Estimating Environmental Parameter of Cutter Elements

This application claims priority to and the benefit of U.S. Provisional Application No. 63/572,814, filed on Apr. 1, 2024, which is incorporated herein by reference in its entirety.

Not applicable.

The disclosure relates generally to drill bits used for drilling a borehole in an earthen formation for the ultimate recovery of oil, gas, or minerals. More particularly, the disclosure relates to estimating thermal characteristics of components of drill bits.

An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.

Fixed cutter bits, also known as rotary drag bits, are one type of drill bit commonly used to drill boreholes. Fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades generally project radially outward along the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors.

The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PCD”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. In addition, each cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PDC bit” or “PDC cutter element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.

While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the face of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may reduce or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to re-cut the same materials, thereby reducing the effective cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the hole are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall. Further, the fluid removes heat, caused by contact with the formation, from the cutter elements in order to prolong cutter element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may impact the performance of the drill bit, in particular the wear life of the PDC cutter elements.

Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section.

Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort, and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer. The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors, including wear life of the PDC cutter elements.

Examples of the present disclosure are directed to a drill bit that includes a bit body configured to rotate about a central axis in a cutting direction of rotation. The bit body includes a bit face. The drill bit also includes a blade extending radially along the bit face and having a leading edge and a trailing edge. The blade includes a pocket proximate to the leading edge and configured to receive a cutter element, a cavity behind the pocket and configured to receive an electronic device, and a passage coupling the cavity to the pocket and configured to receive a probe coupled to the electronic device.

Other examples of the present disclosure are directed to a method including acquiring data from a probe positioned proximate to a backside of a cutter element of a drill bit. The data is indicative of a measured environmental parameter. The method also includes downloading the acquired data from an electronic storage device and processing the downloaded data to correlate the measured environmental parameter with an actual environmental parameter proximate a cutting surface of the cutter element.

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims will be made for purposes of clarity, with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation.

During drilling operations, PDC cutter elements are subject to thermal and mechanical loads. The thermal factors that affect cutter elements lead to increased wear, which in turn leads to a decreased level of performance of the associated drill bit (e.g., decreased rate of penetration (ROP)). In certain situations, cutter element temperatures may be estimated (e.g., using finite element analysis or other such numerical analyses) based on boundary conditions (e.g., drilling fluid flow rate, downhole environment temperature, cutter element size, wear progression of cutter element material), material properties, and assumptions about the operating environment and parameters of the cutter element (e.g., weight on bit (WOB), rotation speed, formation composition, drilling fluid type and flow rate). However, estimating cutter element temperatures in such a manner relies on a number of assumptions, which may either be unrealistic or become unrealistic due to real-time changes in operating conditions and generally do not take into account the variability in parameters that can be experienced during real-time drilling operations. This, in turn, makes it difficult to accurately estimate cutter element temperatures, or temperatures of specific portions of cutter elements, such as the tip or leading (e.g., cutting) face of the cutter element.

Examples of this disclosure are directed to more accurately measuring, modeling, and/or estimating cutter element parameters, such as temperatures, heat flux, vibrations, and/or strain. This allows improved validation of analysis models for cutter element parameters and a better understanding of real-time cutter element behavior during drilling operations downhole. Knowledge of cutter element parameters and conditions allows for greater understanding of thermal and/or mechanical inputs for a particular drill bit design, cooling capacity for a particular drill bit design, masking of cutter elements that results from a particular drill bit design, and the like.

Embodiments described herein are directed to a drill bit including a bit body having one or more blades that extend from bit faces of the bit body. The blades include a leading edge (e.g., facing a cutting direction of rotation of the drill bit) and a trailing edge. The blade includes a pocket proximate to the leading edge, which is configured to receive a cutter element to engage an earthen formation. A cavity is formed behind the pocket (e.g., in the direction of the trailing edge from the pocket) and is configured to receive an electronic device. A passage connects the cavity to the pocket, and is configured to receive a probe (e.g., a temperature probe) that is coupled to the electronic device in the cavity.

When a cutter element is arranged in the pocket, the cutter element includes a substrate coupled to the pocket, and a cutting layer coupled to the substrate. The cutting layer includes a cutting face (e.g., facing the cutting direction of rotation of the drill bit) and a back side coupled to the substrate. The substrate includes a passage, which is configured to couple to the passage of the blade when the cutter element is arranged in the pocket. As a result, a probe, such as a temperature probe, may be positioned extending through the passage in the blade, and through the passage in the substrate, and contact the back side of the cutting layer of the cutter element. In particular, when installed, a measuring tip of the temperature probe is configured to abut the back side of the cutting layer of the cutter element. The electronic device in the cavity is coupled to the probe and configured to acquire and store data generated by the probe (e.g., a time series of data indicative of temperature measurements taken by the probe).

By biasing or otherwise maintaining contact between the probe and the back side of the cutting layer, the probe is protected from wear to the cutter element, which occurs on the opposite side of the cutting layer (e.g., the cutting face), while still generating data indicative of environmental parameters proximate the cutting layer. When the drill bit is removed from the borehole, the electronic device may be retrievable such that the data acquired and stored thereon may be downloaded and processed by a computing device. In some examples of this disclosure, the data comprises a time series of temperature measurements, and the computing device processes the data to correlate the measured temperatures (e.g., the temperatures indicated by the data) to actual temperatures at the cutting face of the cutting layer. These and other details are explained further below, with reference made to the accompanying figures.

In some embodiments, similar arrangements are provided for multiple cutter elements on the drill bit, allowing for data acquisition from different locations on the drill bit, and an enhanced understanding of various cutter element performance during drilling operations downhole. Additionally, in some embodiments, design parameters of a drill bit may be altered to improve thermal and wear characteristics of the drill bit in view of the measured temperatures (and/or correlated actual temperatures of the cutting face(s)), which in turn may increase the estimated run length achievable by the drill bit during operation.

Referring now to, a schematic view of an embodiment of a drilling systemin accordance with the principles described herein is shown. Drilling systemincludes a derrickhaving a floorsupporting a rotary tableand a drilling assemblyfor drilling a boreholefrom derrick. Rotary tableis rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed and controlled by a motor controller (not shown). In other embodiments, the rotary table (e.g., rotary table) may be augmented or replaced by a top drive suspended in the derrick (e.g., derrick) and connected to the drillstring (e.g., drillstring).

Drilling assemblyincludes a drillstringand a drill bitcoupled to the lower end of drillstring. Drillstringis made of a plurality of pipe jointsconnected end-to-end, and extends downward from the rotary tablethrough a pressure control device, such as a blowout preventer (BOP), into the borehole. The pressure control deviceis commonly hydraulically powered and may contain sensors for detecting certain operating parameters and controlling the actuation of the pressure control device. Drill bitis rotated with weight-on-bit (WOB) applied to drill the boreholethrough the earthen formation. Drillstringis coupled to a drawworksvia a kelly joint, swivel, and linethrough a pulley. During drilling operations, drawworksis operated to control the WOB, which impacts the rate-of-penetration of drill bitthrough the formation. In this embodiment, drill bitcan be rotated from the surface by drillstringvia rotary tableand/or a top drive, rotated by downhole mud motordisposed along drillstringproximal bit, or combinations thereof (e.g., rotated by both rotary tablevia drillstringand mud motor, rotated by a top drive and the mud motor, etc.). For example, rotation via downhole motormay be employed to supplement the rotational power of rotary table, if required, and/or to effect changes in the drilling process. In either case, the rate-of-penetration (ROP) of the drill bitinto the boreholefor a given formation and a drilling assembly largely depends upon the WOB and the rotational speed of bit.

During drilling operations a suitable drilling fluidis pumped under pressure from a mud tankthrough the drillstringby a mud pump. Drilling fluidpasses from the mud pumpinto the drillstringvia a desurger, fluid line, and the kelly joint. The drilling fluidpumped down drillstringflows through mud motorand is discharged at the borehole bottom through nozzles in face of drill bit, circulates to the surface through an annular spaceradially positioned between drillstringand the sidewall of borehole, and then returns to mud tankvia a solids control systemand a return line. Solids control systemmay include any suitable solids control equipment known in the art including, without limitation, shale shakers, centrifuges, and automated chemical additive systems. Control systemmay include sensors and automated controls for monitoring and controlling, respectively, various operating parameters such as centrifuge rotations per minute (RPM). It should be appreciated that much of the surface equipment for handling the drilling fluid is application specific and may vary on a case-by-case basis.

Referring now to, drill bitis a fixed cutter bit, sometimes referred to as a drag bit, and is designed for drilling through formations of rock to form a borehole. Bithas a central or longitudinal axis, a first or uphole end, and a second or downhole end. Bitrotates about axisin the cutting direction represented by arrow. In addition, bitincludes a bit bodyextending axially from downhole end, a threaded connection or pinextending axially from uphole end, and a shankextending axially between pinand body. Pincouples bitto drill string, which is employed to rotate the bitto drill the borehole. Bit body, shank, and pinare coaxially aligned with axis, and thus, each has a central axis coincident with axis.

The portion of bit bodythat faces the formation at downhole endb includes a bit faceprovided with a cutting structure. Cutting structureincludes a plurality of blades which extend from bit face. In some examples, cutting structureincludes three angularly spaced-apart primary blades, and three angularly spaced apart secondary blades. Although bitis shown as having three primary bladesand three secondary blades, in general, bitmay comprise any suitable number of primary and secondary blades.

Primary bladesand secondary bladesare separated by drilling fluid flow courses. Each blade,has a leading edge or side,, respectively, and a trailing edge or side,, respectively, relative to the direction of rotationof bit.

Referring still to, each blade,includes a cutter-supporting surfacefor mounting a plurality of cutter elements. In particular, cutter elementsare arranged adjacent one another in a radially extending row proximal the leading edge of each primary bladeand each secondary blade. As used herein, the terms “leads,” “leading,” “trails,” and “trailing” are used to describe the relative positions of two structures (e.g., cutter element) on the same blade relative to the direction of bit rotation. In particular, a first structure that is disposed ahead or in front of a second structure on the same blade relative to the direction of bit rotation “leads” the second structure (i.e., the first structure is in a “leading” position), whereas the second structure that is disposed behind the first structure on the same blade relative to the direction of bit rotation “trails” the first structure (i.e., the second structure is in a “trailing” position).

Each cutter elementhas a cutting faceand comprises an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. In general, each cutter element may have any suitable size and geometry. In this embodiment, each cutter elementhas substantially the same size and geometry. Cutting faceof each cutter elementcomprises a disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material that is bonded to the exposed end of the support member. In the embodiments described herein, each cutter elementis mounted such that its cutting faceis generally forward-facing. As used herein, “forward-facing” is used to describe the orientation of a surface that is substantially perpendicular to, or at an acute angle relative to, the cutting direction of the bit (e.g., cutting directionof bit). For instance, a forward-facing cutting face (e.g., cutting face) may be oriented perpendicular to the direction of rotationof bit, may include a backrake angle, and/or may include a siderake angle. However, the cutting faces are preferably oriented perpendicular to the direction of rotationof bitplus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting faceincludes a cutting edge adapted to positively engage, penetrate, and remove formation material with a shearing action, as opposed to the grinding action utilized by impregnated bits to remove formation material. Such cutting edge may be chamfered or beveled as desired. In this embodiment, cutting facesare substantially planar, but may be convex or concave in other embodiments.

Referring still to, bit bodyfurther includes gage padsof substantially equal axial length measured generally parallel to bit axis. Gage padsare circumferentially-spaced about the radially outer surface of bit body. Specifically, one gage padintersects and extends from each blade,. In this embodiment, gage padsare integrally formed as part of the bit body. In general, gage padscan help maintain the size of the borehole by a rubbing action when cutter elementswear slightly under gage. Gage padsalso help stabilize bitagainst vibration. Further, a nozzleis seated in the lower end of each flow passage. Together, passagesand nozzlesdistribute drilling fluid around cutting structureto flush away formation cuttings and to remove heat from cutting structure, and more particularly cutter elements, during drilling.

shows the drill bitofin a cross-sectional view, in accordance with various examples. Further,shows a zoomed out view ofto provide additional context. In particular,show a cross section of a blade,extending from the bit faceof bit bodyof the drill bit. The blade is labeled as primary bladefor simplicity, but examples of this disclosure could apply equally to a secondary bladeas well. The bladehas a leading edge or sideand a trailing edge or side, relative to the direction of rotation of bit. The leading edgea faces the direction of rotation.

The bladeincludes a pocketproximate to the leading edge, which is configured to receive a cutter elementto engage an earthen formation. When arranged in the pocket, the cutter elementmay be coupled to the bladeusing known methods (e.g., brazing). The bladealso includes a cavity, which is formed behind the pocket(e.g., in the direction of the trailing edgefrom the pocket). The cavityand is configured to receive an electronic device. A passageconnects the cavityto the pocket. As will be explained further below, the passageis configured to receive a probe(e.g., a temperature probe, a heat flux sensor, a vibration sensor, a strain gauge) that is coupled to the electronic devicein the cavity.

The cutter elementincludes a substratecoupled to the pocket, and a cutting layercoupled to the substrate. The cutting layerincludes the cutting faceexplained above, as well as a back sidethat is coupled to the substrate. The substrateincludes a passage. The passageof the substrateis configured to couple to the passageof the bladewhen the cutter elementis arranged in the pocket. As a result, the probe, such as a temperature probe, may be positioned extending through the passagein the blade, and through the passagein the substrate. A measuring tipof the probeis thus able to contact or abut the back sideof the cutting layerof the cutter element.

The electronic devicein the cavityis coupled to the probeand is configured to acquire and store data generated by the probe. In an example in which the probeis a temperature probe, the probemay generate a time series of data indicative of temperature sensed by the probe. In another example in which the probeis a heat flux sensor, the probemay generate a time series of data indicative of heat flux (e.g., across the back side) sensed by the probe. In an example in which the probeis a vibration sensor, the probemay generate a time series of data indicative of vibrations sensed by the probe. In yet another example in which the probeis a strain gauge, the probemay generate a time series of data indicative of strain (e.g., deflection of the back side) sensed by the probe. Regardless of the type of probe, in some examples, the electronic deviceis coupled to the probeby a wired connection, while in other examples the electronic deviceis coupled to the probeby a wireless connection (e.g., a near-field wireless link). The electronic devicemay additionally comprise (or be coupled to) a power source, such as a battery, which is co-located in the cavityas well.

The electronic devicemay be disposed in a housing, which may provide structural support to and protection for the electronic device. The housingmay be made from various materials, sufficiently rigid to support and protect the electronic devicesuch as plastic, metal, or a composite material. In some examples, the probeincludes a shoulderor flange that extends radially from a main portion of the probe. A biasing element, such as a spring, is disposed between the shoulderand the housingfor the electronic device, and is configured to bias the shoulder, and thus the probe, away from the housing. As a result, the biasing elementmaintains contact between the measuring tipof the probe and the back sideof the cutting layerof the cutter element. In another example, rather than a biasing element, an adhesive may be applied to the probeto fix the probein a contacting relationship with the back sideof the cutting layer. For example, the probemay be potted in material (e.g., thermally-conductive and/or relatively rigid epoxy) that maintains the measuring tipin contact with the back sideof the cutting layer, and thus capable of sensing an environmental parameter proximate thereto. In another example, a adhesive may be utilized to couple the measuring tipto the back sideof the cutting layer.

A pressure capis used to seal the cavityfrom an environment external to the drill bitand thus to the bladeas well. A seal between the pressure capand the blade(e.g., the walls of the cavity) may be formed in any suitable manner. For example, the pressure capmay be welded to the walls of the cavity. In another example, the pressure capmay be threaded into the cavityand against a sealing member, such as a crush O-ring or an elastomeric O-ring. Regardless of how the pressure capseals the cavityfrom the external environment, the pressure capprotects the electronic deviceand the probefrom exposure to harsh conditions, which may damage one or both devices,. Further, the passageis also protected from the environment external to the drill bitby a bond between the substrateand the pocket. For example, a bond formed by brazing the substrateto the pocketacts as a seal between the passageand the environment external to the drill bit.

In some examples, the probeis a temperature probeas explained above and may be, for example, a thermocouple, a thermistor, or other types of probes suitable to measure a temperature proximate the back faceof the cutting layer.

Once the drill bitis retrieved to the surface, the data stored on the electronic devicemay be accessed. For example, the electronic devicemay be accessed to download data acquired and stored by the electronic devicewhile the drill bitperformed drilling operations downhole. As explained above, the data acquired and stored by the electronic devicemay include a time series of temperature data generated by the temperature probeduring drilling operations. In other examples, the data acquired and stored by the electronic devicemay include a time series of heat flux data, vibration data, and/or strain data. The data from the electronic devicemay be downloaded to another computing device (not shown for simplicity) at the surface, either through a wired or wireless connection.

The computing device may then analyze or otherwise process the data downloaded from the electronic device, for example to correlate or associate measured parameters from the probeat the back sideof the cutting layerto actual parameters experienced at the cutting faceof the cutting layer. For example, the computing device may apply correlations derived based on heat transfer analyses to correlate measured temperature data from the back sidewith actual temperatures experienced at the cutting faceof the cutting layer. Such heat transfer analyses may take into account material properties of the cutting layer, such as a thickness of the cutting later. Other parameters such as the temperature and flow speed of surrounding drilling fluid may affect the correlations and may thus be included in the heat transfer analyses.

In some examples, because the cutting layerexperiences wear during drilling operations downhole, a thickness of the cutting layerchanges over time. The heat transfer analyses to derive the temperature correlations may include the effect of these changes to calculate the correct correlations for the computing device. The computing device, when applying the temperature correlation(s) to the downloaded data from the electronic device, may apply such correlations over time for the thickness of the cutting layerto more accurately correlate the measured temperature data with actual temperatures experienced at the cutting faceof the cutting layer. In some examples, the change over time of the thickness of the cutting layeris estimated based on a known starting thickness of the cutting layer, an observed thickness of the cutting layerupon retrieval of the drill bit, and material properties of the cutting layer(e.g., that indicate a typical behavior of the cutting layeras it wears). For example, certain cutting layermaterials may wear at an approximately linear rate as a function of time, while other cutting layermaterials may wear at exponential or other nonlinear rates as a function of time. Regardless of how the cutting layerthickness changes over time, such a change in thickness may be utilized in conjunction with the heat transfer equation(s) to more accurately correlate the measured temperature values at the back sideof the cutting layerwith actual temperatures experienced at the cutting faceof the cutting layer.

shows a flow chart of a methodfor processing or analyzing data acquired and stored by the drill bit(e.g., by the electronic device) in accordance with various examples. The methodbegins in blockwith acquiring data from a probe (e.g., probe) positioned proximate to a backsideof a cutter elementof a drill bit. As explained above, the probemay abut the back sideof the substrateof the cutter elementand is configured to measure an environmental parameter. In some examples, the probeis a temperature probe and thus the environmental parameter is temperature. In other examples, the environmental parameter may be heat flux, vibrations, and/or strain/deflection as described above. Also, the probemay be configured to sense multiple environmental parameters and/or multiple probesmay be used, where the probessense different environmental parameters. Regardless of the number of probe(s)and the number of environmental parameter(s) that are measured, the probemeasures the environmental parameter away from the cutting faceof the cutting layerof the cutter element, and thus is protected from the harsh wellbore environment external to the drill bit. The acquired data is transmitted from the probeto an electronic device, which stores the acquired data.

The methodcontinues in blockwith downloading the acquired data from the electronic device. In some cases, the drill bitis retrieved to the surface and the acquired data is downloaded from the electronic device (e.g., over a wired or wireless connection). In other cases, the acquired data may be downloaded from the electronic devicewhile the drill bitremains downhole, for example through a wired and/or wireless connection (e.g., a drillstring-based telemetry system).

The methodthen continues in blockwith processing the downloaded data to correlate the measured environmental parameter with an actual environmental parameter proximate a cutting surfaceof the cutter element. As explained above, the data acquired and stored by the electronic devicemay include a time series of temperature data generated by the temperature probeduring drilling operations. The downloaded data is processed to correlate or associate measured temperatures from the temperature probeat the back sideof the cutting layerto actual temperatures experienced at the cutting faceof the cutting layer. In other examples in which the probeinstead measures heat flux, vibration, and/or strain, such downloaded data is processed to correlate or associate heat flux, vibrations, and/or strain at the back sideof the cutting layerto actual parameter(s) experienced at the cutting faceof the cutting layer.

As explained above, processing may include applying correlations derived based on heat transfer analyses to correlate measured temperature data from the back sidewith actual temperatures experienced at the cutting faceof the cutting layer. In other examples, the processing may include applying correlations derived based on heat flux, vibration, and/or strain analyses to correlate those measured parameters from the back sidewith the actual parameters experienced at the cutting faceof the cutting layer. Regardless of the particular parameter(s) being sensed, these analyses may take into account material properties of the cutting layer, such as a thickness of the cutting later, a material of the cutting layer, a hardness of the cutting layer, and the like. Other parameters such as the temperature and flow speed of surrounding drilling fluid may affect the correlations and may thus be included in the heat transfer, heat flux, vibration, and/or strain analyses.

Additionally, because the cutting layerexperiences wear during drilling operations downhole, a thickness of the cutting layerchanges over time. Thus, the processing may include correlating a first measured parameter (e.g., temperature, heat flux, vibration, and/or strain) with a first actual parameter based on a first thickness of the cutting layer, and also correlating a second measured parameter with a second actual parameter based on a second thickness of the cutting layer. Thus, the effect of the changes in thickness of the cutting layerare is taken into account to correctly correlate measured parameters with actual parameters.

In certain embodiments of the present disclosure, remedial action may be taken to address excessive temperatures, vibrations, and/or strain calculated or estimated for one or more of the cutter elementsof the drill bit. The remedial action may include changing design parameters of the drill bitsuch as position, shape, or other physical attributes of the cutter elements; and position, shape, or other physical attributes of the nozzles. In some examples, remedial action is only taken if a calculated or estimated parameter for at least one cutter elementis above a threshold value. In certain embodiments, the remedial action taken may be manual (e.g., an engineer modifies design parameters of the drill bit), while in other embodiments, the remedial action taken may be automated (e.g., a computer program modifies design parameters of the drill bitbased on an understanding of the impact(s) of such modifications on thermal wear life of the cutter elementsof the drill bit).

By modifying the design parameters of the drill bit, the thermal wear on cutter elementsof the drill bitmay be improved upon, which in turn increases the expected lifespan of the drill bit. In some embodiments, the design parameters of the drill bitare manually adjusted (e.g., by an engineer viewing a preliminary graphical display). In other embodiments, the design parameters of the drill bitare automatically adjusted, for example by a software tool.

Embodiments of this disclosure may include software, embodied on a non-transitory computer-readable medium that, when executed by a computer (e.g., a processor) such as the above-described computing device at the surface, causes the computer to perform some or all of the method steps described herein.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Similarly, methods to conduct the heat transfer analyses may also vary which may include different numerical algorithms, empirical correlations, analytical solutions or approximations. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.