Fixed Cutter Bit With Centrally Positioned Backup Cutter Elements
A drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density, and wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
Latest Smith International, Inc. Patents:
Not Applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot Applicable.
BACKGROUND1. Field of the Invention
The invention relates generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to drag bits and to an improved cutting structure for such bits. Still more particularly, the present invention relates to drag bits with backup cutters on primary blades,
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Two predominate types of rock bits are roller cone bits and fixed cutter (or rotary drag) bits. Some fixed cutter bit designs include primary blades, secondary blades, and sometimes even tertiary blades, spaced about the bit face, where the primary blades are generally longer and start at locations closer to the bit's rotating axis. The blades project radially outward from the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter layouts cut the various strata with differing results and effectiveness.
The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PDC”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. A cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PDC bit” or “PDC cutting element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may reduce or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to re-cut the same materials, thus reducing cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the hole are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall. Further, the fluid removes heat, caused by contact with the formation, from the cutting elements in order to prolong cutting element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may significantly impact the performance of the drill bit.
Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP.
Some conventional fixed cutter bits employ three, four, or more relatively long primary blades that may extend to locations proximal the bit's rotating axis (e.g., into the cone region of the bit). In addition, these primary blades typically support a plurality of cutter elements. In particular, since primary blades often extend to locations proximal the bit's rotating axis, primary blades often support the cutter elements in the innermost central region of the bit. However, for some fixed cutter bits, the presence of a greater number of primary blades may result in a lower ROP. Thus, it may be desirable to decrease the number of relatively long primary blades on a drag bit. In addition, the greater the number of relatively long primary blades provided on the bit, the less space is available for the placement of drilling fluid nozzles. Space limitations may result in the placement of fluid nozzles in less desirable locations about the bit. Compromised nozzle placement may also detrimentally impact fluid hydraulic performance, bit ROP, and bit durability. Still further, space limitations for fluid nozzles may result in more complex bit designs necessary to accommodate drilling fluid channels and nozzles. The increased complexity in the design and manufacture of the bit may increase bit costs.
Accordingly, there remains a need in the art for a fixed cutter bit and cutting structure capable of enhanced ROP and greater bit life, while minimizing other detrimental effects.
BRIEF SUMMARY OF PREFERRED EMBODIMENTSThese and other needs in the art are addressed in one embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density, and wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body with a central axis and an outer radius, in addition, the bit comprises a bit face comprising an inner region extending from the central axis to no more than 50% of the outer radius, and an outer region between the inner region and the outer radius. Further, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade extends from proximal the central axis into the outer region. Still further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade. Moreover, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade, wherein the at least one primary blade has an inner back-up cutter area and an outer backup cutter area, and wherein the inner backup cutter area is greater than the outer backup cutter area.
Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade begins substantially proximal the central axis and extends towards the gage region. Further, the bit comprises at least one secondary blade disposed on the bit face, wherein the at least one secondary blade begins at a radial distance “D” from the central axis and extends toward the gage region, the radial distance “D” being a radius defining the cone region. Still further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade, wherein the primary cutter elements are disposed in a first row extending along the at least one primary blade from substantially proximal the central axis toward the gage region. Moreover, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade, wherein the backup cutter elements are disposed in a second row extending along the at least one primary blade within the cone region.
These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region. In addition, the bit comprises at least one primary blade disposed on the bit face, wherein the at least one primary blade begins proximal the central axis and extends toward the gage region. Further, the bit comprises a plurality of primary cutter elements mounted on the at least one primary blade in the cone region. Still further, the bit comprises a plurality of backup cutter elements mounted on the at least one primary blade in the cone region, wherein the at least one primary blade is free of backup cutter elements in he shoulder region.
Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the embodiments described herein. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGSFor a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:
The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred the embodiments disclosed have broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment or to the features of that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.
Referring to
As best seen in
Referring again to
In the embodiment shown, each primary blade 31, 32 includes a cutter-supporting surface 42 for mounting a plurality of cutter elements, and each secondary blade 33-36 includes a cutter-supporting surface 52 for mounting a plurality of cutter elements. In particular, primary cutter elements 40 having primary cutting faces 44 are mounted to primary blades 31, 32 and secondary blades 33-36. Further, backup cutter elements 50 having backup cutting faces 54 are mounted to primary blades 31, 32.
Still referring to
As described above, the embodiment of bit 10 illustrated in
In different embodiments (not specifically illustrated), bit 10 may comprise a different number of primary blades and/or secondary blades than that shown in
Each blade on bit face 20 (e.g., primary blades 31, 32 and secondary blades 33-36) provides a cutter-supporting surface 42, 52 to which cutter elements are mounted. In the embodiment illustrated in
Primary cutter elements 40 are positioned adjacent one another generally in a first row extending radially along each primary blade 31, 32 and along each secondary blade 33-36. Further, backup cutter elements 50 are positioned adjacent one another generally in a second row extending radially along each primary blade 31, 32. In particular, backup cutter elements 50 form a second row that extends along each primary blade 31, 32 from substantially proximal central axis 11. Backup cutter elements 50 are positioned behind the primary cutter elements 40 provided on the same primary blade 31, 32. As best seen in
In general, primary cutter elements 40 and backup cutter elements 50 need not be positioned in rows, but may be mounted in other suitable arrangements provided each cutter element is either in a leading position (e.g., primary cutter element 40) or trailing position (e.g., backup cutter element 50). Examples of suitable arrangements may include without limitation, rows, arrays or organized patterns, randomly, sinusoidal pattern, or combinations thereof. Further, in other embodiments (not specifically illustrated), additional rows of cutter elements may be provided on a primary blade, secondary blade, or combinations thereof.
As described above, the embodiment of bit 10 illustrated in
Still referring to
As shown in
In certain embodiments (not specifically illustrated), certain gage pads 51 include cutter elements. Further, in some embodiments (not specifically illustrated), no gage pads 51 are provided on bit 10. Wear-resistant inserts may be embedded in gage pads 51 and protrude from the gage-facing surface 60 or forward facing, surface 61 of gage pads 51.
Referring to
Still referring to
Blade profiles 39 and bit face 20 may also be described as two regions termed “inner region” and “outer region”, where the “inner region” is the central most region of bit 10 and is analogous to cone region 24, and the “outer region” is simply the region(s) of bit 10 outside the inner region. Using this nomenclature, the outer region is analogous to the combined shoulder region 25 and gage region 26 previously described. The inner region may be defined similarly to cone region 24 (e.g., by a percentage of the outer radius 23, by distance “D,” etc.).
Referring to
In the embodiment illustrated in
Each blade provided on bit 10 (e.g., primary blades 31, 32, secondary blades 33-36) provides a cutter-supporting surface 42, 52 for mounting cutter elements (e.g., primary cutter elements 40, backup cutter elements 50). In the embodiment illustrated in
Still referring to the embodiment shown in
Each primary cutter element 40 and each backup cutter element 50 comprise an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. Further, each cutter element 40, 50 has a cutting face 44, 54 (respectively) that comprises a forward facing disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member.
In the embodiments described herein, the primary cutter elements 40 and the backup cutter elements 50 are mounted so that their cutting faces 44, 54 are forward facing. As used herein, “forward facing” is used to describe the orientation of a surface that is substantially perpendicular to or at an acute angle relative to the cutting direction of bit 10 represented by arrow 18. For instance, a forward facing cutting face 44, 54 may be oriented substantially perpendicular to the cutting direction of bit 10, may include a backrake angle, and/or may include a siderake angle.
In the embodiment illustrated in
Still referring to
It is to be understood that blades having one or more backup cutter elements and which do not extend into a particular region will have a backup cutter density of zero in that particular region. For example, if a primary blade has one or more backup cutter elements, but the primary blade does not extend into gage region 26, then the primary blade has a gage backup cutter density of zero.
In select embodiments, the cone backup cutter density of a primary blade (e.g., primary blade 31) is greater than the shoulder backup cutter density and greater than the gage backup cutter density. For example, in the embodiment illustrated in
Alternatively, each primary blade 31, 32 may be said to have an inner backup cutter density and an outer backup cutter density, where the inner backup cutter density is the backup cutter density within an inner region, analogous to the cone backup cutter density, and the outer backup cutter density is the backup cutter density on the portion of blade outside the inner region.
Still referring to
It is to be understood that blades having one or more backup cutter elements and which do not extend into a particular region will have a backup cutter area of zero in that particular region. For example, if a primary blade has backup cutter elements, but the primary blade does not extend into gage region 26, then the primary blade has a gage backup cutter area of zero.
In select embodiments, the cone backup cutter area of a primary blade (e.g., primary blade 31) is greater than the shoulder backup cutter area of the same primary blade and greater than the gage backup cutter area of that primary blade. For example, in the embodiment illustrated in
Alternatively, each primary blade 31, 32 may be said to have an inner backup cutter area and an outer backup cutter area, where the inner backup cutter area is the backup cutter area within an inner region, analogous to the cone backup cutter area, and the outer backup cutter area is the backup cutter area on the portion of blade outside the inner region.
As described, certain embodiments disclosed herein reduce the primary blade count on bit 10 as compared to some conventional fixed cutter bits of the same gage diameter that may include three, four, or more primary blades. However, reducing primary blade count on bit 10 (without other design changes) may also result in a reduction in the number of cutter elements on bit 10. In particular, a reduction of cutter elements in cone region 24 of bit 10 may detrimentally impact the ability of the bit to distribute across the cutter elements in the cone region the relatively high loads encountered during drilling. Therefore, in select embodiments, the reduction in primary blade count is also accompanied by the positioning of additional cutter elements, in the form of backup cutter elements, in the cone region 24 such that the overall cutter element count in the cone region may be substantially the same even though the primary blade count has been decreased. Without being limited by theory, by reducing the primary blade count and substantially maintaining the cutter element count within the cone region 24, it is desired that the ROP of bit 10 be increased as compared to some conventional fixed cutter bits.
In addition, as best seen in
Referring to
A plurality of primary cutter elements 40 are provided on cutter-supporting surface 42 of each primary blade 31, 32 and cutter-supporting surface 52 of each secondary blade 33-36. Further, a plurality of backup cutter elements 50 are provided on the cutter-supporting surface 52 of each primary blade 31, 32.
Still referring to the embodiment shown in
Still referring to
Still referring to
As previously described, certain embodiments disclosed herein reduce the primary blade count on bit 10 as compared to some conventional fixed cutter bits of the same gage diameter, while substantially maintaining the total cutter element count in the cone region 24. Without being limited by theory, by reducing the primary blade count and substantially maintaining the cutter element count within the cone region 24, it is desired that the ROP of bit 10 be increased as compared to some conventional fixed cutter bits.
In addition, by reducing the number of primary blades on bit 10, as compared to some conventional fixed cutter bits of the same gage diameter, additional space is made available for positioning nozzles 22 about bit face 20. Without being limited by theory, improved placement of nozzles 24 is intended to enhance removal of formation cuttings and enhance removal of heat from bit 10. As a result, the ROP and life of bit 10 may be advantageously enhanced.
As one skilled in the art will appreciate, numerous variations in the size, orientation, and locations of backup cutter elements 50 and primary cutter elements 40 within cone region 24 are possible. Certain features and variations of backup cutter elements 50 of bit 10 illustrated in
In the embodiments that follow, reference numerals 40a-40h represent primary cutter elements disposed on primary blades 31, 32 within cone region 24 of bit 10. In particular, reference numerals 40a, 40c, 40e, and 40g represent primary cutter elements disposed on primary blade 31, while reference numerals 40b, 40d, 40f and 40h represent primary cutter elements disposed on primary blade 32. Further, reference numerals 50a-50h represent backup cutter elements disposed on primary blades 31, 32 within cone region 24 of bit 10. In particular, reference numerals 50a, 50c, 50e, and 50g represent backup cutter elements disposed on primary blade 31, while reference numerals 50b, 50d, 50f, and 50h represent backup cutter elements disposed on primary blade 32. In addition, primary cutter elements 40a-40h include primary cutting faces 44a-44h, respectively, and backup cutter elements 50a-50h include backup cutting faces 54a-54h, respectively.
Referring to
Bit 10 rotates about central axis 11 in the cutting direction of arrow 18 such that primary blades 31, 32 follow each other. Further, as bit 10 rotates about central axis 11, the backup cutter elements trail the primary cutter elements provided on the same primary blade. For instance, backup cutter elements 50a, 50c, 50e, and 50g on primary blade 31 are positioned behind, and hence trail, primary cutter elements 40a, 40c, 40e, and 40g on primary blade 31 as bit 10 rotates,
The primary cutter elements are positioned adjacent each other substantially in a first row on each primary blade. For instance, primary cutter elements 40b, 40d, 40f, and 40h are arranged substantially in a first row along primary blade 32. In addition, the backup cutter elements are positioned adjacent each other substantially in a second row on each primary blade. For instance backup cutter elements 50b, 50d, 50f, and 50h are arranged substantially in a second row along primary blade 32. Further, in the embodiment illustrated in
In the embodiment shown in
As best seen in the rotated profile shown in
Although the embodiment illustrated in
Still referring to the rotated profile shown in
As best seen in the rotated profile shown in
Although the embodiment illustrated in
The embodiment illustrated in
In the embodiment shown in
As best seen in the rotated profile shown in
Still referring to the rotated profile shown in
In addition, as best seen in the rotated profile shown in
In the embodiment shown in
As best seen in
Still referring to the rotated profile shown in
In addition, as best seen in the rotated profile shown in
The embodiment illustrated in
The various embodiments described herein are intended to offer potential improvements over the prior art. Some embodiments of the present invention offer the potential of improving the ROP of bit 10 by reducing the number of relatively larger primary blades while maintaining the number of cutter elements within the cone region. In addition, by reducing the number of relatively large primary blades, embodiments of the present invention may allow for more advantageous positioning of drilling fluid nozzles 22 about bit face 10. Optimal placement of nozzles 22 may enhance the flow of drilling fluid, thereby improving removal of formation cuttings from bit face 20 and from the bottom of the borehole, and improving removal of heat from bit 10. These potential improvements may in turn enhance the ROP and durability of bit 10. In addition, by reducing the number of primary blades and permitting for more location options for nozzles 22, embodiments of the present invention may reduce the complexity of drilling fluid channels within bit 10, potentially reducing the design and manufacturing costs of bit 10.
While specific preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teaching herein. The embodiments described herein are exemplary only and are not limiting. For example, embodiments described herein may be applied to any bit layout including without limitation single set bit designs where each cutter element has unique radial position along the rotated cutting profile, plural set bit designs where each cutter element has a redundant cutter element in the same radial position provided on a different blade when viewed in rotated profile, forward spiral bit designs, reverse spiral bit designs, or combinations thereof. In addition, embodiments described herein may also be applied to straight blade configurations or helix blade configurations. Many variations and modifications of the system and apparatus are possible. For instance, in the embodiments described herein, a variety of features including without limitation spacing between cutter elements, cutter element geometry and orientation (e.g., backrake, siderake, etc.), cutter element locations, cutter element extension heights, cutter element material properties, or combinations thereof may be varied among one or more primary cutter elements and/or one or more backup cutter elements. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
Claims
1. A drill bit for drilling a borehole in earthen formations, the bit comprising:
- a bit body having a bit face comprising a cone region, a shoulder region, and a gage region;
- at least one primary blade disposed on the bit face, wherein the at least one primary blade extends into the cone region;
- a plurality of primary cutter elements mounted on the at least one primary blade in the cone region;
- a plurality of backup cutter elements mounted on the at least one primary blade in the cone region;
- wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density; and
- wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
2. The drill bit of claim 1, wherein the at least one primary blade extends into the shoulder region, and wherein at least one primary cutter element is mounted on the at least one primary blade in the shoulder region.
3. The drill bit of claim 1, wherein the at least one primary blade has a gage backup cutter density and wherein the cone backup cutter density of the at least one primary blade is greater than the gage backup cutter density of the at least one primary blade.
4. The drill bit of claim 1, wherein the shoulder backup cutter density of the at least one primary blade is zero.
5. The drill bit of claim 3, wherein the gage backup cutter density of the at least one primary blade is zero.
6. The drill bit of 1 further comprising a central axis and an outer radius, wherein the cone region extends from the central axis to no more than 50% of the outer radius.
7. The drill bit of claim 6, wherein the cone region extends from the central axis to no more than 30% of the outer radius.
8. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutting faces are forward facing and the backup cutting faces are forward facing.
9. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
10. The drill bit of claim 1, wherein each primary cutter element includes a primary cutting face and wherein each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
11. The drill bit of claim 1, wherein the bit comprises no more than two primary blades.
12. A drill bit for drilling a borehole in earthen formations, the bit comprising:
- a bit body with a central axis and an outer radius;
- a bit face comprising an inner region extending from the central axis to no more than 50% of the outer radius, and an outer region between the inner region and the outer radius;
- at least one primary blade disposed on the bit face, wherein the at least one primary blade extends from proximal the central axis into the outer region;
- a plurality of primary cutter elements mounted on the at least one primary blade;
- a plurality of backup cutter elements mounted on the at least one primary blade;
- wherein the at least one primary blade has an inner backup cutter area and an outer backup cutter area; and
- wherein the inner backup cutter area of the at least one primary blade is greater than the outer backup cutter area of the at least one primary blade.
13. The drill bit of claim 12, wherein the inner region extends from the central axis to no more than 30% of the outer radius
14. The drill bit of claim 12, wherein the plurality of primary cutter elements are arranged substantially in a first row along the at least one primary blade and the plurality of backup cutter elements are arranged substantially in a second row along the at least one primary blade.
15. The drill bit of claim 12, wherein the outer backup cutter area of the at least one primary blade is zero.
16. The drill bit of claim 12, wherein each primary cutter element includes a primary cutting face and each backup cutter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
17. The drill bit of claim 12, wherein each primary cutter element includes a primary cutting face and each backup cuter element includes a backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
18. The drill bit of claim 12, wherein the bit comprises no more than three primary blades.
19. The drill bit of claim 18, wherein the bit comprises no more than two primary blades.
20. A drill bit for drilling a borehole in earthen formations, the bit comprising:
- a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region;
- at least one primary blade disposed on the bit face, wherein the at least one primary blade begins substantially proximal the central axis and extends towards the gage region;
- at least one secondary blade disposed on the bit face, wherein the at least one secondary blade begins at a radial distance “D” from the central axis and extends toward the gage region, the radial distance “D” being a radius defining the cone region;
- a plurality of primary cutter elements mounted on the at least one primary blade, wherein the primary cutter elements are disposed in a first row extending along the at least one primary blade from substantially proximal the central axis toward the gage region;
- a plurality of backup cutter elements mounted on the at least one primary blade, wherein the backup cutter elements are disposed in a second row extending along the at least one primary blade within the cone region.
21. The drill bit of claim 20, wherein the bit body further comprises an outer radius, wherein the distance “D” is no more than 50% of the outer radius.
22. The drill bit of claim 20, wherein the bit body further comprises an outer radius, wherein the distance “D” is no more than 30% of the outer radius.
23. The drill bit of claim 21, wherein the at least one primary blade has a cone backup cutter density and a shoulder backup cutter density.
24. The drill bit of claim 23, wherein the cone backup cutter density of the at least one primary blade is greater than the shoulder backup cutter density of the at least one primary blade.
25. The drill bit of claim 24, wherein the shoulder backup cutter density of the at least one primary blade is zero.
26. The drill bit of claim 21, wherein the at least one primary blade has a cone backup cutter area and a shoulder backup cutter area.
27. The drill bit of claim 26, wherein the cone backup cutter area of the at least one primary blade is greater than the shoulder backup cutter area of the at least one primary blade.
28. The drill bit of claim 27, wherein the shoulder backup cutter area of the at least one primary blade is zero.
29. A drill bit for drilling a borehole in earthen formations, the bit comprising:
- a bit body having a central axis and a bit face comprising a cone region, a shoulder region, and a gage region;
- at least one primary blade disposed on the bit face, wherein the at least one primary blade begins proximal the central axis and extends toward the gage region;
- a plurality of primary cutter elements mounted on the at least one primary blade in the cone region;
- a plurality of backup cutter elements mounted on the at least one primary blade in the cone region; and
- wherein the at least one primary blade is free of backup cutter elements in the shoulder region.
30. The drill bit of claim 29, wherein the plurality of primary cutter elements are arranged in a first row along the at least one primary blade, and wherein the plurality of backup cutter elements are arranged in a second row along the at least one primary blade substantially parallel to the first row.
31. The drill bit of claim 29, wherein the at least one primary blade is free of backup cutter elements in the gage region.
32. The drill bit of claim 29, wherein each primary cutter element has a forward-facing primary cutting face and wherein each backup cutter element has a forward-facing backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is substantially eclipsed by a primary cutting face.
33. The drill bit of claim 29, wherein each primary cutter element has a forward-facing primary cutting face and wherein each backup cutter element has a forward-facing backup cutting face, wherein the primary cutter elements and the backup cutter elements are mounted on the at least one primary blade such that, in rotated profile, each backup cutting face is partially eclipsed by a primary cutting face.
34. The drill bit of claim 29, wherein the bit further comprises an outer radius and at least one secondary blade, wherein the at least one secondary blade begins at a distance “D” from the central axis and extends toward the gage region.
35. The drill bit of claim 36, wherein the distance “D” is no more than 50% of the outer radius.
36. The drill bit of claim 35, wherein the distance “D” is no more than 30% of the outer radius.
37. The drill bit of claim 29, wherein the bit comprises no more than three primary blades.
38. The drill bit of claim 37, wherein the bit consists of two primary blades.
39. The drill bit of claim 38, wherein the two primary blades are spaced generally opposite each other.
Type: Application
Filed: May 10, 2006
Publication Date: Nov 15, 2007
Applicant: Smith International, Inc. (Houston, TX)
Inventor: Dennis Cisneros (Kingwood, TX)
Application Number: 11/382,510
International Classification: E21B 10/08 (20060101);