DRILL BITS HAVING ROTATING CUTTING STRUCTURES THEREON
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.
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.
BACKGROUNDHistorically, 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 BitsDrag 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
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 BitsRoller 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
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.
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.
SUMMARYThis 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.
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
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
As shown in
Referring now to
Rotating cutting bodies 110 shown in
Referring now to
In addition to rotating cutting bodies 110, bit 100 shown in
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
Further, while the rotating cutting bodies illustrated in
Referring now to
In addition to rotating cutting bodies 110, bit 100 shown in
Referring now to
In addition to rotating cutting bodies 110, bit 100 shown in
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
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
In addition to rotating cutting bodies 110, bit 100 shown in
Rotating cutting bodies 110, as illustrated in
Referring now to
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
Referring now to
In addition to rotating cutting bodies 110, bit 100 shown in
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
Referring now to
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.
A mechanical seal assembly 200 according to some embodiments of the present disclosure is shown assembled within a drill bit in
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
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
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
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
Referring now to
Referring now to
Referring now to
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
As mentioned above, the apex of the conical cutting element may have curvature, including a radius of curvature R, as shown in
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
Referring now to
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.
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
International Classification: E21B 10/08 (20060101); E21B 10/22 (20060101); E21B 10/18 (20060101);