US20100175929A1 - Cutter profile helping in stability and steerability - Google Patents

Cutter profile helping in stability and steerability Download PDF

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Publication number
US20100175929A1
US20100175929A1 US12351518 US35151809A US2010175929A1 US 20100175929 A1 US20100175929 A1 US 20100175929A1 US 12351518 US12351518 US 12351518 US 35151809 A US35151809 A US 35151809A US 2010175929 A1 US2010175929 A1 US 2010175929A1
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plurality
cutter profile
cutting elements
drill bit
cutter
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Abandoned
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US12351518
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Thorsten Schwefe
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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
    • E21B10/46Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/56Button type inserts
    • E21B10/567Button type inserts with preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts
    • 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
    • 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
    • E21B10/46Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/54Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
    • E21B10/55Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits with preformed cutting elements with blades having preformed cutting elements mounted on a distinct support, e.g. polycrystalline inserts

Abstract

An improved drill bit comprises a bit body, a plurality of blades disposed on the bit body, a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile, and a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile. The first plurality of cutting elements may, or may not, be greater in number than the second plurality of cutting elements. The cutting elements of the first plurality may, or may not, be greater in size than the cutting elements of the second plurality. The second cutter profile may be offset inwardly or outwardly from the first cutter profile. The second cutter profile may run along a cone section, a nose section, and/or a shoulder section of the bit.

Description

    CROSS REFERENCE TO RELATED APPLICATIONS
  • Not applicable.
  • 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, such as for drilling into earth formations; and more specifically relate to cutter profiles for such drill bits that improve performance especially in the areas of stability and steerability.
  • 2. Description of the Related Art
  • U.S. Pat. No. 4,440,247 teaches a “blade-type rotary drill bit having radially divergent cutting blades arranged in two arrays and equipped with cutting blanks having upset cutting surfaces formed of an abrasive material such as diamond or the like. The blades in one array cut to the center of the bit to provide a conically shaped core volume and the blades of the second array terminate short of the axis of the bit to define a somewhat larger core volume. The bit is equipped with discharge ports and baffles whereby drilling fluid issuing from the discharge ports moves downwardly and then inwardly to the center of the bit. The cutting blanks located on the second array of blades cut in a common set of tracks which are at least partially different from and compliment the tracks cut by the cutting blanks on the blade of the first array.”
  • U.S. Pat. No. 4,593,777 teaches a “drill bit comprises a bit body having an operating end face. A plurality of self-sharpening cutters are mounted in the bit body and extend through the operating end face. The cutters have cutting faces adapted to engage an earth formation and cut the earth formation to a desired three-dimensional profile. The cutting faces define surfaces have back rake angles which decrease with distance from the profile. The individual cutting faces may be inwardly concave in a plane parallel to the intended direction of motion of the cutter in use. Each of the cutting members has a stud portion disposed in a respective recess in the bit body and defining the inner end of the cutting member, the cutting face being generally adjacent the outer end and having an outer cutting edge. The centerline of the stud portion is rearwardly inclined, from the outer end to the inner end, with respect to the direction of movement in use, taken at the midpoint of the cutting edge, at a first angle from 80.degree. to 30.degree. inclusive. The cutting face is oriented such that the tangent to the cutting face at the midpoint of the cutting edge and in the center plane of the cutting member is disposed at a second angle, for 18.degree. to 75.degree. inclusive, with respect to the centerline of the stud portion.”
  • U.S. Pat. No. 4,932,484 teaches a “whirl resistant drill bit is disclosed for use in rotary drilling. The drill bit includes a generally cylindrical bit body with a plurality of cutting elements extending out from a lower end surface. The cutter elements are grouped in sets such that a first set of cutters are disposed at substantially an equal radius from a center of the bit body to create a groove in the material being drilled. A second set of cutters is connected to the lower end surface with each cutter therein in overlapping radial relationship with each other and extending a maximum distance from the lower end surface less than that of the first set of cutters. At least one cutter of the second set is in overlapping radial relationship with at least one of the cutters within the first set of cutters. This cutter arrangement causes the drill bit to cut grooves within the formation material that tends to prevent destructive bit whirl. Further, adjustments can be made to vary the back rake angle and side rake angle to prevent bit whirl.”
  • U.S. Pat. No. 5,033,560 teaches an “earth boring bit having a body provided with a shank having a tubular bore and a head along the opposite end of said body having flow passages communicating with the bore, the head having face portions including a center end face portion, a nose portion, a shoulder portion, and a gage portion along the maximum diameter of the bit, and cutting elements mounted over said face portions having cutting faces oriented in the direction of rotation of the drill bit, the areas of the cutting faces of the cutting elements ranging from a maximum at the center face portion to a minimum at the gage portion of the bit. The cutters may be individually mounted, mounted in groups, arranged in random patterns, and arranged in a variety of other patterns, including radial longitudinal rows circumferentially spaced around the bit face.”
  • U.S. Pat. No. 5,238,075 teaches a “fixed cutter drill bit includes a plurality of angularly spaced radial wings each with a row of cutting elements mounted thereon and protruding from the bit for drilling through formation material. On a first of the wings, a first row of the cutting elements has alternately larger and smaller area cutting faces at spaced selected radial positions relative to the center of the bit. Similarly, a second row of cutting elements is mounted on a second of the wings at substantially the same radial positions but with the radial positions of the larger and smaller cutting faces reversed over those on the first wing. A third wing includes a third row of cutting elements with cutting faces of intermediate area located at each of the selected radial positions. The combination of different sizes of cutting elements at each radial position defines a set having a profile with the intermediate and smaller cutting elements located entirely within the larger cutting element. The profiles of the larger cutting elements of adjacent sets overlap each other without substantial overlapping of the profiles of any of the other cutting elements.”
  • U.S. Pat. No. 5,549,171 teaches a “fixed cutter drill bit includes sets of cutter elements mounted on the bit face. Each set includes at least two cutters mounted on different blades at generally the same radial position with reset to the bit axis but having differing degrees of backrake. The cutter elements of a set may be mounted having their cutting faces out-of-profile, such that certain elements in the set are exposed to the formation material to a greater extent than other cutter elements in the same set. The cutter elements in a set may have cutting faces and profiles that are identical, or they may vary in size or shape or both. The bit exhibits increased stability and provides substantial improvement in ROP without requiting excessive WOB.”
  • U.S. Pat. No. 5,551,522 teaches a “fixed cutter drill bit includes a cutting structure having radially-spaced sets of cutter elements. The cutter element sets preferably overlap in rotated profile and include at least one low profile cutter element and at least two high profile elements. The low profile element is mounted so as to have a relatively low exposure height. The high profile elements are mounted at exposure heights that are greater than the exposure height of the low profile element, and are radially spaced from the low profile element on the bit face. The high profile elements may be mounted at the same radial position but at differing exposure heights, or may be mounted at the same exposure heights but at different radial positions relative to the bit axis. Providing this arrangement of low and high profile cutter elements tends to increase the bit's ability to resist vibration and provides an aggressive cutting structure, even after significant wear has occurred.”
  • U.S. Pat. No. 5,607,025 teaches a “fixed cutter drill bit includes cutter elements mounted in sets on the bit face. A cutter element set includes at least three cutters with cutting faces having at least two different curvatures. The cutter elements of the set are mounted on various blades of the bit such that, in rotated profile, the cutting profile of a larger and a smaller cutter element overlap, and such that the smaller cutter element is flanked by larger sized cutters. The bit exhibits increased stability, before and after wear has occurred. The large cutters provide for efficient shearing while the smaller cutters may provide prefracturing in certain formations.”
  • U.S. Pat. No. 5,582,261 teaches a “fixed cutter drill bit includes sets of cutter elements mounted on the bit face, each set including at least two cutters that are mounted at generally the same radial position with respect to the bit axis. The cutter elements of a set are positioned on different blades of the bit and are mounted having their cutting faces are out-of-profile, such that certain elements in the set are exposed to the formation material to a greater extent than other cutter elements in the same set. The cutter elements in a set may have equal diameters or may vary in size. The bit exhibits increased stability or vibration resistance, and drills initially as a ‘light-set’ bit and later as a ‘heavy-set’ bit.”
  • U.S. Pat. No. 7,000,715 teaches a “superabrasive cutter-equipped rotary drag bit especially suitable for directional drilling in subterranean formations is provided. The bit may employ PDC cutters in an engineered cutter placement profile exhibiting optimal aggressiveness in relation to where the cutters are positioned along the profile of the bit extending from a cone region laterally, or radially, outward toward a gage region therefore. The engineered cutter placement profile may include cutters exhibiting differing degrees of aggressiveness positioned in order to maximize rate-of-penetration and minimize torque-on-bit while maintaining side cutting capability and steerability.”
  • The inventions disclosed and taught herein are directed to drill bits with improved cutter profiles for enhancing performance and specifically stability and steerability.
  • BRIEF SUMMARY OF THE INVENTION
  • Applicants have created an improved drill bit, such as for drilling into an earth formation. The drill bit preferably comprises a bit body, a plurality of blades disposed on the bit body, a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile, and a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile. The first plurality of cutting elements may, or may not, be greater in number than the second plurality of cutting elements. The cutting elements of the first plurality may, or may not, be greater in size than the cutting elements of the second plurality. The second cutter profile may be offset inwardly or outwardly from the first cutter profile. The second cutter profile may run along a cone section, a nose section, and/or a shoulder section of the drill bit.
  • BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
  • FIG. 1 illustrates a perspective view of an exemplary drill bit incorporating cutting elements and embodying certain aspects of the present inventions;
  • FIG. 2 is an enlarged perspective view of an exemplary cutting element embodying certain aspects of the present inventions;
  • FIG. 3 is a partial elevation view of a blade of a drill bit according to certain aspects of the present inventions;
  • FIG. 4 is an elevation view of a cutter profile of a drill bit according to certain aspects of the present inventions;
  • FIG. 5 is a elevation view of multiple cutter profiles of a drill bit according to certain aspects of the present inventions;
  • FIG. 6 is another elevation view of multiple cutter profiles of a drill bit according to certain aspects of the present inventions; and
  • FIG. 7 is another elevation view of multiple cutter profiles of a drill bit according to 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 in 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.
  • Applicants have created an improved drill bit, such as for drilling into an earth formation. The drill bit preferably comprises a bit body, a plurality of blades disposed on the bit body, a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile, and a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile. The first plurality of cutting elements may, or may not, be greater in number than the second plurality of cutting elements. The cutting elements of the first plurality may, or may not, be greater in size than the cutting elements of the second plurality. The second cutter profile may be offset inwardly or outwardly from the first cutter profile. The second cutter profile may run along a cone section, a nose section, and/or a shoulder section of the drill bit.
  • FIG. 1 is an illustration of a drill bit 10 that includes a bit body 12 having a conventional pin end 14 to provide a threaded connection to a conventional jointed tubular drill string rotationally and longitudinally driven by a drilling rig. Alternatively, the drill bit 10 may be connected in a manner known within the art to a bottomhole assembly which, in turn, is connected to a tubular drill string or to an essentially continuous coil of tubing. Such bottomhole assemblies may include a downhole motor to rotate the drill bit 10 in addition to, or in lieu of, being rotated by a rotary table or top drive located at the surface or on an offshore platform (not shown within the drawings). Furthermore, the conventional pin end 14 may optionally be replaced with various alternative connection structures known within the art. Thus, the drill bit 10 may readily be adapted to a wide variety of mechanisms and structures used for drilling subterranean formations.
  • The drill bit 10, and select components thereof, are preferably similar to those disclosed in U.S. Pat. No. 7,048,081, which is incorporated herein by specific reference. In any case, the drill bit 10 preferably includes a plurality of blades 16 each having a forward facing surface, or face 18. The drill bit 10 may have anywhere from two to sixteen blades 16. While in one preferred embodiment, the face 18 is substantially flat, it may be concave and/or convex.
  • The drill bit 10 also preferably includes a row of cutters, or cutting elements, 20 secured to the blades 16. The drill bit 10 also preferably includes a plurality of nozzles 22 to distribute drilling fluid to cool and lubricate the drill bit 10 and remove cuttings. As customary in the art, gage 24 is the maximum diameter which the drill bit 10 is to have about its periphery. The gage 24 will thus determine the minimum diameter of the resulting bore hole that the drill bit 10 will produce when placed into service. The gage of a small drill bit may be as small as a few centimeters and the gage of an extremely large drill bit may approach a meter, or more. Between each blade 16, the drill bit 10 preferably has fluid slots, or passages, 26 into with the drilling fluid is fed by the nozzles 22.
  • An exemplary cutting element 20 of the present invention, as shown in FIG. 2, 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 20 is preferably formed with a conglomerated super-abrasive material, such as a polycrystalline diamond compact (PDC), 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 20 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 20 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 20 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 20 for the average rotational speed at which the cutting element 20 will engage the formation as well as for the magnitude of normal force and torque to which each cutter 20 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.
  • The blades 16 of modern drill bits often have three or more sections that serve related and overlapping functions. Specifically, referring to FIG. 3, each blade 16 preferably has a cone section, nose section, a shoulder section, and a gage section. 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. The slope and length of the cone section commonly influences stability of the bit 10.
  • 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 16 begins, and extends to the shoulder section. More specifically, the nose section extends where the blade profile tangentially 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 experiences much more wear than does the cone section. The nose section is also a more significant contributor to rate of penetration and drilling efficiency than the cone section.
  • The shoulder section begins where the blade profile departs from the nose radius and continues outwardly on each blade 16 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.
  • 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 the gage 24 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 16 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.
  • Referring also to FIG. 4, the row of cutters 20 are preferably spaced along a curved outer edge of the face 18 of each blade 16, forming a first, or primary, curved cutter, or cutting, profile, or layout, 34. The cutter profile 34, as shown, is a composite of the cutting elements 20 on each blade 16, as the bit 10 rotates through the earth formation. In other words, the cutter profile 34 comprises each of the cutting elements 20 super-imposed as if each cutting elements 20 were rotated into a single plane of a blade 16 extending from bit body 12. In many cases, the profile 34 generally follows the shape of the blades 16.
  • According to certain aspects of the present invention, however, there may be more than one cutter profile 34. For example, referring also to FIG. 5, the bit 10 may have a first, or primary, cutter profile 34, and a second, or secondary, cutter profile 36 offset from the first cutter profile 34. As shown in FIG. 5, FIG. 6, and FIG. 7, the second cutter profile 36 may be offset inwardly or outwardly from the first cutter profile 34. The second cutter profile 36 may be offset from the first cutter profile 34 between 0.020 inches and 0.2 inches, or more. In one preferred embodiment, the second cutter profile 36 is offset from the first cutter profile 34 approximately 0.15 inches. The second cutter profile 36 may be offset from the first cutter profile 34 by some percentage of the cutter diameter. For example, the second cutter profile 36 may be offset from the first cutter profile 34 by between twenty-five and seventy-five percent of the diameter of the cutting elements 20, of the first profile 34, the second profile 36, or an average thereof. In one embodiment, the second cutter profile 36 is offset from the first cutter profile 34 by approximately 50% of the diameter of the cutting elements 20, of the first profile 34.
  • The second cutter profile 36 may be located along the cone, nose, and/or shoulder sections. More specifically, the secondary cutter profile 36 may span more than one adjacent section, such as the cone and nose sections, and/or may span two or more non-adjacent sections, such as the cone and shoulder sections, with the first cutter profile 34 being located along the remaining sections.
  • The second cutter profile 36 preferably comprises a plurality of the cutting elements 20. The second cutter profile 36 may, or may not, comprise all of the cutting elements 20 in the affected section, or sections. For example, the second cutter profile 36 may comprise between five and one hundred percent of the cutting elements 20 in the affected section or sections. In one embodiment, the second cutter profile 36 comprises approximately all of the cutters 20 in the cone section. In another embodiment, the second cutter profile 36 comprises approximately 75% of the cutters 20 in the nose section. In another embodiment, the second cutter profile 36 comprises approximately 50% of the cutters 20 in the shoulder section.
  • In any case, as also shown in FIG. 5, FIG. 6, and FIG. 7, the second cutter profile 36 may comprise fewer cutting elements 20 than the first cutter profile 34. Alternatively, the second cutter profile 36 may comprise roughly the same number, or more, cutting elements 20 than the first cutter profile 34. In one embodiment, the first cutter profile 34 comprises approximately forty cutting elements, while the second cutter profile comprises approximately ten cutting elements. The second cutter profile 36 may comprise a percentage of the cutting elements 20, such as ten, fifteen, or twenty percent. Alternatively, the second cutter profile 36 may comprise a fraction of the cutting elements 20, such as one-quarter, one-third, or one-half.
  • In one embodiment, the cutting elements 20 in each profile 34, 36 are oriented similarly, other than the offset. In other embodiments, the cutting elements 20 in the second profile 36 utilize a different back rake and/or side rake. For example, in one embodiment, the cutting elements 20 in the second profile 36 utilize more back rake than the cutting elements 20 in the first profile 34.
  • 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 cutting elements 20 in each profile may be the identical. Alternatively, the cutting elements 20 may be differently sized, shaped, and/or constructed. Additionally, or alternatively, the drill bit 10 may include three or more cutter profiles, with each being inwardly or outwardly and located in any of the blade sections. Further, the various methods and embodiments of the present invention can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa.
  • 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 (24)

  1. 1. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile,
    wherein each profile is exclusive for at least a portion of each blade.
  2. 2. The drill bit as set forth in claim 1, wherein the first plurality of cutting elements are greater in number than the second plurality of cutting elements.
  3. 3. The drill bit as set forth in claim 1, wherein the cutting elements of the first plurality are greater in size than the cutting elements of the second plurality.
  4. 4. The drill bit as set forth in claim 1, wherein the second cutter profile is offset inwardly from the first cutter profile.
  5. 5. The drill bit as set forth in claim 1, wherein the second cutter profile is offset outwardly from the first cutter profile.
  6. 6. The drill bit as set forth in claim 1, wherein the second cutter profile runs along a cone section.
  7. 7. The drill bit as set forth in claim 6, wherein the first cutter profile runs along a gage section, a shoulder section, and a nose section, but not the cone section.
  8. 8. The drill bit as set forth in claim 1, wherein the second cutter profile runs along a nose section.
  9. 9. The drill bit as set forth in claim 8, wherein the first cutter profile runs along a gage section, a shoulder section, and a cone section, but not the nose section.
  10. 10. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements are fewer in number than the first plurality of cutting elements and define a second cutter profile offset from the first cutter profile,
    wherein the first cutter profile runs along a gage section and a shoulder section, and wherein the second cutter profile exclusively runs along at least a portion of at least one of a nose section and a cone section.
  11. 11. The drill bit as set forth in claim 10, wherein the second cutter profile is offset inwardly from the first cutter profile.
  12. 12. The drill bit as set forth in claim 10, wherein the second cutter profile is offset outwardly from the first cutter profile.
  13. 13. The drill bit as set forth in claim 1, wherein the second cutter profile is offset from the first cutter profile by at least 0.15 inches.
  14. 14. The drill bit as set forth in claim 1, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the first plurality of cutting elements.
  15. 15. The drill bit as set forth in claim 1, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the second plurality of cutting elements.
  16. 16. The drill bit as set forth in claim 1, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the cutting elements.
  17. 17. The drill bit as set forth in claim 10, wherein the second cutter profile is offset from the first cutter profile by at least 0.15 inches.
  18. 18. The drill bit as set forth in claim 10, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the first plurality of cutting elements.
  19. 19. The drill bit as set forth in claim 10, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the second plurality of cutting elements.
  20. 20. The drill bit as set forth in claim 10, wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the cutting elements.
  21. 21. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile,
    wherein the second cutter profile is offset from the first cutter profile by at least 0.15 inches.
  22. 22. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile,
    wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the first plurality of cutting elements.
  23. 23. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile,
    wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the second plurality of cutting elements.
  24. 24. A drill bit, such as for drilling into an earth formation, the drill bit comprising:
    a bit body;
    a plurality of blades disposed on the bit body;
    a first plurality of cutting elements disposed on the blades, such that the first plurality of cutting elements define a first cutter profile; and
    a second plurality of cutting elements disposed on the blades, such that the second plurality of cutting elements define a second cutter profile offset from the first cutter profile,
    wherein the second cutter profile is offset from the first cutter profile between twenty-five and seventy-five percent of an average diameter of the cutting elements.
US12351518 2009-01-09 2009-01-09 Cutter profile helping in stability and steerability Abandoned US20100175929A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
US12351518 US20100175929A1 (en) 2009-01-09 2009-01-09 Cutter profile helping in stability and steerability

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US12351518 US20100175929A1 (en) 2009-01-09 2009-01-09 Cutter profile helping in stability and steerability
US12422418 US9644428B2 (en) 2009-01-09 2009-04-13 Drill bit with a hybrid cutter profile
PCT/US2010/020310 WO2010080868A3 (en) 2009-01-09 2010-01-07 Cutter profile helping in stability and steerability

Related Child Applications (1)

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US12422418 Continuation-In-Part US9644428B2 (en) 2009-01-09 2009-04-13 Drill bit with a hybrid cutter profile

Publications (1)

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US20100175929A1 true true US20100175929A1 (en) 2010-07-15

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US12351518 Abandoned US20100175929A1 (en) 2009-01-09 2009-01-09 Cutter profile helping in stability and steerability

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US (1) US20100175929A1 (en)
WO (1) WO2010080868A3 (en)

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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
WO2013116679A1 (en) * 2012-02-03 2013-08-08 Baker Hughes Incorporated Cutting element retention for high exposure cutting elements on earth-boring tools

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* Cited by examiner, † Cited by third party
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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
WO2013116679A1 (en) * 2012-02-03 2013-08-08 Baker Hughes Incorporated Cutting element retention for high exposure cutting elements on earth-boring tools
US9303460B2 (en) 2012-02-03 2016-04-05 Baker Hughes Incorporated Cutting element retention for high exposure cutting elements on earth-boring tools
US10047565B2 (en) 2012-02-03 2018-08-14 Baker Hughes Incorporated Cutting element retention for high exposure cutting elements on earth-boring tools

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WO2010080868A3 (en) 2010-10-14 application
WO2010080868A2 (en) 2010-07-15 application

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Effective date: 20090107