THERMAL ANALYSIS OF DRILL BITS

A method includes receiving a drill bit design, which specifies design parameters related to a plurality of cutter elements of the drill bit. The method also includes estimating a thermal impact value for the cutter elements based on the design parameters and one or more drilling parameters, and estimating a cooling capacity value for the cutter elements based on the design and one or more cooling parameters. Finally, the method includes presenting the thermal impact values or the cooling capacity values together or individually on a per cutter element basis or as a function of a geometrical or physical property of the cutter elements.

Not applicable.

BACKGROUND

The disclosure relates generally to designing drill bits for drilling a borehole in an earthen formation for the ultimate recovery of oil, gas, or minerals. More particularly, the disclosure relates to designing drill bits to improve the thermal wear life of drill bit cutter elements.

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 significantly impact the performance of the drill bit, in particular the thermal 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 thermal wear life of the PDC cutter elements.

BRIEF SUMMARY OF THE DISCLOSURE

Examples of the present disclosure are directed to a method that includes receiving a drill bit design that specifies design parameters related to a plurality of cutter elements of the drill bit, estimating a thermal impact value for the cutter elements based on the design parameters and one or more drilling parameters, and estimating a cooling capacity value for the cutter elements based on the design and one or more cooling parameters. The method also includes presenting one or more of the thermal impact values and the cooling capacity values responsive to a user input selecting one of a presentation on a per cutter element basis or as a function of a property of the cutter elements.

Other examples of the present disclosure are directed to a non-transitory, computer-readable medium containing instructions that, when executed by a processor, cause the processor to receive a drill bit design from a memory, the design specifying design parameters related to a plurality of cutter elements of the drill bit; estimate a thermal impact value for the cutter elements based on the design parameters and one or more drilling parameters; estimate a cooling capacity value for the cutter elements based on the design and one or more cooling parameters; and display one or more of the thermal impact values and the cooling capacity values responsive to a user input selecting one of a presentation on a per cutter element basis or as a function of a property of the cutter elements.

Yet other examples of the present disclosure are directed to a computing device including a memory configured to store a drill bit design. The drill bit design specifies parameters related to a plurality of cutter elements of the drill bit. The computing device also includes a processor coupled to the memory. The processor is configured to receive the drill bit design from the memory; estimate a thermal impact value for the cutter elements based on the design parameters and one or more drilling parameters; estimate a cooling capacity value for the cutter elements based on the design and one or more cooling parameters; and display, on a display device, one or more of the thermal impact values and the cooling capacity values responsive to a user input selecting one of a presentation on a per cutter element basis or as a function of a property of the cutter elements.

Still other examples of the present disclosure are directed to a drill bit designed according to the method above. Still other examples of the present disclosure are directed to a visual representation of data generated according to the method above.

DETAILED DESCRIPTION

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.

As previously described, PDC cutter elements are affected by thermal factors that lead to increased wear. In certain examples, the thermal factors acting on the various cutter elements is disproportionate, leading to increased wear on certain cutter elements relative to others. Although drilling fluid is used to cool the cutter elements, various drill bit designs may result in certain cutter elements having more or less available cooling capacity (e.g., exposure to drilling fluid) than others.

Embodiments described herein are directed to a method for determining a thermal impact value for the cutter elements of a drill bit, such as a temperature rise over a baseline temperature during operation of the drill bit, Additionally, a cooling capacity coefficient is determined for the cutter elements of the drill bit, and a visual representation of the thermal impact value and the cooling capacity of drilling fluid on a per cutter element basis is used to alter design parameters of the drill bit to reduce thermal wear on the cutter elements of the drill bit during operation. Embodiments described herein are also directed to drill bits designed using such methods. As will be described in more detail below, embodiments of the method and drill bits described herein seek to improve the thermal wear life of cutting elements of the drill bit.

Referring now toFIG. 1, a schematic view of an embodiment of a drilling system10in accordance with the principles described herein is shown. Drilling system10includes a derrick11having a floor12supporting a rotary table14and a drilling assembly90for drilling a borehole26from derrick11. Rotary table14is 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 table14) may be augmented or replaced by a top drive suspended in the derrick (e.g., derrick11) and connected to the drillstring (e.g., drillstring20).

Drilling assembly90includes a drillstring20and a drill bit100coupled to the lower end of drillstring20. Drillstring20is made of a plurality of pipe joints22connected end-to-end, and extends downward from the rotary table14through a pressure control device15, such as a blowout preventer (BOP), into the borehole26. The pressure control device15is commonly hydraulically powered and may contain sensors for detecting certain operating parameters and controlling the actuation of the pressure control device15. Drill bit100is rotated with weight-on-bit (WOB) applied to drill the borehole26through the earthen formation. Drillstring20is coupled to a drawworks30via a kelly joint21, swivel28, and line29through a pulley. During drilling operations, drawworks30is operated to control the WOB, which impacts the rate-of-penetration of drill bit100through the formation. In this embodiment, drill bit100can be rotated from the surface by drillstring20via rotary table14and/or a top drive, rotated by downhole mud motor55disposed along drillstring20proximal bit100, or combinations thereof (e.g., rotated by both rotary table14via drillstring20and mud motor55, rotated by a top drive and the mud motor55, etc.). For example, rotation via downhole motor55may be employed to supplement the rotational power of rotary table14, if required, and/or to effect changes in the drilling process. In either case, the rate-of-penetration (ROP) of the drill bit100into the borehole26for a given formation and a drilling assembly largely depends upon the WOB and the rotational speed of bit100.

During drilling operations a suitable drilling fluid31is pumped under pressure from a mud tank32through the drillstring20by a mud pump34. Drilling fluid31passes from the mud pump34into the drillstring20via a desurger36, fluid line38, and the kelly joint21. The drilling fluid31pumped down drillstring20flows through mud motor55and is discharged at the borehole bottom through nozzles in face of drill bit100, circulates to the surface through an annular space27radially positioned between drillstring20and the sidewall of borehole26, and then returns to mud tank32via a solids control system36and a return line35. Solids control system36may include any suitable solids control equipment known in the art including, without limitation, shale shakers, centrifuges, and automated chemical additive systems. Control system36may include sensors and automated controls for monitoring and controlling, respectively, various operating parameters such as centrifuge 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 toFIG. 2, drill bit100is a fixed cutter bit, sometimes referred to as a drag bit, and is designed for drilling through formations of rock to form a borehole. Bit100has a central or longitudinal axis105, a first or uphole end100a, and a second or downhole end100b. Bit100rotates about axis105in the cutting direction represented by arrow106. In addition, bit100includes a bit body110extending axially from downhole end100b, a threaded connection or pin120extending axially from uphole end100a, and a shank130extending axially between pin120and body110. Pin120couples bit100to drill string20, which is employed to rotate the bit100to drill the borehole26. Bit body110, shank130, and pin120are coaxially aligned with axis105, and thus, each has a central axis coincident with axis105.

The portion of bit body110that faces the formation at downhole end100bincludes a bit face111provided with a cutting structure140. Cutting structure140includes a plurality of blades which extend from bit face111. In some examples, cutting structure140includes three angularly spaced-apart primary blades141, and three angularly spaced apart secondary blades142. Although bit100is shown as having three primary blades141and three secondary blades142, in general, bit100may comprise any suitable number of primary and secondary blades.

Primary blades141and secondary blades142are separated by drilling fluid flow courses143. Each blade141,142has a leading edge or side141a,142a, respectively, and a trailing edge or side141b,142b, respectively, relative to the direction of rotation106of bit100.

Referring still toFIG. 2, each blade141,142includes a cutter-supporting surface144for mounting a plurality of cutter elements145. In particular, cutter elements145are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade141and each secondary blade142. 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 element145has a cutting face146and 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 element145has substantially the same size and geometry. Cutting face146of each cutter element145comprises 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 element145is mounted such that its cutting face146is 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 direction106of bit100). For instance, a forward-facing cutting face (e.g., cutting face146) may be oriented perpendicular to the direction of rotation106of bit100, may include a backrake angle, and/or may include a siderake angle. However, the cutting faces are preferably oriented perpendicular to the direction of rotation106of bit100plus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting face146includes 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 faces146are substantially planar, but may be convex or concave in other embodiments.

Referring still toFIG. 2, bit body110further includes gage pads147of substantially equal axial length measured generally parallel to bit axis105. Gage pads147are circumferentially-spaced about the radially outer surface of bit body110. Specifically, one gage pad147intersects and extends from each blade141,142. In this embodiment, gage pads147are integrally formed as part of the bit body110. In general, gage pads147can help maintain the size of the borehole by a rubbing action when cutter elements145wear slightly under gage. Gage pads147also help stabilize bit100against vibration. Further, a nozzle108is seated in the lower end of each flow passage107. Together, passages107and nozzles108distribute drilling fluid around cutting structure140to flush away formation cuttings and to remove heat from cutting structure140, and more particularly cutting elements145, during drilling.

Referring now toFIG. 3, a flow chart of a method300for thermal analysis of the cutter elements145of the drill bit100is shown. The thermal analysis method300begins in block302with estimating a thermal bad value (e.g., thermal energy input) for the cutter elements145of the drill bit100using application parameters301(e.g., based on a received drill bit100design) such as rotary speed, depth of cut, cut areas, or other parameters relevant to engagement of the cutter element145with the earthen formation, as well as cutting forces (which are related to the type of material being cut through). Application parameters301may also include other information such as the flow rate or temperature of the drilling fluid pumped through the drill bit100. The drill bit100design and other application parameters301may be stored in a memory of a computing device, which is accessible by software executed by the computing device to facilitate the performance of the method300described here and further below.

Next, using the parameters related to the geometry of the drill bit100, the cutter elements145, and the nozzles108, for example from the drill bit100design (block305), as well as thermophysical properties303of the drilling fluid, the drill bit100, and the cutter elements145, the thermal analysis300is conducted to calculate the temperature and the cooling capacities for each cutter element145. The parameters related to the geometry of the drill bit100comprise relevant information about the geometry of the cutter element145, its position and orientation on the drill bit100, the relative distance between one cutter element145and other cutter elements145(e.g., adjacent cutter elements145), and other geometrical features of the drill bit100or the nozzles108, including their shape, location, size, and orientation (block305). The thermophysical properties303for the thermal analysis300include thermal conductivity of various portions of the drill bit100, such as the diamond table, substrate, and body, as well as viscosity, thermal conductivity, heat capacity, and density of the drilling fluid. The thermal analysis300may use inputs from application parameters301depending on the analysis technique.

Based on some or all of the foregoing parameters, a variety of methods can be employed to calculate cutter element145temperatures (block306) or the cooling capacity of drilling fluid (block304). For example, finite element analysis, finite volume analysis, or similar numerical techniques can be used to solve the governing fluid and energy equations in the region (e.g., of the bit100) of interest. A direct output of such a solution may be temperature of various cutter elements145and the drilling fluid in proximity to those cutter elements145. The cooling capacity of the drilling fluid may be computed based on the temperature outputs and other physical properties of the drilling fluid and the cutter elements145. For example, different analysis techniques may be used to obtain these outputs with different degrees of accuracy, and there is no required method to obtain such outputs. Other possible techniques can include analytical solutions and empirical equations, among others.

Referring briefly toFIG. 4, a thermal distribution model400is shown for five cutter elements145as a visual example of the thermal impact value for an example grouping of cutter elements145. As can be seen, the thermal distribution model400includes a middle cutter element402and an outer cutter element404. The middle cutter element402has an increased thermal impact value relative to the outer cutter element404. Certain factors that lead to the increased thermal impact value of the middle cutter element402may include its proximity to other cutter elements (e.g., having cutter elements406,408in close proximity, whereas the cutter element404only has cutter element408in close proximity), and the thermal conductivity of the surrounding material (e.g., the material near the middle cutter element402is warmer than the material near the outer cutter element404, and thus more heat is conducted away from the outer cutter element404than the middle cutter element402). Additionally, the available amount of cooling capacity provided by drilling fluid can also affect these temperatures. Therefore, it is also possible that the outer cutter element404is provided with relatively higher cooling capacity from the drilling fluid, contributing to its lower temperature.

Referring now toFIG. 5, an example graph500of thermal impact values on a per cutter element145basis is shown. In the example graph500, the thermal impact values are delta-T values, or a temperature rise for each cutting element145relative to a baseline value. In an example, the baseline value is the temperature of drilling fluid being pumped through the drill bit100. As can be seen in the example graph500, certain cutter elements145experience a larger delta-T relative to the drilling fluid temperature than other cutter elements. Thus, it is important to not only consider the temperature rise of specific cutter elements145, but also the cooling capacity available to those cutter elements145by virtue of the drill bit100design and the drilling fluid properties. Although not shown inFIG. 5, other embodiments of the present disclosure may present thermal impact values (and/or cooling capacities) as a function of cutter element145radius, or other physical properties of cutter elements145that, for example, differ among at least some of the cutter elements145. The determination of how to present the thermal impact values (and/or cooling capacities) may be responsive to a user input or selection.

Referring back toFIG. 3, the temperature output306of thermal analysis300may correspond to any location on a cutter element145. In some examples, the cutter tip may be a more relevant location as it typically has the highest temperature due to engaging the earthen formation. However, in other examples, the temperature at other locations of the cutter element145is determined and used to evaluate a thermal impact factor.

Still referring toFIG. 3, in view of the equation307, the method300for thermal analysis of the cutter elements145of the drill bit100also includes, in block304, calculating or estimating a convective heat transfer rate for the cutter elements145, In some cases, the cooling capacity of drilling fluid is then represented by either the convective cooling coefficient, h, which depends on a variety of factors including physical properties of the fluid and temperature of the cutter surface in contact with fluid, fluid velocity, local turbulence, viscosity, etc. In some cases, the cooling capacity comprises an area integral of the cooling coefficient h, over a certain surface area of the cutter element145, which can be represented as h*A in equation307. In another case, the total convective heat transfer rate, Q, can be the cooling capacity of the drilling fluid. The cooling capacity of the drilling fluid may be calculated for the front face of the cutter element145where the cutter element145is exposed to the drilling fluid. However, other cutter faces, or combinations thereof, may also be used to evaluate the cooling capacity.

Once the cooling capacity of the drilling fluid and thermal impact values have been calculated for the cutter elements145of the drill bit100, embodiments of the present disclosure may include generating a graphical display of the cooling capacities and the thermal impact values on a per cutter element145basis. Turning toFIG. 6, an example of such a graphical display is shown. InFIG. 6, a preliminary graphical display602represents the cooling capacities of drilling fluid and the thermal impact values for a number of cutter elements145. The cooling coefficients are expressed in Watts, Watts/Kelvin or Watts/Kelvin/area depending on the chosen unit determined inFIG. 3. The thermal impact values are represented as delta-T above a baseline (e.g., drilling fluid temperature) in degrees Celsius. The highlighted area604demonstrates certain of the cutter elements145for which the thermal impact value is highest, but where cooling capacities are relatively lower. This indicates a potential imbalance between thermal energy generation and removal. Those cutter elements145in the area604may experience premature thermal wear relative to the cutter elements145outside of the area604, where adequate cooling capacity versus thermal impact exists.

In certain embodiments of the present disclosure, remedial action may be taken to address the imbalance between the cooling coefficients and the thermal impact values in the highlighted area604. The remedial action may include changing design parameters of the drill bit100such as position, shape, or other physical attributes of the cutter elements145; and position, shape, or other physical attributes of the nozzles108. In some examples, remedial action is only taken if the thermal impact for at least one cutter element145outweighs the cooling capacity for that cutter element145compared to other cutter elements. Although cooling capacity and thermal impact values are not of the same units, in some embodiments a correlation between the two units is established, and a comparison between values takes place, where a thermal impact value exceeding a corresponding cooling capacity by at least a threshold amount is considered (i.e., remedial action may not be needed if the cooling capacity for the cutter element145is sufficiently close in value to the thermal impact value for that cutter element145). In certain embodiments, the remedial action taken may be manual (e.g., an engineer modifies design parameters of the drill bit100), while in other embodiments, the remedial action taken may be automated (e.g., a computer program modifies design parameters of the drill bit100based on an understanding of the impact(s) of such modifications on thermal wear life of the cutter elements145of the drill bit100).

FIG. 6also shows a subsequent graphical display606, which represents the cooling capacities and the thermal impact values for the cutter elements145of a drill bit100following the changes to design parameters of the drill bit100. In particular, the subsequent graphical display606includes a highlighted area608that corresponds to the highlighted area604of the preliminary graphical display602. As can be seen, after the changes to design parameters of the drill bit100, the cooling capacities in the highlighted area608have been improved upon, and thus a relative improvement value is demonstrated in the subsequent graphical display606. Additionally, although certain other cooling capacities outside of the highlighted area608have been reduced, these reduced cooling capacities are still within a tolerable range of the corresponding low thermal impact values in those areas outside the area608(e.g., within a threshold amount of the corresponding thermal impact value). In other examples, where thermal impact values have not changed during an update to drill bit design parameters, but the cooling capacities have changed, the change in cooling capacities is demonstrated by displaying or presenting cooling capacities from before and after the updates to design parameters to demonstrate the improvements.

By modifying the design parameters of the drill bit100in response to the preliminary graphical display602, the thermal wear on cutter elements145of the drill bit100is improved upon, which in turn increases the expected lifespan of the drill bit100. In some embodiments, the design parameters of the drill bit100are manually adjusted (e.g., by an engineer viewing the preliminary graphical display602). In other embodiments, the design parameters of the drill bit100are automatically adjusted, for example by a software tool. In certain cases, the software tool modifies certain design parameters of the drill bit100and again performs the methods described herein to generate one or more intermediate plots of cooling capacities and thermal impact values that represent the impact of the modifications to the drill bit100design parameters. In this way, the software tool may take an iterative approach to modifying design parameters of the drill bit100to improve the overall thermal wear characteristics (e.g., improve or reduce the imbalance between the cooling capacities and thermal impact values for the cutter elements145) for the drill bit100.

Embodiments of this disclosure may include a computing device and/or associated software, embodied on a non-transitory computer-readable medium that, when executed by the computing device (e.g., a processor), causes the computer to perform some or all of the method steps described herein. Further, the various described graphical displays may be displayed on a computer monitor, printed as a hard copy, or otherwise displayed to a user. In the examples where modifications to the design parameters of a drill bit100are carried out by a software tool executed on a computer, one or more of the described graphical display elements may not be actually displayed to a user, although the data that would otherwise be displayed (e.g., the cooling capacities and thermal impact values on a per cutter element145basis) may be taken into account by the software tool in modifying the design parameters of the drill bit100.