U.S. patent application number 12/957012 was filed with the patent office on 2011-10-06 for tapered blade profile on an outer bit.
Invention is credited to Scott Dahlgren, David R. Hall, Jonathan Marshall.
Application Number | 20110240378 12/957012 |
Document ID | / |
Family ID | 44708315 |
Filed Date | 2011-10-06 |
United States Patent
Application |
20110240378 |
Kind Code |
A1 |
Hall; David R. ; et
al. |
October 6, 2011 |
Tapered Blade Profile on an Outer Bit
Abstract
In one aspect of the present invention, a drill bit assembly is
configured for downhole drilling. The drill bit assembly comprises
an outer bit with a plurality of outer blades and a bore disposed
within an outer cutting face. In addition, the outer bit comprises
a rotational axis. The drill bit assembly comprises an inner
cutting face that is configured to cut a hole with an inner gauge
diameter in front of the outer bit. At least one outer blade on the
outer bit comprises a central most cutter configured to degrade the
inner gauge diameter. The central most cutter is axially and
laterally displaced from the second most central cutter on the at
least blade such that less than fifty percent of the central most
cutter axially and laterally overlaps the second most central
cutter.
Inventors: |
Hall; David R.; (Provo,
UT) ; Dahlgren; Scott; (Alpine, UT) ;
Marshall; Jonathan; (Provo, UT) |
Family ID: |
44708315 |
Appl. No.: |
12/957012 |
Filed: |
November 30, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12894371 |
Sep 30, 2010 |
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12957012 |
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12752323 |
Apr 1, 2010 |
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12894371 |
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12755534 |
Apr 7, 2010 |
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12752323 |
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12828287 |
Jun 30, 2010 |
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12755534 |
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Current U.S.
Class: |
175/431 |
Current CPC
Class: |
E21B 10/26 20130101 |
Class at
Publication: |
175/431 |
International
Class: |
E21B 10/36 20060101
E21B010/36 |
Claims
1. A drill bit assembly for downhole drilling, comprising: an outer
bit with a plurality of outer blades and a bore disposed within an
outer cutting face; the outer bit comprises a rotational axis; an
inner bit that is rotationally isolated from the outer bit is
disposed within the bore and comprises an inner cutting face; the
inner bit is configured to cut a hole with an inner gauge diameter
in front of the outer bit; at least one outer blade comprises a
central most cutter configured to degrade the inner gauge diameter;
and the central most cutter is axially and laterally displaced from
the second most central cutter on the at least blade such that less
than 50% of the central most cutter axially and laterally overlaps
the second most central cutter.
2. The drill bit assembly of claim 1, wherein the central most
cutter and the second most central cutter are aligned on a linear
segment of the at least outer blade.
3. The drill bit assembly of claim 1, wherein the central most
cutter and the second most central cutter are aligned on a convex
segment of the at least one outer blade.
4. The drill bit assembly of claim 1, wherein the central most
cutter and the second most central cutter are aligned on a concave
segment of the at least one outer blade.
5. The drill bit assembly of claim 1, wherein the inner bit is
configured to rotate faster than the outer bit.
6. The drill bit assembly of claim 1, wherein the inner bit
comprises a center indenter.
7. The drill bit assembly of claim 1, wherein the inner bit
protrudes from the outer bit.
8. The drill bit assembly of claim 1, wherein the outer bit is
rigidly connected to a drill string and the inner bit is rigidly
connected to a torque transmitting device disposed within the drill
string.
9. The drill bit assembly of claim 8, wherein the torque
transmitting device is configured to provide the inner bit with
power such that the work done per unit area of the inner bit is
greater than work done per unit area of the outer bit.
10. The drill bit assembly of claim 1, further comprising at least
one fluid nozzle disposed on both the inner bit and the outer
bit.
11. The drill bit assembly of claim 1, wherein at least one fluid
nozzle is incorporated in a gauge of the inner bit, wherein the
nozzle is configured to convey fluid across a working face of the
outer bit.
12. The drill bit assembly of claim 1, wherein the inner bit is
configured to steer the drill bit assembly by pushing off the outer
bit.
13. The drill bit assembly of claim 1, wherein the outer bit is
configured to rotate in a first direction and the inner bit is
configured to rotate in a second direction.
14. The drill bit assembly of claim 1, wherein the inner bit is
disposed eccentric with respect to the outer bit.
15. The drill bit assembly of claim 1, wherein the shape of the
outer blade is configured to apply force to the inner gauge
diameter, degrading it beginning at the center and progressing
outwards.
16. The drill bit assembly of claim 1, wherein the protruding inner
bit is configured to weaken a formation, prior to the outer bit
degrading the formation.
17. The drill bit assembly of claim 16, wherein the outer bit is
configured to degrade the weakened formation at a higher rate than
a formation that has not been weakened.
18. The drill bit assembly of claim 1, wherein the central most
cutter is axially displaced from the second most central cutter
such that there is no axial overlap.
19. The drill bit assembly of claim 1, wherein the central most
cutter is laterally displaced from the second most central cutter
such that there is no lateral overlap.
20. The drill bit assembly of claim 1, wherein the inner and outer
bit are rotationally fixed to each other.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation in part of U.S. patent
application Ser. No. 12/894,371, which was a continuation in part
of U.S. patent application Ser. Nos. 12/752,323, which was filed on
Apr. 1, 2010; 12/755,534, which was filed on Apr. 7, 2010; and
12/828,287, which was filed on Jun. 30, 2010. All of these
applications are herein incorporated by reference for all that they
contain.
BACKGROUND OF THE INVENTION
[0002] The present invention relates to drill bit assemblies,
specifically drill bit assemblies for use in subterranean drilling.
More particularly, the present invention relates to drill bits that
include an inner bit. The prior art discloses drill bit assemblies
comprising inner bits.
[0003] One such bit is disclosed in U.S. Pat. No. 4,862,974, to
Warren et al., which is herein incorporated by reference for all
that it contains. Warren et al. discloses a downhole drilling
apparatus for use with an under gauge drill bit comprising a
downhole drilling motor which includes a housing and means for
rotating the drill bit relative to the housing about an axis of
rotation. The apparatus also comprises stabilizers connected to the
housing for stabilizing the drill bit, and it further comprises
cutters connected to the housing for cutting a borehole wall
created by passage of the drill bit, wherein the cutters extend
radially outwardly relative to the axis of rotation to a greater
extent than does the drill bit. A drilling assembly including such
a drilling apparatus and a method of drilling a substantially
vertical borehole in an earthen formation utilizing such an
apparatus are also disclosed.
[0004] U.S. Pat. No. 5,765,653, to Doster et al., which is herein
incorporated by reference for all that it contains. Doster et al.
discloses a method and apparatus for reaming or enlarging a
borehole with enhanced stability. A pilot stabilization pad (PSP)
having an axially and circumferentially tapered entry surface and a
circumferential transition surface above is employed to enhance the
transition from the smaller diameter borehole to be enlarged while
accommodated the side force vector generated by the cutting
assembly used to effect the enlargement. In addition, one or more
eccentric stabilizers are employed above the reaming apparatus to
laterally or radially stabilize the bottomhole assembly, which may
comprise either a straight-hole or steerable, motor-driven
assembly.
[0005] U.S. Pat. No. 7,712,549 to Dennis et al., which is herein
incorporated by reference for all that it contains. Dennis et al.,
discloses a drilling tool that includes a pilot bit and a plurality
of mills encircling the pilot bit. The pilot bit and the plurality
of mills are each driven by a separate, hydraulically powered
turbine or positive displacement motor. The drilling tool does not
include a transmission for transmitting power from the turbine or
motor to any of the plurality of mills or the pilot bit.
BRIEF SUMMARY OF THE INVENTION
[0006] In one aspect of the present invention, a drill bit assembly
is configured for downhole drilling. The drill bit assembly
comprises an outer bit with a plurality of outer blades and a bore
disposed within an outer cutting face. In addition, the outer bit
comprises a rotational axis. Furthermore, the drill bit assembly
comprises an inner bit that is rotationally isolated from the outer
bit and disposed within the bore. The inner bit comprises an inner
cutting face and is configured to degrade the inner gauge diameter.
The central most cutter is axially and laterally displaced from the
second most central cutter on the at least one blade such that less
than fifty percent of the central most cutter axially and laterally
overlaps the second most central cutter.
[0007] The central most cutter and second most central cutter of
the outer bit may be aligned on a linear segment of the at least
one outer blade. The central most cutter and second most central
cutter of the outer bit may be aligned on a convex segment of the
at least one outer blade. The central most cutter and second most
central cutter of the outer bit may be aligned on a concave segment
of the at least one outer blade.
[0008] The inner bit of the drill bit assembly may be configured to
rotate faster than the outer bit. In some embodiments, the inner
and outer bits are rotationally fixed together, and in other
embodiments, the inner and outer bits are configured to rotate in
opposite directions. The inner bit may comprise a center indenter.
The inner bit may protrude from the outer bit.
[0009] The outer bit of the drill bit assembly may be rigidly
connected to a drill string and the inner bit may be rigidly
connected to a torque transmitting device disposed within the drill
string. The torque transmitting device may be configured to provide
the inner bit with power such that the work done per unit area of
the inner bit is greater than the work done per unit area of the
outer bit. The inner bit may be configured to steer the drill bit
assembly by pushing off the outer bit. The outer bit may be
configured to rotate in a first direction and the inner bit may be
configured to rotate in a second direction. The inner bit may be
disposed eccentric with respect to the outer bit.
[0010] The drill bit assembly may comprise at least one fluid
nozzle disposed on both the inner bit and the outer bit. In
addition, at least one fluid nozzle may be incorporated into a
gauge of the inner bit. The fluid nozzle may be configured to
convey fluid across a working face/blade of the outer bit.
[0011] The shape of the outer blade on the outer bit may be
configured to apply force to the inner gauge diameter further
degrading degrading the formation beginning close to the center and
progressing outwards. The inner bit may be configured to weaken the
formation prior to the outer bit degrading the formation. The outer
bit may be configured to degrade the weakened formation easier than
a formation that has not been weakened.
[0012] The central most cutter on the outer bit may be axially
displaced from the second most central cutter such that there is no
axial overlap. The central most cutter may be laterally displaced
from the second most central cutter such that there is no lateral
overlap.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 is a perspective diagram of an embodiment of a
drilling operation.
[0014] FIG. 2 is a cross-sectional diagram of an embodiment of a
drill bit assembly.
[0015] FIG. 3 is a perspective diagram of an embodiment of a drill
bit assembly.
[0016] FIG. 4 is a perspective diagram of an embodiment of a drill
bit assembly.
[0017] FIG. 5 is a perspective diagram of an embodiment of a drill
bit assembly.
[0018] FIG. 6 is a perspective diagram of an embodiment of a drill
bit assembly.
[0019] FIG. 7 is a diagram of an embodiment of a cutter
profile.
[0020] FIG. 8a is an orthogonal diagram of an embodiment of a drill
bit.
[0021] FIG. 8b is an orthogonal diagram of an embodiment of a drill
bit.
[0022] FIG. 9 is an orthogonal diagram of an embodiment of a drill
bit assembly.
[0023] FIG. 10 is an orthogonal diagram of an embodiment of a drill
bit assembly.
DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED
EMBODIMENT
[0024] Referring now to the figures, FIG. 1 discloses a perspective
diagram of an embodiment of a drilling operation comprising a
downhole drill string 100 suspended by a derrick 101 in a bore hole
102. A drill bit assembly 103 may be located at the bottom of the
bore hole 102 and may comprise a drill bit 104. As the drill bit
104 rotates downward the downhole drill string 100 advances farther
into the earth. The downhole drill string 100 may penetrate soft or
hard subterranean formations 105. The downhole drill string 100 may
comprise electronic equipment able to send signals through a data
communication system to a computer or data logging system 106
located at the surface.
[0025] FIG. 2 discloses a cross-sectional diagram of an embodiment
of a drill bit 104. The drill bit 104 may comprise an outer bit 201
and an inner bit 202. The outer bit 201 may comprise a rotational
axis 203 and a plurality of outer blades 204. Additionally, the
outer bit 201 may comprise a bore 221 disposed within an outer
cutting face 222. The inner bit 202 may be disposed within the bore
221 of the outer bit 201. The inner bit 202 may comprise an inner
cutting face 205 and a center indenter 206. The center indenter 206
may be the first to contact the formation (see FIGS. 3-6) during
normal drilling operations and may weaken the formation.
[0026] In this embodiment, the outer bit 201 is rigidly connected
to the drill string 100 and the inner bit 202 is rigidly connected
to a torque transmitting device 207 disposed within the drill
string 100. The torque transmitting device 207 may be configured to
provide the inner bit 202 with power such that the work done per
unit area of the inner bit 202 is greater than the work done per
unit area of the outer bit 201. The torque transmitting device 207
may be a mud driven motor, a positive displacement motor, a
turbine, electric motor, or combinations thereof. The inner bit 202
and the torque transmitting device 207 may be substantially
collinear with the rotational axis 203. The torque transmitting
device 207 may comprise a gearbox 208 to apply a preferential
torque to the inner bit 202.
[0027] The inner bit 202 may be rotationally isolated from the
outer bit 201. When the inner bit 202 is rotationally isolated from
the outer bit 201, the direction and rotational speed of the inner
bit 202 may be independent of the direction and rotational speed of
the outer bit 201. In this embodiment, the torque transmitting
device 207 may exclusively control the direction and speed of the
rotation of the inner bit 202. It is believed that having the inner
bit 202 rotationally isolated from the outer bit 201 may be
advantageous because the torque transmitting device 207 may rotate
the inner bit 202 independent of the drill string 100. The outer
bit 201 may be configured to rotate in a first direction controlled
by the drill string 100 and the inner bit 202 may be configured to
rotate in a second direction controlled by the torque transmitting
device 207. The torque transmitting device 207 may be rotationally
isolated from the drill string 100 such that the torque
transmitting device 207 may rotate the inner bit 202 in the second
direction without compensating for the rotation of the drill string
100.
[0028] The embodiment of FIG. 2 also discloses the inner bit 202
protruding from the outer bit 201. The inner bit 202 may be
configured to move axially with respect to the outer bit 201 such
that the inner bit 202 may protrude and retract within the outer
bit 201. The inner bit 202 may be configured to steer the drill bit
assembly 103 by pushing off the outer bit 201. The torque
transmitting device 207 and the inner bit 202 may be rigidly
connected to a piston 211 in a piston cylinder 220. The piston 211
may comprise a first surface 218 and a second surface 219. The
piston 211 may separate the cylinder 220 into a first pressure
chamber 213 and a second pressure chamber 214. A first fluid
channel 215 may connect the first pressure chamber 213 to at least
one valve 217 and a second fluid channel 216 may connect the second
pressure chamber 214 to the at least one valve 217. The at least
one valve 217 may control the flow of drilling fluid to the first
and second fluid channels 215, 216 to control axial displacement of
the piston 211 by forcing the fluid against first and second piston
surfaces 218, 219. As fluid enters either the first or second
pressure chambers 213, 214 fluid in the other chamber is exhausted
out of the cylinder 220.
[0029] A method of increasing the rate of penetration in downhole
drilling may comprise protruding the inner bit 202 from the outer
bit 201 and rotating the inner bit 202 at a higher angular speed
than the outer bit 201. The step of rotating the inner bit 202 at a
higher angular speed than the outer bit 201 may comprise rotating
the inner bit 202 through the torque transmitting device 207, as
the drill string 100 rotates the outer bit 201. It is believed that
protruding the inner bit 202 from the outer bit 201 and rotating
the inner bit 202 at a higher angular speed than the outer bit 201
allows the inner bit 202 to weaken the formation. The outer bit 201
may degrade the weakened formation at a rate greater than if the
formation had not previously been weakened by the inner bit
202.
[0030] FIGS. 3-6 disclose perspective diagrams of an embodiment of
a drill bit assembly 103. In FIG. 3, the drill bit assembly 103 is
disclosed traveling in the direction of the arrow 300 through a
bore hole 102 previously formed. The inner bit 202 may protrude
from the outer bit 201 and may comprise an inner cutting face 205.
The inner cutting face 205 may comprise a plurality of shear
cutters. The outer bit 201 may comprise a plurality of outer blades
204. At least one outer blade 204 may comprise a central most
cutter 302 and a second most central cutter 303 aligned along a
linear blade segment.
[0031] FIG. 3 further discloses at least one fluid nozzle 304 that
may be incorporated into a gauge of the inner bit. The at least one
nozzle 304 may be configured to convey fluid across a working face
of the outer bit 201. The at least one fluid nozzle 304 may be
aligned such that fluid may pass over the plurality of outer blades
204. During normal drilling operations, pieces of the formation 105
may be deposited onto the outer blades 204 causing the outer blades
204 to less effectively engage in the formation 105. Fluid may be
expelled from the at least one nozzle 304 such that the fluid
directly or tangentially strikes the outer blades 204 removing any
formation deposited on the outer blades 204. Fluid from the at
least one nozzle 304 may also remove degraded formation from the
bottom of the bore hole 102 through an annulus of the bore hole
102.
[0032] FIG. 4 discloses the inner bit 202 as it begins to engage
the formation 105. The inner bit 202 may degrade the formation 105
in front of the outer bit 201 by forming a leading bore with an
inner gauge diameter 450 in the wellbore floor. The leading bore
may weaken the formation 105 immediately around the inner gauge
diameter because the leading bore relieves the formation's
pressure. The weakened region 400 is represented by the
discontinuous line. The weakened region may require less energy to
degrade; thereby requiring a lower applied force from the outer bit
201.
[0033] FIG. 5 discloses the outer blade beginning to engage in the
weakened region. The central most cutters 302 of the outer blades
204 may be configured to degrade the formation at the inner gauge
diameter 450 that was formed by the inner bit 202. The axial and
lateral displacement of the cutters 302, 303 may allow the central
most cutters 302 to engage the inner gauge diameter prior to the
second most central cutter 303 and successive cutters engage the
wellbore floor. As the inner gauge diameter is widened by the
central most cutter, the weakened region is believed to enlarged
proportionate to the increased width of the inner gauge diameter.
The weakened region is believed to expand because the removal of
more material out of the leading bore further relieves the
formation pressure.
[0034] FIG. 6 discloses the drill bit 104 having progressed farther
into the formation 105. The second most central cutter may 303 is
shown degrading the formation 105, in addition to the central most
cutter 302. The central most and the second most central cutters
302, 303 may further degrade the formation 105 beginning at the
inner gauge diameter and traveling outwards. The successive cutters
may further degrade the formation 105, widening the leading bore to
a full gauge diameter of the wellbore.
[0035] The central most cutter 302 and the second most central
cutter 303 (as well as the successive cutters) may be aligned on a
linear portion of the at least one outer most blade 204 of the
outer bit 201. The central most cutter 302 may be axially and
laterally displaced from the second most central cutter 303 such
that less than 50% of the central most cutter 302 axially and
laterally overlaps the second most central cutter 303. In some
embodiments, the central most cutters 302 may be axially displaced
from the second most central cutter 303 such that there is no axial
overlap. In some embodiments, the central most cutters 302 may be
laterally displaced from the second most central cutter 303 such
that there is no lateral overlap.
[0036] The prescribed novel arrangement of cutters on the outer
blade has significant advantages over the prior art references
known to the Applicants. For example, if the cutters on the outer
blade overlapped axially more than 50%, the second most and
successive cutters would engage the wellbore floor in an area
outside of the weakened region. If this occurs, the non-weakened
region will limit the penetration rate of the drill bit because the
non-weakened region will resist the drilling action more than the
weakened region.
[0037] Further, axial overlap greater than 50% is believe to result
in degrading the wellbore floor in areas not at or immediately
adjacent the inner gauge diameter. This is significant because it
is believed that the most efficient mechanism for degrading the
formation with the outer blade cutters is by progressively
expanding the inside of the leading bore (inside out degradation)
until the leading bore is the same width as the full gauge diameter
of the wellbore. A inside out degradation is believed to be more
effective than degrading the straight down from the wellbore floor
(straight down degradation) because the straight down degradation
does not take advantage of the pressure relief provided by the
leading bore.
[0038] In some formations, the weakened region may comprise a
distinct boundary, however, many rock formations will likely
experience a weakened continuum that results in the formation being
weaker closer to the inner gauge diameter and harder the farther
away the formation area is from the inner gauge diameter. But,
regardless of the weakened region's characteristics, the cutter
profile on the outer blade with less than 50% axial overlap is
believed to provide the best overall cutter profile efficiency.
[0039] Also if the outer blade cutters overlapped laterally more
than 50%, then the cutters will not expand the leading bore by
cutting into the inner gauge diameter as efficiently as possible.
The more lateral overlap between the outer blade cutters, then less
the successive outer blade cutters will contribute to degrading the
formation because the loads will disportionately fall upon the
central most cutter.
[0040] FIG. 7 discloses an embodiment of a cutter profile 700
relative to the rotational axis 203. The cutter profile 700 may
comprise an outer bit profile 701 and an inner bit profile 702. The
inner bit profile 702 protrudes from the outer bit profile 701. The
outer bit profile 701 and the inner bit profile 702 may overlap
laterally. The overlapping may occur at the outer end of the inner
gauge diameter and at the inner most cutter of the outer bit. It is
believed that the overlapping of the outer bit profile 701 and the
inner bit profile 702 may increase the service life of the drill
bit. This may provide redundancy at the transition between the
outer bit and the inner bit. By overlapping the outer bit profile
701 and the inner bit profile 702, the transition may be reinforced
such that even if a first cutter breaks off, a second cutter may
become engaged in the formation soon thereafter. Such overlapping
may also reduce wear.
[0041] FIG. 8a discloses the outer bit 201 configured to rotate in
a first direction 800 and the inner bit 202 configured to rotate in
a second direction 801. The first and second directions 800, 801
may be in the same direction or in reverse directions. The inner
bit 202 may be disposed coaxial with the outer bit 201 such that
the rotational axis of the outer bit 201 may also be the axis of
rotation for the inner bit 202.
[0042] The bit may include shear cutters and/or pointed cutters.
The area of engagement on the drill bit assembly 103 may include
shear cutters, diamond enhanced cutters, pointed cutters, rounded
cutters or combinations thereof. The pointed cutters may be better
suited for the inner portions of both the working face of the inner
and outer bit, while the shear cutters may be better suited for the
gauge portions of the inner bit 202 and outer bit 201. The pointed
cutters preferably comprise a rounded apex with a radius of
curvature between 0.050 and 0.120 inches. The radius of curvature
may be formed along a central axis of the cutter. The shear cutters
may have sharp, chamfered, or rounded edges.
[0043] This embodiment further discloses at least one fluid nozzle
802 disposed on the outer bit 201 and at least one fluid nozzle 803
disposed on the inner bit 202. A fluid pathway may be disposed
between the outer bit 201 and the inner bit 202. During normal
drilling operations, the degraded formation 105 may be removed from
the bottom of the bore hole to allow for greater drilling
effectiveness. Fluid from the at least one fluid nozzle 802 on the
outer bit and the at least one fluid nozzle 803 on the inner bit or
from the fluid pathway may remove the degraded formation 105 from
the bottom of the bore hole through an annulus of the bore
hole.
[0044] FIG. 8b discloses the inner bit 202 protruding from the
outer bit 201. The inner bit 202 may be disposed eccentric with
respect to the outer bit 201. During normal drilling operations,
the inner bit 202 may rotate around the rotational axis of the
outer bit 201. In another embodiment, the drill bit 104 may be
configured to hammer the inner bit 202 into a formation. Hammering
the inner bit 202 into the formation and rotating the inner bit 202
around the center axis may allow the inner bit 202 to weaken the
formation through a combinations of mechanisms.
[0045] FIG. 9 discloses the central most cutter 302, a second most
central cutter 303, and the successive cutters aligned on a convex
segment of the outer blade 204. FIG. 10 discloses these cutters
aligned on a concave segment of the outer blade 204.
[0046] Whereas the present invention has been described in
particular relation to the drawings attached hereto, it should be
understood that other and further modifications apart from those
shown or suggested herein, may be made within the scope and spirit
of the present invention.
* * * * *