse (MP) telemetry) and transmitting information by way of electromagnetic signals that propagate at least in part through the earth (EM telemetry). Other telemetry techniques use hardwired drill pipe, fibre optic cable, or drill collar acoustic telemetry to carry data to the surface.

Some patent references in the general field of the invention include: U.S. Pat. Nos. 5,738,178; 5,617,926; 6,092,610; 6,129,160; 7,549,467; 7,987,927; 8,322,461; GB2456421; CA2395082; CA2642713; and CA2647032.

There remains a need for alternative methods for directional drilling.

This invention has a number of aspects. These include methods for directional drilling and various apparatus for directional drilling. One aspect provides an apparatus for directional drilling. The apparatus comprises a bent section, a clutch connected at an uphole end of the bent section and an orientation sensor mounted to monitor an orientation of the bent section. A controller is configured to compare the monitored orientation of the bent section to a desired orientation and to control the clutch to apply a correction to the orientation of the bent section. In some embodiments the uphole end of the bent section is coupled to an output shaft of a first reducing transmission and the clutch is connected in series with the reducing transmission.

In some embodiments the output shaft of the first reducing transmission is coupled to the uphole end of the bent section and the clutch is connected to an input shaft of the transmission. The first reducing transmission may have a through hole in fluid communication with a bore of the bent section. The first reducing transmission may, for example, comprise a harmonic drive™ (i.e. a strain wave gear drive).

Some embodiments have an anti-rotation apparatus attached to a body of the first reducing transmission. In an example embodiment the anti-rotation apparatus comprises an actuator configured to press one or more pads radially outwardly against a borehole wall.

Some embodiments include a second reducing transmission having an output shaft coupled to a downhole end of the bent section. The second reducing transmission may, for example, comprise a harmonic drive™ (i.e. a strain wave gear drive). A second clutch may be connected in series with the second reducing transmission. A controller may be connected to control the first and second clutches to maintain a desired average orientation of the bent section. The controller may, for example, be configured to alternate between a first period of engaging the first clutch while disengaging the second clutch and a second period of engaging the second clutch while disengaging the first clutch. The controller may be configured to correct an average orientation of the bent section by altering the duration of one or both of the first and second periods in one or more cycles.

In some embodiments the controller is configured to adjust a range of oscillation of the bent section in response to a measurement of a diameter of the borehole. For example, the range of oscillation of the bent section may be increased in response to a determination that a diameter of the borehole is decreased. The range of oscillation may be controlled automatically or in response to signals from a human operator or supervisory system that may, for example, be located at the surface.

In some embodiments the apparatus includes an actuator configured to press one or more pads radially outwardly to engage a wall of the borehole and the controller is configured to adjust the range of oscillation of the bent section in response to a configuration of the one or more pads when pressed against the wall of the borehole.

Another aspect provides apparatus for directional drilling. The apparatus comprises: a bent section; a first clutch connected at an uphole end of the bent section; a first reducing transmission; an orientation sensor mounted to monitor an orientation of the bent section; and a controller configured to compare the monitored orientation of the bent section and to control the first clutch to apply a correction to the orientation of the bent section. The uphole end of the bent section is coupled to an output shaft of the first reducing transmission and the first clutch is connected in series with the first reducing transmission.

Another aspect provides apparatus for directional drilling. The apparatus comprises a section of the drill string to be oriented, for example a bent section having uphole and downhole ends. The uphole end of the bent section is coupled by a first clutch to a section of drill string uphole from the bent section. The downhole end of the bent section coupled by way of a second clutch to a drill bit downhole from the bent section. The apparatus includes an orientation sensor mounted to monitor an orientation of the bent section and a controller configured to compare the monitored orientation of the bent section to a desired orientation and to control the first and second clutches to maintain the orientation of the bent section within a desired range of the desired orientation. In some embodiments the controller is configured to alternate between a first period of engaging the first clutch while disengaging the second clutch and a second period of engaging the second clutch while disengaging the first clutch. In some embodiments the controller is configured to set a default length for the first period by engaging the first clutch while disengaging the second clutch and monitoring a rate of rotation of the bent section. In some embodiments the controller is configured to correct an average orientation of the bent section by altering the duration of one or both of the first and second periods in one or more cycles. In addition to maintaining an average orientation of the section, a range of angular oscillation of the section may be varied to compensate for wear of the drill bit and/or adjust diameter of the borehole.

Other aspects of the invention provide methods for directional drilling as described herein. One such aspect provides a method for controlling an orientation of a section in a drill string that comprises while rotating an uphole portion of the drill string uphole from the section: performing a first step of engaging a first clutch to couple the section to be rotated by the uphole portion of the drill string, thereby causing orientation of the section to change in a first direction; and performing a second step of disengaging the first clutch to allow the section to rotate relative to the uphole portion of the drill string while engaging a second clutch to more tightly couple the section to a rotating drill bit, thereby causing the orientation of the section to change in a second direction opposed to the first direction. In some embodiments the first and second steps are repeated in alternation.

Another example aspect provides a method for controlling the orientation of a bent section or other component of a directional drilling string. The method comprises detecting a current orientation of the bent section; comparing the current orientation to a desired orientation; engaging a first clutch coupled between the bent section and a rotating section of the drill string uphole from the bent section and disengaging a second clutch coupled between the bent section and a rotating section of the drill string downhole from the bent section if the orientation of the bent section is more than a first threshold amount away from the desired orientation in a first direction; and engaging the second clutch and disengaging the first clutch if the orientation of the bent section is more than a second threshold amount away from the desired orientation in a second direction opposite to the first direction.

Further aspects of the invention and features of example embodiments are illustrated in the accompanying drawings and/or described in the following description.

The accompanying drawings illustrate non-limiting example embodiments of the invention.

FIG. 1 is a schematic view of a drilling operation.

FIG. 2 is a schematic illustration showing drilling apparatus according to some example embodiments.

FIG. 2A is a schematic detail showing an angle control mechanism.

FIG. 3 is a schematic illustration showing apparatus according to some embodiments.

FIG. 3A is a schematic illustration showing apparatus like that of FIG. 3 with components of a control mechanism shown schematically.

FIG. 4 is a block diagram showing a control system according to some embodiments.

FIG. 5 is a flow chart showing a method according to some embodiments.

Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the technology is not intended to be exhaustive or to limit the system to the precise forms of any example embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.

FIG. 1 shows schematically an example drilling operation. A drill rig 10 drives a drill string 12 which includes sections of drill pipe that extend to a drill bit 14 . The illustrated drill rig 10 includes a derrick 10 A, a rig floor 10 B and draw works 10 C for supporting the drill string. Drill bit 14 is larger in diameter than the drill string above the drill bit. An annular region 15 surrounding the drill string is typically filled with drilling fluid. The drilling fluid is pumped through a bore in the drill string to the drill bit and returns to the surface through annular region 15 carrying cuttings from the drilling operation. As the well is drilled, a casing 16 may be made in the well bore. A blow out preventer 17 is supported at a top end of the casing. The drill rig illustrated in FIG. 1 is an example only. The methods and apparatus described herein are not specific to any particular type of drill rig.

FIG. 2 shows drilling apparatus 20 according to an example embodiment. Apparatus 20 comprises a drill string 12 and a drill bit 14 . Drill bit 14 is connected to a mud motor 22 that can be operated to rotate drill bit 14 (whether or not drill string 12 is being rotated). Located in the drill string, preferably near to drill bit 14 is a bent section 24 . Bent section 24 may, for example, comprise a bent sub having suitable uphole and downhole couplings mounted at angles to one another. As seen in FIG. 2 , a longitudinal centerline of a section of drill string uphole from bent section 24 forms an angle θ with a longitudinal centerline of the apparatus downhole from bent section 24 .

Bent section 24 is located downhole from a rotary coupling 25 such that bent section 24 can turn relative to an uphole part 12 A of drill string 12 about rotary coupling 25 . Apparatus 20 comprises a control mechanism 26 that controls rotation of the sides of rotary coupling 25 relative to one another.

By operating control mechanism 26 to control rotation at rotary coupling 25 , bent section 24 may be maintained in a desired orientation (to provide a desired curve of the borehole being drilled) while upper part 12 A of drill string 12 is rotated. Rotating uphole section 12 A of drillstring 12 while drilling can be advantageous because rotating the drillstring can reduce friction between the drillstring and the well bore. Friction between the drillstring and the wellbore can reduce the force applied to the drill bit. This, in turn, can reduce penetration rate. Turning upper part 12 A while drilling can reduce friction and, therefore, increase penetration rate. Another benefit of rotating uphole section 12 A of drillstring 12 is that rotation of the drill string can help keep drill cuttings suspended in the drilling fluid so they can be lifted to the surface more effectively.

Control mechanism 26 does not need to drive rotation of rotary coupling 25 . In some embodiments uphole section 12 A and downhole section 12 B of drillstring 12 are driven to rotate in opposite directions. Control mechanism 26 may comprise a clutch that varies the torque transmitted across rotary coupling 25 .

Consider the following example. Uphole section 12 A is driven to rotate clockwise (as viewed looking down from the surface) by a drill rig. Mud motor 22 is operated to drive drill bit 14 to rotate clockwise. The reaction torque from driving bit 14 is transmitted to downhole section 12 B and tends to make downhole section 12 B (together with bent section 24 which is part of downhole section 12 B in this example) rotate counterclockwise. The material of the drillstring is elastic and acts as a torsional spring. The reaction torque from drilling is able to ‘wrap’ or twist the drillstring.

As shown in FIG. 2A , control mechanism 26 includes a clutch 26 A that can be controlled to vary the torque transmitted across rotary coupling 25 . If clutch 26 A is disengaged (no torque transfer), uphole section 12 A will rotate clockwise and downhole section 12 B will rotate counterclockwise as a result of the reaction force from drilling rotary coupling 25 will freely swivel. If clutch 26 A is fully engaged without slipping then uphole section 12 A will rotate clockwise and downhole section 12 B, being locked to uphole section 12 A, will also rotate clockwise.

Clutch 26 A may be set in between being fully engaged and fully disengaged so that clutch 26 A transmits just enough torque to counteract the reaction force from drilling that would otherwise drive rotation of lower section 12 B. With this setting of clutch 26 A, the orientation of bent section 24 remains fixed.

The orientation of bent section 24 may be altered by momentarily increasing or decreasing the torque transmitted through clutch 26 A relative to the ‘balance point’ at which bent section 24 is not being rotated. By slightly increasing the torque transmitted by clutch 26 A, bent section 24 may be made to rotate slowly clockwise. By slightly decreasing the torque transmitted by clutch 26 A, bent section 24 may be made to rotate slowly counterclockwise.

Control mechanism 26 may include an orientation sensor for determining the orientation of bent section 24 . The orientation sensor may, for example, comprise one or more sensors such as an inclinometer, a magnetic field sensor (e.g. a compass), a gyroscope (e.g. a laser gyro) or the like. Sensors are indicated generally by 27 . An output of the sensors is provided to an electronic control unit 28 . Control unit 28 determines from the sensor output(s) a change in the orientation of bent section 24 and/or a deviation in the orientation of bent section 24 from a desired orientation. In response to the signals, control unit 28 controls actuation of clutch 26 A to maintain the desired orientation of bent section 24 .

Control unit 28 may comprise, for example, one or more data processors such as microprocessors, embedded processors, digital signal processors or the like configured to receive data (including information about the orientation of bent section 24 ) and/or commands and to control the operation of control mechanism 26 based on those inputs. Where control unit 28 includes a data processor, control unit 28 may also comprise software that configures the data processor to operate control mechanism 26 as described herein. In addition or in the alternative, control unit 28 may comprise custom digital and/or analog circuits configured to perform functions that collectively operate control mechanism 26 .

Control unit 28 may comprise or be connected to receive data from a telemetry system 31 configured for receiving downlink telemetry commands. Such commands may, for example, be provided from a control station at the surface. The commands may, for example, command changes in the orientation of bent section 24 .

Control unit 28 may operate, for example, by frequently determining from the readings of sensors 27 whether the orientation of bent section 24 should be changed and, if so, in what direction. In response, control unit 28 may change the signal actuating clutch 26 A to alter the orientation of bent section 24 . For example, control unit 28 may actuate clutch 26 A to briefly increase the torque transmitted by clutch 26 A in order to shift the orientation of bent section 24 clockwise or to briefly decrease the torque transmitted by clutch 26 A in order to shift the orientation of bent sub 24 counterclockwise.

Control unit 28 may also act to control the actuation of clutch 26 A to find the ‘balance point’ at which there is no change in the orientation of bent section 24 . For example, control unit 28 may monitor to determine a direction of drift (clockwise or counterclockwise) of the orientation of bent section 24 . In response to detecting a clockwise drift, control unit 28 may incrementally reduce the torque transmitted by clutch 26 A. In response to detecting a counterclockwise drift, control unit 28 may incrementally increase the torque transmitted by clutch 26 A.

Apparatus 20 may optionally include a mechanism 21 for holding the orientation of bent section 24 . Holding mechanism 21 may, for example, comprise one or more hydraulically actuated pads coupled to bent section 24 . The pads may be extended outwardly to engage a wall of the wellbore. Control unit 28 may operate the holding mechanism 21 to inhibit rotation of bent section 24 when bent section 24 is oriented at the desired orientation.

The relative rotation of the different sides of rotary coupling 25 may be used to generate electrical power. FIG. 2A shows an electrical generator 29 connected across rotary coupling 25 . Electricity produced by electrical generator 29 may be applied to drive control unit 28 and clutch 26 A, charge batteries for powering downhole systems or the like.

Apparatus 20 has the advantage of conceptual simplicity. However, the design of apparatus 20 requires clutch 26 A to be slipping all or most of the time. This can place significant demands on the design of clutch 26 A and the control system provided by control unit 28 . In some embodiments, clutch 26 A consists of or comprises a variable torque converter. In some such embodiments provision is made to lock the torque converter to allow transfer of torque from uphole drillstring section 12 A to bent section 24 without slippage.

FIG. 3 shows apparatus 30 according to an alternative embodiment. FIG. 3A illustrates schematically a possible control mechanism for apparatus 30 . Apparatus 30 may be operated according to a principle similar to apparatus 20 . Apparatus 30 comprises speed reducing transmissions 32 A and 32 B (collectively or generally transmissions 32 ) located on uphole and downhole sides of bent section 24 respectively. Each transmission 32 may, for example, comprise a suitable planetary transmission, harmonic drive, geared transmission or the like. A controllable clutch is provided in series with each transmission 32 . In the illustrated embodiment, clutch 27 A is provided in series with transmission 32 A and clutch 27 B is provided in series with transmission 32 B. In some embodiments, a variable torque converter is connected in series with one or both of clutches 27 A and 27 B. In some embodiments, one or both of clutches 27 A and 27 B comprises a torque converter which may transmit torque at a level controlled by a controller.

Transmissions 32 are configured to provide through passages for drilling fluid. Such passages may extend, for example through the transmission output shaft that may extend all of the way through the transmission 32 .

Transmission 32 A has an input shaft coupled to uphole section 12 A of drill string 12 and an output shaft coupled to bent section 24 . Transmission 32 B has an input shaft coupled to downhole section 12 B of drill string 12 and an output shaft coupled to bent section 24 .

Each of transmissions 32 comprises a transmission body 33 and a mechanism 34 to hold transmission body 33 against rotation. In the illustrated embodiment, each transmission 32 is associated with one or more hydraulically-operated pads that can be urged outwardly to engage walls of the wellbore. Radially outward ends of the pads are equipped with shoes 35 A and 35 B (generally and collectively shoes 35 ). Shoes 35 are shaped to resist rotation in the wellbore but to slide along the wellbore as drilling progresses. Mechanism 34 A carrying shoes 35 A is provided for transmission 32 A. Mechanism 34 B carrying shoes 35 B is provided for transmission 32 B.

Transmission 32 A is a step-down transmission such that a speed of rotation at the input shaft coupled to uphole section 12 A is faster than a speed of rotation at an output coupled to bent section 24 .

Transmission 32 A may have a gear ratio sufficient to slow the rotation of its output relative to a typical rotation rate of uphole section 12 A to a speed of a few revolutions per minute (RPM) or less. For example, if uphole section 12 A is normally driven at a speed of 50 RPM then transmission 32 A could, for example, have a ratio of 50:1 such that its output which is connected to bent section 24 rotates at a speed of about 1 RPM. In some embodiments the gear ratio of transmission 32 A is in the range of 20:1 to 200:1.

Transmission 32 B is also a step down transmission. Transmission 32 B may have a gear ratio sufficient to slow the rotation of its output relative to a typical rotation rate of downhole section 12 B also to a speed of a few RPM or less. For example, if downhole section 12 B can be driven at a speed of up to 300 RPM by reaction forces from operating drill 14 then transmission 32 B could, for example, have a ratio of 300:1 such that its output rotates at a speed of about 1 RPM when its input (coupled to downhole section 12 B) is driven at 300 RPM. In some embodiments, transmission 32 B has a higher ratio than transmission 32 A. In some embodiments, transmission 32 B has a ratio in the range of 50:1 to 400:1.

It is not necessary that transmissions 32 have ratios such that the rotational speeds of the outputs of transmissions 32 A and 32 B be matched since downhole section 12 B is not positively locked to the formation into which drill 14 is drilling.

In this example embodiment, when clutches 27 A and 27 B are both engaged, uphole section 12 A may be turned clockwise from the surface at, for example, 50 RPM, downhole section 12 B may be turned counterclockwise by the reaction to the torque applied to turn drill bit 14 at, for example, 200 RPM and bent section 24 may rotate, for example, at 1 RPM in either direction (the direction of rotation of bent section 24 depends on the construction of transmissions 32 ).

Bent section 24 may be maintained at a desired orientation by controlling clutches 27 A and 27 B. In some embodiments another clutch or brake 27 C is provided. Clutch or brake 27 C can be actuated to fix the orientation of bent section 24 relative to downhole portion 12 B.

Various modes of operation are possible. Apparatus according to different embodiments may be configured to enable one or more such modes of operation. In some embodiments the apparatus comprises a control unit like control unit 28 described above and the configuration is provided by suitable software instructions and/or configured analog and/or digital circuits that cause the control unit to operate apparatus 30 as described herein. In one example mode of operation, when bent section 24 is oriented in the desired direction (to within a suitable tolerance) clutch 27 A may be disengaged such that it serves as a rotary coupling (or more generally allows uphole drillstring section 12 A to rotate relatively freely relative to bent section 24 ). In this configuration, little or no torque is transferred from uphole section 12 A of drill string 12 to bent section 24 . In this configuration, pressure on pads 35 A may be relaxed somewhat. At the same time, clutch 27 B may be disengaged and a separate clutch 27 C (see FIG. 3A ) may be engaged to fix the relative orientation of downhole section 12 B and bent section 24 such that torque is delivered to drill bit 14 . Pads 35 B may be engaged to hold the orientation of bent section 24 .

If the orientation of bent section 24 shifts from the desired orientation (and/or if the desired orientation of bent section 24 is changed) then clutches 27 A, 27 B and the separate clutch 27 C may be operated to change the orientation of bent section 24 . For example, clutch 27 A may be engaged for a time sufficient to rotate bent section 24 clockwise by a desired amount (note that any desired orientation of bent section 24 may be achieved by rotating bent section 24 far enough clockwise). It is also possible to rotate bent section 24 counterclockwise to a desired orientation by disengaging clutch 27 C, engaging clutch 27 B, and reducing the pressure on pads 35 B.

Another mode of operation requires only two clutches. In this alternative mode of operation a separate clutch is not required. One of clutches 27 A and 27 B may be engaged while the other one of clutches 27 A and 27 B is disengaged. Pressure on the pads 35 corresponding to the disengaged clutch may be reduced. In this mode of operation, bent section 24 may always be rotating in one direction or another. However, because of transmissions 32 , bent section 24 rotates only relatively slowly. The direction of rotation of bent section 24 can be reversed by changing which one of clutches 27 A and 27 B is engaged. Therefore, the orientation of bent section 24 may be made to oscillate about a desired orientation by engaging clutches 27 A and 27 B in alternation. This mode of operation may be advantageous for reducing friction between drillstring 12 and the walls of the borehole since it permits upper section 12 A of drillstring 12 to be rotating during sliding (e.g. during drilling operations in which the orientation of bent section 24 is kept more or less fixed).

The accuracy with which the orientation of bent section 24 is controlled can depend on how often the direction of rotation of bent section 24 is reversed. For example, if bent section 24 is rotating at 1 RPM alternating between clockwise and counterclockwise rotation then shifting the direction of rotation approximately once every ½ second will result in bent section 24 swinging through an angle of only ±1½ degrees from a desired orientation.

The orientation of bent section 24 may be adjusted by slightly altering the length of time that bent section 24 is allowed to rotate in one direction before the direction of rotation is reversed. For example, the orientation of bent section 24 may be moved clockwise by increasing the length of time that clutch 27 A is engaged relative to the length of time that clutch 27 B is engaged. Where bent section 24 rotates at a speed of 1 RPM, for each ⅙ second that the length of time during which clutch 27 A is engaged in a cycle exceeds or is less than the length of time that clutch 27 B is engaged in the cycle the orientation of bent section 24 is shifted by 1 degree. Thus, over the course of one or more cycles the orientation of bent section 24 may be shifted by any desired amount in either direction.

In some embodiments a degree of oscillation of bent section 24 may be controlled to alter the diameter of the borehole being drilled. Increasing the range of oscillation tends to make the borehole larger while decreasing the range of oscillation tends to make the borehole smaller. In some embodiments, control over the degree of oscillation (e.g. controlling how often the direction of rotation of bent section 24 is reversed) may be used to compensate for wear of drill bit 14 . As drill bit 14 wears, the diameter of the borehole being drilled may be reduced. The range of oscillation of bent section 24 may be increased to compensate at least partially for such wear. In some embodiments the range of oscillation is set according to a parameter value that can be set in response to commands sent from the surface by a suitable telemetry method.

The diameter of the borehole being drilled may be measured in various ways. For example, positions of the borehole wall may be detected using contact or non-contact sensors. In an example embodiment pads 35 A and/or 35 B are used to directly measure the diameter of the borehole. In response to pads 35 A and/or 35 B being compressed inwardly (signifying a reduced borehole diameter) the timing of reversal of motion of bent section 24 may be altered (e.g. by increasing the time between reversals) to provide a wider range of oscillation.

In another example embodiment only clutch 27 A is required. Clutch 27 A may be engaged and pads 35 A engaged to cause bent section 24 to rotate clockwise relatively slowly (compared to the rate of rotation of uphole section 12 A). Clutch 27 A may be periodically disengaged and the pressure on pads 35 A relaxed to allow the reaction torques resulting from the rotation of drill 14 to rotate bent section 24 counterclockwise. By alternating between engaging and disengaging clutch 27 A, bent section 24 may be made to maintain a desired average orientation.

FIG. 4 shows schematically an example control system 40 for the apparatus of FIG. 3 . Control system 40 may, for example, be located between transmissions 32 in drill string 12 . Control system 40 may, for example, be packaged in a housing located within a bore of drillstring 12 and/or within a wall of drillstring 12 .

Control system 40 comprises a controller 42 . Controller 42 may comprise one or more programmable processors configured by software instructions stored in a memory to perform as described herein, logic circuits, configurable logic elements (e.g. field-programmable gate arrays), combinations thereof, custom analog and/or digital circuits or the like. Control system 40 is connected to control clutches 27 A and 27 B and to control pressure on pads 35 A and 35 B by suitable interfaces.

Control system 40 comprises one or more orientation sensors 48 that monitor orientation of bent section 24 . In the illustrated embodiment, sensors 48 comprise an optical gyro 48 A, an inclinometer 48 B, and a magnetic bearing sensor 48 C. Other embodiments may have fewer or more sensors or sensors of other types.

Control system 40 also comprises a telemetry system 46 . Telemetry system 46 is configured to at least receive telemetry signals. The telemetry signals may include commands to set the orientation of bent section 24 to a particular orientation and/or to change the orientation of bent section 24 in a commanded direction by a commanded amount. Control system 40 includes a register or other memory location 49 which stores the current desired orientation of bent section 24 .

FIG. 5 is a flow chart illustrating a method 50 that may be performed by controller 40 . In block 52 A, method 50 receives and stores in register 49 a target orientation for bent section 24 . In block 52 B method 50 sets a first default length of time for clockwise rotations. In block 52 C method 50 sets a second default length of time for counterclockwise rotations.

In some embodiments, block 52 B includes engaging clutch 27 A, disengaging clutch 27 B, measuring a rotation rate of bent section 24 and setting the desired length of time for clockwise rotations based on the measured rotation rate. In some embodiments, block 52 C includes engaging clutch 27 B, disengaging clutch 27 A, operating mud motor 22 , measuring a rotation rate of bent section 24 and setting the desired length of time for counterclockwise rotations based on the measured rotation rate. In some embodiments the default first and second lengths of time determined in blocks 52 B and 52 C are coordinated such that no net shift in the orientation of bent section 24 results from cyclically rotating bent section 24 clockwise (by engaging clutch 27 A and disengaging clutch 27 B) for the first default length of time and rotating bent section counterclockwise (by engaging clutch 27 B and disengaging clutch 27 A) for the second default length of time.

In block 54 controller 40 commences an operating mode in which bent section 24 is controlled to rotate clockwise and rotate counterclockwise in alternating periods. Block 55 monitors the orientation of bent section 24 as indicated by sensor(s) 48 and determines an average orientation of bent section 24 . Block 56 compares the average orientation determined by block 55 to the target orientation obtained in block 52 A. If these are different then block 56 determines a correction to the angle of bent section 24 . Block 57 applies the correction determined in block 56 by temporarily applying adjustments to the lengths of one or both of the clockwise rotation and the counterclockwise rotation periods. In some embodiments the amount(s) by which the clockwise rotation period and the counterclockwise rotation period are adjusted depends on the magnitude of the correction determined by block 56 . In other embodiments one or both of the clockwise rotation period and the counterclockwise rotation period are adjusted by predetermined amount(s) to achieve a clockwise drift or a counterclockwise drift in the orientation of bent section 24 .

In some embodiments, the gear ratio provided by second transmission 32 B is selected such that second transmission 32 B drives bent section 24 to counter-rotate at a speed faster than first transmission 32 A drives bent section 24 to rotate. In such embodiments, the counterclockwise rotation period may be significantly shorter than the clockwise rotation period. This may enhance drilling efficiency.

In the discussion above it has been assumed that when upper section 12 A of drill string is rotated, the rotation is clockwise when viewed from above. While this is conventional, the present technology is not limited to any particular direction of rotation. A system as described herein could operate equally with counterclockwise rotation of upper section 12 A and clockwise rotation of lower section 12 B.

The technology described herein with reference to FIG. 3 can be used where bent section 12 A can be rotated one way by driving its rotation from upper section 12 A and rotated the opposite way by driving its rotation from lower section 12 B.

Various embodiments described herein use clutches The clutches in any of these embodiments may be of a range of types including dry clutches, wet clutches, multi-plate clutches, clutches having flat plates, clutches having cylindrical plates (e.g. clutches constructed with members that move radially inwardly or outwardly to engage a drum or cylinder or the like, torque converters combinations of these and so on). In some embodiments as described above, the clutches may be either applied or not applied and do not necessarily slip when applied. In other embodiments one or more clutches may be of a type that can transmit a controllable torque.

While a number of exemplary aspects and embodiments have been discussed above, those of skill in the art will recognize certain modifications, permutations, additions and sub-combinations thereof. It is therefore intended that the following appended claims and claims hereafter introduced are interpreted to include all such modifications, permutations, additions and sub-combinations as are within their true spirit and scope.

Unless the context clearly requires otherwise, throughout the description and the

“comprise,” “comprising,” and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense; that is to say, in the sense of “including, but not limited to”. “connected,” “coupled,” or any variant thereof, means any connection or coupling, either direct or indirect, between two or more elements; the coupling or connection between the elements can be physical, logical, or a combination thereof. “herein,” “above,” “below,” and words of similar import, when used to describe this specification shall refer to this specification as a whole and not to any particular portions of this specification. “or,” in reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list. the singular forms “a,” “an,” and “the” also include the meaning of any appropriate plural forms.

Words that indicate directions such as “vertical,” “transverse,” “horizontal,” “upward,” “downward,” “forward,” “backward,” “inward,” “outward,” “vertical,” “transverse,” “left,” “right,” “front,” “back,” “top,” “bottom,” “below,” “above,” “under,” “clockwise,” “counterclockwise” and the like, used in this description and any accompanying claims (where present) depend on the specific orientation of the apparatus described and illustrated. The subject matter described herein may assume various alternative orientations. Accordingly, these directional terms are not strictly defined and should not be interpreted narrowly.

Where a component (e.g. a circuit, module, assembly, device, drill string component, drill rig system, etc.) is referred to above, unless otherwise indicated, reference to that component (including a reference to a “means”) should be interpreted as including as equivalents of that component any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally equivalent to the disclosed structure which performs the function in the illustrated exemplary embodiments of the invention.

Specific examples of systems, methods and apparatus have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to systems other than the example systems described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described embodiments that would be apparent to the skilled addressee, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.

It is therefore intended that the following appended claims and claims hereafter introduced are interpreted to include all such modifications, permutations, additions, omissions and sub-combinations as may reasonably be inferred. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.