Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
  • E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
  • E21B17/1092—Gauge section of drill bits
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B10/00—Drill bits
  • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts

Definitions

• the present invention relates generally to rotary bits for drilling subterranean formations. More specifically, the invention relates not only to fixed cutter or so-called “drag" bits suitable for directional drilling, wherein tandem gage pads are employed to provide enhanced stability ofthe bit while drilling both linear and non-linear borehole segments, but also to rolling cutter, or so-called “rock” bits employing a set of supplementary gage pads, or two sets in tandem. Leading surfaces ofthe gage pads, and optionally trailing surfaces thereof, may optionally be provided with discrete cutters or other cutting structures to remove ledging on the borehole sidewall and to provide a borehole conditioning gage and (in the case of trailing surface cutting structures) an up- drill capability.
• Directional drilling that is to say, varying the path of a borehole from a first direction to a second, may be carried out along a relatively small radius of curvature as short as five to six meters, or over a radius of curvature of many hundreds of meters.
• Positive displacement (Moineau) type motors as well as turbines have been employed in combination with deflection devices such as bent housings, bent subs, eccentric stabilizers, and combinations thereof to effect oriented, nonlinear drilling when the bit is rotated only by the motor drive shaft, and linear drilling when the bit is rotated by the superimposed rotation ofthe motor shaft and the drill string.
• deflection devices such as bent housings, bent subs, eccentric stabilizers, and combinations thereof to effect oriented, nonlinear drilling when the bit is rotated only by the motor drive shaft, and linear drilling when the bit is rotated by the superimposed rotation ofthe motor shaft and the drill string.
• the sleeve carries individually controllable, expandable, circumferentially spaced steering ribs on its exterior, the lateral forces exerted by the ribs on the sleeve being controlled by pistons operated by hydraulic fluid contained within a reservoir located within the sleeve.
• Closed loop electronics measure the relative position ofthe sleeve and substantially continuously adjust the position of each steering rib so as to provide a steady side force at the bit in a desired direction
• Elongated gage pads exhibiting little or no side cutting aggressiveness, or the tendency to engage and cut the formation, may be beneficial for directional or steerable bits, since they would tend to prevent sudden, large, lateral displacements ofthe bit, which displacements may result in the aforementioned so-called "ledging" ofthe borehole wall.
• a simplistic elongated gage pad design approach exhibits shortcomings, as continuous, elongated gage pads extending down the side ofthe bit body may result in the trapping of formation cuttings in the elongated junk slots defined at the gage ofthe bit between adjacent gage pads, particularly if a given junk slot is provided with less than optimum hydraulic flow from its associated fluid passage on the face ofthe bit.
• rock bits employing one or more rolling cutting structures, and those in particular employed in steerable applications, may also drill a borehole of substandard quality presenting ledges, steps and other undesirable borehole wall irregularities.
• the present invention comprises a rotary drill bit, in one embodiment comprising a drag bit preferably equipped with polycrystalline diamond compact (PDC) cutters on blades extending above and radially to the side beyond the bit face, wherein the bit includes tandem, non-aggressive gage pads in the form of primary or longitudinally leading gage pads which may be substantially contiguous with the blades, and secondary or longitudinally trailing gage pads which are at least either longitudinally or rotationally discontinuous with the primary gage pads.
• PDC polycrystalline diamond compact
• discontinuous tandem gage pads ofthe present invention provide the aforementioned benefits associated with conventional elongated gage pads, but provide a gap or aperture between circumferentially adjacent junk slots in the case of longitudinally discontinuous pads so that hydraulic flow may be shared between laterally-adjacent junk slots
• the use of circumferentially-spaced, secondary gage pads rotationally offset from the primary gage pads provides superior bit stabilization by providing lateral support for the bit at twice as many circumferential locations as if only elongated primary gage pads or circumferentially-aligned primary and secondary gage pads were employed
• bit stability is enhanced during both linear and non-linear drilling, and any tendency toward undesirable side cutting by the bit is reduced
• each primary junk slot communicates with two secondary junk slots, promoting fluid flow away from the bit face and reducing any clogging tendency
• the secondary gage pads employed in the inventive bit are equipped with cutters on their longitudinally leading edges or surfaces at locations extending radially outwardly only substantially to the radially outer bearing surfaces ofthe secondary gage pads Such cutters may also lie longitudinally above the leading edges or surfaces of a pad, but again do not extend beyond the radially outer bearing surface
• Such cutters may comprise natural diamonds, thermally stable PDCs, or conventional PDCs comprised of
• the diamond tables of such cutters may be provided with an annular chamfer at least facing in the direction of bit rotation, or a flat or linear chamfer on that side ofthe diamond table.
• the chamfer is shaped and oriented to present a relatively aggressive cutting edge at the periphery of a cutting surface comprising a robust mass of diamond material exhibiting a negative rake angle to the formation in the direction ofthe shallow helical path traversed by the cutter so as to eliminate the aforementioned ledging.
• the cutters may optionally be slightly tilted backward, relative to the direction of bit rotation, to provide a clearance angle behind the cutting edge.
• an insert having a chisel-shaped diamond cutting surface having an apex flanked by two side surfaces and carried on a tungsten carbide or other stud, such as is employed in rock bits, may be mounted to the leading surface or edge ofthe secondary gage pads.
• the diamond cutting surface may comprise a PDC.
• the term "cutters" includes such inserts mounted to secondary gage pads.
• the insert may be oriented substantially transverse to the orientation ofthe longitudinally leading surface or edge, or tilted forward, relative to the direction of rotation, so as to present the apex ofthe chisel to a formation ledge or other irregularity on the borehole wall with one side surface substantially parallel to the longitudinally leading surface and the other side surface substantially transverse thereto, and generally in line with the rotationally leading surface ofthe gage pad to which the insert is mounted.
• tungsten carbide cutters or diamond film or thin PDC layer-coated tungsten carbide cutters or inserts exhibiting the aforementioned physical configuration and orientation may be employed in lieu of PDC cutters or inserts employing a relatively large thickness or depth of diamond.
• the secondary gage pad leading surface cutters do not extend beyond the radially outward bearing surfaces ofthe secondary gage pads, and so are employed to smooth and refine the wall ofthe borehole by removing steps and ledges.
• Yet another embodiment ofthe invention may involve the disposition of cutting structures in the form of coarse tungsten carbide granules on the leading surfaces or edges ofthe secondary gage pads, such grit being brazed or otherwise bonded to the pad surface.
• a macrocrystalline tungsten carbide material sometimes employed as hardfacing material on drill bit exteriors, may also be employed for suitable formations
• Yet another aspect ofthe invention involves the use of cutting structures on the trailing edges ofthe secondary gage pads to provide drill bits so equipped with an up- drill capability to remove ledges and other irregularities encountered when tripping the bit out ofthe borehole
• cutters (or inserts) having a defined cutting edge may be employed, including the abovementioned PDC cutters, tungsten carbide cutters and diamond- coated tungsten carbide cutters, or, alternatively, tungsten carbide granules or macrocrystalline tungsten carbide may be bonded to the longitudinally trailing gage pad surface.
• a plurality of supplementary gage pads at the same or higher elevation as (as the bit is oriented during drilling) the primary cutting structure ofthe bit provide similar advantages as previously described above with respect to rock bits
• two groups of at least partially longitudinally-separated gage pads may be employed in a "tandem" arrangement, again as described above with respect to drag bits
• One group, comprising the "primary” pads may be located on the radial exterior of the bit legs carrying the cones, or be located thereabove on the bit body and between the legs
• the "secondary" or longitudinally trailing pads may be located between and above the legs If the primary pads are themselves located above the legs, the secondary pads are preferably respectively farther above the primary pads
• cutting structures of various types may be employed on the longitudinally leading and, optionally, trailing surfaces thereof to condition the borehole wall.
• gage pads are again “slick” and laterally nonaggressive, as with the drag bit embodiments ofthe invention.
• the increased gage contact area provided by the gage pads according to the present invention is also believed to provide an added benefit by sharing the laterally inward thrust loads on the rolling cones and bearing structures to which the cones are mounted, potentially extending the lives ofthe bearings and associated seals.
• supplemental gage pads in a single group or in the tandem gage pad arrangement being related somewhat to whether a drag bit or a rock bit carries the pads and to the actual bit design, a better quality borehole and borehole wall surface in terms of roundness, longitudinal continuity and smoothness is created
• Such borehole conditions allow for smoother transfer of weight from the surface ofthe earth through the drill string to the bit, as well as better tool face control, which is critical for monitoring and following a design borehole path by the actual borehole as drilled
• Use of cutters on trailing surfaces ofthe secondary gage pads in addition to furnishing the leading surfaces thereof with cutters facilitates removal of the bit from the borehole and further provides back reaming capabilities to ensure a better quality borehole and borehole wall surface
• FIG 1 comprises a side perspective view of a PDC-equipped rotary drag bit according to the present invention
• FIG. 2 comprises a face view ofthe bit of FIG. 1;
• FIG 3 comprises an enlarged, oblique face view of a single blade ofthe bit of FIG 1,
• FIG 4 is an enlarged perspective view ofthe side ofthe bit of FIG 1, showing the configurations and relative locations and orientations of tandem primary gage pads (blade extensions) and secondary gage pads according to the invention
• FIG 5 comprises a quarter-sectional side schematic of a bit having a profile such as that of FIG 1, with the cutter locations rotated to a single radius extending from the bit centerline to the gage to disclose various cutter chamfer sizes and angles, and cutter back rake angles, which may be employed with the inventive bit
• FIG 6 is a schematic side view of a longitudinally-discontinuous tandem gage pad arrangement according to the invention, depicting the use of PDC cutters on the secondary gage pad leading edge;
• FIG. 7 is a side perspective view of a second PDC-equipped rotary drag bit according to the present invention employing discrete cutters on the leading and trailing surfaces ofthe secondary gage pads;
• FIG. 8 A is an enlarged, side view of a secondary gage pad ofthe bit of FIG. 7 carrying a cutter on a leading and a trailing surface thereof
• FIG. 8B is a longitudinal frontal view ofthe leading surface and cutter mounted thereon ofthe secondary gage pad of FIG. 8 A looking parallel to the surface
• FIG. 8C is a frontal view ofthe leading surface ofthe secondary gage pad of FIG. 8A showing the same cutter thereon, but in a different orientation;
• FIG. 9A and 9B are, respectively, a top view of a chisel-shaped cutter mounted transversely to a cutter flat of a secondary gage pad leading surface, taken perpendicular to the cutter flat, and a longitudinal frontal view ofthe cutter so mounted, taken parallel to the cutter flat;
• FIGS. 10A and 10B are, respectively, a top view of a chisel-shaped cutter mounted in a rotationally forward-leaning direction with respect to a cutter flat of a secondary gage pad leading surface, taken perpendicular to the cutter flat, and a longitudinal frontal view ofthe cutter so mounted, taken parallel to the cutter flat;
• FIG. IOC is a longitudinal frontal view of a chisel-shaped cutter, taken parallel to the cutter flat, wherein the sides ofthe chisel meeting at the apex are separated by a larger angle than the cutter of FIGS. 10A and 10B so as to present a more blunt cutting structure substantially recessed into the gage pad surface.
• FIG. 11 is a schematic side perspective view of an exemplary rolling cone bit incorporating a first tandem arrangement of primary and secondary gage pads according to the present invention
• FIG. 12 is a schematic side perspective view of an exemplary rolling cone bit incorporating a second tandem arrangement of primary and secondary gage pads according to the present invention
• FIG. 13 is a schematic side perspective view of an exemplary rolling cone bit incorporating a third arrangement of a single group of supplementary gage pads according to the present invention in a single group above the legs ofthe bit.
• FIGS. 1 through 5 depict an exemplary rotary drag bit 200 according to the invention.
• Bit 200 includes a body 202 having a face 204 and including a plurality (in this instance, six) of generally radially oriented blades 206 extending above the bit face 204 to primary gage pads 207.
• Primary junk slots 208 lie between longitudinal extensions of adjacent blades 206, which comprise primary gage pads 207 in this embodiment.
• a plurality of nozzles 210 provides drilling fluid from plenum 212 within the bit body 202 and received through passages 214 to the bit face 204. Formation cuttings generated during a drilling operation are transported across bit face 204 through fluid courses 216 communicating with respective primary junk slots 208.
• Secondary gage pads 240 are rotationally and substantially longitudinally offset from primary gage pads 207, and provide additional stability for bit 200 when drilling both linear and nonlinear borehole segments.
• Shank 220 includes a threaded pin connection 222 as known in the art, although other connection types may be employed.
• Primary gage pads 207 define primary junk slots 208 therebetween, while secondary gage pads 240 define secondary junk slots 242 therebetween, each primary junk slot 208 feeding two secondary junk slots 242 with formation cuttings-laden drilling fluid received from fluid courses 216 on the bit face.
• the trailing, radially outer surfaces 244 of primary gage pads 207 are scalloped or recessed to some extent, the major, radially outer bearing surfaces 246 ofthe primary gage pads 207 are devoid of exposed cutters and the rotationally leading edges 248 thereof are rounded or smoothed to substantially eliminate any side cutting tendencies above (in normal drilling orientation) radially outermost cutters 10 on blades 206.
• the radially outer bearing surfaces 250 of secondary gage pads 240 are devoid of exposed cutters, and (as with radially outer bearing surfaces 246 of primary gage pads 207) preferably comprise wear-resistant surfaces such as tungsten carbide, diamond grit-filled tungsten carbide, a ceramic, or other abrasion-resistant material as known in the art.
• the outer bearing surfaces 246 and 250 may also comprise discs, bricks or other inserts of wear-resistant material (see 252 in FIG. 4) bonded to the outer surface ofthe pads, or bonded into a surrounding powdered WC matrix material with a solidified liquid metal binder, as known in the art.
• the outer bearing surfaces 246, 250 of respective primary and secondary gage pads 207 and 240 may be rounded at a radius of curvature, taken from the centerline or longitudinal axis ofthe bit, substantially the same as (slightly smaller than) the gage diameter ofthe bit, if desired.
• the secondary gage pads 240 may be sized to define a smaller diameter than the primary gage pads 207, and measurably smaller than the nominal or gage diameter ofthe bit 200. As shown in FIGS. 1 and 4, there may be a slight longitudinal overlap between primary gage pads 207 and secondary gage pads 240, although this is not required (see FIG. 6) and the tandem gage pads 207, 240 may be entirely longitudinally discontinuous.
• trailing ends 209 of primary gage pads 207 be tapered or streamlined as shown, in order to enhance fluid flow therepast and eliminate areas where hydraulic flow and entrained formation cuttings may stagnate. It is also preferable that secondary gage pads 240 (as shown) be at least somewhat streamlined at both leading edges or surfaces 262 and at their trailing ends 264 for enhancement of fluid flow therepast
• Secondary gage pads 240 carry cutters 260 on their longitudinally leading edges, which in the embodiment illustrated in FIGS. 1 through 4 comprise arcuate surfaces 262 As shown, cutters 260 comprise exposed, three-per-carat natural diamonds, although thermally stable PDCs may also be employed in the same manner.
• the distribution of cutters 260 over arcuate leading surfaces 262 provides both a longitudinal and rotational cutting capability for reaming the sidewall ofthe borehole after passage ofthe bit blades 206 and primary gage pads 207 to substantially remove any irregularities in and on the sidewall, such as the aforementioned ledges.
• the bottomhole assembly following bit 200 is presented with a smoother, more regular borehole configuration.
• the bit 200 ofthe present invention may alternatively comprise circumferentially aligned but longitudinally discontinuous gage pads 207 and 240, with a notch or bottleneck 270 located therebetween.
• primary junk slots 208 are rotationally aligned with secondary junk slots 242, and mutual fluid communication between laterally adjacent junk slots (and indeed, about the entire lateral periphery or circumference of bit 200) is through notches or bottlenecks 270.
• the radial recess depth of notches or bottlenecks 270 may be less than the radial height ofthe gage pads 207 and 240, or may extend to the bottoms of the junk slots defined between the gage pads, as shown in broken lines.
• the cutters employed on the leading surface 262 of secondary gage pad 240 comprise PDC cutters 272, which may exhibit disc-shaped cutting faces 274, or may be configured with flat or linear cutting edges as shown in broken lines 276 It should also be understood that more than one type of cutter 260 may be employed on a secondary gage pad 240, and that different types of cutters 260 may be employed on different secondary gage pads 240 To complete the description ofthe bit of FIGS 1 through 5, although the specific structure is not required to be employed as part ofthe invention herein, the profile 224 ofthe bit face 204 as defined by blades 206 is illustrated in FIG.
• bit 200 is shown adjacent a subterranean rock formation 40 at the bottom ofthe well bore Bit 200 is, as disclosed, believed to be particularly suitable for directional drilling, wherein both linear and non-linear borehole segments are drilled by the same bit First region 226 and second region 228 on profile 224 face adjacent rock zones 42 and 44 of formation 40 and respectively carry large chamfer cutters 110 and small chamfer cutters 10
• First region 226 may be said to comprise the cone 230 ofthe bit profile 224 as illustrated, whereas second region 228 may be said to comprise the nose 232 and flank 234 and extend to shoulder 236 of profile 224, terminating at primary gage pad 207
• large chamfer cutters 1 10 may comprise cutters having PDC tables in excess of 0 070 inch thickness, and preferably about 0 080 to 0 090 inch depth, with chamfers 124 of about a 0 030 to 0 060 inch width, looking at and perpendicular to the cutting face, and oriented at a 45 ° angle to the cutter axis
• the cutters themselves, as disposed in region 226, are back raked at 20° to the bit profile at each respective cutter location, thus providing chamfers 124 with a 65 ° back rake Cutters 10, on the other hand, disposed in region 228, may comprise conventionally-chamfered cutters having about a 0.030 inch PDC table thickness, and a 0 010 inch chamfer width looking at and perpendicular to the cutting face, with chamfers 24 oriented at a 45° angle to the cutter axis Cutters 10 are themselves backraked at 15° on nose 232 (providing a 60
• 70° chamfer angles may be employed with chamfer widths (looking vertically at the cutting face ofthe cutter) in the range of about 0.035 to 0.045 inch, cutters 110 being disposed at appropriate backrakes to achieve the desired chamfer rake angles in the respective regions.
• a boundary region may exist between first and second regions 226 and 228.
• rock zone 46 bridging the adjacent edges of rock zones 42 and 44 of formation 40 may comprise an area wherein demands on cutters and the strength ofthe formation are always in transition due to bit dynamics
• the rock zone 46 may initiate the presence of a third region on the bit profile wherein a third size of cutter chamfer is desirable.
• the annular area of profile 224 opposing zone 46 may be populated with cutters of both types (i.e., width and chamfer angle) and employing backrakes respectively employed in region 226 and those of region 228, or cutters with chamfer sizes, angles and cutter backrakes intermediate those ofthe cutters in regions 226 and 228 may be employed.
• tandem gage pad configuration ofthe invention has utility in conventional bits as well as for bits designed specifically for steerability, and is therefore not so limited
• the additional contact points afforded between the bit and the formation may reduce the tendency of a bit to incur damage under "whirl", or backward precession about the borehole, such phenomenon being well known in the art.
• the distance a bit may travel laterally before making contact with the sidewall is reduced, in turn reducing severity of any impact.
• Bit 200a includes a body 202 having a face 204 and including a plurality (again, six) of generally radially oriented blades 206 extending above the bit face 204 to primary gage pads 207.
• Primary junk slots 208 lie between longitudinal extensions of adjacent blades 206, which comprise primary gage pads 207
• a plurality of nozzles 210 provides drilling fluid from a plenum within the bit body 202 and received through passages to the bit face 204, as previously described with reference to FIG. 5.
• Shank 220 includes a threaded pin connection 222 as known in the art, although other connection types may be employed.
• Primary gage pads 207 define primary junk slots 208 therebetween, while secondary gage pads 240 define secondary junk slots 242 therebetween, each primary junk slot 208 feeding two secondary junk slots 242 with formation cuttings-laden drilling fluid received from fluid courses 216 on the bit face
• the trailing, radially outer surfaces 244 of primary gage pads 207 are not scalloped or recessed to any measurable extent and include the major, radially outer bearing surfaces 246 ofthe primary gage pads 207.
• Bearing surfaces 246 are devoid of exposed cutters and the rotationally leading edges 248 thereof are rounded or smoothed to substantially eliminate any side cutting tendencies above (in normal drilling orientation) radially outermost cutters 10 on blades 206 and to compact filter cake on the borehole wall rather than scraping and damaging it. Further, the smooth leading edges reduce any tendency ofthe bit to "whirl", or precess in a backward direction of rotation, since aggressive leading edges may induce such behavior.
• the radially outer bearing surfaces 250 of secondary gage pads 240 are devoid of exposed cutters, and (as with radially outer bearing surfaces 246 of primary gage pads 207) preferably comprise wear-resistant surfaces such as tungsten carbide, diamond grit- filled tungsten carbide, a ceramic, or other abrasion-resistant material as known in the art
• the outer bearing surfaces 250 and 246 may also comprise discs, bricks or other inserts of wear-resistant material (see 252 in FIG. 4) bonded to the outer surface ofthe pads, or bonded into a surrounding powdered WC matrix material with a solidified liquid metal binder, as known in the art.
• the outer bearing surfaces 246 and 250 may also comprise a tungsten carbide hardfacing material such as is disclosed in U.S. Patent 5,663,512, assigned to the assignee ofthe present invention, or other, conventional, tungsten carbide-containing hardfacing materials known in the art.
• the outer bearing surfaces 246, 250 of respective primary and secondary gage pads 207 and 240 may be rounded at a radius of curvature, taken from the centerline or longitudinal axis ofthe bit, substantially the same as (slightly smaller than) the gage diameter ofthe bit, if desired Further, the secondary gage pads 240 may be sized to define a smaller diameter than the primary gage pads 207, and measurably smaller than the nominal or gage diameter ofthe bit 200.
• primary gage pads 207 and secondary gage pads 240 there is no longitudinal overlap between primary gage pads 207 and secondary gage pads 240, the two sets of gage pads being entirely longitudinally discontinuous. It is preferable that the trailing ends 209 of primary gage pads 207 be tapered or streamlined as shown, in order to enhance fluid flow therepast and eliminate areas where hydraulic flow and entrained formation cuttings may stagnate It is also preferable that secondary gage pads 240 (as shown) be at least somewhat streamlined at both leading edges or surfaces 262 and at their trailing ends 264 for enhancement of fluid flow therepast
• cutters 300 comprise PDC cutters comprising diamond tables 304 bonded to substantially cylindrical cemented tungsten carbide substrates 306
• Cutters 300 are oriented with their longitudinal axes L substantially perpendicular to cutter flats 302 and disposed in a radial direction with respect to the longitudinal axis of bit 200a, so that arcuate, preferably annular, chamfers or rake lands 308 at the periphery ofthe diamond tables 304 (see FIG 8B) present superabrasive cutting surfaces oriented at a negative rake angle to a line perpendicular to the formation as the bit rotates and moves longitudinally ahead during a drilling operation and cutters 300 traverse a shallow helical path
• the distribution of cutters 300 on cutter flats 302 provides a relatively aggressive, controlled cutting capability for reaming the side
• trailing ends or surfaces 264 of secondary gage pads 240 may also be provided with cutters 300 to provide an up-drill capability for removing borehole and borehole wall irregularities as bit 200a and its associated bottomhole assembly are tripped out ofthe borehole or alternately raised or lowered to condition the wall ofthe borehole.
• Trailing ends 264 may be provided with cutter flats 302, and cutters 300 of like configuration and orientation to cutters 300 disposed thereon to provide the aforementioned longitudinal and rotational cutting capability.
• the cutters 300 used on trailing ends 264 may be ofthe same, smaller or larger diameter than those used on the leading ends 262 ofthe secondary gage pads 240.
• the cutters 300 exhibit a relatively thick diamond table, on the order of 0.050 inch or more, although diamond table thicknesses of as little as about 0.020 inch are believed to have utility in the present invention. It is preferred that a significant, or measurable, chamfer or rake land 308, on the order of about 0.020 to 0.100 inch depth be employed.
• the chamfer may be oriented at an angle of about 30° to about 60°, for example at about 45°, to the longitudinal axis ofthe cutter 300, so as to provide a substantial negative back rake to the surface of chamfer 308 adjacent the cutting edge 310, which due to this orientation ofthe cutter 300, lies between the chamfer or rake land 308 and the central portion or clearance face 312 ofthe face of the diamond table 304.
• a relatively aggressive cutting edge 310 is presented, but the negative back rake of chamfer or rake land 308 provides requisite durability.
• FIG. 8C ofthe drawings it is also possible to mount cutters
• the central portion or clearance face 312 ofthe diamond table 304 being thus tilted at a small angle ⁇ , such as about 5°, away from an orientation parallel to cutter flat 302 and hence away from the borehole wall.
• central portion or clearance face 312 is maintained substantially free of engagement with the formation material comprising ledges and other irregularities on the borehole wall so as to reduce friction and wear ofthe diamond table 304, as well as consequent heating and potential degradation ofthe diamond material
• back rake angle may be controlled by orientation ofthe cutter as well as by the chamfer angle
• a clearance angle may be provided with the cutter orientation depicted in FIGS.
• cutters 300 have been illustrated in FIGS 8B and 8C as substantially centered on the surface of cutter flat 302, it will be appreciated that placement closer to a rotationally leading edge ofthe secondary gage pad may be preferred in some instances to reduce the potential for wear ofthe gage pad material as irregularities in the borehole wall are encountered
• Cutters having a relatively thick diamond table and large chamfers or rake lands are disclosed in U S Patent 5,706,906, assigned to the assignee ofthe present invention It is also contemplated that cutters of other designs exhibiting an annular chamfer, or a linear or flat chamfer, or a plurality of such flat chamfers, may be employed in lieu of cutters with annular chamfers Such cutters are disclosed in U S Patents 5,287,936, 5,346,026, 5,467,836 and 5,655,612, and copending U S application Serial No 08/815,063, each assigned to the assignee ofthe present invention.
• cutters employed on leading and trailing ends ofthe secondary gage pads may also comprise suitably shaped tungsten carbide studs or inserts, or such studs or inserts having a diamond coating over at least a portion of their exposed outer ends such as is known in the art
• the significance in cutter selection lies in the ability of the selected cutter to efficiently and aggressively cut the formation while
• Cutters 400 are employed, which may be substituted for cutters 300 previously disclosed herein on the leading surfaces 262 and/or the trailing surfaces 264 of secondary gage pads 240 Cutters 400 may be generally described as "chisel shaped", exhibiting a cutting end comprised of two side surfaces 402 converging toward an apex 404 The side surfaces and apex may comprise a substantial PDC mass formed onto a substantially cylindrical stud 406 of suitable substrate material such as cemented tungsten carbide, a diamond coating formed over a stud exhibiting a chisel shape, or even an uncoated cemented tungsten carbide stud, for softer formation use
• a cutter 400 may, by way of example only, be disposed adjacent a rotationally leading edge or surface 420 of a cutter flat 302 of
• a chisel-shaped cutter 400a may be comprised of side surfaces 402 meeting at apex 400 but defining a larger angle therebetween than the cutters 400 of FIGS 9 A, 9B, 10A and 10B Cutter 400a may be configured so as to have one side surface 402 parallel to, and substantially coincident with, cutter flat 302 and the other side surface 402 parallel to, and substantially coincident with, rotationally leading surface, cutter 400a being substantially recessed within secondary gage pad 240 and presenting minimal exposure therefrom
• the cutter 400a may be configured or oriented to present a clearance angle with respect to formation material being cut, as has been described with respect to preceding embodiments
• the rotationally leading side surface 402 of cutter 400a presents a suitable negative back rake angle
• the leading surfaces 262 or trailing surfaces 264 ofthe secondary gage pads may be equipped with cutting structures in the form of tungsten carbide granules
• Each bit 500a-c includes a body 502 having a shank at one end thereof with a threaded pin as shown at 504 for connection to a drill string
• Bit body 502 also includes three legs or sections 506 opposite threaded shank 504, each leg carrying a cone-shaped cutter 508 thereon at the leading end ofthe bit, cutters 508 being rotatably secured to a bearing shaft associated with each leg 506 Bearing lubrication is provided by a pressure-responsive lubricant compensator 510 located in each leg 506, as known in the art
• the exteriors of cutters 508 may be configured (as in so-called "milled tooth” bits) to provide cutting structures thereon for engaging the rock formation being drilled, but are more typically provided with cutting structures 512 in the form of hard metal (such as cemented tungsten carbide) inserts retained in sockets and arranged in generally circumferential rows on each cutter 508
• bit 500a includes a group of primary gage pads 520 circumferentially disposed about body 502 above legs 506. As shown, primary gage pads 520 are located at least partially longitudinally above legs 506 and in junk slots 516. Primary gage pads may be centered in junk slots 516, or positioned closer to one adjacent leg 506 or the other. Also as shown, secondary gage pads 522 are located are circumferentially disposed about body 502 and at least partially longitudinally above primary gage pads 520 and rotationally offset therefrom. Gage pads 520 and 522 may be configured as previously described herein, or in any other suitable configuration.
• An optional waist area 523 of reduced diameter may, as shown, be located between primary gage pads 520 and secondary gage pads 522 to enhance drilling fluid flow on the bit exterior and facilitate clearance of formation debris from the bit 500a.
• Both primary gage pads 520 and secondary gage pads 522 may be, and preferably are, provided with cutting structures 524 thereon on their longitudinally leading and trailing surfaces, as in some ofthe preceding embodiments.
• Cutting structures 524 may comprise any ofthe previously- described gage pad cutting structures, or combinations thereof. As with the preceding embodiments, the cutting structures 524 do not project radially beyond the outer bearing surfaces 530 ofthe gage pads 520 and 522, and so do not provide any side-cutting capability.
• the radially outer bearing surfaces 530 of both primary gage pads 520 and secondary gage pads 522 are devoid of exposed cutters, and preferably comprise wear- resistant surfaces such as tungsten carbide, diamond grit-filled tungsten carbide, a ceramic, or other abrasion-resistant material as known in the art.
• the outer bearing surfaces 530 may also comprise discs, bricks or other inserts of wear-resistant material (see 252 in FIG.
• the outer bearing surfaces 530 may also comprise a tungsten carbide hardfacing material such as is disclosed in the previously-referenced U.S Patent 5,663,512, or other, conventional, tungsten carbide-containing hardfacing materials known in the art
• the outer bearing surfaces 530 of respective primary and secondary gage pads 520 and 522 may be rounded at a radius of curvature, taken from the centerline or longitudinal axis ofthe bit, substantially the same as (slightly smaller than) the gage diameter ofthe bit, if desired
• the secondary gage pads 522 may be sized to define a smaller diameter than the primary gage pads 522, and measurably smaller than the nominal or gage diameter ofthe bit 500a Referring now to FIG.
• bit 500b is shown. Reference numerals designating features previously described in FIG 11 are also employed in FIG 12 for clarity Bit 500b also includes groups of primary and secondary gage pads 520 and 522, respectively As with bit 500a, the gage pads of each group are circumferentially disposed about body 502 and the two groups of pads are rotationally offset from one another However, bit 500b differs from bit 500a in that the primary gage pads 520 are disposed on the exteriors of legs 506, while the secondary gage pads 522 are disposed in junk slots 516 Secondary gage pads 522 may be centered in junk slots 516, or located closer to either adjacent leg 506 Accordingly, bit 500b presents a more longitudinally compact structure, which may be desirable for extremely short radius directional drilling Both primary and secondary gage pads 520 and 522 carry cutting structures 524 on their longitudinally leading and trailing surfaces to provide both down-drill and up-drill capabilities, and the radially outer surfaces 530 ofthe pads may be structured as previously described with respect to bit 500a As in bit 500a, the
• bit 500c is shown Reference numerals designating features previously described with respect to bits 500a and 500b are also employed to describe bit 500c in FIG 13 for clarity Bit 500c, unlike bits 500a and 500b, employs only a single group of supplementary gage pads 540, located in junk slots 526 between legs 506 of body 502 Supplementary gage pads 540 may include cutting structures 524 of their longitudinally leading and trailing surfaces, and radially outer bearing surfaces 530 may be structured as previously described In each ofthe bits 500a through 500c, the increased contact area with the borehole wall provided by the respective gage pads 520, 522 and 540 may provide a benefit in terms of bit longevity by sharing inward thrust loads otherwise taken solely by the cutters 508 and their supporting bearing structures and associated seals.
• bits 500a through 500a have been illustrated and described as comprising so-called “tri-cone” bits, it will be understood by those of ordinary skill in the art that the invention is not so limited. Bits employing fewer than, or more than, three movable cutters to drill the borehole are also contemplated as falling within the scope ofthe present invention, as are bits which include both fixed and movable cutters to drill the borehole (i.e., bits having rotating cones or other cutters as well as fixed cutters such as PDC cutters on the bit face).
• primary and secondary gage pads may be straight or curved, and may be oriented at an angle to the longitudinal axis ofthe bit, so as to define a series of helical segments about the lateral periphery thereof.

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• 1998
  • 1998-09-03 AU AU92179/98A patent/AU9217998A/en not_active Abandoned
  • 1998-09-03 EP EP98944704A patent/EP1012438A1/de not_active Withdrawn
  • 1998-09-03 WO PCT/US1998/018310 patent/WO1999013194A1/en not_active Application Discontinuation

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