U.S. patent application number 11/367097 was filed with the patent office on 2007-09-06 for fixed cutter drill bit for abrasive applications.
Invention is credited to Shelton W. Alsup, Michael G. Azar, Carl Hoffmaster, Sidney J. Isnor, Thomas W. Oldham, Stuart R. Oliver.
Application Number | 20070205023 11/367097 |
Document ID | / |
Family ID | 36219110 |
Filed Date | 2007-09-06 |
United States Patent
Application |
20070205023 |
Kind Code |
A1 |
Hoffmaster; Carl ; et
al. |
September 6, 2007 |
Fixed cutter drill bit for abrasive applications
Abstract
The invention provides a fixed cutter drill bit for drilling
through unconsolidated, highly abrasive formations. The bit
includes a bit body having a cutting face and a side portion. The
bit body comprising carbide matrix material. A plurality of blades
azimuthally spaced about the cutting face and a plurality of
cutters disposed along the blades. At least one gage pad is
disposed along a side of the bit body and includes wear resistant
gage elements formed of a material more wear resistant than the
matrix material forming a portion of the gage pad. The wear
resistant elements have a rounded surface and are embedded in gage
pad material proximal a leading edge of the gage pad to provide a
rounded wear-resistant edge or surface proximal the leading
edge.
Inventors: |
Hoffmaster; Carl; (Houston,
TX) ; Alsup; Shelton W.; (Houston, TX) ; Azar;
Michael G.; (The Woodlands, TX) ; Oldham; Thomas
W.; (The Woodlands, TX) ; Oliver; Stuart R.;
(Magnolia, TX) ; Isnor; Sidney J.; (Calgary,
CA) |
Correspondence
Address: |
SMITH INTERNATIONAL INC.
16740 HARDY
HOUSTON
TX
77032
US
|
Family ID: |
36219110 |
Appl. No.: |
11/367097 |
Filed: |
March 3, 2006 |
Current U.S.
Class: |
175/408 ;
175/425 |
Current CPC
Class: |
E21B 17/1092 20130101;
E21B 10/43 20130101; E21B 10/54 20130101; E21B 10/26 20130101; E21B
10/55 20130101; E21B 10/567 20130101 |
Class at
Publication: |
175/408 ;
175/425 |
International
Class: |
E21B 10/62 20060101
E21B010/62 |
Claims
1. A fixed cutter drill bit for drilling through unconsolidated,
highly abrasive formations, the drill bit comprising: a bit body
having a cutting face and a side portion, the bit body comprising
carbide matrix material; a plurality of blades azimuthally spaced
about the cutting face; a plurality of cutters disposed along the
blades; and at least one gage pad disposed along a side of the bit
body, the at least one gage pad comprising wear resistant elements
formed of a material more wear resistant than matrix material
forming a portion of the gage pad, the wear resistant elements
having a rounded surface and at least partially embedded in the
gage pad proximal the leading edge to provide rounded
wear-resistant protection proximal the leading edge.
2. The drill bit of claim 1, wherein the matrix material comprises
tungsten carbide powder having an average grain size of about 60
.mu.m or less formed with a metallic binder.
3. The drill bit of claim 1, wherein the matrix material comprises
a matrix power including at least about 40% by weight tungsten
carbide having an average particle size of between about 0.2 and 30
.mu.m formed with a metallic binder.
4. The drill bit of claim 1, wherein the matrix material comprises
cast carbide in an amount of at least about 40% or more by
weight.
5. The drill bit of claim 1, wherein the bit body, at least one of
the blades, or the at least one gage pad comprises a coating of
ultrahard material or ultrahard material embedded in a surface
thereof.
6. The drill bit of claim 5, wherein the at least one of the blades
or the at least one gage pad comprises ultrahard material embedded
therein.
7. The drill bit of claim 6, wherein the ultrahard material
comprises diamond grit impregnated in the gage pad surface.
8. The drill bit of claim 7, wherein substantially the entire gage
pad surface around the wear resistant elements is impregnated with
diamond grit.
9. The drill bit of claim 5, wherein the at least one blade
comprises a plurality of blades having surface set diamonds
embedded in blade tops.
10. The drill bit of claim 5, wherein the ultrahard material has a
grain size of at least about 700 .mu.m or more.
11. The drill bit of claim 1, wherein the bit body, the blades, or
the at least one gage pad is formed of a first matrix material and
a second matrix material wherein the first matrix material has a
different wear resistance than the second matrix material.
12. The drill bit of claim 1, wherein at least one of the blades
increases in thickness in a direction away from the center of the
bit body, and is configured to have a wider blade base than blade
top along a portion thereof.
13. The drill bit of claim 12, wherein at least one of the blades
has a blade front face angle or a blade back face angle greater
than about 5.degree..
14. The drill bit of claim 12, wherein at least one blade has a
blade front radius of curvature or a blade back face radius of
curvature of least about 0.375 inches.
15. The drill bit of claim 1, wherein a majority of the cutters
have a back rake angle of at least about 20.degree..
16. The drill bit of claim 15, wherein selected ones of said
cutters have a back rake angle of at least about 30.degree..
17. The drill bit of claim 1, where the cutters along a majority of
the blades increase in back rake angle along a profile of the bit
toward gage.
18. The drill bit of claim 1, wherein selected ones of the cutters
have a side rake angle greater than 0.degree. degrees.
19. The drill bit of claim 1, wherein the cutters on the bit are
arranged in a short parabolic cutting profile.
20. The drill bit of claim 1, wherein the cutters are positioned to
minimize an imbalance force on the bit or a difference in work rate
between cutters on the bit.
21. The drill bit of claim 1, wherein cutters along at least one of
the blades are arranged to form a helix angle of less than
5.degree..
22. The drill bit of claim 21, wherein the cutters along the at
least one of the blades are arranged to form a helix angle of
2.degree. or less.
23. The drill bit of claim 1, wherein at least one of the cutters
comprises a bevel about a periphery of its cutting face, wherein
the bevel has width of at least about 0.012 inches and is at an
angle of around 45.degree. from a side surface of the cutter.
24. The drill bit of claim 1, wherein a majority of adjacent
cutters along the blades are spaced about 0.04 inches or less
apart.
25. The drill bit of claim 1, wherein a majority of the cutters
positioned on the blades have an exposed substrate length of around
13 mm or less.
26. The drill bit of claim 25, wherein selected ones of the cutters
have an exposed substrate length of about 9 mm or less.
27. The drill bit of claim 1, wherein a majority of the cutters
have a diameter of at least about 16 mm.
28. The drill bit of claim 27, wherein at least some of the cutters
have a diameter of at least about 19 mm.
29. The drill bit of claim 1, wherein a cutter extent from a
corresponding blade front face is less than or equal to about 0.06
inches.
30. The drill bit of claim 29, wherein a majority of the cutters
are arranged substantially flush with corresponding blade front
faces.
31. The drill bit of claim 1, wherein the bit comprises less than 8
blades.
32. The drill bit of claim 31, wherein the bit comprises 6 blades
or less.
33. The drill bit of claim 1, wherein at least one of the cutters
comprise a table of ultrahard material integrally formed with a
carbide substrate comprising tungsten carbide particles formed with
a metallic binder, and the substrate comprises one selected from
the group of a binder content of 12% by weight or less a hardness
of at least about 90 Ra, and a tungsten carbide content of at least
about 88% by weight.
34. The drill bit of claim 33, wherein the substrate has an average
carbide particle size of about 3 microns or less.
35. The drill bit of claim 33, wherein the substrate further
comprises ultrahard particles embedded therein.
36. The drill bit of claim 35, wherein the substrate further
comprises an ultrahard element band embedded therein and generally
positioned behind the table of ultrahard material forming a cutting
face.
37. The drill bit of claim 33, wherein a coating is disposed on at
least a portion of the substrate and the coating comprises
ultrahard material.
38. The drill bit of claim 33, wherein the table of ultrahard
material comprises polycrystalline diamond bonded to the substrate
and the polycrystalline diamond is partially or entirely thermally
stable.
39. The drill bit of claim 1, wherein the at least one gage pad
having a circumferential width of at least about 2 inches or
comprising a plurality of gage pads arranged about the bit body to
provide a total gage pad peripheral coverage of greater than or
equal 30% of the circumference of the bit.
40. The drill bit of claim 1, wherein the at least one gage pad
extends a length of at least about 2 inches along the side of the
bit body.
41. The drill bit of claim 40, wherein the at least one gage pad
extends a length of at least about 4 inches along a side of the bit
body.
42. The drill bit according to claim 1, wherein at least one
back-reaming element is positioned along a heel surface of the bit
to back-ream formation in a path of the bit when the bit is pulled
from a wellbore.
43. The drill bit according to claim 1, wherein a second plurality
of wear-resistant comprising rounded surfaces and embedded in the
surface of the gage pad proximal a trailing edge of the gage pad to
provide rounded wear resistant proximal the trailing edge.
44. The drill bit of claim 43, wherein the wear resistant elements
proximal the leading edge of the gage pad are generally cylindrical
in form and aligned substantially end to end along the leading edge
to provide a rounded wear resistant edge along the leading edge of
the gage pad.
45. The drill bit of claim 44, wherein the wear resistant elements
proximal the trailing edge of the gage pad are also generally
cylindrical in form and aligned substantially end to end along the
trailing edge to provide a rounded wear resistant edge surface
along the trailing edge of the gage pad.
46. The drill bit of claim 43, wherein the wear resistant elements
proximal at least one of the leading edge and the trailing edge of
the gage pad are positioned to generally cover at least 75% of the
gage pad length along the corresponding edge.
47. The drill bit of claim 1, wherein the at least one gage pad is
slanted at an angle with respect to the longitudinally axis of the
bit such that at least one of the leading or a trailing edges of
the gage pad is oriented at an angle of at least about 10.degree.
with respect to the longitudinal axis of the bit.
48. The drill bit of claim 43, wherein a third plurality of wear
resistant elements are arranged proximal at least one is also
disposed proximal a bottom edge and a top edge of the gage pad.
49. The drill bit of claim 48, wherein the wear resistant elements
comprise elements selected from the group of thermally stable
polycrystalline diamond elements, polycrystalline diamond elements,
and grit hot-pressed inserts.
50. The drill bit of claim 43, wherein a plurality of interiorly
positioned wear resistant elements along a surface of the gage pad
between the leading and trailing edges and comprise diamond
enhanced inserts or TSP elements having diameters of at least about
13 mm.
51. The drill bit of claim 50, wherein at least one of the diamond
enhanced inserts or TSP elements has a diameter of at least about
16 mm.
52. The drill bit of claim 51, wherein a plurality of the diamond
enhanced inserts or TSP elements have a diameter of at least about
16 mm.
53. The drill bit of claim 50, wherein the diamond enhanced inserts
have substrate lengths of at least about 13 mm and at least a
portion of the substrate is embedded in the gage pad.
54. The drill bit of claim 50, wherein the plurality of diamond
enhanced inserts or TSP elements comprises at least 5.
55. The drill bit of claim 50, wherein wear resistant elements
cover at least about 50% of the outer surface of the gage pad.
56. The drill bit of claim 43, wherein the wear resistant elements
disposed proximal the leading edge or the trailing edge comprise a
plurality of diamond enhanced inserts having a diameter of at least
about 13 mm.
57. The drill bit of claim 1, wherein the drill bit comprises a
plurality of heel surfaces each having at least one back reaming
element disposed along the heel surface.
58. The drill bit of claim 57, wherein a plurality of back reaming
elements is disposed along each of the heel surfaces.
59. The drill bit of claim 57, wherein the back reaming elements
comprise PDC cutters having a diameter of at least about 13 mm.
60. The drill bit of claim 59, wherein the cutters comprise
polycrystalline diamond having a thermally stabilized surface
layer.
61. The drill bit of claim 60, wherein the PDC cutters comprises a
substrate having a length of at least about 13 mm.
62. The drill bit of claim 1, further comprising fluid ports
disposed in the bit body and oriented to direct fluid towards a
center of a corresponding fluid channel or away from a
corresponding blade front face.
63. The drill bit of claim 1, wherein a coating of ultrahard
material is applied to a portion of the bit body by chemical vapor
deposition.
64. The drill bit of claim 1, wherein a surface of the bit
comprises a diamond coating.
65. The drill bit of claim 1, further comprising a plurality of
fluid ports generally disposed between the blades wherein a number
of fluid ports is greater than the number of blades.
66. The drill bit of claim 1, wherein the drill bit further
comprises a fluid port and the fluid port comprises a diffuser
nozzle.
67. A method for drilling unconsolidated, ultra abrasive
formations, comprising: rotating a bit designed in accordance with
claim 1.
68. A method of manufacturing a drill bit for high rate of
penetration unconsolidated abrasive drilling environments, the
method comprising: constructing a bit in accordance with claim
1.
69. A method of brazing a cutter to a bit comprising: heating braze
material between a cutter and a cutter pocket; and maintaining a
temperature of the braze material between a liquidus temperature
and a solidus temperature while filing gaps between the cutter and
the cutter pocket with the braze material.
70. The method of claim 69, wherein the difference between the
liquidus temperature and the solidus temperature is 40.degree. C.
or more.
71. The method of claim 70, wherein the difference between the
liquidus temperature and solidus temperature is 60.degree. C. or
more.
72. A fixed cutter drill bit, comprising: a bit body having a
cutting face and a side portion; a plurality of blades azimuthally
spaced about the cutting face; a plurality of cutters disposed
along the blades; a gage pad disposed along a side of the bit body,
the gage pad comprising: at least one wear resistant element
disposed proximal a leading edge of the gage pad, the at least one
wear resistant element arranged to span at least about 75% of the
gage pad length.
73. The fixed cutter drill bit of claim 72, wherein the at least
one element comprises a plurality of wear resistant elements, and
the plurality of wear resistant elements span substantially 100% of
at least an inch segment of the gage pad length.
74. The fixed cutter drill bit of claim 72, wherein the gage pad
comprises six or more inserts comprising diamond material and
having a diameter of 13 mm or more.
75. The fixed cutter drill bit of claim 72, where in the at least
one element comprises a plurality of diamond grit hot-pressed
inserts.
76. The fixed cutter drill bit of claim 75, wherein the inserts
comprise a rounded surface and are positioned in the gage pad to
form a rounded edge along the gage pad during drilling.
77. The fixed cutter drill bit of claim 72, wherein the at least
one wear resistant element comprises a plurality of DEIs and TSPs,
wherein the DEIs are arranged in three or more rows with one row of
DEIs positioned proximal the leading edge of the gage pad with TSPs
positioned there between.
78. The fixed cutter drill bit of claim 72, further comprising
matrix material impregnated with diamond grit disposed on an outer
surface of the gage pad.
79. A fixed cutter drill bit, comprising: a bit body having a
cutting face and a side portion, the bit body comprising carbide
matrix material; a plurality of blades azimuthally spaced about the
cutting face; a plurality of cutters disposed along the blades with
cutting faces, the cutters arranged on the blades to have an extent
from a corresponding blade front face of about 0.10 inches or less,
with a majority of adjacent cutters having a spacing of less than
0.25 inches between the cutting faces; a plurality of gage pads
formed of carbide matrix material arranged around the side portion
of the bit body with outward facing surfaces extending
substantially to a gage diameter of the bit, the outward facing
gage surfaces including wear resistant elements embedded therein
and having remaining portions thereof formed from matrix material
impregnated with ultrahard particles; and at least one back reaming
element positioned along a surface of the bit to back ream
formation in a path of the bit when the bit is pulled from a
wellbore.
80. The fixed cutter drill bit of claim 80, wherein said ultrahard
particles comprise diamond grit.
Description
BACKGROUND OF INVENTION
[0001] 1. Field of the Invention
[0002] The invention relates to fixed cutter drill bits designed
for abrasive applications, and more particularly to fixed cutter
bits designed for high rate of penetration drilling in
unconsolidated ultra abrasive formations.
[0003] 2. Background Art
[0004] Different types of drill bits have been developed and found
useful in different drilling environments. Bits typically used for
drilling boreholes in the oil and gas industry include roller cone
bits and fixed cutter. Cutting structures on bits vary depending on
the type of bit and the type of formation being cut. Roller cone
cutting structures typically include milled steel teeth, tungsten
carbide inserts ("TCIs"), or diamond enhanced inserts (DEIs).
Cutting structures for fixed cutter bits typically include
polycrystalline diamond compacts ("PDCs"), diamond grit impregnated
inserts ("grit hot-pressed inserts" (GHIs)), or natural diamond.
The selection of a bit type and cutting structure for a given
drilling application depends upon many factors including the
formation type to be drilled, rig equipment capabilities, and the
time and cost associated with drilling.
[0005] In drilling unconsolidated, ultra abrasive formations, bit
life is limited due to excessive wear; therefore, bit cost has
become a significant factor in the selection of bits for this
environment. One example of an unconsolidated, ultra abrasive
drilling application includes drilling of the pay zone of heavy oil
reservoirs. Heavy oil reservoirs typically comprise unconsolidated
to low compressive strength, yet highly abrasive sands that are
permeated with thick, dense heavy oil. These dense, high viscosity
liquid hydrocarbons are also sometimes referred to as bitumen.
[0006] Heavy oil production typically requires special oil recovery
techniques, such as the injection of heat and/or pressure into the
reservoir to reduce the viscosity of the oil and enhance its flow.
One commonly used recovery technique is known as steam-assisted
gravity drainage (SAGD), which involves drilling a pair of
horizontal wells, typically one above the other, through the
reservoir as shown in FIG. 12, wherein the upper well is used for
steam injection into the reservoir and the lower well is used to
produce the heavy oil. This is further described in Curtis, et al.,
"Heavy-Oil Reservoirs", Oilfield Review, Autumn 2002, pp. 50.
[0007] Horizontal wellbores drilled through heavy oil reservoirs
often extend 1000 meters or more through the reservoir. To maximize
oil recovery in a larger reservoir, multiple directional wells may
be drilled from a common wellbore to reduce the distance the oil
has to travel through rock to reach a wellbore.
[0008] Drill bits used in unconsolidated, ultra abrasive
applications are typically damaged beyond repair after a first run
due to the extreme abrasion and erosion encountered during
drilling. Milled tooth roller cone bits have been considered the
most economically feasible bit for these applications because they
cost significantly less than other bits and offer more aggressive
cutting structures for higher ROP. Fixed cutter bits are generally
not used in these applications because they cost 5 to 10 times more
than a comparable roller cone bit and typically become damaged
beyond repair after a first run, such that their higher cost can
not be justified.
[0009] Although roller cone bits have been found to be most
economically feasible for unconsolidated, ultra abrasive
applications, the useful life of these bits is limited. As a
result, several bits are typically required to complete a wellbore
and the trips back to surface to replace the bits and the number of
bits required to complete a well have a significant economic impact
on a drilling program. However, up to now, milled tooth bits have
still been found to be more economically feasible when compared to
the significant cost of using a conventional fixed cutter PDC
bit.
[0010] What is desired is a fixed cutter drill bit that offers
increased useful life in high ROP, unconsolidated, ultra abrasive
applications. In particular, such bits may be useful in reducing
the number of trips required to complete wellbores in heavy oil
drilling applications, or similar applications. Additionally, a
drill bit capable of maintaining gage over an extended drilling
operation in any highly abrasive environment is desired. Also
desired is a more abrasive resistant drill bit that may be used to
achieve higher rates of penetration (ROP) to provide a positive
economic impact in a drilling program for a heavy oil drilling
application.
SUMMARY OF INVENTION
[0011] In one aspect, the present invention provides a fixed cutter
drill bit providing improved performance in a high rate of
penetration unconsolidated abrasive drilling operation.
[0012] In one embodiment, the bit includes a bit body having a
cutting face and a side portion. The bit body is formed of carbide
matrix material. A plurality of blades azimuthally spaced about the
cutting face and a plurality of cutters disposed along the blades.
At least one gage pad is disposed along a side of the bit body and
comprising wear resistant gage elements formed of a material more
wear resistant than the matrix material forming a portion of the
gage pad. The wear resistant elements include a rounded surface and
are embedded in gage pad material proximal a leading edge of the
gage pad to provide a rounded wear-resistant edge or surface
proximal the leading edge.
[0013] In another embodiment, the drill bit includes a bit body, a
plurality of blades, and a plurality of cutters is disposed along
the blades and arranged to have an extent from a corresponding
blade front face of 0.10 inches or less for a majority of the
cutters. A majority of the adjacent cutters are also positioned to
have spaces there between that are less than 0.25 inches. At least
one gage pad is disposed along a side of the bit body. The at least
one gage pad has a circumferential width that is at least about 2
inches or results in a total gage pad width equal to 30% or more of
the circumference of the bit. At least one wear resistant element
is disposed on the gage pad near a leading edge of the gage pad to
provide wear resistant protection near the leading edge.
Additionally, the bit includes at least one back reaming element
positioned on the bit to back ream formation in a path of the bit
as the bit is pulled from a wellbore.
[0014] Various other aspects and advantages of the invention will
be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0015] FIG. 1 shows is a perspective view of a fixed cutter drill
bit illustrating general features of a bit.
[0016] FIG. 2 shows a plan view of a cutting face for a PDC bit in
accordance with one embodiment of the present invention.
[0017] FIG. 3 shows a perspective view of the cutting face of the
PDC bit shown in FIG. 2.
[0018] FIG. 4A-4B shows wear marks on the blades tops of a PDC bit
having spiral blades after a drilling run in an unconsolidated,
ultra abrasive environment.
[0019] FIGS. 5A-5B show a close up view of a blade of a PDC bit
used for a drilling run in an unconsolidated, ultra abrasive
environment.
[0020] FIG. 5C shows a close up view of a blade on another PDC bit
used for a drilling run in an unconsolidated, ultra abrasive
environment, wherein the blade spiral and spacing between cutters
was reduced compared to the bit in FIGS. 5A-5B and resulted in
reduced wear of matrix material from around the cutters.
[0021] FIG. 6A shows a cross section geometry of a conventional
blade for a PDC bit.
[0022] FIG. 6B shows a cross section geometry of a blade for a PDC
bit in accordance with one embodiment of the invention.
[0023] FIG. 7A shows a blade top for a PDC bit without wear
resistant material embedded in its blade tops or cutter substrates
after a first run in an unconsolidated ultra abrasive
environment.
[0024] FIG. 7B shows a blade top for a PDC bit similar to the one
shown in FIG. 7A but with the addition of wear resistant material
embedded in the blade tops and cutter substrates after a first run
in an unconsolidated ultra abrasive environment.
[0025] FIG. 7C shows the condition of the blade top shown in FIG.
7B after four bit runs.
[0026] FIGS. 8A-8C show a cutter oriented on a blade at a selected
back rake angle in accordance with one embodiment of the present
invention.
[0027] FIG. 9 shows one embodiment of a novel abrasive resistant
gage pad configuration which may be used on a PDC bit in accordance
with one or more embodiments of the present invention.
[0028] FIGS. 10A-10B another embodiment of a novel abrasive
resistant gage pad configuration which may be used on a PDC bit in
accordance with one or more embodiments of the present
invention.
[0029] FIG. 11 shows a partial view of a heel surface of a bit with
back reaming elements positioned on the bit in accordance with an
embodiment of the present invention.
[0030] FIG. 12 shows one example of a multi-well system used for
Steam Assisted Gravity Drainage recovery of heavy oil from a
reservoir.
DETAILED DESCRIPTION
[0031] Reference will now be made to the figures in which various
embodiments of the present invention will be given numerical
designations and in which aspects of the invention will be
discussed so as to enable one skilled in the art to make and use
embodiments of the invention.
[0032] In one aspect, the present invention provides a fixed cutter
drill bit for drilling earth formations, which may be particularly
useful in drilling formations comprising unconsolidated to low
compressive strength, yet highly abrasive sands, such as those
encountered in heavy oil reservoirs. These types of formations will
be generally referred to as "unconsolidated and ultra abrasive" for
simplicity. In another aspect, the present invention provides novel
gage pad configurations for drill bits, which may be particularly
useful on bits designed for any abrasive drilling environment. In
another aspect, the invention provides methods for manufacturing or
rebuilding fixed cutter bits.
Conventional PDC Bits
[0033] Fixed cutter drill bits (also referred to as fixed head bits
or drag bits) are significantly more expensive than mill tooth
roller cone drill bits and are considered to offer less aggressive
cutting structures than roller cone drill bits. However in several
applications fixed cutter bits can be used to drill longer well
segments in a single run and can be rebuilt and reused multiple
times to provide an overall economic benefit that outweighs their
higher cost.
[0034] Fixed cuter bits which include polycrystalline diamond
compact (PDC) cutters are typically referred to as PDC bits. PDC
bits can be rebuilt after being used by heating the entire bit to a
predefined high temperature and then adding material to areas of
the bit where material has been worn away due to erosion or
abrasion. Material is typically added by torch welding or the like.
Additional heat may also be applied to the cutting structure to
melt brazed material around the cutters so that cutters can be
rotated to expose an unworn portion of the cutting edge for
drilling. When cutters cannot be rotated and reused due to
excessive damage or wear, cutters are removed and replaced with new
cutters using additional braze material. Bit rebuilding operations
are typically carried out as quickly and carefully as possible out
to avoid thermal stress cracks in the bit body material. Extensive
rebuild operations require repeated thermal cycling of the bit
which leads to a higher chance of forming thermal stress cracks. If
thermal cracks are found to have developed during a rebuild
operation, the bit must be scrapped and a new bit used. Bits can
only undergo a limited amount of thermal cycling before developing
thermal cracks. Therefore, thermal cycling during a rebuild
operation should be limited when possible to extend the useful life
of a drill bit.
[0035] When considering high rate of penetration (ROP),
unconsolidated, ultra abrasive drilling applications, many PDC bits
are not designed to provide the ROPs demanded in these
applications. PDC bits have also been found to suffer severe
material loss in these unique drilling environments where
unconsolidated ultra abrasive cuttings mix with drilling fluid,
often pumped at high flow rates, to create a highly
abrasive/erosive slurry that flows around surfaces of the bit
during drilling. The bit tends to ride on the abrasive slurry
pumped between surfaces of the bit and the bottomhole, which
results in excessive wear on the bit such that bits cannot be
rebuilt or reused a sufficient number of times to justify their
cost.
[0036] In particular, severe erosion has been found to occur
between cutters, on cutter substrates, and on the blade faces
around the cutters. Severe abrasion has also been found to occur
across blade tops, cutter substrates, gage pad surfaces, and blade
heel surfaces of the bit. For example, a conventional 121/4 matrix
body bit may loose as much as 10 to 12 pounds of material in a
single run when used in an unconsolidated, ultra abrasive
application. These bits typically cannot be rebuilt or rerun and
must be scrapped. In a case where a bit may be rebuilt to attempt a
second run, the rebuild operations required are extensive and often
result in thermal stress cracks. Also, wear and damage sustained by
the cutters are usually such that the cutters cannot be rotated or
reused for a second run.
[0037] In horizontal drilling applications, the gage pads suffer
excessive wear due to constant rubbing action against the formation
and the sharp sands in the abrasive slurry flowing past gage pad
surfaces. This can cause a bit to go under gage prematurely.
Conventional PDC bits also are often less directionally responsive
than roller cone drill bits in these applications and have greater
tendency to drill out of a desired zone and into bounding formation
without any indication at the surface. PDC bits also have gage
surfaces that create multiple points of constant hole wall contact
which results in bits going undergage prematurely in these
environments. Conventional PDC bits have also been found to be more
difficult to trip out of horizontal holes after completing their
drilling requirement in these environments. This is because
cuttings that fail to reach the surface during the drilling tend to
fall to the low side of the hole, effectively creating a restricted
passage back to the surface. Additionally, conventional PDC bits
have been found to be more susceptible to cutter damage when used
to drill out cementing shoes and when engaging more competent
formations above or below the reservoir pay zone. Damage sustained
by conventional PDC bits in these applications leads to costly
rebuild operations or the inability to reuse the bit. Thus,
conventional PDC bits have not been economically feasible
unconsolidated, ultra abrasive drilling applications and are
generally not used.
Fixed Cutter Bits for Unconsolidated, Ultra Abrasive
Applications
[0038] The inventors have studied problems associated with the use
of fixed cutter bits in unconsolidated, ultra abrasive drilling
applications and have discovered several design features that can
be used to significantly extend the life of a fixed cutter drill
bit in these applications to provide a positive economic impact on
a drilling program.
[0039] Examples of the basic features on a PDC bit will now be
generally described with reference to the bit shown in FIG. 1. The
drill bit 100 includes a bit body 102 which has a central axis 104.
The bit body 102 has a connection 106 at one end for connecting to
a drill string and a crown formed at the other end which includes a
cutting face 103 for cutting through earth formation. A plurality
of blades 108 are arranged on the cutting face 103. The blades 108
are azimuthally spaced apart and extend radially and lateral along
the cutting face 103. A plurality of cutters 110 are mounted in
pockets 109 formed on the blades 108. The cutters 110 are typically
attached to the blades 108 by braze material or the like. The
cutters 110 are generally arranged in rows along each of the blades
108, with each cutter 110 mounted at a selected radial position
relative to the central axis 104 of the bit 100. The cutters 110
are positioned and oriented on the blades to engage with earth
formation as the bit 100 is rotated on earth formation under an
applied force. The cutters 110 comprise a body of ultrahard
material 111 bonded to a substrate 112 which is typically formed of
less hard material. Transition layers may also be disposed between
the ultrahard body 111 and the substrate 112. The ultrahard body
111 is positioned to form the cutting face 111 for the cutters 110.
The ultrahard body 111 typically comprises polycrystalline diamond
(PCD), although other ultrahard materials known in the art may be
used, such as cubic boron nitride. In the case of PCD, a region or
the entire PCD body may be treated to render it thermally stable,
such as by removing solvent metal catalyst from a region or the
entire body through a suitable process, such as acid leaching, aqua
regia bath, electrolytic process, or combinations thereof. One
example of a suitable acid leaching method that may be used is
disclosed in U.S. Pat. No. 4,224,380, which is incorporated herein
by reference. Alternatively, the PCD body may be formed using a
catalyzing material, such as silicon, that does not adversely
affect diamond bonded grains of the PCD body at elevated
temperatures.
[0040] A gage region is also formed along an outer side surface 125
of the bit body 102 and includes one or more gage pads 124 having
surfaces that extend proximal the gage diameter of the bit 100. One
or more gage inserts 127 are embedded in material forming the gage
pad 124 to contact the side wall of the wellbore and help maintain
the gage diameter being drilled. Gage pads 124 also help to
stabilize the drill bit 100 against vibration. In the example
shown, a plurality of gage pads 124 are formed at the ends of
blades 108 and are spaced apart around the periphery of the bit
body 102 with junk slots 126 defined there between. Gage pads which
extend around the entire periphery of the body are also known in
the art and may be used.
[0041] A central longitudinal bore (not shown) which extends into
the bit 100 permits drilling fluid to flow from a drill string into
the bit 100. A plurality of openings or flow passages 118 are
positioned in the cutting face 103 of the bit 100 and in fluid
communication with central bore. The flow passages 118 are
configured for mounting nozzles 120 therein which serve to
distribute drilling fluid around the cutters 110 and cutting face
103 of the bit body 102. The nozzles direct fluid to flush
formation cuttings away from the cutting structure and borehole
bottom during drilling. Grooves or channels 122 between the blades
108 serve as drilling fluid flow courses for directing drilling
fluid and cuttings radially outward away from the cutting face 103.
The junk slots 126 between the gage pads 124 of the bit 100 are in
fluid communication with the channels 122 and permit drilling fluid
and formation cuttings to flow away from the cutting face 103 and
up an annulus formed between the drill string and the wall of the
borehole during drilling.
[0042] In this example, small hard elements 128 are also provided
along on a heel surface 129 of the bit 100 to help "back ream" or
remove formation in the path of the bit as the bit 100 is pulled
from the borehole.
Matrix Body Bit
[0043] Features of embodiments of the invention will now be
described with reference to FIG. 2. FIG. 2 shows one example of a
cutting face design for a drill bit in accordance with aspects of
the present invention. The bit body 202, blades 208 and gage pads
224 in this embodiment are generally formed of matrix material to
provide greater abrasion and erosion resistance than conventional
steel bodies. The matrix material may comprise tungsten carbide
infiltrated with binder material. The matrix bit may be formed in
any conventional manner known in the art, such as by packing a
graphite mold with a mix of tungsten carbide powder and then
infiltrating the powder with a molten alloy binder in a furnace and
allowing it to cool to form a hard metal cast matrix body. Examples
of methods and materials for forming matrix body bits are further
described in U.S. Pat. No. 5,662,183, U.S. Pat. No. 6,287,360, and
U.S. Pat. No. 6,375,706 which are all assigned to the assignee of
the present invention and incorporated herein by reference. While
reference is made to tungsten carbide powder above, the powder may
also include other materials, such as nickel, iron, cobalt, and/or
other various alloys. A matrix bit may be formed using other
transition metal carbides, such as molybdenum, niobium, tantalum,
hafnium, and vanadium.
Ultrahard Cutters
[0044] Any cutters suitable for abrasive drilling applications may
be used in accordance with embodiments of the present invention. In
the embodiment shown in FIG. 2, the cutters comprise a table or
body of ultrahard material 211 bonded to a substrate 212 of less
hard material. Typical cutters used are polycrystalline diamond
compact (PDC) cutters, wherein the ultrahard material 211 comprises
a polycrystalline diamond table and the substrate 212 comprises
tungsten carbide. Other embodiments may comprise cutters 210 formed
of any ultrahard material and substrate material suitable for drill
bit cutters, including polycrystalline diamond, polycrystalline
cubic boron nitride, tungsten carbide, combinations thereof, or
other metal carbide.
[0045] PDC cutters can be formed by placing a cemented carbide
substrate or components for forming a carbide substrate into a
press container. A mixture of diamond grains or diamond grains and
catalyst binder is then placed on top the substrate and the
container assembly is subjected to high pressure, high temperature
conditions such that the metal binder migrates from the substrate
and through the diamond grains to promote bonding of the diamond
grains to each other to form the diamond layer, subsequently
bonding the diamond layer to the substrate. The catalyst or binder
material commonly used includes cobalt. The catalyst material may
later be removed or depleted from the working surface of the cutter
for enhanced abrasion resistance. One or more intermediate layers
of material may also be disposed between the diamond layer and the
substrate, as is known in the art. Additionally, the cutter may
include a non-planar interface between the diamond layer and
substrate.
[0046] In one or more embodiments of the present invention, larger
cutters are used on the bit to allow for higher rates of
penetration. In one or more embodiments, cutters having a diameter
of 16 mm or larger are disposed along the blades of the bit. For
the example embodiment shown in FIG. 5C, 16 mm and 19 mm cutters
were used.
Cutter Placement
[0047] Many PDC bit designs have cutters spaced apart along the
blades and positioned to extend from a front of the blade front
face. However, these cutter arrangements can lead to increased
recirculation of abrasive slurry around the cutters and blades and
excessive abrasive and erosive wear on the cutters, blades, and
braze material. Therefore, as shown in FIG. 2, cutters 210 are
preferably placed closer together along the blades 208. By reducing
the amount of space between adjacent cutters 210 less abrasive
slurry is allowed to flow between cutters and across the blade tops
232, which can significantly reduce wear on the cutting
structure.
[0048] Therefore, cutters 210 are preferably arranged on the blades
208 such that adjacent cutters on a blade 208 have a spacing there
between of 0.25 inches or less. In selected embodiments, this
spacing may be closer to around 0.040 inches or less and may be
applied to a majority of adjacent cutters 210 on the blades 208
where possible. Arranging cutters 210 closer together along the
blades 208 also provides greater ultrahard coverage along the
leading edge of the blades 208 which leads to an overall reduction
of wear on cutters. Reducing the spacing between cutters to 0.25
inches or less, and more preferably to 0.10 inches or less, can
help reduce wear on the blade s 208 and the cutters 210, such that
less material is lost from the bit during drilling. This can help a
bit effectively handle longer drilling runs and extend the useful
life of the bit. In particular, this can reduce the time and number
of thermal cycles required for a rebuild operation.
[0049] In one or more embodiments, blades 208 of the bit 200 are
also preferably formed to have a limited helix from cutter to
cutter. Referring to FIGS. 4A and 4B, increased blade spiraling
typically requires that the cutters 710 be physically spaced
further apart at the front face 735 of the blades 708 due to space
limitations at the bases of the cutters. Additionally, when a
significant degree of spiral is applied to cutters along a blade,
wear occurs on the tops of the blades 708. Corresponding spiraled
wear grooves 761 have been found to form across blades tops 732 due
top abrasive slurry flowing in a spiraled pattern between cutters
710. This can also result in increased erosion on cutter substrate
712 for some bit designs. By minimizing the helix spiral of the
blades 708 or the cutters 710, cutters 710 can be spaced closer
together along the blades 708 to minimize erosive wear on the bit.
Therefore, in one or more embodiments, a blade helix angle may be
limited to 5.degree. to allow for a closer spacing of cutters and
to help reduce wear on the bit. In other cases, helix angles may be
limited to 3.degree. or less, and in some cases 1.degree. or less
may be preferred.
[0050] Referring again to FIG. 3, the inventors have also found
that by placing cutters 210 on the blades 208 with a limited
extension from a blade front face 232 can also help to reduce wear
on the cutting structure of the bit. By restricting the extent of
cutters 210 from the blades 208 to 0.10 inches or less, abrasive
wear around the cutters 210 due to recirculation of the abrasive
slurry can be reduced. In selected embodiments, cutter extents of
0.06 inches or less may be used, and in some cases 0.03 inches or
less may be preferred. In the embodiment shown in FIG. 3, the
cutters are substantially flush with the blade front face 235. In
another embodiment, one or more of the cutters may be set recessed
from the blade front face.
[0051] Examples of test bits used for a drilling run in an
unconsolidated, ultra abrasive formation are shown in FIGS. 5A-5C.
FIG. 5A shows a close up view of a first bit used, wherein adjacent
cutters 810 were spaced further apart along the blade front face
835 than the cutters on a second bit shown in FIG. 5C. The cutter
spacing 859 for the bit in FIG. 5A is partially due to an increased
spiral of the blades 808 in this design, as shown in FIG. 5B. The
bit in FIG. 5C had substantially straight blades and a smaller
spacing 859 between adjacent cutters 810. The cutter arrangement
shown in FIG. 5A resulted in more matrix material erosion on the
front face 835 of the blades 808 below and between the cutters 810
than for the bit shown in FIG. 8C. Wear was also noted on cutter
substrates 812. B reducing the helix and minimizing the amount of
space between cutters, less abrasive flow was directed between and
around the cutters and wear on the cutting structure was
reduced.
Thicker Blades and Gage Pads
[0052] In one or more embodiments, the bit also includes thicker
blades and gage pads which may also help to increase the useful
life of the drill bit in ultra abrasive applications. For example,
referring to FIG. 3, the gage pads 224 in this embodiment are
configured to span a circumferential width, w, of at least about 2
inches at a point along their length. However, in other
embodiments, gage thickness will depend on the number of gage pads
in the bit design and the diameter of the bit. Therefore, in other
embodiments, the gage pads may be arranged around the bit to
provide a total width of gage surface around the bit that is
greater than or equal to 30% of the circumference of the bit. For
example, a six blade, 121/4 inch diameter bit may be configured to
have six gage pads, each with a gage with, w, of between about 2
and 31/2 inches, such as around 21/2 inches or more, resulting in a
total gage pad width of 15 inches or more which is around 39% of
the circumference of the bit.
[0053] Space available for blade thickness is limited near the
crown of the bit 200. However, in one or more embodiments, the
blades 208 may be configured to increase in thickness in a
direction away from the center of the bit 200 toward the gage pads
224. The blade thickness will generally depend on the diameter of
the bit 200 and the number of blades 208 in the bit design.
Therefore, in one or more embodiments, the number of blades on the
bit may be limited to eight blades or less, and in many cases six
blades or less to allow for thicker blades as well as higher ROPs.
However, for the six bladed, 121/4 inch bit described above, the
blades 208 can be generally configured to increase in thickness
along their length toward the gage region to a width close to the
selected width of the gage pad.
[0054] In the embodiments shown in FIGS. 2 and 3, the blades
supporting the gage pads 224 are formed continuous with the cutting
structure blades (208). In other embodiments, space may be provided
between the blades 208 extending from the crown of the bit 200 and
the blades or structure supporting the gage pads 224 on the side of
the bit body 202. Additionally, a bit may be configured to have a
single gage pad that extends around the periphery of the bit with
junk slots provided between the bit body and gage pads; however in
many applications a bit having a plurality of gage pads spaced
apart with substantially unrestricted junk slots there between may
be preferred.
[0055] The inventors have determined that providing increased blade
thickness can increase the number of rebuild operations a bit can
undergo before developing thermal stress cracks. Thicker blades and
gage pads have been found to retain heat better during rebuild
operations such that more rebuild work can be done in a single heat
cycle and the number of thermal cycles required during a rebuild
operation can be reduced. Additionally, blades and gage pads that
are initially thicker than structurally required increase the
chances of the bit being structurally sound for a second run before
needing to be rebuilt. This can also reduce the time required for a
rebuild operation because less material will need to be added to
the bit to place it into a structurally sound rerunable condition.
As a result, both the rerunability (ability to rerun the bit) and
the repairability (ability to repair the bit multiple times) can be
increased to enhance the economic feasibility of fixed cutter bits
in unconsolidated, ultra abrasive drilling applications.
[0056] Referring now to FIGS. 6A and 6B, in one or more
embodiments, a drill bit may also be configured to include a radius
corner at the base of a blade between the blade and the bit body
where thermal stresses tend to build up during a rebuild operation.
As shown in FIG. 6A, PDC bits may be designed to have a sharp
corner at the blade base 634 where the blade front faces 635 or
blade back faces 637 join with the bit body 602. When the faces are
substantially perpendicular to the bit body, this is considered a
0.degree. blade front face angle or blade back face angle. High
thermal stresses have been found to develop in these sharp corners
during rebuild operations. Therefore, referring to FIG. 6B, in one
or more embodiments, a bit may be configured to have more rounded
corners at the base 634 of blades 608. For example, the blade front
face 635 and/or the blade back face 637 may be configured to have a
larger blade front face angle 636 and/or blade back face angle 638
so that a larger radius of curvature (655, 657) is formed at the
base 634 of the blade 608. Alternatively, the blades may be formed
to include a desired radius of curvature (655, 657), such as a
radius of curvature of around 0.375 inches or more. In one or more
embodiments, bits may be designed to have blade front angles 636 or
blade back face angles 638 of 1.degree. or more, and in some cases
of at least about 5.degree. or more. In one embodiment the blades
were configured to have blade front face and back face angles of
around 10.degree.. Providing a radius at the base of one or more
blades can help reduce the chance of developing thermal stress
cracks in that area during repeat rebuild operations.
[0057] As shown in FIG. 6B, in some embodiments one or more of the
blades 608 may be configured to increase in thickness from the
blade top 612 to the blade base 634 to provide a more robust blade
for handling longer runs or a greater number of runs before needing
to be rebuilt. Also, as noted above, thicker blades have been found
to retain heat better during rebuild operations and may reduce the
thermal cycling required to rebuild a bit. This can also increase
in the number of rebuild operations a bit can undergo before
developing stress cracks. In some cases, drill bits having blade
tops that increase in width in a radial direction toward gage and
increase in width in an axial direction toward the base of the
blade may be desired for enhanced rerunability and repairability in
heavy oil drilling applications.
Increased Wear Resistant Surfaces
[0058] Additionally, in one or more embodiments, matrix materials
used to form outer surfaces of the bit body, blades, and/or gage
pads may be selected to provide increased wear resistance over
other matrix materials commonly used for PDC bits in applications,
such as high impact applications. For example, matrix materials
having a higher hardness or higher carbide content may be used to
provide increased wear resistance. Alternatively, the wear
resistance of matrix material can be increased by using more fine
grain carbide powder to form the matrix. This can also result in a
higher carbide content and lower binder content when the matrix
body is formed. For example, a tungsten carbide matrix powder used
to form portions of the bit body, blades, and/or gage pads may
include a higher percentage of fine tungsten carbide particles to
achieve an average tungsten carbide grain size of 60 .mu.m or less,
and in some cases 50 .mu.m or less. Alternatively, the matrix
powder used may include at least about 30% by weight tungsten
carbide with an average particle size between about 0.2 .mu.m and
30 .mu.m to provide a higher packing density to achieve increased
wear resistance and strength. In selected embodiments, this amount
is at least about 40% by weight, and in some cases, at least about
50% by weight.
[0059] The wear resistance of matrix material can also be increased
by using a greater amount of particular types of tungsten carbides
to form the matrix powder. Types of tungsten carbides generally
include macro-crystalline tungsten carbide, cast tungsten carbide,
carburized tungsten carbide and sintered tungsten carbide. Matrix
powders typically include two or more of the aforementioned types
of tungsten carbide combined in various weight proportions. Matrix
powders may also include other metal additives, such as nickel
(Ni), iron (Fe), cobalt (Co) or other transition metals. The wear
resistance of matrix material can be increased by using a greater
amount of a harder tungsten carbide in the matrix powder. For
example, more cast carbide may be used in the matrix powder. In
selected embodiments, cast carbides in amounts of around 40% or
more by weight, and in some cases 45% or more, have be used to
provide increased wear resistance over conventional matrix
materials.
[0060] Additionally, in one or more embodiments, cutters used on
the bit may be selected to have more wear resistant substrates.
Wear resistance of substrate material also increases with hardness
or carbide content, or by decreasing the binder contents or
tungsten carbide grain size. Therefore, in one embodiment, cutters
with substrates having hardness of 88 Ra or more may used.
Alternatively, cutters having substrates with a binder content of
around 13% or less by weight may be used. Also, in one embodiment,
substrates may be formed using tungsten carbide particles with an
average grain size of around 3 microns or less to provide increased
wear resistance. Alternatively, cutters 210 may be treated or a
coating applied to exposed surfaces of cutter substrates to reduce
wear in selected embodiments.
Enhanced Wear Resistance Along Surfaces
[0061] To provide increased wear resistance along surfaces of the
bit subjected to the greatest amount of wear, selected portions on
the bit, such as the bit body 202, blades 208, or gage pads 224,
may be formed using different matrix materials to obtain the
increased wear resistance desired without sacrificing impact
toughness or crack resistance of the bit body. Examples of this are
described in U.S. patent application Ser. No. 10/454,924 to
Kembaiyan, titled "Bit Body Formed of Multiple Matrix Materials and
Method for Making the Same," which is assigned to the assignee of
the present invention and incorporated herein by reference.
Referring to FIG. 3, for example, the blade tops 232 and surfaces
of the gage pad 224 can be formed to include an outer layer of
matrix material having a higher wear resistance than an underlying
layer which may provide higher toughness.
[0062] Additionally, ultrahard material can be deposited along
surfaces of the bit body to reduce wear of matrix material in
selected regions. For example, a coating comprising ultrahard
material, such as a plated diamond coating, may be applied to
surfaces of the bit, such as along the blades 208, gage pads 224,
or cutter substrates 212 to increase the wear resistance along
those surfaces. Such coatings may be used to help reduce wear on
bit body surfaces and to allow for longer bit runs.
[0063] Alternatively, ultrahard particles or elements may be
embedded in outer surfaces of the bit to increase the abrasion and
erosion resistance of these surfaces. For example, ultrahard
material can be embedded in blade tops and cutter substrates to
further reduce wear during drilling. Test bits run in a high flow
rate unconsolidated, ultra abrasive application both with and
without ultrahard material embedded in blade tops and cutter
substrates are shown in FIGS. 7A-7C. The bit shown in FIG. 7A was
configured in accordance with aspects of the invention and used to
drill a wellbore segment through a heavy oil reservoir with high
drilling fluid flow rates. This bit did not include ultrahard
material embedded in the blade tops 532 or cutter substrates 512.
As shown in FIG. 7A, when the bit was pulled to the surface after a
first run, the bit was found to have reduced but noticeable wear
across the blade tops 532 and exposed cutter substrates 512.
[0064] The bit shown in FIG. 7B has the same design as the bit in
FIG. 7A but includes the addition of ultrahard particles 542, 544
embedded along the blade tops 532 and in the cutter substrates 512.
This bit was used under similar conditions substantially equivalent
to the one shown in FIG. 7A. As shown in FIG. 7B, when the bit with
ultrahard particles 542, 544 embedded in therein was pulled to the
surface after a first run, significantly less wear was found across
the blade tops 532 and cutter substrates 512. The ultrahard
particles used in this embodiment were natural set diamonds, having
grain sizes of around 1-3 mm or more (1-10 stones per carat ("spc")
or less). A band of ultrahard material 545 was also embedded in the
substrate material 512 behind the diamond table (ultrahard body
511) of the cutter, as further described in U.S. Pat. No. 6,272,753
to Scott, which is assigned to the assignee of the present
invention and incorporated herein by reference. The addition of
ultrahard material in the blade tops 532 and in the cutter
substrates 512 was found to significantly reduce the amount of
matrix material loss from the bit during drilling.
[0065] FIG. 7C shows the condition of the bit in FIG. 7B after a
fourth bit run. The blade tops 532 and cutter substrates 512 with
the embedded ultrahard material (542, 544, 546) were found to be in
better condition than the bit run without embedded ultrahard
material (shown in FIG. 7A). Adding ultrahard elements in surfaces
of the bit subjected to the highest amounts of wear may
significantly reduce the amount of matrix material worn from a bit
in a given run and may also help to lengthen the effective life of
the bit in a drilling program.
[0066] In other embodiments where ultrahard particles or elements
are embedded or infiltrated into the matrix material forming
surfaces of a bit, the ultrahard material may be natural or
synthetic diamond, or a combination of both, and can be obtained in
a variety of shapes and grades as desired. Other ultrahard material
particles or elements known in the art may also or alternatively be
used. In such cases, the matrix material should be selected to
provide sufficient abrasion resistance so that ultrahard particles
or elements are not prematurely released.
[0067] Along surfaces, such as the blade tops, larger ultrahard
particles or elements can used, as desired, to allow for prolonged
retention in matrix material due to increased grip area around the
particles for matrix material to hold them in place longer. For
example, in selected embodiments the blade tops and other surfaces
on the bit can be impregnated with diamond grit of any grain size.
In one embodiment, diamond grit having a grain size of around 700
.mu.m or more (150 spc or less) was used for prolonged resistance.
In another embodiment, diamond grit having a size of around 850
.mu.m more (100 spc or less) were used.
[0068] Alternatively, ultrahard particles embedded in the matrix
material may be disposed both at and below the outer surface of the
matrix material for prolonged abrasion resistance. Ultrahard
particles infiltrated in matrix material to a selected depth
beneath surfaces of the bit may be provided so that as the matrix
material wears and ultrahard particles at the surface fall but,
additional particles will become exposed below the surface for
prolonged abrasion resistance. Bits having surfaces infiltrated
with ultrahard particles to a selected depth maintain their ability
resist abrasion and erosion for longer periods of time, even after
surface particles are worn down, which can also increase the length
or number of runs a bit can be used for before having to be
rebuilt.
[0069] Ultrahard particles or elements embedded in matrix material
may also be coated to achieve a stronger bond in matrix material.
Examples of coatings that may be used are described in U.S.
application Ser. No. 10/928,914 to Oldham, filed Aug. 26, 2004,
titled "Coated Diamond for Use in Impregnated Diamond Bits,"
assigned to the assignee of the present invention and incorporated
herein by reference.
[0070] As noted, ultrahard elements formed of any abrasion
resistant material may be embedded in the blade tops behind the
cutters or along other surfaces of the bit. Examples of ultrahard
elements that may be used include diamond grit-hot pressed inserts
(GHIs), PCBN elements, and TSP elements. For example, GHIs or other
elements containing abrasive resistant material can be placed
behind the cutters, such as similar to that described for example
in U.S. Pat. Nos. 4,823,892, 4,889,017, 4,991,670 or 4,718,505.
GHIs may be infiltrated or brazed into surfaces of the bit, as
discussed in U.S. Pat. No. 6,394,202, to Truax and assigned to the
assignee of the present invention.
[0071] A bit having selected surfaces impregnated with ultrahard
particles or elements, as described above, can be formed by placing
the ultrahard particles or elements in predefined locations of a
bit mold. Alternatively, composite components, or segments
comprising a matrix material infiltrated with diamond particles or
the like can be placed in predefined locations in the mold. Once
the ultrahard material or components are positioned, other
components for forming the bit can be positioned in the mold and
then the remainder of the cavity filled with matrix material, such
as a charge of tungsten carbide powder. Finally, an infiltrant or
binder can be placed on top of the matrix powder and the assembly
then heated sufficiently to melt the infiltrant for a sufficient
period to allow it to flow into and bind the powder matrix and
segments. Using this process, a bit body that incorporates the
desired ultrahard particle containing sections and/or components
can be formed.
[0072] As discussed above and shown in FIGS. 7B and 7C, ultrahard
particles 544 and/or ultrahard elements 546 (e.g., a band of
ultrahard material) can also be embedded in cutter substrates 512
for increased wear resistance along an exposed portion of the
substrate 512. Ultrahard particles embedded in the substrate 512 or
in matrix material surrounding the cutters may comprise particulate
diamond or diamond grit, which may be natural or synthetic, or
other ultrahard particles known in the art. Ultrahard elements used
may comprise polycrystalline diamond (PCD), polycrystalline cubic
boron nitride (PCBN), grit hot-pressed inserts (GHIs), or other
ultrahard material elements known in the art.
[0073] Referring to FIG. 3, wear on cutter substrates 212 can also
be reduced by limiting the amount of cutter substrate 212 exposed
to abrasive slurry during drilling. Therefore, in one or more
embodiments, cutters 210 with shorter substrates 212 may be used or
the cutters 210 positioned in the blade pockets 209 with less than
the full length of the substrate exposed. For example, cutters may
be positioned to have exposed substrate lengths of 16 mm or less.
In some cases, exposed substrates lengths may be limited to less
than 13 mm, and in one or more cases, to 9 mm or less.
Cutting Arrangements
[0074] The cutters of the bit shown in FIGS. 2 and 3 are generally
arranged in a short parabolic profile for to provide enhanced
steerability for horizontal drilling in unconsolidated, ultra
abrasive formations. The cutters are also arranged to minimize an
imbalanced force on the bit and a difference in the work rates of
the cutters. In other embodiments, any bit profile or cutter
arrangement may be used.
[0075] The cutters can also be arranged at a back rake angle to
provide enhanced steerability when desired for particular
horizontal drilling applications, such as for drilling the pay zone
of a heavy oil reservoir. Cutters oriented with back rake provide a
less aggressive cutting structure which may be more resistant to
drilling out of the pay zone of drilling heavy oil reservoirs which
are typically bounded above and below by more consolidated
formations. In particular, the responsiveness of the bit to a
formation change increases with back rake such that if a more
competent formation is encountered during drilling the bit will be
more prone to skip or bounce along the bounding formation and
remain in the desired drilling zone. Also cutters with higher back
rake are less likely to sustain damage when drilling float
equipment or a shoe in the path of the bit, such as at the start of
horizontal drilling section. Providing a bit that is more sensitive
to formation changes can also reduce drilling costs by obviating
the need for directional equipment in these applications. For
unconsolidated, ultra abrasive applications, bits having higher
back rakes may be used because the rate of penetration of these
bits is not a limiting issue in these applications. Additionally, a
bit's sensitivity to formation changes may be further increased by
using a short parabolic profile along with increased back rake
angles.
[0076] Orienting cutters at a back rake angle can also help reduce
erosion on cutter substrates 212. For example, as shown in FIG. 8A,
a cutter 910 mounted on a blade 908 with zero back rake, is exposed
to abrasive slurry passing over the cutting edge of the cutter 910
during drilling. By orienting a cutter 910, as shown in FIG. 8B, at
a selected back rake angle 950, substrate exposure to abrasive
slurry can be reduced and exposure of the ultrahard body 911 to the
abrasive formation can be increased. This may also increase the
area in the blade pocket 909 for bonding cutters 910 to the blade
908. In selected embodiments, the cutters may be oriented with a
back rake angle of 20.degree. or more. In an embodiment similar to
the one shown in FIG. 3, cutters have a back rake distribution such
that near the center of the bit are oriented with back rake angles
of around 20.degree. which increased towards gage to cutters
oriented with back rake angles of about 30.degree. or more near
gage.
[0077] In one or more embodiments, one or more cutters may be
oriented at a selected a side rake angle. For example, cutters may
also be oriented at a side rake angle toward the outside of the bit
that is greater than 0.degree.. Providing cutters oriented to
include a side rake angle may help increase a bits resistance to
drilling out of a desired formation zone and may also help to
direct abrasive cuttings away from the bit for enhanced cuttings
evacuation and reduced wear.
[0078] Referring to FIG. 8C, cutters may also include a bevel or
chamfer 990 that extends from a periphery of the top surface 991 of
the ultrahard body 911 to the sidewall 992 of the ultrahard body
911. The chamfer 990 may extend about the entire periphery of
ultrahard body 911, or only along a periphery portion adjacent the
formation to be cut. Chamfers may be any size and different sized
chamfers may be used in different locations on selected
embodiments. In selected embodiments similar to that shown in FIG.
2, cutters having chamfer lengths of 0.012 inches (measured along
the side of the cutter) oriented at around 45.degree. (with respect
to the side of the cutter) were used for enhanced impact
resistance. In selected embodiments, cutters with larger bevels may
be used, such as for drilling through shoes and equipment in a
wellbore. For example, cutters having a bevel size greater than or
equal to 0.025 inches may be used.
Improved Gage Protection
[0079] When conventional fixed cutter bits are used in
unconsolidated, ultra abrasive applications they suffer excessive
wear along the gage pads due to rubbing action against the
formation and abrasive slurry flowing past gage surfaces.
Therefore, in accordance with embodiments if the present invention,
a fixed cutter drill bit for unconsolidated, ultra abrasive
environments also includes wear resistant elements, such as diamond
or ultrahard material containing elements, embedded in gage pad
surfaces to provide enhanced wear resistance at gage.
[0080] For selected embodiments, especially those designed for long
runs in high flow rate directional drilling applications,
additional gage pad protection may be required. In these
applications, abrasive slurry containing sharp sands tends to
abrade matrix material along the leading edge which exposes inner
regions of the gage pad to a greater amount of abrasive wear. As a
result, matrix material around the wear resistant elements in the
pad may eventually become worn away causing the wear resistant
elements to fall out.
[0081] Therefore, in selected embodiments, wear resistance of a
gage pad may be increased by placing wear resistant elements
proximal a leading edge of the gage pad to serve as a barrier to
abrasive slurry impacting the leading edge. Wear resistance may
also be increased by providing a greater amount of diamond coverage
on the gage pad. This is done by using larger wear resistant
elements with longer substrates or extensions for embedding into
the matrix material to increase the ability of the gage pad to
retain the wear resistant elements during drilling.
[0082] One example of a novel abrasive resistant gage pad
arrangement that may be used on an embodiment of the invention
described above to enable longer drilling runs or on any PDC bit
for enhanced abrasive resistance is shown in FIG. 9. In this
embodiment, the gage pad 1224 includes wear resistant elements 1227
which are embedded in the gage pad material 1275. The gage pad
material 1275 comprises a carbide matrix, such as tungsten carbide
infiltrated with binder material. A number of the wear resistant
1227 elements are embedded in the matrix material close to the
leading edge 1270 of the gage pad 1224. The wear resistant elements
1227 disposed proximal the leading edge 1270 are positioned around
1/4 inch or less away from the leading edge 1270 and arranged span
a majority of the length of the leading edge 1270. A plurality of
the wear resistant elements 1227 are also disposed along a tailing
edge 1272 of the gage pad 1224 and along a top edge 1273 and a
bottom edge 1274 of the gage pad 1224 to provide enhanced wear
resistance along these edges. Wear resistant elements 1227
positioned near the trailing edge 1272 are positioned around 1/4
inch or less away from the trailing edge 1272 and span a majority
of the length of the trailing edge 1272. A plurality of the wear
resistant elements 1227 are also provided in the interior region of
the gage pad to provide a large amount of overall wear resistant
coverage on the gage pad 1224.
[0083] The wear resistant elements 1227 in the embodiment shown in
FIG. 9 include large wear resistant elements 1277 and smaller wear
resistant elements 1276 positioned around the large wear resistant
elements 1277. The larger elements 1277 provide larger bearing
surfaces to help maintain gage and include longer substrates that
are embedded deeper into the gage pad material 1275 for increased
retention. The smaller wear resistant elements 1276 are positioned
around the larger wear resistant elements 1277 for increased wear
resistant coverage.
[0084] In the embodiment shown, the larger wear resistant elements
1277 comprise diamond enhanced inserts ("DEIs") which include a
layer of polycrystalline diamond material bonded to a substrate.
The DEIs are arranged in three rows which generally spanning the
length of the gage pad. Five DEIs are disposed in the rows closest
to the leading edge and the trailing edge. Four DEIs are positioned
in the interior region of the gage pad. The DEIs used on selected
bits may have diameters of 13 mm or more to provide larger bearing
surface areas of greater than 130 mm.sup.2, and may include
substrates having lengths of 9 mm or more to allow for good
retention during drilling. The substrate end of the DEI is embedded
in the matrix material 1275 with the top surface of polycrystalline
diamond exposed at the gage pad surface for contact with abrasive
slurry and the walls of the wellbore. In other embodiments, DEIs or
other large inserts having super abrasive resistant bearing faces
of any size may be used in any arrangement desired. In another
example, 16 mm or larger DEI inserts are used proximal the leading
edge 1270 which act as larger barriers for abrasive slurry passing
over the leading edge to help reduce wear of matrix material from
around other wear resistant elements on the gage pad behind the
leading DEIs. Also, in other embodiments, DEIs may be arranged in
three or more rows or with 3 or more DEIs within a one inch length
of the gage pad.
[0085] The smaller wear resistant elements 1276 comprise thermally
stable polycrystalline diamond (TSP) elements embedded in the gage
pad material 1275. The gage pad material 1275 comprises a metal
carbide matrix material. In selected embodiments, the gage pad
material 1275 may also be impregnated with or coated with ultrahard
particles, such as diamond grit, to further increase abrasion
resistance. In other embodiments, wear resistant elements of any
type, number, shape, or size may be used.
[0086] For the embodiment shown in FIG. 9, the combination of
larger and smaller wear resistant elements 1277, 1276 near leading
and trailing edges of the gage pad provide a total diamond (or
similar wear resistant element) coverage along each edge that is
greater than 75% of the length of the gage pad and closer to 100%.
Additionally, close to 50% or more of the gage pad surface
comprises diamond. Using larger super abrasive resistant elements
with longer substrates near the leading edge of the gage pad
reduces wear of matrix material from the gage pad surface such that
smaller elements disposed on the gage pads are retained longer
during drilling. This will also reduce the amount of material lost
from the gage pad during drilling, which will reduce the amount of
time and energy required to rebuild the bit.
[0087] Another example of a novel gage pad layout that may be used
for embodiments of the inventions to permit longer drilling runs in
abrasive applications is shown in FIGS. 10A and 10B. This gage pad
arrangement may also be used for on any bit for enhanced gage
protection. In this layout, wear resistant elements are positioned
to provide a rounded edge (or surface proximal the edge) on the
gage pad which is more resistant to sharp sands in abrasive slurry
than the gage pad matrix material.
[0088] Referring to FIG. 10A, in accordance with this layout, the
gage pad 1324 of the bit is formed of matrix material 1375, such as
tungsten carbide infiltrated with binder material. Wear resistant
elements 1378 having rounded or convex surfaces are embedded in the
matrix material 1375 proximal the leading edge 1370 of the gage pad
1324 such that they are or may eventually become exposed at the
leading edge 1370 during drilling to provide a rounded and super
abrasive resistant edge on the gage pad 1324. Wear resistant
elements 1378 having rounded or convex surfaces are also embedded
in the matrix material 1375 proximal the trailing edge 1372 of the
gage pad 1324 such that they are or may eventually become exposed
at a trailing edge 1372 during drilling to provide a rounded and
super abrasive resistant trailing edge for the gage pad 1324.
[0089] In the example shown, the wear resistant elements 1378
positioned proximal each edge of the gage pad 1324 are axially
aligned and generally arranged end to end along each edge to
provide rounded, substantially continuous, and wear resistant edge
portions for the gage pad 1324. Small spacing may be provided
between the ends of adjacent wear resistant elements 1378 with
matrix material disposed there between for enhanced retention of
the elements 1378 embedded in the matrix material.
[0090] A cross section of the gage pad in FIG. 10A, taken along
line A-A, is shown in FIG. 10B. As shown in FIG. 10B, the wear
resistant elements 1378 positioned proximal the leading edge 1370
and the trailing edge 1372 of the gage pad 1324 may be cylindrical
in form with axes generally parallel to the leading or trailing
edge. The wear resistant elements 1378 are at least partially
embedded in matrix material 1380 forming the gage pad 1324. When
exposed near a leading or trailing edge 1370, 1372 of the gage pad
1324, the wear resistant elements 1378 provide a rounded and super
abrasive resistant edge surface which results in a smother flow of
abrasive slurry around the edges of the gage pad and significantly
reduces wear of material from interior gage pad surfaces. This
arrangement also provides a gage pad that is able to retain both
edge and interior wear resistant elements 1378, 1379 longer during
drilling.
[0091] Wear resistant elements 1379 disposed along in the interior
region of the gage pad 1324, between the leading edge 1370 and
trailing edge 1372, are arranged along the gage pad 1324 to provide
super abrasive bearing surfaces for maintaining gage during
drilling. In this example, interior wear resistant elements 1379
are generally cylindrical in form with their linear axes generally
perpendicular to the outer surface of the gage pad. As shown in
FIG. 10B, these interior elements 1379 are embedded in matrix
material 1375 forming the gage pad 1324 and have a flat or
generally convex end surface exposed along the surface of the gage
pad for bearing engagement with wide walls of a wellbore during
drilling. In this embodiment, the wear resistant elements 1379 are
generally arranged in a row along the length of the gage pad 1324.
The gage pad 1324 is also slanted or spiraled such that it has
helix angle with respect to the bit axis (not shown). Spiraling the
gage pad 1324 provides increased surface area for the gage pad (for
a given gage width). Aligning the row of wear resistant elements
1324 generally parallel to the leading edge of the gage pad allows
for the placement of more wear resistant elements along the gage
pad length, which can result in enhance gage pad protection and
drilling life for the bit. However, in other embodiments, any shape
or type of gage pad may be used and may include any type, number,
size, shape, or arrangement of wear resistant elements to help
maintain gage.
[0092] In one example, the wear resistant elements 1378 disposed
along the leading edge 1370 and trailing edge 1372 of a gage pad
are diamond grit hot-pressed inserts (GHIs), which may be
infiltrated or brazed into gage pads of a bit, such as the one
shown in FIG. 3. GHIs are diamond impregnated elements which can be
manufactured by placing a mixture of diamond particles and powdered
matrix material in a mold. The contents of the mold are then
hot-pressed or sintered at an appropriate temperature, such as
between about 1000 and 2200.degree. F., to form a composite
diamond-impregnated insert. The diamond particles used may be
natural or synthetic and may be obtained in a variety of shapes and
grades. In the example, six GHIs are disposed proximal the leading
and trailing edges of the gage pad and provide substantially 100%
super abrasive coverage along most of the length of the leading and
trailing edges. The GHIs may have diameters of up to 13 mm or more
and may also have lengths of up to 13 mm or more. In other
embodiments, wear resistant elements 1378 positioned to form at
least part of the leading edge 1370 or at least part of the at the
trailing edge 1372 during drilling may comprise any size, shape or
type of super abrasive resistant elements known in the art,
including GHIs, PCD elements, TSP elements, polycrystalline cubic
boron nitride (PCBN) elements, or the like or combinations
thereof.
[0093] In the example noted, the interior wear resistant elements
1379 positioned along the interior surface of the gage pad 1324
comprise DEIs with carbide substrates. The carbide substrates are
embedded into the gage material with the diamond tables exposed at
the surface of the gage pad. The DEIs have diameters of up to 13 mm
or more with lengths, including substrates, of up to 9 mm or more.
In some cases, DEIs having diameters of 16 mm or more and/or
substrates of 13 mm or more are used. In other embodiments, wear
resistant elements of any type, number, shape, size, or combination
may be used in interior regions of the gage pad, including DEIs,
PCD elements, TSP elements, PCBN elements, GHIs, or the like or
combinations thereof.
[0094] Additionally, the gage pad material 1375 may comprise a
harder matrix material than that used to form another part of the
bit body as described in relation to other aspect of the invention
above. Alternatively or additionally matrix material forming part
or the entire outer surface of the gage pad may be impregnated (or
coated) with ultrahard particles, such as diamond grit, to provide
increased abrasion resistance for the gage pad. For example, as
shown for the gage pad layout in FIG. 10B, the outer surface of the
gage pad may include a layer of matrix material impregnated with
diamond grit 1381 formed on other matrix material 1380 forming part
of the gage pad. This may be achieved by packing surfaces in a bit
mold which form the gage pad with impregnated material before
filing the mold with other matrix material used to form the
bit.
[0095] In one example, diamond grit having a grain size of around
700 .mu.m or more (150 spc or less) was used to form diamond
impregnated surfaces of a gage pad having a similar layout to the
one shown in FIGS. 10A and 10B, with 13 mm GHIs used proximal the
leading and trailing edges of the gage pad and 13 mm DEIs used
along the interior gage pad surface. In another example, diamond
grit having a size of around 850 .mu.m more (100 spc or less) was
used. In one or more embodiments, the combination of larger wear
resistant elements and diamond impregnated matrix material can be
used to provide substantially 100% abrasive resistant coverage on
the gage pad surface to minimize exposure of underlying matrix
material to eroding slurry in ultra abrasive applications. This
gage pad combination was used on the bit shown in FIG. 7B and was
found to be particularly effective when performing longer drilling
runs and/or multiple drilling runs in unconsolidated ultra abrasive
formations.
[0096] Additionally, the gage pads of the bit may be configured as
replaceable gage pads as is generally know in the art with the gage
pad layouts designed in accordance with examples given above. In
the case of replaceable gage pads, the gage pads and corresponding
bit surface may include complementary securing elements which
mutually engage one another and the gage pad removably secured to
the bit body by brazing, mechanical locking, or the like. Removable
gage pads may be used to facility faster rebuild operations.
[0097] In general, it has been found that having rounded wear
resistant elements positioned proximal the leading edge of a gage
pad can significantly reduce wear on gage pad surfaces and increase
bit life, especially in ultra abrasive applications. This can also
reduce the time and materials required to repair a bit. Also, using
GHIs or similar elements may permit the use of larger wear
resistant elements along edges of the gage pad and may also result
in increased element retention. Using DEIs with longer substrates
permits deeper grip in the gage pad material for increased
retention. Additionally, the use of matrix material impregnated
with ultrahard particles along the outer surface of the gage pad
can help to further reduce wear on the gage pads and increase bit
life, especially for bits used in ultra abrasive environments.
Back Reaming Features
[0098] Referring to FIG. 11, one or more embodiments additionally
includes at least one back reaming element 1428 positioned on the
bit to "back ream" or remove formation in the path of the bit as
the bit is pulled from a borehole. The back reaming element 1428
may comprises a PCD cutter or similar shearing element that is
preferably positioned to minimize contact with formation during
drilling yet positioned to effectively drill through formation in
the path of the bit as the bit is pulled out of the wellbore. For
example, referring to FIG. 3, back reaming elements (not shown) may
be positioned along heel surfaces 229 blades at the side 225 of the
bit that support gage pads 224.
[0099] FIG. 11 shows an enlarged partial cross section view of a
heel surface 1429 of a bit 1400 in accordance with an embodiment of
the present invention. The bit 1400 generally comprising a bit body
1402 having a central axis 1404, a connection formed at one end
(generally indicated), and a cutting face disposed at another end
(general indicated). The bit 1400 also includes one or more gage
pads 1424 disposed about a side surface 1425 of the bit 1400. Back
reaming elements 1428 are generally positioned along a heel surface
1429 of the blades supporting the gage pad 1424.
[0100] Back reaming capability is particularly desired for
embodiments of the invention designed for horizontal drilling
because cuttings tend to fall to the low side of the hole during
drilling such that when the bit is retrieved from the borehole it
typically has to plow through cuttings built up on the low side of
the hole so that the bit can be removed. Because back reaming
elements may have to do a lot of work in these applications, larger
back reaming elements and/or a plurality of back reaming elements
may be used to provide increased cutting capability and abrasion
resistance along heel surfaces of the bit.
[0101] In selected embodiments one or more back reaming elements
1428 positioned on a heel surface 1429 of the bit may comprise a
larger element, such as PDC cutters (or similar elements) having a
diameter of about 13 mm, or more. Alternatively, in one or more
other embodiments, at least two back reaming elements 1428 are
disposed along selected heel surface of the bit to provide
efficient removal capability for the bit when pulled out of the
hole. The number and/or size of the back reaming elements on each
heel surface may be selected to provide a particular amount of
diamond coverage. For example, two or more 16 mm back reaming
cutters or cutters of any size may be positioned along heel
surfaces of each gage pad blade to provide diamond coverage of
greater than 300 mm.sup.2 along each of the heel surfaces.
Providing good back reaming capability on selected embodiments used
for directional drilling eliminates issues of the bit getting stuck
in the hole and excessive wear on the heel surfaces of the bit that
must be addressed in rebuild operations.
[0102] In other embodiments, a back reaming element may comprise
any type of active cutting structure known in the art including a
PCD compact, a PCBN compact, a diamond impregnated insert, and
natural diamond elements. PDC back reaming elements have been found
to be particularly effective in maintain gage all the way in
horizontal, unconsolidated, ultra abrasive applications. PDC
elements having longer substrate lengths also permit deeper
penetration of the substrate into the blade matrix material for
greater retention of the cutter.
[0103] In alternative embodiments, back reaming elements positioned
on the bit may comprise different types of cutting elements, such
as TSPs and GHIs or PCD compacts. Additionally, cutter types may be
arranged to alternate along heel surfaces as desired. Heel surfaces
of the bit may also be coated with hardfacing material or
impregnated with wear resistant material, such as diamond particles
or other wear resistant material, to further reduce wear on the
heel surfaces that occurs as bits are removed from longer bit
runs.
Hydraulic Considerations
[0104] In one or more embodiments, to reduce erosive wear,
particularly in high flow rate drilling in unconsolidated, ultra
abrasive applications fluid passageway may disposed between the
blades may be oriented to direct more of the drilling fluid toward
a corresponding junk slot of the bit rather than directly on the
cutters. The bit 200 shown in FIG. 2 includes fluid passageways 218
which are generally disposed between each of the blades 208 to wash
cuttings from the cutters 210, blades 208 and bottomhole of a
wellbore. Fluid passageways 218 are generally oriented at skew
angle selected to direct drilling fluid and cuttings substantially
parallel to or somewhat away from blade front surfaces to reduce
the impingement and velocity of abrasive slurry flowing over the
blades 208 and cutters 210. Fluid passageways 218 are also
generally oriented with a profile angle that more directs abrasive
slurry up the junk slots 226 of the bit rather than for impingement
on the bottomhole to help reduce recirculation of abrasive slurry
around the bit 200 during drilling. This can also help to prevent
over the washing sands and the like from the bottomhole during
drilling.
[0105] Other design considerations may also be used to reduce the
velocity or impingement of the abrasive slurry on the bit body. For
example, in one or more embodiments, one more diffuser nozzles may
be used to reduce fluid velocities around the cutters to help
reduce erosive wear on the cutting structure during drilling.
Alternatively, in one or more embodiments, a bit may be designed to
include more nozzles 220 than blades 208 to help lower the
concentration of hydraulic energy across the cutting face of the
bit. Alternatively, a bit may be designed with an increased total
flow area, such as by configuring the one or more of the
passageways 218 or nozzles 220 to have a larger than normal exit
port.
Braze Material
[0106] Braze material is typically selected for highest braze
strength; however, braze strength is not considered a limiting
factor in many unconsolidated, ultra abrasive applications.
Therefore, in one or more embodiments, a more viscous braze
material may be applied between the cutters and the cutter pockets
to increase the reusability of cutters and reduce the cost
associated with rebuilding the bit. A more viscous braze material
may be used so that when a cutter substrate is slightly eroded or
has minor nicks on the exposed portion of the substrate, the cutter
can be spun during the rebuild operation to coat the substrate with
the thicker braze material to fill the small voids or wear marks
and provide sufficient adhesion for subsequent runs.
[0107] Therefore, in selected embodiments, a braze material which
is or can be kept more viscous during the brazing process may be
used to bond one or more of the cutters into the cutter pockets on
the blades, especially in locations where erosion of the brazed
joint or carbide cutter substrate has been observed or predicted.
The more viscous braze material can be selected from alloys having
a larger difference between the liquidus (L) and solidus (S)
temperatures. For example, the commercial braze alloy BAg7
(L=652.degree. C., S=618.degree. C.), may be selectively replaced
with BAg18 (L=718 C, S=602 C) or other silver-based alloys. The
alloys may include combinations of small percentages of metallic or
transitional elements, or of non-melting elements or refractory
particles, which may increase the effective viscosity while
brazing. The brazing process can also be controlled to use lower
temperatures, which also increases effective viscosity. For
example, a braze materials having a larger difference between the
liquidus and solidus temperatures can be used to braze cutters at a
temperature between the liquidus and solidus temperature, such as
around midway between the range, so that the braze material remains
more viscous during the brazing process.
[0108] Also, in one or more embodiments, a hardfacing overlay
coating may be applied to portions of the bit, such as exposed
surfaces of braze material to minimize erosion of braze material
around the cutters during drilling, as discussed for example in
U.S. Pat. No. 6,772,849 to Oldham et al., titled "Protective
overlay coating for PDC drill bits" discloses a method of
increasing a durability of a PDC drill bit by overlaying at least a
portion of the exposed surface of the braze material between the
cutter and the cutter pocket with a hardfacing material.
Other Embodiments
[0109] Those skilled in the art will appreciate that selected
features described above may be combined in various ways as desired
for a give application to provide a PDC drill bit capable of
drilling longer wellbore segments through abrasive or ultra
abrasive formations. It will also be appreciated that in the case
of PDC elements or cutters provided on the cutting face of the bit
as referenced above, all or a portion of the diamond layer may be
leached or otherwise treated to provide increased abrasion
resistance.
[0110] Bits in accordance with one or more embodiments of the
present invention can be used to drill an entire horizontal segment
through the pay zone of a heavy oil reservoir, which may extend
1500 meters or more in length. Selected embodiments may provide a
drill bit capable of drilling multiple horizontal segments before
having to be pulled to the surface and rebuilt. For example, a
drill bit may be used to drill a first horizontal leg through a
heavy oil reservoir and then side tracked to drill another
horizontal leg without having to be pulled back to surface. A drill
bit able to drill multiple lateral wells can provide a substantial
time and cont savings to a drilling operation. A PDC bit may also
include larger cutters such as 16 mm cutters or larger to provide
higher ROP as well as durability in drilling heavy oil
reservoirs.
[0111] In one or more embodiments, erosion between cutters may be
reduced by reducing cutter separation distances along surfaces of
the bit. In one or more embodiments back reaming capability may be
improved by placing larger cutters or a larger number of cutters
along heel surfaces of the bit to minimize blade upside wear.
Additionally, in one or more embodiments a PDC drill bit may
include larger beveled cutters oriented at a back rake for enhanced
steerability and/or to help minimize impact damage that can result
from drilling out equipment in the wellbore or contacting harder
formation stringers that dip into a drilling zone.
[0112] In accordance with one or more embodiments erosion on cutter
substrates may be reduced by limiting the amount of substrate
material exposed to the formation, by placing cutters at higher
back rake, and/or by minimizing spacing between cutters. In one or
more embodiments, erosion may be reduced around the cutters by
placing PDC cutters substantially flush with the blade face and by
providing cutter arrangements that do not include additional gaps
or spaces, such as cutter pocket relief grooves. Erosion and
abrasion may also be reduced by directing fluid nozzles towards the
center of fluid channels or slightly away from the corresponding
blade front face. Also, in one or more embodiments blades having
limited helix may be used and/or and with diamond imbedded in the
blade tops and/or cutter substrates to reduce wear behind the
cutters and across the blade tops.
[0113] Additionally, a novel gage pad configuration may be used on
any bit to minimize gage pad wear. Additionally, using gage pads
with larger surface area, such as wider or more spiral gage pads,
may help maximize diamond coverage on the gage of the bit. In one
or more embodiments, the diamond coverage on a gage pad may be 35%
or more, and in some cases 50% or more. In one embodiment a gage
pad may comprise five or more gage pad elements with diameters of
13 mm or more arranged in a row along the gage pad. In another
embodiment, a gage pad may comprise seven or more gage pad elements
having diameters of 13 mm or more. In one or more embodiments,
larger wear resistant elements, such as GHIs, DEIs or ultrahard
compacts, may be placed closer to the leading and/or trailing edges
of the gage pads to reduce gage pad wear. Wear resistant elements
having rounded surfaces may be disposed proximal the leading edge
of the gage pad to provide a rounded edge resistant to sharp sands
in the abrasive slurry to help maintain the leading edge longer.
Wear resistant elements disposed in the gage pad may be infiltrated
or brazed into the gage pad. In one or more embodiments,
impregnated diamond grit may be used to form surfaces of the bit,
such as part of the gage pad and/or blade tops to provide increased
abrasion resistant for extended bit life.
[0114] In other embodiments, a coating may also be applied to
surfaces of the bit to provide increased abrasion resistance. For
example, CVD technology or other coating technology may be applied
to coat leading edges or surfaces of the gage pad. PDC bits having
enhanced gage features in accordance with one or more embodiments
of the present invention may be able to effectively resist going
under gage during extended drilling runs, which minimizes the risk
of compromising the effective diameter of the wellbore and
subsequent operational complications.
[0115] One or more embodiments, a PDC bit having cutters closely
spaced, limited blade helix, natural diamond embedded in blade
tops, rounded wear elements disposed along leading and trailing
edges of the gage pad, and impregnated diamond in the gage pad may
be used to provide an economic benefit to a high ROP, heavy oil
drilling program.
[0116] PDC bits including selected features described above may be
rebuilt and reusable a sufficient number of times to provide a
positive economic impact to an overall drilling program in
unconsolidated, ultra abrasive formations and similar formations.
Such bits may also make it possible to drill longer horizontal
segments in these environments without having to pull a bit to the
surface.
[0117] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art will
appreciate that numerous other embodiments can be devised which do
not depart from the scope of the invention as set forth in the
appended claims.
* * * * *