U.S. patent application number 12/200344 was filed with the patent office on 2010-03-04 for drilling out casing bits with other casing bits.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Eric E. McClain, John C. Thomas.
Application Number | 20100051350 12/200344 |
Document ID | / |
Family ID | 41722287 |
Filed Date | 2010-03-04 |
United States Patent
Application |
20100051350 |
Kind Code |
A1 |
McClain; Eric E. ; et
al. |
March 4, 2010 |
DRILLING OUT CASING BITS WITH OTHER CASING BITS
Abstract
The drilling of a casing bit and any other equipment in the
casing with another casing bit where at least two casing bits of
different diameter and having associated casing sections may be
assembled to form a drilling assembly for drilling subterranean
formations, the at least two casing bits and casing sections are
arranged in a telescoping relationship.
Inventors: |
McClain; Eric E.; (Spring,
TX) ; Thomas; John C.; (Lafayette, LA) |
Correspondence
Address: |
TRASKBRITT, P.C.
P.O. BOX 2550
SALT LAKE CITY
UT
84110
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
41722287 |
Appl. No.: |
12/200344 |
Filed: |
August 28, 2008 |
Current U.S.
Class: |
175/62 ;
175/385 |
Current CPC
Class: |
E21B 7/20 20130101; E21B
10/43 20130101; E21B 17/14 20130101; E21B 10/567 20130101 |
Class at
Publication: |
175/62 ;
175/385 |
International
Class: |
E21B 10/26 20060101
E21B010/26 |
Claims
1. A drilling assembly for drilling two or more casing sections
into a subterranean formation comprising: a first casing bit and a
second casing bit, each casing bit of different diameter affixed to
a respective casing section of different diameter, at least two
casing bits and the two or more casing sections arranged in a
telescoping relationship; the second casing bit comprising: a bit
body having a face at a leading end thereof; a first plurality of
cutting elements of at least one type disposed over the bit body,
the cutting elements of the at least one type each exhibiting an
exposure; a second plurality of cutting elements of at least
another, different type disposed over the bit body, each cutting
element of the at least another, different type exhibiting an
exposure relatively greater than an exposure of a proximate cutting
element of the at least one type.
2. The drilling assembly of claim 1, wherein the second casing bit
further includes a plurality of generally radially extending blades
extending over the face, wherein at least one cutting element of
the at least one type and at least one cutting element of the at
least another, different type are disposed on each blade.
3. The drilling assembly of claim 2, wherein a plurality of cutting
elements of the at least one type and a plurality of cutting
elements of the at least another, different type are disposed on
each blade.
4. The drilling assembly of claim 3, wherein at least some cutting
elements of the at least one type have proximate thereto a cutting
element of the at least another, different type.
5. The drilling assembly of claim 4, wherein the at least some
cutting elements of the at least one type and the proximate cutting
element of the at least another, different type are located at a
substantially similar radius from a centerline of a drill bit.
6. The drilling assembly of claim 2, wherein the cutting elements
of the first and second pluralities are disposed in pockets formed
in the generally radially extending blades of the plurality.
7. The drilling assembly of claim 6, wherein the at least one type
of cutting elements comprises superabrasive cutting elements and
the at least another, different type of cutting elements comprises
abrasive cutting elements.
8. The drilling assembly of claim 7, wherein the superabrasive
cutting elements comprise PDC cutting elements and the abrasive
cutting elements comprise tungsten carbide cutting elements.
9. The drilling assembly of claim 1, wherein the at least one type
of cutting elements comprises superabrasive cutting elements and
the at least another, different type of cutting elements comprises
abrasive cutting elements.
10. The drilling assembly of claim 9, wherein the superabrasive
cutting elements comprise PDC cutting elements and the abrasive
cutting elements comprise tungsten carbide cutting elements.
11. The drilling assembly of claim 1, wherein a central portion of
an outer profile of the face is configured as an inverted cone and
is surrounded by a nose.
12. The drilling assembly of claim 11, wherein at least a majority
of the second plurality of cutting elements of the at least
another, different type is disposed within the central portion of
the outer profile of the face and on the nose.
13. The drilling assembly of claim 1, wherein cutting elements of
the at least one type are selected from the group consisting of a
PDC cutting element, a thermally stable diamond cutting element,
and a natural diamond cutting element.
14. The drilling assembly of claim 1, wherein cutting elements of
the at least another, different type are selected from the group
consisting of a tungsten carbide cutting element, another metal
carbide cutting element and a ceramic.
15. The drilling assembly of claim 1, wherein: the second plurality
of cutting elements is configured to initially engage and drill
through a selected region; and the first plurality of cutting
elements is configured to engage and drill through a region to be
subsequently encountered by a drill bit.
16. The drilling assembly of claim 15, wherein each of the second
plurality of cutting elements comprises a tungsten carbide cutting
element and each of the first plurality of cutting elements
comprises a PDC cutting element.
17. The drilling assembly of claim 1, wherein the second plurality
of cutting elements is disposed between a centerline of a drill bit
and a gage region thereof.
18. The drilling assembly of claim 1, wherein the second plurality
of cutting elements is disposed over the face thereof.
19. The drilling assembly of claim 1, wherein cutting elements of
the second plurality are oriented at a forward rake, a neutral
(about 0.degree.) rake or a back rake of up to about
25.degree..
20. The drilling assembly of claim 1, wherein at least some of the
cutting elements of the second plurality include a cutting edge
area defined by an annular flat leading from a side surface of the
cutting elements to an offset chamfer terminating at a cutting
face.
21. The drilling assembly of claim 1, wherein at least one cutting
element of the one type and at least one cutting element of the at
least another, different type are arranged together in a single
structure and disposed in a single pocket on the bit body.
22. The drilling assembly of claim 1, wherein the two or more
casing sections are affixed to one another by way of shear
pins.
23. The drilling assembly of claim 1, wherein one or more casing
bits of the at least two casing bits are disposed at least
partially within one or more other casing bits of the at least two
casing bits in a telescoping relationship.
24. The drilling assembly of claim 1, wherein one or more smaller
casing bits of the at least two casing bits are configured to drill
through at least another larger casing bit of the at least two
casing bits.
25. A method of drilling comprising: drilling through at least one
material forming a component of an assembly located in a casing to
expose one of a drill bit or material of a subterranean formation
using a drill bit having a plurality of cutting elements exhibiting
a relatively greater exposure than another plurality of cutting
elements on the drill bit; engaging exposed subterranean formation
material with the plurality of cutting elements and wearing the
cutting elements away to an extent sufficient at least to expose
cutting edges of the another plurality of cutting elements; and
drilling a wellbore into the subterranean formation with the drill
bit, using the another plurality of cutting elements.
26. A drilling assembly for drilling two or more casing sections
into a subterranean formation comprising: at least two casing
sections of different diameter disposed in a telescoping
relationship; a drilling tool disposed at a longitudinally
preceding end of the at least two casing sections, in relation to
an intended direction of drilling, the drilling tool configured to
drill a diameter exceeding a largest diameter of the at least two
casing sections of different diameter; and the drilling tool
comprising: a bit body having a face at a leading end thereof; a
first plurality of cutting elements of at least one type disposed
over the bit body, the cutting elements of the at least one type
each exhibiting an exposure; a second plurality of cutting elements
of at least another, different type disposed over the bit body,
each cutting element of the at least another, different type
exhibiting an exposure relatively greater than an exposure of a
proximate cutting element of the at least one type.
27. The drilling assembly of claim 26, wherein the at least two
casing sections are affixed to one another by shear pins.
28. The drilling assembly of claim 26, wherein the drilling tool
comprises at least one of a rotary drill bit, a reamer, and a
reaming assembly operably coupled to the innermost of the at least
two casing sections.
29. The drilling assembly of claim 26, further comprising a motor
disposed longitudinally between and coupled to the drilling tool
and the innermost of the at least two casing sections.
30. The drilling assembly of claim 26, wherein the drilling tool
comprises a casing bit operably coupled to the innermost of the at
least two casing sections.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates generally to drilling a
subterranean borehole and, more specifically, drilling structures
disposed on the end of a casing or liner.
[0003] 2. State of the Art
[0004] The drilling of wells for oil and gas production
conventionally employs longitudinally extending sections or
so-called "strings" of drill pipe to which, at one end, is secured
a drill bit of a larger diameter. After a selected portion of the
borehole has been drilled, the borehole is usually lined or cased
with a string or section of casing. Such a casing or liner usually
exhibits a larger diameter than the drill pipe and a smaller
diameter than the drill bit. Therefore, drilling and casing
according to the conventional process typically requires
sequentially drilling the borehole using drill string with a drill
bit attached thereto, removing the drill string and drill bit from
the borehole, and disposing casing into the borehole. Further,
often after a section of the borehole is lined with casing, which
is usually cemented into place, additional drilling beyond the end
of the casing may be desired.
[0005] However, sequential drilling and casing may be time
consuming and costly because at the considerable depths the time
required to implement complex retrieval procedures to recover the
drill string may be lengthy.
BRIEF SUMMARY OF THE INVENTION
[0006] The drilling of a casing bit and any other equipment in the
casing with another casing bit where at least two casing bits of
different diameter and having associated casing sections may be
assembled to form a drilling assembly for drilling subterranean
formations, the at least two casing bits and casing sections are
arranged in a telescoping relationship.
[0007] The features and advantages of the present invention will
become apparent to those of ordinary skill in the art through
consideration of the ensuing description, the accompanying
drawings, and the appended claims.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0008] In the drawings, which illustrate what is currently
considered to be the best mode for carrying out the invention:
[0009] FIG. 1A shows a schematic cross-sectional view of a drilling
assembly including two casing bits arranged in a nested telescoping
relationship;
[0010] FIG. 1B shows a schematic cross-sectional view of the
drilling assembly shown in FIG. 1A in an extended telescoping
relationship;
[0011] FIG. 1C shows a schematic cross-sectional view of a drilling
assembly according to the present invention including three casing
sections and a rotary drill bit;
[0012] FIG. 1D shows a schematic cross-sectional view of a drilling
assembly according to the present invention including a casing bit
of the present invention and three casing sections;
[0013] FIG. 2 shows a perspective view of a drill bit of the
present invention;
[0014] FIG. 3 shows an enlarged perspective view of a portion of
another drill bit of the present invention;
[0015] FIG. 4 shows an enlarged view of the face of the drill bit
of FIG. 2;
[0016] FIG. 5 shows a schematic side cross-sectional view of a
cutting element placement design of a drill bit according to the
present invention showing relative exposures of first and second
types of cutting elements disposed thereon;
[0017] FIG. 6A is a perspective view of one configuration of a
cutting element suitable for drilling through a casing bit and, if
present, cementing equipment components within a casing above the
casing bit, FIG. 6B is a frontal view of the cutting element shown
in FIG. 6A, FIG. 6C is a sectional view taken through line 6C-6C on
FIG. 6B, and FIG. 6D is an enlarged view of the cutting edge of the
cutting element in the circled area of FIG. 6C;
[0018] FIGS. 7A-7H show schematically other configurations of
cutting elements suitable for drilling through a casing bit and, if
present, cementing equipment components within a casing above the
casing bit, wherein FIGS. 7A, 7C, 7E and 7G show transverse
configurations of the cutting elements, and FIGS. 7B, 7D, 7F and 7H
show side views;
[0019] FIGS. 8A-8B show a configuration of a dual-purpose cutting
element suitable for first drilling through a casing bit and, if
present, cementing equipment components and cement within a casing
above the casing bit and subsequently drilling through a
subterranean formation ahead of the casing bit;
[0020] FIG. 9 shows schematically a casing assembly having a casing
bit at the bottom thereof and a cementing equipment component
assembly above the casing bit, the casing assembly disposed within
a borehole;
[0021] FIG. 10 shows a detailed, side cross-sectional view of an
example cementing equipment component assembly such as might be
used in the casing assembly of FIG. 8; and
[0022] FIG. 11 shows a schematic cross-sectional view of a drill
bit according to the present invention disposed within a casing bit
having an inner profile, as well as an outer profile substantially
conforming to a drilling profile defined by cutting elements of the
drill bit.
DETAILED DESCRIPTION OF THE INVENTION
[0023] In the present invention, at least two casino bits of
different diameter and having associated casing sections may be
assembled to form a drilling assembly for drilling into
subterranean formations, wherein radially adjacent casing sections
are selectively releasably affixed to one another and wherein the
at least two casing bits and casing sections are arranged in a
telescoping relationship. Such a configuration may reduce the time
needed to dispose the casing sections that are attached to each
larger and smaller casing bit into the borehole.
[0024] For example, as shown in FIGS. 1A and 1B, drilling assembly
511 may include a first casing bit 516 and a second casing bit 514,
wherein the first casing bit 516 is disposed within the second
casing bit 514. First casing bit 516 may be affixed to casing
section 508 and second casing bit 514 may be affixed to casing
section 506. Thus, the casing sections 506 and 508 may be
configured in a telescoping relationship, i.e., capable of being
extended from or within one another. As shown in FIG. 1A, casing
section 508 is affixed to casing section 506 by way of frangible
elements 518. Frangible elements 518 may be configured to transmit
torque, axial force or weight-on-bit (WOB), or both, between casing
sections 506 and 508. Of course, other structures for transmitting
forces between the casing sections 506 and 508 may be utilized. The
casing section 506 may include cement floating equipment of
cementing equipment component assembly F or downhole motor M
connected thereto and/or second casing bit 514.
[0025] Therefore, during operation, torque and WOB may be applied
to second casing bit 514 through casing section 506. Alternatively,
torque and WOB may be applied to second casing bit 514 by way of
casing section 508 and through frangible elements 518. As may be
appreciated, when the casing bits 514 and 516 are structurally
coupled to one another, torque, WOB, or both, may be transmitted
therebetween. In addition, the fluid ports or apertures between
each of the casing bits 514 and 516 may be coupled so that drilling
fluid may be delivered through the interior of first casing bit 516
to second casing bit 514. Alternatively, drilling fluid may be
delivered through annulus 524, while the ports or apertures of
first casing bit 516 may be plugged or blocked. Thus, many
alternatives are possible for delivering drilling fluid to any of
casing bits 514 and 516.
[0026] As shown in FIG. 1B, a casing section 504 may be disposed at
a first depth. Then, second casing bit 514 may be caused to drill
past casing bit 512 and continue drilling to a second depth. Upon
reaching a second depth, torque, WOB, or both, may be applied to
cause frangible elements to fail or fracture. Alternatively, a
frangible element may be caused to fail by way of selectively
detonating a pyrotechnic agent, an explosive agent, or both. Thus,
first casing bit 516 may be employed to drill through second casing
bit 514 and to a third depth. Put another way, FIG. 1B shows
drilling assembly 511 in an extended telescoping relationship. Of
course, the present invention is not limited to any particular
number of casing bits configured in a telescoping relationship.
Rather, a drilling assembly of the present invention may include
one or more casing bits disposed at least partially within one or
more other casing bits in a telescoping relationship. It should
also be understood that the present invention is not limited to a
smaller casing bit or casing section being positioned at least
partially within another casing bit to be configured in a
telescoping relationship. Rather, more specifically, a casing bit
or casing section may be disposed within another casing section,
which may be affixed to another, larger casing bit, to be
configured in a telescoping relationship.
[0027] Alternatively, an assembly of two of more casing sections
configured in a telescoping relationship may be drilled into a
subterranean formation by a drilling tool disposed at the leading
end thereof. Specifically, as shown in FIG. 1C, illustrating a
drilling assembly 533, casing sections 504, 506, and 508 may be
coupled together by way of, for example, latching casing sections
504, 506, and 508 together to form an assembly that may be drilled
into a formation by a conventional drilling tool 534 disposed at
the leading end, in the direction of drilling, of the drilling
assembly 533, the drilling tool 534 having a diameter that exceeds
the diameter of the largest casing section 504. Drilling tool 534
may comprise a rotary drill bit, a reamer, a reaming assembly, or a
casing bit, without limitation. The drilling tool 534 may precede
into the formation by rotation and translation of the casing
sections 504, 506, and 508. However, preferably, the drilling tool
534 may be structurally coupled to the innermost casing section
508, so that drilling tool 534 may continue to drill into the
formation notwithstanding casing sections 504 or 506 becoming
disposed within the borehole. Optionally, a downhole motor may be
positioned between the innermost casing section 508 and the
drilling tool 534.
[0028] As the drilling assembly proceeds into the formation,
radially adjacent smaller casing sections may be unlatched from
radially adjacent larger casing sections and extended therefrom. Of
course, frangible elements (not shown) as described hereinabove
(FIG. 1A) may structurally connect casing sections 504, 506, and
508 to one another. Forces may be applied to fail such frangible
elements, or incendiary or explosive components may be employed for
failing frangible elements. It is noted that a conventional
drilling tool 534 may not be suited to allow another drilling tool
to drill therethrough. However, the telescoping relationship
between the casing sections 504, 506, and 508 may provide advantage
in reducing the tripping operations for disposing the casing
sections 504, 506, and 508 within the borehole.
[0029] Additionally, an assembly of two of more casing sections
configured in a telescoping relationship may be drilled into a
subterranean formation by a casing bit disposed at the leading end
thereof. As shown in FIG. 1D, a drilling assembly 544 including
casing sections 504, 506, and 508 may be drilled in to a formation
by a casing bit 546 of the present invention. However, the casing
bit 546 may be primarily coupled to the innermost casing section
508, as illustrated by radially extending flange 548 and attachment
surface 547, so that casing bit 546 may continue to drill into the
formation notwithstanding casing sections 504 or 506 becoming
disposed within the borehole, as well as being separated from
casing section 508.
[0030] FIGS. 2-4 illustrate several variations of an embodiment of
a drill bit 12 in the form of a fixed cutter or so-called "drag"
bit, according to the present invention which corresponds to first
casing bit 516 in FIG. 1A and drilling tool 534 and casing bit 546
in FIGS. 1C and 1D. For the sake of clarity, like numerals have
been used to identify like features in FIGS. 2-4. As shown in FIGS.
2-4, drill bit 12 includes a bit body 14 having a face 26 and
generally radially extending blades 22, forming fluid courses 24
therebetween extending to junk slots 35 between circumferentially
adjacent blades 22. Bit body 14 may comprise a tungsten carbide
matrix or a steel body, both as well known in the art. Blades 22
may also include pockets 30, which may be configured to receive
cutting elements of one type such as, for instance, superabrasive
cutting elements in the form of PDC cutting elements 32. Generally,
such a PDC cutting element may comprise a superabrasive region that
is bonded to a substrate. Rotary drag bits employing PDC cutting
elements have been employed for several decades. PDC cutting
elements are typically comprised of a disc-shaped diamond "table"
formed on and bonded under a high-pressure and high-temperature
(HPHT) process to a supporting substrate such as cemented tungsten
carbide (WC), although other configurations are known. Drill bits
carrying PDC cutting elements, which, for example, may be brazed
into pockets in the bit face, pockets in blades extending from the
face, or mounted to studs inserted into the bit body, are known in
the art. Thus, PDC cutting elements 32 may be affixed upon the
blades 22 of drill bit 12 by way of brazing, welding, or as
otherwise known in the art. It is also contemplated that cutting
elements 32 may comprise suitably mounted and exposed natural
diamonds, thermally stable polycrystalline diamond compacts, cubic
boron nitride compacts, or diamond grit-impregnated segments, as
known in the art and as may be selected in consideration of the
subterranean formation or formations to be drilled.
[0031] Also, each of blades 22 may include a gage region 25 which
is configured to define the outermost radius of the drill bit 12
and, thus the radius of the wall surface of a borehole drilled
thereby. Gage regions 25 comprise longitudinally upward (as the
drill bit 12 is oriented during use) extensions of blades 22,
extending from nose portion 20 and may have wear-resistant inserts
or coatings, such as cutting elements in the form of gage trimmers
of natural or synthetic diamond, or hardfacing material, on
radially outer surfaces thereof as known in the art to inhibit
excessive wear thereto.
[0032] Drill bit 12 may also be provided with, for example, pockets
34 in blades 22 which may be configured to receive abrasive cutting
elements 36, 36', 36'' of another type different from the first
type such as, for instance, tungsten carbide cutting elements. It
is also contemplated, however, that abrasive cutting elements 36
may comprise, for example, a carbide material other than tungsten
(W) carbide, such as a Ti, Mo, Nb, V, Hf, Ta, Cr, Zr, Al, and Si
carbide, or a ceramic. However, abrasive cutting elements 36, 36',
36'' may be configured the same as cutting elements 32 depending
upon the material composition to be drilled by cutting elements 36,
36', 36''. Abrasive cutting elements 36, 36', 36'' may be secured
within pockets 34 by welding, brazing or as otherwise known in the
art. As depicted in FIG. 2, abrasive cutting elements 36, 36', 36''
may be of substantially uniform thickness, taken in the direction
of intended bit rotation. As shown in FIGS. 3 and 4, abrasive
cutting elements 36, 36', 36'' may be of varying thickness, taken
in the direction of bit rotation, wherein abrasive cutting elements
36, 36', 36'' at more radially outwardly locations (and, thus,
which traverse relatively greater distance for each rotation of
drill bit 12 than those, for example, within the cone of drill bit
12) may be thicker to ensure adequate material thereof will remain
for cutting casing components and cement until they are to be worn
away by contact with formation material after the casing components
and cement are penetrated.
[0033] Shown in FIGS. 3-5, abrasive cutting elements 36, 36', 36''
may be placed in an area from the cone of the bit out to the
shoulder (in the area from the centerline L to gage regions 25) to
provide maximum protection for cutting elements 32, which are
highly susceptible to damage when drilling casing assembly
components. Broadly, cutting elements 32 on face 26, which may be
defined as surfaces at less than 90.degree. profile angles, or
angles with respect to centerline L, are desirably protected.
Cutting elements 36 may also be placed selectively along the
profile of the face 26 to provide enhanced protection to certain
areas of the face 26 and cutting elements 32 thereon.
[0034] Superabrasive cutting elements 32 and abrasive cutting
elements 36, 36', 36'' may be respectively dimensioned and
configured, in combination with the respective depths and locations
of pockets 30 and 34, to provide abrasive cutting elements 36, 36',
36'' with a greater relative exposure than superabrasive cutting
elements 32. As used herein, the term "exposure" of a cutting
element generally indicates its distance of protrusion above a
portion of a drill bit, for example a blade surface or the profile
thereof, to which it is mounted. However, in reference specifically
to the present invention, "relative exposure" is used to denote a
difference in exposure between a cutting element 32 of the one type
and a cutting element 36, 36', 36'' of the another, different type.
More specifically, the term "relative exposure" may be used to
denote a difference in exposure between one cutting element 32 of
the one type and another cutting element 36, 36', 36'' of the
another, different type which are proximately located on drill bit
12 at similar radial positions relative to a centerline L (see FIG.
5) of drill bit 12 and which, optionally, may be proximately
located in a direction of bit rotation. In the embodiment depicted
in FIGS. 2-4, abrasive cutting elements 36, 36', 36'' may generally
be described as rotationally "following" superabrasive cutting
elements 32 and in close rotational proximity to on the same blade
22, as well as being located at substantially the same radius.
However, abrasive cutting elements 36, 36', 36'' may also be
located to rotationally "lead" associated superabrasive cutting
elements 32.
[0035] By way of illustration of the foregoing, FIG. 5 shows a
schematic side view of a cutting element placement design for drill
bit 12 showing cutting elements 32 as disposed on a drill bit (not
shown) such as drill bit 12 of the present invention in relation to
the longitudinal axis or centerline L and drilling profile P
thereof, as if all the cutting elements 32, 32', and 36 were
rotated onto a single blade (not shown). Particularly, one
plurality of cutting elements 36 may be sized, configured, and
positioned so as to engage and drill a first material or region,
such as a casing shoe, casing bit, cementing equipment component or
other downhole component. Further, the one plurality of cutting
elements 36 may be configured to drill through a region of cement
that surrounds a casing shoe, if it has been cemented within a
wellbore, as known in the art. In addition, another plurality of
cutting elements 32 may be sized, configured, and positioned to
drill into a subterranean formation. Also, cutting elements 32' are
shown as configured with radially outwardly oriented flats and
positioned to cut a gage diameter of drill bit 12, but the gage
region of the cutting element placement design for drill bit 12 may
also include cutting elements 32 and 36 of the first and second
plurality, respectively. The present invention contemplates that
the one plurality of cutting elements 36 may be more exposed than
the another plurality of cutting elements 32. In this way, the one
plurality of cutting elements 36 may be sacrificial in relation to
the another plurality of cutting elements 32. Explaining further,
the one plurality of cutting elements 36, 36', 36'' may be
configured to initially engage and drill through materials and
regions that are different from subsequent materials and regions
that the another plurality of cutting elements 32 is configured to
engage and drill through.
[0036] Accordingly, the one plurality of cutting elements 36, 36',
36'' may be configured differently than the another plurality of
cutting elements 32. Particularly, and as noted above, the one
plurality of cutting elements 36, 36', 36'' may comprise tungsten
carbide cutting elements, while the another plurality of cutting
elements 32 may comprise PDC cutting elements. Such a configuration
may facilitate drilling through a casing shoe or bit, as well as
cementing equipment components within the casing on which the
casing shoe or bit is disposed, as well as the cement thereabout
with primarily the one plurality of cutting elements 36, 36', 36''.
However, upon passing into a subterranean formation, the
abrasiveness of the subterranean formation material being drilled
may wear away the tungsten carbide of cutting elements 36, 36',
36'', and the another plurality of PDC cutting elements 32 may
engage the formation. As shown in FIGS. 2-4, one or more of the
another plurality of cutting elements 32 may rotationally precede
one or more of the one plurality of cutting elements 36, 36', 36'',
without limitation. Alternatively, one or more of the another
plurality of cutting elements 32 may rotationally follow one or
more of the one plurality of cutting elements 36, 36', 36'',
without limitation.
[0037] During drilling with drill bit 12, fluid courses 24 between
circumferentially adjacent blades 22 may be provided with drilling
fluid flowing through nozzles 33 secured in apertures at the outer
ends of passages that extend between the interior of the drill bit
12 and the face 26 thereof. Cuttings of material from engagement of
cutting elements 32 or 36, 36', 36'' are swept away from the
cutting elements 32 and 36, 36', 36'', and cutting elements 32 and
36, 36', 36'' are cooled by drilling fluid or mud pumped down the
bore of a drill string on which drill bit 12 is disposed and
emanating from nozzles 33, the fluid moving generally radially
outwardly through fluid courses 24 and then upwardly through junk
slots 35 to an annulus between an interior wall of a casing section
within which the drill bit 12 is suspended and the exterior of a
drill string on which drill bit 12 is disposed. Of course, after
drill bit 12 has drilled through the end of the casing assembly, an
annulus is formed between the exterior of the drill string and the
surrounding wall of the borehole.
[0038] FIGS. 6A-6D depict one example of a suitable configuration
for cutting elements 36, 36', 36'', including a disc-like body 100
of tungsten carbide or other suitable material and having a
circumferential chamfer 102 at the rear (taken in the direction of
intended cutter movement) thereof, surrounding a flat rear surface
104. A cylindrical side surface 106 extends from circumferential
chamfer 102 to an annular flat 108 oriented perpendicular to
longitudinal axis 110 and extending inwardly to offset chamfer 112,
which leads to flat cutting face 114. An area from the junction of
side surface 106 with annular flat 108 to the junction of offset
chamfer 112 with cutting face 114 may be generally termed the
cutting edge area, for the sake of convenience. The angles of
circumferential chamfer 102 and offset chamfer 112 may be, for
example, 45.degree. to longitudinal axis 110. However, other angles
are contemplated and a specific angle is not limiting of the
present invention. Cutting elements 36 may be disposed on the face
26 (as on blades 22) of drill bit 12 (FIG. 2) at, for example, a
forward rake, a neutral (about 0.degree. angle) rake or a back rake
of up to about 25.degree., for effective cutting of a casing shoe,
casing bit, cementing equipment components, and cement, although a
specific range of back rakes for cutting elements 36, 36', 36'' is
not limiting of the present invention.
[0039] FIGS. 7A-7H depict other suitable configurations for cutting
elements 36, 36', 36''. The cutting element 36, 36', 36'' depicted
in FIGS. 7A and 7B is circular in transverse configuration and, as
shown in FIG. 7B, has a cutting edge area configured similar to
that of cutting element 36 depicted in FIGS. 6A-6D. However, rear
surface 104 is sloped toward the front of the cutting element (in
the intended cutting direction shown by the arrow), providing a
thicker base and a thinner outer edge for cutting, to enhance
faster wear when formation material is engaged. The cutting element
36, 36', 36'' depicted in FIGS. 7C and 7D is also circular in
transverse configuration and, as shown in FIG. 7D, has a cutting
edge area configured similar to that of cutting element 36, 36',
36'' depicted in FIGS. 6A-6D. However, rear surface cutting face
114 is sloped toward the rear of the cutting element, providing a
thicker base and a thinner outer edge for cutting, to enhance
faster wear when formation material is engaged. The cutting element
36, 36', 36'' depicted in FIGS. 7E and 7F is also circular in
transverse configuration and, as shown in FIG. 7F, has a cutting
edge area configuration similar to that of cutting element 36, 36',
36'' depicted in FIGS. 6A-6D. However, cutting face 114 is sloped
toward the rear of the cutting element from the cutting edge area,
providing a thinner base and a thicker outer edge for cutting, to
provide more cutting element material for extended cutting of
casing components and the like. The cutting element 36, 36', 36''
depicted in FIGS. 7G and 7H is ovoid- or egg-shaped in transverse
configuration and, as shown in FIG. 7H, has a cutting edge area
similar to that of cutting element 36, 36', 36'' depicted in FIGS.
6A-6D. Cutting face 114 and rear surface 104 are mutually parallel.
The ovoid configuration provides enhanced loading of material being
cut by the cutting element, to facilitate initial engagement
thereby.
[0040] FIGS. 8A and 8B depict a cutting element 136 which may be
disposed on a drill bit 12 (FIG. 2) to cut casing-associated
components, as well as a subterranean formation, rather than using
separate cutting elements for cutting casing-associated components
and, subsequently, the subterranean formation. Cutting element 136
comprises a superabrasive element 138 bonded to an abrasive element
140, the outer transverse configuration of cutting element 136
being defined as an ovoid by abrasive element 140, superabrasive
element 138 being of circular configuration and offset toward the
base B of cutting element 136 to be tangentially aligned at the
base with abrasive element 140. Thus, an exposure of an outer
extent of abrasive element 140 is greater than an exposure of an
outer extent of superabrasive element 138, as shown at 142. The
cutting edge area of abrasive element 140 may be, as shown in FIG.
7B, configured similarly to that of cutting element 36, 36', 36''
depicted in FIGS. 6A and 6B. As cutting element 136 is mounted to a
drill bit with the base B received in a single pocket on the bit
face, the greater exposure of abrasive element 140 will enable it
to contact casing-associated components (casing shoe, casing bit,
cementing equipment and cement, etc.) and drill therethrough, after
which engagement of abrasive element 140 with subterranean
formation material will case it to wear quickly and result in
engagement of superabrasive element 138 with the formation.
[0041] While examples of specific cutting element configurations
for cutting casing-associated components and cement, on the one
hand, and subterranean formation material on the other hand, have
been depicted and described, the invention is not so limited. The
cutting element configurations as disclosed herein are merely
examples of designs which the inventors believe are suitable. Other
cutting element designs for cutting casing-associated components
may employ, for example, a chamfer bridging between the side of the
cutting element and the cutting face, rather than an offset
chamfer, or no chamfer at all may be employed. Likewise,
superabrasive cutting elements design and manufacture is a highly
developed, sophisticated technology, and it is well known in the
art to match superabrasive cutting element designs and materials to
a specific formation or formations intended to be drilled.
[0042] As shown in FIG. 9, a casing section 200 and a casing bit CB
disposed on the end 204 thereof may be surrounded by cement 202, or
other hardenable material, so as to cement the casing bit CB and
casing section 200 within borehole BH, after borehole BH is
drilled. Cement 202 may be forced through the interior of casing
section 200, through (for example) apertures formed in casing bit
CB, and into the annulus formed between the wall 134 of borehole BH
and the outer surface of the casing section 200. Of course,
cementing equipment component assembly F as shown schematically
above casing bit CB may be used for controlling and delivering the
cement to the casing bit CB. Cementing the casing bit assembly 206
into the borehole BH may stabilize the borehole BH and seal
formations penetrated by borehole BH. In addition, it may be
desirable to drill past the casing bit CB, so as to extend the
borehole BH, as described in more detail hereinbelow.
[0043] Casing bit CB may include an integral stem section S (see
FIG. 10) extending longitudinally from the nose portion of casing
bit CB that includes one or more frangible regions. Alternatively,
flow control equipment of cementing equipment component assembly F,
such as float equipment may be included within the integral stem
section S of casing bit CB. Casing bit CB may include a threaded
end for attaching the casing bit CB to a casing string, or it may
be attached by another suitable technique, such as welding.
Alternatively or additionally, casing bit CB may include, without
limitation, a float valve mechanism, a cementing stage tool, a
float collar mechanism, a landing collar structure, other cementing
equipment, or combinations thereof, as known in the art, within an
integral stem section S, or such components may be disposed within
the casing string above casing bit CB.
[0044] More particularly, an integral stem section of casing bit CB
may include, as a cementing equipment component assembly F,
cementing float valves as disclosed in U.S. Pat. No. 3,997,009 to
Fox and U.S. Pat. No. 5,379,835 to Streich, the disclosures of
which are incorporated by reference herein. Further, valves and
sealing assemblies commonly used in cementing operations as
disclosed in U.S. Pat. No. 4,624,316 to Baldridge et al. and U.S.
Pat. No. 5,450,903 to Budde, the disclosures of each of which are
incorporated by reference herein, may comprise cementing equipment
component assembly F. Further, float collars as disclosed in U.S.
Pat. No. 5,842,517 to Coone, the disclosure of which is
incorporated in its entirety by reference herein, may comprise
cementing equipment component assembly F. In addition, U.S. Pat.
No. 5,960,881 to Allamon et al. and U.S. Pat. No. 6,497,291 to
Szarka, the disclosures of which are incorporated in their entirety
by reference herein, disclose cementing equipment which may
comprise component assembly F. Any of the above-referenced
cementing equipment, or mechanisms and equipment as otherwise known
in the art, may be included within integral stem section S and may
comprise cementing equipment component assembly F thereof.
[0045] In one embodiment, cementing equipment component assembly F
may comprise a float collar, as shown in FIG. 10, which depicts a
partial side cross-sectional view of integral stem section S. As
shown in FIG. 10, cementing equipment component assembly F may
include an inner body 82 anchored within outer body 84 by a short
column of cement 83, and having a bore 86 therethrough connecting
its upper and lower ends. The bore 86 may be adapted to be opened
and closed by check valve 88 comprising a poppet-type valve member
89 adapted to be vertically movable between a lower position
opening bore 86 and an upper position closing bore 86, thus
permitting flow downwardly therethrough, but preventing flow
upwardly therethrough. Therefore, poppet-type valve member 89 may
be biased to an upper position by biasing element 91, which is
shown as a compression spring; however, other biasing mechanisms
may be used for this purpose, such as a compressed gas or air
cylinder or an arched spring. Thus, cement may be delivered through
check valve 88 and through apertures (not shown) or frangible
regions (not shown) formed within the integral stem section S or
the integral casing bit CB, as discussed hereinabove.
[0046] After drilling borehole BH using casing bit assembly 206 and
cementing casing bit assembly within borehole BH, it may be
desirable to drill through the end of casing bit assembly 206 and
into the formation ahead of casing bit assembly, for which a drill
bit of the present invention is especially suitable.
[0047] Referring to FIG. 11 of the drawings, as discussed above, a
casing bit CB may be affixed to a casing section and cemented
within a borehole or wellbore (not shown), as known in the art.
FIG. 11 shows a partial cross-sectional embodiment of a portion of
a wellbore assembly W and a drill bit 12 according to the present
invention disposed within the interior of casing bit CB for
drilling therethrough. Wellbore assembly W is shown without a
casing section attached to the casing bit CB, for clarity. However,
it should be understood that the embodiments of wellbore assembly W
as shown in FIG. 11 may include a casing section which may be
cemented within a borehole as known in the art and as depicted in
FIG. 9.
[0048] Generally, referring to FIG. 11, drill bit 12 may include a
drilling profile P defined along its lower region that is
configured for engaging and drilling through the subterranean
formation. Explaining further, the drilling profile P of the drill
bit 12 may be defined by cutting elements 36 that are disposed
along a path or profile of the drill bit 12. Thus, the drilling
profile P of drill bit 12 refers to the drilling envelope or
drilled surface that would be formed by a full rotation of the
drill bit 12 about its drilling axis (not shown). Of course,
drilling profile P may be at least partially defined by generally
radially extending blades 22 (not shown in FIG. 11, see FIGS. 2-4)
disposed on the drill bit 12, as known in the art. Moreover,
drilling profile P may include arcuate regions, straight regions,
or both.
[0049] Casing bit CB may include an inner profile IP which
substantially corresponds to the drilling profile P of drill bit
12. Such a configuration may provide greater stability in drilling
through casing bit CB. Particularly, forming the geometry of
drilling profile P of drill bit 12 to conform or correspond to the
geometry of the inner profile IP of casing bit CB may enable
cutting elements 36 of relatively greater exposure disposed on the
drill bit 12 to engage the inner profile IP of casing bit CB at
least somewhat concurrently, thus equalizing the forces, the
torques, or both, of cutting therethrough.
[0050] For instance, referring to FIG. 11, the drilling profile P
of drill bit 12 substantially corresponds to the inner profile IP
of casing bit CB, both of which form a so-called "inverted cone."
Put another way, the drilling profile P slopes longitudinally
upwardly from the outer diameter of the drill bit 12 (oriented as
shown in the drawing figure) toward the center of the drill bit 12.
Therefore, as the drill bit 12 engages the inner profile IP of
casing bit CB, the drill bit 12 may be, at least partially,
positioned by the respective geometries of the drilling profile P
of the drill bit 12 and the inner profile IP of the casing bit CB.
In addition, because the cutting elements 36 of the drill bit 12
contact the inner profile IP of the casing bit CB substantially
uniformly, the torque generated in response to the contact may be
distributed, to some extent, more equally upon the drill bit
12.
[0051] As also shown in FIG. 11, the outer profile OP of casing bit
CB of wellbore assembly W may have a geometry, such as an inverted
cone geometry, that substantially corresponds to the drilling
profile P of drill bit 12. In FIG. 5, all the cutting elements 36
are shown on each side (with respect to the central axis of the
drill bit 12) of the drill bit 12, and are shown as if all the
cutting elements 36 were rotated into a single plane. Thus, the
lower surfaces (cutting edges areas) of the overlapping cutting
elements 36 form the drilling profile P of drill bit 12, the
drilling profile P referring to the drilling envelope formed by a
full rotation of the drill bit 12 about its drilling axis (not
shown).
[0052] As a further aspect of the present invention, a casing bit
of the present invention may be configured as a reamer. A reamer is
an apparatus that drills initially at a first smaller diameter and
subsequently at a second, larger diameter. Although the present
invention may refer to a "drill bit," the term "drill bit" as used
herein also encompasses the structures which are referred to
conventionally as casing bits, reamers and casing bit reamers.
[0053] Although the foregoing description contains many specifics,
these should not be construed as limiting the scope of the present
invention, but merely as providing illustrations of some exemplary
embodiments. Similarly, other embodiments of the invention may be
devised which do not depart from the spirit or scope of the present
invention. Features from different embodiments may be employed in
combination. The scope of the invention is, therefore, indicated
and limited only by the appended claims and their legal
equivalents, rather than by the foregoing description. All
additions, deletions, and modifications to the invention, as
disclosed herein, which fall within the meaning and scope of the
claims are to be embraced thereby.
* * * * *