DRILL BITS AND OTHER DOWNHOLE DRILLING TOOLS WITH NON-CYLINDRICAL CUTTER POCKETS

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 63/653,603, filed May 30, 2024, which is hereby incorporated by reference.

TECHNICAL FIELD

The present disclosure generally relates to drill bits having blades with improved cutters. In particular, the disclosure relates to drill bits and other downhole drilling having cutter pockets and cutters having non-circular cross-sections that enable the cutter pockets to self-align cutters inserted therein.

BACKGROUND

Downhole drilling tools, drill bits (such as rotary drag bits), reamers, and similar downhole tools for boring or forming holes in subterranean rock formations are well-known. When drilling oil and natural gas wells, geothermal wells, and mining boreholes, and other boreholes into the earth, rotary drag bits utilize discrete cutting elements, referred to as “cutters,” mounted in fixed locations on the body of the tool against the formation. As the cutters are dragged against the formation by rotation of the tool body, the cutters fail the formation through a shearing action. This shearing action forms small chips that are evacuated hydraulically or pneumatically by drilling fluid pumped through nozzles in the tool body. Conventional cutters are formed from cylindrical bodies. However, such cylindrical bodies may present limitations into the design of downhole tools. For example, where the cutters include a discrete cutting tip, it may be difficult to align the cutting tip in a desired orientation due to the manual brazing process for securing the cutter to the downhole tool. Additionally, the size and shape of the cylindrical bodies may limit the number of cutters on a blade, as well as the customizability of a cutting profile of a drill bit. Therefore, improvements in cutters and downhole tools including such cutters are desired.

SUMMARY

Embodiments of the present invention may encompass downhole tools that may include a body comprising a face and an axis of rotation. The tools may include a plurality of blades disposed on the face of the body. Each of the plurality of blades may define a plurality of cutter pockets. At least one cutter pocket of the plurality of cutter pockets may include a non-circular cross-section. The tools may include a plurality of cutters. A portion of each cutter may be disposed within a respective cutter pocket of the plurality of cutter pockets. The portion of each cutter may have a cross-sectional shape that matches a cross-sectional shape of the respective pocket.

In some embodiments, the downhole tool may be a drill bit. The downhole tool may include a reamer. The at least one pocket may have a generally rectangular cross-section. The generally rectangular cross-section may include two orthogonal linear sides and a rounded corner coupling the two orthogonal linear sides. A width of each rounded corner may be between 5 degrees and 45 degrees as measured from a central axis of the cutter pocket. The blade may include a plurality of knuckles. Each of the plurality of knuckles may protrude from a top surface of one of the plurality of blades and may be in alignment with a respective one of the plurality of cutter pockets and may support a portion of a base of one of the plurality of cutters seated within the respective one of the plurality of cutter pockets. Each of the plurality of knuckles may have a shape and size that substantially corresponds to a size and shape of a portion of the one of the plurality of cutters that extends above the top surface of a respective one of the plurality of blades on which the one of the plurality of cutters is mounted. A top surface of each of the plurality of knuckles may taper downward toward the top surface of a respective one of the plurality of blades in a direction away from the one of the plurality of cutters. Each of the plurality of knuckles may be axially aligned with a respective one of the plurality of cutters. The body may include a plurality of channels. Each channel may be formed between adjacent blades of the plurality of blades. The body may include a plurality of nozzles. Each nozzle may be disposed within one of the plurality of channels. An outlet of each nozzle may be aligned with one of the plurality of cutters that faces the respective channel. At least one of the plurality of cutters may include a diamond table having a non-cylindrical outer periphery that is configured to be rotated about a central axis of the at least one of the plurality of cutters at an angle of between 60 degrees and 300 degrees in the respective cutter pocket to expose a new cutting edge of point loading ability that is greater than a point loading ability of a conventional cylindrical cutter of similar size while maintaining a braze gap thickness of 0.015″ or less across 85% or more of a brazeable surface area of the conventional cylindrical cutter of similar size. A shape and orientation of the at least one cutter pocket and a respective one of the cutters disposed within the at least one cutter pocket may be selected such that when the respective one of the cutters is inserted into the at least one cutter pocket, the respective one of the cutters is oriented with a cutting tip of the respective one of the cutters protruding beyond a top surface of a respective one of the plurality of blades.

Some embodiments of the present technology may encompass cutters for a downhole tool. The cutters may include a substrate comprising a brazing surface. At least a portion of the brazing surface may include a first non-circular cross-section. The cutters may include a diamond table. The diamond table may include a bottom surface joined to the substrate. The diamond table may include a cutting face opposite the bottom surface. The cutting face may include a second non-circular cross-section.

In some embodiments one or both of the first non-circular cross-section and the second non-circular cross-section may include one or more concave and/or convex regions. The cutting face may be non-planar. The cutting face may include multiple discrete cutting tips. One or both of the first non-circular cross-section and the second non-circular cross-section may include a generally quadrilateral shape. The cutter may be symmetrical about two perpendicular planes that extend through both the substrate and the diamond table. One or both of the first non-circular cross-section and the second non-circular cross-section may include two or more linear sides that are connected via a plurality of curved corners. A ratio of a length of the linear sides to a length of the curved corners may be at least 0.5:1. One or both of the first non-circular cross-section and the second non-circular cross-section may include a generally rectangular shape. The generally rectangular shape may include four linear sides and four rounded corners. One or both of the first non-circular cross-section and the second non-circular cross-section may include a generally triangular shape. The generally triangular shape may include three linear sides and three rounded corners. One or both of the first non-circular cross-section and the second non-circular cross-section may include a stadium shape. The diamond table may include a chamfered edge that extends from the cutting face to a lateral side of the diamond table. An angle of the chamfered edge relative to the cutting face may vary along a periphery of the cutting face. The angle of the chamfered edge relative to the cutting face may be greater at a cutting region of the cutting face than at a medial region of the cutting face. The angle of the chamfered edge relative to the cutting face may be lower at a cutting region of the cutting face than at a medial region of the cutting face. A depth of the chamfered edge may vary along a periphery of the cutting face. The depth of the chamfered edge may be greater at a cutting region of the cutting face than at a medial region of the cutting face. The depth of the chamfered edge may be lower at a cutting region of the cutting face than at a medial region of the cutting face. The substrate may include a non-planar interface that protrudes from the substrate in a direction of the diamond table. The non-planar interface may include a non-circular cross-section. A shape of an outer periphery of the non-planar interface may match a shape of an outer periphery of a topmost planar surface of the substrate. A thickness of the non-planar interface may vary across a surface area of the non-planar interface. A thickness of the diamond table may vary across a surface area of the diamond table. A variation in the thickness of the non-planar interface may correspond to a variation in the thickness of the diamond table across the surface area of the diamond table. The diamond table may include a protruding feature. A thickness of the non-planar interface may increase in a region that corresponds to the protruding feature. The diamond table may include a recessed feature. A thickness of the non-planar interface may decrease in a region that corresponds to the recessed feature. A distance from a peripheral edge of the non-planar interface to a peripheral edge of the diamond table may be consistent within 20% of a greatest distance from the peripheral edge of the non-planar interface to the peripheral edge of the diamond table across an entire periphery of the diamond table. The first non-circular cross-section and the second non-circular cross-section may be a same shape.

Some embodiments of the present technology may encompass cutters for a downhole tool that may include a diamond table having a non-cylindrical outer periphery that is configured to be rotated about a central axis of diamond table at an angle of between 60 degrees and 300 degrees within a cutter pocket of a downhole tool to expose a new cutting edge of point loading ability that is greater than a point loading ability of a conventional cylindrical cutter of similar size while maintaining a braze gap thickness of 0.015″ or less across 85% or more of a brazeable surface area of the conventional cylindrical cutter of similar size.

Some embodiments of the present technology may encompass cutters for a downhole tool that may include a body having a central axis. A radial distance between an outer surface of the cutter and the central axis may vary about an outer periphery of the body along at least 50% of the outer periphery of the cutter and along at least 50% of a length of the body.

Some embodiments of the present technology may encompass methods of bonding a cutter to a downhole tool. The methods may include inserting a cutter having a non-circular cross-section into a non-cylindrical pocket formed into a downhole tool such that a gap is formed between an outer face of the cutter and a wall of the pocket. The methods may include providing a metal-containing substance into the gap. The methods may include setting the cutter in the pocket such that the cutter is joined to the downhole tool.

In some embodiments, the metal-containing substance may include a brazing alloy. The pocket and the cutter may each have a generally rectangular cross-section. The pocket and the cutter may each have a generally triangular cross-section. The pocket and the cutter each may have a generally stadium-shaped cross-section. The pocket and the cutter may each have a generally pentagonal cross-section. The pocket and the cutter may each have a generally hexagonal cross-section. The pocket may be formed within a blade that extends outward from a face of the downhole tool. A shape and orientation of the cutter and the pocket may be selected such that when the cutter is inserted into the pocket, the cutter is oriented with a cutting tip of the cutter protruding beyond a top surface of the blade.

Some embodiments of the present technology may encompass methods of manufacturing a downhole tool. The methods may include forming a mold of a body of the downhole tool. The methods may include inserting a plurality of cutter pocket displacements within the mold. The plurality of cutter pocket displacements may have non-circular cross-sections. The plurality of cutter pocket displacements may be aligned within the mold such that the cutter pocket displacements define a size and orientation of cutter pockets. The methods may include filling the mold with a carbide matrix material and a binder material. The methods may include heating the filled mold to form the body of the downhole tool. The plurality of cutter pocket displacements may form the cutter pockets within the body of the downhole tool. At least one of the cutter pockets may include a non-circular cross-section that is configured to automatically orient a cutter in a cutting position. The methods may include removing the body of the downhole tool from the mold. The methods may include inserting a cutter into at least one of the cutter pockets. At least one of the cutters may have a non-circular cross-section that substantially matches the non-circular cross-section of a respective one of the cutter pockets.

In some embodiments, inserting the plurality of cutter pocket displacements within the mold may include inserting each cutter pocket displacement into a trough formed in the mold. Each the plurality of cutter pocket displacements may be aligned within a respective one of the cutter pockets manually. Each of the plurality of cutter pocket displacements may be aligned within a respective one of the cutter pockets using an indexing feature formed in one or both of the mold and the respective cutter pocket displacement. One of the trough and a respective cutter pocket displacement may include a ridge and the other of the trough and a respective cutter pocket displacement may define a groove. Insertion of the ridge into the groove may align the respective cutter pocket displacement within the trough. One of the trough and a respective cutter pocket displacement may include a convexity and other of the trough and a respective cutter pocket displacement may define a concavity. Interfacing the concavity with the convexity may align the respective cutter pocket displacement within the trough. Each of the trough and a respective cutter pocket displacement may define a slot. A key may be inserted within both of the slots to align the respective cutter pocket displacement within the trough. The methods may include removing the cutter pocket displacements from the body of the downhole tool prior to inserting the cutters. The methods may include brazing each cutter within a respective cutter pocket. The body of the downhole tool may include a plurality of blades that extend away from the body of the downhole tool. A shape and orientation of each cutter pocket and a respective one of the cutters disposed within the cutter pocket may be selected such that when the respective one of the cutters is inserted into the cutter pocket, the respective one of the cutters is oriented with a cutting tip of the respective one of the cutters protruding beyond a top surface of a respective one of the plurality of blades.

Some embodiments of the present technology may encompass methods of manufacturing a downhole tool that may include forming a body of a downhole tool. The body may include a plurality of blades. Each blade may include a plurality of cutter pockets. At least one of the plurality of cutter pockets may include a non-circular cross-section. The methods may include hardfacing the body of the downhole tool. The methods may include inserting a cutter into each of the plurality of cutter pockets. At least one cutter may include a non-circular cross-section that substantially matches the non-circular cross-section of a respective one of at least one of the plurality of cutter pockets. The methods may include brazing each cutter into the respective one of the cutter pockets.

In some embodiments, forming the body of the downhole tool may include machining the body from a steel blank. Hardfacing may include fusing a carbide material and a binder onto at least a portion of the body of the downhole tool. A shape and orientation of each cutter pocket and a respective one of the cutters disposed within the cutter pocket may be selected such that when the respective one of the cutters is inserted into the cutter pocket, the respective one of the cutters is oriented with a cutting tip of the respective one of the cutters protruding beyond a top surface of a respective one of the plurality of blades. Forming the body of the downhole tool may include machining each of the plurality of cutter pockets into the body of the downhole tool. Forming the body of the downhole tool may include forming each of the plurality of cutter pockets with a circular cross-section. Forming the body of the downhole tool may include welding a shim into the circular cross-section to form the non-circular cross-section.

Some embodiments of the present technology may encompass methods of re-orienting a cutter to a downhole tool. The methods may include determining that a first cutting tip of a cutter on blade of a downhole tool is excessively worn. The first cutting tip may be in a cutting position in which the first cutting tip protrudes above a top surface of the blade. The cutter may include a plurality of discrete cutting tips. The cutter may include a non-circular cross-section that corresponds with a cross-section of a cutter pocket in which the cutter is secured. The methods may include determining that a second cutting tip of the plurality of discrete cutting tips is in sufficient condition to be utilized in the cutting position. The methods may include removing the cutter from the cutter pocket. The methods may include rotating the cutter and inserting the cutter into the cutter pocket with the second cutting tip oriented into the cutting position. The methods may include securing the cutter within the cutter pocket. In some embodiments, securing the cutter within the cutter pocket may include brazing the cutter to the cutter pocket. A shape and orientation of the cutter pocket the cutter may be selected such that when the cutter is inserted into the cutter pocket, the cutter is oriented with one of the plurality of discrete cutting tips in the cutting position. Determining that a first cutting tip of a cutter on blade of a downhole tool is excessively worn may be done by grading the first cutting tip based on one or more predetermined criteria. Determining that a second cutting tip of the plurality of discrete cutting tips is in sufficient condition to be utilized in the cutting position may be done by grading the second cutting tip based on one or more criteria.

Some embodiments of the present technology may encompass drill bits that may include a body comprising a face for engaging a bottom of a well bore. The drill bits may include a plurality of blades formed on the body. The drill bits may include a plurality of cutters mounted on each blade of the plurality of blades. Each cutter may include a plurality of discrete cutting tips. Each cutter may be mounted on a respective blade with a single cutting tip of the plurality of discrete cutting tips extending beyond a top surface of the respective blade. The single cutting tip of at least some of the plurality of cutters may be oriented non-orthogonally relative to the top surface of the respective blade.

In some embodiments, the at least some of the plurality of cutters may include cutters within a nose and cone of the drill bit. The at least some of the plurality of cutters may be oriented with the single cutting tip rolled inward toward an axis of rotation of the body. The at least some of the plurality of cutters may include cutters that are radially adjacent along a cutting profile of the drill bit. The cutters that are radially adjacent along the cutting profile may have single cutting tips that are oriented with alternating positive and negative angles relative to orthogonal. The at least some of the plurality of cutters may be disposed on a gauge pad of the drill bit. At least one blade of the plurality of blades may include a primary row of cutters and a backup row of cutters. The at least some of the plurality of cutters may be in the primary row of cutters. At least one blade of the plurality of blades may include a primary row of cutters and a backup row of cutters. The at least some of the plurality of cutters may be in the backup row of cutters. Each blade may define a plurality of cutter pockets. Each of the plurality of cutters may be received within a respective cutter pocket. A shape and orientation of each cutter pocket may determine an orientation of a respective cutter received within the cutter pocket.

Some embodiments of the present technology may encompass drill bits that may include a body having a face for engaging a bottom of a well bore. The body may include an axis of rotation that extends along a length of the body. The drill bits may include a plurality of blades formed on the body. The drill bits may include a plurality of cutters mounted on each blade of the plurality of blades. The plurality of cutters may include pairs of cutters. Each pair of cutters may include a first cutter and a second cutter at a same radial distance from the axis of rotation. One or both of the first cutter and the second cutter of each pair of cutters may include a plurality of discrete cutting tips. Each cutter may be mounted on a respective blade with a single cutting tip extending beyond a top surface of the respective blade.

In some embodiments, at least some of the pairs of cutters may be on a same blade. At least some of the pairs of cutters may be on different blades. One of the first cutter and the second cutter of each pair of cutters may include a cylindrical cutter. The first cutter and the second cutter of each pair of cutters may include identical cutting tips. The first cutter and the second cutter of each pair of cutters may include different cutting tips. The first cutter and the second cutter of each pair of cutters may include different cross-sectional shapes.

Some embodiments of the present technology may encompass drill bits to advance a borehole. The drill bits may include a body having a face for engaging a bottom of a well bore. The body may include an axis of rotation that extends along a length of the body. The drill bits may include a plurality of blades formed on the body. The drill bits may include a plurality of cutters mounted on each blade of the plurality of blades. At least one of the blades may be an offset blade having an inner region supporting an inner set of cutters of the plurality of cutters along a first leading edge portion of the offset blade and an outer region supporting an outer set of cutters along a second leading edge portion of the offset blade. The second leading edge portion may be rotationally offset from the first leading edge portion. At least some cutters of the plurality of cutters may include a plurality of discrete cutting tips. Each cutter may be mounted on a respective blade with a single cutting tip of the plurality of discrete cutting tips extending beyond a top surface of the respective blade.

In some embodiments, the at least some cutters may include the inner set of cutters. The at least some cutters may include the outer set of cutters. The at least some cutters may include both the inner set of cutters and the outer set of cutters.

Some embodiments of the present technology may encompass rotary apparatuses for boring earth. The apparatuses may include a body comprising a face for engaging a bottom of a well bore. The body may include an axis of rotation that extends along a length of the body. The apparatuses may include a blade formed on the body. The apparatuses may include at least two pairs of cutters mounted on the blade. Each cutter may include a plurality of discrete cutting tips. Each cutter may be mounted on the blade with a single cutting tip of the plurality of discrete cutting tips extending beyond a top surface of the blade. The cutters may partially define at least a portion of a cutting profile for the apparatus when the apparatus is rotated. A first cutter within each pair of cutters may have a first polarity of side rake and a second cutter within each pair of cutters may have a second polarity of side rake that is different than the first polarity of side rake. Cutting faces of the cutters in each pair of cutters may generally face toward each other.

In some embodiments, each of the first polarity of side rake and the second polarity of side rake may include a positive side rake, a neutral side rake, or a negative side rake. The blade may include an offset blade having an inner region supporting an inner set of cutters of the plurality of cutters along a first leading edge portion of the offset blade and an outer region supporting an outer set of cutters along a second leading edge portion of the offset blade. The inner region may be radially and angularly displaced from the outer region. The cutters in each pair of cutters may have side rake angles that differ from one another by at least 4 degrees.

Some embodiments of the present technology may encompass drill bits that may include a body comprising a face for engaging a bottom of a well bore. The body may include an axis of rotation that extends along a length of the body. The drill bits may include a plurality of blades formed on the body. The drill bits may include a plurality of cutters disposed on each blade. The plurality of cutters may collectively define a cutting profile of the drill bit. Each cutter may include a plurality of discrete cutting tips. Each cutter may be mounted on a respective blade with a single cutting tip of the plurality of discrete cutting tips extending beyond a top surface of the respective blade. At least some of the plurality of cutters that are radially adjacent along the cutting profile may have alternating positive back rake angles. A difference between a majority of back rake angles on adjacent cutters may be less than 20°.

The difference between the back rake angles on two adjacent cutters may be greater than the difference between the back rake angles on another two adjacent cutters that are disposed radially further outward. The at least some of the plurality of cutters that are radially adjacent along the cutting profile may be located within a nose region and a cone region of the drill bit. The at least some of the plurality of cutters may include at least six radially adjacent cutters. At least some radially adjacent cutters of the plurality of cutters within a shoulder region and a gauge region of the drill bit may not have alternating back rake angles.

Some embodiments of the present technology may encompass drill bits that may include a body having a face for engaging a bottom of a well bore. The body may include an axis of rotation that extends along a length of the body. The drill bits may include a first blade and a second blade formed on the body. The drill bits may include a plurality of cutter pairs disposed on the first blade and the second blade. Each cutter may include a plurality of discrete cutting tips. Each cutter may be mounted on a respective blade with a single cutting tip of the plurality of discrete cutting tips extending beyond a top surface of the respective blade. A first cutter of each cutter pair may be disposed on the first blade and a radially corresponding second cutter of each cutter pair may be disposed on the second blade. The cutter pairs may be arranged on the first blade and the second blade with an angular distance between the first cutter and the radially corresponding second cutter being different for at least some of the cutter pairs such that when the drill bit is rotated within a borehole, a time lag between when the first cutter and the radially corresponding second cutter engage a formation is different for the at least some of the cutter pairs.

In some embodiments, the first blade may have a first waveform pattern defined from about the axis of rotation to an outer edge of the first blade. The second blade may have a second waveform pattern defined from about the axis of rotation to an outer edge of the second blade. Each of the first waveform pattern and the second waveform pattern may include at least one concave region and at least one convex region. The first blade may have a first waveform pattern defined from about the axis of rotation to an outer edge of the first blade. The second blade may have a second waveform pattern defined from about the axis of rotation to an outer edge of the second blade. The first waveform pattern and the second waveform pattern may have at least differing characteristic selected from a shape, an amplitude, a frequency, and a phase.

BRIEF DESCRIPTION OF THE DRAWINGS

A further understanding of the nature and advantages of various embodiments may be realized by reference to the following figures. In the appended figures, similar components or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a set of parentheses containing a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.

FIG. 1 is an isometric view of a drill bit according to embodiments of the present invention.

FIG. 2 is an isometric view of a drill bit according to embodiments of the present invention.

FIG. 3 is an isometric view of a reamer according to embodiments of the present invention.

FIGS. 4A-4D illustrate different views of a generally rectangular cutter according to embodiments of the present invention.

FIGS. 5A-5D illustrate different views of a generally triangular cutter according to embodiments of the present invention.

FIGS. 6A-6D illustrate different views of a generally pentagonal cutter according to embodiments of the present invention.

FIGS. 7A-7D illustrate different views of a generally stadium-shaped cutter according to embodiments of the present invention.

FIGS. 8A-8D illustrate different views of a generally hexagonal cutter according to embodiments of the present invention.

FIGS. 9A-9D illustrate different views of a generally rectangular cutter according to embodiments of the present invention.

FIGS. 10A-10D illustrate different views of a generally rectangular cutter with a non-planar diamond table according to embodiments of the present invention.

FIGS. 11A-11D illustrate different views of a generally rectangular cutter with a non-planar diamond table according to embodiments of the present invention.

FIGS. 12A-12D illustrate different views of a generally rectangular cutter with a non-planar diamond table according to embodiments of the present invention.

FIGS. 13A-13D illustrate different views of a generally rectangular cutter with a non-planar diamond table according to embodiments of the present invention.

FIGS. 14A-14C illustrate different views of a generally rectangular cutter with a variable chamfer according to embodiments of the present invention.

FIG. 15 illustrates different views of a generally rectangular cutter with a shaped non-planar interface according to embodiments of the present invention.

FIG. 16 illustrates different views of a generally rectangular cutter with a shaped non-planar interface according to embodiments of the present invention.

FIG. 17 is an isometric view of a drill bit according to embodiments of the present invention.

FIGS. 18A-18C illustrate different views of non-cylindrical cutters and pockets according to embodiments of the present invention.

FIG. 19 illustrates a blade with a cutter pocket including a keyway according to embodiments of the present invention.

FIG. 20 illustrates a keyed shim according to embodiments of the present invention.

FIG. 21 illustrates a non-keyed shim according to embodiments of the present invention.

FIG. 22 illustrates the blade with the keyed shim and the non-keyed shim according to embodiments of the present invention.

FIG. 23 illustrates a spacer with a non-keyed shim according to embodiments of the present invention.

FIG. 24 illustrates the blade with a spacer and two non-keyed shims according to embodiments of the present invention.

FIG. 25 illustrates a blade with a number of non-cylindrical cutters according to embodiments of the present invention.

FIG. 26 illustrates non-cylindrical cutters having various angular positions according to embodiments of the present invention.

FIG. 27 illustrates a cutting profile having non-cylindrical cutters having various angular positions according to embodiments of the present invention.

FIG. 28 shows a schematic illustration of a face view of a drill bit according to embodiments of the present invention.

FIG. 29 represents a schematic illustration of a cutting profile of a drill bit according to embodiments of the present invention.

FIG. 30A shows a schematic illustration of a cutter having a positive back rake angle according to embodiments of the present invention.

FIG. 30B shows a schematic illustration of another cutter having a positive back rake angle according to embodiments of the present invention.

FIGS. 31A and 31B show schematic illustrations of two different cutters having a common positive back rake angle according to embodiments of the present invention.

FIG. 31C shows a schematic illustration of a cutter having a negative back rake angle according to embodiments of the present invention.

FIG. 32A is a cutting profile for a first example of cutters mounted on an offset blade.

FIG. 32B illustrates a three dimensional cutter geometry corresponding to the cutting profile of FIG. 32A.

FIG. 33A represents a cutting profile of a second example of a cutter geometry for an offset blade.

FIG. 33B illustrates the cutter geometry corresponding to the cutting profile of FIG. 33A.

FIG. 34 illustrates a cutter geometry of a third example of an offset blade.

FIGS. 35A-35J are graphs plotting cutter position to a side inclination, such as a side rake or lateral angle, and represent examples of schemes or patterns of such angles across a blade or cutting profile of an earth boring tool with fixed cutters.

FIG. 36A is a graph plotting primary cutter radial positions to side rake angle in degrees for cutters on an example of a PDC bit with offset blades.

FIG. 36B is a graph plotting cutter number to side rake angle.

FIG. 37A is a graph plotting cutter radial position to side rake angle in degrees for cutters on second example of a PDC bit with offset blades.

FIG. 37B is a graph plotting cutter number to side rake angle.

FIGS. 38A-38K are graphs showing exemplary back rake configurations for cutters on a drill bit in accordance with some embodiments of the present invention.

FIGS. 39A-39J are graphs showing exemplary side rake configurations for cutters on a drill bit in accordance with some embodiments of the present invention.

FIGS. 40A-40F show the back rake angles of cutters on blades of a drill bit in accordance with some embodiments of the present invention.

FIGS. 41A-41F show the side rake angles of cutters on blades of a drill bit in accordance with some embodiments of the present invention.

FIG. 42 is a face-on view of a drill bit in accordance according with various embodiments of the present disclosure.

FIG. 43 is a face-on view of a drill bit in accordance according with various embodiments of the present disclosure.

FIG. 44 is a face-on view of a drill bit in accordance according with various embodiments of the present disclosure.

FIG. 44A is a graph showing cutter locations for the drill bit of FIG. 44.

FIG. 44B is a graph showing cutter overlap for the drill bit of FIG. 44.

FIG. 45 is a flowchart illustrating operations of a method for bonding a cutter to a cutter pocket according to embodiments of the present invention.

FIG. 46 is a flowchart illustrating operations of a method for manufacturing a drill bit according to embodiments of the present invention.

FIG. 47 is a flowchart illustrating operations of a method for manufacturing a drill bit according to embodiments of the present invention.

FIG. 48 is a flowchart illustrating operations of a method for re-orienting a cutter within a cutter pocket according to embodiments of the present invention.

FIG. 49 is a flowchart illustrating operations of a method for operating a downhole tool according to embodiments of the present invention.

Several of the figures are included as schematics. It is to be understood that the figures are for illustrative purposes and are not to be considered of scale unless specifically stated to be of scale. Additionally, as schematics, the figures are provided to aid comprehension and may not include all aspects or information compared to realistic representations and may include exaggerated material for illustrative purposes.

DETAILED DESCRIPTION

The subject matter of embodiments of the present invention is described here with specificity to meet statutory requirements, but this description is not necessarily intended to limit the scope of the claims. The claimed subject matter may be embodied in other ways, may include different elements or steps, and may be used in conjunction with other existing or future technologies. This description should not be interpreted as implying any particular order or arrangement among or between various steps or elements except when the order of individual steps or arrangement of elements is explicitly described.

Embodiments of the present invention are directed to non-cylindrical cutters (e.g., cutters having a non-circular cross-sectional shape) and downhole tools that include such cutters. The use of such cutters may provide numerous benefits over conventional cylindrical cutters. For example, use of non-cylindrical cutters may enable better point loading. More specifically, non-cylindrical cutters may include one or more discrete cutting tips (rather than a continuous circular cutting edge) that enables higher pressures to be exerted on the rock formation, as a same amount of force is delivered through a smaller surface area than in conventional cylindrical cutters, which enables drilling efficiency to be increased. Additionally, the geometry of non-cylindrical cutters and cutter pockets may enable the cutters to be self-aligning within the cutter pockets, such that the cutting tip is positioned at a desired orientation (e.g., cutting position) upon the cutter being inserted into the cutter pocket. This may reduce or eliminate alignment errors associated with manual orientation (e.g., by eye or using a measurement tool) during brazing of the cutters within the cutter pockets. Additionally, the presence of multiple discrete cutting tips may enable worn cutters to be removed from the cutter pockets, rotated, and re-brazed into the cutter pockets with a new cutting tip positioned above a top surface of a respective blade. This may enable the cutters to be reused for two or more cycles and may cut down on material waste. Additionally, some or all cutting tips of an individual cutter with multiple discrete cutting tips may have a different chamfer or bevel size, which may reduce overall cutter inventory for the organization, further reducing operating costs.

In some embodiments, the downhole tools described herein may include drill bits, such as rotary drag bits, hybrid drill bits, which can include a variety of fixed cutters, with or without rotating cutters that can fail formation through a shearing or plowing action, and/or rolling elements that fail formations through a crushing action. FIG. 1 illustrates an example of a rotary drill bit 100 according to embodiments of the present disclosure. The rotary drill bit 100 of FIG. 1 is intended to be a representative example of drill bits, e.g., drag bits, for drilling formations. Rotary drill bit 100 is designed to be rotated around its central axis 102. Drill bit 100 may include a bit body 104 connected to a shank 106 having a tapered threaded coupling 108 for connecting the bit to a drill string (not shown). Drill bit 100 may further include a bit breaker surface 111 for cooperating with a wrench to tighten and loosen the coupling to the drill string. The exterior surface of bit body 104 is intended to face generally in the direction of boring and is referred to as bit face. The face generally lies in a plane perpendicular to central axis 102 of drill bit 100. In some embodiments, bit body 104 is made from an abrasion-resistant composite material or “metal matrix composite” that includes, for example, a ceramic component (such as a powdered tungsten carbide) that reinforces a metal matrix, such as a copper alloy matrix. In other embodiments, bit body 104 may be formed from a metal alloy, such as a steel alloy. In some embodiments, all or a portion of a steel alloy bit body 104 may include a hardfacing material, such as a carbide material that has been fused to a surface of the steel alloy to provide additional strength to bit body 104. It will be appreciated that other materials may be used to form bit body 104 in various embodiments.

During drilling operations, drill bit 100 may be coupled to the drill string. As drill bit 100 is rotated within the wellbore via the drill string, drilling fluid may be pumped down the drill string, through the internal fluid plenum and fluid passageways within bit body 104 of drill bit 100, and out from drill bit 100 through nozzles 117. Formation cuttings generated by cutters 112 of bit body 104 may be carried with the drilling fluid through the fluid courses (e.g., “junk slots”), around drill bit 100, and back up the wellbore through the annular space within the wellbore outside the drill string.

Bit body 104 may include one or more raised blades 110 that extend from the face of bit body 104. In some embodiments, blades 110 extend radially along the bit face and are circumferentially spaced structures extending along the leading end or formation engaging portion of bit body 104. Each blade 110 may extend generally in a radial direction, outwardly to the periphery of bit body 104. For example, blades 110 may generally extend from the cone region proximate the longitudinal axis, or central axis 102, of the bit, upwardly to the gauge region, or maximum drill diameter of bit. In some embodiments, blades 110 may be substantially equally spaced around central axis 102 of drill bit 100 and each blade 110 may sweep or curve backward in the direction of rotation indicated by arrow 115. In other embodiments, one or more of blades 110 may have zero sweep (e.g., do not curve in the direction of arrow 115). Channels formed between adjacent blades may form the junk slots that provide paths for drilling fluid and formation cuttings to be carried up the wellbore.

As noted above, bit body 104 further includes a plurality of superabrasive cutters 112. Cutters 112 may be, for example, polycrystalline diamond compact (“PDC”) cutting elements, disposed on front and/or top facing surfaces of each blade 110. For example, a plurality of discrete cutters 112 may be mounted on each blade 110. Cutters 112 may be arranged in a forward spiral, reverse spiral, skip spiral, and/or other cutter arrangement that defines a radial and angular position of each cutter 112. For example, a skip spiral may be differentiated from a forward or reverse spiral in that radially adjacent cutters are not always on angularly adjacent blades, even on the nose and shoulder where all of the secondary blades are present. On a reverse spiral, five bladed bit, cutters 15 through 19 might appear on blades 1, 5, 4, 3, 2, respectively. Whereas on a skip spiral, five bladed bit of similar size and cutter count, cutters 15 through 19 might appear on blades 1, 4, 5, 2, 3 respectively. There are many other ways to arrange a skip spiral layout.

Each discrete cutter 112 may be disposed within a recess or pocket formed in a given blade 110. Cutters 112 may be mounted to drill bit 100 either by press-fitting or otherwise locking the stud (e.g., substrate portion of cutting element) of the respective cutter 112 into a pocket or receptacle on a drag bit, or by brazing a portion of the respective cutter 112 directly into a preformed pocket, socket or other receptacle on a given blade 110. Cutters 112 may be provided in one or more rows along each blade 110. For example, in some embodiments, a given blade 110 may include one or more primary cutters 112 that extend through a leading edge of the blade 110 and one or more backup cutters 112 that are positioned on the blade 110 behind the primary cutters 112. In some embodiments, each cutter 112 may have a unique radial position (i.e., radial distance from central axis 102), while in other embodiments multiple cutters 112 (e.g., two or more, three or more, four or more, etc.) cutters may be positioned at a given radial position. Cutters at a same radial position may be mounted on a same blade 110 or on different blades 110 in various embodiments. In some embodiments, an outlet of some or all nozzles 117 may be aligned with a cutting face of one of the cutters that faces the respective channel, with the axis of each nozzle 117 being aimed slightly away (e.g., between 1 degree and 10 degrees) of parallel with respect to the front surface of the respective blade 110. This may enable the drilling fluid to more effectively wash cuttings away from cutters 112 while helping reduce erosion of the area of the blade 110 surrounding the cutter pockets.

FIG. 2 represents a view of the face of another embodiment of a drill bit 200. Drill bit 200 may be similar to drill bit 100 and may include any of the features described in relation to drill bit 100. Drill bit 200 has a plurality of cutters (PDC or other types) mounted on a plurality of blades. This particular embodiment has six blades, three of which are primary blades 226. The other three are secondary blades 236. The primary blades extend from near the center of the axis of rotation 202, through the cone, nose and shoulder regions, to the gauge of bit 200. In this example, each primary blade 226 is an offset blade. Each secondary blade 236 extends from the nose region of bit 200, through the shoulder region, and then to the gauge of bit 200. Secondary blades 236 are not offset. In alternative embodiments, one or more of the blades may be conventional, non-offset blades. The various features or aspects of the improvements disclosed herein are not limited to a bit with a particular size or number of cutters or blades unless otherwise specifically stated.

The leading edge of a traditional blade, where front wall of the blade transitions to the top surface of the blade and along which the primary cutters are mounted, is curvilinear. However, each offset blade has a leading edge with a pronounced step or set back where it transitions from a first inner region to a second outer region. The distal end of the leading edge of the inner region is rotationally or angularly offset from the proximal end of the leading edge of the outer region, forming a step or offset such that the difference between the angular position of a last cutter (most radially distant) on the inner region and the angular position of the first cutter on the outer region is much greater than the differences in angular positions of the last two cutters on the inner region and the difference in the angular positions of the first two cutters on the outer region. In the illustrated embodiment, each offset blade 226 is continuous, without a gap in the wall of the blade where the offset occurs. However, in alternative embodiments, a small gap between the inner and outer regions may be formed.

As illustrated each offset blade 226 has seven cutters 212-224 (although other numbers of cutters are possible in various embodiments), which are primary cutters. Cutters 212-224 are mounted along a leading edge of the offset blade, adjacent to one of the channels or “junk slots” 234 that extends along the length of the offset blade. The offset blades 226 may also have cutters in the gauge area of drill bit 200, which are not visible in this view of this embodiment. Each offset blade 226 in this example is one continuous blade that has an offset in the blade geometry along the face or front wall of the blade. The offset is, in this embodiment, between cutter 216 and cutter 218. The offset creates two blade regions, a first (or inner) blade region closer to the centerline or axis of rotation 202 of drill bit 200 that extends through the cone region of drill bit 200 to the offset, and a second (or outer) region that extends from the offset, through the nose and shoulder regions, to the gauge of drill bit 200. A proximal end of the outer region is displaced radially (outwardly from the axis of rotation) and angularly from a distal end of the inner region. In this example, the offset in offset blade 226 occurs approximately where the cone region of the bit transitions to the nose region of drill bit 200. However, in other embodiments, the offset may occur in or near other regions of drill bit 200, such in the nose or shoulder, or at the transition of the nose to the shoulder. Furthermore, alternative embodiments of drill bits may have one or more, or all, of the offset blades with more than one offset and different numbers of offsets. For example, an offset blade could have three portions: a first, a second and third, with a first offset between the first two portions and a second offset between the second and third portions. Furthermore, one or more of the offset blades on a bit could have one offset; and one or more of the other offset blades could have two offsets. One or more additional offset blades on the bit could have three or more offsets.

Secondary blades 236 may be used to increase the cutter density of the bit in the nose and shoulder of a bit. Cutters in these regions typically perform much of the work forming a wellbore. As the bit progresses downhole, more material must be removed from the borehole in these regions relative to the cone region because the wider radius of these regions, relative to the cone region, results in a greater surface area of rock that must be removed. The secondary blades allow for balancing the amount of exposed cutter in a region to the area of rock that must be removed from that region. Each of the secondary blades has four primary cutters 238-244 that are visible in this view and may have cutters in the gauge region of drill bit 200 that are occluded from view. Cutters 238-244 each have a fixed position on drill bit 200. The fixed position of a particular cutter being defined by the blade on which the cutter is mounted, the axial distance from the center of rotation of drill bit 200, and the relative radial position of the cutter on the face of drill bit 200.

Drill bit 200 may include a plurality of nozzles 228-232 which are located in a plurality of channels or junk slots 234. Junk slots 234 may be located in front of each of the blades and are defined by the back wall of the blade and a front wall of the following blade (based on a rotational direction of drill bit 200). Nozzles 228-232 direct drilling fluid being pumped through the drill string, which is not shown, toward the cutters to flush cuttings from the face of drill bit 200. Junk slots 234 create room for collecting and evacuating cuttings, with the junk slots direction the flow of drilling fluid and cuttings radially outwardly and then up through the gauge region and into an annulus between the wellbore side wall and the drilling string (not shown.)

Nozzles 230 are in front of the inner region of offset blade 226. The drilling fluid flowing from each nozzle 230 is primarily intended to clear cuttings coming off of primary cutters mounted along a leading of the inner region of each offset blade 226, which in this example are cutters 212, 214, and 216. The drilling fluid flowing from each nozzle 230 is secondarily intended to provide cooling and manage the operating temperature of primary cutters mounted along a leading edge of the inner region of each offset blade 226, which in this example are cutters 212, 214, and 216. Nozzles 230 are therefore directed so that drilling fluid flows across the face of these cutters 212-215 and down junk slot 234 that is between the front of the offset blade 226 and the back side of the secondary blade 236 in front of the offset blade 226.

Nozzles 228 are each tucked into the corner formed in the front wall of the blade formed by the offset in offset blade 226. Each nozzle 228 directs drilling fluid along the outer region of each of offset blades 226, toward faces of cutters 218, 220, 222, and 224, which are primary cutters mounted along a leading edge of the outer region of offset blade 226.

Nozzles 228 are rotationally offset rearwardly with respect to nozzle 230 and radially outwardly. Because each nozzle 228 is rotationally displaced with respect to nozzle 230, fluid flowing from each nozzle 228 tends not to interfere with fluid flow from nozzle 230 or interferes much less than it would if it were not rotationally displaced. Nozzle 230 is aimed so that the drilling fluid from nozzle 230, after flowing across the face of cutters 212, 214, and 218 in the inner region of offset blade 226, tends for flow with the cuttings produced by those cutters primarily through the area between the back of secondary blade 236 and nozzle 228. Fluid flowing from nozzle 228 primarily flows across the face of cutters 218, 220, 222, and 224 and then continues along the front wall or leading edge of the second blade portion of the offset blade 226 into the annular space of the borehole.

Offset blades 226 and secondary blades 236 of drill bit 200 may include sloped surfaces 246 and 248, respectively, on the back of the blades, behind the cutters that are arranged along the leading edge of the blades. The cutting face of the body of drill bit 200, in particular the top surfaces of the blade, act to limit the penetration of the cutters into the formation. The primary cutters extend above the top of the blades or other feature or aspect of the bit that limits how far the cutters can penetrate into rock, which is referred to as cutter exposure. Generally, higher exposures will allow the primary cutters to penetrate deeper into the formation, which can increase the rate that the bit penetrates the formation (the rate of penetration or ROP) to advance the bore hole. On the other hand, if the primary cutter exposure is too high, other problems may arise that might retard rate of penetration or lead to premature failure of cutters and eventual damage or destruction of the drill bit. Therefore, exposure is chosen to optimize ROP while maintaining an acceptable degree of reliability. At high ROP the back part of the top surface of the blades might contact the formation before the front part of the top surface contacts the formation, resulting in added friction and possibly also a shallower penetration than the bit is otherwise capable of. Sloped surfaces 246 and 248 remove some of the blade without substantially weakening it where the back of each blade might otherwise contact the formation during high ROP. Instead of a sloped surface, a step or series of steps could be substituted, but possibly at the cost of added fabrication difficulties and/or a weaker blade.

In some embodiments, the downhole tools described herein may include reamers. FIG. 3 illustrates a reamer 300 for earth boring operations, according to certain embodiments. Reamer 300 may include an upper shaft 302a, a lower shaft 302b, a body 304, and blades 314a-c disposed about body 304. Each blade 314a-c may be separated by channels or “junk slots.” Each blade 314a-c may include one or more cutters 316, which may be PDC cutters in some embodiments. For example, each cutter 316 may include a substrate and a diamond table. The substrate may be formed from a carbon and metal containing material, such as a carbide containing titanium, iron, tungsten, and other suitable metals. The diamond table may include a polycrystalline diamond surface as described above. Each cutter 316 may be inserted into a hollow pocket included in a respective blade 314. The hollow pocket (or “pocket”) may be machined, cast, and/or otherwise formed into reamer 300 during manufacture of reamer 300. Each cutter 316 may be configured such that it corresponds to a specific pocket included in the respective blade 314. For example, a size and shape of each cutter 316 may substantially match (e.g., within about 0.025 inches or less to provide a braze gap for receiving a brazing alloy that joins the cutters with the blade) a size and shape a corresponding pocket that receives the cutter 316.

Reamer 300 may be used, at least in part, to widen a pre-existing hole or bore. For example, the pre-existing hole or bore may be created at a first width by a drill bit similar to drill bits 100 and 200. Reamer 300 may then be inserted into the pre-existing hole or bore to widen the pre-existing hole or bore. As reamer 300 is rotated within the pre-existing hole or bore, cutters 316 may cause material (e.g., earth, rock, etc.) to be removed from the hole or bore.

Although reamer 300 is shown with blades 314a-c disposed vertically between upper shaft 302a and lower shaft 302b, rotated axially with respect to reamer 300, other configurations are possible. For example, blades 314a-c may be disposed vertically between upper shaft 302a and lower shaft 302b with no rotation (parallel to a vertical axis of reamer 300). In another example, blades 314a-c may be arranged about a circumference of reamer 300. Reamer 300 may be a fluted reamer, a winged back reamer, an eccentric reamer, a barrel reamer, and/or any other suitable reamer.

In yet another example, reamer 300 may be an expandable reamer. In such embodiments, blades 314a-c may be enclosed in a housing. During operation, the housing may open and blades 314a-c may extend radially outward from the reamer 300, thus engaging cutters 316 with the formation. In still another example, during periods of non-operation, blades 314a-c may be in a first position in which cutters 316 are not exposed to the formation. During operation, blades 314a-c may rotate and/or extend to a second position in which cutters 316 engage the formation. One of ordinary skill in the art would recognize many different possibilities and configurations.

As disclosed above, the downhole tools described herein may include cutters that are utilized to engage and remove a portion the drilling formation. Each cutter may include a highly wear resistant cutting or wear surface comprised of a polycrystalline diamond (PDC) or similar highly wear resistant material. PDC cutters are typically made by forming a layer of polycrystalline diamond, sometimes called a crown or diamond table, on substrate carbide substrate, such as a tungsten carbide substrate that may include one more additional metal additives in some embodiments. The PDC wear surface may be formed from sintered polycrystalline diamond (either natural or synthetic) exhibiting diamond-to-diamond bonding. Polycrystalline cubic boron nitride, wurtzite boron nitride, aggregated diamond nanotubes (ADN) or other hard, crystalline materials are known substitutes and/or additives and may be useful in some drilling applications. A compact may be made by mixing a diamond grit material in powder form with or without one or more powdered metal catalysts and other materials/additives, forming the mixture into a compact, and then sintering the compact, typically with a tungsten carbide substrate using high heat and pressure. Sintered compacts of polycrystalline cubic boron nitride, wurtzite boron nitride, ADN and similar materials are, for the purposes of description contained below, equivalents to polycrystalline diamond compacts and, therefore, a reference to “PDC” in the detailed description should be construed, unless otherwise explicitly indicated or context does not allow, as a reference to a sintered compacts of polycrystalline diamond, cubic boron nitride, wurtzite boron nitride and other highly wear resistant materials. References to “PDC” are also intended to encompass sintered compacts of these materials with other materials or structure elements that might be used to improve its properties and cutting characteristics. Furthermore, PDC encompasses thermally stable varieties in which a metal catalyst has been partially or entirely removed after sintering. Such PDC cutters can also include “twice-pressed” cutters which involves sintering a diamond table onto a substrate, either planar or non-planar as will be discussed in greater detail below.

Substrates for supporting a PDC wear surface or layer are typically made, at least in part, from cemented metal carbide, with tungsten carbide being the most common. Cemented metal carbide substrates may be formed by sintering powdered metal carbide with a metal alloy binder. The composite of the PDC and the substrate may be fabricated in a number of different ways. The composite may also, for example, include transitional layers in which the metal carbide and diamond are mixed with other elements for improving bonding and reducing stress between the PDC and substrate.

Each PDC cutter may be fabricated as a discrete piece, separate from the downhole tool. Because of the processes used for fabricating them, the polycrystalline diamond layer and substrate typically have a cylindrical shape, with a relatively thin disk of polycrystalline diamond bonded to a taller or longer cylinder of substrate material. The resulting composite can be used as a conventional cutter in a cylindrical shape or may be machined or otherwise formed to a desired non-cylindrical shape. In other embodiments, the substrate and/or diamond table may be pressed or otherwise formed in a non-cylindrical shape and may or may not require machining to have a desired non-cylindrical shape.

By incorporating non-cylindrical cutters into downhole tools, such as drill bits and reamers, may provide several benefits over conventional cylindrical cutters. For example, non-cylindrical cutters may include multiple discrete cutting tips that enable better point loading and may enable drilling efficiency to be increased. Furthermore, the non-cylindrical carbide substrate may reduce or eliminate substrate rubbing on downhole formation at moderate to high depths-of-cut, eliminating the substrate bearing surface that can lead to loss of rate of penetration and/or premature cutter failure due to thermal breakdown. Additionally, the geometry of non-cylindrical cutters and cutter pockets may enable the cutters to be self-aligning within the cutter pockets, such that the cutting tip is positioned at a desired orientation (e.g., cutting position) upon the cutter being inserted into the cutter pocket. Additionally, the presence of multiple discrete cutting tips may enable worn cutters to be removed from the cutter pockets, rotated, and re-brazed into the cutter pockets with a new cutting tip positioned above a top surface of a respective blade. This may enable the cutters to be reused for two or more cycles and may cut down on material waste.

FIGS. 4A-16 illustrate embodiments of non-cylindrical cutters in accordance with the present invention. The non-cylindrical cutters may be used as some or all cutters 112 and 212-224 in drill bits 100 and 200 and/or cutters 316 in reamer 300. Each non-cylindrical cutter may be a PDC cutter and may include a substrate that is used to mount the cutter within a pocket of a downhole tool and a diamond table that is used to engage the cutting formation. FIGS. 4A-4D illustrate a non-cylindrical cutter 400 according to certain embodiments. Cutter 400 may include a body formed from a substrate 402 and a diamond table 404 that is coupled with substrate 402. Cutter 400 may include a central axis 410, which may extend along a length of cutter 400. Substrate 402 may include a base 406, a top surface (not shown) on which diamond table 404 may be mounted, and one or more lateral surfaces 408 that extend between base 406 and the top surface. Similarly, diamond table 404 may include a base (not shown), a top cutting face 412, and one or more lateral surfaces 414 that extend between the base and cutting face 412. As illustrated, cutting face 412 is planar and parallel to base 406, however in some embodiments cutting face 412 may include one or relief features and/or may be angled relative to base 406 as will be described in greater detail below.

Substrate 402 may include a brazing surface, which may include base 406 and all or part of one or more of the lateral surfaces 408. The brazing surface may include a portion of an exterior surface of substrate 402 that may be brazed to a cutter pocket of a downhole tool, such as the portion of the lateral surfaces 408 and/or base 406 that contact and/or are received within the cutter pocket. In other words, the brazing surface or brazeable surface area may include all surfaces that correspond to and/or directly face the walls defining the cutter pocket. In some embodiments, as least a portion of the brazing surface, substrate 402, and/or diamond table 404 may have a non-circular cross-section. For example, a radial distance between the lateral surfaces 408 and/or 414 and the central axis 410 may vary about an outer periphery of the body of cutter 400. The radial distance between the lateral surfaces 408 and/or 414 of cutter 400 and central axis 410 may vary along at least 50% of the outer periphery of cutter 400, at least 60% of the outer periphery, at least 70% of the outer periphery, at least 80% of the outer periphery, at least 90% of the outer periphery, or more. The radial distance between the lateral surfaces 408 and/or 414 of cutter 400 and central axis 410 may vary along at least 75% of a length of the body and/or substrate 402, at least 80% of the length of the body and/or substrate 402, at least 85% of the length of the body and/or substrate 402, at least 90% of the length of the body and/or substrate 402, at least 95% of the length of the body and/or substrate 402, or more. In other words, the cross-section of substrate 402 and/or the body of cutter 400 may be non-circular for at least 75% of a length of the body and/or substrate 402. In some embodiments, only substrate 402 (or a portion thereof) has a non-circular cross-section, while in other embodiments both substrate 402 and diamond table 404 (or portions of one or both components) may have a non-circular cross-section. As used herein, the term cross-sectional shape is understood to mean the cross-sectional shape of a given cutter or cutter pocket taken along a plane that extends through a width of the cutter or cutter pocket and that is normal to a longitudinal axis of the cutter or cutter pocket.

To produce the non-circular cross-sections, rather than having one lateral surface having an arc of constant radius relative to central axis 410, cutter 400 may include multiple distinct lateral surfaces 408 and/or 414, with at least one lateral surface 408 and/or 414 not having an arc of constant radius relative to central axis 410. For example, cutter 400 may include one or more lateral surfaces 408 and/or 414 that are planar and that are joined by one or more corners, which may be sharp or rounded in various embodiments. In other embodiments, one or more lateral surfaces may be rounded, such as convex or concave surfaces. In the illustrated embodiment, lateral surfaces 408 and 414 each include four planar or linear lateral surfaces 408a and 414a that are joined at four corners 408b and 414b to form a generally quadrilateral shape (e.g., a quadrilateral with rounded corners). As illustrated, linear lateral surfaces 408a and 414a are arranged as two pairs of parallel surfaces, with the two pairs being orthogonal relative to one another to form a generally rectangular shaped cross-section, although in other embodiments linear lateral surfaces 408a and/or 414a may be at other angles, such as to form diamond shapes, trapezoids, parallelograms, and/or other quadrilaterals. In some embodiments, each linear lateral surface 408a and 414a may have a same length to create a square-shaped cutter 400. In other embodiments, one opposing pair of linear lateral surface 408a and 414a may be longer than the other pair of linear lateral surface 408a and 414a, which may enable rectangular and/or diamond-shaped cutters 400. In other embodiments, a single linear lateral surface 408a and 414a from one or both opposing pairs may have a different length, enabling asymmetrical cutters 400 to be formed.

As illustrated, corners 408b and 414b are rounded, which may help reduce the amount of pressure applied to corners 408b and 414b as cutter 400 engages a cutting formation. A radius of each corner 408b and 414b may be variable or may be constant. For example, a constant radius may be utilized such that each corner 408b and/or 414b has a same radius through the entire corner 408b and/or 414b. In some embodiments, the radius of each corner 408b and 414b may match that of a circle having a diameter extending between opposing corners 408b and 414b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper corners.

A width of each corner 408b and 414b may vary based on the desired point loading and drilling efficiency, while ensuring that cutter 400 is sufficiently durable to withstand conditions in downhole operations. For example, narrower and/or sharper corners 408b and 414b may increase the point loading and drilling efficiency of cutter 400. However, a minimum width is required to ensure that cutter 400 is strong enough to survive a given number of downhole operations, such as drilling or reaming operations. In a particular embodiment, a width of each corner 408b and 414b may be between 5 degrees and 45 degrees as measured relative to central axis 410.

Each corner 414b of diamond table 404 may form a discrete cutting tip of cutting face 412 that may be positioned on a blade of a downhole tool in a cutting position such that the cutting tip protrudes beyond a top surface of the blade. This positions a corner 414b of diamond table 404 such that corner 414b engages a cutting formation prior to a portion of the blade and enables corner 414b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 408 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 408 to serve as indexing features that are usable to orient cutter 400 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 400 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

Diamond table 404 may include a chamfered edge 416 that extends from cutting face 412 to lateral sides 414 of diamond table 404. For example, chamfered edge 416 may extend from cutting face 412 to lateral sides 414 at an angle of between 20 degrees to 60 degrees relative to cutting face 412. Chamfered edge 416 may reduce the pressure exerted on diamond table 404 by the cutting formation and may help increase the durability of cutter 400. The angle of chamfered edge 416 may be selected to control the aggressiveness of cutting and/or durability of cutter 400.

While FIGS. 4A-4D illustrate non-cylindrical cutters that have generally quadrilateral cross-sections, it will be appreciated that other shapes of non-cylindrical cutters are possible in various embodiments. For example, the diamond table and/or each non-cylindrical cutter may have two or more linear lateral surfaces (and/or concave sides), three or more linear lateral surfaces, four or more linear lateral surfaces, five or more linear lateral surfaces, or more. For example, FIGS. 5A-5D illustrate a non-cylindrical cutter 500 having a generally triangular cross-section. Other than the general cross-sectional shape, cutter 500 may include similar features as cutter 400. For example, cutter 500 may include a body formed from a substrate 502 and a diamond table 504 that is coupled with substrate 502. Cutter 500 may include a central axis 510, which may extend along a length of cutter 500. Substrate 502 may include a base 506, a top surface (not shown) on which diamond table 504 may be mounted, and lateral surfaces 508 that extend between base 506 and the top surface. Similarly, diamond table 504 may include a base (not shown), a top cutting face 512, and three lateral surfaces 514 that extend between the base and cutting face 512. In the illustrated embodiment, lateral surfaces 508 and 514 each include three planar or linear lateral surfaces 508a and 514a that are joined at three corners 508b and 514b to form a generally triangular shape (e.g., a triangle with rounded corners). As illustrated, corners 508b and 514b are rounded, which may help reduce the amount of pressure applied to corners 508b and 514b as cutter 500 engages a cutting formation. A radius of each corner 508b and 514b may be variable or may be constant. For example, a constant radius may be utilized such that each corner 508b and/or 514b has a same radius through the entire corner 508b and/or 514b. In some embodiments, the radius of each corner 508b and 514b may match that of a circle having a diameter extending between opposing corners 508b and 514b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper corners. Diamond table 504 may include a chamfered edge 516 that extends from cutting face 512 to lateral sides 514 of diamond table 504. For example, chamfered edge 516 may extend from cutting face 512 to lateral sides 514 at an angle of between 20 degree and 60 degrees relative to cutting face 512.

Each corner 514b of diamond table 504 may form a discrete cutting tip of cutting face 512 that may be positioned on a blade of a downhole tool in a cutting position such that the cutting tip protrudes beyond a top surface of the blade. This positions a corner 514b of diamond table 504 such that corner 514b engages a cutting formation prior to a portion of the blade and enables corner 514b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 408 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 508 to serve as indexing features that are usable to orient cutter 500 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 500 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

FIGS. 6A-6D illustrate a non-cylindrical cutter 600 having a generally pentagonal cross-section. Other than the general cross-sectional shape, cutter 600 may include similar features as cutters 400 and 500. For example, cutter 600 may include a body formed from a substrate 602 and a diamond table 604 that is coupled with substrate 602. Cutter 600 may include a central axis 610, which may extend along a length of cutter 600. Substrate 602 may include a base 606, a top surface (not shown) on which diamond table 604 may be mounted, and five lateral surfaces 608 that extend between base 606 and the top surface. Similarly, diamond table 604 may include a base (not shown), a top cutting face 612, and lateral surfaces 614 that extend between the base and cutting face 612. In the illustrated embodiment, lateral surfaces 608 and 614 each include five planar or linear lateral surfaces 608a and 614a that are joined at five corners 608b and 614b to form a generally pentagonal shape (e.g., a pentagon with rounded corners). As illustrated, corners 608b and 614b are rounded, which may help reduce the amount of pressure applied to corners 608b and 614b as cutter 600 engages a cutting formation. A radius of each corner 608b and 614b may be variable or may be constant. For example, a constant radius may be utilized such that each corner 608b and/or 614b has a same radius through the entire corner 608b and/or 614b. In some embodiments, the radius of each corner 608b and 614b may match that of a circle having a diameter extending between opposing corners 608b and 614b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper corners. Diamond table 604 may include a chamfered edge 616 that extends from cutting face 612 to lateral sides 614 of diamond table 604. For example, chamfered edge 616 may extend from cutting face 612 to lateral sides 614 at an angle of between 20 degrees and 60 degrees relative to cutting face 612.

Each corner 614b of diamond table 604 may form a discrete cutting tip of cutting face 612 that may be positioned on a blade of a downhole tool such that the cutting tip protrudes beyond a top surface of the blade. This positions a corner 614b of diamond table 604 such that corner 614b engages a cutting formation prior to a portion of the blade and enables corner 614b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 608 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 608 to serve as indexing features that are usable to orient cutter 600 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 600 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

FIGS. 7A-7D illustrate a non-cylindrical cutter 700 having a generally stadium shaped cross-section. In some embodiments, cutter 700 may have a true stadium shape, with two semicircular regions separated by a central rectangular region having a width that matches a diameter of the semicircular regions. In such embodiments, a transition between the semicircular regions and the rectangular region may be seamless. In other embodiments, cutter 700 may have a generally stadium shape, with two arcuate regions, each having less than 180 degrees of a circle, separated by a central rectangular region having a width that is less than a diameter of the semicircular regions. In such embodiments, a transition between the semicircular regions and the rectangular region may result in a corner, which may be rounded or sharp. Other than the general cross-sectional shape, cutter 700 may include similar features as cutters 400, 500, and 600. For example, cutter 700 may include a body formed from a substrate 702 and a diamond table 704 that is coupled with substrate 702. Cutter 700 may include a central axis 710, which may extend along a length of cutter 700. Substrate 702 may include a base 706, a top surface (not shown) on which diamond table 704 may be mounted, and lateral surfaces 708 that extend between base 706 and the top surface. Similarly, diamond table 704 may include a base (not shown), a top cutting face 712, and lateral surfaces 714 that extend between the base and cutting face 712. In the illustrated embodiment, lateral surfaces 708 and 714 each include two planar or linear lateral surfaces 708a and 714a that are each joined by two rounded ends 708b and 714b to form a stadium shape. A radius of each rounded end 708b and 714b may be variable or may be constant. For example, a constant radius may be utilized such that each rounded end 708b and/or 714b has a same radius through the entire rounded end 708b and/or 714b. In some embodiments, the radius of each rounded end 708b and 714b may match that of a circle having a diameter extending between the two rounded ends 708b and 714b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper ends. Diamond table 704 may include a chamfered edge 716 that extends from cutting face 712 to lateral sides 714 of diamond table 704. For example, chamfered edge 716 may extend from cutting face 712 to lateral sides 714 at an angle of between 20 degrees and 60 degrees relative to cutting face 712.

Each rounded end 714b of diamond table 704 may form a discrete cutting tip of cutting face 712 that may be positioned on a blade of a downhole tool such that the cutting tip protrudes beyond a top surface of the blade. This positions a rounded end 714b of diamond table 704 such that rounded end 714b engages a cutting formation prior to a portion of the blade and enables rounded end 714b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 408 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 408 to serve as indexing features that are usable to orient cutter 400 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 400 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

FIGS. 8A-8D illustrate a non-cylindrical cutter 800 having a generally hexagonal cross-section. Other than the general cross-sectional shape, cutter 800 may include similar features as cutters 400, 500, 600, and 700. For example, cutter 800 may include a body formed from a substrate 802 and a diamond table 804 that is coupled with substrate 802. Cutter 800 may include a central axis 810, which may extend along a length of cutter 800. Substrate 802 may include a base 806, a top surface (not shown) on which diamond table 804 may be mounted, and lateral surfaces 808 that extend between base 806 and the top surface. Similarly, diamond table 804 may include a base (not shown), a top cutting face 812, and lateral surfaces 814 that extend between the base and cutting face 812. In the illustrated embodiment, lateral surfaces 808 and 814 each include six planar or linear lateral surfaces 808a and 814a that are joined at six corners 808b and 814b to form a generally hexagonal shape (e.g., a hexagon with rounded corners). As illustrated, corners 808b and 814b are rounded, which may help reduce the amount of pressure applied to corners 808b and 814b as cutter 800 engages a cutting formation. A radius of each corner 808b and 814b may be variable or may be constant. For example, a constant radius may be utilized such that each corner 808b and/or 814b has a same radius through the entire corner 808b and/or 814b. In some embodiments, the radius of each corner 808b and 814b may match that of a circle having a diameter extending between opposing corners 808b and 814b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper corners. Diamond table 804 may include a chamfered edge 816 that extends from cutting face 812 to lateral sides 814 of diamond table 804. For example, chamfered edge 816 may extend from cutting face 812 to lateral sides 814 at an angle of between 20 degrees and 60 degrees relative to cutting face 812.

Each corner 814b of diamond table 804 may form a discrete cutting tip of cutting face 812 that may be positioned on a blade of a downhole tool such that the cutting tip protrudes beyond a top surface of the blade. This positions a corner 814b of diamond table 804 such that corner 814b engages a cutting formation prior to a portion of the blade and enables corner 814b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 808 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 808 to serve as indexing features that are usable to orient cutter 800 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 800 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

FIGS. 9A-9D illustrate a non-cylindrical cutter 900 having a generally rectangular cross-section with concave, rather than linear lateral surfaces. Other than the general cross-sectional shape, cutter 900 may include similar features as cutters 400, 500, 600, 700, and 800. For example, cutter 900 may include a body formed from a substrate 902 and a diamond table 904 that is coupled with substrate 902. Cutter 900 may include a central axis 910, which may extend along a length of cutter 900. Substrate 902 may include a base 906, a top surface (not shown) on which diamond table 904 may be mounted, and lateral surfaces 908 that extend between base 906 and the top surface. Similarly, diamond table 904 may include a base (not shown), a top cutting face 912, and lateral surfaces 914 that extend between the base and cutting face 912. In the illustrated embodiment, lateral surfaces 908 and 914 each include four concave lateral surfaces 908a and 914a that are joined at four corners 908b and 914b to form a generally rectangular shape (e.g., a rectangular with inwardly curved sides and rounded corners). Each concave lateral surface 908a and 914a may have a constant radius or a variable radius in some embodiments. It will further be appreciated that in some embodiments, rather than having concave lateral surfaces, cutter 900 may have convex lateral surfaces. As illustrated, corners 908b and 914b are rounded, which may help reduce the amount of pressure applied to corners 908b and 914b as cutter 900 engages a cutting formation. A radius of each corner 908b and 914b may be variable or may be constant. For example, a constant radius may be utilized such that each corner 908b and/or 914b has a same radius through the entire corner 908b and/or 914b. In some embodiments, the radius of each corner 908b and 914b may match that of a circle having a diameter extending between opposing corners 908b and 914b, although larger or smaller radii may be utilized in various embodiments to make softer or sharper corners.

Diamond table 904 may include a chamfered edge 916 that extends from cutting face 912 to lateral sides 914 of diamond table 904. For example, chamfered edge 916 may extend from cutting face 912 to lateral sides 914 at an angle of between 20 degrees and 60 degrees relative to cutting face 912.

Each corner 914b of diamond table 904 may form a discrete cutting tip of cutting face 912 that may be positioned on a blade of a downhole tool such that the cutting tip protrudes beyond a top surface of the blade. This positions a corner 914b of diamond table 904 such that corner 914b engages a cutting formation prior to a portion of the blade and enables corner 914b to fail the rock or other material forming the cutting formation as the downhole tool rotates within a borehole. Additionally, the presence of one or more lateral surfaces 908 that have non-constant circular arcs (e.g., are linear and/or having variable and/or concave arcs) may enable such lateral surfaces 908 to serve as indexing features that are usable to orient cutter 900 in a corresponding cutter pocket in a cutting position in which a cutting tip of cutter 900 protrudes beyond a top surface of the blade at a desired angle relative to a top and/or front surface of the blade.

While shown with each cutter having a cross-section of a regular shape, it will be appreciated that cutters having irregular shaped cross-sections may be utilized in various embodiments. Additionally, cutters in accordance with the present invention may include circular cross-sections along a portion of a length of the cutter, with the cross-section transitioning to one or more non-circular shapes that collectively extend for at least 75% of the length of the cutter. Similarly, a cross-sectional shape of all or a portion of the diamond table may be different than a cross-sectional shape of some or all of a substrate of the cutter in some embodiments. Oftentimes, a cross-sectional shape of a cutter (or portion thereof) may be formed from two or more linear lateral surfaces that are connected to one another via a number of rounded corners or ends. In such embodiments, a ratio of a length of the linear lateral surfaces to a length of the rounded corners/ends (e.g., a ratio of the outer periphery of the non-circular cross section that is formed from straight surfaces to curved surfaces) may be between 0.5:1 and 10:1, between 0.5:1 and 5:1, between 0.5:1 and 4:1, between 0.5:1 and 3:1, between 0.5:1 and 2.5:1, between 0.5:1 and 2:1, between 0.5:1 and 1.5:1, between 0.5:1 and 1:1, or between 0.5:1 and 0.75:1. In some embodiments, the non-cylindrical cutters described herein may be symmetrical about one or more planes or axes. For example, the cutters may be is symmetrical about two perpendicular planes that extend through both the substrate and the diamond table. This may be the case, for example, with rectangular cutters such as cutter 400, hexagonal cutters such as cutter 800, rectangular cutters with concave sides such as cutter 900 and stadium shaped cutters such as cutter 700. In particular, cutter 400 may be symmetrical about two perpendicular planes that each bisect different pairs of opposing lateral surfaces 408a and 414a and/or about two perpendicular planes that each bisect different pairs of opposing corners 408b and 414b. In other embodiments, the cutters may be asymmetric and/or symmetric about two or more planes that are not orthogonal to one another, such as with triangular cutter 500 and pentagonal cutter 600.

In some embodiments, rather than having diamond tables with planar cutting surfaces as shown in FIGS. 4A-9D, cutters may include diamond tables with non-planar cutting surfaces. For example, the cutting surfaces may include one or more relief features, such as protruding features that extend in a direction opposite the substrate and/or recessed features that extend toward the substrate. The inclusion of relief features may serve different purposes. For example, protruding relief features may increase the thickness of the diamond table to add strength to the cutter, while also improving the point loading of the cutter, as the cutting tip protrudes away from the rest of the diamond table to engage the formation before any other portion of the cutter. Recessed relief features on areas near, but not extending through a cutting tip, may similarly improve the point loading by making the cutting tip extend away from the surrounding portion of the diamond table. FIGS. 10A-12D illustrate different embodiments of cutters having non-planar cutting surfaces in accordance with the present technology. Turning to FIGS. 10A-10D, a rectangular cutter 1000 is illustrated. Cutter 1000 may be similar to rectangular cutter 400 and may include any of the features described in relation to cutter 400. For example, cutter 1000 may include a body that is formed from a substrate 1002 and a diamond table 1004 that is coupled with the substrate 1002. Diamond table 1004 may include a cutting surface that is configured to engage a cutting formation during a downhole operation. Cutting surface 1012 of diamond table 1004 may include one or more relief features that protrude away from and/or are recessed toward substrate 1002. For example, as illustrated diamond table 1004 include a ridge 1020 that extends from one corner of cutting surface 1012 to an opposing corner of cutting surface 1012. Ridge 1020 may have a flat apex, an angled apex, and/or a curved apex in various embodiments. Ridge 1020 is a protruding feature that extends a direction opposite substrate 1002, thereby increasing a thickness of diamond table 1004 at the corners through which ridge 1020 extends. A thickness of diamond table 1004 may taper or otherwise change from a thinnest point proximate the corners that do not include ridge 1020 to a thickest point at an apex of ridge 1020. The taper may be linear as shown here, or may be curved and/or stepped in some embodiments. A difference in thickness between the thickest and thinnest regions of diamond table 1004 may be between 0.005 inch and 0.300 inch, with a total thickness of diamond table 1004 being between 0.050 inch and 0.350 inch.

FIGS. 11A-11D illustrate an embodiment of a rectangular cutter 1100 having multiple relief features. Cutter 1100 may be similar to rectangular cutters 400 and 1000 and may include any of the features described in relation to cutters 400 and 1000. For example, cutter 1100 may include a body that is formed from a substrate 1102 and a diamond table 1104 that is coupled with the substrate 1102. Diamond table 1104 may include a cutting surface that is configured to engage a cutting formation during a downhole operation. Cutting surface 1112 of diamond table 1104 may include one or more relief features that protrude away from and/or are recessed toward substrate 1102. For example, as illustrated diamond table 1104 include two ridges 1120 that each extend from one corner of cutting surface 1112 to an opposing corner of cutting surface 1112. Each ridge 1120 is a protruding feature that extends a direction opposite substrate 1102, thereby increasing a thickness of diamond table 1104 at the corners through which each ridge 1120 extends. The two ridges 1120 may intersect at a center of cutting surface 1112 and may form a thickest region of diamond table 1104. For example, a thickness of diamond table 1104 may taper or otherwise change from a thinnest point proximate midpoints of linear lateral surfaces that extend between adjacent corners of diamond table 1104 to a thickest point at an apex of each ridge 1120. The taper may be linear and may create V-shaped valleys between each pair of adjacent corners of diamond table 1104 as shown here, or may be curved and/or stepped in some embodiments. A difference in thickness between the thickest and thinnest regions of diamond table 1104 may be between 0.005 inch and 0.300 inch, with a total thickness of diamond table 1104 being between 0.050 inch and 0.350 inch.

While shown here with ridges or other protruding relief features extending through the corners/cutting tips of a given cutter, it will be appreciated that some embodiments of cutters may include recessed relief features instead of or in addition to protruding relief features. Such recessed relief features may produce areas of lower thickness of the diamond table and may make the cutting tips more pronounced to improve point loading. Oftentimes, recessed relief features may be positioned between two or more protruding relief features to create a deeper or more pronounced valley between the protruding relief features. Additionally, the presence of one or more recessed relief features may make the cutting tips more pronounced and may improve the point loading and drilling efficiency of the cutter.

In some embodiments, rather than having distinct relief features such as ridges, grooves, and the like, cutters may include sloped surfaces that effectively impart forward rake on the cutting surface. FIGS. 12A-13D illustrate cutters having forward rake in accordance with embodiments of the present invention. For example, FIGS. 12A-12D illustrate a rectangular cutter 1200 having forward rake. Cutter 1200 may be similar to rectangular cutter 400 and may include any of the features described in relation to cutter 400. For example, cutter 1200 may include a body that is formed from a substrate 1202 and a diamond table 1204 that is coupled with the substrate 1202. Diamond table 1204 may include a cutting tip 1222 that is configured to engage a cutting formation during a downhole operation. Cutting surface 1212 of diamond table 1204 may be tapered or otherwise sloped such that diamond table 1204 is thickest at the cutting tip 1222 of diamond table 1204. For example, as illustrated diamond table 1204 slopes from a thinnest point proximate a corner of diamond table 1204 opposite the cutting tip 1222 to a thickest point at cutting tip 1222. The slope may be linear as shown here or may be curved and/or stepped in some embodiments. A difference in thickness between the thickest and thinnest regions of diamond table 1204 may be between 0.005 inch and 0.300 inch, with a total thickness of diamond table 1204 being between 0.050 inch and 0.350 inch. The increased thickness at cutting tip 1222 may impart forward rake on cutter 1200 when cutter 1200 is installed in a pocket of a downhole tool in a cutting position with cutting tip 1222 protruding beyond a top surface of a blade of the downhole tool. The forward rake ensures that cutter 1200 is tilted forward in the direction of bit rotation such that an angle between cutting face 1212 and the formation in front of cutting face 1212 is greater than 90°. Front rake may enable cutter 1200 to penetrate deeper into the cutting formation.

In some embodiments, a cutter having forward rake may be dual-sided. FIGS. 13A-13D illustrate a dual-sided rectangular cutter 1300 having forward rake. Cutter 1300 may be similar to rectangular cutters 400 and 1000 and may include any of the features described in relation to cutters 400 and 1000. For example, cutter 1300 may include a body that is formed from a substrate 1302 and a diamond table 1304 that is coupled with the substrate 1302. Diamond table 1304 may include a cutting surface 1312 having two cutting tips 1322 that are each configured to engage a cutting formation during a downhole operation. Cutting tips 1322 may be positioned on opposite corners of diamond table 1304 such that only one cutting tip 1322 is used to fail the cutting formation at a given time, which enables cutter 1300 to be rotated after use to expose a different cutting tip 1322 after a first cutting tip 1322 has been worn. Cutting surface 1312 of diamond table 1304 may be tapered or otherwise sloped such that diamond table 1304 is thickest at cutting tips 1322 of diamond table 1304. For example, as illustrated diamond table 1304 slopes from a thinnest point proximate a centerline of diamond table 1304 that extends through corners of diamond table 1304 that do not form cutting tips 1322 to a thickest point at each cutting tip 1322. The slope may be linear as shown here or may be curved and/or stepped in some embodiments. A difference in thickness between the thickest and thinnest regions of diamond table 1304 may be between 0.005 inch and 0.300 inch, with a total thickness of diamond table 1304 being between 0.050 inch and 0.350 inch. The increased thickness at each cutting tip 1322 may impart forward rake on cutter 1300 when cutter 1300 is installed in a pocket of a downhole tool in a cutting position with one cutting tip 1322 protruding beyond a top surface of a blade of the downhole tool. The forward rake ensures that cutter 1300 is tilted forward in the direction of bit rotation such that an angle between cutting face 1322 and the formation in front of cutting face 1312 is greater than 90°. Front rake may enable cutter 1300 to penetrate deeper into the cutting formation.

While FIGS. 10A-12D illustrate relief features formed on the cutting surfaces of rectangular cutters, it will be appreciated that similar relief features may be incorporated into cutters having other non-circular cross-sectional shapes. Additionally, cutters may be formed with any number of relief features. For example, each cutting tip of a given cutter may include a protruding feature in some embodiments. The relief features may be distinct elements that are separated by regions of different diamond table thickness and/or may be continuous regions that have a greater or lesser thickness than other regions of the diamond table. It will be appreciated that protruding features are not limited to being positioned at cutting tips of a cutter and that areas of the diamond table that are not intended as cutting tips may include protruding features.

As described above, the cutters described herein may include a chamfered edge that extends from a cutting surface of a diamond table to a lateral surface of the diamond table. The chamfered edge may increase the surface area of the cutting tip and eliminate sharp angles that may result in high force concentrations that may prematurely damage the cutter. In some embodiments, the chamfered edge may be uniform about an entire outer periphery of the cutting face, with an angle and depth of the chamfered edge being consistent about the entire outer periphery of the cutting face. In other embodiments, the angle and/or depth of the chamfered edge may vary along the outer periphery of the cutting face. FIGS. 14A-14C illustrate embodiments of a cutter 1400 that includes a chamfered edge 1416 that extends from a cutting surface 1414 of a diamond table 1404 to a lateral surface 1414 of diamond table 1404. As illustrated in FIG. 14A, chamfered edge 1416a is widest proximate two corners and narrows toward two opposing corners. The change in width may be controlled by changes to a depth (e.g., distance from cutting surface 1412 to lateral surface 1414) of the chamfer and/or angle of the chamfer. In some embodiments, transitions from one chamfer width to another may be done along a lateral surface 1414 and/or along a corner of cutting surface 1412. Transitions in width may be linear and/or arc shaped. As shown in FIG. 14B, chamfered edge 1416b is widest proximate a first pair of opposing corners and thinnest at the other pair of opposing corners. In the illustrated embodiment, transitions between the wide chamfer region and the narrow chamfer region are linear. FIG. 14C illustrates a similar chamfered edge 1416c in which transitions between wide chamfer regions and narrow chamfer regions are arc shaped, with the arc being concave relative to cutting surface 1412c. In some embodiments, the wider regions of chamfered edge 1416 may be used at cutting tips, while in other embodiments the narrower regions of chamfered edge 1416 may be used as cutting tips. In some embodiments, different cutting tips on a single cutter 1400 may have different geometries of chamfered edge 1416 to enable cutter 1400 to be oriented with a particular cutting tip in the cutting position to meet the needs of a particular downhole operation, enabling a single cutter 1400 to provide different cutting parameters.

In some embodiments, a width of chamfered edge 1416 may be between about 0.005 inches and 0.040 inches, with differences between widest and narrowest regions often being between 0.005 inches and 0.035 inches and more commonly between 0.010 inches and 0.025 inches. An angle of chamfered edge 1416 may be between 20 and 60 degrees relative to cutting surface 1412, although the angle is more commonly between 30 degrees and 50 degrees. Chamfered edge 1416 may extend through cutting surface 1412 and/or lateral surface 1414 at angles to form sharp corners and/or may be formed with a radius to soften the corners. Oftentimes, chamfered edge 1416 is at least partially formed using laser grinding techniques, which may enable chamfered edge 1416 to include a mixture of geometries.

In some embodiments, an angle of the chamfered edge relative to the cutting face may vary along a periphery of the cutting face. For example, the angle of the chamfered edge relative to the cutting face may be greater at a cutting region of the cutting face than at a medial region of the cutting face. In other embodiments, the angle of the chamfered edge relative to the cutting face may be lower at a cutting region of the cutting face than at a medial region of the cutting face. In some embodiments, a depth of the chamfered edge may vary along a periphery of the cutting face. For example, the depth of the chamfered edge may be greater at a cutting region of the cutting face than at a medial region of the cutting face. In other embodiments, the depth of the chamfered edge may be lower at a cutting region of the cutting face than at a medial region of the cutting face.

As described above, each cutter may include a substrate and a diamond table that is coupled with the substrate. The substrate may include an interface formed into a surface of the substrate that faces the diamond table. The interface may be formed by pressing, molding, and/or etching the substrate such that the interface protrudes from the top surface of the substrate in a direction of the diamond table. The interface may generally correspond to a peripheral shape of the top surface of the substrate and/or a peripheral shape of the diamond table. For example, in a conventional cylindrical substrate, a cylindrical interface may protrude upward from the top surface of the substrate. The diamond table may therefore include a corresponding (e.g., substantially same size and shape) recess, such that the substrate and the diamond table may be connected via insertion of the cylindrical interface into the recess of the diamond table. In non-cylindrical cutters, such as those described above, the interface may be a non-planar interface (NPI) that has a non-circular cross-section, which may match a cross-sectional shape of the substrate and/or diamond table. In other words, a shape of an outer periphery of the non-planar interface may match a shape of an outer periphery of a topmost planar surface of the substrate and/or an outer periphery of the diamond table. This may enable force being transmitted through the cutter to be more evenly distributed across the interface between diamond table and substrate and/or to prevent weak spots from being formed within the diamond table.

FIG. 15 illustrates one embodiment of a non-cylindrical cutter 1500 with a non-cylindrical non-planar interface 1530. Cutter 1500 may be similar to cutters 400-1400 described herein and may include any of the features described in relation to those cutters. Additionally, each of cutters 400-1400 may incorporate non-planar interfaces such as those described herein. Cutter 1500 may include a substrate 1502 and a diamond table 1504. Cutter 1500 may have a generally rectangular cross-section similar to cutter 400. NPI 1530 may include an outer periphery having a shape that substantially matches an outer periphery of the perimeter of the top surface 1515 of diamond table 1504 such that spacing between edges of NPI 1530 and an edge of substrate 1502 and/or diamond table 1504 is substantially consistent (e.g., within 20%, within 15%, within 10%, within 5%, within 3%, within 1%, or less) about an entire periphery of substrate 1502 and/or diamond table 1504. A top surface of NPI 1530 may be planar or non-planar. For example, as illustrated NPI 1530 includes ridges 1532 and grooves 1534, with each ridge 1532 having a same size and shape and each groove 1534 having a same size and shape. In other embodiments, NPI 1530 may include a lattice pattern, honeycomb pattern, ridges, rings, etc. that enable a portion of the diamond table to be pressed into voids formed within the pattern. Additionally, in some embodiments, the ridges, grooves, and/or other non-planar features may have different sizes and/or shapes across the length and/or width of NPI 1530.

FIG. 16 illustrates multiple views of one embodiment of a shaped cutter 1600 with an NPI 1630 having a variable thickness across a surface area of NPI 1630. Cutter 1600 may be similar to cutters 400-1500 described herein and may include any of the features described in relation to those cutters. Cutter 1600 may include a substrate 1602 and diamond table 1604 that have non-circular cross-sections at a top surface of substrate 1602 and about all of diamond table 1604. Diamond table 1604 may include a relief feature, such as protruding ridge 1620. As illustrated, ridge 1620 may extend across a diameter of diamond table 1604, extending from a depression 1619 in substrate 1602 to another depression 1619 on an opposing side of substrate 1602, although other orientations are possible in various embodiments. Although only one relief feature in diamond table 1604 is shown, diamond table 1604 may include any number of relief features of various shapes and sizes. As illustrated, a thickness of NPI 1630 may vary in accordance with the thickness of diamond table 1604. For example, where diamond table 1604 includes protruding ridge 1620, a thickness of NPI 1630 may increase in a region that corresponds to (e.g., is below and supporting) protruding ridge 1620. In some embodiments, a change in thickness of NPI 1630 within the region below ridge 1620 may be the same as a protrusion distance of ridge 1620, while in other embodiments the protrusion distance may be greater or less than the change in thickness of NPI 1630. Similarly, where diamond table 1604 includes a recessed relief feature, a thickness of NPI 1630 may decrease in a region that corresponds to (e.g., is below and supporting) the recessed relief feature. In some embodiments, a change in thickness of NPI 1630 within the region below the recessed relief feature may be the same as a depth of the recessed relief feature, while in other embodiments the depth may be greater or less than the change in thickness of NPI 1630.

As discussed above, each cutter may be received within a pocket formed within a blade of a downhole tool, such as a drill bit or a reamer. For non-cylindrical cutters, the corresponding pockets may also have non-cylindrical shapes (i.e., do not consist solely of circular or partial circular cross-sections). In particular, a size and shape of each pocket may substantially match that of at least a portion of the cutter that is being inserted into the pocket. This may enable the non-cylindrical cutters to be securely received within the cutter pocket without permitting rotation of the cutter within the pocket. Outer dimensions of the pocket may be slightly larger than the outer dimensions of the cutter, such as by between 0.01 inch and 0.025 inch. This may provide sufficient a gap for braze material that is used to join the cutter to walls defining the pocket, while still limiting the ability of the cutter to rotate within the pocket. Insertion of the cutter into the pocket may therefore completely or substantially orient the cutter in a proper position relative to the blade. More specifically, due to the non-circular cross-section of the pocket and cutter, insertion of the cutter into the blade may result in a cutting tip of the cutter being at a desired angle and projection distance beyond a top surface of the blade (e.g., in a cutting position), with little to no alignment effort by an installer due to the small size of the braze gap. Additionally, for cutters having multiple discrete cutting tips, any number of cutting tips may be placed in the cutting position, enabling the cutter to be removed from the pocket after some use, rotated, and inserted with a different cutting tip in the cutting position, thereby increasing the usable life of the cutter.

While described as being non-cylindrical or as having non-circular cross-sections, it will be appreciated that the pockets described herein may not fully surround the lateral surfaces of a given cutter. For example, a given pocket may only surround between 40% and 95% of the length of the outer periphery of a cutter, with the remaining portion of the cutter being exposed beyond a top surface of the blade on which the pocket is formed. Thus, as used herein, a cylindrical pocket or pocket having a circular cross-section is meant to refer to a pocket in which for greater than 25% of the length of the pocket, a cross-section of the pocket is defined by a single sidewall of a constant radius (possibly with some of the circle missing as the pocket may be open at the top surface of the blade). In contrast, a non-cylindrical pocket or pocket having a non-circular cross-section is meant to refer to a pocket in which at least 10% a non-circular cross-section of the pocket is defined by one or more sidewalls having a variable radius, one or more sidewalls with curvature that is not concentric with the central axis of the cutter pocket, and/or one or more sidewalls including one or more linear and/or convex features, with the non-circular cross-section extending for at least the forwardmost 10% of a length of the cutter pocket, at least the forwardmost 20% of the length, at least the forwardmost 30% of the length, at least the forwardmost 40% of the length, at least the forwardmost 50% of the length, at least the forwardmost 60% of the length, at least the forwardmost 70% of the length, at least the forwardmost 75% of the length, at least the forwardmost 80% of the length, at least the forwardmost 85% of the length, at least the forwardmost 90% of the length, at least the forwardmost 95% of the length, or more, possibly including the entire length. This may enable a front end of the cutter pocket and a front end of the corresponding cutter to index the cutter within a proper orientation relative to the cutter pocket and blade. Embodiments in which the non-circular cross-section extends for all or a majority of the length of the cutter pocket may be beneficial in improving the drilling efficiency, as corresponding cutters will have lower volumes of the substrate extending beyond the top surface of the blade and may therefore provide less resistance to rotation than conventional cylindrical cutters when engaged with the formation.

Moreover, when a cutter pocket is referred to as having a specific cross-sectional shape, it is meant that the cutter pocket is created as a void formed in a blade by a portion of the recited shape such that a cutter having a same cross-sectional size and shape would be able to fit in the pocket without modification. For example, where a pocket is described as having a rectangular cross-section, the pocket may only define between 40% and 95% of a rectangular cross-section and may therefore appear more triangular, pentagonal, or otherwise non-rectangular. However, a rectangular cutter may be inserted into the pocket and enable a discrete cutting tip of the cutter to protrude beyond the top surface of the blade.

The non-cylindrical pockets may be manufactured into the drill bit and/or reamer in non-cylindrical form, or an existing pocket (e.g., cylindrical or a different non-cylindrical shape) may be modified into a non-cylindrical pocket. For example, one or more shims may be inserted into an existing pocket such that the existing pocket is now non-cylindrical. The non-cylindrical pocket may then accept a corresponding non-cylindrical cutter, such as those as described above. In some embodiments, each shim may be inserted into the pocket, then brazed with the corresponding cutter. In other embodiments, each shim may first be brazed, welded, or otherwise attached within the existing pocket prior to a cutter being inserted.

FIG. 17 illustrates a drill bit 1700 without any cutters. Drill bit 1700 may be similar to drill bits 100 and 200 and may include any features described in relation to drill bits 100 and 200. For example, drill bit 1700 may include a bit body 1704 that is designed to be rotated about a central bit axis 1702. Bit body 1704 may include one or more raised blades 1710 that extend from the face of bit body 1704. In some embodiments, blades 1710 extend radially along the bit face and are circumferentially spaced structures extending along the leading end or formation engaging portion of bit body 1704. Each blade 1710 may extend generally in a radial direction, outwardly to the periphery of bit body 1704. For example, blades 1710 may generally extend from the cone region proximate the longitudinal axis, or central axis 1702, of the bit, upwardly to the gauge region, or maximum drill diameter of bit. Channels formed between adjacent blades may form the junk slots that provide paths for drilling fluid and formation cuttings to be carried up the wellbore. As drill bit 1700 is rotated within the wellbore via the drill string, drilling fluid may be pumped down the drill string, through the internal fluid plenum and fluid passageways within bit body 1704 of drill bit 1700, and out from drill bit 1700 through nozzles 1717.

Each blade 1710 may define a number of cutter pockets 1720, with each cutter pocket being configured to receive a cutter, such as cutters 112, 212-224, 316, and 400-1600. Some or all cutter pockets 1720 may include a non-circular cross-section. For example, cutter pockets 1720a may have cross-sections that are rectangular, triangular, pentagonal, stadium-shaped, and/or other non-circular shapes. Each cutter pocket 1720a may be configured to receive a non-cylindrical cutter, such as cutters 400-1600 described herein. For example, each cutter pocket 1720a may have a generally rectangular cross-section, such as with at least two orthogonal linear sides and a rounded corner coupling the two orthogonal linear sides. In some embodiments, one or more additional corners and/or linear sides may be included, such as where a given cutter pocket 1720a surrounds greater than 50% of the perimeter of a corresponding cutter. Some or all of the pockets may surround different amounts of a cutter. In some embodiments, a width of each rounded corner may be between 5 degrees and 45 degrees as measured from a central axis of the cutter pocket.

In some embodiments, drill bit 1700 may also include one or rows of backup cutter pockets 1722 disposed on one or more blades 1710. For example, some blades 1710 may include two rows of cutter pockets 1720 (and subsequently cutters), with one row being substantially behind a first row of primary cutter pockets 1720 that extend through a leading edge of the respective blade 1710. In some embodiments, the backup cutter pockets 1722 may be at a same radial position as a corresponding cutter pocket 1720, while in other embodiments backup cutter pockets 1722 may be at different radial positions than the primary cutter pocket 1720.

In some embodiments, drill bit 1700 may include a number of conventional, cylindrical cutter pockets 1720b, which may be configured to receive conventional cylindrical cutters. For example, as illustrated, cutter pockets 1720b within the nose region of drill bit 1700 include cylindrical cutter pockets 1720b, with the non-cylindrical cutter pockets 1720a being disposed radially outward of cylindrical cutter pockets 1720b. It will be appreciated that other variations are possible and that cylindrical cutter pockets 1720b may be at other radial positions and/or may be entirely omitted in some embodiments.

In some embodiments, each blade 1710 may include one or more knuckles 1730 that protrude from a top surface of blade 1710 and are in alignment with a respective cutter pocket 1720 or 1722. Each knuckle 1730 may support a portion of a base of a cutter that is seated within the respective cutter pocket 1720 or 1722. In some embodiments, each knuckle 1730 may have a size and shape that substantially corresponds to a size and shape of a portion of the cutter that extends above the top surface of the blade 1710 on which the cutter is mounted. For example, if a portion of a rectangular cutter that protrudes above the top surface of blade 1710 is generally triangular in shape, a front surface of knuckle 1730 may have a generally triangular shape. Thus, the base of each cutter pocket 1720 or 1722 and the front face of a corresponding knuckle 1730 may collectively extend behind a full base of a cutter received within the cutter pocket 1720 or 1722 and may provide additional support to the cutter against a direction of rotation during downhole operations. In some embodiments, a cross-sectional size and shape of each knuckle 1730 may substantially match and/or be smaller than a cross-sectional area of the portion of the cutter that protrudes beyond the top surface of blade 1710. Such a design may ensure that knuckle 1730 does not engage the cutting formation and may help reduce wear to knuckle 1730. A top surface of each knuckle 1730 may taper downward toward the top surface of blade 1710 in a direction away from cutter pocket 1720 or 1722. In other embodiments, the transition from the front surface of knuckle 1730 to the top surface of blade 1710 may be stepped. A cross-sectional shape of each knuckle 1730 may remain constant throughout the transition or may vary.

While shown with only rectangular cutter pockets and cylindrical cutter pockets, it will be appreciated that any arrangement of cutter pockets of different shapes may be incorporated into a single drill bit. For example, each cutter shape may create a cutting tip having different cutting characteristics. Cutter pockets and cutters of a drill bit may be selected to create a specific cutting profile that delivers a given performance result.

FIGS. 18A-18C illustrate non-cylindrical cutter pockets with non-cylindrical cutters inserted therein and demonstrate possible cutting positions for non-cylindrical cutters. Cutter pockets 1800 may represent cutter pockets formed on a blade of a downhole tool, such as drill bits 100, 200, and 1700 and reamer 300. For example, FIG. 18A illustrates a generally rectangular cutter pocket 1800a and a generally rectangular cutter 1802a. Cutter 1802a may be similar to cutter 400 and may include four linear lateral surfaces that are arranged as two pairs of parallel surfaces and joined by four corners, with the two pairs of linear lateral surfaces being orthogonal relative to one another to form a generally rectangular shaped cross-section. Each corner of cutter 1802a may form a discrete cutting tip that may protrude above a top surface of cutter pocket 1800a and the blade within which cutter pocket 1800a is formed. In some embodiments, cutter pocket 1800a may be sized such that only two orthogonal linear surfaces and a single corner are provided. In other embodiments, two or three corners may be included, possibly with portions of one or two additional linear surfaces. Where more than 50% of a perimeter of cutter 1802a is constrained, cutter 1802a may be front loaded into pocket 1800a, which may help retain cutter 1802a within pocket 1800a during downhole operations, as the only direction cutter 1802a may be removed is in the direction of rotation of the downhole tool. In some embodiments, a knuckle 1804a may be provided behind pocket 1800a. Knuckle 1804a may have a generally triangular shape such that a base of cutter pocket 1802a and a front face of knuckle 1804a may collectively extend behind a full base of cutter 1802a to provide additional support to cutter 1802a in a direction of rotation during downhole operations. Due to the size and shape of cutter pocket 1800a and cutter 1802a, cutter 1802a may be inserted into cutter pocket 1800a in four different orientations, with each orientation aligning a different cutting tip of cutter 1802a in the cutting position. In some embodiments, each cutting tip maybe identical, while in other embodiments one or more cutting tips may include different relief features and/or chamfered edges as described herein. This may enable a single cutter 1802a to be inserted in different orientations to provide a consistent result (in the event of identical cutting tips) or tailored results (in the event of cutting tips with different characteristics) and may enable cutter 1802a to be reused even after one cutting tip has been damaged.

FIG. 18B illustrates a generally triangular cutter pocket 1800b and a generally triangular cutter 1802b. Cutter 1802b may be similar to cutter 500 and may include three linear lateral surfaces that are arranged at 120 degree angles with respect to one another and joined by three corners to form a generally rectangular shaped cross-section. Each corner of cutter 1802b may form a discrete cutting tip that may protrude above a top surface of cutter pocket 1800b and the blade within which cutter pocket 1800b is formed. Cutter pocket 1800b may be sized to include a linear bottom surface, two corners, and portions of two linear sidewalls that are at 60 degrees (in opposing directions) with respect to the linear bottom surface, and a single corner are provided. Such a design may help lock cutter 1802b into cutter pocket 1800b. For example, cutter 1802b may be front loaded into pocket 1800b, which may help retain cutter 1802b within pocket 1800b during downhole operations. In some embodiments, a knuckle 1804b may be provided behind pocket 1800b. Knuckle 1804b may have a generally triangular shape such that a base of cutter pocket 1802b and a front face of knuckle 1804b may collectively extend behind a full base of cutter 1802b to provide additional support to cutter 1802b in a direction of rotation during downhole operations. Due to the size and shape of cutter pocket 1800b and cutter 1802b, cutter 1802b may be inserted into cutter pocket 1800b in four three orientations, with each orientation aligning a different cutting tip of cutter 1802b in the cutting position. In some embodiments, each cutting tip maybe identical, while in other embodiments one or more cutting tips may include different relief features and/or chamfered edges as described herein. This may enable a single cutter 1802b to be inserted in different orientations to provide a consistent result (in the event of identical cutting tips) or tailored results (in the event of cutting tips with different characteristics) and may enable cutter 1802b to be reused even after one cutting tip has been damaged.

FIG. 18C illustrates a generally stadium-shaped cutter pocket 1800c and a generally stadium-shaped cutter 1802c. Cutter 1802c may be similar to cutter 700 and may include two parallel linear lateral surfaces that are joined by two rounded ends. Each rounded end of cutter 1802c may form a discrete cutting tip that may protrude above a top surface of cutter pocket 1800c and the blade within which cutter pocket 1800c is formed. In some embodiments, cutter pocket 1800c may be sized such that only two parallel linear side surfaces and a single arcuate bottom surface are provided. A depth of cutter pocket 1800c may be between 25% and 75% of a length of cutter 1802c in various embodiments. In some embodiments, a knuckle 1804c may be provided behind pocket 1800c. Knuckle 1804c may have a generally semi-stadium shape such that a base of cutter pocket 1802c and a front face of knuckle 1804c may collectively extend behind a full base of cutter 1802c to provide additional support to cutter 1802c in a direction of rotation during downhole operations. Due to the size and shape of cutter pocket 1800c and cutter 1802c, cutter 1802c may be inserted into cutter pocket 1800c in two different orientations, with each orientation aligning a different cutting tip of cutter 1802c in the cutting position. In some embodiments, each cutting tip maybe identical, while in other embodiments one or more cutting tips may include different relief features and/or chamfered edges as described herein. This may enable a single cutter 1802c to be inserted in different orientations to provide a consistent result (in the event of identical cutting tips) or tailored results (in the event of cutting tips with different characteristics) and may enable cutter 1802c to be reused even after one cutting tip has been damaged.

In some embodiments, a cylindrical or largely cylindrical cutter pocket may be formed within a blade of a downhole tool and later modified to be non-cylindrical. FIGS. 19-24 illustrate techniques for modifying cylindrical or largely cylindrical cutter pockets into non-cylindrical cutter pockets in accordance with the present invention. FIG. 19 illustrates a cutter pocket 1902 formed in a blade 1900 of a downhole tool, with the cutter pocket 1902 having a substantially circular cross-section. A sidewall 1904 of cutter pocket 1902 defines a keyway 1980, according to certain embodiments. Sidewall 1904 and/or a base 1906 of cutter pocket 1902 may at least partially correspond to the cross-sectional shape of a non-cylindrical cutter, such as those described herein. For example, base 1906 may extend upward beyond a top surface of the blade of a downhole tool and form a knuckle 1930, such as those described in relation to FIGS. 17 and 18. As just one example, for a rectangular cutter, base 1906 and knuckle 1930 may collectively form a generally rectangular shape. As illustrated, base 1906 and knuckle 1930 collectively form a teardrop shape, with knuckle 1930 having a generally triangular cross-section that corresponds to a portion of a rectangular cutter that protrudes above the top surface of the blade. Knuckle 1930 may provide additional support for a cutter and may also serve as a reference edge 1920 that may be used to indicate a predetermined orientation of the cutter. Prior to modification, cutter pocket 1902 may be configured to accept a cylindrical cutter with a single scribe point. Knuckle 1930 and reference edge 1920 may indicate a preferred orientation of the scribe point. Thus, knuckle 1930 and reference edge 1920 may indicate a predetermined orientation of the non-cylindrical cutter with the scribe point.

Sidewall 1904 of cutter pocket 1902 may define include a keyway 1908. Keyway 1908 may be formed into cutter pocket 1902 during manufacture of the downhole tool or may be later formed (e.g., by drilling keyway 1908 into cutter pocket 1902). Keyway 1908 may be concave, including a largely round groove, and/or may be angular. As used herein, angular may mean polygonal, triangular, other shape with linear sides, etc. Keyway 1908 may be substantially symmetrical or may be asymmetrical. Although only one keyway 1908 is shown, cutter pocket 1902 may include any number of keyways 1908.

FIG. 20 illustrates a keyed shim 2000, according to certain embodiments. Keyed shim 2000 may include a protrusion 2002, a shim body 2006 having an arcuate outer surface 2012, a support surface 2004, a first end 2008, and a second end 2010. Keyed shim 2000 may be manufactured from steel, tungsten carbide, bronze, brass, Inconel, composites, ceramics, or any other suitable material. Protrusion 2002 may be substantially cylindrical and/or include angular features, as described above. Protrusion 2002 may extend from first end 2008 to second end 2010 or may only extend some portion of the distance between first end 2008 and second end 2010. Protrusion 2002 may be configured to substantially fill the groove of a keyway, such as the keyway 1908. For example, after protrusion 2002 is in keyway 1908, there may be space such that brazing material may be provided to secure protrusion 2002 into keyway 1908. In some embodiments, the protrusion 2002 may substantially fill a width of the groove of the keyway, but not a length of the groove of the keyway.

Support surface 2004 may be configured to alter a shape of a cutter pocket (e.g., cutter pocket 1902) to accept a non-cylindrical cutter. For example, as shown in FIG. 21, support surface 2004 may be substantially planar. When inserted into cutter pocket 1902, support surface 2004 may therefore alter the shape of cutter pocket 1902 to include at least partially planar sidewall. Furthermore, support surface 2004 may also correspond to the shape of at least one lateral surface of a non-cylindrical cutter. For example, the non-cylindrical cutter may include a planar surface at least partially matching the surface 2004. When the non-cylindrical cutter is inserted into the hollow pocket, the surface 2004 may at least partially orient the non-cylindrical cutter within the hollow pocket according to a predetermined orientation.

Although support surface 2004 is shown as substantially planar, support surface 2004 may include any number of indentations and/or protrusions. Furthermore, keyed shim 2000 may have a variable thickness, such as being thicker at one end as compared to the other. For example, keyed shim 2000 may be thicker at second end 2010. Thus, support surface 2004 may be sloped between first end 2006 and second end 2010 at a first angle. Alternatively, second end 2010 may be thicker than first end 2008, causing support surface 2004 to be sloped at a different angle. Furthermore, support surface 2004 may be curved. For example, cutter pocket 1902 may include keyway 1908, but a cylindrical cutter may be inserted into cutter pocket 1902. Then, support surface 2004 may substantially correspond to a sidewall of cutter pocket 1902, such that a cylindrical cutter may be accepted, and keyway 1908 substantially filled. One of ordinary skill in the art would recognize many different possibilities and configurations.

FIG. 21 illustrates a non-keyed shim 2100, according to certain embodiments. Non-keyed shim may include a pocket surface 2102, a support surface 2104, a first end 2108, and a second end 2110. Non-keyed shim 2100 may be manufactured from steel, tungsten carbide, or any other suitable metal, ceramic, composite, or other material. Pocket surface 2102 may be configured to correspond to a sidewall of a hollow pocket, such as the cutter pocket 1902. Pocket surface 2102 may be substantially round and/or may be angular or planar. Similarly, support surface 2104 may be configured to correspond to a surface of a cutter, such as a non-cylindrical cutter. Support surface 2104 may include any number of protrusions and/or grooves, such that support surface 2104 matches the surface of the cutter. Similar to keyed shim 2000, non-keyed shim 2100 may be thicker at one end or another, creating an angle or slope between first end 2108 and second end 2110. Support surface 2104 may also be curved, as described above in relation to keyed shim 2000.

When inserted into the hollow pocket, non-keyed shim 2100 may at least partially alter the shape of cutter pocket 1902 such that cutter pocket 1902 can accept a non-cylindrical cutter. For example, a non-cylindrical cutter may be inserted into a substantially cylindrical hollow pocket. Consequentially, a space may be defined between the non-cylindrical cutter and a sidewall of the hollow pocket. Non-keyed shim 2100 may be inserted in the space, such that the space is substantially filled.

FIG. 22 illustrates the portion of the blade 1900 with keyed shim 2000 and non-keyed shim 2100, according to certain embodiments. As described above in relation to FIG. 19, the cutter pocket 1902 may have been originally manufactured to accept a cylindrical cutter. Thus, sidewall 1904 may be cylindrical. Keyed shim 2000 may be inserted into cutter pocket 1902 such that protrusion 2002 substantially fills keyway 1908. Similarly, non-keyed shim 2100 may be inserted into cutter pocket 1902. Both support surface 2004 and support surface 2104 may at least partially orient a non-cylindrical cutter within the hollow pocket 1902. For example, the non-cylindrical cutter may be a rectangular cutter. Support surface 2004, support surface 2104, knuckle 1930, and reference edge 1920 may assist in orienting (or indexing) the non-cylindrical cutter such that a corner or cutting tip of the rectangular cutter is aligned with reference edge 1920 according to a predetermined orientation.

Keyed shim 2000 and/or non-keyed shim 2100 may be attached to cutter pocket 1902 and/or a non-cylindrical pocket during a brazing process. For example, a brazing process may be started to attach the non-cylindrical cutter to cutter pocket 1902. At some point during the brazing process, one or both of keyed shim 2000 and non-keyed shim 2100 may be inserted into cutter pocket 1902, at least partially to align the non-cylindrical cutter according to a predetermined orientation. Keyed shim 2000 and non-keyed shim 2100 may then also be brazed, such that keyed shim 2000 and non-keyed shim 2100 are attached to cutter pocket 1902 and/or the non-cylindrical cutter, and the non-cylindrical cutter is attached to and/or secured within cutter pocket 1902. Although only one keyed shim 2000 and one non-keyed shim 2100 are shown in FIG. 22, any number of shims, both keyed and non-keyed, may be present (e.g., 2, 3, 4, 5, etc.). While shown with each shim including a single support surface, it will be appreciated that a single shim may include multiple distinct support surfaces, which may be at angles relative to one another. For example, a single shim may be used to provide two lateral surfaces to support corresponding lateral surfaces of a rectangular (or other non-cylindrical) cutter.

In other embodiments, keyed shim 2000 and/or non-keyed shim 2100 may be attached to cutter pocket 1902 by welding (such as tack welding), chemical bonding, or any other suitable method. Keyed shim 2000 and/or non-keyed shim 2100 may be inserted and attached to cutter pocket 1902 at some point prior to the insertion of the non-cylindrical cutter or may be attached at some point after the insertion of the non-cylindrical cutter.

FIG. 23 illustrates a spacer 2300 with non-keyed shim 2100, according to certain embodiments. Spacer 2300 may be configured to at least partially align a non-cylindrical cutter in a predetermined orientation. Spacer 2300 and/or non-keyed shim 2100 may be manufactured from steel, bronze, brass, tungsten carbide, Inconel, ceramics, composites, or any other suitable material. In some embodiments, spacer 2300 may be configured such that a hollow pocket of an earth boring tool can accept non-cylindrical cutters of various lengths. Additionally, or alternatively, spacer 2300 may also be configured to support the non-cylindrical cutter such that the non-cylindrical cutter extends beyond a hollow pocket of an earth boring tool (e.g., cutter pocket 1902 in FIG. 19).

Although the spacer 2300 is shown as substantially flat, spacer 2300 may be configured to tilt the non-cylindrical cutter within the hollow pocket. For example, a thickness of the spacer 2300 may be greater at a backside of spacer 2300 (e.g., where non-keyed shim 2100 is attached). Thus, when a non-cylindrical cutter is placed on spacer 2300 within cutter pocket 1902, the non-cylindrical cutter may be angled away from non-keyed shim 2100. Furthermore, although spacer 2300 is shown attached to non-keyed shim 2100, any number of keyed and/or non-keyed shims may be present. For example, spacer 2300 may be attached to a keyed shim, but not non-keyed shim 2100. In other examples, two non-keyed shims and a keyed shim may be present. One of ordinary skill in the art would recognize may different possibilities and configurations. In some embodiments, the spacer 2300 and the non-keyed shim 2100 may be one unitary piece.

FIG. 24 illustrates blade 1900 with spacer 2300 and two non-keyed shims 2100a-b, according to certain embodiments. Cutter pocket 1902, as illustrated in FIG. 24, may not include a keyway (as is shown in FIG. 19). As described above in relation to FIG. 19, cutter pocket 1902 may have been originally manufactured to accept a cylindrical cutter. Thus, sidewall 1904 may be cylindrical. Non-keyed shims 2100a-b may be inserted into cutter pocket 1902. Both surfaces 2104a and 2104b may at least partially orient a non-cylindrical cutter within cutter pocket 1902. For example, the non-cylindrical cutter may be a rectangular cutter that may be oriented with a corner or cutting tip facing upward in a predetermined orientation based on the positioning of surfaces 2104a and 2104b and reference edge 1920.

Furthermore, spacer 2300 may also be inserted into a predetermined orientation. Spacer 2300 may be inserted into a predetermined orientation prior to a brazing process for attaching a non-cylindrical cutter into a predetermined orientation. Spacer 2300 may be attached prior to the brazing process or may be attached during the brazing process. In some embodiments, spacer 2300 may be attached to a predetermined orientation via welding (e.g., tack welding), chemical bonding, or any other suitable method.

Non-keyed shims 2100a-b may be attached to a predetermined orientation and/or a non-cylindrical cutter during a brazing process. For example, a brazing process may be started to attach the non-cylindrical cutter to a predetermined orientation. At some point during the brazing process, one or both non-keyed shims 2100a-b may be inserted into a predetermined orientation, at least partially to align the non-cylindrical cutter according to a predetermined orientation. Non-keyed shims 2100a-b may then also be brazed, such that non-keyed shims 2100a-b are attached to a predetermined orientation and/or the non-cylindrical cutter, and the non-cylindrical cutter is attached to and/or secured within a predetermined orientation. In some embodiments, non-keyed shims 2100a-b may be attached to a predetermined orientation via welding (e.g., tack welding), chemical bonding, or any other suitable method.

While shown with rectangular, triangular, and stadium-shaped cutter pockets and cutters, it will be appreciated that other shapes of cutters and cutter pockets may be utilized in various embodiments. In some embodiments, the cutter may include a diamond table having a non-cylindrical outer periphery that is configured to be rotated about a central axis of the cutter at an angle of between 60 degrees and 300 degrees in the respective cutter pocket to expose a new cutting edge or tip of similar point loading ability while maintaining a braze gap thickness of 0.015″ or less across 85% or more of a brazeable surface area of a conventional cylindrical cutter of similar size (e.g., a cylindrical cutter having a same maximum outer diameter or other maximum lateral dimension as the non-cylindrical cutter). In other words, the new cutting tip may have less cross-sectional area than a corresponding portion of a conventional cylindrical cutter that protrudes beyond a top surface of the blade, thus enabling higher force concentration on the exposed cutting tip than with conventional cylindrical cutters. For example, a rectangular cutter may be rotated relative to the cutter pocket/blade in 90 degree increments to expose a new cutting tip (e.g., put a new cutting tip into a cutting position). Similarly, triangular cutters may be rotated relative to the cutter pocket/blade in 120 degree increments to expose a new cutting tip, stadium-shaped cutters may be rotated relative to the cutter pocket/blade in 180 degree increments to expose a new cutting tip, pentagonal cutters may be rotated relative to the cutter pocket/blade in 72 degree increments to expose a new cutting tip, and hexagonal cutters may be rotated relative to the cutter pocket/blade in 60 degree increments to expose a new cutting tip. Other variations are possible. A shape and orientation of the cutter pocket and respective cutter may be selected such that when the cutter is inserted into the cutter pocket, the cutter is oriented with a cutting tip protruding beyond a top surface of a respective one of the plurality of blades. In other words, the cutting tip protruding above the top surface of the cutter pocket/blade is in a cutting position. The position and orientation of each cutter pocket within a given blade of a downhole tool may be selected to control various parameters of the cutter. For example, the position of the cutter pocket may control the depth of cut of the cutter, as well as the amount of forward rake, back rake, and/or side rake of the cutter, which may impact the effectiveness of the downhole tool as will be described in greater detail below.

The use of non-cylindrical cutters and cutter pockets may enable a greater number of cutters to be provided on a given blade relative to the use of cylindrical cutters. For example, the non-cylindrical cutters may have more pronounced cutting tips than the constant arcs of cylindrical cutters. Additionally, the constant radius of cylindrical cutters requires a significant amount of space within the blade to form each cutter pocket. In contrast, some non-cylindrical cutter shapes may provide a sufficiently large cutting tip while requiring less space within the blade, which may enable a greater number of cutters, and subsequently cutting surface area, to be provided. As just one example, FIG. 25 illustrates a portion of a blade 2500 having a number of generally stadium-shaped cutters 2502 received in cutter pockets of blade 2500. Cutters 2502 may be similar to cutter 700 and may include any feature described in relation to cutter 700. Given the reduced lateral dimensions (e.g., width between opposing faces of the central rectangular region) of cutters 2502, less distance is needed between adjacent cutters 2502, which enables a greater number of cutters 2502 to be included on blade 2500. For example, the dotted circular lines 2504 illustrate the size of a comparable cylindrical cutter. As shown, lines 2504 of adjacent cutters overlap, which would mean that if cylindrical cutters were utilized, the cutters would need to be spaced further apart and fewer cutters would be included. By increasing the number of cutters on a blade, the size of the bit profile may be reduced while still enabling the drill bit to fail the same amount of material in a given rotation. Additionally, a rate of penetration may be increased. In some embodiments, a greater number of cutters per blade may enable the number of blades on the drill bit to be reduced, which may promote better washing by drilling fluids.

In some embodiments, the cutting tips of various non-cylindrical cutters and/or other cutter designs with distinct, non-cylindrical cutting tips may be oriented at various angles relative to the top surface of a blade. For example, in some embodiments, a cutter may be oriented such that an exposed cutting tip is generally orthogonal (e.g., a neutral angle) to the top surface of the blade, which may ensure that the sharpest point of the cutter is loaded during downhole operations. In other embodiments, the cutter may be oriented such that an exposed cutting tip is rotated inward (e.g., positive angles) or outward (e.g., negative angles) of orthogonal, which may align a portion of a flat surface (e.g., a lateral surface that does not form a portion of a cutting tip) with the cutting profile of the drill bit. The angle of the cutting tip (as measured between the top surface of the blade and a line bisecting the cutter and cutting tip) may be adjusted to modify the specific energy needed to engage the cutter to a desired depth of cut. In some embodiments, the cutting tip may be angled for high efficiency (e.g. at a neutral angle or a slightly (e.g., within 5 degrees of neutral) positive or negative angle) for cutters within the cone and nose of the bit to improve a maximum drilling efficiency and rate of penetration. This is due to the increased point loading of the cutter on the drilling formation. For example, as the cutting tip is more closely aligned orthogonal to the top surface of the blade and/or cutting formation, a smaller surface area of the cutting tip is engaged with the formation. This concentrates greater loads within a smaller area of the cutting tip and may create a highly efficient and penetrating effect. In other embodiments, the cutting tip may be angled for low efficiency (e.g. rotated toward a center or a gauge of the drill bit by larger angles, such as greater than 5 degrees of neutral, possibly up to 90 degrees, depending on the shape, spacing, and/or number of discrete cutting tips) for cutters within the nose and cone to reduce the drill bit's sensitivity to weight on bit changes, which may be desirable in certain applications such as directional drilling. By angling the cutting tip in this manner, the cutting loads may be spread out over a larger area of the cutter and may reduce the cutting efficiency and aggressiveness. This may be done, for example, to control how much (e.g., a depth) of the formation is engaged by the cutter and/or drill bit during a given revolution of the drill bit. As just one example, the cutting tip for cutters within the shoulder and gauge may be angled for high efficiency in directional drilling applications, while a low efficiency orientation would be desired in a vertical drilling application or an operation in which there is very little desire to change the direction of the wellbore. Other variations are possible to meet the needs of a particular application.

In some embodiments, inward or outward rotation of the cutting tip may align a portion of a flat surface with the cutting profile of the drill bit to serve as a depth limiter. When done on the gauge of the drill bit, such angling of the cutting tip may help prevent the drill bit from cutting laterally, as the angling may be used to maintain the cutting profile within a width of a borehole of a given size. In some embodiments, inward or outward rotation of some or all of the cutting tips may be used to adjust lateral spacing between adjacent cutters, which may enable more or fewer cutters to be provided on a given blade and may be used to smooth out the cutting profile, such as by rotating each cutting tip inward toward a central axis of the drill bit. In a given bit, any number of cutters may be rotated in any number of directions to control the cutting profile and/or cutting characteristics of the drill bit. Oftentimes, a number of radially adjacent cutters may be rotated in a single direction or in opposite directions (e.g., positive and negative angles). For example, in some instances a cutting tip oriented in the neutral position may not engage the formation at the center of the cutting tip, which may lead to asymmetric loading that causes premature cutter failure. This may be due to the torsional load on the cutter and may most commonly occur on the shoulder. Similarly, the axial load on the cutter tip may not be centered on a cutting tip oriented in the neutral position, which may be particularly important in the nose and cone regions of the drill bit. To compensate for torsional and/or axial asymmetry and/or other loading issues, one or more cutting tips may be rotated to positive and/or negative angles to better align the cutting tips with the formation to get a desired interaction between the cutter and the formation. The final orientation of each cutter may depend on a variety of factors, such as (but not limited to) the cutter/bit layout, which section (e.g., nose, cone, shoulder, gauge) of the drill bit a given cutter is within, drilling parameters, formation characteristics, and/or other factors. The rotated cutters may include primary cutters and/or backup cutters. In some embodiments, pairs of primary and backup cutters may have a same direction and/or magnitude of rotation, while in other embodiments pairs of primary and backup cutters may have a different direction and/or magnitude of rotation.

In some embodiments, rotation of the cutting tip may be done to control the size and/or shape of the cutter that is exposed to the cutting formation. For example, the cutter (and cutting tip) may be rotated to create asymmetric and/or symmetric loading of the cutter relative to a central axis and/or centroid of the cutter. The area of the cutter that is engaged with the formation may also be indicative of how symmetrically the cutter may be loaded. For example, for symmetric loading of a cutter, a centroid of the area of the portion of the cutter that is engaged with the formation may be aligned or substantially aligned (e.g., within 5 degrees of alignment, within 3 degrees of alignment, within 1 degree of alignment, etc.) with a line extending through a center point and/or apex of the cutting tip and a central axis of the cutter. In applications where lower cutter efficiency is desired (e.g., where less point loading is provided, such as by presenting more of a cutter flat, rather than the cutting tip, to the formation), the cutters may be aligned such that the centroid of the area of the portion of the cutter that is engaged with the formation may be aligned or substantially aligned with a line extending through and perpendicular to the cutter flat and the central axis of the cutter.

In some embodiments, it may be beneficial to expose the cutter to the formation in a symmetric or substantially symmetric manner, which may ensure that the load is centered on the cutter and is distributed evenly about the cross-section of the cutter to reduce the likelihood of cutter failure due to unevenly concentrated loading. This may be particularly beneficial in cutters having non-planar interfaces that are shaped to match the general shape of a non-cylindrical diamond table, which may or may not include one or more protruding and/or recessed features. For example, the cutting tip may be rotated inward or outward to ensure that the cutter engages the formation in a symmetric or substantially symmetric manner. A direction and/or magnitude of the cutter rotation to achieve a symmetric engagement may be dependent on the radial location of the cutter, as well as based on the shape of the blade on which the cutter is mounted.

In some embodiments, substantially symmetric may be interpreted to mean that the cutter is rotated such that the cutter is rotated to a position that is within 10 degrees of a perfectly symmetric engagement of the formation, within 8 degrees of a perfectly symmetric engagement, within 6 degrees of a perfectly symmetric engagement, within 5 degrees of a perfectly symmetric engagement, within 3 degrees of a perfectly symmetric engagement, within 1 degree of a perfectly symmetric engagement, or less. In some embodiments, what constitutes substantially symmetric may be dependent on the radial location of the cutter. For example, substantially symmetric may have a smaller range (e.g., within 5 degrees of perfectly symmetric engagement, within 3 degrees, within 1 degree, or less, etc.) within the cone and/or nose region, where effects of asymmetric loading may be more amplified and a larger range (e.g., within 10 degrees of perfectly symmetric engagement, within 8 degrees, within 6 degrees, or less, etc.) within the shoulder and/or gauge region, although other embodiments are possible.

In some embodiments, each cutter on the drill bit may be arranged for symmetrical and/or substantially symmetrical engagement of the formation, while in some embodiments only a subset of the cutters on the drill bit may be arranged for symmetrical and/or substantially symmetrical engagement. For example, in some embodiments, only cutters within the cone, nose, shoulder, and/or gauge region may be arranged for symmetrical and/or substantially symmetrical engagement.

The amount of rotation of the cutting tip may be controlled by the orientation of the cutter pocket within which the cutter is seated. For example, each cutter pocket within a blade may be formed with a size, shape, and orientation that enables a correspondingly shaped and sized cutter to be inserted within the pocket in a finite number of orientations, each of which results in a cutting tip of the cutter being positioned with a set angular orientation (e.g., orthogonal to blade or rotated inward/outward). This may eliminate or reduce alignment errors associated with manually aligning cutting tips of cylindrical-based cutters during the brazing step.

FIG. 26 illustrates cutting tips of non-cylindrical cutters at different angular orientations. Cutting tip 2600a is rotated outward to a position of −15° relative to orthogonal, cutting tip 2600b is rotated outward to a position of −10°, and cutting tip 2600c is rotated outward to a position of −5°. Cutting tip 2600d is at a neutral, orthogonal position. Cutting tip 2600d is rotated inward to a position of 5° relative to orthogonal, cutting tip 2600e is rotated inward to a position of 10°, and cutting tip 2600f is rotated inward to a position of 15°. It will be appreciated that the degree of rotation may be in any angular increments. Limits for the maximum and minimum amount of rotation of a cutting tip may be based, for example, on a shape of the cutter and cutter pocket. For example, for a square cutter, the range of orientations may be between-45° and 45°. With a triangular cutter, the range of orientations may be between −60° and 60°. For a generally stadium-shaped cutter, the range of orientations may be between −90° and 90°. In other words, the range of orientations may extend over half the angle between adjacent cutting tips of a given cutter.

FIG. 27 illustrates a cutting profile of a drill bit with tips of non-cylindrical cutters 2700 at different angular orientations. Lines 2704 indicates the neutral position of a cutting tip of each cutter 2700, while lines 2702 indicate an actual orientation of the given cutting tip. For example, lines 2702a and 2704a indicate that cutting tip 2700a is rotated outward to a position of −25° relative to orthogonal or neutral, which exposes a moderate portion of an inner lateral edge of cutter 2704a to the cutting formation. Lines 2702b and 2704b indicate that cutting tip 2700b is rotated inward to a position of 50° relative to orthogonal or neutral, which exposes a large portion of an outer lateral edge of cutter 2704b to the cutting formation. Lines 2702c and 2704c indicate that cutting tip 2700c is rotated inward to a position of 10° relative to orthogonal or neutral, which exposes a small portion of an outer lateral edge of cutter 2704c to the cutting formation. Line 2704d indicates that cutting tip 2700d is in the neutral position (e.g., neither rotated inward or outward). Lines 2702e and 2704c indicate that cutting tip 2700e is rotated inward to a position of 20° relative to orthogonal or neutral, which exposes a moderate portion of an inner lateral edge of cutter 2704e to the cutting formation. It will be appreciated that the degree of rotation may be in any angular increments.

In addition to position or location on the bit, each cutter, including the non-cylindrical cutters described herein, has a three-dimensional orientation. Generally, this orientation will be defined with respect to one of two coordinate frames: a coordinate frame of the bit, defined in reference to its axis of rotation; or a coordinate frame generally based on the cutter itself. The orientation of a cutter is usually specified in terms of a back inclination or rotation of the cutter and a side inclination or rotation of the cutter. Back inclination or “back rake” is specified in terms of an axial rake or back rake angle, depending on frame of reference used. Side inclination or “side rake” is typically specified in terms lateral rake or side rake angle, depending on the frame of reference used. Such drill bits are described, for example, in U.S. Pat. No. 9,556,683, the entirety of which is incorporated herein by reference.

The concepts of cutting profile, back rake, and side rake are explained with reference to FIGS. 28-31C. FIG. 28 represents a schematic illustration of a face view of a drill bit. The gauge of the bit is generally indicated by circle 2810 and generally corresponds to the maximum width or diameter of the drill bit. For clarity, only five fixed cutters 2812, 2814, 2815, 2817, and 2819 are illustrated in FIG. 28, although it will be appreciated that drill bits typically include many additional cutters. For purpose of illustration, cutters 2812 and 2814 are shown having different side rake angles but do not have any back rake. Cutters 2815 and 2817 are shown having different back rake angles but do not have any side rake. Cutter 2819 is shown having neither back rake nor side rake. Although not shown, it is contemplated that a cutter may have both back rake and side rake.

Reference number 2818 identifies the center of rotation or longitudinal axis of the drill bit, referred to herein as the “bit axis.” Radial line 2820 is an arbitrary radial selected to represent zero degree angular rotation around bit axis 2818. Fixed cutters 2812 and 2814 are located generally on the same radial line 2822, at the same angular rotation, as indicated by angle 2824, but are radially displaced at different distances, 2826 and 2828, from the bit axis 2818. Fixed cutters 2815 and 2817 are located generally on the same radial line 2831, at the same angular rotation, as indicated by angle 2834, but are radially displaced at different distances, 2835 and 2837, from the bit axis 2818. Cutters 2812 and 2814 are located on one blade, and cutters 2815 and 2817 are located on another blade. For clarity, the blades are not indicated on the schematic representation of FIG. 28. Cutters on the same blade may or may not all lie on the same radial line or at the same angular rotation around bit axis 2818. For example, cutters may be aligned on a given blade in a straight radial line or may be aligned in a curved (arcuate) path along a given blade. Cutter 2819 lies on the radial line 2832, which has a substantially greater angular position than the other cutters. As shown, its radial displacement from the bit axis 2818 is greater than the distances of the other four cutters 2812, 2814, 2815, and 2817.

FIG. 29 represents a schematic illustration of a cutting profile of a bit. Only three fixed cutters are illustrated for sake of clarity, with the outer diameters of the individual cutters represented by circular outlines 2944, 2946, and 2948, respectively. The profiles of the cutters are formed by rotating their positions to the zero degree angular rotation radial line 2820 (FIG. 28) and projecting them into a plane in which the bit axis and the zero degree angular rotation radial line 2820 lie. Curve 2942, which represents the cutting profile of the bit, touches each cutter at one point, and generally represents the intended cross-sectional shape in the borehole left by the bit as it is penetrating the formation. For purposes of simplifying the illustration, each of the outlines 2944, 2946 and 2948 assumes that the cutters do not have any back rake or side rake. If a cutter had any back rake, such as cutters 2815 and 2817, or side rake, such as cutters 2814 and 2816, the projection of the outside diameter of the PDC layer into a plane through the radial line for that cutter would be elliptical.

The cutters in FIG. 29 are shown “face on” and have longitudinal symmetry such that point 2950 (three are shown, one for each cutter) represent both the cutter axis and the surface axis, which coincide with one another. As shown, cutter/surface axis 2950 will be selected, for purposes of example, as the origin of a reference frame for defining side rake of the cutter in the following description.

Line 2952 represents the “side rake axis,” which is the axis about which the cutter is rotated to establish side rake. The side rake axis 2952 is normal to the tangent of the cutting profile at the point 2951 where the projection of the cutter diameter 2944, 2946, 2948 touches the bit cutting profile curve 2942, and extends through point 2950. Side rake axis 2952 also lies on the front surface of the cutting surface. The angle of rotation (not indicated in FIG. 29) of a cutter about the side rake axis 2952 is its “side rake angle,” which is defined as the angle between (1) a line tangent to a circle of rotation for a given cutter, extending through point 2950, and (2) the surface axis.

Referring back to FIG. 28, the cutters 2812 and 2814 are shown having different amounts of side rake, which are indicated by angles 2836 and 2838, respectively. In the case of cutter 2812, the side rake angle 2836 is defined between (i) line 2841, which is tangent to a circle of rotation for cutter 2812, extending through point 2850, and (ii) the surface axis 2843 of cutter 2812. The side rake angle 2838 of the cutter 2814 is defined between (i) line 2845, which is tangent to a circle of rotation for cutter 2814, extending through point 2850, and (ii) the surface axis 2847 of cutter 2814.

As shown in FIG. 28, the rotation of cutter 2812 about its side rake axis 2852 is opposite to the rotation of cutter 2814 about its side rake axis 2852. For cutter 2812, its surface axis 2843 is rotated about the side rake axis 2852 toward the bit axis 2818, and its cutter face defines a cutting surface that is angled toward the gauge circle 2810 of the bit. For cutter 2814, its surface axis 2847 is rotated about the side rake axis 2852 away from the axis of rotation 2818 and towards the gauge circle 2810 of the bit, and its cutter face defines a cutting surface angled toward the bit axis 2818. Accordingly, cutters 2812 and 2814 face toward each other and have side rakes that converge on one another.

As discussed above, the three cutters shown in FIG. 29 and cutter 2819 have no side rake, or a zero degree side rake angle. As convention, rotation of the cutter from the zero degree side rake position to angle the cutter face towards the gauge of the bit establishes a positive side rake angle. Rotation of the cutter from the zero degree side rake position to angle the cutter face towards the bit axis 2818 of the bit establishes a negative side rake angle. Accordingly, cutter 2812 has a positive side rake angle, and cutter 2814 has a negative side rake angle.

The “back rake axis” for a given cutter is defined as the tangent of the cutting profile curve 2942 at the point 2951 where the projection of the cutter touches the bit cutting profile curve 2942. The back rake axis 2958 for a given cutter is thus orthogonal to both the cutter axis and the cutter's side rake axis 2952. Line 2958 for cutters 2946 and 2948 in FIG. 29 represents each cutter's back rake axis. The back rake axis 2958 for cutter 2944 is not labeled because its back rake axis 2958 and the cutting profile curve 2942 substantially overlap. Rotation (not indicated in FIG. 29) of the cutter around its back rake axis 2958 establishes its “back rake angle,” which is defined as the angle between (1) a line normal to the cutting profile at the point (e.g., point 2951) where the projection of the cutter diameter touches the bit cutting profile (e.g., curve 2942) and (2) a line in the plane of the cutting surface extending through the center point 2950 of the cutting surface.

Cutters 2815 and 2817 in FIG. 28 are shown to have different amounts or degrees of back rake, and are also shown in FIGS. 30A and 30B, respectively. In the case of cutter 2815, the back rake angle is defined between line 3074, which is normal to the cutting profile (or formation surface) at contact point 3051, and a line in the plane of the cutting surface 3075 extending through the center point thereof. In the case of cutter 2817, the back rake angle 3076 is defined between line 3078, which is normal to the cutting profile (or formation surface) at contact point 3051 and a line in the plane of cutting surface 3077 extending through the center point thereof. In FIGS. 30A and 30B, the contact point 3051 and each cutter's back rake axis 3058 overlap.

When the cutter face or surface is aligned with the vector normal to the cutting profile, that cutter is said to have zero back rake or a “zero degree” back rake angle. The three cutters shown in FIG. 29 and cutter 2819 shown in FIG. 28 have zero degree back rake angles. When the rotation of the cutter about its back rake axis 2958 angles the cutter face towards the formation leading the cutter along the direction of bit rotation, the rotation about the back rake axis 5058 establishes a positive back rake angle for that cutter. When the rotation of the cutter about its back rake axis 2958 angles the cutter face away from the formation leading the cutter along the direction of bit rotation, the rotation about the back rake axis 2958 is said to have a negative back rake angle for that cutter.

Both the rotation of cutter 2815 and the rotation of cutter 2817 about their respective back rake axes 2958 angle the respective cutting surfaces 3075 and 3077 forward along the direction of bit rotation toward the formation. Thus, cutters 2815 and 2817 each have a positive back rake angle. Cutter 2817 has a greater back rake angle 3076 than back rake angle 3072 of cutter 2815. Comparatively speaking, a cutter having a lesser positive back rake angle is said to have a more aggressive back rake angle than a cutter having a greater positive back rake angle. In a pair of cutters that have different positive back rake angles, the cutter with the lesser back rake angle may be referred to as the aggressive cutter, and the cutter with the greater back rake angle may be referred to as the passive cutter, relative to one another.

In the embodiments shown in FIGS. 30A and 30B, the surface axis aligns with the cutter axis. In some embodiments, as discussed above, the cutter may not be longitudinally symmetrical, resulting in a cutter axis that is slanted or angled relative to the cutting surface. FIGS. 31A and 31B show cutters having cutter axes 3192a and 3192b of their respective cutters that do not align with the respective surface axes 3194a and 3194b of the cutter surfaces. Moreover, cutter axes 3192a and 3192b are slanted or angled relative to their respective cutting surfaces. The same back rake angle 3196, however, may be achieved by mounting the cutters on the bit body at different mounting angles. Having the cutter axis slanted or angled with respect to the cutting surface may facilitate establishing a negative back rake angle, such as negative back rake angle 3198 shown in FIG. 31C.

Referring back to FIG. 29, angle 2956 between the side rack axis 2952 and line 2954, which crosses the cutter's cutter axis and is parallel to the bit axis 2818, defines the “cutting profile angle,” as measured in a clock-wise direction. Line 2960 represents the zero angle for the cutting profile. Section 2962 of the cutting profile corresponds to the cone of a PDC bit. The profile angles in this section are somewhere between 270 degrees and 360 (or zero) degrees. The profile angles increase toward 360 degrees starting from the bit axis 2818 and moving toward the zero degree profile angle at line 2960. The bit's nose corresponds generally to section 2963 of the cutting profile, and is disposed radially outward from the cone section. In the nose section, the profile angles are close to zero degrees. Portion 2964 of the profile corresponds to the bit's shoulder section, and is disposed radially outward from the nose section. The profile angles increase quickly in this section until they reach 90 degrees. Section 2966 of the cutting profile corresponds to the bit's longitudinally extending gauge section. The cutting profile angle in the gauge section is approximately 90 degrees.

In some embodiments, the side rakes of the primary cutters along the leading edges of the offset and non-offset blades in each of these examples can be set to have relatively high side rake. Rotating a cutter angles its cutting face to the formation. When angled to the formation the cutter will tend to generate a reactive lateral force on the bit as the cutter when the cutter engages the formation. Selectively orienting two or more cutters on the bit to generate counteracting lateral forces on the bit can dampen vibrations, increase rate of penetration, and/or improve steerability of the bit. The side rake angles of two or more adjacent primary cutters along each of the offset blades in the illustrated examples may be set to cause the generation opposing or counteracting lateral forces along the blade while engaging a formation. Furthermore, one or more primary cutters along one blade may coordinate or cooperate with one or more cutters on other blades with different side rake angles in a way that reactive lateral forces are created on the bit that counteract each other in ways that dampen bit vibration. For example, these could be radially adjacent or overlapping primary cutters on different blades. Or, for example, the side rakes of the primary cutters within each of two or more groups of primary cutters on the bit can be chosen to generate lateral forces that counteract each other to dampen lateral vibrations or to improve direction control and steerability. The cutters are grouped by, for example, radial positions within the cutting profiles, the region of the bit in which they are located (e.g. cone, nose, shoulder), angular position, location along a blade, by adjacency along a blade or in the bit's cutting profile, or a combination of two or more of these parameters. Cutter side rake schemes for generating counter acting lateral forces that tend to dampen vibration, improve cutting efficiency, improve ROP, and/or otherwise improve bit performance may embody one or more of the following:

(1) A pair or a set of three or more primary cutters mounted on one or more leading edges of one or more offset blades with side rakes that generate counteracting lateral forces on the bit. The pair or set of cutters are mounted, in one embodiment, on the same offset blade or, in another embodiment, on different offset blades. If they are on different offset blades, the cutters in the pair or the set of three or more may be in radially adjacent positions on the bit's primary cutting profile. The pair or set of cutters are, in one embodiment, primary cutters that are adjacent to each other on the same offset blade and, optionally be in radially adjacent locations on the bit's primary cutting profile, and/or partially or completing overlapping in the primary cutting profile. An offset blade like offset blade 226 of FIG. 2 allows primary cutters to be both adjacent on the offset blade and in radially adjacent locations and/or partially or completely overlapping in the cutting profile.

(2) A group of two or more primary cutters on one offset blade with side rake angles set to generate counteracting lateral forces on the bit during drilling. All of the cutters in the group may be in one the following locations: in the cone section of the bit; on opposite sides of the offset in the offset blade; on the first or inner blade portion on the offset blade; or on the second or outer blade portion of the offset blade. The cutters in the group are, in one embodiment, adjacent to each other on the offset blade, and in another embodiment are not adjacent. Primary cutters on an offset blade may have non-zero side rake angles. Primary cutters on non-offset blades, including secondary blades, may also have such a group of one or more cutters. Furthermore, one or more primary cutters on an offset and one or more non-offset blades may form a group of cutters with side rake angles.

(3) Three cutters in a group of three or more cutters that have side rake angles that vary in polarity (positive and negative, positive and zero, and negative and zero) or a change in the side rake of the cutters by rotation inwardly or outwardly relative to another (high positive and low positive, high negative and low negative). For example, if there are three cutters, the second cutter and rotated laterally outwardly relative to the first cutter, and cutter three then rotated inwardly relative to cutter the second cutter. The cutters may be adjacent to each other along a blade, radially adjacent to each other in a cutting profile, or possibly both.

(4) A pair of adjacent cutters have side rakes that are negative and positive, high positive and low positive, high negative and low negative, negative and zero, or positive and zero and face each other or turn away from each other.

(5) Multiple groups of three or more cutters with side rakes are set to generate counteracting lateral forces on the bit. Side rakes of cutters in a group, particularly those that are adjacent on a blade or in a cutting profile may change polarity or exhibit relatively large changes between them.

(6) All of the primary cutters on the bit in particular region or on a blade or on multiple blades of a bit have a distribution of side rake angles (the number of cutters at each side rake angle or a range of side rake angles) that is bimodal or that has multiple maxima. Examples of regions or particular blades include all primary cutters in the cone, cone and nose, nose and shoulder, or cone, nose and shoulder regions; all such primary cutters in the region on offset blades; all primary cutters on any two blades; all primary cutters on one or more offset blades; all primary cutters on one or more offset and one or more non-offset blades; all primary cutters on two or more offset blades; and all primary cutters on the bit.

(7) The magnitude of the differences in side rake angles between at least three, and up to all, of the cutters that are radially adjacent along a blade or that are radially adjacent in at least a portion or region of a bit's cutting profile are mostly, if not always, non-zero and relatively constant in magnitude and/or not less than a certain value. In different embodiments, the differences are 3 or more degrees; 5 or more degrees plus or minus two degrees; and at least 7 degrees. In different embodiments, averages of these differences are at least 3 degrees; at least 5 degrees; and at least 7 degrees. With primary cutters on offset blades, the values of these differences, the minimum value of the differences, and/or the average value of these difference can be made greater than with a conventional blade. Examples of regions include all primary cutters on at least offset blades in the cone, cone and nose, nose and shoulder; and cone, nose and shoulder regions.

Each of the foregoing embodiments of rotary drag bit may have two cutters in a group of two or more fixed cutters, which can be radially adjacent in the cutting profile or on a blade, with large differences in side rake angles. In one example, a large difference between the side rake angles of two cutters is at least 4 degrees or more; in another example at least 7 degrees or more; and in another example at 10 degrees or more; and in another example at least 13 degrees or more.

Unless otherwise noted, differences between side rake angles between a first cutter and a second cutter that are negative indicate that second cutter is turned more inwardly than first cutter. If it is positive, it means that the second cutter turn is turned more outwardly than the first cutter. Thus, a change from −2 degrees to +2 degrees, or from −11 to −7, is a +4 degree difference. A change from +2 to −2 degrees or a change from 11 to 7, is a −4 degree difference. However, if no polarity is indicated, the change or delta should be interpreted as a scaler quantity, without regard to the direction of change. Furthermore, “small side rake angle” and a “large side rake angle” each refer to the scalar value of the angle, meaning the amount of side rotation from the zero angle. Thus, to say that the cutter has high or large side rake angle means that it has a negative or a positive side rake angle with a large value.

FIGS. 32A and 32B depict the cutter geometry (FIG. 32B) of cutters 3212, 3214, 3216, 3218, 3220, 3222, 3223 and 3226 on an offset blade (not shown) of a rotary drag bit (not shown) with an offset blade geometry like the offset blades 226 in FIG. 2. Cutters 3212-3225 are depicted as they would be when mounted along a leading edge on an offset blade, with the offset located between cutters 3216 and 3218. A profile 3228-3242 corresponding to cutting face of each cutter 3212-3226, respectively, is indicated in relation to a primary cutting profile 3210 for the bit, which shows that each of the primary cutter are on the primary cutting profile.

From FIG. 32B the side rake of each of the cutters can be appreciated. For example, cutter 3212 has a positive side rake angle that orients the face of cutter 3212 laterally outwardly. Cutter 3214 is rotated inwardly and has a negative side rake. Cutter 3216 is rotated outwardly as compared to cutter 3214. The cutter geometry illustrates that each blade portion of the offset blade (the inner and outer) allows more room for turning or rotating the cutters to achieve the desired side rake scheme. As can be seen in FIG. 32A, the profiles of the cutters are relatively evenly spaced along the blade. However, without the offset between them, the outward rotation of cutter 3216 and the further outward rotation of cutter 3218 would not have been possible. If cutters 3216 and 3218 were next to each other on a conventional blade, cutter 3216 and the minimum spacing requirement would interfere with the rotation of cutter 3216 to a high side rake angle.

FIGS. 33A and 33B illustrate an example of cutter geometry and cutter profile of primary cutters 3312-3326 mounted along a leading edge of an offset blade (not shown) like offset blade 226 of FIG. 2. Cutters 3312-3316 are mounted on a first or inner blade portion of the offset blade; cutters 3318-3326 are mounted on the second or outer portion of the offset blade. As indicated by the profiles 3328-3342 that correspond, respectively, to cutters 3312-3326, the cutters are on a primary cutting profile 3310. As indicated by the overlapping of cutter profiles 3332 and 3334, primary cutters 3316 and 3318 are partially overlapping. Furthermore, the difference in side rake angles of primary cutters 3316 and 3318 is relatively large-much larger than would be possible on a conventional blade or an offset blade like those in FIG. 2. Although not indicated in this example, the overlapping cutters may allow for additional cutters to be placed on the outer blade portion of the offset blade.

The additional space afforded by the offset blade allows for side rake scheme in which blade-adjacent cutters 3312-3316 on the inner blade portion of the offset bit, which is in the cone region of the bit, are turned or oriented to give any two (adjacent or non-adjacent) of them larger differences in side rake angles than what would be possible with a non-offset or conventional blade, and to employ side rake schemes with that would otherwise not be possible. Larger differences in side rake angles will tend to result in larger counteracting lateral forces on the bit in a region of the cone where counteracting lateral forces tend to have greater effect on dampening vibration and improving cutting performance of the bit. Specifically, in this example cutter 3312 is turned outwardly, cutter 3314 is turned inwardly to face cutter 3312, and cutter 3316 is turned outwardly, each by a significant amount. Such a side rake scheme, with the large changes in side rake, likely would have not be possible on cutters on the same blade, particularly within the cone region, without spacing apart the cutters more and possibly having to reduce the number of cutters on the blade, or without applying the scheme instead to a group of radially adjacent primary cutters spread across multiple blades.

FIG. 34 is another example of a cutter geometry of an offset blade (not shown) of a rotary drag bit, in particular a PDC bit. Primary cutters 3412, 3414, 3416, 3418, 3420, 3424, and 3426 are mounted along a leading edge of an offset blade similar to offset blade 226, with an offset between the third and fourth primary cutters on the blade, which are cutters 3416 and 3418. Cutter profiles 3444, 3446, 3448, 3450, 3452, 3454, 3456 and 3458 that correspond to the cutters show that they are on the bit's primary cutting profile 3410. As indicated by the cutter profiles 3448 and 3450, the primary cutters 3416 and 3418 are adjacent. Because they overlap, a bit designer is able to set the side rake angles of the cutters to opposite polarities give one or both a high side rake angle. In this example, primary cutter 3416, which is the third cutter on the blade, has a side rake angle of negative 7 degrees. Cutter 3418 has a side rake angle of 10 degrees, a difference of 17 degrees. In these cutters where on a non-offset blade and set close to the minimum separation needed for mounting them on the blade, it would not possible to achieve such a large difference in side rakes close to minimum separation. The largest negative side rake for the third cutter (cutter 3416) would be negative one degree and the maximum positive side rake of the fourth cutter (cutter 3418) would be five degrees, only a 6 degree difference.

The graphs of FIGS. 35A to 35G illustrate various examples of side rake schemes for fixed cutters on a rotary earth boring tool, such as a PDC bit or reamer, that illustrate or embody patterns relative side rake angles or changes in side rake changes between cutter that can be used on bits with offset blades for generating counteracting lateral forces on the tool. The x-axis represents successive positions of cutters along a blade or, in an alternative embodiment, successive radial locations of cutters or cutter positions in a bit's cutting profile. An offset blade can be used to increase the side rake angles and differences in side rake angles.

The origin represents, in some embodiments, the axis of rotation of the tool, with successive positions along the x axis representing positions closer to the gauge of the body of the tool and more distant from the axis of rotation. However, the patterns could start at some outer location within the cutting profile or blade. The number of cutters on a bit depends, at least in part, on the size of the bit. The number of data points indicated along the x axis is therefore not intended to be limiting, but representative of a side rake scheme embodying examples of patterns can be used on bits with offset blades for generating counteracting lateral forces on a rotary earth boring with fixed cutters. The y axis indicates the side rake angle of the cutters. The graphs are not intended to imply any particular range of positions on a blade or within a cutting profile. Furthermore, although primary cutters are assumed for the exemplary side rake schema, the patterns in side rake that they embody could be used in side rake schema for a row of backup cutters or cutters on a secondary cutting profile, or a combination of both.

The example of FIG. 35A represents a side rake scheme in which the differences or changes in side rake angles of at least three cutters in adjacent positions alternate directions. For example, the angle of the cutter in the first position and the angle of the cutter in the second position have opposite polarities. The direction of change or the difference is negative. The change between the cutters in the second and the third positions is a direction opposite the direction of the change from the first to the second cutter. The side rake angle increases, and the difference is positive.

The example of FIG. 35B is similar to FIG. 35A, except that it is comprised of two related patterns 3550 and 3552, which are the inverse of each other. In each of these two patterns the change of the side rake from an individual cutter to a group of two or more cutters with a similar side take is in one direction, and then the change in angle from the group to a single cutter is in the opposite direction.

In the example configuration of FIG. 35C, the differences in side rake angles within group 3554 of at least two successive cutters, four in this example, is in a first direction. The angle in this group progressively increase, in this example from negative to positive. In a next adjacent group 3556 of two or more cutters, the side rake angles change in the opposite direction between adjacent members of cutters within that group. In this example, the angles decrease, and furthermore they decrease from being positive angles to negative angles. A third group of at least three cutters 3558, having increasing angles, and thus the direction of change in angle within this group is positive. The pattern thus illustrates an alternating of the direction of change within adjacent groups of cutters.

FIG. 35D is similar to FIG. 35C, except that the changes in side rake angles follow a sinusoidal pattern rather than a linear pattern.

FIG. 35E shows an example of a pattern in which the side rake angles within groups 3560 and 3562 of two or more successive cutters are similar, for example, all the same magnitude or all negative or positive, but that every third or more cutter 3564 has a different angle, for example, positive when the angles in the group 3560 are negative. The angles change in a first direction from group 3560 to cutter 3564, and then in the opposite direction between cutter 3564 and group 3562. Inverting the pattern is an alternative embodiment. The cutter having one polarity of side take might be positioned on one side of the bit and the cutters with the opposing polarity would be positioned on the other side of the bit. For instance, one side rake would be used on blades 1 to 3 and the second side rake would be used for cutters on blades 4 to 6 of a six bladed bit.

FIG. 35F is an example of a pattern for a bit in which side rakes of two or more adjacent cutters within group 3566, for example within a cone of a bit, are positive, and then a group of two or more adjacent cutters are negative in an adjacent group 3568. The second group could be, for example, along the nose and shoulder of the bit. The side rake angle then becomes positive again. The pattern also illustrates stepwise decreases or increases of side rake within a group.

FIG. 35G is an example of a step wise pattern or configuration in which the side rake angle is generally increasing. In this example, the side rake angle is increasing generally in a non-linear fashion, but the change in angle swings between an increasing direction and a neutral direction. In this example the increasing positive side rake pushes cuttings increasingly to the outer diameter of the but, increasing drilling efficiency.

Alternative embodiments to the patterns or configurations of FIGS. 35A to 35D comprise inverting the patterns. Furthermore, although the polarity of the angles (positive or negative) form part of the exemplary patters, the values of the angles in alternative embodiments can be shifted positive or negative directions without changing the polarity of the sides of the cutters in the grouping. In the configuration of FIG. 35A, for example, the cutters could have either all positive or all negative side rake while employing alternating changes in direction of the differences between the cutters. Furthermore, the alternating a pattern of positive and negative direction changes could occur first between cutters with positive angles, and then between cutters with positive and negative side rake angles, and then between cutters with only negative side rake polarities, all without interrupting the alternating pattern. Another embodiment is a bit with, for instance, blades 1 to 3 having one side rake and blades 4 to 6 having an opposing or substantially different side rake, similar to the arrangement shown in FIGS. 35E and 35F. This design could recede walk tendency and might be configured to be more laterally stable than a more conventional design.

FIGS. 35H and 35J are additional examples of alternative patterns. In FIG. 35H, the side rake angles are positive and generally increase. But, at some frequency, the angle decreases. In this example, the frequency is every third cutter in the sequence. However, a different frequency could be chosen, or the point at which the decrease occurs can be based on a transition between section of the bit or blade, such as between cone and nose, nose and shoulder, and shoulder and gauge, or at a blade offset.

FIG. 35I is an alternative embodiment to FIG. 35A, in which the side rake angles remaining positive, but increase and decrease in alternating fashion.

FIG. 35I is an alternative embodiment to FIG. 35A in which the side rake angles remaining positive but increase and decrease in an alternating fashion.

FIG. 35J illustrates that patterns of side rake angles changes may also involve varying the magnitude of change in the side rake angle between cutters in addition to direction.

FIGS. 36A and 36B depict the side rake schema of an example of a PDC bit with offset blades as primary blades with a side rake schema for its primary cutters embodying patterns that generate counteracting lateral forces on the bit that tend to reduce or dampen vibration that reduces bit cutting performance. The PDC bit may be a representative, non-limiting example of a rotary drag bit with fixed cutters and offset blades.

FIG. 36A plots side rake angle against radial location of the primary cutters; FIG. 36B plots side rake angle against cutter number for the same primary cutters. Table 1 below gives the values of side rake, cutter number, blade number and bit profile region (which can be used to determine in what region the cutter is located on the blade) for each of the bit's primary cutters. The bit has three primary blades, each of which is an offset blade, and the offsets for the blades occur within the cone region between the second and third cutters on each primary blade.

In this example, the side rakes of the primary cutters alternate in magnitude or alternate in both magnitude and polarity along the cutting profile of the bit. Thus, radially adjacent cutters on the primary cutting profile have alternating side rakes that provide an alternating series of positive and negative changes in side rake angle. Similarly, the cutters on the inner blade portion and the first cutter on the lower blade portion of at least two of the primary blades have large difference in side rake angles that alternate from positive to negative, with the largest change being negative seven degrees. Alternating negative and positive differences occur between cutters with positive side rake angles in the cone region, and that the alternating pattern of side rakes in the nose and shoulder regions occurs between primary cutters with positive and negative side rakes.

FIGS. 37A and 37B are graphs that plot, respectively, side rakes of primary cutters against cutter number and cutter position in a primary cutting profile of a PDC bit that is intended to be another representative, non-limiting example of a rotary drag bit with fixed cutters and offset blades. This example has 6 blades, with blades 1, 3 and 5 being primary blades with offset geometries. The offsets occur between the third and fourth cutters on blades in the nose region. Table 2 below gives the values of size rake, radial location, and cutter number, as well as angular position, blade number and profile angle (which can be used to determine in what region the cutter is located on the blade) for each of the bit's primary cutters.

The three cutters along the inner blade portions and the first cutter on the outer blade portion change in alternating directions, with side rake differences of least 4 degrees. Cutters in the bit profile form groups of cutters (with at least three cutters in each group) 3702, 3704, 3706, 3708, 3710, 3712, 3714, and 3716 that have the same side rake angles (in alternative embodiments, the angle may different slightly), with relatively large side rake angle differences between groups, with the direction of change alternating between positive and negative between successive groups along the bit's cutting profile, except the two changes between group 3704 and 3706 and 3706 and 3708, both of which of are positive. These patterns of side rake angles help to generate counteracting lateral forces on the bit that dampen bit vibration.

In some embodiments, at least some of the primary cutters on one or more blades of a downhole tool may have positive back rake angles. Further, at least some of the primary cutters on the same blade may have positive back rake angles arranged in an alternating manner. Specifically, one or more blades may include a first set of primary cutters and a second set of primary cutters arranged in an alternating manner. The first set of primary cutters may include one or more primary cutters, and the second set of primary cutters may include one or more primary cutters. Each of the first set of primary cutters may have a positive back rake angle, and each of the second set of primary cutters may have a positive back rake angle. The positive back rake angle of each primary cutter of the first set may be greater than the positive back rake angle of an adjacent primary cutter of the second set, although the positive back rake angle of a primary cutter of the first set may be the same as or less than the positive back rake angle of a non-adjacent primary cutter of the second set. Conversely, the positive back rake angle of each of primary cutter of the second set may be less than the positive back rake angle of an adjacent primary cutter of the first set, although the positive back rake angle of a primary cutter of the second set may be the same as or greater than the positive back rake angle of a non-adjacent primary cutter of the first set. With this configuration, at least the first set of primary cutters and the second set of primary cutters on the same blade may have alternating positive back rake angles.

In some embodiments, one or more primary cutters of the second set may include zero back rake angles. Consequently, in some embodiments, primary cutters having alternating positive back rake angles may include only primary cutter that have positive, non-zero back rake angles, while in some embodiments, primary cutters having alternating positive back rake angles may also include one or more primary cutters that have zero back rake angles. In the latter embodiments, those cutters may also be said to have alternating non-negative back rake angles.

The first set of primary cutters may each have a positive back rake angle within a first predetermined range, within the first predetermined range +3°, within the first predetermined range +5°, or within the first predetermined range +9° in various embodiments. In some aspects, the first predetermined range may be from 10 to 30°, from 15 to 25°, or from 18 to 22°. The average of the first predetermined range may be 20±10°, 20±9°, 20±7°, 20±5°, 20±3°, 20±1°, or approximately 20°.

The second set of primary cutters may each have a positive back rake angle within a second predetermined range, within the second predetermined range ±3°, within the second predetermined range ±5°, or within the second predetermined range ±9° in various embodiments. In some aspects, the second predetermined range may be from 0 to 20°, from 5 to 15°, or from 8 to 12°. The average of the second predetermined range may be 10±10°, 10±9°, 10±7°, 10±5°, 10±3°, 10±1°, or approximately 10°.

The difference between at least one primary cutter of the first set and an adjacent primary cutter of the second set may be less than 20°, less than 15°, less than 10°, or less than 5°, less than 3°, or less than 1° in various embodiments. In some embodiments, the difference may be 20° or greater than 20°. In some embodiments, the difference between at least a majority of back rake angles on adjacent primary cutters of the first and second sets may be less than 20°, less than 15°, less than 10°, or less than 5°. The difference between the average of the positive back rake angles of the first set of primary cutters and the average of the positive back rake angles of the second set of primary cutters may be from 5 to 20°, from 5 to 15°, from 5 to 10°, from 10 to 20°, or from 15 to 20° in various embodiments.

In addition to the primary cutters having alternating positive back rake angles, one or more blades may also include one or more primary cutters that may have positive back rake angle(s), negative back rake angle(s), or zero back rake angle(s). In some embodiments, the additional one or more primary cutters may be disposed radially inward from the first and second sets of primary cutters. In some embodiments, the additional one or more primary cutters may be disposed radially outward from the first and second sets of primary cutters. In some embodiments, one or more of the additional primary cutters may be disposed among or between the first and second sets of primary cutters. In some embodiments, one or more blades or all of the blades may include no primary cutters having negative or zero back rake angles. All of the primary cutters may have positive back rake angles.

FIGS. 38A-38K are graphs showing some non-limiting examples of alternating back rake configurations for fixed cutters on a drill bit, such as the primary cutters and/or the back-up cutters of a drill bit. The horizontal axis represents successive radial positions of adjacent cutters of a blade within a bit's cutting profile. A position along the horizontal axis that is closer to the origin represents a cutter position closer to the axis of rotation (bit axis) of the drill bit and more distant from the gauge of the body of the drill bit. A position along the horizontal axis that is further away from the origin represents a cutter position more distant from the axis of rotation (bit axis) and closer to the gauge of the body. The graphs are intended to illustrate the relative positions of the cutters, i.e., closer to or further away from the axis of rotation, and should not be interpreted to limit or set a particular position for each cutter on the blade or within a cutting profile. Thus, the configurations or patterns illustrated can be used in any section of the blade or any section of the cutting profile. The vertical axis indicates the back rake angle of the cutters. The portion of the vertical axis above the horizontal axis indicates positive back rake angles, and the portion of the vertical axis below the horizontal axis indicates negative back rake angles. The vertical bar crossing each data point indicates a range of back rake angles that the associated cutter may have.

The following discussion of FIGS. 38A-38K refers to the illustrated back rake angles as values of the back rake angle, but it should not be interpreted to limit or set a particular back rake angle to be a single value. Rather, the value of a back rake angle discussed may encompass a range of values. Depending on the embodiments, the difference between the maximum back rake angle and the minimum back rake angle of a range may be 20°, 15°, 10°, or 5°.

FIG. 38A shows a configuration in which the back rake angles of adjacent cutters alternate between a first positive back rake angle value and a second positive back rake angle value. For example, the first and third cutters may have a first back rake angle, and the second and fourth cutters may have a second back rake angle greater than the first back rake angle. As discussed above regarding the back rake angle values, the first and third cutters may or may not have exactly the same back rake angle but may have back rake angles within a first common range. Similarly, the second and fourth cutters may or may not have exactly the same back rake angle but may have back rake angles within a second common range. Although back rake angles of four cutters are shown, similar back rake angle configuration may be used for three cutters or more than four cutters. In the case of three cutters, the middle cutter may have a back rake angle greater than the adjacent cutters in some embodiments, and may have a back rake angle less than the adjacent cutters in other embodiments. In the configuration shown in FIG. 38A, the back rake angle of every other cutter may be roughly the same or within the same range. Additionally, not all cutters in the same row need have alternating back rake angles. For example, in a row of eight cutters, four cutters may have alternating back rake angles and the remaining four cutters may have substantially the same back rake angles.

FIG. 38B shows another configuration of alternating positive back rake angles. The configuration shown in FIG. 38B differs from the configuration shown in FIG. 38A in that the back rake angle of every other cutter may gradually increase as the cutter is disposed further away from the bit axis, although the alternating arrangement of the back rake angles between adjacent cutters may still be observed. Accordingly, in some embodiments, a cutter disposed closer to the gauge may have a smaller back rake angle as compared to its adjacent cutters, but may nonetheless have a greater back rake angle as compared to a cutter disposed closer to the bit axis. For example, in the configuration shown in FIG. 38B, the fifth cutter from the bit axis may have a smaller back rake angle as compared to the fourth and sixth cutters, but may have a greater back rake angle as compared to the first, second, and/or third cutters.

FIG. 38C shows another configuration of alternating positive back rake angles. As compared to the configuration shown in FIG. 38B, in addition to gradually increasing back rake angles in a direction away from the bit axis and toward the gauge of the bit body, the difference between adjacent cutters may also increase.

FIG. 38D shows another configuration of alternating positive back rake angles. In the configuration shown in FIG. 38D, the back rake angles alternate or oscillate about a back rake angle value. In some embodiments, the back rake angles may alternate or oscillate about the average value of the back rake angles of the cutters having alternating positive back rake angles. Further, in the configuration shown in FIG. 38D, the difference between adjacent cutters may gradually decrease as the cutters are disposed further away from the bit axis.

FIG. 38E shows another configuration of alternating positive back rake angles. The configuration shown in FIG. 38E is similar to the configuration shown in FIG. 38D except that the difference between adjacent cutters may gradually increase as the cutters are disposed further away from the bit axis.

FIG. 38F shows another configuration of alternating positive back rake angles. In this configuration, the back rake angle of every other cutter may gradually decrease as the cutters are disposed further away from the bit axis, although the alternating arrangement of the back rake angles between adjacent cutters may still be observed. In some embodiments, as the back rake angles of the further outwardly disposed cutters decrease, one or more cutters may even have negative back rake angles, as indicated by some of the vertical bars extending below the horizontal axis of the graph. Further, in some embodiments, the difference between the back rake angles of adjacent cutters may also decrease as the cutters are disposed further radially outward, although in some embodiments, the difference between the back rake angles of adjacent cutters may increase as the cutters are disposed further radially outward.

FIGS. 38G and 38H show additional configurations of positive back rake angles. The configurations shown in FIGS. 38G and 38H may be similar to the configurations shown in FIGS. 38A to 38F in that an increase in back rake angles between adjacent cutters and a decrease in back rake angles between adjacent cutters may still be observed among the cutters on the same blade. The configurations shown in FIGS. 38G and 38H may differ from the configurations shown in FIGS. 38A to 38F in that the increase or the decrease may not immediately follow each other. In some embodiments, the back rake angles may continue to increase or decrease. For example, in the configuration shown in FIG. 38G, the back rake angle of the third cutter is increased from the back rake angle of the second cutter, while the back rake angle of the fourth cutter is further increased from the back rake angle of the third cutter. In the configuration shown in FIG. 38H, the back rake angle of the second cutter is increased from the back rake angle of the first cutter, while the back rake angle of the third cutter is further increased from the back rake angle of the second cutter.

As already mentioned above, the configurations or patterns illustrated in FIGS. 38A-38H can be used in any section of the blade or any section of the cutting profile. FIGS. 38I-38K show additional configurations of positive back rake angles. In addition to the back rake angles of the cutters (represented by solid dots in FIGS. 38I-38K), FIGS. 38I-38K also show the cutting profile defined by the cutters (represented by hollow dots or circles in FIGS. 38I-38K). Thus, in FIGS. 38I-38K, for each radial position that is occupied by a cutter, the solid dot represents the back rake angle value of the cutter at that radial position, and the hollow dot or circle represents that cutter's relative vertical position or height with respect to other cutters. The cutters defining each of the cutting profiles in FIGS. 38I-38K may all be primary cutters in some embodiments, may all be back-up cutters in some embodiments, or may be a combination of primary and/or back-up cutters in some embodiments. Some of the cutters may have alternating positive back rake angles. Some of the cutters may have positive back rake angles that may not be alternating.

It should be noted that the configurations or patterns illustrated in FIGS. 38I-38K are for illustrative purposes only and are not intended to be limiting. Although the alternating back rake arrangements are more prominently demonstrated in the cone section of each cutting profile for illustrative purposes, the alternating back rake arrangements may be present along any of the cone, nose, shoulder, and/or gauge sections of the cutting profile. As the cutters are disposed further radially outward, the difference between adjacent cutters may gradually decrease or increase, depending on the application. Further, although three exemplary configurations are shown in FIGS. 38I-38K, additional configurations and patterns same as or similar to those discussed above with reference to FIGS. 38A-38H may be present along any portion of the cutting profile.

With reference to FIG. 38I, the back rake angles of adjacent cutters in at least a portion of the cone section may alternate between a first positive back rake angle value and a second positive back rake angle value that may be less than the first positive back rake angle value. The first positive back rake angle value may range from 10 to 30°, from 15 to 25°, or from 18 to 22°. The second positive back rake angle value may range from 0 to 20°, from 5 to 15°, or from 8 to 12°. Every other cutter that has the first positive back rake angle value may have a common positive back rake angle value in some embodiments or may have different positive back rake angle values in some embodiments. Similarly, every other cutter that has the second positive back rake angle value may have a common positive back rake angle value or different positive back rake angle values. The difference between the back rake angle values of adjacent cutters may be less than 20° in some embodiments, e.g., less than 15°, less than 10°, or less than 5°.

As discussed earlier, cutters that are adjacent to one another in a cutting profile are typically on different blades. Thus, the cutters in FIG. 38I that are adjacent to one another in the cutting profile and have alternating back rake arrangement may not be on the same blade, and may be disposed on different blades. For example, the first cutter 3802 (i.e., the cutter at the radial position closest to the bit axis) may be disposed on a first blade, the second cutter 3804 adjacent to and radially outward from the first cutter 3802 may be disposed on a second blade, and the third cutter 3806 adjacent to and radially outward from the second cutter 3804 may be disposed on a third blade. The fourth cutter 3808 and the seventh cutter 3814 may also be disposed on the first blade, the fifth cutter 3810 and the eighth cutter 3816 may also be disposed on the second blade, and the sixth cutter 3812 and the ninth cutter 3818 may also be disposed on the third blade. Thus, in the example shown in FIG. 38I, every third cutter may be disposed on the same blade while adjacent cutters may be disposed on different blades. The first, second, and/or third blades may be adjacent to each other in some embodiments. In some embodiments, the first, second, and/or third blades may not be adjacent to each other.

In the example shown in FIG. 38I, not only do some of the cutters along the cutting profile have alternating positive back rake angles, at least some of the cutters within a single blade may also have alternating back rake angles. For example, the first, fourth, and seventh cutters 3802, 3808, 3814 on the first blade may be arranged in a row with one adjacent to the next and have back rake angle values alternating between the first and second positive back rake angle values. Similarly, the second, fifth, and eighth cutters 3804, 3810, 3816 on the second blade may be arranged in a row with one adjacent to the next and have back rake angles alternating between the first and second positive back rake angle values, and the third, sixth, and ninth cutters 3806, 3812, 3818 on the third blade may be arranged in a row with one adjacent to the next and have back rake angles alternating between the first and second positive back rake angle values.

FIG. 38J shows another configuration of alternating positive back rake angles. The arrangement shown in FIG. 38J is similar to the arrangement shown in FIG. 38I, except that the cutters having the first positive back rake angle value in FIG. 38I have the second positive back rake angle value in FIG. 38J, and the cutters having the second positive back rake angle value in FIG. 38I have the first positive back rake angle value. Further, similar to the arrangement shown in FIG. 38I, every third cutter of the cutters in the cone section shown in FIG. 38J having alternating back rake angles may be disposed on the same blade. Thus, not only may the adjacent cutters along the cutting profile of FIG. 38J have alternating positive back rake angles, the adjacent cutters on at least some of the blades may also have alternating positive back rake angles.

FIG. 38K shows another configuration of alternating positive back rake angles. In this example, some pairs of adjacent cutters may have positive back rake angles of a first positive back rake angle value, and some pairs of adjacent cutters may have positive back rake angles of a second positive back rake angle value. The first positive back rake angle value may range from 10 to 30°, from 15 to 25°, or from 18 to 22°. The second positive back rake angle value may range from 0 to 20°, from 5 to 15°, or from 8 to 12°. Within each pair, the two adjacent cutters may have the same or different, but similar positive back rake angles. In the example shown in FIG. 38K, every other pair of cutters may have a common or similar positive back rake angles. Thus, adjacent pairs of cutters in the example of FIG. 38K have alternating back rake angles. Although pairs of the cutters are shown to have common or similar positive back rake angles in the example of FIG. 38K, more than two, such as three, four, five, or more, adjacent cutters may have a common or similar back rake angles and thus form a group or set of adjacent cutters having a common or similar back rake angles. Further, adjacent or consecutive groups or sets may have alternating back rack angles, and the number of cutters in each group may be the same or different from each other.

As already mentioned above, the various cutter configurations or patterns described herein may be implemented in any of the cone section, the nose section, the shoulder section, and/or the gauge section. The cutters having any of the cutter configurations described herein or a variation or a combination thereof may be disposed on a single or multiple blades. In some embodiments, the back rake angles of the cutters may alternate from blade to blade. For example, the cutters disposed in one or more of the cone, nose, shoulder, and/or gauge sections of a first blade may all have positive back rake angles within a first range, such as from 10 to 30°, from 15 to 25°, or from 18 to 22°. The cutters disposed in one or more of the cone, nose, shoulder, and/or gauge sections of a second blade may all have positive back rake angles within a second range, e.g., from 0 to 20°, from 5 to 15°, or from 8 to 12°. The first blade and the second blade may be adjacent to each other in some embodiments, or may be separated from each other by another blade in some embodiments.

In some embodiments, the drill bit may include a first set of blades and a second set of blades. The cutters in one or more of the cone, nose, shoulder, and/or gauge sections of the first set of blades may all have positive back rake angles within the first range. The cutters in one or more of the cone, nose, shoulder, and/or gauge sections of the second set of blades may all have positive back rake angles within the second range. The first set of blades and the second set of blades may be arranged in any manner. In some embodiments, the first set of blades and the second set of blades may be arranged in an alternating manner. In some embodiments, two or more blades of the first set of blades may be arranged in an adjacent manner. In some embodiments, two or more blades of the second set of blades may be arranged in an adjacent manner. In some embodiments, the adjacent two or more blades of the first set and the adjacent two or more blades of the second set may be arranged in a consecutive manner.

Without being bound by theory, it is believed that when going from a hard to soft formation, greater back rake angles on the nose section reduce weight on the cone and shoulder sections. Moreover, greater back rake angles on the nose section may prevent over-engagement of the nose section by allowing the cone and shoulder sections to catch up to the nose section.

In some embodiments, all blades of a drill bit may include primary cutters having alternating positive back rake angles. In some embodiments, only some of the blades may include primary cutters having alternating positive back rake angles. That is, one or more blades may not include primary cutters having alternating positive back rake angles, although one or more of the back-up cutters may have alternating positive back rake angles. In some embodiments, one or more blades may include both primary cutters having alternating positive back rake angles and back-up cutters having alternating positive back rake angles.

By having alternating positive back rake angles, the back rake angles may alternate between aggressive (i.e., smaller back rake angle) and passive (i.e., larger back rake angle) along the blade, and may alternate between aggressive and passive along the entire cutting profile. The aggressive back rake angles may increase point loading. The passive back rake angles may protect against impact damage during formation transitions. Combining aggressive and passive back rake angles across the drill bit may be particularly beneficial for applications with heavy transitional drilling. Combining aggressive and passive back rake angles may provide forgiveness across formation transitions while maintaining ROP (rate of penetration) potential in each dedicated formation. Combining aggressive and passive back rake angles may also be beneficial for applications where torque fluctuations are common and can cause premature bit damage. The alternating back rake arrangements may also function as a depth of cut controller. The arrangement may be placed in various locations on the bit profile and works to progressively absorb changes in weight on bit. In some embodiments, the cutters having aggressive back rake angles may be non-cylindrical cutters, while the cutters having passive back rakes may be cylindrical cutters. In other embodiments, the cutters having aggressive back rake angles may be cylindrical cutters, while the cutters having passive back rakes may be non-cylindrical cutters. It will be appreciated that other layouts are possible. For example, all cutters may be cylindrical or non-cylindrical, cylindrical and non-cylindrical cutters may alternate (e.g., based on a radial distance from a center of the drill bit), cutters on primary blades may have one shape, while cutters on secondary blades may have another shape. Additionally, where non-cylindrical cutters are used, different non-cylindrical shapes of cutters may be used for aggressive cutters and passive cutters, for different blades, for alternating cutters, and/or in other cutter layouts.

In contrast to known back rake arrangements where the back rake angle of every other cutter remains the same and the difference between the back rake angles of the adjacent cutters remains the same, the present technology described herein varies the back rake angles of cutters and also varies the difference between the back rake angles of adjacent cutters at different sections of the cutting profile. The back rake arrangements described herein achieve increased bit durability, reduced vibration, and better bit control. The alternating positive back rake angle arrangements described herein result in smoother torque signature, less axial vibration damage, and less lateral vibration damage, leading to improved dull grading. The back rake arrangements described herein further requires less mechanical specific energy while maintaining a greater rate of penetration, and thus achieve improved drilling efficiency. The alternating positive back rake angle arrangements can be particularly beneficial for transitional drilling by maintaining ROP (rate of penetration) potential in each dedicated formation.

In addition to having alternating back rake angles, as described above, in some embodiments, at least some of the cutters, primary cutters and/or back-up cutters, may also have non-zero side rake angles. In some embodiments, at least some of the cutters may have alternating side rake angles. As plotted in graphs of FIGS. 32A-32F, on each blade, at least some of the primary cutters may have alternating side rake angles. Depending on the application, the back-up cutters may or may not have alternating side rake angles. Thus, in some embodiments, at least some of the cutters may have both alternating positive back rake angles and alternating side rake angles.

The graphs of FIGS. 39A to 39G illustrate various embodiments of side rake configurations for fixed cutters on a rotary earth boring tool, such as a PDC bit or reamer. The horizontal axis represents successive positions of cutters along a blade, e.g., successive radial positions of adjacent cutters within a bit's cutting profile. The origin represents, in these examples, the bit axis, with successive positions along the horizontal axis representing positions closer to the gauge of the body of the tool and more distant from the bit axis. However, the patterns illustrated could be used in intermediate sections of the cutting profile or intermediate sections of a blade. The vertical axis indicates the side rake angle of the cutters. The graphs are not intended to imply any particular range of positions on a blade or within a cutting profile.

The configuration of FIG. 39A represents a configuration in which the differences or changes in side rake angles of at least three cutters in adjacent positions alternate directions. For example, the angle of the cutter in the first position and the angle of the cutter in the second position have opposite polarities. The direction of change or the difference is negative. The change between the cutters in the second and the third positions is a direction opposite the direction of the change from the first to the second cutter. The angle increases, and the difference in angles is positive.

The pattern of FIG. 39B is similar to FIG. 39A, except that it is comprised of two related patterns 3950 and 3952, which are the inverse of each other. In each of these two patterns the change of the side rake angle from an individual cutter to a group of two (or more) cutters with a similar side rake angle is in one direction, and then the change in angle from the group to a single cutter is in the opposite direction.

In the example configuration of FIG. 39C, the differences in side rake angles within group 3954 of at least two successive cutters (four in the example) is in a first direction. The angle in this group progressively increases, in this example from negative to positive. In a next adjacent group 3956 of two or more cutters, the side rake angles change in the opposite between adjacent members of cutters within that group. In this example, the angles decrease, and furthermore they decrease from being positive angles to negative angles. A third group of at least cutters 3958, having increasing angles, and thus the direction of change in angle within this group is positive. The pattern thus illustrates an alternating of the direction of change within adjacent groups of cutters.

FIG. 39D is similar to FIG. 39C, except that the changes in side rake angles follow a sinusoidal pattern rather than the linear pattern.

FIG. 39E shows an example of a pattern in which the side rake angles within groups 3960 and 3962 of two or more successive cutters are similar (for example, all the same magnitude, or all negative or positive) but that every third (or more) cutter 3964 has a different angle (for example, positive when the angles in the groups 3960 are negative). The angle changes in a first direction from group 3960 to cutter 3964, and then in the opposite direction between cutter 3964 and group 3962. Inverting the pattern is an alternative embodiment. The cutters having one polarity of side rake might be positioned on side of the bit and the cutters with the opposing polarity would be positioned on the other side of bit. For instance, one side rake would be used on blades 1 to 3 and the second side rake would be used on blades 4 to 6 of a six bladed bit.

FIG. 39F is an example of pattern for a bit in which side rakes of two or more adjacent cutters with a group 3966, for example within a cone of a bit, are positive, and then group of two or more adjacent cutters are negative in an adjacent a group 3968. This second group could be, for example, along the nose and shoulder of the bit. The side rake angle then becomes positive again. The pattern also illustrates step-wise decreases or increases within a group.

FIG. 39G is an example of a step-wise pattern or configuration in which the side rake angle is generally increasing. In this example, the side rake angle is increasing generally in a non-linear fashion, but the change in angle swings between an increasing direction and neutral. In this example the increasing positive side rake pushes cuttings increasingly to the outer diameter of the bit, increasing drilling efficiency.

In alternatives to the patterns or configurations of FIGS. 39A to 39D, patterns may be inverted. Furthermore, although the polarity of the angles (positive or negative) form part of the exemplary patterns, the values of the angles in alternative embodiments can be shifted positive or negative without changing other aspects of the pattern, namely the pattern in the directions of changes in the angle between adjacent cutters or group of cutters. In the configuration of FIG. 39A, for example, all of the cutters could have either positive or negative side rake without changing the alternating changes in direction of the differences between the cutters.

Furthermore, the alternating pattern of positive and negative direction changes could occur first between cutters with positive angles, and then shift toward a mixture of positive and negative angles, and then toward all negative angles without interrupting the alternating pattern. Another alternative embodiment is a bit with, for instance, blades 1 to 3 having one side rake and blades 4 to 6 having an opposing or substantially different side rake, similar to the arrangement shown in FIGS. 39E and 39F. This design could reduce walk tendency, and might be configured to be more laterally stable than a more conventional design.

FIGS. 39H to 39J are additional examples of these alternative patterns. In FIG. 39H, the side rake angles are positive and generally increase. But, at some frequency, the angle decreases. In this example, the frequency is every third cutter in the sequence. However, a different frequency could be chosen, or the point at which the decrease occurs can be based on a transition between sections of the bit or blade, such as between cone and nose, nose and shoulder, and shoulder and gauge.

FIG. 39I is an alternative embodiment to FIG. 39A, in which the rake angles remain positive, but increase and decrease in an alternating fashion.

FIG. 39J illustrates that patterns of rake angle changes may also involve varying the magnitude of change in a rake angle between cutters in addition to direction.

Some of the benefits or advantages to adjusting side rakes of fixed cutters on earth boring tools with patterns such as those described above include one or more of the following:

Chip removal and chip evacuation by managing chip growth and the breakage or

removal of cutting chips. This may be enhanced by having hydraulics tuned to enhance chip removal and/or the chip breaking effects.

Improved drilling efficiency achieved by reduced vibration and torque, as a result of managed side forces, reduced imbalance force and/or more efficient rock failure mechanisms. These might be achieved by managing force directions. Rock fracture communication between cutters is enhanced with engineered use of side rakes during bit design including rock fracture communication between primary and backup cutters. The modified elliptical cut shapes achieved with the use of side rake can have a dramatic effect on improving drilling efficiency and can be further enhanced by the position, size and/or orientation of backup cutters. In addition, the strategic use of side rake near or on gauge can also improve steerability.

Depth of cut (DOC) management by using different side rakes to give variable elliptical cut shapes in consort with position of backup elements to better manage depth-of-cut. This design concept may be adopted in discrete locations on the bit to maximize the benefits.

FIGS. 40A-40F show the back rake angles of primary cutters on blades of a 6 blade drill bit. FIGS. 41A-41F show the side rake angles of the primary cutters on blades of a 6 blade drill bit.

As plotted in graphs of FIGS. 40A-40F, on each blade, at least some of the primary cutters had alternating positive back rake angles. Depending on the application, the back-up cutters may or may not have alternating positive back rake angles.

The primary cutters having alternating positive back rake angles may be disposed on at least one of the cone section, the nose section, the shoulder section or the gauge region. For example, the primary cutters that have alternating positive back rake angles on the blades may be disposed on the cone section, the nose section, and the shoulder section. The primary cutters having alternating positive back rake angles on the blades may be disposed on the cone section, the nose section, the shoulder section, and all the way on the gauge. The primary cutters having alternating positive back rake angles on the blades may be disposed only on the nose and shoulder sections.

A drill bit having alternating positive back rake angles, or alternating passive and aggressive back rake angles, may have improved dull grading (e.g., 0-1) as compared to drill bits without alternating aggressive and passive back rake angles, which may have dull grading of from 2 to 8 or 1 to 4 resulted from the same testing/drilling conditions.

“Dull grading” indicates the amount of wear of a cutting structure. Dull grading is reported by use of an eight-increment wear scale in which “0” represents no wear and “8” indicates that no usable cutting surface remains. For PDC cutters, the amount of wear is measured across the diamond table of a cutter. For example, if wear occurs across ⅛ of the diamond table, a dull grading of 1 is reported for that cutter; if wear occurs across 2/8 of the diamond table, a dull grading of 2 is reported for that cutter; and so forth. For drill bits, two values of dull grading are generally reported: an average dull grading (rounded to the nearest integer) for the inner cutters of the drill bit and an average dull grading (rounded to the nearest integer) for the outer cutters of the drill bit. The inner cutters are cutters disposed within the inner ⅔ of the bit diameter, and typically comprise cutters inside the nose of the drill bit. The outer cutters are cutters disposed within the outer ⅓ of the bit diameter, and typically comprise cutters outside the nose of the drill bit.

In some embodiments, by arranging the cutters to have alternating positive back rake angles, the average dull grading for the inner and/or outer cutters may be reduced by at least 3 wear scale, as compared to drill bits without alternating positive back rake angles operating under the same testing/drilling conditions. For example, while a dull grading of 4 or greater, up to 8, may be observed for drill bits without alternating positive back rake angles, a dull grading of only 0 or 1 may be observed for drill bits with alternating positive back rake angles operating under the same testing/drilling conditions.

Using the alternating positive back rake angle configurations described herein may also result in smoother torque signature, less axial vibration damage, and less lateral vibration damage than when using a drill bit without the alternating positive back rake angle configurations.

Typically, a drill bit is designed with blades that have the same or substantially similar shapes. As a result, the cutters at a given radial distance from the central axis of the drill bit are generally evenly spaced relative to rotation. When the conventional drill bit is rotated in the subterranean formation, the time lag between when a cutter on one blade and the radially corresponding cutter of an adjacent blade engage the rock wall is the same for all cutter pairs between the two blades. Said another way, the cutters periodically engage imperfections and inconsistencies in the rock, which may jolt the drill bit and cause vibration.

In some embodiments of the present technology, drill bits including non-cylindrical cutters may incorporate multiple blades that have distinct shapes or orientations. This design changing shape or orientation of the blades allows each individual cutter to engage the imperfections incrementally. The blades may be designed such that the time lag between when a cutter on one blade and the radially corresponding cutter of an adjacent blade engage the rock wall is not the same for all cutter pairs between the two blades. As a result, an imperfection or inconsistency at a given position is engaged non-periodically by the cutters. As a result, the drill bits of the present disclosure can operate with minimized susceptibility to vibration. In particular, the novel drill bits can drill through subterranean wellbores at smooth torque (e.g., minimizing torque spikes).

The present disclosure relates to a drill bit structurally modified to smooth torque and minimize vibration of the drill bit (and the drill string) during operation. In some embodiments, the drill bit comprises a plurality of blades, the pattern (e.g., shape and/or orientation) of some or all blades differing from the other blades in shape or orientation. Varying the shape and/or orientation of the blades relative to other blades, as described herein, smooths the torque on the drill bit during operation.

FIG. 42 illustrates an embodiment of the drill bit 4200 according the present disclosure. Drill bit 4200 may be similar to drill bits 100 and 200 described herein and may include any of the features of drill bits 100 and 200. Drill bit 4200 is designed structurally and mechanically to be rotated around its central axis 4202. As shown, drill bit 4200 comprises a bit body 4204. Bit body 4204 may include a face which is intended to engage a bottom end of a well bore being drilled. In the embodiment shown, the face substantially lies in a plane perpendicular to central axis 4202 of drill bit 4200. Drill bit 4200 further includes a plurality of primary blades 4208 formed in bit body 4204, extending from the face. In the embodiment shown in FIG. 42, each of the plurality of primary blades 4208 has a waveform pattern having one or more peaks and valleys, with the waveform pattern being out of phase from the other primary blades 4208, as described in detail below. In addition, as shown, drill bit 4200 may include secondary blades 4210, which are positioned among the plurality of primary blades 4208, such as between two adjacent primary blades 4208. Whereas the plurality of primary blades 4208 extend from a point generally near the central axis 4202 of bit body 4204 to the outer edge of bit body 4204, the secondary blades 4210 begin a radial distance from central axis 4202 and extend to the outer edge of bit body 4204. Channels 4212 are formed between each of the plurality of blades 4208 and the secondary blades 4210. In other embodiments, the bit may include primary blades but no secondary blade, or secondary blades and no primary blade.

In drill bit 4200, a plurality of cutters 4220 are placed along the leading edge of primary blades 4208 and/or secondary blades 4210. Cutters 4220 may include non-cylindrical cutters, such as cutters 400-1600 described herein. Cutters 4220 may also include cylindrical cutters in some embodiments. The working surfaces of cutters 4220 are facing generally in the rotationally forward direction for shearing the subterranean formations when drill bit 4200 is rotated about its central axis 4202. In some embodiments, each cutter 4220 may be approximately aligned with the leading edge of the respective blade. In other embodiments, a side rake of one of more of the cutters 4220 may be adjusted such that the respective cutter 4220 is not aligned with the leading edge of the blade. For example, the side rake of one or more of the cutters 4220 such that less than about 0.060 inches, less than about 0.050 inches, less than about 0.040 inches, less than about 0.030 inches, less than about 0.020 inches, less than about 0.010 inches, or less of the cutter pocket is exposed. The side rake may be adjusted in any embodiment, however side rake adjustments may be particularly useful in blades whose waveforms have particularly high amplitudes, as such waveforms are more likely to expose larger portions of the cutter pocket without such side rake adjustments. Reducing the exposure of the cutter pocket may help prevent cuttings from lodging within the exposed cutter pocket. In some embodiments, one or more of blades 4208 may comprise one or more rows of cutters 4220 disposed thereon. For example, the drill bit may include a first row of PDC cutters and a second row of PDC cutters mounted on one or more of the blades. In one embodiment, the first row of PDC cutters may be primary cutters, and the second row of PDC cutters may be secondary or backup cutters. Furthermore, the primary cutters may be single set or a plural set (e.g., multiple rows of cutters). In addition, drill bit 4200 may include several load bearing elements 4215, positioned behind the PDC cutters 4220.

While shown in FIG. 42 with the waveform pattern on each primary blade including both concave and convex regions, it will be appreciated that in some embodiments, the waveform pattern of a primary blade and/or secondary blade may include only a single concave region or a single concave region. In some embodiments, the shape of the waveform of rotationally adjacent blades may alternate in some embodiments. For example, where a secondary blade 4210 is disposed between adjacent primary blades 4208a, adjacent blades may alternate between having convex and concave waveform portions.

By utilizing blades with waveform patterns as described in relation to FIG. 42, the time lag between when a cutter on one blade and the radially corresponding cutter of an adjacent blade engage the rock wall is not the same for all cutter pairs between the two blades. As a result, an imperfection or inconsistency at a given position is engaged non-periodically by the cutters. As a result, the drill bits of the present disclosure can operate with minimized susceptibility to vibration. In particular, the novel drill bits can drill through subterranean wellbores at smooth torque (e.g., minimizing torque spikes).

FIG. 43 illustrates another embodiment of the drill bit 4300 according the present disclosure. Drill bit 4300 shown in FIG. 43 is also structurally adapted to smooth torque. Drill bit 4300 is designed structurally and mechanically to be rotated around its central axis 4302a. As with the embodiments shown in FIG. 42, drill bit 4300 of comprises a body 4304 disposed radially around central axis 4302a. Drill bit 4300 differs from that drill bit 4200 in the shape and orientation of its blades 4308a, 4308b, 4308c, which is have a slightly curved pattern, but each differs in orientation. In particular, the blades 4308a, 4308b, 4308c of the drill bit 4300 may have differing offsets from the central axis, as described in detail below. For example, as illustrated, a first blade 4308a has no offset and extends from central axis 4302a to an outer edge of bit body 4304. A second blade 4308b has a negative offset and extends from non-central axis 4302b to an outer edge of bit body 4304. A third blade 4308c has a positive offset and extends from central axis 4302c to an outer edge of bit body 4304. In addition, drill bit 4300 includes secondary blades 4310. Channels 4312 are formed between each of the plurality of blades 4308a, 4308b, 4308c and secondary blades 4310. Notably, various combinations of blades may be employed together, and the disclosure is not limited to the specific configurations shown in the figures. Drill bit 4300 includes a plurality of cutters 4320, placed along the leading edge of blades 4308a, 4308b, 4308c and of secondary blades 4310. The drill bit 4300 may similarly comprise one or more rows of cutters 4320 disposed on one or more blades. In addition, drill bit 4300 may include several load bearing elements 4315, positioned behind the PDC cutters 4320.

FIG. 44 illustrates a drill bit 4400 that may be similar to drill bit 4300. For example, drill bit 4400 may include primary blades 4408a, 4408b, 4408c, which are formed in bit body 4404 and extend from the face, with each blade 4408 including a number of cutters 4420 and/or load bearing elements. While shown with only primary blades 4408, it will be appreciated that in addition or in place of primary blades 4408 the drill bit may include one or more secondary blades. Each of the plurality of blades 4408a, 4408b, 4408c may have a slight curved pattern, but each differs in orientation. For example, a first blade 4408a may have a positive offset relative to central axis 4402a to an outer edge of bit body 4404. A second blade 4408b has no offset and extends from non-central axis 4402b to an outer edge of bit body 4404. A third blade 4408c has a positive offset and extends from central axis 4402c to an outer edge of bit body 4404. Notably, various combinations of blades may be employed together, and the disclosure is not limited to the specific configurations shown in the figures.

FIG. 44A is a graph illustrating the relative positioning the cutters 4420 of drill bit 4400. As shown in FIG. 44B, as the cutters 4420 of each blade as rotated to a same angular position, only one cutter 4420 (or other small subset of the cutters 4420) from each blade 4408 may overlap at a time. This may ensure that imperfections in the wellbore create from each blade will interact with surrounding blades gradually, rather than all at once. This may help smooth torque and reduce vibration.

In the drill bits of the present disclosure, the blades extending from the bit body may vary in terms of shape and/or orientation, as detailed below. In some cases, the shape and orientation of the blade are defined with respect to the blade in and of itself. For example, the shape of the blade may be defined by a leading edge of the blade. In some cases, the shape and orientation are defined with respect to a front line along which the cutting faces of the PDC cutters are aligned. For example, the plurality of PDC cutters supported by a first blade of the drill bit may be aligned along a first line extending from the interior of the bit face to the outer edge of the bit body. The shape and orientation detailed below may be referring to the shape and orientation of that first line (or the respective line on other blades).

Each blade of the drill bit may have any of a variety of shapes. In some cases, one or more blades of the drill bit may have a linear pattern. In some cases, one or more blades of the drill bit have a curved pattern. As used herein, a curved pattern refers to any arcuate shape having a single curve or bend. The shape of the curved pattern is not particularly limited. For example, the curved pattern may be a segment of a circle, ellipse, parabola, or any other rational, algebraic curve. In some embodiments, the curved pattern may have a degree of curvature from −90° to 90°, e.g., from −80° to 80°, from −70° to 70°, from −60° to 60°, from −50° to 50°, or from −45° to 45°.

In some cases, one or more blades of the drill bit have a waveform pattern. As used herein, a waveform pattern refers to a periodic varying shape. In some cases, for example, the waveform pattern may periodically vary in a generally sinusoidal, square, triangular, or sawtooth shape. It should be appreciated that a sinusoidal waveform pattern need not be shaped as a mathematically defined sine function; rather, a sinusoidal waveform pattern refers to a waveform pattern defined by smooth, periodic oscillation. In some embodiments, the waveform pattern may include at least one concave portion and at least one convex portion, however in some embodiments a waveform pattern may include only a single convex section or a single concave section. Similarly, a square waveform pattern need not be shaped as a perfect square; rather, a square waveform pattern refers to a waveform pattern defined by an amplitude that alternates at a steady frequency between fixed minimum and maximum values.

In some embodiments, the waveform pattern may extend entirely from an inner (radially) edge of the blade to an outer edge of the blade. In other embodiments, the waveform pattern may extend across only a portion of a length of the blade. For example, the waveform pattern may be provided on an inner 10% of the blade, an inner 15%, an inner 20%, an inner 25%, an inner 30%, an inner 35%, an inner 40%, an inner 45%, an inner 50%, an inner 55%, an inner 60%, an inner 65%, an inner 70%, an inner 75%, an inner 80%, an inner 85%, an inner 90%, an inner 95%, or more, while the remaining outer portion has a different pattern (such as linear and/or curved). In particular, in some embodiments the waveform pattern may be present on at least the cone and nose of the bit body, while all or a portion of the blade within the shoulder and/or gauge may have a different pattern.

In some embodiments, each blade on a given drill bit may have a waveform pattern.

The waveform pattern on each blade may be out of phase with the rotationally adjacent blade. In some embodiments, the rotationally adjacent blade may refer to any blade on the drill bit (e.g., primary and/or secondary blade), while in other embodiments the rotationally adjacent blade may mean a rotationally adjacent blade within the cone of the drill bit (i.e., a rotationally adjacent primary blade). The adjacent blades may have a same amplitude, frequency, and/or wavelength, while having different phases. For example, as illustrated, a first blade (e.g., blade on the right side as illustrated) may start with a slope that approaches a trough of the waveform pattern, while a second blade (e.g., blade on the top side as illustrated) begins with a slope that approaches a peak of the waveform pattern, and a third blade (e.g., blade on the bottom left) has a slope that begins just after a trough of the waveform pattern. While shown with each blade having a waveform with a similar or same amplitude and wavelength, some drill bits may include blades that have waveforms of different amplitudes and/or wavelengths. In some embodiments, the amplitude, wavelength, and/or frequency of a single blade may vary across a length of the blade (i.e., as the radial distance from the central axis increases). For example, an amplitude of the waveform pattern may be greater at inner regions of the blade than at outer regions.

In some embodiments, the drill bit comprises a plurality of blades, and each blade has a different shape from the others. In some cases, the shape of the blades differ in that each blade has a different type of pattern. For example, the drill bit may comprise two blades: a first blade having a waveform pattern, and a second blade having a linear or curved pattern. In another example, the drill bit comprises three blades: a first blade having a waveform pattern, a second blade having a linear pattern, and a third blade having a curved pattern.

In some cases, the shapes of the blades differ despite overlapping types of patterns. In some embodiments, for example, the drill bit may comprise two blades: a first blade having a first waveform pattern, and a second blade having a second waveform pattern. The first and second waveform patterns may differ in that they have differing oscillating patterns. For example, the first waveform pattern may be sinusoidal, and the second waveform may be square. The differing oscillating patterns may differ, for example, in terms of one or more of amplitude, frequency or wavelength, as detailed below.

In some cases, the drill bit may comprise three or more blades with any combination of the above-described shapes. In one embodiment, for example, the drill bit comprises three blades, including a first waveform pattern, a second waveform pattern, and a linear pattern, respectively. In this embodiment, the first and second waveform pattern may have differing shapes. Of course, other combinations are also possible.

In some embodiments, the plurality of blades on the drill bit may differ in terms of orientation. As used herein, the “orientation” of a blade refers to various aspects of the blade's position on the face of the bit body. In some cases, for example, two or more blades of the bit body may have the same (or generally the same) shape but may nevertheless differ in terms of orientation.

In some aspects, the orientation of the blade refers to the point from which the blade radially extends. As noted above, the blades of the drill extend from a point in the interior of the bit face to the outer edge of the bit body. The interior of the bit face, as used herein, refers to a circular region of the face defined by a radius that is one-third the total radius of the bit face. In some embodiments, one or more blades may extend from any point substantially near the central axis of the bit body. In some cases, for example, a blade may extend from the central axis of the bit body.

In some embodiments, one or more blades may extend from another point that is not at or near the central axis of the bit body but remains within the interior of the bit face. In some cases, this point may be a non-central axis of the drill bit. The non-central axis may be any other axis of the bit body. In some cases, the non-central axis may be an axis separate from but parallel to the central axis of the bit body. In this context, the term non-central axis refers to an imaginary line parallel to the central axis.

In some aspects, the orientation of the blade refers to the offset of the blade from the central axis. As used herein, the term “offset” refers to the perpendicular distance of a given blade's origin from the central axis of the blade bit. The offset of a blade may vary irrespective of the shape of the blade. Said another way, the following discussion of offsets its applicable to a blade having any shape according to the above description.

In some aspects, the orientation of the blade refers to the metrics of a waveform pattern. As noted above, one or more blades of the drill bit may have a waveform pattern. In some embodiments, the drill bit comprises a first blade comprising a first waveform pattern and a second blade comprising a second waveform pattern, and the first waveform pattern and the second waveform pattern differ according to one or more of the metrics described herein.

The waveform pattern of a given blade may vary in terms of amplitude. The amplitude of the waveform pattern refers to the distance from a center line to the top of a crest (or bottom of a tough). The amplitude of the waveform pattern of a blade is not particularly limited. In some embodiments, the ratio of the radius of the bit body to the amplitude of a waveform pattern may range from 5 to 75, e.g., from 5 to 70, from 5 to 65, from 5 to 60, from 5 to 55, from 5 to 50, from 8 to 75, from 8 to 70, from 8 to 65, from 8 to 60, from 8 to 55, from 8 to 50, from 10 to 75, from 10 to 70, from 10 to 65, from 10 to 60, from 10 to 55, from 10 to 50, from 12 to 75, from 12 to 70, from 12 to 65, from 12 to 60, from 12 to 55, from 12 to 50, from 15 to 75, from 15 to 70, from 15 to 65, from 15 to 60, from 15 to 55, or from 15 to 50. In terms of lower limits, the ratio of the radius of the bit body to the amplitude of the waveform pattern may be greater than 5, e.g., greater than 8, greater than 10, greater than 12, or greater than 15. In terms of upper limits, the ratio of the radius of the bit body to the amplitude of the waveform pattern may be less than 75, e.g., less than 70, less than 65, less than 60, less than 55, or less than 50.

Additionally or alternatively, the waveform pattern of a given blade may vary in terms of wavelength. The wavelength of the waveform pattern refers to the length of one complete period of the wave. The wavelength of the waveform pattern of a blade is not particularly limited. In some embodiments, the ratio of the radius of the bit body to the wavelength of a waveform pattern may range from 0.5 to 50, e.g., from 0.5 to 49, from 0.5 to 48, from 0.5 to 47, from 0.5 to 46, from 0.5 to 45, from 0.6 to 50, from 0.6 to 49, from 0.6 to 48, from 0.6 to 47, from 0.6 to 46, from 0.6 to 45, from 0.7 to 50, from 0.7 to 49, from 0.7 to 48, from 0.7 to 47, from 0.7 to 46, from 0.7 to 45, from 0.8 to 50, from 0.8 to 49, from 0.8 to 48, from 0.8 to 47, from 0.8 to 46, from 0.8 to 45, from 0.9 to 50, from 0.9 to 49, from 0.9 to 48, from 0.9 to 47, from 0.9 to 46, or from 0.9 to 45. In terms of lower limits, the ratio of the radius of the bit body to the wavelength of the waveform pattern may be greater than 0.5, e.g., greater than 0.6, greater than 0.7, greater than 0.8, or greater than 0.9. In terms of upper limits, the ratio of the radius of the bit body to the wavelength of the waveform pattern may be less than 50, e.g., less than 49, less than 48, less than 47, less than 46, or less than 45.

Additionally or alternatively, the waveform pattern of a given blade may vary in terms of frequency. The frequency of the waveform pattern refers to the number of periods of the wave completed on the blade. The frequency of the waveform pattern of a blade is not particularly limited. In some embodiments, the frequency of the waveform pattern may range from 0.6 to 30, e.g., from 0.6 to 28, from 0.6 to 26, from 0.6 to 24, from 0.6 to 22, from 0.6 to 20, from 0.7 to 30, from 0.7 to 28, from 0.7 to 26, from 0.7 to 24, from 0.7 to 22, from 0.7 to 20, from 0.8 to 30, from 0.8 to 28, from 0.8 to 26, from 0.8 to 24, from 0.8 to 22, from 0.8 to 20, from 0.9 to 30, from 0.9 to 28, from 0.9 to 26, from 0.9 to 24, from 0.9 to 22, from 0.9 to 20, from 1 to 32, from 1 to 28, from 1 to 26, from 1 to 24, from 1 to 22, or from 1 to 20. In terms of lower limits, the ratio of the radius of the bit body to the wavelength of the waveform pattern may be greater than 0.6, e.g., greater than 0.7, greater than 0.8, greater than 0.9, or greater than 1. In terms of upper limits, the ratio of the radius of the bit body to the wavelength of the waveform pattern may be less than 30, e.g., less than 28, less than 26, less than 24, less than 22, or less than 20.

Additionally or alternatively, the waveform pattern of a given blade may vary in terms of phase. The phase of the waveform pattern refers to the location of a point within a single period of the waveform. For example, the waveform pattern of a given blade may begin at a crest of the waveform, a trough of the waveform, or any point therebetween. In some aspects, the phase may be defined with degrees as angular units, such that the waveform completes one full period in 360°. In this approach, the waveform is at the center line at 0°, 180°, and 360°, at its crest at 90°, and at its trough at 270°. When defined in this way, the waveform pattern of a given blade may begin (e.g., at a point at or near the central axis) at any phase from 0° to 360°.

In some embodiments, two or more blades of the drill bit may differ with respect to any one or more of the above wave metrics. In some embodiments, for example, a first blade may have a waveform pattern with a first, smaller amplitude, and a second blade may have a waveform pattern with a second, larger amplitude. In some embodiments, for example, a first blade may have a waveform pattern with a first, shorter wavelength, and a second blade may have a waveform pattern with a second, longer amplitude. In some embodiments, for example, a first blade may have a waveform pattern with a first, lower frequency, and a second blade may have a waveform pattern with a second, higher frequency.

A difference in phase between the waveform patterns of two blades may be characterized by phase shift. The phase shift refers to the difference between the phase at the beginning of two waveform patterns (e.g., the central axis or the non-central axis from which the blade extends). For example, if the waveform pattern of a first blade begins at a phase of 90°, and the waveform pattern of a second blade begins at a phase of 180°, the phase shift between the two is the difference, or 90°. When the phase shift is zero, the two signals are said to be in phase, otherwise they are out of phase with each other.

In some embodiments, the phase shift between the waveform of a first blade and the waveform of a second blade may be from 0° to 180°, e.g., from 0° to 165°, from 0° to 150°, from 0° to 135°, from 0° to 120°, from 15° to 180°, from 15° to 165°, from 15° to 150°, from 15° to 135°, from 15° to 120°, from 30° to 180°, from 30° to 165°, from 30° to 150°, from 30° to 135°, from 30° to 120°, from 45° to 180°, from 45° to 165°, from 45° to 150°, from 45° to 135°, from 45° to 120°, from 60° to 180°, from 60° to 165°, from 60° to 150°, from 60° to 135°, or from 60° to 120°. In terms of lower limits, the phase shift may be greater than 0°, e.g., greater than 15°, greater than 30°, greater than 45°, or greater than 60°. In terms of upper limits, the phase shift may be less than 180°, e.g., less than 165°, less than 150°, less than 135°, or less than 120°.

A drill bit having blades with waveform patterns that differ based on variation in any one or more above wave metric is envisioned by the present disclosure. In one embodiment, for example, a drill bit may comprise five blades, each with a unique waveform pattern: the first blade may have a sinusoidal waveform pattern, the waveform pattern of the second blade may have a smaller amplitude (relative to the first blade), the waveform pattern of the third blade may have a longer wavelength (relative to the first blade), the waveform pattern of the fourth blade may have a phase shift of 90° (relative to the first blade), and the waveform pattern of the fifth blade may have a phase shift of 180° (relative to the first blade). Other embodiments of the drill bit may have fewer blades (e.g., three or four blades) with a similar combination of differing offsets.

FIG. 45 is a flowchart illustrating operations of a method 4500 for bonding a cutter to a downhole tool according to some embodiments of the present invention. Method 4500 may be used to secure a non-cylindrical cutter, such as cutters 400-1600, into a corresponding non-cylindrical cutter pocket, such as cutter pockets 1720, 1722, 1600, and 1902. Method 4500 may begin at operation 4502 by inserting a cutter having a non-circular cross-section into a non-cylindrical pocket formed into a downhole tool. A small gap, such as between about 0.010 inch and 0.025 inch, may be formed between an outer face of the cutter and a wall defining the pocket. This gap may provide a volume for receiving a metal-containing substance, such as a brazing alloy, that is used to bond the cutter to the walls of the pocket. In some embodiments, prior to inserting the cutter, the pocket may be preheated, such as by using a welding torch, to get the pocket heated to a temperature sufficiently high to accept and bond to a braze material.

At operation 4504, the metal-containing substance may be provided into the gap. For example, a brazing alloy may be melted and delivered to the gap such that the brazing alloy is disposed between all or substantially all of the wall defining the pocket and the adjacent portion of the cutter, including a base of the cutter/pocket and at least a portion of one or more lateral sidewalls or other surfaces of the cutter/pocket. A flux compound may be supplied to the braze joint before, during, and/or after applying the brazing alloy. The flux compound may help prevent the formation of oxides at the braze joint and may help promote higher quality braze joints by helping the brazing alloy flow more freely within the gap between the cutter and pocket. At operation 4506, the cutter may be set within the pocket, such as by allowing the brazing alloy to cool and bond to both the cutter and pocket, thereby joining the cutter with the downhole tool.

FIG. 46 is a flowchart illustrating operations of a method 4600 for manufacturing a downhole tool according to some embodiments of the present invention. Method 4600 may be used to manufacture downhole tools (such as drill bits 100, 200, 1500, 4200, 4300, 4400, reamer 300, and/or drill bits having the cutting configurations described in relation to FIGS. 32A-32F) that include non-cylindrical cutters (such as cutters 400-1600). In particular, method 4600 may be used to manufacture cast matrix downhole tools. Method 4600 may begin at operation 4602 by forming a mold of a body of the downhole tool. The mold may be formed of a rigid, machinable, and heat resistant material, such as (but not limited to) graphite or other carbon-based materials. For example, a graphite log may be cut into pucks that are slightly larger than the size of the final mold. Forming the mold may include, for example, machining the mold using a computer numerical control (CNC) mill and/or other machining tool. The mold may create voids that represent features of the body of the downhole tool, including the face and a number of blades. Locating features or troughs for displacements may be machined into each blade to represent cutter locations on the final downhole tool. At least some of the locating features for the displacements may have non-cylindrical cross-sections or otherwise include one or more sidewalls that do not include a single arc of a constant radius. In some embodiments, such locating for non-cylindrical displacements may include one or more indexing features, such as ridges, grooves, visible markings, and/or other features that may enable a displacement to be properly aligned within the pocket. Additional locating features may be provided for other features of the downhole tool, such as nozzles. Different locating features may have different sizes and shapes. For example, locating features for front loaded cutter pockets may have different sizes and shapes than locating features for top loaded cutter pockets, which may be required where the primary blades meet in the middle, or in double row positions. The lack of clearance in front of the pocket requires that the cutter be loaded into the pocket from the top of the blade rather than the front. The size, shape, and orientation of each cutter locating feature may define a final shape, size, and orientation (e.g., forward rake, back rake, side rake, cutting tip rotation, etc.) of the final cutter pocket and cutter.

Once the mold has been formed, a number of displacements, including cutter pocket displacements, may be inserted into the mold, such as into the locating features at operation 4604. Each displacement may be formed from a material suitable for casting metals, such as graphite and/or resin bonded sand. Each displacement may be oriented in a respective locating feature to ensure that the final cutter pocket and cutter are properly positioned on a blade of the downhole tool. In some embodiments, this alignment may be done manually. For example, a visual indicator, such as a notch, groove, or other indexing feature may be formed in the displacement and/or locating feature that may help an installer properly insert and align the displacement within a respective locating feature. In other embodiments, the locating feature and corresponding displacement may have non-cylindrical cross-sections or other geometry that force the displacement to be properly oriented within the locating feature. In some embodiments, a ridge may be formed in the displacement or the locating feature, with a corresponding groove being formed in the other component. Insertion of the ridge into the groove may align the displacement within the locating feature. In some embodiments, a concavity may be formed in the displacement or the locating feature, with a corresponding convexity being formed in the other component. Insertion of the convexity into the concavity may align the displacement within the locating feature. In some embodiments, the locating feature and the cutter may each define a slot. A key may be inserted into both slots simultaneously to align the displacement within the locating feature. In some embodiments, a hole may be drilled through the junk slot into the hemispherical void, a hole may be drilled into/through the displacement, and a pin may be inserted through both holes to orient the displacement within the locating feature. In some embodiments, a shallow hole may be drilled into the trough of the locating feature at an angle that is not parallel to the axis of rotation of the displacement. A corresponding hole may be drilled into or through the displacement and a pin may be inserted within the holes of both the mold and the displacement to align the displacement within the locating feature. Other techniques for aligning the displacements within the locating feature are possible in various embodiments. The displacements may also include displacements for nozzles and a central bore that may be used to deliver a drilling fluid to the nozzles. The various displacements may be adhered to the locating features using an adhesive material.

Once the displacements have been secured to the mold, a steel head blank (such as a blank for later welding the shank, bit breaker surface, and connectors for connecting the drill bit to a drill string) may be positioned partially within the mold. At this point, the mold may be filled with a granular carbide material and a binder material at operation 4606. For example, the carbide material may include a tungsten carbide (or other hard metal, such as titanium carbide and/or tantalum carbide) powder. In some embodiments, the tungsten carbide powder may include between about 80%-95% tungsten, 3%-15% carbon, and may include trace elements of iron, nickel, molybdenum, titanium, tantalum, and/or niobium, however other formulations are possible in various embodiments. The binder material may be provided as a number of metallic chunks or other pieces that may be roughly on the order of 0.5 in² to 2.0 in², although other sizes are possible in various embodiments. In some embodiments, the binder material may include copper, nickel, silver, and/or alloys thereof, such as in the form of a copper-based alloy binder. For example, the binder material may include between about 40%-60% copper, 20%-30% manganese, 10%-20% nickel, and may include trace elements of zinc, iron, lead, silicon, and/or tin.

At operation 4608, the mold may be placed into a furnace that exposes the filled mold to temperatures of between about 1500° F. and 2500° F. for a period of between about 2 hours and five hours. The heat causes the binder material to melt and flow downward into the tungsten carbide powder which, upon cooling, will form a body of the downhole tool from a carbide reinforced matrix composite. For example, the melted binder material may flow into and fill voids between individual particles of the tungsten carbide powder to form a cast matrix body of the downhole tool. In some embodiments, more binder material than is needed to form the body may be placed into the mold to enable pressure infiltration to form the carbide reinforced matrix composite. For example, once melted, the excess binder material applies downward pressure that forces the liquid binder to flow in between particles of the carbide material to form a matrix. In a particular example, the tungsten carbide particles may reinforce a copper alloy matrix. The mold and body may be removed form the furnace and allowed to cool. At operation 4610, the body of the downhole tool may be removed from the mold. For example, the mold may be cut or otherwise damaged to expose the body of the downhole tool. The shank, bit breaker surface, and connectors for connecting the drill bit to a drill string may be welded into the steel head blank. The displacements may be removed from the body of the downhole tool, which may form cutter pockets on the blades of the downhole tool.

The cutter pockets may be cleaned up via one or more tools to be sized and shaped to each receive a respective cutter. At operation 4612, a cutter may be inserted into each of the cutter pockets. At least some of the cutters may have a non-circular cross-section that substantially matches a non-circular cross-section of a respective one of the cutter pockets. In some embodiments, a shape and orientation of each cutter pocket and a respective one of the cutters disposed within the cutter pocket are selected such that when the respective one of the cutters is inserted into the cutter pocket, the respective one of the cutters is oriented with a cutting tip of the respective one of the cutters protruding beyond a top surface of a respective one of the plurality of blades. The cutter pocket may define the shape, size, and orientation (e.g., forward rake, back rake, side rake, cutting tip rotation, etc.) of the cutter positioned therein. Once inserted in a pocket, each cutter may be brazed to the downhole tool, such as using a process similar to method 4500.

FIG. 47 is a flowchart illustrating operations of a method 4700 for manufacturing a downhole tool according to some embodiments of the present invention. Method 4700 may be used to manufacture downhole tools (such as drill bits 100, 200, 1500, 4200, 4300, 4400, reamer 300, and/or drill bits having the cutting configurations described in relation to FIGS. 32A-32F) that include non-cylindrical cutters (such as cutters 400-1600). In particular, method 4700 may be used to manufacture steel body downhole tools. Method 4700 may begin at operation 4702 by forming a body of a downhole tool. Forming the body of the downhole tool may be performed, for example, by machining the body from a steel blank using a computer numerical control (CNC) mill and/or other machining tool. The body may include a plurality of blades, with each blade defining a plurality of cutter pockets. At least some of the cutter pockets may have a non-circular cross-section as described herein. Machining such non-cylindrical pockets may be done by producing radiused corners, using a one-sided undercut, a two-sided undercut, and/or other machining techniques for generating square or otherwise non-circular voids. In some embodiments, the cutter pockets may have features parallel to the axis of the cutter with a radius less than 0.1″ or a chamfer and/or sharp corner. In other embodiments, a cylindrical pocket may be formed and a shim may later be welded into the pocket to change the cross-sectional shape of the pocket.

At operation 4704, the body of the downhole tool may be hardfaced. For example, heat may be applied to at least a portion of the body of the downhole tool the body and to a hardfacing material to fuse the hardfacing material to at least a portion of the body, such as the blades. The hardfacing material may include a carbide material and a binder that, when fused to the body, harden the body and make the body more resistant to wear. At operation 4706, a cutter may be inserted into each of the cutter pockets. At least some of the cutters may have a non-circular cross-section that substantially matches a non-circular cross-section of a respective one of the cutter pockets. In some embodiments, a shape and orientation of each cutter pocket and a respective one of the cutters disposed within the cutter pocket are selected such that when the respective one of the cutters is inserted into the cutter pocket, the respective one of the cutters is oriented with a cutting tip of the respective one of the cutters protruding beyond a top surface of a respective one of the plurality of blades. The cutter pocket may define the shape, size, and orientation (e.g., forward rake, back rake, side rake, cutting tip rotation, etc.) of the cutter positioned therein. Once inserted in a pocket, each cutter may be brazed to the downhole tool at operation 4708, such as using a process similar to method 4500.

As noted above, the use of non-cylindrical cutters that include multiple discrete cutting tips may enable the cutters to be reused. For example, oftentimes, only one cutting tip will see substantial wear during drilling or reaming operations. This may result in other cutting tips, such as those recessed within the blade, being in suitable condition to be utilized. FIG. 48 is a flowchart illustrating operations of a method 4800 for reorienting a cutter in a downhole tool according to some embodiments of the present invention. Method 4800 may be used with any of the drill bits and/or cutters describe herein, such as those with a number of discrete cutting tips and that have non-circular cross-sections that correspond with a cross-section of a cutter pocket in which the cutter is secured. Method 4800 may begin at operation 4802 by determining that a first cutting tip of a cutter on blade of a downhole tool is excessively worn. The first cutter tip may be protruding above a top surface of the blade and be in a cutting position. The determination may be made, for example, by grading the first cutting tip based on one or more predetermined criteria. For example, one or more wearscars and/or wear flats may be compared to standards set by the International Association of Drilling Contractors (IADC), an evaluation may be made as to whether any chips, cracks, or flinting extend beyond a threshold percentage of a length of the cutter, an evaluation may be made as to whether there is any cobalt leaching on the diameter of the cutter/cutting tip, whether there is any cobalt denuding proximate the cutting tip, an evaluation may be made as to whether there is graphitization, spalling, chipping, diamond pull, cracking, and/or other wear of the cutting tip, and/or other grading techniques may be utilized. If the first cutting tip is damaged/worn beyond use, method 4800 may include determining that a second cutting tip of the discrete cutting tips is in sufficient condition to be utilized in the cutting position at operation 4804. To do so, a similar evaluation of the one or more grading criteria may be performed for the second cutting tip.

If the second cutting tip passes the grading criteria, the cutter may be removed from the cutter pocket at operation 4806. For example, heat may be applied to the cutter and blade, such as using a torch, to remelt the brazing alloy used to secure the cutter within the pocket. The cutter may be pulled out of engagement from the pocket. At operation 4808 the cutter may be rotated and inserted within the cutter pocket with the second cutting tip oriented into the cutting position. The cutter may be secured within the pocket at operation 4810, such as by re-brazing the cutter into the pocket using a process similar to method 4500. A shape and orientation of the cutter pocket the cutter may be selected such that when the cutter is inserted into the cutter pocket, the cutter is oriented with one of the discrete cutting tips in the cutting position. This may eliminate the need for the installer to manually align the cutting tip in a desired orientation.

FIG. 49 illustrates operations of a method 4900 of using a downhole tool in accordance with the present invention. The downhole tool may be a drill bit, reamer, or other rotatable tool (such as drill bits 100, 200, 1500, 4200, 4300, 4400, reamer 300, and/or drill bits having the cutting configurations described in relation to FIGS. 32A-32F) as described herein and may include non-cylindrical cutters (such as cutters 400-1600) on a number of blades. At operation 4902, the downhole tool may be rotated to shear and/or clean out a subterranean formation and/or to advance the well bore. The downhole tool may be rotated in any number of ways. For example, the downhole tool may be coupled with a drill string that is rotated with a top drive or a table drive (not shown) or with a downhole motor that is part of a bottom hole assembly. The downhole tool may be surrounded by a sidewall of the well bore. At operation 4904, as the downhole tool is rotated within the well bore via the drill string, a drilling fluid may be pumped down the drill string through the internal passageways within the downhole tool and out through openings, nozzles or ports. Formation cuttings generated by the one or more PDC cutters of the downhole tool may be carried with the drilling fluid through the channels, around the downhole tool, and back up the well bore through an annular space within the well bore outside the drill string.

It should be noted that the methods, systems, and devices discussed above are intended merely to be examples. It must be stressed that various embodiments may omit, substitute, or add various procedures or components as appropriate. Also, features described with respect to certain embodiments may be combined in various other embodiments. Different aspects and elements of the embodiments may be combined in a similar manner. Also, it should be emphasized that technology evolves and, thus, many of the elements are examples and should not be interpreted to limit the scope of the invention. Some embodiments were described as processes depicted as flow diagrams or block diagrams. Although each may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be rearranged. A process may have additional steps not included in the figure.

Specific details are given in the description to provide a thorough understanding of the embodiments. However, it will be understood by one of ordinary skill in the art that the embodiments may be practiced without these specific details. For example, well-known structures and techniques have been shown without unnecessary detail in order to avoid obscuring the embodiments. This description provides example embodiments only, and is not intended to limit the scope, applicability, or configuration of the invention. Rather, the preceding description of the embodiments will provide those skilled in the art with an enabling description for implementing embodiments of the invention. Various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the invention.

Also, the words “comprise”, “comprising”, “contains”, “containing”, “include”, “including”, and “includes”, when used in this specification and in the following claims, are intended to specify the presence of stated features, integers, components, or steps, but they do not preclude the presence or addition of one or more other features, integers, components, steps, acts, or groups.

Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly or conventionally understood. As used herein, the articles “a” and “an” refer to one or to more than one (i.e., to at least one) of the grammatical object of the article. By way of example, “an element” means one element or more than one element. “About” and/or “approximately” as used herein when referring to a measurable value such as an amount, a temporal duration, and the like, encompasses variations of +20% or +10%, +5%, or +0.1% from the specified value, as such variations are appropriate to in the context of the systems, devices, circuits, methods, and other implementations described herein. “Substantially” as used herein when referring to a measurable value such as an amount, a temporal duration, a physical attribute (such as frequency), and the like, also encompasses variations of +20% or +10%, +5%, or +0.1% from the specified value, as such variations are appropriate to in the context of the systems, devices, circuits, methods, and other implementations described herein. As used herein in the context of shapes, the terms “generally” and “substantially” are understood to mean that a large percentage of the shape of a component (e.g., greater than 70%, greater than 80%, greater than 90%, or more) has the described shape, however some smaller percentage of the component may stray from the shape described. For example, the component may include a number of protrusions, cutouts, and/or small components that prevent the component from perfectly matching the described shape.

Where a range of values is provided, it is understood that each intervening value, to the smallest fraction of the unit of the lower limit, unless the context clearly dictates otherwise, between the upper and lower limits of that range is also specifically disclosed. Any narrower range between any stated values or unstated intervening values in a stated range and any other stated or intervening value in that stated range is encompassed. The upper and lower limits of those smaller ranges may independently be included or excluded in the range, and each range where either, neither, or both limits are included in the smaller ranges is also encompassed within the technology, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included.

As used herein, including in the claims, “and” as used in a list of items prefaced by “at least one of” or “one or more of” indicates that any combination of the listed items may be used. For example, a list of “at least one of A, B, and C” includes any of the combinations A or B or C or AB or AC or BC and/or ABC (i.e., A and B and C). Furthermore, to the extent more than one occurrence or use of the items A, B, or C is possible, multiple uses of A, B, and/or C may form part of the contemplated combinations. For example, a list of “at least one of A, B, and C” may also include AA, AAB, AAA, BB, etc.