Systems and methods of controlling a downhole tool by instrumented engagement element

Abstract

A system may obtain one or more engagement measurements including at least one engagement measurement of a surface in a wellbore from an engagement sensor (646), wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool. A system may obtain accelerometer data from an accelerometer that is concurrent with the one or more engagement measurements (648). A system may correlate data variations in the one or more engagement measurements and in the accelerometer data, wherein the data variations are values outside of a threshold value (650). A system may identify at least one drilling dysfunction based on correlated accelerometer data and engagement measurements (652). A system may change at least one wellbore parameter based on the correlated accelerometer data and engagement measurements (654).

Description

PATENTDocket No. IS24.1698-WOSYSTEMS AND METHODS OF CONTROLLING A DOWNHOLE TOOL BY INSTRUMENTED ENGAGEMENT ELEMENTCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of United States Provisional Patent Application No. 63 / 723,063, filed on November 20, 2024, which is hereby incorporated by reference in its entirety.BACKGROUND

[0002] Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.

[0003] Wellbores can extend deep into the earth, often up to several kilometers. It is important and often difficult to accurately detect and map geological formations to identify sources of oil, gas, heat, or other valuable resources. For example, imaging tools may be implemented to measure various parameters of the surrounding rock.BRIEF SUMMARY

[0004] In some aspects, the techniques described herein relate to a method of controlling a downhole tool, the method including: obtaining one or more engagement measurements including at least one engagement measurement of a surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; obtaining accelerometer data from an accelerometer that is concurrent with the one or more engagement measurements; correlating data variations in thePATENTDocket No. IS24.1698-WO one or more engagement measurements and in the accelerometer data, wherein the data variations are values outside of a threshold value; identifying at least one drilling dysfunction based on correlated accelerometer data and engagement measurements; and changing at least one wellbore parameter based on the correlated accelerometer data and engagement measurements.

[0005] In some aspects, the techniques described herein relate to a method of controlling a downhole tool, the method including: obtaining one or more engagement measurements including at least one downhole engagement measurement of a downhole surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; converting the one or more engagement measurements into a depth log or time log; identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log or time log; training a machine learning (ML) model with the identified drilling dysfunction in the depth log to create a trained ML model; providing a second depth log or time log to the trained ML model; identifying at least one drilling dysfunction in the second depth log or time log; and changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log.

[0006] 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.

[0007] Additional features and advantages 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 advantages 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.PATENTDocket No. IS24.1698-WOBRIEF DESCRIPTION OF THE DRAWINGS

[0008] 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 implementations 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, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example implementations, the implementations will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0009] FIG. 1 shows one embodiment of a drilling system for drilling an earth formation, according to at least one embodiment of the present disclosure;

[0010] FIG. 2 is a bottom view of a downhole end of an embodiment of a bit, according to at least one embodiment of the present disclosure;

[0011] FIG. 3 is a side schematic view of an embodiment of an instrument assembly as implemented in a downhole tool, according to at least one embodiment of the present disclosure;

[0012] FIG. 4 is a perspective view of a downhole tool, according to at least one embodiment of the present disclosure;

[0013] FIG. 5 is a comparison of engagement measurements and accelerometer measurements that are obtained concurrently during a test drilling operation, according to at least one embodiment of the present disclosure;

[0014] FIG. 6 is a flowchart illustrating a method of controlling a downhole tool, according to at least one embodiment of the present disclosure;

[0015] FIG. 7 illustrates collected data from a drill bit including at least one instrumented engagement element, according to at least one embodiment of the present disclosure;PATENTDocket No. IS24.1698-WO

[0016] FIG. 8 is a flowchart illustrating a method of training an ML model to identify drilling dysfunctions from engagement measurements, according to at least one embodiment of the present disclosure;

[0017] FIG. 9 is a flowchart illustrating a method of training an ML model to identify drilling dysfunctions from engagement measurements and at least one other data type, according to at least one embodiment of the present disclosure;

[0018] FIG. 10 is a flowchart illustrating a method of determining drilling dysfunction modes and / or triggers in a drilling operation, according to at least one embodiment of the present disclosure;

[0019] FIG. 11 is a system diagram of a computer system used to implement the various devices, components, and systems described herein;

[0020] FIG. 12-1 is a perspective cutaway view of a downhole tool, according to at least one embodiment of the present disclosure;

[0021] FIGS. 12-2 and 12-3 are schematic views illustrating an engagement of an instrumented engagement element and a lead engagement element, according to at least one embodiment of the present disclosure;

[0022] FIG. 13 is a side cutaway view of an engagement element housing, according to at least one embodiment of the present disclosure; and

[0023] FIG. 14 is a side cutaway view of an engagement element housing, according to at least one embodiment of the present disclosure.DETAILED DESCRIPTION

[0024] This disclosure generally relates to devices, systems, and methods for instrumented engagement elements. For example, a drilling system may implement one or more tools for engaging a borehole. An instrumented engagement element may be implemented in conjunction with one or more downhole tools and may engage the borehole. The instrumented engagement element may include one or more sensors for taking downhole measurements, such as strain or other measurements, associated with the engagement of thePATENTDocket No. IS24.1698-WO engagement element with the borehole. The observed downhole measurements (or more specifically changes in the observed downhole measurements) may be useful for determining and / or mapping one or more features of the borehole, in at least one embodiment described herein.

[0025] In some cases, the instrumented engagement element may collect engagement measurements that allow for characterization of drilling dysfunctions during or after drilling operations. In some embodiments, the engagement measurements are considered in combination with other measurements, such as accelerometer data collected concurrently and / or in the same measurement space as the engagement measurements. In some embodiments, a machine learning model is trained at least partially on the engagement measurements to correlate engagement measurements to one or more drilling dysfunctions and / or the triggers thereof. The trained machine learning model is, in some embodiments, subsequently used to identify drilling dysfunction(s) and / or the triggers thereof in subsequent engagement measurements or other data channels.

[0026] FIG. 1 shows one embodiment of a drilling system 100 for drilling an earth formation 101 (e.g., a downhole earth formation) to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105.

[0027] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 may transmit drilling fluid through a central bore and may transmit rotational power from the drill rig 103 to the BHA 106. Rotational power may also be transmitted through one or more mud motors located in the wellbore 102. In some embodiments, the drill string 105 further includes additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110PATENTDocket No. IS24.1698-WO and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0028] 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 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, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore 102. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and / or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.

[0029] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

[0030] 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. 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 wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within thePATENTDocket No. IS24.1698-WO wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.

[0031] The drilling system 100 may include one or more instrument assemblies which may include an instrumented engagement element for taking measurements based on an engaging the formation 101 in the wellbore 102. For instance, the instrument assembly 119 may be implemented within a body of a downhole tool of the drilling system 100, such as the bit 110. The instrument assembly may include one or more sensors, for example, for taking measurements (such as force) based on an engagement of one or more components of the instrument assembly with the borehole.

[0032] FIG. 2 is a bottom view of the downhole end of an embodiment of a bit 210, according to at least one embodiment of the present disclosure. The bit 210 may include a bit body 211 from which a plurality of blades 212 may protrude. At least one of the blades 212 may have a plurality of cutting elements 213 connected thereto. In some embodiments, at least one of the cutting elements is a planar cutting element, such as a shear cutting element. In other embodiments, at least one of the cutting elements is a non-planar cutting element, such as a conical cutting element (e.g., STINGER cutting elements) and / or a ridged cutting element.

[0033] In some embodiments, the bit 210 includes an instrument assembly 219. The instrument assembly 219 may include instrumentation for taking one or more downhole measurements with the bit 210. For example, the instrument assembly 219 may include one or more sensors for measuring force, stress, strain, pressure, temperature, or combinations thereof. While the instrument assembly 219 is shown and described here with particular reference to a bit, it should be understood that the instrument assembly 219 may be implemented on, within, and / or in connection with any downhole tool which may engage a formation, such as a reamer, stabilizer, pad, steering tool, etc.

[0034] In accordance with at least one embodiment of the present disclosure, the instrument assembly 219 includes an engagement element and anPATENTDocket No. IS24.1698-WO engagement sensor for measuring an engagement of the engagement element with a borehole. A power supply may provide power to the engagement sensor, and a processor and memory may receive and / or record engagement measurements from the engagement sensor. In this way, the engagement element may engage the borehole, and the instrument assembly may take corresponding measurements (e.g., axial forces and / or other measurements) on the engagement element. The engagement measurements may facilitate creating or generating one or more of a graph, plot, image, and / or map of one or more parameters experienced by the bit 210 in order to illustrate one or more properties and / or features associated with the materials encountered by the bit 210 while forming the borehole.

[0035] FIG. 3 is a side schematic view of an embodiment of an instrument assembly 319 as implemented in a downhole tool 310, according to at least one embodiment of the present disclosure. The downhole tool 310 may be a rotating downhole tool such as a bit, reamer, stabilizer, etc., or may be any other downhole tool which may engage a formation, such as a steering tool. The instrument assembly includes an engagement element 321. The engagement element 321 may be positioned within and at least partially extending from a body 311 of the downhole tool 310. For instance, the engagement element 321 may be positioned and configured to engage a formation based on the downhole tool 310 being positioned and operated within a wellbore. In some embodiments, the downhole tool 310 may include one or more additional engagement elements (e.g., cutting elements). The engagement element 321 may, in some cases, be positioned rotationally behind one or more of these additional engagement elements, (e.g., behind a leading element), such that the engagement element 321 engages a formation (or is exposed to the formation) in a rotational path or cutout of the leading element.

[0036] The engagement element 321 may be configured and implemented in accordance with any of the engagement elements, instrument assemblies, and / or downhole tools as described in any of U.S. Patent Application No. 18 / 664,475, filed May 15, 2024; U.S. Patent Application No. 18 / 664,358, filed May 15, 2024;PATENTDocket No. IS24.1698-WOU.S. Patent Application No. 18 / 664,546 filed May 15, 2024; and U.S. Patent Application No. 18 / 639,374 filed April 18, 2024; which are each hereby incorporated by reference in their entirety. For example, the instrument assembly 319 may include and / or may be associated with an engagement sensor 323. The engagement sensor 323 may be as sensor for taking one or more measurements associated with an engagement of the engagement element 321 with a wellbore, borehole, formation, etc. For instance, the engagement element 321 may engage a formation 301 at an engagement surface 307, and the engagement sensor 323 may take measurement data based on this engagement. For example, the engagement sensor 323 may be a sensor for measuring an amount of force (e.g., a normal or axial component of a force) imparted onto the engagement element 321 , such as a force transducer, load cell, strain gauge, hall effect sensor, or any other suitable sensor. In some embodiments, the engagement sensor 323 is positioned at or near a base of the engagement element 321 , at or near a diaphragm of the instrument assembly 319, or another location for taking measurements associated with the engagement element 321 engaging the formation 301 at the engagement surface 307. In this way, the engagement element 321 , or may be instrumented with the engagement sensor 323 for taking measurement data. More example configurations of the engagement element 321 and the instrument assembly 319 are described below in connection with FIGS. 12-1 to 14.

[0037] The engagement element 321 and engagement sensor 323 may be associated with electronics 325 positioned within the body of the downhole tool 310. The electronics 325 may be connected to the engagement sensor 323, for example, for taking and logging measurements with the engagement sensor 323. For instance, the electronics of the instrument assembly 319 may include a processor 325-1 and / or a power source 325-2. The processor 325-1 may be any include any type(s) of processing components such as CPUs, GPUs, etc. The power source 325-2 may be inclusive of any type(s) of power sources, such as batteries, capacitors, inertial power generators, thermal power generators, etc. The electronics 325 may include one or more additional components such asPATENTDocket No. IS24.1698-WO memory resources, additional sensors (e.g., gyroscopic sensors, accelerometers, magnetometers, etc.), etc. In some cases, the electronics 325 may include communication devices such as hardwired communication components or componentry for wireless communication such as Bluetooth, acoustic communication, etc. The electronics 325 may be coupled to and / or associated with the engagement sensor 323. For example, the power source 325-2 may power a function of the sensor 323, and the processor 325-1 may receive and / or record one or more measurements of the engagement sensor 323 (e.g., process and / or save to memory). The electronics 325 may include any of the features and / or functionalities as described in connection with FIG. 5.

[0038] The electronics 325 may be positioned within a sealed portion of the body 311. For example, the electronics 325 (e.g., and in some cases the engagement sensor 323) may be positioned within a housing 314. The housing 314 may be an electronics housing which may house, support, position, and / or protect the various electronic and / or computing components positioned therein. In some cases, the engagement element 321 may be positioned at least partially in or interfacing with the housing 314. In some embodiments, the housing 314 may be positioned proximate, adjacent and / or in a same area or region of the body 311 , such as on a same blade or cutting (e.g., or engagement) structure of the body 311. In some embodiments, the housing 314 may be positioned at a different portion within the body 311 , for example, that is not necessarily adjacent or proximate the engagement element 321 , such that the electronics housing (e.g., and the components housed therein) may be remote and / or positioned some distance from the engagement element 321. As shown in FIG. 3, the housing 314 is illustrated as a dashed box, which is representative of the illustrative nature of this figure, and should be understood as conveying that the housing 314 may contain or house the components illustrated therein, but may not necessarily be positioned and / or oriented as indicated in this figure, but rather may be connected to and / or otherwise associated with the engagement element 321 at any position within the body 311 of the downhole tool 310. In this way, the instrument assembly 319 may be positioned, configured, and implemented in aPATENTDocket No. IS24.1698-WO variety of different ways in order to accommodate various features and functionalities of the instrument assembly 319.

[0039] As mentioned, the instrument assembly 319 may be implemented in connection with the downhole tool 310 to take one or more measurements based on the engagement element 321 engaging the formation 301. For instance, the instrument assembly may be implemented as part of a drill bit for taking measurements during drilling with the bit. For example, the engagement element 321 may be oriented in a general longitudinal direction (e.g., a longitudinal direction of the downhole tool 310, the wellbore, a direction of drilling etc.) and / or downward direction(e.g., downhole with respect to the direction or trajectory of the wellbore). In this way, the engagement element 321 may engage the formation and may take measurement data in connection with the downhole tool 310 (e.g., a drill bit in this case) engaging the wellbore bottom hole in order to drill, form, and / or lengthen the wellbore. For instance, the engagement surface 307 of the formation 301 may be representative of the bottom hole of the wellbore being formed by the downhole tool 310.

[0040] In some cases, the instrument assembly 319 may be implemented in order to take measurement data associated with a wellbore wall of the wellbore, for example, as opposed to the wellbore bottom hole. For example, the engagement element 321 may be positioned, oriented, and / or otherwise configured to extend from the downhole tool 310 and contact the wellbore wall. For instance, the engagement element 321 may extend radially and / or laterally from the downhole tool 310 in order to engage the wellbore wall. The engagement surface 307 in this case may be representative of the wellbore wall. For instance, the wellbore wall may be the wall of a wellbore that has already been formed to a gauge diameter and / or that is being enlarged or further widened by one or more downhole tools. In this way, the instrument assembly 319 may be implemented to collect information associated with the wellbore wall, for example, so as to characterize, image, and / or otherwise measure features of the wellbore wall. In some cases, the engagement element 321 oriented outward in this way for engaging the wellbore wall may be positioned rotationally behind and / or in thePATENTDocket No. IS24.1698-WO cutting path of another, lead element as described herein. In some cases, such as when the engagement element 321 is configured to engage the wellbore wall of a completed and / or finished wellbore (e.g., or finished phase of a wellbore), the engagement element 321 may not specifically be positioned rotationally behind a lead element but may rather engage the formation independent of a cutting path of some rotationally leading element.

[0041] The instrument assembly 319 may be implemented in this way on, at, and / or in connection with any downhole tool having one or more portions that engage outwardly to the wellbore wall. For example, an instrumented engagement element may be positioned on a gauge portion or gauge pad of a drill bit (or other downhole tool having a gauge section), on a blade of a (e.g., expandable) reamer, on rib a stabilizer tool or stabilizer structure of another downhole tool, on a steering tool having one or more expandable arms, pistons or pads, on a dedicated sub for engaging the wellbore wall and taking engagement measurements, or on any other downhole tool which engages the wellbore wall.

[0042] In this way, the instrumented assembly 319 may facilitate engaging the wellbore wall and taking measurement data associated with the wellbore wall (e.g., as opposed to the wellbore hole bottom). As described herein, taking measurement data for the wellbore wall may be advantageous for various purposes, such for taking measurement data when a drill bit is off bottom or not otherwise engaging the wellbore bottom hole, for imaging and / or characterizing aspects of the wellbore wall specifically, and / or evaluating a filter cake formed on the wellbore wall, among other purposes.

[0043] FIG. 4 is a perspective view of a downhole tool 410, according to at least one embodiment of the present disclosure. The downhole tool 410 may be a drill bit for engaging a wellbore bottom hole and lengthening the wellbore. The downhole tool 410 may be illustrative of a fixed-cutter or drag bit having one or more fixed blades 412 or cutting structures with cutting elements 413 thereon for degrading the formation and drilling a wellbore through a shearing interaction of the one or more cutting elements 413 with the formation. The downhole tool 410,PATENTDocket No. IS24.1698-WO however, may be any type of drill bit, such as a roller-cone bit, a hybrid roller- cone / fixed blade bit, etc.

[0044] In some embodiments, the downhole tool 410 has a gauge section 430. The gauge section may be a portion of a body 411 of the downhole tool 410 that is at or near a diameter of the cut of the downhole tool 410. For example, the gauge section 430 may extend radially to (or near) the furthest extent of any portion of the downhole tool 410. The gauge section 430 may include a gauge pad 432 or gauge element which may engage the formation (e.g., the wellbore wall) at the gauge diameter at which the downhole tool 410 cuts or forms the wellbore. The gauge pad 432 may be an engagement element (e.g., similar to the cutting elements 413) inserted into the gauge section 430, may be a larger inserted pad or section of the gauge section 430, may be a portion of the gauge section 430 having hardfacing or other superhard material deposited thereon, or other manner of engaging the wellbore wall. In some cases, the gauge section 430 is connected to and / or part of a blade 412 of the downhole tool 410 or may be otherwise implemented as a separate structure or geometry. In this way, the gauge section 430 and gauge pad 432 may engage the wellbore wall, which may define a specific diameter of cut of the downhole tool 410, may ensure a close or snug fit of the downhole tool 410 into the formed wellbore, may aid in centering the downhole tool 410, may providing stability for the downhole tool 410, etc.

[0045] In some embodiments, the downhole tool 410 includes an instrumented engagement element 421 positioned on or at the gauge section 430 of the downhole tool 410. For instance, the instrumented engagement element 421 may be positioned within the body 411 of the downhole tool 410 and may extend from the body 411 outward in a radial or lateral direction. In some cases, the instrumented engagement element 421 may extend radially in a normal or perpendicular direction to the longitudinal axis (e.g., rotational axis) of the downhole tool 410, or may extend at some other non-normal angle having a radial or lateral component.

[0046] The instrumented engagement element 421 may extend from the downhole tool 410 in this way and may engage the wellbore wall which thePATENTDocket No. IS24.1698-WO downhole tool 410 is or has formed. In some cases, the instrumented engagement element 421 engages the wellbore wall at the gauge diameter of the downhole tool 410 and / or of the wellbore. For instance, the gauge section 430 and the instrumented engagement element 421 may be positioned longitudinally behind (e.g., uphole) that of the cutting elements 413, and accordingly the instrumented engagement element 421 may be configured to engage a finished or completed portion of the wellbore wall. In some embodiments, the instrumented engagement element 421 may be implemented as one of the gauge pads 432 instrumented with an engagement sensor as described herein for collecting engagement measurements associated with the gauge pad 432 engaging the wellbore wall.

[0047] The instrumented engagement element 421 may be configured and / or implemented in connection with an instrument assembly as described herein having an engagement sensor and other associated electronics for taking and logging measurements associated with the instrumented engagement element 421 engaging the wellbore wall. For example, the instrument assembly may have a housing with the electronic components positioned therein, which may be positioned within the body 311 described herein. The housing may be positioned adjacent and / or near the instrumented engagement element 421 or may be positioned at some other portion of the body 311 that may be more remote from the instrumented engagement element 421. In this way, the instrumented engagement element 421 may facilitate engaging the wellbore wall and taking measurement data associated with the wellbore wall as described herein.

[0048] In some embodiments, the downhole tool 410 further includes an accelerometer 434. In some embodiments, an accelerometer is located in a different downhole tool of the tool string. In some embodiments, a processor or computing device is in data communication with both an instrumented assembly including the instrumented engagement element 421 (and sensors thereof) and the accelerometer 434. For example, the accelerometer may allow measurements of shock, vibration, rotation, and other accelerations in an axial direction of a rotational axis of the downhole tool 410, a radial direction relativePATENTDocket No. IS24.1698-WO to the rotational axis, a rotational direction relative to the rotational axis, or combinations thereof.

[0049] In some embodiments, a method of controlling a downhole tool includes obtaining measurements from both an instrument assembly including the instrumented engagement element 421 (and sensors thereof) and the accelerometer 434. In some embodiments, the accelerometer measurements provide information regarding drilling dysfunction(s) that can be correlated with the one or more engagement measurements of an instrumented assembly including the instrumented engagement element 421 (and sensors thereof). For example, the accelerometer data may illustrate whirling of the drill string, and periodic measurements in the one or more engagement measurements may indicate a hard inclusion in the formation. Such correlation may indicate a causal or contributing factor to the whirling. A system and / or operator may change at least one drilling parameter (such as weight-on-bit) based at least partially on the characterization of the drilling dysfunction by the correlated measurements of the instrumented assembly including the instrumented engagement element 421 (and sensors thereof) and the accelerometer 434.

[0050] FIG. 5 is a comparison of engagement measurements 536 (e.g., strain measurements) and accelerometer measurements 538 that are obtained concurrently during a test drilling operation. In some embodiments, the two measurements are transmitted to a computing device concurrently in real-time during collection. For example, the computing device may be local to the downhole environment, such as a control unit in the BHA or tool string. In some examples, the computing device may be remote to the downhole environment, such as a computing device located at a surface location of the drilling system, via wireline communications or other uphole communications. In some examples, the computing device is located remote to the drilling system, such as a cloud computing device in a datacenter in communication with the drilling system via a network. In some embodiments, the two measurements are logged in a hardware storage device in the downhole environment concurrently in real-time duringPATENTDocket No. IS24.1698-WO collection. In some embodiments, the two measurements are transmitted to a computing device concurrently in real-time during collection.

[0051] The engagement measurements 536 (left) are plotted horizontally in the graph relative to a bit angular position and vertically on bit revolution number. The data may also be plotted vertically on bit depth following co-location with a surface depth sensor. Such presentation allows the strain measurements to be plotted in equal measurement space irrespective of the rotational speed and / or ROP of the drill bit. In some examples, the engagement measurements 536 are visualized differently. The graph of the accelerometer measurements 538 (right) illustrates the same drilling section in the same measurement space (e.g., horizontally in the graph relative to a bit angular position and vertically on bit revolution number), and the graph is generated from the radial accelerometer axis of the accelerometer (such as the accelerometer 434 described in relation to FIG. 4). Comparing the engagement measurements 536 and accelerometer measurements 538 in the same measurement space allows a direct correlation of pixel values between the two measurements.

[0052] As illustrated in the data, broad variance regions 540-1 540-2 of increases in strain measurement may illustrate changes in the forces experienced by an instrumented engagement element of the drill bit or other downhole tool, while such changes in strain measurements may not manifest as changes in acceleration of the drill bit or other downhole tool in a radial direction. In contrast, the broad bedding plane 542 encountered around Revolution 6400 is evident in both images. In the accelerometer measurements 538 the high shock zone of the broad bedding plane 542 is horizontally layered and is indicative of a drilling dysfunction. In some embodiments, the accelerometer measurements 538 allow for filtering of the engagement measurements 536 to more accurately identify drilling dysfunctions.

[0053] FIG. 6 is a flowchart illustrating a method 644 of controlling a downhole tool. In some embodiments, the method 644 includes obtaining one or more engagement measurements including at least one downhole engagement measurement of a downhole surface in a wellbore from an engagement sensorPATENTDocket No. IS24.1698-WO at 646, wherein the engagement sensor is housed in an electronics housing positioned within a body of the downhole tool. In some embodiments, obtaining the one or more measurements includes contacting an instrumented engagement element with a wellbore surface and measuring a strain measurement with the instrument engagement element. In some embodiments, at least one of the instrumented engagement elements is a downhole engagement element that contacts a downhole surface of the wellbore. For example, the downhole engagement element is located on a downhole surface of a drill bit, as described herein. In some examples, the downhole engagement element is located on a downhole surface of a pad, reamer, or other component of the tool string. In some embodiments, at least one of the instrumented engagement elements is an uphole engagement element that contacts a lateral surface of the wellbore (e.g., the wellbore wall) uphole from the downhole engagement element. In at least one embodiment, the uphole engagement element is oriented laterally or radially outward. For example, the uphole engagement element is located on a gauge surface of a drill bit, as described herein. In some examples, the uphole engagement element is located on a lateral surface of a pad, reamer, or other component of the tool string.

[0054] In some embodiments, obtaining the one or more engagement measurements includes receiving a transmission from an engagement sensor, a downhole tool, or a processor thereof. For example, the transmission may be a transmission to a computing device at a surface location. In some examples, the transmission may be a transmission from the engagement sensor to a downhole computing device. In some embodiments, obtaining the one or more engagement measurements includes transferring the data locally after drilling and / or reaming operations and after the downhole tool is tripped out of the wellbore. For example, a downhole tool or an engagement sensor thereof may log the one or more engagement measurements in a hardware storage device downhole for later transfer to a computing device.

[0055] The method 644, in some embodiments, further includes obtaining accelerometer data from an accelerometer that is concurrent with the one or morePATENTDocket No. IS24.1698-WO engagement measurements at 648. For example, the accelerometer data may be concurrently collected with the one or more engagement measurements. In some examples, the accelerometer data may be aligned with the one or more engagement measurements after collection by rotational position of the downhole tool (such as described in relation to FIG. 5). In some examples, the accelerometer data may be aligned with the one or more engagement measurements after collection by depth position of the downhole tool. In some examples, the accelerometer data may be aligned with the one or more engagement measurements after collection by time of the downhole tool in the drilling operation.

[0056] In some embodiments, obtaining the accelerometer data includes receiving a transmission from an engagement sensor, a downhole tool, or a processor thereof. For example, the transmission may be a transmission to a computing device at a surface location. In some examples, the transmission may be a transmission from the accelerometer to a downhole computing device. In some embodiments, obtaining the accelerometer data includes transferring the data locally after drilling and / or reaming operations and after the downhole tool is tripped out of the wellbore. For example, a downhole tool or an accelerometer thereof may log the accelerometer data in a hardware storage device downhole for later transfer to a computing device.

[0057] The method 644, in some embodiments, further includes correlating data variations in the one or more engagement measurements and in the accelerometer data, wherein the data variations are values outside of a threshold value at 650. In some embodiments, a data variation is any portion of the accelerometer data and / or the engagement measurements that varies in magnitude relative to adjacent data by at least a threshold value. In some embodiments, the adjacent data is adjacent to a datapoint of the accelerometer data and / or the engagement measurements within a time period. In some embodiments, the adjacent data is adjacent to a datapoint of the accelerometer data and / or the engagement measurements in a rotational direction. In some embodiments, the adjacent data is adjacent to a datapoint of the accelerometerPATENTDocket No. IS24.1698-WO data and / or the engagement measurements in an axial (e.g., depth) direction. In some embodiments, the adjacent data is adjacent to a datapoint of the accelerometer data and / or the engagement measurements within range of datapoints. In some embodiments, the adjacent data is adjacent to a datapoint of the accelerometer data and / or the engagement measurements within range of datapoints.

[0058] In some embodiments, the data variation is a deviation greater than a threshold value from an average value of the accelerometer data and / or engagement measurements of the entire dataset (such as the dataset described in relation to FIG. 5) of the drilling operation. In some embodiments, the data variation is a deviation from a rolling average value of the accelerometer data and / or engagement measurements of a subset of datapoints of the drilling operation. In some embodiments, the data variation is a deviation from a predetermined value of the accelerometer data and / or engagement measurements of the drilling operation.

[0059] In some embodiments, the threshold value is a predetermined value. In some embodiments, the threshold value is a percentage of the total range of collected values for the accelerometer data and / or the engagement measurements, respectively. In some embodiments, the threshold value is a standard deviation of collected values for the accelerometer data and / or the engagement measurements, respectively.

[0060] The method 644, in some embodiments, further includes identifying at least one drilling dysfunction based on correlated accelerometer data and engagement measurements at 652. For example, correlating the accelerometer data and engagement measurements may allow an operator to view only the portions of the collected information that include statistically significant data variations in both the accelerometer data and engagement measurements, and the operator may identify the drilling dysfunction, such as bit bounce, whirling, stick-slip, or other drilling dysfunctions.PATENTDocket No. IS24.1698-WO

[0061] In some embodiments, identifying at least one drilling dysfunction based on correlated accelerometer data and engagement measurements includes automated identification of the drilling dysfunction. For example, the correlated accelerometer data and engagement measurements may identify the drilling dysfunction based at least partially on an axis of the accelerometer data. In some examples, correlated accelerometer data and engagement measurements with an axial accelerometer data variation may indicate bit bounce. In some examples, correlated accelerometer data and engagement measurements with a rotational accelerometer data variation may indicate whirling. In some embodiments, an automated identification may use additional measurements such as acoustic, pressure, or other downhole or surface measurements. In some embodiments, automated identification may further use a machine learning model, as will be described in more detail herein.

[0062] The method 644, in some embodiments, further includes changing at least one wellbore parameter based on the correlated accelerometer data and engagement measurements at 654. In some embodiments, the wellbore parameter is a drilling parameter. For example, the one or more engagement measurements may be obtained during drilling, and the method includes changing at least one drilling parameter (e.g., WOB, TOB, cutting depth, RPM) based at least partially on the one or more engagement measurements. In some embodiments, the wellbore parameter is a production parameter. For example, the one or more engagement measurements may be obtained after drilling and be used for well production. In such an example, a wellbore parameter such as production rate of the well may be changed based at least partially on the one or more engagement measurements. In some examples, the one or more engagement measurements may be obtained after drilling and be used for a wellbore design parameter. In such an example, a wellbore design parameter such as perforation location or perforation interval of the well may be changed based at least partially on the one or more engagement measurements.

[0063] FIG. 7 illustrates collected data from a drill bit including at least one instrumented engagement element. The engagement measurements 736 (e.g.,PATENTDocket No. IS24.1698-WO strain measurements) are illustrated on the right side with each datapoint representing the strain magnitude measurement relative to the rotational position on the horizontal direction and depth on the vertical direction. The striped first variance region 740-1 is identifiable as bit whirling, showing a strain magnitude that is oscillating between high and low values periodically but uncorrelated to rotational position. Conversely, the localized second variance region 740-2 represents a cluster of high magnitude strain measurements that are clustered in both the horizontal (rotational) and vertical (depth) directions. Such a localized second variance region 740-2 indicates a hard inclusion in the formation through which the drill bit is cutting (and with which the instrumented engagement element is engaging upon) upon each revolution of the bit.

[0064] In some examples, an operator or technician may label one or more variance regions or other features in the engagement measurements, and the label(s) and the engagement measurements may be provided as a training dataset for a machine learning (ML) model. Such input may train the ML model by supervised training. In some embodiments, the engagement measurement may include additional metrics or drilling parameters, such as rotations per minute (RPM) 756, static weight on bit (SWOB) 758, etc. In some embodiments, the engagement measurements may be provided as a training dataset for an ML model. Such input may train the ML model by unsupervised training. In some embodiments, the engagement measurements and other measurements may be provided as a training dataset for an ML model. Such input may train the ML model by unsupervised training. In some embodiments, a first dataset including measurements (e.g., the engagement measurements and, optionally, other measurements) and labels may be provided as a training dataset for an ML model while a second dataset including measurements (e.g., the engagement measurements and, optionally, other measurements) and no labels may be provided as a second training dataset for the ML model. Such input may train the ML model by semi-supervised training.

[0065] FIG. 8 is a flowchart illustrating a method 860 of training an ML model to identify drilling dysfunctions from engagement measurements. The methodPATENTDocket No. IS24.1698-WO860 includes obtaining an engagement measurement from an instrument engagement element at 862, such as described herein at least in relation to FIG. 3-5. The method 860 further includes processing the data including the engagement measurement(s) into time logs or depth logs to relate the engagement measurement(s) to a time or location in a wellbore at 864, such as described in relation to the examples of FIG. 5 and FIG. 7.

[0066] In some embodiments, the method 860 further includes identifying and / or labeling the region(s) (e.g., time interval or depth intervals such as the variance regions of FIG. 5 and / or FIG. 7) with features correlating to drilling dysfunction modes and / or severities at 866. In some embodiments, identifying and / or labeling the region(s) includes identifying and / or labeling bit whirling, bit bounce, stick-slip, and other dysfunction modes. In some embodiments, identifying and / or labeling the region(s) includes identifying and / or labeling associated triggers of bit whirling, bit bounce, stick-slip, and other dysfunction modes.

[0067] The method 860 further includes training an ML model using the labeled data sets at 868. The trained ML model may calculate, based on the input training dataset including labels, correlations between the engagement measurements and the labels identifying the drilling dysfunction modes and / or the triggers of the drilling dysfunction modes.

[0068] Similarly, an ML model may be trained on more than just labeled engagement measurements. FIG. 9 is a flowchart illustrating a method 960 of training an ML model to identify drilling dysfunctions from engagement measurements and at least one other data type. The method 960 includes obtaining an engagement measurement from an instrument engagement element at 962, such as described herein at least in relation to FIGS. 3-5. The method 960, in some embodiments, further includes obtaining at least one other surface and / or downhole measurement channel at 970. For example, the at least one other surface and / or downhole measurement channel may be from an MWD tool. In some examples, the at least one other surface and / or downholePATENTDocket No. IS24.1698-WO measurement channel may be from an accelerometer, such as described at least in relation to FIGS. 4-6.

[0069] The method 960 further includes processing the combined data from the engagement measurement and the at least one other surface and / or downhole measurement channel into time logs or depth logs to relate the combined data to a time or location in a wellbore at 964, such as described in relation to the examples of FIG. 5 and FIG. 7.

[0070] In some embodiments, the method 960 further includes identifying and / or labeling the region(s) (e.g., time interval or depth intervals such as the variance regions of FIG. 5 and / or FIG. 7) with features correlating to drilling dysfunction modes and / or severities at 966. In some embodiments, identifying and / or labeling the region(s) includes identifying and / or labeling bit whirling, bit bounce, stick-slip, and other dysfunction modes. In some embodiments, identifying and / or labeling the region(s) includes identifying and / or labeling associated triggers of bit whirling, bit bounce, stick-slip, and other dysfunction modes.

[0071] The method 960 further includes training an ML model using the labeled data sets at 968. The trained ML model may calculate, based on the input training dataset including labels, correlations between the engagement measurements and the labels identifying the drilling dysfunction modes and / or the triggers of the drilling dysfunction modes.

[0072] FIG. 10 is a flowchart illustrating a method 1072 of determining drilling dysfunction modes and / or triggers in a drilling operation. In some embodiments, the method 1072 includes obtaining an engagement measurement from an instrument engagement element at 1062, such as described herein at least in relation to FIGS. 3-5. The method 1072, in some embodiments, optionally, includes obtaining at least one other surface and / or downhole measurement channel at 1070. For example, the at least one other surface and / or downhole measurement channel may be from an MWD tool. In some examples, the at leastPATENTDocket No. IS24.1698-WO one other surface and / or downhole measurement channel may be from an accelerometer, such as described at least in relation to FIGS. 4-6.

[0073] The method 1072 further includes processing the combined data from the engagement measurement and the at least one other surface and / or downhole measurement channel into time logs or depth logs to relate the combined data to a time or location in a wellbore at 1064, such as described in relation to the examples of FIG. 5 and FIG. 7.

[0074] In some embodiments, the method 1072 further includes inputting the logs into the trained ML model at 1074. For example, the trained ML model may be the ML model described in relation to FIG. 8 or FIG. 9 trained on at least engagement measurements and, optionally, other data channels. In some embodiments, the trained ML model is a trained with supervised training. In some embodiments, the trained ML model is a trained with semi-supervised training. In some embodiments, the trained ML model is a trained with unsupervised training.

[0075] In some embodiments, the method 1072 further includes obtaining the dysfunction modes and severity and / or triggers and identifying and / or labeling the dysfunction modes and severity and / or triggers on the time or depth logs using the trained model at 1076. In some embodiments, the method 1072 includes using the obtained and / or labeled dysfunction modes and severity and / or triggers to change at least one wellbore parameter based on the identified dysfunction modes and severity and / or triggers at 1078.

[0076] In some embodiments, the wellbore parameter is a drilling parameter. For example, the one or more engagement measurements may be obtained during drilling, and the method includes changing at least one drilling parameter (e.g., WOB, TOB, cutting depth, RPM) based at least partially on the one or more engagement measurements. In some embodiments, the wellbore parameter is a production parameter. For example, the one or more engagement measurements may be obtained after drilling and be used for well production. In such an example, a wellbore parameter such as production rate of the well may be changed based at least partially on the one or more engagement measurements.PATENTDocket No. IS24.1698-WOIn some examples, the one or more engagement measurements may be obtained after drilling and be used for a wellbore design parameter. In such an example, a wellbore design parameter such as perforation location or perforation interval of the well may be changed based at least partially on the one or more engagement measurements.

[0077] Turning now to FIG. 11 , one or more computer systems 1180 may be used to implement the various devices, components, and systems described herein. The computer system 1180 includes a processor 1182. The processor 1182 may be a general-purpose single- or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor 1182 may be referred to as a central processing unit (CPU). Although just a single processor 1182 is shown in the computer system 1180 of FIG. 11 , in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

[0078] The computer system 1180 also includes memory 1184 in electronic communication with the processor 1182. The memory 1184 may include computer-readable storage media and can be any available media that can be accessed by a general purpose or special purpose computer system. Computer- readable media that store computer-executable instructions are non-transitory computer-readable media (device). Computer-readable media that carry computer-executable instructions are transmission media. Thus, by way of example and not limitations, embodiment of the present disclosure can comprise at least two distinctly different kinds of computer-readable media: non-transitory computer-readable media (devices) and transmission media.

[0079] Both non-transitory computer-readable media (devices) and transmission media may be used temporarily to store or carry software instructions in the form of computer readable program code that allows performance of embodiments of the present disclosure. Non-transitory computer- readable media may further be used to persistently or permanently store suchPATENTDocket No. IS24.1698-WO software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disk storage (e.g., CD, DVD, HDDVD, Blu-ray, etc.), storage devices (e.g., magnetic disk storage, tape storage, diskette, etc.), flash or other solid-state storage or memory, or any other non-transmission medium which can be used to store program code in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.

[0080] Instructions 1186 and data 1188 may be stored in the memory 1184. The instructions 1186 may be executable by the processor 1182 to implement some or all of the functionality disclosed herein. Executing the instructions 1186 may involve the use of the data 1188 that is stored in the memory 1184. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 1186 stored in memory 1184 and executed by the processor 1182. Any of the various examples of data described herein may be among the data 1188 that is stored in memory 1184 and used during execution of the instructions 1186 by the processor 1182.

[0081] A computer system 1180 may also include one or more communication interfaces 1190 for communicating with other electronic devices. The communication interface(s) 1190 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 1190 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.

[0082] The communication interfaces 1190 may connect the computer system 1180 to a network. A “network” or “communications network” may generally be defined as one or more data links that enable the transport of electronic data between computer systems and / or modules, engines, or other electronic devices,PATENTDocket No. IS24.1698-WO or combinations thereof. When information is transferred or provided over a communication network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to a computing device, the computing device properly views the connection as a transmission medium. Transmission media can include a communication network and / or data links, carrier waves, wireless signals, and the like, which can be used to carry desired program or template code means or instructions in the form of computerexecutable instruction or data structures and which can be accessed by a general purpose or special purpose computer.

[0083] A computer system 1180 may also include one or more input devices 1192 and one or more output devices 1194. Some examples of input devices 1192 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 1194 include a speaker and a printer. One specific type of output device that is typically included in a computer system 1180 is a display device 1196. Display devices 1196 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller 1198 may also be provided, for converting data 1188 stored in the memory 1184 into one or more of text, graphics, or moving images (as appropriate) shown on the display device 1196.

[0084] The various components of the computer system 1180 may be coupled together by one or more buses, which may include one or more of a power bus, a control signal bus, a status signal bus, a data bus, other similar components, or combinations thereof. For the sake of clarity, the various buses are illustrated in FIG. 8 as a bus system 1199.

[0085] The techniques described herein may be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a specific manner. Any features described as modules, components, or the like may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implementedPATENTDocket No. IS24.1698-WO in software, the techniques may be realized at least in part by a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions may be organized into routines, programs, objects, components, data structures, etc., which may perform particular tasks and / or implement particular data types, and which may be combined or distributed as desired in various embodiments.

[0086] Further, upon reaching various computer system components, program code in the form of computer-executable instructions or data structures can be transferred automatically or manually from transmission media to non- transitory computer-readable storage media (or vice versa). For example, computer executable instructions or data structures received over a network or data link can be buffered in memory (e.g., RAM) within a network interface module (NIC), and then eventually transferred to computer system RAM and / or to less volatile non-transitory computer-readable storage media at a computer system. Thus, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize transmission media.

[0087] FIGS. 12-1 through FIG. 14 illustrate various examples of downhole tools, instrument assemblies, instrumented engagement elements, and / or other components as discussed herein. It should be understood that the examples described in these figures are representative of possible configurations of components, assemblies, and / or systems for implementing the engagementfrequency system as described herein.

[0088] FIG. 12-1 is a perspective cutaway view of a downhole tool 1210 according to at least one embodiment of the present disclosure. In some embodiments, the downhole tool 1210 is a bit, but the downhole tool 1210 may be any other downhole tool which may be implemented in a wellbore for engaging the formation, contacting the wellbore wall, and / or forming the wellbore. In some embodiments, the downhole tool 1210 includes an instrument assembly 1219. The instrument assembly may include an engagement element assembly 1220PATENTDocket No. IS24.1698-WO that connects to an electronics housing 1214. In some embodiments, the engagement element assembly 1220 removably connects to the electronics housing 1214. In other words, the engagement element assembly 1220 may not be permanently attached to the downhole tool 1210, for example, by brazing the engagement element assembly 1220 (and / or an engagement element of the engagement element assembly 1220) to the downhole tool 1210 as is conventionally done. In this way, the engagement element assembly 1220 may be selectively connected to and / or removed from the downhole tool 1210. In at least one embodiment, this may facilitate incorporating electronics 1225 and / or a sensor 1223 into the downhole tool 1210. For example, the electronics 1225 may be installed into the electronics housing 1214 and connected to the sensor 1223, after which the engagement element assembly 1220 may be connected to the electronics housing 1214 to complete the installation of the instrument assembly 1219. This may facilitate implementing and / or replacing sensing and / or measurement devices such as those included in the instrument assembly 1219 by significantly simplifying the implementation of such devices in the downhole tool 1210, in at least one embodiment.

[0089] In some embodiments, the engagement element assembly 1220 includes an instrumented engagement element 1221. The instrumented engagement element 1221 may be a planar engagement element, a non-planar (e g., conical, hemispherical, bullet, etc.) engagement element such as a STINGER engagement element, or any other engagement element. The instrumented engagement element 1221 may be configured to engage the borehole, such as a cutting element. For example, the instrumented engagement element 1221 may be at least partially composed of an ultrahard material, such as a polycrystalline diamond compact (PCD). As used herein, the term "ultrahard" is understood to refer to those materials known in the art to have a grain hardness of about 1 ,500 HV (Vickers hardness in kg / mm2) or greater. Such ultrahard materials can include but are not limited to diamond, sapphire, moissanite, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide,PATENTDocket No. IS24.1698-WO aluminum manganese boride, metal borides, boron carbon nitride, PCD (including, e.g., leached metal catalyst PCD, non-metal catalyst PCD, and binderless PCD or nanopolycrystalline diamond (NPD)) and other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1 ,500 HV, as well as combinations of the above materials. In some embodiments, the ultrahard material has a hardness value above 3,000 HV. In other embodiments, the ultrahard material has a hardness value above 4,000 HV. In yet other embodiments, the ultrahard material has a hardness value greater than 80 HRa (Rockwell hardness A). In some examples, the instrumented engagement element 1221 is formed from any other material including metals, metallic alloys, ceramic materials, any other material, and combinations thereof.

[0090] The engagement element assembly 1220 may be connected to the electronics housing 1214 such that the instrumented engagement element 1221 extends at least partially past an outer surface 1270 of the downhole tool 1210. For example, the instrumented engagement element 1221 may extend from the downhole tool 1210 such that the instrumented engagement element 1221 may engage the borehole during drilling (or other downhole operation as the case may be) with the downhole tool 1210. The instrumented engagement element 1221 may extend in a substantially vertical direction (e.g., substantially downhole). This may facilitate an engagement of the instrumented engagement element 1221 with the wellbore bottom hole. In one or more embodiments, the instrumented engagement element 1221 may extend in a direction other than longitudinally and / or axially downward toward the bottom hole, such as in a lateral and / or transverse direction from the bottom hole, outward toward a wellbore wall at one or more angles, and / or upward (e.g., uphole) at one or more angles.

[0091] In some embodiments, the instrument assembly includes a sensor 1223. The sensor 1223 may be an engagement sensor and may take measurements associated with an engagement of the instrumented engagement element 1221 with the borehole. The sensor 1223 may be positioned at a base of the engagement element assembly 1220. The sensor 1223 may be positioned at a base of the instrumented engagement element 1221. For example, a conduitPATENTDocket No. IS24.1698-WO1215 and / or the engagement element assembly 1220 may have one or more structural features for holding and / or supporting the sensor 1223 with respect to the instrumented engagement element 1221. When the instrumented engagement element 1221 engages the borehole, a force exerted on the engagement element 1221 may be transferred through the base of the instrumented engagement element 1221 to the sensor 1223. In some embodiments, the force is an axial force. In this way, the sensor 1223 may take measurements based on a force of the instrumented engagement element 1221 . This may facilitate taking measurements associated with the formation encountered by the instrumented engagement element 1221. For example, materials (e.g., geological materials) in the formation may exhibit varying material properties such as hardness, which may correspond to varying measurements (e.g., forces) sensed by the instrumented engagement element 1221. In another example, features in the formation such as cracks, fractures, veins, voids, or other features may correspond to varying measurements (e.g., forces) sensed by the instrumented engagement element 1221. The sensor 1223 may measure these changes, and in this way, detect the features and / or properties of the formation.

[0092] In this way, the sensor 1223 takes measurements associated with the instrumented engagement element 1221 engaging the borehole. For example, the sensor 1223 may measure strain, stress, displacement, pressure, deformation, deflection, or any other parameter associated with an engagement of the instrumented engagement element 1221 with the borehole. These measurements may facilitate calculating or determining a force on the instrumented engagement element 1221 , or determining any other dynamic related to an engagement of the instrumented engagement element 1221 with the borehole. The sensor 1223 may include a strain gauge (e.g., positioned on a diaphragm), a hall effect sensor, a magnet, a capacitive sensor, a spring sensor, a force transducer, any other sensor, or combinations thereof.

[0093] As mentioned above, the instrument assembly 1219 includes an electronics housing 1214 disposed in the tool body 1211. In some embodiments,PATENTDocket No. IS24.1698-WO the electronics housing includes, or defines a conduit 1215 (e.g., a void, volume, or space) extending into the tool body 1211. The conduit 1215 may have an elongate shape. For example, the conduit 1215 may be substantially cylindrical. The conduit 1215 may be any other shape in accordance with that disclosed herein. The conduit 1215 may extend into the downhole tool 1210 such that a volume is defined within the tool body 1211.

[0094] In some embodiments, the instrument assembly 1219 includes a seal 1222. The seal 1222 may be positioned between the engagement element assembly 1220 and the tool body, for example, to seal the electronics housing 1214. For example, the seal 1222 may be an O-ring seal such as a metal, rubber, or plastic O-ring seal. The seal 1222 may be a gasket seal. The seal 1222 may be a surface seal. For example, the tool body 1211 (e.g., in the conduit 1215) and the engagement element assembly 1220 may each have a sealing surface, and these sealing surfaces may interface in order to form the seal 1222. The seal 1222 may function to seal the inner volume of the electronics housing 1214. For example, the electronics housing 1214 may be sealed to maintain an inner pressure of the electronics housing 1214. The electronics housing 1214 may be sealed to prevent fluid from penetrating into the electronics housing 1214. This may facilitate using and / or protecting electronics within the sealed portion of the electronics housing 1214.

[0095] The volume of the electronics housing 1214 may be of such a size and / or shape so as to house the electronics 1225. For example, the electronics 1225 may include a processor 1225-1 and / or a power supply 1225-2 (e.g., a battery). The electronics 1225 may include one or more additional components such as memory, communication devices, etc. The electronics 1225 may be coupled to and / or associated with the sensor 1223. For example, the power supply 1225-2 may power a function of the sensor 1223. The processor 1225-1 may receive and / or record one or more measurements of the sensor 1223 (e.g., process and / or save to memory). The electronics 1225 may be positioned within the sealed portion of the electronics housing 1214. In some embodiments, the sensor 1223 is positioned in the sealed portion of the electronics housing 1214PATENTDocket No. IS24.1698-WO which may facilitate the sensor 1223 connecting with the electronics 1225 (e.g., through a wired connection). In this way, the electronics housing 1214 may facilitate implementing one or more electronic components into the downhole tool 1210, such as a processor for receiving downhole measurements from the sensor 1223.

[0096] The electronics housing 1214 may have an opening 1216. The opening 1216 may be positioned at an outer surface of the tool body 1211. In some embodiments, the engagement element assembly 1220 connects to the electronics housing 1214 at the opening 1216. For example, a portion of the electronics housing 1214 proximate or adjacent to the opening 1216 may be an engagement element pocket 1217. The engagement element pocket 1217 may be a portion of the electronics housing 1214 that is configured to connect to and / or retain the engagement element assembly 1220. In some embodiments, the engagement element pocket 1217 is separate from the conduit 1215. For example, the engagement element pocket 1217 may be at a distinct location on the downhole tool 1210 from the conduit. In other words, the conduit 1215 and / or electronics housing 1214 may be otherwise positioned within the tool body 1211 (or at another location) than that shown in the illustrative example of FIG. 12-1 , but may nevertheless be electronically coupled to the engagement element assembly 1220. For example, the engagement element pocket 1217 may form or define a separate cavity from that of the conduit 1215 shown in FIG. 12-1 . In this way, the electronics 1225 may be housed at a separate location from the engagement element assembly 1220 and / or the sensor 1223.

[0097] In accordance with at least one embodiment of the present disclosure, the opening 1216 may be at a distal (e.g., downhole) end of the conduit 1215. In other embodiments as described herein, the opening 1216 may be at any other location and / or orientation from the downhole tool 1210. The opening 1216 may be at the outer surface 1270 of the tool body 1211 and may provide access to the electronics housing 1214, for example, for inserting and / or connecting the electronics 1225. The engagement element pocket 1217 may be a portion of the conduit 1215 that is adjacent or proximate the opening 1216. In this way, thePATENTDocket No. IS24.1698-WO engagement element pocket 1217 and the conduit 1215 may be located or formed in the same cavity in the tool body 1211 . This may facilitate and / or simplify installing and / or connecting one or more of the electronics 1225, the engagement element assembly 1220, and the sensor 1223. The opening 1216 (and in this example the engagement element pocket 1217) may be at an outer surface of the tool body 1211 that is a downhole end of the downhole tool 1210. This positioning may facilitate the engagement element assembly 1220 and / or the instrumented engagement element 1221 extending from the outer surface of the tool body 1211.

[0098] In some embodiments, the conduit 1215 includes a sleeve 1215-1. For example, the sleeve 1215-1 may have substantially the same shape as the conduit 1215, and may be hollow, or may have an inner bore. In some embodiments, the sleeve 1215-1 is substantially the shape of a hollow cylinder. The sleeve 1215-1 and / or conduit 1215 may be any other shape suitable for housing the electronics 1225 as described herein. In some embodiments, the sleeve 1215-1 is disposed within and / or connected to the conduit 1215. For example, the sleeve 1215-1 may be brazed into the conduit 1215. The sleeve 1215-1 may be glued, pressed, or threaded into the conduit, or any other form of connection suitable for connecting the sleeve 1215-1 to the conduit 1215. The sleeve 1215-1 may span an entire length of the conduit 1215 such that the sleeve 1215-1 substantially makes up an entirety of the conduit 1215. For example, one or more of the features of the conduit 1215 described herein (e.g. , sealing feature, connection with the engagement element assembly, etc.) may be included as part of the sleeve 1215-1. In some embodiments, the sleeve 1215-1 spans or encompasses only a portion of the conduit 1215. For example, the sleeve 1215- 1 may define or be associated with the sealed portion of the electronics housing 1214. As another example, the sleeve 1215-1 may not include or be associated with the connection of the engagement element assembly 1220 with the electronics housing 1214. The sleeve 1215-1 may be a chassis or frame for housing the electronics 1225, for example, to facilitate inserting, positioning, and / or removing the electronics 1225 with respect to the conduit 1215.PATENTDocket No. IS24.1698-WO

[0099] The sleeve 1215-1 may at least partially define or create the sealed volume of the electronics housing 1214. The sleeve 1215-1 may be configured to withstand the pressure differential between the sealed volume and an exterior of the downhole tool 1210. For example, the sleeve 1215-1 may have a wall thickness that is selected to prevent collapse under the pressure differential. In some embodiments, the seal 1222 may be positioned between the sleeve 1215- 1 and the engagement element assembly 1220 to seal the inner volume of the sleeve 1215-1 .

[0100] In some situations, the material properties of the metal matrix of the tool body 1211 make it difficult to include one or more features of the conduit 1215 discussed herein. The sleeve 1215-1 may be more easily machined or manufactured to facilitate including one or more of these features. In some embodiments, the sleeve 1215-1 is manufactured before it is installed into the downhole tool 1210. In some embodiments, the sleeve 1215-1 is installed into the downhole tool 1210 and after one or more features of the electronics housing 1214 have been machined or manufactured into the sleeve 1215-1. In this way, the electronics housing 1214 may include the sleeve 1215-1 to facilitate including one or more features of the instrument assembly 1219.

[0101] In some embodiments, the conduit 1215 is oriented in a longitudinal direction relative to the downhole tool 1210. For example, a longitudinal axis of the conduit 1215 may be oriented such that it is parallel to a longitudinal axis of the downhole tool 1210. The longitudinal axis of the downhole tool 1210 may be an axis of rotation of the downhole tool 1210. In this way, the conduit 1215 may be oriented substantially vertically, for example, during downhole drilling activities of the downhole tool 1210. This may facilitate the engagement element assembly 1220 and / or the engagement element 1221 extending substantially vertically (e.g., downhole) from the downhole tool 1210. However, as discussed herein, other orientations of the engagement element assembly 1220 and / or the engagement element 1221 are contemplated which may not necessarily be in an axial / longitudinal direction.PATENTDocket No. IS24.1698-WO

[0102] While one or more components of the instrument assembly 1219 are shown in FIG. 12-1 as being substantially vertical, or located substantially in a longitudinal plane of the downhole tool 1210, it should be understood that one or more of the components of the instrument assembly 1219 may be oriented, for example, at an angle relative to the longitudinal plane of the downhole tool 1210. Indeed, one or more of the components of the instrument assembly 1219 may be included in the downhole tool 1210 at any orientation consistent with drilling the borehole and / or taking measurements as described herein. For example, one or more of the conduit 1215, the engagement element assembly 1220, or the engagement element pocket 1217 may be oriented horizontally. In another example, one or more of the conduit 1215, the engagement element assembly 1220, or the engagement element pocket 1217 may be oriented transverse and / or at any angle relative to the longitudinal plane. This may facilitate implementing the instrument assembly 1219 in a variety of downhole tools.

[0103] FIGS. 12-2 and 12-3 are schematic views illustrating an engagement of the instrumented engagement element 1221 and a lead engagement element 1275, according to at least one embodiment of the present disclosure. In some embodiments, the electronics housing 1214 (more specifically, the engagement element pocket 1217) is positioned in the tool body 1211 such that the engagement element assembly 1220 and / or the instrumented engagement element 1221 extends from the downhole tool 1210 adjacent to and / or behind the lead engagement element 1275 (such as one or more of the engagement elements 213 of FIG. 2) of the downhole tool 1210. For example, during drilling activities, the downhole tool 1210 may rotate such that the engagement elements follow a rotational path. The instrumented engagement element 1221 may be positioned such that it follows a rotational path that is the same as one of the engagement elements of the downhole tool 1210. In other words, the rotational path of the instrumented engagement element 1221 may be a rotational path that has a radius that is substantially the same as a rotational path of another engagement element of the downhole tool 1210. In this way the instrumented engagement element 1221 may follow the rotational path of a lead engagementPATENTDocket No. IS24.1698-WO element 1275, such as a lead cutting element. While FIG. 12-2 illustrates the lead engagement element 1275 as an element of the downhole tool 1210 that is adjacent to the instrumented engagement element 1221 as well as immediately and / or rotationally ahead of the instrumented engagement element 1221 , it should be understood that the lead engagement element 1275 may be positioned at any location of the downhole tool 1210 (as discussed below) and / or may be any of the engagement elements of the downhole tool 1210.

[0104] The instrumented engagement element 1221 may follow the rotational path of the lead engagement element 1275 by being positioned an offset angle from the lead engagement element 1275. For example, the offset angle may be an angle measured about the axis of rotation of the downhole tool 1210 (e.g., measured in the direction and plane of the rotation of the downhole tool 1210) between the lead engagement element 1275 and the instrumented engagement element 1221. In this way the offset angle may correspond to an angle between a point of engagement of the lead engagement element 1275 with the earth formation and a point of engagement of the instrumented engagement element 1221 with the earth formation.

[0105] In some embodiments, the instrumented engagement element 1221 is positioned substantially adjacent or proximate the lead engagement element 1275. For example, the offset angle may be small, such as 1 °, and the instrumented engagement element 1221 may be positioned immediately (rotationally) behind the lead engagement element 1275. In another example, the offset angle may be large, such as 359°. In some embodiments, the adjacent or proximate positioning of the instrumented engagement element 1221 with the lead engagement element 1275 may correspond with the instrumented engagement element 1221 and the lead engagement element 1275 being positioned in the same blade of the downhole tool 1210.

[0106] In some embodiments, the instrumented engagement element 1221 is not positioned adjacent or proximate the lead engagement element 1275. For example, the offset angle may be any angle between 1 ° and 359°, such as 75°, 90°, 180°, 270°, or any other angle. In some embodiments, this corresponds withPATENTDocket No. IS24.1698-WO the instrumented engagement element 1221 being positioned in the same blade of the downhole tool 1210 as the lead engagement element 1275. In some embodiments, this corresponds with the instrumented engagement element 71 being positioned in a different blade (or not in a blade) of the lead engagement element 1275. In this way, the instrumented engagement element 1221 may be positioned at any offset angle from the lead engagement element 1275 such that the instrumented engagement element 1221 follows along substantially the same rotational path as the lead engagement element 1275. In some embodiments, the instrumented engagement element 1221 and / or the lead engagement element 1275 are each positioned in a blade of the downhole tool 1210. In some embodiments, the instrumented engagement element 1221 and / or the lead engagement element 1275 is not positioned in a blade of the downhole tool 1210.

[0107] It should be understood that the positioning of the instrumented engagement element 1221 and the lead engagement element 1275 in FIG. 12-2 as being adjacent, proximate, or substantially side-by-side is for illustrative purposes only. The positioning and / or spacing of the instrumented engagement element 1221 and the lead engagement element 1275 may correspond with any offset angle as described above. In this way, FIG. 12-2 illustrates the instrumented engagement element 1221 and the lead engagement element 1275 with respect to a rotation 1280 of the downhole tool 1210, and not necessarily with respect to an actual or physical position on the downhole tool 1210. Similarly, it should be understood that FIG. 12-3 does not necessarily illustrate the instrumented engagement element 1221 and the lead engagement element 1275 with respect to, for example, a positioning of each in the downhole tool 1210. Rather, FIG. 12-3 is illustrative of the engagement of the instrumented engagement element 1221 and the lead engagement element 1275 with the earth formation 1201 .

[0108] With reference now to FIG. 12-3, as discussed herein, the instrumented engagement element 1221 engages an earth formation 1201 in order to take one or more corresponding measurements. In some embodiments, the instrumented engagement element 1221 engages the earth formation 1201PATENTDocket No. IS24.1698-WO by contacting and / or extending into the earth formation 1201. This may be characterized by an engagement distance 1273. For example, the lead engagement element 1275 may engage the earth formation and may cut and / or remove a lead groove 1276. The instrumented engagement element 1221 may extend into the formation 1201 at or in the lead groove 1276 (e.g., as shown in FIG. 12-3) and may produce a trailing groove 1277. The engagement distance 1273 may be the difference between the furthest extent (e.g., downhole) of the lead groove 1276 and the trailing groove 1277. In this way, the engagement distance 1273 may correspond to a distance or the furthest extent that the instrumented engagement element 1221 extends into the formation 1201 upon engagement.

[0109] In some embodiments, the engagement distance 1273 may be 1 mm. The engagement distance 1273 may be in a range having an upper value, a lower value, or upper and lower values including any of 0.1 mm, 0.2 mm, 0.3 mm, 0.4 mm, 0.5 mm, 0.6 mm, 0.7 mm, 0.8 mm, 0.9 mm, 1 mm, 2 mm, 3 mm, 4 mm, 5 mm, 10 mm, or any value therebetween. For example, the engagement distance 1273 may be less than 10 mm. In another example, the engagement distance may be greater than 0.1 mm. in yet another example, the engagement distance 1273 may be between 0.1 mm and 10 mm. In some embodiments, the engagement distance 1273 in particular is less than 1 mm to ensure that the instrumented engagement element 1221 experiences a significant enough engagement with the formation 1201 to accurately take one or more measurements while minimizing noise in the measurements. For example, it may be understood that the instrumented engagement element 1221 may not be implemented to necessarily cut, degrade, and / or remove the formation, but rather, may be understood as cutting the formation in a minor capacity, such as scratching, feeling, or otherwise measuring the surface of the formation for measurement purposes.

[0110] Turning back to FIG. 12-2, the instrumented engagement element 1221 may extend axially (e.g., downhole) a sensor axial distance 1271. The lead engagement element 1275 may extend axially (e.g., downhole) a cutting axialPATENTDocket No. IS24.1698-WO distance 1272. The sensor axial distance 1271 and the cutting axial distance 1272 may each be a distance measured between a point of engagement of the respective engagement element with the formation 1201 and a reference point 1274, such as at a base of a blade of the downhole tool 1210. The reference point 1274 may be any reference point for measuring the sensor axial distance 1271 and the cutting axial distance 1272 relative to the engagement of the instrumented engagement element 1221 and the lead engagement element 1275 with the formation 1201. For example, the instrumented engagement element 1221 may be implemented in a downhole tool that engages the wall of a borehole (e.g., rather than the bottom of the borehole), and the sensor axial distance 1271 and the cutting axial distance 1272 may be measured from the reference point 1274 radially outward to an engagement of the instrumented engagement element 1221 and the lead engagement element 1275 with the borehole wall, respectively. In this way, the instrumented engagement element 1221 may follow the same rotational path as the lead engagement element 1275 (e.g., rotationally behind), while still engaging the borehole within a groove or channel cut by the lead engagement element 1275. The sensor axial distance 1271 and / or the cutting axial distance 1272 may be determined or configured such that the instrumented engagement element 1221 engages the formation 1201 with the engagement distance 1273, in accordance with that discussed above.

[0111] In some embodiments, the sensor axial distance 1271 may be greater than the cutting axial distance 1272. In other words, the instrumented engagement element 1221 may axially extend (e.g., downhole) further than the lead engagement element 1275. This may correspond with the instrumented engagement element 1221 being positioned with a smaller offset angle, such as less than 180° (e.g., in accordance with the downhole tool 1210 not having progressed significantly through the formation from the time the lead engagement element 1275 cuts the formation to when the instrumented engagement element 1221 engages the formation). In this way, the instrumented engagement element 1221 may extend axially and engage the earth formation after the lead engagement element 1275 has cut the lead groove 1276.PATENTDocket No. IS24.1698-WO

[0112] In some embodiments, the sensor axial distance 1271 may be substantially the same, or even less than the cutting axial distance 1272. This may correspond with the instrumented engagement element 1221 being positioned with a larger offset angle, such as greater than 180°. For example, while the earth formation has been illustrated in some of the figures herein as having a face that is substantially horizontal or substantially normal to the downhole tool 1210 and / or the various engaging elements of the downhole tool 1210, due to the rotation of the downhole tool 1210, as well as the downhole tool advancing downhole through the formation 1201 as it rotates, in some situations, the face of the formation 1201 may have a helical or spiral nature such that the face of the formation may be represented as slanted or non-normal with respect to downhole tool 1210. In this way, the instrumented engagement element 1221 may extend axially and engage the earth formation after the lead engagement element 1275 has cut the lead groove 1276, even though the instrumented engagement element 1221 may not extend axially further than the lead engagement element 1275. In this way, the configuration of the sensor axial distance 1271 and / or the cutting axial distance 1272 may be based on or dependent on the offset angle as discussed above.

[0113] In some embodiments, the one or more sensors are connected to one or more other components of the BHA. In some embodiments, the one or more sensors include a transmitter to transmit sensor data. For example, the transmitter may transmit sensor data to other components of the BHA. In another example, the transmitter may transmit sensor data to the surface.

[0114] As discussed herein, the instrumented engagement element 1221 may follow the same (or similar) rotational path as the lead cutting element 1275. This may correspond with the instrumented engagement element 1221 engaging the formation 1201 within the lead groove 1276 cut or removed by the lead engagement element 1275. The instrumented engagement element 1221 may be positioned and / or oriented such that the width of the trailing groove 1277 never breaches the width of the lead groove 1276 as the instrumented engagement element 1221 follows rotationally behind the lead engagement element 1275. ForPATENTDocket No. IS24.1698-WO example, the instrumented engagement element 1221 may engage the formation 1201 at a center of the lead groove 1276. In another example, the instrumented engagement element 1221 may engage the formation 1201 at another location of the lead groove 1276 that is not centered. The instrumented engagement element 1221 may engage the formation 1201 within the lead groove 1276 at an angle (e.g., relative to a longitudinal axis of the instrumented engagement element 1221 ), such as a normal or perpendicular angle, or any other angle.

[0115] The instrumented engagement element 1221 may follow behind the lead engagement element 1275 in this way to facilitate a measurement and / or calculation of the force on the instrumented engagement element 1221 , or any other parameters associated with an engagement of the instrumented engagement element 1221 with the borehole. For example, the instrumented engagement element 1221 may engage the formation 1201 in substantially the same way regardless of a depth of cut and / or a rate of penetration of the downhole tool. For a given geometry of rock or material being removed, the force acting on an engagement element (e.g., a cutter) may be proportional to the area of rock being cut or removed. The instrumented engagement element 1221 may engage the formation 1201 within the lead groove 1276 in order to maintain the geometry (more specifically, the area) of rock being removed by the instrumented engagement element 1221 substantially uniform. This may result in a substantially uniform engagement of the instrumented engagement element 1221 with the formation 1201 at all depths of cut and / or rates of penetration of the lead engagement element 1275 and / or a downhole tool implementing the lead engagement element 1275 and the instrumented engagement element 1221. In contrast, if the instrumented engagement element 1221 were to not follow directly behind the lead engagement element 1275 and / or engage the formation 1201 within the lead groove 1276, the area of rock with which the instrumented engagement element 1221 engages (e.g., removes) may vary based on the depth of cut of the lead engagement element 1275, significantly complicating the calculation of the force (or other parameter) on the instrumented engagement element 1221. In this manner, changes in the measured force (orPATENTDocket No. IS24.1698-WO other parameter) on the instrumented engagement element 1221 may be attributable to changes or features in the formation 1201 (e.g., changes in material, changes in hardness, veins or cracks in the formation, etc.), rather than changes in the geometry of the cut of the instrumented engagement element 1221 (e.g., due to different depth of cut of the lead cutting element).

[0116] FIG. 13 is a side cutaway view of an instrumentation housing or an engagement element housing 1324, according to at least one embodiment of the present disclosure. The engagement element housing 1324 includes a housing body 1330 configured to connect to an engagement element pocket 1317 of a downhole tool. The housing body 1330 may have a distal end 1328 and a proximal end 1329. The proximal end 1329 may insert into and / or engage with the engagement element pocket 1317. The housing body 1330 may connect to the engagement element pocket 1317 such that the distal end 1328 is positioned at an outer surface of the downhole tool. The distal end 1328 positioned on the outer surface of the downhole tool may facilitate a measurement by one or more sensors associated with the engagement element housing 1324.

[0117] In some embodiments, the housing body 1330 removably connects to the engagement element pocket 1317. For example, the housing body 1330 may include threads 1326. The threads 1326 may be exterior threads on an outer surface of the housing body 1330. The threads 1326 may thread or screw into interior threads on an inner surface of the engagement element pocket 1317. In another example, the housing body 1330 may removably connect to the engagement element pocket 1317 with a circlip or other removable fastening means. The housing body 1330 may include a tightener 1334. The tightener 1334 may facilitate securing and / or tightening the connection of the housing body 1330 to the engagement element pocket 1317. For example, the tightener 1334 may be a hex head tightener. The tightener 1334 may be a Phillips, flat, star, TORX, TORX pin, square, spline, slotted, any other tightener, or any other suitable means for tightening the connection of the housing body 1330 to the engagement element pocket 1317. The housing body 1330 may include a flange 1335. The flange 1335 may seat against a surface of the engagement element pocket 1317,PATENTDocket No. IS24.1698-WO for example, to tighten the housing body 1330 in the engagement element pocket 1317.

[0118] In some embodiments, the engagement element housing 1324 has a seal 1322. The seal 1322 may be positioned on an exterior of the housing body 1330 such that the seal 1322 is positioned between the housing body 1330 and the engagement element pocket 1317 (e.g., when the engagement element housing 1324 is connected to the engagement element pocket 1317). The seal 1322 may help to seal a portion of the engagement element pocket 1317 (and / or an electronics housing conduit). For example, the seal 1322 may seal a pressure in the engagement element pocket 1317 and / or may prevent fluid or other matter from penetrating into the engagement element pocket 1317. In some embodiments, such as that shown, the seal 1322 is an O-ring seal. The O-ring may seat in a groove or channel on an exterior of the housing body 1330. In some embodiments, the O-ring seats in a groove or channel on the interior of the engagement element pocket 1317. In this way, the O-ring may be positioned between the housing body 1330 and the engagement element pocket 1317 to seal the engagement element pocket 1317. In some embodiments, the seal 1322 is a gasket. For example, the gasket may be disposed on the flange 1335. In some embodiments, the gasket is disposed on a mating surface of the engagement element pocket 1317. The gasket may be positioned between the flange 1335 and a surface of the engagement element pocket 1317 to seal the engagement element pocket 1317. In some embodiments, the seal 1322 is created without a distinct, or dedicated sealing element. For example, mating surfaces of the housing body 1330 and the engagement element pocket 1317 may interface to form the seal 1322 (e.g., the flange 1335 and a surface of the engagement element pocket 1317). In this way, the engagement element housing 1324 may form a removable connection with the downhole tool, and may also seal, for example, an electronics housing conduit of the bit.

[0119] In some embodiments, the engagement element housing 1324 includes a measurement pocket 1331. The measurement pocket 1331 may be formed in the housing body 1330. The measurement pocket 1331 may define aPATENTDocket No. IS24.1698-WO cavity in the housing body 1330. For example, the measurement pocket 1331 may have a pocket base 1332 and a pocket opening 1333. The pocket base 1332 and pocket opening 1333 may be on opposite ends of the measurement pocket 1331. In some embodiments, the pocket opening 1333 is on the distal end 1328 of the housing body 1330. In some embodiments, the pocket base 1332 is on the proximal end 1329 of the housing body 1330. The measurement pocket 1331 may be configured to house one or more sensors for taking one or more downhole measurements. For example, the pocket base 1332 may include or may define a diaphragm 1336. A strain gauge may be connected to the pocket base 1332 at the diaphragm 1336. The strain gauge and / or the diaphragm 1336 may facilitate measuring, for example, a force and / or pressure associated with an operation of the bit. For example, the diaphragm 1336 may experience or exhibit a strain due to a pressure or a force acting on the diaphragm 1336. A strain gauge may measure the corresponding strain. In this way, the downhole measurement may include force measurements and / or pressure measurements. In other examples, other sensors, such as a temperature sensor, pressure sensor, or other sensor(s) may be positioned in the measurement pocket for measuring a temperature (e.g., taking temperature measurements) associated with the bit. In this way, the engagement element pocket 1317 may facilitate including instrumentation in a bit for taking one or more downhole measurements including force measurements, pressure measurements, and temperature measurements, among others.

[0120] The engagement element housing 1324 may be at least partially made of one or more wear-resistant materials. For example, the engagement element housing 1324 may include tungsten carbide, a polycrystalline diamond compact (PDC), high-speed steel, ceramics, nickel alloys, any other suitable wear resistance material, and combinations thereof. In some embodiments, one or more portions of the engagement element housing 1324 are made of or coated with a wear-resistant material. The wear resistant properties of the engagement element housing 1324 may facilitate exposing at least a portion of the engagement element housing 1324 to the conditions of the borehole (e.g., at anPATENTDocket No. IS24.1698-WO outer surface of the bit). In this way, the engagement element housing 1324 may withstand the harsh downhole drilling environment in order that the engagement element housing 1324 may be incorporated in any number of downhole locations and with any number of downhole tools.

[0121] FIG. 14 is a side cutaway view of an engagement element housing 1424, according to at least one embodiment of the present disclosure. In some embodiments, an instrumented engagement element 1421 is disposed or retained in an engagement element housing 1424. The engagement element housing 1424 may include a housing body 1430 having a distal end 1428 and a proximal end 1429. The instrumented engagement element 1421 may be any type of engagement element, such as a planar engagement element, a non- planar (e.g., conical, hemispherical, bullet, etc.) engagement element such as a STINGER engagement element, a rolling engagement element, or any other engagement element. The instrumented engagement element 1421 may be a cutting element, or may be another element that is not configured to or not primarily intended to cut, such as a steering or stabilizing pad. The instrumented engagement element 1421 may be positioned in a measurement pocket 1431. For example, the instrumented engagement element 1421 may be inserted into, at least partially, a cavity defined by the measurement pocket 1431. The instrumented engagement element 1421 may extend out of a pocket opening 1433. The pocket opening 1433 may be positioned on the distal end 1428 of the housing body 1430 such that the instrumented engagement element 1421 extends outward from an outer surface of a downhole tool (e.g., a bit). In this way, the instrumented engagement element 1421 may be configured to extend from the bit in order to engage the borehole.

[0122] The instrumented engagement element 1421 may be connected to or retained in the measurement pocket 1431. For example, the instrumented engagement element 1421 and / or the measurement pocket 1431 may each have a groove or channel. A retainer (e.g., a clip) may be positioned in the corresponding grooves, for example, upon installation of the instrumented engagement element 1421 to retain the instrumented engagement element 1421PATENTDocket No. IS24.1698-WO in the measurement pocket 1431. The instrumented engagement element 1421 may be connected to or retained in the measurement pocket 1431 by any other suitable means. For example, the instrumented engagement element 1421 may be glued, brazed, pressed, threaded, or fastened in the measurement pocket 1431 (e.g., connected to the diaphragm 1436). In this way, the instrumented engagement element 1421 may be removably connected to the housing body 1430.

[0123] The instrumented engagement element 1421 may be retained in the measurement pocket 1431 such that the instrumented engagement element 1421 is axially fixed. For example, the instrumented engagement element 1421 may be fixed such that the instrumented engagement element 1421 may not move substantially relative to its longitudinal axis during engagement with the borehole. This may facilitate transferring a force through the instrumented engagement element 1421 and to the sensor 1423, as discussed herein. The instrumented engagement element 1421 may not move axially in a substantial manner, but for small deflections and / or deformations of the diaphragm 1436. In some embodiments, the instrumented engagement element 1421 is axially fixed but may be free to spin or rotate within the measurement pocket 1431 . This may facilitate continually exposing different portions of a revolving cutting face in order to reduce wear of the instrumented engagement element 1421.

[0124] In some embodiments, a pocket base 1432 of the measurement pocket 1431 includes or defines a diaphragm 1436. The diaphragm 1436 may be positioned at a base of the instrumented engagement element 1421. As the instrumented engagement element 1421 engages the borehole, a force (e.g., an axial force) may be transmitted through the instrumented engagement element 1421 to the diaphragm 1436. For example, in some embodiments, the instrumented engagement element 1421 is retained in the measurement pocket 1431 such that forces exerted on the instrumented engagement element 1421 are not distributed throughout the housing body 1430. Rather, in some embodiments, the instrumented engagement element 1421 is retained in the measurement pocket such that forces exerted on the instrumented engagementPATENTDocket No. IS24.1698-WO element 1421 are directed and / or transmitted through a base of the instrumented engagement element 1421 to the diaphragm 1436. The diaphragm 1436 may experience or exhibit a strain corresponding to at least a portion of the force (e.g., the axial force).

[0125] The strain of the diaphragm 1436 may be due to a material compliance of the diaphragm 1436. In some embodiments, the diaphragm 1436 has a diaphragm thickness of 10 mm. In some embodiments, the diaphragm thickness is in a range having an upper value, a lower value, or upper and lower values including any of 1 mm, 2 mm, 3 mm, 4 mm, 5 mm, 6 mm, 7 mm, 8 mm, 9 mm, 10 mm, 15 mm, 20 mm, or any value therebetween. For example, the diaphragm thickness may be less than 20 mm. In another example, the diaphragm thickness may be greater than 1 mm. In yet another example, the diaphragm thickness may be between 1 mm and 20 mm. In some embodiments, the diaphragm thickness may in particular be between 3 mm and 6 mm to ensure that the diaphragm 1436 exhibits a measurable level of strain, while preventing plastic deformation of the diaphragm 1436 due to the axial forces.

[0126] In some embodiments, a sensor 1423 is housed by the measurement pocket 1431. For example, a strain gauge 1437 may be disposed on the diaphragm 1436. The strain gauge 1437 may measure a strain exhibited by the diaphragm 1436, for example, based on forces exerted on the instrumented engagement element 1421. In this way, the instrumented engagement element 1421 , the diaphragm 1436, and the strain gauge 1437 may form the sensor 1423 (e.g., an engagement sensor). In some embodiments, the strain gauge 1437 is disposed on an opposite side of the diaphragm 1436 from the instrumented engagement element 1421. In this way, the strain gauge 1437 may be positioned in the sealed portion of an engagement element pocket (and / or an electronics housing conduit). This may facilitate incorporating the strain gauge 1437 and / or associated electronics in the bit as no wire path is required to pass through from the sealed portion of the engagement element pocket to an unsealed portion of the engagement element pocket.PATENTDocket No. IS24.1698-WO

[0127] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0128] Additionally, 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. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” 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.

[0129] 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, andPATENTDocket No. IS24.1698-WO 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.

[0130] 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. Additionally, as used herein, the term “and / or” includes any and all combinations of one or more of the associated listed items.

[0131] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

[0132] Embodiments of systems and methods related to controlling downhole tools are described herein according to the clauses below:PATENTDocket No. IS24.1698-WO

[0133] Clause 1. A method of controlling a downhole tool, the method comprising: obtaining one or more engagement measurements including at least one engagement measurement of a surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; obtaining accelerometer data from an accelerometer that is concurrent with the one or more engagement measurements; correlating data variations in the one or more engagement measurements and in the accelerometer data, wherein the data variations are values outside of a threshold value; identifying at least one drilling dysfunction based on correlated accelerometer data and engagement measurements; and changing at least one wellbore parameter based on the correlated accelerometer data and engagement measurements.

[0134] Clause 2. The method of clause 1 , wherein obtaining the one or more engagement measurements includes: engaging a formation at a downhole surface of the wellbore with a downhole tool positioned in the wellbore; engaging the downhole surface with an instrumented engagement element positioned on the downhole tool; and based on engaging the downhole surface with the instrumented engagement element, taking the one or more engagement measurements with the engagement sensor of the instrumented engagement element.

[0135] Clause 3. The method of clause 1 or 2, further comprising logging the one or more engagement measurements with a processor positioned in the electronics housing.

[0136] Clause 4. The method of any preceding clause, wherein the wellbore parameter is a drilling parameter.

[0137] Clause 5. The method of any preceding clause, wherein the wellbore parameter is well design parameter.

[0138] Clause 6. The method of any preceding clause, wherein the one or more engagement measurements and the accelerometer data are collected in a same measurement space.PATENTDocket No. IS24.1698-WO

[0139] Clause 7. The method of any preceding clause, wherein the accelerometer data includes a magnitude in a radial direction of a rotational axis of the downhole tool.

[0140] Clause 8. The method of any preceding clause, wherein the accelerometer data includes a magnitude in an axial direction of a rotational axis of the downhole tool.

[0141] Clause 9. The method of any preceding clause, wherein the accelerometer data includes a magnitude in a rotational direction of a rotational axis of the downhole tool.

[0142] Clause 10. A method of controlling a downhole tool, the method comprising: obtaining one or more engagement measurements including at least one downhole engagement measurement of a downhole surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; converting the one or more engagement measurements into a depth log or time log; identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log or time log; training a machine learning (ML) model with the identified drilling dysfunction in the depth log to create a trained ML model; providing a second depth log or time log to the trained ML model; identifying at least one drilling dysfunction in the second depth log or time log; and changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log.

[0143] Clause 11. The method of clause 10, wherein identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log includes identifying at least one drilling dysfunction in a correlated dataset of a different type of measurement.

[0144] Clause 12. The method of clause 11 , wherein the correlated dataset of a different type of measurement includes accelerometer data.

[0145] Clause 13. The method of clause 11 , wherein the correlated dataset of a different type of measurement includes weight-on-bit (WOB).PATENTDocket No. IS24.1698-WO

[0146] Clause 14. The method of any of clauses 10-13, wherein identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log includes identifying a trigger of the at least one drilling dysfunction.

[0147] Clause 15. The method of any of clauses 10-14, wherein training the ML model includes supervised training.

[0148] Clause 16. The method of any of clauses 10-15, wherein training the ML model includes semi-supervised training.

[0149] Clause 17. The method of any of clauses 10-16, wherein training the ML model includes unsupervised training.

[0150] Clause 18. The method of any of clauses 10-17, wherein identifying at least one drilling dysfunction in the second depth log or time log includes identifying a trigger of the at least one drilling dysfunction.

[0151] Clause 19. The method of any of clauses 10-18, wherein changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log includes changing a WOB.

[0152] Clause 20. The method of any of clauses 10-19, wherein changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log includes changing an RPM.

Claims

PATENTDocket No. IS24.1698-WOCLAIMSWhat is claimed is:1 . A method of controlling a downhole tool, the method comprising: obtaining one or more engagement measurements including at least one engagement measurement of a surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; obtaining accelerometer data from an accelerometer that is concurrent with the one or more engagement measurements; correlating data variations in the one or more engagement measurements and in the accelerometer data, wherein the data variations are values outside of a threshold value; identifying at least one drilling dysfunction based on correlated accelerometer data and engagement measurements; and changing at least one wellbore parameter based on the correlated accelerometer data and engagement measurements.

2. The method of claim 1 , wherein obtaining the one or more engagement measurements includes: engaging a formation at a downhole surface of the wellbore with a downhole tool positioned in the wellbore; engaging the downhole surface with an instrumented engagement element positioned on the downhole tool; and based on engaging the downhole surface with the instrumented engagement element, taking the one or more engagement measurements with the engagement sensor of the instrumented engagement element.

3. The method of claim 1 , further comprising logging the one or more engagement measurements with a processor positioned in the electronics housing.PATENTDocket No. IS24.1698-WO4. The method of claim 1 , wherein the at least one wellbore parameter is a drilling parameter.

5. The method of claim 1 , wherein the at least one wellbore parameter is well design parameter.

6. The method of claim 1 , wherein the one or more engagement measurements and the accelerometer data are collected in a same measurement space.

7. The method of claim 1 , wherein the accelerometer data includes a magnitude in a radial direction of a rotational axis of the downhole tool.

8. The method of claim 1 , wherein the accelerometer data includes a magnitude in an axial direction of a rotational axis of the downhole tool.

9. The method of claim 1 , wherein the accelerometer data includes a magnitude in a rotational direction of a rotational axis of the downhole tool.

10. A method of controlling a downhole tool, the method comprising: obtaining one or more engagement measurements including at least one downhole engagement measurement of a downhole surface in a wellbore from an engagement sensor, wherein the engagement sensor is housed in an electronics housing positioned within a body of a downhole tool; converting the one or more engagement measurements into a depth log or time log; identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log or time log; training a machine learning (ML) model with the identified at least one drilling dysfunction in the depth log to create a trained ML model;PATENTDocket No. IS24.1698-WO providing a second depth log or time log to the trained ML model; identifying at least one drilling dysfunction in the second depth log or time log; and changing at least one wellbore parameter based on the identified at least one drilling dysfunction in the second depth log or time log.

11. The method of claim 10, wherein identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log includes identifying at least one drilling dysfunction in a correlated dataset of a different type of measurement.

12. The method of claim 11 , wherein the correlated dataset of a different type of measurement includes accelerometer data.

13. The method of claim 11 , wherein the correlated dataset of a different type of measurement includes weight-on-bit (WOB).

14. The method of claim 10, wherein identifying at least one drilling dysfunction in the one or more engagement measurements of the depth log includes identifying a trigger of the at least one drilling dysfunction.

15. The method of claim 10, wherein training the ML model includes supervised training.

16. The method of claim 10, wherein training the ML model includes semisupervised training.

17. The method of claim 10, wherein training the ML model includes unsupervised training.PATENTDocket No. IS24.1698-WO18. The method of claim 10, wherein identifying at least one drilling dysfunction in the second depth log or time log includes identifying a trigger of the at least one drilling dysfunction.

19. The method of claim 10, wherein changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log includes changing a WOB.

20. The method of claim 10, wherein changing at least one wellbore parameter based on the at least one drilling dysfunction in the second depth log or time log includes changing a rotations per minute (RPM).

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