U.S. patent number RE34,435 [Application Number 07/897,623] was granted by the patent office on 1993-11-09 for whirl resistant bit.
This patent grant is currently assigned to Amoco Corporation. Invention is credited to J. Ford Brett, Tommy M. Warren.
United States Patent |
RE34,435 |
Warren , et al. |
November 9, 1993 |
Whirl resistant bit
Abstract
A whirl resistant drill bit is disclosed for use in rotary
drilling. The drill bit includes a generally cylindrical bit body
with a plurality of cutting elements extending out from a lower end
surface. The cutter elements are grouped in sets such that a first
set of cutters are disposed at substantially an equal radius from a
center of the bit body to create a groove in the material being
drilled. A second set of cutters is connected to the lower end
surface with each cutter therein in overlapping radial relationship
with each other and extending a maximum distance from the lower end
surface less than that of the first set of cutters. At least one
cutter of the second set is in overlapping radial relationship with
at least one of the cutters within the first set of cutters. This
cutter arrangement causes the drill bit to cut grooves within the
formation material that tends to prevent destructive bit whirl.
Further, adjustments can be made to vary the back rake angle and
side rake angle to prevent bit whirl.
Inventors: |
Warren; Tommy M. (Coweta,
OK), Brett; J. Ford (Tulsa, OK) |
Assignee: |
Amoco Corporation (Chicago,
IL)
|
Family
ID: |
26989682 |
Appl.
No.: |
07/897,623 |
Filed: |
June 11, 1992 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
Reissue of: |
335398 |
Apr 10, 1989 |
04932484 |
Jun 12, 1990 |
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Current U.S.
Class: |
175/398; 175/403;
175/428; 175/431; 175/434 |
Current CPC
Class: |
E21B
10/43 (20130101) |
Current International
Class: |
E21B
10/00 (20060101); E21B 10/42 (20060101); E21B
010/26 (); E21B 010/46 (); E21B 010/48 () |
Field of
Search: |
;175/431,426,428,434,385,398,408,327,376,378,402-404,405.1,387 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
Hough, "The Effect of Back Rake Angle on the Performance of
Small-Diameter PCD Bits: ANOVA Tests", JERT, Dec. 1986, vol.
108/305..
|
Primary Examiner: Novosad; Stephen J.
Attorney, Agent or Firm: Gabala; James A. Kretchmer; Richard
A. Sroka; Frank J.
Claims
What is claimed is:
1. A drill bit for use in rotary drilling a borehole through a
material and adapted for interconnection to a source of rotary
motion comprising:
a generally cylindrical bit body having a lower end surface;
a plurality of cutting elements extending outward from the lower
end surface including:
at least one first set of cutters disposed at substantially an
equal radius from a central axis of the bit body to create a groove
in the material, the first set of cutters extending a maximum
distance X from the lower end surface;
at least two cutters forming a second set of cutters in overlapping
radial relationship and extending a maximum distance Z from the
lower end surface, wherein X is greater than Z; and at least one of
the at least two cutters in the second set being in overlapping
radial relationship with at least one cutter within the first set
of cutters; and
at least two cutters forming a third set of cutters in overlapping
radial relationship and extending a maximum distance Y from the
lower end surface with Y being less than X, and at least one of the
at least two cutters in the third set being in overlapping radial
relationship with at least one cutter within the first set of
cutters.
2. A drill bit of claim 1 wherein the second set of cutters and the
third set of cutters being disposed on either side of the first set
of cutters.
3. A drill bit of claim 1 wherein x>y.gtoreq.z.
4. A drill bit of claim 1 wherein x>z.gtoreq.y.
5. A drill bit of claim 1 wherein at least one cutter in the second
set of cutters has a positive side rake angle.
6. A drill bit of claim 1 wherein at least one cutter in the third
set of cutters has a negative side rake angle.
7. A drill bit of claim 1 wherein at least one cutter in the first
set of cutters has a positive side rake.
8. A drill bit of claim 1 wherein the first set of cutters
comprises a plurality of individual groups of cutters, with cutters
within each grouping disposed in overlapping radial
relationship.
9. A drill bit of claim 8 wherein at least one cutter of each
grouping of cutters disposed at an inner radial position has a
positive side rake angle.
10. A drill bit of claim 8 wherein at least one cutter of each
grouping of cutters disposed at an outer radial position has a
negative side rake angle. .Iadd.
11. A drill bit for use in rotary drilling a borehole through
subterranean formation material and adapted for interconnection to
a source of rotary motion, comprising:
a generally cylindrical bit body having a lower end surface;
and
more than one set of cutting elements extending outward from the
lower end surface in substantially equal radial relationship, the
cutting elements of each set in substantially equal radial
relationship disposed at substantially equal radii from the center
axis of the bit body for cutting one bit whirl preventing groove
around the center of the borehole being drilled each groove having
inside and outside cutter-engaging walls of subterranean formation
material. .Iaddend.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to drill bits used to create
boreholes through a material and, more particularly, to such drill
bits that are used in the exploration for subterranean hydrocarbon
deposits.
2. Setting of the Invention
In the exploration for subterranean hydrocarbon deposits, a
rotating drill bit is used to create a borehole through the earth's
subsurface formations. The users of such drill bits and drill bit
manufacturers have found that by more precisely controlling the
weight-on-bit (WOB) and increasing the rotational speed (RPM) that
highly desirable increased drill bit penetration rates can be
achieved. However, as the RPM is increased the effective life of
the drill bits has decreased dramatically because the cutting
elements on the drill bits become very quickly cracked and can be
violently torn from the drill bits.
Numerous studies have been made to find out what causes such
destruction to the cutting elements. The inventors hereof have
previously found that a substantial portion of the destructive
forces are generated by radial imbalance forces that cause a drill
bit to rotate about a rotational axis offset from the geometric
center of the drill bit in such a way that the drill bit tends to
wobble or "backwards whirl" about the borehole. This backwards
whirling causes the center of rotation to change dramatically as
the drill bit rotates about the borehole. Thus, the cutting
elements travel faster, sideways, and backwards and thus are
subject to greatly increased impact loads which cause the
destruction of the cutting elements.
More specifically, circumferential drilling imbalance forces exist
to some degree on every drill bit and these forces tend to push the
drill bit towards the side of the borehole. In a typical drill bit,
gauge cutting elements are designed to cut the edge of the
borehole. During the cutting process, the effective friction
between the cutting elements near the gauge area increase and,
thus, the instantaneous center of rotation becomes some point other
than the geometric center of the drill bit. When this happens, the
usual result is for the drill bit to begin to backwards whirl
around the borehole. This whirling process regenerates itself
because sufficient friction is always generated between the drill
bit gauge area and the borehole wall, no matter what the
orientation of the drill bit, from the centrifugal forces generated
by the rapid acceleration of the drill bit.
Various methods and equipment have been proposed to eliminate or
reduce these imbalance forces, including using dynamically balanced
lower drillstring assemblies and very precisely aligning the
cutting elements to reduce imbalance forces.
Various designs of drill bits have been developed to improve
penetration rates by aligning the cutting elements in a plurality
of equal radius sets, with each set being in overlapping radial
relationship. One such drill bit design is disclosed in U.S. Pat.
No. 4,545,441. Further, various attempts at improving cutting
element life have been made by varying the back or side rake or
angle of attack of the cutting elements, i.e., the angle at which
the face of the cutting element addresses the formation with
respect to the formation surface. The benefits of varying such back
rake angles are disclosed in "The Effect Of Back Rake On The
Performance Of Small-Diameter Polycrystalline Diamond Rock Bits:
ANOVA Tests," Journal of Energy Resources Technology, Vol. 108, No.
4, pp. 305-309, December 1986; U.S. Pat. No. 4,660,659; U.S. Pat.
No. 4,440,247; U.S. Pat. No. 4,186,628 and U.S.S.R. Pat. No.
395,559. The effects of varying side rake angles is disclosed in
Hunnj SPE-10152 (1981).
There is no disclosure or suggestion in any of the above-identified
article or patents of arranging cutting elements specifically to
prevent or reduce the effects of destructive bit whirl. There is a
need for a drill bit design which incorporates features designed
specifically for preventing bit whirl and improving cutting element
life.
SUMMARY OF THE INVENTION
The present invention has been contemplated to overcome the
foregoing deficiencies and meet the above-described needs.
Specifically, the present invention is a drill bit for use in
rotary drilling which includes a generally cylindrical bit body
having an upper end interconnectable to a source of rotary motion,
and having a lower end surface, which is generally curved. A
plurality of cutting elements extend outward from the lower end
surface and include at least one set of cutting elements (herein
referred to as the first set) disposed at substantially equal
radius from the center axis of the bit body and displaced beyond
the depth profile of the remaining cutters (referred to as the
second set). The first set of cutters extends a maximum distance x
out from the lower end surface. Other cutting elements, at least
two, are also included in overlapping radial relationships with
each other and extend a maximum distance y out from the lower end
surface, wherein x>y. At least one of these other cutting
elements is in overlapping radial relationship with at least one of
the cutting elements within the first set.
Because the first set of cutting elements extends a greater
distance outward from the face of the drill bit, the first set of
cutting elements creates a groove in the formation material. The
cutting elements riding in this resulting groove help prevent the
drill bit from wobbling or whirling about the borehole, because any
time the drill bit tends to move away from the borehole center,
cutters on the opposite side of the groove exert an increasing
force that causes the drill bit to remain centered around the
groove. Other sets of cutting elements remove the remaining
material beside the groove thereby cutting all the formation
material across the surface of the drill bit to create the
borehole. Because the drill bit incorporates specific features to
resist bit whirl, the drilling performance and cutting element life
is improved over prior drill bits.
BRIEF DESCRIPTION OF THE DRAWING
FIG. 1 is a schematic view of cutter arrangements showing both
positive and negative back rake (side view) and side rake (plan
view) for definitional purposes.
FIG. 2 is a bottom view of a lower end surface of a drill bit
having a plurality of cutting elements extending therefrom in
accordance with one embodiment of the present invention.
FIG. 3 is a diagramatic side view of one-half portion of the drill
bit of FIG. 2, showing the cutting element profile and resulting
formation material profile.
FIG. 4 is a bottom view of a lower end surface of a drill bit
having a plurality of cutting elements extending therefrom in
accordance with an alternate embodiment of the present
invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
As stated previously, the present invention is a drill bit for use
in rotary drilling that includes a generally cylindrical bit body
for interconnection to a source of rotary motion. A plurality of
cutting elements extend outward from a lower end surface of the bit
body to create at least one groove in the formation material, which
helps prevent the drill bit from whirling or wobbling about the
borehole.
Before a detailed discussion of the novel features of the present
invention, attention is directed for definitional purposes to FIG.
1 wherein in a side view cutting elements are shown having varying
angles of back rake, and in a plan view, cutting elements are shown
having varying angles of side rake.
As shown in FIG. 2, a drill bit 10, such as a Geoset, PDC or
Stratapak, comprises a generally cylindrical bit body 12, which on
an upper end includes a pin portion with threaded or other similar
connections for interconnection to a source of rotary motion, as is
well known to those skilled in the art. Such source of rotary
motion can include connection through a drill string to a rotary
table or power swivel to the surface, or to a downhole motor or
turbine. On the sides or gauge portion of the bit body 12 and a
lower end surface 14, a plurality of cutting elements, hereinafter
simply called cutters and labeled with a "C," extend outward. The
cutters are arranged to provide material removing coverage only in
a circle about a hollow inner portion if the drill bit is a "coring
bit," and the cutters provide material removing coverage over the
entire surface 14 if a full gauge borehole is to be created. A
plurality of fluid nozzles 16 are provided on and within the bit
body 12, as is well known to those skilled in the art, to provide
fluid from a surface supply through the drillstring and outwardly
through these nozzles 16 to wash away formation material from the
cutters, as well as to cool the face of the cutters.
A major feature of the present invention is that one or more sets
of cutters create one or more circular grooves in the formation
material to prevent bit whirl, A first set of cutters, formed from
at least two cutters, here labeled C-6 through C-10 in FIGS. 2 and
3, are connected to the lower end surface 14, in any known manner.
The first set of cutters C-6 through C-10 are disposed at
substantially an equal radius from the center axis of the bit body
12. It is preferred that the first set of cutters be of equal
radius, but this is not required. The first set of cutters are also
displaced around the center axis. It is preferred that the first
set of cutters be equally spaced, but this is not required. In the
embodiment shown in FIG. 2, there are five such cutters (C-6
through C-10) in such first set, and therefore each cutter would be
at an angle of approximately 72.degree. spaced one from another.
Also, the cutters C-6 through C-10 are shown to be of the same size
and side rake angles. However, the number of cutters, the relative
sizes of the cutters, the back and side rake angle of the cutters
can be uniform, different or in any variation desired as long as
cutters in the first set of cutters simultaneously contact the edge
of resulting groove 18 in material 20.
Another set of cutters (having at least two cutters therein), such
as cutters C-1 through C-5, are disposed about the end surface 14
of the bit body 1 with these cutters having some overlapping radial
relationship, and with at least one of these cutters, such as
cutter C-5, in overlapping radial relationship with at least one
cutter within the first set of cutters (C-6 through C-10). This set
of cutters extending a maximum distance z out from the end surface
14.
Another set of at least two cutters, such as C-11 and C-15, are
connected to the end surface 14 of the bit body 12 at a radius
greater than all other cutters. These cutters have some overlapping
radial relationship and at least one of the cutters (such as C-11)
is in overlapping radial relationship with at least one cutter
within the first set of cutters. This set of cutters extends a
maximum distance y out from the end surface 14.
In the embodiment shown in FIG. 3, x>y; however, any
configuration of sizing, back rake angle, or other arrangement of
the cutters can be utilized as is desired, as long as at least one
groove 18 is formed in the formation material 20. Further, y can be
greater, equal or less than z, as is desired. The example shown in
FIG. 3 has the cutters C-6 through C-10 residing within such groove
18 so that when the drill bit 10 is rotated, these cutters (being
in substantially equal radial relationship) will ride within such
groove, which tends to maintain the drill bit therewithin to
prevent the drill bit 10 from whirling or wobbling about the
borehole. Any force that tends to cause bit 10 to move from its
centered position is resisted by an increased force in the opposite
direction by one of the cutters C-6 through C-10. Thus, the gauge
cutters provide a dynamically stabilizing effect only when the bit
10 tends to move from its desired centered position.
Another major feature that can be incorporated within a drill bit
to assist in preventing bit whirl is to have varied side rake
angles of one or more cutters. This feature can be used alone or,
preferably, with the groove cutting feature described above.
For reference purposes, at side rake angle that is considered
negative, the rock material is forced outwardly and away from the
center of the drill bit; at a neutral side angle a straight
perpendicular path is drawn from the center of the drill bit across
the face of the cutter; and at a positive side angle rock material
is forced towards the center of the drill bit.
As shown in FIG. 4, cutters corresponding to C-6 through C-10 in
FIGS. 2 and 3 can have different, the same or varying back and/or
side rake angles and varying radius. Further, in place of large
single cutters, groupings of cutters can be used. Again a group of
cutters should have a substantially equal radius from the center of
the bit body and also each cutter group can be displaced through
equal or unequal arcs around the axis. Further, the group of
cutters can extend the maximum distance x from the lower end 14 of
the bit body 12. In this manner, all of the cutters (C-2 through
C-12 in FIG. 4) would replace cutters C-6 through C-10 in FIGS. 2
and 3.
It has been found that if positive side rake is used on the inside
portion of the groove 18 and if negative side rake is used on the
outside portion of the groove 18, the resulting dynamic forces tend
to keep the bit 10 rotating about its center. When a sharp
aggressive cutting edge is pushed laterally into the borehole
surface, a high friction point is generated that can become the
instantaneous center of rotation. When the bit 10 tends to move
from the center of the borehole, cutters on one side of the bit 10
engage the inside of the groove 18 and cutters on the opposite side
of the bit 10 engage the outside of the groove 18. By placing
inside cutters with positive side rake and the outside cutters with
negative side rake, the cutters have a reduced friction and have a
reduced tendency to cut away the wall of the groove 18. Thus, the
bit 10 has a greater tendency to be self-centering about the
borehole center.
As shown in FIG. 4, cutters C-2, 5, 8 and 11 have neutral or zero
side rake; cutters C-1, 4, 7 and 10 have positive side rake; and
cutters C-3, 6, 9 and 12 have negative side rake. However, the
arrangement can vary as desired as long as at least one cutter in
an inverse radial position has positive side rake and at least one
cutter in an outer radial position has negative side rake.
Wherein the present invention has been described in particular
relation to the drawings attached hereto, it should be understood
that other and further modifications, apart from those shown or
suggested herein, can be made within the scope and spirit of the
present invention.
* * * * *