U.S. patent application number 09/854765 was filed with the patent office on 2001-10-18 for rotary drill bits for directional drilling exhibiting variable weight-on-bit dependent cutting characteristics.
Invention is credited to Beuershausen, Christopher C., Dykstra, Mark W., Fincher, Roger, Illerhaus, Roland, Matson, Steve R., Norris, James A., Ohanian, Michael P., Pessier, Rudolf C.O..
Application Number | 20010030065 09/854765 |
Document ID | / |
Family ID | 25451855 |
Filed Date | 2001-10-18 |
United States Patent
Application |
20010030065 |
Kind Code |
A1 |
Beuershausen, Christopher C. ;
et al. |
October 18, 2001 |
Rotary drill bits for directional drilling exhibiting variable
weight-on-bit dependent cutting characteristics
Abstract
A PDC-equipped rotary drag bit especially suitable for
directional drilling. Cutter chamfer size and backrake angle, as
well as cutter backrake, may be varied along the bit profile
between the center of the bit and the gage to provide a less
aggressive center and more aggressive outer region on the bit face,
to enhance stability while maintaining side cutting capability, as
well as providing a high rate of penetration under relatively high
weight on bit.
Inventors: |
Beuershausen, Christopher C.;
(Lafayette, LA) ; Dykstra, Mark W.; (Kingwood,
TX) ; Fincher, Roger; (Conroe, TX) ;
Illerhaus, Roland; (The Woodlands, TX) ; Matson,
Steve R.; (Spring, TX) ; Norris, James A.;
(Sandy, UT) ; Ohanian, Michael P.; (Slidell,
LA) ; Pessier, Rudolf C.O.; (Houston, TX) |
Correspondence
Address: |
TRASK BRITT
P.O. BOX 2550
SALT LAKE CITY
UT
84110
US
|
Family ID: |
25451855 |
Appl. No.: |
09/854765 |
Filed: |
May 14, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09854765 |
May 14, 2001 |
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08925525 |
Sep 8, 1997 |
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6230828 |
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Current U.S.
Class: |
175/327 ;
175/397; 175/398; 175/431 |
Current CPC
Class: |
E21B 17/1092 20130101;
E21B 10/5735 20130101; E21B 10/5673 20130101; E21B 10/567 20130101;
E21B 10/43 20130101; E21B 10/55 20130101 |
Class at
Publication: |
175/327 ;
175/397; 175/398; 175/431 |
International
Class: |
E21B 010/46 |
Claims
What is claimed is:
1. A rotary drag bit for drilling a subterranean formation,
comprising: a bit body comprising at least a first region and a
second region over a face to be oriented toward the subterranean
formation during drilling; and a plurality of cutters secured to
the bit body in the first and second regions, the cutters each
comprising a cutting face having a preselected effective cutting
face backrake angle, and being positioned substantially transverse
to a direction of cutter movement during drilling and including a
cutting edge located to engage the subterranean formation, wherein
the respective cutting faces of a majority of cutters located in
the first region exhibit substantially larger effective cutting
face backrake angles than the effective cutting face backrake
angles of the respective cutting faces of a majority of cutters
located in the second region.
2. The rotary drag bit of claim 1, wherein the first region lies
within a cone on the face of the bit body, and the second region
extends at least over a nose and flank on the face of the bit
body.
3. The rotary drag bit of claim 2, wherein the second region
extends to the gage of the bit body.
4. The rotary drag bit of claim 1, wherein the cutting faces are
formed on polycrystalline diamond compact tables.
5. The rotary drag bit of claim 4, wherein the polycrystalline
diamond compact tables are supported by metallic substrates.
6. The rotary drag bit of claim 1, further including a boundary
region on the bit face lying between the first and second regions,
and at least one cutter located in the boundary region having a
preselected effective cutting face backrake angle intermediate the
preselected effective cutting face backrake angles of the majority
of first region cutters and the majority of second region
cutters.
7. The rotary drag bit of claim 1, wherein the bit body further
includes a plurality of generally radially oriented blades
extending over the bit face and to the gage, and wherein the first
region cutters and the second region cutters are located on the
blades.
8. The rotary drag bit of claim 1, wherein the effective cutting
face backrake angles of the cutters are determined at least in part
by cutter backrake angles of the cutters.
9. The rotary drag bit of claim 8, wherein each of the plurality of
cutters in the first region are oriented at greater backrake angles
than each of the backrake angles of the plurality of cutters in the
second region.
10. The rotary drag bit of claim 1, wherein at least one cutter
proximate the gage is backraked at an angle less than a cutter
backrake angle of at least one cutter in the first region.
11. The rotary drag bit of claim 1, wherein the first region lies
within a cone on the face of the bit body, and the second region
extends at least over a nose on the face of the bit body.
12. The rotary drag bit of claim 1, wherein the effective cutting
face backrake angles of the cutters in both regions are determined
at least in part by cutter backrake angle and each of the cutters
in the first region have effective cutter backrake angles greater
than the effective backrake angles of each of the cutters in the
second region; and wherein the plurality of cutters in the second
region comprise cutters located relatively closer to the first
region having greater cutter backrake angles than cutter backrake
angles of other cutters in the second region but which are farther
away from the first region.
13. A rotary drag bit for drilling a subterranean formation,
comprising: a bit body bearing a cutting structure thereon
comprised of a plurality of superabrasive cutters, wherein at least
some of the superabrasive cutters are configured and oriented to
provide different ROP versus WOB characteristics for the bit below
and above about a threshold WOB.
14. A rotary drag bit for drilling a subterranean formation,
comprising a bit body bearing a cutting structure thereon comprised
of a plurality of superabrasive cutters, wherein at least some of
the superabrasive cutters are configured and oriented to provide
different TOB versus WOB characteristics for the bit below and
above about a threshold WOB.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation of application Ser. No.
08/925,525, filed Sep. 8, 1997, pending.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] 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).
[0004] 2. State of the Art
[0005] 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 bottonhole assembly (BRA), 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.
[0006] 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.
[0007] Of the bits referenced in FIGS. 1 and 2 of the drawings, RC
comprises a conventional roller cone bit for reference purposes,
while FC1 is a conventional polycrystalline diamond compact (PDC)
cutter-equipped rotary drag bit having cutters backraked at
20.degree., while FC2 is the directional version of the same bit
with 30.degree. backraked cutters. As can be seen from FIG. 2, the
TOB at a given WOB for FC2, which corresponds to its face
aggressiveness, can be as much as 30% less than for FC1. Therefore,
FC2 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 FC2 bit exhibits a markedly reduced
ROP for a given WOB, in comparison to FIG. 2.
[0008] Thus, it may be desirable for a bit to demonstrate the less
aggressive characteristics of a conventional directional bit such
as FC2 for non-linear drilling without sacrificing ROP to the same
degree when WOB is increased to drill a linear borehole
segment.
[0009] 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.
[0010] U.S. Pat. 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.degree. 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.
[0011] 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.
[0012] 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
[0013] 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.
[0014] 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.
[0015] 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 FC1 and FC2 to exponential,
dual-slope curves as shown with respect to a bit FC3 according to
the invention.
[0016] It is the dual-slope characteristics which are desirable for
directional drilling, demonstrating that a bit such as FC3 is slow
and drills smoothly with less applied torque at a relatively low
WOB such as is applied during oriented drilling of a non-linear
well bore segment, while regaining its full ROP potential at
relatively higher WOB levels such as are applied during linear
drilling.
[0017] It has been found that the chamfer size predominantly
determines at which ROP or WOB level the break in between the two
slopes occurs, while the chamfer backrake angle predominantly
determines curve slopes at low WOB, and cutter backrake angles
dictate the slopes at high WOB. The chamfer backrake angle with
respect to the formation being cut may be modified by actually
changing the chamfer angle on the cutter, changing the backrake
angle of the cutter itself, or a combination of the two. Thus,
different slopes at low WOB may be achieved for bits employing
cutters with similar chamfer angles, but disposed at different
cutter backrake angles, or bits employing cutters with different
chamfer angles but disposed at similar cutter backrake angles.
Generally, placing relatively less aggressive cutters in the center
of the bit face and relatively more aggressive cutters toward the
gage makes the bit more stable. In a broad concept of the
invention, chamfer size and angle of cutters placed at a variety of
radial locations over the face of a bit may be varied as a function
of, or in relation to, cutter redundancy at the various
locations.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0018] FIG. 1 comprises a graphical representation of ROP versus
WOB characteristics of various rotary drill bits in drilling Mancos
Shale at 2000 psi bottomhole pressure;
[0019] FIG. 2 comprises a graphical representation of TOB versus
WOB characteristics of various rotary drill bits in drilling Mancos
Shale at 2,000 psi bottomhole pressure;
[0020] FIG. 3A comprises a frontal view of a small chamfer PDC
cutter usable with the present invention and FIG. 3B comprises a
side sectional view of the small chamfer PDC cutter of FIG. 3A,
taken along section lines B-B;
[0021] FIG. 4 comprises a frontal view of a large chamfer PDC
cutter usable with the present invention;
[0022] FIG. 5 comprises a side sectional view of a first internal
configuration for the large chamfer PDC cutter of FIG. 4;
[0023] FIG. 6 comprises a side sectional view of a second internal
configuration for the large chamfer PDC cutter of FIG. 4;
[0024] FIG. 7 comprises a side perspective view of a PDC-equipped
rotary drag bit according to the present invention;
[0025] FIG. 8 comprises a face view of the bit of FIG. 7;
[0026] FIG. 9 comprises an enlarged, oblique face view of a single
blade of the bit of FIG. 7, illustrating the varying cutter chamfer
sizes and angles and cutter rake angles employed;
[0027] FIG. 10 comprises a quarter-sectional side schematic of a
bit having a profile such as that of FIG. 7, with the cutter
locations rotated to a single radius extending from the bit
centerline to the gage to show the radial bit face locations of the
various cutter chamfer sizes and angles, and cutter backrake
angles, employed in the bit; and
[0028] FIG. 11 comprises a side view of a PDC cutter as employed
with the present invention, depicting the effects of chamfer
backrake and cutter backrake.
DETAILED DESCRIPTION OF THE INVENTION
[0029] As used in the practice of the present invention, and with
reference to the size of the chamfers employed in various regions
of the exterior of the bit, it should be recognized that the terms
"large" and "small" chamfers are relative, not absolute, and that
different formations may dictate what constitutes a relatively
large or small chamfer on a given bit. The following discussion of
"small" and "large" chamfers is, therefore, merely exemplary and
not limiting, in order to provide an enabling disclosure and the
best mode of practicing the invention as currently understood by
the inventors.
[0030] FIGS. 3A and 3B depict an exemplary "small chamfer" cutter
10 comprised of a superabrasive, PDC table 12, supported by a
tungsten carbide (WC) substrate 14, as known in the art. The
interface 16 between the PDC diamond table 12 and the substrate 14
may be planar or non-planar, according to many varying designs for
same as known in the art. Cutter 10 is substantially cylindrical,
and symmetrical about longitudinal axis 18, although such symmetry
is not required and non-symmetrical cutters are known in the art.
Cutting face 20 of cutter 10, to be oriented on a bit facing
generally in the direction of bit rotation, extends substantially
transversely to such direction, and to axis 18. The surface 22 of
the central portion of cutting face 20 is planar as shown, although
concave, convex, ridged or other substantially, but not exactly,
planar surfaces may be employed. A chamfer 24 extends from the
periphery of surface 22 to cutting edge 26 at the sidewall 28 of
PDC table 12. Chamfer 24 and cutting edge 26 may extend about the
entire periphery of PDC table 12, or only along a periphery portion
to be located adjacent the formation to be cut. Chamfer 24 may
comprise the aforementioned 0.010 inch by 45.degree. angle
conventional chamfer, or the chamfer may lie at some other angle,
as referenced with respect to the chamfer 124 of cutter 110
described below. While 0.010 inch chamfer size is referenced as an
example (within conventional tolerances), chamfer sizes within a
range of 0.005 to about 0.020 inch are contemplated as generally
providing a "small" chamfer for the practice of the invention. It
should also be noted that cutters exhibiting substantially no
visible chamfer may be employed for certain applications in
selected outer regions of the bit.
[0031] FIGS. 4 through 6 depict an exemplary "large chamfer" cutter
110 comprised of a superabrasive, PDC table 112 supported by a WC
substrate 114. The interface 116 between the PDC diamond table 112
and the substrate 114 may be planar or non-planar, according to
many varying designs for same as known in the art (see especially
FIGS. 5 and 6). Cutter 110 is substantially cylindrical, and
symmetrical about longitudinal axis 118, although such symmetry is
not required and non-symmetrical cutters are known in the art.
Cutting face 120 of cutter 110, to be oriented on a bit facing
generally in the direction of bit rotation, extends substantially
transversely to such direction, and to axis 118. The surface 122 of
the central portion of cutting face 120 is planar, as shown,
although concave, convex, ridged or other substantially, but not
exactly, planar surfaces may be employed. A chamfer 124 extends
from the periphery of surface 122 to cutting edge 126 at the
sidewall 128 of PDC table 112. Chamfer 124 and cutting edge 126 may
extend about the entire periphery of PDC table 112, or only along a
periphery portion to be located adjacent the formation to be cut.
Chamfer 124 may comprise a surface oriented at 45.degree. to axis
118, of a width, measured radially and looking at and perpendicular
to the cutting face 120, ranging upward in magnitude from about
0.030 inch, and generally lying within a range of about 0.030 to
0.060 inch in width. Chamfer angles of about 10.degree. to about
80.degree. to axis 118 are believed to have utility, with angles in
the range of about 30.degree. to about 60.degree. being preferred
for most applications. The effective angle of a chamfer relative to
the formation face being cut may also be altered by changing the
backrake of a cutter.
[0032] FIG. 5 illustrates one internal configuration for cutter
110, wherein PDC table 112 is extremely thick, on the order of
0.070 inch or greater, in accordance with the teachings of the
aforementioned '076 application.
[0033] FIG. 6 illustrates a second internal configuration for
cutter 110, wherein the front face 115 of substrate 114 is
frustoconical in configuration, and PDC table 112, of substantially
constant depth, substantially conforms to the shape of front face
115 to provide a large chamfer of a desired width without requiring
the large PDC diamond mass of the '076 application.
[0034] FIGS. 7 through 10 depict a rotary drag bit 200 according to
the invention. Bit 200 includes a body 202 having a face 204 and
including a plurality (in this instance, six) of generally radially
oriented blades 206 extending above the bit face 204 to a gage 207.
Junk slots 208 lie between adjacent blades 206. A plurality of
nozzles 210 provides drilling fluid from plenum 212 (FIG. 10)
within the bit body 202 and received through passages 214 (FIG. 10)
to the bit face 204. Formation cuttings generated during a drilling
operation are transported by the drilling fluid across bit face 204
through fluid courses 216 communicating with respective junk slots
208. Secondary gage pads 240 are rotationally and substantially
longitudinally offset from blades 206, and provide additional
stability for bit 200 when drilling both linear and non-linear
borehole segments. Such added stability reduces the incidence of
ledging of the borehole sidewall, and spiraling of the borehole
path. Shank 220 includes a threaded pin connection 222 as known in
the art, although other connection types may be employed.
[0035] The profile 224 of the bit face 204, as defined by blades
206, is illustrated in FIG. 10, wherein bit 200 is shown adjacent a
subterranean rock formation 40 at the bottom of the well bore.
First region 226 and second region 228 on profile 224 face adjacent
rock zones 42 and 44 of formation 40 and respectively carry large
chamfer cutters 110 and small chamfer cutters 10. First region 226
may be said to comprise the cone 230 of the bit profile 224, as
illustrated, whereas second region 228 may be said to comprise the
nose 232, and flank 234 and extend to shoulder 236 of profile 224,
terminating at gage 207.
[0036] In a currently preferred embodiment of the invention and
with particular reference to FIGS. 9 and 10, large chamfer cutters
110 may comprise cutters having PDC tables in excess of 0.070 inch
depth, and preferably about 0.080 to 0.090 inch depth, with
chamfers 124 of about a 0.030 to 0.060 inch width, looking at and
perpendicular to the cutting face 120, and oriented at a 45.degree.
angle to the cutter axis 118. The cutters themselves, as disposed
in first region 226, are backraked at 20.degree. to the bit profile
(see cutters 110 shown partially in broken lines in FIG. 10 to
denote 20.degree. backrake) at each respective cutter location,
thus providing chamfers 124 with a 65.degree. backrake. Cutters 10,
on the other hand, disposed in second region 228, may comprise
conventionally-chamfered cutters having about a 0.030 inch PDC
table thickness, and about a 0.010 to 0.020 inch chamfer width
looking at and perpendicular to cutting face 20, with chamfers 24
oriented at a 45.degree. angle to the cutter axis 18. Cutters 10
are themselves backraked at 15.degree. on nose 232, providing a
60.degree. chamfer backrake, while cutter backrake is further
reduced to 10.degree. at the flank 234, shoulder 236 and on the
gage 207 of bit 200, resulting in a 55.degree. chamfer backrake.
The PDC cutters 10 immediately above gage 207 include preformed
flats thereon oriented parallel to the longitudinal axis of the bit
200, as known in the art. In steerable applications requiring
greater durability at the shoulder 236, large chamfer cutters 110
may optionally be employed, but oriented at a 10.degree. cutter
backrake. Further, the chamfer angle of cutters 110 in each of
first region 226 and shoulder 236 may be other than 45.degree.. For
example, 70.degree. chamfer angles may be employed with chamfer
widths (looking vertically at the cutting face of the cutter) in
the range of about 0.035 to 0.045 inch, cutters 110 being disposed
at appropriate backrakes to achieve the desired chamfer rake angles
in the respective regions.
[0037] A boundary region, rather than a sharp boundary, may exist
between first and second regions 226 and 228. For example, rock
zone 46 bridging the adjacent edges of rock zones 42 and 44 of
formation 40, may comprise an area wherein demands on cutters and
the strength of the formation are always in transition due to bit
dynamics. Alternatively, the rock zone 46 may initiate the presence
of a third region on the bit profile, wherein a third size of
cutter chamfer is desirable. In any case, the annular area of
profile 224 opposing zone 46 may be populated with cutters of both
types (i.e., width and chamfer angle) and employing backrakes
respectively employed in first region 226 and those of second
region 228, or cutters with chamfer sizes, angles and cutter
backrakes intermediate those of the cutters in first and second
regions 226 and 228 may be employed.
[0038] Bit 200, equipped as described with a combination of small
chamfer cutters 10 and large chamfer cutters 110, will drill with
an ROP approaching that of conventional, non-directional bits
equipped only with small chamfer cutters, but will maintain
superior stability, and will drill far faster than a conventional
directional drill bit equipped only with large chamfer cutters.
[0039] It is believed that the benefits achieved by the present
invention result from the aforementioned effects of selective
variation of chamfer size, chamfer backrake angle and cutter
backrake angle. For example and with specific reference to FIG. 11,
the size (width) of the chamfer 124 of the large chamfer cutters
110 at the center of the bit can be selected to maintain
non-aggressive characteristics in the bit up to a certain WOB or
ROP, denoted in FIGS. 1 and 2 as the "break" in the curve slopes
for bit FC3. For equal chamfer backrake angles .beta.1, the larger
the chamfer 124, the greater WOB must be applied before the bit
enters the second, steeper-slope portions of the curves. Thus, for
drilling non-linear borehole segments, wherein applied WOB is
generally relatively low, it is believed that a non-aggressive
character for the bit may be maintained by drilling to a first
depth of cut (DOC1) associated with low WOB, wherein the cut is
taken substantially within the chamfer 124 of the large chamfer
cutters 110 disposed in the center region of the bit. In this
instance, the effective backrake angle of the cutting face 120 of
cutter 110 is the chamfer backrake .beta.1, and the effective
included angle .gamma.1 between the cutting face 120 and the
formation 300 is relatively small. For drilling linear borehole
segments, WOB is increased so that the depth of cut (DOC2) extends
above the chamfers 124 on the cutting faces 120 of the large
chamfer cutters to provide a larger effective included angle
.gamma.2 (and smaller effective cutting face backrake angle
.beta.2) between the cutting face 120 and the formation 300,
rendering the cutters 110 more aggressive and thus increasing ROP
for a given WOB above the break point of the curve of FIG. 1. As
shown in FIG. 2, this condition is also demonstrated by a
perceptible increase in the slope of the TOB versus WOB curve above
a certain WOB level. Of course, if a chamfer 124 is excessively
large, excessive WOB may have to be applied to cause the bit to
become more aggressive and increase ROP for linear drilling.
[0040] The chamfer backrake angle .beta.1 of the large chamfer
cutters 110 may be employed to control DOC for a given WOB below a
threshold WOB wherein DOC exceeds the chamfer depth perpendicular
to the formation. The smaller the included angle .gamma.1 between
the chamfer 124 and the formation 300 being cut, the more WOB is
required to effect a given DOC. Further, the chamfer rake angle
.beta.1 predominantly determines the slopes of the
ROP.backslash.WOB and TOB.backslash.WOB curves of FIGS. 1 and 2 at
low WOB and below the breaks in the curves, since the cutters 110
apparently engage the formation to a DOC1 residing substantially
within the chamfer 124.
[0041] Further, selection of the backrake angles .delta. of the
cutters 110 themselves (as opposed to the backrake angles .beta.1
of the chamfers 124) may be employed to predominantly determine the
slopes of the ROP.backslash.WOB and TOB.backslash.WOB curves at
high WOB and above the breaks in the curves, since the cutters 110
will be engaged with the formation to a DOC2 such that portions of
the cutting face centers of the cutters 110 (i.e., above the
chamfers 124) will be engaged with the formation 300. Since the
central areas of the cutting faces 120 of the cutters 110 are
oriented substantially perpendicular to the longitudinal axes 118
of the cutters 110, cutter backrake .delta. will largely dominate
effective cutting face backrake angles (now .beta.2) with respect
to the formation 300, regardless of the chamfer rake angles
.beta.1. As noted previously, cutter backrake angles .delta. may
also be used to alter the chamfer rake angles .beta.1 for purposes
of determining bit performance during relatively low WOB
drilling.
[0042] It should be appreciated that appropriate selection of
chamfer size and chamfer backrake angle of the large chamfer
cutters may be employed to optimize the performance of a drill bit
with respect to the output characteristics of a downhole motor
driving the bit during steerable or non-linear drilling of a
borehole segment. Such optimization may be effected by choosing a
chamfer size so that the bit remains non-aggressive under the
maximum WOB to be applied during steerable or non-linear drilling
of the formation or formations in question, and choosing a chamfer
backrake angle so that the torque demands made by the bit within
the applied WOB range during such steerable drilling do not exceed
torque output available from the motor, thus avoiding stalling.
[0043] With regard to the placement of cutters exhibiting
variously-sized chamfers on the exterior, and specifically the face
of a bit, the chamfer widths employed on different regions of the
bit face may be selected in proportion to cutter redundancy or
density at such locations. For example, a center region of the bit,
such as within a cone surrounding the bit centerline (see FIGS. 7
through 10 and above discussion), may have only a single cutter
(allowing for some radial cutter overlap) at each of several
locations extending radially outward from the centerline or
longitudinal axis of the bit. In other words, there is only
"single" cutter redundancy at such cutter locations. An outer
region of the bit, portions of which may be characterized as
comprising a nose, flank and shoulder, may, on the other hand,
exhibit several cutters at substantially the same radial location.
It may be desirable to provide three cutters at substantially a
single radial location in the outer region, providing substantially
triple cutter redundancy. In a transition region between the inner
and outer regions, such as on the boundary between the cone and the
nose, there may be an intermediate cutter redundancy, such as
substantially double redundancy, or two cutters at substantially
each radial location in that region.
[0044] Relating cutter redundancy to chamfer width for exemplary
purposes in regard to the present invention, cutters at single
redundancy locations may exhibit chamfer widths of between about
0.030 to 0.060 inch, while those at double redundancy locations may
exhibit chamfer widths of between about 0.020 and 0.040 inch, and
cutters at triple redundancy locations may exhibit chamfer widths
of between about 0.010 and 0.020 inch.
[0045] Rake angles of cutters in relation to their positions on the
bit face have previously been discussed with regard to FIGS. 7
through 10. However, it will be appreciated that differences in the
chamfer angles from the exemplary 45.degree. angles discussed above
may necessitate differences in the relative cutter backrake angles
employed in and within the different regions of the bit face in
comparison to those of the example.
[0046] While the present invention has been described in light of
the illustrated embodiment, those of ordinary skill in the art will
understand and appreciate it is not so limited, and many additions,
deletions and modifications may be effected to the invention as
illustrated without departing from the scope of the invention as
hereinafter claimed.
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