Boring or penetrating the earth – Bit or bit element – Specific or diverse material
Reexamination Certificate
1997-09-08
2001-05-15
Lillis, Eileen D. (Department: 3673)
Boring or penetrating the earth
Bit or bit element
Specific or diverse material
Reexamination Certificate
active
06230828
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates generally to rotary bits for drilling subterranean formations. More specifically, the invention relates to fixed cutter or so-called “drag” bits suitable for directional drilling, wherein cutting edge chamfer geometries are varied at different locations or zones on the face of the bit, the variations being tailored to enhance response of the bit to sudden variations in load and improve stability of the bit as well as rate of penetration (ROP).
2. State of the Art
In state-of-the-art directional drilling of subterranean formations, also sometimes termed steerable or navigational drilling, a single bit disposed on a drill string, usually connected to the drive shaft of a downhole motor of the positive-displacement (Moineau) type, is employed to drill both linear and non-linear borehole segments without tripping of the string from the borehole. Use of a deflection device such as a bent housing, bent sub, eccentric stabilizer, or combinations of the foregoing in a bottomhole assembly (BHA), including a motor, permits a fixed rotational orientation of the bit axis at an angle to the drill string axis for non-linear drilling when the bit is rotated solely by the motor drive shaft. When the drill string is rotated in combination with rotation of the motor shaft, the superimposed rotational motions cause the bit to drill substantially linearly. Other directional methodologies employing non-rotating BHAs using lateral thrust pads or other members immediately above the bit also permit directional drilling using drill string rotation alone.
In either case, for directional drilling of non-linear borehole segments, the face aggressiveness (aggressiveness of the cutters disposed on the bit face) is a critical feature, since it is largely determinative of how a given bit responds to sudden variations in bit load. Unlike roller cone bits, rotary drag bits employing fixed superabrasive cutters (usually comprising polycrystalline diamond compacts, or “PDCs”) are very sensitive to load, which sensitivity is reflected in a much steeper rate of penetration (ROP) versus weight on bit (WOB) and torque on bit (TOB) versus WOB curves, as illustrated in
FIGS. 1 and 2
of the drawings. Such high WOB sensitivity causes problems in directional drilling, wherein the borehole geometry is irregular and resulting “sticktion” of the BHA when drilling a non-linear path renders a smooth, gradual transfer of weight to the bit extremely difficult. These conditions frequently cause motor stalling, and loss or swing of tool face orientation. When tool face is lost, borehole quality declines. In order to establish a new tool face reference point before drilling is recommenced, the driller must stop drilling ahead and pull the bit off the bottom of the borehole, with a resulting loss of time and thus ROP. Conventional methods to reduce rotary drag bit face aggressiveness include greater cutter densities, higher (negative) cutter backrakes and the addition of wear knots to the bit face.
Of the bits referenced in
FIGS. 1 and 2
of the drawings, RC comprises a conventional roller cone bit for reference purposes, while FC
1
is a conventional polycrystalline diamond compact (PDC) cutter-equipped rotary drag bit having cutters backraked at 20°, while FC
2
is the directional version of the same bit with 30° backraked cutters. As can be seen from
FIG. 2
, the TOB at a given WOB for FC
2
, which corresponds to its face aggressiveness, can be as much as 30% less than for FC
1
. Therefore, FC
2
is less affected by the sudden load variations inherent in directional drilling. However, referencing
FIG. 1
, it can also be seen that the less aggressive FC
2
bit exhibits a markedly reduced ROP for a given WOB, in comparison to FIG.
2
.
Thus, it may be desirable for a bit to demonstrate the less aggressive characteristics of a conventional directional bit such as FC
2
for non-linear drilling without sacrificing ROP to the same degree when WOB is increased to drill a linear borehole segment.
For some time, it has been known that forming a noticeable, annular chamfer on the cutting edge of the diamond table of a PDC cutter has enhanced durability of the diamond table, reducing its tendency to spall and fracture during the initial stages of a drilling operation before a wear flat has formed on the side of the diamond table and supporting substrate contacting the formation being drilled.
U.S. Pat. No. Re 32,036 to Dennis discloses such a chamfered cutting edge, disc-shaped PDC cutter comprising a polycrystalline diamond table formed under high pressure and high temperature conditions onto a supporting substrate of tungsten carbide. For conventional PDC cutters, a typical chamfer size and angle would be 0.010 inch (measured radially and looking at and perpendicular to the cutting face) oriented at a 45° angle with respect to the longitudinal cutter axis, thus providing a larger radial width as measured on the chamfer surface itself. Multi-chamfered PDC cutters are also known in the art, as taught by Cooley et al. U.S. Pat. No. 5,437,343, assigned to the assignee of the present invention. Rounded, rather than chamfered, cutting edges are also known, as disclosed in U.S. Pat. No. 5,016,718 to Tandberg.
For some period of time, the diamond tables of PDC cutters were limited in depth or thickness to about 0.030 inch or less, due to the difficulty in fabricating thicker tables of adequate quality. However, recent process improvements have provided much thicker diamond tables, in excess of 0.070 inch, up to and including 0.150 inch. U.S. patent application Ser. No. 08/602,076, now U.S. Pat. No. 5,706,906, assigned to the assignee of the present invention, discloses and claims several configurations of a PDC cutter employing a relatively thick diamond table. Such cutters include a cutting face bearing a large chamfer or “rake land” thereon adjacent the cutting edge, which rake land may exceed 0.050 inch in width, measured radially and across the surface of the rake land itself. Other cutters employing a relatively large chamfer without such a great depth of diamond table are also known.
Recent laboratory testing, as well as field tests, have conclusively demonstrated that one significant parameter affecting PDC cutter durability is the cutting edge geometry. Specifically, larger leading chamfers (the first chamfer on a cutter to encounter the formation when the bit is rotated in the normal direction) provide more durable cutters. The robust character of the above-referenced “rake land” cutters corroborates these findings. However, it was also noticed that cutters exhibiting large chamfers would also slow the overall performance of a bit so equipped, in terms of ROP. This characteristic of large chamfer cutters was perceived as a detriment.
BRIEF SUMMARY OF THE INVENTION
The inventors herein have recognized that varying chamfer size and chamfer rake angle of various PDC cutters as a function of, or in relationship to, cutter redundancy at varying radial locations on the bit face may be employed to provide a bit exhibiting relatively low aggressiveness and good stability while affording adequate side cutting capability for non-linear drilling, as well as providing greater ROP when drilling linear borehole segments than conventional directional or steerable bits with highly backraked cutters.
The present invention comprises a rotary drag bit equipped with PDC cutters, wherein cutters in the low cutter redundancy center region of the bit exhibit a relatively large chamfer and are oriented at a relatively large backrake, while chamfer size, as well as chamfer rake angle decreases in cutters located more toward the outer region, or gage, of the bit, wherein higher cutter redundancy is employed.
Such a bit design noticeably changes the ROP and TOB versus WOB characteristics for the bit from the linear, single slope curves shown in
FIGS. 1 and 2
for FC
1
and FC
2
to exponential, dual-slope curves as shown with respect to a bit FC
3
according to the inventio
Beuershausen Christopher C.
Dykstra Mark W.
Fincher Roger
Illerhaus Roland
Matson Steve R.
Baker Hughes Incorporated
Britt Trask
Lillis Eileen D.
Singh Sunil
LandOfFree
Rotary drilling bits for directional drilling exhibiting... does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Rotary drilling bits for directional drilling exhibiting..., we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Rotary drilling bits for directional drilling exhibiting... will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-2462822