PRIORITY CLAIM
[0001] This application claims the benefit of the filing date of United States Provisional
Patent Application Serial No.
16/213,838, filed December 7, 2018, for "Self-Adjusting Earth-Boring Tools and Related Systems and Methods Of Reducing
Vibrations," the contents and disclosure of which is hereby incorporated herein in
its entirety by this reference.
TECHNICAL FIELD
[0002] This disclosure relates generally to self-adjusting earth-boring tools for use in
drilling wellbores, to bottom-hole assemblies and systems incorporating self-adjusting
earth-boring tools, and to methods and using such self-adjusting earth-boring tools,
assemblies, and systems.
BACKGROUND
[0003] Oil wells (wellbores) are usually drilled with a drill string. The drill string includes
a tubular member having a drilling assembly that includes a single drill bit at its
bottom end. The drilling assembly typically includes devices and sensors that provide
information relating to a variety of parameters relating to the drilling operations
("drilling parameters"), behavior of the drilling assembly ("drilling assembly parameters")
and parameters relating to the formations penetrated by the wellbore ("formation parameters").
A drill bit and/or reamer attached to the bottom end of the drilling assembly is rotated
by rotating the drill string from the drilling rig and/or by a drilling motor (also
referred to as a "mud motor") in the bottom-hole assembly ("BHA") to remove formation
material to drill the wellbore. A large number of wellbores are drilled along non-vertical,
contoured trajectories in what is often referred to as directional drilling. For example,
a single wellbore may include one or more vertical sections, deviated sections and
horizontal sections extending through differing types of rock formations.
[0004] When drilling with a fixed-cutter, or so-called "drag" bit or other earth-boring
tool progresses from a soft formation, such as sand, to a hard formation, such as
shale, or vice versa, the rate of penetration ("ROP") changes, and excessive ROP fluctuations
and/or vibrations (lateral or torsional) may be generated in the drill bit. The ROP
is typically controlled by controlling the weight-on-bit ("WOB") and rotational speed
(revolutions per minute or "RPM") of the drill bit. WOB is controlled by controlling
the hook load at the surface and RPM is controlled by controlling the drill string
rotation at the surface and/or by controlling the drilling motor speed in the drilling
assembly. Controlling the drill bit vibrations and ROP by such methods requires the
drilling system or operator to take actions at the surface. The impact of such surface
actions on the drill bit fluctuations is not substantially immediate. Drill bit aggressiveness
contributes to the vibration, whirl and stick-slip for a given WOB and drill bit rotational
speed. "Depth of Cut" ("DOC") of a fixed-cutter drill bit, is generally defined as
a distance a bit advances into a formation over a revolution, is a significant contributing
factor relating to the drill bit aggressiveness. Controlling DOC can prevent excessive
formation material buildup on the bit (e.g., "bit balling,"), limit reactive torque
to an acceptable level, enhance steerability and directional control of the bit, provide
a smoother and more consistent diameter borehole, avoid premature damage to the cutting
elements, and prolong operating life of the drill bit.
DISCLOSURE
[0005] One or more embodiments of the present disclosure may include a method of reducing
vibration experienced by an earth-boring tool during a drilling operation involving
a combination of crushing and shear cutting a subterranean formation, the method including:
setting an initial exposure of a drilling element coupled to an actuation device disposed
within a blade of the earth-boring tool to be overexposed relative to a primary cutting
element disposed at a leading face of the blade by a distance within a range of about
0.5% and about 8.0% of an overall diameter of the primary cutting element; applying
weight-on-bit to the earth-boring tool; causing the drilling element to retract toward
the actuation device and to be underexposed direction relative to the primary cutting
element; and in response to a drilling event, moving the drilling element relative
to a body of the earth-boring tool to change a level of underexposure of the drilling
element relative to the primary cutting element.
[0006] One or more embodiments of the present disclosure may include a method of reducing
vibration experienced by an earth-boring tool during a drilling operation involving
a combination of crushing and shear cutting a subterranean formation, the method including:
setting an initial exposure of a drilling element coupled to an actuation device disposed
within a blade of the earth-boring tool relative to a primary cutting element disposed
at a leading face of the blade; causing the drilling element to move relative to the
actuation device and to have a second exposure relative to the primary cutting element
by applying weight-on-bit; maintaining at least substantially continuous contact between
the drilling element and the subterranean formation during the drilling operation;
and in response to a drilling event, moving the drilling element relative to a body
of the earth-boring tool to at least substantially maintain contact between the drilling
element and the subterranean formation during and subsequent to the drilling event.
[0007] One or more embodiments of the present disclosure may include an earth-boring tool,
including: a body. The earth boring tool may also include a plurality of blades extending
from the body. The earth boring tool may also include at least one rotatable cutting
structure assembly coupled to the body; an actuation device disposed at least partially
within a blade of the plurality of blades, the actuation device including:. The earth
boring tool may also include a first fluid chamber. The earth boring tool may also
include a second fluid chamber. The earth boring tool may also include at least one
reciprocating member configured to reciprocate back and forth within the first fluid
chamber and the second fluid chamber, the at least one reciprocating member having
a front surface and a back surface. The earth boring tool may also include a hydraulic
fluid disposed within and at least substantially filling the first fluid chamber and
the second fluid chamber. The earth boring tool may also include a connection member
attached to the at least one reciprocating member and extending out of the second
fluid chamber. The earth boring tool may also include a drilling element removably
coupled to the connection member of the actuation device.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] For a detailed understanding of the present disclosure, reference should be made
to the following detailed description, taken in conjunction with the accompanying
drawings, in which like elements have generally been designated with like numerals,
and wherein:
FIG. 1 is a schematic diagram of a wellbore system comprising a drill string that
includes a self-adjusting drill bit according to an embodiment of the present disclosure;
FIG. 2 is a partial cross-sectional view of a self-adjusting drill bit according to
an embodiment of the present disclosure;
FIG. 3 is a schematic representation of an actuation device of a self-adjusting drill
bit according to an embodiment of the present disclosure;
FIG. 4 is a schematic representation of an actuation device of a self-adjusting drill
bit according to another embodiment of the present disclosure;
FIG. 5 is a cross-sectional view of an actuation device for a self-adjusting drill
bit according to another embodiment of the present disclosure;
FIG. 6 is a partial cross-sectional view of a self-adjusting drill bit according to
an embodiment of the present disclosure; and
FIG. 7 shows a flow chart of a method of reducing vibrations experienced by an earth-boring
tool during a drilling operation.
MODE(S) FOR CARRYING OUT THE INVENTION
[0009] The illustrations presented herein are not actual views of any particular drilling
system, drilling tool assembly, or component of such an assembly, but are merely idealized
representations, which are employed to describe the present invention.
[0010] As used herein, the terms "bit" and "earth-boring tool" each mean and include earth
boring tools for forming, enlarging, or forming and enlarging a wellbore. Non-limiting
examples of bits include fixed-cutter (drag) bits, fixed-cutter coring bits, fixed-cutter
eccentric bits, fixed-cutter bicenter bits, fixed-cutter reamers, expandable reamers
with blades bearing fixed cutters, and hybrid bits including both fixed cutters and
movable cutting structures (roller cones).
[0011] As used herein, the term "fixed cutter" means and includes a cutting element configured
for a shearing cutting action, abrasive cutting action or impact (percussion) cutting
action and fixed with respect to rotational movement in a structure bearing the cutting
element, such as, for example, a bit body, a tool body, or a reamer blade, without
limitation.
[0012] As used herein, the terms "wear element" and "bearing element" respectively mean
and include elements mounted to an earth-boring tool and which are not configured
to substantially cut or otherwise remove formation material when contacting a subterranean
formation in which a wellbore is being drilled or enlarged.
[0013] As used herein, the term "drilling element" means and includes fixed cutters, wear
elements, and bearing elements. For example, drilling elements may include cutting
elements, pads, elements making rolling contact, elements that reduce friction with
formations, PDC bit blades, cones, elements for altering junk slot geometry,
etc.
[0014] As used herein, any relational term, such as "first," "second," "front," "back,"
etc., is used for clarity and convenience in understanding the disclosure and accompanying
drawings, and does not connote or depend on any specific preference or order, except
where the context clearly indicates otherwise.
[0015] As used herein, the term "substantially" in reference to a given parameter, property,
or condition means and includes to a degree that one skilled in the art would understand
that the given parameter, property, or condition is met with a small degree of variance,
such as within acceptable manufacturing tolerances. For example, a parameter that
is substantially met may be at least about 90% met, at least about 95% met, or even
at least about 99% met.
[0016] Some embodiments of the present disclosure include self-adjusting drill bits for
use in a wellbore. For example, a self-adjusting drill bit may include an actuation
device for extending and retracting a drilling element (
e.g., a cutting element) of the bit. The drilling element may be attached to a connection
member, which is attached to at least two reciprocating members within the actuation
device. The reciprocating members may extend and retract the drilling element by moving
through inward and outward strokes. The actuation device may include a first fluid
chamber and a second fluid chamber. The first fluid chamber may have a pressure higher
than the pressure of the second fluid chamber. Furthermore, the first fluid chamber
may have a first portion located to apply a pressure on a first reciprocating member
and a second portion located to apply the pressure on a second reciprocating member.
Thus, because the pressure is applied to a first surface of the first reciprocating
member and a second surface of the second reciprocating member, a surface area of
each of the first and second surfaces may be smaller while providing a same force
on the connection member from the pressure. Some embodiments of the present disclosure
include an actuation device for a self-adjusting drill bit that includes a removable
drilling element. Furthermore, some embodiments of the present disclosure include
an actuation device having a pressure compensator for balancing an environment pressure
with a pressure of the second fluid chamber. In some embodiments, the pressure compensator
may include a rubber material.
[0017] FIG. 1 is a schematic diagram of an example of a drilling system 100 that may utilize
the apparatuses and methods disclosed herein for drilling wellbores. FIG. 1 shows
a wellbore 102 that includes an upper section 104 with a casing 106 installed therein
and a lower section 108 that is being drilled with a drill string 110. The drill string
110 may include a tubular member 112 that carries a drilling assembly 114 at its bottom
end. The tubular member 112 may be made up by joining drill pipe sections or it may
be a string of coiled tubing. A drill bit 116 may be attached to the bottom end of
the drilling assembly 114 for drilling the wellbore 102 of a selected diameter in
a formation 118.
[0018] The drill string 110 may extend to a rig 120 at the surface 122. The rig 120 shown
is a land rig 120 for ease of explanation. However, the apparatuses and methods disclosed
equally apply when an offshore rig 120 is used for drilling wellbores under water.
A rotary table 124 or a top drive may be coupled to the drill string 110 and may be
utilized to rotate the drill string 110 and to rotate the drilling assembly 114, and
thus the drill bit 116 to drill the wellbore 102. A drilling motor 126 (also referred
to as "mud motor") may be provided in the drilling assembly 114 to rotate the drill
bit 116. The drilling motor 126 may be used alone to rotate the drill bit 116 or to
superimpose the rotation of the drill bit 116 by the drill string 110. The rig 120
may also include conventional equipment, such as a mechanism to add additional sections
to the tubular member 112 as the wellbore 102 is drilled. A surface control unit 128,
which may be a computer-based unit, may be placed at the surface 122 for receiving
and processing downhole data transmitted by sensors 140 in the drill bit 116 and sensors
140 in the drilling assembly 114, and for controlling selected operations of the various
devices and sensors 140 in the drilling assembly 114. The sensors 140 may include
one or more of sensors 140 that determine acceleration, weight on bit, torque, pressure,
cutting element positions, rate of penetration, inclination, azimuth formation/lithology,
etc. In some embodiments, the surface control unit 128 may include a processor 130 and
a data storage device 132 (or a computer-readable medium) for storing data, algorithms,
and computer programs 134. The data storage device 132 may be any suitable device,
including, but not limited to, a read-only memory (ROM), a random-access memory (RAM),
a Flash memory, a magnetic tape, a hard disk, and an optical disk. During drilling,
a drilling fluid from a source 136 thereof may be pumped under pressure through the
tubular member 112, which discharges at the bottom of the drill bit 116 and returns
to the surface 122 via an annular space (also referred as the "annulus") between the
drill string 110 and an inside wall 138 of the wellbore 102.
[0019] The drilling assembly 114 may further include one or more downhole sensors 140 (collectively
designated by numeral 140). The sensors 140 may include any number and type of sensors
140, including, but not limited to, sensors 140 generally known as the measurement-while-drilling
(MWD) sensors 140 or the logging-while-drilling (LWD) sensors 140, and sensors 140
that provide information relating to the behavior of the drilling assembly 114, such
as drill bit rotation (revolutions per minute or "RPM"), tool face, pressure, vibration,
whirl, bending, and stick-slip. The drilling assembly 114 may further include a controller
unit 142 that controls the operation of one or more devices and sensors 140 in the
drilling assembly 114. For example, the controller unit 142 may be disposed within
the drill bit 116
(e.g., within a shank and/or crown of a bit body of the drill bit 116). The controller unit
142 may include, among other things, circuits to process the signals from sensor 140,
a processor 144 (such as a microprocessor) to process the digitized signals, a data
storage device 146 (such as a solid-state-memory), and a computer program 148. The
processor 144 may process the digitized signals, and control downhole devices and
sensors 140, and communicate data information with the surface control unit 128 via
a two-way telemetry unit 150.
[0020] The drill bit 116 may include a face section 152 (or bottom section). The face section
152 or a portion thereof may face the undrilled formation 118 in front of the drill
bit 116 at the wellbore 102 bottom during drilling. In some embodiments, the drill
bit 116 may include one or more cutting elements that may be extended and retracted
from a surface, such as a surface over the face section 152, of the drill bit 116
and, more specifically, a blade projecting from the face section 152. An actuation
device 156 may control the rate of extension and retraction of the drilling element
154 with respect to the drill bit 116. In some embodiments, the actuation device 156
may be a passive device that automatically adjusts or self-adjusts the rate of extension
and retraction of the drilling element 154 based on or in response to a force or pressure
applied to the drilling element 154 during drilling. In some embodiments, the actuation
device 156 and drilling element 154 may be actuated by contact of the drilling element
154 with the formation 118. In some drilling operations, substantial forces may be
experienced on the drilling elements 154 when a depth of cut ("DOC") of the drill
bit 116 is changed rapidly. Accordingly, the actuation device 156 may be configured
to resist sudden changes to the DOC of the drill bit 116. In some embodiments, the
rate of extension and retraction of the drilling element 154 may be preset, as described
in more detail in reference to FIGS. 2-5.
[0021] FIG. 2 shows an earth-boring tool 200 having an actuation device 156 according to
an embodiment of the present disclosure. In some embodiments, the earth-boring tool
200 includes a fixed-cutter polycrystalline diamond compact (PDC) bit having a bit
body 202 that includes a neck 204, a shank 206, and a crown 208. The earth-boring
tool 200 may be any suitable drill bit or earth-boring tool for use in drilling and/or
enlarging a wellbore in a formation.
[0022] The neck 204 of the bit body 202 may have a tapered upper end 210 having threads
212 thereon for connecting the earth-boring tool 200 to a box end of the drilling
assembly 114 (FIG. 1). The shank 206 may include a lower straight section 214 that
is fixedly connected to the crown 208 at a joint 216. The crown 208 may include a
number of blades 220. Each blade 220 may have multiple regions as known in the art
(cone, nose, shoulder, gage).
[0023] The earth-boring tool 200 may include one or more cutting, wear, or bearing elements
154 (referred to hereinafter as "drilling elements 154") that extend and retract from
a surface 230 of the earth-boring tool 200. For example, the bit body 202 of the earth-boring
tool 200 may carry (
e.g., have attached thereto) a plurality of drilling elements 154. As shown in FIG. 2,
the drilling element 154 may be movably disposed in a cavity or recess 232 in the
crown 208. An actuation device 156 may be coupled to the drilling element 154 and
may be configured to control rates at which the drilling element 154 extends and retracts
from the earth-boring tool 200 relative to a surface 230 of the earth-boring tool
200. In some embodiments, the actuation device 156 may be oriented with a longitudinal
axis of the actuation device 156 oriented at an acute angle (
e.g., a tilt) relative to a direction of rotation of the earth-boring tool 200 in order
to minimize a tangential component of a friction force experienced by the actuation
device 156. In some embodiments, the actuation device 156 may be disposed inside the
blades 220 supported by the bit body 202 and may be secured to the bit body 202 with
a press fit proximate a face 219 of the earth-boring tool 200. In some embodiments,
the actuation device 156 may be disposed within a gage region of a bit body 202. For
example, the actuation device 156 may be coupled to a gage pad and may be configured
to control rates at which the gage pad extends and retracts from the gage region of
the bit body 202. For example, the actuation device 156 may be disposed within a gage
region similar to the actuation devices described in
U.S. Patent Application No. 14/516,069, to Jain, the disclosure of which is incorporated in its entirety herein by this reference.
[0024] FIG. 3 shows a schematic view of an actuation device 156 of a self-adjusting earth-boring
tool 200 (FIG. 2) according to an embodiment of the present disclosure. The actuation
device 156 may include a connection member 302, a chamber 304, a first reciprocating
member 306, a second reciprocating member 308, a divider member 310, a hydraulic fluid
312, a biasing member 314, a first fluid flow path 316, a second fluid flow path 318,
a first flow control device 320, a second flow control device 322, a pressure compensator
324, and a drilling element 154.
[0025] The first reciprocating member 306 and the second reciprocating member 308 may be
attached to the connection member 302 at different locations along a longitudinal
axis of the connection member 302. For example, the first reciprocating member 306
may be attached to a first longitudinal end of the connection member 302, and the
second reciprocating member 308 may be attached to a portion of the connection member
302 axially between the first longitudinal end and a second longitudinal end of the
connection member 302. The drilling element 154 may be attached to the second longitudinal
end of the connection member 302. In some embodiments, the first reciprocating member
306 may have a generally cylindrical shape, and the second reciprocating member 308
may have a generally annular shape. The first reciprocating member 306 may have a
front surface 328 and an opposite back surface 330, and the second reciprocating member
308 have a front surface 332 and an opposite back surface 334. As used herein, a "front
surface" of a reciprocating member may refer to a surface of the reciprocating member
that, if subjected to a force, will result in the reciprocating member moving the
connection member 302 outward toward a formation 118 (FIG. 1) (
e.g., at least partially out of the chamber 304). For example, the front surface 328
of the first reciprocating member 306 may be a surface of the first reciprocating
member 306 opposite the connection member 302. Furthermore, as used herein, a "back
surface" of a reciprocating member may refer to a surface of the reciprocating member
that, if subjected to a force, will result in the reciprocating member moving the
connection member 302 inward and further into the chamber 304. For example, the back
surface 330 of the first reciprocating member 306 may be a surface of the first reciprocating
member 306 that is attached to the connection member 302.
[0026] The front surface 328 of the first reciprocating member 306 may be at least substantially
parallel to the front surface 332 of the second reciprocating member 308. Furthermore,
the back surface 330 of the first reciprocating member 306 may be at least substantially
parallel to the back surface 334 of the second reciprocating member 308.
[0027] The chamber 304 may be sealingly divided by the first and second reciprocating members
306, 308 (
e.g., pistons) and the divider member 310 into a first fluid chamber 336 and a second
fluid chamber 338. The first fluid chamber 336 may include a first portion 340 and
a second portion 342. Furthermore, the second fluid chamber 338 may have a first portion
344 and a second portion 346. The first portion 340 of the first fluid chamber 336
may be sealingly isolated from the first portion 344 of the second fluid chamber 338
by the first reciprocating member 306. The first portion 340 of the first fluid chamber
336 may be located on a front side of the first reciprocating member 306. In other
words, the first portion 340 of the first fluid chamber 336 may be at least partially
defined by the front surface 328 of the first reciprocating member 306. The first
portion 344 of the second fluid chamber 338 may be located on a back side of the first
reciprocating member 306. In other words, the first portion 344 of the second fluid
chamber 338 may be at least partially defined by the back surface 330 of the first
reciprocating member 306.
[0028] The first portion 344 of the second fluid chamber 338 may be isolated from the second
portion 342 of the first fluid chamber 336 by the divider member 310. The divider
member 310 may be stationary relative to the first portion 344 of the second fluid
chamber 338 and the second portion 342 of the first fluid chamber 336. For example,
the first portion 344 of the second fluid chamber 338 may be located between the back
surface 330 of the first reciprocating member 306 and the divider member 310. The
second portion 342 of the first fluid chamber 336 may be sealingly divided from the
second portion 346 of the second fluid chamber 338 by the second reciprocating member
308. For example, the second portion 342 of the first fluid chamber 336 may be located
on a front side of the second reciprocating member 308 (
e.g., at least partially defined by the front surface 332 of the second reciprocating
member 308), and the second portion 346 of the second fluid chamber 338 may be located
on a back side of the second reciprocating member 308 (
e.g., at least partially defined by the back surface 334 of the second reciprocating
member 308). Furthermore, the second portion 342 of the first fluid chamber 336 may
be located between the divider member 310 and the front surface 332 of the second
reciprocating member 308.
[0029] As a result of the orientations described above, the portions (
i.e., the first and second portions of each) of first and second fluid chambers 336,
338 may be oriented in parallel (
e.g., stacked) within the chamber 304. Put another way, the portions (
i.e., the first and second portions of each) of first and second fluid chambers 336,
338 may be oriented parallel to each other along a longitudinal length of the actuation
device 156.
[0030] The first fluid chamber 336 and a second fluid chamber 338 may be at least substantially
filled with the hydraulic fluid 312. The hydraulic fluid 312 may include any hydraulic
fluid 312 suitable for downhole use, such as oil. In some embodiments, the hydraulic
fluid 312 may include one or more of a magneto-rheological fluid and an electro-rheological
fluid.
[0031] In some embodiments, the first and second fluid chambers 336, 338 and may be in fluid
communication with each other via the first fluid flow path 316 and the second fluid
flow path 318. For example, the first fluid flow path 316 may allow hydraulic fluid
312 to flow from the second fluid chamber 338 to the first fluid chamber 336. The
first fluid flow path 316 may extend from the second portion 346 of the second fluid
chamber 338 to the first portion 340 of the first fluid chamber 336 and may allow
the hydraulic fluid 312 to flow from the second portion 346 of the second fluid chamber
338 to the first portion 340 of the first fluid chamber 336. Furthermore, the first
fluid flow path 316 may extend from the first portion 344 of the second fluid chamber
338 to the first portion 340 of the first fluid chamber 336 and may allow the hydraulic
fluid 312 to flow from the first portion 344 of the second fluid chamber 338 to the
first portion 340 of the first fluid chamber 336.
[0032] The first flow control device 320 may be disposed within the first fluid flow path
316 and may be configured to control the flow rate of the hydraulic fluid 312 from
the second fluid chamber 338 to the first fluid chamber 336. In some embodiments,
the first flow control device 320 may include one or more of a first check valve and
a first restrictor (e.g., an orifice). In some embodiments, the first flow control
device 320 may include only a first check valve. In other embodiments, the first flow
control device 320 may include only a first restrictor. In other embodiments, the
first flow control device 320 may include both the first check valve and the first
restrictor.
[0033] The second fluid flow path 318 may allow the hydraulic fluid 312 to flow from the
first fluid chamber 336 to the second fluid chamber 338. For example, the second fluid
flow path 318 may extend from the first portion 340 of the first fluid chamber 336
to the second portion 346 of the second fluid chamber 338 and may allow the hydraulic
fluid 312 to flow from the first portion 340 of the first fluid chamber 336 to the
second portion 346 of the second fluid chamber 338. Furthermore, the second fluid
flow path 318 may extend from the second portion 342 of the first fluid chamber 336
to the second portion 346 of the second fluid chamber 338 and may allow the hydraulic
fluid 312 to flow from the second portion 342 of the first fluid chamber 336 to the
second portion 346 of the second fluid chamber 338. The second flow control device
322 may be disposed within the second fluid flow path 318 and may be configured to
control the flow rate of the hydraulic fluid 312 from the first fluid chamber 336
to the second fluid chamber 338 (
i.e., from the first and second portions 340, 342 of the first fluid chamber 336 to the
second portion 346 of the second fluid chamber 338). In some embodiments, the second
flow control device 322 may include one or more of a second check valve and a second
restrictor (
e.g., orifice). In some embodiments, the second flow control device 322 may include only
a second check valve. In other embodiments, the second flow control device 322 may
include only a second restrictor. In other embodiments, the second flow control device
322 may include both the second check valve and the second restrictor.
[0034] As discussed above, the connection member 302 may be connected at the first longitudinal
end thereof to the back surface 330 of the first reciprocating member 306, which faces
the first portion 344 of the second fluid chamber 338. Furthermore, as discussed above,
the connection member 302 may be connected to the drilling element 154 at a second,
opposite longitudinal end of the connection member 302. The biasing member 314 (
e.g., a spring) may be disposed within the first portion 340 of the first fluid chamber
336 and may be attached to the first reciprocating member 306 on the front surface
328 of the first reciprocating member 306 opposite the connection member 302 and may
exert a force on the first reciprocating member 306 and may move the first reciprocating
member 306, and as a result, the connection member 302 outward toward a formation
118 (FIG. 1). For example, the biasing member 314 may move the first reciprocating
member 306 outward, which may in turn move the connection member 302 and the drilling
element 154 outward (
i.e., extend the drilling element 154). Such movement of the first reciprocating member
306, connection member 302, and drilling element 154 may be referred to herein as
an "outward stroke." As the first reciprocating member 306 moves outward, the first
reciprocating member 306 may expel hydraulic fluid 312 from the first portion 344
of the second fluid chamber 338, through the first fluid flow path 316, and into the
first portion 340 of the first fluid chamber 336.
[0035] As discussed above, the second reciprocating member 308 may also be attached to the
connection member 302 but may be attached to a portion of the connection member 302
axially between the first longitudinal end connected to the first reciprocating member
306 and the second longitudinal end connected to the drilling element 154. For example,
the second reciprocating member 308 may have a generally annular shape and the connection
member 302 may extend through the second reciprocating member 308. Additionally, the
second reciprocating member 308 may be spaced by at least some distance from the first
reciprocating member 306 along the longitudinal axis of the connection member 302.
Furthermore, because the second reciprocating member 308 is attached to the connection
member 302, which is attached to the first reciprocating member 306, when the first
reciprocating member 306 moves outward due to the biasing member 314, the second reciprocating
member 308 moves outward. In other words, the force applied on the first reciprocating
member 306 by the biasing member 314 may result in the second reciprocating member
308 moving outward in addition to the first reciprocating member 306 moving outward.
As the second reciprocating member 308 moves outward, the second reciprocating member
308 may expel hydraulic fluid 312 from the second portion 346 of the second fluid
chamber 338, through the first fluid flow path 316, and into the first portion 340
of the first fluid chamber 336.
[0036] In some embodiments, the second fluid chamber 338 may be at a pressure at least substantially
equal to an environment pressure, and the first fluid chamber 336 may be at a pressure
higher than the pressure of the second fluid chamber 338. For example, the first fluid
chamber 336 may be at a pressure higher than the pressure of the second fluid chamber
338 when the connection member 302 is being subjected to an external load (
e.g., the drilling element 154 is pushing against a formation 118 (FIG. 1)) The pressure
differential between the first fluid chamber 336 and the second fluid chamber 338
may assist in applying a selected force on the first reciprocating member 306 and
the second reciprocating member 308 and moving the first and second reciprocating
members 306, 308, and as a result, the connection member 302 and the drilling element
154 through the outward stroke. For example, the first portion 340 of the first fluid
chamber 336, which is in fluid communication with the front surface 328 of the first
reciprocating member 306, may be at a higher pressure than a pressure of the first
portion 344 of the second fluid chamber 338, which is in fluid communication with
the back surface 330 of the first reciprocating member 306. The pressure differential
between the first portion 340 of the first fluid chamber 336 and the first portion
344 of the second fluid chamber 338 may assist in applying a selected force on the
front surface 328 of the first reciprocating member 306. Furthermore, the second portion
342 of the first fluid chamber 336, which is in fluid communication with the front
surface 332 of the second reciprocating member 308, may be at a higher pressure than
a pressure of the second portion 346 of the second fluid chamber 338, which is in
fluid communication with the back surface 334 of the second reciprocating member 308.
The pressure differential between the second portion 342 of the first fluid chamber
336 and the second portion 346 of the second fluid chamber 338 may assist in applying
a selected force on the front surface 332 of the second reciprocating member 308.
[0037] Because both of the first and second portions 340, 342 of the first fluid chamber
336 are at a higher pressure than the first and second portions 344, 346 of the second
fluid chamber 338 and are located at different locations along the longitudinal axis
of the connection member 302, an overall force applied by the pressure of the first
fluid chamber 336 may be applied in portions at different locations (
i.e., the first and second reciprocating members 306, 308) along the longitudinal axis
of the connection member 302.
[0038] Having the first and second portions 340, 342 of the first fluid chamber 336 at a
higher pressure than the first and second portions 344, 346 of the second fluid chamber
338 and distributed along a longitudinal length of the connection member 302 may enable
a cross-sectional area of the overall actuation device 156 to be smaller than an actuation
device 156 having a single fluid chamber at high pressure. Furthermore, having the
first and second portions 340, 342 of the first fluid chamber 336 at a higher pressure
and distributed along a longitudinal length of the connection member 302 may enable
the cross-sectional area of the overall actuation device 156 to be smaller while maintaining
a same force on the connection member 302. For example, because the higher pressure
is applied to the front surfaces 328, 332 of both of the first and second reciprocating
members 306, 308, a surface area of the front surfaces 328, 332 of each of the first
and second reciprocating members 306, 308 may be smaller while applying a selected
force than if there were only a single larger reciprocating member. Furthermore, a
same selected force may be applied to the connection member 302 by the two smaller
reciprocating members as is applied with the single larger reciprocating member. In
other words, by having two reciprocating members, the front surface of each of the
reciprocating members may have a smaller surface area than otherwise would be needed
with a single reciprocating member to apply the selected force on the connection member
302. Put another way, the pressure of the first fluid chamber 336 may be divided between
and applied to two surface areas (
i.e., the front surfaces 328, 332 of the first and second reciprocating members 306,
308) that are at least substantially parallel to each other. Put yet another way,
the first and second reciprocating members 306, 308 may provide a sufficient surface
area between the two front surfaces 328, 332 of the first and second reciprocating
members 306, 308, which is in fluid communication with the hydraulic fluid 312 in
the first fluid chamber 336 (
e.g., hydraulic fluid 312 at a higher pressure) to withstand (
e.g., handle, carry, absorb, dampen) loads (
e.g., forces) that the connection member 302 and first and second reciprocating members
306, 308 may be subjected to during use in a drilling operation in a wellbore 102
(FIG. 1).
[0039] As a result of the above, an overall cross-sectional area of the actuation device
156 may be smaller than an actuation device 156 having a single reciprocating member,
and the actuation device 156 may apply a same force with the pressure of the first
fluid chamber 336 to the connection member 302 as the actuation device 156 having
a single reciprocating member.
[0040] Referring to FIGS. 1, 2 and 3 together, reducing a cross-sectional area of the actuation
device 156 needed to apply a selected force to the connection member 302 of the actuation
device 156 or withstand (e.g., absorb, endure, tolerate, bear, etc.) a force applied
to the connection member 302 by a formation 118 (FIG. 1) may provide advantages over
other known self-adjusting drill bits. For example, by reducing the cross-sectional
area of the actuation device 156, a space required to house the actuation device 156
is also reduced. Accordingly, the actuation device 156 may be disposed in more types
and sizes of bit bodies 202. For example, the actuation device 156 may be disposed
within smaller bit bodies 202 than would otherwise be achievable with known actuation
devices. Furthermore, by requiring less space, the actuation device 156 may be placed
in more locations within a bit body 202. Moreover, by requiring less space, more drilling
elements 154 of a bit body 202 may be attached to actuation devices 156. Additionally,
by requiring less space, the actuation device 156 may be less likely to compromise
a structural integrity of the bit body 202. Consequently, the given bit body 202 may
be used in more applications and may have increased functionality. Although the actuation
device 156 is described herein as being used with a bit body 202 or drill bit, the
actuation device 156 is equally applicable to reamers, impact tools, hole openers,
etc.
[0041] In some embodiments, the second fluid chamber 338 may be maintained at a pressure
at substantially equal to an environment pressure (
e.g., pressure outside of earth-boring tool 200 (FIG. 2)) with the pressure compensator
324, which may be in fluid communication with the second fluid chamber 338. For example,
one or more of the first or second portions 344, 346 of the second fluid chamber 338
may be in fluid communication with the pressure compensator 324. The pressure compensator
324 may include a bellows, diaphragm, pressure compensator 324 valve,
etc. For example, the pressure compensator 324 may include a diaphragm that is in fluid
communication with the environment (
e.g., mud of wellbore 102 (FIG. 1)) on one side and in fluid communication with the hydraulic
fluid 312 in the second fluid chamber 338 on another side and may at least substantially
balance the pressure of the second fluid chamber 338 with the environment pressure.
In some embodiments, the pressure compensator 324 may comprise a rubber material.
For example, the pressure compensator 324 may include a rubber diaphragm. Including
a pressure compensator 324 may reduce a required sealing pressure for mud seals and
oil seals included in the actuation device 156.
[0042] Referring still to FIG. 3, during operation, when the drilling element 154 contacts
the formation 118 (FIG. 1), the formation 118 (FIG. 1) may exert a force on the drilling
element 154, which may move the connection member 302 and, as a result, the first
and second reciprocating members 306, 308 inward. Moving the first reciprocating member
306 inward may expel the hydraulic fluid 312 from the first portion 340 of the first
fluid chamber 336, through the second fluid flow path 318, and into the second portion
346 of the second fluid chamber 338. Furthermore, moving the second reciprocating
member 308 inward may expel hydraulic fluid 312 from the second portion 342 of the
first fluid chamber 336, through the second fluid flow path 318, and into the second
portion 346 of the second fluid chamber 338. Pushing hydraulic fluid 312 from the
first and second portions 340, 342 of the first fluid chamber 336 into the second
portion 346 of the second fluid chamber 338 may move the drilling element 154 inward
(
i.e., retract the drilling element 154). Such movement of the first and second reciprocating
members 306, 308 and drilling element 154 may be referred to herein as an "inward
stroke."
[0043] The rate of the movement of the first and second reciprocating members 306, 308 (
e.g., the speed at which the first and second reciprocating members 306, 308 moves through
the outward and inward strokes) may be controlled by the flow rates of the hydraulic
fluid 312 through the first and second fluid flow paths 316, 318, and the first and
second flow control devices 320, 322. As a result, the rate of the movement of the
drilling element 154 (
e.g., the speed at which drilling element 154 extends and retracts) and the position
of the drilling element 154 relative to the surface 230 (FIG. 2) may be controlled
by the flow rates of the hydraulic fluid 312 through the first and second fluid flow
paths 316, 318, and the first and second flow control devices 320, 322.
[0044] In some embodiments, the flow rates of the hydraulic fluid 312 through the first
and second fluid flow paths 316, 318 and, as result, between the first and second
fluid chambers 336, 338 may be at least partially set by selecting hydraulic fluids
312 with viscosities that result in the desired flow rates. In some embodiments, the
flow rates of the hydraulic fluid 312 through the first and second fluid flow paths
316, 318 may be at least partially set by selecting flow control devices that result
in the desired flow rates. Furthermore, the hydraulic fluid 312, specifically, a viscosity
of a hydraulic fluid 312, may be selected to increase or decrease an effectiveness
of the first and second flow control devices 320, 322.
[0045] As a non-limiting example, the first and second flow control devices 320, 322, may
be selected to provide a slow outward stroke (
i.e., slow flow rate of the hydraulic fluid 312 through the first fluid flow path 316)
of the drilling element 154 and a fast inward stroke of the drilling element 154 (
i.e., a fast flow rate of the hydraulic fluid 312 through the second fluid flow path
318). For example, a first restrictor may be disposed in the first fluid flow path
316 to provide a slow outward stroke, and a first check valve may be disposed in the
second fluid flow path 318 to provide a fast inward stroke. In other embodiments,
the first and second flow control devices 320, 322, may be selected to provide a fast
outward stroke of the drilling element 154 and a slow inward stroke of the drilling
element 154. For example, a second check valve may be disposed in the first fluid
flow path 316 to provide a fast outward stroke, and a second restrictor may be disposed
in the second fluid flow path 318 to provide a slow inward stroke.
[0046] In some embodiments, the viscosities of the hydraulic fluid 312 and the first and
second flow control devices 320, 322 may be selected to provide constant fluid flow
rate exchange between the first fluid chamber 336 and the second fluid chamber 338.
Constant fluid flow rates may provide a first constant rate for the extension for
the connection member 302 and a second constant rate for the retraction of the connection
member 302 and, thus, corresponding constant rates for extension and retraction of
the drilling element 154. In some embodiments, the flow rate of the hydraulic fluid
312 through the first fluid flow path 316 may be set such that when the earth-boring
tool 200 (FIG. 2) is not in use,
i.e., there is no external force being applied onto the drilling element 154, the biasing
member 314 will extend the drilling element 154 to a maximum extended position. In
some embodiments, the flow rate of the hydraulic fluid 312 through the first fluid
flow path 316 may be set so that the biasing member 314 extends the drilling element
154 relatively fast or suddenly.
[0047] In some embodiments, the flow rates of the hydraulic fluid 312 through the second
fluid flow path 318 may be set to allow a relatively slow flow rate of the hydraulic
fluid 312 from the first fluid chamber 336 into the second fluid chamber 338, thereby
causing the drilling element 154 to retract relative to the surface 230 (FIG. 2) relatively
slowly. For example, the extension rate of the drilling element 154 may be set so
that the drilling element 154 extends from the fully retracted position to a fully
extended position over a few seconds or a fraction of a second while it retracts from
the fully extended position to the fully retracted position over one or several minutes
or longer (such as between 2-5 minutes). It will be noted, that any suitable rate
may be set for the extension and retraction of the drilling element 154. Thus, the
earth-boring tool 200 (FIG. 2) may act as a self-adjusting drill bit such as the self-adjusting
drill bit described in
U.S. Pat. App. Pub. No. 2015/0191979 A1, to Jain et al., filed Oct. 6, 2014, the disclosure of which is incorporated in its entirety herein by this reference.
[0048] In other embodiments, the actuation device 156 may include rate controllers as described
in the
U.S. Application No. 14/851,117, to Jain, filed September 11, 2015, the disclosure of which is incorporated in its entirety herein by this reference.
For example, the actuation device 156 may include one or more rate controllers that
are configured to adjust fluid properties (
e.g., viscosities) of the hydraulic fluid 312, and thereby, control flow rates of the
hydraulic fluid 312 through the first and second flow control devices 320, 322. As
a non-limiting example, the rate controllers may include electromagnets and the hydraulic
fluid 312 may include a magneto-rheological fluid. The electromagnets may be configured
to adjust the viscosity of the hydraulic fluid 312 to achieve a desired flow rate
of the hydraulic fluid 312, and as a result, a rate of extension or retraction of
the drilling element 154.
[0049] Furthermore, in some embodiments, one or more of the first and second flow control
devices 320, 322 may include a restrictor as described in the
U.S. Application No. 14/851,117, to Jain, filed September 11, 2015. For example, the restrictor may include a multi-stage orifice having a plurality
of plates, a plurality of orifices extending through each plate of the plurality of
plates, and a plurality of fluid pathways defined in each plate of the plurality of
plates and surrounding each orifice of the plurality of orifices.
[0050] FIG. 4 is a schematic view of an actuation device 156 for a self-adjusting earth-boring
tool 200 (FIG. 2) according to another embodiment of the present disclosure. Similar
to the actuation device 156 described above in regard to FIG. 3, the actuation device
156 of FIG. 4 may include a connection member 302, a chamber 304, a first reciprocating
member 306, a second reciprocating member 308, a hydraulic fluid 312, a biasing member
314, a first fluid flow path 316, a second fluid flow path 318, a first flow control
device 320, a second flow control device 322, a pressure compensator 324, and a drilling
element 154. Furthermore, the chamber 304 may include a first fluid chamber 336 and
a second fluid chamber 338. The actuation device 156 may operate in substantially
the same manner as the actuation device 156 described in regard to FIG. 3.
[0051] However, the actuation device 156 may include a first divider member 310a and a second
divider member 310b, and the second fluid chamber 338 may include a first portion
344, a second portion 346, and a third portion 348. The actuation device 156 may also
include a third fluid flow path 350 and a fourth fluid flow path 352. The first portion
344 and second portion 346 of the second fluid chamber 338 may be oriented in the
same manner as described above in regard to FIG. 3. Furthermore, the first divider
member 310a may be oriented in the same manner as the divider member 310 described
in regard to FIG. 3.
[0052] The second divider member 310b may be oriented on an opposite side of the first portion
340 of the first fluid chamber 336 than the first reciprocating member 306, and the
third portion 348 of the second fluid chamber 338 may be located on an opposite side
of the second divider member 310b than the first portion 340 of the first fluid chamber
336. In other words, the third portion 348 of the second fluid chamber 338 may be
isolated from the first portion 340 of the first fluid chamber 336 by the second divider
member 310b. The second divider member 310b may be stationary relative to the first
portion 340 of the first fluid chamber 336 and the third portion 348 of the second
fluid chamber 338.
[0053] The third portion 348 of the second fluid chamber 338 may be in fluid communication
with the pressure compensator 324, and pressure compensator 324 may be configured
to at least substantially balance the pressure of the second fluid chamber 338 with
the environment pressure of an environment (
e.g., mud of the wellbore 102 (FIG. 1)), as discussed above in regard to FIG. 3. In other
words, the pressure compensator 324 may help maintain a pressure of the second fluid
chamber 338 that is at least substantially equal to the environment pressure. For
example, the pressure compensator 324 may be in fluid communication on a first side
with the third portion 348 of the second fluid chamber 338 and may be at least partially
disposed within the third portion 348 of the second fluid chamber 338. The pressure
compensator 324 may include one or more of a bellows, diaphragm, and pressure compensator
324 valve and may be in communication on a second side with an environment (
e.g., mud 354 of the wellbore 102 (FIG. 1). In some embodiments, the pressure compensator
324 may comprise a rubber material. For example, the pressure compensator 324 may
include a rubber diaphragm.
[0054] The first fluid flow path 316 may extend from the third portion 348 of the second
fluid chamber 338 to the first portion 340 of the first fluid chamber 336 through
the second divider member 310b. The first flow control device 320 may be disposed
within the first fluid flow path 316 and may include one or more of a first check
valve and a first restrictor. Otherwise, the first fluid flow path 316 and first flow
control device 320 may operate in the same manner as the first fluid flow path 316
and first flow control device 320 described in regard to FIG. 3.
[0055] The second fluid flow path 318 may extend from the second portion 342 of the first
fluid chamber 336 to the second portion 346 of the second fluid chamber 338 through
the second reciprocating member 308. The second flow control device 322 may be disposed
within the second fluid flow path 318 and may include one or more of a second check
valve and a second restrictor. Otherwise, the second fluid flow path 318 and second
flow control device 322 may operate in the same manner as the second fluid flow path
318 and second flow control device 322 described in regard to FIG. 3.
[0056] The first, second, and third portions 344, 346, 348 of the second fluid chamber 338
may be in fluid communication with each other via a third fluid flow path 350. For
example, the third fluid flow path 350 may extend from the second portion 346 of the
second fluid chamber 338 to the first portion 344 of the second fluid chamber 338
and to the third portion 348 of the second fluid chamber 338.
[0057] The first and second portions 340, 342 of the first fluid chamber 336 may be in fluid
communication with each other via the fourth fluid flow path 352. For example, the
fourth fluid flow path may extend from the first portion 340 of the first fluid chamber
336 to the second portion 342 of the first fluid chamber 336.
[0058] FIG. 5 is a cross-sectional view of an example implementation of the actuation device
156 of a self-adjusting bit of FIG. 4. The actuation device 156 may be similar to
the actuation device 156 shown in FIG. 4 as described above. The actuation device
156 may be configured to be press fitted into a crown 208 of a bit body 202 (FIG.
2) of an earth-boring tool 200 (FIG. 2). The actuation device 156 may include a casing
356, a connection member 302, an internal chamber 358, a first reciprocating member
306, a second reciprocating member 308, a hydraulic fluid 312, a biasing member 314,
a first fluid flow path 316, a second fluid flow path 318, a third fluid flow path
350, a fourth fluid flow path 352, a first divider member 310a, a second divider member
310b, a first flow control device 320, a second flow control device 322, a pressure
compensator 324, and a drilling element 154.
[0059] The first reciprocating member 306 and the second reciprocating member 308 may be
attached to the connection member 302 in the same manner as described in regard to
FIG. 3. The casing 356 may define the internal chamber 358 and may have an extension
hole 370 defined in one longitudinal end thereof. Furthermore, the internal chamber
358 may house the first and second reciprocating members 306, 308. Moreover, the first
and second reciprocating members 306, 308 and first and second divider members 310a,
310b may sealingly divide the internal chamber 358 into the first fluid chamber 336
and the second fluid chamber 338.
[0060] The first fluid chamber 336 may include a first portion 340 and a second portion
342, and the second fluid chamber 338 may include a first portion 344, a second portion
346, and a third portion 348. The first portion 340 of the first fluid chamber 336
may be sealingly isolated from the first portion 344 of the second fluid chamber 338
by the first reciprocating member 306. The first portion 340 of the first fluid chamber
336 may be located on a front side of the first reciprocating member 306. In other
words, the first portion 340 of the first fluid chamber 336 may be at least partially
defined by the front surface 328 of the first reciprocating member 306. The first
portion 344 of the second fluid chamber 338 may be located on a back side of the first
reciprocating member 306. In other words, the first portion 344 of the second fluid
chamber 338 may be at least partially defined by the back surface 330 of the first
reciprocating member 306.
[0061] The first portion 344 of the second fluid chamber 338 may be isolated from the second
portion 342 of the first fluid chamber 336 by the first divider member 310a. The first
divider member 310a may be stationary relative to the first portion 344 of the second
fluid chamber 338 and the second portion 342 of the first fluid chamber 336. For example,
the first portion 344 of the second fluid chamber 338 may be located between the back
surface 330 of the first reciprocating member 306 and the first divider member 310a.
In some embodiments, the first divider member 310a may comprise a portion of the casing
356. For example, the first divider may be an annular shape protrusion extending radially
inward from the casing 356. The second portion 342 of the first fluid chamber 336
may be sealingly divided from the second portion 346 of the second fluid chamber 338
by the second reciprocating member 308. For example, the second portion 342 of the
first fluid chamber 336 may be located on a front side of the second reciprocating
member 308 (
e.g., at least partially defined by the front surface 332 of the second reciprocating
member 308), and the second portion 346 of the second fluid chamber 338 may be located
on a back side of the second reciprocating member 308 (
e.g., at least partially defined by the back surface 334 of the second reciprocating
member 308). The second portion 342 of the first fluid chamber 336 may be located
between the first divider member 310a and the front surface 332 of the second reciprocating
member 308. In some embodiments, the second portion 346 of the second fluid chamber
338 may be at least partially enclosed within the second reciprocating member 308.
[0062] The second divider member 310b may be oriented on an opposite side of the first portion
340 of the first fluid chamber 336 than the first reciprocating member 306, and the
third portion 348 of the second fluid chamber 338 may be located on an opposite side
of the second divider member 310b than the first portion 340 of the first fluid chamber
336. In other words, the third portion 348 of the second fluid chamber 338 may be
isolated from the first portion 340 of the first fluid chamber 336 by the second divider
member 310b. The second divider member 310b may be stationary relative to the first
portion 340 of the first fluid chamber 336 and the third portion 348 of the second
fluid chamber 338.
[0063] The third portion 348 of the second fluid chamber 338 may be in fluid communication
with the pressure compensator 324, and pressure compensator 324 may be configured
to at least substantially balance the pressure of the second fluid chamber 338 with
the environment pressure of an environment (e.g., mud 354 of the wellbore 102 (FIG.
1)), as discussed above in regard to FIG. 3. In other words, the pressure compensator
324 may help maintain a pressure of the second fluid chamber 338 that is at least
substantially equal to the environment pressure. For example, the pressure compensator
324 may be in fluid communication on a first side with the third portion 348 of the
second fluid chamber 338 and may be at least partially disposed within the third portion
348 of the second fluid chamber 338. The pressure compensator 324 may include one
or more of a bellows, diaphragm, and pressure compensator 324 valve and may be in
communication on a second side with an environment (
e.g., mud 354 of the wellbore 102 (FIG. 1). In some embodiments, the pressure compensator
324 may comprise a rubber material. For example, the pressure compensator 324 may
include a rubber diaphragm. The first fluid chamber 336 may have a pressure that is
higher than the pressure of the second fluid chamber 338.
[0064] As discussed above, the connection member 302 may be attached to the back surface
330 of the first reciprocating member 306 at a first longitudinal end of the connection
member 302. The connection member 302 may extend through the first portion 344 of
the second fluid chamber 338, the second portion 342 of the first fluid chamber 336,
and the second portion 346 of the second fluid chamber 338 and through the extension
hole 370 of the casing 356 of the actuation device 156. The drilling element 154 may
be attached to a second longitudinal end of the connection member 302 opposite the
first end such that that drilling element 154 may be extended and retracted through
the extension hole 370 of the external casing 356 of the actuation device 156.
[0065] The hydraulic fluid 312 may be disposed within the first fluid chamber 336 and the
second fluid chamber 338 and may at least substantially fill the first fluid chamber
336 and the second fluid chamber 338. The biasing member 314 may be disposed within
the first portion 340 of the first fluid chamber 336 and may be configured to apply
a selected force on the first reciprocating member 306 to cause the first reciprocating
member 306 to move through the first portion 344 of the second fluid chamber 338 outwardly
(
e.g., toward the extension hole 370 of the external casing 356). Furthermore, as discussed
above, the pressure differential between the first fluid chamber 336 and the second
fluid chamber 338 may assist in moving the first and second reciprocating members
306, 308 outward. As result, the biasing member 314 may cause the connection member
302 and drilling element 154 to move outwardly (
e.g., may cause the drilling element 154 to extend). In some embodiments, the biasing
member 314 may include a spring.
[0066] The first fluid flow path 316 may extend from the third portion 348 of the second
fluid chamber 338 to the first portion 340 of the first fluid chamber 336 through
the second divider member 310b. The first flow control device 320 may be disposed
within the first fluid flow path 316. Furthermore, the first flow control device 320
may be configured to control the flow rate of the hydraulic fluid 312 from the third
portion 348 of the second fluid chamber 338 to the first portion 340 of the first
fluid chamber 336. In some embodiments, the first flow control device 320 may include
one or more of a first check valve and a first restrictor. In some embodiments, the
first restrictor may include a multi-stage orifice. In some embodiments, the first
flow control device 320 may include only the first check valve. In other embodiments,
the first flow control device 320 may include only the first restrictor. In other
embodiments, the first flow control device 320 may include both the first check valve
and the first restrictor.
[0067] The second fluid flow path 318 may extend from the first portion 340 of the first
fluid chamber 336 to the second portion 346 of the second fluid chamber 338 through
the first reciprocating member 306, a portion of the connection member 302, and the
second reciprocating member 308. The second fluid flow path 318 may allow the hydraulic
fluid 312 to flow from the first portion 340 of the first fluid chamber 336 to the
second portion 346 of the second fluid chamber 338. The second flow control device
322 may be disposed within the second fluid flow path 318. Furthermore, the second
flow control device 322 may be configured to control the flow rate of the hydraulic
fluid 312 from the first portion 340 of the first fluid chamber 336 to the second
portion 346 of the second fluid chamber 338. In some embodiments, the second flow
control device 322 may include one or more of second check valve and a second restrictor.
In some embodiments, the second restrictor may include a multi-stage orifice. In some
embodiments, the second flow control device 322 may include only the second check
valve. In other embodiments, the second flow control device 322 may include only the
second restrictor. In other embodiments, the second flow control device 322 may include
both the second check valve and the second restrictor.
[0068] The first, second, and third portions 344, 346, 348 of the second fluid chamber 338
may be in fluid communication with each other via the third fluid flow path 350. In
some embodiments, the third fluid flow path 350 may include an aperture extending
through the casing 356.
[0069] The first and second portions 340, 342 of the first fluid chamber 336 may be in fluid
communication with each other via the fourth fluid flow path 352. In some embodiments,
the third fluid flow path 350 may include an aperture extending through the casing
356.
[0070] In some embodiments, the drilling element 154 may be removably attachable to the
connection member 302. A drilling element assembly 359 may be removably coupled to
the second longitudinal end of the connection member 302. The drilling element assembly
359 may include the drilling element 154, a drilling element seat 360, and a shim
362. The drilling element 154 may be disposed in the drilling element seat 360. The
shim 362 may be disposed between the drilling element seat 360 and the second longitudinal
end of the connection member 302.
[0071] In some embodiments, the drilling element 154, drilling element seat 360, and shim
362 may not be rigidly attached to the connection member 302. For example, as discussed
above, the connection member 302 may be under a preload due to the biasing member
314 disposed in the first portion 340 of the first fluid chamber 336, and the biasing
member 314 may press the connection member 302 against the shim 362, drilling element
seat 360, and drilling element 154. In some embodiments, the drilling assembly 359
may only be in contact with the connection member 302 and the preload due to the biasing
member 314 and external loads applied to the connection member 302 during drilling
operations may keep the drilling assembly 359 in contact with the connection member
302. In other words, the drilling assembly 359 may not be rigidly coupled to the connection
member 302.
[0072] Having the drilling element 154 be removably attachable to the connection member
302 may allow the drilling element 154 to be removed and replaced without disassembling
the actuation device 156. In other words, the drilling element 154 may be replaced
independent of the rest of the actuation device 156. Accordingly, removably attaching
the drilling element 154 to the connection member 302 may lead to time and cost savings
when replacing drilling elements 154. In some embodiments, both the drilling element
154 and the drilling element seat 360 may be replaced. In other embodiments, just
the drilling element 154 may be replaced. Additionally, having the drilling element
154 be removably attachable to the connection member 302 may allow a given actuation
device 156 to be used with multiple different drilling elements 154 without requiring
disassembly of the actuation device 156. As a result, the removably attachable drilling
element 154 provides for a wider variety of drilling elements 154 that be used for
a given bit body (FIG. 1) in order to suit particular applications.
[0073] The shim 362 may enable the actuation devices 156 to be used in bit bodies 202 (FIG.
2) more universally (
e.g., among different cavities in the bit bodies 202 (FIG. 2)). For example, cavities
232 (FIG. 2) in bit bodies 202 (FIG. 2) for holding the actuation devices 156 and
drilling elements 154 may have different tolerances and slightly different sizes.
Accordingly, by having a shim 362, the actuation devices and drilling elements 154
may be used in more cavities 232 (FIG. 2) of the bit body 202 (FIG. 2) and may be
shimmed with the shim 362 to meet specific tolerances.
[0074] In some embodiments, the drilling element 154 and the drilling element seat 360 may
be removable from the connection member 302. For example, the drilling element 154
and drilling element seat 360 may be removed through heating the drilling element
154 and drilling element seat 360 to a temperature above that of a melting temperature
of a brazing material used to attach the drilling element 154 and the drilling element
seat 360 to the connection member 302. However, any method known in the art may be
used to remove the drilling element 154 and drilling element seat 360 from the connection
member 302.
[0075] FIG. 6 is a simplified schematic view of an earth-boring tool 600 having an actuation
device 656 according to one or more embodiments of the present disclosure. Portions
of the earth-boring tool have been removed to better show the actuation device 656.
In one or more embodiments, the earth-boring tool 600 may include a drill bit having
one or more rotatable cutting structures in the form of roller cones and one or more
blades. For example, the earth-boring tool 600 may be a hybrid bit (
e.g., a drill bit having both roller cones and blades) as shown in FIG. 6. Furthermore,
the earth-boring tool 600 may include any other suitable drill bit or earth-boring
tool having one or more rotatable cutting structures and one or more blades for use
in drilling and/or enlarging a borehole 102 in a formation 118 (FIG. 1). For instance,
the earth-boring tool 600 may include any of the earth-boring tools described in
U.S. Application Number 15/691,219, to Schoen, filed August 30, 2017, the disclosure of which is incorporated in its entirety by reference herein.
[0076] In one or more embodiments, the earth-boring tool 600 may comprise a body 602 including
a neck 606, a shank 608, and a crown 610. In some embodiments, the bulk of the body
602 may be constructed of steel, or of a ceramic-metal composite material including
particles of hard material (
e.g., tungsten carbide) cemented within a metal matrix material. The body 602 of the
earth-boring tool 600 may have an axial center 604 defining a center longitudinal
axis 605 that may generally coincide with a rotational axis of the earth-boring tool
600. The center longitudinal axis 605 of the body 602 may extend in a direction hereinafter
referred to as an "axial direction."
[0077] The body 602 may be connectable to a drill string 110 (FIG. 1). For example, the
neck 606 of the body 602 may have a tapered upper end having threads thereon for connecting
the earth-boring tool 600 to a box end of a drilling assembly 114 (FIG. 1). The shank
608 may include a lower straight section that is fixedly connected to the crown 610
at a joint. In some embodiments, the crown 610 may include a plurality of rotatable
cutting structure assemblies 612 and a plurality of blades 614.
[0078] Each blade 614 of the plurality of blades 614 of the earth-boring tool 600 may include
a plurality of cutting elements 630 fixed thereto. The plurality of cutting elements
630 of each blade 614 may be located in a row along a profile of the blade 614 proximate
a rotationally leading face 632 of the blade 614. In some embodiments, the plurality
of cutting elements 620 of the plurality of rotatable cutting structures 618 (e.g.,
roller cutters) and plurality of cutting elements 630 of the plurality of blades 614
may include PDC cutting elements 630. Moreover, the plurality of cutting elements
630 of the plurality of rotatable cutting structures 618 and plurality of cutting
elements 630 of the plurality of blades 614 may include any suitable cutting element
configurations and materials for drilling and/or enlarging boreholes.
[0079] The plurality of rotatable cutting structure assemblies 612 may include a plurality
of legs 616 and a plurality of rotatable cutting structures 618, each respectively
mounted to a leg 616. The plurality of legs 616 may extend from an end of the body
602 opposite the neck 606 and may extend in the axial direction. The plurality of
blades 614 may also extend from the end of the body 602 opposite the neck 606 and
may extend in both the axial and radial directions. Each blade 614 may have multiple
profile regions as known in the art (cone, nose, shoulder, gage). In some embodiments,
two or more blades 614 of the plurality of blades 614 may be located between adjacent
legs 616 of the plurality of legs 616. In some embodiments, the plurality of rotatable
cutting structure assemblies 612 may not include a plurality of legs 616 but may be
mounted directed to the crown 610 on the body 602 of the earth-boring tool 600.
[0080] Fluid courses 634 may be formed between adjacent blades 614 of the plurality of blades
614 and may be provided with drilling fluid by ports located at the end of passages
leading from an internal fluid plenum extending through the body 602 from a tubular
shank 608 at the upper end of the earth-boring tool 600. Nozzles 638 may be secured
within the ports for enhancing direction of fluid flow and controlling flow rate of
the drilling fluid. The fluid courses 634 extend to junk slots extending axially along
the longitudinal side of earth-boring tool 600 between blades 614 of the plurality
of blades 614.
[0081] As noted above, the earth-boring tool 600 may further include an actuation device
656. The actuation device 656 may be disposed inside the blades 614 supported by the
bit body 602 and may be secured to the bit body 602 with a press fit proximate a face
619 of the earth-boring tool 600. Furthermore, the actuation device 656 may be coupled
to a drilling element 654 and may be configured to control rates at which the drilling
element 654 extends and retracts from the earth-boring tool 600 relative to a surface
of the earth-boring tool 600 via any of the manners described above in regard to FIGS.
2-5. For instance, the actuation device 656 may include any of the actuation devices
described above in regard to FIGS. 2-5. Furthermore, the drilling element may include
any of the drilling elements (e.g., more cutting, wear, or bearing elements) described
above in regard to FIGS. 2-5. For example, in some embodiments, the drilling element
654 may include an ovoid or an ovoid cutter. As a non-limiting example, the drilling
element 654 may include any of the ovoids described in
U.S. Application 16/004,765, to Russell et al., filed June 11, 2018, the disclosure of which is incorporated in its entirety by reference herein.
[0082] In some embodiments, the drilling element 654 coupled to the actuation device 656
may rotationally trail a primary cutting element (e.g., a cutting element of the plurality
of cutting elements 630) disposed at a leading face of the blade 614 in which the
actuation device 656 is disposed. Furthermore, the drilling element 654 may be configured
to retract and extend relative to the blade 614 (and as a result, the body 602 of
the earth-boring tool 600) responsive to contact or the lack of contact with the subterranean
formation. For example, as is discussed in greater detail below in regard to FIG.
7, in operation, when weight-on-bit is applied to the earth-boring tool 600, the drilling
element 654 may retract due to contact with the subterranean formation enabling typical
hybrid cutting actions. Moreover, as the force acting on one or more drilling elements
(e.g., WOB) is interrupted due to an event, the drilling element 654 may be extended
to reduce a depth-of-cut of one or more primary cutting elements (e.g., the plurality
of cutting elements 630) and may, in some instance, maintain more contact between
the earth-boring tool 600 and the subterranean formation. For example, due to a biasing
member of the actuation device 656, the actuation device 656 may be biased to extend
absent contact (e.g., forces applied) to the drilling element 654. Events may include
any typical event in drilling operations that may cause an interruption of force acting
on one or more drilling elements or contact between the earth-boring tool and the
subterranean formation. For instance, the event may include a change in the formation
(e.g., a change of material of the formation), picking up off bottom, vibrations which
interrupt loading, wellbore friction that prevents constant WOB transfer to the bit
(especially in deviated wellbores), uneven cutting structure loading due to rotating
the drilling assembly while a bent-sub drilling motor is include in the bottom-hole-assembly,
etc.
[0083] Although the actuation device 656 described herein includes two reciprocating members,
the disclosure is not so limited. Rather, the actuation device 656 may include any
of the actuation devices described in
U.S. Patent 9,255,450, to Jain et al., issued February 9, 2016,
U.S. Patent 9,708,859, to Jain et al., issued July 18, 2017, and/or
U.S. Patent 10,000,977, to Jain et al., issued June 19, 2018, the disclosures of which are incorporated in their entireties by reference herein.
Furthermore, the actuation device 656 may be operated via any of the manners described
in the foregoing-listed applications. As a non-limiting example, the actuation device
656 may include a single reciprocating member and may be passively or actively actuated.
[0084] By extending the drilling element 654 during events, reducing a DOC, and maintaining
more contact with the formation, the actuation device 656 may reduce vibrations (i.e.,
torsional, axial, and lateral vibrations) experienced by the earth-boring tool 600
during operation. Reducing the vibrations experienced by the earth-boring tool 600
may reduce damage to the earth-boring tool 600 and may improve earth-boring tool efficiencies.
Reducing the vibrations experienced by the earth-boring tool 600 via the actuation
device 656 is described in greater detail below in regard FIG. 7.
[0085] FIG. 7 shows a flow chart of a method 700 of reducing vibrations experienced by an
earth-boring tool (e.g., earth-boring tool 600) during a drilling operation. In some
embodiments, the method 700 may include reducing vibrations experienced by an earth-boring
tool (e.g., earth-boring tool 600) during a drilling operation that includes a combination
of crushing and scraping and/or shear cutting of a subterranean formation. For example,
the method may include vibrations experienced by an earth-boring tool comprising a
hybrid bit utilizing both fixed blades and rotatable cutting structures to perform
the drilling operation.
[0086] In some embodiments, the method 700 includes setting an initial exposure of a drilling
element coupled to an actuation device of an earth-boring tool relative to a primary
cutting element of the earth boring tool, as shown in act 710. As used herein, the
term "exposure" may refer to a distance by which an outermost point of a cutting profile
defined by the drilling element during drilling operations is spaced from an outermost
point of a cutting profile defined by a primary cutting element of the earth-boring
tool.
[0087] In one or more embodiments, setting an initial exposure of the drilling element may
include setting an initial exposure of the drilling element to be overexposed relative
to a primary cutting element disposed at a leading face of a blade in which the actuation
device is disposed. In some embodiments, setting the initial exposure of the drilling
element may include setting the initial exposure of the drilling element to be overexposed
relative to the primary cutting element by a distance within a range of about 0.5%
and about 8.0% of an overall diameter of a cutting face of the primary cutting element.
In some embodiments, the overexposure distance may be within a range of about 1.0%
and about 4.0% of the overall diameter of the cutting face of the primary cutting
element. In further embodiments, the overexposure distance may be within a range of
about 2.0% and about 3.0% of the overall diameter of the cutting face of the primary
cutting element. As a non-limiting example, the overexposure distance may be with
a range of about 0.010 inches and about 0.030 inches. For instance, the overexposure
distance may be about 0.020 inches. In some instances, the overexposure distance may
extend in an axial direction.
[0088] In some embodiments, setting an initial exposure of the drilling element may include
setting an initial exposure of the drilling element to be underexposed relative to
a primary cutting element disposed at a leading face of a blade in which the actuation
device is disposed by a distance within a range of about 0.5% and about 8.0% of an
overall diameter of a cutting face of the primary cutting element. In some embodiments,
the underexposure distance may be within a range of about 1.0% and about 4.0% of the
overall diameter of the cutting face of the primary cutting element. In further embodiments,
the underexposure distance may be within a range of about 2.0% and about 3.0% of the
overall diameter of the cutting face of the primary cutting element. As a non-limiting
example, the underexposure distance may be with a range of about 0.010 inches and
about 0.030 inches. For instance, the underexposure distance may be about 0.020 inches.
In some instances, the underexposure distance may extend in an axial direction.
[0089] In one or more embodiments, setting an initial exposure of the drilling element may
include setting an initial exposure of the drilling element to be overexposed or underexposed
by any of the above-described distances relative to a surface of a body of the earth-boring
tool instead of or in addition to a primary cutting element. For instance, setting
an initial exposure of the drilling element may include setting an initial exposure
of the drilling element to be overexposed or underexposed relative to a face of a
blade of the earth-boring tool, a bearing surface of a gage pad, etc.
[0090] In some instances, the initial exposure may represent a maximum amount that the actuation
device can extend the drilling element during a drilling operation. For instance,
the initial exposure may represent a fully extended position of the actuation device.
Put another way, the initial exposure may represent an end of an extension motion
(e.g., stroke) of the actuation device. In other embodiments, the initial exposure
may represent a minimum amount that the actuation device can extend the drilling element
during a drilling operation. For instance, the initial exposure may represent a fully
retracted position of the actuation device. Put another way, the initial exposure
may represent an end of a retraction motion (e.g., stroke) of the actuation device.
In further embodiments, the initial exposure may represent a point between a maximum
amount and a minimum amount that the actuation device can extend the drilling element
during a drilling operation.
[0091] In some embodiments, setting an initial exposure of the drilling element is not included
within method 700. For example, setting an initial exposure of the drilling element
is not required in every embodiment. Rather, in some embodiments, an initial exposure
of the drilling element may not be set or may be random.
[0092] The method 700 may further include causing at least a portion of the earth-boring
tool to contact the subterranean formation, as shown in act 720. For instance, act
720 may include causing at least one primary cutting element of the earth-boring tool
to contact the subterranean formation. In some embodiments, causing at least one primary
cutting element of earth-boring tool to contact the subterranean formation may include
applying WOB to the earth-boring tool, as shown in act 730. For instance, causing
at least one primary cutting element of earth-boring tool to contact the subterranean
formation may include applying a typical amount of WOB to the earth-boring tool to
enable typical hybrid drilling operations.
[0093] Causing the at least one primary cutting element of the earth-boring tool to contact
the subterranean formation may cause the drilling element of the actuation device
to be retracted by pressing up against the formation, as shown in act 740. For instance,
the drilling element of the actuation device may be retracted enough to enable typical
depths-of-cut with the at least one primary cutting element of the earth-boring tool.
In some embodiments, the drilling element of the actuation device may be retracted
via any of the manners described above in regard to FIGS. 2-5. The method 700 may
also include performing a drilling operation, as shown in act 750. For instance, the
method 700 may include any conventional drilling operation.
[0094] In one or more embodiments, the method 700 may further include, in response to a
drilling event, moving the drilling element relative to the body of the earth-boring
tool, as shown in act 760. As discussed above, the drilling event may include any
typical event in drilling operations that may cause an interruption of WOB or contact
between the earth-boring tool and the subterranean formation. For instance, the event
may include a change in the formation (e.g., a change of material of the formation),
picking up off bottom, etc.
[0095] As also mention above, moving the drilling element relative to the earth-boring tool
may occur responsive to contact or the lack of contact with the subterranean formation.
For instance, moving the drilling element relative to the body of the earth-boring
tool may include moving the drilling element relative to the body of the earth-boring
tool to at least substantially maintain contact between the drilling element and the
subterranean formation during and subsequent to the drilling event. In some embodiments,
moving the drilling element relative to the body of the earth-boring tool may include
extending the drilling element away from the body of the earth-boring tool due to
reduced contact with the subterranean formation and reducing a depth-of-cut of the
at least one primary cutting element. In additional embodiments, moving the drilling
element relative to the body of the earth-boring tool may include retracting the drilling
element toward the body of the earth-boring tool due to increased contact with the
subterranean formation enabling an increased depth-of-cut of the at least one primary
cutting element.
[0096] By moving the drilling element during drilling events, adjusting a DOC of the earth-boring
tool, and maintaining more contact with the subterranean formation, the actuation
device of the present disclosure may reduce vibrations (i.e., torsional, axial, and
lateral vibrations) experienced by the earth-boring tool during operation. Reducing
the vibrations experienced by the earth-boring tool may reduce damage to the earth-boring
tool and may improve earth-boring tool efficiencies.
[0097] Embodiments of the present disclosure further include the following:
Embodiment 1: A method of reducing vibration experienced by an earth-boring tool during
a drilling operation involving a combination of crushing and shear cutting a subterranean
formation, the method comprising: setting an initial exposure of a drilling element
coupled to an actuation device disposed within a blade of the earth-boring tool to
be overexposed relative to a primary cutting element disposed at a leading face of
the blade by a distance within a range of about 0.5% and about 8.0% of an overall
diameter of the primary cutting element; applying weight-on-bit to the earth-boring
tool; causing the drilling element to retract toward the actuation device and to be
underexposed relative to the primary cutting element; and in response to a drilling
event, moving the drilling element relative to a body of the earth-boring tool to
change a level of underexposure of the drilling element relative to the primary cutting
element.
Embodiment 2: The method of embodiment 1, wherein setting an initial exposure of a
drilling element relative to the primary cutting element comprises setting the distance
of the initial exposure to be within a range of about 1.0% and about 4.0% of the overall
diameter of the primary cutting element.
Embodiment 3: The method of embodiment 1, wherein setting an initial exposure of a
drilling element relative to the primary cutting element comprises setting the distance
of the initial exposure to be within a range of about 2.0% and about 3.0% of the overall
diameter of the primary cutting element.
Embodiment 4: The method of any of embodiments 1-3, wherein moving the drilling element
relative to a body of the earth-boring tool reduces an axial vibration experienced
by the earth-boring tool.
Embodiment 5: The method of any of embodiments 1-4, wherein moving the drilling element
relative to a body of the earth-boring tool reduces a torsional vibration experienced
by the earth-boring tool.
Embodiment 6: The method of any of embodiments 1-5, wherein moving the drilling element
relative to a body of the earth-boring tool reduces a lateral vibration experienced
by the earth-boring tool.
Embodiment 7: The method of any of embodiments 1-6, wherein, in response to a drilling
event, moving the drilling element relative to a body of the earth-boring tool comprises,
in response to a change in the subterranean formation, moving the drilling element
relative to the body of the earth-boring tool.
Embodiment 8: The method of any of embodiments 1-7, wherein, in response to a drilling
event, moving the drilling element relative to a body of the earth-boring tool comprises,
in response to an interruption in an application of weight-on-bit, moving the drilling
element relative to the body of the earth-boring tool.
Embodiment 9: The method of any of embodiments 1-8, wherein moving the drilling element
relative to a body of the earth-boring tool comprises reducing contact between the
primary cutting element and the subterranean formation.
Embodiment 10: The method of any of embodiments 1-9, wherein moving the drilling element
relative to a body of the earth-boring tool comprises reducing a depth-of-cut of the
primary cutting element.
Embodiment 11: The method of any of embodiments 1-10, wherein moving the drilling
element relative to a body of the earth-boring tool comprises reducing a level of
underexposure of the drilling element relative to the primary cutting element.
Embodiment 12: The method of any of embodiments 1-11, wherein moving the drilling
element relative to a body of the earth-boring tool comprises overexposing the drilling
element relative to the primary cutting element.
Embodiment 13: A method of reducing vibration experienced by an earth-boring tool
during a drilling operation involving a combination of crushing and shear cutting
a subterranean formation, the method comprising: setting an initial exposure of a
drilling element coupled to an actuation device disposed within a blade of the earth-boring
tool relative to a primary cutting element disposed at a leading face of the blade;
causing the drilling element to move relative to the actuation device and to have
a second exposure relative to the primary cutting element by applying weight-on-bit;
maintaining at least substantially continuous contact between the drilling element
and the subterranean formation during the drilling operation; and in response to a
drilling event, moving the drilling element relative to a body of the earth-boring
tool to at least substantially maintain contact between the drilling element and the
subterranean formation during and subsequent to the drilling event.
Embodiment 14: The method of embodiment 13, wherein moving the drilling element relative
to a body of the earth-boring tool to at least substantially maintain contact between
the drilling element and the subterranean formation comprises reducing a level of
underexposure of the drilling element relative to the primary cutting element.
Embodiment 15: The method of embodiment 13 or embodiment 14, wherein moving the drilling
element relative to a body of the earth-boring tool to at least substantially maintain
contact between the drilling element and the subterranean formation comprises overexposing
the drilling element relative to the primary cutting element.
Embodiment 16: The method of any of embodiments 13-15, setting an initial exposure
of a drilling element comprises setting the drilling element to be overexposed relative
to the primary cutting element disposed at the leading face of the blade.
Embodiment 17: The method of any of embodiments 13-16, wherein causing the drilling
element to move relative to the actuation device and to have a second exposure relative
to the primary cutting element comprises causing the drilling element to retract toward
the actuation device and to be underexposed relative to the primary cutting element.
Embodiment 18: The method of any of embodiments 13-15 or 17, wherein setting an initial
exposure of a drilling element comprises setting the drilling element to be underexposed
relative to the primary cutting element disposed at the leading face of the blade.
Embodiment 19: The method of any of embodiments 13-18, wherein moving the drilling
element relative to a body of the earth-boring tool comprises reducing contact between
the primary cutting element and the subterranean formation.
Embodiment 20: The method of any of embodiments 13-19, wherein moving the drilling
element relative to a body of the earth-boring tool comprises reducing a depth-of-cut
of the primary cutting element.
Embodiment 21: An earth-boring tool, comprising: a body; a plurality of blades extending
from the body; at least one rotatable cutting structure assembly coupled to the body;
an actuation device disposed at least partially within a blade of the plurality of
blades, the actuation device comprising: a first fluid chamber; a second fluid chamber;
at least one reciprocating member configured to reciprocate back and forth within
the first fluid chamber and the second fluid chamber, the at least one reciprocating
member having a front surface and a back surface; a hydraulic fluid disposed within
and at least substantially filling the first fluid chamber and the second fluid chamber;
and a connection member attached to the at least one reciprocating member and extending
out of the second fluid chamber; and a drilling element removably coupled to the connection
member of the actuation device.
Embodiment 22: The earth-boring tool of embodiment 21, wherein the drilling element
exhibits a biased overexposure relative to a primary cutting element disposed at a
leading face of the blade by a distance within a range of about 0.5% and about 8.0%
of an overall diameter of the primary cutting element.
Embodiment 23: The earth-boring tool of embodiment 21, wherein the drilling element
exhibits a biased overexposure relative to a primary cutting element disposed at a
leading face of the blade by a distance within a range of about 2.0% and about 3.0%
of an overall diameter of the primary cutting element.
[0098] The embodiments of the disclosure described above and illustrated in the accompanying
drawings do not limit the scope of the disclosure, which is encompassed by the scope
of the appended claims and their legal equivalents. Any equivalent embodiments are
within the scope of this disclosure. Indeed, various modifications of the disclosure,
in addition to those shown and described herein, such as alternative useful combinations
of the elements described, will become apparent to those skilled in the art from the
description. Such modifications and embodiments also fall within the scope of the
appended claims and equivalents.