US20090084607A1 - Drill bits and tools for subterranean drilling - Google Patents

Drill bits and tools for subterranean drilling Download PDF

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Publication number
US20090084607A1
US20090084607A1 US11865258 US86525807A US2009084607A1 US 20090084607 A1 US20090084607 A1 US 20090084607A1 US 11865258 US11865258 US 11865258 US 86525807 A US86525807 A US 86525807A US 2009084607 A1 US2009084607 A1 US 2009084607A1
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Prior art keywords
blade
extension pad
drill bit
bit
pad
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Abandoned
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US11865258
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Stephen J. Ernst
Juan Miguel Bilen
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Baker Hughes Inc
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Baker Hughes Inc
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/42Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits

Abstract

A drill bit includes at least one extension pad extending rotationally forward or backward of an associated blade in a gage region of the bit body. The extension pad includes a circumferential bearing surface that extends the circumferential bearing surface of the associated blade and reduces the chordal drop between any blade having an extension pad associated therewith and a circumferentially adjacent blade toward which the extension pad protrudes. A drill bit that reduces a chordal drop segment extending across a junk slot is also disclosed.

Description

    FIELD OF INVENTION
  • The invention, in various embodiments, relates to drill bits and tools for subterranean drilling and, more particularly, to a drill bit or tool incorporating structure for enhancing stabilization and reducing lateral motion.
  • BACKGROUND
  • Fixed cutter rotary drill bits for subterranean earth boring have been employed for decades. It is well known that increasing the rotational speed of such drill bit, for a given weight on bit and subject to the ability of the bit's hydraulic structure to adequately clear formation cuttings from the bit, increases the rate of penetration of the drill string. However, increased rotational speed also tends to decrease the life of a drill bit due to premature damage to and destruction of cutting elements, commonly polycrystalline diamond compacts (PDC's).
  • It has been recognized that cutting element destruction, particularly at higher rotational speeds, is at least in part attributable to a phenomenon known as “whirl” or “bit whirl.” Radially directed centrifugal imbalance forces exist to some extent in every rotating drill bit and drill string. Such forces are in part attributable to mass imbalance within the drill bit and in part to dynamic forces generated by contact of the drill bit with the formation. In the latter instance, aggressive cutter placement and orientation creates a high tangential cutting force relative to the normal force applied to the bit and aggravates the imbalance. In any event, these imbalance forces tend to cause the drill bit to rotate or roll about the bore hole in a direction counter to the normal direction of rotation imparted to the bit during drilling. This counter-rotation is termed “whirl,” and is a self-propagating phenomenon, as the side forces on the bit cause its center of rotation to shift to one side, after which there is an immediate tendency to shift again. Since cutting elements are designed to cut and to resist impact received in the normal direction of bit rotation (clockwise, looking down a drill string), contact of the cutting elements with the bore hole wall in a counter-clockwise direction due to whirl places stresses on the cutting elements beyond their designed limits.
  • One solution to the problems caused by bit whirl has been to focus or direct the imbalance forces as a resultant side force vector to a particular side of the bit via changes in cutting element placement and orientation and bit mass location, and to cause the bit to ride on a low-friction bearing zone or pad on the gage of that side of the bit, thus substantially reducing the drill bit/bore hole wall tangential forces which induce whirl. This solution is disclosed in U.S. Pat. Nos. 4,982,802; 4,932,484; 5,010,789 and 5,042,596, all assigned on their faces to Amoco Corporation of Chicago, Ill.
  • The above-referenced patents conventionally require that the low friction bearing zone or pad on the gage and adjacent bit profile or flank be devoid of cutting elements and, indeed, many alternative bearing zone configurations are disclosed, including wear coatings, diamond stud inserts, diamond pads, rollers, caged ball bearings, etc. It has also been suggested by others that the bearing zone on the bit gage may include cutting elements of different sizes, configurations, depths of cut and/or rake angles than the cutting elements located in the cutting zone of the bit, which extends over the bit face from the cutting elements thereof outwardly to the gage, except in the flank area of the face adjacent the bearing zone. However, it is represented in the prior art that such bearing zone cutting elements should undesirably generate lesser cutting forces than the cutting elements in the cutting zone of the bit so that the bearing zone will have a relatively lower coefficient of friction. See U.S. Pat. No. 4,982,802, Col. 5, lines 29-36; U.S. Pat. No. 5,042,596, Col. 4, lines 18-25. Furthermore, while the prior art provides for focusing or directing the imbalance forces as a resultant side force vector toward a particular side of the bit, it does so by compromising aggressiveness of the bit, particularly affecting the placement and aggressiveness of cutting elements. Moreover, while the above-referenced patents reduce hole wall tangential forces which are generally noted to induce whirl, they do not protect the cutting elements from chipping as a result of the impact loads caused by vibrational instabilities commensurate with bit whirl, particularly when drilling in harder subterranean formations.
  • In order to mitigate the damage upon the cutting elements caused by side impact forces, conventional wisdom has been to direct the imbalance force, i.e., the resultant side force vector, of the bit toward the center and trailing bearing surface of a bit blade or toward the gage region of a particular blade, which undesirably limits design placement of the imbalance force upon the bit. Damage to the cutting elements may also be mitigated by increasing the circumferential width of the of the bearing surface, which undesirably reduces the hydraulic cross-section available for the junks slot, thus reducing hydraulic flow of drilling fluid and potentially decreasing the volume of cuttings which may be carried therethrough by the drilling fluid. In order to improve the stability of the bit while militating against damage, conventional wisdom also includes extending the bearing surface across the width of one or more channels between blades. Such bits are known as so called “steering wheel” bits and generally include fins or cylindrical portions that extend the bearing surface circumferentially about the gage region of the bit as shown and described in U.S. Pat. Nos. 5,671,818, 5,904,213 and 5,967,246. While these so called “steering wheel” bits may increase stability by militating against vibrational instabilities and enhance the ability of such bits to hold bore hole gage diameter, such bits undesirably increase the outer perimeter surface of the bit bearing on the bore hole side wall, making directional drilling more difficult. Furthermore, the configuration of such so called “steering wheel” bits also undesirably reduces the available hydraulic cross-section of the junk slots and may restrict formation cuttings removal from the bit face by substantially circumscribing the flow channels provided by the junk slots. In additional the configuration of the steering wheel bits impedes tripping the bit in and out of the bore hole, and may cause swabbing (removal of formation material from the bore hole side wall) during tripping.
  • Accordingly, it is desirable to provide improvements for a drill bit to enhance stability by reducing lateral motion affected by bit whirl while maintaining or even improving ability to trip in and out of the bore hole.
  • BRIEF SUMMARY OF THE INVENTION
  • In one embodiment, a drill bit includes at least one extension pad for increasing stability and reducing lateral motion acting on the drill bit while drilling a subterranean formation. The drill bit includes a bit body having a face extending to a gage region, at least one blade extending longitudinally and radially outward over the face of the bit body from a longitudinal axis thereof, the at least one blade including an extension pad substantially contiguous with the blade in the gage region of the bit body. The extension pad includes a circumferential bearing surface that rotationally precedes or trails the blade, with respect to the direction of intended bit rotation about the longitudinal axis. The blade may also include a circumferential bearing surface as extended by the extension pad.
  • In other embodiments, a drill bit comprises at least one extension pad extending into an open fluid course circumferentially between two blades, the fluid course communicating with a junk slot of the drill bit. The extension pad is configured and positioned to reduce a chordal drop segment and to improve stability of the drill bit by reducing the extent to which lateral motion may occur while drilling a subterranean formation.
  • Further embodiments comprise a drill bit having at least one extension pad con figured and positioned to reduce a chordal drop segment extending across a junk slot.
  • Other embodiments comprise a drill bit having at least one blade and an extension pad extending therefrom rotationally preceding cutting elements carried on a rotationally leading edge of the at least one blade.
  • Other advantages and features of the invention will become apparent when viewed in light of the detailed description of the various embodiments of the invention when taken in conjunction with the attached drawings and appended claims.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • FIG. 1 shows a perspective, inverted view of a drill bit configured with extension pads according to an embodiment of the invention;
  • FIG. 2 shows a partial, enlarged face view of the drill bit including one of the extension pads of the drill bit shown in FIG. 1;
  • FIG. 3 shows a face view of a drill bit configured with extension pads in accordance with another embodiment of the invention; and
  • FIGS. 4A-4D show schematic side views of extension pads having one of several configurations suitable for use with a drill bit in accordance with embodiments of the invention.
  • DETAILED DESCRIPTION OF THE INVENTION
  • In the description which follows, like elements and features among the various drawing figures are identified for convenience with the same or similar reference numerals.
  • FIG. 1 shows a perspective, inverted (with respect to the usual orientation thereof during drilling) view of a drill bit 10 configured with extension pads 30, according to an embodiment of the invention. The drill bit 10 is configured as a fixed cutter rotary full bore drill bit, also known in the art as a “drag” bit. The drill bit 10 includes a bit crown or body 11 comprising, for example, tungsten carbide infiltrated with a metal alloy binder, a machined steel casting or forging, or a sintered tungsten or other suitable carbide, nitride or boride as discussed in further detail below, and coupled to a support 19. The support 19 includes a shank 13 and a crossover component (not shown) coupled to the shank 13 in this embodiment of the invention. It is recognized that the support 19 may be made from a unitary material piece or multiple pieces of material in a configuration differing from the shank 13 being coupled to the crossover by weld joints as described with respect to this particular embodiment. The shank 13 of the drill bit 10 includes conventional male threads 12 configured to API standards and adapted for connection to a component of a drill string, not shown. Blades 24 that radially and longitudinally extend from the face 14 of the bit body 11 outwardly to a full gage diameter 31 each have mounted thereon a plurality of cutting elements, generally designated by reference numeral 16. Each cutting element 16 comprises a polycrystalline diamond compact (PDC) table 18 formed on a cemented tungsten carbide substrate 20. The cutting elements 16, conventionally secured in respective cutter pockets 21 by brazing, for example, are positioned to cut a subterranean formation being drilled when the drill bit 10 is rotated in a clock-wise direction looking down the drill string under weight on bit (WOB) in a bore hole. In order to enhance stability of the bit 10 while protecting the cutting elements 16 from the undesirable impact stresses caused particularly by bit whirl, an extension pad 30 rotationally precedes at least one blade 24 substantially in the gage region 23 of body 11 to circumferentially extend bearing surface 32 of the gage pad 22. Stated another way, each extension pad 30 may be said, in some embodiments, to rotationally precede cutting elements 16 carried on its associated blade 24 proximate a rotationally leading edge thereof. The extension pad 30, when present, decreases the chordal drop segment 36 between circumferentially adjacent blades 24. “Chordal drop segment” 36, or “chordal drop.” as such terms are used herein, is the circumferential distance, at full bore diameter 31, i.e., in the gage region 23, between a leading edge, or face 25 of the gage pad 22 of one blade 24 and a trailing edge or face 35 of the gage pad 22 of another, rotationally preceding blade 24. In this respect, the chordal drop segment is the circumferential segment extending across a junk slot at the full gage diameter. The reduction in chordal drop segment 36 achieved by extending the bearing surface 32 of the gage pad 22 with extension pad 30, improves stability of the drill bit 10 by reducing the propensity for lateral movement of the bit 10 while drilling and, in turn, any propensity of the bit 10 to whirl. Each extension pad 30 may be configured according to an embodiment of the invention, as hereinafter described.
  • In some embodiments, the bit 10 may have an extension pad rotationally trailing the blade 24 substantially in the gage region 23 of the body 11 of the bit 10. In other embodiments, the bit 10 may have extension pads; one extension pad rotationally trailing an associated blade 24 and the other extension pad 30 rotationally preceding an associated blade 24. In still some embodiments, the bit 10 may have extension pads rotationally preceding, and/or trailing, less than all of the blades. In still other embodiments, the bit 10 may have only one extension pad 30 rotationally preceding or trailing a single blade 24 of the bit 10. Extension pads in accordance with several embodiments of the invention are described in further detail below.
  • The bit body 11 may also carry, on gage pads 22, gage trimmers (not shown) including the aforementioned PDC tables 18 which may be configured with a flat cutting edge aligned parallel to the longitudinal axis 27 of the drill bit 10 to trim the side wall of the bore hole (not shown) and hold the gage diameter 31 thereof, and gage pads 22 comprising bearing surfaces 32 in the gage region 23 for contacting or riding upon the walls of the bore hole to maintain the hole diameter and help stabilize the drill bit 10 while drilling through a subterranean formation. Optionally, the gage pads 22, at least one of which has an extension pad 30 associated therewith, may include a bearing zone or pad (not shown) configured with wear-resistant coatings, tungsten carbide inserts in the form of bricks or discs, diamond stud inserts, diamond-faced pads, rollers, caged ball bearings, for example.
  • During drilling, drilling fluid is discharged through nozzles 26 located in ports 28 in fluid communication with the face 14 of bit body 11 for cooling the PDC tables 18 of cutting elements 16 and removing formation cuttings from the face 14 of drill bit 10 as the fluid moves into passages 15 and through junk slots 17. The nozzles 26 may be sized for different fluid flow rates depending upon the desired flushing required in association with each group of cutting elements 16 to which a particular nozzle assembly directs drilling fluid.
  • The extension pads 30 may be formed from the material of the bit body 11 and manufactured in conjunction with the blades 24 that extend from the face 14 of the bit body 11. The material of the bit body 11, blades 24 and extension pads 30 of the drill bit 10 may be formed, for example, from a cemented carbide that is coupled to the body blank by welding, for example, after a forming and sintering process and is termed a “cemented” bit. The cemented carbide in this embodiment of the invention comprises tungsten carbide particles in a cobalt-based alloy matrix made by pressing a powdered tungsten carbide material, a powdered cobalt alloy material and admixtures that may comprise a lubricant and adhesive, into what is conventionally known as a green body. A green body is relatively fragile, having enough strength to be handled for subsequent furnacing or sintering, but not strong enough to handle impact or other stresses required to prepare the green body into a finished product. In order to make the green body strong enough for particular processes, the green body is then sintered into the brown state, as known in the art of particulate or powder metallurgy, to obtain a brown body suitable for machining, for example. In the brown state, the brown body is not yet fully hardened or densified, but exhibits compressive strength suitable for more rigorous manufacturing processes, such as machining, while exhibiting a relatively soft material state to advantageously obtain features in the body that are not practicably obtained during forming or are more difficult and costly to obtain after the body is fully densified. While in the brown state for example, the cutter pockets 21 or nozzle ports 28 may also be formed in the brown body by machining or other forming methods. Thereafter, the brown body is sintered to obtain a fully dense cemented bit.
  • As an alternative to tungsten carbide, one or more of boron carbide, boron nitride, aluminum nitride, tungsten boride and carbides or borides of Ti, Mo, Nb, V, Hf, Zr, TA, Si and Cr may be employed. As an alternative to a cobalt-based alloy matrix material, or one or more of iron-based alloys, nickel-based alloys, cobalt- and nickel-based alloys, aluminum-based alloys, copper-based alloys, magnesium-based alloys, and titanium-based alloys may be employed.
  • In order to maintain particular sizing of machined features, such as cutter pockets 21 or nozzle ports 28, displacements as know to those of ordinary skill in the art may be utilized to maintain nominal dimensional tolerance of the machined features, e.g., maintaining the shape and dimensions of a cutter pocket 21 or nozzle port 28 as described below. The displacements help to control the shrinkage, warpage or distortion that may be caused during final sintering process required to bring the brown body to full density and strength. While the displacements help to prevent unwanted nominal change in associated dimensions of the brown body during final sintering, invariably, critical component features, such as threads, may require reworking prior to their intended use, as the displacement may not adequately prevent against shrinkage, warpage or distortion.
  • While extension pads 30 are formed in the cemented carbide material of the drill bit 10 of this embodiment of the invention, a drill bit may be manufactured in accordance with embodiments of the invention using a matrix bit body or a steel bit body as are well known to those of ordinary skill in the art, for example, without limitation. Drill bits, termed “matrix” bits are conventionally fabricated using particulate tungsten carbide infiltrated with a molten metal alloy, commonly copper based. Steel body bits comprise steel bodies generally machined from castings or forgings. While steel body bits are not subjected to the same manufacturing sensitivities as noted above, steel body bits may enjoy the advantages of the invention as described herein, particularly with respect to having extension pads 30 for improving the stability and reducing lateral motion providing impact protection of the cutting elements 16, particularly cutting elements 16 oriented proximate to the forward face or leading edges 25 of the blades 24, as opposed to so-called “backup” cutters which significantly rotationally trail the rotationally leading edges 25 of the blades 24.
  • The blades 24 together with any associated extension pads 30 may be distributed upon or about the bit body 11, and may be distributed upon or about the face 14 of the bit body 11 to symmetrically or asymmetrically provide for a desired balance or relative imbalance of the drill bit 10, respectively during rotation about axis 27.
  • FIG. 2 shows an enlarged, partial face view of one of the extension pads 30 of the drill bit 10 as shown in FIG. 1. Reference may also be made back to FIG. 1. The extension pads 30 advantageously enhance stability of the bit body 11, particularly in the gage region 23 thereof, by increasing lateral surface area of contact of the drill bit 10 against the side wall of the borehole being drilled and decreasing the chordal drop segment 36 between adjacent blades 24 of the bit body 11 in the bore hole while minimizing the hydraulic restriction through the junk slot 17 in comparison to that conventionally experienced with so called “steering wheel” bits employing a continuous circumferentially extending gage pad. As shown in FIG. 2, bearing surface 32 is extended substantially in the gage region 23 of the bit body 11 and adjacent the gage pad 22 of the blade 24 by extension pad 30.
  • The bearing surface 32 may include additional features thereupon to further improve contact conditions between the drill bit 10 and the formation, for example, by providing low friction bearing surfaces and abrasion-resistant surfaces, in the form of inserts, coatings, or other bearing function-enhancing features, thereupon, as previously noted.
  • Each extension pad 30 rotationally leads its associated blade 24, and protrudes or extends into the fluid course 15 of the junk slot 17 from the face surface 25 of the blade 24. The extension pad 30 includes the extended bearing surface 32 and a leading edge, or surface, 34 that advantageously reduces impact stress to the cutting elements 16 caused by non-normal forces, i.e., forces not acting in the normal direction of bit rotation (clockwise, looking down a drill string), by providing extended contact with the formation when the drill bit 10 is subjected to bit whirl or other deleterious instabilities or perturbations. Specifically, the extended bearing surface 32 and/or leading surface 34 of the extension pad 30 may be configured to directly engage the formation during bit whirl to provide protection for the cutting elements 16 by absorbing energy and reducing impact and engagement stresses principally caused by bit whirl as the drill bit 10 rotates in the borehole. In this aspect, the extended bearing surface 32 provides contact surface area particularly suited for directing imbalance forces there toward, which is advantageous for forcing the bearing surface 32 toward and against the side wall of the borehole allowing the drill bit 10 to ride thereupon, increasing what is known as so-called “secondary” stability by reducing the effects of bit whirl, which ultimately improves the so-called “primary” stability by reducing impact stresses causing fracture or chipping of the cutting elements 16. The imbalance forces may also include side force vectors, i.e., radial force vectors, resulting from placement and orientations of the cutting elements 16 in the bit body 10. Generally, the imbalance force referred to herein includes the net combined forces of all non-Normal forces of the cutting elements 16 (not acting in the Normal direction perpendicular to bit rotation), such Normal forces including inline axial forces (up and down the longitudinal axis of the drill string) acting upon the bit body 10. Further, the extension pad 30 also improves secondary stability by decreasing the extent to which lateral motion may be caused by chordal drop segment 36 upon the bit 10. In this regard, lateral motion of the bit 10 is reduced while drilling by the presence of increased circumferential surface area, i.e., by increasing the circumferential segment, of the extended bearing surface 32 of the extension pad 30 and the gage pad 22, and the associated reduction in chordal drop segment 36 as compared to a conventionally dimensioned chordal drop segment designated by reference numeral 136 as would be present in a drill bit without features of embodiments of the present invention.
  • FIG. 3 shows a face view of a drill bit 310 configured with extension pads 330, 331, 332, 333, 334 in accordance with another embodiment of the invention. The drill bit 310 comprises a bit body 311, blades 324 a, 324 b, 324 c, 324 d, 324 e open fluid courses 340 and extension pads 330, 331, 332, 333, 334. The bit body 311 includes a face 314, a longitudinal axis (not shown) and a gage region 323. Each of the blades 324 a, 324 b, 324 c, 324 d, and 324 e extend longitudinally and radially outward over the face 314 of the bit body 311. Each of the blades 324 a, 324 b, 324 c, 324 d, and 324 e either rotationally leads or trails another of the blades 324 a, 324 b, 324 c, 324 d, and 324 e. Each of the open fluid courses 340 extends between one of the blades 324 a, 324 b, 324 c, 324 d, 324 e and another of the blades 324 a, 324 b, 324 c, 324 d, 324 e into and through the gage region 323 of the bit body 311. Each of the extension pads 330, 331, 332, 333, 334 substantially extends radially outward from the face 314 of the bit body 311, is substantially contiguous with one of the blades 324 a, 324 b, 324 c, 324 d, 324 e in alignment with the axial rotation of the drill bit 310 and extends into one of the open fluid courses 340, respectively. Each of the extension pads 330, 331, 332, 333, 334, as previously noted with respect to other embodiments, helps to reduce the tendency of drill bit 310 to whirl in operation and to minimize the impact stresses caused by lateral motion from bit whirl upon the cutting elements 16 when engaging the material of the formation being drilled.
  • It is to be recognized that the drill bit 310 may have fewer or greater number of open fluid courses than the five open fluid courses 340 illustrated. Also, the drill bit 310 may have fewer or greater number of blades than the five blades 324 a, 324 b, 324 c, 324 d, 324 e illustrated. Furthermore, the drill bit 310 may have extension pads associated with fewer than all of the blades 324 a, 324 b, 324 c, 324 d, 324 e as illustrated. For example, in the case of an intentionally significantly laterally imbalanced bit, it may be desirable to include only a single extension pad, either leading and or trailing a blade, on the bit body in the gage region 323 to which the lateral imbalance may be directed to help decrease lateral movement by decreasing the circumferential length of a chordal drop segment.
  • Each extension pad 330, 331, 332, 333, 334 is located next to one of each blades 324 a, 324 b, 324 c, 324 d, 324 e, substantially extending the bearing surface 322 of the associated gage pad in the gage region 323 of the bit body 311. Each extension pad 330, 331, 332, 333,334, as shown in FIG. 3, respectively rotationally trails its associated blade 324 a, 324 b, 324 c, 324 d, 324 e, and protrudes or extends from the trailing surface 325 thereof into its corresponding fluid course 340 proximate its juncture with an associated junk slot 317. The extension pads 330, 331, 332, 333, 334 advantageously reduce any potential for impact stress to the cutting elements 16 caused by lateral motion or contact with the formation by extending the bearing surface 322 of the associated gage pad. Specifically, the extended bearing surface 322 of each extension pad 330, 331, 332, 333, 334 may be configured to directly engage the formation during drilling to provide protection for the cutting elements 16 by reducing, if not eliminating, any tendency toward bit whirl as the drill bit 310 rotates while drilling a borehole. In this aspect, the extended bearing surfaces 332 of each extension pad 330, 331, 332, 333, 334 provide increased circumferential surface area, e.g., increased circumferential segment, particularly suited for decreasing the extent of lateral motion attributable to the chordal drop segment 336in comparison to conventional chordal drop segment 436. Increased circumferential surface area provided by each extension pad 330, 331, 332, 333, 334 improves the so-called “secondary” stability by reducing the tendency toward bit whirl, which improves, by reducing, lateral motion to the drill bit while drilling and deleterious effects thereto, such as fracture or chipping of the cutting elements 16.
  • As mentioned herein previously, the bit 310 may have an extension pad rotationally preceding, and or trailing, less than all of the blades. In still other embodiments, the bit 310 may have only one extension pad 330 rotationally preceding or trailing one of the blades 324 a, 324 b, 324 c, 324 d, 324 e of the drill bit 310. Extension pad configurations in accordance with several embodiments of the invention are described in further detail below.
  • Extension pads 230 having one of several configurations suitably selected for use with a drill bit in accordance with embodiments of the invention, as described hereinabove, are schematically shown in FIGS. 4A-4D. Before turning to the configurations of the extension pads 230 schematically shown in FIGS. 4A-4D, a general description of the extension pad 230 is first presented. An extension pad 230, as shown in each of FIGS. 4A-4D, circumferentially extends a bearing surface 232 of an associated gage pad 222 to rotationally precede, rotationally trail or rotationally precede and trail the leading or trailing blade surfaces of a blade 224, respectively, as described above, increasing the circumferential segment 225 of a blade and decreasing the chordal drop segment between circumferentially adjacent blades on a bit body. The extension pad 230 circumferentially increases the circumferential segment 225 by extending bearing surface 232 of the gage pad 222 substantially in the gage region 323 of the along the full gage diameter. In this respect, the bearing surface 232 of the extension pad 230 is aligned substantially parallel with respect to a longitudinal, rotational axis 27 of a bit body in the gage region 223 at a substantially constant radius (not shown) from the axis 27.
  • FIG. 4A schematically shows an extension pad 230 having an bearing surface 232 circumferentially extending from and trailing a gage pad 222 of a blade 224. The extension pad 230 is configured with a trailing edge, or surface, 250 that is slanted, i.e., linear, extending from an upper extension pad extent 251 to a lower extension pad extent 252. As used in the context of FIG. 4A as well as of each of FIGS. 4B through 4D, “upper” and “lower” refer to the orientation of the extension pad 230 when the bit carrying same is in an inverted position, as illustrated in FIG. 1.
  • FIG. 4B schematically shows an extension pad 230 having extended bearing surfaces 232 both trailing and leading a gage pad 222 of a blade 224. The extension pad 230 is configured with a trailing edge 250 that is slanted, i.e., linear, extending from an upper extension pad extent 251 to a lower extension pad extent 252. The extension pad 230 is also configured with a leading edge 254 that is slanted, i.e., linear, extending from an upper extension pad extent 251 to a lower extension pad extent 252.
  • FIG. 4C schematically shows an extension pad 230 having an extended bearing surface 232 trailing a gage pad 222 of a blade 224. The extension pad 230 is configured with a trailing edge 250 that is non-linear and extends from an upper extension pad extent 251 to a lower extension pad extent 252.
  • FIG. 4D schematically shows an extension pad 230 having extended bearing surfaces 232 trailing and leading a gage pad 222 of a blade 224. The extension pad 230 is configured with a trailing edge 250 that is non-linear and extends from an upper extension pad extent 251 to a lower extension pad extent 252. The extension pad 230 is also configured with a leading edge 254 that is non-linear, and extends from an upper extension pad extent 251 to a lower extension pad extent 252.
  • It is recognized that an extension pad 130, 230 or 330 in accordance with any of the above mentioned embodiments of the invention, regardless of weather it trails or leads a blade, may have a linear, or non-linear, leading or trailing edge, as appropriate, configured and positioned for decreasing a chordal drop segment to reduce the extent of lateral motion of a drill bit during drilling, protect the bit and cutting elements thereon from damage, while allowing requisite hydraulic flow of drilling fluid carrying formation cuttings to be passed through an associated junk slot of the drill bit.
  • While particular embodiments of the invention have been shown and described, numerous variations and other embodiments will occur to those skilled in the art. Accordingly, the scope of the present invention is limited by the appended claims and their legal equivalents.

Claims (22)

  1. 1. A drill bit comprising:
    a bit body having a longitudinal axis, and a face extending to a gage region;
    at least one blade extending longitudinally and radially outward over the face and having a plurality of cutting elements disposed thereon; and
    an extension pad substantially contiguous with the at least one blade and including a portion extending at least one of forward of the at least one blade and backward of the at least one blade with respect to a direction of intended bit rotation about the longitudinal axis, the extension pad including a circumferential bearing surface in the gage region.
  2. 2. The drill bit of claim 1, wherein the at least one blade includes a gage pad having a circumferential bearing surface in the gage region extended by the circumferential bearing surface of the extension pad.
  3. 3. The drill bit of claim 1, wherein the at least one blade comprises a plurality of blades circumferentially separated by junk slots.
  4. 4. The drill bit of claim 1, further including additional blades, at least one of the additional blades being without an extension pad associated therewith.
  5. 5. The drill bit of claim 1, further including additional blades each having a plurality of cutting elements disposed thereon, wherein at least some of the cutting elements disposed on at least some of the at least one blade and the additional blades are configured, positioned and oriented to provide a lateral imbalance force upon rotation of the bit body about the longitudinal axis when drilling a formation under weight on bit, the lateral imbalance force being circumferentially directed substantially toward the circumferential bearing surface.
  6. 6. The drill bit of claim 1, wherein the extension pad extends both forward and backward of the at least one blade with respect to the direction of intended bit rotation about the longitudinal axis.
  7. 7. The drill bit of claim 1, wherein the extension pad further includes at least one of a trailing edge and a leading edge extending in at least one of a linear manner and a non-linear manner between an upper extension pad extent and a lower extension pad extent.
  8. 8. The drill bit of claim 7, wherein the extension pad includes both a trailing edge and a leading edge.
  9. 9. The drill bit of claim 7, wherein the extension pad includes at least one of a trailing and a leading edge extending non-linearly between an upper extension pad extent and a lower extension pad extent.
  10. 10. A drill bit comprising:
    a bit body having a longitudinal axis and a face extending to a gage region;
    a plurality of blades extending longitudinally and radially outward over the face, the plurality of blades including at least a first blade and a second blade, the second blade rotationally trailing the first blade about the longitudinal axis;
    an open fluid course between the first blade and the second blade extending to a junk slot in the gage region of the bit body; and
    an extension pad substantially contiguous with one of the first blade and the second blade in the gage region of the bit body, the extension pad extending into at least one of the open fluid course and the junk slot.
  11. 11. The drill bit of claim 10, wherein each of the plurality of blades includes an extension pad coupled thereto.
  12. 12. The drill bit of claim 10, wherein the extension pad extends forward of the second blade in a direction of intended bit rotation.
  13. 13. The drill bit of claim 10, wherein the extension pad includes a circumferential bearing surface.
  14. 14. The drill bit of claim 10, wherein the extension pad, if extending from the first blade, further includes a trailing edge as extending into the at least one of the open fluid course and the junk slot from adjacent the first blade or, if extending from the second blade, a leading edge extending into the at least one of the open fluid course and the junk slot from adjacent the second blade, the respective edge extending one of linearly and non-linearly between an upper extension pad extent and a lower extension pad extent.
  15. 15. The drill bit of claim 10, further comprising at least one additional extension pad, wherein one of the at least one additional extension pad is substantially contiguous with the other of the first blade and the second blade.
  16. 16. The drill bit of claim 15, wherein each of the extension pad and the at least one additional extension pad respectively includes at least one of a trailing edge and a leading edge extending non-linearly between an upper extension pad extent and a lower extension pad extent of each respective extension pad.
  17. 17. The drill bit of claim 13, further comprising a plurality of cutting elements coupled to each of the plurality of blades, at least some of the plurality of cutting elements coupled to at least some of the blades, are configured, positioned and oriented to provide, in combination, lateral imbalance force upon rotational movement of the bit body about the longitudinal axis under weight on bit when drilling a formation, the lateral imbalance force being generally directed toward the circumferential bearing surface.
  18. 18. A drill bit comprising:
    a bit body having a longitudinal axis and a face extending to a gage region;
    a plurality of blades extending longitudinally and radially outward over the face of the bit body to the gage region, at least one of the plurality of blades includes a gage pad; and
    an extension pad extending rotationally backward from a rotationally trailing blade surface of at least one blade of the plurality of blades substantially in the gage region, the extension pad including a trailing edge and comprising a circumferential bearing surface extending from the gage pad.
  19. 19. The drill bit of claim 18, wherein the extension pad reduces a chordal drop segment between the at least one blade and an adjacent, rotationally trailing blade.
  20. 20. The drill bit of claim 18, further comprising additional extension pads, one of the additional extension pads extending forward from a rotationally leading blade surface of another blade of the plurality of blades and includes a leading edge.
  21. 21. The drill bit of claim 20, wherein each of the extension pads provide a reduced chordal drop segment between circumferentially adjacent blades.
  22. 22. The drill bit of claim 16, wherein the trailing edge is one of linear and non-linear and extends between an upper extension pad extent and a lower extension pad extent.
US11865258 2007-10-01 2007-10-01 Drill bits and tools for subterranean drilling Abandoned US20090084607A1 (en)

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US20100270077A1 (en) * 2009-04-22 2010-10-28 Baker Hughes Incorporated Drill bits and tools for subterranean drilling, methods of manufacturing such drill bits and tools and methods of off-center drilling

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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

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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100270077A1 (en) * 2009-04-22 2010-10-28 Baker Hughes Incorporated Drill bits and tools for subterranean drilling, methods of manufacturing such drill bits and tools and methods of off-center drilling
US8079430B2 (en) 2009-04-22 2011-12-20 Baker Hughes Incorporated Drill bits and tools for subterranean drilling, methods of manufacturing such drill bits and tools and methods of off-center drilling

Also Published As

Publication number Publication date Type
WO2009046075A2 (en) 2009-04-09 application
WO2009046075A3 (en) 2009-06-18 application
WO2009046075A4 (en) 2009-08-20 application

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