Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02571062 2006-12-13
ROLLING CONE DRILL BIT
HAVING NON-UNIFORM LEGS
BACKGROUND
Field of the Invention
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.
Background of the Invention
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.
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.
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
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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.
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.
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.
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 , 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
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characteristics may not provide the desirable or optimum ROP for a given
formation, as a further
example.
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
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.
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.
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
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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.
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.
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.
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
For a more detailed description of the preferred embodiments, reference will
now be made to the
accompanying drawings, which are not drawn to scale:
Figure 1 is a perspective view of an earth-boring bit made in accordance with
certain of the
principles of the present invention.
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Figure 2 is a partial section view of the bit shown in Figure 1 taken through
one bit leg and one
cone cutter.
Figure 3 is a schematic representation showing a cross-sectional view of the
intermesh of the
three rolling cones of the bit shown in Figure 1.
Figure 4 is a schematic representation showing the three cone cutters of the
bit shown in Figure
1 as they are positioned in the borehole.
Figure 5 is a partial section view of the drill bit shown in Figure 1 taken
along the lines 4-4
shown in Figure 4.
Figure 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.
Figure 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.
Figure 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.
Figure 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
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.
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...
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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.
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.
Referring now to Figure 1, an earth-boring bit 10 is shown to include a
central axis I 1 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 Figure 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 Figure 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.
Referring now to both Figures 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
Figure 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
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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
(Figure 1). The borehole
created by bit 10 includes sidewall 5, corner portion 6, and bottom 7, best
shown in Figure 2.
Referring still to Figures 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.
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.
In the bit shown in Figures 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
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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.
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 (Figure 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.
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 (Figure 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.
Referring still to Figures 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 (Figure 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.
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Referring momentarily to Figure 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.
Referring still to Figure 3, each cone cutter 1-3 has an envelope 101 defmed
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 I 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
Figure 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 Figure 3, clearance areas
or grooves may not be
necessary.
The drill bit 10 previously described with reference to Figures 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
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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.
Bit offset is best understood with reference to Figure 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.
"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 Figure 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.
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.
Cone offset may be positive or negative. Referring again to Figure 4, cone
cutters 1 and 2 are
mounted with negative offset, with the offset being the distance di for both
cones 1 and 2 in this
example. By contrast, cone 3 is shown to be mounted having positive offset
represented by d2. 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.
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With negative offset, the region of contact Rl 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 R2 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.
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.
One example is to provide a three cone bit with the following offsets:
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
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those of cone cutters I 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.
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.
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 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 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 Figure 5, bit 10, cones 1 and 2, and the journal pins 20-1 and 20-
2 to which they are
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 . 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 . Although not shown in Figure 5, cone 3 is also
mounted with a journal angle
of approximately 30 in this embodiment. Cones 1-3 have the offsets previously
described in reference
to Figure 4.
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
journal angle, bit 10, with
cones 1 and 3 each at a relatively low 30 journal angle, and cone 2 at a 36
journal angle, would be
expected to provide greater ROP. Further, in this example, cone 2, with its
relatively large journal angle
of 36 , would be expected to undergo less scraping against the borehole
sidewall and thereby provide a
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CA 02571062 2006-12-13
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.
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.
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.
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.
As still further examples of particular embodiments of the invention, a three
cone drill bit is
shown in Figure 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
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CA 02571062 2006-12-13
in. and relatively high journal angles of approximately 36 . By contrast, cone
3 includes a relatively
larger offset of +0.313 in. and a relatively low journal angle of 32 . In this
example, cones 1 and 2 are
generally better suited for cutting harder formations.
As a further example, in another multi-coned bit shown in Figure 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 while cones 2 and 3 employ journal angles of
approximately 38 and 35.5 ,
respectively.
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
Figure 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.
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 Figure 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
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CA 02571062 2006-12-13
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 Figure 5, the
diameter ofjoumal pin 20-1
is greater than the diameter of journa120-2 (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.
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.
Bit 10 shown in Figure 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 Figure 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.
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 Figure 5, cone 2 is shown to be
sealed against journal pin 20-2
via a conventional elastomeric 0-ring sea175. By contrast, cone I 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
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CA 02571062 2006-12-13
a "bullet" seal. Certain such bullet seals and other seals applicable in the
embodiments described herein
are described in U.S. Patent Nos. 6,170,830, 6,196,339, and 6,123,337. In the
example shown in
Figure 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 0-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 0-ring, seal.
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 Figure 8, cone 82
employs an 0-ring seal 75. By
contrast, cone 81 employs dual seals 86, 87 that are disposed in spaced apart
seal glands 88, 89,
respectively.
Conventionally, the bit legs, journal pins, and cone cutters are separated by
a uniform angular
distance or "separation angle" of 120 . 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 Figure 9, a bit 90 in
accordance with this application
may include cones 2 and 3 spaced apart by 110 , with each of cones 2 and 3
each separated from cone
1 by 125 . 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 9 7/8 in. diameter while cones 2 and 3 have a 7 7/8 in. diameter which,
in this arrangement,
effectively form an 8 3/4 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
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CA 02571062 2006-12-13
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 0-ring
seal may be employed, where, by contrast, in cone cutter I a dual seal
arrangement may be employed,
such as dual seals 86, 87 shown in Figure 8. It should also be appreciated
that mounting a cone cutter
with a larger journal angle also allows for a larger diameter cone.
The choice of seal types and seal arrangements may follow from cone size. For
example,
referring again to Figure 9, there is schematically shown a bit 90 having cone
I 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
Figure 5. By contrast, the relatively large and slower turning cone 1 may be
sealed with a conventional
0-ring seal, or a pair of seals as mentioned above.
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
Figure 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.
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 Figures 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 -39 ). 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
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CA 02571062 2006-12-13
would also desirably include a larger offset, and a lower journal angle (for
example, in the range of
about 30 -32.5 ).
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.
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.
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.
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