Patent Publication Number: US-2022213753-A1

Title: Magnetically controlled release of chemicals in a downhole environment

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation-in-part application of U.S. Non-Provisional patent application Ser. No. 16/720,879 filed on Dec. 19, 2019. For purposes of United States patent practice, this application incorporates the contents of the Non-Provisional application by reference in its entirety. 
    
    
     TECHNICAL FIELD 
     Disclosed are apparatus and methods for downhole chemical release. More specifically, embodiments related to systems and methods for actuation of downhole chemical storage are provided. 
     BACKGROUND 
     Drillers ‘drill in the dark’ due to their inability to see the trajectory of the well and the downhole environment. What makes drilling more challenging is that once drilling tools, including instruments and devices, are lowered into a well they are inaccessible from the surface. Conventional techniques to control these tools from the surface include mechanical methods, such as applying weight-on-bit and rotating the drillstring assembly, applying pressure and dropping balls, or hydraulic methods such as fluid pressure cycles and flowing pressure cycles. However, mechanical and hydraulic methods may introduce certain restrictions and potential challenges or issues to the drilling process. More recently radio frequency identification (RFID) based systems have been developed for drilling applications. RFID tags programmed with a unique code at the surface are dropped into wells and travel downhole with the drilling fluid flow. Downhole tools, 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 an RF field to ‘listen’ to RFID tags. The RFID 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 drillstring compared to the procedure normally used for activating bypass valves, which involves dropping an activation ball to open the two side ports. A further two balls are dropped to close the ports. Applying pressure from the surface releases all three balls that fall into a ball catcher cage below. RFID systems enable remote activation and place no restrictions on the inner diameter of the drillstring, result in a larger flow area for the drilling fluids, allow any logging instrument to pass through the drillstring without restriction, result is no risk of lost circulation materials damaging the measurement while drilling (MWD) unit or rotary steerable system (RSS) tools below the bypass valve, can be used to perform multiple operations at one depth or several depths with bypass valves placed at one location or multiple locations on the drillstring, and avoid extra trips to the surface to remove the balls or reamer from the drillstring assembly. 
     However, RFID-based systems also have disadvantages. One disadvantage is the lack of ability to release and mix chemicals downhole for reaction to take place to address and mitigate downhole issues. 
     SUMMARY OF THE DISCLOSURE 
     Disclosed are apparatus and methods for downhole chemical release. More specifically, embodiments related to systems and methods for actuation of downhole chemical storage are provided. 
     In a first aspect, a method for on demand release of a downhole chemical is provided. The method includes the steps of extending a drillstring into a wellbore of a subterranean well from a terranean surface. The drill string includes an actuator assembly and a modified stabilizer, where the modified stabilizer includes one or more chemical storage compartments extending from a body, where the one or more chemical storage compartments are hollow and have an electromagnet and a magnetically-actuated door in proximity to the electromagnet. The method includes the further steps of identifying a downhole issue in the wellbore, where the downhole issue is selected from the group consisting of lost circulation, shale instability, stuck pipe, friction issues, viscosity adjustments, mud weight adjustments, hole cleaning requirements, and combinations of the same and activating the actuator assembly to transmit a signal to turn on the electromagnet of the modified stabilizer. The actuator assembly includes a first pipe member with a segment formed of a first material, a second pipe member circumscribing the first pipe member, a bearing positioned between the first pipe member and the second pipe member, the bearing formed of a second material, where the first material is reactive to the second material, where activating the actuator assembly to transmit a signal to turn on the electromagnet includes rotating the drillstring to rotate the first pipe member relative to the second pipe member in a predetermined pattern, and interpreting a resulting reaction of the segment as the bearing rotates past the segment. The method further includes the steps of creating a magnetic field when the electromagnet is turned on by the actuator assembly, opening the magnetically-actuated door due to the magnetically-actuated door being physically attracted to the magnetic field of the electromagnet, where the chemical storage compartment is fluidly connected to the wellbore through the open magnetically-actuated door, releasing downhole chemicals from the chemical storage compartment through the magnetically-actuated door, activating the actuator assembly to transmit a signal to turn off the electromagnet of the modified stabilizer, removing the magnetic field when the electromagnet is turned off by the actuator assembly, and closing the magnetically-actuated door when the magnetic field is removed. 
     In certain aspects, the method further includes the step of reacting the downhole chemicals with a fluid in the wellbore such that a reaction product of the downhole chemicals and the fluid address the downhole issue. In certain aspects, the method further includes the step of reacting the downhole chemicals with a fluid in the wellbore such that a reaction product of the downhole chemicals and the fluid address the downhole issue, where the downhole issue is lost circulation, where the downhole chemical includes an amine-based crosslinker, where the fluid in the wellbore is a lost circulation material includes an epoxy-based resin such that the amine-based crosslinker reacts with the epoxy-based resin to control the lost circulation. In certain aspects, the method further includes the step of reacting the downhole chemicals with a fluid in the wellbore such that a reaction product of the downhole chemicals and the fluid address the downhole issue, where the downhole issue is reduced viscosity, where the downhole chemical includes a water absorbing polymer, where the fluid in the wellbore is an aqueous-based fluid such that the water absorbing polymer reacts with the aqueous-based fluid to increase the viscosity of the fluid. In certain aspects, the actuator assembly is activated from the terranean surface. In certain aspects, the segment is located on an outer diameter surface of the first pipe member and is axially aligned with a side bearing, the side bearing being located between the outer diameter surface of the first pipe member and an inner diameter surface of the second pipe member. In certain aspects, the segment is positioned at and end surface of the first pipe member and is radially aligned with an end bearing, the end bearing being located between the end surface of the first pipe member and a support member secured to the second pipe member that extends radially from the second pipe member. 
     In a second aspect, a system for on demand release on a downhole chemical is provided. The system includes a drillstring extending into a subterranean well from a terranean surface, an actuator assembly physically connected to the drillstring, and the modified stabilizer physically connected to the drillstring. The modified stabilizer includes a body, and a chemical storage compartment physically connected to the body, the chemical storage compartment defining a hollow compartment configured to hold the downhole chemical. The chemical storage compartment includes the electromagnet, electrically connected to the actuator assembly, and a magnetically-actuated door proximately positioned to the electromagnet such that a magnetic field produced by the electromagnets moves the magnetically-actuated door. 
     In certain aspects, the system further including a support member extending radially inward from an inner diameter surface of the second pipe member, the support member supporting the first pipe member within a central bore of the second pipe member. In certain aspects, the system the downhole chemicals are selected from the group consisting of lost circulation materials, hole cleaning materials, fluid viscosity materials, activators, crosslinkers, water absorbing polymers, and combinations of the same. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       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&#39;s scope, for the disclosure may admit to other equally effective embodiments. 
         FIG. 1  is a section view of a subterranean well with a drill string having an actuator assembly and a sensor compartment, in accordance with an embodiment of this disclosure. 
         FIG. 2  is a section view of an actuator assembly, in accordance with an embodiment of this disclosure. 
         FIG. 3  is a section view of an actuator assembly, in accordance with an alternate embodiment of this disclosure. 
         FIG. 4  is a perspective view of a second pipe member of an actuator assembly, in accordance with an embodiment of this disclosure. 
         FIG. 5  is a perspective view of a first pipe member of an actuator assembly, in accordance with an embodiment of this disclosure. 
         FIG. 6  is a schematic representation of a signal pattern generated by an actuator assembly, in accordance with an embodiment of this disclosure, shown with the drill pipe rotating in a single direction. 
         FIG. 7  is a schematic representation of a digital logic circuit of an actuator assembly, in accordance with an embodiment of this disclosure. 
         FIG. 8  is a schematic representation of a digital logic circuit of an actuator assembly, in accordance with an alternate embodiment of this disclosure. 
         FIG. 9  is a schematic representation of continuous signal patterns generated by an actuator assembly, in accordance with an embodiment of this disclosure, shown with the drill pipe rotating in both an anticlockwise and clockwise direction. 
         FIG. 10  is an elevation view of a bearing assembly of an actuator assembly, in accordance with an embodiment of this disclosure. 
         FIG. 11  is a schematic representation of continuous signal patterns generated by an actuator assembly, in accordance with an alternate embodiment of this disclosure, shown with the drill pipe rotating in both an anticlockwise and clockwise direction. 
         FIG. 12  is a is a schematic representation of continuous signal patterns generated by end bearings of an actuator assembly, in accordance with an alternate embodiment of this disclosure, shown with the drill pipe rotating in an anticlockwise direction. 
         FIG. 13  is a is a schematic representation of continuous signal patterns generated by end bearings of an actuator assembly, in accordance with an alternate embodiment of this disclosure, shown with the drill pipe rotating in a clockwise direction. 
         FIG. 14  is a section view of a subterranean well with a drill string having an actuator assembly and a modified stabilizer, in accordance with an embodiment of this disclosure. 
         FIG. 15A-15B  are section views of an operation of the actuation assembly and modified stabilizer releasing the downhole chemicals in accordance with an embodiment of this disclosure. 
         FIG. 16A-16C  are section view of the operation of the modified stabilizer releasing the downhole chemicals in accordance with an embodiment of this disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The Specification, which includes the Summary of Disclosure, Brief Description of the Drawings and the Detailed Description, and the appended Claims refer to particular features (including process or method steps) of the disclosure. Those of skill in the art understand that the disclosure includes all possible combinations and uses of particular features described in the Specification. Those of skill in the art understand that the disclosure is not limited to or by the description of embodiments given in the Specification. The inventive subject matter is not restricted except only in the spirit of the Specification and appended Claims. 
     Those of skill in the art also understand that the terminology used for describing particular embodiments does not limit the scope or breadth of the disclosure. In interpreting the Specification and appended Claims, all terms should be interpreted in the broadest possible manner consistent with the context of each term. All technical and scientific terms used in the Specification and appended Claims have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure relates unless defined otherwise. 
     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. 1 , subterranean well  10  can have wellbore  12  that extends to an earth&#39;s or terranean surface  14 . Subterranean well  10  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  16  can extend into and be located within wellbore  12 . Annulus  18  is defined between an outer diameter surface of drill string  16  and the inner diameter of wellbore  12 . Drill string  16  can include a string of tubular joints and bottom hole assembly  20 . The tubular joints can extend from terranean surface  14  into subterranean well  10 . Bottom hole assembly  20  can include, for example, drill collars, stabilizers, reamers, shocks, a bit sub and the drill bit. Drill string  16  can be used to drill wellbore  12 . Drill string  16  has a string bore  28  that is a central bore extending the length of drill string  16 . Drill string  16  can be rotated to rotate the bit to drill wellbore  12 . 
     In the example embodiment of  FIG. 1 , drill string  16  can further include actuator assembly  22 , sensor compartment  24 , and a plurality of sensors  26  located within sensor compartment  24 . Actuator assembly  22  and sensor compartment  24  can be installed as drilling subs that are part of the drill string assembly. In the example embodiment of  FIG. 1 , actuator assembly  22  is shown extending radially into string bore  28  of drill string  16 . In alternate embodiments, actuator assembly  22  can be located on an outer diameter surface of drill string  16 . In the example embodiment of  FIG. 1 , sensor compartment  24  is shown located on the outer diameter surface of drill string  16 . In alternate embodiments, sensor compartment  24  can extend radially into string bore  28  of drill string  16 . 
     Looking at  FIGS. 2 and 3 , actuator assembly  22  is a tubular shaped actuator assembly with an actuator bore  30 . Actuator assembly  22  can be secured to a downhole end of a joint of drill string  16 . Actuator assembly  22  has an actuator bore  30  that extends axially the length of actuator assembly  22 . The drilling fluid can flow through the drill string  16 , including actuator assembly  22 , out the drill bit, up annulus  18 , and back up to terranean surface  14 . 
     Actuator assembly  22  includes first pipe member  32  and second pipe member  34 . First pipe member  32  and second pipe member are co-axially oriented. Second pipe member  34  can be secured to the downhole end of a joint of drill string  16  so that second pipe member  34  rotates with drill string  16 . Second pipe member  34  can have a diameter that is substantially similar or the same as the diameter of an adjacent joint of drill string  16 . First pipe member  32  can be supported by second pipe member  34 . First pipe member  32  can, for example, be supported between uphole support  36  and downhole support  38 . Uphole support  36  and downhole support  38  can extend radially from second pipe member  34 . 
     In the embodiment of  FIG. 2 , actuator bore  30  is smaller than string bore  28  of adjacent joints of drill string  16  and defines the fluid flow path through actuator assembly  22 . The diameter of first pipe member  32  is smaller than the diameter of second pipe member  34 . Second pipe member  34  circumscribes first pipe member  32 . Uphole support  36  and downhole support  38  extend radially inward from an inner diameter surface of second pipe member  34 . 
     In the embodiment of  FIG. 3  actuator bore  30  has a substantially similar diameter as string bore  28  of adjacent joints of drill string  16  and defines the fluid flow path through actuator assembly  22 . The diameter of first pipe member  32  is larger than the diameter of second pipe member  34 . First pipe member  32  circumscribes second pipe member  34 . Uphole support  36  and downhole support  38  extend radially outward from an outer surface of second pipe member  34 . 
     Looking at  FIGS. 2-3 , bearings  40  can be positioned between first pipe member  32  and second pipe member  34 . Bearings  40  can be ball bearings. An end bearing  42  can be located between an end surface of first pipe member  32  and a support member. As an example, end bearing  42  can be located between an uphole end of first pipe member  32  and uphole support  36 . End bearing  42  can alternately be located between a downhole end of first pipe member  32  and downhole support  38 . Bearings  40  can rotate with second pipe member  34  about a central axis of second pipe member  34 . As an example, bearings  40  can be retained with second pipe member  34  by conventional bearing retention means. 
     Side bearing  44  is located between first pipe member  32  and second pipe member  34 . In the example embodiment of  FIG. 2 , side bearing  44  can be located between an outer diameter surface of first pipe member  32  and an inner diameter surface of second pipe member  34 . Side bearing  44  rotates with second pipe member  34  around an outer diameter surface of first pipe member  32 . In the example embodiment of  FIG. 3 , side bearing  44  can be located between an outer diameter surface of second pipe member  34  and an inner diameter surface of first pipe member  32 . Side bearing  44  can also be located radially exterior of first pipe member  32  within bearing housing  46 . Side bearing  44  rotates with second pipe member  34  around an outer diameter surface of second pipe member  34 . 
     Looking at  FIG. 4 , a series of side bearings  44  can be positioned in axially oriented rows spaced around an inner diameter surface of second pipe member  34 . Looking at  FIG. 5 , an array of segments  48  are spaced around a surface of first pipe member  32 . Segments  48  can be, for example, embedded in first pipe member  32  or be a coating applied to first pipe member  32 . Segments  48  are positioned so that segments  46  are aligned with bearings  40 . The segments are arranged in a specific configuration around first pipe member  32  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. 2 , as an example, segment  48  can be located on an outer diameter surface of first pipe member  32  and can be axially aligned with a side bearing  44 . In alternate embodiments, segment  48  can be positioned at an uphole surface or downhole surface of first pipe member  32  and can be radially aligned with an end bearing  42 . 
     Segment  48  can be formed of a first material and bearing  40  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  16  is rotated, second pipe member  34  will rotate relative to first pipe member  32 . As an example, as drill string  16  is rotated, second pipe member  34  can rotate with drill string  16  and first pipe member  32  can remain static. 
     As bearing  40  rotates over and past segment  48 , a reaction of the first material of segments  48  to the second material of bearing  40  can be sensed. The reaction of the first material of segments  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 as the second material. The voltage peaks are generated due to the exchange of charges between the first material of segments  48  to the second material of bearing  40 . 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  48  to the second material of bearing  40  if the first material of segments  48  has a higher polarity than the second material of bearing  40 , resulting in oppositely charged surfaces. The first material of segments  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. 
     Alternately, the first material of segments  48  can be a piezoelectric material and the second material can cause a mechanical stress on the first material. The first material of segments  48  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  40  move over and along the surface of segments  48 . 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  16  while drilling wellbore  12  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  48  from a magnetostrictive material such as terfenol-D, galfenol, metglas or any other material that show a magnetostrictive properties. The stress applied to the magnetostrictive segments  48  when bearings  40  move over and along segments  48  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  48 . 
     Looking at  FIG. 6 , each time a bearing  40  moves over and along a segment  48 , a voltage peak is generated. The example amplitude and shape of the peak in  FIG. 6  are for illustrative purposes and the amplitude and shape of the peak can be different depending on the size and shape of bearings  40  and segments  48  as well as the speed and frequency of rotation of second pipe member  34  relative to first pipe member  32 . 
     The reaction of the first material of segments  48  to the second material of bearing  40  that is sensed as bearing  40  rotates over and past segment  48  and can be converted to a digital signal for interpretation by an electronics package  50  of actuator assembly  22  ( FIG. 2 ). Electronics package  50  can include a digital logic circuit  54  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  16  ( FIG. 1 ). The pattern can include, for example, a number of turns of drill string  16 , a frequency, speed, or rate of rotation of drill string  16 , or a direction of rotation of drill string  16 . 
     Looking at  FIG. 6  as drill string  16  rotates, continuous signal patterns  52  are generated with voltage peaks due to bearings  40  moving over and along segments  48 , and with periods of no voltage when bearings  40  are rotating around the outer surface of first pipe member  32  where there are no segments  48 . The voltage peaks are converted to digital signals by an analog-to-digital converter and connected as inputs to a digital logic circuit  54 . 
     Digital logic circuit  54  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  22  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. 7 , synchronous sequential circuits have a clock  56 . Memory  58  is connected to clock  56 . Memory  58  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. 8 , 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  60  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. 6 , bearings  40  are side bearings  44  and second pipe member  34  is rotating in a single direction relative to first pipe member  32 . 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  16  will be rotating a single direction, at approximately the same speed. In embodiments of this disclosure drill string  16  can, as an example, be rotated in an anticlockwise direction to drill wellbore  12  ( FIG. 1 ). 
     Digital logic circuit  54  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  22  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. 9  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. 9 , continuous signal patterns  52 A are a result of drill string  16  being rotated in an anticlockwise direction so that second pipe member  34  rotates anticlockwise relative to first pipe member  32 . When drill string  16  changes direction and rotates in a clockwise direction, second pipe member  34  rotates clockwise relative to first pipe member  32 . The resulting continuous signal patterns  52 B has a different pattern than continuous signal patterns  52 A. Digital logic circuit  54  can recognize this change in pattern. 
     Actuator assembly  22  can be controlled from the surface. For example, during drilling operations bearings  40  move along and over segments  48  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  12  and the drill string  16  can be rotated from the surface in a clockwise direction. Digital logic circuit  54  of actuator assembly  22  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  12 , drill string  16  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  22 , each with unique segment patterns, placed at one or various locations in drill string  16 . 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  16  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  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 assembly. In such a case digital logic circuit  54  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  54  can also compare rotation directions over a specific number of rotations. 
     In yet other alternate embodiments, looking at  FIGS. 10-11 , another method to distinguish the direction of rotation of drill string  16  is to provide bearings  40  within latch slot  62 . Latch slot  62  is a slot within second pipe member  34 . Bearings  40 , which are side bearings  44 , will shift to the side of latch slot  62  relative to the direction of angular acceleration created by the rotation of drill string  16 . On one side of latch slot  62  is cylindrical roller bearing  64 . 
     The rotation of drill string  16  will cause side bearing  44  to move within latch slot  62  in a direction that is opposite to the direction of the rotation of drill string  16 . As an example, when drill string  16  is rotating in an anticlockwise direction side bearing  44  is driven in a clockwise direction within latch slot  62  resulting in continuous signal patterns  52 C. When drill string  16  is rotating in a clockwise direction side bearing  44  is driven in an anticlockwise direction within latch slot  62  resulting in continuous signal patterns  52 D. The presence of the smaller cylindrical roller bearing  64  results in a peak of shorter width because cylindrical roller bearing  64  is in contact with segment  48  for a shorter duration of time compared to side bearings  44 . 
     When drill string  16  is rotating in an anticlockwise direction side bearing  44  is further away from cylindrical roller bearing  64  compared to when drill string  16  is rotating in the clockwise direction. Therefore, when drill string  16  is rotating in an anticlockwise direction the time difference T 1  between the peak due to side bearing  44  moving along a segment  48  and the peak due to cylindrical roller bearing  64  moving along the segment  48  is larger than the time difference T 2 . T 2  is the time difference between the peak due to side bearing  44  moving along a segment  48  and the peak due to cylindrical roller bearing  64  moving along the segment  48  when drill string  16  is rotating in a clockwise direction. Therefore continuous signal patterns  52 C are not only different from continuous signal patterns  52 D due to drill string  16  rotating in a opposite direction, but because time difference T 1  and time difference T 2 , which can be utilized to identify the direction of rotation of drill string  16 . 
     In still other embodiments, a unique signal pattern can be generated by segments  48  that are located at the ends of first pipe member  32 . Looking at  FIGS. 12-13 , uphole end  66  of first pipe member  32  can include a series of segments  48  and downhole end  68  of first pipe member can include different patter of a series of segments  48 . As end bearings  42  move along and over segments  48 , a signal pattern is generated. When drill string  16  is rotated anticlockwise, then second pipe member rotates in a direction anticlockwise relative to first pipe member  32  and continuous signal patterns  52 E of  FIG. 12  are generated. When drill string  16  is rotated anticlockwise, then second pipe member rotates in a direction anticlockwise relative to first pipe member  32  and continuous signal patterns  52 F of  FIG. 13  are generated. 
     During drilling operations, charges are constantly being produced due to bearings  40  moving over and along segments  48 , 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  22  can also act as a power source. 
     Signal patterns generated by actuator assembly  22  can be used to instruct actuator assembly  22  to signal a variety of downhole tools, instruments, equipment, or other devices. As an example, actuator assembly  22  can be used for actuating downhole circulation subs to facilitate drilling and wellbore cleaning operations. Actuator assembly  22  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  22  can be sent another trigger signal to close the circulation sub. 
     In alternate embodiments, actuator assembly  22  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  22  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  22  can further be utilized to activate and deactivate flapper valves and stimulation sleeves. 
     In other alternate embodiments, actuator assembly  22  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  22 . The underreamer then extends and drills through with the drill bit. Another trigger signal can be sent from the surface to actuator assembly  22  retract the underreamer. Actuator assembly  22  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  22  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  22  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  22  can alternately be used for sending command signals from the surface to set liner hangers. 
     Turning to  FIG. 14  and  FIG. 16A , drill string  16  can include actuator assembly  22  and modified stabilizer  70 . Actuator assembly  22  and modified stabilizer  70  can be installed as drilling subs that are part of the drill string assembly. In the example embodiment of  FIG. 14 , actuator assembly  22  is shown extending radially into string bore  28  of drill string  16 . In alternate embodiments, actuator assembly  22  can be located on an outer diameter surface of drill string  16 . 
     Modified stabilizer  70  can be any stabilizer capable of stabilizing and centralizing a drill string in a wellbore. Modified stabilizer  70  includes chemical storage compartments  72  and body  74 . Chemical storage compartments  72  and body  74  of modified stabilizer  70  can be formed of materials such as steel, titanium, silicon carbide, aluminum silicon carbide Inconel, and pyroflask to reduce the effect of high temperature encountered in downhole environments. 
     Chemical storage compartments  72  can be the hollowed blades which extend radially from body  74 . Chemical storage compartments  72  include magnetically-actuated door  76  and electromagnet  78 . Chemical storage compartments  72  can be configured to hold downhole chemicals. 
     The downhole chemicals suitable for use include lost circulation materials, hole cleaning materials, fluid viscosity materials, activators, crosslinkers, water absorbing polymers, and combinations of the same. In embodiments where modified stabilizer  70  contains more than one chemical storage compartment  72 , each chemical storage compartment can contain the same downhole chemical or each chemical storage compartment can contain a different downhole chemical. 
     Signal patterns generated by actuator assembly  22  can be used to magnetize or demagnetize electromagnet  78  to open and close magnetically-actuated door  76 . 
     Looking at  FIG. 15A , drill string  16  with actuator assembly  22  and modified stabilizer  70  is extended into wellbore  12  of subterranean well  10 . Drill string  16  is used to drill subterranean well  10 , penetrating through a variety of downhole rock formations. During drilling, drilling fluid fills wellbore  12  and surrounds drill string  16 . In an alternate embodiment, a different fluid can be introduced to the wellbore before during or after drilling. When a downhole issue is identified, actuator assembly  22  can be activated. Downhole issues can include lost circulation, shale instability, stuck pipe, friction issues, viscosity adjustments, mud weight adjustments, hole cleaning requirements, and combinations of the same. These downhole issues can be identified by data readings from sensors in the wellbore, from readings of the return mud, or from any other standard method of capturing data about the drilling process.  FIG. 16B  shows modified stabilizer before the magnetic field is activated with the downhole chemical in chemical storage compartment  72  and magnetically-actuated door  76  closed. 
     Activating actuator assembly  22  transmits a signal pattern to turn on electromagnet  78 . Turning on electromagnet  78  such that electromagnet  78  is magnetized and creates a magnetic field. Looking at  FIG. 15B  and  FIG. 16C , magnetically-actuated door  76  is attracted to the magnetic field and physically moves toward the magnetic field of electromagnet  78  opening the magnetically-actuated door  76 . The opening of magnetically-actuated door  76  creates a fluid connection between chemical storage compartment  72  and wellbore  12  releasing the downhole chemicals from chemical storage compartment  72 . 
     The downhole chemicals released from chemical storage compartment  72  mix with the fluid in wellbore  12  and react with one or more components in the fluid. The reaction products address, mitigate, or reduce the downhole issue. 
     After the downhole chemicals release from chemical storage compartment  72 , actuator assembly  22  can be activated to transmit a signal pattern to turn off electromagnet  78 . Turning off electromagnet  78  demagnetizes electromagnet  78  removing the magnetic field. Removing the magnetic field causes magnetically-actuated door  76  to move away from electromagnet  76  closing magnetically-actuated door  76  such that there is no fluid connection between chemical storage compartment  72  and wellbore  12 . 
     The method and system described herein can be used to release downhole chemicals on demand to address a variety of downhole issues that can be solved by having chemical reactions begin or occur in the wellbore. Examples of downhole issues that are addressed through downhole chemical reactions include lost circulation, shale instability, stuck pipe, friction, viscosity adjustments, mud weight adjustments, and hole cleaning. Advantageously and unexpectedly, the actuator assembly combined with the magnetically-actuated doors has the ability to release downhole chemicals on demand. One example of the use of the methods described here is the use of the actuator assembly and modified stabilizer to mitigate lost circulation. In such example embodiment, the chemical storage compartments can be filled with a crosslinker as the downhole chemical. An example crosslinker is an amine-based crosslinker. During a lost circulation event, an LCM slurry containing a cross-linkable polymer can be pumped from the surface into the wellbore. An example of a cross-linkable polymer is an epoxy-based resin. The actuator assembly can trigger the electromagnet to release the magnetically-actuated doors and release the crosslinker into the LCM slurry containing the cross-linkable polymer. Once mixed with the LCM slurry containing the cross-linkable polymer, the crosslinker reacts with the cross-linkable polymer in the LCM slurry to develop a settable mass to plug fractures and vugs to control loss of circulation into fractures. 
     An alternate example of the methods described here is the use of the actuator assembly and modified stabilizer to increase viscosity. In such example embodiment, the chemical storage compartments can be filled with a water absorbing polymers, such as sodium polyacrylate. The actuator assembly can trigger the electromagnet to release the magnetically-actuated doors and release the water absorbing polymer into the fluid in the wellbore. The water absorbing polymers will then absorb water in the fluid in wellbore and increase the viscosity of the fluid. Depending on the fluid, this could include converting the fluid into a high viscosity pill. 
     Advantageously and unexpectedly, the method and system described herein could be used to release downhole chemicals on demand to address a variety of downhole situations that could be solved by having chemical reactions begin or occur in the wellbore. Examples of downhole situations that are addressed through downhole chemical reactions include lost circulation, shale instability, stuck pipe, friction, viscosity adjustments, mud weight adjustments, and hole cleaning. Advantageously and unexpectedly, the actuator assembly combined with the magnetically-actuated doors has the ability to release downhole chemicals on demand. 
     Advantageously and unexpectedly, the actuator assembly and modified stabilizer allows for release of downhole chemicals in the wellbore ensuring that reactions occur at the correct spot in the wellbore or formation. Advantageously and unexpectedly, the actuator assembly and modified stabilizer combination provide method and system to overcome limitations of conventional chemical treatment methods and allow changes to fluid properties in the wellbore. Advantageously and unexpectedly, the combination of actuator assembly and modified stabilizer enables total control of the chemical system for any given downhole conditions, including time depth and temperature. Advantageously and unexpectedly, the actuator assembly and modified stabilizer increase drilling efficiency and facilitate drilling automation by communicating with and delivering trigger signals to downhole actuation systems in real-time. Advantageously and unexpectedly, the actuator assembly and modified stabilizer can be controlled from the surface to release the downhole chemicals through the magnetically-actuated doors. 
     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 described herein, therefore, are well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While certain embodiments have been described for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the scope of the present disclosure disclosed herein and the scope of the appended claims.