Note: Descriptions are shown in the official language in which they were submitted.
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ROLLING CONE BIT WITH ENHANCEMENTS IN CUTTER ELEMENT PLACEMENT
AND MATERIALS TO OPTIMIZE BOREHOLE CORNER CUTTING DUTY
FIELD OF THE INVENTION
The invention relates generally to earth-boring bits used to drill a borehole
for the
s ultimate recovery of oil, gas or minerals. More particularly, the invention
relates to rolling cone
rock bits and to an improved cutting structure for such bits. Still more
particularly, the
invention relates to enhancements in cutter element placement and materials to
increase bit
durability and rate of penetration and enhance the bit's ability to maintain
gage.
BACKGROUND OF THE INVENTION
to An earth-boring drill bit is typically mounted on the lower end of a drill
string and is
rotated 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 formed in the drilling process will have a diameter
generally equal to the
i 5 diameter or "gage" of the drill bit.
A typical earth-boring bit 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 cutters
thereby engaging and disintegrating the formation material in its path. The
rotatable cutters may
a o be described as generally conical in shape and are therefore sometimes
referred to as rolling
cones. The borehole is formed as the gouging and scraping or crushing and
chipping action of
the rotary cones remove chips of formation material which are carned upward
and out of the
borehole by drilling fluid which is pumped downwardly through the drill pipe
and out of the bit.
The drilling fluid carries the chips and cuttings as it flows up and out of
the borehole.
2 5 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
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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, while those having teeth formed from the cone material are known
a.s "steel tooth
bits." The cutting surfaces of inserts are, in some instances, coated with a
very hard and
s abrasion resistant coating such as polycrystaline diamond (PCD). Similarly,
the teeth of steel
tooth bits are many times coated with a hard metal layer generally referred to
as hardfacing. In
each instance, the cutter elements on the rotating cutters breakup the
formation to form new
borehole by a combination of gouging and scraping or chipping and crushing.
In oiI and gas drilling, the cost of drilling a borehoie is proportional to
the length of time
z o 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 in order
to reach 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
15 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
a o upon its rate of penetration ("ROP"), as well as its durability or ability
to maintain an acceptable
ROP. The form and positioning of the cutter elements (both steel teeth and
tungsten carbide
inserts) upon the cutters greatly impact bit durability and ROP and thus are
critical to the
success of a particular bit design.
Bit durability is, in part, measured by a bit's ability to "hold gage,"
meaning its ability to
2s maintain a foil gage borehole diameter over the entire length of the
borehoie. Gage holding
ability is particularly vital in directional drilling applications which have
become increasingly
important. If gage is not maintained at a relatively constant dimension, it
becomes more
difficult, and thus more costly, to insert drilling apparatus into the
borehole than if the borehole
had a constant diameter. For example, when a new, unworn bit is inserted into
an undergage
3 o borehole, the new bit will be required to ream the undergage hole as it
progresses toward the
bottom of the borehole. Thus, by the time it reaches the bottom, the bit may
have experienced a
substantial amount of wear that it would not have experienced had the prior
bit been able to
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maintain full gage. This unnecessary wear will shorten the bit life of the
newly-inserted bit,
thus prematurely requiring the time consuming and expensive process of
removing the drill
string, replacing the worn bit, and reinstalling another new bit downhole.
To assist in maintaining the gage of a borehole, conventional rolling cone
bits typically
s employ a heel row of hard metal inserts on the heel surface of the rolling
cone cutters. The heel
surface is a generally frustoconical surface and is configured and positioned
so as to generally
align with and ream the sidewall of the borehole as the bit rotates. The
inserts in the heel
surface contact the borehole wall with a sliding motion and thus generally may
be described as
scraping or reaming the borehole sidewall. The heel inserts function primarily
to maintain a
lo constant gage and secondarily to prevent the erosion and abrasion of the
heel surface of the
rolling cone. Excessive wear of the heel inserts leads to an undergage
borehole, decreased ROP,
increased loading on the other cutter elements on the bit, and may accelerate
wear of the cutter
bearing and ultimately lead to bit failure.
In addition to the heel row inserts, conventional bits typically include a
gage row of
15 cutter elements mounted adjacent to the heel surface but orientated and
sized in such a manner
so as to cut the corner of the borehole. In this orientation, the gage cutter
elements generally are
required to cut both the borehole bottom and sidewall. The lower surface of
the gage row insert
engages the borehole bottom while the radially outermost surface scrapes the
sidewall of the
borehole. Conventional bits also include a number of additional rows of cutter
elements that are
2 0 located on the cones in rows disposed radially inward from the gage row.
These cutter elements
are sized and configured for cutting the bottom of the borehole and are
typically described as
inner row cutter elements.
Differing forces are applied to the cutter elements by the sidewall than the
borehole
bottom. Thus, requiring gage cutter elements to cut both portions of the
borehole compromises
z5 the cutter design. In general, the cutting action operating on the borehole
bottom is typically a
crushing or gouging action, while the cutting action operating on the sidewall
is a scraping or
reaming action. Ideally, a crushing or gouging action requires a tough insert,
one able to
withstand high impacts and compressive loading, while the scraping or reaming
action calls for
a very hard and wear resistant insert. One grade of cemented tungsten carbide
cannot optimally
a o perform both of these cutting functions as it cannot be as hard as desired
for cutting the sidewail
and, at the same time, as tough as desired for cutting the borehole bottom.
Similarly, PCD
grades differ in hardness and toughness and, although PCD coatings are
extremely resistant to
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wear, they are particularly vulnerable to damage caused by impact loading as
typically
encountered in bottom hole cutting duty. As a result, compromises have been
made in
conventional bits such that the gage row cutter elements are not as tough as
the inner row of
cutter elements because they must, at the same time, be harder, more wear
resistant and less
s aggressively shaped so as to accommodate the scraping action on the sidewall
of the borehole.
Accordingly, there remains a need in the art for a drill bit and cutting
structure that is ,
more durable than those conventionally known and that will yield greater ROP's
and an increase
in footage drilled while maintaining a full gage borehole. Preferably, the bit
and cutting
structure would not require the compromises in cutter element toughness, wear
resistance and
s o hardness which have plagued conventional bits and thereby limited
durability and ROP.
SUMMARY OF THE INVENTION
The present invention provides an earth boring bit having enhancements in
cutter
element placement and materials for optimizing borehole corner duty. Such
enhancements
provide the potential for increased bit durability, ROP and footage drilled
(at full gage) as
l s compared with similar bits of conventional technology.
According to the invention, the bit includes a bit body and one or more
rolling cone
cutters rotatably mounted on the bit body. The rolling cone cutter includes a
generally conical
surface, an adjacent heel surface and, preferably, a circumferential shoulder
therebetween. The
cone cutter also includes groups of first and second cutter elements that are
mounted in separate,
a o radially-spaced, circumferential rows.
The first cutter elements have cutting surfaces of a first nominal hardness
and are
positioned on the cone cutter such that their cutting surfaces cut along a
first cutting path having
a most radially distant point P~ as measured from the bit axis. The second
cutter elements have
cutting surfaces of a different nominal hardness and are positioned on the
cone cutter so that
2 s their cutting surfaces cut along a second cutting path having a most
radially distant point PZ as
measured from the bit axis. The first and second rows are positioned such that
the radial
distance from the bit axis to P, exceeds the radial distance from the bit axis
to PZ by a distance D
that is selected such that the first and second cutter elements cooperatively
cut the corner of the
borehole, and such that the first cutter elements primarily cut the borehole
sidewall and the
3 o second cutter elements primarily cut the borehole bottom.
The cutter elements may be hard metal inserts having cutting portions attached
to .
generally cylindrical base portions which are mounted in the cone cutter, or
may comprise steel
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teeth that are milled, cast, or otherwise integrally formed from the cone
material. The distance
D may be the same for all the cone cutters on the bit, or may differ among the
various cone
cutters in order to achieve a desired balance of durability and wear
characteristics for the cone
cutters.
s In one preferred embodiment, the first cutter elements are gage cutter
elements that cut
to full gage, while the second cutter elements are mounted in a first inner
row of off gage cutter
elements positioned so that their cutting surfaces are close to gage, but are
off=gage by the
distance D. In this embodiment, the gage row cutter elements may be mounted
along or near
the circumferential shoulder, either on the heel surface or on the adjacent
conical surface. In a
z o different embodiment of the invention, the cutting surfaces of both the
first and second cutter
elements are off gage, with the second cutter elements having cutting surfaces
that are filrther
off gage than the first cutter elements.
By dividing the borehole corner cutting duty among the rows of first and
second cutter
elements, the cutting surfaces of these elements may be optimized by use of
material
is enhancements to further improve bit ROP, durability and footage drilled at
full gage. The
materials for the cutting surfaces of the first and second cutter elements
will be varied and
optimized depending primarily upon the characteristics of the formation to be
drilled. In most
applications, the cutting surfaces of the first cutter elements will be harder
than those of the
second cutter elements due to the fact that the first cutter elements will be
exposed to more
z o sidewall cutting duty and thus will typically be subject to more wear and
abrasion than the
second cutter elements. Similarly, in most applications, the cutting surfaces
of the second cutter
elements will be tougher and more impact resistant than those of the first
cutter elements.
The hardness and toughness of the cutter elements that are in the rows that
cooperate to
cut the borehole corner may be varied by employing differing formulations of
cemented
2 s tungsten carbide, or by applying a coating of super abrasives (such as PCD
or PCBI~ having
the appropriate hardness, toughness and thermal stability for the particular
application. For
example, where the first cutter elements are gage row cutters and the desired
hardness is
obtainable without a coating of super abrasives, a preferred embodiment of the
invention
includes gage row inserts made from cemented tungsten carbide having a
hardness greater than
s o or equal to 88.8 HRa, and most preferably at least 90.8 HRa. In instances
where the second
cutter elements do not require a coating of super abrasives or where the
coating of super
abrasives would not withstand the impact loading of a particular formation or
drilling technique,
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a preferred embodiment of the invention includes off gage cutter elements of
cemented tungsten
carbide having a hardness not greater than 88.8 HRa, and preferably not
greater than 87.4 HRa.
A coating of PCD and PCBN or other super abrasive may be applied to vary the
hardness and toughness of the first and second cutter elements as required or
desirable for
various formations and drilling techniques. For example, where impact loading
is not
excessive, the invention includes cutter elements having a PCD coating having
an average grain
size not greater than 25 pm. Such PCD coatings have particular application in
gage row
elements. Where super abrasives are desired and feasible, but where increased
toughness is
required, such as in cutter elements experiencing significant degree of bottom
hole cutting, the
to invention includes cutter elements with a PCD coating having an average
grain size greater than
25 ~.m.
Thus, the present invention comprises a combination of features and advantages
which
enable it to substantially advance the drill bit art. By strategically placing
gage and near-gage
rows of cutter elements so that they cooperatively cut the borehole corner,
enhanced ROP, bit
durability and footage drilled at full gage may be achieved. In turn, this
placement of the cutter
elements permits the cutting function of a cutter element in each of the
different rows to be
enhanced further through the selective use of materials that are best suited
for the particular duty
the cutter element will experience. Such material enhancements provide
opportunity for still
greater improvement in cutter element life and thus bit durability and ROP
potential. These and
2 o various other characteristics and advantages of the present invention will
be readily apparent to
those skilled in the art upon reading the following detailed description of
the preferred
embodiments of the invention, and by refernng to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
For an introduction to the detailed description of the preferred embodiments
of the
invention, reference will now be made to the accompanying drawings, wherein:
Figure 1 is a perspective view of an earth-boring bit made in accordance with
the
principles of the present invention;
Figure 2 is a partial section view taken through one leg and one rolling cone
cutter of the
bit shown in Figure 1;
3 o Figure 3 is a perspective view of one cutter of the bit of Figure 1;
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Figure 4 is a enlarged view, partially in cross-section, of a portion of the
cutting
structure of the cutter shown in Figures 2 and 3, and showing the cutting
paths traced by certain
of the cutter elements mounted on that cutter;
Figure 5 is a view similar to Figure 4 showing an alternative embodiment of
the
s invention;
. Figure 6 is a partial cross sectional view of a set of prior art rolling
cone cutters (shown
in rotated profile) and the cutter elements attached thereto;
Figure 7 is an enlarged cross sectional view of a portion of the cutting
structure of the
prior art cutter shown in Figure 6 and showing the cutting paths traced by
certain of the cutter
1 o elements;
Figure 8 is a partial elevational view of a rolling cone cutter showing still
another
alternative embodiment of the invention;
Figure 9 is a cross sectional view of a portion of rolling cone cutter showing
another
alternative embodiment of the invention;
~.s Figure 10 is a perspective view of a steel tooth cutter showing an
alternative
embodiment of the present invention;
Figure I 1 is an enlarged cross-sectional view similar to Figure 4, showing a
portion of
the cutting structure of the steel tooth cutter shown in Figure i 0;
Figure 12 is a view similar to Figure 4 showing another alternative embodiment
of the
z o invention;
Figure 13 is a view similar to Figure 4 showing another alternative embodiment
of the
invention.
DETAIIIED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring first to Figure l, an earth-boring bit IO made in accordance with
the present
z s invention includes a central axis 1 l and a bit body 12 having a threaded
section 13 on its upper
end for securing the bit to the drill string (not shown). Bit 10 has a
predetermined gage
diameter as defined by three rolling cone cutters 14, 15, I6 rotatably mounted
on bearing shafts
that depend from the bit body I2. 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
3 o plurality of nozzles 18 that are provided for directing drilling fluid
toward the bottom of the
borehole and around cutters 14-16. Bit IO further includes lubricant
reservoirs I7 that supply
lubricant to the bearings of each of the cutters.
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Referring now to Figure 2, in conjunction with Figure 1, each cutter I4-I6 is
rotatably
mounted on a pin or journal 20, with an axis of rotation 22 orientated
generally downwardly and
inwardly toward the center of the bit. Drilling fluid is pumped from the
surface through fluid
passage 24 where it is circulated through an internal passageway (not shown)
to nozzles 18
s (Figure 1). Each cutter 14-I6 is typically secured on pin 20 by ball
bearings 26. In the
embodiment shown, radial and axial thrust are absorbed by roller bearings 28,
30, thrust washer
31 and thrust plug 32; however, the invention is not limited to use in a
roller bearing bit, but
may equally be applied in a friction bearing bit. In such instances, the cones
14, 15, 16 would
be mounted on pins 20 without roller bearings 28, 30. In both roller bearing
and friction bearing
lo bits, lubricant may be supplied from reservoir 17 to the bearings by
apparatus that is omitted
from the figures for clarity. The lubricant is sealed and drilling fluid
excluded by means of an
annular seal 34. The borehole created by bit 10 includes sidewall 5, corner
portion 6 and
bottom 7, best shown in Figure 2. Referring still to Figures l and 2, each
cutter 14-16 includes
a backface 40 and nose portion 42 spaced apart from backface 40. Cutters 14-16
further
1s include a frustoconical surface 44 that is adapted to retain cutter
elements that scrape or ream
the sidewalls of the borehole as cutters 14-16 rotate about the borehole
bottom. Frustoconical
surface 44 will be referred to herein as the "heel" surface of cutters 14-16,
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.
a o 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
the cone cutters
rotate about the borehole. Conical surface 46 typically includes a plurality
of generally
frustoconical segments 48 generally referred to as "lands" which are employed
to support and
secure the cutter elements as described in more detail below. Grooves 49 are
formed in cone
as surface 46 between adjacent lands 48. Frustoconical heel surface 44 and
conical surface 46
converge in a circurnferential 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
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.
s o In the embodiment of the invention shown in Figures 1 and 2, each cutter
1M16 includes
a plurality of wear resistant inserts 60, 70, 80 that include generally
cylindrical base portions
that are secured by interference fit into mating sockets drilled into the
lands of the cone cutter,
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and cutting portions that are connected to the base portions and that extend
beyond the surface
of the cone cutter. The cutting portion includes a cutting surface that
extends from cone
surfaces 44, 46 for cutting formation material. The present invention will be
understood with
reference to one such cutter 14, cones l S, 16 being similarly, although not
necessarily
s identically, configured.
. Cone cutter 14 includes a plurality of heel row inserts 60 that are secured
in a
circumferential row 60a in the fiustoconical heel surface 44. Cutter 14
further includes a
circumferential row 70a of gage inserts 70 secured to cutter 14 in locations
along or near the
circumferential shoulder 50. Cutter 14 further includes a plurality of inner
row inserts 80, 81,
so 82, 83 secured to cone surface 46 and arranged in spaced-apart inner rows
80a, 81a, 82a, 83a,
respectively. Relieved areas or Iands 78 (best shown in Figure 3) are formed
about gage cutter
elements 70 to assist in mounting inserts 70. As understood by those skilled
in this art, heel
inserts 60 generally function to scrape or ream the borehole sidewall S to
maintain the borehole
at full gage and prevent erosion and abrasion of heel surface 44. Cutter
elements 81, 82 and 83
15 Of inner rows 81a, 82a, 83a are employed primarily to gouge and remove
formation material
from the borehole bottom 7. Inner rows 80a, 81a, 82a, 83a are arranged and
spaced on cutter 14
so as not to interfere with the inner rows on each of the other cone cutters
15, 16.
As shown in Figures I-4, the preferred placement of gage cutter elements 70 is
a
position along circumferential shoulder 50. This mounting position enhances
bit 10's ability to
2 o divide corner cutter duty among inserts 70 and 80 as described more fully
below. This position
also enhances the drilling fluid's ability to clean the inserts and to wash
the formation chips and
cuttings past heel surface 44 towards the top of the borehole. Despite the
advantage provided
by placing gage cutter elements 70 along shoulder 50, many of the substantial
benefits of the
present invention may be achieved where gage inserts 70 are positioned
adjacent to
a s circumferential shoulder 50, on either conical surface 46 (Figure 9) or on
heel surface 44
(Figure 5) . For bits having gage cutter elements 70 positioned adjacent to
shoulder 50, the
precise distance of gage cutter elements 70 to shoulder 50 will generally vary
with bit size: the
larger the bit, the larger the distance can be between shoulder 50 and cutter
element 70 while
still providing the desired division of corner cutting duty between cutter
elements 70 and 80.
s o The benefits of the invention diminish, however, if gage cutter elements
are positioned too far
. from shoulder 50, particularly when placed on heel surface 44. The distance
between shoulder
SO to cutter elements 70 is measured from shoulder 50 to the nearest edge of
the gage cutter
9
CA 02228156 2005-06-27
element 70, the distance represented by "d" as shown in Figures 9 & 5. Thus,
as used herein to
describe the mounting position of cutter elements 70 relative to shoulder 50,
the term "adjacent"
shall mean on shoulder 50 or on either surface 46 or 44 within the ranges set
forth in the
following table:
Table 1
Distance from Shoulder
Bit Diameter Distance from Shoulder50
"BD" (inches) 50 Along Heel Surface
Along Surface 46 (inches)44
(inches)
BD <_ 7 .120 .060
7 < BD <_ 10 .180 .090
< BD <_ 15 .250 .130
BD > 15 .300 .150
The spacing between heel inserts 60, gage inserts 70 and inner row inserts 80-
83, is best
shown in Figure 2 which also depicts the borehole formed by bit 10 as it
progresses through the
formation material. Figure 2 also shows the cutting profiles of inserts 60,
70, 80 as viewed in
rotated profile, that is with the cutting profiles of the cutter elements
shown rotated into a single
plane. The rotated cutting profiles and cutting position of inner row inserts
81', 82', inserts that
are mounted and positioned on cones 15, 16 to cut formation material between
inserts 81, 82 of
cone cutter 14, are also shown in phantom. Gage inserts 70 are positioned such
that their cutting
surfaces cut to fixll gage diameter, while the cutting surfaces of off gage
inserts 80 are
strategically positioned off gage. Due to this positioning of the cutting
surfaces of gage inserts
70 and first inner row inserts 80 in relative close proximity, it can be seen
that gage inserts 70
cut primarily against sidewall 5 while inserts 80 cut primarily against the
borehole bottom 7.
The cutting paths taken by heel row inserts 60, gage row inserts 70 and the
first inner
row inserts 80 are shown in more detail in Figure 4. Referring to Figures 2
and 4, each cutter
element 60, 70, 80 will cut formation material as cone 14 is rotated about its
axis 22. As bit 10
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descends fiuther into the formation material, the cutting paths traced by
cutters 60, 70, 80 may
be depicted as a series of curves. In particular: heel row inserts 60 will cut
along curve 66;
gage row inserts 70 will cut along curve 76; and cutter elements 80 of first
inner row 80a will
cut along curve 86. As shown in Figure 4, curve 76 traced by gage insert 70
extends farther
s from the bit axis 1 I (Figure 2) than curve 86 traced by first inner row
cutter element 80. The
most radially distant point on curve 76 as measured from bit axis 11 is
identified as P,.
Likewise, the most radiaily distant point on curve 86 is denoted by PZ . As
curves 76, 86 show,
as bit IO progresses through the formation material to form the borehole, the
first inner row
cutter elements 80 do not extend radially as far into the formation as gage
inserts 70. Thus,
i o instead of extending to full gage, inserts 80 of first inner row 80a
extend to a position that is
"off gage" by a predetermined distance D, D being the difference in radial
distance between
points P, and P, as measured from bit axis 1 I.
As understood by those skilled in the art of designing bits, a "gage curve" is
commonly
employed as a design tool to ensure that a hit made in accordance to a
particular design will cut
15 the specified hole diameter. The gage curve is a complex mathematical
formulation which,
based upon the parameters of bit diameter, journal angle, and journal offset,
takes all the points
that will cut the specified hole size, as located in three dimensional space,
and projects these
points into a two dimensional plane which contains the journal centerline and
is parallel to the
bit axis. The use of the gage curve greatly simplifies the bit design process
as it allows the gage
s o cutting elements to be accurately located in two dimensional space which
is easier to visualize.
The gage curve, however, should not be confused with the cutting path of any
individual cutting
element as described previously.
A portion of gage curve 90 of bit 10 is depicted in Figure 4. As shown, the
cutting
surface of off gage cutter 80 is spaced radially inward from gage curve 90 by
distance D', D'
25 being the shortest distance between gage curve 90 and the cutting surface
of off gage cutter
element 80. Given the relationship between cutting paths 76, 86 described
above, in which the
outer most point P" Pz are separated by a radial distance D, D' will be equal
to D. Accordingly,
the first inner row of cutter elements 80 may be described as "off gage," both
with respect to the
gage curve 90 and with respect to the cutting path 76 of gage cutter elements
70. As known
a o to those skilled in the art, the American Petroleum Institute (API) sets
standard tolerances for bit
diameters, tolerances that vary depending on the size of the hit. The term
"off gage" as used
herein to describe inner row cutter elements 80 refers to the difference in
distance that cutter
1I
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elements 70 and 80 radially extend into the formation (as described above) and
not to whether
or not cutter elements 80 extend far enough to meet an API definition for
being on gage. That
is, for a given size bit made in accordance with the present invention, cutter
elements 80 of a
first inner row 80a may be "off gage" with respect to gage cutter elements 70,
but may still
s extend far enough into the formation such that cutter elements 80 of inner
row 80a would fall
within the API tolerances for being on gage for that given bit size.
Nevertheless, cutter
elements 80 would be "off gage" as that term is used herein because of their
relationship to the
cutting path taken by gage inserts 70. In more preferred embodiments of the
invention,
however, cutter elements 80 that are "off gage" {as herein defined) will also
fall outside the API
so tolerances for the given bit diameter.
Referring again to Figures 2 and 4, it is shown that cutter elements 70 and 80
cooperatively operate to cut the corner 6 of the borehole, while inner row
inserts 81, 82, 83
attack the borehole bottom. Meanwhile, heel row inserts 60 scrape or ream the
sidewalk of the
borehole, but perform no corner cutting duty because of the relatively large
distance that heel
row inserts 60 are separated from gage row inserts 70. Cutter elements 70 and
80 may be
referred to as primary cutting structures in that they work in unison or
concert to simultaneously
cut the borehole corner, cutter elements 70 and 80 each engaging the formation
material and
performing their intended cutting function immediately upon the initiation of
drilling by hit 10.
Cutter elements 70, 80 are thus to be distinguished from what are sometimes
referred to as
z o "secondary" cutting structures which engage formation material only after
other cutter elements
have become worn.
As previously mentioned, gage row cutter elements 70 may be positioned on heel
surface 44 according to the invention, such an arrangement being shown in
Figure 5 where the
cutting paths traced by cutter elements 60, 70, 80 are depicted as previously
described with
z s reference to Figure 4. Like the arrangement shown in Figure 4, the cutter
elements 80 extend to
a position that is off gage by a distance D, and the borehole corner cutting
duty is divided
among the gage cutter elements 70 and inner row cutter elements 80. Although
in this
embodiment gage row cutter elements 70 are located on the heel surface, heel
row inserts 60 are
still too far away to assist in the corner cutting duty.
s o Referring to Figures 6 and 7, a typical prior art bit 110 is shown to have
gage row inserts
100, heel row inserts 102 and inner row inserts 103, 104, 105. By contrast to
the present .
invention, such conventional bits have typically employed cone cutters having
a single row of
12
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WO 97/38205 PCT/US97/05948
cutter elements, positioned on gage, to cut the borehole corner. Gage inserts
100, as well as
inner row inserts 103-105 are generally mounted on the conical bottom surface
46, while heel
row inserts 102 are mounted on heel surface 44. In this arrangement, the gage
row inserts 100
are required to cut the borehole corner without any significant assistance
from any other cutter
s elements as best shown in Figure 7. This is because the first inner row
inserts I03 are mounted
a substantial distance from gage inserts 100 and thus are too far away to be
able to assist in
cutting the borehole corner. Likewise, heel inserts I02 are too distant from
gage cutter 100 to
assist in cutting the borehole corner. Accordingly, gage inserts 100
traditionally have had to cut
both the borehole sidewall 5 along cutting surface 106, as well as cut the
borehole bottom 7
lo along the cutting surface shown generally at 108. Because gage inserts 100
have typically been
required to perform both cutting functions, a compromise in the toughness,
wear resistance,
shape and other properties of gage inserts 100 has been required.
The failure anode of cutter elements usually manifests itself as either
breakage, wear, or
mechanical or thermal fatigue. Wear and thermal fatigue are typically results
of abrasion as the
m elements act against the formation material. Breakage, including chipping of
the cutter element,
typically results from impact loads, although thermal and mechanical fatigue
of the cutter
element can also initiate breakage.
Refernng still to Figure 6, breakage of prior art gage inserts 100 was not
uncommon
because of the compromise in toughness that had to be made in order for
inserts 100 to also
2 o withstand the sidewall cutting they were required to perform. Likewise,
prior art gage inserts
100 were sometimes subject to rapid wear and thermal fatigue due to the
compromise in wear
resistance that was made in order to allow the gage inserts 100 to
simultaneously withstand the
impact loading typically present in bottom hole cutting.
Referring again to Figures 1-4., it has been determined that positioning the
first inner
a s row cutter elements 80 much closer to gage than taught by the prior art,
but at the same time,
maintaining a minimum distance from gage to cutter element 80, substantial
improvements may
be achieved in ROP, bit durability, or both. To achieve these results, it is
important that the first
inner row of cutter elements 80 be positioned close enough to gage cutter
elements 70 such that
the corner cutting duty is divided to a substantial degree between gage
inserts 70 and inner row
3 o inserts 80. The distance D that inner row inserts 80 should be placed off
gage so as to allow the
advantages of this division to occur is dependent upon the bit offset, the
cutter element
placement and other factors, but rnay also be expressed in terms of bit
diameter as follows:
I3
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Table 2
Acceptable More Preferred Most Preferred
Bit Diameter Range for Range for Range for
"BD" Distance D Distance D Distance D
(inches) {inches) (inches) (inches)
BD _< 7 .015 - .I00 .020 - .080 .020 - .060
7 < BD _< 10 .020 - .150 .020 - .120 .030 - .090
< BD _< 15 .025 - .200 .035 - .I60 .045 - .120
BD > 15 .030 - .250 .050 - .200 .060 - .150
s If cutter elements 80 of the first inner row 80a are positioned too far from
gage, then
gage row 70 will be required to perform more bottom hole cutting than would be
preferred,
subjecting it to more impact loading than if it were protected by a closely-
positioned but off
gage cutter element 80. Similarly, if inner row cutter element 80 is
positioned too close to the
gage curve, then it would be subjected to loading similar to that experienced
by gage inserts 70,
Zo and would experience more side hole cutting and thus more abrasion and wear
than would be
otherwise preferred. Accordingly, to achieve the appropriate division of
cutting Load, a division
that will permit inserts 70 and 80 to be optimized in terms of shape,
orientation, extension and
materials to best withstand particular loads and penetrate particular
formations, the distance that
cutter element 80 is positioned off gage is important.
Referring again to Figure 6, conventional bits having a comparatively large
distance
between gage inserts 100 and frst inner row inserts 103 typically have
required that the cutter
include a relatively large number of gage inserts in order to maintain gage
and withstand the
abrasion and sidewall forces imposed on the bit. It is known that increased
ROP in many
formations is achieved by having relatively fewer cutter elements in a given
bottom hole cutting
s o row such that the force applied by the bit to the formation material is
more concentrated than if
the same force were to be divided among a larger number of cutter elements.
Thus, the prior art
14
CA 02228156 1998-O1-28
WO 97!38205 PCT/US97105948
bit was again a compromise because of the requirement that a substantial
number of gage inserts
100 be maintained on the bit in an effort to hold gage.
By contrast, and according to the present invention, because the sidewall and
bottom
hole cutting functions have been divided between gage inserts 70 and inner row
inserts 80, a
s more aggressive cutting structure may be employed by having a comparatively
fewer number of
first inner row cutter elements 80 as compared to the number of gage row
inserts 100 of the
prior art bit shown in Figure 6. In other words, because in the present
invention gage inserts 70
cut the sidewall of the borehole and are positioned and configured to maintain
a full gage
borehole, first inner row elements 80, that do not have to function to cut
sidewall or maintain
lo gage, may be fewer in number and may be further spaced so as to better
concentrate the forces
applied to the formation. Concentrating such forces tends to increase ROP in
certain
formations. Also, providing fewer cutter elements 80 on the first inner row
80a increases the
pitch between the cutter elements and the chordal penetration, chordai
penetration being the
maximum penetration of an insert into the formation before adjacent inserts in
the same row
15 contact the hole bottom. Increasing the chordai penetration allows the
cutter elements to
penetrate deeper into the formation, thus again tending to improve ROP.
Increasing the pitch
between inner row inserts 80 has the additional advantages that it provides
greater space
between the inserts which results in improved cleaning of the inserts and
enhances cutting
removal from hole bottom by the drilling fluid.
a o The present invention may also be employed to increase durability of bit
10 given that
inner row cutter elements 80 are positioned off gage where they are not
subjected to the load
from the sidewall that is instead assumed by the gage row inserts.
Accordingly, inner row
inserts 80 are not as susceptible to wear and thermal fatigue as they would be
if positioned on
gage. Further, compared to conventional gage row inserts 100 in bits such as
that shown in -
25 Figure 6, inner row inserts 80 of the present invention are called upon to
do substantially less
work in cutting the borehoie sidewall. The work performed by a cutter element
is proportional
to the force applied by the cutter element to the formation multiplied by the
distance that the
cutter element travels while in contact with the formation, such distance
generally referred to as
the cutter element's "strike distance." In the present invention in which gage
inserts 70 are
s o positioned on gage and inner row inserts 80 are off gage a predetermined
distance, the effective
or unassisted strike distance of inserts 80 is lessened due to the fact that
cutter elements 70 will
assist in cutting the borehole wall and thus will lessen the distance that
insert 80 must cut
IS
CA 02228156 1998-O1-28
WO 97/38205 PCTlUS97/05948
unassisted, This results in less wear, thermal fatigue and breakage for
inserts 80 relative to that
experienced by conventional gage inserts 100 under the same conditions. The
distance referred
to as the "unassisted strike distance" is identified in Figures 4 and S by the
reference "USD." As
will be understood by those skilled in the art, the further that inner row
cutter elements 80 are
s off gage, the shorter the unassisted strike distance is for cutter elements
80. In other words, by
increasing the off gage distance D, cutter elements 80 are required to do less
work against the
borehole sidewall, such work instead being performed by gage row inserts 70.
This can be
confirmed by comparing the relatively long unassisted strike distance USD for
gage inserts 100
in the prior art bit of Figure 7 to the unassisted strike distance USD of the
present invention
s o {Figures 4 and 5 for example).
Referring again to Figure 1, it is generally preferred that gage row cutter
elements 70 be
circumferentially positioned at locations between each of the inner row
elements 80. With first
inner row cutter elements 80 moved off gage where they are not responsible for
substantial
sidewall cutting, the pitch between inserts 80 may be increased as previously
described in order
i5 to increase ROP. Additionally, with increased spacing between adjacent
cutter elements 80 in
row 80a, two or more gage inserts 70 may be disposed between adjacent inserts
80 as shown in
Figure 8. This configuration further enhances the durability of bit 10 by
providing a greater
number of gage cutter elements 70 adjacent to circumferential shoulder 50.
An additional advantage of dividing the borehole cutting function between gage
inserts
z o 70 and off gage inserts 80 is the fact that it allows much smaller
diameter cutter elements to be
placed on gage than conventionally employed for a given size bit. With a
smaller diameter, a
greater number of inserts 70 may be placed around the cutter 14 to maintain
gage, and because
gage inserts 70 are not required to perform substantial bottom hole cutting,
the increase in
number of gage inserts 70 will not diminish or hinder ROP, but will only
enhance bit 10's
2 s ability to maintain full gage. At the same time, the invention allows
relatively large diameter or
large extension inserts to be employed as off gage inserts 80 as is desirable
for gouging and
breaking up formation on the hole bottom. Consequently, in preferred
embodiments of the
invention, the ratio of the diameter of gage inserts 70 to the diameter of
first inner row inserts 80
is preferably not greater than 0.75. Presently, a still more preferred ratio
of these diameters is
a o within the range of 0.5 to 0.725.
Also, given the relatively small diameter of gage inserts 70 (as compared both
to inner
row inserts 80 and to conventional gage inserts 100 as shown in Figure 6), the
invention
I6
CA 02228156 1998-O1-28
WO 97/38205 PCTIUS97/05948
preferably positions gage inserts 70 and inner row inserts 80 such that the
ratio of distance D
that inserts 80 are off gage to the diameter of gage insert 70 should be less
than 0.3, and even
more preferably less than 0.2. It is desirable in certain applications that
this ratio be within the
range of 0.05 to 0.15.
s Positioning inserts 70 and 80 in the manner previously described means that
the cutting
profiles of the inserts 70, 80, in many embodiments, will partially overlap
each other when
viewed in rotated profile as is best shown in Figures 4 or 9. Referring to
Figure 9, the extent of
overlap is a fiulction of the diameters of the inserts 70, 80, the off gage
distance D of insert 80,
and the inserts' orientation, shape and extension from cutter 14. As used
herein, the distance of
s o overlap 91 is defined as the distance between parallel planes P3 and P4
shown in Figure 9. Plane
P3 is a plane that is parallel to the axis 74 of gage insert 70 and that
passes through the point of
intersection between the cylindrical base portion of the inner row insert 80
and the land 78 of
gage insert 70. P4 is a plane that is parallel to P3 and that coincides with
the edge of the
cylindrical base portion of gage row insert 70 that is closest to bit axis as
shown in Figure 9.
i5 This definition also applies to the embodiment shown in Figure 4.
The greater the overlap between cutting profiles of cutter elements 70, 80
means that
inserts 70, 80 will share more of the corner cutting duties, while less
overlap means that the
gage inserts 70 will perform more sidewall cutting duty, while off gage
inserts 80 will perform
less sidewall cutting duty. Depending on the size and type of bit and the type
formation, the
2 o ratio of the distance of overlap to the diameter of the gage inserts 70 is
preferably greater than
0.40.
As those skilled in the art understand, the International Association of
Drilling
Contractors (IADC) has established a classification system for identifying
bits that are suited for
particular formations. According to this system, each bit presently falls
within a particular three
a s digit IADC classification, the first two digits of the classification
represef~ting, respectively,
formation "series" and formation "type." A "series" designation of the numbers
l through 3
designates steel tooth bits, while a "series" designation of 4 through 8
refers to tungsten carbide
insert bits. According to the present classification system, each series 4
through 8 is further
divided into four "types," designated as 1 through 4. TCI bits are currently
being designed for
a o use in significantly softer formations than when the current IADC
classification system was
established. Thus, as used herein, an IADC classification range of between "41-
62" should be
understood to mean bits having an IADC classification within series 4 (types 1-
4), series 5
17
CA 02228156 1998-O1-28
WO 97/38205 PCT/LTS97/05948
(types 1-4) or series 6 (type 1 or type 2) or within any later adopted IADC
classification that
describes TCI bits that are intended for use in formations softer than those
for which bits of
current series 6 (type 1 or 2) are intended.
In the present invention, because the cutting functions of cutter elements 70
and 80 have
s been substantially separated, it is generally desirable that cutter elements
80 extend further from
cone I4 than elements 70 (relative to cone axis 22). This is especially true
in bits designated to
drill in soft through some medium hard formations, such as in steel tooth bits
or in TCI insert
bits having the IADC formation classifications of between 4I-62. This
difference in extensions
may be described as a step distance 92, the "step distance" being the distance
between planes PS
lo and P6 measured perpendicularly to cone axis 22 as shown in Figure 9. Plane
PS is a plane that
is parallel to cone axis 22 and that intersects the radially outermost point
on the cutting surface
of cutter element 70. Plane P6 is a plane that is parallel to cone axis 22 and
that intersects the
radially outermost point on the cutting surface of cutter element 80.
According to certain
preferred embodiments of the invention, the ratio of the step distance to the
extension of gage
Zs row cutter elements 70 above cone 14 should be not less than 0.8 for steel
tooth bits and for TCI
formation insert bits having IADC classification range of between 41-62. More
preferably, this
ratio should be greater than iØ
As mentioned previously, it is preferred that first inner row cutter elements
80 be
mounted off gage within the ranges specified in Table 2. In a preferred
embodiment of the
z o invention, the off gage distance D will be selected to be the same for all
the cone cutters on the
bit. This is a departure from prior art mufti-cone bits which generally have
required that the off
gage distance of the first inner row of cutter elements be different for some
of the cone cutters
on the bit. In the present invention, where D is the same for all the cone
cutters on the bit, the
number of gage cutter elements 70 may be the same for each cone cutter and,
simultaneously,
2s all the cone cutters may have the same number of off gage cutter elements
80. In other
embodiments of the invention, as shown in Figure l, there are advantages to
varying the
distance that inner row cutter elements 80 are off gage between the various
cones 14-I6. For
example, in one embodiment of the invention, cutter elements 80 on cutter I4
are disposed
0.040 inches off gage, while cutter elements 80 on cones 15 and 16 are
positioned 0.060 inches
3 0 off gage.
Varying among the cone cutters 14-16 the distance D that first inner row
cutter elements
80 are off gage allows a balancing of durability and wear characteristics for
all the cones on the
I8
CA 02228156 1998-O1-28
WO 97/38205 PCT/US97/05948
bit. More specifically, it is typically desirable to build a rolling cone bit
in which the number of
gage row and inner row inserts vary from cone to cone. In such instances, the
cone having the
fewest cutter elements cutting the sidewall or borehole corner will experience
higher wear or
impact loading compared to the other rolling cones which include a larger
number of cutter
s elements. If the off gage distance D was constant for all the cones on the
bit, there would be no
means to prevent the cutter elements on the cone having the fewest cutter
elements from
wearing or breaking prematurely relative to those on the other cones. On the
other hand, if the
first inner row of off gage cutter elements 80 on the cone having the fewest
cutter elements was
experiencing premature wear or breakage from sidewall impact relative to the
other cones on the
to bit, improved overall bit durability could be achieved by increasing the
off gage distance D of
cutter elements 80 on that cone so as to lessen the sidewall cutting performed
by that cone's
elements 80. Conversely, if the gage row inserts 70 on the cone having the
fewest cutter
elements were to experience excessive wear or impact damage, improved overall
bit durability
could be obtained by reducing the off gage distance D of off gage cutter
elements 80 on that
Zs cone so as to increase the sidewall cutting duty performed by the cone's
off gage cutter elements
80.
By dividing the borehole corner cutting duty between gage cutter elements 70
and first
inner row cutter elements 80, further and significant additional enhancements
in bit durability
and ROP are made possible. Specifically, the materials that are used to form
elements 70, 80
2 o can be optimized to correspond to the demands of the particular
application for which each
element is intended. In addition, the elements can be selectively and
variously coated with
super abrasives, including polycrystalline diamond ("PCD") or cubic boron
nitride {"PCBN") to
further optimize their performance. These enhancements allow cutter elements
70, 80 to
withstand particular loads and penetrate particular formations better than
would be possible if
25 the materials were not optimized as contemplated by this invention. Further
material
optimization is in turn made possible by the division of corner cutting duty.
The gage cutter element of a conventional bit is subjected to high wear loads
from the
contact with borehole wall, as well as high stresses due to bending and impact
loads from
contact with the borehole bottom. The high wear load can cause thermal
fatigue, which initiates
s o surface cracks on the cutter element. These cracks are filrther propagated
by a mechanical
fatigue mechanism that is caused by the cyclical bending stresses and/or
impact loads applied to
19
CA 02228156 1998-O1-28
WO 97/38205 PCT1US97J05948
the cutter element. These result in chipping and, more severely, in
catastrophic cutter element
breakage and failure.
The gage cutter elements 70 of the present invention are subjected to high
wear loads,
but are subjected to relatively low stress and impact loads, as their primary
function consists of
s scraping or reaming the borehole wall. Even if thermal fatigue should occur,
the potential of
mechanically propagating these cracks and causing failure of a gage cutter
element 70 is much ,
lower compared to conventional bit designs. Therefore, the present gage cutter
element exhibits
greater ability to retain its original geometry, thus improving the ROP
potential and durability
of the bit.
z o As explained in more detail below, the invention thus includes using a
different grade of
hard metal, such as cemented tungsten carbide, for gage cutter elements 70
than that used for
first inner row cutter elements 80. Additionally, the use of super abrasive
coatings that differ in
abrasive resistance and toughness, alone or in combination with hard metals,
yields
improvements in bit durability and penetration rates. Specific grades of
cemented tungsten
s5 carbide and PCD or PCBN coatings can be selected depending primarily upon
the
characteristics of the formation and operational drilling practices to be
encountered by bit 10.
Cemented tungsten carbide inserts formed of particular formulations of
tungsten carbide
and a cobalt binder (WC-Co) are successfully used in rock drilling and earth
cutting
applications. This material's toughness and high wear resistance are the two
properties that
a o make it ideally suited for the successful application as a cutting
structure material. Wear
resistance can be determined by several ASTM standard test methods. It has
been found that the
ASTM B611 test correlates well with field performance in terms of relative
insert wear life. It
has further been found that the ASTM 8771 test, which measures the fracture
toughness (K1c)
of cemented tungsten carbide material, correlates well with the insert
breakage resistance in the
2 s field.
It is commonly known in the cemented tungsten carbide industry that the
precise WC-
Co composition can be varied to achieve a desired hardness and toughness.
Usually, a carbide
material with higher hardness indicates higher resistance to wear and also
lower toughness or
lower resistance to fracture. A carbide with higher fracture toughness
normally has lower
3 o relative hardness and therefore lower resistance to wear. Therefore there
is a trade-off in the
material properties and grade selection. The most important consideration for
bit design is to
CA 02228156 1998-O1-28
WO 97/38205 ~'CT/CTS97/05948
select the best grade for its application based on the formation material that
is expected to be
encountered and the operational drilling practices to be employed.
As understood by those skilled in the art, the wear resistance of a particular
cemented
tungsten carbide cobalt binder formulation (WC-Co) is dependent upon the grain
size of the
s tungsten carbide, as well as the percent, by weight, of cobalt that is mixed
with the tungsten
carbide. Although cobalt is the preferred binder metal, other binder metals,
such as nickel and
iron can be used advantageously. In general, for a particular weight percent
of cobalt, the
smaller the grain size of the tungsten carbide, the more wear resistant the
material will be.
Likewise, for a given grain size, the lower the weight percent of cobalt, the
more wear resistant
lo the material will be. Wear resistance is not the only design criteria for
cutter elements 70, 80,
however. Another trait critical to the usefulness of a cutter element is its
fracture toughness, or
ability to withstand impact loading. In contrast to wear resistance, the
fracture toughness of the
material is increased with larger grain size tungsten carbide and greater
percent weight of cobalt.
Thus, fracture toughness and wear resistance tend to be inversely related, as
grain size changes
15 that increase the wear resistance of a specimen will decrease its fracture
toughness, and vice
versa.
Due to irregular grain shapes, grain size variations and grain size
distribution within a
single grade of cemented tungsten carbide, the average grain size of a
particular specimen can
be subject to interpretation. Because for a fixed weight percent of cobalt the
hardness of a
a o specimen is inversely related to grain size, the specimen can be
adequately defined in terms of
its hardness and weight percent cobalt, without reference to its grain size.
Therefore, in order to
avoid potential confusion arising out of generally Iess precise measurements
of grain size,
specimens will hereinafter be defined in terms of hardness (measured in
hardness Rockwell A
(HRa)) and weight percent cobalt.
2 s As used herein to compare or claim physical characteristics (such as wear
resistance or
hardness) of different cutter element materials, the term "differs" means that
the value or
magnitude of the characteristic being compared varies by an amount that is
greater than that
resulting from accepted variances or tolerances normally associated with the
manufacturing
processes that are used to formulate the raw materials and to process and form
those materials
s o into a cutter element. Thus, materials selected so as to have the same
nominal hardness or the
same nominal wear resistance will not "differ," as that term has thus been
defined, even though
various samples of the material, if measured, would vary about the nominal
value by a small
21
CA 02228156 1998-O1-28
WO 97!38205 PCT/US97/05948
amount. By contrast, each of the grades of cemented tungsten carbide and PCD
identified in the
Tables herein "differs" from each of the others in terms of hardness, wear
resistance and fracture
toughness.
There are today a number of commercially available cemented tungsten carbide
grades
s that have differing, but in some cases overlapping, degrees of hardness,
wear resistance,
compressive strength and fracture toughness. One of the hardest and most wear
resistant of
these grades presently used in softer formation petroleum bits is a finer
grained tungsten carbide
grade having a nominal hardness of 90-9I I-iRa and a cobalt content of 6% by
weight.
Although wear resistance is an important quality for use in cutter elements,
this carbide grade
lo unfortunately has relatively low toughness or ability to withstand impact
loads as is required for
cutting the borehole bottom. Consequently, and refernng momentarily to Figure
6, in many
prior art petroleum bits, cutter elements formed of this tungsten carbide
grade have been limited
to use as heel row inserts 102. Inner rows 103-105 of petroleum bits intended
for use in softer
formations have conventionally been formed of coarser grained tungsten carbide
grades having
Zs nominal hardnesses in the range of 85.8-86.4 HRa, with cobalt contents of
I4-16 percent by
weight because of this material's ability to withstand impact Loading. This
formulation was
employed despite the fact that this material has a relatively low wear
resistance and despite the
fact that, even in bottom hole cutting, significant weax can be experienced by
inner row cutter
elements 103-105 of conventional bits in particular formations.
2 o As will be recognized, the choice of materials for prior art gage inserts
100 (Figure 6)
was a compromise.. Although gage inserts 100 experienced both significant side
wall and
bottom hole cutting duty, they could not be made as wear resistant as
desirable for side wall
cutting, nor as tough as desired for bottom hole cutting. Making the gage
insert more wear
resistant caused the insert to be less able to withstand the impact loading.
Likewise, making the.
2~ insert 100 tougher so as to enable it to withstand greater impact loading
caused the insert to be
less wear resistant. Because the choice of material for conventional gage
inserts 100 was a
compromise, the prior art softer formation petroleum bits typically employed a
medium grained
cemented tungsten carbide having nominal hardness around 88.1-88.8 HRa with
cobalt contents
of 10-11% by weight.
3 o The following table reflects the wear resistance and other mechanical
properties of
various commercially-available cemented tungsten carbide compositions:
22
CA 02228156 1998-O1-28
WO 97/38205 PCT/US97/05948
Table 3: Properties of Typical Cemented Tungsten Carbide Insert Grades Used in
OiI/Gas DriIlling
Cobalt Nominal Nominal FractureNominal Wear
content Hardness Toughness Klc Resistance per
[wt, %] [HRa] per ASTM test ASTM test
B771 [ksi~in] B611 [1000 rev/cc]
6 90.8 10.8 10.0
1 I 89.4 11.0 6. I
I1 88.8 12.5 4.1
88.1 13.2 3.8
12 87.4 14.1 3.2
16 87.3 13.7 2.6
14 86.4 16.8 2.0
16 85.8 17.0 1.9
Refernng again to Figures 1-4, according to the present invention, it is
desirable to form
s gage cutter elements 70 from a very wear resistant carbide grade for most
formations.
Preferably gage cutter elements 70 should be formed from a finer grained
tungsten carbide
grade having a nominal hardness in the range of approximately 88.1-90.8 HRa,
with a cobalt
content in the range of about 6-1 l percent by weight. Suitable tungsten
carbide grades include
those having the following compositions:
23
CA 02228156 1998-O1-28
WO 97/38205 PCT/US97/fl5948
Table 4: Properties of Grades of Cemented Tungsten Carbide Presently Preferred
for
Gage
Cotter Element 70 for OiUGas Drilling
Cobalt content Nominal Nominal Fracture Nominal Wear
[wt. %] Hardness Toughness Klc Resistance
[HRa] per ASTM test per ASTM test
B771 [ksi~in] B611 [ 1000 rev/cc]
6 90.8 10.8 10.0
11 89.4 11.0 6.1
11 88.8 12.5 4.1
88.1 I3.2 3.8
5
The tungsten carbide grades are listed from top to bottom in Table 4 above in
order of
decreasing wear resistance, but increasing fracture toughness.
In general, a harder grade of tungsten carbide with a lower cobalt content is
less prone to
thermal fatigue. The division of cutting duties provided by the present
invention allows use of a
1 o gage cutter element 70 that is a harder and more thermally stable than is
possible in prior art bit
designs, which in turn improves the durability and ROP potential of the bit.
In contrast, for first inner row of cutter elements 80, which must withstand
the bending
moments and impact loading inherent in bottom hole drilling, it is preferred
that a tougher and
more impact resistant material be used, such as the tungsten carbide grades
shown in the
following table:
24
CA 02228156 1998-O1-28
WO 97/38205 PCT/LJS97/05948
Table S: Properties of Grades of Cemented Tungsten Carbide Presently Preferred
for
Off Gage Cutter Element 80 for OiUGas Drilling
Cobalt Nominal Nominal FractureNominal Wear
content Hardness Toughness Klc Resistance
[wt. %] [Hra] per ASTM test per ASTM test
B771 [ksi~in] B611 [1000 rev/cc]
11 88.8 12.5 4.1
88.1 13.2 3.8
12 87.4 14.1 3.2
16 87.3 13.7 2.6
14 86.4 I6.8 2.0
16 85.8 17.0 1.9
s With one exception, the tungsten carbide grades identified from top to
bottom in Table S
increase in fracture toughness and decrease in wear resistance {the grade
having 12% cobalt and
a nominal hardness of 87.4 HRa being tougher than the grade having 16% cobalt
and a hardness
of 87.3 HRa). Although an overlap exists in grades for gage and off gage use,
the off gage
cutter elements 80 will, in most all instances, be made of a tungsten carbide
grade having a
i o hardness that is less than that the gage cutter element 70. In most
applications, cutter elements
80 will be of a material that is less wear resistant and more impact
resistant. The relative
difference in hardness between gage and off gage cutter elements is dependent
upon the
application. For harder formation bit types, the relative difference is less,
and conversely, the
difference becomes larger for soft formation bits.
It wiii be understood that the present invention is not limited by the
cemented tungsten .
carbide grades identified in Tables 3-5 above. Typically in mining
applications, it is preferred
to use harder grades, especially on inner rows. Also, the invention
contemplates using harder,
more wear resistant and/or tougher grades such as microgram and nanograin
tungsten carbide
composites as they are technically developed.
a o According to one preferred embodiment of the invention, gage inserts 70
will be formed
of a cemented tungsten carbide grade having a nominal hardness of 90.8 HRa and
a cobalt
CA 02228156 1998-O1-28
WO 97/38205 PCT/US97/OS948
content of 6% by weight and thus will have the wear resistance that previously
was used in heel
inserts 102 of the prior art (Figure 6). At the same time, the closely spaced
but off gage inserts
80 will be formed of a tungsten carbide grade having a nominal hardness of
86.4 HRa and a
cobalt content of 14% by weight, this grade having the impact resistance
conventionally
s employed on inner rows 103-105 in prior art bits (Figure 6). By optimizing
the fracture
toughness of inserts 80 for the particular formation to be drilled as
contemplated by this
invention, inserts 80 may have longer extensions or more aggressive cutting
shapes, or both, so
as to increase the ROP potential of the bit. Furthermore, by making first
inner row cutter
elements 80 from a tougher material than has been conventionally used for gage
row cutter
lo elements, the number of cutter elements 80 can be decreased and the pitch
or distance between
adjacent cutter elements 80 can be increased (relative to the distance between
adjacent prior art
gage inserts 100 of Figure 6). This can lead to improvements in ROP, as
described previously.
The longest strike distance on the borehole wall for the gage cutter inserts
70 occurs in Iarge
diameter, soft formation bit types with Iarge offset. For those bits, a hard
and wear-resistant
m tungsten carbide grade for the gage inserts 70 is important, particularly in
abrasive formations.
In addition, due to the increased gage durability, resulting from the above-
described
cutter element placement geometry and material optimization, the range of
applications in
which a bit of the present invention can be used is expanded. Since both ROP
and bit durability
are improved, it becomes economical to use the same bit type over a wider
range of formations.
z o A bit made in accordance to the present invention can be particularly
designed to have
sufficient strength/durability to enable it to drill harder or more abrasive
sections of the
borehole, and also to drill with competitive ROP in sections of the borehole
where softer
formations are encountered.
According to the present invention, substantial improvements in bit life and
the ability
zs of the bit to drill a full gage borehole are also afforded by employing
cutter elements 70, 80
having coatings comprising differing grades of super abrasives. Such super
abrasives may be,
for example, PCD or PCBN coatings applied to the cutting surfaces of
preselected cutter
elements 70, 80. All cutter elements in a given row may not be required to
have a coating of
super abrasive. In many instances, the desired improvements in wear
resistance, bit life and
3 o durability may be achieved where only every other insert in the row, for
example, includes the
coating.
26
1030-07106
CA 02228156 2005-06-02
Super abrasives are significantly harder than cemented tungsten carbide.
Because of this
substantial difference, the hardness of super abrasives is not usually
expressed in terms of
Rockwell A (HRa). As used herein, the term "super abrasive" means a material
having a
hardness of at least 2,700 Knoop (kg/mmZ). PCD grades have a hardness range of
about 5,000-
8,000 Knoop (kg/mm2) while PCBN grades have hardnesses which fall within the
range of
about 2,700-3,500 Knoop (kg/mmz). By way of comparison, the hardest grade of
cemented
tungsten carbide identified in Tables 3-5 has a hardness of about 1475 Knoop
(kg/mmz).
Certain methods of manufacturing cutter elements 70, 80 with PDC or PCBN
coatings
are well known. Examples of these methods are described, for example, in U.S.
Patent
to Numbers 4,604,106, 4,629,373, 4,694,918 and 4,811,801. Cutter elements with
coatings of
such super abrasives are commercially available from a number of suppliers
including, for
example, Smith Sii Megadiamond, Inc., General Electric Company, DeBeers
Industrial
Diamond Division, or Dennis Tool Company. Additional methods of applying super
abrasive
coatings also may be employed, such as the methods described in the co-pending
U.S. patent
i5 application titled "Method for Forming a Polycrystalline Layer of Ultra
Hard Material," Serial
No. 08/568,276, filed December 6, 1995 and assigned to the assignee of the
present invention,
now U.S. Patent No. 5,766, 294.
Typical PCD coated inserts of conventional bit designs are about 10 to 1000
times more
wear resistant than cemented tungsten carbide depending, in part, on the test
methods employed
2 o in making the comparison. The use of PCD coatings on inserts has, in some
applications,
significantly increased the ability of a bit to maintain full gage, and
therefore has increased the
useful service life of the bit. However, some limitations exist. Typical
failure modes of PCD
coated inserts of conventional designs are chipping and spalling of the
diamond coating. These
failure modes are primarily a result of cyclical loading, or what is
characterized as a fatigue
a s mechanism.
The fatigue life, or load cycles until failure, of a brittle material like a
PCD coating is
dependent on the magnitude of the load. The greater the load, the fewer cycles
to failure.
Conversely, if the load is decreased, the PCD coating will be able to
withstand more load cycles
before failure will occur.
3 o Since the gage and off gage insets 70, 80 of the present invention
cooperatively cut the
corner of the borehole, the loads (wear, frictional heat and impact) from the
cutting action is
27
1030-07106
CA 02228156 2005-06-02
shared between the gage and off gage inserts. Therefore, the magnitude of the
resultant load
applied to the individual inserts is significantly less than the load that
would otherwise be
applied to a conventional gage insert such as insert I00 of the bit of Figure
6 which alone was
required to perform the comer cutting duty. Since the magnitude of the
resultant force is
s reduced on cutter elements 70, 80 in the present invention, the fatigue
life, or cycles to failure of
the PCD coated inserts is increased. This is an important performance
improvement of the
present invention resulting in improved durability of the gage (a more durable
gage gives better
ROP potential, maintains directional responsiveness during directional
drilling, allows longer
bearing life, etc.) and an increase in the useful service life of the bit.
Also, it expands the
1 o application window of the bit to drill harder rock which previously could
not be economically
drilled due to limited fatigue life of the PCD on conventional gage row
inserts. When
employing super abrasive coatings on inserts 70, 80 of the invention, it is
preferred that the
super abrasive be applied over the entire cutting portion of the insert. That
is, the entire surface
of the insert that extends beyond the cylindrical case portion is preferably
coated. By covering
15 the entire cutting portion of the insert, the super abrasive coating is
more resistant to chipping or
impact damage than if only a portion of the cutting surface were coated. The
term "fully
capped" as used herein means an insert whose entire cutting portion is coated
with super
abrasive.
Employing PCD coated inserts in the gage row 70a, or in the first inner row
80a, or both,
z o has additional significant benefits over conventional bit designs,
benefits arising from the
superior wear resistance and thermal conductivity of PCD relative to tungsten
carbide. PCD has
about 5.4 times better thermal conductivity than tungsten carbide. Therefore,
PCD conducts the
frictional heat away from the cutting surfaces of cutter elements 70, 80 more
efficiently than
tungsten carbide, and thus helps prevent thermal fatigue or thermal
degradation.
25 PCD starts degrading around 700°C. PCBN is thermally stable up to
about 1300°C. In
applications with extreme frictional heat from the cutting action, or/and in
applications with
high formation temperatures, such as drilling for geothermal resources, using
PCBN coatings on
the gage row cutter elements 70 in a bit 10 of the present invention could
perform better than
PCD coatings.
3 o The strength of PCD is primarily a function of diamond grain size
distribution and
diamond to diamond bonding. Depending upon the average size of the diamond
grains, the
range of grain sizes, and the distribution of the various grain sizes
employed, the diamond
28
1030-07106
CA 02228156 2005-06-02
coatings may be made so as to have differing functional properties. A PCD
grade with
optimized wear resistance will have a different diamond grain size
distribution than a grade
optimized for increased toughness.
The following table shows three categories of diamond coatings presently
available from
s Smith Sii MegaDiamond Inc.
Table 6
Average Rank Wear Rank Rank
Designation Diamond GrainResistance*Strength Thermal
or
Size Range Toughness*Stability*
(~,m)
D4 <4 1 3 3
D 10 4-25 2 2 2
D30 >25 3 1 1
i o * A ranking of "1" being highest and "3" the lowest.
In abrasive formations, and particularly in medium and medium to hard abrasive
formations, bit 10 of the present invention may include gage inserts 70 having
a cutting surface
with a coating of super abrasives. For example, all or a selected number of
gage inserts 70 may
i s be coated with a high wear resistant PCD grade having an average grain
size range of less than 4
~,m. Alternatively, depending upon the application, the PCD grade may be
optimized for
toughness, having an average grain size range of larger than 25 ~,m. These
coatings will enable
the preselected gage insert 70 to withstand abrasion better than a tungsten
carbide insert that
does not include the super abrasive coating, and will permit the cutting
structure of bit 10 to
z o retain its original geometry longer and thus prevent reduced ROP and
possibly a premature or
unnecessary trip of the drill string. Given that gage inserts 70 having such
coating will be
slower to wear, off gage inserts 80 will be better protected from the sidewall
loading that would
29
1030-07106
CA 02228156 2005-06-02
otherwise be applied to them if gage inserts 70 were to wear prematurely.
Furthermore, with
super abrasive coating on inserts 70, off gage inserts 80 may be made with
longer extensions or
with more aggressive cutting shapes, or both (leading to increased ROP
potential) than would be
possible if off gage inserts 80 had to be configured to be able to bear
sidewall cutting duty after
gage inserts 70 (without a super abrasive coating) wore due to abrasion and
erosion.
In some soft or soft to medium hard abrasive formations, such as silts and
sandstones, or
in formations that create high thermal loads, such as claystones and
limestones, conventional
gage inserts 100 (Figure 6) of cemented tungsten carbide have typically
suffered from thermal
fatigue, which has lead to subsequent gage insert breakage. According to the
present invention,
1 o it is desirable in such formations to include a super abrasive coating on
certain or all of the off
gage inserts 80 of bit 10 to resist abrasion, to maintain ROP, and to increase
bit life. However,
because first inner row inserts 80 in this configuration must be able to
withstand some impact
loading, the most wear resistant super abrasive material is generally not
suitable, the application
instead requiring a compromise in wear resistance and toughness. A suitable
diamond coating
for off gage insert 80 in such an application would have relatively high
toughness and relatively
lower wear resistance and be made of a diamond grade with average grain size
range larger than
~,m. Gage insert 70 in this example could be manufactured without a super
abrasive coating,
and preferably would be made of a finer grained cemented tungsten carbide
grade having a
nominal hardness of 90.8 HRa and a cobalt content of 6% by weight. Gage
inserts 70 of such a
a o grade of tungsten carbide exhibit 2.5 times the nominal resistance and
have significantly better
thermal stability than inserts formed of a grade having a nominal hardness
88.8 HRa and cobalt
content of about 11 %, a typical grade for conventional gage inserts 100 such
as shown in Figure
6. Where gage inserts 70 are mounted between inserts 80 along circumferential
shoulder 50 in
the configuration shown in Figures 1-4, inserts 70 of this example are
believed capable of
2 s resisting wear and thermal loading in these formations even without a
super abrasives coating.
Also, applying a PCD or PCBN coating on gage inserts 70 may be undesirable in
bits employed
when drilling high inclination wells with steerable drilling systems due to
potentially severe
impact loads experienced by the gage inserts 70 as the drill string is rotated
within the well
casing -- loading that would not be exposed by the more protected inner row
off gage cutter
3 o elements 80.
The present invention also contemplates constructing bit 10 with preselected
gage
inserts 70 and off gage inserts 80 each having coatings of super abrasive
material. In certain
1030-07106
CA 02228156 2005-06-02
extremely hard and abrasive formations, both gage inserts 70 and off gage
inserts 80 may
include the same grade of PCD coating. For example, in such formations, the
preselected
inserts 70, 80 may include extremely wear resistant coatings such as a PCD
grade having an
average grain size range of less than 4 ~,m. In other formations that tend to
cause high thermal
s loading on the inserts, such as soft and medium soft abrasive formations
like silt, sandstone,
limestone and shale, a coating of super abrasive material having high thermal
stability is
important. Accordingly, in such formations, it may be desirable to include
coatings on inserts
70 and 80 that have greater thermal stability than the coating described
above, such as coatings
having an average grain size range of 4-25 ~,m.
to In drilling direction wells through abrasive formations having varying
compressive
strengths (nonhomogeneous abrasive formations), it may be desirable to include
super abrasive
coatings on both gage inserts 70 and off gage inserts 80. In such
applications, off gage inserts
80, for example, may be subjected to a more severe impact loading than gage
inserts 70. In this
instance, it would be desirable to include a tougher or more impact resistant
coating on off gage
15 insert 80 than on gage inserts 70. Accordingly, in such an application, it
would be appropriate
to employ a diamond coating on insert 80 having an average grain size range of
greater than 25
~,m, while gage insert 70 may employ more wear resistant, but not as tough
diamond coating,
such as one having an average grain size within the range of 4-25 ~,m or
smaller.
Optimization of cutter element materials in accordance with the present
invention is
2 o further illustrated by the Examples set forth below. The Examples are
illustrative, rather than
inclusive, of the various permutations that are considered to fall within the
scope of the present
invention.
Example 1
A rolling cone cutter such as cutter 14 shown in Figures 1-4 is provided with
both gage
2 s and off gage inserts 70, 80 consisting of uncoated tungsten carbide. The
gage inserts 70 have a
nominal hardness in the range of 88.8 to at least 90.8 HRa and cobalt content
in the range of
about 11 to about 6 weight percent, while the first inner row inserts 80 have
a nominal hardness
in the range of 85.8 to 88.8 HRa and cobalt content in the range of about 16
to about 10 weight
percent. Comparing the nominal wear resistances of a cemented tungsten carbide
grade having
3 o a nominal hardness of 89.4 HRa and one having a nominal hardness of 88.8
HRa as might be
employed in the gage row 70a and first inner row 80a, respectively, in the
above example, the
wear resistance of the gage elements 70 would exceed that of the off gage
element 80 by about
31
1030-07106
CA 02228156 2005-06-02
48%. A most preferred embodiment of this example, however has inserts 70 in
the gage row
70a with a nominal hardness of 90.8 HRa and cobalt content of about 6 percent
and inserts 80 in
the off gage row 80a with a nominal hardness of 87.4 HRa and cobalt content of
about 12
percent, such that gage inserts 70 are more than three times as wear resistant
as off gage inserts
s 80, but where off gage inserts 80 are more than 30% tougher than gage
inserts 70.
Example 2
A rolling cone cutter such as cutter 14 as shown in Figures 1-4 is provided
with PCD-
coated gage inserts 70 and off gage inserts 80 consisting of uncoated tungsten
carbide. The
coating on the gage inserts 70 may be any suitable PCD coating, while the
inserts 80 in the off
io gage row 80a have a nominal hardness in the range of 85.8 to 88.8 HRa and
cobalt content in
the range of about 16 to about 10 weight percent. The most preferred
embodiment of this
example has inserts 80 in the off gage row with a nominal hardness of 87.4 to
88.1 HRa and
cobalt content in the range of about 12 to about 10 weight percent.
Example 3
15 A rolling cone cutter such as cutter 14 as shown in Figures 1-4 is provided
with PCD-
coated gage inserts 70 and off gage inserts 80. The coating on the gage
inserts 70 or off gage
inserts 80 may be any suitable PCD coating. In a preferred embodiment of this
example, the
coating on the gage inserts 70 is optimed for wear resistance and has an
average grain size range
of less than or equal to 25 ~.m. The PCD coating on the off gage inserts 80 is
optimized for
2 o toughness and preferably has an average grain size range of greater than
25 ~,m.
Example 4
A rolling cone cutter such as cutter 14 as shown in Figures 1- 4 is provided
with gage
inserts 70 of uncoated tungsten carbide and off gage inserts 80 coated with a
suitable PCD
coating. The gage inserts 70 have a nominal hardness in the range of 89.4 to
90.8 HRa and
a s cobalt content in the range of about 11 to about 6 weight percent. The
most preferred
embodiment of this example has gage inserts 70 with a nominal hardness of 90.8
HRa and
cobalt content about 6 percent and off gage inserts 80 having a coating
optimized for toughness
and preferably having an average grain size range of greater than 25 ~.m.
Although the invention has been described with reference to the currently-
preferred and
3 o commercially available grades or classifications tungsten carbide and PDC
coatings, it should be
understood that the substantial benefits provided by the invention may be
obtained using any of
a number of other classes or grades of carbide and PCD coatings. What is
important to the
32
1030-07106
CA 02228156 2005-06-02
invention is the ability to vary the wear resistance, thermal stability and
toughness of cutter
elements 70, 80 by employing carbide cutter elements and diamond coatings
having differing
compositions. Advantageously then, the principles of the present invention may
be applied
using even more wear resistant or tougher tungsten carbide PCD or PCBN
surfaces as they
become commercially available in the future.
Optimizing the placement and material combinations for gage inserts 70 and off
gage
inserts 80 allows the use of more aggressive cutting shapes in gage rows 70a
and off gage rows
80a leading to increased ROP potential. Specifically, it is advantageous to
employ chisel-
shaped cutter elements in one or both of gage row 70a and off gage row 80a.
Preferred chisel
1 o cutter shapes include those shown and described in U.S. Patent No.
5,172,777, 5,322,138 and
4,832,139. A chisel insert presently-preferred for use in bit 10 of the
present invention is shown
in Figure 13. As shown, both gage insert 170 and off gage insert 180 are
sculptured chisel
inserts having no non-tangential intersections of the cutting surfaces and
having an inclined
crest 190. The inserts 170, 180 are oriented such that the crests 190 are
substantially parallel to
i5 cone axis 22 and so that the end 191 of the crest that extends furthest
from cone axis 22 is
closest to the bit axis 11. Crest 190 of gage insert 170 extends to gage curve
90, while the insert
190 of insert 180 is off gage by a distance D previously described.
The cutting surfaces of these inserts 170, 180 may be formed different grades
of
cemented tungsten carbide or may have super abrasive coatings in various
combinations, all as
a o previously described above. In most instances, gage insert 170 will be
more wear-resistance
than off gage insert 180. Inserts 170, 180 having super abrasive coatings
should be fully
capped.
Example 5
A particularly desirable combination employing chisel inserts in rows 70a and
80a
a 5 include gage insert 170 having a PCD coating with an average grain size of
less than or equal to
25 ~.m and an off gage insert 180 of cemented tungsten carbide having a
nominal hardness of
88.1 HRa. Where greater wear-resistance is desired for gage row 80a, insert
180 shown in
Figure 13 may instead be coated with a PCD coating such as one having an
average grain size
greater than 25 ~.m. From the preceding description, it wi 1l be apparent to
those skilled in the
3 o art that a variety of other combinations of tungsten carbide grades and
super abrasive coatings
33
CA 02228156 1998-O1-28
WO 97/38205 PCTlLTS97/05948
be employed advantageously depending upon the particular formation being
drilled and drilling
application being applied.
The present invention may be employed in steel tooth bits as well as TCI bits
as will be
understood with reference to Figure 10 and 11. As shown, a steel tooth cone
130 is adapted for
s attachment to a bit body i2 in a like manner as previously described with
reference to cones 14-
16. When the invention is employed in a steel tooth bit, the bit would include
a plurality of
cutters such as rolling cone cutter 130. Cutter I30 includes a backface 40, a
generally conical
surface 46 and a heel surface 44 which is formed between conical surface 46
and backface 40,
alI as previously described with reference to the TCI bit shown in Figures 1-
4. Similarly, steel
l o tooth cutter 130 includes heel row inserts 60 embedded within heel surface
44, and gage row
cutter elements such as inserts 70 disposed adjacent to the circumferential
shoulder 50 as
previously defined. Although depicted as inserts, gage cutter elements 70 may
likewise be steel
teeth or some other type of cutter element. Relief 122 is formed in heel
surface 44 about each
insert 60. Similarly, relief 124 is formed about gage cutter elements 70,
relieved areas 122, 124
is being provided as lands for proper mounting and orientation of inserts 60,
70. In addition to
cutter elements 60, 70, steel tooth cutter 130 includes a plurality of first
inner row cutter
elements 120 generally formed as radially-extending teeth. Steel teeth 120
include an outer
layer or layers of wear resistant material 121 to improve durability of cutter
elements 120.
In conventional steel tooth bits, the first row of teeth are integrally formed
in the cone
2 o cutter so as to be "on gage." This placement requires that the teeth be
configured to cut the
borehole corner without any substantial assistance from any other cutter
elements, as was
required of gage insert 100 in the prior art TCI bit shown in Figure 6. By
contrast, in the present
invention, cutter elements 120 are off gage within the ranges specified in
Table 2 above so as to
form the first inner row of cutter elements 120a. In this configuration, best
shown in Figure 11,
2 s gage inserts 70 and first inner row cutter elements 120 cooperatively cut
the borehole corner
with gage inserts 70 primarily responsible for sidewall cutting and with steel
teeth cutter
elements 120 of the first inner row primarily cutting the borehole bottom. As
best shown in
Figure 11, as the steel tooth bit forms the borehole, gage inserts 70 cut
along path 76 having a
radially outermost point P,. Likewise, inner row cutter element 120 cuts along
the path
3 o represented by curve 126 having a radially outermost point PZ . As
described previously with
reference to Figure 4, the distance D that cutter elements 120 are "off gage"
is the difference in
radial distance between P, and P2. The distance that cutter elements 120 are
"off gage" may
34
1030-07106
CA 02228156 2005-06-02
likewise be understood as being the distance D' which is the minimum distance
between the
cutting surface of cutter element 120 and the gage curve 90 shown in Figure 1
l, D' being equal
to D.
Steel tooth cutters such as cutter 130 have particular application in
relatively soft
formation materials and are preferred over TCI bits in many applications.
Nevertheless, even in
relatively soft formations, in prior art bits in which the gage row cutters
consisted of steel teeth,
the substantial sidewall cutting that must be performed by such steel teeth
may cause the teeth to
wear to such a degree that the bit becomes undersized and cannot maintain
gage. Additionally,
because the formation material cut by even a steel tooth bit frequently
includes strata having
1 o various degrees of hardness and abrasiveness, providing a bit having
insert cutter elements 70
on gage between adjacent off gage steel teeth 120 as shown in Figures 10 and
11 provides a
division of corner cutting duty and permits the bit to withstand very abrasive
formations and to
prevent premature bit wear. Other benefits and advantages of the present
invention that were
previously described with reference to a TCI bit apply equally to steel tooth
bits, including the
advantages of employing materials of differing hardness and toughness for gage
inserts 70 and
off gage steel teeth 120. Optimization of cutter element materials in steel
tooth bits is further
described by the illustrative examples set forth below.
Example 6
A steel tooth bit having a cone cutter 130 such as shown in Figure 11 is
provided with
2o gage row inserts 70 of tungsten carbide with a nominal hardness within the
range of 88.1-90.8
HRa and cobalt content in the range of about 11 to about 6% by weight. Within
this range, it is
preferred that gage inserts 70 have a nominal hardness within the range of
89.4 to 90.8 HRa.
Off gage teeth 120 include an outer layer of conventional wear resistant
hardfacing material
such as tungsten carbide and metallic binder compositions to improve their
durability.
Example 7
A steel tooth bit having a cone cutter 130 such as shown in Figure 11 is
provided with
tungsten carbide gage row inserts 70 having a coating of super abrasives of
PCD or PCBN.
Where PCD is employed, the PCD has an average grain size that is not greater
than 25 ~.m. Off
gage steel teeth 120 include a layer of conventional hardfacing material.
3 o Although in the preferred embodiments described thus far, the cutting
surfaces of cutter
elements 70 extend to full gage diameter, many of the substantial benefits of
the present
invention can be achieved by employing a pair of closely spaced rows of cutter
elements that are
CA 02228156 1998-O1-28
WO 97/38205 PCTlUS97/05948
positioned to share the borehole corner cutting duty, but where the cutting
surfaces of the cutter
elements of each row are off gage. Such an embodiment is shown in Figure 12
where bit I0
includes a heel row of cutter elements 60 which have cutting surfaces that
extend to full gage
and that cut along curve 66 which includes a radially most distant point P, as
measured from bit
s axis 11. The bit 10 further includes a row of cutter elements 140 that have
cutting surfaces that
cut along curve 146 that includes a radially most distant point P2. Cutter
elements 140 are
positioned so that their cutting surfaces are off gage a distance D, from gage
curve 90, where D,
is also equal to the difference in the radial distance between point P, and Pz
as measured from
bit axis 11. As shown in Figure 12, bit 10 further includes a row of off gage
cutter elements
z o 1 SO that cut along curve 156 having radially most distant point P3. D2
(not shown in Figure 12
for clarity) is equal to the difference in radial distance between points Pz
and P3 as measured
from bit axis 11. In this embodiment, D, should be selected to be within the
range of distances
shown in Table 2 above. D, may be less than or equal to DZ, but preferably is
less than D2. So
positioned, cutter elements 140, 150 cooperatively cut the borehole corner,
with cutter elements
is 140 primarily cutting the borehole sidewali and cutter elements 150
primarily cutting the
borehole bottom. Heel cutter elements 60 serve to ream the borehole to foil
gage diameter by
removing the remaining uncut formation material from the borehole sidewall.
While various preferred embodiments of the invention have been shown and
described,
modifications thereof can be made by one skilled in the art without departing
from the spirit and
a o teachings of the invention. The embodiments described herein are exemplary
only, and are not
limiting. Many variations and modifications of the invention and apparatus
disclosed herein are
possible and are within the scope of the invention. Accordingly, the scope of
protection i$ not
limited by the description set out above, but is only limited by the claims
which follow, that
scope including all equivalents of the subject matter of the claims.
36
