Boring or penetrating the earth – Processes
Reexamination Certificate
2000-12-21
2004-01-06
Shackelford, Heather (Department: 3673)
Boring or penetrating the earth
Processes
C175S430000, C175S431000
Reexamination Certificate
active
06672406
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates generally to methods of drilling subterranean formations with fixed cutter-type drill bits. More specifically, the invention relates to methods of drilling, including directional drilling, with fixed cutter, or so-called “ drag,” bits wherein the cutting face of the cutters of the bits are tailored to have different cutting aggressiveness to enhance response of the bit to sudden variations in formation hardness, to improve stability and control of the toolface of the bit, to accommodate sudden variations on weight on bit (WOB), and to optimize the rate of penetration (ROP) of the bit through the formation regardless of the relative hardness of the formation being drilled.
2. Background of the Invention
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 (straight) and nonlinear (curved) borehole segments without tripping, or removing, the drill string from the borehole to change out bits specifically designed to bore either linear or nonlinear boreholes. 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 downhole motor permit a fixed rotational orientation of the bit axis at an angle to the drill string axis for nonlinear drilling when the bit is rotated solely by the drive shaft of the downhole motor. When the drill string is rotated by a top-side motor in combination with rotation of the downhole motor shaft, the superimposed, simultaneous rotational motions cause the bit to drill substantially linearly or, in other words, causes the bit to drill a generally straight borehole. Other directional methodologies employing nonrotating 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 nonlinear, or curved, borehole segments, the face aggressiveness (aggressiveness of the cutters disposed on the bit face) is a significant feature, since it is largely determinative of how a given bit responds to sudden variations in bit load or formation hardness. 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 nonlinear path renders a smooth, gradual transfer of weight to the bit extremely difficult. These conditions frequently cause downhole motor stalling and result in the loss of control of tool face orientation of the bit, and/or cause the tool face of the bit to swing to a different orientation. When control of tool face orientation is lost, borehole quality often declines dramatically. In order to establish a new tool face reference point before drilling is recommenced, the driller must stop drilling ahead, or making hole, and pull the bit off the bottom of the borehole. Such a procedure is time consuming, expensive, results in loss of productive rig time and causes a reduction in the average ROP of the borehole. 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°, and
FIG. 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 as 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 nonlinear 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. Patent 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 of an inch (measured radially and looking at and perpendicular to the cutting face) oriented at approximately a 45° angle with respect to the longitudinal cutter axis, thus providing a larger radial width as measured on the chamfer surface itself.
Multichamfered PDC cutters are also known in the art. For example a multichambered cutter is taught by Cooley et al., U.S. Pat. No. 5,437,343, assigned to the assignee of the present invention. In particular the Cooley et al. patent discloses a PDC cutter having a diamond table having two concentric chamfers. A radially outermost chamfer D
1
is taught as being disposed at an angle &agr; of 20° and an innermost chamfer D
2
is taught as being disposed at an angle &bgr; of 45° as measured from the periphery, or radially outermost extent, of the cutting element. An alternative cutting element having a diamond table in which three concentric chamfers are provided thereon is also taught by the Cooley et al. patent. The specification of the Cooley et al. patent provides discussion directed toward explaining how cutting elements provided with such multiple chamfer cutting edge geometry provides excellent fracture resistance combined with cutting efficiency generally comparable to standard unchamfered cutting elements.
U.S. Pat. No. 5,443,565 to Strange Jr. discloses a cutting element having a cutting face incorporating a dual bevel configuration. More specifically in column
3
, lines
35
-
53
, and as illustrated in
FIG. 5
, Strange Jr. discloses a cutting element
9
having a cutting face
10
provided with a first bevel
12
and a second bevel
14
. Bevel
12
is described as extending at a first bevel angle
12
with respect to the longitudinal axis of cutting element
9
. Likewise, bevel
14
is described as extending at a second bevel angle
15
also measured with respect to the longitudinal axis of cutter
9
. The specification, in the same above-referenced section, states that the subject cutting element had increased drilling efficiency and increased cutting element and bit life because the bevels served to minimize splitting, chipping, and cracking of the cutting element during the drilling process, which in turn resulted in decreased drilling time and expenses.
U.S. Pat. No. 5,467,836 to Grimes et al. is directed toward gage cutting inserts and depicts in
FIG. 2
thereof an insert
31
having a cutting end
35
formed of a superabrasive material and which is provided with a wear-resistant face
Baker Hughes Incorporated
Shackelford Heather
Singh Sunil
TraskBritt
LandOfFree
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