US20100122848A1 - Hybrid drill bit - Google Patents

Hybrid drill bit Download PDF

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Publication number
US20100122848A1
US20100122848A1 US12274709 US27470908A US2010122848A1 US 20100122848 A1 US20100122848 A1 US 20100122848A1 US 12274709 US12274709 US 12274709 US 27470908 A US27470908 A US 27470908A US 2010122848 A1 US2010122848 A1 US 2010122848A1
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cutting
method
set forth
bit body
earth formation
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Abandoned
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US12274709
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Eric E. McClain
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Baker Hughes Inc
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Baker Hughes Inc
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/42Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
    • E21B10/43Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements

Abstract

A method for optimizing drill bit design and several embodiments of an optimized drill bit for drilling a well in an earth formation. In one embodiment, the optimized drill bit comprises a diamond impregnated bit body with one or more cutting elements, the cutting element comprising a cutting table and a substrate. The substrate preferably comprises a material that will support the cutting table during normal drilling operations and wear when exposed to the earth formation, thereby limiting the effects of wear flat areas on drilling efficiency. Alternatively, or additionally, the cutting elements may be placed, or spaced, so as to limiting the effects of wear flat areas on drilling efficiency.

Description

    CROSS REFERENCE TO RELATED APPLICATIONS
  • This subject matter of this application is similar to the subject matter disclosed in U.S. patent application Ser. Nos. 12/250,443, 12/250,445, 12/250,447, and 12/250,448, all filed Oct. 13, 2008, which are incorporated herein by specific reference.
  • STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
  • Not applicable.
  • REFERENCE TO APPENDIX
  • Not applicable.
  • BACKGROUND OF THE INVENTION
  • 1. Field of the Invention
  • The inventions disclosed and taught herein relate generally to drill bits for drilling wells; and more specifically relate to diamond impregnated drill bits with super-abrasive cutting elements for drilling wells in earth formations.
  • 2. Description of the Related Art
  • U.S. Pat. No. 6,095,265 discloses “a diamond impregnated bit with an adaptive matrix in the ribs. The ribs have at least two different areas of metal-matrix composite impregnated with diamonds with different wear resistance such that during boring of formation, the areas will wear at different rates and provide fluid flow spaces across the surface of the ribs.”
  • U.S. Pat. No. 6,296,069 discloses a “drill bit as used in particular in the oil well drilling field comprising a central body (2), cutting blades (3) protruding with respect to the body (2), both at the front of this body according to a drill direction and at the sides of this same body (2), and cutting elements (9) divided over an outer front surface (10) and over an outer lateral well sizing surface (11) comprised by each blade (3), wherein there are provided as cutting elements: in a central area (13) of the front surface (10), on at least one blade (3): at least one synthetic polycrystalline diamond compact cutting disc (12), and in a remaining area (14) of the front surface (10) of this blade, situated beyond said central area (13) with respect to the rotation axis, and on the other blades: thermally stable synthetic diamonds and/or impregnated diamond particles.”
  • U.S. Pat. No. 6,510,906 discloses a “drill bit employing a plurality of discrete, post-like diamond grit impregnated cutting structures extending upwardly from abrasive particulate-impregnated blades defining a plurality of fluid passages therebetween on the bit face. PDC cutters with faces oriented in the general direction of bit rotation are placed in the cone of the bit, which is relatively shallow, to promote enhanced drilling efficiency through softer, non-abrasive formations. A plurality of ports, configured to receive nozzles therein are employed for improved drilling fluid flow and distribution. The blades may extend radially in a linear fashion, or be curved and spiral outwardly to the gage to provide increased blade length and enhanced cutting structure redundancy.”
  • U.S. Pat. No. 6,843,333 discloses a “drill bit employing a plurality of discrete, post-like, abrasive, particulate-impregnated cutting structures extending upwardly from abrasive, particulate-impregnated blades defining a plurality of fluid passages therebetween on the bit face. Additional cutting elements may be placed in the cone of the bit surrounding the centerline thereof. The blades may extend radially in a linear fashion, or be curved and spiral outwardly to the gage to provide increased blade length and enhanced cutting structure redundancy. Additionally, discrete protrusions may extend outwardly from at least some of the plurality of cutting structures. The discrete protrusions may be formed of a thermally stable diamond product and may exhibit a generally triangular cross-sectional geometry relative to the direction of intended bit rotation.”
  • The inventions disclosed and taught herein are directed to an improved diamond impregnated drill bit with super-abrasive cutting elements for drilling wells in earth formations.
  • BRIEF SUMMARY OF THE INVENTION
  • The invention relates to a method for optimizing drill bit design and several embodiments of an optimized drill bit for drilling a well in an earth formation. In one embodiment, the optimized drill bit comprises a diamond impregnated bit body with one or more cutting elements, the cutting element comprising a cutting table and a substrate. The substrate preferably comprises a material that will support the cutting table during normal drilling operations and wear when exposed to the earth formation, thereby limiting the effects of wear flat areas on drilling efficiency. Alternatively, or additionally, the cutting elements may be placed, or spaced, so as to limiting the effects of wear flat areas on drilling efficiency.
  • BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
  • FIG. 1 comprises an inverted perspective view of a first embodiment of a bit of the present invention;
  • FIG. 2 is a top elevation of the bit of FIG. 1 after testing, showing wear of the discrete cutting structures and PDC cutters; and
  • FIG. 3 is an enlarged perspective view of an exemplary cutting element embodying certain aspects of the present inventions.
  • DETAILED DESCRIPTION
  • The Figures described above and the written description of specific structures and functions below are not presented to limit the scope of what Applicants have invented or the scope of the appended claims. Rather, the Figures and written description are provided to teach any person skilled in the art to make and use the inventions for which patent protection is sought. Those skilled in the art will appreciate that not all features of a commercial embodiment of the inventions are described or shown for the sake of clarity and understanding. Persons of skill in this art will also appreciate that the development of an actual commercial embodiment incorporating aspects of the present inventions will require numerous implementation-specific decisions to achieve the developer's ultimate goal for the commercial embodiment. Such implementation-specific decisions may include, and likely are not limited to, compliance with system-related, business-related, government-related and other constraints, which may vary by specific implementation, location and from time to time. While a developer's efforts might be complex and time-consuming in an absolute sense, such efforts would be, nevertheless, a routine undertaking for those of skill this art having benefit of this disclosure. It must be understood that the inventions disclosed and taught herein are susceptible to numerous and various modifications and alternative forms. Lastly, the use of a singular term, such as, but not limited to, “a,” is not intended as limiting of the number of items. Also, the use of relational terms, such as, but not limited to, “top,” “bottom,” “left,” “right,” “upper,” “lower,” “down,” “up,” “side,” and the like are used in the written description for clarity in specific reference to the Figures and are not intended to limit the scope of the invention or the appended claims.
  • Particular embodiments of the invention may be described below with reference to block diagrams and/or operational illustrations of methods. In some alternate implementations, the functions/actions/structures noted in the figures may occur out of the order noted in the block diagrams and/or operational illustrations. For example, two operations shown as occurring in succession, in fact, may be executed substantially concurrently or the operations may be executed in the reverse order, depending upon the functionality/acts/structure involved.
  • Applicants have created both a method for optimizing drill bit design and several embodiments of an optimized drill bit for drilling a well in an earth formation. In one embodiment, the optimized drill bit comprises a diamond impregnated bit body with one or more cutting elements, the cutting element comprising a cutting table and a substrate. The substrate preferably comprises a material that will support the cutting table during normal drilling operations and wear when exposed to the earth formation, thereby limiting the effects of wear flat areas on drilling efficiency. Alternatively, or additionally, the cutting elements may be placed, or spaced, so as to limit the effects of wear flat areas on drilling efficiency.
  • The present invention includes both a method for optimizing drill bit design and several embodiments of an optimized drill bit 10 for drilling a well in an earth formation. The bit 10 may be similar to those disclosed in U.S. Pat. No. 6,843,333, the disclosure of which is incorporated herein by specific reference in its entirety. Referring now to FIGS. 1 and 2, a first embodiment of the bit 10 of the present invention is depicted. In FIG. 1, the bit 10 is shown inverted from its normal face-down operating orientation for clarity. The bit 10 is, in one embodiment, 8½″ in diameter and includes a matrix-type bit body 12 having a shank 14 for connection to a drill string (not shown) extending therefrom opposite a bit face 16. A plurality of blades 18 extends generally radially outwardly in linear fashion to gage pads 20 defining junk slots 22 therebetween.
  • The bit 10 may include conventional impregnated bit cutting structures and/or discrete, impregnated cutting structures 24 comprising posts extending upwardly from the blades 18 on the bit face 16. The cutting structures 24 may be formed as an integral part of the matrix-type blades 18 projecting from the matrix-type bit body 12 by hand-packing diamond grit-impregnated matrix material in mold cavities on the interior of a bit mold defining locations of the cutting structures 24 and blades 18. Thus, each blade 18 and associated cutting structure 24 may define a unitary structure. It is noted that the cutting structures 24 may be placed directly on the bit face 16, dispensing with the blades. It is also noted that, while discussed in terms of being integrally formed with the bit 10, the cutting structures 24 may be formed as discrete individual segments, such as by hot isostatic pressing, and subsequently brazed or furnaced onto the bit 10.
  • The discrete cutting structures 24 may be mutually separate from each other to promote drilling fluid flow therearound for enhanced cooling and clearing of formation material removed by the diamond grit. The discrete cutting structures 24 may be generally of a round or circular transverse cross-section at their substantially flat, outermost ends, but become more oval with decreasing distance from the face of the blades 18 and thus provide wider or more elongated (in the direction of bit rotation) bases for greater strength and durability. As the discrete cutting structures 24 wear, the exposed cross-section of the posts increases, providing progressively increasing contact area for the diamond grit with the formation material. As the cutting structures wear down, the bit 10 takes on the configuration of a heavier-set bit more adept at penetrating harder, more abrasive formations. Even if discrete cutting structures 24 wear completely away, the diamond-impregnated blades 18 will provide some cutting action, reducing any possibility of ring-out and having to pull the bit 10.
  • While the cutting structures 24 are illustrated as exhibiting posts of circular outer ends and oval shaped bases, other geometries are also contemplated. For example, the outermost ends of the cutting structures may be configured as ovals having a major diameter and a minor diameter. The base portion adjacent the blade 18 might also be oval, having a major and a minor diameter, wherein the base has a larger minor diameter than the outermost end of the cutting structure 24. As the cutting structure 24 wears towards the blade 18, the minor diameter increases, resulting in a larger surface area. Furthermore, the ends of the cutting structures 24 need not be flat, but may employ sloped geometries. In other words, the cutting structures 24 may change cross-sections at multiple intervals, and tip geometry may be separate from the general cross-section of the cutting structure. Other shapes or geometries may be configured similarly. It is also noted that the spacing between individual cutting structures 24, as well as the magnitude of the taper from the outermost ends to the blades 18, may be varied to change the overall aggressiveness of the bit 10 or to change the rate at which the bit is transformed from a light-set bit to a heavy-set bit during operation. It is further contemplated that one or more of such cutting structures 24 may be formed to have substantially constant cross-sections if so desired depending on the anticipated application of the bit 10.
  • Discrete cutting structures 24 may comprise a synthetic diamond grit, such as, for example, DSN-47 Synthetic diamond grit, commercially available from DeBeers of Shannon, Ireland, which has demonstrated toughness superior to natural diamond grit. The tungsten carbide matrix material with which the diamond grit is mixed to form discrete cutting structures 24 and supporting blades 18 may desirably include a fine grain carbide, such as, for example, DM2001 powder commercially available from Kennametal Inc., of Latrobe, Pa. Such a carbide powder, when infiltrated, provides increased exposure of the diamond grit particles in comparison to conventional matrix materials due to its relatively soft, abradable nature. The base 30 of each blade 18 may desirably be formed of, for example, a more durable 121 matrix material, obtained from Firth MPD of Houston, Tex. Use of the more durable material in this region helps to prevent ring-out even if all of the discrete cutting structures 24 are abraded away and the majority of each blade 18 is worn.
  • It is noted, however, that alternative particulate abrasive materials may be suitably substituted for those discussed above. For example, the discrete cutting structures 24 may include natural diamond grit, or a combination of synthetic and natural diamond grit. Alternatively, the cutting structures may include synthetic diamond pins. Additionally, the particulate abrasive material may be coated with a single layer or multiple layers of a refractory material, as known in the art and disclosed in U.S. Pat. Nos. 4,943,488 and 5,049,164, the disclosures of each of which are hereby incorporated herein by reference in their entirety. Such refractory materials may include, for example, a refractory metal, a refractory metal carbide or a refractory metal oxide. In one embodiment, the coating may exhibit a thickness of approximately 1 to 10 microns. In another embodiment, the coating may exhibit a thickness of approximately 2 to 6 microns. In yet another embodiment, the coating may exhibit a thickness of less than 1 micron.
  • In one embodiment, one or more of the blades 18 carry cutting elements, shown as polycrystalline diamond compact (PDC) cutters 26, in conventional orientations, with cutting faces oriented generally facing the direction of bit rotation. In one embodiment, the PDC cutters 26 are located within the cone portion 34 of the bit face 16. The cone portion 34, best viewed with reference to FIG. 1, is the portion of the bit face 16 wherein the profile is defined as a generally cone-shaped section about the centerline of intended rotation of the drill bit 10. Alternatively, or additionally, the PDC cutters 26 may be located across the blades 18 and elsewhere on the bit 10.
  • The PDC cutters 26 may comprise cutters having a PDC jacket or sheath extending contiguously with, and to the rear of, the PDC cutting face and over a supporting substrate 32. For example, a cutter of this type is offered by Hughes Christensen Company, a wholly owned subsidiary of the assignee of the present invention, as NIAGARA™ cutters. Such cutters are further described in U.S. Pat. No. 6,401,844, the disclosure of which is incorporated herein by specific reference in its entirety. This cutter design provides enhanced abrasion resistance to the hard and/or abrasive formations typically drilled by impregnated bits, in combination with enhanced performance, or rate of penetration (ROP), in softer, nonabrasive formation layers interbedded with such hard formations. It is noted, however, that alternative PDC cutter designs may be implemented. For example, the PDC cutters 26 may be configured of various shapes, sizes, or materials as known by those of skill in the art. Also, other types of cutting elements may be formed within the cone portion 34 of, and elsewhere across, the bit 10 depending on the anticipated application of the bit 10. For example, the cutting elements 26 may include cutters formed of thermally stable diamond product (TSP), natural diamond material, or impregnated diamond.
  • An exemplary cutting element 26 of the present invention, as shown in FIG. 3, includes a super-abrasive cutting table 28 of circular, rectangular or other polygon, oval, truncated circular, triangular, or other suitable cross-section. The super-abrasive table 28, exhibiting a circular cross-section and an overall cylindrical configuration, or shape, is suitable for a wide variety of drill bits and drilling applications. The super-abrasive table 28 of the cutting element 26 is preferably formed with a conglomerated super-abrasive material, with an exposed cutting face 30. The cutting face 30 will typically have a top 30A and a side 30B with the peripheral junction thereof serving as the cutting region of the cutting face 30 and more precisely a cutting edge 30C of the cutting face 30, which is usually the first portion of the cutting face 30 to contact and thus initially “cut” the formation as the drill bit 10 retaining the cutting element 26 progressively drills a bore hole. The cutting edge 30C may be a relatively sharp approximately ninety-degree edge, or may be beveled or rounded. The super-abrasive table 28 will also typically have a primary underside, or attachment, interface joined during the sintering of the diamond, or super-abrasive, layer forming the super-abrasive table 28 to a supporting substrate 32 typically formed of a hard and relatively tough material such as a cemented tungsten carbide or other carbide. The substrate 32 may be preformed in a desired shape such that a volume of particulate diamond material may be formed into a polycrystalline cutting, or super-abrasive, table 28 thereon and simultaneously strongly bonded to the substrate 32 during high pressure high temperature (HPHT) sintering techniques practiced within the art. Alternatively, the substrate 32 may be formed of steel, or other strong material with an abrasion resistance less than that of tungsten carbide and/or the earth formation being drilled. In still other embodiments, the substrate 32 may comprise a relatively thin tungsten carbide layer backed by a steel body.
  • In any case, the substrate 32 may be cylindrical, conical, tapered, and/or rectangular in over-all shape, as well as, circular, rectangular or other polygon, oval, truncated circular, and/or triangular, in cross-section. A unitary cutting element 26 will thus be provided that may then be secured to the drill bit 10 by brazing or other techniques known within the art, such as gluing, press fitting, and/or using a stud mounting technique.
  • In accordance with the present invention, the super-abrasive table 28 preferably comprises a heterogeneous conglomerate type of PDC layer or diamond matrix in which at least two different nominal sizes and wear characteristics of super-abrasive particles, such as diamonds of differing grains, or sizes, are included to ultimately develop a rough, or rough cut, cutting face 30, particularly with respect to the cutting face side 30B and most particularly with respect to the cutting edge 30C. In one embodiment, larger diamonds may range upwards of approximately 600 μm, with a preferred range of approximately 100 μm to approximately 600 μm, and smaller diamonds, or super-abrasive particles, may preferably range from about 15 μm to about 100 μm. In another embodiment, larger diamonds may range upwards of approximately 500 μm, with a preferred range of approximately 100 μm to approximately 250 μm, and smaller diamonds, or super-abrasive particles, may preferably range from about 15 μm to about 40 μm.
  • The specific grit size of larger diamonds, the specific grit size of smaller diamonds, the thickness of the cutting face 30 of the super-abrasive table 28, the amount and type of sintering agent, as well as the respective large and small diamond volume fractions, may be adjusted to optimize the cutter 26 for cutting particular formations exhibiting particular hardness and particular abrasiveness characteristics. The relative, desirable particle size relationship of larger diamonds and smaller diamonds may be characterized as a tradeoff between strength and cutter aggressiveness. On the one hand, the desirability of the super-abrasive table 28 holding on to the larger particles during drilling would dictate a relatively smaller difference in average particle size between the smaller and larger diamonds. On the other hand, the desirability of providing a rough cutting surface would dictate a relatively larger difference in average particle size between the smaller and larger diamonds. Furthermore, the immediately preceding factors may be adjusted to optimize the cutter 26 for the average rotational speed at which the cutting element 26 will engage the formation as well as for the magnitude of normal force and torque to which each cutter 26 will be subjected while in service as a result of the rotational speeds and the amount of weight, or longitudinal force, likely to be placed on the drill bit 10 during drilling.
  • While PDC cutters, such as those discussed above, are used in a preferred embodiment, other cutters may be used alternatively and/or additionally. For example, cutters made of thermally stable polycrystalline (TSP) diamond, in triangular, pin, and/or circular configuration, cubic boron nitride (CBN), and/or other superabrasive materials may be used. In some embodiments, even simple carbide cutters may be used.
  • According to certain aspects of the present invention, rather than constructing every component of the drill bit 10 from the strongest, most durable and abrasion resistant materials available, it may beneficial to make portions of the drill bit 10 sacrificial. For example, with drilling rig day rates often significantly exceeding the cost of drill bits, designing a drill bit that minimizes the cost of drilling operations is paramount. Historically, drill bits have been designed to be as durable and wear resistant as possible. Unfortunately, due to the extreme environment in which they are expected to perform, all known drill bits experience wear. More specifically, as the drill bit 10 wears, wear flat areas develop on the bit body 12, blades 18, and the cutters 26 themselves. These wear flat areas abrade against the earth formation, such as rock, and cause unproductive heat, drag, as well as other harmful byproducts of the drilling operation. The heat and drag further degrade the drill bit 10 and increase the wear flat problem, requiring more and more energy as well as decreasing rate of penetration. More specifically, increased wear flat area increases the specific energy, or the energy required to remove a unit volume of rock. At some point, the wear flat area becomes so great that the specific energy required is too great, drilling efficiency is therefore lost, and the drill bit 10 must be replaced.
  • Clearly, the cutting tables 28 must be made from a material with an abrasion resistance greater than the abrasiveness of the earth formation, in order to cut therethrough. Because the substrate 32 is intended to provide support to the cutting table 28, rather than significantly contribute to the rate of penetration, the substrate 32 may be made of a material with an abrasion resistance less than the abrasiveness of the earth formation. Therefore, in some embodiments, the substrates 32 of the cutting elements 26 and/or other portions of the bit body 12 are preferably made of a material with less abrasion resistance than that of the cutting table 28 and/or the earth formation into which the drill bit 10 is drilling. In one embodiment, cutters 26 with sacrificial substrates 32 could be mounted on every blade 18, spaced SO as to minimize the wear flat area's influence on the required specific energy. The wear flat area's influence may also be minimized by mounting cutters 26 with sacrificial substrates 32 on every other blade 18.
  • The above differences in abrasiveness can be accomplished in terms of independently specified material properties. For example, the optimized drill bit 10 according to the present invention may be designed such that the cutting table 28 is made of a cutting material with a minimum abrasion resistance, significantly higher than the abrasiveness of the earth formation. The optimized drill bit 10 according to the present invention may be designed such that the substrate 32 is made of a substrate material with a minimum and/or maximum abrasion resistance, which is preferably lower than the abrasiveness of the earth formation.
  • Alternatively, the above differences in abrasiveness can be accomplished in terms of specified ratios. For example, an optimized drill bit 10 according to the present invention may be designed to maintain a minimum ratio of abrasion resistance between: the cutting table 28 and the earth formation; the cutting table 28 and the substrate 32; and/or earth formation and the substrate 32. In any case, as discussed above, the abrasiveness of the earth formation is preferably such that at least the substrate material erodes rather quickly when and where it comes into frictional contact with the earth formation.
  • It can be appreciated that a pre-designed and pre-manufactured drill bit may be selected based on the earth formation predicted and/or encountered. Alternatively, a drill bit may be specifically designed for the earth formation predicted and/or encountered.
  • It has been discovered that the blades 18 rarely wear evenly. Therefore, it may be desirable to optimize the design of the blades 18 and the distribution and/or spacing of cutting material along the blades 18, to increase drill bit useful life and minimize the required specific energy while maintaining an acceptable rate of penetration and drilling efficiency. The blades 18 of modern drill bits often have three or more sections that serve related and overlapping functions. Specifically, each blade 18 preferably has a cone section, a nose section, a shoulder section, and a gage section.
  • As discussed above, the cone section of each blade is preferably a substantially linear section extending from near a center-line of the drill bit 10 outward. Because the cone section is nearest the center-line of the drill bit 10, the cone section does not experience as much, or as fast, movement relative to the earth formation. Therefore, it has been discovered that the cone section commonly experiences less wear than the other sections. Thus, the cone section can maintain effective and efficient rate of penetration with less cutting material. This can be accomplished in a number of ways. For example, the cone section may have fewer cutting structures 24 and/or PDC cutters 26, smaller cutting structures 24 and/or PDC cutters 26, and/or more spacing between cutting structures 24 and/or PDC cutters 26. The cone angle for a PDC bit is typically 15-25°, although, in some embodiments, the cone section is essentially flat, with a substantially 0° cone angle.
  • The nose represents the lowest point on a drill bit. Therefore, the nose cutter is typically the leading most cutter. The nose section is roughly defined by a nose radius. A larger nose radius provides more area to place cutters in the nose section. The nose section begins where the cone section ends, where the curvature of the blade begins, and extends to the shoulder section. More specifically, the nose section extends where the blade profile substantially matches a circle formed by the nose radius. The nose section experiences much more, and more rapid, relative movement than does the cone section. Additionally, the nose section typically takes more weight than the other sections. As such, the nose section commonly experiences much more wear than does the cone section. Therefore, the nose section preferably has a higher distribution, concentration, or density of cutting structures 24 and/or PDC cutters 26.
  • The shoulder section begins where the blade profile departs from the nose radius and continues outwardly on each blade 18 to a point where a slope of the blade is essentially completely vertical, at the gage section. The shoulder section experiences much more, and more rapid, relative movement than does the cone section. Additionally, the shoulder section typically takes the brunt of abuse from dynamic dysfunction, such as bit whirl. As such, the shoulder section experiences much more wear than does the cone section. The shoulder section is also a more significant contributor to rate of penetration and drilling efficiency than the cone section. Therefore, the shoulder section preferably has a higher distribution, concentration, or density of cutting structures 24 and/or PDC cutters 26. Depending on application, the nose section or the shoulder section may experience the most wear, and therefore either the nose section or the shoulder section may have the highest distribution, concentration, or density of cutting structures 24 and/or PDC cutters 26.
  • The gage section begins where the shoulder section ends. More specifically, the gage section begins where the slope of the blade is predominantly vertical. The gage section continues outwardly to an outer perimeter or gauge of the drill bit 10. The gage section experiences the most, and most rapid, relative movement with respect to the earth formation. However, at least partially because of the high, substantially vertical, slope of the blade 18 in the gage section, the gage section does not typically experience as much wear as does the shoulder section and/or the nose section. The gage section does, however, typically experience more wear than the cone section. Therefore, the gage section preferably has a higher distribution of cutting structures 24 and/or PDC cutters 26 than the cone section, but may have a lower distribution of cutting structures 24 and/or PDC cutters 26 than the shoulder section and/or nose section.
  • In one embodiment, a highest concentration of the cutting structures 24 and/or PDC cutters 26 occurs near the border between the shoulder section and the gage section. Alternative embodiments may include a highest concentration of the cutting structures 24 and/or PDC cutters 26, in the shoulder section and/or the gage section.
  • Upon reading this disclosure, it can be appreciated that the design of a drill bit includes consideration of many factors, such as the size, shape, spacing, orientation, and number of blades; the size, shape, spacing, orientation, and number of cutters, or cutting elements; as well as the materials of the bit body, blades, cutting tables, and substrates. All of these factors may be considered in light of the materials of the earth formation(s) for which the drill bit is designed and/or matched.
  • The bit 10 may employ a plurality of ports 36 over the bit face 16 to enhance fluid velocity of drilling fluid flow and better apportion the flow over the bit face 16 and among fluid passages 38 between blades 18 and extending to junk slots 22. This enhanced fluid velocity and apportionment helps prevent bit balling in shale formations, for example, which phenomenon is known to significantly retard rate of penetration (ROP). Further, in combination with the enhanced diamond exposure of bit 10, the improved hydraulics substantially enhances drilling through permeable sandstones.
  • Other and further embodiments utilizing one or more aspects of the inventions described above can be devised without departing from the spirit of Applicant's invention. For example, the various methods and embodiments of the drill bit 10 can be included in combination with each other to produce variations of the disclosed methods and embodiments. Reading this disclosure, it can be appreciated that there are a number of ways to impact concentrations or distributions of cutter volume, such as by using differently sized, shaped, and/or spaced cutters. Discussion of singular elements can include plural elements and vice-versa.
  • The order of steps can occur in a variety of sequences unless otherwise specifically limited. The various steps described herein can be combined with other steps, interlineated with the stated steps, and/or split into multiple steps. Similarly, elements have been described functionally and can be embodied as separate components or can be combined into components having multiple functions.
  • The inventions have been described in the context of preferred and other embodiments and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicants, but rather, in conformity with the patent laws, Applicants intend to fully protect all such modifications and improvements that come within the scope or range of equivalent of the following claims.

Claims (20)

  1. 1. A method of designing a drill bit, such as for drilling into an earth formation, the method comprising the steps of:
    configuring the drill bit with a diamond impregnated bit body and at least one cutting element, the cutting element comprising a cutting table and a substrate; and
    selecting a material for the substrate so that the substrate will support the cutting table during normal drilling operations and wear when exposed to the earth formation, thereby limiting the effects of wear flat areas on drilling efficiency.
  2. 2. The method as set forth in claim 1, wherein the cutting table is operable to cut the earth formation.
  3. 3. The method as set forth in claim 1, wherein the bit body is operable to cut the earth formation.
  4. 4. The method as set forth in claim 1, wherein the cutting table has an abrasion resistance greater than the earth formation.
  5. 5. The method as set forth in claim 1, wherein the bit body has an abrasion resistance greater than the earth formation.
  6. 6. The method as set forth in claim 1, wherein the substrate has an abrasion resistance less than the earth formation.
  7. 7. The method as set forth in claim 1, wherein the substrate has an abrasion resistance less than the cutting table.
  8. 8. The method as set forth in claim 1, wherein the substrate has an abrasion resistance less than the bit body.
  9. 9. The method as set forth in claim 1, further including the step of arranging a plurality of diamond impregnated cutting structures on the bit body.
  10. 10. The method as set forth in claim 1, further including the step of arranging a plurality of diamond impregnated cutting structures among the cutting elements.
  11. 11. A method of designing a drill bit, such as for drilling into an earth formation, the method comprising the steps of:
    configuring the drill bit with a diamond impregnated bit body and a plurality of cutting elements, the cutting element comprising a cutting table and a substrate; and
    placing the cutting elements on the bit body to limit the effects of wear flat areas on drilling efficiency.
  12. 12. The method as set forth in claim 11, wherein the cutting elements are spaced tighter in a shoulder section of the bit body.
  13. 13. The method as set forth in claim 11, wherein the cutting elements are spaced tighter in a nose section of the bit body.
  14. 14. The method as set forth in claim 11, wherein the cutting elements have greater spacing in a cone section of the bit body.
  15. 15. The method as set forth in claim 11, wherein the cutting elements have greater spacing in a gage section of the bit body.
  16. 16. The method as set forth in claim 11, further including the step of arranging a plurality of diamond impregnated cutting structures on the bit body.
  17. 17. The method as set forth in claim 11, further including the step of arranging a plurality of diamond impregnated cutting structures among the cutting elements.
  18. 18. A method of designing a drill bit, such as for drilling into an earth formation, the method comprising the steps of:
    configuring the drill bit with a diamond impregnated bit body a plurality of diamond impregnated cutting structures and a plurality of cutting elements, each cutting elements comprising a cutting table and a substrate;
    selecting a material for the substrate so that the substrate will support the cutting table during normal drilling operations and wear when exposed to the earth formation, thereby limiting the effects of wear flat areas on drilling efficiency; and
    placing the cutting elements on the bit body to limit the effects of wear flat areas on drilling efficiency.
  19. 19. The method as set forth in claim 18, wherein both the cutting table and the bit body are operable to cut the earth formation, while the substrate has an abrasion resistance less than the cutting table, the bit body and the earth formation.
  20. 20. The method as set forth in claim 18, wherein the cutting elements are spaced tighter in a shoulder section and a nose section than in a cone section or a gage section of the bit body.
US12274709 2008-11-20 2008-11-20 Hybrid drill bit Abandoned US20100122848A1 (en)

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8191654B2 (en) 2004-02-19 2012-06-05 Baker Hughes Incorporated Methods of drilling using differing types of cutting elements
US8225888B2 (en) * 2004-02-19 2012-07-24 Baker Hughes Incorporated Casing shoes having drillable and non-drillable cutting elements in different regions and related methods
US8899350B2 (en) 2010-12-16 2014-12-02 Caterpillar Inc. Method and apparatus for detection of drill bit wear
US20150300095A1 (en) * 2013-08-30 2015-10-22 Halliburton Energy Services, Inc. Improved cutters for drill bits
US9243458B2 (en) 2013-02-27 2016-01-26 Baker Hughes Incorporated Methods for pre-sharpening impregnated cutting structures for bits, resulting cutting structures and drill bits so equipped

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US20090159338A1 (en) * 2007-12-21 2009-06-25 Baker Hughes Incorporated Reamer With Improved Hydraulics For Use In A Wellbore
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US20090126998A1 (en) * 2007-11-16 2009-05-21 Zahradnik Anton F Hybrid drill bit and design method
US20090166093A1 (en) * 2007-12-21 2009-07-02 Baker Hughes Incorporated Reamer With Stabilizers For Use In A Wellbore
US20090159341A1 (en) * 2007-12-21 2009-06-25 Baker Hughes Incorporated Reamer with balanced cutting structures for use in a wellbore
US20090159338A1 (en) * 2007-12-21 2009-06-25 Baker Hughes Incorporated Reamer With Improved Hydraulics For Use In A Wellbore

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8191654B2 (en) 2004-02-19 2012-06-05 Baker Hughes Incorporated Methods of drilling using differing types of cutting elements
US8225888B2 (en) * 2004-02-19 2012-07-24 Baker Hughes Incorporated Casing shoes having drillable and non-drillable cutting elements in different regions and related methods
US8297380B2 (en) 2004-02-19 2012-10-30 Baker Hughes Incorporated Casing and liner drilling shoes having integrated operational components, and related methods
US8899350B2 (en) 2010-12-16 2014-12-02 Caterpillar Inc. Method and apparatus for detection of drill bit wear
US9243458B2 (en) 2013-02-27 2016-01-26 Baker Hughes Incorporated Methods for pre-sharpening impregnated cutting structures for bits, resulting cutting structures and drill bits so equipped
US20150300095A1 (en) * 2013-08-30 2015-10-22 Halliburton Energy Services, Inc. Improved cutters for drill bits
US9725960B2 (en) * 2013-08-30 2017-08-08 Halliburton Energy Services, Inc. Cutters for drill bits

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Effective date: 20081118