U.S. patent application number 11/610537 was filed with the patent office on 2007-06-14 for rolling cone drill bit having non-uniform legs.
This patent application is currently assigned to Smith International, Inc.. Invention is credited to Scott D. McDonough, Amardeep Singh.
Application Number | 20070131457 11/610537 |
Document ID | / |
Family ID | 37712068 |
Filed Date | 2007-06-14 |
United States Patent
Application |
20070131457 |
Kind Code |
A1 |
McDonough; Scott D. ; et
al. |
June 14, 2007 |
ROLLING CONE DRILL BIT HAVING NON-UNIFORM LEGS
Abstract
A drill bit for drilling through earthen formations. In an
embodiment, the drill bit comprises a bit body having a bit axis.
In addition, the drill bit comprises a first rolling cone cutter
mounted on the bit body at a first journal angle and adapted for
rotation about a first cone axis. Further, the drill bit comprises
a second rolling cone cutter mounted on the bit body at a second
journal angle and adapted for rotation about a second cone axis,
wherein the second journal angle differs from the first journal
angle.
Inventors: |
McDonough; Scott D.;
(Houston, TX) ; Singh; Amardeep; (Houston,
TX) |
Correspondence
Address: |
CONLEY ROSE, P.C.
P.O. BOX 3267
HOUSTON
TX
77253-3267
US
|
Assignee: |
Smith International, Inc.
1640 Hardy street
Houston
TX
77032
|
Family ID: |
37712068 |
Appl. No.: |
11/610537 |
Filed: |
December 14, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60750415 |
Dec 14, 2005 |
|
|
|
Current U.S.
Class: |
175/374 ;
175/376 |
Current CPC
Class: |
E21B 10/08 20130101 |
Class at
Publication: |
175/374 ;
175/376 |
International
Class: |
E21B 10/16 20060101
E21B010/16 |
Claims
1. A drill bit for drilling through earthen formations comprising:
a bit body having a bit axis; a first rolling cone cutter mounted
on the bit body at a first journal angle and adapted for rotation
about a first cone axis; a first plurality of cutter elements
mounted to the first rolling cone cutter; a second rolling cone
cutter mounted on the bit body at a second journal angle and
adapted for rotation about a second cone axis, wherein the second
journal angle differs from the first journal angle; a second
plurality of cutter elements mounted to the second rolling cone
cutter, wherein at least one of the second plurality of cutter
elements intermeshes with the first plurality of cutter
elements.
2. The drill bit of claim 1 wherein the first rolling cone cutter
is mounted on the bit body at a first cone offset and the second
rolling cone cutter is mounted on the bit body at a second cone
offset that is different than the first cone offset.
3. The drill bit of claim 2 wherein the first cone offset is
greater than the second cone offset, and wherein the first journal
angle is less than the second journal angle.
4. The drill bit of claim 2 wherein the first cone offset is
positive and the second cone offset is negative.
5. The drill bit of claim 3 wherein the first and second plurality
of cutter elements each include a circumferential row of gage
inserts, wherein the number of gage inserts mounted to the first
rolling cone cutter is different than the number of gage inserts
mounted to the second rolling cone cutter.
6. The drill bit of claim 2 wherein the first cone offset is less
than the second cone offset and wherein the first journal angle is
less than the second journal angle.
7. The drill bit of claim 1 wherein the first rolling cone cutter
is mounted on a first journal pin extending from the bit body and
the second rolling cone cutter is mounted on a second journal pin
extending from the bit body, wherein the diameter of the first
journal pin is different than the diameter of the second journal
pin.
8. A drill bit for drilling through earthen formations comprising:
a bit body having a bit axis; at least three rolling cone cutters
mounted on the bit body and adapted for rotation about a different
cone axis, each of the cone cutters including a circumferential row
of gage cutter elements and at least one circumferential row of
inner row cutter elements spaced apart from the row of gage cutter
elements, wherein at least one of the inner row cutter elements of
one rolling cone cutter intermeshes with the inner row cutter
elements of a different rolling cone cutter; wherein each of the
rolling cone cutters defines a journal angle and a cone offset; and
wherein the journal angle of a first of the cone cutters differs
from the journal angle of a second of the cone cutters.
9. The drill bit of claim 8 wherein at least one cone cutter has an
offset that is different from the offset of another of the cone
cutters.
10. The drill bit of claim 9 wherein at least one of the cone
cutters has a positive offset and at least one of the cone cutters
has negative offset.
11. The drill bit of claim 8 wherein each of the cone cutters is
mounted on a different journal pin extending from the bit body, and
wherein the diameter of at least one journal pin is different from
the diameter of another journal pin.
12. The drill bit of claim 8 wherein each of the cone cutters is
mounted on a different journal pin and wherein the journal pin of
at least one cone cutter differs from the journal pin of another of
the cone cutters in at least one characteristic selected from the
group consisting of journal length and journal diameter.
13. The drill bit of claim 8 wherein at least one of the cone
cutters is mounted with roller bearings and at least a second cone
cutter is mounted with journal bearings.
14. The drill bit of claim 8 wherein the bit includes at least one
cone seal disposed between each cone and the journal pin upon which
it is mounted, and wherein the bit includes cone seals of differing
types.
15. The drill bit of claim 8 wherein a first cone cutter is
disposed between and immediately adjacent a second cone cutter and
a third cone cutter, wherein the first cone cutter is separated
from the second cone cutter by a first separation angle and
separated from the third cone cutter by a second separation angle
that is different than the first separation angle.
16. A drill bit for drilling through earthen formations,
comprising: a bit body having a bit axis; at least three rolling
cone cutters mounted on the bit body and adapted for rotation about
a different cone axis; wherein each of the cone cutters includes a
circumferential row of gage cutter elements and at least one
circumferential row of inner row cutter elements spaced apart from
the row of gage cutter elements, wherein at least one of the inner
row cutter elements of one rolling cone cutter intermeshes with the
inner row cutter elements of a different rolling cone cutter;
wherein a first of the cone cutters differs from a second of the
cone cutters in at least one characteristic selected from the group
consisting of cone offset, journal angle, seal type, journal
length, and journal diameter.
17. The drill bit of claim 16 wherein a first cone cutter has a
first cone offset and a second cone cutter has a second cone offset
that is different from the first cone offset, and wherein the first
cone cutter is mounted having a first journal angle that differs
from the journal angle of at least one other of the cone
cutters.
18. The drill bit of claim 17 wherein each of the cone cutters
differs in cone offset and journal angle from each of the other
cone cutters.
19. The drill bit of claim 17 wherein the second cone cutter is
mounted having a second journal angle, and wherein first cone
offset is greater than the second cone offset and the first journal
angle is less than the second journal angle.
20. The drill bit of claim 17 wherein the second cone cutter is
mounted having a second journal angle, and wherein the first cone
offset is less than the second cone offset and the first journal
angle is less than the second journal angle.
21. A drill bit for drilling through earthen formations comprising:
a bit body having a bit axis; a plurality of bit legs, each of the
legs including a rolling cone cutter mounted thereon and adapted
for rotation about a different cone axis; wherein each of the cone
cutters includes at least one circumferential row of inner row
cutter elements, wherein at least one of the inner row cutter
elements of one cone cutter intermeshes with the inner row cutter
elements of a different cone cutter; wherein at least a first of
the cone cutters differs from a second of the cone cutters in at
least one characteristic selected from the group consisting of
journal angle, cone offset, seal type and bearing
configuration.
22. The drill bit of claim 21 wherein the first of the cone cutters
has a first cone offset and the second of the cone cutters has a
second cone offset that is different from the first cone offset,
and wherein the first of the cone cutters is mounted having a first
journal angle that differs from the journal angle of at least one
other of the cone cutters.
23. The drill bit of claim 22 wherein the second of the cone
cutters is mounted having a second journal angle, and wherein first
cone offset is greater than the second cone offset and the first
journal angle is less than the second journal angle.
24. A drill bit for drilling through earthen formations comprising:
a bit body having a bit axis; at least three rolling cone cutters
mounted on the bit body and adapted for rotation about a different
cone axis, each of the cone cutters including a circumferential row
of gage cutter elements and at least one circumferential row of
inner row cutter elements spaced apart from the row of gage cutter
elements, wherein at least one of the inner row cutter elements of
one rolling cone cutter intermeshes with the inner row cutter
elements of a different rolling cone cutter; wherein each of the
cone cutters defines a journal angle and a cone offset; and wherein
the cone offset of at least one cone cutter is different from the
cone offset of another of the cone cutters.
25. The drill bit of claim 24 wherein the journal angle of a first
of the cone cutters differs from the journal angle of a second of
the cone cutters.
26. The drill bit of claim 24 wherein at least one of the cone
cutters has a positive offset and at least one of the cone cutters
has negative offset.
27. The drill bit of claim 24 wherein each of the cone cutters is
mounted on a different journal pin and wherein the journal pin of
at least one cone cutter differs from the journal pin of another of
the cone cutters in at least one characteristic selected from the
group consisting of journal length and journal diameter.
28. The drill bit of claim 24 wherein at least one of the cone
cutters is mounted with roller bearings and at least a second cone
cutter is mounted with journal bearings.
29. The drill bit of claim 24 wherein the bit includes at least one
cone seal disposed between each cone and the journal pin upon which
it is mounted, and wherein the bit includes at least two cone seals
of differing types.
30. The drill bit of claim 24 wherein a first cone cutter is
disposed between and immediately adjacent a second cone cutter and
a third cone cutter, wherein the first cone cutter is separated
from the second cone cutter by a first separation angle and
separated from the third cone cutter by a second separation angle
that is different than the first separation angle.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. provisional
application Ser. No. 60/750,415 filed Dec. 14, 2005, and entitled
"Rolling Cone Drill Bit Having Non-Uniform Legs," which is hereby
incorporated herein by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable.
BACKGROUND
[0003] 1. Field of the Invention
[0004] The invention relates generally to earth-boring bits used to
drill a borehole for the ultimate recovery of oil, gas or minerals.
More particularly, the invention relates to rolling cone rock bits.
Still more particularly, the invention relates to leg, cone, and
journal arrangements of such bits.
[0005] 2. Background of the Invention
[0006] An earth-boring drill bit is typically mounted on the lower
end of a drill string and is turned by rotating the drill string at
the surface or by actuation of downhole motors or turbines, or by
both methods. With weight applied to the drill string, the rotating
drill bit engages the earthen formation and proceeds to form a
borehole along a predetermined path toward a target zone. The
borehole thus created will have a diameter generally equal to the
diameter or "gage" of the drill bit.
[0007] An earth-boring bit in common use today includes one or more
rotatable cutters that perform their cutting function due to the
rolling movement of the cutters acting against the formation
material. The cutters roll and slide upon the bottom of the
borehole as the bit is rotated, the rotatable cutters thereby
engaging and disintegrating the formation material in their path.
The rotatable cutters may be described as generally conical in
shape and are therefore sometimes referred to as rolling cones or
rolling cone cutters. The borehole is formed as the action of the
rotary cones remove chips of formation material which are carried
upward and out of the borehole by drilling fluid which is pumped
downwardly through the drill pipe and out of the bit.
[0008] The earth disintegrating action of the rolling cone cutters
is enhanced by providing the cutters with a plurality of cutter
elements. Cutter elements are generally of two types: inserts
formed of a very hard material, such as tungsten carbide, that are
press fit into undersized apertures in the cone surface; or teeth
that are milled, cast or otherwise integrally formed from the
material of the rolling cone. Bits having tungsten carbide inserts
are typically referred to as "TCI" bits or "insert" bits, while
those having teeth formed from the cone material are known as
"steel tooth bits." In each instance, the cutter elements on the
rotating cutters break up the formation to form the new borehole by
a combination of gouging and scraping or chipping and crushing.
[0009] In oil and gas drilling, the cost of drilling a borehole is
very high, and is proportional to the length of time it takes to
drill to the desired depth and location. The time required to drill
the well, in turn, is greatly affected by the number of times the
drill bit must be changed before reaching the targeted formation.
This is the case because each time the bit is changed, the entire
string of drill pipe, which may be miles long, must be retrieved
from the borehole, section by section. Once the drill string has
been retrieved and the new bit installed, the bit must be lowered
to the bottom of the borehole on the drill string, which again must
be constructed section by section. As is thus obvious, this
process, known as a "trip" of the drill string, requires
considerable time, effort and expense. Accordingly, it is always
desirable to employ drill bits which will drill faster and longer,
and which are usable over a wider range of formation hardness.
[0010] The length of time that a drill bit may be employed before
it must be changed depends upon its rate of penetration ("ROP"), as
well as its durability. The geometry, materials, and positioning of
cutter elements upon the rotatable cone cutters significantly
impact ROP and durability. Likewise, the geometry and positioning
of the cone cutter cutters on the bit legs may affect ROP, footage
drilled and total bit life. For example, characteristics including
journal angle, cone offset, cone diameter, cone height, and other
factors may impact bit life, drilling efficiency and footage
drilled.
[0011] In designing rolling cone drill bits, a conventional
practice is to employ bit legs and rotatable cone cutters that
include uniform characteristics such as journal angle, cone offset,
cone diameter, cone height, and others. For example, it is
generally believed that a higher journal angle, for example about
36.degree., is more effective in drilling through relatively hard
formations. As such, when a particular formation hardness is
expected to be encountered, it is typical to employ a bit in which
all three cones have identical, relatively high journal angles.
Similarly, it is common to employ bits in which the rolling cone
cutters are all offset the same amount relative to the bit axis. By
designing bits with rolling cone cutters of uniform or identical
characteristics, such as journal angle and cone offset, as
examples, the bit may be thought to be optimized for particular
formations and/or other drilling parameters; however, in many
cases, the selected, uniform characteristics may actually cause the
bit to suffer undesirable consequences, such as undue wear to
certain rows of cutter elements, and/or breakage of particular
cutting elements. Likewise, providing all the rolling cone cutters
and bit legs with the same characteristics may not provide the
desirable or optimum ROP for a given formation, as a further
example.
[0012] Increasing ROP while maintaining good cutter and bit life to
increase the footage drilled is an important goal in order to
reduce drilling time and recover valuable oil and gas more
economically. Optimizing bit leg and cone characteristics to
provide enhancements in ROP and bit life would further that
goal.
BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS
[0013] In accordance with at least one embodiment, a drill bit for
drilling through earthen formations comprises a bit body having a
bit axis. In addition, the drill bit comprises a first rolling cone
cutter mounted on the bit body at a first journal angle and adapted
for rotation about a first cone axis. Further, the drill bit
comprises a second rolling cone cutter mounted on the bit body at a
second journal angle and adapted for rotation about a second cone
axis, wherein the second journal angle differs from the first
journal angle.
[0014] In accordance with another embodiment, a drill bit for
drilling through earthen formations comprises a bit body having a
bit axis. In addition, the drill bit comprises at least three
rolling cone cutters mounted on the bit body and adapted for
rotation about a different cone axis, each of the cone cutters
including a circumferential row of gage cutter elements and at
least one circumferential row of inner row cutter elements spaced
apart from the row of gage cutter elements. At least one of the
inner row cutter elements of one rolling cone cutter intermesh with
the inner row cutter elements of a different rolling cone cutter.
Further, each of the rolling cone cutters defines a journal angle
and a cone offset. Still further, the journal angle of a first of
the cone cutters differs from the journal angle of a second of the
cone cutters.
[0015] In accordance with another embodiment, a drill bit for
drilling through earthen formations comprises a bit body having a
bit axis. In addition, the drill bit comprises at least three
rolling cone cutters mounted on the bit body and adapted for
rotation about a different cone axis. Further, each of the cone
cutters includes a circumferential row of gage cutter elements and
at least one circumferential row of inner row cutter elements
spaced apart from the row of gage cutter elements, wherein at least
one of the inner row cutter elements of one rolling cone cutter
intermeshes with the inner row cutter elements of a different
rolling cone cutter. Still further, a first of the cone cutters
differs from a second of the cone cutters in at least one
characteristic selected from the group consisting of cone offset,
journal angle, seal type, journal length, and journal diameter.
[0016] In accordance with another embodiment, a drill bit for
drilling through earthen formations comprises a bit body having a
bit axis. In addition, the drill bit comprises a plurality of bit
legs, each of the legs including a rolling cone cutter mounted
thereon and adapted for rotation about a different cone axis.
Further, each of the cone cutters includes at least one
circumferential row of inner row cutter elements, wherein at least
one of the inner row cutter elements of one cone cutter intermeshes
with the inner row cutter elements of a different cone cutter.
Moreover, at least a first of the cone cutters differs from a
second of the cone cutters in at least one characteristic selected
from the group consisting of journal angle, cone offset, seal type
and bearing configuration.
[0017] In accordance with yet another embodiment, a drill bit for
drilling through earthen formations comprises a bit body having a
bit axis. In addition, the drill bit comprises at least three
rolling cone cutters mounted on the bit body and adapted for
rotation about a different cone axis, each of the cone cutters
including a circumferential row of gage cutter elements and at
least one circumferential row of inner row cutter elements spaced
apart from the row of gage cutter elements. Further, at least one
of the inner row cutter elements of one rolling cone cutter
intermeshes with the inner row cutter elements of a different
rolling cone cutter. Each of the cone cutters defines a journal
angle and a cone offset, and the cone offset of at least one cone
cutter is different from the cone offset of another of the cone
cutters.
[0018] Thus, the embodiments described herein comprise a
combination of features providing the potential to overcome certain
shortcomings associated with prior devices. The various
characteristics described above, as well as other features, will be
readily apparent to those skilled in the art upon reading the
following detailed description of the preferred embodiments, and by
referring to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] For a more detailed description of the preferred
embodiments, reference will now be made to the accompanying
drawings , which are not drawn to scale:
[0020] FIG. 1 is a perspective view of an earth-boring bit made in
accordance with certain of the principles of the present
invention.
[0021] FIG. 2 is a partial section view of the bit shown in FIG. 1
taken through one bit leg and one cone cutter.
[0022] FIG. 3 is a schematic representation showing a
cross-sectional view of the intermesh of the three rolling cones of
the bit shown in FIG. 1.
[0023] FIG. 4 is a schematic representation showing the three cone
cutters of the bit shown in FIG. 1 as they are positioned in the
borehole.
[0024] FIG. 5 is a partial section view of the drill bit shown in
FIG. 1 taken along the lines 4-4 shown in FIG. 4.
[0025] FIG. 6 is an elevation view of the bottom of an alternative
three cone drill bit made in accordance with certain principles of
the present invention.
[0026] FIG. 7 is an elevation view of the bottom of an alternative
three cone drill bit made in accordance with certain principles of
the present invention.
[0027] FIG. 8 is a partial section view of another alternative
drill bit taken through two intersecting planes so as to show views
of two cones simultaneously.
[0028] FIG. 9 is a schematic representation showing three cone
cutters in another alternative embodiment drill bit made in
accordance with certain principles of the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0029] Certain terms are used throughout the following description
and claims to refer to particular features or components. As one
skilled in the art will appreciate, different persons may refer to
the same feature or component by different names. This document
does not intend to distinguish between components or features that
differ in name but not function. The drawing figures are not
necessarily to scale. Certain features and components herein may be
shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in interest of
clarity and conciseness.
[0030] In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ." Also, the term "couple" or "couples" is intended to mean
either an indirect or direct connection. Thus, if a first device
couples to a second device, that connection may be through a direct
connection, or through an indirect connection via other devices and
connections.
[0031] Rolling cone drill bits typically have been designed and
manufactured such that their rotatable cones have identical journal
angles, seal types, and bearing assemblies. This has an advantage
of making the assembly of the bit easier and faster. Also, this
conventional design approach does not require a manufacturer to
inventory what might be a substantially larger number of parts, and
it lessens the likelihood of assembly errors. Likewise, many
conventional bits are manufactured with each rolling cone having
the same degree of offset relative to the bit axis. However, at the
same time, employing identical bit legs, journal angles, cone
offsets seals, and bearings eliminates potential enhancements that
could otherwise be provided by varying one or more of these
characteristics. By optimizing these exemplary characteristics, as
well as other leg and cone characteristics, a bit designer can
enhance bit performance in one or more aspects, such as, ROP,
gage-holding ability, durability, bit life, or combinations
thereof
[0032] Referring now to FIG. 1, an earth-boring bit 10 is shown to
include a central axis 11 and a bit body 12 having a threaded pin
section 13 at its upper end that is adapted for securing the bit to
a drill string (not shown). Bit 10 has a predetermined gage
diameter as defined by the outermost reaches of three rolling cone
cutters 1, 2, 3 (cones 1 and 2 shown in FIG. 1), which are
rotatably mounted on bearing shafts that depend from the bit body
12. Bit body 12 is composed of three sections or legs 19 (two shown
in FIG. 1) that are welded together to form bit body 12. Bit 10
further includes a plurality of nozzles 18 that are provided for
directing drilling fluid toward the bottom of the borehole and
around cone cutters 1-3. Bit 10 includes lubricant reservoirs 17
that supply lubricant to the bearings that support each of cone
cutters 1-3. Bit legs 19 include a shirttail portion 16 that serves
to protect the cone bearings and cone seals from damage caused by
cuttings and debris entering between leg 19 and its respective cone
cutter.
[0033] Referring now to both FIGS. 1 and 2, each cone cutter 1-3 is
mounted on a pin or journal 20 extending from bit body 12, and is
adapted to rotate about a cone axis of rotation 22 oriented
generally downwardly and inwardly toward the center of the bit
(only exemplary cone cutter 2 illustrated in FIG. 2). Pin 20 may
also be referred to as a journal arm or journal pin. Each cutter
1-3 is secured on pin 20 by locking balls 26, in a conventional
manner. In the embodiment shown, radial and axial thrusts are
absorbed by journal sleeve 28 and thrust washer 31. The bearing
structure shown is generally referred to as a journal bearing or
friction bearing; however, the invention is not limited to use in
bits having such structure, but may equally be applied in a roller
bearing bit where cone cutters 1-3 would be mounted on pin 20 with
roller bearings disposed between the cone cutter and journal pin
20. In both roller bearing and friction bearing bits, lubricant may
be supplied from reservoir 17 to the bearings by apparatus and
passageways that are omitted from the figures for clarity. The
lubricant is sealed in the bearing structure, and drilling fluid
excluded therefrom, by means of an annular seal 34 which may take
many forms. Drilling fluid is pumped from the surface through fluid
passage 24 where it is circulated through an internal passageway
(not shown) to nozzles 18 (FIG. 1). The borehole created by bit 10
includes sidewall 5, corner portion 6, and bottom 7, best shown in
FIG. 2.
[0034] Referring still to FIGS. 1 and 2, each cutter 1-3 includes a
generally planar backface 40 and nose portion 42 opposite backface
40. Adjacent to backface 40, cutters 1-3 further include a
frustoconical surface 44 that is adapted to retain cutter elements
that scrape or ream the sidewalls of the borehole as the cone
cutters rotate about the borehole bottom. Frustoconical surface 44
will be referred to herein as the "heel" surface of cone cutters
1-3, it being understood, however, that the same surface may be
sometimes referred to by others in the art as the "gage" surface of
a rolling cone cutter.
[0035] Extending between heel surface 44 and nose 42 is a generally
conical surface 46 adapted for supporting cutter elements that
gouge or crush the borehole bottom 7 as cone cutters 1-3 rotate
about the borehole. Frustoconical heel surface 44 and conical
surface 46 converge in a circumferential edge or shoulder 50.
Although referred to herein as an "edge" or "shoulder," it should
be understood that shoulder 50 may be contoured, such as by a
radius, to various degrees such that shoulder 50 will define a
contoured zone of convergence between frustoconical heel surface 44
and the conical surface 46. Conical surface 46 is divided into a
plurality of generally frustoconical regions or bands 48a-c
generally referred to as "lands" which are employed to support and
secure the cutter elements as described in more detail below.
Grooves 49a, b are formed in cone surface 46 between adjacent lands
48a-c.
[0036] In the bit shown in FIGS. 1 and 2, each cone cutter 1-3
includes a plurality of wear resistant inserts or cutter elements
60, 61, 62. Inserts 60, 61, 62 each generally include a cylindrical
base portion with a central axis, and a cutting portion that
extends from the base portion and includes a cutting surface for
cutting formation material. The cutting surface may be symmetric or
asymmetric relative to the insert central axis. All or a portion of
the base portion is secured into a mating socket formed in the
surface of the cone cutter. Each insert 60, 61, 62 may be secured
within the mating socket by any suitable means including, without
limitation, an interference fit, brazing, or combinations thereof.
The "cutting surface" of an insert is defined herein as being that
surface of the insert that extends beyond the surface of the cone
cutter. Further, the extension height of an insert or cutter
element is the distance from the cone surface to the outermost
point of the cutting surface of the cutter element as measured
substantially perpendicular to the cone surface.
[0037] Inserts 60 are referred to herein as "heel" or "heel row"
inserts as they extend from the generally frustoconical heel
surface 44. Heel inserts 60 generally function to scrape or ream
the borehole sidewall 5 (FIG. 2) to maintain the borehole at full
gage, to prevent erosion and abrasion of heel surface 44, and to
protect the shirttail portion 16 of bit leg 19. In this embodiment,
heel inserts 60 are arranged in a circumferential row about cone
axis 22.
[0038] Inserts 61 are positioned adjacent shoulder 50 and radially
inward (relative to bit axis 11) of the circumferential row of heel
cutter elements 60. Inserts 61 are referred to as "gage" or "gage
row" inserts and are oriented to cut the borehole corner 6 (FIG. 2)
and to ensure that the borehole maintains full gage diameter. In
this embodiment, gage inserts 61 are arranged in a circumferential
row about cone axis 22 and axially spaced apart from heel row
inserts 60 relative to cone axis 22. In this embodiment, gage
cutter elements 61 include a cutting surface having a generally
slanted crest, although alternative shapes and geometries may be
employed. Although cutter elements 61 are referred to herein as
gage or gage row cutter elements, others in the art may instead
describe such cutter elements as heel cutters or heel row
cutters.
[0039] Referring still to FIGS. 1 and 2, inserts 62 are positioned
between the circumferential row of gage cutter elements 61 and nose
42. Inserts 62 are referred to as "inner row" or "bottomhole"
cutter elements and serve primarily to gouge, crush, and remove
formation material from the borehole bottom 7 (FIG. 2). In this
embodiment, inner row cutter elements 62 are arranged in
circumferential rows about cone axis 22 that are axially spaced
apart from each other, from heel row inserts 60, and from gage
inserts 61 relative to cone axis 22. Further, although bottomhole
cutter elements 62 are shown to include cutting surfaces having a
generally rounded chisel shape, other shapes and geometries may
also be employed. As will be described in more detail below, inner
row inserts 62 are preferably arranged and spaced on each cone
cutter 1-3 so as to intermesh, yet not interfere with the inner row
inserts 62 of the other cone cutters 1-3.
[0040] Referring momentarily to FIG. 3, the intermeshed
relationship between cones 1-3 of bit 10 is schematically shown. In
this view, commonly termed a "cluster view," cone 2 is
schematically represented in two halves so that the intermesh
between cones 2 and 3 and between cones 1 and 2 may be depicted
simultaneously. Performance expectations of rolling cone bits
typically require that the cone cutters be as large as possible
within the borehole diameter so as to allow use of the maximum
possible bearing size and to provide a retention depth adequate to
secure the cutter element base within the cone steel. To achieve
maximum cone cutter diameter and still have acceptable insert
retention and protrusion, some of the rows of cutter elements are
arranged to pass between the rows of cutter elements on adjacent
cones as the bit rotates. In some cases, certain rows of cutter
elements extend so far that clearance areas or grooves
corresponding to cutting paths taken by cutter elements in these
rows are provided on adjacent cones so as to allow the bottomhole
cutter elements on adjacent cutters to intermesh farther. Thus, the
term "intermesh" as used herein refers to the overlap of any part
of at least one cutter element on one cone cutter with the envelope
defined by the maximum extension of the cutter elements on an
adjacent cutter.
[0041] Referring still to FIG. 3, each cone cutter 1-3 has an
envelope 101 defined by the maximum extension height of the cutter
elements on that particular cone. In this embodiment, envelope 101
of each cone cutter 1-3 is defined by the extension height of inner
row inserts 62; inner row inserts 62 have the largest extension
height in this embodiment. The cutter elements that "intersect" or
"break" the envelope 101 of an adjacent cone may be said to
"intermesh" with that adjacent cone. For example, inner row insert
62-1 of cone 1 breaks envelope 101 of cone 2, and breaks envelope
101 of cone 3, and therefore intermeshes with the inserts of cones
2 and 3. Likewise, inner row insert 62-2 of cone 2 breaks envelope
101 of cone 1, and envelope 101 of cone 3, and therefore
intermeshes with the inserts of cones 1 and 3. Still further, inner
row insert 62-3 of cone 3 breaks envelope 101 of cone 1, and
envelope 101 of cone 2, and therefore intermeshes with the inserts
of cones 1 and 2. As best seen in FIG. 3, grooves 49a and 49b on
each cone 1-3 allow the cutting surfaces of certain bottomhole
cutter elements 62 of adjacent cone cutters 1-3 to intermesh,
without contacting the cone steel or surface of cones 1-3. It
should be understood however, that in embodiments where the
intermeshing cutter elements do not extend as far as those depicted
in FIG. 3, clearance areas or grooves may not be necessary.
[0042] The drill bit 10 previously described with reference to
FIGS. 1 and 2 employs bit legs 19 and cone cutters 1-3 that differ
in various characteristics, including journal angle and cone
offset. In this way, each leg 19 and each cutter 1-3 can be
optimized for a particular cutting duty or to better withstand
applied loads and forces in order to provide the potential for
increased ROP and bit life.
[0043] Bit offset is best understood with reference to FIG. 4. In
this Figure, cones 1-3 are shown schematically as they appear in
the borehole. In this instance, cones 1 and 2 are each positioned
to have the same offset, while cone 3 has a different offset. Thus,
the cone cutters 1-3 have differing or non-uniform offsets.
[0044] "Offset" is a term used to describe the orientation of a
cone cutter and its axis relative to the bit axis. More
specifically, a cone is offset (and thus a bit may be described as
having cone offset) when the cone axis does not intersect or pass
through the bit axis, but instead passes a distance away from the
bit axis. Referring to FIG. 4, cone offset may be defined as the
distance "d" between the projection 22p of the rotational axis 22
of the cone cutter and a line "L" that is parallel to that
projection and intersects the bit axis 11. Thus, the larger the
distance "d", the greater the offset.
[0045] In a bit having cone offset, a rolling cone cutter is
prevented from rolling along the hole bottom in what would
otherwise be its "free rolling" path, and instead is forced to
rotate about the centerline of the bit along a non-free rolling
path. This causes the rolling cone cutter and its cutter elements
to engage the hole bottom in motions that may be described as
skidding, scraping and sliding. These motions apply a shearing type
cutting force to the hole bottom. Without being limited by this or
any other theory, it is believed that in certain formations, these
motions can be a more efficient or faster means of removing
formation material, and thus enhance ROP, as compared to bits
having no cone offset where the cone cutter predominantly cuts via
compressive forces and a crushing action. However, it should also
be appreciated that such shearing cutting forces arising from cone
offset accelerate the wear of cutter elements, especially in hard,
more abrasive formations, and may cause cutter elements to fail or
break at a faster rate than would be the case with cone cutters
having no offset. This wear and possibly breakage is particularly
noticeable in the gage row where the cutter elements cut the corner
6 of the borehole to maintain the borehole at full gage
diameter.
[0046] Cone offset may be positive or negative. Referring again to
FIG. 4, cone cutters 1 and 2 are mounted with negative offset, with
the offset being the distance d, for both cones 1 and 2 in this
example. By contrast, cone 3 is shown to be mounted having positive
offset represented by d.sub.2. In other embodiments, all three cone
cutters may have positive offset, or all may have negative offset,
where at least one of the offsets differs in magnitude from the
others.
[0047] With negative offset, the region of contact R.sub.1 is
behind the cone's axis of rotation with respect to the direction of
rotation of the bit. On the other hand, with positive offset, the
region of contact R.sub.2 of the cone cutter with the sidewall is
ahead of the axis of rotation of the cone cutter. Both positive and
negative offset cause the cone cutters to deviate from a pure
rolling motion and causes them to slide over and scrape the bottom
of the borehole in a shearing action. Without being limited by this
or any other theory, it is believed that, whether positive or
negative, a larger total offset distance "d" (i.e., a larger
absolute value offset) tends to increase formation removal and ROP,
but may also result in accelerated gage row insert wear, and hence
tends to decrease bore hole gage maintenance. Conversely, it is
believed that a smaller total offset distance "d" (i.e., a smaller
absolute value offset) tends to enhance borehole gage maintenance,
but may reduce ROP.
[0048] Varying the magnitude of the offsets among the cone cutters
provides a bit designer the potential to improve ROP and other
performance criteria of the bit. For example, in comparison to a
conventional bit having a +0.219 in. offset for each of the three
cones, it would be expected that increasing that offset to +0.50
in. for each of the three cones would provide a bit having a higher
ROP if other factors remained the same. However, compared to the
same bit having +0.219 in. offset for all three cones, in the bit
with all cones having +0.50 in. offset, it would also be expected
that on one or more of the +0.50 in. offset cones, the gage cutter
elements would wear significantly and round off, such that it might
prove impossible to maintain a full gage diameter borehole for an
acceptable period of time. Accordingly, it is desirable to vary the
offset among the three cones to optimize the bit's all-around
performance and, for example, to provide at least one cone whose
primary function would be to enhance ROP, and another cone whose
primary function would be to maintain gage.
[0049] One example is to provide a three cone bit with the
following offsets: TABLE-US-00001 Cone 1 Cone 2 Cone 3 +0.50 in.
-0.031 in. +0.50 in.
As compared to a conventional three cone bit in which all three
cones have the same +0.219 in. offset, providing the bit with a
larger +0.50 in. offset for cones 1 and 3 would be expected to
provide a higher bit ROP if other factors remained the same.
Providing cone 2 with -0.031 in. offset would enhance the bit's
ability to maintain gage, even at the higher ROP, as the gage and
heel cutter elements of cone 2 would not be subjected to the higher
impacts and shearing forces from sidewall and corner cutting as
those of cone cutters 1 and 3. Thus, employing differing or
non-uniform cone offsets provides a potential for a bit design
having enhanced ROP with satisfactory gage-holding
capabilities.
[0050] The example given above is exemplary only, and various other
positive and negative offsets may be employed. For example, in the
specific example above, cone 2 may instead have a zero offset or a
+0.031 in. offset and still provide the desirable gage-holding
function.
[0051] Like offset, varying the journal angle between the various
legs on the bit offers potential advantages. Journal angle may be
defined as the angle between the cone axis (the cone axis
coinciding with the axis of the journal pin) and a plane
perpendicular to the axis of rotation of the drill bit.
Conventionally, for relatively hard formations, such as bits having
the IADC classification 6-1-x and higher, the journal angle for all
cones is about 36.degree. or more. Softer formation bits, such as
bits having an IADC classification lower than 6-1-x, typically have
uniform journal angles of about 32.degree. for all cones. In
general, a smaller or lower journal angle tends to increase
formation removal and ROP, but may also detrimentally impact
borehole gage maintenance. Without being limited by any particular
theory, it is believed that a lower journal angle increases
bottomhole scraping and sliding, but also reduces engagement
between the gage row inserts and heel row inserts engages and the
borehole sidewall. Conversely, it is believed that relatively
higher journal angles tend to decrease formation removal and ROP,
but also tend to enhance borehole gage maintenance. Referring to
FIG. 5, bit 10, cones 1 and 2, and the journal pins 20-1 and 20-2
to mounted, respectively, are shown in partial cross-section. As
shown, cone 1 is rotatably mounted on bit 10 with a journal angle
70 measured between axis 22 of cone 1 and a plane perpendicular to
bit axis 11. In this example, journal angle 70 of cone 1 is
30.degree.. Cone 2 is mounted with the journal angle 71 measured
between axis 22 of cone 2 and a plane perpendicular to bit axis 11.
In this example, journal angle 71 of cone 2 is 36.degree.. Although
not shown in FIG. 5, cone 3 is also mounted with a journal angle of
approximately 30.degree. in this embodiment. Cones 1-3 have the
offsets previously described in reference to FIG. 4.
[0052] Thus, the lower journal angle 70 of cone 1 provides greater
ROP relative to cone 2. Compared to a conventional three cone bit
having each cone cutter mounted at a 32.5.degree. journal angle,
bit 10, with cones 1 and 3 each at a relatively low 30.degree.
journal angle, and cone 2 at a 36.degree. journal angle, would
expected to provide greater ROP. Further, in this example, cone 2,
with its relatively large journal angle of 36.degree., would be
expected to undergo less scraping against the borehole sidewall and
thereby provide a cone cutter capable of cutting to full gage
diameter for a longer period of time than cone cutters 1 and 3 that
are more aggressively positioned with the lower journal angle.
[0053] One method for designing a bit that provides enhanced ROP
relative to a conventional three cone bit, and that provides
satisfactory gage-holding ability, is as follows. First, the
arrangement of inserts and the cutting structure on the three cone
cutters are selected and then analyzed to determine which cone
cutter includes cutting inserts that will most impact ROP. That
cone cutter (cone A in this example) will typically be the most
aggressive cutter and include inserts in locations suggesting that
they will dig into the formation the most and thereby provide the
most benefit to ROP. Relative to a conventional three cone bit
having the same offset and same journal angle for all three cone
cutters, cone A in the new bit design would be provided with a
larger offset and a lower journal angle than that of the
conventional bit.
[0054] Next, the cone cutter that would appear to be the least
aggressive based on the insert pattern and cutting structure would
be identified. That cone cutter (cone B in this example) on the new
design would be provided with the lowest offset and the highest
journal angle of the three cone cutters in the new bit design.
Given its less-aggressive cutting structure, cone B will have the
least effect on ROP. However, the relatively low offset and high
journal angle of cone B will enhance its ability to protect gage
and maintain a full diameter borehole.
[0055] Next, the remaining cone cutter (cone C in this example) of
the new bit design is selected to have a first benchmark journal
angle and offset. For instance, cone cutter C may first be provided
with the same journal angle and offset as a conventional bit where
all three cones have the same characteristics. If in testing or
modeling the ROP of the new design was not as great as desired,
then the design could be modified to provide cone C with a lower
journal angle and/or a larger offset compared to the initial offset
and journal angle selected for cone C that did not provide the
desired ROP performance. Conversely, if upon testing or modeling
the bit was not able to maintain gage satisfactorily, then the
design for cone C could be modified to have a smaller offset and/or
higher journal angle relative to the initial offset and journal
angle selected for cone C. Further iterations are possible to
achieve an optimum offset and journal angles for each of the three
cones A, B, and C.
[0056] As still further examples of particular embodiments of the
invention, a three cone drill bit is shown in FIG. 6 to include two
cones having low offsets and high journal angles relative to the
third cone on the bit. For example, cones 1 and 2 include
relatively small offsets of approximately +0.125 in. and relatively
high journal angles of approximately 36.degree.. By contrast, cone
3 includes a relatively larger offset of +0.313 in. and a
relatively low journal angle of 32.degree.. In this example, cones
1 and 2 are generally better suited for cutting harder
formations.
[0057] As a further example, in another multi-coned bit shown in
FIG. 7, cone 1 is provided with a relatively high cone offset
relative to cones 2 and 3. In this example, cone 1 includes a
positive offset of approximately +0.313 in. By contrast, cones 2
and 3 are provided with zero offset. In this arrangement, cone 1
with its relatively high offset may provide a relatively high
penetration rate on the borehole bottom, while the cone cutters 2
and 3 maintain gage without experiencing severe wear or an
inordinate amount of insert breakage in the gage row as might
otherwise occur if 2 and 3 were likewise aggressively positioned
with relatively high offsets. In this example, cone 1 may include a
journal angle of about 32.5.degree. while cones 2 and 3 employ
journal angles of approximately 38.degree. and 35.5.degree.,
respectively.
[0058] It should be understood that the examples presented above
are merely specific examples of certain of the bits that may be
manufactured to employ the concepts broadly disclosed herein.
However, the concepts described herein are not limited only to
those examples and may, for example, include multi-cone bits in
which the journal angles and cone offsets differ in other respects
and to different degrees. As a further specific example, a bit such
as that shown in FIG. 5 may be employed having a first cone offset
that is less than the cone offset of a second cone of the bit, and
where the journal angle of the first cone is less than the journal
angle of the second cone. In certain applications, as dictated by
bit size, formation material, and other factors, substantial ROP
gains from employing a relatively low journal angle in this bit may
compensate or override the detrimental effects on ROP presented by
a relatively low offset. Thus, such a situation could permit the
relatively low offset to be employed in a particular cone cutter in
order to enhance the durability of the gage region of the cutter
and thus enhance the ability of the bit to maintain full gage
diameter.
[0059] It is also contemplated that bearings will differ from leg
to leg on a given bit, such differences including journal diameter,
length and bearing type. Presently, it is conventional practice to
employ the same type and sized bearings for each cone cutter and
bit leg. For a conventional journal bearing bit, the diameter of
the journal pin is typically the same for each cone cutter, the
diameter being dependent on maintaining a minimum measure of cone
steel between the bearing and the embedded base of adjacent
inserts. For example, referring again to FIG. 5, an insert 62-1 is
shown to have its base embedded in the steel of cone 2 at a
location adjacent to journal pin 20-2. A minimum distance M must be
maintained between the ball race 73 that is formed in the cone
steel and the base of insert 62-1. Thus, in designing a
conventional three cone bit, the journal pins on each of the three
legs would have the same diameter, the diameter being that required
to maintain a sufficient minimum distance M between the cone and
insert base that most closely approaches the cone. This has been
conventional practice even in cases where other cone cutters could
have employed larger journal diameters because they were not
constrained by adjacent inserts. By contrast, in FIG. 5, the
diameter of journal pin 20-1 is greater than the diameter of
journal 20-2 (figures not drawn to scale). In part, this is because
there is no cutter element positioned in region 74 that would
prevent pin 20-1 from having a relatively larger diameter. As such,
the diameter of journal pin 20-1 is enlarged relative to the
diameter of journal pin 20-2. Likewise, as discussed further
herein, the diameter of cones 1 and 2 may differ. In general, a
larger diameter cone offers the ability to employ journal pins that
are longer or have a greater diameter, or both.
[0060] Providing a bit with legs and cones having non-uniform
journal angles and offsets also offers potential for optimization
of bearing size(s), although it should be appreciated that insert
size and placement affects the bearing size to a greater degree
than journal angle and bit offset. Nevertheless, for bit legs and
cone cutters having higher journal angles or smaller offsets, or
both, there may exist greater space to accommodate a larger
diameter journal pin and larger bearing surfaces. For example, an
increase in journal angle while maintaining cone distance from the
bottomhole allows for a longer cone cutter and hence a larger
bearing surface area between the cone and the journal pin.
[0061] Bit 10 shown in FIG. 5 employs journal bearings on all three
cone cutters. In other embodiments, certain cone cutters will be
mounted via journal bearings while other cone cutters are mounted
via roller bearings. For example, referring to FIG. 8, a roller
cone bit 80 includes a first cone cutter 81 mounted on a journal
pin 20-1 by means of roller bearings 84. Second cone cutter 82 is
mounted with journal bearings. In part, the choice of bearing type
may depend on the cone diameter, as well as cone speed. Without
necessarily considering all other design factors, it may be
preferable to use the roller bearings in larger diameter cone
cutters and, in other cases, in cone cutters that turn faster than
other cutters on the bit.
[0062] In a similar manner, the seal types and configurations may
vary from leg to leg or cone to cone on a multi-coned bit.
Referring again to FIG. 5, cone 2 is shown to be sealed against
journal pin 20-2 via a conventional elastomeric O-ring seal 75. By
contrast, cone 1 is sealed to journal pin 20-1 via seal member 76
having an elongate profile which may be, for example, what is
sometimes characterized as a "bullet" seal. Certain such bullet
seals and other seals applicable in the embodiments described
herein are described in U.S. Pat. Nos. 6,170,830, 6,196,339, and
6,123,337, the disclosure of each of which is hereby incorporated
herein by reference in its entirety. In the example shown in FIG.
5, where cone 1 is primarily intended to enhance ROP, such as in
relatively soft formations, it may be that the RPMs of cone 1 are
substantially higher per bit revolution than cone 2, and thus, a
bullet seal may be more appropriate for cone 1. However, in cone 2,
where bottomhole formation removal and ROP are not its primary
function, the RPM may not be as high, and thus, an O-ring seal may
be more appropriate. Preferably, although not a requirement, a cone
that experiences greater RPMs employs a bullet seal, whereas a cone
that experiences slower RPMs employ a more conventional O-ring,
seal.
[0063] Thus, rather than standardizing on a particular bearing and
seal for every leg of a multi-coned bit, the bearings and seals may
be varied and optimized to provide maximum durability and bit life.
Most conventional bits use identical bearings and seals for each
cone in a multi-coned bit in order to simplify manufacturing and
inventory management. However, the embodiments disclosed herein
provide design flexibility such that the bearing capacity may be
maximized for each individual cone cutter and optimized relative to
the cutting structure of each cone in order to best absorb and
withstand the cone's proportional share of load, as well as the
direction in which it is loaded. Likewise, various seal types and
seal arrangements may be employed and may be varied from cone to
cone to optimize bit life and/or performance. For instance,
referring to FIG. 8, cone 82 employs an O-ring seal 75. By
contrast, cone 81 employs dual seals 86, 87 that are disposed in
spaced apart seal glands 88, 89, respectively.
[0064] Conventionally, the bit legs, journal pins, and cone cutters
are separated by a uniform angular distance or "separation angle"
of 120.degree.. However, according to some embodiments illustrated
and described herein, the separation angle between the legs of the
drill bit and the cone cutters attached thereto may be varied. As
shown schematically in FIG. 9, a bit 90 in accordance with this
application may include cones 2 and 3 spaced apart by 110.degree.,
with each of cones 2 and 3 each separated from cone 1 by
125.degree.. This greater degree of separation between cones 1 and
2 and between cones 1 and 3 may provide clearance for cone 1 to be
larger in diameter than cones 2 and 3. For example, cone 1 may have
a 97/8 in. diameter while cones 2 and 3 have a 77/8 in. diameter
which, in this arrangement, effectively form an 83/4 in. diameter
bit 90. In general, a relatively larger cone (e.g., cone 1)
provides the bit designer with the ability to employ larger
diameter inserts in a given row, or a greater number of inserts, or
both, than could be employed in the smaller sized cone. Likewise,
the journal pin and bearing surfaces for cone 1 may be larger for
the larger cone cutter. For example, the journal pin may be larger
in diameter and may have a greater length, decreasing the unit
loading on the bearing. Further, the larger cone 1 may provide the
ability to employ a different type or longer-lasting seal assembly,
or one structured in a way that could not be employed with the
relatively smaller clearances in the smaller cone cutters 2 and 3.
For example, in cone cutters 2 and 3, a single elastomeric O-ring
seal may be employed, where, by contrast, in cone cutter 1 a dual
seal arrangement may be employed, such as dual seals 86, 87 shown
in FIG. 8. It should also be appreciated that mounting a cone
cutter with a larger journal angle also allows for a larger
diameter cone.
[0065] The choice of seal types and seal arrangements may follow
from cone size. For example, referring again to FIG. 9, there is
schematically shown a bit 90 having cone 1 with a relatively large
diameter and cones 2 and 3 with relatively smaller and equal
diameters. In this example, the smaller cones 2 and 3 will rotate
faster, making it desirable to use a seal such as the bullet seal
76 shown in FIG. 5. By contrast, the relatively large and slower
turning cone 1 may be sealed with a conventional O-ring seal, or a
pair of seals as mentioned above.
[0066] It should be appreciated that having both positive and
negative offset cone cutters on the same bit may also dictate or
suggest employing differing separation angles. For example,
referring again to FIG. 4, the separation angle between cones 2 and
3 is greater than the separation angle between cones 1 and 2 and
between cones 1 and 3.
[0067] It may also be desirable in certain designs to include
differing cone heights from leg to leg. Cone height may be measured
from various points, but generally is defined as the distance
between a fixed point on the bit and the point in which the
projection of the cone axis 22 intersects bit axis 11. For example,
referring back to FIGS. 1 and 5, and using the upper surface 9 of
pin section 13 as the fixed reference point, cone cutter 1 is
higher in the bit than cone cutter 2 and thus may be described as
having a greater cone height (the cone having the greater height
being the one closer to a reference point and further from the
borehole bottom than the other cone). In a drill bit where, for
example, one cone was intended primarily to maintain gage, and
another (or others) intended to enhance ROP, the cone cutter
designed to maintain gage preferably has a greater cone height (be
positioned further from the hole bottom). Such cone cutter would
also desirably include a low offset, and a high journal angle (for
example, in the range of about 36.degree.-39.degree.). On the other
hand, the cone cutter designed to enhance ROP preferably has a
smaller cone height (be positioned closer to the hole bottom). Such
cone cutter would also desirably include a larger offset, and a
lower journal angle (for example, in the range of about
30.degree.-32.5.degree.).
[0068] In designing a multi-cone bit, one exemplary method of
design would be for the bit designer to first select an offset for
the first cone cutter and an offset for the second cone cutter. As
explained above, the first offset may be intended to enhance ROP
while the second is intended to enhance gage-holding ability.
Thereafter, journal angles of the first and second cones may be
selected, with such angles also selected to enhance ROP,
gage-holding ability, or other desired performance characteristics.
Alternatively, the journal angle(s) and offset(s) for the differing
cone cutter(s) and leg(s) may first be selected.
[0069] A next step in the design may be to choose the journal angle
and offset for a third cone cutter in a bit employing more than two
cones. The method would also include the step of determining the
appropriate size, shape, and materials for the cutting inserts, as
well as their layout on the cone cutters. It is desirable that the
bearing structure then be determined after the insert geometry is
designed so as to be able to maintain the necessary separation
between the inserts and the journal. Thereafter, depending upon
such factors as cone size and speed, appropriate seal type and size
may then be selected. The method also includes selecting the
appropriate cone height, cone diameter, and cone separation angles.
Typically, these three characteristics would be selected after
determination of the offset and journal angle for each cone
cutter.
[0070] While preferred embodiments have been shown and described,
modifications thereof can be made by one skilled in the art without
departing from the spirit or teaching herein. The embodiments
described herein are exemplary only and are not limiting. Many
variations and modifications of the above-described structures are
possible and are within the scope of the invention. Accordingly,
the scope of protection is not limited to the embodiments described
herein, but is only limited by the claims which follow, the scope
of which shall include all equivalents of the subject matter of the
claims.
* * * * *