1. Technical Field
The present invention relates in general to earth-boring drill bits and, in particular, to a bit having a combination of rolling and fixed cutters and cutting elements and a method of drilling with same.
2. Description of the Related Art
The success of rotary drilling enabled the discovery of deep oil and gas reservoirs and production of enormous quantities of oil. The rotary rock bit was an important invention that made the success of rotary drilling possible. Only soft earthen formations could be penetrated commercially with the earlier drag bit and cable tool, but the two-cone rock bit, invented by Howard R. Hughes, U.S. Pat. No. 930,759, drilled the caprock at the Spindletop field, near Beaumont, Tex. with relative ease. That venerable invention, within the first decade of the last century, could drill a scant fraction of the depth and speed of the modern rotary rock bit. The original Hughes bit drilled for hours, the modern bit drills for days. Modern bits sometimes drill for thousands of feet instead of merely a few feet. Many advances have contributed to the impressive improvements in rotary rock bits.
In drilling boreholes in earthen formations using rolling-cone or rolling-cutter bits, rock bits having one, two, or three rolling cutters rotatably mounted thereon are employed. The bit is secured to the lower end of a drillstring that is rotated from the surface or by a downhole motor or turbine. The cutters mounted on the bit roll and slide upon the bottom of the borehole as the drillstring is rotated, thereby engaging and disintegrating the formation material to be removed. The rolling cutters are provided with cutting elements or teeth that are forced to penetrate and gouge the bottom of the borehole by weight from the drillstring. The cuttings from the bottom and sides of the borehole are washed away by drilling fluid that is pumped down from the surface through the hollow, rotating drillstring, and are carried in suspension in the drilling fluid to the surface.
Rolling-cutter bits dominated petroleum drilling for the greater part of the 20th century. With improvements in synthetic or manmade diamond technology that occurred in the 1970s and 1980s, the fixed-cutter, or “drag” bit became popular again in the latter part of the 20th century. Modern fixed-cutter bits are often referred to as “diamond” or “PDC” (polycrystalline diamond compact) bits and are far removed from the original fixed-cutter bits of the 19th and early 20th centuries. Diamond or PDC bits carry cutting elements comprising polycrystalline diamond compact layers or “tables” formed on and bonded to a supporting substrate, conventionally of cemented tungsten carbide, the cutting elements being arranged in selected locations on blades or other structures on the bit body with the diamond tables facing generally in the direction of bit rotation. Diamond bits have an advantage over rolling-cutter bits in that they generally have no moving parts. The drilling mechanics and dynamics of diamond bits are different from those of rolling-cutter bits precisely because they have no moving parts. During drilling operation, diamond bits are used in a manner similar to that for rolling cutter bits, the diamond bits also being rotated against a formation being drilled under applied weight on bit to remove formation material. Engagement between the diamond cutting elements and the borehole bottom and sides shears or scrapes material from the formation, instead of using a crushing action as is employed by rolling-cutter bits. Rolling-cutter and diamond bits each have particular applications for which they are more suitable than the other; neither type of bit is likely to completely supplant the other in the foreseeable future.
In the prior art, some earth-boring bits use a combination of one or more rolling cutters and one or more fixed blades. Some of these combination-type drill bits are referred to as hybrid bits. Previous designs of hybrid bits, such as is described in U.S. Pat. No. 4,343,371, to Baker, III, have provided for the rolling cutters to do most of the formation cutting, especially in the center of the hole or bit. Other types of combination bits are known as “core bits,” such as U.S. Pat. No. 4,006,788, to Garner. Core bits typically have truncated rolling cutters that do not extend to the center of the bit and are designed to remove a core sample of formation by drilling down, but around, a solid cylinder of the formation to be removed from the borehole generally intact.
Another type of hybrid bit is described in U.S. Pat. No. 5,695,019, to Shamburger, Jr., wherein the rolling cutters extend almost entirely to the center. Fixed cutter inserts 50 (
Although each of these bits is workable for certain limited applications, an improved hybrid earth-boring bit with enhanced drilling performance would be desirable.
Embodiments of the present invention comprise an improved earth-boring bit of the hybrid variety. One embodiment comprises an earth-boring bit including a bit body configured at its upper extent for connection into a drillstring, the bit body having a central axis and a radially outermost gage surface. At least one fixed blade extends downward from the bit body in the axial direction, the at least one fixed blade having a leading edge and a trailing edge. At least one rolling cutter is mounted for rotation on the bit body, the at least one rolling cutter having a leading side and a trailing side. At least one nozzle is mounted in the bit body proximal the central axis. The nozzle is arranged to direct a stream of pressurized drilling fluid between the leading edge of the fixed blade and the trailing side of the rolling cutter. At least one rolling-cutter cutting element, which also may be termed “inserts” or “rolling-cutter cutting elements” are arranged on the rolling cutter and radially spaced apart from the central axis of the bit body. A plurality of cutting elements, hereinafter referred to as “fixed-blade cutting elements” for convenience are arranged on the leading edge of the at least one fixed blade. At least one of the fixed-blade cutting elements on the at least one fixed blade is located proximal the central axis of the bit.
According to an embodiment of the present invention, the rolling-cutter cutting elements and the fixed-blade cutting elements combine to define a cutting profile that extends from substantially the central axis to the gage surface of the bit body, the fixed-blade cutting elements forming a substantial portion of the cutting profile at the central axis and the gage surface, and the rolling-cutter cutting elements overlapping the cutting profile of the fixed-blade cutting elements between the axial center and the gage surface.
According to an embodiment of the present invention, a junk slot is formed between the trailing side of the at least one rolling cutter, the leading edge of the at least one fixed blade, and a portion of the bit body, the junk slot providing an area for removal of disintegrated formation material, the junk slot being equal to or larger in at least an angular dimension than a space between the leading side of the at least one rolling cutter and the trailing edge of the at least one fixed blade.
According to an embodiment of the present invention, the at least one nozzle arrangement further comprises at least one fixed blade nozzle proximal the central axis of the bit body, each fixed blade nozzle arranged to direct a stream of drilling fluid toward the fixed-blade cutting elements; and at least one rolling cutter nozzle spaced from the central axis of the bit body, each rolling cutter nozzle arranged to direct a stream of drilling fluid toward a rolling cutter.
According to an embodiment of the present invention, at least one of the fixed cutting elements is within approximately 0.040 inches of the central axis of the bit body.
According to an embodiment of the present invention, at least one backup cutting element is located between the leading and trailing edges of the at least one fixed blade.
According to an embodiment of the present invention, each backup cutting element is aligned with one of the fixed-blade cutting elements on the leading edge of the at least one fixed blade.
According to an embodiment of the present invention, there is a plurality of backup cutting elements arranged on a fixed blade in at least one row extending generally parallel to the leading edge of the blade and rotationally behind the cutting elements on the leading edge of the blade.
Other features and advantages of embodiments of the earth-boring bit according to the present invention will become apparent with reference to the drawings and the detailed description of the invention.
So that the manner in which the features and advantages of the present invention, which will become apparent, are attained and can be understood in more detail, more particular description of embodiments of the invention as briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the appended drawings which form a part of this specification. It is to be noted, however, that the drawings illustrate only some embodiments of the invention and therefore are not to be considered limiting of its scope as the invention may admit to other equally effective embodiments.
Referring to
The radially outermost surface of the bit body 13 is known as the gage surface and corresponds to the gage or diameter of the borehole (shown in phantom in
A rolling cutter 21 is mounted on a sealed journal bearing that is part of each bit leg 17. According to the illustrated embodiment, the rotational axis of each rolling cutter 21 intersects the axial center 15 of the bit. Sealed or unsealed journal or rolling-element bearings may be employed as cutter bearings. Each of the rolling cutters 21 is formed and dimensioned such that the radially innermost ends of the rolling cutters 21 are radially spaced apart from the axial center 15 (
At least one (a plurality are illustrated) rolling-cutter cutting inserts or elements 25 are arranged on the rolling cutters 21 in generally circumferential rows thereabout such that each cutting element 25 is radially spaced apart from the axial center 15 by a minimal radial distance 27 of about 0.30 inch. The minimal radial distances 23, 27 may vary according to the application and bit size, and may vary from cone to cone, and/or cutting element to cutting element, an objective being to leave removal of formation material at the center of the borehole to the fixed-blade cutting elements 31 (rather than the rolling-cutter cutting elements 25). Rolling-cutter cutting elements 25 need not be arranged in rows, but instead could be “randomly” placed on each rolling cutter 21. Moreover, the rolling-cutter cutting elements may take the form of one or more discs or “kerf-rings,” which would also fall within the meaning of the term rolling-cutter cutting elements.
Tungsten carbide inserts, secured by interference fit into bores in the rolling cutter 21 are shown, but a milled- or steel-tooth cutter having hardfaced cutting elements (25) integrally formed with and protruding from the rolling cutter could be used in certain applications and the term “rolling-cutter cutting elements” as used herein encompasses such teeth. The inserts or cutting elements may be chisel-shaped as shown, conical, round, or ovoid, or other shapes and combinations of shapes depending upon the application. Rolling-cutter cutting elements 25 may also be formed of, or coated with, superabrasive or super-hard materials such as polycrystalline diamond, cubic boron nitride, and the like.
In addition, a plurality of fixed or fixed-blade cutting elements 31 are arranged in a row and secured to each of the fixed blades 19 at the leading edges thereof (leading being defined in the direction of rotation of bit 11). Each of the fixed-blade cutting elements 31 comprises a polycrystalline diamond layer or table on a rotationally leading face of a supporting substrate, the diamond layer or table providing a cutting face having a cutting edge at a periphery thereof for engaging the formation. At least a portion of at least one of the fixed cutting elements 31 is located near or at the axial center 15 of the bit body 13 and thus is positioned to remove formation material at the axial center of the borehole (typically, the axial center of the bit will generally coincide with the center of the borehole being drilled, with some minimal variation due to lateral bit movement during drilling). In a 7⅞ inch bit as illustrated, the at least one of the fixed cutting elements 31 has its laterally innermost edge tangent to the axial center of the bit 11 (as shown in
Fixed-blade cutting elements 31 radially outward of the innermost cutting element 31 are secured along portions of the leading edge of blade 19 at positions up to and including the radially outermost or gage surface of bit body 11. In addition to fixed-blade cutting elements 31 including polycrystalline tables mounted on tungsten carbide substrates, such term as used herein encompasses thermally stable polycrystalline diamond (TSP) wafers or tables mounted on tungsten carbide substrates, and other, similar superabrasive or super-hard materials such as cubic boron nitride and diamond-like carbon. Fixed-blade cutting elements 31 may be brazed or otherwise secured in recesses or “pockets” on each blade 19 so that their peripheral or cutting edges on cutting faces are presented to the formation.
Four nozzles 63, 65 are generally centrally located in receptacles in the bit body 13. A pair of fixed blade nozzles 63 is located close or proximal to the axial center 15 of the bit 11. Fixed blade nozzles 63 are located and configured to direct a stream of drilling fluid from the interior of the bit to a location at least proximate (preferably forward of to avoid unnecessary wear on elements 31 and the material surrounding and retaining them) at least a portion of the leading edge of each fixed blade 19 and the fixed-blade cutting elements 31 carried thereon (
In connection with the nozzles, a pair of junk slots 71 are provided between the trailing side of each rolling cutter 21, and the leading edge of each fixed blade 19 (leading and trailing again are defined with reference to the direction of rotation of the bit 11). Junk slots 71 provide a generally unobstructed area or volume for clearance of cuttings and drilling fluid from the central portion of the bit 11 to its periphery for return of these materials to the surface. As shown in
Also provided on each fixed blade 19, between the leading and trailing edges, are a plurality of backup cutters or cutting elements 81 arranged in a row that is generally parallel to the leading edge of the blade 19. Backup cutters 81 are similar in configuration to fixed blade cutters or cutting elements 31, but may be smaller in diameter or more recessed in a blade 19 to provide a reduced exposure above the blade surface than the exposure of the primary fixed-blade cutting elements 31 on the leading blade edges. Alternatively, backup cutters 81 may comprise BRUTE™ cutting elements as offered by the assignee of the present invention through its Hughes Christensen operating unit, such cutters and their use being disclosed in U.S. Pat. No. 6,408,958. As another alternative, rather than being active cutting elements similar to fixed blade cutters 31, backup cutters 81 could be passive elements, such as round or ovoid tungsten carbide or superabrasive elements that have no cutting edge (although still referred to as backup cutters or cutting elements). Such passive elements would serve to protect the lower surface of each blade 19 from wear.
Preferably, backup cutters 81 are radially spaced along the blade 19 to concentrate their effect in the nose, shoulder, and gage areas (as described below in connection with
In addition to backup cutters 81, a plurality of wear-resistant elements 83 are present on the gage surface at the outermost periphery of each blade 19 (
Cutter 101 of
As illustrated and previously mentioned, the radially innermost fixed-blade cutting element 31 preferably is substantially tangent to the axial center 15 of the bit 11. The radially innermost lateral or peripheral portion of the innermost fixed cutting element should preferably be no more than 0.040 inch from the axial center 15. The radially innermost rolling-cutter cutting element 25 (other than the cutter nose elements, which do not actively engage the formation), is spaced apart a distance 29 of about 2.28 inch from the axial center 15 of the bit for the 7⅞ inch bit illustrated.
Thus, the rolling-cutter cutting elements 25 and the fixed-blade cutting elements 31 combine to define a congruent cutting face in the nose 45 and shoulder 47 (
A reference plane 51 (
In another embodiment, rolling-cutter cutting elements 25 may extend beyond (e.g., by approximately 0.060-0.125 inch) the distal-most position of the fixed blades 19 and fixed-blade cutting elements 31 to compensate for the difference in wear between those components. As the profile 41 transitions from the shoulder 47 to the gage 43 of the hybrid bit 11, the rolling-cutter elements 25 no longer engage the formation (see
The invention has several advantages and includes providing a hybrid drill bit that cuts at the center of the hole solely with fixed cutting elements and not with rolling cutters. The fixed-blade cutting elements are highly efficient at cutting the center of the hole. Moreover, due to the relatively low cutting velocity of the fixed-blade cutting elements in the center due to their proximity to the central axis of the bit body, the polycrystalline diamond compact or other superabrasive cutting elements are subject to little or no wear. The rolling cutters and their cutting elements are configured to cut a nearly congruent surface (with the cutting elements on the fixed blade) and thereby enhance the cutting action of the blades in the most difficult to drill nose and shoulder areas, which are the leading profile section (axially speaking) and thus are subjected to high wear and vibration damage in harder, more abrasive formations. The crushing action of the tungsten carbide rolling cutter inserts drives deep fractures into the hard rock, which greatly reduces its strength. The pre- or partially fractured rock is easier to remove and causes less damage and wear to the fixed-blade cutting elements than pristine formation material commonly drilled by conventional diamond or PDC cutting element-equipped drag bits. The perimeter or gage of the borehole is generated with multiple, vertically-staggered rows of fixed-blade cutting elements. This leaves a smooth borehole wall and reduces the sliding and wear on the less wear-resistant rolling cutter inserts.
While the invention has been shown or described in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes without departing from the scope of the invention as hereinafter claimed, and legal equivalents thereof.
This application is a continuation-in-part of co-pending application Ser. No. 11/784,025, filed Apr. 5, 2007, entitled FIXED CUTTERS AS THE SOLE CUTTING ELEMENTS IN THE AXIAL CENTER OF THE DRILL BIT.
Number | Date | Country | |
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Parent | 11784025 | Apr 2007 | US |
Child | 12061536 | US |