Smart triggers for instrumented engagement element

Abstract

A method of operating an instrumented engagement element positioned on a downhole tool, the instrumented engagement element configured for engaging a formation within a wellbore, includes, operating, in a first operation mode, an instrument assembly positioned within a body of the downhole tool, the instrument assembly including the instrumented engagement element, an engagement sensor of the instrumented engagement element, and a processor (510). The method includes monitoring, with one or more sensors of the instrument assembly, one or more downhole parameters within the wellbore (520), the method includes determining a trigger (530) based on identifying a trigger signature in the one or more downhole parameters. The method includes operating the instrument assembly in a second operation mode in response to the trigger (540).

Description

PATENTDocket No. IS24.1676-WOSMART TRIGGERS FOR INSTRUMENTED ENGAGEMENT ELEMENTCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of United States Provisional Patent Application No. 63 / 723,046, 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 method of operating an instrumented engagement element positioned on a downhole tool, the instrumented engagement element configured for engaging a formation within a wellbore, includes, operating, in a first operation mode, an instrument assembly positioned within a body of the downhole tool, the instrument assembly including the instrumented engagement element, an engagement sensor of the instrumented engagement element, and a processor. The method includes monitoring, with one or more sensors of the instrument assembly, one or more downholePATENTDocket No. IS24.1676-WO parameters within the wellbore, the method includes determining a trigger based on identifying a trigger signature in the one or more downhole parameters. The method includes operating the instrument assembly in a second operation mode in response to the trigger. In some embodiments, the method is performed by a computer system. In some embodiments the method is performed as instructions stored on a computer-readable storage medium.

[0005] In some embodiments, a method of taking measurement data within a wellbore for characterizing a formation includes taking one or more first measurements with a first instrumented engagement element positioned on a downhole tool and configured to engage a formation. The first instrumented engagement element is included as part of a first instrument assembly positioned within a body of the downhole tool. The method includes operating a second instrument assembly in a sleep mode. The second instrument assembly is positioned within the body of the downhole tool and includes a second instrumented engagement element positioned on the downhole tool and configured for engaging the formation. The method includes monitoring, with one or more sensors of the second instrument assembly, one or more downhole parameters within the wellbore, and determining a trigger based on identifying a trigger signature in the one or more downhole parameters. The method includes waking the second instrument assembly from the sleep mode based on the trigger, and taking one or more second measurements with the second instrumented engagement element.

[0006] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0007] Additional features and advantages of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and advantages of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in thePATENTDocket No. IS24.1676-WO 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

[0008] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific implementations thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example implementations, the implementations will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

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

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

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

[0012] FIG. 4 illustrates an example implementation of a smart trigger system as described herein, according to at least one embodiment of the present disclosure;

[0013] FIG. 5-1 illustrates a flow diagram for a method or a series of acts for operating an instrumented engagement element as described herein, according to at least one embodiment of the present disclosure;PATENTDocket No. IS24.1676-WO

[0014] FIG. 5-2 illustrates a flow diagram for a method or a series of acts for taking measurement data within a wellbore for characterizing a formation as described herein, according to at least one embodiment of the present disclosure;

[0015] FIG. 6 illustrates certain components that may be included within a computing system;

[0016] FIG. 7-1 is a perspective cutaway view of a downhole tool, according to at least one embodiment of the present disclosure;

[0017] FIGS. 7-2 and 7-3 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;

[0018] FIG. 8 is a side cutaway view of an engagement element housing, according to at least one embodiment of the present disclosure; and

[0019] FIG. 9 is a side cutaway view of an engagement element housing, according to at least one embodiment of the present disclosure.DETAILED DESCRIPTION

[0020] This disclosure generally relates to devices, systems, and methods for instrumented engagement elements. For example, a drilling system may implement one or more tools for engaging a borehole. An instrumented engagement element may be implemented in conjunction with one or more downhole tools and may engage the borehole. The instrumented engagement element may include one or more sensors for taking downhole measurements, such as strain or other measurements, associated with the engagement of the engagement element with the borehole. The observed downhole measurements (or more specifically changes in the observed downhole measurements) may be useful for determining and / or mapping one or more features of the borehole, in at least one embodiment described herein.

[0021] A computer-implemented smart trigger system may be configured to detect various triggers from observable sensor measurements of downhole parameters. Based on the triggers, the smart trigger system may determine anPATENTDocket No. IS24.1676-WO operation mode for an instrument assembly to operate in. For instance, the smart trigger system may indicate when and / or in what manner the instrument assembly operates. In this way, power and / or memory resources of at least one embodiment of the instrument assembly (which may be limited) may be efficiently and / or effectively utilized for taking measurement data for formations of interest, for example, without wasting these resources during unproductive times.

[0022] 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.

[0023] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 may transmit drilling fluid through a central bore and may transmit rotational power from the drill rig 103 to the BHA 106. Rotational power may also be transmitted through one or more mud motors located in the wellbore 102. In some embodiments, the drill string 105 further includes additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0024] 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 toolsPATENTDocket No. IS24.1676-WO 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.

[0025] 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.

[0026] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within 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.

[0027] The drilling system 100 may include one or more instrument assemblies (e.g., instrument assembly 119) which may include an instrumented engagement element for taking measurements based on an engaging the formation 101 in the wellbore 102. For instance, the instrument assembly 119 may be implemented within a body of a downhole tool of the drilling system 100, such as the bit 110. The instrument assembly may include one or more sensors, for example, for taking measurements (such as force) based on an engagement of one or more components of the instrument assembly with the borehole. The instrument assembly may include a smart trigger system 120 implementedPATENTDocket No. IS24.1676-WO thereon. The smart trigger system 120 may facilitate determining one or more triggers for operating the instrument assembly and / or the instrumented engagement element in accordance with the one or more triggers as described herein.

[0028] 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.

[0029] 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.

[0030] 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 borehole. A power supply may provide power to the engagement sensor, and a processor and memory may receive and / or record engagement measurements from the engagement sensor. In this way, the engagement element may engage the borehole, and the instrument assembly may take corresponding measurements (e.g., axial forces and / or other measurements) on the engagement element. The engagement measurements may facilitatePATENTDocket No. IS24.1676-WO creating or generating one or more of a graph, plot, image, and / or map of one or more parameters experienced by the bit 210 in order to illustrate one or more properties and / or features associated with the materials encountered by the bit 210 while forming the borehole.

[0031] FIG. 3 is a side schematic view of an embodiment of an instrument assembly 319 as implemented in a downhole tool 310, according to at least one embodiment of the present disclosure. The downhole tool 310 may be a rotating downhole tool such as a bit, reamer, stabilizer, etc., or may be any other downhole tool which may engage a formation, such as a steering tool. The instrument assembly includes an engagement element 321. The engagement element 321 may be positioned within and at least partially extending from a body 311 of the downhole tool 310. For instance, the engagement element 321 may be positioned and configured to engage a formation based on the downhole tool 310 being positioned and operated within a wellbore. In some embodiments, the downhole tool 310 may include one or more additional engagement elements (e.g., cutting elements). The engagement element 321 may, in some cases, be positioned rotationally behind one or more of these additional engagement elements, (e.g., behind a leading element), such that the engagement element 321 engages a formation (or is exposed to the formation) in a rotational path or cutout of the leading element.

[0032] The engagement element 321 may be configured and implemented in accordance with any of the engagement elements, instrument assemblies, and / or downhole tools as described in any of U.S. Patent Application No. 18 / 664,475, filed May 15, 2024; 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, borehole, formation, etc. For example, the engagement sensor 323 may be a sensor for measuring an amount of force (e.g., a normal or axial component of a force) imparted onto the engagementPATENTDocket No. IS24.1676-WO 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 a formation. 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. 7-1 to 9.

[0033] The engagement element 321 and engagement sensor 323 may be associated with electronics 325 positioned within the body of the downhole tool 310. The electronics 325 may be connected to the engagement sensor 323, for example, for taking and logging measurements with the engagement sensor 323. For instance, the electronics of the instrument assembly 319 may include a processor 325-1 and / or a power source 325-2. The processor 325-1 may be any include any type(s) of processing components such as CPUs, GPUs, etc. The power source 325-2 may be inclusive of any type(s) of power sources, such as batteries, capacitors, inertial power generators, thermal power generators, etc. The electronics 325 may include one or more additional components such 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 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. 6.PATENTDocket No. IS24.1676-WO

[0034] 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 may be an electronics housing which may house, support, position, and / or protect the various electronics 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 representation, and should be understood as conveying that the housing 314 may contain or house the components illustrated therein, but may not necessarily be positioned and / or oriented as indicated in this figure, but rather may be connected to and / or otherwise associated with the engagement element 321 at any position within the body 311 of the downhole tool 310. In this way, the instrument assembly 319 may be positioned, configured, and implemented in a variety of different ways in order to accommodate various features and functionalities of the instrument assembly 319.

[0035] 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. For instance, the instrument assembly may be implemented as part of a bit for taking measurements during drilling with the bit. In some cases, the instrument assembly 319 may be implemented as part of a reamer, stabilizer, engagement pad, piston, or other tool or component that makes contact with the formation. As mentioned, the instrument assembly 319 may be integrated within the body 311PATENTDocket No. IS24.1676-WO of the downhole tool 310 as a separate, independent system that is local to the downhole tool 310. For example, the instrument assembly 319 may include the power source 325-2, processor 325-1 , sensor 323 and other electronic and / or computing components within an interior space or volume of the body 311 , which may not be connected to or in communication with one or more other systems. For instance, the instrument assembly 319 may not be connected to, directed by, administered by, or otherwise associated with another computing system, for example, contained or implemented in another downhole tool such as a BHA, measurement or logging tool, or other sub. In this way, the instrument assembly 319 may be independent and wholly implemented based on the components included as part of the instrument assembly 319.

[0036] In at least one embodiment, one or more functions of the instrument assembly 319 operate in accordance with and / or based on one or more triggers. For instance, a trigger may indicate one or more of a measurement depth of the instrument assembly, an operation state of the downhole tool, any other criteria which should be met in order to perform one or more operations with the instrument assembly 319, or combinations thereof. Trigger-based operation of the instrument assembly 319, in at least one embodiment, in this way may facilitate effectively and efficiently utilizing the memory and / or power resources of the instrument assembly 319. For example, power and / or memory resources may be limited (e.g., due to limited space within the body 311 ), and, in at least one embodiment, it is advantageous to provide a smart system for identifying, via various triggers, one or more of a manner, duration, time, or combinations thereof for the instrument assembly to operate in order to advantageously allocate and utilize the limited electronic and computing resources rather than continually operating these components when measurement data may not be desired. In other examples, some downhole operations, measurement depths of the wellbore, and / or formations may be of particular interest for collecting data while others less so. Accordingly, various triggers may indicate to a smart system when to operate in order to prioritize capturing data in these circumstances of interest.PATENTDocket No. IS24.1676-WO

[0037] As mentioned above, the instrument assembly 319 may include a smart trigger system (e.g., the smart trigger system 120 described in FIG. 1 or the smart trigger system 420 described in FIG. 4) implemented thereon. FIG. 4 illustrates an example implementation of the smart trigger system 420 as described herein, according to at least one embodiment of the present disclosure. The smart trigger system 420, in at least one embodiment, facilitates determining various triggers for advantageously directing the operation of the instrument assembly 319.

[0038] The smart trigger system 420 may include a measurement manager 422, a trigger manager 424, and an operation mode manager 426. The smart trigger system 420 may also include a data storage 430 having measurement data 432 stored thereon. For instance, the measurement manager 422 may be associated with operating a sensor (e.g., engagement sensor 323) and / or other electronics to sample and store measurement data with the engagement element. In some cases, the trigger manager 424 is implemented to monitor for and detect various downhole parameters (e.g., via one or more sensors) and to smartly determine trigger events based on the observed downhole circumstances. The operation mode manager 426 may be tasked with determining and implementing operation modes of the instrument assembly, for example, in accordance with the determined triggers. While these various components 422-426 may be described in accordance with specific features and / or functionalities of the smart trigger system 420, it will be appreciated that specific features described in connection with one component of the smart trigger system 420 may, in some examples, be performed by one or more of the other components of the smart trigger system 420.

[0039] In some embodiments, the smart trigger system 420 is implemented on an electronic and / or computing system of the instrument assembly. For example, some or all of the smart trigger system 420 may be implemented by a processor (e.g., processor 325-1 as described in connection with FIG. 3). In some embodiments, one or more of the features of the smart trigger system 420 may be implemented on or across multiple devices and / or processors, includingPATENTDocket No. IS24.1676-WO individual functions of a specific component being performed across multiple devices. In this way, in at least one embodiment, the smart trigger system 420 may be implemented wholly as a standalone, isolated, local, and / or independent computing system associated with the engagement element and contained within a body of the downhole tool. For example, in some cases, the smart trigger system 420 is not implemented, administered, and / or in communication with one or more other systems, such as one or more other computing or control systems on one or more other downhole tools, subs, assemblies, etc., but rather takes measurements and makes smart decisions as an independent, standalone system. To elaborate, in some cases, the smart trigger system 420 is implemented as described herein wholly by the electronics contained within the downhole tool and is not, for example, connected to or implemented by another computer system within a BHA, logging tool, measurement tool, sub, etc. In some cases, as described herein the smart trigger system 420 may facilitate some communication, for example, with another (e.g., independent) smart trigger system 420 associated with another instrument assembly on the same or other downhole tool.

[0040] The smart trigger system 420 may be implemented to sample and record measurement data associated with an operation of the downhole tool. For example, the engagement element may be utilized to engage a formation and to measure forces exerted on the engagement element via this engagement, such as with an associated strain gauge. For example, the measurement data 432 may include strain measurements associated with axial or normal forces acting on the engagement element as the engagement element engages a formation. The instrument assembly may include any of a number of different sensors for taking any of a number of different types of measurement data. Accordingly, the instrument assembly may be implemented to collect valuable downhole data that may be useful in characterizing a downhole formation or subsurface feature, among other objectives.

[0041] The smart trigger system 420 may facilitate implementing one or more operation modes of the instrument assembly. For example, the instrumentPATENTDocket No. IS24.1676-WO assembly may be configured to perform various operations, take various measurements and / or measurement types, etc., which may be accomplished via the different operation modes. In some embodiments, the various operation modes may facilitate efficiently and effectively utilizing memory and / or power resources of the instrument assembly.

[0042] For example, in at least one embodiment, it is advantageous to make a smart decision regarding when to operate and when not to operate the instrument assembly. For instance, it may be desirable to specifically utilize the instrument assembly to take measurements at a specific location in a wellbore, of a specific formation, and / or for a specific duration (or several specific durations). To elaborate, it may be inefficient and / or detrimental for the instrument assembly, in at least one embodiment, to continually take and / or log measurement data for an entirety of a drilling trip or operation, but rather, in at least one embodiment, it is beneficial to prioritize implementing the instrument assembly for specific portions of a drilling operation, while not prioritizing (or even skipping) others. For instance, it may not be worthwhile to log measurements during a trip in or trip out duration, during a fluid circulation duration, or during other durations of a downhole operation, but rather the resources of the instrument assembly may better be utilized for taking measurements while the downhole tool is being used for engaging the formation, such as during drilling. In this way, the power and / or memory resources of the instrument assembly, in at least one embodiment, is more advantageously used to take measurements associated with engaging the formation without wasting these resources during non-productive periods.

[0043] In some embodiments, the instrument assembly may be configured to operate in a sleep mode. For instance, in the sleep mode, the instrument assembly may conserve power by reducing one or more functionalities to a minimal state, such as by maintaining only essential processes to monitor for triggers as described herein. This may facilitate extending battery life, for example during durations in which the instrument assembly is not needed for taking measurements with the engagement element. In a particular example, thePATENTDocket No. IS24.1676-WO instrument assembly may be operated initially (e.g., from surface) in a sleep mode, so as to conserve power (e.g., battery) and memory resources through a trip in duration until the downhole tool is positioned and situated to engage the formation. In some embodiments, the instrument assembly may operate in the sleep mode after one or more other operation modes or operations, such as by the smart trigger system 420 identifying one or more triggers as described herein.

[0044] In some cases, in the sleep mode, the instrument assembly may monitor one or more sensors in order to detect triggers. For instance, the instrument assembly may periodically check one or more sensors and / or sensor measurements. In some embodiments, the smart trigger system 420 may operate on the instrument assembly in a low power mode in order to monitor sensor data for triggers. For example, in some cases, one or more sensors of the instrument assembly may operate in accordance with low power signal driven acquisition (LPSDA). For example, rather than more actively and / or directly monitoring sensor data with the smart trigger system 420 (e.g., continuously and / or periodically sampling and processing sensor signals), the smart trigger system 420 may remain in a low power state and may be driven to respond only when there is a significant or threshold change event in the signal. This may reduce the power consumption by reducing unnecessary processing.

[0045] In some embodiments, the instrument assembly may be prompted to wake up from the sleep mode. For instance, the instrument assembly may wake up to a standby mode, in which one or more functionalities and / or processes is restored and / or in which the instrument assembly awaits an instruction to begin sampling and / or logging.

[0046] In some embodiments, the instrument assembly may be configured to operate in a sampling mode. The sampling mode may correspond with the instrument assembling taking one or more measurements as described herein. For example, in the sampling mode, the instrument assembly may take measurements associated with the formation based on the engagement element engaging the formation as described herein. In some embodiments, the instrument assembly may be directed to stop operating in the sampling mode,PATENTDocket No. IS24.1676-WO such as based on a detected trigger. For instance, the trigger may indicate for the instrument assembly to transition back to the standby mode.

[0047] In some embodiments, the instrument assembly may be configured to operate in a logging mode. The logging mode may correspond with the instrument assembly both taking one or more measurements, as well as logging those measurements to memory. In some embodiments, the instrument assembly may be prompted to stop operating in the logging mode (e.g., via a trigger), such as by transitioning back to the sampling mode, back to a standby mode, or another operation mode.

[0048] In some embodiments, the instrument assembly may be configured to operate in a calibration mode. For example, in some cases, the instrument assembly may perform a calibration or zeroing operation of one or more sensors, such as of the engagement sensor. For instance, in some cases the engagement element may wear, may develop buildup, or the engagement sensor may otherwise become attenuated, biased, or out of calibration. In other examples, a downhole pressure may change (e.g., increase) based on the downhole tool advancing further into the earth, and a baseline pressure acting on the engagement element may affect the engagement sensor measurements. Accordingly, the calibration mode may facilitate maintaining accurate measurements with one or more sensors.

[0049] In this way, the smart trigger system 420 may direct the instrument assembly to operate in any of a variety of operation modes, including switching between operation modes. Selectively implementing various operations modes in this way facilitates, in at least one embodiment, tailoring the allocation of power and / or memory resources to utilize these resources in advantageous situations. For instance, by making smart decisions about when to sleep and when to sample and / or log, the smart trigger system 420 can avoid needlessly expending power and / or memory resources during durations of a downhole operation in which the engagement element may not be engaging the formation (e.g., one or more of tripping or traveling durations, circulation durations, other durations, or combinations thereof). Additionally, the various operation modes may facilitatePATENTDocket No. IS24.1676-WO taking measurements of a specific subsurface formation, feature, structure, other subsurface characteristic, of interest, or combinations thereof, for example, while advantageously not taking measurements of one or more other features (e.g., which may preserve power and / or memory).

[0050] In at least one embodiment, determining a certain type of measurement to take with the instrument assembly with the smart trigger system 420 is advantageous. For example, in some cases, one or more subsurface formations, features, structures, other characteristics, or combinations thereof at a particular measurement depth may be of particular interests for taking a specific type of measurement with a specific type of sensor. Accordingly, the smart trigger system 420 may determine, based on one or more triggers, to collect and record measurement data with a specific sensor included in or associated with the instrument assembly. In another example, one or more subsurface formations, features, and / or structures at a particular measurement depth may specifically be of interest for collecting high quality and / or high-resolution data, and other formations may be of less interest. Accordingly, in some cases, the smart trigger system 420 may determine, based on one or more triggers, to collect and record measurement data at a specific sampling frequency, for instance based on the level of detail or resolution desired for a specific formation.

[0051] As mentioned above, the smart trigger system 420 may operate to detect, identify and / or determine one or more triggers for informing smart decisions about various operation modes to implement with the instrument assembly. For example, the smart trigger system 420 may monitor continuously, intermittently, and / or passively (e.g., through LPSDA techniques) sensor signals from one or more sensors included in the instrument assembly. These sensors may measure certain observable conditions or downhole parameters, which may serve as the basis for the smart trigger system 420 identifying certain trigger signatures in the downhole parameters as triggers. For instance, the instrument assembly may include one or more of an accelerometer, a gyroscope, a magnetometer, a temperature sensor, the engagement sensor, or any other sensor, instrument, or gauge. The smart trigger system 420 may observe orPATENTDocket No. IS24.1676-WO monitor the downhole parameters via any of these sensors in order to identify one or more triggers.

[0052] In some embodiments, the downhole parameters include a downhole pressure. For example, the wellbore and / or an annular space may be at least partially filled with a flow of a downhole fluid, which may exhibit a hydrostatic pressure. The smart trigger system 420 may observe or measure the downhole pressure via the engagement sensor and the engagement element. For example, in cases where the downhole tool is off bottom or is not engaging the wellbore bottom hole, the engagement sensor may be sensitive to the hydrostatic pressure acting on the engagement element. The engagement sensor may accordingly register a baseline (e.g., strain) measurement which may correspond with the applied hydrostatic pressure at that measurement depth. In some embodiments, the instrument assembly may include a dedicated pressure sensor, for example, apart from the engagement sensor.

[0053] In some embodiments, the downhole parameters include an applied force on the engagement element. For instance, based on the engagement element engaging the formation, the engagement sensor may detect a force (e.g., via an associated strain) on the engagement element.

[0054] In some embodiments, the downhole parameters include a shock and / or vibration of the downhole tool. For example, based on movement of the downhole tool (e.g., during engagement with the formation, during transit, etc.) and / or of the drill string, an accelerometer may detect various shocks and / or vibrations.

[0055] In some embodiments, the downhole parameters include a rotation of the downhole tool. For example, a magnetometer (and / or accelerometer) may detect a direction, speed, and / or changes thereof to a rotation of the downhole tool.

[0056] In some embodiments, the downhole parameters include a temperature. For instance, a temperature sensor may be situated in, at, or near the engagement element, or otherwise included as part of the electronics of thePATENTDocket No. IS24.1676-WO instrument assembly housed within the downhole tool. Accordingly, the temperature sensor may measure a temperature of the engagement element, and / or an internal temperature of the body of the downhole tool. The temperature measurement may be based on an ambient (e.g., annular) temperature, and / or based on the engagement of the engagement element with the formation.

[0057] In some embodiments, the downhole parameters include an inclination of the downhole tool. For example, a gyroscope may determine an angle with respect to the surface, with respect to horizontal, or with respect to another reference. For instance, this may facilitate identifying an inclination and / or directionality of the wellbore, such as to identify a vertical section, inclined section, horizontal section, etc.

[0058] Based on observing one or more of the downhole parameters, the smart trigger system 420 may determine one or more triggers for informing a smart decision about an operation mode of the instrument assembly. For example, the smart trigger system 420 may identify a trigger signature of the downhole parameters which may correspond with a particular trigger for operating the instrument assembly in a particular manner. For instance, a trigger signature may be a downhole parameter above, below, or at a specified threshold value. In another example, a trigger signature may be associated with a specified duration of time in which a downhole parameter is observed at a particular value. In another example, a trigger signature may be a change or variation of a downhole parameter of a threshold amount, to a threshold value, with a threshold standard deviation, or in accordance with a particular modulation or pattern which may indicate a trigger event. For example, the trigger signature may be identifiable based on any frequency content within a frequency of rotation of the downhole tool.

[0059] In some embodiments, the smart trigger system 420 identifies a trigger based on a trigger signature of the force downhole parameter. For instance, in at least one embodiment, it is advantageous to know when the engagement element is engaging the formation. The smart trigger system 420 may identify when the force measurements on the engagement element surpass a thresholdPATENTDocket No. IS24.1676-WO value and / or for a threshold duration of time. In this way, the smart trigger system 420 may determine, as a trigger, that the downhole tool is engaging the formation (e.g., drilling), for instance, as opposed to a transit operation, fluid circulation operation, etc., of the wellbore.

[0060] In some embodiments, the smart trigger system 420 identifies a trigger based on a trigger signature of the pressure downhole parameter. For instance, the hydrostatic pressure observed via the engagement sensor as a baseline (e.g. , strain) measurement may increase with an increase in depth as the columnar pressure of the drilling fluid exerts an increasing amount of force over the area of the engagement element. Accordingly, based on the observed downhole pressure, the smart trigger system 420 may identify a trigger associated with an estimated depth of the downhole tool. For example, the smart trigger system 420 may be pre-programed, or else may be equipped to calculate, an estimate of the depth below the surface based on the observed downhole pressure.

[0061] In some cases, the smart trigger system 420 identifies a trigger based on a trigger signature of a pattern of the downhole pressure. For example, in some cases, a formation integrity test may be performed in the wellbore for assessing the strength of the geological formation around the wellbore. During testing, the downhole pressure may be increased and maintained and / or prolonged for one or more durations and / or at one or more pressures, after which the pressure may be released. The smart trigger system 420, by monitoring the downhole pressure, may identify a pattern in the downhole pressure corresponding with a formation integrity test, and may accordingly determine a corresponding trigger. For instance, in some cases the formation integrity test may be followed by a drilling operation and the smart trigger system 420 may accordingly implement one or more operation modes based on this information.

[0062] In some embodiments, the smart trigger system 420 identifies a trigger based on a trigger signature of the rotation downhole parameter. For example, by identifying that the downhole tool is rotating, the smart trigger system 420 may determine a particular operation of the downhole tool, such as drilling. This mayPATENTDocket No. IS24.1676-WO facilitate distinguishing between transit, circulation, steering (e.g., sliding), or other operations, for instance, in which the downhole tool may not rotate.

[0063] In some embodiments, the smart trigger system 420 identifies a trigger based on a trigger signature of the shock and / or vibration downhole parameter. For instance, certain downhole operations, conditions, situations, etc., may be associated with certain known and / or observable shocks and / or vibrations. For instance, by identifying shocks and / or vibrations of a threshold degree and / or for a threshold duration, the smart trigger system 120 may determine that the downhole tool is performing a certain downhole operation, such as drilling, reaming, steering, etc. Similarly, shocks and / or vibrations at or below a threshold degree (e.g., or the absence thereof) may indicate one or more other operations of the downhole tool, such as transit, circulation, etc.

[0064] In some embodiments, the smart trigger system 120 identifies a trigger based on a trigger signature of the inclination downhole parameter. For example, based on the measured inclination, the smart trigger system 420 may determine a certain section of the wellbore where the downhole tool is positioned, which may facilitate informing an operation mode of the instrument assembly. For instance, a vertical (or substantially vertical) inclination may be associated with a formation that is of less interest for taking measurements, and a non-vertical (e.g. , horizontal) inclination may indicate that the downhole tool is positioned in and / or engaging a formation of particular interest, such as a formation containing a reservoir. In another example, a vertical inclination may indicate that the downhole tool is in transit through a vertical portion of the wellbore, for example, rather than at the wellbore hole bottom.

[0065] In some embodiments, the smart trigger system 420 identifies a trigger based on a trigger signature of the temperature downhole parameter. For example, a temperature at or above a threshold level may indicate that the downhole tool is engaging the formation, which may typically result in elevated downhole temperatures. In another example, a temperature of a given value or threshold may indicate a circulation operation, which may tend to reducePATENTDocket No. IS24.1676-WO temperatures, for example, to a steady state value of a temperature of the downhole fluid being circulated.

[0066] In some embodiments, the smart trigger system 420 identifies a trigger based on a time duration. For example, the smart trigger system 420 may record or determine an elapsed time from a previous operation, previous trigger, or other event.

[0067] In this way, the smart trigger system 420 may determine any number of different triggers based on observable trigger signatures in the downhole parameters. Based on identifying one or more triggers, the smart trigger system 420 may make a smart determination regarding a particular operation mode to implement for the instrument assembly. For example, the decision of the smart trigger system 420 may be a smart decision in that the smart trigger system 420 may determine and execute an operation mode based solely on the observations, measurements, triggers, and / or other information that is available to the smart trigger system 420 as implemented as a standalone, independent, and / or isolated system within the body of the downhole tool. For instance, in some cases, the smart trigger system 420 may not be instructed via communication from one or more other control systems, for example, such as that positioned in or at a BHA, a measurement or logging tool, or other sub or tool. The smart trigger system 420 may determine to implement any of the operation modes (including combinations) described herein based on any trigger (or combination of multiple triggers).

[0068] By way of illustrative example, in some embodiments the smart trigger system 420 may operate the instrument assembly in a sleep mode at one or more instances in order to conserve power and memory. For example, the instrument assembly may be initiated in the sleep mode at the surface, and may maintain the sleep mode until the smart trigger system 420 detects one or more triggers prompting the instrument assembly to wake up from the sleep mode. For instance, in at least one embodiment, it is advantageous that the instrument assembly utilizes minimal power and / or memory while the downhole tool is being tripped into the wellbore, for example, from the surface to the wellbore bottom hole. It may be of particular interest that the instrument assembly takePATENTDocket No. IS24.1676-WO measurements with the engagement sensor when the downhole tool is being operated to engage the formation, for example, so as to take measurements of the formation for capturing and characterizing one or more features therein. Accordingly, the smart trigger system 420 may monitor for one or more triggers which may indicate that the downhole tool is at the wellbore bottom hole and / or is operating to engage the formation (e.g., drilling). In this way, the instrument assembly may know when to begin sampling and logging measurement data. For instance, based on the smart trigger system 420 identifying any of the triggers associated with force, pressure, shock / vibration, temperature, rotation, or time, the smart trigger system 420 may make a smart decision that the downhole tool is engaging the formation, and may accordingly only operate the instrument assembly to take measurements once engagement has commenced. In this way, the memory and / or power resources of the instrument assembly may be more effectively allocated for moments or durations which are of particular interest for taking measurements.

[0069] In some embodiments, the ability to adjust sampling frequency based on real-time drilling parameters may provide additional operational efficiency. For example, lower RPM may correspond to slower circumferential coverage of the borehole, meaning fewer samples are needed per unit time to maintain the same angular resolution. Similarly, higher RPM may require higher sampling frequencies so that features around the borehole are not undersampled. Similarly, for axial progression, low ROP allows a reduced sampling frequency without loss of vertical resolution, whereas high-ROP intervals may require an increased sampling rate to ensure that lithological boundaries, fractures, or anomalies are captured with adequate fidelity. Accordingly, adaptive sampling based on RPM and / or ROP may further extends the usable operational life of the instrument assembly while maintaining high-quality spatially correlated datasets.

[0070] In some cases, an engagement operation of the downhole tool in this way may be intermittent, and / or may proceed through various discrete or separated time intervals. Accordingly, the smart trigger system 420 may identify triggers associated with the engagement operation of the downhole tool stoppingPATENTDocket No. IS24.1676-WO or ceasing, and may accordingly change an operation mode of the instrument assembly to stop sampling and / or logging measurements, such as to a standby mode or a sleep mode, which may further prolong the power and memory resources.

[0071] In this way, the smart trigger system 420 may facilitate implementing the instrument assembly in a limited space within the body of the downhole tool notwithstanding the associated limit to the power and memory resources. For example, in some cases the instrument assembly may be configured to operate for about 60 hours, about 120 hours, or about 200 hours (or any value therebetween) of measurement and logging time (e.g., not necessarily continuous elapsed time, but a total of discrete segments of usage). The amount of elapse time of the entirety of a downhole operation (e.g. , starting at the surface to completing the downhole operation) may exceed the operational time capabilities of the instrument assembly such that the instrument assembly may not be capable of continually logging through the entirety of the downhole operation. Accordingly, the smart trigger system 420 may leverage the observable downhole conditions to smartly determine, locally at the instrument assembly, when and how to operate the instrument assembly such that the durations of interest of a downhole operation may be characterized through the measurements of the instrument assembly notwithstanding the time limit capabilities of the instrument assembly. For instance, by implementing the smart trigger system 420 and operating the instrument assembly as described herein, up to 30%, 40%, 50%, or 60% (or any value therebetween) more of the power and / or memory resources may be utilized for taking relevant measurements of a formation of interest, for example, as opposed to these resources be wasted on otherwise unproductive portions or duration of a downhole operation (e.g., nondrilling durations).

[0072] In some embodiments, the smart trigger system 420 may make smart operational decisions based on detecting and considering multiple triggers. For example, in some cases, the smart triggers system 420 may determine, based on a first trigger, an operational state of the downhole tool, and may corroboratePATENTDocket No. IS24.1676-WO or validate the determined operational state based on one or more additional triggers. For example, the smart trigger system 420 may identify that, based on the force on the engagement element, the downhole tool is engaging the formation as part of an engagement operation. The smart trigger system 420 may validate that this determination is correct based on one or more triggers indicating that the downhole tool is rotating, that the downhole tool is experiencing corresponding shock and / or vibration, that the temperature is at or within an expected threshold, that the force is observed for a threshold duration of time, that the downhole tool is at a corresponding measurement depth, or other trigger condition (and combinations thereof). In this way, the smart trigger system 420 may leverage multiple triggers for ensuring that the determined circumstances reflect the actual circumstances.

[0073] In some embodiments, the smart trigger system 420 may make smart operational decisions based on detecting and considering multiple triggers, for example, as part of a logic or progression for implementing an operation mode. For example, one or more triggers may serve as checkpoints or thresholds, and a certain operation mode (e.g., sampling and logging) may only be implemented in response to a given trigger after or to the extent that the checkpoints or thresholds are satisfied. For example, it may be desirable to take and log measurement data associated with a second formation that is below a first formation. Accordingly, the smart trigger system 420 may not indicate for the instrument assembly to take and log measurement data until a certain depth threshold has been reached, in order to prioritize the measurement of the second formation. In another example, the smart trigger system 420 may not check for certain triggers (e.g., a drilling trigger) until after a certain depth threshold has been reached, which may reduce the chances of a false positive of rotation, shock, vibration, etc. prematurely indicating an engagement operation has begun (e.g., before reaching the hole bottom, such as during transit).

[0074] In another example, it may be desirable to collect only a certain amount of measurements for a given formation, and the smart trigger system 420 may implement the sampling and logging operation mode for a limited time periodPATENTDocket No. IS24.1676-WO based on a time duration trigger. In some embodiments, it may be desirable to take measurement data at different frequencies. For example, it may be desirable to take and log measurements at a first sampling frequency for a first formation, and take and log measurements at a second sampling frequency for a second formation, for example, to collect higher-resolution data for a particular formation of interest but not for others. Accordingly, the smart trigger system 420 may, based on a trigger of an engagement operation of the downhole tool, begin taking and logging measurements, and may alter or change the sampling frequency as needed based on a depth trigger indicating the transition between the first and second formations.

[0075] In some embodiments, the smart trigger system 420 is configured to dynamically adjust the sampling frequency of the instrument assembly based on one or more real-time drilling parameters. For example the rotation rate may be adjusted based on a rotation rate (RPM) of the downhole tool. In some embodiments, the RPM may be determined locally using one or more of an accelerometer, gyroscope, or magnetometer included within the instrument assembly. In some embodiments, base on the measured RPM, the sampling frequency may be increased when the downhole tool is rotating faster, and may be decreased when the downhole tool is rotating slower. In this way, measurement data may be captured with sufficient temporal resolution corresponding to a distance or rotation that the downhole tool covers with (or between) each sample. In this way power and / or memory resources may not be unnecessarily consumed.

[0076] In another example, the smart trigger system 420 may adjust the sampling frequency based on a rate of penetration (ROP). In some embodiments, ROP may not be directly measurable by a single instrument assembly, and the instrument assembly may infer or receive the ROP through one or more mechanisms. In one embodiment, a surface system may convey ROP (or other drilling parameters) to the instrument assembly via downlinks, such as pressurepulses, RPM modulation sequences, or other low-bandwidth telemetry recognizable by the onboard sensors. In another embodiment, two or morePATENTDocket No. IS24.1676-WO instrument assemblies positioned at axially spaced locations on the same downhole tool or BHA may exchange data, for example using low-power acoustic or magnetic communication. By correlating the timestamps and measurement signatures associated with the same formation features (e.g., similar force / strain signatures from a bed boundary, fracture, or lithology transition), the assemblies may determine a relative time shift between the events and thus calculate an estimated ROP using the known spacing between the instrument assemblies.

[0077] Based on the determined or inferred ROP, the smart trigger system 420 may reduce sampling frequency during periods of slow progression through a formation to conserve power and memory, and may increase sampling frequency during periods of rapid advancement to ensure that sufficient vertical-resolution data is collected and valuable formation transitions are not missed. In this way, allows the system may adaptively adjust the sampling frequency to allocate limited power and storage resources.

[0078] In another example, it may be desirable to only take and log measurement data for a portion of the wellbore that is inclined or horizontal through a formation, which may correspond with a reservoir or other underground target. Accordingly, the smart trigger system 420 may only respond to a trigger indicating an engagement operation of the downhole tool to the extent that an inclination threshold is satisfied. The smart trigger system 420 may incorporate any number of triggers and in connection with any logic, progression, threshold, or otherwise in order to make sophisticated, smart determinations about when and how to operate the instrument assembly.

[0079] In some embodiments, multiple instrument assemblies may be implemented simultaneously within the wellbore. For example, the multiple instrument assemblies may be implemented in the same downhole tool. In another example, multiple instrument assemblies may be implemented in different downhole tools that may be adjacent or proximate, such as within a same BHA. Each of the multiple instrument assemblies may be controlled as described herein via a separate instance of the smart trigger system 420.PATENTDocket No. IS24.1676-WO

[0080] In some embodiments, when two or more instrument assemblies are positioned at different axial locations along a downhole tool or BHA, the assemblies may communicate measurement summaries or trigger timestamps to each other. In some embodiments, each instrumented engagement element may encounter the same formation structures at different times, and the time offset between the corresponding measurement signatures may be used to determine an estimated ROP based on the known axial spacing of the instrument assemblies. Such correlations may be performed locally by either instrument assembly without requiring surface communication.

[0081] In some embodiments, the multiple instrument assemblies may be implemented to take similar, simultaneous, and / or redundant measurement data, for instance, to provide a more robust characterization of the formation. For instance, multiple engagement elements may be positioned at different engagement radii so as to provide characterizations of different radial portions of the formation.

[0082] In some embodiments, the multiple instrument assemblies may be implemented in order to provide a prolonged operation time over that which a single instrument assembly may provide. For instance, a first instrument assembly may be operated during a first stage of a downhole operation, and at or near a point where the power and / or memory resources of the first instrument assembly are exhausted, a second instrument assembly may be activated to continue collecting measurement data. For instance, the second instrument assembly may be configured to wake up, activate, and / or take and log measurement data when the first instrument assembly has exhausted 60%, 70%, 80%, 90%, 95%, or 99% (or any value therebetween) of its power and / or memory resources. In some embodiments, one or more instrument assemblies may be activated based on a time threshold and / or a depth threshold to activate after an active period of one or more previous instrument assemblies.

[0083] In some embodiments, a second instrument assembly having a second smart trigger system 420 implemented thereon may determine, based on one or more triggers and / or associated logic when to activate, wake up, and / or beginPATENTDocket No. IS24.1676-WO collecting measurement data. For example, the second instrument assembly may be configured to not respond to triggers for a certain duration of time, after which it may begin to operate as described herein. In another example, the second smart trigger system 420 may identify and determine the same triggers as the first smart trigger system 420 for the purposes of estimating the remaining power and / or memory of the first instrument assembly. For example, the second smart trigger system 420 may detect, but may not respond and / or operate based on the identified triggers, but instead may determine (e.g., estimate or predict) how the first smart trigger system 420 is behaving (e.g., responding to the detected triggers) in order that it may estimate to what extent the power and memory resources of the first instrument assembly are being utilized. After the second smart trigger system 420 determines that the power and / or memory resources of the first instrument assembly are exhausted to a threshold degree, the second smart trigger system 420 may begin to operate as described herein and may accordingly implemented various operation modes of the second instrument assembly in response to identified triggers.

[0084] In some embodiments, the instrument assemblies may be equipped with one or more communication components. For example, one or more of the instrument assemblies may be equipped with a wireless transmitter and / or receiver (e.g., sonic, acoustic, radio, etc), which may emit an acoustic pulse, signal, flag, alert, or other indication to be received by one or more other instrument assemblies. In this way, a first instrument assembly may indicate to a second instrument assembly, through a simple and low-power means, to wake up and / or to begin taking and logging measurement data. For example, the first instrument assembly may communicate in this way based on its power and / or memory resources being exhausted to a threshold degree.

[0085] In this way, multiple instrument assemblies may be implemented in conjunction to extend the usable life over that of a single instrument assembly. For instance, the multiple instrument assemblies may be configured to activate according to any of the techniques described herein in a cascading, sequential, and / or serial manner.PATENTDocket No. IS24.1676-WO

[0086] FIG. 5-1 illustrates a flow diagram for a method 500 or a series of acts for operating an instrumented engagement element as described herein, according to at least one embodiment of the present disclosure. While FIG. 5-1 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 5-1 . In some embodiments, the acts of FIG. 5-1 are performed as a method. In some embodiments, the acts of FIG. 5-1 are performed by a computer system, in some embodiments, the acts of FIG. 5-1 are performed as instruction stored on a computer-readable storage medium.

[0087] In some embodiments, the method 500 includes an act 510 of operating, in a first operation mode, an instrument assembly positioned within a body of the downhole tool, the instrument assembly including the instrumented engagement element, an engagement sensor of the instrumented engagement element, and a processor.

[0088] In some embodiments, the method 500 includes an act 520 of monitoring, with one or more sensors of the instrument assembly, one or more downhole parameters observable within the wellbore.

[0089] In some embodiments, the method 500 includes an act 530 of determining a trigger based on identifying a trigger signature in the one or more downhole parameters.

[0090] In some embodiments, the method 500 includes an act 540 of operating the instrument assembly in a second operation mode in response to the trigger.

[0091] In some embodiments, the one or more downhole parameters is a force on the instrumented engagement element as measured by the engagement sensor and the trigger signature is the force over a threshold amount.

[0092] In some embodiments, the trigger signature is the force over the threshold amount for a threshold duration.PATENTDocket No. IS24.1676-WO

[0093] In some embodiments, the force on the instrumented engagement element corresponds with an engagement operation of the downhole tool.

[0094] In some embodiments, the first operation mode is a sleep mode and wherein operating the instrument assembly in the second operation mode includes waking the instrument assembly up from the sleep mode.

[0095] In some embodiments, operating the instrument assembly in the second operation mode includes taking and logging one or more measurements with the instrumented engagement element.

[0096] In some embodiments, the method further includes engaging the formation with the instrumented engagement element to take the one or more measurements.

[0097] In some embodiments, waking the instrument assembly up from the sleep mode is based on the trigger indicating an engagement operation of the downhole tool based on a threshold force observed on the instrumented engagement element by the engagement sensor.

[0098] In some embodiments, the one or more downhole parameters is a downhole pressure as measured with the engagement sensor, and the trigger is a measurement depth of the downhole tool based on the downhole pressure.

[0099] In some embodiments, the one or more downhole parameters is shock or vibration of the downhole tool, and wherein the trigger signature is a shock or vibration corresponding with an engagement operation of the downhole tool.

[0100] In some embodiments, the one or more sensors of the instrument assembly includes an accelerometer, and the shock or vibration is measured by the accelerometer.

[0101] In some embodiments, the one or more downhole parameters is a rotation of the downhole tool, and wherein the trigger signature is a rotation corresponding with an engagement operation of the downhole tool.PATENTDocket No. IS24.1676-WO

[0102] In some embodiments, the one or more sensors of the instrument assembly includes a magnetometer, and the rotation is measured by the magnetometer.

[0103] In some embodiments, the one or more downhole parameters is a temperature associated with the instrumented engagement element, and wherein the trigger signature is a temperature over a threshold degree corresponding with an engagement operation of the downhole tool.

[0104] In some embodiments, the one or more sensors of the instrument assembly includes a temperature sensor positioned in the instrumented engagement element, and the temperature is measured by the temperature sensor.

[0105] In some embodiments, the downhole tool is a bit.

[0106] In some embodiments, the instrument assembly is an independent system that is not in communication with one or more other control systems.

[0107] FIG. 5-2 illustrates a flow diagram for a method 501 or a series of acts for taking measurement data within a wellbore for characterizing a formation as described herein, according to at least one embodiment of the present disclosure. While FIG. 5-2 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 5-2. In some embodiments, the acts of FIG. 5-2 are performed as a method. In some embodiments, the acts of FIG. 5-2 are performed by a computer system, in some embodiments, the acts of FIG. 5-2 are performed as instruction stored on a computer-readable storage medium.

[0108] In some embodiments, the method 501 includes an act 550 of taking one or more first measurements with a first instrumented engagement element positioned on a downhole tool and configured to engage a formation, wherein the first instrumented engagement element is included as part of a first instrument assembly positioned within a body of the downhole tool.PATENTDocket No. IS24.1676-WO

[0109] In some embodiments, the method 501 includes an act 560 of operating a second instrument assembly in a sleep mode, the second instrument assembly being positioned within the body of the downhole tool and including a second instrumented engagement element positioned on the downhole tool being configured for engaging the formation.

[0110] In some embodiments, the method 501 includes an act 570 of monitoring, with one or more sensors of the second instrument assembly, one or more downhole parameters observable within the wellbore.

[0111] In some embodiments, the method 501 includes an act 580 of determining a trigger based on identifying a trigger signature in the one or more downhole parameters.

[0112] In some embodiments, the method 501 includes an act 590 of waking the second instrument assembly from the sleep mode based on the trigger.

[0113] In some embodiments, the method 501 includes an act 591 of taking one or more second measurements with the second instrumented engagement element.

[0114] In some embodiments, the trigger is associated with one or more of a memory resource or a power resource of the first instrumented engagement element being exhausted to a threshold degree.

[0115] In some embodiments, the method further includes engaging the wellbore with the first instrumented engagement element and the second instrumented engagement element.

[0116] In some embodiments, the method further includes engaging the wellbore with the second instrumented engagement element while the second instrument assembly is in the sleep mode.

[0117] In some embodiments, the one or more sensors of the second instrument assembly include one or more of an accelerometer, a gyroscope, temperature sensor, or a magnetometer positioned within the body of the downhole tool.PATENTDocket No. IS24.1676-WO

[0118] In some embodiments, the downhole tool is a bit.

[0119] In some embodiments, the first instrument assembly and the second instrument assembly are each independent systems that are not in communication with one or more other control systems.

[0120] Turning now to FIG. 6, this figure illustrates certain components that may be included within a computer system 600. One or more computer systems600 may be used to implement the various devices, components, and systems described herein.

[0121] The computer system 600 includes a processor 601. The processor601 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 601 may be referred to as a central processing unit (CPU). Although just a single processor 601 is shown in the computer system 600 of FIG. 6, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

[0122] The computer system 600 also includes memory 603 in electronic communication with the processor 601 . The memory 603 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.

[0123] 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 allowsPATENTDocket No. IS24.1676-WO 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 purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.

[0124] Instructions 605 and data 607 may be stored in the memory 603. The instructions 605 may be executable by the processor 601 to implement some or all of the functionality disclosed herein. Executing the instructions 605 may involve the use of the data 607 that is stored in the memory 603. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 605 stored in memory 603 and executed by the processor 601 . Any of the various examples of data described herein may be among the data 607 that is stored in memory 603 and used during execution of the instructions 605 by the processor 601 .

[0125] A computer system 600 may also include one or more communication interfaces 609 for communicating with other electronic devices. The communication interface(s) 609 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 609 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.

[0126] The communication interfaces 609 may connect the computer system 600 to a network. A “network” or “communications network” may generally bePATENTDocket No. IS24.1676-WO 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 computerexecutable instruction or data structures and which can be accessed by a general purpose or special purpose computer.

[0127] A computer system 600 may also include one or more input devices 611 and one or more output devices 613. Some examples of input devices 611 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 613 include a speaker and a printer. One specific type of output device that is typically included in a computer system 600 is a display device 615. Display devices 615 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 617 may also be provided, for converting data 607 stored in the memory 603 into one or more of text, graphics, or moving images (as appropriate) shown on the display device 615.

[0128] The various components of the computer system 600 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. 6 as a bus system 619.

[0129] 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,PATENTDocket No. IS24.1676-WO 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.

[0130] 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.

[0131] FIGS. 7-1 through 9 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 operation mode system as described herein.

[0132] FIG. 7-1 is a perspective cutaway view of a downhole tool 710 according to at least one embodiment of the present disclosure. In some embodiments, the downhole tool 710 is a bit, but the downhole tool 710 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 somePATENTDocket No. IS24.1676-WO embodiments, the downhole tool 710 includes an instrument assembly 719. The instrument assembly may include an engagement element assembly 720 that connects to an electronics housing 714. In some embodiments, the engagement element assembly 720 removably connects to the electronics housing 714. In other words, the engagement element assembly 720 may not be permanently attached to the downhole tool 710, for example, by brazing the engagement element assembly 720 (and / or an engagement element of the engagement element assembly 720) to the downhole tool 710 as is conventionally done. In this way, the engagement element assembly 720 may be selectively connected to and / or removed from the downhole tool 710. In at least one embodiment, this may facilitate incorporating electronics 725 and / or a sensor 723 into the downhole tool 710. For example, the electronics 725 may be installed into the electronics housing 714 and connected to the sensor 723, after which the engagement element assembly 720 may be connected to the electronics housing 714 to complete the installation of the instrument assembly 719. This may facilitate implementing and / or replacing sensing and / or measurement devices such as those included in the instrument assembly 719 by significantly simplifying the implementation of such devices in the downhole tool 710, in at least one embodiment.

[0133] In some embodiments, the engagement element assembly 720 includes an instrumented engagement element 721. The instrumented engagement element 721 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 721 may be configured to engage the borehole, such as a cutting element. For example, the instrumented engagement element 721 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,PATENTDocket No. IS24.1676-WO 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. In yet other embodiments, the ultrahard material has a hardness value greater than 80 HRa (Rockwell hardness A). In some examples, the instrumented engagement element 721 is formed from any other material including metals, metallic alloys, ceramic materials, any other material, and combinations thereof.

[0134] The engagement element assembly 720 may be connected to the electronics housing 714 such that the instrumented engagement element 721 extends at least partially past an outer surface 770 of the downhole tool 710. For example, the instrumented engagement element 721 may extend from the downhole tool 710 such that the instrumented engagement element 721 may engage the borehole during drilling (or other downhole operation as the case may be) with the downhole tool 710. The instrumented engagement element 721 may extend in a substantially vertical direction (e.g., substantially downhole). This may facilitate an engagement of the instrumented engagement element 721 with the wellbore bottom hole. In one or more embodiments, the instrumented engagement element 721 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.

[0135] In some embodiments, the instrument assembly includes a sensor 723. The sensor 723 may be an engagement sensor and may take measurements associated with an engagement of the instrumented engagement element 721 with the borehole. The sensor 723 may be positioned at a base of thePATENTDocket No. IS24.1676-WO engagement element assembly 720. The sensor 723 may be positioned at a base of the instrumented engagement element 721. For example, a conduit 715 and / or the engagement element assembly 720 may have one or more structural features for holding and / or supporting the sensor 723 with respect to the instrumented engagement element 721. When the instrumented engagement element 721 engages the borehole, a force exerted on the engagement element 721 may be transferred through the base of the instrumented engagement element 721 to the sensor 723. In some embodiments, the force is an axial force. In this way, the sensor 723 may take measurements based on a force of the instrumented engagement element 721. This may facilitate taking measurements associated with the formation encountered by the instrumented engagement element 721. For example, materials (e.g., geological materials) in the formation may exhibit varying material properties such as hardness, which may correspond to varying measurements (e.g., forces) sensed by the instrumented engagement element 721. 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 721. The sensor 723 may measure these changes, and in this way, detect the features and / or properties of the formation.

[0136] In this way, the sensor 723 takes measurements associated with the instrumented engagement element 721 engaging the borehole. For example, the sensor 723 may measure strain, stress, displacement, pressure, deformation, deflection or any other parameter associated with an engagement of the instrumented engagement element 721 with the borehole. These measurements may facilitate calculating or determining a force on the instrumented engagement element 721 , or determining any other dynamic related to an engagement of the instrumented engagement element 721 with the borehole. The sensor 723 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.PATENTDocket No. IS24.1676-WO

[0137] As mentioned above, the instrument assembly 719 includes an electronics housing 714 disposed in the tool body 711. In some embodiments, the electronics housing includes, or defines a conduit 715 (e.g., a void, volume, or space) extending into the tool body 711. The conduit 715 may have an elongate shape. For example, the conduit 715 may be substantially cylindrical. The conduit 715 may be any other shape in accordance with that disclosed herein. The conduit 715 may extend into the downhole tool 710 such that a volume is defined within the tool body 711.

[0138] In some embodiments, the instrument assembly 719 includes a seal 722. The seal 722 may be positioned between the engagement element assembly 720 and the tool body, for example, to seal the electronics housing 714. For example, the seal 722 may be an O-ring seal such as a metal, rubber or plastic O-ring seal. The seal 722 may be a gasket seal. The seal 722 may be a surface seal. For example, the tool body 711 (e.g., in the conduit 715) and the engagement element assembly 720 may each have a sealing surface, and these sealing surfaces may interface in order to form the seal 722. The seal 722 may function to seal the inner volume of the electronics housing 714. For example, the electronics housing 714 may be sealed to maintain an inner pressure of the electronics housing 714. The electronics housing 714 may be sealed to prevent fluid from penetrating into the electronics housing 714. This may facilitate using and / or protecting electronics within the sealed portion of the electronics housing 714.

[0139] The volume of the electronics housing 714 may be of such a size and / or shape so as to house the electronics 725. For example, the electronics 725 may include a processor 725-1 and / or a power supply 725-2 (e.g., a battery). The electronics 725 may include one or more additional components such as memory, communication devices, etc. The electronics 725 may be coupled to and / or associated with the sensor 723. For example, the power supply 725-2 may power a function of the sensor 723. The processor 725-1 may receive and / or record one or more measurements of the sensor 723 (e.g., process and / or save to memory). The electronics 725 may be positioned within the sealed portion ofPATENTDocket No. IS24.1676-WO the electronics housing 714. In some embodiments, the sensor 723 is positioned in the sealed portion of the electronics housing 714 which may facilitate the sensor 723 connecting with the electronics 725 (e.g., through a wired connection). In this way, the electronics housing 714 may facilitate implementing one or more electronic components into the downhole tool 710, such as a processor for receiving downhole measurements from the sensor 723.

[0140] The electronics housing 714 may have an opening 716. The opening 716 may be positioned at an outer surface of the tool body 711. In some embodiments, the engagement element assembly 720 connects to the electronics housing 714 at the opening 716. For example, a portion of the electronics housing 714 proximate or adjacent to the opening 716 may be an engagement element pocket 717. The engagement element pocket 717 may be a portion of the electronics housing 714 that is configured to connect to and / or retain the engagement element assembly 720. In some embodiments, the engagement element pocket 717 is separate from the conduit 715. For example, the engagement element pocket 717 may be at a distinct location on the downhole tool 710 from the conduit. In other words, the conduit 715 and / or electronics housing 714 may be otherwise positioned within the tool body 711 (or at another location) than that shown in the illustrative example of FIG. 7-1 , but may nevertheless be electronically coupled to the engagement element assembly 720. For example, the engagement element pocket 717 may form or define a separate cavity from that of the conduit 715 shown in FIG. 7-1. In this way, the electronics 725 may be housed at a separate location from the engagement element assembly 720 and / or the sensor 723.

[0141] In accordance with at least one embodiment of the present disclosure, the opening 716 may be at a distal (e.g., downhole) end of the conduit 715. In other embodiments as described herein, the opening 716 may be at any other location and / or orientation from the downhole tool 710. The opening 716 may be at the outer surface 770 of the tool body 711 and may provide access to the electronics housing 714, for example, for inserting and / or connecting the electronics 725. The engagement element pocket 717 may be a portion of thePATENTDocket No. IS24.1676-WO conduit 715 that is adjacent or proximate the opening 716. In this way, the engagement element pocket 717 and the conduit 715 may be located or formed in the same cavity in the tool body 711. This may facilitate and / or simplify installing and / or connecting one or more of the electronics 725, the engagement element assembly 720, and the sensor 723. The opening 716 (and in this example the engagement element pocket 717) may be at an outer surface of the tool body 711 that is a downhole end of the downhole tool 710. This positioning may facilitate the engagement element assembly 720 and / or the instrumented engagement element 721 extending from the outer surface of the tool body 711.

[0142] In some embodiments, the conduit 715 includes a sleeve 715-1. For example, the sleeve 715-1 may have substantially the same shape as the conduit 715, and may be hollow, or may have an inner bore. In some embodiments, the sleeve 715-1 is substantially the shape of a hollow cylinder. The sleeve 715-1 and / or conduit 715 may be any other shape suitable for housing the electronics 725 as described herein. In some embodiments, the sleeve 715-1 is disposed within and / or connected to the conduit 715. For example, the sleeve 715-1 may be brazed into the conduit 715. The sleeve 715-1 may be glued, pressed, or threaded into the conduit, or any other form of connection suitable for connecting the sleeve 715-1 to the conduit 715. The sleeve 715-1 may span an entire length of the conduit 715 such that the sleeve 715-1 substantially makes up an entirety of the conduit 715. For example, one or more of the features of the conduit 715 described herein (e.g., sealing feature, connection with the engagement element assembly, etc.) may be included as part of the sleeve 715-1. In some embodiments, the sleeve 715-1 spans or encompasses only a portion of the conduit 715. For example, the sleeve 715-1 may define or be associated with the sealed portion of the electronics housing 714. As another example, the sleeve 715-1 may not include or be associated with the connection of the engagement element assembly 720 with the electronics housing 714. The sleeve 715-1 may be a chassis or frame for housing the electronics 725, for example, to facilitate inserting, positioning, and / or removing the electronics 725 with respect to the conduit 715.PATENTDocket No. IS24.1676-WO

[0143] The sleeve 715-1 may at least partially define or create the sealed volume of the electronics housing 714. The sleeve 715-1 may be configured to withstand the pressure differential between the sealed volume and an exterior of the downhole tool 710. For example, the sleeve 715-1 may have a wall thickness that is selected to prevent collapse under the pressure differential. In some embodiments, the seal 722 may be positioned between the sleeve 715-1 and the engagement element assembly 720 to seal the inner volume of the sleeve 715- 1.

[0144] In some situations, the material properties of the metal matrix of the tool body 711 make it difficult to include one or more features of the conduit 715 discussed herein. The sleeve 715-1 may be more easily machined or manufactured to facilitate including one or more of these features. In some embodiments, the sleeve 715-1 is manufactured before it is installed into the downhole tool 710. In some embodiments, the sleeve 715-1 is installed into the downhole tool 710 and after one or more features of the electronics housing 714 have been machined or manufactured into the sleeve 715-1. In this way, the electronics housing 714 may include the sleeve 715-1 to facilitate including one or more features of the instrument assembly 719.

[0145] In some embodiments, the conduit 715 is oriented in a longitudinal direction relative to the downhole tool 710. For example, a longitudinal axis of the conduit 715 may be oriented such that it is parallel to a longitudinal axis of the downhole tool 710. The longitudinal axis of the downhole tool 710 may be an axis of rotation of the downhole tool 710. In this way, the conduit 715 may be oriented substantially vertically, for example, during downhole drilling activities of the downhole tool 710. This may facilitate the engagement element assembly 720 and / or the engagement element 721 extending substantially vertically (e.g., downhole) from the downhole tool 710. However, as discussed herein, other orientations of the engagement element assembly 720 and / or the engagement element 721 are contemplated which may not necessarily be in an axial / longitudinal direction.PATENTDocket No. IS24.1676-WO

[0146] While one or more components of the instrument assembly 719 are shown in FIG. 7-1 as being substantially vertical, or located substantially in a longitudinal plane of the downhole tool 710, it should be understood that one or more of the components of the instrument assembly 719 may be oriented, for example, at an angle relative to the longitudinal plane of the downhole tool 710. Indeed, one or more of the components of the instrument assembly 719 may be included in the downhole tool 710 at any orientation consistent with drilling the borehole and / or taking measurements as described herein. For example, one or more of the conduit 715, the engagement element assembly 720 and the engagement element pocket 717 may be oriented horizontally. In another example, one or more of the conduit 715, the engagement element assembly 720, and the engagement element pocket 717 may be oriented transvers and / or at any angle relative to the longitudinal plane. This may facilitate implementing the instrument assembly 719 in a variety of downhole tools.

[0147] FIGS. 7-2 and 7-3 are schematic views illustrating an engagement of the instrumented engagement element 721 and a lead engagement element 775, according to at least one embodiment of the present disclosure. In some embodiments, the electronics housing 714 (more specifically, the engagement element pocket 717) is positioned in the tool body 711 such that the engagement element assembly 720 and / or the instrumented engagement element 721 extends from the downhole tool 710 adjacent to and / or behind the lead engagement element 775 (such as one or more of the engagement elements 213 of FIG. 2) of the downhole tool 710. For example, during drilling activities, the downhole tool 710 may rotate such that the engagement elements follow a rotational path. The instrumented engagement element 721 may be positioned such that it follows a rotational path that is the same as one of the engagement elements of the downhole tool 710. In other words, the rotational path of the instrumented engagement element 721 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 710. In this way the instrumented engagement element 721 may follow the rotational path of a lead engagement element 775, such as a leadPATENTDocket No. IS24.1676-WO cutting element. While FIG. 7-2 illustrates the lead engagement element 775 as an element of the downhole tool 710 that is adjacent to the instrumented engagement element 721 as well as immediately and / or rotationally ahead of the instrumented engagement element 721 , it should be understood that the lead engagement element 775 may be positioned at any location of the downhole tool 710 (as discussed below) and / or may be any of the engagement elements of the downhole tool 710.

[0148] The instrumented engagement element 721 may follow the rotational path of the lead engagement element 775 by being positioned an offset angle from the lead engagement element 775. For example, the offset angle may be an angle measured about the axis of rotation of the downhole tool 710 (e.g., measured in the direction and plane of the rotation of the downhole tool 710) between the lead engagement element 775 and the instrumented engagement element 721 . In this way the offset angle may correspond to an angle between a point of engagement of the lead engagement element 775 with the earth formation and a point of engagement of the instrumented engagement element 721 with the earth formation.

[0149] In some embodiments, the instrumented engagement element 721 is positioned substantially adjacent or proximate the lead engagement element 775. For example, the offset angle may be small, such as 1 °, and the instrumented engagement element 721 may be positioned immediately (rotationally) behind the lead engagement element 775. 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 721 with the lead engagement element 775 may correspond with the instrumented engagement element 721 and the lead engagement element 775 being positioned in the same blade of the downhole tool 710.

[0150] In some embodiments, the instrumented engagement element 721 is not positioned adjacent or proximate the lead engagement element 775. For example, the offset angle may be any angle between 1 ° and 359°, such as 75°, 90°, 180°, 270°, or any other angle. In some embodiments, this corresponds withPATENTDocket No. IS24.1676-WO the instrumented engagement element 721 being positioned in the same blade of the downhole tool 710 as the lead engagement element 775. In some embodiments, this corresponds with the instrumented engagement element 721 being positioned in a different blade (or not in a blade) of the lead engagement element 775. In this way, the instrumented engagement element 721 may be positioned at any offset angle from the lead engagement element 775 such that the instrumented engagement element 721 follows along substantially the same rotational path as the lead engagement element 775. In some embodiments, the instrumented engagement element 721 and / or the lead engagement element 775 are each positioned in a blade of the downhole tool 710. In some embodiments, one or more of the instrumented engagement element 721 or the lead engagement element 775 is not positioned in a blade of the downhole tool 710.

[0151] It should be understood that the positioning of the instrumented engagement element 721 and the lead engagement element 775 in FIG. 7-2 as being adjacent, proximate, or substantially side-by-side is for illustrative purposes only. The positioning and / or spacing of the instrumented engagement element 721 and the lead engagement element 775 may correspond with any offset angle as described above. In this way, FIG. 7-2 illustrates the instrumented engagement element 721 and the lead engagement element 775 with respect to a rotation 780 of the downhole tool 710, and not necessarily with respect to an actual or physical position on the downhole tool 710. Similarly, it should be understood that FIG. 7-3 does not necessarily illustrate the instrumented engagement element 721 and the lead engagement element 775 with respect to, for example, a positioning of each in the downhole tool 710. Rather, FIG. 7-3 is illustrative of the engagement of the instrumented engagement element 721 and the lead engagement element 775 with the earth formation 701 .

[0152] With reference now to FIG. 7-3, as discussed herein, the instrumented engagement element 721 engages an earth formation 701 in order to take one or more corresponding measurements. In some embodiments, the instrumented engagement element 721 engages the earth formation 701 by contacting and / or extending into the earth formation 701. This may be characterized by anPATENTDocket No. IS24.1676-WO engagement distance 773. For example, the lead engagement element 775 may engage the earth formation and may cut and / or remove a lead groove 776. The instrumented engagement element 721 may extend into the formation 701 at or in the lead groove 776 (e.g., as shown in FIG. 7-3) and may produce a trailing groove 777. The engagement distance 773 may be the difference between the furthest extent (e.g., downhole) of the lead groove 776 and the trailing groove 777. In this way, the engagement distance 773 may correspond to a distance or the furthest extent that the instrumented engagement element 721 extends into the formation 701 upon engagement.

[0153] In some embodiments, the engagement distance 773 may be 1 mm. The engagement distance 773 may be in a range having an upper value, a lower value, or upper and lower values including any of 0.1 mm, 0.2 mm, 0.3 mm, 0.4 mm, 0.5 mm, 0.6 mm, 0.7 mm, 0.8 mm, 0.9 mm, 1 mm, 2 mm, 3 mm, 4 mm, 5 mm, 10 mm, or any value therebetween. For example, the engagement distance 773 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 773 may be between 0.1 mm and 10 mm. In some embodiments, the engagement distance 773 in particular is less than 1 mm to ensure that the instrumented engagement element 721 experiences a significant enough engagement with the formation 701 to accurately take one or more measurements while minimizing noise in the measurements. For example, it may be understood that the instrumented engagement element 721 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.

[0154] Turning back to FIG. 7-2, the instrumented engagement element 721 may extend axially (e.g., downhole) a sensor axial distance 771. The lead engagement element 775 may extend axially (e.g., downhole) a cutting axial distance 772. The sensor axial distance 771 and the cutting axial distance 772 may each be a distance measured between a point of engagement of the respective engagement element with the formation 701 and a reference pointPATENTDocket No. IS24.1676-WO774, such as at a base of a blade of the downhole tool 710. The reference point 774 may be any reference point for measuring the sensor axial distance 771 and the cutting axial distance 772 relative to the engagement of the instrumented engagement element 721 and the lead engagement element 775 with the formation 701. For example, the instrumented engagement element 721 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 771 and the cutting axial distance 772 may be measured from the reference point 774 radially outward to an engagement of the instrumented engagement element 721 and the lead engagement element 775 with the borehole wall, respectively. In this way, the instrumented engagement element 721 may follow the same rotational path as the lead engagement element 775 (e.g., rotationally behind), while still engaging the borehole within a groove or channel cut by the lead engagement element 775. The sensor axial distance 771 and / or the cutting axial distance 772 may be determined or configured such that the instrumented engagement element 721 engages the formation 701 with the engagement distance 773, in accordance with that discussed above.

[0155] In some embodiments, the sensor axial distance 771 may be greater than the cutting axial distance 772. In other words, the instrumented engagement element 721 may axially extend (e.g., downhole) further than the lead engagement element 775. This may correspond with the instrumented engagement element 721 being positioned with a smaller offset angle, such as less than 180° (e.g., in accordance with the downhole tool 710 not having progressed significantly through the formation from the time the lead engagement element 775 cuts the formation to when the instrumented engagement element 721 engages the formation). In this way, the instrumented engagement element 721 may extend axially and engage the earth formation after the lead engagement element 775 has cut the lead groove 776.

[0156] In some embodiments, the sensor axial distance 771 may be substantially the same, or even less than the cutting axial distance 772. This may correspond with the instrumented engagement element 721 being positioned withPATENTDocket No. IS24.1676-WO 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 710 and / or the various engaging elements of the downhole tool 710, due to the rotation of the downhole tool 710, as well as the downhole tool advancing downhole through the formation 701 as it rotates, in some situations, the face of the formation 701 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 710. In this way, the instrumented engagement element 721 may extend axially and engage the earth formation after the lead engagement element 775 has cut the lead groove 776, even though the instrumented engagement element 721 may not extend axially further than the lead engagement element 775. In this way, the configuration of the sensor axial distance 771 and / or the cutting axial distance 772 may be based on or dependent on the offset angle as discussed above.

[0157] 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.

[0158] As discussed herein, the instrumented engagement element 721 may follow the same (or similar) rotational path as the lead cutting element 775. This may correspond with the instrumented engagement element 721 engaging the formation 701 within the lead groove 776 cut or removed by the lead engagement element 775. The instrumented engagement element 721 may be positioned and / or oriented such that the width of the trailing groove 777 never breaches the width of the lead groove 776 as the instrumented engagement element 721 follows rotationally behind the lead engagement element 775. For example, the instrumented engagement element 721 may engage the formation 701 at a center of the lead groove 776. In another example, the instrumented engagement element 721 may engage the formation 701 at another location of the lead groove 776 that is not centered. The instrumented engagement element 721 mayPATENTDocket No. IS24.1676-WO engage the formation 701 within the lead groove 776 at an angle (e.g., relative to a longitudinal axis of the instrumented engagement element 721 ), such as a normal or perpendicular angle, or any other angle.

[0159] The instrumented engagement element 721 may follow behind the lead engagement element 775 in this way to facilitate a measurement and / or calculation of the force on the instrumented engagement element 721 , or any other parameters associated with an engagement of the instrumented engagement element 721 with the borehole. For example, the instrumented engagement element 721 may engage the formation 701 in substantially the same way regardless of a depth of cut and / or a rate of penetration of the downhole tool. For a given geometry of rock or material being removed, the force acting on an engagement element (e.g., a cutter) may be proportional to the area of rock being cut or removed. The instrumented engagement element 721 may engage the formation 701 within the lead groove 776 in order to maintain the geometry (more specifically, the area) of rock being removed by the instrumented engagement element 721 substantially uniform. This may result in a substantially uniform engagement of the instrumented engagement element 721 with the formation 701 at all depths of cut and / or rates of penetration of the lead engagement element 775 and / or a downhole tool implementing the lead engagement element 775 and the instrumented engagement element 721. In contrast, if the instrumented engagement element 721 were to not follow directly behind the lead engagement element 775 and / or engage the formation 701 within the lead groove 776, the area of rock with which the instrumented engagement element 721 engages (e.g., removes) may vary based on the depth of cut of the lead engagement element 775, significantly complicating the calculation of the force (or other parameter) on the instrumented engagement element 721 . In this manner, changes in the measured force (or other parameter) on the instrumented engagement element 721 may be attributable to changes or features in the formation 701 (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 thePATENTDocket No. IS24.1676-WO instrumented engagement element 721 (e.g., due to different depth of cut of the lead cutting element).

[0160] FIG. 8 is a side cutaway view of an instrumentation housing or an engagement element housing 824, according to at least one embodiment of the present disclosure. The engagement element housing 824 includes a housing body 830 configured to connect to an engagement element pocket 817 of a downhole tool. The housing body 830 may have a distal end 828 and a proximal end 829. The proximal end 829 may insert into and / or engage with the engagement element pocket 817. The housing body 830 may connect to the engagement element pocket 817 such that the distal end 828 is positioned at an outer surface of the downhole tool. The distal end 828 positioned on the outer surface of the downhole tool may facilitate a measurement by one or more sensors associated with the engagement element housing 824.

[0161] In some embodiments, the housing body 830 removably connects to the engagement element pocket 817. For example, the housing body 830 may include threads 826. The threads 826 may be exterior threads on an outer surface of the housing body 830. The threads 826 may thread or screw into interior threads on an inner surface of the engagement element pocket 817. In another example, the housing body 830 may removably connect to the engagement element pocket 817 with a circlip or other removable fastening means. The housing body 830 may include a tightener 834. The tightener 834 may facilitate securing and / or tightening the connection of the housing body 830 to the engagement element pocket 817. For example, the tightener 834 may be a hex head tightener. The tightener 834 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 830 to the engagement element pocket 817. The housing body 830 may include a flange 835. The flange 835 may seat against a surface of the engagement element pocket 817, for example, to tighten the housing body 830 in the engagement element pocket 817.

[0162] In some embodiments, the engagement element housing 824 has a seal 822. The seal 822 may be positioned on an exterior of the housing body 830PATENTDocket No. IS24.1676-WO such that the seal 822 is positioned between the housing body 830 and the engagement element pocket 817 (e.g., when the engagement element housing 824 is connected to the engagement element pocket 817). The seal 822 may help to seal a portion of the engagement element pocket 817 (and / or an electronics housing conduit). For example, the seal 822 may seal a pressure in the engagement element pocket 817 and / or may prevent fluid or other matter from penetrating into the engagement element pocket 817. In some embodiments, such as that shown, the seal 822 is an O-ring seal. The O-ring may seat in a groove or channel on an exterior of the housing body 830. In some embodiments, the O-ring seats in a groove or channel on the interior of the engagement element pocket 817. In this way, the O-ring may be positioned between the housing body 830 and the engagement element pocket 817 to seal the engagement element pocket 817. In some embodiments, the seal 822 is a gasket. For example, the gasket may be disposed on the flange 835. In some embodiments, the gasket is disposed on a mating surface of the engagement element pocket 817. The gasket may be positioned between the flange 835 and a surface of the engagement element pocket 817 to seal the engagement element pocket 817. In some embodiments, the seal 822 is created without a distinct, or dedicated sealing element. For example, mating surfaces of the housing body 830 and the engagement element pocket 817 may interface to form the seal 822 (e.g., the flange 835 and a surface of the engagement element pocket 817). In this way, the engagement element housing 824 may form a removable connection with the downhole tool, and may also seal, for example, an electronics housing conduit of the bit.

[0163] In some embodiments, the engagement element housing 824 includes a measurement pocket 831 . The measurement pocket 831 may be formed in the housing body 830. The measurement pocket 831 may define a cavity in the housing body 830. For example, the measurement pocket 831 may have a pocket base 832 and a pocket opening 833. The pocket base 832 and pocket opening 833 may be on opposite ends of the measurement pocket 831. In some embodiments, the pocket opening 833 is on the distal end 828 of the housingPATENTDocket No. IS24.1676-WO body 830. In some embodiments, the pocket base 832 is on the proximal end 829 of the housing body 830. The measurement pocket 831 may be configured to house one or more sensors for taking one or more downhole measurements. For example, the pocket base 832 may include or may define a diaphragm 836. A strain gauge may be connected to the pocket base 832 at the diaphragm 836. The strain gauge and / or the diaphragm 836 may facilitate measuring, for example, a force and / or pressure associated with an operation of the bit. For example, the diaphragm 836 may experience or exhibit a strain due to a pressure or a force acting on the diaphragm 836. A strain gauge may measure the corresponding strain. In this way, the downhole measurement may include force measurements and / or pressure measurements. In other examples, other sensors, such as a temperature sensor, pressure sensor, or other sensor(s) may be positioned in the measurement pocket for measuring a temperature (e.g., taking temperature measurements) associated with the bit. In this way, the engagement element pocket 817 may facilitate including instrumentation in a bit for taking one or more downhole measurements including force measurements, pressure measurements, and temperature measurements, among others.

[0164] The engagement element housing 824 may be at least partially made of one or more wear-resistant materials. For example, the engagement element housing 824 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 824 are made of or coated with a wear-resistant material. The wear resistant properties of the engagement element housing 824 may facilitate exposing at least a portion of the engagement element housing 824 to the conditions of the borehole (e.g., at an outer surface of the bit). In this way, the engagement element housing 824 may withstand the harsh downhole drilling environment in order that the engagement element housing 824 may be incorporated in any number of downhole locations and with any number of downhole tools.PATENTDocket No. IS24.1676-WO

[0165] FIG. 9 is a side cutaway view of an engagement element housing 924, according to at least one embodiment of the present disclosure. In some embodiments, an instrumented engagement element 921 is disposed or retained in an engagement element housing 924. The engagement element housing 924 may include a housing body 930 having a distal end 928 and a proximal end 929. The instrumented engagement element 921 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 921 may be a cutting element, or may be another element that is not configured to or not primarily intended to cut, such as a steering or stabilizing pad. The instrumented engagement element 921 may be positioned in a measurement pocket 931. For example, the instrumented engagement element 921 may be inserted into, at least partially, a cavity defined by the measurement pocket 931 . The instrumented engagement element 921 may extend out of a pocket opening 933. The pocket opening 933 may be positioned on the distal end 928 of the housing body 930 such that the instrumented engagement element 921 extends outward from an outer surface of a downhole tool (e.g., a bit). In this way, the instrumented engagement element 921 may be configured to extend from the bit in order to engage the borehole.

[0166] The instrumented engagement element 921 may be connected to or retained in the measurement pocket 931. For example, the instrumented engagement element 921 and / or the measurement pocket 931 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 921 to retain the instrumented engagement element 921 in the measurement pocket 931 . The instrumented engagement element 921 may be connected to or retained in the measurement pocket 931 by any other suitable means. For example, the instrumented engagement element 921 may be glued, brazed, pressed, threaded, or fastened in the measurement pocket 931 (e.g., connectedPATENTDocket No. IS24.1676-WO to the diaphragm 936). In this way, the instrumented engagement element 921 may be removably connected to the housing body 930.

[0167] The instrumented engagement element 921 may be retained in the measurement pocket 931 such that the instrumented engagement element 921 is axially fixed. For example, the instrumented engagement element 921 may be fixed such that the instrumented engagement element 921 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 921 and to the sensor 923, as discussed herein. The instrumented engagement element 921 may not move axially in a substantial manner, but for small deflections and / or deformations of the diaphragm 936. In some embodiments, the instrumented engagement element 921 is axially fixed but may be free to spin or rotate within the measurement pocket 931 . This may facilitate continually exposing different portions of a revolving cutting face in order to reduce wear of the instrumented engagement element 921 .

[0168] In some embodiments, a pocket base 932 of the measurement pocket 931 includes or defines a diaphragm 936. The diaphragm 936 may be positioned at a base of the instrumented engagement element 921 . As the instrumented engagement element 921 engages the borehole, a force (e g., an axial force) may be transmitted through the instrumented engagement element 921 to the diaphragm 936. For example, in some embodiments, the instrumented engagement element 921 is retained in the measurement pocket 931 such that forces exerted on the instrumented engagement element 921 are not distributed throughout the housing body 930. Rather, in some embodiments, the instrumented engagement element 921 is retained in the measurement pocket such that forces exerted on the instrumented engagement element 921 are directed and / or transmitted through a base of the instrumented engagement element 921 to the diaphragm 936. The diaphragm 936 may experience or exhibit a strain corresponding to at least a portion of the force (e.g., the axial force).

[0169] The strain of the diaphragm 936 may be due to a material compliance of the diaphragm 936. In some embodiments, the diaphragm 936 has aPATENTDocket No. IS24.1676-WO 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 936 exhibits a measurable level of strain, while preventing plastic deformation of the diaphragm 936 due to the axial forces.

[0170] In some embodiments, a sensor 923 is housed by the measurement pocket 931 . For example, a strain gauge 937 may be disposed on the diaphragm 936. The strain gauge 937 may measure a strain exhibited by the diaphragm 936, for example, based on forces exerted on the instrumented engagement element 921 . In this way, the instrumented engagement element 921 , the diaphragm 936, and the strain gauge 937 may form the sensor 923 (e.g. , an engagement sensor). In some embodiments, the strain gauge 937 is disposed on an opposite side of the diaphragm 936 from the instrumented engagement element 921 . In this way, the strain gauge 937 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 937 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.

[0171] 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,PATENTDocket No. IS24.1676-WO 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.

[0172] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1 %, within 0.1 %, or within 0.01 % of a stated value.

[0173] 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. EachPATENTDocket No. IS24.1676-WO addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0174] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1 % of, within less than 0.1 % of, and within less than 0.01 % of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. Additionally, as used herein, the term “and / or” includes any and all combinations of one or more of the associated listed items.

[0175] 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. IS24.1676-WOCLAIMSWhat is claimed is:1 . A method of operating an instrumented engagement element positioned on a downhole tool, the instrumented engagement element configured for engaging a formation within a wellbore, comprising: operating, in a first operation mode, an instrument assembly positioned within a body of the downhole tool, the instrument assembly including the instrumented engagement element, an engagement sensor of the instrumented engagement element, and a processor; monitoring, with one or more sensors of the instrument assembly, one or more downhole parameters within the wellbore; determining a trigger based on identifying a trigger signature in the one or more downhole parameters; and operating the instrument assembly in a second operation mode in response to the trigger.

2. The method of claim 1 , wherein the one or more downhole parameters is a force on the instrumented engagement element as measured by the engagement sensor and the trigger signature is the force over a threshold amount.

3. The method of claim 2, wherein the trigger signature is the force over the threshold amount for a threshold duration.

4. The method of claim 2, wherein the force on the instrumented engagement element corresponds with an engagement operation of the downhole tool.

5. The method of claim 1 , wherein the first operation mode is a sleep mode and wherein operating the instrument assembly in the second operation mode includes waking the instrument assembly up from the sleep mode.PATENTDocket No. IS24.1676-WO6. The method of claim 5, wherein operating the instrument assembly in the second operation mode includes taking and logging one or more measurements with the instrumented engagement element.

7. The method of claim 6, further comprising engaging the formation with the instrumented engagement element to take the one or more measurements.

8. The method of claim 5, wherein waking the instrument assembly up from the sleep mode is based on the trigger indicating an engagement operation of the downhole tool based on a threshold force observed on the instrumented engagement element by the engagement sensor.

9. The method of claim 1 , wherein the one or more downhole parameters is a downhole pressure as measured with the engagement sensor, and the trigger is a measurement depth of the downhole tool based on the downhole pressure.

10. The method of claim 1 , wherein the one or more downhole parameters is shock or vibration of the downhole tool, and wherein the trigger signature is a shock or vibration of a threshold corresponding with an engagement operation of the downhole tool.

11. The method of claim 10, wherein the one or more sensors of the instrument assembly includes an accelerometer, and the shock or vibration is measured by the accelerometer.

12. The method of claim 1 , wherein the one or more downhole parameters is a rotation of the downhole tool, and wherein the trigger signature is a rotation corresponding with an engagement operation of the downhole tool.PATENTDocket No. IS24.1676-WO13. The method of claim 12, wherein the one or more sensors of the instrument assembly includes a magnetometer, and the rotation is measured by the magnetometer.1 . The method of claim 1 , wherein the one or more downhole parameters is a temperature associated with the instrumented engagement element, and wherein the trigger signature is a temperature over a threshold degree corresponding with an engagement operation of the downhole tool.

15. The method of claim 14, wherein the one or more sensors of the instrument assembly includes a temperature sensor positioned in the instrumented engagement element, and the temperature is measured by the temperature sensor.

16. The method of claim 1 , wherein the first operation mode is a first sampling frequency, and the second operation mode is a second sampling frequency, and the one or more downhole parameters is one or more of a rotational speed (RPM) of the downhole tool or a rate of penetration (ROP) of the downhole tool.PATENTDocket No. IS24.1676-WO17. An instrument assembly positioned within a body of a downhole tool, including: an instrumented engagement element; one or more sensors, the one or more sensors including an engagement sensor coupled to the instrumented engagement element for taking measurement data associated with the instrumented engagement element engaging a formation; a processor connected to the one or more sensors; a memory in electronic communication with the processor; and instructions stored in the memory which, when executed by the processor, cause the processor to perform acts of: operating the instrument assembly in a first operation mode; monitoring, with the one or more sensors, one or more downhole parameters within a wellbore; determining a trigger based on identifying a trigger signature in the one or more downhole parameters; and operating the instrument assembly in a second operation mode in response to the trigger.PATENTDocket No. IS24.1676-WO18. A method of taking measurement data within a wellbore for characterizing a formation, comprising: taking one or more first measurements with a first instrumented engagement element positioned on a downhole tool and configured to engage a formation, wherein the first instrumented engagement element is included as part of a first instrument assembly positioned within a body of the downhole tool; operating a second instrument assembly in a sleep mode, the second instrument assembly being positioned within the body of the downhole tool and including a second instrumented engagement element positioned on the downhole tool being configured for engaging the formation; monitoring, with one or more sensors of the second instrument assembly, one or more downhole parameters within the wellbore; determining a trigger based on identifying a trigger signature in the one or more downhole parameters; waking the second instrument assembly from the sleep mode based on the trigger; and taking one or more second measurements with the second instrumented engagement element.

19. The method of claim 18, wherein the trigger is associated with one or more of a memory resource or a power resource of the first instrumented engagement element being exhausted to a threshold degree.

20. The method of claim 18, further comprising engaging the wellbore with the second instrumented engagement element while the second instrument assembly is in the sleep mode.

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