EP0325272B1

EP0325272B1 - Drill bit with improved steerability

Info

Publication number: EP0325272B1
Application number: EP19890100960
Authority: EP
Inventors: Gordon A. Tibbitts; Mark L. Jones
Original assignee: Eastman Teleco Co
Current assignee: Baker Hughes Oilfield Operations LLC
Priority date: 1988-01-20
Filing date: 1989-01-20
Publication date: 1993-04-28
Anticipated expiration: 2009-01-20
Also published as: CA1306245C; DE68906166T2; AU613142B2; DE68906166D1; AU2858589A; EP0325272A3; EP0325272A2

Description

The present invention relates generally to a drill bit as set forth in the pre-characterizing portion of claim 1.
Conventional drill bits (US-A-4 176 723 and US-A-2 553 701) typically include one or more cutting surfaces to initially cut the gage of the borehole, i.e., the nominal diameter of the borehole. The gage cutting elements defining the cutting surface may be one of any of the conventional types of cutting elements.
Additionally, conventional drill bits (US-A-3 318 400) typically include gage pads extending along the side of the bit to contact the sides of the borehole (as cut and defined by the gage cutting elements), to help maintain stability of the bit. Conventional gage pads typically provide relatively broad contact surfaces extending along 30-60% of the radial periphery of the bit. These gage pads are typically formed of diamond impregnated pads, of pads including vertical rows of diamonds (referred to as "broach stones") or of other wear-resistent materials such as tungsten carbide slugs. With the diamond impregnated pads, the diamond impregnation is utilized primarily to provide abrasion resistance to the bit gage pad as it rotates within the wellbore. The broach stone gage cutters are typically conformed to provide a minimal cutting capability to the gage pad. In summary, the primary purpose of gage pads in conventional bits is to maintain hole diameter and resist deviation from the borehole axis.
The drilling of angled or "deviated" wellbores has been known for many years. However, techniques for drilling deviated wellbores through navigational drilling techniques are becoming increasingly sophisticated. These navigational drilling techniques may benefit from drill bits with improved steerability, i.e., an ability to respond to directional loading forces applied by steering apparatus. Drill bits heretofore utilized for navigational drilling have, however, typically been of the conventional types as described above. However, such bits are better adapted, because of their gage design, for straight, rather than deviated, drilling of wellbores.
Accordingly, it is an object of the invention to provide a new and improved drill bit which will exhibit improved steerability relative to conventional designs, thereby providing optimal performance in directional and navigational drilling environments.
The improvement is a drill bit as claimed in claim 1. Drill bits in accordance with the present invention facilitate the bit's cutting an arcuate or curved path in a formation in response to side loading of the bit. The gage of the bit is adapted to minimize contact with the side of the borehole and allows the bit to turn within the formation while the upper gage section will assure that the hole size is maintained throughout the turn while acting as a fulcrum to bit deviation.
Figs. 1A-B depict a first embodiment of a drill bit in accordance with the present invention. Fig. 1A depicts the drill bit from a side view. Fig. 1B schematically depicts the drill bit of Fig. 1A in an earth borehole, illustrated in vertical section.
Figs. 2A-B depict an alternative embodiment of a drill bit in accordance with the present invention. Fig. 2A depicts the drill bit from a side view. Fig. 2B depicts the drill bit in a partial, bottom plan view.
Referring not to Figs. 1A and 1B, therein is depicted a first embodiment of a drill bit 70 in accordance with the present invention. Drill bit 70 includes a body member 72 and a plurality of cutting pads 74. Cutting pads 74 each preferably extend radially, and may eventually be vertical, from proximate the longitudinal axis of drill bit 70 to lower gage line 76 of bit 70. Each cutting pad 74 again may surround a central aperture 78 to provide dedicated hydraulic flow across cutting pad 74.
Drill bit 70 also includes an upper gage section, indicated generally at 80. Upper gage section defines an upper gage line 94 which is separated from lower gage line 76 by a separation distance 82. Upper gage section 80 includes a plurality of vertical gage cutting pads distributed around the periphery of drill bit 70. The portions of gage cutters 84 within separation distance include a radius 92 terminating at gage dimension. Upper gage section cutters are depicted as including cutting elements across their entire surface. In some configurations, it may be desirable to include cutting elements only proximate the lower portion of gage cutting pads 84 and to establish the upper portion of each gage pad 84 as merely a diamond impregnated pad, as previously described herein.
When drill bit 70 is operated to drill a nonlinear borehole path, separation distance 82 provides a relief to facilitate deflection of bit 70 and to thereby facilitate the drilling of the nonlinear path, because the cutting pads 74 do not have excessive resistance to side loading as in conventional bits, and gage cutting pads 84 provide a contact point against which bit 70 may turn. Since lower cutting pads 74 extend only a minimal distance above lower gage line 76, when side load forces are placed on drill bit 70, there is relatively minimal resistance to lateral cutting of the formation. Because of the dimensional relief provided by separation distance 82, upper gage line 94 may be considered the location of a fulcrum on the interior of the arc around which drill bit 70 can deflect. As more and more of cutting pads 84 encounter the formation, the resistance to deflection of drill bit 70 within the formation will increase. The separation distance, therefore, in combination with the number and size or upper gage cutting pads 84 and the cutting element distribution on each pad 84 will cooperatively serve to define a radius which drill bit 70 can optimally traverse. It will be apparent that the dimension of separation distance may vary between different embodiments of bits. However, by way of example only, separation distances or from 1.25 inches to 3 inches may potentially advantageously be utilized in embodiments of bit 70. Although upper gage section 80 of drill bit 70 is depicted as having vertically arranged cutting pads, these cutting pads could easily be arranged in spiraled or other curvilinear shapes along their respective portions of the periphery of drill bit 70.
It will be understood by one of ordinary skill in the art that references herein to cutting or holding a gage dimension while the bit is traversing a nonlinear path are not meant to imply that the borehole is of perfect gage, or even symmetrical. Turning a bit will normally result in an oversized, generally elliptical cross-section, hole, with its longer dimension parallel to the direction of the turn. In some instances, as for example where the turn is not entirely planar, a generally circular but oversized hole (in all radial dimensions) may result.
It will also be appreciated that the use of the present invention in a bit may also be employed to reduce, enhance or otherwise control the bit's tendency to "sidetrack" to the right or left by varying its resistance to lateral displacement in the borehole.
Referring now to Fig. 2A-B, therein is depicted an alternative embodiment of a drill bit 50 in accordance with the present invention. Drill bit 50 includes a plurality of bottom cutting pads 52, 54 which extend generally radially along the periphery of drill bit 50. Cutting pads 52 cut primarily along the bottom surface when drill bit 50 is operated within a formation, while cutting pads 54 extend to the gage 56 of bit 50. Cutting pads 52 thus extend from proximate the longitudinal axis of drill bit 50 to generally vertical above gage line 56. Each cutting pad 52, 54 preferably exhibits a generally triangular form along the periphery of drill bit 50. Each cutting pad 52, 54 may again, as in bit 30 of Fig. 2, be a generally continuous pad surrounding a central aperture 58, 60, respectively, to provide a dedicated hydraulic flow across each cutting pad 52, 54.
Drill bit 50 further includes discrete gage cutting pads 62 which are preferably disposed in generally radial alignment with cutting pads 52. Gage cutting pads 62 preferably include cutting elements suitable for cutting the formations which bottom cutting pads are designed to cut. Preferably, each gage cutting pad 62 will have cutting elements arranged primarily on the lower portion, for example the lower two-thirds, of the pad 62. This allows the lower portion of the gage cutting pad 62 to cut freely into the formation, while the upper portions will tend to function as a stand-off for bit 50. The upper portions of gage cutting pad 62 will preferably be formed of an abrasion resistant material, such as a diamond impregnated matrix, as discussed earlier herein.
The distribution and sizing of discrete gage cutting pads 62 establishes a relatively wide angle (φ) 64 between adjacent leading and trailing edges of neighboring gage cutting pads 62. Each gage cutting pad 62 extends upwardly from a position at or below gage line 56.
In operation, as drill bit 50 is rotated and deflected within a borehole, these discrete gage cutting pads 62 will facilitate optimal steerability for bit 50. As drill bit 50 begins to cut an arc, the surfaces which normally tend to oppose deflection of the bit are gage cutting pads 62. However, because of the spacing of gage cutting pads 62, there is a distance around the periphery of drill bit 50, as a result of the angular spacing represented by angle (φ) 64, which will not oppose deflection of bit 50. By way of illustration only, drill bit 50 may be considered as being capable of deflecting around a fulcrum defined by the adjacent leading and trailing edges of adjacent gage cutting pads 62, as indicated generally along dashed line 66 in Figures 3A-B or around a fulcrum 68 defined by the corresponding edges of cutting pads 54. Accordingly, as drill bit 50 is deflected and rotated within the formation, each pad cutting the gage dimension, 54, 62, will take a progressively deeper cut to the inner side of the arc trajectory, facilitating the cutting of the arc. Further, as the full dimension of the gage cutting pads 62 traverses downwardly through the formations, they will continue to cut the gage dimension.
The cooperative arrangement of cutting pads 54 extending to the gage of bit 50, and the spaced distribution of relatively narrow gage cutting pads 62, as depicted on drill bit 50, serves to concentrate side loading on drill bit 50 when drill bit 50 is operated in a formation such that the side load is applied primarily to the side and gage cutting portions of the bit encountering the formation. Accordingly, the bit does not provide an undesirable resistance to steering along a desired nonlinear path, as is the case with prior art bits.

Claims

Drill bit (50,70) for drilling a bore hole in an earth formation and comprising a body member (72), a bottom cutting means including a plurality of bottom cutting portions, and a gage cutting means having a plurality of gage cutting portions (52,54,62,74,84) peripherally spaced on the drill bit (50,70), characterized in that the gage cutting means comprises an upper gage cutting section and a separate lower gage cutting section, either of the gage cutting sections being concentric to the bit axis, the gage cutting portions (62,84) of the upper gage cutting section being spaced in the longitudinal direction of the bit from the longitudinally adjacent gage cutting portions (52,74) of the lower gage cutting section, thereby defining a separation distance of lesser diameter than the longitudinally adjacent cutting portions (52,62;74,84) facilitating the deflection of the drill bit (50,70) when the drill bit (50,70) is operated to drill a nonlinear bore hole path in the formation.
The drill bit of claim 1, wherein at least some of said gage cutting portions are generally vertically oriented on said drill bit.
The drill bit of claim 1, wherein said second gage cutting section (62,84) on said drill bit includes surface set diamonds (19) as cutting elements.
The drill bit of claim 1, wherein said second gage cutting section comprises cutting pads (62,84) having surface set diamonds (19) disposed thereon as cutting elements.
The drill bit of claim 1, wherein said plurality of cutting elements comprises surface set diamonds (19).