CN111287665A

CN111287665A - Self-adjusting ground engaging tool and associated system and method for reducing vibration

Info

Publication number: CN111287665A
Application number: CN201911280894.3A
Authority: CN
Inventors: R·M·韦尔奇
Original assignee: Baker Hughes a GE Co LLC
Current assignee: Baker Hughes Holdings LLC
Priority date: 2018-12-07
Filing date: 2019-12-09
Publication date: 2020-06-16
Also published as: CA3063866A1; MX2019014509A; AU2019275556A1; RU2019139569A; EP3667012A1

Abstract

A self-adjusting ground engaging tool and associated system and method for reducing vibration. The method reduces vibration experienced by the earth-engaging tool during drilling operations that include a combination of crushing and shear cutting of subterranean formations. The method comprises the following steps: setting an initial exposure of a drilling element coupled to an actuating device disposed within a blade of the earth-engaging tool to overexpose or underexpose a distance relative to a primary cutting element disposed at a leading face of the blade, the distance being in a range of 0.5% to 8.0% of an overall diameter of the primary cutting element; applying bit pressure to the ground digging tool; retracting the drilling element toward the actuator and underexposing with respect to the primary cutting element; and in response to a drilling event, moving the drilling element relative to the body of the earth-engaging tool to change the underexposure level of the drilling element relative to the primary cutting element.

Description

Self-adjusting ground engaging tool and associated system and method for reducing vibration

Priority requirement

This application claims benefit Of filing date Of U.S. provisional patent application serial No. 16/213,838 entitled "Self-Adjusting Earth-supporting tools and Related Systems and Methods Of Reducing visions" filed on 7.12.2018, the contents and disclosure Of which are incorporated herein by reference in their entirety.

Technical Field

The present disclosure relates generally to self-adjusting ground engaging tools, bottom hole assemblies, and systems incorporating self-adjusting ground engaging tools for drilling wellbores and methods of using such self-adjusting ground engaging tools, assemblies, and systems.

Background

Oil wells (wellbores) are typically drilled with a drill string. The drill string includes a tubular member having a drilling assembly including a single drill bit at a bottom end thereof. The drilling assembly typically includes devices and sensors that provide information relating to various parameters relating to the drilling operation ("drilling parameters"), the behavior of the drilling assembly ("drilling assembly parameters"), and parameters relating to the formation penetrated by the wellbore ("formation parameters"). A drill bit and/or reamer attached to the bottom end of a drilling assembly is rotated by rotating the drill string of 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 profile trajectories in a manner commonly referred to as directional drilling. For example, a single wellbore may include one or more vertical, deviated, and horizontal sections that extend through different types of formations.

When drilling with a fixed cutter or so-called "drag" bit or other earth-engaging tool proceeds from a soft formation (e.g., sandstone) to a hard formation (e.g., shale) or from a hard formation to a soft formation, the rate of penetration ("ROP") changes and excessive ROP fluctuations and/or vibrations (lateral or torsional) may be generated in the bit. ROP is typically controlled by controlling the Weight On Bit (WOB) and the rotational speed (revolutions per minute or "RPM") of the drill bit. WOB is controlled by controlling the hook load on the surface and RPM is controlled by controlling drill string rotation on the surface and/or by controlling the drilling motor speed in the drilling assembly. Controlling bit vibration and ROP by such methods requires the drilling system or operator to take action at the surface. The effect of such ground actions on bit fluctuations is not substantially immediate. For a given WOB and bit rotational speed, bit attack can result in vibration, rotation, and stick-slip. The "depth of cut" ("DOC") of a fixed cutter drill bit is generally defined as the distance into the formation a bit makes one revolution, which is an important factor associated with bit aggressiveness. Controlling the DOC can prevent excessive formation material buildup on the drill bit (e.g., "balling up" the bit), limit reactive torque to acceptable levels, enhance steerability and directional control of the bit, provide a smoother borehole with a more consistent diameter, avoid premature failure of cutting elements, and extend the useful life of the bit.

Disclosure of Invention

One or more embodiments of the present disclosure may include a method of reducing vibration experienced by a ground engaging 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 actuating device disposed within a blade of a ground engaging tool to overexpose a distance relative to a primary cutting element disposed at a leading face of the blade, the distance being in a range of about 0.5% to about 8.0% of an overall diameter of the primary cutting element; applying bit pressure to the ground digging tool; retracting the drilling element toward the actuation device and in an underexposed direction relative to the primary cutting element; and in response to a drilling event, moving the drilling element relative to the body of the earth-engaging tool to change the underexposure level of the drilling element relative to the primary cutting element.

One or more embodiments of the present disclosure may include a method of reducing vibration experienced by a ground engaging 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 actuating device disposed within a blade of a ground engaging tool relative to a primary cutting element disposed on a leading face of the blade; moving the drilling element relative to the actuating device and having 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 a drilling operation; and in response to the drilling event, moving the drilling element relative to the body of the earth-engaging tool during and after the drilling event to at least substantially maintain contact between the drilling element and the subterranean formation.

One or more embodiments of the present disclosure may include a ground engaging tool including a body. The ground engaging tool may also include a plurality of blades extending from the body. The ground engaging tool may further 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 excavation tool can also include a first fluid chamber. The excavation tool can also include a second fluid chamber. The ground engaging tool may also include at least one reciprocating member configured to reciprocate in the first fluid chamber and the second fluid chamber, the at least one reciprocating member having a front surface and a rear surface. The ground engaging tool may also include a hydraulic fluid disposed within and at least substantially filling the first and second fluid chambers. The ground engaging tool may also include a connecting member attached to the at least one reciprocating member and extending from the second fluid chamber. The ground engaging tool may also include a drilling element removably coupled to the connecting member of the actuating device.

Drawings

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 are generally indicated by like reference numerals, and:

FIG. 1 is a schematic illustration of a wellbore system including a drill string including 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 one embodiment of the present disclosure;

FIG. 3 is a schematic view of an actuation arrangement for a self-adjusting drill bit according to one embodiment of the present disclosure;

FIG. 4 is a schematic view of an actuation arrangement for 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 one embodiment of the present disclosure; and

fig. 7 illustrates a flow chart of a method of reducing vibration experienced by a ground engaging tool during a drilling operation.

Detailed Description

The illustrations presented herein are not actual views of any particular drilling system, ground engaging tool assembly, or components of such assemblies, but are merely idealized representations which are employed to describe the present disclosure.

As used herein, the terms "drill bit" and "ground engaging tool" refer to and include, respectively, ground engaging tools used to form, enlarge, or both form and enlarge a wellbore. Non-limiting examples of drill bits include fixed cutter drill bits (drag bits), fixed cutter coring bits, fixed cutter eccentric bits, fixed cutter bi-center bits, fixed cutter reamers, broachable reamers with blades supporting the fixed cutter, and hybrid drill bits comprising a fixed cutter and a movable cutting structure (rolling cone).

As used herein, the term "fixed cutter" refers to and includes a cutting element configured for shear, abrasive, or percussive (percussive) cutting action and fixed in a structure supporting the cutting element (such as, but not limited to, a bit body, a tool body, or a reamer) with respect to rotational movement.

As used herein, the terms "wear element" and "support element" refer to and include elements mounted on a ground engaging tool, respectively, and which are configured to substantially cut or remove formation material when they contact a subterranean formation in which a wellbore is being drilled or enlarged.

As used in this application, the term "drilling element" refers to and includes fixed cutters, wear elements, and bearing elements. For example, the drilling elements may include cutting elements, pads, elements that make rolling contact, elements that reduce friction with the formation, PDC bit blades, rolling cones, elements for changing the geometry of the junk slots, and the like.

As used in this application, any relational terms such as "first," "second," "front," "back," and the like are used for clarity and ease of understanding the present disclosure and the drawings, and do not imply or rely on any particular preference or order unless the context clearly dictates otherwise.

As used herein, the term "substantially" in reference to a given parameter, characteristic, or condition means and includes to some extent that the given parameter, characteristic, or condition is satisfied with a small degree of variation, such as within acceptable manufacturing tolerances, as would be understood by one skilled in the art. For example, a substantially satisfactory parameter may be at least about 90% satisfied, at least about 95% satisfied, or even at least about 99% satisfied.

Some embodiments of the present disclosure include a self-adjusting drill bit 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 drill bit. The drilling element may be attached to a connecting member attached to at least two reciprocating members within the actuating device. The reciprocating member may extend and retract the drill by moving through inward and outward strokes. The actuation means may comprise a first fluid chamber and a second fluid chamber. The pressure of the first fluid chamber may be higher than the pressure of the second fluid chamber. Further, the first fluid chamber may have a first portion configured to apply pressure to the first reciprocating member and a second portion configured to apply pressure to the second reciprocating member. Thus, since the pressure is applied to the first surface of the first reciprocating member and the second surface of the second reciprocating member, the first surface and the second surface can be small while the same force is provided to the connecting member by the pressure. Some embodiments of the present disclosure include an actuation device for a self-adjusting drill bit that includes a removable drilling element. Further, some embodiments of the present disclosure include an actuation device having a pressure compensator for equalizing an ambient pressure with a pressure of the second fluid chamber. In some embodiments, the pressure compensator may comprise a rubber material.

FIG. 1 is a schematic diagram of one example of a drilling system 100 that may utilize the apparatus and methods for drilling wellbores disclosed herein. Fig. 1 shows a wellbore 102, the wellbore 102 including an upper portion 104 with a casing 106 installed and a lower portion 108 drilled with a drill string 110. The drill string 110 may include a tubular member 112, the tubular member 112 carrying a drilling assembly 114 at a bottom end thereof. The tubular member 112 may be constructed by connecting drill pipe sections, or it may be a continuous string of pipes. A drill bit 116 may be attached to the bottom end of the drilling assembly 114 to drill a wellbore 102 having a selected diameter in the formation 118.

The drill string 110 may extend above ground 122 to a drilling rig 120. For ease of explanation, the rig 120 is shown as a land rig 120. However, the disclosed apparatus and method are equally applicable when drilling a wellbore underwater using an offshore drilling rig 120. A rotary table 124 or top drive may be coupled to the drill string 110 and may be used to rotate the drill string 110 and rotate the drilling assembly 114, thereby causing the drill bit 116 to drill the wellbore 102. A drilling motor 126 (also referred to as a "mud motor") may be disposed in the drilling assembly 114 to rotate the drill bit 116. The drilling motor 126 may be used to rotate the drill bit 116 alone or in combination with the rotation of the drill bit 116 by the drill string 110. The drilling rig 120 also includes conventional equipment such as mechanisms to add additional sections to the tubular member 112 while drilling the wellbore 102. A surface control unit 128, which may be a computer-based unit, may be placed on the surface 122 to receive and process downhole data transmitted by the sensors 140 in the drill bit 116 and the sensors 140 in the drilling assembly 114, and to control the operation of the various devices and sensors 140 in the drilling assembly 114. The sensors 140 may include one or more sensors 140 for determining acceleration, bit weight, torque, pressure, cutting element position, penetration rate, inclination, azimuthal formation/lithology, and the like. In some embodiments, the surface control unit 128 may include a processor 130 and a data storage device 132 (or 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, Read Only Memory (ROM), Random Access Memory (RAM), flash memory, magnetic tape, hard disk, and optical disk. During drilling, drilling fluid from a drilling source 136 may be pumped under pressure through the tubular member 112, which tubular member 112 drains at the bottom of the drill bit 116 and returns to the surface 122 via an annular space (also referred to as an "annulus") between the drill string 110 and an inner wall 138 of the wellbore 102.

The drilling assembly 114 may also include one or more downhole sensors 140 (generally represented by reference numeral 140). The sensors 140 may include any number and type of sensors 140, including, but not limited to, sensors 140 commonly referred to as Measurement While Drilling (MWD) sensors 140 or Logging While Drilling (LWD) sensors 140, and sensors 140 that provide information related to the behavior of the drilling assembly 114, such as bit rotation (revolutions per minute or "RPM"), toolface, pressure, vibration, rotation, bending, and stick-slip. The drilling assembly 114 may also include a controller unit 142 that controls the operation of the sensors 140 and one or more devices in the drilling assembly 114. For example, the controller unit 142 may be disposed within the drill bit 116 (e.g., in the shank and/or crown of the bit body of the drill bit 116). The controller unit 142 may include: circuitry to process signals from the sensor 140, a processor 144 (e.g., a microprocessor) to process the digitized signals, a data storage device 146 (e.g., solid state memory), and a computer program 148. The processor 144 may process the digitized signals, control the downhole devices and sensors 140, and communicate data information to the surface control unit 128 via the two-way telemetry unit 150.

The drill bit 116 may include an end face 152 (or bottom). During drilling, the face 152 or a portion thereof may face the undrilled formation 118 in front of the drill bit 116 at the bottom of the wellbore 102. In some embodiments, the drill bit 116 may include one or more cutting elements that may be extended and retracted from a surface of the drill bit 116, such as a surface on the end face 152, and in particular a blade protruding from the end face 152. The actuation device 156 may control the rate of extension and retraction of the drilling element 154 relative 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 the force or pressure applied to the drilling element 154 during drilling. In some embodiments, the actuation device 156 and the drilling element 154 may be actuated by contact of the drilling element 154 with the formation 118. In some drilling operations, when the depth of cut ("DOC") of the drill bit 116 is rapidly changed, significant forces may be experienced on the drilling element 154. Accordingly, the actuation device 156 may be configured to resist sudden changes in the DOC of the drill bit 116. As described in more detail with reference to fig. 2-5, in some embodiments, the rate of extension and retraction of the drilling element 154 may be preset.

Fig. 2 illustrates a ground engaging tool 200 having an actuating device 156 according to an embodiment of the present disclosure. In some embodiments, the ground engaging tool 200 includes a fixed cutter Polycrystalline Diamond Compact (PDC) bit having a bit body 202, the bit body 202 including a neck 204, a shank 206, and a crown 208. The ground engaging tool 200 may be any suitable drill bit or ground engaging tool for drilling and/or enlarging a wellbore in a formation.

The neck 204 of the bit body 202 may have a tapered upper end 210 with threads 212 thereon for connecting the ground engaging tool 200 to the box end of the drilling assembly 114 (fig. 1). The stem 206 may include a lower straight section 214, the lower straight section 214 being fixedly connected to the crown 208 at a joint 216. The crown 208 may include a plurality of blades 220. Each blade 220 may have a plurality of regions (taper, nose, shoulder, gauge) as known in the art.

The ground engaging tool 200 can include one or more cutting, wear or support elements 154 (hereinafter "drilling elements 154") that extend and retract from the surface 230 of the ground engaging tool 200. The bit body 202 of the earth-engaging tool 200 may carry (e.g., be accompanied by) a plurality of drilling elements 154. As shown in fig. 2, the drilling element 154 is movably disposed in a cavity or recess 232 of the crown 208. The actuating device 156 can be coupled to the drilling element 154 and can be configured to control the rate at which the drilling element 154 is extended and retracted from the ground engaging tool 200 relative to the surface 230 of the ground engaging tool 200. In some embodiments, the actuating device 156 may be oriented with the longitudinal axis of the actuating device 156 oriented at an acute angle (e.g., inclined) relative to the direction of rotation of the ground engaging tool 200 to minimize the tangential component of the frictional force experienced by the actuating device 156. In certain embodiments, the actuating device 156 may be disposed inside a blade 220 supported by the bit body 202 and may be secured near the end face 219 of the bit body 202 of the bit tool 200 by a press fit. In some embodiments, the actuation device 156 may be disposed within a gauge region of the bit body 202. For example, the actuation device 156 may be coupled to the gage pad and may be configured to control the rate at which the gage pad extends and retracts from the gage portion of the bit body 202. For example, the actuation device 156 may be disposed within the gauge portion similar to the actuation device described in U.S. patent application No. 14/516,069 to Jain, the disclosure of which is incorporated herein by reference in its entirety.

Fig. 3 illustrates a schematic view of the actuating device 156 of the self-adjusting ground engaging tool 200 (fig. 2) according to one embodiment of the present disclosure. The actuation device 156 may include a connecting member 302, a chamber 304, a first reciprocating member 306, a second reciprocating member 308, a dividing member 310, 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 the drilling element 154.

The first reciprocating member 306 and the second reciprocating member 308 may be attached to the connecting member 302 at different locations along the longitudinal axis of the connecting member 302. For example, the first reciprocating member 306 may be attached to a first longitudinal end of the connecting member 302, while the second reciprocating member 308 may be axially attached to a portion of the connecting member 302 between the first longitudinal end and the second longitudinal end. The drilling element 154 may be attached to a second longitudinal end of the connecting member 302. In some embodiments, the first reciprocating member 306 may have a generally cylindrical shape, while the second reciprocating member 308 may have a generally annular shape. The first reciprocating member 306 may have a front surface 328 and an opposing rear surface 330, while the second reciprocating member 308 may have a front surface 332 and an opposing rear surface 334. As used herein, the "front surface" of the reciprocating member may refer to a surface of the reciprocating member that, if subjected to a force, will cause the reciprocating member to move the connecting member 302 outward (e.g., at least partially out of the removal chamber 304) toward the formation 118 (fig. 1). For example, the front surface 328 of the first reciprocating member 306 may be the surface of the first reciprocating member 306 opposite the connecting member 302. Further, as used herein, the "rear surface" of the reciprocating member may refer to a surface of the reciprocating member that, if subjected to a force, will cause the reciprocating member to move the connecting member 302 inwardly and further into the chamber 304. For example, the rear surface 330 of the first reciprocating member 306 may be the surface of the first reciprocating member 306 that is attached to the connecting member 302.

The front surface 328 of the first reciprocating member 306 can be at least substantially parallel to the front surface 332 of the second reciprocating member 308. Further, the rear surface 330 of the first reciprocating member 306 may be at least substantially parallel to the rear surface 334 of the second reciprocating member 308.

The chamber 304 may be sealingly divided into a first fluid chamber 336 and a second fluid chamber 338 by first and second reciprocating members 306, 308 (e.g., pistons) and a partition member 310. The first fluid chamber 336 may include a first portion 340 and a second portion 342. In addition, 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 the rear side of the first reciprocating element 306. In other words, the first portion 344 of the second fluid chamber 338 may be at least partially defined by the rear surface 330 of the first reciprocating member 306.

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 partition member 310. The partition member 310 may be fixed 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 positioned between the rear surface 330 of the first reciprocating member 306 and the partition member 310. The second portion 342 of the first fluid chamber 336 may be sealingly separated 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), while 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). Additionally, the second portion 342 of the first fluid chamber 336 may be located between the partition member 310 and the front surface 332 of the second reciprocating member 308.

As a result of the above-described orientation, various portions (i.e., respective first and second portions) of the first and second

fluid chambers

336, 338 may be oriented (e.g., stacked) in parallel within the chamber 304. As such, the various portions (i.e., the respective first and second portions) of the first and second

fluid chambers

336, 338 may be oriented parallel to one another along the longitudinal direction of the actuation device 156.

The first and second

fluid chambers

336, 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 magnetorheological fluid and an electrorheological fluid.

In some embodiments, the first and second

fluid chambers

336, 338 may be in fluid communication with each other via the first and second

fluid flow paths

316, 318. For example, the first fluid flow path 316 may allow the 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. Further, 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.

The first flow control device 320 may be disposed within the first fluid flow path 316 and may be configured to control a 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 flow restrictor (e.g., an 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 flow restrictor. In other embodiments, the first flow control device 320 may include a first check valve and a first flow restrictor.

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. Further, 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 a flow rate of the hydraulic fluid 312 from the first fluid chamber 336 to the second fluid chamber 338 (i.e., from the first portion 340 and the second portion 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 flow restrictor (e.g., an orifice). in some embodiments, the second flow control device 322 may include only the second check valve.

As described above, the connecting member 302 may be connected at a first longitudinal end thereof to the rear surface 330 of the first reciprocating member 306, which faces the first portion 344 of the second fluid chamber 338. Further, as described above, the connecting member 302 may be connected to the drilling element 154 at a second, opposite longitudinal end of the connecting member 302. A biasing member 314 (e.g., a spring) may be disposed within the first portion 340 of the first fluid chamber 336, may be attached to the first reciprocating member 306 on a front surface 328 of the first reciprocating member 306 opposite the connecting member 302, may exert a force on the first reciprocating member 306, may move the first reciprocating member 306, and as a result, the connecting member 302 outward toward the formation 118 (fig. 1). For example, the biasing member 314 may move the first reciprocating member 306 outward, which in turn may move the connecting member 302 and the drilling element 154 outward (i.e., extend the drilling element 154). This movement of the first reciprocating member 306, the connecting member 302 and the 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 displace the 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.

As described above, the second reciprocating member 308 may also be attached to the connecting member 302, but may be axially attached to a portion of the connecting member 302 between a first longitudinal end connected to the first reciprocating member 306 and a second longitudinal end connected to the drilling member 154. For example, the second reciprocating member 308 may have a generally annular shape, and the connecting member 302 may extend through the second reciprocating member 308. Additionally, the second reciprocating member 308 may be spaced at least some distance from the first reciprocating member 306 along the longitudinal axis of the connecting member 302. Further, since the second reciprocating member 308 is attached to the connecting member 302 and the connecting member 302 is attached to the first reciprocating member 306, when the first reciprocating member 306 is moved outward by the biasing member 314, the second reciprocating member 308 is moved outward. In other words, in addition to the outward movement of the first reciprocating member 306, the force exerted by the biasing member 314 on the first reciprocating member 306 may cause the outward movement of the second reciprocating member 308. As the second reciprocating member 308 moves outward, the second reciprocating member 308 may displace the 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.

In some embodiments, the pressure of the second fluid chamber 338 may be at least substantially equal to ambient pressure, while the pressure of the first fluid chamber 336 may be higher than the pressure of the second fluid chamber 338. For example, when the connection member 302 is being subjected to an external load (e.g., the drilling element 154 is pushing against the formation 118 (fig. 1)), the pressure of the fluid chamber 336 may be higher than the pressure of the second fluid chamber 338. The pressure differential between the first and second

fluid chambers

336, 338 may assist in applying a selected force on the first and second

reciprocating members

306, 308 and moving the first and second

reciprocating members

306, 308 such that, as a result, the connecting member 302 and the drilling element 154 pass through an outward stroke. For example, the pressure of the first portion 340 of the first fluid chamber 336 in fluid communication with the front surface 328 of the first reciprocating member 306 may be higher than the pressure of the first portion 344 of the second fluid chamber 338 in fluid communication with the rear 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 the selected force on the front surface 328 of the first reciprocating member 306. Additionally, the pressure of the second portion 342 of the first fluid chamber 336 in fluid communication with the front surface 332 of the second reciprocating member 308 may be higher than the pressure of the second portion 346 of the second fluid chamber 338 in fluid communication with the rear 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 the selected force on the front surface 332 of the second reciprocating member 308.

Because the pressure of the first and

second portions

340, 342 of the first fluid chamber 336 is higher than the pressure of the first and

second portions

344, 346 of the second fluid chamber 338 and is located at different positions along the longitudinal axis of the connecting member 302, the total force exerted by the pressure of the first fluid chamber 336 may be proportionally exerted on the different positions (i.e., the first and second reciprocating members 306, 308) along the longitudinal axis of the connecting member 302.

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 the longitudinal length of the connecting member 302 may result in the cross-sectional area of the entire actuating device 156 being less than the cross-sectional area of an actuating device 156 having a single high-pressure fluid chamber. Furthermore, having the pressure of the first and

second portions

340, 342 of the first fluid chamber 336 higher and distributed along the longitudinal length of the connecting member 302 may result in a smaller cross-sectional area of the overall actuation device 156 while maintaining the same force on the connecting member 302. For example, because a higher pressure is applied to the

front surfaces

328, 332 of both the first reciprocating member 306 and the second reciprocating member 308, the surface area of the

front surfaces

328, 332 of the first reciprocating member 306 and the second reciprocating member 308, respectively, may be smaller while applying the selected force than if there were only a single larger reciprocating member. In addition, two smaller reciprocating members are used to apply the same selected force to the connecting member 302 as a single larger reciprocating member would apply. In other words, by providing two reciprocating members, the surface area of the front surface of each reciprocating member may be less than the surface area required for a single reciprocating member to exert a selected force on the connecting member 302. In other words, the pressure of the first fluid chamber 336 may be divided between and applied to at least two surface areas that are substantially parallel to each other (i.e., the

front surfaces

328, 332 of the first reciprocating member 306 and the second reciprocating member 308). In still other words, the first and second

reciprocating members

306, 308 may provide sufficient surface area between the two

front surfaces

328, 332 of the first and second

reciprocating members

306, 308 that is in fluid communication with the hydraulic fluid 312 (e.g., high pressure hydraulic fluid 312) in the first fluid chamber 336 to withstand (e.g., process, carry, absorb, attenuate) the load (e.g., force) experienced by the connecting member 302 and the first and second

reciprocating members

306, 308 during drilling operations for the wellbore 102 (fig. 1).

As a result of the above, the total cross-sectional area of the actuating device 156 may be less than the total cross-sectional area of the actuating device 156 having a single reciprocating member, and the actuating device 156 may apply the same force to the linkage 302 as the actuating device 156 having a single reciprocating member with the pressure of the first fluid chamber 336.

Referring to fig. 1,2, and 3 together, reducing the cross-sectional area of actuating device 156 (which is necessary to apply a selected force to connecting member 302 of actuating device 156 or to withstand (e.g., absorb, endure, withstand, support, etc.) the force applied to connecting member 302 by 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, the space required to house the actuation device 156 is also reduced. Thus, the actuation device 156 may be provided in more types and sizes of bit bodies 202. For example, the actuation device 156 may be disposed within a smaller bit body 202 than may be achievable with known actuation devices. Further, because less space is required, the actuation device 156 may be placed in more locations within the bit body 202. Furthermore, because less space is required, more drilling elements 154 of the bit body 202 may be attached to the actuating device 156. Furthermore, because less space is required, the actuation device 156 is less likely to compromise the structural integrity of the bit body 202. Thus, a given bit body 202 may be used in more applications and may have added functionality. Although the present application describes the drive device 156 as being used with the bit body 202 or bit, the drive device 156 is equally applicable to reamers, percussive tools, hole openers, and the like.

In some embodiments, the second fluid chamber 338 may be maintained at a pressure substantially equal to an ambient pressure (e.g., a pressure external to the ground engaging tool 200 (fig. 2)) using the pressure compensator 324, which pressure compensator 324 may be in fluid communication with the second fluid chamber 338. For example, one or more of the first portion 344 or the second portion 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, a diaphragm, a pressure compensator 324 valve, and the like. For example, the pressure compensator 324 may include a diaphragm in fluid communication with the environment (e.g., mud of the wellbore 102 (fig. 1)) on one side and the hydraulic fluid 312 in the second fluid chamber 338 on the other side, and may at least substantially balance the pressure of the second fluid chamber 338 with the ambient pressure. In some embodiments, the pressure compensator 324 may comprise a rubber material. For example, the pressure compensator 324 may include a rubber diaphragm. The inclusion of the pressure compensator 324 may reduce the sealing pressure required for mud and oil seals included in the actuating device 156.

Still referring 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 that may move the connecting member 302, thereby causing the first reciprocating member 306 and the second reciprocating member 308 to move inwardly. Moving the first reciprocating member 306 inward may drain 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. Additionally, moving the second reciprocating member 308 inward may drain the 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 first and

second portions

340, 342 of first fluid chamber 336 into second portion 346 of second fluid chamber 338 may move drilling element 154 inward (i.e., retract drilling element 154). This movement of the first and second

reciprocating members

306, 308 and the drilling element 154 may be referred to herein as an "inward stroke".

The speed of movement of the first reciprocating member 306 and the second reciprocating member 308 (e.g., the speed at which the first reciprocating member 306 and the second reciprocating member 308 move through the outward and inward strokes) may be controlled by the flow rate 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 speed of movement of the drilling element 154 (e.g., the speed at which the drilling element 154 is extended and retracted) and the position of the drilling element 154 relative to the surface 230 (fig. 2) may be controlled by the flow rate 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.

In some embodiments, the flow rate of the hydraulic fluid 312 through the first and second fluid flow paths 316, 318 (and thus the flow between the first and second fluid chambers 336, 338) may be set, at least in part, by selecting the hydraulic fluid 312 to have a viscosity that produces a desired flow rate. In some embodiments, the flow rate of the hydraulic fluid 312 through the first fluid flow passage 316 and the second fluid flow passage 318 may be set, at least in part, by selecting a flow control device having a flow rate that produces a desired flow rate. Further, the hydraulic fluid 312 (and specifically the viscosity of the hydraulic fluid 312) may be selected to increase or decrease the effectiveness of the first and second

flow control devices

320, 322.

As a non-limiting example, the first and second

flow control devices

320, 322 may be selected to provide a slow outward stroke of the drilling element 154 (i.e., a slow flow rate of the hydraulic fluid 312 through the first fluid flow path 316) 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 flow restrictor may be disposed in the first fluid flow path 316 to provide a slow outward stroke, while 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 flow control device 320 and the second flow control device 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 rapid outward stroke, while a second flow restrictor is disposed in the second fluid flow path 318 to provide a slow inward stroke.

In some embodiments, the viscosity of the hydraulic fluid 312 and the first and second

flow control devices

320, 322 may be selected to provide a constant fluid flow rate exchange between the first and second

fluid chambers

336, 338. The constant fluid flow rate may provide a first constant rate for extension of the connection member 302 and a second constant rate for retraction of the connection member 302, thus providing a corresponding constant rate 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 the biasing member 314 extends the drilling element 154 to a maximum extended position when the ground engaging tool 200 (fig. 2) is not in use, i.e., no external force is applied to 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 the biasing member 314 relatively quickly or abruptly extends the drilling element 154.

In some embodiments, the flow rate of the hydraulic fluid 312 through the second fluid flow path 318 may be set to allow the hydraulic fluid 312 to flow relatively slowly from the first fluid chamber 336 to the second fluid chamber 338, thereby causing the drilling element 154 to retract relatively slowly relative to the surface 230 (fig. 2). For example, the rate of extension of the drilling element 154 may be set such that the drilling element 154 extends from a fully retracted position to a fully extended position over a few seconds or fractions of a second while it retracts from the fully extended position to the fully deployed position over a minute or minutes or more (e.g., 2 to 5 minutes). It should be noted that any suitable rate may be provided for the extension and retraction of the drilling element 154. Accordingly, the earth-engaging tool 200 (fig. 2) may be used as a self-adjusting drill bit, such as described in U.S. patent application publication No. 2015/0191979 a1, filed 2014, 6, by Jain et al, the entire contents of which are incorporated herein by reference.

In other embodiments, the actuation device 156 may include a rate controller as described in U.S. application No.14/851,117 filed by Jain on 11/9 2015 (the disclosure of which is incorporated herein by reference in its entirety). For example, the actuation device 156 may include one or more rate controllers configured to adjust a fluid property (e.g., viscosity) of the hydraulic fluid 312, thereby controlling a flow rate of the hydraulic fluid 312 through the first and second

flow control devices

320, 322. By way of non-limiting example, the rate controller may include an electromagnet, and the hydraulic fluid 312 may include a magnetorheological fluid. The electromagnet may be configured to adjust the viscosity of the hydraulic fluid 312 to achieve a desired flow rate of the hydraulic fluid 312, thereby adjusting the rate of extension or retraction of the drilling element 154.

Further, in some embodiments, one or more of the first flow control device 320 and the second flow control device 322 may include a restrictor as described in U.S. application No.14/851,117 filed by Jain on 11/9/2015. For example, the flow restrictor may include a multi-stage orifice having a plurality of plates, a plurality of orifices extending through each of the plurality of plates, and a plurality of fluid passages defined in each of the plurality of plates and surrounding each orifice of the plurality of plates.

Fig. 4 is a schematic view of an actuating device 156 for a self-adjusting ground engaging tool 200 (fig. 2) according to another embodiment of the present disclosure. Similar to the actuation device 156 described above with respect to fig. 3, the actuation device 156 of fig. 4 may include a connecting 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. Further, 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 with respect to fig. 3.

However, the actuation device 156 may include a first partition member 310a and a second partition 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 and

second portions

344, 346 of the second fluid chamber 338 may be oriented in the same manner as described above with respect to fig. 3. Further, the first partition member 310a may be oriented in the same manner as the partition member 310 described with respect to fig. 3.

The second partition member 310b may be oriented on an opposite side of the first portion 340 of the first fluid chamber 336 from 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 partition 310b from the first portion 340 of the first fluid chamber 336. In other words, the second partition 310b may isolate the third portion 348 of the second fluid chamber 338 from the first portion 340 of the first fluid chamber 336. The second partition member 310b may be fixed relative to the first portion 340 of the first fluid chamber 336 and the third portion 348 of the second fluid chamber 338.

The third portion 348 of the second fluid chamber 338 may be in fluid communication with the pressure compensator 324, and the pressure compensator 324 may be configured to at least substantially balance the pressure of the second fluid chamber 338 with an ambient pressure (as discussed above with respect to fig. 3) of the environment, such as mud in the wellbore 102 (fig. 1). In other words, the pressure compensator 324 may help maintain the pressure of the second fluid chamber 338 at least substantially equal to the ambient pressure. For example, the pressure compensator 324 may be in fluid communication with the third portion 348 of the second fluid chamber 338 on a first side 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, a diaphragm, and a pressure compensator 324 valve, and may be in communication with the environment (e.g., the mud 354 in the wellbore 102 (fig. 1)) on a second side. 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 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 partition member 310 b. 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 flow restrictor. Otherwise, the first fluid flow path 316 and the first flow control device 320 may operate in the same manner as the first fluid flow path 316 and the first flow control device 320 described with respect to fig. 3.

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 flow restrictor. Otherwise, the second fluid flow path 318 and the second flow control device 322 may operate in the same manner as the second fluid flow path 318 and the second flow control device 322 described with respect to fig. 3.

The first portion 344, the second portion 346, and the third portion 348 of the second fluid chamber 338 may be in fluid communication with one another 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 the third portion 348 of the second fluid chamber 338.

The first and

second portions

340, 342 of the first fluid chamber 336 may be in fluid communication with each other via a 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.

Fig. 5 is a cross-sectional view of an exemplary embodiment of an actuation device 156 of the self-adjusting drill bit of fig. 4. The actuating device 156 may be similar to the actuating device 156 shown in fig. 4. The actuating device 156 may be configured to be press fit into the crown 208 of the bit body 202 (fig. 2) of the ground engaging tool 200 (fig. 2). The actuation device 156 may include a housing 356, a connecting member 302, an internal chamber 358, a first reciprocating member 306, a second reciprocating member 308, 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 partition member 310a, a second partition member 310b, a first flow control device 320, a second flow control device 322, a pressure compensator 324, and a drilling element 154.

The first reciprocating member 306 and the second reciprocating member 308 may be attached to the connecting member 302 in the same manner as described with respect to fig. 3. The housing 356 may define an interior chamber 358 and may define an extension aperture 370 on one longitudinal end thereof. In addition, the interior chamber 358 may house the first reciprocating member 306 and the second reciprocating member 308. Further, the first and second

reciprocating members

306, 308 and the first and

second partition members

310a, 310b may sealingly partition the interior chamber 358 into first and second

fluid chambers

336, 338.

The first fluid chamber 336 may include a first portion 340 and a second portion 342, while 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 the rear 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 rear surface 330 of the first reciprocating member 306.

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 partition member 310 a. The first partition member 310a may be fixed 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 rear surface 330 of the first reciprocating member 306 and the first partition member 310 a. In some embodiments, the first divider 310a may comprise a portion of the housing 356. For example, the first divider may be an annular protrusion extending radially inward from the housing 356. The second portion 342 of the first fluid chamber 336 may be sealingly separated 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 partition 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.

The third portion 348 of the second fluid chamber 338 may be in fluid communication with the pressure compensator 324, and the pressure compensator 324 may be configured to at least substantially balance the pressure of the second fluid chamber 338 with an ambient pressure (as discussed above with respect to fig. 3) of the environment, such as the mud 354 in the wellbore 102 (fig. 1). In other words, the pressure compensator 324 may help maintain the pressure of the second fluid chamber 338 at least substantially equal to the ambient pressure. For example, the pressure compensator 324 may be in fluid communication with the third portion 348 of the second fluid chamber 338 on a first side 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, a diaphragm, and a pressure compensator 324 valve, and may be in communication with the environment (e.g., the mud 354 in the wellbore 102 (fig. 1)) on a second side. In some embodiments, the pressure compensator 324 may comprise a rubber material. For example, the pressure compensator 324 may include a rubber diaphragm. The pressure of the first fluid chamber 336 may be higher than the pressure of the second fluid chamber 338.

As described above, the connecting member 302 may be attached to the rear surface 330 of the first reciprocating member 306 at a first longitudinal end of the connecting member 302. The connecting 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 extending aperture 370 of the housing 356 of the actuation device 156. The drilling element 154 may be attached to a second longitudinal end of the connecting member 302 opposite the first end such that the drilling element 154 may be extended and retracted through an extended bore 370 of the housing 356 of the actuating device 156.

The hydraulic fluid 312 may be disposed within the first and second

fluid chambers

336, 338 and may at least substantially fill the first and second

fluid chambers

336, 338. The biasing member 314 may be disposed within the first portion 340 of the first fluid chamber 336 and may be configured to exert a selected force on the first reciprocating member 306 to move the first reciprocating member 306 outward (e.g., toward the extended aperture 370 of the housing 356) through the first portion 344 of the second fluid chamber 338. Further, as described above, the pressure differential between the first and second

fluid chambers

336, 338 may assist in moving the first and second

reciprocating members

306, 308 outward. As a result, the biasing member 314 may move the connecting member 302 and the drilling element 154 outward (e.g., may extend the drilling element 154). In some embodiments, the biasing member 314 may comprise a spring.

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 partition member 310 b. A first flow control device 320 may be disposed within the first fluid flow path 316. Further, the first flow control device 320 may be configured to control a 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 flow restrictor. In some embodiments, the first flow restrictor may comprise 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 flow restrictor. In other embodiments, the first flow control device 320 may include a first check valve and a first flow restrictor.

The second fluid flow path 318 may extend from a first portion 340 of the first fluid chamber 336 to a second portion 346 of the second fluid chamber 338 through the first reciprocating member 306, a portion of the connecting 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. A second fluid control device 322 may be disposed within the second fluid flow path 318. Further, the second fluid control device 322 may be configured to control a 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 a second check valve and a second flow restrictor. In some embodiments, the second flow restrictor may comprise 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 flow restrictor. In other embodiments, the second flow control device 322 may include both a second check valve and a second flow restrictor.

The first portion 344, the second portion 346, and the third portion 348 of the second fluid chamber 338 may be in fluid communication with one another via a third fluid flow path 350. In some embodiments, the third fluid flow path 350 may include an aperture extending through the housing 356.

The first and

second portions

340, 342 of the first fluid chamber 336 may be in fluid communication with each other via a fourth fluid flow path 352. In some embodiments, the third fluid flow path 350 may include an aperture extending through the housing 356.

In some embodiments, the drilling element 154 may be removably attached to the connecting member 302. The drilling element assembly 359 may be removably coupled to the second longitudinal end of the connecting member 302. The drilling element assembly 359 may include the drilling element 154, a drilling element seat 360, and shims 362. Drilling element 154 may be disposed in drilling element seat 360. Spacer 362 may be disposed between drilling element seat 360 and the second longitudinal end of connecting member 302.

In some embodiments, drilling element 154, drilling element seat 360, and spacer 362 may not be rigidly attached to connection member 302. For example, as described above, with the biasing member 314 disposed in the first portion 340 of the first fluid chamber 336, the connecting member 302 may be under a preload, and the biasing member 314 may press the connecting member 302 against the spacer 362, the drilling element seat 360, and the drilling element 154. In some embodiments, the drilling assembly 359 may be in contact with the connecting member 302 and the preload due to the biasing member 314 alone, and external loads applied to the connecting member 302 during drilling operations may maintain the drilling assembly 359 in contact with the connecting member 302. In other words, the drilling assembly 359 may not be rigidly coupled to the connecting member 302.

Removably attaching the drilling element 154 to the connecting member 302 may allow the drilling element 154 to be removed and replaced without disassembling the actuating device 156. In other words, the drilling element 154 may be replaced independently of the rest of the actuating device 156. Thus, removably attaching the drilling element 154 to the connection member 302 may save time and cost when replacing the drilling element 154. In some embodiments, the drilling element 154 and the drilling element seat 360 may be replaced. In other embodiments, only the drilling element 154 may be replaced. Additionally, having the drilling elements 154 removably attached to the connecting member 302 may allow a given actuating device 156 to be used with a plurality of different drilling elements 154 without having to disassemble the actuating device 156. As a result, the removably attached drilling elements 154 provide a wider variety of drilling elements 154 for a given bit body (fig. 1) to suit a particular application.

The spacer 362 may enable the actuation device 156 to be more generally used in the bit body 202 (fig. 2) (e.g., between different cavities in the bit body 202 (fig. 2)). For example, the cavity 232 (fig. 2) in the bit body 202 (fig. 2) for holding the actuating device 156 and the drilling element 154 may have different tolerances and slightly different dimensions. Thus, by providing shims 362, the actuating device and drilling element 154 may be used in more cavities 232 (fig. 2) of the bit body 202 (fig. 2), and may be shimmed with shims 362 to meet specific tolerances.

In some embodiments, drilling element 154 and drilling element seat 360 are removable from connecting member 302. For example, the drilling element 154 and the drilling element seat 360 may be removed by heating the drilling element 154 and the drilling element seat 360 to a temperature above 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 drilling element 154 and drilling element seat 360 from connecting member 302.

Fig. 6 is a simplified schematic diagram of a ground engaging tool 600 having an actuating device 656 according to one or more embodiments of the present disclosure. Various portions of the ground engaging tool have been removed to better illustrate the actuating device 656. In one or more embodiments, the ground engaging tool 600 may include a drill bit having one or more rotatable cutting structures in the form of a rolling cone and one or more blades. For example, as shown in fig. 6, the ground engaging tool 600 may be a hybrid drill bit (e.g., a drill bit having both a roller cone and a blade). Additionally, the earth-engaging tool 600 may include any other suitable drill bit or earth-engaging tool having one or more rotatable cutting structures and one or more blades for drilling and/or enlarging the wellbore 102 in the formation 118 (fig. 1). For example, the ground engaging tool 600 may include any of the ground engaging tools described in U.S. application No. 15/691,219 (the entire disclosure of which is incorporated herein by reference) filed by Schoen on 2017, 8, 30.

In one or more embodiments, the ground engaging tool 600 can include a body 602, the body 602 including a neck 606, a shank 608, and a crown 610. In some embodiments, a majority of the body 602 may be made of steel or a ceramic metal composite including particles of a hard material (e.g., tungsten carbide) bonded in a metal matrix material. The body 602 of the ground engaging tool 600 may have an axial center 604 defining a central longitudinal axis 605 that may generally coincide with the axis of rotation of the ground engaging tool 600. The central longitudinal axis 605 of the body 602 may extend in a direction hereinafter referred to as "axial".

The body 602 may be connected to the drill string 110 (fig. 1). For example, the neck 606 of the body 602 may have a tapered upper end with threads thereon for connecting the ground engaging tool 600 to the box end of the drilling assembly 114 (fig. 1). The stem 608 may include a lower straight portion that is fixedly connected to the crown 610 at a joint. In some embodiments, crown 610 may include a plurality of rotatable cutting structure assemblies 612 and a plurality of blades 614.

Each of the plurality of blades 614 of the ground engaging tool 600 may include a plurality of cutting elements 630 secured thereto. The plurality of cutting elements 630 of each blade 614 may be arranged in a row along the profile of blade 614 proximate leading face of rotation 632 of blade 614. In some embodiments, the plurality of cutting elements 620 of the plurality of rotatable cutting structures 618 (e.g., roller cutters) and the plurality of cutting elements 630 of the plurality of blades 614 may comprise PDC cutting elements 630. Further, the plurality of cutting elements 630 in plurality of rotatable cutting structures 618 and the plurality of cutting elements 630 in plurality of blades 614 may comprise any suitable cutting element configuration and materials for drilling and/or enlarging a wellbore.

The plurality of rotatable cutting structure assemblies 612 may include a plurality of legs 616 and a plurality of rotatable cutting structures 618, each mounted to a respective leg 616. The plurality of legs 616 may extend from an end of the body 602 opposite the neck 606 and may extend in an axial direction. A plurality of blades 614 may also extend from an end of the body 602 opposite the neck 606, and may extend in both axial and radial directions. Each blade 614 may have a plurality of profile regions (taper, nose, shoulder, gauge) as known in the art. 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 the plurality of legs 616, but may be mounted directly to the crown 610 on the body 602 of the ground engaging tool 600.

A fluid flow path 634 may be formed between adjacent blades 614 of the plurality of blades 614 and the fluid flow path 634 may be provided with drilling fluid through a port at the end of the passage leading to an internal fluid plenum extending from the tubular shank 608 in the upper portion of the ground engaging tool 600 through the body 602. A nozzle 638 may be secured within the port to enhance the direction of fluid flow and control the flow rate of the drilling fluid. The fluid flow passage 634 extends to a flow passage receptacle that extends axially along a longitudinal side of the ground engaging tool 600 between the blades 614 of the plurality of blades 614.

As described above, the ground engaging tool 600 may also include an actuating device 656. The actuating device 656 may be disposed within the blade 614 supported by the bit body 602 and may be secured to the bit body 602 adjacent the end face 619 of the ground engaging tool 600 by a press fit. Further, the actuating device 656 may be coupled to the drilling element 654 and may be configured to control the rate at which the drilling element 654 is extended and retracted from the ground engaging tool 600 relative to the surface of the ground engaging tool 600 via any of the manners described above with respect to fig. 2-5. For example, the actuation device 656 may include any of the actuation devices described above with respect to fig. 2-5. Further, the drilling element may include any of the drilling elements described above with respect to fig. 2-5 (e.g., more cutting, wear, or bearing elements). For example, in some embodiments, drilling element 654 may include an ovoid or ovoid cutter. As a non-limiting example, the drilling element 654 may include any ovoid described in U.S. application 16/004,765 filed 2018, 6, 11 by Russell et al (the disclosure of which is incorporated herein by reference in its entirety).

In some embodiments, a drilling element 654 coupled to an actuator 656 rotatably drags 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 actuator 656 is disposed. Further, the drilling element 654 may be configured to retract and extend relative to the blades 614 (and thus the body 602 of the ground engaging tool 600) in response to contact or lack of contact with the subterranean formation. For example, as discussed in more detail below with respect to fig. 7, in operation, when weight-on-bit is applied to the ground engaging tool 600, the drilling element 654 may retract due to contact with the subterranean formation, thereby achieving a typical hybrid cutting action. Further, when the force on one or more drilling elements (e.g., WOBs) is interrupted due to an event, the drilling element 654 may be extended to reduce the depth of cut of one or more primary cutting elements (e.g., cutting elements 630) and, in some cases, may maintain more contact between the earth engaging tool 600 and the subterranean formation. For example, due to the biasing member of the actuation device 656, the actuation device 656 may be biased to extend out of contact with the drilling element 654 (e.g., lack an applied force). The events may include any typical event in a drilling operation that may result in a break in the forces acting on one or more drilling elements or contact between the earth-engaging tool and the subterranean formation. For example, the events may include formation changes (e.g., formation material changes), picking up from the bottom hole, interrupting the vibration of the load, wellbore friction that prevents constant WOB from being transferred to the drill bit (particularly in deviated wellbores), uneven cutting structure loading due to rotating the drilling assembly when an elbow drilling motor is included in the bottom hole assembly, and the like.

Although the present application describes an actuation device 656 that includes two reciprocating members, the present disclosure is not so limited. Rather, the actuating device 656 may include any of the actuating devices described in U.S. patent 9,255,450 issued to Jain et al on 9/2/2016, U.S. patent 9,708,859 issued to Jain et al on 18/7/2017, and/or U.S. patent 10,000,977 issued to Jain et al on 19/6/2018, which are all incorporated herein by reference. Further, the actuation device 656 may operate in any manner described in the previously listed applications. By way of non-limiting example, the actuation device 656 may comprise a single reciprocating member and may be passively or actively actuated.

By extending the drilling element 654 during an event, reducing the DOC and maintaining more contact with the formation, the actuating device 656 may reduce the vibrations (i.e., torsional, axial, and lateral vibrations) experienced by the ground engaging tool 600 during operation. Reducing the vibration experienced by the ground engaging tool 600 may reduce damage to the ground engaging tool 600 and may increase the efficiency of the ground engaging tool. Reducing the vibration experienced by the ground engaging tool 600 via the steering device 656 is described in more detail below with respect to fig. 7.

Fig. 7 illustrates a flow diagram of a method 700 of reducing vibration experienced by a ground engaging tool, such as the ground engaging tool 600, during a drilling operation. In some embodiments, the method 700 may include reducing vibration experienced by a ground engaging tool during a drilling operation (e.g., the ground engaging tool 600) that includes a combination of crushing and scraping and/or shearing of a subterranean formation. For example, the method may include vibrations experienced by a ground engaging tool including a hybrid drill bit that utilizes both the fixed blades and the rotatable cutting structures to perform drilling operations.

In some embodiments, the method 700 includes setting an initial exposure of a drilling element coupled to an actuating device of a ground engaging tool relative to a primary cutting element of the ground engaging tool, as shown in step 710. In this application. The term "exposure" may refer to a distance that separates an outermost point of a cutting profile defined by a drilling element from an outermost point of a cutting profile defined by a primary cutting element of a ground engaging tool during a drilling operation.

In one or more embodiments, setting the initial exposure of the drilling element may include setting the initial exposure of the drilling element to be overexposed relative to a primary cutting element disposed on a leading face of a blade on which an actuating 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 a distance relative to the placement of the primary cutting element, the distance being in a range of about 0.5% to about 8.0% of an overall diameter of a cutting face of the primary cutting element. In some embodiments, the overexposure distance may be in the range of about 1.0% to about 4.0% of the total diameter of the cutting face of the primary cutting element. In other embodiments, the overexposure distance may be in the range of about 2.0% to about 3.0% of the total diameter of the cutting face of the primary cutting element. By way of non-limiting example, the overexposure distance may be in the range of about 0.010 inches to about 0.030 inches. For example, the overexposure distance may be about 0.020 inches. In some cases, the overexposure distance may extend in the axial direction.

In some embodiments, setting the initial exposure of the drilling element may include setting the initial exposure of the drilling element to be underexposed relative to a primary cutting element disposed at a leading face of a blade on which the actuation device is disposed and the distance being in a range of about 0.5% to about 8.0% of an overall diameter of a cutting face of the primary cutting element. In some embodiments, the underexposure distance may be in a range of about 1.0% to about 4.0% of the total diameter of the cutting face of the primary cutting element. In further embodiments, the underexposure distance may be in a range of about 2.0% and about 3.0% of the total diameter of the cutting face of the primary cutting element. As a non-limiting example, the underexposure distance may range from about 0.010 inches to about 0.030 inches. For example, the underexposure distance may be about 0.020 inches. In some cases, the underexposed distance may extend in the axial direction.

In one or more embodiments, setting the initial exposure of the drilling element may include setting the initial exposure of the drilling element so as to over-expose or under-expose any of the above distances relative to the surface of the ground engaging tool body (rather than or in addition to the primary cutting elements). For example, setting the initial exposure of the drilling element may include setting the initial exposure of the drilling element so as to be over-exposed or under-exposed with respect to a blade surface of a ground engaging tool, a support surface of a gage pad, or the like.

In some cases, the initial exposure may represent a maximum amount that the actuation device may extend the drilling element during a drilling operation. For example, the initial exposure may be indicative of a fully extended position of the actuation device. In other words, the initial exposure may represent the end of the extension movement (e.g., stroke) of the actuation device. In other embodiments, the initial exposure may represent a minimum amount by which the actuation device may extend the drilling element during a drilling operation. For example, the initial exposure may be indicative of a fully retracted position of the actuation device. In other words, the initial exposure may represent the end of the retracting movement (e.g., stroke) of the actuation device. In other embodiments, the initial exposure may represent a point between a maximum amount and a minimum amount that the actuation device may extend the drilling element during the drilling operation.

In some embodiments, setting the initial exposure of the drilling element is not included in the method 700. For example, there is no need to set the initial exposure of the drilling element in each embodiment. Rather, in some embodiments, the initial exposure of the drilling elements may not be set, or may be random.

The method 700 may also include contacting at least a portion of the ground engaging tool with the subterranean formation, as shown in step 720. For example, step 720 may include contacting at least one primary cutting element of the earth-engaging tool with the subterranean formation. In some embodiments, contacting at least one primary cutting element of the ground engaging tool with the subterranean formation may include applying WOB to the ground engaging tool, as shown in step 730. For example, contacting at least one primary cutting element of a ground engaging tool with a subterranean formation may include applying a typical amount of WOB to the ground engaging tool to effect a typical hybrid drilling operation.

Contacting at least one primary cutting element of the earth-engaging tool with the subterranean formation may cause the drilling element of the actuating device to retract by pressing upward against the formation, as shown in step 740. For example, the drilling element of the actuating device may be retracted sufficiently to achieve a typical depth of cut for at least one primary cutting element of the ground engaging tool. In some embodiments, the drilling element of the actuation device may be retracted in any of the manners described above with respect to fig. 2-5. The method 700 may also include performing a drilling operation, as shown at step 750. For example, method 700 may include any conventional drilling operation.

In one or more embodiments, the method 700 may further include moving the drilling element relative to the body of the ground engaging tool in response to a drilling event, as shown at step 760. As described above, a drilling event may include any typical event that may cause a WOB interruption or contact between the excavation tool and the subterranean formation during a drilling operation. For example, the event may include a formation change (e.g., a formation material change), pick up from the bottom hole, and the like.

As also described above, the drilling element may be moved relative to the earth engaging tool in response to contact or lack of contact with the subterranean formation. For example, moving the drilling element relative to the body of the ground engaging tool may include moving the drilling element relative to the body of the ground engaging tool to at least substantially maintain contact between the drilling element and the subterranean formation during and after a drilling event. In some embodiments, moving the drilling element relative to the body of the ground engaging tool may include extending the drilling element away from the body of the ground engaging tool due to reduced contact with subterranean formations and reduced depth of cut of at least one primary cutting element. In further embodiments, moving the drilling element relative to the body of the earth-engaging tool may include retracting the drilling element toward the body of the earth-engaging tool due to increased contact with the subterranean formation, thereby enabling an increase in the depth of cut of the at least one primary cutting element.

By moving the drilling element, adjusting the DOC of the ground engaging tool, and maintaining more contact with the subterranean formation during a drilling event, the actuating device of the present disclosure may reduce the vibrations (i.e., torsional, axial, and lateral vibrations) experienced by the ground engaging tool during operation. Reducing the vibration experienced by the ground engaging tool may reduce damage to the ground engaging tool and may increase the efficiency of the ground engaging tool.

Embodiments of the present disclosure also include the following:

example 1: a method of reducing vibration experienced by an earth-engaging 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 actuating device disposed within a blade of the ground engaging tool to overexpose a distance relative to a primary cutting element disposed at a leading face of the blade, the distance being in a range of about 0.5% to about 8.0% of an overall diameter of the primary cutting element; applying bit pressure to the ground digging tool; retracting the drilling element toward the actuation device and underexposing with respect to the primary cutting element; and in response to a drilling event, moving the drilling element relative to the body of the earth-engaging tool to change an underexposure level of the drilling element relative to the primary cutting element.

Example 2: the method of embodiment 1, wherein setting an initial exposure of the drilling element relative to the primary cutting element comprises setting a distance of the initial exposure in a range of about 1.0% to about 4.0% of an overall diameter of the primary cutting element.

Example 3: the method of embodiment 1, wherein setting an initial exposure of the drilling element relative to the primary cutting element comprises setting a distance of the initial exposure in a range of about 2.0% to about 3.0% of an overall diameter of the primary cutting element.

Example 4: the method of embodiments 1-3 wherein moving the drilling element relative to the body of the ground engaging tool reduces axial vibration experienced by the ground engaging tool.

Example 5: the method of embodiments 1-4 wherein moving the drilling element relative to the body of the ground engaging tool reduces torsional vibrations experienced by the ground engaging tool.

Example 6: the method of embodiments 1-5 wherein moving the drilling element relative to the body of the ground engaging tool reduces lateral vibration experienced by the ground engaging tool.

Example 7: the method of embodiments 1-6 wherein moving the drilling element relative to the body of the ground engaging tool in response to a drilling event comprises moving the drilling element relative to the body of the ground engaging tool in response to a change in a subterranean formation.

Example 8: the method of embodiments 1-7 wherein moving the drilling element relative to the body of the ground engaging tool in response to a drilling event comprises moving the drilling element relative to the body of the ground engaging tool in response to a break in the application of weight-on-bit.

Example 9: the method of embodiments 1-8, wherein moving the drilling element relative to the body of the earth-engaging tool comprises reducing contact between the primary cutting element and the subterranean formation.

Example 10: the method of embodiments 1-9, wherein moving the drilling element relative to the body of the ground engaging tool comprises reducing a depth of cut of the primary cutting element.

Example 11: a method of reducing vibration experienced by an earth-engaging tool during a drilling operation that includes a combination of crushing and shear cutting a subterranean formation, the method comprising: setting an initial exposure of a drilling element coupled to an actuating device disposed within a blade of the ground engaging tool relative to a primary cutting element disposed on a leading face of the blade; moving the drilling element relative to the actuating device and having a second exposure relative to the main cutting element by applying weight-on-bit; maintaining at least substantially continuous contact between the drilling element and the subterranean formation during a drilling operation; and in response to a drilling event, moving the drilling element relative to the body of the earth-engaging tool during and after the drilling event to at least substantially maintain contact between the drilling element and the subterranean formation.

Example 12: the method of embodiment 11, wherein moving the drilling element relative to the body of the earth-engaging tool to at least substantially maintain contact between the drilling element and the subterranean formation comprises reducing an underexposure level of the drilling element relative to the primary cutting element.

Example 13: the method of embodiment 11, wherein moving the drilling element relative to the body of the earth-engaging 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.

Example 14: the method of embodiments 11-13, wherein setting the initial exposure of the drilling element comprises setting the drilling element to be overexposed with respect to the primary cutting element disposed at the leading face of the blade.

Example 15: the method of embodiment 14, wherein moving the drilling element relative to the actuating device and having a second exposure relative to the primary cutting element comprises: retracting the drilling element toward the actuation device and underexposing with respect to the primary cutting element.

Example 16: the method of embodiments 11-13, wherein setting an initial exposure of the drilling element comprises: the drilling element is set to be underexposed relative to a primary cutting element disposed at a leading face of the blade.

Example 17: the method of embodiments 11-16, wherein moving the drilling element relative to the body of the earth-engaging tool comprises reducing contact between the primary cutting element and the subterranean formation.

Example 18: the method of embodiments 11-17, wherein moving the drilling element relative to the body of the ground engaging tool comprises reducing a depth of cut of the primary cutting element.

Example 19: a ground engaging tool comprising: a main body; a plurality of blades extending from the body; at least one rotatable cutting structure assembly connected to the body; an actuating device disposed at least partially within one of the plurality of blades, the actuating device comprising: a first fluid chamber; a second fluid chamber; at least one reciprocating member configured to reciprocate in the first and second fluid chambers, the at least one reciprocating member having a front surface and a rear surface; a hydraulic fluid disposed within and at least substantially filling the first and second fluid chambers; a connecting member attached to the at least one reciprocating member and extending from the second fluid chamber; and a drilling element removably coupled to the connecting member of the actuating device.

Example 20: the ground engaging tool of embodiment 19 wherein the drilling element exhibits an offset overexposure with respect to the primary cutting element disposed at the leading face of the blade by a distance in the range of about 0.5% to about 8.0% of the overall diameter of the primary cutting element.

The embodiments of the present disclosure described above and illustrated in the drawings are not intended to limit the scope of the present disclosure, which is covered by the appended claims and their legal equivalents. Any equivalent embodiments are within the scope of the present 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. Such modifications and embodiments are also within the scope of the appended claims and equivalents.

Claims

1. A method of reducing vibration experienced by an earth-engaging 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 actuating device disposed within a blade of the ground engaging tool to overexpose a distance relative to a primary cutting element disposed at a leading face of the blade, the distance being in a range of about 0.5% to about 8.0% of an overall diameter of the primary cutting element;

applying bit pressure to the ground digging tool;

retracting the drilling element toward the actuation device and underexposing with respect to the primary cutting element; and is

In response to a drilling event, moving the drilling element relative to a body of the earth-engaging tool to change an underexposure level of the drilling element relative to the primary cutting element.

2. The method of claim 1, wherein setting an initial exposure of the drilling element relative to the primary cutting element comprises: setting the distance of the initial exposure to be in a range of about 1.0% to about 4.0% of the total diameter of the primary cutting element.

3. The method of claim 1, wherein setting an initial exposure of the drilling element relative to the primary cutting element comprises: setting the distance of the initial exposure to be in a range of about 2.0% to about 3.0% of the total diameter of the primary cutting element.

4. The method of claim 1 wherein moving the drilling element relative to the body of the ground engaging tool reduces axial vibration experienced by the ground engaging tool.

5. The method of claim 1 wherein moving the drilling element relative to the body of the ground engaging tool reduces torsional vibrations experienced by the ground engaging tool.

6. The method of claim 1 wherein moving the drilling element relative to the body of the ground engaging tool reduces lateral vibration experienced by the ground engaging tool.

7. The method of claim 1, wherein moving the drilling element relative to the body of the ground engaging tool in response to a drilling event comprises: moving the drilling element relative to the body of the earth-engaging tool in response to changes in the subterranean formation.

8. The method of claim 1, wherein moving the drilling element relative to the body of the ground engaging tool in response to a drilling event comprises: moving the drilling element relative to the body of the earth-engaging tool in response to an interruption in the application of weight-on-bit.

9. The method of claim 1, wherein moving the drilling element relative to the body of the ground engaging tool comprises: reducing contact between the primary cutting element and the subterranean formation.

10. The method of claim 1, wherein moving the drilling element relative to the body of the ground engaging tool comprises reducing a depth of cut of the primary cutting element.

11. A method of reducing vibration experienced by an earth-engaging tool during a drilling operation that includes a combination of crushing and shear cutting a subterranean formation, the method comprising:

setting an initial exposure of a drilling element coupled to an actuating device disposed within a blade of the ground engaging tool relative to a primary cutting element disposed at a leading face of the blade;

moving the drilling element relative to the actuating device and having a second exposure relative to the main cutting element by applying weight-on-bit;

maintaining at least substantially continuous contact between the drilling element and the subterranean formation during a drilling operation; and is

In response to a drilling event, moving the drilling element relative to the body of the earth-engaging tool to at least substantially maintain contact between the drilling element and the subterranean formation during and after the drilling event.

12. The method of claim 11, wherein moving the drilling element relative to the body of the ground engaging tool to at least substantially maintain contact between the drilling element and the subterranean formation comprises: decreasing an under exposure level of the drilling element relative to the primary cutting element.

13. The method of claim 11, wherein moving the drilling element relative to the body of the ground engaging 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.

14. The method of claim 11, wherein setting an initial exposure of the drilling element comprises: setting the drilling element to be overexposed with respect to the primary cutting element disposed at the leading face of the blade.

15. The method of claim 14, wherein moving the drilling element relative to the actuation device and having a second exposure relative to the primary cutting element comprises: retracting the drilling element toward the actuation device and underexposing with respect to the primary cutting element.

16. The method of claim 11, wherein setting an initial exposure of the drilling element comprises: the drilling element is set to be underexposed relative to a primary cutting element disposed at a leading face of the blade.

17. The method of claim 11, wherein moving the drilling element relative to the body of the ground engaging tool comprises: reducing contact between the primary cutting element and the subterranean formation.

18. The method of claim 11, wherein moving the drilling element relative to the body of the ground engaging tool comprises: reducing a depth of cut of the primary cutting element.

19. A ground engaging tool comprising:

a main body;

a plurality of blades extending from the body;

at least one rotatable cutting structure assembly connected to the body;

an actuation device disposed at least partially within one 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 in the first and second fluid chambers, the at least one reciprocating member having a front surface and a rear surface;

a hydraulic fluid disposed within and at least substantially filling the first and second fluid chambers; and

a connecting member attached to the at least one reciprocating member and extending from the second fluid chamber; and

a drilling element removably coupled to the connecting member of the actuation device.

20. The ground engaging tool of claim 19 wherein said drilling element exhibits an offset overexposure with respect to a primary cutting element disposed at the leading face of said blade by a distance in the range of about 0.5% to about 8.0% of the overall diameter of said primary cutting element.