US20070261890A1 - Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements - Google Patents

Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements Download PDF

Info

Publication number
US20070261890A1
US20070261890A1 US11382510 US38251006A US2007261890A1 US 20070261890 A1 US20070261890 A1 US 20070261890A1 US 11382510 US11382510 US 11382510 US 38251006 A US38251006 A US 38251006A US 2007261890 A1 US2007261890 A1 US 2007261890A1
Authority
US
Grant status
Application
Patent type
Prior art keywords
primary
backup
bit
blade
cutter
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US11382510
Inventor
Dennis Cisneros
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Smith International Inc
Original Assignee
Smith International Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date

Links

Images

Classifications

    • 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 drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density, and wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.

Description

    CROSS-REFERENCE TO RELATED APPLICATIONS
  • Not Applicable.
  • STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
  • Not Applicable.
  • BACKGROUND
  • 1. Field of the Invention
  • The invention relates generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to drag bits and to an improved cutting structure for such bits. Still more particularly, the present invention relates to drag bits with backup cutters on primary blades,
  • 2. Background of the Invention
  • An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
  • Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Two predominate types of rock bits are roller cone bits and fixed cutter (or rotary drag) bits. Some fixed cutter bit designs include primary blades, secondary blades, and sometimes even tertiary blades, spaced about the bit face, where the primary blades are generally longer and start at locations closer to the bit's rotating axis. The blades project radially outward from the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter layouts cut the various strata with differing results and effectiveness.
  • The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PDC”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. A cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PDC bit” or “PDC cutting element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
  • While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may reduce or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to re-cut the same materials, thus reducing cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the hole are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall. Further, the fluid removes heat, caused by contact with the formation, from the cutting elements in order to prolong cutting element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may significantly impact the performance of the drill bit.
  • Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
  • The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP.
  • Some conventional fixed cutter bits employ three, four, or more relatively long primary blades that may extend to locations proximal the bit's rotating axis (e.g., into the cone region of the bit). In addition, these primary blades typically support a plurality of cutter elements. In particular, since primary blades often extend to locations proximal the bit's rotating axis, primary blades often support the cutter elements in the innermost central region of the bit. However, for some fixed cutter bits, the presence of a greater number of primary blades may result in a lower ROP. Thus, it may be desirable to decrease the number of relatively long primary blades on a drag bit. In addition, the greater the number of relatively long primary blades provided on the bit, the less space is available for the placement of drilling fluid nozzles. Space limitations may result in the placement of fluid nozzles in less desirable locations about the bit. Compromised nozzle placement may also detrimentally impact fluid hydraulic performance, bit ROP, and bit durability. Still further, space limitations for fluid nozzles may result in more complex bit designs necessary to accommodate drilling fluid channels and nozzles. The increased complexity in the design and manufacture of the bit may increase bit costs.
  • Accordingly, there remains a need in the art for a fixed cutter bit and cutting structure capable of enhanced ROP and greater bit life, while minimizing other detrimental effects.
  • BRIEF SUMMARY OF PREFERRED EMBODIMENTS
  • These and other needs in the art are addressed in one embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density, and wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
  • These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body with a central axis and an outer radius, in addition, the bit comprises a bit face comprising an inner region extending from the central axis to no more than 50% of the outer radius, and an outer region between the inner region and the outer radius. Further, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends from proximal the central axis into the outer region. Still further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade. Moreover, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade, wherein the at least one primary blade has an inner back-up cutter area and an outer backup cutter area, and wherein the inner backup cutter area is greater than the outer backup cutter area.
  • Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade begins substantially proximal the central axis and extends towards the gage region. Further, the bit comprises at least one secondary blade disposed on the bit face, wherein the at least one secondary blade begins at a radial distance “D” from the central axis and extends toward the gage region, the radial distance “D” being a radius defining the cone region. Still further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade, wherein the primary cutter elements are disposed in a first row extending along the at least one primary blade from substantially proximal the central axis toward the gage region. Moreover, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade, wherein the backup cutter elements are disposed in a second row extending along the at least one primary blade within the cone region.
  • These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade begins proximal the central axis and extends toward the gage region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade is free of backup cutter elements in he shoulder region.
  • Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the embodiments described herein. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • For a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:
  • FIG. 1 is a perspective view of an embodiment of a bit made in accordance with the principles described herein.
  • FIG. 2 is a view of the face of the bit shown in FIG. 1;
  • FIG. 3 is a partial cross-sectional view of the bit shown in FIG. 1 with the cutter elements of the bit shown rotated into a single profile;
  • FIG. 4 is a schematic view of an embodiment of a bit made in accordance with the principles described herein;
  • FIG. 5 is a schematic view of another embodiment of a bit made in accordance with the principles described herein;
  • FIG. 6A is a schematic view of an arrangement of primary cutter elements and backup cutter elements in the cone region of a bit made in accordance with the principles described herein;
  • FIG. 6B is a schematic view showing the rotated profiles of the cutting faces of the cutter elements of the bit shown in FIG. 6A;
  • FIG. 7A is a schematic view of an arrangement of primary cutter elements and backup cutter elements in the cone region of a bit made in accordance with the principles described herein;
  • FIG. 7B is a schematic view showing the rotated profiles of the cutting faces of the cutter elements of the bit shown in FIG. 7A;
  • FIG. 8A is a schematic view of an arrangement of primary cutter elements and backup cutter elements in the cone region of a bit made in accordance with the principles described herein;
  • FIG. 8B is a schematic view showing the rotated profiles of the cutting faces of the cutter elements of the bit shown in FIG. 8A;
  • FIG. 9A is a schematic view of an arrangement of primary cutter elements and backup cutter elements in the cone region of a bit made in accordance with the principles described herein;
  • FIG. 9B is a schematic view showing the rotated profiles of the cutting faces of the cutter elements of the bit shown in FIG. 9A;
  • FIG. 10A is a schematic view of an arrangement of primary cutter elements and backup cutter elements in the cone region of a bit made in accordance with the principles described herein; and
  • FIG. 10B is a schematic view showing the rotated profiles of the cutting faces of the cutter elements of the bit shown in FIG. 10A.
  • DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
  • The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred the embodiments disclosed have broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment or to the features of that embodiment.
  • Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
  • In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.
  • Referring to FIGS. 1 and 2, exemplary bit 10 is a fixed cutter bit, sometimes referred to as a drag bit, and is preferably a PDC bit adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body 12, a shank 13 and a threaded connection or pin 14 for connecting bit 10 to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. Bit face 20 supports a cutting structure 15 and is formed on the end of the bit 10 that is opposite pin end 16. Bit 10 further includes a central axis 11 about which bit 10 rotates in the cutting direction represented by arrow 18. Body 12 may be formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix. Alternatively, the body can be machined from a metal block, such as steel, rather than being formed from a matrix.
  • As best seen in FIG. 3, body 12 includes a central longitudinal bore 17 permitting drilling fluid to flow from the drill string into bit 10. Body 12 is also provided with downwardly extending flow passages 21 having ports or nozzles 22 disposed at their lowermost ends. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluids around a cutting structure 15 to flush away formation cuttings during drilling and to remove heat from bit 10.
  • Referring again to FIGS. 1 and 2, cutting structure 15 is provided on face 20 of bit 10. Cutting structure 15 includes a plurality of blades which extend from bit face 20. In the embodiment illustrated in FIGS. 1 and 2, cutting structure 15 includes two angularly spaced-apart primary blades 31, 32 and four angularly spaced apart secondary blades 33, 34, 35 and 36. In particular, in this embodiment, the plurality of blades are spaced generally uniformly about the bit face 20. In addition, the two primary blades 31, 32 are spaced substantially opposite each other (e.g., about 180° apart). In other embodiments (not specifically illustrated), the blades may be spaced non-uniformly about bit face 20.
  • In the embodiment shown, each primary blade 31, 32 includes a cutter-supporting surface 42 for mounting a plurality of cutter elements, and each secondary blade 33-36 includes a cutter-supporting surface 52 for mounting a plurality of cutter elements. In particular, primary cutter elements 40 having primary cutting faces 44 are mounted to primary blades 31, 32 and secondary blades 33-36. Further, backup cutter elements 50 having backup cutting faces 54 are mounted to primary blades 31, 32.
  • Still referring to FIGS. 1 and 2, primary blades 31, 32 and secondary blades 33, 34, 35 and 36 are integrally formed as part of, and extend from, bit body 12 and bit face 20. Primary blades 31, 32 and secondary blades 33, 34, 35 and 36 extend radially across bit face 20 and longitudinally along a portion of the periphery of bit 10. Primary blades 31, 32 extend radially from substantially proximal central axis 11 toward the periphery of bit 10. Thus, as used herein, the term “primary blade” is used to describe a blade that extends from substantially proximal central axis 11. Secondary blades 33, 34, 35 and 36 do not extend from substantially proximal central axis 11. As best seen in FIG. 2, secondary blades 33-36 extend radially from a location that is a distance “D” away from central axis 11 toward the periphery of bit 10. Hence, primary blades 31, 32 extend closer to central axis 11 than secondary blades 33-36. Thus, as used herein, the term “secondary blade” is used to describe a blade that does not extend from substantially proximal central axis 11. Primary blades 31, 32 and secondary blades 33, 34, 35 and 36 are separated by drilling fluid flow courses 19.
  • As described above, the embodiment of bit 10 illustrated in FIGS. 1 and 2 includes two relatively longer primary blades (e.g., primary blades 31, 32). As compared to some conventional fixed cutter bits that employ three, four, or more relatively long primary blades, bit 10 has fewer primary blades that extend substantially proximal the center of bit 10. By reducing the number of relatively long primary blades, embodiments of the present invention may improve the ROP of bit 10.
  • In different embodiments (not specifically illustrated), bit 10 may comprise a different number of primary blades and/or secondary blades than that shown in FIGS. 1 and 2. In general, bit 10 may include one or more primary blades and one or more secondary blades as desired. As one example only, bit 10 may comprise three primary blades and three secondary blades.
  • Each blade on bit face 20 (e.g., primary blades 31, 32 and secondary blades 33-36) provides a cutter-supporting surface 42, 52 to which cutter elements are mounted. In the embodiment illustrated in FIGS. 1 and 2, primary cutter elements 40 are disposed on the cutter-supporting surface 42 of primary blades 31, 32 and on the cutter-supporting surface 52 of secondary blades 33, 34, 35, and 36 In addition, backup cutter elements 50 are disposed only on the cutter-supporting surface 42 of primary blades 31, 32. In different embodiments (not specifically illustrated), backup cutter elements may also be provided on cutter-supporting surface 52 of secondary blades 33-36
  • Primary cutter elements 40 are positioned adjacent one another generally in a first row extending radially along each primary blade 31, 32 and along each secondary blade 33-36. Further, backup cutter elements 50 are positioned adjacent one another generally in a second row extending radially along each primary blade 31, 32. In particular, backup cutter elements 50 form a second row that extends along each primary blade 31, 32 from substantially proximal central axis 11. Backup cutter elements 50 are positioned behind the primary cutter elements 40 provided on the same primary blade 31, 32. As best seen in FIG. 2, when bit 10 rotates about central axis 11 in the cutting direction represent by arrow 18, backup cutter elements 50 trail the primary cutter elements 40 provided on the same primary blade 31, 32. Thus, as used herein, the term “backup cutter element” is used to describe a cutter element that trails any other cutter element on the same blade when bit 10 is rotated in the cutting direction represented by arrow 18. Further, as used herein, the term “primary cutter element” is used to describe a cutter element provided on the leading edge of a blade. In other words, when bit 10 is rotated about central axis 11 in the cutting direction of arrow 18 a “primary cutter element” does not trail any other cutter elements on the same blade.
  • In general, primary cutter elements 40 and backup cutter elements 50 need not be positioned in rows, but may be mounted in other suitable arrangements provided each cutter element is either in a leading position (e.g., primary cutter element 40) or trailing position (e.g., backup cutter element 50). Examples of suitable arrangements may include without limitation, rows, arrays or organized patterns, randomly, sinusoidal pattern, or combinations thereof. Further, in other embodiments (not specifically illustrated), additional rows of cutter elements may be provided on a primary blade, secondary blade, or combinations thereof.
  • As described above, the embodiment of bit 10 illustrated in FIGS. 1 and 2 includes a first row of primary cutter elements 40 and a second row of backup cutter elements 50 on each primary blade 31, 32. Thus, although embodiments of the present invention may provide fewer relatively long primary blades as compared to some conventional fixed cutter bits, the total cutter element count may not be detrimentally reduced since some cutter elements lost by removing one or more primary blades are replaced by adding a second row of cutter elements on each remaining primary blades, the second row being “backup cutter elements” on “primary blades” as described herein
  • Still referring to FIGS. 1 and 2, bit 10 further includes gage pads 51 of substantially equal length that are disposed about the circumference of bit 10 at angularly spaced locations. Gage pads 51 intersect and extend from blades 31-36, respectively Gage pads 51 are integrally formed as part of the bit body 12.
  • As shown in FIGS. 1 and 2, each gage pad 51 includes a generally gage-facing surface 60 and a generally forward-facing surface 61 which intersect in an edge 62, which may be radiused, beveled or otherwise rounded. Gage-facing surface 60 includes at least a portion that extends in a direction generally parallel to bit access 11 and extends to full gage diameter. In some embodiments, other portions of gage-facing surface 60 may be angled, and thus slant away from the borehole sidewall. Also, in select embodiments, forward-facing surface 61 may likewise be angled relative to central axis 11 (both as viewed perpendicular to central axis 11 or as viewed along central axis 11). Surface 61 is termed generally “forward-facing” to distinguish that surface from the gage surface 60, which generally faces the borehole sidewall. Gage-facing surface 60 of gage pads 51 abut the sidewall of the borehole during drilling. The pads can help maintain the size of the borehole by a rubbing action when primary cutter elements 40 wear slightly under gage. The gage pads also help stabilize the bit against vibration.
  • In certain embodiments (not specifically illustrated), certain gage pads 51 include cutter elements. Further, in some embodiments (not specifically illustrated), no gage pads 51 are provided on bit 10. Wear-resistant inserts may be embedded in gage pads 51 and protrude from the gage-facing surface 60 or forward facing, surface 61 of gage pads 51.
  • Referring to FIG. 3, an exemplary profile of bit 10 is shown as it would appear with all blades (e.g., primary blades 31, 32, secondary blades 33-36) and all cutter elements (e.g., primary cutter elements 40, backup cutter elements 50) rotated into a single rotated profile. As shown in FIG. 3, in rotated profile the plurality of blades of bit 10 (e.g., primary blades 31, 32 and secondary blades 33-36) include blade profiles 39. Blade profiles 39 and bit face 20 may be divided into three different regions labeled cone region 24, shoulder region 25, and gage region 26. Cone region 24 is concave in this embodiment and comprises the inner most region of bit 10 (e.g., cone region 24 is the central most region of bit 10). Adjacent cone region 24 is shoulder (or the upturned curve) region 25. Next to shoulder region 25 is the gage region 26 which is the portion of the bit face 20 which defines the outer radius 23 of bit 10. Outer radius 23 extends to and therefore defines the full gage diameter of bit 10. As used herein, the term “full gage diameter” is used to describe elements or surfaces extending to the full, nominal gage of the bit diameter.
  • Still referring to FIG. 3, cone region 24 is defined by a radial distance along the x-axis measured from central axis 11. It is to be understood that the x-axis is perpendicular to central axis 11 and extends radially outward from central axis 11. Cone region 24 may be defined by a percentage of outer radius 23 of bit 10. In some embodiments, cone region 24 extends from central axis 11 to no more than 50% of outer radius 23. In select embodhients, cone region 24 extends from central axis 11 to no more than 30% of outer radius 23. Cone region 24 may likewise be defined by the location of one or more secondary blades (e.g., secondary blades 33-36). For example, cone region 74 extends from central axis 11 to a distance at which a secondary blade begins (e.g., distance “D” illustrated in FIG. 2). In other words, the outer boundary of cone region 24 may coincide with the distance “D” at which one or more secondary blades begin. The actual radius of cone region 24, measured from central axis 11, may vary from bit to bit depending on a variety of factors including without limitation, bit geometry, bit type, location of one or more secondary blades (e.g., secondary blades 33-36), location of backup cutter elements 50, or combinations thereof. For instance, in some cases bit 10 may have a relatively flat parabolic profile resulting in a cone region 24 that is relatively large (e.g., 50% of outer radius 23). However, in other cases, bit 10 may have a relatively long parabolic profile resulting in a relatively smaller cone region 24 (e.g., 30% of outer radius 23).
  • Blade profiles 39 and bit face 20 may also be described as two regions termed “inner region” and “outer region”, where the “inner region” is the central most region of bit 10 and is analogous to cone region 24, and the “outer region” is simply the region(s) of bit 10 outside the inner region. Using this nomenclature, the outer region is analogous to the combined shoulder region 25 and gage region 26 previously described. The inner region may be defined similarly to cone region 24 (e.g., by a percentage of the outer radius 23, by distance “D,” etc.).
  • Referring to FIG. 4, a schematic view of an embodiment of bit 10 is illustrated. As discussed above, bit 10 comprises a bit face 20 having a cone region 24, a shoulder region 25, and a gage region 26. Bit 10 further includes two primary blades 31, 32 and four secondary blades 33-36 integrally formed as part of, and which extend from, bit face 20. Primary blades 31, 32 extend radially from within cone region 24 proximal central axis 11 toward gage region 26 and outer radius 23. Secondary blades 33-36 extend radially from within shoulder region 25 proximal cone region 24 toward gage region 26 and outer radius 23. In this embodiment, each secondary blade 33-36 begins at a distance “D” that substantially coincides with the outer radius of cone region 24 (e.g., the intersection of cone region 24 and should region 25). In some embodiments, primary blades 31, 32 may extend to outer radius 23. Further, in select embodiments, secondary blades 33-36 may extend to outer radius 23 (and gage region 26). Still further, in other embodiments, one or more secondary blades 33-36 may extend into cone region 24.
  • In the embodiment illustrated in FIG. 4, primary blades 31, 32 and secondary blades 33-36 taper (e.g., become thinner) as the blades extend inward toward central axis 11. In different embodiments (not specifically illustrated), one or more primary blades 31, 32, one or more secondary blades 33-36, or combinations thereof may be uniform or taper towards full gage radius 23. Further the taper may be linear or non-linear. In addition, although primary blades 31, 32 and secondary blades 33-36 illustrated in FIG. 4 are substantially straight as they extend towards full gage diameter 23, in other embodiments (e.g., FIG. 2), one or more primary blades 31, 32, one or more secondary blades 33-36, or combinations thereof may curve along their radial length.
  • Each blade provided on bit 10 (e.g., primary blades 31, 32, secondary blades 33-36) provides a cutter-supporting surface 42, 52 for mounting cutter elements (e.g., primary cutter elements 40, backup cutter elements 50). In the embodiment illustrated in FIG. 4, a plurality of primary cutter elements 40 are provided on primary blades 31, 32 and secondary blades 33-36. Further, a plurality of backup cutter elements 50 are provided on primary blades 31, 32. In the embodiment illustrated in FIG. 4, backup cutter elements 50 are provided only on primary blades 31, 32 (e.g., no backup cutter elements 50 are provided on secondary blades 33-36). In other embodiments (not specifically illustrated), backup cutter elements 50 may be provided on one or more primary blades, one or more secondary blades, or combinations thereof.
  • Still referring to the embodiment shown in FIG. 4, backup cutter elements 40 are provided within the cone region 24 on primary blades 31, 32. The shoulder region 25 and gage region 26 of bit 10 are substantially free of backup cutter elements. In particular, in this embodiment, neither primary blades 31, 32, nor secondary blades 33-36 include backup cutter elements 50 within shoulder region 25 and gage region 26.
  • Each primary cutter element 40 and each backup cutter element 50 comprise an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. Further, each cutter element 40, 50 has a cutting face 44, 54 (respectively) that comprises a forward facing disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member.
  • In the embodiments described herein, the primary cutter elements 40 and the backup cutter elements 50 are mounted so that their cutting faces 44, 54 are forward facing. As used herein, “forward facing” is used to describe the orientation of a surface that is substantially perpendicular to or at an acute angle relative to the cutting direction of bit 10 represented by arrow 18. For instance, a forward facing cutting face 44, 54 may be oriented substantially perpendicular to the cutting direction of bit 10, may include a backrake angle, and/or may include a siderake angle.
  • In the embodiment illustrated in FIG. 4, each primary cutter element 40 has substantially the same size and geometry as other primary cutter elements 40. Further, each backup cutter element 50 has substantially the same size and geometry as other backup cutter elements 50. However, in general, each primary cutter element 40 and each backup cutter element 50 may have any suitable size and geometry.
  • Still referring to FIG. 4, each blade having one or more backup cutter elements 50 (e.g., primary blades 31, 32) can be described or characterized in terms of a cone backup cutter density, a shoulder backup cutter density, and a gage backup cutter density. As used herein, the term “backup cutter density” is used to refer to the average number of backup cutter elements 50 per unit length of blade. Thus, “cone backup cutter density” refers to the backup cutter density of the portion of a blade within cone region 24, “shoulder backup cutter density” refers to the backup cutter density of the portion of a blade within shoulder region 25, and “gage backup cutter density” refers to the backup cutter density of the portion of a blade within the gage region. For example, if a primary blade (e.g., primary blade 32) has an average of two backup cutter elements 50 per inch of blade within cone region 24 and an average an average of one backup cutter element 50 per inch of blade within shoulder region 25, then the cone backup cutter density of the primary blade is two (2 backup cutter elements 50 per inch) and the backup cutter density within shoulder region 25 is one (one backup cutter elements per inch).
  • It is to be understood that blades having one or more backup cutter elements and which do not extend into a particular region will have a backup cutter density of zero in that particular region. For example, if a primary blade has one or more backup cutter elements, but the primary blade does not extend into gage region 26, then the primary blade has a gage backup cutter density of zero.
  • In select embodiments, the cone backup cutter density of a primary blade (e.g., primary blade 31) is greater than the shoulder backup cutter density and greater than the gage backup cutter density. For example, in the embodiment illustrated in FIG. 4, the cone backup cutter density of primary blade 32 is greater than the shoulder backup cutter density of primary blade 32. Further, the cone backup cutter density of primary blade 32 is greater than the gage backup cuter density of primary blade 32. In particular, cone region 24 includes backup cutter elements 50 on primary blade 32, but shoulder region 25 and gage region 26 of primary blade 32 are free of backup cutter elements 50. Thus, the shoulder backup cutter density and gage backup cutter density of primary blade 32 are both zero In different embodiments (not specifically illustrated), for a given primary blade, the cone backup cutter density may alternatively be equal to or less than either or both the shoulder backup cutter density and gage backup cutter density.
  • Alternatively, each primary blade 31, 32 may be said to have an inner backup cutter density and an outer backup cutter density, where the inner backup cutter density is the backup cutter density within an inner region, analogous to the cone backup cutter density, and the outer backup cutter density is the backup cutter density on the portion of blade outside the inner region.
  • Still referring to FIG. 4, each blade having one or more backup cutter elements 50 (e.g., primary blades 31, 32) has a “cone backup cutter area”, a “shoulder backup cutter area”, and a “gage backup cutter area”. As used herein, the term “backup cutter area” is used to refer to the sum total of the surface area of each backup cutting face 54. Thus, cone backup cutter area refers to the backup cutter area of the portion of a blade within cone region 24, shoulder backup cutter area refers to the backup cutter area of the portion of a blade within shoulder region 25, and gage backup cutter area refers to the backup cutter area of the portion of a blade within the gage region For example, if each backup cutting face 54 has a surface area of 1 in.2, and a particular blade has four backup cutter elements 50 in cone region 24, one backup cutter element 50 in shoulder region 25, and zero backup cutter elements in gage region 26, then the cone backup cutter area for the blade is 4 in.2 (4×1 in.2), the shoulder backup cutter area for the blade is 1 in.2 (1×1 in.2), and the gage backup cutter area for the blade is 0 in.2 (0×1 in.2).
  • It is to be understood that blades having one or more backup cutter elements and which do not extend into a particular region will have a backup cutter area of zero in that particular region. For example, if a primary blade has backup cutter elements, but the primary blade does not extend into gage region 26, then the primary blade has a gage backup cutter area of zero.
  • In select embodiments, the cone backup cutter area of a primary blade (e.g., primary blade 31) is greater than the shoulder backup cutter area of the same primary blade and greater than the gage backup cutter area of that primary blade. For example, in the embodiment illustrated in FIG. 4, the cone backup cutter area of primary blade 32 is greater than the shoulder backup cutter area of primary blade 32. Further, the cone backup cutter area of primary blade 32 is greater than the gage backup cutter area of primary blade 32. In particular, there are backup cutter elements in cone region 24 of primary blade 32, but no backup cutter elements in shoulder region 25 nor gage region 26 of primary blade 32. Thus, the shoulder backup cutter area and gage backup cutter area of primary blade 32 are both zero. In different embodiments (not specifically illustrated), for a given primary blade, the cone backup cutter area may alternatively be equal to or less than either or both the shoulder backup cutter area and gage backup cutter area.
  • Alternatively, each primary blade 31, 32 may be said to have an inner backup cutter area and an outer backup cutter area, where the inner backup cutter area is the backup cutter area within an inner region, analogous to the cone backup cutter area, and the outer backup cutter area is the backup cutter area on the portion of blade outside the inner region.
  • As described, certain embodiments disclosed herein reduce the primary blade count on bit 10 as compared to some conventional fixed cutter bits of the same gage diameter that may include three, four, or more primary blades. However, reducing primary blade count on bit 10 (without other design changes) may also result in a reduction in the number of cutter elements on bit 10. In particular, a reduction of cutter elements in cone region 24 of bit 10 may detrimentally impact the ability of the bit to distribute across the cutter elements in the cone region the relatively high loads encountered during drilling. Therefore, in select embodiments, the reduction in primary blade count is also accompanied by the positioning of additional cutter elements, in the form of backup cutter elements, in the cone region 24 such that the overall cutter element count in the cone region may be substantially the same even though the primary blade count has been decreased. Without being limited by theory, by reducing the primary blade count and substantially maintaining the cutter element count within the cone region 24, it is desired that the ROP of bit 10 be increased as compared to some conventional fixed cutter bits.
  • In addition, as best seen in FIG. 4, by reducing the number of primary blades on bit 10, as compared to some conventional fixed cutter bits flat include three four or more primary blades, additional space is made available for positioning nozzles 22 about bit face 20. In this manner, nozzles 22 may be positioned in more desirable locations which may not otherwise be available due to space limitations resulting from a greater number of primary blades. Without being limited by theory, improved placement of nozzles 24 is intended to enhance removal of formation cuttings and enhance removal of heat from bit 10. As a result, the ROP and life of bit 10 may be advantageously enhanced.
  • Referring to FIG. 5, a schematic view of another embodiment of bit 10 is illustrated. As discussed above, bit 10 comprises a bit face 20 having a cone region 24, a shoulder region 25, and a gage region 26. Primary blades 31, 32 extend radially from within cone region 24 proximal central axis 11 toward gage region 26 and outer radius 23. Secondary blades 33-36 begin partially within cone region 24 and extend radially into shoulder region 25 toward gage region 26 and outer radius 23. In this embodiment, each secondary blade 33-36 begins at a distance “D” that is distinct from the outer radius of cone region 24. In particular, the distance “D” at which secondary blades 33-36 begin lies within cone region 24. In other words, in this embodiment, secondary blades 33-36 extend slightly into cone region 24.
  • A plurality of primary cutter elements 40 are provided on cutter-supporting surface 42 of each primary blade 31, 32 and cutter-supporting surface 52 of each secondary blade 33-36. Further, a plurality of backup cutter elements 50 are provided on the cutter-supporting surface 52 of each primary blade 31, 32.
  • Still referring to the embodiment shown in FIG. 5, backup cutter elements 50 are provided within the cone region 24 on primary blades 31, 32. Further, backup cutter elements 50 are provided within shoulder region 25 on primary blades 31, 32. However, gage region 26 of bit 10 is substantially free of backup cutter elements 50. In this embodiment, no backup cutter elements 50 are provided on secondary blades 33-36,
  • Still referring to FIG. 5, each blade having one or more backup cutter elements 50 (e.g., primary blades 31, 32) can be described or characterized in terms of a cone backup cutter density, a shoulder backup cutter density, and a gage backup cutter density. In the embodiment illustrated in FIG. 5, the cone backup cutter density of primary blade 32 is greater than the shoulder backup cutter density of primary blade 32. Further, the shoulder backup cutter density of primary blade 32 is greater than the gage backup cutter density of primary blade 32.
  • Still referring to FIG. 5, each blade having one or more backup cutter elements 50 (e.g., primary blades 31, 32) has a “cone backup cutter area”, a “shoulder backup cutter area”, and a “gage backup cutter area”. In the embodiment illustrated in FIG. 5, the cone backup cutter area of primary blade 32 is greater than the shoulder backup cutter area of primary blade 32, and the shoulder backup cutter area of primary blade 32 is greater than the age backup cutter area of primary blade 32.
  • As previously described, certain embodiments disclosed herein reduce the primary blade count on bit 10 as compared to some conventional fixed cutter bits of the same gage diameter, while substantially maintaining the total cutter element count in the cone region 24. Without being limited by theory, by reducing the primary blade count and substantially maintaining the cutter element count within the cone region 24, it is desired that the ROP of bit 10 be increased as compared to some conventional fixed cutter bits.
  • In addition, by reducing the number of primary blades on bit 10, as compared to some conventional fixed cutter bits of the same gage diameter, additional space is made available for positioning nozzles 22 about bit face 20. Without being limited by theory, improved placement of nozzles 24 is intended to enhance removal of formation cuttings and enhance removal of heat from bit 10. As a result, the ROP and life of bit 10 may be advantageously enhanced.
  • As one skilled in the art will appreciate, numerous variations in the size, orientation, and locations of backup cutter elements 50 and primary cutter elements 40 within cone region 24 are possible. Certain features and variations of backup cutter elements 50 of bit 10 illustrated in FIGS. 1-5 may be best understood with reference to schematic enlarged views of the primary blades 31, 32 within cone region 24 of bit 10. In addition, certain features and variations may be best understood with reference to rotated profile views, one associated with each enlarged view, in which the primary cutting faces 44 and backup cutting faces 54 of each enlarged view can be viewed simultaneously in schematic fashion.
  • In the embodiments that follow, reference numerals 40 a-40 h represent primary cutter elements disposed on primary blades 31, 32 within cone region 24 of bit 10. In particular, reference numerals 40 a, 40 c, 40 e, and 40 g represent primary cutter elements disposed on primary blade 31, while reference numerals 40 b, 40 d, 40 f and 40 h represent primary cutter elements disposed on primary blade 32. Further, reference numerals 50 a-50 h represent backup cutter elements disposed on primary blades 31, 32 within cone region 24 of bit 10. In particular, reference numerals 50 a, 50 c, 50 e, and 50 g represent backup cutter elements disposed on primary blade 31, while reference numerals 50 b, 50 d, 50 f, and 50 h represent backup cutter elements disposed on primary blade 32. In addition, primary cutter elements 40 a-40 h include primary cutting faces 44 a-44 h, respectively, and backup cutter elements 50 a-50 h include backup cutting faces 54 a-54 h, respectively.
  • FIG. 6A illustrates an embodiment of an arrangement of primary blades, primary cutter elements, and backup cutter elements within cone region 24 of bit 10. FIG. 6B illustrates the rotated profile view of the primary cutting faces 44 a-44 h of primary cutter elements 40 a-40 h and backup cutting faces 54 a-54 h of backup cutter elements 50 a-50 h shown in FIG. 6A.
  • Referring to FIG. 6A, cone region 24 of bit 10 comprises two primary blades 31, 32 that extend radially outward from proximal central axis 11. In addition, bit 10 comprises eight primary cutter elements 40 a-40 h within cone region 24 and eight backup cutter elements 50 a-50 h within cone region 24. In particular, primary blades 31, 32 each include four primary cutter elements and four backup cutter elements. For instance, primary cutter elements 40 a, 40 c, 40 e, and 40 g and backup cutter elements 50 a, 50 c, 50 e, and 50 g are disposed on primary blade 31 within cone region 24 of bit 10. In different embodiments, each primary blade (e.g., primary blade 31, 32) may have any suitable number of primary cutting elements and backup cutting elements within cone region 24.
  • Bit 10 rotates about central axis 11 in the cutting direction of arrow 18 such that primary blades 31, 32 follow each other. Further, as bit 10 rotates about central axis 11, the backup cutter elements trail the primary cutter elements provided on the same primary blade. For instance, backup cutter elements 50 a, 50 c, 50 e, and 50 g on primary blade 31 are positioned behind, and hence trail, primary cutter elements 40 a, 40 c, 40 e, and 40 g on primary blade 31 as bit 10 rotates,
  • The primary cutter elements are positioned adjacent each other substantially in a first row on each primary blade. For instance, primary cutter elements 40 b, 40 d, 40 f, and 40 h are arranged substantially in a first row along primary blade 32. In addition, the backup cutter elements are positioned adjacent each other substantially in a second row on each primary blade. For instance backup cutter elements 50 b, 50 d, 50 f, and 50 h are arranged substantially in a second row along primary blade 32. Further, in the embodiment illustrated in FIG. 6A, the primary cutter elements and backup cutter elements are uniformly spaced on each primary blade. However, in general, the primary cutter elements and backup cutter elements may have any suitable location, arrangement, geometry, and orientation.
  • In the embodiment shown in FIG. 6A, the centerline on each backup cutter element substantially coincides with the centerline of a primary cutter element on the same primary blade. For example, the centerline 80 a of primary cutter element 40 a is substantially the same as the centerline 90 a of backup cutter element 50 a. In other embodiments, each backup cutter element may not share a centerline with a primary cutter element. For example, in some embodiments, each backup cutter elements is staggered relative to a primary cutter elements on the same primary blade.
  • As best seen in the rotated profile shown in FIG. 6B, as a result of the position of the backup cutter elements 50 a-50 h relative to the primary cutter elements 40 a-40 h, and due to the relative sizes of the backup cutting faces 54 a-54 h and primary cutting faces 44 a-44 h, each primary cutting face 44 a-44 h substantially eclipses a backup cutting face 54 a-54 h provided on the same primary blade. In other words, each backup cutting face passes completely through a path made by a primary cutting face on the same primary blade. For example, as bit 10 rotates about central axis 11, backup cutting face 54 b on primary blade 32 passes completely within and through the path created by primary cutting face 44 b on primary blade 32 Depending on a variety of factors including without limitation the size, location and arrangement of backup cutter elements and primary cutter elements, in some embodiments, the primary cutter elements may substantially eclipse, partially eclipse, or not eclipse each backup cutter element. As used herein, the term “substantially eclipse” is used to refer to a primary cutting face that overlaps more than 50% of the area of a backup cutting face. As used herein, the term “partially eclipse” is used to refer to a primary cutting face that overlaps less than 50% of the area of a backup cutting face 54.
  • Although the embodiment illustrated in FIG. 6B shows each primary cutting face 44 a-44 h and each backup cutting face 54 a-54 h as substantially circular, in different embodiments, the cutting face of each primary cutter element and backup cutter element may be any suitable geometry including without limitation, circular, oval, rectangular, triangular, or combinations thereof.
  • Still referring to the rotated profile shown in FIG. 6B, the row of primary cutter elements 40 a, 40 c, 40 e, and 40 g disposed on primary blade 31 are staggered relative to the row of primary cutter elements 40 b, 40 d, 40 e, and 40 g disposed on primary blade 32, such that in rotated profile, primary cutting faces 44 a, 44 c, 44 e, and 44 g on primary blade 31 sweep between primary cutting faces 44 b, 44 d, 44 f, and 44 g on primary blade 32, and vice versa. Thus, each primary cutting face on primary blade 31 fills a gap created between primary cutting faces on primary blade 32. For instance, in rotated profile, primary cutting face 44 d on primary blade 32 rotates through the gap between primary cutting face 44 c and 44 e on primary blade 31. In addition, since the centerline of each backup cutter element substantially coincides with a primary cutter element on the same blade, the row of backup cutter elements 50 a, 50 c, 50 e, and 50 g disposed on primary blade 31 are also staggered relative to the row of backup cutter elements 50 b, 50 d, 50 f, and 50 h disposed on primary blade 32.
  • As best seen in the rotated profile shown in FIG. 6B, primary cutting faces 44 a-44 h have a greater extension height than backup cutting faces 54 a-54 h As used herein, the term “extension height” is used to describe the distance a cutter face extends from the cutter-supporting surface of the blade to which it is attached. Thus, primary cutting faces 44 a-44 h will engage a greater depth of formation than backup cutting faces 54 a-54 h. In some embodiments, one or more backup cutting face 54 a-54 h may have the same or a greater extension height than one or more primary cutting face 44 a-44 h.
  • Although the embodiment illustrated in FIGS. 6A and 6B shows all backup cutter elements 50 a-50 h as having substantially the same geometry and orientation, and all primary cutter elements 40 a-40 h as having substantially the same geometry and orientation, in different embodiments the geometry and orientation of each backup cutter element may vary and/or the geometry and orientation of each primary cutter element may vary.
  • FIG. 7A illustrates another, embodiment of primary blades, primary cutter elements, and backup cutter elements within cone region 24 of bit 10. FIG. 7B illustrates the rotated profile view of the primary cutting faces 44 a-44 h of primary cutter elements 40 a-40 h and backup cutting faces 54 a-54 h of backup cutter elements 50 a-50 h shown in FIG. 7A.
  • The embodiment illustrated in FIGS. 7A and 7B is substantially the same as the embodiment illustrated in FIGS. 6A and 6B. However, in the embodiment shown in FIG. 7A, although backup cutter elements 50 a-50 h are generally smaller than primary cutter elements 40 a-40 h, backup cutting faces 54 a-54 h have an extension height equal to that of primary cutting faces 44 a-44 h. Thus, backup cutting faces 54 a-54 h will engage substantially the same depth of formation as primary cutting faces 44 a-44 h.
  • FIG. 8A illustrates another embodiment of primary blades, primary cutter elements, and backup cutter elements within cone region 24 of bit 10. FIG. 8B illustrates the rotated profile view of the primary cutting faces 44 a-44 h of primary cutter elements 40 a-40 h and backup cutting faces 54 a-54 h of backup cutter elements 50 a-50 h shown in FIG. 8A.
  • In the embodiment shown in FIG. 8A, a backup cutter element trails each primary cutter element, however, each backup cutter element is partially offset relative to the primary cutter element which it trails on the same primary blade. For instance, centerline 90 a of backup cutter element 50 a is offset from centerline 80 a of primary cutter element 40 a. In addition, primary cutter elements 40 a-40 h, and associated primary cutting faces 44 a-44 h, are relatively larger than backup cutter elements 50 a-50 h, and associated backup cutting faces 54 a-54 h.
  • As best seen in the rotated profile shown in FIG. 8B, as a result of the position of backup cutter elements 50 a-50 h relative to the primary cutter elements 40 a-40 h, and due to the relative sizes of the backup cutting faces 54 a-54 h and primary cutting faces 44 a-44 h, each backup cutting face 54 a-54 h is partially eclipsed by a primary cutting face on the same primary blade and partially eclipsed by a primary cutting face on a different primary blade. For example, backup cutting face 54 b on primary blade 32 is partially eclipsed by primary cutting face 44 b on primary blade 32 and partially eclipsed by primary cutting face 44 c on primary blade 32.
  • Still referring to the rotated profile shown in FIG. 8B, the row of primary cutter elements 40 a, 40 c, 40 e, and 40 g disposed on primary blade 31 are staggered relative to the row of primary cutter elements 40 b, 40 d, 40 f and 40 g disposed on primary blade 32, such that in rotated profile, primary cutting faces 44 a, 44 c, 44 e, and 44 g on primary blade 31 sweep between primary cutting faces 44 b, 44 d, 44 f, and 44 g on primary blade 32. Further, the row of backup cutter elements 50 a, 50 c, 50 e, and 50 g disposed on primary blade 31 are staggered relative to the row of backup cutter elements 50 b, 50 d, 50 f, and 50 h disposed on primary blade 32, such that in rotated profile, backup cutting faces 54 a, 54 c, 54 e, and 54 g disposed on primary blade 31 sweep between backup cutting faces 54 b, 54 d, 54 f, and 54 h disposed on primary blade 32.
  • In addition, as best seen in the rotated profile shown in FIG. 8B, although backup cutting faces 54 a-54 h are smaller than primary cutting faces 44 a-44 h, backup cutting faces 44 a-44 h have substantially the same extension height as primary cutting faces 44 a-44 h. Thus, backup cutting faces 54 a-54 h will engage substantially the same depth of formation as primary cutting faces 44 a-44 h.
  • FIG. 9A illustrates another embodiment of primary blades, primary cutter elements, and backup cutter elements within cone region 24 of bit 10. FIG. 9B illustrates the rotated profile view of primary cutting faces 44 a-44 h and backup cutting faces 54 a-54 h shown in FIG. 9A.
  • In the embodiment shown in FIG. 9A, each backup cutter element is offset relative to the primary cutter elements provided on the same primary blade. For instance, centerline 90 a of backup cutter element 50 a on primary blade 31 is offset relative to primary cutter elements 40 a and 40 c on primary blade 31. In addition, primary cutter elements 40 a-40 h, and associated primary cutting faces 44 a-44 h, are substantially the same size as backup cutter elements 50 a-50 h, and associated backup cutting faces 54 a-54 h.
  • As best seen in FIG. 9B, in this embodiment, the amount of offset between the primary cutter elements 40 a-40 h and backup cutter elements 50 a-50 h on each primary blade in combination with the relative sizes of the backup cutting faces 54 a-54 h and primary cutting faces 44 a-44 h results in no overlap between primary cutting faces and backup cutting faces on the same blade (e.g., each backup cutting face on a primary blade is not eclipsed by a primary cutting face on the same blade). For instance, in rotated profile, there is no overlap between primary cutting faces 44 a, 44 c, 44 e, and 44 g on primary blade 31 and backup cutting faces 54 a, 54 c, 54 e, and 54 g on primary blade 31.
  • Still referring to the rotated profile shown in FIG. 9B, the row of primary cutter elements 40 a, 40 c, 40 e, and 40 g disposed on primary blade 31 are staggered relative to the row of primary cutter elements 40 b, 40 d, 40 f, and 40 g disposed on primary blade 32, such that in rotated profile, primary cutting faces 44 a, 44 c, 44 e, and 44 g on primary blade 31 sweep between primary cutter elements 44 b, 44 d, 44 f, and 44 g on primary blade 32. Further, the row of backup cutter elements 50 a, 50 c, 50 e, and 50 g disposed on primary blade 31 are staggered relative to the row of backup cutter elements 50 b, 50 d, 50 f, and 50 h disposed on primary blade 32, such that in rotated profile, backup cutting faces 54 a, 54 c, 54 e, and 54 g disposed on primary blade 31 sweep between backup cutting faces 54 b, 54 d, 54 f, and 54 h disposed on primary blade 32. However, in this embodiment, backup cutting faces 54 a, 54 c, 54 e, and 54 g on primary blade 31 are substantially eclipsed by primary cutter elements 44 b, 44 d, 44 f, and 44 h on primary blade 32. Similarly, backup cutting faces 54 b, 54 d, 54 f, and 54 h on primary blade 32 are substantially eclipsed by primary cutting faces 44 a, 44 c, 44 e, and 44 f on primary blade 31.
  • In addition, as best seen in the rotated profile shown in FIG. 9B, although primary cutting faces 44 a-44 h and backup cutting faces 54 a-54 h are substantially the same size, backup cutting faces 54 a-54 h have greater extension heights than primary cutting faces 44 a-44 h. Thus, backup cutting faces 54 a-54 h will engage a greater depth of formation than primary cutting faces 44 a-44 h.
  • FIG. 10A illustrates another embodiment of primary blades, primary cutter elements, and backup cutter elements within cone region 24 of bit 10. FIG. 10B illustrates the rotated profile view of the primary cutting faces 44 a-44 h and backup cutting faces 54 a-54 h shown in FIG. 10A.
  • The embodiment illustrated in FIGS. 10A and 10B is substantially the same as the embodiment illustrated in FIGS. 8A and 8B. However, in the embodiment shown in FIGS. 10A and 10B, backup cutter elements 50 a-50 h, and associated backup cutting faces 54 a-54 h, are substantially the same size as primary cutter elements 50 a-50 h, and associated primary cutting faces 44 a-44 h. Further, backup cutting faces 54 a-54 h and primary cutting faces 44 a-44 h have substantially the same extension height. Thus, backup cutting faces 54 a-54 h will engage substantially the same depth of formation as primary cutting faces 44 a-44 h.
  • The various embodiments described herein are intended to offer potential improvements over the prior art. Some embodiments of the present invention offer the potential of improving the ROP of bit 10 by reducing the number of relatively larger primary blades while maintaining the number of cutter elements within the cone region. In addition, by reducing the number of relatively large primary blades, embodiments of the present invention may allow for more advantageous positioning of drilling fluid nozzles 22 about bit face 10. Optimal placement of nozzles 22 may enhance the flow of drilling fluid, thereby improving removal of formation cuttings from bit face 20 and from the bottom of the borehole, and improving removal of heat from bit 10. These potential improvements may in turn enhance the ROP and durability of bit 10. In addition, by reducing the number of primary blades and permitting for more location options for nozzles 22, embodiments of the present invention may reduce the complexity of drilling fluid channels within bit 10, potentially reducing the design and manufacturing costs of bit 10.
  • While specific preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teaching herein. The embodiments described herein are exemplary only and are not limiting. For example, embodiments described herein may be applied to any bit layout including without limitation single set bit designs where each cutter element has unique radial position along the rotated cutting profile, plural set bit designs where each cutter element has a redundant cutter element in the same radial position provided on a different blade when viewed in rotated profile, forward spiral bit designs, reverse spiral bit designs, or combinations thereof. In addition, embodiments described herein may also be applied to straight blade configurations or helix blade configurations. Many variations and modifications of the system and apparatus are possible. For instance, in the embodiments described herein, a variety of features including without limitation spacing between cutter elements, cutter element geometry and orientation (e.g., backrake, siderake, etc.), cutter element locations, cutter element extension heights, cutter element material properties, or combinations thereof may be varied among one or more primary cutter elements and/or one or more backup cutter elements. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.

Claims (39)

  1. 1. A drill bit for drilling a borehole in earthen formations, the bit comprising:
    a bit body having a bit face comprising a cone region, a shoulder region, and a gage region;
    at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region;
    a plurality of primary cutter elements mounted on the at least one primary blade in the cone region;
    a plurality of backup cutter elements mounted on the at least one primary blade in the cone region;
    wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density; and
    wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
  2. 2. The drill bit of claim 1, wherein the at least one primary blade extends into the shoulder region, and wherein at least one primary cutter element is mounted on the at least one primary blade in the shoulder region.
  3. 3. The drill bit of claim 1, wherein the at least one primary blade has a gage backup cutter density and wherein the cone backup cutter density of the at least one primary blade is greater than the gage backup cutter density of the at least one primary blade.
  4. 4. The drill bit of claim 1, wherein the shoulder backup cutter density of the at least one primary blade is zero.
  5. 5. The drill bit of claim 3, wherein the gage backup cutter density of the at least one primary blade is zero.
  6. 6. The drill bit of 1 further comprising a central axis and an outer radius, wherein the cone region extends from the central axis to no more than 50% of the outer radius.
  7. 7. The drill bit of claim 6, wherein the cone region extends from the central axis to no more than 30% of the outer radius.
  8. 8. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutting faces are forward facing and the backup cutting faces are forward facing.
  9. 9. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
  10. 10. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
  11. 11. The drill bit of claim 1, wherein the bit comprises no more than two primary blades.
  12. 12. A drill bit for drilling a borehole in earthen formations, the bit comprising:
    a bit body with a central axis and an outer radius;
    a bit face comprising an inner region extending from the central axis to no more than 50% of the outer radius, and an outer region between the inner region and the outer radius;
    at least one primary blade disposed on the bit face, wherein the at least one primary blade extends from proximal the central axis into the outer region;
    a plurality of primary cutter elements mounted on the at least one primary blade;
    a plurality of backup cutter elements mounted on the at least one primary blade;
    wherein the at least one primary blade has an inner backup cutter area and an outer backup cutter area; and
    wherein the inner backup cutter area of the at least one primary blade is greater than the outer backup cutter area of the at least one primary blade.
  13. 13. The drill bit of claim 12, wherein the inner region extends from the central axis to no more than 30% of the outer radius
  14. 14. The drill bit of claim 12, wherein the plurality of primary cutter elements are arranged substantially in a first row along the at least one primary blade and the plurality of backup cutter elements are arranged substantially in a second row along the at least one primary blade.
  15. 15. The drill bit of claim 12, wherein the outer backup cutter area of the at least one primary blade is zero.
  16. 16. The drill bit of claim 12, wherein each primary cutter element includes a primary cutting face and each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
  17. 17. The drill bit of claim 12, wherein each primary cutter element includes a primary cutting face and each backup cuter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
  18. 18. The drill bit of claim 12, wherein the bit comprises no more than three primary blades.
  19. 19. The drill bit of claim 18, wherein the bit comprises no more than two primary blades.
  20. 20. A drill bit for drilling a borehole in earthen formations, the bit comprising:
    a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region;
    at least one primary blade disposed on the bit face, wherein the at least one primary blade begins substantially proximal the central axis and extends towards the gage region;
    at least one secondary blade disposed on the bit face, wherein the at least one secondary blade begins at a radial distance “D” from the central axis and extends toward the gage region, the radial distance “D” being a radius defining the cone region;
    a plurality of primary cutter elements mounted on the at least one primary blade, wherein the primary cutter elements are disposed in a first row extending along the at least one primary blade from substantially proximal the central axis toward the gage region;
    a plurality of backup cutter elements mounted on the at least one primary blade, wherein the backup cutter elements are disposed in a second row extending along the at least one primary blade within the cone region.
  21. 21. The drill bit of claim 20, wherein the bit body further comprises an outer radius, wherein the distance “D” is no more than 50% of the outer radius.
  22. 22. The drill bit of claim 20, wherein the bit body further comprises an outer radius, wherein the distance “D” is no more than 30% of the outer radius.
  23. 23. The drill bit of claim 21, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density.
  24. 24. The drill bit of claim 23, wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
  25. 25. The drill bit of claim 24, wherein the shoulder backup cutter density of the at least one primary blade is zero.
  26. 26. The drill bit of claim 21, wherein the at least one primary blade has a cone backup cutter area and a shoulder backup cutter area.
  27. 27. The drill bit of claim 26, wherein the cone backup cutter area of the at least one primary blade is greater than the shoulder backup cutter area of the at least one primary blade.
  28. 28. The drill bit of claim 27, wherein the shoulder backup cutter area of the at least one primary blade is zero.
  29. 29. A drill bit for drilling a borehole in earthen formations, the bit comprising:
    a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region;
    at least one primary blade disposed on the bit face, wherein the at least one primary blade begins proximal the central axis and extends toward the gage region;
    a plurality of primary cutter elements mounted on the at least one primary blade in the cone region;
    a plurality of backup cutter elements mounted on the at least one primary blade in the cone region; and
    wherein the at least one primary blade is free of backup cutter elements in the shoulder region.
  30. 30. The drill bit of claim 29, wherein the plurality of primary cutter elements are arranged in a first row along the at least one primary blade, and wherein the plurality of backup cutter elements are arranged in a second row along the at least one primary blade substantially parallel to the first row.
  31. 31. The drill bit of claim 29, wherein the at least one primary blade is free of backup cutter elements in the gage region.
  32. 32. The drill bit of claim 29, wherein each primary cutter element has a forward-facing primary cutting face and wherein each backup cutter element has a forward-facing backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
  33. 33. The drill bit of claim 29, wherein each primary cutter element has a forward-facing primary cutting face and wherein each backup cutter element has a forward-facing backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
  34. 34. The drill bit of claim 29, wherein the bit further comprises an outer radius and at least one secondary blade, wherein the at least one secondary blade begins at a distance “D” from the central axis and extends toward the gage region.
  35. 35. The drill bit of claim 36, wherein the distance “D” is no more than 50% of the outer radius.
  36. 36. The drill bit of claim 35, wherein the distance “D” is no more than 30% of the outer radius.
  37. 37. The drill bit of claim 29, wherein the bit comprises no more than three primary blades.
  38. 38. The drill bit of claim 37, wherein the bit consists of two primary blades.
  39. 39. The drill bit of claim 38, wherein the two primary blades are spaced generally opposite each other.
US11382510 2006-05-10 2006-05-10 Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements Abandoned US20070261890A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
US11382510 US20070261890A1 (en) 2006-05-10 2006-05-10 Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US11382510 US20070261890A1 (en) 2006-05-10 2006-05-10 Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements
GB0708446A GB2438053B (en) 2006-05-10 2007-05-01 Drill bit
CA 2587287 CA2587287A1 (en) 2006-05-10 2007-05-03 Fixed cutter bit with centrally positioned backup cutter elements

Publications (1)

Publication Number Publication Date
US20070261890A1 true true US20070261890A1 (en) 2007-11-15

Family

ID=38171031

Family Applications (1)

Application Number Title Priority Date Filing Date
US11382510 Abandoned US20070261890A1 (en) 2006-05-10 2006-05-10 Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements

Country Status (3)

Country Link
US (1) US20070261890A1 (en)
CA (1) CA2587287A1 (en)
GB (1) GB2438053B (en)

Cited By (38)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20080105466A1 (en) * 2006-10-02 2008-05-08 Hoffmaster Carl M Drag Bits with Dropping Tendencies and Methods for Making the Same
US20080302575A1 (en) * 2007-06-11 2008-12-11 Smith International, Inc. Fixed Cutter Bit With Backup Cutter Elements on Primary Blades
US20090145669A1 (en) * 2007-12-07 2009-06-11 Smith International, Inc. Drill Bit Cutting Structure and Methods to Maximize Depth-0f-Cut For Weight on Bit Applied
US20090266619A1 (en) * 2008-04-01 2009-10-29 Smith International, Inc. Fixed Cutter Bit With Backup Cutter Elements on Secondary Blades
US20100025121A1 (en) * 2008-07-30 2010-02-04 Thorsten Schwefe Earth boring drill bits with using opposed kerfing for cutters
US20100089649A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089658A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089661A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089664A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100155151A1 (en) * 2008-12-19 2010-06-24 Varel International Multi-set pdc drill bit and method
US20100218999A1 (en) * 2009-02-27 2010-09-02 Jones Mark L Drill bit for earth boring
US20100252332A1 (en) * 2009-04-02 2010-10-07 Jones Mark L Drill bit for earth boring
WO2010121116A2 (en) * 2009-04-16 2010-10-21 Smith International, Inc. Fixed cutter bit for directional drilling applications
US20100307837A1 (en) * 2009-06-05 2010-12-09 Varel International, Ind., L.P. Casing bit and casing reamer designs
US20100319996A1 (en) * 2009-05-29 2010-12-23 Varel International, Ind., L.P. Milling cap for a polycrystalline diamond compact cutter
US20100319997A1 (en) * 2009-05-29 2010-12-23 Varel International, Ind., L.P. Whipstock attachment to a fixed cutter drilling or milling bit
WO2010151649A2 (en) * 2009-06-25 2010-12-29 Baker Hughes Incorporated Drill bit for use in drilling subterranean formations
US20110005841A1 (en) * 2009-07-07 2011-01-13 Baker Hughes Incorporated Backup cutting elements on non-concentric reaming tools
US20110073369A1 (en) * 2009-09-28 2011-03-31 Baker Hughes Incorporated Earth-boring tools, methods of making earth-boring tools and methods of drilling with earth-boring tools
US20110100714A1 (en) * 2009-10-29 2011-05-05 Moss William A Backup cutting elements on non-concentric earth-boring tools and related methods
US20110108326A1 (en) * 2009-11-09 2011-05-12 Jones Mark L Drill Bit With Recessed Center
US20110155472A1 (en) * 2009-12-28 2011-06-30 Baker Hughes Incorporated Earth-boring tools having differing cutting elements on a blade and related methods
US20110192651A1 (en) * 2010-02-05 2011-08-11 Baker Hughes Incorporated Shaped cutting elements on drill bits and other earth-boring tools, and methods of forming same
US20110253457A1 (en) * 2007-09-06 2011-10-20 Smith International, Inc. Drag bit with utility blades
US8316967B2 (en) * 2007-11-05 2012-11-27 Baker Hughes Incorporated Earth-boring tools with primary and secondary blades, methods of forming and designing such earth-boring tools
CN102959175A (en) * 2010-06-24 2013-03-06 贝克休斯公司 Downhole cutting tool having center beveled mill blade
WO2012148704A3 (en) * 2011-04-27 2013-04-04 Varel International, Ind., L.P. Casing end tool
US8500833B2 (en) 2009-07-27 2013-08-06 Baker Hughes Incorporated Abrasive article and method of forming
US20130292186A1 (en) * 2012-05-03 2013-11-07 Smith International, Inc. Gage cutter protection for drilling bits
US8657036B2 (en) 2009-01-15 2014-02-25 Downhole Products Limited Tubing shoe
US8757299B2 (en) 2009-07-08 2014-06-24 Baker Hughes Incorporated Cutting element and method of forming thereof
US8851207B2 (en) 2011-05-05 2014-10-07 Baker Hughes Incorporated Earth-boring tools and methods of forming such earth-boring tools
US8978788B2 (en) 2009-07-08 2015-03-17 Baker Hughes Incorporated Cutting element for a drill bit used in drilling subterranean formations
US9022149B2 (en) 2010-08-06 2015-05-05 Baker Hughes Incorporated Shaped cutting elements for earth-boring tools, earth-boring tools including such cutting elements, and related methods
US9133667B2 (en) 2011-04-25 2015-09-15 Atlas Copco Secoroc Llc Drill bit for boring earth and other hard materials
US9316058B2 (en) 2012-02-08 2016-04-19 Baker Hughes Incorporated Drill bits and earth-boring tools including shaped cutting elements
US9556683B2 (en) 2012-12-03 2017-01-31 Ulterra Drilling Technologies, L.P. Earth boring tool with improved arrangement of cutter side rakes
US9828810B2 (en) 2014-02-07 2017-11-28 Varel International Ind., L.P. Mill-drill cutter and drill bit

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7896106B2 (en) 2006-12-07 2011-03-01 Baker Hughes Incorporated Rotary drag bits having a pilot cutter configuraton and method to pre-fracture subterranean formations therewith
EP2118430A2 (en) 2007-01-25 2009-11-18 Baker Hughes Incorporated Rotary drag bit
US8047307B2 (en) * 2008-12-19 2011-11-01 Baker Hughes Incorporated Hybrid drill bit with secondary backup cutters positioned with high side rake angles

Citations (58)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3158216A (en) * 1961-04-27 1964-11-24 Inst Francais Du Petrole High speed drill bit
US3344870A (en) * 1965-03-19 1967-10-03 Hughes Tool Co Reamer for jet piercer
US4140189A (en) * 1977-06-06 1979-02-20 Smith International, Inc. Rock bit with diamond reamer to maintain gage
US4167980A (en) * 1978-04-12 1979-09-18 Dresser Industries, Inc. Rock boring cutter with replaceable cutting element
US4351401A (en) * 1978-06-08 1982-09-28 Christensen, Inc. Earth-boring drill bits
US4444281A (en) * 1983-03-30 1984-04-24 Reed Rock Bit Company Combination drag and roller cutter drill bit
US4471845A (en) * 1981-04-01 1984-09-18 Christensen, Inc. Rotary drill bit
US4591008A (en) * 1984-08-22 1986-05-27 Smith International, Inc. Lube reservoir protection for rock bits
US4602691A (en) * 1984-06-07 1986-07-29 Hughes Tool Company Diamond drill bit with varied cutting elements
US4936398A (en) * 1989-07-07 1990-06-26 Cledisc International B.V. Rotary drilling device
US4991670A (en) * 1984-07-19 1991-02-12 Reed Tool Company, Ltd. Rotary drill bit for use in drilling holes in subsurface earth formations
US5064007A (en) * 1988-11-23 1991-11-12 Norvic S.A. Three disc drill bit
US5074367A (en) * 1990-05-11 1991-12-24 Rock Bit Industries, Inc. Rock bit with improved shank protection
US5145017A (en) * 1991-01-07 1992-09-08 Exxon Production Research Company Kerf-cutting apparatus for increased drilling rates
US5145016A (en) * 1990-04-30 1992-09-08 Rock Bit International, Inc. Rock bit with reaming rows
US5186268A (en) * 1991-10-31 1993-02-16 Camco Drilling Group Ltd. Rotary drill bits
US5238075A (en) * 1992-06-19 1993-08-24 Dresser Industries, Inc. Drill bit with improved cutter sizing pattern
US5244039A (en) * 1991-10-31 1993-09-14 Camco Drilling Group Ltd. Rotary drill bits
US5289889A (en) * 1993-01-21 1994-03-01 Marvin Gearhart Roller cone core bit with spiral stabilizers
US5407024A (en) * 1992-06-24 1995-04-18 Borg-Warner Automotive, Inc. On demand vehicle drive system
US5494123A (en) * 1994-10-04 1996-02-27 Smith International, Inc. Drill bit with protruding insert stabilizers
US5531281A (en) * 1993-07-16 1996-07-02 Camco Drilling Group Ltd. Rotary drilling tools
US5549171A (en) * 1994-08-10 1996-08-27 Smith International, Inc. Drill bit with performance-improving cutting structure
US5551522A (en) * 1994-10-12 1996-09-03 Smith International, Inc. Drill bit having stability enhancing cutting structure
US5553681A (en) * 1994-12-07 1996-09-10 Dresser Industries, Inc. Rotary cone drill bit with angled ramps
US5582261A (en) * 1994-08-10 1996-12-10 Smith International, Inc. Drill bit having enhanced cutting structure and stabilizing features
US5592996A (en) * 1994-10-03 1997-01-14 Smith International, Inc. Drill bit having improved cutting structure with varying diamond density
US5607025A (en) * 1995-06-05 1997-03-04 Smith International, Inc. Drill bit and cutting structure having enhanced placement and sizing of cutters for improved bit stabilization
US5607024A (en) * 1995-03-07 1997-03-04 Smith International, Inc. Stability enhanced drill bit and cutting structure having zones of varying wear resistance
US5651421A (en) * 1994-11-01 1997-07-29 Camco Drilling Group Limited Rotary drill bits
US5697462A (en) * 1995-06-30 1997-12-16 Baker Hughes Inc. Earth-boring bit having improved cutting structure
US5709278A (en) * 1996-01-22 1998-01-20 Dresser Industries, Inc. Rotary cone drill bit with contoured inserts and compacts
US5746280A (en) * 1996-06-06 1998-05-05 Baker Hughes Incorporated Earth-boring bit having shear-cutting inner row elements
US5755301A (en) * 1996-08-09 1998-05-26 Dresser Industries, Inc. Inserts and compacts with lead-in surface for enhanced retention
US5816346A (en) * 1996-06-06 1998-10-06 Camco International, Inc. Rotary drill bits and methods of designing such drill bits
US5839526A (en) * 1997-04-04 1998-11-24 Smith International, Inc. Rolling cone steel tooth bit with enhancements in cutter shape and placement
US5862871A (en) * 1996-02-20 1999-01-26 Ccore Technology & Licensing Limited, A Texas Limited Partnership Axial-vortex jet drilling system and method
US5890550A (en) * 1997-05-09 1999-04-06 Baker Hughes Incorporation Earth-boring bit with wear-resistant material
US5996713A (en) * 1995-01-26 1999-12-07 Baker Hughes Incorporated Rolling cutter bit with improved rotational stabilization
US6123160A (en) * 1997-04-02 2000-09-26 Baker Hughes Incorporated Drill bit with gage definition region
US6123161A (en) * 1997-06-14 2000-09-26 Camco International (Uk) Limited Rotary drill bits
US6173797B1 (en) * 1997-09-08 2001-01-16 Baker Hughes Incorporated Rotary drill bits for directional drilling employing movable cutters and tandem gage pad arrangement with active cutting elements and having up-drill capability
US6227314B1 (en) * 1999-04-29 2001-05-08 Baker Hughes, Inc. Inclined leg earth-boring bit
US6283233B1 (en) * 1996-12-16 2001-09-04 Dresser Industries, Inc Drilling and/or coring tool
US20020020565A1 (en) * 2000-08-21 2002-02-21 Hart Steven James Multi-directional cutters for drillout bi-center drill bits
US6408958B1 (en) * 2000-10-23 2002-06-25 Baker Hughes Incorporated Superabrasive cutting assemblies including cutters of varying orientations and drill bits so equipped
US6481511B2 (en) * 2000-09-20 2002-11-19 Camco International (U.K.) Limited Rotary drill bit
US6536543B2 (en) * 2000-12-06 2003-03-25 Baker Hughes Incorporated Rotary drill bits exhibiting sequences of substantially continuously variable cutter backrake angles
US6615934B2 (en) * 2001-08-15 2003-09-09 Smith International, Inc. PDC drill bit having cutting structure adapted to improve high speed drilling performance
US6659199B2 (en) * 2001-08-13 2003-12-09 Baker Hughes Incorporated Bearing elements for drill bits, drill bits so equipped, and method of drilling
US6688410B1 (en) * 2000-06-07 2004-02-10 Smith International, Inc. Hydro-lifter rock bit with PDC inserts
US6883623B2 (en) * 2002-10-09 2005-04-26 Baker Hughes Incorporated Earth boring apparatus and method offering improved gage trimmer protection
US7025156B1 (en) * 1997-11-18 2006-04-11 Douglas Caraway Rotary drill bit for casting milling and formation drilling
US20060260845A1 (en) * 2005-05-17 2006-11-23 Johnson Simon C Stable Rotary Drill Bit
US20070079995A1 (en) * 2004-02-19 2007-04-12 Mcclain Eric E Cutting elements configured for casing component drillout and earth boring drill bits including same
US7278499B2 (en) * 2005-01-26 2007-10-09 Baker Hughes Incorporated Rotary drag bit including a central region having a plurality of cutting structures
US20070240905A1 (en) * 2006-04-18 2007-10-18 Varel International, Ltd. Drill bit with multiple cutter geometries
US20080135297A1 (en) * 2006-12-07 2008-06-12 David Gavia Rotary drag bits having a pilot cutter configuraton and method to pre-fracture subterranean formations therewith

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6394200B1 (en) * 1999-10-28 2002-05-28 Camco International (U.K.) Limited Drillout bi-center bit

Patent Citations (60)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3158216A (en) * 1961-04-27 1964-11-24 Inst Francais Du Petrole High speed drill bit
US3344870A (en) * 1965-03-19 1967-10-03 Hughes Tool Co Reamer for jet piercer
US4140189A (en) * 1977-06-06 1979-02-20 Smith International, Inc. Rock bit with diamond reamer to maintain gage
US4167980A (en) * 1978-04-12 1979-09-18 Dresser Industries, Inc. Rock boring cutter with replaceable cutting element
US4351401A (en) * 1978-06-08 1982-09-28 Christensen, Inc. Earth-boring drill bits
US4471845A (en) * 1981-04-01 1984-09-18 Christensen, Inc. Rotary drill bit
US4444281A (en) * 1983-03-30 1984-04-24 Reed Rock Bit Company Combination drag and roller cutter drill bit
US4602691A (en) * 1984-06-07 1986-07-29 Hughes Tool Company Diamond drill bit with varied cutting elements
US4991670A (en) * 1984-07-19 1991-02-12 Reed Tool Company, Ltd. Rotary drill bit for use in drilling holes in subsurface earth formations
US4591008A (en) * 1984-08-22 1986-05-27 Smith International, Inc. Lube reservoir protection for rock bits
US5064007A (en) * 1988-11-23 1991-11-12 Norvic S.A. Three disc drill bit
US4936398A (en) * 1989-07-07 1990-06-26 Cledisc International B.V. Rotary drilling device
US5145016A (en) * 1990-04-30 1992-09-08 Rock Bit International, Inc. Rock bit with reaming rows
US5145016B1 (en) * 1990-04-30 1996-08-13 Rock Bit International Inc Rock bit with reaming rows
US5074367A (en) * 1990-05-11 1991-12-24 Rock Bit Industries, Inc. Rock bit with improved shank protection
US5145017A (en) * 1991-01-07 1992-09-08 Exxon Production Research Company Kerf-cutting apparatus for increased drilling rates
US5186268A (en) * 1991-10-31 1993-02-16 Camco Drilling Group Ltd. Rotary drill bits
US5244039A (en) * 1991-10-31 1993-09-14 Camco Drilling Group Ltd. Rotary drill bits
US5238075A (en) * 1992-06-19 1993-08-24 Dresser Industries, Inc. Drill bit with improved cutter sizing pattern
US5407024A (en) * 1992-06-24 1995-04-18 Borg-Warner Automotive, Inc. On demand vehicle drive system
US5289889A (en) * 1993-01-21 1994-03-01 Marvin Gearhart Roller cone core bit with spiral stabilizers
US5531281A (en) * 1993-07-16 1996-07-02 Camco Drilling Group Ltd. Rotary drilling tools
US5582261A (en) * 1994-08-10 1996-12-10 Smith International, Inc. Drill bit having enhanced cutting structure and stabilizing features
US5549171A (en) * 1994-08-10 1996-08-27 Smith International, Inc. Drill bit with performance-improving cutting structure
US5592996A (en) * 1994-10-03 1997-01-14 Smith International, Inc. Drill bit having improved cutting structure with varying diamond density
US5494123A (en) * 1994-10-04 1996-02-27 Smith International, Inc. Drill bit with protruding insert stabilizers
US5551522A (en) * 1994-10-12 1996-09-03 Smith International, Inc. Drill bit having stability enhancing cutting structure
US5651421A (en) * 1994-11-01 1997-07-29 Camco Drilling Group Limited Rotary drill bits
US5553681A (en) * 1994-12-07 1996-09-10 Dresser Industries, Inc. Rotary cone drill bit with angled ramps
US5996713A (en) * 1995-01-26 1999-12-07 Baker Hughes Incorporated Rolling cutter bit with improved rotational stabilization
US5607024A (en) * 1995-03-07 1997-03-04 Smith International, Inc. Stability enhanced drill bit and cutting structure having zones of varying wear resistance
US5607025A (en) * 1995-06-05 1997-03-04 Smith International, Inc. Drill bit and cutting structure having enhanced placement and sizing of cutters for improved bit stabilization
US5697462A (en) * 1995-06-30 1997-12-16 Baker Hughes Inc. Earth-boring bit having improved cutting structure
US5709278A (en) * 1996-01-22 1998-01-20 Dresser Industries, Inc. Rotary cone drill bit with contoured inserts and compacts
US5862871A (en) * 1996-02-20 1999-01-26 Ccore Technology & Licensing Limited, A Texas Limited Partnership Axial-vortex jet drilling system and method
US5746280A (en) * 1996-06-06 1998-05-05 Baker Hughes Incorporated Earth-boring bit having shear-cutting inner row elements
US5816346A (en) * 1996-06-06 1998-10-06 Camco International, Inc. Rotary drill bits and methods of designing such drill bits
US5755301A (en) * 1996-08-09 1998-05-26 Dresser Industries, Inc. Inserts and compacts with lead-in surface for enhanced retention
US6283233B1 (en) * 1996-12-16 2001-09-04 Dresser Industries, Inc Drilling and/or coring tool
US6123160A (en) * 1997-04-02 2000-09-26 Baker Hughes Incorporated Drill bit with gage definition region
US5839526A (en) * 1997-04-04 1998-11-24 Smith International, Inc. Rolling cone steel tooth bit with enhancements in cutter shape and placement
US5890550A (en) * 1997-05-09 1999-04-06 Baker Hughes Incorporation Earth-boring bit with wear-resistant material
US6123161A (en) * 1997-06-14 2000-09-26 Camco International (Uk) Limited Rotary drill bits
US6173797B1 (en) * 1997-09-08 2001-01-16 Baker Hughes Incorporated Rotary drill bits for directional drilling employing movable cutters and tandem gage pad arrangement with active cutting elements and having up-drill capability
US7025156B1 (en) * 1997-11-18 2006-04-11 Douglas Caraway Rotary drill bit for casting milling and formation drilling
US6227314B1 (en) * 1999-04-29 2001-05-08 Baker Hughes, Inc. Inclined leg earth-boring bit
US6688410B1 (en) * 2000-06-07 2004-02-10 Smith International, Inc. Hydro-lifter rock bit with PDC inserts
US20020020565A1 (en) * 2000-08-21 2002-02-21 Hart Steven James Multi-directional cutters for drillout bi-center drill bits
US6481511B2 (en) * 2000-09-20 2002-11-19 Camco International (U.K.) Limited Rotary drill bit
US6408958B1 (en) * 2000-10-23 2002-06-25 Baker Hughes Incorporated Superabrasive cutting assemblies including cutters of varying orientations and drill bits so equipped
US6536543B2 (en) * 2000-12-06 2003-03-25 Baker Hughes Incorporated Rotary drill bits exhibiting sequences of substantially continuously variable cutter backrake angles
US6711969B2 (en) * 2000-12-06 2004-03-30 Baker Hughes Incorporated Methods for designing rotary drill bits exhibiting sequences of substantially continuously variable cutter backrake angles
US6659199B2 (en) * 2001-08-13 2003-12-09 Baker Hughes Incorporated Bearing elements for drill bits, drill bits so equipped, and method of drilling
US6615934B2 (en) * 2001-08-15 2003-09-09 Smith International, Inc. PDC drill bit having cutting structure adapted to improve high speed drilling performance
US6883623B2 (en) * 2002-10-09 2005-04-26 Baker Hughes Incorporated Earth boring apparatus and method offering improved gage trimmer protection
US20070079995A1 (en) * 2004-02-19 2007-04-12 Mcclain Eric E Cutting elements configured for casing component drillout and earth boring drill bits including same
US7278499B2 (en) * 2005-01-26 2007-10-09 Baker Hughes Incorporated Rotary drag bit including a central region having a plurality of cutting structures
US20060260845A1 (en) * 2005-05-17 2006-11-23 Johnson Simon C Stable Rotary Drill Bit
US20070240905A1 (en) * 2006-04-18 2007-10-18 Varel International, Ltd. Drill bit with multiple cutter geometries
US20080135297A1 (en) * 2006-12-07 2008-06-12 David Gavia Rotary drag bits having a pilot cutter configuraton and method to pre-fracture subterranean formations therewith

Cited By (82)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20080105466A1 (en) * 2006-10-02 2008-05-08 Hoffmaster Carl M Drag Bits with Dropping Tendencies and Methods for Making the Same
US7621348B2 (en) * 2006-10-02 2009-11-24 Smith International, Inc. Drag bits with dropping tendencies and methods for making the same
US20080302575A1 (en) * 2007-06-11 2008-12-11 Smith International, Inc. Fixed Cutter Bit With Backup Cutter Elements on Primary Blades
US7703557B2 (en) * 2007-06-11 2010-04-27 Smith International, Inc. Fixed cutter bit with backup cutter elements on primary blades
US8869919B2 (en) * 2007-09-06 2014-10-28 Smith International, Inc. Drag bit with utility blades
US20110253457A1 (en) * 2007-09-06 2011-10-20 Smith International, Inc. Drag bit with utility blades
US8316967B2 (en) * 2007-11-05 2012-11-27 Baker Hughes Incorporated Earth-boring tools with primary and secondary blades, methods of forming and designing such earth-boring tools
US9016407B2 (en) * 2007-12-07 2015-04-28 Smith International, Inc. Drill bit cutting structure and methods to maximize depth-of-cut for weight on bit applied
US20090145669A1 (en) * 2007-12-07 2009-06-11 Smith International, Inc. Drill Bit Cutting Structure and Methods to Maximize Depth-0f-Cut For Weight on Bit Applied
US20090266619A1 (en) * 2008-04-01 2009-10-29 Smith International, Inc. Fixed Cutter Bit With Backup Cutter Elements on Secondary Blades
WO2009146078A1 (en) * 2008-04-01 2009-12-03 Smith International, Inc. Fixed cutter bit with backup cutter elements on secondary blades
US8100202B2 (en) * 2008-04-01 2012-01-24 Smith International, Inc. Fixed cutter bit with backup cutter elements on secondary blades
US20100025121A1 (en) * 2008-07-30 2010-02-04 Thorsten Schwefe Earth boring drill bits with using opposed kerfing for cutters
US8020641B2 (en) 2008-10-13 2011-09-20 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
WO2010045170A1 (en) 2008-10-13 2010-04-22 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20140223833A1 (en) * 2008-10-13 2014-08-14 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US8720609B2 (en) 2008-10-13 2014-05-13 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
WO2010045164A2 (en) 2008-10-13 2010-04-22 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089661A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US9540884B2 (en) * 2008-10-13 2017-01-10 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089658A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089649A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
US20100089664A1 (en) * 2008-10-13 2010-04-15 Baker Hughes Incorporated Drill bit with continuously sharp edge cutting elements
GB2475202B (en) * 2008-12-19 2013-02-13 Varel International Inc Multi-set pdc drill bit and method
WO2010080535A1 (en) * 2008-12-19 2010-07-15 Varel International, Ind., L.P. Multi-set pdc drill bit and method
US20100155151A1 (en) * 2008-12-19 2010-06-24 Varel International Multi-set pdc drill bit and method
GB2475202A (en) * 2008-12-19 2011-05-11 Varel International Inc Multi-set pdc drill bit and method
US8327956B2 (en) 2008-12-19 2012-12-11 Varel International, Ind., L.P. Multi-set PDC drill bit and method
US8657036B2 (en) 2009-01-15 2014-02-25 Downhole Products Limited Tubing shoe
US8336649B2 (en) 2009-02-27 2012-12-25 Atlas Copco Secoroc Llc Drill bit for earth boring
US20100218999A1 (en) * 2009-02-27 2010-09-02 Jones Mark L Drill bit for earth boring
US20100252332A1 (en) * 2009-04-02 2010-10-07 Jones Mark L Drill bit for earth boring
US8439136B2 (en) 2009-04-02 2013-05-14 Atlas Copco Secoroc Llc Drill bit for earth boring
WO2010121116A3 (en) * 2009-04-16 2011-03-31 Smith International, Inc. Fixed cutter bit for directional drilling applications
US8418785B2 (en) 2009-04-16 2013-04-16 Smith International, Inc. Fixed cutter bit for directional drilling applications
GB2481351A (en) * 2009-04-16 2011-12-21 Smith International Fixed cutter bit directional drilling applications
GB2481351B (en) * 2009-04-16 2014-01-01 Smith International Fixed cutter bit directional drilling applications
WO2010121116A2 (en) * 2009-04-16 2010-10-21 Smith International, Inc. Fixed cutter bit for directional drilling applications
US20110100724A1 (en) * 2009-04-16 2011-05-05 Smith International, Inc. Fixed Cutter Bit for Directional Drilling Applications
US20100319997A1 (en) * 2009-05-29 2010-12-23 Varel International, Ind., L.P. Whipstock attachment to a fixed cutter drilling or milling bit
US20100319996A1 (en) * 2009-05-29 2010-12-23 Varel International, Ind., L.P. Milling cap for a polycrystalline diamond compact cutter
US8327944B2 (en) 2009-05-29 2012-12-11 Varel International, Ind., L.P. Whipstock attachment to a fixed cutter drilling or milling bit
US8517123B2 (en) 2009-05-29 2013-08-27 Varel International, Ind., L.P. Milling cap for a polycrystalline diamond compact cutter
US20100307837A1 (en) * 2009-06-05 2010-12-09 Varel International, Ind., L.P. Casing bit and casing reamer designs
US8561729B2 (en) 2009-06-05 2013-10-22 Varel International, Ind., L.P. Casing bit and casing reamer designs
WO2010141781A1 (en) * 2009-06-05 2010-12-09 Varel International, Ind., L.P. Casing bit and casing reamer designs
CN102414393A (en) * 2009-06-05 2012-04-11 维拉国际工业有限公司 Casing bit and casing reamer designs
WO2010151649A3 (en) * 2009-06-25 2011-03-31 Baker Hughes Incorporated Drill bit for use in drilling subterranean formations
US8887839B2 (en) 2009-06-25 2014-11-18 Baker Hughes Incorporated Drill bit for use in drilling subterranean formations
WO2010151649A2 (en) * 2009-06-25 2010-12-29 Baker Hughes Incorporated Drill bit for use in drilling subterranean formations
US20110005841A1 (en) * 2009-07-07 2011-01-13 Baker Hughes Incorporated Backup cutting elements on non-concentric reaming tools
US9816324B2 (en) 2009-07-08 2017-11-14 Baker Hughes Cutting element incorporating a cutting body and sleeve and method of forming thereof
US8978788B2 (en) 2009-07-08 2015-03-17 Baker Hughes Incorporated Cutting element for a drill bit used in drilling subterranean formations
US9957757B2 (en) 2009-07-08 2018-05-01 Baker Hughes Incorporated Cutting elements for drill bits for drilling subterranean formations and methods of forming such cutting elements
US8757299B2 (en) 2009-07-08 2014-06-24 Baker Hughes Incorporated Cutting element and method of forming thereof
US9174325B2 (en) 2009-07-27 2015-11-03 Baker Hughes Incorporated Methods of forming abrasive articles
US10012030B2 (en) 2009-07-27 2018-07-03 Baker Hughes, A Ge Company, Llc Abrasive articles and earth-boring tools
US8500833B2 (en) 2009-07-27 2013-08-06 Baker Hughes Incorporated Abrasive article and method of forming
US9744646B2 (en) 2009-07-27 2017-08-29 Baker Hughes Incorporated Methods of forming abrasive articles
US20110073369A1 (en) * 2009-09-28 2011-03-31 Baker Hughes Incorporated Earth-boring tools, methods of making earth-boring tools and methods of drilling with earth-boring tools
US8127869B2 (en) 2009-09-28 2012-03-06 Baker Hughes Incorporated Earth-boring tools, methods of making earth-boring tools and methods of drilling with earth-boring tools
US20110100714A1 (en) * 2009-10-29 2011-05-05 Moss William A Backup cutting elements on non-concentric earth-boring tools and related methods
US20110108326A1 (en) * 2009-11-09 2011-05-12 Jones Mark L Drill Bit With Recessed Center
US8839886B2 (en) 2009-11-09 2014-09-23 Atlas Copco Secoroc Llc Drill bit with recessed center
US8505634B2 (en) 2009-12-28 2013-08-13 Baker Hughes Incorporated Earth-boring tools having differing cutting elements on a blade and related methods
US20110155472A1 (en) * 2009-12-28 2011-06-30 Baker Hughes Incorporated Earth-boring tools having differing cutting elements on a blade and related methods
US20110192651A1 (en) * 2010-02-05 2011-08-11 Baker Hughes Incorporated Shaped cutting elements on drill bits and other earth-boring tools, and methods of forming same
US8794356B2 (en) 2010-02-05 2014-08-05 Baker Hughes Incorporated Shaped cutting elements on drill bits and other earth-boring tools, and methods of forming same
US9200483B2 (en) 2010-06-03 2015-12-01 Baker Hughes Incorporated Earth-boring tools and methods of forming such earth-boring tools
CN102959175A (en) * 2010-06-24 2013-03-06 贝克休斯公司 Downhole cutting tool having center beveled mill blade
US9022149B2 (en) 2010-08-06 2015-05-05 Baker Hughes Incorporated Shaped cutting elements for earth-boring tools, earth-boring tools including such cutting elements, and related methods
US9458674B2 (en) 2010-08-06 2016-10-04 Baker Hughes Incorporated Earth-boring tools including shaped cutting elements, and related methods
US9133667B2 (en) 2011-04-25 2015-09-15 Atlas Copco Secoroc Llc Drill bit for boring earth and other hard materials
WO2012148704A3 (en) * 2011-04-27 2013-04-04 Varel International, Ind., L.P. Casing end tool
CN103492662A (en) * 2011-04-27 2014-01-01 维拉国际工业有限公司 Casing end tool
US8851207B2 (en) 2011-05-05 2014-10-07 Baker Hughes Incorporated Earth-boring tools and methods of forming such earth-boring tools
US10017998B2 (en) 2012-02-08 2018-07-10 Baker Hughes Incorporated Drill bits and earth-boring tools including shaped cutting elements and associated methods
US9316058B2 (en) 2012-02-08 2016-04-19 Baker Hughes Incorporated Drill bits and earth-boring tools including shaped cutting elements
US9464490B2 (en) * 2012-05-03 2016-10-11 Smith International, Inc. Gage cutter protection for drilling bits
US20130292186A1 (en) * 2012-05-03 2013-11-07 Smith International, Inc. Gage cutter protection for drilling bits
US9556683B2 (en) 2012-12-03 2017-01-31 Ulterra Drilling Technologies, L.P. Earth boring tool with improved arrangement of cutter side rakes
US9828810B2 (en) 2014-02-07 2017-11-28 Varel International Ind., L.P. Mill-drill cutter and drill bit

Also Published As

Publication number Publication date Type
GB2438053A (en) 2007-11-14 application
CA2587287A1 (en) 2007-11-10 application
GB2438053B (en) 2009-05-06 grant
GB0708446D0 (en) 2007-06-06 grant

Similar Documents

Publication Publication Date Title
US5732784A (en) Cutting means for drag drill bits
US6695080B2 (en) Reaming apparatus and method with enhanced structural protection
US6988569B2 (en) Cutting element orientation or geometry for improved drill bits
US6345673B1 (en) High offset bits with super-abrasive cutters
US6659207B2 (en) Bi-centered drill bit having enhanced casing drill-out capability and improved directional stability
US5279375A (en) Multidirectional drill bit cutter
US4552232A (en) Drill-bit with full offset cutter bodies
US6883624B2 (en) Multi-lobed cutter element for drill bit
US20110192651A1 (en) Shaped cutting elements on drill bits and other earth-boring tools, and methods of forming same
US20070205023A1 (en) Fixed cutter drill bit for abrasive applications
US6173797B1 (en) Rotary drill bits for directional drilling employing movable cutters and tandem gage pad arrangement with active cutting elements and having up-drill capability
US20080179108A1 (en) Rotary drag bit and methods therefor
US5722497A (en) Roller cone gage surface cutting elements with multiple ultra hard cutting surfaces
US6308790B1 (en) Drag bits with predictable inclination tendencies and behavior
US6062325A (en) Rotary drill bits
US7819208B2 (en) Dynamically stable hybrid drill bit
US5033560A (en) Drill bit with decreasing diameter cutters
US20080264695A1 (en) Hybrid Drill Bit and Method of Drilling
US5607024A (en) Stability enhanced drill bit and cutting structure having zones of varying wear resistance
US6575256B1 (en) Drill bit with lateral movement mitigation and method of subterranean drilling
US6564886B1 (en) Drill bit with rows of cutters mounted to present a serrated cutting edge
US7117960B2 (en) Bits for use in drilling with casting and method of making the same
US6843333B2 (en) Impregnated rotary drag bit
US5549171A (en) Drill bit with performance-improving cutting structure
US20030029644A1 (en) Advanced expandable reaming tool

Legal Events

Date Code Title Description
AS Assignment

Owner name: SMITH INTERNATIONAL, INC., TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:CISNEROS, DENNIS;REEL/FRAME:017913/0515

Effective date: 20060628