Downhole directional drilling tools

Abstract

A downhole tool has a directional pad that contacts a wellbore wall at a pad contact location and a drill bit having at least one active cutting element that contacts the wellbore wall at a cutting element contact location. The contact distance between the pad contact location and the cutting element contact location is 3 inches (7.6 cm) or less.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of and priority to U.S. Patent Application No. 62 / 805,977, filed on February 15, 2019, the entire contents of which are incorporated herein by reference. Background Art

[0003] Wellbores may be drilled to surface locations or to the seafloor for a variety of exploration or production purposes. For example, wellbores may be drilled to access fluids stored in underground formations, such as liquid and gaseous hydrocarbons, and to produce fluids from the formations. Wellbores used to produce or produce fluids may be lined with casing around the wellbore walls. A variety of drilling methods may be used, depending in part on the characteristics of the formation through which the wellbore is drilled.

[0004] Drilling can be done by a drilling system that bores downward from the ground through earthy material. Some wellbores are drilled vertically downward, and some wellbores have one or more curves in the wellbore to follow ideal geological formations, avoid problematic geological formations, or a combination of both. Summary of the invention

[0005] In some aspects, a downhole tool includes a directional pad configured to contact a wellbore wall at a pad contact location, and a drill bit having at least one active cutting element. The at least one active cutting element contacts the wellbore wall at the cutting element contact location, and a contact distance between the pad contact location and the cutting element contact location is 3 inches (7.6 cm) or less.

[0006] According to some aspects, a downhole tool includes a directional pad configured to contact a borehole wall at a pad contact location and a drill bit having at least one active cutting element. The contact ratio between the drill bit diameter and the contact length between the pad contact location and the at least one active cutting element is greater than 3:1.

[0007] According to another aspect, a downhole tool includes an directional pad configured to contact a borehole wall at a pad contact position and a drill bit having at least one active cutting element. An directional pad angle between the contact position and the at least one active cutting element relative to a longitudinal axis is greater than 0° and less than or equal to 5°.

[0008] Additional aspects include a downhole tool having a directional pad configured to contact a wellbore wall at a pad contact position and a drill bit having a first active cutting element and a second active cutting element. The first active cutting element is located further uphole than any other cutting element, and the second active cutting element is located further uphole than any other cutting element other than the first active cutting element. The angle between the first active cutting element and the second active cutting element is greater than 0° and less than or equal to 5°.

[0009] This summary is provided to introduce a selection of concepts that are further described in the detailed description below. This summary is not intended to identify the key or essential features of the claimed subject matter, nor is it intended to be used as an auxiliary tool to limit the scope of the claimed subject matter. Instead, additional features and aspects of the embodiments of the present disclosure will be set forth in the subsequent description, and will be apparent in part from the description, or may be learned through the practice of such embodiments. The features and aspects of these embodiments may be realized and obtained through the instruments and combinations specifically pointed out in the appended claims. These and other features will become more apparent from the following description and the appended claims, or may be learned through the practice of such embodiments as set forth below. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] In order to describe the manner in which the above and other features of the present disclosure can be obtained, a more specific description will be given by reference to specific embodiments thereof shown in the accompanying drawings. For better understanding, the same elements are represented by the same reference numerals in the various drawings. Although some of the drawings may be schematic or exaggerated representations of the concepts, at least some of the drawings may be drawn to scale. It should be understood that the drawings depict some exemplary embodiments, and the embodiments will be described and explained with additional specificity and detail through the use of the drawings, in which:

[0011] Figure 1 is a schematic diagram of a drilling system according to at least one embodiment of the present disclosure;

[0012] FIG2 is a schematic diagram of a prior art directional drilling system;

[0013] Figure 3 is a schematic diagram of a directional drilling system according to at least one embodiment of the present disclosure;

[0014] Figure 4 is a cross-sectional view of a directional drilling system according to at least one embodiment of the present disclosure;

[0015] Figure 5 is another cross-sectional view of a directional drilling system according to at least one embodiment of the present disclosure;

[0016] Figure 6 is a partial side view of a drill bit according to at least one embodiment of the present disclosure;

[0017] Figure 7 is another partial side view of a drill bit according to at least one embodiment of the present disclosure;

[0018] Figure 8 is a side view of a drill bit according to at least one embodiment of the present disclosure;

[0019] Fig. 9is a schematic diagram of a composite cutting profile according to at least one embodiment of the present disclosure;

[0020] Fig.10 is another representation of a composite cutting profile according to at least one embodiment of the present disclosure;

[0021] Fig.11 is a side view of an assembly tool that can be used to connect a drive shaft to a drill bit according to at least one embodiment of the present disclosure;

[0022] Figure 12-1 is a perspective view of another assembly tool that can be used to connect a drive shaft to a drill bit according to at least one embodiment of the present disclosure; and

[0023] Figure 12-2 yes Figure 12-1 A perspective view of the assembly tool with the drill bit removed. DETAILED DESCRIPTION

[0024] The present disclosure generally relates to apparatus, systems, and methods for downhole directional drilling tools.

[0025] Figure 1 One example of a drilling system 100 for drilling into a formation 101 to form a wellbore 102 is shown. The drilling system 100 includes a drilling rig 103 for rotating a drilling tool assembly 104 extending downwardly into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottom hole assembly ("BHA") 106, and a drill bit 110, which is attached to the downhole end of the drill string 105.

[0026] The drill string 105 may include several joints of drill pipe 108 connected end to end by tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the drill string 105 may also include additional components, such as short joints, short joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid is pumped through nozzles, orifices or other orifices of selected sizes in the drill bit 110 for the purpose of cooling the drill bit 110 and the cutting structure thereon and lifting drill cuttings out of the wellbore 102 while drilling.

[0027] The BHA 106 may include a drill bit 110 or other components. The example BHA 106 may include additional or other components (e.g., coupled between the drill string 105 and the drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement while drilling (“MWD”) tools, logging while drilling (“LWD”) tools, downhole motors, underreamers, segment mills, hydraulic disconnects, jars, vibration or damping tools, other components, or combinations thereof.

[0028] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). The additional components included in the drilling system 100 may be considered part of the drilling tool assembly 104, the drill string 105, or the BHA 106, depending on their location in the drilling system 100.

[0029] The drill bit 110 in the BHA 106 can be any type of drill bit suitable for degrading downhole materials. For example, the drill bit 110 can be a drill bit suitable for drilling the formation 101. Example types of drill bits used to drill the formation are fixed cutters or scraper bits. Cuttings or other drill cuttings formed using a mill may be lifted to the surface or may fall downhole. The drill bit 110 may be guided by a directional drilling assembly 112.

[0030] FIG. 2 is a schematic diagram of a prior art directional drilling assembly 212 including a drill bit 210. The drill bit 210 may be connected to a directional drilling sub 214 having one or more selective directional pads 216 configured to contact a wall 218 of a wellbore 202. The directional pads may be expandable, such as when the directional drilling sub 214 is a rotary steerable system. When the directional pads 216 selectively expand and contact the wall 218, the drill bit 210 is subjected to greater forces at a drill bit contact position 224 on the opposite side of the wall 218, thereby forcing the wellbore 202 to deflect radially or dog leg. The drill bit 210 is stabilized by contact of the stabilizer 220 with the wall 218 at the stabilizer contact position, thereby promoting consistent radial deflection or dog leg severity (DLS). The closer the directional pads 216 are to the drill bit contact position 224, the greater the DLS. In the illustrated directional drilling assembly 212 (e.g., including a rotary steerable system), the internal structural mechanics of selectively extending the directional pad 216 limit the extent to which the directional pad 216 can be placed near the drill bit 210. As shown, the distance between the directional pad 216 and the drill bit contact location 224 is large. For example, as shown, the distance between the directional pad 216 and the drill bit contact location 224 is greater than 12 inches (30.5 centimeters).

[0031] Figure 331 is a schematic diagram of an embodiment of a directional drilling assembly 312. A drill bit 310 may be connected to a directional drilling sub 314 via a drill bit connector 328. A directional pad 316 may be connected to the downhole end of the directional drilling sub 314. The directional pad 316 may be located or contained in a directional pad housing 330 located on the directional drilling sub 314. In some embodiments, the directional pad 316 (and optionally the portion of the directional pad housing 330 that supports the directional pad 316) may be located at or toward the lower end of the directional drilling sub 314 and may extend past the directional pad housing 330 and / or the downhole end 332 of the directional drilling sub 314. In particular, a distance 334 referred to as an overhang is shown as the directional pad 316 (and / or the associated portion of the directional pad housing 330) extending beyond or overhanging the downhole end 332 of another portion of the directional pad housing 330.

[0032] like Figure 3 As shown, the portion where the downhole end 332 of the directional pad housing 330 is located can be directly opposite the directional pad 316; however, this is not restrictive. In the same or other embodiments, the downhole end 332 can be the downhole end of the directional pad housing 330 that supports a portion of the second pad 317. In some embodiments, the second pad 317 does not extend axially as far downhole as the directional pad 316. In the same or other embodiments, the second pad 317 can also extend radially from a portion of the directional pad housing 330. The radial extension of the second pad 317 can vary, and in some embodiments, the distance between the longitudinal axis of the directional pad housing 330 and the outer surface of the second pad 317 is less than the distance between the longitudinal axis of the directional pad housing 330 and the outer surface of the directional pad 316. In a further exemplary embodiment, the distance between the longitudinal axis of the directional pad housing 330 and the outer surface of the second pad 317 can be less than or equal to the cutting element radius at the final cutting element contact position 338.

[0033] In some embodiments, the second pad 317 is a separate component attached to the directional pad housing 330. In other embodiments, the second pad 317 is integrally formed with the directional pad housing 330 (see Figure 4 ). In addition, any number of second pads 317 can be used. For example, in at least some embodiments, the orientation pad housing 330 includes or is attached to one orientation pad 316 and two, three, four, or more second pads 317.

[0034] The directional pads 316 may engage or contact the wall 318 of the wellbore 302 at the pad contact location 336. The cutting elements 337 located on the drill bit 310 may engage the formation 301, degrade or cut the formation 301 to form the wellbore 302. Some of the cutting elements 337 are active cutting elements 337, meaning that they actively engage and remove the formation 301, or cut a path through the formation 301. At least one active cutting element 337 may be located at a location that defines a final active cutting element contact location 338. In some embodiments, the contact length 340 between the pad contact location 336 and the final cutting element contact location 338 may directly affect the DLS that can be achieved using the directional drilling assembly 312. In other words, a shorter contact length 340 may increase the DLS, and a longer contact length 340 may decrease the DLS.

[0035] In some embodiments, the drill bit 310 can rotate independently of the directional pad housing 330 or relative to the directional pad housing 330. In other words, the drill bit 310 can be driven by a downhole motor (not shown), such as a mud turbine or a Moineau pump. The directional pads 316 can maintain an absolute angular orientation (e.g., relative to gravity and / or a cardinal direction such as magnetic north). As the wellbore 302 advances, the directional pads 316 can slide along the wellbore wall 318, continuously pushing the drill bit 310 relative to the pad contact position 336. Thus, the directional drilling assembly 312 can form a bidirectional bend by sliding drilling. The direction of the bidirectional bend can be changed by rotating the directional pad housing 330. In addition, the size of the DLS can be adjusted by switching between drilling modes from sliding to rotating.

[0036] At least a portion of a downhole tool (e.g., a downhole motor drive shaft, not shown) extends from a downhole end 332 of the directional pad housing 330 to form a drill bit connection 328. The drill bit connection 328 can extend a connection length 342, thereby moving (e.g., extending) the directional pad housing 330, and potentially moving the directional pad 316, away from the drill bit 310. In some embodiments, an overhang 334 including a downhole end 332 that extends or protrudes beyond another portion of the directional pad housing 330 can allow the directional pad 316 to be positioned closer to the drill bit 310 without interfering with the drill bit connection 328. In this way, the contact length 340 can be reduced, thereby increasing the DLS.

[0037] Figure 4 is a cross-sectional view of an embodiment of a portion of a directional drilling assembly 412. In some embodiments, the directional drilling assembly 412 may be Figure 3 An enlarged view of a portion of directional drilling assembly 312 .

[0038] exist Figure 44, the drill bit 410 is connected to the downhole tool 444 at the drill bit connector 428. The directional pad 416 can be attached to the directional pad housing 430, and the directional pad 416 can contact the wall 418 of the wellbore 402 at one or more pad contact locations 436. In some embodiments, the directional pad 416 contacts the wall 418 at a single location, or at a point location, or along a single line. In other embodiments, the directional pad 416 can contact the wall 418 over an area of ​​the directional pad 416. In some embodiments, there is a significant contact area, such as half, most, or all of the outer surface area of ​​the directional pad 416. The pad contact location 436 can be the most downhole location where the directional pad 416 contacts the wall 418.

[0039] The drill bit 410 may include a plurality of cutting elements 437. Some of the cutting elements 437 may be active cutting elements 437. Active cutting elements 437 are cutting elements that actively degrade and remove a volume of the formation 401 when the drill bit 410 is rotated and weight on the drill bit is applied downhole. Thus, cutting elements located uphole of the cutting element at a greater or equal radial distance may not be considered active cutting elements 437, because the volume that may be removed by the cutting element may be removed to the location of the removed rock as the cutting element moves. Instead, such cutting elements may alternatively be used to protect gauge, stabilize the drill bit, or for backreaming, rather than for active cutting while advancing the drill bit 410.

[0040] The final active cutting element 437-1 may be the most uphole active cutting element 437. Thus, the final active cutting element 437-1 may be located further uphole than every other active cutting element 437 in the plurality of cutting elements 437. In some examples, the final active cutting element 437-1 may be the furthest uphole cutting element 437. In other examples, one or more non-active cutting elements 437 may be located uphole of the final active cutting element 437. For example, when the drill bit 410 is removed from the borehole, one or more cutting elements 437 may be used for post-reaming.

[0041] The final active cutting element 437-1 may engage the formation 401 at a final cutting element contact location 438 and remove a volume of rock from the formation 401. The final cutting element contact location 438 may be approximately at the center of the final active cutting element 437-1 (e.g., the longitudinal center of the cylindrical cutter), as measured longitudinally downward along the longitudinal axis 446 of the directional drilling assembly 412. Thus, the contact length 440 may be the distance between the pad contact location 436 and the final cutting element contact location 438. In the illustrated embodiment, the contact length 440 may be the distance between the most downhole location at which the directional pad 416 contacts the wall 418 and the center of the final active cutting element 437-1.

[0042] In some embodiments, the contact length 440 can be within a range having a lower limit, an upper limit, or both, including any of 0.25 inches (0.6 cm), 0.5 inches (1.3 cm), 0.75 inches (1.9 cm), 1.0 inches (2.5 cm), 1.25 inches (3.2 cm), 1.5 inches (3.8 cm), 1.75 inches (4.4 cm), 2.0 inches (5.1 cm), 2.25 inches (5.7 cm), 2.5 (6.4 cm), 2.75 inches (7.0 cm), 3.0 inches (7.6 cm), 4.0 inches (10.2 cm), 5.0 inches (12.7 cm), 6.0 inches (15.2 cm), 7.0 inches (17.8 cm), 8.0 inches (20.3 cm), or any value therebetween. For example, the contact length 440 can be greater than 0.25 inches (0.6 cm). In other examples, the contact length 440 can be less than 8.0 inches (2.3 centimeters). In other examples, the contact length 440 can be any value within a range between 0.25 inches (0.6 centimeters) and 8.0 inches (2.3 centimeters). In other examples, the contact length 440 can be less than 6.0 inches (15.2 centimeters). In other examples, the contact length 440 can be less than 3.0 inches (7.6 centimeters). In at least some embodiments, a contact length 440 of less than 3.0 inches (7.6 centimeters) may be critical to achieving a desired DLS increase for the directional drilling assembly 412.

[0043] In some embodiments, the maximum DLS achievable by the directional drilling assembly 412 can be within a range having a lower limit, an upper limit, or both a lower limit and an upper limit, including any of 1° per 100 feet (30 meters), 2° per 100 feet (30 meters), 3° per 100 feet (30 meters), 4° per 100 feet (30 meters), 5° per 100 feet (30 meters), 6° per 100 feet (30 meters), 7° per 100 feet (30 meters), 8° per 100 feet (30 meters), 9° per 100 feet (30 meters), 10° per 100 feet (30 meters), or any value therebetween. Some further analysis was performed to indicate that the maximum DLS achievable by the directional assembly 412 may even exceed 10° per 100 ft (30 m), and may even be as high as 20° per 100 ft (30 m), as high as 25° per 100 ft (30 m), as high as 40° per 100 ft (30 m), and even as high as 60° per 100 ft (30 m).

[0044] Thus, the maximum DLS may be greater than 1° per 100 ft (30 m), greater than 10° per 100 ft (30 m), greater than 20° per 100 ft (30 m), greater than less than 30° per 100 ft (30 m), or greater than 40° per 100 ft (30 m). In the same or other examples, the maximum DLS may be less than 60° per 100 ft (30 m), less than 50° per 100 ft (30 m), less than 40° per 100 ft (30 m), less than 25° per 100 ft (30 m), less than 20° per 100 ft (30 m), or less than 10° per 100 ft (30 m). In other examples, the maximum DLS may be any value within a range between 1° per 100 feet (30 meters) and 25° per 100 feet (30 meters), or any value within a range between 1° per 100 feet (30 meters) and 60° per 100 feet (30 meters).

[0045] and Figure 3 Similar to the directional drilling assembly 312 of directional drilling assembly 412, directional drilling assembly 412 may include an directional pad 416 extending a distance to have an overhang 434 relative to and beyond a downhole end 432 of a portion of a directional pad housing 430. Downhole end 432 is shown as a downhole end of a portion of a directional pad housing 430 that is aligned with and supports a portion of a second pad 417. Second pad 417 may be opposite directional pad 416 (i.e., angularly offset by 180° in the illustrated embodiment); however, in other embodiments, second pad 417 may be offset from directional pad 416 by less than 180° (e.g., 90° or 120°).

[0046] In some embodiments, the overhang distance 448 between the downhole end of the directional pad 416 and the downhole end 432 of the other portion of the directional pad housing 430 can be equal to or less than the distance 442 between the downhole end 432 and the uphole end of the drill bit 410. For example, the overhang 434 can extend across the entire shank of the drill bit connector 428. When manufactured, the shank of the drill bit connector 428 can remain outside the drill bit 410 when it is buckled onto the drill bit 410 as described herein. In these or other embodiments, the contact length 440 can be zero or close to zero (e.g., less than the diameter of the final active cutting element 437-1). In some embodiments, the contact length 440 can be a percentage of the connection distance 442. The connection distance 442 can be the distance between the downhole end 432 of the other portion of the directional pad housing 430 and the uphole end of the drill bit 410. In some embodiments, the connection length 442 corresponds to the length of the shank of the drill bit connector 428.

[0047] The overhang distance 448 can be related to the connection length 442 by the overhang percentage. In some embodiments, the overhang percentage (i.e., the percentage of the overhang distance 448 to the connection length 442) can be within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any one of 10%, 25%, 40%, 50%, 60%, 70%, 80%, 90%, 95%, 100%, or any value therebetween. For example, the overhang percentage may be greater than 10%. In other examples, the overhang percentage may be less than 100%. In other examples, the overhang percentage may be any value within a range between 10% and 100%.

[0048] The drill bit 410 has a drill bit diameter, which may also be referred to as a gauge diameter. The drill bit diameter is Figure 4 In some embodiments, the drill bit diameter can be any diameter used in drilling a wellbore, including drill bit diameters between 4 inches (10.2 centimeters) and 24 inches (61.0 centimeters). In some embodiments, the drill bit diameter is between 6 inches (15.2 centimeters) and 13 inches (33.0 centimeters) or between 8 inches (20.3 centimeters) and 9 inches (22.9 centimeters). The contact ratio can be defined as the ratio of the drill bit diameter to the contact length 440. For example, the contact ratio can be greater than 3:1. In other examples, the contact ratio can be 4:1. In other examples, the contact ratio can be between 20:1 and 2:1. For example, the contact ratio can be 33:2, 10:1, 9:1, 17:2, 8:1, 35:6, 5:1, 9:2; 8:3, or any other combination of drill bit diameter and contact length 440. In some cases, a higher contact ratio can increase the maximum DLS of the directional drilling assembly 412.

[0049] Figure 4The directional pad 416 has a pad radius 452 measured from the longitudinal axis 446 of the directional drilling assembly 412. In some embodiments, the pad radius 452 is equal to or greater than the drill bit radius 450. For example, the pad radius 452 can be equal to the drill bit radius 450. In other embodiments, the pad radius 452 can be greater than the drill bit radius 450. For example, the drill bit radius 450 can be the final active cutting element radius, and the pad radius 452 can be greater than the final active cutting element radius. In some embodiments, the pad radius 452 is between 100% and 150%, between 100% and 120%, between 101% and 115%, or between 101% and 110% of the drill bit radius 450. Increasing the pad radius can increase the force applied to the wall 418 of the wellbore 402 during use, and the greater force applied to the wall 418 can increase the DLS of the directional drilling assembly 412. In some embodiments, the directional pad 416 can be fixed radially relative to the longitudinal axis 446. For example, directional pad 416 may be a fixed pad that does not extend, expand, or otherwise actuate such that pad radius 452 remains constant. In the same or other embodiments, second pad 417 may also be a fixed pad rather than an extendable or actuable pad.

[0050] In some embodiments, the drill bit 410 is rotated relative to the directional pad housing 430 by a downhole tool 444. For example, the downhole tool 444 may include a drive shaft, such as a drive shaft from a downhole motor, such as a turbine or a positive displacement motor (e.g., a Moineau pump). The directional pad housing 430 can maintain a desired rotational orientation during drilling, including an orientation relative to gravity and / or an orientation relative to magnetic north or true north. For example, the directional pad housing 430 can be used for sliding drilling. In some embodiments, the directional pad housing 430 and the directional pad 416 can be rotationally fixed relative to the longitudinal axis 446. In other embodiments, the directional pad housing 430 can rotate, thereby changing the bidirectional bending of the directional drilling assembly 412. In some embodiments, the directional pad 416 can be a single directional pad 416. In other words, the directional pad housing 430 can have a single (e.g., only one) directional pad 416. Wherein the directional pad housing 430 has one or more directional pads 416, the directional pad housing 430 may include one or more other or second pads 417 with different configurations. The second pad 417 may not contribute substantially to the directional tendency of the directional pad housing 430. For example, the second pad 417 may have a radial extension (and optionally a reduced axial extension) relative to the directional pad 416 so that the second pad 417 may act more like a stabilizer when the directional pad 416 manipulates the directional drilling assembly 412.

[0051] In some embodiments, the drill bit 410 may include a box connector 454. The box connector 454 may be a hollow portion inside the drill bit 410 that is configured to connect to the downhole tool 444 at a pin connector that is coupled to the drill bit connector 428. In some examples, the box connector 454 and the drill bit connector 428 may be connected by threads 456, wherein the box connector 454 has a female end of the threaded connector 456 and the drill bit connector 428 has a male end of the threaded connector 456. The threaded connector may be a single shoulder connector, such as an API connector. In some embodiments, the threaded connector is a double shoulder connector or an advanced connector, such as a proprietary connector or a licensed connector. When the drill bit 410 is buckled onto the downhole tool 444, fluid flowing through the center hole 458 of the downhole tool 444 (e.g., in the drive shaft) may flow into the drill bit 410 and through one or more ports or nozzles in the body of the drill bit 410. The threaded connection 456 may allow sufficient space in the drill bit body to allow the ports or nozzles to provide a total flow sufficient to clean and cool the cutting structure of the drill bit 410 while drilling into the formation.

[0052] Figure 5 5 is another cross-sectional view of an embodiment of a directional drilling assembly 512. In some embodiments, a directional pad 516 may contact or engage a wall 518 of a wellbore 502 at a pad contact location 536. The drill bit 510 has a plurality of cutting elements 537, some of which are active cutting elements 537 that engage and remove the formation 501. The final active cutting element 537-1 may be the most uphole active cutting element 537. In other words, the final active cutting element 537-1 may be the furthest uphole active cutting element 537 of all the active cutting elements 537. Figure 5 As shown, in at least some embodiments, the final active cutting element 537-1 may not be the farthest uphole cutting element 537. One or more non-active cutting elements 537-2 may be located uphole of the final active cutting element 537-1. In some embodiments, one or more non-active cutting elements 537-2 may be located on the same blade as the final active cutting element 537-1. In other embodiments, one or more non-active cutting elements 537-2 may be located on a different blade than the final active cutting element 537-1. Therefore, as described above, the contact length 540 can be measured from the pad contact position 536 to the final active cutting element contact position 538.

[0053] Figure 66 is a schematic diagram of a portion of a directional drilling assembly 612 in accordance with at least one embodiment of the present disclosure. A directional pad 616 may be located above a well of a drill bit 610 that includes a plurality of cutting elements. In some embodiments, the plurality of cutting elements include an active gauge cutting element 638 and an active adjacent gauge cutting element 637. The directional pad 616 optionally has an outermost surface at a pad radius 652 measured relative to a longitudinal axis 646 of the drill bit 610, the pad radius 652 being greater than a gauge radius 660 at an outermost cutting tip of the active gauge cutting element 638. Thus, relative to the longitudinal axis 646, there may be a directional pad angle 662 between the pad contact position 636 and a final cutting element contact position of the active gauge cutting element 638. In some embodiments, the directional pad angle 662 can be within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any one of 0.0°, 0.1°, 0.5°, 1.0°, 1.5°, 2.0°, 2.5°, 3.0°, 3.5°, 4.0°, 4.5°, 5.0°, or any value therebetween. For example, the directional pad angle 662 tapers radially inward from the directional pad 616 to the active specification cutting element 638 at an angle greater than 0.0° and / or less than 5.0°. In other examples, the directional pad angle 662 can be any value within a range between 0.0° and 5.0° and / or between 0.0° and 5.0° and including 0.0° and 5.0°. In other embodiments, the angle can be greater than 5.0°. In some embodiments, a relatively high directional pad angle 662 can increase DLS compared to a relatively small directional pad angle 662 that can reduce DLS.

[0054] In some embodiments, the contact length 640 can be less than 3 inches (7.6 cm) and the directional pad angle 662 can be between 0.0° and 5.0° or between 0.5° and 3.5°. The combination of the contact length 640 and the directional pad angle 662 can further increase the DLS and / or improve control over the accuracy or precision of the DLS.

[0055] Figure 7 is a schematic diagram of a portion of a drill bit 710 according to at least one embodiment of the present disclosure. The drill bit 710 may include a plurality of cutting elements, including an active gauge cutting element 737-1 and an active adjacent gauge cutting element 737-2. Figure 7 , cutting elements 737-1, 737-2 illustrate cutting element positions in a composite cutting profile where all cutting elements are aligned in the same blade. Thus, multiple discrete cutting elements may be located at the same cutting element position and will be shown as a single cutting element. If multiple cutting elements are shown as a single cutting element in a cutting profile view, the cutting element positions are considered to have redundancy.

[0056] In some embodiments, active specification cutting element 737-1 is located further uphole than each other cutting element in the plurality of cutting elements (or further uphole than each other active cutting element in the plurality of cutting elements), including active adjacent specification cutting element 737-2. Active adjacent specification cutting element 737-2 is located further uphole than each other cutting element in the plurality of cutting elements except active specification cutting element 737-1. In some embodiments, active specification cutting element 737-1 and active adjacent specification cutting element 737-2 are located on the same blade of drill bit 710. In other embodiments, a blade may include one but not two active specification cutting element 737-1 and active adjacent specification cutting element 737-2.

[0057] The active gauge cutting element 737-1 has a first cutting element radius 764-1 relative to the longitudinal axis 746 of the drill bit 710. The active adjacent gauge cutting element 737-2 has a second cutting element radius 764-2 relative to the longitudinal axis 746. In some embodiments, the second cutting element radius 764-2 can be different from the first cutting element radius 764-1. In this way, a cutting element angle 766 is formed between the first cutting element 737-1 and the second cutting element 737-2. In some embodiments, the cutting element angle 766 can be within a range having a lower limit value, an upper limit value, or a lower limit value and an upper limit value, including any one of 0.05°, 0.1°, 0.5°, 1.0°, 1.5°, 2.0°, 2.5°, 3.0°, 3.5°, 4.0°, 4.5°, 5.0°, or any value therebetween. For example, the cutting element angle 766 can be greater than 0.05°. In other examples, the cutting element angle 766 can be less than 5.0°. In other examples, cutting element angle 766 may be any value within a range between 0.0° and 5.0°, between 0.1° and 4°, or between 1° and 3°.

[0058] In some embodiments, the second cutting element radius 764-2 may be less than the first cutting element radius 764-1. Thus, a negative cutting element angle 766 is formed. In other words, the drill bit specification may have a negative or inward taper in the downhole direction. When the directional pad (e.g., Figure 3 When the force on one side of the drill bit 710 is increased by the directional pad 316 of the drill bit 710, the negative cutting element angle 766 can enable the upper cutting element on the drill bit specification to more fully engage the formation (e.g., Figure 3 of stratum 301).

[0059] In some embodiments, the cutting element angle 766 can be aligned with the directional pad angle (e.g., Figure 6When the drill bit 710 is pushed by the directional pad, this can further achieve a uniform force distribution or cutting volume across multiple active cutting elements 737-1, 737-2. In other embodiments, the cutting element angle 766 can be greater or less than the directional pad angle.

[0060] Figure 8 868. The drill bit 810 may include a box connector 854 having a box length 868. In some embodiments, the box length 868 may be within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any one of 0.5 inches (1.3 cm), 0.75 inches (1.9 cm), 1.0 inches (2.5 cm), 1.25 inches (3.2 cm), 1.5 inches (3.8 cm), 1.75 inches (4.5 cm), 2.0 inches (5.1 cm), 2.25 inches (5.7 cm), 2.5 inches (6.4 cm), 2.75 inches (7.0 cm), 3.0 inches (7.6 cm), 5.0 inches (12.7 cm), or any value therebetween. For example, the box length 868 may be greater than 0.5 inches (1.3 cm). In other examples, the box length 868 may be less than 3.0 inches (7.6 cm). In other examples, the box length 868 can be any value within a range between 0.5 inches (1.3 centimeters) and 5.0 inches (12.6 centimeters) or between 1.0 inches (2.5 centimeters) and 3.0 inches (7.6 centimeters).

[0061] The drill bit 810 has a drill bit diameter 850. In some embodiments, the drill bit ratio can be a ratio of the drill bit diameter 850 to the box length 868. In some embodiments, the drill bit ratio can be between 2.5 and 5. For example, the drill bit ratio can be 8.5:2 (17:4), 8:2.5 (16:5), 8.75:2.75 (35:11), 8.5:2.75 (34:11), 3:1, or any other ratio of the drill bit diameter 850 to the box length 868. In some embodiments, the drill bit ratio can be greater than 3:1 or less than 4.5:1. In some embodiments, the box length 868 can depend at least in part on the drill bit diameter 850. A longer box length 868 can be more robust, and a larger drill bit diameter 850 can create more force on the box connector 854, thereby affecting the drill bit ratio. However, in some embodiments, the formation to be drilled through (e.g., Figure 3The type of formation 301) may affect the drill bit ratio. In some embodiments, at least one cutting element 837 (e.g., an active cutting element) of the drill bit 810 can axially overlap the box connector 854. In other words, both a portion of the body connector 854 and the at least one cutting element 837 can be positioned at an axial position along the longitudinal axis of the drill bit 810. Thus, a radius extending through the at least one cutting element 837 can extend through a portion of the box connector 854. Although the drill bit diameter 850 is shown relative to the drill bit body, in other embodiments, the drill bit diameter 850 is measured relative to the gauge diameter of the drill bit (i.e., based on the cutting tip of the cutting element 837).

[0062] Fig. 9 is a schematic diagram of a composite cutting profile 970 according to at least one embodiment of the present disclosure. The composite cutting profile 970 may be used with any drill bit described herein, particularly with respect to the reference Figures 3 to 8 The composite cutting profile 970 is on the drill bit ( Figure 3 Schematic diagram of the radial and axial cutting positions of each cutting element 937 of the drill bit 310 of FIG. Composite cutting profile 970 may include a final active cutting element 937-1 located in a specification area of ​​the drill bit. In some embodiments, the final active cutting element 937-1 may be located in a wellbore (e.g., Figure 3 The wellbore 302) is advancing in the downhole direction while passing through the formation (e.g., Figure 3 The final active cutting element 937-1 (or the cutting element 937-1 at the final active cutting element position) can be located farther uphole than the cutting element 937 at any other cutting element position on the cutting profile 970. Therefore, the final active cutting element(s) 937-1 can be located the farthest uphole of any cutting element 937. The final active cutting element 937-1 may not be a back-expanding cutting element, or may be configured to cut primarily as the drill bit is pulled out of the wellbore, or to simply maintain the gauge diameter cut by the cutting elements located farther downhole. Instead, the final active cutting element 937-1 may be configured to engage and cut a volume of formation while the wellbore is advancing.

[0063] In some embodiments, the drill bit may include a redundant or spare final active cutting element 937-1. In some embodiments, a drill bit having multiple blades may have multiple redundant cutting elements 937 located at the same radial and longitudinal positions on each of two or more different blades. The cutting elements 937 located at the same longitudinal position on different blades are redundant because they cut the same rotational path. In this way, placing multiple final active cutting elements 937-1 at the same radial and longitudinal positions on multiple blades provides redundancy, which can help improve the life of the final active cutting element 937-1, which may experience greater wear than other cutting elements because each of them can actively remove a reduced total volume.

[0064] As can be seen in the composite cutting profile 970, if a redundant or spare final active cutting element 937-1 is placed on each blade of the drill bit (and if the blades do not include a back cutter at other locations), no other cutting elements 937 can be at a location in the cutting profile 970 that overlaps with the location of the final active cutting element 937-1. Placing the redundant or spare final active cutting element 937-1 on some but less than every blade (e.g., half, one-third, one-quarter, every other blade, etc.) can allow for some overlap of active cutting elements with the location of the final active cutting element 937-1 on the cutting profile 970.

[0065] Fig.10 is a schematic diagram of a composite cutting profile 1070 according to at least one embodiment of the present disclosure. The composite cutting profile 1070 may be used with any drill bit described herein, particularly with respect to the reference Figures 3 to 8 The composite cutting profile 1070 is a composite cutting profile of each cutting element 1037 in the drill bit (e.g., Figure 3 Schematic diagram of a cutting path on a drill bit 310 of a composite cutting profile 1070. Composite cutting profile 1070 may include a first final active cutting element 1037-1 located in a gauge area of ​​the drill bit. First final active cutting element 1037-1 may be the most uphole active cutting element 1037 (or multiple first final active cutting elements 1037-1). Second final active cutting element 1037-2 actively engages and removes uphole formations further than any other cutting element 1037 other than first final active cutting element 1037-1.

[0066] The first final active cutting element 1037-1 and the second final active cutting element 1037-2 can overlap in the cutting profile 1070 and can therefore be located on different blades of the drill bit, or at the front and rear positions of a single blade. Thus, in at least some embodiments, the first final active cutting element 1037-1 and the second final active cutting element 1037-2 can have overlapping cutting paths. In this way, the cutting element angle (e.g., cutting element angle 766) can be fine-tuned along the length of the drill bit.

[0067] Fig.11 An example assembly tool 1171 is shown in accordance with at least one embodiment of the present disclosure. The motor, drive shaft, or offset unit connector 1128 may include a connecting shoulder 1172 and a plurality of keyed features 1174. In some embodiments, the connector 1128 may include eight flats spaced about the outer surface of the connector 1128 that collectively define a surface or connection feature that allows the assembly tool 1171 to hold the connector 1128 in place while a drill bit (e.g., drill bit 310, 410, 510, 610, 710, 810) can be rotated and secured thereto. In other embodiments, the assembly tool 1171 may be used to rotate the connector 1128 while another suitable device holds the drill bit in place.

[0068] Although the connector 1128 is shown as having eight flats defining key features 1174, the connector 1128 of the motor, drive shaft, or biasing unit can have any suitable features. In other embodiments, for example, the drill bit connector 1128 may include 1, 2, 3, 4, 5, 6, 7, or more than 8 flats or other key features 1174. In some embodiments, the key features may include protrusions, recesses, grooves, or holes that can be engaged by an assembly tool. Any suitable key features 1174 can be evenly spaced around the circumference of the connector 1128. In other embodiments, the key features 1174 can be unevenly spaced around the circumference of the connector 1128. For example, a larger groove or flat portion can correspond to a specific position on the assembly tool 1171, thereby aligning the connector 1128 with the assembly tool 1171.

[0069] Connector 1128 may be a connector that is coupled to a drill bit (e.g., Figure 4 The drill bit 410) of the box connector (e.g., Figure 4The connector 1128 may be attached to a downhole tool or a portion of a downhole tool, such as a drive shaft from a downhole motor, such as a turbine or a positive displacement motor (e.g., a Moineau pump). The downhole tool is optionally located within the interior of the directional pad housing 1130 and is rotatable relative to the directional pad housing 1130. The directional pad 1116 (and optionally the portion of the directional pad housing 1130 that supports the directional pad 1116) may extend beyond or overhang the downhole end of the directional pad housing 1130 (e.g., Figure 4 In some embodiments, the directional pad 1116 (and optionally the portion of the directional pad housing 1130 supporting the directional pad 1116) may extend over one or more of the plurality of keyed features 1174 and / or connecting shoulders 1172. The connector 1128 may include a threaded connector 1156 that may be connected to corresponding threads on the drill bit.

[0070] In order to securely fasten the drill bit to the connector 1128 via the threaded connector 1156, the drill bit is rotated relative to the drill bit connector 1128 (or vice versa). The assembly tool 1171 can be clamped onto the connector 1128 to limit or even prevent the drive shaft or other downhole tool from rotating when the drill bit is fastened to the connector 1128. In the illustrated embodiment, the assembly tool has an upper portion 1176 and a lower portion 1178. The upper portion 1176 and the lower portion 1178 can have a generally U-shaped radial cross-sectional area to clamp around the connector 1128. The upper portion 1176 can have an upper cutout 1180 that mates with a portion of one or more of the directional pad 1116, the directional pad housing 1130, or the keyed feature 1174. For example, the size of the upper cutout 1180 can be designed to pass over the connector 1128 and the directional pad 1116. When as Fig.11 When positioned as shown, the size and position of one or more portions of the cutout 1180 can limit the rotation of the directional pad 1116 or the directional pad housing 1130. The lower portion 1178 can have a lower cutout 1182 that is sized to connect to the connector 1128 at the plurality of keyed features 1174. The lower cutout 1182 can include one or more protrusions or engagement surfaces that are sized to mate, engage, or interlock with one or more of the plurality of keyed features 1174. In some embodiments, the lower cutout 1182 can include a second pad (e.g., Figure 4 A notch of the second pad 417).

[0071] The upper portion 1176 and the lower portion 1178 may be connected at an interface 1184. The interface 1184 may be used to clamp or otherwise secure the upper portion 1176 and the lower portion 1178 together (e.g., using a compressive force). The interface 1184 may be a bolted, threaded, or Fig.11The upper portion 1176 is aligned with or secured to any other connection or interface of the lower portion 1178 in the closed configuration shown. In other words, the assembly tool 1171 is clamped to the connector 1128 over the orientation pad 1116 when the interface 1184 is used to secure the upper portion 1176 to the lower portion 1178. In this manner, the connector 1128 is rotationally secured relative to the assembly tool 1171 by the one or more engagement surfaces of the lower portion 1178 mating or interlocking with the one or more keyed features 1174, and the surface of the upper cutout 1180 possibly limiting the rotation of the orientation pad 1116. Thus, the drill bit can be attached to and tightened to the connector 1128 using the assembly tool 1171 to provide a counter-rotational force.

[0072] Figure 12-1 and 12-2 Another example assembly tool 1271 is shown in accordance with at least one embodiment of the present disclosure. The motor, drive shaft or bias unit connector 1228 may include a plurality of keyed features 1274. The shoulder may also include, e.g. Fig.11 shown, but is optional and may not be included in some embodiments.

[0073] In some embodiments, connector 1228 includes two grooves spaced apart around an outer surface of connector 1228 that cooperatively define surfaces or connection features to allow assembly tool 1271 to hold connector 1228 in place while drill bit 1210 can be rotated and secured thereto, or rotated around drill bit 1210 while drill bit 1210 is held in place. Fig.11 Compared to the flat portion 1174 shown in FIG. 1 , the groove 1274 can be deeper and allow for a higher torque to be applied. In addition, in some embodiments, one or more flat portions or other surfaces can also be provided on the connector 1228 along with the groove 1274. For example, in Figure 12-2 , two grooves and four flats can be seen, but any suitable number of grooves, flats, etc. can be used. Thus, as described herein, any suitable keying feature 1274 can be used, and can include one keying feature, or multiple keying features spaced evenly or unevenly around the circumference of the connector 1228.

[0074] Connector 1228 may be a box connector (e.g., Figure 4 The connector 1228 may be attached to, or be part of, a downhole tool, such as a drive shaft from a downhole motor (e.g., a turbine or positive displacement motor). The downhole tool may optionally be located within the interior of the directional pad housing 1230 and may rotate relative to the directional pad housing 1230. The directional pad 1216 (and optionally the portion of the directional pad housing 1230 that supports the directional pad 1216) may extend beyond or overhang the downhole end of the directional pad housing 1230 (e.g., Figure 4 1274, and optionally the portion of the directional pad housing 1230 supporting the directional pad 1216, as described herein. In some embodiments, the directional pad 1216 (and optionally the portion of the directional pad housing 1230 supporting the directional pad 1216) extends at least partially over and is axially aligned with one or more of the plurality of keyed features 1274, flats, and / or connecting shoulders or pin connections of the connector 1228. The connector 1228 may include a threaded connector that may be connected to corresponding threads on the drill bit 1210.

[0075] In order to securely fasten the drill bit 1210 to the connector 1228 via the threaded connector, the drill bit 1210 is rotated relative to the drill bit connector 1228 (or vice versa). The assembly tool 1271 can be assembled around the connector 1228 and optionally assembled into the key feature 1274 to limit or even prevent the drive shaft or other downhole tool from rotating when the drill bit 1210 is fastened to the connector 1228. In the illustrated embodiment, the assembly tool has an outer portion 1276 and an inner portion 1278. The inner portion 1278 can be assembled within the outer portion 1276 and optionally fixed therein rotationally using one or more pins 1279 or other fasteners. In some embodiments, there can be a single part, rather than separate inner and outer portions 1276, 1278. As further shown, one or more openings 1280 can be formed in the outer portion 1276 and optionally in the inner portion 1278. These openings can be used as a clamp so that the assembly tool 1271 can be held in place. Of course, other mechanisms such as clamps, keyed features, etc. may be used to otherwise hold assembly tool 1271 in place.

[0076] The interior 1278 may have a cutout 1280 that mates with a portion of one or more of the keyed features (e.g., flats) of the directional pad 1216, the directional pad housing 1230, or even the connector 1228. For example, the cutout 1280 may be sized to pass over the connector 1228 and the directional pad 1216. Then, one or more portions of the cutout 1280 may be sized and positioned to fit over the connector 1228 and the directional pad 1216. Figure 12-2The position shown is to limit the rotation of the directional pad 1216 or the directional pad housing 1230. The interior 1278 can also have an engagement portion 1282 that is sized to connect to the connector 1228 at a plurality of slots 1274. The engagement portion 1282 can include one or more protrusions or engagement surfaces that are sized to cooperate, engage, fit within, or interlock with one or more of the plurality of key features 1274. In some embodiments, the interior 1278 can be symmetrical or otherwise include a second cutout 1280. The second cutout 1280 can provide an opening for a second pad that can be supported by the directional pad housing 1230. In this way, the connector 1228 is rotationally fixed relative to the assembly tool 1271 by one or more engagement features 1282 (e.g., tabs) of the interior 1278 cooperating or interlocking with one or more key features 1274, and possibly cooperating or interlocking with the surface of the cutout 1280 that limits the rotation of the directional pad 1216. Thus, the drill bit 1210 may be attached to the connector 1228 using the assembly tool 1271 and secured to the connector 1228 to provide a counter-rotational force.

[0077] Embodiments of downhole directional drilling tools have been described primarily with reference to wellbore drilling operations; furthermore, the downhole directional drilling tools described herein may be used in applications other than drilling wellbores. In other embodiments, downhole directional drilling tools according to the present disclosure may be used outside of a wellbore or other downhole environment for the exploration or production of natural resources. For example, the downhole directional drilling tools of the present disclosure may be used in a borehole for the placement of a utility line. Therefore, the terms "wellbore," "borehole," and the like should not be construed to limit the tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0078] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the currently disclosed technology. In addition, in order to provide a concise description of these embodiments, all features of the actual embodiments may not be described in the specification. It should be understood that in the development of any such actual implementation, as in any engineering or design project, many implementation-specific decisions will be made to achieve the developer's specific goals, such as complying with system-related and business-related constraints, which may vary from embodiment to embodiment. In addition, it should be understood that such development work may be complex and time-consuming, but for ordinary technicians who benefit from this disclosure, it is still a routine task of design, production and manufacturing.

[0079] The articles "a", "an", and "the" are intended to indicate the presence of one or more of the preceding described elements. 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 described features. For example, to simplify the discussion herein, some features are described with respect to a particular embodiment. However, any non-mutually exclusive features may be combined or interchanged. For example, Figure 3-5 The features of are interchangeable. In addition, any other elements described with respect to an embodiment herein can be combined with any elements of any other embodiment described herein. For example, Figure 6 , 7 The cutting profile of any one of 9 and 10 can be obtained by Figure 3-5 or any drill bit limit of 8. Similarly, Figure 8 The drill bits can be used for Figure 3-5 Any downhole tool.

[0080] As will be understood by one of ordinary skill in the art, the numbers, percentages, ratios, or other values ​​described herein are intended to include the value, and other values ​​that are "about" or "approximately" the value are included in the embodiments of the present disclosure. Therefore, the values ​​should be interpreted broadly enough to include values ​​that are at least close enough to the value to perform the desired function or achieve the desired result. The values ​​include at least the variations expected in suitable manufacturing or production processes, and may include values ​​within 5%, within 1%, within 0.1%, or within 0.01% of the value.

[0081] In view of the present disclosure, those of ordinary skill in the art should recognize that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and modifications may be made to the disclosed embodiments without departing from the spirit and scope of the present disclosure. Equivalent structures, including functional "means plus function" statements, are intended to cover structures described herein that perform the functions described, including structural equivalents that operate in the same manner and equivalent structures that provide the same functions. It is the express intent of the applicant not to invoke means plus function or other functional claims for any claim, except for claims in which the term "means for..." appears together with the associated function. Every addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is included in the claims.

[0082] As used herein, the terms "approximately," "about," and "substantially" refer to an amount that is close to a stated amount that still performs a desired function or achieves a desired result. For example, the terms "approximately," "about," and "substantially" may refer to an amount that is within 5%, within 1%, within 0.1%, and within 0.01% of the stated amount. Further, it should be understood that any directions or reference frames in the foregoing descriptions are merely relative directions or movements. For example, any reference to "up" and "down," or "above" or "below," is merely a description of the relative position or movement of the associated elements.

[0083] The present disclosure may be implemented in other specific forms without departing from its spirit or features. The described embodiments are considered to be illustrative rather than restrictive. Therefore, the scope of the present disclosure is indicated by the appended claims rather than by the foregoing description. Changes within the equivalent meaning and scope of the claims should be included within their scope.

Claims

1. A downhole tool comprising: Directional a pad, the directional pad configured to contact a wellbore wall at a pad contact location; and a drill bit including a longitudinal axis and having at least one active cutting element, wherein the at least one active cutting element includes one or more active cutting elements at a first location that is located farther up the wellbore than each other of the at least one active cutting element, the at least one active cutting element at the first location contacts the wellbore wall at a cutting element contact location, the contact length between the cutting element contact location and the pad contact location not exceeding 7.6 centimeters; and A directional pad angle between the pad contact location and the at least one active cutting element relative to the longitudinal axis, the directional pad angle being greater than 0° and less than or equal to 5°.

2. The downhole tool of claim 1, the drill bit having a drill bit diameter between 20.3 cm and 22.9 cm.

3. The downhole tool according to claim 2, wherein the contact ratio of the drill bit diameter to the contact length is greater than 3:

1. The downhole tool of claim 1 , wherein the drill bit is rotatable relative to the orientation pad.

5. The downhole tool of claim 1, the directional pad being over-spec relative to the drill bit, and the downhole tool having only one directional over-spec pad.

6. The downhole tool of claim 1, the directional pad coupled to a first portion of an directional pad housing, the directional pad extending longitudinally through a downhole end of a second portion of the directional pad housing.

7. The downhole tool of claim 1, the directional pad being coupled to a directional tool, and the drill bit comprising a box connector coupled to a pin connector of the directional tool, wherein at least one active cutting element axially overlaps the box connector.

8. A downhole tool comprising: case; an oriented pad coupled to the housing and configured to contact a wellbore wall at a pad contact location; and a drill bit including a longitudinal axis and having at least one active cutting element and a drill bit diameter, wherein the at least one active cutting element is located at a first location that is located farther uphole than each other of the at least one cutting element that is not at the first location, and wherein a contact ratio of the drill bit diameter to a contact length between the at least one active cutting element at the first location and a pad contact location is greater than 3:1; and A directional pad angle between the pad contact location and the at least one cutting element relative to the longitudinal axis, the directional pad angle being greater than 0° and less than or equal to 5°.

9. The downhole tool of claim 8, wherein the contact ratio is between 3:1 and 8.5:

1.

10. The downhole tool of claim 8, further comprising a downhole motor including a drive shaft; wherein the drill bit includes a box connection coupled to a pin connection of the downhole motor, and at least one active cutting element axially overlaps the box connection; Wherein the downhole tool includes an oriented pad housing coupled to the oriented pad, and the drive shaft is inside the oriented pad housing.

11. The downhole tool of claim 10, the box connector having a box length, a drill bit ratio between a drill bit diameter and the box length being between 8.75:3 and 8.5:

2.

12. The downhole tool of claim 8, the at least one active cutting element comprising at least one sized cutting element, the directional pad having a pad radius greater than a cutting element radius of the at least one sized cutting element.

13. The downhole tool according to claim 8 further includes one or more second pads connected to the shell or integral with the shell, and the one or more second pads are each angularly offset from the directional pad, wherein the directional pad has a larger radius than each of the one or more second pads and extends farther in the downhole direction.

14. The downhole tool of claim 8, the orientation pad being radially fixed relative to a longitudinal axis of the downhole tool.

15. The downhole tool of claim 8, the directional pad coupled to a first portion of a housing having a first downhole end and extending longitudinally beyond a second downhole end of the housing that is offset 120° to 180° from the first portion of the housing.

16. A downhole tool comprising: an oriented pad configured to contact a wellbore wall at a contact location; and A drill bit having a longitudinal axis, the drill bit comprising: Multiple active cutting elements, including: at least one first active cutting element at a first position located farther up the well than each other of the plurality of active cutting elements not at the first position, a directional pad angle between the contact location and the first active cutting element relative to the longitudinal axis being greater than 0° and less than or equal to 5°; and a second active cutting element at a second position located farther up the well than each other of the plurality of active cutting elements except those at the first position, an active cutting element angle between the first active cutting element and the second active cutting element relative to the longitudinal axis being greater than 0° and less than or equal to 5°, The contact length between the contact position and the first active cutting element does not exceed 7.6 cm.

17. The downhole tool of claim 16, the drill bit having a drill bit diameter, and a ratio between the drill bit diameter and a contact length between the first active cutting element and the contact location being greater than 3:

1.

18. The downhole tool of claim 16, the directional pad coupled to an directional pad housing, the directional pad having an overhang relative to the directional pad housing.

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