Patent Publication Number: US-2023151695-A1

Title: Downhole tool with tapered actuators

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 17/202,393 filed Mar. 16, 2021, which is a continuation of U.S. patent application Ser. No. 16/309,717 filed Dec. 13, 2018, which is a 371 national stage entry of International Patent Application No. PCT/US2017/039358, filed Jun. 27, 2017, which claims priority to and the benefit of U.S. patent application No. 62/357,215, filed on Jun. 30, 2016, and to U.S. Patent Application No. 62/357,225, filed on Jun. 30, 2016. The entireties of each of the foregoing applications are incorporated herein by this reference. 
    
    
     BACKGROUND 
     This section provides background information to facilitate a better understanding of the various aspects of the 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. 
     In underground drilling, a drill bit is used to drill a borehole into subterranean formations. The drill bit is attached to sections of pipe that stretch back to the surface. The attached sections of pipe are called the drill string. The section of the drill string that is located near the bottom of the borehole is called the bottom hole assembly (BHA). The BHA typically includes the drill bit, sensors, batteries, telemetry devices, and other equipment located near the drill bit. A drilling fluid, called mud, is pumped from the surface to the drill bit through the pipe that forms the drill string. The primary functions of the mud are to cool the drill bit and carry drill cuttings away from the bottom of the borehole and up through the annulus between the drill pipe and the borehole. 
     Because of the high cost of setting up drilling rigs and equipment, it is desirable to be able to explore formations other than those located directly below the drilling rig, without having to move the rig or set up another rig. In off-shore drilling applications, the expense of drilling platforms makes directional drilling even more desirable. 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. 
     SUMMARY 
     In some embodiments of a push-the-bit steering device, a steering body may include a series of actuators installed radially around the body, each actuator mounted transverse to the axis of the body. On each actuator is a working face, which may contain one surface, or more than three surfaces. A first surface of the working face may be approximately parallel to the axis of the body. A second surface, downhole of the working face, may slant radially inward from the first surface. A third surface, uphole of the working face, may slant radially inward from the first surface. 
     The working face may include two materials: a first material including a standard wear material and a second surface including an ultrahard insert. The ultrahard insert may have a different coefficient of friction from the first material. The ultrahard insert may be located primarily on the leading and downhole edges of the working face. In some embodiments, the ultrahard insert may include 25% of the perimeter and 25% of area of the working face. 
     In some embodiments, the actuator may include a radially inward shaft and a radially outward body. The shaft and the body of the actuator may have different cross-sectional areas. In the embodiment where the shaft has a larger cross-sectional area than the body, a stop may be placed on the receiver of the actuator to prevent ejection of the actuator from the steering body. Additionally, the shaft and body may have non-round profiles, including elliptical, square, hexagonal, polygonal of any number of sides, concave polygonal, any non-polygonal enclosed shape, or any other enclosed shape. When used in combination with a complimentarily shaped receiver, the non-round shaft or body may prevent rotation through contact with the receiver. The receiver may include a tungsten carbide band, sized with a clearance over the actuator such that in combination with a hydraulic fluid of sufficient viscosity, a sealing surface is created. Standard elastomeric seals are not durable enough to withstand the harsh, high-repetition environment to which the pistons are exposed; a tungsten carbide band may withstand the conditions. 
     In other embodiments, the actuator may have a cradle on the radially outward face. The cradle may house a roller, configured to contact the borehole wall. Upon actuation, the roller may contact the borehole wall, and roller may roll along the surface of the borehole wall 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which: 
         FIG.  1    is a schematic diagram of an embodiment of a directional drilling system with a directional drilling actuator assembly, according to the present disclosure; 
         FIG.  2    is a pictorial diagram of attitude and steering parameters depicted in a global coordinate reference frame, according to the present disclosure; 
         FIG.  3    is a schematic representation of an actuator assembly in a downhole environment, according to the present disclosure; 
         FIGS.  4 - 1  through  4 - 3    are cross-sectional views of embodiments of actuator assemblies in a directional drilling system showing assemblies of two, three and four actuators, according to the present disclosure; 
         FIG.  5    is a cross-sectional view of an embodiment of a multi-surfaced actuator, according to the present disclosure; 
         FIGS.  6 - 1  and  6 - 2    are schematic views of an embodiment of an actuator using a guide pin and channel to direct actuation, according to the present disclosure; 
         FIG.  7    is a representation of the working face of the embodiment of an actuator of  FIG.  5   , showing multiple surfaces and materials, according to the present disclosure; 
         FIGS.  8 - 1  through  8 - 2    illustrate further embodiments of the working face of  FIG.  7   , according to the present disclosure; 
         FIGS.  9 - 1  through  9 - 5    illustrate embodiments of actuators having various cross-sectional areas, according to the present disclosure; 
         FIGS.  10 - 1  and  10 - 2    illustrate embodiments of actuators with examples of differing shaft and body sizes, according to the present disclosure; 
         FIGS.  11 - 1  and  11 - 2    illustrate embodiments of a band in a receiver in combination with a hydraulic fluid to create a sealing surface with the actuator, according to the present disclosure; 
         FIGS.  12 - 1  and  12 - 2    are cross-sectional views of the embodiments of the band of  FIGS.  11 - 1  and  11 - 2   , showing clearance between the band and the actuator, according to the present disclosure; and 
         FIGS.  13 - 1  and  13 - 2    illustrate an embodiment of an actuator with a roller in a cradle, according to the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     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 does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
     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. 
     The directional drilling process creates geometric boreholes by steering a drilling tool along a planned path. A directional drilling system typically utilizes a steering assembly to steer the drill bit and to create the borehole along the desired path (i.e., trajectory). Steering assemblies may be classified generally, for example, as a push-the-bit or point-the-bit devices. Push-the-bit devices typically apply a side force on the formation to influence the change in orientation. A point-the-bit device typically has a fixed bend in the geometry of the bottom hole assembly. Rotary steerable systems (“RSS”) provide the ability to change the direction of the propagation of the drill string and borehole while drilling. 
     According to one or more embodiments, control systems may be incorporated into the downhole system to stabilize the orientation of propagation of the borehole and to interface directly with the downhole sensors and/or actuators. For example, directional drilling devices (e.g., RSS and non-RSS devices) may be incorporated into the bottom hole assembly. Directional drilling may be positioned directly behind the drill bit in the drill string. According to one or more embodiments, directional drilling devices may include a control unit and bias unit. The control unit may include, for example, sensors in the form of accelerometers and/or magnetometers to determine the orientation of the tool and the propagating borehole, and processing and memory devices. The accelerometers and magnetometers may be referred to generally as measurement-while-drilling sensors. The bias unit may be referred to as the main actuation portion of the directional drilling tool and the bias unit may be categorized as a push-the-bit or point-the-bit actuators. The drilling tool may include a power generation device, for example, a turbine to convert the downhole flow of drilling fluid into electrical power. 
     Push-the-bit steering devices apply a side force to the formation through a stabilizer for example. This provides a lateral bias on the drill bit through bending in the borehole. Push-the-bit steering devices may include, for example, actuator pads. According to some embodiments, a motor in the control unit rotates a rotary valve that directs a portion of the flow of drilling fluid into actuator chambers. The differential pressure between the pressurized actuator chambers and the formation applies a force across the area of the pad to the formation. A rotary valve, for example, may direct the fluid flow into an actuator chamber to operate a pad and create the desired side force. In these systems, the tool may be continuously steering. 
     In point-the-bit steering devices, the axis of the drill bit is at an angular offset to the axis of the bottom hole assembly. For example, the outer housing and the drill bit may be rotated from the surface and a motor may rotate in the opposite direction from the outer housing. A power generating device (e.g., turbine) may be disposed in the drilling fluid flow to generate electrical power to drive a motor. The control unit may be located behind the motor, with sensors that measure the attitude and control the tool face angle of the fixed bend. 
       FIG.  1    is a schematic illustration of an embodiment of a directional drilling system  10  in which embodiments of steering devices and steering actuators may be incorporated. The directional drilling system  10  includes a rig  12  located above a surface  14  and a drill string  16  suspended from the rig  12 . A drill bit  18  disposed with a bottom hole assembly (“BHA”)  20  and deployed on the drill string  16  to drill (i.e., propagate) a borehole  22  into a formation  24 . 
     The depicted 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 , a steering system  32  (e.g., RSS device, steering actuator, actuators, pads), a power generation module or sub  34 , or combinations thereof. The directional drilling system  10  includes an attitude hold controller  36  disposed with the BHA  20  and operationally connected with the steering system  32  to maintain the drill bit  18  and the BHA  20  on a desired drill attitude to propagate the borehole  22  along the desired path (i.e., target attitude). The depicted attitude hold controller  36  includes a downhole processor  38  and direction and inclination (“D&amp;I”) sensors  40 , for example, accelerometers and magnetometers. According to an embodiment, the downhole attitude hold controller  36  is a closed-loop system that interfaces directly with the BHA  20  sensors (e.g., the D&amp;I sensors  40 , the MWD sub  28  sensors, and the steering system  32  to control the drill attitude). The attitude hold controller  36  may be, for example, a unit configured as a roll stabilized or a strap down control unit. Although embodiments are described primarily with reference to rotary steerable systems, it is recognized that embodiments may be utilized with non-RSS directional drilling tools. The directional drilling system  10  includes drilling fluid or mud  44  that can be circulated from the surface  14  through the axial bore of the drill string  16  and returned to the surface  14  through the annulus between the drill string  16  and the formation  24 . 
     The tool&#39;s attitude (e.g., drill attitude) is generally identified as the rotational axis  46  of the BHA  20  for example in  FIG.  2   . Attitude commands may be inputted (i.e., transmitted) from a directional driller or trajectory controller generally identified as a 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 the surface controller  42 , the downhole attitude hold controller  36  controls the propagation of the borehole  22  through a downhole closed loop, for example by operating the steering system  32 . In particular, the steering system  32  is actuated to drive the drill to a set point. 
     In the point-the-bit system, the axis of rotation of the drill bit  18  is deviated from the local rotational axis  46  (e.g.,  FIG.  2   ) of the BHA  20  in the general direction of the new borehole  22 . The borehole  22  is propagated in accordance with the customary three-point geometry defined by upper and lower stabilizer  26  contact points and the drill bit  18  contact point with the formation  24 . The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the bottom hole assembly close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. 
     In the push-the-bit rotary steerable system there is usually no specially identified mechanism to deviate the drill bit axis from the local bottom hole assembly axis; instead, the requisite non-collinear condition is achieved by causing either or both of the upper or lower stabilizers to apply an eccentric force or displacement in a direction that is preferentially orientated with respect to the direction of the borehole propagation. There are many ways in which this may be achieved, including non-rotating (with respect to the hole) eccentric stabilizers (displacement based approaches) and eccentric actuators that apply force to the drill bit in the desired steering direction. As noted above, steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. 
       FIG.  2    illustrates attitude and steering parameters for a bottom hole assembly  20 , identified by a rotational axis  46 , in a global or Earth reference frame coordinate system. The Earth reference frame is the inertial frame which is fixed and corresponds to the geology in which the borehole is being drilled and by convention is a right handed coordinate system with the x-axis pointing downhole and the y-axis pointing magnetically North. The attitude is the direction of propagation of the drill bit and represented by a unit vector for the downhole control systems. The instantaneous attitude “X” of the BHA  20  is indicated by the inclination θ inc  and azimuth θ azi  angles. The data from the BHA  20  (e.g., the D&amp;I sensors  40 ) may be communicated to the surface controller  42  (e.g., the direction driller) for example via a low bandwidth (2 to 20 bits per second) mud pulse to identify the instantaneous inclination and azimuth and thus the attitude of the BHA  20 . The tool face is identified by the numeral  48  and the tool face angle, θ tf , is the clockwise difference in angle between the projection of “a” in the tool face plane and the steering direction (i.e., target or demand attitude) “x d ” in the plane. The directional driller (e.g., the surface controller  42 ) communicates attitude reference signals to the downhole attitude hold controller  36  (e.g., the processor  38 ). The reference signals for example being a demand tool inclination and demand tool azimuth set points for the desired tool orientation in the Earth reference frame. For example, the steering system  32  (e.g., the tool face actuator) is operated to direct the drill bit along the desired attitude. 
       FIG.  3    illustrates the actuator assembly  54  of steering system  32  according to one or more embodiments. The steering system  32  (e.g., bias unit) includes a plurality of steering actuators  50  (e.g., actuators, pads) arranged radially in the bias body  52  and transverse to the rotational axis  46  of the bias body  52 .  FIGS.  4 - 1  through  4 - 3    show examples of actuator  50  placements in a cross-sectional view of the bias body  52 . For example,  FIG.  4 - 1    illustrates actuators  50  positioned radially opposing one another at 180° intervals.  FIG.  4 - 2    illustrates actuators  50  positioned at 120° intervals around the bias body  52 .  FIG.  4 - 3    illustrates actuators  50  positioned at 90° intervals about the bias body  52 . Note that in various embodiments, two, three, four or more actuators may be distributed evenly around the bias body  52 . In other embodiments, the actuators  50  may be distributed about the bias body  52  at uneven intervals. At least one actuator may be actuated, independently of the remaining actuators, to extend radially out of the bias body  52  toward the borehole wall  56 . 
     In a push-the-bit rotary steerable system, upon extension, the actuator  50  may contact the borehole wall  56 , applying a force. A correspondingly opposite force will be applied to the bias body  52 . The force transfers from the bias body  52 , located in the steering system  32 , down through the BHA  20  and to the drill bit  18 , pushing the bit in approximately the opposite direction of the force. 
       FIG.  5    details a longitudinal cross-sectional view of an actuator  150 . The working face  158  may include up to three surfaces: a first surface  160 , a second surface  162  and a third surface  164 . In some embodiments, the first surface  160  has a profile in the longitudinal direction that is approximately parallel to the local axis. For example, when the tool is oriented in a downhole environment, the first surface  160  may be parallel to the axis of the tool and/or parallel to a surface of the wellbore. Downhole of the first surface  160  may be the second surface  162 , which may slant radially inward from the first surface  160  at an angle a (alpha). Uphole of first surface  160  may be the third surface  164 , which may slant radially inward from the first surface  160  at an angle (beta) away from the second surface  162 . Each of the first, second and third surfaces may be curved parallel to the local axis to approximately the same radius as the borehole wall. In some embodiments, the first surface  160  may account for approximately 50% of the working face  158 . In other embodiments, the first surface  160  may account for more than 50% or less than 50% of the working face  158 . In some embodiments, the first surface  160  may include more than 25% of the perimeter of the working face  158 . 
       FIGS.  6 - 1  and  6 - 2    illustrate movement of an actuator  250  relative to a receiver  282 . A hydraulic fluid  284  may apply a force to the actuator  250  to move the actuator  250  relative to a receiver  282 .  FIGS.  6 - 1    shows that during actuator extension, the guide pin  266  slides through the pin channel  268  until it hits the radially inside end of the pin channel  268 , at which point the guide pin  266  contacts the edge of the pin channel  268 , thereby stopping further extension. During actuator retraction, the guide pin  266  slides through the pin channel  268  until it hits the radially outside end of the pin channel  268 , thereby stopping further retraction. Additionally, the guide pin  266  may prevent rotation of the actuator  250  by contact with the walls of the pin channel  268  upon introduction of a torque to the actuator  250 . The pin channel  268  need not be straight; the pin channel  268  may include a 90° turn at the radially inside end. Then after a distance, the pin channel  268  may include an additional 90° turn back toward the end of the actuator  250 . 
     Referring back to  FIG.  5   , upon contact with the borehole wall, the first surface  160  and second surface  162  may experience different frictional forces with the borehole wall. The different forces between the first surface  160  and the second surface  162  of the working face  158  may induce a cyclic clockwise (CW)/counter-clockwise (CCW) torque on the actuator  150 . Referring again to  FIG.  6 - 1   , the cyclic CW/CCW torque places stress on the guide pin  266 . Referring now to  FIG.  7   , a decrease of the percentage of the surface area of the working face  158  of the first surface  160  from 50% to less than 50% may provide a more unidirectional torque when the working face  158  contacts the borehole wall. Reducing the stress on the guide pin may save both material and operating costs. 
     In some embodiments of the present disclosure, the working face  158  of the actuator  150  may include two 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/mm 2 ) or greater. Such ultra-hard materials can include those capable of demonstrating physical stability at temperatures above about 750° C., and for certain applications above about 1,000° C., that are 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). 
     Each ultrahard material has a specific coefficient of friction on contact with and movement along another material. When the ultrahard materials are placed on the working face  158  and put in contact with a borehole wall, the frictional forces can have an impact on borehole drilling. For example, a reduced coefficient of friction may reduce rotational resistance of the actuator assembly. Additionally, a reduced coefficient of friction may reduce actuator wear on the working face  158  and/or other portions of the actuator  150 . A reduced coefficient of friction may also reduce gouging of the borehole wall. Each of these may result in reduced material costs for actuator replacement, reduced operational costs from tripping the actuator assembly to the surface, and improved borehole walls. 
       FIG.  7    provides an end-view of the working face  158  of  FIG.  5   . For example, the first material  170  may include thermally stable polycrystalline diamond (TSP) inserts on a tungsten carbide bed (e.g., infiltrated tungsten carbide), and the second material  172  may include a PCD insert. In some embodiments, PCD may have a lower coefficient of friction than diamond inserts on a tungsten carbide bed, with a ratio of coefficients of friction between TSP inserts on a tungsten carbide bed and PCD of about 4.0:1. The PCD may be sintered in a high-pressure high-temperature (HPHT) press using a tungsten carbide substrate. The tungsten carbide substrate may then be connected to the actuator using braze, epoxy, a mechanical connection such as a dovetail joint or a threaded connection, or some other secure connection. In some embodiments, the working face  158  may include a total surface area of more than two square inches, and the second material  172  may include a total surface area of more than one square inch (e.g., the ultrahard material may cover greater than 50% of the surface area of the working face). In some embodiments, the ultrahard material may cover between 30 and 90% of the surface area of the working face, and in still other embodiments, the ultrahard material may cover between 40 and 80% of the surface of the working face. However, the ultrahard material may cover any suitable percentage of the working face. 
     Placement of the second material  172  on the working face  158  in combination with a different first material  170  may result in differential frictional forces acting on the working face  158 . The differential frictional forces on the working face  158  will produce a torque applied to the actuator  150 . This frictional torque may combine with the cyclic CW/CCW torque to produce a net torque on the actuator  150 . Changing the second material  172  to a material with a different coefficient of friction may result in a different net torque. In this manner, an actuator  150  may be developed for drilling conditions from combinations of the first material  170  and the second material  172 . For example, the materials and/or relative sizes of the first and second materials may be modified to achieve a desired net torque. In at least one embodiment, the frictional torque will completely counteract one of the opposing cyclic CW/CCW torques, resulting in a unidirectional torque on actuator  150 . 
     The working face  158  includes a leading edge  174  and a downhole edge  176 . The leading edge  174  is the edge of the working face  158  that is first to come into contact with the borehole wall  56  as the steering system  32  rotates. The leading edge  174  may include up to half of the perimeter of the working face  158 . The downhole edge  176  is the edge of the working face  158  that is first to come into contact with the borehole wall  56  as the steering system  32  travels downhole. The downhole edge  176  may include up to half of the perimeter of the working face  158 . The second material  172  may be located on at least a portion of the leading edge  174  or the downhole edge  176 . In some embodiments, the second material  172  includes at least 25% of the perimeter of the working face  158  and 25% of the surface area of the working face  158 , primarily located in the quadrant of the working face  158  that includes both the leading edge  174  and the downhole edge  176 . In some embodiments, the second material covers between 20 and 60% of the perimeter of the working face, and in some embodiments, the second material covers between 25 and 40% of the perimeter of the working face. 
     In some embodiments, the second material  172  is different from the first material  170 , and the first material  170  and the second material  172  have a different coefficient of friction. As discussed above, materials with differing coefficients of friction on the working face  158  may result in a net torque on the actuator  150 . Altering the location and extent of the second material  172  may result in a different net torque. In this manner, an actuator may be developed for drilling conditions from using different first and/or second materials. In some embodiments, the ratio of coefficients of friction between the first material and the second material may include a range of ratios, the range having an upper value, a lower value, or upper and lower values including 1:1, 2:1, 3:1, 4:1, 5:1, 6:1, 7:1, 8:1, 9:1, 10:1, or any value therebetween. For example, the ratio of coefficients of friction may be 1:1, meaning the coefficients of friction are the same. In other examples, the ratio of coefficients of friction may be 10:1. In yet other examples, the ratio of coefficients of friction may be a range of 1:1 to 10:1. 
     In the embodiment shown in  FIGS.  5  and  7   , the second material  172  is PCD, sintered on a tungsten carbide substrate. The first material  170  may be thermally stable polycrystalline diamond (TSP) inserts set in infiltrated tungsten carbide. In one embodiment the second material  172  may be located on more than one surface, either the first surface  160  and the second surface  162 , the first surface  160  and the third surface  164 , or the first surface  160  the second surface  162  and the third surface  164 . The second material  172  may also be located only on one surface, either the first surface  160 , second surface  162 , or third surface  164 . In other embodiments, the second material  172  may include more than 60% of the second surface  162 . In still other embodiments, the second material  172  may be positioned across a portion of the second surface  162  in a range having an upper value, a lower value, or upper and lower values including any of 0%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100%, or any value therebetween. For example, the second material  172  may be greater than 0% of the second surface  162 . In other examples, the second material  172  may be less than 100% of the second surface  162 . In yet other examples, the second material  172  may be in a range of 0% to 100% of the second surface  162 . 
       FIGS.  8 - 1  and  8 - 2    show other embodiments of the configuration between the first material  170  and second material  172  of  FIG.  7   . In the embodiment of  FIG.  8 - 1   , the second material  372  comprises approximately 25% of the area and perimeter of the working face  358  from the center of the leading edge  374  down to the center of the downhole edge  376 . The first material  370  accounts for the remainder of the area and the perimeter of the working face  358 . In other embodiments, the second material  372  may be positioned across a portion of the working face  358  in a range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, or any value therebetween. For example, the second material  372  may be greater than 10% of the working face  358 . In other examples, the second material  372  may be less than 70% of the working face  358 . In yet other examples, the second material  372  may be in a range of 10% to 70% of the working face  358 . 
     In the embodiment of  FIG.  8 - 2   , the second material  472  comprises a strip located on the perimeter of the working face  458  from the leading edge  474  down to the downhole edge  476 . In other embodiments, the second material  472  may be positioned across a portion of the perimeter of the working face  458  in a range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, or any value therebetween. For example, the second material  472  may be positioned on greater than 10% of the working face  458  perimeter. In other examples, the second material  472  may be positioned on less than 70% of the working face  458  perimeter. In yet other examples, the second material  472  may be positioned on in a range of 10% to 70% of the working face  458  perimeter. 
     Additional embodiments of working faces  458  could include the second material  472  covering the entire leading edge  474  hemisphere of the working face  458 . Still other embodiments could include the second material  472  including the entire downhole edge  476  hemisphere of the working face  458 . In still other embodiments, the entire working face  458  could be covered with the second material  472 .  FIGS.  8 - 1  and  8 - 2    are solely representations of possible configurations; any combination or geometry of the first material  470  and the second material  472  is envisioned by this application. 
       FIGS.  9 - 1  through  9 - 5    refer to a series of further embodiments of the actuator, where the shape of at least part of the actuator may be non-round. When a portion of a non-round actuator is inserted into a complementarily shaped receiver, the portion of the non-round actuator will contact the receiver when acted on by a torque, thereby preventing free rotation. With no free rotation, the guide pin  266  and channel  268  of  FIG.  6    may no longer be needed to prevent rotation. At least a portion of an embodiment of an actuator may have a non-circular transverse cross-sectional shape. For example, the transverse cross-sectional shape may be one of a variety of shapes. For example, an embodiment of an actuator  550  may have a transverse cross-sectional shape that is an ellipsoid ( FIG.  9 - 1   ), a square actuator  650  ( FIG.  9 - 2   ), a hexagonal actuator  750  ( FIG.  9 - 3   ), a polygonal actuator of any number of sides ( FIGS.  9 - 2  through  9 - 4   ), a concave polygon actuator  850  ( FIG.  9 - 4   ), or a non-polygonal enclosed shaped actuator  950  ( FIG.  9 - 5   ). For example, the elliptical actuator  550  of  FIG.  9 - 1    need only have a sufficient difference in magnitude between the major axis and the minor axis so as to prevent binding upon extension or retraction of the actuator. In some embodiments, the major axis of the elliptical actuator  550  may be larger than the minor axis in a range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100%, or any value therebetween. For example, the elliptical actuator  550  may have a major axis greater than 10% larger than the minor axis. In other embodiments, the major axis may be less then 100% larger than the minor axis. In yet other examples, the major axis may be in a range of 10% to 100% larger than the minor axis. 
       FIGS.  10 - 1  and  10 - 2    show an embodiment of the disclosure in which the actuator includes a shaft  1078  and actuator body  1080 , the actuator body  1080  including working face  1058  and located radially outward of the shaft  1078 . The shaft  1078  may be inserted into a receiver  1082 . The receiver  1082  may have a complimentary transverse cross-sectional shape to at least a portion of the actuator  1050  (e.g., the actuator shaft  1078  and/or actuator body  1080 ). The actuator may be extended and/or retracted through the application of a hydraulic, pneumatic or mechanical force on the end of the shaft  1078 . An oil based, water based or drilling mud based hydraulic fluid  1084  may apply the force to shaft  1078 , causing shaft  1078  to move relative to a band  1086  and extend from the receiver  1082  toward the wellbore wall  1056 . In some embodiments, the band  1086  may provide a fluid seal (as will be described in more detail in relation to  FIG.  11 - 1    through  FIG.  12 - 2   ). In some embodiments, the shaft  1078  and the actuator body  1080  may have the same transverse cross-sectional shape. In other embodiments, the shaft  1078  and/or the actuator body  1080  may have different transverse cross-sectional shapes. For example, each transverse cross-sectional shape may be circular, any of the profiles envisioned in  FIGS.  9 - 1  through  9 - 5   , or any other transverse cross-sectional shape. In other examples, the shaft  1078  may have a circular transverse cross-sectional shape and the actuator body  1080  may have a square transverse cross-sectional shape. In yet other examples, the shaft  1078  may have a square transverse cross-sectional shape and the actuator body  1080  may have a circular transverse cross-sectional shape. 
     The shaft  1078  and actuator body  1080  may be integral (e.g., originate from one cohesive block), from which the differences between shaft  1078  and actuator body  1080  are carved, machined, cast in, or otherwise altered. In other embodiments, the shaft  1078  and actuator body  1080  may comprise two separate pieces, the shaft  1078  and actuator body  1080  connected via epoxy, braze, weld, mechanical connection, or the like. 
     In the embodiment shown in  FIG.  10 - 1   , shaft  1078  may have a smaller cross-sectional area than the actuator body  1080 . In another embodiment shown in  FIG.  10 - 2   , shaft  1178  may have a larger cross sectional area than the actuator body  1180 . If the shaft  1178  has a larger cross sectional area than the actuator body  1180 , the receiver  1182  may include a stop  1190 . During actuation, if the borehole wall  1156  does not prevent further actuation through contact with the working face  1158 , then actuation will be stopped by contact of the shaft  1178  with the stop  1190 . In at least one embodiment, a shaft  1178  and actuator body  1180  as shown in  FIG.  10 - 2    may amplify the force on the wellbore wall  1156  applied by the hydraulic fluid  1184  to move the shaft  1178  and actuator body  1180  relative to the receiver  1182  and the band  1186 . 
       FIG.  11 - 1    shows still another embodiment of the disclosure, in which actuator  1250  is inserted into receiver  1282 . The hydraulic fluid  1284  applies a force to the actuator  1250  to move the actuator  1250  toward the wellbore wall  1256 . A band  1286  is positioned at least partially radially between the actuator  1250  and the receiver  1282 . For example, the actuator  1250  is positioned radially within the receiver  1282  and at least partially longitudinal within the receiver  1282 . There may be some amount of space between the actuator  1250  and the receiver  1282 , and the band  1286  may be at least partially located in that radial space. In some embodiments, the band  1286  fully encloses the perimeter of the actuator  1250  along a portion of its length. In the embodiment depicted in the  FIG.  11 - 1   , the band  1286  is fixed on the outside of receiver  1282 , fully enclosing the perimeter of the actuator  1250 . 
       FIG.  11 - 2    shows another embodiment in which the band  1386  is located in a groove within the actuator  1350  to retain a hydraulic fluid  1384 . An additional embodiment includes the band  1386  located on a groove within the receiver  1386 . In this embodiment, the band  1386  be may remain longitudinally static relative to the receiver  1382  as the actuator  1350  moves toward the wellbore wall  1356  but freely rotate about the actuator  1350 . In other embodiments, the band  1386  may be fixed longitudinally relative to the actuator  1350  and may move relative to the receiver  1382 . 
     In some embodiments, the band may be a non-elastomeric band  1386 . For example, the band  1386  may include or be made of an ultrahard material. In other examples, the band  1386  may include or be made of a metal alloy. In at least one embodiment, the band  1386  may include or be made of a carbide, such as tungsten carbide, silicon carbide, aluminum carbide, boron carbide, or other carbide compounds. 
       FIG.  12 - 1    shows a cross-sectional view of the band receiving the actuator.  FIG.  12 - 2    shows a detailed portion of the contact between the band  1486  and the actuator  1450 . The band  1486  has a clearance  1488  over the actuator  1450 . In some embodiments, the clearance  1488  is sized such that when the hydraulic fluid has a sufficient viscosity, cohesion, adhesion, or combinations thereof, the band  1486  and hydraulic fluid  1484  create a sealing surface around the actuator  1450 . For example, the clearance  1488  may be in a range having an upper value, a lower value, or an upper value and lower value including any of 20 microns, 30 microns, 40 microns, 50 microns, 60 microns, 70 microns, 80 microns, 90 microns, 100 microns, or any values therebetween. For example, the clearance  1488  may be greater than 20 microns. In other examples, the clearance  1488  may be less than 100 microns. In yet other examples, the clearance  1488  may be in a range of 20 microns to 100 microns. In further examples, the clearance  1488  may be in a range of 30 microns to 60 microns. The clearance  1488 , in combination with the viscosity, cohesion, adhesion, or combinations thereof of the hydraulic fluid  1484  may create a sealing surface around the actuator  1450  to limit and/or prevent the flow of hydraulic fluid  1484  past the band  1486  at working temperatures. While these clearances have been described with reference to the band, these clearances may be used with respect any surface the actuator interfaces with. For example, if no band is used, and the actuator interfaces with the receiver, the clearance between the actuator and receiver, at least at the outermost point of the receiver may be in a range having an upper value, a lower value, or an upper value and lower value including any of 20 microns, 30 microns, 40 microns, 50 microns, 60 microns, 70 microns, 80 microns, 90 microns, 100 microns, or any values therebetween. 
     Typically, hydraulic fluid  1484  is oil-based to create a sealing surface, although a water-based or drilling-mud based fluid may be used. Standard elastomeric seals may be less durable than a non-elastomeric band sized to create a sealing surface, as the elastomeric seals may break down in the high-repetition environment to which the actuator  1450  is subjected. 
     In another embodiment of the disclosure illustrated by  FIGS.  13 - 1  and  13 - 2   , actuator  1550  may include a cradle  1592  facing radially outward. Nestled within the cradle is roller  1594 , designed to freely rotate in an axis approximately parallel to the local axis of an RSS tool. When the actuator  1550  is extended far enough that roller  1594  contacts borehole wall, roller  1594  will roll along the borehole wall  1556  until actuator  1550  is retracted or pressure is no longer applied to the backside of the actuator. 
     A rolling contact with borehole wall  1556  may reduce rotational friction on the steering mechanism, as well as reduce the gouging of borehole wall from a sliding working surface. A variety of materials may be used for the roller  1594 , including hard materials such as steel or tungsten carbide (WC), as well as elastomeric materials. In some embodiments, the roller may be made from an elastomeric material, which may result in deformation of the roller  1594  upon contact with the borehole wall  1556 . Deformation of the roller  1594  upon contact with the borehole wall  1556  increases the contact surface, which may reduce the pressure on the borehole wall  1556 . 
     In some embodiments, the roller  1594  may include a taper on the downhole end, the taper being a percentage of the total axial length of the roller  1594 . In some embodiments, the taper may comprise a range of percentages of the total axial length of the roller  1594 , the range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100%, or any value therebetween. For example, the taper may be 10% of the axial length of the roller  1594 . In other examples, the taper may be 100% of the axial length of the roller  1594 . In yet other examples, the taper may be a range of 10% to 100% of axial length of the roller  1594 . In some embodiments, the taper includes 100% of the axial length of the roller  1594 , effectively creating a cone out of the roller  1594 . The connection between the roller  1594  and the actuator  1550  may pivot on the uphole and/or downhole end of the actuator  1550 . The pivotable connection between the actuator  1550  and the roller  1594  may allow the roller  1594  to conform to various contact angles of borehole wall  1556  relative to the actuator  1550 . 
     In some embodiments, an actuator assembly includes a body, a receiver in the body, and an actuator positioned at least partially in the receiver, mounted transverse to a rotational axis of the body. The actuator may have an actuator body and an actuator shaft, the actuator shaft being connected to the actuator body, the actuator body being located radially outward from the actuator shaft, and at least part of the actuator may have a non-circular transverse cross sectional shape. The non-circular transverse cross sectional shape may be elliptical, square, hexagonal, polygonal, or non-polygonal. The actuator shaft may have a transverse cross sectional shape that is different from a transverse cross sectional shape of the actuator body. The receiver may have a complimentary transverse cross-sectional shape to receive the at least part of the actuator. The receiver may limit rotation of the actuator through contact of the receiver with the actuator. The actuator shaft may have a larger cross sectional area than the actuator body. The receiver may have a stop, complementarily shaped with the actuator body, and the stop may be configured to stop extension of the actuator through contact with at least a portion of the actuator shaft that extends beyond a transverse cross sectional shape of the actuator body. 
     In some embodiments, an actuator assembly may include a body, a receiver in the body, and an actuator positioned at least partially in the receiver, mounted transverse to a rotational axis of the body. The assembly may include a non-elastomeric band, and the non-elastomeric band may be positioned in the receiver such that at least part of the non-elastomeric band is positioned between the actuator and the receiver. The non-elastomeric band may include tungsten carbide. The assembly may further include a fluid positioned in the receiver and in contact with a portion of the actuator positioned at least partially in the receiver. The fluid may be positioned between at least a portion of the non-elastomeric band and at least one of the receiver and the actuator. The non-elastomeric band may be at least partially fixed relative to the receiver. The assembly may further include a clearance between the non-elastomeric band and at least one of the actuator and the receiver. The non-elastomeric band may be at least partially located in a groove. 
     In some embodiments, an assembly for steering a rotary tool relative to a borehole wall includes a body having a rotational axis, and a plurality of actuators, at least one of the plurality of actuators positioned at least partially in the body and configured to move transverse to the rotational axis of the body. At least one actuator may have a cradle, and a roller at least partially within the cradle and configured to rotate relative to the cradle, the roller positioned radially outward from the body relative to the cradle and having a downhole end. The roller may include an elastomeric material to increase the contact area with the borehole wall. A downhole edge of roller may be tapered between 10% and 100% of an axial length of the roller. The roller may be pivotally mounted to the cradle at an uphole end of the roller. The roller may be pivotally mounted to the cradle at the downhole end of the roller. The roller may include tungsten carbide. 
     Although the embodiments of drilling systems and associated methods have been primarily described with reference to wellbore drilling operations, the drilling systems and associated methods described herein may be used in applications other than the drilling of a wellbore. In other embodiments, drilling systems and associated methods according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, drilling systems and associated methods of the present disclosure may be used in a borehole used for placement of utility lines, or in a bit used for a machining or manufacturing process. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment. 
     References to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein is combinable with any element of any other embodiment described herein, unless such features are described as, or by their nature are, mutually exclusive. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value. Where ranges are described in combination with a set of potential lower or upper values, each value may be used in an open-ended range (e.g., at least 50%, up to 50%), as a single value, or two values may be combined to define a range (e.g., between 50% and 75%). 
     A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims. 
     The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. 
     The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.