LOW COLLISION DAMAGE BIT

BACKGROUND OF THE DISCLOSURE

Wells can be drilled into a surface location or ocean bed to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations. In some locations, a planned wellbore may have a path that passes near an existing wellbore. The location of the existing wellbore may be known to a precise degree or not. The existing wellbore may be a cased wellbore having a metal or other casing around the wellbore to support and maintain the wellbore.

The creation of a new wellbore near one or more existing wellbores includes a risk of collision with the casing of an existing wellbore. A collision between a bit and wellbore casing may cause damage to the casing and/or bit. In some instances, the damage to the casing may be extensive enough to rupture the casing. Repairing the casing may expensive, time consuming, and/or impossible. The pressure in the existing wellbore may cause fluids normally contained within the casing to exit through the rupture in the casing, which can result in environmental, personal, and mechanical harm.

Bits having different shapes may be used for different formations. For drilling in a soft formation a bit having a more aggressive tooth profile can be used to remove material from the formation at a high rate. A bit may be exposed to less wear in a soft formation, allowing the use of a more aggressive tooth profile that may not have a viable wear resistance for drilling in harder formations. A more aggressive tooth profile (e.g., deeper and sharper teeth) may exhibit greater resistance to bit balling than a less aggressive tooth profile in a soft formation. An aggressive bit profile may expose both the bit and the casing of existing wellbores in the surrounding area to a risk of damage.

SUMMARY

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

In a first non-limiting embodiment, a cone for use in a roller cone bit includes a nose, a heel, a hard portion, and a soft portion. The heel is located at an opposite end of the cone from the nose. The hard portion of the cone forms at least a part of the nose. The soft portion of the cone forms at least a part of the heel. The hard portion of the cone has a first yield strength greater than a second yield strength of the soft portion of the cone.

In a second non-limiting embodiment, a bit includes a bit body having a bit axis and a leg extending from the bit body with a cone rotatably connected to the leg. The cone has a nose and a heel with at least part of the nose being made of a first material and at least part of the heel being made of a second material. The first material has a greater yield strength than the second material.

In a third non-limiting embodiment, a method of manufacturing a bit includes providing a cone body having a nose and a heel and made of or including a first material and affixing to the heel a second material, where the cone body has a first hardness and the second material has a second hardness. The second hardness is less than the first hardness.

Additional features and advantages of implementations of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such implementations. The features and advantages of such implementations may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such implementations as set forth hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is a schematic illustration of a drilling system creating a wellbore incident with an existing cased wellbore, according to the present disclosure;

FIG. 2 is a side view of a low collision damage roller-cone bit, according to at least one embodiment as described herein;

FIG. 3 is a bottom view of a low collision damage roller-cone bit, according to at least one embodiment as described herein;

FIG. 4 is a top view of a low collision damage roller-cone bit, according to at least one embodiment as described herein;

FIG. 5 is a longitudinal cross-sectional view of a of a low collision damage roller-cone bit, according to at least one embodiment as described herein;

FIG. 6 is another side view of a low collision damage roller-cone bit, according to at least one embodiment as described herein;

FIG. 7 is a side view of a low collision damage cone having a gage row made of a second material, according to at least one embodiment as described herein;

FIG. 8 is a side view of another low collision damage cone having a gage row partially made of a second material, according to at least one embodiment as described herein;

FIG. 9 is a side view of yet another low collision damage cone having a disc adjacent a gage row made of a second material, according to at least one embodiment as described herein; and

FIG. 10 is a flowchart of a method of manufacture of a low collision damage cone, according to at least one embodiment as described herein.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will be described below. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual implementation may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

This disclosure generally relates to devices, systems, and methods for reducing damage incurred by collisions between a bit and casing of an existing wellbore. More particularly, this disclosure relates to devices, systems, and methods for providing a bit that may impart less energy to the casing of existing wellbore during a collision. For example, a bit may include a hard portion and a soft portion. The soft portion may have a hardness that is less than the hardness of the hard portion and the soft portion may, therefore, deform more easily than the hard portion when a load is applied. For example, during operation, the bit may rotate about a bit axis to remove a portion of the surrounding formation. In some embodiments, a portion of the bit furthest from the bit axis may define a rotational diameter of the bit. The soft portion may be applied to a bit such that the soft portion defines the rotational diameter of the bit. In other embodiments, a bit may include one or more cones that include a hard portion and a soft portion. A portion of the one or more cones furthest from the bit axis may define a cutting diameter of the bit. In some embodiments, the soft portion of the one or more cones may define the cutting diameter of the bit. For example, the cutting diameter of the one or more cones may be greater than an outer diameter of the bit body. In other embodiments, the cutting diameter of a bit may be less than the rotational diameter of the bit.

When the soft portion defines the rotational diameter of the bit, the soft portion may be the first portion of the bit that may contact any existing wellbore casing or other subterranean structure during rotation of the bit. The soft portion may be softer (i.e., have a lesser yield strength) than the existing wellbore casing or other subterranean structure. The soft portion of the bit may deform and transfer less energy to the existing wellbore casing or other subterranean structure than the hard portion of the bit may. The hard portion of the bit may have a higher hardness, and therefore, wear resistance during drilling.

FIG. 1 illustrates a drilling system 100 including a low collision damage bit 102. The bit 102 may be delivered downhole by a drill string 104 to drill a wellbore 106. The drilling system 100 may drill the wellbore 106 through a formation 108 that includes an existing wellbore 110. The existing wellbore 110 may have casing 112 enclosed and supporting the existing wellbore 110. In some embodiments, the formation 108 may be a soft formation, such as a claystone, mudstone, shale, other low metamorphic grade formations, unconsolodated sand or earth, or combinations thereof. In some examples, the formation 108 may have an unconfined compressive strength of less than 100 kilopounds per square inch (“ksi”). In other examples, the formation 108 may have an unconfined compressive strength of less than 56 ksi. In yet other examples, the formation 108 may have a compressive strength of about 3-5 ksi. In other embodiments, the formation 108 may be a formation with low permeability. In some embodiments, the soft portion of the bit 102 may have a hardness and/or yield strength greater than a hardness and/or yield strength of the formation 108. In other embodiments, the soft portion of the bit 102 may have a hardness and/or yield strength equal to or less than a hardness and/or yield strength of the formation 108. For example, the soft portion may have a hardness and/or yield strength equal to or less than a hardness and/or yield strength of the formation 108 when drilling a hole less than 100 meters.

The wellbore 106 may be drilled in relatively close proximity to the existing wellbore 110 to access fluids not accessible from the existing wellbore 110. In some instances, the wellbore 106 being drilled and existing wellbore 110 may collide at an incident angle 114. The incident angle 114 may be a relative angle of the wellbore 106 being drilled and the existing wellbore 110. For example, the incident angle 114 may be the same as or different from an angle of either the wellbore 106 or the existing wellbore 110 relative to gravity (i.e., vertical). The incident angle may be within a range having upper and lower values including any of 1°, 2°, 3°, 4°, 5°, 6°, 7°, 8°, 9°, 10°, 12°, 14°, 16°, 18°, 20°, 30°, 40°, 50°, 60°, 70°, 80°, 90°, or any value therebetween. For example, the incident angle may be between 1° and 20°. In another example, the incident angle may be between 2° and 5°. In another example, the incident angle may be about 4°. While FIG. 1 depicts the wellbore 104 as being substantially vertical, the wellbore 106 may be drilled at other angles.

The existing wellbore 110 may be a producing wellbore or may be capped. In some embodiments, a surface structure 116 may contain a positive pressure within the casing 112. The positive pressure within the existing wellbore 110 may urge a fluid therein to exit through damage caused by a collision with the bit 102. The drilling system 100 may apply torque to rotate the drill string 104 using, for example, a kelly 118 mated to a rotary table 120 at the surface. The rotary table 120 may have a kelly bushing (not shown) which may have an inside profile that may complimentarily mate with an outside profile of the kelly 118, such as a square, hexagon, or other polygonal shape that allows for the transmission of torque. The kelly 118 may move longitudinally freely relative to the rotary table 120 in order to transmit longitudinal force to the drill string 104. In other embodiments, the drill string 104 may be rotated by another torque transmitting device. For instance, a top drive may be used. The drill string 104 may transmit torque to the bit 102 sufficient to damage the casing 112 of an existing wellbore. When a collision is detected (e.g., due to a drop in rate of penetration or a change in another drilling parameter), the drilling system 100 may be stopped or slowed to prevent further damage.

Information regarding the performance of the drilling system 100 may be obtained in various ways at the surface of the wellbore or using downhole instrumentation. For example, information about drilling performance may be collected by one or more downhole tools, such as a measurements-while-drilling tool 122, a logging-while-drill tool 124, or other information collection tools in the drill string 104. The information may be provided from the information collection tools to a controller or operator 128 by a communication module 126. The data collection modules may include controllers positioned downhole and/or at the surface that may vary the operation of (e.g., steer or orient) the bit 102 or other portions of the drilling system 100. Mud pulse telemetry, wired drill pipe, fiber optic coiled tubing, wireless signal propagation, other information transmission techniques, or combinations thereof may be used to send information to or from the surface.

The damage imparted by the bit 102 to the casing 112 may be reduced by engaging the casing 112 with a soft portion of the bit 102 that is has a lesser hardness and/or yield strength than the casing 112. In some embodiments, the casing 112 may be an uncemented casing. In other embodiments, the casing 112 may be a cemented casing. In some embodiments, the casing 112 may be a metal casing. For example, the casing 112 may be API 5L Grade A (30 ksi (210 MPa) yield strength), B (35 ksi (240 MPa) yield strength), X42 (42 ksi (290 MPa) yield strength), X46 (46 ksi (320 MPa) yield strength), X52 (52 ksi (360 MPa) yield strength), X56 (56 ksi (390 MPa) yield strength), X60 (60 ksi (410 MPa) yield strength), X65 (65 ksi (450 MPa) yield strength), X70 (70 ksi (480 MPa) yield strength), X80 (80 ksi (550 MPa) yield strength), or other grades.

FIG. 2 is a side view of an embodiment of a low collision damage bit 202 according to the present disclosure. The bit 202 may have a bit body 230 that has one or more legs 232 extending therefrom. The bit 202 may include one or more cones 234 connected to the bit body 230. In some embodiments, each of the one or more legs 232 may be connected to one of the one or more cones 234. In other embodiments, at least one of the one or more legs 232 may be connected to more than one of the one or more cones 234. A cone 234 may be rotatably connected to one or more one or more legs 232 about a cone axis 236. The cone 234 may have a soft portion 238 and a hard portion 240. In some embodiments, the soft portion 238 may be farther from the cone axis 236 than the hard portion 240. For example, the soft portion 238 may have a larger diameter than the hard portion. In other embodiments, the soft portion 238 may be farther from a bit axis 242 than the hard portion 240. In yet other embodiments, at least part of the soft portion 238 may be farther from the bit axis 242 than any part of the bit body 230. In some embodiments, the soft portion 238 may define the cutting diameter of the bit 202. In other embodiments, the soft portion 238 may define the rotational diameter of the bit 202. While the present disclosure may describe the use of a cone 234 having a soft portion 238 and a hard portion 240, where the soft portion 238 may define the cutting diameter of the bit 202, it should be understood that a cone having a soft portion 238 and a hard portion 240 may be used in conjunction with a high shear roller cone bit, as described in U.S. Pat. No. 8,672,060 entitled “HIGH SHEAR ROLLER CONE DRILL BITS” filed Jul. 27, 2010, the disclosure of which is incorporated herein by reference in its entirely. When used in conjunction with a high shear roller cone bit, the soft portion may still define the cutting diameter of the bit, while the cutting diameter may be defined by a nose of the cone.

In some embodiments, the hard portion 240 of the bit 202 may be made of or include one or more materials used in conventional drill bits, such as steel 4718, 4815, 4715, or combinations thereof, each of which have a yield strength of 80 ksi (550 MPa) or greater.

FIG. 3 is a bottom view of another embodiment of a low collision damage bit 302. The bit 302 may have a plurality of cones 334 rotatably connected to a plurality of legs (not shown). Each of the cones 334 may have a plurality of cutting teeth 344. The plurality of cutting teeth 344 may be positioned at even intervals along the cone 334 or at uneven intervals along the cone 334. For example, as shown in FIG. 3, the plurality of cones 334 may have a plurality of cutting teeth 344 positioned at different intervals along the cone 334 to allow the plurality of cutting teeth 344 on each cone 334 to not interfere with the plurality of cutting teeth 344 on the other cones 334. In other embodiments, the cones 334 may be spaced to prevent interference between the pluralities of cutting teeth. In yet other embodiments, a cone 334 may have one or more recesses configured to receive a cutting insert. The cutting insert may be made of or include any suitable material; for example, the cutting insert may be made of or include steel, diamond, tungsten carbide, cubic boron nitride, or other materials having a higher yield strength and/or hardness than a formation to be cut.

The bit 302 may include one or more fluid outlets 354. The fluid outlets 354 may be any suitable fluid outlet, e.g., ports or nozzles. In some embodiments, the fluid outlets 354 may be oriented such that a fluid path 356 may be directed between the gage rows 346. In other embodiments, the fluid path 356 may be directed away from the gage rows 346 and angled away from the bit axis 342 (shown in dashed lines). The fluid outlets 354 may facilitate deballing of the cutting teeth 344. In yet other embodiments, the fluid outlets 354 may be directed substantially coaxially with the bit axis 342. The fluid path 356 may direct the fluid toward a portion of a formation (such as formation 108 described in relation to FIG. 1). The fluid may mobilize at least a portion of the formation adjacent to the bit 302.

FIG. 3 also depicts a bit 302 having one or more inner fluid outlets 362. The inner fluid outlets 362 may assist in deballing the cutting teeth 344 located on the cones 334 radially inward from a gage row 346 toward a bit axis 342. For example, the fluid outlets 354 may be angled radially outward from the bit axis (e.g. toward an intermediate row of cutting teeth). The fluid path 356, therefore, may not provide fluid to the plurality of cutting teeth 344 at and/or near the nose of the cones 334. The one or more inner fluid outlets 362 may provide fluid in an inner fluid path 363 to deball the cutting teeth 344 not part of the gage row 346.

The gage row 346 may be proximate a heel 348 of the cone 334. The heel 348 may be opposite a nose 350 of the cone 334. The cone 334 may be oriented so that the nose 350 may be proximate a bit axis 342. The gage row 346 may define a cutting diameter of the bit 302. FIG. 4 is a top view of another embodiment of a low collision damage bit 402 depicting a cutting diameter 458 greater than a bit body diameter 460. In some embodiments, the difference between the cutting diameter 458 and the bit body diameter 460 may be within a range having upper and lower values including any of 0%, 2%, 4%, 6%, 8%, 10%, 12%, 14%, 16%, 18%, 20%, and any value therebetween. For example, the difference between the cutting diameter 458 and the bit body diameter 460 may be between 2% and 16%. In another example, the difference between the cutting diameter 458 and the bit body diameter 460 may be between 4% and 12%. In yet another example, the difference between the cutting diameter 458 and the bit body diameter 460 may be about 8%.

FIG. 5 is a cross-sectional view of a cone 534 having a first material 564 and a second material 566. In some embodiments, the first material 564 may be at least part of a hard portion (such as hard portion 240 described in relation to FIG. 2) and the second material 566 may be at least part of a soft portion (such as soft portion 238 described in relation to FIG. 2). In other embodiments, the first material 564 may be a cone body to which the second material 566 may be connected. At least part of the first material 564 may be positioned about a cone axis 536. The part of the cone 534 furthest from the cone axis 536 may be the second material 566. The second material 566 may be positioned on a leg 532 such that at least a part of the second material 566 may extend radially beyond the leg 532. For example, the second material 566 may be positioned on a leg 532 to provide a protective layer of the second material that may deform, wear, or otherwise allow the leg 532 to contact a wellbore casing (such as casing 112 described in relation to FIG. 1) with a material having a lesser yield strength than the casing. In at least one embodiment, the second material 566 on the leg 532 may reduce damage to the casing upon contact with a leg 532. The second material 566 on the leg 532 may have any suitable thickness and may extend along a portion of or all of the outward facing leg surface.

In the depicted embodiment, the second material 566 extends toward the cone axis 536. In some embodiments, the second material 566 may extend a full distance to the cone axis 536 and form a complete disc at the base of the cone. In other embodiments, the second material 566 may extend less than the full distance to the cone axis 536 and may form a ring, as shown in FIG. 5. In some embodiments, at least part of a heel 548 of the cone 534 may be the second material 566. In other embodiments, the entire surface of the heel 548 may be the second material 566.

The cone 534 may have a beveled surface 568 adjacent to the heel 548. In some embodiments, the beveled surface 568 may include at least part of the second material 566. The beveled surface 568 may be non-coplanar with the heel 548. In some embodiments, the beveled surface 568 may be curved in longitudinal cross-section. In other embodiments, the beveled surface 568 may be flat in longitudinal cross-section. In some embodiments, at least part of the beveled surface 568 may be parallel with a bit axis 542. In other embodiments, the beveled surface 568 forms a first angle 572 with the cone axis 536. For example, the first angle 572 may be less than a second angle 574 between the cone axis 536 and the bit axis 542, resulting in at least a part of the beveled surface 568 being non-parallel with the bit axis 542. In some embodiments, at least part of the second material 566, as shown in FIG. 5, may have a radial thickness greater than the difference 570 between a bit body radius and the cutting radius. In other embodiments, no part of the second material 566 may have a radial thickness 552 greater than the difference 570 between a bit body radius and the cutting radius. In at least some embodiments, the beveled surface 568 may distribute force applied by the cone 534 when the cone 534 contacts another surface or object, such as casing 112 described in relation to FIG. 1. The beveled surface 568 may be oriented to apply the force over some or substantially all of the beveled surface 568 and may reduce the pressure applied to a point. In other embodiments, the second material 566 may deform and increase a contact surface of the beveled surface 568, thereby further reducing pressure from the cone 534 on the other surface or object.

When applied to a high shear roller cone bit as described in relation to FIG. 2, the second material 566 may be applied at or near the nose 550. Applying the second material 566 at or near the nose 550 when the cone 534 is oriented with the nose 550 radially outward, as in a high shear roller cone bit, may allow the second material 566 positioned at or near the nose 550 to provide a lower yield strength surface upon contact with another surface or object (such as the casing 112) during operation.

FIG. 6 is a side view of another embodiment of a low collision damage cone 634 having a second material 666 positioned as a ring upon the heel 648 of the cone 634. A first material 664 may support the ring of the second material 666 as the second material 666 assists in removal of material from a surrounding formation (not shown). While the second material 666 is shown as a ring having an inner diameter 676 of uniform distance from a cone axis 636, it should be understood that the second material 666 may have a non-uniform inner diameter 676. One or more radial features (not shown) of the second material 666 may provide additional torsional strength of a connection between the second material 666 and first material 664.

FIGS. 7 through 9 are side views of embodiments of low collision damage cones having a soft portion proximate the heel of the cone. FIG. 7 illustrates an embodiment of a cone 734 having a plurality of rows of cutting teeth. The cone 734 may include a nose row 778, an inner row 780, and a gage row 746 of cutting teeth 744. The cutting teeth 744 of the nose row 778, the inner row 780, and the gage row 746 may have the same profile or different profiles. In some embodiments, the nose row 778 and the inner row 780 may have the same profile, while the gage row 746 may have a different profile. For example, the gage row 746 may have a less aggressive profile to the cutting teeth 744 thereon. In at least one embodiment, the gage row 746 may have a profile in accordance with an IADC 21X rating (where X is bearing and/or mounting designation) and at least one other row of cutting teeth 744 on the cone 734 may have a profile in accordance with an IADC 11X rating. In other embodiments, the gage row 746 may have a profile in accordance with an IADC 31X rating and at least one other row of cutting teeth 744 on the cone 734 may have a profile in accordance with an IADC 21X or 11X rating. However, any combination of cutter profiles may be used where the gage row 746 has a less aggressive cutting structure than at least one of the other rows of cutting teeth 744. In other embodiments, the nose row 778 and inner row 780 may have different profiles, and the gage row may have a third profile. In yet another embodiment, the nose row 778, the inner row 780, and the gage row 746 may have cutting teeth 744 with similar or the same profile. For example, in some embodiments, the gage row 746 may have a greater density of teeth and/or shorter teeth and/or blunter teeth than the nose row 778 and/or the inner row 780. As shown in FIG. 6, the gage row may have teeth that are shorter and blunter than the taller and sharper teeth of the inner row 780 of FIG. 7.

As shown in FIG. 7, the cone 734 may have a gage row 746 of cutting teeth 744. The gage row 746 may be a second material 766 of the cone 734. The inner row 780 and the nose row 778 may be a first material 764 of the cone 734. The second material 766 may be connected to the first material 764 by welding, brazing, adhesive, mechanical fasteners (i.e., bolts, rivets, screws, pins, etc.), other connection types, or combinations thereof. In an embodiment, the second material 766 may be removably connected to the first material 764 using one or more mechanical fasteners (not shown). A removable connection between the second material 766 and the first material 764 may allow for the individual replacement of the first material 764 and/or second material 766. Individual replacement of the first material 764 and/or second material 766 may provide longer operational lifetime by replacing a portion of the cone 734 with a higher wear rate while a portion of the cone 734 with a lower wear rate may continue to be used.

In some embodiments, the first material 764 may include (e.g., be made of) steel alloys, titanium alloys, superalloys, other metals, or combinations thereof. In some embodiments, the first material 764 may include a steel alloy including alloying elements such as a carbon, manganese, nickel, chromium, molybdenum, tungsten, vanadium, silicon, boron, lead, another appropriate alloying element, or combinations thereof. In other embodiments, the first material 764 may include a titanium alloy including alloying elements such as aluminum, vanadium, palladium, nickel, molybdenum, ruthenium, niobium, silicon, oxygen, iron, another appropriate alloying element, or combinations thereof. In yet other embodiments, the first material 764 may include a superalloy including elements such as nickel, cobalt, iron, chromium, molybdenum, tungsten, tantalum, aluminum, titanium, zirconium, rhenium, yttrium, boron, carbon, another appropriate alloying element, or combinations thereof.

In some embodiments, the second material 766 may be any material having a different hardness and/or yield strength than the first material 764. In other embodiments, the second material 766 may be a material having a hardness and/or yield strength less than the first material. In yet other embodiments, the second material 766 may be a material having a hardness less than that of a casing of known or expected existing wellbores in a drilling environment. For example, the second material 766 may by a material having a hardness and/or yield strength less than the hardness and/or yield strength of the casing 112 of the existing wellbore 110 described in relation to FIG. 1. In at least some embodiments, the second material 766 may have a yield strength less than any of 30 ksi (210 MPa), 35 ksi (240 MPa), 42 ksi (290 MPa), 46 ksi (320 MPa), 52 ksi (360 MPa), 56 ksi (390 MPa), 60 ksi (410 MPa), 65 ksi (450 MPa), 70 ksi (480 MPa), 80 ksi (550 MPa), or any value therebetween.

In some embodiments, the second material 766 may be or include an aluminum alloy, a copper alloy, a mild steel, or combinations thereof. In other embodiments, the second material 766 may be or include an aluminum-copper bronze that is about 8% aluminum by weight with the balance being copper having a yield strength about 30 ksi (e.g., an aluminum-copper bronze that is 8.2 wt % aluminum and 91.8 wt % copper). The second material may be work-hardened. For example, the second material 766 may be a work-hardened aluminum-copper bronze with a yield strength between 30 ksi (210 MPa) and 56 ksi (390 MPa). In yet other embodiments, the second material 766 may be carbon fiber and/or a carbon fiber composite with a yield strength less than that of the first material. In some embodiments, the second material may be selected so that the initial hardness and/or yield strength and the expected work hardened hardness and/or yield strength is less than the hardness and/or yield strength of any expected casing.

FIG. 8 depicts another embodiment of a cone 834 according to the present disclosure. At least some elements of the cone 834 may be similar to elements of the cone 734 described in relation to FIG. 7. The cone 834 may have a gage row 846 of cutting teeth 844. The gage row 846 may be at least partly composed of a first material 864 and a second material 866. In the depicted embodiment, the first material 864 may account for approximately half of the gage row 846 in a direction coaxial with a cone axis 836. The second material 866 may account for approximately half of the gage row 846 in the direction coaxial with a cone axis 836. In other embodiments, the first material 864 and second material 866 may account for different proportions of the gage row 846 in the direction coaxial with a cone axis 836; e.g., the second material may account for 25%, 50%, 75%, 85%, 90%, 95%, or 100% of the gage row 846.

In yet another embodiment of a cone 934 according to the present disclosure, and as shown in FIG. 9, a gage row 946 may be at least partially a first material 964. The cone 934 may include a disc 982 made of or including a second material 966. In some embodiments, the disc 982 may have an outer diameter relative to a cone axis 936 approximately equal to that of the gage row 946. In other embodiments, the disc 982 may have an outer diameter that is less than an outer diameter of the gage row 946. In yet other embodiments, the disc 982 may have an outer diameter that is greater than an outer diameter of the gage row 946. The disc 982 may be substantially featureless or may have one or more surface features. A disc 982 having one or more surface features may aid the cone 934 in removal of material from a formation, such as the formation 108 described in relation to FIG. 1. A disc 982 that is substantially featureless may further reduce damage incurred when the cone 934 contacts a casing, such as casing 112 of an existing wellbore 110 as described in relation to FIG. 1.

FIG. 10 is a flowchart illustrating a method 1084 of manufacture for a low collision damage bit according to at least one embodiment described herein. The method 1084 may include providing 1086 a cone body having a nose and a heel and made of or including a first material and affixing 1088 to the heel a second material, where the cone body has a first hardness and the second material has a second hardness. In some embodiments, a cone body may be formed of a first material, the cone may then be machined to remove a portion of the first material at the gage, and then a second material may be affixed to the cone. The second hardness may be less than the first hardness. In other embodiments, the method of manufacture may further include connecting the cone according to the method 1084 to a bit body having a bit axis and an outer surface such that at least a part of the second material is further from the bit axis than the outer surface of the bit body. In yet other embodiments, the method may include shaping at least a part of the second material to have a plurality of cutting teeth. In further embodiments, shaping at least a part of the second material may include simultaneously shaping at least a part of the first material. Shaping the second material and/or first material may include milling, cutting, abrading, ablating, melting, hammering, other metalshaping techniques, or combinations thereof.

In an embodiment of the invention, a cone for use in a roller cone bit includes a nose, a heel located at an opposite end from the nose, a hard portion having a first yield strength, the hard portion forming at least a part of the nose, and a soft portion having a second yield strength less than the first yield strength, the soft portion forming at least a portion of the heel. In an embodiment, the soft portion has one or more teeth. In an embodiment, the soft portion is welded to the hard portion. In an embodiment, the hard portion has one or more recesses configured to receive a cutting insert. The soft portion may be an aluminum alloy or an aluminum bronze alloy. In an embodiment, the soft portion includes a gage row of cutting teeth. In an embodiment, the cone further comprises a gage row of cutting teeth, at least one cutting tooth of the gage row including part of the soft portion and part of the hard portion. In an embodiment, the soft portion has no teeth thereon.

In another embodiment of the invention, a bit for removal of earth comprises a bit body having a bit axis, a leg extending from the bit body, and a cone, the cone being rotatably connected to the leg, the cone having a nose and a heel, at least part of the nose being made of a first material and at least part of the heel being made of a second material, wherein the first material has a greater yield strength than the second material. In an embodiment, the bit body has a first diameter and the cone at least partially defining a second diameter greater than the first diameter. In an embodiment, the heel is further from the bit axis than an outer surface of the leg. The second material may have a yield strength less than 30 ksi, less than 35 ksi, less than 56 ksi, or less than 80 ksi. In an embodiment, the cone is rotatably connected to the leg about a cone axis that forms a first angle relative to the bit axis and the heel has a beveled surface that forms a second angle relative to the cone axis. The first angle may be equal to the second angle, less than the second angle, or greater than the second angle. The beveled surface may be curved or flat in longitudinal cross-section. In an embodiment, the cone has a first row of cutting teeth and a second row of cutting teeth, where the second row of cutting teeth is proximate the heel. In an embodiment, the first row of cutting teeth having a more aggressive profile than the second row of cutting teeth. In an embodiment, the second row of cutting teeth having an IADC 21X rating and the first row of cutting teeth having an IADC 11X rating.

In an embodiment of the invention, a method of manufacturing a bit includes providing a cone body having a nose and a heel, the cone body being made of a first material having a first hardness, and affixing to the heel a second material having a second hardness, the second hardness being less than the first hardness. In an embodiment, the method further includes connecting the cone to bit body having a bit axis, at least a portion of the second material being further from the bit axis than an outer surface of the bit body. In an embodiment, the method further includes shaping the second material to have a first plurality of cutting teeth. In an embodiment, the cone body has a second plurality of cutting teeth having the first hardness and the second plurality of cutting teeth having the second hardness. In an embodiment, the method further comprises shaping an interface between the second material and the first material to have a plurality of cutting teeth that are at least partly deformable material and at least partly cone body, wherein shaping the interface includes simultaneously shaping at least part of the first material and at least part of the second material.

In an embodiment of the invention, a bit includes a bit body having a bit axis and an outer diameter and one or more cones connected to the bit body, the one or more cones defining a cutting diameter that is less than the outer diameter of the bit body.

In another embodiment of the invention, a bit includes a bit body having bit axis and an outer diameter, one or more cones connected to the bit body, and one or more fluid outlets in the bit body, at least one of the fluid outlets being configured to provide a fluid path directed between the one or more cones. In an embodiment, the fluid path is directed between a plurality of gage rows and radially beyond the outer diameter. In an embodiment, the fluid path is directed coaxially with the bit axis.

In another embodiment of the invention, a cone for use in a roller cone bit includes a nose, a heel located at an opposite end from the nose, a nose row of cutting teeth proximate the nose, the nose row having a first profile, and a gage row of cutting teeth proximate the heel, the gage row having a second profile that is less aggressive profile than the first profile. In an embodiment, the second profile has a greater density of cutting teeth than the first profile. In an embodiment, the second profile has cutting teeth that are shorter than the first profile. In an embodiment, the second profile has cutting teeth that are blunter than the first profile.

While embodiments of bits and cones have been primarily described with reference to wellbore drilling operations, the bits and cones described herein may be used in applications other than the drilling of a wellbore. In other embodiments, bits and cones according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, bits and cones of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

LOW COLLISION DAMAGE BIT

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