U.S. patent application number 17/286979 was filed with the patent office on 2021-12-16 for matching of primary cutter with backup cutter.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Shilin Chen.
Application Number | 20210388678 17/286979 |
Document ID | / |
Family ID | 1000005854356 |
Filed Date | 2021-12-16 |
United States Patent
Application |
20210388678 |
Kind Code |
A1 |
Chen; Shilin |
December 16, 2021 |
MATCHING OF PRIMARY CUTTER WITH BACKUP CUTTER
Abstract
A multi-layer downhole drilling tool designed for drilling a
wellbore including a plurality of formations is disclosed,
including a bit body; blades disposed on exterior portions of the
bit body; first layer cutting elements disposed on the exterior
portions of the blades, the first layer cutting elements extending
a first distance along a first direction and a second distance
along a second direction, the first direction orthogonal to the
second direction, wherein the first distance is less than the
second distance; and second layer cutting elements disposed on the
exterior portions of the blades, at least one of the second layer
cutting elements track set with one first layer cutting element and
the second layer cutting elements extending a third distance along
the first direction and a fourth distance along the second
direction, the third distance is greater than or equal to the first
distance.
Inventors: |
Chen; Shilin; (Montgomery,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
1000005854356 |
Appl. No.: |
17/286979 |
Filed: |
December 13, 2018 |
PCT Filed: |
December 13, 2018 |
PCT NO: |
PCT/US2018/065482 |
371 Date: |
April 20, 2021 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 10/43 20130101 |
International
Class: |
E21B 10/43 20060101
E21B010/43 |
Claims
1. A multi-layer downhole drilling tool designed for drilling a
wellbore including a plurality of formations, comprising: a bit
body; a plurality of blades disposed on exterior portions of the
bit body; a plurality of first layer cutting elements disposed on
the exterior portions of the blades, each of the first layer
cutting elements extending a first distance along a first direction
and a second distance along a second direction, the first direction
orthogonal to the second direction, wherein the first distance is
less than the second distance; and a plurality of second layer
cutting elements disposed on the exterior portions of the blades,
at least one of the second layer cutting elements track set with
one first layer cutting element and each of the second layer
cutting elements extending a third distance along the first
direction and a fourth distance along the second direction, wherein
the third distance is greater than or equal to the first distance,
wherein the at least one of the second layer cutting elements track
set with the at least one first layer cutting element is larger
than the first layer cutting element is arranged such that the
second layer cutting element engages the formation when the track
set first layer cutting element is sufficiently worn.
2. The drilling tool of claim 1, wherein each of the plurality of
second layer cutting elements is track set with one first layer
cutting element.
3. The drilling tool of claim 1, wherein the at least one second
layer cutting element is larger than the track set first layer
cutting element.
4. The drilling tool of claim 2, wherein each second layer cutting
element track set with a first layer cutting element is larger than
the track set first layer cutting element.
5. The drilling tool of claim 1, wherein the at least one second
layer cutting element has a rectangular geometric shape, with
distal ends of the geometric shape along the second direction
having an arc and the track set first layer cutting element has a
rectangular geometric shape, with distal ends of the rectangular
geometric shape along the second direction having an arc.
6. The drilling tool of claim 2, wherein each second layer cutting
element track set with a first layer cutting element has a
rectangular geometric shape, with distal ends of the geometric
shape along the second direction having an arc and each track set
first layer cutting element has a rectangular geometric shape, with
distal ends of the rectangular geometric shape along the second
direction having an arc.
7. The drilling tool of claim 1, wherein the at least one second
layer cutting element has a circular geometric shape that is
truncated along the first direction and the track set first layer
cutting element has a circular geometric shape that is truncated
along the first direction.
8. The drilling tool of claim 2, wherein each second layer cutting
element track set with a first layer cutting element has a circular
geometric shape that is truncated along the first direction and
each track set first layer cutting element has a circular geometric
shape that is truncated along the first direction.
9. The drilling tool of claim 1, wherein the at least one second
layer cutting element has a circular geometric shape, and the track
set first layer cutting element has an elliptical geometric
shape.
10. The drilling tool of claim 2, wherein each second layer cutting
element track set with a first layer cutting element has a circular
geometric shape, and each track set first layer cutting element has
an elliptical geometric shape.
11. The drilling tool of claim 1, wherein the at least one second
layer cutting element has a first elliptical geometric shape, and
the track set first layer cutting element has a second elliptical
geometric shape.
12. The drilling tool of claim 2, wherein each second layer cutting
element track set with a first layer cutting element has a first
elliptical geometric shape, and each track set first layer cutting
element has a second elliptical geometric shape.
13. The drilling tool of claim 1, wherein one of the at least one
second layer cutting element or the track set first layer cutting
element has a conical shape and the other has a circular geometric
shape or an elliptical geometric shape.
14. The drilling tool of claim 2, where, for each second layer
cutting element and its track set first layer cutting element, one
of the second layer cutting element and the track set first layer
cutting element has a conical shape and the other has a circular
geometric shape or an elliptical geometric shape.
15. The drilling tool of claim 1, wherein the second distance is
greater than or equal to the fourth distance.
16. A downhole drilling system, comprising: a drill string; a drill
bit coupled to the drill string, the drill bit including: a bit
body; a plurality of blades disposed on exterior portions of the
bit body; a plurality of first layer cutting elements disposed on
the exterior portions of the blades, each of the first layer
cutting elements extending a first distance along a first direction
and a second distance along a second direction, the first direction
orthogonal to the second direction, wherein the first distance is
less than the second distance; and a plurality of second layer
cutting elements disposed on the exterior portions of the blades,
at least one of the second layer cutting elements track set with
one first layer cutting element and each of the second layer
cutting elements extending a third distance along the first
direction and a fourth distance along the second direction, wherein
the third distance is greater than or equal to the first distance,
wherein the at least one of the second layer cutting elements track
set with the at least one first layer cutting element is larger
than the first layer cutting element is arranged such that the
second layer cutting element engages the formation when the track
set first layer cutting element is sufficiently worn.
17. The drilling system of claim 16, wherein each of the plurality
of second layer cutting elements is track set with one first layer
cutting element.
18. The drilling system of claim 16, wherein the at least one
second layer cutting element is larger than the track set first
layer cutting element.
19. The drilling system of claim 18, wherein each second layer
cutting element track set with a first layer cutting element is
larger than the track set first layer cutting element.
20. The drilling system of claim 16, wherein the at least one
second layer cutting element has a rectangular geometric shape,
with distal ends of the geometric shape along the second direction
having an arc and the track set first layer cutting element has a
rectangular geometric shape, with distal ends of the rectangular
geometric shape along the second direction having an arc.
Description
TECHNICAL FIELD
[0001] The present disclosure relates generally to downhole
drilling tools and, more particularly, to rotary drill bits and
methods for designing rotary drill bits with multi-layer cutting
elements.
BACKGROUND
[0002] Various types of downhole drilling tools including, but not
limited to, rotary drill bits, reamers, core bits, and other
downhole tools. Typical formations in which downhole drilling tools
are used may generally have a relatively low compressive strength
in the upper portions (e.g., lesser drilling depths) of the
formation and a relatively high compressive strength in the lower
portions (e.g., greater drilling depths) of the formation. Thus, it
typically becomes increasingly more difficult to drill at
increasingly greater depths. Additionally, cutting elements on the
drill bit may experience increased wear as drilling depth
increases.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] A more complete understanding of the present disclosure and
its features and advantages thereof may be acquired by referring to
the following description, taken in conjunction with the
accompanying drawings, in which like reference numbers indicate
like features, and wherein:
[0004] FIG. 1 is an elevation view of a drilling system in which a
rotary drill bit may be used;
[0005] FIG. 2 is an isometric view of a rotary drill bit oriented
upwardly in a manner often used to model or design fixed cutter
drill bits;
[0006] FIG. 3A is a perspective view of cutting elements of a
rotary drill bit without wear;
[0007] FIG. 3B is a perspective view of cutting elements of a
rotary drill bit with little wear;
[0008] FIG. 3C is a perspective view of cutting elements of a
rotary drill bit with substantial wear;
[0009] FIG. 4A is a perspective view of cutting elements of a
rotary drill bit without wear;
[0010] FIG. 4B is a perspective view of cutting elements of a
rotary drill bit with little wear;
[0011] FIG. 4C is a perspective view of cutting elements of a
rotary drill bit with substantial wear;
[0012] FIG. 5A is a perspective view of cutting elements of a
rotary drill bit without wear;
[0013] FIG. 5B is a perspective view of cutting elements of a
rotary drill bit with little wear;
[0014] FIG. 5C is a perspective view of cutting elements of a
rotary drill bit with substantial wear;
[0015] FIG. 6A is a perspective view of cutting elements of a
rotary drill bit having a conical shape;
[0016] FIG. 6B is a perspective view of cutting elements of a
rotary drill bit having a conical shape;
[0017] FIG. 7 is a flow chart of an example method for designing
rotary drill bits with multi-layer cutting elements;
[0018] FIGS. 8A-8I illustrate schematic drawings of bit faces of a
rotary drill bit, in accordance with some embodiments of the
present disclosure;
[0019] FIGS. 9A-9F illustrate schematic drawings of bit faces of a
rotary drill bit with placements for back-up cutting elements, in
accordance with some embodiments of the present disclosure; and
[0020] FIG. 10 illustrates a bit profile of a drill bit having
track set cutting elements.
DETAILED DESCRIPTION
[0021] The present disclosure relates to rotary drill bits in which
cutting elements are arranged in multiple layers on blades of the
drill bit such that back-up (second) layer cutting elements engage
formations when primary (first) layer cutting elements are
sufficiently worn. The second layer cutting elements can be greater
in size than the first layer cutting elements. The first and the
second layer cutting elements can have the same shape as well.
[0022] Embodiments of the present disclosure and its advantages are
best understood by referring to FIGS. 1-10, where like numbers are
used to indicate like and corresponding parts.
[0023] FIG. 1 is an elevation view of an example drilling system
100. Drilling system 100 is configured to drill into one or more
geological formations. Drilling system 100 may include well surface
or well site 106. Various types of drilling equipment such as a
rotary table, mud pumps and mud tanks (not expressly shown) may be
located at a well surface sometimes referred to as "well site" 106.
For example, well site 106 may include drilling rig 102 that may
have various characteristics and features associated with a "land
drilling rig." However, downhole drilling tools incorporating
teachings of the present disclosure may be satisfactorily used with
drilling equipment located on offshore platforms, drill ships,
semi-submersibles and drilling barges (not expressly shown).
[0024] Drilling system 100 may include drill string 103 associated
with rotary drill bit 101 that may be used to rotate rotary drill
bit 101 in radial direction 105 around bit rotational axis 104 of
form a wide variety of wellbores 114 such as generally vertical
wellbore 114a or generally horizontal wellbore 114b as shown in
FIG. 1. Various directional drilling techniques and associated
components of bottom hole assembly (BHA) 120 of drill string 103
may be used to form generally horizontal wellbore 114b. For
example, lateral forces may be applied to drill bit 101 proximate
kickoff location 113 to form generally horizontal wellbore 114b
extending from generally vertical wellbore 114a. Wellbore 114 is
drilled to a drilling distance, which is the distance between the
well surface and the furthest extent of wellbore 114, and which
increases as drilling progresses.
[0025] BHA 120 may be formed from a wide variety of components
configured to form a wellbore 114. For example, components 122a,
122b and 122c of BHA 120 may include, but are not limited to rotary
drill bit 101, drill collars, rotary steering tools, directional
drilling tools, downhole drilling motors, reamers, hole enlargers
or stabilizers. The number of components such as drill collars and
different types of components 122 included in BHA 120 may depend
upon anticipated downhole drilling conditions and the type of
wellbore that will be formed by drill string 103 and fixed-cutter
drill bit 101.
[0026] Wellbore 114 may be defined in part by casing string 110
that may extend from well site 106 to a selected downhole location.
Various types of drilling fluid may be pumped from well site 106
through drill string 103 to attached drill bit 101. Such drilling
fluids may be directed to flow from drill string 103 to respective
nozzles included in rotary drill bit 101. The drilling fluid may be
circulated back to well surface 106 through annulus 108 defined in
part by outside diameter 112 of drill string 103 and inside
diameter 111 of casing string 110.
[0027] Drilling system 100 may also include rotary drill bit
("drill bit") 101. Drill bit 101, discussed in further detail in
FIG. 2, may include one or more blades 126 that may be disposed
outwardly from exterior portions of rotary bit body 124 of drill
bit 101. Rotary bit body 124 may have a generally cylindrical body
and blades 126 may be any suitable type of projections extending
outwardly from rotary bit body 124. Drill bit 101 may rotate with
respect to bit rotational axis 104 in a direction defined by
directional arrow 105. Blades 126 may include one or more cutting
elements 128 disposed outwardly from exterior portions of each
blade 126. Blades 126 may include one or more depth of cut
controllers (not expressly shown) configured to control the depth
of cut of cutting elements 128. Blades 126 may further include one
or more gage pads (not expressly shown) disposed on blades 126.
Drill bit 101 may be designed and formed in accordance with
teachings of the present disclosure and may have many different
designs, configurations, and/or dimensions according to the
particular application of drill bit 101.
[0028] Drilling system 100 may include one or more second layer
cutting elements on a drill bit that are configured to cut into the
geological formation at particular drilling depths and/or when
first layer cutting elements experience sufficient wear. Thus,
multiple layers of cutting elements may exist that engage with the
formation at multiple drilling depths. Placement and configuration
of the first layer and second layer cutting elements on blades of a
drill bit may be varied to enable the different layers to engage at
specific drilling depths. For example, configuration considerations
may include under-exposure and blade placement of second layer
cutting elements with respect to first layer cutting elements,
and/or characteristics of the formation to be drilled.
[0029] Cutting elements may be arranged in multiple layers on
blades such that second layer cutting elements may engage the
formation when the depth of cut is greater than a specified value
and/or when first layer cutting elements are sufficiently worn. In
some embodiments, the drilling tools may have first layer cutting
elements arranged on blades in a single-set or a track-set
configuration. Second layer cutting elements may be arranged on
different blades that are track-set and under-exposed with respect
to the first layer cutting elements. In some embodiments, the
amount of under-exposure may be approximately the same for each of
the second layer cutting elements. In other embodiments, the amount
of under-exposure may vary for each of the second layer cutting
elements.
[0030] FIG. 2 illustrates an isometric view of rotary drill bit 101
oriented upwardly in a manner often used to model or design fixed
cutter drill bits, in accordance with some embodiments of the
present disclosure. Drill bit 101 may be any of various types of
fixed cutter drill bits, including PDC bits, drag bits, matrix
drill bits, and/or steel body drill bits operable to form wellbore
114 extending through one or more downhole formations. Drill bit
101 may be designed and formed in accordance with teachings of the
present disclosure and may have many different designs,
configurations, and/or dimensions according to the particular
application of drill bit 101.
[0031] Drill bit 101 may include one or more blades 126 (e.g.,
blades 126a-126g) that may be disposed outwardly from exterior
portions of rotary bit body 124 of drill bit 101. Rotary bit body
124 may have a generally cylindrical body and blades 126 may be any
suitable type of projections extending outwardly from rotary bit
body 124. For example, a portion of blade 126 may be directly or
indirectly coupled to an exterior portion of bit body 124, while
another portion of blade 126 is projected away from the exterior
portion of bit body 124. Blades 126 formed in accordance with
teachings of the present disclosure may have a wide variety of
configurations including, but not limited to, substantially arched,
helical, spiraling, tapered, converging, diverging, symmetrical,
and/or asymmetrical.
[0032] In some cases, blades 126 may have substantially arched
configurations, generally helical configurations, spiral shaped
configurations, or any other configuration satisfactory for use
with each downhole drilling tool. One or more blades 126 may have a
substantially arched configuration extending from proximate
rotational axis 104 of drill bit 101. The arched configuration may
be defined in part by a generally concave, recessed shaped portion
extending from proximate bit rotational axis 104. The arched
configuration may also be defined in part by a generally convex,
outwardly curved portion disposed between the concave, recessed
portion and exterior portions of each blade which correspond
generally with the outside diameter of the rotary drill bit.
[0033] Each of blades 126 may include a first end disposed
proximate or toward bit rotational axis 104 and a second end
disposed proximate or toward exterior portions of drill bit 101
(e.g., disposed generally away from bit rotational axis 104 and
toward uphole portions of drill bit 101). The terms "uphole" and
"downhole" may be used to describe the location of various
components of drilling system 100 relative to the bottom or end of
wellbore 114 shown in FIG. 1. For example, a first component
described as uphole from a second component may be further away
from the end of wellbore 114 than the second component. Similarly,
a first component described as being downhole from a second
component may be located closer to the end of wellbore 114 than the
second component.
[0034] Blades 126a-126g may include primary blades disposed about
the bit rotational axis. For example, in FIG. 2, blades 126a, 126c,
and 126e may be primary blades or major blades because respective
first ends 141 of each of blades 126a, 126c, and 126e may be
disposed closely adjacent to associated bit rotational axis 104. In
some embodiments, blades 126a-126g may also include at least one
secondary blade disposed between the primary blades. Blades 126b,
126d, 126f, and 126g shown in FIG. 2 on drill bit 101 may be
secondary blades or minor blades because respective first ends 141
may be disposed on downhole end 151 a distance from associated bit
rotational axis 104. The number and location of secondary blades
and primary blades may vary such that drill bit 101 includes more
or less secondary and primary blades. Blades 126 may be disposed
symmetrically or asymmetrically with regard to each other and bit
rotational axis 104 where the disposition may be based on the
downhole drilling conditions of the drilling environment. In some
cases, blades 126 and drill bit 101 may rotate about rotational
axis 104 in a direction defined by directional arrow 105.
[0035] Each blade may have a leading (or front) surface disposed on
one side of the blade in the direction of rotation of drill bit 101
and a trailing (or back) surface disposed on an opposite side of
the blade away from the direction of rotation of drill bit 101.
Blades 126 may be positioned along bit body 124 such that they have
a spiral configuration relative to rotational axis 104. In other
embodiments, blades 126 may be positioned along bit body 124 in a
generally parallel configuration with respect to each other and bit
rotational axis 104.
[0036] Blades 126 may include one or more cutting elements 128
disposed outwardly from exterior portions of each blade 126. For
example, a portion of cutting element 128 may be directly or
indirectly coupled to an exterior portion of blade 126 while
another portion of cutting element 128 may be projected away from
the exterior portion of blade 126. Cutting elements 128 may be any
suitable device configured to cut into a formation, including but
not limited to, primary cutting elements, back-up cutting elements,
secondary cutting elements or any combination thereof. By way of
example and not limitation, cutting elements 128 may be various
types of cutters, compacts, buttons, inserts, and gage cutters
satisfactory for use with a wide variety of drill bits 101.
[0037] Cutting elements 128 may include respective substrates with
a layer of hard cutting material disposed on one end of each
respective substrate. The hard layer of cutting elements 128 may
provide a cutting surface that may engage adjacent portions of a
downhole formation to form wellbore 114. The contact of the cutting
surface with the formation may form a cutting zone associated with
each of cutting elements 128. The edge of the cutting surface
located within the cutting zone may be referred to as the cutting
edge of a cutting element 128.
[0038] Each substrate of cutting elements 128 may have various
configurations and may be formed from tungsten carbide or other
materials associated with forming cutting elements for rotary drill
bits. Tungsten carbides may include, but are not limited to,
monotungsten carbide (WC), ditungsten carbide (W.sub.2C),
macrocrystalline tungsten carbide and cemented or sintered tungsten
carbide. Substrates may also be formed using other hard materials,
which may include various metal alloys and cements such as metal
borides, metal carbides, metal oxides and metal nitrides. For some
applications, the hard cutting layer may be formed from
substantially the same materials as the substrate. In other
applications, the hard cutting layer may be formed from different
materials than the substrate. Examples of materials used to form
hard cutting layers may include polycrystalline diamond materials,
including synthetic polycrystalline diamonds.
[0039] In some embodiments, blades 126 may also include one or more
depth of cut controllers (DOCCs) (not expressly shown) configured
to control the depth of cut of cutting elements 128. A DOCC may
comprise an impact arrestor, a back-up cutting element and/or an
MDR (Modified Diamond Reinforcement). Exterior portions of blades
126, cutting elements 128 and DOCCs (not expressly shown) may form
portions of the bit face.
[0040] Blades 126 may further include one or more gage pads (not
expressly shown) disposed on blades 126. A gage pad may be a gage,
gage segment, or gage portion disposed on exterior portion of blade
126. Gage pads may often contact adjacent portions of wellbore 114
formed by drill bit 101. Exterior portions of blades 126 and/or
associated gage pads may be disposed at various angles, positive,
negative, and/or parallel, relative to adjacent portions of
generally vertical wellbore 114a. A gage pad may include one or
more layers of hardfacing material.
[0041] Uphole end 150 of drill bit 101 may include shank 152 with
drill pipe threads 155 formed thereon. Threads 155 may be used to
releasably engage drill bit 101 with BHA 120, described in detail
below, whereby drill bit 101 may be rotated relative to bit
rotational axis 104. Downhole end 151 of drill bit 101 may include
a plurality of blades 126a-126g with respective junk slots or fluid
flow paths 240 disposed therebetween. Additionally, drilling fluids
may be communicated to one or more nozzles 156.
[0042] Drill bit operation may be expressed in terms of depth of
cut per revolution as a function of drilling depth. Depth of cut
per revolution, or "depth of cut," may be determined by rate of
penetration (ROP) and revolution per minute (RPM). ROP may
represent the amount of formation that is removed as drill bit 101
rotates and may be in units of ft/hr. Further, RPM may represent
the rotational speed of drill bit 101. For example, drill bit 101
utilized to drill a formation may rotate at approximately 120 RPM.
Actual depth of cut (A) may represent a measure of the depth that
cutting elements cut into the formation during a rotation of drill
bit 101. Thus, actual depth of cut may be expressed as a function
of actual ROP and RPM using the following equation:
.DELTA.=ROP/(5*RPM).
[0043] Actual depth of cut may have a unit of in/rev.
[0044] Multiple formations of varied formation strength may be
drilled using drill bits configured in accordance with some
embodiments of the present disclosure. As drilling depth increases,
formation strength may likewise increase. For example, a first
formation may extend from the surface to a drilling depth of
approximately 3000 feet and may have a rock strength of
approximately 10,000 pounds per square inch (psi). Additionally, a
second formation may extend from a drilling depth of approximately
3,000 feet to a drilling depth of approximately 5,000 feet and may
have rock strength of approximately 15,000 psi. As another example,
a third formation may extend from a drilling depth of approximately
5,000 feet to a drilling depth of approximately 6,000 feet and may
have a rock strength over approximately 20,000 psi.
[0045] With increased drilling depth, formation strength or rock
strength may increase or decrease and thus, the formation may
become more difficult or may become easier to drill. For example, a
drill bit including seven blades may drill through the first
formation very efficiently, but a drill bit including nine blades
may be desired to drill through the second and third
formations.
[0046] Accordingly, as drill bit 101 drills into a formation, the
cutting elements 128 may begin to wear as the drilling depth
increases.
[0047] FIGS. 3A-3C illustrate a first layer cutting element 302a
and a second layer cutting element 302b (collectively referred to
as cutting elements 302). For simplicity of illustration, the first
layer cutting element 302a is illustrated as overlaid with the
second layer cutting element 302b, and the second layer cutting
element 302b illustrated separately as well. The first layer
cutting element 302a and the second layer cutting element 302b can
be similar to the cutting elements 128 described above with respect
to FIG. 1.
[0048] FIG. 3A illustrates the cutting elements 302 prior to wear
on the cutting elements 302, and specifically, wear on the first
layer cutting element 302a. The cutting elements 302 can extend
along a first direction 310 and a second direction 312, with the
second direction 312 being orthogonal to the first direction
310.
[0049] The first layer cutting element 302a can extend along the
first direction 310 a distance 380 and along the second direction
312 a distance 382. In some examples, the distance 380 is less than
the distance 382. In some examples, the first layer cutting element
302a has a rectangular geometric shape, with distal ends 320a, 320b
(collectively referred to as distal ends 320) along the second
direction 312 having an arc.
[0050] In some examples, the first layer cutting element 302a has a
circular geometric shape that is truncated along the first
direction 310. Specifically, the first layer cutting element 302a
is truncated, forming substantially planar sides 360.
[0051] The second layer cutting element 302b can extend along the
first direction 310 a distance 390 and along the second direction
312 a distance 392. In some examples, the distance 390 is less than
the distance 392. In some examples, the second layer cutting
element 302b has a rectangular geometric shape, with distal ends
322a, 322b (collectively referred to as distal ends 322) along the
second direction 312 having an arc. In some examples, the distance
390 is greater than or equal to the distance 380. In some examples,
the distance 382 is greater than or equal to the distance 392.
[0052] In some examples, the second layer cutting element 302b has
a circular geometric shape that is truncated along the first
direction 310. Specifically, the second layer cutting element 302b
is truncated, forming substantially planar sides 370.
[0053] To that end, the second layer cutting element 302b can be
underexposed relative to the first layer cutting element 302a,
e.g., underexposed a distance .delta..sub.1. That is, the second
layer cutting element 302b can be positioned relative to the first
layer cutting element 302a such that the second layer cutting
element 302b does not cut into the formations until a particular
drilling depth is achieved, e.g., based on the distance
.delta..sub.1
[0054] FIG. 3B illustrates the cutting elements 302 at a first
level of wear. In some examples, the first level of wear can be
substantially the same as the amount of underexposure of the second
layer cutting element 302b with respect to the first layer cutting
element 302a, e.g., the distance .delta..sub.1. As illustrated, the
first layer cutting element 302a, at the first level of wear,
includes a first worn edge 330 that includes (non-efficient)
cutting zones 332. Additionally, the second layer cutting element
302b includes a first cutting edge 334. In some examples, the first
layer cutting element 302a can serve as the major cutter, while the
second layer cutting element 302b can begin to serve as an active
cutter.
[0055] FIG. 3C illustrates the cutting elements 302 at a second
level of wear. In some examples, the second level of wear is
greater than the amount of underexposure of the second layer
cutting element 302b with respect to the first layer cutting
element 302a, e.g., the distance .delta..sub.1. As illustrated, the
first layer cutting element 302, at the second level of wear,
includes a second worn edge 340. Additionally, the second layer
cutting element 302b includes a second cutting edge 342. In some
examples, the second worn edge 340 of the first layer cutting
element 302a and the second cutting edge 342 of the second layer
cutting element 302b are at a substantially same radially position
from a center of the drill bit 101. In some examples, the first
layer cutting element 302a and the second layer cutting element
302b can both serve as major cutters.
[0056] FIGS. 4A-4C illustrate a first layer cutting element 402a
and a second layer cutting element 402b (collectively referred to
as cutting elements 402). For simplicity of illustration, the first
layer cutting element 402a is illustrated as overlaid with the
second layer cutting element 402b, and the second layer cutting
element 402b illustrated separately as well. The first layer
cutting element 402a and the second layer cutting element 402b can
be similar to the cutting elements 128 described above with respect
to FIG. 1.
[0057] FIG. 4A illustrates the cutting elements 402 prior to wear
on the cutting elements 402, and specifically, wear on the first
layer cutting element 402a. The cutting elements 402 can extend
along a first direction 410 and a second direction 412, with the
second direction 412 being orthogonal to the first direction
410.
[0058] The first layer cutting element 402a can extend along the
first direction 410 a distance 480 and along the second direction
412 a distance 482. In some examples, the distance 480 is less than
the distance 482. In some examples, the first layer cutting element
402a has an elliptical geometric shape.
[0059] The second layer cutting element 402b can extend along the
first direction 410 a distance 490 and along the second direction
412 a distance 492. In some examples, the second layer cutting
element 402b has a circular geometric shape. In some examples, the
distance 490 is greater than or equal to the distance 480. In some
examples, the distance 482 is greater than or equal to the distance
492.
[0060] To that end, the second layer cutting element 402b can be
underexposed relative to the first layer cutting element 402a,
e.g., underexposed a distance .delta..sub.2. That is, the second
layer cutting element 402b can be positioned relative to the first
layer cutting element 402a such that the second layer cutting
element 402b does not cut into the formations until a particular
drilling depth is achieved, e.g., based on the distance
.delta..sub.2.
[0061] FIG. 4B illustrates the cutting elements 402 at a first
level of wear. In some examples, the first level of wear can be
substantially the same as the amount of underexposure of the second
layer cutting element 402b with respect to the first layer cutting
element 402a, e.g., the distance .delta..sub.2. As illustrated, the
first layer cutting element 402, at the first level of wear,
includes a first worn edge 440 that includes (non-efficient)
cutting zones 442. Additionally, the second layer cutting element
402b includes a first cutting edge 444. In some examples, the first
layer cutting element 402a can serve as the major cutter, while the
second layer cutting element 402b can begin to serve as an active
cutter.
[0062] FIG. 4C illustrates the cutting elements 402 at a second
level of wear. In some examples, the second level of wear is
greater than the amount of underexposure of the second layer
cutting element 402b with respect to the first layer cutting
element 402a, e.g., the distance .delta..sub.2. As illustrated, the
first layer cutting element 402a, at the second level of wear,
includes a second worn edge 460. Additionally, the second layer
cutting element 402b includes a second cutting edge 462. In some
examples, the second worn edge 460 of the first layer cutting
element 402a and the second cutting edge 462 of the second layer
cutting element 402b are at a substantially same radially position
from a center of the drill bit 101. In some examples, the first
layer cutting element 402a and the second layer cutting element
402b can both serve as major cutters.
[0063] FIGS. 5A-5C illustrate a first layer cutting element 502a
and a second layer cutting element 502b (collectively referred to
as cutting elements 502). For simplicity of illustration, the first
layer cutting element 502a is illustrated as overlaid with the
second layer cutting element 502b, and the second layer cutting
element 502b illustrated separately as well. The first layer
cutting element 502a and the second layer cutting element 502b can
be similar to the cutting elements 128 described above with respect
to FIG. 1.
[0064] FIG. 5A illustrates the cutting elements 502 prior to wear
on the cutting elements 502, and specifically, wear on the first
layer cutting element 502a. The cutting elements 502 can extend
along a first direction 510 and a second direction 512, with the
second direction 512 being orthogonal to the first direction
510.
[0065] The first layer cutting element 502a can extend along the
first direction 510 a distance 580 and along the second direction
512 a distance 582. In some examples, the distance 580 is less than
the distance 582. In some examples, the first layer cutting element
502a has a first elliptical geometric shape.
[0066] The second layer cutting element 502b can extend along the
first direction 510 a distance 590 and along the second direction
512 a distance 592. In some examples, the distance 590 is less than
the distance 592. In some examples, the second layer cutting
element 502b has a second elliptical geometric shape that differs
from the first elliptical geometric shape of the first layer
cutting element 502a. In some examples, the distance 590 is greater
than or equal to the distance 580. In some examples, the distance
582 is greater than or equal to the distance 592.
[0067] To that end, the second layer cutting element 502b can be
underexposed relative to the first layer cutting element 502a,
e.g., underexposed a distance .delta..sub.3. That is, the second
layer cutting element 502b can be positioned relative to the first
layer cutting element 502a such that the second layer cutting
element 502b does not cut into the formations until a particular
drilling depth is achieved, e.g., based on the distance
.delta..sub.3.
[0068] FIG. 5B illustrates the cutting elements 502 at a first
level of wear. In some examples, the first level of wear can be
substantially the same as the amount of underexposure of the second
layer cutting element 502b with respect to the first layer cutting
element 502a, e.g., the distance .delta..sub.3. As illustrated, the
first layer cutting element 502, at the first level of wear,
includes a first worn edge 540 that includes cutting zones 542.
Additionally, the second layer cutting element 502b includes a
first cutting edge 544. In some examples, the first layer cutting
element 502a can serve as the major cutter, while the second layer
cutting element 502b can begin to serve as an active cutter.
[0069] FIG. 5C illustrates the cutting elements 502 at a second
level of wear. In some examples, the second level of wear is
greater than the amount of underexposure of the second layer
cutting element 502b with respect to the first layer cutting
element 502a, e.g., the distance .delta..sub.3. As illustrated, the
first layer cutting element 502a, at the second level of wear,
includes a second worn edge 560. Additionally, the second layer
cutting element 502b includes a second cutting edge 562. In some
examples, the second worn edge 560 of the first layer cutting
element 502a and the second cutting edge 562 of the second layer
cutting element 502b are at a substantially same radially position
from a center of the drill bit 101. In some examples, the first
layer cutting element 502a and the second layer cutting element
502b can both serve as major cutters.
[0070] FIGS. 6A, 6B illustrate a first layer cutting element 602a
and a second layer cutting element 602b (collectively referred to
as cutting elements 602). For simplicity of illustration, the first
layer cutting element 602a is illustrated as overlaid with the
second layer cutting element 602b, and the second layer cutting
element 602b illustrated separately as well. The first layer
cutting element 602a and the second layer cutting element 602b can
be similar to the cutting elements 128 described above with respect
to FIG. 1.
[0071] FIG. 6A illustrates the cutting elements 602 prior to wear
on the cutting elements 602, and specifically, wear on the first
layer cutting element 602a. The cutting elements 602 can extend
along a first direction 610 and a second direction 612, with the
second direction 612 being orthogonal to the first direction
610.
[0072] The first layer cutting element 602a can include a conical
shape along the second direction 612. The first layer cutting
element 602b can include a circular geometric shape, or an
elliptical geometric shape.
[0073] To that end, the second layer cutting element 602b can be
underexposed relative to the first layer cutting element 602a,
e.g., underexposed a distance .delta..sub.4. That is, the second
layer cutting element 602b can be positioned relative to the first
layer cutting element 602a such that the second layer cutting
element 602b does not cut into the formations until a particular
drilling depth is achieved, e.g., based on the distance
.delta..sub.4.
[0074] Referring to FIG. 6B, in some examples, the second layer
cutting element 602b can include a conical shape along the second
direction 612; and the first layer cutting element 602a can include
a circular geometric shape, or an elliptical geometric shape.
[0075] FIG. 7 illustrates a flow chart of an example method 700 for
designing rotary drill bits with multi-layer cutting elements. The
steps of method 700 may be performed by various computer programs,
models or any combination thereof, configured to simulate and
design drilling systems, apparatuses and devices. The programs and
models may include instructions stored on a computer readable
medium and operable to perform, when executed, one or more of the
steps described below. The computer readable media may include any
system, apparatus or device configured to store and retrieve
programs or instructions such as a hard disk drive, a compact disc,
flash memory or any other suitable device. The programs and models
may be configured to direct a processor or other suitable unit to
retrieve and execute the instructions from the computer readable
media. Collectively, the computer programs and models used to
simulate and design drilling systems may be referred to as a
"drilling engineering tool" or "engineering tool."
[0076] For illustrative purposes, method 700 is described with
respect to drill bit 101 and cutting elements 302, 402, 502,
602.
[0077] Method 700 may start, and at step 702, the engineering tool
may place first layer cutting elements (e.g., cutting elements
302a, 402a, 502a, and/or 602a) on blades 126 disposed on exterior
portions of bit body 124. In some examples, the first layer cutting
elements extend along a first direction and a second direction,
with the first direction being orthogonal to the second direction.
At step 704, the engineering tool defines a first distance that
each of the first layer cutting elements (e.g., cutting elements
302a, 0402a, 502a, and/or 602a) extend along the first direction.
At step 706, the engineering tool defines a second distance that
each of the first layer cutting elements (e.g., cutting elements
302a, 402a, 502a, and/or 602a) extend along the second direction.
In some examples, the first distance is less than the second
distance. At step 708, the engineering tool configures the first
layer cutting elements (e.g., cutting elements 302a, 402a, 502a,
and/or 602a) based on the first distance and the second
distance.
[0078] At step 710, the engineering tool places second layer
cutting elements (e.g., cutting elements 302b, 402b, 502b, and/or
602b) on blades 126 disposed on exterior portions of bit body 124.
In some examples, the second layer cutting elements extend along
the first direction and the second direction, with the first
direction being orthogonal to the second direction. At step 712,
the engineering tool defines a third distance that each of the
second layer cutting elements (e.g., cutting elements 302b, 402b,
502b, and/or 602b) extend along the first direction. At step 714,
the engineering tool defines a fourth distance that each of the
second layer cutting elements (e.g., cutting elements 302b, 402b,
502b, and/or 602b) extend along the second direction. In some
examples, the third distance is greater than or equal to the first
distance. At step 716, the engineering tool configures the second
layer cutting elements (e.g., cutting elements 302b, 402b, 502b,
and/or 602b) based on the third distance and the fourth
distance.
[0079] FIGS. 8A-8I illustrate schematic drawings of bit faces of
drill bit 801, which can be similar to drill bit 101. Specifically,
FIGS. 8A-8I can illustrate placements for first layer cutting
elements 828 (similar to any of first layer cutting elements 302a,
402a, 502a, 602a) and second layer cutting elements 838 (similar to
any of second layer cutting elements 302b, 402b, 502b, 602b).
[0080] For purposes of this disclosure, blades 826, similar to
blades 126, may be numbered l-n based on the blade configuration.
For example, FIGS. 8A-8I depict eight-bladed drill bits 801a-801i
and blades 826 may be numbered 1-8. However, drill bit 801a-801i
may include more or fewer blades than shown in FIGS. 8A-8I without
departing from the scope of the present disclosure. For an
eight-bladed drill bit, blades 1, 3, 5 and 7 may be primary blades,
and 2, 4, 6 and 8 may be secondary blades.
[0081] In FIGS. 8A-8D, first layer cutting element 828a with cutlet
point 830a may be located on blade 1 and first layer cutting
element 828c may be located on blade 3. Cutting elements 828a and
828c may be single set.
[0082] FIG. 8A illustrates second layer cutting element 838b and
control point P.sub.840b located on blade 2 of drill bit 801a such
that second layer cutting element 838b may be track set with first
layer cutting element 828a. Second layer cutting element 838d may
be located on blade 4 and may be track set with first layer cutting
element 828c. Because second layer cutting elements are located on
the blade rotationally in front of the corresponding first layer
cutting element, drill bit 801a may be described as front track
set.
[0083] FIG. 8B illustrates second layer cutting element 838h and
control point P.sub.840h located on blade 8 of drill bit 801b such
that second layer cutting element 838h may be track set with first
layer cutting element 828a. Second layer cutting element 838b may
be located on blade 2 and may be track set with first layer cutting
element 828c. Because second layer cutting elements are located on
the blade rotationally behind the corresponding first layer cutting
element, drill bit 801b may be described as behind track set.
[0084] FIG. 8C illustrates second layer cutting element 838f and
control point P.sub.840f located on blade 6 of drill bit 801c such
that second layer cutting element 838f may be track set with first
layer cutting element 828a. Second layer cutting element 838h may
be located on blade 8 and may be track set with first layer cutting
element 828c.
[0085] FIG. 8D illustrates second layer cutting element 838d and
control point P.sub.840d located on blade 4 of drill bit 801d such
that second layer cutting element 838d may be track set with first
layer cutting element 828a. Second layer cutting element 838f may
be located on blade 6 and may be track set with first layer cutting
element 828c.
[0086] In FIG. 8E, first layer cutting element 828a with cutlet
point 830a may be located on blade 1 of drill bit 801e and first
layer cutting element 828c may be located on blade 3 such that
cutting element 828c may be track set with first layer cutting
element 828a. First layer cutting elements 828e and 828g located on
blades 5 and 7, respectively, may also be track set. Second layer
cutting elements 838b and 838d, located on blades 2 and 4,
respectively, may be track set with first layer cutting elements
828a and 828c. Second layer cutting elements 838f and 838h, located
on blades 6 and 8, respectively, may be track set with first layer
cutting elements 828e and 828g. Second layer cutting element 838b
may include control point P.sub.840b. As such, cutting elements on
blades 1-4 may be track set (more specifically, front track set),
and cutting elements on blades 5-8 may be track set.
[0087] In FIG. 8F, first layer cutting element 828a with cutlet
point 830a may be located on blade 1 of drill bit 801f. First layer
cutting element 828g may be located on blade 7 and may be track set
with first layer cutting element 828a. First layer cutting elements
828c and 828e located on blades 3 and 5, respectively, may also be
track set. Second layer cutting elements 838f and 838h, located on
blades 6 and 8, respectively, may be track set with first layer
cutting elements 828a and 828g. Second layer cutting elements 838b
and 838d, located on blades 2 and 4, respectively, may be track set
with first layer cutting elements 828c and 828e. Second layer
cutting element 838h may include control point P.sub.840h. As such,
cutting elements on blades 2-5 may be track set (more specifically,
back track set), and cutting elements on blades 1 and 6-8 may be
track set.
[0088] FIG. 8G illustrates first layer cutting element 828a with
cutlet point 830a located on blade 1 of drill bit 801g. First layer
cutting element 828e may be located on blade 5 and may be track set
with first layer cutting element 828a. First layer cutting elements
828c and 828g located on blades 3 and 7, respectively, may also be
track set. Second layer cutting elements 838b and 838f, located on
blades 2 and 6, respectively, may be track set with first layer
cutting elements 828a and 828e. Second layer cutting elements 838d
and 838h, located on blades 4 and 8, respectively, may be track set
with first layer cutting elements 828c and 828g. Second layer
cutting element 838b may include control point P.sub.840b. As such,
cutting elements on blades 1, 2, 5 and 6 may be track set, and
cutting elements on blades 3, 4, 7, and 8 may be track set.
[0089] FIG. 8H illustrates first layer cutting element 828a with
cutlet point 830a located on blade 1 of drill bit 801h. First layer
cutting element 828g may be located on blade 7 and may be track set
with first layer cutting element 828a. First layer cutting elements
828c and 828e located on blades 3 and 5, respectively, may also be
track set. Second layer cutting elements 838d and 838h, located on
blades 4 and 8, respectively, may be track set with first layer
cutting elements 828a and 828g. Second layer cutting elements 838b
and 838f, located on blades 2 and 6, respectively, may be track set
with first layer cutting elements 828c and 828e. Second layer
cutting element 838d may include control point P.sub.840d. As such,
cutting elements on blades 1, 4, 7 and 8 may be track set, and
cutting elements on blades 2, 3, 5, 6 may be track set.
[0090] FIG. 8I illustrates first layer cutting element 828a with
cutlet point 830a located on blade 1 of drill bit 801i. First layer
cutting element 828e may be located on blade 5 and may be track set
with first layer cutting element 828a. First layer cutting elements
828c and 828g located on blades 3 and 7, respectively, may also be
track set. Second layer cutting elements 838b and 838f, located on
blades 2 and 6, respectively, may be track set. Second layer
cutting elements 838d and 838h, located on blades 4 and 8,
respectively, may be track set.
[0091] Accordingly, FIGS. 9A-9F illustrate schematic drawing of bit
faces of a drill bit with exemplary placements for first layer
cutting elements 928 (similar to any of first layer cutting
elements 302a, 402a, 502a, 602a) and back-up cutting elements 938
(similar to any of second layer cutting elements 302b, 402b, 502b,
602b), in accordance with some embodiments of the present
disclosure. For purposes of this disclosure, blades 926 may also be
numbered l-n based on the blade configuration. For example, FIGS.
9A-9F depict seven-bladed drill bits 901a-901f and blades 926 may
be numbered 1-7. However, drill bit 901a-901f may include more or
fewer blades than shown in FIGS. 9A-9F without departing from the
scope of the present disclosure.
[0092] For a seven-bladed drill bit, there may be six possible
blades 926 for placement of back-up cutting elements 938 in
accordance with some embodiments of the present disclosure. In
FIGS. 9A-9F, primary cutting elements 928a with cutlet points 930a
may be located on blade 1. FIG. 9A illustrates back-up cutting
elements 938b and control point P.sub.940b located on blade 2 of
drill bit 901a. FIG. 9B illustrates back-up cutting elements 938c
and control point P.sub.940c located on blade 3 of drill bit 901b.
FIG. 9C illustrates back-up cutting elements 938d and control point
P.sub.940d located on blade 4 of drill bit 901c. FIG. 9D
illustrates back-up cutting elements 938e and control point
P.sub.940e located on blade 5 of drill bit 901d. FIG. 9E
illustrates back-up cutting elements 938f and control point
P.sub.940f located on blade 6 of drill bit 901e. FIG. 9F
illustrates back-up cutting elements 938g and control point
P.sub.940g located on blade 7 of drill bit 901f.
[0093] FIG. 10 illustrates a bit profile of a bit (e.g., drill bit
101) having track set cutting elements. For example, when the
underexposure .delta. of the cutting element 1004 (similar to any
of second layer cutting elements 302b, 402b, 502b, 602b) with
respect to the cutting element 1002 (similar to any of first layer
cutting elements 302a, 402a, 502a, 602a) is equal to zero, cutting
elements 1002, 1004 have the same radial location along the bit
profile. Similar, cutting elements 1006, 1008 are also track
set.
[0094] The disclosure includes a multi-layer downhole drilling tool
designed for drilling a wellbore including a plurality of
formations, include a bit body; a plurality of blades disposed on
exterior portions of the bit body; a plurality of first layer
cutting elements disposed on the exterior portions of the blades,
each of the first layer cutting elements extending a first distance
along a first direction and a second distance along a second
direction, the first direction orthogonal to the second direction,
wherein the first distance is less than the second distance; and a
plurality of second layer cutting elements disposed on the exterior
portions of the blades, at least one of the second layer cutting
elements track set with one first layer cutting element and each of
the second layer cutting elements extending a third distance along
the first direction and a fourth distance along the second
direction, wherein the third distance is greater than or equal to
the first distance, wherein the at least one of the second layer
cutting elements track set with the at least one first layer
cutting element is larger than the first layer cutting element is
arranged such that the second layer cutting element engages the
formation when the track set first layer cutting element is
sufficiently worn.
[0095] The above embodiment may have one or more of the following
additional elements in any combination with one another or other
elements disclosed herein, unless clearly mutually exclusive:
Element 1: wherein each of the plurality of second layer cutting
elements is track set with one first layer cutting element. Element
2: wherein the at least one second layer cutting element is larger
than the track set first layer cutting element. Element 3: wherein
each second layer cutting element track set with a first layer
cutting element is larger than the track set first layer cutting
element. Element 4: wherein the at least one second layer cutting
element has a rectangular geometric shape, with distal ends of the
geometric shape along the second direction having an arc and the
track set first layer cutting element has a rectangular geometric
shape, with distal ends of the rectangular geometric shape along
the second direction having an arc. Element 5: wherein each second
layer cutting element track set with a first layer cutting element
has a rectangular geometric shape, with distal ends of the
geometric shape along the second direction having an arc and each
track set first layer cutting element has a rectangular geometric
shape, with distal ends of the rectangular geometric shape along
the second direction having an arc. Element 6: wherein the at least
one second layer cutting element has a circular geometric shape
that is truncated along the first direction and the track set first
layer cutting element has a circular geometric shape that is
truncated along the first direction. Element 7: wherein each second
layer cutting element track set with a first layer cutting element
has a circular geometric shape that is truncated along the first
direction and each track set first layer cutting element has a
circular geometric shape that is truncated along the first
direction. Element 8: wherein the at least one second layer cutting
element has a circular geometric shape, and the track set first
layer cutting element has an elliptical geometric shape. Element 9:
wherein each second layer cutting element track set with a first
layer cutting element has a circular geometric shape, and each
track set first layer cutting element has an elliptical geometric
shape. Element 10: wherein the at least one second layer cutting
element has a first elliptical geometric shape, and the track set
first layer cutting element has a second elliptical geometric
shape. Element 11: wherein each second layer cutting element track
set with a first layer cutting element has a first elliptical
geometric shape, and each track set first layer cutting element has
a second elliptical geometric shape. Element 12: wherein one of the
at least one second layer cutting element or the track set first
layer cutting element has a conical shape and the other has a
circular geometric shape or an elliptical geometric shape. Element
13: where, for each second layer cutting element and its track set
first layer cutting element, one of the second layer cutting
element and the track set first layer cutting element has a conical
shape and the other has a circular geometric shape or an elliptical
geometric shape. Element 14: wherein the second distance is greater
than or equal to the fourth distance.
[0096] Although the present disclosure and its advantages have been
described in detail, it should be understood that various changes,
substitutions and alternations can be made herein without departing
from the spirit and scope of the disclosure as defined by the
following claims. For example, although the present disclosure
describes the configurations of blades and cutting elements with
respect to drill bits, the same principles may be used with any
suitable drilling tool according to the present disclosure. It is
intended that the present disclosure encompasses such changes and
modifications as fall within the scope of the appended claims.
* * * * *