US20190063163A1

US20190063163A1 - Cutting element assemblies comprising rotatable cutting elements insertable from the back of a blade

Info

Publication number: US20190063163A1
Application number: US15/688,397
Authority: US
Inventors: John Abhishek Raj Bomidi; William A. Moss, Jr.; Jon David Schroder; Alexander Rodney Boehm; Kegan L. Lovelace
Original assignee: Individual
Current assignee: Baker Hughes Holdings LLC
Priority date: 2017-08-28
Filing date: 2017-08-28
Publication date: 2019-02-28

Abstract

An earth-boring tool is comprised of a body, blade, and cutting element assembly. The sleeve of the cutting element assembly has an interior surface that defines a cavity. A rotatable cutting element fits within the cavity secured by a threaded end cap. The rotatable cutting element is comprised of a polycrystalline hard material bonded to a supporting substrate. The polycrystalline hard material has an end cutting surface on a first end and the supporting substrate has a back surface on a second end opposite the first end. An annular ring has an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap. There is a spring in a void defined by an inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.

Description

FIELD

Embodiments of the present disclosure relate generally to rotatable cutting elements and earth-boring tools having such cutting elements.

BACKGROUND

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 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 of the cutting element to a point high enough to braze the cutting element to the bit body in a fixed position but not so high as to damage the PCD layer of the cutting element.
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 A_Lof rotation 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.

BRIEF SUMMARY

A cutting element assembly includes a sleeve, a rotatable cutting element, an annular ring, an end cap, and a spring. The sleeve of the cutting element assembly has at least one interior surface that defines a cavity therein. The sleeve has helical threads proximate an end of at least one interior surface. The cutting element assembly has an end cap having an upper surface and threads engaging the helical threads of the sleeve. Within the sleeve, there is a rotatable cutting element comprising a polycrystalline hard material bonded to a supporting substrate. The polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element. The supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end. An annular ring of the cutting element assembly has an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap. The annular ring has an inner surface and a spring disposed within a void defined by the inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.
Some embodiments include an earth-boring tool comprising a body comprising at least one blade extending radially outward to define a face proximate a leading end of the body. A cutting element assembly is carried by a rotationally leading portion of the at least one blade. The cutting element comprises a sleeve, wherein the sleeve has at least one interior surface that defines a cavity therein. The sleeve has helical threads proximate an end of at least one interior surface. The cutting element assembly has an end cap with the end cap having an upper surface and threads engaging the helical threads of the sleeve. Within the sleeve, there is a rotatable cutting element. The rotatable cutting element comprises a polycrystalline hard material bonded to a supporting substrate. The polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element. The supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end. An annular ring of the cutting element assembly has an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap. The annular ring has an inner surface and a spring disposed within a void defined by the inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified schematic diagram of an example of a drilling system using cutting element assemblies disclosed herein.

FIG. 2 is a simplified perspective view of a fixed-blade earth-boring rotary drill bit that may be used in conjunction with the drilling system of FIG. 1.

FIG. 3 is a simplified cross-section showing a cutting element assembly.

FIG. 4 is a simplified perspective view showing the cutting element assembly FIG. 3.

FIG. 5 is a simplified exploded perspective view showing the sleeve and the end cap of the cutting element assembly of FIG. 3.

FIG. 6 is a simplified exploded perspective view showing a rotatable cutting element and an annular ring of the cutting element assembly of FIG. 3.

FIG. 7 is a simplified perspective view showing another embodiment of a rotatable cutter of a cutting element assembly.

FIG. 8 is a simplified cross-section showing another embodiment of a cutting element assembly.

DETAILED DESCRIPTION

The illustrations presented herein are not actual views of any particular cutting assembly, tool, or drill string, 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. The drawings accompanying the application are for illustrative purposes only, and are 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, 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 Kg_f/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 “intergranular bond” means and includes any direct atomic bond (e.g., covalent, metallic, etc.) between atoms in adjacent grains of material.
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.
FIG. 1 is a schematic diagram of an example of a drilling system 100 using cutting element assemblies disclosed herein. FIG. 1 shows a wellbore 110 that includes an upper section 111 with a casing 112 installed therein and a lower section 114 that is being drilled with a drill string 118. The drill string 118 includes a tubular member 116 that carries a drilling assembly 130 at its bottom end. The tubular member 116 may be coiled tubing or may be formed by joining drill pipe sections. A drill bit 150 (also referred to as the “pilot bit”) is attached to the bottom end of the drilling assembly 130 for drilling a first, smaller diameter borehole 142 in the formation 119. A reamer bit 160 may be placed above or uphole of the drill bit 150 in the drill string 118 to enlarge the borehole 142 to a second, larger diameter borehole 120. The terms wellbore and borehole are used herein as synonyms.
The drill string 118 extends to a rig 180 at the surface 167. The rig 180 shown is a land rig for ease of explanation. The apparatus and methods disclosed herein equally apply when an offshore rig is used for drilling underwater. A rotary table 169 or a top drive may rotate the drill string 118 and the drilling assembly 130, and thus the pilot bit 150 and reamer bit 160, to respectively drill boreholes 142 and 120. The rig 180 also includes conventional devices, such as mechanisms to add additional sections to the tubular member 116 as the wellbore 110 is drilled. A surface control unit 190, which may be a computer-based unit, is placed at the surface 167 for receiving and processing downhole data transmitted by the drilling assembly 130 and for controlling the operations of the various devices and sensors 170 in the drilling assembly 130. A drilling fluid from a source 179 thereof is pumped under pressure through the tubular member 116 that discharges at the bottom of the pilot bit 150 and returns to the surface via the annular space (also referred to as the “annulus”) between the drill string 118 and an inside wall of the wellbore 110.
During operation, when the drill string 118 is rotated, both the pilot bit 150 and the reamer bit 160 rotate. The pilot bit 150 drills the first, smaller diameter borehole 142, while simultaneously the reamer bit 160 enlarges the borehole 142 to a second, larger diameter 120. The earth's subsurface may contain rock strata made up of different rock structures that can vary from soft formations to very hard formations, and therefore the pilot bit 150 and/or the reamer bit 160 may be selected based on the formations expected to be encountered in a drilling operation.
FIG. 2 is a perspective view of a fixed-cutter earth-boring rotary drill bit 200 that may be used in conjunction with the drilling system 100 of FIG. 1. For example, the drill bit 200 may be the pilot bit 150 shown in FIG. 1. The drill bit 200 includes a bit body 202 that may be secured to a shank 204 having a threaded connection portion 206 (e.g., an American Petroleum Institute (API) threaded connection portion) for attaching the drill bit 200 to a drill string (e.g., drill string 118, shown in FIG. 1). In some embodiments, the bit body 202 may be secured to the shank 204 using an extension 208. In other embodiments, the bit body 202 may be secured directly to the shank 204.
The bit body 202 may include internal fluid passageways that extend between the face 203 of the bit body 202 and a longitudinal bore, extending through the shank 204, the extension 208, and partially through the bit body 202. Nozzle inserts 214 may be provided at the face 203 of the bit body 202 within the internal fluid passageways. The bit body 202 may further include a plurality of blades 216 that are separated by junk slots 218. In some embodiments, the bit body 202 may include gage wear plugs 222 and wear knots 228. A plurality of cutting element assemblies 210 may be mounted on the face 203 of the bit body 202 in cutting element pockets 212 that are located along each of the blades 216. The cutting element assemblies 210 may include PDC cutting elements, or may include other cutting elements. For example, some or all of the cutting element assemblies 210 may include rotatable cutters, as described below and shown in FIGS. 3-7.
For instance, a rotatable cutter may be configured to rotate within a sleeve, such that an entire edge of the rotatable cutter adjacent the end of the rotatable cutter can contact the formation 119 (FIG. 1) at various times during a drilling operation. Rotatable cutting elements assemblies as disclosed herein may have certain advantages over conventional rotatable cutting elements and over conventional fixed cutting elements. For example, sleeves may be installed into a bit body (e.g., by brazing) before the rotatable cutting elements are installed into the sleeves. Thus, the rotatable cutting elements, and particularly the PDC tables, need not be exposed to the high temperatures typical of brazing. Thus, installing rotatable cutting elements into sleeves already secured to a bit body may avoid thermal damage caused by brazing. Furthermore, rotatable cutting elements as disclosed herein may be removed easily and replaced, such as when the cutting elements are worn or damaged. Separation of rotatable cutting element from a sleeve secured by a threaded end cap may be trivial in comparison to removal of cutting elements or sleeves brazed into a bit body. Similarly, insertion of a new cutting element may be effected rapidly and without reheating of the drill bit. Thus, drill bits may be more quickly repaired than drill bits having conventional cutting elements.
FIGS. 3 and 4 are simplified views showing a cross-section and a perspective view respectively of the cutting element assembly 210 containing a sleeve 308 and a rotatable cutting element 320. The cutting element assembly 210 may include a sleeve 308. FIG. 5 is a simplified exploded perspective view of the sleeve 308 and an end cap 312. The sleeve 308 may have a lower cylindrical interior surface 302, a frustoconical interior surface 304, and an upper cylindrical interior surface 306, together defining a cavity in the sleeve 308. The cavity may extend all the way through the sleeve 308, as shown in FIG. 5.
The sleeve 308 may have threads 310 proximate a lower end of the lower cylindrical surface 302 which may be, for example, helical and configured to receive the end cap 312 having similar threads. An exterior surface 305 of the sleeve 308 may be brazed or welded within a hole in the blade 216 (FIG. 2). In other embodiments, the sleeve 308 may be integrally formed with the blade 216, such that there is no physical interface between the sleeve 308 and the blade 216.
FIG. 6 is a simplified exploded perspective view of the rotatable cutting element 320 and an annular ring 340. The rotatable cutting element 320 may be at least partially within the sleeve 308. The rotatable cutting element 320 may include a polycrystalline hard material 322 bonded to a substrate 324 at an interface 325.
The polycrystalline hard material 322 may include diamond, cubic boron nitride, or another hard material. The polycrystalline hard material 322 may have an end cutting surface 326, and may also have other surfaces, such as a side surface 328, a chamfer 330, (see FIG. 4) etc., which surfaces may be cutting surfaces intended to contact a subterranean formation. The polycrystalline hard material 322 may be generally cylindrical about the axis of rotation A_L, and the interface 325 may be generally parallel to the end cutting surface 326.
The substrate 324 may include, for example, cobalt-cemented tungsten carbide or another carbide material. The supporting substrate 324 may have a lower cylindrical portion 332, a frustoconical surface 334, and an upper cylindrical surface 336. The surfaces 332, 334, and 336 of the supporting substrate 324 may have a shape corresponding to the interior surfaces 302, 304, and 306 (see FIG. 4) of the sleeve 308, respectively. The lower cylindrical surface 332 may have a larger radial diameter than the upper cylindrical surface 336, and the surfaces 332, 334, and 336 may share a common axis of rotation, which may coincide with a longitudinal axis A_Lof rotation of the rotatable cutting element 320. Thus, when the rotatable cutting element 320 rotates within the sleeve 308, the surfaces 332, 334, and 336 of the supporting substrate 324 may be in rotational sliding contact with the interior surfaces 302, 304, and 306 of the sleeve 308, respectively.
The supporting substrate 324 may be generally cylindrical, with a generally planar back surface 338 of the supporting substrate 324 perpendicular to the longitudinal axis A_Lof rotation. A central portion 335 of the back surface 338 of the supporting substrate 324, a central portion 345 of the upper surface 339 of the end cap 312, and an interior surface 346 of the annular ring 340 may together define a void 348 between the substrate 324 and the end cap 312. The cutting element assembly 210 may include a spring 350 within the void 348.
This void 348 may prevent compressive longitudinal loads (or longitudinal components of loads) on the rotatable cutting element 320 from being transferred to the end cap 312 through the central portion 335 of the back surface 338 of the supporting substrate 324 (e.g., because there may not be contact between central portion 345 of the upper surface 339 of the end cap 312 and the central portion 335 of the back surface 338 of the supporting substrate 324). Instead, a compressive longitudinal load may be transferred substantially (e.g., entirely or almost entirely) via an axial bearing interface at which a bearing surface 337 portion of the back surface 338 of the supporting substrate 324 is in contact with an upper surface 344 of an annular ring 340.
At least this bearing surface 337 portion of the back surface 338 of the supporting substrate 324 may be generally parallel to the end cutting surface 326 such that when the rotatable cutting element 320 rotates around a longitudinal axis A_Lof rotation within the sleeve 308, the bearing surface 337 portion of the back surface 338 of the supporting substrate 324 may be in rotational sliding contact with the upper surface 344 of the annular ring 340. In some embodiments, the bearing surface 337 portion of the back surface 338 of the supporting substrate 324 may have approximately the same dimensions as the upper surface 344 of the annular ring 340, and may be annular.
The annular ring 340 may be disposed between the bearing surface 337 portion of the back surface 338 of the supporting substrate 324 and a bearing surface 349 portion of the upper surface 339 of the end cap 312 such that compressive longitudinal loads may be transferred from the bearing surface 337 portion of the back surface 338 of the supporting substrate 324 to the bearing surface 349 portion of the upper surface 339 of the end cap 312 substantially (e.g., entirely or almost entirely) via a lower surface 342 of the annular ring 340.
The annular ring 340 may be a metal, an alloy, a ceramic, a hard material, a combination of a metal, alloy and/or ceramic, or any other material capable of sustaining a compressive load applied to the rotatable cutting element 320. In some embodiments, the annular ring 340 may include a material having a composition similar or identical to the substrate 324 and/or the sleeve 308. In other embodiments, the annular ring 340 may include a material having a composition different from the substrate 324 and/or the sleeve 308.
The annular ring 340, the back surface 338 of the supporting substrate 324, and the upper surface 339 of the end cap 312 may have one or more polished surfaces to limit sliding friction and enable the rotatable cutting element 320 to freely rotate. In certain embodiments, the annular ring 340, the back surface 338 of the supporting substrate 324, and/or the upper surface 339 of the end cap 312 may include a lubricant, a coating, or another feature to reduce friction. For example, at least a portion of the annular ring 340, the back surface 338 of the supporting substrate 324, and the upper surface 339 of the end cap 312 may include a coating such as diamond or diamond-like carbon. Diamond-like coatings are described in, for example, U.S. Patent Application Publication 2009/0321146, “Earth Boring Bit with DLC Coated Bearing and Seal,” published Dec. 31, 2009, the entire disclosure of which is hereby incorporated herein by reference.
FIG. 7 shows a simplified perspective view of another embodiment of a rotatable cutting element 720. A lower cylindrical surface 732 of the rotatable cutting element 720 intersects an annular plane 735 perpendicular to the longitudinal axis A_Lof rotation of the rotatable cutting element 720. The annular plane 735 intersects both the upper 736 and lower 732 cylindrical surfaces. The lower cylindrical surface 732 may have a larger radial diameter than the upper cylindrical surface 736, and the surfaces 732, 736 may share a common axis of rotation, which may coincide with a longitudinal axis A_Lof rotation of the rotatable cutting element 720. A cutting element assembly may have a sleeve with interior surfaces that correspond to the surfaces 732, 734, and 736 of the rotatable cutting element 720.
FIG. 8 shows a simplified view of a cross-section of another embodiment of a cutting element assembly 800. In this embodiment, a supporting substrate 824 of a rotatable cutting element 820 defines a frustoconical surface 834 from the upper cylindrical surface 836 to the back surface 838.
A sleeve 808, with interior surfaces 804 and 806 that correspond to the surfaces 834 and 836 of the rotatable cutting element 820, may be in sliding contact when the rotatable cutting element 820 rotates around a longitudinal axis A_Lof rotation within the sleeve 808. The bearing surface 837 portion of the back surface 838 of the supporting substrate 824 may be in rotational sliding contact with an upper surface 844 of an annular ring 840. A lower surface 842 of the annular ring 840 may be in rotational sliding contact with a bearing surface 849 portion of an upper surface 839 of an end cap 812. The cutting element assembly 800 may include a spring 850 disposed within a void 848 defined by a central portion 835 of the back surface 838 of the supporting substrate 824 and a central portion 845 of the upper surface 839 of the end cap 812 and an inner surface 846 of the annular ring 840.
Additional nonlimiting example embodiments of the disclosure are described below.
Embodiment 1: A cutting element assembly comprising a sleeve, having at least one interior surface that defines a cavity therein. The sleeve has helical threads proximate an end of the at least one interior surface. The cutting element assembly has an end cap having an upper surface and threads engaging the helical threads of the sleeve. Within the sleeve, there is a rotatable cutting element comprising a polycrystalline hard material bonded to a supporting substrate. The polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element, and the supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end. An annular ring of the cutting element assembly has an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap. The annular ring has an inner surface and a spring disposed within a void defined by the inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.
Embodiment 2: The cutting element assembly of Embodiment 1, wherein the back surface of the cutting element is parallel to the end cutting surface.
Embodiment 3: The cutting element assembly of Embodiment 1 or Embodiment 2, wherein the supporting substrate defines a bearing portion of the back surface, and wherein the bearing portion of the back surface is in rotational sliding contact with the upper surface of the annular ring.
Embodiment 4: The cutting element assembly of any of Embodiments 1 through 3, wherein the lower surface of the annular ring is in rotational sliding contact with the upper surface of the end cap.
Embodiment 5: The cutting element assembly of any of Embodiments 1 through 4, wherein the spring comprises a metal.
Embodiment 6: The cutting element assembly of any of Embodiments 1 through 5, wherein the annular ring comprises a metal.
Embodiment 7: The cutting element assembly of any of Embodiments 1 through 6, wherein the annular ring comprises a ceramic.
Embodiment 8: The cutting element assembly of any of Embodiments 1 through 7, wherein the annular ring comprises a combination of a metal and a ceramic.
Embodiment 9: The cutting element assembly of any of Embodiments 1 through 8, wherein when a compressive longitudinal load is applied to the end cutting surface of the polycrystalline hard material of the rotatable cutting element, the compressive longitudinal load is transferred to the end cap substantially via the annular ring.
Embodiment 10: The cutting element assembly of any of Embodiments 1 through 9, further comprising a lubricant between the sleeve and the rotatable cutting element.
Embodiment 11: The cutting element assembly of any of Embodiments 1 through 10, further comprising a diamond like carbon coating over at least one surface selected from the group consisting of the back surface of the supporting substrate, the upper surface of the end cap, the upper surface of the annular ring, and the lower surface of the annular ring.
Embodiment 12: An earth-boring tool comprising a body comprising at least one blade extending radially outward to define a face proximate a leading end of the body and a cutting element assembly carried by a rotationally leading portion of at least one of the blades. The cutting element comprises a sleeve having at least one interior surface that defines a cavity therein. The sleeve has helical threads proximate an end of the at least one interior surface. The cutting element assembly has an end cap with the end cap having an upper surface and threads engaging the helical threads of the sleeve. Within the sleeve, there is a rotatable cutting element comprising a polycrystalline hard material bonded to a supporting substrate. The polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element and the supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end. An annular ring of the cutting element assembly has an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap. The annular ring has an inner surface and a spring disposed within a void defined by the inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.
Embodiment 13: The earth-boring tool of Embodiment 12, wherein the back surface of the cutting element is parallel to the end cutting surface.
Embodiment 14: The earth-boring tool of Embodiment 12 or Embodiment 13, wherein the supporting substrate defines a bearing portion of the back surface, and wherein the bearing portion of the back surface is in rotational sliding contact with the upper surface of the annular ring.
Embodiment 15: The earth-boring tool of any of Embodiments 12 through 14, wherein the lower surface of the annular ring is in rotational sliding contact with the upper surface of the end cap.
Embodiment 16: The earth-boring tool of any of Embodiments 12 through 15, wherein the spring comprises a metal.
Embodiment 17: The earth-boring tool of any of Embodiments 12 through 16, wherein the annular ring comprises a metal.
Embodiment 18: The earth-boring tool of any of Embodiments 12 through 17, wherein the annular ring comprises a ceramic.
Embodiment 19: The earth-boring tool of any of Embodiments 12 through 18, wherein the annular ring comprises a combination of a metal and a ceramic.
Embodiment 20: The earth-boring tool of any of Embodiments 12 through 19, wherein when a compressive longitudinal load is applied to the end cutting surface of the polycrystalline hard material of the rotatable cutting element, the compressive longitudinal load is transferred to the end cap substantially via the annular ring.
Embodiment 21: The earth-boring tool of any of Embodiments 12 through 20, further comprising a lubricant between the sleeve and the rotatable cutting element.
Embodiment 22: The earth-boring tool of any of Embodiments 12 through 21, further comprising a diamond like carbon coating over at least one surface selected from the group consisting of the back surface of the supporting substrate, the upper surface of the end cap, the upper surface of the annular ring, and the lower surface of the annular ring.
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.

Claims

What is claimed is:

1. A cutting element assembly, comprising:

a sleeve having at least one interior surface defining a cavity therein and helical threads proximate an end of the at least one interior surface;

an end cap having threads engaging the helical threads of the sleeve, the end cap having an upper surface;

a rotatable cutting element within the sleeve, the rotatable cutting element comprising a polycrystalline hard material bonded to a supporting substrate, wherein the polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element and wherein the supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end;

an annular ring having an upper surface in contact with the back surface of the supporting substrate and a lower surface in contact with the upper surface of the end cap, the annular ring having an inner surface; and

a spring disposed within a void defined by the inner surface of the annular ring, the back surface of the supporting substrate, and the upper surface of the end cap.

2. The cutting element assembly of claim 1, wherein the back surface of the rotatable cutting element is parallel to the end cutting surface.

3. The cutting element assembly of claim 1, wherein the supporting substrate defines a bearing portion of the back surface, and wherein the bearing portion of the back surface is in rotational sliding contact with the upper surface of the annular ring.

4. The cutting element assembly of claim 1, wherein the lower surface of the annular ring is in rotational sliding contact with the upper surface of the end cap.

5. The cutting element assembly of claim 1, wherein the spring comprises a metal.

6. The cutting element assembly of claim 1, wherein the annular ring comprises a metal.

7. The cutting element assembly of claim 1, wherein the annular ring comprises a ceramic.

8. The cutting element assembly of claim 1, wherein when a compressive longitudinal load is applied to the end cutting surface of the polycrystalline hard material of the rotatable cutting element, the compressive longitudinal load is transferred to the end cap substantially via the annular ring.

9. The cutting element assembly of claim 1, further comprising a lubricant between the sleeve and the rotatable cutting element.

10. The cutting element assembly of claim 1, further comprising a diamond like carbon coating over at least one surface selected from the group consisting of the back surface of the supporting substrate, the upper surface of the end cap, the upper surface of the annular ring, and the lower surface of the annular ring.

11. An earth-boring tool comprising:

a body comprising at least one blade extending radially outward to define a face proximate a leading end of the body; and

a cutting element assembly carried by a rotationally leading portion of the at least one blade, the cutting element assembly comprising a sleeve;

the sleeve having at least one interior surface defining a cavity therein and helical threads proximate an end of the at least one interior surface;

a rotatable cutting element within the sleeve, the rotatable cutting element comprising a polycrystalline hard material bonded to a supporting substrate, wherein the polycrystalline hard material has an end cutting surface on a first end of the rotatable cutting element and the supporting substrate has a back surface on a second end of the rotatable cutting element opposite the first end;

12. The earth-boring tool of claim 11, wherein the back surface of the rotatable cutting element is parallel to the end cutting surface.

13. The earth-boring tool of claim 11, wherein the supporting substrate defines a bearing portion of the back surface, and wherein the bearing portion of the back surface is in rotational sliding contact with the upper surface of the annular ring.

14. The earth-boring tool of claim 11, wherein the lower surface of the annular ring is in rotational sliding contact with the upper surface of the end cap.

15. The earth-boring tool of claim 11, wherein the spring comprises a metal.

16. The earth-boring tool of claim 11, wherein the annular ring comprises a metal.

17. The earth-boring tool of claim 11, wherein the annular ring comprises a ceramic.

18. The earth-boring tool of claim 11, wherein when a compressive longitudinal load is applied to the end cutting surface of the polycrystalline hard material of the rotatable cutting element, the compressive longitudinal load is transferred to the end cap substantially via the annular ring.

19. The cutting element assembly of claim 11, further comprising a lubricant between the sleeve and the rotatable cutting element.

20. The cutting element assembly of claim 11, further comprising, a diamond like carbon coating over at least one surface selected from the group consisting of the back surface of the supporting substrate, the upper surface of the end cap, the upper surface of the annular ring, and the lower surface of the annular ring.