Short make-up length bit

Abstract

A bit may include a body. A bit may include a plurality of blades extending from the body. A bit may include a bit connection extending uphole from the body. A bit may include a skirt extending from the body, the skirt extending at least partially over the bit connection to form an annular connection space between the skirt and the bit connection.

Description

FILED ELECTRONICALLY Docket No. IS240955-WO-PCTTITLESHORT MAKE-UP LENGTH BITCROSS-REFERENCED TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Patent Application 63 / 701,699 filed on October 1, 2024. The disclosure of which is incorporated herein in its entirety.BACKGROUND OF THE DISCLOSURE

[0002] Rotary drilling is defined as a system in which a bottom hole assembly, including the drill bit, is connected to a drill string which is rotatably driven from the drilling platform at the surface. When drilling holes in subsurface formations, it is sometimes desirable to be able to vary and control the direction of drilling, for example, to direct the borehole towards a desired target, or to control the direction horizontally within the payzone once the target has been reached. It may also be desirable to correct for deviations from the desired direction when drilling a straight hole, or to control the direction of the hole to avoid obstacles. Further, steering or directional drilling techniques may also provide the ability to reach reservoirs where vertical access is difficult or not possible (e.g., where an oilfield is located under a city, a body of water, or a difficult to drill formation) and the ability to group multiple wellheads on a single platform (e.g., for offshore drilling).SUMMARY

[0003] In some aspects, the techniques described herein relate to a bit. The bit includes a body. A plurality of blades extend from the body. A bit connection extends uphole from the body. A skirt extends from the body. The skirt extends at least partially over the bit connection to form an annular connection space between the skirt and the bit connection.

[0004] In some aspects, the techniques described herein relate to a steering system. The steering system includes a steering unit having a steering unit connection. A bit is connected to the steering unit. The bit includes a bit body. A plurality of blades extend from the bit body. A bit connection extends uphole from the bit body. A skirt extends uphole from the bit body. When the bit is connected to the steering unit at the steering unitFILED ELECTRONICALLY Docket No. IS240955-WO-PCT connection and the bit connection, the skirt extends at least partially over the steering unit connection.

[0005] In some aspects, the techniques described herein relate to a bit. The bit includes a bit connection and a plurality of blades having a gauge portion. The plurality of blades extend over the bit connection in the gauge portion.

[0006] This summary is provided to introduce a selection of concepts that are further described 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. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] 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:

[0008] FIG. l is a representation of a drilling system, according to at least one embodiment of the present disclosure.

[0009] FIG. 2 is a schematic representation of a steering system located in a wellbore, according to at least one embodiment of the present disclosure.

[0010] FIG. 3 is a perspective view of a bit, according to at least one embodiment of the present disclosure.

[0011] FIG. 4 is a side-view of a steering system having a steering unit connected to a bit with a connection, according to at least one embodiment of the present disclosure.FILED ELECTRONICALLY Docket No. IS240955-WO-PCT

[0012] FIG. 5-1 through FIG. 5-3 are representations of a bit in a steering system, according to at least one embodiment of the present disclosure.

[0013] FIG. 6 is a cross-sectional view of a representation of a bit 610, according to at least one embodiment of the present disclosure.DETAILED DESCRIPTION

[0014] By way of background, FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (BHA) 106, and a bit 110, attached to the downhole end of drill string 105.

[0015] The drill string 105 may include several joints of drill pipe 108 connected end-to- end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, for lifting cuttings out of the wellbore 102 as it is being drilled, for controlling influx of fluids in the well, for maintaining the wellbore integrity, and for other purposes.

[0016] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or damping tools, other components, or combinations of the foregoing. The BHA 106 may further include a directional tool 111 such as a bent housing motor or a rotary steerable system (RSS). The directional tool 111 may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. In some cases, at least a portion of the directional tool 111 may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, or true north. UsingFILED ELECTRONICALLY Docket No. IS240955-WO-PCT measurements obtained with the geostationary position, the directional tool 111 may locate the bit 110, change the course of the bit 110, and direct the directional drilling tool 111 on a projected trajectory. For instance, although the BHA 106 is shown as drilling a vertical portion 102-1 of the wellbore 102, the BHA 106 (including the directional tool 111) may instead drill directional or deviated well portions, such as directional portion 102-2.

[0017] Examples of directional tools 111 and / or steering systems may include “push-the- bif ’ systems, “point-the-bif ’ systems, hybrid systems, any other system, and combinations thereof. In a push-the-bit system, actuator pads may extend from the directional tool 111 to contact the wellbore wall. The actuator pads may apply a force against the wellbore wall, which may push the bit away from the actuator pad. Other examples of push-the-bit systems may include RSS systems, non-rotating (with respect to the hole) eccentric stabilizers (e.g., displacement-based systems). Steering is achieved by creating non colinearity between the drill bit and at least two other touch points.

[0018] In point-the-bit systems, the axis of rotation of the bit 110 is deviated from the local axis of the BHA 106 in the general direction of the desired path (target attitude). The borehole is propagated in accordance with the customary three-point geometry defined for example by upper and lower stabilizers and the hole reaming cutters. The angle of deviation of the drill bit axis coupled with a finite distance between the lower and middle touch points results in the non-collinear condition for a curve to be generated. This may be accomplished, for example, by a fixed bend at a point in the BHA 106 close to the lower stabilizer or flexure in the drill bit drive shaft distributed between the upper and lower stabilizers.

[0019] In general, the drilling system 100 may include additional or other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

[0020] In some embodiments, the BHA 106 may include a downhole motor to power for downhole systems and / or provide rotational energy for downhole components (e.g., rotate the bit 110, drive the directional tool 111, etc.). The downhole motor may be any type of downhole motor, including a positive displacement pump (such as a progressive cavityFILED ELECTRONICALLY Docket No. IS240955-WO-PCT motor) or a turbine. In some embodiments, a downhole motor may be powered by the drilling fluid flowing through the drill pipe 108. In other words, the drilling fluid pumped downhole from the surface may provide the energy to rotate a rotor in the downhole motor. The downhole motor may operate with an optimal pressure differential or pressure differential range. The optimal pressure differential may be the pressure differential at which the downhole motor may not stall, bum out, overspin, or otherwise be damaged. In some cases, the downhole motor may rotate the bit 110 such that the drill string 105 may not be rotated at the surface, or may rotate at a different rate (e.g., slower) than the rotation of the bit 110.

[0021] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials such as earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, and combinations thereof. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other downhole materials, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface or may be allowed to fall downhole. In still other embodiments, the bit 110 may include a reamer. For instance, an underreamer may be used in connection with a drill bit and the drill bit may bore into the formation while the underreamer enlarges the size of the bore.

[0022] The bit 110 may have a short make-up length. Put another way, a distance between the bit 110 and the directional tool 111 may be reduced. To reduce the make-up length, a portion of the gauge portion of the bit 110 may overlap the connection between the bit 110 and the directional tool 111. For example, the gauge portion of the blades of the bit 110 may overlap or extend over the connection between the bit 110 and the directional tool 111. Reducing the make-up length between the bit 110 and the directional tool 111 may increase the maximum DLS possible to be drilled between the vertical portion 102-1 and the directional portion 102-2. Further, reducing the make-up length may result in increased steering efficiency. In some embodiments, reducing the make-up length may reduce theFILED ELECTRONICALLY Docket No. IS240955-WO-PCT weight of the bit 110. This may improve the ease of manufacturing and / or reduce wear and tear on the drilling system.

[0023] FIG. 2 is a schematic representation of a steering system 215 located in a wellbore, according to at least one embodiment of the present disclosure. The steering system 215 includes a bit 210 and a steering unit 214. The bit 210 and the steering unit 214 may be located in a wellbore 202. The steering unit 214 shown includes a push-the-bit steering system, however, it should be understood that the principles of this disclosure may be applied to any steering system, including point-the-bit systems, hybrid systems, any other system, and combinations thereof.

[0024] The steering unit 214 includes a set of stabilizer pads 216 and a set of steering pads 218. The steering pads 218 may be selectively extended through the housing of the steering unit 214 and through one or more actuator supports. The steering pads 218 may extend out of the housing and the actuator supports to contact the wellbore wall 220. For example, when extended, the steering pads 218 may apply a force to an outer radial surface 212 of the wellbore wall 220. The stabilizer pads 216 may contact the wellbore wall 220 as the steering pads 218 push outer radial surface 212. The eccentricity in the force may cause the bit 210 to be pointed in a different direction. In this manner, as the bit 210 engages the wellbore wall 220 to advance the wellbore 202, the wellbore 202 may be deviated in a “dogleg,” or a curve away from a straight-line trajectory.

[0025] The steering system 215 shown includes a stiff three-point steering assembly. The steering pads 218 engage the wellbore wall 220 at a lower contact point 222. The steering pads 218 are located further downhole (e.g., closer to the bit, further from the collar of the wellbore 202), than the stabilizer pads 216. The stabilizer pads 216 engage the wellbore wall 220 at an upper contact point 224. The bit 210 engages the wellbore wall 220 at a bit contact point 226, which may be the uphole-most portion of the bit 210 that contacts the wellbore wall 220. The bit contact point 226 may be at the portion of the bit 210 this is pushed into the wellbore wall 220 based on the steering pads 218 pushing against the wellbore wall 220. Embodiments of the present disclosure may describe the bit contact point 226 as the uphole-most cutting element, but it should be understood that the bit contact point 226 may include whichever cutting element engages the wellbore at the uphole-most location on the bit 210.FILED ELECTRONICALLY Docket No. IS240955-WO-PCT

[0026] In the stiff three-point steering assembly shown, the dogleg severity (DLS) capability or curvature response may be expressed as:DLS = — Eq. 1L1*L2 where ecc is the eccentricity (e.g., the stroke length of the steering pads 218, the distance the steering pads 218 push the bit 210), LI is the distance from the uphole-most active cutting structure on the bit and the steering pad, and L2 is the distance from the steering pad to the upper contact point. In the illustrated embodiment, the LI distance 237 may be the distance from the bit contact point 226 and the lower contact point 222 and the L2 distance 235 may be the distance from the upper contact point 224 and the lower contact point 222.

[0027] As may be seen in Eq. 1, the DLS is inversely proportional to the LI distance 237 and the L2 distance 235. Thus, a reduction in the LI distance 237 or the L2 distance 235 results in an increase in DLS. In practice, the LI distance 237 is shorter than the L2 distance 235. Thus, a change of a few inches or cm in the LI distance 237 may result in a larger increase in the DLS than a comparative change in the L2 distance 235. In at least one embodiment, the LI distance 237 can be reduced by moving the bit contact point 226 closer to the steering pads 218.

[0028] In some embodiments, the uphole-most gauge cutting element 228 is the uphole- most cutting element on the bit 210. As the uphole-most gauge cutting element is on the bit, the uphole-most gauge cutting element 228 may contact the wellbore wall 220 at the bit contact point 226. In some embodiments, the uphole-most gauge cutting element may be the last (or uphole-most) active cutting element on the bit 210, or the last cutting element that is configured to engage the wellbore wall 220 to actively degrade the formation.

[0029] In accordance with at least one embodiment of the present disclosure, the bit 210 may reduce the LI distance 237 by having a portion of the bit overlap a connection 230 between the bit 210 and the steering unit 214. For example, as discussed in further detail herein, a portion of a gauge portion 232 of the bit 210 may overlap the connection 230. This may reduce a make-up length 234 between the bit 210 and the steering unit 214. The make-up length 234 may be the length that the connection 230 occupies between the steering unit 214 and the bit 210. Reducing the make-up length 234 may reduce the LIFILED ELECTRONICALLY Docket No. IS240955-WO-PCT di stance 237, thereby increasing the maximum DLS of the steering system 215, improving steering efficiency, and / or reducing the weight of the bit 210.

[0030] FIG. 3 is a perspective view of a bit 310, according to at least one embodiment of the present disclosure. The bit 310 includes a bit body 336. A plurality of blades 338 may extend from the bit body 336. For example, the plurality of blades 338 may extend away from an outer surface of the bit body 336. The bit 310 may include a gauge portion 332, a shoulder portion 340, a nose portion 342, and a cone portion 344.

[0031] The bit 310 includes a bit connection 346. The bit connection 346 may be configured to connect the bit 310 to another portion of a drilling assembly. For example, the bit connection 346 may be configured to connect the bit 310 to a steering unit (such as the steering unit 214 illustrated in FIG. 2), an RSS, a slide drilling system, or any other portion of a drilling system. In the embodiment illustrated, the bit 310 includes a threaded bit connection 346. In particular, the bit connection 346 shown is a pin connection, for use in a pin-up drilling system. However, the techniques of the present disclosure may be applied box connections (for use in a pin-down drilling system). In some embodiments, the techniques of the present disclosure may be applied to other connection types, such as bolted connections, brazed connections, welded connections, any other types of connections, and combinations thereof.

[0032] In accordance with at least one embodiment of the present disclosure, at least a portion of the gauge portion 332 of the bit 310 may be opposite the bit connection, or overlap the bit connection 346. For example, at least a portion of the gauge portion 332 may extend over a portion of the bit connection 346, or be located opposite the bit connection 346. In some examples, at least a portion of the gauge portion 332 may be located opposite the threads of the bit connection 346. This may embed or recess the bit connection 346 at least partially within the bit body 336 of the bit 310. In this manner, the connection with the steering unit may be recessed or embedded within the bit 310, or within the bit body 336 of the bit 310. This may reduce the make-up length of the steering system, thereby reducing the LI length and increasing the maximum DLS of the steering system, increasing the steering efficiency, and / or reducing the weight of the bit.

[0033] In some embodiments, the bit 310 may include a skirt 348. The skirt 348 may surround, overlap, or extend over the bit connection 346. For example, the skirt 348 mayFILED ELECTRONICALLY Docket No. IS240955-WO-PCT extend from an outer surface of the bit body 336 such that the skirt 348 extends past an upper edge of the bit connection 346 and radially surround the bit connection 546. The skirt 348 may form an annular connection space 350 between an inner surface of the skirt 348 and an outer surface of bit connection 346. As may be seen, in some embodiments, the blades 338 may extend into the skirt 548 to overlap the bit connection 346 such that at least a portion of the gauge portion 332 of the blades 338 is located opposite the annular space 350 and the bit connection 346.

[0034] When the bit 310 is connected to the steering unit, a flange of the steering unit may extend into the annular connection space 350. In this manner, the skirt 348, and at least a portion of the gauge portion 332 of the blades 338, may surround, extend over, or overlap the steering unit connection, or a flange that extends downhole from the steering unit connection.

[0035] FIG. 4 is a side-view of a steering system 415 having a steering unit 414 connected to a bit 410 with a connection 430, according to at least one embodiment of the present disclosure. As discussed herein, a gauge portion 432 of blades 438 of the bit 410 may at least partially overlap the connection 430. This may reduce a make-up length 434 of the steering system 415.

[0036] As may be seen, a flange 452 from the steering unit 414 may extend into the bit 410. For example, the steering unit 414 may include a steering unit connection. The steering unit connection may include a flange 452 that may extend downhole from the steering unit 414. The flange 452 may extend into the bit 410 such that the gauge portion 432 of the blades 438 may extend over at least a portion of the steering unit connection, including the flange 452. This may move the bit 410 closer to the steering unit 414, and steering pads 418 of the steering unit 414. In this manner, the make-up length 434 may be reduced, thereby reducing the LI distance and increasing the maximum DLS for the steering system 415, increasing the steering efficiency, and / or reducing the weight of the bit.

[0037] FIG. 5-1 is a side-view of a representation of a bit 510, according to at least one embodiment of the present disclosure. The bit 510 includes a bit body 536. A plurality of blades 538 may extend from the bit body 536. For example, the plurality of blades 538 mayFILED ELECTRONICALLY Docket No. IS240955-WO-PCT extend away from an outer surface of the bit body 536. The blades 538 may include a gauge portion 532, a shoulder portion 540, a nose portion 542, and a cone portion 544.

[0038] The bit body 536 may extend uphole (e.g., away from the cone portion 544 and the nose portion 542). A bit connection 546 may be connected to the bit body 536. The bit connection 546 illustrated is a threaded connection, and in particular a pin connection for a pin-up connection with a steering unit. In accordance with at least one embodiment of the present disclosure, the bit 510 may extend over the bit connection 546. For example, at least a portion of the bit body 536 may extend into a skirt 548, and the skirt may surround and extend over the bit connection 546 such that a portion of the skirt 548 overlaps the bit connection 546.

[0039] The skirt 548 may surround the bit connection 546 to form an annular connection space 550 between the skirt 548 and the bit connection 546. When the bit 510 is connected to a steering unit, the steering unit connection may extend at least partially into the annular connection space 550 such that a portion of the steering unit connection is recessed within the bit body 536 of the bit 510.

[0040] FIG. 5-2 is a cross-sectional view of the bit 510 of FIG. 5-1. As may be seen, the skirt 548 surrounds, extends over, or at least partially overlaps, the bit connection 546. Put another way, the bit connection 546 is at least partially recessed in the bit body 536. In this manner, a bit make-up face 554 may be recessed in the bit body 536 of the bit 510. The bit make-up face 554 may be the portion of the bit 510 that engages or contacts the connection with the steering unit. For example, when the steering unit is connected to the bit 510, a steering unit make-up face may engage or contact the bit make-up face 554 of the bit 510. The bit make-up face 554 may be perpendicular, or approximately perpendicular, to a rotational axis of the bit 510. In some embodiments, the bit make-up face 554 may have another shape, including angled or curved with respect to the rotational axis of the bit 510.

[0041] The bit make-up face 554 may be located in a downhole direction 556 of an uphole surface 558 of the gauge portion 532 of the blades 538. In some embodiments, the bit makeup face 554 may be located downhole of an uphole-most cutting element 560. In the embodiment shown, the uphole-most cutting element 560 is a back-reamer located at the uphole surface 558 of the gauge portion 532 of the blades 538. In some embodiments, the uphole-most cutting element 560 may include a gauge cutting element secured to the gaugeFILED ELECTRONICALLY Docket No. IS240955-WO-PCT portion 532 of the blades 538, and the gauge cutting element may be located opposite the annular connection space and / or the bit connection. In the embodiment shown, the uphole- most cutting element 560 includes a back-reamer, and the back-reamer extends over the bit connection. However, it should be understood that the uphole-most cutting element 560 may be any type of cutting element, including a wear pad oriented to slide along the wellbore wall (rather than cut or engage the wellbore wall), a conical cutting element, an axe-shaped cutting element, any other cutting element, and combinations thereof.

[0042] In the embodiment shown, the skirt 548 extends past the uphole surface 558 of the blades 538. However, it should be understood that the uphole surface 564 of the skirt 548 may be flush or matched to the uphole surface 558. In some embodiments, the skirt 548 may include a breaker slot or other elements to grip the bit 510 and separate the bit 510 from the connected drilling system. In some embodiments, the breaker slot may be located in the gauge portion 532 of the blades 538. In some embodiments, the breaker slot may be located in the part of the gauge portion 532 that is located opposite the bit connection 546 or the annular connection space 550. Put another way, the breaker slot may be located opposite the bit connection 546. In some embodiments, a bit connection system may utilize a star breaker or other breaker system that grips the bit 510 from a downhole end, and engages the blades 538 to break the connection between the bit 510 and the steering unit. In this manner, the bit 510 may have a reduced length of the skirt 548, or the distance the skirt 548 extends past the uphole surface 558 of the blades 538, thereby reducing the makeup length.

[0043] In accordance with at least one embodiment of the present disclosure, the skirt 548, or at least a portion of the skirt 548 at the uphole surface 564, may be formed from a wearresistant material. For example, the uphole surface 564 may be exposed during drilling activities. Forming the uphole surface 564 from a wear-resistant material may reduce or prevent damage or wear to the skirt 548. The wear-resistant material may include any wearresistant material, such as tungsten carbide, another carbide, polycrystalline diamond, any other wear-resistant material, and combinations thereof.

[0044] The annular connection space 550 may have a connection space depth 562, or a distance from an uphole surface 564 of the skirt 548 and the bit make-up face 554. In some embodiments, the connection space depth 562 may be in a range having an upper value, aFILED ELECTRONICALLY Docket No. IS240955-WO-PCT lower value, or upper and lower values including any of 0.1 in (0.25 cm), 0.5 in. (1 .3 cm), 1.0 in. (2.5 cm), 2.0 in. (5.1 cm), 3.0 in. (7.6 cm), 4.0 in. (10.2 cm), 5.0 in. (12.7 cm), 6.0 in (15.2 cm), 7.0 in. (17.8 cm), 8.0 in. (20.3 cm), 9.0 in. (22.9 cm), 10 in. (25.4 cm), 11 in. (27.9 cm), 12 in. (30.5 cm), or any value therebetween. For example, the connection space depth 562 may be greater than 0.1 in (0.25 cm). In another example, the connection space depth 562 may be less than 12 in. (30.5 com). In yet other examples, the connection space depth 562 may be any value in a range between 0.1 in (0.25 cm) and 12 in. (30.5 cm). In some embodiments, it may be critical that the connection space depth 562 is between 3.0 in. (7.6 cm) and 9.0 in. (22.9 cm) to decrease the make-up length, increase the maximum DLS, and reduce the weight of the bit.

[0045] The bit make-up face 554 may be located a face distance 566 from the uphole surface 558. The gauge portion 532 of the blades 538 has a gauge length 568. The face distance 566 may be a gauge percentage of the gauge length 568. Put another way, the face distance 566 may be located along the gauge portion 532 of the blades 538 the gauge percentage. In some embodiments, the gauge percentage may be in a range having an upper value, a lower value, or upper and lower values including any of 1%, 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100% (e.g., the bit make-up face 554 is located at or downhole hole of the boundary between the gauge portion 532 and the shoulder portion 540, the gauge portion 532 overlaps an entirety of the bit connection, the gauge portion 532 overlaps over an entirety of the gauge portion 532), or any value therebetween. For example, the gauge percentage may be greater than 1%. In another example, the gauge percentage may be less than 100%. In yet other examples, the gauge percentage may be any value in a range between 1% and 100%. In some embodiments, it may be critical that the gauge percentage is between 10% and 50% to reduce the make-up length, increase the maximum DLS, and decrease the weight of the bit 510.

[0046] The bit 510 including the recessed bit make-up face 554 may be any size bit having a bit diameter. In some embodiments, the bit diameter may be in a range having an upper value, a lower value, or upper and lower values including any of 2.0 in. (5.1 cm), 3.0 in. (7.6 cm), 4.0 in. (10.2 cm), 5.0 in. (12.7 cm), 6.0 in (15.2 cm), 7.0 in. (17.8 cm), 8.0 in. (20.3 cm), 9.0 in. (22.9 cm), 10 in. (25.4 cm), 11 in. (27.9 cm), 12 in. (30.5 cm), 14 in. (35.6 cm), 16 in. (40.6 cm) 18 in. (45.7 cm), 20 in. (50.8 cm), 22 in. (55.9 cm), 24 in. (61.0FILED ELECTRONICALLY Docket No. IS240955-WO-PCT cm), 30 in. (76.2 cm), 38 in. (96.5 cm), or any value therebetween. For example, the bit diameter may be greater than. For example, the bit diameter may be greater than 4.0 in. (10.2 cm). In another example, the bit diameter may be less than 38 in. (96.5 cm). In yet other examples, the bit diameter may be any value in a range between 4.0 in. (10.2 cm) and 38 in. (96.5 cm). In some embodiments, bits having a larger bit diameter may be able to obtain a larger decrease in make-up length.

[0047] The bit 510 may be formed from any material. For example, the bit 510 may be formed from steel. The features of the bit 510, including the bit body 536, the blades 538, a fluid path 570 through the bit 510, including fluid conduits to one or more nozzles at the bit 510, the bit connection 546, and so forth, may be machined or otherwise formed from a steel blank. In some embodiments, the bit 510 may be formed from a matrix material, such as tungsten carbide or other carbide material. In some embodiments, the bit 510 may be formed from a combination of matrix material and steel. In some embodiments, all or a portion of the bit 510 may be formed using additive manufacturing techniques (e.g., 3-D printing). For example, the geometry of the bit 510 may be formed layer-by-layer, thereby allowing for curved structures not otherwise attainable using conventional substrative manufacturing techniques.

[0048] FIG. 5-3 is a representation of the bit 510 of FIG. 5-1 connected to a steering unit 514. In the embodiment shown, a steering unit connection 572 may be connected to the bit connection 546 to form a completed connection 530. As may be seen, at least a portion of the steering unit connection 572 extends into the annular connection space 550 of the bit 510. When the connection 530 is made, a steering unit make-up face 574 may engage the bit make-up face 554. In this manner, at least a portion of the steering unit connection 572 may extend into the bit body 536, thereby reducing the make-up length of the connection 530.

[0049] In accordance with at least one embodiment of the present disclosure, at the steering unit connection 572, the bit 510 may include a seal. For example, in some situations, the steering unit make-up face 574 and the bit make-up face 554 may not contact, and drilling mud, cuttings, and other elements may collect in the gap between the steering unit makeup face 574 and the bit make-up face 554. The steering unit connection 572 may include a seal, such as an O-ring, Teflon (or other polymer) ring, or other sealing material. This mayFILED ELECTRONICALLY Docket No. IS240955-WO-PCT provide a seal at the steering unit connection 572 to reduce or prevent the accumulation of material at the steering unit connection 572 and / or a washout of the steering unit connection 572.

[0050] As may be seen, at least a portion of the gauge portion 532 of the blades 538 extends over, or overlaps, the steering unit connection 572. In some embodiments, the blades 538 overlap the steering unit connection 572 over an entirety of the steering unit connection 572. In some embodiments, at least one gauge cutting element is located opposite the steering unit connection 572.

[0051] The steering unit connection 572 may include a flange 576. The flange 576 may be the portion of the steering unit connection 572 that extends out of a body of the steering unit 514. In some embodiments, an entirety of the flange 576 may extend into the annular connection space 550. In some embodiments, the steering unit connection 572 may be located at a downhole end of the flange 576.

[0052] FIG. 6 is a cross-sectional view of a representation of a bit 610, according to at least one embodiment of the present disclosure. The bit 610 includes a bit body 636. A plurality of blades 638 may extend from the bit body 636. For example, the plurality of blades 638 may extend away from an outer surface of the bit body 636. The blades 638 may include a gauge portion 632, a shoulder portion 640, a nose portion 642, and a cone portion 644.

[0053] The bit body 636 may extend uphole (e.g., away from the cone portion 644 and the nose portion 642). A bit connection 646 may be connected to the bit body 636. The bit connection 646 illustrated is a threaded connection, and in particular a pin connection for a pin-up connection with a steering unit. In accordance with at least one embodiment of the present disclosure, the bit 610 may extend over the bit connection 646. For example, at least a portion of the bit body 636 may extend into a skirt 648, and the skirt may surround and extend over the bit connection 646 such that a portion of the skirt 648 overlaps the bit connection 646.

[0054] The skirt 648 may form an annular connection space 650 between the skirt 648 and the bit connection 646. When the bit 610 is connected to a steering unit, the steering unit connection may extend at least partially into the annular connection space 650 such that a portion of the steering unit connection is recessed within the bit body 636 of the bit 610.FILED ELECTRONICALLY Docket No. IS240955-WO-PCT

[0055] In the embodiment shown in FIG. 6, the bit 610 is a two-piece bit. For example, the bit 610 includes a first piece 678 and a second piece 680. The first piece 678 and the second piece 680 may be separately manufactured. To form the bit 610, the first piece 678 and the second piece 680 may be combined. The first piece 678 and the second piece 680 may be combined in any manner. For example, the first piece 678 and the second piece 680 may be connected with a connection, such as a brazed connection, a welded connection, a threaded connection, a bolted connection, any other connection, and combinations thereof.

[0056] In some embodiments, the first piece 678 and the second piece 680 may be formed from different materials. For example, the first piece 678 may be formed from a matrix material, such as tungsten carbide or another carbide. The second piece 680 may be formed from a relatively more ductile material, such as steel. This may facilitate a tough, wear and erosion resistant material for the first piece 678 that may engage the wellbore wall, and a ductile second piece 680 that may be used to connect the bit 610 to other portions of the drilling assembly, including the steering unit.

[0057] As may be seen, the first piece 678 may form a cavity or other void into which the 680 may be inserted. When the second piece 680 is secured to the first piece 678, the bit connection 646 may be inserted at least partially into the bit body 636 of the bit 610 so that the some of the threads of the bit connection 646 may be inside the annular connection space 650 and / or a part of the gauge portion 632 of the plurality of blades 638 may overlap the threads of the bit connection 646.

[0058] The embodiments of the short make-up length bit have been primarily described with reference to wellbore drilling operations; the short make-up length bits described herein may be used in applications other than the drilling of a wellbore. In other embodiments, short make-up length bits 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, short make-up length bits 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.

[0059] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques.FILED ELECTRONICALLY Docket No. IS240955-WO-PCTAdditionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment 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 embodiment-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 embodiment 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.

[0060] 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.

[0061] 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 inFILED ELECTRONICALLY Docket No. IS240955-WO-PCT 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.

[0062] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which 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.

[0063] 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.

Claims

FILED ELECTRONICALLY Docket No. IS240955-WO-PCTCLAIMSWhat is claimed is:

1. A bit, comprising: a body; a plurality of blades extending from the body; a bit connection extending uphole from the body; and a skirt extending from the body, the skirt extending at least partially over the bit connection to form an annular connection space between the skirt and the bit connection.

2. The bit of claim 1, wherein a bit make-up face is located further downhole than an uphole surface of a gauge portion of the plurality of blades.

3. The bit of claim 1, wherein the plurality of blades overlap the annular connection space in a gauge portion of the plurality of blades.

4. The bit of claim 3, wherein the plurality of blades overlap the annular connection space over an entirety of the gauge portion.

5. The bit of claim 3, wherein at least one gauge cutting element secured to the gauge portion is located opposite the annular connection space.

6. The bit of claim 1, further comprising a breaker slot in a gauge portion of the plurality of blades.

7. The bit of claim 1, wherein the bit connection is a pin connection.

8. The bit of claim 1, wherein the bit is formed from steel.

9. A steering system, comprising: a steering unit having a steering unit connection; and a bit connected to the steering unit, the bit including: a bit body; a plurality of blades extending from the bit body; a bit connection extending uphole from the bit body; and a skirt extending uphole from the bit body, wherein, when the bit is connected to the steering unit at the steering unit connection and the bit connection, the skirt extends at least partially over the steering unit connection.FILED ELECTRONICALLY Docket No. IS240955-WO-PCT10. The steering system of claim 9, wherein the plurality of blades extend into the skirt to overlap the steering unit connection at a gauge portion of the plurality of blades.

11. The steering system of claim 10, wherein the plurality of blades overlap the steering unit connection over an entirety of the steering unit connection.

12. The steering system of claim 10, wherein at least one gauge cutting element secured to the gauge portion is located opposite the steering unit connection.

13. The steering system of claim 9, wherein the skirt extends over an entirety of the steering unit connection.

14. The steering system of claim 9, wherein the bit connection is a pin connection and the steering unit connection is a box connection.

15. The steering system of claim 9, wherein the bit further includes a breaker slot in the plurality of blades opposite the steering unit connection.

16. A bit, compri sing : a bit connection; and a plurality of blades including a gauge portion, wherein the plurality of blades extend over the bit connection in the gauge portion.

17. The bit of claim 16, wherein the gauge portion extends over the bit connection from an uphole-most cutting element of the plurality of blades.

18. The bit of claim 16, wherein the plurality of blades form an annular connection space between the plurality of blades and the bit connection.

19. The bit of claim 16, wherein a back-reamer secured to the plurality of blades extends over the bit connection.

20. The bit of claim 16, further comprising a skirt surrounding the bit connection at the plurality of blades.

Images