1. Field of the Invention
The present invention relates to rotary drag bits for drilling subterranean formations and their operation. More specifically, the present invention relates to a method of designing such bits for optimum performance by evaluating the work-force rate and sliding-wear rate of the cutting elements on a bit and positioning the cutting elements so as to improve the overall durability and efficiency of the bits.
2. State of the Art
The drilling industry has employed rotary drag bits for nearly a century, and has undergone significant change since then. Today, the most common rotary drag bits are impregnated diamond bits and bits with polycrystalline diamond compact (PDC) cutting elements, or “cutters.” Impregnated diamond bits, rather than having separate cutters, consist of many, relatively small, diamonds, or diamond particles, set in a tungsten carbide matrix throughout the face and crown of the bit. Impregnated diamond bits perform best in non-brittle, plastic formations, abrasive formations, and high-rotary speed drilling. PDC cutting elements typically comprise a disc-shaped diamond “table” formed on a supporting substrate (e.g., a cemented tungsten carbide (WC) substrate, etc.) and bonded to the substrate under high pressure, high temperature conditions. Many separate PDC cutting elements are inserted into and secured within (e.g., brazed into, etc.) pockets in the bit face and in blades that extend from the face, or are mounted to studs inserted into the bit body. Bits carrying PDC cutting elements have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths.
The rotary drag bit is placed at the end of a long string of hollow steel tubulars, or drill pipe, to drill a well. A single pipe, or joint, of drilling tubular is approximately 30 feet (about 10 m), and three drill pipes frequently are threaded together to form a single, ninety foot (about 30 m) stand. Individual stands of pipe are then threaded together to form an entire drill string that reaches the bottom of the well, with subsequent stands added as needed as the well is drilled deeper. A drill string may reach a length of hundreds or thousands of feet, and may even be several miles or kilometers long. The drill string with the bit attached is then turned from the surface with a rotary drive mechanism; in some instances, a down-hole motor is located between the drill pipe and the bit additionally turns the bit. For drilling a well with a specified geometry, a down-hole motor or turbine in combination with a bent housing or sub may be used to rotate the bit alone while the pipe remains stationary.
The economic cost of drilling a well strongly depends upon the ROP, or the rate at which the bit drills into the formation, usually measured in feet per hour (or meters per hour). Therefore, subject to several constraints, such as limits to a particular drilling rig, formation characteristics, drilling fluid properties, and others, a drilling contractor seeks to maximize the ROP, which minimizes the cost per foot (or meter) drilled.
In addition to the rate at which a particular bit drills, another significant factor in the economic efficiency of drilling a well is the durability of the bit, or that rate at which its cutting elements wear. That is, it is desirable to have a bit drill as long as possible before it must be replaced due to dulling of or damage to the cutting elements. As mentioned, the bit is located at the end of a string of drill pipe. To replace a worn bit, the entire string must be pulled or “tripped” out of the hole either by the single joint or by the stand, a time consuming process in any case, more so when the string extends several miles into the earth and takes upwards of a day to remove from the well. Thus, it is desirable to have a bit that wears less for a given amount of formation drilled.
An unmet need exists for a method of designing drill bits that associates the work-force rate and sliding-wear rate to the volume and location of cutting elements. Other factors may further by optimized in conjunction with the present invention. Other factors of bit design, including, without limitation, back-rake and side-rake angles, cutter edge geometry (e.g., chamfer, etc.), bit profile, or others, may be further individually optimized or in combination. Examining these aforementioned factors holistically, rather than individually, provides a novel solution that increases the life of a bit (distance drilled), aggressiveness (ROP), and efficiency (the rate or manner in which the bit wears).
The present invention includes methods for designing drill bits that include evaluating a combination of factors to optimize the duration and efficiency of the bit.
The method includes several acts, the order of which may be taken in a manner that best suits the needs of the person practicing the invention. A drill bit drills a formation, which may occur in a computer simulation, a laboratory test, or in the field on a drilling rig. The cutting elements are evaluated, which may include the work-force rate and the sliding-wear rate. “Work-force rate” is a calculation of the force on the cutting elements and the distance over which that force is applied, and may be normalized against a benchmark, which may include distance drilled or ROP, among others. “Sliding-wear rate” evaluates the dull condition of a cutting element, which may include the area of the cutting element worn away for a given distance that the cutting element travels across a formation during drilling thereof.
A bit design may incorporate information gathered during drilling. The bit design may include an adjustment of the number of cutting elements on a bit, an adjustment of the location of one or more cutting elements on the bit, an adjustment to the orientation of one or more cutting elements of the bit, a change in the number of blades on the bit, a change in the profile, or length of the bit, alteration of bit hydraulics, or a combination of any of the foregoing. Such changes may improve the durability or efficiency of the bit. For example, cutting elements may be added to, deleted from, or moved from locations in a prior bit design. Such changes reduce the number of cutting elements that experience a low work-force or sliding-wear rate, while increasing the number of cutting elements at locations in a new bit design where the cutting elements experience greater work or wear. Again, the total number of cutting elements may stay the same as compared to the original bit, or may increase or decrease. Finally, the process may include selecting a particular rotary drag bit to drill a given formation, as well as optimizing a rotary drag bit to drill a given formation.
Optionally, the new bit design may be tested by drilling a formation, similar to the test conducted on the previous bit design, or by another method. The new bit design may be evaluated for work-force rate, sliding-wear rate, and/or other characteristics of interest. The new bit design may be further modified to alter or enhance desired traits, which may include the aggressiveness, the durability/redundancy of cutting elements, efficiency, or other traits, individually or in combination.
A drill bit that has been designed in accordance with the teachings of the present invention is also within the scope of the present invention. Such a drill bit may include features, such as cutting elements, that are arranged and oriented to optimize the achievable ROP while minimizing the wear of the cutting elements by placing an adequate number of cutting elements in those locations that previously exhibited adverse work-force and sliding-wear rates.
Other features and advantages of the present invention will become apparent to those of skill in the art through consideration of the ensuing description, the accompanying drawings, and the appended claims.
One embodiment of a method according to the present invention includes a series of acts that, while described in a particular order here and in
The characteristics that are evaluated during or following drilling may include, but are not limited to, the size, shape, and orientation of a wear flat on one or more cutting elements; the condition of the cutting elements, the bit body, or other features of the bit; characteristics of the formation drilled, including, without limitation, abrasiveness and compressive strength; the drilling fluid used; operating parameters, such as weight-on-bit (WOB) or torque; or any combination of the foregoing.
An algorithmic (e.g., computer-based) model or physical model of the drill bit may be developed, at reference 12, in a manner known in the art. As a nonlimiting example of an algorithmic model, some form of the PDCWEAR computer code or other suitable algorithm or set of algorithms, embodied in a computer program or otherwise, may be used. D. A. Glowka, Use of Single-Cutter Data in the Analysis of PDC Bit Designs: Part 2Development and Use of the PDCWEAR Computer Code, J. Petroleum Tech., 850, SPE Paper No. 19309 (August 1989), the disclosure of which is hereby incorporated herein, in it entirety, by this reference, is an example of a PDCWEAR program that may be used.
The model may include a work-force model, a sliding-wear model, or any other model or combination of models useful for determining the wear or work of one or more individual cutting elements during drilling. The model may account for the location of one or more individual cutting elements, hydraulics, or other parameters of interest. The model may be calibrated, at reference 13, so that it correlates to those characteristics recorded during and after the bit drilled the formation. The model of the bit that drilled the formation may be used as a template for a new bit, or an entirely new drill bit design may be created, as indicated at reference 14 of
Various factors that affect bit performance may be modified, including, but not limited to, the location or volume of one or more cutting elements, as compared to the location or volume of one or more corresponding cutting elements of a previous bit design. For example, the location of one or more cutting elements may be moved from a location on a bit where they experience a relatively low work-force or sliding-wear rate, or both, to a location on the bit that experiences a relatively high work-force or sliding-wear rate, or both. Other elements that may be adjusted, individually or in combination, include, but are not limited to, the number of blades, or “blade count;” the length or shape of the bit profile; the hydraulics of the bit, including, without limitation, the size, location, or orientation of nozzles and the size, number, or paths of fluid courses; the size, shape, or number of cutting elements; and operating parameters, such as weight on bit, rate of rotation, and the like.
A virtual model of the bit may be run in the previously developed computer model to simulate drilling a formation or a physical model of the bit may be run in a well or a laboratory test fixture, as indicated at reference 15. The results achieved with the new drill bit may be compared with the original bit, at reference 16, with subsequent improvements iteratively tested, at reference 17, if necessary, until an optimum design is reached, which may include optimizing a bit to drill in a specific field, formation, application, or other need. Thus, the process may be used to select an optimum bit design for drilling a formation, which might include using either an existing bit design or developing a new bit design optimized for the particular formation or field.
In another embodiment, the manner in which an existing drill bit wears while drilling a formation is recorded, at reference 21 of
The back-rake and side-rake angles of individual cutting elements, or the geometries (e.g., chamfer, etc.) of their edges, may be altered, at reference 26, which may change the aggressiveness with which such cutting elements attack a formation, as well as the overall aggressiveness of the bit. By increasing the volume or number of cutting elements at one or more locations (e.g., radial positions) on a bit where cutting elements exhibit excessive adverse work or wear, the rake angle of one or more cutting elements may be altered to change the aggressiveness with which that cutting element attacks a formation. Side-rake angles affect how a cutting element pushes drilled cuttings to the side of the cutting element, much like the action of a plow. Back-rake angle is the angle of the face of the cutting element relative to a vertical line perpendicular to the face of a formation being drilled, and is usually expressed in terms of a negative angle, although positive back-rake, or forward-raked, cutting element orientations have been proposed. Thus, the cutting face of the cutting element is angled backwards, or leaning away, from the direction of the rotation of the bit. A back-rake angle of 0° would indicate that the cutting element is vertical, or perpendicular to the formation, and may be termed a “neutral” back-rake. The smaller the back-rake angle, i.e. the closer to zero or vertical, the more aggressively the cutting element attacks the formation. Edge geometries may also be tailored to provide desired effects.
The back-rake and side-rake angles, and/or the edge geometry of one or more cutting elements, may be matched to the formation drilled, with more aggressive angles (closer to zero) suitable to softer formations and less aggressive angles suitable for harder formations. Conventionally, more aggressive back-rake and side-rake angles correspond to greater cutting element and bit wear rates. Thus, the durability of a bit and the ROP for which the bit is designed may be optimized as needed or desired for a particular application, at reference 27.
As an example, the aggressiveness of a bit may be maximized at the expense of the wear condition, which may be of particular use for a short drilling section in environments in which costs are particularly high, such as offshore. In other situations, durability might be paramount as compared to aggressiveness, such as in situations where a bit run is anticipated to be quite long and the time needed to trip in and out of the hole is significant. An optimum balance between durability and aggressiveness may be achieved.
Other elements that may be adjusted include, but are not limited to, the profile of the bit; the size, shape and number of the cutting elements; hydraulics of the bit, including placement, orientation, and size of nozzles and fluid courses; stability; and other factors.
The term “stability” refers to the tendency of a bit, in particular PDC bits, to suffer from vibration and whirl, both negatively affecting the durability of a bit. Several attempts to describe and model stability are known in the art, including, for example, C. J. Langeveld, PDC Bit Dynamics, SPE/IADC Paper No. 23867 (1992) (presented at the IADC/SPE Drilling Conference in New Orleans, La., Feb. 18-21, 1992) and Thomas M. Warren, et al., Development of a Whirl-Resistant Bit, SPE Drilling Engineering, 297 (December 1990), the entire disclosure of which is hereby incorporated herein, in its entirety, by this reference.
Another possible factor to be evaluated or modified is bit hydraulics, also known in the art, of which just one example is M. R. Taylor, High Penetration Rates and Extended Bit Life Through Revolutionary Hydraulic and Mechanical Design in PDC Bit Development, SPE Paper No. 36435 (1996) (presented at the 1996 SPE Annual Technical Conference and Exhibition in Denver, Colo., Oct. 6-9, 1996), the disclosure of which is hereby incorporated herein, in its entirety, by this reference.
Several bits were evaluated in accordance with teachings of the present invention.
The existing bit designs are represented by reference numerals 41 and 51, while the bits that have been designed in accordance with teachings of the present invention are represented by reference characters 61 and 61′.
Representative data from a first existing bit 41 (
If a computer model of the bit is used, the computer model of the existing drill bit and the formation that was drilled may be generated by including various parameters, such as characteristics of the formation or formations, drilling equipment, such as mud pump size or rotary drive torque limits, well-bore parameters, such as casing or wellbore dimensions, or other factors. Parameters of the bit may include, without limitation, individually or in combination, bit profile (radius and height), blade dimensions (height, thickness, orientation, number), cutting elements (number, type (PDC, tungsten carbide, natural diamond), back-rake and side-rake angles, radial and axial position, edge geometries, etc.), or hydraulic data (number and size of hydraulic jets which permit drilling fluid to flow out of the bit and into the annulus of the wellbore), or other factors.
A comparison of the profile 47 of bit 41 in
A new bit design, which is referred to in
In
When compared with the bit 51 (
Once the new bits 61 and 61′ were designed and computer models thereof created, a simulation of each new bit 61, 61′ cutting a formation in the model was developed, simulated drilling was effected in a computer model, and the resulting data was collected. Referring again to
Another way to compare the data relates to the average ROP to reach a certain depth, in this case a stop depth of 1,060 feet (323 m) that corresponds to the depth at which the penetration rate of bits 41 and 51 slowed to 15 ft/hr (about 5 m/hr) and is represented by dotted vertical line 33 in
The wear each cutting element undergoes relative to its radial position from the center of the bit may also be compared with the wear of cutting elements at comparable radial positions on one or more other bits. Those cutting elements on the shoulder of the bit, the area between the cone and the gauge of the bit, may wear more quickly than cutting elements at other areas, depending on the geometry of the bit; particularly because elements at the shoulder are the greatest radial distance from the axis of rotation of the bit and, therefore, travel a greater distance, encounter a greater amount of the formation being drilled, and are subject to a greater amount of work than the cutting elements of the bit that are located radially closer to the axis of rotation.
In another example of the method,
The data obtained from drilling with the bits 41, 51, and 81 was compared with drilling data from another exemplary embodiment of bit 91, which is illustrated in
In the cutting element profile 97 of bit 91, several modifications of the bit 91 relative to bits 41, 51, and 81 (
The newly designed bit 91 was subsequently input into the computer model, which was then run for each of the four bits to simulate drilling of a formation. In this instance, an output of the work-force rate that each cutting element underwent during the drilling of the formation was plotted in a graph, as illustrated in
It may be observed that the cutting elements endure the highest work rate in the area between approximately 2½ inches (about 6½ cm) and 3½ inches (about 9 cm) radial distance from the bit center, which corresponds approximately to the radial lines 48, 58, 88, 98 and 49, 59, 89, and 99, respectively. The plot of
The cutting elements 92 of the newly designed bit 91 endure a work rate significantly less than the cutting elements 42, 52, 82 of the other bits 41, 51, 81, as the data indicate. In designing bit 91, a number of cutting elements located elsewhere on the other bits have been moved to the region defined between the lines 98 and 99, which endure the greatest work-force rate. The presence of a larger number of cutting elements 92 in this area reduces the work-force rate that any individual cutting element 92 must undergo. A benefit of this is that, for a given formation, the cutting elements 92 will have increased durability, which should permit a drilling operator to run the bit for longer periods of time and drill greater distances before having to remove the bit because it is worn.
The data for bit 51 indicate that several cutting elements located approximately between 2½ inches (about 6½ cm) and 3½ inches (about 9 cm) radial distance from the axis of rotation of the bit 51 appear to be subjected to little or no work. These cutting elements correspond to the TCI (and/or PDC) backup cutting elements 52′. One reason for the lack of work or wear on the TCI (and/or PDC) backup cutting elements 52′ may be that the primary cutting elements 52 endure all of the initial work cutting the formation when the bit 51 is new and the backup cutting elements 52′ do not appear to undergo any work because they might not yet engage the formation.
Because the cutting elements 92 of newly designed bit 91 endure a reduced work-force rate relative to the work-force rates of the cutting elements 42, 52, and 82 on the other bits 41, 51, and 81, other features of the bit 91 might then be optimized. For example, the cutting elements 92 might be oriented more aggressively vis-à-vis the formation. In other words, the back-rake and/or side-rake angles of the cutting elements 92 may be decreased so that they attack the formation more directly. This might improve the ROP that a bit achieves during the run. Other factors may also be modified, either as an alternative or in conjunction with the modified orientation of the cutting elements.
From the data that has been plotted in the graph of
Related to
Therefore, as the previous embodiments demonstrate, recording observed characteristics of existing drill bits before, during, and after drilling a formation, may be harnessed to design new drill bits. In each case, the performance (distance drilled, rate of penetration) of existing bits and the work-force rate and the sliding-wear rate that the cutting elements endure during the drilling of a formation has been observed. From this, the cutting elements may be moved from those locations that endure a lower work-force and sliding-wear rate to those areas where the cutting elements suffer higher work-force and sliding-wear rates. After doing this, the new bit may be tested against the performance of the existing bit and the results compared. Further improvements may then be taken. For example, the location, number, or volume of cutting elements may be optimized to achieve better durability and reduce wear. This might include, among other things, holding the volume of cutting elements constant, or reducing or increasing the volume. In addition, the profile of the bit itself may be modified to accommodate the new location of cutting elements. This might entail increasing, decreasing, or altogether removing the blades of an existing design, adjusting the height of the profile, or making other modifications to the bit to improve hydraulics, stability, or other parameters known in the art.
Furthermore, the back-rake and/or side-rake angles or edge geometries of individual cutting elements may be modified in direct response to the changed location and volume of cutting elements. More specifically, the back-rake and/or side-rake angles or edge geometries, for example, may be modified so that one or more cuttings elements of a bit designed for increased durability and efficiency attack the formation in a more aggressive manner, such as by reducing the negative back-rake so that the cutting element is oriented more closely to perpendicular with respect to the formation being drilled. Increasing the aggressiveness of the cutting element might not be possible had the location and volume of the cutting elements not previously been optimized by this method. In this manner, a new bit design might have increased durability (distance drilled) and efficiency (wear characteristics), but also improved aggressiveness (rate of penetration) in a way not previously achievable.
The foregoing embodiments and descriptions merely provide examples of various embodiments. For example, while the embodiments disclosed herein relate to bits with PDC cutters, the method might be performed equally with bits having natural diamond cutters. Therefore, the embodiments disclosed do not limit the scope of the invention or its equivalents, which are governed only by the claims.
This application claims the benefit of U.S. Provisional Application No. 60/734,571, filed Nov. 8, 2005, the disclosure of which is hereby incorporated herein, in its entirety, by this reference.
Number | Date | Country | |
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60734571 | Nov 2005 | US |