Instrumented engagement element in roller cone bit

Abstract

A downhole tool (410) for forming a wellbore in a formation includes a rotary engagement component (420) including one or more penetrating elements (424) for forming a plurality of penetrations in the formation defining a rotational sweep (430) of the rotary engagement component, and a cutting structure (412) formed on a body of the downhole tool having one or more cutting elements (423) positioned thereon for degrading the formation. The downhole tool includes an instrumented engagement element (421) positioned on the cutting structure and positioned to engage the formation at an engagement radius that is outside of the rotational sweep of the rotary engagement component, and an engagement sensor connected to electronics for taking one or more measurements associated with the instrumented engagement element engaging the formation.

Description

PATENTDocket No. IS24.1679-WO-PCTINSTRUMENTED ENGAGEMENT ELEMENT IN ROLLER CONE BITCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of United States Provisional Patent Application No. 63 / 723,054, 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 embodiments, a downhole tool for forming a wellbore in a formation includes a rotary engagement component including one or more penetrating elements for forming a plurality of penetrations in the formation defining a rotational sweep of the rotary engagement component, and a cutting structure formed on a body of the downhole tool having one or more cutting elements positioned thereon for degrading the formation. The downhole tool includes an instrumented engagement element positioned on the cutting structure and positioned to engage the formation at an engagement radius that is outside of the rotational sweep of the rotary engagement component, and anPATENTDocket No. IS24.1679-WO-PCT engagement sensor connected to electronics for taking one or more measurements associated with the instrumented engagement element engaging the formation.

[0005] In some embodiments, a method of taking downhole measurements includes engaging a formation with a downhole tool including rotating the downhole tool to form a wellbore in the formation, and engaging the formation with a rotary engagement component of the downhole tool having one or more penetrating elements to form a plurality of penetrations in the formation defining a rotational sweep of the rotary engagement component. The method further includes engaging the formation with an instrumented engagement element positioned on a body of the downhole tool at an engagement radius that is outside of the rotational sweep, and taking one or more measurements with an engagement sensor of the instrumented engagement element based on the instrumented engagement element engaging the formation.

[0006] In some embodiments, a downhole tool for forming a wellbore in a formation includes a rotary engagement component including one or more penetrating elements for forming a plurality of penetrations in the formation at a penetration depth, a cutting structure formed on a body of the downhole tool having one or more cutting elements positioned thereon for degrading the formation, and a lead cutting element of the one or more cutting elements positioned on the cutting structure and positioned to degrade the formation along a rotational path of the lead cutting element and at a depth of cut that is greater than the penetration depth. The downhole tool includes an instrumented engagement element positioned on the cutting structure and positioned to engage the formation within the rotational path of the lead cutting element at an engagement depth that is greater than the depth of cut, and an engagement sensor connected to electronics for taking one or more measurements associated with the instrumented engagement element engaging the formation.

[0007] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intendedPATENTDocket No. IS24.1679-WO-PCT 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.

[0008] 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.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] 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:

[0010] FIG. 1 shows one embodiment of a drilling system for drilling an earth formation, according to at least one embodiment of the present disclosure;

[0011] 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;

[0012] 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;PATENTDocket No. IS24.1679-WO-PCT

[0013] FIG. 4-1 is a top view and FIG. 4-2 is a side cross-sectional view of a downhole tool having an instrumented engagement element implemented thereon, according to at least one embodiment of the present disclosure;

[0014] FIG. 4-3 is a top view and FIG. 4-4 is a side cross-sectional view of the downhole tool of FIGS. 4-1 and 4-2 as illustrated with respect to a rotational sweep of a rotary engagement component, according to at least one embodiment of the present disclosure;

[0015] FIG. 5-1 is a top view and FIG. 5-2 is a side cross-sectional view of a downhole tool having an instrumented engagement element positioned thereon, according to at least one embodiment of the present disclosure;

[0016] FIG. 5-3 is a schematic diagram illustrating the engagement of various elements of a downhole tool with a formation, according to at least one embodiment of the present disclosure;

[0017] FIG. 6-1 illustrates a flow diagram for a method or a series of acts for taking downhole measurements as described herein, according to at least one embodiment of the present disclosure;

[0018] FIG. 6-2 illustrates a flow diagram for a method or a series of acts for taking downhole measurements as described herein, according to at least one embodiment of the present disclosure;

[0019] FIG. 7 illustrates certain components that may be included within a computing system;

[0020] FIG. 8-1 is a perspective cutaway view of a downhole tool, according to at least one embodiment of the present disclosure;

[0021] FIGS. 8-2 and 8-3 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. 9 is a side cutaway view of an engagement element housing, according to at least one embodiment of the present disclosure; andPATENTDocket No. IS24.1679-WO-PCT

[0023] FIG. 10 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 wellbore. An instrumented engagement element may be implemented in conjunction with one or more downhole tools and may engage the wellbore. 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 the engagement element with the wellbore. 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 wellbore, in at least one embodiment described herein.

[0025] In some cases, the instrumented engagement element is implemented on a downhole tool having one or more rotary engagement components such as roller cones. For example, the downhole tool may be a hybrid fixed-cutter rollercone drill bit. The rotary engagement components may penetrate and / or gouge the formation to facilitate forming a wellbore, for example, in harder formations. The penetrations formed by the rotary engagement components may be detrimental to the measurement data collected via the instrumented engagement element. For example, by engaging and encountering the penetrations, the measurements of the instrumented engagement element may be sensitive to or be dominated by the penetrations rather than formation features in the formation.

[0026] In some embodiments, the instrumented engagement element is positioned at an engagement radius on the downhole tool that is outside of a rotational sweep of the rotary engagement components. For example, the penetrations formed in the formation by the rotary engagement component may form or define a rotational sweep within which the penetrations may be formed. By situating the instrumented engagement element such that it engages thePATENTDocket No. IS24.1679-WO-PCT formation outside of this rotational sweep, the instrumented engagement element may not encounter the penetrations and may accordingly take detailed, reliable measurement data notwithstanding the penetrating action of the rotary engagement elements.

[0027] In some embodiments, the instrumented engagement element is positioned within the rotational sweep of the rotary engagement component and rotationally behind a lead cutting element. For example, the penetrations formed by the rotary engagement component may be formed at a penetration depth within the formation. A lead cutting element may be implemented with a depth of cut that is at least as deep as, or deeper than, the penetration depth of the rotary engagement components. In this way, the lead cutting element may cut or remove material from the formation to clear the penetrations in order that the instrumented engagement element — which may follow in a groove or path formed by the lead cutting element — may engage the formation at a smooth or uniform interface. In this way, the instrument assembly may be implemented in connection with a downhole tool having one or more rotary engagement components to take measurement data based on an engagement of the instrumented engagement element with the formation.

[0028] 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.

[0029] 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 isPATENTDocket No. IS24.1679-WO-PCT 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 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0030] 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.

[0031] 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.

[0032] 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 bePATENTDocket No. IS24.1679-WO-PCT a junk mill used to mill away tools, plugs, cement, other materials within the 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.

[0033] 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 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 wellbore.

[0034] 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.

[0035] 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.PATENTDocket No. IS24.1679-WO-PCT

[0036] In accordance with at least one embodiment of the present disclosure, the instrument assembly 219 includes an engagement element and an engagement sensor for measuring an engagement of the engagement element with a wellbore. 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 wellbore, 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 wellbore.

[0037] 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, cutout, or groove of the leading element.

[0038] The engagement element 321 may be configured and implemented in accordance with any of the engagement elements, instrument assemblies, and / orPATENTDocket No. IS24.1679-WO-PCT downhole tools as described in any of U.S. Patent Application No. 18 / 664,475, filed May 15, 2024; and U.S. Patent Application No. 18 / 664,358, filed May 15, 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, wellbore, 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 feree (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 may be an instrumented engagement element, 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. 8-1 to 10.

[0039] 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 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. ThePATENTDocket No. IS24.1679-WO-PCT electronics 325 may include one or more additional components such as 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 engagement 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. 7.

[0040] 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, thePATENTDocket No. IS24.1679-WO-PCT instrument assembly 319 may be positioned, configured, and implemented in a variety of different ways in order to accommodate various features and functionalities of the instrument assembly 319.

[0041] 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. The engagement element 321 may be oriented in a generally 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.

[0042] 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 forPATENTDocket No. IS24.1679-WO-PCT engaging the wellbore wall may be positioned rotationally behind and / or in the 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.

[0043] 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.

[0044] In this way, the instrument assembly 319 may be configured and implemented in a variety of different ways and in connection with a variety of different downhole tools for engaging a formation (e.g., a wellbore wall and / or bottom hole) in order to take measurement data, or engagement data, based on this engagement with the formation.

[0045] FIG. 4-1 is a top view and FIG. 4-2 is a side cross-sectional view of a downhole tool 410 having an instrumented engagement element implemented thereon, according to at least one embodiment of the present disclosure. The downhole tool 410 may be a bit for degrading the formation at a wellbore bottom hole in order to form or lengthen the wellbore.

[0046] In some embodiments, the downhole tool 410 includes one or more cutting elements 413. For example, a plurality of cutting elements 413 may be distributed about one or more cutting structures 412 or blades formed on andPATENTDocket No. IS24.1679-WO-PCT extending from a body 411 the downhole tool. The plurality of cutting elements 413 may engage the formation and may cut or degrade the formation through a sheering interaction with the formation. For example, the downhole tool 410 may be driven to rotate, and the one or more cutting elements 413 may be fixed cutting elements which may drag, scrape, or otherwise cut against the wellbore bottom hole to drill the wellbore. In this way, the plurality of cutting elements 413 may form a cutting profile of the downhole tool 410.

[0047] The downhole tool 410 includes one or more rotary engagement components. For example, in the example shown in FIG. 4-1 , the downhole tool 410 includes two (2) rotary engagement components 420, but the downhole tool 410 may be implemented with more or less than two (2) rotary engagement components 420. Each rotary engagement component 420 may be rotatable about a longitudinal axis 422 of the respective rotary engagement component 420. In some embodiments, the rotary engagement components 420 have a general or partial cone shape. The rotary engagement components 420 may have any other shape, such as spherical, round, cylindrical, oval, or combinations thereof. The longitudinal axis 422 about which a rotary engagement component 420 rotates may be transverse to the rotational axis of the downhole tool 410. In this way, a portion of the body 425 of the rotary engagement components 420 may be positioned (e.g., flatly) against the formation, and the rotary engagement components 420 may roll along the formation. For example, the rotary engagement components 420 may engage the formation and may be driven to rotate about their longitudinal axes 422 passively based on the rotation of the downhole tool 410. In this way, the rotary engagement components 420 may rotate or roll along the wellbore bottom hole as the downhole tool 410 rotates. For example, the rotary engagement components 420 may be roller cones.

[0048] The rotary engagement components 420 each include one or more penetrating elements 424. For example, a plurality of penetrating elements 424 may be formed on the body 425 of the rotary engagement component and may extend therefrom. The penetrating elements 424 may be spikes, cones, teeth, grooves, or other penetrating structure which may extend from the body 425. ThePATENTDocket No. IS24.1679-WO-PCT penetrating elements 424 may be formed on or of the body 425, or may be separate components inserted or attached thereon. Based on the rotary engagement component 420 engaging the formation and rolling along the formation as described, the penetrating elements 424 may be driven to penetrate and / or gouge the formation. For example, the penetrating elements 424 may be driven into the formation and may form a plurality of penetrations therein, such as holes, fractures, cracks, indentations, etc., in the formation. This penetrating or gouging action may facilitate breaking apart and / or pulverizing the formation, which may be beneficial for forming the wellbore in certain situations, such as when encountering harder formations.

[0049] In this way, the downhole tool 410 may include both a cutting structure 412 with cutting elements 413 thereon for cutting the formation, as well as a rotary engagement component 420 with penetrating elements 424 thereon for penetrating, gouging, and breaking up the formation. For example, the downhole tool 410 may be a hybrid fixed-cutter roller-cone drill bit. For example, the cutting structure 412 and cutting elements 413 may facilitate the downhole tool 410 efficiently drilling softer formations, and the rotary engagement component 420 may facilitate drilling through harder formations. In this way, the hybrid nature of the downhole tool 410 may provide versatility across a wide variety of formation types and formation hardness, for example, without needed to change bits.

[0050] In some embodiments, the downhole tool 410 includes an instrument assembly 419, including an instrumented engagement element 421 as described herein. The instrumented engagement element 421 may be positioned on and connected to the body 411 and may extend therefrom. For example, the instrumented engagement element 421 may be positioned on the cutting structure 412.

[0051] The instrumented engagement element 421 may be positioned and configured to engage the wellbore as described herein. For example, the instrument assembly 419 includes an engagement sensor 423 which may be coupled to and / or associated with the instrumented engagement element 421 in order to take measurement data associated with the instrumented engagementPATENTDocket No. IS24.1679-WO-PCT element 421 engaging the formation. For example, the engagement sensor 423 may be implemented in any of a variety of ways, such as a strain gauge positioned on a diaphragm near the base of the instrumented engagement element 421 , a load cell, a force transducer, a Hall effect sensor, etc., for detecting force on the instrumented engagement element 421. In this way, the instrumented engagement element 421 may facilitate taking measurement data based on engaging the formation, for example, for measuring, characterizing, and / or imaging various formation features.

[0052] In some cases, the instrumented engagement element 421 may take measurement data based on engaging the formation at a smooth, uniform, and / or pre-formed interface with the formation. For example, in some cases the instrumented engagement element 421 may engage the formation at or within a groove or path formed by one or more cutting elements rotationally ahead of the instrumented engagement element 421. For instance, in some cases the instrumented engagement element 421 may be positioned to follow a rotational path of a lead cutting element such that the instrumented engagement element 421 engages the formation within a smooth and / or uniform path cut by the lead cutting element. In this way, the instrumented engagement element 421 may take measurements of the formation based on features in the formation, for example, rather than being influenced by non-uniform, uneven, broken, rough, and / or other features caused by or resulting from the drilling of the wellbore.

[0053] Accordingly, implementing the instrument assembly 419 in connection with the downhole tool 410 may present challenges associated with the penetrating elements of the rotary engagement component gouging, penetrating, and / or fracturing the formation. For example, the rotary engagement component 420 may roll and / or pass over a portion of the formation leaving a plurality of penetrations (e.g., fractures, holes, gouges, etc.) therein, which may adversely affect the measurements taken via the instrumented engagement element 421 . For example, in cases where the instrumented engagement element 421 may pass over, through, by, and / or in the plurality of penetrations, such an interaction may register at the engagement sensor 423, and accordingly the associatedPATENTDocket No. IS24.1679-WO-PCT measurement data may reflect these penetrations in the formation. This may affect the ability of the instrumented engagement element 421 to detect other features in the formation. For example, the measurements taken via the instrumented engagement element 421 may be dominated by the penetrations in the formation, for example, rather than detecting other inherent formation features in the formation. In another example, the penetrations in the formation may create noise in the measurement data which may hide or mask one or more formation features.

[0054] FIG. 4-3 is a top view and FIG. 4-4 is a side cross-sectional view of the downhole tool 410 as illustrated with respect to a rotational sweep of the rotary engagement component 420, according to at least one embodiment of the present disclosure. As mentioned above, the rotary engagement component 420 may roll or rotate along the wellbore bottom hole and the penetrating elements 424 may create a plurality of penetrations in the formation. Due to the rotating action of the downhole tool 410, in addition to the rolling or rotation of the rotary engagement component 420, these penetrations may be formed in a circular or rotational pattern. For example, as the downhole tool rotates, the plurality of penetrations may be formed within a rotational sweep 430 of the rotary engagement component 420. For example, the rotational sweep 430 may be defined by the plurality of penetrations, such as a surface or area in which the plurality of penetrations are formed. The rotational sweep 430 may have a radius 432, and each of the plurality of penetrations may be formed within an area defined by the radius 432. For example, the rotational sweep 430 may be a measure from the axis of rotation of the downhole tool 410 radially outward to the furthest extent of the plurality of penetrations, or to a furthest penetration. The rotational sweep 430 may be representative of a plurality of penetrations formed by one, or by multiple rotary engagement components 520 of the downhole tool 410. The rotational sweep 430 may be continually formed in a circular and / or spiraling manner as the downhole tool 410 rotates and progresses through the formation. FIG. 4-3 illustrates a partial portion of the rotational sweep 430 for illustrative purposes with respect to the instrumented engagement element 421 ,PATENTDocket No. IS24.1679-WO-PCT but it should be understood that the rotational sweep 430 may be a complete (e.g., 360°) or continuous revolution based on the rotation of the downhole tool 410.

[0055] In some embodiments, the instrumented engagement element 421 may be positioned on the body 411 such that the instrumented engagement element 421 is outside of (or is not within) the rotational sweep 430 of the rotary engagement component 420. For example, the instrumented engagement element 421 may be positioned at, and may engage the formation at, an engagement radius 434. The engagement radius 434 may be a measure of a distance from the center of the downhole tool 410 and / or the axis of rotation of the downhole tool 410 to a point of engagement of the instrumented engagement element 421 . The engagement radius 434 may be greater than the radius 432 of the rotational sweep 430 such that the instrumented engagement element 421 is not positioned within the rotational sweep 430. In some embodiments, the instrumented engagement element 421 is considered to be positioned outside of the rotational sweep 430 when the point of engagement of the instrumented engagement element 421 (e.g., the engagement radius 434 is greater than or equal to the radius 432 of the rotational sweep) is positioned outside of the rotational sweep 430 but one or more other portions of the instrumented engagement element may nevertheless located within the rotational sweep 430. For example, a portion of the instrumented engagement element 421 may be positioned within the rotational sweep 430, while the point of engagement (e.g., a tip) of the instrumented engagement element 421 may positioned outside of the rotational sweep 430 such that penetrations within the rotational sweep 430 may be avoided for purposes of collecting measurement data with the instrumented engagement element 421. In other embodiments, the instrumented engagement element 421 is considered to be positioned outside of the rotational sweep 430 when all of the instrumented engagement element 421 is positioned outside of the rotational sweep 430.

[0056] The instrumented engagement element 421 may be positioned outside of the rotational sweep 430 in this way such that measurement data may be takenPATENTDocket No. IS24.1679-WO-PCT via the instrumented engagement element 421 without the penetrations affecting the measurement data. For example, the instrumented engagement element 421 may engage the formation at a rotational path that is smooth, uniform, and / or formed by the one or more cutting elements 413. For example, the engagement path of the instrumented engagement element 421 may not include any cracks, fractures, holes, gouges, penetrations, etc., formed by the penetrating elements 424 such that the instrumented engagement element 421 may engage the formation without encountering any of the penetrations formed by the rotary engagement component 420. In this way, the instrument assembly 419 may be implemented to collect valuable downhole data for detecting, characterizing, and / or imaging formation features, for example, notwithstanding the gouging and / or pulverizing action of the downhole tool 410.

[0057] FIG. 5-1 is a top view and FIG. 5-2 is a side cross-sectional view of a downhole tool 510 having an instrumented engagement element implemented thereon, according to at least one embodiment of the present disclosure. The downhole tool 510 may be substantially similar to the downhole tool 410 of FIGS. 4-1 to 4-4. For example, the downhole tool 510 includes a tool body 511 having one or more cutting structures 512 formed thereon. One or more cutting elements 513 are positioned on the cutting structures 512 for engaging and cutting the formation. The downhole tool includes one or more rotary engagement components 520 having one or more penetrating elements 524 thereon. The rotary engagement component 520 may engage the formation by rolling along the formation and forming a plurality of penetrations in the formation. The plurality of penetrations may form or define a rotational sweep 530 of the rotary engagement component having a radius 532.

[0058] The downhole tool 510 includes an instrument assembly 519 including an instrumented engagement element 421 as described herein. In some embodiments, the instrumented engagement element 521 may be positioned within the rotational sweep 530 of the rotary engagement component 520. For example, an engagement radius 534 at which the instrumented engagement element 521 is positioned on the body 511 and at which the instrumentedPATENTDocket No. IS24.1679-WO-PCT engagement element 521 engages the formation may be less than, and at most equal to, the radius 532 of the rotational sweep 530. Accordingly, the instrumented engagement element 521 may be positioned within the rotational sweep 530. For example, the instrumented engagement element 521 may engage the formation along a rotational path that may cross over, intersect, or encounter one or more locations where one or more penetrations have been formed in the formation by the rotary engagement component 520.

[0059] FIG. 5-3 is a schematic diagram illustrating the engagement of various elements of the downhole tool 510 with a formation 501 , according to at least one embodiment of the present disclosure. In some embodiments, the penetrating elements 524, at least one cutting element 513, and the instrumented engagement element 521 may engage the formation at different depths in order to facilitate the instrumented engagement element taking measurements without interference from the penetrations formed in the formation 501 .

[0060] As mentioned, the penetrating elements 524 may penetrate, gouge, etc., the formation 501 and may form a plurality of penetrations 536 therein. The penetrating elements 524 may penetrate the formation 501 at a penetration depth 540. For example, the penetration depth 540 may be a depth at which the penetrating elements 524 penetrate the formation 501 from a surface 552 or body of the downhole tool 510 upon which the penetrating elements 524 are dispose and from which they extend. In another example, the penetration depth 540 may be a distance from an exposed surface 550 of the formation 501 to a furthest or deepest depth of the penetrations 536. For example, in some cases the exposed surface 550 may contact or abut the downhole tool 510 at the surface 552, which may establish or define the depth at which various elements (e.g., the penetrating elements 524, the cutting elements 513, the instrumented engagement element 521 , etc.) engage the formation 501 .

[0061] As mentioned, the downhole tool 510 includes one or more cutting elements 513. At least one of these cutting elements 513 may be a lead cutting element 513-1. The lead cutting element 513-1 may be positioned rotationally ahead of the instrumented engagement element 521 such that the instrumentedPATENTDocket No. IS24.1679-WO-PCT engagement element 521 follows in a rotational path, groove, or channel cut by the lead cutting element 513-1. The lead cutting element may be advantageously implemented with a depth of cut 542 that is equal to or greater than the penetration depth 540 of the penetrating elements 524. For example, the lead cutting element 513-1 may cut deeper into the formation 501 than (or at least as deep as) the depth at which the penetrating elements 524 penetrate into the formation 501 . By having a depth of cut 542 that is greater or deeper (or at least as deep as) than the penetration depth 540, the lead cutting element 513-1 may cut, smooth, even out, or otherwise clear the penetrations 536 from the rotational path 548 of the engagement element 521 . For example, the lead cutting element 513-1 may remove material from the formation 501 at the same or greater depth than the penetrations 536 such that the resulting rotational path 548 does not include any cracks, holes, fractures, gouges, or other portion of the penetrations 536. Accordingly, the engagement element 521 may engage the formation 501 on, at, or within the rotational path 548, which may provide a smooth, and / or uniform interface for the instrumented engagement element 521 to engage the formation 501. The instrumented engagement element 521 may engage the formation 501 with an engagement depth 546 that is greater than the depth of cut 542 of the lead cutting element 513-1 in order that the instrumented engagement element 521 can detect and / or sense features in the formation 501 , which may be recorded as measurement data.

[0062] In some cases, multiple (or all) of the cutting elements 513 may be implemented with depths of cut that are the same as or greater than the penetration depth 540. For instance, multiple (or all) of the cutting elements 513 may have a (same or different) depth of cut which may be at least as deep as the penetration depth 540. In some embodiments, only the lead cutting element 513- 1 is implemented with the depth of cut 542 being the same or greater than the penetration depth 540, for example, and the remaining cutting elements 513 have depths of cut that are smaller than or shallower than the penetration depth 540.

[0063] In this way, the lead element 513-1 may be implemented to clear the penetrations 536 from the rotational path 548 such that the penetrations 536 mayPATENTDocket No. IS24.1679-WO-PCT not affect the measurements of the instrumented engagement element 521. For example, the instrumented engagement element 521 may in this way be sensitive to features inherent in the formation 501 , rather than being affected by or dominated by drilling-induced features, such as the penetrations 536.

[0064] FIG. 6-1 illustrates a flow diagram for a method 600 or a series of acts for taking downhole measurements as described herein, according to at least one embodiment of the present disclosure. While FIG. 6-1 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 6-1. In some embodiments, the acts of FIG. 6-1 may be performed by a computer system, in some embodiments, the acts of FIG. 6-1 may be performed as instructions stored on a computer-readable storage medium.

[0065] In some embodiments, the method 600 includes an act 610 of engaging a formation with a downhole tool including rotating the downhole tool to form a wellbore in the formation.

[0066] In some embodiments, the method 600 includes an act 620 of engaging the formation with a rotary engagement component of the downhole tool having a plurality of penetrating elements to form a plurality of penetrations in the formation defining a rotational sweep of the rotary engagement component.

[0067] In some embodiments, the method 600 includes an act 630 of engaging the formation with an instrumented engagement element positioned on a body of the downhole tool at an engagement radius that is outside of the rotational sweep.

[0068] In some embodiments, the method 600 includes an act 640 of taking one or more measurements with an engagement sensor of the instrumented engagement element based on the instrumented engagement element engaging the formation.

[0069] In some embodiments, the method 600 further includes engaging a bottom hole of the wellbore with the rotary engagement component and with the instrumented engagement element.PATENTDocket No. IS24.1679-WO-PCT

[0070] In some embodiments, the method 600 further includes logging the one or more measurements to memory with a processor housed in an electronics housing positioned within the body of the downhole tool.

[0071] In some embodiments, taking the one or more measurements includes detecting a force on the instrumented engagement element.

[0072] In some embodiments, engaging the formation with the instrumented engagement element includes not encountering the plurality of penetrations with the instrumented engagement element.

[0073] FIG. 6-2 illustrates a flow diagram for a method 601 or a series of acts for taking downhole measurements as described herein, according to at least one embodiment of the present disclosure. While FIG. 6-2 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 6-2. In some embodiments, the acts of FIG. 6-2 may be performed by a computer system, in some embodiments, the acts of FIG. 6-2 may be performed as instructions stored on a computer-readable storage medium.

[0074] In some embodiments, the method 601 includes an act 650 of engaging a formation with a downhole tool including rotating the downhole tool to form a wellbore in the formation.

[0075] In some embodiments, the method 601 includes an act 660 of engaging the formation with a rotary engagement component of the downhole tool having a plurality of penetrating elements to form a plurality of penetrations in the formation at a penetration depth.

[0076] In some embodiments, the method 601 includes an act 670 of engaging the formation with a lead cutting element positioned on a body of the downhole tool to degrade the formation along a rotational path of the lead cutting element and at a depth of cut that is greater than the penetration depth.

[0077] In some embodiments, the method 601 includes an act 680 of engaging the formation with an instrumented engagement element positioned onPATENTDocket No. IS24.1679-WO-PCT the body of the downhole tool within the rotational path of the lead cutting element and at an engagement depth that is greater than the depth of cut.

[0078] In some embodiments, the method 601 includes an act 690 of taking one or more measurements with an engagement sensor of the instrumented engagement element based on the instrumented engagement element engaging the formation.

[0079] In some embodiments, the method 601 further includes engaging a bottom hole of the wellbore with the rotary engagement component, with the lead cutting element, and with the instrumented engagement element.

[0080] In some embodiments, the method 601 further includes logging the one or more measurements to memory with a processor housed in an electronics housing positioned within the body of the downhole tool.

[0081] In some embodiments, taking the one or more measurements includes detecting a force on the instrumented engagement element.

[0082] In some embodiments, the plurality of penetrations form a rotational sweep of the rotary engagement component, and further comprising engaging the formation with the lead cutting element and with the instrumented engagement element within the rotational sweep of the rotary engagement component.

[0083] In some embodiments, engaging the formation with the instrumented engagement element includes not encountering the plurality of penetrations with the instrumented engagement element.

[0084] Turning now to FIG. 7, this figure illustrates certain components that may be included within a computer system 700. One or more computer systems 700 may be used to implement the various devices, components, and systems described herein. For example, any of the electronics and / or computing components described herein may include any of the features and / or functionalities of the computer system 700.PATENTDocket No. IS24.1679-WO-PCT

[0085] The computer system 700 includes a processor 701. The processor 701 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 701 may be referred to as a central processing unit (CPU). Although just a single processor 701 is shown in the computer system 700 of FIG. 7, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

[0086] The computer system 700 also includes memory 703 in electronic communication with the processor 701 . The memory 703 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 computerexecutable 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.

[0087] 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 such 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 purposePATENTDocket No. IS24.1679-WO-PCT computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.

[0088] Instructions 705 and data 707 may be stored in the memory 703. The instructions 705 may be executable by the processor 701 to implement some or all of the functionality disclosed herein. Executing the instructions 705 may involve the use of the data 707 that is stored in the memory 703. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 705 stored in memory 703 and executed by the processor 701 . Any of the various examples of data described herein may be among the data 707 that is stored in memory 703 and used during execution of the instructions 705 by the processor 701 .

[0089] A computer system 700 may also include one or more communication interfaces 709 for communicating with other electronic devices. The communication interface(s) 709 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 709 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.

[0090] The communication interfaces 709 may connect the computer system 700 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, 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 computer-PATENTDocket No. IS24.1679-WO-PCT executable instruction or data structures and which can be accessed by a general purpose or special purpose computer.

[0091] A computer system 700 may also include one or more input devices 711 and one or more output devices 713. Some examples of input devices 711 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 713 include a speaker and a printer. One specific type of output device that is typically included in a computer system 700 is a display device 715. Display devices 715 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 717 may also be provided, for converting data 707 stored in the memory 703 into one or more of text, graphics, or moving images (as appropriate) shown on the display device 715.

[0092] The various components of the computer system 700 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. 7 as a bus system 719.

[0093] 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 implemented 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.PATENTDocket No. IS24.1679-WO-PCT

[0094] 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.

[0095] FIGS. 8-1 through 10 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 (and non-limiting) configurations of components, assemblies, and / or systems for implementing the various engagement elements as described herein.

[0096] FIG. 8-1 is a perspective cutaway view of a downhole tool 810 according to at least one embodiment of the present disclosure. In some embodiments, the downhole tool 810 is a bit, but the downhole tool 810 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 810 includes an instrument assembly 819. The instrument assembly may include an engagement element assembly 820 that connects to an electronics housing 814. In some embodiments, the engagement element assembly 820 removably connects to the electronics housing 814. In other words, the engagement element assembly 820 may not be permanently attached to the downhole tool 810, for example, by brazing the engagement element assembly 820 (and / or an engagement element of the engagement element assembly 820) to the downhole tool 810 as is conventionally done. In this way, the engagement element assembly 820 may be selectively connectedPATENTDocket No. IS24.1679-WO-PCT to and / or removed from the downhole tool 810. In at least one embodiment, this may facilitate incorporating electronics 825 and / or a sensor 823 into the downhole tool 810. For example, the electronics 825 may be installed into the electronics housing 814 and connected to the sensor 823, after which the engagement element assembly 820 may be connected to the electronics housing 814 to complete the installation of the instrument assembly 819. This may facilitate implementing and / or replacing sensing and / or measurement devices such as those included in the instrument assembly 819 by significantly simplifying the implementation of such devices in the downhole tool 810, in at least one embodiment.

[0097] In some embodiments, the engagement element assembly 820 includes an instrumented engagement element 821. The instrumented engagement element 821 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 821 may be configured to engage the borehole, such as a cutting element. For example, the instrumented engagement element 821 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, 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.PATENTDocket No. IS24.1679-WO-PCTIn yet other embodiments, the ultrahard material has a hardness value greater than 80 HRa (Rockwell hardness A). In some examples, the instrumented engagement element 821 is formed from any other material including metals, metallic alloys, ceramic materials, any other material, and combinations thereof.

[0098] The engagement element assembly 820 may be connected to the electronics housing 814 such that the instrumented engagement element 821 extends at least partially past an outer surface 870 of the downhole tool 810. For example, the instrumented engagement element 821 may extend from the downhole tool 810 such that the instrumented engagement element 821 may engage the borehole during drilling (or other downhole operation as the case may be) with the downhole tool 810. The instrumented engagement element 821 may extend in a substantially vertical direction (e.g., substantially downhole). This may facilitate an engagement of the instrumented engagement element 821 with the wellbore bottom hole. In one or more embodiments, the instrumented engagement element 821 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.

[0099] In some embodiments, the instrument assembly includes a sensor 823. The sensor 823 may be an engagement sensor and may take measurements associated with an engagement of the instrumented engagement element 821 with the borehole. The sensor 823 may be positioned at a base of the engagement element assembly 820. The sensor 823 may be positioned at a base of the instrumented engagement element 821. For example, a conduit 815 and / or the engagement element assembly 820 may have one or more structural features for holding and / or supporting the sensor 823 with respect to the instrumented engagement element 821. When the instrumented engagement element 821 engages the borehole, a force exerted on the engagement element 821 may be transferred through the base of the instrumented engagement element 821 to the sensor 823. In some embodiments, the force is an axial force. In this way, the sensor 823 may take measurements based on a force of the instrumentedPATENTDocket No. IS24.1679-WO-PCT engagement element 821. This may facilitate taking measurements associated with the formation encountered by the instrumented engagement element 821. 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 element821. 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 821. The sensor 823 may measure these changes, and in this way, detect the features and / or properties of the formation.

[0100] In this way, the sensor 823 takes measurements associated with the instrumented engagement element 821 engaging the borehole. For example, the sensor 823 may measure strain, stress, displacement, pressure, deformation, deflection, or any other parameter associated with an engagement of the instrumented engagement element 821 with the borehole. These measurements may facilitate calculating or determining a force on the instrumented engagement element 821 , or determining any other dynamic related to an engagement of the instrumented engagement element 821 with the borehole. The sensor 823 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.

[0101] As mentioned above, the instrument assembly 819 includes an electronics housing 814 disposed in the tool body 811. In some embodiments, the electronics housing includes, or defines a conduit 815 (e.g., a void, volume, or space) extending into the tool body 811. The conduit 815 may have an elongate shape. For example, the conduit 815 may be substantially cylindrical. The conduit 815 may be any other shape in accordance with that disclosed herein. The conduit 815 may extend into the downhole tool 810 such that a volume is defined within the tool body 811 .

[0102] In some embodiments, the instrument assembly 819 includes a seal822. The seal 822 may be positioned between the engagement elementPATENTDocket No. IS24.1679-WO-PCT assembly 820 and the tool body, for example, to seal the electronics housing 814. For example, the seal 822 may be an O-ring seal such as a metal, rubber, or plastic O-ring seal. The seal 822 may be a gasket seal. The seal 822 may be a surface seal. For example, the tool body 811 (e.g., in the conduit 815) and the engagement element assembly 820 may each have a sealing surface, and these sealing surfaces may interface in order to form the seal 822. The seal 822 may function to seal the inner volume of the electronics housing 814. For example, the electronics housing 814 may be sealed to maintain an inner pressure of the electronics housing 814. The electronics housing 814 may be sealed to prevent fluid from penetrating into the electronics housing 814. This may facilitate using and / or protecting electronics within the sealed portion of the electronics housing 814.

[0103] The volume of the electronics housing 814 may be of such a size and / or shape so as to house the electronics 825. For example, the electronics 825 may include a processor 825-1 and / or a power supply 825-2 (e.g., a battery). The electronics 825 may include one or more additional components such as memory, communication devices, etc. The electronics 825 may be coupled to and / or associated with the sensor 823. For example, the power supply 825-2 may power a function of the sensor 823. The processor 825-1 may receive and / or record one or more measurements of the sensor 823 (e.g., process and / or save to memory). The electronics 825 may be positioned within the sealed portion of the electronics housing 814. In some embodiments, the sensor 823 is positioned in the sealed portion of the electronics housing 814 which may facilitate the sensor 823 connecting with the electronics 825 (e.g., through a wired connection). In this way, the electronics housing 814 may facilitate implementing one or more electronic components into the downhole tool 810, such as a processor for receiving downhole measurements from the sensor 823.

[0104] The electronics housing 814 may have an opening 816. The opening 816 may be positioned at an outer surface of the tool body 811. In some embodiments, the engagement element assembly 820 connects to the electronics housing 814 at the opening 816. For example, a portion of thePATENTDocket No. IS24.1679-WO-PCT electronics housing 814 proximate or adjacent to the opening 816 may be an engagement element pocket 817. The engagement element pocket 817 may be a portion of the electronics housing 814 that is configured to connect to and / or retain the engagement element assembly 820. In some embodiments, the engagement element pocket 817 is separate from the conduit 815. For example, the engagement element pocket 817 may be at a distinct location on the downhole tool 810 from the conduit. In other words, the conduit 815 and / or electronics housing 814 may be otherwise positioned within the tool body 811 (or at another location) than that shown in the illustrative example of FIG. 8-1 , but may nevertheless be electronically coupled to the engagement element assembly 820. For example, the engagement element pocket 817 may form or define a separate cavity from that of the conduit 815 shown in FIG. 8-1. In this way, the electronics 825 may be housed at a separate location from the engagement element assembly 820 and / or the sensor 823.

[0105] In accordance with at least one embodiment of the present disclosure, the opening 816 may be at a distal (e.g., downhole) end of the conduit 815. In other embodiments as described herein, the opening 816 may be at any other location and / or orientation from the downhole tool 810. The opening 816 may be at the outer surface 870 of the tool body 811 and may provide access to the electronics housing 814, for example, for inserting and / or connecting the electronics 825. The engagement element pocket 817 may be a portion of the conduit 815 that is adjacent or proximate the opening 816. In this way, the engagement element pocket 817 and the conduit 815 may be located or formed in the same cavity in the tool body 811. This may facilitate and / or simplify installing and / or connecting one or more of the electronics 825, the engagement element assembly 820, and the sensor 823. The opening 816 (and in this example the engagement element pocket 817) may be at an outer surface of the tool body 811 that is a downhole end of the downhole tool 810. This positioning may facilitate the engagement element assembly 820 and / or the instrumented engagement element 821 extending from the outer surface of the tool body 811 .PATENTDocket No. IS24.1679-WO-PCT

[0106] In some embodiments, the conduit 815 includes a sleeve 815-1. For example, the sleeve 815-1 may have substantially the same shape as the conduit 815, and may be hollow, or may have an inner bore. In some embodiments, the sleeve 815-1 is substantially the shape of a hollow cylinder. The sleeve 815-1 and / or conduit 815 may be any other shape suitable for housing the electronics 825 as described herein. In some embodiments, the sleeve 815-1 is disposed within and / or connected to the conduit 815. For example, the sleeve 815-1 may be brazed into the conduit 815. The sleeve 815-1 may be glued, pressed, or threaded into the conduit, or any other form of connection suitable for connecting the sleeve 815-1 to the conduit 815. The sleeve 815-1 may span an entire length of the conduit 815 such that the sleeve 815-1 substantially makes up an entirety of the conduit 815. For example, one or more of the features of the conduit 815 described herein (e.g., sealing feature, connection with the engagement element assembly, etc.) may be included as part of the sleeve 815-1. In some embodiments, the sleeve 815-1 spans or encompasses only a portion of the conduit 815. For example, the sleeve 815-1 may define or be associated with the sealed portion of the electronics housing 814. As another example, the sleeve 815-1 may not include or be associated with the connection of the engagement element assembly 820 with the electronics housing 814. The sleeve 815-1 may be a chassis or frame for housing the electronics 825, for example, to facilitate inserting, positioning, and / or removing the electronics 825 with respect to the conduit 815.

[0107] The sleeve 815-1 may at least partially define or create the sealed volume of the electronics housing 814. The sleeve 815-1 may be configured to withstand the pressure differential between the sealed volume and an exterior of the downhole tool 810. For example, the sleeve 815-1 may have a wall thickness that is selected to prevent collapse under the pressure differential. In some embodiments, the seal 822 may be positioned between the sleeve 815-1 and the engagement element assembly 820 to seal the inner volume of the sleeve 815- 1.PATENTDocket No. IS24.1679-WO-PCT

[0108] In some situations, the material properties of the metal matrix of the tool body 811 make it difficult to include one or more features of the conduit 815 discussed herein. The sleeve 815-1 may be more easily machined or manufactured to facilitate including one or more of these features. In some embodiments, the sleeve 815-1 is manufactured before it is installed into the downhole tool 810. In some embodiments, the sleeve 815-1 is installed into the downhole tool 810 and after one or more features of the electronics housing 814 have been machined or manufactured into the sleeve 815-1. In this way, the electronics housing 814 may include the sleeve 815-1 to facilitate including one or more features of the instrument assembly 819.

[0109] In some embodiments, the conduit 815 is oriented in a longitudinal direction relative to the downhole tool 810. For example, a longitudinal axis of the conduit 815 may be oriented such that it is parallel to a longitudinal axis of the downhole tool 810. The longitudinal axis of the downhole tool 810 may be an axis of rotation of the downhole tool 810. In this way, the conduit 815 may be oriented substantially vertically, for example, during downhole drilling activities of the downhole tool 810. This may facilitate the engagement element assembly 820 and / or the engagement element 821 extending substantially vertically (e.g., downhole) from the downhole tool 810. However, as discussed herein, other orientations of the engagement element assembly 820 and / or the engagement element 821 are contemplated which may not necessarily be in an axial / longitudinal direction.

[0110] While one or more components of the instrument assembly 819 are shown in FIG. 8-1 as being substantially vertical, or located substantially in a longitudinal plane of the downhole tool 810, it should be understood that one or more of the components of the instrument assembly 819 may be oriented, for example, at an angle relative to the longitudinal plane of the downhole tool 810. Indeed, one or more of the components of the instrument assembly 819 may be included in the downhole tool 810 at any orientation consistent with drilling the borehole and / or taking measurements as described herein. For example, one or more of the conduit 815, the engagement element assembly 820 and thePATENTDocket No. IS24.1679-WO-PCT engagement element pocket 817 may be oriented horizontally. In another example, one or more of the conduit 815, the engagement element assembly 820, and the engagement element pocket 817 may be oriented transvers and / or at any angle relative to the longitudinal plane. This may facilitate implementing the instrument assembly 819 in a variety of downhole tools.

[0111] FIGS. 8-2 and 8-3 are schematic views illustrating an engagement of the instrumented engagement element 821 and a lead engagement element 875, according to at least one embodiment of the present disclosure. In some embodiments, the electronics housing 814 (more specifically, the engagement element pocket 817) is positioned in the tool body 811 such that the engagement element assembly 820 and / or the instrumented engagement element 821 extends from the downhole tool 810 adjacent to and / or behind the lead engagement element 875 (such as one or more of the engagement elements 213 of FIG. 2) of the downhole tool 810. For example, during drilling activities, the downhole tool 810 may rotate such that the engagement elements follow a rotational path. The instrumented engagement element 821 may be positioned such that it follows a rotational path that is the same as one of the engagement elements of the downhole tool 810. In other words, the rotational path of the instrumented engagement element 821 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 810. In this way the instrumented engagement element 821 may follow the rotational path of a lead engagement element 875, such as a lead cutting element. While FIG. 8-2 illustrates the lead engagement element 875 as an element of the downhole tool 810 that is adjacent to the instrumented engagement element 821 as well as immediately and / or rotationally ahead of the instrumented engagement element 821 , it should be understood that the lead engagement element 875 may be positioned at any location of the downhole tool 810 (as discussed below) and / or may be any of the engagement elements of the downhole tool 810.

[0112] The instrumented engagement element 821 may follow the rotational path of the lead engagement element 875 by being positioned an offset anglePATENTDocket No. IS24.1679-WO-PCT from the lead engagement element 875. For example, the offset angle may be an angle measured about the axis of rotation of the downhole tool 810 (e.g., measured in the direction and plane of the rotation of the downhole tool 810) between the lead engagement element 875 and the instrumented engagement element 821 . In this way the offset angle may correspond to an angle between a point of engagement of the lead engagement element 875 with the earth formation and a point of engagement of the instrumented engagement element 821 with the earth formation.

[0113] In some embodiments, the instrumented engagement element 821 is positioned substantially adjacent or proximate the lead engagement element 875. For example, the offset angle may be small, such as 1 °, and the instrumented engagement element 821 may be positioned immediately (rotationally) behind the lead engagement element 875. 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 821 with the lead engagement element 875 may correspond with the instrumented engagement element 821 and the lead engagement element 875 being positioned in the same blade of the downhole tool 810.

[0114] In some embodiments, the instrumented engagement element 821 is not positioned adjacent or proximate the lead engagement element 875. For example, the offset angle may be any angle between 1 ° and 359°, such as 85°, 90°, 180°, 280°, or any other angle. In some embodiments, this corresponds with the instrumented engagement element 821 being positioned in the same blade of the downhole tool 810 as the lead engagement element 875. In some embodiments, this corresponds with the instrumented engagement element 821 being positioned in a different blade (or not in a blade) of the lead engagement element 875. In this way, the instrumented engagement element 821 may be positioned at any offset angle from the lead engagement element 875 such that the instrumented engagement element 821 follows along substantially the same rotational path as the lead engagement element 875. In some embodiments, the instrumented engagement element 821 and / or the lead engagement element 875PATENTDocket No. IS24.1679-WO-PCT are each positioned in a blade of the downhole tool 810. In some embodiments, the instrumented engagement element 821 and / or the lead engagement element 875 is not positioned in a blade of the downhole tool 810.

[0115] It should be understood that the positioning of the instrumented engagement element 821 and the lead engagement element 875 in FIG. 8-2 as being adjacent, proximate, or substantially side-by-side is for illustrative purposes only. The positioning and / or spacing of the instrumented engagement element 821 and the lead engagement element 875 may correspond with any offset angle as described above. In this way, FIG. 8-2 illustrates the instrumented engagement element 821 and the lead engagement element 875 with respect to a rotation 880 of the downhole tool 810, and not necessarily with respect to an actual or physical position on the downhole tool 810. Similarly, it should be understood that FIG. 8-3 does not necessarily illustrate the instrumented engagement element 821 and the lead engagement element 875 with respect to, for example, a positioning of each in the downhole tool 810. Rather, FIG. 8-3 is illustrative of the engagement of the instrumented engagement element 821 and the lead engagement element 875 with the earth formation 801 .

[0116] With reference now to FIG. 8-3, as discussed herein, the instrumented engagement element 821 engages an earth formation 801 in order to take one or more corresponding measurements. In some embodiments, the instrumented engagement element 821 engages the earth formation 801 by contacting and / or extending into the earth formation 801. This may be characterized by an engagement distance 873. For example, the lead engagement element 875 may engage the earth formation and may cut and / or remove a lead groove 876. The instrumented engagement element 821 may extend into the formation 801 at or in the lead groove 876 (e.g., as shown in FIG. 8-3) and may produce a trailing groove 877. The engagement distance 873 may be the difference between the furthest extent (e.g., downhole) of the lead groove 876 and the trailing groove 877. In this way, the engagement distance 873 may correspond to a distance or the furthest extent that the instrumented engagement element 821 extends into the formation 801 upon engagement.PATENTDocket No. IS24.1679-WO-PCT

[0117] In some embodiments, the engagement distance 873 may be 1 mm. The engagement distance 873 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 distance873 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 873 may be between 0.1 mm and 10 mm. In some embodiments, the engagement distance 873 in particular is less than 1 mm to ensure that the instrumented engagement element 821 experiences a significant enough engagement with the formation 801 to accurately take one or more measurements while minimizing noise in the measurements. For example, it may be understood that the instrumented engagement element 821 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.

[0118] Turning back to FIG. 8-2, the instrumented engagement element 821 may extend axially (e.g., downhole) a sensor axial distance 871. The lead engagement element 875 may extend axially (e.g., downhole) a cutting axial distance 872. The sensor axial distance 871 and the cutting axial distance 872 may each be a distance measured between a point of engagement of the respective engagement element with the formation 801 and a reference point 874, such as at a base of a blade of the downhole tool 810. The reference point874 may be any reference point for measuring the sensor axial distance 871 and the cutting axial distance 872 relative to the engagement of the instrumented engagement element 821 and the lead engagement element 875 with the formation 801. For example, the instrumented engagement element 821 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 871 and the cutting axial distance 872 may be measured from the reference point 874 radially outward to an engagement of the instrumented engagement element 821 and thePATENTDocket No. IS24.1679-WO-PCT lead engagement element 875 with the borehole wall, respectively. In this way, the instrumented engagement element 821 may follow the same rotational path as the lead engagement element 875 (e.g., rotationally behind), while still engaging the borehole within a groove or channel cut by the lead engagement element 875. The sensor axial distance 871 and / or the cutting axial distance 872 may be determined or configured such that the instrumented engagement element 821 engages the formation 801 with the engagement distance 873, in accordance with that discussed above.

[0119] In some embodiments, the sensor axial distance 871 may be greater than the cutting axial distance 872. In other words, the instrumented engagement element 821 may axially extend (e.g., downhole) further than the lead engagement element 875. This may correspond with the instrumented engagement element 821 being positioned with a smaller offset angle, such as less than 180° (e.g., in accordance with the downhole tool 810 not having progressed significantly through the formation from the time the lead engagement element 875 cuts the formation to when the instrumented engagement element 821 engages the formation). In this way, the instrumented engagement element 821 may extend axially and engage the earth formation after the lead engagement element 875 has cut the lead groove 876.

[0120] In some embodiments, the sensor axial distance 871 may be substantially the same, or even less than the cutting axial distance 872. This may correspond with the instrumented engagement element 821 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 810 and / or the various engaging elements of the downhole tool 810, due to the rotation of the downhole tool 810, as well as the downhole tool advancing downhole through the formation 801 as it rotates, in some situations, the face of the formation 801 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 810. In this way, the instrumented engagement element 821 may extend axially and engagePATENTDocket No. IS24.1679-WO-PCT the earth formation after the lead engagement element 875 has cut the lead groove 876, even though the instrumented engagement element 821 may not extend axially further than the lead engagement element 875. In this way, the configuration of the sensor axial distance 871 and / or the cutting axial distance 872 may be based on or dependent on the offset angle as discussed above.

[0121] 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.

[0122] As discussed herein, the instrumented engagement element 821 may follow the same (or similar) rotational path as the lead cutting element 875. This may correspond with the instrumented engagement element 821 engaging the formation 801 within the lead groove 876 cut or removed by the lead engagement element 875. The instrumented engagement element 821 may be positioned and / or oriented such that the width of the trailing groove 877 never breaches the width of the lead groove 876 as the instrumented engagement element 821 follows rotationally behind the lead engagement element 875. For example, the instrumented engagement element 821 may engage the formation 801 at a center of the lead groove 876. In another example, the instrumented engagement element 821 may engage the formation 801 at another location of the lead groove 876 that is not centered. The instrumented engagement element 821 may engage the formation 801 within the lead groove 876 at an angle (e.g., relative to a longitudinal axis of the instrumented engagement element 821 ), such as a normal or perpendicular angle, or any other angle.

[0123] The instrumented engagement element 821 may follow behind the lead engagement element 875 in this way to facilitate a measurement and / or calculation of the force on the instrumented engagement element 821 , or any other parameters associated with an engagement of the instrumented engagement element 821 with the borehole. For example, the instrumented engagement element 821 may engage the formation 801 in substantially thePATENTDocket No. IS24.1679-WO-PCT 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 821 may engage the formation 801 within the lead groove 876 in order to maintain the geometry (more specifically, the area) of rock being removed by the instrumented engagement element 821 substantially uniform. This may result in a substantially uniform engagement of the instrumented engagement element 821 with the formation 801 at all depths of cut and / or rates of penetration of the lead engagement element 875 and / or a downhole tool implementing the lead engagement element 875 and the instrumented engagement element 821. In contrast, if the instrumented engagement element 821 were to not follow directly behind the lead engagement element 875 and / or engage the formation 801 within the lead groove 876, the area of rock with which the instrumented engagement element 821 engages (e.g., removes) may vary based on the depth of cut of the lead engagement element 875, significantly complicating the calculation of the force (or other parameter) on the instrumented engagement element 821 . In this manner, changes in the measured force (or other parameter) on the instrumented engagement element 821 may be attributable to changes or features in the formation 801 (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 821 (e.g., due to different depth of cut of the lead cutting element).

[0124] FIG. 9 is a side cutaway view of an instrumentation housing or an engagement element housing 924, according to at least one embodiment of the present disclosure. The engagement element housing 924 includes a housing body 930 configured to connect to an engagement element pocket 917 of a downhole tool. The housing body 930 may have a distal end 928 and a proximal end 929. The proximal end 929 may insert into and / or engage with the engagement element pocket 917. The housing body 930 may connect to the engagement element pocket 917 such that the distal end 928 is positioned at anPATENTDocket No. IS24.1679-WO-PCT outer surface of the downhole tool. The distal end 928 positioned on the outer surface of the downhole tool may facilitate a measurement by one or more sensors associated with the engagement element housing 924.

[0125] In some embodiments, the housing body 930 removably connects to the engagement element pocket 917. For example, the housing body 930 may include threads 926. The threads 926 may be exterior threads on an outer surface of the housing body 930. The threads 926 may thread or screw into interior threads on an inner surface of the engagement element pocket 917. In another example, the housing body 930 may removably connect to the engagement element pocket 917 with a circlip or other removable fastening means. The housing body 930 may include a tightener 934. The tightener 934 may facilitate securing and / or tightening the connection of the housing body 930 to the engagement element pocket 917. For example, the tightener 934 may be a hex head tightener. The tightener 934 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 930 to the engagement element pocket 917. The housing body 930 may include a flange 935. The flange 935 may seat against a surface of the engagement element pocket 917, for example, to tighten the housing body 930 in the engagement element pocket 917.

[0126] In some embodiments, the engagement element housing 924 has a seal 922. The seal 922 may be positioned on an exterior of the housing body 930 such that the seal 922 is positioned between the housing body 930 and the engagement element pocket 917 (e.g., when the engagement element housing 924 is connected to the engagement element pocket 917). The seal 922 may help to seal a portion of the engagement element pocket 917 (and / or an electronics housing conduit). For example, the seal 922 may seal a pressure in the engagement element pocket 917 and / or may prevent fluid or other matter from penetrating into the engagement element pocket 917. In some embodiments, such as that shown, the seal 922 is an O-ring seal. The O-ring may seat in a groove or channel on an exterior of the housing body 930. In some embodiments, the O-ring seats in a groove or channel on the interior of thePATENTDocket No. IS24.1679-WO-PCT engagement element pocket 917. In this way, the O-ring may be positioned between the housing body 930 and the engagement element pocket 917 to seal the engagement element pocket 917. In some embodiments, the seal 922 is a gasket. For example, the gasket may be disposed on the flange 935. In some embodiments, the gasket is disposed on a mating surface of the engagement element pocket 917. The gasket may be positioned between the flange 935 and a surface of the engagement element pocket 917 to seal the engagement element pocket 917. In some embodiments, the seal 922 is created without a distinct, or dedicated sealing element. For example, mating surfaces of the housing body 930 and the engagement element pocket 917 may interface to form the seal 922 (e.g., the flange 935 and a surface of the engagement element pocket 917). In this way, the engagement element housing 924 may form a removable connection with the downhole tool, and may also seal, for example, an electronics housing conduit of the bit.

[0127] In some embodiments, the engagement element housing 924 includes a measurement pocket 931 . The measurement pocket 931 may be formed in the housing body 930. The measurement pocket 931 may define a cavity in the housing body 930. For example, the measurement pocket 931 may have a pocket base 932 and a pocket opening 933. The pocket base 932 and pocket opening 933 may be on opposite ends of the measurement pocket 931. In some embodiments, the pocket opening 933 is on the distal end 928 of the housing body 930. In some embodiments, the pocket base 932 is on the proximal end 929 of the housing body 930. The measurement pocket 931 may be configured to house one or more sensors for taking one or more downhole measurements. For example, the pocket base 932 may include or may define a diaphragm 936. A strain gauge may be connected to the pocket base 932 at the diaphragm 936. The strain gauge and / or the diaphragm 936 may facilitate measuring, for example, a force and / or pressure associated with an operation of the bit. For example, the diaphragm 936 may experience or exhibit a strain due to a pressure or a force acting on the diaphragm 936. A strain gauge may measure the corresponding strain. In this way, the downhole measurement may include forcePATENTDocket No. IS24.1679-WO-PCT 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 917 may facilitate including instrumentation in a bit for taking one or more downhole measurements including force measurements, pressure measurements, and temperature measurements, among others.

[0128] The engagement element housing 924 may be at least partially made of one or more wear-resistant materials. For example, the engagement element housing 924 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 924 are made of or coated with a wear-resistant material. The wear resistant properties of the engagement element housing 924 may facilitate exposing at least a portion of the engagement element housing 924 to the conditions of the borehole (e.g., at an outer surface of the bit). In this way, the engagement element housing 924 may withstand the harsh downhole drilling environment in order that the engagement element housing 924 may be incorporated in any number of downhole locations and with any number of downhole tools.

[0129] FIG. 10 is a side cutaway view of an engagement element housing 1024, according to at least one embodiment of the present disclosure. In some embodiments, an instrumented engagement element 1021 is disposed or retained in an engagement element housing 1024. The engagement element housing 1024 may include a housing body 1030 having a distal end 1028 and a proximal end 1029. The instrumented engagement element 1021 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 1021 may be a cutting element, or may be another element that is not configured to or notPATENTDocket No. IS24.1679-WO-PCT primarily intended to cut, such as a steering or stabilizing pad. The instrumented engagement element 1021 may be positioned in a measurement pocket 1031. For example, the instrumented engagement element 1021 may be inserted into, at least partially, a cavity defined by the measurement pocket 1031. The instrumented engagement element 1021 may extend out of a pocket opening 1033. The pocket opening 1033 may be positioned on the distal end 1028 of the housing body 1030 such that the instrumented engagement element 1021 extends outward from an outer surface of a downhole tool (e.g., a bit). In this way, the instrumented engagement element 1021 may be configured to extend from the bit in order to engage the borehole.

[0130] The instrumented engagement element 1021 may be connected to or retained in the measurement pocket 1031. For example, the instrumented engagement element 1021 and / or the measurement pocket 1031 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 1021 to retain the instrumented engagement element 1021 in the measurement pocket 1031. The instrumented engagement element 1021 may be connected to or retained in the measurement pocket 1031 by any other suitable means. For example, the instrumented engagement element 1021 may be glued, brazed, pressed, threaded, or fastened in the measurement pocket 1031 (e.g., connected to the diaphragm 1036). In this way, the instrumented engagement element 1021 may be removably connected to the housing body 1030.

[0131] The instrumented engagement element 1021 may be retained in the measurement pocket 1031 such that the instrumented engagement element 1021 is axially fixed. For example, the instrumented engagement element 1021 may be fixed such that the instrumented engagement element 1021 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 1021 and to the sensor 1023, as discussed herein. The instrumented engagement element 1021 may not move axially in a substantialPATENTDocket No. IS24.1679-WO-PCT manner, but for small deflections and / or deformations of the diaphragm 1036. In some embodiments, the instrumented engagement element 1021 is axially fixed but may be free to spin or rotate within the measurement pocket 1031 . This may facilitate continually exposing different portions of a revolving cutting face in order to reduce wear of the instrumented engagement element 1021 .

[0132] In some embodiments, a pocket base 1032 of the measurement pocket 1031 includes or defines a diaphragm 1036. The diaphragm 1036 may be positioned at a base of the instrumented engagement element 1021. As the instrumented engagement element 1021 engages the borehole, a force (e.g., an axial force) may be transmitted through the instrumented engagement element 1021 to the diaphragm 1036. For example, in some embodiments, the instrumented engagement element 1021 is retained in the measurement pocket 1031 such that forces exerted on the instrumented engagement element 1021 are not distributed throughout the housing body 1030. Rather, in some embodiments, the instrumented engagement element 1021 is retained in the measurement pocket such that forces exerted on the instrumented engagement element 1021 are directed and / or transmitted through a base of the instrumented engagement element 1021 to the diaphragm 1036. The diaphragm 1036 may experience or exhibit a strain corresponding to at least a portion of the force (e.g., the axial force).

[0133] The strain of the diaphragm 1036 may be due to a material compliance of the diaphragm 1036. In some embodiments, the diaphragm 1036 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 1036PATENTDocket No. IS24.1679-WO-PCT exhibits a measurable level of strain, while preventing plastic deformation of the diaphragm 1036 due to the axial forces.

[0134] In some embodiments, a sensor 1023 is housed by the measurement pocket 1031. For example, a strain gauge 1037 may be disposed on the diaphragm 1036. The strain gauge 1037 may measure a strain exhibited by the diaphragm 1036, for example, based on forces exerted on the instrumented engagement element 1021. In this way, the instrumented engagement element 1021 , the diaphragm 1036, and the strain gauge 1037 may form the sensor 1023 (e.g., an engagement sensor). In some embodiments, the strain gauge 1037 is disposed on an opposite side of the diaphragm 1036 from the instrumented engagement element 1021 . In this way, the strain gauge 1037 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 1037 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.

[0135] 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.

[0136] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended toPATENTDocket No. IS24.1679-WO-PCT 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.

[0137] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0138] 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 lessPATENTDocket No. IS24.1679-WO-PCT 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.

[0139] 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.

Claims

PATENTDocket No. IS24.1679-WO-PCTCLAIMSWhat is claimed is:1 . A downhole tool for forming a wellbore in a formation, comprising: a rotary engagement component including one or more penetrating elements for forming a plurality of penetrations in the formation defining a rotational sweep of the rotary engagement component; a cutting structure formed on a body of the downhole tool having one or more cutting elements positioned thereon for degrading the formation; an instrumented engagement element positioned on the cutting structure and positioned to engage the formation at an engagement radius that is outside of the rotational sweep of the rotary engagement component; and an engagement sensor connected to electronics for taking one or more measurements associated with the instrumented engagement element engaging the formation.

2. The downhole tool of claim 1 , wherein the rotary engagement component is a roller cone.

3. The downhole tool of claim 1 , wherein the downhole tool is a hybrid fixed- cutter roller-cone drill bit for drilling the wellbore.

4. The downhole tool of claim 1 , wherein the rotary engagement component, the one or more cutting elements, and the instrumented engagement element are each positioned to engage a bottom hole of the wellbore.PATENTDocket No. IS24.1679-WO-PCT5. The downhole tool of claim 1 , wherein the rotary engagement component is a first rotary engagement component, and further comprising a second rotary engagement component including a second plurality of penetrating elements for forming a second plurality of penetrations in the formation within the rotational sweep defined by the first rotary engagement component.

6. The downhole tool of claim 1 , wherein the rotary engagement component is rotatable about a longitudinal axis of the rotary engagement component that is transverse to a rotational axis of the downhole tool.

7. The downhole tool of claim 1 , wherein the cutting structure is a blade of the downhole tool, and wherein at least a portion of the blade is within the rotational sweep of the rotary engagement component.

8. The downhole tool of claim 7, wherein at least one cutting element of the one or more cutting elements is positioned on the cutting structure within the rotational sweep of the rotary engagement component.

9. The downhole tool of claim 1 , further comprising an electronics housing positioned within the body of the downhole tool, wherein the electronics are positioned within the electronics housing.

10. The downhole tool of claim 9, wherein the electronics include a processor connected to the engagement sensor and a power source.11 . The downhole tool of claim 1 , wherein the engagement sensor measures a force on the instrumented engagement element.PATENTDocket No. IS24.1679-WO-PCT12. A method of taking downhole measurements, comprising: engaging a formation with a downhole tool including rotating the downhole tool to form a wellbore in the formation; engaging the formation with a rotary engagement component of the downhole tool having one or more penetrating elements to form a plurality of penetrations in the formation defining a rotational sweep of the rotary engagement component; engaging the formation with an instrumented engagement element positioned on a body of the downhole tool at an engagement radius that is outside of the rotational sweep; and taking one or more measurements with an engagement sensor of the instrumented engagement element based on the instrumented engagement element engaging the formation.

13. The method of claim 12, further comprising engaging a bottom hole of the wellbore with the rotary engagement component and with the instrumented engagement element.

14. The method of claim 12, further comprising logging the one or more measurements to memory with a processor housed in an electronics housing positioned within the body of the downhole tool.

15. The method of claim 12, wherein taking the one or more measurements includes detecting a force on the instrumented engagement element.

16. The method of claim 12, wherein engaging the formation with the instrumented engagement element includes not encountering the plurality of penetrations with the instrumented engagement element.PATENTDocket No. IS24.1679-WO-PCT17. A downhole tool for forming a wellbore in a formation, comprising: a rotary engagement component including one or more penetrating elements for forming a plurality of penetrations in the formation at a penetration depth; a cutting structure formed on a body of the downhole tool having one or more cutting elements positioned thereon for degrading the formation; a lead cutting element of the one or more cutting elements positioned on the cutting structure and positioned to degrade the formation along a rotational path of the lead cutting element and at a depth of cut that is greater than the penetration depth; an instrumented engagement element positioned on the cutting structure and positioned to engage the formation within the rotational path of the lead cutting element at an engagement depth that is greater than the depth of cut; and an engagement sensor connected to electronics for taking one or more measurements associated with the instrumented engagement element engaging the formation.

18. The downhole tool of claim 17, wherein the one or more penetrating elements form the plurality of penetrations defining a rotational sweep of the rotary engagement component, wherein the cutting structure is a blade of the downhole tool, wherein at least a portion of the blade is within the rotational sweep of the rotary engagement component, and wherein the lead cutting element and the instrumented engagement element are positioned on the cutting structure to engage the formation within the rotational sweep of the rotary engagement component.

19. The downhole tool of claim 17, wherein the rotary engagement component is a roller cone.PATENTDocket No. IS24.1679-WO-PCT20. The downhole tool of claim 17, wherein the downhole tool is a hybrid fixed- cutter roller-cone drill bit for drilling the wellbore.

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