WO2025010062A1

WO2025010062A1 - Devices, systems, and methods for steering a wellbore

Info

Publication number: WO2025010062A1
Application number: PCT/US2023/026879
Authority: WO
Inventors: Edward Richards; Riadh Boualleg
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Priority date: 2023-07-05
Filing date: 2023-07-05
Publication date: 2025-01-09
Anticipated expiration: 2026-01-05

Abstract

A steering system may include a steering unit having a plurality of steering pads and a steering connection. A steering system may include a bit having a gauge diameter and a bit connection, the bit connecting to the steering unit at the bit connection and the steering connection, the bit including a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.

Description

DEVICES, SYSTEMS, AND METHODS FOR STEERING A WELLBORE

BACKGROUND OF THE DISCLOSURE

[0001] 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

[0002] In some aspects, the techniques described herein relate to a drilling system. The drilling system includes a steering unit having a plurality of steering pads and a steering connection. A bit has a gauge diameter and a bit connection. The bit connects to the steering unit at the bit connection and the steering connection. The bit includes a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.

[0003] In some aspects, the techniques described herein relate to a drilling system. The drilling system includes a steering unit having a plurality of steering pads and a steering connection. A bit has a gauge diameter and a bit connection. The bit connects to the steering unit at the bit connection and the steering connection. A gauge ring is located between the bit and the plurality of steering pads. The gauge ring includes a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.

[0004] In some aspects, the techniques described herein relate to a bit. The bit includes a body. A plurality of blades extend from the body. The plurality of blades have a gauge diameter. A bit

1

SUBSTITUTE SHEET ( RULE 26) connection connects the bit to a steering unit. A skirt includes an uphole-most gauge cutting element located uphole of the bit connection.

[0005] 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

[0006] 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:

[0007] FIG. l is a representation of a drilling system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure;

[0008] FIG. 2 is a schematic representation of a steering system located in a wellbore, according to at least one embodiment of the present disclosure;

[0009] FIG. 3-1 is an exploded view of a schematic representation of a steering system, according to at least one embodiment of the present disclosure;

[0010] FIG. 3-2 is a representation of the assembled steering system of FIG. 3-1;

[0011] FIG. 4 is a schematic representation of an exploded view of a steering system, according to at least one embodiment of the present disclosure;

[0012] FIG. 5 is a schematic representation of an exploded view of a steering system, according to at least one embodiment of the present disclosure;

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SUBSTITUTE SHEET ( RULE 26) [0013] FIG. 6 is a schematic representation of an exploded view of a steering system, according to at least one embodiment of the present disclosure;

[0014] FIG. 7-1 through FIG. 7-3 are representations of bits, according to at least one embodiment of the present disclosure; and

[0015] FIG. 8 is a flowchart of a method for manufacturing a steering system, according to at least one embodiment of the present disclosure.

DETAILED DESCRIPTION

[0016] This disclosure generally relates to devices, systems, and methods for steering systems in a downhole drilling environment. A steering system may include a bit and a steering unit. The steering unit may include one or more actuator pads. The steering system may include one or more actuator pads that extend to contact the wellbore wall. The actuator pads may cause the bit to be redirected. The bit may include a bit connection that is connected to a steering connection of the steering unit. In accordance with at least one embodiment of the present disclosure, the steering system may include one or more gauge cutting elements that are located uphole of the bit connection. In at least one embodiment as described herein, the combination of one or more of these features facilitates increasing the dogleg severity and/or steering control of the steering system.

[0017] In accordance with at least one embodiment of the present disclosure, the bit may include a skirt. The skirt may extend uphole of the bit connection. The skirt may include one or more gauge cutting elements. Placing the gauge cutting elements on the skirt may move the cutting elements close to and/or adjacent to the actuator pads of the steering unit. In at least one embodiment described herein, one or more of these features may reduce the LI distance, thereby increasing the dogleg severity and/or steering control of the drilling system.

[0018] In some embodiments, the steering system includes one or more gauge rings between the bit and the steering unit. The gauge ring may include one or more gauge cutting elements. The gauge ring may be secured to the steering system between a bit shoulder on the bit and a steering shoulder on the shoulder. In this manner, the gauge cutting elements may be located close to and/or adjacent to the actuator pads of the steering unit. In at least one embodiment described herein, one or more of these features may reduce the LI distance, thereby increasing the dogleg severity and/or steering control of the drilling system.

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SUBSTITUTE SHEET ( RULE 26) [0019] To facilitate understanding of the reader, 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.

[0020] 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 further includes 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.

[0021] 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, measurementwhile-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. Using 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.

[0022] 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

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SUBSTITUTE SHEET ( RULE 26) 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 co-linearity between the drill bit and at least two other touch points.

[0023] 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 noncollinear 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.

[0024] In accordance with at least one embodiment of the present disclosure, a steering system may include a bit 110 having gauge cutting element located proximate the directional tool 111. This may reduce the distance between the lower end of the bit 110 and the actuators of the directional tool 111. As discussed in further detail herein, reducing the distance between the bit 110 and the directional tool 111 may help to increase the dogleg severity and/or improve the steering control of the directional tool 111.

[0025] 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.

[0026] In some embodiments, the BHA 106 includes 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 cavity motor) or a turbine. In some embodiments, a downhole motor is 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

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SUBSTITUTE SHEET ( RULE 26) 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.

[0027] 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.

[0028] FIG. 2 is a schematic representation of a steering system 212 located in a wellbore, according to at least one embodiment of the present disclosure. The steering system 212 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.

[0029] The steering unit 214 includes a set of stabilizer pads 216 and a set of steering pads 218. The steering pads 218 may extend to contact the wellbore wall 220. The steering pads 218 may apply a force to the wellbore wall 220. The stabilizer pads 216 may contact the wellbore wall 220 as the steering pads 218 pushes against the wellbore wall 220. 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.

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SUBSTITUTE SHEET ( RULE 26) [0030] The steering system 212 shown includes a stiff three-point steering assembly. The stabilizer pads 216 engage the wellbore wall 220 at an upper contact point 222. The stabilizer pads 216 are located further downhole (e.g., closer to the bit, further from the collar of the wellbore 202), than the steering pads 218. The stabilizer pads 216 engage the wellbore wall 220 at a lower contact point 224. The lowest cutting element of the bit engages the wellbore wall 220 at a bit contact point 226. 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.

[0031] In the stiff three-point steering assembly shown, the dogleg severity (DLS) capability or curvature response may be expressed as:

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 last cutting structure 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 224 and the L2 distance 235 may be the distance from the lower contact point 224 and the upper contact point 222.

[0032] 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.

[0033] In accordance with at least one embodiment of the present disclosure, the LI distance 237 can be reduced by moving the bit contact point 226 closer to the steering pads 218. To move the bit contact point 226 closer to the steering pads 218, the bit 210 may include an uphole-most gauge cutting element 228 (or a plurality of uphole-most gauge cutting elements 228) that is located uphole of a connection 230 between the bit 210 and the steering unit 214.

[0034] The bit 210 may include a bit connection 234. In the embodiment shown, the bit connection 234 is a box connection. Put another way, the connection 230 may be a pin-down connection, with the steering unit 214 including a pin connection at the steering connection 236. While the embodiment shown illustrates a pin-down connection, it should be understood that embodiments of the present disclosure may be used in a pin-up connection (e.g., with the bit 210

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SUBSTITUTE SHEET ( RULE 26) including a pin connection and the steering unit 214 including a box connection), any other type of connection, and combinations thereof

[0035] In some embodiments, the bit 210 includes a skirt 232. The skirt 232 may be located uphole of the bit connection 234, In accordance with at least one embodiment of the present disclosure, the uphole-most gauge cutting element 228 may be located on the skirt 232. In this manner, the uphole-most gauge cutting element 228 may be located uphole of the bit connection 234. This may place the uphole-most gauge cutting element 228 closer to the steering pads 218. [0036] 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 this manner, by locating the uphole-most gauge cutting element 228 on the skirt 232 of the bit 210, the LI distance 237 may be reduced. This may increase the DLS and/or steering control of the steering system 212.

[0037] In the embodiment shown, the skirt 232 is integrally formed with the bit 210. However, it should be understood that the skirt 232 may be separately formed from the bit 210. For example, the skirt 232 may be formed as a gauge ring that is sandwiched between the bit 210 and the steering unit 214. In some examples, the skirt 232 may include a plurality of gauge rings.

[0038] In the embodiment shown, the uphole-most gauge cutting element 228 may have the same diameter (e.g., a gauge diameter) as a gauge diameter of the bit 210. In some embodiments, the uphole-most gauge cutting element 228 has a different gauge diameter. For example, the uphole-most gauge cutting element 228 may have a larger gauge diameter than the bit 210. In some examples, the uphole-most gauge cutting element 228 may have a smaller gauge diameter than the bit 210. Adjusting the gauge diameter of the uphole-most gauge cutting element 228 may help to adjust whether and/or how much of the wellbore wall 220 is removed by the uphole-most gauge cutting element 228.

[0039] In some embodiments, the uphole-most gauge cutting element 228 is a cutting element. For example, the uphole-most gauge cutting element 228 may be a cutting element having any shape, such as planar, axe, wedge, conical, any other shape, and combinations thereof. In some embodiments, the uphole-most gauge cutting element 228 has a shape that is configured to cut the formation. In this manner, when the uphole-most gauge cutting element 228 engages the wellbore wall 220, the uphole-most gauge cutting element 228 may widen the diameter of the wellbore 202

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SUBSTITUTE SHEET ( RULE 26) at the inner surface of the dogleg. In some embodiments, the uphole-most gauge cutting element 228 includes a wear element. For example, the uphole-most gauge cutting element 228 may not be configured to cut or otherwise remove the formation. The uphole-most gauge cutting element 228 may include a wear element that is configured to engage the wellbore wall 220 without substantially cutting the wellbore wall 220.

[0040] In some embodiments, the uphole-most gauge cutting element 228 is located an extending distance 238 from the last hole-defining cutting element. The last hole-defining cutting element may be the uphole-most cutting element on the bit 210 that actively widens the wellbore. By increasing the extending distance 238, the effective length of the bit 210 is increased. This may help to decrease the LI distance 237, thereby increasing the DLS of the steering system 212.

[0041] In some embodiments, the bit 210 includes an axial gap 240 between the last holedefining cutting element and the uphole-most gauge cutting element 228. In some embodiments, the axial gap 240 includes no cutting elements that are present at or greater than the bit gauge diameter and/or contain no passive load bearing surface that is present at or greater than the bit gauge diameter. In some embodiments, the axial gap 240 includes the breaker slots used to tighten and remove the bit 210 from the steering unit 214. Put another way, the uphole-most gauge cutting element 228 may be located uphole of the breaker slots.

[0042] FIG. 3-1 is a schematic representation of an exploded view of a steering system 312, according to at least one embodiment of the present disclosure. The steering system 312 shown includes a steering unit 314 having a body 342. The body 342 may include one or more actuators or steering pads 318. The steering pads 318 may extend to a kicker 344, which may help to prevent the steering pads 318 from overextending.

[0043] The steering system 312 includes a bit 310. The bit 310 may include a body 346 with one or more blades 348 extending therefrom. A plurality of cutting elements 350 may be secured to the blades 348. The cutting elements 350 may be arranged and configured to cut the formation to advance the wellbore.

[0044] The bit 310 shown includes one or more uphole-most gauge cutting elements 328. The uphole-most gauge cutting elements 328 may be located uphole of the last hole-defining cutting element of the cutting elements 350 on the bit 310. The uphole-most gauge cutting elements 328 may be configured to contact the formation uphole of the last hole-defining cutting element, thereby increasing the DLS. In the embodiment shown, the uphole-most gauge cutting elements

9

SUBSTITUTE SHEET ( RULE 26) 328 may be located on or at any portion of the bit 310. For example, the uphole-most gauge cutting elements 328 may be located on one of the blades 348. In at least one embodiment, locating the uphole-most gauge cutting elements 328 on the bit 310 allows the uphole-most gauge cutting elements 328 to be aligned and/or otherwise located at a specific location with respect to the other cutting elements 350. In at least one embodiment, the location of the uphole-most gauge cutting elements 328 is determined based on and/or incorporated into the cutting profile of the bit 310. [0045] The bit 310 includes a bit connection 334. The bit connection 334 may be complementary to a steering connection 336 on the steering unit 314. The bit connection 334 and the steering connection 336 may connect the bit 310 to the steering unit 314. In the embodiment shown, the connection between the steering unit 314 and the bit 310 is a pin-down connection. Put another way, the bit connection 334 may include a box connection and the steering connection 336 may include a pin connection, where the pin connection on the steering connection 336 is oriented downhole.

[0046] In the embodiment shown, the bit 310 includes a skirt 332. The uphole-most gauge cutting elements 328 may be secured to the bit 310 at the skirt 332. In accordance with at least one embodiment of the present disclosure, the skirt 332 may extend uphole of the bit connection 334. This may locate the uphole-most gauge cutting elements 328 uphole of the bit connection 334. In this manner, when the bit 310 is secured to the steering unit 314, the uphole-most gauge cutting elements 328 may be located close to, adjacent to, or proximate to the steering pads 318, thereby reducing the LI distance 337 (as shown in FIG. 3-2).

[0047] As may be seen, the skirt 332 may include a breaker slot 360. The breaker slot 360 may be a portion of the bit 310 that allows for a torque to be applied to the bit 310 during connection and disconnection of the bit 310 from the steering unit 314. The uphole-most gauge cutting elements 328 may be located uphole of the breaker slot 360. In this manner, the uphole-most gauge cutting elements 328 may be located adjacent to the steering pads 318, thereby decreasing the LI distance 337 and increasing the DLS of the steering system 312.

[0048] The body 342 of the steering unit 314 may include a shank 352. The shank 352 may be located downhole of a steering shoulder 354, or between the steering shoulder 354 and the steering connection 336. The shank 352 may have a smaller diameter than the body 342 of the steering unit 314. The shank 352 may be sized and/or complementary to fit in a skirt interior 356.

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SUBSTITUTE SHEET ( RULE 26) [0049] To assemble the steering system 312, the bit 310 may be secured to the steering unit 314. To connect the bit 310 to the steering unit 314, the bit 310 may be inserted onto the body 342 of the steering unit 314. This may cause the steering connection 336 to be inserted into the skirt interior 356 and into the bit connection 334. This may cause the shank 352 to be inserted into the skirt interior 356. The bit 310 may be rotated to cause the bit connection 334 to connect to the steering connection 336. As the bit 310 is secured to the steering unit 314, a bit shoulder 358 of the bit 310 may contact the steering shoulder 354 of the body 342.

[0050] In accordance with at least one embodiment of the present disclosure, because the uphole-most gauge cutting elements 328 are located on the skirt 332, sliding the skirt 332 over the shank 352 may place the uphole-most gauge cutting elements 328 close to the steering pads 318, thereby decreasing the LI distance 337. In the embodiments, the uphole-most gauge cutting elements 328 may be located at the uphole-most part of the skirt 332. For example, the uphole- most gauge cutting elements 328 may be located at the bit shoulder 358 of the skirt 332. In this manner, the uphole-most gauge cutting elements 328 may be located as close as possible to the steering pads 318. In this manner, the LI distance 337 may be reduced, thereby increasing the DLS of the steering system 312. In FIG. 3-2, the bit 310 has been connected to the steering unit 314. As may be seen, the uphole-most gauge cutting elements 328, located on the skirt 332, may be located adjacent to the steering pads 318. This may reduce the LI distance 337, thereby increasing the DLS.

[0051] FIG. 4 is a schematic representation of an exploded view of a steering system 412, according to at least one embodiment of the present disclosure. The steering system 412 shown includes a steering unit 414 having a body 442. The body 442 may include one or more actuators or steering pads 418. The steering pads 418 may extend to a kicker 444, which may help to prevent the steering pads 418 from overextending.

[0052] The steering system 412 includes a bit 410. The bit 410 may include a body 446 with one or more blades 448 extending therefrom. A plurality of cutting elements 450 may be secured to the blades 448. The cutting elements 450 may be arranged and configured to cut the formation to advance the wellbore.

[0053] The bit 410 includes a bit connection 434. The bit connection 434 may be complementary to a steering connection 436 on the steering unit 414. The bit connection 434 and the steering connection 436 may connect the bit 410 to the steering unit 414. In the embodiment

11

SUBSTITUTE SHEET ( RULE 26) shown, the connection between the steering unit 414 and the bit 410 is a pin-down connection. Put another way, the bit connection 434 may include a box connection and the steering connection 436 may include a pin connection, where the pin connection on the steering connection 436 is oriented downhole.

[0054] The body 442 of the steering unit 414 may include a shank 452. The shank 452 may be located downhole of a steering shoulder 454, or between the steering shoulder 454 and the steering connection 436. The shank 452 may have a smaller diameter than the body 442 of the steering unit 414. The shank 452 may be sized and/or complementary to fit in a skirt interior 456.

[0055] The steering unit 414 shown includes a gauge ring 462. One or more uphole-most gauge cutting elements 428 may be located on the gauge ring 462. During assembly of the steering system 412, the gauge ring 462 may be located between the bit 410 and the steering unit 414. For example, the gauge ring 462 may be sandwiched between the bit 410 and the steering unit 414 such that the gauge ring 462 is in contact with both the bit 410 and the body 442 of the steering unit 414. In some embodiments, the ring shoulder 464 contacts the steering shoulder 454 of the body 442 of the steering unit 414. The gauge ring 462 may be compressed between the bit 410 and the body 442 of the steering unit 414.

[0056] Placing the uphole-most gauge cutting elements 428 on the gauge ring 462 may place the one or more uphole-most gauge cutting elements 428 close to or adjacent to the steering pads 418. In at least one embodiment, placing one or more uphole-most gauge cutting elements close or adjacent to the steering pads helps to reduce the LI distance (e.g., the LI distance 237 shown in FIG. 2), thereby increasing the DLS.

[0057] In some embodiments, a gauge ring 462 allows the steering system 412 to be retrofitted to place the one or more uphole-most gauge cutting elements 428 closer to the steering pads 418. In some embodiments, a gauge ring 462 allows the number, orientation, size, pattern, any other feature, and combinations thereof, of the one or more uphole-most gauge cutting elements 428 to be adjusted. In this manner, the gauge ring 462, in at least one embodiment, is modular; various different gauge rings 462 may be designed and/or selected based on the various drilling and/or geologic conditions.

[0058] In some embodiments, the gauge ring 462 is rotationally keyed to the bit 410. For example, the gauge ring 462 may include a ring keying feature and the body 446 and/or blades 448 of the bit 410 may include a bit keying feature, the ring keying feature and the bit keying feature

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SUBSTITUTE SHEET ( RULE 26) being complementary keying features. The complementary keying features may rotationally fix the gauge ring 462 to the bit 410. This may allow the uphole-most gauge cutting elements 428 to be rotationally aligned or otherwise oriented based on the cutting elements 450 of the bit 410. This allows the uphole-most gauge cutting elements 428, in at least one embodiment, to be included and/or designed as part of the cutting profile of the bit 410.

[0059] In some embodiments, the gauge ring 462 is rotationally keyed to the body 442 of the steering unit 414. For example, the gauge ring 462 may include ring keying features and the body 442 of the steering unit 414 may include steering keying features, the ring keying features and the steering keying features being complementary keying features. The complementary keying features may rotationally fix the gauge ring 462 to the body 442 of the steering unit 414. This allows the uphole-most gauge cutting elements 428, in at least one embodiment, to be rotationally aligned or otherwise oriented based on one or more features of the steering unit 414. In at least one embodiment, keying the gauge ring 462 to the body 442 allows the uphole-most gauge cutting elements 428 to be oriented with the steering pads 418 and/or the kicker 444.

[0060] FIG. 5 is a schematic representation of an exploded view of a steering system 512, according to at least one embodiment of the present disclosure. The steering system 512 shown includes a steering unit 514 having a body 542. The body 542 may include one or more actuators or steering pads 518. The steering pads 518 may extend to a kicker 544, which may help to prevent the steering pads 518 from overextending.

[0061] The steering system 512 includes a bit 510. The bit 510 may include a body 546 with one or more blades 548 extending therefrom. A plurality of cutting elements 550 may be secured to the blades 548. The cutting elements 550 may be arranged and configured to cut the formation to advance the wellbore.

[0062] The bit 510 includes a bit connection 534. The bit connection 534 may be complementary to a steering connection 536 on the steering unit 514. The bit connection 534 and the steering connection 536 may connect the bit 510 to the steering unit 514. In the embodiment shown, the connection between the steering unit 514 and the bit 510 is a pin-up connection. Put another way, the bit connection 534 may include a pin connection and the steering connection 536 may include a box connection, where the pin connection on the bit connection 534 is oriented uphole.

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SUBSTITUTE SHEET ( RULE 26) [0063] The bit 510 shown includes a skirt 532. The skirt 532 may extend past the bit connection 534. This may form an annular space 566 between the pin connection of the bit connection 534 and the inner surface of the skirt 532. The skirt 532 may extend over a shank 552 of the body 542 of the steering unit 514.

[0064] The bit 510 may include one or more uphole-most gauge cutting elements 528. The uphole-most gauge cutting elements 528 may be located on and/or connected to the skirt 532 of the bit 510. This may place the uphole-most gauge cutting elements adjacent to and/or proximate to the steering pads 518.

[0065] FIG. 6 is a schematic representation of an exploded view of a steering system 612, according to at least one embodiment of the present disclosure. The steering system 612 shown includes a steering unit 614 having a body 642. The body 642 may include one or more actuators or steering pads 618. The steering pads 618 may extend to a kicker 644, which may help to prevent the steering pads 618 from overextending.

[0066] The steering system 612 includes a bit 610. The bit 610 may include a body 646 with one or more blades 648 extending therefrom. A plurality of cutting elements 650 may be secured to the blades 648. The cutting elements 650 may be arranged and configured to cut the formation to advance the wellbore.

[0067] The bit 610 includes a bit connection 634. The bit connection 634 may be complementary to a steering connection 636 on the steering unit 614. The bit connection 634 and the steering connection 636 may connect the bit 610 to the steering unit 614. In the embodiment shown, the connection between the steering unit 614 and the bit 610 is a pin-up connection. Put another way, the bit connection 634 may include a pin connection and the steering connection 636 may include a box connection, where the pin connection on the bit connection 634 is oriented uphole.

[0068] The steering unit 614 shown includes a gauge ring 662. One or more uphole-most gauge cutting elements 628 may be located on the gauge ring 662. During assembly of the steering system 612, the gauge ring 662 may be located between the bit 610 and the steering unit 614. For example, the gauge ring 662 may be sandwiched between the bit 610 and the steering unit 614 such that the gauge ring 662 is in contact with both the bit 610 and the body 642 of the steering unit 614.

[0069] In some embodiments, the gauge ring 662 at least partially overlaps the bit connection 634. The gauge ring 662 may form an annular space between the bit connection 634 and the outer

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SUBSTITUTE SHEET ( RULE 26) body of the gauge ring 662. The gauge ring 662 may extend over a shank 652 of the body 642 of the steering unit 614. In this manner, the one or more uphole-most gauge cutting elements 628 may be located proximate to and/or adjacent to the steering pads 618. This may help to reduce the LI distance, thereby increasing the DLS of the steering system 612.

[0070] FIG. 7-1 through FIG. 7-3 are representations of bits (collectively 710), according to at least one embodiment of the present disclosure. The bits 710 include a body 746 and one or more blades 748. The bits 710 include an uphole-most cutting element (collectively 728). The uphole- most cutting element 728 may be the cutting element on the bits 710 that is located furthest uphole on the bits 710. The bits 710 have a bit gauge diameter 768. The bit gauge diameter 768 may be the diameter of the bit 710. For example, the bit gauge diameter 768 may be the diameter that the bit 710 drills during drilling operation. The uphole-most cutting elements 728 may have an uphole- most gauge diameter (collectively 770). The uphole-most gauge diameter 770 may be the diameter at which the uphole-most cutting element 728 engage the wellbore wall adjacent to the steering pads.

[0071] In accordance with at least one embodiment of the present disclosure, the uphole-most gauge diameter 770 may be variable. For example, the uphole-most gauge diameter 770 may be variable based on variable sized gauge rings. In some examples, the uphole-most gauge diameter 770 may be variable based on a variable sized skirt. In some examples, the uphole-most gauge diameter 770 may be variable based on a variable exposure of the uphole-most cutting element 728. In at least one embodiment, varying the uphole-most gauge diameter 770 helps to vary the amount of the increase in DLS. In at least one embodiment, varying the uphole-most gauge diameter 770 helps to vary the amount that the wellbore is widened when drilling a dogleg.

[0072] In FIG. 7-1, the first bit 710-1 has first uphole-most cutting elements 728-1 that have a first uphole-most gauge diameter 770-1. In the embodiment shown in FIG. 7-1, the first uphole- most gauge diameter 770-1 may be the same or approximately the same as the bit gauge diameter 768. This may help to extend the length of the first bit 710-1 to the first uphole-most cutting elements 728-1, thereby decreasing the LI distance.

[0073] In FIG. 7-2, the second bit 710-2 has second uphole-most cutting elements 728-2 that have a second uphole-most gauge diameter 770-2. In the embodiment shown in FIG. 7-2, the second uphole-most gauge diameter 770-2 may be less than the bit gauge diameter 768. This may

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SUBSTITUTE SHEET ( RULE 26) help to reduce the amount of material that the elements 728-2 remove from the inner diameter of the dogleg of the wellbore.

[0074] In FIG. 7-3, the third bit 710-3 has third uphole-most cutting elements 728-3 that have a third uphole-most gauge diameter 770-3. In the embodiment shown in FIG. 7-3, the third uphole- most gauge diameter 770-3 may be greater than the bit gauge diameter 768. This may help to further increase the DLS when the third bit 710-3 is connected to a steering unit providing room on the inner wall of the dogleg for the steering unit to move while drilling a dogleg.

[0075] FIG. 8 is a flowchart of a method 872 for manufacturing a steering system, according to at least one embodiment of the present disclosure. The method 872 may include providing a bit having an uphole-most cutting element that extends uphole of a bit connection at 874. The uphole- most cutting element may be a gauge cutting element. The bit may be secured to a steering unit such that the uphole-most cutting element on the bit extends uphole of the connection between the bit connection and the steering connection on the steering unit at 876. This may place the uphole- most cutting element closer to the steering pads of the steering unit, thereby shortening the LI distance and increasing the dogleg severity.

[0076] The embodiments of the steering unit have been primarily described with reference to wellbore drilling operations; the steering units described herein may be used in applications other than the drilling of a wellbore. In other embodiments, steering units 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, steering units 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.

[0077] One or more specific embodiments of the present disclosure are described herein. 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 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 embodimentspecific 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

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SUBSTITUTE SHEET ( RULE 26) consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0078] 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.

[0079] 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.

[0080] 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

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SUBSTITUTE SHEET ( RULE 26) 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.

[0081] 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.

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SUBSTITUTE SHEET ( RULE 26)

Claims

CLAIMS What is claimed is:

1. A drilling system, comprising: a steering unit having a plurality of steering pads and a steering connection; and a bit having a gauge diameter and a bit connection, the bit connecting to the steering unit at the bit connection and the steering connection, the bit including a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.

2. The drilling system of claim 1, wherein the bit connection includes a box connection and the steering connection includes a pin connection.

3. The drilling system of claim 1 , wherein the bit includes a skirt, the skirt extending past the bit connection, the plurality of gauge cutting elements being located on the skirt.

4. The drilling system of claim 3, wherein the steering unit includes a shank, the skirt extending over the shank when the bit is connected to the steering unit.

5. The drilling system of claim 3, wherein the plurality of gauge cutting elements are located at a base of the skirt.

6. The drilling system of claim 3, wherein the skirt is integrally formed with the bit.

7. The drilling system of claim 3, wherein the skirt includes a breaker slot.

8. The drilling system of claim 1, wherein the bit includes a blade, and wherein the plurality of gauge cutting elements are aligned with the blade.

9. The drilling system of claim 1, wherein a diameter of the plurality of gauge cutting elements is the same as a gauge diameter of the bit.

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SUBSTITUTE SHEET ( RULE 26)

10. The drilling system of claim 1, wherein the plurality of gauge cutting elements include a wear element.

11. The drilling system of claim 10, wherein the bit connection includes a pin connection.

12. A drilling system, comprising: a steering unit having a plurality of steering pads and a steering connection; a bit having a gauge diameter and a bit connection, the bit connecting to the steering unit at the bit connection and the steering connection, and a gauge ring located between the bit and the plurality of steering pads, the gauge ring including a plurality of gauge cutting elements located between the bit connection and the plurality of steering pads.

13. The drilling system of claim 12, a diameter of the plurality of gauge cutting elements being the same as the gauge diameter of the bit.

14. The drilling system of claim 12, wherein the gauge ring includes a ring keying feature and the steering unit includes a steering keying feature complementary to the ring keying feature such that the gauge ring is rotationally keyed to the steering unit.

15. The drilling system of claim 12, wherein the gauge ring includes a ring keying feature and the bit includes a bit keying feature complementary to the ring keying feature such that the gauge ring is rotationally keyed to the bit.

16. The drilling system of claim 12, wherein the gauge ring includes a plurality of gauge rings.

17. A bit, comprising: a body; a plurality of blades extending from the body, the plurality of blades having a gauge diameter; a bit connection to connect the bit to a steering unit; and

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SUBSTITUTE SHEET ( RULE 26) a skirt, the skirt including an uphole-most gauge cutting element located uphole of the bit connection.

18. The bit of claim 17, wherein the bit connection includes a box connection complementary to pin connection of the steering unit.

19. The bit of claim 17, wherein the uphole-most gauge cutting element has an uphole-most gauge diameter that is the same as the gauge diameter.

20. The bit of claim 17, wherein the skirt is integrally formed with the body.

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SUBSTITUTE SHEET ( RULE 26)