DRILL BITS HAVING ROTATING CUTTING STRUCTURES THEREON

- SMITH INTERNATIONAL, INC.

A drill bit may include a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and a plurality of cutting structures having at least one fixed cutting structure disposed on the bit body face and at least one cutting body rotatably attached to the face of the bit body; wherein, in a rotated view of the plurality of cutting structures into a single plane, there is substantially no radial overlap between at least one fixed cutting structure and the at least one cutting body.

Skip to: Description  ·  Claims  · Patent History  ·  Patent History
Description
RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/665632 filed Jun. 28, 2012, and U.S. Provisional Patent Application Ser. No. 61/548433 filed Oct. 18, 2011, both of which are incorporated by reference herein in their entireties.

BACKGROUND

Historically, there have been two main types of drill bits used for drilling earth formations, drag bits and roller cone bits. The term “drag bits” refers to those rotary drill bits with no moving elements. Drag bits include those having cutters attached to the bit body, which predominantly cut the formation by a shearing action. Roller cone bits include one or more roller cones rotatably mounted to the bit body. These roller cones have a plurality of cutting elements attached thereto that crush, gouge, and scrape rock at the bottom of a hole being drilled.

Typically, bit type may be selected based on the primary nature of the formation to be drilled. However, many formations have mixed characteristics (i.e., the formation may include both hard and soft zones), which may reduce the rate of penetration of a bit (or, alternatively, reduces the life of a selected bit) because the selected bit is not preferred for certain zones. For example, both milled tooth roller cone bits and PDC bits can efficiently drill soft formations, but PDC bits will typically have a rate of penetration higher than roller cone bits.

PDC Drill Bits

Drag bits, often referred to as “fixed cutter drill bits,” include bits that have cutting elements attached to the bit body, which may be a steel bit body or a matrix bit body formed from a matrix material such as tungsten carbide surrounded by a binder material. Drag bits may generally be defined as bits that have no moving parts. However, there are different types and methods of forming drag bits that are known in the art. For example, drag bits having abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body are commonly referred to as “impreg” bits. Drag bits having cutting elements made of an ultra hard cutting surface layer or “table” (typically made of polycrystalline diamond material or polycrystalline boron nitride material) deposited onto or otherwise bonded to a substrate are known in the art as polycrystalline diamond compact (“PDC”) bits.

PDC bits drill soft formations easily, but they are frequently used to drill moderately hard or abrasive formations. They cut rock formations with a shearing action using small cutters that do not penetrate deeply into the formation. Because the penetration depth is shallow, high rates of penetration are achieved through continuous cutting of the formation.

An example of a prior art PDC bit having a plurality of cutters with ultra hard working surfaces is shown in FIG. 1. The drill bit 10 includes a bit body 11 having a threaded upper pin end 12 and a cutter end 13. The cutter end 13 typically includes a plurality of ribs or blades 14 arranged about the rotational axis of the drill bit and extending radially outward from the bit body 11. Cutting elements, or cutters, 15 are embedded in the blades 14 at predetermined angular orientations and radial locations relative to a working surface and with a desired back rake angle against a formation to be drilled.

A plurality of orifices 16 is positioned on the bit body 11 in the areas between the blades 14, which may be referred to as “gaps” or “fluid courses.” The orifices 16 are commonly adapted to accept nozzles. The orifices 16 allow drilling fluid to be discharged through the bit in selected directions and at selected rates of flow between the cutting blades 14 for lubricating and cooling the drill bit 10, the blades 14 and the cutters 15. The drilling fluid also cleans and removes the cuttings as the drill bit 10 rotates and penetrates the geological formation. Without proper flow characteristics, insufficient cooling of the cutters 15 may result in cutter failure during drilling operations. The fluid courses are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit 10 toward the surface of a wellbore (not shown).

Roller Cone Drill Bits

Roller cone drill bits are generally used to drill formations that fail by crushing and gouging as opposed to shearing. Typically, roller cone drill bits are also preferred for heterogeneous formations that initiate vibration in drag bits. Roller cone drill bits include milled tooth bits and insert bits. Milled tooth roller cone bits may be used to dill relatively soft formations, while insert roller cone bits are suitable for medium or hard formations.

Roller cone drill bits typically include a main body with a threaded pin formed on the upper end of the main body for connecting to a drill string, and one or more legs extending from the lower end of the main body. Referring now to FIG. 2, a conventional insert roller cone drill bit, generally designated as 20, consists of bit body 21 forming an upper pin end 22 and a cutter end 23 of roller cones 24 that are supported by legs 25 extending from body 21. The threaded pin end 22 is adapted for assembly onto a drill string (not shown) for drilling oil wells or the like. Each of the legs 25 terminates in a shirttail portion 26.

Each of the roller cones 24 typically has a plurality of cutting elements 27 thereon for cutting earth formation as the drill bit 20 is rotated about the longitudinal axis L. FIG. 2 shows cutting elements 27 pressed within holes formed in the surfaces of the cones 24, however, milled tooth bits will have hardfaced steel teeth milled on the outside of the cone 24 instead of carbide inserts. Nozzles 28 in the bit body 21 introduce drilling mud into the space around the roller cones 24 for cooling and carrying away formation chips drilled by the drill bit 20. Drilling fluid is directed within the hollow pin end 22 of the bit 20 to an interior plenum chamber 29 formed by the bit body 21. The fluid is then directed out of the bit through the one or more nozzles 28.

Each leg 25 includes a journal 30 extending downwardly and radially inward towards a center line, or longitudinal axis, L of the bit body 21. A bearing assembly is disposed between the cone 24 and the journal 30. For higher rotational speed applications, roller cone bits may have roller bearing assemblies. A plurality of ball bearings 32 is fitted into complementary ball races in the cone 24 and on the journal 30, respectively. These balls 32 are inserted through a ball passage 34, which extends through the journal 30 between the ball races and the exterior of the drill bit 20. A cone 24 is first fitted on the journal 30, and then the balls 32 are inserted through the ball passage 34. The balls 32 carry any thrust loads tending to remove the cone 24 from the journal 30 and thereby retain the cone 24 on the journal 30. The balls 32 are retained in the races by a ball retainer 35 inserted through the ball passage 34 after the balls are in place and welded therein.

Contained within bit body 21 is a grease reservoir system, generally designated as 36. Lubricant passage 37 is provided from a reservoir chamber 38 to ball bearing surfaces 33 formed between a cone 24 and a journal 30. The ball bearing surfaces 33 between the cone 24 and journal 30 are lubricated by a lubricant or grease composition. Lubricant or grease is retained in the bearing structure by a resilient seal 39 between the cone 24 and journal 30.

Both roller cone and PDC bits have their own advantages. Due to the difference in cutting mechanisms and cutting element materials, each is best suited for different drilling conditions. Roller cone bits predominantly use a crushing mechanism in drilling, which gives roller cone bits overall durability and strong cutting ability. PDC bits use a pure shearing mechanism for cutting, which allows higher performance in soft formation drilling than roller cone bits are able to achieve.

Despite many valuable contributions from the art, it would be beneficial to develop drill bits having desirable cutting mechanisms.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments disclosed herein relate to a drill bit that includes a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and a plurality of cutting structures having at least one fixed cutting structure disposed on the bit body face and at least one cutting body rotatably attached to the face of the bit body; wherein, in a rotated view of the plurality of cutting structures into a single plane, there is substantially no radial overlap between at least one fixed cutting structure and the at least one cutting body.

In one aspect, embodiments disclosed herein relate to a drill bit that includes a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and a plurality of cutting structures including a plurality of cutting bodies rotatably attached to the face of the bit body, wherein each of the plurality of cutting bodies have a substantially parallel axis of rotation and have axially overlapping cutting surfaces; and wherein the bit body has no blades extending azimuthally therefrom.

In another aspect, embodiments disclosed herein relate to a drill bit that includes a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and at least one cutting structure including at least one cutting body rotatably attached to the face of the bit body, wherein the at least one cutting body comprises a plurality of raised segments aximuthally spaced about the at least one cutting body.

In yet another aspect, embodiments disclosed herein relate to a drill bit that includes a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end, wherein the face comprises at least one bore formed therein; and at least one cutting structure including at least one cutting body rotatably attached to the face of the bit body, wherein the at least one cutting body comprises an exposed end and a shaft that extends into the bore formed in the face of the bit body.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a perspective of a conventional PDC drill bit.

FIG. 2 is a semi-schematic perspective of a conventional three cone roller cone drill bit.

FIGS. 3A-3C show three different perspective views of one embodiment of a drill bit.

FIGS. 4A and 4B show two different perspective views of one embodiment of a drill bit.

FIGS. 5A and 5B show two different perspective views of one embodiment of a drill bit.

FIGS. 6A and 6B show two different perspective views of one embodiment of a drill bit.

FIGS. 7A and 7B show two different perspective views of one embodiment of a drill bit.

FIGS. 8A and 8B show two different perspective views of one embodiment of a drill bit.

FIGS. 9A and 9B show two different perspective views of one embodiment of a drill bit.

FIGS. 10A and 10B show two different perspective views of one embodiment of a drill bit.

FIG. 11 shows a rolling cutting body having a shaft inserted into a bore in a bit body.

FIG. 12 shows a conical cutting insert.

FIGS. 13A-B show side and top perspective views of a faceted insert.

FIG. 14 shows an example cutting trajectory for a cutting element located on a rotating cutting body.

FIG. 15 shows a cross-sectional view of a rotating cutting body attached to a bit body.

FIGS. 16A-B show cross-sectional views of a mechanical seal assembly disposed between a rotating cutting body and a bit body according to embodiments of the present disclosure.

FIGS. 17A-B show cross-sectional views of a mechanical seal assembly disposed between a rotating cutting body and a bit body according to embodiments of the present disclosure.

FIG. 18 shows an exploded view of a bit having an open bearing assembly according to embodiments of the present disclosure.

FIGS. 19A-C show radial bearing surfaces according to embodiments of the present disclosure.

FIGS. 20A-B show bearing sleeves according to embodiments of the present disclosure.

FIGS. 21A-D show perspective views of bearing rings according to embodiments of the present disclosure.

FIG. 22 shows perspective views of wear buttons according to embodiments of the present disclosure.

FIG. 23 shows an exploded view of a rotating cutting body attached to a bit.

FIG. 24 shows a side perspective view of a bit according to embodiments of the present disclosure.

FIG. 25 shows a top perspective view of a bit according to embodiments of the present disclosure.

 DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to drill bits having rotating cutting bodies disposed thereon. Specifically, such rotating cutting bodies may be used as the sole cutting structure on a bit or may be used with conventional cutting structures such as fixed blades (with cutters) and roller cones.

Referring to FIGS. 3A and 3B, two different perspective views of a drill bit are shown. As shown in FIGS. 3A and 3B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (shown in FIG. 3C). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 3A-B, each of the plurality of rotating cutting bodies 110 has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. The rotating cutting bodies 110 shown in FIGS. 3A-B are mounted on a journal 112 that extends from the face 104 of bit body 102. Rotating cutting bodies 110 are retained on journal 112 by retention balls 114. An axial thrust bearing 116 may be disposed between axial bearing surfaces of the rotating cutting body 110 and journal 112. A bearing sleeve and/or inlay 118 may be disposed between radial bearing surfaces of the rotating cutting body 110 and journal 112. Axial and radial bearing surfaces are lubricated by grease from lube passage 120. Lubricant or grease is retained in the bearing structure by a seal 122 between the rotating cutting body 110 and journal 112. Alternatively, instead of being mounted on journal 112, rotating cutting body 110 may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

Rotating cutting bodies 110 are shown as having a plurality of inserts 124 pressed into holes formed in the rotating cutting body 110. In the illustrated embodiment, rotating cutting bodies 110 are truncated super-ellipsoid shaped. The side circumferential surface of rotating cutting bodies 110 defines the gage 126 or outer diameter of the bit, which is engaged with the sidewall of the formation to maintain hole diameter. The radial end surface 128 of rotating cutting bodies 110 forms the active cutting region of the bit 100, such that the inserts 124 in such a region remaining substantially engaged with the formation, and perform active cutting and rock removal functions.

In the embodiment shown in FIGS. 3A-B, there are two types of inserts used: conical inserts 1241 and faceted inserts 1242. Conical inserts 1241, discussed in greater detail below with respect to FIG. 12, may be particularly desirable on the radial end surface 128 so that the inserts may penetrate into the rock and the drill bit may progress. Other embodiments may use undulating inserts, as described, for example, in U.S. Pat. No. 7,757,789, which is assigned to the present assignee and herein incorporated by reference in its entirety, in place of the conical inserts 1241. Faceted inserts 1242 (shown in greater detail in FIG. 13) may be particularly desirable on the gage region 126 of the rotating cutting bodies 110 to maintain hole diameter. Inserts 1242 may provide rotating forces to cutting bodies 110 through reactions from rock formation when bit body 102 rotates. Therefore two rotating motions could be involved with cutting bodies 110. One is the rotation provided by bit body 102 and the other is the rotation around their own axes. Other shaped cutting elements may also be used, such as chisel-shaped, semi-round top, etc. as known in the art, depending on the desired formation interaction. Further, it is also within the scope of the present disclosure that the bit of FIGS. 3A-B may have any of the rotating cutting bodies illustrated in FIGS. 3A-B, 4A-B, 7A-B (described below) in any combination or used alone.

As shown in FIG. 3C, the connection end 106 of the drill bit 100 may be secured to a drill string 50. The drill string 50 may be rotated by a turbine motor assembly 52, which may include a non-moving or stator housing 54 and a moving or rotor assembly 56. The rotor assembly may include blades attached to the drill string 50, which are designed to rotate as drilling mud flows through the turbine motor assembly 52 and into the borehole (not shown). Other turbine motors known in the art may be used in combination with drill bits of the present disclosure to rotate the drill bit, such as, for example, turbine assemblies described in U.S. Patent Application No. 2010/0314172, which is incorporated herein by reference.

Referring now to FIGS. 4A and 4B, two different perspective views of a drill bit are shown. As shown in FIGS. 4A and 4B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 4A-B, each of the plurality of rotating cutting bodies 110 has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

Rotating cutting bodies 110 shown in FIGS. 4A and 4B include a plurality of raised segments 130 spaced azimuthally about the rotating cutting body 110 with fluid courses 132 therebetween. A fluid opening 134 (with optional hydraulic components such as a nozzle (not shown)) is shown as being present at the centerline of the rotating cutting bodies, which may allow drilling fluid to flow therethrough and up the through the fluid courses 132. Raised segments 130 extend azimuthally from a radial end surface 128 through a gage region 126. As discussed in FIGS. 3A-B, the radial end surface 128 of rotating cutting bodies 110 forms the active cutting region of the bit 100, such that the inserts 124 in such a region remaining substantially engaged with the formation, and perform active cutting and rock removal functions, whereas inserts 124 in the gage region 126 are engaged with the sidewall of the formation to maintain hole diameter. Inserts 124 used in this embodiment include conical inserts 1241 on the radial end surface 126 and faceted inserts 1242 in the gage region. Other shaped cutting elements may also be used, such as undulating, chisel-shaped, semi-round top, etc. as known in the art, depending on the desired formation interaction.

Referring now to FIGS. 5A and 5B, two different perspective views of a drill bit are shown. As shown in FIGS. 5A and 5B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 5A-B, each of the plurality of rotating cutting bodies 110 has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

In addition to rotating cutting bodies 110, bit 100 shown in FIGS. 5A-B also includes, as a cutting structure, a fixed structure of a plurality of inserts 136 mounted in holes (not shown) in the bit body face 104. When viewed in a rotated view into a single plane, there is substantially no radial overlap (from bit centerline) between inserts 136 and the rotating cutting bodies 110. As defined herein, substantially no radial overlap is defined to mean an overlap of less than 10% of the total radius of the cutting profile. In embodiments, even less overlap, such as less than 5% overlap or no overlap, may be envisioned. The rotating cutting bodies 110 shown in this embodiment are the same as those shown in and discussed above with respect to FIGS. 3A-B. Inserts 136 that are inserted into holes in bit body 102 are illustrated as conical inserts having axes that are substantially parallel with each other, the axes of rotating cutting bodies 110 and the centerline of bit 100. However, it is also envisioned that inserts 136 may be inserted into holes such that each insert is inserted tangent to the surrounding bit face, and if the bit face possesses such curvature, the inserts may not necessarily be substantially parallel. As shown, the plurality of inserts 136 are of different sizes, with the insert 136 residing substantially at or overlapping the bit centerline (i.e., r0) being the largest insert (diameter and extension). The inserts 136 at the next closest radial location to the bit centerline (i.e., r1) are smaller than the center insert 136 at r0. Inserts 136 at the next closest radial location to the bit centerline (i.e., r2) are of an intermediate size between inserts 136 at r0 and r1. Finally, inserts 136 at the furthest radial location to the bit centerline (i.e., r3) are the smallest inserts 136, smaller than the inserts 136 at r1. The details of inserts 136 (and insert geometry) are discussed below in greater detail. Additionally, moving radially outward from r0 to r3, the axial location of the apex of the inserts 136 at each radial location increases, with the center insert 136 having the lowest axial apex and the inserts at r3 having the uppermost axial apex (when the bit is oriented downward toward the formation), so that the center insert contacts the bottomhole first.

Rotating cutting bodies 110 are attached to bit face 104 at a radial distance greater than r3, but it is envisioned that the profile of inserts 124 located on rotating cutting bodies may overlap with the profile of inserts 136 at r3, when all of the cutting elements are viewed in a rotated single plane. Bit body 102 may extend into lobes or radial projections 138 to support rotating cutting bodies 110. In such a manner, bit body 102 remains contoured to allow for maximum fluid flow between spaced cutting structures. While the bit bodies 102 shown in FIGS. 3 and 4 are also contoured, the lobes are less pronounced than as shown in FIGS. 5A-B due to the compactness of the rotating cutting bodies 110 around the bit centerline in the previously illustrated embodiments. While the bit 100 shown in FIGS. 5A-B has two types of cutting structures: rotating cutting bodies 110 and inserts 136, only the rotating cutting bodies 110 contribute to maintaining gage. Gage protection elements 140 may be embedded in bit body 102 along portions of the bit body that extend to gage to help protect wear along this portion of the bit body.

Further, while the rotating cutting bodies illustrated in FIGS. 5A-B are of the same type as illustrated in FIGS. 3A-B, it is also within the scope of the present disclosure that rotating cutting bodies having raised segments, such as those shown in FIGS. 4A-B may be used in combination with or in place of the illustrated rotating cutting bodies 110.

Referring now to FIGS. 6A and 6B, two different perspective views of a drill bit are shown. As shown in FIGS. 6A and 6B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 6A-B, the plurality of rotating cutting bodies 110 each has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

In addition to rotating cutting bodies 110, bit 100 shown in FIGS. 6A-B also includes, as a cutting structure, a fixed cutting structure of blades 142 that extend azimuthally from bit body 102. Each blade 142 includes a plurality of cutter pockets in which cutters 144 may be disposed. When viewed in a rotated view into a single plane, there is substantially no radial overlap (from bit centerline) (as discussed above) between cutters 144 and rotating cutting bodies 110. The rotating cutting bodies 110 shown in this embodiment include two types of cutting bodies on a single bit: two cutting bodies as shown in and discussed above with respect to FIGS. 3A-B and one cutting body similar to the one as shown in and discussed with respect to FIGS. 4A-B. However, the bit may, instead of having rotating cutting bodies of the same type, have either those illustrated in FIGS. 3A-B or in FIGS. 4A-B. It is noted that the rotating cutting body 110 having the raised segments 130 shown in FIGS. 6A-B does not include a central fluid passageway as discussed in FIGS. 4A-B. Similar to FIGS. 5A-5B, only the rotating cutting bodies 110 (along with gage protection elements 140) contribute to maintaining gage in this illustrated embodiment due to the radially interior placement of the fixed blades 142 and cutters 144.

Referring now to FIGS. 7A and 7B, two different perspective views of a drill bit are shown. As shown in FIGS. 7A and 7B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 7A-B, the plurality of rotating cutting bodies 110 each has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

In addition to rotating cutting bodies 110, bit 100 shown in FIGS. 7A-B also includes, as a cutting structure, a fixed cutting structure of blades 142 that extend azimuthally from bit body 102. Each blade 142 includes a plurality of cutter pockets in which cutters 144 may be disposed. In this embodiment, blades 142 extend to the gage of the bit, and may include gage protection elements 142 thereon When viewed in a rotated view into a single plane, in contrast to the embodiment shown in FIGS. 6A-B, there is more than insubstantial radial overlap (from bit centerline) between cutters 144 and rotating cutting bodies 110. As defined herein, “more than insubstantial radial overlap” is defined to mean an overlap of more than 10% of the total radius of the cutting profile. In embodiments, a greater than 25% overlap, or a greater than 50% may also be envisioned.

The rotating cutting bodies 110 shown in this embodiment include a single type of cutting bodies on a single bit: cutting bodies 110 having a plurality of raised segments 130 spaced azimuthally about rotating cutting bodies 110, as shown in and discussed with respect to FIGS. 4A-B. However, it is also within the scope of the present disclosure that rotating cutting bodies 110 of the type shown in FIGS. 3A-B may be used in combination with or in place of the illustrated rotating cutting bodies 110. Further, the rotating cutting bodies 110 shown in FIGS. 7A-B are not identical to those illustrate in FIGS. 4A-B. Rather, in addition to raised segments 130 extending through both the radial end 128 and the gage region 126 and having inserts 124 thereon, the rotating cutting bodies 110 of FIGS. 7A-B also include raised segments 130-1 that only extend through the gage region 126 and that do not have cutting elements disposed thereon. Such raised segments 130-1 may include a gage pad or other wear resistant material thereon, as known to those of ordinary skill in the art of drill bits. Thus, inserts 124 on raised segments 130, raised segments 130-1 and cutters 142 in the gage region 146 of blades 144 all contribute to maintaining gage in this illustrated embodiment. It is also noted that the rotating cutting bodies 110 illustrated in FIGS. 7A-B may also be used in any of the above described embodiments of bits having rotating cutting bodies 110 thereon. Further, it is also within the scope of the present disclosure that the bit 110 of FIGS. 7A-B may have any of the rotating cutting bodies illustrated in FIGS. 3A-B, 4A-B, 7A-B in any combination or used alone.

Fluid openings 134 (with optional hydraulic components such as a nozzle (not shown)) are shown as being present spaced between the raised segments 130 are provided on the rotating cutting bodies, which may allow drilling fluid to flow through and up the through fluid courses extending through the rotating cutting bodies 110. Fluid openings 134 may be used to clean and cool the cutting structures on the bit 100, including both the fixed cutting structure of cutters 144 and the rotating cutting structure on rotating cutting bodies 110, as well as aim at the bottom hole for potential cuttings removal. In an embodiment, fluid openings 134 may be designed to have specific orientations to spread fluid directly on the cutter faces when cutting bodies 110 rotate. Additionally, bit face 104 may also be provided with provided with fluid openings 135 (and optional hydraulic components) to aid fluid openings 134 in the hydraulic cleaning, cooling and cuttings removal.

Referring now to FIGS. 8A and 8B, two different perspective views of a drill bit are shown. As shown in FIGS. 8A and 8B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 are rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 8A-B, the plurality of rotating cutting bodies 110 each have an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

In addition to rotating cutting bodies 110, bit 100 shown in FIGS. 8A-B also includes, as a cutting structure, a fixed cutting structure of blades 142 that extend azimuthally from a raised body volume 150 extending axially from face 104 of bit body 102. Each blade 142 includes a plurality of cutter pockets in which cutters 144 may be disposed. Similar to FIGS. 5A-5B, only the rotating cutting bodies 110 contribute to maintaining gage in this illustrated embodiment due to the radially interior placement of the fixed blades 142 and cutters 144. When viewed in a rotated view into a single plane, there is substantially no radial overlap (from bit centerline) (as discussed above) between cutters 144 and rotating cutting bodies 110. However, in some embodiments, there is a radial overlap (from bit centerline) between the cutters and rotating cutting bodies.

Rotating cutting bodies 110, as illustrated in FIGS. 8A-B, have a plurality of raised segments azimuthally spaced thereabout extending from a radial end surface 128 through a gage region 126. Unlike the rotating cutting bodies 110 illustrated in FIGS. 4A-B, the rotating cutting bodies 110 of FIGS. 8A-B have diamond impregnated cutting ribs. Different diamond grade particles may be impregnated into the ribs of the rotating cutting bodies, such as natural diamond and/or synthetic diamond, thermally stable polycrystalline diamond, or may include cubic boron nitride, silicon carbide, and/or other super abrasive particles known in the art, and may range in size, for example, from 0.01 to 2.0 mm. It is also noted that the rotating cutting bodies 110 illustrated in FIGS. 8A-B may also be used in any of the above described embodiments of bits having rotating cutting bodies 110 thereon. Further, it is also within the scope of the present disclosure that the bit 110 of FIGS. 8A-B may have any of the rotating cutting bodies illustrated in FIGS. 3A-B, 4A-B, 7A-B and 8A-B in any combination or used alone.

Referring now to FIGS. 9A and 9B, two different perspective views of a drill bit are shown. As shown in FIGS. 9A and 9B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 9A-B, the plurality of rotating cutting bodies 110 each has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft that extends into a bore formed in the face 104 of bit body 102, as described below.

In addition to rotating cutting bodies 110, the plurality of cutting structures further includes conventional roller cones 152 mounted on journals (not shown) that extend downward and radially inward from legs 154 that extend from the bit face 104. Roller cones 152 are illustrated as having milled teeth integral with the cone, but it is also within the scope of the disclosure that roller cones 152 may have inserts press fit into insert holes formed therein.

Rotating cutting bodies 110, as illustrated in FIGS. 9A and 9B, are cylindrical bodied. A plurality of inserts 124 is disposed on both the radial end face 128 and the circumferential side or gage surface 126 of the cylindrical rotating cutting bodies 110. All of the inserts 124 shown as being disposed on the cylindrical rotating cutting bodies are conical inserts, discussed in greater detail below, but it is also within the scope of the present disclosure that other shaped cutting elements may be used. Further, it is also within the scope of the present disclosure that the bit 110 of FIGS. 9A-B may have any of the rotating cutting bodies illustrated in FIGS. 3A-B, 4A-B, 7A-B, 8A-B and 9A-B in any combination or used alone.

Referring now to FIGS. 10A and 10B, two different perspective views of a drill bit are shown. As shown in FIGS. 10A and 10B, drill bit 100 has a bit body 102 having a face 104 at one end thereof and a connection end 106 at the opposite end thereof for securing the drill bit 100 to a drill string (not shown). A plurality of cutting bodies 110 is rotatably attached thereto on a face 104 of bit body 102. In the embodiment shown in FIGS. 10A-B, the plurality of rotating cutting bodies 110 each has an axis substantially parallel (or exactly parallel) to the axes of the other rotating cutting bodies and also substantially parallel (or exactly parallel) to the longitudinal axis of the drill bit; however, it is envisioned that some embodiments may involve rotating cutting bodies attached to the drill bit such that their axes may be skewed with respect to one another. Rotating cutting bodies 110 may be attached to bit body such as by the mechanism described with respect to FIGS. 3A-B or they may include a shaft 156 that extends into a bore 158 formed in the face 104 of bit body 102, as illustrated in FIG. 10B and described in more detail in FIG. 11 below.

In addition to rotating cutting bodies 110, bit 100 shown in FIGS. 10A-B also includes, as a cutting structure, a fixed cutting structure of blades 142 that extend azimuthally from bit body 102. Each blade 142 includes a plurality of cutter pockets in which cutters 144 may be disposed. When viewed in a rotated view into a single plane, there is substantially no radial overlap (from bit centerline) (as discussed above) between cutters 144 and rotating cutting bodies 110.

The rotating cutting bodies 110 shown in this embodiment all include raised segments 130 extending from a radial top surface to a gage side region, but none of the segments 130 have inserts or other cutting elements disposed thereon. Rather, the raised segment 130 itself is intended to engage the formation. Rotating cutting bodies 110 may have spiral segments 130-1 or straight segments 130-2. Further, it is also within the scope of the present disclosure that the bit 110 of FIGS. 10A-B may have any of the rotating cutting bodies illustrated in FIGS. 3A-B, 4A-B, 7A-B, 8A-B, 9A-B, 10A-B in any combination or used alone.

Referring now to FIG. 11, an embodiment of showing the attachment of rotating cutting body 110 to a bit body 102 is shown. FIGS. 23-25 show an exploded view of the rotating cutting bodies 110 attached to the bit body 102, a side perspective view of the bit 100, and a top perspective view of the bit 100, respectively. As shown, rotating cutting body 110 includes a shaft 156 extending axially away from the radial end surface 128, which is exposed to the environment. Shaft 156 resides in bore 158 formed within bit body 102. Shaft 156 (and rotating cutting body 110) is retained in bore 158 by a plurality of retention balls 160 that traverse a ball passage 162 and are kept within a ball race that is formed between shaft 156 and bit body 102 by a ball retainer (not shown).

A bearing sleeve, inlay, or the like (not shown) may be disposed in a bearing sleeve housing 164 formed between radial bearing surfaces 166, 168 of shaft 156 and bit body 102. A thrust bearing (not shown) may be disposed in a thrust bearing housing 170 formed between axial bearing surfaces 172, 174 of shaft 156 and bit body 102. A grease reservoir 176 may provide a lubricant or grease to the bearing surfaces. A first seal gland 178 is formed between the shaft 156 of the rotating cutting body 110 and the bit body 102 proximal the face 104 of the bit body 102 and a seal is disposed within the seal gland to keep circulating well fluids away from the bearing surfaces between shaft 156 and bit body 102 and to retain the lubricant or grease within the bearing housings.

Some embodiments may provide for drilling fluid to be pumped through the rotating cutting bodies 110 and out openings on rotating cutting bodies provided on the surface thereof. In such a case, the end of shaft 156 may include an opening 182 into a conduit extending through shaft 156 through which the fluids may flow. Fluid is delivered to opening from fluid plenum (not shown) through fluid passageway 184 formed in bit body 102. In such a case where wellbore fluid is provided to an opening 182 in shaft 156, a second seal gland 180 (and accompanying seal) may seal the bearing surfaces to keep lubricant within and wellbore fluids away from the bearing housings. One of ordinary skill in the art would appreciate that some variations on the bearing structures and retention mechanisms may be present and still be within the scope of the present disclosure. Further, as mentioned above, a rotating cutting body 110 having a shaft 156 that is retained within a bore 158 formed within bit body may be used in any of the above-described bits. It is also within the scope of the present disclosure that openings (and corresponding hydraulic components) may be included on the bit body, as known to those of ordinary skill in the art.

FIG. 15 shows a drill bit according to embodiments of the present disclosure having a mechanical seal assembly 200 between a rotating cutting body 110 and a bit body 102. The rotating cutting body 110 includes a shaft 156 extending axially away from the radial end surface 128 of the rotating cutting body 110. The shaft 156 resides in bore 158 formed within the bit body 102 and is retained in the bore 158 by a plurality of retention balls 160. A bearing sleeve 165 is disposed in a bearing sleeve housing formed between the radial bearing surfaces 166, 168 of the shaft 156 and bit body 102. A thrust bearing 175 is disposed in a thrust bearing housing formed between axial bearing surfaces 172, 174 of the shaft 156 and bit body 102. A grease reservoir 176 may provide a lubricant or grease to the bearing surfaces, and a pressure compensation subassembly may be used to balance the pressure between the exterior well bore fluid and the lubricant provided by the grease reservoir. The mechanical seal assembly 200 may be positioned between the shaft 156 of the rotating cutting body 110 and the bit body 102 proximal the face 104 of the bit body 102.

A mechanical seal assembly 200 according to some embodiments of the present disclosure is shown assembled within a drill bit in FIG. 16A and in a detailed view in FIG. 16B. As shown in FIG. 16A, the mechanical seal assembly 200 is disposed between a rotating cutting body 110 and the bit body 102 proximal the face 104 of the bit body 102. As shown in FIG. 16B, the mechanical seal assembly 200 includes two sealing rings 202, 204 and an elastomer energizer 206. Particularly, a first sealing ring 204 is proximate to the cutting body 110, an elastomer energizer 206 is proximate to the bit body 102 and a second sealing ring 202 is disposed between the first sealing ring 204 and the elastomer energizer 206. The elastomer energizer 206 may urge the first and second sealing rings 204, 202 in contact with each other to maintain a good dynamic sealing surface. As shown, the first sealing ring 204 contacts the second sealing ring 202 at an interface surface 203.

According to some embodiments, the cross-sectional width of the contact area between the first sealing ring 204 and the second sealing ring 202 may be less than 0.4 inches. For example, in some embodiments, the width of the contact area may be selected from a width ranging between 0.1 and 0.3 inches. The geometry of the interfacing surfaces of the first and second sealing rings may be altered to reduce the contact area there between. For example, as shown in FIG. 16B, the edges of interfacing surface of the first sealing ring 204 may be chamfered 205 to reduce the contact area with the interfacing surface of the second sealing ring 202. Advantageously, a low contact area between the two sealing rings may reduce the amount of friction between the two sealing rings as they rotate in relation to each other. Further, a channel 208 may be formed between the rotating cutting body 110 and the bit body 102 that extends to the mechanical sealing assembly 200 so that lubricant provided by a grease reservoir may reach the contact area, which may help to reduce friction at the interface 203 between the first sealing ring 204 and second sealing ring 202.

The elastomer energizer 206 may be used to prevent relative movement between the second sealing ring 202 and the elastomer energizer 205. According to some embodiments, an o-ring 209 may also be disposed between the second sealing ring 202 and the bit body 102, adjacent to the elastomer energizer 206, which may help to prevent rotation of the second sealing ring 202 in relation to the elastomer energizer 205. Thus, in embodiments with an elastomer energizer and an o-ring providing a substantially stationary second sealing ring 202, the first sealing ring 204 may rotate in conjunction with the rotating cutting body along the interface surface 203 between the first and second sealing rings, thereby forming a dynamic seal between the rotating cutting body 110 and the bit body 102. It should be noted that although the above description and corresponding figures show two distinct sealing rings (a first sealing ring 204 and a second sealing ring 202), a mechanical sealing assembly of the present disclosure may have only one distinct sealing ring (i.e., a sealing ring forming a distinct, separate part of the sealing assembly). For example, according to some embodiments, the first sealing ring 204 may be formed integrally with the rotating cutting body 110, while the second sealing ring 202 is a separate part, disposed between the first sealing ring 204 and elastomer energizer 206.

Another example of a mechanical sealing assembly 200 according to embodiments of the present disclosure is shown in FIG. 17A, assembled within a drill bit, and in FIG. 17B, in a detailed view. As shown in FIG. 17A, the mechanical seal assembly 200 is disposed between a rotating cutting body 110 and the bit body 102 proximal the face 104 of the bit body 102. As shown in FIG. 17B, the mechanical seal assembly 200 includes two sealing rings 202, 204 and an elastomer energizer 206 and does not include an o-ring. Particularly, a first sealing ring 204 is proximate to the cutting body 110, and disposed within a receiving groove 201 formed in the cutting body 110. An elastomer energizer 206 is disposed adjacent to the bit body 102, and a second sealing ring 202 is disposed between the first sealing ring 204 and the elastomer energizer 206. The elastomer energizer 206 may urge the first and second sealing rings 204, 202 in contact with each other to maintain a good dynamic sealing surface. As shown, the first sealing ring 204 contacts the second sealing ring 202 at an interface surface 203. Additionally, the first sealing ring 204 may be integrally formed with the rotating cutting body 110, or may be a separate and distinct part.

Elastomer energizers according to embodiments disclosed herein may comprise a fluoroelastomer, perfluoroelastomer, highly saturated nitrile, or a combination thereof. Sealing rings according to embodiments disclosed herein may comprise metal alloys and/or super hard materials known in the art. For example, one or more sealing rings may comprise tungsten carbide, silicon carbide, polycrystalline diamond or combinations thereof. Further, according to some embodiments, at least one of the first sealing ring and the second sealing ring may have a diamond coating there between.

Advantageously, because the wear resistance of the material forming the sealing rings is much higher than that of conventionally used elastomer seals, the mechanical seal assembly disclosed herein is particularly useful for roller drill bits in normal or high rotation (rpm) applications. For example, conventional roller bit design uses o-rings/elastomers to prevent lubricant from escaping from around the bearing surfaces and to prevent the abrasive drilling fluid from entering between the roller cone and journal and damaging the bearing surfaces. Each individual rolling cone or cutter of a roller drill bit may rotate at about three times the rotation speed of the bit body. Thus, the wear resistance of the o-ring/elastomer seals will limit the performance of a roller bit during normal and high speed applications. However, mechanical seal assemblies of the present disclosure use metal and/or super hard material sealing rings to provide a dynamic seal, while an elastomer energizer ring supports the sealing rings into contact rather than providing the seal. Thus, while conventionally used elastomer seals for lubrication systems in roller drill bits are prone to failure during high rpm applications, the mechanical seal assembly disclosed herein may be used in normal speed rpm applications as well as high speed rpm applications, such as 1,000 rpm or greater.

The above descriptions of sealing assemblies have been directed to sealed bearing and lubrication systems. However, according to other embodiments of the present disclosure, an open bearing system may be used. Referring to FIG. 18, an exploded view of a drill bit 100 having an open bearing system (a bearing system without the use of a seal) is shown. The bit 100 has a plurality of rotating cutting bodies 110 attached to the bit body 102, wherein a rotating cutting body 110 includes a shaft 156 extending axially away from the radial end surface 128, which is exposed to the environment. The shaft 156 resides in bore 158 formed within bit body 102. Shaft 156 (and rotating cutting body 110) is retained in bore 158 by a plurality of retention balls 160 that traverse a ball passage and are kept within a ball race that is formed between shaft 156 and bit body 102 by a ball retainer (not shown). Retention balls may be made of, for example, steel, ceramics and hard materials such as carbides. For example, retention balls may be coated with a wear resistant material or may be carburized. Further, retention balls, such as shown in FIGS. 11, 15 and 18, may be used to retain any of the rotating cutting bodies disclosed herein.

The open bearing system includes a radial bearing surface 310 extending around the circumference of the shaft 156 of the rotating cutting body 110 and a bearing sleeve 320 disposed around the radial bearing surface 310. Bearing sleeves may be disposed in a bearing sleeve housing formed between the radial bearing surface 310 of shaft 156 and bit body 102. The open bearing system also includes a thrust bearing 330 disposed in a thrust bearing housing formed between axial bearing surfaces 172, 174 of shaft 156 and bit body 102, wherein the thrust bearing comprises at least two bearing rings 332, 334. As shown, a plurality of wear buttons 340 may be disposed between the two bearing rings 332, 334. However, according to other embodiments, such as described below, other wear surfaces may be provided between the two bearing rings. In a thrust bearing having two bearing rings 332, 334, the bearing ring 332 adjacent to the shaft 156 may rotate with the shaft 156, while the bearing ring 334 adjacent to the bit body 102 may not move relative to the shaft 156. Thus, the two bearing rings 332, 334 rotate relative to each other at an interface therebetween. In thrust bearings having two bearing rings and wear buttons 340 or a wear ring (described below) disposed between the two bearing rings 332, 334, the rotation occurs between the wear buttons or wear ring.

Referring now to FIGS. 19A-19C, various embodiments of a radial bearing surface 310 extending around the circumference of the shaft 156 of a rotating cutting body 110 are shown. Radial bearing surfaces 310 according to embodiments of the present disclosure may include wear buttons 340 having various shapes and sizes. For example, as shown in FIG. 19A, a plurality of circular wear buttons 340 may be disposed in equally spaced apart rows around the shaft 156 of a rotating cutting body 110 to form the radial bearing surface 310. In FIG. 19B, a plurality of columnar wear buttons 340 are equally spaced apart around the shaft 156 of a rotating cutting body 110 to form the radial bearing surface 310. In FIG. 19C, a mixture of circular and columnar wear buttons 340 are spaced around the shaft 156 of a rotating cutting body 110 to form the radial bearing surface 310. However, other shapes and sizes of wear buttons may be used to form the radial bearing surface. Additionally, wear buttons may be equally or unequally spaced around the shaft of a rotating cutting body. Further, as shown in FIGS. 19A-19C, wear buttons 340 may be disposed within the surface of the shaft 156 such that the wear buttons are flush with the surface of the shaft 156 to form a substantially smooth radial bearing surface 310. Alternatively, wear buttons may be disposed around the circumference of a shaft such that the wear buttons protrude from the surface of the shaft, thereby forming an uneven radial bearing surface.

Referring now to FIGS. 20A and 20B, bearing sleeves 320 according to embodiments of the present disclosure are shown. As shown in FIG. 20A, a bearing sleeve may be made entirely of or be coated with a wear resistant material. Wear resistant material may include, for example, borides, nitrides, carbides, such as tungsten carbide and silicon carbide, and polycrystalline diamond, or combinations thereof. According to other embodiments, as shown in FIG. 20B, a bearing sleeve may have wear buttons 340, as described above, disposed on the inner surface 321 of the bearing sleeve 320. The wear buttons 340 may be equally spaced around the inner surface of the bearing sleeve 320. Further, the bearing sleeve may have a wear resistant material or a steel base and wear buttons made of carbides, such as tungsten carbide and silicon carbide, nitrides, borides, and/or diamond. Examples of carbide material that may be used in bearing sleeves according to embodiments of the present disclosure include coarse grain carbide, such as carbides having an average grain size ranging from 6 to 12 microns and a binder content ranging from 5% to 30%. According to some embodiments, bearing sleeves may also comprise diamond, such as polycrystalline diamond or a diamond composite, for example a diamond and silicon carbide composite or a diamond and tungsten carbide composite, as known in the art.

Referring now to FIGS. 21A-21D, bearing rings 334 used in thrust bearings according to several embodiments of the present disclosure are shown. As shown in FIG. 21A, a bearing ring 334 used to form one or more of the bearing rings in a thrust bearing may be made entirely of a wear resistant material or may be made of a steel base coated with a wear resistant material or carburized. For example, the bearing ring 334 may be made of a carbide material, such as tungsten carbide or silicon carbide, or a carbide material having a diamond coating thereon. Other wear resistant materials that may be used to form bearing rings of a thrust bearing are described above with respect to the bearing sleeves. In some embodiments, as shown in FIG. 21B, a bearing ring 334 may have wear buttons 340 disposed thereon. Wear buttons 340 may be made of a wear resistant material, as described above, such a carbide material, for example tungsten carbide or silicon carbide, or a diamond material, such as polycrystalline diamond or a diamond/carbide composite. The wear buttons 340 may be equally spaced around the surface that interfaces with a second bearing ring (not shown). However, according to some embodiments of the present disclosure, a thrust bearing may be made of three bearing rings, wherein one of the bearing rings is a wear ring disposed between the other two bearing rings. For example, as shown in FIGS. 21C and 21D, a wear ring 341 is disposed on a bearing ring 334 used in a thrust bearing assembly. The wear ring 341 may comprise a wear resistant material, such as that used for wear buttons. Further, the wear ring 341 may have a uniform height, as shown in FIG. 21C. Alternatively, as shown in FIG. 21D, a wear ring 341 may have channels 342 formed therein, extending radially from an inner surface 331 to an outer surface 333. When the wear ring 341 having channels 342 formed therein is disposed between two bearing rings 334 to form a thrust bearing, the channels 342 may provide a flow passage for lubricant to flow through, which may cool the thrust bearing components.

Referring now to FIG. 22, various shapes and sizes of wear buttons 340 according to some embodiments of the present disclosure are shown. For example, wear buttons 340 may be columnar, rectangular, triangular, circular, or have a polygon shape, such as a hexagon. However, the shapes other than the ones shown in FIG. 22 may be used to form wear buttons 340. As discussed above, wear buttons 340 may be used along bearing surfaces in an open bearing system, such as on a radial bearing surface of a rotating cutting body shaft, a bearing sleeve, and between bearing rings of a thrust bearing.

Drill bits according to some embodiments of the present disclosure having rotating cutting bodies positioned substantially (or exactly) parallel with the rotational axis of the bit body may rotate about two to three times faster than cutting bodies positioned at an angle relative to the rotational axis of the bit body (such as conventional roller cones mounted to a journal extending from a bit leg). Accordingly, by providing such bits with bearing systems disclosed herein (such as a mechanical seal assembly or an open bearing system described above) that can withstand high rpm applications, the bits may have a longer drill life.

Many embodiments discussed above mention conical inserts 124 and 136. As shown in FIG. 12, such inserts may possess a diamond layer 184 on a substrate 186 (such as a cemented tungsten carbide substrate), where the diamond layer 184 forms a conical diamond working surface. Specifically, the conical geometry may comprise a side wall that tangentially joins the curvature of the apex. Conical cutting elements 124, 136 may be formed in a process similar to that used in forming diamond enhanced inserts (used in roller cone bits) or may brazing of components together. The interface (not shown separately) between diamond layer 184 and substrate 186 may be non-planar or non-uniform, for example, to aid in reducing incidents of delamination of the diamond layer 184 from substrate 186 when in operation and to improve the strength and impact resistance of the element. One skilled in the art would appreciate that the interface may include one or more convex or concave portions, as known in the art of non-planar interfaces. Additionally, one skilled in the art would appreciate that use of some non-planar interfaces may allow for greater thickness in the diamond layer in the tip region of the layer. Further, it may be desirable to create the interface geometry such that the diamond layer is thickest at a critical zone that encompasses the primary contact zone between the diamond enhanced element and the formation. Additional shapes and interfaces that may be used for the diamond enhanced elements of the present disclosure include those described in U.S. Patent Publication Nos. 2008/0035380, 2008/0314647, 2010/0089648, which are herein incorporated by reference in their entirety. Further, the diamond layer 184 may be formed from any polycrystalline superabrasive material, including, for example, polycrystalline diamond, polycrystalline cubic boron nitride, thermally stable polycrystalline diamond (formed either by treatment of polycrystalline diamond formed from a metal such as cobalt or polycrystalline diamond formed with a metal having a lower coefficient of thermal expansion than cobalt).

As mentioned above, the apex of the conical cutting element may have curvature, including a radius of curvature R, as shown in FIG. 12. In an embodiment, the radius of curvature may range from about 0.010 to 0.180 inches or from about 0.040 to 0.120 inches. Some embodiments may have a radius of curvature ranging from a lower limit of any of 0.01, 0.02, 0.04, 0.06, 0.08, and 0.10 to an upper limit of any of 0.08, 0.10, 0.12, 0.014, 0.016, and 0.018. In some embodiments, the curvature may comprise a variable radius of curvature, a portion of a parabola, a portion of a hyperbola, a portion of a catenary, or a parametric spline. Further, referring to FIG. 12, the cone angle α of the conical end may vary, and be selected based on the particular formation to be drilled. In an embodiment, the cone angle α may range from about 30 to about 120 degrees or from about 60 to about 90 degrees. Some embodiments may have a cone angle α ranging from a lower limit of any of 30, 40, 50, 60, 70 and 80 degrees to an upper limit of any of 60, 80, 70, 90, 100 and 120 degrees.

Additionally, the conical cutting elements may be characterized as having both a conical portion (extension portion) and a cylindrical portion (grip portion). The relative extension height of the conical portion may be expressed as a ratio of the height of the conical portion H0 to the total height H of the insert (conical and cylindrical portions). In an embodiment, H0/H may range from about 0.1 to about 0.7 or from 0.2 to 0.5. Some embodiments may have a H0/H ratio ranging from a lower limit of any of 0.1, 0.2, 0.3, 0.4 and 0.5 to an upper limit of any of 0.3 0.4, 0.5, 0.6 and 0.7. The outer diameter of the conical inserts may range from about 0.1 to about 1.25 inches or from about 0.25 to about 0.875 inches.

As mentioned above, the diamond layer 184 may be formed from polycrystalline diamond (PCD) in which PCD comprises a polycrystalline mass of diamonds (typically synthetic) that are bonded together (through the use of a catalyst) to form an integral, tough, high-strength mass or lattice. The resulting PCD structure produces enhanced properties of wear resistance and hardness, making PCD materials extremely useful in aggressive wear and cutting applications where high levels of wear resistance and hardness are desired. Catalyst contents used in forming the PCD of the conical inserts may range from 2 to 35 weight percent (premixed or infiltrated from a substrate or a combination thereof) with PCD grain sizes ranging from 0.2 to 50 microns. The thickness of the PCD layer may generally range from about 0.012 to about 0.400 inches. Further, transition layers such as those used in diamond enhanced inserts may be used with different combinations of metal, diamond and metal carbides.

Substrate 186 may be formed from a suitable material such as tungsten carbide, tantalum carbide or titanium carbide. Additionally, various binding metals may be included in the substrate, such as cobalt, nickel, iron, metal alloys or mixtures thereof. In the substrate, the metal carbide grains are supported within the metallic binder, such as cobalt. Cobalt (or other metals) in the substrate may range from about 2 to 35 weight percent, and the average carbide grain size may generally range from about 0.2 to 35 microns.

Various embodiments disclosed above referred to the use of cutters 144 on blades 142. Cutters 144 as referred to herein include a compact of polycrystalline diamond (PCD) (or other ultrahard material) bonded to a substrate material, which is typically a sintered metal-carbide. A PDC cutter is conventionally formed by placing a sintered carbide substrate into the container of a press. A mixture of diamond grains or diamond grains and catalyst binder is placed atop the substrate and treated under high pressure, high temperature conditions. In doing so, metal binder (often cobalt) migrates from the substrate and passes through the diamond grains to promote intergrowth between the diamond grains. As a result, the diamond grains become bonded to each other to form the diamond layer, and the diamond layer is in turn integrally bonded to the substrate. The substrate often comprises a metal-carbide composite material, such as tungsten carbide-cobalt. The deposited diamond layer is often referred to as the “diamond table,” “abrasive layer,” or “ultrahard layer.”

Materials that may be used to form the “ultrahard layer” may include a conventional polycrystalline diamond table (a table of interconnected diamond particles having interstitial spaces therebetween in which a metal component (such as a metal catalyst) may reside, a thermally stable diamond layer (i.e., having a thermal stability greater than that of conventional polycrystalline diamond, 750° C.) formed, for example, by removing substantially all metal from the interstitial spaces between interconnected diamond particles or from a diamond/silicon carbide composite, or other ultra hard material such as a cubic boron nitride.

The substrate on which the cutting face is disposed may be formed of a variety of hard or ultra hard particles. In one embodiment, the substrate may be formed from a suitable material such as tungsten carbide, tantalum carbide or titanium carbide. Additionally, various binding metals may be included in the substrate, such as cobalt, nickel, iron, metal alloys or mixtures thereof. In the substrate, the metal carbide grains are supported within the metallic binder, such as cobalt. Additionally, the substrate may be formed of a sintered tungsten carbide composite structure. It is well known that various metal carbide compositions and binders may be used, in addition to tungsten carbide and cobalt. Thus, references to the use of tungsten carbide and cobalt are for illustrative purposes only, and no limitation on the type substrate or binder used is intended.

Referring now to FIGS. 13A-B, an embodiment of a faceted insert 1242 is shown. As shown in FIGS. 13A-B, insert 1242 has a grip region 190 and an extension portion 192. Grip region 190 is substantially cylindrical and extends into a hole formed in a rotating cutting body (not shown) and may be retained therein by interference fit. Extension portion 192 includes a substantially flat wear surface 194 and a plurality of facets 196 extending between the wear surface 194 and the cylindrical grip region 190. As shown in FIGS. 13A-B, wear surface 194 is a quadrilateral and thus four facets 196 extend between wear surface 194 and grip region 190; however, the present disclosure is not so limited. Rather, it is also within the scope of the present disclosure that the wear surface 194 may have three or more than four sides with the corresponding number of facets extending therefrom. Further, as shown in FIGS. 13A-B, wear surface 194 may be slanted (not perpendicular with respect to an insert axis) from a peak 198, which may include a point or an edge, depending on the orientation of the wear surface 194. Additionally, it is also within the scope of the present disclosure that the inserts described in U.S. Pat. No. 7,743,855, which is assigned to the present assignee and herein incorporated by reference in its entirety, may be used on the gage region of a rotating cutting body, in place of the faceted insert 1242 shown in FIGS. 13A-B.

Referring now to FIG. 14, an example cutting trajectory of a conical insert located on a rotating cutting body is shown in terms of kinematic motion analysis. The trajectory shown in FIG. 14 is for a single conical insert located on a rotating cutting body that rotates at a rotation ratio of 1:3.5 (entire bit:rotating cutting body). The trajectory indicates that the conical insert cuts the formation continuously at the bottom of a hole along an unconventional path on a projected plane. In contrast, a cutter fixed on a blade will rotate along a fixed circular path. Varying the rotation ratio may allow for variance in the trajectory of each insert with low tracking to alter ROP or other drilling variables.

Drill bits disclosed herein may be rotated using turbine assemblies, which are attached to and rotate the drill string and connected drill bit. Turbine assemblies used in combination with drill bits of the present disclosure may include, for example, impulse or reaction type turbines, and may include turbine blades rigidly attached (directly or indirectly) to the drill string. Drilling fluid may be pumped into the borehole and through the turbine assembly to provide rotational power. Turbine assemblies that may be used to rotate drill bits of the present disclosure may be found, for example, in U.S. Pat. Nos. 7,204,326, 7,730,972 and 7,967,083 and U.S. Patent Publication No. 2010/0314172, which are incorporated herein by reference. For example, in some embodiments, a turbine assembly may be placed in the drill string, wherein the turbine assembly includes a stator and a rotor. The rotor may include a plurality of blades or vanes that are rotated as drilling fluid flows past the blades. The stator may include a plurality of flow channels that direct the drilling fluid in a certain direction in relation to the rotor blades. The shape and size of the flow channels may be designed to impart a particular fluid flow velocity and direction, thus resulting in a particular velocity of the turbine rotor and ultimately the rotation velocity of the drill bit. In some embodiments, the stator may have fixed flow channels that remain stationary relative to the rotor. In other embodiments, such as described in U.S. Pat. No. 7,730,972, the flow channels may be movable, and thus capable of changing the engagement angle of the fluid flowing through the borehole with the rotor blades of the turbine.

Embodiments of the present disclosure may provide at least one of the following advantages. The bits of the present disclosure may provide for a new cutting mechanism that can be used alone or in combination with conventional cutting mechanisms used in drill bits. The incorporation of new rotatable or rolling structures may provide for a change in the mechanism of rock removal, which can have an effect on rate of penetration as well as durability.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A drill bit, comprising:

a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and
a plurality of cutting structures comprising: at least one fixed cutting structure disposed on the bit body face; and at least one cutting body rotatably attached to the face of the bit body;
wherein, in a rotated view of the plurality of cutting structures into a single plane, there is substantially no radial overlap between at least one fixed cutting structure and the at least one cutting body.

2. The drill bit of claim 1, wherein the at least one fixed cutting structure comprises at least one blade extending azimuthally from the bit body, the at least one blade having a plurality of cutters thereon.

3. The drill bit of claim 1, wherein the at least one fixed cutting structure comprises a raised body extending from the face, the raised body having a plurality of blades extending azimuthally therefrom, the plurality of blades having a plurality of cutters thereon.

4. The drill bit of claim 1, wherein the at least one fixed cutting structure comprises a cutting element inserted into an insert hole formed in the bit body.

5. The drill bit of claim 1, wherein the plurality of cutting structures comprise a plurality of the cutting bodies, wherein each of the plurality of cutting bodies have a substantially parallel axis of rotation.

6. The drill bit of claim 1, wherein the at least one cutting body comprises a plurality of raised segments azimuthally spaced about the at least one cutting body.

7. The drill bit of claim 1, wherein the at least one cutting body comprises a plurality of cutting elements thereon.

8. The drill bit of claim 1, wherein the cutting surface of the at least one fixed cutting structure has an axial overlap with the cutting surface of the at least one cutting body.

9. The drill bit of claim 1, wherein the bottommost extent of the at least one cutting body is located axially above the bottommost extent of the at least one fixed cutting structure.

10. The drill bit of claim 1, wherein the at least one cutting body comprises a shaft that extends into the bore formed in the face of the bit body.

11. The drill bit of claim 1, wherein a turbine assembly is connected to the drill string.

12. A drill bit, comprising:

a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and
a plurality of cutting structures comprising: a plurality of cutting bodies rotatably attached to the face of the bit body, wherein each of the plurality of cutting bodies have a substantially parallel axis of rotation and have axially overlapping cutting surfaces; and
wherein the bit body has no blades extending azimuthally therefrom.

13. The drill bit of claim 12, further comprising:

at least one leg extending from a face of the bit body and having a journal formed thereon; and
wherein the plurality of cutting structures further comprises at least one roller cone rotatably mounted on the journal.

14. The drill bit of claim 12, wherein the plurality of cutting structures consist of the plurality of cutting bodies.

15. The drill bit of claim 12, wherein the plurality of cutting structures further comprises a cutting element inserted into an insert hole formed in the bit body.

16. The drill bit of claim 12, wherein the plurality of rotating cutting bodies comprises a cylindrical body.

17. The drill bit of claim 16, wherein the cylindrical body comprises cutting elements disposed circumferentially around the cylindrical body.

18. The drill bit of claim 16, wherein the cylindrical body comprises cutting elements disposed on the planar surface thereof.

19. The drill bit of claim 12, wherein a turbine assembly is connected to the drill string.

20. A drill bit, comprising:

a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end; and
at least one cutting structure comprising: at least one cutting body rotatably attached to the face of the bit body, wherein the at least one cutting body comprises a plurality of raised segments aximuthally spaced about the at least one cutting body.

21. The drill bit of claim 20, wherein the at least one cutting structure further comprises at least one blade extending azimuthally from the bit body, the at least one blade having a plurality of cutters thereon.

22. The drill bit of claim 21, wherein, in a rotated view of the plurality of cutting structures into a single plane, there is radial overlap between the cutters at least one blade and the at least one cutting body.

23. The drill bit of claim 20, wherein the at least one fixed cutting structure comprises a raised body extending from the face, the raised body having a plurality of blades extending azimuthally therefrom, the plurality of blades having a plurality of cutters thereon.

24. The drill bit of claim 20, wherein the at least one fixed cutting structure comprises a cutting element inserted into an insert hole formed in the bit body.

25. The drill bit of claim 20, wherein the plurality of cutting structures comprise a plurality of the cutting bodies, wherein each of the plurality of cutting bodies have a substantially parallel axis of rotation.

26. A drill bit, comprising:

a bit body rotatable about a longitudinal axis and having, at one end, a connection for securing the drill bit to a drill string and having a face opposite the connection end, wherein the face comprises at least one bore formed therein; and
at least one cutting structure comprising: at least one cutting body rotatably attached to the face of the bit body, wherein the at least one cutting body comprises an exposed end and a shaft that extends into the bore formed in the face of the bit body.

27. The drill bit of claim 26, wherein the at least one cutting body has an opening formed on the surface thereof, the opening fluidly connected to a conduit extending through the exposed end and the shaft for channeling a fluid from a fluid plenum to outside the bit.

28. The drill bit of claim 26, wherein the drill bit further comprises:

a first seal gland formed between the shaft of the at least one cutting body and the bit body proximal the face of the bit body; and
a first seal disposed in the first seal gland.

29. The drill bit of claim 26, wherein the drill bit further comprises:

a second seal gland formed between the shaft of the at least one cutting body and the bit body proximal the end of the shaft; and
a second seal disposed in the second seal gland.

30. The drill bit of claim 26, further comprising:

a bearing sleeve disposed in a bearing sleeve housing formed between radial surfaces of the shaft and the bit body.

31. The drill bit of claim 26, further comprising:

a thrust bearing disposed in a thrust bearing housing formed between axial surface of the shaft and the bit body.

32. The drill bit of claim 26, further comprising:

a plurality of retention balls disposed in a ball race formed between the shaft and the bit body.

33. The drill bit of claim 26, further comprising:

a first seal gland formed between the shaft of the at least one cutting body and the bit body proximal the face of the bit body;
a first seal disposed in the first seal gland;
a bearing sleeve disposed in a bearing sleeve housing formed between radial bearing surfaces of the shaft and the bit body and axially adjacent the first seal gland;
a thrust bearing disposed in a thrust bearing housing formed between axial bearing surfaces of the shaft and the bit body and axially adjacent the bearing sleeve;
a lubricant reservoir in fluid connection with the bearing surfaces;
a plurality of retention balls disposed in a ball race formed between the shaft and the bit body and axially adjacent the thrust bearing;
a second seal gland formed between the shaft of the at least one cutting body and the bit body proximal the end of the shaft;
a second seal disposed in the second seal gland;
wherein the at least one cutting body has an opening formed on the surface thereof, the opening fluidly connected to a conduit extending through the exposed end and the shaft for channeling a fluid from a fluid plenum to outside the bit, and wherein the second seal seals the bearing surfaces from the fluid.

34. The drill bit of claim 26, further comprising a mechanical seal assembly disposed between the cutting body and the bit body, proximal to the face of the bit body, wherein the mechanical seal assembly comprises:

a first sealing ring proximate to the cutting body;
an elastomer energizer proximate to the bit body; and
a second sealing ring disposed between the first sealing ring and the elastomer energizer.

35. The drill bit of claim 34, wherein the first sealing ring contacts the second sealing ring at an interface surface having a width of less than 0.4 inches.

36. The drill bit of claim 34, wherein the elastomer energizer comprises a fluoroelastomer, perfluoroelastomer, highly saturated nitrile, or a combination thereof.

37. The drill bit of claim 34, wherein the first sealing ring is integral with the cutting body.

38. The drill bit of claim 34, wherein at least one of the first sealing ring and the second sealing ring has a diamond coating there between.

39. The drill bit of claim 34, further comprising an o-ring disposed between the second sealing ring and the bit body, adjacent to the elastomer energizer.

40. The drill bit of claim 26, further comprising an open bearing system, wherein the open bearing system comprises:

a radial bearing surface extending around the circumference of the shaft;
a bearing sleeve disposed around the axial bearing surface;
a thrust bearing disposed between the shaft and the base of the bore, wherein the thrust bearing comprises at least two bearing rings.

41. The drill bit of claim 40, wherein at least one of the radial bearing surface, the bearing sleeve and the thrust bearing comprises wear buttons.

42. The drill bit of claim 40, wherein the bearing sleeve comprises at least one of tungsten carbide, silicon carbide and polycrystalline diamond.

43. The drill bit of claim 40, wherein the thrust bearing comprises three bearing rings and wherein one of the bearing rings is a wear ring disposed between the other two bearing rings.

44. The drill bit of claim 40, wherein wear buttons are disposed between two bearing rings of the thrust bearing.

45. The drill bit of claim 26, wherein a turbine assembly is connected to the drill string.

Patent History
Publication number: 20130098688
Type: Application
Filed: Oct 15, 2012
Publication Date: Apr 25, 2013
Applicant: SMITH INTERNATIONAL, INC. (HOUSTON, TX)
Inventor: Smith International, Inc. (Houston, TX)
Application Number: 13/651,947