SYSTEMS AND METHODS FOR DEPTH TRACKING IN A DOWNHOLE ENVIRONMENT

Description

BACKGROUND

For drilling of a borehole, directional drilling allows creation of a non-linear borehole or a linear borehole through varying earth formations. Directional drilling units conventionally communicate with the surface to transmit status information and/or receive instructions through lengthy pulse communications. Reduction of communication time can increase the uptime of a drilling system.

SUMMARY

In some aspects, the techniques described herein relate to a method of measuring depth in a borehole, the method including: drilling a portion of the borehole with a bottomhole assembly (BHA) including a downhole tool; receiving, at the downhole tool, a zero pulse; receiving, at the downhole tool, a stand pulse; determining an added stand length based at least partially on the stand pulse; and adding the added stand length to a total string length.

In some aspects, the techniques described herein relate to a method of measuring depth in a borehole, the method including: drilling a portion of the borehole with a bottomhole assembly (BHA) including a downhole tool; receiving, at the downhole tool, a zero pulse; receiving, at the downhole tool, a stage pulse; receiving, at the downhole tool, a stand pulse; determining an added stand length based at least partially on the stand pulse; and adding the added stand length to a known drill string length based at least partially on the stage pulse.

In some aspects, the techniques described herein relate to a downhole system including: a directional steering tool; a sensor; and a control unit in data communication with the directional steering tool and the sensor, the control unit including: a processor, and a hardware storage device having instructions stored thereon executable by the processor to cause the control unit to: receive, at the control unit, a zero pulse; receive, at the control unit, a stand pulse; determine an added stand length based at least partially on the stand pulse; and add the added stand length to a total string length.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

Additional features and aspects of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and aspects of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims or may be learned by the practice of such embodiments as set forth hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, non-schematic drawings should be considered as being to scale for some embodiments of the present disclosure, but not to scale for other embodiments contemplated herein. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 illustrates a drilling system and downhole environment, according to some embodiments of the present disclosure;

FIG. 2 is a side view of a downhole environment in which a bottomhole assembly (BHA) and drill string steer the bit to create a curve of a borehole, according to some embodiments of the present disclosure;

FIG. 3 is a system diagram of a BHA including a control unit, according to some embodiments of the present disclosure;

FIG. 4 is a schematic representation of an embodiment of a well plan stored on a hardware storage device of a control unit and/or BHA, according to some embodiments of the present disclosure;

FIG. 5 is an embodiment of a downlink communications from a surface of a drilling system to a BHA, according to some embodiments of the present disclosure;

FIG. 6 is a flowchart illustrating an embodiment of a method of controlling a BHA in a downhole environment, according to some embodiments of the present disclosure;

FIG. 7 is a graph of standpipe fluid pressure in a drill string during drilling of borehole; and

FIG. 8 is a flowchart illustrating a method of controlling a BHA in a downhole environment, according to some embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure generally relate to devices, systems, and methods for controlling a downhole tool in a downhole environment. More particularly, the present disclosure relates to accurate tracking of a downhole location, such as total drill string length or true vertical depth (TVD). In some embodiments, systems and methods described herein include storing a pipe tally and/or well plan on a hardware storage device of a downhole tool, such as a control unit or directional steering tool (e.g., a rotational steering system (RSS)). The downhole tool receives or detects signals in the drilling system to determine when a stand of drill pipe is added to the drill string and, in some embodiments, the length of the stand added. The downhole tool adds the added stand length to a current stand length to track a total drill string length locally in the downhole environment. Determining the total drill string length locally in the downhole environment reduces the need for downlink communications from the surface of the drilling system to the bottomhole assembly (BHA). In some embodiments, the downhole tool further calculates a TVD by comparing the total drill string length (including drill pipe and BHA lengths) to a well plan stored locally on the hardware storage device. By comparing the total drill string length to the well plan, the downhole tool can determine the current location of the BHA and/or bit in the well plan and, hence, the TVD of the BHA and/or bit in the earth formation.

In some embodiments, the signals received and/or detected by the downhole tool are pulses. For example, a pulse may be a mud pulse. In some examples, the pulse may be a rotations per minute (RPM) pulse. A mud pulse, in some embodiments, refers to a particular flow rate and/or fluid pressure of drilling fluid (i.e., mud) downhole through the drill string to the BHA. In some embodiments, the mud pulse is a single flowrate or fluid pressure of the mud in the downhole direction with a known duration. For example, a mud pulse received and/or detected by the downhole tool may be a 50 gallon per minute (gpm) flowrate that is constant for 20-seconds. In some embodiments, the mud pulse is a series of pre-determined flowrates or fluid pressures of the mud in the downhole direction with a known duration. For example, the mud pulse may include a series of four mud pressure increases of 250 pounds per square inch (psi) for 10 seconds each with 5 seconds between pressure increases.

In some embodiments, the pulse is an RPM pulse. For example, the RPM pulse may be a pulse of an RPM other than a drilling RPM for at least a pre-determined duration. In some examples, the RPM pulse is a single RPM that is different from a drilling RPM for at least 20 seconds. In a particular example, the RPM pulse is an RPM that is approximately ½ of the drilling RPM for at least 30 seconds. In some embodiments, the RPM pulse includes returning the RPM of the BHA to a drilling RPM. For example, the RPM pulse includes dropping the RPM to approximately ½ of the drilling RPM for 30 seconds and then returning to the drilling RPM.

Systems and methods for determining a depth of the downhole tool and/or BHA, in some embodiments, includes receiving or detecting a zero pulse of an RPM pulse or a mud pulse. In some embodiments, a zero pulse is a measured flowrate or fluid pressure of drilling fluid of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the flowrate of the drilling fluid is zero for at least 20 seconds. In some embodiments, a zero pulse is a measured RPM of the drill string of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the RPM of the BHA is zero for at least 30 seconds. In some instances, a zero pulse is associated with drilling system operators stopping the drilling system to add a stand of drill pipe to the drill string.

In some embodiments, systems and methods according to the present disclosure further include a stand pulse received at or detected by the downhole tool. The stand pulse is, in some embodiments, at least one of a mud pulse and a stand pulse. The stand pulse is separate from and different from the zero pulse. The stand pulse is a pulse of known magnitude (flowrate, fluid pressure, RPM, etc.) and duration. In some embodiments, the downhole tool determines the added stand length based at least partially on the stand pulse. For example, different magnitudes and/or durations of the stand pulse correspond to different lengths of the stand added to the drill string.

While the zero pulse received at and/or detected by the downhole tool informs the downhole tool that the drilling system is stopped to add drill pipe, and the stand pulse informs the downhole tool of the length of the added stand, in some embodiments, the type of pulse need not be the same between the zero pulse and the stand pulse. In some embodiments, the downhole tool receives and/or detects a zero pulse of drilling fluid flowrate and a stand pulse of RPM. In some embodiments, the downhole tool receives and/or detects a zero pulse of RPM and a stand pulse of drilling fluid pressure. By determining stoppages of the drill string with a zero pulse and receiving a stand pulse corresponding to an added stand length, the downhole tool can compare the stand pulse to a locally stored pipe tally and/or table pre-determined stand lengths to determine a total drill string length at the downhole tool without requiring complex and time-consuming downlink communications from the surface.

FIG. 1 illustrates an embodiment of a drilling system and downhole environment. FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a borehole 102. The drilling system 100 includes a drill rig 103 used to turn a drilling assembly 104 which extends downward into the borehole 102. The drilling assembly 104 may include a drill string 105 and a bottomhole assembly (BHA) 106 attached to the downhole end of the drill string 105. Where the drilling system 100 is used for drilling formation, a drill bit 110 can be included at the downhole end of the BHA 106.

The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and can transmit rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid 111 is pumped from the surface. The drilling fluid 111 discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, for lifting cuttings out of the borehole 102 as it is being drilled, and for preventing the collapse of the borehole 102. The drilling fluid 111 carries drill solids including drill fines, drill cuttings, and other swarf from the borehole 102 to the surface. The drill solids can include components from the earth formation 101, the drilling assembly 104 itself, from other man-made components (e.g., plugs, lost tools/components, etc.), or combinations thereof.

The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and/or the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, directional steering tools, section mills, hydraulic disconnects, jars, vibration dampening tools, other components, or combinations of the foregoing.

In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, safety valves, centrifuges, shaker tables, and rheometers). Additional components included in the drilling system 100 may be considered a part of the surface system (e.g., drill rig 103, drilling assembly 104, drill string 105, or a part of the BHA 106, depending on their locations and/or use in the drilling system 100).

The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the borehole 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the borehole 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface by the drilling fluid 111 or may be allowed to fall downhole. The conditions of the equipment of the drilling system 100, the formation 101, the borehole 102, the drilling fluid 111, or other part of the wellsite can change during operations.

In some embodiments, the BHA 106 includes one or more biasing units that allow an operator to steer the bit 110 relative to the earth formation 101 as the drilling assembly 104 rotates in the borehole 102. For example, FIG. 2 is a side view of an embodiment of a downhole environment in which a BHA 206 and drill string 205 steer the bit 210 to create a curve of a borehole 202.

In some embodiments, a portion of the BHA 206 and/or drill string 205 contacts a radially inward surface 212 of the borehole 202 as the BHA 206 and drill string 205 follow the curve. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience damage from the formation 201. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience drag, in the longitudinal direction and/or the rotational direction, placing additional strain on the drilling system and components thereof. Precise control of steering the BHA 206 and the bit 210 with a directional steering tool 214 allows the drilling system to limit and/or prevent damage to the BHA 206 and drill string 205 in non-linear boreholes 202.

In some embodiments, a directional steering tool 214 is a discrete steering tool that is coupled to a drill bit 210. In some embodiments, the directional steering tool 214 is the drill bit with an integrated biasing element or steering element. For example, a directional steering tool 214 includes at least one actuatable biasing element 216 configured to actuate radially outward from a rotational axis of the BHA 206 and drill string 205. As the BHA 206 and drill string 205 rotate, the actuatable biasing element 216 is actuated between a closed position and an open position to selectively apply a lateral force to the borehole wall. The drill bit 210 is urged in an opposing lateral direction to steer the drill bit 210 and the direction of the borehole 202.

In some embodiments, an MWD unit allows for measurements of a plurality of operating conditions, environmental conditions, fluid measurements, or other status information regarding the performance and/or condition of the downhole tool and the downhole environment in which the downhole tool is operating. In some embodiments, the MWD unit measures and/or records directional information of the downhole tool. In some examples, the MWD unit includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some embodiments, the MWD unit records the directional measurements. In some embodiments, the MWD unit transmits the measurements to a system and/or operator at the surface.

In some embodiments, the MWD unit measures and/or records drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed (e.g., RPM) of the drill string and/or drill bit; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit records the drilling mechanics information or reports the drilling mechanics information to a control unit in the BHA 206. In some embodiments, the MWD unit transmits the drilling mechanics information to a system and/or operator at the surface.

In some embodiments, the BHA includes a control unit configured to receive one or more of directional information, operating conditions, environmental conditions, fluid measurements, drilling mechanics information, or other status information, as illustrated in the embodiment of FIG. 3. In some embodiments, the control unit 320 is in data communication with at least one sensor (e.g., an MWD 318 including one or more sensors) and a directional steering tool 314. In some embodiments, the control unit 320 is integrated with the MWD 318 and/or the direction steering tool 314. The control unit 320 includes a processor 322 and a hardware storage device 324 in data communication with the processor 322. The hardware storage device 324 has instructions stored thereon that, when executed by the processor 322, cause the BHA 306 to perform at least a portion of any method described herein.

In some embodiments, the hardware storage device 324 has a pipe tally and/or well plan 326 stored thereon. In some embodiments, the pipe tally and/or well plan 326 is loaded to the hardware storage device 324 at the surface of the drilling system prior to running the BHA 306 (including the control unit 320) downhole. In some embodiments, the well plan 326 includes a plurality of stages of the well plan 326. In some embodiments, the pipe tally 326 includes a plurality of pipe lengths, stand lengths, and stand identifications that the control unit 320 can access in the downhole environment. The control unit 320 obtains at least one of the directional information, operating conditions, environmental conditions, fluid measurements, drilling mechanics information, or other status information from one or more sensors of the BHA 306. In at least one example, the sensors are in or part of the MWD 318.

A formation measurement is, in some examples, a measurement of at least one property of the formation through which the BHA 306 is drilling or otherwise located. For example, a formation measurement includes a formation fluid composition, a formation solids composition (e.g., geochemistry), a formation hardness, a formation porosity, a formation fluid flowrate, a formation homogeneity, etc. In some embodiments, the formation measurement is made by one or more sensors of the BHA 306. In some embodiments, the formation measurement is made by sensors in the drill bit 310. In some embodiments, the formation measurement is made by sensors in the MWD 318. In some embodiments, the formation measurement is made by sensors in the directional steering tool 314.

An environmental measurement is, in some examples, a measurement of at least one property of the downhole environment that may or may not be related to the formation through which the BHA 306 drills or is located. For example, an environmental measurement may include temperature, pressure, or other measurements that are not formation measurements but inform the drilling system of downhole conditions. In some embodiments, the environmental measurement is made by one or more sensors of the BHA 306. In some embodiments, the environmental measurement is made by sensors in the drill bit 310. In some embodiments, the environmental measurement is made by sensors in the MWD 318. In some embodiments, the environmental measurement is made by sensors in the directional steering tool 314.

In some embodiments, a pipe tally 326 includes a sequence of known segments or stands of drill pipe that are planned for connection to the drill string. At each connection (determined by the control unit 320 via receipt of a zero pulse and a stand pulse), the control unit 320 adds the next stand of drill pipe to the current drill string length to determine a total drill string length. In some embodiments, a pipe tally and/or well plan 326 includes approximate stand length values based on a quantity of drill pipes in a stand. At each connection, the control unit receives and/or detects a stand pulse that corresponds to a stand length value. While an exact length of the individual stand may vary from the approximate stand length stored on the hardware storage device 324, the control unit 320 can maintain an approximate total drill string length to determine the BHA's position in the well plan 326.

In some embodiments, the control unit 320 uses the well plan 326 to determine the location of the BHA 306, such as a TVD of the BHA 306, based on the geometry of the borehole being created according to the well plan 326.

FIG. 4 is a schematic representation of an embodiment of a well plan stored on a hardware storage device of a control unit and/or BHA described herein. In some embodiments, the well plan includes a plurality of stages with transitions therebetween. For example, the well plan may include a curved stage 428 and/or a linear stage 430. In some embodiments, the well plan includes a plurality of curved stages 428 and linear stages 430. In some embodiments, the well plan includes at least one vertical stage. In some embodiments, the well plan includes a landing stage 434. The directional steering tool and other components of the drill string directs the BHA and drill bit through the formation according to the inclination, azimuth, dogleg severity, rate of penetration, axial length along the stage, and other parameters of the well plan. Determining the location of the BHA in the well plan and/or a stage of the well plan can improve the accuracy of the drilling system.

A curved stage 428 is any stage of the well plan in which at least one of the inclination and the azimuth of the borehole 402 changes along a length of the stage. While the schematic illustration of FIG. 4 depicts an embodiment of a curved stage 428 with a change in inclination along a length of the curved stage 428, it should be understood that in some embodiments of a curved stage the inclination is substantially constant and the azimuth of the borehole 402 changes. In some embodiments, both the inclination and the azimuth of the borehole 402 changes in the curved stage 428.

A linear stage 430 is any stage of the well plan in which the inclination and azimuth of the borehole 402 remains constant along the length of the stage. In some embodiments, a linear stage 430 is a vertical stage of the well plan in which the inclination is substantially vertical relative to a direction of gravity. For example, a vertical stage may be an initial stage from the surface. In such an example, the trigger to change from the vertical stage to a second stage (e.g., curved stage 428) may be the TVD relative to the surface. In some embodiments, a linear stage 430 of the well plan is a directional stage 434 in which the inclination and azimuth are substantially constant, while the inclination is non-vertical, creating a lateral net movement of the borehole 402 along the length of the directional stage 434 relative to the direction of gravity.

In some embodiments, the well plan includes a landing stage 436. In some embodiments, the landing stage 436 is a curved stage in which the borehole 402 attains a substantially horizontal orientation relative to the direction of gravity. In some embodiments, the landing stage 436 is a final stage of the well plan. For example, a trigger for changing to the landing stage 436 may include a formation composition, as the borehole 402 turns and runs horizontally to remain within the formation when the desired formation composition is detected.

FIG. 5 is an embodiment of a downlink communications from a surface of a drilling system 500 to a BHA 506. In some embodiments, the drilling system 500 can communicate downhole with the control unit 520 and/or BHA 506 by mud pulses 538. For example, a drilling fluid 511 or mud flows downward through the drill string 505 to the control unit 520 and/or BHA 506 as described herein. By varying a flow rate and/or a fluid pressure of the drilling fluid 511, the drilling rig 503 at the surface of the drilling system 500 can transmit instructions to the control unit 520 and/or BHA 506. In a conventional system, the downlink communication includes a plurality of mud pulses 538 in the downhole direction, where each mud pulse 538 is of varying duration to communicate or select settings in the BHA 506. In some examples, the borehole 501 and/or drill string 505 can be long, introducing fluidic drag into the mud pulses 538, requiring each mud pulse to be a minute or longer. A sequence of mud pulses 538, therefore, can take several minutes or longer to communicate a relatively simple change to BHA settings.

In some embodiments, the drilling system 500 can communicate downhole with the control unit 520 and/or BHA 506 by RPM pulses 540. For example, the drilling rig applies a torque to change the revolutions per minute (RPM) of the drill string 505 to communicate with the control unit 520 and/or BHA 506. By varying an RPM of the drill string 505 through a series of changes or at a particular RPM, the drilling rig 503 at the surface of the drilling system 500 can transmit instructions to the control unit 520 and/or BHA 506. In a conventional system, the downlink communication includes a plurality of RPM pulses 540, where each RPM pulses 540 is of varying duration and/or RPM to communicate or select settings in the BHA 506. In some examples, the borehole 501 and/or drill string 505 can be long, introducing significant torsional elasticity, fluidic drag, friction with a borehole wall and other variables into the communication of the transmission of the RPM pulse 540 in the downhole direction. The delay and/or noise (e.g., torsional oscillations) in the transmission of the RPM pulses 540 can require each RPM pulse 540 to be a minute or longer to effectively communicate the signal to the control unit 520 and/or BHA 506. A sequence of RPM pulses 540, therefore, can take several minutes or longer to communicate a relatively simple change to BHA settings.

FIG. 6 is a flowchart illustrating an embodiment of a method 642 of controlling a BHA in a downhole environment. In some embodiments, the method 642 includes drilling a portion of the borehole with a bottomhole assembly (BHA) including a downhole tool at 644. In some embodiments, after drilling the portion of the borehole, the method 642 includes receiving, at the downhole tool, a zero pulse at 646. As described herein, the zero pulse may be associated with the drilling operators stopping the drilling process to add a stand of drill pipe to the drill string before advancing the drill string further downhole. In some embodiments, the zero pulse is received by the control unit measuring or detecting the zero pulse of the flow rate, fluid pressure, or RPM. In some embodiments, the zero pulse is received by a sensor or another component of the BHA, such as an MWD, transmitting the flow rate, fluid pressure, or RPM to the control unit. In some embodiments, the zero pulse is received at the control unit by a sensor or another component of the BHA, such as an MWD, identifying the zero pulse and transmitting a single indicating the detection of the zero pulse to the control unit.

In some embodiments, a zero pulse is a measured flowrate or fluid pressure of drilling fluid of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the flowrate of the drilling fluid is zero for at least 20 seconds. In some embodiments, a zero pulse is a measured RPM of the drill string of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the RPM of the BHA is zero for at least 30 seconds. In some instances, a zero pulse is associated with drilling system operators stopping the drilling system to add a stand of drill pipe to the drill string.

In some examples, however, the flow of drilling fluid and/or the RPM of a portion of the drilling system may be or approach zero for reasons other than adding a stand of drill pipe. To confirm the addition of a stand of drill pipe, the method 642 further includes receiving, at the downhole tool, a stand pulse at 648.

The stand pulse is, in some embodiments, at least one of a mud pulse and a stand pulse. The stand pulse is separate from and different from the zero pulse. The stand pulse is a pulse of known magnitude (flowrate, fluid pressure, RPM, etc.) and duration. In some embodiments, the downhole tool determines the added stand length based at least partially on the stand pulse. For example, different magnitudes and/or durations of the stand pulse correspond to different lengths of the stand added to the drill string.

While the zero pulse received at and/or detected by the downhole tool informs the downhole tool that the drilling system is stopped to add drill pipe, and the stand pulse informs the downhole tool of the length of the added stand, in some embodiments, the type of pulse need not be the same between the zero pulse and the stand pulse. In some embodiments, the downhole tool receives and/or detects a zero pulse of drilling fluid flowrate and a stand pulse of RPM. In some embodiments, the downhole tool receives and/or detects a zero pulse of RPM and a stand pulse of drilling fluid pressure. By determining stoppages of the drill string with a zero pulse and receiving a stand pulse corresponding to an added stand length, the downhole tool can compare the stand pulse to a locally stored pipe tally and/or table pre-determined stand lengths to determine a total drill string length at the downhole tool without requiring complex and time-consuming downlink communications from the surface.

In some embodiments, the method 642 includes determining an added stand length based at least partially on the stand pulse at 650 and adding the added stand length to a total string length at 652. In some embodiments, determining an added stand length includes comparing the stand pulse to a lookup table (LUT) of known stand lengths and/or pipe lengths, such as a pipe tally. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of approximate stand lengths and/or pipe lengths.

In some embodiments, the LUT is pre-loaded onto the hardware storage device of the control unit before tripping the control unit downhole. A pre-loaded LUT allows the control unit to select from the information in the LUT in the downhole environment without complex downlink communications. In some embodiments, the LUT is a pipe tally including a sequence of known pipe lengths and/or stand lengths planned to be added to the drill string as the drilling system creates the borehole. In such examples, determining an added stand length includes incrementing through the known pipe lengths and/or stand lengths of the pipe tally.

For example, a pipe tally may include a sequence of known pipe lengths and a duration or magnitude of the stand pulse indicates the quantity of pipe segments added to the drill string. In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the pipe tally and add the next known pipe length to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including the next three segments of pipe added to the drill string. The control unit may access the pipe tally and add the next three known pipe lengths to the current drill string length to determine a total drill string length. In some embodiments, the pipe tally further includes joint lengths between pipe segments that allow the control unit to determine the added stand length from the plurality of pipe lengths of the pipe tally.

In another example, the LUT includes approximate stand lengths based on standardized stand lengths of drill pipe used in the drilling system. While some variation in the exact length of each segment of drill pipe segment is possible, a LUT with approximate stand lengths allows the BHA to track the total drill string length without a precise pipe tally and/or without a pre-determined sequence of pipe segments to be added to the drill string. For example, a pipe segment may be approximately 10 meters in length, and the stand pulse may indicate to the control unit the quantity of pipe segments in an added stand length.

In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the LUT and add 10 meters to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including three segments of pipe added to the drill string. The control unit may access the LUT and add 30 meters to the current drill string length to determine a total drill string length.

The control unit may provide to the directional steering unit of the BHA the total drill string length (and hence position downhole) to inform the directional steering unit of the BHA's location in the well plan. In some embodiments, the method 642 optionally includes determining a TVD of the BHA based at least partially on the well plan and the total string length at 654. In some embodiments, the control unit compares the total drill string length to the well plan (such as described in relation to FIG. 4) to determine a TVD of the control unit and/or BHA relative to the surface, based at least partially on the location of the control unit and/or BHA in the well plan.

FIG. 7 is a graph 756 of standpipe fluid pressure 758 in a drill string during drilling of borehole. The fluid pressure 758 varies during the drilling portions 760 of the drilling. The fluid pressure 758 reaches zero during connections 762 when a stand of drill pipe is added to the drill string. In at least one instance, the fluid pressure 758 reaches zero during a non-connection duration 764 when other operations were occurring. This may be an example of a system or method according to the present disclosure that detects a zero pulse during the non-connection duration 764, but a stand pulse may not follow the zero pulse, allowing the system to ignore the zero pulse. The connections 762, in some embodiments, are associated with a duration of zero RPM and a control unit detects the associated zero pulse as part of some embodiments of a method described herein.

FIG. 8 is a flowchart illustrating a method 842 of controlling a BHA in a downhole environment. In some embodiments, the method 842 includes drilling a portion of a borehole with a BHA including a downhole tool at 844, such as described in relation to FIG. 6. In some embodiments, the method 842 includes receiving, at the downhole tool, a zero pulse at 846. In some examples, the zero pulse is associated with an addition of a stand of drill pipe to the drill string.

In some embodiments, the addition of stands to the drill string moves the BHA through the stages of the well plan, as described in relation to FIG. 4. Upon the drilling system reaching the end of a stage and/or the start of stage, the transition between the stage may occur at a known drill string length. In some embodiments, the method 842 uses the known drill string length at a stage transition to reset the total drill string length and reduce cumulative errors in the determinations of the control unit. For example, variations in joint lengths or other portions of the drill string relative to a well plan or a pipe tally can cause variations between the calculated total drill string length and the actual drill string length.

In some embodiments, the stage transition has a known total drill string length at the stage transition. The control unit has the well plan and/or stages of the well plan stored locally on a hardware storage device in the downhole environment. In some embodiments, the method 842 includes receiving, at the downhole tool, a stage pulse at 866. The stage pulse may be a mud pulse and/or an RPM pulse of known duration and/or magnitude. The control unit receives the stage pulse and resets the total drill string length to the known drill string length at the stage transition of the well plan. In some embodiments, the control unit compares the magnitude, type, duration, or combinations thereof of the stage pulse to a LUT or to the well plan, itself. For example, a stage pulse may inform the control unit that the drilling system has completed the third stage of the well plan, and the known drill string length is 1000 meters. In another example, a stage pulse may inform the control unit that the drilling system has completed the fifth stage of the well plan, and the known drill string length is 1500 meters. The control unit then resets the total drill string length to the known value according to the LUT and/or well plan.

The method 842 further includes receiving, at the downhole tool, a stand pulse at 848, such as described in relation to FIG. 6, and determining an added stand length at 868. In some embodiments, the control unit adds the added stand length to the known drill string length according to the associated stage pulse. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of known stand lengths and/or pipe lengths, such as a pipe tally. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of approximate stand lengths and/or pipe lengths. In some embodiments, the stand length LUT changes with different stages (related to changes in pipe and/or connections for different stages), and the control unit compares the stand pulse to a stand length LUT associated with the current stage, at least partially according to the stage pulse.

In some embodiments, the LUT is pre-loaded onto the hardware storage device of the control unit before tripping the control unit downhole. A pre-loaded LUT allows the control unit to select from the information in the LUT in the downhole environment without complex downlink communications. In some embodiments, the LUT is a pipe tally including a sequence of known pipe lengths and/or stand lengths planned to be added to the drill string as the drilling system creates the borehole. In such examples, determining an added stand length includes incrementing through the known pipe lengths and/or stand lengths of the pipe tally.

For example, a pipe tally may include a sequence of known pipe lengths and a duration or magnitude of the stand pulse indicates the quantity of pipe segments added to the drill string. In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the pipe tally and add the next known pipe length to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including the next three segments of pipe added to the drill string. The control unit may access the pipe tally and add the next three known pipe lengths to the current drill string length to determine a total drill string length. In some embodiments, the pipe tally further includes joint lengths between pipe segments that allow the control unit to determine the added stand length from the plurality of pipe lengths of the pipe tally.

In another example, the LUT includes approximate stand lengths based on standardized stand lengths of drill pipe used in the drilling system. While some variation in the exact length of each segment of drill pipe segment is possible, a LUT with approximate stand lengths allows the BHA to track the total drill string length without a precise pipe tally and/or without a pre-determined sequence of pipe segments to be added to the drill string. For example, a pipe segment may be approximately 10 meters in length, and the stand pulse may indicate to the control unit the quantity of pipe segments in an added stand length.

In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the LUT and add 10 meters to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including three segments of pipe added to the drill string. The control unit may access the LUT and add 30 meters to the current drill string length to determine a total drill string length.

The control unit may provide to the directional steering unit of the BHA the total drill string length (and hence position downhole) to inform the directional steering unit of the BHA's location in the well plan. In some embodiments, the method 842 optionally includes determining a TVD of the BHA based at least partially on the well plan and the total string length as described in relation to FIG. 6. In some embodiments, the control unit compares the total drill string length to the well plan to determine a TVD of the control unit and/or BHA relative to the surface, based at least partially on the location of the control unit and/or BHA in the well plan.

Embodiments of the present disclosure generally relate to devices, systems, and methods for controlling a downhole tool in a downhole environment. More particularly, the present disclosure relates to accurate tracking of a downhole location, such as total drill string length or true vertical depth (TVD). In some embodiments, systems and methods described herein include storing a pipe tally and/or well plan on a hardware storage device of a downhole tool, such as a control unit or directional steering tool (e.g., a rotational steering system (RSS)). The downhole tool receives or detects signals in the drilling system to determine when a stand of drill pipe is added to the drill string and, in some embodiments, the length of the stand added. The downhole tool adds the added stand length to a current stand length to track a total drill string length locally in the downhole environment. Determining the total drill string length locally in the downhole environment reduces the need for downlink communications from the surface of the drilling system to the bottomhole assembly (BHA). In some embodiments, the downhole tool further calculates a TVD by comparing the total drill string length (including drill pipe and BHA lengths) to a well plan stored locally on the hardware storage device. By comparing the total drill string length to the well plan, the downhole tool can determine the current location of the BHA and/or bit in the well plan and, hence, the TVD of the BHA and/or bit in the earth formation.

In some embodiments, the signals received and/or detected by the downhole tool are pulses. For example, a pulse may be a mud pulse. In some examples, the pulse may be a rotations per minute (RPM) pulse. A mud pulse, in some embodiments, refers to a particular flow rate and/or fluid pressure of drilling fluid (i.e., mud) downhole through the drill string to the BHA. In some embodiments, the mud pulse is a single flowrate or fluid pressure of the mud in the downhole direction with a known duration. For example, a mud pulse received and/or detected by the downhole tool may be a 50 gallon per minute (gpm) flowrate that is constant for 20-seconds. In some embodiments, the mud pulse is a series of pre-determined flowrates or fluid pressures of the mud in the downhole direction with a known duration. For example, the mud pulse may include a series of four mud pressure increases of 250 pounds per square inch (psi) for 10 seconds each with 5 seconds between pressure increases.

In some embodiments, the pulse is an RPM pulse. For example, the RPM pulse may be a pulse of an RPM other than a drilling RPM for at least a pre-determined duration. In some examples, the RPM pulse is a single RPM that is different from a drilling RPM for at least 20 seconds. In a particular example, the RPM pulse is an RPM that is approximately ½ of the drilling RPM for at least 30 seconds. In some embodiments, the RPM pulse includes returning the RPM of the BHA to a drilling RPM. For example, the RPM pulse includes dropping the RPM to approximately ½ of the drilling RPM for 30 seconds and then returning to the drilling RPM.

Systems and methods for determining a depth of the downhole tool and/or BHA, in some embodiments, includes receiving or detecting a zero pulse of an RPM pulse or a mud pulse. In some embodiments, a zero pulse is a measured flowrate or fluid pressure of drilling fluid of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the flowrate of the drilling fluid is zero for at least 20 seconds. In some embodiments, a zero pulse is a measured RPM of the drill string of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the RPM of the BHA is zero for at least 30 seconds. In some instances, a zero pulse is associated with drilling system operators stopping the drilling system to add a stand of drill pipe to the drill string.

In some embodiments, systems and methods according to the present disclosure further include a stand pulse received at or detected by the downhole tool. The stand pulse is, in some embodiments, at least one of a mud pulse and a stand pulse. The stand pulse is separate from and different from the zero pulse. The stand pulse is a pulse of known magnitude (flowrate, fluid pressure, RPM, etc.) and duration. In some embodiments, the downhole tool determines the added stand length based at least partially on the stand pulse. For example, different magnitudes and/or durations of the stand pulse correspond to different lengths of the stand added to the drill string.

While the zero pulse received at and/or detected by the downhole tool informs the downhole tool that the drilling system is stopped to add drill pipe, and the stand pulse informs the downhole tool of the length of the added stand, in some embodiments, the type of pulse need not be the same between the zero pulse and the stand pulse. In some embodiments, the downhole tool receives and/or detects a zero pulse of drilling fluid flowrate and a stand pulse of RPM. In some embodiments, the downhole tool receives and/or detects a zero pulse of RPM and a stand pulse of drilling fluid pressure. By determining stoppages of the drill string with a zero pulse and receiving a stand pulse corresponding to an added stand length, the downhole tool can compare the stand pulse to a locally stored pipe tally and/or table pre-determined stand lengths to determine a total drill string length at the downhole tool without requiring complex and time-consuming downlink communications from the surface.

In some embodiments, the BHA includes a control unit configured to receive one or more of directional information, operating conditions, environmental conditions, fluid measurements, drilling mechanics information, or other status information. In some embodiments, the control unit is in data communication with at least one sensor (e.g., an MWD including one or more sensors) and a directional steering tool. In some embodiments, the control unit is integrated with the MWD and/or the direction steering tool. The control unit includes a processor and a hardware storage device in data communication with the processor. The hardware storage device has instructions stored thereon that, when executed by the processor, cause the BHA to perform at least a portion of any method described herein.

In some embodiments, the hardware storage device has a pipe tally and/or well plan stored thereon. In some embodiments, the pipe tally and/or well plan is loaded to the hardware storage device at the surface of the drilling system prior to running the BHA (including the control unit) downhole. In some embodiments, the well plan includes a plurality of stages of the well plan. In some embodiments, the pipe tally includes a plurality of pipe lengths, stand lengths, and stand identifications that the control unit can access in the downhole environment. The control unit obtains at least one of the directional information, operating conditions, environmental conditions, fluid measurements, drilling mechanics information, or other status information from one or more sensors of the BHA. In at least one example, the sensors are in or part of the MWD.

A formation measurement is, in some examples, a measurement of at least one property of the formation through which the BHA is drilling or otherwise located. For example, a formation measurement includes a formation fluid composition, a formation solids composition (e.g., geochemistry), a formation hardness, a formation porosity, a formation fluid flowrate, a formation homogeneity, etc. In some embodiments, the formation measurement is made by one or more sensors of the BHA. In some embodiments, the formation measurement is made by sensors in the drill bit. In some embodiments, the formation measurement is made by sensors in the MWD. In some embodiments, the formation measurement is made by sensors in the directional steering tool.

An environmental measurement is, in some examples, a measurement of at least one property of the downhole environment that may or may not be related to the formation through which the BHA drills or is located. For example, an environmental measurement may include temperature, pressure, or other measurements that are not formation measurements but inform the drilling system of downhole conditions. In some embodiments, the environmental measurement is made by one or more sensors of the BHA. In some embodiments, the environmental measurement is made by sensors in the drill bit. In some embodiments, the environmental measurement is made by sensors in the MWD. In some embodiments, the environmental measurement is made by sensors in the directional steering tool.

In some embodiments, a pipe tally includes a sequence of known segments or stands of drill pipe that are planned for connection to the drill string. At each connection (determined by the control unit via receipt of a zero pulse and a stand pulse), the control unit adds the next stand of drill pipe to the current drill string length to determine a total drill string length. In some embodiments, a pipe tally and/or well plan includes approximate stand length values based on a quantity of drill pipes in a stand. At each connection, the control unit receives and/or detects a stand pulse that corresponds to a stand length value. While an exact length of the individual stand may vary from the approximate stand length stored on the hardware storage device, the control unit can maintain an approximate total drill string length to determine the BHA's position in the well plan.

In some embodiments, the control unit uses the well plan to determine the location of the BHA, such as a TVD of the BHA, based on the geometry of the borehole being created according to the well plan. In some embodiments, the well plan includes a plurality of stages with transitions therebetween. For example, the well plan may include a curved stage and/or a linear stage. In some embodiments, the well plan includes a plurality of curved stages and linear stages. In some embodiments, the well plan includes at least one vertical stage. In some embodiments, the well plan includes a landing stage. The directional steering tool and other components of the drill string directs the BHA and drill bit through the formation according to the inclination, azimuth, dogleg severity, rate of penetration, axial length along the stage, and other parameters of the well plan. Determining the location of the BHA in the well plan and/or a stage of the well plan can improve the accuracy of the drilling system.

A curved stage is any stage of the well plan in which at least one of the inclination and the azimuth of the borehole changes along a length of the stage. While in some embodiments, a curved stage has a change in inclination along a length of the curved stage, it should be understood that in some embodiments of a curved stage the inclination is substantially constant and the azimuth of the borehole changes. In some embodiments, both the inclination and the azimuth of the borehole changes in the curved stage.

A linear stage is any stage of the well plan in which the inclination and azimuth of the borehole remains constant along the length of the stage. In some embodiments, a linear stage is a vertical stage of the well plan in which the inclination is substantially vertical relative to a direction of gravity. For example, a vertical stage may be an initial stage from the surface. In such an example, the trigger to change from the vertical stage to a second stage (e.g., curved stage) may be the TVD relative to the surface. In some embodiments, a linear stage of the well plan is a directional stage in which the inclination and azimuth are substantially constant, while the inclination is non-vertical, creating a lateral net movement of the borehole along the length of the directional stage relative to the direction of gravity.

In some embodiments, the well plan includes a landing stage. In some embodiments, the landing stage is a curved stage in which the borehole attains a substantially horizontal orientation relative to the direction of gravity. In some embodiments, the landing stage is a final stage of the well plan. For example, a trigger for changing to the landing stage may include a formation composition, as the borehole turns and runs horizontally to remain within the formation when the desired formation composition is detected.

In some embodiments, the drilling system can communicate downhole with the control unit and/or BHA by mud pulses. For example, a drilling fluid or mud flows downward through the drill string to the control unit and/or BHA as described herein. By varying a flow rate and/or a fluid pressure of the drilling fluid, the drilling rig at the surface of the drilling system can transmit instructions to the control unit and/or BHA. In a conventional system, the downlink communication includes a plurality of mud pulses in the downhole direction, where each mud pulse is of varying duration to communicate or select settings in the BHA. In some examples, the borehole and/or drill string can be long, introducing fluidic drag into the mud pulses, requiring each mud pulse to be a minute or longer. A sequence of mud pulses, therefore, can take several minutes or longer to communicate a relatively simple change to BHA settings.

In some embodiments, the drilling system can communicate downhole with the control unit and/or BHA by RPM pulses. For example, the drilling rig applies a torque to change the revolutions per minute (RPM) of the drill string to communicate with the control unit and/or BHA. By varying an RPM of the drill string through a series of changes or at a particular RPM, the drilling rig at the surface of the drilling system can transmit instructions to the control unit and/or BHA. In a conventional system, the downlink communication includes a plurality of RPM pulses, where each RPM pulses is of varying duration and/or RPM to communicate or select settings in the BHA. In some examples, the borehole and/or drill string can be long, introducing significant torsional elasticity, fluidic drag, friction with a borehole wall and other variables into the communication of the transmission of the RPM pulse in the downhole direction. The delay and/or noise (e.g., torsional oscillations) in the transmission of the RPM pulses can require each RPM pulse to be a minute or longer to effectively communicate the signal to the control unit and/or BHA. A sequence of RPM pulses, therefore, can take several minutes or longer to communicate a relatively simple change to BHA settings.

In some embodiments, a method of controlling a BHA in a downhole environment includes drilling a portion of the borehole with a bottomhole assembly (BHA) including a downhole tool. In some embodiments, after drilling the portion of the borehole, the method includes receiving, at the downhole tool, a zero pulse. As described herein, the zero pulse may be associated with the drilling operators stopping the drilling process to add a stand of drill pipe to the drill string before advancing the drill string further downhole. In some embodiments, the zero pulse is received by the control unit measuring or detecting the zero pulse of the flow rate, fluid pressure, or RPM. In some embodiments, the zero pulse is received by a sensor or another component of the BHA, such as an MWD, transmitting the flow rate, fluid pressure, or RPM to the control unit. In some embodiments, the zero pulse is received at the control unit by a sensor or another component of the BHA, such as an MWD, identifying the zero pulse and transmitting a single indicating the detection of the zero pulse to the control unit.

In some embodiments, a zero pulse is a measured flowrate or fluid pressure of drilling fluid of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the flowrate of the drilling fluid is zero for at least 20 seconds. In some embodiments, a zero pulse is a measured RPM of the drill string of zero for at least a pre-determined duration. For example, a zero pulse is received and/or measured when the RPM of the BHA is zero for at least 30 seconds. In some instances, a zero pulse is associated with drilling system operators stopping the drilling system to add a stand of drill pipe to the drill string.

In some examples, however, the flow of drilling fluid and/or the RPM of a portion of the drilling system may be or approach zero for reasons other than adding a stand of drill pipe. To confirm the addition of a stand of drill pipe, the method further includes receiving, at the downhole tool, a stand pulse.

The stand pulse is, in some embodiments, at least one of a mud pulse and a stand pulse. The stand pulse is separate from and different from the zero pulse. The stand pulse is a pulse of known magnitude (flowrate, fluid pressure, RPM, etc.) and duration. In some embodiments, the downhole tool determines the added stand length based at least partially on the stand pulse. For example, different magnitudes and/or durations of the stand pulse correspond to different lengths of the stand added to the drill string.

While the zero pulse received at and/or detected by the downhole tool informs the downhole tool that the drilling system is stopped to add drill pipe, and the stand pulse informs the downhole tool of the length of the added stand, in some embodiments, the type of pulse need not be the same between the zero pulse and the stand pulse. In some embodiments, the downhole tool receives and/or detects a zero pulse of drilling fluid flowrate and a stand pulse of RPM. In some embodiments, the downhole tool receives and/or detects a zero pulse of RPM and a stand pulse of drilling fluid pressure. By determining stoppages of the drill string with a zero pulse and receiving a stand pulse corresponding to an added stand length, the downhole tool can compare the stand pulse to a locally stored pipe tally and/or table pre-determined stand lengths to determine a total drill string length at the downhole tool without requiring complex and time-consuming downlink communications from the surface.

In some embodiments, the method includes determining an added stand length based at least partially on the stand pulse and adding the added stand length to a total string length. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of known stand lengths and/or pipe lengths, such as a pipe tally. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of approximate stand lengths and/or pipe lengths.

In some embodiments, the LUT is pre-loaded onto the hardware storage device of the control unit before tripping the control unit downhole. A pre-loaded LUT allows the control unit to select from the information in the LUT in the downhole environment without complex downlink communications. In some embodiments, the LUT is a pipe tally including a sequence of known pipe lengths and/or stand lengths planned to be added to the drill string as the drilling system creates the borehole. In such examples, determining an added stand length includes incrementing through the known pipe lengths and/or stand lengths of the pipe tally.

For example, a pipe tally may include a sequence of known pipe lengths and a duration or magnitude of the stand pulse indicates the quantity of pipe segments added to the drill string. In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the pipe tally and add the next known pipe length to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including the next three segments of pipe added to the drill string. The control unit may access the pipe tally and add the next three known pipe lengths to the current drill string length to determine a total drill string length. In some embodiments, the pipe tally further includes joint lengths between pipe segments that allow the control unit to determine the added stand length from the plurality of pipe lengths of the pipe tally.

In another example, the LUT includes approximate stand lengths based on standardized stand lengths of drill pipe used in the drilling system. While some variation in the exact length of each segment of drill pipe segment is possible, a LUT with approximate stand lengths allows the BHA to track the total drill string length without a precise pipe tally and/or without a pre-determined sequence of pipe segments to be added to the drill string. For example, a pipe segment may be approximately 10 meters in length, and the stand pulse may indicate to the control unit the quantity of pipe segments in an added stand length.

In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the LUT and add 10 meters to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including three segments of pipe added to the drill string. The control unit may access the LUT and add 30 meters to the current drill string length to determine a total drill string length.

The control unit may provide to the directional steering unit of the BHA the total drill string length (and hence position downhole) to inform the directional steering unit of the BHA's location in the well plan. In some embodiments, the method optionally includes determining a TVD of the BHA based at least partially on the well plan and the total string length. In some embodiments, the control unit compares the total drill string length to the well plan to determine a TVD of the control unit and/or BHA relative to the surface, based at least partially on the location of the control unit and/or BHA in the well plan.

In some embodiments, a method of controlling a BHA in a downhole environment includes drilling a portion of a borehole with a BHA including a downhole tool, such as described herein. In some embodiments, the method includes receiving, at the downhole tool, a zero pulse. In some examples, the zero pulse is associated with an addition of a stand of drill pipe to the drill string.

In some embodiments, the addition of stands to the drill string moves the BHA through the stages of the well plan. Upon the drilling system reaching the end of a stage and/or the start of stage, the transition between the stage may occur at a known drill string length. In some embodiments, the method uses the known drill string length at a stage transition to reset the total drill string length and reduce cumulative errors in the determinations of the control unit. For example, variations in joint lengths or other portions of the drill string relative to a well plan or a pipe tally can cause variations between the calculated total drill string length and the actual drill string length.

In some embodiments, the stage transition has a known total drill string length at the stage transition. The control unit has the well plan and/or stages of the well plan stored locally on a hardware storage device in the downhole environment. In some embodiments, the method includes receiving, at the downhole tool, a stage pulse. The stage pulse may be a mud pulse and/or an RPM pulse of known duration and/or magnitude. The control unit receives the stage pulse and resets the total drill string length to the known drill string length at the stage transition of the well plan. In some embodiments, the control unit compares the magnitude, type, duration, or combinations thereof of the stage pulse to a LUT or to the well plan, itself. For example, a stage pulse may inform the control unit that the drilling system has completed the third stage of the well plan, and the known drill string length is 1000 meters. In another example, a stage pulse may inform the control unit that the drilling system has completed the fifth stage of the well plan, and the known drill string length is 1500 meters. The control unit then resets the total drill string length to the known value according to the LUT and/or well plan.

The method further includes receiving, at the downhole tool, a stand pulse, such as described herein, and determining an added stand length. In some embodiments, the control unit adds the added stand length to the known drill string length according to the associated stage pulse. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of known stand lengths and/or pipe lengths, such as a pipe tally. In some embodiments, determining an added stand length includes comparing the stand pulse to a LUT of approximate stand lengths and/or pipe lengths. In some embodiments, the stand length LUT changes with different stages (related to changes in pipe and/or connections for different stages), and the control unit compares the stand pulse to a stand length LUT associated with the current stage, at least partially according to the stage pulse.

In some embodiments, the LUT is pre-loaded onto the hardware storage device of the control unit before tripping the control unit downhole. A pre-loaded LUT allows the control unit to select from the information in the LUT in the downhole environment without complex downlink communications. In some embodiments, the LUT is a pipe tally including a sequence of known pipe lengths and/or stand lengths planned to be added to the drill string as the drilling system creates the borehole. In such examples, determining an added stand length includes incrementing through the known pipe lengths and/or stand lengths of the pipe tally.

For example, a pipe tally may include a sequence of known pipe lengths and a duration or magnitude of the stand pulse indicates the quantity of pipe segments added to the drill string. In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the pipe tally and add the next known pipe length to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including the next three segments of pipe added to the drill string. The control unit may access the pipe tally and add the next three known pipe lengths to the current drill string length to determine a total drill string length. In some embodiments, the pipe tally further includes joint lengths between pipe segments that allow the control unit to determine the added stand length from the plurality of pipe lengths of the pipe tally.

In another example, the LUT includes approximate stand lengths based on standardized stand lengths of drill pipe used in the drilling system. While some variation in the exact length of each segment of drill pipe segment is possible, a LUT with approximate stand lengths allows the BHA to track the total drill string length without a precise pipe tally and/or without a pre-determined sequence of pipe segments to be added to the drill string. For example, a pipe segment may be approximately 10 meters in length, and the stand pulse may indicate to the control unit the quantity of pipe segments in an added stand length.

In at least one example, a stand pulse including a 10-second RPM pulse indicates a single segment of pipe added to the drill string. The control unit may access the LUT and add 10 meters to the current drill string length to determine a total drill string length. In at least one example, a stand pulse including a 30-second RPM pulse indicates a stand of drill pipe including three segments of pipe added to the drill string. The control unit may access the LUT and add 30 meters to the current drill string length to determine a total drill string length.

The control unit may provide to the directional steering unit of the BHA the total drill string length (and hence position downhole) to inform the directional steering unit of the BHA's location in the well plan. In some embodiments, the method optionally includes determining a TVD of the BHA based at least partially on the well plan and the total string length as described herein. In some embodiments, the control unit compares the total drill string length to the well plan to determine a TVD of the control unit and/or BHA relative to the surface, based at least partially on the location of the control unit and/or BHA in the well plan.

It should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein, to the extent such features are not described as being mutually exclusive. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about”, “substantially”, or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims. The described embodiments are therefore to be considered as illustrative and not restrictive, and the scope of the disclosure is indicated by the appended claims rather than by the foregoing description.