Downhole steering tool with at least one tapered pad

Abstract

A downhole steering tool is provided that is deployed while drilling a wellbore to steer direction of drilling. The steering tool includes at least one pad movable in a radial direction relative to a central axis of the steering tool to apply a steering force to a wall of the wellbore while drilling the wellbore. The pad has a front face to contact the wall of the wellbore, wherein the front face includes an uphole part and a downhole part, wherein the uphole part has an uphole tapered section that tapers in a radial direction toward the central axis of the drilling tool. The uphole tapered section can be configured to improve maximum attainable DLS of the downhole steering tool.

Description

CROSS-REFERENCE TO RELATED APPLICATION(S)

[0001] The present disclosure claims priority from U.S. Prov. Patent Appl. No. 63 / 742,020, filed on Jan. 6, 2025, herein incorporated by reference in its entirety.FIELD

[0002] The present disclosure relates to directional drilling systems and methods that use pads which are disposed on the outside of a downhole steering tool and contact the wellbore wall to apply a side force to the wellbore wall in order to change the direction of drilling of the drill bit.BACKGROUND

[0003] This section provides background information to facilitate a better understanding of the various aspects of the present disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.

[0004] In underground drilling, a drill bit is used to drill a borehole into a subterranean formation. The drill bit can be attached to sections of drill pipe that extend from a drilling rig at the surface. The attached sections of drill pipe are commonly referred to as a drill string. The section of the drill string that is located near the bottom of the borehole is commonly referred to as a bottom hole assembly (BHA). The BHA typically includes the drill bit, sensors, batteries, telemetry devices, and other equipment located near the drill bit. Alternatively, in coiled tubing drilling, the drill pipe sections are replaced by a continuous, flexible steel pipe deployed from a large reel. Drilling fluid, which is commonly referred to as mud, is pumped from the surface to the drill bit through the drill string or flexible steel pipe. The mud can function to cool the drill bit and carry drill cuttings away from the bottom of the borehole and up through the annulus between the drill string or flexible steel pipe and the borehole wall.

[0005] Because of the high cost of setting up drilling rigs and equipment, directional drilling can be used to access formations other than those located directly below the drilling rig, without having to move the rig or set up another rig. Directional drilling refers to the intentional deviation of a wellbore from a vertical path. A driller can drill to an underground target by pointing the drill bit in a desired drilling direction. In offshore drilling applications, the expense of drilling platforms makes directional drilling even more desirable.

[0006] A directional drilling system creates one or more wellbores in a subterranean formation by steering a drill bit along a planned path or trajectory. The directional drilling system can utilize a bottom hole assembly (BHA) with a rotary steering system (RSS) that can be configured to steer the drill bit and create the one or more wellbores along the desired path (i.e., trajectory). Rotary steering systems include push-the-bit steering tools that use pads which are disposed on the outside of the steering tool and contact the wellbore wall to apply a side force to the wellbore wall in order to cause a change in the direction of drilling of the drill bit. The push-the-bit steering tools can include a control unit and bias unit. The control unit may include, for example, sensors in the form of accelerometers and magnetometers to determine the orientation of the tool and the propagating borehole, and processing devices and memory devices. The accelerometers and magnetometers may be referred to generally as measurement-while-drilling sensors. The bias unit can provide for actuation of the pads to control and steer the direction of drilling of the drilling bit. In some systems, a motor in the control unit rotates a rotary valve that directs a portion of the flow of drilling fluid into piston chambers. The differential pressure between the pressurized piston chambers and the formation can apply a force across the surface area of the pad in the direction of the formation to operate the pad to create a desired side force for steering the direction of drilling of the drill bit. The push-the-bit steering tools can also include a power generation device, for example, a turbine to convert the downhole flow of drilling fluid into electrical power.

[0007] Push-the-bit steering tools enable complex well geometries to be drilled including vertical, curve and lateral sections to reach the target reservoir. In the curve section, the rate of build or turn is referred to as dog leg severity (DLS) and is measured by the rate of change of direction over 100 ft (° / 100 ft). With a trend towards improving drilling efficiency and reducing overall drilling time to reach a target reservoir, drilling the curve section with higher DLS is a key client requirement.

[0008] In current push-the-bit steering tools, the maximum attainable DLS can be limited by unwanted contact of the uphole portion of the pads, clamp plate and kickers of the push-the-bit steering tool to the formation. More specifically, when a pad of a push-the-bit steering tool is pushing against the formation to steer the bit, the pads on the opposite side of the tool can close. Furthermore, parts of the tool (such as the upper kicker, clamp plates or upper portion of a pad) disposed on the opposite side of the system can contact the formation. Such unwanted contact can create forces that oppose the steering force and reduce the overall steering efficiency and possible build rate and maximum attainable DLS of the push-the-bit steering tool.SUMMARY

[0009] According to one or more aspects of the disclosure, a downhole steering tool is provided that is deployed while drilling a wellbore to steer direction of drilling of the drill bit. The steering tool includes at least one pad movable in a radial direction relative to a central axis of the steering tool to apply a steering force to a wall of the wellbore while drilling the wellbore. The pad has a front face to contact the wall of the wellbore. The front face includes an uphole part and a downhole part. The uphole part has an uphole tapered section that tapers in a radial direction toward the central axis of the steering tool. The uphole tapered section can be configured to improve maximum attainable DLS of the downhole steering tool.

[0010] In embodiments, the front face can be configured with a downhole edge disposed opposite an uphole edge as well as a leading edge disposed opposite a trailing edge. A mid-line (ML) of the front face can extend between the leading edge and the trailing edge at a midpoint between the uphole edge and the downhole edge of the front face. The uphole part can be disposed between the uphole edge of the front face and the mid-line (ML), and the downhole part can be disposed between the downhole edge of the front face and the mid-line (ML). The uphole tapered section can include a portion of the uphole part of the front face.

[0011] In embodiments, a leading-midline point of the front face can be located at the intersection of the leading edge and the mid-line (ML) of the front face. A leading-uphole corner point of the front face can be located at the corner of the front face where the leading edge intersects the uphole edge of the front face. A trailing-uphole corner point of the front face can be located at the corner of the front face where the trailing edge intersects the uphole edge of front face. The uphole tapered section can be configured to taper radially inward toward the central axis of the steering tool from the leading-midline point toward the leading-uphole corner point and from the leading-midline point toward the trailing-uphole point.

[0012] In embodiments, the uphole tapered section can be configured to cover triangular area defined by the leading-midline point, the leading-uphole corner point, and the trailing-uphole corner point.

[0013] In embodiments, the uphole tapered section can be configured to extend beyond the triangular area into the uphole part of the front face.

[0014] In embodiments, the uphole tapered section can be configured to cover an area of the uphole part of the front face where undesirable contact is likely to occur that could limit the maximum attainable DLS of the downhole steering tool.

[0015] In embodiments, the downhole part of the front face can be configured with a downhole tapered section that tapers in a radial direction toward the central axis of the downhole steering tool.

[0016] In embodiments, the downhole tapered section can be configured to taper radially inward toward the central axis of the downhole steering tool for a portion of the downhole part that is disposed adjacent a downhole edge of the front face.

[0017] In embodiments, the front face includes an ultrahard material. The ultrahard material can have a grain hardness of about 1,500 HV (Vickers hardness in kg / mm2) or greater. The ultrahard material can include a material selected from diamond, polycrystalline diamond (PCD), leached PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD, nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, or other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials. The ultrahard material can have a hardness value above 3,000 HV, or the ultrahard material can have a hardness value above 3,000 HV, or the ultrahard material can have a hardness value greater than 80 HRa (Rockwell hardness A).

[0018] In embodiments, the front face, including the uphole tapered section and optionally the downhole tapered section, can be configured to include thermally stable polycrystalline diamond (TSP) inserts and / or polycrystalline diamond (PCD) inserts on a tungsten carbide substrate.

[0019] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS

[0020] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings as described below.

[0021] FIG. 1 illustrates an example directional drilling system with a push-the-bit steering tool that can embody aspects of the present disclosure.

[0022] FIGS. 2 to 4 are sectional views of an example push-the-bit steering tool that can embody aspects of the present disclosure.

[0023] FIG. 5 illustrates IDEAS modelling of a push-the-bit steering tool operated in a wellbore including region of contact of the steering tool with the wellbore.

[0024] FIG. 6 is an image of a push-the-bit steering tool operated over a number of downhole runs in wellbores showing a wear pattern on the upper kicker of the steering tool that results from undesirable contact of the upper kicker on the formation during the downhole runs.

[0025] FIG. 7 is a side view of an example push-the-bit steering tool that incorporates pads with corresponding tapered front faces that are spaced from one another about the outside of the steering tool in accordance with aspects of the present disclosure.

[0026] FIGS. 8 and 9 are side and perspective views of a pad with corresponding tapered front face of the push-the-bit steering tool of FIG. 7. The other pads of the push-the-bit steering tool can have the same or similar configuration of the illustrated pad.DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0027] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and / or configurations discussed.

[0028] As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element may be utilized to more clearly describe some elements. Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.

[0029] FIG. 1 is a schematic illustration of an embodiment of a directional drilling system, generally denoted by the numeral 10, which can incorporate embodiments of the present disclosure. Directional drilling system 10 includes a rig 12 located on a surface 14 and a drill string 16 suspended from rig 12. A bottom hole assembly (BHA) 20 with drill bit 18 is deployed on drill string 16 to drill (i.e., propagate) borehole or wellbore 22 into formation 24, for example in a drilling direction 100 as shown. In alternate embodiments employing coiled tubing drilling, the drill string 16 can be replaced by a continuous, flexible steel pipe deployed from a large reel and injected into the borehole 22 with the BHA 20 mounted to the flexible steel pipe.

[0030] The BHA 20 includes one or more stabilizers 26, a measurement-while-drilling (MWD) module or sub 28, a logging-while-drilling (LWD) module or sub 30, and a steering tool 32 (e.g., push-the-bit RSS system), and a power generation module or sub 34. The steering tool 32 includes an attitude hold controller 36 that operates to control the attitude of the drill bit 18 such that it maintains a desired target attitude to propagate borehole 22 along the desired path. The attitude hold controller 36 can include a downhole processor 38 and direction and inclination (D&I) sensors 40, for example, accelerometers and magnetometers. According to an embodiment, the attitude hold controller 36 can embody a downhole closed-loop system that interfaces directly with BHA sensors (i.e., D&I sensors 40, MWD sub 28 sensors, and steering tool 32) to control the attitude of the drill bit 18. Attitude hold controller 36 may be, for example, a unit configured as a roll stabilized or a strap down control unit.

[0031] Directional drilling system 10 also includes drilling fluid or mud 44 that can be circulated from surface 14 through the axial bore of drill string 16 (or through the flexible steel pipe in coil tubing drilling) and returned to surface 14 through the annulus between the formation 24 and the drill string 16 (or the flexible steel pipe in coil tubing drilling).

[0032] The attitude (or drilling direction) of the drill bit 18 can be specified generally as the central axis of BHA 20, which is identified by label 46 in FIG. 1. Attitude commands may be inputted (i.e., transmitted) from a directional driller or trajectory controller identified generally as the surface controller 42 (e.g., processor) in the illustrated embodiment. Signals, such as the demand attitude commands, may be transmitted. for example, via mud pulse telemetry, wired pipe, acoustic telemetry, and wireless transmissions. Accordingly, upon directional inputs from surface controller 42, the attitude hold controller 36 can control the propagation of borehole 22 while drilling through a downhole closed loop, for example, by operating steering tool 32. In particular, steering tool 32 can be actuated to extend the pads 50 into contact with the wellbore wall to drive the attitude of the drill bit to a set point.

[0033] FIGS. 2 to 4 illustrate sectional views of a push-the-bit steering tool 32 which can be incorporated into the BHA 20 of FIG. 1. The push-the-bit steering tool 32 includes a set of radially extendable pads (for example, three shown as 50A, 50B, 50C) disposed about the outside of the tool 32. In FIG. 2, the pad 50A is in a fully retracted position below the gauge 76 of the drill bit 18. An example of operation of the steering tool of FIGS. 2 to 4 is disclosed in co-owned U.S. Pat. No. 8,708,064, which is herein incorporated by reference in its entirety. In operation, drilling fluid can be selectively routed via valve 33 to radially move an actuator 35A, 35B, 35C (which can be embodied by a piston or other actuating device) to extend the corresponding pad 50A, 50B, 50C radially beyond the gauge of the drill bit 18 to contact the wellbore wall and apply a steering force. For example, the pads 50A, 50B, 50C may be pivotably connected to a body 37 of the steering tool 32. The pads 50A, 50B, 50C each have a corresponding outer or front face 52A, 52B, 52C oriented toward the wellbore wall. The front faces 52A, 52B, 52C may be generally cylindrically shaped as illustrated in FIG. 2 relative to the gauge of the drill bit 18 and the radius of the wellbore wall.

[0034] With reference to FIG. 4, each face 52A, 52B, 52C can have a corresponding leading edge 53A, 53B, 53C offset from a corresponding trailing edge 54A, 54B, 54C, that are indicated relative to the rotational direction 102 of the pads 50A, 50B, 50C during drilling. For each pad, the leading edge is the edge of the face that is first to come into contact with the wellbore wall as the steering tool rotates during drilling, and the trailing edge is the edge of the face disposed opposite the leading edge.

[0035] In the push-the-bit steering tool 32 of FIGS. 2 to 4, the maximum attainable DLS can be limited by contact of the uphole portion of exterior parts of the steering tool 32. For example, the uphole portion of the pads 52A, 52B, 52C and / or the uphole portion of corresponding clamp plates and / or the uphole portion of an upper kicker of the steering tool 32 can contact the formation and such contact can limit the maximum attainable DLS of the steering tool 32. More specifically, when a given pad (such as pad 50A) of the steering tool 32 is pushing against the formation to steer the bit, the other pads on the opposed side of the system (such as pad 50B or 50C) can close. Furthermore, exterior parts of the steering tool 32 that are disposed on the opposite side of the steering tool (such as the uphole portion of the pads 50B or 50C and / or the uphole portion of corresponding clamp plates and / or the uphole portion of an upper kicker) can contact the formation. Such unwanted contact can create forces that oppose the steering force and reduce the overall steering efficiency and possible build rate and maximum attainable DLS of the push-the-bit steering tool 32. This unwanted effect has been confirmed with both IDEAS modelling as shown in FIG. 5 as well as wear patterns from downhole runs showing undesirable contact on the upper kicker as shown in FIG. 6. In both cases, the unwanted contact limits the maximum attainable DLS of the steering tool.

[0036] In embodiments, the geometry of the uphole part of the front face of the pads of a push-the-bit steering tool (such as the push-the-bit steering tool 32 of FIGS. 2 to 4) can be configured to reduce the tendency of the pads to limit the maximum attainable DLS of the steering tool.

[0037] FIG. 7 illustrates a push-the-bit steering tool 32′ that incorporates a set of three pads (two shown as 50A′, 50C′) with corresponding tapered front faces (two shown as 52A′, 52C′) that are spaced 120° apart from one another about the outside of the steering tool 32′. FIGS. 8 and 9 are side and perspective views of pad 50A′ with corresponding tapered front face 52A′. The other pads (including pad 50C′) can have the same or similar configuration as pad 50A′.

[0038] As best shown in FIG. 9, a mid-line (ML) extends between the leading edge of the front face 52A′ and the trailing edge of the front face 52A′ at the midpoint between the uphole edge and the downhole edge of the front face 52A′. The downhole edge is the edge of the front face 52A′ that is first to come into contact with the wellbore wall as the steering tool travels downhole, and the uphole edge is the edge of the front face 52A′ disposed opposite the downhole edge. A leading-midline point (L-MP Point) of the front face 52A′ is located at the intersection of the mid-line (ML) and the trailing edge of the front face 52A′. A leading-uphole corner point (L-U Corner Point) is located at the corner of the front face 52A′ where the leading edge intersects the uphole edge of the front face 52A′. A trailing-uphole corner point (T-U Corner Point) is located at the corner of the front face 52A′ where the trailing edge intersects the uphole edge of front face 52A′.

[0039] The front face 52A′ can be logically partitioned into an uphole part and a downhole part. The uphole part is disposed between the uphole edge of the front face 52A′ and the mid-line (ML) of the front face 52A′, and the downhole part is disposed between the downhole edge of the front face 52A′ and the mid-line (ML) of the front face 52A′. The front face 52A′ has an uphole tapered section 58A′ that includes a portion of the uphole part of the front face 52A′ and a downhole tapered section 59A′ that includes a portion of the downhole part of the front face 52A′.

[0040] The uphole tapered section 58A′ tapers downward (radially inward) toward the central tool axis from the leading-midline point (L-MP Point) toward the leading-uphole corner point (L-U Corner Point) and from the leading-midline point (L-MP Point) toward the trailing-uphole point (T-U Corner Point) as best shown in FIGS. 8 and 9. The uphole tapered section 58A′ can cover a triangular area defined by the three points (leading-midline point (L-MP Point, leading-uphole corner point (L-U Corner Point), trailing-uphole corner point (T-U Corner Point)). The uphole tapered section 58A′ can extend beyond this triangular area into the uphole part of the front face 52A′ as best show in FIG. 9. The uphole tapered section 58A′ can be configured to cover an area of the uphole part of the front face 52A′ where undesirable contact is likely to occur that could limit the maximum attainable DLS of the steering tool.

[0041] The downhole tapered section 59A′ tapers downward (radially inward) toward the central tool axis for a portion of the downhole part of the front face 52A′ that is disposed adjacent the downhole edge of the front face 52A′ as best show in FIGS. 8 and 9.

[0042] In embodiments, the front face 52A′ can include one or more materials. At least one of the materials may include an ultrahard material. As used herein, the term “ultrahard” is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg / mm2) or greater. Such ultrahard materials can include those capable of demonstrating physical stability at temperatures above 750° C., and for certain applications above 1,000° C. Such ultrahard materials can be formed from consolidated materials. Such ultrahard materials can include but are not limited to diamond, polycrystalline diamond (PCD), leached PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD, nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, or other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials. In some embodiments, the ultrahard material may have a hardness value above 3,000 HV. In other embodiments, the ultrahard material may have a hardness value above 4000 HV. In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A).

[0043] In embodiments, the front face 52A′ (including the uphole tapered section 58A′ and the downhole tapered section 59A′) can include thermally stable polycrystalline diamond (TSP) inserts and / or PCD inserts on a tungsten carbide substrate. The PCD inserts may be sintered in a high-pressure high-temperature (HPHT) press using a tungsten carbide substrate. The pad 50A′ can be connected to the corresponding actuator (e.g., piston 35A of FIG. 3) using braze, epoxy, a mechanical connection such as a dovetail joint or a threaded connection, or some other secure connection.

[0044] The other pads (including pad 50C′) can have the same or similar configuration as pad 50A′ as described above with respect to FIGS. 7 to 9.

[0045] The improved geometry of the uphole part of the front face of one or more pads of a steering tool as described herein can be combined with a tapered clamp plate lug and upper kicker of the steering to maximize the clearance to the borehole locally in that region.

[0046] The improvements provided by the present disclosure are applicable to push-the-bit steering tools, such as the PowerDrive Orbit and Orbit G2 tools made commercially available by SLB of Houston, TX. In such steering tools, the tapering of the uphole portion of the pads can improve overall steering force and maximum attainable DLS of the steering tools, while the tapering of the downhole portion of the pads can reduce the tendency of the pads to act as a cutting element that removes rock from the sidewall of the wellbore from which it is supposed to push off from in order to steer the drilling direction of the bit.

[0047] The improvements provided by the present disclosure can provide the following benefits:

[0048] drill a curved section of wellbore with higher DLS to improve drilling efficiency by reducing the overall time to drill the curve section; and

[0049] drill with higher ROP at a lower DLS enabling improvements in drilling efficiency by reducing the overall time to drill a curve section and overall wellbore

[0050] The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure. Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and / or achieving the same advantages of the embodiments introduced herein. 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, features shown in individual embodiments referred to above may be used together in combinations other than those which have been shown and described specifically. Accordingly, any such modification is intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not just structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface,

[0051] in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke means-plus-function for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Examples

Embodiment Construction

[0027]It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and / or configurations discussed.

[0028]As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, d...

CROSS-REFERENCE TO RELATED APPLICATION(S)

[0001] The present disclosure claims priority from U.S. Prov. Patent Appl. No. 63 / 742,020, filed on Jan. 6, 2025, herein incorporated by reference in its entirety.FIELD

[0002] The present disclosure relates to directional drilling systems and methods that use pads which are disposed on the outside of a downhole steering tool and contact the wellbore wall to apply a side force to the wellbore wall in order to change the direction of drilling of the drill bit.BACKGROUND

[0003] This section provides background information to facilitate a better understanding of the various aspects of the present disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.

[0004] In underground drilling, a drill bit is used to drill a borehole into a subterranean formation. The drill bit can be attached to sections of drill pipe that extend from a drilling rig at the surface. The attached sections of drill pipe are commonly referred to as a drill string. The section of the drill string that is located near the bottom of the borehole is commonly referred to as a bottom hole assembly (BHA). The BHA typically includes the drill bit, sensors, batteries, telemetry devices, and other equipment located near the drill bit. Alternatively, in coiled tubing drilling, the drill pipe sections are replaced by a continuous, flexible steel pipe deployed from a large reel. Drilling fluid, which is commonly referred to as mud, is pumped from the surface to the drill bit through the drill string or flexible steel pipe. The mud can function to cool the drill bit and carry drill cuttings away from the bottom of the borehole and up through the annulus between the drill string or flexible steel pipe and the borehole wall.

[0005] Because of the high cost of setting up drilling rigs and equipment, directional drilling can be used to access formations other than those located directly below the drilling rig, without having to move the rig or set up another rig. Directional drilling refers to the intentional deviation of a wellbore from a vertical path. A driller can drill to an underground target by pointing the drill bit in a desired drilling direction. In offshore drilling applications, the expense of drilling platforms makes directional drilling even more desirable.

[0006] A directional drilling system creates one or more wellbores in a subterranean formation by steering a drill bit along a planned path or trajectory. The directional drilling system can utilize a bottom hole assembly (BHA) with a rotary steering system (RSS) that can be configured to steer the drill bit and create the one or more wellbores along the desired path (i.e., trajectory). Rotary steering systems include push-the-bit steering tools that use pads which are disposed on the outside of the steering tool and contact the wellbore wall to apply a side force to the wellbore wall in order to cause a change in the direction of drilling of the drill bit. The push-the-bit steering tools can include a control unit and bias unit. The control unit may include, for example, sensors in the form of accelerometers and magnetometers to determine the orientation of the tool and the propagating borehole, and processing devices and memory devices. The accelerometers and magnetometers may be referred to generally as measurement-while-drilling sensors. The bias unit can provide for actuation of the pads to control and steer the direction of drilling of the drilling bit. In some systems, a motor in the control unit rotates a rotary valve that directs a portion of the flow of drilling fluid into piston chambers. The differential pressure between the pressurized piston chambers and the formation can apply a force across the surface area of the pad in the direction of the formation to operate the pad to create a desired side force for steering the direction of drilling of the drill bit. The push-the-bit steering tools can also include a power generation device, for example, a turbine to convert the downhole flow of drilling fluid into electrical power.

[0007] Push-the-bit steering tools enable complex well geometries to be drilled including vertical, curve and lateral sections to reach the target reservoir. In the curve section, the rate of build or turn is referred to as dog leg severity (DLS) and is measured by the rate of change of direction over 100 ft (° / 100 ft). With a trend towards improving drilling efficiency and reducing overall drilling time to reach a target reservoir, drilling the curve section with higher DLS is a key client requirement.

[0008] In current push-the-bit steering tools, the maximum attainable DLS can be limited by unwanted contact of the uphole portion of the pads, clamp plate and kickers of the push-the-bit steering tool to the formation. More specifically, when a pad of a push-the-bit steering tool is pushing against the formation to steer the bit, the pads on the opposite side of the tool can close. Furthermore, parts of the tool (such as the upper kicker, clamp plates or upper portion of a pad) disposed on the opposite side of the system can contact the formation. Such unwanted contact can create forces that oppose the steering force and reduce the overall steering efficiency and possible build rate and maximum attainable DLS of the push-the-bit steering tool.SUMMARY

[0009] According to one or more aspects of the disclosure, a downhole steering tool is provided that is deployed while drilling a wellbore to steer direction of drilling of the drill bit. The steering tool includes at least one pad movable in a radial direction relative to a central axis of the steering tool to apply a steering force to a wall of the wellbore while drilling the wellbore. The pad has a front face to contact the wall of the wellbore. The front face includes an uphole part and a downhole part. The uphole part has an uphole tapered section that tapers in a radial direction toward the central axis of the steering tool. The uphole tapered section can be configured to improve maximum attainable DLS of the downhole steering tool.

[0010] In embodiments, the front face can be configured with a downhole edge disposed opposite an uphole edge as well as a leading edge disposed opposite a trailing edge. A mid-line (ML) of the front face can extend between the leading edge and the trailing edge at a midpoint between the uphole edge and the downhole edge of the front face. The uphole part can be disposed between the uphole edge of the front face and the mid-line (ML), and the downhole part can be disposed between the downhole edge of the front face and the mid-line (ML). The uphole tapered section can include a portion of the uphole part of the front face.

[0011] In embodiments, a leading-midline point of the front face can be located at the intersection of the leading edge and the mid-line (ML) of the front face. A leading-uphole corner point of the front face can be located at the corner of the front face where the leading edge intersects the uphole edge of the front face. A trailing-uphole corner point of the front face can be located at the corner of the front face where the trailing edge intersects the uphole edge of front face. The uphole tapered section can be configured to taper radially inward toward the central axis of the steering tool from the leading-midline point toward the leading-uphole corner point and from the leading-midline point toward the trailing-uphole point.

[0012] In embodiments, the uphole tapered section can be configured to cover triangular area defined by the leading-midline point, the leading-uphole corner point, and the trailing-uphole corner point.

[0013] In embodiments, the uphole tapered section can be configured to extend beyond the triangular area into the uphole part of the front face.

[0014] In embodiments, the uphole tapered section can be configured to cover an area of the uphole part of the front face where undesirable contact is likely to occur that could limit the maximum attainable DLS of the downhole steering tool.

[0015] In embodiments, the downhole part of the front face can be configured with a downhole tapered section that tapers in a radial direction toward the central axis of the downhole steering tool.

[0016] In embodiments, the downhole tapered section can be configured to taper radially inward toward the central axis of the downhole steering tool for a portion of the downhole part that is disposed adjacent a downhole edge of the front face.

[0017] In embodiments, the front face includes an ultrahard material. The ultrahard material can have a grain hardness of about 1,500 HV (Vickers hardness in kg / mm2) or greater. The ultrahard material can include a material selected from diamond, polycrystalline diamond (PCD), leached PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD, nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, or other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials. The ultrahard material can have a hardness value above 3,000 HV, or the ultrahard material can have a hardness value above 3,000 HV, or the ultrahard material can have a hardness value greater than 80 HRa (Rockwell hardness A).

[0018] In embodiments, the front face, including the uphole tapered section and optionally the downhole tapered section, can be configured to include thermally stable polycrystalline diamond (TSP) inserts and / or polycrystalline diamond (PCD) inserts on a tungsten carbide substrate.

[0019] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS

[0020] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings as described below.

[0021] FIG. 1 illustrates an example directional drilling system with a push-the-bit steering tool that can embody aspects of the present disclosure.

[0022] FIGS. 2 to 4 are sectional views of an example push-the-bit steering tool that can embody aspects of the present disclosure.

[0023] FIG. 5 illustrates IDEAS modelling of a push-the-bit steering tool operated in a wellbore including region of contact of the steering tool with the wellbore.

[0024] FIG. 6 is an image of a push-the-bit steering tool operated over a number of downhole runs in wellbores showing a wear pattern on the upper kicker of the steering tool that results from undesirable contact of the upper kicker on the formation during the downhole runs.

[0025] FIG. 7 is a side view of an example push-the-bit steering tool that incorporates pads with corresponding tapered front faces that are spaced from one another about the outside of the steering tool in accordance with aspects of the present disclosure.

[0026] FIGS. 8 and 9 are side and perspective views of a pad with corresponding tapered front face of the push-the-bit steering tool of FIG. 7. The other pads of the push-the-bit steering tool can have the same or similar configuration of the illustrated pad.DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0027] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and / or configurations discussed.

[0028] As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element may be utilized to more clearly describe some elements. Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.

[0029] FIG. 1 is a schematic illustration of an embodiment of a directional drilling system, generally denoted by the numeral 10, which can incorporate embodiments of the present disclosure. Directional drilling system 10 includes a rig 12 located on a surface 14 and a drill string 16 suspended from rig 12. A bottom hole assembly (BHA) 20 with drill bit 18 is deployed on drill string 16 to drill (i.e., propagate) borehole or wellbore 22 into formation 24, for example in a drilling direction 100 as shown. In alternate embodiments employing coiled tubing drilling, the drill string 16 can be replaced by a continuous, flexible steel pipe deployed from a large reel and injected into the borehole 22 with the BHA 20 mounted to the flexible steel pipe.

[0030] The BHA 20 includes one or more stabilizers 26, a measurement-while-drilling (MWD) module or sub 28, a logging-while-drilling (LWD) module or sub 30, and a steering tool 32 (e.g., push-the-bit RSS system), and a power generation module or sub 34. The steering tool 32 includes an attitude hold controller 36 that operates to control the attitude of the drill bit 18 such that it maintains a desired target attitude to propagate borehole 22 along the desired path. The attitude hold controller 36 can include a downhole processor 38 and direction and inclination (D&I) sensors 40, for example, accelerometers and magnetometers. According to an embodiment, the attitude hold controller 36 can embody a downhole closed-loop system that interfaces directly with BHA sensors (i.e., D&I sensors 40, MWD sub 28 sensors, and steering tool 32) to control the attitude of the drill bit 18. Attitude hold controller 36 may be, for example, a unit configured as a roll stabilized or a strap down control unit.

[0031] Directional drilling system 10 also includes drilling fluid or mud 44 that can be circulated from surface 14 through the axial bore of drill string 16 (or through the flexible steel pipe in coil tubing drilling) and returned to surface 14 through the annulus between the formation 24 and the drill string 16 (or the flexible steel pipe in coil tubing drilling).

[0032] The attitude (or drilling direction) of the drill bit 18 can be specified generally as the central axis of BHA 20, which is identified by label 46 in FIG. 1. Attitude commands may be inputted (i.e., transmitted) from a directional driller or trajectory controller identified generally as the surface controller 42 (e.g., processor) in the illustrated embodiment. Signals, such as the demand attitude commands, may be transmitted. for example, via mud pulse telemetry, wired pipe, acoustic telemetry, and wireless transmissions. Accordingly, upon directional inputs from surface controller 42, the attitude hold controller 36 can control the propagation of borehole 22 while drilling through a downhole closed loop, for example, by operating steering tool 32. In particular, steering tool 32 can be actuated to extend the pads 50 into contact with the wellbore wall to drive the attitude of the drill bit to a set point.

[0033] FIGS. 2 to 4 illustrate sectional views of a push-the-bit steering tool 32 which can be incorporated into the BHA 20 of FIG. 1. The push-the-bit steering tool 32 includes a set of radially extendable pads (for example, three shown as 50A, 50B, 50C) disposed about the outside of the tool 32. In FIG. 2, the pad 50A is in a fully retracted position below the gauge 76 of the drill bit 18. An example of operation of the steering tool of FIGS. 2 to 4 is disclosed in co-owned U.S. Pat. No. 8,708,064, which is herein incorporated by reference in its entirety. In operation, drilling fluid can be selectively routed via valve 33 to radially move an actuator 35A, 35B, 35C (which can be embodied by a piston or other actuating device) to extend the corresponding pad 50A, 50B, 50C radially beyond the gauge of the drill bit 18 to contact the wellbore wall and apply a steering force. For example, the pads 50A, 50B, 50C may be pivotably connected to a body 37 of the steering tool 32. The pads 50A, 50B, 50C each have a corresponding outer or front face 52A, 52B, 52C oriented toward the wellbore wall. The front faces 52A, 52B, 52C may be generally cylindrically shaped as illustrated in FIG. 2 relative to the gauge of the drill bit 18 and the radius of the wellbore wall.

[0034] With reference to FIG. 4, each face 52A, 52B, 52C can have a corresponding leading edge 53A, 53B, 53C offset from a corresponding trailing edge 54A, 54B, 54C, that are indicated relative to the rotational direction 102 of the pads 50A, 50B, 50C during drilling. For each pad, the leading edge is the edge of the face that is first to come into contact with the wellbore wall as the steering tool rotates during drilling, and the trailing edge is the edge of the face disposed opposite the leading edge.

[0035] In the push-the-bit steering tool 32 of FIGS. 2 to 4, the maximum attainable DLS can be limited by contact of the uphole portion of exterior parts of the steering tool 32. For example, the uphole portion of the pads 52A, 52B, 52C and / or the uphole portion of corresponding clamp plates and / or the uphole portion of an upper kicker of the steering tool 32 can contact the formation and such contact can limit the maximum attainable DLS of the steering tool 32. More specifically, when a given pad (such as pad 50A) of the steering tool 32 is pushing against the formation to steer the bit, the other pads on the opposed side of the system (such as pad 50B or 50C) can close. Furthermore, exterior parts of the steering tool 32 that are disposed on the opposite side of the steering tool (such as the uphole portion of the pads 50B or 50C and / or the uphole portion of corresponding clamp plates and / or the uphole portion of an upper kicker) can contact the formation. Such unwanted contact can create forces that oppose the steering force and reduce the overall steering efficiency and possible build rate and maximum attainable DLS of the push-the-bit steering tool 32. This unwanted effect has been confirmed with both IDEAS modelling as shown in FIG. 5 as well as wear patterns from downhole runs showing undesirable contact on the upper kicker as shown in FIG. 6. In both cases, the unwanted contact limits the maximum attainable DLS of the steering tool.

[0036] In embodiments, the geometry of the uphole part of the front face of the pads of a push-the-bit steering tool (such as the push-the-bit steering tool 32 of FIGS. 2 to 4) can be configured to reduce the tendency of the pads to limit the maximum attainable DLS of the steering tool.

[0037] FIG. 7 illustrates a push-the-bit steering tool 32′ that incorporates a set of three pads (two shown as 50A′, 50C′) with corresponding tapered front faces (two shown as 52A′, 52C′) that are spaced 120° apart from one another about the outside of the steering tool 32′. FIGS. 8 and 9 are side and perspective views of pad 50A′ with corresponding tapered front face 52A′. The other pads (including pad 50C′) can have the same or similar configuration as pad 50A′.

[0038] As best shown in FIG. 9, a mid-line (ML) extends between the leading edge of the front face 52A′ and the trailing edge of the front face 52A′ at the midpoint between the uphole edge and the downhole edge of the front face 52A′. The downhole edge is the edge of the front face 52A′ that is first to come into contact with the wellbore wall as the steering tool travels downhole, and the uphole edge is the edge of the front face 52A′ disposed opposite the downhole edge. A leading-midline point (L-MP Point) of the front face 52A′ is located at the intersection of the mid-line (ML) and the trailing edge of the front face 52A′. A leading-uphole corner point (L-U Corner Point) is located at the corner of the front face 52A′ where the leading edge intersects the uphole edge of the front face 52A′. A trailing-uphole corner point (T-U Corner Point) is located at the corner of the front face 52A′ where the trailing edge intersects the uphole edge of front face 52A′.

[0039] The front face 52A′ can be logically partitioned into an uphole part and a downhole part. The uphole part is disposed between the uphole edge of the front face 52A′ and the mid-line (ML) of the front face 52A′, and the downhole part is disposed between the downhole edge of the front face 52A′ and the mid-line (ML) of the front face 52A′. The front face 52A′ has an uphole tapered section 58A′ that includes a portion of the uphole part of the front face 52A′ and a downhole tapered section 59A′ that includes a portion of the downhole part of the front face 52A′.

[0040] The uphole tapered section 58A′ tapers downward (radially inward) toward the central tool axis from the leading-midline point (L-MP Point) toward the leading-uphole corner point (L-U Corner Point) and from the leading-midline point (L-MP Point) toward the trailing-uphole point (T-U Corner Point) as best shown in FIGS. 8 and 9. The uphole tapered section 58A′ can cover a triangular area defined by the three points (leading-midline point (L-MP Point, leading-uphole corner point (L-U Corner Point), trailing-uphole corner point (T-U Corner Point)). The uphole tapered section 58A′ can extend beyond this triangular area into the uphole part of the front face 52A′ as best show in FIG. 9. The uphole tapered section 58A′ can be configured to cover an area of the uphole part of the front face 52A′ where undesirable contact is likely to occur that could limit the maximum attainable DLS of the steering tool.

[0041] The downhole tapered section 59A′ tapers downward (radially inward) toward the central tool axis for a portion of the downhole part of the front face 52A′ that is disposed adjacent the downhole edge of the front face 52A′ as best show in FIGS. 8 and 9.

[0042] In embodiments, the front face 52A′ can include one or more materials. At least one of the materials may include an ultrahard material. As used herein, the term “ultrahard” is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg / mm2) or greater. Such ultrahard materials can include those capable of demonstrating physical stability at temperatures above 750° C., and for certain applications above 1,000° C. Such ultrahard materials can be formed from consolidated materials. Such ultrahard materials can include but are not limited to diamond, polycrystalline diamond (PCD), leached PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD, nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, or other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials. In some embodiments, the ultrahard material may have a hardness value above 3,000 HV. In other embodiments, the ultrahard material may have a hardness value above 4000 HV. In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A).

[0043] In embodiments, the front face 52A′ (including the uphole tapered section 58A′ and the downhole tapered section 59A′) can include thermally stable polycrystalline diamond (TSP) inserts and / or PCD inserts on a tungsten carbide substrate. The PCD inserts may be sintered in a high-pressure high-temperature (HPHT) press using a tungsten carbide substrate. The pad 50A′ can be connected to the corresponding actuator (e.g., piston 35A of FIG. 3) using braze, epoxy, a mechanical connection such as a dovetail joint or a threaded connection, or some other secure connection.

[0044] The other pads (including pad 50C′) can have the same or similar configuration as pad 50A′ as described above with respect to FIGS. 7 to 9.

[0045] The improved geometry of the uphole part of the front face of one or more pads of a steering tool as described herein can be combined with a tapered clamp plate lug and upper kicker of the steering to maximize the clearance to the borehole locally in that region.

[0046] The improvements provided by the present disclosure are applicable to push-the-bit steering tools, such as the PowerDrive Orbit and Orbit G2 tools made commercially available by SLB of Houston, TX. In such steering tools, the tapering of the uphole portion of the pads can improve overall steering force and maximum attainable DLS of the steering tools, while the tapering of the downhole portion of the pads can reduce the tendency of the pads to act as a cutting element that removes rock from the sidewall of the wellbore from which it is supposed to push off from in order to steer the drilling direction of the bit.

[0047] The improvements provided by the present disclosure can provide the following benefits:

[0048] drill a curved section of wellbore with higher DLS to improve drilling efficiency by reducing the overall time to drill the curve section; and

[0049] drill with higher ROP at a lower DLS enabling improvements in drilling efficiency by reducing the overall time to drill a curve section and overall wellbore

[0050] The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure. Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and / or achieving the same advantages of the embodiments introduced herein. 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, features shown in individual embodiments referred to above may be used together in combinations other than those which have been shown and described specifically. Accordingly, any such modification is intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not just structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface,

[0051] in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke means-plus-function for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Examples

Embodiment Construction

[0027]It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and / or configurations discussed.

[0028]As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, d...

Claims

1. A downhole steering tool that is deployed while drilling a wellbore to steer direction of drilling, the downhole steering tool comprising:at least one pad movable in a radial direction relative to a central axis of the steering tool to apply a steering force to a wall of the wellbore while drilling the wellbore, the pad having a front face to contact the wall of the wellbore, wherein the front face includes an uphole part and a downhole part, wherein the uphole part has an uphole tapered section that tapers in a radial direction toward the central axis of the steering tool.

2. The downhole steering tool of claim 1, wherein:the uphole tapered section is configured to improve maximum attainable DLS of the downhole steering tool.

3. The downhole steering tool of claim 1, wherein:the front face has a downhole edge disposed opposite an uphole edge as well as a leading edge disposed opposite a trailing edge;a mid-line (ML) of the front face extends between the leading edge and the trailing edge at a midpoint between the uphole edge and the downhole edge of the front face;the uphole part is disposed between the uphole edge of the front face and the mid-line (ML);the downhole part is disposed between the downhole edge of the front face and the mid-line (ML) of the front face; andthe uphole tapered section includes a portion of the uphole part of the front face.

4. The downhole steering tool of claim 3, wherein:a leading-midline point of the front face is located at the intersection of the leading edge and the mid-line (ML) of the front face;a leading-uphole corner point of the front face is located at the corner of the front face where the leading edge intersects the uphole edge of the front face;a trailing-uphole corner point of the front face is located at the corner of the front face where the trailing edge intersects the uphole edge of front face; andthe uphole tapered section tapers radially inward toward the central axis of the steering tool from the leading-midline point toward the leading-uphole corner point and from the leading-midline point toward the trailing-uphole point.

5. The downhole steering tool of claim 4, wherein:the uphole tapered section covers a triangular area defined by the leading-midline point, the leading-uphole corner point, and the trailing-uphole corner point.

6. The downhole steering tool of claim 5, wherein:the uphole tapered section extends beyond the triangular area into the uphole part of the front face.

7. The downhole steering tool of claim 1, wherein:the uphole tapered section is configured to cover an area of the uphole part of the front face where undesirable contact is likely to occur that could limit the maximum attainable DLS of the downhole steering tool.

8. The downhole steering tool of claim 1, wherein:the downhole part has a downhole tapered section that tapers in a radial direction toward the central axis of the downhole steering tool.

9. The downhole steering tool of claim 8, wherein:the downhole tapered section tapers radially inward toward the central axis of the downhole steering tool for a portion of the downhole part that is disposed adjacent a downhole edge of the front face.

10. The downhole steering tool of claim 1, wherein:the front face includes an ultrahard material.

11. The downhole steering tool of claim 10, wherein:the ultrahard material has a grain hardness of about 1,500 HV (Vickers hardness in kg / mm2) or greater.

12. The downhole steering tool of claim 10, wherein:the ultrahard material includes a material selected from diamond, polycrystalline diamond (PCD), leached PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD, nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, or other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials.

13. The downhole steering tool of claim 10, wherein:the ultrahard material has a hardness value above 3,000 HV; orthe ultrahard material has a hardness value above 3,000 HV; orthe ultrahard material has a hardness value greater than 80 HRa (Rockwell hardness A).

14. The downhole steering tool of claim 10, wherein:the front face, including the uphole tapered section, includes thermally stable polycrystalline diamond (TSP) inserts and / or polycrystalline diamond (PCD) inserts on a tungsten carbide substrate.

15. The downhole steering tool of claim 1, further comprising:an actuator configured to move the pad in a radial direction relative to a central axis of the steering tool to apply a steering force to a wall of the wellbore while drilling to steer the direction of drilling.

16. The downhole steering tool of claim 1, which is a push-the-bit RSS system.

17. A bottom hole assembly (BHA), comprising:a drill bit; anda downhole steering tool according to claim 1, wherein the downhole steering tool is operably coupled to the drill bit.

18. The BHA of claim 17, wherein:the downhole steering tool is a push-the-bit RSS system.

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