WO2009046069A2 - Foret et outil de forage souterrain - Google Patents

Foret et outil de forage souterrain Download PDF

Info

Publication number
WO2009046069A2
WO2009046069A2 PCT/US2008/078401 US2008078401W WO2009046069A2 WO 2009046069 A2 WO2009046069 A2 WO 2009046069A2 US 2008078401 W US2008078401 W US 2008078401W WO 2009046069 A2 WO2009046069 A2 WO 2009046069A2
Authority
WO
WIPO (PCT)
Prior art keywords
blade
drill bit
bit
boss
bearing surface
Prior art date
Application number
PCT/US2008/078401
Other languages
English (en)
Other versions
WO2009046069A4 (fr
WO2009046069A3 (fr
Inventor
Michael L. Doster
Original Assignee
Baker Hughes Incorporated
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
Application filed by Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Publication of WO2009046069A2 publication Critical patent/WO2009046069A2/fr
Publication of WO2009046069A3 publication Critical patent/WO2009046069A3/fr
Publication of WO2009046069A4 publication Critical patent/WO2009046069A4/fr

Links

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
    • E21B10/00—Drill bits
    • E21B10/42—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits

Definitions

  • 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 improving hydraulic configuration.
  • whirl 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 borehole wall in a counter-clockwise direction due to whirl places stresses on the cutting elements beyond their designed limits.
  • 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 bit face adjacent the bearing zone.
  • 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. Patent 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 borehole gage diameter, such bits undesirably increase the outer perimeter surface of the bit bearing on the borehole side wall, making directional drilling more difficult.
  • 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.
  • the configuration of the steering wheel bits impedes tripping the bit in and out of the borehole, and may cause swabbing (removal of formation material from the borehole side wall) during tripping.
  • a drill bit includes at least one boss for increasing stability and reducing impact shock caused by a lateral imbalance force 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 a boss coupled to the blade in the gage region of the bit body.
  • the boss includes a - A - circumferential bearing surface that rotationally precedes the blade when rotated about the longitudinal axis.
  • the blade may also include a circumferential bearing surface.
  • a drill bit comprises at least one boss extending into an open fluid course circumferentially between two blades, the fluid course communicating with a junk slot of the drill bit.
  • the boss provides enhanced stability to the drill bit.
  • inventions comprise a drill bit having at least one blade and a boss extending therefrom, rotationally preceding cutting elements carried on a rotationally leading edge of the at least one blade.
  • Still other embodiments comprise a drill bit having at least one blade with a circumferential bearing surface rotationally forwardly shifted for enhanced alignment with a lateral force vector acting upon the drill bit during operation.
  • FIG. 1 shows a perspective, inverted view of a drill bit configured with bosses according to an embodiment of the invention
  • FIG. 2 shows a partial face view of one of the bosses of the drill bit shown in FIG. 1;
  • FIG. 3 shows a partial face view of a conventional drill bit schematically representing an imbalance force and reaction forces acting between a blade of the drill bit and a side wall of a borehole when drilling a subterranean formation;
  • FIG. 4 shows a partial face view of a drill bit schematically representing an imbalance force and reaction forces acting between a blade and a boss of a drill bit in accordance with embodiments of the invention and a side wall of a borehole when drilling a subterranean formation;
  • FIG. 5 shows a face view of a drill bit configured with bosses in accordance with another embodiment of the invention
  • FIGS. 6A-6C show partial perspective views of variations of bearing surface configurations for the bosses shown in FIG. 5.
  • FIG. 1 shows a perspective, inverted view of a drill bit 10 configured with bosses 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.
  • 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 American Petroleum Institute (API) standards and adapted for connection to a component of a drill string, not shown.
  • API American Petroleum Institute
  • Blades 24 that radially and longitudinally extend from the face 14 of the bit body 11 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 borehole.
  • PDC polycrystalline diamond compact
  • each boss 30 rotationally precedes the blade 24 substantially in the gage region 23 of body 11 of the bit 10.
  • each boss 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.
  • Each boss 30 may be configured according to an embodiment of the invention, as hereinafter described.
  • the bit 10 may have bosses rotationally preceding less than all of the blades.
  • the bit 10 may have only one boss 30 rotationally preceding a single blade 24 of the bit 10. Bosses in accordance with several embodiments of the invention are described in further detail below.
  • the bit body 11 may also carry 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 borehole (not shown) and hold the gage diameter thereof, and gage pads comprising bearing surfaces 22 in the gage region 23 for contacting or riding upon the walls of the borehole to maintain the hole diameter and help stabilize the drill bit 10 while drilling through a subterranean formation.
  • the gage pads 22 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, or caged ball bearings, for example.
  • 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 bosses 30 may be formed from the material of the bit body 11 and manufactured together 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 bosses 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.
  • 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.
  • the brown body is not yet fully hardened or densif ⁇ ed, 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.
  • 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.
  • tungsten carbide one or more of diamond, boron carbide, boron nitride, aluminum nitride, tungsten boride and carbides or borides of Ti, Mo, Nb, V, Hf, Zr, T, Si and Cr may be employed.
  • 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.
  • displacements as known 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 the final sintering process required to bring the brown body to full density and strength.
  • critical component features such as threads, may require reworking prior to their intended use, as the displacements may not adequately prevent against shrinkage, warpage or distortion.
  • the material of the body 11 as described may be made from a tungsten carbide/cobalt alloy matrix, other materials suitable for use as a bit body may also be utilized.
  • 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.
  • 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 bosses 30 for improving the stability and 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 bosses 30 may be distributed upon or about the bit body 11 in order to substantially provide rotational balance of the drill bit 10 when rotating about its axis 27, 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.
  • FIG. 2 shows a partial face view of one of the bosses 30 of the drill bit 10 as shown in FIG. 1.
  • the bosses 30 advantageously enhance stability of the bit body 11, particularly in the gage region 23 thereof, by enhancing the lateral surface area of contact of the drill bit 10 against the side wall of the borehole being drilled by desirably decreasing the cross-sectional "footprint" of the bit body in the borehole and decreasing the hydraulic restriction through the junk slot 17 in comparison to that conventionally experienced with so called “steering wheel” bits.
  • Adjacently located next to the bearing surface 22 of the blade 24 and substantially in the gage region 23 of the bit body 11 is a boss 30 that also includes a bearing surface 32.
  • bearing surface 22 associated with the blade 24 will hereinafter be referred to as “first bearing surface” with reference to numeral 22
  • bearing surface 32 associated with the boss 30 will hereinafter be referred to as “second bearing surface” with reference to numeral 32.
  • the second bearing surface 32 of the boss 30 rotationally precedes the first bearing surface 22 about the longitudinal axis 27 with reference to the rotational direction of the drill bit 10.
  • the first bearing surface 22 and the second bearing surface 32 will be circumferentially adjacent or even contiguous in the gage region 23 extending across a boss 30 and its associated blade 24, as illustrated in FIG. 1, in order to provide a smooth, uninterrupted and substantially transitionless engagement when riding, or impinging, upon or making contact against the side wall of the borehole through the formation being drilled.
  • first bearing surface 22 and the second 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, such as inserts or wear knots, thereupon.
  • Each boss 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 boss 30 includes the second 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 leading contact with the formation when the drill bit 10 is subjected to bit whirl or other deleterious instabilities or perturbations.
  • the second bearing surface 32 and/or leading surface 34 of the boss 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.
  • first bearing surface 22 and the second bearing surface 32 provide contact surface area particularly suited for directing imbalance forces theretoward, which is particularly advantageous for forcing the first and second bearing surfaces 22 and 32 toward and against the side wall of the borehole thereby 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 strategic placement and orientations of the cutting elements 16 in the bit body 10.
  • 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.
  • a designed lateral imbalance force is flirther discussed with respect to a conventional drill bit shown in FIG. 3 and then with respect to a drill bit in accordance with embodiments of the invention as shown in FIG.4.
  • FIG. 3 shows a partial face view of a conventional drill bit 110 schematically representing an imbalance force Fi and reaction forces Fr between a blade 124 of the drill bit 110 and a side wall 102 of a borehole 100 when drilling in a subterranean formation.
  • the vector of imbalance force Fi particularly is located substantially perpendicular to the longitudinal bit axis 27 and is achieved by selectively positioning and orienting the cutting elements 16 upon the bit body 111 to achieve a net radial imbalance force vector Fi as is well understood by a person having ordinary skill in the art.
  • the magnitude and direction of the net radial imbalance force vector Fi will depend on the positioning and orientation of the cutting elements 16, and the shape of the drill bit as the shape influences cutter position. Orientation of a cutting element includes backrake and siderake. The magnitude and direction of imbalance force vector Fi is also influenced by a number of factors such as the specific configuration and size of the individual cutting elements, the weight-on-bit load applied to the drill bit, the speed of rotation, and the physical properties of the materials of the subterranean formation. While the imbalance force or net radial imbalance force vector Fi is shown being directed radially outward from the axis 27, it may be directed radially outward from another location of the drill bit 110 while being oriented substantially perpendicular with the axis 27.
  • the reaction forces Fr are the result of the imbalance force Fi of the drill bit 110 as it makes contact with the side wall 102 of the borehole 100.
  • the reaction forces Fr are representatively illustrated herein, i.e., not determinative of actual force magnitudes, and substantially act upon the bearing surface 122 of the drill bit 110 as it rotates in the borehole 100.
  • the reaction forces Fr are also representative of the impact stresses caused upon the cutting elements 16 by bit whirl.
  • the cutting elements 16, particularly those cutting elements 16 located proximate leading face 125 of the blade 124 of the drill bit 110 and on the shoulder of the bit face below the gage region and down to the nose (as the bit is oriented during drilling), are more prone to being directly impacted against the material of the formation, thus sustaining impact stresses having force magnitude of reaction forces Fr thereupon, which tends to cause damage to cutting elements 16.
  • the potential damage to the cutting elements 16 caused by reaction forces Fr is further increased as the imbalance force Fi is directed toward the forward or leading portions of bearing surface 122 (as illustrated) or even rotationally leading the leading face 125 of the blade 124.
  • the cutting elements 16 are also subject to reaction forces Fr caused by bit whirl or other perturbations during drilling.
  • reaction forces Fr caused by bit whirl or other perturbations during drilling.
  • FIG. 4 shows a partial face view of a drill bit 210 schematically representing an imbalance force Fi and reaction forces Fr acting between a blade 224 and a boss 230 of a drill bit 210 in accordance with embodiments of the invention and a side wall 202 of a borehole 200 when drilling a subterranean formation.
  • a bearing surface 232 of the boss 230 is aligned with the imbalance force Fi and related reaction force Fr that is particularly directed toward the leading face 225 of the blade 224 absent the presence of boss 230.
  • the additional presence of leading surface 234 of boss 230 essentially alleviates any tendency, as exhibited in conventional drill bits, for the blade 224 to "bite" into the formation as drill bit 210 rotates and initiates whirl and other perturbations.
  • the boss 230 also increases the primary and second stability of the drill bit 210 by providing an increase in the total bearing surface, i.e., the first bearing surface 222 of blade 224 and the second bearing surface 232 of boss 230, which resultantly decreases instabilities, such as bit whirl, while primarily preventing against unintended direct impact of cutting elements 16 with the formation. It is recognized that the cutting elements 16 are designed to directly engage and shear material from a formation while moving primarily in the normal direction of bit rotation. Impact stress from reaction forces Fr, in a direction other than the intended direction of cutter movement, may potentially cause one of the cutting elements 16 to become chipped, cracked, or even dislodged from its attachment with the bit body 211.
  • the boss 230 allows the cutting elements 16 to be more efficiently positioned and oriented for cutting upon rotational movement of the bit body 211 about the axis 27 when drilling a formation, while reducing potential damage to the cutting elements 16 by bit whirl or other perturbations.
  • the boss 230 enables the imbalance force Fi to be radially directed substantially towards the first bearing surface 222 and the second bearing surface 232, as illustrated, thus providing improved protection for the cutting elements 16 as described herein.
  • a circumferentially extended bearing surface area enables greater accommodation of variations in the direction of imbalance force Fi under various drilling conditions and as cutting elements 16 wear.
  • the imbalance force Fi may be nominally centered on the combined circumferential extent of first and second bearing surfaces 222 and 232.
  • bosses according to embodiments of the present invention enables the circumferential width of the blades (not including the boss) to be reduced at the rotationally trailing side thereof, with the additional circumferential width being moved rotationally forward into the boss.
  • junk slot area may be easily preserved even with the presence of a boss rotationally forwardly protruding into a junk slot.
  • abrasion and impact resistant features may be placed upon the second bearing surface 232 of the boss 230 and/or the first bearing surface 222 of the blade 224.
  • the abrasion and impact resistant features may include low friction attributes known by a person having ordinary skill in the art.
  • FIG. 5 shows a face view of a drill bit 310 configured with bosses 330, 331, 333 in accordance with another embodiment of the invention. Reference may also be made to FIGS. 6A-6C showing partial perspective views of the bosses 330, 331, 333, as shown in FIG. 5.
  • the drill bit 310 comprises a bit body 311, three blades 324a, 324b, 324c, three open fluid courses 340, 341, 342, and three bosses 330, 331, 333.
  • the bit body 311 includes a face 314, a longitudinal axis (not shown) and a gage region 323. Each of the three blades 324a, 324b, 324c extends longitudinally and radially outward over the face 314 of the bit body 311.
  • Each of the three blades 324a, 324b, 324c either rotationally leads or trails another of the three blades 324a, 324b, 324c.
  • Each of the open fluid courses 340, 341, 342 extends between one of the three blades 324a, 324b, 324c, and another of the three blades 324a, 324b, 324c, in the gage region 323 of the bit body 311.
  • Each of the three bosses 330, 331, 333 is coupled to one of the three blades 324a, 324b, 324c and extends into one of the three open fluid courses 340, 341, 342, respectively.
  • Each of the three bosses 330, 331, 333 helps to reduce the tendency of drill bit 310 to whirl in operation and to minimize the impact stresses caused by bit whirl upon the cutting elements 16 when engaging the material of the formation being drilled.
  • the drill bit 310 may have fewer or greater number of open fluid courses than the three open fluid courses 340, 341, 342 illustrated.
  • the drill bit 310 may have fewer or greater number of blades than the three blades 324a, 324b, 324c illustrated.
  • the drill bit 310 may have bosses associated with fewer than all of the blades 324a, 324b, 324c as illustrated. For example, in the case of an intentionally significantly laterally imbalanced bit, it may be desirable to include only a single boss on the bit body in the gage area to which the lateral imbalance is directed.
  • Each boss 330, 331, 333 is located next to one of a first bearing surface 322 (see FIGS. 6A-6C) of each blade 324a, 324b, 324c substantially in the gage region 323 of the bit body 311.
  • Each boss 330, 331, 333 also includes a second bearing surface 332 (see FIGS. 6A-6C) located in the gage region 323 of the bit body 311.
  • the second bearing surface 332 of each boss 330, 331, 333 rotationally precedes the first bearing surface 322 of each blade 324a, 324b, 324c, respectively, about the axis with reference to the rotational direction of the drill bit 310.
  • first bearing surface 322 and the second bearing surface 332 of a select boss 330, 331, 333 and a blade 324a, 324b, 324c, respectively will be adjacently, or continuously, coupled together between the boss 330, 331, 333 and the respectively associated gage region 323 of the blade 324a, 324b, 324c, as illustrated, in order to provide a smooth, uninterrupted or transitionless engagement when impinging, or riding, upon, or making contact against the formation being drilled.
  • first bearing surface 322 and the second bearing surface 332 may include additional features thereupon to further improve the contact condition between the drill bit 310 and the formation being drilled, for example, by providing low friction bearing surfaces and abrasion-resistant surfaces, such as inserts, thereupon.
  • Each boss 330, 331, 333 respectively rotationally leads its associated blade 324a, 324b, 324c, and protrudes or extends from the face surface 325 thereof into its corresponding fluid course 315 proximate its juncture with an associated junk slot 317.
  • the bosses 330, 331, 333 advantageously reduce any potential for impact stress to the cutting elements 16 caused by contact with the formation by providing the second bearing surface 332 and a leading surface or edge 334.
  • the second bearing surface 332 and/or leading surface 334 of each boss 330, 331, 333 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.
  • first bearing surface 322 and the second bearing surface 332 provide surface area particularly suited for directing a designed imbalance force toward and against the side wall of the borehole allowing the drill bit 310 to ride thereupon, increasing the so-called “secondary” stability by reducing the tendency toward bit whirl, which ultimately improves and maintains the so-called “primary” stability by reducing impact stresses which cause fracture or chipping of the cutting elements 16.
  • the leading surface or edge 334 of the bosses 330, 331, 333 may be configured as a blunt leading edge 334 as shown in FIG. 6A, an oblique leading edge 334 as shown in FIG. 6B, or a rounded leading edge 334 as shown in FIG. 6C, respectively.
  • the leading edge 334 is substantially aligned with the axis of drill bit 310 in the gage region 323 of the bit body 311.
  • leading edge 334 provides a smooth transition between the second bearing surface 332 and the fluid course 315.
  • the leading edge 334 of any one of the bosses 330, 331, 333 may have the shape of a blunt, oblique or rounded leading edge, and may have any other suitable shape that is consistent with the disclosure herein presented.
  • the leading edges 334 take the brunt of the load on the blade during initiation of bit whirl or other lateral perturbation. Any one, or all, of the bosses 330, 331, 333 enhance stability of the drill bit.
  • any one of the bosses 330, 331, 333 may also be used to improve the hydraulic configuration of drill bit 310, by advantageously utilizing its stability improvements to circumferentially outwardly locate at least one nozzle port in one of the bosses 330, 331, 333 of the bit for improved removal of formation cuttings as described below.
  • Each of the bosses 330, 331, 333 further includes a plateau or land 350 and a nozzle port 328 extending into the land 350, the land 350 being substantially orthogonal to the axis of the bit body 310.
  • a nozzle 326 may be removably secured by a threaded engagement or other engagement into the nozzle port 328 allowing drilling fluid to be selectively directed towards the front blade surface 325 of the blade 324 substantially from the gage region 323 of the bit body 311.
  • the land 350 also allows the nozzle 326 to be selectively placed such that drilling fluid exiting the nozzle 326 from substantially the gage region 323 of the bit body 311 may be directed generally toward specific cutting elements 16 and having a selected radially outward, axial or inward orientation as desired, thus allowing for improved hydraulic configuration for cleaning and lubricating the cutting elements 16.
  • each of the bosses 330, 331, 333 includes a land 350 and a nozzle port 328 extending into the land 350, it is recognized that any or all of the bosses 330, 331, 333 may include fewer or more nozzle ports extending into the land 350 than illustrated.
  • the drill bit 310 also includes cutting elements 16 coupled to each of the blades.
  • cutting elements 16 may be configured, positioned and oriented to provide a selected, directed imbalance force upon rotational movement of the bit body 311, about its axis under weight-on-bit when drilling a borehole in a formation.
  • the imbalance force may be directed radially toward one of the novel bearing surfaces 332 as described above.
  • each of the "bearing surfaces,” as presented in the embodiments of the invention herein above, are defined as being substantially parallel with respect to a longitudinal, rotational axis of a bit body extending in the gage region at a substantially constant radius from the axis.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention concerne un foret qui comporte un bossage s'étendant de manière rotative à l'avant d'une ou plusieurs de ses lames, dans une région de calibrage du corps d'un foret pour augmenter la stabilité et réduire le choc à l'impact provoqué par la force de déséquilibre latéral agissant sur le foret lors du forage d'une formation souterraine. Le bossage comporte une surface d'appui ronde qui précède de manière rotative la surface d'appui ronde de la ou des lames. L'invention décrit également un foret qui comporte un bossage muni dans lequel s'étend un orifice de buse.
PCT/US2008/078401 2007-10-01 2008-10-01 Foret et outil de forage souterrain WO2009046069A2 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US11/865,296 2007-10-01
US11/865,296 US20090084606A1 (en) 2007-10-01 2007-10-01 Drill bits and tools for subterranean drilling

Publications (3)

Publication Number Publication Date
WO2009046069A2 true WO2009046069A2 (fr) 2009-04-09
WO2009046069A3 WO2009046069A3 (fr) 2009-07-02
WO2009046069A4 WO2009046069A4 (fr) 2009-10-08

Family

ID=40506907

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2008/078401 WO2009046069A2 (fr) 2007-10-01 2008-10-01 Foret et outil de forage souterrain

Country Status (2)

Country Link
US (1) US20090084606A1 (fr)
WO (1) WO2009046069A2 (fr)

Families Citing this family (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2010121116A2 (fr) * 2009-04-16 2010-10-21 Smith International, Inc. Trépan fixe à molettes pour des applications de forage directionnel
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
WO2011038383A2 (fr) * 2009-09-28 2011-03-31 Bake Hughes Incorporated Outils de forage, procédés de fabrication d'outils de forage et procédés de forage au moyen d'outils de forage
GB201302379D0 (en) 2013-01-16 2013-03-27 Nov Downhole Eurasia Ltd Drill bit
AR099499A1 (es) 2014-02-20 2016-07-27 Ulterra Drilling Tech Lp Broca o trépano
US10233696B2 (en) 2014-06-18 2019-03-19 Ulterra Drilling Technologies, L.P. Drill bit
US11015394B2 (en) * 2014-06-18 2021-05-25 Ulterra Drilling Technologies, Lp Downhole tool with fixed cutters for removing rock
US11480016B2 (en) 2018-11-12 2022-10-25 Ulterra Drilling Technologies, L.P. Drill bit

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR2627541A2 (fr) * 1986-11-04 1989-08-25 Vennin Henri Outil de forage monobloc rotatif
EP0728915A2 (fr) * 1995-02-16 1996-08-28 Baker Hughes Incorporated Méthode et dispositif de surveillance et d'enregistrement de conditions de l'opération d'un trépan de forage pendant le forage
EP0974730A2 (fr) * 1998-07-22 2000-01-26 Camco International (UK) Limited Trépan racleur

Family Cites Families (24)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5010789A (en) * 1989-02-21 1991-04-30 Amoco Corporation Method of making imbalanced compensated drill bit
CA1333282C (fr) * 1989-02-21 1994-11-29 J. Ford Brett Outil de forage a auto-equilibrage
US5042596A (en) * 1989-02-21 1991-08-27 Amoco Corporation Imbalance compensated drill bit
US4932484A (en) * 1989-04-10 1990-06-12 Amoco Corporation Whirl resistant bit
US4982802A (en) * 1989-11-22 1991-01-08 Amoco Corporation Method for stabilizing a rotary drill string and drill bit
GB8926688D0 (en) * 1989-11-25 1990-01-17 Reed Tool Co Improvements in or relating to rotary drill bits
US5186268A (en) * 1991-10-31 1993-02-16 Camco Drilling Group Ltd. Rotary drill bits
EP0569663A1 (fr) * 1992-05-15 1993-11-18 Baker Hughes Incorporated Trépan amélioré anti-tourbillon
US5558170A (en) * 1992-12-23 1996-09-24 Baroid Technology, Inc. Method and apparatus for improving drill bit stability
US5549171A (en) * 1994-08-10 1996-08-27 Smith International, Inc. Drill bit with performance-improving cutting structure
EP0707132B1 (fr) * 1994-10-15 2003-08-06 Camco Drilling Group Limited Trépan de forage rotatif
US5996713A (en) * 1995-01-26 1999-12-07 Baker Hughes Incorporated Rolling cutter bit with improved rotational stabilization
US5992548A (en) * 1995-08-15 1999-11-30 Diamond Products International, Inc. Bi-center bit with oppositely disposed cutting surfaces
US5722499A (en) * 1995-08-22 1998-03-03 Smith International, Inc. Multiple diamond layer polycrystalline diamond composite cutters
US6089336A (en) * 1995-10-10 2000-07-18 Camco International (Uk) Limited Rotary drill bits
US5904213A (en) * 1995-10-10 1999-05-18 Camco International (Uk) Limited Rotary drill bits
US5794725A (en) * 1996-04-12 1998-08-18 Baker Hughes Incorporated Drill bits with enhanced hydraulic flow characteristics
US5967247A (en) * 1997-09-08 1999-10-19 Baker Hughes Incorporated Steerable rotary drag bit with longitudinally variable gage aggressiveness
US6321862B1 (en) * 1997-09-08 2001-11-27 Baker Hughes Incorporated Rotary drill bits for directional drilling employing tandem gage pad arrangement with cutting elements and up-drill capability
US6230828B1 (en) * 1997-09-08 2001-05-15 Baker Hughes Incorporated Rotary drilling bits for directional drilling exhibiting variable weight-on-bit dependent cutting characteristics
US6260636B1 (en) * 1999-01-25 2001-07-17 Baker Hughes Incorporated Rotary-type earth boring drill bit, modular bearing pads therefor and methods
US6834733B1 (en) * 2002-09-04 2004-12-28 Varel International, Ltd. Spiral wave bladed drag bit
US8061453B2 (en) * 2006-05-26 2011-11-22 Smith International, Inc. Drill bit with asymmetric gage pad configuration
US20070278014A1 (en) * 2006-05-30 2007-12-06 Smith International, Inc. Drill bit with plural set and single set blade configuration

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR2627541A2 (fr) * 1986-11-04 1989-08-25 Vennin Henri Outil de forage monobloc rotatif
EP0728915A2 (fr) * 1995-02-16 1996-08-28 Baker Hughes Incorporated Méthode et dispositif de surveillance et d'enregistrement de conditions de l'opération d'un trépan de forage pendant le forage
EP0974730A2 (fr) * 1998-07-22 2000-01-26 Camco International (UK) Limited Trépan racleur

Also Published As

Publication number Publication date
US20090084606A1 (en) 2009-04-02
WO2009046069A4 (fr) 2009-10-08
WO2009046069A3 (fr) 2009-07-02

Similar Documents

Publication Publication Date Title
US10851594B2 (en) Kerfing hybrid drill bit and other downhole cutting tools
US7798257B2 (en) Shaped cutter surface
CA2505710C (fr) Surface formee d'elements de coupe
US5119892A (en) Notary drill bits
US20090084606A1 (en) Drill bits and tools for subterranean drilling
CA2675270C (fr) Tete de coupe rotative et procedes associes
US8127869B2 (en) Earth-boring tools, methods of making earth-boring tools and methods of drilling with earth-boring tools
EP2220330B1 (fr) Trépans et outils de forage souterrain
WO2013085869A1 (fr) Éléments coupants rotatifs pour trépans p.d.c.
US8079430B2 (en) Drill bits and tools for subterranean drilling, methods of manufacturing such drill bits and tools and methods of off-center drilling
CA3034511A1 (fr) Ensemble element roulant dote d'un dispositif de retenue souple
US9464490B2 (en) Gage cutter protection for drilling bits
US20090084607A1 (en) Drill bits and tools for subterranean drilling
CA3024117A1 (fr) Element roulant a demi-verrouillage

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 08834723

Country of ref document: EP

Kind code of ref document: A2

WWE Wipo information: entry into national phase

Ref document number: 2008834723

Country of ref document: EP

NENP Non-entry into the national phase

Ref country code: DE