Apparatus and methods for drilling a wellbore with a rotary steerable system

Abstract

The present disclosure provides an apparatus for use in a wellbore, the apparatus including a non-rotating portion disposed along a drill string. The non-rotating portion has a bore and at least one biasing member engaging an adjacent wall. A rotating portion is disposed in the bore of the non-rotating portion, and a bearing is positioned between the rotating portion and the non-rotating portion. The apparatus further includes a relative rotation sensor generating a signal indicative of rotation of the rotating portion relative to the non-rotating portion, an orientation sensor generating a signal indicative of an orientation of the non-rotating portion relative to a selected frame of reference, and a controller in signal communication with the at least one relative rotation sensor and the at least one orientation sensor. The controller adjusts a force exerted by the at least one biasing element and / or a position of the at least one biasing element in response to the generated signal from the at least one relative rotation sensor and the generated signal from the at least one orientation sensor.

Description

BACKGROUND

[0001] Directional drilling is commonly used in oil and gas exploration and production operations. Directional drilling is commonly achieved using sensor modules and / or steering assemblies for changing the direction of a drill bit. One type of directional drilling assembly involves a so-called "non-rotating sleeve" that includes a device for generating a force against a borehole wall or a device that bends a drive shaft that passes through the non-rotating sleeve. In such applications, the non-rotating sleeve is typically supported by a bearing that allows the sleeve to remain relatively stationary with respect to the formation. The stationary position of the sleeve allows a relatively stationary force to be applied to the borehole wall to create a steering direction. SUMMARY

[0002] In one aspect, an apparatus for use in a wellbore is disclosed. The apparatus can include a drill string configured to drill a wellbore, a non-rotating portion disposed along the drill string and having a bore and at least one biasing member that engages an adjacent wall, a rotating portion disposed in the bore of the non-rotating portion, a bearing between the rotating portion and the non-rotating portion that allows relative rotation between the rotating portion and the non-rotating portion, at least one relative rotation sensor configured to generate a signal indicative of rotation of the rotating portion relative to the non-rotating portion, at least one orientation sensor configured to generate a signal indicative of an orientation of the non-rotating portion relative to a selected frame of reference, and a controller in signal communication with the at least one relative rotation sensor and the at least one orientation sensor. The controller adjusts at least one of (i) a force exerted by the at least one biasing element and (ii) a position of the at least one biasing element in response to the generated signal from the at least one relative rotation sensor and the generated signal from the at least one orientation sensor.

[0003] A related method of using the apparatus includes disposing the apparatus in a formation, changing a frequency of rotation of the rotating portion to send a control signal, determining the control signal using the controller by detecting the change in frequency of rotation using the at least one relative rotation sensor, and controlling the force and / or position of the at least one biasing element using the determined control signal and the generated signal from the at least one orientation sensor.

[0004] In aspects, the present disclosure provides an apparatus for use in a wellbore. The apparatus can include a drill string configured to drill the wellbore, a non-rotating portion disposed along the drill string, the non-rotating portion having a bore and at least one biasing element that engages a wall of the wellbore, a rotating portion disposed in the bore of the non-rotating portion, at least one relative rotation sensor configured to generate a signal indicative of rotation of the rotating portion relative to the non-rotating portion, at least one orientation sensor within the non-rotating portion, the at least one orientation sensor configured to generate a signal indicative of an orientation of the non-rotating portion relative to a selected frame of reference, and a controller. The controller can be in signal communication with the at least one relative rotation sensor and the at least one orientation sensor, the controller configured to adjust at least one of (i) a force exerted by the at least one biasing element and (ii) a position of the at least one biasing element, the adjustment responsive to the generated signal from the at least one relative rotation sensor indicative of rotation of the rotating portion relative to the non-rotating portion and the generated signal from the at least one orientation sensor indicative of an orientation of the non-rotating portion relative to the selected frame of reference.

[0005] In aspects, the present disclosure provides a method of using an apparatus in a wellbore. The method can include disposing a drill string in the wellbore, the drill string configured to drill the wellbore. The drill string can include (i) a non-rotating portion disposed along the drill string, the non-rotating portion having a bore and at least one biasing element configured to engage a wall of the wellbore, (ii) a rotating portion disposed in the bore of the non-rotating portion, (iii) at least one relative rotation sensor configured to generate a signal indicative of relative rotation between the rotating portion and the non-rotating portion, (iv) at least one orientation sensor within the non-rotating portion and configured to generate a signal indicative of an orientation of the non-rotating portion relative to a selected frame of reference, and (v) a controller in signal communication with the at least one relative rotation sensor and the at least one orientation sensor. The method can also include the steps of varying a rotational velocity of the rotating portion to send a control signal, determining the control signal using the controller by detecting a rotational frequency change using the at least one relative rotation sensor, receiving energy from rotation of the rotating portion within the non-rotating portion, and controlling a force and / or position of the at least one biasing element using the determined control signal and the generated signal from the at least one orientation sensor indicative of an orientation of the non-rotating portion relative to the selected frame of reference. BRIEF DESCRIPTION OF DRAWINGS

[0006] The subject matter regarded as the invention is particularly pointed out and distinctly claimed in the concluding portion of the specification taking note that the invention covers what can come to be, both literally and metaphorically, within the scope of the invention. The foregoing and other features and advantages of the invention are apparent from the following detailed description taken in conjunction with the accompanying drawings in which:

[0007] FIG. 1 Embodiments of a drilling and / or measurement system are depicted;

[0008] FIG. 2 Embodiments of a steering assembly for a drilling system are depicted, the steering assembly including a module mounted on a non-rotating sleeve;

[0009] FIG. 3 Embodiments of a steering assembly of FIG. 2 wherein the module is removed from the non-rotating sleeve;

[0010] FIG. 4A and FIG. 4B are perspective views of a module configured to be incorporated in a steering system;

[0011] FIG. 5 are internal views of the module of FIG. 4A and FIG. 4B ;

[0012] FIG. 6 are cross-sectional views of the module of FIG. 4A and FIG. 4B ;

[0013] FIG. 7 Embodiments of a steering assembly for a drilling system are depicted, the steering assembly including a module mounted on a non-rotating sleeve and an energy transmission / reception device;

[0014] FIG. 8 are perspective views of the module of the steering assembly of FIG. 7 ;

[0015] FIG. 9 are close-up views of auxiliary devices in the module of the steering assembly of FIG. 7 , the auxiliary devices configured to receive energy from a rotating portion of the steering assembly rotationally decoupled from the non-rotating sleeve, inside the module in the non-rotating sleeve;

[0016] FIG. 10 are cross-sectional views of the module of the steering assembly of FIG. 9 ;

[0017] FIG. 11 Embodiments of a bottom hole assembly are depicted in functional form, the bottom hole assembly controllable using downhole instructions represented by changes in drill string rotation;

[0018] FIG. 12An implementation scheme for a bottom hole drilling assembly is described in functional form, which can be controlled by downlink commands represented by changes in drill string rotation, and uses multiple independent modules in the non-rotational portion;

[0019] FIG. 13A to FIG. 13D The diagram shows that it can be made by FIG. 11 The unique drill string rotation characteristics for bottom hole drill string assembly detection and decoding;

[0020] FIG. 14 Depicted in schematic form FIG. 11 Implementation plan for bottom hole drilling tool components;

[0021] FIG. 15 A cross-sectional end view of a relative rotation sensor according to one embodiment of the present disclosure is depicted;

[0022] FIG. 16A and FIG. 16B as well as FIG. 17 The diagram illustrates the process of... FIG. 15 The representative voltage signal generated by the relative rotation sensor;

[0023] FIG. 18 A cross-sectional end view of a relative rotation sensor according to one embodiment of the present disclosure is depicted, the relative rotation sensor generating a non-uniform magnetic field;

[0024] FIG. 19 The diagram illustrates the process of... FIG. 18 The representative voltage signal generated by the relative rotation sensor;

[0025] FIG. 20 A cross-sectional end view of a relative rotation sensor according to one embodiment of the present disclosure is depicted, the relative rotation sensor generating a non-uniform magnetic field with multiple magnetic field variations;

[0026] FIG. 21 The diagram illustrates the process of... FIG. 20 The representative voltage signal generated by the relative rotation sensor;

[0027] FIG. 22 A cross-sectional end view of another relative rotation sensor according to one embodiment of the present disclosure is depicted, which generates a non-uniform magnetic field;

[0028] FIG. 23 and FIG. 24 The diagram illustrates the process of... FIG. 22 The representative voltage signal generated by the relative rotation sensor;

[0029] FIG. 25 A cross-sectional end view of a dedicated relative rotation sensor according to one embodiment of the present disclosure is depicted, which generates a single mark each time the drill string rotates; and

[0030] FIG. 26 A flow diagram is depicted that illustrates one method of transmitting downhole instructions to a non-rotating portion of a drill string, according to one embodiment of the disclosure. DETAILED DESCRIPTION

[0031] Described herein are apparatuses, systems, and methods for directional drilling through a formation. Embodiments of a directional drilling apparatus or system include a self-contained module configured to be incorporated in a downhole assembly, which can include a substantially non-rotating sleeve. The module is hermetically sealed and is modular, i.e., the self-contained module can be easily swapped for other modules to reduce turnaround time. According to exemplary aspects, the self-contained module can be installed on and / or removed from the downhole assembly or substantially non-rotating sleeve without having to electrically disconnect the module or otherwise affect other components of the system, such as the downhole assembly, directional drilling apparatus, substantially non-rotating sleeve, and / or steering system.

[0032] The self-contained module houses and at least partially encloses or encapsulates one or more of various components to facilitate or perform functions such as steering, measuring, and / or other functions. In one embodiment, the self-contained module houses and at least partially encloses a biasing device (e.g., a cylinder and piston assembly) that can be actuated to affect a change in drilling direction. The self-contained module can include an energy storage device (e.g., a battery, a rechargeable battery, a capacitor, a supercapacitor, or a fuel cell). In one embodiment, the self-contained module can house an energy transmission / reception device configured to supply energy, such as electrical energy, to components in the module. The energy transmission / reception device can generate electricity, for example, via inductive coupling with a magnetic field generated as a result of rotation of a drive shaft or other components of the drill string.

[0033] FIG. 1 An exemplary embodiment of a drilling, exploration, production, measurement (e.g., logging), and / or geosteering system 10 is shown that includes a drill string 12 configured to be disposed in a borehole 14 that penetrates a formation 16. While the borehole 14 is shown as being substantially vertical, it is contemplated that the borehole 14 can be substantially horizontal or at an angle other than vertical. FIG. 1The borehole is shown as having a constant diameter and orientation, but the borehole is not so limited. For example, the borehole 14 can have a varying diameter and / or orientation (e.g., varying azimuth and inclination). The drill string 12 is made of, for example, pipe, multiple pipe segments, or coiled tubing. The system 10 and / or the drill string 12 includes a drilling assembly (including, for example, the drill bit 20 and the steering assembly 24), and can include various other downhole components or assemblies (such as the measurement tool 30 and the communication assembly), one or more of which can be collectively referred to as a bottom hole assembly (BHA) 18. The measurement tool can be included for performing a measurement program, such as logging while drilling (LWD) applications and measuring while drilling (MWD) applications. Sensors can be disposed at one or more locations along the drill string of the borehole, for example, in the BHA 18, in the drill string 12, in the measurement tool 30 (such as a logging probe), or as a distributed sensor.

[0034] The drill string 12 drives the drill bit 20 through the formation 16. Downhole drilling fluid (such as drilling mud) is pumped through the surface assembly 22 (including, for example, a derrick, a rotary table or top drive, a coiled tubing reel, and / or a riser), the drill string 12, and the drill bit 20, and back to the surface through the borehole 14, using one or more pumps.

[0035] The steering assembly 24 includes components configured to steer the drill bit 20. In one embodiment, the steering assembly 24 includes one or more biasing elements 26 configured to be actuated to apply a lateral force to the drill bit 20 to effect a change in direction. The one or more biasing elements 26 can be housed in a module 28 that is removably attached to a sleeve (not separately labeled) in the steering assembly 24.

[0036] Various types of sensors or sensing devices can be incorporated in the system and / or the drill string. For example, sensors such as magnetometers, gravimeters, accelerometers, gyroscopic sensors, and other directional and / or position sensors can be incorporated into the steering assembly 24 or into separate components. Various other sensors can be incorporated into the BHA 18, such as into the steering assembly 24 and / or into the measurement tool 30. Examples of measurement tools include resistivity tools, gamma ray tools, density tools, or calipers.

[0037] Other examples of devices that can be used to perform measurements include temperature or pressure measurement tools, pulsed neutron tools, acoustic tools, nuclear magnetic resonance tools, seismic data acquisition tools, acoustic impedance tools, formation pressure testing tools, fluid sampling and / or analysis tools, coring tools, tools that measure operational data such as vibration-related data, e.g., acceleration, vibration, weight such as weight on bit, torque such as bit torque, rate of penetration, depth, time, rotational speed, bending, stress, strain, any combination thereof, and / or any other type of sensor or device capable of providing information about the formation 16, the borehole 14, and / or the operation.

[0038] The types of sensors can include discrete sensors (e.g., strain sensors and / or temperature sensors) along the drill string or sensor systems that include one or more transmitters, receivers, or transceivers at a distance, as well as distributed sensor systems having various discrete sensors or sensor systems distributed along the system 10. It is noted that the number and types of sensors described herein are exemplary and not intended to be limiting as any suitable type and configuration of sensors can be employed to measure the properties.

[0039] The processing unit 32 is connected in operable communication with components of the system 10 and can be located, for example, at a surface location. The processing unit 32 can also be at least partially incorporated in the drill string 12 or the BHA 18 as part of the downhole electronics 42 or otherwise disposed downhole as desired. Components of the drill string 12 can be connected to the processing unit 32 via any suitable communication scheme, such as mud-pulse telemetry, electromagnetic telemetry, acoustic telemetry, wired links (e.g., hard-wired drill pipe or coiled tubing), wireless links, optical links, or others. The processing unit 32 can be configured to perform functions such as controlling drilling and steering (e.g., by the steering assembly 24), transmitting and receiving data (e.g., to and from the BHA 18 and / or the modules 28), processing measurement data, and / or monitoring the operation. In one embodiment, the processing unit 32 includes a processor 34, a communication and / or detection means 36 for communicating with downhole components, and a data storage (or computer-readable medium) 38 for storing data, models, and / or computer programs or software 40. Other processing units can include two or more processing units at different locations in the system 10, with each of the processing units including at least one of a processor, a communication device, and a data storage.

[0040] FIG. 2 and FIG. 3Embodiments of a steering assembly 50 for use in directional drilling are shown. The steering assembly 50 can be incorporated into the system 10 (e.g., in the BHA 18), or can be part of any other system configured to perform drilling operations. The steering assembly 50 includes a drive shaft 52 configured to be rotated from the surface, such as by a top drive (not shown) that can be part of the surface assembly 22, or from downhole (such as by a mud motor or turbine (also not shown) that can be part of the BHA 18). The drive shaft 52 can be connected at one end to a disintegration device, such as a drill bit 54, via a connector such as a bit box connector 56. The disintegration device in conjunction with or in place of the drill bit 54 can include any other device suitable for disintegrating rock or formation, including but not limited to an electrical pulse device (also referred to as a discharge device), a jetting drilling device, or a hammer.

[0041] The drive shaft 52 can be connected at the other end and / or at the same end as the disintegration tool to downhole components 58, such as a mud motor (not shown), a communication tool that provides communication with the surface assembly 22, a generator (not shown) that generates electrical power downhole to power other tools in the BHA 18, such as the downhole electronics 42, a measurement tool 30 (including sensors such as formation evaluation sensors or operational sensors), a reamer (e.g., a down reamer, not shown), a steering assembly 24, 50, or a section of pipe in the drill string 12, via a suitable tubular string connector such as a pin box connector. When connected at the lower end of the drive shaft 52 between the disintegration device and the steering assembly 50, some downhole components 58, such as measurement tools, can benefit from the location close to the disintegration device.

[0042] The steering assembly 50 also includes a sleeve 60 that encircles a portion of the drive shaft 52. The sleeve 60 can include one or more biasing elements 62 that can be actuated to control the direction of the drill bit 54 and the drill string 12. Examples of biasing elements include devices such as cylinders, pistons, wedge elements, hydraulic pillows, expandable rib elements, blades, and the like.

[0043] The sleeve 60 is mounted on the drive shaft via a bearing 61 or another suitable mechanism such that the sleeve 60 is at least somewhat rotationally decoupled from the drive shaft 52 or other rotating components. For example, the sleeve 60 is connected to a bearing 61 (e.g., a mud lubricated bearing), which can be any type of bearing including, but not limited to, a contact bearing (such as a sliding contact bearing or a rolling contact bearing), a journal bearing, a ball bearing, or a bushing. The sleeve 60 can be referred to as a “non-rotating sleeve” or a “slowly rotating sleeve,” which is defined as a sleeve or other component that is at least somewhat rotationally decoupled from the rotating components of the steering assembly 50. During drilling, the sleeve 60 can not be completely stationary due to friction between the sleeve 60 and the drive shaft 52 (e.g., friction generated by the bearing 61), but can rotate at a lower rotational speed than the drive shaft 52. The sleeve 60 can have slow rotational movement or no rotational movement compared to the drive shaft 52 (e.g., when the biasing element 62 is engaged with the borehole wall), or can rotate independently of the drive shaft 52 (typically, the sleeve 60 rotates at a much lower rate than the drive shaft 52), especially when the biasing element 62 is actively engaged.

[0044] For example, while the drive shaft 52 can rotate between about 100 to about 600 revolutions per minute (RPM), the sleeve 60 can rotate at a speed of less than about 2 RPM. Thus, the sleeve 60 is substantially non-rotating relative to the drive shaft 52, and is therefore referred to herein as a substantially non-rotating or non-rotating sleeve, regardless of its actual rotational speed. In some cases, the biasing element 62 can be supported by a spring element (not shown), such as a coil spring or a spring washer (e.g., a conical spring washer), to engage with the formation even when the biasing element 62 is not actively powered.

[0045] In one embodiment, the biasing element 62 (or elements) is configured to engage the borehole wall and provide a lateral force component to the drive shaft 52 through the bearing 61 to cause the drive shaft 52 and the drill bit 54 to change direction. The biasing element 62 or elements is connected to the non-rotating sleeve 60 to apply a relatively stationary force to the borehole wall (also referred to as “pushing the drill bit”) or to deflect the drive shaft 52, resulting in the curved direction of the rotating drive shaft 52 to produce a steering direction (also referred to as “pointing the drill bit”).

[0046] Because the non-rotating sleeve 60 rotates significantly slower relative to the formation 16 or not at all, the biasing elements 62, and thus the force applied to the borehole wall, have a direction that changes relatively slowly compared to the faster rotation of the drive shaft 52. This allows the force applied to the borehole wall to remain in the desired steering direction with much less variation than if the biasing elements 62 were rotating with the drive shaft 52. As such, the power required to achieve and / or maintain the desired steering direction is significantly lower compared to systems in which the biasing elements 62 are rotating with the drive shaft 52. Thus, utilizing the non-rotating sleeve 60 allows the steering system to operate with a relatively low power demand.

[0047] The sleeve 60 can be a modular component of the steering assembly 50. In aspects, the sleeve 60 can be installed on and removed from the steering assembly 50 without having to electrically disconnect the sleeve or otherwise affect other components of the steering system. Alternatively or additionally, the sleeve 60 also includes one or more modules 64 configured to enclose or house one or more components to facilitate steering functionality. Each module 64 is mechanically and electrically independent and modular in that the modules 64 can be attached to and removed from the sleeve 60 without affecting the components in the module 64 or the steering assembly 50.

[0048] For example, each module 64 includes a mechanical attachment feature, such as a clamping element (not shown), e.g., a device for thermal clamping, a device including a shape memory alloy, a press-fit device, or a taper-fit device, or a screw hole 66 that allows the module 64 to be fixedly connected to the sleeve 60 with a removable securing mechanism, such as a screw, a bolt, a thread, a magnet, or a clamping element, e.g., a mechanical clamping element, a thermal clamping element, a clamping element including a shape memory alloy, a press-fit element, a taper-fit element, and / or any combination thereof. Further, in another example, the module 64 can be fixedly connected to the sleeve 60 with a removable securing mechanism, such as a screw, a bolt, a thread, a magnet, or a clamping element, e.g., a mechanical clamping element, a thermal clamping element, a clamping element including a shape memory alloy, a press-fit element, a taper-fit element, or any combination thereof, without any non-removable securing elements.

[0049] Each module 64 can at least partially enclose one or more biasing elements 62 and can include one type of biasing element 62 or multiple types of biasing elements 62. Note that each module 64 can include a respective biasing element 62 and associated controller, allowing each biasing element 62 to be independently operated.

[0050] In FIG. 2 and FIG. 3In the illustrated embodiment, the sleeve 60 includes three modules 64 arranged circumferentially (e.g., separated by the same angular distance). However, the sleeve 60 is not limited thereto and can include a single module 64 or any suitable number of modules 64. Also, one or more modules 64 can be positioned at any suitable location or configuration.

[0051] Each module 64 and / or the sleeve 60 can include a sealing component to allow the modules 64 to be hermetically sealed to the sleeve 60 so as to prevent fluid flow through the walls of the sleeve 60. Alternatively, the modules 64 can be attached to the sleeve 60 without sealing the modules 64 to the sleeve 60, such as without any fluid sealing elements in addition to the mechanical attachments described above.

[0052] In one embodiment, each module 64 is configured to communicate with components external to the module 64 without a physical electrical connection, such as a wire or cable. That is, the modules 64 are electrically isolated while still being configured to receive energy and / or data.

[0053] Thus, the modules 64 can be handled as a closed unit even when they are separated from the sleeve 60. Thus, since the modules 64 can be hermetically closed units, they can be, for example, tested, verified, calibrated, maintained, and / or repaired, or they can exchange data (download or upload) without needing to attach the modules 64 to the sleeve 60, or simply cleaned, such as by using a conventional high-pressure gasket. The modules 64 can be further replaced for quick repair of the steering assembly 50 during a drilling operation or in preparation for the drilling operation, while not in normal operation. That is, the modules 64 can be replaced by accessing the BHA 18 or steering assembly 24 from the outer periphery of the BHA 18 or steering assembly 24. This allows the modules 64 to be replaced without breaking the string connections.

[0054] In particular, the modules 64 can be replaced with the string connections at the upper and / or lower ends of the steering assembly remaining intact and without disassembling the steering assembly 24 from the BHA 18 or drill string 12. In particular, the modules 64 can be replaced while the steering assembly 24 is connected (e.g., mechanically connected to at least a portion of the BHA 18 or drill string 12 via one or more string connections). The replaced modules can be shipped to an off-site repair and maintenance facility for further investigation and maintenance without needing to transport the steering assembly 50 or disconnect the steering assembly 50 from at least a portion of the BHA 18 or drill string 12. That is, testing, verification, calibration, data transfer (upload or download data), maintenance, and repair can be done at the module level rather than the tool level. This allows for quick replacement of the modules to repair the assembly and transport a relatively small module rather than the complete downhole drilling tool.

[0055] Additionally, the example embodiments allow for quick replacement of modules from the outer periphery of the steering assembly 24 to effect repairs while the steering assembly 24 remains physically connected to the BHA 18 and / or drill string 12. The ability to quickly replace modules to repair the steering assembly 24 and select for relatively small modules to ship instead of the entire downhole drilling tool and / or the ability to quickly replace modules to repair the assembly while the steering assembly 24 remains physically connected to the BHA 18 and / or drill string 12 (e.g., via a tubular string connector) are major benefits that facilitate significant reductions in operating costs.

[0056] As noted, one or more of the modules 64 can be configured to wirelessly communicate with a communication device, such as an antenna 69 and / or an inductive coupling device at one component (such as a tubular segment, the BHA 18, the drill bit 20, the drive shaft 52, or other downhole component 58) and / or another module 64 in the same or another component.

[0057] FIG. 4A and FIG. 4B A perspective view of a module 64 is shown. As shown, in one embodiment, the module 64 includes a housing 70 having a shape configured to removably attach (e.g., via screws, bolts, threads, magnets, or clamping elements (e.g., mechanical clamping elements, thermal clamping elements, clamping elements including shape memory alloys), pressure fit elements, taper fit elements, or any combination thereof) into a correspondingly shaped cutout (not separately labeled) in a wall of the sleeve 60. The module 64 can have a thickness equal to or similar to a thickness of the sleeve 60, thereby forming a portion of the wall. Alternatively, the module 64 can have a thickness less than a thickness of the sleeve 60 and can be installed at a recess (not separately labeled) formed in the sleeve wall. The thickness of the module 64 can be sized to accommodate various parts and components included in the module 64, as discussed further below. The module 64 can also be curved so as to conform to the curvature of the sleeve 60, which is generally cylindrical. Optionally, the module 64 can be covered by a hatch (not separately labeled).

[0058] Housing 70 can be a unitary part accessible via an opening, such as a bore or a port, and can also include multiple housing components, such as lower housing component 72, which can be a single unitary housing component or have multiple housing components. Upper housing component 74 can also be a single unitary housing component or have multiple housing components and can be attached to lower housing component 72 via a permanent joint (e.g., by welding, gluing, brazing, adhering) or a removable joint (e.g., screws, bolts, threads, magnets, or clamping elements (e.g., mechanical clamping elements, thermal clamping elements, clamping elements including shape memory alloys), pressure fit elements, taper fit elements, or any combination thereof). Note that the terms "upper" and "lower" are not intended to dictate any particular orientation of module 64 relative to, for example, a drill string, a sleeve, or a borehole.

[0059] As shown in FIG. 4A and FIG. 4B Housing 70, lower housing component 72, and / or upper housing component 74 can be made of multiple segments 76. For example, housing 70 is divided into multiple segments 76, which can house different components and can be joined together removably (such as by screws, bolts, threads, magnets, or clamping elements (e.g., mechanical clamping elements, thermal clamping elements, clamping elements including shape memory alloys), pressure fit elements, taper fit elements, or any combination thereof) or permanently (such as by welding, gluing, brazing, or adhering).

[0060] FIG. 5 and FIG. 6 Examples of components that can be housed in module 64 are shown. Note that the components are not limited to those shown in FIG. 5 and FIG. 6 and are also not limited to the particular orientations, shapes, and positions shown. Each component can be secured in any suitable manner. For example, module 64 can include recesses shaped to conform to the respective devices to be disposed therein. In one embodiment, the devices can be enclosed and secured in place via upper housing component 74 and / or one or more faceplates. In another embodiment, the devices can be installed into module 64 via a port or bore, such as between upper housing component 74 and lower housing component 72. The devices can also be disposed individually in segments 76.

[0061] In FIG. 5 and FIG. 6In the example of FIG. 1, module 64 includes biasing element 62, antenna 68, and various devices for performing functions related to steering, communication, power supply, processing, etc. Such devices can include power supply devices, power storage devices, data storage devices, biasing control devices, communication devices, and electronics such as one or more controllers / processors, or data storage devices. Examples of devices that can be housed in module 64 are discussed below, however module 64 and constituent devices are not limited thereto. In particular, antenna 68 is an optional device that can be omitted without significantly reducing system functionality. That is, as discussed further herein, communication with independent module 64 can be achieved via magnet 98 and auxiliary shaft 102 (e.g., magnet 98 and auxiliary shaft 102 of energy transfer / receiving device 96). Thus, one embodiment is a steering assembly 50 characterized by a non-rotating sleeve 60 having one or more independent modules 64 that do not include an antenna, such as antenna 68.

[0062] Module 64 can also include a control mechanism for operating biasing element 62. Examples of control mechanisms include hydraulically pumped and / or hydraulically controlled actuators, as well as motors, such as electric motors.

[0063] In the example of FIG. 1, module 64 includes biasing element 62, antenna 68, and various devices for performing functions related to steering, communication, power supply, processing, etc. Such devices can include power supply devices, power storage devices, data storage devices, biasing control devices, communication devices, and electronics such as one or more controllers / processors, or data storage devices. Examples of devices that can be housed in module 64 are discussed below, however module 64 and constituent devices are not limited thereto. In particular, antenna 68 is an optional device that can be omitted without significantly reducing system functionality. That is, as discussed further herein, communication with independent module 64 can be achieved via magnet 98 and auxiliary shaft 102 (e.g., magnet 98 and auxiliary shaft 102 of energy transfer / receiving device 96). Thus, one embodiment is a steering assembly 50 characterized by a non-rotating sleeve 60 having one or more independent modules 64 that do not include an antenna, such as antenna 68. FIG. 5 and FIG. 6 In the example of FIG. 1, module 64 includes biasing element 62, antenna 68, and various devices for performing functions related to steering, communication, power supply, processing, etc. Such devices can include power supply devices, power storage devices, data storage devices, biasing control devices, communication devices, and electronics such as one or more controllers / processors, or data storage devices. Examples of devices that can be housed in module 64 are discussed below, however module 64 and constituent devices are not limited thereto. In particular, antenna 68 is an optional device that can be omitted without significantly reducing system functionality. That is, as discussed further herein, communication with independent module 64 can be achieved via magnet 98 and auxiliary shaft 102 (e.g., magnet 98 and auxiliary shaft 102 of energy transfer / receiving device 96). Thus, one embodiment is a steering assembly 50 characterized by a non-rotating sleeve 60 having one or more independent modules 64 that do not include an antenna, such as antenna 68. FIG. 5 and FIG. 6 In the example of FIG. 1, module 64 includes biasing element 62, antenna 68, and various devices for performing functions related to steering, communication, power supply, processing, etc. Such devices can include power supply devices, power storage devices, data storage devices, biasing control devices, communication devices, and electronics such as one or more controllers / processors, or data storage devices. Examples of devices that can be housed in module 64 are discussed below, however module 64 and constituent devices are not limited thereto. In particular, antenna 68 is an optional device that can be omitted without significantly reducing system functionality. That is, as discussed further herein, communication with independent module 64 can be achieved via magnet 98 and auxiliary shaft 102 (e.g., magnet 98 and auxiliary shaft 102 of energy transfer / receiving device 96). Thus, one embodiment is a steering assembly 50 characterized by a non-rotating sleeve 60 having one or more independent modules 64 that do not include an antenna, such as antenna 68. FIG. 5 and FIG. 6 In the example of FIG. 1, module 64 includes biasing element 62, antenna 68, and various devices for performing functions related to steering, communication, power supply, processing, etc. Such devices can include power supply devices, power storage devices, data storage devices, biasing control devices, communication devices, and electronics such as one or more controllers / processors, or data storage devices. Examples of devices that can be housed in module 64 are discussed below, however module 64 and constituent devices are not limited thereto. In particular, antenna 68 is an optional device that can be omitted without significantly reducing system functionality. That is, as discussed further herein, communication with independent module 64 can be achieved via magnet 98 and auxiliary shaft 102 (e.g., magnet 98 and auxiliary shaft 102 of energy transfer / receiving device 96). Thus, one embodiment is a steering assembly 50 characterized by a non-rotating sleeve 60 having one or more independent modules 64 that do not include an antenna, such as antenna 68.

[0064] To control the force and position of the biasing element 62, the module 64 includes control electronics or a controller 88, which can include data storage. The controller 88 controls operation of the biasing control assembly by controlling at least one of the pump, motor 80, linear motion device 84, and / or one or more valves (not individually labeled). The module 64 can include or be in communication with one or more orientation sensors (e.g., via the antenna 68) to measure directional characteristics of the BHA 18 or a piece of the BHA 18, such as the measurement tool 30, the steering assembly 50, and / or the drill bit 54. In one embodiment, the orientation sensors are configured to detect or estimate an azimuthal orientation, a tool face orientation, or an inclination of the sleeve 60. Examples of orientation sensors include bend sensors, accelerometers, gravitometers, magnetometers, and gyroscopic sensors.

[0065] Any other suitable sensors can be included in or in communication with a module that can benefit from a location close to the drill bit. Examples of such sensors include formation evaluation sensors, such as but not limited to sensors that measure resistivity, gamma, density, thickness, and / or chemical properties, or sensors that measure operational data such as time, drilling fluid properties, temperature, pressure, vibration-related data (e.g., acceleration, weight such as weight on bit, torque such as drill bit torque, depth, rate of penetration, rotational speed, bending, stress, strain), and / or any other type of sensor or device that can provide information about the formation, the borehole, and / or the operation.

[0066] Another component that can be included in the module 64 is a pressure compensation device, such as a pressure compensator 90. In this example, the pressure compensator 90 is encapsulated within the module 64, except for a surface that is movable or flexible and exposed to fluid pressure. The pressure compensator 90 can be used to provide a reference pressure that can be equal to or related to the fluid pressure outside of the module 64 and / or to provide a compensation fluid volume. The reference pressure can be provided to the motion device 84 and / or the motor 80 in order to create a pressure differential relative to the reference pressure, thereby directing the working fluid to apply the appropriate pressure to the biasing element 62 via the hydraulic coupling 86. Alternatively or additionally, the compensation fluid volume can be used to compensate for a fluid-filled volume that changes in response to the moving motion device 84 or motor 80.

[0067] In another embodiment, the motion device 84 and / or the motor 80 is moving relative to a mechanical barrier, such as a mechanical shoulder, that prevents movement of the motion device 84 in at least one direction. In yet another embodiment, the compensation fluid volume can be taken from a finite volume of compressible fluid, such as a gas, for example air. Thus, if the motion device 84 and / or the motor 80 is moving relative to a mechanical barrier that prevents movement in at least one direction, and the compensation fluid volume is taken from a finite volume of compressible fluid, such as a gas, for example air, then the configuration can operate without the pressure compensator 90.

[0068] The components housed in the module 64 can be powered via an energy storage device 94, such as a battery, a capacitor, a super capacitor, a fuel cell, and / or a rechargeable battery.

[0069] In addition to or in place of the energy storage device 94, the module 64 can include an energy transmission / reception device 96 to provide power to control the steering direction and perform other functions. Using the energy transmission / reception device 96, energy can be transmitted to and / or received from the surface assembly 22 via conductors (also not shown) that extend along the drill string 12 to an energy storage device (not shown), such as a battery, a rechargeable battery, a capacitor, a super capacitor, or a fuel cell disposed within a rotating portion of the BHA, or an energy converter (also not shown) that converts one form of energy (e.g., vibration, fluid flow such as drilling fluid, relative motion / rotation of parts such as between the drive shaft 52 and the non-rotating sleeve 60) to another form of energy (e.g., electrical energy, chemical energy within a battery, or any combination thereof). Energy converters commonly known for use downhole are, for example, turbines that convert fluid flow to rotation of mechanical parts, generators / dynamos that convert rotation of mechanical parts to electrical energy, and charging devices that convert electrical energy to battery chemical energy. If energy is provided downhole for reasons other than to provide energy, these energy converters are sometimes referred to as energy harvesting devices.

[0070] In one embodiment, the energy transmission / reception device 96 includes one or more coils (e.g., energy harvesting coils) enclosed within the module 64. The coils are positioned so that they are within a magnetic field generated by one or more magnetic devices mounted on the drive shaft 52 or other suitable location.

[0071] In one embodiment, the magnetic devices include one or more magnets 98 FIG. 3), such as an electromagnet (e.g., a coil, such as a coil wrapped around a magnetic material) or a permanent magnet or a combination of both attached to and rotating with the drive shaft 52 or other rotating component to generate an alternating magnetic field received by the coil of the energy transmission / reception device 96. The electromagnet can include one or more electrically conductive coils on the rotating drive shaft 52. An electric current can be applied to the electrically conductive coil to generate a magnetic field. The electric current applied to the electrically conductive coil can be modulated to produce a modulated magnetic field that can be used for communication and / or can allow energy transfer into the module even when the drive shaft 52 is not rotating (or there is at least substantially no relative rotation between the drive shaft 52 and the sleeve 60). Communication via the antenna 68 and / or the energy transmission / reception device 96 can be controlled by the communication controller 92.

[0072] The energy transmission / reception device 96 described herein transmits magnetic energy into the encapsulated unit (e.g., an energy harvesting coil) through a separator. In one embodiment, the magnetic energy coupling is achieved by generating and altering the primary magnetic field received by the secondary device by the magnetic device. The secondary device can be one or more stationary coils mounted in the proper orientation and position relative to the time-varying or alternating magnetic field produced by the magnetic device. In this way, mechanical energy is directly converted into electrical energy.

[0073] The energy transmission / reception device 96 can include an energy controller 100, which can include a data storage device, for controlling the power supply of components in the module, and / or for controlling the charging and recharging of the energy storage device 94. The energy controller 100 can include a rectifier to generate DC current from the received electrical energy, which will be provided by the energy controller 100 to other electronics within the module 64. The energy controller 100 can be a different controller, or can be configured to control multiple components in the module, such as the energy transmission / reception device 96, a communication device for wireless communication (such as the antenna 68), and / or the biasing element 62. Thus, one or more of the energy controller 100, the communication controller 92, and the controller 88 for controlling the biasing element 62 can in fact be the same or different control devices or control circuitry with various control functions as appropriate. That is, the scope of the present disclosure is not limited to where which control function is implemented.

[0074] In one embodiment, the secondary device includes another magnetic device disposed in the primary magnetic field. The secondary device can be configured to rotate or otherwise move and / or generate a secondary magnetic field through the primary magnetic field.

[0075] FIG. 7 to FIG. 10An example of an auxiliary magnetic device configured to be positioned in a primary magnetic field is shown. In this example, the auxiliary magnetic device includes an auxiliary shaft 102 disposed inside or connected to the module 64. The auxiliary shaft 102 is supported by a bearing or another suitable mechanism such that the auxiliary shaft 102 can rotate independently of the sleeve and module 64 in response to the primary magnetic field generated by the magnet 98 rotating with the drive shaft 52. The auxiliary shaft 102 can feature a magnet, an electrical coil, or other device attached to allow torque to be transferred from the primary magnetic field to a secondary magnetic field. The secondary magnetic field can be generated by, for example, a permanent magnet, an eddy current device, an electrical coil, and / or a hysteresis material. As FIG. 10 shown, the auxiliary shaft can be operably connected to an alternator device 104 to convert mechanical energy into electrical energy that can be provided to various components, for example, to provide power to the motor 80 and / or to charge an energy storage device. Optionally, a gear box (not shown), including gears (also not shown), such as planetary gears, can be connected between the auxiliary shaft 102 and the alternator device 104 to enable more efficient energy transfer.

[0076] The modules described herein improve and facilitate the application of directional forces (e.g., via biasing elements) to control the direction of the drilling assembly. In one embodiment, the modules are configured to house an active biasing mechanism, such as a piston, lever, and pad that is actively controlled via a controller. In another embodiment, the biasing mechanism can be supported by a passive mechanism, such as a spring, for example, to engage the formation even if the ability to actively control the biasing mechanism is lost. Both passive and active elements can be limited. For example, the biasing element 62 can be partially powered by a spring. If the energy storage capacity of the energy storage device 94 becomes too small to provide for communication and active formation engagement, the biasing element 62 can be powered solely by the spring or as an adjunct to an active biasing element.

[0077] In certain embodiments, conventional communication devices are not used to transfer information between the rotating and non-rotating portions of the drill string. Conventional communication devices refer to devices in which information is encoded into electrical, electromagnetic, or optical signals that are transmitted from a transmitter to a receiver by wire or wirelessly. Instead of using such encoded signal transmission, downhole tools according to the present disclosure can be configured to estimate the rotational speed (RPM) of the rotating portion relative to the non-rotating portion directly or indirectly. At the surface, such relative rotation can be controlled in a manner that indicates one or more components of the non-rotating portion to take one or more desired actions. Such indications can be referred to as “downhole instructions” or “command signals.”

[0078] Referring to FIG. 11 A bottom hole assembly (BHA) 2000 that uses drill string rotation variations in order to send downhole instructions / command signals is shown in the form of a functional block diagram. The BHA 2000 can include at least a portion of a drill string 12 FIG. 1The rotating portion 2004 and the non-rotating portion 2002. In an embodiment, the non-rotating portion 2002 may be similar to... FIG. 2 and FIG. 3 The non-rotating sleeve 60, and the rotating part 2004 can be similar to FIG. 2 and FIG. 3 The drive shaft 52. For the sake of brevity, the term "non-rotating part" 2002 may be used interchangeably with the term "non-rotating sleeve" 2002. Additionally, the term "rotating part" 2004 may be used interchangeably with the terms "drive shaft" or "rotating shaft" 2004.

[0079] The non-rotating sleeve 2002 may include one or more biasing elements 2006, one or more orientation sensors 2008, one or more relative rotation sensors 2010, and a controller 2012. All these components may be enclosed in module 2003. The biasing element 2006 may be similar to... FIG. 1 bias element 26 or FIG. 2 The bias element 62. Examples of bias elements include devices such as cylinders, pistons, wedge elements, hydraulic cushions, expandable rib elements, blades, etc. The bias element 2006 can use the previously combined bias element 26 ( FIG. 1 ) and bias element 62 ( FIG. 2 The control mechanism can be actuated by any of the mechanisms discussed. Examples of control mechanisms include hydraulic pumps and / or hydraulically controlled actuators, and motors such as electric motors. Regarding the components used to operate the bias element 2006, the controller 2012 may be similar to... FIG. 5 The controller 88. For example, the controller 2012 can be programmed with an appropriate algorithm 2014 in the memory module 2016 to actuate the actuator 2018 associated with the bias member 2006. For example, the actuator 2018 may include the components described above with respect to the controller 88 ( FIG. 5 The pumps and valves discussed above. Module 2003 may be similar to those described above (e.g., refer to...). FIG. 2 and FIG. 3 ) Independent modular module 64.

[0080] Additionally, the controller 2012 can include suitable algorithms to use information from the orientation sensor 2008 and the relative rotation sensor 2010 to control the biasing elements 2006. For example, the controller 2012 can be configured to adjust the force exerted by one or more biasing elements 2006 and / or adjust the physical position of one or more biasing elements 2006. Generally, the relative rotation sensor 2010 generates information indicative of the rotational speed of the rotating portion 2004 relative to the non-rotating portion 2002 or the "relative rotational speed" of the rotating portion 2004. Additionally, in some applications, the relative rotation sensor 2010 can also detect the instantaneous (angular) position between the rotating portion 2004 and the non-rotating portion 2002. As described above, the relative rotation sensor 2010 can also function as an energy transfer / receiving device 96 FIG. 5 ) and / or a communication device (e.g., in combination with a magnetic device or an auxiliary magnetic device). In such embodiments, one or more coils (e.g., energy harvesting coils of the energy transfer / receiving device 96) can be enclosed within, for example, the module 64 FIG. 5 ), and can also be used to sense a magnetic field generated by a magnet 98 rotating with the drive shaft 52. The coils are positioned such that they are within the magnetic field generated by one or more magnetic devices mounted on the drive shaft 52 or other suitable location. In one embodiment, the magnetic device includes one or more magnets 98 FIG. 3 or FIG. 14 2102). The orientation sensor 2008 generates information about the orientation of the non-rotating portion 2002 relative to a selected frame of reference, such as the earth's magnetic field or the earth's gravitational field. Exemplary orientation sensors 2008 include, but are not limited to, single-axis accelerometers, multi-axis accelerometers, single-axis or multi-axis magnetometers, gyroscopes, etc. Optionally, the module 2003 can include a wireless communication unit 2021 to enable signal exchange between components of the module 2020 and components external to the module 2020, such as components within the drive shaft 52 FIG. 2 and FIG. 3 ). As will be discussed in greater detail below, the controller 2012 uses information from the relative rotation sensor 2010 to decode a command signal embedded in changes in rotation of the rotating portion 2004 relative to the non-rotating portion 2002. The command signal can be an instruction to effect a change in the drilling path. The controller 2012 effects the change in the drilling direction after first determining the orientation of the biasing elements 2006 with reference to the selected frame of reference and then suitably positioning or repositioning one or more of the biasing elements 2006.

[0081] While FIG. 11Embodiments are depicted in which the non-rotating sleeve 2002 includes multiple biasing elements 2006 controlled by a controller 2012, but the teachings of the present disclosure are not limited to such embodiments. For example, as shown in FIG. 12 the non-rotating sleeve 2002 can include multiple independent modules 2020, each including a biasing element 2006, an associated actuator 2018, a controller 2012, an orientation sensor 2008, and a relative rotation sensor 2010. The modules 2020 can be similar to the independently modular modules 64 as described above (e.g. FIG. 2 and FIG. 3 ). Optionally, one or more of the modules 2020 can include a wireless communication unit 2021 to enable signal exchange between components of the various modules 2020 and / or components external to the modules 2020, such as components within the drive shaft 52 FIG. 2 and FIG. 3 ). It will be appreciated that embodiments of the present disclosure are not limited to any particular number of biasing elements per module 2020. For example, some modules 2020 can include one biasing element 2006, and other modules 2020 can include two or more biasing elements 2006. Optionally, one or more of the modules 2020 can include a wireless communication unit 2021 to enable signal exchange between components of the modules 2020 and components external to the modules 2020, such as components within the drive shaft 52 FIG. 2 and FIG. 3 or components in one or more other modules 2020. In alternative embodiments, one or more of the modules 2020 do not have at least one of a relative rotation sensor and an orientation sensor, but receive at least one of relative rotation information and orientation information from one of the other modules 2020 that includes a relative rotation sensor and / or an orientation sensor via the wireless unit 2021. Alternatively, the orientation information and relative rotation information can be received in the modules 2020 from sensors installed in the sleeve 2002 external to any of the modules 2020 via the wireless communication unit 2021.

[0082] Referring to FIG. 13A to FIG. 13D , exemplary rotational speed variations of the rotating portion 2004 are shown, which can be used to communicate downhole instruction / command signals from surface locations to the controller 2012 of the non-rotating sleeve 2002. Time is shown along the “X” axis in units such as minutes. Rotational speed is shown along the “Y” axis in RPM. Typically, the variations involve switching between two specified rotational speeds and a specified duration at each specified RPM. While FIG. 13A to FIG. 13D two discrete relative rotational speeds are shown, some encoding schemes can use three or more discrete relative rotational speeds.

[0083] FIG. 13A Downward instructions are shown represented by relative rotational velocity profile 2030, which begins with a higher rotational rate (RPM) 2032 of rotating portion 2004( FIG. 11 ) that decreases to a lower rotational rate (RPM) 2034 after a specified duration of a first time period 2036. After a specified duration of a second time period 2038, the rotational rate returns to the higher RPM 2032 for a specified duration of the first time period 2036. The durations of the first time period 2036 and the second time period 2038 can be equal durations or different durations. Such a pattern of higher and lower RPMs and associated durations can uniquely identify a desired directional change, such as “turn left.”

[0084] FIG. 13B Downward instructions are shown represented by relative rotational velocity profile 2040, which begins with a lower rotational rate (RPM) 2042 of rotating portion 2004( FIG. 11 ) that increases to a higher rotational rate (RPM) 2044 after a specified duration of a first time period 2046. After a specified duration of a second time period 2048, the rotational rate returns to the lower RPM 2042 for a specified duration of the first time period 2046. The durations of the first time period 2036 and the second time period 2038 can be equal or different. Such a pattern of lower and higher RPMs and associated durations can also uniquely identify a desired change, such as “turn right.”

[0085] FIG. 13C Downward instructions are shown represented by relative rotational velocity profile 2050, which begins with a higher rotational rate (RPM) 2052 of rotating portion 2004( FIG. 11 ) that decreases to a lower rotational rate (RPM) 2054 after a specified duration of a first time period 2056. After a specified duration of a second time period 2058, the rotational rate returns to the higher RPM 2052. Thereafter, the rotational rate oscillates between the higher RPM 2052 and the lower RPM 2054 twice, for relatively short third and fourth time periods 2060 and 2062. The pattern can then begin again. Such a pattern of higher and lower RPMs and associated durations can uniquely identify a desired directional change, such as “turn up.”

[0086] FIG. 13D Downward instructions are shown represented by relative rotational velocity profile 2070, which begins with a lower rotational rate (RPM) 2072 of rotating portion 2004( FIG. 11) begins at a lower rotational rate (RPM) 2072 that increases to a higher rotational rate (RPM) 2074 after a specified duration of a first time period 2076. After a specified duration of a second time period 2078, the rotational rate returns to the lower RPM 2072. Thereafter, the rotational rate oscillates between the lower RPM 2072 and the higher RPM 2074 twice for relatively short third and fourth time periods 2080 and 2082. The pattern can then begin again. Such a pattern of higher and lower RPMs and associated durations can uniquely identify a desired directional change, such as a "turn down."

[0087] Thus, it should be appreciated that manipulation of the drill string rotation at the surface can be used to communicate downhole instructions to perform various actions downhole. As described above, the downhole instructions can dictate a change in the drilling direction with respect to inclination and / or azimuth. The downhole instructions can also adjust the force applied by one or more biasing elements, which can change the rate of the drilling direction change. The downhole instructions can also include non-drilling direction commands, such as closing / opening components. While FIG. 13A to FIG. 13D Simple commands (such as "turn up," "turn down," "turn left," "turn right") are described by relatively simple RPM patterns, but those skilled in the art will appreciate that patterns similar to those described with reference to FIG. 13A to FIG. 13D More complex commands would enable support for "hold" commands, such as commands to hold a steering parameter (e.g., inclination or azimuth) at a particular value or within a particular range. One example is a command like "hold inclination at 20°." Receiving such a command via the antenna 68 and / or energy transmission / reception device 96 FIG. 5 ) through the RPM pattern would cause the controller 88 to control the biasing elements 62 in a manner in which the steering parameter would be held at the particular value or within the particular range.

[0088] It should be appreciated that manipulating the drill string rotation by utilizing two or more discrete RPMs and selecting different time periods to hold the RPMs can allow multiple downhole instruction / command signals to be communicated to the controller 2012 on the non-rotating portion 2002 FIG. 11 、 FIG. 12 Of course, there can be practical considerations, such as in conjunction with a change of sufficient magnitude or duration long enough for the downhole instrument to detect the change in RPM due to communication of the command signal as opposed to "noise" associated with drilling operations. However, the teachings of the present disclosure can utilize any scheme, pattern, or manner of change in rotational rate and associated duration, and is not limited to the combination of FIG. 13A to FIG. 13DThose discussed. For example, although FIG. 13A to FIG. 13D The signal implies the use of a specific relative rotational speed, but the encoding scheme can use other methods. For example, the scheme can use the difference between a higher and a lower rotational speed without considering the actual rotational speed. Moreover, the scheme can use ranges to form features, such as RPM greater than or less than a threshold (e.g., greater than 150 RPM or less than 100 RPM).

[0089] FIG. 14 The schematic illustration shows a combination of the present disclosure. FIG. 11 and FIG. 12 The described functionality is a non-limiting configuration of the BHA 2000. The BHA 2000 may include a non-rotating sleeve 2002 with a bore 2090, and a drill string 12 ( FIG. 1 The rotating portion 2004 is disposed in the bore. One or more bearings 2092 may be positioned between the non-rotating sleeve 2002 and the rotating portion 2004 to allow relative rotation between them. As previously described, the non-rotating sleeve 2002 may include one or more biasing elements 2006, one or more orientation sensors 2008, one or more relative rotation sensors 2010, and a controller 2012. These components may be housed in separate modules as previously described.

[0090] Optionally, the BHA 2000 may include one or more anti-rotation elements 2094 positioned on the non-rotating sleeve 2002. In some embodiments, the biasing element 2006 provides sufficient friction against the borehole wall 2096 to anchor the non-rotating sleeve 2002 substantially statically relative to the borehole wall 2096. In other embodiments, the anti-rotation element 2094 either cooperates with the biasing element 2006 or primarily generates the required friction to anchor the non-rotating sleeve 2002 substantially statically relative to the borehole wall 2096. The anti-rotation element 2094 may utilize a mechanism similar to the biasing element 2006, such as a spring, a pad, etc. In embodiments, the anti-rotation element 2094 may be statically and continuously frictionally engaged with the borehole wall 2096. In other embodiments, the anti-rotation element 2094 may be retractable to disengage from the borehole wall 2096 in response to a suitable control signal. It should be understood that borehole wall 2096 is merely an example of an adjacent surface on which biasing element 2006 and anti-rotation element 2094 may act. Other adjacent surfaces may be the inner surfaces of casing, lining, or other wellbore tubular structures.

[0091] In the implementation scheme, in addition to transmitting and receiving energy for the non-rotating sleeve 2002, the energy transmission / reception device 96 (e.g., FIG. 5) can also be used as a relative rotation sensor 2010. In such embodiments, the relative rotation sensor 2010 includes one or more coils 2100 (e.g., energy harvesting coils, alternator coils) and is positioned such that they are within a magnetic field generated by one or more magnetic devices 2102 mounted on a portion of the rotating portion 2004.

[0092] FIG. 15 A cross-sectional view of one non-limiting embodiment of an energy transmission / receiving device also used as a relative rotation sensor 2010 is shown. The relative rotation sensor 2010 can include one or more coils 2100 disposed in the non-rotating portion 2002. In the depicted arrangement, there are three coil sets 2106, with each coil set having two coils 2100. It should be appreciated that more or fewer coil sets 2106 can be used. The relative rotation sensor 2010 also includes magnetic devices 2108 distributed on a portion of the rotating portion 2004. For example, the magnetic devices 2108 can include one or more magnets 2110 or magnetic elements arranged circumferentially within or on an outer surface of the rotating portion 2004. As used herein, the term such as magnet, magnetic element, or magnetic material refers to any object or member that produces a magnetic field, including a loop of electrically conductive tubing such as a coil through which current flows. In a conventional manner, during relative rotation between the rotating portion 2004 and the non-rotating sleeve 2002 at a constant RPM, the magnetic field generated by the magnetic devices 2108 produces an alternating voltage in the coils 2100 having a constant frequency and constant peak voltage.

[0093] Referring to FIG. 16A and FIG. 16B , voltage signals associated with two different constant RPMs are shown that can be generated by the relative rotation of the sensor 2010 of FIG. 15 In both graphs, time (ms) is along the “X” axis, and voltage (V) is along the “Y” axis. In FIG. 16A , the voltage signal 2120 can have an amplitude of about 22 volts and a period of about 22 milliseconds. FIG. 16A The voltage signal 2120 of FIG. 16B , the voltage signal 2122 can have an amplitude of about 44 volts and a period of 11 milliseconds. FIG. 16B The voltage signal 2122 of FIG. 16A and FIG. 16B The voltage signals and associated rotational speeds of FIG. 16A and FIG. 16BThe voltage changes shown and their associated current flow through the coils 2100 of the coil set 2106 can also be used to provide power to components within the non-rotating portion 2002 (such as to the controller 2012 or biasing member 2006 to provide power) or to charge one or more capacitors, supercapacitors, batteries, fuel cells, or rechargeable batteries within at least one independent module 2020. FIG. 11 and FIG. 12 The controller 2012 or biasing member 2006 provides power) or to charge one or more capacitors, supercapacitors, batteries, fuel cells, or rechargeable batteries within at least one independent module 2020. FIG. 11 and FIG. 12 The controller 2012 or biasing member 2006 provides power) or to charge one or more capacitors, supercapacitors, batteries, fuel cells, or rechargeable batteries within at least one independent module 2020.

[0094] Referring to FIG. 17 , voltage signals 2124 representative of a transition from a higher RPM to a lower RPM that can be generated by the relative rotation sensor 2010 of the FIG. 14 or FIG. 15 are shown. Time (ms) is along the “X” axis and voltage (V) is along the “Y” axis. The voltage signals 2124 can have a first segment 2126 associated with a given rotational speed and a second segment 2128 associated with a relatively lower rotational speed. The first segment 2126 has a greater amplitude and shorter period than the second segment 2128 due to the relatively higher rotational speed. As described in connection with FIG. 13A to FIG. 13D , these changes in relative rotational speed detected by measuring the voltage signals in the relative rotation sensor 2010 can be used to create unique signatures and to transmit desired downhole instruction / command signals from the surface to the controller 2012 FIG. 14 ).

[0095] It should be noted that the energy transmission / reception devices described in connection with FIG. 7 to FIG. 10 may also be used to detect changes in drill string rotation as described above. For example, the magnet 98 can be used to transmit energy from the rotation of the drive shaft 52 via the auxiliary shaft 102 into the independent and sealed module 64. Voltage and current changes in the module 64 corresponding to the energy received within the module 64 are also sensed to obtain information about the rotation (e.g., rotational speed) of the drive shaft relative to the sleeve 60. The identified rotational pattern can then be used to identify a command or message to receive information from the rotating drive shaft and the associated surface assembly 22 FIG. 1 ) at the surface.

[0096] Referring to FIG. 14In embodiments, the controller 2012 can include an algorithm, program, or other suitable machine-readable instructions that use the voltage signals from the relative rotation sensor 2010 to estimate a change in the relative rotational speed. The instructions can estimate parameters of the signal indicative of the relative rotational speed, such as amplitude, frequency, and / or duration. The controller 2012 can use one or more of the estimated parameters to determine whether a command signal was transmitted via a change in rotational speed, and if so, to decode the command signal to determine the instruction to be performed. It should be appreciated that the controller 2012 does not necessarily estimate any given rotational speed. Rather, the controller 2012 can use only the associated voltage signals to determine the command signal associated with a given pattern or sequence of rotational speed changes, without performing calculations to determine the RPM of the detected voltage signals.

[0097] Referring to FIG. 18 , another embodiment of a relative rotation sensor 2010 is shown that also provides a signal to estimate the relative position between the rotating portion 2004 and the non-rotating portion 2002. The relative rotation sensor 2010 can include one or more coils 2100 disposed in the non-rotating portion 2002, as discussed in connection with the embodiment of FIG. 15 To estimate the relative position, the relative rotation sensor 2010 includes a magnetic device 2130 that produces a non-uniform magnetic field. By "non-uniform" it is meant that the magnetic field has a locally designed variation in magnetic field strength. By "designed" it is meant that the variation in the magnetic field is an intended feature and has predetermined characteristics or properties, as opposed to an accidental feature. In one arrangement, the variation in magnetic field strength can be obtained by varying the volume of magnetic material at a particular location compared to the volume of other magnetic material distributed over a portion of the rotating portion 2004. For example, the magnetic device 2130 can have a sector 2132 that does not have any magnetic material. Thus, the sector 2132 will have a weaker magnetic field than the magnetic field in the rest of the magnetic device 2130.

[0098] Referring to FIG. 19 , an illustrative voltage signal 2134 that can be generated by the embodiment of FIG. 18 is shown. Time (ms) is along the "X" axis, and voltage (V) is along the "Y" axis. FIG. 19 The voltage signal of FIG. 18 includes voltage oscillations caused by the local variation in magnetic field strength produced by the magnetic device 2130( FIG. 18 ). The voltage signal 2134 can have a segment 2136 associated with the sector 2132( ) where the voltage drops due to the weakened magnetic field, and a segment 2138 that is the baseline voltage attributable to the rest of the magnetic device 2130. Thus, when the segment 2134 is detected, the rotating portion 2004 has a known orientation or alignment relative to the non-rotating portion 2002.

[0099] Referring to FIG. 20 , another embodiment of a relative rotation sensor 2010 is shown that provides signals to estimate the relative position or rotation between the rotating portion 2004 and the non-rotating portion 2002 and other information. The relative rotation sensor 2010 can include one or more coils 2100 disposed in the non-rotating portion 2002 as discussed in connection with the embodiment of FIG. 15 The relative rotation sensor 2010 also includes a magnetic device 2140 located on the rotating portion 2004 and generating a non-uniform magnetic field. In this arrangement, the magnetic device 2140 can have two or more sectors 2142, 2144 in which the strength of the magnetic field is lower or higher than the strength of the adjacent magnetic field. As shown, the sectors 2142, 2144 are gaps that do not have magnetic material. Thus, the sectors 2142, 2144 will have a weaker magnetic field than the magnetic field in the rest of the magnetic device 2140. In one embodiment, the magnetic device 2140 includes a set of magnetic multipoles (e.g., magnetic dipoles, quadrupoles, etc.) distributed around the circumference of the rotating portion 2004, where the multipoles are arranged to produce a periodic pattern around the circumference of the rotating portion. The sectors 2142, 2144 include a magnetic field characteristic that is different from the periodic pattern of the magnetic multipoles.

[0100] Referring to FIG. 21 , an exemplary voltage signal 2150 that can be generated by the embodiment of FIG. 20 is shown. Time (ms) is along the "X" axis and voltage (V) is along the "Y" axis. The voltage signal 2152 can have a first segment 2154 associated with the sector 2142( FIG. 20 ) and a second segment 2156 associated with the sector 2144( FIG. 20) associated second segment 2156, where the voltage drops due to the weakened magnetic field or due to the lower frequency of the magnetic devices in sectors 2142, 2144. Thus, when a sector 2142, 2144 is detected, the rotating portion 2004 has a known orientation or alignment relative to the non-rotating portion 2002. Moreover, it will be appreciated that the distance or angular spacing between sectors 2142, 2144 is known, and the time between detection of sectors 2142, 2144 corresponding to the time between first segment 2154 and second segment 2156 can be determined. This information can be used to better assess downhole conditions and drilling dynamics. For example, detection of sectors 2142, 2144 can be used as a cross-check to verify the voltage signal. That is, if both sectors 2142, 2144 produce similar voltage signals at the expected time, it is more likely that accurate data is being obtained. Moreover, for a given rotational speed, the theoretical time gap between detection of sectors 2142, 2144 can be calculated. A difference in the measured time gap can be indicative of a drilling dysfunction, such as stick slip. As shown, sectors 2142, 2144 can be distributed asymmetrically, such that there is a different time gap between successive detections. That is, assuming rotation is clockwise, there is a shorter time gap from detection of sector 2144 to detection of sector 2142 due to the 90 degree angular spacing 2148, and a longer time gap from detection of sector 2142 to detection of sector 2144 due to the 270 degree angular spacing 2149. It will be appreciated that other embodiments can use three or more sectors, and / or these sectors can be distributed evenly with equal angular spacing or with unequal angular spacing. The gaps can have any angular value, not just the 90 degrees and 270 degrees depicted.

[0101] It will be appreciated that the teachings of the present disclosure are not limited to magnetic field reduction obtained by reducing the volume of the magnetic material (e.g., height, width, and / or depth of the magnetic elements). For example, options for using magnetic markers without weakening the magnetic field would include shaping the magnetic field output.

[0102] Referring to FIG. 22 An embodiment of a relative rotation sensor 2010 is shown that provides a signal to estimate the relative position between the rotating portion 2004 and the non-rotating portion 2002 using a Halbach array. By flipping the magnetic elements into a direction 90° from the adjacent magnetic elements, a non-uniform field is created that results in a magnetic field change in the form of a directed peak in the magnetic field strength at the Halbach array. The relative rotation sensor 2010 can include one or more coils 2100 disposed in the non-rotating portion 2002, as in the embodiment of FIG. 21, or in the rotating portion 2004, as in the embodiment of FIG. 22. The coils 2100 can be configured to detect the magnetic field changes and provide a signal indicative of the relative position between the rotating portion 2004 and the non-rotating portion 2002. FIG. 15embodiments discussed. Relative rotation sensor 2010 also includes a magnetic device 2160 located on rotating portion 2004 and generating a non-uniform magnetic field. In this arrangement, magnetic device 2140 can have sectors 2162 with magnets 2164 offset by 90° relative to adjacent magnets. Additionally, multiple sets of magnetic elements with a 90° offset relative to adjacent magnets can be used. Thus, sectors 2162 will have a magnetic field peak relative to the rest of magnetic device 2160. While FIG. 22 Using a technique with a 90° offset for adjacent magnets, other suitable techniques for shaping the magnetic field include, but are not limited to, alternating orientation or alternating magnetization of permanent magnets.

[0103] Referring to FIG. 23 , a voltage signal 2170 representing a constant RPM that can be generated by relative rotation sensor 2010 of FIG. 22 is shown. Time (ms) is along the "X" axis, and voltage (V) is along the "Y" axis. Voltage signal 2170 can have a nominal voltage amplitude 2172 during most of the rotation and a peak voltage amplitude 2174 associated with sectors 2162 FIG. 22 ) caused by offset magnets 2164 at sectors 2162 FIG. 22 ).

[0104] Referring to FIG. 24 , a voltage signal 2180 representing a transition from a higher RPM to a lower RPM that can be generated by relative rotation sensor 2010 of FIG. 22 is shown. A full rotation at both the higher RPM and the lower RPM is shown. As before, time (ms) is along the "X" axis, and voltage (V) is along the "Y" axis. Voltage signal 2180 can have a first section 2182 related to a given rotational speed and a second section 2184 related to a relatively lower rotational speed. First section 2182 has a greater voltage amplitude and a shorter period than second section 2184 due to the relatively higher rotational speed. In addition, voltage peaks 2188 are generated due to the Halbach array at sectors 2162 FIG. 22 ), providing an instantaneous indication of the relative orientation between rotating portion 2004 and non-rotating portion 2002, as described previously. While for the first rotational speed, the magnetic peak or feature will occur, for example, once every 600 ms, for the second rotational speed, the marker feature will occur once every 1200 ms.

[0105] Alternatively, dedicated sensor elements can be used to detect the instantaneous position between rotating and stationary components. See, for example, FIG. 25The sensor assembly 2200 can include a sensor element 2202 on the non- rotating sleeve 2002 and a trigger element 2204 on the rotating portion 2004. One or more biasing elements 2006 can be positioned on the non-rotating sleeve 2002. The sensor element 2202 can use a variety of interactions to detect the proximity of the trigger element 2204; for example, physical contact, electrical interaction, magnetic interaction, etc. In practice, this interaction results in a "mark" that occurs once per rotation. For simplicity, this will be referred to as a "single mark." A non-limiting example can be a Hall sensor for the sensor element 2202 and a magnetic element for the trigger element 2204. However, it should be understood that different types of sensing elements and corresponding trigger elements can also be used.

[0106] According to FIG. 18 , FIG. 20 , FIG. 22 , FIG. 25 The previously described relative rotation sensor 2010 and the configuration shown in FIG. 25 allow for detection of the instantaneous position of the rotating portion 2004 relative to the non-rotating portion 2002. The instantaneous relative position can also be used to calculate the number of revolutions over a period of time (rpm measurement). This signal can be used alone for the downhole command method described above (e.g., according to FIG. 13A to FIG. 13D ), or as a combined verification that supports alternating voltage detection. For applications that establish sensor communication between a rotating MWD and a non-rotating portion (e.g., as described above FIG. 1 to FIG. 10 ), the instantaneous relative position can be used to synchronize measurements from the rotating portion 2004 and the non-rotating portion 2002. Such synchronized measurements can also be used for formation evaluation, dynamics, direction, and other measurements that benefit from combining content from the rotating and non-rotating portions. In certain embodiments, an MWD sensor on a rotating portion of a drill string and a processor configured to calculate a steering vector using the identified instantaneous relative position between the drive shaft and the sleeve and information from the MWD sensor.

[0107] Referring to FIG. 26 , a non-limiting method 2300 of transmitting a command signal from a surface location to one or more components on a non-rotating sleeve without using traditional communication devices such as a transmitter and receiver is shown. The method can be performed in conjunction with the systems and devices described above, but is not limited thereto. The method includes one or more stages or steps described below. In one embodiment, the method includes performing all stages in the order listed. However, certain stages can be omitted, stages can be added, or the order of stages can be changed.

[0108] In preparation for performing the method 2300, a drilling assembly connected to a drill string is deployed into a borehole, for example, as part of an LWD or MWD operation. Thereafter, the drilling assembly is operated by rotating a drive shaft and drill bit via surface or downhole means. In one embodiment, the drive shaft (rotating portion) is encircled by a non-rotating sleeve (non-rotating portion) that includes one or more modules housing and at least partially enclosing one or more biasing elements. In another embodiment, one or more modules are included in the rotating portion of the BHA. One or more components in each module are powered via an energy storage device and / or an energy transfer / receiving device, such as a coil that receives an alternating magnetic field, an inductive coupler, an inductive transformer, an inductive power device, a movable magnet, a mechanical coupling, or a magnetic coupling that converts mechanical energy from the flow of drilling fluid, rotation of the drive shaft, or vibrations of the BHA into electrical energy to power control devices, sensors, and / or actuation devices of the biasing elements.

[0109] In a first stage 2310, to induce relative rotation of the drive shaft and the non-rotating sleeve, initial friction between the non-rotating sleeve and an adjacent surface (which can be the borehole wall or the inner surface of a wellbore tubular) can be created by initial actuation or expansion of one or more biasing elements. For example, friction between the biasing elements and the borehole wall can be increased to a level that is close to or even higher than the friction of the bearing, thereby creating an initial resistance to rotation of the non-rotating sleeve relative to the borehole wall, and thus inducing relative rotation between the drive shaft and the non-rotating sleeve. Alternatively or additionally, a non-rotating element can be used to physically contact the adjacent surface and create the required friction to allow relative rotation. The relative rotation enables the energy receiving device to convert energy from the rotation of the drill string into energy for operating the biasing elements, controllers, electronics, sensors, or to charge the energy storage device. The energy storage device can also be recharged by the energy receiving device during operation of the steering assembly.

[0110] Such biasing elements configured to be initially expanded or actuated to increase friction between the non-rotating sleeve and the borehole wall can be at least one of a sliding pad, an electrified roller, a spring, a blade, or a rotating lever. The biasing elements configured to be initially expanded or actuated to increase friction between the non-rotating sleeve and the borehole wall can be active elements that require an external supply of energy or passive elements that can be actuated or expanded without an external supply of energy, such as, for example, a spring. If the initial expansion or actuation of the biasing elements is provided by an active element, the energy required to expand / actuate the biasing elements by the active element can be provided by an energy storage device, such as a capacitor, a supercapacitor, a battery, a fuel cell, or a rechargeable battery. Such energy storage devices can also be used to power controllers or sensors within the module.

[0111] In the second phase 2320, a decision to adjust the borehole direction is made. The decision can be made by a human, by a machine, or a combination of the two. The decision is converted into a downhole command signal or command signal having a unique signature / pattern of drill string rotation speed at different speeds and associated durations as previously discussed. The surface and downhole equipment are operated to manipulate the drill string rotation to obtain the unique signature / pattern. In the case of a mud motor, the surface rpm will be superimposed by the downhole rpm generated by the mud motor. Since the mud motor rpm is a function of the rate of drilling fluid flow pumped through the surface assembly 22, the superimposed rotation speed of the rotating portion 2004 relative to the non-rotating portion 2002 is controlled by the surface flow rate and the surface rpm. The command signal signature / pattern sent from the surface to the downhole tool is a change in the surface rpm and / or the rate of drilling fluid flow of the BHA including the mud motor.

[0112] In the third phase 2330, the controller on the non-rotating sleeve detects the changes in drill string rotation and uses the relative rotation sensor to detect the unique signature of the drill string rotation changes. As previously discussed, the sensor can generate a voltage signal representative of these drill string rotation changes. The controller can utilize a preprogrammed lookup table or other database to determine the desired action associated with the detected unique signature. The desired action can be to change the drilling direction, or other action. The controller on the non-rotating sleeve also uses information from the orientation sensor to estimate the orientation or position of the non-rotating sleeve relative to a predetermined reference frame. This information can be used to set the orientation of the non-rotating sleeve relative to the predetermined reference frame and identify which biasing element(s) should be actuated in order to obtain the desired change in drilling direction.

[0113] In certain embodiments, the MWD sensor on the rotating portion of the drill string and a processor configured to use the identified instantaneous relative position between the drive shaft and the sleeve and information from the MWD sensor to calculate a steering vector. The instantaneous relative position can also be used to synchronize measurements from the rotating portion 2004 and the non-rotating portion 2002. Such synchronized measurements can be used for formation evaluation, dynamics, direction, and other measurements that beneficially combine content from the rotating and non-rotating portions.

[0114] In the fourth phase 2340, the controller actuates the biasing element, for example to contact the borehole wall. For example, the controller can operate an actuator to adjust the force applied by the biasing element(s) and / or adjust the physical position of the biasing element(s). In this manner, the biasing element is controlled to control the direction of the drilling assembly.

[0115] Some embodiments of the foregoing disclosure are illustrated below:

[0116] One non-limiting embodiment described above includes an apparatus for use in a wellbore. The apparatus can include a non-rotating portion and a non-rotating portion disposed along a drill string. The non-rotating portion has a bore and at least one biasing element that engages with a wellbore wall. A rotating portion is disposed in the bore of the non-rotating portion. The apparatus further includes at least one relative rotation sensor configured to generate a signal indicative of rotation of the rotating portion relative to the non-rotating portion; and at least one orientation sensor within the non-rotating portion configured to generate a signal indicative of an orientation of the non-rotating portion relative to a selected frame of reference; and a controller. The apparatus further includes the controller in signal communication with the at least one relative rotation sensor and the at least one orientation sensor. The controller is configured to adjust at least one of (i) a force exerted by the at least one biasing element, and (ii) a position of the at least one biasing element, responsive to the generated signal from the at least one relative rotation sensor indicative of rotation of the rotating portion relative to the non-rotating portion and the generated signal from the at least one orientation sensor indicative of an orientation of the non-rotating portion relative to the selected frame of reference.

[0117] One non-limiting embodiment of a method using the apparatus described above can include disposing a drill string in a wellbore, the drill string including the apparatus described above. The method can further include the steps of changing a rotational speed of the rotating portion to send a control signal; determining the control signal using the controller by detecting a rotational frequency change using the at least one relative rotation sensor; receiving energy from rotation of the rotating portion within the non-rotating portion, and controlling the force and / or position of the at least one biasing element using the determined control signal and the generated signal from the at least one orientation sensor indicative of an orientation of the non-rotating portion relative to the selected frame of reference.

[0118] Various analyses and / or analysis components can be used in conjunction with the teachings herein, including digital and / or analog subsystems. The system can have components such as processors, storage media, memory, inputs, outputs, communications links (wireless, wired, pulsed mud, optical, etc.), user interfaces, software programs, signal processors, and the like, used in the operation and analysis of the devices and methods disclosed herein, in any of a variety of ways. It is contemplated that these teachings can be implemented in a variety of ways, including but not limited to software, hardware, firmware, and the like. These teachings can be provided as one or more computer-readable storage media having stored computer-executable instructions that, when executed by one or more computers, cause the computers to carry out the methods described herein. The computer-executable instructions can be in any suitable form, including but not limited to high-level, interpreted, or machine code, depending on the desires of the programmer. The computer-executable instructions can be provided as one or more programs, which can be stored in any suitable computer readable medium and which can be executed by one or more computers to provide the functionality described herein. The computer-readable storage media can be transportedable, such that the one or more programs stored thereon can be loaded into and executed by various different types of computers.

[0119] Those skilled in the art will recognize that a variety of components or technologies can provide certain necessary or beneficial functionality or features. Thus, the functionality and features supported by the claims and their variants below are considered inherent in the invention as part of the teachings herein and disclosed.

[0120] While the present invention has been described with reference to example embodiments, it will be understood by those skilled in the art that various changes can be made and equivalents can be substituted for elements thereof without departing from the scope of the present invention. In addition, many modifications can be made to adapt a particular instrument, situation, or material to the teachings of the present invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed as the best currently contemplated mode of carrying out the invention.

Claims

1. An apparatus for use in a wellbore, the apparatus comprising: a drill string (12) configured to drill the wellbore; a non-rotating portion (2002) disposed along the drill string (12), the non-rotating portion (2002) having a bore (2090) and at least one biasing element (2006) that engages a wall of the wellbore, the apparatus characterized by: - a rotating portion (2004) disposed in the bore (2090) of the non-rotating portion (2002); -- at least one relative rotation sensor (2010) configured to generate a signal representative of rotation of the rotating portion (2004) relative to the non-rotating portion (2002); - at least one orientation sensor (2008) within the non-rotating portion (2002), the at least one orientation sensor configured to generate a signal representative of an orientation of the non-rotating portion (2002) relative to a selected frame of reference; and - a controller (88, 2012) in signal communication with the at least one relative rotation sensor (2010) and the at least one orientation sensor (2008), the controller (88, 2012) configured to adjust at least one of (i) a force exerted by the at least one biasing element (2006) and (ii) a position of the at least one biasing element (2006), the adjustment responsive to the generated signal from the at least one relative rotation sensor (2010) representative of rotation of the rotating portion (2004) relative to the non-rotating portion (2002) and the generated signal from the at least one orientation sensor (2008) representative of an orientation of the non-rotating portion (2002) relative to a selected frame of reference, wherein the at least one biasing element is powered using energy received within the non-rotating portion from the rotation of the rotating portion.

2. The apparatus of claim 1, further characterized by a plurality of anti-rotation elements (2094) configured to prevent rotation of the rotating portion (2004) relative to the wall of the wellbore.

3. The apparatus of claim 1, further characterized by The generated signal representative of the rotation of the rotating portion (2004) relative to the non-rotating portion (2002) includes a characteristic representative of the rotation of the rotating portion (2004) relative to the non-rotating portion (2002), the characteristic being at least one of (i) a frequency, (ii) an amplitude, (iii) a period, and (iv) a single token.

4. The apparatus of claim 1, further characterized by The generated signal indicative of the rotation of the rotating portion (2004) relative to the non-rotating portion (2002) is associated with at least one control signal transmitted from a surface location, and wherein the controller (88, 2012) is configured to determine the at least one control signal by processing the signal generated by the at least one relative rotation sensor (2010) indicative of the rotation of the rotating portion (2004) relative to the non-rotating portion (2002).

5. The apparatus of claim 1, further characterized by The at least one relative rotation sensor (2010) comprises at least one magnet element (2110) that generates a magnetic field, wherein the at least one relative rotation sensor (2010) senses a signal indicative of a relative rotation between the rotating portion (2004) and the non-rotating portion (2002).

6. The apparatus of claim 5, further characterized by The at least one relative rotation sensor (2010) further generates and supplies power using the magnetic field of the at least one magnet element (2110).

7. The apparatus of claim 5, further characterized by The at least one magnet element (2110) comprises a plurality of magnet elements (2110) arranged on the rotating portion (2004).

8. The apparatus of claim 7, further characterized by The plurality of magnet elements (2110) are arranged in a periodic pattern around at least a portion of a circumference of the rotating portion (2004).

9. The apparatus of claim 1, further characterized by: A standalone module (2020) comprising the relative rotation sensor (2010), the orientation sensor (2008), the controller (88, 2012), and the biasing element (2006), wherein the standalone module (2020) is electrically isolated from the non-rotating portion (2002).

10. The apparatus of claim 9, further characterized by The standalone module (2020) comprises a wireless communication unit (2021), and wherein the standalone module (2020) communicates via the wireless communication unit (2021).

11. The apparatus of claim 6, further characterized by A standalone module (2020) comprising the relative rotation sensor (2010), the orientation sensor (2008), the controller (88, 2012), and the biasing element (2006), wherein the standalone module is powered using the magnetic field of the magnet element (2110).

12. The apparatus of claim 11, further characterized by The standalone module (2020) comprises a power source that powers the controller (88, 2012) and / or the biasing element (2006).

13. A method of using an apparatus in a wellbore, the method comprising: providing a drill string (12) in the wellbore, the drill string (12) being configured to drill the wellbore, wherein the drill string (12) comprises: a non-rotating portion (2002) provided along the drill string (12), the non-rotating portion (2002) having a bore (2090) and at least one biasing element (2006) configured to engage a wall of the wellbore, a rotating portion (2004) provided in the bore (2090) of the non-rotating portion (2002), at least one relative rotation sensor (2010) configured to generate a signal representative of a relative rotation between the rotating portion (2004) and the non-rotating portion (2002), at least one orientation sensor (2008) in the non-rotating portion (2002) and configured to generate a signal representative of an orientation of the non-rotating portion (2002) relative to a selected frame of reference, and a controller (88, 2012) in signal communication with the at least one relative rotation sensor (2010) and the at least one orientation sensor (2008); varying a rotational speed of the rotating portion (2004) to send a control signal; using the controller (88, 2012) to determine the control signal using the at least one relative rotation sensor (2010); receiving energy within the non-rotating portion (2002) from the rotation of the rotating portion (2004); and controlling a force and / or position of the at least one biasing element (2006) by using the determined control signal and the generated signal from the at least one orientation sensor (2008) representative of the orientation of the non-rotating portion (2002) relative to a selected frame of reference, wherein at least one of the determination of the control signal and the control of the force and / or the position is performed using the received energy.

14. The method of claim 13, further characterized by The at least one relative rotation sensor (2010) includes at least one magnet element (2110) that generates a magnetic field.

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