Drill Bits and Other Downhole Drilling Tools with Non-Cylindrical Cutter Pockets

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

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.

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.

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.

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.

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.illustrates an example of a rotary drill bitaccording to embodiments of the present disclosure. The rotary drill bitofis intended to be a representative example of drill bits, e.g., drag bits, for drilling formations. Rotary drill bitis designed to be rotated around its central axis. Drill bitmay include a bit bodyconnected to a shankhaving a tapered threaded couplingfor connecting the bit to a drill string (not shown). Drill bitmay further include a bit breaker surfacefor cooperating with a wrench to tighten and loosen the coupling to the drill string. The exterior surface of bit bodyis 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 axisof drill bit. In some embodiments, bit bodyis 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 bodymay be formed from a metal alloy, such as a steel alloy. In some embodiments, all or a portion of a steel alloy bit bodymay 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. It will be appreciated that other materials may be used to form bit bodyin various embodiments.

During drilling operations, drill bitmay be coupled to the drill string. As drill bitis 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 bodyof drill bit, and out from drill bitthrough nozzles. Formation cuttings generated by cuttersof bit bodymay be carried with the drilling fluid through the fluid courses (e.g., “junk slots”), around drill bit, and back up the wellbore through the annular space within the wellbore outside the drill string.

Bit bodymay include one or more raised bladesthat extend from the face of bit body. In some embodiments, bladesextend radially along the bit face and are circumferentially spaced structures extending along the leading end or formation engaging portion of bit body. Each blademay extend generally in a radial direction, outwardly to the periphery of bit body. For example, bladesmay generally extend from the cone region proximate the longitudinal axis, or central axis, of the bit, upwardly to the gauge region, or maximum drill diameter of bit. In some embodiments, bladesmay be substantially equally spaced around central axisof drill bitand each blademay sweep or curve backward in the direction of rotation indicated by arrow. In other embodiments, one or more of bladesmay have zero sweep (e.g., do not curve in the direction of arrow). 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 bodyfurther includes a plurality of superabrasive cutters. Cuttersmay be, for example, polycrystalline diamond compact (“PDC”) cutting elements, disposed on front and/or top facing surfaces of each blade. For example, a plurality of discrete cuttersmay be mounted on each blade. Cuttersmay 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. 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 cuttermay be disposed within a recess or pocket formed in a given blade. Cuttersmay be mounted to drill biteither by press-fitting or otherwise locking the stud (e.g., substrate portion of cutting element) of the respective cutterinto a pocket or receptacle on a drag bit, or by brazing a portion of the respective cutterdirectly into a preformed pocket, socket or other receptacle on a given blade. Cuttersmay be provided in one or more rows along each blade. For example, in some embodiments, a given blademay include one or more primary cuttersthat extend through a leading edge of the bladeand one or more backup cuttersthat are positioned on the bladebehind the primary cutters. In some embodiments, each cuttermay have a unique radial position (i.e., radial distance from central axis), while in other embodiments multiple cutters(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 bladeor on different bladesin various embodiments. In some embodiments, an outlet of some or all nozzlesmay be aligned with a cutting face of one of the cutters that faces the respective channel, with the axis of each nozzlebeing aimed slightly away (e.g., between 1 degree and 10 degrees) of parallel with respect to the front surface of the respective blade. This may enable the drilling fluid to more effectively wash cuttings away from cutterswhile helping reduce erosion of the area of the bladesurrounding the cutter pockets.

represents a view of the face of another embodiment of a drill bit. Drill bitmay be similar to drill bitand may include any of the features described in relation to drill bit. Drill bithas 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. The other three are secondary blades. The primary blades extend from near the center of the axis of rotation, through the cone, nose and shoulder regions, to the gauge of bit. In this example, each primary bladeis an offset blade. Each secondary bladeextends from the nose region of bit, through the shoulder region, and then to the gauge of bit. Secondary bladesare 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 bladeis 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 bladehas seven cutters-(although other numbers of cutters are possible in various embodiments), which are primary cutters. Cutters-are mounted along a leading edge of the offset blade, adjacent to one of the channels or “junk slots”that extends along the length of the offset blade. The offset bladesmay also have cutters in the gauge area of drill bit, which are not visible in this view of this embodiment. Each offset bladein 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 cutterand cutter. The offset creates two blade regions, a first (or inner) blade region closer to the centerline or axis of rotationof drill bitthat extends through the cone region of drill bitto 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. 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 bladeoccurs approximately where the cone region of the bit transitions to the nose region of drill bit. However, in other embodiments, the offset may occur in or near other regions of drill bit, 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 bladesmay 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-that are visible in this view and may have cutters in the gauge region of drill bitthat are occluded from view. Cutters-each have a fixed position on drill bit. 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, and the relative radial position of the cutter on the face of drill bit.

Drill bitmay include a plurality of nozzles-which are located in a plurality of channels or junk slots. Junk slotsmay 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). Nozzles-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. Junk slotscreate 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.)

Nozzlesare in front of the inner region of offset blade. The drilling fluid flowing from each nozzleis primarily intended to clear cuttings coming off of primary cutters mounted along a leading of the inner region of each offset blade, which in this example are cutters,, and. The drilling fluid flowing from each nozzleis 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, which in this example are cutters,, and. Nozzlesare therefore directed so that drilling fluid flows across the face of these cutters-and down junk slotthat is between the front of the offset bladeand the back side of the secondary bladein front of the offset blade.

Nozzlesare each tucked into the corner formed in the front wall of the blade formed by the offset in offset blade. Each nozzledirects drilling fluid along the outer region of each of offset blades, toward faces of cutters,,, and, which are primary cutters mounted along a leading edge of the outer region of offset blade.

Nozzlesare rotationally offset rearwardly with respect to nozzleand radially outwardly. Because each nozzleis rotationally displaced with respect to nozzle, fluid flowing from each nozzletends not to interfere with fluid flow from nozzleor interferes much less than it would if it were not rotationally displaced. Nozzleis aimed so that the drilling fluid from nozzle, after flowing across the face of cutters,, andin the inner region of offset blade, tends for flow with the cuttings produced by those cutters primarily through the area between the back of secondary bladeand nozzle. Fluid flowing from nozzleprimarily flows across the face of cutters,,, andand then continues along the front wall or leading edge of the second blade portion of the offset bladeinto the annular space of the borehole.

Offset bladesand secondary bladesof drill bitmay include sloped surfacesand, 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, 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 surfacesandremove 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.illustrates a reamerfor earth boring operations, according to certain embodiments. Reamermay include an upper shaft, a lower shaft, a body, and blades-disposed about body. Each blade-may be separated by channels or “junk slots.” Each blade-may include one or more cutters, which may be PDC cutters in some embodiments. For example, each cuttermay 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 cuttermay be inserted into a hollow pocket included in a respective blade. The hollow pocket (or “pocket”) may be machined, cast, and/or otherwise formed into reamerduring manufacture of reamer. Each cuttermay be configured such that it corresponds to a specific pocket included in the respective blade. For example, a size and shape of each cuttermay 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.

Reamermay 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 bitsand. Reamermay then be inserted into the pre-existing hole or bore to widen the pre-existing hole or bore. As reameris rotated within the pre-existing hole or bore, cuttersmay cause material (e.g., earth, rock, etc.) to be removed from the hole or bore.

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

In yet another example, reamermay be an expandable reamer. In such embodiments, blades-may be enclosed in a housing. During operation, the housing may open and blades-may extend radially outward from the reamer, thus engaging cutterswith the formation. In still another example, during periods of non-operation, blades-may be in a first position in which cuttersare not exposed to the formation. During operation, blades-may rotate and/or extend to a second position in which cuttersengage 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.