Patent Application
20190078393
Embodiments of the present disclosure relate generally to devices and methods involving rotatable cutting elements for earth-boring tools used in earth boring operations and, more specifically, to rotatable cutting elements for earth-boring tools configured to rotate in order to alter an exposure of a cutting edge of the cutting element relative to an adjacent surface of the earth-boring tool to which a cutting element assembly is mounted, to earth-boring tools so equipped, and related methods.
Wellbores are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from the subterranean formation and extraction of geothermal heat from the subterranean formation. Wellbores may be formed in a subterranean formation using a drill bit, such as an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). The drill bit is rotated and advanced into the subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of earth above the subterranean formations being drilled. Various tools and components, including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may include, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through the annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore. The downhole motor may be operated with or without drill string rotation.
A drill string may include a number of components in addition to a downhole motor and drill bit including, without limitation, drill pipe, drill collars, stabilizers, measuring while drilling (MWD) equipment, logging while drilling (LWD) equipment, downhole communication modules, and other components.
In addition to drill strings, other tool strings may be disposed in an existing well bore for, among other operations, completing, testing, stimulating, producing, and remediating hydrocarbon-bearing formations.
Cutting elements used in earth boring tools often include polycrystalline diamond compact (often referred to as “PDC”) cutting elements, which are cutting elements that include so-called “tables” of a polycrystalline diamond material mounted to supporting substrates and presenting a cutting face for engaging a subterranean formation. Polycrystalline diamond (often referred to as “PCD”) material is material that includes inter-bonded grains or crystals of diamond material. In other words, PCD material includes direct, intergranular bonds between the grains or crystals of diamond material.
Cutting elements are typically mounted on the body of a drill bit by brazing. The drill bit body is formed with recesses therein, commonly termed “pockets,” for receiving a substantial portion of each cutting element in a manner which presents the PCD layer at an appropriate back rake and side rake angle, facing in the direction of intended bit rotation, for cutting in accordance with the drill bit design. In such cases, a brazing compound is applied between the surface of the substrate of the cutting element and the surface of the recess on the bit body in which the cutting element is received. The cutting elements are installed in their respective recesses in the bit body, and heat is applied to each cutting clement via a torch to raise the temperature to a point high enough to braze the cutting elements to the bit body in a fixed position but not so high as to damage the PCD layer.
Unfortunately, securing a PDC cutting element to a drill bit restricts the useful life of such cutting element, because the cutting edge of the diamond table and the substrate wear down, creating a so-called “wear flat” and necessitating increased weight-on-bit to maintain a given rate of penetration of the drill bit into the formation due to the increased surface area presented. In addition, unless the cutting element is heated to remove it from the bit and then rebrazed with an unworn portion of the cutting edge presented for engaging a formation, more than half of the cutting element is never used.
Rotatable cutting elements mounted for rotation about a longitudinal axis of the cutting element can wear more evenly than fixed cutting elements, and exhibit a significantly longer useful life without removal from the drill bit. That is, as a cutting element rotates in a bit body, different parts of the cutting edges or surfaces may be exposed at different times, such that more of the cutting element is used. Thus, rotatable cutting elements may have a longer life than fixed cutting elements.
In some embodiments, an earth-boring tool for removing subterranean formation material in a wellbore comprises a tool body and a rotatable cutting element assembly. The rotatable cutting element assembly comprises a cutting element, a sleeve, and a positioning feature. The cutting element comprises a substrate and a table of a polycrystalline hard material secured to the substrate. The table has a front cutting face and a central axis extending through a center of the front cutting face. The sleeve is fixed to the tool body and comprises a cavity having a central axis extending through a center thereof. A portion of the substrate of the cutting element is disposed within the cavity of the sleeve. The positioning feature is disposed within the cavity of the sleeve and at least partially encircles the portion of the substrate disposed within the cavity of the sleeve. The positioning feature is configured to radially offset the central axis of the table from the central axis of the sleeve. The cutting element is rotatable about the central axis of the table within the cavity of the sleeve, and the cutting element and positioning feature are rotatable within the cavity of the sleeve such that the central axis of the table revolves about the central axis of the sleeve.
In other embodiments, a cutting element assembly comprises a sleeve and a cutting element. The sleeve comprises a cavity having a central axis extending through a center thereof. The cutting element comprises a table of polycrystalline hard material secured to a substrate. At least a portion of the substrate is encircled by the cavity of the sleeve. The table has a front cutting face and a central axis extending through a center of the front cutting face and radially offset from the central axis of the sleeve.
In yet other embodiments, a method of using a rotatable cutting element comprises engaging a cutting element of a cutting element assembly with a subterranean formation. The cutting element assembly comprises the cutting element including a table of polycrystalline hard material secured to a substrate and a central axis extending through a center of a front cutting face of the table. The cutting element assembly further comprises a sleeve extending circumferentially about at least a portion of the substrate and having a central axis extending centrally therethrough. The central axis of the cutting element extends parallel to and radially offset from the central axis of the sleeve. The method further comprising rotating the cutting element about the central axis thereof and rotating the cutting element within the sleeve such that the central axis of the cutting element revolves about the central axis of the sleeve.
While the specification concludes with claims particularly pointing out and distinctly claiming embodiments of the present disclosure, the advantages of embodiments of the disclosure may be more readily ascertained from the following description of embodiments of the disclosure when read in conjunction with the accompanying drawings in which:
The illustrations presented herein are not actual views of any particular earth-boring tool, rotatable cutting element assembly or component thereof, but are merely idealized representations employed to describe example embodiments of the present disclosure. The following description provides specific details of embodiments of the present disclosure in order to provide a thorough description thereof. However, a person of ordinary skill in the art will understand that the embodiments of the disclosure may be practiced without employing many such specific details. Indeed, the embodiments of the disclosure may be practiced in conjunction with conventional techniques employed in the industry. In addition, the description provided below does not include all elements to form a complete structure or assembly. Only those process acts and structures necessary to understand the embodiments of the disclosure are described in detail below. Additional conventional acts and structures may be used. Also note, any drawings accompanying the application are for illustrative purposes only, and are thus not drawn to scale. Additionally, elements common between figures may have corresponding numerical designations.
As used herein, the terms “comprising,” “including,” “containing,” “characterized by,” and grammatical equivalents thereof are inclusive or open-ended terms that do not exclude additional, unrecited elements or method steps, but also include the more restrictive terms “consisting of” and “consisting essentially of” and grammatical equivalents thereof.
As used herein, the term “may” with respect to a material, structure, feature, or method act indicates that such is contemplated for use in implementation of an embodiment of the disclosure, and such term is used in preference to the more restrictive term “is” so as to avoid any implication that other compatible materials, structures, features and methods usable in combination therewith should or must be excluded.
As used herein, the term “configured” refers to a size, shape, material composition, and arrangement of one or more of at least one structure and at least one apparatus facilitating operation of one or more of the structure and the apparatus in a predetermined way.
As used herein, the singular forms following “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.
As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.
As used herein, spatially relative terms, such as “beneath,” “below,” “lower,” “bottom,” “above,” “upper,” “top,” “front,” “rear,” “left,” “right,” and the like, may be used for ease of description to describe one element's or feature's relationship to another element(s) or feature(s) as illustrated in the figures. Unless otherwise specified, the spatially relative terms are intended to encompass different orientations of the materials in addition to the orientation depicted in the figures.
As used herein, the term “substantially” in reference to a given parameter, property, or condition means and includes to a degree that one of ordinary skill in the art would understand that the given parameter, property, or condition is met with a degree of variance, such as within acceptable manufacturing tolerances. By way of example, depending on the particular parameter, property, or condition that is substantially met, the parameter, property, or condition may be at least 90.0% met, at least 95.0% met, at least 99.0% met, or even at least 99.9% met.
As used herein, the term “about” used in reference to a given parameter is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the given parameter).
As used herein, the term “hard material” means and includes any material having a Knoop hardness value of about 1,000 Kgf/mm2 (9,807 MPa) or more. Hard materials include, for example, diamond, cubic boron nitride, boron carbide, tungsten carbide, etc.
As used herein, the term “polycrystalline hard material” means and includes any material comprising a plurality of grains or crystals of the material that are bonded directly together by intergranular bonds. The crystal structures of the individual grains of polycrystalline hard material may be randomly oriented in space within the polycrystalline hard material.
As used herein, the term “earth-boring tool” means and includes any type of bit or tool used for drilling during the formation or enlargement of a wellbore and includes, for example, rotary drill bits, percussion bits, core bits, eccentric bits, bi-center bits, reamers, mills, drag bits, roller-cone bits, hybrid bits, and other drilling bits and tools known in the art.
A row of cutting element assemblies 100 may be mounted to at least one blade 16. For example, cutting element pockets may be formed in the blades 16, and the cutting element assemblies 100 may be positioned in the cutting element pockets. At least one component of the cutting element assembly 100 may be bonded (e.g., brazed, welded, etc.) to the blades 16.
With continued reference to each of
The cutting element assembly 100 further comprises a cutting element 106. The cutting element 106 includes a table 107 having a front cutting face 108 that may engage a subterranean formation during operation of the bit 10 and a back side surface 110 that may be secured to an end of a substrate 112. A central axis L107 may extend through a center of the front cutting face 108 of the table 107.
The table 107 may be formed from a polycrystalline hard material, such as polycrystalline diamond or polycrystalline cubic boron nitride. The substrate 112 may be formed from a hard material including, but not limited to, steel, steel alloys, metal or metal-alloy-cemented carbide, and any derivatives and combinations thereof. Suitable cemented carbides may contain varying amounts of tungsten carbide (WC), titanium carbide (TiC), tantalum carbide (TaC), and niobium carbide (NbC). Additionally, various binding metals or metal alloys may be included in the substrate 112, such as cobalt, nickel, iron, metal alloys, or mixtures thereof. In the substrate 112, the metal carbide particles are supported within a metallic binder, such as cobalt. In other embodiments, the substrate 112 may be formed of a sintered tungsten carbide composite structure. The sleeve 102 may include a hard material such as one of the hard materials described with regard to the hard material of the substrate 112.
As best illustrated in the cross-sectional views of
With continued reference to
In some embodiments and as illustrated in the top view of
The positioning feature 124 is sized and configured to radially offset the central axis L107 of the table 107 from the central axis L102 of the sleeve 102. Accordingly, while the central axis L102 of the sleeve 102 and the central axis L107 of the table 107 may extend parallel to each other, the central axis L102 and the central axis L107 are not coaxial.
Each of the positioning feature 124 and the cutting element 106 may be rotatably mounted within the cavity 104 of the sleeve 102. In operation, the cutting element 106 is configured to rotate within the sleeve 102 and within the positioning feature 124 about the central axis L107 and the central axis L102 responsive to engagement of the cutting element 106 with the subterranean formation. As the bit 10 may be rotated about the central axis 14 thereof and as the front cutting face 108 and a cutting edge 122 extending about a periphery of the front cutting face 108 engages the formation, contact with the formation by the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 to rotate about the central axis L107. Accordingly, the cutting element 106 may be referred to herein as a “rotatable cutting element” as the cutting element 106 rotates about the central axis L107. Rotation of the cutting element 106 may allow the table 107 to engage the formation using the entire circumference of the cutting edge 122, rather than the same section or segment of the cutting edge 122 if the cutting element 106 was not rotatable within the sleeve 102. This may generate more uniform edge wear on the cutting element 106, reducing the potential for formation of a localized, flat area on the cutting edge 122 of the table 107 and a wear flat on the substrate 112 to the rear of the table 107. As a result, the rotatable cutting element 106 may not wear as quickly in one region and thereby exhibit longer downhole life and increased efficiency. Additionally or alternatively, contact of the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 and the positioning feature 124 to rotate within the sleeve 102 about the central axis L102 of the sleeve 102. Accordingly, the cutting element 106 may also be referred to herein as an “orbiting cutting element” as the cutting element 106 orbits (e.g., revolves) about the central axis L102 of the sleeve 102. Rotation of the cutting element 106 may allow an exposure of the cutting edge 122 relative to an adjacent portion of the bit body 12 to which the cutting element assembly 100 may be mounted to be adjusted during operation of the bit 10 as explained in further detail with reference to
In some embodiments, some of the components of the cutting element assembly 100 may be coated with wear resistant and/or low friction coatings. In some embodiments, one or more of the interior sidewall 105 of the cavity 104, the upper surface 118 of the sleeve 102, the upper surface 130 of the positioning feature 124, the lower surface 115 of the upper portion 114 of the substrate 112, the outer surface 120 of the lower portion 116 of the substrate 112, the interior sidewall 126 of the positioning feature 124, and the exterior sidewall 128 of the positioning feature 124 may be provided with such coatings. The coatings may include low friction coatings and/or wear resistant coatings capable of withstanding downhole conditions, such as, by way of example but not limitation, diamond-like carbon (DLC), soft metals (e.g., materials having relatively lower hardness, copper), dry lube films, etc. The coatings may be positioned on the interface surfaces between one or more of the components where there may be a high potential for increased wear as the cutting element 106 and the positioning feature 124 move (e.g., rotate and/or revolve) within the sleeve 102. In some embodiments, different coatings may be used on different surfaces within the same rotatable cutting element assembly 100, as different coatings may have additional benefits when applied to different surfaces. Additional examples may include any variations of low friction or wear resistant materials.
The cutting element assembly 200 may further comprise a biasing element 214. As illustrated in
The positioning feature 216 may comprise a sleeve 222 having a cavity 224 extending at least partially therethrough. As illustrated in the cross-sectional view of
The positioning feature 216 may comprise a track 228 extending about an exterior sidewall 240 thereof. The track 228 may be formed of an upper track 228a and a lower track 228b. The track 228 may be recessed into a portion of the sleeve 222 as illustrated in FIG. 4. Each of the upper and lower track 228a, 228b may be undulating and may comprise alternating protrusions 230 and recesses 232. The pin 212 passing through the sleeve 202 may be engaged with the track 228. The engagement of the pin 212 in the track 228 may be configured to rotate the sleeve 222 and the cutting element 106 disposed within the cavity 224 of the sleeve 222 such that the central axis L107 may orbit (e.g., revolve) about the central axis L202 of the sleeve 202 as described in further detail with regard to
Grooves 234 may be provided above and below the track 228. The grooves 234 may be sized and configured to receive a sealing element 236 therein. The sealing element 236 may encircle the sleeve 222 and may be configured to form a seal between the positioning feature 216 and the sleeve 202 to prevent drilling mud and formation debris from hindering rotation of the positioning feature 216.
A groove 238 may also be provided within an interior sidewall 226 of the cavity 224. The groove 238 may extend about the circumference of the interior sidewall 226 to encircle the outer surface 120 of the lower portion 116 of the substrate 112 disposed in the positioning feature 216. The groove 234 may be sized and configured to receive a retaining element 235 to retain the cutting element 106 within the positioning feature 216 while permitting the cutting element 106 to rotate within the cavity 224. The retaining element 235 may comprise a resilient material and/or may be, for example, an O-ring, a split ring, a beveled retaining ring, a bowed retaining ring, a spiral retaining ring, a Belleville spring, or another retaining element. Those skilled in the art will readily appreciate that the retention mechanism, such as the groove 238 and retaining element 235, may alternatively comprise any other device or mechanism that enables the cutting element 106 to rotate while simultaneously inhibiting removal of the cutting element 106 from the positioning feature 216 without departing from the scope of the disclosure.
The cutting element assembly 200 may also comprise the cutting element 106. As illustrated in
In some embodiments, some of the components of the cutting element assembly 200 may be coated with wear resistant and/or low friction coatings as previously described herein. In some embodiments, one or more of the interior sidewall 206 of the cavity 204, the upper surface 203 of the sleeve 202, the upper surface 220 of the positioning feature 216, the lower surface 115 of the upper portion 114 of the substrate 112, the outer surface 120 of the lower portion 116 of the substrate 112, the interior sidewall 226 of the positioning feature 216, and the exterior sidewall 240 of the positioning feature 216 may be provided with such coatings.
In operation, as the bit 10 may be rotated about the central axis 14 thereof and as the front cutting face 108 and the cutting edge 122 of the cutting element 106 engage the formation, contact with the formation by the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 to rotate about the central axis L107 within the cavity 224 of the positioning feature 216. Accordingly, the cutting element 106 may be referred to herein as a “rotatable cutting element,” as previously described herein.
The positioning feature 216 may also enable the cutting element 106 and, more particularly, the central axis L107 extending through the center of the table 107 to revolve about the central axis L202 of the sleeve 202. The track 228 of the positioning feature 216 may act to at least partially prevent revolutions of the cutting element 106 about the central axis L202 and to at least partially enable revolutions of the cutting element 106 about the central axis L202. As previously described herein, the biasing element 214 interposed between the lower surface 218 of the positioning feature 216 within the cavity 204 of the sleeve 202 biases the cutting element 106 and the positioning feature 216 in the expanded position. When the cutting edge 122 and an adjacent portion of the front cutting face 108 engage the formation, contact with the formation by the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 and the positioning feature 216 into the compressed position by applying a force indirectly on the biasing element 214 sufficient to overcome the constant force applied by the biasing element 214 on the positioning feature 216 and the cutting element 106. When the cutting edge 122 and an adjacent portion of the front cutting face 108 are disengaged with the formation, the biasing element 214 may urge the cutting element 106 and the positioning feature 216 into the expanded position.
As the positioning feature 216 is moved axially between the expanded position and the compressed position, the pin 212 may slide along the track 228 between the offset protrusions 230 and recesses 232 and rotate the positioning feature 216 within the sleeve 202 such that the cutting element 106 disposed within the positioning feature 216 revolves about the central axis L202. In particular, as the positioning feature 216 moves between the compressed position to the expanded position, the pin 212 moves between engagement with a recess 232 in the lower track 228b to a recess 232 in the upper track 228a by moving upward along a surface between the recess 232 to a crest of the protrusion 230 of the lower track 228b. As the positioning feature 216 moves between the expanded position to the compressed position, the pin 212 moves between engagement with a recess 232 in the upper track 228a to a recess 232 in the lower track 228b by moving downward along a surface between the recess 232 to a crest of the protrusion 230 of the upper track 228a. As a result, as the positioning feature 216 moves axially to the expanded position and back to the compressed position, the pin 212 moves between adjacent recesses 232 in the lower track 228b. Accordingly, the positioning feature 216 and the cutting element 106 may be incrementally rotated about the central axis L202 of the sleeve 202 and may, therefore, be referred to herein as an “indexing mechanism” as the positioning feature 216 and, more particularly, the track 228 of the positioning feature 216 indexes the amount of rotation of the positioning feature 216 and of the cutting element 106. In view of the foregoing, contact of the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 and the positioning feature 124 to rotate about the central axis L102 of the sleeve 102. Accordingly, the cutting element 106 may also be referred to herein as an “orbiting cutting element” as the cutting element 106 orbits (e.g., revolves) about the central axis L202 of the sleeve 202. Rotation of the cutting element 106 may allow an exposure of the cutting edge 122 relative to an adjacent portion of the bit body 12 to which the cutting element assembly 100 may be mounted to be adjusted during operation of the bit 10 as explained in further detail with reference to
The spacing of the protrusions 230 and recesses 232 in the upper and lower tracks 228a, 228b may be selected to provide a predetermined amount of radial positions for the positioning feature 216 and the cutting element 106. By way of example, in some embodiments, there may be eight evenly spaced protrusions 230 and recesses 232 in each of the upper and lower tracks 228a, 228b such that the cutting element 106 may be revolved about the sleeve 202 in 45-degree increments. In other embodiments, the protrusions 230 and recesses 232 in each of the upper and lower tracks 228a, 228b may be comprise eight unevenly spaces such that the cutting element 106 may be revolved about the sleeve 202 in varying increments. The number of protrusions 230 and recesses 232 and the spacing between adjacent protrusions 230 and recesses 232 may be selected and varied based on the amount of revolution desired of the cutting element 106 within the sleeve 202. Furthermore, the slopes of the surfaces between the recesses 232 and the protrusion 230 may be varied to vary the amount of rotation of the positioning feature 216 achieved as the positioning feature 216 is axially translated between the expanded position and the compressed position as described in U.S. patent application Ser. No. 15/662,626, entitled “Rotatable Cutters and Elements for Use on Earth-Boring Tools in Subterranean Boreholes, Earth-Boring Tools Including Same, and Related Methods,” filed on Jul. 28, 2017, the entire disclosure of which is hereby incorporated herein by this reference.
While the track 228 has been illustrated and described as being provided on and about the positioning feature 216 and the pin 212 has been illustrated and described as being provided through the sleeve 202, in other embodiments, the track 228 may be formed about the interior sidewall 206 of the sleeve 202 and the pins 212 may be provided within openings formed in the positioning feature 216 as described in U.S. patent application Ser. No. 15/662,626, previously incorporated herein by reference.
The cutting element assembly 300 may also comprise a positioning feature 306 disposed within the cavity 304. The positioning feature 306 may comprise a sleeve 308 having a cavity 310 formed therein similar to the cavity 224 formed in the positioning feature 216 of the embodiment of
In some embodiments, an aperture 312 may be formed through the sleeve 302 in which the positioning feature 306 may be received such that an impelling feature 314 may be coupled to (e.g., secured to) the positioning feature 306. The impelling feature 314 may comprise a shaft 316 having a mating surface 318A at a longitudinal end of the shaft 316 opposite a longitudinal end of the shaft 316 coupled to the positioning feature 306.
A formation-engaging feature 320 may be located proximate to (e.g., rotationally behind) the cutting element assembly 300 on a common blade 16 therewith. The formation-engaging feature 320 may comprise a rolling element configured to interact with the formation. The formation-engaging feature 320 may comprise a formation-engaging feature as shown and described in U.S. patent application Ser. No. 15/704,806, entitled “Earth-Boring Tools Including Rotatable Cutting Elements and Formation-Engaging Features that Drive rotation of Such Cutting Elements, and Related Methods,” filed on even date herewith, assigned to the assignee of the present application, the entire disclosure of which is incorporated by this reference. The formation-engaging feature 320 may be rotatably mounted to the blade 16 and may rotate about a central axis L320 thereof responsive to frictional forces acting between an exterior sidewall 324 of the formation-engaging feature 320 as the bit 10 is rotated about the central axis 14 thereof. The formation-engaging feature 320 may comprise an impelling feature 326 comprising a shaft 328 having a mating surface 318B. The mating surfaces 318A, 318B of the impelling features 314, 328 may comprise miter gears as illustrated in
In operation, as the bit 10 may be rotated about the central axis 14 thereof, the exterior sidewall 324 of the formation-engaging feature 320 may engage the formation, contact with the formation by the exterior sidewall 324 of the formation-engaging feature 320 may urge the formation-engaging feature 320 to rotate about its rotational axis L320. As the formation-engaging feature 320 may be operatively coupled to the cutting element assembly 300, rotation of the formation-engaging feature 320 may drive rotation of the cutting element 106. When the formation-engaging feature 320 rotates about the central axis L320 thereof, the mating surface 318B may rotate and resultantly rotate the mating surface 318A engaged therewith and the shaft 316 coupled to the positioning feature 306. Accordingly, rotation of the formation-engaging feature 320 may drive rotation of the positioning feature 306 within the sleeve 302. Rotation of the positioning feature 306 rotates the cutting element 106 within the sleeve 302 such that the central axis L107 extending through the center of the table 107 revolves about the central axis L302 of the sleeve 302.
In operation, as the bit 10 may be rotated about the central axis 14 thereof and as the front cutting face 108 and the cutting edge 122 of the cutting element 106 engage the formation, contact with the formation by the cutting edge 122 and an adjacent portion of the front cutting face 108 may urge the cutting element 106 to rotate about the central axis L107 within the cavity 310 of the positioning feature 306. In other embodiments, the cutting element 106 may also be coupled to the impelling feature 314 such that rotation of the formation-engaging feature 320 may also drive rotation of the cutting element 106 as previously described with regard to the rotation of the positioning feature 306. Accordingly, the cutting element 106 may be referred to herein as a “rotatable cutting element,” as previously described herein.
As illustrated in
In some embodiments, the positioning feature 124, 216 and the substrate 112 of the cutting element 106 may be coupled together or integrally formed. Put differently, in some embodiments, the substrate 112 of the cutting element 106 may be sized and configured to substantially fill the volume of the cavity 104, 204 of the sleeve 102, 202. In such embodiments, the cutting element 106 may be formed to be asymmetrical such that the lower portion 116 of the substrate 112 has a central axis extending therethrough, which is not coaxial with the central axis L107 of the table 107 formed thereover but is coaxial with the central axis L102, L202 of the sleeve 102, 202. Accordingly, as the cutting element 106 rotates within the sleeve 102, 202, the central axis L107 may revolve about the central axis L102, L202 of the sleeve 102, 202. In such embodiments, the rotation of the cutting element 106 about the central axis L107 and about the central axis L102 may be one and the same.
Rotation of the cutting element 106 within the sleeve 102 of the embodiment of
As known in the art the face of the bit 10 may comprise a cone region, a nose region, and a shoulder region extending successively from adjacent the central axis 12 of the bit 10 and radially outward forward the gage 18. The drill bit 10 may comprise a plurality of cutting element assemblies 100, 200 mounted along the blade 16 such that the cutting element assemblies 100, 200 may be mounted in one or more of the cone region, the nose region, and the shoulder region. Accordingly, the drill bit 10 may be configured such that the DOC of the cutting element 106 may be varied across one or more of the cone region, the nose region, and the shoulder region. In such embodiments, one or more of the cutting elements 106 may have the same exposure or different exposure 350 as another cutting element 106 mounted in the same region or a different region of the bit 10.
By modifying the exposure 350 during operation of the bit 10, the aggressiveness of the bit 10 may be modified during operation of the bit 10. As used herein, the aggressiveness of the bit 10 refers to the relative volume of subterranean formation material being removed by engagement of one of more cutting elements 106 with the formation on each rotation of the drill bit 10. A high aggressiveness refers to a relatively larger volume of subterranean formation material being removed by one or more cutting elements 106 on each rotation of the drill bit 10, while a low aggressiveness refers to a relatively smaller volume of subterranean formation material being removed by one or more cutting elements 106 on each rotation of the drill bit 10.
Drill bit aggressiveness may contribute to the vibration, whirl, and stick-slip for a given weight-on-bit (WOB) and drill bit rotational speed. By controlling exposure 350 of cutting element 106 and other aggressiveness-affecting parameters, the bit 10 may form a smoother borehole, avoid premature damage to the cutting elements 106, and prolong operating life of the earth-boring tool. Further, rotation of the cutting element 106 such that the entire circumference of the cutting edge 122 may be used to engage the formation, rather than the same section or segment of the cutting edge 122 if the cutting element 106 was not rotatable, may generate more uniform edge wear on the cutting element 106, and may prolong the operating life and increased cutting efficiency of the cutting elements 106 and the earth-boring tool.
While the present invention has been described herein with respect to certain illustrated embodiments, those of ordinary skill in the art will recognize and appreciate that it is not so limited. Rather, many additions, deletions, and modifications to the illustrated embodiments may be made without departing from the scope of the invention as claimed, including legal equivalents thereof. In addition, features from one embodiment may be combined with features of another embodiment while still being encompassed within the scope of the invention as contemplated by the inventors. Further, embodiments of the disclosure have utility with different and various tool types and configurations.
