Patent Description:
When drilling a subterranean well, operators are unable to view the trajectory of the wellbore and the downhole environment directly. In addition, once tools, instruments, equipment, and other devices are lowered in the wellbore they are inaccessible from the surface. Conventional techniques to control downhole tools or instruments or devices from the surface include mechanical methods, such as applying weight-on-bit and rotating the drill string assembly, applying pressure and dropping balls, or hydraulic methods such as fluid pressure cycles and flowing pressure cycles.

Radio frequency identification ("RFID") based systems have also been developed for drilling applications. RFID tags are programmed with a unique code at the surface are dropped into wells and travel downhole with the drilling fluid flow. Downhole devices such as bypass valves, reamers or packers are integrated with an RFID reader. The RFID reader consists of a battery, electronics and an antenna encapsulated for protection. The RFID tags are energized by the antenna of the reader when they are in the vicinity of each other. The antenna constantly generates a radio frequency field to 'listen' to RFID tags. The readers have the ability to only respond to a specific identification code and to ignore other codes, and also to eliminate repetition of operations by only accepting a unique code once. The biggest advantage RFID-based systems have is that they place no restrictions on the inner diameter of the drill string compared to the procedure normally used for activating bypass valves, which involves dropping an activation ball. RFID systems enable remote activation and places no restrictions inside the drill string, resulting in a larger flow area for the drilling fluids, allows any logging instrument to pass through the drill string without restriction. <CIT> describes a drilling assembly for drilling a subterranean wellbore with an expandable reamer and an expandable stabilizer, each have a tubular body with a longitudinal axis and a drilling fluid flow path. A plurality of blades is carried by the reamer and a plurality of bearing pads is carried by the stabilizer. The blades and bearing pads are outwardly movable from a retracted position to an extended position with respect to the longitudinal axes of the reamer and stabilizer, respectively. The reamer and stabilizer each include an actuation device for moving the blades and bearing pads, respectively, from the retracted position to the extended position.

Mechanical and hydraulic methods of instructing downhole devices can introduce certain restrictions and potential challenges or issues to the drilling process. For example, actuation systems that include dropping an activation ball to open side ports requires applying pressure from the surface, which can damage downhole components. Such a system also requires extra trips downhole to remove the balls or to ream to ball from the drill string assembly.

RFID systems have drawbacks. For example, RFID systems require a drilling fluid flow for the RFID tag to travel through the drill string assembly and towards the RFID reader to activate or deactivate downhole devices. In addition, the RFID tag must be in the correct or optimized orientation when passing through the RFID reader antenna to transmit its unique identification number and specific instructions to the RFID reader. Further, once the RFID tags are dropped from the surface there is no control of the tag from the surface 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 can also be contaminated by debris from drilling fluids. In addition, the RFID reader antenna is always on because it has to 'listen' for an RFID tag signal. An operation cannot be ceased or started immediately if required as another RFID tag will have to be deployed to activate, deactivate, or reset a downhole device and the timing of the activation or deactivation will depend on the time taken for the RFID tag to reach the vicinity of the RFID reader.

Systems and methods of this disclosure overcome the deficiencies of both of the currently available mechanical and RFID system. Systems and methods of this disclosure can communicate with and deliver instruction signals to downhole devices in real-time. Embodiments of this disclosure provide a downhole actuation system that can be controlled from the surface to actuate digitally enabled downhole devices, such as tools and instruments. Actuation of these different devices can enable 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 displace existing drilling portfolios.

In embodiments of this disclosure, a set of signal pattern is created and interpreted by digital logics which are then converted to send specific signals to activate or deactivate a particular device. The initial set of ball bearings of the system are used to generate a first set of signals for interpretation as a first set of instructions to the downhole device. Dissolvable materials that are used to form certain of the bearings can then be dissolved to generate a different set of signals that will be interpreted as different instructions to the device, or can be used to instruct a different device, for performing other functions downhole.

In an embodiment of this disclosure, a system for instructing a device within a wellbore of a subterranean well includes a drill string extending into the subterranean well from a terranean surface. The drill string has an actuator assembly. The actuator assembly has a first pipe member with a segment formed of a first material. A second pipe member is coaxially aligned with the first pipe member. A plurality of bearings are positioned between the first pipe member and the second pipe 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 changeable bearing that includes a dissolvable material. The actuator assembly is operable to instruct an operation of the device by generating an instruction signal by rotating the first pipe member relative to the second pipe member and interpreting a pattern of a reaction of the segment as the plurality of bearings rotate past the segment.

In alternate embodiments, the changeable bearing can have an outermost layer of the dissolvable material, and the dissolvable material can be the second material. The changeable bearing can include a core bearing formed of an electrically insulating material, which is coated by the outermost layer of the dissolvable material. Alternately, the entire changeable bearing can be formed of the dissolvable material. Alternately, the changeable bearing can include a core bearing formed of the second material that is coated by an outermost layer of a dissolvable polymer that is the dissolvable material and that is non-reactive to the first material.

In other alternate embodiments, the plurality of bearings can include a side bearing, and the segment can be located on an outer diameter surface of the first pipe member and be axially aligned with the side bearing. The side bearing can be located between the outer diameter surface of the first pipe member and an inner diameter surface of the second pipe member. Alternately, the plurality of bearings can include a side bearing, and the segment can be located on an inner diameter surface of the first pipe member and be axially aligned with the side bearing. The side bearing can be located between the inner diameter surface of the first pipe member and an outer diameter surface of the second pipe member.

In still other alternate embodiments, the system can further include a support member extending radially inward from an inner diameter surface of the second pipe member. The support member can support the first pipe member within a central bore of the second pipe member. The plurality of bearings can include an end bearing, and the segment can be positioned at and end surface of the first pipe member and be radially aligned with the end bearing. The end bearing can be located between the end surface of the first pipe member and the support member secured to the second pipe member that extends radially from the second pipe member.

In yet other alternate embodiments, the actuator assembly can further include a digital logic circuit configured to receive and to interpret the pattern of the reaction of the segment as the plurality of bearings rotate past the segment, and to generate the instruction signal. The second pipe member can be operable to rotate with the drill string and the first pipe member can be located within the second pipe member and be circumscribed by the second pipe member. Alternately, the second pipe member can be operable to rotate with the drill string and the first pipe member can circumscribe the second pipe member.

In an alternate embodiment of this disclosure, a method for instructing a device within a wellbore of a subterranean well includes extending a drill string into the subterranean well from a terranean surface. The drill string includes an actuator assembly having a first pipe member with a segment formed of a first material. A second pipe member is coaxially aligned with the first pipe member. A plurality of bearings are positioned between the first pipe member and the second pipe member. Each of the plurality of bearings includes a second material, where the first material is reactive to the second material. At least one of the plurality of bearings is a changeable bearing that includes a dissolvable material. The method further includes instructing an operation of the device with the actuator assembly by generating an instruction signal by rotating the second pipe member relative to the first pipe member and interpreting a pattern of a reaction of the segment as the plurality of bearings rotate past the segment.

In alternate embodiments, the method can further include dissolving the dissolvable material and instructing a subsequent operation of the device with the actuator assembly by generating a revised instruction signal by rotating the second pipe member relative to the first pipe member and interpreting a revised pattern of the reaction of the segment as the plurality of bearings rotate past the segment. The changeable bearing can have an outermost layer of the dissolvable material and a core bearing formed of an electrically insulating material. The dissolvable material can be the second material, and dissolving the dissolvable material can include dissolving the outermost layer of the dissolvable material so that the changeable bearing is non-reactive to the first material. Alternately, the entire changeable bearing can be formed of the dissolvable material, where the dissolvable material is the second material, and dissolving the dissolvable material can include dissolving the entire changeable bearing. Alternately, the changeable bearing can include a core bearing formed of the second material that is coated by an outermost layer of a dissolvable polymer that is the dissolvable material and that is non-reactive to the first material, and dissolving the dissolvable material can include dissolving the outermost layer of the dissolvable material so that the changeable bearing is reactive to the first material.

In other alternate embodiments, the plurality of bearings can include a side bearing, and the segment can be located on an outer diameter surface of the first pipe member and be axially aligned with the side bearing. The side bearing can be located between the outer diameter surface of the first pipe member and an inner diameter surface of the second pipe member, and interpreting the pattern of the reaction of the segment as the plurality of bearings rotate past the segment can include interpreting the reaction of the segment as the side bearing rotates past the segment. Alternately, the plurality of bearings can include a side bearing, and the segment can be located on an inner diameter surface of the first pipe member and be axially aligned with the side bearing. The side bearing can be located between the inner diameter surface of the first pipe member and an outer diameter surface of the second pipe member, and interpreting the pattern of the reaction of the segment as the plurality of bearings rotate past the segment can include interpreting the reaction of the segment as the side bearing rotates past the segment.

In yet other alternate embodiments, the method can further include supporting the first pipe member within a central bore of the second pipe member with a support member extending radially inward from an inner diameter surface of the second pipe member. The plurality of bearings can include an end bearing, and the segment can be positioned at and end surface of the first pipe member and be radially aligned with the end bearing. The end bearing can be located between the end surface of the first pipe member and the support member secured to the second pipe member that extends radially from the second pipe member. Interpreting the pattern of the reaction of the segment as the plurality of bearings rotate past the segment can include interpreting the reaction of the segment as the end bearing rotates past the segment.

In still other alternate embodiments, the actuator assembly can further include a digital logic circuit, and the method can further include receiving and interpreting the pattern of the reaction of the segment as the plurality of bearings rotate past the segment, and generating the instruction signal with the digital logic circuit. The second pipe member can rotate with the drill string and the first pipe member can be located within the second pipe member and be circumscribed by the second pipe member, where rotating the second pipe member relative to the first pipe member can include rotating the drill string. Alternately, the second pipe member can rotate with the drill string and the first pipe member can circumscribe the second pipe member, where rotating the second pipe member relative to the first pipe member can include rotating the drill string.

So that the manner in which the above-recited features, aspects and advantages of the disclosure, as well as others that will become apparent, are attained and can be understood in detail, a more particular description of the embodiments of the disclosure briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only certain embodiments of the disclosure and are, therefore, not to be considered limiting of the disclosure's scope, for the disclosure may admit to other equally effective embodiments.

As used in the Specification and appended Claims, the singular forms "a", "an", and "the" include plural references unless the context clearly indicates otherwise. As used, the words "comprise," "has," "includes", and all other grammatical variations are each intended to have an open, non-limiting meaning that does not exclude additional elements, components or steps. Embodiments of the present disclosure may suitably "comprise", "consist" or "consist essentially of" the limiting features disclosed, and may be practiced in the absence of a limiting feature not disclosed. For example, it can be recognized by those skilled in the art that certain steps can be combined into a single step.

Spatial terms describe the relative position of an object or a group of objects relative to another object or group of objects. The spatial relationships apply along vertical and horizontal axes. Orientation and relational words including "uphole" and "downhole"; "above" and "below" and other like terms are for descriptive convenience and are not limiting unless otherwise indicated.

Where the Specification or the appended Claims provide a range of values, it is understood that the interval encompasses each intervening value between the upper limit and the lower limit as well as the upper limit and the lower limit. The disclosure encompasses and bounds smaller ranges of the interval subject to any specific exclusion provided.

Where reference is made in the Specification and appended Claims to a method comprising two or more defined steps, the defined steps can be carried out in any order or simultaneously except where the context excludes that possibility.

Looking at <FIG>, subterranean well <NUM> can have wellbore <NUM> that extends to an earth's or terranean surface <NUM>. Subterranean well <NUM> can be an offshore well or a land based well and can be used for producing hydrocarbons from subterranean hydrocarbon reservoirs, or can be otherwise associated with hydrocarbon development activities.

Drill string <NUM> can extend into and be located within wellbore <NUM>. Annulus <NUM> is defined between an outer diameter surface of drill string <NUM> and the inner diameter of wellbore <NUM>. Drill string <NUM> can include a string of tubular joints and bottom hole assembly <NUM>. The tubular joints can extend from terranean surface <NUM> into subterranean well <NUM>. Bottom hole assembly <NUM> can include, for example, drill collars, stabilizers, reamers, shocks, a bit sub and the drill bit. Drill string <NUM> can be used to drill wellbore <NUM>. Drill string <NUM> has a string bore <NUM> that is a central bore extending the length of drill string <NUM>. Drill string <NUM> can be rotated to rotate the bit to drill wellbore <NUM>.

Drill string <NUM> can further include actuator assembly <NUM> and device <NUM>. Actuator assembly and device <NUM> can be installed as drilling subs that are part of the drill string assembly. In the example embodiment of <FIG>, actuator assembly <NUM> is shown extending radially into string bore <NUM> of drill string <NUM>. In alternate embodiments, actuator assembly <NUM> can be located on an outer diameter surface of drill string <NUM>. In the example embodiment of <FIG>, device <NUM> is secured in line with joints of drill string <NUM>. In alternate embodiments, device <NUM> can extend radially into string bore <NUM> of drill string <NUM>, or can extend radially outward from drill string <NUM>.

Looking at <FIG>, actuator assembly <NUM> is a tubular shaped actuator assembly with an actuator bore <NUM>. Actuator assembly <NUM> can be secured to a downhole end of a joint of drill string <NUM>. Actuator assembly <NUM> has an actuator bore <NUM> that extends axially the length of actuator assembly <NUM>. The drilling fluid can flow through the drill string <NUM>, including actuator assembly <NUM>, out the drill bit, up annulus <NUM>, and back up to terranean surface <NUM>.

Actuator assembly <NUM> includes first pipe member <NUM> and second pipe member <NUM>. First pipe member <NUM> and second pipe member are co-axially oriented. Second pipe member <NUM> can be secured to the downhole end of a joint of drill string <NUM> so that second pipe member <NUM> rotates with drill string <NUM>. Second pipe member <NUM> can have a diameter that is substantially similar or the same as the diameter of an adjacent joint of drill string <NUM>. First pipe member <NUM> can be supported by second pipe member <NUM>. First pipe member <NUM> can, for example, be supported between uphole support <NUM> and downhole support <NUM>. Uphole support <NUM> and downhole support <NUM> can extend radially from second pipe member <NUM>.

In the embodiment of <FIG>, actuator bore <NUM> is smaller than string bore <NUM> of adjacent joints of drill string <NUM> and defines the fluid flow path through actuator assembly <NUM>. The diameter of first pipe member <NUM> is smaller than the diameter of second pipe member <NUM>. Second pipe member <NUM> circumscribes first pipe member <NUM>. Uphole support <NUM> and downhole support <NUM> extend radially inward from an inner diameter surface of second pipe member <NUM>.

In the embodiment of <FIG> actuator bore <NUM> has a substantially similar diameter as string bore <NUM> of adjacent joints of drill string <NUM> and defines the fluid flow path through actuator assembly <NUM>. The diameter of first pipe member <NUM> is larger than the diameter of second pipe member <NUM>. First pipe member <NUM> circumscribes second pipe member <NUM>. Uphole support <NUM> and downhole support <NUM> extend radially outward from an outer surface of second pipe member <NUM>.

Looking at <FIG>, a plurality of bearings <NUM> can be positioned between first pipe member <NUM> and second pipe member <NUM>. Bearings <NUM> can be ball bearings. An end bearing <NUM> can be located between an end surface of first pipe member <NUM> and a support member. As an example, end bearing <NUM> can be located between an uphole end of first pipe member <NUM> and uphole support <NUM>. End bearing <NUM> can alternately be located between a downhole end of first pipe member <NUM> and downhole support <NUM>. Bearings <NUM> can rotate with second pipe member <NUM> about a central axis of second pipe member <NUM>. As an example, bearings <NUM> can be retained with second pipe member <NUM> by conventional bearing retention means.

Side bearing <NUM> is located between first pipe member <NUM> and second pipe member <NUM>. In the example embodiment of <FIG>, side bearing <NUM> can be located between an outer diameter surface of first pipe member <NUM> and an inner diameter surface of second pipe member <NUM>. Side bearing <NUM> rotates with second pipe member <NUM> around an outer diameter surface of first pipe member <NUM>. In the example embodiment of <FIG>, side bearing <NUM> can be located between an outer diameter surface of second pipe member <NUM> and an inner diameter surface of first pipe member <NUM>. Side bearing <NUM> can also be located radially exterior of first pipe member <NUM> within bearing housing <NUM>. Side bearing <NUM> rotates with second pipe member <NUM> around an outer diameter surface of second pipe member <NUM>.

Looking at <FIG>, a series of side bearings <NUM> can be positioned in axially oriented rows spaced around an inner diameter surface of second pipe member <NUM>. Looking at <FIG>, an array of segments <NUM> are spaced around a surface of first pipe member <NUM>. Segments <NUM> can be, for example, embedded in first pipe member <NUM> or be a coating applied to first pipe member <NUM>. Segments <NUM> are positioned so that segments <NUM> are aligned with bearings <NUM>. The segments are arranged in a specific configuration around first pipe member <NUM> which corresponds to signal patterns required to trigger or convey a specific command or instruction to a downhole tool, instrument, equipment, or other device. Looking at <FIG>, as an example, segment <NUM> can be located on an outer diameter surface of first pipe member <NUM> and can be axially aligned with a side bearing <NUM>. In alternate embodiments, segment <NUM> can be positioned at an uphole surface or downhole surface of first pipe member <NUM> and can be radially aligned with an end bearing <NUM>.

Segment <NUM> can be formed of a first material and bearing <NUM> can be formed of a second material. The first material can be reactive to the second material. In an embodiment of the disclosure, as drill string <NUM> is rotated, second pipe member <NUM> will rotate relative to first pipe member <NUM>. As an example, as drill string <NUM> is rotated, second pipe member <NUM> can rotate with drill string <NUM> and first pipe member <NUM> can remain static.

As bearing <NUM> rotates over and past segment <NUM>, a reaction of the first material of segments <NUM> to the second material of bearing <NUM> can be sensed. The reaction of the first material of segments <NUM> to the second material of bearing <NUM> does not require a separate power source, such as a battery. As an example, the first material can have an opposite polarity as the second material. The voltage peaks are generated due to the exchange of charges between the first material of segments <NUM> to the second material of bearing <NUM>. Certain materials are more inclined to gain electrons and other materials are more included to lose electrons. Electrons will be injected from the first material of segments <NUM> to the second material of bearing <NUM> if the first material of segments <NUM> has a higher polarity than the second material of bearing <NUM>, resulting in oppositely charged surfaces. The first material of segments <NUM> to the second material of bearing <NUM> 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.

Alternately, the first material of segments <NUM> can be a piezoelectric material and the second material can cause a mechanical stress on the first material. The first material of segments <NUM> can be, as an example, quartz, langasite, lithium niobate, titanium oxide, or any other material exhibiting piezoelectricity. In such an embodiment the piezoelectric segments are stressed when bearings <NUM> move over and along the surface of segments <NUM>. The mechanical stresses experienced by the piezoelectric materials generate electric charges resulting in voltage peaks. The constant motion due to the rotation of drill string <NUM> while drilling wellbore <NUM> enables the piezoelectric segments to go through the motions of being stressed and released to generate voltage peaks.

Another alternate method of generating voltage peaks is by forming segments <NUM> from a magnetostrictive material such as terfenol-D, galfenol, metglas or any other material that showa magnetostricitve properties. The stress applied to the magnetostrictive segments <NUM> when bearings <NUM> move over and along segments <NUM> results in a change in the magnetic field of the magnetostrictive material. This induced magnetic field can be converted to a voltage by a planar pick-up coil or a solenoid that can be fabricated with segment <NUM>.

Looking at <FIG>, each time a bearing <NUM> moves over and along a segment <NUM>, a voltage peak is generated. The example amplitude and shape of the peak in <FIG> are for illustrative purposes and the amplitude and shape of the peak can be different depending on the size and shape of bearings <NUM> and segments <NUM> as well as the speed and frequency of rotation of second pipe member <NUM> relative to first pipe member <NUM>.

The reaction of the first material of segments <NUM> to the second material of bearing <NUM> that is sensed as bearing <NUM> rotates over and past segment <NUM> and can be converted to a digital signal for interpretation by an electronics package <NUM> of actuator assembly <NUM> (<FIG>). Electronics package <NUM> can include a digital logic circuit <NUM> for signal interpretation and can include an actuator system transceiver for signaling a downhole tool, instrument, equipment, and other device, based on the instructions received by way of the predetermined pattern of the rotation of drill string <NUM> (<FIG>). The pattern can include, for example, a number of turns of drill string <NUM>, a frequency, speed, or rate of rotation of drill string <NUM>, or a direction of rotation of drill string <NUM>.

Looking at <FIG> as drill string <NUM> rotates, continuous signal patterns <NUM> are generated with voltage peaks due to bearings <NUM> moving over and along segments <NUM>, and with periods of no voltage when bearings <NUM> are rotating around the outer surface of first pipe member <NUM> where there are no segments <NUM>. The voltage peaks are converted to digital signals by an analog-to-digital converter and connected as inputs to a digital logic circuit <NUM>.

Digital logic circuit <NUM> can be a sequential logic circuit, where the output is not only a function of the inputs but is also a function of a sequence of past inputs. In order to store past inputs, sequential circuits have state or memory. Such features allow actuator assembly <NUM> to interpret the sequence of voltage peaks over time and provide a control signal to a downhole tool, instrument, equipment, and other device to perform a specific action.

The sequential logic circuits can be synchronous, asynchronous or a combination of both. Looking at <FIG>, synchronous sequential circuits have a clock <NUM>. Memory <NUM> is connected to clock <NUM>. Memory <NUM> receives inputs of all of the memory elements of the circuit, which generate a sequence of repetitive pulses to synchronize all internal changes of state. There are two types of sequential circuits, pulsed output and level output. In pulsed output circuits the output remains throughout the duration of an input pulse or the clock pulse for clocked sequential circuits. In level output sequential circuits the output changes state at the initiation of an input or clock pulse and remains in that state until the next input or clock pulse.

Looking at <FIG>, asynchronous sequential circuits do not have a periodic clock and the outputs change directly in response to changes in the inputs. Asynchronous sequential circuits are faster because they are not synchronized by a clock and the speed to process the inputs is only limited by the propagation delays of the logic gates in feedback loop <NUM> used in the circuit. However, asynchronous sequential circuits are harder to design due to timing problems arising from time-delay propagation not always being consistent throughout the stages of the circuit. The digital logic circuits can be implemented as an integrated circuit (IC) such as a field-programmable gate array (FPGA), application-specific integrated circuit (ASIC), complex programmable logic device (CPLD) or system on a chip (SoC).

Looking at <FIG>, bearings <NUM> are side bearings <NUM> and second pipe member <NUM> is rotating in a single direction relative to first pipe member <NUM>. During the drilling process the signals will have the same sequences with peak voltage amplitudes followed by periods of zero or very low voltage since drill string <NUM> will be rotating a single direction, at approximately the same speed. In embodiments of this disclosure drill string <NUM> can, as an example, be rotated in an anti-clockwise direction to drill wellbore <NUM> (<FIG>).

Digital logic circuit <NUM> will compare the signal sequences over a given time period, clock cycle or fixed set of rotations and make a decision to enable, disable or perform no action in relation to a downhole tool, instrument, equipment, or other device. Actuator assembly <NUM> can be programmed to perform no action if the signal patterns are the same over the comparison period. However, if the direction of rotation is changed from anticlockwise to a clockwise direction as shown in <FIG> then the sequence of signals changes. This change in the sequence of voltage peaks can be utilized to develop unique code sequences to execute various downhole process.

Looking at <FIG>, continuous signal patterns 52A are a result of drill string <NUM> being rotated in an anticlockwise direction so that second pipe member <NUM> rotates anticlockwise relative to first pipe member <NUM>. When drill string <NUM> changes direction and rotates in a clockwise direction, second pipe member <NUM> rotates clockwise relative to first pipe member <NUM>. The resulting continuous signal patterns 52B has a different pattern than continuous signal patterns 52A. Digital logic circuit <NUM> can recognize this change in pattern.

Actuator assembly <NUM> can be controlled from the surface. For example, during drilling operations bearings <NUM> move along and over segments <NUM> in an anticlockwise direction. If the sequence has to be changed to actuate a downhole tool, instrument, equipment, or other device, then drilling can be ceased, the drill bit can be lifted off the bottom of wellbore <NUM> and the drill string <NUM> can be rotated from the surface in a clockwise direction. Digital logic circuit <NUM> of actuator assembly <NUM> will recognize the difference in the signal sequence patterns and send a control signal to the downhole tool, instrument, equipment, or other device to perform an appropriate action.

When the drill bit is off the bottom of wellbore <NUM>, drill string <NUM> can be rotated anticlockwise or clockwise to generate a large number of signal sequence patterns, which can be translated to perform different functions. Moreover, there can be multiple actuator assembly <NUM>, each with unique segment patterns, placed at one or various locations in drill string <NUM>. Therefore, a number of downhole tools, instruments, equipment, or other devices can be controlled and triggered from the surface.

An alternate method of generating a unique signal sequence patter is by changing the frequency of the rotation of drill string <NUM> in the anticlockwise direction, the clockwise direction, or in both directions, over one or multiple cycles. The rotation speed can be i) increased and then decreased or decreased and increased in one direction; ii) increased in the anticlockwise direction and decreased in the clockwise direction; iii) increased in the clockwise direction and decreased in the anticlockwise direction; or iv) any combination of increase/decrease in anticlockwise/clockwise directions.

In other alternate embodiments, the size and shape of segments <NUM> 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 assembly. In such a case digital logic circuit <NUM> can recognize the direction of rotation and initiate action to actuate a downhole tool, instrument, equipment, or other device after a specific number of rotations. Digital logic circuit <NUM> can also compare rotation directions over a specific number of rotations.

In yet other alternate embodiments, looking at <FIG>, another method to distinguish the direction of rotation of drill string <NUM> is to provide bearings <NUM> within latch slot <NUM>. Latch slot <NUM> is a slot within second pipe member <NUM>. Bearings <NUM>, which are side bearings <NUM>, will shift to the side of latch slot <NUM> relative to the direction of angular acceleration created by the rotation of drill string <NUM>. On one side of latch slot <NUM> is cylindrical roller bearing <NUM>.

The rotation of drill string <NUM> will cause side bearing <NUM> to move within latch slot <NUM> in a direction that is opposite to the direction of the rotation of drill string <NUM>. As an example, when drill string <NUM> is rotating in an anticlockwise direction side bearing <NUM> is driven in a clockwise direction within latch slot <NUM> resulting in continuous signal patterns 52C. When drill string <NUM> is rotating in a clockwise direction side bearing <NUM> is driven in an anticlockwise direction within latch slot <NUM> resulting in continuous signal patterns 52D. The presence of the smaller cylindrical roller bearing <NUM> results in a peak of shorter width because cylindrical roller bearing <NUM> is in contact with segment <NUM> for a shorter duration of time compared to side bearings <NUM>.

When drill string <NUM> is rotating in an anticlockwise direction side bearing <NUM> is further away from cylindrical roller bearing <NUM> compared to when drill string <NUM> is rotating in the clockwise direction. Therefore, when drill string <NUM> is rotating in an anticlockwise direction the time difference T1 between the peak due to side bearing <NUM> moving along a segment <NUM> and the peak due to cylindrical roller bearing <NUM> moving along the segment <NUM> is larger than the time difference T2. T2 is the time difference between the peak due to side bearing <NUM> moving along a segment <NUM> and the peak due to cylindrical roller bearing <NUM> moving along the segment <NUM> when drill string <NUM> is rotating in a clockwise direction. Therefore continuous signal patterns 52C are not only different from continuous signal patterns 52D due to drill string <NUM> rotating in a opposite direction, but because time difference T1 and time difference T2, which can be utilized to identify the direction of rotation of drill string <NUM>.

In still other embodiments, a unique signal pattern can be generated by segments <NUM> that are located at the ends of first pipe member <NUM>. Looking at <FIG>, uphole end <NUM> of first pipe member <NUM> can include a series of segments <NUM> and downhole end <NUM> of fist pipe member can include different patter of a series of segments <NUM>. As end bearings <NUM> move along and over segments <NUM>, a signal pattern is generated. When drill string <NUM> is rotated anticlockwise, then second pipe member rotates in a direction anticlockwise relative to first pipe member <NUM> and continuous signal patterns 52E of <FIG> are generated. When drill string <NUM> is rotated anticlockwise, then second pipe member rotates in a direction anticlockwise relative to first pipe member <NUM> and continuous signal patterns 52F of <FIG> are generated.

Looking at <FIG>, in other alternate embodiments, different unique signal patterns can be generated by the use of changeable bearings <NUM>. At least one of the bearings <NUM> can be a changeable bearing. Changeable bearing <NUM> can include a dissolvable material. By dissolving the dissolvable material of changeable bearing <NUM>, the signal pattern can be changed to allow for a different instruction to be delivered to device <NUM>.

Looking at <FIG>, changeable bearing <NUM> can have outermost layer <NUM> that can be formed of the dissolvable material. In certain embodiments, changeable bearing <NUM> includes core bearing <NUM> that is formed of an electrically insulating material. The electrically insulating material is non-reactive to the first material. The non-reactive material of core bearing <NUM> can be made of materials such as carbide, silicide, oxide, nitride, or the mixture of any of these materials. In such an embodiment, outermost layer <NUM> can be the second material that is reactive to the first material.

Looking at <FIG>, in other alternate embodiments, the entire changeable bearing <NUM> can be formed of the dissolvable material. In such an embodiment, the dissolvable material is the second material and is reactive to the first material.

In embodiments where the dissolvable material is the second material, the dissolvable material can be any of metallic based material that can be dissolved in the downhole environment. More specifically, the dissolvable metal can be either a magnesium based alloy, or an aluminum based alloy. The dissolving rates of these alloys depend greatly on downhole temperature and fluid composition. The dissolving rates depend on downhole pressure to a much lesser degree. The exact composition of the dissolvable material that is the second material can be selected based on the known downhole temperature, pressure and fluid composition of a particular well that will result in the desired dissolving rate.

Alternately, a preferred dissolvable material can be selected and the dissolving rate can be adjusted by pumping fluids into subterranean well <NUM> that can either speed up or slow down the dissolving rate of the dissolvable material. As an example, if an operator wishes to speed up the dissolving rate of a dissolvable material, the operator can pump a higher-concentration brine or acid into subterranean well so that such brine or acid comes into contact with the dissolvable material. If a brine is used, the resultant in the dissolving reaction can be metal hydroxide powder, which has low dissolvability in brine and can be flushed away by the dynamic flow of downhole fluid. If an acid is used, the resultant in the dissolving reaction can be ions fully dissolved in the solutions.

Looking at <FIG>, when outermost layer <NUM> of changeable bearing <NUM> is the second material or when changeable bearing <NUM> is formed entirely of the second material, when actuator assembly <NUM> is first delivered into subterranean well <NUM>, each of the bearings <NUM> will react with segments <NUM> to generate continuous signal pattern <NUM>. Signal pattern <NUM> is interpreted by digital logic circuit <NUM> to provide a control signal to a downhole tool, instrument, equipment, and other device to perform a specific action.

The dissolvable material that is the second material of changeable bearing <NUM> can then be dissolved. The dissolvable material can be formed of a material that has been selected to dissolve over a predetermined time based on the temperature and the fluid composition and to a lesser extent, the pressure downhole within subterranean well <NUM>. Alternately the operator can pump a selected fluid into subterranean well that will affect the dissolving rate of the dissolvable material of changeable bearing <NUM>.

Looking at <FIG>, after the dissolvable material of changeable bearing <NUM> has dissolved, each of the remaining bearings <NUM> will react with segments <NUM> to generate continuous signal pattern <NUM>'. Because of the lack of reaction of certain bearings that were reactive in the generation of signal pattern <NUM> of <FIG>, signal pattern <NUM>' is a revised signal pattern. Signal pattern <NUM>' can be interpreted by digital logic circuit <NUM> to provide a control signal or instruction to a different downhole tool, instrument, equipment, or other device to perform a specific action. Alternately, signal pattern <NUM>' can be interpreted by digital logic circuit <NUM> to provide a revised control signal or revised instruction to a downhole tool, instrument, equipment, or other device to perform a specific action.

In alternate embodiments, looking at <FIG>, core bearing <NUM> can be formed of the second material, and outermost layer <NUM> can be a dissolvable material that is non-reactive to the first material. In such an embodiment, outermost layer <NUM> can be a dissolvable polymer. As an example, the dissolvable polymer can be a polyglycolic acid (PGA), polylactic acid (PLA), polymers poly(lactide-co-glycolide), polyanhydride, poly(propylene fumarate), polycaprolactone (PCL), polyethylene glycol (PEG), or a polyurethane. The dissolvable polymer can be degraded by hydrolysis in which the long chains of these polymers can be broken down to smaller polymers when exposed to water or humidity, so that they lose the structural integrity and the mechanical properties.

Outermost layer <NUM> that is formed of a dissolvable polymer can fall apart under a certain low load or erosion. Furthermore, with time and temperature increase, the dissolvable polymers with smaller chains can become acids, such as glycolic acid (for PGA) or lactic acid (for PLA). When the dissolvable polymer reaches such a stage, there is no solid part remaining. The dissolving or degradation rate of the dissolvable polymers is strongly dependent on the temperature and fluid composition of the wellbore fluids.

Looking at <FIG>, when outermost layer <NUM> of changeable bearing <NUM> is a dissolvable polymer that is non-reactive with the first material, when actuator assembly <NUM> is first delivered into subterranean well <NUM>, only certain of the bearings <NUM> will react with segments <NUM> to generate continuous signal pattern <NUM>. Changeable bearings <NUM> that have the outermost layer <NUM> of dissolvable polymer will not react with segment <NUM>. Signal pattern <NUM> is interpreted by digital logic circuit <NUM> to provide a control signal to a downhole tool, instrument, equipment, and other device to perform a specific action.

The dissolvable material of changeable bearing <NUM> that is a dissolvable polymer can then be dissolved or degraded. The dissolvable material can be formed of a material that has been selected to dissolve over a predetermined time based on the temperature and the fluid composition and to a lesser extent, the pressure downhole within subterranean well <NUM>. Alternately the operator can pump a selected fluid into subterranean well that will affect the dissolving rate of the dissolvable material of changeable bearing <NUM>.

Looking at <FIG>, after the dissolvable material of changeable bearing <NUM> has dissolved, core bearing <NUM> of each changeable bearing <NUM> will be exposed. Each of the bearings <NUM>, including changeable bearings <NUM> will now react with segments <NUM> to generate continuous signal pattern <NUM>'. Because of the addition of the reaction of changeable bearings <NUM> which were previous non-reactive in the generation of signal pattern <NUM> of <FIG>, signal pattern <NUM>' is a revised signal pattern. Signal pattern <NUM>' can be interpreted by digital logic circuit <NUM> to provide a control signal or instruction to a different downhole tool, instrument, equipment, or other device to perform a specific action. Alternately, signal pattern <NUM>' can be interpreted by digital logic circuit <NUM> to provide a revised control signal or revised instruction to a downhole tool, instrument, equipment, or other device to perform a specific action.

Looking at <FIG>, signal patterns generated by actuator assembly <NUM> can be used to instruct actuator assembly <NUM> to signal a variety of downhole tools, instruments, equipment, or other devices. As an example, actuator assembly <NUM> can be used for actuating downhole circulation subs to facilitate drilling and wellbore cleaning operations. Actuator assembly <NUM> can be used to send a trigger signal to open the circulation sub by sliding a sleeve or opening a valve to divert the drilling fluid directly into the annulus. This operation increases drilling fluid flow in the annulus and aids wellbore cleaning and can also split flow between the annulus and the drill string assembly. Once the operation is completed, actuator assembly <NUM> can be sent another trigger signal to close the circulation sub.

In alternate embodiments, actuator assembly <NUM> can be used for actuating bypass valves at a selected depth below fractures so that lost circulation material can be pumped through the bypass valves to plug the fractures. After the operation, instructions are conveyed from the surface through actuator assembly <NUM> to close the valves immediately of after a certain period of time. Similar operations can be performed to change the drilling fluid or to pump cement into the wellbore at desired depths. Actuator assembly <NUM> can further be utilized to activate and deactivate flapper valves and stimulation sleeves.

In other alternate embodiments, actuator assembly <NUM> can be used for actuating drilling reamers for increasing the size of the wellbore below casing. A drilling underreamer is a tool with cutters that is located behind a drill bit. Reamers are utilized to enlarge, smooth and condition a wellbore for running casing or completion equipment without any restrictions. Instead of pulling the drill string assembly out of the well when problems arise downhole, a reamer can be activated by actuator assembly <NUM>. The underreamer then extends and drills through with the drill bit. Another trigger signal can be sent from the surface to actuator assembly <NUM> retract the underreamer. Actuator assembly <NUM> can be programmed to extend or retract reamers in several finite steps depending on the desired diameter of the wellbore.

In still other alternate embodiments, actuator assembly <NUM> can be used to expand and retract casing scrapers. Casing scrapers are utilized to remove debris and scale left by drilling fluids on the internal casing. Casing scrapers can be run with a drilling assembly in retracted mode while drilling an open hole section. The scrapers can be expanded at any time, for example when tripping out of hole, to scrape internal casing or critical zones in internal casing.

In yet other alternate embodiments, actuator assembly <NUM> can be used to expand and contract an inflatable, production, or test packer. Expanded packers seal the wellbore to isolate zones in the wellbore and also function as a well barrier. Production or test packers are set in cased holes while inflatable packers are set in both open and cased holes.

Actuator assembly <NUM> can alternately be used for sending command signals from the surface to set liner hangers.

During drilling operations, charges are constantly being produced due to bearings <NUM> moving over and along segments <NUM>, especially while drilling. These charges not only generate signal patterns, but can also be converted from an analog signal to a digital signal by a bridge rectifier and stored in a di-electric capacitor de-rated for use at high temperatures, or can be stored in a ceramic, an electrolytic or a super capacitor. By storing the energy in a capacitor, actuator assembly <NUM> can also act as a power source.

In an example of operation, looking at <FIG> device <NUM> that is instructed by actuator assembly <NUM> can be a compartment with a door that can be opened and closed by actuator assembly <NUM> to release a product from the compartment. Drill string <NUM> with actuator assembly <NUM> and with device <NUM> is extended into wellbore <NUM> of subterranean well <NUM>. Drill string <NUM> is used to drill subterranean well <NUM>, penetrating through a variety of downhole rock formations. Looking at <FIG>, in certain embodiments, drilling can be ceased after passing through a target depth <NUM> so that device <NUM> is located adjacent to the target depth.

Looking at <FIG>, once the target depth <NUM> is reached by device <NUM>, the driller can pull the drill bit off the bottom of wellbore <NUM> and can rotate drill string <NUM> in different directions and frequencies to generate unique signal pattern from the surface that is a predetermined signal. The signal patterns are then translated into a specific action. As an example, the signal pattern can be an instruction to open a door of device <NUM> to allow for the release of product into subterranean well <NUM>.

If additional operations are required to be performed within subterranean well <NUM> and new unique signal pattern is required, then dissolvable material of changeable bearing <NUM> can be dissolved so that previous signal pattern <NUM> becomes revised signal pattern <NUM>', as disclosed in <FIG> and <FIG>. The revised signal pattern <NUM>' can be used to provide instructions for performing a different operation with the same device <NUM>, or can be used to provide instructions to a new or different device <NUM>.

Therefore embodiments of this disclosure provide systems and methods for actuating different devices, tools, and instruments from the surface it also enables the execution of discrete drilling workflows in real-time. Systems and methods of this disclosure can be controlled from the surface. 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 displace existing drilling portfolios. The proposed actuation system and methods not only allows the redesign of workflows to increase drilling efficiency but can also facilitate drilling automation by closing one of the key technology gaps, communicating with and delivering trigger signals to downhole actuation systems in real-time. Because the signal patterns are unique to a specific operation, such as releasing a selected number or type of sensors, discrete drilling workflows can be executed without affecting other downhole tools instruments, devices, or operations.

Embodiments of this disclosure allow for the generation of additional signal patterns by changing the number of reactionary bearings. These additional signal patterns could be utilized to control more than one tools or devices.

Looking at <FIG> fourth industrial revolution (referred to as "4IR") technologies such as artificial intelligence, machine learning, big data analytics, and robotics are progressing at a very rapid rate. According to an embodiment of this disclosure, human intervention to control the downhole actuation device in a drilling rig <NUM> can be replaced by an intelligent drilling system <NUM>. The intelligent drilling system <NUM> performs optimized drilling operations based on smart drilling dynamics <NUM> and smart hydraulic systems <NUM>. For example, raw data from the various sensors on a rig can be extracted, analyzed and turned into useful information by the smart drilling dynamics <NUM> and smart hydraulic systems <NUM>. If a wellbore needs to be cleaned based on the data received then this can be conveyed to the intelligent drilling system <NUM>, which in turn can rotate the drill pipe in the required configurations to generate specific sequences utilizing the actuating system. The sequences can then be converted to a specific trigger signal to open bypass valves to divert the drilling fluid into the annulus to increase the annular velocity and clean the wellbore.

One embodiment is a downhole actuation system that can be controlled from the surface to actuate digitally enabled downhole devices or tools or instruments. Actuation of different devices or tools or instruments enables the execution of discrete drilling workflows. The actuation system is a separate system that can be seamlessly integrated with downhole tools or devices or instruments so it does not displace existing drilling portfolios.

Claim 1:
A system for instructing a device (<NUM>) within a wellbore (<NUM>) of a subterranean well (<NUM>), the system including:
a drill string (<NUM>) extending into the subterranean well from a terranean surface (<NUM>), the drill string having an actuator assembly (<NUM>); characterized in that
the actuator assembly has:
a first pipe member (<NUM>) with a segment (<NUM>) formed of a first material;
a second pipe member (<NUM>) coaxially aligned with the first pipe member;
a plurality of bearings (<NUM>) positioned between the first pipe member and the second pipe member, each of the plurality of bearings including a second material, where the first material is reactive to the second material, and where at least one of the plurality of bearings is a changeable bearing (<NUM>) that includes a dissolvable material; and where
the actuator assembly is operable to instruct an operation of the device by generating an instruction signal by rotating the first pipe member relative to the second pipe member and interpreting a pattern of a reaction of the segment as the plurality of bearings rotate past the segment.