ESTIMATING ENVIRONMENTAL PARAMETER OF CUTTER ELEMENTS

Description

CROSS-REFERENCE TO RELATED APPLICATION

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.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

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.

BRIEF SUMMARY OF THE DISCLOSURE

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.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic view of a drilling system including a drill bit in accordance with the principles described herein;

FIG. 2 is a perspective view of the drill bit of FIG. 1 in accordance with the principles described herein;

FIG. 3a is a cross-sectional view of a part of the drill bit of FIGS. 1 and 2 in accordance with the principles described herein;

FIG. 3b is a zoomed out view of FIG. 3a in accordance with the principles described herein; and

FIG. 4 is a flow chart of a method for processing or analyzing data acquired and stored by the drill bit of the foregoing figures, in accordance with the principles described herein.

DETAILED DESCRIPTION

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 FIG. 1, a schematic view of an embodiment of a drilling system 10 in accordance with the principles described herein is shown. Drilling system 10 includes a derrick 11 having a floor 12 supporting a rotary table 14 and a drilling assembly 90 for drilling a borehole 26 from derrick 11. Rotary table 14 is 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 14) may be augmented or replaced by a top drive suspended in the derrick (e.g., derrick 11) and connected to the drillstring (e.g., drillstring 20).

Drilling assembly 90 includes a drillstring 20 and a drill bit 100 coupled to the lower end of drillstring 20. Drillstring 20 is made of a plurality of pipe joints 22 connected end-to-end, and extends downward from the rotary table 14 through a pressure control device 15, such as a blowout preventer (BOP), into the borehole 26. The pressure control device 15 is commonly hydraulically powered and may contain sensors for detecting certain operating parameters and controlling the actuation of the pressure control device 15. Drill bit 100 is rotated with weight-on-bit (WOB) applied to drill the borehole 26 through the earthen formation. Drillstring 20 is coupled to a drawworks 30 via a kelly joint 21, swivel 28, and line 29 through a pulley. During drilling operations, drawworks 30 is operated to control the WOB, which impacts the rate-of-penetration of drill bit 100 through the formation. In this embodiment, drill bit 100 can be rotated from the surface by drillstring 20 via rotary table 14 and/or a top drive, rotated by downhole mud motor 55 disposed along drillstring 20 proximal bit 100, or combinations thereof (e.g., rotated by both rotary table 14 via drillstring 20 and mud motor 55, rotated by a top drive and the mud motor 55, etc.). For example, rotation via downhole motor 55 may be employed to supplement the rotational power of rotary table 14, if required, and/or to effect changes in the drilling process. In either case, the rate-of-penetration (ROP) of the drill bit 100 into the borehole 26 for a given formation and a drilling assembly largely depends upon the WOB and the rotational speed of bit 100.

During drilling operations a suitable drilling fluid 31 is pumped under pressure from a mud tank 32 through the drillstring 20 by a mud pump 34. Drilling fluid 31 passes from the mud pump 34 into the drillstring 20 via a desurger 36, fluid line 38, and the kelly joint 21. The drilling fluid 31 pumped down drillstring 20 flows through mud motor 55 and is discharged at the borehole bottom through nozzles in face of drill bit 100, circulates to the surface through an annular space 27 radially positioned between drillstring 20 and the sidewall of borehole 26, and then returns to mud tank 32 via a solids control system 37 and a return line 35. Solids control system 37 may include any suitable solids control equipment known in the art including, without limitation, shale shakers, centrifuges, and automated chemical additive systems. Control system 37 may 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 FIG. 2, drill bit 100 is a fixed cutter bit, sometimes referred to as a drag bit, and is designed for drilling through formations of rock to form a borehole. Bit 100 has a central or longitudinal axis 105, a first or uphole end 100a, and a second or downhole end 100b. Bit 100 rotates about axis 105 in the cutting direction represented by arrow 106. In addition, bit 100 includes a bit body 110 extending axially from downhole end 100b, a threaded connection or pin 120 extending axially from uphole end 100a, and a shank 130 extending axially between pin 120 and body 110. Pin 120 couples bit 100 to drill string 20, which is employed to rotate the bit 100 to drill the borehole 26. Bit body 110, shank 130, and pin 120 are coaxially aligned with axis 105, and thus, each has a central axis coincident with axis 105.

The portion of bit body 110 that faces the formation at downhole end 100b includes a bit face 111 provided with a cutting structure 140. Cutting structure 140 includes a plurality of blades which extend from bit face 111. In some examples, cutting structure 140 includes three angularly spaced-apart primary blades 141, and three angularly spaced apart secondary blades 142. Although bit 100 is shown as having three primary blades 141 and three secondary blades 142, in general, bit 100 may comprise any suitable number of primary and secondary blades.

Primary blades 141 and secondary blades 142 are separated by drilling fluid flow courses 143. Each blade 141, 142 has a leading edge or side 141a, 142a, respectively, and a trailing edge or side 141b, 142b, respectively, relative to the direction of rotation 106 of bit 100.

Referring still to FIG. 2, each blade 141, 142 includes a cutter-supporting surface 144 for mounting a plurality of cutter elements 145. In particular, cutter elements 145 are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade 141 and each secondary blade 142. 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 element 145 has a cutting face 146 and 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 element 145 has substantially the same size and geometry. Cutting face 146 of each cutter element 145 comprises 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 element 145 is mounted such that its cutting face 146 is 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 direction 106 of bit 100). For instance, a forward-facing cutting face (e.g., cutting face 146) may be oriented perpendicular to the direction of rotation 106 of bit 100, may include a backrake angle, and/or may include a siderake angle. However, the cutting faces are preferably oriented perpendicular to the direction of rotation 106 of bit 100 plus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting face 146 includes 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 faces 146 are substantially planar, but may be convex or concave in other embodiments.

Referring still to FIG. 2, bit body 110 further includes gage pads 147 of substantially equal axial length measured generally parallel to bit axis 105. Gage pads 147 are circumferentially-spaced about the radially outer surface of bit body 110. Specifically, one gage pad 147 intersects and extends from each blade 141, 142. In this embodiment, gage pads 147 are integrally formed as part of the bit body 110. In general, gage pads 147 can help maintain the size of the borehole by a rubbing action when cutter elements 145 wear slightly under gage. Gage pads 147 also help stabilize bit 100 against vibration. Further, a nozzle 108 is seated in the lower end of each flow passage 107. Together, passages 107 and nozzles 108 distribute drilling fluid around cutting structure 140 to flush away formation cuttings and to remove heat from cutting structure 140, and more particularly cutter elements 145, during drilling.

FIG. 3a shows the drill bit 100 of FIGS. 1 and 2 in a cross-sectional view, in accordance with various examples. Further, FIG. 3b shows a zoomed out view of FIG. 3a to provide additional context. In particular, FIGS. 3a and 3b show a cross section of a blade 141, 142 extending from the bit face 111 of bit body 110 of the drill bit 100. The blade is labeled as primary blade 141 for simplicity, but examples of this disclosure could apply equally to a secondary blade 142 as well. The blade 141 has a leading edge or side 141a and a trailing edge or side 141b, relative to the direction of rotation of bit 100. The leading edge 141a faces the direction of rotation.

The blade 141 includes a pocket 302 proximate to the leading edge 141a, which is configured to receive a cutter element 145 to engage an earthen formation. When arranged in the pocket 302, the cutter element 145 may be coupled to the blade 141 using known methods (e.g., brazing). The blade 141 also includes a cavity 304, which is formed behind the pocket 302 (e.g., in the direction of the trailing edge 141b from the pocket 302). The cavity 304 and is configured to receive an electronic device 306. A passage 308 connects the cavity 304 to the pocket 302. As will be explained further below, the passage 308 is configured to receive a probe 310 (e.g., a temperature probe, a heat flux sensor, a vibration sensor, a strain gauge) that is coupled to the electronic device 306 in the cavity 304.

The cutter element 145 includes a substrate 322 coupled to the pocket 302, and a cutting layer 324 coupled to the substrate 322. The cutting layer 324 includes the cutting face 146 explained above, as well as a back side 326 that is coupled to the substrate 322. The substrate 322 includes a passage 328. The passage 328 of the substrate 322 is configured to couple to the passage 308 of the blade 141 when the cutter element 145 is arranged in the pocket 302. As a result, the probe 310, such as a temperature probe, may be positioned extending through the passage 308 in the blade 141, and through the passage 328 in the substrate 322. A measuring tip 318 of the probe 310 is thus able to contact or abut the back side 326 of the cutting layer 324 of the cutter element 145.

The electronic device 306 in the cavity 304 is coupled to the probe 310 and is configured to acquire and store data generated by the probe 310. In an example in which the probe 310 is a temperature probe, the probe 310 may generate a time series of data indicative of temperature sensed by the probe 310. In another example in which the probe 310 is a heat flux sensor, the probe 310 may generate a time series of data indicative of heat flux (e.g., across the back side 326) sensed by the probe 310. In an example in which the probe 310 is a vibration sensor, the probe 310 may generate a time series of data indicative of vibrations sensed by the probe 310. In yet another example in which the probe 310 is a strain gauge, the probe 310 may generate a time series of data indicative of strain (e.g., deflection of the back side 326) sensed by the probe. Regardless of the type of probe 310, in some examples, the electronic device 306 is coupled to the probe 310 by a wired connection, while in other examples the electronic device 306 is coupled to the probe 310 by a wireless connection (e.g., a near-field wireless link). The electronic device 306 may additionally comprise (or be coupled to) a power source, such as a battery, which is co-located in the cavity 304 as well.

The electronic device 306 may be disposed in a housing 312, which may provide structural support to and protection for the electronic device 306. The housing 312 may be made from various materials, sufficiently rigid to support and protect the electronic device 206 such as plastic, metal, or a composite material. In some examples, the probe 310 includes a shoulder 316 or flange that extends radially from a main portion of the probe 310. A biasing element 314, such as a spring, is disposed between the shoulder 316 and the housing 312 for the electronic device 306, and is configured to bias the shoulder 316, and thus the probe 310, away from the housing 312. As a result, the biasing element 314 maintains contact between the measuring tip 318 of the probe and the back side 326 of the cutting layer 324 of the cutter element 145. In another example, rather than a biasing element 314, an adhesive may be applied to the probe 310 to fix the probe 310 in a contacting relationship with the back side 326 of the cutting layer 324. For example, the probe 310 may be potted in material (e.g., thermally-conductive and/or relatively rigid epoxy) that maintains the measuring tip 318 in contact with the back side 326 of the cutting layer 324, and thus capable of sensing an environmental parameter proximate thereto. In another example, a adhesive may be utilized to couple the measuring tip 318 to the back side 326 of the cutting layer 324.

A pressure cap 320 is used to seal the cavity 304 from an environment external to the drill bit 100 and thus to the blade 141 as well. A seal between the pressure cap 320 and the blade 141 (e.g., the walls of the cavity 304) may be formed in any suitable manner. For example, the pressure cap 320 may be welded to the walls of the cavity 304. In another example, the pressure cap 320 may be threaded into the cavity 304 and against a sealing member, such as a crush O-ring or an elastomeric O-ring. Regardless of how the pressure cap 320 seals the cavity 304 from the external environment, the pressure cap 320 protects the electronic device 306 and the probe 310 from exposure to harsh conditions, which may damage one or both devices 306, 310. Further, the passage 328 is also protected from the environment external to the drill bit 100 by a bond between the substrate 322 and the pocket 302. For example, a bond formed by brazing the substrate 322 to the pocket 302 acts as a seal between the passage 328 and the environment external to the drill bit 100.

In some examples, the probe 310 is a temperature probe 310 as explained above and may be, for example, a thermocouple, a thermistor, or other types of probes suitable to measure a temperature proximate the back face 326 of the cutting layer 324.

Once the drill bit 100 is retrieved to the surface, the data stored on the electronic device 306 may be accessed. For example, the electronic device 306 may be accessed to download data acquired and stored by the electronic device 306 while the drill bit 100 performed drilling operations downhole. As explained above, the data acquired and stored by the electronic device 306 may include a time series of temperature data generated by the temperature probe 310 during drilling operations. In other examples, the data acquired and stored by the electronic device 306 may include a time series of heat flux data, vibration data, and/or strain data. The data from the electronic device 306 may 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 306, for example to correlate or associate measured parameters from the probe 310 at the back side 326 of the cutting layer 324 to actual parameters experienced at the cutting face 146 of the cutting layer 324. For example, the computing device may apply correlations derived based on heat transfer analyses to correlate measured temperature data from the back side 326 with actual temperatures experienced at the cutting face 146 of the cutting layer 324. Such heat transfer analyses may take into account material properties of the cutting layer 324, such as a thickness of the cutting later 324. 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 layer 324 experiences wear during drilling operations downhole, a thickness of the cutting layer 324 changes 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 306, may apply such correlations over time for the thickness of the cutting layer 324 to more accurately correlate the measured temperature data with actual temperatures experienced at the cutting face 146 of the cutting layer 324. In some examples, the change over time of the thickness of the cutting layer 324 is estimated based on a known starting thickness of the cutting layer 324, an observed thickness of the cutting layer 324 upon retrieval of the drill bit, and material properties of the cutting layer 324 (e.g., that indicate a typical behavior of the cutting layer 324 as it wears). For example, certain cutting layer 324 materials may wear at an approximately linear rate as a function of time, while other cutting layer 324 materials may wear at exponential or other nonlinear rates as a function of time. Regardless of how the cutting layer 324 thickness 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 side 326 of the cutting layer 324 with actual temperatures experienced at the cutting face 146 of the cutting layer 324.

FIG. 4 shows a flow chart of a method 400 for processing or analyzing data acquired and stored by the drill bit 100 (e.g., by the electronic device 306) in accordance with various examples. The method 400 begins in block 402 with acquiring data from a probe (e.g., probe 310) positioned proximate to a backside 324 of a cutter element 145 of a drill bit 100. As explained above, the probe 310 may abut the back side 324 of the substrate 322 of the cutter element 145 and is configured to measure an environmental parameter. In some examples, the probe 310 is 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 probe 310 may be configured to sense multiple environmental parameters and/or multiple probes 310 may be used, where the probes 310 sense different environmental parameters. Regardless of the number of probe(s) 310 and the number of environmental parameter(s) that are measured, the probe 310 measures the environmental parameter away from the cutting face 146 of the cutting layer 324 of the cutter element 145, and thus is protected from the harsh wellbore environment external to the drill bit 100. The acquired data is transmitted from the probe 310 to an electronic device 306, which stores the acquired data.

The method 400 continues in block 404 with downloading the acquired data from the electronic device 306. In some cases, the drill bit 100 is 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 device 306 while the drill bit 100 remains downhole, for example through a wired and/or wireless connection (e.g., a drillstring-based telemetry system).

The method 400 then continues in block 406 with processing the downloaded data to correlate the measured environmental parameter with an actual environmental parameter proximate a cutting surface 146 of the cutter element 145. As explained above, the data acquired and stored by the electronic device 306 may include a time series of temperature data generated by the temperature probe 310 during drilling operations. The downloaded data is processed to correlate or associate measured temperatures from the temperature probe 310 at the back side 326 of the cutting layer 324 to actual temperatures experienced at the cutting face 146 of the cutting layer 324. In other examples in which the probe 310 instead 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 side 326 of the cutting layer 324 to actual parameter(s) experienced at the cutting face 146 of the cutting layer 324.

As explained above, processing may include applying correlations derived based on heat transfer analyses to correlate measured temperature data from the back side 326 with actual temperatures experienced at the cutting face 146 of the cutting layer 324. 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 side 326 with the actual parameters experienced at the cutting face 146 of the cutting layer 324. Regardless of the particular parameter(s) being sensed, these analyses may take into account material properties of the cutting layer 324, such as a thickness of the cutting later 324, a material of the cutting layer 324, a hardness of the cutting layer 324, 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 layer 324 experiences wear during drilling operations downhole, a thickness of the cutting layer 324 changes 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 324, and also correlating a second measured parameter with a second actual parameter based on a second thickness of the cutting layer 324. Thus, the effect of the changes in thickness of the cutting layer 324 are 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 elements 145 of the drill bit 100. The remedial action may include changing design parameters of the drill bit 100 such as position, shape, or other physical attributes of the cutter elements 145; and position, shape, or other physical attributes of the nozzles 108. In some examples, remedial action is only taken if a calculated or estimated parameter for at least one cutter element 145 is 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 100), while in other embodiments, the remedial action taken may be automated (e.g., a computer program modifies design parameters of the drill bit 100 based on an understanding of the impact(s) of such modifications on thermal wear life of the cutter elements 145 of the drill bit 100).

By modifying the design parameters of the drill bit 100, the thermal wear on cutter elements 145 of the drill bit 100 may be improved upon, which in turn increases the expected lifespan of the drill bit 100. In some embodiments, the design parameters of the drill bit 100 are manually adjusted (e.g., by an engineer viewing a preliminary graphical display). In other embodiments, the design parameters of the drill bit 100 are 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.