Systems, methods, and devices for directionally drilling an oil well while rotating including remotely controlling drilling equipment

Abstract

Methods, systems, and storage media are presented for operating a drill string within a well. Exemplary implementations may: detect, using one or more sensors, data representing an analog control command sequence; analyze the analog control command sequence; determine that the control command sequence represents a command to change an operational mode of the drill string from a first operational mode to a second operational mode; and transmit a signal to an actuator of the drill string, the signal representing an electronic command to activate the actuator in such a way as to change the drill string from the first operational mode to the second operational mode. In some embodiments, the analog control sequence may comprise a predetermined sequence of rotational inputs, vibrational inputs, pressure inputs, or a combination thereof.

Claims

1. A method of operating a drill string within a well, the method comprising: receiving data from one or more sensors of the drill string, the data representing an analog control command sequence comprising a predetermined sequence of rotational inputs to the drill string; analyzing the analog control command sequence; determining that the control command sequence represents a command to change an operational mode of the drill string from a first operational mode to a second operational mode; and transmitting a signal to an actuator of the drill string, the signal representing an electronic command to activate the actuator in such a way as to change the drill string from the first operational mode to the second operational mode.

2. The method of claim 1, wherein the analog control sequence further comprises a predetermined sequence of vibrational inputs to the drill string.

3. The method of claim 2, wherein the predetermined sequence of vibrational inputs comprises actuations of at least one pump associated with the downhole device.

4. The method of claim 1, wherein the drill string further comprises: a substantially cylindrical body comprising a plurality of segments; and an anchoring subassembly segment comprising one or more retractable anchors; wherein: the actuator comprises an electronic driver that, when the drill string is in the second operational mode, activates an internal mechanism of the anchoring subassembly to force the retractable anchors outward to contact a wall of the well such that rotational motion of the anchoring subassembly is inhibited while axial movement of the anchoring subassembly segment is not prevented.

5. The method of claim 4, wherein a clutch assembly is configured to allow for rotation of the drill string above the anchoring subassembly when the drill string is in the second operational mode.

6. The method of claim 1, wherein the drill string further comprises: a first and second tubular member, the first and second tubular members at least partially nested within each other and each of the first and second tubular members having a threaded connection at its distal end; and an axially moveable cylindrical sleeve disposed laterally between the first and second tubular members; wherein: the cylindrical sleeve is rotationally coupled to the first tubular member; the actuator comprises an electric motor configured to cause axial movement of the cylindrical sleeve when activated; when the drill string is in the first operational mode, the cylindrical sleeve is rotationally coupled to the second tubular member; and when the drill string is in the second operational mode, the cylindrical sleeve is rotationally decoupled from the second tubular member.

7. The method of claim 1, wherein the drill string further comprises: a substantially cylindrical body comprising a plurality of segments; a circulating subassembly segment comprising a bottom aperture at the distal end of the circulating subassembly and one or more annulus apertures in a side wall of the circulating subassembly; and a hollow cylindrical sleeve positioned within the circulating subassembly; wherein: the actuator comprises an electric motor configured to cause axial movement of the cylindrical sleeve when activated; when the drill string is in the first operational mode, the cylindrical sleeve is positioned such that the one or more annulus apertures are blocked and a fluid may flow through the bottom aperture, which is not blocked; and when the drill string is in the second operational mode, the cylindrical sleeve is positioned such that the fluid may flow through both the one or more annulus apertures and the bottom aperture.

8. The method of claim 7, further comprising a third operational mode of the drill string, wherein a ball valve is configured to inhibit the fluid from flowing through the bottom aperture while the cylindrical sleeve is positioned to allow the fluid to flow through the one or more annulus apertures.

9. A system comprising: a drill string; and one or more hardware processors configured by machine-readable instructions to: receive data from one or more sensors of the drill string, the data representing an analog control sequence comprising a predetermined sequence of vibrational inputs to the drill string including actuations of at least one pump associated with the downhole device; analyze the analog control sequence; determine that the analog control sequence represents a command to change an operational mode of the drill string from a first operational mode to a second operational mode; and transmit a signal to an actuator of the drill string, the signal representing an electronic command to activate the actuator in such a way as to change the drill string from the first operational mode to the second operational mode.

10. The system of claim 9, wherein the analog control sequence further comprises a predetermined sequence of rotational inputs to the drill string.

11. The system of claim 9, wherein the drill string further comprises: a substantially cylindrical body comprising a plurality of segments; and an anchoring subassembly segment comprising one or more retractable anchors; wherein: the actuator comprises an electronic driver that, when the drill string is in the second operational mode, activates an internal mechanism of the drill string to force the retractable anchors of the anchoring subassembly outward to contact a wall of the well such that rotational motion of the anchoring subassembly is inhibited while axial movement of the anchoring subassembly segment is not prevented.

12. The system of claim 11, further comprising a clutch assembly configured to allow for rotation of the drill string above the anchoring subassembly when the drill string is in the second operational mode.

13. The system of claim 9, wherein the drill string further comprises: a first and second tubular member, the first and second tubular members at least partially nested within each other and each of the first and second tubular members having a threaded connection at its distal end; and an axially moveable cylindrical sleeve disposed laterally between the first and second tubular members; wherein: the cylindrical sleeve is rotationally coupled to the first tubular member; the actuator comprises an electric motor configured to cause axial movement of the cylindrical sleeve when activated; when the drill string is in the first operational mode, the cylindrical sleeve is rotationally coupled to the second tubular member; and when the drill string is in the second operational mode, the cylindrical sleeve is rotationally decoupled from the second tubular member.

14. The system of claim 9, wherein the drill string further comprises: a substantially cylindrical body comprising a plurality of segments; a circulating subassembly segment comprising a bottom aperture at the distal end of the circulating subassembly and one or more annulus apertures in the side wall of the circulating subassembly; and a hollow cylindrical sleeve positioned within the circulating subassembly; wherein: the actuator comprises an electric motor configured to cause axial movement of the cylindrical sleeve when activated; when the drill string is in the first operational mode, the cylindrical sleeve is positioned such that the one or more annulus apertures are blocked and a fluid may flow through the bottom aperture, which is not blocked; and when the drill string is in the second operational mode, the cylindrical sleeve is positioned such that the fluid may flow through both the one or more annulus apertures and the bottom aperture.

15. The system of claim 14, further comprising a third operational mode of the drill string, wherein a ball valve is configured to inhibit the fluid from flowing through the bottom aperture while the cylindrical sleeve is positioned to allow the fluid to flow through the one or more annulus apertures.

16. An anchoring subassembly of a drill string within a well, the anchoring subassembly comprising: one or more retractable anchors positioned about an axis of the anchor subassembly, the retractable anchors having a radially extended position and a radially retracted position; an actuator segment comprising an electronic driver configured to radially move the retractable anchors between the radially extended position and the radially retracted position; and an electronic control module configured to receive data from one or more sensors of the drill string, the data representing an analog control sequence including a predetermined sequence of rotational inputs to the drill string, the electronic control module further configured to: determine that the control command sequence represents a command to change an operational mode of the drill string from a first operational mode to a second operational mode or from the second operational mode to the first operational mode, the first operational mode associated with the radially retracted position of the retractable anchors and the second operational mode associated with the radially extended position of the retractable anchors; and transmit a signal to the actuator of the drill string, the signal representing an electronic command to move the retractable anchors into the radially extended position or into the radially retracted position according to the particular operational mode indicated by the analog control sequence, such that when the drill string is in the second operational mode, the retractable anchors contact the well bore such that rotational motion of the anchoring subassembly is inhibited while axial movement of the anchoring subassembly is not prevented.

17. The anchoring subassembly of claim 16, wherein the analog control sequence further comprises a predetermined sequence of vibrational inputs to the drill string, the predetermined sequence of vibrational inputs comprising actuations of at least one pump associated with the downhole device.

18. A clutch subassembly of a drill string within a well, the clutch assembly comprising: at least a first tubular member and a second tubular member, the first and second tubular members at least partially nested within each other and each of the first and second tubular members having a threaded connection at its distal end; an axially moveable cylindrical sleeve disposed laterally between the first and second tubular members, the cylindrical sleeve rotationally coupled to the first tubular member, the cylindrical sleeve having an engaged position wherein the cylindrical sleeve is rotationally coupled to the second tubular member, the cylindrical sleeve also having a disengaged position wherein the cylindrical sleeve is rotationally disengaged from the second tubular member; an actuator comprising an electric motor configured to cause axial movement of the cylindrical sleeve when activated; an electronic control module configured to receive data from one or more sensors of the drill string, the data representing an analog control command sequence, the electronic control module further configured to: determine that the control command sequence represents a command to change an operational mode of the drill string from a first operational mode to a second operational mode or from the second operational mode to the first operational mode, the first operational mode associated with the engaged position of the cylindrical sleeve and the second operational mode associated with the disengaged position of the cylindrical sleeve; transmit a signal to the actuator of the drill string, the signal representing an electronic command to activate an actuator in such a way as to move the cylindrical sleeve into the engaged or disengaged position according to the particular operational mode indicated by the control command sequence.

19. The clutch subassembly of claim 18, wherein the analog control sequence comprises a predetermined sequence of rotational inputs to the drill string.

20. The clutch subassembly of claim 18, wherein the analog control sequence comprises a predetermined sequence of vibrational inputs to the drill string, the predetermined sequence of vibrational inputs comprising actuations of at least one pump associated with the downhole device.

21. A circulating subassembly of a drill string within a well, the circulating subassembly comprising: at least one bottom aperture at or near a distal end of the circulating subassembly; a ball valve having an engaged position wherein the ball valve is configured to inhibit a fluid from flowing through the at least one bottom aperture, the ball valve further having a disengaged position wherein the ball valve is configured to allow the fluid to flow through the at least one bottom aperture; one or more annulus apertures in a side wall of the circulating subassembly; a hollow cylindrical sleeve positioned within the circulating subassembly, the cylindrical sleeve having an engaged position wherein the cylindrical sleeve is configured to allow fluid to flow through the one or more annulus apertures, the cylindrical sleeve further having a disengaged position wherein the cylindrical sleeve is configured to inhibit fluid from flowing through the one or more annulus apertures; a ball valve actuator comprising an electronic drive configured to move the ball valve between its engaged and disengaged positions; a sleeve actuator comprising an electronic driver configured to move the cylindrical sleeve between its engaged and disengaged positions; an electronic control module configured to receive data from one or more sensors of the drill string, the data representing an analog control command sequence, the electronic control module further configured to: determine that the control command sequence represents a command to change an operational mode of the drill string to a first, second, or third operational mode, the first operational mode representing both the ball valve and the cylindrical sleeve in their respective disengaged positions, the second operational mode representing the ball valve in its disengaged position while the cylindrical sleeve is in its engaged position, the third operational mode representing both the ball valve and the cylindrical sleeve in their respective engaged positions; and transmit one or more signals to the ball valve actuator and the cylindrical sleeve actuator, the one or more signals representing electronic commands to move the ball valve and the cylindrical sleeve into their proper positions according to the particular operational mode indicated by the control command sequence.

22. The circulating subassembly of claim 21, wherein the analog control sequence comprises a predetermined sequence of rotational inputs to the drill string.

23. The circulating subassembly of claim 21, wherein the analog control sequence comprises a predetermined sequence of vibrational inputs to the drill string, the predetermined sequence of vibrational inputs comprising actuations of at least one pump associated with the downhole device.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) For a more complete understanding of this disclosure and its advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

(2) FIG. 1 illustrates a high-level component diagram of an electronic control module according to some embodiments of this disclosure.

(3) FIG. 2 represents a flowchart for a method of controlling a drill string according to some embodiments of this disclosure.

(4) FIG. 3 is a sectional view of a drill string including an anchor subsection device according to some embodiments of this disclosure.

(5) FIGS. 4A and 4B are isometric side views of an anchor subsection tool according to some embodiments of this disclosure.

(6) FIGS. 4C and 4D are end views of an anchor subsection tool according to some embodiments of this disclosure.

(7) FIGS. 5A-5C are a sectional side view, an isometric side view, and an end view, respectively, of an anchor subsection tool according to some embodiments of this disclosure.

(8) FIGS. 6A and 6B are sectional side views of a drill string including a downhole clutch tool according to some embodiments of this disclosure.

(9) FIG. 7 is a sectional side view of a downhole clutch tool according to some embodiments of this disclosure.

(10) FIGS. 8A and 8B are side sectional views of a circulating subsection tool according to some embodiments of this disclosure.

(11) FIGS. 9A-9C are side sectional views of a circulating subsection tool in various modes of operation, according to some embodiments of this disclosure.

DETAILED DESCRIPTION

(12) Embodiments of methods and systems for operating a drill string within a well are presented. FIGS. 1 through 9C, discussed below, and the various embodiments used to describe the principles of this disclosure are by way of illustration only and should not be construed in any way to limit the scope of the disclosure.

(13) FIG. 1 illustrates a high-level component diagram of an electronic control module according to some embodiments of this disclosure. According to some embodiments, electronic control module (“ECM”) 102 may be positioned within a drill string—for example located within a subassembly of the drill string. According to some embodiments, ECM 102 may include one or more processors 104, one or more memories 110, an input analysis module 106, and one or more communication interfaces 108.

(14) According to some embodiments, the one or more processors 104 may include one or more of a microprocessing unit (“MPU”), and application-specific integrated circuit, or another type of computing processor. Accordingly, in some embodiments, communication and/or memory functions of elements 108 and 110, for example, may be integrated into processor 104.

(15) According to some embodiments, one or more sensors 112 may detect events or conditions, and pass this data to ECM 102. In some embodiments, sensors 112 may include one or more of micro-electromechanical system (“MEMS”) gyroscopes, accelerometers, temperature sensors, pressure sensors, impact sensors, or other suitable vibration or motion sensors. In some embodiments, sensors 112 may send data to ECM control module 102 via communication interface 108. One of ordinary skill in the art will recognize numerous other known an valid ways of transmitting such data.

(16) In some embodiments, when ECM 102 receives sensor data from sensors 112, it attempts to interpret the input data using input analysis module, 106. According to some embodiments, one or more predefined control input sequences may be available to ECM 102, for example by having been stored in memory 110 by a manufacturer or operator of a drill string or subassembly containing ECM 102. In some embodiments, control input sequences may be modified using a user interface (not shown at FIG. 1).

(17) Input commands may be made in various ways, according to some embodiments. For example, rotational inputs of the drill string, vibration inputs of the drill string, or pressure inputs of the drill string. According to some embodiments, an example rotational input command sequence may be represented as follows:

(18) 1. The drill string is held still for longer than two minutes.

(19) 2. Rotation is turned on for between 25 and 35 seconds.

(20) 3. Rotation is stopped.

(21) 4. Rotation begins again between 25 and 35 seconds later (for operational mode 1) OR

(22) 5. Rotation begins again between 55 and 65 second later (for operational mode 2)

(23) In some embodiments, a third or more additional operational modes may be defined, for example by using different timing. The input sequences may be defined or altered according to some embodiments in response to particular circumstances of a drilling project.

(24) According to some embodiments, an example vibrational input command sequence may be represented as follows: 1. The drill string fluid pumps are turned off for greater than two minutes. 2. The pumps are turned on for between 25 and 35 seconds. 3. The pumps are turned off. 4. The pumps are turned back on between 25 and 35 seconds later (for operational mode 1) OR 5. The pumps are turned back on between 55 and 65 seconds later (for operational mode 2).
In some embodiments, a third or more additional operational modes may be defined, for example by using different timing. The input sequences may be defined or altered according to some embodiments in response to particular circumstances of a drilling project.

(25) According to some embodiments, when input analysis module 106 identifies a valid control input sequence, ECM may send an electronic signal to a linear actuator 114 to cause a physical movement using the linear actuator and/or motors 116, all contained within the drill string. According to some embodiments, a battery 118 may provide power to various components of the system including the sensors, ECM, linear actuator, and motors.

(26) FIG. 2 represents a flowchart for a method of controlling a drill string according to some embodiments of this disclosure. At step 202, data is received from one or more sensors. According to some embodiments, this data may be received at an electronic control module such as ECM 102 of FIG. 1.

(27) At step 204, according to some embodiments, the sensor data is analyzed, for example by an input analysis module similar to input analysis module 106 of FIG. 1. At step 206, according to some embodiments, a control command sequence is recognized within the control data.

(28) At step 208, according to some embodiments, a determination is made that the recognized control command sequence represents a command to change the drill string and/or a submodule of the drill string from a first operational mode to a second operational mode.

(29) At step 210, according to some embodiments, a signal may be transmitted to an actuator of the drill string, for example a linear actuator 114 as described at FIG. 1. According to some embodiments, a motor may additionally be controlled in order to effect the desired change of operational mode.

(30) FIG. 3 is a sectional view of a drill string 300 including an anchor subsection according to some embodiments of this disclosure. According to various embodiments, the anchor subsection tool may include a bottom sub 302, an arm sub 304, a return spring 306, one or more arms 308, one or more rollers 310, and an oil pressure section 312 configured to drive arms out and prevent rotary movement while allowing axial movement when the anchor subsection is in an anchored mode of operation.

(31) According to various embodiments, drill string 300 may further include a manifold 314, electronic return valve 316, oil pump 318, a first oil-filled section 320, a motor 322, a second oil-filled section 324, a compensation piston 326, a centralizer 328, a top sub 330, a vibration damper 332, an electronic driver 334, and a battery 336.

(32) According to various embodiments, the anchor subsection may be designed to be switched on and off using rotary, vibration, flow, or pressure commands, or a combination thereof. According to various embodiments, when a command is received to activate anchor mode, arms 308 are pushed out and provide pressure and friction at the well bore wall.

(33) According to various embodiments, during anchor mode, a clutch above the anchor subsection may be set to rotary mode, allowing the drill string to rotate above the anchor sub. According to some embodiments, directional drilling of the drill string may be achieved in this formation with full rotation of the drill string above the BHA while the mud motor and measurement-while-drilling (“MWD”) device maintain toolface orientation with the anchor sub. According to some embodiments, the anchor sub holds the reactive torque created by a mud motor and the motor is set to the direction the well is intended to follow.

(34) FIGS. 4A and 4B are isometric side views of an anchor subsection tool according to some embodiments of this disclosure. Arms 402 show the arms in a deployed (“anchor”) position according to some embodiments. Arms 408 show the arms in a retracted (“drill”) position according to some embodiments.

(35) FIGS. 4C and 4D are end views of an anchor subsection tool according to some embodiments of this disclosure. Configuration 404 is an end view of the anchor subsection showing the arms in a deployed (“anchor”) position according to some embodiments. Configuration 406 is an end view of the anchor subsection showing the arms in a retracted (“drill”) position according to some embodiments. In this example, there are three arm elements 120 degrees from each other.

(36) FIGS. 5A-5C are a sectional side view, an isometric side view, and an end view, respectively, of an anchor subsection tool according to some embodiments of this disclosure. Arms 502 are shown in a deployed position. Arms or extendable pads 514 are shown in a retracted position. The anchor subsection, according to some embodiments, may further comprise rollers 516.

(37) According to some embodiments, anchor subsection 500 may include an oil chamber 504, manifold 506, hydraulic pump/motor 508, oil tank 510, electronics driver 512, and battery stave 518. According to some embodiments, the anchor subassembly system may lock the BHA below a swivel by means of a mechanical anchoring system that prevents rotation due to reactive torque, while allowing for freedom of movement in the axial direction. The anchor system may be engaged and disengaged according to some embodiments through a combination of rotation, vibration, and/or axial force. According to some embodiments, surface telemetry signals may be made available to electronics within the anchor subassembly, including electromagnetic, mud pulse telemetry, and rotary speed combinations.

(38) According to some embodiments, a clutch system may be provided to allow rotation of the drill string above the anchored BHA. The clutch maintains rotation and hydraulic integrity of the drill string to the bottom of the BHA, as well as an axial connection to the top of the BHA. According to some embodiments, the clutch system can be engaged and disengaged without limit using rotational and/or axial force, or vibrations.

(39) According to some embodiments, preventing the BHA from rotation while allowing it to move axially creates the ability to hold the drill bit toolface constant in order to directionally steer the BHA, for example for drilling new wellbore or sidetracking an additional wellbore. According to some embodiments, allowing the drill string above the clutch to rotate improves general hole cleaning and increases the axial force up and down on the top of the anchored BHA, while the anchored BHA is non-rotating.

(40) FIGS. 6A and 6B are sectional side views of a downhole clutch subassembly 600 in “locked” mode according to some embodiments of this disclosure. According to some embodiments, subassembly 600 may include bearings at locations 602, 606, 608, and 614. According to some embodiments, subassembly 600 may further include compensation piston 604. At location 610 according to some embodiments, shifting balls or “keys” may be used to engage and lock the clutch for rotation.

(41) According to various embodiments, subassembly 600 may further include shifting sleeve 612 and 616 for engaging and disengaging the clutch assembly. According to some embodiments, lead screw nut 618 and lead screw 620 may be manipulated using motor 622 to engage the clutch mechanism. Location 624 shows the clutch subassembly locked in position. According to some embodiments, subassembly 600 may include an electronics and battery section 626. FIG. 6B according to some embodiments, shows example dimensions of a downhole clutch subassembly.

(42) A downhole clutch tool according to some embodiments may include two tubular members that are axially fastened to one another but are free to rotate freely with respect to each other. According to some embodiments, A sleeve shaped component with keys or a spline feature can be moved into a position that locks the two tubular members together or held in a position where they are unlocked and free to rotate. According to some embodiments, the sleeve component is moved axially by a linear drive system that is powered by an electric motor, connected to an electronics section and a battery.

(43) According to some embodiments, the two tubular members may contain a section arranged such that one tubular section is nested, or contained, within the other. According to some embodiments, this configuration allows length (typically 12-36 inches) for radial and axial bearings and for seals. The seals are present to ensure that the drilling fluid on the inside of the tubular members does not leak to the outside. Some embodiments may also include an oil filled section in a space that is radially between the two members. The oil filled section is present in order to lubricate the movement of the engagement keys or splines with respect to each other.

(44) Sleeve Component

(45) According to some embodiments, the sleeve component may comprise a hollow cylinder of approximately 5 inches overall length. The sleeve is machined with spline teeth on its outer surface for constant engagement with the inner surface of the outer tubular member. The inside of the sleeve is configured to accept keys (or in this case, ball bearings that act as keys). According to some embodiments, the device is configured such that in one axial position the keys (or balls) will engage with a mating profile on the outer surface of the inner tubular and prevent relative rotation. In another axial position the keys (or balls) will be out of alignment with that profile and there will be no torque transferred between the bodies. In that case the bodies are allowed to spin freely with respect to each other.

(46) Linear Drive System

(47) A linear drive module according to some embodiments contains a ball screw or other linear drive mechanism, an electric motor, a battery, a motor driver circuit, and a sensor and MPU circuit. The MPU/Sensor circuit monitors the vibration or rotational status of the tool and then uses that input to make a determination about when to send a signal to activate the motor. The motor driver circuit takes power from the battery and turns the motor a measured number of turns to extend the linear drive to a position congruent with the instruction from the MPU.

(48) Sensor

(49) According to some embodiments, a positional or environmental sensor may comprise accelerometers and magnetometers that are configured to detect the level of vibration and/or rotation of the tool. Vibration level is correlated with mud flow rate, so varying or cycling the mud flow rate at certain measured intervals can be used as a means of encoding information. Measuring the time between vibration events in the downhole tool can be used as a means of decoding that same information. Alternatively, information can be encoded in time intervals between rotation events of the drill string. By measuring and filtering the rotation status over time that information can be decoded.

(50) Communications with the Downhole Clutch Tool

(51) According to some embodiments, a mode of communication with the tool will be via changes to rotation. By measuring the oscillations in the magnitude of the lateral magnetometers and/or accelerometers a determination about the rotational state of the tool can be made. For instance, if there is a primary frequency to the fluctuations of all 4 sensors that is equivalent, is above a certain threshold, and is between 0.1 Hz and 3 Hz then we can say that the tool is rotating. If the drill string is rotated for an exact period of time (plus or minus a small margin), then stopped for an exact period of time, and then started again after a measured but variable amount of time, data can be encoded into the amount of time that has elapsed since the first stoppage in rotation. So as an example:

(52) 1. The Drill string is held still for greater than 2 minutes.

(53) 2. Rotation is turned on for between 25 and 35 seconds.

(54) 3. Rotation is stopped.

(55) 4. Rotation begins again between 25 and 35 seconds later (for position 1) or

(56) 5. Rotation begins again between 55 and 65 seconds later (for position 2).

(57) According to some embodiments, vibration sensing, where the overall value of the measurement of the accelerometers is used, may also be used for this type of data downlink. In that case an example of a downlink sequence might be:

(58) 1. The pumps are turned off for greater than 2 minutes.

(59) 2. The pumps are turned on for between 25 and 35 seconds.

(60) 3. Pumps are turned off.

(61) 4. Pumps begin again between 25 and 35 seconds later (for position 1) or

(62) 5. Pumps begin again between 55 and 65 seconds later (for position 2).

(63) The preceding sequences are examples only. The exact timing and tolerance bands for each time sequence may be adjusted depending on depth and other factors regarding the drilling process.

(64) According to some embodiments, the electronics can be configured such that movement to the sleeve component is carried out only when the tool senses that no vibration is present. In this way, excess stress on the splines or keys that would be caused by mating or de-mating while under torque can be avoided.

(65) FIG. 7 is a sectional side view of a downhole clutch tool in free spinning mode according to some embodiments of this disclosure. At section 710, shifting balls are disengaged, in “rotating mode,” as contrasted to the locked mode shown at section 610 of FIG. 6.

(66) FIGS. 8A and 8B are side sectional views of a circulating subsection tool according to some embodiments of this disclosure. According to some embodiments, an example circulating subsection tool includes valve seat 802 and valve ball 804 for blocking or allowing flow through a bottom aperture of the subsection. According to some embodiments, one or more apertures or openings in the side of the body are located in the area shown at 806. The apertures, when unblocked, allow the flow of fluid to the exterior of the tool into the wellbore or annulus.

(67) According to some embodiments, internal sleeve 808 is positioned within the body of the circulating subsection in part to block or unblock apertures 806. According to some embodiments, linear actuator 810 and electric motor may be used to move internal sleeve 808 into the desired position.

(68) According to some embodiments, attachment 814 is provided to affix electric motor 812 to the device body, and attachment 816 is provided for attaching other elements such as a sensor, MPU, and batteries of the example embodiment.

(69) According to some embodiments, a downhole operable circulating sub may include two principal components: the valve body module and the linear drive module. According to some embodiments, the valve body effects changes to the fluid flow and the linear drive module positions the valve body.

(70) Valve Body Module

(71) The valve body module consists of a sleeve attached on one side to the linear drive and on the other side to a poppet or ball shape. The sleeve and poppet assembly move axially inside of the tool to one of three positions, shown below at FIGS. 9A-9C.

(72) Position 1: The solid section of the sleeve and the holes on the side of the sub body are aligned so that the sleeve is sealing the holes in the sub body. The poppet is not engaged with its seat. Mud flows axially through the tool.

(73) Position 2: The solid section of the sleeve and the holes in the body are now misaligned so that mud is permitted to flow out through the side of the tool. The poppet is not engaged with its seat. Mud flows axially through the tool and some of the flow stream exits the side ports.

(74) Position 3: The solid section of the sleeve is still misaligned with the holes on the body so that mud flows out through the side of the tool. The poppet is now engaged with its seat so that axial flow is now blocked and all of the mud flow is forced out the side.

(75) Linear Drive Module

(76) According to some embodiments, the linear drive module contains a ball screw or other linear drive mechanism, an electric motor, a battery, a motor driver circuit, and a sensor and MPU circuit. The MPU/Sensor circuit monitors the vibration or rotational status of the tool and then uses that input to make a determination about when to send a signal to activate the motor. The motor driver circuit takes power from the battery and turns the motor a measured number of turns to extend the linear drive to a position congruent with the instruction from the MPU.

(77) Sensor

(78) The positional or environmental sensor according to some embodiments may include accelerometers and magnetometers that are configured to detect the level of vibration and/or rotation of the tool. Vibration level may be correlated with mud flow rate, so varying or cycling the mud flow rate at certain measured intervals can be used as a means of encoding information. Measuring the time between vibration events in the downhole tool can be used as a means of decoding that same information. Alternatively, information can be encoded in time intervals between rotation events of the drill string. By measuring and filtering the rotation status over time that information can be decoded.

(79) Communications with the Circulating Sub

(80) According to some embodiments, a mode of communication with the tool will be via changes to rotation. By measuring the oscillations in the magnitude of the lateral magnetometers and/or accelerometers a determination about the rotational state of the tool can be made. For instance, if there is a primary frequency to the fluctuations of all 4 sensors that is equivalent, is above a certain threshold, and is between 0.1 Hz and 3 Hz then we can say that the tool is rotating. If the drill string is rotated for an exact period of time (plus or minus a small margin), then stopped for an exact period of time, and then started again after a measured but variable amount of time, data can be encoded into the amount of time that has elapsed since the first stoppage in rotation. As one example:

(81) 1. The Drill string is held still for greater than 2 minutes.

(82) 2. Rotation is turned on for between 25 and 35 seconds.

(83) 3. Rotation is stopped.

(84) 4. Rotation begins again between 25 and 35 seconds later (for mode 1) or

(85) 5. Rotation begins again between 55 and 65 seconds later (for mode 2) or

(86) 6. Rotation begins again between 85 and 95 seconds later (for mode 3).

(87) According to some embodiments, vibration sensing, where the overall value of the measurement of the accelerometers is used, may also be used for this type of data downlink. In that case an example of a downlink sequence might be:

(88) 1. The pumps are turned off for greater than 2 minutes.

(89) 2. The pumps are turned on for between 25 and 35 seconds.

(90) 3. Pumps are turned off.

(91) 4. Pumps begin again between 25 and 35 seconds later (for mode 1) or

(92) 5. Pumps begin again between 55 and 65 seconds later (for mode 2) or

(93) 6. Pumps begin again between 85 and 95 seconds later (for mode 3).

(94) The preceding sequences are examples only. The exact timing and tolerance bands for each time sequence may be adjusted depending on depth and other factors regarding the drilling process.

(95) According to some embodiments, the electronics can be configured such that movement to the valve body is carried out only when the tool senses that no flow is present. In this way, excess stress on the sealing elements can be avoided.

(96) FIG. 8B is provided to show dimensions of an example embodiment of a circulating subsection tool according to some embodiments of this disclosure.

(97) FIGS. 9A-9C are side sectional views of a circulating subsection tool in various modes of operation, according to some embodiments of this disclosure. FIG. 9A according to some embodiments shows a first operational mode in which the ball is valve open and the apertures to the annulus closed.

(98) FIG. 9B according to some embodiments shows a second operational mode in which both the ball valve and the apertures are open, allowing fluid to flow through the bottom opening as well as through the apertures into the annulus.

(99) FIG. 9C according to some embodiments shows a third operational mode in which the ball valve is closed, preventing flow to the motor through the bottom opening of the tool, while the apertures are open, allowing fluid to flow out of the circulating subsection tool into the annulus.

(100) None of the descriptions in this application should be read as implying that any particular element, step, or function is an essential element that must be included in the claim scope. The scope of patented subject matter is defined only by the claims. Moreover, none of the claims is intended to invoke 35 U.S.C. 112(f) unless the exact words “means for” are followed by a participle.