Downhole actuation system and method with dissolvable ball bearings

Abstract

A system and method for indicating a device in a wellbore of an underground well includes a drill string having an actuator assembly extending underground. The actuator assembly has a first tubular member having a segment formed of a first material. A second tubular member is coaxially aligned with the first tubular member. A plurality of bearings are positioned between the first tubular member and the second tubular member. Each of the plurality of bearings includes a second material. The first material is reactive to the second material. Some of the plurality of bearings are variable bearings including a dissolvable material. The actuator assembly is operable to indicate the operation of the device by generating a command signal, the command signal being generated by rotating the first tubular member relative to the second tubular member and interpreting a pattern of the reaction of the segment when the bearing rotates through the segment.

Description

Technical Field

[0001] The present disclosure relates generally to subterranean well development, and more particularly to actuation and sensing systems for collecting downhole information. Background Art

[0002] When drilling a subterranean well, the operator cannot directly observe the trajectory of the wellbore and the downhole environment. In addition, once tools, instruments, equipment and other devices are lowered into the wellbore, they cannot be accessed from the surface. Conventional techniques for controlling downhole tools or instruments or devices from the surface include mechanical methods such as applying weight-on-bit and turning the drill string components, applying pressure and throwing a ball, or hydraulic methods such as fluid pressure circulation and flow pressure circulation.

[0003] Radio frequency identification ("RFID") based systems have also been developed for drilling applications. An RFID tag is programmed with a unique code at the surface, lowered into the well and travels down the wellbore with the flow of drilling fluid. Downhole devices such as bypass valves, reamers or packers are integrated with an RFID reader. The RFID reader consists of a battery, electronics and antenna that are enclosed for protection. When the RFID tag and the reader's antenna are in proximity to each other, the RFID tag is excited by the reader's antenna. The antenna continuously generates a radio frequency field to "listen" for the RFID tag. The reader has the ability to respond only to specific identification codes and ignore other codes, and also has the ability to eliminate duplicate operations by accepting a unique code only once. The biggest advantage of RFID based systems is that they have no restrictions on the inner diameter of the drill string compared to the process commonly used to activate bypass valves (involving dropping an activation ball). RFID systems enable remote activation and no restrictions on the interior of the drill string, resulting in a larger flow area for drilling fluids, allowing any logging instrument to pass through the drill string without restriction. Summary of the invention

[0004] Mechanical and hydraulic methods of indicating downhole devices present certain limitations and potential challenges or problems to the drilling process. For example, actuation systems that involve dropping an activation ball to open a side port require pressure to be applied from the surface, which can damage downhole components. Such systems also require additional trips down the wellbore to remove the ball from the drill string assembly or to ream the ball.

[0005] RFID systems have disadvantages. For example, RFID systems require that the drilling fluid flow for the RFID tag travel through the drill string assembly and toward the RFID reader to activate or deactivate the downhole device. In addition, the RFID tag must be in the correct or optimized orientation when the unique identification number and specific instructions of the RFID tag are sent to the RFID reader through the RFID reader antenna. In addition, once the RFID tag is dropped from the ground, the tag cannot be controlled from the ground, and multiple RFID tags need to be deployed down the drill string for multiple activation / deactivation operations. The RFID reader antenna takes up space in the drill pipe and may also be contaminated by debris from the drilling fluid. In addition, the RFID reader antenna is always in the open state because it must "listen" for the RFID tag signal. Operations cannot be stopped or started immediately as needed because another RFID tag must be deployed to activate, deactivate or reset the downhole device, and the timing of activation or deactivation will depend on the time it takes for the RFID tag to arrive near the RFID reader.

[0006] The disclosed systems and methods of the present invention overcome the deficiencies of both currently available mechanical and RFID systems. The disclosed systems and methods of the present invention can communicate with downhole devices in real time and transmit command signals to the downhole devices. The disclosed embodiments of the present invention provide a downhole actuation system that can be controlled from the ground to actuate digitally enabled downhole devices, such as tools and instruments. The actuation of these different devices enables the execution of discrete drilling workflows. The actuation system is a separate system that can be seamlessly integrated with the downhole devices so that it does not replace the existing drilling assembly.

[0007] In a disclosed embodiment of the invention, a set of signal images are created and interpreted by digital logic, which is then converted to send specific signals to activate or deactivate specific devices. An initial set of ball bearings for the system is used to generate a first set of signals to be interpreted as a first set of instructions to the downhole devices. Then, the dissolvable material used to form certain bearings can be dissolved to generate different sets of signals that will be interpreted as different instructions to the devices, or can be used to instruct different devices to perform other functions downhole.

[0008] In a disclosed embodiment of the present invention, a system for indicating a device in a wellbore of an underground well includes a drill string extending from the ground into the underground well. The drill string has an actuator assembly. The actuator assembly has a first tubular member having a segment formed of a first material. The second tubular member is coaxially aligned with the first tubular member. A plurality of bearings are positioned between the first tubular member and the second tubular member. Each of the plurality of bearings includes a second material. The first material is reactive to the second material. At least one of the plurality of bearings is a variable bearing including a dissolvable material. The actuator assembly is operable to indicate the operation of the device by generating a command signal, the command signal being generated by rotating the first tubular member relative to the second tubular member and interpreting a pattern of the reaction of the segment when the plurality of bearings rotate through the segment.

[0009] In alternative embodiments, the variable bearing may have an outermost layer of a dissolvable material, and the dissolvable material may be a second material. The variable bearing may include a core bearing formed of an electrically insulating material, the core bearing being coated with an outermost layer of a dissolvable material. Alternatively, the entire variable bearing may be formed of a dissolvable material. Alternatively, the variable bearing may include a core bearing formed of a second material, the core bearing being coated with an outermost layer of a dissolvable polymer, the dissolvable polymer being a dissolvable material and being non-reactive to the first material.

[0010] In other alternative embodiments, the plurality of bearings may include a side bearing, and the segment may be located on the outer diameter surface of the first tubular member and axially aligned with the side bearing. The side bearing may be located between the outer diameter surface of the first tubular member and the inner diameter surface of the second tubular member. Alternatively, the plurality of bearings may include a side bearing, and the segment may be located on the inner diameter surface of the first tubular member and axially aligned with the side bearing. The side bearing may be located between the inner diameter surface of the first tubular member and the outer diameter surface of the second tubular member.

[0011] In other alternative embodiments, the system may further include a support member extending radially inward from the inner diameter surface of the second tubular member. The support member may support the first tubular member within the central bore of the second tubular member. The plurality of bearings may include an end bearing, and the segment may be positioned at the end surface of the first tubular member and radially aligned with the end bearing. The end bearing may be located between the end surface of the first tubular member and the support member, which is fixed to the second tubular member and extends radially from the second tubular member.

[0012] In yet other alternative embodiments, the actuator assembly may further include a digital logic circuit configured to receive and interpret the pattern of the reaction of the segment as the plurality of bearings rotate past the segment and generate a command signal. The second tubular member is operable to rotate with the drill string, and the first tubular member may be located within and surrounded by the second tubular member. Alternatively, the second tubular member is operable to rotate with the drill string, and the first tubular member may surround the second tubular member.

[0013] In an alternative embodiment of the disclosure of the present invention, a method for indicating a device within a wellbore of a subterranean well includes extending a drill string from the ground into the subterranean well. The drill string includes an actuator assembly having a first tubular member having a segment formed of a first material. A second tubular member is coaxially aligned with the first tubular member. A plurality of bearings are positioned between the first tubular member and the second tubular member. Each of the plurality of bearings includes a second material, wherein the first material is reactive to the second material. At least one of the plurality of bearings is a variable bearing including a dissolvable material. The method further includes using the actuator assembly to indicate the operation of the device by generating a command signal, the command signal being generated by rotating the second tubular member relative to the first tubular member and interpreting a pattern of the reaction of the segment when the plurality of bearings rotate through the segment.

[0014] In an alternative embodiment, the method may further include dissolving the dissolvable material and indicating subsequent operation of the device using the actuator assembly by generating a correction indication signal, the correction indication signal being generated by rotating the second tubular member relative to the first tubular member and interpreting the correction pattern of the reaction of the segment when the plurality of bearings rotate through the segment. The variable bearing may have an outermost layer of a dissolvable material and a core bearing formed of an electrically insulating material. The dissolvable material may be a second material, and dissolving the dissolvable material may include dissolving the outermost layer of the dissolvable material so that the variable bearing is non-reactive to the first material. Alternatively, the entire variable bearing may be formed of a dissolvable material, wherein the dissolvable material is a second material, and dissolving the dissolvable material may include dissolving the entire variable bearing. Alternatively, the variable bearing may include a core bearing formed of a second material, the core bearing being coated with an outermost layer of a dissolvable polymer, the dissolvable polymer being a dissolvable material and being non-reactive to the first material, and dissolving the dissolvable material may include dissolving the outermost layer of the dissolvable material so that the variable bearing is reactive to the first material.

[0015] In other alternative embodiments, the plurality of bearings may include a side bearing, and the segment may be located on the outer diameter surface of the first tubular member and aligned axially with the side bearing. The side bearing may be located between the outer diameter surface of the first tubular member and the inner diameter surface of the second tubular member, and the pattern explaining the reaction of the segment when the plurality of bearings rotates through the segment may include explaining the reaction of the segment when the side bearing rotates through the segment. As an alternative, the plurality of bearings may include a side bearing, and the segment may be located on the inner diameter surface of the first tubular member and aligned axially with the side bearing. The side bearing may be located between the inner diameter surface of the first tubular member and the outer diameter surface of the second tubular member, and the pattern explaining the reaction of the segment when the plurality of bearings rotates through the segment may include explaining the reaction of the segment when the side bearing rotates through the segment.

[0016] In yet other alternative embodiments, the method may further include supporting the first tubular member within the central bore of the second tubular member using a support member extending radially inward from the inner diameter surface of the second tubular member. The plurality of bearings may include an end bearing, and the segment may be positioned at the end surface of the first tubular member and radially aligned with the end bearing. The end bearing may be located between the end surface of the first tubular member and a support member fixed to and extending radially from the second tubular member. The pattern of explaining the reaction of the segment when the plurality of bearings rotates past the segment may include explaining the reaction of the segment when the end bearing rotates past the segment.

[0017] In still other alternative embodiments, the actuator assembly may further include a digital logic circuit, and the method may further include receiving and interpreting a pattern of responses of the segment as the plurality of bearings rotate past the segment, and generating a command signal using the digital logic circuit. The second tubular member may rotate with the drill string, and the first tubular member may be located within and surrounded by the second tubular member, wherein rotating the second tubular member relative to the first tubular member may include rotating the drill string. Alternatively, the second tubular member may rotate with the drill string, and the first tubular member may surround the second tubular member, wherein rotating the second tubular member relative to the first tubular member may include rotating the drill string. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] In order to obtain and understand in detail the above-mentioned features, aspects and advantages of the disclosure of the present invention, as well as other features, aspects and advantages that will become apparent, a more specific description of the disclosed embodiments of the present invention briefly summarized above can be obtained by reference to the disclosed embodiments of the present invention shown in the accompanying drawings forming a part of this specification. However, it should be noted that the accompanying drawings only illustrate certain embodiments of the disclosure of the present invention and therefore should not be considered as limiting the scope of the disclosure of the present invention, as the disclosure of the present invention may allow for other equivalent embodiments.

[0019] Figure 1is a cross-sectional view of a subterranean well having a drill string with an actuator assembly and a sensor compartment in accordance with a disclosed embodiment of the present invention.

[0020] Figure 2 is a cross-sectional view of an actuator assembly according to a disclosed embodiment of the present invention.

[0021] Figure 3 is a cross-sectional view of an actuator assembly according to a disclosed alternative embodiment of the present invention.

[0022] Figure 4 is a perspective view of a second tube member of an actuator assembly according to a disclosed embodiment of the present invention.

[0023] Figure 5 is a perspective view of a first tube member of an actuator assembly according to a disclosed embodiment of the present invention.

[0024] Figure 6 is a schematic representation of a signal pattern generated by an actuator assembly according to a disclosed embodiment of the present invention, showing a drill rod rotating in a single direction.

[0025] Figure 7 is a schematic representation of the digital logic circuitry of an actuator assembly in accordance with a disclosed embodiment of the present invention.

[0026] Figure 8 is a schematic representation of the digital logic circuitry of an actuator assembly in accordance with a disclosed alternative embodiment of the present invention.

[0027] Fig. 9 is a schematic representation of a continuous signal image generated by an actuator assembly according to a disclosed embodiment of the present invention, showing rotation of a drill rod in both counterclockwise and clockwise directions.

[0028] Fig.10 is a front view of a bearing assembly of an actuator assembly according to a disclosed embodiment of the present invention.

[0029] Fig.11 is a schematic representation of a continuous signal image generated by an actuator assembly according to an alternative embodiment of the disclosure of the present invention, showing rotation of a drill rod in both counterclockwise and clockwise directions.

[0030] Fig.12 is a schematic representation of a continuous signal image generated by an end bearing of an actuator assembly according to a disclosed alternative embodiment of the present invention, showing the drill rod rotating in a counterclockwise direction.

[0031] Fig.13is a schematic representation of a continuous signal image generated by an end bearing of an actuator assembly according to a disclosed alternative embodiment of the present invention, showing the drill rod rotating in a clockwise direction.

[0032] Fig.14 is a cross-sectional view of an actuator assembly according to a disclosed embodiment of the present invention, showing a variable bearing.

[0033] Fig.15 is a cross-sectional view of an actuator assembly according to a disclosed embodiment of the present invention, showing the variable bearing after it has been dissolved.

[0034] Fig.16 is a cross-sectional view of a variable bearing of an actuator assembly according to a disclosed embodiment of the present invention.

[0035] Fig.17 is a cross-sectional view of a variable bearing of an actuator assembly according to a disclosed alternative embodiment of the present invention.

[0036] Fig.18 is a schematic representation of a signal image generated by an actuator assembly according to a disclosed embodiment of the present invention, showing the drill rod rotating in a single direction and showing a variable bearing.

[0037] Fig.19 is a schematic representation of an image of signals generated by an actuator assembly according to a disclosed embodiment of the present invention, showing the drill rod rotating in a single direction and after the variable bearing has been dissolved.

[0038] Fig. 20 is a schematic representation of an image of signals generated by an actuator assembly according to an alternative embodiment of the disclosure of the present invention, showing the drill rod rotating in a single direction and showing a variable bearing.

[0039] Fig.21 is a schematic representation of a signal image generated by an actuator assembly according to a disclosed embodiment of the present invention, showing the drill rod rotating in a single direction and after the variable material of the variable bearing has been dissolved.

[0040] Fig. 22 is a schematic representation of an exemplary application of an actuation assembly according to a disclosed embodiment of the present invention.

[0041] FIG. 23A to FIG. 23C is a cross-sectional view of the operation of an actuation assembly according to a disclosed embodiment of the present invention.

[0042] Fig.24 is a schematic diagram of a downhole actuation system that may be controlled from the surface to actuate a digitally enabled downhole device, according to one or more exemplary embodiments. DETAILED DESCRIPTION

[0043] This specification, including the summary of the invention, the accompanying drawings and the detailed description of the embodiments, and the appended claims relate to specific features (including process or method steps) disclosed in the present invention. It should be understood by those skilled in the art that the disclosure of the present invention includes all possible combinations and uses of the specific features described in this specification. It should be understood by those skilled in the art that the disclosure of the present invention is not limited to or by the description of the embodiments given in this specification. The subject matter of the present invention is not subject to any limitation, only to the spirit of this specification and the appended claims.

[0044] It will also be understood by those skilled in the art that the terms used to describe specific embodiments do not limit the scope or breadth of the disclosure of the present invention. When interpreting this specification and the appended claims, all terms should be interpreted in the broadest possible manner consistent with the context of each term. Unless otherwise defined, all technical and scientific terms used in this specification and the appended claims have the same meanings as those of ordinary skill in the art to which the disclosure of the present invention relates.

[0045] As used in this specification and the appended claims, the singular forms "a", "an", and "the" include plural references unless the context clearly indicates otherwise. As used, the words "comprise", "have", "include", and all other grammatical variations are each intended to have an open, non-restrictive meaning that does not exclude additional elements, components, or steps. The disclosed embodiments of the present invention may appropriately "comprise", "consist of", or "consist of" the disclosed limiting features, and may be practiced in the absence of undisclosed limiting features. For example, those skilled in the art may recognize that certain steps may be combined into a single step.

[0046] Spatial terms describe the relative position of one object or group of objects relative to another object or group of objects. Spatial relationships apply along vertical and horizontal axes. Orientation and related words including "uphole" and "downhole", "above" and "below" and other similar terms are for descriptive convenience and are not limiting unless otherwise indicated.

[0047] Where a numerical range is provided in this specification or the appended claims, it is understood that the interval encompasses the upper and lower limits and every intervening value therebetween. The disclosure of the invention encompasses and defines the smaller ranges of the interval subject to any specific exclusion provided.

[0048] When this specification and the appended claims refer to a method comprising two or more defined steps, these defined steps may be performed in any order or simultaneously, unless the context excludes this possibility.

[0049] See also Figure 1 , a subterranean well 10 may have a wellbore 12 extending into the earth's surface or ground 14. The subterranean well 10 may be an offshore well or a land-based well and may be used to produce hydrocarbons from a subterranean hydrocarbon reservoir or may otherwise be associated with hydrocarbon development activities.

[0050] A drill string 16 may extend into and be located within the wellbore 12. An annulus 8 is defined between the outer diameter surface of the drill string 16 and the inner diameter of the wellbore 12. The drill string 16 may include a series of pipe joints and a bottom hole assembly 20. The pipe joints may extend from the surface 14 into the underground well 10. The bottom hole assembly 20 may include, for example, drill collars, stabilizers, reamer, percussion drill, drill bit shorting, and drill bit. The drill string 16 may be used to drill the wellbore 12. The drill string 16 has a column bore 28, which is a central hole extending along the length of the drill string 16. The drill string 16 may be rotated to rotate the drill bit to drill the wellbore 12.

[0051] The drill string 16 may further include an actuator assembly 22 and a device 24. The actuator assembly and the device 24 may be installed as a drilling sub as part of the drill string assembly. Figure 1 In the exemplary embodiment of the present invention, the actuator assembly 22 is shown extending radially into the column bore 28 of the drill string 16. In an alternative embodiment, the actuator assembly 22 can be located on the outer diameter surface of the drill string 16. Figure 1 In the exemplary embodiment of the present invention, the device 24 is fixed to align with the joint of the drill string 16. In alternative embodiments, the device 24 can extend radially into the column hole 28 of the drill string 16, or can extend radially outward from the drill string 16.

[0052] See also Figure 2 and Figure 3 , the actuator assembly 22 is a tubular actuator assembly having an actuator bore 30. The actuator assembly 22 may be secured to the wellbore downside end of the joint of the drill string 16. The actuator assembly 22 has an actuator bore 30 extending axially along the length of the actuator assembly 22. Drilling fluid may flow through the drill string 16, including through the actuator assembly 22, out of the drill bit, up the annulus 18, and back to the surface 14.

[0053] The actuator assembly 22 includes a first tubular member 32 and a second tubular member 34. The first tubular member 32 and the second tubular member are coaxially oriented. The second tubular member 34 can be fixed to the wellbore lower end of the joint of the drill string 16 so that the second tubular member 34 rotates with the drill string 16. The second tubular member 34 can have a diameter that is substantially similar or the same as the diameter of the adjacent joint of the drill string 16. The first tubular member 32 can be supported by the second tubular member 34. The first tubular member 32 can be supported, for example, between a wellbore upper support 36 and a wellbore lower support 38. The wellbore upper support 36 and the wellbore lower support 38 can extend radially from the second tubular member 34.

[0054] exist Figure 2 In the embodiment of the present invention, the actuator hole 30 is smaller than the column hole 28 of the adjacent joint of the drill string 16 and defines a fluid flow path through the actuator assembly 22. The diameter of the first tubular member 32 is smaller than the diameter of the second tubular member 34. The second tubular member 34 surrounds the first tubular member 32. The wellbore upper side support 36 and the wellbore lower side support 38 extend radially inward from the inner diameter surface of the second tubular member 34.

[0055] exist Figure 3 In the embodiment of the present invention, the actuator bore 30 has a substantially similar diameter to the column bore 28 of the adjacent joint of the drill string 16 and defines a fluid flow path through the actuator assembly 22. The diameter of the first tubular member 32 is greater than the diameter of the second tubular member 34. The first tubular member 32 surrounds the second tubular member 34. The wellbore upper support 36 and the wellbore lower support 38 extend radially outward from the outer surface of the second tubular member 34.

[0056] See also Figures 2 to 3 , a plurality of bearings 40 may be positioned between the first tubular member 32 and the second tubular member 34. The bearings 40 may be ball bearings. The end bearings 42 may be located between the end surface of the first tubular member 32 and the support member. As an example, the end bearings 42 may be located between the wellbore upper end of the first tubular member 32 and the wellbore upper support 36. The end bearings 42 may alternatively be located between the wellbore lower end of the first tubular member 32 and the wellbore lower support 38. The bearings 40 may rotate with the second tubular member 34 about the central axis of the second tubular member 34. As an example, the bearings 40 may be held together with the second tubular member 34 by conventional bearing retaining devices.

[0057] The side bearing 44 is located between the first tube member 32 and the second tube member 34. Figure 2 In an exemplary embodiment of the present invention, the side bearing 44 may be located between the outer diameter surface of the first tubular member 32 and the inner diameter surface of the second tubular member 34. The side bearing 44 rotates around the outer diameter surface of the first tubular member 32 together with the second tubular member 34. Figure 3In an exemplary embodiment of the present invention, the side bearing 44 can be located between the outer diameter surface of the second tubular member 34 and the inner diameter surface of the first tubular member 32. The side bearing 44 can also be located radially outside the first tubular member 32 within the bearing housing 46. The side bearing 44 rotates with the second tubular member 34 around the outer diameter surface of the second tubular member 34.

[0058] See also Figure 4 , a set of side bearings 44 can be positioned in axially oriented rows that are spaced apart around the inner diameter surface of the second tubular member 34. Figure 5 , an array of segments 48 are spaced around the surface of the first tubular member 32. The segments 48 may, for example, be embedded into the first tubular member 32 or may be a coating applied to the first tubular member 32. The segments 48 are positioned so that the segments 48 are aligned with the bearing 40. The segments are arranged in a particular configuration around the first tubular member 32 that corresponds to the signal pattern required to trigger or transmit a particular command or instruction to a downhole tool, instrument, equipment, or other device. See Figure 2 As an example, the segment 48 may be located on the outer diameter surface of the first tubular member 32 and may be axially aligned with the side bearing 44. In an alternative embodiment, the segment 48 may be located at the wellbore upper surface or wellbore lower surface of the first tubular member 32 and may be radially aligned with the end bearing 42.

[0059] The segments 48 may be formed of a first material and the bearings 40 may be formed of a second material. The first material may be reactive to the second material. In the disclosed embodiment of the present invention, when the drill string 16 rotates, the second tubular member 34 will rotate relative to the first tubular member 32. As an example, when the drill string 16 rotates, the second tubular member 34 may rotate with the drill string 16 and the first tubular member 32 may remain stationary.

[0060] As bearing 40 rotates over and passes through segment 48, the reaction of the first material of segment 48 to the second material of bearing 40 can be sensed. The reaction of the first material of segment 48 to the second material of bearing 40 does not require a separate power source, such as a battery. As an example, the first material can have an opposite polarity to the second material. Due to the exchange of charge between the first material of segment 48 and the second material of bearing 40, a voltage peak is generated. Certain materials are more inclined to gain electrons, and other materials are more inclined to lose electrons. If the first material of segment 48 has a higher polarity than the second material of bearing 40, electrons will be injected from the first material of segment 48 to the second material of bearing 40, resulting in oppositely charged surfaces. The first material of segment 48 to the second material of bearing 40 can be made of materials such as polyamide, polytetrafluoroethylene (PTFE), polyethylene terephthalate (PET), polydimethylacrylamide (PDMA), polydimethylsiloxane (PDMS), polyimide, carbon nanotubes, copper, silver, aluminum, lead, elastomer, Teflon, kapton, nylon or polyester.

[0061] Alternatively, the first material of the segment 48 can be a piezoelectric material and the second material can induce mechanical stress on the first material. As an example, the first material of the segment 48 can be quartz, langasite, lithium niobate, titanium oxide, or any other material having piezoelectric properties. In such an embodiment, the piezoelectric segment is stressed as the bearing 40 traverses and moves along the surface of the segment 48. The mechanical stress experienced by the piezoelectric material generates an electric charge, which results in a voltage spike. The constant motion generated by the rotation of the drill string 16 while drilling the wellbore 12 enables the piezoelectric segment to experience a motion of being stressed and released to generate a voltage spike.

[0062] Another alternative method of generating a voltage spike is by forming the segment 48 from a magnetostrictive material, such as terfenol-D, galfenol, metglas, or any other material having magnetostrictive properties. The stress applied to the magnetostrictive segment 48 as the bearing 40 traverses and moves along the segment 48 causes a change in the magnetic field of the magnetostrictive material. This induced magnetic field can be converted into a voltage by a planar pick-up coil or solenoid that can be manufactured with the segment 48.

[0063] See also Figure 6 , each time the bearing 40 traverses and moves along the segment 48, a voltage peak is generated. Figure 6The exemplary magnitude and shape of the peak in are for illustrative purposes, and the magnitude and shape of the peak may vary depending on the size and shape of the bearing 40 and segment 48 , as well as the rotational speed and frequency of the second tubular member 34 relative to the first tubular member 32 .

[0064] The reaction of the first material of segment 48 to the second material of bearing 40 sensed as bearing 40 rotates through and past segment 48 can be converted into a digital signal for use by electronics package 50 ( Figure 2 ) for interpretation. The electronics package 50 may include digital logic circuitry 54 for signal interpretation and may include circuitry for Figure 1 ) to send signals to downhole tools, instruments, equipment and other devices based on instructions received from a predetermined rotation pattern of the drill string 16. The pattern may include, for example, the number of revolutions of the drill string 16, the frequency, speed or rate of rotation of the drill string 16, or the direction of rotation of the drill string 16.

[0065] See also Figure 6 As the drill string 16 rotates, a continuous signal pattern 52 is generated having voltage peaks due to the movement of the bearing 40 across and along the segments 48 and periods of no voltage as the bearing 40 rotates around the outer surface of the first tubular member 32 without the segments 48. The voltage peaks are converted to digital signals by an analog-to-digital converter and connected as input values ​​to a digital logic circuit 54.

[0066] The digital logic circuit 54 may be a sequential logic circuit, in which the output value is a function not only of the input value but also of a set of past input values. To store past input values, the sequential circuit has a state or memory. Such a feature allows the actuator assembly 22 to interpret a sequence of voltage peaks that vary over time and provide control signals to downhole tools, instruments, equipment, and other devices to perform specific actions.

[0067] Sequential logic circuits can be synchronous, asynchronous, or a combination of both. Figure 7 , a synchronous sequential circuit has a clock 56. A memory 58 is connected to the clock 56. The memory 58 receives input values ​​from all storage elements of the circuit, which generates a sequence of repetitive pulses to synchronize all internal state changes. There are two types of sequential circuits, including pulse output and level output. In a pulse output circuit, the output value remains constant for the entire duration of the input pulse or clock pulse for clock sequential circuits. In a level output sequential circuit, the output value changes state at the beginning of the input pulse or clock pulse and remains in that state until the next input pulse or clock pulse.

[0068] See also Figure 8, asynchronous sequential circuits do not have a periodic clock, and the output value changes in direct response to changes in the input value. Asynchronous sequential circuits are faster because they are not synchronized by a clock, and the speed at which input values ​​are processed is limited only by the propagation delays of the logic gates in the feedback loop 60 used in the circuit. However, asynchronous sequential circuits are more difficult to design due to timing problems caused by the propagation of time delays that are not always consistent in the various levels of the circuit. Digital logic circuits can be implemented as integrated circuits (ICs), such as field programmable gate arrays (FPGAs), application specific integrated circuits (ASICs), complex programmable logic devices (CPLDs), or systems on a chip (SoCs).

[0069] See also Figure 6 , the bearing 40 is a side bearing 44, and the second tubular member 34 rotates in a single direction relative to the first tubular member 32. Because the drill string 16 will rotate in a single direction at approximately the same speed, the signal will have the same sequence during the drilling process, with peak voltage amplitudes followed by periods of zero or very low voltage. In the disclosed embodiment of the present invention, as an example, the drill string 16 may rotate in a counterclockwise direction to drill the wellbore 12 ( Figure 1 ).

[0070] The digital logic circuit 54 will compare the signal sequence within a given time period, clock cycle or fixed set of rotations and decide to enable, disable or perform no action with respect to the downhole tool, instrument, equipment or other device. The actuator assembly 22 can be programmed to perform no action if the signal pattern is the same within the comparison period. However, if the direction of rotation changes from counterclockwise to clockwise, then Fig. 9 The signal sequence shown changes. This change in the voltage peak sequence can be used to develop unique code sequences to perform various downhole procedures.

[0071] See also Fig. 9 , the continuous signal image 52A is the result of the drill string 16 rotating in the counterclockwise direction so that the second tubular member 34 rotates counterclockwise relative to the first tubular member 32. When the drill string 16 changes direction and rotates in the clockwise direction, the second tubular member 34 rotates clockwise relative to the first tubular member 32. The resulting continuous signal image 52B has a different image from the continuous signal image 52A. The digital logic circuit 54 can recognize this change in image.

[0072] The actuator assembly 22 can be controlled from the surface. For example, during drilling operations, the bearing 40 moves in a counterclockwise direction along and through the section 48. If a change in sequence is needed to actuate downhole tools, instruments, equipment, or other devices, drilling can be stopped, the drill bit can be lifted off the bottom of the wellbore 12, and the drill string 16 can be turned in a clockwise direction from the surface. The digital logic circuit 54 of the actuator assembly 22 will recognize the difference in the signal sequence pattern and send a control signal to the downhole tool, instrument, equipment, or other device to perform the appropriate action.

[0073] When the drill bit leaves the bottom of the wellbore 12, the drill string 16 can be rotated counterclockwise or clockwise to generate a large number of signal sequence images, which can be converted to perform different functions. In addition, there can be multiple actuator assemblies 22, each actuator assembly having a unique segment pattern placed at one or more locations in the drill string 16. Therefore, multiple downhole tools, instruments, equipment or other devices can be controlled and triggered from the surface.

[0074] An alternative method of generating a unique signal sequence image is by varying the frequency of rotation of the drill string 16 in the counterclockwise direction, the clockwise direction, or both directions over one or more cycles. The rotation speed may i) increase and then decrease or decrease and then increase in a single direction; ii) increase in the counterclockwise direction and decrease in the clockwise direction; iii) increase in the clockwise direction and decrease in the counterclockwise direction; or iv) any combination of increase / decrease in the counterclockwise / clockwise directions.

[0075] In other alternative embodiments, the size and shape of the segment 48 can be changed to generate signals of different amplitudes, widths, and shapes. These signal patterns can then be used to identify the direction of rotation of the drill string component. In this case, the digital logic circuit 54 can identify the direction of rotation and initiate an action to actuate a downhole tool, instrument, equipment, or other device after a specific number of revolutions. The digital logic circuit 54 can also compare the direction of rotation within a specific number of revolutions.

[0076] In yet other alternative embodiments, see Figure 10 to Figure 11 Another method for distinguishing the direction of rotation of the drill string 16 is to provide a bearing 40 in a latch groove 62. The latch groove 62 is a groove in the second tubular member 34. The bearing 40 as a side bearing 44 will be displaced to one side of the latch groove 62 relative to the direction of the angular acceleration generated by the rotation of the drill string 16. On one side of the latch groove 62 is a cylindrical roller bearing 64.

[0077] The rotation of the drill string 16 will cause the side bearing 44 to move within the latch slot 62 in a direction opposite to the rotation direction of the drill string 16. As an example, when the drill string 16 rotates in a counterclockwise direction, the side bearing 44 is driven in a clockwise direction within the latch slot 62, resulting in a continuous signal pattern 52C. When the drill string 16 rotates in a clockwise direction, the side bearing 44 is driven in a counterclockwise direction within the latch slot 62, resulting in a continuous signal pattern 52D. Because the cylindrical roller bearing 64 is in contact with the segment 48 for a shorter duration than the side bearing 44, the presence of the smaller cylindrical roller bearing 64 results in a shorter width peak.

[0078] When the drill string 16 rotates in the counterclockwise direction, the side bearing 44 moves further away from the cylindrical roller bearing 64 than when the drill string 16 rotates in the clockwise direction. Therefore, when the drill string 16 rotates in the counterclockwise direction, the time difference T1 between the peak value generated by the side bearing 44 moving along the section 48 and the peak value generated by the cylindrical roller bearing 64 moving along the section 48 is greater than the time difference T2. T2 is the time difference between the peak value generated by the side bearing 44 moving along the section 48 and the peak value generated by the cylindrical roller bearing 64 moving along the section 48 when the drill string 16 rotates in the clockwise direction. Therefore, the reason why the continuous signal image 52C is different from the continuous signal image 52D is not only because the drill string 16 rotates in the opposite direction, but also because of the time difference T1 and the time difference T2, which can be used to identify the rotation direction of the drill string 16.

[0079] In still other embodiments, a unique signal pattern may be generated by the segment 48 located at the end of the first tube member 32. Figure 12 to Figure 13 , the wellbore upper end 66 of the first tubular member 32 may include a set of segments 48, and the wellbore lower end 68 of the first tubular member may include a set of segments 48 of a different pattern. When the end bearing 42 moves along and through the segments 48, a signal pattern is generated. When the drill string 16 rotates counterclockwise, the second tubular member rotates in a counterclockwise direction relative to the first tubular member 32, and a signal pattern is generated. Fig.12 When the drill string 16 rotates counterclockwise, the second tubular member rotates counterclockwise relative to the first tubular member 32, and generates Fig.13 Continuous signal image 52F.

[0080] See also Figure 14 to Figure 15 In other alternative embodiments, different unique signal patterns can be generated by using a variable bearing 70. At least one of the bearings 40 can be a variable bearing. The variable bearing 70 can include a dissolvable material. By dissolving the dissolvable material of the variable bearing 70, the signal pattern can be changed to allow different instructions to be transmitted to the device 24.

[0081] See also Fig.16, the variable bearing 70 may have an outermost layer 72, which may be formed of a dissolvable material. In some embodiments, the variable bearing 70 includes a core bearing 74 formed of an electrically insulating material. The electrically insulating material is non-reactive to the first material. The non-reactive material of the core bearing 74 may be made of a material such as a carbide, a silicide, an oxide, a nitride, or a mixture of any of these materials. In such an embodiment, the outermost layer 72 may be a second material that is reactive to the first material.

[0082] See also Fig.17 In other alternative embodiments, the entire variable bearing 70 can be formed of a dissolvable material. In such an embodiment, the dissolvable material is the second material and is reactive to the first material.

[0083] In embodiments where the dissolvable material is a second material, the dissolvable material may be any metal-based material that is soluble in a downhole environment. More specifically, the dissolvable metal may be a magnesium-based alloy or an aluminum-based alloy. The dissolution rate of these alloys depends primarily on the downhole temperature and fluid composition. The dissolution rate depends to a much lesser extent on the downhole pressure. The exact composition of the dissolvable material as the second material may be selected based on the known downhole temperature, pressure, and fluid composition of a particular well that will achieve the desired dissolution rate.

[0084] Alternatively, a preferred soluble material may be selected and the dissolution rate may be adjusted by pumping fluid into the underground well 10, which adjustment may speed up or slow down the dissolution rate of the soluble material. As an example, if the operator wishes to speed up the dissolution rate of the soluble material, the operator may pump a higher concentration of brine or acid into the underground well so that such brine or acid contacts the soluble material. If brine is used, the product of the dissolution reaction may be a metal hydroxide powder that has a low solubility in brine and can be washed away by the dynamic flow of the downhole fluid. If acid is used, the product of the dissolution reaction may be an ion that is completely dissolved in solution.

[0085] See also Fig.18 When the outermost layer 72 of the variable bearing 70 is the second material or when the variable bearing 70 is entirely formed of the second material, as the actuator assembly 22 is first delivered into the subterranean well 10, each bearing 40 will react with the segment 48 to generate a continuous signal pattern 52. The signal pattern 52 is interpreted by the digital logic circuit 54 to provide control signals to downhole tools, instruments, equipment and other devices to perform specific actions.

[0086] The dissolvable material that is the second material of the variable bearing 70 may then be dissolved. The dissolvable material may be formed of a material that has been selected to dissolve within a predetermined time based on the temperature and fluid composition and, to a lesser extent, the downhole pressure within the subterranean well 10. Alternatively, the operator may pump a selected fluid into the subterranean well that will affect the rate of dissolution of the dissolvable material of the variable bearing 70.

[0087] See also Fig.19 After the dissolvable material of the variable bearing 70 has dissolved, each remaining bearing 40 will react with the segment 48 to generate a continuous signal image 52'. Fig.18 The signal image 52' is a corrected signal image because some bearings were once reactive in the generation of the signal image 52. The signal image 52' can be interpreted by the digital logic circuit 54 to provide control signals or instructions to different downhole tools, instruments, equipment or other devices to perform specific actions. Alternatively, the signal image 52' can be interpreted by the digital logic circuit 54 to provide corrected control signals or corrected instructions to downhole tools, instruments, equipment or other devices to perform specific actions.

[0088] In an alternative embodiment, see Fig.16 , the core bearing 74 can be formed of a second material, and the outermost layer 72 can be a soluble material that is non-reactive to the first material. In such an embodiment, the outermost layer 72 can be a soluble polymer. As an example, the soluble polymer can be polyglycolic acid (PGA), polylactic acid (PLA), polymer poly(lactide-co-glycolide)), polyanhydride, poly(propylene fumarate)), polycaprolactone (PCL), polyethylene glycol (PEG), or polyurethane. Soluble polymers can be degraded by hydrolysis, in which the long chains of these polymers can be broken down into smaller polymers when exposed to water or moisture, causing them to lose structural integrity and mechanical properties.

[0089] The outermost layer 72 formed by the soluble polymer will break under certain low loads or erosion. In addition, with the increase of time and temperature, the soluble polymer with smaller chain can become acid, such as glycolic acid (for PGA) or lactic acid (for PLA). When the soluble polymer reaches this stage, no solid part remains. The dissolution rate or degradation rate of the soluble polymer strongly depends on the temperature and fluid composition of the wellbore fluid.

[0090] See also Fig. 20, when the outermost layer 72 of the variable bearing 70 is a dissolvable polymer that is non-reactive to the first material, as the actuator assembly 22 is first delivered into the subterranean well 10, only some of the bearings 40 will react with the segments 48 to generate the continuous signal pattern 52. The variable bearings 70 having the outermost layer 72 formed of the dissolvable polymer will not react with the segments 48. The signal pattern 52 is interpreted by the digital logic circuit 54 to provide control signals to downhole tools, instruments, equipment and other devices to perform specific actions.

[0091] The dissolvable material of the variable bearing 70, which is a dissolvable polymer, may then be dissolved or degraded. The dissolvable material may be formed of a material that has been selected to dissolve within a predetermined time based on the temperature and fluid composition and, to a lesser extent, the downhole pressure within the subterranean well 10. Alternatively, the operator may pump a selected fluid into the subterranean well that will affect the dissolution rate of the dissolvable material of the variable bearing 70.

[0092] See also Fig.21 , after the soluble material of the variable bearing 70 has dissolved, the core bearing 74 of each variable bearing 70 will be exposed. Now, each bearing 40 including the variable bearing 70 will react with the segment 48 to generate a continuous signal image 52'. Fig. 20 The signal image 52' is a modified signal image because the reaction of the variable bearing 70, which was once non-reactive, is generated in the signal image 52. The signal image 52' can be interpreted by the digital logic circuit 54 to provide control signals or instructions to different downhole tools, instruments, equipment or other devices to perform specific actions. Alternatively, the signal image 52' can be interpreted by the digital logic circuit 54 to provide modified control signals or modified instructions to downhole tools, instruments, equipment or other devices to perform specific actions.

[0093] See also Fig. 22 , the signal image generated by the actuator assembly 22 can be used to instruct the actuator assembly 22 to send signals to various downhole tools, instruments, equipment or other devices. As an example, the actuator assembly 22 can be used to actuate downhole circulation subs to facilitate drilling and wellbore cleaning operations. The actuator assembly 22 can be used to send a trigger signal to open the circulation sub by sliding the sleeve or opening the valve, so that the drilling fluid is directly transferred to the annulus. This operation increases the flow of drilling fluid in the annulus and helps with wellbore cleaning, and can also separate the flow between the annulus and the drill string assembly. Once the operation is completed, the actuator assembly 22 can send another trigger signal to close the circulation sub.

[0094] In an alternative embodiment, the actuator assembly 22 can be used to actuate a bypass valve at a selected depth below the fracture so that lost circulation material can be pumped through the bypass valve to plug the fracture. After the operation, a command is transmitted from the surface through the actuator assembly 22 to immediately close the valve after a certain period of time. Similar operations can be performed to change the drilling fluid or to pump cement to the desired depth in the wellbore. The actuator assembly 22 can further be used to activate and deactivate a flapper valve and a stimulation sleeve.

[0095] In other alternative embodiments, the actuator assembly 22 can be used to actuate a drilling reamer to increase the size of the wellbore below the casing. A drilling underreamer is a tool with a cutter located behind the drill bit. The reamer is used to expand, smooth and adjust the wellbore so that the casing or completion equipment can be sent in without any restrictions. When a problem occurs downhole, the drill string assembly can be activated by the actuator assembly 22 instead of pulling it out of the well. Then, the underreamer is extended and drilled through with the drill bit. Another trigger signal can be sent to the actuator assembly 22 from the ground to retract the underreamer. The actuator assembly 22 can be programmed to extend or retract the reamer in a number of limited steps according to the desired diameter of the wellbore.

[0096] In other alternative embodiments, the actuator assembly 22 can be used to deploy and retract a casing scraper. The casing scraper is used to remove debris and scale left by the drilling fluid on the inner casing. The casing scraper can be operated with the drilling assembly in a retracted mode when drilling an open hole section. The scraper can be extended at any time, such as when tripping out of hole, to scrape the inner casing or critical areas in the inner casing.

[0097] In yet other alternative embodiments, the actuator assembly 22 can be used to expand and contract a swellable packer, a production packer, or a test packer. The expanded packer can seal the wellbore to isolate an area in the wellbore and also serve as a well barrier. The production packer or the test packer is placed in a cased well, while the swellable packer is placed in both open hole and cased wells.

[0098] The actuator assembly 22 may alternatively be used to send a command signal from the surface to position a liner hanger.

[0099] During drilling operations, as the bearing 40 moves across and along the section 48, especially when drilling, charges are continuously generated. These charges not only generate signal images, but can also be converted from analog signals to digital signals by a bridge rectifier and stored in a di-electric capacitor that is derated for use at high temperatures, or can be stored in a ceramic capacitor, an electrolytic capacitor, or a supercapacitor. By storing energy in a capacitor, the actuator assembly 22 can also be used as a power source.

[0100] In the example of operation, see Fig.23A , the device 24 commanded by the actuator assembly 22 may be a compartment having a door that can be opened and closed by the actuator assembly 22 to release product from the compartment. The drill string 16 with the actuator assembly 22 and the device 24 extends into the wellbore 12 of the underground well 10. The drill string 16 is used to drill the underground well 10, penetrating various underground rock formations. See Fig. 23B In some embodiments, drilling may be stopped after the target depth 100 is passed so that the device 24 is located near the target depth.

[0101] See also Fig.23C Once the device 24 reaches the target depth 100, the driller can pull the drill bit away from the bottom of the wellbore 12 and can rotate the drill string 16 in different directions and at different frequencies to generate a unique signal pattern from the surface as a predetermined signal. The signal pattern is then converted into a specific action. As an example, the signal pattern can be an instruction to open the door of the device 24 to allow the product to be released into the underground well 10.

[0102] If additional operations need to be performed in the underground well 10, and a new unique signal image is desired, the dissolvable material of the variable bearing 70 can be dissolved so that the previous signal image 52 becomes a revised signal image 52', such as Figure 18 to Figure 19 and Figure 20 to Figure 21 The modified signal image 52 ′ may be used to provide instructions to the same device 24 for performing a different operation, or may be used to provide instructions to a new or different device 24 .

[0103] Therefore, the disclosed embodiments of the present invention provide systems and methods for actuating different devices, tools and instruments from the ground, and also enable discontinuous drilling workflows to be performed in real time. The disclosed systems and methods of the present invention can be controlled from the ground. The actuation system is a separate system that can be seamlessly integrated with downhole tools, devices and instruments, so that the actuation system does not replace the existing drilling portfolio. The proposed actuation system and method not only allow the workflow to be redesigned to improve drilling efficiency, but also help drilling automation by bridging one of the key technology gaps, communicating in real time with the downhole actuation system and transmitting trigger signals to it in real time. Because the signal image is unique for a specific operation, such as releasing a selected number or type of sensors, discontinuous drilling workflows can be performed without affecting other downhole tools, instruments, devices or operations.

[0104] The disclosed embodiments of the present invention allow additional signal patterns to be generated by varying the number of reactionary bearings. These additional signal patterns can be used to control more than one tool or device.

[0105] See also Fig.24 , the fourth industrial revolution (referred to as "4IR") technologies, such as artificial intelligence, machine learning, big data analysis, and robotics, are developing at a very fast pace. According to the disclosed embodiment of the present invention, human intervention in controlling the downhole actuators in the drilling rig 76 can be replaced by an intelligent drilling system 78. The intelligent drilling system 78 performs optimized drilling operations based on intelligent drilling dynamics 80 and an intelligent hydraulic system 82. For example, raw data from various sensors on the drilling rig can be extracted, analyzed, and transformed into useful information by the intelligent drilling dynamics 80 and the intelligent hydraulic system 82. If the wellbore needs to be cleaned based on the received data, the need can be transmitted to the intelligent drilling system 78, and the actuation system can be used to rotate the drill pipe in the desired configuration to generate a specific sequence. Then, the sequence can be converted into a specific trigger signal to open the bypass valve, thereby diverting the drilling fluid into the annulus to increase the annular velocity and clean the wellbore.

[0106] One embodiment is a downhole actuation system that can be controlled from the surface to actuate digitally enabled downhole devices or tools or instruments. The actuation of different devices or tools or instruments enables discrete drilling workflows to be performed. The actuation system is a separate system that can be seamlessly integrated with the downhole tools or devices or instruments, so it does not replace the existing drilling assembly.

[0107] Therefore, the embodiments described herein are well adapted to achieve the above-mentioned objects and obtain the above-mentioned objects and advantages, as well as other aspects inherent therein. Although certain embodiments have been described for the purpose of disclosure, there are many changes in the details of the process for achieving the desired results. These and other similar modifications will be obvious to those skilled in the art and are intended to be included within the scope of the disclosure of the invention disclosed herein and the scope of the appended claims.

Claims

1. A system for indicating a device within a wellbore of a subterranean well, the system comprising: a drill string extending from the surface into the subterranean well, the drill string having an actuator assembly; in The actuator assembly comprises: a first tubular member having a section formed of a first material; a second tubular member coaxially aligned with the first tubular member; a plurality of bearings positioned between the first tubular member and the second tubular member, each of the plurality of bearings comprising a second material, wherein the first material is reactive to the second material, and wherein at least one of the plurality of bearings is a variable bearing comprising a dissolvable material; and wherein The actuator assembly is operable to direct operation of the device by generating a command signal generated by rotating the first tubular member relative to the second tubular member and interpreting a pattern of response of the segment as the plurality of bearings rotate past the segment.

2. The system according to claim 1, wherein: The variable bearing has an outermost layer of the dissolvable material, wherein the dissolvable material is the second material.

3. The system according to claim 2, wherein: The variable bearing includes a core bearing formed of an electrically insulating material, the core bearing being coated by the outermost layer of the dissolvable material.

4. The system according to claim 2, wherein: The entire variable bearing is formed of the dissolvable material.

5. The system according to claim 1, wherein: The variable bearing comprises a core bearing formed from the second material, the core bearing being coated with an outermost layer of a dissolvable polymer that is the dissolvable material and is non-reactive to the first material.

6. The system according to claim 1, wherein: The plurality of bearings includes a side bearing, and wherein the segment is located on an outer diameter surface of the first tubular member and is axially aligned with the side bearing, the side bearing being located between the outer diameter surface of the first tubular member and an inner diameter surface of the second tubular member.

7. The system according to claim 1, wherein: The plurality of bearings includes a side bearing, and wherein the segment is located on an inner diameter surface of the first tubular member and is axially aligned with the side bearing, the side bearing being located between the inner diameter surface of the first tubular member and an outer diameter surface of the second tubular member.

8. The system of claim 1, further comprising a support member extending radially inward from an inner diameter surface of the second tubular member, the support member supporting the first tubular member within the central bore of the second tubular member.

9. The system according to claim 8, wherein: The plurality of bearings include an end bearing, and wherein the segment is positioned at an end surface of the first tubular member and radially aligned with the end bearing, the end bearing being located between the end surface of the first tubular member and the support member, the support member being fixed to the second tubular member and extending radially from the second tubular member.

10. The system according to claim 1, wherein: The actuator assembly further includes a digital logic circuit configured to receive and interpret a pattern of reactions of the segments as the plurality of bearings rotate past the segments and generate the command signal.

11. The system according to claim 1, wherein: The second tubular member is operable to rotate with the drill string, and the first tubular member is located within and surrounded by the second tubular member.

12. The system of claim 1, wherein: The second tubular member is operable to rotate with the drill string, and the first tubular member surrounds the second tubular member.

13. A method for indicating a device within a wellbore of a subterranean well, the method comprising: A drill string is extended from the surface into the subterranean well, the drill string having an actuator assembly, wherein the actuator assembly has: a first tubular member having a section formed of a first material; a second tubular member coaxially aligned with the first tubular member; a plurality of bearings positioned between the first tubular member and the second tubular member, each of the plurality of bearings comprising a second material, wherein the first material is reactive to the second material, and wherein at least one of the plurality of bearings is a variable bearing comprising a dissolvable material; and using the actuator assembly to direct operation of the device by generating a command signal, the command signal being generated by rotating the second tubular member relative to the first tubular member and interpreting a pattern of the reaction of the segment as the plurality of bearings rotate through the segment.

14. The method of claim 13, further comprising dissolving the dissolvable material and instructing subsequent operation of the device using the actuator assembly by generating a correction command signal, the correction command signal being generated by rotating the second tubular member relative to the first tubular member and interpreting a correction pattern of the reaction of the segment as the plurality of bearings rotate past the segment.

15. The method according to claim 14, wherein: The variable bearing has an outermost layer of the dissolvable material and a core bearing formed of an electrically insulating material, wherein the dissolvable material is the second material, and wherein dissolving the dissolvable material includes dissolving the outermost layer of the dissolvable material such that the variable bearing is non-reactive to the first material.

16. The method according to claim 14, wherein: The entire variable bearing is formed of the dissolvable material, wherein the dissolvable material is the second material, and wherein dissolving the dissolvable material includes dissolving the entire variable bearing.

17. The method according to claim 14, wherein: The variable bearing comprises a core bearing formed from the second material, the core bearing being coated by an outermost layer of a soluble polymer, the soluble polymer being the soluble material and being non-reactive to the first material, and wherein dissolving the soluble material comprises dissolving the outermost layer of the soluble material such that the variable bearing is reactive to the first material.

18. The method according to claim 13, wherein: The plurality of bearings include a side bearing, and wherein the segment is located on an outer diameter surface of the first tubular member and is axially aligned with the side bearing, the side bearing being located between the outer diameter surface of the first tubular member and the inner diameter surface of the second tubular member, and wherein the pattern that explains the reaction of the segment when the plurality of bearings rotates past the segment includes explaining the reaction of the segment when the side bearing rotates past the segment.

19. The method according to claim 13, wherein: The plurality of bearings include a side bearing, and wherein the segment is located on an inner diameter surface of the first tubular member and is axially aligned with the side bearing, the side bearing being located between the inner diameter surface of the first tubular member and the outer diameter surface of the second tubular member, and wherein the pattern that explains the reaction of the segment as the plurality of bearings rotates past the segment includes explaining the reaction of the segment as the side bearing rotates past the segment.

20. The method of claim 13, further comprising supporting the first tubular member within the central bore of the second tubular member using a support member extending radially inward from an inner diameter surface of the second tubular member.

21. The method according to claim 20, wherein: The plurality of bearings include an end bearing, and wherein the segment is positioned at an end surface of the first tubular member and radially aligned with the end bearing, the end bearing being located between the end surface of the first tubular member and the support member, the support member being fixed to the second tubular member and extending radially from the second tubular member, and wherein the pattern explaining the reaction of the segment when the plurality of bearings rotate past the segment includes explaining the reaction of the segment when the end bearing rotates past the segment.

22. The method according to claim 13, wherein: The actuator assembly further includes a digital logic circuit, and the method further includes receiving and interpreting a pattern of responses of the segment as the plurality of bearings rotate through the segment, and generating the command signal using the digital logic circuit.

23. The method according to claim 13, wherein: The second tubular member rotates with the drill string, and the first tubular member is located within and surrounded by the second tubular member, wherein rotating the second tubular member relative to the first tubular member includes rotating the drill string.

24. The method according to claim 13, wherein: The second tubular member rotates with the drill string and the first tubular member surrounds the second tubular member, wherein rotating the second tubular member relative to the first tubular member includes rotating the drill string.

Images